Fracturing high-permeability formations

Smith and Hannah documented the evolution of hydraulic fracturing in high-permeability reservoirs since the 1950s. The first fracture treatments in the 1950s were pumped in moderate- to high-permeability formations. Those treatments were designed to remove formation damage that usually occurred during the drilling and completion operations. Low-permeability reservoirs were fracture treated in the 1950s and 1960s, but, at low oil and gas prices, low-permeability reservoirs were generally not economic, even after a successful fracture treatment.

Overview

The values of high, moderate, and low permeability need to be defined on the basis of both the formation permeability and the reservoir fluid viscosity, or the k/μ ratio, where k is the formation permeability in md, and μ is the formation fluid viscosity in cp. For a gas well, the average viscosity of the gas is assumed to be approximately 0.02 cp. For a typical gas well:

• A low-permeability formation might be where k<

0.1 md

• A medium-permeability reservoir might be 10>

k > 1 md

• A high-permeability reservoir might be 25 md>

k

If the formation contains oil with a fluid viscosity of 2 cp, then all the permeability values must be multiplied by a factor of 100 to determine what is a low-, moderate-, and high-permeability formation. This example illustrates that the definition of "high permeability" also depends on the value of the reservoir-fluid viscosity. In heavy-oil plays, in which the reservoir fluid viscosity is several thousand centipoises, then formations with several Darcies permeability would be considered a low-permeability reservoir. From this point forward, we assume that the formation fluid is either gas or light oil; thus, a formation with a permeability of several hundred millidarcies or more will be considered high permeability.

Candidate selection criteria for high-permeability formations

The main reasons for fracture treating high-permeability formations are:

• To improve both the reservoir and wellbore communication
• To bypass formation damage
• To reduce the drawdown around the wellbore
• To increase the back stress on the formation
• To control sand production
• To reduce fines migration
• To reduce asphaltene deposition
• To reduce water coning

As mentioned, the early fracture treatments were pumped to break through damage near the wellbore and increase the productivity index of the formation. Today, fracture treatments in high-permeability wells are pumped to bypass damage, but other reasons have become just as important. For example, many treatments are pumped for sand-control purposes. By creating a short, highly conductive fracture connecting the reservoir to the wellbore, the productivity index is increased; thus, more oil and gas can be produced with a lower drawdown. As the drawdown is reduced, the tendency of a poorly consolidated reservoir to produce sand is also reduced. In certain formations, the reduction in drawdown also helps to deter:

• Fines migration
• Asphaltene deposition
• Water coning

Design considerations for high-permeability formations

Most fracture treatments in high-permeability formations are designed to achieve a tip screenout. A tip screenout design is one in which the pad volume is designed carefully so that the pad leaks off during the treatment, causing the propping agent to bridge at the tip of the fracture near the end of the job. At this point, the fracture quits growing in length, but pumping continues. As pumping continues, the pressure in the fracture increases, which leads to increasing width and, sometimes, increasing height. The fracture continues to inflate and is packed with the propping agent. The purpose of a tip-screenout design is to create a short, extremely wide fracture that is completely packed with the propping agent.

Smith and Hannah documented that Amoco successfully combined hydraulic fracturing and gravel packing in the Hackberry field south of Lake Charles, Louisiana, in 1984. Hannah et al. described a combination fracture treatment and gravel pack in an offshore field in 1994. Since the early 1990s, “frac-pack” treatments have become standard for many producing areas worldwide. Frac-pack treatments tend to reduce the skin factors from very high numbers (10 to 50) to essentially a skin of zero. In other words, the damage to the formation surrounding the wellbore during the drilling and completion of the well is negated by the frac-pack operations. In many cases, the productivity index is increased by a factor of three or more by the frac-pack treatments.

Park provided information concerning the design criteria for tip screenout treatments that are part of a frac-pack operation. In general, the designed fracture lengths for a frac-pack treatment are from 10 to 50 ft. The treatments are designed to create as wide a propped fracture as possible; thus, treatments are designed for proppant concentrations as high as 17 to 20 lbm/ft². Many unconsolidated or poorly consolidated sands have values of Young’s modulus that range from 90,000 to 200,000 psi, which theoretically can result in created fracture widths of 3 in. and propped fracture widths of 2 in. As the value of modulus increases, the rock becomes stiffer, the created fractures become narrower, and the amount of propping agent that can be placed in the fracture decreases. Tip screenout treatments can be designed with almost any fracture-treatment-design model. Just like any design, the engineer must have data that describe the reservoir and the treatment conditions accurately. Some fracture design models have special features to optimize the size of the pad volume, the leakoff characteristics of the fluid, and other variables that affect tip screenout designs.

Early frac-pack treatments were pumped with the equipment, fluids, and gravel commonly used in gravel-packing operations. For example, the fluid most commonly used was hydroxyethyl cellulose gel, because it is clean and should not significantly damage the reservoir. Also, 40- to 60-mesh gravel was used as the propping agent. As the technology has evolved, other fluids such as hydroxypropyl guar crosslinked with borates and viscoelastic surfactant fluids have been used successfully to pump a frac-pack treatment. Because fracture conductivity is so important, the use of 20- to 40-mesh proppants is now common.

In summary, fracture treatment technology was first developed in the 1950s to break through damage in high-permeability reservoirs. In the 1960s, gelled water fluids were used successfully to fracture treat both low- and high-permeability oil and gas wells. The technology evolved in the 1970 and 1980s; the industry was pumping massive hydraulic fracture treatments in microdarcy reservoirs. Massive treatments in tight reservoirs are still being pumped today and will become even more important in the future. However, in the 1990s, because of the tip screenout design process and frac-pack operations, stimulation of high-permeability reservoirs is once again an important aspect of hydraulic fracturing to reduce the effects of formation damage and to enhance gravel packing.

External links

Recent Advances In Hydraulic Fracturing

See also

Fracture treatment design

Fracture mechanics

Hydraulic fracturing

PEH:Hydraulic_Fracturing

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