Unlocking gas from tight sands

Feb. 27, 2006
Without hydraulic fracturing, most tight-sand gas reservoirs would not produce economically even at the relatively high levels wellhead gas prices have reached recently in the US.

Without hydraulic fracturing, most tight-sand gas reservoirs would not produce economically even at the relatively high levels wellhead gas prices have reached recently in the US.

The concept of hydraulic fracturing is simple. Fluid pumped down the well and into the formation creates fractures that allow gas or oil to flow into the wellbore at rates higher than would be possible without the procedure. The pumped fluid often includes proppants, such as sand, that ensure that the mechanically created fracture remains open.

Operators have used variants of this technology for decades for accelerating oil and gas production as well as for recovering previously uneconomic resources.

One problem in wells completed in tight gas sands is that, even with hydraulic fracturing, production rates and ultimate gas recoveries tend to be low. Operators often do not want to spend enough money to properly design the jobs.

A workshop on fracturing tight gas sands, organized by the Petroleum Technology Transfer Council (PTTC) last week in Houston, brought out some of the design issues required for proper frac designs.

As Larry Britt, of NSI Technologies Inc., Tulsa, noted in his presentation at the PTTC workshop, if a job is not designed correctly “the well becomes a disposal site for sand and water.”

Tight sands

Tight gas sands in the US produce 2-3 tcf/year, and various estimates indicate that ultimate gas recovery from this resource may exceed 250 tcf out of 5,000 tcf or more in place. These amounts are greater than the estimated 190 tcf of gas remaining in conventional US gas reservoirs.

Sandstone formations with less than 0.1 md permeability are commonly called tight gas sands. Many tight formations are at depths greater than 10,000 ft. In the past, operators completed these wells on 320 or 640-acre spacing, but infill drilling has decreased spacing in many fields to 80 or 40 acres. In some fields, wells are even placed on 10 and 20-acre spacing.

Advances in technology have helped lower drilling costs for tightly spaced wells. In new fields, operators have learned how to target sweet spots that will flow gas at high rates.

But even with higher well density and drilling in sweet spots, the wells require hydraulic frac jobs to attain economic gas flow rates.

Evolving technology

Hydraulic fracturing has evolved over several decades and continues to change. Stephen Holditch, department head of petroleum engineering at Texas A&M University, at the PTTC workshop recounted briefly the evolution of frac fluids, the first of which were pumped in 1947 and consisted of gasoline with napalm left over from World War II.

Holditch said the technology progressed to gelled oil in the 1950s, linear gelled water in the 1960s, cross-linked gelled water in the 1970s, foamed fluids in the 1980s, and advanced breaker technology and reduced polymer loadings in the 1990s. Polymer-free fluids are among the latest fluids. They damage fractures less but cost more than alternatives.

Fluid cost has encouraged some operators to use water fracs with small amounts of proppants. These fluids have shown good results in such naturally fractured formations as the Barnett shale. But the consensus at the PTTC workshop was that fluids capable of supporting proppant loads higher than those used in water fracs would create greater fracture conductivity and allow higher gas producing rates in most cases.

Some form of most of these fluids, except for napalm, still are in use in fracturing applications. Designers of frac treatments have to base fluid choices on various factors.

The selection of the best fluids and proppants for a job requires the designer to consider geomechanical properties of the formation, such as stresses and their orientation, modulus of elasticity, leak-off, and reservoir permeability, which can be extracted from seismic, geologic, logging, and drilling and completion data.

Acquiring these data adds costs but usually only for the first few wells, since parameters in a field do not change much from well to well.

The US is not alone in having tight gas sands. As the technology for unlocking tight gas evolves, development may spread to many of the world’s basins if local gas prices permit.