(Tech Connections Column, December 2006, American Oil and Gas Reporter)

Those interested in the Barnett or other evolving shale-gas plays hear lots about shale geochemistry, drilling, completion, and stimulation techniques. But there are geological concepts that need to be understood as well. The Bureau of Economic Geology (BEG), Jackson School of Geosciences, at the University of Texas shared results from its study of the Barnett Shale in PTTC workshops in Houston and Midland, Tx.

About 400 billion cubic feet a year, or 2 percent of U.S. natural gas consumption, now comes from the Barnett Shale. There were 5,200 wells in mid-2006 and rapid development continues. There are surface issues in urban areas, and since very large water fracs are the stimulation of choice, freshwater use/supply is a concern.

Horizontal wells have become prominent. Horizontal completions are moving toward tighter lateral spacing (from 1,500 to 500 feet), longer laterals (from 3,500 to 5,000 feet), from uncemented to cemented laterals, toward tighter perforation spacing, and to more stages. Underbalanced drilling can reduce cost by 25 percent or more through improved penetration rates (double) and reduced bit requirements, plus there is less formation damage. One speaker noted that "with continued technology evolution and expansion to noncore areas," activity will continue strong as long as gas price stays above $4 an Mcf.

But some big picture questions remain. How many refracs per well? How will regional pressure drawdown and resulting gas desorption affect decline curves? Will regional depressur-ing and a multicounty linked-frac mosaic result in free gas migration westward? With 80 percent of gas left in place after the current round of development, what forms of enhanced gas recovery will be effective? BEG’s work goes a long way toward addressing geological questions.

The Barnett Shale is a Mississippian foreland basin deposit. It is a dark-colored, fine-grained, kerogen-rich siliceous mud-stone with some muddy limestones. Being a deeper marine deposit, there are a variety of geological processes at work: debris flow, turbidity current flow, suspension settling, and contour currents. There is strong evidence for Barnett deposition occurring in a deeper water (400-700 feet or more), euxinic (anaerobic or limited oxygen) environment. The sediment is laminated (not much perturbation at that depth). Pyrite, which must be considered in logging, likely will be encountered.

A seismic time slice on the Forestburg, which overlies the Lower Barnett, reveals numerous collapse or sink-hole structures related to earlier Ellenberger karsting. These affect the thickness of the Barnett. It’s also evident from log and seismic data that there may be multiple clinoforms in the Lower Barnett. These are deepwater surface structures on the slope in a marine sedimentary accumulation. The significance is that different facies environments may be present along the clino-forms, which will affect productivity and how wells should be completed. It’s not layer cake geology, so understanding it will pay off.

One key issue when mapping is establishing a valid hang-line/timeline for correlation. The top of the Marble Falls Shale is potentially the best timeline, but it is sometimes difficult to identify. Understanding the depositional environments of the Lower and Upper Marble Falls formations is critical to establishing proper correlations and timelines. The Lower Barnett target interval is up to 100 feet thick as far west as Brown and Stephens counties. Increased thickness of the Lower Barnett to the northeast is largely a function of increased proportions of carbonate lithologies.

The fractures and faults in the Barnett Shale result from regional, tectonic paleostress, local effects of major faults and folds, and sag features associated with underlying Ellenberger karst. One must treat faults separately from the opening-mode fractures (joints and veins) that are common. The predominant natural fractures trend north-west, though there is a less common set trending north-south. Most natural fractures are sealed with calcite and dolomite, and some pyrite. Connectivity is improved by the presence of multiple fracture sets. Fracture system porosity is low, but where there are fracture clusters (and they are common), permeability may be locally high. Sealed natural fractures reactivate during hydraulic fracturing. In situ stress controls hydraulic fracture orientation. Fracture orientation during refracs conducted after a period of production is known to change. This effectively accesses a new volume of rock. How many times will this beneficial effect be observed?

Understanding what makes the Barnett Shale tick is the first step in looking at less mature shale-gas plays. Operators in new plays must understand what is similar and what is different. This applies to concepts across the board–from geology through drilling, completion, and operations practices. Those wanting a more thorough understanding of geological concepts may contact BEG’s Robert Loucks (bob.loucks@beg.utexas.edu), phone 512-471-0366); or Stephen Ruppel (Stephen.ruppel@beg.utexas.edu), phone 512-471-2965). A CD containing workshop presentations can be purchased for $15. Ask for BEG publication No. SW0016, Barnett Shale-Gas Play of the Fort Worth Basin.