High surface treating pressures and high temperatures create a fracturing challenge.
by Doug Walser, Pinnacle, a Halliburton Service
July 29, 2011

As domestic exploration and development efforts continue to shift toward the extraction of liquid hydrocarbons, a few plays are still producing natural gas at low commodity prices, which continues, under certain circumstances, to make fiscal sense. The Haynesville in East Texas and Louisiana is one such play. Though drilling and completion (D&C) costs can be significantly higher than in the typical North American unconventional plays and though decline rates can be abnormally high, the tremendous initial production rates can contribute to relatively short payout times.

The Need for State-of-the-Art Technology

Extraction of gaseous hydrocarbons from the Haynesville involves invoking state-of-the-art equipment and processes. Two root causes of this requirement are high treating pressures and high temperatures associated with typical Haynesville reservoirs. As in many Gulf Coast geosyncline formations, this shale is radically over-pressured, likely due in part to historical sediment loading and partly because of internal volumetric expansion associated with the maturing of individual microscopic pockets of hydrocarbons over geologic time. Static reservoir pressure gradients are typically from 0.87 to 0.91 psi/foot, and fracture gradients range from 0.95 to over 1.1 psi/foot.
As a result, typical surface treating pressures during fracture stimulation operations are between 10,000 and 15,000 psi. The typical temperature gradient is about 1.8 degrees F/100 feet, so static temperatures range between 265 and 320 degrees F. This temperature span can present difficulties with respect to degradation of downhole electronic measurement and control devices, and accelerate the vulcanization and eventual destruction of various synthetic, rubber-based mechanical sealing devices.
As with other North American unconventional plays, statistical evidence shows that the Haynesville is a resource play in which D&C processes can influence the rate of acceleration of reserve recovery as much as geological and geophysical issues can affect it. Unlike conventional reservoirs (where understanding of geological and geophysical parameters is wholly dominant), the particular methods chosen to fracture-stimulate the reservoir are critical to early production profiles

Figure 1. Oblique view of a microseismic mapping operation performed in the Haynesville

Causes of Haynesville’s High Surface Treating Pressures

Several parameters contribute to the high surface treating pressures commonly encountered during Haynesville stimulation treatments. Bottomhole fracturing pressure, typically offset only by the hydrostatic of the fracturing fluid, is the primary contributor. Fluid friction down the casing is a second contributor but is typically less than 2,000 psi.
In horizontal completions, total entry friction (the sum of perforation friction plus near-wellbore pressure drop, or tortuosity) can be substantial—sometimes exceeding 2,000 psi or even 3,000 psi. The result is that the surface pumping equipment is subjected to regular cycling of 10,000 to 15,000 psi pressure differentials.
Effective management of the controllable processes requires up-front “science” expenditures by the operator early in the development and exploitation process. Controllable parameters (among many) that benefit from up-front science are:

  • Lateral elevation—Knowledge of conventional petrophysical properties, geochemical properties (total organic carbon, kerogen content & type, etc.), and advanced geomechanical properties (brittleness, ductility, Young’s modulus, Poisson’s ratio, etc.) is required for this parameter. It also requires knowledge of far-field fracture height (see the example of microseismic mapping shown in Figure 1).
  • Lateral azimuth—This parameter requires knowledge of far-field fracture network azimuth trend.
  • Fracture initiation point count along the lateral (consists of stages/1,000 ft and clusters/stage)—This parameter is best optimized by simple far-field observation of early field development completions.
  • Pump rate—Determining the relationship (if any) between pump rate and far-field fracture height is critical to long-term development. In addition, pump rate can impact the pumpability ratio (the percent of stages successfully pumped to completion) of a given project.
  • Lateral positioning and spacing—Far-field fracture mapping assists in determining the optimum distance between laterals.

Redefining the Frac Pump Duty Cycle

Fracturing work in the Haynesville Shale has created a whole new landscape for fracturing pump suppliers. It has redefined the industry’s understanding of the fracturing pump duty cycle, changed the industry’s perspective on pump failure modes and created new challenges for maintaining a fracturing fleet.

The Haynesville’s typical treating pressures and job durations create a new fracturing pump duty cycle, one that the industry has never seen previously. In years past, the fracturing duty cycle was one of high power demands over relatively short durations of run time, as compared to generators or other continuous duty applications. The Haynesville fracturing treatment regime continues to follow this model but has dramatically amplified the calendar time service companies spend online pumping each day.

Traditional pumping units would have spent several months accumulating the hours that units in the Haynesville now typically experience in weeks. This unique challenge means that vendors who supply frac pumping components must reassess their offerings to ensure that they provide the best value to those actually providing pumping services. Even slight changes to product offerings that promote extended life are now of great interest to all parties, where they would have once been overlooked by the industry as a whole.

In terms of fluid ends, fracturing pump life has traditionally been decided by its ability to resist or tolerate wear due to erosion from pumping proppant laden fluids. Spikes in fluid velocity and overall velocity profiles in fluid ends have been a strong consideration in pump design from a historical perspective. This wear regime has proven to be a lesser factor in the Haynesville, where pump fatigue is now the dominant failure mode for most fracturing pumps.

An interesting facet of the fatigue failure trend is that it affects both the fluid and power ends of a fracturing pump. Power end designers are now in the spotlight of pump design discussions, as power end failures from fatigue continue to plague segments of the industry.

Fracturing pump maintenance is not a trivial issue for pumping service companies working in the Haynesville. The duty cycle in this market demands that even the most robust pumps receive regular maintenance. The demanding duty cycle of this play requires that preventive maintenance, reactive maintenance and proactive maintenance regimes must often be completed in the field.

This approach creates practical challenges with respect to methods of accessing the pertinent parts of a given unit and lends itself to non-productive time (NPT) concerns for service companies and their clients. Fracturing pump designers are being challenged to create and enable a way to readily maintaining frac pumps in this environment, while attempting to extend the service interval as long as possible to avoid NPT.

One means of extending service intervals is lengthening the service life of consumable pump parts (valve inserts, packing, etc.). A supply chain laden with longer-lasting pump consumables benefits the pumping service companies, as well as operators in this demanding play.

Fiscal success in the Haynesville is clearly dependent upon more than just naturally occurring geological parameters. Though commodity prices certainly play a role, D&C processes are critical. Up-front expenditures for science and superior mechanical execution can often be the differentiators between those operators who are simply holding leases and those who are profitably extracting hydrocarbons.

Upstream Pumping Solutions, Winter 2011