The Haynesville Shale is a massive, very plastic and ultra-low permeability shale. It is a dry natural gas formation found in Northwest Louisiana, East Texas, and the Southwestern tip of Arkansas that lies at true vertical depths between 10,000 and 14,000 feet trending deeper as you move north to south. The majority of the current Haynesville Shale activity is located within DeSoto and Red River Parish, Louisiana as well as Panola County, Texas. Haynesville Shale activity has significantly increased in the last few years due primarily to the advances in drilling and completion technology and techniques. Currently there are approximately 40-45 rigs actively drilling in the Haynesville Shale. The surge in activity is due to many industry advances but none more important than the reservoir stimulation design.
Stimulation design can be a topic of much debate. To begin, let's try to stick with practical design parameters that are assumed to be true amongst the majority of industry professionals. Pumping rates directly affect fracture growth. This can be fracture height, fracture length, or a combination of the two. Higher viscosity fluid systems tend to create more fracture width and potentially height. The opposite applies for lower viscosity fluid systems. Proppant selection should include the consideration of closure stresses, and of course formation deliverability, which can be determined via basic reservoir models. These are fracture characteristics that do not take into account factors such as barriers or unconventional fracturing networks.
Now that we have discussed basic fracturing dynamics, let's look at previous fracturing designs in horizontal Haynesville Shale wells. The industry began fracture stimulation of the Haynesville Shale reservoir in horizontal wells in the Ark-La-Tex region in early 2008. Initially operators experimented with two main fluid systems; a low-viscosity "Treated Water" system and high-viscosity "Crosslinked-Gel" system. Both systems have their merits; treated water's being lower formation damage and crosslinked-gel's being the ability to place high conductivity proppants at high proppant concentrations. Proppant selection varied based on the fluid system. Low-viscosity fluid systems required the use of high pump rates (80-100bpm), large stage fluid volumes, and small mesh sizes (100 mesh sand, 40/70 mesh) at low proppant concentrations (up to 1.5ppg) due to the narrow fracture width and poor proppant transport capabilities of low-viscosity fluids. High-viscosity fluid systems allowed for lower pump rates (40-60bpm), smaller stage fluid volumes, higher strength proppants (PRC, CRC, Ceramic), and larger mesh sizes (20/40 mesh sand) at higher proppant concentrations (up to 5ppg) due to the high fluid efficiency and good proppant transport capabilities of high-viscosity fluids. Regardless of the fluid system and proppant selection, most operators targeted 200'- 400' lateral stage spacing and 1,200 to 1,800 pounds of proppant per lateral foot.
A large portion of initial stimulation design parameters for the Haynesville Shale were based on the Barnett Shale reservoir but over time more Haynesville Shale reservoir properties and characteristics were identified and used for stimulation design. Restored and improved production from refrac techniques is also a critical reason for the current Haynesville Shale stimulation design trends. Many operators have elected to refrac Haynesville Shale wells from the early years of development and have discovered that the reservoir was in some if not most cases severely under stimulated. The recent discoveries have led to operators pushing the limits of proppant loading. Currently the majority of Haynesville Shale stimulation designs utilize a hybrid fluid system (combination of Treated Water, Linear-Gel and Crosslinked-Gel) with 100-165' stages, 4-8 perf clusters per stage, and an adequate number of perfs per cluster depending on designed pump rate. Most operators utilize limited entry for perforation design, targeting approximately 1.5 bpm of pump rate per perforation assuming a 0.42" EHD. Hybrid fluid systems theoretically allow one to capture the best of both worlds with respect to stimulation design. The Haynesville Shale is an unconventional reservoir with low permeability, so the majority of the hybrid fluid system is treated water. As proppant concentration increases above 2ppg, linear and/or crosslinked systems are used with gel concentrations in the range of 20ppg - 25ppg. Total proppant pumped ranges from 400,000#s - 650,000#s on a per stage basis targeting 3,000-5,000 pounds per lateral foot, and average pumping rates range from 80 bpm - 100 bpm. It is widely believed that more densely staged frac designs with higher sand loadings per lateral foot (3,000-5,000 pounds as mentioned above) are leading to much higher reserves per well and ultimately higher recoveries.
In conclusion, Brammer Engineering has extensive and varied experience completing horizontal Haynesville Shale wells. We strive to continually improve our processes as new technology is developed in an effort to meet the demands of a changing market. Let us put our experience to work for you designing and executing your next horizontal Haynesville Shale completion.
