LOUISIANA HAYNESVILLE SHALE—2: Economic operating envelopes characterized for Haynesville shale

Jan. 9, 2012
The Haynesville shale has grown into the largest gas shale play in the US due to favorable geologic conditions and technological improvements in drilling horizontal wells and stimulation treatment.

Mark J. Kaiser
Yunke Yu
Louisiana State University
Baton Rouge

The Haynesville shale has grown into the largest gas shale play in the US due to favorable geologic conditions and technological improvements in drilling horizontal wells and stimulation treatment. Unconventional gas resources are abundant, but their development is particularly sensitive to technologic risk, geologic uncertainty, and gas price.

Misunderstanding aboveground risk, however, can have an unpleasant effect on project economics.

The two defining characteristics of shale gas development in Louisiana's Haynesville shale are the high costs of drilling and completion and the high degree of uncertainty surrounding physical and economic parameters that affect project returns. Project risk is caused by uncertainty from unforeseen or unknowable conditions or events that affect costs or performance.

The purpose of this article, the second of three parts, is to examine the price sensitivity of Haynesville wells. We characterize the operating envelope under which Haynesville wells are economic and describe the profit space based on a technical review of cost characteristics. Two-variable factor models are combined with type curves to construct before and after-tax profit matrices.

The majority of Haynesville wells fail to break even on a full-cycle basis at prevailing gas prices. This harsh economic reality will control future activity after new entrants fulfill their drilling requirements.

For $6/Mcf gas, average wells are expected to generate pretax returns between 1% and 11.5% for $1 to $0.50/Mcf operating expenses and $7.5 million capital expenditure. P10 wells are expected to generate a pretax return of 52% for $7.5 million to 25% for $10 million capital expenditures and posttax returns of 20% to 40%. We show that gas prices during the first year of production are an important determinant in profitability.

Shale play economics

For shale gas wells to be profitable, they must produce at sufficient rates and volumes to recover the high cost of drilling and completion. The tradeoff between perforated length, completion strategy, and production is a key consideration in cost and returns. Shale wells produce smaller volumes per well compared with conventional resources, and typically, per-well profit margins are smaller. Recovery factors are also much lower than in conventional gas plays, typically on the order of 20-30%.

Unconventional reservoir systems are governed by a large number of factors and interrelationships that are difficult to accurately discriminate. Geologic and reservoir engineering and economic modeling have lagged the science of hydraulic fracturing, but progress continues to be made.

Production risk is higher in shale plays because of the need to use advanced technologies and constraints imposed by the reservoir. Completion technology and geologic controls are considered the primary determinant of production and economic success. Completion strategies involve many factors, including lateral length and number of stages, method of isolation, completion and fracturing techniques, and proppant type and concentration. Strategies evolve with experience and experimentation, and performance are influenced by many interrelated parameters.

Cost data

Acquisition

Over the past 3 years, lease bonuses on state lands in the Haynesville region have ranged between $5,000 and $25,000/acre and averaged $9,000/acre. The average royalty rate on state land has ranged from 22.5% to 28.5%, while royalty interest and overrides on private land generally range from 20% to 30%.

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