Horizontal Drilling Successful In More Than Just Fractured Carbonates

(Tech Connections Column, February 2001, American Oil and Gas Reporter)

Historically, 88 percent of U.S. horizontal wells in the lower-48 have been in fractured carbonates, primarily the Austin Chalk and Bakken Shale. A study funded by the U.S. Department of Energy examines the potential from horizontal wells in the United States in four specific light-oil geological settings.

The total potential indicated at an oil price of $24 a barrel is an incremental 965 million barrels. The potential from fractured carbonates, profile modification applications, thin bed applications, and continuity improvement applications, respectively, is 318 MMbbl, 401 MMbbl, 128 MMbbl and 118 MMbbl. Misconceptions about horizontal technologies are the biggest impediment to more widespread application by U.S. independents.

A common misconception is that “rules of thumb” comparing horizontal to vertical well costs and performance are applicable. They are not; each situation demands a site-specific evaluation. Since most drilling problems are encountered in the curve section, the incremental cost of drilling further once horizontal is minimal. Incremental costs for drilling further are also kept low because most horizontal sections can be completed open hole, even in relatively unconsolidated reservoirs. High-cost areas of operation are also very amenable to horizontal technologies, since the incremental cost for horizontal technology is small relative to the total.

The driving forces that encourage horizontal technology are both the lateral access to the target reservoir and the “line versus point source” concept, which recognizes that a line source makes more efficient use of reservoir drive energy. When employing horizontal technology, the key is not just higher production rates, but improved recovery.

Reservoir characterization and visualization technologies are critical tools for making site-specific evaluations. Except for complex situations, analytical models are sufficient for making screening decisions. For complex situations, numerical simulation is probably warranted.

Many factors control success. First, exploitation efforts must employ fully integrated, multidisciplinary teams, and these teams must incorporate the driller. Second, the team must not overlook the basic steps during the vertical well stage. Third, each well must be tailored to site-specific conditions. Fourth, one must work backward, that is, consider the reservoir first and the “why” of horizontal technology before getting into the details of “how.” Fifth and importantly, expect and plan to make real-time adjustments in response to what is encountered during the drilling process.

Optimally-applied horizontal technology can be very profitable. Texaco’s Aneth Field in Utah was discovered in the 1950s, and waterflooding with 40-acre five-spots was initiated soon after. By mid-1990, the field was nearing its economic limit. Texaco employed multilateral, openhole re-entries to convert the waterflood to a line drive pattern. This comprehensive re-entry program increased production 1,500 barrels a day over projected base line decline. Through mid-1998, 1 million barrels of incremental oil had been produced.

Furthermore, as Texaco progressed up the learning curve in drilling horizontal wells, later wells cost less and were more efficient. Placing multiple laterals in each existing well achieved further efficiencies.
Texaco applied knowledge gained from the Aneth Field to the Bryant-G-Devonian Field in the Permian Basin. Discovered in the mid-1960s, this field was developed with 19 wells in eight sections. Gas cycling of the retrograde condensate reservoir in the mid-1970s proved unsuccessful because reservoir permeability was too low and too discontinuous. Gas cycling was stopped, and primary production dropped to 2 million cubic feet of gas a day plus 100 bbl/d condensate.

In 1994-95, a vertical well, infill-drilling program added 11 wells, each of which initially produced 500 Mcf/d. Texaco conducted its first horizontal re-entry in early 1996 with good results. This success resulted in 11 re-entries and 19 new wells during 1996 and ’97. The company also added 13 new wells on the flanks of the structure outside the unit boundary. Following activity decline in 1998, the 1999 program concentrated on adding second laterals to existing wells.

The net result was gas production increased to 60 MMcf/d, a 30-fold increase from 2 MMcf/d prior to horizontal drilling activity. Condensate production was increased by nearly the same ratio. Expected recoverable reserves were increased 300 percent. As in the Aneth Field, there was a learning curve, and final drilling and completion costs were $650,000 a well less than initial wells.

These field examples illustrate the potential of properly designed and implemented horizontal technology applications. However, the vast majority of these successful applications have been achieved by the major international operators.  The time may be ripe for more independents to learn how to apply the multidisciplinary asset team approach to horizontal drilling. 

Editor’s Note: The author wishes to acknowledge horizontal technology insights and case studies shared by R.G. “Bob” Knoll with Maurer Engineering Inc. during a Dec. 8 PTTC workshop  in Los Angeles.