Fort Worth Barnett flow at 425 MMcfd; Devon looks at shales in nearby basins

June 27, 2002
A large US independent is exploiting a substantial gas resource in the Mississippian Barnett shale in the Fort Worth basin.

Alan Petzet
Chief Editor—Exploration and Economics

HOUSTON, June 27 -- A large US independent is exploiting a substantial gas resource in the Mississippian Barnett shale in the Fort Worth basin.

Devon Energy Corp., Oklahoma City, expects to recover an initial 8% of an estimated 142.5 bcf/sq mile of original gas in place (OGIP) from its core area leasehold in North Texas. That compares with 5-50 bcf/sq mile for the Ohio, Antrim, New Albany, and Lewis shales being exploited in northern and western US basins.

The company has booked 2.1 tcfe of net reserves thus far in the overpressured, unconventional Barnett gas play.

The company suspects it could extract as much as an additional 8-10% of OGIP by restimulating wells multiple times during their producing lives and by halving well spacing to 27 acres from 55 acres.

Wells that have been completed, including a frac job, and then refractured after a few years on production are contributing 80 MMcfd of Devon's gross 425 MMcfd output from the Barnett shale. This compares with gross output of 60-80 MMcfd during 1996-99.

Devon described the Barnett play as low risk, big, and not very unique in the US. The company said it is already looking at other shales in nearby basins.

Barnett play status
More than 120 tcf of OGIP lies under Devon's leasehold of 545,000 net acres centered on a core area in Wise and Denton counties, north and northwest of Fort Worth.

Other operators have completed a few wells as far east as Coppell, Tex., northeast of Dallas-Fort Worth International Airport, and drilling is permitted but minimal in the Fort Worth city limits (OGJ Online, Nov. 27, 2001).

As the city grew, Devon and its predecessor drilled ahead of residential construction, drilled about 30 directional wells among established housing, reserved 5-acre pads to allow operations in perpetuity, and developed a program to notify residents of its activities.

Devon and predecessor Mitchell Energy & Development Corp., which Devon acquired in January 2002, have drilled 1,043 wells. Devon has 890 wells left to drill in the core area based on 55-acre spacing. The core area is about 22% of the company's total acreage.

Devon operates all of the wells with an average 90% working interest.

About 70% of Devon's leasehold is held by production from shallower Atoka conglomerates.

Field highlights
Devon is running 14 rigs, and rig efficiency is currently 2 wells/rig/month, and improving. Drilling and completion costs have declined 15-30% from mid-2001 to $700,000-750,000 this year.

The company's plan for 2002 is to drill 300 development wells, including a horizontal well in the core area, refrac 144 wells, drill 8 exploration wells, and complete expansion of the Bridgeport gas processing plant (OGJ Online, Dec. 7, 2000). It had spudded 170 wells through June 17.

The Barnett is 400-500 ft thick at drilling depths of 7,200-9,000 ft. The Barnett play is an example of targeting a source rock with the drill bit, said Devon geologist and exploration manager Jeff Hall.

The first Barnett completion was in 1981 in the southeast corner of Wise County.

The first 1,500 ft half-length designed massive hydraulic frac (MHF) job took place in 1985, when 14 wells had been drilled. MHFs were used only on the Lower Barnett. Light sand fracs (LSF) took over exclusively in 1998, also the first year of Upper Barnett completions.

Devon has completed six pilots on 27-acre spacing. During the next 6-12 months it will evaluate the pilots and determine how to proceed with infill programs in areas still spaced at 55 acres.

It called the play highly economic. It put gross profit at $1.83/Mcf with the gas price at $3 and $2.80/Mcf at $4.

Well refracs
Devon said refracs in the field may double the wells' initial reserves.

The range of reserves added after refracs is from less than 0.5 bcf to more than 1 bcf, and all of those wells made money, said Devon operations manager Mark Whitley. Finding costs tend to run $0.45/Mcf for refracs vs. $0.75/Mcf for new wells, although the production decline after a refrac is less steep than that of a new well, he said.

A refrac captures more reserves by introducing a new fracture at a different orientation from the wellbore than the original fracture. The first fracture runs generally NE-SW and the second more E-W.

Initial refracs in the Barnett have also restored production to a rate more or less that obtained after the original completion.

Devon told security analysts in late June that as many as two to six refracs might be possible on each well, and that the optimum length of time it should deplete one fracture before the next refrac is a matter of close study.

However, no well has yet been treated to a third frac and the first could be 2 years away.

Devon will begin refracs of LSF wells this year. About 150 original MHF wells remain for LSF refracs.

Devon put the cost of refracs at less than $300,000/well. Mitchell performed 100 refracs in 2001, and Devon said refrac performance is consistent.

Expansion areas
Devon is beginning to explore extension areas north, west, and south of the core area.

The company's 2002 plans in those areas are to interpret 175 miles of 2D seismic data, acquire 53 sq miles of 3D data, acquire more acreage, and drill 8 wildcats. Those will include 3 horizontal wells, two in southeastern Denton County and one that has spudded in southeastern Parker.

In Denton and Wise counties, Devon would add to the core area 90,000 acres to its north and east, providing 1,300 locations on 55-acre spacing or nearly double that number on 27-acre spacing.

Another expansion area involves exploration potential south of Fort Worth in Johnson County and west of the city in eastern Parker County.

The core area has two Barnett lenses with limestones above, between, and below. Under Barnett are Viola and then Ellenburger, which is often wet. Viola pinches out west of the core area.

The lean area east of the pinchout, which engineers wrote off about 3 years ago, now produces more than 100 MMcfd, Whitley said. Rich gas is piped to Bridgeport, while lean gas goes directly into pipelines.

Some seismic work is aimed at identifying areas where the Viola is wet. Service companies and Devon are searching for ways to frac the Lower Barnett without breaking into the Viola. Frac out of zone due to faulting was the fate of Devon/Mitchell's only two unsuccessful Barnett wells.

North of the core area towards the Muenster arch, Viola gets porous and can contain water or gas, Hall said, and Devon will work with 3D seismic there.

Hall said the better opportunities are in Johnson County, where the Barnett is thicker and the upper frac barrier is absent. The 2002 program includes the drilling of 3 vertical wildcats in Johnson County.

Devon puts OGIP at 26 tcf in the 120,000-acre core area and 20 tcf in the 90,000-acre core expansion area, within the limits of the gas window, Muenster arch, and the Viola barrier. It provides no OGIP estimate for the 335,000 exploratory acres.

Contact Alan Petzet at [email protected].