The DUG Eagle Ford drilling panel hosted detailed drilling plans and descriptions – one, a Maverick Basin approach by consulting engineer Steven Carter for Newfield Exploration Co., and the other, an experimental, discovery-oriented approach by the tag-team presentation by Swift Energy's Homer Adams and Weatherford's Robert Kolkmeier.

"It takes teamwork – constantly communicating with and working with and trusting your partners as a team to build continual success when you're working in a new field."

Partners Swift Energy and Weatherford began testing the program on a series of five horizontal Olmos wells in 2009. The partners would take results, experience and lessons learned from the test wells and apply it to Olmos wells and a seven-well Eagle Ford program for Swift.

The team wanted to determine whether or not horizontal drilling plan was a viable solution for Olmos and then to see if the plan would carry over to Eagle Ford. The first wells were conventionally drilled with mud motors to drill the curve, then they used rotary steerable systems (RSS) to drill the laterals. In the first three Olmos test wells, they used swellable packers in openhole and hydraulic sleeves, and completed nine 500-foot stages using slickwater frac. They reported mixed results including liner parting in the lateral on the third completion. For the fourth and fifth wells they changed to a cemented liner/longstring completion design and pumped 10–11 stages with 300 intervals stages using slickwater frac design and no gel.

By the third Olmos well, they reached total depth (9,560 feet) from the surface casing point in a single run, which marked the second-longest run in the area and they drilled it in less than 15 days. The reduced drilling time has resulted in an overall per-well cost reduction of $4.4 million and cut dry-hole cost to $1.8 million.

The results and lessons were applied to Swift's Eagle Ford wells and where they used slickwater frac, performed more testing on stage lengths, frac volumes and pump rate in unique areas across the play. In addition, they could drill the same well using 400 feet of conductor casing, 5,500 feet of surface casing and drill to production total depth instead of using 100 feet of conductor casing, 1,500 feet of surface casing, 11,000 feet of intermediate casing – all this saved trip-in/out and casing supplies and materials.

Newfield's Eagle Ford well design was to accommodate long-term production of liquids from a wet gas zone. According to Carter the drilling design was driven by completion design, with the production casing sized to accommodate the frac design. The target zone total vertical depth and horizontal length would drive the well geometry design.

Newfield drilled a 12-1/4 inch surface hole and set 9-5/8 inch surface casing to 500 feet then drilled to total depth with a mill tooth but and used one and sometimes two stabilizers. They ran and set 5-1/2 inch production casing using water-based mud and earthen pits while drilling.

When drilling from the kick-off point, Newfield built the well at 8 degrees per 100 feet and used 10.5-pound per gallon oil-based mud with a 4-1 (75%) oil/water ratio. They found that proper hole-cleaning practices were needed and that 400-500 gallons per minute flow was best. The rotary drilling RPM was limited by the mud motor bend. Depending on the hole size area, a smaller annular area made it easier to clean horizontal hole. During casing operations, they spaced out the casing and installed a rotating cement head, circulated the hole clean and pumped conditioning mud and rotated the casing until end of the cement job.