PITTSBURGH—“We take a very holistic approach to our super-lateral drilling process beginning with our multifaceted engineering approach” said Oleg Tolmachev, vice president of drilling and completions at Eclipse Resources Corp. during the opening keynote of the recent DUG Technology day at Hart Energy’s DUG East Conference and Exhibition. “At the heart of it is our custom drilling procedures to plan how a well will be drilled.”
Eclipse’s approach includes drilling unit geometry, pad spacing and configuration and land position. It also looks at pad size and completions interference for lateral, kick outs and sidetracks.
“One of our most important aspects of our operation at the drilling site is the performance specialist team,” Tolmachev continued. “We have multiple specialists who cycle in and out of the drilling operation, depending on where we are in the well construction phase.”
Eclipse uses onsite, experienced specialists in mud and cement engineering, directional drilling and bottomhole-assembly engineering.
To date, the company has drilled 15 super laterals with an average lateral length of 18,375 ft. Its longest lateral was 20,803 ft—Purple Hayes, which was drilled in 13 days.
In 2018, the company plans to drill about 73% of its wells in excess of 15,000 ft in lateral length.
Eclipse’s well economics for the superlaterals is about $975 to $1,520 (PV10 estimated revenue) per foot with an incremental internal rate of return (IRR) of 130% to 215%.
“We spread our fixed costs for things such as roads, vertical wellbore, pad size and surface facilities across the footage of the lateral,” Tolmachev said.
He said he is often asked about the reserves and seeing any deterioration of reserves as a function of increasing lateral length. He noted that the estimated ultimate recovery (EUR) of Eclipse’s super laterals “are basically outperforming the average shorter-length lateral sections. We believe that this is because of the modern completion technologies we use. We also see that for every incremental foot drilled, the IRR is 215% for dry gas and 130% for condensate.”
According to the Tolmachev, some places are better suited for super laterals than others.
“Surface and subsurface geology plays a huge role as well as the cost of access and environmental and human considerations and the size of the development footprint,” he said.
In Ohio, he added, the horizontal-hole section of the well is relatively easy to drill in terms of geohazards in both Marcellus and Utica-Point Pleasant, and the structure is similar and has no faults, salts or other hazards that are often present in West Virginia or Pennsylvania Marcellus.
In drilling the Purple Hayes well, Eclipse had a stabilized flow rate of 5.6 MMcf/d of gas. The horizontal well has an extended lateral length of 18,500 ft with a total depth of 27,048 feet. It was completed with 124 stages of fracturing.
After the first 24 hours of flowback into sales, the well was producing approximately 5 MMcf of 1,300 Btu gas, with 1,200 bbl of condensate per day. Eclipse also noted that after stabilization and well clean-up, the condensate yield is expected to match the original estimates of approximately 175 to 180 bbl/MMcf of gas. It has recovered 583 MMcf equivalent of gas since it was brought online and has had shallow pressure declines.
“One thing I must emphasize is that drilling a 20,000-ft lateral is not the same as drilling a 10,000-ft lateral twice.
According to Tolmachev, some of the most critical drilling and completion techniques can be separated into three areas—the vertical hole, the curved section and the lateral section.
In the vertical section, torque and drag modeling, including wireline and plug drillout models, is critical. Air drilling for the vertical section must be perfect.
It is also important to select the proper bottomhole-assembly to make a smooth well bore for the directional component. The limitations to step-outs and back-drills must be understood. Excessive slant in the vertical hole can also mean multiple trips and additional reaming.
The curved section is crucial in terms of subsequent torque and drag situations in the lateral section—this is the section where execution must be flawless. The proper tools must be used for directional profile planning and execution.
In the lateral section the proper rotary steering tool must be used to minimize horizontal doglegs. Mud rheology can improve the wellbore stability as well as the use of managed pressure drilling. In addition, the proper mud will also manage gas influx and prepare the well for “frac hits” and production interference.
To manage circulation, three mud pumps are suggested for the best circulation rates at total depth and split-string drill pipe is also used to maximize circulating rates and minimize friction losses.
Operators and service companies work together to push the limits of technology while drilling better quality wellbores and more productive wells.
ConocoPhillips Niobrara producers plus the completion of a South Texas field’s first horizontal well top this week’s drilling activity highlights from around the world.
Results of the completed wells, located in Webb County, Texas, had lateral lengths ranging from 4,976 ft to 8,576 ft with initial production (IP) rates surpassing 12 million cubic feet equivalent per day.