Marathon Oil Corp. believes it’s high time that the methodology makes its way into the unconventional sector.
To prove its point, Marathon conducted a series of field trials in the Eagle Ford shale, with the aim of reducing the flat times more typically associated with deepwater well construction. The company specifically set out to evaluate the potential time-savings of offline casing running and cementing in its largely two-string shale wells. In separate trials, Marathon says it proved that the concept saves time in running both the surface and production casing, but the economic results were mixed.
“We’re so efficient in our drilling rates, that a 20% improvement in actually making hole is not anything like a 20% reduction in flat time,” Adrian Binnion, Marathon’s Eagle Ford drilling engineering supervisor, told the IADC Drilling Engineering Committee (DEC) quarterly Technology Forum on March 21. “We concentrated on reducing flat time with the objective of reducing our dollars/ft, which is king.”
Marathon began investigating the concept in late 2015 with offline cementing of the 95/8-in. surface casing. “It was rather simple, as we didn’t have well control issues or the BOP stack to worry about. At that point, we looked at what else we could take offline. The next logical step was proving we could actually run surface casing offline,” he said, during the forum devoted to drilling unconventional resource plays. “The expectations were that we could possibly save about 11.5 hours.”
In subsequent field trials, after the 121/4-in. surface hole was drilled to programmed depth and circulated clean, the crew tripped out, pulled the bottom hole assembly (BHA) above ground level and, depending on rig type, skidded or walked to begin work on the next well. A fit-for-purpose configuration, featuring a 350-ton crane, stepped in to land the casing at between 5,000 and 6,000 ft, after which cementing commenced.
While the three-well field trial progressively reduced casing running time from 18 hr to 13.5 hr, Binnion said, with the crane and other equipment required, the exercise proved to be an economic challenge, essentially breaking even. “We proved we could do this, but in order to make it work, you have to be super-consistent. We’re still working on a system, where we could use it on multiple wells on a pad,” he said.
“Trickier” proposition. Undaunted, Marathon decided to proceed with the more complicated offline running and cementing of the 51/2-in. production casing, where risk mitigation took center stage. “You have well control issues and the BOP to deal with, so it becomes a bit trickier than simply running and cementing surface pipe. We’re talking about moving the BOP stack off the well before it’s cemented, so, of course, that’s going to raise a lot of questions,” he said.
Multi-disciplinary risk assessments, including with offshore personnel, “tried to figure out everything that could possibly go wrong,” Binnion said.
At the onset, to allay the pre-cementing well control concerns, Marathon collaborated with its wellhead provider to engineer a cementing spool to be inserted below the BOP stack. “We have two of these cementing spools that kind of hopscotch across the pad, so we move the BOP stack from one to the next cementing spool.”
In operation, before drilling the 8 1/2-in. production interval, the cementing spool and BOP are nippled up and tested. Upon reaching target depth, the casing running equipment is rigged up, and the string is run in normal fashion and circulated bottoms-up.
Unlike a conventional cementing job, taking the offline route involves first pulling the landing joint and running the pack-off and other hardware. After all is secured, circulation is established across the cementing spool. “Once we’ve established bottoms up and are comfortable there are no issues with gas, and we have added ECD (equivalent circulating densities) and there are no pack-off issues, we nipple down the BOP and skid the rig to the next well and rig up our work platform,” Binnion said.
Meanwhile, once the now-cemented well is verified as exhibiting zero flow, sequential steps include setting the back-pressure valve, rigging down the work platform, disconnecting the cementing assembly and installing an 11-in. hydraulic pack-off, before capping it off with installation of the tubing head. The additional equipment and complexities notwithstanding, Binnion said the five-well test proved economically viable, to the tune of saving around $20,000/well.
“We proved the concept is a technical success, and we could save rig time,” he said. “We wanted to prove up the concept before investing in spools, and we also wanted to make sure we were in a stable market. We didn’t want to make the investment and then lay down rigs.”
Spoiler alert. While Binnion’s DEC presentation was entitled, in part, “Thinking outside the rotary table,” the absence of same, and the inability to rotate the casing, could prove a hindrance to wholesale adoption of the concept, suggests Halliburton Principal Technical Professional Cole Pavlock. “We will have to figure out something different, if we want to rotate casing for an offline production job. For our money, for mud displacement and best practices, casing rotation is the best thing you can do to adequately cement the wellbore,” he said during a separate presentation.
For many unconventional operators, rotating casing during cementing is a standard operating procedure, especially in the Haynesville shale, Pavlock said. “A lot of people don’t rotate and are able to achieve their ultimate goal of zonal isolation. I’m just saying that casing rotation is a better method for cement placement.”
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