Portraying the back-to-back Austin Chalk wells in East Texas as having a few issues is like saying Mr. Einstein may have known a thing or two about physics. First off, there was the double-whammy of high temperatures effectively cutting the mud weight required to hold back an early 14,000-psi reservoir pressure. Then, there were the chronic fractures that generated well integrity risks with practically every foot drilled.
“It was very problematic,” said Bobby Elmore, senior engineer with Signa Engineering Corp, in the ultimate understatement, when describing the myriad pitfalls encountered in the first of consecutive HPHT wells drilled in the field. “We had a real rodeo on that first one.”
What ostensibly was to be “a straightforward horizontal well,” instead turned out to be anything but, with reservoir temperature and bottomhole pressure (BHP) of 334°F and 13,900 psi, respectively. This created all manner of problems, including a casing failure, stuck pipe, tripping and directional issues, not to mention a host of well control incidents that eventually led to a near-blowout. After six failed conventional attempts, underbalanced and managed pressure drilling (UBD/MPD) techniques were employed to successfully land a sidetrack, but not before a number of service and tool failures caught all the principals off-guard.
In a presentation to the quarterly Drilling Engineering Association (DEA) Technology Forum in Houston, Elmore said that after the experience on the first well, the independent operator took no chances with its follow-up, electing to use MPD techniques at the onset, but with a host of modifications.
“For the second well, MPD was selected to avoid the classic Kick-Loss-Kick scenario while drilling,” he said. “The secondary goal was to ascertain the downhole pressure environment limits, but the greatest benefit of MPD was seen while handling several well control incidents that occurred in the HPHT reservoir section.”
Eyes wide open. With the encore, likewise, expected to encounter equally scorching reservoir temperatures and pressures, requiring 18.5 lb/gal equivalent mud density, Elmore said the strategy was to conduct all-inclusive training and have contingencies in place for any eventuality. “When dealing with temperature and pressure, you have to consider the smallest details. We wanted to make sure we had the right equipment in the hole, to avoid the numerous service and tool failures we had on the first well. We learned a lot from our mistakes. For this (second) well, we integrated the well control and flow drilling processes.”
The modifications began with the casing program, which in the first well comprised 95/8-in. and 75/8-in casing with a 4-in. tie-back. The second well ran 95/8-in. casing with higher burst pressure and a 5-in. tie-back. “We did not want geometry to contribute to additional dynamic friction loss, but still allow us to utilize ECD (equivalent circulating density) for BHP control. By going with a 5-in. (tie-back), we were able to reduce pressure by 700 psi,” he said.
A major changeover, he said, was a UBD/MPD BOP configuration with four ram preventers, as well as the annular and rotating head. “On the first well, we had tried a stack with three variable bore rams and had failures. We did a lot of well control mitigation scenarios with this stack, especially with trapped pressures between the components,” he said.
He said integrating the BOP equipment with flow drilling for pressure control allowed the mud weight to be cut back from 18.5 lb/gal to 17.8 lb/gal. “We dropped the mud weight back, so we could see what the well was doing with pressure on the choke,” he said. “We could see what the well was throwing at us and control it.”
Elmore said that, by far, the “greatest culprit” to the operation was the bottomhole temperatures that, after breaking apart downhole tool seals in the first well, required more temperature-resistant materials for the second. “Nobody thought it would get that hot. Anytime you see rubber coming over the shakers, you better shut down and investigate, because you’re in trouble.”
As the combination of temperatures and fractures created havoc with maintaining mud density, pre-mixed batches of 17.8 lb/gal drilling, 18.5 lb/gal balance and heavy 20.5 lb/gal kill mud for tripping were on location, and ready for displacement in the HPHT sections. “In this particular area, fractures would occur every 50 ft to 100 ft. These fractures would explode, when we hit them, and we would get a quick influx. We had fracture zones, where we were losing 18.2 lb/gal mud, and at the same time, had fractures open to the wellbore that were kicking us really hard at 18.7 lb/gal,” he said. “So, we had a half-pound variation in pressure, and you don’t control something like that conventionally.”
For these wells, he said, having a pressure-while-drilling (PWD) tool in the hole is indispensible. “By monitoring with the PWD tool, we understood what we were dealing with, and the measurements minimized unnecessary mud weight adjustments,” he said.
Elmore said that at 14,000 ft in the lateral, after the losses became so severe and it was impossible to trap all the pressure and continue flow drilling, it was decided to TD the well. “The key to this well was understanding what Mother Nature was giving us. Yes, these are tough wells, and some are said to be undrillable, but there is a way,” he said.
- Medley, G. H., R. J. Elmore, R. C. Goodwin and S. Nauduri, “Successfully drilling sidetrack # 7 with MPD/UBD combination after six failed conventional drilling attempts,” SPE paper168944, presented at the SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference & Exhibition, Madrid, Spain, April 8-9, 2014.
- Elmore, R. J., G. H. Medley and R. C. Goodwin, “MPD techniques optimize HPHT well control,” SPE paper 170887, presented at SPE Annual Technical Conference and Exhibition, Amsterdam, The Netherlands, Oct. 27-29, 2014.
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