PITTSBURGH—Home to some of the nation’s longest laterals, technological advancements made in the Marcellus and Utica basins’ has transcended the pace of development across the Appalachia.
Essentially working as a global demonstration project, the roadblocks and winning metrics of the Appalachia’s drilling and completions practices was discussed among a stacked panel of experts from Halliburton Co., Schlumberger Ltd., Encino Energy LLC and Baker Hughes, a GE Company (BHGE), at Hart Energy’s recently held DUG East conference and exhibition.
“Previously we always drilled these wells using conventional tools and we had a lot of issues with sliding and rotating causing a lot of tortuosity in the wellbore. With the technology from various service providers that now have the high build-up rate rotary steerable systems we’re able to reduce the tortuosity, so therefore we’re able to drill farther, a lot longer, and drill some of these record wells,” McKenna Czerneski, BHGE’s engineering lead of drilling services—northeast U.S. land, said.
Expanding on technology’s role as the primary driver of the region’s metamorphosis, Czerneski said that BHGE’s application of geosteering has turned its MWDs into directional drillers, resulting in a more optimized approach to achieving longer laterals.
In order to reach deeper depths, Halliburton’s business development technology manager Des Murphy said it elicits a look into particular developments in service modeling and/or dissolvable technology.
“There are significant challenges in getting the proppant down there, so there’s been a lot of work done at Halliburton in developing friction reducers that are capable of maintaining their state for the full length of the lateral,” Murphy said. “Some of the traditional friction reducers lose their effectiveness as you get down 15,000 to 17,000 feet, so we’re working on making products that can both hydrate quick enough to get the friction down and maintain that state to keep all that proppant down.”
Houston-based E&P Encino Energy LLC is following that path of innovation as an answer to completions difficulties.
“Producing tortuosity obviously reduces the friction, but we’re also looking at increasing the production casing, maybe going to six-inch casing, to help reduce friction on the tools and on the pumping of the job as well to try and reduce the treating pressure on those two stages,” Chris Galle, Encino’s subsurface modeling manager, said.
Simultaneously, the press and noise surrounding well intervention has prompted both service providers and operators in the play to conjure ways to combat the issue.
“It is very critical that we understand the reasons behind well interference and be able to predict with some degree of certainty that when we come back and we put a child well beside a parent, that we understand if we will impact that well when we frac the child. Once we get confidence in whether we’re going to interfere with it or not, then we need to have a plan in place to reduce the effect of that interference,” Murphy said.
With the efforts of his team at Halliburton, Murphy said the company is developing a prediction tool and other intelligent advancements to mitigate the risks of well interference.
“We’ve seen that if we go back in and recharge that parent well with a fluid—it’s not just pumping and it’s all good. We take the regional completion record from that parent well and, utilizing our machine learning and other intelligent algorithms, we’re trying to understand what the optimal volume is to pump into that well to basically recharge that rock. We’ve seen evidence that when we are fracking beside a charged up formation then that frac will tend to grow more symmetrical giving the child well the ability to produce to its full potential,” he said.
The time of the parent well being on production, distance between the child and parent well, and even surrounding geology are some of the anticipated functions of the prediction tool, which Murphy said will help yield interesting results and provide child protection.
“We understand that different rocks will transmit energy different, so what occurs in the Bakken may not occur in the Marcellus or in the Eagle Ford, so getting an intelligent algorithm together that can predict that is a first step,” he said.
Simultaneously, the data curated from the deployed technology is not only easing jobs, but also adding steam to the “rig of the future” train.
“I think going down the remote path is a humongous benefit for not only the service provider, but also for the operator. The way its set up now with the rig of the future basically being in reach, it’s going to be a smooth transition to continue this path,” Czerneski said. “By doing stuff remote, you now have somebody that’s a little more valuable. They can watch over more rigs, get more experience real-time, and see more lessons learned on a broader spectrum as opposed to just being siloed.”
More significantly, it levels out the dichotomy between the majors and smaller one-off operators, she said.
“Having service providers and actually utilizing them to give you the data and lessons learned…now suddenly everyone’s performing at the exact same playing field. It’s helping a lot of these smaller operators to be able to do what they want to do like drill and produce more wells because their efficiencies are right up there with all the major companies,” Czerneski added.
Between the efforts of Halliburton, Schlumberger, BHGE and Encino, the Appalachia will make a good point of reference for onlookers of other shale plays.
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