Operators continue to push for even greater cost reductions in tools and services than the 20% to 30% that have already occurred. How do service companies deliver improved production in the face of those lower costs? The answer is technology.
Operators continue to focus on saving time, decreasing costs and reducing risks. “What they are looking for are ways to make the well completions more efficient and cost-effective,” explained Garrett Frazier, director of sales and marketing, Magnum Oil Tools.
“The operators are looking for efficiencies. They’re looking for the ability to understand that they’ve stimulated the wellbore to the best of their ability,” Joe DeGeare, president, U.S. sales and operations, NCS Multistage LLC, told E&P.
Dan Themig, president and CEO, Packers Plus Energy Services, speaking at Hart Energy’s DUG Permian Conference May 20, said, “There’s a huge upside in driving efficiencies in our industry. One thing I think we sometimes overlook is effectiveness of our existing completion practices. Driving costs down is only part of it. Our goal is to move those cumulative curves up as well.”
When service companies provide the technology to meet those efficiencies and effectiveness, operators will be looking for that technology, even in a down market.
Reducing well interventions
To paraphrase the movie Field of Dreams, “If you build it, they will come.” Magnum Oil Tools worked to develop a dissolvable plug for hydraulic fracturing. In 2012 the company brought its experience in zonal isolation to the table, partnering with Kureha Corp. and utilizing its unique material to develop a dissolvable line of completion tools. In March 2013 Magnum launched the first of these products, which was called the Fastball―a dissolvable frack ball for sliding-sleeve completions.
On the heels of the Fastball’s introduction, further R&D resulted in the release of the Magnum Vanishing Plug (MVP), a dissolvable frack plug used in plug-and-perf (PNP) completions. The MVP eliminates the plug drill-out process, enabling operators to save significant time, money and risks associated with well intervention.
“Instead of waiting for coiled tubing [CT] to drill out the plugs, clean out the well and then take it to production, all an operator has to do is pump that last frack, change out the frack valve on location to a production tree and send the well straight to production,” he explained.
“This is certainly a step-change technology. We just released it in October 2014. We’re really starting to push a lot of products. We’re still in a hiring mode in that service department to satisfy all the demand,” Frazier said.
“Thousands of stages per month are still being fracked even in this downturn, and operators are looking for significant ways to optimize their operations,” he continued. This new technology is completely eliminating the well intervention process, and operators are reporting that these benefits are invaluable.
At the time of the MVP launch in October 2014, approximately one month before the crash in oil prices, potential savings of eliminating CT were substantially higher than in today’s market.
However, Frazier noted, “Even though the pricing has declined on the cost of the CT operations by somewhere around 50%, Magnum’s dissolvable technology continues to make advances in more efficient and cost-effective completions.”
Forty stages in 24 hours
Costs and time on the drilling side have been reduced considerably. The biggest cost in bringing a well into production is for completion. On the efficiency side, how quickly can the completion work be accomplished?
NCS Multistage completed an 87-stage well in the Powder River Basin in Wyoming for Devon Energy Corp. in less than one hour per stage. All the fracks were single-point injection using NCS Multistage’s CT frack system. The company set a record with 40 fracks in 24 hours with an average of 36 minutes per stage, DeGeare said.
Casing sleeves were run and cemented as part of the production casing string. The frack-isolation tool was run on CT to open each sleeve―in a single CT run.
“When compared with [PNP], which was used on nearby wells, we saved them several days of work,” he added.
What operators are doing “is looking at new technologies to have better conductivity to the wellbore and have the assurance that they have stimulated the wellbore at every point of injection,” he explained.
With this technology NCS Multistage also reduced the footprint in the frack spread by reducing the required horsepower on location by about two-thirds. “All of that adds to their bottom line. We’re gaining new customers all the time. Last month we worked for six new customers. This month we’ve got another three or four new customers. We just finished our first well in the Marcellus, and we’ve just delivered equipment to do a Utica well,” he continued.
“With our system, when we’re done with the frack we can put the well on production. We’re saving operators several days by putting production online more quickly,” DeGeare said.
Three new strategies for effectiveness
Being able to make an impact on poor cluster efficiency is a goal of many operators. Themig discussed three technologies that could impact reservoir effectiveness.
The first is rapid execution strategy, which involves generating fracture complexity to affect rock mechanics of the reservoir. Painted Pony Production Ltd., for example, improved its type curve from 142 MMcm to 382 MMcm (5 Bcf to 13.5 Bcf) in the Montney play in Canada. The rapid execution strategy involves drilling a pair of parallel horizontal wells. One lateral is quickly fractured and shut in with no flowback. The second lateral is then fracked. The goal is to create complex fractures between the two laterals. Openhole completions respond particularly well to this method, he explained.
A second strategy is to ensure flawless execution. Packers Plus introduced its e-PLUS Retina monitoring system to collect and analyze real-time data that can detect a ball that fails to launch or double-shift on a stage, he continued.
The third strategy is the use of dual and triple laterals from the same wellbore. “It is possible to design wellbore construction to do downspace drilling from existing wellbores. This can include dual laterals,” he emphasized.
Evolving isolation valve technology
In long laterals debris can be a problem in activating isolation valves. For the past five years Schlumberger has been developing a debris-tolerant isolation valve that provides both modularity and flexibility.
“We’ve installed more than 1,800 isolation valves in more than 40 countries and 44 clients. We have a diverse portfolio of valves, and we are on our third generation of isolation valves, which is called the FORTRESS premium isolation valve,” said Ali Adlene Arraour, product line manager for safety and isolation valves, Completions, Schlumberger.
“It has become very clear that our clients are aiming for longer reach, deeper wells with more clusters and different laterals. The use of this kind of isolation valve becomes a necessity,” he emphasized.
More than one year was spent debris-testing the new valve. “We compared the actuation force required to open a valve between our old generation and new generation. This helped us modify our design, especially for the ball and mechanical sections. By doing the debris test, we found that the activation force for the old generation valve in a debris-filled well required more than 123% activation force. The new FORTRESS design greatly reduced this requirement to only 15%,” added Alaa Fouad, isolation valves product champion, Completions, Schlumberger.
What the designers did was eliminate more passes that may cause debris to settle out. They reinforced the design by creating a full-bore ball valve. Now the tool is more stable and debris-tolerant, Arraour said.
“We recently closed out a project in the Middle East of over 100 valves used with an electric submersible pump completion. We saw 100% success on the installation,” he continued.
Complementing the proven installation processes that were developed, product reliability was greatly improved, he said. A well in Malaysia was suspended for 4.4 years. The isolation valve was opened remotely the first time as per plan, and the well began producing with no issues, he added.
The first isolation valves were only activated with a nitrogen (N) trigger. The modularity and flexibility in the new generation FORTRESS valve comes from the new triggers (S, N and HP) to meet different well conditions:
• S-trigger is pressure-driven, uses no nitrogen and has a reduced risk from debris locking;
• N-trigger is nitrogen-activated and can be customized for any depth of well or completion fluid; and
• HP-trigger is designed for HT/HP wells up to 177 C [350 F] and 25,000-psi reservoir pressure.