Halliburton aims for 100% digitisation of assets
Halliburton is working on a project, currently at proof of concept stage, to digitise production across an entire well with sensors providing temperature, pressure and flow rates data, as well as information on how equipment is performing while monitoring emissions levels and any spills. The data accessed via the cloud.
FORT WORTH, Texas—It’s no secret that technology has led to advancements in the Permian Basin.

Average drilling days dropped by 27% to 19 in 2016, compared to 2010. Lateral lengths nearly doubled to 7,178 ft per well as the amount of proppant skyrocketed by 932% to 11.46 million pounds per well, David Adams, senior vice president for completions and production for Halliburton Co. (NYSE: HAL), said during Hart Energy’s recently held DUG Permian Basin conference.

“In this same time frame we saw shale oil production go from 150,000 barrels per day to nearly 2 million barrels per day,” Adams said, adding the change was the result of more efficient drilling rigs, multiwell pads and better well and fracture placement and other technologies.

Most would agree that the industry has done a fantastic job at lowering costs and finding better ways to become more efficient, Adams said; however, there is still room for improvement in recovery rates and optimizing production.

As U.S. shale drillers increase activity amid improving market conditions, focus is expected to remain on technology to drive further efficiency gains and lower costs. But the next chapter in the Permian Basin shale story could see more attention on data and services integration, analytics and automation, and technologies aimed at increasing recovery rates. Such technologies may be the key to growing revenue for shale operators as the price for a barrel of oil remains relatively flat.

Adams highlighted some of technology trends aimed at lowering the cost per barrel of oil equivalent and increasing recovery. Among these is the digitization of the oil field with big data. The challenge for the industry in this area is that “we are very data rich, but insight poor,” Adams said.

Data can be gathered by applying sensors to LWD and open-hole logging tools, for example, as well as tied to surface equipment for reservoir modeling, while real-time platforms allow operators to connect, collect and view data as operations are being carried out. The industry is now putting cloud computing to use to create a common repository for data, he explained, before adding big data analytics gives companies computing power to analyze data. This “enables us to create complex algorithms to find commonalities in the data that help us find solutions.”

Halliburton has put sensors on its hydraulic fracturing fleet, a move that has helped the company gain knowledge on the equipment’s workload and the timing of needed maintenance. As a result, the oilfield service company was able to compare the data to historical data and create predictive algorithms to better understand equipment maintenance needs.

“Historically we were maintaining equipment on a time-based effort,” Adams said. “Now we are doing it truly on the condition and the ware of each piece of equipment, which is significantly reducing maintenance costs. But more importantly for the operator it’s helping to drive reliability in our fleet.”

Halliburton has also embarked upon another project, which is still in the proof of concept phase, involving digitizing production across an entire asset with sensors that will provide data such as temperature, pressure and flow rates. The project also aims to collect information on how equipment is performing, while also keeping an eye out for emissions levels and any spills. All of the information is transferred to the cloud, where it can be remotely viewed and assessed.

“The operator will no longer have to depend in the very near future on having people work around each of their well sites to look at production, to look at how each of their wells is performing,” Adams said. “It will all be done in real time. Similarly, it will all be optimized.”

The technology gives insight needed to help determine which assets are in most need of personnel and when.

Other technology areas include:

Far-field and near-wellbore diverters, which aims to boost stimulated reservoir volume by improving fracture placement, increasing fracture conductivity and creating more complex fractures. The latter is accomplished with far-field diverters. “All of this is for not if we don’t effectively place the right proppant and microproppant into these fractures to ensure that we sustain conductivity for the life of the well;” and

Integrated Sensor Diagnostics, which replaces the typical trial and error approach by using information gathered from downhole sensors. Such information helps with better well spacing, well placement, fracture spacing and completion design, Adams said. “With this we can now do sensitivity analysis with our reservoir models,” so adjustments can be made. One operator took this approach by using fiber optics and microseismic to monitor stimulations. The result led to a switch from 1,000-ft spacing to 600-ft spacing. The operator would’ve otherwise bypassed 40% of its reserves, according to Adams.

“If we leverage the technologies that help us maximize recovery, maximize production and reduce maintenance costs, I am confident that we will see a step change in unconventional economics that will provide a commercial avenue for us all to be successful at flat oil prices going forward,” Adams said.

Velda Addison can be reached at vaddison@hartenergy.com.