The severe and still-mounting shortfall of electricity in oil country is something that will only be resolved when suppliers and users alike are aware of the needs and the limitations of the system. For E&P companies, communication is the key.
by Al Pickett, special contributor
The shift from vertical to more horizontal drilling in the Permian Basin—as productive as it has been—has brought with it a problem. The oil and gas industry’s expansion in West Texas is projected to push the power transmission and distribution capacity of the region’s electrical system to its limits in the next few years.
Realizing the emerging problem, the Permian Basin Petroleum Association formed an Electrical Coalition Committee in 2014 to address the looming power transmission issues in the Permian Basin.
“The utilities got caught off-guard by the shift [to horizontal drilling],” acknowledged Electrical Coalition Committee chairperson Toni Gordon, who is the power technical specialist for Pioneer Natural Resources.
While the initial efforts of the committee were to develop a dialogue with the region’s utility companies, as well as the Public Utility Commission of Texas (PUC) and the Electric Reliability Council of Texas (ERCOT), to help them understand the problem, the committee is now attempting to educate the Permian Basin’s oil and gas operators about the need to provide their utility service providers with their long-term electrical power needs.
In response to the coalition, ERCOT hired a consulting group, Energy Ventures Analysis, based in Arlington, Va., in the summer of 2015 to assist in a West Texas electrical load study to gather data for ERCOT’s Regional Planning Group. ERCOT is the independent system operator that manages the electrical grid for most the state, including the Permian Basin, and has a central planning role for transmission upgrades and additions. The survey provided recommendations for future steps to be taken by PUCT, ERCOT, the utilities, and oil and gas operators, marking a departure from the survey’s original intent to simply verify potential transmission shortfalls. The study’s change of course occurred because of a lack of participation by the Permian Basin’s producers and midstream companies, according to Gordon.
“Operators are not letting the utilities know what their power needs are going forward,” she explained.
“Response to this study was sparse and represented only approximately 40 percent of the load in West Texas,” added James Meier, a committee member who is vice president of Permian Gas and Power Infrastructure for Pioneer Natural Resources.
Other committee members include Joe De Almeida of Occidental Petroleum, Sam Hakes of Apache Corporation, and Tim Jenkins of XTO Energy.
“Operators in general are here to drill wells and process gas,” Gordon emphasized. “They don’t usually have an understanding of power needs and requirements. However, operators cannot successfully produce long-term without electricity. Operators need to understand their plans for the next two to five years. Additionally, just because an operator shares long-term plans, those plans do not obligate the operator financially. I can provide a reasonable estimate to the utilities what Pioneer plans to drill for the next five years at $40 per barrel of oil, at $60 per barrel, or at $80. Every operator should have a general knowledge of what they plan to drill at certain price caps.”
It Takes Time
One thing the committee learned is that it is a lengthy process to build the required electrical infrastructure, according to Hakes, who is the electrical energy manager-Permian for Apache.
“It takes five years to put in a transmission line,” he explains. “The oil industry can move much faster. But if the oil and gas industry doesn’t have electricity and has to use onsite generation, it is extremely expensive. The PBPA saw we had an issue and the utilities’ infrastructure was lagging behind. The transmission and distribution service providers were hampered by weak infrastructure, and ERCOT was slow to react. ERCOT has enormous pressure handling capacity, especially in the summer heat. We formed a coalition of players in the Permian Basin to understand the issues. We need a voice with the PUCT and ERCOT to find how we can work together.”
Hakes praised the PUCT, which helped mediate the issue between the utilities and the oil and gas industry.
“It helped us to sit in a room with the utilities in Austin and come to a common ground,” he added.
Gordon pointed out that the oil and gas industry represents 20-30 percent of the state’s economy, but the utilities and ERCOT had not kept pace with the rapid evolution of the workings of this region’s oil and gas industry, an acceleration that began with the advent of horizontal drilling.
“There was a disconnect,” she remarked. “Operators would give the utilities their plans. The utilities would then consolidate those plans to submit to ERCOT for future development. But the utilities didn’t have the proper understanding of the load projections they were being provided, so they would diversify the numbers based on historical data. But there is a dramatic difference between a 30-hp motor on a rod pump for a vertical well that requires roughly six to ten kW and a 150-hp ESP required for a horizontal well that requires roughly 110 kW per well. The new horizontal drilling also requires expanding the supporting facility sizes (saltwater disposal wells and tank batteries) to accommodate the increased volumes.”
Of course, the horizontal wells are producing more crude oil, as well as water and natural gas liquids, requiring a need to move more liquids, as well as a need for gas processing plants, which are big users of electricity.
“We have an aging transmission system in need of repair and upgrade. The old 69 KV system needs to be upgraded to higher transmission voltage to handle the increasing electrical load,” Hakes added. “It takes large pumps to move fluids and to get the gas out.”
Gordon cited an example of what the lack of necessary electrical power can mean to an operator.
“If we have to use a generator at the well site instead of a 150-hp electrical submersible pump, that can cost upwards of $40,000 a month compared to $5,000 a month for an electrical pump at six cents per kilowatt hour,” she contended. “If you have 10 wells on generators for several months while waiting on utility power, the cost for the generators could be as much as for a new horizontal well.”
She acknowledged that the shift to horizontal wells “opened everyone’s eyes” with the increase in electricity and water consumption.
“This paradigm has shifted,” she noted.
Gordon said there were three issues when the committee first began its dialogue with the utility companies, the PUCT, and ERCOT: one, the existing infrastructure needed some improvements to improve reliability, but the larger concern was whether the system could handle future growth; two, the ability of the utilities to react customer service issues in a timely manner; and three, educating the utilities, the PUCT, and ERCOT, on the needs of the oil and gas industry.
“Customer service has improved,” she admitted. “It has a ways to go, but capacity and reliability have also improved. We just want to keep that momentum going.”
She added that ONCOR is currently proposing several large upgrades in West Texas to support O&G growth. The committee has worked primarily with four public utilities—Texas-New Mexico Power Company, ONCOR, Sharyland Utilities, and AEP.
Hakes emphasized that when operators provide their utility service provider with their needs, they should be able to expect a response within 30 days to answer the following questions: “Can we serve the load, when can we have it, and what will it cost?”
“We needed an understanding of how the utility market works,” he reiterated. “The most important thing is to get the utility your load requirements as quickly as possible.”
While the transmission and distribution system needs have been upgraded throughout the Permian Basin, Hakes noted that the Delaware Basin in far West Texas and the southeastern edge of New Mexico is in need of every type of infrastructure—including pipelines, gas plants, and an electrical system—to support the burgeoning oil and gas production in that region.
Pioneer’s Meier said he has been involved in power planning for just a year.
“I have been drinking from the fire hose,” he quipped. “The lead time for an offshore platform is a multiyear process. I have learned that building transmission lines is in some ways similar to offshore development planning. Oil and gas industry companies have to be proactive and talk to their service provider. They can’t assume it will be a short lead time to get them the electricity they need.”
Meier added that utilities plan holistically. So if Pioneer predicts, with 100 percent accuracy, what its electrical load needs will be, it is meaningless if other companies with operations in the same area don’t provide the utility with their load demands since power from the electrical grid cannot be reserved.
“It requires everyone’s participation,” he emphasized. “It is not like open season on a pipeline.”
It is important to understand what the load requirements are, too. For example, he said, Pioneer has been using electric submersible pumps, but it is now using more gas lift, which doesn’t require as much power. However, this may not be the same operational philosophy for other companies, a circumstance that complicates trying to use the forecasts that are provided to utilities to extrapolate data for missing forecasts.
On the processor side, an electric-driven gas plant may require a 40-plus megawatt substation, which is a large load in a concentrated area, according to Meier. He acknowledged it is a balancing game to have the needed power.
“Utilities are here to serve the public,” he stated. “If they build an expensive expansion, that cost is shared through potential rate increases for all consumers. Therefore, they need solid justification before being approved for construction, which is a main driver for the long lead times for transmission projects. ”
Meier adds that using electricity is becoming more important as one factors in the economic tradeoff of potentially paying for carbon credits—which may be required by future greenhouse gas regulations—when compared to continuing to use gas-driven power sources.
Pioneer is in a unique situation in that it owns and operates a 1,700-mile power distribution network for its production facilities.
“It has served us well,” Meier stated. “It has helped us troubleshoot problems. We can resolve issues quickly, and we have built up the necessary expertise to manage that infrastructure. The challenge is not all companies have that expertise.”
Contact Your Utility
Meier said he believes the PUCT and ERCOT appreciate the work of the coalition. Now, the challenge is to educate other producers.
“It is much more organized,” he emphasized. “The PUCT, ERCOT, and the utilities are collaborating to find ways to improve the process.”
So what should producers and processors do?
“They need to go to their service provider with their future plans,” Meier continued. “If they want, they can come to the Permian Basin Petroleum Association and we can definitely help direct them where to go and help them facilitate meetings with the proper person.”
“We would love for people to join the coalition if they want to be part of the process,” Gordon added. “Anyone is welcome. But they don’t have to just to ensure their needs are met long-term. If an operator wants to know who to contact, we can provide that information. The important thing is for operators to plug in with their utilities and give them a five-year projection of load to ensure there is enough transmission and distribution capacity. Operators will need to know in advance if power is available and if feeder upgrades are needed to successfully maintain and sustain long-term drilling plans.”
Al Pickett is a freelance writer in Abilene and author of four books. He also owns the West Central Texas Oil Activity Index, a daily and weekly oil and gas reporting service. For more information, email firstname.lastname@example.org.