A pair of innovative field development strategies are helping tame the wild, wild Permian Basin.
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Like its salty neighbor to the east, the Permian Basin of west Texas and southeastern New Mexico has been proclaimed dead on many occasions. Such proclamations of their demise, however, are mere exaggerations as the Gulf of Mexico and the Permian Basin continue to thrive.
These historic oil and gas production powerhouses have delivered to global markets billions of barrels of oil and trillions of cubic feet of natural gas over the past century. Through the booms and the busts, the resiliency of each was made possible by the combination of ingenuity and perseverance and by advancements in techniques and technologies.
Specifically, the Permian’s unconventional resources were “opened by the confluence of two major technologies—horizontal drilling and hydraulic fracturing—more than a decade ago. And since then, we have not stopped,” Nicole Champenoy, director of Chevron’s shale and tight‑asset class division, said at the recent SPE Permian Basin Energy Conference (PBEC) held in Midland, Texas.
“From incredible advances across the board—from completions optimization to execution efficiencies where one rig today is doing the work of three rigs from several years ago—the list goes on and on. We did that in a decade. The innovation and technology we have deployed has been remarkable,” she said.
‘Growth Engines’
The basin’s remarkable success occurred in a decade that saw more than one market downturn and was capped off with a crude-oil supply glut eliminated by the global COVID-19 pandemic.
Before the widespread pandemic-related closures began, the Permian produced 4.9 million B/D in March 2020, with production a year later dropping to 3.6 million B/D in February 2021, according to the US Energy Information Administration (EIA) data.
Two years later, in March 2022, production finally shattered the 5 million B/D mark just as the world began to emerge from the pandemic.
In November production in the region stands at more than 5.4 million B/D, according to the EIA’s Drilling Productivity Report.
The Permian continues its reign as the largest oil-producing region in the US, with the Eagle Ford of south Texas and North Dakota’s Bakken plays coming in at 1.2 million and 1.1 million B/D, respectively. As for natural gas, the Permian produced more than 21.2 MMcf/D, second only to the Appalachia region’s production of 35.4 MMcf/D, per the EIA data.
The US is on track to produce 11.8 million B/D in 2022, with that number growing to 12.3 million B/D in 2023, according to the EIA’s Short-Term Energy Outlook.
Much of that oil will likely come from the Permian. In June 2022, the basin accounted for about 43% of US crude oil production and 17% of US natural gas production, the EIA said.
“When we talk about the growth engines of the US hydrocarbon system, they are the Permian’s Midland and Delaware basins,” Chris Paulsen, vice president of business development and strategy for Pioneer Natural Resources, told PBEC attendees. “Everything else for the most part of the US is nominally increasing and not declining in terms of gas production.”
He noted that it will be interesting to see how the growth trajectory plays out with companies pulling back on spending, citing concerns over ESG, free cash flow, and capital efficiency as inflation takes root.
But he does see several positives that will help moving forward.
“We’ve gone from standalone developments, growth at all costs, and a lot of urgency to people standing back and thinking about how to best complete reservoirs to ensure we’re not leaving behind hydrocarbons,” he said.
‘Only Good Wells’
In their quest for the best, the region’s operators have steadily evolved the shale resource potential, learning, and then applying those lessons through each stage of the Permian’s development.
Permian shale producer Diamondback Energy, for example, balances well degradation and incremental reserves in its co-development strategy.
The Midland-based independent holds about 269,000 net acres in the Midland Basin and about 153,000 net acres in the Delaware Basin. The company in the third quarter 2022 reported a net production of about 386,000 BOE/D, with oil production about 224,000 B/D.
When it comes to its development strategy, it is a question of optimizing for net present value (NPV) or optimizing for the initial rate of return (IRR) for a development, according to Al Barkmann, senior vice president of reservoir engineering for the company.
He said in his remarks at the PBEC that both are “fundamentally different development philosophies. One maximizes the number of locations we put into a development, and the other one is trying to maximize the return on every dollar that we’ve put into that development.”
“At Diamondback we’ve developed a saying that represents our approach to the problem: ‘Only good wells’”, he said, explaining that this starts with understanding what the drainage geometry looks like. “To do this we collect microseismic during our well completions to understand what our fracture geometries look like,” he said. “We conduct testing during production phases to understand the interference in hydraulic communications. More recently, with the advancements in geochemistry we’ve been able to refine the vertical drainage profile and that’s helped us in our development planning of the reservoirs.”
These processes help to understand how the wells are communicating with each other, to identify the degree of interference, and then understand the degree of degradation as more wells are added to the development.
“We focus on the highest rate of return zone and plan the development of that zone,” he said, noting that as incremental wells are added into the zone, some degradation is seen in the existing wells. “We can calculate the incremental return for each well that goes into a development plan. ”
The goal is balancing the degradation of the wells in the development plan versus the incremental reserves and the acceleration economics obtained when a well is added, he said.
It is an approach that is paying off. When questioned about the company’s co-development strategy during the recent third-quarter earnings call, Diamondback’s President and Chief Financial Officer Kaes Van’t Hof said that the “math tells us that we’re striking a good balance between IRR and NPV,” he said, adding that he expects the trend to continue, especially as “higher commodity prices bring more zones into the equation and maybe even one or two wells per zone.”
Grand Slam Approach
BPX Energy’s strategy to developing its Delaware Basin acreage utilizes electrified central processing facilities and a massive network of pipes and infrastructure to collect and transport oil, gas, and water.
BPX Energy was in the process of being formed after its parent company BP purchased the US shale oil and gas assets of Australia’s BHP Billiton (BHP) in 2018 for $10.5 billion.
The Denver-based oil and gas producer has about 1 million acres in three core areas that it is focused on developing: the Permian Basin with 84,000 acres, the Eagle Ford Shale with about 371,000 acres, and the Haynesville Shale with about 537,000 acres. The company currently averages about 350,000 BOE/D, of which about 40% is liquids.
BP is committed to reducing its operational emissions by 50% by 2030. To achieve this goal the company invested heavily in infrastructure, including up to $1.3 billion in the Permian.
Grand Slam—the first of the electrified central processing facilities—came online in June 2020 and is the largest infrastructure project to date for BPX Energy.
“We were new to the Permian Basin four years ago,” said David Lawler, chief executive of BPX Energy, during a tour of the Grand Slam facility. “We sat down as a team and said, ‘What would be the way to [develop the resource] right?’ and that’s when we mapped out our electric strategy.
“The very first actions that we took were to secure two 200-MW substations from Oncor Electric and together we installed those as our very first step. We then designed the Grand Slam facility and set up the entire field to flow into it.
“We took a marked change from day one with a whole different strategy, one that we felt was consistent with what the world was asking us to do and what we knew was the right thing to do. That’s the path that we chose,” he said.
Located near Orla, Texas, Grand Slam is an electrified central oil, gas, and water-handling facility that uses a separation and compression system to recover gas that would typically be flared at the wellsite. This allows BP to commercialize the gas instead of flaring it. The facility is also highly automated, enabling the status of operating conditions to be reported in near-real time to reduce the number of operational upsets.
It also serves as the model for future development, with a second facility—Bingo—currently under construction and should be completed in 2023. Two more facilities—Checkmate and Royal Flush—are planned for completion in 2024 and 2025, respectively.
Additionally, the company has built a 400-MW electrical substation network that’s growing to 800 MW once installed in 2025, with the electrical infrastructure enabling the electrification of 100% of its Permian wells by 2025.
As a part of the acquisition, BPX secured more than 140 legacy well locations that the company is transitioning to be in line with its emissions standards. These locations had six different sources of emissions: power generation system, tanks, flare stack, natural gas engine on the compressor, vessel blowdown, and pneumatic control systems.
About 80% of these wellsites are electrified, with high-voltage electric lines replacing natural gas-powered generation systems, according to BPX.
In addition to the centralized production facilities, new wellsites have no tanks, flares, or onsite compression to help further reduce its emissions performance. Electric submersible pumps are used early in the life of the well, with each one flowing production to a separation system before then flowing into field lines that deliver the oil, gas, and produced water to the Grand Slam facility. The entire site is automated and remotely monitored to ensure safe and efficient operations.
By electrifying virtually its entire Delaware position, BPX has actively lowered its methane emissions while also improving its productivity, according to Lawler. “When we acquired the position from BHP 4 years ago, we were flaring approximately 16% of the gas that was produced. At this point, we’ve been able to go below 1% on a consistent basis. We’ve made real progress on flaring and on emissions intensity. And this, in turn, allows us to sell more product and keep natural gas in the pipes where it belongs.”
Drilling new wells and building out the infrastructure to support the production of those wells is ongoing, according to Lawler. “Bringing on both at the same time made the most economic sense,” he said. “We didn’t want to drill wells where we didn’t have a facility like Grand Slam to receive production and capture emissions.”
In 2023 the company plans to do more with electric-powered drilling and well stimulation.
“We’re tapped into the power lines here and we’re one of the leading companies that has figured out how to use and load the power off the lines and directly into the stimulation equipment,” said Lawler. “The whole chain—from drilling to subsurface pumping and compression—will be powered by electricity in many cases.”
BPX Energy’s electrified and automated wellsite design is simplified, using no tanks, flares, or onsite compression to help reduce its emissions performance.
Source: Jennifer Presley.
Electrification Expands
It is important to note that electrification is being adopted by many Permian operators. Diamondback Energy said in its 2022 Corporate Sustainability Report that it incorporates a strategy of having electrical infrastructure in place prior to placing new wells on production, providing line power to a significant number of its wells since 2019. The company also drilled its first well using an electric-powered rig and is planning to use an all-electric frac fleet in the fourth quarter of 2022 and another in early 2023.
Independent shale producer Pioneer Natural Resources announced in October that it is working with a subsidiary of NextEra Energy Resources to develop a 140-MW wind generation facility on Pioneer-owned surface acreage in Midland County.
The project is supported by a power purchase agreement with Pioneer, in which Targa Resources will participate and is expected to be operational in 2024. Pioneer also is a participant in the 160-MW Concho Valley Solar project through Targa’s power purchase agreement, which began delivering renewable electricity during October 2022.
According to Pioneer, the electricity sourced from these projects will power a portion of Pioneer and Targa’s operations of the jointly owned natural gas processing infrastructure and field operations.
Chevron and Algonquin Power & Utilities teamed up in 2020 to construct renewable energy sources to provide electricity to the company’s Permian assets. The 50/50 joint venture has the two companies constructing the largest solar facility in Eddy County, New Mexico.
Sitting on 133 acres of state trust land managed by the New Mexico State Land Office, Chevron’s Hayhurst Solar Power Facility will generate renewable electricity for its Permian oil and gas operations. When complete the solar facility will comprise 56,000 solar panels with six inverter stations with transformers producing 20‑MW of power.
Challenges on the Horizon
While Permian operators have had great success over the past decade, there are opportunities to explore and challenges ahead that could either boost or throw a wrench into the highly developed, well-thought-out plans for the storied shale play.
“There’s a ton of resource in the basin that has been tested or proven in the Tier 2 or noncore areas that are still competitive on the global scale. They may not be the best of the best, but these areas are still better than what many major players in North America and even globally have access to,” said Stephen Sagriff, vice president of intelligence for Enverus.
Sagriff sees the biggest opportunity is unlocking the full potential of the Permian Basin, but that is also its biggest challenge.
“What is the best way to develop those resources? There’s no one right way to do it, but there’s also been a considerable amount of resource impaired by previous development strategies. One of the biggest challenges is going to be mitigating parent/child well interactions using technology,” he said.
Public perception is another challenge that Alexandre Ramos-Peon, head of shale research for Rystad Energy, sees as highly significant. “Public perception has been a problem for a while, particularly with fracturing. That’s the challenge the industry must work on proving that it is not as dangerous or necessarily more polluting than other large-scale industrial activity or other sources of fuel supplies,” he said. “Another is around water disposal. We’re starting to see more concern around water management, sourcing, disposal, and the costs associated with it.”
As for opportunities, Ramos-Peon sees plenty as the Permian provides one of the most affordable sources of supply, supportive governments, powerful lobbies, and sufficient infrastructure.
“We see the case that the US remains the incremental source of supply for years to come,” he said.
Time will tell, but as Chevron’s Nicole Champenoy told PBEC attendees, “We’ve done so much the past 10 years, what could we possibly do over the next 10? There’s a whole lot left here, as we’re only scratching the surface of this resource.”
