The relentless growth of oil production in the Permian Basin is a test of the industry’s will to keep drilling the wells needed to fill the gap left by fast-declining older wells.
“The treadmill runs faster over time,” said Raoul LeBlanc, executive director of energy for IHS Markit.
The future cost of drilling so many wells will depend on well productivity. Less production per foot drilled means more wells will be required for growth. A recent report from Schlumberger showed newer Permian wells produce less than older ones, after adjusting for differences in the drilling and completions. “Since wells are not getting more productive anymore, we have to spend more capital to grow,” LeBlanc said.
His presentation at the recent AAPG Global Super Basins Conference on the Permian still concluded that output growth there is likely to continue through 2025. Well productivity, though, is clearly an industry concern based on presentations at the conference.
The growth prescriptions that speakers at the conference offered mixed geology and engineering. The scale of analysis needed to get more from enormous plays, such as the Wolfcamp, focused on details of a microscopic scale.
Occidental has developed a detailed, standardized subsurface workflow that draws on a large company database to evaluate where and how to develop its huge inventory of Permian acreage, said John Polasek, vice president of geoscience for Occidental. The database consolidates its rock and reservoir data as well as results from companies actively working these plays.
Predictions are based on its store of geological, geophysical, geochemical, and petrophysical information. They are compared to the well results. If model predictions are validated by the “actual performance we know we have this figured out,” Polasek said.
Early results are promising. Occidental’s 30-day average production has increased annually since 2012, and it has drilled 26 of top of 50 wells in the basin while drilling 5% of the wells, he said.
Polasek pointed out that those top wells were completed with “25% less proppant than our peers. We feel we have done quite well with less and that is critical to becoming profitable in shale.”
Less Oil Actually
When asked what Concho Resources is doing to increase the well productivity, Christopher Spies, its vice president of geoscience and technology, talked about using fiber optic cable to measure whether fracture clusters are achieving greater fracture density “to get more out of each stage.”
Most speakers, though, focused more on the quality of the rock that they target to drill and fracture.
“The source rock is a reservoir now. We need to take those old tricks for modeling sources for establishing productivity parameters,” and adapt them to unconventional plays, said Andrew Pepper, director of the consulting firm, This is Petroleum Systems.
Taking a multifaceted look at the geochemistry, depositional history, thermal maturity of the rock, and stresses, among other things, represents a change of thinking in the shale sector where the pioneers learned a lot from trial and error.
Pepper, whose geoscience background includes painstaking offshore project analysis for BP, Hess and BHP, is now trying to convince unconventional operators that they also need to look at their plays as petroleum systems using methods adapted for those plays. He pointed out that the test used to estimate oil in place in cores does not consider if the oil can be produced. The problem is that as much as 30% or more of the oil is locked into organic matter in the rock—he called it sorbed—and should be deducted from resources estimates when calculating potential production.
“For example on the edge of the Avalon (play in the Permian) there is a lot of organic carbon. It is a really good source rock, but not a reservoir. A lot of people drilled where there was zero productivity,” Pepper said.
Pepper said he has met petroleum engineers who are open to his message that testing often overstates the resource. He recommends using pyrolysis, which heats the core sample producing vapors that he can use to distinguish between sorbed and producible oil. Instead, the oil estimate is often determined using the Dean-Stark test that uses solvents to extract all the oil, which is lumped together in the resource estimate, he said.
“The flip side of the (volume of) producible oil in place being lower is that the fracs are doing a better job of recovering the actual reservoir fluid; recovery factors are higher than currently appreciated,” Pepper said.
Both Occidental and Cimarex use programmed pyrolysis. Polasek said. Occidental uses it to estimate the fractional flow of gas and liquids, and to validate estimates of hydrocarbon storage capacity based on petrophysics data. “This is really critical. The recovery factor is a big issue,” he said.
While Polasek acknowledges these analyses should discount the size of the oil resource to highlight the amount recovered from the bulk reservoir, even with that smaller total he said realistic recovery percentages remain in single digits.
Cash flow signals
Closely tracking production details, such as the gas/oil ratio can help define the fractured production networks. Some mental readjustments are required “for those of who had experience working with reservoirs with actual permeability,” said Steven Jones, a reservoir engineering advisor for Cimarex Energy.
In highly permeable reservoirs produced by vertical wells, the pressure reduction due to production quickly reaches the boundary of the reservoir. The gas-oil ratio at that point indicates the average reservoir pressure is below the bubble point—the level where gas is escaping from the oil. That stage is called “boundary-dominated flow.”
Those looking for the same pattern in unconventional reservoirs may jump to erroneous conclusions. What makes reservoir unconventional is rock so tight that fracturing is required to stimulate the flow needed to justify development. The pace of the pressure changes there are slow so it takes a lot longer to reach boundary flow than in a conventional reservoir. The gas-oil ratio charts look quite different.
Unanswered questions complicate matters. Researchers are studying if ultra-confined spaces can alter bubble point pressure in ways that affect production.
For those whose mind goes blank when they hear the term “suppressed bubble point,” Jones said there is value in learning to interpret gas-oil ratio trends in unconventional rock. In can help determine the area drained by a well, which is valuable information for those trying to find the best well spacing.
“The point is to look at the gas-oil ratio against cumulative production and when it is clearly rising due to boundary-dominated flow,” Jones said. He added: “Cumulative production at the time the gas-oil ratio is rising in boundary dominated flow is proportional to drainage volume.”
More densely spaced fractures and wells are likely to produce more early on, Jones said. Over time, actual production from lagging early producers might catch up, but companies cannot afford to wait long enough to find out. They often need the early cash flow for the next well.
Without constant drilling, the Permian could become like the Barnett play, where gas production continues but drilling has ground to a halt. “All these plays will end up looking like the Barnett does today. It has some sweet spot exhaustion. They either decline or you have to invest more money,” LeBlanc said.
