KBazin/iStock via Getty Images
KBazin/iStock via Getty Images
The Permian region and its oil and gas plays are a monster resource spanning over 75,000 sq. miles. The Permian Basin covers 55 counties in west Texas and southeast New Mexico and its history goes back 100 years when the first well was spudded in 1920 and produced just 10 barrels of oil per day. It currently produces 5 million barrels of crude oil per day and 20 billion cubic feet per day of natural gas (gross production). If the Permian basin were a country, it would be ranked 3rd behind only Russia and Saudi Arabia. It's big, and with soaring commodity prices, it is expected to grow to 6.5MMbbls/day of crude oil and 26 Bcf/d of natural gas (gross production) by 2027. Due to its low breakeven prices ($35/barrel of oil in core locations), the Permian has received the lion's share of attention over the past decade. Not bad for a region that produced only 800Kb/d of crude oil and 4.5 Bcf/d of natural gas (gross production) back in 2010.
Permian Crude Oil Forecast (RBN)
Permian Crude Oil Forecast (RBN)
Basins, fields and plays go through a natural evolution. Once discovered and drilled, their production soars to new heights but inevitably, production reaches a peak, natural declines take over, and the field goes into terminal decline.
Historical production in the Permian Basin (Federal Reserve Bank of Dallas)
Historical production in the Permian Basin (Federal Reserve Bank of Dallas)
Sometimes, new technology or drilling techniques revive interest in a play and it can go through a rebirth, soaring once again to new heights. The Permian basin went through just such an evolution, and what brought it back was the invention and maturity of horizontal hydraulic fracturing which allowed drillers to tap the oil and gas trapped in shale deposits.
Unconventional or hydraulically fractured wells decline fast. The average fractured Permian well loses over 50% of its oil production and over 35% of the natural gas in the first year. The only way to stem the tide is to keep on drilling!
Permian Basin Shale OIl production 2012-2021 (ShaleProfile.com)
Permian Basin Shale OIl production 2012-2021 (ShaleProfile.com)
Typically, the cores of the basin which produces the most productive and economical wells will be produced first before drilling moves to less economical or non-core areas.
Permian basin - core vs. non-core counties in the Delaware and Midland basins (Federal Reserve Bank of Dallas)
Permian basin - core vs. non-core counties in the Delaware and Midland basins (Federal Reserve Bank of Dallas)
When will the party be over for the Permian? US shale has produced every incremental barrel of crude oil and natural gas liquids needed in the world for the past 10 years, roughly 9MMbbl/d, of which the Permian produced an incremental 6MMbbl/d of crude oil and natural gas liquids or 2/3rds of the additional barrels needed. When the Permian Basin peaks affects everything from the oil and gas industry and OPEC+, to the energy transition, to oil and gas prices, to inflation and our global economy.
I'll save you the trouble of reading the entire article and just give you the answer: we don't know precisely when the Permian will peak. We don't know because there are too many variables, and we can't predict with precision how it will unfold. If truth be told, the EIA does a lousy job of predicting US oil production. Here are 10 years of predictions and every year was wrong, although the ones in 2018 and 2019 are the closest:
10 Years of US OIl Productions Predictions by EIA (JD Supra/EIA)
10 Years of US OIl Productions Predictions by EIA (JD Supra/EIA)
What follows then is our best guess for how this will unfold, but first, let's walk through some definitions.
(1) Original Oil in Place (OOIP) - original oil in place is the total sum of the oil in the basin. If we could magically suck all the oil and gas out of a play, this would be the amount that the basin would produce. When a conventional oil well is drilled, natural pressure in the typical well recovers roughly 10% of the original oil in place (OOIP). Secondary recovery using pump jacks and water flooding can capture another 20-40%, leaving roughly 50-70% of the oil in the ground. Tertiary recovery, using steam or CO2 injection, can capture another 10-20% percentage.
Primary recovery of tight oil and gas in a shale play (which includes lifts and pumps) is small, less than 10% and can range from as low as 2-8% depending on the play. Secondary and tertiary recovery, for example with CO2, is unproven. Refracturing a well is typically only done when the well was sub-optimally fractured in the initial go-around.
(2) Technically Recoverable Reserves or Resources (TRR) - an estimation of the total amount of oil and/or gas that can be produced without regards to cost. Setting economics aside, how much oil and gas could we theoretically produce given today's technology and knowhow - that's TRR.
Every year, the EIA re-estimates these figures for every region/basin in the US and Gulf of Mexico and further subdivides this information into numerous plays within the basin. From that they produce a glorious 22-page report called the "Oil and Gas Supply Module." TRR has been climbing for years because the shale revolution unlocked reserves, and as of Jan 1, 2019, the US is home to 351 billion barrels of oil and 2,900 trillion cubic feet of natural gas that can be technically produced. TRR is a moving target and the calculations to arrive at this figure are crude (pun intended).
Technically Recoverable US Crude Resources (EIA)
Technically Recoverable US Crude Resources (EIA)
Technically Recoverable US Gas Resources (EIA)
Technically Recoverable US Gas Resources (EIA)
(3) Proved Reserves - estimates of oil and gas that we are reasonably certain can be produced economically with today's technology and knowhow. These figures change every year because some of the hydrocarbons get produced, new discoveries are made, we gain greater knowledge of existing plays, prices change for oil and gas, costs to own and produce oil and gas change, infrastructure is planned and we develop new technology and techniques.
The EIA keeps track of this and publishes a report called, "Proved Reserves of Crude Oil and Natural Gas in the United States." The figures are a fraction of the TRR figure - natural gas is 473 trillion cubic feet and 36 billion for crude oil or 38 billion if you include condensate. At today's production, costs and technical knowhow, we have enough proved reserves to last roughly 13 years for natural gas and 9 years for crude and condensate. Here's how our proved reserves have changed over time - note the inflection when hydraulic fracturing and horizontal wells took off. Proved reserves increased substantially even though oil and gas prices plummeted.
US Proved Oil Reserves 1980-2020 (EIA)
US Proved Oil Reserves 1980-2020 (EIA)
(4) Estimated Ultimate Recovery (EUR) - the total amount of hydrocarbons a well will produce in its lifetime.
(5) Well Spacing - Like the name implies, this tells you how far apart the wells need to be to economically produce the oil and gas. If the well spacing is too close, then one well will cannibalize the production from another well, reducing the economics. Typically expressed as the number of wells per square mile. This can be as low as 3 wells per square mile to as high as 20 wells per square mile in tight shale plays in the US.
Note: wells at the surface can be closer together if they are accessing different zones of a play or different plays. The Permian Basin is blessed with multiple stacked plays, for example, in the Delaware side of the Permian basin, the Bone Springs play has 3 zones, and it is above the Wolfcamp play which has 4 zones. Also note, some extreme laterals are up to 15,000 to 17,000 feet long and can span 1-3 miles into neighboring drilling zones. The average lateral is 9,000 to 10,000 feet long in the Permian.
One cross section of the Permian Basin showing multiple stacked plays (EIA and USGS.)
One cross section of the Permian Basin showing multiple stacked plays (EIA and USGS.)
Technically Recoverable Resources for the Permian Basin (EIA)
Technically Recoverable Resources for the Permian Basin (EIA)
Using the stats for the Permian basin, we can illustrate how the EIA calculates TRR. The area with potential is the area of the play that is expected to have reserves. To arrive at the TRR, simply multiply the area with potential by the average number of wells per square mile multiplied by the average estimated ultimate recovery (the average amount a well will produce over the lifetime of the well).
At current production levels and setting aside economics, the TRR says the Permian has 57 more years of crude and 39 years of gas. EIA models US production out to 2050 in part based on the TRR:
US Crude Production Forecast to 2050 (EIA)
US Crude Production Forecast to 2050 (EIA)
However, there are known issues with using TRR to estimate how long a play will last before it declines.
1. As discussed, some areas and sections of plays may not be economical to produce. TRR doesn't include economics in the calculation.
2. Areas that haven't been drilled are unknown in an emerging play. Clarity is gained over time as more areas are drilled and long-term productivity from existing wells is learned. Across a single play or play sub-area there can be significant variations in the play's characteristics, including depth, thickness, porosity, carbon content, pore pressure, clay content, thermal maturity, and water content. For example, the thickness of a play within a basin can vary from section to section. If the landing zone for the horizontal well is too thin, the results can be poor. The TRR may not accurately predict the remaining resources of an undrilled section where the available data is poor.
3. The cores of basins and plays will always be produced first so the average estimated ultimate recovery (EUR) is skewed to the high side. As drilling moves to the non-core areas, the average EUR across the play will decline.
4. Not every square mile of a play can be drilled, and this too can add uncertainty to how long a play will last.
5. Technical advancements have led to more productive wells over time, which have reduced the costs for drilling and completion. Recent wells produce more oil and gas for four main reasons: the horizontal lengths are longer, the amount of water and proppant increased over time, the number of fracture stages and the size of the stages has increased and the wells are better optimized (spacing, distance between fracture zones, etc..). The average EUR across an entire play may not accurately capture this, and the well spacing data may evolve over time given that longer laterals span into other production pads.
Evolution of Permian Wells (EIA)
Evolution of Permian Wells (EIA)
Models have been developed to try to improve predictability. One model that shows promise is the one developed by Wardana Saputra and others. They use Permian well data from 53,708 horizontal, hydrofractured wells (just the tight oil and gas - no conventional wells in this analysis). The study also focusing exclusively on the 3 biggest plays in the Permian: the Bone Springs, Wolfcamp and Spraberry and excludes data from the 7 significantly smaller EIA listed plays. They carefully factor in key aspects like core vs non-core, profitability and the age of the existing wells to build a robust model. The results of that study are a bit sobering:
Forecast of Economic Tight Oil and Gas Production in Permian Basin (MDPI)
Forecast of Economic Tight Oil and Gas Production in Permian Basin (MDPI)
The data excludes the conventional wells which are producing about 400Kbbls/d so you need to visualize that data on top of the unconventional well data to get a sense for the basin's full production. The dataset includes the mean value projection (P50) for 156,000 new drilling locations The purple line is the decline rate of all existing tight oil wells in the basin and shows what a "do nothing" scenario would look like. The red line is the additional wells (55,402) that will be drilled in the cores of each of the plays. The orange line projects the production for the wells (100,314) that will be drilled in the non-core areas of the play and the green line is the "others" section of the Permian that are less uneconomical to drill and won't be drilled unless we maintain oil prices well above that section's $72/bbl breakeven price. The right graph shows the cumulative production for all regions.
This is a model, so they haven't smoothed the data. For representation purposes, they assume every well will be drilled in the core before a well is created in the non-core area. As drilling locations become scarce in the core, drilling will naturally and gradually move to the non-core areas. Some producers like Devon (DVN) have up to 2+ decades of inventory. These two factors will smooth the production line. The model predicts a faster decline to the Permian than EIA data suggests in part because they are excluding uneconomical areas, the conventional wells and some of the sub-basins.
Note the drop-off in 2032 as the cores of 3 major plays are exhausted and drilling moves to the less productive non-core areas. Also note, the model is showing steady production for the next 11 years, 4.5MM tight oil barrels per day, and current projections have the Permian producing 6 MM barrels of tight oil per day by 2027, so that will accelerate the timeline of core exhaustion by roughly 2 years.
The natural gas model shows more longevity because the non-core areas are gassier. Note, this is dry gas, not gross gas, which includes the natural gas liquids. Once the core is drilled out, midstream companies like Enlink (ENLC) who have infrastructure exclusively in the cores will need to migrate to the non-core areas as producers divert their focus.
Forecast of Economic Tight Oil and Gas Production in Permian Basin (MDPI)
Forecast of Economic Tight Oil and Gas Production in Permian Basin (MDPI)
The implications of a peaking Permian are profound. Once the Permian basin is no longer able to produce the marginal barrel of oil, then oil prices will rise to incent new drilling elsewhere. If we add this to the fact that we've missed a couple of major world discoveries which will be felt as early as 2023, we may be headed for a major energy crunch by mid-decade. If drilling in the Permian accelerates to compensate for this and demand keeps rising, the Permian will peak earlier than forecasted. A counter movement is the acceleration of renewable energy and electric vehicles. We may also invent new ways to extract more hydrocarbons from the rock or simply export fracking to other countries. Will it be enough to avert a crisis?
This article was written by
Disclosure: I/we have a beneficial long position in the shares of ENLC either through stock ownership, options, or other derivatives. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.