Petroleum engineers consider various factors, including the oil’s viscosity, the permeability of the rock, and the natural reservoir pressure, when they plan reservoir development. Oil wells and reservoirs follow a typical production path: the production rate peaks early, plateaus, and then declines because reservoir pressure drops as oil is extracted. This is known as the “decline curve.” The rate of decline depends on the geological factors and can be moderated with technology (e.g., pumping, injecting water or gas, and enhanced oil recovery techniques) but ultimately cannot be prevented. Because production from individual oil wells and reservoirs declines, simply maintaining a constant rate of oil production requires the drilling of additional wells and the development of new reservoirs, and increasing the rate requires even more drilling and development.
Furthermore, while technology can sometimes be used to temporarily increase production, prolong an oil field’s production plateau phase, or moderate the decline, it requires additional investment and involves temporal tradeoffs. For example, maintaining a field’s plateaued production level for longer typically leads to a higher rate of decline when the plateau phase finally ends. One extreme case of these tradeoffs is Mexico’s offshore Cantarell field. As Cantarell’s production rate began to decline in the 1990s, Pemex, Mexico’s state‐owned oil company, invested in a nitrogen injection project to maintain the reservoir pressure. This brought the field’s production up to a peak of more than 2 million barrels per day in 2004, making it the second most productive field in the world. But production then crashed, reaching an annual decline rate of nearly 14 percent. Recent Pemex reports put the field’s production rate at 160 thousand barrels per day, less than 8 percent of its peak.
Most reservoirs are also “rate‐sensitive,” meaning the production rate affects the ultimate amount of oil extracted. Drilling too many wells or allowing wells to produce at too high a rate can cause a quick drop in reservoir pressure, causing some of the oil to be trapped in the reservoir. Drilling too few wells can also reduce output because of friction in the reservoir. Petroleum engineers calculate the number of wells and the rate at which they produce to maximize reservoir lifetime output.
The costs of oil production are largely fixed: the initial capital costs of exploration and development of reservoirs. Once wells are drilled, the marginal operating costs are very low, typically much lower than the price of oil. Thus, most wells produce oil at a rate that maximizes the lifetime output of the reservoir regardless of changes in price. In other words, in most cases, oil production decisions for existing wells are a binary choice between operating or ceasing production entirely rather than increasing or decreasing their output.
Ceasing production (“shutting in”) involves plugging a well with thick mud and cement. Restarting production requires a drilling rig to remove the cement and pump out the mud. Also, there is a risk that once production is stopped, the porous rock containing the oil will be clogged. A restarted well may not return to the same level of production and may not restart at all.
Finally, not all crude oil is created equal. Different oils from different reservoirs and fields have varying densities and sulfur contents. Refineries are configured with specific crude sources in mind, taking into consideration both dimensions. Any investment into new oil wells or restarting shut‐in wells requires consideration of the quality of oil that will be extracted and where and how it will be refined.
Thus, raising and lowering production is much more difficult than OPEC’s quota announcements would suggest. Production expansion requires substantial planning and management. In general, growing production requires investment in new wells and/or reservoirs rather than increasing the output of existing wells. And that expansion takes time. For example, a Saudi capacity expansion of 1 million barrels per day took four years, from 2005 to 2009.
Investing for the long term? / So, oil production from existing wells cannot be easily increased and investment in new capacity takes time. Do producers invest in new capacity ahead of time so that it can be activated quickly when positive demand shocks occur?
Spare capacity has various definitions, but in general it is the difference between a maximum amount of oil production that can be brought online relatively quickly and then sustained for some period and the current oil production level. The U.S. Energy Information Administration (EIA) defines spare capacity “as the volume of production that can be brought on within 30 days and sustained for at least 90 days.” Saudi Aramco, the Saudi state oil company, defines its “maximum sustainable capacity” as “the average maximum number of barrels per day of crude oil that can be produced for one year during any future planning period … after being given three months to make operational adjustments.”
OPEC, especially Saudi Arabia, had spare capacity in the 1980s and 1990s, but it was largely the result of happenstance, not policy choices. Declining oil demand and concurrent increases in non‐OPEC supply in the ’80s created a large amount of idle OPEC capacity. As oil demand rebounded and the growth in non‐OPEC supply slowed in the ’90s, OPEC’s spare capacity eroded, culminating in a real, binding short‐run supply constraint in the mid‐2000s caused primarily by rapidly increasing demand from China and India. Since then, there has been little excess capacity.
EIA data suggest that most OPEC nations operate at or near capacity except during periods of political turmoil. Table 1 presents the average capacity utilization (oil production as a percentage of EIA estimated total production capacity) from 2003 to 2022 of nine core OPEC members (nations that were members for the entire period). While Saudi Arabia on average utilized 84 percent of its capacity, OPEC as a whole averaged a utilization rate of roughly 91 percent, OPEC excluding Saudi Arabia averaged nearly 96 percent, and OPEC excluding Saudi Arabia, Kuwait, and the UAE averaged 98.5 percent. Much of the underutilization occurred during the historic drop in world oil demand caused by the COVID-19 pandemic beginning in 2020. During the pre‐COVID‐19 period 2003–2019, the average capacity utilization of OPEC was roughly 92 percent while the utilization of OPEC excluding Saudi Arabia, Kuwait, and the UAE was nearly 100 percent.
Why is spare capacity so scarce? It is expensive. And as the Saudi 2005–2009 capacity expansion suggests, it takes time to create. But equally important is that if spare capacity existed in the politically unstable Middle East, the incentives for a military takeover of that capacity would increase. According to energy economists Robert Cairns and Enrique Calfucura: “Having excessive capacity may not be prudent…. Making the industry vulnerable to a relatively easy and quick take‐over, with overly high levels of wealth in developed assets providing overly rich net cash flows, may raise the immediate rewards to revolution.”
What Does OPEC Do?
So, there are constraints on the rapid change of oil production and on long‐run investment in the capacity of OPEC oil fields. The important question for the United States is, given those constraints, how does OPEC behave and how does its behavior affect oil prices?
Our evaluation of OPEC quotas concludes that members’ production exceeded their quotas nearly 80 percent of the time and, on average, members adjusted production by less than a third of the allocated reductions or increases. Additionally, for the last 30 years the short‐run variation of the oil production of three of the most stable OPEC members, Saudi Arabia, Kuwait, and the UAE, is similar to the United States, implying those nations are not utilizing an ability to rapidly alter oil production.
Quotas and cheating / Since 1982, OPEC’s method of coordination has been to set production allocations, or quotas, for each member. The quotas are adopted at OPEC meetings, typically a few times a year, though quotas were set roughly monthly during the COVID-19 pandemic. The process by which the quotas are decided and the factors considered are opaque, though some evidence suggests that production allocations are linked to each member’s production capacity.
There are significant incentives for members to cheat on their quotas. OPEC nations are highly reliant on oil revenues, and producing more oil would allow them to earn more revenue, especially when oil prices are high. And there is little OPEC can do to stop members from cheating. OPEC has no system to monitor oil production by its members and no established mechanism to enforce the production allocations. While Saudi Arabia is traditionally seen as OPEC’s enforcer, its only option to punish cheating by other members is to engage in a price war, flooding the world oil market and ultimately undercutting its own and the rest of OPEC’s oil revenues. In the mid‐1980s, Saudi Arabia seemed willing to do this to punish excessive cheating, but that has not been the case lately.
Cheating on the quotas is common among OPEC members. Table 2 presents the average difference between production allocations and actual production by OPEC members for two periods, January 1993–October 2007 and January 2017–December 2022. (From November 2007 to December 2016, OPEC published its overall production targets but did not release individual member allocations.) During the earlier period, all the included members of OPEC produced more than their quota on average. And the cheating was frequent and large: members’ production exceeded their quotas nearly 80 percent of the time, exceeded their quota by more than 5 percent nearly 45 percent of the time, and exceeded their quota by more than 10 percent nearly 30 percent of the time.
