It hasn’t been widely reported, but during cold snaps in late fall and early winter, a number of crude oil producers in the Permian Basin have faced a “perfect storm” of events that made it challenging to meet crude pipelines’ vapor pressure standards. At first glance, this may seem like a problem for “the technical folks” to deal with, but in fact the issue has been affecting the ability to move crude to market, and the price of oil at Midland, TX versus the crude hub at Cushing, OK. It has even forced Permian producers to “shut in” some crude production—at least for a time—along several major pipelines in the region because they’ve been unable to adequately prepare their crude for piping or trucking. Today we examine an under-the-radar problem that’s been vexing producers in the U.S.’s leading crude oil play, and affecting oil prices and markets.
The Permian Basin has proven to be one of the wonders of the hydrocarbon world. Falling crude oil prices may have sucker-punched most crude-focused plays in the U.S., but production in the Permian in West Texas and southeastern New Mexico have continued rising. Output there now averages ~2.2 million barrels per day (MMb/d), according to RBN production estimates, up from ~1.6 MMb/d in mid-2014, when crude prices started their long decline. This production gain came as exploration and production companies (E&Ps) focused on their most prolific “sweet spots” and worked to further reduce their drilling and completion costs. But the Permian’s good times have come with occasional challenges, including the need to quickly develop gathering system capacity—and, during periods of very cold weather so far this fall and early winter, difficulties in meeting the vapor pressure standards of the pipelines that deliver crude from the Permian to the Gulf Coast, the Cushing hub and other markets. As we’ll get to, in a way this problem is the result of E&Ps’ success in significantly increasing the volumes of crude produced for each well or pads with several wells.
When oil emerges from the well (as “wellhead crude”), it generally is part of a mix that also includes water, natural gas liquids (NGLs), and natural gas, as well as a number of impurities. As a first step toward preparing crude for delivery to market, this mix is run through a specialized piece of equipment, which in the Permian usually is what is known as a heater/treater unit, which (as its name suggests), flashes off the gas and heats the mix to “boil off” most of the more volatile elements such as NGLs - ethane, propane and normal butane. Doing so not only begins the multi-stage process of separating and preparing crude, NGLs and natural gas for their various end-users, it enables producers to meet the vapor pressure standards of the crude oil pipelines and storage facilities that will be moving crude to market and of refineries, which also store crude and which want the physical characteristics of the crude they receive to fall within certain parameters. These attributes typically include the crude’s API (American Petroleum Institute) gravity, a measure of how “light” or “heavy” the crude is (for more on this, see Don’t Let Your Crude Oils Grow Up to Be Condensates); and the crude’s Reid Vapor Pressure, or RVP. RVP is the vapor pressure of crude oil (or any liquid, for that matter) at 100 degrees Fahrenheit (a July afternoon in West Texas!), and is a measure of how quickly the crude (or gasoline) evaporates—or, to put it another way, how stable and free of volatile, flammable elements it is. Interest in crude-oil RVP grew in the wake of rail accidents that occurred during the growth of crude-by-rail (CBR) out of the Bakken, whose crude has a relatively high RVP of about 11, and especially after the CBR disaster in Lac-Mégatic, QB in July 2013. For more on RVP as it applies to gasoline blending see Regulatory Gas Pressure Party and You’re A Stabilizer Baby for RVP as it applies to Eagle Ford crude.
Our understanding is that while the heater/treater infrastructure in the Permian Basin has been adequate for dealing with the increasing volumes of wellhead crude being produced during the warmer months of the year (when it’s easier for the heater/treaters to do their job of boiling off lighter, more volatile elements of the crude mix), that same infrastructure has often been unable to sufficiently heat and treat all the wellhead crude processed during recent cold snaps in the region, when temperatures sometimes dropped to 20 degrees F (very cold for West Texas/southeastern New Mexico). As we said, part of the problem is tied to the success of Permian producers in focusing on sweet spots and on boosting production from each well—often to 2 or 3 Mb/d per individual well and to 6 Mb/d or more per multi-well pad (many times higher than typical per-well or per-pad production a few years ago).
These gains come from many drilling-and-completion improvements: among them, increased use of pad drilling (from 10 to 20% a year or two ago to as much as 80% pad drilling in 2017), much longer laterals (from less than one mile a while back to up to two miles now) and the use of far more sand per “frac” (10 to 15 million pounds today versus 5 million pounds before). The capacities of pumps, lease automatic custody transfer units (LACTs, which measure the net volume and quality of wellhead crude), and heater/treaters just haven’t kept up. The combination of the much higher volumes being processed and the challenges of sufficiently heating wellhead crude when the outside temperature is so low is reported to have significantly increased the RVP of much of the crude exiting heater/treaters and raised concern at pipelines, storage facilities and refineries.
The concern is related in part to safety—crude with a higher RVP (an RVP of up to 9 or 9.5 pounds per square inch, or psi, is generally considered acceptable) releases more of its volatile elements (ethane, propane, butane, etc.) more quickly, which releases more volatiles from floating-roof crude storage tanks (increasing the risk of an explosion). Crude quality is another major concern. Refineries make more money on their crude input if it has less NGLs entrained in it, and the more NGLs in the crude, the higher the RVP. A higher RVP also can create bubbles in the crude stream, causing pumps to “cavitate” or send shockwaves when the bubbles burst, sometimes creating “pounding” in lines and even damaging them. Floating tank tops could also have problems if the vapor pressure levels are too high. In addition to an apparent shortfall in cold-weather heater/treater capacity, the Permian also may be suffering from a lack of sufficient crude storage capacity at the lease. Typically, it’s recommended that (to allow more stabilization) crude be stored for several hours before being fed into a pipeline or a truck. But again, a number of Permian producers dealing with much higher crude production volumes that they had been accustomed to might not have sufficient storage available downstream of their heater/treaters to allow for in-tank stabilization.
Because refineries are not inclined to accept crude with too-high RVP levels, the burden of enforcing RVP limits tends to fall to midstream companies, which deliver crude to refineries by pipeline or truck and which (we are told) have been cracking down lately by insisting that Permian producers do all necessary testing to ensure that the RVPs remain within bounds. In many cases, the inability of producers in the play to sufficiently heat/treat their wellhead crude has resulted in some Permian wells being either “choked back” or shut in—that is, production at the wells has either been reduced or stopped entirely. This has happened in the past few weeks to scores of wells and well pads along several major pipelines in the Permian, reportedly including Plains All American’s (PAA) Basin Pipeline and Occidental Petroleum’s Centurion Pipeline. Collectively, these production cutbacks during periods of cold weather have reduced the flow of crude to the Permian’s Midland, TX hub, and appear to be having a significant effect on Midland crude pricing.
A significant portion of Permian crude production flows northeast from Midland to the Cushing hub, and it costs about $1/bbl to pipe crude from Midland to Cushing. Typically, that would suggest that crude at Midland should be priced at about $1/bbl less than the Cushing price (to account for the pipeline-transportation costs). But that has not been the case in some time. As we said in (What’s the Story) Midland Premium? (in the summer of 2015), the addition of two major Permian takeaway pipelines earlier in 2015—PAA’s Cactus Pipeline from McCamey, TX to Gardendale, TX and Sunoco Logistics Partners’ Permian Express II from Garden City, TX to Corsicana, TX—left the market with more than enough pipeline capacity out of the play and too few barrels of crude coming into Midland, sparking a “battle for barrels” in Midland and driving up the price of crude there. During the first 10 months of 2016, the Midland price averaged only about $0.20/bbl less than the price in Cushing (see Figure 1).
Figure 1; Source: Bloomberg; RBN
But wait. In November and December, when the RVP issue kicked in for the first time, crude was selling for less in Cushing than in Midland—an average of $0.10/bbl less in November and a whopping $0.80/bbl less (again, on average) in December. And there were a few days last month when the Cushing vs. Midland differential got all the way to a negative $1.40/bbl! What seems to be happening is that the RVP issue is exascerbating the battle for barrels in Midland—effectively cutting supply and therefore making an already bad situation worse. Oh, and by the way, it’s going to be very cold again in the Permian this Thursday and Friday night, so the RVP issue isn’t going away.
In an upcoming episode, we’ll consider the degree to which recent cold-weather RVP issues may be repeated in the future, the effect they may have on crude production in the Permian and crude prices in Midland, and possible solutions to the pressure issue.
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