We are hard pressed to guess how many people we talk with and interview each year.  A thousand? Two thousand? Most of these are unstructured conversations on a particular topic, but most wonder off in a variety of directions. Here are some of the themes we hear repeated during these conversations:

Big, long wells are easy to drill. This is about the least newsworthy item on the list, but it sets the tone for the next one, which is…

Big,  long wells are a challenge to complete. From the frac service company point of view, a horizontal well fracs just like a vertical well – turn the pumps on, pump like crazy, mix in a lot of sand and chemistry, flush with water, turn the pumps off – just on a larger scale. From the wireline company’s point of view, however, getting the tools placed properly in the lateral, firing them, and pulling them out of the hole is difficult. It’s getting more and more challenging with every foot of crooked hole the drillers create. But this challenge still isn’t as problematic as the next one, which is…

Big, long wells are almost impossible to produce after the initial production dies off. Perhaps this is an overstatement, but it seems as though every production engineer, every production manager, every oil company production department we’ve ever spoken with about installing artificial lift in a well with an extended reach lateral frowns with exasperation. Lift works great in near vertical wells; lift works poorly in horizontal wells.

Here’s what these three notes might mean: 

Let’s say an oil company drills a STACK or Wolfcamp well that comes in at 5,000 bopd (barrels of oil per day). The reservoir team looks at pressures, volumes, permeabilities, porosities, and estimates that the well has 1 million barrels of oil that it can ultimately recover over the life of the well. Valued at $50/bbl, that’s $50M for a $10M investment.  

But this assumes that the operator can put a lift system in the well that works economically for years after the well’s initial production dies off from 5,000 to, say, 300 bopd in year two, and even less after.

In the first year the well generates 500,000 bbls ($25M). However, after that, keeping the well producing is a pain in the neck -- or maybe impossible -- because  it is hard to get lift systems to work properly in the horizontal section. If the remaining 500,000 bbls of oil can’t actually be economically produced, the question for investors becomes, should the original EUR (estimated ultimate recovery) be reduced in half?

At this point, no one seems to have a handle on what portion of the wells being completed today might struggle to produce the second half of their recoverable oil. This would mean that perhaps we aren’t as awash in oil as we think we are, which would have implications for future US oil shale production and global oil prices. 

Of course, the challenge with lateral lift, and its potential impending failures, is a huge opportunity for the lift companies to develop systems that work well (and cheaply!) in horizontal wells. Without that progress, we’ll witness the premature death of tens of thousands of really sweet gushers. 

So, the race to better technology is on.