EOR, proppant, laterals
Core Laboratories (ticker: CLB) Chairman and CEO David Demshur identified three major trends in modern unconventional operations in the company’s recent conference call: unconventional EOR, smaller proppant and dealing with friction in increasingly long laterals.
Unconventional EOR can improve single-digit recovery factors
The first major trend Demshur identified is the increasing interest in enhanced oil recovery from unconventional reservoirs. While unconventional plays often have tremendous resources in place, like the 20 billion barrels of oil in the Wolfcamp shale, current development techniques have recovery factors of around 8% or 9%, meaning a tremendous amount of oil is left in the ground. Enhanced oil recovery could improve this percentage, allowing companies to access further oil in the ground.
According to Demshur, “early work performed by Core has indicated possible recoveries increasing from an average of about 9% in shale reservoirs to 13% to 15% by utilizing engineered gas adsorption techniques, gas recycling and the laws of physics and thermodynamics.”
“Ongoing dynamic flow tests look promising, and Core has developed gaseous tracers that will be used to determine the positioning and effectiveness of this engineered gasses in the EOR process. We are now investigating the role of dense and complex completion and stimulation programs and the role in the EOR process. Increased recovery rates of these magnitudes can increase the clients’ return on their invested capital by 40% to 50%, boosting their free cash flow and shareholder value.”
The Q&A portion of the call allowed further EOR details to be fleshed out.
Q: So a couple of questions around EOR. Could you talk about the incremental cost associated with basically taking the recovery from 9% to 15%?
David M. Demshur: If you look at what is going to be needed at the well site, you’re going to need some compression assets, where you’re going to take this engineered gas and inject it into the reservoir. And then, you’re going to need on the production side and it might already be present. You’re probably going to need some separator equipment, because what we’re going to do is, inject this gas at pressures into the reservoir and temperatures, and then go ahead, and in the separator, go ahead and reduce those temperatures and pressures, so we get hydrocarbons dropping out of that engineered gas solution.
So, if we look at what the incremental adds are, probably somewhere between $1 million and $2 million of additional assets at the well site or at the pad site. If you look at that versus an increase in, let’s say, a recovery of EUR of 1 million barrels, taking that at 10% recovery rate to a 1.5 million barrels – 500,000 barrels, a recovery rate of 15%, so you get an extra 500,000 barrels for a $1 million or $2 million, I think, that improves the return on invested capital for our client by a long way. So, that’s kind of what we’re looking at for additional cost.
Q: And what basins are you looking at for this particular type of unconventional EORs?
David M. Demshur: Right now, all basins, and we’ve got projects in essentially from all oil – liquids-rich shale plays.
Tiny proppant can make frac jobs more effective
The second major trend Demshur mentioned is interest in using finer proppants or micro proppants in the initial procedures in a hydraulic fracture program. Theoretically, using small proppant in the first stage of a fracture treatment will mean the small proppant will be pushed far into the fractures, where only tiny sand grains can fit. In a standard frac treatment these narrow fractures are too small for proppant to fit, meaning these fractures close after the treatment if complete and do not contribute to production. Small proppant can keep these fractures open, giving wells a much larger fractured area to produce from.
Core Laboratories has an industry-wide proppant consortia with a 30-plus year history that evaluates proppant performance. According to Demshur, this consortium is “boosting its evaluation of 100, 200 and 400 non-API mesh sand. These micro proppants are thought to open secondary and tertiary fracture patterns, significantly increasing stimulated reservoir volume, therefore, increasing initial flow rates, as well as the estimated ultimate recovery from a wellbore.”
“Micro proppants pumped during the placement of the frac pad could potentially boost these curves by tens of thousands of barrels with very little added cost. Pumping 70 and 40 mesh sand late in the frac process also appears critical for success.”
Lateral lengths topping out?
The third trend identified by Demshur may be unexpected, lateral lengths may have reached a maximum. A standard fracture treatment involves pumping large volumes of water and sand down very narrow pipes, sometimes for several miles. This creates losses due to friction, which means that pumps at the surface must operate at higher pressures to maintain the same pressure at the formation. The longer the lateral length the higher the pressure losses, and therefore the higher the surface pressures must be to compensate. Too-high surface pressures can cause a host of problems, meaning companies cannot drill infinitely longer laterals.
Core is looking to solve this problem by developing new friction-reducing additives, which may decrease the required surface pressure and allow longer laterals. Demshur further discussed this problem in the Q&A portion of the call.
Q: Your comments about lateral lengths somewhat hitting their peak at this point was very interesting to me. Could you perhaps expand a bit on that and the science behind that? It’s suggesting that perhaps we cannot drill further lateral lengths and there’s going to have to be some maybe reduction in additional cluster spacing perhaps closer to the wellbore?
David M. Demshur: Right now, the average lateral length is about 10,000 feet that expended from a number of years ago from an average of 7,000 feet to 8,000 feet. The problem is, the frictional forces in pumping the proppant and fluids at or above 10,000 feet, you don’t get enough effective pressure to actually do a good job in fracturing the reservoir.
We’re looking at friction reducers to enable longer laterals to be drilled, because we are still in the camp of longer laterals, more proppant, more stages, closer clusters to increase the size or the amount of this stimulated reservoir volume, because that is a critical factor, not only in initial recovery efforts, but in what we see as the next coming wave of EOR in unconventional reservoirs.
