TOGY talks to
Time for Texas tea
Robert Watson, CEO of Abraxas, talks to TOGY about the company’s operations in the Permian Basin and the Bakken Formation, new fracking methods and the effect the new US president is having on the domestic oil and gas industry. Established in 1977, Abraxas is a San Antonio-based E&P company listed on the NASDAQ stock exchange.
Abraxas’ core assets exist in North Dakota’s Bakken and Three Rivers formations, western Texas’ Permian Basin, and southern Texas’ Eagle Ford Shale and Austin Chalk. As of the end of 2016, Abraxas had 1,001 gross producing wells in in its three core basins in the USA. The company used to operate in Canada through its subsidiary Canadian Abraxas Petroleum, which it sold in 2014.
• On fracking with diverters: The most innovative thing we did, though we weren’t the first to do so in North Dakota, was using diverters, of which the polylactic acid diverters appear to be the best. It is the cheapest chemical and doesn’t leave any residue in the formation. We have used it very successfully in our previous six fracking operations in the Bakken formation and results were up 15-20% in the same rocks. We, therefore, attribute that to our new fracking design.
• On the theory behind using diverters: It’s a very simple concept; in a 180-to-200-foot [54.9-to-61-metre] stage of a frack, you have clusters of perforations. When you start pumping a frack, it follows the path of least resistance. If you continue pumping, it all follows the same path. If you drop diverters in that path, however, it closes off that path of least resistance, forcing the frack to change to a new path. If you continue to drop diverters, theoretically, it will lead to 100% of the rock being stimulated as opposed to just a small area.
Watson also discussed the company’s operations in the Permian Basin and the Bakken Formation, as well as the effect the new presidential administration is having on Abraxas’ business. Most TOGY interviews are published exclusively on our business intelligence platform TOGYiN, but you can find the full interview with Robert Watson below.
What are some of the current operations you have in the Permian Basin?
We currently have one rig in the Wolfcamp Shale Formation that’s drilling a two-well pad, and we also have our own rig in the Bakken Formation which is drilling a four-well pad.
We had a very cheap entry cost in the Permian Basin compared to the Bakken Formation. I made an acquisition in the early 1990s of some deep gasfields in the Permian Basin, and they have been legacy assets for us ever since. The horizontal Wolfcamp-Bone Springs play just got closer to our production, and we therefore decided to test it ourselves.
For the past 120 days, our Wolfcamp well has been producing about 700 boepd and 600 mcf [311,000 cubic metres] of gas per day. We also have a couple of hundred bopd in addition to the Wolfcamp, but the Wolfcamp is principally on top of gasfields.
How have advances in technology helped your fracking methods?
We’re using highly concentrated friction-reducer technology which allows us to put a little more proppant in place and eliminates guar from our [fracturing fluid] recipe. The most innovative thing we did, though we weren’t the first to do so in North Dakota, was using diverters, of which the polylactic acid diverters appear to be the best.
It is the cheapest chemical and doesn’t leave any residue in the formation. We have used it very successfully in our previous six fracking operations in the Bakken formation and results were up 15-20% in the same rocks. We, therefore, attribute that to our new fracking design.
We also fracked our first well in the Delaware Basin where we used diverters as well. Not many people, if any, had tried it there yet, and we were thus at the forefront in that regard. Then, all of a sudden, we wound up with a well that other people said was one of the best wells in the basin, both laterally and by area. This is something which I also attribute to the diverters.
It’s a very simple concept; in a 180-to-200-foot [54.9-to-61-metre] stage of a frack, you have clusters of perforations. When you start pumping a frack, it follows the path of least resistance. If you continue pumping, it all follows the same path. If you drop diverters in that path, however, it closes off that path of least resistance, forcing the frack to change to a new path. If you continue to drop diverters, theoretically, it will lead to 100% of the rock being stimulated as opposed to just a small area.
We’re proud and excited of the fact that we consider ourselves on the cutting edge of fracking technology. We are engineering-oriented; I myself am an engineer, and we have more engineers than geologists. Our engineering group stays on top of fracking technology, and we are lucky to be in the Bakken formation and to have access to the [well data on] North Dakota websites.
For example, we were able to data mine about 8,000 Bakken/Three Forks wells when we shut our rig down in December of 2015 and started it back up in November 2016. Moreover, for about six months we didn’t have a rig working anywhere. During this time we went in and looked at the fracking jobs on all 8,000 wells, figured out what proppant they were using and how much, the type of fluid and how much, and whether they were plug-and-perf or sliding-sleeve completions.
These are all the different things that can impact the success of a fracking job. We put this data into a matrix and compared it to the actual results, which is called reported production, and came up with a fracking design that appeared to maximise the stimulation of the rock.
Who would you say is your main competitor in this industry?
We don’t look at others as competitors. Rather, we see them as people who are doing the same things we’re doing. I don’t know of another company of our size that’s growing production as fast as we are and not outspending cash flow. This recent equity raise of ours puts us in a position in which, during the next two or three years, we can drill and generate free cash flow but still have good double-digit production growth.
We have the inventory to do that. We see ourselves producing in excess of 10,000 boepd by the end of 2017 and then maybe 12,000 boepd in 2018, which puts us in a bigger league than we have been in in the past.
With the new administration in place, what kind of infrastructure could be useful to Abraxas as an E&P company?
The Dakota Access Pipeline has a direct impact on us. The delay has cost us about USD 150,000 per month in differentials that we’ll see squeezing when that pipeline is underway. The [new] permitting procedures of the Bureau of Land Management [BLM] have also had a favorable impact on us. Prior to President Trump taking charge, we saw innumerable roadblocks to getting wells permitted. In fact, the government was doing everything it could to slow companies down.
For example, we have a unit in the Bakken that has some federal minerals in it, which means they have jurisdiction over it. Since Trump was elected, the permitting process has gone very smoothly and very quickly and, as a result, we have changed our drilling schedule because what we thought might take another year to get permitted might now be the next pad we move to. We were pleasantly surprised at how fast that happened.
As far as infrastructure is concerned, the private industry is going to do everything we need. There are several large pipelines being built across the border into Mexico for gas takeaway coming out of the Delaware Basin from the Waha hub, which are going to help us.
As far as expansion goes, what are the other projects that you have in the USA? Finally, what primary objectives would you like to accomplish in 2017?
Our expansion plans are only for the Bakken and the Delaware Basin. The goal is to increase our inventory in those areas. Right now, we have about 15 years of inventory, which is a lot for a company such as ours. The well you will drill 20 years from now is worthless today based on today’s values, but if we can continue to build our inventory in the Delaware Basin, we will do so.
Our two main objectives for 2017 are to get production growth to the 10,000-12,000 boepd range and maybe net acreage growth in the Delaware Basin of another 50% from where we are right now. The Bakken Formation is a difficult place [to acquire new assets in] because the core of the Bakken is very tightly held and it is difficult to pick up anything there. Despite that, we’re always looking and will be opportunistic if anything comes up. Most of our focus, though, will be on the Delaware Basin.
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- From the field
- From the field