Replacing one-size-fits-all with custom completion designs
Whiting Petroleum (ticker: WLL) announced first quarter results today, showing net earnings of $15 million, or $0.17 per share. After adjusting for hedges and other special charges, Whiting earned an adjusted $83.7 million in Q1.
Both of these results greatly exceed the company’s Q1 2017 results. At this time last year the company reported GAAP and adjusted losses of $87 million and $54.2 million respectively.
Whiting produced an average of 127 MBOEPD in Q1, down slightly from the 128 MBOEPD the company produced in Q4 2017. This is primarily due to the heavy winter, which forced the company’s Bakken production down by 3 MBOEPD.
The company drilled 24 Williston Basin wells in Q1, and put 19 wells on production in the play. The company brought a further six online in its Redtail acreage, where it is working on completing the DUC inventory.
Whiting expects to keep production roughly flat in Q2, with the current output level near the midpoint of guidance.
Third-party gas processing plant shuts down for repair
The winter is not the only difficulty faced by Whiting in the new year, as third-party gas processing is also a challenge. The company reports the plant that processes Whiting’s northeast Bakken gas production will be shut down for unscheduled maintenance for the majority of May. This will not impact oil sales, but will reduce Whiting’s gas and NGL production by about 150 MBOE and decrease discretionary cash flow by $2 million. Full-year production guidance is unchanged, however.
Whiting also discussed its current fracture design, which has shifted away from a one size fits all philosophy. Instead, the company is using calibrated completion models to determine the optimal completion design for individual areas, and then adjusting these based on the density of nearby wells.
If the company wants to complete a new well that is very close to existing wells, for example, it will use a frac design with lower sand loading, more entry points and higher use of diverters. This design ideally produces a frac that does not go very far into the formation, avoiding the problem of fracturing previously-drained rock. In an area with minimal existing development, on the other hand, Whiting will use significantly higher sand loading to produce the largest fractures it can.
Source: Whiting Petroleum
“Southern Hidden Bench” well vastly exceeds offsets: 4,837 BOEPD – 24-hour IP
Whiting reported it recently drilled a well in the southern portion of its Hidden Bench focus area that utilized this new completion design. The well recorded a 24-hour IP rate of 4,837 BOEPD, significantly outperforming older local wells. The closest of these had an average 24-hour IP rate of 2,647 BOEPD, meaning Whiting’s new well produced 80% higher than the older wells.
Source: Whiting Petroleum
Redtail Niobrara assets are on the block – WLL moves toward Bakken pure play status
Whiting reports it is exploring monetization of its Redtail assets, which would leave the company with only Bakken properties. If Redtail is sold, Whiting will be the only major U.S. E&P that is pure-play Bakken, since Oasis purchased a major Permian position in late 2017.
Whiting President and CEO Bradley J. Holly commented on the results, saying “The team did a great job managing through a heavy winter, allowing us to meet our first quarter goals. For the second quarter in a row, Whiting generated discretionary cash flow that significantly exceeded its capital expenditures. As we move through the second quarter into the summer months, we plan to increase our pace of operations in the Bakken in order to accelerate our growth profile. We remain on target with our $750 million capex budget as the focus shifts from Redtail drilled uncompleted wells to Bakken development in the second half of the year.”
Q&A from WLL conference call
Q: As we look into 2019 and the potential for Whiting to maybe accelerate organically once some of the other priorities are managed, what do you think that the basin can sustain right now in terms of rig additions sort of vis-à-vis the gas processing constraints out there with some of the rising gas processing requirements and how are you all managing through that process and are there any sort of visible chokepoints on Whitings and…?
WLL: I guess I’ll comment first on Whiting’s gas capture rate and follow-up in the latter half of your question. I’ll say that Whiting has one of the higher gas capture rates in the Williston Basin right now. And we work very closely with the midstream providers to make sure they understand our development plans and are building to meet those needs. And I’ll say we’ve done a lot of planning around our gas capture. In terms of how many rigs would the basin support, I guess I don’t have a great number but, yeah, I’d guess probably 60 to 65, somewhere in that order.
Q: On slide 13 of the presentation, it illustrates the large frac geometry completions, that mix, both far-reaching and near wellbore fractures. And I thought this is really interesting since the current industry standard is exclusively a near wellbore completion. I was wondering if you could provide some color on what led you to employ the large frac completion and where is it typically most appropriate and what gains does it achieve versus a purely near wellbore completion?
WLL: What we’re targeting there with completions on slide 13 is, well we’ve got maybe a little bit more geometry, a little more space between wells. We’re targeting the, what we call large geometry fracs that will be more proppant. We’ll still focus on diverter but we’re trying to get further from the wellbore to cover the area around the well.
And then the high intensity near wellbore completions would be where we’ve got a little less geometry, a little less area, and we’re really working pretty hard with diverters to try and create more complexity in the area that we are stimulating. Diverters that will go further out not just in the perforation tunnel but go out in the formation and create more cracks, more intensity and allow us to better drain the area that we’re stimulating.
WLL: So, I would add that there’s no longer any cookie-cutter completions for us. We are rightsizing every completion that we pump based on where we are in the field and what the offsets look like.
Q: Wanted to touch on OpEx a little bit. In 2016 and 2017 you guys really brought down OpEx quite a bit despite production declining, and I realized that some of that may be kind of shedding higher-cost assets. But I also assume that you guys have been working on some additional initiatives going forward to drive that as well. I would fully expect that we get just with greater scale some downward pressure on that front. But can you talk about any additional initiatives you have going forward that can help lower those unit OpEx numbers on a forward basis?
WLL: Sure. Some of the things that we’re currently focusing on and are continuing to focus on would be getting more of our water on the pipeline and continuing to try and renegotiate and bring our price for saltwater disposal down. That’s one of our highest cost categories. So it certainly demands focus. And we’ve made good headway as you’ve mentioned over the last few years and I think there’s still room to go.
And then secondly, the other thing we’re working on is just well intervention rate or reliability on our downhole pumping equipment. And we’ve made very good headway over that through some advanced data monitoring that we use and design work to try and minimize our failures. And I think in our slide show we show that we had – over a year’s period we brought our well intervention rate down by 12%, and we believe there’s some more to go there and we continue to focus on that.
