In benchmarking well productivity, it has become common practice to evaluate wells based on production per lateral foot of perforated length. All else being equal, we frequently see productivity per foot decline for longer laterals. And yet, the industry continues to move toward using longer laterals in the Permian. Why? Because operators strive to maximizing value, not production, and they balance well productivity against well costs. The Texas side of the Delaware Basin can be used to demonstrate the importance of using both productivity per foot and cost per foot to assess performance.
We consider six counties to be part of the Delaware TX: Culberson, Reeves, Loving, Winkler, Ward and Pecos. Reeves and Loving have seen the highest levels of recent activity and each has attracted a number of dedicated operators who are tackling unique operational challenges.
Perforated lateral length varies widely in the Delaware TX, with a large number of wells concentrated in the 4,000-5,000 ft category, the most common lateral length range for 1-mile spacing units. However, almost half the wells in our sample (see Figure 1) exhibit the 2-mile design, residing in the 9,000-10,000’ and 10,000-11,000’ ranges. This is still distinct from some more developed parts of the Permian, where the distribution of lateral length is even more biased to the 2-mile range. Furthermore, nearly 15% of the wells in our sample use 1.5 mile spacing units (7,000’ to 8,000’ lateral length).
Not all well costs rise linearly with the length of the lateral. Even rig and OCTG cost are only partially scalable as the lateral length increases amid no changes in vertical depth. Several cost components are not related to the length of lateral at all, such as the connecting roads and pad construction. With this in mind, it is logical to expect lower drilling and completion cost per foot for long laterals compared to shorter laterals.
Rystad Energy’s well-level cost data from ShaleWellCube confirms this observation for all six counties in Delaware TX. For short laterals, D&C cost per foot typical resides within the $1,400 to $1,650 range. Long laterals rarely cost more than $1,100 per foot.
A simple linear relationship suggests that for every 1,000 feet of additional lateral length, operators are able to save $74 in drilling and completion cost per foot on average. Hence, on average, operators are able to allow a 5% degradation in productivity per foot for every additional 1,000 feet of additional lateral length, when they use a reference point of productivity per foot of a 4,500’ design. In other words, a 9,500’ lateral with 25% lower productivity per foot than a 4,500’ lateral will still deliver identical F&D cost per barrel of oil equivalent (boe).
Cost-normalized productivity helps us to generate more meaningful operator benchmarking, and delivers more valuable insights compared to standard linear normalization. Compared to standard linear productivity normalized to the length of lateral, cost-normalized productivity discounts productivity per foot of shorter laterals to account for difference in costs per foot.
Looking at the most active operators in the Delaware TX by lateral length (Figure 3), Chevron (CVX), Felix Energy (FELI), Parsley Energy (PE) and Halcon Resources (HK) have a high share of wells with 2-mile laterals whereas others—such as Apache (APA) and Rosehill Resources (ROSE)—mostly use 1 mile laterals.
Figure 4a below looks at the total first year two-stream recovery per well, without any normalization. Cimarex Energy (XEC) stands out as a clear outlier and top-performer, followed by CVX, EOG Resources (EOG), ExxonMobil (XOM) and Carrizo Oil and Gas (CRZO). ROSE exhibits one of the lowest recovery rates in the sub-basin, together with MDC Texas Energy (MDC) and APA.
However when productivity is normalized to 10,000’ length (Figure 4b), the picture changes substantially. Most notably, EOG now takes second place, surpassing CVX, while ROSE moves from the bottom of the pack all the way to 5th place. APA also moves up few places, thanks to its short average lateral length.
Finally, in the cost-normalized recovery per 10,000’ laterals (Figure 4c), XEC remains in first place, while CVX switches place with EOG again. XOM still trails the top 3, followed by WPX Energy (WPX) in fifth place and OXY in sixth place.
ROSE perhaps demonstrates most clearly how different the results can be. Without any normalization it was near the bottom in productivity per well. When we normalized for lateral length, ROSE shot up to the 4th rank, just behind CVX and ahead of OXY. Yet we when we normalize for cost in additional to length, ROSE lands in the middle of the pack.
In an environment of heightened capital discipline, this cost-normalized productivity benchmarking is critical to identifying operators who are making the most of their capital budget.