Well spacing: The final frontier. These are the voyages of the U.S. E&P industry. Its continuing mission is to explore tight formation hydrocarbons, maximize IP and EUR, and seek out capital efficiency. To boldly go where the industry has not gone before: sustainable free cash flow.
That spacing narrative could create a Hollywood epic. Will our crew overcome the Klingons of well interaction or the Romulans of optimum resource well spacing?
And don’t forget the prime directive. The first well on a section, with its goal of capturing acreage via production while also generating enough IP and EUR to inflame Wall Street’s financial imagination, is the best well that will ever be drilled on that section.
Discussion over 24 to 30 wells per section in stacked plays with production projected on the primary well is enough to excite the imagination of any Starfleet commander. The traditional Starfleet path is found in the narrative of tight formation development: discovery begets delineation, which begets optimization, which begets full-field development. This tight formation narrative invites optimism in a logarithmically optimistic S-curve.
Industry engineers, Scotty-like, have reduced drill days, lengthened laterals and increased water and sand volumes with closer stage and denser cluster spacing while adding more wells per pad. Yet E&P companies are far from full warp power in the face of lackluster commodity prices and the Wall Street Borg.
It turns out that the tight formation developmental model may be nuanced. It appears each step in the overall S curve of tight formation development is a fractal. The transition from optimized multiwell pads to cube, tank, row or patterned development involving $100 million or more of investment per square mile and up to nine months to turn production in-line is colliding with well spacing issues, leading to lower than anticipated results as the full-field development protocol unfolds.
Well interactions—frac hits—could reduce recovery from one-third to one-half of original projections as tighter stage spacing along the wellbore cannibalizes production from neighboring stages while the tighter spacing between laterals cannibalizes neighboring production. Well interactions, many unfavorable, touch 70% of all U.S. tight formation activity.
Well interaction is not all bad. Zipper fracs, or alternating stage completions in parallel wells on a pad, increase resource recovery. Yet the impact of denser well spacing—think of it as resource overcapitalization— abides as the primary industry challenge.
In the current iteration, the industry received distress signals from Concho Resources as full-field development well spacing in the Delaware Basin Dominator project resulted in diminished production. Now Concho is returning to relaxed spacing (880 ft between laterals or six to eight wells per section) in a resource-focused approach. Concho echoes earlier distress signals from across the galaxy in the Midland Basin as part of Encana’s cube development
The problem is structural and relates to how the industry approaches full-field development. It takes time to alter the path of an Enterprise-class spaceship. Each increment of the supply chain (e.g., drilling, stimulation, completion or building infrastructure) creates enormous inertia to stick with a choreographed schedule because of the logistical challenges allocating multiple rigs and stimulation crews in a capital-efficient manner at the surface. The greater the complexity in large-scale development, the more difficult to adapt to dynamic conditions. Consequently, the full-field development stage of resource development will require its own innovative S-curve iteration.
That may call for a flexible approach to completing individual stages and adjacent laterals in the best rock rather than arbitrarily engineered mathematic stage intervals or supply chain schedule inertia.
As Captain Jean-Luc Picard would say, “Make it so.”
The acquisition of privately held GEP Haynesville follows Southwestern’s entrance into the Haynesville earlier this year with its $2.7 billion purchase of Indigo Natural Resources.
The acquisition of Noble Energy makes Chevron the No. 2 U.S. shale oil producer behind EOG Resources Inc. and gives it nearly 1 Bcf of international natural gas reserves close to growing markets.
Shareholders of Houston-based independent E&P company Noble Energy will receive 0.1191 shares of Chevron for each Noble Energy share and are expected to own approximately 3% of the combined company.