Conventional and Unconventional Development Part II: Extrapolation of Unconventional Horizontal Development to Low Permeability Reservoirs
Authors: Pearson C. M. , Fowler G. , McClure M. , Rylance M. 
Published: January 2025

The combination of hydraulic fracturing and horizontal wells has been very well established. Initially deployed in moderate quality conventional style reservoirs (Owens et al., 1992), (Abou-Sayed et al., 1995) and (Cipolla et al., 2000). Then, more recently, and even more extensively within the unconventional environment (Steward, 2013). However, there has been very little application of this combination within the intermediate "low perm" or "tight" arena, as the majority of onshore low permeability/tight oil fields at least in North America (NA) were developed some 30 to 50 years ago using the conventionally fractured vertical well approach.

Therefore, as the Rest of the World (RoW) begins to develop their own tight-resources, an often-asked question is when does conventional fracturing transition into unconventional, and when can a conventional viscous fluid, high-density proppant-pack be replaced by slickwater placed partial "proppant" coverage? The scope of this Part II paper is to take a field-matched, optimized horizontal slickwater design used for a Bakken unconventional development and conduct a modelling study to investigate its direct applicability to low permeability / tight plays with several orders of magnitude increase in permeability. Development costs for a 2x1 mile horizontal development spacing unit were then compared to equivalent conventional high-permeability proppant pack completions for a vertical well development of the same area.

URTeC 4043244 (Pearson et al., 2024) described the process that was employed in optimizing a Bakken development calibrated against a five well program within a 2x1 mile spacing unit – one parent well followed by 4 infill wells drilled after some 3½ years of production. A multi-variate approach to the development optimization demonstrated a variety of options which could be selected, based on the individual economic criteria that are being optimized. Using this dataset, which had a base permeability of 6 µD, the development design was re-run with permeability (and commensurate porosity) increased through 4 orders of magnitude up to 60 mD. Since the created horizontal well fracture half-lengths were on the order of 600+ ft; the development costs were then compared to an equivalent vertical well development of 32 wells on 40 acre spacing (1,320 ft well separation with fracture half-lengths of 660 ft) in order to compare performance of the horizontal well development to the same area of theoretical vertical well development.

Finally, the economics were considered by assigning the average development costs to each of the horizontal and vertical well cases for both onshore and offshore cost environments in North America and RoW. This allowed the recovery results to be presented as tables of Unit Development Costs (UDC), calculated as capital $ spent / BO recovered, for the two distinct development approaches as an underlying function of the reservoir permeability.

The results demonstrate that for all cases that were considered that a horizontal well development program will generate lower Unit Development Costs. Furthermore, even in expensive RoW-Onshore and RoW-Offshore completion environments, that horizontal well development provides the only path for economic development of µD to sub-mD reservoirs.