Hydraulic fracturing combined with gravel packing in high-permeability gas reservoirs (frac-packing, or F&P) is currently considered the most reliable completion technology for offshore Gulf of Mexico (GoM) completions. Such treatments are designed to bypass damage near the wellbore and prevent formation sand production. Despite the relative maturity of this technology, there has been insufficient focus on non-Darcy flow, particularly in the fracture, in F&P wells in the literature.
Previously published work, based on single-phase inflow equations, acknowledged that a very high pressure drop exists near the wellbore in F&P completions, but this has been usually attributed to a limited number of effective perforations. In this work, we used reservoir simulation and an inflow equation for pressure drop across the perforation tunnels to quantify the relative pressure drop contributions in the reservoir, fracture, and gravel pack system. We considered both non-Darcy and multiphase flow in our evaluation.
We found that non-Darcy flow in the fracture and perforation tunnels results in substantial near-wellbore pressure drops for typical F&P gas wells with gas rates greater than 0.2 to 3 MMscf/D/ft. Increasing fracture conductivity and fracture lengths and using proppants with lower non-Darcy flow coefficients can help in reducing non-Darcy pressure drops and optimizing F&P completions.
Introduction
The frac-packing technique for sand control resulted in a significant productivity improvement compared with conventional gravel packing in the early 1990s.1 Frac-packing employs tip-screenout (TSO) hydraulic-fracture stimulation pumped with screens in place to reduce operational costs. By 2002, approximately 1,000 F&P treatments were being performed on a yearly basis. U.S. operators now apply this method to complete more than 60% of offshore wells.1
To pay back the large investments required to develop unconsolidated, high-permeability, deep-water reservoirs, it is necessary to produce wells at high rates. F&P wells are often completed subject to proppant size limits and produced subject to pressure drawdown limits to control sand production. At high rates, well productivity is often affected by non-Darcy flow, which increases the pressure drawdown at a given rate, or decreases the flow rate at a given pressure drawdown. Thus, optimizing F&P wells involves designing the completion and operating the well to achieve a balance between (1) production rates, and revenue, (2) completion costs, (3) non-Darcy flow effects, which reduces well productivity, and (3) prevention of sand production. To do this optimization requires knowledge of the pressure drops in all components of the completion-gravel pack, hydraulic fracture and reservoir-and the factors affecting these pressure drops. If we determine that we have excessive pressure drops in components of the system that we can affect, then we may be able to design better F&P treatments and improve the well productivity and profitability.
The history, application, design aspects, and economic benefits of F&P treatments have been widely discussed in the literature.1–5 Despite the relative maturity of the F&P technology, there has been little focus in the literature on the effect of non-Darcy flow throughout the reservoir-fracture-pack flow system in F&P wells. Most of the focus has been on the effect of non-Darcy flow in the gravel-pack, with the implication that non-Darcy flow is not as significant in the fracture and reservoir. We summarize the literature pertinent to non-Darcy flow in F&P wells in the following sections.
