Events

"Shale Fracturing Enhancement by Using Polymer-Free Foams and Ultra-Light Weight Proppants"

Supervisor: Kishore K. Mohanty

Horizontal wells with long propped fractures are needed to maximize productivity from ultra-low permeability shales. Slickwater fracturing produces long fractures, but only the near wellbore region is propped due to fast settling of sand. Gel fluids can create long propped fractures, but they damage the fracture surface and proppant pack. High water consumption is another issue for water-based fracturing. The goal of this project is to develop non-damaging, less water intense fracturing treatments for shale gas reservoirs with high proppant placement efficiency. Ultra-light weight proppants and polymer-free foams are developed and evaluated because they minimize water use, reduce formation damage, and decrease proppant settling.

A reservoir simulation model is built in CMG to study the impact of fracture conductivity and propped length on fracture productivity. The minimum conductivity required to stimulate the reservoir is obtained as a function of propped length and production time. A fracturing model has been developed to simulate the fracture propagation and proppant transport. In this model, pressure impact and leak-off models are considered for foam fracturing.

Strength and API conductivity tests are conducted for three ultra-light weight proppants. Their conductivity has been determined as a function of areal concentration and confining stress. The empirical conductivity correlations are applied in the fracturing model and reservoir model to predict the conductivity distribution and fracture productivity by using the ULWPs in slickwater fracturing. Simulation study shows that all three ULWPs have strong productivity advantages over sand in typical shale reservoirs by creating more propped areas and longer propped length. The economic advantages of using the ULWPs decrease with increasing production time, shale permeability and proppant price. By adding ULWPs into sand, both the high conductivity zone at the bottom and low conductivity zone at the upper and deeper zones can be achieved, which benefits both short and long-term production.

Polymer-free foams are developed based on foam stability test applied on over fourteen surfactants. The rheology of three different surfactant solutions (A & B: regular surfactant foams; C: VES foam, chosen from the stability test) as well as their foams is evaluated in a flow loop under high pressure and temperature. Foams A and B show shear thinning behavior at qualities above 60%, non-shear dependent behavior from 50% to 60% and shear thickening behavior below 50% (due to turbulence). The VES foam C shows shear thinning behavior at both low and high qualities. Temperature has a negligible effect on the rheology of regular surfactant foams A and B. Pressure increases foam viscosity for high quality foams (Q>50%). The pressure impact increases with increasing foam quality and decreasing pressure. Foams A and B are both less viscous than 0.24 wt% guar foams, while the VES foam C has an apparent viscosity similar to that of 0.24-0.36 wt% guar foams. New correlations are developed to describe the aqueous foam rheology as a function of shear rate, quality, and pressure. The correlations are incorporated in the models to evaluate the foam fracturing efficiency. Compared with slickwater, polymer-free foams can generate better productivity than slickwater when carrying sand into shales because they create larger propped areas. By assuming typical treatment costs, the economic profit (ROFI) and water usage efficiency (Return-On-Water-Investment, ROWI) of the polymer-free foams are evaluated and compared with slickwater. It shows that 60-70% quality foams carrying sand (mesh 40) at partial monolayer concentration can have significantly improved ROFI and ROWI. The benefits of using the polymer-free foams decrease with increasing production time and shale permeability, while increase with increasing pumping time.