Frac Fluid induced Damage in Tight Sands and Shale Reservoirs

Abstract

Abstract During the hydraulic fracturing of tight sands and shale reservoirs, ten thousands cubic meters of frac fluids were pumped into formation, while only 6-30% can be recovered. Frac fluids imbibed into formation matrix via capillary or forced pressure can cause formation damage, and this has been widely concerned. In this paper, we firstly reviewed and summarized the main damage mechanisms during the hydraulic fracturing of tight and shale reservoirs, including formation damage induced by fluids invasion, rock-fluids and fluids-fluids incompatibilities, proppants compaction and embedment, clay swelling and fines migration, chemical adsorption and particle dispersion et al. Secondly, we evaluated the formation damage via large-scale rock-block experiment (40cm×10cm×3cm cuboid size). Fluids invasion, water imbibition and flow-back process were carried out at the in-situ pressure condition to simulate the whole procedure of hydraulic fracturing. Liquid recovery and pressure profile obtained via the pressure detecting probes were used as evaluation method. What's more, nuclear magnetic resonance (NMR) methods were also used to illustrate the inner mechanism, explain the inside fluids distribution and fluids migration characteristics in different hydraulic fracturing procedure. Results showed that after frac fluid invasion, the rock permeability declined by 8-20%, and the hydrocarbon recovery decline by 25-30%, while the rock permeability can recover 3-12% after 24h's well shut-ins. Well shut-ins can increase rock permeability and this improvement is beneficial to hydrocarbon output in the later flow-back process. At the in-situ pressure condition, 4.3% more kerosene can be recovered than just at the spontaneous imbibition condition. Results also shows that invaded frac fluid forms a ‘water block’ and mainly distributes in macropores and mesopores and forms a water-block near fracture face, increasing capillary discontinuity and blocking seepage channels, while imbibition mechanism can reduce near-fracture water-blocks. A balance of displacement pressure and capillary pressure is crucial to the imbibition mechanism when considering in-situ pressure. The re-migration and distribution of the oil-water phase during the well shut-ins can weaken the water damage effect of the fracture wall, increase the relative permeability of the oil phase, and reduce the discontinuity of the capillary. Low fluids recovery after hydraulic fracturing would not all do harm to hydrocarbon recovery, sometimes it may help oil and gas extraction. Study of this paper can provide basis for oilfield field engineers to switch oil production choke and flow-back schedule management.