Experimental Proppant Conductivity Observations: Evaluating Impact of Proppant Size and Fluid Chemistry on Long-Term Production in Shales

Abstract

Abstract Propped hydraulic fractures have enabled economic hydrocarbon production from organic rich shales. Laboratory testing of proppants can help in systematic evaluation of different factors that can affect proppant performance. This study is focused on long-term conductivity measurements of proppant-packs at simulated reservoir pressure and temperature conditions. Mechanisms like proppant crushing, embedment, and diagenesis are investigated. Testing was done using a conductivity cell made of Hastelloy; allowing simultaneous measurement of fracture compaction and permeability. The proppant filled fracture (concentration: 0.75-3 lb/ft2) is subjected to axial load (5000 psi) to simulate closure stress. Brine is flowed through the pack at a constant rate (3 ml/min) at elevated temperature (250° F) over an extended duration of time (from 10-60 days). 20/40 and 60/100 mesh Ottawa sand were used in this study. The proppant-pack performance is evaluated between shale platens fabricated from Eagle Ford rock (58% clay by wt.; Nanoindentation Young's modulus - 16 GPa). Experiments on the 20/40 and 60/100 Ottawa sand (1.5 lb/ft2 proppant concentration) at elevated pressure (5000 psi) and temperature (250° F), spanning 10 days demonstrate that proppant size strongly impacts proppant performance. The proppant-pack permeability for 60/100 sand drops dramatically within a few hours. The 20/40 proppant permeability is double the permeability of 60/100 sand even after 10 days of testing. Approximately 60% compaction is observed over the test duration, with 28% contribution from proppant crushing and rearrangement, and 32% contribution from embedment. Particle size analysis of proppant grains and SEM images verify proppant crushing, fines migration and embedment as dominant damage mechanisms. Proppant embedment and crushing are observed to be dependent on the shales being tested. Fracturing jobs involve maintaining a basic pH environment for optimal performance of fluid additives for better proppant placement via control on viscosity. A second study was conducted to compare performance on similar Eagle Ford shale by altering the fluid chemistry (pH ~ 10.5) to understand the impact on permeability and compaction over time. Over a duration of 20 days, the permeability dropped from 120 darcy to 200 md. After 8 days, the pH:10 brine permeability was 10 times lower than pH:7 brine permeability. After 18 days, the fracture width reduced by 90%, indicating a creep behavior. High silica content (>20 ppm) was observed in the outlet brine. The proppant and rock surface were studied under SEM to investigate the role of secondary mineral growth during the drastic reduction of permeability. This study is focused on understanding fracture conductivity under as realistic near in-situ experimental conditions. Testing between shale platens at reservoir temperature and pressure conditions is more representative of subsurface environment. Dynamic measurements in the current study were conducted for long duration (spanning 10-30 days) using brine. This allows the study of effects of mechanical and chemical degradation of fracture conductivity, which has been used to separate the effects of crushing and embedment. Our results demonstrate that the fracture conductivity is dependent on proppant size and pH of the flowing solution.