Multiscale Experimental Studies on Interactions Between Aqueous-Based Fracturing Fluids and Tight Organic-Rich Carbonate Source Rocks
- Feng Liang (Aramco Services Company) | Jilin Zhang (Aramco Services Company) | Hui-Hai Liu (Aramco Services Company) | Kirk M. Bartko (Saudi Aramco)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- May 2019
- Document Type
- Journal Paper
- 402 - 417
- 2019.Society of Petroleum Engineers
- tight carbonate, aqueous-based fracturing fluids, interactions, morphology, permeability
- 35 in the last 30 days
- 101 since 2007
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Hydraulic fracturing has been widely used for unconventional reservoirs, including organic-rich carbonate formations, for oil and gas production. During hydraulic fracturing, massive amounts of fracturing fluids are pumped to crack open the formation, and only a small percentage of the fluids are recovered during the flowback process. The negative effects of the remaining fluid on the formation, such as clay swelling and reduction of rock mechanical properties, have been reported in the literature. However, the effects of the fluids on source-rock properties—especially on microstructures, porosity, and permeability—are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and the corresponding changes in permeability and porosity are reported.
Two sets of tight organic-rich carbonate-source-rock samples were examined. One sample set was sourced from a Middle East field, and the other was an outcrop from Eagle Ford Shale that is considered to be similar to the one from the Middle East field in terms of mineralogy and organic content. Three fracturing fluids—2% potassium chloride (KCl), 0.5 gal/1,000 gal (gpt) slickwater, and synthetic seawater—were used to treat the thin section of the source-rock and core samples. Modern analytical techniques, such as scanning electron microscopy (SEM) and energy-dispersive spectroscopy (EDS), were used to investigate the source-rock morphology and mineralogy changes before and after the fluid treatment, at the micrometer scale. Permeability as a function of effective stress was quantified on core samples to investigate changes in flow properties caused by the fracturing-fluid treatments.
The SEM and EDS results before and after fracturing-fluid treatments on the source-rock samples showed the microstructural changes for all three fluids. For 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of the aperture for pre-existing microfractures was slightly more noticeable for samples treated with 2% KCl compared with slickwater at the micrometer scale. In one sample, dissolution of organic matter was captured in the slickwater-fluid-treated rock sample. Mineral precipitation of sodium chloride (NaCl) and generation of new microfractures were observed for samples treated with synthetic seawater. The formation of new microfractures and the dissolution of minerals could result in increases in both porosity and permeability, whereas the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stress for the core-plug samples. This effect on absolute-gas-permeability increase might have an important implication for hydrocarbon recovery from unconventional reservoirs.
This study provides experimental evidence at different scales that aqueous-based fracturing fluid might potentially have a positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new fractures or reopening of existing microfractures. This observation will be beneficial to the future use of freshwater-and seawater-based fluids in stimulating gas production from organic-rich carbonate formations.
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