Post-fracturing production data analysis indicates stimulation of some west Texas wells with surfactant additives did not enhance production as high as expected. Analysis of flowback and produced water for surfactant residues revealed 99% of surfactant was retained inside wells (
Literature precedent exists that polyelectrolyte (PET)-based SAs could significantly reduce surfactant adsorption not only onto a variety of outcrop minerals (Carlpool dolomite, calcite, kaolinite, Berea sandstone, Indiana limestone, etc.) and metal oxide nanoparticles, but also unconventional shale formulations in which surface area can be up to 700 m2/g. In this study, the adsorptions of surfactant and SA to proppants were first examined. Results indicate no adsorption was observed to proppant for both surfactants and PET-based SAs. SAs (0.5 to 1 gal/1,000 gal (gpt)) were then injected with surfactant (1 to 3 gpt) at an appropriate ratio into column-packed shale formulations (primarily composed of calcite, dolomite, quartz, illite, pyrite, and plagioclase feldspar) to investigate its effectiveness in controlling surfactant retention caused by adsorption. Laboratory testing revealed injection of 3 gpt mixture of surfactant and SA has a similar adsorption profile (surface tension as a function of time) as 3 gpt surfactant alone based on the dynamic surface tension measurement. Notably, the addition of SAs resulted in lower surface tension and enhanced hydrocarbon solubility; and thus, an improved oil recovery by surfactant was achieved as evidenced by the oil recovery tests. Additionally, 68% friction reduction of the fracturing fluid with surfactant and SA was sufficient for the field operation compared to the guar-based fluid used in the hydraulic fracturing applications.
As a result of the laboratory findings, field trials were executed on a three well pad in the Permian basin (PB). For the first 30 days oil and gas production appeared to be significantly higher than the average production from offset wells in the same area that were previously fractured with the same surfactant.
Production from tight formation resources leads the growth in U.S. crude oil production. Compared with chemical flooding and water flooding, gas injection is a promising EOR approach in shale reservoirs. A limited number of experimental studies concerning gas flooding in the literature focus on unconventional plays. This study is a laboratory investigation of gas flooding to recover light crude oil from nano-permeable shale reservoirs.
In this work, the N2 flooding process was applied to Eagle Ford core plugs saturated with dead oil. To investigate the effects of flooding time and injection pressure on the recovery factor, two groups of core-flood tests were performed. In group one, flooding time ranged from 1 to 5 days in increments of 1 day; in the other group, the injection pressure ranged from 1,000 psi to 5,000 psi in increments of 1,000 psi. The experimental setup was monitored using X-ray CT that helped to visualize phase flow and estimate the recovery efficiency during the test.
The potential of N2 flooding for improving oil recovery from shale core plugs was examined, and the recovery factor (RF) of each case was presented. The results from group one showed that more oil was produced with a longer flooding time. However, the incremental RF decreased with the increase of flooding time. The oil recovery was significant at the initial period of the recovery process, and a longer flooding time had less effect on extracting more oil. With flooding time constant in 1-day, the results from the second group indicated that RF increased with injection pressure, especially rising pressure, from 1,000 psi to 2,000 psi. The gas breakthrough time became shorter with the increase of injection pressure. The analysis of the CT number showed that the oil recovery process mainly occurred before the gas breakthrough. Once a fluid flow path was established, the injected gas flowed through the limited communication channels; thus, no extra oil could be extracted without increasing the injection pressure. This experimental study illustrates that gas flooding has liquid oil production potential in shale reservoirs.
The Green River, Utah holds the world's greatest oil shale resources. However, the hydrocarbon, which is namely kerogen, extraction from shales is limited due to environmental and technical challenges. In this study, we investigated the effectiveness of the combustion process for shale oil extraction. Samples collected from the Green River formation were first characterized by X-ray Diffraction (XRD) and Scanning Electron Microscopy (SEM). Then, series of dry combustion tests were conducted at different heating rates and wet combustion tests by water addition. The combustion efficiency was enhanced by mixing oil shale samples with an iron based catalyst. The effectiveness of dry, wet, and catalyst added combustion processes was examined by the thermal decomposition temperature of kerogen. Because the conventional oil shale extraction methods are pyrolysis (retorting) and steaming, the same experiments were conducted also under nitrogen injection to mimic retorting. It has been observed that the combustion process is a more efficient method for the extraction of kerogen from oil shale than the conventional techniques. The addition of water and catalyst to combustion has been found to lower the required temperature for kerogen decomposition for lower heating rate. This study provides insight for the optimization of the thermal methods for the kerogen extraction.