Imbibition of water into the shale matrix is known as the primary reason for inefficient water recovery after hydraulic fracturing treatments. The hydration of clay minerals may induce microfractures in clay-rich shale samples. The increased porosity and permeability due to induced microfractures has been considered to be partly responsible for 1) excessive water uptake of gas shales, and 2) increase in hydrocarbon production rate after prolonged shut-in periods. To test this hypothesis, it is necessary to measure imbibition-induced strain and stress under representative laboratory conditions. In this study, we conduct laboratory tests to 1) measure the strain and stress induced by water imbibition in gas shales and 2) investigate the effect of confining load on the rate of water imbibition. We conduct a three-phase study on rock samples from the Horn River Basin (HRB) and the Duvernay (DUV) Formation, located in the Western Canadian Sedimentary Basin.
The objective of this paper is to understand the effects of rock mineralogy, water salinity, and soaking time on spontaneous oil production from tight oil cores immersed in water. We present comprehensive experiments to investigate the interaction of deionized (DI) water and brine with oil-saturated core plugs from wells drilled in the Montney (MT) tight oil play located in the Western Canadian Sedimentary Basin. As-received core plugs were immersed in reservoir brine for a long time, and then were flooded with oil to arrive at irreducible brine saturation. The saturated plugs were cut in half, and placed in imbibition cells filled with DI water and reservoir brine to visualize and measure spontaneous oil production. The results suggest that both brine and fresh water spontaneously imbibe into and force the oil out of the samples. We did not observe any significant difference in the imbibition rate of DI water and brine. We also conducted SEM/EDS analysis, and observed the existence of pores surrounded with different minerals including quartz, carbonates, feldspars, clays, and organic matter, with different affinities to oil and water. This observation explains why oil can spontaneously imbibe into as-received samples, and why brine can spontaneously imbibe into oil-saturated samples and force the oil out.
Binazadeh, Mojtaba (University of Alberta) | Xu, Mingxiang (University of Alberta) | Jiang, Kaiyan (University of Alberta) | Zolfaghari, Ashkan (University of Alberta) | Dehghanpour, Hassan (University of Alberta)
The uptake of water by rock matrix in a hydrocarbon producing well brings in both economic justification and environmental concerns. A detailed understanding of the water-rock interactions is essential for design and implication of hydrocarbon recovery techniques and environmental impact analysis. In this study, the water imbibition results are described by the electrostatic interactions between the water and shale samples. The effect of leachable ions in the shale, imbibed fluid ionic strength, electrostatic double layer, and zeta potential of shale are studied.
The shale powders are washed with DI (deionized water) sequentially. Individual ion concentrations are obtained by ICP-MS analysis. The ionic strength and Debye length of the brine obtained from each step of the washing experiment are calculated. Zeta potential of the fresh and washed powders are measured in DI water and 10-times concentrated brines from first washing stage (CN brines). A set-up is designed to perform the imbibition experiments on the intact and washed shale powders. DI water and CN brines are used as the imbibing fluids.
Washing with DI water leached ions out of the shale powders. After a maximum of 7 washing steps, the ionic strength of the resulting brine solution reached to a constant value which cannot be further reduced by washing. Zeta potential of shale powders in CN brines are substantially lower than the zeta potential of shale powders in DI water. This reduction in the zeta potential value to higher ionic strength of CN brines as compared with DI water. Imbibition experiments reveal that the CN brine solutions imbibe slower into the shale powders as compared with DI water. DI water imbibes faster in washed powders as compared with fresh powders. Debye length is correlated with imbibition rate, as higher Debye length of the solution results in faster imbibition. A reduction in the solution ionic strength increases the thickness of electrostatic double layer and zeta potential value. The thickness of electrostatic double layer in contact with the shale surface, which is modulated by the ionic strength of the in-situ brine solution, is an important factor that influence the particle zeta potential of shale as well as the imbibition rate of aqueous solution into shales.
Understanding water uptake of gas shales is critical for designing fracturing and treatment fluids. Previous imbibition experiments on unconfined gas shales have led to several key observations. The water uptake of dry shales is higher than their oil uptake. Furthermore, water imbibition results in sample expansion and microfracture induction. This study provides additional experimental data to understand the effects of rock fabric, complex pore network, and clay swelling on imbibition behavior.
We systematically measure the imbibition rates of fresh water, brine and oil into the confined and unconfined rock samples and crushed packs from different shale members of the Horn River Basin. We also measure the ion diffusion rate from shale into water during imbibition experiments. The results show that confining the shale samples decreases the water imbibition rate of samples tested parallel to the bedding. However, it has a negligible effect on water uptake of samples tested perpendicular to the bedding and on ion diffusion rates. The comparative study suggests that, for both confined and unconfined samples, water uptake is higher than oil uptake. The liquid imbibition and ion diffusion rates along the bedding are higher than those against the bedding. Surprisingly, the crushed samples show a completely different behavior. The oil uptake of crushed packs is higher than their water uptake. The data suggest that the connected pore network of the intact samples is water wet while the majority of rock including poorly connected pores is oil wet. This argument is backed by complete spreading of oil on fresh break surfaces of the rock.
Tight oil and gas reservoirs, considered "unconventional resources", have been emerged as a significant source of energy supply in the United State and Canada, to supplement the decreasing supply of conventional resources and meet the increased global demands on oil and gas (Frantz et al, 2005; Zahid et al., 2007; Khlaifat et al., 2011). Unconventional resources with ultralow matrix permeability are capable of producing oil and gas at economic rates when completed by hydraulically fractured horizontal wells (Ning et al., 1993). During hydraulic fracturing, a great amount of water-based hydraulic fracturing fluid with low proppant concentration is injected into the target formation to create multiple fractures and increase the contact surface between the wellbore and reservoir (Holditch and Tschirhart, 2005; Palisch et al., 2010). However, only a small fraction of injected fluid, typically 10 to 20%, can be recovered during the clean-up phase (King, 2012; Cheng, 2012). Spontaneous imbibition of fracturing fluid is known as the primary mechanism for fracturing fluid loss and ineffcient water recovery (Cheng, 2012; Bennion et al., 2005; Paktinat et al., 2006; Shaoul et al., 2011; Roychaudhuri et al., 2011). Other possible mechanisms which control the behavior of the retained water in the reservoir include gravity segregation and stress-sensitive fracture conductivities (Holditch, 1979; Gdanski et al., 2009; Parmar et al, 2012; 2013; 2014).