In some complex reservoirs, low-resistivity/low-contrast pay, low-porosity/low-permeability, and medium-to-heavy oil, nuclear magnetic resonance (NMR) log data--independently or in combination with other log data--provide the best and/or only means of accurate formation and fluid evaluation. Because NMR-log data acquisition is complex, job preplanning is essential to ensure optimal selection of acquisition parameters that will result in reliable and accurate data and in the maximum information possible in any given reservoir and logging environment. A clear understanding of the logging job objectives is necessary for optimizing the NMR acquisition parameters to best achieve these objectives. This process must take place before the actual logging. In addition to job objectives, determination of the appropriate NMR-acquisition parameters is also influenced by operational considerations and the anticipated in-situ reservoir properties (Fig.1).
After precipitation, asphaltene can remain as a suspended solid in the oil or deposit onto the rock. Here, the term precipitation corresponds to the formation of a solid phase from thermodynamic equilibrium and deposition means the settling of solid particles onto the rock surface. Deposition will induce alteration of wettability (from water-wet to oil-wet) of the rock and plugging of the formation. These aspects have been known for a long time and are the subject of many recent investigations. This section reviews the investigations and laboratory observations of these aspects.
Relative permeability and capillary pressure defined capillary pressure as the difference in pressure across the interface between two phases. With Laplace's equation, the capillary pressure Pcow between adjacent oil and water phases can be related to the principal radii of curvature R1 and R2 of the shared interface and the interfacial tension σow for the oil/water interface: The relationship between capillary pressure and fluid saturation could be computed in principle, but this is rarely attempted except for very idealized models of porous media. Methods for measuring the relationship are discussed in Measurement of capillary pressure and relative permeability. For this example, water is the wetting phase, and gas is the nonwetting phase. As shown in Figs. 2 and 3, a wetting phase spreads out on the solid, and a nonwetting phase does not.
Relative permeability and capillary pressure defines relative permeabilities as dimensionless functions of saturation with values generally ranging between 0 and 1. Relative permeability is important for estimating the flow of reservoir fluids. The semilog scale of Figure 1 is convenient for reading the relative permeabilities less than 0.05. Although the curves are labeled "gas" and "oil" in these figures, the phase identity of a curve can be deduced without the labels. For example, the relative permeability that increases in the direction of increasing oil saturation must be the oil relative permeability.
Water is the wetting phase. Figure 1.5 – Primary drainage, imbibition, and secondary drainage for an oil/water system in which the oil and water wet the solid surface equally. Figure 1.6 – Primary drainage and imbibition for unconsolidated dolomite powder (the lines merely connect the data). These authors wrote capillary pressure as the negative of Eq. 4 because oil was the wetting phase for most of the tests. The legend gives contact angles measured through the water phase (in degrees). Leverett and coworkers, based on the evaluation of gas/water capillary pressure data for drainage and imbibition in unconsolidated sands, proposed the following definition: ....................(15.6) The function j(Sw), defined in Eq. 15.6, is known to many as the "Leverett j-function." The j-function is obtained from experimental data by plotting against Sw. The combination is often considered an estimate of the mean hydraulic radius of pore throats.
There are many possible causes of formation damage. In addition to the numerous sources identified in separate articles (see See Also section below), other, less common causes include emulsions and sludges, wettability alteration, bacterial plugging, gas breakout, and water blocks. The presence of emulsions at the surface does not imply the formation of emulsions in the near-wellbore region. Most often, surface emulsions are a result of mixing and shearing that occur in chokes and valves in the flow stream after the fluids have entered the well. Such emulsions usually have a higher viscosity than either of the constituent fluids and can result in significant decreases in the ability of the hydrocarbon phase to flow.
At the pore level (i.e., where the water and oil phases interact immiscibly when moving from one set of pores to the next), wettability and pore geometry are the two key considerations. The interplay between wettability and pore geometry in a reservoir rock is what is represented by the laboratory-determined capillary pressure curves and water/oil relative permeability curves that engineers use when making original oil in place (OOIP) and fluid-flow calculations. This article discusses these basic concepts and their implications for initial water- and oil-saturation distribution, relative permeability, and how initial gas saturation will affect water/oil flow behavior. Figure 1 is a schematic diagram of the water/oil displacement process. Wettability is defined in terms of the interaction of two immiscible phases, such as oil and water, and a solid surface, such as that of the pores of a reservoir rock.
Peng, Sheng (The University of Texas at Austin) | Liu, Yijin (SLAC National Accelerator Laboratory) | Ko, Lucy Tingwei (The University of Texas at Austin) | Ambrose, William (The University of Texas at Austin)
Oil production from the subsurface is essentially a process of multiphase flow; however, this process is poorly understood in shale because of the complex properties of its surface and structure of its pore systems. Where unrecovered fracturing fluid goes and how it displaces the in-situ oil in the shale matrix remain open questions. Understanding of wettability, an important factor influencing multiphase flow, is still vague for shale. In this study, an integrated tracer imbibition and multiscale imaging method is adapted for direct visualization of water/oil displacement by spontaneous imbibition, a process mimicking what occurs in the subsurface after hydraulic fracturing. Oil removal ratio by water spontaneous imbibition is quantified through image analysis. Five Wolfcamp Shale samples are used in this study. The major pore type in all the samples is identified via imaging to be clay mineral pores coated with organic matter. Water/oil displacement results indicate that the samples are water-wet, an opposite conclusion to the common concept for shale that organic matter is oil-wet. The sessile drop method, a commonly-used method for contact angle measurement, measures surface wettability, which may not be relevant to pore wettability and thus fluid flow in shale.
Water imbibition is an important process in the early phase of oil production in unconventional reservoirs (“shale” for simplicity) after hydraulic fracturing. A major fraction of the injected fracturing fluid, on average ~90% or even higher, remains in the formation (Vidic et al., 2013; Lu et al., 2018). However, where the unrecovered fracturing fluid goes and how it displaces the in-situ oil are still open questions. Previous research on spontaneous imbibition using inch-scale plug samples (Dehghanpour et al., 2013; Roychaudhuri et al., 2013; Dutta et al., 2014; Alvarez and Schechter, 2017) can explain, in part, the fluid loss after fracturing. However, for a shale rock that can contain significant heterogeneity in the pore system, understanding the spatial distribution of water uptake or water/oil displacement in a smaller scale (e.g., microscale) and its correlation with local mineralogy or organic matter distribution is more meaningful.
The concept of shale oil EOR by adding surfactant into fracturing fluid became quite popular in the recent decade. Mechanisms of the improved productions are either Interfacial Tension (IFT) reduction or Wettability (WTB) Alteration. While surfactant based shale oil EOR has been proven to be an effective approach by several scholars, the dominating mechanism is still vague and needing a better understanding for project optimization. In addition, as most current studies focused on the spontaneous imbibition under atmospheric pressure, it is important to investigate the process with external pressures because hydraulic fracturing is a high-pressure driven operation. By performing both experimental and numerical simulation studies, this work is to explore the feasibility and potential of surfactant, as a liquid phase substance, to improve the recovery from shale matrix with the assistance of cyclically injected external forces. Further, the relative contributions of IFT reduction and WTB alterations are separately investigated.
The experimental work was performed with a self-assembled set-up allowing high external pressures to be applied. Cyclic injections with up to 3000 psi soaking pressure were conducted with a series of surfactant candidates vary in IFTs. The experiments followed a 12-hour-soaking / 12-hour-depletion schedule with 8 cycles in total for each case. The oil recovery after each cycle was recorded visually to provide more reliabilities. A lab-scaled simulation model that is able to separately reflect the effects of IFT reduction and WTB alteration was built and tuned to match our experimental results. The individual effects through soaking and depletion stages were further analyzed.
The experimental results showed that it is possible to improve oil recovery from shales by cyclically injecting a liquid phase with the assistance of surfactant, and WTB alteration is still the dominating effect in this process. The recovery factor (RF) was as high as 38% after 8 cycles by injecting the surfactant candidate that altered the wettability of shale from oil-wet to water-wet without prominently reducing the IFT. Through the simulation study, the soaking time showed major effects on the recovery in a short period, while the depletion time didn't affect the results too much. However, the times of soaking-depletion cycle will not change the final recovery in the long run. Cyclic Surfactant Injection (CSI) technique will expedite the production, but the potentially enhanced recovery depends on the properties of selected surfactants. Our results and observations provided suggestions to successfully perform a surfactant based EOR project in shale oil reservoirs.