Fluid Spontaneous Imbibition Under the Influence of Osmotic Pressure in Deep Coalbed Methane Reservoir in the Ordos Basin, China
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Summary The flowback rate of a hydraulic fracturing fluid is related to coalbed methane (CBM) production in gas wells. The deep (>2000 m) CBM reservoir in the Ordos Basin has an extremely high salinity (>200 000 mg/L), which results in a very low flowback rate of fracturing fluid. The mechanism underlying the extremely low flowback rate of the fracturing fluid remains unclear. This study experimentally simulated two patterns of osmotic pressure variation that exist at a hydraulic fracturing site: the processes of injection of a low-salinity fracturing fluid into a high-salinity reservoir and a high-salinity fracturing fluid into a low-salinity reservoir. Low-field nuclear magnetic resonance (NMR) technology was used to monitor dynamic fluid migration and fluid distribution in the coals. Results showed that osmotic pressure is a driving force for spontaneous imbibition when the salinity of the fracturing fluid is lower than that of the reservoir water, and more fluid enters the coal as the osmotic pressure increases. This causes the displacement of the high-salinity fluid already present in the micropores by the low-salinity fracturing fluid. In high-salinity deep coal seams, both osmotic pressure and capillary forces cause the spontaneous imbibition of the fracturing fluid from fractures into pores, promoting CH4 desorption, alleviating the water-blocking effect, and enhancing the filtration loss of the fracturing fluid. In contrast, the injection of a high-salinity fluid into the reservoir with a low-salinity brine (LSB) creates an osmotic pressure difference that prevents fluid imbibition. In shallow, low-salinity coal seams, the injection of high-salinity fracturing fluids can result in high flowback rates. Therefore, these two injection schemes are significant for an understanding of the role of osmotic pressure in deep CBM extraction and serve as valuable guides for optimizing the selection of the fracturing fluid and improving its effective flowback.Keywords:
Coalbed Methane
Imbibition
Fracturing fluid
Capillary pressure
Produced water
Summary Countercurrent imbibition is an important recovery mechanism during waterflooding in fractured reservoirs. This may be a rapid and efficient recovery process in strongly water-wet systems, but if the reservoir is mixed-wet, while it is possible for some water to imbibe spontaneously, the ultimate recovery is lower and the imbibition rate may be several orders of magnitude slower than for strongly water-wet rock. We use quasistatic pore-scale network modeling as a tool to study the behavior of mixed-wet rocks and to predict relative permeability and capillary pressure. The model uses a topologically disordered network that represents the pore space of Berea sandstone. We adjust the distribution of contact angles at the pore scale to match previously published experimental cocurrent waterflood recoveries and wettability indices on Berea. We then input the relative permeabilities and capillary pressures into a conventional grid-based code and simulate countercurrent imbibition in 1D. We make predictions, with no matching parameters, of the recovery as a function of time and compare the results with the experimental measurements. We are able to reproduce the observed dramatic increase in imbibition time as the system changes from being water-wet to mixed-wet. In a mixed-wet system, spontaneous imbibition, where the capillary pressure is positive, is limited to a narrow saturation range where the water saturation is small. At these low saturations, the water is poorly connected through the network in wetting layers and the water relative permeability is extremely low, leading to recovery rates tens to thousands of times slower than for water-wet media. We present a semiempirical equation to correlate imbibition recovery in mixed-wet rocks of different wettability and viscosity ratio. The recovery rate is proportional to the water mobility at the end of imbibition.
Imbibition
Capillary pressure
Saturation (graph theory)
Countercurrent exchange
Relative permeability
Water saturation
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We use dual porosity microfluidics and fluorescence microscopy to investigate immiscible imbibition in the pore networks formed in fractured rocks, and to identify emergent pore-scale events that arise as a result of the interplay between advection-dominant flow in fractures (F) and capillary-driven matrix imbibition (M). The dimensionless ratio between the two time scales T = tF/tM defines the various displacement patterns: fracture-dominant advective invasion at low Τ-values leaves a higher residual non-wetting phase saturation; compact invasion is observed at intermediate T-values, and fractures act as capillary barriers during matrix-dominant capillary imbibition at high Τ-values. Experiments and analyses show effective capillary-driven corner flow during immiscible imbibition; in particular, corner flow imbibition displaces non-wetting fluids that were initially trapped in the matrix during fast advective invasion. In contrast to wetting fluid invasion and imbibition, injected non-wetting fluids invade and flow along fractures as soon as the capillary pressure reaches the fracture entry pressure, and there is no matrix invasion and drainage. The capillary pressure versus saturation curve for the fractured rock mass assumes that fractures and matrix blocks share the same capillary pressure at equilibrium; then, the combined pressure-saturation response is a function of their relative contributions to the total porosity. In the absence of gouge or precipitates, fractures determine the entry pressure while the matrix controls storativity.
Imbibition
Capillary pressure
Saturation (graph theory)
Matrix (chemical analysis)
Pressure gradient
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