Mohammad Sarmadivaleh

Influence of temperature and pressure on quartz–water–CO2 contact angle and CO2–water interfacial tension

We measured water-CO2 contact angles on a smooth quartz surface (RMS surface roughness ∼40 nm) as a function of pressure and temperature. The advancing water contact angle θ was 0° at 0.1 MPa CO2 pressure and all temperatures tested (296-343 K); θ increased significantly with increasing pressure and temperature (θ=35° at 296 K and θ=56° at 343 K at 20 MPa). A larger θ implies less structural and residual trapping and thus lower CO2 storage capacities at higher pressures and temperatures. Furthermore we did not identify any significant influence of CO2-water equilibration on θ. Moreover, we measured the CO2-water interfacial tension γ and found that γ strongly decreased with increasing pressure up to ∼10 MPa, and then decreased with a smaller slope with further increasing pressure. γ also increased with increasing temperature.

Swelling‐induced changes in coal microstructure due to supercritical CO2 injection

Enhanced coalbed methane recovery and CO2 geo-storage in coal seams are severely limited by permeability decrease caused by CO2 injection and associated coal matrix swelling. Typically it is assumed that matrix swelling leads to coal cleat closure and as a consequence, permeability is reduced. However, this assumption has not yet been directly observed. Using a novel in-situ reservoir condition x-ray micro computed tomography flooding apparatus, for the first time we observed such micro cleat closure induced by supercritical CO2 flooding in-situ. Furthermore, fracturing of the mineral phase (embedded in the coal) was observed; this fracturing was induced by the internal swelling stress. We conclude that coal permeability is drastically reduced by cleat closure, which again is caused by coal matrix swelling; which again is caused by flooding with supercritical CO2.

On wettability of shale rocks

The low recovery of hydraulic fracturing fluid in unconventional shale reservoirs has been in the centre of attention from both technical and environmental perspectives in the last decade. One explanation for the loss of hydraulic fracturing fluid is fluid uptake by the shale matrix; where capillarity is the dominant process controlling this uptake. Detailed understanding of the rock wettability is thus an essential step in analysis of loss of the hydraulic fracturing fluid in shale reservoirs, especially at reservoir conditions. We therefore performed a suit of contact angle measurements on a shale sample with oil and aqueous ionic solutions, and tested the influence of different ion types (NaCl, KCl, MgCl2, CaCl2), concentrations (0.1, 0.5 and 1M), pressures (0.1, 10 and 20MPa) and temperatures (35 and 70°C). Furthermore, a physical model was developed based on the diffuse double layer theory to provide a framework for the observed experimental data. Our results show that the water contact angle for bivalent ions is larger than for monovalent ions; and that the contact angle (of both oil and different aqueous ionic solutions) increases with increase in pressure and/or temperature; these increases are more pronounced at higher ionic concentrations. Finally, the developed model correctly predicted the influence of each tested variable on contact angle. Knowing contact angle and therefore wettability, the contribution of the capillary process in terms of water uptake into shale rocks and the possible impairment of hydrocarbon production due to such uptake can be quantified.

Test Design and Sample Preparation Procedure for Experimental Investigation of Hydraulic Fracturing Interaction Modes

Abstract Hydraulic fracturing is a complex operation which is influenced by several factors including the formation properties, state of stresses in the field, injecting fluid and pumping rate. Before carrying out the expensive fracturing operation in the field, it would be useful to understand the effect of various parameters by conducting physical experiments in the laboratory. Also, laboratory experiments are valuable for validating numerical simulations. For this purpose, laboratory experiments may be conducted on synthetically made samples to study the effect of various parameters before using real rock samples, which may not be readily available. To simulate the real stress conditions in the field, experiments need to be conducted on cube-shaped samples on which three independent stresses can be applied. The hydro-mechanical properties of a sample required for modelling purposes and the design of a scaled hydraulic fracturing test in the laboratory can be estimated by performing various laboratory experiments on cylindrical plugs. The results of laboratory experiments are scaled to field operation by applying scaling laws. In this paper, the steps to prepare a cube-shaped mortar sample are explained. This follows a review of the sample set-up procedure in a true tri-axial stress cell for hydraulic fracturing experiments. Also, the minimum tests on cylindrical plugs required to estimate the hydro-mechanical properties of the rock sample are explained. To simulate the interaction mode when a hydraulic fracture approaches an interface in the laboratory, the procedure for producing samples with parallel artificial fracture planes is explained in this paper. The in-fill material and the angle of fracture planes were changed in different samples to investigate the effect of interface cohesion and the angle of approach on the interaction mechanism.

Wettability alteration of oil-wet limestone using surfactant-nanoparticle formulation

Wettability remains a prime factor that controls fluid displacement at pore-scale with substantial impact on multi-phase flow in the subsurface. As the rock surface becomes hydrophobic, any oleic phase present is tightly stored in the rock matrix and produced (hydrocarbon recovery) or cleaned up (soil-decontamination) by standard waterflooding methods. Although surface active agents such as surfactants have been used for several decades for changing the wetting states of such rocks, an aspect that has been barely premeditated is the simultaneous blends of surfactants and nanoparticles. This study thus, systematically reports the behaviour of surfactants augmented nanoparticles on wettability alteration. Contact angle, spontaneous imbibition, and mechanistic approaches were adopted to assess the technical feasibility of the newly formulated wetting agents, tested over wide-ranging conditions to ascertain efficient wetting propensities. The contact angle measurement is in good agreement with the morphological and topographical studies and spontaneous imbibition. The wetting trends for the formulated systems indicate advancing and receding water contact angle decreased with increase in nanoparticle concentration and temperature, and the spontaneous water imbibition test also showed faster water-imbibing tendencies for nanoparticle-surfactant exposed cores. Thus, the new formulated nanoparticle-surfactant systems were considered suitable for enhancing oil recovery and soil-decontamination, particularly in fractured hydrophobic reservoirs.

Modified Reinshaw and Pollard Criteria for a Non-Orthogonal Cohesive Natural Interface Intersected by an Induced Fracture

Abstract Hydraulic fracturing is a widely used stimulation method to enhance the productivity of unconventional resources. The hydraulic fracturing operation in naturally fractured reservoirs or when it is expected to intersect a natural interface, such as an interbed is subjected to complexity. The induced fracture may cross, get arrested by or open the fracture plane upon its arrival at the natural interface. Besides other parameters, this depends on the natural interface mechanical properties, including the cohesion and friction angle of the interface. Several analytical criteria have been developed to predict the interaction mechanism of induced and natural fracture. While these analytical solutions have been developed based on some simplified assumptions, they can provide a good understanding of the effect of different parameters. The first part of this paper summarizes the available criteria for interaction of hydraulic and natural fractures. Important factors will be mentioned and illustrations will be given to present the limitations of each criterion. The second part discusses the development and validation of an extension to Renshaw and Pollard criterion in the form a single analytical formula for non-orthogonal cohesive fracture. This includes the contribution of the strength of the in-fill material to the bonding of the two sides of a fracture, hence its effect on the interaction mechanism. The proposed criterion was validated using published laboratory data. Finally, a methodology is proposed to help the design of interaction experiments in the laboratory, which can also be used for prediction of interaction mode in numerical simulations.

Microstructural effects on mechanical properties of shaly sandstone

AbstractUnderstanding the mechanical properties of shaly sandstone is of great importance in reservoir geomechanics. Because of the lack of core data, measurements based on acoustic wave velocities...

Effect of brine salinity on CO2 plume migration and trapping capacity in deep saline aquifers

CO2 migration and storage capacity are highly affected by various parameters (e.g. reservoir temperature, vertical to horizontal permeability ratio, cap rock properties, aquifer depth and the reservoir heterogeneity). One of these parameters, which has received little attention, is brine salinity. Although brine salinity has been well demonstrated previously as a factor affecting rock wettability (i.e. higher brine salinity leads to more CO2-wet rocks), its effect on the CO2 storage process has not been addressed effectively. Thus, we developed a three-dimensional homogeneous reservoir model to simulate the behaviour of a CO2 plume in a deep saline aquifer using five different salinities (ranging from 2000 to 200 000 ppm) and have predicted associated CO2 migration patterns and trapping capacities. CO2 was injected at a depth of 1408 m for a period of 1 year at a rate of 1 Mt year–1 and then stored for the next 100 years. The results clearly indicate that 100 years after the injection of CO2 has stopped, the salinity has a significant effect on the CO2 migration distance and the amount of mobile, residual and dissolved CO2. First, the results show that higher brine salinity leads to an increase in CO2 mobility and CO2 migration distance, but reduces the amount of residually trapped CO2. Furthermore, high brine salinity leads to reduced dissolution trapping. Thus, we conclude that less-saline aquifers are preferable CO2 sinks.

EOR Processes, Opportunities and Technological Advancements

Enhanced oil recovery (EOR) processes are well known for their efficiency in incre‐ menting oil production; however, the selection of the most suitable method to adopt for specific field applications is challenging. Hence, this chapter presents an overview of different EOR techniques currently applied in oil fields, the opportunities associated with these techniques, key technological advancements to guide the decision‐making process for optimum applicability and productivity and a brief review of field applications.

In-situ Residual Oil Saturation And Cluster Size Distribution In Sandstones After Surfactant Flooding Imaged With X-ray Micro-computed Tomography

We imaged a sandstone at connate water saturation, residual waterflood oil saturation, residual surfactant flood oil saturation and residual polymer flood oil saturation at high resolution in 3D with a micro-computed tomograph. We measured oil saturations, porosities, residual oil cluster size distributions and oil cluster surface areas on each image. We found that the waterflood and polymer flood reduced the oil saturations significantly (from 68.4% initial oil in place to 38.3% after waterflooding and 28.5% after polymer flooding). The surfactant flood was ineffective, which is probably due to the formulation we used and/or the fluid equilibration times we applied. The residual oil cluster size distributions and cluster surface area-volume relationships followed power-law relations, consistent with previous experimental measurements. We conclude that micro-computed tomography can enhance understanding of pore-scale fluid dynamics significantly.