Experimental evaluation of liquid nitrogen fracturing on the development of tight gas carbonate rocks in the Lower Indus Basin, Pakistan

Tight gas carbonate formations have enormous potential to meet the supply and demand of the ever-growing population. However, it is impossible to produce from these formations due to the reduced permeability and lower marginal porosity. Several methods have been used to extract unconventional tight gas from these reservoirs, including hydraulic fracturing and acidizing. However, field studies have demonstrated that these methods have environmental flaws and technical problems. Liquid nitrogen (LN2) fracturing is an effective stimulation technique that provides sudden thermal stress in the rock matrix, creating vivid fractures and improving the petro-physical potential. In this study, we acquired tight gas carbonate samples and thin sections of rock from the Laki limestone formation in the Lower Indus Basin, Pakistan, to experimentally quantify the effects of LN2 fracturing. Initially, these samples were characterized based on mineralogical (X-ray diffraction), petrography, and petro-physical (permeability and porosity) properties. Additionally, LK-18-06 Laki limestone rock samples were exposed to LN2 for different time intervals (30, 60, and 90 mins), and various techniques were applied to comprehend the effects of the LN2 before and after treatment, such as atomic force microscopy, scanning electron microscopy, energy-dispersive spectroscopy, nano-indentation, and petro-physical characterization. Our results reveal that the LN2 treatment was very effective and induced vivid fractures of up to 38 µm. The surface roughness increased from 275 to 946 nm, and indentation moduli significantly decreased due to the decreased compressibility of the rock matrix. Petro-physical measurements revealed that the porosity increased by 47% and that the permeability increased by 67% at an optimum LN2 treatment interval of 90 mins. This data can aid in an accurate assessment of LN2 fracturing for the better development of unconventional tight gas reservoirs

Effect of organic acids on CO2-rock and water-rock interfacial tension: Implications for CO2 geo-storage

A small concentration of organic acid in carbon dioxide (CO2) storage formations and caprocks could significantly alter the wettability of such formations into less water-wet conditions, decreasing the CO2-storage potential and containment security. Recent studies have attempted to infer the influence of the organic acid concentration on the wettability of rock–CO2–brine systems by measuring advancing and receding contact angles. However, no studies have investigated the influence of organic acid contamination on CO2-storage capacities from rock-fluid interfacial tension (IFT) data because solid-brine and solid-CO2 IFT values cannot be experimentally measured. Equilibrium contact angles and rock-fluid IFT datasets were used to evaluate the viability of CO2 storage in storage rocks and caprocks. First, the contact angles of rock in brine-CO2 systems were measured to compute Young\u27s equilibrium contact angles. Subsequently, rock-brine and rock-gas IFT values at CO2 geo-storage conditions were computed via a modified form of Neumann\u27s equation of state. For two storage-rock minerals (quartz and calcite) and one caprock mineral (mica), the results demonstrated high CO2-brine equilibrium contact angles at high pressure (0.1–25 MPa) and increasing concentrations of stearic acid (10−5 to 10−2 mol/L). Rock-brine IFT increased with the increased stearic acid concentration but remained constant with increased pressure. In all conditions, the order of increasing hydrophobicity of the mineral surfaces is calcite \u3e mica \u3e quartz. At 323 K, 25 MPa, and a stearic acid concentration of 10−2 mol/L, quartz became intermediate-wet with a CO2-brine equilibrium contact angle of 89.8°, whereas mica and calcite became CO2-wet with CO2-brine equilibrium contact angles of 117.5° and 136.5°, respectively. This work provides insight into the effects of organic acids inherent in CO2 geo-storage formations and caprocks on rock wettability and rock-fluid interfacial interactions

First assessment of hydrogen/brine/Saudi basalt wettability: implications for hydrogen geological storage

Introduction: Underground hydrogen (H2) storage is a prominent technique to enable a large-scale H2-based economy as part of the global energy mix for net-zero carbon emission. Recently, basalts have gained interest as potential caprocks for subsurface H2 storage due to their low permeability, vast extension, and potential volumetric capacity induced by structural entrapment of the buoyant H2. Wettability represents a fundamental parameter which controls the capillary-entrapment of stored gases in porous media.Methods: The present study evaluates the wettability of basalt/H2/brine system of two basalt samples from Harrat Uwayrid, a Cenozoic volcanic field, in Saudi Arabia. The H2/basalt contact angle was measured using a relevant reservoir brine (10% NaCl) under storage conditions of 323K temperature and pressure ranges from 3 to 28 MPa using the modified sessile drop method. The surface roughness of the basaltic rocks was determined to ensure accurate results.Results: The investigated Saudi basalt samples are water-wet, thereby they did not achieve a 100% hydrogen wetting phase even at 28 MPa pressure. The measured contact angles slightly decrease as pressure increases, thereby pressure did not significantly influences the height of the H2 column.Discussion: We interpret this trend to the slight increase in H2 density with increasing pressure as well as to the olivine-rich mineralogical composition of the Saudi basalt. Thus, from the wettability aspects, Saudi basalt has the potential to store a large volume of H2 (>1,400 m height) and maintain its excellent storage capacity even in deep, high-pressure regimes. This study demonstrates that the basalt rock texture (pore throat radii) and mineralogy control their capacity for subsurface H2 storage

A Cell-Centred CVD-MPFA Finite Volume Method for Two-Phase Fluid Flow Problems with Capillary Heterogeneity and Discontinuity

A novel finite-volume method is presented for porous media flow simulation that is applicable to discontinuous capillary pressure fields. The method crucially retains the optimal single of freedom per control-volume being developed within the flux-continuous control-volume distributed multi-point flux approximation (CVD-MPFA) framework (Edwards and Rogers in Comput Geosci 02(04):259–290, 1998; Friis et al. in SIAM J Sci Comput 31(02):1192–1220, 2008) . The new methods enable critical subsurface flow processes involving oil and gas trapping to be correctly resolved on structured and unstructured grids. The results demonstrate the ability of the method to resolve flow with oil/gas trapping in the presence of a discontinuous capillary pressure field for diagonal and full-tensor permeability fields. In addition to an upwind approximation for the saturation equation flux, the importance of upwinding on capillary pressure flux via a novel hybrid formulation is demonstrated

CVD-MPFA full pressure support, coupled unstructured discrete fracture–matrix Darcy-flux approximations

Two novel control-volume methods are presented for flow in fractured porous media, involving coupling the control-volume distributed multi-point flux approximation (CVD-MPFA (c.f. Edwards et al.)) constructed with full pressure support (FPS), to two types of discrete fracture-matrix approximation for flow simulation on unstructured grids; (i) involving hybrid grids and (ii) a lower dimensional fracture model. Flow is governed by Darcy's law together with mass conservation both in the rock matrix and in fractures, where large discontinuous permeability tensors can occur. Finite-volume FPS schemes are more robust than the earlier CVD-MPFA triangular pressure support (TPS) schemes for problems involving strongly anisotropic homogeneous and heterogeneous full-tensor permeability fields. We use a cell-centred hybrid-grid method, where fractures are represented by lower-dimensional interfaces between matrix grid cells in the physical mesh, and expanded to equi-dimensional cells in the computational domain. We present a simple procedure to form a consistent hybrid-grid locally for a dual-cell. We also propose a novel hybrid-grid for intersecting fractures, for the FPS method, which improves the condition number of the global linear system and permits larger time steps for tracer transport. The tracer flow transport equation is coupled with the pressure equation and the results provide flow parameter assessment of the fracture models. Transport results obtained via TPS and FPS hybrid-grid formulations are compared with corresponding results of fine-scale explicit equi-dimensional formulations. The results show that the hybrid-grid FPS method applies to general full-tensor fields and provides improved robust approximations compared to the hybrid-grid TPS method for fractured domains, for both weakly anisotropic permeability fields and in particular for very strong anisotropic full-tensor permeability fields where the TPS scheme exhibits spurious oscillations. The hybrid-grid FPS formulation is extended to compressible flow and the results demonstrate the method is also robust for transient flow. Furthermore, FPS is coupled with a lower-dimensional fracture model, where fractures are strictly lower-dimensional in the physical mesh. Comparisons of the hybrid-grid FPS method and the FPS lower-dimensional fracture model are presented for several cases of isotropic and strongly anisotropic fractured media which illustrate the benefits of the respective methods