Journal of Unconventional Oil and Gas Resources最新文献

In this study trace element and radioactive element contents of the Hatıldağ oil shale (HOS) in Turkey and geochemical processes controlling the deposition of these elements are investigated. Ratios of redox-sensitive elements show that HOS were formed in mostly dioxic-anoxic and partly euxinic conditions. Element contents of shales in the northern part are associated mostly with clays and slightly with organic material. It was determined that uranium in southern part is derived from phosphates and calcium-carbonates and thorium is mostly originated from organic material and slightly associated with phosphate and calcium-carbonate. Radioactivity of HOS is derived from uranium and potassium.

Based on data independently measured and collected within depth from 135.9 to 1243.6 m in Western Guizhou, SW China, the distribution of in-situ stress was analyzed systematically. Maximum horizontal principal stress (σ_Hmax), minimum horizontal principal stress (σ_Hmin), vertical stress (σ_v) and lateral pressure ratio variations with depth were obtained by regression analysis. Results show that the growth rate of horizontal stresses is higher than that of vertical ones. Three types of stress field distribution have been noted that σ_v ⩾ σ_Hmax ⩾ σ_Hmin mainly occurs in shallow and intermediate to deep coal seams (<400 m and 600–1000 m), the σ_Hmax ⩾ σ_v ⩾ σ_Hmin mainly occurs in deep and shallow to intermediate coal seams (400–600 m and >1000 m). The ratio of maximum and minimum horizontal principal stress versus depth shows linear relationships with a correlation coefficient of 0.77 and 0.85, separately. The ratio of the maximum horizontal principal stresses to vertical stress is usually between 0.5 and 2.0 in coal seams, and decreases as the depth increases and approaches 1.0. The coefficient of average lateral stress versus depth (λ) is also illustrated, which shows a wide range at shallow sites from 0.48 to 1.80, and then gradually decreases to a fixed value as the depth increases. Coal permeability obtained during injection/falloff tests shows that the permeability is damaged with a trend difference under a depth of 550–750 m for the in-situ stress belting change and other reasons.

The deflection of initial fractures and the formation of new fractures as non-planar fractures were investigated, which both are possible mechanisms for production improvement in refracturing or SRV(Stimulated reservoir volume). Firstly, initial fractures were formed under initial tri-axial stresses loading. Secondly, the formation and development of new fractures from refracturing were stimulated with changing horizontal stresses. The results show that (1) During refracturing new fractures were formed, and the initial fractures were re-opened, initiated and deflected. Whlie most of the deflection was identified as tensile and shear failure. (2) New fractures do not always result from the stress field change. This implied the smaller horizontal stress difference was, the easier the initial fractures were deflected, and the larger horizontal stress difference was, the easier the new single-wing fractures were formed on the walls of the initial fractures; (3) Deflection of initial fractures was more easier than formation of new fractures. The study indicated that, the injection pressure of deflection was lower than the initial breakdown pressure, while the formation of new fractures required higher pressure than initial breakdown pressure. (4) The injection rate contributed to a significant effect on the formation of new fractures. When injection rate was low, the formation of new fractures on the walls of the initial fractures was difficult. But when injection rate was high, new single-wing fractures formation was easily occurred on the walls of the initial fractures.

Optimal development of tight-oil resources requires better petrophysical understanding of several key reservoir and mechanical properties. We highlight these for the Cardium Formation at the Pembina field, where controls on these properties appear to occur within elementary lithological components (ELCs) at the cm- to sub-cm scale moderated in part by the effects of synsedimentary bioturbation. This complexity in reservoir behavior necessitates new and innovative approaches for petrophysical property estimation, which is the subject of the current work. The workflow outlined starts with the quantification of the volumetric distribution of ELCs. For this purpose, 360° photographic imaging was used to first identify ELCs, and then quantify their volumetric percentages in whole core. This initial step is limited to the exposed surfaces of the core, consequently we used X-ray computed tomography (XRCT) in order to project the ELCs volumetric distribution into the core interior. The correlation between CT number, mineralogy, and bulk density of the rock further allowed porosity to be calculated from XRCT and shed light on its distribution throughout the core interior. Variations in fine-scale permeability were evaluated by collecting pressure-decay profile permeability measurements across a core slab surface following a 5 × 5 mm-2D grid. Relationships between ELCs permeability and porosity were then generated and, when combined with the volumetric distribution of ELCs previously assessed, enabled a 3D distribution of reservoir quality at the mm-scale throughout the core. Finally, microhardness data was collected on the same 2D grid enabling ELC-scale quantification of mechanical properties. Reservoir properties of whole core samples identified in previous publications appear to be reasonably predicted when utilizing ELCs-specific permeability versus porosity transforms and volumetric percentages generated in this study, thus demonstrating scale-up potential.

Production from tight formation resources leads to the growth in U.S. crude oil production. Compared with chemical flooding and water flooding, gas injection is a promising enhanced oil recovery (EOR) approach in shale reservoirs. A limited number of experimental studies concerning gas flooding in the literature have focused on unconventional plays. This paper presents experimental work for applying an immiscible N₂ flooding process in oil-saturated shale plugs. To investigate the effect of injection pressure on recovery performance, multiple core-flood tests were performed at the injection pressures of 1000 psi, 3000 psi, and 5000 psi, respectively. A lab-scale numerical simulation model was built to match the experimental data. Based on this model, we conducted sensitive studies and analyzed the recovery process.

The potential of N₂ flooding for improving oil recovery from shale core plugs has been demonstrated by the experimental observations and simulation results. Under a certain injection pressure, the results show that the oil was produced with a high and stable production rate at the initial period of the recovery process, before gas breakthrough. After that, the incremental RF decreased with the increase of a flooding period, and a much longer time had less effect on extracting more oil. We also examined the effect of injection pressure on gas breakthrough time, ultimate RF, and oil recovery history. This study illustrates that gas flooding could be considered as an improved oil recover (IOR) approach in shale oil reservoirs.

Novel reservoir engineering displacement fluids (cetyltrimethylammonium bromide and sodium salicylate in water) are examined as candidates for proppant placement during fracturing. The need for additional crosslinkers, breakers or contact with hydrocarbons to change the viscosity is eliminated. These materials have a viscoelastic response governed by flow. Two fluid compositions are investigated in relation to Newtonian fluids of similar base viscosity to determine how shear induced structures (SIS) influence flow properties in the near-wellbore region of a fracture. In Couette flow, the fluid displays shear thickening and thinning within a discrete shear regime. Extensional flow tests in a microfluidic device reveal a flow resistance up to 25 times higher than Newtonian fluids. This extra flow resistance is due to an induced intermicellar network and has potential application for improved proppant carrying after injection via a perforation. Particle image velocimetry is used to visualise the entrance flow in a fracture. Instabilities are reduced as flow through the perforation increases. The viscosity contrast ratio between zero-shear viscosity and maximum viscosity response determines the extra proppant carrying capacity.

The mesostructures of aqueous solutions (one simple type of water-based drilling fluids), with a kinetic hydrate inhibitor (polyvinyl pyrrolidone, PVP) or/and drilling fluid additive (sodium carboxymethyl cellulose, CMC), and their rheological properties after two shearing actions (600 r/min and 6000 r/min) were respectively investigated using a scanning electronic microscope (SEM) and a six-speed rotation viscometer, considering the different shearing actions imposed on drilling fluids during their circulation in the well. The results show (1) aqueous solutions with polymers (CMC, PVP and CMC + PVP) exhibit three different types of network framework (normally in the size of several to tens of micrometers), thin films + thin rods, globular particles + thin rods, and thin films + thin slices. Upon increasing the concentration of CMC or/and PVP, the thickness of the backbones and branches of the network framework increased, causing the volume of the pore space to decrease and the apparent viscosity and shear stress to increase. The tackifying effect of CMC was stronger than that of PVP, and the synergistic effect of CMC and PVP apparently increased the apparent viscosity and the shear stress. (2) With the shear rate increasing from 600 r/min to 6000 r/min, the apparent viscosities and shear stresses of these aqueous solutions decreased to some degree, and the four aqueous solutions of 0.75 wt% CMC, 1.5 wt% PVP, 0.75 wt% CMC + 1 wt% PVP, and 0.75 wt% CMC + 1.5 wt% PVP had relatively larger decreases in the apparent viscosity and the shear stress, which might result from changes in the spatial morphology of the network framework and the pore space, the spatial distribution and contents of the three different states of water, and the mobility of free water. The changes in the mesostructures might affect the local conditions of the heat and mass transfer in hydrate dissociation and formation in the annular space.

The production from shale resources in the US has shifted from the gas window to the condensate and oil windows recently due to the low natural gas price. Liquid-rich shales, such as Barnett, Woodford and Eagle Ford Shales, etc., are brought more attentions than ever before. Therefore, it is critical to understand the fluid phase behavior and their impacts on production in the condensate systems.

Fluid phase behavior in porous media is governed by not only fluid molecule–fluid molecule interactions but also fluid molecule-porous media wall interactions. In the shale formations, a large amount of hydrocarbons are stored within the organic matters where the pore sizes are in the order of nanometers. Inside these nanopores, the interactions between the fluid molecules and porous walls play such an important role that can change the fluid properties of the stored fluids. Our work focused on the predictions of fluid density distributions of both dry gas and liquid rich systems inside nanoporous media. Simplified Local-Density theory coupled with Modified Peng–Robinson Equation of State was used to predict the density profiles of pure and mixture hydrocarbons in confined pores. Adsorption isotherms were generated based on the density profiles calculated. The adsorption isotherms of pure methane and the methane/ethane binary mixture were calculated and compared to experimental data and molecular simulation results in the literature with excellent accuracy.

Our results showed that due to the fluid-wall interactions, the fluid density is not uniformly distributed across the pore width. In general, the fluid density is higher near the porous media wall than that in the center of the pore. It also showed the fluid density profiles are temperature, pressure, pore size and fluid composition dependent. In general, the adsorbed amount increased by increasing pressure and decreased by increasing temperature. The pore size range of interest is from 2 nm to 20 nm. In order to present the condensate system, a binary mixture of 80% methane and 20% n-butane was used. It was found that fluid composition for the fluid mixture was not uniformly distributed across the pore. Heavier component (n-butane) tended to accumulate near the wall while lighter component (methane) would like to stay in the center region of the pore. For the methane/ethane binary mixture, the composition of methane in confined space was found much smaller than the bulk methane composition. For example, the methane composition in confined silicalite is 7% when the bulk methane composition is 50% at 355 kPa and 300 K.

Fundamentally, recovery methods of untapped crude oils require injection of foreign material(s) in the reservoir, which subsequently promote(s) the displacement of residual oil. In chemical enhanced oil recovery (EOR), the microscopic sweep efficiency depends primarily on achievement of a low interfacial tension. The present work investigates into the surface tension and phase behavior properties of microemulsion developed from a contact between a dimeric ammonium salt surfactant achieve an ultra-low interfacial tension (IFT) was compared with a conventional polysorbate surfactant commonly used in chemical EOR. At fairly low concentration, dimeric surfactants achieved an IFT of order of 10⁻³ mN/m. Salinity tolerance and IFT were significantly altered not only by the heaviness i.e. API of the crude, but also by the reservoir conditions. Moreover, alkane carbon number (ACN), introduced in this work, revealed that modeling a micellar slug formulation solely based on chemical composition of the crude and/or its nature could be misleading. Presence of divalent ions was found to promote the increase in IFT rather to a shift to a lower value. Also, a relative low adsorption of micellar slug was found in both dolomite and Berea sandstone. However, active head of the dimeric surfactant showed a preferential attachment to carbonate rock while low interactions were observed for sandstone. Lastly, the present study has highlighted an inhibiting acidity activity for dimeric ammoniums salt surfactants.