Coupling Relationship between Lithofacies and Brittleness of the Shale Oil Reservoir: A Case Study of the Shahejie Formation in the Raoyang Sag

Analyzing the characteristics of rock brittleness in low-permeability mudstone and shale (MS) formations is imperative for efficient hydraulic fracturing stimulation. Rock brittleness depends on the mineral composition, organic matter abundance, and bedding structure. Based on the MS from Shahejie Formation mineral composition (clay mineral, felsic mineral, and calcareous mineral contents), total organic content, and bedding structure (laminated, laminar, and massive), six types of lithofacies were identified: clay-rich MS, felsic-rich MS, calcareous-rich MS, clay MS, felsic MS, and calcareous MS. The quartz, feldspar, calcite, and dolomite of the Shahejie Formation are brittle minerals. Consequently, lithofacies with high felsic and calcareous mineral contents are more brittle. In addition, laminated and laminar MS are also conducive to hydraulic fracturing. Therefore, laminated, organic-rich, and calcareous-rich MS are the dominant lithofacies for hydraulic fracturing in the Shahejie Formation. The lithofacies and brittleness index were predicted by the response characteristics between mineral compositions and logging curves. The 3521–3552 m section of well B11x is dominated by calcareous-rich MS with developed laminae, representing a favorable section for hydraulic fracturing. Fragile minerals and oil are widely developed in the lower part of the lower 1st member of the Shahejie Formation (Es1L) in the southwestern part of Zhaohuangzhuang-Suning, where hydraulic fracturing can be used to increase shale oil production.

Oil Occurrence States in Shale Mixed Inorganic Matter Nanopores

In present paper, the mineral and fluid compositions of shale oil from the Songliao Basin are analyzed systematically using core samples, X-ray diffractometer (XRD), and gas chromatography (GC). The effects of shale mineral composition, pore size, temperature, and pressure on the mass density of the adsorbed layers are then studied utilizing molecular dynamics simulation. The results show that illite and quartz are predominant in the micro petrological components of the shale, and nC19 is the main carbon peak. The fluid consists primarily of n-alkane molecules, and nC19 is found to be representative of the shale oil composition. Moreover, the adsorbing effect of quartz-illite mixed wall is between that of a pure mineral wall (illite and quartz), indicating that the selection of a mixed wall is similar to the actual shale composition. If the pores are inorganic, the minimum pore size of only adsorption oil is smaller than the organic pores. The critical adsorption point of shale oil in inorganic pores is less than 3.2 nm. Furthermore, compared to pressure, the temperature has a more significant effect on fluid adsorption due to the correlation with the kinetic energy of alkane molecules. This research shows the oil occurrence status in inorganic matter nanopore with a mixed solid wall, and provides theoretical support for shale oil exploration.

Fractal characteristics of the micropore throats in the shale oil reservoirs of the Chang 7 Member of the Yanchang Formation, Ordos Basin

With the development of the global shale oil and gas revolution, shale oil became an important replacement field to increase oil and gas reserves and production. The Chang 7 Member of the Yanchang Formation in the Ordos Basin was an important shale oil exploration series in China. To study the micropore-throat structure characteristics of the Chang 7 Member, we launched nuclear magnetic resonance (NMR) and high-pressure mercury injection (HPMI) experiments to analyze the pore-throat structure features of the Chang 7 reservoir, and we considered fractal theory to study the fractal characteristics. The NMR results indicated that the T2 spectral morphology of the Chang 7 reservoir could be characterized by three main patterns encompassing early and late peaks with different amplitudes: the type 1 reservoir contained mostly small pores and few large pores, and the porosities of the small and large pores range from 4.16% to 9.04% and 0.70% to 2.40%, respectively. The type 2 reservoir contained similar amounts of small and large pores, and the type 3 reservoir contained few small pores and mostly large pores, while the porosities of the small and large pores range from 1.81% to 2.74% and 3.32% to 5.64%, respectively. The pore-throat structure parameters were obviously affected by the pore size distribution, which in turn influenced the reservoir seepage characteristics of the reservoir. The micropore-throat structure of the reservoir exhibited obvious piecewise fractal characteristics and mainly included dichotomous and trilateral fractals. The type 1 reservoirs were dominated by dichotomous fractals, and these two fractal types were equally distributed in the type 2 and 3 reservoirs. The fractal dimension of the pore throats of different scales exhibited a negative correlation with the corresponding porosity, but no correlation was observed with the permeability, indicating that the size of the reservoir determined by pore throats imposed a strong controlling effect on their fractal characteristics.

Simultaneous Experimental Analysis of Oil Content And Molecular Composition of Shale Fractions

The important research content and basis of exploration and development is to evaluate the reservoir property, oil bearing property, fluidity and compressibility of shale reservoir.The key of exploration and development is to evaluate the oil-bearing and fluidity of shale reservoir.In this paper, the "shale oil content and fine components synchronous experimental analysis device" is used. Five temperature ranges of 30 ℃-90 ℃, 90 ℃-150 ℃, 100 ℃- 200 ℃, 150 ℃-250 ℃ and 250 ℃-300 ℃ were adopted. The heating rate of each temperature segment was 25 ℃ / min, and the final temperature was kept constant for 5 min. The oil content of shale (pyrolysis S1) was cut into five fractions.Simultaneous determination of oil content and molecular composition of shale fractions,and the external standard method was used to evaluate the oil content and fluidity.The results show that the five fractions of shale are mainly composed of nC1-nC9 gas, nC10-nC15 gasoline, nC12-nC20 kerosene, nC15-nC22 diesel oil and nC18-nC26 heavy oil of the first member of Qingshangkou formation in Songliao basin.There are differences in the fractionation and oil content characteristics of samples with different maturity in different wells.The parent material, properties and quality of crude oil are reflected in shale. The higher the maturity of shale oil is, the more light components are, the larger the light / heavy ratio parameter value of (gasoline + kerosene + diesel) and heavy oil is, the better the fluidity is, and the easier to exploit effectively.

CO2 Mass Transfer and Oil Replacement Capacity in Fractured Shale Oil Reservoirs: From Laboratory to Field

CO2-based fracturing is widely introduced to stimulate shale oil reservoirs for its multiple advantages. However, the range of CO2 entering the matrix around fractures and CO2-oil replacement capacity between matrix and fractures cannot be fully explained. To address this issue, a radial constant volume diffusion experiment on shale cores was designed in this study, and the pressure drop curve history was matched through numerical model to determine the composition effective diffusion coefficient. A field-scale numerical model was established, in which a series of certain grids were used to explicitly characterize fracture and quantify the prosess of CO2 mass transfer and oil replacement. Based on the field-scale numerical model, the process of shut-in, flow back, and oil production was simulated. The distribution of CO2 in fractured shale oil formation and its impact on crude oil during shut-in stage and flow back stage were investigated. This study concludes that CO2 gradually exchanges the oil in matrix into fractures and improve the fluidity of oil in matrix until the component concentrations of the whole reservoir reaches equilibrium during the shut-in process. Finally, about 30∼35 mole % of CO2 in fractures exchanges for oil in matrix. The range of CO2 entering the matrix around fractures is only 1.5 m, and oil in matrix beyond this distance will not be affected by CO2. During the process of flow back and production, the CO2 in fracture flows back quickly, but the CO2 in matrix is keeping dissolved in oil and will not be quickly produced. It is conclued that the longest possible shut-in time is conducive to making full use of the CO2-EOR mechanism in fractured shale oil reservoirs. However, due to the pursuit of economic value, a shut-in time of 10 days is the more suitable choice. This work can provide a better understanding of CO2 mass transfer mechanism in fractured shale oil reservoirs. It also provides a reference for the evaluation of the shut-in time and production management after CO2 fracturing.