With the decline of conventional resources, the tight oil reserves in the Daqing oilfield are becoming increasingly important, but measuring relative permeability and determining production forecasts through laboratory core flow tests for tight formations are both difficult and time consuming. Results of laboratory testing are questionable due to the very small pore volume and low permeability of the reservoir rock, and there are challenges in controlling critical parameters during the special core analysis (SCAL) tests. In this paper, the protocol and workflow of a digital rock study for tight sandstones of the Daqing oilfield are discussed. The workflow includes 1) using a combination of various imaging methods to build rock models that are representative of reservoir rocks, 2) constructing digital fluid models of reservoir fluids and injectants, 3) applying laboratory measured wettability index data to define rock-fluid interaction in digital rock models, 4) performing pore-scale modelling to accelerate reservoir characterization and reduce the uncertainty, and 5) performing digital enhanced oil recovery (EOR) tests to analyze potential benefits of different scenarios. The target formations are tight (0.01 to 5 md range) sandstones that have a combination of large grain sizes juxtaposed against small pore openings which makes it challenging to select an appropriate set of imaging tools. To overcome the wide range of pore and grain scales, the imaging tools selected for the study included high resolution microCT imaging on core plugs and mini-plugs sampled from original plugs, overview scanning electron microscopy (SEM) imaging, mineralogical mapping, and high-resolution SEM imaging on the mini-plugs. High resolution digital rock models were constructed and subsequently upscaled to the plug level to differentiate bedding and other features could be differentiated. Permeability and porosity of digital rock models were benchmarked against laboratory measurements to confirm representativeness. The laboratory measured Amott-Harvey wettability index of restored core plugs was honored and applied to the digital rock models. Digital fluid models were built using the fluid PVT data. A Direct HydroDynamic (DHD) pore-scale flow simulator based on density functional hydrodynamics was used to model multiphase flow in the digital experiments. Capillary pressure, water-oil, surfactant solution-oil, and CO2-oil relative permeability were computed, as well as primary depletion followed with three-cycle CO2 huff-n-puff, and primary depletion followed with three-cycle surfactant solution huff-n-puff processes. Recovery factors were obtained for each method and resulting values were compared to establish most effective field development scenarios. The workflow developed in this paper provides fast and reliable means of obtaining critical data for field development design. Capillary pressure and relative permeability data obtained through digital experiments provide key input parameters for reservoir simulation; production scenario forecasts help evaluate various EOR methods. Digital simulations allow the different scenarios to be run on identical rock samples numerous times, which is not possible in the laboratory.
Relative permeability is one of the most important petrophysical parameters to evaluate a reservoir’s production during primary and subsequent secondary or enhanced oil recovery processes. Yet measured relative permeability data for tight oil reservoirs are very scarce to find in the literature, mainly because the measurement is difficult and time consuming to make. In this paper the protocol and results of water/oil, surfactant /oil, CO2/oil, and N2/oil relative permeability are presented, and compared to the digital core analysis results where wettability was set to water-wet or mixed-wet, as well as the Brooks-Corey model. Amott-Harvey wettability index was measured to explain the differences. The target formation is a sandstone tight oil formation located in Songliao Basin, China. Its permeability is mostly in the 0.01-5mD range. Core and oil samples from the target formation were used in the wettability and relative permeability determination. Relative permeability was measured at reservoir conditions using a customized core flow setup. Core samples were cleaned then wettability restored. To match the reservoir fluid viscosity and avoid changing wettability, stock tank oil was blended with kerosene to reservoir fluid viscosity at reservoir temperature. Relative permeability was measured using the unsteady-state method. Amott-Harvey wettability index was measured on core samples from the same formation at reservoir temperature. Amott-Harvey wettability index results show that the restored wettability ranged from water-wet to oil-wet, with most samples being mixed-wt. The addition of non-ionic surfactant promoted wettability change toward more water-wetness. However, anionic surfactant had little effect on reversing wettability. Oil relative permeability (Kro) results obtained from the digital rock analysis (DRA) assuming uniform water-wetness are consistent with relative permeability calculated from mercury injection capillary pressure using Brooks-Corey model. When wettability of the digital rock model was set to mixed-wet, the resulted Kro matches the measured Kro of a sister plug to the sample used to build the digital rock model, which is consistent with the wettability measurements. The addition of surfactants increased both water and oil relative permeability through wettability alteration and IFT reduction. CO2 flood was conducted as an immiscible flood due to reservoir pressure lower than MMP. CO2 flood left high residual oil saturation compared with water floods. N2 flood left even more oil behind compared with CO2 flood. Relative permeability provides key input parameters for formation evaluation and the subsequent EOR processes such as huff-n-puff operations. There are very little published relative permeability data for tight oil reservoirs. This work extends the relative permeability database, and is a starting point for future EOR work.
The carbonate reservoirs in the middle Sichuan area have undergone complicated tectonics, resulting in various types of reservoir space, large secondary changes, and multiple complexities. Taking the tight carbonate gas reservoir of the Deng-4 member in this area as an example, based on casting thin sections, scanning electron microscopy, and high-pressure mercury injection experiments, the reservoir space and microstructural characteristics of the micropore throats were studied, and the influence of the microscale heterogeneity in different types of reservoirs on the seepage capacity was analyzed by applying fractal theory. The results showed that the reservoir space in the tight carbonate rock of the Deng-4 member in the study area could be divided into 3 types: pore-hole-fracture, pore-hole, and pore types. The distribution characteristics of the pore throat diameter were multimode wide type, double-mode high and low asymmetrical type, and single-mode concentrated type. The fractal dimension and seepage capability of the pore throat increased successively in sizes from less than 0.1 μm to 0.1~1.0 μm and greater than 1.0 μm. On the one hand, the development of karst caves and fractures controlled the percolation ability of tight carbonate reservoirs; on the other hand, it enhanced the heterogeneity of the micropore throat structure. However, the development degree of dissolved pores and microfractures has a weak contribution to the connectivity and seepage capacity of the reservoir space. Acidification, fracturing, and other measures can be adopted to enhance the connectivity between pores to improve the productivity of the gas reservoir. This study provides a scientific basis for the efficient exploration and development of tight carbonate reservoirs.
The characteristics of seepage capability and rock strain during reservoir depletion are important for reservoir recovery, which would significantly influence production strategy optimization. The Cretaceous deep natural gas reservoirs in Keshen Gasfield in Tarim Basin are mainly buried over 5000 m, featuring with ultra-low permeability, developed natural fractures and complex in-situ stress states. However, there is no comprehensive study on the variation of mechanical properties and seepage capability of this gas reservoir under in-situ stress conditions and most studies on stress-sensitivity are conducted under conventional triaxial or uniaxial stress conditions, which cannot truly represent in-situ stress environment. In this work, Cretaceous tight sandstone in Keshen Gasfield was tested under true-triaxial stresses conditions by an advanced geophysical imaging true-triaxial testing system to study the stress-sensitivity and anisotropy of rock stress-strain behavior, porosity and permeability. Four groups of sandstone samples are prepared as the size of 80mm×80mm×80mm, three of which are artificially fractured with different angle (0°,15°,30°) to simulate hydraulic fracturing. The test results corresponding to different samples are compared to further reveal the influence of the fracture angle on rock mechanical properties and seepage capability. The samples are in elastic strain during reservoir depletion, showing an apparent correlation with fracture angles. The porosity decreases linearly with stress loading, where the decrease rate of effective porosity of fracture samples is significantly higher than that of intact samples. The permeabilities decrease exponentially and show significant anisotropy in different principal stress directions, especially in σH direction. The mechanical properties and seepage capability of deep tight sandstone are successfully tested under true-triaxial stresses conditions in this work, which reveals the stress-sensitivity of anisotropic permeability, porosity and stress-strain behavior during gas production. The testing results proposed in this paper provides an innovative method to analyse rock mechanical and petrophysical properties and has profound significance on exploration and development of tight gas reservoir.
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