Multilayer commingled production is an important development method for most hydrocarbon reservoirs because there are multiple profitable production layers vertically. Commingled production method can not only reduce drilling cost, but also improve hydrocarbon reservoir recovery. The investigation of gas production characteristics of multilayer commingled production in gas reservoirs can not only reflect the effect of interlayer heterogeneity on the percolation law, but also reveals the reserves mobility and gas production capacity of different gas layers. However, the differences in petrophysical properties, temperature and pressure conditions, gas saturation, effective thickness and geometric parameters of different gas layers make the gas production characteristics of each layer complicated during multilayer commingled production.
Most of the ultradeep carbonate gas reservoirs in the Sichuan Basin are connected with edge and bottom water bodies, and the reserves of gas reservoirs with water account for 80% of the total reserves. The Cambrian Longwangmiao Formation gas reservoir with severe water encroachment is a typical representative. The water encroachment characteristics of gas reservoirs are not only affected by external water bodies, but also closely related to their own initial water content conditions. Therefore, revealing the gas–water relationship in the reservoir under initial conditions and during exploitation is crucial for clarifying the water encroachment characteristics. The complex gas–water relationship in ultradeep carbonate gas reservoirs is mainly caused by the multiple types of reservoir media and strong heterogeneity. Insufficient understanding of the gas–water relationship not only affects the predictions of gas percolation characteristics and gas well production performance, but also restricts the long-term and efficient development of this type of gas reservoir.
Miscible CO2 soaking alternating gas (CO2-SAG) flooding is an improved version of CO2 flooding, which compensates for the insufficient interaction of CO2 and crude oil in the reservoir by adding a CO2 soaking process after the CO2 breakthrough (BT). The transmission of CO2 in the reservoir during the soaking process is controlled by the pore throat structure of the formation, which in turn affects the displacement efficiency of the subsequent secondary CO2 flooding. In this work, CO2-SAG flooding experiments at reservoir conditions (up to 70 °C, 18 MPa) have been carried out on four samples with very similar permeabilities but significantly different pore size distributions and pore throat structures. The results have been compared with the results of CO2 flooding on the same samples. It was found that the oil recovery factors (RFs) when using CO2-SAG flooding are higher than those when using CO2 flooding by 8–14%. In addition, we find greater improvements in the RF for rocks with greater heterogeneity of their pore throat microstructure compared with CO2 flooding. The CO2 soaking process compensates effectively for the insufficient interaction between CO2 and crude oil because of premature CO2 BT in heterogeneous cores. Moreover, rocks with a more homogeneous pore throat microstructure exhibit a higher pressure decay rate in the CO2 soaking process. The initial rapid pressure decay stage lasts for 80–135 min (in our experimental cores), accounting for over 80% of the total decay pressure. Rocks with the larger and more homogeneous pore throat microstructure exhibit smaller permeability decreases because of asphaltene precipitation after CO2-SAG flooding, possibly because the permeability of rocks with a more heterogeneous and smaller pore throat microstructure is more susceptible to damage from asphaltene precipitation. However, the overall permeability decline is 0.6–3.6% higher than that of normal CO2 flooding because of the increased time for asphaltene precipitation. Nevertheless, the corresponding permeability average decline per 1% oil RF is 0.11–0.34%, which is lower than that for CO2 flooding, making the process worthwhile. We have shown that CO2-SAG flooding has the potential to improve oil RFs with relatively less damage to cores, especially for cores with small and heterogeneous pore throat microstructures, but for which severe wettability changes due to the CO2 soaking process can become significant.
The fractal dimension is a basic parameter to indicate the random self-similar shape and phenomena. The damage process is the result of co-effect of all the cracks, which shows a good collective behavior and random statistical complexity. The collective evolution of short fatigue cracks was experimentally studied through cylindrical specimens with annular notches with respect to the variation of nominal strain amplitudes. The maximum between-class variance method (Otsu's method) was adopted for the denoised image binarization and the fractal dimensions were obtained. The results show that: the collective behavior of short fatigue cracks possesses good fractal characteristics; as the evolution of the short fatigue cracks, fractal dimensions underwent two stages: a primary stage of high growth speed, a relatively stable stage of almost to zero growth speed; the critical cut-off point at about 30% of the fatigue life according to the experimental results can be used to represent a threshold value of the MSC and PSC of short fatigue cracks.
High-pressure sorption isotherms of CH4, C2H6, and their mixtures on shales from Sichuan Basin, China, were measured by a volumetric method. The sorption measurements for pure components were conducted at 40, 60, and 80 °C, with the pressure up to ∼20 MPa. The binary sorption measurements were performed to ∼11 MPa at 40 °C and ∼16 MPa at 80 °C, and two feed gas compositions of C2H6 (10 and 20%) were studied. The excess sorption isotherms of pure components were fitted by the three-parameter Langmuir model, and the extended Langmuir (EL) model was used to predict the absolute sorption isotherms of binary mixtures. The sorption discrepancies of CH4/C2H6 were discussed, and the preferential sorption of C2H6 was quantitatively analyzed. As the temperature decreases, the excess sorption isotherm of C2H6 presents a more sharp increase and then a more rapid decrease. The excess sorption isotherms of C2H6 at 40 °C show significant differences with other CH4/C2H6 isotherms. In comparison to gas composition, the temperature has a more notable effect on binary excess sorption isotherms. C2H6 shows a stronger affinity than CH4, and its stronger affinity is less significant in the mixtures compared to the single component. The sorption selectivity presents a first increasing and later decreasing trend with the pressure. The presence of C2H6 mainly reduces the excess sorption of CH4 at a high pressure, and its effect at a low pressure is negligible.
Organic-matter content (OMC) is an important property of a shale-gas reservoir. Quantitative seismic interpretation of OMC can be difficult because OMC can be determined by various properties of shales. In this paper, we propose an OMC seismic interpretation method based on the random forest algorithm (RFA). Real log data is used to evaluate the viability of this method. One major advantage of this method is that the prediction result is stable and has high accuracy even if the types and quantities of predictor are small. We also applied the new method to a real 3D seismic dataset of a Lower Silurian shale-gas reservoir formation in the south of Sichuan Basin. A comparison between seismic interpretation result and well logs demonstrates the feasibility of this method. Presentation Date: Tuesday, September 17, 2019 Session Start Time: 9:20 AM Presentation Start Time: 10:10 AM Location: Poster Station 5 Presentation Type: Poster
It is difficult to investigate the formation process and occurrence states of water in multi-type reservoirs, due to the strong heterogeneity and complex microstructure of the fracture–cavity carbonate gas reservoirs. To date, there is no systematic study on the occurrence characteristics of multi-type formation water, especially through visual observation experiments. In this paper, a new creation method for visual micromodels based on CT scan images and microelectronic photolithography techniques was described. Subsequently, a gas–drive–water visual experiment was conducted to intuitively study the formation mechanism and the occurrence states of formation water. Then, the ImageJ gray analysis method was utilized to quantitatively investigate the gas-water saturation and the proportion of residual water film. Finally, the occurrence characteristics of formation water and its effects on gas seepage flow were comprehensively analyzed. Visual experimental results showed that: the migration processes of natural gas in different types of reservoirs are different; the water in multiple media consists of native movable water and residual water, and residual water is composed of secondary movable water and irreducible water; the residual water mainly occurs in different locations of different reservoirs with the forms of “water film”, “water mass”, “water column” and “water droplets”; the main influencing factors are capillary force, surface tension, displacement pressure and channel connectivity. Quantitative results reflect that the saturation of movable water and residual water are the parameters related directly to reservoir physical properties, pore structure and displacement pressure—the smaller the size of flow channel, the larger the space occupied by water film; the thickness proportion of water film is increasing exponentially with the channel size; the thickness proportion of water film decreases as the increase of displacement pressure; the thickness proportion of water film is essentially constant when the displacement pressure increases to a certain extent. The conducted visual investigation not only improves our intuitive understanding of the occurrence characteristics of formation water, but also provides a theoretical basis for the efficient development of fracture-cavity gas reservoirs.
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