An improved method in petrophysical rock typing based on mercury-injection capillary pressure data

Tang, Xiao; Zhou, Wenyin; Yang, Weili; Zhang, Chong; Zhang, Chaomo

doi:10.1080/15567036.2020.1800140

Cited by 5 publications

(3 citation statements)

References 25 publications

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“…As shown in Figures 4-6, increasing the injection As shown in Figure 9, the oil recovery factors obtained from experiments on core C (Tor formation) have higher MFZI in comparison with core B (Ekofisk formation). Thus, core C from the Tor formation belongs to a different rock type than core B according to standard FZI-based rock type analysis [62,63]. This shows that higher MFZI can attribute in higher recovery factors for experiments on core plug C. It can be seen in this plot that the recovery factors for SW injection lie under the linear trend passing the recovery factors for FW, whereas the recovery factors for DSW lie above this trend line.…”

Section: Capillary End Effectmentioning

confidence: 82%

Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

et al. 2021

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We present a systematic study of crude oil–brine–rock interactions in tight chalk cores at reservoir conditions. Flooding experiments are performed on outcrops (Stevns Klint) as well as on reservoir core plugs from Dan field, the Ekofisk and Tor formations. These studies are carried out in core plugs with reduced pore volumes, i.e., short core samples and aged with a dynamic ageing method. The method was evaluated by three different oil compositions. A series of synthetic multicomponent brines and designed fluid injection scenarios are investigated; injection flow rates are optimized to ensure that a capillary-dominant regime is maintained. Changes in brine compositions and fluid distribution in the core plugs are characterized using ion chromatography and X-ray computed tomography, respectively. First, we show that polar components in the oil phase play a major role in wettability alteration during ageing; this controls the oil production behavior. We also show that, compared to seawater, both formation water and ten-times-diluted seawater are better candidates for enhanced oil recovery in the Dan field. Finally, we show that the modified flow zone indicator, a measure of rock quality, is likely the main variable responsible for the higher oil recoveries observed in Tor core samples.

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Section: Capillary End Effectmentioning

confidence: 82%

Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

et al. 2021

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“…In recent years, many researchers have investigated the methods for reservoir classification based on the NMR T 2 distribution. The main idea of reservoir classification methods based on NMR logging is to convert the NMR T 2 distribution to capillary pressure curves based on HPMI experiments and, thereby, obtain the pore structure parameters (e.g., displacement pressure and median radius) for pore structure evaluation and reservoir classification. − On the basis of the correlation between the NMR T 2 distribution and pore-throat size distribution, a method for pore structure identification was established, where NMR was used to investigate the characteristics of pore structures . This method provides a basis for the evaluation of tight sandstone reservoirs.…”

Section: Introductionmentioning

confidence: 99%

Classification of Tight Sandstone Reservoirs Based on the Nuclear Magnetic Resonance T₂ Distribution: A Case Study on the Shaximiao Formation in Central Sichuan, China

et al. 2022

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The classification of tight sandstone reservoirs is of significance for hydrocarbon exploration and production. Different from conventional reservoirs, tight sandstone reservoirs are characterized by a complex pore structure and strong heterogeneity. Tight sandstone reservoir classification may not be reliable with conventional reservoir classification methods. In this paper, a classification method of tight sandstone reservoirs was proposed on the basis of the nuclear magnetic resonance (NMR) transverse relaxation (T 2 ) distribution, and it was employed for reservoir classification on the Shaximiao Formation in central Sichuan, China. As a result of the complex pore structure of a tight sandstone reservoir, the NMR T 2 distribution is characterized by the presence of multiple peaks. Therefore, the three-peak Gaussian function was used to fit the T 2 distribution and obtain the characteristic parameters. On the basis of high-pressure mercury intrusion (HPMI) experiments, the correlation between the characteristic parameters of the NMR T 2 distribution and pore structure parameters and petrophysical properties was analyzed, and then the optimal characteristic parameters of the NMR T 2 distribution were selected according to the results of correlation analysis and used to establish the pore structure index. In combination of petrophysical properties with the pore structure index, the model for classification of tight sandstone reservoirs was established by the naive Bayesian method based on hierarchical clustering, and the accuracy of the model was verified by k-fold cross-validation. Finally, the effectiveness of the proposed method was verified using the actual NMR logging data in conjunction with the oil test data. The results showed that the method for classification of tight sandstone reservoirs based on the NMR T 2 distribution can provide effective guidance for production capacity evaluation.

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“…In recent years, with the development of new exploration technologies, unconventional reservoirs have become the research focus in the field of petroleum exploration. − Conventional methods are no longer applicable to the evaluation of unconventional reservoirs, like sandstone reservoirs. Therefore, to improve the evaluation of unconventional reservoirs, it is necessary to quantitatively characterize their pore structures. − Because pore structure parameters are obtained using mercury injection capillary pressure (MICP) curves, based on which the type of reservoir can be determined, − the accurate determination of MICP curves is of great importance. − Currently, MICP curves are generally obtained through MICP experiments. However, in actual exploration, it is difficult to obtain a large number of core samples, which are then destroyed by mercury injection measurements. , Therefore, non-destructive methods by which to continuously obtain reservoir MICP curves for reservoir evaluation have become a key subject of oil and gas exploration. , …”

Section: Introductionmentioning

confidence: 99%

Novel Method for Predicting Mercury Injection Capillary Pressure Curves of Tight Sandstone Reservoirs Using NMR T₂ Distributions

Xie

et al. 2021

Energy Fuels

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In this research, mercury injection capillary pressure (MICP) experiments and nuclear magnetic resonance (NMR) experiments were carried out on 19 reservoir core samples. Based on the experimental results, the relationships between the capillary pressure (P c ) and NMR transverse relaxation time (T 2 ) were established. A novel classified piecewise multi-parameter power function transformation (CPMPFT) method is proposed to predict the MICP curves using the NMR T 2 distributions and is described as follows. First, the multi-parameter power function transformation model is established, after which the reservoir is classified and the appropriate pore segmentation point is selected. Then, for each type of reservoir, the coefficients of the transformation model for large and small pores are calculated based on the simulated annealing and genetic algorithm combined with non-linear programming, and the models for predicting the MICP curves are ultimately obtained. Using these models, the MICP curves can be predicted continuously based on the NMR T 2 distribution, based on which the pore structure parameters, including the displacement pressure (P d ), median pressure (P c50 ), and so forth, can be precisely extracted. 19 core samples and well data were processed using the proposed method, and the predicted results were compared with the measured results; the results were found to match well, thereby proving the reliability of the proposed method.

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An improved method in petrophysical rock typing based on mercury-injection capillary pressure data

Cited by 5 publications

References 25 publications

Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

Classification of Tight Sandstone Reservoirs Based on the Nuclear Magnetic Resonance T₂ Distribution: A Case Study on the Shaximiao Formation in Central Sichuan, China

Novel Method for Predicting Mercury Injection Capillary Pressure Curves of Tight Sandstone Reservoirs Using NMR T₂ Distributions

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An improved method in petrophysical rock typing based on mercury-injection capillary pressure data

Cited by 5 publications

References 25 publications

Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

Crude Oil–Brine–Rock Interactions in Tight Chalk Reservoirs: An Experimental Study

Classification of Tight Sandstone Reservoirs Based on the Nuclear Magnetic Resonance T2 Distribution: A Case Study on the Shaximiao Formation in Central Sichuan, China

Novel Method for Predicting Mercury Injection Capillary Pressure Curves of Tight Sandstone Reservoirs Using NMR T2 Distributions

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Classification of Tight Sandstone Reservoirs Based on the Nuclear Magnetic Resonance T₂ Distribution: A Case Study on the Shaximiao Formation in Central Sichuan, China

Novel Method for Predicting Mercury Injection Capillary Pressure Curves of Tight Sandstone Reservoirs Using NMR T₂ Distributions