The Application of Nuclear Magnetic Resonance 1D T2 and 2D T1–T2 Maps in the Research of Condensate Oil Saturation in Condensate Gas Reservoirs

Sun, Bowen; Guo, Ping

doi:10.1021/acs.energyfuels.2c01689

Cited by 3 publications

(1 citation statement)

References 39 publications

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“…A SPEC-RC035 NMR analyzer was used for performing 2D NMR analysis. , The equipment was operated at a frequency of 15 MHz, magnetic field strength of 0.35 T, and room temperature of 25 °C. , The 2D NMR of the as-received sample, the washed oil, and the saturated oil sample was tested. The 2D NMR T 1 –T 2 map is generally used for distinguishing the hydrogen-bearing components in the fine-grained sedimentary rocks and the occurrence states of free oil and adsorbed oil. , The fluid types are divided according to different T 1 /T 2 ratios and T 2 values.…”

Section: Methods and Proceduresmentioning

confidence: 99%

Oil Mobility Evaluation of Fine-Grained Sedimentary Rocks with High Heterogeneity: A Case Study of the Lucaogou Formation in the Jimusar Sag, Junggar Basin, NW China

et al. 2023

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The oil mobility in unconventional tight/shale oil reservoirs is complex because of the high heterogeneity in the matrix pore structure and connectivity. Thus, it is difficult to evaluate hydrocarbon exploration potential precisely. In this study, multistep temperature pyrolysis (MTP) Rock-Eval and 1D (dimensional) as well as 2D nuclear magnetic resonance (NMR) techniques were employed to systematically characterize the oil mobility in lacustrine fine-grained sedimentary rocks from the Lucaogou Formation in the Jimusar Sag, Junggar Basin, NW China. The results show that the Lucaogou Formation fine-grained sedimentary rocks can be subdivided into six types of lithofacies. With the increase of organic matter richness, the content of adsorbed oil increases, whereas the content of movable oil increases first and tends to stabilize (when total organic carbon (TOC) > 4%). This is because when TOC is low, the fine-grained sedimentary rocks need to self-adsorb before oil production; when TOC increases further, the generated oil will break through the absorption limit and charge into the adjacent reservoirs; therefore, the movable oil ceases to increase. Permeability is found to have a greater impact on movable fluid saturation than porosity. Meanwhile, good throat radius and pore connectivity are conducive to oil flow as movable oil is more sensitive to throats rather than pores. Furthermore, a higher content of brittle minerals is not necessarily favorable for oil flow; alternatively, more clay minerals are easy to from cements causing pore blockage, which will essentially hinder oil mobility. Overall, the organic matter content, reservoir pore structure, and rock mineral composition are the main factors affecting tight/shale oil mobility. On the basis of the above research, a conceptual model of oil mobility in different lithofacies’ reservoirs is established. These results have a reference significance for evaluating oil recoverability in fine-grained sedimentary rocks.

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Section: Methods and Proceduresmentioning

confidence: 99%

Oil Mobility Evaluation of Fine-Grained Sedimentary Rocks with High Heterogeneity: A Case Study of the Lucaogou Formation in the Jimusar Sag, Junggar Basin, NW China

et al. 2023

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An Experimental Method for Measuring the Three-Phase Relative Permeability of Oil, Gas and Water By Nuclear Magnetic Resonance

Chang,

Song,

et al. 2023

SPE/IATMI Asia Pacific Oil &Amp; Gas Conference and Exhibition

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The three-phase relative permeability of oil, gas, and water place a significant practical emphasis in the study and evolution of compact sandstone condensate gas traps. However, most investigations on itare relied on forecast patterns that make an effort to appraise it from the relative permeability of two phases. We have measured it of artificial dense sandstone core by online NMR tests. Firstly, the extracting of tight sandstone condensate gas reservoirs was mimicked using a steady-state flow toward, and crude oil, nitrogen and formation water were injected into tight sandstone simultaneously at room temperature according to the variation mechanism of reducing gas injection, and increasing water and oil injection. Secondly, the three-phase saturations were obtained by the different partition of oil-water phases in the 2D T1-T2 spectrum and the volume balance method. Finally, the relative permeability of three phases under various saturations was determined based on Darcy's formula. The findings indicated that in the 2D T1-T2 spectrum, the aqueous phase was mainly concentrated at the position where the T1/T2 ratio was 1, and the oil phase was mainly concentrated at the position where the T1/T2 ratio was greater than 1. Compared with the T2 spectrum, the T1 spectrum could effectively distinguish the oil and water phase, and their boundary was about 10 ms at the T1 relaxation time. The relative permeability of each phase exhibited a trend toward decreasing over time as gas injection decreased and water and oil injection increased. The relative permeability of the water phase dropped, albeit not as much as that of the oil-gas phases. The relative permeability curve of three phases was convex to the point where the oil saturation was equal to 1. As a result, the relative permeability of the gas-oil phases will be significantly impacted within the mining period of tight sandstone condensate gas accumulations when a little amount of condensate water arrives in the reservoir. Therefore, it is necessary to take measures to reasonably control the precipitation of water in condensate gas reservoir. In order to better understand the three-phase relative permeability, an innovative study has been conducted. And its results can more accurately predict and guide the production of condensate gas reservoirs.

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Comparative Laboratory Wettability Study of Sandstone, Tuff, and Shale Using 12-MHz NMR T1-T2 Fluid Typing: Insight of Shale

Wang,

Gu,

Guo

et al. 2024

SPE Journal

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Summary Wettability is a fundamental parameter significantly influencing fluid distributions, saturations, and relative permeability in porous media. Despite the availability of several wettability measurement techniques, obtaining consistent wettability index results, particularly in tight reservoirs, remains a challenge. Nevertheless, obtaining accurate wettability indices is crucial for gaining a more profound understanding of rock properties and precisely identifying and evaluating oil recovery processes. This study adapts T1-T2 nuclear magnetic resonance (NMR) in twin plugs (cores cut in half from the middle) style wettability measurement for different reservoirs. The fluid typing in different lithologies by T1-T2 NMR is proved to be effective by introducing D2O with a modified pressurization saturation process. Therefore, demarcating the regions requires multiple experiments, including sole brine, sole oil phase, and D2O imbibition processes, to define oil and water distribution regions. Such fluid typing ability enables better accuracy in wettability characterization. The weighing method shows good agreement with the T2 spectrum but lacks the ability to differentiate fluids. It is observed that the same fluid in various porous media displays different divisions of T1/T2 ratios. The wettability index of sandstone, tuff, and shale measured by weighing and T1-T2 NMR method are compared and studied to demonstrate the applicability of different methods. The weighing method and the NMR method, as modified-Amott methods, share the same fundamental principle but differ in their measurement techniques. This study’s T1-T2 NMR wettability indices are −0.52, 0.06, and 0.14, whereas the weighing wettability indices are −0.63, 0.07, and 0.34 of sandstone, tuff, and shale, respectively. In addition to the difference in shale wettability index, there are also differences in shale porosity measured by methods with/without the ability to differentiate the fluid types. The T1-T2 NMR method is more accurate in measuring the wettability of shale because it can distinguish among free water in pores, structural water, and clay-bound water in smectitic clay minerals. If the clay-related water is not treated properly, the hydrophilicity of the shale will be overestimated. Ultimately, four types of pores (water-wet, oil-wet, mixed-wet, and unconnected pores) are classified and quantified by the proposed NMR method.

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The Application of Nuclear Magnetic Resonance 1D T₂ and 2D T₁–T₂ Maps in the Research of Condensate Oil Saturation in Condensate Gas Reservoirs

Cited by 3 publications

References 39 publications

Oil Mobility Evaluation of Fine-Grained Sedimentary Rocks with High Heterogeneity: A Case Study of the Lucaogou Formation in the Jimusar Sag, Junggar Basin, NW China

Oil Mobility Evaluation of Fine-Grained Sedimentary Rocks with High Heterogeneity: A Case Study of the Lucaogou Formation in the Jimusar Sag, Junggar Basin, NW China

An Experimental Method for Measuring the Three-Phase Relative Permeability of Oil, Gas and Water By Nuclear Magnetic Resonance

Comparative Laboratory Wettability Study of Sandstone, Tuff, and Shale Using 12-MHz NMR T1-T2 Fluid Typing: Insight of Shale

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