Non-cracked oil in ultra-deep high-temperature reservoirs in the Tarim basin, China

Zhu, Guangyou; Milkov, Alexei V.; Chen, Feiran; Weng, Na; Zhang, Zhiyao; Yang, Haijun; Liu, Keyu; Zhu, Yongfa

doi:10.1016/j.marpetgeo.2017.07.019

Cited by 67 publications

(15 citation statements)

References 44 publications

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“…Insufficient supply of hydrogen might also explain why some oils have not been cracked to gas at reservoir temperature of 200°C and higher as reported by (Dominé et al (1988), Waples (2000) and Zhu et al (2018). Also, total lack of an external supply of hydrogen might be the reason why oil and biomolecules trapped in mineral cements are reported to have endured for more than 2 billion years at maximum temperature higher than 280°C and probably as high as 350°C (George et al, 2008).…”

Section: In-reservoir Maturation Of Oil By External Supply Of Hydrogenmentioning

confidence: 89%

Timing of oil expulsion from source rocks and a revitalization of the pre-1970 model

Bjørkum¹

2021

Preprint

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New data from North Sea Upper Jurassic source rock samples show no decline in the total amount of organic matter (TOC) within the oil expulsion window between 120 and 150°C which is a key prediction by today’s model for oil expulsion. However, today’s model for oil expulsion is not consistent with either subsurface source rock TOC data or chemical attributes of shallow oils. Instead, these data are more consistent with oil expulsion occurring at much lower temperatures and shallower depths, more similar to models advocated by most oil explorers prior to 1970 where the oil was assumed to have expelled at burial depths less than ~2km. In this paper, main oil expulsion has been determined to be take place at burial depths less than 1km and approximately 30°C. The oil is mobilized by CO2 gas which is generated from decomposing organic matter and is predicted to migrate out of the source rock and into nearby high-permeable rocks via horizontal fractures that originate from loadbearing swelling organic lamina and in a direction towards decreasing overburden. The thermally immature (heavy) oil is then converted to light crude within the reservoir oil starting at 60-70°C by hydrogenation. Hydrogen gas is common in subsurface fluids and is provided to pooled oil from coalification of organic matter in mudstones. Thus, if the supply of hydrogen is limited, in-reservoir thermal upgrading will be hampered. In this model, most of the heavy oil accumulations encountered are immature rather than due to biodegradation of mature oil at low temperatures.

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Section: In-reservoir Maturation Of Oil By External Supply Of Hydrogenmentioning

confidence: 89%

Timing of oil expulsion from source rocks and a revitalization of the pre-1970 model

Bjørkum¹

2021

Preprint

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“…Almost 30 years of exploration in the Tahe Oilfield has shown that the Arkekule Arch comprises Cambrian, Ordovician, Carboniferous, Permian, Triassic, Jurassic, Cretaceous, and Quaternary strata from bottom to top [26,37]. The main hydrocarbon producing reservoirs are in Ordovician strata, which belong to shallow sea platform-slope facies [38,39], and the caprock is Lower Carboniferous mudstone [34]. From bottom to top, there are six layers developing in the Ordovician strata, including the Lower Ordovician Penglaiba Formation (O l p) and Yingshan Formation (O 1 y), the Middle Ordovician Yijianfang Formation (O 2 y), and the Upper Ordovician Group divided into the Qiaerbake Formation (O 3 q), the Lianglitage Formation (O 3 l), and the Sangtamu Formation (O 3 s) ( Figure 2) [40,41].…”

Section: Geological Backgroundmentioning

confidence: 99%

Three-Dimensional Geophysical Characterization of Deeply Buried Paleokarst System in the Tahe Oilfield, Tarim Basin, China

Tian

Wang

Fang

et al. 2019

Water

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Paleokarst reservoirs are the major type of the Ordovician carbonate reservoirs in the Tahe Oilfield. Due to the strong heterogeneity in distribution, it is a real challenge to detect the spatial distribution of paleokarst reservoirs, especially those deeply buried more than 5500 m in the Tahe area. Based on the abundant core samples, this paper first described the structure of paleocaves drilled by well. Second, after time–depth conversions, the results from drilled wells were tied to three-dimensional (3D) seismic datasets, and then the threshold of host rocks and caves in wave impedance were identified. Third, the seismic-scale mapping and visualization of the paleokarst reservoirs were achieved by tracing the distribution of paleocaves. This approach was applied in the well T403 area, and the structure of the paleokarst, especially the runoff zone, was interpreted. 3D structure and spatial distribution of the paleokarst system was demonstrated by plane, vertical, and 3D models. Additionally, according to the hydrology genetic relationships, the paleocaves in the runoff zone were divided into sinkholes, main channel, and branch channel. The approach of a 3D geophysical characterization of a deeply buried paleokarst system can be applicable to Tahe and other similar paleokarst oilfields, which will guide hydrocarbon exploration in paleokarst reservoirs.

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“…The Tarim Basin, encompassing an area of 560,000 km 2 , is the largest petroleum-bearing basin in China and is also one of the most complex superimposed basins in the world [11,12]. This basin is characterized by thick sediments, multiple cycles of uplift and erosion, and complex distribution of oil and gas accumulations [13].…”

Section: Geological Settingmentioning

confidence: 99%

Fluid Phase Simulation and Evolution of a Condensate Gas Reservoir in the Tazhong Uplift, Tarim Basin

et al. 2019

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The fluid phase and the evolution of the condensate gas reservoir in the Lianglitage Formation (O3), Well ZG7-5, Tazhong Uplift, were studied by integrating the PVTsim and the PetroMod software. The fluid phase was successfully simulated, and the burial, temperature, pressure, and pressure coefficient histories were reconstructed. The evolution of the fluid phase and its properties (density, viscosity, and gas-oil ratio) under the ideal and gas washing conditions was also explored. The simulated pressure-temperature (P‐T) phase diagram confirms that the reservoir fluid is in the condensate gas phase at present, with an order of critical point-cricondenbar-cricondentherm (CP‐Pm‐Tm). The temperature and pressure show an overall increasing trend considering the entirety of geological evolution. Under ideal conditions, fluid transition from coexisting gas and liquid phases to a single condensate gas phase occurred during the Late Cretaceous (80 Ma, T=135.7°C, and P=58.19 MPa). The density and viscosity of the liquid phase decreased gradually while the density and viscosity of the gas phase and the solution gas-oil ratio increased during geological processes. With the consideration of gas washing, the critical phase transition time points for 100% and 50% gas washing fluid are 394 Ma, 383 Ma, 331 Ma, and 23 Ma, as well as 266 Ma and 23 Ma, respectively. The average liquid phase density, gas phase density, and liquid phase viscosity under 100% gas washing are larger than those under 50% gas washing before 23 Ma (Miocene), while the gas phase viscosity values are similar for both cases. This study visually suggests that the temperature and pressure histories, which are controlled by the burial history and heat flow evolution, and gas washing have significant impacts on the formation of the condensate gas reservoirs and evolution of the fluid phase and its features in the Tazhong Uplift.

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Non-cracked oil in ultra-deep high-temperature reservoirs in the Tarim basin, China

Cited by 67 publications

References 44 publications

Timing of oil expulsion from source rocks and a revitalization of the pre-1970 model

Timing of oil expulsion from source rocks and a revitalization of the pre-1970 model

Three-Dimensional Geophysical Characterization of Deeply Buried Paleokarst System in the Tahe Oilfield, Tarim Basin, China

Fluid Phase Simulation and Evolution of a Condensate Gas Reservoir in the Tazhong Uplift, Tarim Basin

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