The nature, type, and origin of diagenetic fluids and their control on the evolving porosity of the Lower Cambrian Xiaoerbulak Formation dolostone, northwestern Tarim Basin, China

Liu, Peixian; Guan, Peng; Jin, Yiqiu; Wang, Kai; Yongquan, Chen

doi:10.1007/s12182-020-00434-0

“…Their combination makes the determination of in situ thermal conductivity more complicated and problematic. For a given rock, the characteristics of rocks such as porosity and mineral are closely linked with the influ-ence of external factors [25,26]. According to the previous studies [27,28], the effect of fluid on thermal conductivity depends chiefly on the porosity of rocks.…”

Section: Implication For In Situ Thermal Conductivitymentioning

confidence: 98%

Effect of Temperature on the Thermal Conductivity of Rocks and Its Implication for In Situ Correction

Chen

¹

,

Zhu

²

,

Zhang

³

et al. 2021

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Detailed knowledge of the effects of temperature on the thermal conductivity ( λ ) of rocks is essential for investigating the geothermal regime of basins and their thermal evolution. In this study, the λ of four rock types (carbonate, clastic, intrusive, and volcanic rocks) were measured at temperatures of 25°C, 50°C, 100°C, 150°C, 200°C, 250°C, and 300°C using the Transient Plane Source (TPS) approach, which is accurate to ±3%. Experimental results demonstrate that the λ of carbonate and clastic specimens decrease strongly with increasing temperature. In contrast, the λ of intrusive and volcanic rocks are relatively insensitive to temperature. The temperature ( T ) dependence of λ can be classified into three groups in terms of the value of λ at 25°C. The first group is composed of rocks characterized by high λ (>4.5 W/m·K) at room temperature, for which the curves of λ − T exhibit a concave pattern. The second group consists of rocks with a moderate λ (2.5~3.5 W/m·K), in which the curves tend to be a straight line. The last group comprises rocks with a low λ (<2.5 W/m·K), exhibiting convex curves. There exists a close relationship between the λ at 25°C and its rate of decrease ( α ). The absolute value of α increases with the λ at 25°C rising. The relationship between the two values can be fitted by the equation y = a x + b 1 / x + c to derive the fitting parameters a , b , and c ; by this equation with known fitting parameters, the λ of the deep carbonate rocks of the Tarim Basin have been estimated.

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“…The platform was generally submerged, and it retreated, and a rimmed shelf-type carbonate platform formed. The two 2 Geofluids stages of platform facies deposition in the ADRBB have resulted in the development of superimposed intraplatform mound-beach carbonate reservoirs in the western section and the development of longitudinally aggradational gentle-slope reef-beach carbonate reservoirs in the mideastern section [14,15]. The deposited carbonate reservoirs are mostly argillaceous limestones with high organic matter content and are a set of main source rocks in the Jurassic in the ADRBB.…”

Section: Geology Overviewmentioning

confidence: 99%

“…Hence, to study the formation period of oil and gas reservoirs, it is necessary first to divide the diagenetic process of reservoirs in a certain area in detail. Constructive diagenesis includes dissolution, dolomitization [2], and tectonic faulting. Destructive diagenesis includes compaction, cementation, stylolitization, and recrystallization.…”

Section: Introductionmentioning

confidence: 99%

Study on Hydrocarbon Accumulation Periods Based on Fluid Inclusions and Diagenetic Sequence of the Subsalt Carbonate Reservoirs in the Amu Darya Right Bank Block

Shan

¹

,

Wang

²

,

Zhang

³

et al. 2022

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In order to provide paleofluid evidence of hydrocarbon accumulation periods in the Amu Darya Right Bank Block, microexperiments and simulations related to the Middle-Upper Jurassic Callovian-Oxfordian carbonate reservoirs were performed. On the basis of petrographic observation, the diagenetic stages were divided by cathodoluminescence, and the entrapment stages of fluid inclusions were divided by laser Raman experiment and UV epifluorescence. The hydrocarbon generation (expulsion) curve and burial (thermal) history curve of source rocks were simulated by using real drilling data coupled with geochemical parameters of source rocks, such as total organic carbon (TOC) and vitrinite reflectance ( R o ). The above results were integrated with microthermometry of fluid inclusions by inference the timing of hydrocarbon migration into the carbonate reservoirs. The horizon-flattening technique was used to process the measured seismic profile and restore the structural evolution profile. Four diagenetic periods and three hydrocarbon accumulation periods were identified. (i) For Syntaxial stage, the fluid captured by the overgrowing cement around particles is mainly seawater; (ii) for (Early) Mesogenetic burial stage, the calcite cements began to capture hydrocarbon fluids and show yellow fluorescence under UV illumination; (iii) for (Late) Mesogenetic burial stage, two sets of cleavage fissures developed in massive calcite cements, and oil inclusions with green fluorescence were entrapped in the crystal; (iv) for Telogenetic burial stage, blue fluorescent inclusions along with hydrocarbon gas inclusions developed in dully luminescent calcite veins. Based on the accurate division of hydrocarbon migration and charging stages, combined with the structural evolution history of the traps, the hydrocarbon accumulation model was established. Because two of the three sets of source rocks are of marine origin, resulting in the lack of vitrinite in the kerogen of those source rocks, there may be some deviation between the measured value of R o and the real value. Some systematic errors may occur in the thermal history and hydrocarbon generation (expulsion) history of the two sets of source rocks. Due to the limitations of seismic horizon-flattening technique—such as the inability to accurately recover the inclined strata thickness and horizontal expansion of strata—the final shape of the evolution process of structural profile may also deviate from the real state in geological history. The accumulation model established in this study was based upon the fluid inclusion experiments, which can effectively characterize the forming process of large condensate gas reservoirs in the Amu Darya Right Bank Block and quantify the timing of hydrocarbon charging. However, the hydrocarbon migration and accumulation model does not take the oil-source correlation into account, but only the relationship between the mature state of source rocks and the timing of hydrocarbon charging into the reservoirs. Subsequent research needs to conduct refined oil-source correlation to reveal the relationship between gas, condensate, source rocks, and recently discovered crude oil and more strictly constrain and modify the accumulation model, so as to finally disclose the origin of the crude oil and oil reservoir forming process in the Amu Darya Right Bank Block, evaluate the future exploration potential, and point out the direction of various hydrocarbon resources (condensate gas and crude oil).

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“…The Tarim Basin has the richest deep hydrocarbons and deepest oil drilling in China. − The current development of new and advanced technologies and equipment, such as hydraulic fracturing, nanomaterials, and 12,000 m drilling rigs, are incentives for the petroleum industry to explore and develop deep-basin oil. However, as the theoretical understanding of DLOA lags far behind exploration technology, hydrocarbon drilling activity is prevented from expanding to deeper strata. , From the perspective of hydrocarbon accumulation dynamics, based on experimental and statistical analyses and by employing pore throat radius parameters, the critical condition of the DLOA of Lower Ordovician deep carbonate rocks in the Tazhong area of the Tarim Basin was quantitatively characterized, the genetic mechanism of the threshold of oil accumulation in carbonate rocks was revealed, and the deep oil exploration potential was forecasted in this study.…”

Section: Introductionmentioning

confidence: 99%

Critical Condition of the Depth Limit of Oil Accumulation of Carbonate Reservoirs and Its Exploration Significance in the Lower Ordovician of the Tazhong Area in the Tarim Basin

Wang,

Pang,

Wang

et al. 2023

ACS Omega

0

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Carbonate rocks typically constitute porous media, making the study of hydrocarbon accumulation in carbonate reservoirs an essential area of research. In the Tazhong area of the Tarim Basin, specifically within the Lower Ordovician stratum exceeding 7000 m, effective reservoirs and industrial liquid hydrocarbon accumulations persist. However, the existence of a depth limit of oil accumulation (DLOA) for oil accumulation in carbonate reservoirs remains unclear, posing a challenge for explorers. This study quantitatively characterizes the critical condition of DLOA in deep carbonate reservoirs from the perspective of hydrocarbon accumulation dynamics. Through comprehensive experimental analysis, statistical assessments, and numerical simulations, it also forecasts the potential for deep oil exploration. Based on the results of mercury injection experiments on 350 carbonate rock cores collected from 19 drilling wells in the deep Lower Ordovician, it was found that the reservoir is compact and exhibits significant heterogeneity. The driving force for oil accumulation is the capillary pressure difference between the surrounding rock and the reservoir. A greater capillary pressure difference indicates improved oil-bearing properties within the reservoir. When the capillary pressure difference between the reservoir and surrounding rock reaches zero, oil accumulation cannot occur, marking the critical condition of DLOA. The critical pore throat radius for DLOA in the deep Lower Ordovician carbonate rocks in the Tazhong area of the Tarim Basin is determined to be 0.01 μm, and the DLOA is estimated at 9000 m. This study confirms that the maximum depth for the embedded Lower Ordovician carbonate reservoir in the Tazhong area does not surpass this limit. Consequently, oil exploration in deep carbonate rocks within this stratum is both feasible and promising. The findings from this study hold significant importance in scientifically predicting favorable areas for oil exploitation in deep layers and offer valuable insights into understanding the oil flow in carbonate rocks.

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The nature, type, and origin of diagenetic fluids and their control on the evolving porosity of the Lower Cambrian Xiaoerbulak Formation dolostone, northwestern Tarim Basin, China

Cited by 10 publications

References 77 publications

Effect of Temperature on the Thermal Conductivity of Rocks and Its Implication for In Situ Correction

Effect of Temperature on the Thermal Conductivity of Rocks and Its Implication for In Situ Correction

Study on Hydrocarbon Accumulation Periods Based on Fluid Inclusions and Diagenetic Sequence of the Subsalt Carbonate Reservoirs in the Amu Darya Right Bank Block

Critical Condition of the Depth Limit of Oil Accumulation of Carbonate Reservoirs and Its Exploration Significance in the Lower Ordovician of the Tazhong Area in the Tarim Basin

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