No abstract

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).

In this paper, taking Block G in Canada as an example, combined with the data of the working area, the Pearson–MIC comprehensive evaluation method was adopted to optimize the key parameters of productivity. Based on the analytic hierarchy process, the weight of each parameter was calculated, the grade of evaluation index of the “sweet spot” was divided, the standard of the sweet spot was established, and the distribution of the superimposed sweet spot was finally depicted. The results show that lateral length, number of stages, volume of fluid, and amount of proppant are the key engineering parameters of horizontal well, and lateral length is an independent key engineering parameter. The cumulative gas production in the first two years was normalized on the lateral length to eliminate the engineering influence, and the total organic carbon (TOC) was finally determined as the key geological parameter, whereas porosity and water saturation were the secondary key parameters. The area of Type I sweet spots accounts for 24.2% in the Series Upper and 23.1% in the Series Lower. This study proposed a new sweet spot prediction idea based on the influence of geological factors on productivity, and its results also laid a foundation for the subsequent placement of horizontal wells in Block G.

The Amu Darya Right Bank Block is located northeast of the Amu Darya basin, a large petroliferous sedimentary basin, with abundant natural gas resources in carbonate rocks under the ultra-thick gypsum-salt layer. Oil fields producing crude oils have recently been found around large gas fields. Unraveling the origins of the crude oils is crucial for effective petroleum exploration and exploitation. The origin of gas condensates and crude oils was unraveled through the use of comprehensively analytical and interpretative geochemical approaches. Based on oil-source correlation, the reservoir forming process has been restored. The bulk geochemical parameters of the local source rocks of the ADRBB indicated that the local sources have hydrocarbon generation and accumulation potential. The middle-lower Jurassic coal-bearing mudstone is gas prone, while the mudstone of the Callovian-Oxfordian gap layer is oil prone, and the organic matter type of Callovian-Oxfordian carbonate rocks is the mixed type between the two previous source rocks. The interpretation schemes for compositions of n-alkanes, pristane and phytane, C27–C28–C29 sterane distributions, C19+C20–C21–C23 tricyclic terpane distributions, extended tricyclic terpane ratio, and δ13C indicated that crude oil is likely from marine organic matter, while condensates mainly originate from terrestrial organic matter. However, from the perspective of the 18α-trisnorneohopane/17α-trisnorhopane and isomerization ratio of C29 sterane, condensates are too mature to have originated in the local source rocks of the ADRBB, whose maturity is well comparable with that of crude oils. The geochemical, geologic, and tectonic evolutions collectively indicate that the crude oils were most likely generated and migrated from the relatively shallow, lowly mature gap layer and Callovian-Oxfordian carbonate rocks of the ADRBB, while the condensates mostly originated from the relatively deep and highly mature middle-lower coal-bearing mudstone and Callovian-Oxfordian carbonate rocks in the Murgab depression in the southeast of the basin. Basement faults are the key factors affecting the types of oil and gas reservoirs. During the periods of oil and gas migration, traps with basement faults mainly captured natural gas and condensates and traps without basement faults were enriched with crude oils generated from local source rocks.