Quanyou Liu

Presence of carboxylate salts in marine carbonate strata of the Ordos Basin and their impact on hydrocarbon generation evaluation of low TOC, high maturity source rocks

The total organic carbon (TOC) in the marine source rock of the Ordos Basin mostly ranges from 0.2% to 0.5%. The industrial standard commonly states that the TOC value has to be no less than 0.5% (0.4% for high mature or over-mature source rock) to form large petroleum reservoirs. However, gas source correlation indicates that the natural gas in the Jingbian gas field does receive contribution from marine source rocks. In order to determine the effect of carboxylate salts (or called as organic acid salts) on TOC in highly mature source rocks with low TOC value, we sampled the Ordovician marine source rock and the Permian transitional facies source rock in one drilled well in the southern Ordos Basin and performed infrared and GC-MS analysis. It is found that both kerogen-derived organic acids and carboxylate salt-conversed organic acids exist in both marine and transitional facies source rocks. The carboxylate salt-conversed organic acids mainly come from the complete acidification of carboxylate salts, which confirms the presence of carboxylate salts in the marine source rocks. Although the C16:O peak is the main peak for the organic acids both before and after acidification, the carboxylate salt-conversed organic acids have much less relative abundance ahead of C16:O compared with that of the kerogen-based and free organic acids. This observation suggests that the kerogen-based and free organic acids mainly decarboxylate to form lower carboxylic acids, whereas the carboxylate salt-conversed organic acids mainly break down into paraffins. By using calcium hexadecanoate as the reference to quantify the kerogen-derived and carboxylate salt-conversed organic acids, the high TOC (>2.0%) marine source rocks have low carboxylate salt content and the low TOC (0.2%–0.5%) marine source rocks contain high content of carboxylate salt. Therefore, for the marine source rocks with 0.2%–0.5% TOC, the carboxylate salts may be a potential gas source at high maturity stage.

Mercury concentration in natural gas and its distribution in the Tarim Basin

Here I collected natural gas samples from 41 industrial gas wells in the Tarim Basin, and studied the mercury distribution in the area. My data show that there is certain regularity in the distribution of mercury in the Tarim Basin. Generally, the mercury concentration is high at the edge of the basin and low in the central basin. The highest mercury concentration occurs in the Southwest Depression, ranging from 15428.5 to 296763.0 ng/m3 with an average of 156095.7 ng/m3, followed by the Kuqa Depression ranging from 15.0 to 56964.3 ng/m3 with an average of 11793.7 ng/m3, and the Hade oil and gas field in the North Depression has the lowest mercury concentration ranging from 17.7 to 3339.5 ng/m3 with an average of 1678.6 ng/m3. The mercury concentrations in the natural gases of different structural units are various, with the highest mercury concentration in the zone of strong structural activity of Southwest Depression. It is profitable of Hg accumulation in the self sourced and self accumulated gas reservoirs or volcanic existence; in contrast, the low Hg concentration exists in the secondary gas reservoir. The mercury concentration in the natural gas generated under continental depositional environment is higher than that in marine gas. Therefore, the mercury concentration in the natural gases is constrained by gas genesis, depositional environment of source rocks, tectonic activity, and volcanic activity, and the tectonic activity is the main factor for the mercury concentration in the natural gas, followed by volcanic activity and depositional environments.

Potential petroleum sources and exploration directions around the Manjar Sag in the Tarim Basin

Since the discovery of the Tahe oilfield, it has been controversial on whether the main source rock is in the Cambrian or Middle-Upper Ordovician strata. In this paper, it is assumed that the crude oil from the Wells YM 2 and TD 2 was derived from the Middle-Upper Ordovician and Cambrian source rocks, respectively. We analyzed the biomarkers of the crude oil, asphalt-adsorbed hydrocarbon and saturated hydrocarbon in bitumen inclusions from the Lunnan and Hade areas in the North Uplift of the Tarim Basin. Results show that the ratios of tricyclic terpane C21/C23 in the crude oil, asphalt-adsorbed hydrocarbon and saturated hydrocarbon in bitumen inclusions are less than 1.0, indicating that they might be from Upper Ordovician source rocks; the ratios of C28/(C27+C28+C29) steranes in the saturated hydrocarbon from reservoir bitumen and bitumen inclusions are higher than 25, suggesting that they might come from the Cambrian source rocks, however, the ratios of C28/(C27+C28+C29) steranes in oil from the North Uplift are less than 25, suggesting that they might be sourced from the Upper Ordovician source rocks. These findings demonstrate that the sources of crude oil in the Tarim Basin are complicated. The chemical composition and carbon isotopes of Ordovician reservoired oil in the Tarim Basin indicated that the crude oil in the North Uplift (including the Tahe oilfield) and Tazhong Depression was within mixture areas of crude oil from the Wells YM 2 and TD 2 as the end members of the Cambrian and Middle-Upper Ordovician sourced oils, respectively. This observation suggests that the crude oil in the Ordovician strata is a mixture of oils from the Cambrian and Ordovician source rocks, with increasing contribution from the Cambrian source rocks from the southern slope of the North Uplift to northern slope of the Central Uplift of the Tarim Basin. Considering the lithology and sedimentary facies data, the spatial distribution of the Cambrian, Middle-Lower Ordovician and Upper Ordovician source rocks was reconstructed on the basis of seismic reflection characteristics, and high-quality source rocks were revealed to be mainly located in the slope belt of the basin and were longitudinally developed over the maximum flooding surface during the progressive-regressive cycle. Affected by the transformation of the tectonic framework in the basin, the overlays of source rocks in different regions are different and the distribution of oil and gas was determined by the initial basin sedimentary structure and later reformation process. The northern slope of the Central Uplift-Shuntuo-Gucheng areas would be a recent important target for oil and gas exploration, since they have been near the slope area for a long time.

Sequence development, depositional filling evolution, and prospect forecast in northern Aryskum Depression of South Turgay Basin, Kazakstan

Jurassic to Cretaceous clastic rocks of the South Turgay Basin were deposited in the typical Mesozoic rift basin formed during the late Triassic collision between the Kazakstan and Siberia plates. In this study, we used more than 140 wells and 2400 km2 of 3D seismic data in the northern Aryskum Depression to produce a detailed sequence stratigraphic interpretation of the South Turgay Basin. Guided by sequence stratigraphy, sedimentology, and structural geology, lower Jurassic-lower Cretaceous strata of the northern Aryskum Depression in the South Turgay Basin, Kazakhstan were subdivided into 10 third-order sequences based on geological and geophysical data. Combined with tectonic evolution characteristics, sequence developments in the basin can be divided into four stages: early rift stage (SQ1–SQ3), late rift stage (SQ4–SQ6), fault to depression transition stage (SQ7–SQ8), and depression stage (SQ9–SQ10). Through comprehensive analysis of seismic sequence configuration, sequence stacking pattern, and depositional filling characteristics, we established the depositional model of the Aryskum Depression in the South Turgay Basin. It is indicated that there are differences in depositional compositions of sequences formed in different stages. Four stages can be clearly identified: filling stage of fan delta facies–lacustrine facies (Stage I) corresponding to the rapid filling in the early rift stage, filling stage of fan delta facies–lacustrine facies–normal delta facies (Stage II) corresponding to trichotomous characteristics of internal systems tracts in the late rift stage, filling stage of braided river delta facies–normal delta facies–lacustrine facies (Stage III) corresponding to the development of high-stand systems tracts in the fault to depression transition stage, and filling stage of fluvial facies–normal delta facies–lacustrine facies (Stage IV) corresponding to binary characteristics of internal systems tracts in the depression stage. Finally, optimization of favorable exploration strata and prospects in the Aryskum Depression are proposed.

Origin of Marine Sour Natural Gas and Gas-Filling Model in the Puguang Giant Gas Field, Sichuan Basin, China

Taking the geology and tectonic evolution characteristics of the Sichuan Basin into account, the chemical and stable isotopic compositions of natural gas, and biomarker compounds in the reservoir bitumen in the Puguang giant gas field, are investigated to identify the genetic type of marine sour natural gas, take the gas-source correlation, and set up the gas-filling model of the Puguang giant gas field in the Sichuan Basin. The alkane gases in the field are dominated by methane, ranging from 22.06% to 99.64% with an average value of 76.52%, and the low content of heavy hydrocarbon gases are dominantly ethane and little propane. The H2S contents occur among the marine carbonate gas reservoirs, ranging from 0 to 62.17%, wherein the H2S contents in the Upper Permian Changxing Formation and Lower Triassic Feixianguan Formation range from 6.9% to 34.72% (average value=15.27%) and from 0% to 62.17% (average value= 13.4%), respectively, indicating that both are H2S-enriched reservoirs. The chemical and carbon isotopic compositions of marine natural gases show that the alkane gas in the Puguang giant gas field is dominantly oil-cracking gas at high maturity stage, and the biomarker characteristics of reservoir bitumen indicate that the major source rocks are the Upper Permian Longtan Formation sapropelic matters. Moreover, various levels of thermochemical sulfate reduction (TSR) were present in the process of oil-gas transformation, not only increasing the content of non-hydrocarbon gas components (CO2 and H2S) and decreasing the content of heavy hydrocarbon gases, but also causing the reversal of carbon isotope compositions of methane and ethane and the heavier carbon isotope of methane. The recovery of structural configurations over geological time investigates that the gas-filling history of Puguang giant gas field can be divided into three stages: formation of paleo-oil accumulation from the middle-late Indosinian period to the early Yanshanian period, thermal cracking of paleo-oil and TSR alteration from the early to the middle Yanshanian period, and adjustment of gas accumulation from the late Yanshanian to the early Himalayan period. The gypsum of the Lower Triassic Jianglingjiang Formation and the Middle Triassic Leikoupo Formation plays the most important role as effective seal to the gas preservation in different periods.

Effects of Deep Fluids on Hydrocarbon Generation and Accumulation in Chinese Petroliferous Basins

Deep fluids in a petroliferous basin generally come from the deep crust or mantle beneath the basin basement, and they transport deep substances (gases and aqueous solutions) as well as heat to sedimentary strata through deep faults. These deep fluids not only lead to large-scale accumulations of CO2, CH4, H2, He and other gases, but also significantly impact hydrocarbon generation and accumulation through organic-inorganic interactions. With the development of deep faults and magmatic-volcanic activities in different periods, most Chinese petroliferous basins have experienced strong impacts associated with deep fluid activity. In the Songliao, Bohai Bay, Northern Jiangsu, Sanshui, Yinggehai and Pearl Mouth Basins in China, a series of CO2 reservoirs have been discovered. The CO2 content is up to 99%, with δCCO2 values ranging from −4.1‰ to −0.37‰ and He/He ratios of up to 5.5 Ra. The abiogenic hydrocarbon gas reservoirs with commercial reserves, such as the Changde, Wanjinta, Zhaozhou, and Chaoyanggou reservoirs, are mainly distributed in the Xujiaweizi faulted depression of the Songliao Basin. The δCCH4 values of the abiogenic alkane gases are generally >−30‰ and exhibit an inverse carbon isotope sequence of δCCH4>δCC2H6>δCC3H8>δCC4H10. According to laboratory experiments, introducing external H2 can improve the rate of hydrocarbon generation by up to 147% through the kerogen hydrogenation process. During the migration from deep to shallow depth, CO2 can significantly alter reservoir rocks. In clastic reservoirs, feldspar is easily altered by CO2-rich fluids, leading to the formation of dawsonite, a typical mineral in high CO2 partial pressure environments, as well as the creation of secondary porosity. In carbonate reservoirs, CO2-rich fluids predominately cause dissolution or precipitation of carbonate minerals. The minerals, e.g., calcite and dolomite, show some typical features, such as higher homogenization temperatures than the burial temperature, relatively high concentrations of Fe and Mn, positive Eu anomalies, depletion of O and enrichment of radiogenic Sr. Due to CO2-rich fluids, the development of high-quality carbonate reservoirs is extended to deep strata. For example, the Well TS1 in the northern Tarim Basin revealed a high-quality Cambrian dolomite reservoir with a porosity of 9.1% at 8408 m, and the Well ZS1C in the central Tarim Basin revealed a large petroleum reserve in a Cambrian dolomite reservoir at ~6900 m. During the upward migration from deep to shallow basin strata, large volumes of supercritical CO2 may extract petroleum components from hydrocarbon source rocks or deep reservoirs and facilitate their migration to shallow reservoirs, where the petroleum accumulates with the CO2. Many reservoirs containing both supercritical CO2 and petroleum have been discovered in the Songliao, Bohaiwan, Northern Jiangsu, Pearl River Mouth and Yinggehai Basins. The components of the petroleum trapped with CO2 are dominated by low molecular weight saturated hydrocarbons.

Genetic Types and Source of the Upper Paleozoic Tight Gas in the Hangjinqi Area, Northern Ordos Basin, China

The molecular and stable isotopic compositions of the Upper Paleozoic tight gas in the Hangjinqi area in northern Ordos Basin were investigated to study the geochemical characteristics. The tight gas is mainly wet with the dryness coefficient (C1/ ) of 0.853–0.951, and δ13C1 and δ2H-C1 values are ranging from 36.2 to 32.0 and from 199 to 174 , respectively, with generally positive carbon and hydrogen isotopic series. Identification of gas origin indicates that tight gas is mainly coal-type gas, and it has been affected by mixing of oil-type gas in the wells from the Shilijiahan and Gongkahan zones adjacent to the Wulanjilinmiao and Borjianghaizi faults. Gas-source correlation indicates that coal-type gas in the Shiguhao zone displays distal-source accumulation. It was mainly derived from the coal-measure source rocks in the Upper Carboniferous Taiyuan Formation (C3t) and Lower Permian Shanxi Formation (P1s), probably with a minor contribution from P1s coal measures from in situ Shiguhao zone. Natural gas in the Shilijiahan and Gongkahan zones mainly displays near-source accumulation. The coal-type gas component was derived from in situ C3t-P1s source rocks, whereas the oil-type gas component might be derived from the carbonate rocks in the Lower Ordovician Majiagou Formation (O1m).

Geochemical Characteristics and Genetic Types of Natural Gas in the Xinchang Gas Field, Sichuan Basin, SW China

The molecular compositions and stable carbon and hydrogen isotopic compositions of natural gas from the Xinchang gas field in the Sichuan Basin were investigated to determine the genetic types. The natural gas is mainly composed of methane (88.99%–98.01%), and the dryness coefficient varies between 0.908 and 0.997. The gas generally displays positive alkane carbon and hydrogen isotopic series. The geochemical characteristics and gas-source correlation indicate that the gases stored in the 5 member of the Upper Triassic Xujiahe Formation are coal-type gases which are derived from source rocks in the stratum itself. The gases reservoired in the 4 member of the Xujiahe Formation and Jurassic strata in the Xinchang gas field are also coal-type gases that are derived from source rocks in the 3 and 4 members of the Xujiahe Formation. The gases reservoired in the 2 member of the Upper Triassic Xujiahe Formation are mainly coal-type gases with small amounts of oil-type gas that is derived from source rocks in the stratum itself. This is accompanied by a small amount of contribution brought by source rocks in the Upper Triassic Ma’antang and Xiaotangzi formations. The gases reservoired in the 4 member of the Middle Triassic Leikoupo Formation are oil-type gases and are believed to be derived from the secondary cracking of oil which is most likely to be generated from the Upper Permian

Formation mechanism of dolomite reservoir controlled by fourth-order sequence in an evaporated marine environment – An example from the Lower Ordovician Tongzi Formation in the Sichuan Basin

The high-porosity dolomite reservoirs of the Lower Ordovician Tongzi Formation (Fm.) were widely developed in the Sichuan Basin of southern China. The characteristics and developing mechanisms of the high-porosity dolomite reservoirs under the control of fourth-order sequence boundaries are discussed. In the Tongzi stage of the Early Ordovician, the Sichuan Basin was in a restricted platform facies in an evaporated shallow seawater environment. From the western to eastern regions of the basin, the Tongzi Fm. was serially developed in a tidal flat-lagoon-high-energy shoal depositional system. The evaporated seawater consequently led to dolomitization by way of the refluxing model. The Tongzi Fm. dolomites were subdivided into four coarsening-upward fourth-order sequences. Many tiny dissolution pores were formed in the dolomite beneath the four fourth-order sequence boundaries due to syn-sedimentation meteoric water erosion. Exposure above the seawater due to the short-term fall of the relative sea level consequently led to contemporaneous meteoric erosion. The Tongzi Fm. dolomites in the belt surrounding the Central Paleo-uplift were further subaerially dissolved by meteoric water due to tectonic uplift in the Guangxi Movement since the end of the Silurian period. Therefore, dolomitization, syn-sedimentation meteoric erosion under the fourth-order sequence boundaries, and meteoric karst during the Guangxi tectonic uplift jointly controlled the development of the Tongzi Formation high-porosity dolomite reservoirs. In the eastern and southeastern Sichuan Basin, the favourable reservoirs are the high-energy shoal dolomites that were eroded by meteoric water under fourth-order sequence boundaries. Around the Central Paleo-uplift, the favourable reservoirs are the dolomites dissolved by subaerial meteoric karst during the Guangxi Movement.