Zhijun Jin

Formation and accumulation of oil and gas in marine carbonate sequences in Chinese sedimentary basins

Advances in studies of formation and accumulation mechanisms of oil and gas in marine carbonate sequences have led to continuing breakthroughs of petroleum exploration in marine carbonate sequences in Chinese sedimentary basins in recent years. The recently discovered giant Tahe Oil Field and Puguang Gas Field have provided geological entities for further studies of the formation and accumulation of oil and gas in marine carbonate sequences. Marine carbonate sequences in China are characterized by old age, multiple structural deformation, differential thermal evolution of source rocks, various reservoir types (i.e. reef-bank complex and paleo-weathered crust karst reservoir), uneven development of caprocks, especially gypsum seal, and multi-episodes of hydrocarbon accumulation and readjustment. As a result, the formation of hydrocarbon accumulations in the Chinese marine carbonate sequences has the following features: (i) the high-quality marine source rocks of shale and calcareous mudstone are often associated with siliceous rocks or calcareous rocks and were deposited in slope environments. They are rich in organic matter, have a higher hydrocarbon generation potential, but experienced variable thermal evolutions in different basins or different areas of the same basin. (ii) High quality reservoirs are controlled by both primary depositional environments and later modifications including diagenetic modifications, structural deformations, and fluid effects. (iii) Development of high-quality caprocks, especially gypsum seals, is the key to the formation of large- and medium-sized oil and gas fields in marine carbonate sequences. Gypsum often constitutes the caprock for most of large sized gas fields. Given that Chinese marine carbonate sequences are of old age and subject to multiple episodes of structural deformation and superposition, oil and gas tend to accumulate in the slopes and structural hinge zones, since the slopes favor the development of effective assemblage of source-reservoir-caprock, high quality source rocks, good reservoirs such as reef-bank complex, and various caprocks. As the structural hinge zones lay in the focus area of petroleum migration and experienced little structural deformation, they are also favorable places for hydrocarbon accumulation and preservation.

A Late Triassic gravity flow depositional system in the southern Ordos Basin

Abstract Based on the analysis of numerous drill cores and drilling data, lacustrine gravity flow depositional systems were analyzed comprehensively in the Chang6 and Chang7 oil members (Triassic Yanchang Formation) in the southern part of the Ordos Basin. The gravity flow depositional systems in these members are made up of slides, slumps, sandy debris flows, liquefied flows, turbidity current etc , forming well developed units in the study area. Successive beds characterized by, from bottom to top, massive bedding (MB), graded bedding (GB) and horizontal bedding (HB) form well developed sequences; parallel bedding (GB) and ripple bedding (RB) are rare. It turns out that the depositional sequences are quite different from turbidites with a Bouma sequence: (1) MB represents a sandy debris flow, (2) GB deposits in a turbidity current, (3) PB and RB are deposits that were reworked by bottom currents (traction flow), and (4) HB represents a deep-water environment rather than gravity flows. Deposits in the proximal part of the subaqueous lacustrine fan consist mainly of slides, slumps and massive sandy debris flows. Deposits at the middle part of the fan are characterized by an MB-GB-HB sequence of massive sandy debris flows, graded turbidites and horizontally bedded lacustrine mudstones. Deposits at the end of the subaqueous lacustrine fan were mainly graded turbidites and horizontally bedded lacustrine mudstones (GB-HB sequence). Sandy gravity flow deposits mainly developed on the delta front and in the basin plain, extending for dozens of kilometers. They directly cover the source rock in the Chang7 oil members, which has the advantage of near-source oil accumulation. The sandstones at the bottom of each sedimentary cycle are worth further exploration because of their good reservoir properties and high oil content.

Controls of Late Jurassic-Early Cretaceous tectonic event on source rocks and seals in marine sequences, South China

Thermal evolution of source rocks and dynamic sealing evolution of cap rocks are both subjected to tectonic evolution. The marine sequences in South China have experienced superposed structural deformation from multiple tectonic events. To investigate the effectiveness of preservation conditions, it is of great importance to understand the controls of key tectonic events on the dynamic evolution of cap rocks. This paper discusses the controls of Late Jurassic-Early Cretaceous (J3-K1) tectonic event on source and cap rocks in marine sequences in South China based on the relationships between J3-K1 tectonic event and the burial history types of the marine sequences, the hydrocarbon generation processes of marine source rocks, the sealing evolution of cap rocks, the preservation of hydrocarbon accumulations, and the destruction of paleo-oil pools. The study has the following findings. In the continuously subsiding and deeply buried areas during the J3-K1 period, marine source rocks had been generating hydrocarbons for over a long period of time and hydrocarbon generation ended relatively late. At the same time, the sealing capacity of the overburden cap rocks had been constantly strengthened so that hydrocarbons could be preserved. In the areas which suffered compressional deformation, folding and thrusting, uplifting and denudation in J3-K1, the burial history was characterized by an early uplifting and the hydrocarbon generation by marine source rocks ended (or suspended) during the J3-K1 period. The sealing capacity of the cap rocks was weakened or even vanished. Thus the conditions for preserving the hydrocarbon accumulations were destroyed. The continuously subsiding and deeply buried areas during the J3-K1 period are the strategic precincts of the petroleum exploration in marine sequences in South China.

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.

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.

Formation and distribution characteristics of Proterozoic–Lower Paleozoic marine giant oil and gas fields worldwide

There are rich oil and gas resources in marine carbonate strata worldwide. Although most of the oil and gas reserves discovered so far are mainly distributed in Mesozoic, Cenozoic, and upper Paleozoic strata, oil and gas exploration in the Proterozoic–Lower Paleozoic (PLP) strata—the oldest marine strata—has been very limited. To more clearly understand the oil and gas formation conditions and distributions in the PLP marine carbonate strata, we analyzed and characterized the petroleum geological conditions, oil and gas reservoir types, and their distributions in thirteen giant oil and gas fields worldwide. This study reveals the main factors controlling their formation and distribution. Our analyses show that the source rocks for these giant oil and gas fields are mainly shale with a great abundance of type I–II organic matter and a high thermal evolution extent. The reservoirs are mainly gas reservoirs, and the reservoir rocks are dominated by dolomite. The reservoir types are mainly karst and reef–shoal bodies with well-developed dissolved pores and cavities, intercrystalline pores, and fractures. These reservoirs are highly heterogeneous. The burial depth of the reservoirs is highly variable and somewhat negatively correlated to the porosity. The cap rocks are mainly thick evaporites and shales, with the thickness of the cap rocks positively correlated to the oil and gas reserves. The development of high-quality evaporite cap rock is highly favorable for oil and gas preservation. We identified four hydrocarbon generation models, and that the major source rocks have undergone a long period of burial and thermal evolution and are characterized by early and long periods of hydrocarbon generation. These giant oil and gas fields have diverse types of reservoirs and are mainly distributed in paleo-uplifts, slope zones, and platform margin reef-shoal bodies. The main factors that control their formation and distribution were identified, enabling the prediction of new favorable areas for oil and gas exploration.

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.

Burial depth interval of the shale brittle–ductile transition zone and its implications in shale gas exploration and production

Brittleness and ductility of shale are closely related to shale gas exploration and production. How to predict brittleness and ductility of shale is one of the key issues in the study of shale gas preservation and hydraulic fracturing treatments. The magnitude of shale brittleness was often determined by brittle mineral content (for example, quartz and feldspars) in shale gas exploration. However, the shale brittleness is also controlled by burial depth. Shale brittle/ductile properties such as brittle, semi-brittle and ductile can mutually transform with burial depth variation. We established a work flow of determining the burial depth interval of brittle–ductile transition zone for a given shale. Two boundaries were employed to divide the burial depth interval of shale brittle/ductile properties. One is the bottom boundary of the brittle zone (BZ), and the other is the top boundary of the ductile zone (DZ). The brittle–ductile transition zone (BDTZ) is between them. The bottom boundary of BZ was determined by the over-consolidation ratio (OCR) threshold value combined with pre-consolidation stress which the shale experienced over geological time. The top boundary of DZ was determined based on the critical confining pressure of brittle–ductile transition. The OCR threshold value and the critical confining pressure were obtained from uniaxial strain and triaxial compression tests. The BZ, DZ and BDTZ of the Lower Silurian Longmaxi shale in some representative shale gas exploration wells in eastern Sichuan and western Hubei areas were determined according to the above work flow. The results show that the BZ varies with the maximum burial depth and the DZ varies with the density of the overlying rocks except for the critical confining pressure. Moreover, the BDTZ determined by the above work flow is probably the best burial depth interval for marine shale gas exploration and production in Southern China. Shale located in the BDTZ is semi-brittle and is not prone to be severely naturally fractured but likely to respond well to hydraulic fracturing. The depth interval of BDTZ determined by our work flow could be a valuable parameter of shale gas estimation in geology and engineering.

A comparative study of salient petroleum features of the Proterozoic–Lower Paleozoic succession in major petroliferous basins in the world:

The Proterozoic–Lower Paleozoic marine facies successions are developed in more than 20 basins with low exploration degree in the world. Some large-scale carbonate oil and gas fields have been found in the oldest succession in the Tarim Basin, Ordos Basin, Sichuan Basin, Permian Basin, Williston Basin, Michigan Basin, East Siberia Basin, and the Oman Basin. In order to reveal the hydrocarbon enrichment roles in the oldest succession, basin formation and evolution, hydrocarbon accumulation elements, and processes in the eight major basins are studied comparatively. The Williston Basin and Michigan Basin remained as stable cratonic basins after formation in the early Paleozoic, while the others developed into superimposed basins undergone multistage tectonic movements. The eight basins were mainly carbonate deposits in the Proterozoic–early Paleozoic having different sizes, frequent uplift, and subsidence leading to several regional unconformities. The main source rock is shale with total organic carbon content of generally greater than 1% and type I/II organic matters. Various types of reservoirs, such as karst reservoir, dolomite reservoir, reef-beach body reservoirs are developed. The reservoir spaces are mainly intergranular pore, intercrystalline pore, dissolved pore, and fracture. The reservoirs are highly heterogeneous with physical property changing greatly and consist mainly of gypsum-salt and shale cap rocks. The trap types can be divided into structural, stratigraphic, lithological, and complex types. The oil and gas reservoir types are classified according to trap types where the structural reservoirs are mostly developed. Many sets of source rocks are developed in these basins and experienced multistage hydrocarbon generation and expulsion processes. In different basins, the hydrocarbon accumulation processes are different and can be classified into two types, one is the process through multistage hydrocarbon accumulation with multistage adjustment and the other is the process through early hydrocarbon accumulation and late preservation.