Coaly Source Rocks Research Articles

A REVIEW OF THE COALY SOURCE ROCKS AND GENERATED PETROLEUMS IN THE DANISH NORTH SEA: AN UNDEREXPLORED MIDDLE JURASSIC PETROLEUM SYSTEM?

This paper reviews the Middle Jurassic petroleum system in the Danish Central Graben with a focus on source rock quality, fluid compositions and distributions, and the maturation and generation history. The North Sea including the Danish Central Graben is a mature oil province where the primary source rock is composed of Upper Jurassic – lowermost Cretaceous marine shales. Most of the shale‐sourced structures have been drilled and, to accommodate continued value creation, additional exploration opportunities are increasingly considered in E&P strategies. Triassic and Jurassic sandstone plays charged from coaly Middle Jurassic source rocks have proven to be economically viable in the North Sea. In the Danish‐Norwegian Søgne Basin, coal‐derived gas/condensate is produced from the Harald and Trym fields and oil from the Lulita field; the giant Culzean gas‐condensate field is under development in the UK Central North Sea; and in the Norwegian South Viking Graben, coal‐derived gas and gas‐condensate occur in several fields. The coaly source rock of the Middle Jurassic petroleum system in the greater North Sea is included in the Bryne/Lulu Formations (in Denmark), the Pentland Formation (in the UK), and the Sleipner and Hugin Formations in Norway. In the Danish Central Graben, the coal‐bearing unit is composed of coals, coaly shales and carbonaceous shales, has a regional distribution and can be mapped seismically as the ‘Coal Marker’. The coaly source rocks are primarily gas‐prone but the coals have an average Hydrogen Index value of c. 280 mg HC/g TOC and values above 300 mg HC/g TOC are not uncommon, which underpins the coals' capacity to generate liquid hydrocarbons (condensate and oil). The coal‐sourced liquids are differentiated from the common marine‐sourced oils by characteristic biomarker and isotope compositions, and in the Danish Central Graben are grouped into specific oil families composed of coal‐sourced oil and mixed oils with a significant coaly contribution. Similarly, the coal‐sourced gases are recognized by a normally heavier isotope signature and a relatively high dryness coefficient compared to oil‐associated gas derived from marine shales. The coal‐derived and mixed coaly gases are likewise assigned to well‐defined gas families. Coal‐derived liquids and gas discoveries and shows in Middle Jurassic strata suggest that the coaly Middle Jurassic petroleum system has a regional distribution. A 3D petroleum systems model was constructed covering the Danish Central Graben. The model shows that present‐day temperatures for the Middle Jurassic coal source rock ('Coal Marker') are relatively high (>150 °C) throughout most of the Danish Central Graben, and expulsion of hydrocarbons from the ‘Coal Marker’ was initiated in Late Jurassic time in the deep Tail End Graben. In the Cretaceous, the area of mature coaly source rocks expanded, and at present day nearly the whole area is mature. Hydrocarbon expulsion rates were low in the Paleocene to Late Oligocene, followed by significant expulsion in the Miocene up to the present day. High Middle Jurassic reservoir temperatures prevent biodegradation.

GEOCHEMICAL EVALUATION OF CRUDE OILS FROM THE CARACARA AND TIPLE AREAS, EASTERN LLANOS BASIN, COLOMBIA: PALAEO BIODEGRADATION AND OIL MIXING

This study presents an organic geochemical characterization of heavy and liquid oils from Cretaceous and Cenozoic reservoir rocks in the Tiple and Caracara blocks in the eastern Llanos Basin, Colombia. Samples of heavy oil were recovered from the Upper Eocene Mirador Formation and the C7 interval of the Oligocene – Miocene Carbonera Formation; the liquid oils came from these intervals and from the Cretaceous Guadalupe, Une and Gachetá Formations. The heavy oil and most of the liquid oils probably originated from multiple source rocks or source facies, and showed evidence of biodegradation as suggested by the coexistence of n‐alkanes and 25‐norhopanes. The results indicate a close genetic relationship between the samples in the Carbonera (C7 interval), Mirador and Guadalupe Formation reservoirs. These petroleums are interpreted to result from at least two separate oil charges. An early charge (Oligocene to Early Miocene) was derived from marine carbonate and transitional siliciclastic Cretaceous source rocks as indicated by biomarker analysis using GC/MS. This initial oil charge was biodegraded in the reservoir, and was mixed with a later charge (or charges) of fresh oil during the Late Miocene to Pliocene. A relatively high proportion of the unaltered oil charge was recorded for heavy oil samples from the Melero‐1 well in the Tiple block, and is inferred to originate from Cenozoic carbonaceous shale or coaly source rocks. Geochemical parameters suggest that oils from the Gachetá and Une Formations are similar and that they originated from a source different to that of the other oil samples. These two oils do not correlate well with extracts from transitional siliciclastic source rock from the Upper Cretaceous Gachetá Formation in the Ramiriqui‐1 well, located in the LLA 22 block to the north. By contrast, one or more organofacies of the Gachetá Formation may have generated the heavy oil and most of the liquid oil samples. The results suggest that the heavy oils may have formed as a result of biodegradation at the palaeo oil‐water contact, although deasphalting cannot entirely be dismissed.

Petroleum systems in Southeast Asian Tertiary basins

Productive Tertiary basins in Southeast Asia have essentially similar geodynamic developments, and share many hydrocarbon habitats and active petroleum systems. In order to facilitate understanding of the essential elements that contribute to the success of petroleum systems I have classified them into a number of groups or ‘associations’ according to their sedimentary facies. This facilitates use of them as valuable analogues. Five such facies associations, containing characteristic and distinct petroleum parameters have been recognised: (i) lacustrine (ii) paralic (iii) open marine shelf (iv) deeper marine and (v) pre-Tertiary. They belong to particular cycles or stages in basin development that provide the context within which the depositional environments and palaeogeography evolve. Lacustrine facies typify the early stages of synrift development in basins closer or more proximal to the Sundaland province in northern and western SE Asia. Open marine facies, on the other hand, typify the early postrift period and basins in palaeogeographically more distal areas, such as eastern Indonesia and The Philippines. Paralic and bathyal facies characterise the later stages of the synrift and postrift cycles and are widespread throughout the proximal and intermediate parts of the area. Pre-Tertiary source facies, which provide charge in parts of eastern Indonesia and Thailand, are mainly terrestrial in nature. These differences have important implications for petroleum occurrence, which can be summarised accordingly: • More proximal basins are dominated by lacustrine to paralic facies in the synrift cycle and have a mainly non-marine sedimentary fill. Petroleum systems with oil charge are dominant. • More distal basins are dominated by rapid postrift subsidence. In the open marine facies carbonate reservoirs are well-developed, while petroleum systems are mainly gas-prone. • Around Borneo thick late postrift passive margin delta sequences with oil- and gas-prone coaly source rocks and clastic reservoirs are developed in delta-top environments. Transported terrigenous organic material is commonly found in related deep marine environments and contributes to a marine source facies. Both give rise to prolific petroleum systems. • Many basins in the Sunda Shelf area lie in an intermediate situation, where a non-marine synrift is followed by a marine postrift cycle. Such basins benefit from lacustrine and paralic source rock and reservoir sequences in both the syn- and the postrift, and are often characterised by multiple petroleum systems. Evaluation of petroleum potential in Southeast Asian Tertiary basins requires a special approach: in most parts of the World, such as the Middle East and Northwest Europe, source rocks are of marine origin, are relatively consistent in type and quality and are located in well-defined formations of regional extent. In SE Asia the terrestrial and lacustrine source rocks are more difficult to locate, are variable in quality and are often distributed in thin beds throughout thick sequences. These differences mean that predictive extrapolations of charge quality and maturity, and therefore of basin prospectivity, are much more difficult in Southeast Asia: This probably explains why discoveries continue to be made after almost 130 years of exploration!

Genesis of Paleogene gas in the Dongpu Depression, Bohai Bay Basin, East China

The Dongpu Depression, located in the southwest of the Bohai Bay Basin, east China, is enriched in natural gas with proven reserves of about 480 billion m3. However, their genesis and distribution are not completely clear. On the basis of molecular, stable carbon isotope and noble gas isotope (Ar) composition of a large amount of gas samples and combined with the geological background, this paper analyzed the genesis and migration features of Paleogene gas from major gas fields in the Dongpu depression. The results show that Paleogene gases in the Dongpu Depression are of thermogenic origin, and can be divided into coal-derived gas, oil-associated gas and their mixture. Furthermore, Natural gases from the E2s3L and E2s3M are predominantly oil-associated gas generated from E2s3 source rocks, while those from E2s4, and E2s3U and E2s2 in the Baimiao area are derived from the Carboniferous-Permian coaly source rocks. In addition, the coal-derived gas can also mix with the oil-associated gas, which can be called mixed coal-derived gas and oil-associated gas. Carbon isotope data suggest that gases of E2s3 and most E2s2 are predominately unaltered, while those of E2s4 and several E2s2 mostly from Baimiao area are altered and undergoing strong dissipation. The geographical variation in the gas composition can be attributed to the geochemical fraction caused by vertical migration through the basement faults for the coal-derived gas in E2s4 and several E2s3U and E2s2 in Baimiao area. While the oil-associated gas in E2s3L and E2s3M are resulted from the near-source or even in situ accumulation.

Organic geochemical characteristics of oils from the offshore Jiza-Qamar Basin, Eastern Yemen: New insight on coal/coaly shale source rocks

Coals, coaly shales and oil show samples from Late Cretaceous sections in the offshore Jiza-Qamar Basin (Yemen) were analysed using organic geochemical analyses to investigate the source of organic matter input and the genetic link between oils and potential source rocks in the basin. The coals and coaly shales have high TOC contents between 6.90 and 77.62wt% and Hydrogen Index (HI) values are largely above 300mg HC/g TOC, indicating that the Late Cretaceous coaly shales and coals as expected are organically rich, and predominantly contain Type III-II kerogens.The oil shows are classified as paraffinic–naphthenic–aromatic (P–N–A) oil with high wax contents, suggesting that the oils were generated from coal and coaly source rocks that were deposited in a deltaic–coastal environment. This is supported by bulk geochemical characteristics and biomarker compositions. A variety of biomarkers n-alkanes, regular isoprenoids, terpanes and steranes indicate that the oil shows were derived predominantly from source rock containing higher plant derived organic matter and were deposited in fluvial to deltaic environments under relatively oxic conditions. The biomarker characteristics and stable isotope compositions of the oils are similar to those of the Late Cretaceous coal and coaly shale rocks. The new data presented in this paper suggests genetic link between oil shows and coal/coaly shale rocks in the offshore Jiza-Qamar Basin and provides new evidence for the oil generative potential of the Cretaceous coals and coaly shales in the basin.

Confined Pyrolysis for Simulating Hydrocarbon Generation from Jurassic Coaly Source Rocks in the Junggar Basin, Northwest China

Several oil and gas fields have been found in which oil and gas were mainly derived from the Jurassic coaly source rocks in the Junggar Basin, northwest China. Pyrolysis experiments were performed on two coals (J23C1 and FM1C2) and one type III kerogen of mudstone (Di9S1) from Jurassic strata in the basin at two heating rates of 20 and 2 °C/h in confined systems (gold capsules). Hydrogen indices and H/C atomic ratios of the three samples J23C1, FM1C2, and Di9S1 are 83, 197, and 226 mg/g TOC, and 0.70, 0.86, and 1.01, respectively. The measured maximum oil yields for the three samples are 59.37, 175.75, and 80.75 mg/g TOC, respectively, inconsistent with hydrogen indices and H/C atomic ratios. However, the measured maximum gas yields (∑C1–5) for the three samples are 90.69, 157.24, and 198.15 mg/g TOC, respectively, consistent with hydrogen indices and H/C atomic ratios. This result is interpreted by kerogen Di9S1 containing mainly crossed alkane moieties with both terminals attached to aromatic rings whil...

Origins of Jurassic oil reserves in the Turpan–Hami Basin, northwest China: Evidence of admixture from source and thermal maturity

Middle–Lower Jurassic coaly shales were considered to be the source of Jurassic oil reserves in the Turpan–Hami Basin. In this study, we investigated the molecular and stable isotopic compositions of 35 gas samples and the geochemical parameters for 28 oil samples to reexamine the origin of these hydrocarbons. We show that the Jurassic natural gas reserves are derived mainly from coaly source rocks in the Middle Jurassic Xishanyao and Lower Jurassic Badaowan formations with maturities varying from 0.6% to 0.9%Ro. However, analysis of the low molecular weight hydrocarbons and diamondoid hydrocarbons shows that the maturities of the oils are clearly higher than those of the Jurassic coal measures and the natural gas generated from them. Their molecular and carbon isotopic compositions indicate that most of the Jurassic oil reserves are derived from pre-Jurassic lacustrine mudstones. The Hongtai gas/condensate field is an exception where the Jurassic coal measures are major contributors of light hydrocarbons. In contrast, the biomarker fingerprints of the Jurassic oils reveal a predominantly humic origin, which is most probably resulted from migration contamination. As such, the Jurassic petroleum system of the Turpan–Hami Basin is a mixed oil system derived from pre-Jurassic lacustrine mudstones and the Middle–Lower Jurassic coaly source rocks. This study opens pre-Jurassic structures in the Turpan–Hami Basin as favorable exploration prospects and illustrates the value of multiple correlation techniques to determine the sources of associated light and heavy hydrocarbons.

An overview on source rocks and the petroleum system of the central Upper Rhine Graben

The petroleum system of the Upper Rhine Graben (URG) comprises multiple reservoir rocks and four major oil families, which are represented by four distinct source rock intervals. Based on geochemical analyses of new oil samples and as a review of chemical parameter of former oil fields, numerous new oil–source rock correlations were obtained. The asymmetric graben resulted in complex migration pathways with several mixed oils as well as migration from source rocks into significantly older stratigraphic units. Oldest oils originated from Liassic black shales with the Posidonia Shale as main source rock (oil family C). Bituminous shales of the Arietenkalk-Fm. (Lias α) show also significant source rock potential representing the second major source rock interval of the Liassic sequence. Within the Tertiary sequence several source rock intervals occur. Early Tertiary coaly shales generated high wax oils that accumulated in several Tertiary as well as Mesozoic reservoirs (oil family B). The Rupelian Fish Shale acted as important source rock, especially in the northern URG (oil family D). Furthermore, early mature oils from the evaporitic-salinar Corbicula- and Lower Hydrobienschichten occur especially in the area of the Heidelberg-Mannheim-Graben (oil family A). An overview on potential source rocks in the URG is presented including the first detailed geochemical source rock characterization of Middle Eocene sediments (equivalents to the Bouxwiller-Fm.). At the base of this formation a partly very prominent sapropelic coal layer or coaly shale occurs. TOC values of 20–32 % (cuttings) and Hydrogen Index (HI) values up to 640–760 mg HC/g TOC indicate an extraordinary high source rock potential, but a highly variable lateral distribution in terms of thickness and source rock facies is also supposed. First bulk kinetic data of the sapropelic Middle Eocene coal and a coaly layer of the ‘Lymnaenmergel’ are presented and indicate oil-prone organic matter characterized by low activation energies. These sediments are considered as most important source rocks of numerous high wax oils (oil family B) in addition to the coaly source rocks from the (Lower) Pechelbronn-Schichten (Late Eocene). Migration pathways are significantly influenced by the early graben evolution. A major erosion period occurred during the latest Cretaceous. The uplift center was located in the northern URG area, resulting in SSE dipping Mesozoic strata in the central URG. During Middle Eocene times a second uplift center in the Eifel area resulted in SW-NE-directed shore lines in the central URG and contemporaneous south-southeastern depocenters during marine transgression from the south. This structural setting resulted in a major NNW-NW-directed and topography-driven migration pattern for expelled Liassic oil in the fractured Mesozoic subcrop below sealing Dogger α clays and basal Tertiary marls.

The fluvial and lacustrine sedimentary systems and stratigraphic correlation in the Upper Triassic Xujiahe Formation in Sichuan Basin, China

The calcarenites and siliciclastic sandstones in the Upper Triassic Xujiahe Formation are key targets of the unconventional gas exploration in Sichuan Basin. To resolve the long-debated stratigraphic correlation of the interfingering lithostratigraphic members between the different exploration blocks, a facies classification scheme integrating sedimentary structures in borehole images (BHI) and lithology from wireline logs is calibrated in the cored wells and extrapolated into the noncored wells. Three major sedimentary systems are recognized in Xujiahe by mapping the facies trends and paleocurrent directions in the coarse-grained sediments. One system may dominate over the others at different times and/or locations in the foreland basin in response to the orogenic movements in the surrounding mountains. The Longmen Shan in the northwest of the study area is the main source provenance for the carbonate conglomerates and calcarenites. Meanwhile, the systems in the northeast and southeast deposited the sandstone wedges. Alternating lacustrine, swamp, and fluvial sediments are penetrated in both proximal and distal areas in the basin, although there is no indication of a basinwide lake in the Xujiahe period. Abundant sandy shale-breccia conglomerates containing large shale breccias, plant materials, and contorted shale blocks in association with thick foreset-bedded sandstones suggest subaqueous gravity flows possibly because of the collapse of a multistoried delta front. Characterization of these dynamic sedimentary systems through multidisciplinary interpretation of the seismic data, cores, BHI, and wireline logs is not only fundamental to the sedimentary analysis, but also the exploration strategy in the areas with optimal juxtaposition of reservoir sandstones and coaly source rocks.

Genesis of tight sand gas in the Ordos Basin, China

Based on molecular and stable carbon isotope composition of a large collection of gas samples and integrated with the geological context, this article discusses the genesis and migrational characteristics of natural gases from the giant tight sand gas fields of the Upper Paleozoic strata, Ordos Basin (UPOB). Our results show that the UPOB gas is mostly derived from coaly source rocks, with a minor contribution of oil-associated gas probably from the interbedded carbonate source rocks. Gas isotope data suggest that the Yulin–Zizhou gas field was likely formed from a single gas charge with no significant alteration, whereas the Sulige field contains a mixture of gases from successive charges with multiple maturity levels. The geographical variation in the observed gas composition is attributed primarily to the effect of source rock maturity, with no explicit geochemical fractionation caused by long distance lateral migration.

Marine influence helps preserve the oil potential of coaly source rocks: Eocene Mangahewa Formation, Taranaki Basin, New Zealand

Many Cretaceous–Cenozoic coaly source rocks in Australasian and southeast Asian basins were deposited in coastal plain environments, yet the effect of early diagenetic marine influence on their oil potential is not well understood. An integrated organic geochemical and petrographic study of humic coals from the Eocene Mangahewa Formation (Taranaki Basin, New Zealand) was undertaken with coals predominantly from raised mire petrofacies, with subordinate proportions from planar mires. The total S content of 0.63–4.4% (dry, ash-free) indicated very slight to strong degrees of marine influence. Other than minor addition of inferred mangrove derived suberinite and associated liptodetrinite, the degree of marine influence had no obvious effect on maceral or plant tissue abundance. However, hydrogen index (HI) values were up to ca. 150% (109mgHC/gTOC) higher, and total (C6+) oil potential up to ca. 140% (43mg/gTOC) higher among the more strongly marine influenced coals. Correlation of organic S with solvent extract parameters pristane/phytane, C27–C29 diasteranes/steranes, C29 steranes/hopanes, C35/(C35+C34) homohopanes and oleanane index suggested that inundation of brackish water into the early diagenetic peat forming environment enhanced the bio-resistance of higher plant and other lipids through sulfurization, thereby helping to preserve more of the inherent H content and total oil potential of the original peat biomass. Conversely, marine influence had only a minor effect on the capacity of Mangahewa coals to generate paraffinic oil. Total (n-C6+) and non-volatile (n-C15+) paraffinic oil potentials were instead controlled primarily by the abundance of leaf derived cutinite and associated liptodetrinite. This, in turn, was dependent on the type of peat mire facies, with planar mire facies having better potential for preservation of leaf litter than raised mire facies because of their generally higher groundwater level. Marine influence is nonetheless beneficial for paraffinic oil charge from coaly source rock sequences in that the associated higher HIs enhance the efficiency and quantum of paraffinic oil expulsion through increased saturation of the coal pore system.

New exploration opportunities along Australia's southern margin

The 2012 Australian offshore acreage release includes exploration areas in four southern margin basins. Three large Release Areas in the frontier Ceduna Sub-basin lie adjacent to four exploration permits granted in 2011. The petroleum prospectivity of the Ceduna Sub-basin is controlled by the distribution of Upper Cretaceous marine and deltaic facies and a structural framework established by Cenomanian growth faulting. These Release Areas offer a range of plays charged by Cretaceous marine and coaly source rocks and Jurassic lacustrine sediments. In the westernmost part of the gas-producing Otway Basin, a large Release Area offers numerous opportunities to test existing and new play concepts in underexplored areas beyond the continental shelf. Gas and oil shows in the eastern part of the Release Area confirm the presence of at least two working petroleum systems. In the eastern Otway Basin, several Release Areas are offered in shallow water on the eastern flank of the highly prospective Shipwreck Trough and provide untested targets along the eastern basin margin southward into Tasmanian waters. To the south, a large Release Area in the frontier Sorell Basin provides the opportunity to explore a range of untested targets in depocentres that formed along the western Tasmanian transform continental margin. Two Release Areas offer exploration potential in the under-explored eastern deepwater part of the Gippsland Basin. Geological control is provided by several successful wells indicating the presence of both gas and liquids in the northern area, while the southern area represents the remaining frontier of the basin

HYDROCARBON POTENTIAL OF MIDDLE JURASSIC COALY AND LACUSTRINE AND UPPER JURASSIC – LOWERMOST CRETACEOUS MARINE SOURCE ROCKS IN THE SØGNE BASIN, NORTH SEA

The Søgne Basin in the Danish‐Norwegian Central Graben is unique in the North Sea because it has been proven to contain commercial volumes of hydrocarbons derived only from Middle Jurassic coaly source rocks. Exploration here relies on the identification of good quality, mature Middle Jurassic coaly and lacustrine source rocks and Upper Jurassic – lowermost Cretaceous marine source rocks. The present study examines source rock data from almost 900 Middle Jurassic and Upper Jurassic – lowermost Cretaceous samples from 21 wells together with 286 vitrinite reflectance data from 14 wells. The kerogen composition and kinetics for bulk petroleum formation of three Middle Jurassic lacustrine samples were also determined.Differences in kerogen composition between the coaly and marine source rocks result in two principal oil windows: (i) the effective oil window for Middle Jurassic coaly strata, located at ∼3800 m and spanning at least ∼650 m; and (ii) the oil window for Upper Jurassic – lowermost Cretaceous marine mudstones, located at ∼3250 m and spanning ∼650 m. A possible third oil window may relate to Middle Jurassic lacustrine deposits. Middle Jurassic coaly strata are thermally mature in the southern part of the Søgne Basin and probably also in the north, whereas they are largely immature in the central part of the basin. HImax values of the Middle Jurassic coals range from ∼150–280 mg HC/g TOC indicating that they are gas‐prone to gas/oil‐prone. The overall source rock quality of the Middle Jurassic coaly rocks is fair to good, although a relatively large number of the samples are of poor source rock quality.At the present day, Middle Jurassic oil‐prone or gas/oil‐prone rocks occur in the southern part of the basin and possibly in a narrow zone in the northern part. In the remainder of the basin, these deposits are considered to be gas‐prone or are absent. Wells in the northernmost part of the Søgne Basin / southernmost Steinbit Terrace encountered Middle Jurassic organic–rich lacustrine mudstones with sapropelic kerogen, high HI values reaching 770 mg HC/g TOC and Ea‐distributions characterised by a single dominant Ea‐peak. The presence of lacustrine mudstones is also suggested by a limited number of samples with HI values above 300 mg HC/g TOC in the southern part of the basin; in addition, palynofacies demonstrate a progressive increase in the abundance and areal extent of lacustrine and brackish open water conditions during Callovian times. A regional presence of oil‐prone Middle Jurassic lacustrine source rocks in the Søgne Basin, however, remains speculative.Middle Jurassic kitchen areas may be present in an elongated palaeo‐depression in the northern part of the Søgne Basin and in restricted areas in the south.Upper Jurassic – lowermost Cretaceous mudstones are thermally mature in the central, western and northern parts of the basin; they are immature in the eastern part towards the Coffee Soil Fault, and overmature in the southernmost part. Only a minor proportion of the mudstones have HI values >300 mg HC/g TOC, and the present‐day source rock quality is for the best samples fair to good. In the south and probably also in most of the northern part of the Søgne Basin, the mudstones are most likely gas‐prone, whereas they may be gas/oil‐prone in the central part of the basin. A narrow elongated zone in the northern part of the basin may be oil‐prone. The marine mudstones are, however, volumetrically more significant than the Middle Jurassic strata.Possible Upper Jurassic – lowermost Cretaceous kitchen areas are today restricted to the central Søgne Basin and the elongated palaeo‐depression in the north.

Modeling of petroleum generation in the Vietnamese part of the Malay Basin using measured kinetics

Two-dimensional (2-D) modeling of source rock maturation and hydrocarbon (HC) generation histories were conducted for the Malay-Cho Thu Basin in the Gulf of Thailand and South China Sea. The source rocks comprise Oligocene synrift lacustrine mudstones and coals, postrift coals, and terrigenous-influenced mudstones. Three different lacustrine mudstone source rocks and coals were considered in the 2-D modeling, and each source rock was assigned specific generation potential and kinetics. Measured kinetics for bulk petroleum generation determined on two thermally immature upper Oligocene oil-prone lacustrine mudstones and on a terrigenous-influenced mudstone derived from wells were used together with published coal kinetics. The onshore Krong Pa graben, a small-scale rift basin in central Vietnam, was used as a conceptual model for the distribution of lithofacies, including source rock types, in the 2-D models. Exploration targets and drilled direct HC indicators (DHIs) are mainly located in the tectonically disturbed postrift succession. Modeling results suggest that the risks related to this play are (1) timing of petroleum generation from the oil-prone lacustrine synrift deposits relative to structural trap formation, (2) complex migration pathways through strongly faulted strata, and (3) relatively small kitchen areas. Oil generation from uppermost synrift and postrift coaly source rocks with minor contribution from lacustrine deposits after principal trap formation is consistent with the prominent terrigenous geochemical signature of oils in the Malay-Cho Thu Basin. A new untested play is proposed based on mapping of potential DHIs associated with sandstone bodies in tectonically undisturbed synrift traps.

Reservoir potential of Late Cretaceous terrestrial to shallow marine sandstones, Taranaki Basin, New Zealand

Late Cretaceous coals and coaly source rocks are the main source of hydrocarbons in the Taranaki Basin, yet to date there have not been any hydrocarbon discoveries within Cretaceous strata, and sandstone distribution and reservoir quality for this interval have been poorly understood. The Late Cretaceous sediments were deposited in several sub-basins across Taranaki, with their distribution largely determined by sediment supply, subsidence, and sea level change. In this study, we describe potential reservoir facies in well penetrations of Cretaceous strata in Taranaki, as well as from outcrop in northwest Nelson, on the southern edge of the basin. Study of Cretaceous outcrop has shown that facies distribution is a major control on reservoir quality. Shoreface, intertidal, and estuarine depositional facies contain both excellent, well sorted sandstone reservoir facies as well as low net-to-gross, reservoir-poor facies. These contrast with deposits from generally less well sorted, and more heterolithic coastal plain environments. Much of the facies distribution is attributed to relative sea level fluctuations, which occurred throughout deposition. Late Cretaceous sandstones display a range of mean grain sizes and compositions, with the latter related to geographic location and sediment source. Burial depths are highly variable across the basin, ranging from <1 km to >6 km, and this has had a profound effect on reservoir quality. The main petrographic controls on reservoir quality are sandstone composition, volume of clay minerals, degree of mechanical compaction (related to maximum burial depth), and proximity to a source of acidic pore fluids for the generation of secondary porosity. Results from this study suggest that Cretaceous strata are a viable reservoir play over much of the western part of the Taranaki Basin and into parts of the south-eastern basin. Palaeogeographic maps and textural/compositional data can be used to high-grade regions for further exploration.

Capel and Faust basins—integrated geoscientific assessment of Australia's remote offshore eastern frontier

The paper discusses the results from the GA–302 2D seismic survey and GA–2436 (RV Tangaroa) marine reconnaissance survey over the Capel and Faust basins in the northern Tasman Sea. The integration of seismic, potential field and bathymetric data sets in 3D space at an early stage in the project workflow has assisted in the visualisation of the basin architecture, the interpolation of data between the seismic lines and the iterative refinement of interpretations. The data sets confirm the presence of multiple depocentres previously interpreted from satellite gravity data with a maximum sediment thickness of 5–7 km. Preliminary interpretation of the seismic data has identified two predominantly Cretaceous syn-rift and two Upper Cretaceous to Neogene sag megasequences overlying a heterogeneous pre-rift basement. The comparison of seismic facies and tectonostratigraphic history with offshore New Zealand and eastern Australian basins suggests the presence of possible Jurassic to Upper Cretaceous coaly and lacustrine source rocks in the pre-rift and syn-rift, and fluvio-deltaic to shallow marine reservoir rocks in the syn-rift to early post-rift successions. Preliminary 1D basin modelling suggests that the deeper depocentres of the Capel and Faust basins are within the oil and gas windows. Large potential stratigraphic and structural traps are also present.

Geology of giant gas fields in China

Twenty-five gas fields with recognized ultimate recoveries larger than 25 billion cubic meters have been found in six basins in China. The earliest was found in 1959 and the latest in 2005. Recognition of more recent discoveries as giants will probably further increase the population. Examination of reservoir age, lithology, trap and depositional environment leads to the conclusion that there are no diagnostic characteristics common to all of the giants. However, coaly source rocks, traps in close proximity to major gas kitchens, reservoirs and caprocks with reasonable quality, late gas accumulation and continuous gas supply are the preferred parameters. Uncommonly thick reservoir rocks or unusual development of porosity and permeability are not required. The fact that giant gas fields exist in reasonable numbers and have been discovered steadily through the years suggests that more efforts are needed to find the remaining gas resources in China.

Diagenesis, Porosity Evolution, and Petroleum Emplacement in Tight Gas Reservoirs, Taranaki Basin, New Zealand

Abstract Tight gas reservoirs have become popular targets in petroleum exploration in recent years, due largely to the increasing market demand for gas and also to technology advances used in extraction. Reservoir quality is typically poor due to deep-burial diagenesis, resulting in significant compaction, cementation, and illitization. However, analysis of tight reservoirs using integrated techniques can improve our understanding about the controls on reservoir quality, and these results can potentially be used to help predict reservoir quality at other sites. The use of integrated analysis of diagenetic and burial history is here shown for the Eocene, K3E Kapuni Group reservoir in Cardiff-1, Taranaki Basin, New Zealand. The K3E belongs to a deep gas play that was considered uncommercial in the early 1990's due to poor reservoir quality associated with extensive authigenic illite. Potassium-argon dating has shown that destruction of the reservoir through illitization occurred in the Pliocene, associated with a late-stage heating and/or fluid-flow event. Timing of illite authigenesis in the K3E reservoir postdates the likely circulation of CO2-rich fluids that caused reaction of feldspar to form kaolinite and quartz. Homogenization temperatures from two-phase aqueous fluid inclusions within quartz cements, together with 1D basin models of CO2 expulsion from coaly source rocks, indicate that feldspar reactions may have started in the mid Miocene. The CO2-rich fluids are thought to have been generated by thermal decarboxylation of intraformational Paleocene–Eocene coals. At the same time, oil was being expelled from older, Cretaceous coals and migrated into the mid-late Eocene reservoirs; evidence for oil migration is demonstrated by the presence of residual oil and by the local occurrence of abundant oil-bearing fluid inclusions. The products of feldspar dissolution appear to be in reasonable balance with the amount of dissolved feldspar, suggesting a relatively closed diagenetic system with little improvement in reservoir quality despite the large volume of feldspar dissolved. Petrographic evidence of reservoir sandstones at Cardiff-1 demonstrates the presence of some illite-free secondary macropores lined by residual oil. This local preservation of porosity may be replicating the original distribution of oil-saturated pores in the Pliocene, at the time when authigenic kaolinite underwent reaction to form illite. Remobilization of the oil probably occurred by gas flushing after the main phase of illitization at c. 5 Ma. The data presented in this study are consistent with redistributed liquid petroleum into up-dip traps and represent the potential for a new exploration play. The Eocene reservoir at Cardiff-1 is currently gas-charged, with the pore system composed of approximately one third large macropores connected by a tortuous, microporous network. However, it is possible that, with the currently buoyant gas market and modern hydraulic fracturing techniques, it may now be economic to flow gas from the locally large pores identified in the K3E reservoir.

PETROLEUM POTENTIAL OF THE GREAT SOUTH BASIN, NEW ZEALAND—NEW SEISMIC DATA IMPROVES IMAGING

Much of the Great South Basin is covered by a 30,000 km grid of old seismic data, dating from the 1970s. This early exploration activity resulted in drilling eight wells, one of which, Kawau–1a, was a 461 Bcf gas-condensate discovery. Three other wells had significant oil and gas shows; in particular, Toroa–1 had extensive gas shows and 300 m oil shows. Cuttings are described in the geological logs as dripping with oil. The well was never tested due to engineering difficulties, meaning that much of the bore was accidentally filled with cement while setting casing.In early 2006, Crown Minerals, New Zealand’s petroleum industry regulating body, conducted a new 2D seismic survey in a previously lightly surveyed region across the northern part of the Great South Basin. While previous surveys were generally recorded for five seconds, sometimes six, with up to a 2,500-metre-long cable, the new survey, acquired by CGG Multiwave’s Pacific Titan, employed a 6,000-metre-long streamer and recorded for eight seconds.The dataset was processed to pre-stack time migration (PreSTM) by the GNS Science group using its access to the New Zealand Supercomputer. Increasing the recording time yielded dividends by more fully imaging, for the first time, the nature of rift faulting in the basin. Previous data showed only the tops of many fault blocks. The new data show a system of listric extensional faults, presumably soling out onto a mid-crust detachment. Sedimentary reflectors are observed to seven seconds, implying a thickness of up to 6,000 m of section, probably containing source rock units. The rotated fault blocks provide focal points for large compaction structures. The new data show amplitude anomalies and other features possibly indicating hydrocarbons associated with many of these structures. The region around the Toroa–1 well was typified by anomalously low velocities, which created a vertical zone of heavily attenuated reflections, particularly on intermediate processing products. The new data also show an amplitude anomaly at the well’s total depth (TD) which gives rise to a velocity push-down.Santonian age coaly source rocks are widespread and several reservoir units are recognised. The reservoir at Kawau–1a is the extensive Kawau Sandstone, an Early Maastrichtian transgressive unit sealed by a thick carbonate-cemented mudstone. In addition to the transgressive sandstone target, the basin also contains sandy Eocene facies, and Paleogene turbidite targets may also be attractive. Closed structures are numerous and many are very large with potential to contain billion barrel oil fields or multi-Tcf gas fields.

The controlling factors of oil and gas generation from coal in the Kuqa Depression of Tarim Basin, China

Abstract The organic matter-rich rocks in the Kuqa Depression are mainly coal measures and therefore are gas prone. However, small amounts of oil also occur and appear to be derived from these coals and associated shales. The hydrocarbons have five different modes of occurrence: pure dry gas, wet gas, condensate, oil–gas mixtures and pure oil. The distribution of coal-related reservoired petroleum in the Kuqa Depression of the Tarim Basin indicates that the existence oil versus gas accumulations are largely influenced by geologic history and timing of generation. The oils and gases occur in various geological settings. The coal measures have mainly generated gas, but in different geological settings, different types of oil and gas accumulations occur. The traps containing dry gas in the Kuqa Depression formed late in the geological history, and therefore could only capture late gas generated by high maturity coaly source rocks. The traps which reservoir wet gas or condensates have a high integrity and formed when the coals had a lower maturity. The oil pools mainly occur in areas where seals are poor and in some cases fractured. The gas previously existing in these reservoirs was largely dissipated, but a small quantity of oil remained to form minor, residual oil or oil–gas occurrences.