Reservoir characterization and multiscale heterogeneity modeling of inclined heterolithic strata for bitumen-production forecasting,McMurray Formation,Corner, Alberta,Canada

Bitumen reservoirs dominated by inclined heterolithic stratification (IHS) formed in large point bars of the Aptian (Lower Cretaceous) McMurray Formation in the northwestern part of the Corner oil sand lease (Alberta, Canada) were investigated to establish their value. Hybrid production technologies were applied to thin pay, typified by homogeneous reservoir sand units thicker than 5 m at the base overlain by IHS (so-called ‘thin pay’), as well as IHS-dominated reservoirs in which the IHS extends down to the base of the reservoir. High-resolution seismic data and well data (core, dipmeter, HMI) were used to map four facies associations, comprising a total of 16 sedimentary facies, as well as various fluid contacts to assist in reservoir characterization and risk assessment. The conceptual depositional model was based on the analysis of the migration and re-orientation history of the IHS-dominated point bars reflecting lateral accretion, downstream migration, rotation and relocation of the bars. Multiple reactivation events, which control the heterolithic nature and reservoir quality of the deposits, create developable “pools”.Seven electrofacies (with generally increasing mud content) were defined and used as input to construct vertical proportion curves that relate the electrofacies distribution to geomodel statistics in the main reservoir zone. At the electrofacies scale, numerical effective porosity-permeability models were created using micromodeling and minimodeling concepts. The geometrical shape of the electrofacies in the geomodel was investigated using non-stationary Truncated Gaussian (TG) facies simulation to enforce the stacking patterns. Each geomodel area was characterized using one variogram to efficiently compute the horizontal and vertical variogram ranges and average azimuths. Sequential Gaussian simulation (SGS) was used to map the distribution of key petrophysical parameters such as effective porosity, effective water saturation and V_shale. Empirically derived saturation versus elevation profiles for each electrofacies were included in the modeling. The distributions from the micro- and mini-modeling were introduced using probability field (P-field) simulation. To investigate the amount of connected resources (the degree of connectivity of good sand as well as IHS) were extractable flow simulation studies were performed at the pad scale. In preparation for reservoir simulation, connectivity calculations within the local pool geomodel realizations were tailored for the reservoir heterogeneities (i.e., IHS) that are expected to have a major impact on the specific thermal and gravity drainage extraction processes. The geomodel realizations were ranked by expected pseudo-dynamic behaviour with connected exploitable pay as a critical parameter.     

Mechanical properties of organic matter in shales mapped at the nanometer scale

The mechanical properties of organic matter strongly affect the way shales deform and fracture. However, the way organic matter responds to mechanical stresses is poorly understood, representing a critical obstacle to assessing oil and gas production in shale formations. Little is known about the mechanical properties of organic matter in fine grained rocks primarily because it often occupies tiny nanometer-scale voids between the mineral grains which cannot be accessed using standard mechanical testing techniques. Here, we use a new atomic force microscopy technique (PeakForce QNM™) to map the mechanical properties of organic and inorganic components at the nanometer scale. We find that the method is able to distinguish between different phases such as pyrite, quartz, clays, and organic matter. Moreover, within the organic component Young's modulus values ranged from 0 to 25 GPa; in 3 different samples – all of which come from thermally mature Type II/III source rocks in the dry gas window – a modal value of 15–16 GPa was measured, with additional peaks measured at ≤10 GPa. In addition, the maps suggest that some porous organic macerals possess a soft core surrounded by a harder outer shell 50–100 nm thick. Thus, our results demonstrate that the method represents a powerful new petrographic tool with which to characterize the mechanical properties of organic-rich sedimentary rocks.     

The indigenous origin of Witwatersrand “carbon”

In the Witwatersrand approximately 40% of the gold is intimately associated with so-called “carbon” in “carbon seam reefs”, which occur in over a dozen paleoplacers, many of them concentrated at two stratigraphic levels in the 7000-m-thick succession of Archean siliciclastic sedimentary rocks. This is reduced carbon, present as kerogen admixed in various proportions with derivative (now solid) bitumen(s). Oil generation and migration were active geological processes during Early Earth history. Numerous possible source rocks for oil generation, including the carbon seams themselves, occur within the Witwatersrand basin. In the Witwatersrand ore, oil-bearing fluid inclusions are also present, derived like the bitumen, by thermal maturation of the kerogen. The presence of kerogen and bitumen in the Witwatersrand sedimentary rocks, together with a wealth of observations on the spatial distribution of the carbon seams confirm that the carbon originated in situ from living organisms in microbial mat cover, as opposed to flowing in from elsewhere as liquid hydrocarbons as some researchers have suggested. Paleochannels, which truncated auriferous carbon seams early in the depositional history, are of widespread occurrence, and micro-synsedimentary faults offset carbon seams. The carbon seams are thus indigenous biogenic markers that grew contemporaneously with placer development. The various features highlighting the nature and spatial distribution of Witwatersrand carbon seams provide a classic case where field evidence trumps laboratory data in the reconstruction of geological processes.     

Radial patterns of bitumen dykes around Quaternary volcanoes,provinces of northern Neuquén and southernmost Mendoza,Argentina

Where the Neuquén Basin of Argentina abuts the Andes, hundreds of veins of solid hydrocarbon (bitumen) are visible at the surface. Many of these veins became mines, especially in the last century. By consensus, the bitumen has resulted from maturation of organic-rich shales, especially the Vaca Muerta Fm of Late Jurassic age, but also the Agrio Fm of Early Cretaceous age. To account for their maturation, recent authors have invoked regional subsidence, whereas early geologists invoked magmatic activity. During 12 field seasons (since 1998), we have tracked down the bitumen localities, mapped the veins and host rocks, sampled them, studied their compositions, and dated some of them. In the provinces of northern Neuquén and southernmost Mendoza, the bitumen veins are mostly sub-vertical dykes. They tend to be straight and continuous, crosscutting regional structures and strata of all ages, from Jurassic to Palaeocene. Most of the localities lie within 70 km of Tromen volcano, although four are along the Rio Colorado fault zone and another two are at the base of Auca Mahuida volcano. On both volcanic edifices, lavas are of late Pliocene to Pleistocene age. Although regionally many of the bitumen dykes tend to track the current direction of maximum horizontal tectonic stress (ENE), others do not. However, most of the dykes radiate outward from the volcanoes, especially Tromen. Thicknesses of dykes tend to be greatest close to Tromen and where the host rocks are the most resistant to fracturing. Many of the dykes occur in the exhumed hanging walls of deep thrusts, especially at the foot of Tromen. Here the bitumen is in places of high grade (impsonite), whereas further out it tends to be of medium grade (grahamite). A few bitumen dykes contain fragments of Vaca Muerta shale, so that we infer forceful expulsion of source rock. At Curacó Mine, some shale fragments contain bedding-parallel veins of fibrous calcite (beef) and these contain some bitumen, which is geochemically of low grade. In contrast, a large crosscutting bitumen dyke is of higher grade and formed later. At other localities, near basement faults, bitumen dykes have cap-rocks of hydrothermal calcrete. Other dykes or their wall rocks contain hydrothermal minerals. Finally, some dykes splay upward towards the current land surface. We conclude that (1) the bitumen dykes formed during volcanic activity in Pliocene–Pleistocene times, and that (2) heat advection by hydrothermal fluids helped to generate oil, which migrated upwards or downwards from the source rock and filled intrusive veins, before solidifying to bitumen, by loss of volatile elements. This unconventional hydrocarbon system may have significant implications for regional exploration in the foothills of the Andes.     

塔里木盆地北部沥青、干酪根Pb-Sr-Nd同位素体系及成因演化

 Pb、Sr、Nd同位素体系研究表明沥青与寒武纪、奥陶纪地层中的干酪根具有明显的同位素组成差异,表明来自异源。沥青Pb同位素组成具有明显的幔源与壳幔混合特征,而干酪根显示出壳源特征。沥青与干酪根的Nd同位素组成也存在着明显的差别,反映出老地壳源与新地壳源的明显差别。来自柯坪隆起大湾沟沥青的Nd-Sr同位素体系给出了晚元古的相关等时线,年龄分别为872Ma与1195Ma,可能代表了沥青的最早形成年龄。但来自塔北隆起的沥青其Sm-Nd体系显示出介于大湾沟沥青与干酪根之间的混合相关,表明具有壳源与幔源的二元混合成因。Rb-Sr和Pb-Pb等时线趋向和Pb模式年龄还给出加里东期(～440Ma)和印支期(～250Ma)的原油运移与沥青沉淀年龄信息。Nd模式年龄还表明柯坪-阿克苏地区存在太古宙基底(3.2-2.5Ga).塔里木油藏受深断裂控制。     

碳酸盐岩有机质赋存形式及成烃特征

在分析多种有机质赋存形式的基础上，探讨了塔里木盆地下古生界和南华北石炭系碳酸盐岩的各种有机质含量关系及其成烃演化特征。研究发现，一般操作条件下所得的沥青Ａ和尖青Ｃ并非真正意义的吸附有机质和包裹有机质。目前还无法将真正的包裹有机质从碳酸盐岩中分离出来，由于成熟度，排烃条件等的影响、碳酸盐岩中各种有机质含量的相关关系不明显，仅沥青Ａ和沥青Ｃ有比较差的正相关关系。     

The distribution of hydrocarbon minerals in the Welsh borderlands and adjacent areas

Solid hydrocarbon minerals occur in small quantities in the Lower Palaeozoic Welsh Basin, where Ordovician igneous intrusions mobilized them from local organic-rich source rocks. Hydrocarbon minerals are widespread in the Wenlockian and Carboniferous Limestones, and at least in the Carboniferous Limestone they show a close and probably genetic relationship with lead-zinc mineralization. The association of hydrocarbon minerals with lead-zinc-copper ores in Ordovician and Longmydian rocks' in the West Shropshire mining region is however largely coincidental. The hydrocarbon minerals in that region are residual from Carboniferous reservoir hydrocarbons. Reservoir hydrocarbon minerals in a breccia at Row Brook include crystallites of iron sulphides and manganese oxides. Hydrocarbon minerals in siderite nodules in the Coal Measures are spatially related to metal sulphides.     

Oil-bearing inclusions in vein quartz and calcite and,bitumens in veins: Testament to multiple phases of hydrocarbon migration in the Barrandian basin (lower Palaeozoic), Czech Republic

The petroleum charge history of the Barrandian basin was investigated by analysing quartz and calcite and organic phases that occur in veins and fractures cutting dolerite sills within the Liteň Formation (Silurian). The geochemical characteristics of fluid inclusions trapped in vein quartz and calcite, vein bitumens and adjacent potential source rocks when combined with burial and thermal history data reflect the presence of at least three separate hydrocarbon charge episodes. Solid highly reflecting (R_max = 0.92–1.49%) bitumen provides information on the first and oldest episode of oil migration. The precursor oil was probably derived relatively early during diagenesis from nearby organic-rich sediments and was subsequently thermally altered to form the solid bitumen.     

TSR对碳酸盐岩中沥青生烃影响的模拟实验

利用地层孔隙热压生排烃模拟仪实验装置,对采自四川盆地西北部广元矿山梁地区下寒武统具高有机质含量、高氢指数和低成熟度特征的固体沥青,开展了模拟地层条件下的"沥青+白云岩+去离子水"(系列A)和"沥青+白云岩+硫酸镁+去离子水"(系列B)生排烃实验。结果表明,这两个系列的气体产率具有较大差异,其中,加入硫酸镁的系列(系列B)发生了热化学硫酸盐还原反应(TSR),使气态烃和非烃气体的产率增大,同时也加速了重烃气体的裂解,导致重烃气体大量裂解的温度降低。     

Occurrence and composition of solid bitumens from the Bulonggoer Devonian paleo-oil reservoir,North Xinjiang,China

The Bulonggoer paleo-oil reservoir (BPR) on the northwest Junggar Basin is the first Devonian paleo-oil reservoir discovered in North Xinjiang, China. Solid bitumens occur within sandstone pores and as veins filling fractures. Samples of both types were analyzed using stable carbon isotope and reflectance measurements, as well as molecular biomarker parameters.The extremely positive δ¹³C values and biomarker indicators of depositional environment/lithology, such as pristane/phytane (Pr/Ph), C₂₉/C₃₀ hopane, diasteranes/regular steranes and dibenzothiophene/phenanthrene ratios, indicate a siliciclastic source for the BPR and their deposition in a highly reducing hypersaline environment. The presence of long chain n-alkanes and abundant tetracyclic diterpanes, C₂₀–C₂₁ tricyclic terpanes and perylene are indicators of higher plant organic matter input. Moreover, the bimodal distribution of C₂₇ > C₂₈ < C₂₉ regular steranes and abundant methyltriaromatic steroids also support a contribution of microalgae as well as higher plants organic matter. The similar molecular composition and thermal maturity parameters indicate that the reservoir and veined solid bitumens were altered from a common paleo-petroleum, which originated from peak oil window matured source rocks.All solid bitumens from the BPR are characterized by relatively low bitumen reflectance values (Rb% < 0.7), suggesting that they were generated from low temperature processes rather than oil thermal cracking. Comparatively, the Rb% values for veined bitumens are higher than reservoir bitumens, indicating that the veined bitumens occurred earlier and experienced higher thermal conditions.