Diagenetic evolution of the upper Cretaceous limestone and sandstone exhumed reservoirs in the western Basque–Cantabrian Basin,North Spain

The Basque–Cantabrian Basin (NE Spain) has been considered one of the most interesting areas for hydrocarbon exploration in the Iberian Peninsula since the 60th to 70th of last century. This basin is characterized by the presence of numerous outcrops of tar sands closely associated with fractures and Triassic diapirs. The aims of this work is to establish the diagenetic evolution of the Upper Cretaceous reservoir rocks with special emphasis in the emplacement of oil and their impact on reservoir quality. The studied rocks are constituted of carbonates and sandstones that contain massive quantities of bitumen filling vugs and fractures.Petrographic results indicate that the carbonate rocks from Maestu outcrops are bioclastic grainstones and wackestones, whereas the tar sandstones from Atauri and Loza outcrops are dominated by quartzarenites and subordinated subarkoses. The paragenetic sequence of the main diagenetic phases and processes include, pyrite, bladed and drusy calcite cement, calcite overgrowths, silicification of bioclasts and microcrystalline rhombic dolomite cement, and first stage of oil emplacement, blocky calcite cement, coarse crystalline calcite cement, calcitized dolomite, calcite veins, saddle dolomite and stylolites filled by the second phase of oil entrance. Together with the above mentioned diagenetic alterations, the arenites are affected by early kaolinitization of feldspars and the scarce formation of clay rim and epimatrix of illite. All sandstones and dolomitized carbonate rocks show high intercrystalline and intergranular porosity which is full by biodegraded hydrocarbons (solid bitumen). The biodegradation affects alkanes, isoprenoids and partially hopanes and steranes saturated hydrocarbons. Aromatics hydrocarbons, like naphthalenes, phenanthrenes, dibenzothiophenes and triaromatics are also affected by biodegradation. Results indicate that the first HC emplacement corresponds to early stage of calcite and dolomite cementation, and the second and more important emplacement is related to fracturation processes resulting in the formation of excellent reservoirs.     

Characteristics and petroleum origin of the Carboniferous volcanic rock reservoirs in the Shixi Bulge of Junggar Basin,western China

Shixi Bulge of the central Junggar Basin in western China is a unique region that provides insight into the geological and geochemical characteristics of large-scale petroleum reservoirs in volcanic rocks of the western Central Asian Orogenic Belt. Carboniferous volcanic rocks in the Shixi Bulge mainly consist of striped lava and agglomerate, as well as breccia lava and tight tuff. Volcanic rocks differ in porosity and permeability. Striped lava exhibits the highest porosity (average: 14.2%) but the lowest permeability (average: 0.67 × 10⁻¹⁵ m) among the rock types. Primary gas pores are widely developed and mostly filled. Secondary dissolution pores and fractures are two major reservoir storage spaces. Capillary pressure curves suggest the existence of four pore structure types of reservoir rocks. Several factors, namely, lithology, pore structure, and various diagenesis, govern the physical properties of volcanic rocks. The oil is characterized by a high concentration of tricyclic terpane, a terpane distribution of C₂₃ < C₂₁ > C₂₀, and sterane distributions of C₂₇ < C₂₈ < C₂₉ and C₂₇ > C₂₈ < C₂₉. Oil and gas geochemistry revealed that the oil is a mixture derived primarily from P₂w source rock and secondarily from P₁j source rock in the sag west of Pen-1 Well. The gases are likely gas mixtures of humic and sapropelic organic origins, with the sapropelic gas type dominant in the mixture. The gas mixture is most likely cracked from kerogen rather than oils. The Carboniferous volcanic reservoirs in Shixi Bulge share some unique characteristics that may provide useful insights into the various roles of different volcanic reservoir types in old volcanic provinces. The presence of these reservoirs will undoubtedly encourage future petroleum exploration in volcanic rocks up to the deep parts of sedimentary basins.     

Prediction of diagenetic facies using well logs – A case study from the upper Triassic Yanchang Formation,Ordos Basin,China

Understanding diagenetic heterogeneity in tight sandstone reservoirs is vital for hydrocarbon exploration. As a typical tight sandstone reservoir, the seventh unit of the Upper Triassic Yanchang Formation in the Ordos Basin (Chang 7 unit), central China, is an important oil-producing interval. Results of helium porosity and permeability and petrographic assessment from thin sections, X-ray diffraction, scanning electron microscopy and cathodoluminescence analysis demonstrate that the sandstones have encountered various diagenetic processes encompassing mechanical and chemical compaction, cementation by carbonate, quartz, clay minerals, and dissolution of feldspar and lithic fragments. The sandstones comprise silt-to medium-grained lithic arkoses to feldspathic litharenites and litharenites, which have low porosity (0.5%–13.6%, with an average of 6.8%) and low permeability (0.009 × 10⁻³ μm² to 1.818 × 10⁻³ μm², with an average of 0.106 × 10⁻³ μm²).This study suggests that diagenetic facies identified from petrographic observations can be up-scaled by correlation with wire-line log responses, which can facilitate prediction of reservoir quality at a field-scale. Four diagenetic facies are determined based on petrographic features including intensity of compaction, cement types and amounts, and degree of dissolution. Unstable and labile components of sandstones can be identified by low bulk density and low gamma ray log values, and those sandstones show the highest reservoir quality. Tightly compacted sandstones/siltstones, which tend to have high gamma ray readings and relatively high bulk density values, show the poorest reservoir quality. A model based on principal component analysis (PCA) is built and show better prediction of diagenetic facies than biplots of well logs. The model is validated by blind testing log-predicted diagenetic facies against petrographic features from core samples of the Upper Triassic Yanchang Formation in the Ordos Basin, which indicates it is a helpful predictive model.     

Reservoir origin and characterization of gas pools in intrusive rocks of the Yingcheng Formation,Songliao Basin,NE China

In 2013, the first discovery of gas pools in well LS 208 in intrusive rocks of the Songliao Basin (SB), NE China was made in the 2nd member of the Yingcheng Formation in the Yingtai rift depression, proving that intrusive rocks of the SB have the potential for gas exploration. However, the mechanisms behind the origin of reservoirs in intrusive rocks need to be identified for effective gas exploration. The gas pool in intrusive rocks can be characterized as a low-abundance, high-temperature, normal-pressure, methane-rich, and lithologic pool based on integrated coring, logging, seismic, and oil test methods. The intrusive rocks show primary and secondary porosities, such as shrinkage fractures (SF), spongy pores (SP), secondary sieve pores (SSP), and tectonic fractures (TF). The reservoir is of the fracture–pore type with low porosity and permeability. A capillary pressure curve for mercury intrusion indicates small pore-throat size, negative skewness, medium–high displacement pressure, and middle–low mercury saturation. The development of fractures was found to be related to the quenching effects of emplacement and tectonic inversion during the middle–late Campanian. SP and SSP formed during two phases. The first phase occurred during emplacement of the intrusive rock in the late Albian, when the intrusions underwent alteration by organic acids. The second phase occurred between the early Cenomanian and middle Campanian, when the intrusions underwent alteration by carbonic acid. The SF formed prior to oil charging, the SSP + SP formed during oil charging, and the TF formed during the middle–late Campanian and promoted the distribution of gas pools throughout the reservoir. The intrusive rocks in the SB and the adjacent basins were emplaced in the mudstone and coal units, and have great potential for gas exploration.     

Kilometer-scale fault-related thermal anomalies in tight gas sandstones

Upper Carboniferous sandstones make one of the most important tight gas reservoirs in Central Europe. This study integrates a variety of geothermometers (chlorite thermometry, fluid inclusion microthermometry and vitrinite reflection measurements) to characterize a thermal anomaly in a reservoir outcrop analog (Piesberg quarry, Lower Saxony Basin), which is assumed responsible for high temperatures of circa 300 °C, deteriorating reservoir quality entirely. The tight gas siliciclastics were overprinted with temperatures approximately 90–120 °C higher compared to outcropping rocks of a similar stratigraphic position some 15 km to the west. The local temperature increase can be explained by circulating hydrothermal fluids along the fault damage zone of a large NNW-SSE striking fault with a displacement of up to 600 m in the east of the quarry, laterally heating up the entire exposed tight gas sandstones. The km-scale lateral extent of this fault-bound thermal anomaly is evidenced by vitrinite reflectance measurements of meta-anthracite coals (VR_rot ∼ 4.66) and the temperature-related diagenetic overprint. Data suggest that this thermal event and the associated highest coalification was reached prior to peak subsidence during Late Jurassic rifting (162 Ma) based on K-Ar dating of the <2 μm fraction of the tight gas sandstones. Associated stable isotope data from fluid inclusions, hosted in a first fracture filling quartz generation (T ∼ 250 °C) close to lithostatic fluid pressure (P ∼ 1000 bars), together with authigenic chlorite growth in mineralized extension fractures, demonstrate that coalification was not subject to significant changes during ongoing burial. This is further evidenced by the biaxial reflectance anisotropy of meta-anthracite coals. A second event of quartz vein formation occurred at lower temperatures (T ∼ 180 °C) and lower (hydrostatic) pressure conditions (P ∼ 400 bars) and can be related to basin inversion. This second quartz generation might be associated with a second event of illite growth and K-Ar ages of 96.5–106.7 Ma derived from the <0.2 μm fraction of the tight gas sandstones.This study demonstrates the exploration risk of fault-bound thermal anomalies by deteriorating entirely the reservoir quality of tight gas sandstones with respect to porosity and permeability due to the cementation with temperature-related authigenic cements. It documents that peak temperatures are not necessarily associated with peak subsidence. Consequently, these phenomena need to be considered in petroleum system models to avoid, for example, overestimates of burial depth and reservoir quality.     

New insights into the carbonate karstic fault system and reservoir formation in the Southern Tahe area of the Tarim Basin

As worldwide hydrocarbon exploration has extended from shallowly to deeply buried strata, reservoir quality has attracted substantial and persistent interest in petroleum geology. In particular, deeply buried strata (>5500 m) in the Tarim Basin have attracted considerable attention because carbonate reservoirs that have experienced fracture or dissolution have also been shown to demonstrate considerable hydrocarbon potential. Therefore, it is necessary to determine how these reservoirs are developed and distributed in detail from both scientific and practical standpoints.In this paper, we address this issue using a case study in the southern Tahe area, which is contained within the largest Palaeozoic marine oilfield in China. In the northern Tahe area, mega-paleokarst systems developed in the Ordovician strata; however, the reservoir quality in the southern part of the Tahe area is relatively poor because it is covered by insoluble formations during karstification. Observations of cores and analyses of images of well logging demonstrate that these reservoirs are dominated by caves, vugs and fractures that have developed near faults. We speculate that the faults penetrating insoluble formations represent the main dissolution passages that originally developed these karstic fault systems. Additionally, we analyse a series of outcrops, seismic data, and structures to characterize the spatial geometry of these major faults and their surrounding fractures in detail. Most of these are strike-slip faults, and their subsequent reservoirs can be divided into three categories based on their development, including dendritic, sandwich and slab reservoirs. Recent studies demonstrate that karstic fault reservoirs are most common traps in the study area. Although various types of carbonate karstic fault reservoirs are represented in this region, the dendritic karstic fault reservoir is the most hydrocarbon-rich.Guided by these initial results, 108 wells were drilled from 2013 to 2014, producing 485 thousand tons of oil and yielding success ratios greater than 89%. The average production of dendritic reservoirs is 37.4 tons per day (t/d), while those of sandwich and slab types are 20.2 t/d and 14.0 t/d, respectively. These results represent significant references for future hydrocarbon exploration and the development of similar deeply buried karstic fault reservoirs in the Tarim Basin and elsewhere.     

Complementing coal seam gas facies modelling workflows with decompaction based processes

Differential compaction plays a key role in influencing the palaeogeographic organisation of many depositional systems. In the Jurassic Walloon Subgroup, Surat Basin, Eastern Australia, the process of compensational stacking contributes significantly to the complex coal layer architecture and is documented in mine exposure, borehole and seismic datasets. Despite this understanding, current best-practices do not formally consider the mechanics of compensational stacking when populating palaeogeography facies in coal seam gas (CSG) reservoir models. To address this limitation, a hybrid modelling workflow was developed in which numerical rules representing the process of differential compaction are used explicitly to condition an iterative workflow containing traditional geostatistical facies modelling algorithms. The workflow is facilitated by a newly developed open source plugin which allows grid decompaction in Schlumberger PETREL™ 2015. Application of the workflow was tested in a CSG production area containing closely spaced wellbores and a 3D seismic survey. In this area, facies models were constructed using both traditional geostatistical approaches and the newly developed hybrid methodology. Comparison of these models suggests that facies models constructed via unconstrained geostatistical approaches often result in unrepresentative realisations, inconsistent with coal seam architectures as observed in seismic and outcrop. The hybrid geostatistical-forward modelling approach developed during this study was better able to reproduce complex alluvial stacking patterns, particularly with respect to coal seam amalgamation, bifurcation and washout.     

High-resolution sequence stratigraphy,sedimentology and reservoir quality evaluation of the Yaojia Formation in the Longxi area of the Western Slope,Songliao Basin,China

Delta-front sand bodies with large remaining hydrocarbon reserves are widespread in the Upper Cretaceous Yaojia Formation in the Longxi area of the Western Slope, Songliao Basin, China. High-resolution sequence stratigraphy and sedimentology are performed based on core observations, well logs, and seismic profile interpretations. An evaluation of the reservoir quality of the Yaojia Formation is critical for further petroleum exploration and development. The Yaojia Formation is interpreted as a third-order sequence, comprising a transgressive systems tract (TST) and a regressive systems tract (RST), which spans 4.5 Myr during the Late Cretaceous. Within this third-order sequence, nine fourth-order sequences (FS9–FS1) are recognized. The average duration of a fourth-order sequence is approximately 0.5 Myr. The TST (FS9–FS5) mostly comprises subaqueous distributary channel fills, mouth bars, and distal bars, which pass upward into shallow-lake facies of the TST top (FS5). The RST (FS4–FS1) mainly contains subaqueous distributary-channel and interdistributary-bay deposits. Based on thin-sections, X-ray diffraction (XRD), scanning electron microscope (SEM) and high-pressure mercury-intrusion (HPMI) analyses, a petrographic study is conducted to explore the impact of the sedimentary cyclicity and facies changes on reservoir quality. The Yaojia sandstones are mainly composed of lithic arkoses and feldspathic litharenites. The sandstone cements mostly include calcite, illite, chlorite, and secondary quartz, occurring as grain coating or filling pores. The Yaojia sandstones have average core plug porosity of 18.55% and permeability of 100.77 × 10⁻³ μm², which results from abundant intergranular pores and dissolved pores with good connectivity. Due to the relatively coarser sediments and abundant dissolved pores in the feldspars, the FS4–FS1 sandstones have better reservoir quality than the FS9–FS5 sandstones, developing relatively higher porosity and permeability, especially the FS1 and FS2 sandstones. The source–reservoir–cap-rock assemblages were formed with the adjoining semi-deep lake mudstones that were developed in the Nenjiang and Qingshankou Formations. This study reveals the deposition and distribution of the delta-front sand bodies of the Yaojia Formation within a sequence stratigraphic framework as well as the factors controlling the Yaojia sandstones reservoir quality. The research is of great significance for the further exploration of the Yaojia Formation in the Longxi area, as well as in other similar lacustrine contexts.     

The diagenetic history of Oligocene-Miocene sandstones of the Austrian north Alpine foreland basin

Diagenesis is an essential tool to reconstruct the development of reservoir rocks. Diagenetic processes - precipitation and dissolution - have an influence on pore space. The present paper aims to study the diagenetic history of deep-marine sandstones of the Austrian Alpine Foreland Basin. To reach that goal, sediment petrology and diagenetic features of more than 110 sandstone samples from water- and gas-bearing sections from gas fields within the Oligocene-Miocene Puchkirchen Group and Hall Formation has been investigated. Special emphasis was put on samples in the vicinity of the gas-water contact (GWC). The sediment petrography of sandstones of Puchkirchen Group and Hall Formation is similar; hence their diagenesis proceeded the same way. In fact, primary mineralogy was controlled by paleo-geography with increasing transport distance and diverse detrital input.Sediment petrographically, investigated sandstones from the water-bearing horizon seemed quite comparable to the gas-bearing sediments. In general, they can be classified as feldspatic litharenites to litharenites and display porosities of up to 30% and permeabilities of up to 1300 mD. The carbon and oxygen isotopic composition of bulk carbonate cements from these sandstones range from−3.8 to +2.2 and from −7.5 to +0.2‰ [VPDB]. However, near the Gas-Water Contact (GWC) a horizon with low porosities (<3%) and permeabilities (<0.1 mD) is present. This zone is completely cemented with calcite, which has a blocky/homogenous morphology. A slight, but significant negative shift in δ18O isotopy (−2.5‰) is evident.During early diagenesis the first carbonate generations formed. First a fibrous calcite and afterwards a micritic calcite precipitated. Further siliciclastic minerals, such as quartz and feldspar (K-feldspar and minor plagioclase), exhibit corroded grains. Occasionally, clay minerals (illite; smectite, chlorite) formed as rims around detrital grains. Late diagenesis is indicated by the formation of a low permeable zone at the GWC.