Diagenetic Controls Research Articles

Influence of reservoir oil charging on diagenesis and reservoir quality: An example from Dunlin Reservoir Sandstones, East Shetland Basin, North Sea, UK

The sandstone facies from two reservoir blocks (extensional fault walls) of the Dunlin Field have been studied to evaluate the impact of the reservoir charge history on the diagenesis and reservoir quality of these sandstones. The study has identified seven main reservoir sandstone facies (D1–D7) from the reservoir crestal block (oil leg) to the flank block (water leg). These sandstone facies exhibited similar diagenetic patterns, controlled by their depositional parameters, hence having the same porosity and permeability values in both reservoir blocks (legs) until hydrocarbon charging in the Late Cretaceous‐Pliocene. The burial and thermal model indicates that these reservoirs were charged at a temperature of 60–75°C during the 80–50 Ma and 95–100°C during the 10 Ma to Present, and significantly controlled the mesodiagenetic output, notably illite, and quartz authigenesis. The reservoir oil leg recorded a higher amount of recovered bitumen (ca. 95%) than the water leg (ca. 5%), indicating that hydrocarbon charging of the sandstone reservoir was progressive rather than instantaneous, first filling the water leg (palaeo‐oil leg). Subsequent leak‐off depleted this reservoir block and remigrated to fill the reservoir leg (palaeo‐water). The fluctuating oil charging and leakage between these two reservoir fault blocks modulated diagenetic alteration of these reservoir sandstones; hence is the cause of the minor disparity in porosity values between these reservoir legs contrary to the wide variation between conventional reservoir oil‐ and water‐legs distinguished by hydrocarbon emplacement with no such complex history. This study, therefore, demonstrates the importance of evaluating the depositional and diagenetic controls on reservoir quality and charging of hydrocarbon‐bearing sandstones for optimum oil production and recovery in clastic depositional settings.

REE + Y signatures of the Navay phosphate deposit, SW Venezuela: Seawater paleoredox conditions and diagenetic implications

Phosphate rock occurrences in western Venezuela are well-known in Cretaceous sedimentary sequences, which are associated to the Caribbean-Tethyan passive margin, along an SW-trend belt of the Venezuelan Andes chain. In this study, the geochemical characteristics of the Navay phosphate deposit were investigated to discuss the ocean paleo-oceanographic conditions and diagenetic controls that prevailed during the deposit formation. The rare earth elements plus yttrium (REY) concentrations were determined and normalized with the Post-Archean Australian Shale (PAAS) values to generate the REY patterns. Our results reveal a typical seawater signature, except for the absence of a marked negative Ce* anomaly (Ce/Ce* = 0.76–1.00). The determined seawater REY patterns, along to the calculated ratios for (La/Sm)N = 0.78–1.00, and (La/Yb)N = 0.34–0.66, are similar to the modern oceanic water ratios. These data point to a lack of diagenetic alteration on the primary REY signatures, which corresponds with a terrigenous-free marine sediment source for the REY content present in the deposit. In brief: i) the slightly negative anomalies displayed by the Ce* and Eu*, accompanied by the Mn depletion, ii) a relative enrichment of some transition metal elements (V, Cr, and Cu), and iii) the low Mo/U ratios, are all of them considered as geochemical indicators of suboxic to anoxic conditions, which were predominated during the phosphogenetic processes of the deposit. Furthermore, our data reveals an economic potential of the phosphorites as a raw material to produce phosphoric acid (H3PO4) as well as a source of supply for rare earth elements, by means of: i) relative high grades of P2O5 (15.46–30.09 wt %), ii) low CaO/P2O5 ratios (1.22–1.28), iii) a lack of organic matter, chert or chalcedony, iv) a low content of Mg (0.07–0.22%), v) REE concentrations varying from 141.82 to 256.53 μg/g, with an average value of 208.14 μg/g; and vi) concentrations for toxic elements (i.e., V, Cr, Co, Ni, Cu, Zn, As, Sr, Pb, and U) below or at the acceptable levels, in comparison to commercial phosphorites worldwide.

Using core to reduce risk and deliver added business value throughout field life: a carbonate reservoir focus

Abstract The role of the subsurface team is to reduce technical risk and uncertainty associated with profile delivery, for both hydrocarbon production and the injection of water or gases, enabling confident reservoir management and investment decisions. Core is a key resource for delivering this objective, providing the only opportunity to directly observe and measure the reservoir rock. However, it is expensive to acquire and the decision to take new core should be clearly linked to a business objective. A combination of depositional and diagenetic factors can result in carbonate reservoirs being highly heterogeneous, making them a challenge to find and develop. Core studies can significantly improve understanding of the controls on heterogeneity and its distribution within the subsurface, but to maximize value, they should be fully integrated with wireline logs, seismic and production or test data to predict likely reservoir behaviour. For example, thin (<1 m) high or low permeability zones can dominate production yet remain very subtle or undetectable in wireline log or seismic data alone. During exploration and appraisal, sufficient data and knowledge are required to enable appraise/develop or walk-away decisions. Appropriate geological description of core material helps to establish original volumes in place, net-to-gross, depositional setting, age, reservoir architecture and large-scale flow zones. Core material can also help establish other key reservoir parameters such as saturation, reservoir fluids, seismic rock properties and geomechanical properties as well as influence decisions such as well design, development strategy and facility requirements. As a field is developed and production matures, reservoir behaviour may change and detail of the sedimentology, structure, diagenesis, baffles and thin heterolithic permeability zones may become more important. In carbonate reservoirs, this often requires the integration of existing legacy core or new core material and targeted surveillance data, such as injection and production logging tool (ILT/PLT) or saturation logs, to understand the stratigraphic, depositional and diagenetic controls on flow units and improve predictive capability. Moving a reservoir from natural depletion onto waterflood or enhanced oil recovery (EOR) may need more advanced core-based data from core flood experiments to deliver maximum value from the reservoir. New core material, or detailed review and new sampling of existing or analogue legacy core, may be required to understand complex rock–fluid interactions and the value that waterflood or EOR could bring to a development. To maximize the value and insights gained from core, it is essential to use it throughout a field's life. High quality description and a well-considered sampling regime should be carried out at the earliest opportunity to provide baseline data. However, periodically revisiting the core enables the entire subsurface team to keep testing hypotheses and refreshing models. Where there is no core material available in the field, analogue field core can be especially useful both to narrow uncertainty and explore possible alternative models. A multi-disciplinary approach integrating new data with core observations helps refine and improve predictions and can lead to the identification of significant additional opportunities as reservoir behaviour matures and field development progresses.

Depositional and diagenetic controls on reservoir properties along the shallow-marine carbonates of the Sarvak Formation, Zagros Basin: Petrographic, petrophysical, and geochemical evidence

As the second important oil reservoir of Iran, shallow-marine carbonates of the Sarvak Formation were deposited in a tectonically active setting, under a warm and humid paleoclimatic condition. This study focuses on sedimentological, geochemical, and petrophysical analysis of this formation in the Abadan Plain, Zagros Basin. Petrographic studies have resulted in the recognition of five microfacies deposited in lagoon, patch-reefs and their taluses, shoal, and open marine environments. They represent a ramp-like depositional model for the Sarvak Formation. Two third-order depositional sequences are differentiated and dated as Cenomanian–Turonian, according to the results of biostratigraphic analysis. Effects of intensive meteoric diagenesis are recorded beneath the two paleoexposure surfaces (Cenomanian–Turonian boundary, and middle Turonian). They include pervasive dissolution (karstification), collapsed brecciation, silicification, recrystallization, and development of paleosols. Additionally, decreased values of δ18Ocarb and δ13Ccarb and a sharp inverted-J pattern in the δ18Ocarb vs. δ13Ccarb cross plot indicate major meteoric phases. The most decreased values of δ18Ocarb (−7 ‰) and δ13Ccarb (−8.6 ‰) are measured from the meteoric cements and paleosols. Reservoir quality evaluation revealed that the best reservoir zones of the Sarvak Formation are developed within the rudist-dominated facies with intensive meteoric dissolution. They are concentrated within the regressive systems tract of the Cenomanian sequence. Fractured and dolomitized mud-dominated facies provided the speed/baffle zones in transgressive systems tracts, and highly compacted/cemented facies formed the barrier units. It could be concluded that the facies characteristics and meteoric diagenetic processes had major controls on reservoir quality of the Sarvak Formation, in the Abadan Plain. These controlling factors are predictable in a high-resolution sequence stratigraphic framework.

Depositional and diagenetic controls over reservoir quality of tight sandstone and conglomerate in the lower Cretaceous Shahezi formation, Xujiaweizi fault depression, Songliao basin, China

The distribution of high-quality reservoirs restricts the exploration and development of tight gas in the Shahezi Formation in the Xujiaweizi Fault Depression, but the complex sedimentary composition and abundant diagenesis make it difficult to determine which rocks are high-quality reservoirs. In this paper, the petrological, mineralogical, and pore structure characteristics of sandstone and conglomerate were investigated to elucidate how depositional and diagenetic processes jointly control reservoir quality and identify favorable sequences in which high-quality reservoirs are distributed. The results showed that the content and type of matrix and lithic clasts in the sedimentary rock unit controlled the effects of the following diagenetic sequence, which in turn controlled the reservoir porosity, permeability and pore size distribution. Conglomerate and coarse-to medium-grained sandstone, both with a low muddy matrix content and high intermediate–basic volcanic lithic clast content, underwent extensive dissolution or grain fracturing during diagenesis, resulting in a reservoir with pore spaces >0.1 μm in diameter, which is considered as a high-quality reservoir for tight gas exploration. Conglomerate and fine-grained silty sandstone, both with a high muddy matrix content and low intermediate–basic volcanic lithic clasts, or those reservoir units directly adjacent to mudstone often experienced severe mechanical compaction or cementation during diagenesis. This resulted in a reservoir dominated by micropores (<0.1 μm) and therefore formed nonreservoir areas for tight gas exploration. High-quality reservoirs are more likely to be developed in the lacustrine transgressive systems tract and regressive systems tract in sequence four of the Shahezi Formation in the Xujiaweizi Fault Depression.

Stable Barium Isotope Fractionation in Pore Waters of Estuarine Sediments

AbstractThe development of stable barium (Ba) isotope measurements provides a novel tool to investigate the geochemical cycling of Ba in the ocean and its sediments. In sediment pore waters, gradients of dissolved Ba concentrations result from various diagenetic processes. The distribution and fractionation of Ba isotopes in the pore waters are expected to further improve our understanding of these early diagenetic control mechanisms. Here, we present pore water profiles of dissolved stable Ba isotopic signatures (δ138Bapw) from shallow water sediments covering the entire Pearl River Estuary (PRE) in Southern China. We find pronounced depth‐dependent Ba isotope variations generally showing a shift from heavy to light δ138Bapw signatures from the sediment surface down to 15 cm depth. These gradients are well reproduced by a diffusion‐reaction model, which generates an apparent fractionation factor (138ε) of −0.60 ± 0.10‰ pointing to preferential removal of low‐mass Ba isotopes from the pore water during solution‐solid phase interactions. Consequently, the combined diagenetic processes induce the highest δ138Bapw values of +0.5 to +0.7‰ in the pore waters of the topmost sediment layer. Although the detrital fraction dominates the Ba content in the PRE surface sediments, the determined gradients of pore water Ba isotopes, together with concentration variations of Ba and other redox‐sensitive elements such as manganese (Mn), show that non‐detrital excess Ba carriers including Mn oxides and authigenic barite clearly affect the post‐depositional Ba dynamics. Stable Ba isotopes are thus a potentially powerful tracer of Ba geochemistry during early sediment diagenesis in estuarine depositional environments.

Role of depositional and diagenetic controls on reservoir quality of complex heterogenous tidal sandstone reservoirs: An example from the Lower Goru formation, Middle Indus Basin, Southwest Pakistan

The Lower Goru Formation, one of the key hydrocarbon development targets in Pakistan's Middle Indus Basin, offers a unique opportunity to investigate the role of depositional and diagenetic controls on reservoir quality in complex stratigraphic traps. An integrated approach, including thin-section petrography, scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS), helium porosity, and permeability measurements, was used to analyze the Lower Goru Formation in three gas-producing fields. Based on petrographic interpretation, the sandstones are quartzarenite, sublitharenite, subarkose, and less commonly, litharenite. High permeability and high porosity reservoirs are associated with well-sorted and medium-grained sandstones. Main diagenetic processes include compaction, carbonate cementation, authigenic chlorite and quartz overgrowth. Authigenic chlorite, and quartz cementation were the principal reservoir quality controlling factors. Well-developed chlorite coatings preserved porosity and inhibited quartz cementation. Good quality reservoirs (average porosity: 17%; average permeability: 96 mD) are restricted to tidal channels and tidal inlet in the prograding shoreface environments. Transgressive and tidally reworked deposits show moderate porosity and very low permeability (average porosity: 9.5%; average permeability: 0.07 mD). Middle shoreface and bioturbated storm sands have low porosity and very low permeability (average porosity: 8.7%; average permeability: 0.9 mD) and are considered tight reservoirs. The quality of the studied reservoirs depends on quartz overgrowth, chlorite coating, carbonate cementation and minor detrital clay. Secondary porosity is associated with partial to complete dissolution of feldspar, volcanic rock fragments (VRF), biotite, chamosite ooids, and bioclast grains. This integrated work would be helpful for exploration and field development plans in the stratigraphic traps of the Middle Indus Basin and would lead to new exploration targets, i.e., tight and low permeability reservoirs. The study provides insight into the complex interplay between depositional facies and diagenesis in controlling reservoir quality in the Lower Goru Formation and similar depositional conditions and trapping mechanisms elsewhere.

Diagenetic controls on pore structure variations in fan deltaic sandstones of the Eocene Shahejie Formation, Bohai Bay Basin, China: Implications for reservoir quality and oiliness heterogeneities

The fan deltaic sandstones in the third section of the third member of the Eocene Shahejie Formation (Es33) are important hydrocarbon exploration targets in the northern Nanpu sag, Bohai Bay Basin, China. The Es33 sandstones are characterized by highly variable pore structures. A total of 364 Es33 sandstone samples were measured by a series of petrological and petrophysical analyzes to investigate these variations and their controls on reservoir quality and oiliness heterogeneities. The heterogeneity of Es33 sandstone can be manifested by type I, type II and type III pore structures. Primary intergranular pores and dissolution pores were the main storage spaces for type I sandstones, while dissolution pores and intercrystalline pores were the main storage spaces for type II and type III sandstones, respectively. These results indicate that compaction is the main factor in the loss of primary intergranular porosity, with an average loss of 78%. The grain size controlled the preservation of primary pores in Es33 sandstones with a carbonate cement content of less than 6%. The different types of clay minerals have various effects on the pore structure. Chlorite plays an active role in the preservation of intergranular pores and the improvement of reservoir quality, while mixed layers of illite and smectite greatly reduced the pore size and connectivity and lowered the reservoir quality. The Es33 sandstones have undergone a more open diagenetic system. Dissolution significantly increased the porosity of type I and type II sandstones with more primary intergranular pores, but exerted a minor role in contributing to the permeability. Furthermore, a pore‐throat radius of approximately 0.4 μm is considered to be the threshold for oil accumulation in Es33 fan deltaic sandstones.

Spatial variability of petrofacies using supervised machine learning and geostatistical modeling: Sycamore Formation, Sho-Vel-Tum Field, Oklahoma, USA

The Sycamore Formation at the Sho-Vel-Tum Field primarily consists of clay-rich mudstones (Mdst) and quartz-rich siltstones. The clay-rich Mdst are mainly composed of clays, quartz grains, some allochems, and detrital organic matter. The siltstones are structureless and are divided into two petrofacies: high porosity and permeability massive calcareous siltstones and low porosity and permeability massive calcite-cemented siltstones. Core and well-log data provide mineralogical, lithologic, and porosity information that is useful to define petrophysical facies (petrofacies) and to create facies logs within the Sycamore Formation. We used the data to establish the Sycamore Formation stratigraphic architecture and to map its spatial variability and reservoir properties. To classify the Sycamore Formation petrofacies in noncored wells, we developed a machine learning-based workflow that compares more than 1800 classification models and selects the best combination of well logs, algorithms, and hyperparameters to predict defined petrofacies. The process includes combinations of well logs that were optimized in four classification algorithms: artificial neural network, K-nearest neighbor, support vector machine, and random forest. To adjust each classifier, we used a grid search and a fivefold cross validation to find the best combination of three hyperparameters to improve results of each algorithm. This workflow allows for the efficient extraction of information from cores at a low cost. After we generated the petrofacies logs in noncored wells, we combined them with multiple constraints to create a 3D petrofacies model for the Sycamore Formation at the Sho-Vel-Tum Field and analyze the stratigraphic and diagenetic controls on petrofacies and its impact in reservoir quality.

Depositional and diagenetic controls on the evolution of abnormally high porosity in braided river deltaic sandstones (Oligocene), Xihu Depression, East China Sea

Abnormally high porosity (AHP) was observed at the depth interval of ∼3650–3900 m in the Oligocene Huagang Formation braided river deltaic sandstones from the Xihu Depression, East China Sea Shelf Basin. The AHP is ∼1.35–1.95 times (median values) higher than the background normal porosity (NP). In this work, 136.8 m consecutive core samples located within the AHP zone were collected. We used sedimentary facies interpretation, helium porosity/permeability, thin section petrography, scanning electron microscopy, X-ray diffraction, laser grain size and fluid inclusions to discuss the potential influences of depositional environment and diagenesis on AHP evolution, which can be simplified into three steps. In step (1) (pre-dissolution), greater depositional porosity, and/or weaker cementation, and/or weaker compaction result in greater porosity preservation before entering the dissolution window. One AHP sample has already exhibited a higher porosity than NP samples at this step. In step (2) (dissolution window), greater porosity before entering the dissolution window dominantly results in stronger grain dissolution. Meanwhile, chlorite coats inhibit the growth of quartz overgrowths and therefore enlarge the net porosity increase through grain dissolution. As a result, the porosity gap between AHP and NP samples is further widened. In step (3) (post-dissolution), post-dissolution cements exert negligible influences on the further growth or decline in the porosity gap. Therefore, we proposed eight possible AHP evolution paths. This work may serve as a reference for discussing the evolution of AHP in analogous geological settings.

Storm-driven variations in depositional environments modify pyrite sulfur isotope records

The sulfur isotopic composition of marine pyrite (δ34Spyr) is one of the major geochemical tools to reconstruct global changes in Earth's surface environment. Storm-driven variations in depositional environments, however, can play key roles in modifying the δ34Spyr signal. Here we present δ34Spyr values in a complete Holocene muddy storm deposit on the East China coastal plain, which is identified by comprehensive analyses of sediment components, organic matter composition, bulk organic carbon isotopic ratios, carbon and oxygen isotopic ratios of carbonates and trace element concentrations. We find that positive (+5.8‰ to +15.8‰) and negative (−9.0‰ to −19.7‰) δ34Spyr values were preserved in two successive intervals of the muddy storm deposit (ca. 62 cm long), corresponding to the high-energy storm peak phase (HESPP) and the waning-energy late storm phase (WELSP), respectively. We propose that the 34S enrichment in pyrite from the HESPP is most likely due to a combination of storm reworking of sediments and high sedimentation rates, which involves various physical and chemical processes leading to the accumulation of 34S-enriched pyrite, such as oxidation of near-surface sulfides, reduced exchange of sulfate between sediment pore fluids and the overlying water column, and/or input of excess reactive iron minerals. In contrast, lower sedimentation rates and limited sedimentary remobilization during the WELSP allow the isotopic signal of early-formed 32S-enriched pyrite to be preserved. The striking shift in δ34Spyr values, therefore, reflects a dramatic change in the local depositional environment between the HESPP and WELSP, suggesting that non-steady-state deposition induced by storm activity facilitates the formation of isotopically “heavy” pyrite. This sharp shift can be further generalized as a characteristic feature of δ34Spyr values in storm deposits. Our work highlights the critical impact of weather- and climate-event-driven depositional variations on δ34Spyr values, adding to the growing evidence emphasizing the local environmental and diagenetic controls on these records.

Controls on the formation and evolution of multimodal pore network in lower cretaceous limestone reservoir, Abu Dhabi, United Arab Emirates

Petrographic and petrophysical analyses of a Lower Cretaceous limestone reservoir, Abu Dhabi, United Arab Emirates provide new insights into the formation and diagenetic evolution of bimodal pore network. The most important diagenetic controls include: (i) widespread development of microporosity by micritization of allochems and partial cementation by grain-rimming calcite during eogenesis at or below the seafloor, (ii) partial to complete dissolution of peloids and concomitant precipitation of equant calcite cement during early mesogenesis, and (iii) stylolitization and development of tension gashes and concomitant massive cementation of the macropores by coarse-crystalline calcite and partial cementation of the micropores by calcite micro-overgrowths around micrite during late mesogenesis. Lateral compression owing to ophiolite obduction in late Cretaceous allowed flow of hot basinal brines along stylolites and tension gashes, which resulted in the precipitation of saddle dolomite and pyrite. Abundant depositional interparticle macropores were preserved in the grainstones by sparse grain rimming, dogtooth-like calcite cement that reduced the effect of mechanical compaction. Micro- and macropores are well interconnected yet the moldic, fracture pores, and intraparticle micropores within peloids are less well connected with the pore system. Hydrocarbon emplacement in the naturally oil/mixed-wet carbonate reservoir both increases the fluid pore pressure within the pore spaces of the rock thus reducing overburden stress and effective compaction; and reduces nucleation sites for cement growth thus retarding chemical diagenesis. However, the hydrocarbon emplacement occurred gradually and selectively filled the crestal limestones from the top to bottom in a way that its effect on rate of diagenesis differ vertically and spatially across the study area. Constraining the formation, evolution, and distribution of multimodal porosity network, including abundant micropores and mesopores allows better detection and evaluation of low-resistivity pay zones in carbonate successions.

Depositional and Diagenetic Controls on Reservoir Quality of Neogene Surma Group from Srikail Gas Field, Bengal Basin, Bangladesh

The development of an effective and profitable exploration and production depends heavily on the quality of the reservoir. The primary goal of this study was to evaluate the reservoir quality of the Neogene Surma Group at the Srikail Gas Field, which is situated in the western part of the eastern folded belt of the Bengal Basin, Bangladesh. Wire-line logs, core analysis, petrography, X-Ray diffraction (XRD) and a scanning electron microscope (SEM) were used to understand the depositional and diagenetic controls of the quality of the reservoir. The Surma Group of the Srikail Gas Field was deposited in a delta system with a dominant influence of tide. The subarkosic to sublitharenitic Neogene Surma Group sandstones have primary porosities ranging from 0% to 25.8%, with an average of 21.5%, and the secondary porosity is approximately 7%. The range of log porosity ranges from 15% to 22.2%, while log permeability and core permeability vary from 3.01 to 54.09 mD and 0.1 to 76 mD, respectively. The primary porosity had been destroyed mainly by mechanical and ductile grain compaction. Most of the clay minerals (illite/illite-smectite, chlorite and kaolinite) in sandstone occur as grain coatings, grain lining (rim) and a few occur as pore-filling. This study reveals that the reservoir quality is predominantly controlled by the depositional environment (sediment texture and facies, ductile grain supply, clay content), and diagenetic process (mainly mechanical and ductile grain compaction followed by clay cement). The information gathered from this research will be useful for future petroleum production and for enhancing predictability in order to find new prospects.

Depositional and diagenetic controls on porosity evolution in sandstone reservoirs of the Stuttgart Formation (North German Basin)

The Mesozoic succession of the North German Basin comprises permeable sandstones operated by ‘conventional’ open doublet systems for geothermal heat production. The high permeability, exceeding 6 Darcy at individual localities, is the result of undercompacted grain fabrics, low abundance of authigenic minerals and large secondary porosity volumes. The discrepancy of undercompacted grain fabrics and porosity volumes of >20% at depth of up to 2500 m gave rise to a basin-scale study, in which classical petrographic methods were employed to reconstruct the diagenesis of sandstones on the example of the Stuttgart Formation (Schilfsandstein, Late Triassic). Associated to the deposition of sandstones in distinct fluvio-deltaic environments, four diagenetic pathways are indicated by systematic variations of detrital and authigenic assemblages. These four pathways are herein introduced as Delta Channel, Delta Plain, Fluvial Channel, and Floodplain Diagenesis Types. In response to the history of the North German Basin, high permeabilities of sandstones of the Delta Channel and Fluvial Channel Diagenesis Types are related to the subsequent control of depositional and diagenetic regimes on porosity evolution. Pervasive eogenetic calcite cementations contributed to preservation of pre-burial intergranular volumes and effectively prevented the mechanical compaction of grain fabrics during late Triassic–late Jurassic burial diagenesis. The uplift from deep to shallow burial depth, associated to latest Jurassic–Cenozoic structural differentiation and inversion of the North German Basin, triggered substantial dissolution processes that mainly affected carbonate cementations. This opened pores and contributed to the evolution of secondary porosity, in particular in sandstones of the Delta Channel and Fluvial Channel Diagenesis Types. Moderate post-inversion reburial rates resulted only in negligible mechanical compaction and reduction of secondary porosity. The improved knowledge of diagenetic pathways, herein exemplified by sandstones of the Stuttgart Formation, will significantly contribute to improved predictions of Mesozoic hydrothermal reservoir in the North German Basin.

Impact of depositional and diagenetic controls on reservoir quality of syn-rift sedimentary systems: An example from Oligocene-Miocene Al Wajh Formation, northwest Saudi Arabia

Tertiary, syn-rift clastic reservoirs offer a unique opportunity to investigate the pivotal role of depositional and early diagenetic controls on reservoir quality. The Al Wajh Formation is a vital exploration target for petroleum in the Red Sea, and is characterized by early, near-surface diagenetic signatures. An integrated petrographic-mineralogical study is conducted to assess the role of depositional factors (e.g., sand grain size and clay matrix) and early diagenetic overprints on reservoir quality. The Al Wajh sandstones are primarily subarkose and lithic arkose, deposited in alluvial fan, braided fluvial, and nearshore environments. Braided fluvial sandstones of the formation have the best quality reservoirs (average porosity: 23.2 %; average permeability: 3025 mD) because of medium to coarse grain size and small proportion of clay matrix, whereas the nearshore sandstones form reservoirs of far lower quality (average porosity: 12.6 %; average permeability: 486 mD) owing to predominantly finer grain size and higher proportion of clay matrix. Clay volume between 10 and 20 % generally reduces the reservoir properties to <10 % porosity and 100 mD permeability. Compaction and grain dissolution are the major near-surface, early diagenetic processes that have strongly affected the sandstones reservoir quality. High mechanical compaction has been recorded in sandstones characterized by abundant matrix content and ductile rock fragments. Dissolution of labile grains (e.g., feldspars) has created secondary, intragranular porosity of up to 13.5 % (average 4.7 %). Kaolinite is the primary authigenic pore-filling clay in the continental units of the formation, whereas detrital and authigenic smectites are the key pore-filling clays in the nearshore units of the formation. Grain-coating smectite (up to 18.7 %; average: 7.1 %) was mainly emplaced through mechanical infiltration and has the potential for inhibiting quartz cementation should deep burial occur. The findings of the study can be utilized for modelling reservoir quality in the subsurface analogue of the Al Wajh Formation in the Red Sea or elsewhere, thereby improving reservoir quality prediction.

Lithofacies and Diagenetic Controls on Tight Silty and Sandy Upper Triassic Reservoirs of the Heshui Oil Field (Ordos Basin, North China)

Summary Tight oil, present in reservoirs of low porosity and permeability, can be regarded as a kind of unconventional resource. The tightening process in this kind of reservoir is controlled by the lithology and diagenetic history of the host formation. Upper Triassic Yanchang Formation siltstones and sandstones are the main reservoirs for hydrocarbon accumulation in the Heshui Oil Field (HOF), southwestern Ordos Basin. The reservoirs exhibit low porosity, low permeability, and strong heterogeneity. In recent years, numerous drillcores have been recovered from these units, but the porosity-permeability characteristics and burial history of these silty and sandy reservoirs have not yet been reported in detail. In this study, an integrated analysis of the lithofacies, diagenesis, and reservoir characteristics of the siltstones and sandstones was achieved using a combination of core and thin section, grain size, scanning electron microscopy (SEM), X-ray diffraction (XRD), δ13C and δ18O, mercury intrusion capillary pressure (MICP), and porosity and permeability data. Our primary goals were to quantify the porosity-permeability characteristics of these silty and sandy reservoirs, restore their diagenetic histories, and examine the paragenetic relationship of reservoir tightness to hydrocarbon accumulation. The silty and sandy reservoirs represent braided river delta facies consisting of compositionally and texturally immature sediments. In the burial environment, they underwent complex diagenetic processes that reduced porosity from an initial average of ~38% to the present ~8%. Porosity-destructive processes included compaction (~ –12.5%) and cementation (~ –21%), with increases in porosity related to grain dissolution (~ +2.2%) and tectonic fractures (~ +1.1%). The reservoirs underwent four diagenetic stages: (1) Penesyngenetic and Eogenetic A Stage (Late Triassic-Early Jurassic); (2) Eogenetic B Stage (Late Jurassic); (3) Early Mesogenetic A Stage (Early Cretaceous); and (4) Late Mesogenetic A Stage (Late Cretaceous to recent). Hydrocarbon charging of these reservoirs occurred in three pulses. Existing pore space was partly filled by hydrocarbons during the Eogenetic B Stage. A second hydrocarbon charging event occurred during the Early Mesogenetic A Stage, when residual primary intergranular pores and secondary dissolution pores were filled. A third hydrocarbon charging event occurred during the Late Mesogenetic A Stage, when the reservoirs were tight. Siltstone beds deposited in delta front environments are the main future exploration targets in the Chang 6 to 8 members. The results of this study provide a useful reference framework for future exploration of hydrocarbon resources in the Upper Triassic Yanchang Formation of the HOF, as well as potential insights into the evolution of similarly tight reservoirs in other basins.

Impact of meteoric water flushing on diagenesis of deep-marine turbidite sandstones: A case study from the Tertiary sandstones of Frigg and Grane fields, northern North sea

Meteoric water flushing into deep-marine environments is a topic of debate since the actual transport mechanism remains elusive. In order to evaluate the potential impact of meteoric water on early diagenesis of deep-marine sandstones, two submarine fan sandstone reservoirs, the Eocene Frigg (Frigg oilfield) and the Palaeocene Heimdal (Grane field) that have the same source area, were compared and contrasted. Petrographic studies reveal that both sandstone reservoirs are at the eodiagenesis stage (<70 °C) at the present day. However, the Eocene Frigg sandstones are characterized by geological features suggestive of potential meteoric water diagenesis, such as dissolution and kaolinization of the silicate grains, whereas the Palaeocene Heimdal sandstones show negligible alteration. The δ13CV-PDB and δ18OV-PDB values of siderites in the Eocene Frigg sandstones range from +5.2‰ to +16.7‰, and from −8.2‰ to −6.6‰, respectively, indicating siderite formation during methanogenesis in meteoric pore water. Results from generic hydrogeochemical modelling scenarios lend further support to the hypothesis of meteoric water flushing. Thus, we suggest that massive meteoric water might have been brought into the Frigg turbidite sands by basinward migration of the meteoric water. This occurred because the East Shetland Platform experienced two stages of relative sea-level fall (during and at the end of the Eocene, Priabonian), and flushing might have taken place via connected incised canyons. The location of the Frigg sands deposited immediately below the Shetland escarpment and the narrow palaeo-shelf area may have facilitated such meteoric water incursions. Our study suggests meteoric water intrusions as a possible diagenetic control of deep-marine sandstones, and, therefore, meteoric water diagenesis should be considered in the prediction of properties of deep-marine sandstone reservoirs.

Depositional and diagenetic controls on sandstone compactional fabrics in an Andean broken foreland basin, the Miocene Vinchina formation, northwestern Argentina

The very thick (up to 6000 m thick) Miocene Vinchina Formation was deposited between 16 and 8 Ma ago and later covered by more than 2500 m of Pliocene-Pleistocene sediments in a broken foreland basin. The very thick sedimentary pile accumulated in a medium to low-gradient basin must have suffered intense mechanical compaction during burial.Seventy thin sections of unaltered sandstones collected in three sections along the depositional strike of the Vinchina Formation at the Sierra de Los Colorados, La Rioja Province, northwestern Argentina, were analyzed under the microscope for determining compactional paths and controls.The role of compaction in sandstone diagenesis was firstly assessed using the change in intergranular volume (IGV), which is the sum of all cement and remaining primary porosity. It is clear from the IGV analysis that most of the studied sandstones lose more porosity by compaction (COPL) than by cementation (CEPL). In general compaction increased from the upper to the lower member of the Vinchina Formation (i.e with depth) and there is a clear trend of the compaction index ICOMPACT increase from the northern, shorter Los Pozuelos to the central, thicker La Troya sections. Surprisingly, the thickest southern El Yeso section shows anomalous results possibly due to the extensive development of cements as indicated by the highest CEPL values. Cements are related to the depositional environment (gypsum, calcite) and clast composition (zeolites). Early cements may have prevented further compaction while late cements may have produced open fabrics by dissolution of matrix and framework clasts. Both cases show that diagenetic processes are not homogeneous basin-wide and that the diagenetic pathways are not only controlled by the increase in burial depth but also by characteristics associated with depositional environments and framework clast composition.We also attempted to relate compaction to burial depth based on the nature (point, long, concave-convex and sutured contacts) and the number (contact and packing indexes) of grain-to-grain contacts in the studied sandstones. The sandstones present predominance of concave-convex grain-to-grain contacts and IC indexes mostly between 3 and 4. Sutured contacts are uncommon, and stylolites were not observed at all. Persistence of open fabrics, floating textures and point grain-to-grain contacts at different depths are the result of dissolution-cementation processes. A clear trend of increasing mechanical compaction with depth is only seen along the northern coarser-grained but thinner Los Pozuelos section. Although compaction seems to have increased with depth and also from north to south, the thickest but overall finer-grained El Yeso (southern) section do not show a clear pattern of change with depth. This behavior seems to be the result of at least four main factors: 1) mean sandstone grain-size, 2) thickness of muddy intervals, 3) development of early diagenetic cements, and 4) depth of burial.Comparison with comparable examples suggests that similar compactional characteristics are achieved between 3.5 and 6 km of maximum burial depths. However, cumulative thickness of the Vinchina basin-fill indicate that the base of the Vinchina Formation may have been buried at 8.5 km deep but preliminary backstripping models suggest that by 5 Ma this surface may have reached up to 10 km depth. Alternatively, recorded repetitive episodes of deformation, uplift, and erosion (progressive unconformities) in the Vinchina basin may have prevented the sedimentary pile to be deeply buried and therefore allow to reconcile the observed compactional textures with depth of burial.The results obtained in this work show that the analysis of mechanical compaction in sandstones constitutes a complex task and in occasions there is not a linear relationship between the contact indexes and depth of burial. Sandstone compaction is controlled not only by the depth of burial but also by other factors such as, time, geothermal flow, matrix content, the development of early cements, the ratio between ductile and rigid lithic fragments and, in tectonically active basins the development of progressive unconformities. Therefore, in most cases, it is very speculative to extend diagenetic conditions to basin-wide scales. In particular, the porosity-depth relationship must be based on primary porosity only.

Sedimentary and Diagenetic Controls across the Cretaceous—Paleogene Transition: New Paleoenvironmental Insights of the External Ionian Zone from the Pelagic Carbonates of the Gardiki Section (Epirus, Western Greece)

Field investigation, biostratigraphic, paleoecological, and sedimentary microfacies analyses, as well as diagenetic processes characterization, were carried out in the Epirus region (Western Ionian Basin) to define the depositional environments and further decipher the diagenetic history of the Late Cretaceous–Early Paleocene carbonate succession in western continental Greece. Planktonic foraminiferal biostratigraphy of the studied carbonates revealed that the investigated part of the Gardiki section covers the Cretaceous–Paleogene (K-Pg) transition, partly reflecting the Senonian limestone and calciturbidites formations of the Ionian zone stratigraphy. Litho-and bio-facies analyses allowed for the recognition of three distinct depositional facies: (a) the latest Maastrichtian pelagic biomicrite mudstone with in situ planktonic foraminifera, radiolarians, and filaments, (b) a pelagic biomicrite packstone with abundant planktonic foraminifera at the K-Pg boundary, and (c) an early Paleocene pelagic biomicrite wackestone with veins, micritized radiolarians, and mixed planktonic fauna in terms of in situ and reworked (aberrant or broken) planktonic foraminifera. The documented sedimentary facies characterize a relatively low to medium energy deep environment, representing the transition from the deep basin to the deep shelf and the toe of the slope crossing the K-Pg boundary. Micropaleontological and paleoecological analyses of the samples demonstrate that primary productivity collapse is a key proximate cause of this extinction event. Additional petrographic analyses showed that the petrophysical behavior and reservoir characteristics of the study deposits are controlled by the depositional environment (marine, meteoric, and burial diagenetic) and further influenced by diagenetic processes such as micritization, compaction, cementation, dissolution, and fracturing.

Diagenetic Control of Reservoir Performance and Its Implications for Reservoir Prediction in Jinci Sandstone of Upper Carboniferous in the Middle East Ordos Basin.

The Upper Carboniferous sandstone reservoir is a vital replacement area for natural gas exploration in Ordos Basin. In this study, 157 Jinci sandstone samples were selected to conduct a series of experiments and analyses. The reservoir material composition and pore structure analysis shows that the lithology of the reservoir is mainly quartz arenite, followed by sublithic arenite. The detrital particles are mainly quartz (69-97.5%), followed by rock fragments (0.1-24.5%), and the content of feldspar is less than 0.01%. The cement consists of siliceous material, clay minerals, and carbonate, with averages of 2.34, 5.96, and 1.81%, respectively. Three types of pore-throat structures (HPMI curve: types 1, 2, and 3) are identified in the Jinci sandstone reservoir, corresponding to different pore-throat radius distributions (RCP curves: types A, B, and C). The study of the factors affecting reservoir pore structure and its internal mechanism shows that the reservoir pore-throat combination, affecting the reservoir performance, is mainly controlled by deposit composition and the subsquent diagenetic modification. A higher rigid particle content and an appropriate amount of siliceous cementation (2-10%) would lead to resistance of the compaction, in favor of the preservation of primary intergranular pores. When the content of ductile particles is more than 3%, the original intergranular pores tend to be substantially reduced. The deposit composition of sandstone controls the preservation of residual intergranular pores by affecting the intensity of compaction and dissolution controlling the amount and type of cementation. Compared with dissolution-subjected quartz arenites, the sublithic arenites are characterized by a common occurrence of altered kaolinite and recrystallized illite, which would destroy the reservoir property. The early diagenetic carbonate cementation, as well as the strong siliceous cementation in "sedimentary quartz arenite", are unfavorable to the formation of high-quality reservoirs. Then, on the basis of the characteristics of various diagenesis and their interaction and internal relationship, the diagenetic sequence and diagenetic-pore evolution patterns of different types of reservoirs were established. Finally, according to the lithological characteristics and the diagenetic-controlled pore-throat evolution patterns of different types of reservoirs, the reservoir quality in the study area was predicted.