Al-Khali Basin Research Articles

First record of the Cenomanian-Turonian Oceanic Anoxic Event (OAE-2) in the eastern Rub’ Al Khali Basin by means of elemental chemostratigraphy

First record of the Cenomanian-Turonian Oceanic Anoxic Event (OAE-2) in the eastern Rub’ Al Khali Basin by means of elemental chemostratigraphy

Biostratigraphy and sequence stratigraphy of the Minjur and Marrat Formations (Upper Triassic to Middle Jurassic) in Kuwait

This paper summarizes sedimentological and biostratigraphic data for the Minjur and Marrat Formations in Kuwait and places them within an expanded sequence stratigraphic framework based on the letter and number scheme initiated by Sharland and others (2001). Only two sequences (Tr80 and J10) were identified in this interval in the original scheme, whereas, between Tr80 and the top of the Upper Marrat, 18 sequences are now recognized and their sequence boundaries and maximum flooding surfaces identified and illustrated herein. One new sequence (Tr90) was proposed in the underlying Jilh A Member. Three new sequences (Tr100, Tr105 and Tr110) are recognized in the Minjur Formation (= Lower Minjur in Saudi Arabia). Four sequences (J02, J04, J06 and J08) and part of a fifth (J10) are recognized in the Lower Marrat. Seven sequences (part of J10 and J11-J16) are recognized in the Middle Marrat. Three sequences (J17, J18 and J19) are recognized in the Upper Marrat. Biostratigraphic data are sparse for the Minjur and Marrat Formations. In the Marrat Formation, calcareous nannofossils are extremely rare, benthic foraminifers are relatively common but long-ranging and palynomorphs are sparse and most commonly non-age diagnostic. Published and unpublished proprietary data from 33 wells have been combined to determine the ages of the succession. Using palynology, the Minjur Lower Member was dated as Norian. An undifferentiated Norian-Rhaetian age range is assigned to the Middle and upper Members of the Minjur Formation. The Triassic/Jurassic boundary is placed just below the base of the Lower Member of the Marrat Formation, where cuttings samples from a thin interval of strata yielded long age-ranging palynomorphs. The Sinemurian/Pliensbachian boundary occurs in the Lower Marrat at the base of the S J06 transgressive systems tract. The Pliensbachian/Toarcian boundary, dated on the basis of Nannoceratopsis triceras and Lotharingius crucicentralis, is also in the Lower Marrat at the base of the S J10 transgressive systems tract. The contact of the Middle and Upper Marrat is unconformable and locally karsted but appears to correlate to the Toarcian/Aalenian boundary. The upper section of the Upper Marrat and the base of the overlying Dhruma Formation have not been cored but the Aalenian/Bajocian boundary is placed in the upper portion of Sequence J19. SB J20 is placed at the top of the Upper Marrat Member. Change in the age of the Late Triassic Baluti Formation in Iraq has resulted in changes in correlations of the Minjur and Marrat Formations to each other and to other formations in the region. The Lower Marrat is shown to be the shallow marine equivalent of the Upper Minjur siliciclastics in the subsurface Rub al Khali Basin and in the shallow subsurface Arabian Basin near the outcrop belt in Saudi Arabia. The Lower Marrat correlates to the Adaiyah Formation and the Upper Sarki Formation in Iraq. The Middle Marrat correlates to the Mus and Alan Formations in Iraq and to all of the Marrat Formation as defined in outcrop in Saudi Arabia. The Upper Marrat is largely represented by an Aalenian-age hiatus in the Saudi Arabian outcrop belt but a thin, condensed Aalenian section is present in the subsurface, basinward of the outcrop belt, and correlated with the Lower Dhruma (D1-D2). The Upper Marrat is correlated to the lower Sargelu Formation in Iraq. These new and revised correlations clarify the timing of the Late Triassic (Norian) uplift of the Qatar Arch.

Sedimentology, sequence stratigraphy and their control on reservoirs quality in mid-Cretaceous Mishrif formation in East Rub al Khali Basin, Western UAE

Sedimentology, sequence stratigraphy and their control on reservoirs quality in mid-Cretaceous Mishrif formation in East Rub al Khali Basin, Western UAE

The design of an open-source carbonate reservoir model

This work presents a new open-source carbonate reservoir case study, the COSTA model, that uniquely considers significant uncertainties inherent to carbonate reservoirs, providing a far more challenging and realistic benchmarking test for a range of geo-energy applications. The COSTA field is large, with many wells and large associated volumes. The dataset embeds many interacting geological and petrophysical uncertainties in an ensemble of model concepts with realistic geological and model complexity levels and varying production profiles. The resulting number of different models and long run times creates a more demanding computational challenge than current benchmarking models. The COSTA model takes inspiration from the shelf-to-basin geological setting of the Upper Kharaib Member (Early Cretaceous), one of the most prolific aggradational parasequence carbonate formations sets in the world. The dataset is based on 43 wells and the corresponding fully anonymised data from the northeastern part of the Rub Al Khali basin, a sub-basin of the wider Arabian Basin. Our model encapsulates the large-scale geological setting and reservoir heterogeneities found across the shelf-to-basin profile, into one single model, for geological modelling and reservoir simulation studies. The result of this research is a semi-synthetic but geologically realistic suite of carbonate reservoir models that capture a wide range of geological, petrophysical, and geomodelling uncertainties and that can be history-matched against an undisclosed, synthetic ‘truth case’. The models and dataset are made available as open-source to analyse several issues related to testing new numerical algorithms for geological modelling, uncertainty quantification, reservoir simulation, history matching, optimization and machine learning. Supplementary material: supplementary data associated with this article can be found in the data repository for the COSTA model available at https://doi.org/10.17861/6e36e28d-50d9-4e31-9790-18db4bce6e5d and supplementary material is available at https://doi.org/10.6084/m9.figshare.c.5823571

Saturation evaluation of microporous low resistivity carbonate oil pays in Rub Al Khali Basin in the Middle East

To solve the problem that it is difficult to identify carbonate low resistivity pays (LRPs) by conventional logging methods in the Rub Al Khali Basin, the Middle East, the variation of fluid distribution and rock conductivity during displacement were analyzed by displacement resistivity experiments simulating the process of reservoir formation and production, together with the data from thin sections, mercury injection and nuclear magnetic resonance experiments. In combination with geological understandings, the genetic mechanisms of LRPs were revealed, then the saturation interpretation model was selected, the variation laws and distribution range of the model parameters were defined, and finally an updated comprehensive saturation interpretation technique for the LRPs has been proposed. In the study area, the LRPs have resistivity values of less than 1 Ω·m, similar to or even slightly lower than that of the water layers. Geological research reveals that the LRPs were developed in low-energy depositional environment and their reservoir spaces are controlled by micro-scale pore throats, with an average radius of less than 0.7 μm, so they are typical microporous LRPs. Different from LRPs of sandstone and mudstone, they have less tortuous conductive paths than conventional reservoirs, and thus lower resistivity value under the same saturation. Archie's formula is applicable to the saturation interpretation of LRPs with a cementation index value of 1.77—1.93 and a saturation index value of 1.82—2.03 that are 0.2—0.4 lower than conventional reservoirs respectively. By using interpretation parameters determined by classification statistics of petrophysical groups (PGs), oil saturations of the LRPs were calculated at bout 30%—50%, 15% higher than the results by conventional methods, and basically consistent with the data of Dean Stark, RST, oil testing and production. The 15 wells of oil testing and production proved that the coincidence rate of saturation interpretation is over 90% and the feasibility of this method has been further verified.

Data-driven machine learning approach to predict mineralogy of organic-rich shales: An example from Qusaiba Shale, Rub’ al Khali Basin, Saudi Arabia

The Qusaiba Shale is a proven source rock for the Palaeozoic petroleum system of the middle east and it is targeted as a potential source of unconventional shale gas potential reservoirs in Saudi Arabia and recently considered a possible source of unconventional gas. Mineralogy of shale plays a key role in the successful design and performing the hydraulic fracturing operations and in turn evaluating the production potential. There is limited research available in the literature on the application of artificial intelligence for mineralogical prediction, which motivate us to perform this research on the Qusaiba Shale. The study aims to predict the Qusaiba Shale mineralogy, specifically clay and quartz minerals using readily available conventional logs, where both minerals are the major constituents of shale and help in assessing the brittle and ductile zones within the shale formation. Three lithofacies were defined in the Qusaiba Shale based on different geological and sedimentary features of core samples, and they have different ranges of quartz and clay content. Predictive models were developed for two utmost important minerals present in Qusaiba Shale formation including clay and quartz using artificial intelligence techniques. An adaptive neuro-fuzzy inference system (ANFIS) and artificial neural networks (ANN) were employed to precisely predict the two major minerals contents in Qusaiba Shale formation. All four models were found to have good accuracy. ANN-based models exhibited minimal errors with AAPE and RMSE of 2.53 and 1.45 for quartz and 3.43 and 2.01 for unseen data points for clay prediction models respectively. ANFIS-based prediction models presenting the AAPE and RMSE 2.67 and 1.83 for predicted quartz values and 3.59 and 1.89 for the clay content respectively. The applied artificial intelligence predictive model for major minerals in Qusaiba Shale i.e., clay and quartz would be a viable and useful approach to achieve valuable information about minerals content in shale for prospective evaluation of shale gas reservoirs. The results of this work would be useful in prospect evaluation and optimizing the production from unconventional shale gas reservoirs in Saudi Arabia. Moreover, the approach used may provide insights into replacing traditional mineralogy determination methods to save cost and resources in the absence of cores and mineralogy logs in the unconventional Qusaiba Shale resource. Furthermore, applying the same artificial intelligence approach and steps could be used for the field development of other shale gas and oil fields worldwide.

New approaches to distinguish shale-sourced and coal-sourced gases in petroleum systems

Current approaches relating thermogenic gases to either shale source rocks (predominantly type II kerogen) or coal source rocks (predominantly type III kerogen) are not reliable and not globally applicable. This is because these mostly empirical approaches were developed using small poorly-constrained datasets from limited locations. The evaluation of a large global dataset of molecular and isotopic properties of gases from unconventional shale and coal reservoirs suggests that two genetic diagrams based on stable carbon isotopes of methane and ethane, δ13C-C2H6versus δ13C-CH4 and δ13C-CH4versus Δ(δ13C-C2H6 – δ13C-CH4), provide the best separation of shale-sourced and coal-sourced gases. Newly designated genetic fields and shale/coal separation lines on these diagrams were tested and validated using data from five petroleum systems with, likely, only shale (class B and A organofacies) source rocks (the Maracaibo Basin in Venezuela, the Guajira Basin in Colombia and the Rub Al Khali Basin in Iran) and only coal (class F organofacies) source rocks (the Southern Permian Basin in Germany and the Sichuan Basin in China). The practical usefulness of this new approach to gas-source correlations was demonstrated in two case studies from petroleum systems with debated source rock organofacies (the Mozambique Basin in Mozambique and the Indus Basin in Pakistan). These better constrained and more reliable diagrams with genetic fields and shale/coal separation lines represent a new tool for the evaluation of petroleum systems.

Viscoelastic Model and Synthetic Seismic Data of Eastern Rub’Al-Khali

The Rub’ Al-Khali basin in Saudi Arabia remains unexplored and lacks data availability due to its remoteness and the challenging nature of its terrain. Thus far, there are neither digital geologic models nor synthetic seismic data from this specific area accessible for testing research techniques and analysis. In this study, we build a 2D viscoelastic model of the eastern part of the Rub’ Al-Khali basin and generate a corresponding dual-component seismic data set. We compile high-resolution depth models of compressional- and shear-wave velocities, density, as well as compressional- and shear-wave quality factors from published data. The compiled models span Neoproterozoic basement up to Quaternary sand dunes. We then use the finite-difference technique to model the propagation of seismic waves in the compiled viscoelastic medium of eastern Rub’ Al-Khali desert. In particular, we generate vertical and horizontal components of the shot gathers with accuracy to the fourth and second orders in space and time, respectively. The viscoelastic models and synthetic seismic datasets are made available in an open-source site for prospective re-searchers who desire to use them for their research. Users of these datasets are urged to make their findings also accessible to the geoscience community as a way of keeping track of developments related to the Rub’ Al-Khali desert.

Control of Lithofacies and Geomechanical Characteristics on Natural Fracture Systems in Qusaiba Shale, Rub’ Al-Khali Basin, Saudi Arabia

The lower Silurian Qusaiba Shale is one of the major source rocks for Paleozoic oil/gas reservoirs in Saudi Arabia and recently considered a potential unconventional shale gas resource. The study aims to evaluate the reservoir heterogeneity and production potential of Qusaiba Shale through the integration of geological, geomechanical and fractures characteristics. Three lithofacies were identified in Qusaiba shale. Mineralogical composition resulted in variable amounts of quartz ranging from 39 to 40, 45–55 and 60–78% for Lithofacies-I, II and III, respectively. Inter-granular porosity of these lithofacies is very low; however, fractures along laminations, at angle with laminations, and few micro-faults enhance porosity up to 5–6, 2–3, and < 1% in Lithofacies-I, II and III, respectively. The Lithofacies-I hosts the lowest fracture density (1.2 fractures/foot), likely due to the relatively lower quartz content (39%) as compared to other lithofacies. The fracture densities in Lithofacies-II and III are 2.1 and 3.2 fractures/foot, respectively. Lithofacies-I exhibits low stiffness in terms of low Young’s modulus (average 26 GPa) and high Poisson’s ratio (average 0.34). Mineralogy- and elastic parameters-based brittleness indices exhibited ductile behavior of this lithofacies. The brittleness index exhibited brittle behavior for silica-rich Lithofacies-III and has highest intensity of natural fractures. Hence, it is concluded that mineralogy and geological characteristics are the main controlling factors on shale brittleness, mechanical properties and fractures characteristics. The integration of geology, mineralogy and geomechanics plays the key role to better evaluate the prospectivity of shale reservoirs.

Origin of solutes in a regional multi-layered sedimentary aquifer system (a case study from the Rub’ al Khali basin, Saudi Arabia)

An isotope and solute evaluation was applied to identify the origin and mechanisms of groundwater salinization in three major Tertiary aquifers in the Rub’ al Khali topographic basin. We demonstrate that the groundwater chemistry evolved from a low- (1800 ppm) to high- (>120,000 ppm) salinity Na–Cl water type, regardless of the aquifer. The similarity in water types between the groundwater from the different formations suggests that the same origin and geochemical processes may be controlling the salinity and major ion chemistry in these aquifers. The suite of hydrogeological, hydrochemical (Cl vs. Br), and isotopic (Cl vs δ18O and Br vs δ81Br) data indicates that the source of solutes is associated with the entrapment of evaporated paleo-seawater (connate water) in nearshore and lagoonal environments during the time of deposition. Moreover, the results from the 87Sr/86Sr ratios show no evidence of significant vertical connectivity between the three Tertiary aquifers. Instead, the data support that evaporated paleo-seawater was trapped in each aquifer individually during the time of deposition, and that each has evolved similarly through water-rock and redox reactions. The stable isotopic compositions of δ18O, δ2H, and 14C show that the entrapped paleo-seawater was partially flushed out by fresh meteoric water during the Late Pleistocene and Early Holocene periods.

Sedimentary response of Cretaceous tectonic evolution in the Middle East Rub Al Khali Basin and its inspirations for oil exploration

Sedimentary response of Cretaceous tectonic evolution in the Middle East Rub Al Khali Basin and its inspirations for oil exploration

Characteristics of Paleozoic tight gas sandstone reservoir: integration of lithofacies, paleoenvironments, and spectral gamma-ray analyses, Rub’ al Khali Basin, Saudi Arabia

The glaciogenic Sarah Formation (Hirnantian) is a potential tight gas sandstone reservoir in the Rub’ al Khali Basin and other basins in Saudi Arabia. This study investigated the facies heterogeneity and paleoenvironments of the Sarah Formation using cores, petrographic thin sections, and spectral gamma-ray (SGR) analyses. The study revealed four facies associations (FAs), including massive to ripple-laminated sandstone (FA1), gray massive sandstone (FA2), diamictites (FA3), and partially deformed, massive-graded sandstone (FA4), interpreted to have been deposited in fluvial, glaciofluvial, glaciolacustrine delta, and subglacial outwash environments, respectively. The sandstone varies from fine-, to medium-, and coarse-grained and is a moderately to poorly sorted quartz arenite, subarkose, and to sublithic arenite. The integration of facies analysis with SGR analysis allowed us to classify the facies further into low matrix and argillaceous sandstones in the fluvial and glaciofluvial facies, mixed sandstones in the glaciolacustrine delta facies, and clast-supported and matrix-supported diamictites with shales in the subglacial facies. The results of this study might provide guidelines for facies identification and the prediction of reservoir-quality targets in the tight sandstone in the subsurface. This classification could facilitate the identification of and distinction between the glaciogenic lithofacies of tight gas reservoirs in the subsurface and provides a tool for correlating the lithofacies. This work might also provide guidelines for the exploration and development of Paleozoic tight gas sandstone reservoirs in the subsurface that are deeply buried and show a wide range of facies, paleoenvironments, and paleogeographic settings.

Factors Controlling Reservoir Quality of a Paleozoic Tight Sandstone, Rub’ al Khali Basin, Saudi Arabia

The heterogeneity of depositional and diagenetic controls on the reservoir quality of tight sandstones is a major challenge. Understanding which factors are the most influential is significant for improving reservoir evaluation and prediction. This study utilized sedimentological core descriptions, thin-section petrography, quantitative evaluation of mineralogy by scanning electron microscope, X-ray diffractometry, scanning electron microscopy and porosity–permeability measurements to define and characterize the factors that control reservoir quality in the Upper Ordovician Sarah Formation of the Rub’ al Khali Basin. Four facies associations (FA), including fluvial (FA1), glaciolacustrine delta (FA2), subglacial (FA3) and glaciofluvial (FA4), have been recognized. The results show that the highest reservoir quality was enhanced by feldspar dissolution in FA1. The development of its reservoir quality was, however, partially limited by compaction, and authigenic pore filling and grain coating with the clay mineral, illite. The lowest reservoir quality, related to FA3, appears to have been influenced by the detrital matrix content, compressibility and siderite cement precipitation. The presence of a detrital matrix, anhydrite and barite cement, and grain compaction reduced the reservoir quality in FA2. On the other hand, intergranular porosity, and fractures that facilitated the development of dual porosity and permeability systems in this FA, might have slightly enhanced its reservoir quality. Factors such as grain-size distribution and sorting influenced the reservoir quality of all the FAs, but these were the main controls on the reservoir quality of FA4, in addition to compaction. The reservoir quality of this FA might have also been improved by fractures and the dissolution of unstable grains.

Mitigating the effects of sand dunes on seismic data from the Rub al Khali basin, Saudi Arabia

ABSTRACTThe Rub Al Khali region in Saudi Arabia is characterized by the presence of sand dunes separated by salt flats, also called Sabkhas. In general, the elevation of dunes in this region varies between 90 and 250 m above sea level. The presence of these sand dunes, along with the rapidly changing surface topography poses challenges for seismic data acquisition and processing. The high contrast in acoustic impedance between the dune base and the underlying formation often results in amplification of seismic waves that are recorded at stations located on the surface of sand dunes. Attempts to address the issue using conventional surface‐consistent amplitude scaling methods without reducing these amplification effects generally fail, thus compromising the suitability of the processed data for amplitude versus offset analysis. In this study, we propose a new reference site technique to reduce the effects of sand dune amplification, enabling the production of data sets that are suitable for amplitude versus offset processing. The proposed technique uses a deterministic approach to derive surface‐consistent, frequency‐dependent de‐amplification functions for shots and stations located on the dunes only. Two‐dimensional synthetic and field data examples show that the technique significantly reduces the effects of sand dune amplification.

Insights on spatial variography and outcrop-subsurface relationship of sandstone reservoir properties: A case study from the Late Triassic Minjur Formation, central Saudi Arabia

Understanding the variography of outcrop properties may give a guide for predicting the subsurface reservoir quality, more significantly for the more stable and resistant reservoir rocks such as sandstones compared to the carbonates. This study was planned to investigate the lithofacies and reservoir properties of different sandstone lithofacies of the Late Triassic Minjur Formation outcrop, and attempted to develop a relationship between these aspects in outcrop and subsurface settings. Based on the field and petrographic analyses, sandstone lithofacies of Minjur Formation were categorized into five types upon their textures. These lithofacies were intensively investigated for porosity and permeability. Variography analyses were applied on composite outcrop lithofacies, and also on porosity and permeability data. A good relationship was observed between porosity and permeability, which coincides with the univariate statistics of each and confirmed by variography analysis. Combination of outcrop and subsurface reservoir properties showed an acceptable correlation between outcrop reservoir properties and data from central Saudi Arabia and Rub’ Al-Khali Basin in southern and southeastern Saudi Arabia. This correlation was further highlighted by the global sense of subsurface sandstone reservoir properties. In general, the current study reflects the possibility of sandstone outcrop data to act as a representative analog for its equivalent subsurface reservoir. This possibility, which is mainly controlled by the similarity in depositional setting, can be also attained for reservoir properties and quality. Obtaining more qualitative and quantitative data is always advantageous to get better and more robust correlation.

Natural fracture system of the Cambro-Permian Wajid Group, Wadi Al-Dawasir, SW Saudi Arabia

This study investigates the regional and outcrop-scale fracture system within the Wajid Group exposures in Wadi Al-Dawasir, southwest Saudi Arabia. The Wajid Group is a Cambro-Permian siliciclastic succession that forms the main groundwater aquifers in the study area and is considered as a potential hydrocarbon reservoir in the Rub' Al-Khali Basin. The succession is composed of fluvial, marine, and glacial to glaciofluvial deposits. This study aims to characterize and model the fracture system within the Wajid Group in the Wadi Al-Dawasir area using satellite imagery and direct field measurements. A further study objective is to define the geological factors controlling the fracture distribution within the Wajid Group succession. Five sets of regional-scale fractures (lineaments) were defined: N000°, N015°, N035°, N075°, and N135°. In addition, five sets of the outcrop-scale fractures were delineated: N015°, N035°, N075°, N135°, and N165°. The N135°- and N035°-oriented fracture sets are predominant at the regional scale. At the outcrop scale, however, the N165°- and N075°-oriented fracture sets are predominant. The trace-length of the regional-scale fractures is distributed according to the negative exponential distribution. The fractures within the Wajid Group outcrops are vertical to sub-vertical extensional fractures (mode 1). Those fractures are open, however, and at some localities, they are sealed or coated with calcite or iron oxides. Fracture swarms with an orientation of N015° were also observed in the southeastern part of the study area. Hierarchical outcrop conceptual models of two fracture sets are proposed. The proposed models show that the regional-scale fractures are not influenced by stratigraphic or lithological variations. In contrast, the outcrop-scale fractures are controlled by the stratigraphic, lithological, and diagenetic variations in the fracture-hosting sandstone. The diagenetic characteristics (cementation and dissolution), bed thickness, and porosity of the fracture-hosting sandstone play a key role in the fracture distribution within the Wajid succession. The results of this study contribute to the understanding of groundwater flow behaviour within fractured aquifers in the study area and will help to enhance gas production from fractured hydrocarbon reservoirs in the Rub' Al-Khali Basin.

Integrated geomechanical, petrographical and petrophysical study of the sandstones of the Wajid Group, SW Saudi Arabia

The Cambro-Permian siliciclastic succession in southwestern Saudi Arabia is represented by the Wajid Group, which consists mainly of fluvial, shallow marine, aeolian, and glacial sandstones. The Wajid Group comprises the Dibsiyah, Sanamah, Qalibah, Khusayyayn, and Juwayl Formations. It is exposed in the Wadi Al-Dawasir area and extends to Najran City. The sandstones of the Wajid Group serve as groundwater aquifers in the Wadi Al-Dawasir and Najran areas and host hydrocarbon (mainly gas) reservoirs in the Rub’ Al-Khali Basin. This study aims to characterize the geomechanical properties (rock strength and Young's modulus) of the sandstones of the Wajid Group using field and experimental techniques. A further objective is to investigate the relationships between the geomechanical properties and the petrographical and petrophysical properties of the studied sandstones. The geomechanical properties of the studied sandstones vary from glacial to non-glacial sandstones, as the glacial sandstones display high values of the geomechanical properties with high variability indices. Four geological factors including grain size, cement content, porosity and permeability were observed as the main controls on the geomechanical behaviour of the studied sandstones except for the Khusayyayn sandstone, where the mineral composition was also important. Significant correlations were observed between the petrographical and petrophysical properties and the geomechanical properties of the glacial sandstones. Predictive models of the geomechanical properties (RN, UCS, and E) were generated using regression analysis to account for the glacial sandstones.

Analysis of lineaments within the Wajid Group, SW Saudi Arabia, and their tectonic significance

The Wajid Group is a Cambro-Permian sedimentary succession in southwest Saudi Arabia. This group is a well-known groundwater aquifer in the Wadi Al-Dawasir and Najran areas. The group also represents siliciclastic hydrocarbon reservoirs in the Rub' Al-Khali Basin. The Wajid Group is exposed in an area extending from Wadi Al-Dawasir southward to Najran city. This study aims to map and characterize the lineament traces of the Wajid Group outcrops. Landsat-8 OLI/TIRS satellite images with 30-m resolution, Spot-5 satellite images with 2.5-m resolution and SRTM digital elevation models (DEM) with 30-m resolution were used for lineament trace detection. Those lineament traces supplemented by aeromagnetic lineaments detected from reduced to pole magnetic anomaly map of the studied outcrop. Multi-scale lineament trace maps were generated, and the lineament datasets, including orientation and length, were analyzed statistically. Eight lineament trace trends were identified including NW-SE, NNW-SSE, N-S, NNE-SSW, NE-SW, ENE-WSW, E-W, and WNW-ESE. The northerly, northwesterly, and northeasterly trending lineament traces are predominant. The lineament trace lengths are generally followed the power law distribution. The lineament trace trends were validated through field investigation of the Wajid Group outcrop. The reported outcrop fracture trends are consistent with major lineament trace trends. Lineaments within the Wajid Group outcrop are also consistent with those of the southern portion of the Arabian Shield. The results of this study provide insight into the tectonic origin of the Wajid Group outcrop lineaments, and understanding of the lineaments distribution which can help to predict the fluid flow behavior within the groundwater fractured aquifers or hydrocarbon fractured reservoirs in Rub’ Al-Khali Basin.

Mesozoic siliciclastic reservoirs and petroleum system in the Rub’ Al-Khali basin, Saudi Arabia

Hydrocarbons have recently been discovered in Upper Triassic to Middle Jurassic siliciclastic reservoirs in the Rub' Al-Khali basin in Saudi Arabia. The reservoirs fill accommodation space created by Triassic and early Jurassic crustal-scale basins on the order of 100 km (62 mi) in wavelength and hundreds of meters in depth. These basins are separated by highs that are interpreted as crustal-scale epeirogenic folds. Lithologies include well-sorted quartz arenites deposited in shallow-marine, shoreface, and fluviodeltaic settings. These sequences can be correlated across the basin to extensive escarpment outcrops south of Riyadh and beyond Saudi Arabia into well-documented equivalents elsewhere in the Middle East and East Africa. The gross architecture of the interval is imaged on reflection seismic, showing clinoformal geometries and onlap onto the Triassic structured surface. Geochemistry of tested fluids indicates a type III kerogen source. The simplest interpretation is that the system is self-sourcing hydrocarbons from interbedded coaly material that is observed in the wells and at outcrop. Reservoir pressures are anomalously low relative to the overlying carbonate reservoir systems. These low pressures are interpreted to indicate lateral communication from the Rub' Al-Khali basin westward to outcrop, in contrast with the overlying carbonate fairways that are known to contain facies boundaries that trend across the regional dip. Onlapping geometries in the siliciclastic fairway combine with Cretaceous and Cenozoic compressional structures to create combined structural-stratigraphic traps.

Applications of chemostratigraphy in Cretaceous sediments encountered in the North Central Rub’ al-Khali Basin, Saudi Arabia

The following study was undertaken on inorganic geochemical data acquired for 832 core and cuttings samples taken from Cretaceous sediments encountered in 11 wells in the North Central Rub’ al-Khali Basin, Saudi Arabia. The study sections extend from Khafji Member at the base of the Wasia Formation to the basal part of the Aruma Formation. The principal objective of the study was to produce a chemostratigraphic scheme for these wells, though a comparison was also made with a previous lithostratigraphic scheme.Although ICP–OES (Inductively Coupled Plasma–Optical Emission Spectrometry) and ICP–MS (Inductively Coupled Plasma–Mass Spectrometry) were used to acquire data for 50 elements, the chemostratigraphic scheme is based on changes in the following ‘key’ elements and ratios: Ca, Al, Zr, P/Y, Zr/P, Zr/Y, Zr/Nb, Mo and Zr. The scheme comprises a hierarchical order of five zones, 18 subzones and four divisions, with the zones labelled C1, C2, C3, C4 and C5 in ascending stratigraphic order. The definition of these zones are mainly based on changes in Ca and Al reflecting variations in bulk lithology as a response to changes in base level. Zone C1 is dominated by elevated Al and low Ca concentrations and represents calcareous mudrocks deposited in a lagoonal–prodelta environment. An increase in base level led to the formation of highly calcareous rudistic limestones deposited in a shallow marine environment, with a further increase in base level resulting in the deposition of calcareous mudrocks with high Al values in zone C3. Zone C4 comprises rudistic limestones (with elevated Ca and low Al) deposited in shallow marine conditions, while C5 is dominated by calcareous mudrocks and argillaceous limestones deposited in a prodeltaic paleoenvironment. Although the definition of zones mainly relates to changes in base level/bulk lithology, more subtle changes in provenance are modelled using the P/Y, Zr/P, Zr/Y and Zr/Nb ratios which are used to define most subzones and divisions. Variations in this ratio are almost entirely dependent on changes in source/provenance.Although all of the zones and most of the subzones are correlative between the study wells it is noted that different criteria are used to define the zone C2 and C4 subzones in the eastern and western wells of the study area. This suggests that separate sediment sources were responsible for the delivery of clastic material to these carbonate ‘reefs’ during the deposition of these subzones.One important conclusion from this study is that there are close links between the chemostratigraphic and lithostratigraphic correlations but the former offers a much higher level of resolution.