Now showing items 1-20 of 172

    • Hydrothermal metalliferous sediments in the Red Sea: Characterization and properties

      Modenesi, M. Clara; Santamarina, Carlos (Engineering Geology, Elsevier BV, 2022-05-19) [Article]
      Sediment accumulations within the Red Sea central deeps have unique genesis and properties. We piece together available information to understand their geological setting and formation history, and conduct an extensive sediment characterization study to assess their geotechnical properties in order to anticipate engineering/mining implications. The various sediment columns reflect slow-rate background sedimentation (biogenic and detrital particles – Valdivia deep) and hydrothermal metalliferous sediments that nucleate and grow within the overlying brine pools (primarily in the Atlantis II, as well as in the Wando deep, and to a lesser extent in Discovery deep). All sediments are fine-grained silt and clay-size particles; smaller particles tend to have higher specific gravity and define the metalliferous content. Hydrothermal sediments exhibit extreme properties when compared to sediments worldwide: they have uncharacteristically large maximum void ratio and compressibility, and their self-compaction is very different from background Red Sea sediments. Their unique self-compaction trends have a strong effect on remote acoustic characterization and sampling, and must be carefully accounted for during field studies and resource assessment. Three distinct properties of hydrothermal metalliferous sediments are relevant for separation and enrichment: high specific surface area, high specific gravity, and ferromagnetic signature. Small grains and low-density flocs have low terminal Stokes' velocities and their residency times may be extended in convective stratified brine pools; this observation affects the environmental analysis of mining operations and tailings disposal.
    • Adsorption of Polar Species at Crude Oil–Water Interfaces: the Chemoelastic Behavior

      Saad, Ahmed Mohamed; Aime, Stefano; Chandra Mahavadi, Sharath; Song, Yi-Qiao; Yutkin, Maxim; Weitz, David; Patzek, Tadeusz (Langmuir, American Chemical Society (ACS), 2022-05-17) [Article]
      We investigate the formation and properties of crude oil/water interfacial films. The time evolution of interfacial tension suggests the presence of short and long timescale processes reflecting the competition between different populations of surface-active molecules. We measure both the time-dependent shear and extensional interfacial rheology moduli. Late-time interface rheology is dominated by elasticity, which results in visible wrinkles on the crude oil drop surface upon interface disturbance. We also find that the chemical composition of the interfacial films is affected by the composition of the aqueous phase that it has contacted. For example, sulfate ions promote films enriched with carboxylic groups and condensed aromatics. Finally, we perform solution exchange experiments and monitor the late-time film composition upon the exchange. We detect the film composition change upon replacing chloride solutions with sulfate-enriched ones. To the best of our knowledge, we are the first to report the composition alteration of aged crude oil films. This finding might foreshadow an essential crude oil recovery mechanism.
    • Late Pleistocene to Holocene Architecture of a Land-attached Carbonate Platform Lagoon in the African-Arabian Desert Belt (Al Wajh platform, N Red Sea, Saudi Arabia).

      Putri, Indah; Petrovic, Alexander; Sifontes, Rangelys; Vahrenkamp, Volker (Copernicus GmbH, 2022-05-12) [Presentation]
      Investigation of carbonate platform architecture is a crucial element to understanding the evolution of a platform. Extensive studies have been done on the architectures of various modern carbonate platforms. However, compared to humid climates, detailed studies in arid climates are rare, although many ancient carbonate reservoirs are developed under these conditions. This study investigates the Late Pleistocene architecture of the land-attached Al Wajh carbonate platform in the Northeastern Red Sea, Saudi Arabia. The platform is enclosed by a coral reef belt and characterized by a large lagoon (1,100 km2). The lagoon reaches 43 meters in depth and hosts more than 90 carbonate islands and numerous pinnacle and patch reefs. We utilize 700 km hydroacoustic data acquired using EdgeTech sub-bottom profiler during two research cruises with KAUST RV EXPLORER. An age model was established by utilizing a recently published Red Sea sea-level curve. Available climate data were used for the reconstructions of depositional environments. Data analysis reveals five depositional units: U1(Holocene) to U5(Late Pleistocene). Nine hydroacoustic facies are identified to describe the internal architecture, from homogenous reflection-free to wavy laminated facies. The oldest unit (U5) consists of homogeneous facies and reef facies. The unit is overlain by units 4 and 3, with up to five meters thick homogeneous facies and stratified facies. Unit 2 has a maximum thickness of 3 meters and consists of wavy laminated facies. Unit 1 is the youngest unit and consists of several facies, including heterogeneous, homogeneous, stratified, drift, reef, and reef debris facies. During MIS5e (U5), the Red Sea was experiencing a pluvial period, while the sea level was 10 meters higher than the present, leading to total flooding of the lagoon. Most of today's exposed carbonate islands in the lagoon correspond to carbonate accumulation during MIS5e. The depositional environment is interpreted as carbonate-dominated with the frequent siliciclastic influx in the coastal region during heavy rain. In the subsequent periods (MIS 5d to 5a), sea level dropped stepwise and exposed the platform partly. Stratified facies indicate terrestrial sediment input introduced during short pluvial periods. In the following glacial period (MIS 4 to 2), the platform was fully exposed for over 70,000 years. Due to the hyper-arid climate, we interpret unit 2 as an aeolian deposit likely reworked during Holocene transgression. During the platform's flooding in the Holocene, carbonate sedimentation restarted while coastal near stratified facies indicate an increased terrestrial influx during the short Holocene pluvial period (10,000-6000 years ago). The modern Al Wajh lagoon experiences an arid climate, with active carbonate sedimentations and minimal terrestrial input. Although the Red Sea has experienced several humid periods during the last 125,000 years, and extensive diagenetic alteration is recognized in the island's drill cores, no karst morphology has been identified. Results indicate that climate highly influences Al Wajh lagoon architecture, shown by its unique characteristics, including extensive carbonate deposition, intermittent terrestrial influx including aeolian deposits, and minimum karstification. Insights of this study will improve our understanding of the architecture of carbonate platforms in the subsurface deposited under similar conditions.
    • A Gradient-based Deep Neural Network Model for Simulating Multiphase Flow in Porous Media

      Yan, Bicheng; Harp, Dylan Robert; Chen, Bailian; Hoteit, Hussein; Pawar, Rajesh J. (Journal of Computational Physics, Elsevier BV, 2022-05-10) [Article]
      Simulation of multiphase flow in porous media is crucial for the effective management of subsurface energy and environment-related activities. The numerical simulators used for modeling such processes rely on spatial and temporal discretization of the governing mass and energy balance partial-differential equations (PDEs) into algebraic systems via finite-difference/volume/element methods. These simulators usually require dedicated software development and maintenance, and suffer low efficiency from a runtime and memory standpoint for problems with multi-scale heterogeneity, coupled-physics processes or fluids with complex phase behavior. Therefore, developing cost-effective, data-driven models can become a practical choice, and in this work, we choose deep learning approaches as they can handle high dimensional data and accurately predict state variables with strong nonlinearity. In this paper, we describe a gradient-based deep neural network (GDNN) constrained by the physics related to multiphase flow in porous media. We tackle the nonlinearity of flow in porous media induced by rock heterogeneity, fluid properties, and fluid-rock interactions by decomposing the nonlinear PDEs into a dictionary of elementary differential operators. We use a combination of operators to handle rock spatial heterogeneity and fluid flow by advection. Since the augmented differential operators are inherently related to the physics of fluid flow, we treat them as first principles prior knowledge to regularize the GDNN training. We use the example of pressure management at geologic CO2 storage sites, where CO2 is injected in saline aquifers and brine is produced, and apply GDNN to construct a predictive model that is trained with physics-based simulation data and emulates the physics process. We demonstrate that GDNN can effectively predict the nonlinear patterns of subsurface responses, including the temporal and spatial evolution of the pressure and CO2 saturation plumes. We also successfully extend the GDNN to convolutional neural network (CNN), namely gradient-based CNN (GCNN), and validate its capability to improve the prediction accuracy. GDNN has great potential to tackle challenging problems that are governed by highly nonlinear physics and enable the development of data-driven models with higher fidelity.
    • Numerical investigations of the PUGA geothermal reservoir with multistage hydraulic fractures and well patterns using fully coupled thermo-hydro-geomechanical modeling

      Gudala, Manojkumar; Govindarajan, Suresh Kumar; Yan, Bicheng; Sun, Shuyu (Energy, Elsevier BV, 2022-05-06) [Article]
      The Puga geothermal reservoir is located in the south-eastern part of Ladakh (Himalayan region, India), and it is providing encouraging results towards heat production. We proposed an improved mathematical model for the fully coupled thermo-hydro-geomechanical model to examine the variations in the Puga geothermal reservoir at between 4500 m from the surface with three, four, and seven hydraulic fractures in the reservoir along with four-spot, five-spot, seven-spot, and nine-spot well patterns. The distribution of low-temperature region is found in each fracture, and it is low in the reservoir with seven hydraulic fractures. The changes in the rock and fluid properties are examined effectively. Thermal strain is dominated in the fractures, and mechanical strain is impressive in the rock matrix; it is dependent on the number of hydraulic fractures and well patterns. The thermal performance of the Puga reservoir is examined with the geothermal life, reservoir impedance, and heat power and found that the number of hydraulic fractures and well patterns are influenced significantly in the multistage modeling of the Puga geothermal reservoir. Thus, the proposed mathematical model can effectively evaluate and predict the variations that occur in the Puga geothermal reservoir with dynamic rock, fracture, and fluid properties.
    • A robust Upwind Mixed Hybrid Finite Element method for transport in variably saturated porous media

      Younes, Anis; Hoteit, Hussein; Helmig, Rainer; Fahs, Marwan (Copernicus GmbH, 2022-04-27) [Preprint]
      The Mixed Finite Element (MFE) method is well adapted for the simulation of fluid flow in heterogeneous porous media. However, when employed for the transport equation, it can generate solutions with strong unphysical oscillations because of the hyperbolic nature of advection. In this work, a robust upwind MFE scheme is proposed to avoid such unphysical oscillations. The new scheme is a combination of the upwind edge/face centred Finite Volume (FV) method with the hybrid formulation of the MFE method. The scheme ensures continuity of both advective and dispersive fluxes between adjacent elements and allows to maintain the time derivative continuous, which permits employment of high order time integration methods via the Method of Lines (MOL). Numerical simulations are performed in both saturated and unsaturated porous media to investigate the robustness of the new upwind-MFE scheme. Results show that, contrarily to the standard scheme, the upwind-MFE method generates stable solutions without under and overshoots. The simulation of contaminant transport into a variably saturated porous medium highlights the robustness of the proposed upwind scheme when combined with the MOL for solving nonlinear problems.
    • Pore-Scale Spontaneous Imbibition at High Advancing Contact Angles in Mixed-Wet Media: Theory and Experiment

      Saad, Ahmed Mohamed; Yutkin, Maxim; Radke, Clayton J.; Patzek, Tadeusz (Energy & Fuels, American Chemical Society (ACS), 2022-04-22) [Article]
      Mixed wettability develops naturally on a pore scale in oil reservoirs after primary drainage. The invading oil fills pore interiors that become oil-wet by asphaltene deposition, while the residual water retreats into the pore corners, masking them and retaining their water wetness. This wettability alteration hinders oil mobilization during secondary waterflood. Therefore, a proper understanding of the conditions controlling pore-scale imbibition into mixed-wet pores may lead to a substantial increase in oil recovery from the portions of reservoir rocks bypassed during the original waterflood. We use selective silane coating to fabricate reservoir-representative mixed-wet capillaries with angular cross-sections. We validate our procedure on silica and glass substrates and characterize the mixed-wet surfaces by atomic force microscopy, scanning electron microscopy, and contact angle measurements. Subsequently, we investigate experimentally the invasion of water against air in mixed-wet, water-wet, and oil-wet square capillaries and compare our findings with the theoretical predictions of dynamic (Washburn, Szekely, and Bosanquet) and quasi-static [Mayer–Stowe–Princen (MSP)] meniscus-invasion models. None of the dynamic models for ducts of uniform wettability can fully describe our experimental data in mixed-wet capillaries. However, the experimental results agree with the predictions of MSP theory. We discuss the similarities and differences between experiment and theory and the reasons for the failure of the dynamic models. To our knowledge, this is the first direct experimental validation of MSP theory under mixed-wet conditions in such a controlled manner. We confirm the possibility of spontaneous piston-type imbibition with high (>90°) advancing contact angles into mixed-wet pores, given that the contact angle is lowered below a critical value that is a function of the pore geometry and water saturation. In oil reservoirs, injection of custom-designed brines would be required to change the contact angle to values below the imbibition threshold
    • Modelling the initiation of bitumen-filled microfractures in immature, organic-rich carbonate mudrocks: The Maastrichtian source rocks of Jordan

      Abu Mahfouz, Israa Salem; Wicaksono, Akbar Nugroho; Idiz, Erdem; Cartwright, Joe; Santamarina, Carlos; Vahrenkamp, Volker (Marine and Petroleum Geology, Elsevier BV, 2022-04-22) [Article]
      The initiation of bitumen-filled microfractures was analysed in the organic-rich Maastrichtian carbonate mudrocks of Jordan, which show great potential as source rocks and for a future unconventional hydrocarbon play. A modelling approach was performed to assess the possible scenarios causing horizontal small-scale (mm to cm in length) bitumen fractures (microfractures) at the immature stage. The aim was to back-calculate how much overpressure and bitumen generation was needed in the past to initiate horizontal microfracturing, comparing those simulated parameters with the actual generation potential from the source rock samples. The results show that the local overpressure resulting from the bitumen generation during early catagenesis was not high enough to initiate the microfracturing. We hypothesise that the increase of internal pressure was caused by the inability of the bitumen to be squeezed into the pore space during burial. The resulting overpressure induced a perturbation to the stable-state stress distribution around the kerogen boundary that eventually led to the initiation of horizontal microfractures along the tip of bitumen flakes. Subsequently, short-distance migration of bitumen and a significant decrease in pressure have prevailed in the study area. This proves that primary migration can occur long before the source rock reaches the oil or gas windows, at a comparatively shallow burial depth. This also indicates that the first framework pathways by the precursor horizontal microfractures may control the flow patterns of the hydrocarbons within source rocks. Understanding these factors is critical to predicting the impact of these microscale fractures on hydrocarbon expulsion and storage, and hence likely productivity of an analogous subsurface unconventional reservoir.
    • Improved Amott Cell Procedure for Predictive Modeling of Oil Recovery Dynamics from Mixed-Wet Carbonates

      Kaprielova, Ksenia; Yutkin, Maxim; Gmira, Ahmed; Ayirala, Subhash; Radke, Clayton; Patzek, Tadeusz (SPE, 2022-04-18) [Conference Paper]
      Spontaneous counter-current imbibition in Amott cell experiments is a convenient laboratory method of studying oil recovery from oil-saturated rock samples in secondary or tertiary oil recovery by waterflood of adjustable composition. Classical Amott cell experiment estimates ultimate oil recovery. It is not designed, however, for studying the dynamics of oil recovery. In this work we identify a flaw in the classical Amott cell imbibition experiments that hinders the development of predictive recovery models for mixed-wet carbonates. We revise the standard Amott procedure in order to produce smoother experimental production curves, which then can be described by a mathematical model more accurately. We apply Generalized Extreme Value distribution to model the cumulative oil production. We start with the Amott imbibition experiments and scaling analysis for Indiana limestone core plugs saturated with mineral oil. The knowledge gained from this study will allow us to develop a predictive model of water-oil displacement for reservoir carbonate rock and crude oil recovery systems.
    • Fast Screening of LSW Brines Using QCM-D and Crude Oil-Brine Interface Analogs

      Yutkin, Maxim; Kaprielova, K. M.; Kamireddy, Sirisha; Gmira, A.; Ayirala, S. C.; Radke, C. J.; Patzek, Tadeusz (SPE, 2022-04-18) [Conference Paper]
      This work focuses on a potentially economic incremental oil-recovery process, where a brine amended with inexpensive salts (in contrast to expensive surfactants and other chemicals) is injected into a reservoir to increase oil production. Historically, this process received the name of low salinity waterflooding (LSW) although the salinity is not always low(er). Nevertheless, we keep using this terminology for historical reasons. The idea of LSW has been known for three decades, but to the best of our knowledge no specific brine recipes that guarantee success have been presented so far. The reasons hide in the problem's complexity, disagreements in the scientific community, and a race to publish rather than to understand the fundamental principles behind the process. In this paper, we present an experimental model system that captures many of the important fundamental features of the natural process of crude oil attachment to mineral surfaces, but at the same time decomposes this complex process into simpler parts that can be more precisely controlled and understood. We systematically investigate the first-order chemical interactions contributing to the well-known strong attachment of crude oil to minerals using SiO2 as a mineral for its surface chemistry simplicity. Our preliminary results suggest that magnesium and sulfate ions are potent in detaching amino/ammonium-based linkages of crude oil with a SiO2 surface. However, when used together in the form of MgSO4, they lose part of their activity to the formation of a MgSO4 ion pairs. We also find that sulfate-detachment propensity stems not from the interaction with prototype mineral surface, but rather from the interactions with the crude oil-brine interface analog. We continue the systematic study of the ion effects on crude oil detachment, with and more results following in the future.
    • Effect of organic acids on CO2-rock and water-rock interfacial tension: Implications for CO2 geo-storage

      Al-Yaseri, Ahmed; Yekeen, Nurudeen; Ali, Muhammad; Pal, Nilanjan; Verma, Amit; Abdulelah, Hesham; Hoteit, Hussein; Sarmadivaleh, Mohammad (Journal of Petroleum Science and Engineering, Elsevier BV, 2022-04-07) [Article]
      A small concentration of organic acid in carbon dioxide (CO2) storage formations and caprocks could significantly alter the wettability of such formations into less water-wet conditions, decreasing the CO2-storage potential and containment security. Recent studies have attempted to infer the influence of the organic acid concentration on the wettability of rock–CO2–brine systems by measuring advancing and receding contact angles. However, no studies have investigated the influence of organic acid contamination on CO2-storage capacities from rock-fluid interfacial tension (IFT) data because solid-brine and solid-CO2 IFT values cannot be experimentally measured. Equilibrium contact angles and rock-fluid IFT datasets were used to evaluate the viability of CO2 storage in storage rocks and caprocks. First, the contact angles of rock in brine-CO2 systems were measured to compute Young's equilibrium contact angles. Subsequently, rock-brine and rock-gas IFT values at CO2 geo-storage conditions were computed via a modified form of Neumann's equation of state. For two storage-rock minerals (quartz and calcite) and one caprock mineral (mica), the results demonstrated high CO2-brine equilibrium contact angles at high pressure (0.1–25 MPa) and increasing concentrations of stearic acid (10−5 to 10−2 mol/L). Rock-brine IFT increased with the increased stearic acid concentration but remained constant with increased pressure. In all conditions, the order of increasing hydrophobicity of the mineral surfaces is calcite > mica > quartz. At 323 K, 25 MPa, and a stearic acid concentration of 10−2 mol/L, quartz became intermediate-wet with a CO2-brine equilibrium contact angle of 89.8°, whereas mica and calcite became CO2-wet with CO2-brine equilibrium contact angles of 117.5° and 136.5°, respectively. This work provides insight into the effects of organic acids inherent in CO2 geo-storage formations and caprocks on rock wettability and rock-fluid interfacial interactions.
    • A coupled phase-field and reactive-transport framework for fracture propagation in poroelastic media

      PENA CLAVIJO, Santiago; Addassi, Mouadh; Finkbeiner, Thomas; Hoteit, Hussein (Wiley, 2022-04-03) [Preprint]
      We present a novel approach to model hydro-chemo-mechanical responses in rock formations subject to fracture propagation within chemically active rock formations. The developed framework integrates the mechanisms of reactive transport, fluid flow and transport in porous media, and fracture propagation in poroelastic media using the phase-field model. The solution approach integrates the geochemical package PHREEQC with a finite-element open-source platform, FEniCs. Thereby, the PHREEQC solver is used to calculate the localized chemical reaction, including solid dissolution/precipitation. The resulting solid weakening by chemical damage is estimated from the reaction-induced porosity change. The proposed coupled model was verified with previous numerical results and applied to a synthetic case exhibiting hydraulic fracturing enhanced with chemical damage. Simulation results suggest that mechanical failure could be accelerated in the presence of ongoing chemical processes due to rock weakening and porosity changes, allowing the nucleation, growth, and development of fracture
    • Analytical Modelling and Simulation of Drilling Lost-Circulation in Naturally Fractured Formation

      Albattat, Rami (2022-04) [Dissertation]
      Advisor: Hoteit, Hussein
      Committee members: Patzek, Tadeusz; Sun, Shuyu; Yotov, Ivan
      Drilling is crucial to many industries, including hydrocarbon extraction, CO2 sequestration, geothermal energy, and others. During penetrating the subsurface rocks, drilling fluid (mud) is used for drilling bit cooling, lubrication, removing rock cuttings, and providing wellbore mechanical stability. Significant mud loss from the wellbore into the surrounding formation causes fluid lost-circulation incidents. This phenomenon leads to cost overrun, environmental pollution, delays project time and causes safety issues. Although lost-circulation exacerbates wellbore conditions, prediction of the characteristics of subsurface formations can be obtained. Generally, four formation types cause lost-circulation: natural fractures, and induced fractures, vugs and caves, and porous/permeable medium. The focus in this work is on naturally fractured formations, which is the most common cause of lost circulation. In this work, a novel prediction tool is developed based on analytical solutions and type-curves (TC). Type-curves are derived from the Cauchy equation of motion and mass conservation for non-Newtonian fluid model, corresponding to Herschel-Bulkley model (HB). Experimental setup from literature mimicking a deformed fracture supports the establishment of the tool. Upscaling the model of a natural fracture at subsurface conditions is implemented into the equations to achieve a group of mud type-curves (MTC) alongside another set of derivative-based mud type-curves (DMTC). The developed approach is verified with numerical simulations. Further, verification is performed with other analytical solutions. This proposed tool serves various functionalities; It predicts the volume loss as a function of time, based on wellbore operating conditions. The time-dependent fluid loss penetration from the wellbore into the surrounding formation can be computed. Additionally, the hydraulic aperture of the fracture in the surrounding formation can be estimated. Due to the non-Newtonian behavior of the drilling mud, the tool can be used to assess the fluid loss stopping time. Validation of the tool is performed by using actual field datasets and published experimental measurements. Machine-Learning is finally investigated as a complementary approach to determine the flow behavior of mud loss and the corresponding fracture properties.
    • Paragenesis of a Pleistocene Carbonate Island in the African-Arabian Desert Belt (Al-Wajh Carbonate Platform Lagoon, NE Red Sea, Saudi-Arabia)

      Chirakal, Tojo; Petrovic, Alexander; Oyinloye, Michael; Vahrenkamp, Volker (Copernicus GmbH, 2022-03-28) [Presentation]
      Quaternary carbonate islands have contributed significantly to the fundamental understanding of the interplay between climate and early diagenetic processes in carbonates. However, most of the studied islands, such as the carbonate islands on the Great Bahamas Bank, are situated in humid climate zones. Contrary to this, the Al-Wajh carbonate platform, situated within the arid African-Arabian desert belt on the NE Red Sea shelf (Saudi-Arabia), hosts a plethora of poorly studied carbonate islands. These islands were likely formed during the Last Interglacial (LIG) sea level highstand, commonly defined by Marine Isotope Stage 5e (MIS 5e: 124 – 119 ka). As such, these islands provide an excellent opportunity to give new insights into the paragenesis of carbonate islands within an arid climatic setting and an overall regressive/transgressive sequence. This study investigates Shurayrah Island, located in the southern part of the Al-Wajh platform lagoon. Shaped by the prevailing NW wind direction, Shurayrah Island has an elongated shape, while a reef belt is established on the upwind NW side and carbonate sand spits accumulate on the leeward SE side. The main data base consisted of five drill cores with a total recovered length of 61 m and 150 thin sections. Eight lithofacies (LFT) and 17 microfacies types (MFT) were differentiated, including, amongst others, coral framestones, coral float- & rudstones and ooid-bioclast grainstones. Diagenetic analysis was based on a detailed petrographic investigation, while porosities (Φ) were measured from thin sections with digital image analysis (n = 150) and core plugs using a helium porosimeter (n = 102). Results reveal generally high porosities (mean Φ from thin sections = 29 %; mean Φ from core plugs = 45 %). Pore types are dominated by primary pores in the growth framework of coral framestones and secondary moldic & vuggy pores. Dissolution features are most pronounced in coral framestones, which show almost complete dissolution of original aragonite microstructures. Cement types include dog tooth, pore-filling and bladed cements, with a dominance of dog tooth cements in terms of frequency. Aragonite fibrous cements only occur scarcely and can be overgrown by dog tooth cements. Additionally, dog tooth and bladed cements are frequently observed to grow inside moldic pores. The diagenetic analysis clearly reveals a dominance of porosity creating processes (dissolution) vs. porosity reducing processes (cementation) during paragenesis. In addition, results emphasize the importance of facies-controlled diagenesis: high primary porosities combined with metastable mineral composition of aragonite in coral framestones, result in a high meteoric diagenetic potential. Cement stratigraphy indicates a shift in the diagenetic realm, transitioning from marine (MIS 5e) to meteoric (MIS 5d – MIS 2) conditions, followed by a return to a marine setting with the Holocene Transgression (MIS 1). The overall strong meteoric diagenetic overprint suggests the influence of temporary humid phases (MIS 5c & a), during the overall >100 ka long subaerial exposure period. The observations highlight the significance of short-term climate fluctuations introducing meteoric waters for the diagenesis of carbonate islands in arid climate belts.
    • Micritization and Microbial-related Diagenetic Features in Modern Shallow Marine Carbonates (Red Sea, Arabian Sea and Arabian Gulf)

      Teillet, Thomas; Hachmann, Kai; Chandra, Viswasanthi; Garuglieri, Elisa; Odobel, Charlene; Areias, Camila; Sánchez-Román, Mónica; Vahrenkamp, Volker (Copernicus GmbH, 2022-03-28) [Presentation]
      Pores smaller than 10 microns in diameter (microporosity) can make up more than 90% of the total porosity in giant Arabian carbonate reservoirs. While a lot of research has been done to understand the distribution of microporosity, the diagenetic processes initiating its development are still debated. Since microporosity occurs in highly diagenetically overprinted rocks the involvement of early syn-sedimentary processes are generally overlooked. Micritization is a process happening during early diagenesis in the first centimeters of depth in which parts of carbonate grains are reworked to cryptocrystalline textures. The fundamental drivers of micritization are still somewhat debated, however, more and more evidence points to the involvement of microbes such as cyanobacteria, algae, or fungi. So, how can we decipher the diagenetic sequence that ancient limestones have experienced and predict microporosity distribution if the initial steps are poorly understood? The hypothesis driving this research places microbial micritization as the first step toward the creation of microporosity in limestones. Here, we present the first results undertaken as part of a multidisciplinary research project, at the interface of geology and microbiology and coupling field sampling and laboratory experiments. We compare the rates of micritization and the variety of microbial-related diagenetic features encountered between different carefully selected intertidal locations from the Red Sea and Arabian Sea (Saudi Arabia), and the Arabian Gulf (United Arab Emirates). A series of 1 m long sediment cores has been collected at low tide, and subsamples were extracted from every 10 cm for systematic petrographic and geochemical analyses. Thin section petrography revealed extensive microborings and associated micritization in the sediments. XRD analysis has been carried out to establish the mineral variations through the locations and depth, and SEM imagery further confirmed the presence of organic biofilms and mucous. The results from the metagenomic analysis revealed the microbial diversities and provide further understanding of the specific microbial drivers that play a key role in micritization processes. The work presented here hence aims to enhance the fundamental understanding of micritization in shallow marine carbonate sediment, the role of microbes in early diagenetic processes and their potential impact on microporosity development.
    • Modern Marine Stromatolites discovered in the NE Red Sea - Al Wajh carbonate platform, KSA

      Vahrenkamp, Volker; Garuglieri, Elisa; Petrovic, Alexander; Khanna, Pankaj; Chandra, Viswasanthi; Marasco, Ramona; Van Goethem, Marc Warwick; Daffonchio, Daniele (Copernicus GmbH, 2022-03-27) [Preprint]
      Stromatolites are the vestige of first life on earth and were the dominating carbonate forming marine biota in the Archean and Proterozoic.&#160; During the course of the Phanerozoic their importance in producing carbonates has been reduced to niche occurrences usually found in challenging environments, such as hypersaline marine settings and alkaline lakes.&#160; Most recently, the discovery in 2010 of a new chlorophyll type - chlorophyll f - from stromatolites in Hamelin Pool in Shark Bay, Western Australia has sparked much additional interest in the genesis and composition of modern stromatolites. &#160;</p><p>We report the discovery of stromatolites in the NE Red Sea on Sheybara Island, Al Wajh carbonate platform, KSA.&#160; Based on satellite and drone surveys calibrated by site surveys, the Red Sea stromatolites are distributed over an area of about 50,000 m<sup>2</sup> in an intertidal to very shallow subtidal setting on a paleo-reef flat facing the open sea.&#160; Two principal growth shapes are recognized: (i) elongated rhomboidal structures 10-100 cm in length, up to 5-50 cm in width and up to 10 cm in height and (ii) low relief (height <3 cm) irregular shaped tabular sheets in the shallow subtidal environment.&#160; The rhomboidal intertidal stromatolites are pustular on the outside and laminated internally. X-ray CT scanning of the stromatolite samples showed moderately well laminated, millimeter scale, lithified layers potentially representing alternating modes of sedimentation and growth. Scanning Electron Microscopy (SEM) revealed that laminae consist of heavily bored carbonate grains, calcified tubes of filamentous cyanobacteria, mucoid sheets and spider-web like organic matter of likely dehydrated extracellular polymeric substance (EPS).&#160; Carbonate precipitates of sub-micron size equant crystals and elongated aragonite needles, either occurring as single rods or in mashes, were also apparent from SEM. Molecular analysis of bacteria diversity show that cyanobacteria dominate the stromatolite surface, while heterotrophic bacteria are the main component in deeper layers.</p><p>During a sampling campaign in March 2021 salinity, pH and dissolved oxygen have been measured with average values at 42ppt, 7.8&#177;0.1 and 5.9&#177;0.5mg/L, respectively, typical for coastal Red Sea surface marine waters.&#160; Water temperatures range from 18&#176;C in the winter to 29&#176;C in the summer.&#160; During exposure at low tides surface temperatures over the tidal flats may fall as low as 12&#176;C in the winter exceeding 43&#176;C in the summer.&#160; Large numbers of cerithid gastropods were found grazing on the stromatolite surfaces apparently not affecting their growth.</p><p>Hence, the setting and conditions are overall similar to some of the stromatolites found on the Exuma Islands in the Bahamas, the only other known occurrence of stromatolites in normal marine waters.&#160; Research is continuing on the environmental conditions, the aerial distribution, the microbial diversity and chemical composition of these modern stromatolites to determine why they form in this particular location and if they are similar or not to other reported occurrences of stromatolites.
    • CO2 injection and storage for geothermal power generation in hydrothermal reservoirs along the Red Sea of Western Saudi Arabia

      Yalcin, Bora; Ezekiel, Justin; Arifianto, Indra; Mai, Paul Martin (Copernicus GmbH, 2022-03-27) [Presentation]
      As an alternative to water, CO2 can be used for heat mining from geothermal reservoirs, while also trapping most of the injected CO2 underground. In addition, supercritical CO2 has higher mobility and heat capacity than water, rendering CO2 capture, utilization and storage (CCUS) in geothermal reservoirs a very attractive option in a circular carbon economy. CCUS is also in line with Saudi Vision 2030, which includes the strategic framework to reduce Saudi Arabia’s dependence on hydrocarbons and diversify its economy. The western coast of Saudi Arabia, where the young and high-heat-flow Red Sea rift basins are located, are considered suitable for geothermal heat extraction and CO2 storage. In this study, we explore the potential of CCUS for geothermal power generation and CO2 storage in the hydrothermal reservoirs of Al Wajh basin located on the Red Sea coast. Geological studies in Al Wajh basin report that the hot fluid bearing, thick, porous, siliciclastic formations, such as Al Wajh (formation’s top depth, TD= 3900 meters), Burqan (TD = 2880 m) and Jebel Kibrit (Umluj member with TD = 1930 m) are sealed by the overlying anhydrite (Kial) and salt formations (Mansiyah). We combine publicly available data with different resolution scales, such as satellite gravity, seismic sections and well-log information to build a 3D geologic model, which enables us to constrain the 3D gross rock volume and the Net-to-Gross ratio/distribution of the target hydrothermal reservoirs. A 3D temperature model shows that the average surface temperature in the region and the subsurface temperature gradient create formation fluid temperature of over 120o C at 3 km depth. We conduct reservoir simulation of coupled transport of formation fluid, injected non-condensable gas (CO2) and heat in heterogeneous 3D reservoir model, using CMG STARS. We then estimate the geothermal energy extracting capacity and storage efficiency of CO2 in the prospective hydrothermal reservoirs in the Al Wajh basin. Our study provides the first semi-realistic reservoir model and simulation study in Saudi Arabia for combined CO2-based geothermal power generation and CO2 storage potential at a designated target site. The work-flow we propose is transferable to other suitable hydrothermal reservoirs in different locations in Saudi Arabia, thereby enabling CCUS technology implementation along the Red Sea.
    • Giant polygonal Tepee structures discovered in the NE Red Sea - AL Wajh carbonate platform, KSA

      Vahrenkamp, Sarima; Panagiotou, Marika; Petrovic, Alexander; Khanna, Pankaj; Chandra, Viswasanthi; Vahrenkamp, Volker (Copernicus GmbH, 2022-03-27) [Presentation]
      Carbonate tepee structures are believed to initiate through cement growth in shallow marine hardgrounds causing lateral expansion and leading to upward buckling of cemented layers commonly along polygonal boundaries. They reportedly form in subtidal to supratidal marine settings and are stratigraphically important markers for exposure and cycle boundaries in ancient rock sequences. Yet in modern carbonate settings only minor occurrences have been reported from the Arabian Gulf in Abu Dhabi and Qatar as well as in Australia. We have discovered two spectacular fields of giant polygonal tepee structures on Sheybara Island, a part of the Al Wajh carbonate platform in the NE Red Sea, KSA. Satellite and drone data were used to measure the dimensions of polygons. Samples have been collected from three transects and two boreholes for age dating, petrographic and geochemical analysis. The tepee fields cover an area of 420,000 m2 and 130,000 m2, respectively, in the supratidal to intertidal environment on the ocean facing side of the island. Individual tepees are composed of chaotically superimposed rugged slabs reaching 3-10 cm in thickness. Tepee ridges range in height from 10-50 cm. Tepees are aligned along larger structures of well-defined polygonal shapes. Their diameters range from 5m to 55m (n =100) with the majority having a diameter of 10-25 m (n=69). Peculiar to many polygons is a central domal buckle with extensional fracture patterns. The tepees have formed in a well-cemented layer of shallow marine bioclastic sand to gravel-sized sediments composed predominantly of coral, red algae, benthic foraminfera, bivalve and gastropod debris that overlie a paleo-reef flat. Grains are heavily micritized, cemented by clotted micrite and fibrous to acicular rim cements and occasionally covered by lace-like meshes of organic matter, likely indicating microbial activity. SEM images from tepee samples show evidence for the presence of microbial activity - biofilms, morphologies that strongly resembles filamentous and coccoidal cyanobacteria, and mineralized cyanobacterial mats. Environmentally corrected C14 age data indicate that polygons formed between 3000 to 1000 years before present (b.p.) correlating with a sealevel regression from a mid-Holocene sealevel highstand some 4000 to 5000 years b.p. Dead and blackened finger corals commonly encrust tepees indicating that the elevated tepee crusts provide preferential seeding for coral colonialization upon re-submergence.
    • Fracture networks in a Late Jurassic Arab-D reservoir outcrop analogue, Upper Jubaila Formation, Saudi Arabia.

      Panara, Yuri; Khanna, Pankaj; Chandra, Viswasanthi; Finkbeiner, Thomas; Vahrenkamp, Volker (Copernicus GmbH, 2022-03-26) [Preprint]
      Fracture networks are responsible for channeling flow in subsurface reservoirs (hydrocarbon or geothermal) and markedly impact well productivity and ultimate recovery. Yet, methods to provide fracture (network) distribution at sufficiently high resolution are still lacking – mainly because subsurface data do not adequately capture natural fractures at the mesoscale (cm to m in size) beyond the well bore. In this study we utilize an outcrop analogue to bridge this scale gap. Over the last decades 3D digital photogrammetry drastically improved in terms of measurement amount and quality enabling the collection of large data sets over wide outcrops. Such data provide critical insights on depositional and structural heterogeneities that may then be utilized for reservoir analogue simulations. Subject of this study is an outcrop in Wadi Laban located in SW Riyadh, Saudi Arabia, along the Mecca-Riyadh highway. We constructed a reliable 3D Digital Outcrop Model (DOMs) at high resolution of the Late Jurassic (Kimmeridgian) Upper Jubaila Formation following a ~800m long escarpment without any occlusion or bias. In particular we reconstruct a colorized dense point cloud using the high-quality setting of Agisoft Metashape© software. We investigated DOMs with CloudCompare© software (CloudCompare, 2021) to map the visible fractures 3D exposure and infer general fractures pattern. Four fracture sets are evident in the data: the predominant sets 1 and 2 are roughly E-W oriented, while sets 3 and 4 are roughly NNE-SSW oriented. Most fractures are strata bound and sub-vertical in nature. Fracture intensity (P21) analysis along the entire outcrop enables us to describe and quantify lateral and vertical variability. Laterally natural fractures are concentrated in corridors with a spacing of few tens of meters. Vertically, fracture intensity is heterogeneous. Furthermore, we found a strong correspondence between fracture intensity on the outcrop and a porosity log acquired on core samples from a well drilled only a few meters behind the outcrop. The outcome of this study provides a step forward for the comparison of outcrop and subsurface fractures, and expand the application of outcrop data to generate high resolution and fidelity reservoir analogue models.
    • An Experimental and Numerical Approach for the Best Enhanced Oil Recovery Strategy in Capillary-Dominant Reservoirs

      Alabdulghani, Ahmad; Hoteit, Hussein; Abdullah, King (OTC, 2022-03-18) [Conference Paper]
      Working with naturally fractured reservoirs (NFRs) can be challenging. Inadequate understanding of the enhanced oil recovery (EOR) driving forces in these reservoirs may result in serious conformance issues due to excessive water production. As a result, this work investigates and numerically validates some fundamental flow mechanisms in heterogeneous reservoirs, particularly capillary-dominant ones, to highlight the best EOR strategy for this specific case. Consequently, a two-dimensional lab-scale reservoir model with injection and production ports was designed, fabricated, and tested in single-phase and two-phase flow scenarios, simulating a water-wet fractured system. First, a single-phase flow waterflood baseline was studied, compared to the literature, verified by commercial reservoir simulation software, and eventually considered to calibrate the porosity and permeability model in the simulation model where the controlling variables are limited. Based on this work, the same procedures were experimentally repeated and verified by simulation, where waterflooding and polymer injection were used to displace oil with more governing variables. The single-phase scenarios aided in distinguishing between the waterflood and polymer flood cases. Water prefers to channel through high permeable streaks when injected into a fractured water-wet reservoir, resulting in poor volumetric sweep and significant bypassed zones. Whereas the controlling variables in two-phase flow were increased, capillarity and mobility ratio were dominant in the simulation. During waterflooding, flow divergence was observed faster toward the matrix medium, overriding the high permeability front in the fracture due to the strong capillarity contrast between the matrix and fracture media. Even when capillarity is strongly present, polymer flooding demonstrated a better volumetric sweep in all scenarios. The unique demonstration of fluid flow inside the two-dimensional lab-scale reservoir model, as well as numerical simulation, shed light on the efficacy of these EOR strategies in fractured reservoirs. Furthermore, for the first time, the behavior of capillary-dominant reservoirs with an advancing flow path within smaller pores compared to larger ones within the reservoir media has been experimentally captured. Understanding reservoir characteristics and having the know-how to implement the best recovery scenario can, in fact, maximize the field's life cycle and increase the Recovery Factor (RF).