Middle devonian-lower frasnian natural hydrocarbon reservoirs of the Pechora Sea shelf and Timan-Pechora oil and gas province adjacent area

The research is based on the three-layer natural hydrocarbon reservoirs theory, which allocates 3 layers in a natural reservoir – the genuine seal, the productive part and the intermediate layer situated between them - the false seal. The Middle Ordovician-Lower Frasnian terrigenous complex variable in thickness, composition and stratigraphic completeness sub-regional natural reservoir was identified in the northern part of the Timan-Pechora oil and gas province adjacent to the Pechora Sea. It includes several zonal and local natural reservoirs (Middle Ordovician-Lower Devonian, Middle Ordovician-Eiffelian, Zhivetian-Lower Frasnian and others). The distribution areas of these natural reservoirs were extrapolated to the Pechora Sea offshore. The areas with the highest prospects of oil and gas potential of the Pechora Sea offshore were delineated, basing on the Timan-Pechora oil and gas potential analysis. These are the northwest extensions into the Pechora Sea of the Denisov trough, the Kolva megaswell, as well as the Varandei-Adzva structural zone and the Karotaiha depression. Keywords: natural reservoir; genuine seal; false seal; field; pool; hydrocarbons.

Rapid microbial methanogenesis during CO2 storage in hydrocarbon reservoirs

Carbon capture and storage (CCS) is a key technology to mitigate the environmental impact of carbon dioxide (CO2) emissions. An understanding of the potential trapping and storage mechanisms is required to provide confidence in safe and secure CO2 geological sequestration1,2. Depleted hydrocarbon reservoirs have substantial CO2 storage potential1,3, and numerous hydrocarbon reservoirs have undergone CO2 injection as a means of enhanced oil recovery (CO2-EOR), providing an opportunity to evaluate the (bio)geochemical behaviour of injected carbon. Here we present noble gas, stable isotope, clumped isotope and gene-sequencing analyses from a CO2-EOR project in the Olla Field (Louisiana, USA). We show that microbial methanogenesis converted as much as 13–19% of the injected CO2 to methane (CH4) and up to an additional 74% of CO2 was dissolved in the groundwater. We calculate an in situ microbial methanogenesis rate from within a natural system of 73–109 millimoles of CH4 per cubic metre (standard temperature and pressure) per year for the Olla Field. Similar geochemical trends in both injected and natural CO2 fields suggest that microbial methanogenesis may be an important subsurface sink of CO2 globally. For CO2 sequestration sites within the environmental window for microbial methanogenesis, conversion to CH4 should be considered in site selection.

Sedimentology and Evolution of the Fluvial-Deltaic System: A Modern Depositional Model Analog from the Red Sea Coastal Region, Saudi Arabia

Siliciclastic sediments represent important lithological unit of the Red Sea coastal plain. Their subsurface equivalents are important targets of groundwater aquifer and hydrocarbon reservoirs in the region. The lithofacies of the modern fluvial deltaic system has several distinct geomorphic units and sub-environments such as alluvial, fluvial, delta plain, aeolian, intertidal, coastal sabkha and eustuarine sediments. This study intends to characterize the lithofacies and the depositional environments and to produce an integrated facies model for this modern fluvial-deltaic system. The study might provide a valuable modern analog to several important subsurface Neogene formations that act as important hydrocarbon reservoirs and groundwater aquifers. The study integrates information and data obtained from landsats, maps and detailed field observation and measurements of facies analysis of the fluvial and deltaic along traveses from the Arabian Shield to the Red Sea coast. The lithofacies sediment analysis revealed four main lithofacies associations namely lithofacies A,B,C ad D. Lithoacies Associations A, which represents the oldest unit is dominated by coarse gravel with minor sands facies. While the lithofacies B is dominated byfine gravel and sand lithofacies, occasionally pebbly, vary from horizontal, planar to massive sands with minor laminated to massive silts and mud facies. The lithofacies in A and B show lateral proximal to distal variation as well as characteristic vertical stacking patterns. The Facies Association A and B indicates a change in fluvial depositional styles from gravelly alluvial fans to gravelly sandy fluvial systems. The lithofacies association C represents the recent fluvial system which consists of minor gravel lag deposits associated maily with various sand lithofacies of planner, horizontal and massive sand associated with massive and limainted sand and mud lithofacies. The lithofacies Association D is dominated with Barchan sand dunes local interfigger with muddy iinterdunes and sand sheets. Lithofacies D occupies rather more distal geomporphic position of the fluvial deltaic system that is adjace to coastal sabkha. The lithofacies associations described here document the evolution and development of the coastal plain sediments through space and time under various autocyclic and allocyclic controls. This included the tectonics and structural development associated with the Red Sea rifting and opening since the Oligocene – Miocene time. Others controls include the evolution of the Arabian shield (provenance) and the coastal plain through space and time as controlled by tectonics, sediment supply, climate and locally by autocyclic environmental This study might be beneficial for understanding the controls and stratigraphic evolution of the Red Sea region and will be of great value for reservoir and aquifer characterization, development and management. This modern analog model can also help in providing geological baseline information that would be beneficial for understanding similar ancient fluvial deltaic sediments. The study might provide guides and leads to understand the subsurface facies, stratigraphic architecture and heterogeneity of any potential groundwater aquifers and hydrocarbon reservoirs.

Evaluating Phase Blockages and Mobility Changes During Pressure Transient Analysis

Pressure transient analysis (PTA) is a cogent methodology to evaluate dynamics of hydrocarbon reservoirs. Numerous analytical and numerical models have been developed to model various types of wellbore, reservoir, and boundary responses. However, the near-wellbore region remains to be perplexing in pressure transient analysis. In this paper we investigate the pressure transient behavior of phase blocking and mobility variations caused by fluid phase interactions or properties, such as viscous drag forces and surface tension at the near-wellbore region and their impact on pressure transient evaluation. We have used real field examples to scrutinize relative effects of mobility variations in pressure transients. The impact of capillary number (Nc) acting on the near-wellbore region and its influence on pressure transient behavior and skin alteration were examined in detail. Several real field examples honoring actual reservoir rock special core analysis (SCAL) and fluid pressure/volume/temperature (PVT) properties have been studied. Actual field data discussed in this paper for PTA were captured during drill stem testing (DST) operations from various hydrocarbon reservoirs in the Berkine Basin of Algeria. PVT laboratory-measurement-based fluid properties were used in conjunction with tuned equation of state (EOS) models to ensure consistency between wells and reservoirs. Pressure transient analysis of a gas condensate reservoir system can depict various mobility regions, especially while flowing below dew point pressure. In some cases, three-distinct-mobility regions can be identified as: a far-field zone with initial gas and condensate saturation; a mid-field zone with increased condensate saturation and lower gas relative permeability; and a near-wellbore zone with high Nc which increases gas relative permeability and mobility. These three-distinct-mobility regions form due to condensate dropping out and fluid interactions in the near wellbore. We demonstrate, with real-life field examples of the near-wellbore region, how the relative effects of viscous drag forces and surface tension forces acting across the liquid and gas interface can enable the reference fluid phase to regain its mobility. We further investigate the evaluation of skin factor in such circumstances and show how the existence of phase blocking and velocity stripping can cause over-estimation or under-estimation of skin factor. We present a novel set of real field examples and relations between various zones in hydrocarbon reservoirs to avoid snags of misleading pressure transient interpretations and how composite models can be accurately used to represent complex cases. Field examples from Algerian hydrocarbon reservoirs are depicted. The findings could be easily applied for similar reservoirs in other parts of the globe to identify and model such intricate systems.

Large Scale Placement For Multilateral Wells Using Network Optimization

Multilateral wells are an evolution of horizontal wells in which several wellbore branches radiate from the main borehole. In the last two decades, multilateral wells have been increasingly utilized in producing hydrocarbon reservoirs. The main advantage of using such technology against conventional and single-bore wells comes from the additional access to reservoir rock by maximizing the reservoir contact with fewer resources. Today, multilateral wells are rapidly becoming more complex in both designs and architecture (i.e., extended reach wells, maximum reservoir contact, and extreme reservoir contact wells). Certain multilateral design templates prevail in the industry, such as fork and fishbone types, which tend to be populated throughout the reservoir of interest with no significant changes to the original architecture and, therefore, may not fully realize the reservoir's potential. Placement of optimal multilateral wells is a multivariable problem, which is a function of determining the best well locations and trajectories in a hydrocarbon reservoir with the ultimate objectives of maximizing productivity and recovery. The placement of the multilateral wells can be subject to many constraints such as the number of wells required, maximum length limits, and overall economics. This paper introduces a novel technology for placement of multilateral wells in hydrocarbon reservoirs utilizing a transshipment network optimization approach. This method generates scenarios of multiple wells with different designs honoring the most favorable completion points in a reservoir. In addition, the algorithm was developed to find the most favorable locations and trajectories for the multilateral wells in both local and global terms. A partitioning algorithm is uniquely utilized to reduce the computational cost of the process. The proposed method will not only create different multilateral designs; it will justify the trajectories of every borehole section generated. The innovative method is capable of constructing hundreds of multilateral wells with design variations in large-scale reservoirs. As the complexity of the reservoirs (e.g., active forces that influence fluid mobility) and heterogeneity dictate variability in performance at different area of the reservoir, multilateral wells should be constructed to capture the most productive zones. The new method also allows different levels of branching for the laterals (i.e., laterals can emanate from the motherbore, from other laterals or from subsequent branches). These features set the stage for a new generation of multilateral wells to achieve the most effective reservoir contact.

A site assessment tool for H2 storage in depleted hydrocarbon reservoirs

Hydrogen storage is a key component in realization of an emission free future. Depleted hydrocarbon reservoirs offer a low cost medium for large-scale hydrogen storage. While the effect of hydrogen in triggering some chemical and biochemical reactions has stablished some screening criteria to choose a suitable underground storage site according to reservoir geochemistry, there is no screening criteria based on the effect of variables such as pressure, temperature and composition of the residual hydrocarbon on hydrogen recovery. In this work, we first investigate the cost required for hydrogen compression in terms of the work required for compressors. Then we investigate the effect of reservoir pressure, storage pressure, reservoir temperature and residual composition on hydrogen recovery. Our results show that on one hand the work required for pressurizing hydrogen does not increase linearly with pressure, and on the other hand, hydrogen recovery increases with storage pressure. Additionally, Hydrogen recovery was shown to decrease by increase in reservoir initial pressure before hydrogen storage. Therefore, it seems that hydrogen storage will be more efficient if it is conducted at the highest possible pressure in a reservoir with low initial pressure (either a shallow reservoir, or a depleted reservoir). Our results did not show any strong relationship between hydrogen recovery and temperature. Hydrogen recovery showed to increase slightly with increase in residual hydrocarbon density. However, the effect of residual hydrocarbon was observed to be significant on purity of the produced hydrogen. In this sense, depleted black oil reservoirs seem to be the best and dry gas reservoirs the worst choice.

Leaky Waveguides in Hydrocarbon Reservoirs and their Implications for Oil Banks Detection

The presence of naturally occurring subsurface waveguides for electromagnetic (EM) waves has been previously documented. In particular, the mining industry recognized that a coal seam bounded by layers of conductive rock acts as a leaky waveguide. Consequently, the attenuation constant and phase shift of EM signals propagating through the coal layer are modulated by the thickness of the coal and the EM properties of the three layers forming the leaky waveguide. The radio imaging method (RIM) was developed based on this discovery to characterize coal deposits. Recent studies have demonstrated that guided waves can provide useful information about the subsurface. Structures with similar dimensions and EM properties are found in oil fields in the form of layers of evaporite (e.g. anhydrite) bounded by hydrocarbon reservoirs. To the best of our knowledge, the feasibility of exploiting such structures to characterize the inter-well region has not been investigated extensively. We conducted a theoretical analysis and 3D numerical simulations in the time and frequency domains to demonstrate that layered structures in oil fields can act as leaky waveguides and efficiently guide EM waves. Our results suggest that such structures substantially enhance the propagation of MHz EM signals. Among multiple parameters evaluated, the conductivity of the layers has the most significant effect on signal attenuation, and thus its range of propagation. We estimated that EM signals of approximately 10 MHz can propagate several hundreds of meters through a layer of anhydrite in the presence of conductive bounding reservoirs. The received signals are affected by the properties of the anhydrite layer, but also by the properties of the bounding reservoirs, conferring sensitivity to changes in reservoir saturation. We conclude that this approach could be further developed to infer fluid saturation and especially to identify the presence of oil banks in water-flooded hydrocarbon reservoirs.