Facies models of hydrocarbon-bearing formations of Podneytinskiy reservoir at Bovanenkovskoye and Kharasaveyskoye fields

Background. Significant part of hydrocarbons at Bovanenkovskoye and Kharasaveyskoye fields are contained in Podneytinskiy reservoir, and study of geological features of its productive strata is important for development planning for the fields in a whole. Aim. The paper reflects the results of integrating well and seismic data to characterize the formations of Podneytinskiy reservoir at Bovanenkovskoye and Kharasaveyskoye fields. Materials and methods. As part of the study, sedimentological description of core was analyzed, the core, well logging and seismic survey information were assessed, and the facies schemes were prepared. Results. As a result of the work, the reservoir architecture features and the distribution of reservoir properties of the target interval were revealed. It has been established that the considered formations of Podneytinskiy reservoir can be divided into two parts, the lower one is represented by deposits of predominantly deltaic origin, and the upper one is of continental and subcontinental genesis. The sedimentary conditions of rocks influenced the complexity of their architecture, so, in the formations referred to the lower part of the studied interval, the reservoirs, as a rule, are laterally continuous, in contrast to the deposits of the upper part of the section, which are typically characterized by extremely high lateral heterogeneity. Depositional conditions also influenced the reservoir properties of productive sediments. As a result of the work, it was revealed that the reservoirs of better quality are formed in fluvial and tidal channels, distributary channels and proximal parts of deltas, they have higher reservoir properties, are characterized by thicker sandstone interlayers and lower portion of carbonated interlayers in comparison with reservoirs formed in other conditions. Conclusions. The article provides quantitative characteristics of reservoir properties depending on sedimentary conditions. The results obtained form the basis for creation of geological models of Bovanenkovskoye and Kharasaveyskoye fields.

Reservoir Architecture Modeling at Sub-Seismic Scale for a Depleted Carbonate Reef Reservoir for CO2 Storage in Sarawak Basin, Offshore Malaysia

It is still a challenge to build a numerical static reservoir model, based on limited data, to characterize reservoir architecture that corresponds to the geological concept models. The numerical static reef reservoir model has been evolving from the oversimplified tank-like models, simple multi-layer models to the complex multi-layer models that are more realistic representations of complex reservoirs. A simple multi-layer model for the reef reservoir with proportional layering scheme was applied in the CO2 Storage Development Plan (SDP) study, as the most-likely scenario to match the geological complexity. Model refinement can be conducted during CO2 injection phase with Measurement, Monitoring and Verification (MMV) technologies for CO2 plume distribution tracking. The selected reservoir is a Middle to Late Miocene carbonate reef complex, with three phases of reef growth: 1) basal transgressive phase, 2) lower buildup phase, and 3) upper buildup phase. Three chronostratigraphic surfaces were identified on 3D seismic reflection data as the zone boundaries, which were then divided into sub-zones and layers. Four layering methods were compared, which are ‘proportional’, ’follow top’, ‘follow base’ and ‘follow top with reference surface’. The proportional layering method was selected for the base case of the 3D static reservoir model and the others were used in the uncertainty analysis. Based on the results of uncertainty and risk assessment, a risk mitigation for CO2 injection operation were modeled and three CO2 injection well locations were optimized. The reservoir architecture model would be updated and refined by the difference between the modeled CO2 plume patterns and The MMV results in the future.

Reservoir Quality of the Miocene Formation Gas Deposits, Onshore Abu Dhabi

Understanding reservoir architecture is key to comprehend the distribution of reservoir quality when evaluating a field's prospectivity. Renewed interest in the tight, gas-rich Middle Miocene anhydrite intervals (Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6) by ADNOC has given new impetus to improving its reservoir characterisation. In this context, this study provides valuable new insights in geological knowledge at the field scale within a formation with limited existing studies. From a sedimentological point of view, the anhydrite layers of the Miocene Formation, Anh-1, Anh-2, Anh-3, Anh-4 and Anh-6 (which comprise three stacked sequences: Bur1, Bur2 and Bur3; Hardenbol et al., 1998), have comparable depositional organisation throughout the study area. Bur1 and Bur2 are characterised by an upward transition from intertidal-dominated deposits to low-energy inner ramp-dominated sedimentation displaying reasonably consistent thickness across the area. Bur3 deposits imply an initial upward deepening from an argillaceous intertidal-dominated to an argillaceous subtidal-dominated setting, followed by an upward shallowing into intertidal and supratidal sabkha-dominated environments. This Bur3 cycle thickens towards the south-east due to a possible deepening, resulting in the subtle increase in thickness of the subtidal and intertidal deposits occurring around the maximum-flooding surface. The interbedded relationship between the thin limestone and anhydrite layers within the intertidal and proximal inner ramp deposits impart strong permeability anisotropy, with the anhydrite acting as significant baffles to vertical fluid flow. A qualitative reservoir quality analysis, combining core sedimentology data from 10 wells, 331 CCA data points, 58 thin-sections and 10 SEM samples has identified that reservoir layers Anh-4 and Anh-6 contain the best porosity and permeability values, with the carbonate facies of the argillaceous-prone intertidal and distal inner ramp deposits hosting the best reservoir potential. Within these facies, the pore systems within the carbonate facies are impacted by varying degrees of dolomitisation and dissolution which enhance the pore system, and cementation (anhydrite and calcite), which degrade the pore system. The combination of these diagenetic phases results in the wide spread of porosity and permeability data observed. The integration of both the sedimentological features and diagenetic overprint of the Middle Miocene anhydrite intervals shows the fundamental role played by the depositional environment in its reservoir architecture. This study has revealed the carbonate-dominated depositional environment groups within the anhydrite stratigraphic layers likely host both the best storage capacity and flow potential. Within these carbonate-dominated layers, the thicker, homogenous carbonate deposits would be more conducive to vertical and lateral flow than thinner interbedded carbonates and anhydrites, which may present as baffles or barriers to vertical flow and create significant permeability anisotropy.

Microporosity of the Shuaiba Formation: The Link Between Depositional Character and Diagenesis in Sharjah, United Arab Emirates

Objectives/Scope This study focuses on assessing the uncertainties related to sedimentological heterogeneity and the diagenetic variability within the gas-condensate reservoirs of the Shuaiba Formation, Sharjah, United Arab Emirates. Methods, Procedures, Process For characterizing the sedimentology of the Shuaiba Formation, a lithofacies scheme has been developed on the basis of Dunham's (1962) and Embry & Klovan classification (1971). The lithofacies are grouped on the basis of their genetic relationships which also correspond to their depositional environment, and are designated as lithofacies associations. A pore-scale fabric/textural investigation was completed using conventional thin-section microscopy and Scanning Electron Microscopy (SEM). Results, Observations, Conclusions The Shuaiba sediments are characterized by skeletal-rich wackestone/packstones to floatstones deposited in an inner ramp setting. The stacking pattern of the inner ramp deposits define broad third order trends observed across the studied field.These trends are relatable to the regional sequence stratigraphic framework of Sharland et al. (2001). In higher order sequences, lateral variations in lithology occur, defining the reservoir heterogeneity, which are most likely forced by topographic/hydrodynamic variation as well as sea level changes. Reservoir quality distribution is controlled by various factors, including the depositional texture and allochem assemblage (abundance, type, and size). Diagenetic alteration of the textures played an important role in determining overall reservoir quality. The pore enhancing phases are defined by dissolution events, where later stage dissolution was the dominant phase to enhance micropores and also to create meso- to macropores which partially to completely negated the effect of previous cementing phases. In these Shuaiba deposits, the porosity comprises common matrix-hosted as well as grain-hosted micropores along with variably distributed intraparticle and rare mouldic meso- to macropores. The measured porosity ranges from very poor to moderate (0.5-17%) while permeability is very low to low (<0.001-1.49 mD). The detailed petrographic analysis highlighted that changes in micritic fabric shows a variation in the reservoir properties. From SEM observations, it was noted that microcrystalline calcite crystals of polyhedral to sub-rounded morphologies with intercrystalline contacts ranging from facial to sub-punctic, which display relatively a good microporosity developement, whereas crystals that show anhedral compact character with coalescent/fused intercrystalline contacts are rarely associated with any microporosity. Novel/Additive Information In addition to SEM characterization, porosity data and elastic properties (e.g., Young's moduli) generated from the interpretation of the well-log data, were used to investigate the prospective relationship between the microporous carbonates and elastic properties. The comparisons highlight that an increase in porosity values results in a decrease of Young's moduli values, thereby reflecting a decrease in the stiffness of the rock. On the other hand, the increase in porosity maybe linked to the evolution of anhedral, compact, micritic fabric to polyhedral/sub-rounded micritic fabric. The understanding of this relationship provides a powerful tool to be utilized in reservoir architecture prediction based on integrating the sedimentological framework and diagenetic overprint.

3D Integrated Structural, Facies and Petrophysical Static Modeling Approach for Complex Sandstone Reservoirs: A Case Study from the Coniacian–Santonian Matulla Formation, July Oilfield, Gulf of Suez, Egypt

The Coniacian–Santonian Matulla Formation is one of the important reservoirs in the July oilfield, Gulf of Suez Basin. However, this formation is characterized by uncertainty due to the complexity of reservoir architecture, various lithologies, lateral facies variations and heterogeneous reservoir quality. These reservoir challenges, in turn, affect the effectiveness of further exploitation of this reservoir along the Gulf of Suez Basin. In this work, we conduct an integrated study using multidisciplinary datasets and techniques to determine the precise structural, petrophysical, and facies characteristics of the Matulla Formation and predict their complex geometry in 3D space. To complete this study, 30 2D seismic sections, five digital well logs, and core samples of 75 ft (ft = 0.3048 m) length were used to build 3D models for the Matulla reservoir. The 3D structural model shows strong lateral variation in thickness of the Matulla Formation with NW–SE, NE–SW and N–S fault directions. According to the 3D facies model, shale beds dominate the Matulla Formation, followed by sandstone, carbonate, and siltstone beds. The petrophysical model demonstrates the Matulla reservoir's ability to store and produce oil; its upper and lower zones have good quality reservoir, whereas its middle zone is a poor quality reservoir. The most promising areas for hydrocarbon accumulation and production via the Matulla reservoir are located in the central, southeast, and southwest sectors of the oilfield. In this approach, we combined multiple datasets and used the most likely parameters calibrated by core measurements to improve the reservoir modeling of the complex Matulla reservoir. In addition, we reduced many of the common uncertainties associated with the static modeling process, which can be applied elsewhere to gain better understanding of a complex reservoir.

Introduction to this special section: Quantitative interpretation

Quantitative interpretation (QI) is the geophysicist's endeavor to go beyond reservoir architecture. It is the effort to use geophysical measurements in understanding reservoir properties such as rock type, porosity, and fluid composition. QI often refers to the use of seismic amplitude analysis to predict lithology, porosity, and pore fluids away from the wellbore in oil and gas reservoirs. However, we can generalize and expand the concept of QI beyond seismic methods and beyond oil and gas reservoirs. In this special section, we feature five papers and cover not only seismic and well-log data, but also gravity and magnetic data. We address a hydrothermal reservoir in addition to several oil and gas reservoirs.

Reservoir Architecture and Fluid Connectivity in an Abu Dhabi Oil Accumulation

Summary Developing an understanding of reservoir architecture and fluid connectivity is a challenging, but essential task for well, reservoir and facilities management (WRFM). Insight into fluid connectivity (both static and dynamic) can be obtained from molecular fingerprinting of crude oil samples. Oil fingerprinting is also applied for allocation of commingled fluid streams, and in time-lapse mode it can even help to understand fluid flow in the subsurface. Results from fingerprinting studies are directly used as constraints for static and dynamic reservoir models. A basic requirement for most fingerprinting applications is an understanding of the initial, pre-production fluid distribution. The limited availability of pre-production fluids has until now been a major constraint for the widespread application of oil fingerprinting in the industry. Reservoir rock samples contain enough residual hydrocarbons for fluid fingerprinting. Reservoir core and cuttings samples are widely available and thus provide an excellent opportunity to increase the spatial coverage of fluid fingerprints in a reservoir. A major challenge, however, is the accuracy and reproducibility of existing fingerprinting methods, which are insufficient in the chromatographic range of the ‘heavier’, non-volatile, hydrocarbons remaining in reservoir rock samples. This paper describes the application of a new, high resolution, molecular fingerprinting technology that resolves these limitations. This so-called Compound Class Specific Fingerprinting (CCSF) technique has unprecedented accuracy and reproducibility over the full analytical window, which makes it suitable for fingerprinting of both oils and extracts. An added benefit of this approach is that the additional compound class information may help to resolve why fluids are different, as not all differences are related to reservoir connectivity. As a first test, the new CCSF technology has been applied to fluid samples from an offshore field in Abu Dhabi. Two specific aspects are highlighted in this paper: Assessment of vertical compartmentalization and fault transmissibility of four stacked reservoirs in a highly fractured zone. Even in this highly fractured zone, a barrier to vertical fluid flow was identified between the top reservoir and the three underlying reservoirs, which contain slightly different oil. The improved resolution of the CCSF method, combined with the molecular information it provides, made it possible to demonstrate that the fluids in the lower reservoirs are vertically connected and that gravity segregation has created a compositional gradient. These conclusions could not have been reached with existing fingerprinting technologies. Identify opportunities for production monitoring. Some of the reservoirs in this field show strong compositional gradients related to the complex charge history and incomplete fluid mixing. Fluid surveillance of the mid-flank producers will help identify the efficiency of the gas and water injection schemes that are simultaneously applied to this reservoir. In addition, fluid surveillance will help to predict water and/or gas breakthrough.

Redefining Reservoir Architecture of Hydrocarbon-Bearing Ngrayong Formation in Banyu Urip Area:New Insights to Unravel Hidden Potential in East Java Basin

Results of Banyu Urip (BU) carbonate exploration, appraisal and development drillings revealed the existence of hydrocarbon-contained in Serravallian deep-water clastic reservoir on top of the primary BU carbonate reservoir. This clastic reservoir is equivalent to the Ngrayong Formation in East Java Basin which is widely known as a mature exploration target and consists of a wide range of depositional environment from fluvio-deltaic (northern part of the Basin) to basin floor (southern part of the basin) with various reservoir quality. However, after a century of exploration activities in East Java Basin, commercial discoveries in the Ngrayong Formation are still considered insignificant (approximately 330 MMboe) (Mazied et al. 2016). This probably due to complex reservoir architecture posted high uncertainty of its reservoir presence, distribution, and quality as well challenging on their dynamic aspects such as un-known hydrocarbon connectivity, un-even contacts and low-deliverability. This paper will present new insights and the potential of Ngrayong clastic opportunity in BU area based on static and dynamic data including BU wells, newly reprocessed 3D seismic data, conventional core and thin sections, as well as integrated geologic and geophysical analyses. Integration of the available dataset suggest the presence of stacked deep water channels and deep water lobes systems. The distribution of stacked channels and lobes seem to be more predictive and widespread, hence providing a better understanding of its reservoir distribution. Furthermore, well data indicates approximately total of 100m net stacked clastic reservoirs consist of mixed carbonate-clastic materials, and have good reservoir pressure connectivity with the carbonate reservoir underneath. This mixed clastic-carbonate system in Ngrayong Formation is diagenetically-altered, and this diagenesis process plays as an important roles in modifying reservoir quality. Although carbonate cement and diagenetic overprint impose challenging reservoir quality prediction, a dissolution creates better reservoir quality, generates excess permeability and produces high flow reservoir. Detail study of reservoir architecture and diagenesis process are critical to better assess volumetric and development opportunity. These key components will open up new paradigm and essential for successful of Ngrayong Formation exploration in East Java Basin in order to contribute to the country’s energy demand.

Uncertainty Management Using Multi-Scenario Modeling in a Partially Appraised Field

Considering the imminent end of the ‘easy oil’ era, the increasing demand for energy and the global push towards the energy transition, oil and gas companies are more than ever interested in sustainable ways to develop marginal and complex hydrocarbon fields economically, through the application of technology and maximization of data analysis. In small partially appraised fields where the cost of drilling an appraisal well could derail the project economics, it becomes necessary to sweat the limited data available for reservoir modelling. The uncertainty analysis must be robust enough to ensure that the adopted field development strategy would yield a positive net present value despite the wide uncertainties associated with the field. The conventional workflow for subsurface uncertainty modelling involves defining the uncertainty ranges of static and dynamic reservoir parameters based on a single reservoir model concept. This paper focuses on a marginal field case study where the multi scenario modelling approach was adopted. This approach considered alternate reservoir geologic concepts based on different interpretations of the reservoir architecture, taking full cognizance of the available data, reservoir uncertainties and regional geology knowledge. Field Alpha is located onshore of Niger Delta in Nigeria. The geologic setting consists mainly of multi-storey, complex channel-belt systems, incising through Shoreface deposits. The reservoir of interest is an elongated structure with only two well penetrations located at the opposite distal part of the structure. The key reservoir uncertainties are reservoir structure, architecture, connectivity, and property distribution. Two possible distinct architecture were interpreted based on regional correlation and seismic. This paper focuses on how the interpretations and other information informed a robust development strategy that yielded significant (30 %) reduction in development cost and positive net present value.