|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Abstract Carbonate reservoir characterization is often a complex task, due to the interplay between primary processes (e.g. depositional environments, facies changes) and secondary processes (e.g. burial, diagenesis, faulting and fracturing, cementation). In order to properly characterize and model such a reservoir, it is paramount to unravel the order by which such processes have affected the rock, leading to the present day petrophysical properties. In the presented case study (onshore dolomitized carbonate reservoir in Central Asia), a multi-step approach was taken for its characterization and modelling. The characterization phase was focused in understanding the key processes and controls on porosity and permeability. From the core and log data, a detailed sedimentologic and diagenetic study was performed, to identify the depositional environments and facies, as well as the pore system geometry, and its impact on fluid flow. Furthermore, several trends on reservoir quality were identified, related to faults, and associated with depositional cyclicity. From the above work, a reservoir model was built, to support field development planning and associated uncertainties. A structural and stratigraphic framework was built, and Flow Unit Types (FUT) were defined using seismic, cores, thin sections, logs and mercury injection capillary pressure data (MICP). Property modelling was carried out for porosity and permeability, honouring FUT, depositional and diagenetic trends. In particular, two trends were modelled: a fault-related trend, to introduce the impact of diagenetic leaching related to faults (observed in core data); and a cyclicity related trend, to introduce the impact of preferential fluid flow pathways that occur at or near cycle tops. The uncertainty in the reservoir property models was evaluated with different FUT, driven by depositional and diagenetic concepts. The results indicate that a significant improvement in reservoir understanding can be achieved with the use of an integrated study and model workflow, focusing on the key control factors that affect the pore system and the distribution of permeability. In this way it was possible to recognize spatial trends and capture the relationship between petrophysical properties, pore architecture and sweep efficiency.
Abstract Reservoir characterization and modelling of highly heterogeneous carbonate reservoirs encompasses the interplay between petrophysical properties, facies, diagenesis, and their relationship with depositional environments. This case study describe a strongly dolomitized carbonate reservoir of Valanginian age onshore Kazakhstan, Central Asia. A reservoir model was built by using an integrated workflow with all the available data, namely seismic, cores, thin sections, logs and MICP. In order to build a robust subsurface model and reduce uncertainties, reservoir rock types (RRTs) were defined and modelled honouring depositional trends and diagenetic attributes. Due to the complexity of the reservoir, the Winland R35 method, together with Lorenz plots and petrophysical groups, was used to derive the RRTs and to assign a porosity-permeability relationship for each RRT. The uncertainty in the reservoir property models was evaluated with different RRT connectivity scenarios, driven by depositional and diagenetic concepts. With the integration of diagenetic trends in the model, it was possible to capture the heterogeneity of the reservoir and better understand the porosity and permeability distributions. This has led to development plan optimization through the definition of sweet spot areas and an improved STOIIP calculation. The results indicate that a substantial improvement in reservoir understanding can be achieved with an integrated reservoir characterization and modelling process that accounts for depositional and diagenetic trends, especially in reducing subsurface uncertainty. Furthermore, it was possible to recognize spatial trends and capture the relationship between petrophysical properties, pore architecture and sweep efficiency. It is expected that the ultimate recovery will also improve. 1. Introduction The case study field is located onshore Kazakhstan, and comprises several oil bearing units. The principal reservoir corresponds to Aptian deltaic-marine sands, whereas this study addresses a secondary reservoir, which is the Valanginian carbonate. The producing structure is an E-W oriented anticline with a western downdip, where some faults are present. The Carbonate reservoir was discovered as an upside in the mid-2000’s while drilling an exploration well. Encouraging flow tests from a 6 m interval have led to the kick-off of a detailed reservoir modelling exercise, in order to support a development plan. After that, a first pass static model was done with just a few wells. More recently, several appraisal wells were drilled to delineate the extent of the Carbonate reservoir. The Valanginian Carbonate comprises fine grained limestone, dolomite and marl. This total interval is some 370-400 m thick (Figure 1). The oil bearing unit itself occurs in the uppermost part of the interval, and is mainly composed of skeletal dolopackstone, dolowackestone/dolopackstone, doloboundstones, with some intervals of dolomudstones. This oil bearing unit presents layer cake geometry, and is sealed by anhydrite.
Ferreira, Joana (University of Lisbon, Faculty of Sciences, Department of Geology) | Azerêdo, Ana C. (University of Lisbon, Faculty of Sciences, Department of Geology and Instituto Dom Luiz) | Bizarro, Paulo (Partex Oil & Gas) | Ribeiro, Maria Teresa (Partex Oil & Gas) | Sousa, Ana (Partex Oil & Gas)
Abstract Characterizing highly heterogeneous carbonate reservoirs requires the integration and detailed analysis of petrophysics, facies, diagenesis, geometry, depositional environments and lateral and vertical variability. This is often challenging to conceptual models at oil-field scale, as this thorough analysis is hard to fully reproduce at reservoir-scale models. In order to improve skills and interpretations on both approaches, we addressed a case study from a Middle Jurassic outcrop of Portugal as an analogue for a carbonate reservoir. The outcrop exhibits three barrier shoreface lithofacies: L1 - oolitic and bio-intraclastic grainstones (divided into: L1a- with planar stratification or unstructured; L1b - with diverse cross-stratification styles); L2 - coarser grained grainstones/rudstones; and L3- coral/algal biostromes. Outcrop analysis was combined with petrographic/diagenetic studies of rock samples. Regarding petrophysical properties, three methods were used to determine the porosity: thin-section impregnation with blue-dyed epoxy resin, rock-slab water saturation and, for a few samples, plug measurements in a Helium gas expansion porosimeter. The plugs were also used to acquire permeability values using a digital gas permeameter. The results show that the outcrop is a tight reservoir, since most levels have low porosity (~3.5% average) and permeability (mostly <0.1md), though higher values (φ~10-15% and K~160md) occur locally. Most levels are classified as hybrid 1 or diagenetic reservoirs, according to Ahr (2008). L1b shows the highest porosity (mostly WP and CH), while the highest permeability is neither related to facies nor the most common porosity, but with certain late diagenetic processes, such as dissolution along stylolites and fracturing. It was concluded that the layers with the greatest reservoir potential exhibit channel porosity as the dominant type and, in a few rare cases, connected vuggy pores are seen in thin-section. In order to create a facies model that honors the geological observations and analysis, it is mandatory to consider the geometry of the carbonate bodies observed in the field. When the defined bodies are introduced and propagated using the modelling software, a better visualization of the reservoir (including potential stratigraphic/diagenetic traps) is achieved. The biostrome bodies often display a lenticular configuration, whereas oolitic bodies display lateral variations/interfingering with coarser/tempestite levels, thus isolating the levels with increased permeability. Normal industry workflows often do not fully consider geological data and conceptual models, and instead rely heavily on geostatistical propagation of well data. The results obtained indicate that there is an improvement in reservoir understanding with an integrated reservoir characterization and modelling process that accounts for actual depositional and diagenetic trends, as well as the distribution of the sedimentary bodies.
Abstract This study focuses on the Early to middle Triassic carbonates of the Ghail Formation outcropping in Ras Al Khaimah (UAE). A range of different methods, which includes outcrop logging, sampling, petrographic descriptions, fluid inclusion and isotopic analyses has been used to describe the main stratigraphic and diagenetic features of the outcropping sedimentary series. Optical microscopy, Scanning Electron Microscopy (SEM) and Backscattered Electron image (BSE) with Energy-dispersive X-ray spectroscopy (EDS) were used to assess the timing of different diagenetic events (paragenesis), which included dolomitization, physical/chemical compaction, iron oxide formation and late calcite cementation. Isotope analysis showed two different generations of dolomites, i.e. a low temperature dolostone and a high temperature dolomite cement, which could result from evaporation in a sabkha environment and from burial diagenesis, respectively. Fluid inclusion microthermometry in cements filling vugs proved useful to confirm the mesogenetic (burial origin) of the drusy dolomite cements.
The Upper Jurrasic Arab Formation in the Satah Field is composed of two major rock units, i.e. shallow marine carbonates and cyclic carbonates-anhydrite sequence. The former is defined as the Arab D zone, while the latter is divided into three zones, i.e. Arab A, B and C in descending order. The Arab C and D zones comprise hydrocarbon bearing formations in the field.
The Arab D reservoir is characterized by upward shallowing sequence. Its lower and middle portions are dominated by mud supported facies deposited on a shallow shelf, while its upper part is composed of various lithology types resulting from upward shallowing system. Total eight lithology types were identified within the Arab D reservoir. The petrophysical characteristics of the Arab D sequence is determined by the original sedimentary fabrics and by various diagenetic processes. Leaching and dolomitization processes. Leaching and dolomitization can enhance both porosity and permeability, whereas bitumen fills permeability, whereas bitumen fills associated with paleo O.W.C. and matrix cementation related to paleo acquifer reduce the reservoir quality. In general, below `Bitumen Mat' both porosity and permeability deteriorate rapidly. In permeability deteriorate rapidly. In other word, the Arab D reservoir is considered to be bottom sealed reservoir. According to the lithological and petrophysical variations, the Arab D petrophysical variations, the Arab D reservoir was subdivided into fifteen reservoir layers.
On the other hand, the Arab C zone is made up of alternated carbonates and anhydrite and was accumulated under the various depositional environments ranging from supratidal-sabkha to subtidal conditions. The carbonates are dominated by grain-supported facies and divided into six lithology types. The original fabrics of the sediments play an important role on the reservoir quality, as well as several diagenetic events. Good reservoir characteristics are distributed where the secondary pores by leaching and dolomitization are connected with the primary pore networks. Major porosity primary pore networks. Major porosity reduction as observed in the Arab D reservoir is not recognized.
Such geological analysis is considered to be not only essential but helpful for the reservoir layering scheme and simulation study.
The Satah Field is located offshore Abu Dhabi in the United Arab Emirates (U.A.E.), approximately 10 km south-east of the Qatar border and 180 km north-west of Abu Dhabi city (Fig.1). The first well was drilled in 1975 and resulted in oil discoveries in both Arab C and D reservoirs. Total twenty-one wells have been drilled according to the development plan and production started in 1987.
The field is a circular dome structure with a relatively gentle slope and is located on the north-south structural trend extending from the El Bunduq to Arzanah fields, which are considered to have been formed by deep seated salt movement.