FACIES HETEROGENEITIES AND 3D POROSITY MODELLING IN AN OLIGOCENE (UPPER CHATTIAN) CARBONATE RAMP,SALENTO PENINSULA,SOUTHERN ITALY

Appraisal of the volumes of fluid in a carbonate reservoir will typically require a reliable predictive model. This can be achieved by combining studies of well-exposed carbonate successions with 3D models in order to obtain reliable quantitative data. In this paper, we present a detailed outcrop study and a 3D porosity model of a well-exposed Oligocene carbonate ramp (Salento Peninsula, southern Italy) to investigate the nature of small-scale facies and porosity heterogeneities. Porosity and permeability in the ramp carbonates appear to be controlled by the original mineralogy of skeletal components and by depositional textures. The aims of the study were therefore to identify the factors controlling porosity development in an undeformed carbonate ramp; to model the scale-dependent heterogeneities characteristic of the facies associations; and finally to produce a 3D model of the porosity distribution. The upper Chattian Porto Badisco Calcarenite which crops out along the coast of the Salento Peninsula consists of six lithofacies ranging from inner ramp deposits to fine-grained outer ramp calcarenites. The lithofacies are: inner ramp small benthic foraminiferal wackestone-packstones associated with (i) sea grass meadows (SG) and (ii) coral mounds (CM) consisting of coral bioconstructions with a floatstone/packstone matrix; middle ramp (iii) large rotaliid packstones to wackestone-packstones (LR), (iv) rhodolith floatstone-rudstones (RF), and (v) large lepidocyclinid packstones (LL); and (vi) outer ramp fine-grained bioclastic calcarenites (FC). A total of 38 samples collected from six stratigraphic sections (A, B, D, J, E, LO), measured in the Porto Badisco ravine, were investigated to discriminate the types of porosity. Effective and total porosity was measured using a helium pycnometer. The 3D porosity modelling was performed using PETREL™ 2016 software (Schlumberger). Four main types of porosity were recognized in the carbonates: interparticle, intraparticle, vuggy and mouldic. Primary porosity (inter- and intraparticle) is limited to middle ramp lithofacies (LL and LR) and outer ramp lithofacies (FC), whereas secondary porosity (vuggy and mouldic) was present in both inner ramp lithofacies (CM and SG) and middle ramp red algal lithofacies (RF). In the Porto Badisco carbonates, stratigraphic complexity and the distribution of primary porosity are controlled by lateral and vertical variations in depositional facies. Significant secondary porosity was produced by the dissolution of aragonitic and high-magnesium calcite components, which are dominant in the sea-grass and coral mound facies of the inner ramp and in the rhodolith floatstone-rudstones of the middle ramp. 3D models were developed for both effective and total porosity distribution. The porosity models show a clear correlation with facies heterogeneities. However of the two models, the effective porosity model shows the best correlation with the 3D facies model, and shows a general increase in effective porosity basinwards in the middle ramp facies.     

CARBONATE GEOBODIES: HIERARCHICAL CLASSIFICATION AND DATABASE – A NEW WORKFLOW FOR 3D RESERVOIR MODELLING

Quantitative data on geobodies are crucial for reservoir modelling. Although abundant quantitative data are available in the literature for siliciclastic depositional systems, equivalent data for carbonate systems are scarce. In this paper we introduce a new approach to the management of quantitative data on carbonate geobodies which is based on a hierarchical classification scheme. The classes to which a carbonate geobody are assigned are: (1) depo‐time (i.e. geological age); (2) depo‐system (i.e. type of carbonate platform); (3) depo‐zone (i.e. facies belt or zone); (4) depo‐shape (i.e. geometry of the geological body); (5) depo‐element (i.e. architectural elements present); and (6) depo‐facies (litho‐ and biofacies). This hierarchical classification is complemented by a set of rules for modifying depo‐shapes which refer to their spatial distribution and patterns of interaction. Based on this classification, an extensive database has been developed which can be used for 3D reservoir modelling. The database holds more than 600 case studies from outcrop analogues and the subsurface and also from satellite images of modern carbonate settings. The database can be used as the basis for a new workflow for reservoir modelling which uses multiple‐point statistics (MPS). MPS makes use of training images to capture and reproduce facies patterns and geometries during stochastic simulations. The application of this new approach is demonstrated by modelling a Cretaceous outcrop reservoir analogue from southern France. The use of MPS allows the generation of geologically realistic and complex facies distributions in the model based on the simplified training images.     

ARE SHOAL RESERVOIRS DISCRETE BODIES? A COQUINA SHOAL OUTCROP ANALOGUE FROM THE MID TRIASSIC UPPER MUSCHELKALK,SW GERMANY

Carbonate ramp reservoirs may show a much higher degree of complexity than the schematic and often layer‐cake type depositional models which are widely used in exploration and reservoir characterisation, especially in three dimensions. This complexity was investigated in an outcrop study of the Ladinian (Middle Triassic) Quaderkalk Formation (Upper Muschelkalk) from SW Germany. The formation was deposited on an epicontinental, gently inclined carbonate ramp in the regressive part of a third‐order depositional sequence and represents a sub‐seismic‐scale coquina‐dominated shoal reservoir analogue. In the study area, coquina carbonates make up a complex system of four stratigraphically separated shoal complexes. The present paper investigates the 1‐D to 3‐D facies distribution, reservoir architecture and sequence stratigraphic evolution of the largest shoal complex of the Quaderkalk Formation, the Oberer Hauptquader. The object of this outcrop analogue study was to improve the understanding of internal reservoir heterogeneities (such as connectivity and continuity) in similar carbonate shoal complexes in the subsurface. To that end, detailed analyses of 71 quarry outcrop and core samples were carried out, together with the study of more than 400 thin sections, the 2‐D analysis of three quarry wall panels and regional‐scale 2‐D correlations, and facies mapping. This investigation documents significant sedimentological heterogeneities at different scales within the studied shoal reservoir analogue. Instead of a continuous facies belt, a number of separate potential reservoirs form a shoal complex “mosaic”. Shoal development is controlled by sequence stratigraphic architecture, mainly by cycles which were responsible for shoal expansion during times of regression (forming potential reservoir‐volume) and shoal drowning during times of transgression (forming seals and potential stratigraphic traps). Within the individual shoal complexes, thickness and lithofacies types show gradational lateral changes. Correspondingly, lithofacies associations within the studied shoal analogue are not defined by sharp boundaries. Thus the present “shoals” do not in fact represent discrete “bodies”, as often depicted in reservoir models and as commonly used in reservoir simulation. In addition, shoal‐internal sedimentological heterogeneities (potential flow baffles in the subsurface) are strongly influenced by a combination of small‐scale cyclicity and event‐type deposition. This study therefore demonstrates the need for sedimentological studies of reservoir heterogeneities at various scales in order to decrease uncertainties and risks in exploration and production.     

3D SEDIMENTARY MODELLING OF A MIOCENE DELTAIC RESERVOIR UNIT, SINCOR FIELD, VENEZUELA: A NEW APPROACH

The “C2” unit in the Morichal Member of the Miocene Oficina Formation at the Sincor field (East Venezuela Basin) is characterised by a succession of superposed deltaic cycles which control vertical and horizontal reservoir connectivity. In order to model this reservoir in three dimensions, a workflow was developed which addressed a series of specific challenges. First, the deltaic nature of the succession required that both distributary channel and mouth bar sandbodies had to be modelled according to the defined sequence stratigraphic framework. Second, the relationship between distributary channels and mouth bars had to be honoured. A third issue was that individual distributary channel sandbodies were on occasion thicker than the cycle to which they belonged (i.e. they eroded down into the underlying cycle), and the relationship between mouth bar and channel sandbodies in adjacent sequences was therefore broken. Although conceptually simple from a geological viewpoint, this aspect proved particularly difficult during 3D modelling. This paper discusses the construction of the stratigraphic model, as well as that of the channel and mouth bar models. The workflow is based on existing stochastic approaches, arranged in nested steps dependent on the stratigraphic framework and on defined depositional processes in order to simulate reservoir distribution and partitioning. By integrating sedimentological observations and interpretations with existing modelling procedures, a reliable reservoir model can be built. The model is based on the observed sequence stratigraphic framework, and its infill takes into account the relationship between distributary channels and mouth bar deposits, derived from depositional processes. The model provides realistic distributions of the channel fills and mouth bar deposits at Sincor field using a multi‐realisation scheme. Improved local vertical connectivity between individual sequences, caused by erosion of highstand mudstone seals and baffles, can effectively be simulated; this is of particular significance at Sincor where planned second‐phase heavy oil recovery will depend on the use of steam‐assisted gravity drainage.     

MICROPOROSITY IN THE UPPER JURASSIC ARAB‐D CARBONATE RESERVOIR,CENTRAL SAUDI ARABIA: AN OUTCROP ANALOGUE STUDY

This study investigates microporosity in an outcrop analogue of the Upper Jurassic (Kimmeridgian) Arab‐D carbonate reservoir in central Saudi Arabia, integrating outcrop facies analysis, petrographic and SEM data and statistical analyses. At the study location in Wadi Nisah, the outcropping succession includes the uppermost Jubaila Formation and the entire Arab‐D Member of the Arab Formation which together comprise the Arab‐D reservoir interval. The succession is composed of eight lithofacies which can be grouped into three lithofacies associations based on their depositional environments. The stromatoporoid lithofacies association includes dolomitic mudstones, dolomitic wackestones and stromatoporoid wackestones and packstones; the skeletal bank lithofacies association includes burrowed fossiliferous wackestones and peloidal fossiliferous grainstones; and the tidal flat lithofacies association comprises laminated mudstones, wave‐rippled sandy grainstones, and supra‐ and intertidal muds with rip‐up clasts. The lithofacies were classified into mud‐dominated, grain‐dominated and dolostone textural groups. Microporosity and associated permeability in the analysed samples (n = 125 for porosity and n = 61 for permeability) range from 0.11% to 4.8 % and 0.36 to 4.35 mD, respectively. Three types of microporosity were observed: (i) between macro‐ and micro‐sparry calcite crystals; (ii) between micrites of varying morphologies; and (iii) within macro‐sized dolomite crystals. Microporosity distribution was controlled by sparry calcite cement, micrite crystal size, sorting and shape, and the presence of dolomite crystals. Statistical analyses of microporosity and associated permeability show non‐normal distributions for both variables. Coefficients of variation indicated high variability for porosity and permeability, which may be attributed to the high degree of heterogeneity in the pore system. In general there was a poor correlation between microporosity and permeability, but the correlation improved when visualized for individual textural groups.     

CARBONATE RESERVOIR ROCKS AT GIANT OIL AND GAS FIELDS IN SW IRAN AND THE ADJACENT OFFSHORE: A REVIEW OF STRATIGRAPHIC OCCURRENCE AND PORO‐PERM CHARACTERISTICS

SW Iran and the adjacent offshore are prolific petroleum‐producing areas with very large proven oil and gas reserves and the potential for significant new discoveries. Most of the oil and gas so far discovered is present in carbonate reservoir rocks in the Dehram, Khami and Bangestan Groups and the Asmari Formation, with smaller volumes in the Dashtak, Neyriz, Najmeh, Gurpi, Pabdeh, Jahrum, Shahbazan, Razak and Mishan (Guri Member) Formations. The Permo‐Triassic Dehram Group carbonates produce non‐associated gas and condensate in Fars Province and the nearby offshore. The Jurassic – Lower Cretaceous Khami Group carbonates are an important producing reservoir at a number of offshore fields and in the southern Dezful Embayment, and are prospective for future exploration. Much of Iran's crude oil is produced from the Oligo‐Miocene Asmari Formation and the mid‐Cretaceous Sarvak Formation of the Bangestan Group in the Dezful Embayment. This review paper is based on data from 115 reservoir units at 60 oil‐ and gasfields in SW Iran and the adjacent offshore. It demonstrates that the main carbonate reservoir units vary from one‐another significantly, depending on the particular sedimentary and diagenetic history. Ooidal‐grainstones and rudist‐ and Lithocodium‐bearing carbonate facies form the most important reservoir facies, and producing units are commonly dolomitised, karstified and fractured. In general, reservoir rocks in the study area can be classified into six major types: grainstones; reefal carbonates; karstified, dolomitised and fractured carbonates; and sandstones. The stratigraphic distribution of these reservoir rocks was principally controlled by the palaeoclimatic conditions existing at the time of deposition. A comparative reservoir analysis based on core data shows that dolomitised and/or fractured, grain‐dominated carbonates in the Dehram Group, Lower Khami Group and Asmari Formation typically have better reservoir qualities than the Cretaceous limestones in the Upper Khami and Bangestan Groups.