Reservoir Units Research Articles

GIS-based machine learning models for mapping tar mat zones in upper part (DJ unit) of Zubair Formation in North Rumaila supergiant oil field, southern Iraq

In this study, three machine learning models, namely, support vector machine, naïve Bayes, and random forest, along with the geographic information system, are used to delineate the tar mat occurrence hazard in the upper part of Zubair Formation (named as DJ unit) in Rumaila oil field, southern Iraq. To build these models, a well inventory map that consists of 213 wells (tar and free-tar) is used with five factors that control the mat distribution in the DJ reservoir unit. These factors are porosity, volume of shale, water saturation, DJ unit thickness, and distance to the major fold axis. Multicollinearity and feature selection tests demonstrate that three of the five factors (distance to the major fold axis, water saturation, and porosity) are responsible for the tar distribution in the reservoir unit. The important factors with well inventory are used to develop the machine models and the results are compared using five evaluation measures namely, accuracy, sensitivity, specificity, kappa, and the relative operating characteristics curve. Findings from the models suggest that random forest is the best model, followed by support vector machine with polynomial kernel. The prediction random forest model is used to delineate the mat distribution, and the probability of tar mat occurrence hazard is classified into five zones, namely, very low, low, moderate, high, and very high. The produced hazard map in this study can be used as guide in the drilling of new wells in the considered reservoir unit and in avoiding the drilling of wells where the tar expected to occur.

PETROLEUM SYSTEMS MODELLING IN A FOLD‐AND‐THRUST BELT SETTING: THE INVERTED CAMEROS BASIN, NORTH‐CENTRAL SPAIN

The Mesozoic Cameros Basin, northern Spain, was inverted during the Cenozoic Alpine orogeny when the Tithonian – Upper Cretaceous sedimentary fill was uplifted and partially eroded. Tar sandstones outcropping in the southern part of the basin and pyrobitumen particles trapped in potential source rocks suggest that hydrocarbons have been generated in the basin and subsequently migrated. However, no economic accumulations of oil or gas have yet been found. This study reconstructs the evolution of possible petroleum systems in the basin from initial extension through to the inversion phase, and is based on structural, stratigraphic and sedimentological data integrated with petrographic and geochemical observations. Petroleum systems modelling was used to investigate the timing of source rock maturation and hydrocarbon generation, and to reconstruct possible hydrocarbon migration pathways and accumulations.In the northern part of the basin, modelling results indicate that the generation of hydrocarbons began in the Early Berriasian and reached a peak in the Late Barremian – Early Albian. The absence of traps during peak generation prevented the formation of significant hydrocarbon accumulations. Some accumulations formed after the deposition of post‐extensional units (Late Cretaceous in age) which acted as seals. However, during subsequent inversion, these reservoir units were uplifted and eroded.In the southern sector of the basin, hydrocarbon generation did not begin until the Late Cretaceous due to the lower rates of subsidence and burial, and migration and accumulation may have taken place until the initial phases of inversion. Sandstones impregnated with bitumen (tar sandstones) observed at the present day in the crests of surface anticlines in the south of the basin are interpreted to represent the relics of these palaeo‐accumulations.Despite a number of uncertainties which are inherent to modelling the petroleum systems evolution of an inverted and overmature basin, this study demonstrates the importance of integrating multidisciplinary and multi‐scale data to the resource assessment of a complex fold‐and‐thrust belt.

What matters for flow and recovery in carbonate gas reservoirs: Insights from the mature Central Luconia Province, offshore Sarawak, Malaysia

Miocene carbonate reservoirs in Central Luconia, offshore Sarawak, Malaysia, have been delivering gas for over 30 yr. In this paper, learnings from that period of production are used to understand the key drivers affecting flow during production and recovery optimization in existing fields as well as development decisions for new discoveries. The large data set, generated over more than 40 yr, was analyzed in a consistent manner through a holistic database, constrained by a stratigraphic framework, to allow reservoir units to be compared like-for-like (“integrated knowledge base” [IKB] concept). Carbonate reservoir heterogeneities impacting flow are grouped into “horizontal–heterogeneities”—argillaceous flooding layers and exposure-related karst—and “vertical–heterogeneities”—large-scale architectural elements, found especially along platform margins. Both types of heterogeneities control water ingress during production and influence the recovery mechanism. Argillaceous flooding layers can act as baffles, holding back water rise during production, or can form pressure compartments. Long-lived, fault-bounded reef margins, carbonate shoals, islands, and karsts can be vertical conduits for aquifer inflow. Platform shape and architecture impact column height and hence recovery efficiency. Additional drivers impacting recovery were found to be gas-column height, aquifer size and permeability, pressure connection to neighboring fields, and field development concepts. All drivers identified impact decisions throughout the field life, e.g., well count and design, intervention capabilities, evaluation and mitigation of early-water breakthrough, reservoir management, selecting enhanced recovery methods, and abandonment pressure. The IKB allowed to derive “big rules” on what matters for flow, which were used to decide on development strategies for greenfields in Central Luconia. The presented outcomes can be extrapolated to comparable carbonate systems, whereas the IKB approach can be adapted and applied to other mature basins and reservoir types where equally vast and historic data sets are awaiting to be used in the current era of digitalization.

ГЕОЛОГИЯ АПТ-АЛЬБСКИХ ПОРОД КАРБОНАТНОЙ ПЛАТФОРМЫ ОСАДОЧНОЙ ГРУППЫ КОГОЛЛО И ПОСЛЕДСТВИЯ АНОКСИДНЫХ ОКЕАНИЧЕСКИХ СОБЫТИЙ БАССЕЙНА МАРАКАЙБО (СЕВЕРО-ЗАПАДНАЯ ЧАСТЬ ЮЖНОЙ АМЕРИКИ)

Актуальность исследования обусловлена необходимостью проведения дополнительных поисково-разведочных работ на нефть и газ в северо-западной части нефтегазоносного бассейна Маракайбо, которые позволят повысить рентабельность разработки действующих месторождений и расширят возможности поиска новых залежей углеводородов в западной части Венесуэлы. Анализируемая осадочная толща Коголло, представленная формациями Апон, Лижур и Марака, включает промышленно продуктивный интервал, который слагают карбонатные отложения и нефтематеринские породы мелового периода. Литологическая характеристика нефтематеринских пород указывает на аноксидные океанические события при формировании формации Апон. Первое событие соотносится с осадконакоплением пачки Мачикес, а второе – с кровлей пачки Пиче. Обе пачки принадлежат к формации Апон. Рассматриваемые события способствовали формированию нефтематеринских пород высокого генерационного потенциала углеводородов, чем объясняется интерес данного исследования. Основной целью исследования является изучение фациальных условий формирования отложений формации Апон в разрезе обнажения континентальной части бассейна Маракайбо и их корреляция с ближайшими глубокими скважинами для определения стратиграфического местоположения коллекторов и их возможной связи с интервалами потенциальной нефтематеринской породы. Объекты: обнажения карьера Цементос Кататумбо С.А. в горной системе Периха, где выделяется карбонатная тоща нижней группы Коголло, а также глубокие поисковые скважины X-1, X-15, X-21, X-14 и X-23. Имеющиеся варианты корреляции отложений в обнажении горной системы Периха недостаточно обоснованы и требуют уточнения. Методы: седиментологический и геохимический анализы карбонатных пород группы Коголло в пределах в карьере Цементос Кататумбо С.А., штат Сулия, Венесуэла, включающие макро- и петрографическое описание пород, биостратиграфический анализ, изучение содержания общего органического углерода в породе, данных гамма-каротажа по разрезу обнажения и в глубоких скважинах. Результаты. Выделено 14 микрофаций, связанных с условиями седиментации в пределах склона карбонатного бассейна. В последовательности переслаивания отложений формации Апон выделяются участки максимальной трансгрессии моря и скрытые стратиграфические несогласия. Аппроксимированная и оценочная корреляция, учитывающая стратиграфию, литофации и данные гамма-каротажа, была проведена в обнажении карьера Цементос Кататумбо С.А. и сопоставлена с разрезами нефтяных скважин X-1, X-15, X-21, X-14 и X-23.

2D Seismic Interpretation of the Meyal Area, Northern Potwar Deform Zone, Potwar Basin, Pakistan

Abstract Meyal Field is considered as one of the chief hydrocarbon producing fields in the Potwar Basin, Pakistan. The present research emphasize on the subsurface structures affecting the Mesozoic-Cenozoic successions exclusively foremost reservoir units comprising the Eocene Chor Gali and Sakesar formations. Data from six seismic lines and three wells (aligned with those lines) have been deliberated comprehensively with remarkable and tremendous calibration. Five prominent and imperative reflectors specifically the Permian, Triassic, Jurassic, Paleocene and Eocene successions were interpreted through seismic tactics. Time structure maps were equipped on the basis of two-way travel time (TWT) of the seismic line. Likewise, four isopach maps portrayed the thickness discrepancy of prospective hydrocarbon strata. Structurally, analytical section reveals that the Meyal anticline is a plunging and faulted anticline. The pop-up structure is constrained by back-thrust from the north and fore-thrust from the south, on the dip lines. These maps depicted potential reservoir, demarcate promising site for future hydrocarbon exploration.

Sandstone reservoir zonation using conventional core data: A case study of lower cretaceous sandstones, Orange Basin, South Africa

This study outlines the different methodologies used to identify and classify different rock units in the sandstone reservoirs of the Orange Basin in South Africa into flow units. The flow units are defined on the basis of conventional core porosity and the permeability of the reservoir occurring in the fluvial and shallow marine depositional environments within the lower Cretaceous period. A total of six facies were identified from the core data, and they were corroborated with gamma ray log data. Facies A1, A2, A3, and A4 are the main reservoir units with generally fine-to medium-grained sands, which dominantly comprise quartz grains. Facies A5 mainly comprises silts with lenses of fine-grained sands, while Facies A6 is claystone laminated with minor burrows filled with shale and occasional siltstone presence. The porosity and permeability were used to compute the permeability/porosity relationship, the rock quality index, pore spaces, storage and flow capacity values, and to indicate the flow zone. The highest porosity and permeability values correspond to facies A1 and A2, which are represented by mega pore spaces, and they displayed high flow capacity values and moderate to high storage capacities. The lowest porosity and permeability values belonged to core facies A6 and A5, which mostly comprise siltstone and clay with Nano pore spaces. The flow zone indicator (FZI) values determined ranges from 0.01 to 13.9 μm, which were grouped into four different hydraulic flow units (HFUs) within the cored intervals. The defined hydraulic units do not always coincide with the facies. The Windland pore throat radius (r35) calculated that pore spaces correlated better with the Lorenz flow zone plot and facies. It is recommended that the statistically derived reservoir quality index (RQI) equation of facies A1 and A2 be used to extrapolate the RQI and FZI values for other wells in the field. It is thus recommended that dynamic data be used to validate flow units.

Sedimentology, geological modeling and prediction of the remaining oil distribution in a complicated fault-block reservoir in the Weicheng Oilfield, Dongpu Depression, China

Reservoirs in the Weicheng Oilfield, which occur in Paleogene Shahejie Formation Member 4 (Es4), were formed during the initial and strongly rifting stage of the Dongpu Depression. The geometry and distribution of sands of different types have controlled the heterogeneity of the reservoirs and have resulted in exploration challenges and relatively low recoveries. Based on various static and dynamic geological data including drilling, logging, seismic and production data, the microfacies features and distribution of Es4 were analyzed. Geostatistical three-dimensional (3-D) models and an integrated numerical simulation were constructed to quantify the geometry, spatial distribution and continuity of the reservoir sands and to predict the remaining oil distribution rules. Two depositional systems were recognized in Es4: terminal fans deposits in the lower part and partial shallow-lake deposits in the upper part. The three-dimensional geological model provided insights into the external and internal geometries, distributions and physical properties of the reservoir units. A sedimentary and connectivity feature analysis suggested four types of flow units: Type I units, which are primary sands of distributary channels and bars; Type II units, which are primary sands of proximal overbank and beaches; Type III units, which are sands of distal overbank; and Type IV units, which are mud flats and inter-beach-bar. The numerical simulation reproduced the changing process of the remaining oil, and the areas that have both high remaining oil saturations and reserve abundance, which are controlled by micro-facies and influenced by the structural trend and injection-production relations, comprise the key potential reservoirs: the sand pinch-out area, the imperfect pattern area and structural highs in Type I units and most of the areas in Type II units.

Quantitative risk assessment for Optimum Mud weight window design: A case study

Deterministic approach in selecting mud weight window at pre-drill condition has uncertainties for wellbore stability analysis. Quantitative Risk Assessment (QRA) technique has been successfully used in pre-drill condition addressing the variability of input parameters like, principal stresses and rock properties. The output of this process recommends the mud weight window with probability of drilling success which can avoid the wellbore collapse and lost circulation events. This kind of stochastic approach to predict safe mud weight window can assure stable wellbore with significant cost effectiveness related to drilling success.A workflow to perform QRAis demonstrated which starts with derivation of stresses in deviated wellbore. Seismic velocity data has been used to estimate pore pressure and validated with formation pressure obtained from reservoir characterization instrument data for a study well located in east coast of India. Mogi-Coulomb failure criteria have been used to estimate required mud weights to avoid shear failure. Mud weights required to avoid lost circulation has also been calculated. Then QRA has been accomplished to predict safe mud weight window sat specific depth within 14 ¾” hole and borehole section (12 ¼”). The results have been validated with real data set and based on that exercise, mechanical earth model and uncertainty associated with input parameters for study well has been established. A feasibility study has been performed to check the viability of drilling a near horizontal (75ο inclination) well along the reservoir unit with azimuth of 250ο. The wellbore collapse and lost circulation curves intersect near 35% probability of success point. The results of QRA indicate that the inclination and azimuth would not be favorable for successful drilling in this scenario. Based on these QRA, recommendations have been made in data acquisition plan for future drilling to reduce the variability in input parameters and successful completion of well.

Sequence stratigraphic analysis of the Lower Jurassic Precipice Sandstone and Evergreen Formation in the Surat Basin, Australia: Implications for the architecture of reservoirs and seals for CO2 storage

Abstract The Lower Jurassic Precipice Sandstone and Evergreen Formation in the Surat Basin, Australia are a highly prospective interval for carbon capture and storage (CCS). However, their stratigraphic nomenclature is inconsistently applied, and a basin-wide stratigraphic framework that is ubiquitously agreed upon remains elusive. In particular, a sandy transitional sandstone interval that occurs above the main Precipice Sandstone reservoir unit has caused confusion about how the two units should be subdivided. To address this issue, we integrate core observations with seismic interpretation and wireline log correlation to construct a sequence stratigraphic framework for the Lower Jurassic System that goes beyond lithostratigraphy. The main findings of our work include: (1) the identification of three 3rd-order sequences, SQ1-SQ3, from base to top. Two main sandstone intervals, the Precipice Sandstone and the Boxvale Sandstone Member (Evergreen Formation), represent the lowstand systems tracts (LSTs) of SQ1 and SQ3, respectively. The Westgrove Ironstone Member in the upper Evergreen Formation – a distinctive oolitic ironstone unit – represents the transgressive system tract (TST) of SQ3; (2) the transitional interval above the main Precipice Sandstone reservoir corresponds to the lower TST in SQ1 (lower Evergreen Formation). It is manifest as an upward-fining succession with a retrogradational facies stacking pattern, and is significantly different from the main Precipice Sandstone reservoir which shows an aggradational stacking pattern; (3) the Precipice Sandstone and lower Evergreen Formation progressively onlap the western and the eastern margins of the Surat Basin, and this confines the Precipice Sandstone to the central portion of the basin; (4) the three sequences (SQ1-SQ3) approximately coincide with global sea-level cycles documented from the early Jurassic. Two episodes of accelerated tectonic subsidence were responsible for the thinning and onlap of SQ1 and SQ3 onto the basin margins. In contrast, weaker tectonic subsidence was responsible for the overall finer grained sediment, the uniformity in thickness, and widespread distribution of SQ2. The results of our stratigraphic analysis indicate that the architecture of the reservoir and seal significantly differs from previous thinking, such that: (1) the Precipice Sandstone, the main reservoir unit, has a distribution that is limited to the basin centre; (2) the transitional interval above the main Precipice Sandstone reservoir forms poorly-connected, localized reservoirs that onlap and backstep towards the basin margins; and, (3) SQ2 and SQ3 are sealing units because they are very widespread and mud-dominated. Viewing the Precipice Sandstone and Evergreen Formation from a sequence stratigraphic standpoint provides important information about how to subdivide them and helps clarify the stratal relationships that were previously unclear from a mixture of terminology. Furthermore, this study gives insights into the spatial-temporal evolution of this reservoir and sealing interval that is an important CCS target in Australia.

The Rattray Volcanics: Mid-Jurassic fissure volcanism in the UK Central North Sea

The Middle Jurassic Rattray Volcanic Province is located at the triple junction of the North Sea continental rift system. It has previously been thought to be sourced from three large central volcanoes: the Glenn, Fisher Bank and Ivanhoe volcanic centres. Re-interpretation using 3D seismic and well data shows that no volcanic centres are present and the Rattray Volcanics were instead sourced in fissure eruptions from linear vents, including the Buchan–Glenn Fissure System, a c. 25 km long zone of WSW–ENE-striking linear fissure vents and associated small volcanic edifices across the Buchan–Glenn Horst. The orientation of the fissures is broadly parallel to the Highland Boundary Fault, which intersects the Rattray Volcanics at the Buchan–Glenn Fissure System, implying that Mid-Jurassic magmatism exploited pre-existing crustal structural anisotropies established during the Caledonian Orogeny. The lack of large intrusive complexes beneath the Rattray Volcanics indicates that the pre-Middle Jurassic sedimentary sequences (e.g. the Devonian–Carboniferous Old Red Sandstone Group, the Permian Rotliegend and Zechstein groups and the Triassic Skagerrak Formation) extend further than previously supposed and therefore the presence of possible subvolcanic reservoir and source rock units within the triple junction of the Central North Sea may have been overlooked.

Unraveling the reservoir heterogeneity of the tight gas sandstones using the porosity conditioned facies modeling in the Whicher Range field, Perth Basin, Western Australia

Tight sandstones of the late Permian Willespie Formation constitute an important reservoir rock in the Whicher Range gas field of the Perth Basin. The sandstones under the effect of sedimentary conditions and diagenesis show some degree of heterogeneity reflecting in reservoir properties and production history. The Willespie Formation consists of fine to coarse-grained and gravelly feldspathic sandstones intercalated with shale, siltstone and coal, deposited in a meandering river system. Different diagenetic processes including compaction, cementation (authigenic clays, calcite and siliceous) and dissolution have severely affected the pore system properties of the reservoir sandstones, as they are considered as tight sandstones. In this study, three-dimensional modeling of reservoir sandstones has been performed using stochastic modeling algorithms for facies and porosity properties. A preliminary facies analysis of the main reservoir rocks based on core and well logs data provided the basis for reservoir zonation and modeling. Regarding the close relationship between acoustic impedance with depositional/diagenetic characteristics of reservoir facies and their porosity, this seismic attribute was used as a secondary parameter in porosity modeling. The results indicate a close relationship between sedimentary characteristics and reservoir properties. Based on the extracted models, most of the porous zones are related to the clean and coarse sandstones of the fluvial channels accumulating in the upper parts of the reservoir. In fact, initial sedimentary characteristics have the main impact on the distribution of reservoir zones, their thickness and continuity in the field and controlling large-scale reservoir heterogeneity which has been enhanced by the effect of diagenetic processes on the pore system properties and controlling the internal reservoir heterogeneity in next stages. Distinctive variability in reservoir properties towards the upper reservoir units and also among different wells can be considered for optimizing exploration and development targets of the field.

Cenomanian-Early Campanian Carbonate Reservoir Rocks of Northwestern Iraq: Diagenesis and Porosity Development

The present work focuses on the upper Cretaceous (Cenomanian-early Campanian) carbonate successions in selected wells from northwestern Iraq. These successions are represented by Gir Bir (Cenomanian-early Turonian), Wajna (late Santonian) and Mushorah (early Campanian) Formations. The succession has affected by early burial near-surface, unconformity-related and deep burial diagenesis represented by cementation, neomorphism, dolomitization, dedolomitization, silicification, authigenesis of glauconite and pyrite, compaction, micritization, solution and porosity formation. The common porosity types are intergranular, fenestral, intercrystalline, moldic, vuggy, channel and fracture. Three porosity zones (I, II, and III) are identified depending on variation in gamma ray which reflects their shale content. The upper part of zone (II) is highly porous and regarded on the main reservoir unit in the middle and upper parts of the Gir Bir Formation. Fracture and moldic and vuggy dissolution features in addition to karstic and fissure features are responsible for the porosity increase in the fractured reservoir unit.

The Paleozoic petroleum system in the north of Scotland – outcrop analogues

Abstract All of the components of an exhumed Devonian petroleum system occur in Orkney. These include a good quality mature source rock to bitumen-bearing sandstone reservoirs, with several separate accumulations that could have held about 1.88 billion barrels of oil. The exhumed system presents an excellent analogue for deeply buried petroleum systems offshore. Whilst lighter oils are now absent, reported oil shows occur, commonly associated with faults cutting the Eday Group. On Orkney, Middle Devonian source rocks (750 m thick) were thick lacustrine laminites (fish beds) representing some 30% of the sequence. RockEval and vitrinite analyses show the organic matter is good quality Type I and II and within the early oil window. These source rocks underwent burial until Permian inversion. Several exhumed reservoirs occur on Orkney in aeolian and fluvial sandstones with porosities from 15 to 25%. These reservoirs have been ‘breached’, losing the light-end hydrocarbons, leaving pore space oil stain and bitumen residues. Thin fluvial and sheet-floods sands found within the lake cycles have bitumen residues and provided connectivity between the thicker reservoir units. All types of trap are found including a major, broad anticline running north–south on Mainland Orkney and an unconformity with fault traps and pinchouts.

Summary of the new stratigraphic guide to the Chalk Group in the UK and Norwegian sectors of the North Sea

This brief guide summarizes the updated and unified stratigraphy of the Chalk Group for the UK and Norwegian sectors in the North Sea. The information was presented at the ‘Chalk of the Northern Province’ symposium held in Hull on 12 September 2015. The update rationalizes Chalk Group lithostratigraphy across the North Sea, reducing the need to use unique names for reservoir units, without proper documentation or lack of biostratigraphic and correlative insight.

Mapping Northern Australia’s Present Day Stress Field: The Canning Basin

The Canning Basin of Western Australia has recently become a site of interest for unconventional hydrocarbons, with several formations within deeper basin depocentres being investigated for resources. Modern petroleum resource evaluation is generally dependent on an understanding of both local and regional stresses, as well as the geomechanical properties of reservoir units. Presently, there are significant gaps in our understanding of these factors within the Canning Basin. This study is part of a greater effort from Geoscience Australia to understand the present-day stress field of northern Australia. A generally NE-SW oriented maximum horizontal stress azimuth is identified from interpretation of borehole failure in five petroleum wells, and a broadly strike-slip faulting stress regime is interpreted from wireline data and wellbore testing. Variations in stress regime at different crustal levels within the Canning Basin are highlighted by one-dimensional mechanical earth models that show changes in the stress regime with depth as well as by lithology, with a general move towards a normal faulting stress regime at depths greater than ~2.5 km.

Scattering and intrinsic attenuation as a potential tool for studying of a fractured reservoir

Intrinsic attenuation is mainly caused by the frictional movement induced by seismic waves during their passage between fluids contained in subsurface pores and solid grains. In contrast, scattering attenuation is due to small reflections caused by subsurface heterogeneities. Since porosity and fractures are important sources of heterogeneity and fluids, scattering and intrinsic attenuation are suitable seismic attributes for investigating porous and fractured subsurface zones, such as oil and gas reservoirs. In the present study, we accurately estimated scattering and intrinsic attenuation from zero-offset vertical seismic profiling (VSP) and sonic data acquired from three wells that cross a reservoir zone of an oilfield located in Abu Dhabi in the United Arab Emirates. In addition, we properly separated scattering and intrinsic attenuation. The attenuation profiles show high variation with depth. Furthermore, the scattering is frequency dependent and has a significant contribution to the total attenuation. This is due to the high heterogeneous property of carbonate rocks, which dominate the lithology of the reservoir zone. This means that the variation of attenuation can be used as an indicator of the heterogeneity degree of reservoir zone. The VSP and sonic intrinsic attenuations exhibit high anomalies in oil-rich zones, and the ratio of the compressional sonic attenuation to the shear attenuation exhibits a high anomaly in gas-rich zones, but not in oil-rich zones, because the presence of oil influences the compressional and shears attenuations in a similar fashion. However, the presence of gas attenuates compressional waves much more than the shear waves. Therefore, can be used to distinguish oil- and gas-rich zones. The highly fractured reservoir units display negative VSP intrinsic attenuation anomalies and strong scattering, which reveals a strong interference phenomenon. This phenomenon leads to an increase in amplitude of the downgoing wave versus depth, which results in negative attenuation. Hence, strong negative intrinsic attenuation accompanied by strong scattering can be an indicator of a highly fractured zone. The VSP and sonic intrinsic attenuations in such zones have a large discrepancy, which might be due to the squirt flow mechanism due to the inter-crack fluid flow due to the compressional stress induced by seismic waves on the fractures. This mechanism attenuates the waves propagating at low frequencies less, because the fluid pressure has sufficient time to reach equilibrium, which is not the case at high frequencies. This explains why the VSP intrinsic attenuation is much smaller than the sonic attenuation in highly fractured zones. As such, a large discrepancy between VSP and sonic intrinsic attenuations also indicates a highly fractured reservoir.

Reservoir characterization of the Burgan Formation in northwestern Persian Gulf

Lower Cretaceous sequences of the Burgan Formation are notable siliciclastic reservoirs in the Middle East. Despite of this importance, a little is known about various geological characteristics of this reservoir in Iranian northwestern part of the Persian Gulf. In this study, an integrated sedimentological and reservoir geological evaluation has been carried out on the Burgan reservoir using a complete dataset of drilled cores, core plugs, thin sections and petrophysical logs along with laboratory data including XRD analysis of all components to define grain's mineralogy and porosity – permeability data for reservoir quality evaluation. Depositional facies and environments are interpreted and correlated in sequence stratigraphic framework of targeted reservoir across the studied fields and then compared with stratigraphic equivalents in the Middle East. Seven facies types are recognized that indicate deposition in a transitional environment from siliciclastic-dominated delta setting into shallow-marine carbonate platform. Diagenesis study indicates a simple history of post-depositional events that includes near surface (marine) and shallow to deep burial realms. Diagenetic processes are grouped into two categories based on their effects on reservoir properties. They include porosity enhancing (i.e. dissolution and fracturing) and porosity reducing (compaction and cementation) diagenetic processes. Reservoir evaluation of depositional facies has been carried out by defining petrographic rock-types (PRTs) and hydraulic flow units (HFUs) and their correlation in sequence stratigraphic framework. Results showed that semi-to unconsolidated sandstone facies accumulated in Burgan-B member provides the best reservoir units in the Burgan Formation. Organic-rich (rootled) and pelagic shale facies form several intra-reservoir barriers between the reservoir units, especially in Burgan-A member. These show close correlation with reservoir descriptions of this formation reported from the neighboring areas in the Persian Gulf (i.e. Kuwait).

Geophysical strata rating (GSR) as an aid in carbonate reservoir characterisation: an example from the South Pars gas field, Persian Gulf Basin

In this study, the geophysical strata rating (GSR) is calculated from petrophysical data using the equations developed for clastic rocks. The region being investigated is the South Pars gas field in the Persian Gulf Basin, where the Permian–Triassic Dalan and Kangan reservoirs host the largest accumulations of gas in the world. A 3D GSR model is estimated from 3D poststack seismic data by using a probabilistic neural network model. In this study, two methodologies are used to obtain GSR values at the different scales of wireline logs and 3D seismic data.Strong correlations between neural network predictions and actual GSR data at a blind well prove the validity of the intelligent model for estimating GSR. The GSR results are also in good agreement with porosity and elastic moduli of these carbonate rocks. Discrimination between the reservoir and non-reservoir shaly units can easily be obtained by comparing GSR and well logs. Very low GSR values with high gamma ray log responses indicate shaly intervals. These can cause washouts, casing collapse and other related drilling problems. Intervals with low GSR values and low gamma ray log responses indicate the presence of good reservoir units.

Imaging high-resolution velocity and attenuation structures from walkaway vertical seismic profile data in a carbonate reservoir using visco-acoustic waveform inversion

Frequency domain visco-acoustic waveform inversion is applied to multi-offsets vertical seismic profile data acquired over a carbonates reservoir in an oil field offshore Abu Dhabi in the United Arab Emirates, to produce high resolution seismic velocity and attenuation structures. The starting velocity and attenuation models are obtained from traveltime tomography, and from the centroid frequency-shift method, respectively. Waveform tomography is performed between the frequencies 4 and 50 Hz. To reduce coupling between velocity and attenuation parameters during model updates, a two stage inversion strategy is adopted. During the first stage, only the velocity model is recovered and, during the second stage, velocity and attenuation models are recovered. The density is estimated from empirical correlation derived from sonic and density logs at the borehole location. A judicious selection of the time-damping constant [Formula: see text], used to suppress late arrivals in the Laplace-Fourier domain is critical to mitigate nonlinearities. Prior to the inversion, data preconditioning is done to transform the data in a form convenient for the visco-acoustic wave equation. High resolution final velocity and attenuation models are obtained. Extracted 1D profiles from the final models generally correlate well with the sonic log and estimated clay content from the gamma-ray log. These observations give confidence to the results. A comparison of the synthetic data generated from the final models and the field data shows a high degree of similarity. The high resolution of the results enables us to readily identify layers and provide a geologic interpretation from Quaternary to Late Jurassic. The inverted models show a stack of layers with alternating relatively high and low velocity values associated with relatively high- and low-attenuation values defining anticlines, as we progressed deeper into the subsurface. The two main reservoirs units in the Lower Cretaceous are clearly identified.

Fluid flow properties of the Wilhelmøya Subgroup, a potential unconventional CO2 storage unit in central Spitsbergen

The Upper Triassic to Middle Jurassic Wilhelmoya Subgroup forms one of the more suitable reservoir units on the Norwegian Arctic archipelago of Svalbard. The target siliciclastic storage unit, which is encountered at approx. 670 m depth at the potential injection site in Adventdalen, central Spitsbergen, is a severely under-pressured (at least 35 bar), tight and compartmentalised reservoir with significant contribution of natural fractures to permeability. In this contribution, we characterise the 15–24 m-thick Wilhelmoya Subgroup storage unit using both borehole and outcrop data and present water-injection test results that indicate the presence of fluid-flow barriers and the generation of new, and propagation of pre-existing natural fractures during injection. Whole core samples from drillcores and outcrops were sampled for pore network characterisation and analysed using high-resolution X-ray computed tomography (Micro-CT). We demonstrate that heterogeneities such as structural discontinuities, igneous bodies and lateral facies variations, as examined in well core and equivalent outcrops, will strongly influence fluid flow in the target reservoir, both by steering and baffling fluid migration. Many of these heterogeneities are considered to be subseismic, and their detailed characterisation is important to predict subsurface CO2 storage potential and optimise injection strategy.