ALBERT

Description: The key problem addressed in this paper arises in the situation where multi-scale shale drapes are present along channel, channel-belt and/or valley-bounding surfaces, but the channel location is uncertain or unknown. In order to reduce this uncertainty, the channel and drape locations should be modified in order to calibrate the flow response to the historic production data as well as any static data from wells. We propose a coupled geological modelling and history-matching method in which the reservoir architecture composed of channels is simulated with a pre-defined stacking pattern, then the shale drapes are simulated along the bounding surfaces using a multiple-point statistics technique and, finally, channel and scour-hole locations are gradually perturbed until the corresponding flow responses match the field production data. The perturbation during the history matching must be geologically consistent, i.e. the result must honour the observed individual channel geometries and the interpreted channel stacking patterns. A digital 3D model representing a real field in offshore West Africa was studied to demonstrate this modelling and history-matching approach in which the multi-scale shale drapes are simulated and perturbed while the reservoir geological concepts are preserved and the well data are honoured. The final history-matched geological models have better prediction power than geological models built with randomly selected input parameters.

Description: In this study, all available geological, geophysical and geochemical data were integrated to assess the hydrocarbon prospectivity of the Haymana Basin, an interior basin in Central Anatolia. First, the basin was modelled in three dimensions (3D) using gravity data which identified the deepest part of the basin to the east of Haymana, south of Ankara. This potential hydrocarbon generation area has not been properly explored. Next, the first order vertical derivative of the gravity anomaly map was computed to identify boundaries of prospective structures from inflections in the gravity gradient. Aeromagnetic data were transformed to an analytical signal to identify the probable locations of buried magmatic intrusions. The prospective part of the Haymana Basin was interpreted as being located to the east of an intrusion. Finally, all available geochemical data of the Kirkkavak Formation were classified for different parameters (TOC, S1+S2 and Tmax) and maximum values of each parameter were mapped. In comparing the 3D depth model with individual geochemical maps, it was observed that each geochemical parameter was consistent with the interpreted prospective zone of the Haymana Basin.

Description: A comprehensive simulation study tested and analysed the sensitivity of dynamic connectivity in turbidite channel reservoirs to a large number of stratigraphic and engineering parameters. The study showed that subseismic shale architecture has a significant effect on reservoir connectivity. However, representing the complete spectrum of fine-scale architectural details in full-field simulation models is beyond the limits of existing computational capabilities. Previous work demonstrated that incorporating geologically based pseudo-relative permeabilities into relatively coarse full-field reservoir models renders practically intractable simulation cases tractable. We developed a methodology for generating pseudo-relative permeabilities at multiple geological scales, incorporating the effect of channel architecture and reservoir connectivity into fast simulation models. We describe a dynamic modelling workflow that integrates geologically based pseudo-relative permeabilities into a two-stage automatic history-matching algorithm. The history-matching problem is posed as one of data conditioning in the Bayesian framework. We show the application of the workflow to a channelized turbidite reservoir in West Africa. It is demonstrated that multiple geologically consistent models that are conditioned to production data can be generated rapidly thanks to optimally coarse simulation models that capture the effect of subseismic channel architecture on recovery behaviour, and run efficiently as the forward model within a Bayesian inference framework. Proof-of-concept tests carried out using field data indicate that the history-matched models predict well-by-well future recovery response with good accuracy.

Description: This paper provides data on the lateral continuity and geometry of potential reservoir geobodies in outcrops of Upper Khuff Formation time-equivalent strata in the Jebel Al Akhdar area (Oman Mountains, Sultanate of Oman). It presents outcrop-based quantitative data of shoal-associated grainstone bodies in a sequence stratigraphic framework on the scale of an average Khuff gas field. Such data may be useful for correlation and modelling of subsurface reservoirs. A stratigraphic correlation of five outcrop sections, based on facies, sequence analysis and gamma-ray pattern, was used as a framework for mapping the distribution and lateral extent of grainstone geobodies over an area of 8 x 8 km. Four grainstone bodies were traced laterally along distinct marker beds over several hundreds of metres. The stratigraphic architecture shows a general layer-cake pattern. The thickness and lateral extent of reservoir geobodies is strongly influenced by their stratigraphic position. High-energy shoal facies developed preferentially in the regressive parts of cycles of multiple hierarchies. Individual grainstone bodies may reach a thickness of 6 m, and those thicker than 3 m extend across the area of interest. Clinoforms or shingle-type geometries were explicitly searched for, but were not present. The observed systematic variations in extent and two-dimensional sedimentary architecture of Khuff grainstone bodies were used as input for 3D static facies modelling. Outcomes of this study have been used to reduce uncertainty on grainstone geometries, production-scale correlation strategies and definition of lateral facies successions in subsurface models of the Khuff reservoir.

Description: A detailed interpretation of seismic data has been carried out to analyse salt diapirism in the Straits of Hormuz in the Persian Gulf. Salt diapirs in the Zagros Foldbelt are mainly characterized by structures formed by mobilization of the Cambrian Hormuz salt as reactive diapirs during the Late Cretaceous-Tertiary Zagros orogeny. Interpretation of available data in the straits of Hormuz suggests that diapirs of Hormuz salt grew actively until the Early Miocene and then continued to rise passively by downbuilding of surrounding sediments until the present time. The syn- to post-Miocene Zagros sedimentation played a major role in passive diapirism. Sedimentation of the thick Lower Miocene deposits led to greater subsidence of the basin and passive diapirism of the Early Miocene Fars salt as well as further inflation of the Hormuz salt into neighbouring structures. Seismic mapping of the salt-related structures as well as observations in the overlying sediments, such as thickness variations and faulting, also constrain the Late Tertiary passive diapirism of the Hormuz and Fars salt in the Zagros.

Description: Nuclear magnetic resonance (NMR) is a useful tool in reservoir evaluation. The objective of this study is to predict petrophysical properties from NMR T2 distributions. A series of laboratory experiments including core analysis, capillary pressure measurements, NMR T2 measurements and image analysis were carried out on sixteen greensand samples from two formations in the Nini field of the North Sea. Hermod Formation is weakly cemented, whereas Ty Formation is characterized by microcrystalline quartz cement. The surface area measured by the BET method and the NMR derived surface relaxivity are associated with the micro-porous glauconite grains. The effective specific surface area as calculated from Kozeny's equation and as derived from petrographic image analysis of backscattered electron micrograph's (BSE), as well as the estimated effective surface relaxivity, is associated with macro-pores. Permeability may be predicted from NMR by using Kozeny's equation when surface relaxivity is known. Capillary pressure drainage curves may be predicted from NMR T2 distribution when pore size distribution within a sample is homogeneous.

Description: This paper presents an integrated seismic, petrophysical and analogue core study of the Mid-Eocene Grid deep-water Sandstone Member from the Nelson Field area, Central North Sea. Two possible turbiditic units were identified in seismic data. Grid 1 shows channel-like features and a complex stratigraphy whilst Grid 2 consists of scattered bright amplitude events (shown to be slumped shales and chalky limestones by cuttings analysis). Lower Eocene Tay Sandstone Member core from the nearby Gannet Field provided an analogue for sedimentary facies. This enabled petrophysical and seismic observations of the Grid Sandstone Member to be tied to sedimentological facies. An integrated model shows five facies associations and a complex reservoir quality distribution. A comparison with outcrop and seismic examples of channelized turbidites indicates that the Grid system represents a medium-scale channel complex, exhibiting multi-storey, nested offset stacking. This work presents a new example that provides a link between laboratory experiments on topographic interaction of turbidite flows with seismic-scale observations and facies determination. The Grid system also adds to our knowledge of Palaeogene turbidite evolution from sheet-like to channel-like forms and provides a useful analogue for improving hydrocarbon exploration and production efficiency in adjacent areas.

Description: Reservoir mapping in the Gulf of Suez petroleum system is challenging because rift-parallel and cross-rift faults disrupted the sediments, leaving the reservoirs confined to stratigraphic, structural, and combined traps. We have developed a technique to address this challenge that integrates fault outcrop mapping using satellite image interpretation, seismic near-surface characterization techniques such as Rayleigh wave velocity mapping and ray parameter interferometry, as well as ant tracking of faults and geobody delineation on a prestack time-migrated (PSTM) cube. The technique uses a combination of geographic information system (GIS) and geological modelling software such as Petrel for surface/subsurface integration. The joint analysis of Rayleigh wave data with satellite imagery provides a near-surface structural geological model. The acquisition, processing, and interpretation of point-receiver seismic data enables the interpretation of near-surface geological structures. Detailed shallow structural geology can be imaged in the near surface, a data regime that is conventionally masked by the acquisition noise from the seismic acquisition. The shallow geological model comprises shallow lithological horizons as well as fault zones, the mapping of which may assist with the mitigation of shallow drilling risks. The integration of surface and subsurface structural mapping provides a tectonic framework for the delineation of reservoirs in the rift-faulted environment of the Gulf of Suez.

Description: Oceanic and continental lithosphere distribution within the eastern Mediterranean is not well understood. A gravity inversion, incorporating a lithosphere thermal gravity anomaly correction, has been used to map Moho depth, crustal thickness and lithosphere thinning for the eastern Mediterranean, from which the distribution of oceanic and continental lithosphere, the structure of the ocean–continent transition (OCT) and the location of the continent–ocean boundary (COB) can be determined. The gravity inversion results show thin crust and high continental lithosphere thinning under the Ionian Sea and the Herodotus Basin, consistent with these basins being underlain by oceanic crust. Moho depths from gravity inversion are in agreement with seismic refraction estimates in these basins. Highly thinned continental crust is predicted under the offshore Sirte and Levant basins. The sharp decrease in crustal thickness predicted by gravity inversion off the Libyan and Egyptian coast gives an indication of COB location. Crustal thickness and continental lithosphere thinning determined from gravity inversion have also been used to explore the relationship between the Cretaceous West and Central African Rift System (WCARS: Benue Trough, Chad, Central African Shear Zone (CASZ) and Sudan basins) and the eastern Mediterranean basins; continuity between the Cretaceous WCARS and the eastern Mediterranean basins is not apparent in the gravity inversion results.

Description: There is significant opportunity in re-working older data with modern geophysical technology to develop new plays and concepts in the northern and eastern Mediterranean. New exploration success and higher commodity prices have encouraged both majors and independents to reconsider the Mediterranean as a viable entry point to North African and Southern European energy markets. Two case studies in the Adriatic Sea and Levantine Basin are examined for play concepts and leads using vintage seismic data re-imaged with modern imaging techniques integrated together with a geologically driven workflow. The Adriatic was selected based upon maturity of hydrocarbon discovery; in comparison the Levantine Basin ranks as a region of new territory which we are only just beginning to understand.

Description: The offshore Matruh and Herodotus basins of NW Egypt represent an underexplored region of the Eastern Mediterranean with only two wells drilled along the margin to date. The Matruh Canyon segment in the broader Matruh Basin appears to be unique in Egypt having a large gravity-driven linked system detached on shale. The updip extension with blocks bounded by listric normal faults (rafts) in the onshore part of the system transitions into downdip contraction with toe-thrust imbrications in the ultra-deep water part of the Herodotus Basin. The structures above a prominent Cretaceous shale detachment level within the basin fill of the Matruh Canyon developed during two major periods. The Syrian Arc regional-scale inversional episodes appear to trigger and reactivate the gravity-driven linked system during the Santonian and the mid-Cenozoic. Whereas the Messinian unconformity post-dates the formation of the rafts, an offhore segment of the linked system shows neotectonic activity.

Description: Valid palaeotectonic and palaeogeographical reconstructions of the easternmost Mediterranean and adjacent region involve a long-lived Tethys (Rheic, Palaeotethyan and Neotethyan oceans), northward subduction beneath Eurasia and rifting of continental fragments from Gondwana. Rifted microcontinents bordering Gondwana were separated (from south to north) by the Southern Neotethyan ocean, the Berit ocean (new name), the Inner Tauride ocean and the Izmir–Arkara–Erzincan ocean. Mid-Permian to Mid-Triassic pulsed rifting culminated in Late Triassic–Early Jurassic spreading of the Southern Neotethyan oceans (the main focus here). After Early–Mid-Jurassic passive subsidence, the Late Jurassic–Early Cretaceous was characterized by localized alkaline, within-plate magmatism related to plume activity or renewed rifting. Late Cretaceous ophiolites formed above subduction zones in several oceanic basins. Ophiolites were emplaced southwards onto the Tauride and Arabian platforms during the latest Cretaceous. The Southern Neotethys sutured with the Arabian margin during the Early–Middle Miocene, while oceanic crust remained in the Eastern Mediterranean further west. The leading edge of the North African continental margin, the Eratosthenes Seamount, collided with a subduction trench south of Cyprus during the Late Pliocene–Pleistocene, triggering rapid uplift. Coeval Plio-Quaternary uplift of the Taurides may relate to break-off or delamination of a remnant oceanic slab.

Description: Giant gas discoveries in the vicinity have sparked increased interest in the petroleum potential of the Eastern Mediterranean. However, a lack of well data from the area means that a number of crucial unknowns about the region remain. Many of these unknowns relate to uncertainties regarding the sedimentary infill of the main basins, including the sediment provenance areas and elastic properties. The petroleum potential of this region has been investigated through the acquisition and analysis of multiple 2D and 3D seismic surveys offshore Cyprus and Lebanon and a thorough review of available literature regarding the regional geology. An amplitude extraction study indicates sourcing of probable clastic sediments from the NE, from present-day Syria. In addition evidence of conduits coming off onshore Lebanon can be seen in the seismic data. Use of released data from one of the closest wells penetrating the same stratigraphy as the new discoveries enabled us to build a synthetic model over one of these discoveries (Tamar discovery) and to perform a fluid-substitution over this model. Comparison of these results with characteristics of identified leads and prospects in the northern, undrilled part of the Levantine Basin may improve our understanding of the rock properties in this area as similarities in between these may also indicate similarities in the elastic properties.

Description: In sedimentary basins, compaction disequilibrium generates overpressure during rapid burial of fine-grained sediments in the mechanical compaction regime, at temperatures below ~70°C. Mudstones behave differently at greater depths in the chemical compaction regime, at temperatures above ~100°C, where evidence suggests that porosity reduction with increasing depth and temperature continues independently of effective stress up to high values of overpressure. We offer an explanation for this behaviour. The horizontal alignment of clay mineral grains is enhanced during clay diagenesis, creating sub-horizontal, flat pores. Because of their flexibility, the flat pores tend to close even under low values of normal effective stress acting across them. Thus, chemical compaction can proceed unless the net expulsion of pore water from the mudstones is inhibited sufficiently for the flat pores to be held open, which necessarily requires the pore pressure to approach the lithostatic stress. In the Lower Kutai Basin, density log reversals are encountered in mudstones in the chemical compaction regime at depths of 3–4 km, where the pore pressure is close to the lithostatic stress. We attribute these reversals to the inhibition of dewatering during clay diagenesis at shallower depths, when the pore pressure was already close to lithostatic stress. Porosity was preserved by the very high pore pressure holding the flat pores open while the mudstone matrix was being cemented by the products of clay diagenesis. We coin the term ‘chemical undercompaction’ for this process.

Description: This paper reconstructs drainage systems with outlets close to the present-day Nile system, honouring both onshore and offshore evidence and attempts a source to sink quantification. A large river is evidenced to have extended the length of the Red Sea Hills from Eritrea to the current outlet since the Oligocene. The early route of the river is uncertain through Sudan but a more westerly course is proposed through Egypt. The largest contributor of clastic sediment was the Red Sea Hills, where average erosion of the order of 1200–1500 m is constrained by a combination of Apatite Fission Track Analysis, planation surface analysis, and Red Sea sink volumes. Nubia was a significant supplier of sand-rich sediment during wet periods. This sediment supply pattern contrasts with the present-day situation where the Ethiopian Highlands contribute the vast majority of sediments, this contrast being validated by available mineralogical data. This is a consequence of wetter climates in the past and of the younger Ethiopian topography. The interpretations presented here illustrate the importance of hinterland climate change on clastic supply and allow the reservoir fairways in the Nile Cone to be more precisely mapped out in time and space.

Description: Interpretation of 2D long-offset multi-client seismic data acquired by CGGVeritas in 2004–5 has allowed the distribution and composition of the Messinian salinity crisis (MSC) facies to be mapped across the offshore Sirt Basin, Libya. The results reveal that only the Lower and Upper Evaporites are present within the marginal offshore Sirt Basin, with the middle halite unit confined to the deeper basin. The Upper Evaporites, ‘Lago Mare’, are characterized by a period of fluctuating base level and strong water salinity changes controlled by astronomical precession. They consist of interbedded evaporites and clastics with a total of seven precessional cycles recognized, each associated with erosional sub-aerial channels interpreted to have been created by the Eosahabi rivers sourced from the flooding of Neogene Lake Chad. The Lower Evaporites display a high relief, irregular topography which strongly controls the distribution of the overlying Lago Mare facies. They have an overall chaotic high amplitude response with very little internal structure and are interpreted to represent mass transport complex deposits of the Re-sedimented Lower Gypsum unit. There is a strong correlation between the distribution and composition of the MSC facies and the quality of seismic imaging.

Description: The effect of the vertical to horizontal permeability ratio ( k v / k h ) on many displacement properties is significant, making it an important parameter to estimate for reservoir models. Simple ‘streamline’ models have been developed which relate k v / k h at the reservoir scale to shale geometry, fraction and vertical frequency. A limitation of these models, especially for tidally-influenced reservoirs, is the lack of quantitisative geological inputs. To address this lack of data, detailed shale characteristics were measured, using Lidar point clouds, from four different tidally-influenced reservoir analogues: estuarine point bar (McMurray Formation, Alberta, Canada), tidal sand ridge (Tocito Sandstone, New Mexico), as well as both unconfined and confined tidal bars (Sego Sandstone, Utah). Estuarine point bars have long ( x = 67.8 m) shales that are thick and frequent relative to the other units. Tidal sand ridges have short shales ( x = 8.6 m dip orientation) that are thin and frequent. Confined tidal bars contain shales that are thin, infrequent and anisotropic (x– = 16.3 m dip orientation). Unconfined tidal bars contain nearly equidimensional shales of intermediate length ( x = 18.6 m dip orientation) with moderate thicknesses and vertical frequency. The unique shale character of each unit results in a different distribution of estimated k v / k h values. Estuarine point bars have lower average k v / k h values ( x = 8.2 x 10 –4 ) than any other setting because of the long shales they contain. Tidal sand ridges have short, but frequent shales, which results in moderate k v / k h estimates ( x = .011). Estimates of k v / k h are typically highest in confined tidal bars ( x = .038), which contain anisotropic and infrequent shales. Unconfined tidal bars have moderate lengths and frequency resulting in k v / k h estimates averaging 0.004. The results of this study highlight the link between heterogeneity, reservoir architecture and flow parameters.

Description: Large gas reserves are trapped in the coals of the Middle Jurassic (Callovian) Walloon Subgroup (lower part of the Injure Creek Group) in the Surat Basin, eastern Australia. The series is divided into the Juandah Coal Measures (upper), Tangalooma Sandstone and Taroom Coal Measures (lower). The upper and lower units are locally further subdivided. These economically important coals were deposited in an alluvial plain setting within an interior basin, which has no recorded contemporaneous marine influence. The coals are typically bituminous, perhydrous and low rank with a high volatile content. Despite individual ply (bench) thicknesses typically less than a metre, series of plies or seams of coals up to 10 m thick have historically been tentatively correlated across the entire play area (over 150 km).

Description: The Ekofisk Field is a giant field which has been producing at a high level for more than forty years and, since 1987, this production has taken place with the support of sea-water injection. The Danian-aged chalk deposits of the Ekofisk Formation and the Maastrichtian Tor Formation form the main reservoir units in the Ekofisk Field. The Ekofisk Formation principally consists of porous resedimented chalks intercalated with relatively thin and lower porosity beds, called dense zones. A multi-scale study of dense zones, from scanning electron microscopy to wells and seismic impedance data, has allowed the characterization and mapping of these deposits. Five main dense zone lithotypes have been identified: (1) argillaceous chalk; (2) chalk with abundant flint nodules; (3) chalk beds cemented with silica/nano-quartz; (4) calcite-cemented chalk; and (5) stylolitized chalk. The different types of dense zones tend to cluster in certain stratigraphic intervals, such as the EE and EM reservoir units at the base and in the middle part of the Ekofisk Formation. Dense zones have different mechanical properties compared to porous chalks and, depending on the connectivity of their fracture networks, they can act as preferential conduits or baffles for the reservoir fluids. An increased understanding of the distribution, characteristics and geological factors at the origin of the dense zones is fundamental to better define the reservoir architecture and ultimately identify unswept zones for future infill drilling targets. Supplementary material Descriptions of analytical procedures, composition, poro-perm and well log values of dense zone samples is available at: www.geolsoc.org.uk/SUP18573 .

Description: An integrated workflow has been devised for the investigation of deep-water rifted continental margins. At a margin this allows us to predict the crustal structure, the distribution of continental-lithosphere thinning and the location of the ocean–continent transition with a new degree of confidence. The workflow combines the analytical techniques of 2D or 3D gravity inversion, 2D or 3D flexural backstripping with reverse thermal subsidence modelling, upper-crustal fault analysis and rifted margin forward modelling. No one technique on its own can provide all of the required answers, nor can it provide answers without some degree of uncertainty. The use of a combination of techniques, however, provides answers to several different problems and, crucially, more confidence in these answers. The workflow provides direct information on the present-day geometry of rifted margins and leads towards a better understanding of the geodynamic evolution of these margins. It also provides information which can inform the exploration process by making predictions about crustal structure at the ocean–continent transition, the location of the continent–ocean boundary, stretching-factor, heat-flow magnitude and history, palaeobathymetric history and subsurface palaeostructure. Application of the workflow is illustrated here with reference to the continental margins of West India, Brazil, West Australia, Norway and Newfoundland–Iberia.

Description: Sedimentary facies is a key control on petrophysical properties within subsurface reservoirs and facies modelling is a critical aspect of reservoir modelling. Several modelling methods exist and selecting the best approach for a specific case is challenging and time-consuming. Outcrop analogues provide detailed information on architecture, geometry and facies connectivity that is not directly available in the subsurface. By modelling outcrop data it is possible to test and compare different modelling strategies systematically in a case where the geology is well constrained. The Eocene aged, Sant Llorenc del Munt fan-delta complex (NE Spain) is a well exposed, transgressive-regressive fan-delta. Outcrop data were used to test a variety of modelling strategies in which the density of conditioning wells, stratigraphic subdivision, modelling algorithm and trends were all varied. The results of these modelling exercises were compared against themselves and against a close-to-deterministically built Base Case reconstruction using a series of static measures including the distribution of fan-delta front reservoir facies, directional connectivity and reservoir-to-well connectivity. The results highlight the following: (a) the impact of the conditioning well density on improving the stratigraphic architecture reproduction in the different modelling approaches; (b) that surface-based modelling subdivisions including the maximum flooding surface to separate independent grids for modelling the transgressive and regressive sequence sets can be detrimental when compared to using only the top and base of the composite sequence unless additional constraints are included; (c) that an algorithm combining a linear trend and a Gaussian field is the most suitable algorithm for reproducing this type of architecture, but requires defining a 3D trend; and (d) the need for using trends to reproduce the architecture when well data are sparse. These results provide guidelines for modelling analogue fan-delta reservoirs in the subsurface.

Description: Petrographic evidence of thin sheet-like or platelet-shaped quartz cement parallel to bedding is documented in deeply buried, originally smectite-rich, Late Cretaceous mudstones from well 6505/10-1 in the Voring Basin, offshore Norway. The platelets are mainly built up of areas of patchy continuous quartz cement with various amounts of earlier-formed interlocking microquartz crystals. Cathode luminescence (CL) spectra confirm an authigenic origin for the quartz cement. The quartz platelets may originate as flakes (at c. 90-100 {degrees}C) that may evolve into well-developed near-continuous patchy quartz cement identified at 4300 m/150 {degrees}C. The quartz cement is probably sourced from silica released by the clay dissolution-precipitation processes (smectite and smectite/illite to illite and kaolinite to illite). At temperatures above about 90-100 {degrees}C, the continuous supply of silica from these clay mineral reactions results in precipitation of quartz flakes and sheet-like quartz cement. The quartz sheets may act as a mudrock stiffening agent, reinforcing and further cementing together the microquartz networks and aggregates and possibly also enhancing the schistosity and anisotropy of these mudstones during increasing burial. The quartz sheets may also act as vertical permeability barriers in the sediment possibly contributing to overpressure formation during chemical compaction.

Description: The Pereriv Suite reservoir in the Azeri culmination of the ACG Oilfield is characterized by laterally continuous layers of variable net-to-gross (NTG) ratio deposited in a channel-dominated, fluvio-deltaic environment. The reservoir is being developed by down-dip water injection, with up-dip gas injection on the more steeply dipping central north flank. We use high-resolution models derived from outcrop analogue and subsurface data to demonstrate that four key sedimentological heterogeneities control recovery in both oil-water and gas-oil displacements: (1) local variations in NTG within low NTG ( 85%) layers; (3) sinuosity and (4) stacking pattern of channel-fill sandbodies in low NTG layers. The first three heterogeneities control sandbody connectivity; the fourth controls sweep efficiency in the connected sandbodies. Two further heterogeneities control recovery in gas-oil displacements in high NTG layers: (5) vertical-to-horizontal permeability ratio of channel-fill sandbodies and (6) mud clast lags at channel bases. Models which omit these small-scale features predict that sedimentological heterogeneity has little impact on water-oil or gas-oil displacements in high NTG layers, but fail to capture the effect of heterogeneity on the gravity stability of the gas-oil displacement, which significantly impacts on recovery.

Description: Fault seal plays a critical part in hydrocarbon traps, and the same will be true for CO2 storage. The standard workflow for prediction of capillary seal of hydrocarbons can be readily adapted to prediction of CO2 seal since the fluid properties of CO2 at reservoir temperatures and pressures are within the range shown by hydrocarbons. The workflow is applied in a feasibility study into the proposed CO2 storage in the Johansen Formation of the Troll Field. Computation of Shale Gouge Ratio (SGR) over the fault surfaces, in combination with juxtaposition diagrams, was used to estimate the sealing potential of faults cutting the Johansen Formation. SGR values were converted to potential CO2 column heights that might be trapped at each fault. Column heights are generally less than 100 m at each fault, allowing a cross-fault migration route from the Johansen Sand via the Statfjord Formation, Cook Formation and Brent Group. Analysis of in-situ stresses suggests that the faults in the Troll Field are not close to failure and therefore up-dip leakage of CO2 is unlikely. Extremely large CO2 columns (〉300 m) would be required to change this stress stability, and across-fault capillary leakage would occur first.

Description: Exploration well 50/26b-6 in the UK Southern North Sea discovered a trap containing a gas-bearing Rotliegend Group (Leman Sandstone Formation) reservoir which was a major surprise at the time of drilling in that its gas composition was approximately 50% CO2 (with 9% N2 and the remainder methane). Christened the Fizzy Discovery', the accumulation was appraised by well 50/26b-8. Subsequently, another CO2-rich discovery (Oak) was made along-strike in nearby block 54/1b. Column heights at the well locations are of the order of a few tens of metres, but at the Fizzy Discovery the column height at the trap crest is estimated to be over 200 m. Interpretation of a high fidelity PSTM 3D seismic dataset has been constrained by 33 exploration wells allowing fault geometries and stratigraphic offsets to be determined with confidence. Despite late-stage (Late Cretaceous) structural inversion, the net boundary-fault offset is sufficient in both the Fizzy and Oak discoveries to almost breach the Zechstein Group evaporite super-seal, and the CO2-bearing Rotliegend Group in the footwall is now juxtaposed against hanging wall sediments of the uppermost Zechstein Group. Hence, these Zechstein Group units evidently act as a robust long-term side-seal for the carbon dioxide column. The Fizzy and Oak accumulations are noteworthy in providing a natural demonstration of top seal and fault side-seal integrity for carbon dioxide in a subsurface reservoir, that has remained intact over a geological timescale in what is otherwise a prolific methane-rich reservoir play fairway.

Description: The Bunter Sandstone Formation (BSF) in the UK sector of the Southern North Sea is thought to have a significant potential for the injection and storage of anthropogenic CO 2 within periclines that lie above salt domes and pillows formed by halokinesis in underlying Zechstein strata. During the formation of the periclines, the BSF and its overlying top seals were subjected to extensional stresses and, in consequence, are commonly cut by seismically resolvable faults that present a risk to the containment of gas and buoyant fluids such as supercritical CO 2 . Although most of the closed structures in the BSF are saline water-bearing, eight gas fields (total gas initially-in-place 〉72 bcm (billion cubic metres)) have been discovered to date. The seismically resolved structure of these gas fields demonstrates that two different top seals, the Haisborough Group and the Speeton Clay, can seal gas columns of up to 128 and 104 m respectively, despite the presence of faults with small displacements above the field gas–water contacts. The observed gas columns are equivalent to CO 2 columns of up to around 100 m in height. Simple geomechanical modelling suggests that existing optimally orientated faults may dilate or be reactivated if the pore-fluid pressure increase as a result of CO 2 injection exceeds a gradient of about 13.4 MPa km –1 , potentially resulting in loss of storage integrity.

Description: Pore-lining chlorites are often associated with a low-resistivity contrast between corresponding reservoir units, making the identification and quantitation of hydrocarbon-bearing intervals difficult. In many low-resistivity situations, the traditional approach of using Archie’s equation to determine saturation from electrical resistivity fails, and modified Archie equations derived specifically for ‘shaly sands’ have been developed. In chlorite-bearing intervals, however, the effect of chlorite can be such that both Archie and the so-called shaly-sand models are inappropriate. Under these circumstances, calculating saturation from electrical resistivity can be circumvented by detailed analysis of the sedimentology and petrophysics, enabling the construction of a saturation height model based on core data. In this novel study we integrate a detailed core-based sedimentological facies scheme with wireline log data and petrophysical core data to demonstrate a clear link between chlorite occurrence, petrophysical characteristics and saturation height. Through this innovative approach, saturation is estimated without recourse to resistivity logs and improves hydrocarbon saturation estimates in chlorite-bearing reservoirs.

Description: Preliminary dynamic modelling, using TOUGH2/ECO2N, has been carried out to assess the suitability of a site in the UK North Sea for sequestering CO 2 . The potential storage site is a previously unused saline formation within the Permian Rotliegend sandstone. Data regarding the site are limited. Therefore, additional input parameters for the model have been taken from the literature and nearby analogues. The sensitivity of the model to a range of parameters has been tested. Results indicate that the site can sustain an injection rate of around 2.5 Mt a –1 of CO 2 for 20 years. The main control on pressure build-up in the model is the permeability of the unit directly beneath the Rotliegend in the location of the proposed storage site. The plume diameter is primarily controlled by the porosity and permeability of the site. A comparison between static, analytical and dynamic modelling highlights the advantages of dynamic modelling for a study such as this. Further data collection and modelling are required to improve predictions of pressure build-up and CO 2 migration. Despite uncertainties in the input data, the use of a full three-dimensional (3D) numerical simulation has been extremely useful for identifying and prioritizing factors that need further investigation.

Description: Natural gas hydrate (NGH) is a solid crystalline material composed of water and natural gas (primarily methane) that is stable under conditions of moderately high pressure and moderately low temperature found in permafrost and continental margin sediments. A NGH petroleum system is different in a number of important ways from conventional petroleum systems related to large concentrations of gas and petroleum. The critical elements of the NGH petroleum system are: (1) a gas hydrate stability zone (GHSZ) in which pressure and temperature lie within the field of hydrate stability, creating a thermodynamic trap of suitable thickness for NGH concentrations to form; (2) recent and modern gas flux into the GHSZ along migration pathways; and (3) suitable sediment host sands within the GHSZ. These elements have to be active now and in the recent geological past. Exploration in continental margin sediments includes basin analysis to identify source and host sediment likelihood and disposition, potential reservoir localization using existing seismic analysis tools for locating turbidite sands and estimating NGH saturation, and deposit characterization using drilling and logging. Drilling has validated first-order seismic analysis techniques for identifying and quantifying NGH using rock physics mechanical models.

Description: Understanding the controls on the size and shape of sandstone bodies deposited by fluvial systems is important in the reconstruction of ancient fluvial deposits and construction of quantitative reservoir models. Measurements and analyses of sandbodies from remotely sensed imagery have allowed quantification of width and length ratios of barforms in modern fluvial systems. For bank-attached bars the width:length ratios range between 0.12 and 0.47 (arithmetic mean: 0.25), for lateral bars between 0.19 and 0.42 (arithmetic mean: 0.30), for mid-channel bars between 0.09 and 0.49 (arithmetic mean: 0.28), and for point bars between 0.14 and 0.50 (arithmetic mean: 0.30). The majority of width:length ratios for all bar types range between 0.15 and 0.35. Examination of other parameters such as basin type, planform geometry, apparent stream width, river length, gradient over the investigated area, aggradational or degradational system, tectonic setting and climate do not significantly affect the width:length ratio. Therefore, the bar planform shape, the width:length ratio, can be considered to be scale invariant. The recognition that bar planform shape in fluvial systems is scale invariant will be useful in the construction of subsurface three-dimensional models of fluvial deposits with variable dimensions. Supplementary material: Data tables with information obtained for all of the rivers studied are available at http://www.geolsoc.org.uk/SUP18745 .

Description: The carbonate-dominated Albian to Turonian succession is one of the key petroleum systems of the Arabian Plate. It is dominated by shallow water platform carbonates that were deposited in a shallow epeiric sea on the margins of Neotethys. In general, the reservoirs in this succession have high porosities but exhibit heterogeneous permeabilities. This study reviews published data for the region and attempts to unravel the key diagenetic controls on the porosity and permeability of the reservoirs. The results demonstrate that a spectrum of diagenetic processes created highly heterogeneous multimodal pore networks. Intense boring and micritization of skeletal allochems, differential cementation of a pervasive burrow network and preferential dissolution of aragonitic skeletal allochems are ubiquitous. Locally, particularly on the northern and eastern Arabian Plate, deep-penetrating epikarst can be tied to a differential response to global sea level fluctuation and local tectonism. The development of a peripheral bulge in late Cenomanian–Turonian times, halokinesis, localized influx of channelized clastic material and sub-regional climatic variability contributed to a heterogeneous pattern of meteoric diagenesis across the Arabian Plate. The succession was then buried to up to 10 km during the Late Cretaceous–Tertiary. Where deep-penetrating fault systems were reactivated by Alpine tectonism, flushing by hydrothermal brines resulted in highly localized patterns of hydrothermal dolomitization and leaching, associated with hydrocarbon emplacement.

Description: In reservoir characterization, rock-physics models provide the link between seismic observables (density, compressional and shear wave speeds) and reservoir parameters, such as porosity, lithology and fluid saturation. However, the accuracy of these predictions is rarely explored. In fact, the validation of a model representing a dataset is often limited to the analysis of a cross-plot of two arbitrary magnitudes. The objective of this paper is to improve the calibration procedure through a quantitative assessment of the reservoir property predictions using various rock-physics models. The analysis is based on an inverse rock-physics modelling that organizes the rock-physics transforms into constraint data so that the seismic variables are direct functions of the reservoir parameters. It is revealed that the predictions of reservoir quality can assist in the diagnosis of the rock microstructure itself, such as the location of clay particles in clay-rich sediments. In addition, we found that a quantitative analysis is the only way to evaluate accurately the performance of various models when studying heterogeneous datasets.

Description: Although reservoir quality cut-off criteria have been used for more than 50 years as a guide for economic decisions, there is still no rational procedure for identifying and applying them in Iranian oil and gas fields. In other words, there are different ‘rules-of-thumb’ in different sections of the National Iranian Oil Companies for determination of cut-off values. For instance, in one section, values of 10%, 50% and 50% are used for porosity, water saturation and shale content cut-offs, respectively; in another section, cut-off criteria are not used at all, simply an estimate of the time when 20% of oil-in-place could be produced. This paper addresses the optimization of cut-off value estimation from raw and processed petrophysical data based on extracting the most appropriate relationship for permeability as a function of porosity, water saturation and shale content – k = ƒ(ϕ, Sw, Vsh). The procedure starts by looking at permeability as the key parameter in choosing a cut-off value because sometimes the minimum value (the permeability cut-off) is directly related to economic circumstances and is defined by the client. Regression analysis coefficients of 0.936 and 0.870 were achieved for relationships of the form k = ƒ (ϕ, Sw, Vsh) in the two petrofacies intervals studied. This leads to specification of minimum k values of permeability and determination of optimum cut-off values for ϕ, Sw and Vsh. This method is then used to determine optimum cut-off values for the Burgan Member (sandstone) in the Kazhdumi Formation in an offshore oil field in the Persian Gulf. The calculated cut-off values for this case for k = 1.0 mD are ϕ = 12.5%, Sw = 60% and Vsh = 27%, as opposed to the ‘standard’ corporate values of ϕ = 10%, Sw = 50% and Vsh = 50%.

Description: A detailed seismic stratigraphic interpretation of a previously unpublished, well-calibrated 3D seismic volume and regional 2D seismic lines in the Northern Porcupine Basin, west of Ireland has provided significant insights into the basin development, sedimentary fill and petroleum prospectivity within this area of the Irish Atlantic continental margin. The results of the seismic interpretation presented here provide a detailed description of the evolution of the Connemara discovery and have resulted in a revised model for the tectonic development and stratigraphic evolution of the fault block structure containing the oil accumulation. The new seismic stratigraphic analysis also provides the basis for an alternative interpretation of Early Cretaceous ‘clinoform’ features based on the results of the 3D seismic interpretation which supports a genesis through structural rotation of onlapping horizons rather than depositional downlap favoured by previous interpretations. This new-found structural and stratigraphic understanding not only has significant implications for determining the main controls on the Connemara discovery, but also provides a basis upon which to place other prospective structures in their regional context, including the identification and risking of exploration plays and prospects in the area.

Description: The Simply Folded Belt of the Zagros Mountains, Iran, is a spectacularly well-exposed example of a foreland fold and thrust belt. A regional analysis of the Cenomanian–Coniacian Sarvak and Ilam Formations, exposed in the southern Lurestan Province, is presented as a case study for sub-seismic fracture development in this type of compressive setting. The area is characterized by gentle to tight anticlines and synclines parallel to the NW–SE trend of the belt. In the Lurestan Province, the Cenomanian–Coniacian interval is exposed in the core of most of the outcropping anticlines. Fold style is intimately related to both vertical and lateral facies distribution.Geometry, kinematics and timing of sub-seismic fractures were characterized through extensive fieldwork, interpretation of orthorectified QuickBird imagery and interpretation of 3D photorealistic models derived from LiDAR. Data were collected from 12 anticlines covering an area of approximately 150 × 200 km. Key outcrops for understanding fracture geometry, kinematics and timing are presented.Field observations and interpretation of QuickBird and 3D photorealistic models reveal the complexity of fracture geometry and timing. Fractures record pre-, syn- and post-folding stages of deformation. Pre-folding structures include synsedimentary normal faults, and subsequent small-scale thrusts, systematic veins and stylolites. During folding, pre-existing fracture planes were re-activated and through-going fractures and reverse faults developed. Strike-slip faults typically postdate pre- and syn-folding structures and are probably related to the late stages of fold tightening. All structures are geometrically and kinematically consistent with the trend of the Arabian passive margin and its subsequent tectonic inversion.

Description: In Jabal Madmar in the Sultanate of Oman, Cretaceous epeiric carbonate platform architectures were characterized by employing a digital outcrop modelling workflow. A framework model for Natih Sequence I (Natih E member) was established, which embeds a meticulously studied platform-top incision and shoal complex. Outcrop-scale clinoforms are recognized in these shoals by hectometre-scale (100 m long) medium to high-angle (1–5°) inclined stratal surfaces comprising texture-based facies transitions. These clinoforms are usually beneath the resolution of seismic data and as such are not easily recognized and correlated between wells. Geologically realistic clinoform models were built using a well-defined stratigraphic model that incorporated inclined surfaces in the model grid and if available, data on lateral facies transitions. Waterflood simulations demonstrated improved sweep efficiency in these models. In contrast, simple models without clinoform heterogeneities resulted in less efficient piston-like patterns of sweep. The study presented in this paper demonstrates an outcome contrary to previous studies, as in this study, barriers to flow are absent. Complex clinoform models must be considered in reservoir modelling workflows to correctly derive static and dynamic rock properties. This is because outcrop-scale clinoforms have a potential impact on reservoir behaviour under secondary and tertiary recovery mechanisms.

Description: Outcrop data derived from fieldwork, remote sensing satellite and LiDAR-derived 3D models were used to build an integrated dual porosity-permeability static reservoir model which captured stratigraphic, diagenetic and structural heterogeneities. The study focuses upon the Mishrif-Mauddud/Sarvak interval, one of the most prolific reservoir units in the Middle East. The study area is exceptionally well exposed in deep gorges which cut transversally across anticlines of the Simply Folded Belt of the Zagros Mountains. The outcrops reveal volumetrically significant dolomitization of the latest Albian to Turonian carbonates of the Lower and Upper Sarvak formations. Three different dolomite bodies, which are spatially connected and genetically linked to the same fluid flow event, were recognized and mapped: (1) a thick dolomite body replacing the Lower Sarvak and forming a massive dolomite core; (2) horizontally extensive stratabound dolomite bodies (sheets), emanating laterally from the massive dolomite; and (3) vertically elongated dolomite pipes, rooted in the massive dolomite and typically replacing slope facies of the Upper Sarvak Formation.The widespread development of tight, non-planar dolomite textures (a typical feature of high temperature dolomitization) drastically reduces the reservoir potential of the dolomitized geobody in the study area. In particular, this is present in the massive dolomitized body. Vuggy porosity seems to increase porosity only locally and to a limited extent, developing a non-connected pore network. The dominant porous dolomite textures are more abundant in the peripheral part of the geobody (dolomite sheets), where they are strongly controlled by precursor facies and diagenesis. Three main dolomite pore types were identified (intercrystalline, interparticle and mouldic), linked to the depositional environment of the precursor limestone. These pore types were used for petrophysical modelling. The approach adopted in this study allowed the distribution of rock properties in the dolomitized geobody to mimic the main depositional facies architecture.The study area is characterized by a simple fracture network. Two main fracture sets and two major sets of conjugate normal faults were recognized in the field and mapped on 3D virtual outcrop data. Non-stratabound fracture density varied according to stratigraphic unit and/or dolomite body type (pipes/massive/sheets), showing a general increase from precursor limestone to dolomite. Fracture density also varied according to distance from faults (fault damage zone). This was particularly true in the limestone. The data also showed a prominent increase in fracture height from limestone to dolomite bodies, indicating that the dolomitized geobodies are likely sites for high production and early water breakthrough.

Description: Investigation of core and outcrop samples of the Cenomanian Natih-B Member (North Oman) indicates that the different lithofacies present experienced rather different early diagenesis shortly after deposition. Transmitted-light, cathodoluminescence and backscattered scanning-electron microscopy, as well as stable-isotopic, X-ray diffraction and total organic carbon (TOC) analyses were employed to delineate the major controls on the cyclic pattern of early diagenesis and hydrocarbon source potential.The Natih-B intrashelf basinal carbonates are composed of pelagic sediments that exhibit high-frequency cyclicity marked by decimetre-thick lithofacies alternations, mainly between: Lithofacies A compacted, partially bioturbated, skeletal, organic carbon-rich mudstone to wackestone; and Lithofacies B uncompacted, extensively bioturbated, skeletal, sparry-calcite rich wackestone to packstone. Individual units are composed variously of authigenic and biogenic calcite (58.1–97.6%, average 78.5%) and organic carbon (0.3–13.7% TOC, average 3.6%), together with minor quartz, clay, pyrite, dolomite and phosphatic material (fish debris). Lithofacies A contains relatively more organic carbon, clay, pyrite and dolomite than Lithofacies B and constitutes an excellent source rock. Diagenetic textures of Lithofacies A are dominated by compactional deformation of burrow fabrics, faecal pellets and solution seams, in addition to zoned/bright luminescent, non-ferroan sparry and isopachous calcite cement in and around uncompacted foraminifer tests, in an uncemented matrix. In contrast, Lithofacies B does not show any signs of compaction other than microstylolites and is dominated by zoned/dull luminescent, non-ferroan calcite microspar replacement, in addition to pore-filling, predominantly dull-luminescent, non-ferroan, sparry calcite cement. Moreover, Lithofacies B shows evidence of isopachous and meniscus-style cementation, together with geopetal structures and mictritic peloids. Stable-isotopic compositions of both lithofacies were determined from whole-rock samples (δ13C = −0.9 to +0.9‰, average +0.3‰; δ18O = −5.6 to −3.7‰, average −4.8‰) and sparry calcite (both cement and matrix) subsamples (δ13C = −0.6 to +1.2‰, average +0.6‰; δ18O = −5.7 to −3.7‰, average −4.3‰); all results being relative to Vienna Pee Dee Belemnite.These petrographic and isotopic characteristics suggest that the Natih-B abundant calcite cements and replacements were precipitated early, prior to compaction, mainly from ‘normal’ (open, oxic) seawater at slightly elevated depositional temperatures. Some of the slightly negative δ13C values, however, indicate an addition of isotopically light carbon, probably derived from organic-matter oxidation by organisms living in marine pore waters. Based on evidence of extensive seafloor bioturbation and cementation, and their position within the depositional succession, the tops of Lithofacies B (wackestones to packstones) are interpreted as ‘discontinuity surfaces’ that cap shallowing-upward, fifth-order cycles, formed as a function of sediment starvation and increased bottom-current activity during relative sea-level stillstand/turnaround. In contrast, Lithofacies A (mudstones to wackestones) is believed to reflect high organic production coupled with high sedimentation rate and rapid burial. These conditions limited total infaunal colonization and extensive calcite precipitation, and preserved organic matter together with some escape burrows and in-place fauna, suggesting episodic sediment influx when more accommodation was available and seafloor diagenesis was minimized during relative sea-level rises. The relatively higher amounts of pyrite and dolomite in Lithofacies A likely indicate organic-matter degradation by bacterial sulphate reduction in anoxic pore waters during shallow burial.

Description: Accurate rock property prediction is often a critical success factor for wells targeting hydrocarbons. This applies not only to reservoir porosity and permeability affecting productivity directly, but also to acoustic velocity, seismic time-to-depth conversion and depth prognosis. A detailed analysis of variation in the overburden rock velocity in the Southern North Sea has shown that Triassic velocity variations of up to 18% occur within short distances (e.g.

Description: Effective permeability to water in a petroleum column was estimated from routinely-measured mercury injection capillary pressure data of reservoir rocks, by applying a well-known reservoir engineering formula. The gradient of hydraulic potential across the column for a simplified petroleum trap model was then calculated to assess the realistic magnitude of hydrodynamic effects on capillary seal capacity under abnormally pressured conditions. The estimated effective permeability to water in the column ranges from 10–2 to 10–3 mD, even at several hundreds of metres above the free water level where it must become minimal. Since this figure is significantly larger than permeability of typical seals, it results in a negligible gradient of hydraulic potential in the column. The calculation, though including inherent uncertainties, indicates that hydrodynamics play a minor role on capillary sealing of typical petroleum traps, providing the reservoirs are water-wet, their tortuosity does not change with water saturation, and their anisotropy is not significantly large.

Description: World-wide exploration for unconventional hydrocarbon accumulations has been increasing in the last decade. The deep Makó Trough of the Pannonian Basin in southeast Hungary has become a new target for companies looking for unconventional gas resources, but so far the exploration drilling has been unsuccessful.To investigate the size of the assumed basin-centred gas accumulation we have studied the hydrocarbon potential of the source rocks in the Makó Trough using 3D basin and petroleum system modelling technology. The thermal and maturity history and timing of hydrocarbon generation were assessed, and the generated volume of hydrocarbons estimated and compared with the pore volume of the assumed unconventional reservoirs. The estimated mean volume of gas generated in the drainage area (490–650 × 109 Sm3) [given at surface conditions] is much less than the volume (〉14 × 1012 Sm3) needed to fill the basin-centred gas accumulation. Therefore, the Makó Trough is unlikely to contain a large tight-gas sand accumulation. The Endrőd Marl is a fair quality, gas-prone source rock with average original TOC values of 0.75 wt%, reaching 1.5 wt% in the Hód-I and Makó-7 wells. These are below the TOC values of the proven gas shales of North America.

Description: This stratigraphic article summarizes a number of observations on the mid-Cretaceous stratigraphy of Arabia made during the 2nd Arabian Plate Geology Workshop held in Abu Dhabi in January 2010. These observations pertain to the lithostratigraphic nomenclature applied on the eastern Arabian Plate and its relationship to mid-Cretaceous (Late Aptian–Turonian) depositional systems and sequences recognized plate-wide. It appears that several of the commonly applied lithostratigraphic terms are diachronous as a result of (i) plate-wide migration of carbonate and siliciclastic facies belts; (ii) the occurrence of intra-shelf basins at different times and locations; (iii) differential preservation beneath erosional unconformities; and (iv) simple differences in usage across political boundaries. A plate-wide sequence stratigraphic scheme is thus a powerful tool for regional correlation and mapping, and for reconciling lithostratigraphic differences.The studied interval can be subdivided into two primary sedimentary systems that differ in lithology, depositional geometries and dominant faunal assemblages. First, latest Aptian- and Albian-aged systems, which are characterized by volumetrically significant Arabian Shield-derived siliciclastics (both sandstones and claystones) that alternate with carbonate beds. The carbonate beds thicken up-section and have generally very low-angle, muddy ramp depositional geometries. Organic-rich basinal facies are found only in the Kazhdumi Basin in SW Iran at this time. The faunal composition of the carbonates is dominated by benthic foraminifera (notably orbitolinids). Within this succession three third-order depositional sequences are distinguished (MFS K90, K100 and K110). Secondly, Cenomanian–early Turonian-aged sedimentary systems are characterized by a marked reduction in siliciclastic influx, the development of carbonate platform to intra-shelf basin topography and deposition of basinal source rocks. Rudists are the dominant component of grainy, high-energy platform margin/barrier facies, and are also present in the platform top sediments. Within this succession three Cenomanian sequences can be correlated clearly at the scale of the plate (MFS K120, K130 and K140), whereas the number of sequences in the Turonian interval is less well known owing to significant local erosion and/or non-deposition during a period of tectonic instability.Applying this robust sequence stratigraphic framework in combination with a synthesis of biostratigraphic age calibration demonstrates the diachronous character of the Mauddud, Safaniya, Ahmadi and Mishrif formations and equivalents from the southern to the northern part of the Arabian Plate.

Description: The reduction of fluid pressure during reservoir production promotes changes in the effective and total stress distribution within the reservoir and the surrounding strata. This stress evolution is responsible for many problems encountered during production (e.g. fault reactivation, casing deformation). This work presents the results of an extensive series of 3D numerical hydro-mechanical coupled analyses that study the influence of reservoir geometry and material properties on the reservoir stress path. The stress path is defined in terms of parameters that quantify the amount of stress arching and stress anisotropy that occur during reservoir production. The coupled simulations are performed by explicitly coupling independent commercial geomechanical and flow simulators. It is shown that stress arching is important in reservoirs with low aspect ratios that are less stiff than the bounding material. In such cases, the stresses will not significantly evolve in the reservoir, and stress evolution occurs in the over- and sideburden. Stiff reservoirs, relative to the bounding rock, exhibit negligible stress arching regardless of the geometry. Stress anisotropy reduces with reduction of the Young's modulus of the bounding material, especially for low aspect ratio reservoirs, but as the reservoir extends in either or both of the horizontal directions, the reservoir deforms uniaxially and the horizontal stress evolution is governed by the Poisson's ratio of the reservoir. Furthermore, the effect of the stress path parameters is introduced in the calculation of pore volume multiplier tables to improve non-coupled simulations, which otherwise overestimate the average reservoir pore pressure drawdown when stress arching is taking place.

Description: In this paper we describe an improved sample-preparation technique for applying confocal laser scanning microscopy to image the void space of porous geological media, particularly various kinds of carbonate rocks with significant microporosity. We have improved the existing sample-preparation technique for confocal imaging by introducing a positive-pressure application step. This additional step helps to force the fluorescent-doped epoxy mixture inside the submicron pores (the microporosity) which make up a significant fraction of the total porosity of the carbonate rocks being characterized using confocal laser scanning microscopy. We also provide additional technical details and discuss practical aspects important to consider when imaging carbonate rock samples using this technique.

Description: Analytical well-test solutions are mainly derived for simplified and idealized reservoir models and therefore cannot always honour the true complexity of real reservoir heterogeneities. Pressure transients in the reservoir average out heterogeneities, and therefore some interpretations may not be relevant and could be misleading. Geological well testing refers to the numerical simulation of transient tests by setting up detailed geological models, within which different scales of heterogeneity are present. The concept of geological well testing described in this paper assists in selecting from multiple equi-probable static models. This approach is used to understand which heterogeneities can influence the pressure transients. In this paper, a low-energy multi-facies fluvial reservoir is studied, for which data from a well test of exceptionally long duration are available. The pervasive low reservoir quality facies and restricted macro cross-flow between the reservoir layers give rise to an effective commingled system of flow into the wellbore (i.e. zero or very low vertical cross-flow between the reservoir units). In our model, facies transitions produce lateral cross-flow transients that result in a ‘double-ramp-effect’ signature in the test response. A sophisticated multi-point statistical (MPS) facies modelling approach is utilized to simulate complex geological heterogeneities and to represent facies spatial connectivity within a set of generated static models. The geological well-test model responses to a real well-testing cycle are then evaluated using dynamic simulation. The pressure match between simulated and recorded data is improved by generating multiple facies and petrophysical realizations, and by applying an engineering-based hybridization algorithm to combine different models that match particular portions of the real well-test response. In this example, the reservoir dynamics are controlled by subtle interaction between high-permeability channels and low-permeability floodplain deposits. Effective integration of geology and dynamic data using modern methods can lead to better reservoir characterization and modelling of such complex reservoir systems.

Description: Many diverse challenges – political, economic, legal and technical – face the continued development and deployment of geological storage of anthropogenic CO 2 . Among the technical challenges will be the satisfactory proof of storage site security and efficacy. Evidence from many past geotechnical projects has shown the investigations and analyses that are required to demonstrate safe and satisfactory performance will be site specific. This will hold for the geomechanical assessment of saline aquifer storage site integrity where, compared to depleted hydrocarbon fields, there will be no previous pressure response history or rock property characterization data available. The work presented was carried out as part of a project investigating the improvement in levels of confidence in all aspects of saline aquifer site selection and characterization that could be expected with increasing data availability and in-depth analysis. Attention focused on the geomechanical modelling and the rock mechanics data used to populate models of two storage sites in geological settings analogous to those where CO 2 storage might be considered. Coupled geomechanical models were developed from reservoir simulation models initially incorporating generic rock mechanical properties and then laboratory-derived site-specific properties. The models were run in various configurations to investigate the effect of changing the rock mechanical properties on the geomechanical response of the storage systems. Modelling results showed that the pressure response at one site due to low injectivity caused significant potential for fault reactivation. Increasing the number of injection wells, thereby reducing the individual rates needed to deliver the target capacity, reduced the injection pressures and ameliorated, but did not eliminate, this adverse response.

Description: Core samples from seven wells in Lower Cretaceous limestones of the Upper Shu’aiba Member were characterized by conventional core analyses, petrography, bulk chemistry and mercury-injection capillary pressure data to define reservoir rock types (RRT). In the main oilfield studied, lithofacies are arranged in three main belts corresponding to ramp crest, upper slope and lower slope, with bioclast content and size decreasing down depositional dip. Rock typing is based on the observation of distinct, but overlapping, porosity–permeability transforms for each lithofacies, although most samples plot in or below the class 3 field of Lucia, reflecting the presence of abundant lime-mud matrix. Because of the wide range of porosity in each of the main lithofacies, an arbitrary division at 20% porosity is used in combination with lithofacies to define RRT with both three-dimensional (3D) geological significance and distinct ranges of permeability and capillary pressure characteristics. The use of total porosity as a rock-typing criterion is based on the interpretation that porosity is controlled on the reservoir scale by the depositional clay content of the local stratigraphic environment. The seaward and uppermost parts of the clinoforms a have low clay, and, thus, highest porosity. Because both lithofacies and porosity are linked to the sedimentological and stratigraphic organization of the Upper Shu’aiba clinoforms, the RRT can potentially be implemented in a reservoir model for assigning distinct ranges of petrophysical properties to the different architectural elements comprising each clinoform. Two additional grain-dominated RRT have also been defined in a single core that was available from a second oilfield.

Description: One of the main objectives of nanotechnology in the oil industry is to identify applications that could bring significant benefits to enhanced oil recovery. Therefore, it has attracted the attention of many researchers over the last decade. This paper experimentally investigates the efficiency of surface-modified silica nanoparticles in enhanced oil recovery. These nanoparticles improve oil recovery through two main mechanisms: oil–water interfacial tension reduction; and wettability alteration. Various concentrations of nanofluid were made, and their effect on wettability and interfacial tension were investigated to determine the optimum concentration for injection into core samples. The results indicate that a concentration of 4 g l –1 is the optimum concentration. Moreover, this paper reports the nanofluids’ potential in enhanced oil recovery of water-wet core plugs. The results of coreflood experiments reveal that oil recovery increases by 26.2% and total oil recovery considerably improves after the injection of nanofluid. In addition, filtration of the nanofluid before injection into the core was very effective in reducing the risk of possible permeability damage that occurred due to the deposition of large nanoparticle aggregates onto the rock surface.

Description: The wireline gamma-ray log is sensitive to open-hole conditions and, in particular, the diameter. This means that the log can jump at casing points. Although environmental corrections exist, they can fail at these points. We present a Bayesian method for deriving a new quantity – the shifted gamma–ray index – that takes these shifts into account by fitting a piecewise linear function to open-hole data in a depth window around the casing point. Because it is Bayesian, the method enables us to assess our uncertainty about its performance. This method requires very little knowledge of the borehole or drilling conditions but relies on the assumption that the lithology is consistent. Investigating the other wireline logs enables us to assess whether this assumption is valid. We demonstrate our method using well data from offshore mid-Norway.

Description: Hydrocarbon leakage is a major exploration challenge in the western Hammerfest Basin. Most exploration failures in the area have been attributed to leakage; hydrocarbon-bearing traps are rarely filled to their structural capacity, and almost all traps have hydrocarbon shows down to their structural spillpoint or below. We have investigated to what extent the hydrocarbon column heights can be explained by vertical leakage along faults or at fault intersections. For the fields that we evaluated we observe that: (a) all dry structures have fault intersections at top reservoir level up dip of the well position: (b) the only structure where no faults intersect at top reservoir level is the only structure that is clearly filled to structural spillpoint; and (c) all fluid contacts in underfilled structures broadly coincide with the position of intersecting faults. The underfilled structures have less than two fault intersections up dip and above the gas-bearing reservoir. We suggest that vertical leakage at fault intersections has exerted a main control on the position of the gas–water contacts in the western Hammerfest Basin, and therefore that hydrocarbon column-height predictions can be improved by addressing the positions of such intersections at the top reservoir surface.

Description: Future geological CO 2 sequestration in the Gippsland Basin is contingent upon an effective regional top seal; potentially provided by the late Oligocene–early Miocene Lakes Entrance Formation. This study integrates various top-seal assessment methodologies into a workflow to estimate the efficiency of the Lakes Entrance Formation as a top seal. Factors related to, for example, top-seal lithology, shale volume, carbonate content and fracture density, and factors relating to the faults that cut the top seal, fault-zone shale content, strain, slip-tendency, etc., are compared to hydrocarbon leakage and seepage indicators reported in the study area. The factors that best correlate with reported leakage indicators are combined to map the spatial risk variation. While the study indicated that the ultimate control on top-seal efficiency is the formation’s membrane seal capacity; it also highlighted the spatial correlation between leakage indicators and some fault-related factors, suggesting that faults are key to top-seal bypass in much of the Gippsland Basin. Fault-zone shale content proved the dominant fault-related factor; as such, it can be concluded in the Gippsland Basin, at least, that a fault-zone shale content of less than 0.3 is the dominant factor with regard to faults enabling fluids to bypass top seals.

Description: The initialization of a reservoir simulator calls for the populating of a three-dimensional dynamic grid-cell model using subsurface data and interrelational algorithms that have been synthesized to be fit for purpose. These prerequisites are rarely fully satisfied in practice. This paper sets out to strengthen initialization through four key thrusts, all of which seek to optimize the bridgehead between reservoir geoscience and reservoir engineering, and thereby maximize value from reservoir simulation. The first addresses representative data acquisition, which includes the key-well concept as a framework for the cost-effective incorporation of free-fluid porosity and permeability within an initialization database. The second concerns the preparation of these data and their products for populating the static and dynamic models. Important elements are dynamically conditioned net-reservoir cut-offs, recognition of primary flow units, and establishing interpretative algorithms at the simulator grid-cell scale for application over net-reservoir zones. The third thrust is directed at the internal consistency of capillary character, relative permeability properties and petrophysically-derived hydrocarbon saturations over net reservoir. This exercise is central to the simulation function and it is an integral component of hydraulic data partitioning. The fourth concerns the handling of formation heterogeneity and anisotropy, especially from the standpoint of directional parametric averaging and interpretative algorithms. These matters have been synthesized into a workflow for optimizing the initialization of reservoir simulators. In so doing, a further important consideration is the selection of the appropriate procedures that are available within and specific to different software packages. It is the authors’ experience that implementation of these thrusts has demonstrably enhanced the authentication of reservoir simulators through more readily attainable history matches with less required tuning. This outcome is attributed to a more systematic initialization process with a lower risk of artefacts. Of course, these benefits feed through to more assured estimates of ultimate recovery and, thence, hydrocarbon reserves.

Description: The Fjerritslev Formation in the Norwegian–Danish Basin forms the main seal to Upper Triassic–Lower Jurassic sandstone reservoirs. In order to estimate the sealing potential and rock properties, samples from the deep wells Vedsted-1 in Jylland, and Stenlille-2 and Stenlille-5 on Sjælland, were studied and compared to samples from Skjold Flank-1in the Central North Sea. Mineralogical analyses based on X-ray diffractometry (XRD) show that onshore shales from the Norwegian–Danish Basin are siltier than offshore shales from the Central Graben. Illite and kaolinite dominate the clay fraction. Porosity measurements obtained using helium porosimetry–mercury immersion (HPMI), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) techniques on the shale samples show that MICP porosity is 6–10% lower than HPMI or NMR porosity. Compressibility, from uniaxial loading, and elastic wave velocities were measured simultaneously on saturated samples under drained conditions at room temperature. Uniaxial loading tests indicate that shale is significantly stiffer in situ than is normally assumed in geotechnical modelling. Permeability can be predicted from elastic moduli, and from combined MICP and NMR data. The permeability predicted from Brunauer–Emmett–Teller (BET)-specific surface-area measurements using Kozeny’s formulation for these shales, being rich in silt and kaolinite, falls in the same order of magnitude as permeability measured from constant rate of strain (CRS) experiments but is two–three orders of magnitude higher than the permeability predicted from the 1998 model of Yang & Aplin, which is based on clay fraction and average pore radius. When interpreting CRS data, Biot’s coefficient has a significant and systematic influence on the resulting permeability of deeply buried shale.

Description: This study examines the four-dimensional (4D) seismic signatures from multiple seismic surveys shot during gas exsolution and dissolution in a producing hydrocarbon reservoir, and focuses in particular on what reservoir information may be extracted from their analysis. To aid in this process, hydrocarbon gas properties and behaviour are studied, and their relationship to the fluid-flow physics is understood using numerical simulation. This knowledge is then applied to interpret the seismic response of a turbidite field in the UK Continental Shelf (UKCS). It is concluded that for a repeat seismic survey shot 6 months or more after a pressure change above or below bubble point (as in our field case), the gas-saturation distribution during either exsolution or dissolution exists in two fixed saturation conditions defined by the critical and the maximum possible gas saturation. Awareness of this condition facilitates an interpretation of the data from our field example, which has surveys repeated at intervals of 12–24 months, to obtain an estimate of the critical gas saturation of between 0.6 and 4.0%. These low values are consistent with a range of measurements from laboratory and numerical studies in the open literature. Our critical gas-saturation estimate is also in qualitative agreement with the solution gas–oil ratios estimated in a material balance exercise using our data. It is not found possible to quantify the maximum gas saturation using the 4D seismic data alone, despite the advantage of having multiple surveys, owing to the insensitivity of the seismic amplitudes to the magnitude of this gas saturation. Assessment of the residual gas saturation left behind after secondary gas-cap contraction during the dissolution phase suggests that small values of less than a few per cent may be appropriate. The results are masked to some extent by an underlying water flood. It is believed that the methodology and approach used in this study may be readily generalized to other moderate- to high-permeability oil reservoirs, and used as input in simulation model updating.

Description: The Norwegian Atlantic margin, although frequently described as passive, has seen several significant and highly variable deformation events prior to and after early Cenozoic break-up. This chronology is strongly exemplified in the northern Vøring Basin, where deformation resulted in significant vertical motions, including deep erosion and sediment reworking. Post-break-up compressional deformation is well documented in the NE Atlantic margins, and is represented in the north Vøring Basin by the Vema and Naglfar domes. A prominent Maastrichtian–Paleocene pre-break-up phase of compression inverted the northern prolongation of the latest Turonian Vigrid Syncline. This syncline was the fairway for the approximately 1 km-thick Santonian–Campanian Nise Formation sandstone, shed from NE Greenland and/or the western Barents Sea margin. The inversion focused on the Vigrid Syncline axis, forming an anticline here referred to as the Vema–Nyk Anticline. The anticline may have been a major trap but was breached by erosion prior to collapse due to Late Paleocene extension. The remnant eastern half of the anticline is the Nyk High. The associated flanking syncline, the Någrind Syncline, also remains preserved. The collapsed side of the anticline is the Hel Graben, which itself was inverted in the Middle Miocene time forming the Naglfar and Vema domes. More speculatively, the development of the Vigrid Syncline and its bounding structural highs, the Gjallar Ridge and Utgard High, may also represent folds, marking the onset of compressional buckling in the mid-Norwegian–NE Greenland rift system. The repeated compressional deformation, as well as the extensional collapse, was focused on the area subjected to Early Cretaceous hyperextension. Compressional buckling under relatively low stress levels is proposed to have been due to significant lithosphere weakening caused by the hyperextension, whereby both high attenuation of the crystalline crust and serpentinization of the upper mantle contribute to the weakening. The Late Cenozoic compression post-dated the hyperextension by approximately 110 Ma, which suggests that the weakening is long-lived and that lithosphere has not been strengthened significantly through time.

Description: Because a large number of oil and gas reservoirs are naturally fractured, they play an important role in hydrocarbon exploration and production. To fully extract and model the fracture system features of reservoirs, a new fracture modelling method, called the stochastic extended finite element (SEFE) method, is presented in this paper. This method couples fracture mechanics and the kriging method with a multi-field trend in an attempt to benefit from the advantages of each method: compliance with fracture mechanics equations and the reproduction of the fracture’s observed data, respectively. Based on the SEFE simulation method, we wrote a fracture modelling system software and built a fracture propagation model and a fracture distribution model of the Upper Cretaceous Formation in the Daqingzi region. A parallel study was performed to verify the fracture propagation pattern and boundary conditions in the proposed model based on a geomechanical analogue experiment. The results of these studies demonstrate that fracture modelling based on the SEFE method may improve the precise characterization of fractured reservoirs.

Description: Based on the characteristics of seven representative coalbed reservoirs in the Qinshui Basin in Shan’xi Province, China, the reservoirs were classified as gas pressure reservoirs, water pressure reservoirs or hybrid pressure reservoirs. Reservoir modelling technology was adopted to study the 1000 day recoverability and reservoir pressure transmission process of three typical coalbed methane (CBM) wells, each of which represents one of the three coalbed reservoir classifications identified. The results indicate that the three reservoirs are quite different in terms of their drainage performance. For gas pressure reservoirs, reservoir pressure changes in a very small region around the well bore. The gas production of this type of reservoir is very low; hence, integrated coal and gas mining may be appropriate to enhance its recovery. Reservoir pressure propagates further in water pressure reservoirs but declines gradually. The gas recoverability in water pressure reservoirs is also low, which indicates that effective water drainage is the key technology for improving it. The pressure in hybrid pressure reservoirs propagates moderately in the whole effective region. This type of reservoir has the strongest gas recoverability and is suitable for CBM exploitation using surface to reservoir boreholes.

Description: This paper presents a comparative analysis of the thicknesses–displacement relationships of fault cores in non-/low-porous carbonate and porous sandstone reservoirs. Fault thickness data were collected from extensional faults in mainly Cretaceous continental sandstones and Late Cretaceous–Paleogene marine carbonates exposed along the eastern flank of the Suez Rift, Egypt. The dataset consists of 730 thickness measurements, of which 313 are from 68 faults in carbonate rocks, and 417 are from 120 deformation band/microfaults and faults in sandstones. These data show that the increase in fault core thickness with displacement for the two lithologies is, overall, similar in log–log space, consistent with a power-law trend with an exponent of 0.5. However, for smaller faults, cores in carbonates are generally thicker than those in sandstones. The observation of nearly equal core thickness–displacement relationships for larger faults (〉10 m displacement) suggests that increased displacement reduces the geomechanical influence of lithology. In a statistical analysis of bins of fault displacement, small displacement faults seem to follow a skewed distribution towards smaller fault core thicknesses, moderate displacement faults have a normal distribution, while large displacement faults have a distribution skewed towards large core thicknesses. Each thickness distribution can be estimated with a mean and standard deviation. Fault core thickness variations are caused by interplaying factors such as fault geometric development, spatial and temporal positioning of shear and volumetric strains, and rheological changes. The variability in core thickness and intrinsic architecture of fault cores for any given location will cause significant variation in across-fault fluid flow, even for the same juxtaposition style.

Description: Investigation by spectral gamma-ray (SGR) and inductively coupled plasma-mass spectrometry (ICP-MS) geochemical analyses of the Upper Jurassic Arab-D reservoir analogue (central Saudi Arabia) revealed a strong correlation between the SGR response of the outcrop lithofacies and their elemental content. The two units of the reservoir (the Upper Jubaila Member of the Jubaila Formation and the Arab-D Member of the Arab Formation) showed distinctive SGR log profiles controlled mainly by their lithofacies associations. The geochemical analysis revealed four groups of chemical associations. Group 1 includes SiO 2 , Al 3 O 2 , Fe 2 O 3 , K 2 O, TiO 2 , Zr and Zn. This group has a strong relationship with the radioactive elements U, K and Th (Group 4). The reservoir facies exhibit high concentrations of chemicals from these two clusters. Group 2 includes CaO and Sr. A high concentration of chemicals from this group indicates a tendency towards pure carbonate facies and fewer siliciclastic impurities. A high concentration of MgO, the only chemical included in Group 3, marks dolomitic zones. Group 4 contains the radioactive elements. The boundary between the Upper Jubaila Member and the Arab-D Member is clearly defined from vertical SGR log profiles, vertical geochemical data logging and cross-plots of Group 1 chemicals with the radioactive elements in Group 4. The geochemical data for the Upper Jubaila Member show a very low concentration of U, K and Th. Consequently, the SGR response of the lithofacies was very low. All of the reservoir lithofacies showed high concentration of Group 1 and Group 4 components compared with the non-reservoir lithofacies. The Th/U ratio indicates a general shoaling upwards following the same trend of the outcrop lithofacies. A high Th/U ratio characterizes reservoir lithofacies, whereas a low ratio characterizes non-reservoir lithofacies. The lithofacies and the SGR log motifs were related in the measured sections. This study provides a method for predicting lithofacies from SGR log motifs within a high-resolution stratigraphic framework integrated with the geochemical data analysis. Here, we introduce an exploration guide for subsurface reservoir zonation and the identification of formation tops.

Description: The Middle Jurassic Brent Group of the northern North Sea presents a mature and highly productive reservoir play fairway where a combination of effective facies analysis and depositional sequence stratigraphy offers real potential to optimize exploitation. The north of the Brent province differs from classically studied southern areas in being dominated by marginal-marine delta-front facies. A core- and log-based study of 37 wells around the Don fields was performed to establish a sequence stratigraphic framework, map facies and thereby describe facies architecture. The results demonstrate that reservoir quality and productivity are regionally and locally controlled by facies. Of particular interest are intervals of fluvio-estuarine channel to sharp-based shoreface sandstone that formed during sea-level lowstands, since it is these packages that boost well productivity but, conversely, also increase the risk of early water breakthrough on production. Analogy with the Saloum Delta of Senegal highlights the importance of rapid and continuous barrier migration and destruction in controlling the deflection and switching of fluvio-estuarine channels, explaining also the preferential preservation of channel-floor deposits over continuously eroded barrier and delta-top facies. Interpretations suggest that deposition in the study area was dominated by punctuated progradation of the Brent Delta, as periods of delta plain incision alternated with episodes of base-level rise and delta aggradation/progradation. A model of regression for the Brent Delta is presented, where the Rannoch, Etive and Ness formations are an amalgam of highstand, falling stage and lowstand systems tract deposits, and the Tarbert Formation is a transgressive systems tract deposit, with the delta responding to regional relative sea-level changes driven by uplift and deflation of the mid North Sea dome. The prograding Brent Delta is characterized as a succession of attached shorefaces formed by alternating periods of normal and forced regression. Significantly, this explains the long distance (〉200 km) build out of the Brent Delta and the continued presence of coarse-sandstone packages, as well as the potential for high-quality reservoirs even in the distal reaches of the system. It also suggests that there is limited potential for lowstand fan plays beyond the northernmost tip of the delta.

Description: Monitoring of stored carbon dioxide (CO 2 ) in subsurface reservoirs is fundamental to operation and management of the storage site, and is a requirement of some national and international legislation. As a consequence, effectiveness of monitorability (the ability to observe the evolving location of subsurface CO 2 ) for any given level of investment in monitoring technology is a significant investment uncertainty that must be assessed along other components of the storage-site selection criteria (e.g. capacity, injectivity and storage economies). We develop a workflow to assess the time-lapse seismic detectability of changes in subsurface aquifer reservoirs by analysing expected changes in seismic amplitude variation with angle (AVA) in the field. Laboratory measurements are used to calculate the seismic response of the reservoir at different saturations and pressures. We include the scattering effect of material above and below the reservoir by using a finite-difference, full-waveform modelling approach AVA analysis then assimilates local site effects into the detectability assessment. We show that performing waveform modelling which includes local geological heterogeneities above and below the reservoir interval is essential to assess the storage site monitroability. In order to quantify expected time-lapse changes in the seismic response, we introduce a new set of robust time-lapse attributes based on time–frequency decomposition. The attributes effectively separate amplitude and phase changes (time-shifts) of time-lapse seismic records, and allow us to quantify their repeatability against the background noise. Furthermore, the frequency-dependent nature of the attributes provides a quantification of the frequency–domain effects of time-lapse changes. The approach is employed to assess the detectability of supercritical CO 2 in two analogue storage sites in the near-shore UK North Sea. Analysis of laboratory measurements and AVA responses indicate the contrasting monitorability of the two sites, which helps decision making about further site investigation and development. Application of the approach to hydrocarbon reservoir monitoring is straightforward.

Description: The distribution and orientation of faults, fracture intensity and seismic-reflection characteristics of the Mesaverde Group (Williams Fork and Iles formations) at Mamm Creek Field vary stratigraphically, and with lithology and depositional setting. For the Mesaverde Group, the occurrence of faults and natural fractures is important as they provide conduits for gas migration, and enhance the permeability and productivity of the tight-gas sandstones. The Upper Cretaceous Mesaverde Group represents fluvial, alluvial-plain, coastal-plain and shallow-marine depositional environments. Structural interpretations based on three-dimensional (3D) seismic-amplitude data, ant-track (algorithm that enhances seismic discontinuities) seismic attributes and curvature attributes are utilized jointly to understand the complex fault characteristics of the Williams Fork Formation. This study reveals that the lowermost lower Williams Fork Formation is characterized by NNW- and east–west-trending small-scale thrust and normal faults. Study suggests that the uppermost lower Williams Fork Formation, and the middle and upper Williams Fork formations, exhibit NNE- and east–west-trending arrays of fault splays that terminate upwards and do not appear to displace the upper Williams Fork Formation. In the uppermost Williams Fork Formation and Ohio Creek Member, NNE-trending discontinuities are displaced by east–west-trending events and the east–west-trending events dominate. Fracture analysis, based on borehole-image logs, together with ant-track and attenuation-related seismic attributes, illustrates the spatial variability of fracture intensity and lithological controls on fracture distribution. In general, higher fracture intensity occurs within the southern, southwestern and western portions of the field, and fracture intensity is greater within the fluvial sandstone deposits of the middle and upper Williams Fork formations. More than 90% of natural fractures occur in sandstones and siltstones. In situ stress analysis, based on induced-tensile fractures and borehole breakouts, indicates a NNW orientation of present-day maximum horizontal stress ( $${S}_{{\hbox{ H }}_{\hbox{ max }}}$$ ), an approximate 20° rotation (in a clockwise direction) in the orientation of $${S}_{{\hbox{ H }}_{\hbox{ max }}}$$ with depth and an abrupt stress shift below the Williams Fork Formation within the Rollins Sandstone Member.

Description: Cenozoic carbonate platforms in the central Mediterranean region show distinct vertical changes in carbonate skeletal assemblages and porosity characteristics that reflect shifts in environmental conditions affecting the western Tethys. The Photozoan Association produced by carbonate ecosystems adapted to low nutrient environments and the Heterozoan Association favoured by mesotrophic conditions alternate through time over the Malta Platform and nearby carbonate platforms, although not in phase with trans-Mediterranean Oligocene carbonates. This anomaly reflects the transitional nature of Cenozoic climate as well as continental convergence of the Tethyan margins. Restricted conditions amplified the effect of nutrient flux from North African fluvial systems, which was controlled by meridional shifts in the inter-tropical convergence zone (ITCZ) precipitation belt. We model the climate–carbonate interaction by comparing the global oxygen isotope proxy to ice volume and meridional position of the ITCZ to changes in trophic level of carbonate ecosystems. The results show that the development of Palaeogene Mediterranean photozoan assemblages coincides with periods when the ITCZ had shifted away from North Africa (as is the case presently), whereas the heterozoan assemblages thrived during increased nutrient flux when the precipitation belt was located over the Sahara. The climatic controls resulted in facies characteristics that exert a fundamental influence on porosity in carbonate reservoirs.

Description: The Campos Basin is a petroleum-productive, marginal sag basin along the Brazilian margin. It contains a stratigraphic sequence recording lithospheric extension and rift tectonics developing to a fully evolved post-break-up setting. We present a combined approach using subsidence analysis and basin history inversion models to make predictions on source-rock maturation. The classical uniform stretching model does not account for the observed tectonic subsidence, and so we consider the thermal and subsidence implications of incorporating different events of magmatic underplating. The post-rift is characterized by one major phase of post-rift thermal subsidence: changes in sediment supply and load, as well as halokinetic movements, cause deviations from normal thermal subsidence and relaxation. The dimensions of these events have been examined and quantified.Our best-fit forward model is tested against measured borehole temperature (BHT) data. Results show a systematic overestimation of present-day temperatures in the shallow-water wells. Including the effects of hydrothermal convection by raising the conductivity of the top part of the stratigraphic sequence results in an almost perfect fit between predicted and measured BHTs in the shallow-water wells.Based on these forward models, we predict that the lacustrine shales of the syn-rift Lagoa Feia Fm. could be mature to generate oil and/or gas over a larger area than previously expected. Furthermore, our results suggest that the early post-rift Macaé Fm. is locally mature to generate oil, and that the middle/late post-rift Carapebus/Ubatuba Fm. shales are likely to generate oil as well, if organic-rich facies are indeed present. In light of the most recent pre- and post-salt discoveries made near established oil fields in the Campos Basin, our results support the idea that many more such accumulations may be found.

Description: Reservoir compartmentalization can seriously compromise a project’s economics if left undetected during appraisal. Its early identification is made more likely if maximum use is made of available fluid appraisal data. This involves making a critical comparison of time-scales for various fluid properties to equilibrate compared with the actual time since those properties were initially disturbed. Spatially varying fluid properties indicate compartmentalization if they have existed for longer than the time needed for them to equilibrate. Here we use data from appraisal wells and reservoir mixing time-scales to investigate vertical and horizontal compartmentalization in the Horn Mountain Field (Gulf of Mexico) and to quantify the properties of the baffles/barriers identified. We compare our results with earlier work using time-lapse geochemistry and mud gas isotope logging. Present fluid compositional variations in the field are shown not to be diagnostic of horizontal compartmentalization as the mixing time-scales by molecular diffusion are longer than the time since the reservoir filled. In contrast, pressure shifts and density differences are diagnostic. They indicate that faults within the Horn Mountain Field are relatively impermeable and would act as barriers during oil production. They also confirm that a shale-filled channel acts as a barrier to vertical flow.

Description: The structural position of the Upper Jurassic–Lower Cretaceous carbonates located in the central part of the Catalan Coastal Ranges corresponds to the southwestern end of the Vallès-Penedès Fault. This fault was reactivated at different times during successive extensional and compressional events and several generations of fractures and cementations were formed.Based on petrological and geochemical analyses of this cementation an evolution of the fluids related to the different tectonic stages can be deduced. (1) During the Mesozoic extension, the parent fluids resulted either from a mixing of trapped Upper Jurassic–Lower Cretaceous seawater and meteoric water, or from buffered meteoric waters. (2) Related to the Paleogene compression, the fluids came from the percolation of meteoric waters indicating shallow-depth deformation. (3) During the transitional phase between Paleogene compression and Neogene extension, a karstic dissolution took place and the porosities were infilled by different generations of sediments and cements deposited from meteoric fluids. (4) During the Neogene extension several episodes of meteoric percolations and fracturing processes occurred. The Neogene extensional faults used the earlier karstic system to develop and, later, during the late post-rift stage, a new karstic system occurred, covering the walls of open fractures with speleothems.

Description: Depositional (facies) models of fluvial architecture permit straightforward categorization of deposits, but are necessarily simplistic. Here we describe a complementary database methodology which is designed to encapsulate the inherent complexity of fluvial systems and their preserved deposits. The database is implemented as a series of tables (characterizing qualitative and quantitative architectural and geomorphological properties and system attributes) populated with data derived from peer-reviewed studies of both modern rivers and ancient fluvial successions, and from other reliable sources. Architectural properties (geometries, internal organization, spatial distribution and reciprocal relationships of lithosomes) are assigned to three different orders of genetic bodies organized in a hierarchical framework, ultimately belonging to stratigraphic volumes that are homogeneous in terms of their controlling factors and internal parameters. Interrogation of the database generates a varied suite of quantitative information, whose principal applications include: (i) the quantitative comparison of fluvial architecture to evaluate the relative importance of intrinsic and extrinsic controls; (ii) development of quantitatively justified fluvial depositional models through the integration of data from multiple sources; (iii) development of better constraints on the workflows used to infer borehole correlations and to condition stochastic models of subsurface architecture; (iv) identification of appropriate modern and ancient analogues for hydrocarbon reservoirs.

Description: Interpretation of 3D seismic reflection data supported by well data provides insights into the geometry of early Paleogene depositional systems along the eastern margin of the North Viking Graben. These deposits, which consist mainly of sandstones interbedded with claystones and siltstones, are interpreted to document deposition at the edge of a large base-of-slope to proximal basin floor fan system which was sourced from the eastern basin margin. Individual sandstone bodies are up to 80 m thick and occur within four sandstone-prone packages (DU1–4), and well-to-seismic ties indicate that the thicker sandstones (〉10 m) are represented by channelized or sheet-like, high-amplitude anomalies. Both well and seismic data suggest that the sandstones are of limited lateral extent (

Description: Well testing is a critical part of any evaluation of a carbonate reservoir discovery. Well-test interpretation in carbonate reservoirs poses additional challenges to those normally faced in the interpretation process in clastic reservoirs. The range of different boundary and crossflow relationships that are generated during well testing by the complex porosity systems are often poorly quantified and understood. The volume over which the pressure response is effective is also a source of great uncertainty and could be critical at the exploration/appraisal stage in any project.In this paper, which describes a generic modelling approach, we consider carbonate reservoirs which contain three pore sytems (or porosity types): (1) microporosity (end-member) with low permeability and high porosity; (2) macroporosity (end-member) with high permeability and high porosity; and (3) fracture porosity with high permeability and low porosity. These occur in various nested geometrical distributions and varying contrasts. The observed well-test responses (i.e. fracture flow, fracture–matrix interactions) tend to ‘obscure’ one of these systems when compared with theoretical models. Micro- (meso-) and macroporosity can merge into a single matrix porosity system where the permeability contrasts are not great and the correlation lengths short (which can often be the case in carbonates). Macroporosity can also appear in well testing to ‘merge’ with the fracture response, i.e. the contributions of flow in the fractures and (high-permeability) porous matrix are indistinguishable. As a result of the homogenizing attributes of pressure dissipation away from the well, it is not generally possible to see the effects of a ‘triple-porosity’ response (i.e. where three different pore systems have a separate and identifiable signature on the well-test response) and a classical double-porosity response in the well test, despite three different pore systems being present, is possible. The apparent double-porosity response, which might obscure a triple-porosity system, therefore needs careful interpretation in order to attribute the appropriate properties during reservoir characterization in carbonates.In this work we use ‘geological’ well testing (i.e. well testing through numerical simulation of hypothetical geological models) to systematically analyse the effects of microporosity, macroporosity and fracture porosity on pressure dissipation and their apparent homogenization. While recent studies have proposed that a triple-porosity system should result in a ‘W-shaped’ response, we do not observe this behaviour in our simulations, although we specifically designed our geological models with a triple-porosity system. Instead we observe how macroporosity merges with the fractures or micro- and macroporosity merge, creating a ‘sub-dominant’ matrix or a ‘dominant’ fracture system, respectively and follow a traditional ‘V-shaped’ double-porosity response.

Description: We review the structural genesis and evolutionary history of basins along the Brazilian South Atlantic margin from the Sergipe-Alagoas (north) to the Pelotas basin (south), and demonstrate the links with petroleum system and play development. In our approach, we first break basins down into their tectonostratigraphic megasequences and define their characteristics, particularly focused on the development of characteristic source- and reservoir-rock intervals. We then compare these megasequences with similar types of megasequences in other basins, thereby providing a means to learn through a greater population of analogues. We demonstrate, using trajectory plots, that these basins experienced a similar tectonostratigraphic basin evolution, resulting in the deposition of many analogue potential source- and reservoir-rock intervals. These give rise to the development of similar types of potential petroleum systems and play (level)s. Although the area is currently being actively explored, large areas remain poorly understood, with unknown source-rock maturity distributions and many unknown/untested reservoirs/plays. This approach allows us to make analogue comparisons between the Brazilian marginal basins in order to evaluate and predict the presence of potential, yet undiscovered or under-explored, hydrocarbon accumulations. Supplementary material: Published source-rock and play properties used in this analysis are available at http://www.geolsoc.org.uk/SUP18536

Description: In this paper, we investigate subcritical propagation of an initially oil-filled, sub-horizontal microcrack driven by the excess fluid pressure associated with the conversion of oil to gas in a petroleum source rock under continuous burial. The crack propagation distance and propagation duration (the time required for the crack to propagate during conversion of all oil to gas), as well as the excess pressure inside the crack, are determined using a finite difference scheme that couples linear elastic fracture mechanics, oil–gas transformation kinetics and an equation of state for the gas. The effects of the source-rock temperature at the initial depth of the microcrack and fracture properties of the source rock are also considered. Our numerical results show that higher burial rates significantly reduce the crack propagation duration. However, the influence of the geothermal gradient on the propagation duration and distance is only marginal. Similar to the results for the oil-driven crack propagation during kerogen–oil conversion, the duration of gas-driven crack propagation is also governed by transformation kinetics because the subcritical crack propagation rate is much faster than the oil–gas conversion rate.

Description: A new methodology for robust, high-resolution correlation of reservoir sandstones in highly compactable depositional sequences is proposed. Quantitative sequential re-burial modelling has been successfully applied on real data from seven wells covering the heterogeneous fluviodeltaic Åre Formation in the Heidrun Field, offshore mid-Norway. The methodology is based on ten interpreted lithofacies classes derived from core descriptions and wireline logs signatures, in addition to interpreted sequence stratigraphic surfaces, i.e. flooding surfaces. Analysis of decompacted sedimentary columns, with emphasis on studies of shallow compaction effects tied to uniquely calculated compaction curves, has revealed several new correlatable horizons within the Åre Formation. These include laterally extensive coals and several laterally correlatable fluvial sandstones enabling a reinterpretation of parts of the Åre stratigraphy. The results from the present study demonstrate the benefits of correcting for the effects of differential compaction in well-to-well correlation of heterogeneous reservoirs comprising highly compactable sediments. The methodology outlined here has widespread applicability to other stratigraphic successions and could potentially help in the correlation of highly compacted sediments in the subsurface.

Description: The host rocks of shale gas accumulations act as source, seal and reservoir. They are characterized by complex pore systems with ultra-low to low interparticle permeability and low to moderate porosity. The word ‘shale’ is used in the sense of a geological formation rather than a lithology, so shale gas reservoirs can show marked variations in rock type from claystones, marlstones and mudstones to sandstone and carbonate lithological ‘sweet spots’. The pore space includes both intergranular and intrakerogen porosity. The density of natural fractures varies markedly, and pore throat connectivity is relatively ineffective. Moreover, in-situ gas pore volume has to take account of both free and adsorbed gas, an evaluation exercise that is complicated by pronounced variations in water salinity. All these characteristics present major challenges to the process of petrophysical evaluation. The petrophysical responses to these issues are severalfold. First, a broader calibrating database of core measurements is required at key wells, especially as regards mineralogy, porosity and permeability data, shale/mudstone sample analyses, total organic carbon, gas desorption isotherms, and the analysis of extracted formation waters. Second, at least in the key wells, an extended suite of logs should include an elemental analysis log, magnetic resonance imager, electrical micro-imager, and a dipole sonic log. These databases lead to a rock-typing scheme that takes better account of dynamic properties and fracturability. They also allow reservoir partitioning based on exclusivity of empirical interpretative algorithms, e.g. quartz content vs. producibility. These responses comprise key elements of a functional petrophysical system that encompasses fit-for-purpose interpretation methods, such as a pseudo-Archie approach, i.e. the application of the Archie equations with non-intrinsic exponents. This system is presented as a workflow for application in shale gas reservoirs, for which bulk density retains a major influence on computed gas in place. The benefits of this approach are especially strong in reserves reporting of these unconventional gas reservoirs.

Description: Upper Cretaceous sandstones are the main clastic reservoirs of the Santos Basin, eastern Brazil, showing high porosity at depths greater than 4000 m. Porosity preservation in these deep sandstones is ascribed to the inhibition of quartz cementation and pressure dissolution by authigenic pore-lining chlorite. Santos sandstones are mostly fine-grained, lithic arkoses, rich in volcanic rock fragments (VRF). Chlorite, the most abundant diagenetic constituent, occurs as coatings, rims, rosettes and replacing grains. Chlorite precipitation was favoured by the presence of eodiagenetic smectite coatings and by the abundance of VRF. Detrital heavy minerals, biotite and mud intraclasts were also sources and/or substrates for chlorite authigenesis. The chloritization of VRF, biotite and heavy minerals resulted in precipitation of abundant TiO 2 minerals. Fluid flow patterns, burial and thermal history also played a role in chlorite authigenesis and reservoir quality evolution. Discontinuous and thin coatings and rims were not effective in inhibiting quartz cementation, while those too thick severely reduced the permeability. The rosette aggregates exerted no inhibition on quartz cementation, while reducing intergranular porosity. Systematic studies are necessary for modelling the diagenetic patterns of Santos Basin sandstones, in order to contribute to the reduction of risks involved in the exploration of these reservoirs.

Description: A series of waterflood simulations were performed to investigate the effect of basinal position and facies permeability within a turbidite sheet system on oil recovery efficiency. Simulations used three-dimensional outcrop models of the Peïra Cava system, comprising gravel, sandstone, thin-bedded heterolithic and mudstone facies. Recovery efficiency declines with increasing permeability heterogeneity and is influenced by the interaction of vertical bed-permeability trends and flood-front gravity slumping. The occurrence of gravels with permeabilities lower than overlying sandstones produces optimum recoveries. High permeability gravels act as thief zones, enhanced by downward gravity slumping, reducing normalized recovery by up to 34 %. The effect of thief zones on recovery is related to their permeability contrast, abundance, thickness, lateral continuity, vertical position within permeable units and the permeability of underlying facies. Proximal to distal stratigraphic variations produce relatively small differences in normalized recovery of up to 13 % in models with the highest permeability heterogeneity. Differences in recovery are interpreted to reflect spatial trends in facies architecture, which determine the effectiveness of high permeability gravel thief zones. The poorest recovery is recorded from the medial model where recovery is lower than distal areas because of higher gravel abundance and thicknesses and lower compared to proximal areas because of the higher lateral continuity of gravels and underlying low-permeability mudstones.

Description: This paper documents a study that used high quality, conventionally processed, speculative 3D seismic data for two specific purposes: first, to identify and avoid any health, safety, security and environmental (HSSE) issues regarding the water bottom and, secondly, to avoid shallow (〈1 s below the mud line) geohazards when drilling the wells. The study integrated existing legacy well data, new 3D data from the BM-S-52 concession and a targeted programme of water-bottom grab samples from the BM-S-52 concession, Santos Basin, offshore Brazil. Two aspects of the analysis are described: the first addresses the problem and solution adopted for characterizing the water-bottom environment in this area; the second addresses the interpretation of the data for shallow geohazards. The results of this case study have been accepted by the regulatory authorities as representing sufficient evidence of risk evaluation that no further dedicated site-survey data acquisition is required. This has led to savings in time and in costs which would otherwise have been expended on deep-water site-survey campaigns. Furthermore, the use of 3D seismic data for well-location planning brings benefits in improved imaging of the near-mud-line geology, full coverage over the whole concession, operational flexibility for changing well location and timely availability of data. The analysis workflow may also be applicable in other, similar deep-water areas.

Description: Whether a reduction in overpressure across a hydrocarbon column and its seal will reduce the column height that the seal is capable of supporting has been much debated. Recent studies have focused on measuring water relative permeability at high capillary pressure, and have concluded that hydrocarbon columns may be sufficiently permeable to water for the seal capacity to be unaffected by hydrodynamic flow in most situations. A new method for estimating the capillary seal capacity is developed which properly takes into account viscous as well as gravity and capillary forces. A reassessment of existing analyses indicates that hydrodynamic flow has a greater influence on the seal capacity than previously thought. Sets of sensitivity models, including a range of reservoir and seal geometrical and petrophysical characteristics, indicate that – as a general rule – hydrodynamic flow should not be neglected when assessing capillary seal capacity. The sealing capacity of thick top seals above reservoirs with a basal aquifer are least likely to be affected by hydrodynamic flow. The sealing capacity of membrane fault seals, irrespective of whether they have a basal or edge aquifer, may be influenced by realistic overpressure differences. Simple end-member equations define the possible influence of hydrodynamic flow in a particular situation, and only if this is significant should a more comprehensive evaluation be considered.

Description: In this study of the Dorood oil field, offshore Iran, 3D seismic data were utilized to identify a complex fault pattern in the highly faulted and fractured Fahliyan Formation. To enhance data quality and improve attribute accuracy and detection power, a steering cube was first computed based on a sliding 3D Fourier analysis technique, using the concept of directivity. The steering cube, which contains dip and azimuth information for each trace, was utilized for calculation of dip-steered filters and attributes. We applied the dip-steered median filter to remove random noise and to enhance laterally continuous seismic events by filtering along the structural dip. Several fault identification attributes, such as dip, curvature, coherency and similarity, and a meta-attribute of a ridge enhancement filter, were extracted from dip-steered, noise-attenuated data. A supervised, fully connected multi-layer perceptron neural network was constructed to select and combine the most sensitive fault attributes. The neural network, trained at identified fault and non-fault locations, was applied to the whole seismic volume to generate a cube of fault probability. Interpretations of major faults and fractures were integrated with geological, reservoir engineering and production data to highlight the role of these heterogeneities on dynamic reservoir properties. Faults and fractures in the Fahliyan reservoir were identified in general to have the effect of decreasing reservoir permeability. While most of the faults recognized have locally a sealing capacity effect, when the fault throws are large enough to bring into contact the Manifa and Yamama reservoirs, they act as a conduit for fluid communication and, wherever a well crosses a major fault, early water breakthrough is observable.

Description: The Zagros Fold and Thrust Belt of NE Iraq hosts a prolific hydrocarbon system. Reservoirs are commonly found in fractured Cretaceous carbonates (Shiranish Formation) such as in the Taq Taq Field located in the Kirkuk Embayment of the Zagros foothills. Data providing information on fractures in the Taq Taq Field are core, image logs and flowmeters from wells, and surface observations. For comparison, an outcrop study has been undertaken around the Bina Bawi Anticline (10 km from Taq Taq Field), where the same stratigraphical unit is exposed in a continuous, lenticular-shaped belt. Fracture data have been collected using scanlines on bedding surfaces in the limbs and hinge of the anticlines. Both the Bina Bawi Anticline and Taq Taq Field show a systematic relationship between fracture sets and fracture lineaments, with a dominance of NE–SW-oriented structures. This orientation is perpendicular to the major folds and parallel to the maximum horizontal in situ stress. There are three fracture populations in the Bina Bawi Anticline, classified according to their relationship with the fold axis and bedding: (i) NW–SE-striking fractures normal to bedding: (ii) NE–SW-striking fractures normal to bedding; and (iii) conjugate oblique fracture sets subnormal to bedding. Both fracture intensity and fracture terminations are controlled by the location within the anticline; the hinge zone displays the highest intensity and the most fracture-abutting terminations. Cross-cutting relationships suggest that a prefolding stage of NE–SW tensional fractures predates folding-related tensional and shear fractures. Few uplift fractures can be indicated. We propose that the former fracture set (joints) formed in a foreland setting and was controlled by the far-field stresses, whereas later fracturing occurred due to outer arc extension during flexing of the Bina Bawi and Taq Taq anticlines. Our comparative analysis of outcrop and well data underline the importance of representative analogue data for reservoir modelling and production strategies.

Description: This study focuses on the reservoir characteristics of a Permian tight gas field in the Southern Permian Basin, Eastern Frisia, Germany. To improve the understanding of the reservoir, 3D seismic, wireline and core data were compared with a reservoir analogue in the Panamint Valley, United States. Depositional environments of the Permian Upper Rotliegend II include perennial saline lakes, coastal parallel sand belts comprising wet, damp and dry sand flats and aeolian dunes with interdune deposits. Polygonal patterns at different scales were observed on seismic horizon slices in the reservoir intervals and the overlying Zechstein. Outlines of superordinate polygons coincide with interpreted faults. Similar polygonal networks were identified on modern dry lakes in the western United States. The kilometre-long, up to 1.20 m deep open fissures in the Panamint Valley are interpreted to originate from the combined effects of synaeresis and tectonics. Subsequently, the fissures were filled with aeolian sediment. Vegetation growth confined to the lineaments indicates enhanced fluid circulation. Such fissures systems may serve as weakness zones and fault grain and impact reservoir quality in terms of hydraulic connectivity of reservoir compartments. For the Rotliegend reservoirs, original porosities and permeabilities of these zones were reduced to a minimum by enhanced cementation along the fluid migration pathways. Permeability barriers and reservoir compartmentalization, which can be clearly depicted on seismic attribute volumes, are a potential result of this development.

Description: New exploration opportunities and improved imaging of already known prospects in the Caspian Sea, Kazakhstan, are presented, based on the acquisition, processing and interpretation of long-offset 2D seismic data acquired by CGGVeritas from 2006–2009. We have identified further examples of three already successful plays in the Caspian Sea and onshore, within open blocks in the North Caspian and North Ustyurt basins and a fourth, relatively unknown play, in the North Ustyurt basin. The already known plays include Devono-Carboniferous carbonate reefs and clastics, Triassic–Tertiary post-salt clastics and carbonates in the North Caspian basin and Jurassic–Cretaceous post-thrust clastics and carbonates in the North Ustyurt basin. The fourth play that we have identified comprises thrust faults, anticlinal structures with Late Palaeozoic–Early Mesozoic clastic and carbonate reservoirs in the North Ustyurt basin which, to our knowledge, has not been tested elsewhere in the region.

Description: Creating earth models for deep-water appraisal and development studies is perhaps the most challenging task confronting the petroleum geologist today. Data are limited (few wells, limited core, untested seismic quality), time is limited and drilling, testing and facilities costs are very high. Uncertainty in geological characterization of the reservoir can have the greatest potential impact on project value. How can a thorough characterization of reservoir uncertainty be made based on limited data and in a timely fashion? A workflow for creation of suites of models for appraisal and development studies of deep-water reservoirs is described. The goal of the workflow is to rapidly construct suites of earth models based on limited data that capture the full range of uncertainty in reservoir characteristics and properties. After characterizing possible distributions for individual parameters, suites of earth models are built in a single step using an experimental design framework, aided by a powerful workflow manager which automates earth model construction. Earth models created using the experimental design framework are seamlessly linked to flow simulation software. Plackett–Burman, folded Plackett–Burman and Full Factorial experimental designs were used in different appraisal and development cases. Multiple experimental designs were produced by adding and modifying uncertainty parameters as additional data arrived, and ideas about the possible character of the reservoir evolved. In the appraisal case described here, 6 experimental designs were made, 388 earth models were created and studied, and 79 of those models were dynamically simulated. The process of quickly building and re-building suites of earth models using experimental designs to address changing perceptions and concerns about uncertainty in reservoir character is termed here ‘procycling’. Procycling is complementary to experimental design studies, in that multiple experimental designs are employed over time: procycling focuses on changes in predictions made by individual experimental design studies. The results of procycling are not necessarily to change the perception of uncertainty (for example the range of possible outcomes), but to anchor what the limits of uncertainty are and what the most important uncertainties are with the given data.

Description: Many of the original muddy marine sediments that have compacted to become gas shale could have been in a depositional environment suitable for the formation of natural gas hydrate (NGH), which concentrates gas by a factor of 164 (at STP). Dispersed biogenic NGH in fine-grained continental slope sediments today occurs in sections as thick as 250 m and contains enormous amounts of methane. Concentrated NGH can completely fill porosity in more permeable sediments. Formation of NGH in the early diagenetic history of shale gas sediments may have been the first step in the gas concentration process. NGH that formed in ancient gas shale sediments could have persisted and held the natural gas in place during lithification so long as hydrate remained stable. It is possible that the concentrated gas was held in place until the packing of the clay minerals effectively reduced permeability to a point that the gas released from naturally converting hydrate could not migrate easily. Because NGH creates open porosity upon conversion, a very large part of this gas could have been trapped in the shales before dissociation of the NGH to its component water and gas was completed. An implication for shale gas exploration is that high gas concentrations may not be confined to organic-rich shales but may also be found in any shales that once contained substantial gas hydrates. These include grey shales with lower organic content and more siliceous shales, which respond well to fracking.

Description: In western Kazakhstan there are several world class hydrocarbon fields, including the onshore Karachaganak Field. The geological setting is very challenging for the seismic imaging techniques where deep carbonate platform targets underlie a complex overburden including diapiric and detached salt structures. Furthermore, the extensive oil field infrastructure generates a noisy environment for seismic acquisition and reduced access for vibroseis trucks. KPO conducted an extensive integrated feasibility study for a new survey, complemented by a seismic acquisition test in 2008 which confirmed the need for dense source and receiver coverage, long offsets and wide azimuths to optimize imaging of the pre-salt targets. The survey was acquired in 2009 and survey execution exceeded local and international standards. It was the highest channel survey acquired in Kazakhstan and when fully depth image processed it will yield a high spatially sampled seismic volume, with improved resolution and structural definition. The application of the latest technology and techniques will enable better characterization of this complex carbonate reservoir, adding future value by better placement of wells and reducing overall costs for the ongoing development of the field.

Description: Gravity data were analysed in the Ghadames Basin and surrounding regions in southern Tunisia in order to determine the basement structure of the region and its relationship to petroleum exploration in relatively unexplored basins. The analysis included the construction of regional Bouguer gravity anomaly and horizontal gravity gradient maps. These maps indicate that the Ghadames Basin is not a simple sag basin but consists of a series of sub-basins and uplifts. The northern boundary of the basin which we call the Telemzan–Ghadames transition zone is marked by a NE-trending high amplitude gravity gradient anomaly which decreases in amplitude toward the east and breaks into a series of north–south- and east–west-trending anomalies implying a more structurally complex region. When the known petroleum fields are overlain on to the gravity gradient anomaly maps, the fields mostly occur along or next to linear alignments of horizontal gravity gradient maxima. We interpret the correlation of the petroleum fields and horizontal gravity gradient maxima to indicate that the basement was involved in forming the petroleum traps. This study illustrates that a regional gravity analysis can be useful in determining where additional exploration can be applied in relatively unexplored basins.

Description: Fault-seal analysis in hydrocarbon exploration often involves prediction of the sealing capacity of fault rock at reservoir–reservoir juxtapositions on subsurface faults. A proxy property, such as Shale Gouge Ratio (SGR), is mapped on to the fault surface, and then SGR is either (a) calibrated by observations of known sealing faults, to define its sealing capacity (empirical approach), or (b) assumed to be equal to the composition of the fault rock, for which a database of capillary threshold pressures is available from cores (deterministic approach). The deterministic approach implicitly assumes that capillary pressures measured on centimetre-scale samples are representative of seismically mappable faults, for example that faults of intermediate SGR are equivalent to phyllosilicate framework fault rocks.This contribution builds on earlier outcrop and modelling work to suggest an alternative explanation for the observed progressive increase in sealing capacity on faults of increasing SGR. Stochastic models of disrupted shale smears display the same pattern of increasing sealing capacity as SGR increases. These models have a bimodal ‘fault rock’ composed only of sealing shale smears and non-sealing matrix and, yet, at intermediate SGR the predicted column heights are similar to those normally ascribed to intermediate composition fault rocks. The resulting ‘fault-seal envelope’ in the models is a statistical estimate of the maximum trappable column height, dependent on the random occurrence of a gap in the smeared fault surface.

Description: This paper presents an integrated seismic, petrophysical and core facies study of the Mey Sandstone Member of the Central North Sea Lista Formation. Seismic mapping and attribute analysis reveal that the Mey Sandstone Member is composed of distinct axial and lateral routing systems. In turn, the axial system can be divided into coeval western and eastern fairways defined by the underlying graben topography in a similar manner to the overlying Sele Formation (Forties) sandstones. These trends are confirmed by petrophysical analysis, which also reveals that the lateral systems are not as important as previously proposed and that the cycles of the Mey Sandstone Member prograded over time before a late stage of backstepping. These variations can be related directly to published sea-level curves. Core analysis reveals that mean grain size is the main control on sandstone quality and that similar proximal (channelized) to distal (sheet-like) changes in sedimentological facies occur to those described in the Sele Formation. It is argued that these deposits cannot be described as simple basin floor fans due to the impact of topography on turbidite flow routing and the existence of multiple entry points of sediment into the basin.

Description: Geoelectrical methods measure resistivity and induced polarization (IP) effects in the subsurface. The differentially normalized electromagnetic method (DNME) detects geochemical alteration zones due to anomalous electrical responses which are often located above a hydrocarbon accumulation. Leakage above a non-perfect top seal is postulated to change the pH in the overlying sediments where a shallower mobility barrier is encountered. Epigenetic pyrite mineral growth is stimulated when iron and sulfur ions are available. Leakage and mineral growth are modelled by mathematical formulae assuming diffusion migration through the overburden. Effects of time and tectonic faulting are examined. Pyrite is highly polarizable and easily detected by an electrical IP survey in the field, whereby a current is introduced into the ground and subsequently turned off. Decay of the potential difference over the receiver electrodes is monitored in time. Special parameters facilitate detection of IP anomalies related to the presence of hydrocarbons. An inverted electrical depth model is computed using the Cole–Cole formula. The impact of geochemical modelling and predicted epigenetic mineral growth is demonstrated for the Severo-Gulyaevskaya dataset (Siberia). The overall DNME track record shows a reduced risk attached to hydrocarbon prospects, with a more reliable ranking at reasonable costs.

Description: In order to predict the style and impact of post-depositional modification of carbonate successions, well-studied and accessible outcrop analogues are invaluable. The Lower Carboniferous (Dinantian) carbonate platforms of the Pennine Basin of northern England have a long history of investigation. As such, they offer the potential to evaluate the mechanisms and timing of fluid flux during extensional tectonism, post-rift basinal subsidence and inversion. This study concentrates upon the diagenetic evolution of the late Dinantian of the southern margin of the Askrigg Platform of North Yorkshire and a comparison with published data from the age-equivalent Derbyshire Platform. A pattern of consistent, diagenetic modification during early diagenesis is evident, but key differences occur in the burial realm. On both the southern margin of the Askrigg Platform and the Derbyshire Platform, patterns of dolomitization, hydrocarbon emplacement and mineralization can be determined on the platform that reflect the diagenetic evolution of the adjacent basins. However, within the study area of the Askrigg Platform, there is only local evidence for a fault/fracture control on the migration of Mg-enriched, hydrocarbon-bearing fluids. In contrast, on the Derbyshire Platform, burial diagenesis is intimately associated with NW–SE- and NE–SW-trending faults and fractures. Data suggest that pervasive cementation in the marine and meteoric realm occluded matrix porosity in both areas, such that fluid migration was almost entirely fracture controlled. With the localization of structural deformation along the Craven Fault Zone, and a low abundance and density of open fault/fracture networks, circulation of fluids on to the southern margin of the Askrigg Platform was inhibited, however. Furthermore, the presence of local aquifers in the Craven Basin may have led to fluid expulsion from the basin during early burial.

Description: Grids used for flow simulation are often at a much coarser scale than that of grids for geological modelling due to computational demand. Unstructured grids offer increased flexibility for the flow grid design; however, solving the flow equations and upscaling from high resolution geological grids to the coarse flow grid is more complex than using coarse regular grids. The multipoint flux approximation (MPFA) is one technique applied to discretize the flow equations on unstructured grids. This paper develops an upscaling technique that uses the MPFA method to solve the flow equations on the fine- and coarse-scale grids. Unlike most cases where the fine-scale grid is regular or structured, this work utilizes a high resolution triangular grid that conforms to the coarse-scale grid. The triangular grid is generated using the coarse-scale interaction regions as constraints. Upscaling leads to transmissibility matrices of the coarse-scale interaction regions. Two different types of local boundary conditions for the MPFA upscaling approach are developed, including linear varying pressures and pressures computed by solving the flow equations around the element boundary. The method is tested using flow simulation on several cases. Results are comparable with flow using a high resolution regular grid.

Description: A new well testing response from lateral cross flow within layers is described. The response occurs when there is extremely low effective vertical permeability in the system at the larger scale. Low vertical permeability actually accentuates the layering and reduces vertical cross flow whilst enhancing lateral cross flow from within-layer heterogeneities. The response is investigated using numerical simulation of flow in end-member models of complex and geologically realistic architecture in high net-to-gross fluvial systems. This ‘ramp’ response is shown to form one member of a family of well test pressure transient responses. The other members of the family include previously-described negative geoskin and geochoke. The use of well test data to characterize these particular types of layered fluvial reservoirs is an important step in the static-dynamic integration of geological and reservoir engineering models.

Description: Supercritical CO2 breakthrough and flow mechanisms in shale have been investigated in laboratory experiments using a high pressure flow cell and cylindrical samples of shale from the Draupne formation in the North Sea. The main objective is to study the basic mechanisms involved in the breakthrough process and define the controlling parameters for supercritical CO2 flow in a low permeable shale.Experimental testing provides new insight into the CO2 breakthrough process through simultaneous measurements of deformation and ultrasonic velocities in the sample. A marked sample dilation associated with the CO2 breakthrough is identified accompanied with a pronounced drop in ultrasonic velocities. X-ray images of the sample using a high resolution 3D computer tomography (CT) scanner provide information on macroscopic fracture distribution inside the sample before and after testing.The CO2 breakthrough pressure for the Draupne material seems to depend on confining pressure and effective pressure rather than pore pressure difference across the sample. After breakthrough the effective CO2 permeability was found to follow a simple model for permeability in fractured rock. The drop in ultrasonic velocity was associated with mechanical changes and possible micro fracturing inside the sample. Based on our observations we conclude that pressure-induced opening of micro-fractures during the breakthrough process is an important mechanism for flow in addition to capillary displacement. Our findings may have important consequences for later testing and estimation of CO2 breakthrough pressure and flow in shale.

Description: The current model describing the sealing mechanism of high-pressure hydrocarbon traps and the ensuing methodology for predicting top seal integrity and capacity in high-pressure plays assumes that the caprock, defined as the low matrix permeability formation immediately overlying the reservoir, is the seal.This study challenges this assumption and proposes the existence within the caprock of a fluid waste zone consisting of a system of fractures cutting from the reservoir upwards into the caprock and, therefore, charged with reservoir fluids. Because of the waste zone fractures the reservoir fluids are not sealed at the base of the caprock. Instead the seal coincides with the fracture waste zone tip point, which occurs at an important stress and stratigraphic boundary termed the ultimate seal. Six case studies demonstrate that in the UK Central Graben the top seal for Mesozoic high pressure hydrocarbon accumulations lies between the Base Cretaceous Unconformity and the base of the Chalk Group and that the Jurassic Kimmeridge Clay Formation is not necessarily the seal for these traps. The data used for the construction of structural and stress models for the case studies include pore pressure measurements, formation integrity measurements, well logs and reflection seismic profiles.An important conclusion of this study is that the shorter the waste zone the higher the chance of finding a hydrocarbon column in the reservoir.

Description: Hydrocarbons in the Clair Field, west of the Shetland Islands, are hosted by Devonian–Carboniferous clastic red beds deposited in a non-marine fluviolacustrine setting. The succession is almost entirely biostratigraphically barren and, hence, alternative approaches to reservoir correlation are required. Heavy mineral analysis (HMA), which subdivides clastic successions on the basis of changes in provenance and sediment transport history, has proven successful in establishing a high-resolution correlation framework for the Clair Field. Since the technique offers a reliable and rapid method for monitoring the stratigraphy of the Clair reservoir succession, HMA has been undertaken on a real-time basis at well site for virtually all development wells during Phase 1 of the Clair Field development, and for all Phase 2 appraisal wells. Heavy mineral data can be acquired in less than 2 hours from receipt of sample. Consequently, owing to the relatively slow penetration rates frequently associated with Clair drilling, stratigraphic information is usually acquired ahead of logging while drilling. Heavy mineral data are used in the decision-making process in a variety of situations, including picking of casing and coring points, whether to maintain or alter well trajectory, and when to terminate drilling. In the Clair Field, formation tops can be subtle and, since HMA can establish trends and predict formation changes before they are encountered, they are critical in aiding geosteering decisions. HMA has also been used to monitor stratigraphy and to pick formation tops when logging tools have failed, allowing drilling to continue and avoiding tripping to change the bottom-hole assembly. The application of HMA to the Clair Field development is illustrated by reference to a number of wells drilled on the field since 2005.

Description: The Karachaganak Field is an oil and gas condensate supergiant field located in the western Kazakhstan Pricaspian Basin. As part of the challenge to improve reservoir knowledge, KPO has been continuously monitoring the reservoir using a microseismic array deployed downhole since February 2009. Continuous deep recording of microseismic activity is an innovative technique for reservoir monitoring; progressive refinements were made to fine-tune the acquisition and processing techniques. By December 2010, 8074 events had been detected and, from this group, 2556 events have been located. Events within the reservoir were recorded up to 8 km from the array to a depth of 5 km with moment magnitudes (Mw) ranging from –2.4 to +1. Microseismic events are continuously located and their spatial and temporal distribution analysed. This basic analysis is the input to an integrated study that considers the static model for the reservoir, in addition to dynamic and operational aspects such as production and injection rates, pressure baffles, drilling behaviour and casing perforations. The results to date indicate valuable reservoir information concerning the location of lateral and vertical reservoir pressure baffles and delineation of zones of instability at the reservoir–seal interface, important for well integrity issues. This new information is helping to improve dynamic and geomechanical reservoir models and also wellbore stability predictions. This article presents the details of the Karachaganak microseismic array and how microseismic events were located. Discussion follows on the interpretation and the possible impact on reservoir monitoring and drilling. The Karachaganak array is one of the deepest installations of a passive microseismic monitoring system and also represents one of the longer periods of continuous monitoring, with two years of data available.

Description: Overpressure distributions within the Paleocene Forties, Cromarty and Eocene Tay sandstones in the Central North Sea have been compiled to gain better insight into hydrocarbon migration pathways. Drainage within the Forties Sandstone Member is westwards at the toe of the fan, where overpressures are 〉1000 psi (7 MPa), swinging round to northwestwards up-dip, towards the Moray Firth. Overpressure distributions in the Cromarty and Tay sandstone members indicate that these formations are draining westwards, where fluids probably escape through shelfal sandstones of the Mousa and Dornoch formations. Locations of vertical drainage pathways can be interpreted from local anomalies in overpressure distribution, and good hydraulic connectivity may be indicated where overpressures in different sandstone members are the same. Fluids within the Forties Sandstone Member appear to be draining vertically upwards into the Cromarty Sandstone Member within UK blocks 22/29 and 22/30, 29/05 and 29/10, and 29/01, with drainage pathways in UK block 29/01 permitting migration of good quality oils into the recently discovered accumulations of Catcher, Vardero, Burgman and Carnaby. The lateral overpressure gradients within the Cromarty and Tay sandstone members, the pressure evidence for vertical drainage, and the presence of oil accumulations showing limited biodegradation imply connection to the deeper graben through still-active pathways for the migration of oil and gas.