ABSTRACT Navarin Basin, located on the northwestern margin of the Bering Sea Shelf, is a Cenozoic backarc extensional basin overlying Mesozoic rocks. Formation of the basin began with right-lateral oblique extension along northwest trending strike/ slip fault systems. Local highs provided sediment supply to syntectonic lows. Seismic facies analysis of this syntectonic fill suggested alluvial to shallow marine fill, possibly in an estuarine setting. Subsequent inversion of this syntectonic package resulted in its being in a structurally high position. Analysis of the exploration potential of this syntectonic package suggested that it could be sand prone, and might provide an effective reservoir if seal rock was deposited prior to the major pulse of hydrocarbon generation from known Eocene oil-prone organic rich rock. Drilling of the syntectonic package, following O.C.S. Sale 83 (April 1984) found tight, late Cretaceous non-marine to shallow marine facies with no hydrocarbons. Post-drill analysis confirmed that the tectonic inversion history did not provide effective topseal of the potential reservoir sandstones prior to the main pulse of hydrocarbon generation.

High resolution biostratigraphic analyses provide calibration of both depositional systems and specific depositional environments. Such studies facilitate prediction of reservoir geometry and the lateral continuity of both reservoir sandstones and sealing shales. Data from the offshore Nigeria Oso Field is presented as a case study of one late Miocene deltaic depositional system. Within the Oso Field, marine shales are recognized as effective topseals across the entire field in contrast to marginal marine to nonmarine shales which have more restricted distribution and act as intrafield baffles. Multiple sequence stratigraphic models have been considered; one model based on regional seismic and well-logs data, one on log-motif and core sedimentology, and one on biostratigraphic data integrated with core sedimentology. The lower Oso Field producing interval is interpreted as a lowstand prograding wedge and the upper interval as a prograding distal transgressive or alternatively distal highstand system tract, based on integrating all these data.

An ongoing study utilizes outcrop-scale seismic data and lithofacies data from the Texas continental shelf to develop type sections or preliminary two dimensional depositional models that relate the distribution of sedimentary deposits to sequence stratigraphy. The approach examines the variability in the spatial and temporal distribution of systems tract deposits produced during the most recent glacial-eustatic cycle (the past 120,000 years). The current data base consists of nearly 20,000 kilometers of high-resolution seismic data (with vertical resolution of tens of centimeters to two meters) and lithologic data from hundreds of sediment cores and platform boring descriptions. Only with high resolution data can realistic depositional models be developed. Detailed work has focused on several study areas (east Texas: Trinity/Sabine, east Texas: Brazos/Colorado, central Texas, and south Texas) that represent a range of depositional settings in terms of sediment supply, shelf gradient, climatic setting, and storm (wave) versus fluvial influence on sedimentation. On the east Texas shelf the transgressive and lowstand systems tracts contain most of the sand-prone deposits. On the central Texas shelf the sand-prone deposits are concentrated in the highstand systems tract. On the south Texas shelf the lowstand and transgressive systems tracts contain sand-prone deposits. Preliminary results suggest that observed trends in the stratigraphic occurrence of sand-prone units repeat themselves during successive glacial-eustatic cycles. This repetition is important because it indicates that these depositional patterns are predictable and therefore can be modeled.

Data collected from outcrops of the Cretaceous Ferron Sandstone, central Utah, support the theory that stratigraphic heterogeneities are predictable and can be related to position within a stratigraphic cycle ( Gardner 1993 ; Barton 1994 ; Barton 1995 ). Specifically, strongly progradational parts of the fluvial-deltaic Ferron system are characterized by mud-rich, internally heterogeneous delta front deposits interpreted to have been rapidly deposited along a river-dominated coastline under conditions of low accommodation and high sediment supply. In contrast, aggradational to retrogradational parts of the system are characterized by sand-rich, internally homogeneous delta front deposits interpreted to have been deposited along a wave-dominated coastline under conditions of relatively high accommodation and low sediment supply. Data collected from Ferron outcrops was integrated with borehole and production data from the nearby Ferron gas field. The Ferron gas field is located just 5 km to the northwest of outcrops studied and produces largely from the Ferron Sandstone. The description of reservoir architecture within the Ferron gas field was aided by calibrating key surfaces and facies successions identified in borehole data with nearby outcrop equivalents. The gas field is positioned near the seaward extent of the Ferron system and consists of four upward shoaling, shallow marine successions. The basal succession steps strongly basinward, the overlying succession is vertically stacked, and the upper two successions are arranged in a backstepping pattern. A comparison of sandstone body geometry and cumulative production on a well-by-well basis for each succession illustrates areas of unrecovered gas and styles of reservoir compartmentation. Aggradational and backstepping shallow marine successions contain relatively large reservoir volumes that are effectively contacted and drained by conventional well patterns. Favorable sites for stratigraphic entrapment, however, exist near the landward pinchouts of these successions where they interfinger with lagoonal mudstones. In contrast, offlapping and downstepping shallow-marine successions are highly compartmentalized by marginal marine and marine mudstones. Past completions have contacted only small reservoir volumes. Optimal reservoir drainage within these units may require additional infill wells outside the standard field limits or at intervals less then conventional well spacing. All factors being equal, these types of shallow-marine deposits possess the greatest amount of reserve growth potential.

Combining field description, in situ minipermeameter measurements, geostatistical analysis, and ground penetrating radar (GPR) analysis permits development of an interwell-scale 3D characterization of sandstone deposits. In the Tonganoxie Sandstone incised-valley-fill (IVF) system in the Pennsylvanian of eastern Kansas, outcrop analogs were examined in order to determine the types of macroforms that exist in the system, describe architectural elements and their orientation, and provide estimates of the variations in permeability values in these elements. In the Tonganoxie Sandstone, fluvial and fluvially-influenced, estuarine (FIE) sandstones are present that are potential reservoir analogs for numerous IVF oil and gas reservoirs in the Pennsylvanian of the midcontinent. Two outcrop sites were studied, one of fluvial sandstone and the other of FIE sandstone. The sites were analyzed in terms of their flow unit characteristics by combining geological descriptions utilizing architectural element analysis with geostatistical descriptions of their permeability structure. Conventional statistical analyses and semivariograms were used to determine the permeability structures and the horizontal continuity of permeability values within flow units identified at the sites. The results of the analysis of permeability measurements taken along the two exposures are discussed and the sites are compared in order to highlight differences in their permeability structures. In addition, the fluvial study site was investigated using a combination of information from outcrop description and three-dimensional GPR analysis. A grid of high-resolution GPR profiles showed the three-dimensional (3D) geometry of component elements in one of the flow units identified at the fluvial site and was used to establish the size, spatial continuity, and general transport directions for several of these elements. This study provides geological descriptions, geometric information, and geostatistical descriptions of macroform types that are thought to commonly occur in subsurface IVF reservoirs.

ABSTRACT Incised valley-fill deposits of the Pennsylvanian Morrow Formation of eastern Colorado and western Kansas have proven to be prolific oil reservoirs. Since the discovery of oil from a Morrow sandstone reservoir at Sorrento Field in 1979, 66.5 million barrels of oil have been produced along two major incised valley trends. Ultimate cumulative production from these reservoirs is estimated to be 107 million barrels of oil. Understanding the trapping mechanisms and internal complexities of these reservoirs provides insight to significant opportunities for further exploration and development along these trends and important analog data for similar types of incised valley-fill reservoir plays worldwide. The Morrow Formation is Early Pennsylvanian in age. Several fourth-order sequences comprise the upper Morrow siliciclastic interval. These high order sequences developed as a result of sea level fluctuations associated with Early Pennsylvanian glacio-eustasy. During the Morrowan, the study area was part of the broad, gently dipping northwest shelf of the Anadarko basin. Rising and falling sea level alternately submerged and exposed this shelf, causing maximum shoreline displacements of 90 to 125 miles (145 to 200 km) across the low-gradient muddy shelf. Extensive drainage systems trending northwest-to-southeast developed during each of these sea level cycles as rivers incised into the muddy shelf strata during lowstand periods. The reservoirs within these valleys are primarily amalgamated fluvial channel sandstones. Marine influenced sandstones are locally important reservoirs that formed from deposition in estuarine systems developed as valleys became flooded from rising sea level. Interfluve areas were sites of soil formation during valley incisement and valley-fill accumulation. This study focuses on the southern area of the Stateline Morrow trend along the Colorado-Kansas border. Four sequences produce oil and/or gas from incised valley-fill reservoirs in three fields along this trend - Second Wind, Jace, and Moore-Johnson. Establishing the sequence stratigraphic framework for these incised valley-fill sandstones allows for the mapping of trap geometries for petroleum accumulation. The sequence stratigraphic framework is developed by correlating wireline logs and integrating core data. Once the sequence framework is established, individual valley-fill reservoirs can be defined, attributed to specific sequences, and their geometries mapped. Three-dimensional seismic data is of great benefit in determining the dimensions and the geometries of the oldest two valley-fill systems. Complications to development geology arise when several valley systems of different ages are superposed and cross-cut. Moore-Johnson, Jace, and Second Wind fields illustrate problems with field exploitation due both to superposition of valleys and to internal reservoir complexity resulting from high-frequency relative sea level fluctuations.

ABSTRACT Current completion targets are individual reservoir flow units, often comprising a single depositional unit such as an upper shoreface sandbody or a tidal channel which has remained undrained from previous development campaigns. Identification, location, and accurate description of these targets requires detailed models of reservoir stratigraphy and architecture, based upon good-quality core and well data sets, together with accurate structural and stratigraphic mapping using high-resolution 3D seismic so that the connected oil in place and transmissivity can be estimated accurately for individual flow units. The method of ichnofabric analysis, combined with routine sedimentology, provides unequivocal interpretation of shallow marine and estuarine depositional environments allowing the interpreter to recognize and determine the relative importance of the various stratal surfaces seen in cores. The tectonic tilt of the stratal surfaces as interpreted from dip-logs such as the FMI, FMS, or even the SHDT, assists in determining the relative importance of these stratal surfaces. The key stratal surfaces concept provides the main correlation surfaces (erosional sequence boundaries and flooding surfaces) for delineating individual parasequences, parasequence sets and sequences and for constructing a new high-resolution sequence stratigraphy (HRSS). Once calibrated, these surfaces can be recognized in, and correlated between, uncored wells by the shapes of the natural gamma-ray and density logs. By careful integration of all well data with the high-resolution seismic within the HRSS framework, an accurate description of the geometries and architecture of all the reservoir sediment bodies is obtained. The final product is a robust and accurate description of the reservoir architecture and facies contents down to the bedset (decimeter) scale. This is a sound basis from which to construct computer-based 3D reservoir models and assign petrophysical properties for reservoir simulation studies. Shell’s proprietary reservoir modelling software (GEOCAP-MoReS) has been used to provide detailed static 3D reservoir models for reservoir simulation. Results of this work have allowed engineers to optimize field development plans in the mature development phase of field life.

ABSTRACT This study of Kotabatak field (835 MMSTB OOIP) in the Central Sumatra Basin, Indonesia provides a case example of the application of sequence stratigraphy, based on the integration of core, wire-line log, and biostratigraphic data, as a predictive reservoir characterization tool for a proposed EOR (pattern waterflood) project. A peripheral waterflood (started 1981) has not performed as anticipated because previous studies of Kotabatak field failed to recognize the presence and significance of highly permeable incised valley-filling (IVF) sandstones. IVF sandstones typically have excellent reservoir characteristics, and thus, the recognition of IVF features has important implications for reservoir modeling studies. Lithofacies maps of Bekasap strata in Kotabatak field provide geologic explanations for field-wide variations in: oil production rates, remaining oil-in-place, water injection rates, and produced water. The Bekasap Formation is subdivided into three lithostratigraphic units (A-, B-, and C-Sands); the Bekasap A-Sand has accounted for most (80%) of the cumulative production (180 MMSTB) from Kotabatak Field. Four lithostratigraphic units (A-1, A-2, A-3, and A-4 sandstones) are recognized locally within the Bekasap A-Sand stratal package. Chronostratigraphic correlations reveal that IVF reservoirs are restricted to the Bekasap A-3 Sand. The A-3 Sand is underlain by the 21 ma sequence boundary. Bekasap A-3 incised valleys record the entrenchment of an estuarine channel complex into underlying offshore marine strata. This entrenchment of the estuarine depositional system has resulted in an abnormal vertical association of lithofacies wherein marginal marine (estuarine), and locally nonmarine (fluvial), strata directly overlie offshore marine lithofacies. Apparently, the intervening shallow marine lithofacies have been eroded during the basinward shift of estuarine processes. Bekasap A-3 (IVF) reservoirs consist mainly of tidally-influenced estuarine channel lithofacies; these sandstones have an average porosity of > 20% and an average horizontal permeability of 800 md (maximum 7.5 darcies). Characteristically, channelized Bekasap A-3 Sand reservoirs exhibit a strongly directional permeability parallel to the channel axis. In contrast, underlying Bekasap A-4 sandstones are fine-grained, glauconitic, profusely bioturbated lower shoreface lithofacies, representing a highstand systems tract (HST). The A-4 Sand has an average porosity of 15% and an average permeability of < 100 md. Because these IVF and HST sandstones have markedly different reservoir properties, Bekasap reservoirs within Kotabatak field are compartmentalized. Bekasap A-3 IVF sandstones occur preferentially in the northwestern area of Kotabatak field which, historically, has exhibited excellent reservoir performance. Low-permeability Bekasap A-4 Sand reservoirs are predominant in the southeastern area of Kotabatak field and are the target of a pilot pattern waterflood. Bekasap A-3 estuarine sandstones are overlain conformably by Bekasap A-2 / A-1 tidal lithofacies and comprise the lower part of a transgressive systems tract (TST). Uppermost Bekasap strata are overlain by the Telisa Formation which represents middle- to outer-shelf paleoenvironments of deposition. Telisa strata record the maximum mid-Miocene transgression and form the regional top seal for the giant oil accumulations within the Central Sumatra Basin. The study of Kotabatak field reservoirs demonstrates clearly that sequence stratigraphy is a powerful geologic tool for improving the understanding of stratal architecture and consequently field development strategies. The integration of sedimentologic, chronostratigraphic, and production-engineering data sets, at the field scale, is essential to the understanding of sandstone reservoir continuity and connectivity prior to reservoir simulation studies and the designing of EOR projects.

ABSTRACT Well, seismic, and outcrop data were used to constrain the timing and development of unconformities associated with uplift events, and to aid in the definition of lithostratigraphic units of the Eocene of the southern Maracaibo and west-central Barinas/Apure basins. Palynology provided the main control on age dating of the sections, and graphic correlation was used to illustrate the amount of missing time in the lithostratigraphic record. An integration of biostratigraphic and lithostratigraphic data from wells and outcrops shows that deltaic to shallow marine conditions prevailed over most of the Maracaibo and west-central Barinas/Apure basins during the middle Eocene. Fluvial sedimentation dominated in areas of high standing basement features, and was accentuated by the development of incised valleys and their subsequent marine fill sequences along the southern and southeastern margins of the Maracaibo Basin. The main controls governing depositional facies, and the presence or absence of unconformities were differential structural motion and, to a lesser extent, relative sea level fluctuations. A basal Eocene to late Paleocene unconformity, as well as several intra-middle Eocene unconformities appear to have been primarily caused by a drop in base level (sea level + structural subsidence), forming incised valleys over most of the study area. Biostratigraphic (palynological) data, as well as field observations and subsurface mapping indicate that other unconformities within the upper middle Eocene, and between middle and upper Eocene strata are ravinement surfaces caused by transgressive marine re-working of pre-existing units. Sequence boundaries caused by incised valleys often overlie transgressive deposits, and can merge with ravinement surfaces and other sequence boundaries in areas of intense erosion. This is especially true for the multiple intra-middle Eocene unconformities and sequence boundaries observed and inferred for the eastern part of the Maracaibo Basin; these are not reflected in the outcrop belt to the south because the rate of accommodation space was not rapid enough to allow their preservation. Nevertheless, marine transgressive deposits in the southern part of the basin can be clearly recognized (where they are preserved) because of their contrast with otherwise dominant fluvio-deltaic strata; the recognition of specific transgressive events in the eastern part of the basin is less certain because they are less clearly differentiated within the mostly marginal marine strata of the area. The presence of favorable reservoir facies in Eocene rocks in the study area is primarily a function of original sandstone composition, grain size, and burial depth. In the northeastern part of the study area, estuarine channels and transgressive marine/tidal bars have the best reservoir properties in the Misoa Formation. In the southern Maracaibo Basin, fluvial channels and transgressive marine/tidal bars are also the best reservoirs in the Mirador Formation. Transgressive marine/tidal bars within the Carbonera Formation also have favorable reservoir characteristics. Productivity of the best Eocene reservoirs is generally high.

ABSTRACT The Middle Jurassic Brent Group of Northwest Hutton Field includes recently recognized incised valley systems in the Etive and Ness formations. These valleys were cut during relative sea-level falls and back-filled during subsequent rises. Valley-fills comprise mixed fluvial-tidal and purely fluvial rocks. Their grain size, orientation, and geometry contrast markedly with volumetrically greater highstand shoreface and delta mouth bar sheet sandstones. The valley-fills have significantly influenced production history of the field. Published data from other Brent Group fields allows correlation of sequence boundaries semi-regionally. Incised valley-fills range from 1.5 to 15 km in width and appear to have been focused on the Northwest Hutton area through time. Similarly other Brent Group fields appear to have occupied interfluve positions at successive sequence boundary times. This observation reconciles historical conflicts over the presence of sequence boundaries in the Brent province, with some fields having only subtle expressions of these key regional surfaces. Comparison of Brent incised valleys with well exposed examples from the Book Cliffs, Utah increases confidence in valley-fill interpretation and allows prediction of likely ranges of geometry and fill type in undrilled areas. The Book Cliffs example also raises the issues of the nature and location of possible lowstand deposits in front of the Brent delta.

ABSTRACT During the late 1950s hydrocarbons were discovered in the Miocene Lagunillas Formation in Blocks III and IV of the Lake Maracaibo Basin, Venezuela. In ascending order, the Lagunillas is divided into three members: the Lower Lagunillas, Laguna, and Bachaquero. This study focuses primarily on the Lower Lagunillas and Laguna members, which are estimated to contain approximately 2550 MMB OOIP. Overall thickness of the Lower Lagunillas and Laguna members decreases from 630 feet in the southern part of the field to 435 feet along the northern margin. Prior to this study, the Lower Lagunillas and Laguna members were subdivided into six reservoir units for the purpose of reservoir management. However, production and engineering studies showed that this simplistic model, which assumed the six units were homogeneous and in pressure communication, did not adequately address the heterogeneities of the reservoir. A sedimentologic and sequence stratigraphic analysis that integrated eight cores, wireline log suites from 210 wells, and production and pressure data, was undertaken by a team of geoscientists and engineers from GeoQuest and Maraven. The result was a new geological model that contains 29 distinctive, correlatable reservoir layers consisting of 22 sandstones (reservoirs) and 9 shales (barriers). This revised model better explains the historical production performance of the field. Additionally, integration of the new reservoir correlation scheme with production and pressure data, gas chromatography of produced oil samples, and the interpretation of the 3D seismic survey identified several areas where sealing faults have further compartmentalized the reservoir. The Lower Lagunillas and Laguna members were deposited in a variety of depositional environments ranging from fluvial and fluvial-estuarine to strandplain and fluvial-deltaic. The two members comprise part of a third-order sequence that includes at least part of the overlying Bachaquero Member. The contact of the Lower Lagunillas Member with the underlying La Rosa marine shale (Unit I) is interpreted as a type 1 sequence boundary. The revised geological model was then utilized in a reservoir simulation of Blocks III and IV. Simulation results indicate that the shales associated with the nine mappable marine flooding surfaces and sealing faults have acted as barriers to vertical and horizontal communication and define reservoir compartments that contain bypassed oil. Recent drilling has supported the revised model and confirmed the importance of the shales and faults in controlling the distribution and movement of fluids. The revised reservoir model has also identified new opportunities to add reserves and significantly improve recovery from the field through infill drilling, horizontal wells, redesign of waterflood patterns, and recompletions.

ABSTRACT Large volumes of mobile oil remain in mature Gulf Coast fluvial-deltaic reservoirs, in some cases more than has been produced through five decades. Detailed characterization studies that identify the location of remaining oil are needed to recover this large resource. Such studies rely on the confident identification of reservoir architecture and heterogeneity, which are difficult to determine with the limited subsurface data typically available in mature fields. Observations from the Cretaceous Ferron Sandstone of Utah indicate that architecture and heterogeneity are related to position within a high-frequency depositional cycle and are consequently predictable. To test the application of these observations to Gulf Coast reservoirs, the architecture and heterogeneity of upper delta plain channel belt reservoirs within a flooding surface-bounded interval in Tijerina-Canales-Blucher (T-C-B) field, located within the Frio Formation Fluvial-Deltaic Sandstone (Vicksburg Fault Zone) play in South Texas, were examined. Channel belt sandstone reservoirs deposited during the progradational/aggradational portion of a depositional cycle are narrow, ranging from 0.4 to 1.5 mi in width, and internally homogeneous, with single gas completions draining comparatively large reservoir volumes of approximately 40 ac. In contrast, channel belt deposits of the retrogradational portion of a cycle are broad, more than 3.5 mi in width, and internally heterogeneous, with individual completions typically draining oil reservoir volumes of 1.5 ac. These patterns parallel observations of incised valley channel architecture in the Ferron and are probably strongly influenced by progressive increases in baselevel rise through a cycle. However, climate may also influence patterns, as indicated by similarities with Pleistocene Gulf Coast fluvial systems that are interpreted to vary in architecture as a consequence of changing river discharge volumes. Application of Ferron and Scott/Whitehill observations to other Gulf Coast reservoirs should be made cautiously, with appropriate considerations of position along depositional dip and age-specific eustatic amplitudes being incorporated. Predictions of reservoir architecture and heterogeneity made on the basis of position within a depositional cycle can assist in the prioritization of reservoirs for detailed characterization studies, in overall estimations of reserve-growth potential, and in focusing of mature field revitalization strategies.

ABSTRACT From a multidisciplinary study that utilized high-resolution seismic and a variety of analytical data from four continuously-cored boreholes, we have identified six major (and many minor) sequence boundaries and maximum flooding surfaces associated with the oxygen isotope stages 14 to 1 (since 500 KY BP) within the Late Pleistocene shelf margin Lagniappe delta complex in the NE Gulf of Mexico. We discuss here in detail a portion of the delta complex that prograded seaward for several tens of miles during the last, fourth-order, glacial-interglacial cycle since 125 KY BP. A well-developed calcareous-rich interval deposited during the isotope stage 5 (125-70 KY BP) underlies this portion of the delta complex. The delta complex consists of many lobes that were deposited during the several, fifth-order, sealevel drops within the falling stage and during the maximum lowstand-early sealevel rise of the cycle. We have recognized one main fourth-order sequence boundary that resulted from the erosion of an incised valley during the maximum lowstand of sealevel, and several, fifth-order sequence boundaries that were created during the minor sealevel drops within the falling stage. The incised valley-fill deposits consist of distributary channel deposits, bay-head deltas and estuarine deposits that were subsequently transgressed during the Holocene sealevel rise. This transgressive surface forms the base of isotope stage 1. On the whole, the isotope 5 to 1 stage interval of the Lagniappe Delta can be divided into four systems-tracts—highstand, falling stage, lowstand-early rise and transgressive.

ABSTRACT The Aman Trough of Central Sumatra, Indonesia has two associated major hydrocarbon accumulations, Minas and Duri fields. As with most maturely explored basins, more recent exploration activities have involved smaller structural closures, often testing new or different exploration concepts. Sidingin Gas Field, discovered in 1989, is located on an isolated fault block on the northern end of the Aman Trough. Wells in the field encountered reservoir stratigraphy quite different from that encountered in most wells in the Aman Trough. The stratigraphy of the North Aman Trough demonstrates several scales of stratigraphic development: (1) a 2nd order tectonic (syn-rift) cycle, encompassing the entire Pematang Group (Oligocene), composed of stacked fluvial-lacustrine-fluvial members; (2) a series of higher order (3rd order?) sequences, best observed in the fluvial strata, composed of basal coarse fluvial sandstones overlain by floodplain shales; (3) parasequences of individual sandstone/shale couplets. The fluvial rocks in the North Aman Trough and in the Sidingin field are interpreted in terms of regularly varying and repeating base-level cycles. The sedimentology and stacking patterns can be explained in terms of lowered base-level producing highly erosional coarser-grained fluvial channel sands, likely autocyclic in origin, giving way to individual channel and splay sands deposited as base-level rose, and finally capped by a muddy floodplain shale interval. In many cases, the tops of the shale packages are capped with a paleosol, interpreted as a remnant subaerial exposure surface consistent with a relative lowering of base-level. Although well logs through Sidingin field display somewhat similar log character to wells within the Aman Trough proper, evaluation of seismic facies and petrography yielded different stratigraphic interpretations. The reservoir in Sidingin field is interpreted as an alluvial fan and fan delta interval, sourced by highlands associated with the rift basin border fault. The facies successions from oxidized, proximal alluvial fan to intercalated fan delta–lacustrine shale strata suggest that base-level variations related to the local structuring controlled stratigraphic development and distribution in the Sidingin field area.

ABSTRACT The Apiay field is located in the southwestern part of the Llanos Basin, Colombia. The main Apiay reservoirs are in Upper Cretaceous (Coniacian-Campanian) sandstones. Within the lower Tertiary strata (lower Oligocene), a secondary gas/ condensate reservoir occurs in the lowermost sandstones of the Carbonera Formation, informally named the “T1 sandstone.” The T1 sandstone is sandstone-rich across the central part of the field and more mud-rich to the west, and is interpreted as representing the fill of a paleovalley. It comprises dominantly marginal marine strata deposited under brackish water conditions, as indicated by a detailed facies analysis, the trace fossil assemblages, and biostratigraphic data. Lithofacies descriptions recognize the following depositional history within the valley (from bottom to top): a thin interval of fine-grained fluvial sandstone, which rests unconformably over black, shallow marine shales. These fluvial deposits are confined to the deepest part of the paleovalley and have a restricted distribution within the field. There is an abrupt transition upward into marginal marine, brackish deposits composed of medium-grained sandstones, that represent mainly intertidal sandstone bars. The upward change from fluvial deposition to marginal marine is interpreted to reflect an overall transgression during filling of the paleovalley. Marginal marine deposits are volumetrically the most important within the T1 sandstone reservoir. The T1 sandstone can be divided into two flow units. Flow unit 1 shows poor reservoir quality (porosity 17%, permeability of 146 md); flow unit 2 shows good reservoir quality (porosities 14.5%-15.6%, permeabilities 309-397 md). A zone of lower porosity and permeability (13% and 197 md, respectively) was found within this flow unit.

ABSTRACT The Triassic Sherwood Sandstone Group reservoir in the Wytch Farm Field is a c . 150m thick red bed succession deposited in a variety of fluvial, lacustrine and aeolian depositional systems within an actively extensional basin. These systems show at least three orders of facies cyclicity which are interpreted to be the depositional response to base level and climatic changes. The first-order evolutionary trend spans the entire Sherwood Sandstone Group and marks a change from perennial braidplain to ephemeral sheetflood systems to ephemeral lacustrine conditions, culminating in the deposition of playa mudrocks of the overlying Mercia Mudstone Group. The Mercia mudstone shows evidence of marine incursions (several hundred meters above the Sherwood). The first order trend reflects a long-term waning of sand supply across the Wytch Farm area and increasing ‘flashiness’ of the fluvial system coupled with a long term base level rise. The first order facies trend can be subdivided into second-order cycles within the Sherwood by four areally widespread, heavily rooted floodplain and ephemeral lacustrine deposits containing only minor fluvial sandstones. The floodplain and lacustrine deposits represent widespread reductions in sand flux combined with rising base level during more ‘humid’ climatic conditions. These horizons form the basis for the reservoir layering scheme because they are field-wide, have unique core and wireline log expressions and bound fluvial intervals of fundamentally different depositional character. Higher frequency third order cycles are defined by thin (<2m), but areally widespread floodplain and lacustrine horizons which are most readily identifiable in the upper half of the Sherwood section. The sandstones between these cycles are composed of aeolian and sheetflood deposits, but are eroded by coarse grained multistorey/multilateral channel deposits infilling incisional topography. The incisions are interpreted to be the result of fluvial erosion during dry climatic conditions when lake levels fell and the alluvial plain was devegetated. The interfluves to the incisions are locally marked by deep rhizocretionary calcrete precipitated around the roots of phreatophyte-like plants which attempted to reach the lowered water table. The infilling fluvial deposits form the principal producing intervals in the upper part of the reservoir. At outcrop, the stratigraphically equivalent Otter Sandstone Formation ( c . 100km to the west) shows a comparable punctuated evolutionary pattern, albeit with a subtly different facies make-up. The recognition of a hierarchy of facies cycles within the reservoir permits high resolution correlation and the recognition of subtle, but important changes in sandbody geometry and connectivity within successive cycles.