Neil Grant

The role of deformation in controlling depositional patterns in the south-central Niger Delta, West Africa

Abstract The Niger Delta has a distinctive structural and stratigraphic zonation. Regional and counter-regional growth faults, developed in an outer-shelf and upper-slope setting, are linked, via a translational zone containing shale diapirs, to a contractional zone defined by a fold-thrust belt that developed in a toe-of-slope setting. Structural and depositional systems have migrated with the progradation of the delta. A paleo fold belt is buried under the modern upper/middle slope. The structural system in this paleo fold belt is complex and comprises a series of en echelon thrust-cored folds and associated ponded slope-basins, shale diapirs, and extensional growth faults. Analysis of the growth sections filling the ponded slope-basins provides a record of how this accommodation was created and subsequently filled and how the individual structural elements interact to create and modify the available space. The depositional systems initially exploit primary accommodation on the slope created by structural movement—the synchronous growth of the fold, the extensional faults and the shale diapir. As the pond is progressively filled, the previously deposited strata modify the accommodation and subsequent depositional systems compensate accordingly.

The role of fluid pressure and diagenetic cements for porosity preservation in Triassic fluvial reservoirs of the Central Graben, North Sea

Anomalously high porosities and permeabilities are commonly found in the fluvial channel sandstone facies of the Triassic Skagerrak Formation in the central North Sea at burial depths greater than 3200 m (10,499 ft), from which hydrocarbons are currently being produced. The aim of our study was to improve understanding of sandstone diagenesis in the Skagerrak Formation to help predict whether the facies with high porosity may be found at even greater depths. The Skagerrak sandstones comprise fine to medium-grained arkosic to lithic-arkosic arenites. We have used scanning electron microscopy, petrographic analysis, pressure history modeling, and core analysis to assess the timing of growth and origin of mineral cements, with generation, and the impact of high fluid pressure on reservoir quality. Our interpretation is that the anomalously high porosities in the Skagerrak sandstones were maintained by a history of overpressure generation and maintenance from the Late Triassic onward, in combination with early microquartz cementation and subsequent precipitation of robust chlorite grain coats. Increasing salinity of pore fluids during burial diagenesis led to pore-filling halite cements in sustained phreatic conditions. The halite pore-filling cements removed most of the remaining porosity and limited the precipitation of other diagenetic phases. Fluid flow associated with the migration of hydrocarbons during the Neogene is inferred to have dissolved the halite locally. Dissolution of halite cements in the channel sands has given rise to megapores and porosities of as much as 35% at current production depths.

Porosity trends in the Skagerrak Formation, Central Graben, United Kingdom Continental Shelf: The role of compaction and pore pressure history

This paper describes reservoir properties in the Triassic Skagerrak Formation in the Central North Sea. This prolific sandstone reservoir often possesses anomalously high porosity for its depth of burial. Simple statistical analysis of wire-line-log-derived porosity data is used to derive empirical trends as a function of both depth and vertical effective stress that show variations between neighboring hydrocarbon fields and between different parts of the basin. Porosity data from the Josephine (J) Ridge (Quadrant 30 of the United Kingdom Continental Shelf [UKCS]) show a marked degradation with depth, but the porosities are significantly higher than in similarly deeply buried areas such as the Puffin high to the west (Quadrant 29) or the Forties–Montrose high to the north (Quadrant 22). To understand the porosity patterns better the data have been analyzed by plotting against vertical effective stress. This allows a better comparison to be made between fields and wells within the high-pressure–high-temperature (HPHT) realm. High pressure here refers to fluid pressures above 10,000 psi (), whereas high temperatures are above 300°F (149°C). Results show that porosity and fractional effective reservoir (the proportion of net sandstone with a porosity greater than a predetermined cutoff) decrease systematically with increasing vertical effective stress. Data from the different J Ridge fields fall on a common compaction trend even though they are derived from structures with marked variations in present-day depth of burial and static formation overpressure. Trends from the other areas of the Central Graben (the Puffin and Forties–Montrose highs) indicate more indurate reservoir states. The observed porosity trends are independent of fluid type within the reservoir and the absolute magnitude of overpressure. The main observed hydrocarbon effect is the result of buoyancy forces. The analysis supports the contention that, after accounting for facies-related grain-size variations, compaction controls average reservoir properties. Differences in compaction state between areas are postulated to relate primarily to structurally controlled timing of overpressure development relative to burial, and how these affect the resultant vertical effective stress history. Both the Puffin and Forties–Montrose highs are directly attached to the basin margins across stepped faults. These marginal terraces were open to lateral fluid flow for longer probably because across-fault seals were only established late in the burial history when higher temperatures promoted cementation and the destruction of permeability within fault cores. As a result, they developed overpressures in the last 5–10 m.y. or so and are largely normally compacted. The J Ridge horst block is hydrologically more isolated within the basin center by across-fault juxtaposition seals. Here, overpressure development appears to have started earlier, possibly between 50 and 60 Ma, retarding compaction and allowing preservation of higher porosities. Compaction continues to present day driven by the large static vertical effective stress gradients in these deeply buried reservoirs. The observed empirical trends offer a means of predicting average reservoir properties in deep untested exploration targets.

Episodic discrete and distributed deformation : consequences and controls in a thrust culmination from the central Pyrenees

Abstract The Pic de Port Vieux culmination is a 0.5 km long thrust culmination in the footwall of the Gavarnie Thrust in the central Pyrenees. The culmination comprises a set of blind thrusts that imbricate a 50 m thick Mesozoic cover sequence, comprising Triassic red beds and Upper Cretaceous limestone, sandwiched between underlying Hercynian basement and the overlying Palaeozoic strata of the Gavarnie thrust sheet. An intense cleavage developed within the culmination associated with the oblique tip-lines of the thrusts as they climbed from the basement into the cover strata. Detailed mapping shows that the distributed strain associated with the fault tips locally re-activated earlier folded thrusts, creating upper detachments to the system, and produced a set of new overstepping isolated faults. The main detachment occurred along the roof of the culmination using the back-limbs of folds in the roof thrust. The movement on these detachments can be demonstrated to have been episodic, with periods of fault slip producing splays that were then folded during periods when distributed deformation was dominant. The main control on this episodic deformation is modelled as the result of feedback between increase in fluid pressure associated with inelastic porosity reduction during cleavage development, and fluid pressure bleed-off associated with fault zone dilatancy in the culmination.

Salt tectonics, sediments and prospectivity: an introduction

Salt is a crystalline aggregate of the mineral halite, which forms in restricted environments where the hydrodynamic balance is dominated by evaporation. The term is used non-descriptively to incorporate all evaporitic deposits that are mobile in the subsurface. It is the mobility of salt that makes it such an interesting and complex material to study. As a rock, salt is almost unique in that it can deform rapidly under geological conditions, reacting on slopes ≤0.58 dip and behaving much like a viscous fluid. Salt has a negligible yield strength and so is easy to deform, principally by differential sedimentary or tectonic loading. Significant differences in rheology and behavioural characteristics exist between the individual evaporitic deposits. Wet salt deforms largely by diffusion creep, especially under low strain rates and when differential stresses are low. Basins that contain salt therefore evolve and deform more complexly than basins where salt is absent. The addition of halokinetic processes to the geodynamic history of a basin can lead to a plethora of architectures and geometries. The rich variety of resultant morphologies have considerable economic as well as academic interest. Historically, salt has played an important role in petroleum exploration since the Spindletop Dome discovery in Beaumont, Texas in 1906. Today, much of the prime interest in salt tectonics still derives from the petroleum industry because many of the world’s largest hydrocarbon provinces reside in salt-related sedimentary basins (e.g. Gulf of Mexico, North Sea, Campos Basin, Lower Congo Basin, Santos Basin and Zagros). An understanding of salt and how it influences tectonics and sedimentation is therefore critical to effective and efficient petroleum exploration. Within rift basins in particular, salt is seen to orchestrate the petroleum system. Through halokinesis it creates structural traps, counter-regional dips on continental margins, and it can carry or entrain adjacent lithologies via rafting. Salt influences synand post-kinematic sediment dispersal patterns and reservoir distribution and can therefore be important for the creation of stratigraphic traps. It can also form top and side seals to hydrocarbon accumulations and act as a seal to fluid migration and charge at a more regional scale. Salt may also dramatically affect the thermal evolution of sediments due to its high thermal conductivity. A thick layer of salt cools sediments that lie below it while heating sediments above it. This effect cannot be underestimated as it helps provide the favourable conditions for source rock maturation in the deepwater Gulf of Mexico and Santos basins, even though sedimentary overburden may be 5 km or more in thickness. Salt can also impact reservoir quality. The role of salt in the diagenetic history of reservoirs through its control on hydrothermal pore waters is a crucial element in the risking of the deepwater Palaeogene play of the Gulf of Mexico, for example. Salt continues to kinetically evolve through time, not only by the classical roller-diapir-pedestal-canopy/ collapse progression but also with varying rates of deformation, in response to changing sedimentation rates and patterns. The relative timing of salt movement and its impact on source, reservoir, trap, seal and timing often governs the prospectivity in saltrelated basins. Beyond the realm of petroleum, salt is also used as a resource for potash, gypsum and nitrates and has the potential to be employed as a repository for radioactive waste or a top seal to sequestered CO2.

A look into the Val Verde Basin, Texas

Editors note: This paper won the Best Poster Paper Award from the 2001 Annual Meeting in San Antonio. The study area consists of 180 miles2 within the Val Verde Basin. A new interpretation is proposed and is based primarily on 3D seismic data. Emphasis is placed on the Lower Permian to Pennsylvanian Section in which hydrocarbons have been found from tight reservoirs. The general stratigraphy is summarized, the focus being on hydrocarbon source, reservoirs, and seal. Seismic lines, spread across the area, illustrate structure. The producing fields sit atop the Foreland Thrust, which was transported as a decollement zone on Mississippian shales. A series of backthrusts is invoked to accommodate the movement of competent rocks up the ramped Foreland Thrust, creating the main structures in the fields. The Foreland Thrust is thought to be the primary migration pathway while the back-thrusts appear to be secondary migration pathways. The new interpretation incorporates 3D seismic, well, and reservoir performance data. The 3D seismic data, in particular, demonstrate the overall sequence stratigraphy of the basin and lead to a new structural interpretation. This interpretation is based mainly on 3D seismic data. Emphasis is placed on the Lower Permian to Pennsylvanian geologic section where hydrocarbons have been found in tight reservoirs. Currently, these reservoirs are being developed by Conoco Inc. in partnership with Tom Brown Inc. Geographically, the study area is located about 120 miles south of Midland in Texas. It encompasses Conocos 3D seismic coverage in the Val Verde Basin and occupies an area roughly 30 × 6 miles. Geologically, the Val Verde Basin comprises the southern portion of the greater Permian Basin of mid-continent United States. It lies between the Central Basin Platform to the north and the Marathon Uplift to the south (Figure 1). Figure 1. Location map. Based on 2D seismic …

A geometrical model for shale smear: implications for upscaling in faulted geomodels

A new 1D bed-scale model has been built to help model shale smear in interbedded sand–shale sequences using the shale smear factor (SSF). A smear envelope is generated by mapping each potential shale smear onto the fault plane employing five different shale smear geometries. Graphical outputs then focus on the cumulative length of the resultant smears and the remaining sand–sand juxtaposition windows in the predicted shale smear envelope. The smears are evaluated stochastically with lengths that are a randomized function of the estimated Vclay content of the source shale layers, allowing the smear pattern to change with each realization. A new fragmented smear mode is developed that allows discontinuous smears to be distributed randomly on the fault plane and can be used to modify the smear pattern as fault displacement increases. The model has been tested using well data. Results show that windows in the smear envelope are commonly present, and that their frequency and location are dependent on the smear placement model and sand–shale stacking pattern. Smear fragmentation leads to more windows being preserved. The 1D model can also assess the impact of geocellular upscaling on fault seal analysis. Upscaling reduces cross-fault sand connectivity due to the elimination of thin beds. Shale smear envelopes are also reduced in length as fewer shale beds are involved, even though layers are thicker. A fault may or may not appear more sealing dependent on the layer configuration and net-to-gross ratio (NTG). The model offers results that can inform input to fault seal evaluations and allows the effect of geomodel upscaling to be more closely interrogated.

ABSTRACT: On how the interaction of tectonics and sedimentation within the Niger Delta has created a complete petroleum system

The Niger Delta comprises a highly integrated tectonostratigraphic system where all elements of the deltaic system work in concert to form the source, reservoirs, seals, migration pathways and traps that are key to a working petroleum system. The delta was initially confined within the Benue Trough. Sediment mass was low and relatively few structures were developed. In this setting much of the sediment load bypassed the slope and was deposited on the basin floor. These strata were subsequently buried by the advancing delta front. Continued sediment loading during progradation of the delta created gravitational instability that in turn lead to the development of linked systems of extensional, diapiric and contractional structures. These structures modified accommodation on the slope and the sedimentary systems compensated accordingly. Deformation of the delta caused restricted bypass of the sediment mass to the basin floor, creating the slope centered depositional profile observed today. The increasing sediment load had another important effect -- it generated hydrocarbons, which in turn helped create the structural form. The generation of hydrocarbons within shales of the lower deltaic sequences created overpressured conditions over a wide region. This facilitated the generation of the huge detachment surface that underlies the linked extensional and contractional regions. To complete the linkage, the structural and stratigraphic systems themselves not only interact to create traps and seals within the delta system but also serve as conduits for hydrocarbon migration. The Niger Delta is thus a complete petroleum system in which all elements are contained within the deltaic succession.