Petroleum Geoscience - Volume 21, Issue 2-3, 2015

The results of well-constrained seismic interpretation and new mapping of three-dimensional (3D) seismic data volumes demonstrates that the North Falkland Basin consists of two superimposed failed rift basins: a Late Jurassic NW–SE-striking Southern Rift Basin (SRB); and an Early Cretaceous north–south-striking Northern Rift Basin (NRB).

The SRB is best developed in coastal waters of the Falkland Islands, where it comprises a series of extensional sub-basins that are transected by faults belonging to the more substantive NRB. Regional interpretation demonstrates that the NRB consists of a southward-tapering, asymmetric extensional basin containing a thick (in excess of 10 km) sequence of sediments. Its syn-rift subsidence history was controlled by a major west-dipping normal fault array comprising several fault segment precursors, which, together with corresponding antithetic faults, effectively subdivides the hanging wall into a series of sub-basins throughout its length.

The NRB initially developed in a fluvial and later lacustrine environment before becoming predominantly marine in the Tertiary. A prograding delta system filled the basin from the north during the early post-rift phase. Contemporaneously, sediment was shed off the segmented basin-bounding fault via long-established feeder drainage systems through breached relay ramps into the depocentre. The resultant sediment dispersal led to deposition of numerous lacustrine turbidites that created the Sea Lion fans and its affiliates, the location of which mimics, and is thus interpreted to have been controlled by, the underlying syn-rift sub-basins.

Post-rift subsidence was punctuated by an important, but short-lived, phase of basin inversion during the Aptian that created a large, broad and gentle north–south-striking anticline that runs along the central basin axis. Whilst the episode of basin inversion arrested subsidence, it did not inhibit petroleum prospectivity. The syn-rift lacustrine source intervals did subsequently pass through the critical moment in the Cretaceous leading to hydrocarbon maturation and the migration of waxy oil, a process that continues to the present day.

In 1998, the first six wells were drilled in the North Falkland Basin, and demonstrated the presence of excellent source rock and good reservoirs. Oil and gas shows were encountered in all but one well; however, no commercial volumes of hydrocarbons were proven. At that time, the focus of exploration was almost exclusively on traditional structural traps mapped on two-dimensional (2D) seismic surveys. Eleven years later, in May 2010, Rockhopper Exploration discovered the Sea Lion Field, which has over a billion barrels of estimated oil in place. Discovery well 14/10-2 was drilled on three-dimensional (3D) seismic data acquired by Rockhopper in 2007. Unlike the targets of the first campaign, the Sea Lion prospect was a stratigraphic trap imaged as a series of fan-shaped amplitude anomalies.

Following a successful drill stem test of the SL10 and SL20 fans in the discovery well, Rockhopper embarked on an aggressive field appraisal and exploration drilling programme in the Sea Lion area. A second fully engineered production test was successfully performed on a later well to establish commercial flow rates. In addition to appraising the Sea Lion reservoirs, a further three hydrocarbon-bearing reservoirs were proven (Casper, Casper South and Beverley). Comprehensive data acquisition and analysis has been key to de-risking the first commercial development in the basin. A full suite of wireline logs was run in all the appraisal wells; seven wells were extensively cored and fluid samples were recovered for analysis from all reservoirs. In parallel with the drilling campaign, in 2010–11 a total of 4500 km2 of 3D seismic data was acquired and processed in a collaborative programme with Argos and Desire.

In 2012, Premier Oil farmed-in to the licence and assumed operatorship with 60% equity. Dynamic modelling indicates that estimated resources of approximately 160 million barrels (160 mmbbl) can be recovered from the north-east flank of the field based on a Floating Production, Storage and Offloading (FPSO) facilities concept for Phase 1 of the field development. The concepts for additional phases of field development are currently being evaluated.

The Sea Lion Field, lying approximately 220 km north of the Falkland Islands in the northern rift of the North Falkland Basin, contains waxy oil in Lower Cretaceous reservoir sands. The oil is likely to be sourced from Lower Cretaceous lacustrine source rocks lying beneath the reservoir sands. A significant complication in interpreting the geochemical data for the Sea Lion oils comes from their overprinting by leaching of bitumen components (especially biomarkers) from immature organic-rich claystones that are interbedded with the reservoir. Accordingly, best estimates of maturity are obtained from gasoline-range and aromatic hydrocarbons. A higher maturity charge is seen in oils from some of the more western wells, consistent with their higher gas–oil ratios. Basin modelling has shown that the source rocks are more mature to the south of the Sea Lion Field, and the observed differences in oil maturity can be related to sourcing from different parts of this kitchen area and/or different stratigraphic intervals of the source-rock package. Gasoline-range hydrocarbons provide evidence for phase fractionation, with some oils having lost a more volatile fraction whilst others have received additional gas charge. A gas leg in the Beverley and Casper South reservoirs in Well 14/15-4Z appears to have been the original fluid charge, and has not displaced oil, although gas compositions suggest that gas was co-generated with oil, and subsequently separated into two phases, at least in some parts of the field.

Fan bodies in the North Falkland Basin, including those that comprise the reservoir in the Sea Lion Field, have been defined seismically with the aid of several seismic attributes. This has provided a greater understanding of their geomorphology, potential reservoir variations and distribution, and has helped illuminate the full extent of some fans as well as the internal architectural detail of others. The attributes used include reflectivity attributes on full-stack and part-stack three-dimensional (3D) seismic data, impedance attributes on inverted seismic data, isochron attributes, and geometric attributes such as coherence, dip, curvature and spectral decomposition. The combination of spectral decomposition and high-resolution visualization techniques has greatly aided the identification and interpretation of some of the fans. Colour blending, where separate colours relating to different frequency ranges are blended into a single image, can reveal additional detail within the fan systems. Specific colour blends are seen to highlight separate sand bodies, as well as thickness variations, and have helped to resolve stratigraphic and petrophysical heterogeneity. Seismic attribute responses have been quantified with the integration of well data from the 18 wells within the 3D data set. This has resulted in a detailed reservoir characterization and definition of geological features within some of the fan bodies. This detailed use of seismic attributes on the North Falkland Basin 3D data set has been of benefit for both the appraisal and development of the Sea Lion Field, and has also helped to define future exploration targets and well locations within the basin.

Extensive use has been made of seismic-derived quantitative interpretation for mapping and predicting reservoir properties in the Sea Lion Field, North Falkland Basin. The Sea Lion sands are acoustically hard compared to the encasing shales, with fairly constant rock properties. The fans are typically 20–60 m in thickness and are predominantly seismically tuned events. Detection of hydrocarbon fluid effects from seismic data has proved elusive to date.

Extended elastic impedance (EEI) was selected as the appropriate seismic analysis tool. Almost all sands are visible on the full-stack seismic data. Coloured inversion of an EEI volume with a rotation angle (χ) of −70° (henceforth shown as EEI(−70)) was found to be an optimal sand predictor and is primarily sensitive to the shale volume of the sands. This EEI χ angle also allows detection of sand that is not observed on the full-stack seismic.

The EEI(−70) coloured inversion data were also used to estimate net sand thickness and the net-to-gross maps of the fans. Subsequently, a new algorithm termed DT-AMP was used to apply seismic amplitude detuning to the full three-dimensional (3D) seismic volume. This has proved useful in the evaluation of new exploration targets beyond the Sea Lion Field area.

A sand classification was performed using multiple EEI attributes, including lithology and fluid cubes. This indicates that there are differences in the amplitude v. offset (AVO) response across the main Sea Lion fan complex.

Pre-stack simultaneous inversion was also performed using both deterministic and stochastic schemes. A three-term inversion was tested but density estimation was considered to be unreliable.

Seismic data were tested at several stages to constrain the static reservoir model, using coloured, deterministic and stochastic inversion methods. The final static model incorporated a set of scenarios using net-to-gross maps inferred from the quantitative analysis of the EEI(−70) data.

Application of a multidisciplinary stratigraphic approach has significantly improved understanding of the vertical and lateral distribution of reservoir sandstone bodies and associated sediment pathways of the Sea Lion Field in the North Falklands Basin (NFB). Bio- and chemical stratigraphy combine to provide a robust framework capable of providing subseismic resolution to sandstone layering within the lacustrine setting of the basin, as well as highlighting the geochemical link between the timing of sandstone deposition and specific sediment supply points. The Barremian–Aptian mudrocks that host the Sea Lion reservoirs are uniform deep-water, anoxic shales with limited regional, chronostratigraphic resolution. In the absence of marine planktonic groups and with the scarcity of age diagnostic taxa, use has been made of locally correlative bioevents that have provided resolution to characterize and correlate most of the Sea Lion reservoir units or to provide some further subdivision of seismically defined units.

Chemical stratigraphic analysis (X-ray fluorescence (XRF)) initially yielded a highly variable set of data that cross-correlated biostratigraphic and seismic data, indicating that the controls on elemental character were not primarily stratigraphically controlled. An innovative approach to interpretation is described that brings together stratigraphic and geographical geochemical variation, and, by accommodating diachroneity, has resulted in a detailed sequencing of the individual turbidite fan systems, from the perspective of evolving and migrating sediment supply points into the NFB. The use of geochemical data has also provided a basis for the subseismic resolution and subdivisions of sandstone units.

The Sea Lion Field in the North Falkland Basin was discovered in 2010 by Well 14/10-2, which tested oil from Lower Cretaceous sands of the Sea Lion fan complex. Appraisal of the field involved the drilling of a further eight wells from which an extensive wireline-log data set and 455 m of core were acquired. This unique data set has allowed detailed study of the reservoir sedimentology and has significantly benefited reservoir characterization. The reservoirs are interpreted to be deposited in a deep-water lacustrine basin as base-of-slope to basin-floor fans fed by canyons or channel-feeder systems from the east. Deposition is considered to have been affected both by turbidity currents and by liquefied sediment gravity flows, such that reservoir facies are dominated by those associated with high- and low-density turbidites, mass-flow deposits, and, to a lesser extent, hybrid-event beds. In the absence of significant chronostratigraphic control, the description of the first-order reservoir architecture is primarily driven by seismic interpretation, whilst the core affords significant control of the internal architecture of individual fans. Several lines of evidence point towards the Sea Lion sands being derived from a coexisting, shallow-water system on the eastern margin of the basin. Palaeogeographical reconstruction links this shoreface system to a large, contemporaneous, southerly-prograding delta via wave reworking and longshore drift of delta-front sands. Evolution of this delta has played a significant role in the timing, positioning and emplacement of fans along the eastern margin of the North Falkland Basin. The overall impact of the core data set has been to improve confidence in the reservoir characterization and spatial distribution of facies within the reservoir model, and to narrow significantly the range of uncertainty, which has direct implications for field development planning.

The reservoirs that form the Sea Lion Field comprise a series of canyon-fed fans deposited into a deep, anoxic lake, on the hanging wall of the basin boundary fault. The fans primarily form stratigraphic traps with an element of fault seal on the west flank. These fans are dominated by mass flow and high-density turbidite sands, with subordinate low-density turbidites set within lacustrine shales. The fans mapped on seismic profiles are partitioned into lobes, based on sand bodies penetrated into the wells or the conceptual model where correlation between wells is not possible. Ten facies are identified from core but attempts to discriminate facies met with mixed success. Facies are therefore combined into four associations (‘Rock Types’) for use in dynamic flow modelling. Rock Types are distributed within the fans using a hierarchical reservoir architecture (‘fan-lobe-surge’). This paper describes the reservoir and fluid characteristics, and outlines the challenges associated with converting the detailed geological model into a form suitable for reservoir simulation, while preserving the main reservoir features that will influence fluid movement within the reservoir

Gas wells may suffer a significant decline in gas production or may even be destroyed as a result of the influx of water into production zones. The situation may even be worse in horizontal wells. Closing off the water-producing zone may not be appropriate and the disposal of produced water is, in many cases, expensive. A substantial decline in gas production is usually associated with an increase in water production or water cut. Water shut-off/reducing water production is helpful in maintaining gas production at high values. In this study, the feasibility of reducing the water production in modelled gas reservoirs by changing the wettability of the gas zone from preferential water- to gas-wetness using a fluorine carbon surfactant has been investigated experimentally. The basic mechanism used is that the entry capillary pressure has to be overcome prior to water entering the gas zone after the wettability has been altered to gas-wetness. Naturally, water can imbibe into gas zones spontaneously because the rock in gas zones is, most probably, water wet. After wettability alteration from water- to gas-wetness, water cannot enter gas zones if the differential pressure is less than the entry capillary pressure, and so the water flux will be significantly reduced even if the differential pressure is greater than the entry capillary pressure. An artificially made, consolidated two-layer core model was used to conduct the study. The two layers had different permeabilities, and the top layer was served as the gas zone and the bottom layer as the bottom aquifer. The gas production was measured at different initial water saturations with and without wettability alteration from preferential water- to gas-wetness in the gas zone. The experimental results showed that the water breakthrough time could be postponed and that the amount of water entering the gas zone could be reduced significantly by altering the wettability of the gas zone to gas-wetness. The advantages of this approach in reducing water cut were: (1) the permeability of the gas zone was almost unaffected by the chemical treatment for wettability alteration; and (2) the chemical treatment for wettability alteration had great longevity.