User:Hannah paradis/Kingfish Oil Field

Location
The Kingfish oil field is located 48 miles offshore southeastern Victoria, Australia. The Gippsland Basin is large enough to have an onshore and offshore components. Majority of Gippsland Basin is offshore, while the onshore part extends from Western Port Bay to Orbost.

Tectonic History
The tectonic history concerning the formation of the Gippsland Basin is complex. The catalyst for the formation was the breakup of Gondwana in the Late Jurassic/Early Cretaceous. Specifically in the Tithonian Age, when Australia and Antartica started to diverge, the Gippsland Basin formed in the west and the Bight Basin formed in the east. The divergence of Australia and Antartica created an east/west rift valley system in the Gippsland Basin filled with half-graben structural features. The half-grabens consisted of coarse-grained alluvial material. In the Early Cretaceous, volcaniclastic materials piled up with an extensive fluvial system. The volcaniclastic sediment is due to the eruptions along the Australian margin. Fine-grained floodplain deposits produced coal horizons in the top of the succession. The fluvial sediment from the Early Cretaceous is named the Strzelecki Group in the Gippsland Basin. After Australia and Antartica separated every basin in this area underwent different tectonic events and basin-specific depositional patterns developed that were primarily controlled by the relative position to spreading centers and Paleozoic basement blocks. In the Turonian, the Gippsland Basin changed into an internally draining depositional system. Deep rift valley lakes contributed to a thick sequence of lacustrine shales while coarse grained alluvial deposits were shed from the uplifted basin margins.

The second phase of rifting occurs in the Late Santonian when the Tasman Sea is formed. As a result of the development of the Tasman Sea, the rift trends NE-SW. The sediment that deposited during the opening of the Tasman Sea was marine shales in the eastern part and a broadening coastal plain in the western part of the Gippsland Basin. This phase generated a classic extensional geometry comprising a depocenter (the Central Deep) flanked by platforms and terraces which provided the accommodation space for large volumes of basement-derived sediments. These platforms are defined by the Rosedale and Lake Wellington Fault Systems on the northern basin margin and by the Darriman and Foster Fault Systems on the southern margin. The renewed extensional tectonism also generated numerous volcanic horizons, which are mostly confined to the immediate vicinity of major faults. From the Maastrichtian to the Eocene, the Gippsland Basin underwent a period of thermal subsidence, along with normal faulting. During this period the interaction between the coastal plain nearshore and offshore marine depositional processes was critical for the establishment of the required petroleum systems elements. In the middle Eocene, sea-floor spreading had ended for the Tasman Sea and the offshore basin deepened and little faulting occurred.

The third major phase was the compressional period that took place in the Late Eocene. The compressional period reactivated faults and developed a series of northeast to east-northeast-trending anticlines. Compression and structural growth peaked in the middle Miocene and resulted in partial basin inversion. All the major fold structures at the top of the Latrobe Group, which became the hosts for the large oil and gas accumulations, such as Barracouta, Tuna, Kingfish, Snapper and Halibut, are related to this tectonic episode. The anticlines act as the structural regional seal to these formations and are composed of Tertiary cool-water carbonates.

Depositional Environment
The depositional environments of the Gippsland Basin have evolved over the course of its formation. The Gippsland Basin’s 3 billion bbl recoverable oil was produced from humic coal snf associated carbonaceous. The Latrobe group which contains most of the hydrocarbons has one of the thickest fluvio deltaic sequences. The sequences occurred over the course of 60 m.y., but ended in the Oligocene transgressive event. The transgressive event allowed erosion to take place on the top of the Latrobe group. This left room for the deposition of muds to take place. Similar to the Latrobe group, the Strzelecki group sediments were deposited in a fluvial to deltaic and alluvial fan environments. The Strzelecki group sediments were deposited in non-marine and fluvial deposition environments.

The Latrobe group, the most successful oil producing group, was able to be traced back to a terrestrial environment. This is contributed to the fact that geological and geochemical data suggests the coal-rich Latrobe group is the source of oil. The climate suggested by the plants and flora recorded in the Eocene relate to a 13℃ to 14℃ which is similar to modern day New Zealand.This is characterized as a temperate to rain-forest environment. The southern coniferous rainforests were dominated by Kauri vegetation which is supported by the pollen that was fossilized. Another reason the Latrobe group has a large amount of oil is due to its raised bog setting promoted the development of unusually thick coal seams with well-preserved tree trunks, cones, seeds, leaves, and resin bodies, which provided large quantities of exinite macerals with the potential to generate oil. The type of oil that the Latrobe group produces is derived from immature source rocks that suggest paraffinic oil. The paraffinic oil is derived from coal deposits and naphthenic oil from resin.

Strzelecki Group
The Strzelecki Group was formed in the initial syn-rifting in the Early Cretaceous which created those systems of grabens and half grabens. The Strzelecki Group unconformably overlies igneous and folded sedimentary rocks of Palaeozoic age. These structural formations allowed volcaniclastic sandstones, minor coals, and mudstones to be deposited in the Cenomanian. Thickness of the Strzelecki Group generally ranges from a few hundred meters to more than 2,600 m, but estimated thickness in some areas is as much as 6,000 m. The Strzelecki Group is traditionally regarded by the petroleum industry as ‘economic basement’ within the Gippsland Basin.

Emperor Subgroup
The Emperor Subgroup was deposited in the Turonian age during the evolving rift valley. The Emperor Subgroup is composed of coarse-grained alluvial fan/plain facies and braided stream units, and associated lacustrine facies characteristic of rift-valley deposition prior to continental break-up. Alluvial fan/plain and braided stream units were deposited near the basin margin. These comprise immature sandstones, siltstones, shale and minor coals. The alluvial fan/plain and braided stream stream units are known as the Curlip Formation. This initial deposition was eventually eroded from the uplifted basin margins. A series of large, deep lakes developed, resulting in the deposition of the lacustrine Kipper Shale. This lake complex is described as deep and persistent through time with lake surface areas estimated at 5,000 km². Thick sections of lacustrine shale have been drilled. The deposition of lacustrine siltstones, shales, and minor coarse-grained sandstones accumulated makes up the Kipper Shale.

Golden Beach Subgroup
The Longtom Unconformity separates the lacustrine dominated Emperor Subgroup from fluvial and marine sediments of the Golden Beach Subgroup, with the first marine incursion recorded by the upper Santonian sediments of the Anemone Formation (Golden Beach Subgroup) in the eastern part of the basin .The Golden Beach Subgroup is located and mostly confined to the Central Deep and does not extend significantly to north of Rosedale Fault system or south of the Foster Fault system. The first of two distinct facies is the Chimaera formation that is composed of sandstones and minor shales that were deposited as part of an extensive fluvial system near the basin margin. The second distinct facies is the Anemone formation which consists of marine shales that represent the first basinwide marine incursions. This deposition was caused by the opening of the Tasman Sea evolved into seafloor spreading several Campanian basaltic volcanic horizons are observed within the Golden Beach Subgroup. A distinct intra-Campanian unconformity, recognized across many parts of the basin, marks the termination of Golden Beach sedimentation.

Halibut Subgroup
This subgroup is extremely important because the majority of the hydrocarbons come from. Rift-related extensional tectonism continued until the early Eocene and produced pervasive northwest-striking normal faults, especially in the Central Deep. A succession of fluvial, deltaic and marine sediments was deposited across the basin forming the Halibut Subgroup. The Barracouta Formation is characterized by fluvial siltstones, sandstones and minor coals and was deposited on an upper coastal. The Volador and Kingfish formations comprise typical lower coastal plain coal-rich sediments and are separated by the Kate Shale. The Kate Shale is a marine interval recognized at the Cretaceous/Cenozoic boundary. The Mackerel Formation consists of nearshore marine sandstones, commonly typified by excellent reservoir quality, with intercalated marine shales. It documents the changes from marine to non-marine environments in an east-west (or offshore-onshore) direction. Relative sea-level fall in the early Eocene, driven by basin inversion, initiated a period of major canyon cutting in the central basin during which parts of the lower coastal plain and the shelf were eroded.The array of fluvial channel systems that developed has added considerable complexity to seismic mapping, because the major channels cut down hundreds of meters into the underlying strata. During subsequent transgressions, the channels were filled with marine sediments leading to the generation of potential stratigraphic hydrocarbon traps.

Cobia Subgroup
By the middle Eocene to early Oligocene, sea-floor spreading had ceased in the Tasman Sea and there was a period of basin sag, during which the offshore basin deepened but little faulting occurred. This subgroup is composed of coal-bearing, lower coastal plain facies of the Burong Formation, which is reasonably well-developed across the eastern part of the onshore Gippsland Basin. The Cobia Subgroup also consists of a transgressive shallow to open marine Gurnard Formation, which is a condensed section characterized by fine- to medium-grained glauconitic siliciclastic sediments. The Gurnard Formation is believed to act as a top seal for some of the giant hydrocarbon fields offshore. Deposition of the Cobia Subgroup ceased during the early Oligocene, due to a marked decline in sediment supply. Large areas of the central basin were left with starved or condensed sections, which led to the development of what is traditionally known as the ‘Latrobe Unconformity’.

Seaspray Group
In the early Oligocene, sediments of the Seaspray group deposited were calcareous sediments that unconformably overlie the siliciclastics of the Latrobe Group. The accumulation of limestones and marls was subsequent to the change in ocean circulation along the southern Australian margin. This effect caused a shift and cool-water carbonate production and deposition occurred and the shelf prograded. The Lakes Entrance Formation, is basin-wide and has a high quality regional seal to the oil and gas accumulations at the top of the Latrobe group. The Lakes Entrance Formation is the lowermost unit of the Seaspray Group and is composed predominantly of smectite-rich calcareous mudstones and claystones, with some variation in composition across the basin.

Seals
The Seaspray Group forms the regional seal to the Top Latrobe hydrocarbon pools in the basin and is fully marine in the offshore where it consists of fine-grained calcareous mudstones, marls as well as fossiliferous limestones. The Seaspray Group is a carbonate-dominated mega-sequence and the basal Lakes Entrance Formation forms a regional seal across the basin. The group also provides critical amounts of overburden, (1 km thick near the basin margins, up to 3 km thick in the Central Deep) needed for source rock maturation. In the Emperor Subgroup, Kipper Shale formation, it is dominated by mudstones with intercalated fine- to medium-grained sandstones and is a potential sealing facies. The thickness of this seal is around 500 m. There are many intraformational sealing units within the Latrobe Group like thin, stacked sandstone/mudstone successions that are in cross-faults. For example, one of the Kingfish wells is one of the few wells in the basin that instructively documents the lithological variations in the Seaspray Group. The well only penetrated the uppermost 150 m of the Latrobe Group, successfully drilling the “Coarse-Clastics” oil reservoir unit, which is sealed by siltstones and mudstones of the Gurnard Formation.

Maturation & Porosity
Consequently, exploration within the Gippsland Basin is mature in comparison to other Australian basins. Latrobe Group reservoir porosities average 15–25% across the basin, with the best primary porosities preserved in fluvial/ deltaic sandstones that are texturally mature and moderately well sorted. Peak hydrocarbon generation within the Latrobe Group source rocks is considered to take place with Ro at 0.92–1.0% (Clark and Thomas, 1988), which agrees well with the findings of Burns et al (1987), whose maturity data (Methylphenanthrene Index of Radke and Welte, 1983) indicated that most Gippsland Basin oils were generated with Ro at 0.9–1.16%.

Trapping Mechanisms
The trapping mechanisms were formed during the extensional tectonism in the early Eocene and compressional tectonism from the early Eocene and early Miocene. Extensional tectonism prevailed until the early Eocene and produced pervasive NW-SE trending normal faults. Also following the conclusion of Tasman Sea rifting in the Eocene, a period of compression initiated a series of northeast to east-northeast trending anticlines and the main hydrocarbon traps offshore. This resulted in a series of anticlines forming oblique to the basin trend and the partial inversion of the earlier normal faults. This phase peaked during the middle Miocene but continued to overprint the basin until the Pleistocene. Specifically for the Kingfish Field area the traps were placed in the Late Oligocene.

Oil History
In 1965, Esso and BHP Billiton took a chance when they drilled Australia’s first offshore well and discovered the Barracouta gas field in the Bass Strait. On April 6, 1967 the Kingfish oilfield was discovered which was the first offshore oil field. The Kingfish Oil Field was declared a commercial oil field in May of 1968. This is the largest oil field ever discovered in Australia. Esso and BHP Billiton’s contract expired September 19, 2010. Since then Exxon and Esso have owned the Kingfish oilfield.

Oil Production
In 2007, according to ExxonMobil Australia chairman Mark Nolan, the Kingfish field has produced over 1 billion barrels of crude, and continues to be one of our most important oil producers 40 years after its discovery. The Gippsland Basin is forecast to continue to provide the majority of gas produced from offshore south east Australia. In the period through to 2022, the pattern of upstream production remains similar to recent trends with the Gippsland Basin continuing to provide increased gas supplies during periods of peak seasonal demand.

Future Plans
The Gippsland Basin will eventually be transformed into a CO2 injection site in the distant future. Due to the slow decrease in production old wells will be reused by storing CO2 gases. A study completed in 2012 by Miranda et al., experiments and discusses the data to support this plan. After their preliminary results the regional attributed model of the Gippsland Basin is adequate for visualizing the effects of CO2 injection and associated plume migration at selected sites. However there are many limitations due to the lack of evidence and data.