THE ELANG OIL DISCOVERY ESTABLISHES NEW OIL PROVINCE IN THE EASTERN TIMOR SEA (TIMOR GAP ZONE OF COOPERATION)

1995 ◽  
Vol 35 (1) ◽  
pp. 44
Author(s):  
I. F. Young ◽  
T.M. Schmedje ◽  
W.F. Muir
Keyword(s):  
Seismic Data ◽  
Late Jurassic ◽  
Joint Venture ◽  
Seismic Survey ◽  
Normal Faults ◽  
Commercial Development ◽  
The North ◽  
3D Data ◽  
Porosity And Permeability ◽  
Timor Sea

The Elang-1 oil discovery in the Timor Gap Zone of Cooperation (ZOC) has established a new oil province in the eastern Timor Sea. The discovery well, completed in February 1994, recorded a flow of 5,800 BOPD (5,013 STBOPD) from marine sandstone of the Late Jurassic Montara beds. The oil is a light (56° API), undersaturated oil with a GOR of approximately 550 SCF/STB. Elang-1 was the first well drilled by the ZOCA 91-12 Joint Venture and only the fifth well in the ZOC since exploration of this frontier area resumed in 1992.The Elang Prospect, initially mapped by Petroz in the late 1970s on the basis of regional seismic data, was detailed by the 1992 Walet Seismic Survey. The prospect is the main crestal culmination on the Elang Trend, a prominent structural high to the north of the Flamingo High that was established during continental break-up in the Late Jurassic. The Elang Trend is bounded to the south by a series of en-echelon normal faults and connecting relay ramps and comprises a number of horst and tilted fault blocks.Elang-1 tested a near crestal culmination on the Elang Prospect and intersected a 76.5 m gross oil column below 3,006.5 m RT. At time of drilling this oil column was the thickest that had been encountered by any well in the Northern Bonaparte Basin. Good quality reservoir sandstone in six discrete bodies were intersected within the Montara beds. Core-measured porosity and permeability range up to 17 per cent and 2.2 Darcies within the oil column.Subsequent to the Elang discovery, the Joint Venture recorded a 402 km2 3D survey over the Elang Trend. Elang-2, an appraisal well spudded in September 1994 prior to receipt of the 3D data, established the lateral continuity of the Montara beds reservoirs. Flow rates of 6,080 BOPD (5,300 STBOPD) and 7,500 BOPD (5,970 STBOPD) from separate intervals have confirmed that high deliverabilities can be expected from individual sandstones. Further appraisal drilling is planned in the first half of 1995. This is expected to lead to commercial development of the field.

THE YELLOWTAIL OIL DISCOVERY

1983 ◽  
Vol 23 (1) ◽  
pp. 170
Author(s):  
A. R. Limbert ◽  
P. N. Glenton ◽  
J. Volaric
Keyword(s):  
Oil Recovery ◽  
Seismic Data ◽  
Joint Venture ◽  
Seismic Survey ◽  
3D Seismic ◽  
Well Control ◽  
Reservoir Volume ◽  
3D Data ◽  
Small Feature ◽  
Gippsland Basin

The Esso/Hematite Yellowtall oil discovery is located about 80 km offshore in the Gippsland Basin. It is a small accumulation situated between the Mackerel and Kingfish oilfields. The oil is contained in Paleocene Latrobe Group sandstones, and sealed by the calcareous shales and siltstones of the Oligocene to Miocene Lakes Entrance Formation. Structural movement and erosion have combined to produce a low relief closure on the unconformity surface at the top of the Latrobe Group.The discovery well, Yellowtail-1, was the culmination of an exploration programme initiated during the early 1970's. The early work involved the recording and interpretation of conventional seismic data and resulted in the drilling of Opah- 1 in 1977. Opah-1 failed to intersect reservoir- quality sediments within the interpreted limits of closure although oil indications were encountered in a non-net interval immediately below the top of the Latrobe Group. In 1980 the South Mackerel 3D seismic survey was recorded. The interpretation of these 3D data in conjunction with the existing well control resulted in the drilling of Yellowtail-1 and subsequently led to the drilling of Yellowtail-2.In spite of the intensive exploration to which this small feature has been subjected, the potential for its development remains uncertain. Technical factors which affect the viability of a Yellowtail development are:The low relief of the closure makes the reservoir volume highly sensitive to depth conversion of the seismic data.The complicated velocity field makes precise depth conversion difficult.The thin oil column reduces oil recovery efficiency.The detailed pattern of erosion at the top of the Latrobe Group may be beyond the resolution capability of 3D seismic data.The 3D seismic data may not be capable of defining the distribution of the non-net intervals within the trap.The large anticlinal closures and topographic highs in the Gippsland Basin have been drilled, and the prospects that remain are generally small or high risk. Such exploration demands higher technology in the exploration stage and more wells to define the discoveries, and has no guarantee of success. The Yellowtail discovery is an illustration of one such prospect that the Esso/Hematite joint venture is evaluating.

DEMETER HIGH RESOLUTION 3D SEISMIC SURVEY—REVITALISED DEVELOPMENT AND EXPLORATION ON THE NORTH WEST SHELF, AUSTRALIA

2006 ◽  
Vol 46 (1) ◽  
pp. 101 ◽  
Author(s):  
K.J. Bennett ◽  
M.R. Bussell
Keyword(s):  
High Resolution ◽  
Seismic Data ◽  
New Technologies ◽  
Seismic Survey ◽  
Future Application ◽  
3D Seismic ◽  
Gas Field ◽  
North West ◽  
The North ◽  
Exploration And Development

The newly acquired 3,590 km2 Demeter 3D high resolution seismic survey covers most of the North West Shelf Venture (NWSV) area; a prolific hydrocarbon province with ultimate recoverable reserves of greater than 30 Tcf gas and 1.5 billion bbls of oil and natural gas liquids. The exploration and development of this area has evolved in parallel with the advent of new technologies, maturing into the present phase of revitalised development and exploration based on the Demeter 3D.The NWSV is entering a period of growing gas market demand and infrastructure expansion, combined with a more diverse and mature supply portfolio of offshore fields. A sequence of satellite fields will require optimised development over the next 5–10 years, with a large number of wells to be drilled.The NWSV area is acknowledged to be a complex seismic environment that, until recently, was imaged by a patchwork of eight vintage (1981–98) 3D seismic surveys, each acquired with different parameters. With most of the clearly defined structural highs drilled, exploration success in recent years has been modest. This is due primarily to severe seismic multiple contamination masking the more subtle and deeper exploration prospects. The poor quality and low resolution of vintage seismic data has also impeded reservoir characterisation and sub-surface modelling. These sub-surface uncertainties, together with the large planned expenditure associated with forthcoming development, justified the need for the Demeter leading edge 3D seismic acquisition and processing techniques to underpin field development planning and reserves evaluations.The objective of the Demeter 3D survey was to re-image the NWSV area with a single acquisition and processing sequence to reduce multiple contamination and improve imaging of intra-reservoir architecture. Single source (133 nominal fold), shallow solid streamer acquisition combined with five stages of demultiple and detailed velocity analysis are considered key components of Demeter.The final Demeter volumes were delivered early 2005 and already some benefits of the higher resolution data have been realised, exemplified in the following:Successful drilling of development wells on the Wanaea, Lambert and Hermes oil fields and identification of further opportunities on Wanaea-Cossack and Lambert- Hermes;Dramatic improvements in seismic data quality observed at the giant Perseus gas field helping define seven development well locations;Considerably improved definition of fluvial channel architecture in the south of the Goodwyn gas field allowing for improved well placement and understanding of reservoir distribution;Identification of new exploration prospects and reevaluation of the existing prospect portfolio. Although the Demeter data set has given significant bandwidth needed for this revitalised phase of exploration and development, there remain areas that still suffer from poor seismic imaging, providing challenges for the future application of new technologies.

A NEW TECTONO-STRATIGRAPHIC SYNTHESIS OF THE NORTH WEST CAPE AREA

1991 ◽  
Vol 31 (1) ◽  
pp. 154 ◽  
Author(s):  
R.J. Malcolm ◽  
M.C. Pott ◽  
E. Delfos
Keyword(s):  
Seismic Data ◽  
Joint Venture ◽  
Lateral Displacement ◽  
Landsat Imagery ◽  
Block Rotation ◽  
Surface Mapping ◽  
North West ◽  
The North ◽  
Oil Flow ◽  
Transfer Faults

The North West Cape area in the Exmouth Sub-basin was the site of the first onshore oil flow in Australia at Rough Range-1 in 1953. Subsequently, exploration focused on two large surface anticlines, Cape Range and Rough Range. By 1984, 30 unsuccessful wells had made it clear that the subsurface was far more complex than indicated by the surface mapping and limited seismic data. A detailed reappraisal of the subsurface structure and stratigraphy was needed.A joint venture group operated by Ampol Exploration began a new phase of exploration by recording over 1200 km of seismic data, both regional and detailed, between 1985 and 1989. An integrated interpretation of seismic data, well information and Landsat imagery has improved the understanding of structural and stratigraphic complexities and has given direction to the current exploration effort.Five of the most significant tectonic episodes to affect the North West Cape area have been recognised. They are Late Carboniferous and Early Jurassic (Sinemurian) rifting phases, Callovian-Oxfordian and Berriasian-Valanginian syn-rift pulses related to break-up and, finally, structural inversion in the Late Miocene. Each of these episodes is associated with characteristic structural styles and stratigraphic sequences.Significant lateral displacement along transfer faults during Sinemurian rifting and again during the Berriasian- Valanginian syn-rift pulse has resulted in the formation of tear faults that swing westward and merge with the plane of the transfer faults. Fault-block rotation and uplift associated with these tear faults provide potential structural and stratigraphic traps. The influence that transfer faults have on the hydrocarbon prospectivity of the North West Cape area has been recognised, including their role in the distribution of reservoir and source rocks.These tectono-stratigraphic concepts have provided a sound framework for future exploration in the North West Cape area, and may have implications for hydrocarbon prospectivity in other parts of the North West Shelf and on passive margins elsewhere.

THE EXPLORATION AND APPRAISAL HISTORY OF THE SKUA FIELD, AC /P2 - TIMOR SEA.

1990 ◽  
Vol 30 (1) ◽  
pp. 197
Author(s):  
M. Osborne
Keyword(s):  
Data Quality ◽  
Seismic Data ◽  
Joint Venture ◽  
Complex Field ◽  
Quality Improvements ◽  
Associated Gas ◽  
Seismic Acquisition ◽  
History Of ◽  
Timor Sea ◽  
Field Geology

The discovery of the Skua Field resulted from an extended and aggressive exploration program with major emphasis placed on gaining continual improvements in seismic data quality. Improved seismic data was principally responsible for the accurate delineation of the Swift and Skua structures which resulted in the drilling of the Skua-2 discovery well in 1985.A positive analysis of the results of Skua-2 (which clipped the fault bounded edge of the field) coupled with extensive new seismic acquisition and further seismic data quality improvements encouraged the AC/P2 Joint Venture to drill the field confirmation well Skua-3, in 1987.The appraisal stage of the Skua field included three further wells and was designed to investigate several specific problem areas: the modest structural size, the volume of a small associated gas cap, the presence of steeply dipping reservoir strata of interbedded sands and shales, and the effect of discrete zones of intense velocity anomaly.A major consideration has been to achieve a balance between exploration expenditure and the need to attain a thorough understanding of the complex field geology to reduce the uncertainties associated with the problem areas.The only potentially viable development option for Skua is to use subsea completions and a floating production facility (FPF). BHP Petroleum's engineering expertise and history of FPF developments at Jabiru and Challis is of great importance to successfully developing this smaller, more complex field.

Seismic, gravity and magnetics, a complementary geophysical study of the Paqualin Structure, Timor Sea, Australia

1989 ◽  
Vol 20 (2) ◽  
pp. 25 ◽  
Author(s):  
P.M. Smith ◽  
M. Whitehead
Keyword(s):  
Seismic Data ◽  
Gravity Data ◽  
Seismic Survey ◽  
Magnetic Data ◽  
Data Sets ◽  
Intrusive Body ◽  
Geophysical Study ◽  
Timor Sea ◽  
Susceptibility Contrast ◽  
Gravity And Magnetic Data

The presence of a large anomalous structure in the northern part of Permit AC/P2 in the Timor Sea has been recognised ever since seismic data were first acquired in the area. Historically, however, sparse seismic coverage has always prevented a detailed and unambiguous interpretation of the complicated structure. In order to overcome this problem, some 2000 km of 3D seismic data were acquired over the feature. In conjunction with this seismic survey, detailed gravity and magnetic data sets were also recorded over the structure.Interpretation of the new seismic data indicated the presence of a piercement structure which is associated with a small negative Bouguer gravity anomaly and a magnetic intensity anomaly resulting from a positive susceptibility contrast. Modelling of the magnetic data indicated that an acidic or intermediate intrusive body was the most likely cause of the piercement structure. The presence of an acidic intrusive body was consistent with the gravity data which indicated that no large density contrast existed between the material of the piercement structure and the surrounding sediments.The combined interpretation of these three data sets was tested by a well, Paqualin-1, drilled on the flank of the piercement structure. The well encountered a thick evaporite sequence with associated thin bands of magnetitie and intermediate igneous rocks. It was logged with a three component downhole magnetic probe and forward magentic modelling work incorporating the results of the magnetic log gave good agreement with the observed aeromagnetic profiles.

Mid-crustal detachment beneath southern Timor-Leste: seismic evidence for Australian basement in the Timor collision complex (and implications for prospectivity)

2021 ◽  
Author(s):  
T. R. Charlton
Keyword(s):  
Seismic Data ◽  
Passive Margin ◽  
Petroleum Exploration ◽  
Seismic Survey ◽  
Normal Faults ◽  
Thrust Belt ◽  
Collision Complex ◽  
Fold And Thrust Belt ◽  
Timor Leste ◽  
Seismic Sections

Seismic data originally acquired over SW Timor-Leste in 1994 shows two consistent seismic reflectors mappable across the study area. The shallower ‘red’ reflector (0.4-1s twt) deepens southward, although with a block-faulted morphology. The normal faults cutting the red marker tend to merge downward into the deeper ‘blue’ marker horizon (0.5-2.8s twt), which also deepens southward. Drilling intersections in the Matai petroleum exploration wells demonstrate that the red marker horizon corresponds to the top of metamorphic basement (Lolotoi Complex), while the blue marker horizon has the geometry of a mid-crustal extensional detachment. We see no indications for thrusting on the seismic sections below the red marker horizon, consistent with studies of the Lolotoi Complex at outcrop. However, surficial geology over much of the seismic survey area comprises a thin-skinned fold and thrust belt, established in 8 wells to overlie the Lolotoi Complex. We interpret the fold and thrust belt as the primary expression of Neogene arc-continent collisional orogeny, while the Lolotoi Complex represents Australian continental basement underthrust beneath the collision complex. In the seismic data the basal décollement to the thrust belt dips southward beneath the synorogenic Suai Basin on the south coast of Timor, and presumably continues southward beneath the offshore fold and thrust belt, linking into the northward-dipping décollement that emerges at the Timor Trough deformation front. The same seismic dataset has been interpreted by Bucknill et al. (2019) in terms of emplacement of an Asian allochthon on top of an imbricated Australian passive margin succession. These authors further interpreted a subthrust anticlinal exploration prospect beneath the allochthon, which Timor Resources plan to drill in 2021. This well (Lafaek) will have enormous significance not only commercially, but potentially also in resolving the long-standing allochthon controversy in Timor: i.e., does the Lolotoi Complex represent ‘Australian’ or ‘Asian’ basement?

Seismic stratigraphy of the East-Siberian and Chukchi seas as a key to the Amerasia Basin stratigraphy end evolution

2020 ◽  
Author(s):  
Kseniia Startseva ◽  
Anatoly Nikishin
Keyword(s):  
Foreland Basin ◽  
Sedimentary Basins ◽  
Geological Structure ◽  
Seismic Survey ◽  
Normal Faults ◽  
Seismic Profiles ◽  
The North ◽  
Sea Bottom ◽  
Reported Study ◽  
Bottom Sampling

<p>Based on new seismic survey, offshore drilling and geological structure of the adjacent onshore a new model of geological evolution of sedimentary basins of the East-Siberian and Chukchi seas since the Mesozoic has been constructed. The main stages of their tectonic history are highlighted: 1) forming of the foreland basin in Jurassic – Early Creatceous time; 2) synrift extension in Aptian-Albian time; 3) start of postrift subsidence in Later Cretaceous; 4) uplift and deformations at the turn of Cretaceous and Paleogene, start of forming of the thick (up to 4-6 km) clinoform complex; 5) episode of synrift extension in Middle-Later Eocene, forming of the system of multiple low-amplitude normal faults; 6) inversion deformations in Oligocene-Miocene; 7) relatively calm tectonic conditions in Neogene-Quaternary time. Boundaries of the interpreted seismic complexes corresponding to these stages has been extended to the entire Amerasia basin with regards to the ages of magnetic anomalies in the Gakkel Ridge and sea-bottom sampling on the Mendeleev Rise. Volcanic areas of the De Long Islands and the North Wrangel High has been traced on the seismic profiles toward Mendeleev Rise and Podvodnikov Basin and dated as ±125 Ma. According to the seismic interpretation, the age of the Podvodnikov and Toll basins is not older than Aptian. The reported study was funded by RFBR and NSFB, project number 18-05-70011, 18-05-00495 and 18-35-00133.</p>

scholarly journals Deep crustal structure of the North-West African margin from combined wide-angle and reflection seismic data (MIRROR seismic survey)

2015 ◽  
Vol 656 ◽  
pp. 154-174 ◽  
Author(s):  
Y. Biari ◽  
F. Klingelhoefer ◽  
M. Sahabi ◽  
D. Aslanian ◽  
P. Schnurle ◽  
...  
Keyword(s):  
Crustal Structure ◽  
Seismic Data ◽  
West African ◽  
Seismic Survey ◽  
Wide Angle ◽  
North West ◽  
Reflection Seismic ◽  
The North ◽  
Deep Crustal Structure

scholarly journals Geohazard detection using 3D seismic data to enhance offshore scientific drilling site selection

2020 ◽  
Vol 28 ◽  
pp. 1-27 ◽  
Author(s):  
David R. Cox ◽  
Paul C. Knutz ◽  
D. Calvin Campbell ◽  
John R. Hopper ◽  
Andrew M. W. Newton ◽  
...  
Keyword(s):  
Site Selection ◽  
Seismic Data ◽  
Seismic Survey ◽  
3D Seismic ◽  
Seismic Reflection Data ◽  
Scientific Drilling ◽  
The North ◽  
Reflection Data ◽  
3D Seismic Data ◽  
Geohazard Assessment

Abstract. A geohazard assessment workflow is presented that maximizes the use of 3D seismic reflection data to improve the safety and success of offshore scientific drilling. This workflow has been implemented for International Ocean Discovery Program (IODP) Proposal 909 that aims to core seven sites with targets between 300 and 1000 m below seabed across the north-western Greenland continental shelf. This glaciated margin is a frontier petroleum province containing potential drilling hazards that must be avoided during drilling. Modern seismic interpretation techniques are used to identify, map and spatially analyse seismic features that may represent subsurface drilling hazards, such as seabed structures, faults, fluids and challenging lithologies. These hazards are compared against the spatial distribution of stratigraphic targets to guide site selection and minimize risk. The 3D seismic geohazard assessment specifically advanced the proposal by providing a more detailed and spatially extensive understanding of hazard distribution that was used to confidently select eight new site locations, abandon four others and fine-tune sites originally selected using 2D seismic data. Had several of the more challenging areas targeted by this proposal only been covered by 2D seismic data, it is likely that they would have been abandoned, restricting access to stratigraphic targets. The results informed the targeted location of an ultra-high-resolution 2D seismic survey by minimizing acquisition in unnecessary areas, saving valuable resources. With future IODP missions targeting similarly challenging frontier environments where 3D seismic data are available, this workflow provides a template for geohazard assessments that will enhance the success of future scientific drilling.

Time-transgressive fault evolution and its impact on trap integrity: Timor Sea examples

2010 ◽  
Vol 50 (2) ◽  
pp. 701
Author(s):  
Bozkurt Ciftci ◽  
Laurent Langhi
Keyword(s):  
Late Jurassic ◽  
Normal Faults ◽  
Seal Integrity ◽  
Seal Failure ◽  
Hydrocarbon Traps ◽  
Exploration Risk ◽  
Timor Sea ◽  
Downward Propagation ◽  
Fault Growth ◽  
Fault Evolution

Top and fault seal failure represents an exploration risk in the Timor Sea where hydrocarbons are typically associated with hourglass structures. These structures comprise two distinct systems of conjugate normal faults that formed by 1st-phase (late Jurassic) and 2nd-phase (Neogene) extensions. Horst blocks bounded by 1st-phase faults potentially trap hydrocarbons and are overlain by grabens bounded by 2nd-phase faults. The two fault systems generally merge and intersect in dip direction to form the composite and time-transgressive faults of the hourglass structures. The 2nd-phase of extension is seen as the dominant cause of the seal breach. Revaluation of a series of hourglass structures on the Laminaria High confirmed two distinct sections of syn-kinematic strata. Bases of these sections correspond to maximum throws on the fault planes where the faults were probably nucleated. The presence of negative throw gradients upward and downward from the throw maximums indicate syn-kinematic deposition and fault growth, respectively. Assessment of these trends suggests that the 1st and 2nd-phase faults were detached at the onset of the 2nd-phase of extension. Connection was predominantly established by down-dip growth of the 2nd-phase faults while the reactivation of the 1st-phase faults may have remained minor. Seismic evidence of leakage from attribute mapping is used to constrain the timing of fault linkage and to validate prediction of leaking fault planes. It was noted that downward propagation of the 2nd-phase faults towards the hydrocarbon traps stresses the top seal integrity due to fault tip deformation front and development of sub-seismic fractures.

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