Petroleum Systems Analysis of The Tungkal PSC Area, South Sumatra – A Means of Adding New Life to A Mature Area

Proc. Indon. Petrol. Assoc., Digital Technical Conference, 2020 ◽

10.29118/ipa20-g-399 ◽

2020 ◽

Author(s):

A. Livsey

Keyword(s):

Seismic Data ◽

Systems Analysis ◽

Generation Model ◽

Hydrocarbon Accumulation ◽

Petroleum Systems ◽

Oil Generation ◽

Exploration Risk ◽

Exploration Area ◽

Hydrocarbon Charge ◽

Surface Geology

South Sumatra is considered a mature exploration area, with over 2500MMbbls of oil and 9.5TCF of gas produced. However a recent large gas discovery in the Kali Berau Dalam-2 well in this basin, highlights that significant new reserve additions can still be made in these areas by the re-evaluation of the regional petroleum systems, both by identification of new plays or extension of plays to unexplored areas. In many mature areas the exploration and concession award history often results in successively more focused exploration programmes in smaller areas. This can lead to an increased emphasis on reservoir and trap delineation without further evaluation of the regional petroleum systems and, in particular, the hydrocarbon charge component. The Tungkal PSC area is a good example of an area that has undergone a long exploration history involving numerous operators with successive focus on block scale petroleum geology at the expense of the more regional controls on hydrocarbon prospectivity. An improved understanding of hydrocarbon accumulation in the Tungkal PSC required both using regional petroleum systems analysis and hydrocarbon charge modelling. While the Tungkal PSC operators had acquired high quality seismic data and drilled a number of wells, these were mainly focused on improving production from the existing field (Mengoepeh). More recent exploration-driven work highlighted the need for a new look at the hydrocarbon charge history but it was clear that little work had been done in the past few year to better understand exploration risk. This paper summarises the methodology employed and the results obtained, from a study, carried out in 2014-15, to better understand hydrocarbon accumulation within the current Tungkal PSC area. It has involved integration of available well and seismic data from the current and historical PSC area with published regional paleogeographic models, regional surface geology and structure maps, together with a regional oil generation model. This approach has allowed a better understanding of the genesis of the discovered hydrocarbons and identification of areas for future exploration interest.

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The Local Structure Research on the Nanpu 5th Construct

Applied Mechanics and Materials ◽

10.4028/www.scientific.net/amm.733.80 ◽

2015 ◽

Vol 733 ◽

pp. 80-83

Author(s):

Chun Qiu ◽

Ming Xue Zhang ◽

Xiao Yan Lv

Keyword(s):

Seismic Data ◽

Local Structure ◽

Oil And Gas ◽

Structural Characteristics ◽

Bohai Bay ◽

Hydrocarbon Accumulation ◽

Local Structures ◽

Huanghua Depression ◽

Exploration Area ◽

Structure Research

The Nanpu 5th construct is in the western part of Huanghua Depression Nanpu Sag of Bohai Bay Basin, was a complicated anticline belt that develops between Jian Dong fault and the downthrown side of the southwestern Zhuang fault and the favorable exploration area is 120km2. On the basis of the region's large number of multi-channel seismic data analysis and interpretation, the trap types, structural characteristics and distribution of local structures between the layers of the region are researched. Interlayer local structures in the area are mainly divided into nose structure and small anticline. The fault zone is a structural high in the region, to promote oil and gas to migrate and accumulate to the low-potential zones that become favorable zones for hydrocarbon accumulation, but the real decisive construct parts of the hydrocarbon accumulation is positive local structure in favorable zones which point out the region for hydrocarbon accumulation.

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New play type, southern Bonaparte Basin-Petrel Sub-basin—WA-442-P and NT/P81 exploration permits

The APPEA Journal ◽

10.1071/aj11041 ◽

2012 ◽

Vol 52 (1) ◽

pp. 525

Author(s):

Margaret Hildick-Pytte

Keyword(s):

Seismic Data ◽

Early Carboniferous ◽

Oil Fields ◽

Source Rocks ◽

Lower Carboniferous ◽

Petroleum Systems ◽

Seismic Data Acquisition ◽

Early Palaeozoic ◽

Hydrocarbon Charge ◽

3D Seismic Data

Recent investigation, including mapping re-processed seismic data, suggests there is deeper hydrocarbon potential in the WA-442-P and NT/P81 exploration permits beneath the Early Carboniferous Tanmurra Formation horizon. Earlier interpretation of the area showed tilted fault blocks commonly thought of as economic basement in the vicinity of the Turtle and Barnett oil fields and extending to the northwest to connect with the Berkley Platform. The deep-gas play type is structural and is believed to be two nested three-way dip anticlines developed against a large bounding fault to the northeast, with axial trends northwest to southeast, and axial plane curving towards the northeast for the deeper structure. This play type is believed to be associated with structural compression and movement along the master fault with incremental re-activation most recently during the Cainozoic as recorded in overlying sediments. The Nova Structure and the deeper Super Nova structure have closures of about 450 and 550 km2, respectively. The sediments beneath the Nova horizon are believed to be of Devonian Frasnian-Famennian age but have not been drilled offshore in the Southern Bonaparte Basin (Petrel Sub-basin). Earlier work suggests that there are two petroleum systems present in the southern Bonaparte Basin, a Larapintine source from Early Palaeozoic Devonian to Lower Carboniferous source rocks, and a transitional Larapintine/Gondwana system sourced from Lower Carboniferous to Permian source rocks. Hydrocarbon charge for the structures is most likely from the Larapintine source rock intervals or yet to be identified older intervals associated with the salt deposition during the Ordovician and Silurian. Independent estimates place close to 7 TCF (trillion cubic feet) of gas in the Nova Structure. New 3D seismic data acquisition is planned over the structures to better define the geology and ultimately delineate well locations.

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Geology and hydrocarbon prospectivity of the northern Houtman Sub-basin

The APPEA Journal ◽

10.1071/aj16027 ◽

2017 ◽

Vol 57 (2) ◽

pp. 709 ◽

Cited By ~ 3

Author(s):

Irina Borissova ◽

Chris Southby ◽

Lisa Hall ◽

Emma Grosjean ◽

George Bernardel ◽

...

Keyword(s):

Source Rock ◽

Seismic Data ◽

Systems Analysis ◽

Lower Triassic ◽

Multiple Source ◽

Hydrocarbon Potential ◽

Seismic Sequence ◽

Regional Mapping ◽

Petroleum Systems ◽

Half Graben

New 2D seismic data acquired by Geoscience Australia in the northern Houtman Sub-basin of the Perth Basin provides important information on the prospectivity of this frontier area. To date, lack of quality seismic data and limited geological understanding have led to the perception that the hydrocarbon potential of the area is very low. However, interpretation of newly collected data suggests that the northern Houtman depocentre contains up to 15 km of pre-breakup sediments comprised of Permian, Triassic and Jurassic successions, which potentially contain multiple source rock, reservoir and seal intervals. The Permian syn-rift succession is confined to a series of large half-graben that are controlled by basement-involved faults separating the Houtman depocentre from the Bernier Platform. This succession is up to 10 km thick and is mapped throughout the inboard part of the new seismic grid. A prominent unconformity at the top of the Permian syn-rift sequence is overlain by a thick (up to 1800 m) and regionally extensive seismic sequence interpreted as the Lower Triassic Kockatea Shale. The thickness of the overlying Triassic succession ranges from approximately 1 km in the inboard part of the basin to up to 5 km further outboard. The Jurassic succession is thickest (up to 4 km) in the outboard part of the basin and is interpreted to contain sequences corresponding to the Cattamarra, Cadda and Yarragadee formations. Our study integrates new results from regional mapping, geophysical modelling and petroleum systems analysis, which enables a more accurate prospectivity assessment of this frontier basin.

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THE CEDUNA SUB-BASIN—A SNAPSHOT OF PROSPECTIVITY

The APPEA Journal ◽

10.1071/aj00015 ◽

2001 ◽

Vol 41 (1) ◽

pp. 321 ◽

Cited By ~ 8

Author(s):

R. Somerville

Keyword(s):

Late Cretaceous ◽

Seismic Data ◽

Charge System ◽

The North ◽

Exploration Risk ◽

Exploration Drilling ◽

Marine Seismic ◽

Hydrocarbon Charge ◽

Great Australian Bight ◽

Water Depths

The Ceduna Sub-basin comprises one of the major untested potential petroleum provinces in Australia. It is located in the Great Australian Bight, forming part of the Bight Basin. Water depths range from 100 m in the north to over 4,000 m in the south. Although over 100,000 line km of 2D marine seismic data have been acquired in the Great Australian Bight, only 20,600 line km of 2D marine seismic data of variable vintage and quality have been acquired in the Ceduna Sub-basin. Only one exploration well, Potoroo–1, has been drilled within the Ceduna Sub-basin. The Potoroo–1 well is located on the extreme landward edge of the depocentre which is dominated by the Late Cretaceous Ceduna Delta. Consequently, the hydrocarbon potential of the basin is effectively untested.The most promising play types within the Ceduna Subbasin are dip and fault-dip closures associated with listric faults within the Late Cretaceous (Santonian- Maastrichtian) deltaic sequence and accentuated by slight Late Cretaceous/Tertiary compression. Fault-dip closures are also recognised within the Santonian section. A channel sub-crop play within the Santonian is also potentially viable.Hydrocarbon charge is perceived to be the most significant exploration risk. Although asphaltite strandings have been reported, the hydrocarbon charge system is unproven. Future exploration in the Great Australian Bight will need to address:harsh climatic/meteorological and oceanographic conditions in the Southern Ocean and short seasonal windows;extreme sea floor relief and viability of safe exploration drilling in water depths over 1,500 m; andoperating in a responsible and environmentally sensitive way in proximity to the Benthic Protection Zone.

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PETROLEUM SYSTEMS AND EXPLORATION POTENTIAL IN THE OFFICER BASIN, WESTERN AUSTRALIA

The APPEA Journal ◽

10.1071/aj02025 ◽

2003 ◽

Vol 43 (1) ◽

pp. 473 ◽

Cited By ~ 3

Author(s):

G.M. Carlsen ◽

A.P. Simeonova ◽

S.N. Apak

Keyword(s):

Western Australia ◽

Seismic Data ◽

Complex Salt ◽

Normal Faults ◽

Petroleum Systems ◽

Oil Generation ◽

Salt Structure ◽

Different Levels ◽

Different Parts ◽

Structural Zones

The Officer Basin in Western Australia contains a variety of hydrocarbon plays associated with compressional, halokinetic, unconformity and stratigraphic traps. Five distinct structural zones have been defined in the basin—a northeastern Marginal Overthrusted Zone, a northeastern Salt-ruptured Zone, a central Thrusted Zone, a Western Platform and a complex salt-dominated Minibasins Zone. These zones, together with salt-associated and sub-salt structure, are well delineated on about 2,900 km of reprocessed 1980s vintage seismic data, now publicly released.Neoproterozoic rocks are marginally to fully mature for oil generation on the Western Platform and immature to overmature for different levels of the succession in the Salt-ruptured and Thrusted zones. Geochemical modelling indicates that the main phases of oil generation vary from different stratigraphic intervals and different parts of the Neoproterozoic basin with peaks during the latest Neoproterozoic, Cambrian, and Permian–Triassic. A variety of hydrocarbon shows have been recorded in each of the structural zones. The most recent, a gas show recorded in the stratigraphic well Vines–1 indicates the presence of potentially effective petroleum systems in the unexplored Waigen area of the Marginal Overthrusted Zone.A wide variety of trap styles have been identified, associated with normal faults, thrust faults, thrust ramp folds, compressive folds, fault tip folds, sub-salt plays, unconformity truncations, pinchouts, lateral facies changes, erosive channels and valleys, fractured carbonates and halokinetic traps. Most of these trap styles are poorly tested or untested.

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Near Surface Research and Excitation Horizon Prediction Based on Old River Course of Xiaoqing River in Shan Dong

Advanced Materials Research ◽

10.4028/www.scientific.net/amr.664.94 ◽

2013 ◽

Vol 664 ◽

pp. 94-98

Author(s):

Guang De Zhang

Keyword(s):

Seismic Data ◽

Practical Significance ◽

Cone Penetration ◽

Surface Deposition ◽

Near Surface ◽

Sedimentary Characteristics ◽

The Difference ◽

Exploration Area ◽

Data Requirements ◽

Static Cone Penetration Test

Following deepened exploration and development in Shengli exploration area, seismic data requirements are also getting higher and higher. However, in recent years the difference of Xiaoqing river on both sides have made us know that the importance of this problem. In view of the above, this task is aimed at quaternary shallow of old river course within Xiaoqing River. Our analysis of lithology and sedimentary characteristics are using static cone penetration test and rock core exploration method, and we want to reappear near surface deposition of old river course within Xiaoqing River. The research is close combined with the exploration demand and theoretical study, so it has important theoretical and practical significance.

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Acquire Ocean Bottom Seismic Data and Time-Lapse Geochemistry Data Simultaneously to Identify Compartmentalization and Map Hydrocarbon Movement

10.4043/30975-ms ◽

2021 ◽

Author(s):

Rick Schrynemeeckers

Keyword(s):

High Resolution ◽

Seismic Data ◽

Time Lapse ◽

Field Trials ◽

Detection Methods ◽

Ocean Bottom ◽

Field Development ◽

Dense Grid ◽

Hydrocarbon Charge ◽

Sweet Spots

Abstract Current offshore hydrocarbon detection methods employ vessels to collect cores along transects over structures defined by seismic imaging which are then analyzed by standard geochemical methods. Due to the cost of core collection, the sample density over these structures is often insufficient to map hydrocarbon accumulation boundaries. Traditional offshore geochemical methods cannot define reservoir sweet spots (i.e. areas of enhanced porosity, pressure, or net pay thickness) or measure light oil or gas condensate in the C7 – C15 carbon range. Thus, conventional geochemical methods are limited in their ability to help optimize offshore field development production. The capability to attach ultrasensitive geochemical modules to Ocean Bottom Seismic (OBS) nodes provides a new capability to the industry which allows these modules to be deployed in very dense grid patterns that provide extensive coverage both on structure and off structure. Thus, both high resolution seismic data and high-resolution hydrocarbon data can be captured simultaneously. Field trials were performed in offshore Ghana. The trial was not intended to duplicate normal field operations, but rather provide a pilot study to assess the viability of passive hydrocarbon modules to function properly in real world conditions in deep waters at elevated pressures. Water depth for the pilot survey ranged from 1500 – 1700 meters. Positive thermogenic signatures were detected in the Gabon samples. A baseline (i.e. non-thermogenic) signature was also detected. The results indicated the positive signatures were thermogenic and could easily be differentiated from baseline or non-thermogenic signatures. The ability to deploy geochemical modules with OBS nodes for reoccurring surveys in repetitive locations provides the ability to map the movement of hydrocarbons over time as well as discern depletion affects (i.e. time lapse geochemistry). The combined technologies will also be able to: Identify compartmentalization, maximize production and profitability by mapping reservoir sweet spots (i.e. areas of higher porosity, pressure, & hydrocarbon richness), rank prospects, reduce risk by identifying poor prospectivity areas, accurately map hydrocarbon charge in pre-salt sequences, augment seismic data in highly thrusted and faulted areas.

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Using AI/ML to Explore & Develop Quickly and Efficiently

10.2118/207377-ms ◽

2021 ◽

Author(s):

Anthony Aming

Keyword(s):

Artificial Intelligence ◽

Machine Learning ◽

Seismic Data ◽

3D Seismic ◽

Structure Amplitude ◽

Zero Crossing ◽

Petroleum Systems ◽

Exploration And Production ◽

Data Volume ◽

3D Seismic Data

Abstract See how application of a fully trained Artificial Intelligence (AI) / Machine Learning (ML) technology applied to 3D seismic data volumes delivers an unbiased data driven assessment of entire volumes or corporate seismic data libraries quickly. Whether the analysis is undertaken using onsite hardware or a cloud based mega cluster, this automated approach provides unparalleled insights for the interpretation and prospectivity analysis of any dataset. The Artificial Intelligence (AI) / Machine Learning (ML) technology uses unsupervised genetics algorithms to create families of waveforms, called GeoPopulations, that are used to derive Amplitude, Structure (time or depth depending on the input 3D seismic volume) and the new seismic Fitness attribute. We will show how Fitness is used to interpret paleo geomorphology and facies maps for every peak, trough and zero crossing of the 3D seismic volume. Using the Structure, Amplitude and Fitness attribute maps created for every peak, trough and zero crossing the Exploration and Production (E&P) team can evaluate and mitigate Geological and Geophysical (G&G) risks and uncertainty associated with their petroleum systems quickly using the entire 3D seismic data volume.

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