The West Erregulla gas discovery. Implications for an extensive Permian play fairway across the onshore northern Perth Basin, Western Australia

2021 ◽  
Vol 61 (2) ◽  
pp. 594
Author(s):  
A. Cortis ◽  
A. Farley ◽  
D. Lewis ◽  
S. Cheong ◽  
A. Chia ◽  
...  
Keyword(s):  
Column Height ◽  
The West ◽  
Gas Field ◽  
Water Contact ◽  
Seismic Amplitude ◽  
Axial Part ◽  
Wireline Logs ◽  
Large Gas Field ◽  
Deep Fields ◽  
New Discovery

The West Erregulla field is a significant new discovery in the northern Perth Basin that expands the play fairways for the basal Triassic/late Permian sandstones of the Dongara/Wagina formations and early Permian sandstones of the Kingia/High Cliff formations. The 2019 discovery well, West Erregulla-2, targeted three stacked seismic amplitude anomalies interpreted to be gas-charged conventional sandstones at depths between 4100m and 5000m. Gas charge is confirmed in all three units. Gas is hosted in linked, reactivated Permian-aged fault blocks located in the axial part of the Dandaragan Trough. They represent a down-dip analogue to the Waitsia gas field NW of West Erregulla. Only the Kingia sandstone was tested in West Erregulla-2. It contains good to excellent quality reservoir with >55m of pay averaging 12.6% porosity and gas saturations of 65%. Despite deep burial, porosity of the reservoirs was retained by a combination of syndepositional clay coatings and early burial gas charge. Testing of this zone achieved a maximum sustained flow rate of 69mmcf/day. Wireline logs and seismic mapping suggest the presence of a large gas field with gross gas column height of >200m over an area of ~40km2. Scoping volumetric estimates using a range of possible gas water contact (GWC) suggest a P50 in-place original gas in place (OGIP) of ~1182 Bcf for the Kingia formation (informal name). The West Erregulla, Waitsia and Beharra springs deep fields contain significant gas resources. Their spatial distribution suggests the existence of a deep, regional Permian fairway that could cover a large portion of the Perth Basin.

Latest Permian (Changhsingian) to Early Triassic (Induan-Olenekian) of the Mt Goodwin Sub-group at Blacktip gas field, southeastern Bonaparte Basin, Australia

2010 ◽  
Vol 50 (1) ◽  
pp. 203 ◽  
Author(s):  
John Gorter ◽  
Robert Nicoll ◽  
Andrea Caudullo ◽  
Robyn Purcell ◽  
Kon Kostas
Keyword(s):  
Depositional Environment ◽  
Early Triassic ◽  
Northern Australia ◽  
Seismic Profiles ◽  
Gas Field ◽  
Seismic Amplitude ◽  
Amplitude Anomaly ◽  
Wireline Logs ◽  
Geochemical Analyses ◽  
Integrated Study

Gas was discovered in intra-Mt Goodwin Sub-group sandstones (Ascalon Formation) of the southeastern Bonaparte Basin in Blacktip–1 in 2001 from a zone characterised by a discrete seismic amplitude anomaly. This integrated study uses wireline logs, cores, cuttings, palynology, micropaleontology and geochemical analyses to determine the depositional environment of the Mt Goodwin Sub-group reservoirs and the source rock potential of this large, latest Permian (Changhsingian) to Early Triassic (Induan Olenekian) section of the Bonaparte Basin in northern Australia. Specific outcomes include a better understanding of the Early Triassic reservoir sandstone depositional environment and recognition of marker horizons on electric logs and seismic profiles, resulting in a more consistent regional interpretive framework for the uppermost Permian (Changhsingian) and Early Triassic (Induan Olenekian), in the Bonaparte Basin.

Success story of integrated subsurface study to deliver a successful infill drilling: Buntal-5 case study

2021 ◽  
Author(s):  
B. Khoironi
Keyword(s):  
History Matching ◽  
Gas Field ◽  
Water Contact ◽  
Seismic Amplitude ◽  
Water Breakthrough ◽  
Geological Features ◽  
Open Hole ◽  
Geophysical Study ◽  
Infill Drilling ◽  
Geological Concept

Buntal is a mature gas field located in South Natuna Sea Block B PSC. The field was discovered by well Buntal-1 and delineated by appraisal well Buntal-2. The field consists of multi-stacked sandstone reservoirs, which were deposited under fluvial deltaic environment. The major Buntal reservoirs have been produced since 2004 from two subsea wells. Buntal-3 was producing from zones Beta-1 and Beta-2, while Buntal-4 was a horizontal well producing from Zone-1C. Both of those wells had loaded up prior to Buntal-5 drilling. This paper describes the details of a multidisciplinary approach taken for the proposal of Buntal-5 infill drilling. An integrated geological and geophysical study were carried out to quantify resources and uncertainties of the remaining thin unproduced zones. In total, there are 8 virgin zones as Buntal-5 initial target namely Beta-0, Zone-1A, Zone-1B, Zone-1D, Zone-1E, Zone-2B, Zone-3 and Zone-3A. Max-trough seismic amplitude was utilized to identify geological features across for each Buntal reservoir. The result was then combined with geological concept based on its depositional environment to justify a reasonably higher hydrocarbon volume which can not be estimated only by wells’ data. A reservoir simulation study was also carried out to not only to evaluate production potential from the virgin zones but also to capture upside potential from the produced zones. Simulation history matching result on Zone-1C revealed early water breakthrough experienced by Buntal-4 well due to water cresting phenomena which left significant gas reserves. This result added upside potential to Buntal-5 which initially only targeted marginal remaining unproduced zones. The well was drilled at the end of 2019 and proven to be a major success. Buntal-5 open hole logs data indicate thicker and better virgin zones reservoir quality as expected by integrated geological and geophysical study. Furthermore, significant remaining gas was encountered in Zone-1C with actual gas water contact was within the simulation result proving the water cresting theory, the zone itself add well’s gas-in-place by 30% on top of the unproduced zones’ gas-in-place.

The method for modeling the development of a gas field on the basis of a hierarchy of mathematical models

2019 ◽  
Vol 5 (3) ◽  
pp. 69-82
Author(s):  
Vitaly P. Kosyakov ◽  
Amir A. Gubaidullin ◽  
Dmitry Yu. Legostaev
Keyword(s):  
Mathematical Models ◽  
Energy State ◽  
Reservoir Pressure ◽  
Gas Field ◽  
Water Contact ◽  
Simple Models

This article presents an approach aimed at the sequential application of mathematical models of different complexity (simple to complex) for modeling the development of a gas field. The proposed methodology allows the use of simple models as regularizers for the more complex ones. The main purpose of the applied mathematical models is to describe the energy state of the reservoir — reservoir pressure. In this paper, we propose an algorithm for adapting the model, which allows constructing reservoir pressure maps for the gas field, as well as estimating the dynamics of reservoir pressure with a possible output for determining the position of the gas-water contact level.

Some applications of clay mineralogy to reservoir description

Clay Minerals ◽  
1986 ◽  
Vol 21 (4) ◽  
pp. 811-826 ◽  
Author(s):  
A. Hurst ◽  
J. S. Archer
Keyword(s):  
Clay Mineralogy ◽  
Sand Production ◽  
Water Contact ◽  
Reservoir Evaluation ◽  
Sandstone Diagenesis ◽  
Porosity And Permeability ◽  
Neutron Porosity ◽  
Wireline Logs ◽  
Formation Resistivity ◽  
Reservoir Description

AbstractStudy of sandstone diagenesis provides information about the origin, texture, distribution and composition of clay minerals, which in turn is used in reservoir description. Three examples of the use of clay mineralogy in reservoir description are given. (1) Kaolinite commonly forms pore-filling cements which are pervasive in specific sandstone intervals. It is shown that water-zone kaolinization homogenizes and lowers the porosity and permeability relative to the oil zone; in a reservoir model different Ø/Krelationships are defined above and below the oil-water contact. (2) An occurrence of chlorite in dish-structured horizons is shown to increase horizontal permeability and decrease formation resistivity. The sensitivity of the neutron porosity log to the chlorite cement reduces the usefulness of the log for porosity evaluation. Uncritical application of wireline logs to define reservoir parameters can give pessimistic reservoir evaluation. (3) Sand production can be related to wettability, which in turn is strongly influenced by clay mineralogy. A perforation strategy to minimize sand production may then be based on knowledge of the clay mineralogy of a reservoir.

USE OF HEAVY MINERAL SUITES IN RESERVOIR SAND STUDIES IN THE HARRIET FIELD, BARROW SUB-BASIN, WESTERN AUSTRALIA

1992 ◽  
Vol 32 (1) ◽  
pp. 359
Author(s):  
John Scott ◽  
Pete Di Bona ◽  
Vincent Beales
Keyword(s):  
Heavy Mineral ◽  
Time Interval ◽  
Reflection Seismology ◽  
Submarine Fan ◽  
Water Contact ◽  
Wireline Logs ◽  
Total Composition ◽  
Oil Water ◽  
Heavy Mineral Analysis ◽  
Diagenetic History

Analysis of the heavy mineral suites in the reservoir at Harriet Field has significantly improved reservoir unit definition and correlation and provided information on facies changes and diagenetic history. It has provided further evidence for a stratigraphic barrier as a cause of the variation of the oil-water contact in the field.The reservoir consists of a number of discrete sandstone bodies which are arranged in a multistorey manner.The reservoir is further subdivided into compartments by minor faulting. Prior to the use of heavy mineral analysis, correlation between wells was often unclear. Such correlation is beyond the resolution of reflection seismology and the massive nature of the sandstones means that definition and correlation is uncertain when made on the basis of lithology combined with wireline logs. The time interval involved in the deposition of the reservoir sequence is too short to permit discrimination by palaeontological analysis.Eight distinct sandstone bodies can be defined on the basis of analysis of the heavy mineral suites in the 14 wells of the field. The total composition of the suites, certain 'marker minerals' and various statistical indices have been used to define these sandstone units which are interpreted to be individual lobes within a submarine fan complex. The methods and results are illustrated with examples from the field. The results of the analysis show that heavy mineral populations can provide critical information for accurate reservoir mapping and analysis.

The Babbage Field, Block 48/2a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 97-108 ◽  
Author(s):  
R. M. Phipps ◽  
C. J. Tiltman
Keyword(s):  
Seismic Imaging ◽  
Complex Salt ◽  
Reverse Time ◽  
Gas Field ◽  
Water Contact ◽  
Depth Migration ◽  
Reservoir Permeability ◽  
Northern Edge ◽  
Sandstone Formation ◽  
Volume Range

AbstractThe Babbage gas field was discovered in 1988 by exploration well 48/2-2 which drilled into the Permian-age lower Leman Sandstone Formation below a salt wall. Seismic imaging is compromised by the presence of this salt wall, which runs east–west across the southern part of the structure, creating uncertainties in depth conversion and in the in-place volumes. Pre-stack depth migration with beam and reverse time migrations appropriate for the complex salt geometry provided an uplift in subsalt seismic imaging, enabling the development of the field, which is located at the northern edge of the main reservoir fairway in a mixed aeolian–fluvial setting. Advances in artificial fracturing technology were also critical to the development: in this area, deep burial is associated with the presence of pore-occluding clays, which reduce the reservoir permeability to sub-millidarcy levels. The Babbage Field was sanctioned in 2008, based on an in-place volume range of 248–582 bcf; first production was in 2010. It produces from five horizontal development wells that were artificially fracced to improve deliverability of gas from the tight matrix. None of the wells has drilled the gas–water contact, which remains a key uncertainty to the in-place volumes, along with depth-conversion uncertainty below the salt wall.

The Elswick Field, Bowland Basin, UK Onshore

2020 ◽  
Vol 52 (1) ◽  
pp. 62-73 ◽  
Author(s):  
Mathew Hampson ◽  
Heather Martin ◽  
Lucy Craddock ◽  
Thomas Wood ◽  
Ellie Rylands
Keyword(s):  
Electricity Generation ◽  
Alluvial Fan ◽  
Reservoir Quality ◽  
Gas Field ◽  
Water Contact ◽  
Depositional Processes ◽  
Well Field ◽  
Domal Structure ◽  
Single Well ◽  
Sandstone Formation

AbstractThe Elswick Field is located within Exploration Licence EXL 269a (Cuadrilla Resources Ltd is the operator) on the Fylde peninsula, West Lancashire, UK. It is the first producing onshore gas field to be developed by hydraulic fracture stimulation in the region. Production from the single well field started in 1996 and has produced over 0.5 bcf for onsite electricity generation. Geologically, the field lies within a Tertiary domal structure within the Elswick Graben, Bowland Basin. The reservoir is the Permian Collyhurst Sandstone Formation: tight, low-porosity fluvial desert sandstones, alluvial fan conglomerates and argillaceous sandstones. The reservoir quality is primarily controlled by depositional processes further reduced by diagenesis. Depth to the reservoir is 3331 ft TVDSS with the gas–water contact at 3400 ft TVDSS and with a net pay thickness of 38 ft.

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