THE EXPLORATION AND APPRAISAL HISTORY OF THE KATNOOK AND LADBROKE GROVE GAS FIELDS, ONSHORE OTWAY BASIN, SOUTH AUSTRALIA

1992 ◽  
Vol 32 (1) ◽  
pp. 67 ◽  
Author(s):  
K. A. Parker
Keyword(s):  
South Australia ◽  
Subsequent Development ◽  
Hydrocarbon Exploration ◽  
Gas Field ◽  
Water Contact ◽  
Field Development ◽  
Gas Accumulation ◽  
Seismic Acquisition ◽  
History Of ◽  
Gas Fields

The discoveries of the Katnook Field and, later, the Ladbroke Grove Field were significant milestones for hydrocarbon exploration in the southeast of South Australia as well as for the Otway Basin in general. The initial 1987 discovery at Katnook-1 of a relatively shallow gas accumulation in the basal part of the Eumeralla Formation was eclipsed in late 1988 at the Katnook-2 appraisal stage where deeper and more significant gas reserves were discovered in the Pretty Hill Sandstone.Technological improvement, in seismic acquisition, in particular, use of longer offset configurations and higher fold, and in filtering and correction techniques at the processing stage, are discussed in relation to improved geologic understanding. These aspects ultimately led to drilling success in both exploration and appraisal.At the deep Katnook discovery stage several significant problem areas remained unresolved. These related to uncertainties in vertical distribution of gas pay, level of a gas-water contact, and unreliable reserve estimates the result of the inability of conventional log analysis techniques to distinguish gas-bearing from water-bearing sands. Both in the evaluation of Katnook-2 and at the Katnook-3 appraisal stage, expensive cased-hole testing programs were undertaken to determine the size, extent and producibility of the gas accumulation. A key development between drilling Katnook-2 and Katnook-3 was the discovery of carbon dioxide-rich gas at Ladbroke Grove during 1989 in an adjacent structure to the south.The Katnook Field was the first commercial gas field development in the southeast, South Australian part of the Otway Basin, with gas sales commencing in March 1991, within a year of completing field appraisal. The discoveries, and subsequent development, have led to a renewed focus on the Otway Basin as a prospective hydrocarbon province.

EXPLORATION IN THE COOPER BASIN

1989 ◽  
Vol 29 (1) ◽  
pp. 366 ◽  
Author(s):  
R. Heath
Keyword(s):  
Oil And Gas ◽  
South Australia ◽  
Mature Stage ◽  
Small Contribution ◽  
Terrestrial Source ◽  
Seismic Acquisition ◽  
Proterozoic Basement ◽  
Gas Fields ◽  
Coal Measures ◽  
Cooper Basin

The Cooper Basin is located in the northeastern corner of South Australia and in the southwestern part of Queensland. The basin constitutes an intracratonic depocentre of Permo- Triassic age. The Cooper Basin succession unconformably overlies Proterozoic basement as well as sediments and metasediments of the Cambro- Ordovician age. An unconformity separates in turn the Cooper succession from the overlying Jurassic- Cretaceous Eromanga Basin sediments.The Permo- Triassic succession comprises several cycles of fluvial sandstones, fluvio- deltaic coal measures and lacustrine shales. The coal measures contain abundant humic kerogen, comprising mainly inertinite and vitrinite with a small contribution of exinite. All hydrocarbon accumulations within the Cooper Basin are believed to have originated from these terrestrial source rocks.Exploration of the basin commenced in 1959 and, after several dry holes, the first commercial discovery of gas was made at Gidgealpa in 1963. To date, some 97 gas fields and 10 oil fields, containing recoverable reserves of 5 trillion cubic feet of gas and 300 million barrels recoverable natural gas liquids and oil, have been discovered in the Cooper Basin. Production is obtained from all sand- bearing units within the Cooper stratigraphic succession.The emphasis of exploration in the Cooper Basin is largely directed towards the assessment of four- way dip closures and three- way dip closures with fault control, but several stratigraphic prospects have been drilled. Furthermore, in the development phase of some gas fields a stratigraphic component of the hydrocarbon trapping mechanism has been recognised.Improvements in seismic acquisition and processing, combined with innovative thinking by the explorers, have facilitated the development of untested structural/stratigraphic plays with large reserves potential. Exploration for the four- and three- way dip closure plays in the Cooper Basin is now at a mature stage. However, reserves objectives are expected to continue to be met, with the expectation of a continuing high success rate.Selected new plays are expected to be tested within a continuing active exploration program as exploration for oil and gas in the Cooper Basin refines the search for the subtle trap.

THE LA BELLA AND MINERVA GAS DISCOVERIES, OFFSHORE OTWAY BASIN

1995 ◽  
Vol 35 (1) ◽  
pp. 405 ◽  
Author(s):  
C.W. Luxton ◽  
S. T. Horan ◽  
D.L. Pickavance ◽  
M.S. Durham.
Keyword(s):  
Late Cretaceous ◽  
Oil And Gas ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Production Test ◽  
Water Contact ◽  
Excellent Quality ◽  
Fault Block ◽  
Well Location ◽  
Gas Fields

In the past 100 years of hydrocarbon exploration in the Otway Basin more than 170 exploration wells have been drilled. Prior to 1993, success was limited to small onshore gas fields. In early 1993, the La Bella-1 and Minerva-1 wells discovered significant volumes of gas in Late Cretaceous sandstones within permits VIC/P30 and VIC/P31 in the offshore Otway Basin. They are the largest discoveries to date in the basin and have enabled new markets to be considered for Otway Basin gas. These discoveries were the culmination of a regional evaluation of the Otway Basin by BHP Petroleum which highlighted the prospectivity of VIC/P30 and VIC/P31. Key factors in this evaluation were:geochemical studies that indicated the presence of source rocks with the potential to generate both oil and gas;the development of a new reservoir/seal model; andimproved seismic data quality through reprocessing and new acquisition.La Bella-1 tested the southern fault block of a faulted anticlinal structure in the southeast corner of VIC/P30. Gas was discovered in two Late Cretaceous sandstone intervals of the Shipwreck Group (informal BHP Petroleum nomenclature). Reservoirs are of moderate to good quality and are sealed vertically, and by cross-fault seal, by Late Cretaceous claystones of the Sherbrook Group. The gas is believed to have been sourced from coals and shales of the Early Cretaceous Eumeralla Formation and the structure appears to be filled to spill as currently mapped. RFT samples recovered dry gas with 13 moI-% CO2 and minor amounts of condensate.Minerva-1 tested the northern fault block of a faulted anticline in the northwest corner of VIC/ P31. Gas was discovered in three excellent quality reservoir horizons within the Shipwreck Group. Late Cretaceous Shipwreck Group silty claystones provide vertical and cross-fault seal. The hydrocarbon source is similar to that for the La Bella accumulation and the structure appears to be filled to spill. A production test was carried out in the lower sand unit and flowed at a rig limited rate of 28.8 MMCFGD (0.81 Mm3/D) through a one-inch choke. The gas is composed mainly of methane, with minor amounts of condensate and 1.9 mol-% C02. Minerva-2A was drilled later in 1993 as an appraisal well to test the southern fault block of the structure to prove up sufficient reserves to pursue entry into developing gas markets. It encountered a similar reservoir unit of excellent quality, with a gas-water contact common with that of the northern block of the structure.The La Bella and Minerva gas discoveries have greatly enhanced the prospectivity of the offshore portion of the Otway Basin. The extension of known hydrocarbon accumulations from the onshore Port Campbell embayment to the La Bella-1 well location, 55 km offshore, demonstrates the potential of this portion of the basin.

A Study of Hydrate Inhibition for Deepwater Gas Field Development

2019 ◽  
Author(s):  
Hualei Yi ◽  
Yun Hao ◽  
Xiaohong Zhou
Keyword(s):  
Produced Water ◽  
Water Flow Rate ◽  
Injection Rate ◽  
Gas Field ◽  
Subsea Pipeline ◽  
Field Development ◽  
Flow Simulations ◽  
The World ◽  
Gas Fields ◽  
Selection Of

Abstract For deepwater subsea tie-back gas field development, hydrate tends to be formed in deepwater subsea production system and gas pipeline due to high pressure and low temperature. Based on the gas field A development, this paper studies the selection of hydrate inhibitors and injection points, i.e. different injection points with different inhibitors. Transient and steady flow simulations are performed using the OLGA software widely used for multiphase flow pipeline study in the world. The produced water flow rate affects the hydrate inhibition in case of well opening, including cases of different times with different water temperatures. This paper presents the calculation of the maximum inhibitor injection rate in the subsea pipeline by taking the whole production years into consideration. The measures on hydrate remediation are taken by quickly relieving the subsea pipeline pressure from wellheads and the platform according to different hydrate locations. Now more and more deepwater gas fields are developed in South China Sea and around the world. The experience obtained from the gas field A development will benefit the hydrate inhibition for future deepwater gas field development.

scholarly journals Application of Hydrodynamic Potential Analysis to Investigate Possibility Reservoir Connectivity between Neighboring Gas Fields

2019 ◽  
Vol 2 (1) ◽  
Author(s):  
Tri Firmanto ◽  
Muhammad Taufiq Fathaddin ◽  
R. S. Trijana Kartoatmodjo
Keyword(s):  
Stone Formation ◽  
Material Balance ◽  
Gas Field ◽  
Water Contact ◽  
Potential Analysis ◽  
Balance Analysis ◽  
Hydrodynamic Potential ◽  
Flowing Material ◽  
Reservoir Connectivity ◽  
Gas Fields

<em>T field is a producting gas field in North Bali PSC, which currently producing 210 mmscfd from paciran sand stone formation. Paciran formation extends more than 20 km across the PSC area, which consists of 3 developed gas fields and one potential development field.  The flowing material balance analysis conducted on T field suggests possibility of reservoir connectivty between this field and its neighboring fields. Even though each field is already have a well defined Gas Water Contact, a thorough investigation was done using hyrdodynamic potential analysis to see if theres any hydrodynamic potential that allowed connectivity between these fields, and enable tilted contact occurred between these field. Using pressure data taken from each fields exploration wells the analysis can be conducted that conclude that there is an existing hydrodynamic potential between gas fields in paciran formation. A review on the tilted contact analysis concludes that the existing hydrodynamic potential is not enough to tilt the contact as per actually observed contact</em>.

ECONOMICS OF GAS FIELD DEVELOPMENTS IN THE COOPER BASIN AFTER 1999

1997 ◽  
Vol 37 (1) ◽  
pp. 600
Author(s):  
R.C.M. McDonough
Keyword(s):  
Operating Cost ◽  
South Australia ◽  
Competitive Market ◽  
Field Size ◽  
Gas Field ◽  
Field Development ◽  
The Public ◽  
Cooper Basin

In February 1999 all Cooper Basin exploration acreage in South Australia, which has been under licence since 1954, will be relinquished and therefore become available to new explorers. To assist new explorers in evaluating exploration opportunities, Mines and Energy South Australia (MESA) has developed feasibility level costs for gas field developments which are independent of existing infrastructure owned by the Cooper Basin Joint Venturers. Alternatively, new producers may be able to negotiate access to existing facilities. MESA has developed estimated tolls based on pricing principles which imitate a competitive market. Tolls in this instance should lie between the operating cost of the facility as a minimum and the deprival value cost as a maximum.The study shows that if access to existing facilities is negotiated on a deprival value cost, fields with as little as 5 BCF (141 Mm3) recoverable raw gas are economic. However, if field development is totally independent of existing facilities, the minimum economic field size exceeds 35 BCF (987 Mm3) recoverable raw gas (assuming flaring of LPG is not permitted).MESA conducted this study based on data available in the public and commercial arenas. This demonstrates that it is possible for any company to develop their own data for development and negotiation purposes.

The Saltfleetby Field, Block L 47/16, Licence PEDL 005, Onshore UK

2003 ◽  
Vol 20 (1) ◽  
pp. 911-919 ◽  
Author(s):  
T. Hodge
Keyword(s):  
Processing Plant ◽  
Gas Field ◽  
Initial Field ◽  
Seismic Line ◽  
Field Development ◽  
Gas Recovery ◽  
Basic Assumptions ◽  
Mud Logging ◽  
Gas Fields ◽  
Exploration Well

AbstractThe Saltfleetby Gas Field is located onshore in East Lincolnshire at the western extent of the Humber Basin, midway between the Southern North Sea gas fields and the established Onshore Oilfields of Welton and Scampton North. Commercial discovery was in 1996, following the re-entry of a 1986 exploration well, confirming the pre-drill belief that the earlier drilling had been mis-appraised. Basic assumptions at the time of drilling the re-entry well suggested a possible 40 BCF gas-in-place in Early Westphalian sandstones. This assessment was based on only a single 2D seismic line, an association with gravity form, and the mud logging information from the earlier exploration well.Full delineation of the field extent following 3D seismic mapping and development drilling has indicated a gas-in-place of 114 BCF. Field development consent was granted in March 1999 and production commenced in December 1999. Initial field production exceeded 50 MMSCFD from four wells and to date (end July 2001) 24 BCF of gas has been produced. Ultimate gas recovery is expected to be 73 BCF proven plus probable reserves. A fifth horizontal well has been drilled in a deeper, Namurian, zone and a sixth well confirmed hydrocarbons in a southern promontory to complete the field development. An 8 km mixed phase export pipeline of 10" diameter exists to the Theddlethorpe processing plant, where gas and condensate is separated. Sharing of Pickerill compression facilities, located at Theddlethorpe were commissioned late in 2001.

scholarly journals Modern Political and Economic Aspects of the Oil and Gas Complex in the Southeast Asia Region

2014 ◽  
pp. 54-59
Author(s):  
V. I. Salygin ◽  
S. V. Berezinskiy
Keyword(s):  
Southeast Asia ◽  
Oil And Gas ◽  
American Business ◽  
Gas Field ◽  
Field Development ◽  
Oil And Gas Fields ◽  
Oil And Gas Field ◽  
Offshore Oil And Gas ◽  
Gas Fields ◽  
Offshore Oil

AbstracUThe article reviews the problems caused by the conflict of interests between certain Southeast Asian countries and other states, China foremost, which aroused from oil and gas field development on disputable offshore sections. At the same time the positions of the region's leading transnational corporations in the field of oil and gas policy and their relationships with the countries-ASEAN (Association of South East Asian Nations) members are outlined. Separately are represented the foreign policy stands of Indonesia, Vietnam, Brunei, Philippines and Malaysia on territorial disputes over offshore oil and gas fields. These processes are pushing both European and American business to abandon the conventional schemes and accept the new conditions of their activity in Southeast Asia.

CUTTAPIRRIE 1—AN OIL DISCOVERY IN THE EARLY JURASSIC OF THE EROMANGA BASIN

1981 ◽  
Vol 21 (1) ◽  
pp. 60
Author(s):  
T. M. Barr ◽  
Bridget C. Youngs
Keyword(s):  
South Australia ◽  
Early Jurassic ◽  
Oil Field ◽  
Gas Field ◽  
Oil Accumulation ◽  
Gas Accumulation ◽  
Eromanga Basin ◽  
Cooper Basin

Cuttapirrie 1 discovered a significant oil accumulation at a depth of 8 016 ft in the Early Jurassic Hutton Sandstone of the Eromanga Basin. In addition, it discovered a small gas accumulation at 9 386 ft in the underlying Permo-Triassic Cooper Basin of South Australia. The well was 210 km from the nearest Jurassic oil field and 30 km from the nearest gas field when it was drilled.

The Halladale–Speculant fields: the first nearshore gas fields to be developed from mainland Australia

2018 ◽  
Vol 58 (1) ◽  
pp. 255
Author(s):  
Andrew Constantine ◽  
Glenn Morgan ◽  
Robin O'Leary ◽  
Simon Smith
Keyword(s):  
Cost Effective ◽  
Lattice Energy ◽  
Vertical Wells ◽  
Gas Field ◽  
Development Costs ◽  
Exploration And Production ◽  
Drilling Technology ◽  
Access Problems ◽  
Seismic Acquisition ◽  
Gas Fields

Extended-reach drilling (ERD) is becoming an increasingly common technique used to explore for hydrocarbons and develop fields in areas where simple vertical wells cannot be drilled due to access problems, stakeholder concerns, environmental issues, poor reservoir quality and/or cost. While these types of wells are generally more expensive and technically challenging to drill than vertical wells, they can be very cost-effective, and if a discovery is made, considerably quicker to monetise when future development costs are also taken into consideration, particularly in offshore environments. In 2014–2015, the conventional Exploration and Production division of Origin Energy (now Lattice Energy) drilled three onshore-to-offshore ERD wells and a geological sidetrack in the Otway Basin with horizontal offsets of 1929, 2576, 4239 and 5152 m targeting an undeveloped gas field (Halladale) and exploration prospect (Speculant) located in Victorian state waters near Port Campbell. The three wells (Halladale-2, Speculant-1 and Speculant-2) and sidetrack (Speculant-2ST1) were drilled during a single drilling campaign from the same pad to reduce mobilisation, drilling and development costs. Halladale-2 was designed to develop the Halladale Field, while Speculant-1, -2 and -2ST1 were designed to evaluate the Speculant Prospect. Both Speculant wells and the sidetrack encountered significant gas columns with Speculant-1 and Speculant-2ST1 subsequently completed as producers after being successfully flow tested. A 33 km onshore pipeline was then constructed to transport the gas from Halladale and Speculant back to the Otway Gas Plant (OGP) for processing and sale. The arrival of first gas at the OGP from the Halladale and Speculant gas fields on 26 August 2016 marked a significant milestone for Origin Energy in terms of accelerated project delivery. It also represented the end of a 15-year journey for Halladale from exploration to discovery to development. The drilling campaign also set several records in the process with: (1) Speculant being the first offshore field to be discovered from mainland Australia; (2) Halladale and Speculant being the first offshore fields to produce gas back to mainland Australia from onshore wells; (3) Halladale-2, Speculant-1 and Speculant-2 being the three longest onshore-to-offshore wells drilled to date in Australia (in horizontal departure terms); and (4) Halladale-2 being the longest well (in mMDRT terms) drilled to date in the Otway Basin. Speculant is a good example of how transition zone (TZ) seismic and ERD technology can be used successfully to explore and develop resources in areas previously considered too difficult by using more conventional seismic acquisition and drilling technology.

Decision making for modeling of oil and gas fields by using case based reasoning

2019 ◽  
Vol 5 (3) ◽  
pp. 147-163
Author(s):  
Igor N. Glukhikh ◽  
Dmitry V. Nikiforov
Keyword(s):  
Decision Making ◽  
Oil And Gas ◽  
Main Tool ◽  
Engineering Practice ◽  
Case Based Reasoning ◽  
Gas Field ◽  
Field Development ◽  
Oil And Gas Fields ◽  
Gas Fields ◽  
Case Based

This article describes a case-based reasoning (CBR) method as a decision-making tool in modeling oil and gas fields, its existing and potential application in the industry. The main direction for the application of the CBR method is the search for analogous objects for the design of oil and gas field development. The current engineering practice involves a vaguely formalized method of analogies, which does not allow defining the object as much as possible authentically the analogue that does not cause errors. The analogue object serves not only as a source of ready-made near optimal design solutions, but also as additional information about the object of development and key decisions in modeling hydrocarbon fields.<br> This paper considers the CBR method as the main tool for finding analogue objects, the main methods of extracting precedents from the database, and gives an idea of the object of development as a precedent. Proceeding from the peculiarities of presenting the object of development as a precedent and the peculiarities of applying the methods of extracting precedents, the authors have developed the concept of searching for analogue objects. In its implementation, it will allow for a different degree of information content of precedents stored in the database and will accelerate the procedure of extracting precedents from the database. The principal novelty is that the presented conceptual scheme allows using the methods of extracting precedents in the conditions of insufficient input data, which is important for the design of oil and gas fields.

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