Discovery to development: a subsurface case history of the Kitan Oil Field, Timor Sea, Joint Petroleum Development Area, Timor-Leste and Australia

2013 ◽  
Vol 53 (2) ◽  
pp. 439
Author(s):  
Dave Wheller ◽  
Grant Ellis ◽  
Yohan Suhardiman ◽  
Ryosuke Yokote ◽  
Doani Selvaggi ◽  
...  
Keyword(s):  
Joint Venture ◽  
Oil Field ◽  
Oil Accumulation ◽  
Field Development ◽  
Timor Leste ◽  
History Of ◽  
Timor Sea ◽  
Development Area ◽  
Petroleum Development ◽  
East West

The Kitan oil field is located in the northern Bonaparte Basin in the Joint Petroleum Development Area, an area jointly administered by Timor-Leste and Australia. The Kitan structure is a Jurassic east-west trending tilted fault block. The Kitan–1 exploration well was drilled and successfully tested in early 2008. Kitan–2 appraisal well was drilled immediately after Kitan–1 and intersected the reservoir up-dip from Kitan–1 and confirmed the extension of the oil accumulation. The main oil-bearing section is in the shallow marine sandstone of the Middle Jurassic Laminaria Formation. It is divided into two reservoir zones: a blocky channelised sandstone (Unit–2) overlain by a dominantly finer-grained succession composed of coarsening-upwards para-sequences (Unit–1). Kitan oil field was declared a commercial discovery in April 2008 and a field development plan was submitted in May 2009 and approved in April 2010. Four development wells were drilled of which three were completed as producers, each employing an intelligent completion design to enable independent control and monitoring of the two reservoirunits. The three wells were tied back subsea via flexible flowlines and risers to the Glas Dowr FPSO. Oil production from the Kitan started in October 2011, about 3.5 years after the discovery of the field. The fast-track development of Kitan was achieved due to accelerated appraisal, prompt completion of studies, early commitment to long lead items, and excellent support from joint-venture partners and government.

LAM IN ARIA—A NEW TIMOR SEA DISCOVERY

1996 ◽  
Vol 36 (1) ◽  
pp. 12 ◽  
Author(s):  
G.C Smith ◽  
L. A Tilbury ◽  
A. Chatfield ◽  
P. Senycia ◽  
N. Thompson.
Keyword(s):  
Joint Venture ◽  
Maximum Flow ◽  
Seismic Survey ◽  
Production Test ◽  
Oil Accumulation ◽  
Seismic Surveys ◽  
International Boundary ◽  
Timor Sea ◽  
Seismic Lines ◽  
East West

The Laminaria-1 discovery in the southeast of AC/P8 is a major new Timor Sea oil accumulation. The discovery well, drilled in October 1994, encountered a gross oil column of 102 m in deltaic to jiearshore marine sediments of the Callovian-Oxfordian Laminaria Formation. On production test, a maximum flow rate of 7,507 BOPD was recorded through a 5/8 in. choke. The oil is a light (59° API), undersaturated oil with a GOR of 175 SCF/STB. Laminaria-1 was the first well drilled by the AC/P8 Joint Venture since resumption of exploration following resolution of the international boundary between Australia and Indonesia.The Laminaria Prospect, originally identified prior to the boundary dispute, was detailed by seismic surveys in 1992 and 1993. The prospect was selected as the best of several structural targets, comprising a large complex horst block produced by major east-west faults, discernible on the 2D seismic lines at Aptian (KA) level. The prospect was expected to have Upper to Middle Jurassic Flamingo and Plover sandstone reservoirs, sealed by the Flamingo Group Shales,with hydrocarbons sourced from the same shales in adjacent synclines.Since the discovery, a comprehensive appraisal campaign has been undertaken to delineate the accumulation, including the acquisition of a large 3D seismic survey over almost the entire AC/P8 permit, and the drilling of a further two wells and a sidetrack. The Laminaria horst is now interpreted to comprise a series of tilted fault-blocks, orientated ENE to WSW and dipping to the southeast.

EVOLUTION OF TIMOR SEA TREATY AND IMPACTS ON CONTRACTORS

2003 ◽  
Vol 43 (2) ◽  
pp. 127
Author(s):  
S.J. Barrymore
Keyword(s):  
Field Work ◽  
East Timor ◽  
Exact Form ◽  
Production Sharing ◽  
The Status ◽  
History Of ◽  
Timor Sea ◽  
Development Area ◽  
Petroleum Development ◽  
Further Development

Since the de-annexation of East Timor from Indonesia, the status of the production sharing contracts issued under the Timor Gap Treaty between Australia and Indonesia has been uncertain. The Zone of Co-operation has been administered pursuant to interim arrangements agreed between Australia and UNTAET, the United Nations authority responsible for the administration of East Timor. With the exception of the development activities being carried on in connection with the Bayu-Undan Field, work by the contractors under their PSC’s has basically halted. The contractors have in effect been in a state of force majeure.On 20 May 2002, Australia and East Timor signed a Treaty for the further development of the region, now known as the joint petroleum development Area. A number of significant changes have been made. At the time of preparing this abstract the Treaty has not been ratified and the exact form of the production sharing contracts to be offered to the existing contractors is not known. The arrangements under the Timor Sea Treaty are interim only and can be changed upon permanent delimitation of the seabed boundaries. Australia and East Timor have indicated that they intend to proceed to negotiate those boundaries.This paper will analyse the history of the negotiations and their outcome, the international unitisation agreement, the positions of the existing holders of production sharing contracts and how their rights are to be transitioned through to the new regime. The paper will report on the new issues and risks that arise for contractors who have existing titles and those who are seeking to invest in the JPDA and on any changes to commercial terms.

Diagenetic history of the proterozoic carbonates and its role in the oil field development in the Baikit Anteclise, Southwestern Siberia

2020 ◽  
Vol 342 ◽  
pp. 105690
Author(s):  
Kseniia Y. Vasileva ◽  
Victoria B. Ershova ◽  
Andrey K. Khudoley ◽  
Rustam R. Khusnitdinov ◽  
Anton B. Kuznetsov ◽  
...  
Keyword(s):  
Oil Field ◽  
Field Development ◽  
Oil Field Development ◽  
History Of ◽  
Southwestern Siberia ◽  
Diagenetic History

The Hermes oil field: a small field takes wings

2009 ◽  
Vol 49 (1) ◽  
pp. 221 ◽  
Author(s):  
Greg C Smith ◽  
Jai Louis ◽  
Roy White ◽  
Ritu Gupta ◽  
Roger Collinson
Keyword(s):  
Scenario Analysis ◽  
Flow Line ◽  
Field Potential ◽  
Statistical Design ◽  
High Water ◽  
Oil Field ◽  
Oil Accumulation ◽  
Field Development ◽  
Uncertain Variables ◽  
Water Cut

The Lambert field was discovered in 1973 with oil reservoired in Tithonian turbidites. It was viewed as uneconomic until 1996 when re-evaluation led to discovery of the adjacent Hermes oil accumulation by Lambert–2. The Lambert–3 producer was drilled nearby to Lambert–2 in 1997 and tied back to the Cossack-Pioneer floating production storage offloader (FPSO). Lambert–3 was expected to drain about 25 MMBBLs of oil, coming off plateau after one year and declining substantially thereafter; however, it had produced more than 52 MMBBLs of oil by late 2008 without any water cut and may produce much more in the next 15–20 years. In contrast, several appraisal and production wells drilled since in the adjacent Lambert accumulation have only produced modest recoveries. Why were the original deterministic views of the Lambert-Hermes field so far from present estimates? This paper describes the approach taken to re-assess the Lambert and Hermes oil accumulations. First, the traps were reviewed by framing the main uncertain variables followed by a rigorous scenario analysis of the field. The work was expedited by using a statistical design to substantially reduce the number of scenarios required for modelling and simulation. The results included a statistical analysis and produced a better view of the probable reserves ranges. Remarkably, after 11 years’ production the field potential warranted re-appraisal. The scenario analysis indicated which uncertain variables needed attention and helped to select well locations. The results of appraisal should decide between several re-development options. The main possibilities for new field development include: drilling of additional oil producers; water shut-off in some producers; an additional flow-line to de-bottleneck oil production from Lambert and Hermes; re-instatement of a gas-injection line for gas-lift of wells at high water-cut; and installation of a new manifold further north in the Hermes accumulation to optimise field recovery.

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.

THE RENEWED SEARCH FOR OIL AND GAS IN THE BASS BASIN: RESULTS OF YOLLA-2 AND WHITE IBIS-I

1999 ◽  
Vol 39 (1) ◽  
pp. 248 ◽  
Author(s):  
R.G. Lennon ◽  
R.J. Suttill ◽  
D.A. Guthrie ◽  
A.R. Waldron
Keyword(s):  
Joint Venture ◽  
Oil And Gas ◽  
Oil Accumulation ◽  
Field Development ◽  
Seismic Control ◽  
White Ibis ◽  
Basement High ◽  
Oil Rim ◽  
Coal Measures ◽  
Exploration Well

Boral Energy Resources Ltd and its Joint Venture partners drilled two weUs in the offshore Bass Basin during 1998. Both wells targetted reservoirs in the Upper Cretaceous to Eocene Eastern View Coal Measures (EVCM).Yolla–2, located in Petroleum Licence T/RL1, appraised sandstones within the EVCM, first established gas bearing in the Yolla structure by the 1985 exploration well Yolla–1, drilled by Amoco. The exploration well White Ibis–1, located in adjacent permit T/18P, was a crestal test on a large basement high updip of the 1967 well Bass-3, drilled by Esso.Both wells of the 1998 drilling program encountered gas columns in the objective Paleocene to Lower Eocene section of the EVCM (Intra-EVCM). Liquids-rich gas was recovered from these reservoirs in wireline tests. Formation pressure data suggest a thin oil rim is developed in White Ibis–1. Neither well was tested in cased hole though White Ibis–1 was suspended for potential re-entry. Yolla–1 also encountered a gas and oil accumulation at the top of the Eastern View Coal Measures, but this level was not an objective in Yolla–2.Based on well results and 3D seismic control, a gas resource of between 450–600 BCF OGIP is currently estimated in the Yolla Field. The gas accumulation encountered in White Ibis–1 is estimated at 85 BCF OGIP.The 1998 drilling campaign has provided encour-agement to the T/RL1 and T/18P Joint Ventures to continue the search for both oil and gas in the Bass Basin. Markets for gas are being pursued in both Tasmania and Victoria and engineering studies are being undertaken in parallel to refine parameters for a potential Yolla Field development. The White Ibis Field may provide a candidate as a satellite to such a development. Depending on the outcomes of these studies, further drilling may occur in 1999 to increase confidence in the reserves base in the Yolla Field, and to further evaluate the exploration potential of T/18P.

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