APPRAISING THE YOLLA FIELD IN THE BASS BASIN—HOW EFFECTIVE DATA COLLECTION, ANALYSIS AND INTEGRATION INCREASED ESTIMATED HYDROCARBON VOLUMES IN PLACE

2006 ◽  
Vol 46 (1) ◽  
pp. 15
Author(s):  
D.M. Brooks ◽  
B.A. Pidgeon ◽  
A.D. Hall ◽  
R.J. Taylor ◽  
J.L. Parvar
Keyword(s):  
Joint Venture ◽  
Volatile Oil ◽  
Field Size ◽  
Gas Reservoirs ◽  
Depositional Facies ◽  
Field Development ◽  
Recoverable Reserves ◽  
Coal Measures ◽  
Solution Gas ◽  
Associated Solution

Between June and October 2004, two development wells (Yolla–3 and –4) were drilled on the Yolla field in Bass Strait by the T/L1 joint venture. The top and intra-Eastern View Coal Measures (EVCM) hydrocarbon-bearing reservoirs in the field were intersected close to prognosis. A previously undiscovered oil-bearing intra-EVCM sand was encountered in Yolla–4 and the upper EVCM gas and oil bearing reservoir section was completed in Yolla–3 and its productivity confirmed.A key objective of the development drilling campaign was to collect detailed geological and engineering data to assist in field development and quantification of the resource. Subsequent interpretation of these data led to a revision of the depositional facies and reservoir parameters and provided new inputs into a complex 3D reservoir model.The new reservoir model resulted in an upward revision in calculated gas in-place volumes for the intra-EVCM gas reservoirs of about 100 bcf (2,832 m3 x106) or 20% of the pre-drill field size to 600 bcf (16,991 m3x106) and a corresponding increase in recoverable reserves estimates. The upper EVCM is now interpreted to hold 16.5 MMstb (2,623,005 kL) of oil-in-place and total gas-in-place including the gas cap and the solution gas in the oil leg of 33 bcf (934.5 m3x106). These volumes add to the gas reserves for the field, and it is expected that the volatile oil leg will contribute to a richer liquids yield when the zone is produced. The new oil pool in the intra-EVCM has been provisionally estimated at 3.2 MMstb (508,704 kL) oil-inplace with associated solution gas of 2.5 bcf (71 m3x106).

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.

scholarly journals Incremental and acceleration production estimation and their effect on optimization of well infill locations in tight gas reservoirs

2021 ◽  
Author(s):  
Atheer Dheyauldeen ◽  
Omar Al-Fatlawi ◽  
Md Mofazzal Hossain
Keyword(s):  
Transient Flow ◽  
Development Planning ◽  
Main Role ◽  
Gas Reservoirs ◽  
Type Curves ◽  
Field Development ◽  
Drilling Performance ◽  
Well Location ◽  
Infill Drilling ◽  
Tight Formations

AbstractThe main role of infill drilling is either adding incremental reserves to the already existing one by intersecting newly undrained (virgin) regions or accelerating the production from currently depleted areas. Accelerating reserves from increasing drainage in tight formations can be beneficial considering the time value of money and the cost of additional wells. However, the maximum benefit can be realized when infill wells produce mostly incremental recoveries (recoveries from virgin formations). Therefore, the prediction of incremental and accelerated recovery is crucial in field development planning as it helps in the optimization of infill wells with the assurance of long-term economic sustainability of the project. Several approaches are presented in literatures to determine incremental and acceleration recovery and areas for infill drilling. However, the majority of these methods require huge and expensive data; and very time-consuming simulation studies. In this study, two qualitative techniques are proposed for the estimation of incremental and accelerated recovery based upon readily available production data. In the first technique, acceleration and incremental recovery, and thus infill drilling, are predicted from the trend of the cumulative production (Gp) versus square root time function. This approach is more applicable for tight formations considering the long period of transient linear flow. The second technique is based on multi-well Blasingame type curves analysis. This technique appears to best be applied when the production of parent wells reaches the boundary dominated flow (BDF) region before the production start of the successive infill wells. These techniques are important in field development planning as the flow regimes in tight formations change gradually from transient flow (early times) to BDF (late times) as the production continues. Despite different approaches/methods, the field case studies demonstrate that the accurate framework for strategic well planning including prediction of optimum well location is very critical, especially for the realization of the commercial benefit (i.e., increasing and accelerating of reserve or assets) from infilled drilling campaign. Also, the proposed framework and findings of this study provide new insight into infilled drilling campaigns including the importance of better evaluation of infill drilling performance in tight formations, which eventually assist on informed decisions process regarding future development plans.

The Clipper Field, Blocks 48/19a, 48/19c, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 691-698
Author(s):  
M. J. Sarginson
Keyword(s):  
North Sea ◽  
Upper Permian ◽  
Lower Permian ◽  
Reservoir Properties ◽  
Gas Field ◽  
Field Development ◽  
Matrix Permeability ◽  
Recoverable Reserves ◽  
Reservoir Permeability ◽  
Sandstone Formation

AbstractThe Clipper Gas Field is a moderate-sized faulted anticlinal trap located in Blocks 48/19a, 48/19c and 48/20a within the Sole Pit area of the southern North Sea Gas Basin. The reservoir is formed by the Lower Permian Leman Sandstone Formation, lying between truncated Westphalian Coal Measures and the Upper Permian evaporitic Zechstein Group which form source and seal respectively. Reservoir permeability is very low, mainly as a result of compaction and diagenesis which accompanied deep burial of the Sole Pit Trough, a sub basin within the main gas basin. The Leman Sandstone Formation is on average about 715 ft thick, laterally heterogeneous and zoned vertically with the best reservoir properties located in the middle of the formation. Porosity is fair with a field average of 11.1%. Matrix permeability, however, is less than one millidarcy on average. Well productivity depends on intersecting open natural fractures or permeable streaks within aeolian dune slipface sandstones. Field development started in 1988. 24 development wells have been drilled to date. Expected recoverable reserves are 753 BCF.

Predictive estimates of subsidence of the earth’s surface during the development of the Yamburgskoye oil and gas condensate field

2021 ◽  
pp. 9-22
Author(s):  
Yu. V. Vasiliev ◽  
M. S. Mimeev ◽  
D. A. Misyurev
Keyword(s):  
Oil And Gas ◽  
Active Faults ◽  
Physical And Mechanical Properties ◽  
Deformation Model ◽  
Reservoir Pressure ◽  
Gas Reservoirs ◽  
Field Development ◽  
Geodynamic Processes ◽  
Deformation Processes ◽  
The Stability

The production of hydrocarbons is associated with a change in the physical and mechanical properties of oil and gas reservoirs under the influence of rock and reservoir pressures. Deformation of the reservoir due to a drop in reservoir pressure leads to the formation of various natural and man-made geodynamic and geomechanical phenomena, one of which is the formation of a subsidence trough of the earth's surface, which leads to a violation of the stability of field technological objects.In order to ensure geodynamic safety, a set of works is used, which includes analysis of geological and field indicators and geological and tectonic models of the field, interpretation of aerospace photographs, identification of active faults, construction of a predictive model of subsidence of the earth's surface of the field with identification of zones of geodynamic risk.This work was carried out to assess the predicted parameters of rock displacement processes during field development; even insignificant disturbances in the operation of technological equipment caused by deformation processes can cause significant damage.Prediction of rock displacements is possible only on the basis of a reservoir deformation model that adequately reflects the geomechanical and geodynamic processes occurring in the subsoil. The article presents a model of reservoir deformation with a drop in reservoir pressure, describes its numerical implementation, and performs calculations of schemes for typical development conditions.

A PROJECT OF TECHNOLOGY TRANSFER TO THE CHINESE OFFSHORE PETROLEUM INDUSTRY

1984 ◽  
Vol 24 (1) ◽  
pp. 118
Author(s):  
Geoffrey Hart
Keyword(s):  
Joint Venture ◽  
Petroleum Industry ◽  
Oil Fields ◽  
Medium Size ◽  
Financial Evaluation ◽  
Field Development ◽  
Foreign Companies ◽  
Offshore Engineering ◽  
Training Courses ◽  
Offshore Oil

Under the umbrella of a Technical Co-operation Agreement between Australia and China, CSR is managing a project to transfer to the Chinese petroleum industry the equipment and knowledge required for the financial evaluation of large offshore developments by computer modelling.A medium-size interactive computer will be supplied along with a financial evaluation software package. Australian specialists in financial evaluation and modelling, computer management and offshore engineering will visit China to conduct training courses, and twelve Chinese professionals will visit Australia for tertiary studies and work experience.China is coming to the end of the first round of awarding contracts to foreign companies for the exploration of offshore oil fields. Ahead are later stages of bidding and contract negotiation, the evaluation of field development proposals, and the management of joint venture participation in producing fields. The computer equipment and application skills to be supplied under this project will significantly upgrade the capability of the Chinese petroleum industry to manage these future stages.

The Gawain Field, Blocks 49/24, 49/29a, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 713-722
Author(s):  
R. A. Osbon ◽  
O. C. Werngren ◽  
A. Kyei ◽  
D. Manley ◽  
J. Six
Keyword(s):  
North Sea ◽  
Early Permian ◽  
Water Contact ◽  
Field Development ◽  
Dune Sands ◽  
Southern North Sea ◽  
Recoverable Reserves ◽  
Structural Relief ◽  
Sandstone Formation

AbstractThe Gawain Field is located on the Inde shelf in the Southern North Sea, 85 km NE of the Norfolk coast. Gawain was discovered in 1970 by well 49/29-1 and a total of nine wells have been drilled on the structure. Gas is produced from the Leman Sandstone Formation of Early Permian age. The reservoir section is comprised predominantly of stacked aeolian dune sands possessing excellent poroperm characteristics. The structure is a complex NW-SE trending horst block with a common gas-water contact at 8904 ft TVDss. Low structural relief has presented a major challenge to field development, which has utilized extended reach wells to maximize drainage potential. Initial gas-in-place is estimated at 289 BCF with recoverable reserves in the order of 196 BCF. The field came on production in September 1995 via a sub-sea tie back to the Thames infrastructure and has an expected field life of 10 years

Efficient handling of fault properties using the Juxtaposition Table Method

2020 ◽  
Vol 496 (1) ◽  
pp. 199-207 ◽  
Author(s):  
Tor Anders Knai ◽  
Guillaume Lescoffit
Keyword(s):  
History Matching ◽  
Oil And Gas ◽  
Production Data ◽  
Gas Reservoirs ◽  
Fault Rock ◽  
Field Development ◽  
Table Method ◽  
Reservoir Models ◽  
Complete Life Cycle ◽  
Fault Properties

AbstractFaults are known to affect the way that fluids can flow in clastic oil and gas reservoirs. Fault barriers either stop fluids from passing across or they restrict and direct the fluid flow, creating static or dynamic reservoir compartments. Representing the effect of these barriers in reservoir models is key to establishing optimal plans for reservoir drainage, field development and production.Fault property modelling is challenging, however, as observations of faults in nature show a rapid and unpredictable variation in fault rock content and architecture. Fault representation in reservoir models will necessarily be a simplification, and it is important that the uncertainty ranges are captured in the input parameters. History matching also requires flexibility in order to handle a wide variety of data and observations.The Juxtaposition Table Method is a new technique that efficiently handles all relevant geological and production data in fault property modelling. The method provides a common interface that is easy to relate to for all petroleum technology disciplines, and allows a close cooperation between the geologist and reservoir engineer in the process of matching the reservoir model to observed production behaviour. Consequently, the method is well suited to handling fault property modelling in the complete life cycle of oil and gas fields, starting with geological predictions and incorporating knowledge of dynamic reservoir behaviour as production data become available.

Complexity in tight gas sand development—an example from Perth Basin, Western Australia

2011 ◽  
Vol 51 (2) ◽  
pp. 743
Author(s):  
Reza Rezaee
Keyword(s):  
Tight Gas ◽  
Gas Reservoirs ◽  
Field Development ◽  
Fine Grained ◽  
Well Completion ◽  
Well Stimulation ◽  
Tight Gas Sands ◽  
Facies Change ◽  
Key Issues ◽  
Reservoir Geometry

One of the key issues for tight gas reservoirs is about reservoir heterogeneities and its connectivity. Knowledge of reservoir geometry, orientation, and connectedness is vital for reservoir modelling, which is the essential tool for successful field development, well completion, and well stimulation strategies. Fluvial sediments are heterogeneous both vertically and laterally due to facies change and diagenetic processes. These make their field development difficult. In terms of sand geometry and connectivity, the first step to making the reservoir model in three directions is to determine the width of sandstone bodies in various directions. Fine-grained facies associated with fluvial deposits can compartmentalise reservoirs and can significantly complicate the development of such units, as well as make well stimulation and fracturing jobs unpredictable. In this paper, the above issues are studied for some fluvial tight gas sands of the Perth Basin. The aim is to discuss the best possible way to successfully plan well and well stimulation strategies.

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.

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