Making the most of mature field opportunities—2009 Cobia infill drilling campaign

2010 ◽  
Vol 50 (2) ◽  
pp. 703
Author(s):  
Andy Zannetos ◽  
Will Leonard ◽  
Grant Clements ◽  
Dean Grant ◽  
Andrew Miatello ◽  
...  
Keyword(s):  
Production Data ◽  
3D Seismic ◽  
Initial Development ◽  
Seismic Modelling ◽  
Drilling Performance ◽  
3D Data ◽  
Infill Drilling ◽  
Fit For Purpose ◽  
Processing Techniques ◽  
Gippsland Basin

The Halibut and Fortescue oil fields are located in the Gippsland Basin, offshore Australia, and have produced 1.3 billion barrels of oil since the 1970s. The fields have been developed from three platforms—Cobia, Halibut and Fortescue—using multiple infill drilling campaigns post initial development. A strong emphasis has been placed on leveraging the latest technology to optimise development of these fields. The advent of high resolution 3D seismic surveys and improved processing techniques have proved invaluable in recent programs. This is illustrated by the 2009 Cobia infill program where the nine wells drilled over six months have increased field production from an average of 4,000 to 20,000 barrels of oil per day. Key success elements for this program included the use of new 3D re-processing technology, the application of past learnings, and the in-house enhancement of 3D data, in addition to seismic modelling and the integration of production data. The maturing of individual leads to economically viable targets used fit-for-purpose analysis of the data in which 3D seismic, well and production data were integrated and later built into 3D geologic models. Location choice was also important to the success of the program, where several potential targets were rejected after failing to meet technical or economic criteria. Drilling performance was exceptional, with all nine wells drilled within budget. The new 2009 Cobia infill wells have already produced over 2.2 million barrels of oil and show how mature fields can be re-invigorated through the use of re-processed 3D seismic and integrated data analysis.

THE YELLOWTAIL OIL DISCOVERY

1983 ◽  
Vol 23 (1) ◽  
pp. 170
Author(s):  
A. R. Limbert ◽  
P. N. Glenton ◽  
J. Volaric
Keyword(s):  
Oil Recovery ◽  
Seismic Data ◽  
Joint Venture ◽  
Seismic Survey ◽  
3D Seismic ◽  
Well Control ◽  
Reservoir Volume ◽  
3D Data ◽  
Small Feature ◽  
Gippsland Basin

The Esso/Hematite Yellowtall oil discovery is located about 80 km offshore in the Gippsland Basin. It is a small accumulation situated between the Mackerel and Kingfish oilfields. The oil is contained in Paleocene Latrobe Group sandstones, and sealed by the calcareous shales and siltstones of the Oligocene to Miocene Lakes Entrance Formation. Structural movement and erosion have combined to produce a low relief closure on the unconformity surface at the top of the Latrobe Group.The discovery well, Yellowtail-1, was the culmination of an exploration programme initiated during the early 1970's. The early work involved the recording and interpretation of conventional seismic data and resulted in the drilling of Opah- 1 in 1977. Opah-1 failed to intersect reservoir- quality sediments within the interpreted limits of closure although oil indications were encountered in a non-net interval immediately below the top of the Latrobe Group. In 1980 the South Mackerel 3D seismic survey was recorded. The interpretation of these 3D data in conjunction with the existing well control resulted in the drilling of Yellowtail-1 and subsequently led to the drilling of Yellowtail-2.In spite of the intensive exploration to which this small feature has been subjected, the potential for its development remains uncertain. Technical factors which affect the viability of a Yellowtail development are:The low relief of the closure makes the reservoir volume highly sensitive to depth conversion of the seismic data.The complicated velocity field makes precise depth conversion difficult.The thin oil column reduces oil recovery efficiency.The detailed pattern of erosion at the top of the Latrobe Group may be beyond the resolution capability of 3D seismic data.The 3D seismic data may not be capable of defining the distribution of the non-net intervals within the trap.The large anticlinal closures and topographic highs in the Gippsland Basin have been drilled, and the prospects that remain are generally small or high risk. Such exploration demands higher technology in the exploration stage and more wells to define the discoveries, and has no guarantee of success. The Yellowtail discovery is an illustration of one such prospect that the Esso/Hematite joint venture is evaluating.

Technology, investment and people: a process for extending the life of the Central Fields Complex, Gippsland Basin

2008 ◽  
Vol 48 (1) ◽  
pp. 133
Author(s):  
Michael Gross ◽  
Abdul Aziz Abdul Rahim ◽  
Erin Broad ◽  
Dean Grant ◽  
Brad Hargreaves
Keyword(s):  
Data Integration ◽  
Data Quality ◽  
Seismic Data ◽  
Depositional Environments ◽  
3D Seismic ◽  
Initial Development ◽  
Technology Investment ◽  
Technical Advances ◽  
Gippsland Basin ◽  
3D Seismic Data

The greater Central Fields complex of the Gippsland Basin, comprised of the Halibut, Fortescue and Mackerel fields, has produced 1.7 billion barrels of oil from four platforms in 37 years of production. After the initial development drilling phases from Halibut (1969–70), Mackerel (1977–80), Fortescue (1983–86) and Cobia (1983–85) platforms and five in-fill drilling campaigns (1992–2003) it is still possible to target unswept highly productive multi-darcy reservoirs along with bypassed zones in lower quality sands. During 2007, a six well program was completed from the Halibut platform using an upgraded workover rig that added significant volumes with combined initial rates of more than 16,000 barrels of oil per day. In addition, despite being conductor limited, the program tested strategic concepts and demonstrated significant remaining potential in a variety of reservoir qualities and depositional environments. The outstanding success of the 2007 program was based on an up-to-date geologic framework, key technical advances, ongoing investment commitment and multi-discipline integration across workplace functions. Advancements in 3D seismic data quality and analyses, reservoir surveillance, innovative slot recovery and data integration all played a role in the success of the program. Building on the success elements of the 2007 program, a higher capacity rig has been mobilised and upgraded to apply new drilling technologies to access the remaining potential and help mitigate basin decline.

IMPROVED STRUCTURAL RESOLUTION FROM 3D SURVEYS IN AUSTRALIA

1982 ◽  
Vol 22 (1) ◽  
pp. 17
Author(s):  
J. I. Sanders ◽  
G. Steel
Keyword(s):  
Three Dimensional ◽  
Velocity Analysis ◽  
Complex Structures ◽  
3D Seismic ◽  
3D Data ◽  
Survey Line ◽  
Line Spacing ◽  
Data Volume ◽  
Marine Seismic ◽  
Gippsland Basin

Two marine seismic three-dimensional (3D) surveys were carried out in the Gippsland Basin during 1980. The results of these surveys illustrate the improved structural resolution that can be obtained by 3D migration in complex areas, and also the great detail with which a structure can be defined by the dense data volume given by a 3D survey.Certain aspects of data collection and processing are particularly critical in achieving a successful 3D survey. Line spacing and depth-point spacing must be related to the maximum dips and reflection frequencies expected, and accurate navigation and streamer positioning are essential. Correct migration of the data is highly dependent on obtaining the proper migration velocities, and these are derived from the stacking velocity analysis by a form of 3D modelling.Sections and Seiscrop' horizontal time slices from the surveys demonstrate that in areas of complex three-dimensional structures, 3D seismic methods are necessary to properly image the reflection energy. The Seiscrop sections also show how the dense spatial sampling of 3D data is required to map these complex structures with adequate resolution for the most effective planning of a drilling programme.

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 Forties and Brimmond Fields, Blocks 21/10, 22/6a, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 557-561 ◽  
Author(s):  
A. Carter ◽  
J. Heale
Keyword(s):  
North Sea ◽  
Low Cost ◽  
New Technology ◽  
Horizontal Wells ◽  
Oil Price ◽  
3D Seismic ◽  
Rotary Drilling ◽  
Geological Society ◽  
Recoverable Reserves ◽  
Infill Drilling

AbstractThis paper updates the earlier account of the Forties Field detailed in Geological Society Memoir 14 (Wills 1991), and gives a brief description of the Brimmond Field, a small Eocene accumulation overlying Forties (Fig. 1).The Forties Field is located 180 km ENE of Aberdeen. It was discovered in 1970 by well 21/10-1 which encountered 119 m of oil bearing Paleocene sands at a depth of 2131 m sub-sea. A five well appraisal programme confirmed the presence of a major discovery including an extension into Block 22/6 to the southeast. Oil-in-place was estimated to be 4600 MMSTB with recoverable reserves of 1800 MM STB. The field was brought onto production in September 1975. Plateau production of 500 MBOD was reached in 1978, declining from 1981 to 77 MBOD in 1999.In September 1992 a programme of infill drilling commenced, which continues today. The earlier infill targets were identified using 3D seismic acquired in 1988. Acquisition of a further 3D survey in 1996 has allowed the infill drilling programme to continue with new seismic imaging of lithology, fluids and saturation changes. The performance of the 1997 drilling showed that high step-out and new technology wells, including multi-lateral and horizontal wells, did not deliver significantly better targets than drilling in previous years.In line with smaller targets, and in the current oil price environment, low cost technology is being developed through the 1999 drilling programme. Through Tubing Rotary Drilling (TTRD) is currently seen as the most promising way of achieving a step

3D Seismic Modelling by Demigration

1998 ◽  
Author(s):  
T. Pokrovskaia ◽  
L. T. Santos ◽  
J. Schleicher ◽  
M. Tygel ◽  
P. Hubral
Keyword(s):  
3D Seismic ◽  
Seismic Modelling

2D and 3D seismic modelling of crustal structural heterogeneities

1991 ◽  
Author(s):  
S. Hestholm ◽  
B. O. Rosland ◽  
E. S. Husebye ◽  
B. O. Ruud
Keyword(s):  
3D Seismic ◽  
Seismic Modelling ◽  
2D And 3D ◽  
Structural Heterogeneities

IMAGING ADDITIONAL OIL AND GAS RESERVES, INTEGRATING WELL PRODUCTION DATA AND 3D SEISMIC AVO CLASSIFICATION TO IMAGE REMAINING OIL AND GAS RESERVES—A CASE STUDY ON THE NGATORO FIELD, TARANAKI, NEW ZEALAND

2001 ◽  
Vol 41 (1) ◽  
pp. 679
Author(s):  
S. Reymond ◽  
E. Matthews ◽  
B. Sissons
Keyword(s):  
New Zealand ◽  
Oil And Gas ◽  
Seismic Facies ◽  
Bright Spot ◽  
Production Data ◽  
3D Seismic ◽  
Reservoir Model ◽  
Reservoir Properties ◽  
Well Production

This case study illustrates how 3D generalised inversion of seismic facies for reservoir parameters can be successfully applied to image and laterally predict reservoir parameters in laterally discontinuous turbiditic depositional environment where hydrocarbon pools are located in complex combined stratigraphic-structural traps. Such conditions mean that structural mapping is inadequate to define traps and to estimate reserves in place. Conventional seismic amplitude analysis has been used to aid definition but was not sufficient to guarantee presence of economic hydrocarbons in potential reservoir pools. The Ngatoro Field in Taranaki, New Zealand has been producing for nine years. Currently the field is producing 1,000 bopd from seven wells and at three surface locations down from a peak of over 1,500 bopd. The field production stations have been analysed using new techniques in 3D seismic imaging to locate bypassed oils and identify undrained pools. To define the objectives of the study, three questions were asked:Can we image reservoir pools in a complex stratigraphic and structural environment where conventional grid-based interpretation is not applicable due to lack of lateral continuity in reservoir properties?Can we distinguish fluids within each reservoir pools?Can we extrapolate reservoir parameters observed at drilled locations to the entire field using 3D seismic data to build a 3D reservoir model?Using new 3D seismic attributes such as bright spot indicators, attenuation and edge enhancing volumes coupled with 6 AVO (Amplitude Versus Offset) volumes integrated into a single class cube of reservoir properties, made the mapping of reservoir pools possible over the entire data set. In addition, four fluid types, as observed in more than 20 reservoir pools were validated by final inverted results to allow lateral prediction of fluid contents in un-drilled reservoir targets. Well production data and 3D seismic inverted volume were later integrated to build a 3D reservoir model to support updated volumetrics reserves computation and to define additional targets for exploration drilling, additional well planning and to define a water injection plan for pools already in production.

PESA Australian exploration review 2018

2019 ◽  
Vol 59 (2) ◽  
pp. 493
Author(s):  
D. Lockhart ◽  
D. Spring
Keyword(s):  
Oil And Gas ◽  
Petroleum Exploration ◽  
3D Seismic ◽  
The North ◽  
Second Year ◽  
Gippsland Basin ◽  
2D And 3D ◽  
Conventional Oil ◽  
Exploration Activity ◽  
Offshore Petroleum

Available data for 2018 indicates that exploration activity is on the rise in Australia, compared to 2017, and this represents a second year of growth in exploration activity in Australia. There has been an increase in area under licence by 92 000 km2, reversing the downward trend in area under licence that commenced in 2014. Since 2016, exploratory drilling within Australia has seen a continued upward trend in both the number of wells drilled and the percentage of total worldwide. Onshore, 77 conventional exploration and appraisal wells were spudded during the year. Offshore, exploration and appraisal drilling matched that seen in 2017, with five new wells spudded: two in the Roebuck Basin, two in the Gippsland Basin and one in the North Carnarvon Basin. Almost 1500 km of 2D seismic and over 10 000 km2 of 3D seismic were acquired within Australia during 2018, accounting for 2.4% and 3.9% of global acquisition, respectively. This represents an increase in the amount of both 2D and 3D seismic acquired in Australia compared with 2017. Once the 2017 Offshore Petroleum Acreage Release was finalised, seven new offshore exploration permits were awarded as a result. A total of 12 bids were received for round one of the 2018 Offshore Petroleum Exploration Release, demonstrating an increase in momentum for offshore exploration in Australia. The permits are in Commonwealth waters off Western Australia, Victoria and the Ashmore and Cartier islands. In June 2018, the Queensland Government announced the release of 11 areas for petroleum exploration acreage in onshore Queensland, with tenders closing in February/March 2019; a further 11 areas will be released in early 2019. The acreage is a mix of coal seam gas and conventional oil and gas. Victoria released five areas in the offshore Otway Basin within State waters. In the Northern Territory, the moratorium on fracking was lifted in April, clearing the way for exploration to recommence in the 2019 dry season. With the increase in exploration has come an increase in success, with total reserves discovered within Australia during 2018 at just under 400 million barrels of oil equivalent, representing a significant increase from 2017. In 2018, onshore drilling resulted in 18 new discoveries, while offshore, two new discoveries were made. The most notable exploration success of 2018 was Dorado-1 drilled in March by Quadrant and Carnarvon Petroleum in the underexplored Bedout Sub-basin. Dorado is the largest oil discovery in Australia of 100 million barrels, or over, since 1996 and has the potential to reinvigorate exploration in the region.

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