Integrated Reservoir Model: Lithoseismic Interpretation and Definition of the 3D Seismic Constraint

2006 ◽  
pp. 373-408
Author(s):  
Philippe Nivlet ◽  
Nathalie Lucet ◽  
Thierry Tonellot ◽  
Olivier Lerat ◽  
Frédéric Lefeuvre ◽  
...  
Keyword(s):  
3D Seismic ◽  
Reservoir Model ◽  
Definition Of

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.

THE APPLICATION OF 3D SEISMIC INTERPRETATION TECHNIQUES FOR OPTIMISING WELL PLACEMENT: FORTESCUE FIELD RE DEVELOPMENT, GIPPSLAND BASIN

1997 ◽  
Vol 37 (1) ◽  
pp. 31
Author(s):  
P.J. Ryan ◽  
T.E. Vinson
Keyword(s):  
High Precision ◽  
Seismic Data ◽  
Development Program ◽  
Seismic Interpretation ◽  
3D Seismic ◽  
Well Placement ◽  
Seismic Waveform ◽  
Attribute Analysis ◽  
Definition Of ◽  
Gippsland Basin

In order to achieve successful drilling results on mature fields, geophysical analysis has become increasingly focussed on the application of high precision 3D seismic interpretation and analysis techniques. These techniques were critical to the success of the re-development program recently completed on the Fortescue Field* Gippsland Basin. Fortescue, initially developed in 1983, contains an estimated oil reserve of 300 million barrels. The field is currently over 80 percent depleted. To offset declining production and develop remaining reserves, an 18 well additional drilling program together with upgrades to platform topsides and production facilities was conducted on the field from October 1994 to October 1996.Many of the proposed additional drilling opportunities relied on oil being trapped structurally updip from existing completions. Given the size (approx. 1 MSTB) and subtle, low relief nature of the targets being pursued, the precision of conventional 3D seismic interpretation techniques was inadequate to optimise the location of wells. This necessitated the development of a series of specific tools that could provide high resolution definition of both the trap and lithology as well as optimising well placement.These high precision interpretation techniques include: reservoir subcrop edge prediction through qualitative calibration of geological models to seismic data: the assessment of overburden velocity distortions of the seismic time field by utilising isochron mapping and interval attribute analysis; and prediction of trap geometries and lateral stratigraphic variations by the application of seismic waveform attributes.The application of these advanced 3D seismic interpretation techniques and their integration with related geoscience and engineering technologies resulted in the completion of a successful 18 well re-development program for the Fortescue field.

Subtle oil fields along the Western Flank of the Cooper/Eromanga petroleum system

2015 ◽  
Vol 55 (2) ◽  
pp. 440 ◽  
Author(s):  
Mark Sales ◽  
Malcolm Altmann ◽  
Glen Buick ◽  
Claire Dowling ◽  
John Bourne ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Oil Fields ◽  
3D Seismic ◽  
Success Rates ◽  
Reservoir Properties ◽  
Seismic Attribute ◽  
Western Flank ◽  
Definition Of ◽  
Market Capitalisation

Oil production from Cooper/Eromanga started in 1978, peaked in the 1980s and began a steady decline. Oil production from the Western Flank commenced in 2002 and has steadily increased. In the year until July 2014, a total of 8.6 million BBL of oil was produced from 16 active fields along the Western Flank, bringing the cumulative total to 24 million BBL. Western Flank oil has underpinned a ten-fold growth in market capitalisation in four listed Australian companies: Beach Energy, Drillsearch Ltd, Senex Energy and Cooper Energy. Two sandstone plays dominate the Western Flank petroleum geology: the Namur Sandstone low-relief structural play and the mid-Birkhead stratigraphic play. The use of 3D seismic has improved the definition of both plays, increased exploration success and optimised field appraisal and development drilling. Success rates have improved despite most Namur structural closures being close to the resolution margin for depth conversions (less than 8 m). Seismic attribute mapping is being refined in the more difficult search for mid-Birkhead stratigraphic traps with recent exploration discoveries indicating improved success. Reservoir properties in the Namur are excellent with multi-Darcy permeability, unlimited aquifer strength, low gas/oil ratio (GOR) and low residual oil saturation. This combination leads to an oil recovery factor greater than 75%. Initial free-flow production rates commonly exceed 6,000 BBL per a day. The mid-Birkhead reservoir is also of high quality but the lack of a strong aquifer drive reduces primary recovery. New and re-processed 3D seismic and water-flood projects are expected to drive further discoveries, reserve and production growth.

The Greater Etom Area (GEA): A New Phase of Exploration in the South Lokichar Basin, Turkana County, Northern Kenya

2016 ◽  
Author(s):  
Kevin Christopherson
Keyword(s):  
East Africa ◽  
Success Factors ◽  
3D Seismic ◽  
The South ◽  
Northern Kenya ◽  
The North ◽  
Structural Framework ◽  
Exploration Drilling ◽  
Complex Structural ◽  
Definition Of

ABSTRACT East Africa is an integral part of the Tullow business. Tullow has been active for over ten years in the onshore rift basins of East Africa, which began with the opening of the Uganda Lake Albert Rift Basin in 2006 following the drilling of Mputa-1. We developed multiple sub-surface evaluation tools and an understanding on how rift success factors can combine during the drilling of the Lake Albert Basin that we then applied to the Tertiary rifts of Kenya. Extensive Full Tensor Gradiometry (FTG), seismic and drilling has taken place over the last five years in Kenya. This has established the South Lokichar basin as a significant oil basin with significant remaining exploration upside. Up until 2015 exploration drilling in the South Lokichar utilized 2D seismic data. The acquisition of 3D seismic in the north and west of the basin has allowed an improved definition of the structural framework and highlighted additional exploration potential. The Etom-2 well spud in November 2015 highlights the value of this 3D seismic in complex structural settings. Etom-1 was planned and drilled on 2D seismic and encountered 10 m of oil pay. Subsequent re-mapping based upon the 3D seismic revealed that the Etom structure was more complicated than originally interpreted and that Etom-1 had drilled into a collapse graben and not tested the structural crest of the field. Etom-2 targeted the up-thrown northern fault block which was not penetrated by the Etom-1 well and encountered 102 m of oil pay. The northern part of the South Lokichar basin is structurally complex and the 3D seismic provided the required detail to highlight that Etom-1 hadn't properly tested the Etom structure. Further mapping of the 3D seismic in the area around Etom-2 has identified multiple follow-up prospects that could be part of a new play domain in the northern part of the South Lokichar Basin. These targets are the focus for Exploration drilling that is due to commence in Q4 2016.

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