Mature field Development to Periphery Area: Tambora West Flank development

2021 ◽  
Author(s):  
Y. S Priastomo
Keyword(s):  
Seismic Data ◽  
Sediment Provenance ◽  
Reservoir Properties ◽  
The West ◽  
Gas Field ◽  
Field Development ◽  
Dynamic Uncertainty ◽  
Mahakam Delta ◽  
Fully Connected ◽  
Positive Results

Tambora gas field, discovered in 1974 is located in a swamp area at the apex of Mahakam Delta, and it is adjacent to Nilam field, which is operated by another operator. Geologically, the Tambora and Nilam Fields have the same anticline structure that originates from the sediment provenance west of Kalimantan as reflected in present day Mahakam Delta. Therefore, this study aims to analyze the challenges to unlock the potential of the west flank area of Tambora Fields. The geological synthesis of both Tambora and Nilam fields shows similar net sand and pay distribution in lateral and vertical proportions. Most developments in the Tambora Anticline area are in the crest and the distances between wells are ~100-200m. Challenges to unlock potential in flank areas are derived from the limitation of wells and seismic data. Based on data and knowledge of the flank areas in both fields, the west flank has better productivity compared to the east. Therefore, geological synthesis is conducted in the west flank area to define hydrocarbon and reservoir properties. Furthermore, channel models were made from 2D seismic scouring, controlled by the continuation of well log channel facies in the anticline crest area. Based on the preliminary approach, 3 wells were proposed to unlock west flank Tambora potential and were integrated into the plan of development. Primarily, dynamic uncertainty affects the potential of the west flank since production in the anticline crest area is enormous, and the uncertainty was analyzed by drilling one recent well. The result shows that hydrocarbon in the flank is not fully connected with the anticline crest area and has proven the sidebar heterogeneity concept. These gave more confidence to seek further positive results and develop west flank Tambora to sustain Mahakam production in the future.

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.

THE INTEGRATED USE OF PETROPHYSICAL, AVO, SEISMIC INVERSION AND 3D VISUALISATION TOOLS FOR RESERVOIR CHARACTERISATION

2001 ◽  
Vol 41 (2) ◽  
pp. 131
Author(s):  
A.G. Sena ◽  
T.M. Smith
Keyword(s):  
Seismic Data ◽  
New Technology ◽  
Seismic Inversion ◽  
Well Log ◽  
Reservoir Properties ◽  
Gas Field ◽  
Geological Interpretation ◽  
3D Visualisation ◽  
Quantitative Understanding ◽  
Inversion Techniques

The successful exploration for new reservoirs in mature areas, as well as the optimal development of existing fields, requires the integration of unconventional geological and geophysical techniques. In particular, the calibration of 3D seismic data to well log information is crucial to obtain a quantitative understanding of reservoir properties. The advent of new technology for prestack seismic data analysis and 3D visualisation has resulted in improved fluid and lithology predictions prior to expensive drilling. Increased reservoir resolution has been achieved by combining seismic inversion with AVO analysis to minimise exploration risk.In this paper we present an integrated and systematic approach to prospect evaluation in an oil/gas field. We will show how petrophysical analysis of well log data can be used as a feasibility tool to determine the fluid and lithology discrimination capabilities of AVO and inversion techniques. Then, a description of effective AVO and prestack inversion tools for reservoir property quantification will be discussed. Finally, the incorporation of the geological interpretation and the use of 3D visualisation will be presented as a key integration tool for the discovery of new plays.

scholarly journals Facies models of the Achimov Formation of East-Urengoiskoe license as the basis for optimizing exploration and field development patterns

Georesursy ◽  
2020 ◽  
Vol 22 (3) ◽  
pp. 55-61
Author(s):  
Alena V. Khramtsova ◽  
Sergey I. Pakhomov ◽  
Nikita Y. Natchuk ◽  
Мaria P. Kalashnikova ◽  
Sergey V. Romashkin ◽  
...  
Keyword(s):  
Seismic Data ◽  
Lower Cretaceous ◽  
Comprehensive Analysis ◽  
Core Analysis ◽  
Reservoir Properties ◽  
Development Patterns ◽  
Field Development ◽  
Submarine Fans ◽  
Well Correlation ◽  
Marine Basin

The results of sedimentological core analysis of the Achimov Formation (Upper Valanginian, Lower Cretaceous) confirm that it was formed by higher efficiency systems of submarine fans in (relatively) deep marine basin. Lithofacies models of Ach5-6 were generated, well correlation was performed based on the comprehensive analysis of core, well logging and seismic data. Distributary channels and proximal parts of depositional lobes are characterized by the best reservoir properties.

Geological Model Coupled with Geomechanics Makes an Impact on Fracturing Stimulation and Field Development Strategy of a Tight Gas Formation in the Sultanate of Oman

2015 ◽  
Author(s):  
Kevin Bate ◽  
Mauricio Lane ◽  
Alexey Moiseenkov ◽  
Sergey Nadezhdin
Keyword(s):  
Development Strategy ◽  
Fracture Propagation ◽  
Radioactive Tracer ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Reservoir Properties ◽  
Gas Field ◽  
Field Development ◽  
Tight Gas Formation ◽  
The Individual

Abstract Appraisal drilling of a recently discovered Cambrian-aged gas field in Oman is indicating that the field may have significant amounts of gas locked in a challenging deep, hot, and highly pressured reservoir environment. The low porosity and permeability values of the Amin reservoir allow the classification of the reservoir as a tight gas sand. The variability of reservoir properties, both spatially and vertically, makes it difficult to standardize perforation and fracture stimulation design which, in turn, complicates delineation of a development plan for the project. One of the difficulties relates to uncertainty in vertical propagation of hydraulic fractures. Fracture height based on evaluation of radioactive tracer logs indicates that vertical barriers to fracture propagation may relate to specific geologic zones in the reservoir. The mapping of the reservoir zones into undeveloped areas of the field would allow selection of primary and secondary production targets based on the specific physical properties of the individual zones. To assume that no barrier to fracture propagation exists between separate production units may lead to attempts to stimulate them synchronously, which would be disadvantageous for several reasons, such as premature screenouts and incomplete coverage of gas-bearing layers. Reserves booking and allocation can also be jeopardized should the fractures propagate into undesired zones.

Field development with three‐dimensional seismic methods in the Gulf of Thailand—A case history

Geophysics ◽  
1982 ◽  
Vol 47 (2) ◽  
pp. 149-176 ◽  
Author(s):  
C. G. Dahm ◽  
R. J. Graebner
Keyword(s):  
Seismic Data ◽  
Direct Detection ◽  
Three Dimensional ◽  
Seismic Survey ◽  
Gulf Of Thailand ◽  
Gas Field ◽  
Field Development ◽  
Hydrocarbon Traps ◽  
Line Spacing ◽  
The Gulf Of Thailand

A three‐dimensional (3-D) marine seismic survey was conducted in the Gulf of Thailand to aid in the development of a gas field indicated by three wildcat wells which had been located by seismic reconnaissance programs shot over a period of several years. The key to successful exploration in the area, basically a hinge line play, was a detailed understanding of the complex faulting controlling the hydrocarbon traps. Since the prospect lies 160–220 km offshore, some specialized surveying techniques were employed to achieve the required positioning accuracy. About 1280 km of seismic data were recorded at 100-m line spacing over a roughly rectangular block covering about [Formula: see text]. The 48‐fold data were processed using a 3-D wave equation migration algorithm yielding a set of seismic traces representing the data vertically below a grid of depth points spaced at [Formula: see text] by 100 m. The results of the 3-D program showed greater fault resolution and structural delineation. The interpretation developed from a series of horizontal slices provided by the 3-D processing further improved fault resolution. Five wells, drilled on the basis of the 3-D survey, are productive and closely tie the seismic data. Initial studies of amplitude patterns of key reflectors, combined with interval velocities from seismic derived logs, appear to offer the potential of direct detection of productive gas zones thicker than 25 to 30 ft. The 3-D seismic data are being utilized for planning additional development wells and potential platform locations.

Synergistic integration of seismic and geologic data for modeling petrophysical properties

2020 ◽  
Vol 39 (3) ◽  
pp. 164-169
Author(s):  
Yuan Zee Ma ◽  
David Phillips ◽  
Ernest Gomez
Keyword(s):  
Neural Networks ◽  
Seismic Data ◽  
Reservoir Characterization ◽  
Integrated Approach ◽  
Reservoir Modeling ◽  
Petrophysical Properties ◽  
Reservoir Properties ◽  
Field Development ◽  
Realistic Description ◽  
Geologic Data

Reservoir characterization and modeling have become increasingly important for optimizing field development. Optimal valuation and exploitation of a field requires a realistic description of the reservoir, which, in turn, requires integrated reservoir characterization and modeling. An integrated approach for reservoir modeling bridges the traditional disciplinary divides and tears down interdisciplinary barriers, leading to better handling of uncertainties and improvement of the reservoir model for field development. This article presents the integration of seismic data using neural networks and the incorporation of a depositional model and seismic data in constructing reservoir models of petrophysical properties. Some challenging issues, including low correlation due to Simpson's paradox and under- or overfitting of neural networks, are mitigated in geostatistical analysis and modeling of reservoir properties by integrating geologic information. This article emphasizes the integration of well logs, seismic prediction, and geologic data in the 3D reservoir-modeling workflow.

A REVIEW OF THE RECENT EXPLORATION AND HYDROCARBON POTENTIAL OF THE AMADEUS BASIN, NORTHERN TERRITORY

1984 ◽  
Vol 24 (1) ◽  
pp. 19 ◽  
Author(s):  
R. J. Schroder ◽  
J. D. Gorter
Keyword(s):  
Seismic Data ◽  
Joint Venture ◽  
Oil And Gas ◽  
Northern Territory ◽  
Hydrocarbon Potential ◽  
The West ◽  
Gas Field ◽  
Single Fold ◽  
Oil And Gas Field ◽  
Active Exploration

Since commencing operatorship in the Amadeus Basin in June 1980, the Amadeus Joint Venture has acquired 3000 km of multifold seismic data and reprocessed 2500 km of existing single fold and multifold data. These data, integrated with geological, Landsat, gravity and airphoto information, led to the drilling of eight exploration wells, which resulted in two gas discoveries (in the Dingo 1 and West Walker 1 wells) and numerous additional oil and gas shows in the remaining wells.Interpretation of these multi-discipline data has enabled a number of significant structural trends and styles in the Amadeus Basin to be defined. Individual prospects within some of the major structural trends have now been tested by the drill. This paper describes the nature of these structural trends and illustrates geologically and geophysically typical examples of drilled prospects existing within these trends.The primary exploration targets in the Amadeus Basin are the Ordovician Stairway and Pacoota Sandstones (confirmed by the Mereenie Oil and Gas Field, Palm Valley Gas Field, and the West Walker gas discoveries) and the Precambrian-basal Cambrian Arumbera Sandstone (confirmed by the Dingo gas discovery). Geochemical and maturation data indicate that significant additional oil and gas accumulations can be discovered in these formations.Data from Dingo 1, Mt Winter 1 and Finke 1 have again indicated that significant quantities of both oil and gas have been generated in the Late Proterozoic sediments of the Basin. An active exploration program is continuing and will endeavour to confirm these expectations.

3D Seismic Data Design, Acquisition and Interpretation of Kolmani Exploratory Field, Upper Benue Trough, Gongola Basin; Nigeria

2021 ◽  
Author(s):  
Usman Abdulkadir ◽  
Jamaluddeen Hashim ◽  
Ajay Kumar ◽  
Umar Yau ◽  
Akpam Simon ◽  
...  
Keyword(s):  
Seismic Data ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Data Sets ◽  
Gas Field ◽  
Gas Industry ◽  
Subsequent Formation ◽  
Benue Trough ◽  
Field Development ◽  
Improve Design

Abstract In an Oil and Gas field development plan, identifying appropriate reservoir location of a field and deciding the best design strategy as well as meeting the economic hydrocarbon viability are imperative for sustainability. 3-Dimensional seismic data have become a key tool used by geophysicists in the Oil and Gas industry to identify and understand subsurface reservoir deposits. In addition to providing excellent structural images, the dense sampling of a 3D survey can sometimes make it possible to map reservoir quality and the distribution of Oil and Gas. Primarily, Seismic data sets were retrieved from the ongoing Kolmani exploratory work of upper Benue trough, bordering Gombe-Bauchi communities of Nigeria and Simulation study from improve design was conducted using PETREL and SURFER software's to obtain numerous coordinates from the source and receiver lines respectively and subsequent formation of strategic-designs that shows different arrangements of the prospect area, an interpretation of the acquired data sets that indicates the reservoir location appropriately and probable onset of drilling spot. The well to seismic was also merged using synthetic seismogram that shows the location of reservoir (s) from the seismic data obtained and four different wells with anticipated depths respectively. The overall aim of the whole design and simulation studies is to aid petroleum Geologist and Geophysicists avoids common pit falls by reducing dry holes and increasing the overall number of productive wells prior to actual commencement of drilling in this prospect area and elsewhere.

Unlocking Oil Resources without Artificial Lift Using Testing Barge in Tambora Gas Field

2020 ◽  
Author(s):  
J., A. Anggoro
Keyword(s):  
Oil Recovery ◽  
Gas Field ◽  
Artificial Lift ◽  
Oil Resources ◽  
Cumulative Production ◽  
Inspection And Maintenance ◽  
Routine Inspection ◽  
Prime Condition ◽  
Safety Operation ◽  
Mahakam Delta

Tambora field is a mature gas field located in a swamp area of Mahakam delta without artificial lift. The main objective of this project is to unlock existing oil resources. Most oil wells could not flow because there is no artificial lift, moreover the network pressure is still at Medium Pressure (20 Barg). Given the significant stakes, the option to operate the testing barge continuously as lifting tool is reviewed. The idea is to set the separator pressure to 1-3 Barg, so that the wellhead flowing pressure could be reduced to more than 15 Barg which will create higher drawdown in front of the reservoir. The oil flows from the reservoir into the gauge tank, where it is then returned to the production line by transfer pumps. The trial was performed in well T-1 for a week in November 2017 and successfully produced continuous oil with a stable rate of 1000 bbls/d. What makes this project unique is the continuous operation for a long period of time. Therefore, it is important to ensure the capacity of the gauge tank and the transfer pump compatibility with the rate from the well, the system durability which required routine inspection and maintenance to ensure the testing barge unit is in prime condition and to maintain vigilance and responsiveness of personnel. This project started in 2018 for several wells and the cumulative production up to January 2020 has reached 158 k bbls and will be continued as there are still potential oil resources to be unlocked. Innovation does not need to be rocket science. Significant oil recovery can be achieved with a simple approach considering all safety operation, production and economic aspect.

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