An Integrated Pile Foundation Reassessment to Support Life Extension and New Build Activities for a Mature North Sea Oil Field Project

2017 ◽  
pp. 695-702 ◽  
Author(s):  
R Argiolas ◽  
R Jardine
Keyword(s):  
North Sea ◽  
Pile Foundation ◽  
Oil Field ◽  
Life Extension

Evaluation of Residual Life of Existing Offshore Platforms in Western Offshore, India

2021 ◽  
Author(s):  
A. Renugadevi ◽  
S. Nallayarasu ◽  
S. Karunanithi
Keyword(s):  
Residual Life ◽  
Probability Of Failure ◽  
Oil Field ◽  
Life Extension ◽  
Offshore Platforms ◽  
Strength Assessment ◽  
Encounter Probability ◽  
Reliability Method ◽  
Reserve Strength ◽  
Extension Period

Abstract Western offshore oil field in India has nearly 300 offshore platforms for oil and gas exploration, of which almost 50% of platforms have outlived their life. Life extension of these platforms has become essential for further production activities. In many cases, design level analyses combined with ultimate strength assessment, life extension has been granted. However, risk-based assessment based on the probability of failure based on available reserve strength linked to additional life extension could be a logical method. The Reserve Strength Ratio (RSR) is defined as a ratio of reserve capacity of the jacket structure and the design level environmental loads (1 year or 5year or 10 year or 100-year return period). The encounter probability of these design storms for the life extension period has been established probability for the extension period has been used as a threshold to determining the required RSR using the probability of collapse. For the present study, four typical aged wellhead platforms with different water depths are selected, and RSR is evaluated by carrying out push over analysis. The Monte Carlo Simulation method is used to generate the statistical values of RSR. The probability of failure is then calculated by First Order Reliability Method (FORM) using MATLAB for different RSR values. Reassessment criteria for the existing offshore platforms have been described from the reliability analysis results based on probability failure and encounter probability.

Depositional Modelling of UK North Sea Alba Field Reservoir

1992 ◽  
Vol 10 (4-5) ◽  
pp. 300-320
Author(s):  
Ian W. Thomas ◽  
John D. Collinson ◽  
Colin M. Jones
Keyword(s):  
North Sea ◽  
Middle Eocene ◽  
Oil Field ◽  
Seismic Survey ◽  
Linear Feature ◽  
The United Kingdom ◽  
Submarine Channel ◽  
Partial Filling ◽  
Detailed Interpretation ◽  
Central North Sea

The Alba Field is contained within block 16/26 of the Central North Sea of the United Kingdom. This oil field was discovered in 1984 by Chevron UK Ltd with the 16/26–5 well and has been appraised by 16 wells and sidetracks. The field is currently being developed and is scheduled to achieve first production around the end of 1993. A 3-D seismic survey, acquired in 1989, has greatly enhanced delineation of the field. It is a NW-SE trending linear feature approximately 5.25 miles (8.5 kms) in length with adjacent satellite structures. The reservoir sands comprise the Nauchlan Member of the Alba Formation (Horda Group) and are primarily of Middle Eocene age. Gross sand thicknesses in excess of 400 ft (120 m) are present within the field area with porosities ranging up to 38% and permeabilities of the order of 2800 mD. The sands were deposited as a series of submarine channel fills whose mutual relationships present problems of detailed interpretation. Channel sandbodies appear to be discontinuous along their length for a variety of reasons including erosive relief on the base of the channel, and partial filling of channels otherwise filled by mud.

Evaluating the well integrity of old exploration wells as a risk factor for future storage projects – an example from the Troll field in the Norwegian North Sea

2021 ◽  
Author(s):  
Bastien Dupuy ◽  
Benjamin Emmel ◽  
Simone Zonetti
Keyword(s):  
North Sea ◽  
Early Stage ◽  
Numerical Models ◽  
Low Frequency ◽  
Oil Field ◽  
Finite Element Software ◽  
Well Completion ◽  
Well Integrity ◽  
Volumetric Assessment ◽  
Work Done

<p>More than 750 wildcat wells have been drilled in the Norwegian North Sea since 1966. Some of these wells could pose a risk for the environment, climate, and future H<sub>2</sub> and CO<sub>2</sub> storage projects by being preferred leakage paths for subsurface- and stored- gases (e.g., CH<sub>4</sub>, CO<sub>2 </sub>and/or H<sub>2</sub>). To ensure well integrity, these wells were secured by cement framing the well casing, and by building cement plugs at crucial positions in the well path before abandoning the well. However, in an early stage of exploration the geology of the subsurface was relatively uncertain, and the requirements for plug placing and how to abandon a well were not established and regulated. We analysed data relevant for the quality of a Plugging and Abandonment (P&A) work done on old exploration wells (1979 to 2003) from the Troll gas and oil field in the Norwegian North Sea. The data were extracted from public available well completion reports and the webpage of the Norwegian Petroleum Directorate. The dataset was analysed regarding their availability, plausibility and evaluated towards the present P&A regulations and geological knowledge for offshore Norway. Based on 12 criteria including reporting to the authorities, volumetric assessment of used cement quantities, position and length of the plugs in relation to reservoir- cap-rocks petrophysical conditions, and verification of the cementing job, a final P&A ranking of 31 exploration wells was established.</p><p>Parts of this data were used to build realistic numerical models of P&A'ed well to simulate electromagnetic responses using the finite element software COMSOL Multiphysics. Taking advantage of a dedicated implementation of low frequency ElectroMagnetics (EM), including effective formulations for thin electrical layers, it was possible to study the response of well components to external EM fields, both for the purpose of well detection and well monitoring. Results from the numerical models can be used as benchmark models in a realistic field scale well integrity monitoring approach.</p><p>In our presentation we will show results from the TOPHOLE project including realistic field distributions for different representative well configurations, examples of well detection and monitoring signals, and the ranking evaluation results.</p><p>Acknowledgments: This work is performed with support from the Research Council of Norway (TOPHOLE project Petromaks2-KPN 295132) and the NCCS Centre (NFR project number 257579/E20).</p>

Investigating the AVO Signature of a North Sea Oil-Field Using Pseudo-Wells and Unsupervised Deep Learning

2019 ◽  
Author(s):  
L. Mosser ◽  
A. Amato del Monte ◽  
P. Avseth ◽  
A. Draege ◽  
L. MacGregor
Keyword(s):  
Deep Learning ◽  
North Sea ◽  
Oil Field ◽  
Unsupervised Deep Learning

The Emerald Field, Blocks 2/10a, 2/15a, 3/11b, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 111-116 ◽  
Author(s):  
D. M. Stewart ◽  
A. J. G. Faulkner
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Maximum Flow ◽  
Oil Field ◽  
Injection Wells ◽  
Initial Development ◽  
Flexible Risers ◽  
Northern North Sea ◽  
The Uk ◽  
Gas Lift

AbstractThe Emerald Oil Field lies in Blocks 2/10a, 2/15a and 3/1 lb in the UK sector of the northern North Sea. The field is located on the 'Transitional Shelf, an area on the western flank of the Viking Graben, downfaulted from the East Shetland Platform. The first well was drilled on the structure in 1978. Subsequently, a further seven wells have been drilled to delineate the field.The Emerald Field is an elongate dip and fault closed structure subparallel to the local NW-SE regional structural trend. the 'Emerald Sandstone' forms the main reservoir of the field and comprises a homogeneous transgressive unit of Callovian to Bathonian age, undelain by tilted Precambrian and Devonian Basement Horst blocks. Sealing is provided by siltstones and shales of the overlying Healther and Kimmeridge Clay Formations. The reservoir lies at depths between 5150-5600 ft, and wells drilled to date have encountered pay thicknesses of 42-74 ft. Where the sandstone is hydrocarbon bearing, it has a 100% net/ gross ratio. Porosities average 28% and permeabilities lie in the range 0-1 to 1.3 darcies. Wireline and test data indicate that the field contains a continouous oil column of 200 ft. Three distinct structural culminations exist on and adjacent to the field, which give rise to three separate gas caps, centred around wells 2/10a-4, 2/10a-7 and 2/10a-6 The maximum flow rate achieved from the reservoir to date is 6822 BOPD of 24° API oil with a GOR of 300 SCF/STBBL. In-place hydrocarbons are estimated to be 216 MMBBL of oil and 61 BCF of gas, with an estimated 43 MMBBL of oil recoverable by the initial development plan. initial development drilling began in Spring 1989 and the development scheme will use a floating production system. Production to the facility, via flexible risers, is from seven pre-drilled deviated wells with gas lift. An additional four pre-drilled water injection wells will provide reservoir pressure support.

Samarium-neodymium isotope stratigraphy of the Lunde and Statfjord Formations of Snorre Oil Field, northern North Sea

1989 ◽  
Vol 146 (2) ◽  
pp. 217-228 ◽  
Author(s):  
E. W. MEARNS ◽  
R. KNARUD ◽  
N. RÆSTAD ◽  
K. O. STANLEY ◽  
C. P. STOCKBRIDGE
Keyword(s):  
North Sea ◽  
Oil Field ◽  
Isotope Stratigraphy ◽  
Northern North Sea

The palingenesy of the Piper oil field, UK North Sea

1998 ◽  
Vol 4 (3) ◽  
pp. 271-286 ◽  
Author(s):  
S. D. Harker
Keyword(s):  
North Sea ◽  
Oil Field
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