The Babbage Field, Block 48/2a, UK North Sea

AbstractThe Babbage gas field was discovered in 1988 by exploration well 48/2-2 which drilled into the Permian-age lower Leman Sandstone Formation below a salt wall. Seismic imaging is compromised by the presence of this salt wall, which runs east–west across the southern part of the structure, creating uncertainties in depth conversion and in the in-place volumes. Pre-stack depth migration with beam and reverse time migrations appropriate for the complex salt geometry provided an uplift in subsalt seismic imaging, enabling the development of the field, which is located at the northern edge of the main reservoir fairway in a mixed aeolian–fluvial setting. Advances in artificial fracturing technology were also critical to the development: in this area, deep burial is associated with the presence of pore-occluding clays, which reduce the reservoir permeability to sub-millidarcy levels. The Babbage Field was sanctioned in 2008, based on an in-place volume range of 248–582 bcf; first production was in 2010. It produces from five horizontal development wells that were artificially fracced to improve deliverability of gas from the tight matrix. None of the wells has drilled the gas–water contact, which remains a key uncertainty to the in-place volumes, along with depth-conversion uncertainty below the salt wall.

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

Geological Society London Memoirs ◽

10.1144/gsl.mem.2003.020.01.55 ◽

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.

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Exploration success on the North West Shelf via continuous application of seismic technologies

The APPEA Journal ◽

10.1071/aj08013 ◽

2009 ◽

Vol 49 (1) ◽

pp. 205

Author(s):

Mark Thompson ◽

M Royd Bussell ◽

Michael Wilkins ◽

Dave Tapley ◽

Jenny Auckland

Keyword(s):

Seismic Imaging ◽

Leading Edge ◽

Seismic Survey ◽

Water Contact ◽

North West ◽

Depth Migration ◽

Petroleum Systems ◽

The North ◽

Continuous Application ◽

Near Term

Expansion of the North West Shelf Venture (NWSV) production infrastructure is driving plans for sequential development of the small satellite fields. The desire for additional gas reserves has fuelled increased exploration and appraisal drilling in recent years with encouraging results. The NWSV area is a complex geologic environment with multiple play levels, petroleum systems and trapping styles. Seismic imaging is poor in many areas, primarily due to multiple contamination. In 2004, the NWSV acquired the leading edge, regional Demeter 3D Seismic Survey. Since then, continuous application of improved processing techniques, such as 3D Surface-related Multiple Elimination (SRME) and Pre-Stack Depth Migration (PreSDM), have been key to providing significant imaging enhancements. Exploration drilling based on Demeter data resulted in three significant new gas discoveries. Pemberton–1 (2006) explored Triassic sub-cropping sands in a horst block at the southwestern end of the Rankin Trend. The well encountered an upside gas column due to the presence of intra-Mungaroo Formation shales providing a base-seal trapping geometry. Lady Nora–1 (2007) tested the fault block west of the Pemberton horst and encountered a 102 m gross gas column with gas on rock. The upside result accelerated a near term appraisal opportunity at Lady Nora–2 (2008). Persephone–1 (2006) drilled a down-thrown Legendre Formation dip closure in the Eaglehawk graben. Success relied on the sealing potential of the North Rankin Field bounding fault. In spite of pressure depletion associated with over 20 years of production, Persephone–1 encountered a 151 m gross gas column at virgin pressures and a different gas-water contact to North Rankin. The result demonstrated active and significant fault seal along the major North Rankin Field bounding fault. These recent, successful exploration wells have resulted in identification of follow-up drilling opportunities and a drive for ongoing seismic imaging improvements. The discoveries have material impacts on NWSV development plans for the Greater Western Flank and in the vicinity of the Perseus, North Rankin and Goodwyn gas fields.

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The Elswick Field, Bowland Basin, UK Onshore

Geological Society London Memoirs ◽

10.1144/m52-2017-29 ◽

2020 ◽

Vol 52 (1) ◽

pp. 62-73 ◽

Cited By ~ 1

Author(s):

Mathew Hampson ◽

Heather Martin ◽

Lucy Craddock ◽

Thomas Wood ◽

Ellie Rylands

Keyword(s):

Electricity Generation ◽

Alluvial Fan ◽

Reservoir Quality ◽

Gas Field ◽

Water Contact ◽

Depositional Processes ◽

Well Field ◽

Domal Structure ◽

Single Well ◽

Sandstone Formation

AbstractThe Elswick Field is located within Exploration Licence EXL 269a (Cuadrilla Resources Ltd is the operator) on the Fylde peninsula, West Lancashire, UK. It is the first producing onshore gas field to be developed by hydraulic fracture stimulation in the region. Production from the single well field started in 1996 and has produced over 0.5 bcf for onsite electricity generation. Geologically, the field lies within a Tertiary domal structure within the Elswick Graben, Bowland Basin. The reservoir is the Permian Collyhurst Sandstone Formation: tight, low-porosity fluvial desert sandstones, alluvial fan conglomerates and argillaceous sandstones. The reservoir quality is primarily controlled by depositional processes further reduced by diagenesis. Depth to the reservoir is 3331 ft TVDSS with the gas–water contact at 3400 ft TVDSS and with a net pay thickness of 38 ft.

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

Geological Society London Memoirs ◽

10.1144/gsl.mem.1991.014.01.52 ◽

1991 ◽

Vol 14 (1) ◽

pp. 417-423 ◽

Cited By ~ 1

Author(s):

R. T. Farmer ◽

A. P. Hillier

Keyword(s):

North Sea ◽

Upper Permian ◽

Lower Permian ◽

Reservoir Properties ◽

Gas Field ◽

Initial Development ◽

Reservoir Performance ◽

Matrix Permeability ◽

Reservoir Permeability ◽

Sandstone Formation

AbstractThe Clipper Gas Field is a moderate-sized faulted anticlinal trap located in Blocks 48/19a and 48/19c 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 Fm. is on average about 715 ft thick, laterally heterogeneous and zoned vertically with the best reservoir properties about the middle of the formation. Porosity is fair with a field average of 11.1%. Matrix permeability, however, is less than 1 millidarcy on average and is so low that some intervals in the field will not flow gas unless stimulated. Steep dipping zones of natural fractures occur in certain areas of the field; these commonly allow high flow rates to be achieved from large blocks of low-permeability matrix. Expected recoverable reserves from the most favourable part of the field are 558 BCF and Clipper Field is now being developed in conjunction with part of the adjacent Barque Gas Field. Later development of the remainder of Clipper Field will depend upon reservoir performance in the initial development area.

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Pluto 4D—Australia's first 4D over a gas field is an outstanding success

The APPEA Journal ◽

10.1071/aj17096 ◽

2018 ◽

Vol 58 (1) ◽

pp. 395 ◽

Cited By ~ 1

Author(s):

Larry Tilbury ◽

Andre Gerhardt

Keyword(s):

History Matching ◽

Feasibility Studies ◽

Seismic Survey ◽

Gas Field ◽

Water Contact ◽

Depth Migration ◽

Water Ingress ◽

Noise Data ◽

Excellent Control ◽

4D Seismic

The Pluto 4D seismic survey is Australia’s first 4D survey acquired over a gas field and has been an outstanding success despite the prior high technical risk of not being able to detect 4D differences above the background noise. At the time of the Pluto 4D monitor survey, the Pluto field had been on production for three years and nine months and produced approximately 1 Tcf of gas. The first monitor survey was acquired by PGS between November 2015 and February 2016 using dual sources and 12 streamers of 7050 m (geostreamer configuration). Also of note was the use of steerable sources to assist with repeatability, and towing the streamers at 20 m to minimise noise. Data was processed by CGG to pre-stack depth migration (PreSDM), took 12 months to deliver and required significant interaction between Woodside geoscientists and CGG to ensure an excellent 4D product. 4D feasibility studies carried out before acquisition showed that saturation changes (related to water ingress) were expected to show strong 4D responses near the gas water contact (GWC) and would be interpretable if the monitor survey was run after approximately three to four years of production. If the monitor survey was delayed, it showed that the pressure response became too large, swamped the 4D differences and made interpretation difficult or impossible. Strong ‘hardening’ responses on the 4D difference volumes are interpreted as water ingress into the field. Hardening responses are seen in all reservoir sequences in the Triassic from the TR27 to the TR32 units and range from strong (obvious) to weak (possible). Several examples are shown – the strongest response is seen in the large Triassic (TR27.3) valley within an essentially shale prone unit, which shows water ingress into the valley and moving upwards from the GWC towards the producing well. The results/insights from the 4D data have provided excellent control points for the history matching of the Pluto Field.

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Shenzi OBN: An imaging step change

The Leading Edge ◽

10.1190/tle40050348.1 ◽

2021 ◽

Vol 40 (5) ◽

pp. 348-356

Author(s):

Cheryl Mifflin ◽

Drew Eddy ◽

Brad Wray ◽

Lin Zheng ◽

Nicolas Chazalnoel ◽

...

Keyword(s):

Model Building ◽

Seismic Imaging ◽

Survey Design ◽

Waveform Inversion ◽

Complex Salt ◽

Step Change ◽

Ocean Bottom ◽

Maximum Frequency ◽

Reverse Time ◽

Time Migration

The story of seismic imaging over BHP's Shenzi Gulf of Mexico production field follows the history of offshore seismic imaging, from 2D to 3D narrow-azimuth streamer acquisition and to its leading the wide-azimuth movement with the Shenzi rich-azimuth (RAZ) survey. Each RAZ reprocessing project over the last 15 years applied the latest processing technology, culminating in hundreds of scenario tests to refine the salt model, but eventually the RAZ data reached a technical limit. A new ocean-bottom-node (OBN) survey acquired in 2020 has produced a step-change improvement over the legacy RAZ image. The uplift can be attributed to several factors. First, an OBN feasibility and survey design study demonstrated that a core of dense nodes combined with sparse nodes would improve the accuracy and resolution of the full-waveform inversion (FWI) solution. Second, the OBN data acquired following the survey design and employing FWI as the main model-building tool realized the predicted improvement. The result was a substantial change to the complex salt model, verified by a salt proximity survey as well as other salt markers, and improvement in imaging over the entire field. In addition to the improvement arising from a more accurate FWI velocity model, the steep-dip imaging also benefited from the new full-azimuth and long-offset data. However, the best steep-dip and fault imaging comes from the FWI image, a direct estimation of reflectivity from the FWI velocity. As the maximum frequency used by FWI moves toward the maximum frequency of the final reverse time migration (RTM), the FWI image approaches the resolution necessary to compete as the primary interpretation volume. Its subsalt illumination surpassed that of the RTM and even the least-squares RTM volumes. These imaging improvements are providing a new understanding of the faults and stratigraphic relationships of the field.

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The method for modeling the development of a gas field on the basis of a hierarchy of mathematical models

Tyumen State University Herald Physical and Mathematical Modeling Oil Gas Energy ◽

10.21684/2411-7978-2019-5-3-69-82 ◽

2019 ◽

Vol 5 (3) ◽

pp. 69-82

Author(s):

Vitaly P. Kosyakov ◽

Amir A. Gubaidullin ◽

Dmitry Yu. Legostaev

Keyword(s):

Mathematical Models ◽

Energy State ◽

Reservoir Pressure ◽

Gas Field ◽

Water Contact ◽

Simple Models

This article presents an approach aimed at the sequential application of mathematical models of different complexity (simple to complex) for modeling the development of a gas field. The proposed methodology allows the use of simple models as regularizers for the more complex ones. The main purpose of the applied mathematical models is to describe the energy state of the reservoir — reservoir pressure. In this paper, we propose an algorithm for adapting the model, which allows constructing reservoir pressure maps for the gas field, as well as estimating the dynamics of reservoir pressure with a possible output for determining the position of the gas-water contact level.

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3-D elastic prestack, reverse‐time depth migration

Geophysics ◽

10.1190/1.1443620 ◽

1994 ◽

Vol 59 (4) ◽

pp. 597-609 ◽

Cited By ~ 101

Author(s):

Wen‐Fong Chang ◽

George A. McMechan

Keyword(s):

Finite Differences ◽

Synthetic Data ◽

P Wave ◽

Common Source ◽

Reverse Time ◽

Depth Migration ◽

Full Wave ◽

Source Data ◽

Recorded Data ◽

Time Extrapolation

By combining and extending previous algorithms for 2-D prestack elastic migration and 3-D prestack acoustic migration, a full 3-D elastic prestack depth migration algorithm is developed. Reverse‐time extrapolation of the recorded data is by 3-D elastic finite differences; computation of the image time for each point in the 3-D volume is by 3-D acoustic finite differences. The algorithm operates on three‐component, vector‐wavefield common‐source data and produces three‐component vector reflectivity distributions. Converted P‐to‐S reflections are automatically imaged with the primary P‐wave reflections. There are no dip restrictions as the full wave equation is used. The algorithm is illustrated by application to synthetic data from three models; a flat reflector, a dipping truncated wedge overlying a flat reflector, and the classical French double dome and fault model.

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Rhyl Field: developing a new structural model by integrating basic geological principles with advanced seismic imaging in the Irish Sea

Geological Society London Petroleum Geology Conference series ◽

10.1144/pgc8.11 ◽

2016 ◽

Vol 8 (1) ◽

pp. 355-371 ◽

Cited By ~ 3

Author(s):

Gavin Ward ◽

Dean Baker

Keyword(s):

Structural Model ◽

Seismic Imaging ◽

Critical Factor ◽

Integrated Approach ◽

Velocity Model ◽

Irish Sea ◽

Depth Migration ◽

Processing Power ◽

And Migration ◽

Automated Quality Control

AbstractA new model of compression in the Upper Triassic overlying the Rhyl Field has been developed for the Keys Basin, Irish Sea. This paper highlights the significance of the overburden velocity model in revealing the true structure of the field. The advent of 3D seismic and pre-stack depth migration has improved the interpreter's knowledge of complex velocity fields, such as shallow channels, salt bodies and volcanic intrusions. The huge leaps in processing power and migration algorithms have advanced the understanding of many anomalous features, but at a price: seismic imaging has always been a balance of quality against time and cost. As surveys get bigger and velocity analyses become more automated, quality control of the basic geological assumptions becomes an even more critical factor in the processing of seismic data and in the interpretation of structure. However, without knowledge of both regional and local geology, many features in the subsurface can be processed out of the seismic by relying too heavily on processing algorithms to image the structural model. Regrettably, without an integrated approach, this sometimes results in basic geological principles taking second place to technology and has contributed to hiding the structure of the Rhyl Field until recently.

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