The Rhyl Field, Block 113/27b, UK East Irish Sea

AbstractThe Rhyl Field is located in the offshore East Irish Sea Basin, approximately 30 km to the west of Barrow-in-Furness. Rhyl is one of the producing gas fields forming the Morecambe Hub development, operated by Spirit Energy. The Rhyl reservoir is the Ormskirk Sandstone Formation of Triassic age which regionally comprises four depositional facies types: aeolian, fluvial, sandflat and playa. The depositional system provides excellent reservoir properties that are impacted by a diagenetic history of authigenic illitization and quartz overgrowths. The northern boundary of the field is located underneath the Fleetwood Dyke Complex, resulting in significant imaging and depth-conversion uncertainty. This has been addressed by dyke mapping and manual depth corrections to seismic processing. The trapping mechanism at the southern boundary of the field is also unclear; the dip-closed structural spill point as mapped at the southern boundary appears shallower than the log-derived gas–water contact. Rhyl gas contains a significant inert content: 37% CO2 and 7% N2. The field's production rate has been limited to approximately 40 MMscfgd by the CO2 processing limit of the onshore gas terminal. Material balance studies have yielded a satisfactory understanding of connected gas in place, recoverable reserves and dynamic field behaviour.

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The Hamilton and Hamilton North Gas Fields, Block 110/13a, East Irish Sea

Geological Society London Memoirs ◽

10.1144/gsl.mem.2003.020.01.06 ◽

2003 ◽

Vol 20 (1) ◽

pp. 77-86 ◽

Cited By ~ 5

Author(s):

A. Yaliz ◽

P. Taylor

Keyword(s):

Gas Production ◽

Irish Sea ◽

Hydrocarbon Generation ◽

High Porosity ◽

Water Contact ◽

The North ◽

Depositional Processes ◽

Sandstone Formation ◽

Two Phases ◽

Water Cut

AbstractThe Hamilton and Hamilton North Fields are located in Block 110/13a in the East Irish Sea, and contain 627 BCF and 230 BCF GIIP, respectively. First gas was produced from the Hamilton North Field in December 1995. The fields are being developed with four producers in the Hamilton Field and three in the Hamilton North Field. The Hamilton Field structure consists of a N-S trending horst block with dip closure to the north and south, while the Hamilton North structure is defined by major faults to the north and west with dip closure to the east and south. The gas is trapped in the highly productive Triassic Ormskirk Sandstone Formation. The reservoir comprises high porosity aeolian and fluvial sandstones. Depth to reservoir is shallow (2300-2600 ft) with the gas-water contact being at 2910 ft in the Hamilton Field and 3166 ft in the Hamilton North Field. Reservoir quality is principally controlled by primary depositional processes and no significant diagenetic effects are observed. The hydrocarbon filling history was complex, with at least two phases of hydrocarbon generation. Hamilton North gas is sweet whereas the Hamilton gas contains up to 11OOppm H2S, which is removed during processing at the Douglas complex and at the Point of Ayr gas terminal. Cumulative gas production to May 1999 was 180 BCF and no water-cut has been observed to date.

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Application of Hydrodynamic Potential Analysis to Investigate Possibility Reservoir Connectivity between Neighboring Gas Fields

Journal of Earth Energy Science, Engineering, and Technology ◽

10.25105/jeeset.v2i1.4647 ◽

2019 ◽

Vol 2 (1) ◽

Author(s):

Tri Firmanto ◽

Muhammad Taufiq Fathaddin ◽

R. S. Trijana Kartoatmodjo

Keyword(s):

Stone Formation ◽

Material Balance ◽

Gas Field ◽

Water Contact ◽

Potential Analysis ◽

Balance Analysis ◽

Hydrodynamic Potential ◽

Flowing Material ◽

Reservoir Connectivity ◽

Gas Fields

<em>T field is a producting gas field in North Bali PSC, which currently producing 210 mmscfd from paciran sand stone formation. Paciran formation extends more than 20 km across the PSC area, which consists of 3 developed gas fields and one potential development field. The flowing material balance analysis conducted on T field suggests possibility of reservoir connectivty between this field and its neighboring fields. Even though each field is already have a well defined Gas Water Contact, a thorough investigation was done using hyrdodynamic potential analysis to see if theres any hydrodynamic potential that allowed connectivity between these fields, and enable tilted contact occurred between these field. Using pressure data taken from each fields exploration wells the analysis can be conducted that conclude that there is an existing hydrodynamic potential between gas fields in paciran formation. A review on the tilted contact analysis concludes that the existing hydrodynamic potential is not enough to tilt the contact as per actually observed contact</em>.

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The Tolmount Field, Block 42/28d, UK North Sea

Geological Society London Memoirs ◽

10.1144/m52-2018-16 ◽

2020 ◽

Vol 52 (1) ◽

pp. 262-272 ◽

Cited By ~ 1

Author(s):

A. Miles ◽

M. Allen ◽

L. Fairweather ◽

J. Hilton ◽

H. Sloan ◽

...

Keyword(s):

North Sea ◽

Burial History ◽

Reservoir Properties ◽

Water Contact ◽

Diagenetic Alteration ◽

Reservoir Sandstones ◽

Sandstone Formation ◽

The Uk ◽

Continental Basin ◽

Gas Bearing

AbstractThe Tolmount Field is a lean gas condensate accumulation located in Block 42/28d of the UK Southern North Sea. The field was discovered in 2011 by well 42/28d-12, which encountered good-quality gas-bearing reservoir sandstones of the Permian Leman Sandstone Formation. The discovery was appraised in 2013 by wells 42/28d-13 and 42/28d-13Z, which logged the gas–water contact on the eastern flank of the field. The Tolmount structure is a four-way, dip-closed, faulted anticline, orientated NW to SE. The reservoir comprises mixed aeolian dune and fluvial sheetflood facies deposited within an arid continental basin. Dune sands display the best reservoir properties with porosities around 22% and permeabilities exceeding 100 mD. Only minor diagenetic alteration has occurred, primarily in the form of grain-coating illite. Superior reservoir quality is observed at Tolmount compared to adjacent areas, due to the preservation of dune facies, a hypothesized early gas emplacement and a relatively benign burial history. Current mapped gas initially-in-place estimates for the field are between 450 bcf and 800 bcf, with an estimated recovery factor between 70 and 90%. An initial four-well development is planned, with first gas expected in 2020.

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Potential for the Geological Storage of CO2 in the Croatian Part of the Adriatic Offshore

Minerals ◽

10.3390/min9100577 ◽

2019 ◽

Vol 9 (10) ◽

pp. 577 ◽

Cited By ~ 1

Author(s):

Bruno Saftić ◽

Iva Kolenković Močilac ◽

Marko Cvetković ◽

Domagoj Vulin ◽

Josipa Velić ◽

...

Keyword(s):

Pannonian Basin ◽

Sedimentary Basins ◽

Petroleum Exploration ◽

Geological Storage ◽

Reservoir Properties ◽

Secondary Porosity ◽

Deep Saline Aquifer ◽

Total Potential ◽

History Of ◽

Gas Fields

Every country with a history of petroleum exploration has acquired geological knowledge of its sedimentary basins and might therefore make use of a newly emerging resource—as there is the potential to decarbonise energy and industry sectors by geological storage of CO2. To reduce its greenhouse gas emissions and contribute to meeting the Paris agreement targets, Croatia should map this potential. The most prospective region is the SW corner of the Pannonian basin, but there are also offshore opportunities in the Northern and Central Adriatic. Three “geological storage plays” are suggested for detailed exploration in this province. Firstly, there are three small gas fields (Ida, Ika and Marica) with Pliocene and Pleistocene reservoirs suitable for storage and they can be considered as the first option, but only upon expected end of production. Secondly, there are Miocene sediments in the Dugi otok basin whose potential is assessed herein as a regional deep saline aquifer. The third option would be to direct future exploration to anticlines composed of carbonate rocks with primary and secondary porosity, covered with impermeable Miocene to Holocene clastic sediments. Five closed structures of this type were contoured with a large total potential, but data on their reservoir properties allow only theoretical storage capacity estimates at this stage.

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Rock-physics modeling guided by depositional and burial history in low-to-intermediate-porosity sandstones

Geophysics ◽

10.1190/geo2013-0226.1 ◽

2014 ◽

Vol 79 (2) ◽

pp. D115-D121 ◽

Cited By ~ 16

Author(s):

Per Avseth ◽

Tor Arne Johansen ◽

Aiman Bakhorji ◽

Husam M. Mustafa

Keyword(s):

Rock Physics ◽

Contact Theory ◽

Well Log ◽

Tight Gas ◽

Burial History ◽

Reservoir Properties ◽

Rock Physics Modeling ◽

History Of ◽

Physics Modeling ◽

Diagenetic History

We present a new rock-physics modeling approach to describe the elastic properties of low-to-intermediate-porosity sandstones that incorporates the depositional and burial history of the rock. The studied rocks have been exposed to complex burial and diagenetic history and show great variability in rock texture and reservoir properties. Our approach combines granular medium contact theory with inclusion-based models to build rock-physics templates that take into account the complex burial history of the rock. These models are used to describe well log data from tight gas sandstone reservoirs in Saudi Arabia, and successfully explain the pore fluid, rock porosity, and pore shape trends in these complex reservoirs.

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THE EXPLORATION AND APPRAISAL HISTORY OF THE KATNOOK AND LADBROKE GROVE GAS FIELDS, ONSHORE OTWAY BASIN, SOUTH AUSTRALIA

The APPEA Journal ◽

10.1071/aj91007 ◽

1992 ◽

Vol 32 (1) ◽

pp. 67 ◽

Cited By ~ 1

Author(s):

K. A. Parker

Keyword(s):

South Australia ◽

Subsequent Development ◽

Hydrocarbon Exploration ◽

Gas Field ◽

Water Contact ◽

Field Development ◽

Gas Accumulation ◽

Seismic Acquisition ◽

History Of ◽

Gas Fields

The discoveries of the Katnook Field and, later, the Ladbroke Grove Field were significant milestones for hydrocarbon exploration in the southeast of South Australia as well as for the Otway Basin in general. The initial 1987 discovery at Katnook-1 of a relatively shallow gas accumulation in the basal part of the Eumeralla Formation was eclipsed in late 1988 at the Katnook-2 appraisal stage where deeper and more significant gas reserves were discovered in the Pretty Hill Sandstone.Technological improvement, in seismic acquisition, in particular, use of longer offset configurations and higher fold, and in filtering and correction techniques at the processing stage, are discussed in relation to improved geologic understanding. These aspects ultimately led to drilling success in both exploration and appraisal.At the deep Katnook discovery stage several significant problem areas remained unresolved. These related to uncertainties in vertical distribution of gas pay, level of a gas-water contact, and unreliable reserve estimates the result of the inability of conventional log analysis techniques to distinguish gas-bearing from water-bearing sands. Both in the evaluation of Katnook-2 and at the Katnook-3 appraisal stage, expensive cased-hole testing programs were undertaken to determine the size, extent and producibility of the gas accumulation. A key development between drilling Katnook-2 and Katnook-3 was the discovery of carbon dioxide-rich gas at Ladbroke Grove during 1989 in an adjacent structure to the south.The Katnook Field was the first commercial gas field development in the southeast, South Australian part of the Otway Basin, with gas sales commencing in March 1991, within a year of completing field appraisal. The discoveries, and subsequent development, have led to a renewed focus on the Otway Basin as a prospective hydrocarbon province.

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THE USE OF OIL FINGERPRINTING TO ENHANCE FIELD PRODUCTION ON BARROW ISLAND

The APPEA Journal ◽

10.1071/aj98023 ◽

1999 ◽

Vol 39 (1) ◽

pp. 408

Author(s):

A. Pitchford ◽

S.C. Teerman ◽

P.A. Clark

Keyword(s):

Structural Model ◽

Poor Quality ◽

Geological Model ◽

Reservoir Properties ◽

Water Contact ◽

Well Control ◽

North East ◽

History Of ◽

High Production ◽

Oil Water

Oil production from well B28 completed in the Windalia Sand Reservoir of the Barrow Island Field was anomalously high in comparison to surrounding wells. Reservoir properties evaluated from the well could not account for the high production rates. Oil fingerprinting, which is a reservoir-geochemistry technique based on the gas chromatographic character of oil, was applied to identify the reservoir affiliation of the additional oil. The oil fingerprinting indicated that the oil from the B28 well is geochemically similar to oil from the deeper Flacourt Formation Reservoir.The results of the oil fingerprinting prompted a re-evaluation of the existing geological model in the area of well B28. The well intersects the Barrow Fault within a downthrown sliver of Windalia Sand. A large volume fracture stimulation over this interval may have opened the Barrow Fault to the underlying upper Flacourt Formation Reservoir. However, the structure outlined by the oil-water contact in the upper Flacourt Formation Reservoir had been mapped as a four-way dip closure 500 m north east of the B28 well. A review of the local stratigraphy identified a thin sand (the B28 sand), at the top of the Lowendal member of the IYluderong Shale, which could form a conduit from the Barrow Fault to the nearby upper Flacourt Formation Reservoir. The interpretation of the B28 sand conduit also increased the mapped extent of the upper Flacourt accumulation. In December 1997, 41 years after development began on Barrow Island, the B28 sand was successfully targeted by infill well CUM and subsequently developed as an extension to the Flacourt accumulation. Well CUM has the second highest initial production rate (1,360 BOPD) in the history of the field. The application of oil fingerprinting has enhanced the stratigraphic and structural model of an area with limited well control and sparse, poor quality seismic.

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The South Morecambe Field, Blocks 110/2a, 110/3a, 110/8a, UK East Irish Sea

Geological Society London Memoirs ◽

10.1144/gsl.mem.1991.014.01.66 ◽

1991 ◽

Vol 14 (1) ◽

pp. 527-541 ◽

Cited By ~ 9

Author(s):

I. A. Stuart ◽

G. Cowan

Keyword(s):

Early Stage ◽

High Reliability ◽

Irish Sea ◽

High Permeability ◽

The South ◽

Reservoir Properties ◽

Gas Field ◽

Reservoir Performance ◽

Diagenetic History ◽

First Time

AbstractThe South Morecambe Gas Field has been developed as a seasonal supply field to boost supplies to the National Transmission System at times of peak demand. This mode of operation has led to a requirement for exceptionally high reliability in all aspects of the development. This requirement has prompted the generation of an accurate and comprehensive geological model so that reservoir performance can be predicted as reliably as possible, and that wells can be drilled in optimum locations. The exceptional shallowness of the structure (crest at -2400 ft TVSS, GWC -3750 ft TVSS), coupled with the need to drain the reservoir cost-effectively and to minimize the risk of well interference has led to the use of slant drilling techniques for the first time in European waters. The field is located in the East Irish Sea Basin. The Triassic Sherwood Sandstone Gp forms the reservoir, and the Mercia Mudstone Gp provides the seal. The reservoir sands were laid down in a rapidly subsiding basin under continental semi-arid conditions, and comprise a complex interplay of major channel-fill sandstones, secondary channel-fill sandstones associated with non-channelized sheetflood sandstones, and localized, very high permeability (> 1000 md) aeolian and reworked aeolian sandstones. A vertical organization of these facies has been observed, with some intervals dominated by channel deposition, others by non-channelized deposits, due to periodic adjustments of the whole basin, and this has permitted the establishment of a reservoir zonation. A complex diagenetic history is recognized, with several phases of dolomite and quartz cementation. Differential compaction is also a major control on the disposition of reservoir properties. The greatest control on permeability (but not porosity) is platy illite which formed beneath a palaeo-GWC at an early stage in the growth of the structure, and which gives rise to a diagenetic layering of the reservoir into a high permeability Illite-Free Layer and a deeper, low permeability Illite-Affected Layer. The data presented herein is based upon the results of development drilling on South Morecambe.

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