bluuebunny/crossref_metadata_2025_split huggingface dataset:
Ardmore Field: rebirth of the first offshore oil field, UKCS
Authors: GLUYAS J. G. , MAIR B. , SCHOFIELD P. , ARKLEY P. , McRAE D. 
Published: April 2010

The UK’s first offshore oil production began in June 1975 from the Argyll Field. In a 17-year period the field produced 72.6 million barrels of sweet, light crude. However, in 1992, production from the field became uneconomic, the field was abandoned, all wells were plugged and the facilities removed. In January 2002 two new oil companies, Tuscan Energy and Acorn Oil and Gas, were awarded the licence to redevelop the Argyll Field – now renamed Ardmore. A field development plan was submitted to the DTI and approval granted in October 2002. The first Ardmore well was drilled in the summer of 2003 and ‘second’ oil flowed in September 2003.
Ardmore is a geologically complex field with four distinct reservoirs, of which the three oldest appear to be in both pressure and fluid communication. During the ‘Argyll’ production years (1975–1992), vuggy, karstified, Zechstein carbonates were then interpreted to have delivered about 80% of their oil in place. Rather than reflecting an error in volumetrics (underestimated STOIIP) the oil is interpreted to have come from the underlying Rotliegend and Devonian sandstone reservoirs. Natural aquifer support was significant for the Rotliegend, and probably the Zechstein reservoirs, while the volumetrically dominant Devonian reservoir produced via pressure depletion. Recovery from Jurassic sandstones on the west flank of Ardmore was minimal.
Vertical and low deviation subsea wells tied back to a floating production system were used for the initial development of Argyll. As production progressed, the increasing water cut and lower reservoir pressure required artificial lift for most wells. The limited amount of gas available restricted the number of wells which could be produced. There were several wells drilled late in field life which tested oil using nitrogen gas lift but which were abandoned without being produced due to the restrictions of the gas lift system. Argyll was abandoned in 1992 with an average water cut of about 70%. Detailed subsurface studies, integrating the geology, geophysics and petrophysics with the 17 years of dynamic data, have led to a better understanding of the field performance and have allowed new development targets to be identified. The redevelopment of the field targets a combination of attic oil in Zechstein, bypassed oil in the Rotliegend, resegregated oil in the Zechstein and Rotliegend and unproduced but proven oil in the Devonian.
The global gas renaissance: opportunities for innovative exploration plays and new technologies in existing fields and unconventional gas resources in the liberalized gas market place: overview
Authors: BURLEY S. D. , IRESON D. 
Published: April 2010

Of all the fossil fuels, natural gas is environmentally the cleanest, having a lower carbon content with respect to energy output than either coal or oil. Global demand for gas has risen steadily over the last decade and forecast demand growth now outstrips all other major energy sources. These two factors should dictate that gas will remain the energy source of choice until renewable alternative energy sources become readily and economically available.
The UK is set to face a shortage of proven indigenous gas reserves. However, the known conventional global resources of natural gas are very significant, with reserves projected to last for 60 years at current production levels, and expected un-discovered resources predicted to exceed this figure. In addition, huge volumes of ‘unconventional’ gas resources are trapped in hydrates on the seafloor, in coal beds, in low-permeability sandstone reservoirs (so-called ‘tight gas sands’) or in shale deposits. Whilst the global resource base is good, the UK is set become a net importer of gas as the scope for significant new conventional resources is small, UK gas production is already very efficient, and opportunities for unconventional resources are limited.
Traditionally, natural gas has been viewed as a stranded asset when located far from markets. However, since natural gas can now be efficiently converted to a liquid by cooling to −160°C, and then economically transported in ships, gas is now a mobile commodity like oil. The bottleneck of the European Interconnector, once seen as the key to UK gas supply, has thus been circumvented. Liquified Natural Gas (LNG) is being transformed from a small volume, exotic trade into a sophisticated global spot market, opening global gas exploration and production to deep waters and plays far removed from markets.
Additionally, the steady advance of technology has played and will continue to play an active role in developing new gas exploration plays, optimizing recovery factors and rapidly monetizing reserves. Unconventional sources of gas will undoubtedly provide additional significant reserves, but on a timescale of ten years and beyond. The future of natural gas looks assured for some time to come.
The world according to gas
Authors: ODEDRA A. , BURLEY S. D. , LEWIS A. , HARDMAN M. , HAYNES P. 
Published: April 2010

Proven global reserves of conventional natural gas are immense, with some 5500 × 10
12
SCF recognized world-wide, sufficient for around 60 years supply at current global gas production rates. However, total global growth in demand for gas is expected to average 3.2% over the coming decade and is projected to double by 2025. Along with accelerating liberalization of gas markets, this growth in demand will generate huge opportunities for gas explorers and producers. The exploration and reservoir engineering challenges are to find and produce three times more gas over the next 20 years than the industry has found in cumulative total since 1970. Current estimates suggest that 50% of conventional gas resources have been discovered to date. These resources are well characterized and exploration will have to extend deeper into sedimentary basins, in deeper waters, and in new plays, as well as creatively re-evaluate current acreage, to discover additional conventional natural gas. Tertiary deltas will be a major exploration play over the next decade.

In the future, unconventional gas resources will be used increasingly to supplement high volume demand in developed markets and as a major longer-term source of energy. Natural gas in low permeability sandstone reservoirs, coal beds and fractured shale already accounts for more than 25% of natural gas production in the USA. Additionally, enormous volumes of natural gas are generated by methanogenic bacteria during early burial in marine sediments, much of which then contributes to frozen methane hydrates on the continental slopes. At present, much of this unconventional natural gas is categorized as hypothetical and requires fundamental scientific research before it can be considered as an economic resource.
Historically, the commercial imperative has been to find gas close to markets. Shipping of liquefied gas, liquid gas derivatives and potentially solid methane hydrates (LNG, GTL and GTS technologies) around the globe, are changing the traditional patterns of gas exploration, transportation and market supply as new producers and demand centres emerge. LNG has already been transformed from a small volume, exotic trade into a sophisticated global market and GTL is likely to follow, opening global gas exploration and production to deep waters and plays far removed from markets.
Key challenges to realizing full potential in an emerging giant gas province: Nile Delta/Mediterranean offshore, deep water, Egypt
Authors: DOLSON J. C. , BOUCHER P. J. , SIOK J. , HEPPARD P. D. 
Published: April 2010

The Nile Delta is an emerging giant gas province with proven reserves of approximately 42 × 10
12
SCF. This resource has more than doubled in the last three years, largely from successful deep water exploration for Pliocene slope-channel systems. Proven reservoirs vary in age from Oligocene through Pleistocene. Source rocks include Jurassic coals and shales and the Lower Miocene condensed Qantara Formation shales. Additional source rocks may be present in condensed intervals of Cretaceous, Oligocene and Eocene age.

Following Tethyan rifting and opening of the Mediterranean in the Jurassic, prominent Cretaceous mixed clastic and carbonate shelf edges aggraded vertically along a steep fault-bounded shelf-slope break (the ‘hingeline’) in northern Egypt, which exerts the fundamental control on reservoir distribution in Tertiary age strata. In late Eocene time, northern Egypt was tilted toward the Mediterranean during regional uplift associated with the opening of the Gulf of Suez and Red Sea rifts. Drainage systems shed reservoir quality sediments northward in a series of forced regressions. These regressions culminated in be-heading of the youngest deltas by subaerial erosion during the Messinian salinity crisis. Early Pliocene transgressions laid a thick sealing interval over the low-stand Messinian valley networks. Renewed deltaic deposition began at approximately 3.8Ma.
The steep structural hingeline and faulted continental shelf created a large amount of accommodation space with relatively minor progradation of depositional systems. As a result, the primary play consists of slope-channel fairways in all levels. The Pliocene systems are the shallowest targets in the basin and future large reserve growth will come from the pre-Messinian strata.

Nile Delta gas resources lie close to emerging and established markets in the Mediterranean. Challenges to capturing the deeper pre-Messinian prize include:

establishing favourable economic terms for export and domestic markets;

reducing drilling costs and optimization of wellbore patterns to develop multiple stacked objectives;

working in deep water and high pressure environments;

developing predictive models for pressure regressions in overpressured reservoir fairways;

recognizing and exploiting thin bedded low resistivity pay.
Surface geophysical monitoring of gas fields: some experiences
Authors: EIKEN O. , TOLLEFSEN T. , AANVIK F. , ALSOS T. 
Published: April 2010

Gas production has some different reservoir technical challenges compared to oil production, due to higher mobility of the hydrocarbons. Wider spatial distribution of wells and less infill drilling make estimates of remaining reserves, and optimization of production rates and late field life, particularly important objectives for reservoir monitoring. Changing a water-flushed zone from initial to residual gas saturation may cause modest changes in seismic velocities, and more significant changes in densities. Changes in the seismic response may be modest, while mass changes may be detectable by gravimetric monitoring. Decreasing pore pressure causes slight velocity increase, sometimes too small to observe in time-lapse seismic data. Surface or seafloor subsidence may be included in the reservoir monitoring program.
2D seismic and gravimetric monitoring has been selected as surface geophysical monitoring techniques for Troll gas production, for reasons of cost and quality After six years of production, a change in response at the gas–liquid contact can be observed both on seismic and gravimetric time-lapse data, and pressure depletion has caused a slight time-shift. On the Sleipner East Field, water rise has been mapped by combining 4D seismic and repeated well saturation-log data, and this information has been used in planning of new wells and in the further reservoir management. Geophysical monitor programs have further been initiated on the Midgard and Snøhvit gas fields. These are expected to provide important input to predictions of production behaviour, to enable timely actions in the reservoir management, and hence to increase the value of the asset.
Armada Phase II and Seymour Phase I
Authors: SAMUEL A. , TAYLOR C. , RICHARDS S. , WARBURTON I. , HIGHTON P. 
Published: April 2010

The Armada development comprises three gas-condensate fields in the Central North Sea: Fleming (Paleocene Maureen Formation reservoir), Drake and Hawkins (Upper Jurassic Fulmar Formation reservoirs). Armada came on streamin 1997, with seven Phase I wells producing at a plateau rate of 450 × 10
6
SCFD. A Phase II drilling campaign, comprising three Armada wells, was implemented in 2002 with the aim of extending the duration of the Armada production plateau and, where possible, accessing new reserves. The first well was a relatively straightforward Paleocene Maureen Formation producer, although the target was revised based on a new seismic attribute study, which revealed important heterogeneities in this deep-marine reservoir. The second well targeted the undrilled western compartment of the Hawkins discovery. Unfortunately, the Fulmar Formation was water-wet with no evidence for any hydrocarbon charge, despite the fact that gas had been proved by an earlier exploration well in a downdip compartment. Fortunately, to mitigate the risks, which had been recognized pre-drill, the well had been designed with a secondary Paleocene Maureen Formation target which came in better than prognosed.

A significant aspect of the Armada Phase II programme was the extensive integration across a number of disciplines. The combined team was soon able to propose a convincing explanation for the failure of West Hawkins, giving comfort that East Hawkins should be fully charged and was worth drilling. The final Phase II well was therefore targeted on East Hawkins, although it was a difficult well to plan as the key reservoir horizon had only minor stand-off from the gas–water contact. A number of different well trajectories were considered and 3Dvisualization proved invaluable in ensuring the final well path was optimized. In addition, a major benefit was derived from a recently installed onsite 3Dvisualization centre that enabled the multidisciplinary Armada team to work together very effectively. For example, the drilling engineers were truly able to appreciate what was driving the geotechnical requirements for the well and vice versa. The well came in very close to prognosis, adding valuable reserves and further extending the Armada plateau.
With a rig on the Armada platform the opportunity was taken to drill the South West Seymour prospect, whose chance of success had increased dramatically after a possible direct hydrocarbon indicator was recognized on an inverted seismic volume. The well discovered hydrocarbons in the primary target, the Fulmar Formation and also in the Pentland Formation and was immediately side-tracked to a previously planned updip Fulmar development location.

Supplementary material:
The movie referred to in the article is available at
https://doi.org/10.6084/m9.figshare.c.4811091
Cross-flow to enhance gas recovery in the Dalton Field, East Irish Sea
Authors: KING T. R. , WANNELL M. , ALQASSAR T. M. 
Published: April 2010

Dalton is a sub-sea gas field located in Block 110/2b of the UKCS in the East Irish Sea Basin. The field has been the subject of downward reserve revisions through its life based on increased geological understanding from well, production and simulation data. An innovative infill technique is proposed to reverse those trends and increase recovery by harnessing stranded reservoir gas.
Dalton was discovered in 1990 by well 110/2b-9 which encountered a dry gas column of 345 ft within the Ormskirk Sandstone Formation of the Triassic Sherwood Sandstone. The field was developed in 1999 by wells 110/2b-R1 and 110/2b-R2. Wells were located on the eastern field crest in order to attain maximum gas column and maximize recovery from the good quality reservoir (average permeability >50mD). Production tests showed the majority of flow from the wells to come from thin, high permeability (>200mD) aeolian sands. Two smaller highs located in the west and south, separated from the eastern crest by a saddle and normal faults, were not drilled and were assumed to be in communication through the good quality reservoir and open intra-reservoir faults with the field crest in the east. The risk of fault sealing in the high permeability, high net reservoir was considered to be low.

Initial gas production in 1999 of 100 × 10
6
SCFD was followed by a rapid decline to 15 × 10
6
SCFD early in 2001. This rapid decline suggests more complex reservoir geology than was anticipated, with barriers to field-wide reservoir communication occurring due to faulting or variation in reservoir quality. Geological, production and simulation data suggest that current wells located on the eastern crest are not accessing gas reserves elsewhere in the field due to sealing of major intra-reservoir faults. Field production has led to a significant pressure difference between the eastern fault compartment and the rest of the field. A horizontal well is planned to connect the western and eastern fault blocks and induce cross-flow of gas across the sealing fault into existing wells via the high permeability aeolian beds. The horizontal well will not be completed or tied back at surface and, hence, if successful, will be a low cost solution to increasing Dalton Field reserves.
UK shale-gas resources
Authors: SELLEY R. C. 
Published: April 2010

In the USA gas has been produced from shale in commercial quantities for nearly two centuries. Production commenced in New York State in 1821, when wells were located by market and drilled with little appliance of science. Subsequently, production has been established in five shale-gas systems: the Ohio Shale (Devonian) of the Appalachian Basin, the Antrim Shale (Devonian) of the Michigan Basin, the New Albany Shale (Devonian) of the Illinois Basin, the Barnett Shale (Upper Carboniferous) of the Fort Worth Basin, and the Lewis Shale (Cretaceous) of the San Juan Basin. A recent study by the USGS concluded that total in place US shale-gas resources are in the order of 497–783 × 10
12
SCF with estimated recoverable resources of 31–76 SCF.

Gas produced from organic-rich shales is of both biogenic and thermogenic origin, with matrix permeabilities of some 0.001D. For commercial production this is enhanced by fractures, natural or artificial. Shale gas has high calorific values (
c
.1200 btu), and is commonly wet, with over 10% ethane. After initial high-pressure ‘blows’ wellhead pressures stabilize at 300–500 psi with flow rates of between 50–100 cubic feet of gas per day and depletion rates of 10% pa. One shale-gas well may provide enough energy for a school, a hospital or a housing estate for decades. The economics of shale-gas production is too small to be of commercial interest to major energy companies, but is viable in the USA, where petroleum exploration and production may flourish on a cottage industry scale.

Exploration for shale-gas requires a somewhat different mindset from that of conventional petroleum exploration, and a completely different technology, both in terms of petroleum genesis, seismic prospecting, well drilling and completion.
Some 20 years ago it was suggested that, by analogy with the USA, the UK may possess considerable reserves of shale-gas. This was predicated on the assumption that shale-gas only resulted from the thermal maturation of organic-rich shales. Subsequently, it has been realized that shale-gas can be formed by methanogenic bacteria acting on organic-rich rocks, irrespective of age and thermal history, and especially as a result of post-glacial flushing of aquifers. This realization enhances British shale gas resources dramatically, making any fractured organic-rich shale prospective. Potential British shale-gas petroleum systems include the thermally overmature Caledonide fold belt, the Lower Carboniferous thermally mature basinal shales of northern England and the Midland Valley of Scotland. The Jurassic (Lias, Oxford and Kimmeridge) clays may have considerable potential for thermogenic and biogenic shale-gas. The leaner Lower Cretaceous (Wealden) and Eocene (London Clay) formations of southern England may have minor potential for biogenic shale-gas.
Paleocene exploration in the Faroe–Shetland Channel: disappointments and discoveries
Authors: SMALLWOOD J. R. , KIRK W. J. 
Published: April 2010

While the early drilling in the UK West of Shetlands area was concentrated on structural highs, the 1992 discovery of oil in the deep-water Paleocene sands of the Foinaven Field re-invigorated exploration interest in hydrocarbon traps with a stratigraphic element and encouraged a high level of participation in the UK 16th Licensing Round (1995) west of Britain. Many of the main exploration targets in these rounds were mapped as sand pinchouts onto either the basin margin or onto intra-basinal structural highs, for example, updip to the southeast of the 1989 well, 205/9-1. Few of the initial wells drilled to test this type of pinchout play were commercially successful but, as part of the exploration effort, a large area of the basin was blanketed with 3D seismic data on which more subtle features could be recognized. Seismic anomalies similar to those of the successful discoveries were sought on the new 3D data, as this type of play relied heavily on seismic attributes to help define risks and reserve size. The Foinaven and Schiehallion fields have a suite of attractive seismic characteristics and exploration effort was driven by the search for similar seismic anomaly features throughout the Atlantic Margin. As wells were drilled on 16th Round acreage, some of the targeted seismic reflection anomalies, originally seen as direct hydrocarbon indicators, turned out to have different causes. Representative examples are shown from the central part of Quadrant 205 in which tuning, seismic artefacts, porosity effects and unexpected igneous lithologies contributed to the drilling of unsuccessful exploration wells. The variation with depth of rock physics trends in the area are shown, the characteristics of some direct hydrocarbon seismic indicators are modelled and comments are made on the sensitivity of the modelled seismic response to shear velocity estimation.
The former ‘White Zone’ or undesignated area, the previously unlicensed acreage between the UK and Faroe Islands, was opened through the Faroes 1st and the UK 19th Licensing Rounds in 2000 and 2001. By 2003 the first 8 of 15 commitment exploration wells were drilled in these licenses. Together with an assessment of the seismic anomalies and the risks of stratigraphical traps in the area, analysis of the petroleum system led to the siting of the 6004/16-1z well on the structural high of a Cenozoic inversion anticline. The resulting ‘Marjun’ discovery, the first in the Faroes, consisted of a gross 170 m hydrocarbon column in the T10 Early Paleocene interval, thus opening a new fairway in the area. The challenge has evolved in the last five years from finding an effective reservoir in the basinal areas to the search for a robust trap with an intact sealing lithology.