bluuebunny/crossref_metadata_2025 huggingface dataset:
The life cycle of the Netherlands’ natural gas exploration: 40 years after Groningen, where are we now?
Authors: BREUNESE J. , MIJNLIEFF H. , LUTGERT J.
Published: April 2010

The discovery of the giant Permian Groningen Field in 1959 triggered the main phase of gas exploration in NW Europe. This paper deals with the history and future of natural gas exploration in the Netherlands. The aim is to explain the historical exploration process and use the results to predict the remaining part of the exploration life cycle. Data from over 40 years of continuous exploration and production are presented and analysed for relationships between exploration and production (E&P) activity levels (licence area coverage, seismic surveying and drilling rates) and reserves growth. The E&P data are further investigated in terms of the exploration efficiency. After more than 1000 exploration wells drilled, the cumulative reserves growth curve still shows little sign of creaming off. At first sight, this observation would appear to indicate a not very efficient historical exploration process. The paper will try to explain the impact of the underlying dynamic factors such as added information through time, technology development and infrastructure extensions.

Past exploration has revealed part of the total natural distribution of gas accumulations present in the Netherlands subsurface. The best known, i.e. least uncertain, part of the distribution consists of discovered accumulations (although changes in the assessment of this part of the portfolio still occur). Next comes the presently known portfolio of mapped prospects, identified and assessed according to proven play concepts. There is already some of uncertainty as to their actual subsurface volumes. Finally, from the observation that new prospects have been identified even in recent years, it is proposed that the perceived prospect portfolio will also behave dynamically in the future. Indicators of the maturity level and the estimated ultimate potential of the main play areas are derived. Today’s remaining potential is the source of future exploration. However, the actual outcome of future exploration is not determined by geology alone: business activity levels and exploration efficiency will be shown to be at least as important in the prediction of discovery and production rates.
The hydrocarbon potential of the Danish Continental Shelf
Authors: HEMMET M.
Published: April 2010

Considerable remaining resources are believed to be present in several different mature to immature plays and in the already discovered fields in the Danish area. The oil and gas resources and reserves of the Danish Central Graben area are evaluated at 807 × 10
6
m
3
oil and 425 × 10
9
Nm
3
gas. The remaining resources in the mature Chalk play and the less mature Jurassic plays of the Danish Central Graben are discussed together with those of the less mature basins outside the Central Graben. These three examples have been chosen to illustrate the prospectivity as well as the nature and range of the exploration opportunities in the Danish area. The best explored and most successful reservoir (with an exploration success rate of 50%) has, for many years, been the Late Cretaceous and Danian Chalk in the Danish Central Graben. In recent years the Chalk has experienced a revitalization after the discovery of the stratigraphic/dynamic traps in the Halfdan and Halfdan NE fields. Continued incremental improvements in exploration, development and production technology are expected to generate a corresponding increase in reserves from both new Chalk discoveries and increased recovery from existing fields, as well as making smaller and more difficult discoveries commercial. Major reserve potential is believed to be present in the fluvial, shallow-marine and turbiditic Jurassic sandstones of the Danish Central Graben. The encouraging demonstration of porosity preservation at great depths by the recently drilled Hejre-1 and Svane-1 wells, together with the ability of new 3D seismic data to image individual sandstone bodies suggests that new discoveries are likely to be made in these sands. In addition, it is believed that more work using improved technological methods may further the understanding of the exploration potential of the area east of 6°15′ E, especially concerning hydrocarbon generation and timing.
Characterization of the Heimdal Sandstones within Alveim, Quads 24 and 25, Norwegian North Sea
Authors: FITZSIMMONS R. , VEIBERG D. , KRÅKENES T.
Published: April 2010

The economics of small fields commonly mean that more attention is needed to create robust geological models ahead of development. Full integration of available core, electronic log and seismic data is essential to reduce uncertainty. In this paper we aim to illustrate how an iterative integration between disciplines has helped to evaluate prospects within the Alveim discovery as the field is delineated. Alveim lies in the Norwegian sector of the North Sea, within parts of quadrants 24 and 25. The primary play is the Paleocene Heimdal Sandstones, which lie up-depositional dip from the Heimdal gas field. The first exploration wells, (24/6-2 and 25/4-3), had proved the presence of both gas and oil within the area. However, subtle closures and imaging problems within the reservoir had made it difficult to initially assess the potential volumes of the prospect. Furthermore, the hydrocarbon column varied across the development area, partially in response to the complex topography (loft) developed at top reservoir. High-order fan abandonment surfaces were recognized and utilized to understand the gross architecture of the Heimdal fan. The sedimentology and depositional processes of the uppermost sequence were then analyzed through full core description. The resulting model was then tested against the observations made from the most recent, higher resolution, seismic analysis, and was then integrated into the geological model.
Sand injectites: an emerging global play in deep-water clastic environments
Authors: HURST A. , CARTWRIGHT J. A. , DURANTI D. , HUUSE M. , NELSON M.
Published: April 2010

Although long-recognized features in the geological record, the hydrocarbon reserve potential of sand injectites has only recently become apparent. Advances in the quality and resolution of 3D seismic data allow the definition of a range of trap and reservoir geometries that have, in the past, not been deliberately targeted by exploration wells. Sand injectites form a new trapping style. They are intrusive, occuring as discrete traps and in combination with structural and stratigraphical features. Dykes, sills, emergent sills, scalloped tops and irregular bodies are identified as trapping styles. Reservoir quality is typically homogeneous and good, even when in an overall low net:gross system. The North Sea Palaeogene, in which at least 2.4 × 10
9
BOE reserves are associated with injectite fields, or fields modified by sand injection, is used as an example of sand injectite plays. Statistically, the additional reserve potential for sand injectites in the North Sea Palaeogene is high. Globally, the presence and significance of sand injectites is largely overlooked. As most sand injectite reservoirs of commercial significance develop during early burial and are associated with overpressure, play concepts are developed that combine mechanisms for overpressure development with sedimentology. Recognition of the presence of sand injectites will have a major affect on many deep-water and other plays both in terms of exploration and production.
The North Sea Chalk: an underexplored and underdeveloped play
Authors: MEGSON J. , TYGESEN T.
Published: April 2010

Chalk fields in the North Sea have seen recent large increases in recovery factors and a lowered limit on the effective permeability of reservoirs that can be developed. For example, the Halfdan Field in Denmark has an effective permeability of 0.5mD. As a result the industry expects to recover significantly more hydrocarbons from most Chalk fields but, in addition, there is an additional source of upside in existing fields, which is the dynamic trap. Due to the low permeability of the Chalk, hydrocarbon migration and re-equilibration occurs over geological time-scales. Examples of these types of traps are the Halfdan and South Arne fields in the Danish sector and, possibly, the Joanne Field in the UK. All these fields have strongly tilted free-water levels (FWLs). The implications are that reserves downflank of discoveries may be overlooked, as was the case with the South Arne Field, developed 30 years after discovery following the drilling of better reservoir downflank and tilted FWLs. Another example is the Halfdan Field, which was discovered in 1999. The oil legs in the Halfdan and Dan fields are connected, but Halfdan was not discovered until 1998, although Dan has been producing since 1972. Dynamic trapping mechanisms also suggest enormous additional exploration potential in the North Sea Chalk if the location of migrating hydrocarbons can be predicted. A new type of trap – the constriction trap – is discussed, which is caused by a permeability reduction in the migration direction causing ‘banking’ of hydrocarbons due to the greater influx of hydrocarbons than outflow over geological time. The thickness of post intra-Chalk unconformity Chalk in the Danish sector is used to predict these traps in the Chalk: lateral thinning of the relatively high permeability Tor can potentially create a trap if all the other elements of the petroleum system are in place.
Lower Cretaceous: the next target for oil exploration in the Barents Sea?
Authors: SELDAL J.
Published: April 2010

During the early days of exploration in the southwestern Barents Sea, Lower Cretaceous wedges and mounds were identified on seismic data along the margins of the Hammerfest Basin above rotated Jurassic fault blocks. They were ranked as secondary targets after the giant Jurassic closures in the central part of the basin. Drilling of the latter proved the Snøhvit area gas fields and Snøhvit’s thin oil leg. However, the majority of the wells drilled in the Hammerfest Basin have oil shows in Lower Cretaceous strata. Even the claystones in the most basinal part have oil shows, interpreted by the industry to be remnants of oil leaked from Jurassic reservoirs to the surface. Lower Cretaceous sandstones have also been drilled along the Troms–Finnmark Platform, Loppa High and Senja Ridge, where almost all wells have oil shows. Three wells drilled along the southern margin of the Loppa High have even proved small amounts of oil ranging from 31° API to 38° API and the westernmost well, 7120/1-2, is ranked as an oil discovery. Thick (123–157m) massive sandstones of Valanginian to Hauterivian age in wells 7120/1-2, 7122/2-1 and 7120/10-2 represent the reservoir analogues for a possible Lower Cretaceous oil giant. The Gamma gas discovery 7019/1-1 at the eastern margin of the Tromsø Basin could be an indication of such a giant. Lower Cretaceous sandstones were also the primary target for 7120/10-2. The reservoir sandstones were deposited as submarine fans and the drilled massive sandstones have good reservoir parameters.
The Buzzard Field
Authors: DORÉ G. , ROBBINS J.
Published: April 2010

The Buzzard Field is one of the largest fields to be discovered on the United Kingdom Continental Shelf in the last 25 years; it has a current reserves estimate of over 400 × 10
6
BBL. It lies some 50 km northeast of the Scottish mainland and 20 km west of the Ettrick Field in a water depth of 300 ft.

The Buzzard Field was discovered in May 2001 by well 20/6-3. This well encountered high quality 32° API oil trapped within a latest Oxfordian to Early Volgian age reservoir informally defined here as the Buzzard Sandstone Member. The side-track penetrated an oil–water contact at 9194 ft TVDSS, establishing a minimum hydrocarbon column of 750ft. The field was the subject of an appraisal programme in late 2001 and early 2002, with eight wells and side-tracks drilled to define the field extent. These wells, coupled with a continual improvement in the quality of the seismic data, have helped to reduce the uncertainty associated with estimates of the STOIIP and reservoir geometry.

The trapping mechanism for the field involves a complex stratigraphic pinchout of reservoir sands within shales of the Kimmeridge Clay Formation. This is combined with a downthrown faulted closure against Palaeozoic rocks. The Buzzard Sandstone Member comprises base of slope, submarine gravity flow sands with excellent porosity and permeability characteristics.
Depositional and structural controls on Triassic reservoir performance in the Heron Cluster, ETAP, Central North Sea
Authors: McKIE T. , AUDRETSCH P.
Published: April 2010

The Heron Cluster fields form part of the Eastern Trough Area Project, an integrated development of a total of seven fields. The main reservoir within the cluster is the Triassic Skagerrak Formation (with undeveloped Jurassic Pentland Formation in Heron and Egret). The fields are classified as HPHT reservoirs, with initial pressures and temperatures of 9300–12 900 psi and 300–350°F respectively. Development of these fields initially assumed that the Skagerrak would be well connected and likely to have an active aquifer. However, initial production from Heron in 1998 revealed a dramatic pressure decline, indicating that the reservoir was more compartmentalized than anticipated, with little or no aquifer, necessitating a revision to the reservoir model. The Skagerrak can be subdivided into an upper, more channel-dominated interval and a lower, poorer quality, more unconfined fluvial section, bounded below by the largely playa Marnock Shale and above by the lacustrine Heron Shale. Re-description of the reservoir suggested a setting dominated by terminal splay deposits, arranged into cycles bounded by a hierarchy of shales, which formed laterally persistent, effective barriers to vertical flow. Additional perforations through the Skagerrak section encountered near virgin pressures and restored production profiles to prognosis. Egret came on-stream in 1999 with a single vertical well and again showed a rapid pressure decline, in this case additionally due to fault compartmentalization. However, it was observed that the reservoir was re-charging during shut-in periods, suggesting that the faults were transmissible with sufficient pressure drawdown. With experience from Heron and Egret on vertical compartmentalization and fault transmissibility, Skua was brought on-stream in 2001 with a single horizontal well designed to intersect as much stratigraphy as possible. The Skagerrak reservoir in Skua also exhibits Egret-like recharging across faults. Overall the Skagerrak reservoirs in the Heron Cluster appear to have the following common characteristics: good lateral connectivity, but poor to zero vertical connectivity; large faults become ‘leaky’ with sufficient pressure drawdown, and there appears to be no aquifer support. The short term production behaviour of these reservoirs is not representative of their longer-term behaviour, and in particular, short-term well tests indicate a level of compartmentalization that does not materialize during production.
The Caister–Murdoch System (CMS) III Carboniferous cluster development, UK Southern North Sea
Authors: COOPER M. M. , EASTON S. D. W. , LYNCH J. J. , FOZDAR I. M.
Published: April 2010

The Caister–Murdoch System (CMS) III development comprises five separate Late Carboniferous Westphalian gas accumulations that surround the CMS transport hub in Quadrant 44 of the UK Southern North Sea: Hawksley, Murdoch K, McAdam, Watt and Boulton H. All are relatively small, single-well discoveries and most have been lying undeveloped for several years.

The following factors have contributed to their development: new techniques for seismic mapping and visualization have allowed a more complete understanding of the field geometries and trapping styles and greatly facilitated well design and reduced planning costs; a better understanding of Carboniferous reservoirs, including a more detailed sub-division of the Westphalian B and C/D that has led to more optimal targeting of the development wells; a unitized agreement between the parties who have equity in the satellites and transportation systems negotiated prior to project sanction; and the consecutive development of five fields reducing the overall cost and risk of the project.
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 Magnus Field: extending field life through good reservoir management and enhanced oil recovery
Authors: MACGREGOR A. G. , TRUSSELL P. , LAUVER S. , BEDROCK M. , BRYCE J. , MOULDS T.
Published: April 2010

The Magnus Field has been on production since 1983. Production of oil is from intra-Kimmeridge Clay Formation age turbidite sandstones. The individual lobes of the turbidites are generally fining-up, or have fine tops. Waterflood production tends to sweep the lower part of the units very effectively, thus leaving an unswept oil target at the top of many flow units. An enhanced oil recovery (EOR) scheme has been implemented on the Magnus Field by bringing gas, which had no access to a market, from the Foinaven and Schiehallion fields West of Shetland. Because the gas is mainly methane it is taken via the Sullom Voe Terminal (SVT) on the Shetland Islands where it is enriched by injecting higher molecular weight gases. This enrichment improves the effectiveness of the EOR process at Magnus. The scheme adds value not only at the Magnus Field but also to the West of Shetland fields and at SVT. The gas can also be used as fuel to replace diesel at SVT, bringing environmental benefits.
Designer wells to maximize recovery for Otter Field development, Northern North Sea
Authors: HARKER S. D. , LONGIS C. , ROUX J.-F. , LIVINGSTONE L. , THOMAS H. , MILNE K. , HOLM G. , STROMBERG S.
Published: April 2010

The 2002 to 2003 Otter Field development drilling campaign utilized a combination of detailed trajectory planning and integrated geosteering techniques. The objective of this work was to maximize oil recovery, with a minimal number of wells, from the complexly faulted Otter structure. To achieve this, subhorizontal production wells were planned to track near top reservoir, through the structural culminations, to connect adjacent fault blocks. Otter is the most northwesterly of the Brent Province fields of the Northern North Sea, located in UK blocks 210/15a and 210/20d, 530 km north of Aberdeen, operated by TOTAL with partners Shell U.K. Exploration and Production, ExxonMobil and Dana. The field was discovered by the Phillips 210/15-2 well in 1977 (then called Wendy) and appraised by Fina well 210/15a-5 in 1997, following 3D seismic acquisition in 1994. The decision to proceed with development was confirmed after the success of appraisal well 210/15a-6 drilled by TotalFina in 2000.

The Otter structure is an easterly dipping tilted panel that is divided into four major blocks and several minor blocks by a network of subsidiary faults. The reservoir is the Middle Jurassic Brent Group, with the uppermost Tarbert Formation shallow marine sandstones comprising the main producing target. The oil source rock is the Late Jurassic Kimmeridge Clay, present in the off-structure areas, though locally absent over the Otter Field area. Top seal is provided by the Mid- to Late Jurassic Heather Shales. The Otter oil is a medium gravity crude (36.5° API) with a GOR of 79m
3
/m
3
(443 scf/bbl), in a normally pressured reservoir at a crestal depth of 1970m subsea. Otter well planning was conducted using a 3D geocellular model based on interpretation of both conventional and acoustic impedance inversion seismic datasets. Apilot study, prior to development drilling, included geochemical and petrophysical reservoir unit definition and the forward modelling of LWD log response in sub-horizontal wells. The results of these studies were used to aid geosteering, incorporating real time chemostratigraphy and LWD data at the wellsite. In addition, borehole resistivity images while drilling were used to assist in structural interpretation in real time and thus to guide the well trajectory to maximize the pay section. A key component in using these new technologies was the office-based integration of all the data via web-based monitoring of the operations.

Three production wells target the culminations at the extremities of the Otter Field, supported by a downdip water injector, all drilled from a centrally located subsea template. Following the successful drilling of the first production well, 210/215a-T1, production start-up was in October 2002, via subsea tieback to the Eider facility.
A late life opportunity: using a multidisciplinary approach to unlock reserves in the Rannoch Formation, Ninian Field
Authors: MATTHEWS S. , THURLOW A. D. , AITKEN F. J. , GOWLAND S. , JONES P. D. , COLVILLE G. J. , ROBINSON C. I. , TAYLOR A. M.
Published: April 2010

Over 10
9
BBL oil have been produced from the Ninian Field. Although the Rannoch Formation is known to contain 10% of the field STOIIP, yet less than 5 × 10
6
BBL of production can be allocated to this formation. The low permeability Rannoch Formation produced low watercut oil at low oil production rates. Other, higher permeability, Brent Group zones produce at higher rates and have been preferentially perforated. Unable to contribute to production when higher permeability reservoir zones were co-produced, the Rannoch Formation became enclosed by highly swept reservoir zones. This lack of production contribution indicated a requirement for dedicated production from the Rannoch Formation. However, historical production rates were uneconomic. Any strategy for economic exploitation of the Rannoch Formation was partly hindered because the distribution of productive sands in the Rannoch Formation was not previously understood, rendering the production performance unpredictable. In addition, this formation is seismically unresolvable. A sedimento- logical reappraisal of the Brent Group resulted in a depositional facies scheme. This provided a correlatable framework within which the depositional context and heterogeneity of the Rannoch Formation could be understood. This formation predominantly comprises middle shoreface sandstones with subordinate higher permeability upper shoreface facies. Cyclic stacking of these deposits defines parasequences with a clinoform geometry. A scoping sector simulation model was built to assess the Rannoch Formation production capability. This concluded that a horizontal well, combined with artificial lift, would deliver maximum, economic, production. The well was to be maintained within productive upper shoreface sands,
c.
10′ thick and within the Rannoch Formation interval,
c.
40′ in thickness, and drilled utilizing a joint geosteering and biosteering approach. The well penetrated 490′ of productive upper shoreface sand within a 1700′ horizontal section, flowed at economic rates and is predicted to produce 10% more oil than the basis on which the well was justified.
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.
Challenges of developing Carboniferous gas fields in the UK Southern North Sea
Authors: CORBIN S. , GORRINGE S. , TORR D.
Published: April 2010

The Carboniferous, as one of the three major productive intervals in the UK Southern North Sea, has considerable future potential, particularly as national demand for gas exceeds production. Almost 3 × 10
12
SCF are under development in the southern Quad 44 area, more than 600 × 10
9
SCF reserves discovered await development and the potential for yet-to-find reserves is recognized. Most of the undeveloped assets have transferred ownership a number of times and only now are operators and partner groups going ahead with development. The subsurface, engineering and commercial challenges that face those operators are outlined.

The Carboniferous reservoir sandstones are relatively thin and cannot be mapped directly using 3D seismic data. Because they are separated by non-reservoir shales and siltstones, understanding the three-dimensional distribution of these sandstones is critical to ensure optimal well placement, maximum exposure to the reservoir and, ultimately, recovery of gas. Trap definition and size depend upon accurate seismic time-to-depth conversion of a complex overburden. Halokinesis, lateral velocity variations, erosional unconformities and wedges of low velocity sediments all need to be addressed in order to generate the best time-to-depth conversion.

Gas in Carboniferous reservoirs is richer in inert gases, CO
2
and N
2
, than is gas from the Rotliegendes fields. These two gases contribute to reducing its calorific and commercial value, necessitating blending with higher quality gas or the removal of the inert gases before acceptence for entry into onshore distribution networks. This relies on the ability, willingness and capacity of host facility operators to accept this gas through their infrastructure. Negotiations to allow blending and acceptance of lower calorific value gas, to no detriment to the user, and the removal of inert gases will result in continued development of the Carboniferous fields. It may also encourage further exploration of the Carboniferous once a market and an off-take route to that market are established.
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.
Biodegradation, gas destruction and methane generation in deep subsurface petroleum reservoirs: an overview
Authors: LARTER S. R. , HEAD I. M. , HUANG H. , BENNETT B. , JONES M. , APLIN A. C. , MURRAY A. , ERDMANN M. , WILHELMS A. , DI PRIMIO R.
Published: April 2010

Plate tectonics forms and destroys sedimentary basins, accumulating organic carbon and converting it into mobile petroleum which may be concentrated in reservoir traps in which, if temperatures are below 80°C, it may become biologically degraded (biodegraded). The biodegradation process produces altered, denser, heavy oils and methane as a primary product. Much of the world’s oil is biodegraded under anaerobic conditions, with methane being a major by-product of the action of the deep biosphere on petroleum when sulphate is not present as an oxidant. A review of the literature relating to destruction of wet gas and the systematics of methane generation during subsurface oil biodegradation concludes that large biodegrading oil fields may be major source systems of dry gas.
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.
NE Atlantic break-up: a re-examination of the Iceland mantle plume model and the Atlantic–Arctic linkage
Authors: LUNDIN E. R. , DORÉ A. G.
Published: April 2010

Final break-up of Pangaea – opening of the NE Atlantic (NEA) and the Arctic Eurasia Basin – was associated with significant magmatism (in the NEA) and is commonly ascribed to thermal effects from a proto-Iceland plume. The plume is often assumed to be fixed with respect to the Earth’s core and to have governed NEA break-up. It is argued here that the Iceland anomaly, past and present, cannot represent a fixed plume, nor be rooted at the core–mantle boundary and that the Greenland–Faroes Ridge is inconsistent with a classic time-transgressive hotspot track. It is shown that the Iceland anomaly has probably been located at the constructive plate boundary (Mid-Atlantic Ridge and antecedents) since its inception. While recent studies allow for some ‘wandering’ of hotspots relative to the core and mantle, it is considered unlikely that such drift of a mantle plume would precisely match lithospheric drift in order to achieve constant centering on the spreading ridge. The alternative view is, therefore, supported – that the anomaly is an upper mantle response to plate break-up. The two pulses of NEA magmatism are related to separate phases of North Atlantic break-up. Early Paleocene magmatism (c. 62–58 Ma) was governed by a short-lived attempt at seeking a new rift path, intermediate in time and space between the Labrador Sea–Baffin Bay and the NEA–Eurasia Basin rifts. The voluminous Early Eocene magmatism (c. 56–53 Ma) along the NEA margins was related to final break-up of Pangaea, exploiting the collapsed Caledonian fold belt. The interpretations here are at odds with Iceland representing a classic Morgan-type plume and it is suggested that the magmatism in the NEA and the Iceland anomaly represent a ‘top-down’ effect of plate tectonics.