United Kingdom Continental Shelf Research Articles

Selective Flotation of Casing From a Floating Vessel

Summary This paper outlines a new technique for running production casing from semisubmersible drilling rigs on highly deviated wells that was used for the first time on the Captain field, United Kingdom Continental Shelf (UKCS), operated by ChevronTexaco. The process, which incorporates selective-flotation techniques in which air at atmospheric pressure is trapped in the bottom of the casing string to lighten the casing during deployment in the high-angle part of a highly deviated well, has been used successfully on four subsea wells to date. This is believed to be the first implementation of this technique on semisubmersible rigs.

Importance of exploration and appraisal drilling to employment in the oil and gas industry in United Kingdom continental shelf

The successive rise in the importance of the oil and gas industry in Scotland has generated tremendous economic growth. Scotland’s dependence on oil and gas related employment has increased dramatically over the years since the first oil strike in the United Kingdom Continental Shelf (UKCS) in September 1969. This study is able to identify that Exploration and Appraisal (E&A) activity within the oil and gas industry in the UK is a strong determinant of the rise and fall of employment. There is a clear and strong positive correlation between these two variables.

Regulation and efficiency: an empirical analysis of the United Kingdom continental shelf petroleum industry

The petroleum industry of the United Kingdom Continental Shelf (UKCS) has been subject to various degrees of regulation. Self-sufficiency, security of supply and developing offshore supply industry triggered government regulations that were seen as interventionary and protectionist. This paper tests the extent to which regulations targeting involvement of British offshore supply industry in the UKCS activity created inefficiencies. Data envelopment analysis (DEA), stochastic frontier analysis (SFA), Malmquist Indices, and standard regression analysis are used to measure the amount and address the source of inefficiencies. We will show that such inefficiencies could not be ruled out. The results provide an important insight into the UKCS production techniques and, more generally, into governments’ abilities to influence private sector behaviour through contracts and tendering.

Technical Innovation in Light Aircraft Aerial Dispersant Application Systems

ABSTRACT Recent changes in legislation within the United Kingdom created pressure for change in the response strategies applicable in the UK offshore environment. To meet the new requirements, innovative technology was required which was capable of speedily delivering a payload of approximately one ton of dispersant. To provide a cost efficient solution, a system was developed capable of being mounted on a non-dedicated aircraft, which can be rapidly adapted to meet the response requirements. This paper describes the design criteria for the system and goes on to detail the development, construction and flight testing programme for the dispersant pods. It then goes on to briefly describe the operational response system which has been established to provide a response for the offshore operators in the United Kingdom Continental Shelf (UKCS). The development represents a significant step forward in providing a low cost, effective solution to changing response requirements using innovative engineering solutions, allowing for potential application in other parts of the world.

The Development of Technology in Response to Changing Legislation1

ABSTRACT As environmental control and awareness increases globally, it is becoming progressively more important to be able to use existing oil pollution response technology in the most cost effective manner. In 1999 the Department of Trade and Industry, who govern offshore operations in the United Kingdom Continental Shelf, set some prescriptive guidelines regarding response capabilities. These guidelines set mandatory response times, to include surveillance and achievable oil quantity combat rates. The operators affected by these guidelines turned to their respective tier 2 and 3 response service providers and it became obvious that these guidelines were not achievable at that time. This poster will provide a case study of how two large oil spill response organisations joined forces to provide their customers with a solution to a potential “operation halting” problem. This solution involved the utilisation of current response equipment and the development of new equipment and operating procedures.

The tectonic and stratigraphic framework of the United Kingdom's oil and gas fields

Abstract Onshore exploration success during the first half of the 20th century led to petroleum production from many, relatively small oil and gas accumulations in areas like the East Midlands, North Yorkshire and Midland Valley of Scotland. Despite this, the notion that exploration of the United Kingdom's continental shelf (UKCS) might lead to the country having self-sufficiency in oil and gas production would have been viewed as extremely fanciful as recently as the late 1950s. Yet as we pass into the new century, only thirty-five years on from the drilling of the first offshore well, that is exactly the position Britain finds itself in. By 2001, around three million barrels of oil equivalent were being produced each day from 239 fields. The producing fields have a wide geographical distribution, occur in a number of discrete sedimentary basins and contain a wide spectrum of reservoirs that were originally deposited in diverse sedimentary and stratigraphic units ranging from Devonian to Eocene in age. Although carbonates are represented, the main producing horizons have primarily proved to be siliciclastic in nature and were deposited in environments ranging from aeolian and fluviatile continental red beds, coastal plain, nearshore beach and shelfal settings all the way through to deep-marine, submarine fan sediments. This chapter attempts to place each of the main producing fields into their proper stratigraphic, tectonic and sedimentological context in order to demonstrate how a wide variety of factors have successfully combined to produce each of the prospective petroleum play fairways and hence, make the UKCS such a prolific and important petroleum province.

The Discovery Decline Phenomenon: Microeconometric Evidence from the UK Continental Shelf

The Discovery Decline Phenomenon (DDP) requires that firm-level discoveries of a non-renewable resource depend, non-linearly, upon cumulative industry wide exploration. In this paper, an optimal rule for the exploration effort that adheres to the DDP is derived. Data from the United Kingdom Continental Shelf (UKCS) are applied to the model where it is found that cumulative exploration is a highly significant determinant of firm-level exploration, and that prices and taxes also determine exploration effort. The 'Hubbert peak’ in discoveries in the UKCS is estimated to be 1989 thereby improving upon previous estimates but also implying that the DDP in this region is already quite advanced.

Site managers and safety leadership in the offshore oil and gas industry

Management commitment to safety is recognised as a fundamental component of an organisation's safety culture ( Reason, 1997. Managing the Risks of Organisational Accidents. Ashgate, Aldershot, UK). However, the role and experiences of site managers in relation to safety have rarely been examined. A survey questionnaire was conducted of 200 Offshore Installation Managers (OIMs) from 157 offshore oil and gas installations belonging to 36 organisations operating on the United Kingdom Continental Shelf. The questionnaire gathered data relating to OIMs' level of experience and style of leadership as well as their knowledge and experience of safety and leadership within the industry. The aims of the study are twofold. The first aim is to investigate the relationship between managers' level of experience and style of leadership with their safety attitudes and behaviour. The second aim is to investigate managers' perceptions of best practice in safety leadership and their beliefs about the key outstanding safety issues. Findings suggest that experience is not the dominant factor in determining leadership style or attitudes to safety, however, the less experienced OIMs and those with more directive styles of leadership were found to overestimate their ability to influence and motivate the workforce. It seems that although managers are aware of best practice in safety leadership, they do not always act in ways consistent with this. They report having considerable difficulty in motivating and controlling some safety crucial aspects of workforce behaviour such as getting workers to accept ownership of safety and getting workers to report near misses. In terms of outstanding safety issues, it appears that improvements still need to be made in a number of areas such as the standardisation of safety culture; the harmonisation of safety practices and procedures across the industry; improved workforce competency and increased workforce involvement in safety activities and decision making.

The Development of Heavy Oil Fields in the United Kingdom Continental Shelf: Past, Present, and Future

Summary In this paper we review progress made in developing United Kingdom Continental Shelf (UKCS) heavy oil fields. Reservoir productivity is compared with existing light oil developments and three categories of heavy oil reservoir are identified, which require the application of different well technologies to achieve acceptable offshore production rates. Case histories from existing developments and fields under appraisal are used to illustrate how advances in technology and effective risk management allow increasingly difficult heavy oil fields to be developed. Finally, the future direction for these heavy oil developments is discussed, looking at the scope for improved oil recovery (IOR) techniques and further technology developments to drive down costs and to increase reserves in fields currently under waterflood or to improve the economics of hitherto subeconomic fields.

The Kopervik fairway, Moray Firth, UK

The Albian–Aptian sand fairway in the Outer Moray Firth of the United Kingdom Continental Shelf, informally referred to as the Kopervik fairway, poses considerable challenges to the explorationist, but has the potential to generate significant commercial reward. After an initial spate of activity in the mid 1970s, the Kopervik Sandstone remained largely ignored as a primary exploration target until the late 1990s, despite its excellent reservoir quality and proven charge. This renewed exploration effort led to a number of successful discoveries. As a result of this activity – and a willingness among operators along the fairway to share information – a large regional database is developing. Drawing on this, we summarize our current and historical understanding of the fairway, using existing discoveries as examples.

Improved Residual Light Oil Recovery by Air Injection (LTO Process)

Abstract A new air injection technique, low temperature oxidation (LTO) process, is described. Improved oil recovery from deep, light oil reservoirs is achieved by removing the oxygen in the injected air by LTO reactions with the residual oil in the reservoir. The product of the LTO reactions is a "flue gas," which displaces the oil. Preliminary results of LTO reaction kinetics and oil recovery have been obtained using four North Sea light oils. The paper also contains some discussion of the safety issues related to air injection offshore. Introduction Gas injection into light oil reservoirs is a proven improved oil recovery IOR technique. The IOR potential for gas injection in the United Kingdom Continental Shelf (UKCS) has been estimated at 1.4 bSTB(1). However, the application of gas injection is limited by gas availability and cost, particularly for many mature fields, with the prospect of abandonment unless economic methods can be developed to extend the field life. Therefore, there is now growing interest in air injection because of its availability. Air injection has been widely used in the past for production of viscous heavy oils, where the heat generated by in situ combustion is a necessary part of the recovery process. Air injection can also be used for the recovery of light oils, but in this case, heat generation is not necessary for the displacement. Some form of oxidation is only required in order to remove the oxygen from the air and prevent it from reaching the production wells. Yannimaras et al.(2) have discussed the benefits of air injection for IOR from deep, light oil reservoirs, wherein the principle objective was to generate flue gas (85﹪ N2, 15﹪ CO2) by in situ combustion. There are a number of ongoing successful air injection field projects, notably in the West Hackberry Field, Louisiana [Amoco(3)]; in Medicine Pole Hills Unit, North Dakota; Buffalo, South Dakota [Koch(4)]; most recently, in the Horse Creek Field, North Dakota [Total(5)]; and Total's proposed LTO pilot test in the H Field in Indonesia(6). In the latter case, core flooding studies were undertaken to investigate the effect of various parameters on oxygen uptake by the oil. Previous field projects and simulation studies have considered that high temperature oxidation (HTO, or in situ combustion) is needed to remove the oxygen and enhance oil recovery. Christopher(7) [see also Yannimaras et al.(8)] used an accelerating rate calorimeter (ARC) to screen light reservoir oils for continuous exothermicity. For light oils they found that about 20﹪ were good candidates for propagating full in situ combustion. This suggests that perhaps a majority of light oils will sustain only low temperature oxidation (LTO). Thus, when the primary objective is only to generate nitrogen and carbon dioxide in situ, then a less intensive oxidation process, without combustion, is sufficient. The focus is therefore on a spontaneous LTO process, which can be applied in all light oil reservoirs with sufficiently high reactivity to react with (and consume) oxygen in the injected air.

A new era for the offshore oil and gas industry on the UKCS

This paper explores the development of the offshore oil and gas industry on the United Kingdom Continental Shelf (UKCS) and particularly the role played by science and technology in that development. An historical perspective is taken in the first instance to place recent developments in context, before exploring the role of science and technology in the 1990s. Three areas of key importance form the basis of the discussion: the maintenance of production from the traditional provinces, the development of new provinces and the mitigation of environmental impacts. The paper demonstrates the crucial role that science and technology plays in each of these areas.

The Trent Gas Field: correlation and reservoir quality within a complex Carboniferous stratigraphy

The Trent Field gas accumulation in the UKCS (United Kingdom Continental Shelf) Southern Gas Basin is reservoired in Carboniferous age sediments. It is contained within a NW–SE trending base Permian structural feature that straddles Blocks 43/24a, 43/23 and 43/25. The proven reserves within the core area lie solely within the 43/24a block. Field appraisal and development encountered three main areas of complexity: structure, reservoir continuity and reservoir property variations. The 20 km long base Permian feature is controlled by NW–SE trending post-Rotliegendes reverse faults which produced a positive inversion. Antithetic faults to these reverse faults also occur within the structure. A second WSW–ENE normal fault trend comparmentalizes the field, and is also thought to have influenced sedimentation during Carboniferous times. Similar fault-influenced deposition is documented at equivalent times in the UK onshore. Ultimately this structural complexity controls the Carboniferous subcrop, which is seen to increase in age from late to early Westphalian A, in a southeasterly direction, although dramatic changes can occur on a more local scale in some fault compartments. The Trent Field accumulation is contained within an interval ranging in age from Marsdenian to early Westphalian A. It encompasses a number of facies associations in delta top and lower delta plain environments, which vary rapidly both vertically and laterally. Reservoir facies include incised valley-fills, transgressive reworked sandstones and distributary channels, which vary markedly in their lateral extent. Reservoir quality of these facies ranges from very poor to excellent and is controlled primarily by the depositional environment in which grain size and sediment maturity are the most important factors.

The Andrew Formation and ‘biosteering’ — different reservoirs, different approaches

Abstract Biosteering, the provision of real-time biostratigraphic data for the drilling of horizontal wells, has developed and evolved a wide range of approaches and applications in recent years. Its value to the success of a development project has grown beyond its core role as an effective and rapid method by which to define the relative stratigraphic position of the drill bit for steering purposes. High-resolution biostratigraphy and biosteering are now being used as part of an integrated service which is being incorprated in the planning of a horizontal drilling programme and individual well paths. This paper illustrates some of this diversity of applications by describing two very different styles of biosteering from age-equivalent turbidite sands of the Andrew Formation, on the United Kingdom continental shelf (UKCS). The first example describes biosteering through thin (10–15 ft) turbidite sands from the Joanne Field. The reservoir is one of several thin allochthonous sand and limestone subunits, requiring a very detailed biostratigraphic framework to provide sufficient resolution to identify each of the subunits. The framework utilizes both in situ and derived/reworked assemblages and associations (microfacies) to identify up to 10 discrete and correlative lithostratigraphic subunits. Local dip variations, faults of subseismic resolution and thinness of sand hampered efforts to continuously remain within the reservoir during horizontal drilling operations. Well-site micropalaeontological interpretation correctly identified the position of the drill bit in relation to the reservoir sand, allowing the correct well-path deviation to be enacted. In the absence of this technique, hundreds of feet of additional non-reservoir section would have been drilled. The second example describes the Andrew Field, again comprising deep-marine turbidite sandstones of the Andrew Formation. Development of the Andrew Field has incorporated both the biosteering function of well-site biostratigraphy as well as pre-drill, high-resolution facies analysis of the microfaunas to assist in depositional modelling of the field. Microfacies analysis provides data relating to the potential sealing qualities and lateral continuity of adjacent silt and claystones, and how these may act as barriers or baffles during production. This information is utilized in the planning of the well path to optimize production through well placement and stand-off from oil-water and gas-oil contacts, and at the well site during horizontal drilling to confirm, through micropalaeontological analysis, key horizons at which to geosteer.

The Schiehallion development

The Schiehallion development is one of the largest on the United Kingdom Continental Shelf in the last ten years, with mean recoverable reserves of 425 × 10 6 BBL. It is the second development West of Shetland, following the Foinaven Field. The Schiehallion development comprises two fields; Schiehallion and Loyal, which are located approximately 200 km west of the Shetland Islands and a similar distance northwest of the Orkneys in water depths of 300–500 m. The Schiehallion Field was discovered in late 1993 by Well 204/20-1 and side-track -1Z. Oil is trapped in submarine slope reservoir sandstone of Paleocene age. The discovery well penetrated an oil–water contact at 2064 m TVDSS. The field extent was mapped on 3D seismic data through the first half of 1994. This was followed by the drilling of five further vertical appraisal wells in 1994–95, three operated by BP/Britoil and two by Amerada Hess. In 1995, a horizontal well, 204/20-5, was drilled and subsequently tested over an extended period. The Loyal Field, to the north of Schiehallion, was discovered in late 1994 by Well 204/20-3 which encountered an oil column in sandstone of Paleocene age. The well was successfully side-tracked into a second, adjacent oil-hearing sandstone. An oil–water contact was penetrated at 2397 m TVDSS. A second well, 204/20-6A, drilled in 1995, confirmed the presence of oil at the crest of Loyal in a second separate segment with an oil–water contact inferred at 2160-m TVDSS. The mapping of net pay thickness directly from 3D seismic underpins the reservoir description of the Schiehallion and Loyal fields. Vertical appraisal wells were targeted to calibrate the net pay model and reduce reservoir uncertainties. This enabled a rapid appraisal of the key elements of the static reservoir description. Seismic attribute mapping and detailed seismic facies mapping, combined with sedimentological analysis of the cores and borehole imaging electric logs, defined the channelized architecture of the reservoirs. Horizontal Well 204/20–5 and subsequent extended well test (EWT) were designed to answer questions on the dynamic performance of the reservoir, particularly the connectivity and productivity of the sandstone reservoirs. This well was completed in the summer of 1995 after penetrating a gross reservoir length of c . 1700 m. The subsequent EWT achieved a stabilized, constrained flow rate of c . 18000 BQPD and demonstrated the productivity and good reservoir connectivity of the field. The well was suspended as a future producer. The development of the two fields was sanctioned in 1996. Development drilling began later in 1996 and oil production commenced on schedule in July 1998. The fields will be exploited using a floating production, storage and off-loading (FPSO) vessel which is jointly owned by the field partners (BP Exploration (Operator), Shell UK Exploration and Production, Amerada Hess Ltd, Murphy Petroleum Ltd, OMV (UK) Ltd and Statoil (UK) Ltd).

The Importance of Interfacial Tension on Fluid Distribution During Depressurization

Summary Many North Sea reservoirs produce water at very high cuts under current waterflooding conditions. As oil production drops below economical limits, procedures for recovering residual and bypassed oil are being investigated. One technique identified as potentially suitable for at least ten candidate fields in the United Kingdom Continental Shelf (UKCS) is to depressurize these fields. During pressure depletion, improved hydrocarbon recovery has been shown to result from the release of solution gas and subsequent expansion of the freed gas. The precise nature of gas nucleation and its subsequent growth phenomena, however, have not been well understood. For example, there exists experimental evidence supporting two apparently conflicting models describing gas nucleation. High pressure micromodel studies have shed light on the physical processes occurring at the pore scale during pressure depletion in waterflooded systems. Specifically, tests performed with fluids characterized by different gas/oil interfacial tensions (IFT's) have shown the important role gas/oil and gas/water IFT's play during bubble formation and growth in porous media. Analysis of visual information from water-wet micromodel tests have shown that the magnitude of the liquid-gas IFT is one of the factors that determines in which phase the bubbles nucleate, and how many bubbles form per unit volume of pore space. A low gas/oil IFT results in a relatively large number of bubbles forming in the oil phase only, with little or no supersaturation. Higher values of gas/oil IFT result in increasing levels of supersaturation with relatively fewer bubbles nucleating at cavity sites on the water-solid interface. Not only is the gas/oil IFT at the bubblepoint important in determining the nucleation loci and densities, but the increasing gas/oil IFT values with decreasing pressure also affect the distribution of the three phases during the process. Increasing gas/oil IFT's, combined with the effect of disjoining pressure in thin water films separating oil ganglia, result in delayed oil production and expulsion of water from the system below a certain threshold pressure. This suggests that there is an identifiable minimum pressure below which hydrocarbon production will not be viable.

Exploration in the Shetland‐Faeroe Basin using densely spaced arrays of ocean‐bottom seismometers

Recent exploration activity in the peripheral regions of the Shetland‐Faeroe Basin, offshore northwest Scotland, has led to the discovery of some of the largest oil reserves on the United Kingdom (UK) continental shelf. We present results from two ocean‐bottom seismometer profiles acquired by Mobil North Sea Ltd. across the center of the Shetland‐Faeroe Basin. These data provide a powerful tool for delineating long‐wavelength velocity variations and thus have potential for reducing the nonuniqueness associated with conventional seismic exploration methods. Analysis of the first‐arrival traveltime data using both forward and inverse ray‐based techniques produces a well constrained velocity‐depth model of the basin fill. We estimate that the uncertainty in the velocity structure is ±5% from a series of trial and error perturbations applied to the final models. The velocity structure of the Faeroe Basin has three principal layers: (1) a near‐surface layer with velocities in the range 1.6 to 2.2 km/s, (2) a 3.0–3.2 km/s layer which is characterized by a northwards structural pinch out in the center of the basin, and (3) a deeper laterally heterogeneous layer with velocities in the range 3.8 to 4.2 km/s. In the northwestern portion of the basin, a high velocity (5.0 km/s) basaltic layer is imaged dipping toward the southeast at a depth of 2–3 km. The basement is mapped at a depth of 7–9 km in the center of the basin. Gravity modeling provides independent corroboration of our models through the application of a velocity‐density relationship obtained from a synthesis of physical property measurements. Reflections from the Moho indicate a crustal thickness of 18 ± 3 km, suggesting that the basin is underlain by highly attenuated continental crust, but the velocities in the basement are closer to those of the Faeroe Islands basalts than the expected Lewisian gneiss, suggesting that it may be highly intruded.

Geological information from telecommunications cable route surveys of the continental shelf

Several burial assessment surveys using a seabed plough have been carried out along routes on the United Kingdom continental shelf to assess their potential for cable burial. Detailed information on sediment thicknesses and characteristics within the top meter of the seabed was collected using a survey tool called the Plough Surveyor. Geophysical surveys along these routes have enabled correlation with the plough data. Results include the range of tensions, tension trace characteristics, and typical penetration, and these have been correlated with seabed types and thickness of sediment.

Contributions to atmospheric methane by natural seepages on the U.K. continental shelf : [Mar. Geol. 137 (1997) 165–189

Natural gas seepages occur on the United Kingdom's continental shelf and although published reports suggest that they are very rare, the petroleum industry has identified, but not publicly reported, many more. There is also very little data on the flux of gas from seabed seepages, and even less on the contribution of seepages to atmospheric concentrations of gases such as methane. Potential gas source rocks include Quaternary and Tertiary peats as well as petroliferous source rocks such as the Carboniferous Coal Measures and the Upper Jurassic Kimmeridge Clays. There are also other organic-rich sediments which are potential source rocks. Together these cover a considerable part of the U.K. continental shelf. Analogue seismic reflection (pinger) profiles acquired during the British Geological Survey's regional mapping programme have been reviewed to identify water column targets including fish and plumes of gas bubbles. The ability to distinguish targets is critical to an assessment of the distribution of gas seepages. Both theoretical predictions of target identity and the habits of shoaling fish have been investigated in order to identify a method of distinction. Data from seabed seepages and measurements of seepage rates have been used to establish likely ranges of gas flux rates and the sizes of gas bubbles. The likelihood that a rising bubble will survive and escape into the atmosphere is determined primarily by bubble size and water depth; methane, the principal constituent of seepage gas, is relatively unreactive and sparingly soluble. The studies have enabled a new estimate of the distribution of gas seepages on the U.K. continental shelf, and of the contribution to atmospheric methane levels. The results suggest that natural gas seepages are significantly more important as a source of methane than had hitherto been established. It is estimated that between 120,000 and 3.5 mtonnes of methane per year come from a continental shelf area of about 600,000 km 2. This represents between 2% and 40% of the total United Kingdom methane emission. It is suggested that similar contributions arise from other continental shelf areas worldwide, and that geological sources of atmospheric methane are more significant than is generally acknowledged.

Enrichment and characterisation of sulfate-reducing bacteria from sandstone rock cores from the UK Continental shelf

A fresh sandstone core was extracted during drilling of an exploration well within a United Kingdom Continental Shelf oilfield at a depth of approximately 1000 m. Scanning electron microscopy of the rock core revealed cell-like structures attached to the sandstone grains. Microbiological analysis demonstrated that the inner core was not sterile but contained sulfate-reducing bacteria and other anaerobes. One enrichment culture of sulfate-reducing bacteria (denoted EX306), was chosen for further study. Enrichments of EX306 showed that it was comprised of a tightly knit group of three different bacteria which continued as a stable community despite repeated subculturing for over 2 years. EX306 was able to utilise pyruvate-producing acetate and propionate as metabolites, growth was optimal at 55°C.