Forties Field Research Articles

Anisotropy in shale and its impact on AVO modelling and prospect de-risk: a case study of a Central North Sea field

The inherent anisotropy in shale is an attribute associated with its clay minerals platelets alignment and layering and very common with transversely isotropic (TI) medium. This implies that velocity is fastest along the horizontal axis and slowest along the vertical axis, which could affect velocity signature from sonic tools measurements in deviated wells. This may lead to wrong amplitude variation with offset (AVO) signature, inaccurate depth conversions, seismic-to-well tie difficulty etc. Nineteen (19) wells in Forties field andthirteen (13) in Huntington field were investigated and interpreted for the presence of anisotropy effect within the caprock over the reservoir Forties sands of the Sele (shales) Formation. In order to analyse the Thomsen weak anisotropy parameters (ϵ, γ and δ) per field, wells with closer Sele depth range were considered. The well inclinations ( θ ), average compressional (α) and shear (β) velocities per well were utilised for forward and inverse modelling of Thomsen anisotropy equations. The estimated anisotropy (VTI) parameters and the P-wave ( α o ) and S-wave velocities (βo ) at zero inclinations in Sele Formation for the studied wells are: α o = 2448 ± 15.9 m/s, β o = 1003 ± 34.8 m/s, ϵ = 0.15 ± 0.02, γ = 0.33 ± 0.10, δ = 0.030 ± 0.015 in the Forties field Sele, while α o = 2775 ± 23.6 m/s, β o = 1306 ± 47.9 m/s, ϵ = 0.22 ± 0.02, γ = 0.43 ± 0.14, δ = 0.022 ± 0.018 in the Huntington field. AVO responses were compared, assuming both isotropic and anisotropic P–P reflectivity models. Result shows an increase in AVO gradient for all anisotropic case in both fields. AVO signatures were either completely or averagely masked in both fields using the isotropic assumptions. There is also an increase in AVO gradient for all anisotropic cases in both fields. Velocity decreases of about 1.2% and 3.5% were observed in the Sele Formation for the Forties and Huntington fields respectively for anisotropy. The corrected two-way traveltime (TWT) should in principle allow for a better seismic-to-well tie estimation. Similarly, using the faster deviated velocity (i.e. uncorrected velocity) in any depth conversion would result in under estimation of the actual depth across the field.

The Forties Field, Blocks 21/10 and 22/6a, UK North Sea

Abstract The Forties Field, discovered by BP in 1970, is the largest oilfield on the UK Continental Shelf. It is trapped in a simple four-way dip closure, with a Paleocene turbidite sandstone reservoir. The Forties Field originally contained between 4.2 and 5 billion bbl of oil, with 2.75 billion bbl produced to June 2017. Production has been supported by water injection and the influx of a regional aquifer. The original development contained equally spaced producers with peripheral injectors. As the field matured, production was concentrated in the crestal parts of the field with injectors tending to be moved upflank. With the development of seismic lithology prediction and fluid detection, together with 4D seismic technology, it became possible in the late 1990s to target bypassed oil in unexpected locations throughout the field. In 2003, BP sold the field to Apache who were able to rejuvenate production, adding over 170 MMbbl oil reserves, with an extended drilling campaign targeting bypassed pay identified using seismic technologies. Production at the Forties facility has been further enhanced by the development of four satellite oilfields, Bacchus (Jurassic reservoir), Brimmond, Maule and Tonto (Eocene reservoirs), together with Aviat (Pleistocene reservoir) produced for fuel gas supply.

The Blane Field, Block 30/3a, UK North Sea

Abstract The Blane Field is located in the central North Sea in Block 30/3a (Licence P.111), approximately 130 km SE of the Forties Field, in a water depth of 75 m (246 ft). It straddles the UK/Norway median line with 82% of the field in the UK and 18% in Norway. Blane produces undersaturated oil from the Upper Forties Sandstone Member of the Sele Formation and contains good quality light oil within a four-way structural closure; it has a hydrodynamically tilted original oil–water contact. The field stock-tank oil initially in place estimate is 93 MMbbl with an expected ultimate recovery of 33 MMbbl. Blane first oil was achieved in September 2007. The field has been developed by two horizontal producers located on the central crest of the field supported by a water injector drilled on the NW flank. Oil production peaked at c. 17 000 bopd in 2007 and the field is currently in decline. By the end of 2018 production was c. 3000 bopd with 55% water-cut. Cumulative oil production to the end of 2018 was 26.6 MMbbl.

Development of the Brimmond Sand Fairway

Abstract The Eocene age Brimmond Sand Fairway is situated along the north-eastern flank of the Paleocene Forties Field (UKCNS blocks 21/10 and 22/6). Located along the western margin of this Brimmond Fairway are well imaged remobilized sands that form the reservoir interval for the Maule and Tonto Fields and, along with deep-water channels, the Brimmond Field. These Eocene Brimmond sandstones are encased in the Horda Shale which provides the sealing lithology. The interpretation of these remobilized and injected sands is driven from geometries derived from 3D seismic and historic logging of thin sandstones in the Eocene interval. Conical shape features with sills and steep dykes are mapped, with seismic evidence of injection along active faults and fractures. The developments of the Brimmond, Maule and Tonto Fields has been successful due to impressive seismic imaging with inversion and Direct Hydrocarbon Indicator (DHI) volumes allowing the identification of hydrocarbon bearing remobilized sandstones, along with 4D data imaging un-swept areas.

Increasing resolution in the North Sea

Recent step changes in seismic processing and imaging technology have delivered dramatic improvements in resolution, velocity model building and multiple attenuation. This article will explore improvements in resolution that have been demonstrated on two multi-client surveys in the North Sea: Cornerstone and Northern Viking Graben (NVG). Extending full-waveform inversion (FWI) to include absorption effects as well as velocity has delivered improved imaging, higher resolution and more reliable AVO products for the NVG survey, and this will now be applied to the reprocessed Cornerstone data. Both surveys cover more than 35,000 km2 each, so application of high-resolution processing sequences to these two data sets will deliver advanced high-resolution data over two large areas of the North Sea. The NVG survey was acquired using BroadSeis variable-depth streamers in conjunction with a broadband source to maximize the bandwidth. However, new developments in broadband processing, including ghost wavefield elimination (GWE) and bandwidth extension, can be extended to the reprocessing of conventionally-acquired data sets, which can now be uplifted to deliver data of almost similar quality to modern broadband data by mitigating many of the limitations of traditional acquisition. This is demonstrated by the reprocessing of the Cornerstone project in the Central North Sea. Although this survey was recently reprocessed in depth using multi-layer tomography, the rapid improvements in GWE, multiple and noise attenuation, velocity modelling and imaging in the last few years mean that it can still benefit from being reprocessed again. Modern processing techniques ensure compliance with amplitude versus offset (AVO) analysis, and AVO attributes are used for QC purposes during the processing flow to ensure that the final data sets can be used directly for reservoir characterization. The AVO attribute maps for Cornerstone shown later in this article have already delivered impressive high-resolution images of the Forties field

Aviat: a Lower Pleistocene shallow gas hazard developed as a fuel gas supply for the Forties Field

Abstract The search for a gas source near to Apache's Forties Field in the North Sea was motivated by the prediction of an ever-increasing fuel gas shortfall as the field oil rate declined. The Central North Sea is well known for a large number of shallow gas hazards in the Pleistocene section that have historically caused blowouts during exploration and development. These gas accumulations typically show up as small bright anomalies on seismic data. In 2009, a large gas anomaly was identified to the east of Forties, and the Aviat Field was discovered in 2010 when exploration well 22/7-5 was drilled. The Aviat Field reservoir is interpreted to be a subaqueous glacial outwash fan, consisting of silt-grade, rock flour material, deposited in front of a grounded ice sheet in some 400 m of water. Aviat sits on an overcompacted silty mudstone that was deformed by this ice sheet – the Crenulate Marker. The distribution of this horizon implies that the Early Pleistocene ice sheet covered at least the northern half of the UK North Sea. Although the Aviat reservoir is thin (2–9 m thick), the well tests, pressure profiles and geophysical response demonstrate that the reservoir is well connected, extensive (over 35 km 2 ) with high deliverability (up to 18 MMscfd achieved). Aviat was sanctioned in 2014 for development as a fuel gas supply for the Forties Field, with first gas achieved in July 2016.

Re-saturation targets identified from 4D seismic softening responses in the Forties Field

Abstract A novel 4D methodology by targeting softening responses, a decrease in impedance over time, is described from the Forties Field. It is demonstrated that these anomalies identified areas where oil had re-saturated previously swept rock. When first observed in some of the older vintages of 4D data, softening responses were dismissed as side lobes of underlying water-swept reservoirs. With improved 4D data quality, softening responses were seen to be clearly responding to an acoustic softening effect isolated in the reservoir. Pressure measurements ruled out hypotheses of gas exsolution or geomechanically induced dilatation of the overlying shale. At the time of writing 22 re-saturation targets had been drilled at Forties with an average water saturation ( S w ) of 28%, close to virgin conditions. These results indicated that a previously swept sand can be re-saturated to near initial oil conditions. The driving mechanism behind the re-saturation is understood to be related to changes in both production offtake and water injection. The resulting complex hydrodynamic interactions appeared to be moving banks of oil around the field. From 2011 to year-end of 2015 re-saturation targets produced 14.6 MMBO and were a key target type at the Forties Field.

Resaturated pay: A new infill target type identified through the application and continuous improvement of 4D seismic at the Forties Field

Forties is a giant North Sea oil field with an estimated 4.2 billion to 5 billion barrels of oil initially in place. The field has been producing since 1975 and by year-end 2015 had produced more than 2.7 billion barrels of cumulative oil production. The peak production rate exceeded more than 500,000 barrels of oil per day (BOPD) in 1979, and since then more than 3.8 billion barrels of water have been injected into the field. The majority of the field is now water swept due to the combined effect of water injection and extensive depletion supported by a large underlying aquifer. The ability to identify the few remaining unswept portions of the reservoir has elevated 4D seismic into a key technology to derisk all new wells drilled at Forties. The types of 4D targets at Forties are ever-evolving as continuous improvements in seismic acquisition and processing technologies deliver higher quality time-lapse seismic data. With every subtle improvement in 4D repeatability, additional and sometimes unexpected information about the reservoir has come to light. Historically the primary and most robust 4D effect was an increase in impedance (i.e., a “hardening” effect), which could be mapped confidently to identify areas where water was replacing oil. As 4D repeatability improved, it became evident that a decrease in impedance (i.e., a “softening” effect) was observed in many areas in the reservoir. Further analysis revealed that this type of 4D response was highlighting areas where oil had resaturated previously swept reservoir, forming a new type of infill target in the Forties portfolio called resaturation targets. Since drilling the first 4D resaturation target in 2011, 22 of these targets have been drilled with an 86% success rate, delivering 15 million barrels of new oil production from the Forties Field.

Oil reservoir waterflooding efficiency evaluation method

ABSTRACTThe effective hydrocarbon field development requires a well-developed waterflooding strategy with surveillance plan for continuous efficiency monitoring. The modified capacitance resistance model (CRM) is proposed to monitor the efficiency of oil field waterflood. The model outcomes give and understanding of flooding response. Forties field data was used to test and present the waterflood performance based on proposed modified CRM model.

North Sea Oil and the Scottish Independence Referendum

Guest editorial On 18 September 2014, the Scottish public will vote on the question, “Should Scotland be an independent country?” With North Sea oil predicted to be the largest sector in an independent Scottish economy, the industry finds itself at the center of a political and economic debate. First, some basics. The United Kingdom (UK) consists of England, Scotland, Wales, and Northern Ireland. In 1999, a new Scottish Parliament opened with limited devolved powers including health and education. Following its surprise 2011 election victory, the pro-independence Scottish National Party is now delivering on its referendum pledge. Scotland’s population of 5 million forms just 8% of the UK total, but is comparable to that of its prosperous Scandinavian neighbors, including Norway. While well beyond its 2000 peak production, the North Sea oil and gas sector remains valuable; up to a further 24 billion BOE is recoverable. Although substantial in the Scottish context, this forms less than 1% of global reserves. Tax revenues amounted to GBP 11 billion in 2012 while the sector employs 500,000 workers. The resource meets more than 50% of UK hydrocarbon demand, sharply reducing import dependence. The outlook for the North Sea is mixed. Investment sits at record levels (GBP 13 billion in 2013) as multinationals develop new opportunities in the Atlantic margin (e.g., Total’s Laggan-Tormore project) while smaller independents redevelop mature assets (e.g., Apache’s purchase of BP’s Forties field). Production, however, has tumbled to below 2 million BOEPD and exploration continues to fall. Approximately 85% of reserves on the UK Continental Shelf (UKCS) lie in waters closest to Scotland. Upon independence, this would account for almost a fifth of Scotland’s national gross domestic product. While much debated publicly, the precise location of the UK-Scotland maritime boundary is less significant in terms of reserves than might be imagined. Arrangements for distinctive island communities in the far north (Orkney and Shetland) require resolution, however. More pertinent to the effect on the oil and gas industry would be new Scottish tax arrangements, treatment of cross-border pipelines, and unitization agreements. In terms of licensing, the Scottish government has pledged to honor existing agreements but provision of tax relief on the sector’s predicted GBP 35 billion of decommissioning liabilities is a source of industry uncertainty.

Constraining the origin of reservoirs formed by sandstone intrusions: Insights from heavy mineral studies of the Eocene in the Forties area, United Kingdom central North Sea

The presence of hydrocarbon-bearing sandstones within the Eocene of the Forties area was first documented in 1985, when a Forties field (Paleocene) development well discovered the Brimmond field. Further hydrocarbons in the Eocene were discovered in the adjacent Maule field in 2009. Reservoir geometry derived from three-dimensional seismic data has provided evidence for both a depositional and a sand injectite origin for the Eocene sandstones. The Brimmond field is located in a deep-water channel complex that extends to the southeast, whereas the Maule field sandstones have the geometry of an injection sheet on the updip margin of the Brimmond channel system with a cone-shape feature emanating from the top of the Forties Sandstone Member (Paleocene). The geometry of the Eocene sandstones in the Maule field indicates that they are intrusive and originated by the fluidization and injection of sand during burial. From seismic and borehole data, it is unclear whether the sand that was injected to form the Maule reservoir was derived from depositional Eocene sandstones or from the underlying Forties Sandstone Member. These two alternatives are tested by comparing the heavy mineral and garnet geochemical characteristics of the injectite sandstones in the Maule field with the depositional sandstones of the Brimmond field and the Forties sandstones of the Forties field. The study revealed significant differences between the sandstones in the Forties field and those of the Maule and Brimmond fields), both in terms of heavy mineral and garnet geochemical data. The Brimmond-Maule and Forties sandstones therefore have different provenances and are genetically unrelated, indicating that the sandstones in the Maule field did not originate by the fluidization of Forties sandstones. By contrast, the provenance characteristics of the depositional Brimmond sandstones are closely comparable with sandstone intrusions in the Maule field. We conclude that the injectites in the Maule field formed by the fluidization of depositional Brimmond sandstones but do not exclude the important function of water from the huge underlying Forties Sandstone Member aquifer as the agent for developing the fluid supply and elevating pore pressure to fluidize and inject the Eocene sand. The study has demonstrated that heavy mineral provenance studies are an effective method of tracing the origin of injected sandstones, which are increasingly being recognized as an important hydrocarbon play.

The habitat of bypassed pay in the Forties Field

Abstract The Forties Field, the largest oilfield in the UK North Sea, has been a prolific producer since its initial development. With an initial plateau rate of 500 000 bopd the field had produced some 2500 mmbo and the field rate had declined to 41 000 bopd by 2003 when the operatorship changed from BP to Apache. From 2004 to 2012, over 100 bypassed pay targets were drilled with a success rate of 75%, establishing a late life plateau of 50 000–60 000 bopd. The Forties reservoir is provided by Paleocene turbidites of the Forties Sandstone Member of the Sele Formation, deposited in a channelized proximal area of the Forties Fan. In this paper, the reservoir architecture is described, and bypassed pay examples are discussed in the context of the reservoir architecture and the production history. Bypassed pay is shown to occur in both the high net to gross channel axes and the heterogeneous wing deposits. Oil is trapped by subseismic channel architecture and subtle faulting. The occurrence of bypassed pay at a particular location is also shown to be dependent on the continually evolving pattern of injection and production within the field.

Towards improved time-lapse seismic repetition accuracy by use of multimeasurement streamer reconstruction

Patrick Smith, Jason Thekkekara, Julie Branston, Grant Byerley, David Monk and Jeffrey Towart describe, with an example from the North Sea Forties field, how multi-measurement streamer technology enables the reconstruction of a monitor survey to the streamer locations and datum of a previous survey, thus improving time-lapse repeatability.

Forties Infill Drilling 8 Years Later: Development Driven by 4D Seismic

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 145433, ’Forties Infill Drilling 8 Years On: Continued Success Through the Application of Thorough Development Geoscience Driven by 4D Seismic,’ by Philip Rose, Gregg Barker, Klaas Koster, and Jeff Pyle, Apache North Sea, prepared for the 2011 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 6-8 September. The paper has not been peer reviewed. In the 8 years since Apache purchased the Forties field, more than 100 in-field targets have been drilled, with an overall success rate of 74%. The campaign resulted in a shortage of sidetrack-donor wells, with a return to surface drilling on all five platforms. To enable full exploitation of the target portfolio, Apache is installing a new 18-slot platform in 2012. Key to success has been a constant drive to push the boundaries of 4D-seismic interpretation and of the lithology prediction from seismic, and the ability to integrate this information with local production and well data. Introduction The Forties field, in the UK central North Sea, was purchased by Apache in 2003, at which time it was a giant field in the decline phase of its life. Annualized average production was 41,000 BOPD and declining. No new wells had been drilled in the field since 2001. In the early 1980s, the field produced between 400,000 and 500,000 BOPD. By 2003, the field had produced 2.5 billion bbl of the 4.2- to 5-billion-bbl original oil in place. The field’s remaining recoverable reserves were listed as 144 million BO. Since the purchase, more than 100 drilling targets have been tested, resulting in more than 80 production and four injection completions. As a result of the drilling campaign, annualized average production has remained at approximately 60,000 BOPD since 2005, with total production of more than 150 million BO, of which 75 million BO has been produced from newly drilled wells. As shown in Fig. 1, approximately 70% of the current field production is from wells drilled since the purchase. Foundation: Data Integration Use of an integrated multidisciplinary interpretation approach was critical to identify new targets continually. The ability to display well-log-derived attributes with seismic amplitudes, seismic geobodies, and production information in a single interpretation environment was invaluable. The data book contains map locations, illustrations of the pay section with completion history, production history, workover record, and a current completion diagram for every well completed in the field. All interpreters have access to the company’s live production-allocation database. Although many of the infill-drilling targets were driven by seismic interpretation, including the identification of direct hydrocarbon indicators (DHIs) or unswept areas highlighted by time-lapse (4D) seismic, others were generated to replace mechanically failed wells having remaining production potential, and a few targets were generated following the analysis of simulation results.

Contractual Arrangements and Revenue Management: The UK/Scotland and Norwegian Experience

Many new oil-producing countries are emerging--most of them developing countries. The lessons from the UK and Norway following the initial discovery of hydrocarbons in the 1960s offer interesting insights, with two very different approaches to resource extraction and two very different outcomes. This experience, briefly outlined in this essay, may inform policymakers in today's new oil-producing countries who are faced with important choices on how best to use their resource wealth and foster development. The framework to analyze contractual arrangements and revenue management revolves around three global cycles: the political cycle, the resource nationalist cycle, and the obsolescing bargain cycle. The political cycle refers to the view--usually driven by ideology--over the role of government in the allocation of economic resources within an economy. If it is believed that markets do not work efficiently because of market failure, governments should intervene. However, if it is believed that government intervention leads to a misallocation of resources, then markets should intervene--the so-called Washington Consensus. The resource nationalist cycle refers to the desire of governments to assert control over their natural resources together with their attitude toward foreign companies. The peak of the cycle would be a strong desire for control with xenophobic dimensions. This, in part, is driven by the magnitude of and need for oil revenues, which to a large extent are determined by oil mineral prices. The obsolescing bargain cycle refers to the idea that the terms of the upstream agreement are determined initially by the relative bargaining power of the parties at the time of negotiation. However, after the operator has made the investments, the bargaining power swings strongly toward the government leading them to seek renegotiation of terms. This cycle is driven in part by the resource nationalist cycle, the size of the eventual oil discovery, and the price of oil. The UK oil experience begins in May 1964 with the UK Continental Shelf Act. This, following the Continental Shelf Convention of 1958, gave the government the power to allocate exploration acreage and approve field developments. Commercial gas was found in West Sole in September 1965. Philips discovered the first commercial oil in the Ekofisk field on the Norwegian side in 1969. In October 1970, BP discovered the Forties field and, in 1971, Shell discovered the Brent field. Production was slow to develop, reflecting the fact that the offshore operations were at the extreme frontier of technical knowledge. By 1976, production had reached only 253,000 barrels per day. Globally, during this period, there were strong pressures for government intervention in the economy. The UK was no exception as the government increasingly struggled to manage an economy sliding into ever-deeper trouble. Balance of payments were seriously undermined by Sterling crises coupled with growing unemployment and a rising budget deficit. In 1964, the government actually introduced a Five Year Plan. Resource nationalism was building to a peak in the Middle East, seriously threatening the major international oil companies. In addition, the obsolescing bargain cycle was strong as host governments sought to exercise their growing postimperial power to squeeze more from fiscal terms. The discovery of North Sea oil was seen as manna from heaven, especially after the first oil price shock of 1973-1974 quadrupled international oil prices. However, there was little or no public debate within the UK on how the windfall might be managed. Rather, the government took the decision to produce the oil as rapidly as possible to reverse the underlying macroeconomic problems of the economy. Concerns over security of imported oil supplies following the Arab oil embargo of 1973 reinforced this desire for haste. The result was that Aberdeen became a clone of Houston as manpower and offshore technology poured in from the United States, which effectively had a monopoly. …

Correcting sonic logs for shale anisotropy: a case study in the Forties field

Donald Keir, Brett McIntyre, Ted Hibbert, Rachael Dixon, Klaas Koster, Farid Mohamed, Adam Donald, Anzar Syed, Chang Liu, Tom O’Rourke, Andrea Paxton, Steve Horne, Ed Knight, Colin Sayers and Paolo Primiero describe how a method employed to quantify anisotropy and correct sonic logs across the Forties field led to modifications of drilling parameters and practices and ultimately to significantly improved efficiency/productivity.

Managing Drilling Risk in a Mature North Sea Field

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 124666, ’Managing Drilling Risk in a Mature North Sea Field,’ by Brett McIntyre, SPE, Ted Hibbert, SPE, Donald Keir, and Rachel Dixon, Apache North Sea Ltd., and Tom ORourke, SPE, Farid Mohammed, Adam Donald, Liu Chang, Anzar Syed, and Valerie Biran, SPE, Schlumberger, originally prepared for the 2009 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 8-11 September. The paper has not been peer reviewed. The likelihood of losses increases as reservoir pressures decline while higher mud weights are needed to prevent collapse of overburden shales as targets are pushed farther from the platform. Drilling parameters for the Forties field have become fairly well established after years of experience, yet 65% of the wells drilled between 2002 and 2007 experienced incidents attributed to instability. Through a better understanding of the field geomechanics and past drilling events, the drilling team has implemented fit-for-purpose drilling procedures that have improved drilling efficiency significantly. Introduction Discovered in 1970, the Forties field has been developed and produced from five platforms in the UK sector of the central North Sea since 1974. There are now more than 300 boreholes in the area. In recent years, the drilling program has pursued infill targets from donor wells sidetracked near the base of the 95/8-in. casing or step-out targets with sidetracks higher up existing wells. Of the 94 boreholes drilled over a 5-year period (2002–07), 45% were lost because of drilling or completion problems. A bottomhole assembly (BHA) was lost in 40% of these failures. Even the successful wells encountered various drilling problems, and when this is taken into account, 65% of all the wells drilled during this period experienced some degree of instability. As field production declined, economic viability demanded a step change in performance. Drilling parameters for the Forties field have become fairly well established after years of experience. Over the period, mud weights tended to creep up in response to cavings and packoffs and then were lowered when losses became of greater concern. Where these events became more than a minor problem, drilling practices frequently were responsible. Fragile zones often are stable if undisturbed, but mechanical or hydraulic disturbance will generate debris, sometimes in considerable volumes. Were the holdups, stuck pipe, pickoffs, and loss incidents in the Forties field caused by hole instability as a result of incorrect mud weights or caused by drilling practices? Is the debris in the borehole fresh cavings or unremoved cuttings? If the cause of these problems can be identified correctly, appropriate drilling and operational contingencies can be defined before hazards are encountered. When hole problems do develop, appropriate remedial actions can be taken on the basis of an understanding of what is occurring downhole. Incorrect diagnosis can lead to an inappropriate solution, exacerbating the problem and leading to further damage.

Mesozoic rift magmatism in the North Sea region: 40Ar/39Ar geochronology of Scanian basalts and geochemical constraints

More than 100 volcanic necks composed of basanites and melanephelinites occur in Scania, southern Sweden, at the junction of two major tectonic lineaments, the Phanerozoic Sorgenfrei-Tornquist Zone (STZ) and the Proterozoic Protogine Zone. New 40Ar/39Ar isotope analyses of whole rock fragments of nine selected basalt necks suggest that the Mesozoic alkaline volcanism in the Scanian province commenced earlier than previously reported and comprised three separate volcanic episodes that span a total period of ca. 80 Myr: a first Jurassic (191–178 Ma), a second at the Jurassic/Cretaceous boundary (ca. 145 Ma), and a final middle Cretaceous episode (ca. 110 Ma). The new results allow for precise time correlations between eruption events in the Scanian and those in the North Sea volcanic provinces. The older, early Jurassic event in Scania is largely synchronous with that in the Egersund Basin and the Forties field whereas the event at ca. 145 Ma is correlated with activity in the Central Graben. These volcanic episodes also correlate in age with Kimmerian tectonic activity. Volcanic activity in the middle Cretaceous period has also been dated in the triple junction in the North Sea and offshore in the Netherland Sector. The correlation of basalt volcanism in Scania with the Egersund nephelinites strongly suggest that volcanism was triggered by repeated tectonic activity along the STZ. Geochemical data of alkaline mafic rocks in the Scanian and the North Sea volcanic provinces imply that different provinces have largely unique geochemical signatures in favour of a heterogeneous mantle in the North Sea volcanic region. However, basalts of different generations in one and the same province cannot be readily separated on the basis of geochemistry, suggesting that the same lithospheric mantle was the source of repeated volcanism over time in each province. The data suggest a low degree of melting of a volatile-bearing mantle lherzolite enriched in incompatible elements with the exception of the Forties basalts in the rift centre, produced by larger degree of melting and evolved by fractional crystallization.

The Huntington discoveries: efficient exploration in the UK Central North Sea

Abstract The Huntington discoveries are an unusual exploration success in that two oil accumulations were tested in separate syn- and post-rift reservoirs with a single well. The discoveries are located 205 km east of Aberdeen in the East Central Graben some 35 km east of Forties Field in 300 ft of water. The 22/14-5 discovery well, drilled in May 2007, encountered a 122 ft oil column in the Paleocene Forties Sandstone and also a 136 ft oil column in the Upper Jurassic Fulmar Sandstone. Both the Forties and the Fulmar contain high-quality oil, 41 and 39° api gravity, respectively. Aggregate flow rates from the two zones exceeded 11 000 boepd on test. Appraisal drilling of the Forties was completed in late 2007 with first oil targeted for 2011. The Fulmar appraisal programme is currently in progress. The Forties reservoir is a high net to gross sandstone containing stacked channel sequences deposited in a submarine fan system. The Fulmar reservoir also contains a thick sand package deposited in a shallow marine shelf setting. Pre-drill mapping based on reprocessed 3D seismic indicated a structural closure on both horizons at the location tested by the well. At both the Forties and Fulmar targets, however, the oil column height exceeded the pre-drill prognosis. This overview will focus on pre-drill perceptions of the prospect relative to actual drilling results.

Corrosion Management for Aging Pipelines—Experience From the Forties Field

Summary In 2003, Apache became the operator of the Forties Field. The field has now been in operation for 33 years and much of the infield pipeline system has exceeded its original design life of 20–25 years. Apache intends to continue production in the Forties Field for, potentially, in excess of a further 20 years. With that in mind, they have identified numerous issues with respect to corrosion management of the infield pipeline system. Since late 2006, the Forties Field infield pipeline corrosion and integrity management has been carried out by IONIK Consulting/JP Kenny Caledonia Ltd. Working closely with Apache, the infield pipeline system has been reviewed; a number of issues have been assessed and quantified; and practices with respect to corrosion management, corrosion monitoring, and inspection have been implemented. This document examines the issues identified, the corrosion management strategy put in place, and the inspection actions undertaken. Examples of issues identified with respect to corrosion management systems include a requirement for a dedicated pipeline corrosion management strategy, pipeline corrosion modeling, a corrosion risk assessment of the pipeline system, a review of corrosion inhibition and pigging, and a review of key performance indicators with emphasis on pipeline management. Specific corrosion issues identified include anode depletion, preferential weld corrosion, localized corrosion, and 6 o'clock corrosion. Examples of other factors identified have been potential risks from microbial and underdeposit corrosion caused by low flow rates. This publication provides an overview of these issues and the implementation of solutions, alongside changes to items such as documentation and modification of existing procedures, risk assessment, corrosion management, and the implementation of an intelligent pigging program.