The Shearwater Field, Blocks 22/30b and 22/30e, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 574-588 ◽  
Author(s):  
B. J. Taylor ◽  
D. W. Jones
Keyword(s):  
Near Field ◽  
Upper Jurassic ◽  
Lessons Learned ◽  
Main Field ◽  
Initial Field ◽  
Initial Development ◽  
Field Development ◽  
Production Platform ◽  
Production Wells ◽  
Exploration And Production

AbstractThe Shearwater Field is a high-pressure–high-temperature (HPHT) gas condensate field located 180 km east of Aberdeen in UKCS Blocks 22/30b and 22/30e within the East Central Graben. Shell UK Limited operates the field on behalf of co-venturers Esso Exploration and Production UK Limited and Arco British Limited, via a fixed steel jacket production platform and bridge-linked wellhead jacket in a water depth of 295 ft.Sandstones of the Upper Jurassic Fulmar Formation constitute the primary reservoir upon which the initial field development was sanctioned; however, additional production has been achieved from intra-Heather Formation sandstones, as well as from the Middle Jurassic Pentland Formation. Following first gas in 2000, a series of well failures occurred such that by 2008 production from the main field Fulmar reservoir had ceased. This resulted in a shut-in period for the main field from 2010 before a platform well slot recovery and redevelopment drilling campaign reinstated production from the Fulmar reservoir in 2015. In addition to replacement wells, the redevelopment drilling also included the design and execution of additional wells targeting undeveloped reservoirs and near-field exploration targets, based on the lessons learned during the initial development campaign, resulting in concurrent production from all discovered reservoirs via six active production wells by 2018.

JOHN BROOKES GAS FIELD DEVELOPMENT

2005 ◽  
Vol 45 (1) ◽  
pp. 13
Author(s):  
A.J. McDiarmid ◽  
P.T. Bingaman ◽  
S.T. Bingham ◽  
B. Kirk-Burnnand ◽  
D.P. Gilbert ◽  
...  
Keyword(s):  
Low Cost ◽  
Time Frame ◽  
Gas Production ◽  
Gas Field ◽  
Initial Development ◽  
North West ◽  
Field Development ◽  
The North ◽  
Production Wells ◽  
Development Approach

The John Brookes gas field was discovered by the drilling of John Brookes–1 in October 1998 and appraisal drilling was completed in 2003. The field is located about 40 km northwest of Barrow Island on the North West Shelf, offshore West Australia. The John Brookes structure is a large (>90 km2) anticline with >100 m closure mapped at the base of the regional seal. Recoverable sales gas in the John Brookes reservoir is about 1 Tcf.Joint venture approval to fast track the development was gained in January 2004 with a target of first gas production in June 2005. The short development time frame required parallel workflows and use of a flexible/low cost development approach proven by Apache in the area.The John Brookes development is sized for off-take rates up to 240 TJ/d of sales gas with the development costing A$229 million. The initial development will consist of three production wells tied into an unmanned, minimal facility wellhead platform. The platform will be connected to the existing East Spar gas processing facilities on Varanus Island by an 18-inch multi-phase trunkline. Increasing the output of the existing East Spar facility and installation of a new gas sweetening facility are required. From Varanus Island, the gas will be exported to the mainland by existing sales gas pipelines. Condensate will be exported from Varanus Island by tanker.

The Kingfisher Field, Block 16/8a, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 305-314 ◽  
Author(s):  
Samantha Spence ◽  
Helge Kreutz
Keyword(s):  
Hydrocarbon Composition ◽  
Upper Jurassic ◽  
Gas Condensate ◽  
Production Performance ◽  
Horizontal Drilling ◽  
Field Development ◽  
Reservoir Architecture ◽  
Production Wells ◽  
Medium Quality ◽  
A Minor

AbstractThe Kingfisher Field is located in the South Viking Graben, Block 16/8a, with a minor extension into Block 16/8c. Block 16/8 was initially awarded in June 1970 to Shell and Esso, with the Kingfisher discovery well 16/8-1 spudded in 1972. The well tested high H2S oil at marginal rates from Upper Jurassic Brae Formation sandstones. Subsequent appraisal well 16/8a-4 (1984) tested gas/condensate from better quality Brae Formation sandstone reservoirs. This well also discovered the deeper Middle Jurassic Heather Formation sandstone gas/condensate accumulation at near-HPHT conditions. The Brae and Heather Formation sandstones contain stacked hydrocarbon accumulations in separate combinations of stratigraphic and structural traps. Production by natural aquifer drive commenced from a sub-sea satellite to Marathon's Brae B platform in 1997, initially from the Brae reservoirs. To date, three production wells have been completed and a fourth well is planned to be on stream in 2000. The Brae Formation sandstones at Kingfisher are interpreted as distal deposits of the Brae/Miller fan-apron system and range in quality from excellent to very poor across the field. The Heather Formation reservoir consists of medium quality sands deposited within a submarine incised valley. The most recent volumetric estimate (1998) for the total field predicts an ultimate recovery of 41.2 MMBBL of pipeline liquids and 280 BCF of dry export gas. Regional reservoir architecture and connectivity as well as hydrocarbon composition are key to understanding the production performance of the critical gas/condensate below dewpoint. Advances in sub-sea and horizontal drilling technology have enabled field development.

The Alba Field, Block 16/26a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 637-650 ◽  
Author(s):  
Ian Moore ◽  
James Archer ◽  
David Peavot
Keyword(s):  
North Sea ◽  
Water Channel ◽  
Rock Physics ◽  
Reservoir Properties ◽  
Oil Accumulation ◽  
Initial Field ◽  
Field Development ◽  
Production Wells ◽  
Reservoir Connectivity ◽  
Central North Sea

AbstractThe Alba Field is a relatively heavy oil accumulation lying in an Eocene deep-water channel complex in Block 16/26a of the Central North Sea. With an estimated 880 MMbbl in place, the reservoir is characterized by thick, high net/gross sands with excellent reservoir properties and rock physics favourable for seismic property detection. The field has been developed by horizontal production wells, with pressure support provided by seawater injectors. After 24 years of production, more than 427 MMbbl have been recovered.Over the course of the development, the results of development drilling and improved reservoir imaging from seismic have revealed greater reservoir complexity than anticipated at sanction. The highly irregular reservoir geometry is likely to reflect the internal stacking patterns of channel elements within the channel complex that are locally overprinted by post-depositional remobilization. This increased reservoir complexity has required more wells to effectively drain the expected volumes. Despite this, recovery has exceeded estimates from the initial field development plan, reflecting an extremely efficient waterflood. 4D seismic spectacularly images extensive sweep away from injectors and excellent reservoir connectivity. Throughout the development, the application of seismic technologies has been a key enabler for effective reservoir management and, looking forward, maximizing value.

The Jasmine Field, Blocks 30/06 and 30/07a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 498-510 ◽  
Author(s):  
H. M. Lawrence ◽  
L. E. Armstrong ◽  
K. Ashton ◽  
A. D. Jones ◽  
I. E. Mearns
Keyword(s):  
North Sea ◽  
Near Field ◽  
Dynamic Modelling ◽  
Structural Complexity ◽  
Late Triassic ◽  
Field Development ◽  
Well Production ◽  
Production Wells ◽  
Exploration Drilling ◽  
The Uk

AbstractThe high-pressure–high-temperature Jasmine Field lies 270 km east of Aberdeen in the UK Central North Sea and forms part of Chrysaor’s J-Area. Hydrocarbons were discovered at Jasmine in 2006, in Middle–Late Triassic fluvial sandstones of the Joanne Sandstone Member of the Skagerrak Formation. Appraisal proved a greater than 2000 ft hydrocarbon column and, in 2010, the Jasmine Field development was sanctioned. Five development wells were pre-drilled between 2010 and 2013, and the field was brought on line in November 2013, after which one further appraisal and three additional production wells were drilled. Jasmine infrastructure comprises an accommodation platform and a wellhead platform tied back to a riser platform adjacent to the Judy processing and export facility.Rapid early pressure depletion, a highly layered fluvial reservoir, structural complexity and variable fluid types present significant challenges for both static and dynamic modelling. Following production start-up, acquisition of new post-production reservoir pressure and flow data, and incorporation of allocated well production data, have been used to address these modelling challenges, and to provide encouragement for future infill and near-field exploration drilling opportunities.

THE ROLE OF RESERVOIR SIMULATION IN THE DEVELOPMENT OF THE CHALLIS AND CASSINI FIELDS

1990 ◽  
Vol 30 (1) ◽  
pp. 212
Author(s):  
I.G.D. Gorman
Keyword(s):  
Water Injection ◽  
Oil Field ◽  
Production Performance ◽  
Analytical Models ◽  
Production Test ◽  
Well Performance ◽  
Initial Development ◽  
Field Development ◽  
Production Wells ◽  
Interference Test

The Challis oil field development was approved in 1987 with marginal reserves (for an isolated offshore project) of 22 MMbbl. The initial development envisaged three subsea production wells connected via a riser to a floating production facility with one water injector also being required to maximise recovery. However, due to additional potential in the vicinity of the field, the production system was designed to accommodate up to 10 production/injection wells.Further appraisal in 1988/1989 doubled the reserves to 43 MMbbl and increased the number of initial production wells to seven from five reservoirs. The appraisal results also confirmed earlier concerns as to the structural complexity of the field. Analytical interpretations of the production tests performed on the wells could not be fully reconciled with the available well log, core and seismic data. Furthermore, the analytical models developed from these interpretations could not fully match the test results.Reservoir simulation was used to resolve, where possible, the discrepancies. Individual reservoir models were calibrated with the production test results and used to quantify the major uncertainties and their potential impact on production performance. The simulation results indicated that water injection may not be required. However, the degree of internal reservoir communication and the extent of the expected aquifer support were identified as the two principal unknowns.Production policy and monitoring procedures were structured to resolve these uncertainties as quickly as possible during the production start-up phase. Comparative forecasts of expected performance were developed for each reservoir with various levels of aquifer support. A surface controlled interference test was designed to investigate the extent of internal reservoir communication in the main reservoir.The success of the interference test and the results of the early well performance have confirmed the simulation predictions. Simulation modelling was successful in quantifying the range of expected pressure response (to production) for each reservoir and was able to quickly confirm the degree of pressure support present in each reservoir.

The Starling, Scoter and Merganser fields, Blocks 22/30a and 29/3a, UK North Sea

2020 ◽  
Vol 52 (1) ◽  
pp. 589-605 ◽  
Author(s):  
C. J. F. Freeman ◽  
R. J. Garrard ◽  
A. Farwana
Keyword(s):  
North Sea ◽  
Normal Pressure ◽  
Economic Recovery ◽  
Salt Diapir ◽  
Main Field ◽  
High Pressure High Temperature ◽  
Production Platform ◽  
Production Wells ◽  
Zechstein Salt ◽  
Central North Sea

AbstractThe Shearwater Field is located 242 km east of Aberdeen in the Central North Sea (CNS) and has three satellite fields, Starling, Scoter and Merganser. Acting as the hub for the gas-condensate-producing normal-pressure–normal-temperature (NPNT) satellites, Shearwater, which produces high-pressure–high-temperature (HPHT) Jurassic reservoirs, comprises a bridge-linked wellhead jacket to a production platform. The satellites, developed as subsea tiebacks, target Paleocene turbidite reservoirs, with the Starling Field most distant at 33 km from the host while Merganser is tied in via Scoter through a 15 km pipeline. Each satellite consists of a subsea manifold connected to two production wells at Merganser, and three production wells each at Scoter and Starling. All reservoir traps at the satellites are due to Permian-age Zechstein salt diapirs. Starling and Scoter produce Forties Sandstone Member reservoirs via three deviated wells targeting anticline structures. At Merganser, two long horizontal production wells cross over 4000 ft of faulted Paleocene reservoir intervals to produce under salt diapir overhangs. The satellites have been instrumental in maintaining the Shearwater facilities given early main field well failures, whilst recent challenges have developed as the satellites mature, requiring infill wells and well interventions to maximize economic recovery.

PENGEMBANGAN PEMBELAJARAN TARI LENGGOK MAK INANG MELALUI MULTIMEDIA INTERAKTIF BERBASIS E-LEARNING

2019 ◽  
Vol 8 (1) ◽  
pp. 49
Author(s):  
Ronni Lirahman ◽  
Yusnizar Heniwaty Heniwaty
Keyword(s):  
Field Trial ◽  
Interactive Multimedia ◽  
Multimedia Learning ◽  
Learning Material ◽  
Main Field ◽  
Initial Field ◽  
E Learning ◽  
Definition Of

ABSTRACT This research produced a product of the development of Lenggok Mak Inang dance learning through interactive multimedia which included appreciation learning material (Basic Competence 3) and expression (Basic Competence 4) in class X of SMK / SMA. The appreciation material contains the definition of dance, accompaniment music, clothing, patterns, while the expression material contains terms, variety and arrangement of motion in the Lenggok Mak Inang dance. From the test media experts got a score of 4,42 (Very Good), media experts got a score of 4 (Good), user trials which included an initial field trial of 4,08 (Good), main field trial 4,22 ( Very Good) and an operational field trial of 4,53 (Very Good). The results obtained indicate that the development of interactive multimedia learning Lenggok Mak Inang dance is very feasible to use or be used as a learning media for dance.                                                                                    Keywords: Interactive Multimedia, E-Learning, Lenggok Mak Inang Dance.  ABSTRAKPenelitian ini menghasilkan produk pengembangan pembelajaran tari Lenggok Mak Inang melalui multimedia interaktif yang didalamnya terdapat materi pembelajaran apresiasi (Kompetensi Dasar 3) dan ekspresi (Kompetensi Dasar 4) kelas X SMK/SMA. Materi apresiasi berisikan definisi tari, musik pengiring, busana, pola/ garis, sedangkan materi ekspresi berisikan istilah, ragam dan susunan gerak pada tari Lenggok Mak Inang. Dari uji ahli media mendapatkan skor 4,42 (Sangat Baik), ahli media mendapatkan skor 4 (Baik), uji coba pengguna yang meliputi uji coba lapangan awal 4,08 (Baik), uji coba lapangan utama 4,22 (Sangat Baik) dan uji coba lapangan operasional 4,53 (Sangat Baik). Hasil yang diperoleh menunjukkan bahwa pengembangan multimedia interaktif pembelajaran tari Lenggok Mak Inang ini Sangat Layak digunakan atau dijadikan media pembelajaran tari. Kata kunci: Multimedia Interaktif, E-Learning, Tari Lenggok Mak Inang.

scholarly journals Trusting the Corona-Warn-App? Contemplations on trust and trustworthiness at the intersection of technology, politics and public debate

2021 ◽  
pp. 026732312110283
Author(s):  
Judith Simon ◽  
Gernot Rieder
Keyword(s):  
Technology Development ◽  
Public Debate ◽  
Lessons Learned ◽  
Initial Development ◽  
The Public ◽  
Public Debates ◽  
Moral Duties ◽  
Moral Demands

Ever since the outbreak of the COVID-19 pandemic, questions of whom or what to trust have become paramount. This article examines the public debates surrounding the initial development of the German Corona-Warn-App in 2020 as a case study to analyse such questions at the intersection of trust and trustworthiness in technology development, design and oversight. Providing some insights into the nature and dynamics of trust and trustworthiness, we argue that (a) trust is only desirable and justified if placed well, that is, if directed at those being trustworthy; that (b) trust and trustworthiness come in degrees and have both epistemic and moral components; and that (c) such a normatively demanding understanding of trust excludes technologies as proper objects of trust and requires that trust is directed at socio-technical assemblages consisting of both humans and artefacts. We conclude with some lessons learned from our case study, highlighting the epistemic and moral demands for trustworthy technology development as well as for public debates about such technologies, which ultimately requires attributing epistemic and moral duties to all actors involved.

Optimization Applied to Buzios Flexible Riser Systems and Subsea Layout

2021 ◽  
Author(s):  
Vinicius Gasparetto ◽  
Thierry Hernalsteens ◽  
Joao Francisco Fleck Heck Britto ◽  
Joab Flavio Araujo Leao ◽  
Thiago Duarte Fonseca Dos Santos ◽  
...  
Keyword(s):  
Deep Water ◽  
Technology Use ◽  
Capital Expenditure ◽  
Lessons Learned ◽  
Internal Diameter ◽  
Flexible Riser ◽  
Flexible Pipe ◽  
Injection Wells ◽  
Gas Field ◽  
Field Development

Abstract Buzios is a super-giant ultra-deep-water pre-salt oil and gas field located in the Santos Basin off Brazil's Southeastern coast. There are four production systems already installed in the field. Designed to use flexible pipes to tie back the production and injection wells to the FPSOs (Floating Production Storage and Offloading), these systems have taken advantage from several lessons learned in the previous projects installed by Petrobras in Santos Basin pre-salt areas since 2010. This knowledge, combined with advances in flexible pipe technology, use of long-term contracts and early engagement with suppliers, made it possible to optimize the field development, minimizing the risks and reducing the capital expenditure (CAPEX) initially planned. This paper presents the first four Buzios subsea system developments, highlighting some of the technological achievements applied in the field, as the first wide application of 8" Internal Diameter (ID) flexible production pipes for ultra-deep water, leading to faster ramp-ups and higher production flowrates. It describes how the supply chain strategy provided flexibility to cover the remaining project uncertainties, and reports the optimizations carried out in flexible riser systems and subsea layouts. The flexible risers, usually installed in lazy wave configurations at such water depths, were optimized reducing the total buoyancy necessary. For water injection and service lines, the buoyancy modules were completely removed, and thus the lines were installed in a free-hanging configuration. Riser configuration optimizations promoted a drop of around 25% on total riser CAPEX and allowed the riser anchor position to be placed closer to the floating production unit, promoting opportunities for reducing the subsea tieback lengths. Standardization of pipe specifications and the riser configurations allowed the projects to exchange the lines, increasing flexibility and avoiding riser interference in a scenario with multiple suppliers. Furthermore, Buzios was the first ultra-deep-water project to install a flexible line, riser, and flowline, with fully Controlled Annulus Solution (CAS). This system, developed by TechnipFMC, allows pipe integrity management from the topside, which reduces subsea inspections. As an outcome of the technological improvements and the optimizations applied to the Buzios subsea system, a vast reduction in subsea CAPEX it was achieved, with a swift production ramp-up.

Case History: Coring in ERD Well with Collision Risk Challenge and Optimization of Coring Parameters Based on Previous Coring Jobs in Carbonate Formation Alleviated Core Recovery

2021 ◽  
Author(s):  
Rahul Kamble ◽  
Youssef Ali Kassem ◽  
Kshudiram Indulkar ◽  
Kieran Price ◽  
Majid Mohammed A. ◽  
...  
Keyword(s):  
United Arab Emirates ◽  
Lessons Learned ◽  
Low Flow ◽  
High Angle ◽  
Collision Risk ◽  
Pilot Hole ◽  
Field Development ◽  
Core Recovery ◽  
Carbonate Formation ◽  
Carbonate Formations

Abstract Coring during the development phase of an oil and gas field is very costly; however, the subsurface insights are indispensable for a Field Development Team to study reservoir characterization and well placement strategy in Carbonate formations (Dolomite and limestone with Anhydrite layers). The objective of this case study is to capture the successful coring operation in high angle ERD wells, drilled from the fixed well location on a well pad of an artificial island located offshore in the United Arab Emirates. The well was planned and drilled at the midpoint of the development drilling campaign, which presented a major challenge of wellbore collision risk whilst coring in an already congested area. The final agreed pilot hole profile was designed to pass through two adjacent oil producer wells separated by a geological barrier, however, the actual separation ratio was < 1.6 (acceptable SF to drill the well safely), which could have compromised the planned core interval against the Field Development Team's requirement. To mitigate the collision risks with offset wells during the coring operation, a low flow rate MWD tool was incorporated in the coring BHA to monitor the well path while cutting the core. After taking surveys, IFR and MSA corrections were applied to MWD surveys, which demonstrated an acceptable increase in well separation factor as per company Anti-Collision Risk Policy to continue coring operations without shutting down adjacent wells. A total of 3 runs incorporating the MWD tool in the coring BHA were performed out of a total of 16 runs. The maximum inclination through the coring interval was 73° with medium well departure criteria. The main objective of the pilot hole was data gathering, which included a full suite of open hole logging, seismic and core cut across the target reservoir. A total of 1295 ft of core was recovered in a high angle well across the carbonate formation's different layers, with an average of 99% recovery in each run. These carbonate formations contain between 2-4% H2S and exhibit some fractured layers of rock. To limit and validate the high cost of coring operations in addition to core quality in the development phase, it was necessary to avoid early core jamming in the dolomite, limestone and anhydrite layers, based on previous coring runs in the field. Core jamming leads to early termination of the coring run and results in the loss of a valuable source of information from the cut core column in the barrel. Furthermore, it would have a major impact on coring KPIs, consequently compromising coring and well objectives. Premature core jamming and less-than-planned core recovery from previous cored wells challenged and a motivated the team to review complete field data and lessons learned from cored offset wells. Several coring systems were evaluated and finally, one coring system was accepted based on core quality as being the primary KPI. These lessons learned were used for optimizing certain coring tools technical improvements and procedures, such as core barrel, core head, core handling and surface core processing in addition to the design of drilling fluids and well path. The selection of a 4" core barrel and the improved core head design with optimized blade profile and hold on sharp polished cutters with optimized hydraulic efficiency, in addition to the close monitoring of coring parameters, played a significant role in improving core cutting in fractured carbonate formation layers. This optimization helped the team to successfully complete the 1st high angle coring operation offshore in the United Arab Emirates. This case study shares the value of offset wells data for coring jobs to reduce the risk of core jamming, optimize core recovery and reduce wellbore collision risks. It also details BHA design decisions(4"core barrel, core head, low flow rate MWD tool and appropriate coring parameters), all of which led to a new record of cutting 1295 ft core in a carbonate formation with almost 100% recovery on surface.

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