Shell Expro Research Articles

Designing an optimal 4D streamer survey pays reservoir dividends

In this case study of a 4D survey offshore Norway, Keith Watt and Gavin Pattison of I/O company Concept Systems provide a case study of how planning and design of a 4D seismic survey ultimately rewards reservoir management. 4D started life as a research technology in the geophysicists’ domain, but the real beneficiaries of the final outcome are reservoir geoscientists. Over the last few years the reservoir engineering community has begun to understand the benefits of 4D and how the technology can be applied to optimise reservoir management programmes. Conferences such as the joint SPE/EAGE conference ‘What Do Petroleum Engineers Expect from Time Lapse Seismic, and Do Geophysicists Answer the Right Questions?’ in March this year helped to bring the two communities together to build a common understanding of the technologies. A key issue in 4D surveys is to ensure that the data is of sufficient quality to provide reliable imaging of changes in reservoir behaviour during production. For marine acquisition of 4D seismic using towed streamers, this poses a major positional challenge which Concept Systems has been addressing for several years now. The company has been involved in over 40 surveys, enough to identify that major sources of error arise from the towing of long cables and the differences in source/receiver positions between monitor and baselines surveys. To minimise these positional differences, the first priority is to measure them. In 2001 Concept began a research project in partnership with Shell Expro to develop software to measure the positional errors in 4D surveys and correlate them with the processed seismic data. The resulting ‘repeatability’ technology was used successfully in Shell’s 2002 North Sea 4D programme to QC/optimise the acquisition and to make 4D infill choices. One lesson from this early work was the significant benefit arising from anticipating the positional issues at an early stage of the process, in other words in the planning stages. The ability to measure 4D repeatability during the design/ planning phase of a 4D project, and to analyse multiple scenarios to decide on the best compromise between repeatability and acquisition costs, can significantly improve the quality of a 4D dataset. We focus here on the application of the technology and knowledge applied in the design and planning phase of a 4D project.

Briefing. What the papers say

Geology TodayVolume 19, Issue 3 p. 82-88 Briefing. What the papers say , Search for more papers by this author , Search for more papers by this author First published: 01 December 2003 https://doi.org/10.1046/j.1365-2451.2003.00409.x Geology Today is distributed to schools and colleges teaching A-level geology by courtesy of Shell UK Exploration and Production (Shell Expro). Read the full textAboutPDF ToolsRequest permissionExport citationAdd to favoritesTrack citation ShareShare Give accessShare full text accessShare full-text accessPlease review our Terms and Conditions of Use and check box below to share full-text version of article.I have read and accept the Wiley Online Library Terms and Conditions of UseShareable LinkUse the link below to share a full-text version of this article with your friends and colleagues. Learn more.Copy URL Share a linkShare onFacebookTwitterLinked InRedditWechat Volume19, Issue3May 2003Pages 82-88 RelatedInformation

Successful application of time-lapse seismic data in Shell Expro's Gannet Fields, Central North Sea, UKCS

The Central North Sea contains a large variety of oil and gas fields at different stages of maturity within the life cycle of an asset, at varying depths, in varied geology and at widely differing pressure and temperature conditions. Over the last three years Shell UK Exploration and Production (Shell Expro) has acquired new 3D surveys over many of these fields which, following careful attention to detail in acquisition and processing, have been quantitatively compared to pre-production surveys. Differences between these time-lapse seismic datasets have then been interpreted in terms of changes in reservoir fluid movement and changed pressure/temperature conditions. These interpretations have proven useful for reservoir management by identifying swept versus unswept zones, sealing versus non-sealing faults, efficiency of drive mechanisms and connected volumes to specific wells Four case studies from the Gannet Development illustrate how these observations have impacted reservoir management and show how application of this relatively new, yet rapidly maturing technology has had a positive impact on the remaining value of these fields. Importantly, the detectability of changes in the reservoir has been seen to be greater than predicted prior to data acquisition. Indeed, 4D seismic data have become an established part of the long-term plans for all of Shell Expro's subsurface assets. With these successes have come fresh challenges and future efforts will focus on reducing costs in proven 4D technology whilst pushing to introduce new techniques for data gathering and for interpretation of large volumes of new information.

R&M Case—A Contractor's Perspective

Click to increase image sizeClick to decrease image size Additional informationNotes on contributorsSteve ToogoodSteve is currently a Principal Safety & Reliability Consultant in the Defence Business Unit of Advantage Technical Consulting. Steve joined Advantage in 1989 experience includes development of availability models in support of Reliability Centred Maintenance (RCM) reviews of offshore oil and gas platforms. This led to a greater involvement in RCM studies for the oil and gas industry, culminating in the management of a large RCM review for Shell Expro and then was a major influence in the direction and emphasis of the RCM work conducted by the RN and Army. Additional activities include a wide range of ARM and Safety consultancy support to the MoD, defence contractors and the railway industry. More recently he prepared the draft public comment issue of Def-Stan 00–42 Part 3.

Gas field planning tool

AbstractGas Field Planning Tool (GFPT) was developed in 1990 by the Shell Group of Companies to fill the need for a tool for gas field planning and development using deterministic subsurface and surface models. Main initiators were Shell Canada, NAM (the Netherlands), Shell Expro (UK) and BSP (Shell Brunei), as these companies are major gas producers.Shell Companies now have several years experience with using the GFPT. Application ranges from simple single field models to corporate-level models with a large number of gas reservoirs and wells. Shell companies now using GFPT models are Shell Expro (UK), BSP (Brunei), SSB (Malaysia), Shell Canada, SPDC (Nigeria), SDA (Australia), Woodside (Australia), PDO (Oman), NAM (the Netherlands), New Business Development (e.g. Lunar Project) and in future also Shell Egypt.NAM currently has a GFPT model for the Anjum field in Friesland and for the Ten Arlo field in the north of Holland.GFPT is currently being migrated to an HFPT (Hydrocarbon Field Planning Tool), which can also be used for planning of condensate, oil and water developments and for control of hydrocarbon compositions in the network using PVT de-lumping at the well head (e.g. for LNG plants) and optimisation techniques (linear, non-linear or based on bean-back lists).

Holistic Environmental Assessment and Offshore Oil Field Exploration and Production

According to UK Government surveys, concern for the environment is growing. Environmental regulation of the industry is becoming wider in its scope and tougher in its implementation. Various techniques are available to assess how the industry can drive down its environmental impact and comply with environmental regulation. Environmental Assessments (EA) required by European law do not cover the whole life cycle of the project that they are analysing. Life Cycle Analysis (LCA) was developed to assess the environmental loadings of a product, process or activity over its entire life cycle. It was the first technique used in environmental analysis that adopted what was described as a holistic approach. It fails this approach by not assessing accidental emissions or environmental impacts other than those that are direct. Cost Benefit Analysis (CBA) offers the opportunity to value environmental effects and appraise a project on the basis of costs and benefits. Not all environmental effects can be valued and of those that can there is considerable uncertainty in their valuation and occurrence. CBA cannot satisfactorily measure the total environmental risk of a project. Consequently there is a need for a technique that overcomes the failures of project-level EA, LCA and CBA, and assesses total environmental risk. Many organizations such as, the British Medical Association, the European Oilfield Speciality Chemicals Association, the Royal Ministry of Petroleum and Energy (Norway) and Shell Expro now recognize that a holistic approach is an integral part of assessing total risk. The Brent SPAR case study highlights the interdisciplinary nature required of any environmental analysis. Holistic Environmental Assessment is recommended as such an environmental analysis.

Electrical Coiled-Tubing Drilling: A Smarter Drilling System

This article is a synopsis of paper SPE 52791, "Electric Coiled-Tubing Drilling: A Smarter CT-Drilling System," by D.R. Turner, SPE, XL Technology Ltd.; T.W.R. Harris, SPE, Shell Expro U.K. Ltd.; M. Slater, SPE, Amoco Corp. E&P Technology; M.A. Yuratich, SPE, TSL Technology Ltd.; and P.F. Head, SPE, XL Technology Ltd., originally presented at the 1999 SPE/IADC Drilling Conference, Amsterdam, 9-11 March.

Time-lapse seismic in Shell Expro - some examples and economic aspects 1

Time-lapse seismic in Shell Expro - some examples and economic aspects 1

Time-lapse seismic in Shell Expro — some examples and economic aspects

Time-lapse seismic in Shell Expro — some examples and economic aspects

On Irregular, Nonlinear Waves in a Spread Sea

Abstract Optimal design and reassessment of offshore structures requires a good understanding of the ocean environment. The motion of the sea surface can be viewed as a three-dimensional, nonlinear stochastic process in time. In order to characterize the wave environment adequately, we need to model its random, nonlinear, and spread nature. In this paper, we address: • the expected shape of a wave near a crest or trough, • the expected shape of the ocean surface at one point, given a crest at a different point, • an efficient method to incorporate nonlinear effects within linear wave simulations, • the magnitude of wave nonlinearity as a function of wave amplitude. Detailed comparison of theory and full-scale offshore measurements at the Shell Expro Tern platform show good agreement.

Implications of Fault Scarp Degradation for Brent Group Prospectivity, Ninian Field, Northern North Sea

Although the majority of the oil reserves contained in the Ninian field are being produced from tilted Middle Jurassic sandstones of the Brent Group, significant volumes of oil have also been discovered within a poorly documented, subtle structural trap that lies in the immediate footwall to the field's controlling, eastern boundary fault. Integration of well data and the interpretation of seismic surveys allow the definition of an area characterized by major footwall degradation. The data demonstrate that the 1.25-mi (2-km) wide area affected lies to the east of the zone of Brent Group truncation, along the whole 15-mi (25-km) length of the field. A combination of sedimentary and stratigraphic information shows that the degradation and products obtain a thickness that locally exceeds 450 ft (126 m). The degradation process appears to have been triggered by accelerated extension during the Callovian-early Oxfordian deposition of the Heather Formation. The development of pronounced fault terraces due to footwall collapse ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received February 26, 1996; revised manuscript received August 12, 1996; final acceptance December 24, 1996. 2Department of Geology and Geophysics, The University of Edinburgh, Kings Buildings, West Mains Road, Edinburgh, EH9 3JW Scotland; e-mail: jru@glg.ed.ac.uk 3Chevron (UK) Ltd., Ninian House, Crawpeel Road, Aberdeen, AB12 3LG Scotland. 4Department of Earth Sciences, University of Manchester, Oxford Road, Manchester, M13 9PL England. We would like to thank the Ninian Partners [Chevron UK Ltd., Murphy Petroleum Ltd., Oryx UK Energy Company, Sands Petroleum (formerly NESTE North Sea Ltd.), Sun Oil Britain Ltd., and Ranger Oil] for permission to publish this article. However, the views expressed here are ours and are not necessarily those of Chevron or the Ninian Partnership. Help was received from Rick Davis, Robert Heming, Bryan Man, Bill Higgs, Andrew Harding, and John Connor of Chevron. Gerry White is thanked for drafting the diagrams. Interpretations carried out using GeoQuest ies and iesx software mounted on Edinburgh's Seismic Workstation facility were supported by The Petroleum Science and Technology Institute (PSTI), Norsk Hydro, Shell Expro, and Esso Exploration and Production (UK) Ltd. The study forms part of a wider research program studying the occurrence and effects of fault scarp degradation and subtle stratigraphic trap formation in the Brent province currently being supported at The University of Edinburgh by a Natural Environmental Research Council (NERC) Realising Our Potential Award (ROPA) Grant, GR3/R9521. Finally, we would like to acknowledge AAPG reviewers Alan Roberts and J. Brint for helpful and constructive comments.

Dental problems in the offshore oil and gas industry: a review.

The study of medical evacuation records from offshore installation workers indicates that dental pathology is a significant problem. Dental evacuations (dentivacs) account for the highest single category of medical evacuation (medivacs). Dentivacs result in human suffering and are the cause of many lost man hours for the major oil operators in the United Kingdom. This paper reviews the reporting of dentivacs at Shell Expro over a seven year period and makes some suggestions for the way forward in the handling of offshore dental problems.

Field Trial Results of Annular Pressure Behavior in a High-Pressure/High-Temperature Well

Abstract The problem of annular pressure buildup due to heating of the strings by the (hot) well effluent, will typically be of concern in the design of casing strings for high-pressure/high-temperature (HP/HT) sub-sea wells. In such completions bleeding off the pressure through the wellhead, as done routinely with surface wells, is not possible. Theoretical studies indicated that, potentially, extreme pressures could develop in confined sealed annuli of subsea completions, posing a severe threat to well integrity. To investigate the effect under realistic conditions, Shell Expro (UK) ran battery operated gauges in the 9 5/8 in. × 13 5/8 in. annulus of an offshore HP/HT well, to record pressure and temperature changes during drilling, cementing and production testing. This paper presents the results of these tests and a general model for pressure buildup in unconfined sealed annuli to correlate the field data. Since only pressure and temperature measurements were available certain assumptions had to be made with respect to, e.g., formation response to pressure buildup, in situ liquid properties, etc. Although these assumptions could be debatable, it is hoped that by publishing and sharing ideas, a better understanding of annular pressure behavior can be developed.

Development and Implementation of an HSE Management System in Exploration and Production Companies

Summary This paper describes the experience to date with safety management systems (SMS's) and describes their implementation after the Piper Alpha disaster and Lord Cullen's report. It also shows the gradual expansion of these systems toward fully integrated health, safety, and environment (HSE) management systems. Our company policy, which was clearly stated before publication of Lord Cullen's report, is that work should not start until the appropriate controls are in place. Work based on this policy and on objective-setting SMS's within Shell IntI. Petroleum Mij. (SIPM) E&P coordination started in earnest soon after the publication of the report in Nov. 1990 and has continued without interruption since that time. Objective-setting systems may be defined as systems where the company management sets its own objectives or goals on the basis of functional rather than prescriptive requirements and then goes on to demonstrate how such goals have been, or are being, met. The paper ends with a projection of what may be expected in the future. Introduction Following the Piper Alpha disaster and the in-depth public inquiry led by Lord Cullen, the recommendation was made that all offshore installations on the U.K. continental shelf should have safety cases similar to those already required under the U.K. Control of Industrial Major Accident Hazards Regulations. This recommendation was given effect by means of the safety-case regulation within the U.K. with a Nov. 1993 deadline for the submission of safety cases. Shell Expro, as a major operator in the U.K. sector of the North Sea, had already begun work on its safety cases before publication of the Cullen report and was one of the companies that contributed to the so called "voluntary" safety cases before this date. It was apparent to E&P management within SIPM that the SMS and the safety case provided better assurance of safe operation and were of real value to Shell operations worldwide. (In this paper, Shell is sometimes used for E&P companies of the Royal Dutch/ Shell group in general, and Shell E&P is used if experience was gained through technical service agreements supported by SIPM E&P). It was also clear that a worldwide move toward such systems would take place. Thus, application of these systems was both good business and appropriate for all Shell E&P operating companies. As a direct consequence, an integrated project team (both project engineering and operations) was set up to implement SMS and safety cases throughout Shell upstream operations worldwide.

Work-based Learning in an Offshore Environment

SUMMARY This paper describes the pilot stage of a work-based learning project. The partners were the Robert Gordon University, Aberdeen, Shell Expro UK and seven Shell technicians who are also part-time students on the Robert Gordon University HND/BSc in Mechanical Engineering. The part-time course follows a day release format but the technicians are employed on a rota of 2 weeks offshore followed by 3 weeks onshore. It was recognized that their work was highly technical and that they had considerable responsibility. Shell have a formal competence assessment scheme and the project team compared this with the learning outcomes of the course. Areas of commonality in four subjects were identified as satisfying certain outcomes although in all cases some secondary evidence of understanding was required in addition to the competencies. A major problem is the inaccessibility of the workplace. Assessment was conducted by rig supervisors and two academics paid a quality assurance visit to a platform. All of the partners have found benefits from the programme although academics also reported an increased workload. It is planned to extend the scheme next year.

High-Pressure Well Design

Summary Shell U.K. E&P (Shell Expro), operator in the U.K. North Sea on behalf of Shell and Esso, plans to drill 20 high-pressure wells during the next 2 years. The well design is based on new standards developed after the U.K. Dept. of Energy restriction on high-pressure drilling in the autumn of 1988. Studies were carried out to optimize casing design and drilling performance on these wells. Several casing schemes, including a slim-hole option, were analyzed. The material specifications for casing and drillpipe were reviewed to ensure that they met the loads imposed during drilling, well-control, and well-testing operations. The requirement for sour-service material was weighted against possible H2S adsorption by the mud film. As a result, a new drillstring and two high-pressure casing schemes have been specified. The high-pressure casing scheme used depends on the maximum expected surface pressure.

Case Study Well Information: Records Management in the Key Business

In May 1988 a new Information Support Unit (ISTJ) was created in the Southern Business sector of Shell UK Exploration and Production Limited (Shell Expro), to implement corporate Records and Information Management (RIM) policies into a (hitherto fragmented) informally controlled record group: all records relating to the company's subsurface activities. The records concerned were classified as VITAL to continuing business success.

Drilling From Deepwater, Concrete Gravity Platforms

This paper discusses the operation of three different types of gravity platforms in the North Sea. When the Brent, Cormorant, and Dunlin fields platforms in the North Sea. When the Brent, Cormorant, and Dunlin fields were discovered, drilling required the use of a completely untried type of platform. Various design problems and their solutions are described. platform. Various design problems and their solutions are described. Introduction When oil exploration rigs first drilled in the northern North Sea, many companies knew that if oil was found, no established production method existed in such hostile waters. The announcement in Aug. 1972 by Shell U.K. Exploration and Production Ltd. of the discovery of the Brent Field heralded one of the most expensive and innovative oilfield development programs ever seen. In the following year, Shell announced the discovery of two more fields in the far north, Cormorant and Dunlin. For these three fields, six platforms were ordered (summarized in Table 1). Five of these were of a type completely untried for drilling operations: gravity platforms. Unlike a conventional steel jacket, which platforms. Unlike a conventional steel jacket, which relies on piles driven deep into the seabed to keep it secure, a gravity platform relies mainly on its own weight contacting a large area of the seabed to prevent it from moving. This paper discusses Shell's experience in operating three different types of gravity platforms (Fig. 1). (Shell Expro operates in the North Sea on behalf of Shell and Esso in a 50/50 partnership covering all areas where joint acreage is held). Because economic incentives to start exploiting the oil as soon as possible were great, there was no time to think out every detail of platform design before construction began. Simultaneous design and construction became the order of the day. When drilling engineers began to look at the problems of drilling from a gravity structure, it soon was apparent that disturbing the platform foundation (the seabed) by drilling through it would weaken the structure itself. Avoiding undue disturbance of the seabed and near-surface sediments was a major concern. These gravity platforms were larger than any used before. The high derrick-floor elevation along with the great water depth could lead to difficulties in getting mud returns while drilling tophole - the second major concern. A third problem was to design the conductor and subsequent pipe strings to take wind and wave loads, either applied directly or through the platform. Fourth, each individual platform had its own individual problems resulting from differences in general layout and design. Conductor String Design The main criteria for the conductor strings wereto be strong enough to absorb environmental loads,to be strong enough to take vertical loads imposed by platform settlement,to be strong enough to be driven to refusal using the largest diesel hammer that could be used in a derrick (Delmag D-55, 144,000 ft-lbf),if possible, to be driven so deep that mud returns could be obtained at derrick-floor level without fracturing the formation at the conductor shoe when drilling out of the conductor, andto be large enough for a 20-, 13 3/8-, 9 5/8-, and 7-in. casing scheme. P. 926

Value of Heave Compensators to Floating Drilling

This examination of the motion compensator concludes that it is one of the biggest advances made in offshore drilling in recent years. Analysis of the operation of rigs equipped with motion compensators indicates a saving of about 16 days per rig-year. Optimum bit loads allow maximum penetration rates and increased bit life. Another advantage is safety in penetration rates and increased bit life. Another advantage is safety in well killing and BOP-stack handling. Introduction Before the design and introduction of the first heave or drillstring compensators, variations in the distance between the bit and the drilling level owing to wave action were accounted for with the aid of bumper subs. As offshore exploration moved into deeper and rougher water and failures achieved new dimensions in terms of cost, an alternate and more flexible method was sought. The result was the motion compensator first produced in the late 1960's when Vetco Offshore, Inc., installed a twin-cylinder model on the Wodeco IV, a drill barge working in the Santa Barbara channel. This equipment operated successfully within its design limits, and the concept of hydraulic or pneumatic heave compensation was proved viable. At least seven companies are now engaged in the design and manufacture of compensators. Each machine has a mode of operation peculiar to itself and possesses its own series of peculiar to itself and possesses its own series of problems. Shell Expro has been able to analyze the problems. Shell Expro has been able to analyze the performance of both the Vetco and the RUCKER Shaffer performance of both the Vetco and the RUCKER Shaffer models since they were installed on Shell-contracted rigs in the North Sea in Jan. 1974. Operating problems of other models such as the Western Gear Single Cylinder and the Ocean Science and Engineering, Inc., Crown Compensator have been assessed wherever possible. Savings in terms of weather down-time, bit life, and personnel and equipment safety have been observed during the latter part of the winter and throughout the summer of 1973-74 and are discussed in some detail. Now that drilling has moved further north, almost to latitude 62 degrees, the weather has produced a greater impact on rig operations. West of the Shetland Islands, where extremely long swells have been observed with correspondingly high heaves, one rig would certainly have been shut down without a heave compensator. Drilling has continued successfully in weather conditions producing heaves in excess of 12 ft and blowout-preventer producing heaves in excess of 12 ft and blowout-preventer (BOP) stacks have been landed with similar movement. Principles of Operations Principles of Operations Motion compensators may be located in the crown block or between the traveling block and the hook; they may operate either pneumatically or hydraulically, or by a combination of the two. During rig heave conditions, the operating medium is forced back and forth by means of hoses between the compensator's piston/cylinder arrangement and a number of pressure bottles or accumulators (Fig. 1). In the traveling-block units, hydraulic hoses hang from their respective standpipes in the derrick, whereas the compensated crown eliminates these - all hoses are fitted to the outside of the derrick. The mode of operation may be considered active or passive, or a hybrid of the two. In the purely passive passive, or a hybrid of the two. In the purely passive system (Fig. 2), the activating fluid results in air being compressed and expanded in and out of a bank of accumulator bottles; use is made of the adiabatic gas law: p1V1k = p2V2k V1 k p = p2 − p1 = p1 [(--------) −1],.......(1) V1−AX JPT P. 938

Platforms in the Southern North Sea

Introduction While so much attention is being centered on developments and expectations in the Northern North Sea it is useful to look back at what has been done to date in the South. Such is the tempo in this industry that we rarely realize it was only 6 years ago that we were first faced with placing platforms off the east of England. We then described the environment there with all the superlatives now used for the Western Approaches. However, with familiarization and careful planning, operations in the gas fields are now routine. We should therefore review our experiences in the South and see whether what we have learned there can be used to help us in the North. In this review the platforms considered are those installed by Shell U. K. Exploration and Production Ltd. (Shell Expro) as operators of concessions owned jointly by Shell U. K, Ltd. and Esso Petroleum Co. Ltd. Leman Gas Field Platforms In 1967 Shell Expro installed its first platform in the North Sea in the Leman gas field about 30 miles off the cost of Norfolk. This was a drilling platform with decks measuring 150 x 114 ft. It stands on two similar jackets that provide, in all, 16 piles in a 4 x 4 configuration. In 1968 this Complex A development was extended with a production platform having decks 140 ft long and 70 ft wide. The platform is a 12-piled structure, the piles being in a 4 x 3 configuration. The reason for going to a two-platform plan was that it was necessary to install a platform as soon as possible to start development drilling, and install a complex that could safely produce gas to shore without disrupting that drilling. A further important advantage gained by this approach was that more reservoir data could be obtained before the design of the production facilities was completed. The second complex - Complex B - was started in 1969 when Platform BD (B - Drilling) was completed. Before detailed designing on this platform was started, several possible configurations were studied in order to arrive at the most economical platform design to suit the packaged rig that had already been contracted for. As a result, a 12-pile (4 x 3) single-jacket platform was selected with decks 150 ft long and 114 ft wide. A similar optimization study on the production platform resulted in an eight-pile (4 x 2) production platform resulted in an eight-pile (4 x 2) jacket designed to support production decks 150 ft long and 55 ft wide. For the third complex - Complex C - a twin-platform design was again chosen, A third drilling contractor had been selected, so the drilling platform was redesigned to accommodate a different rig configuration. This platform has one jacket of 12 piles, but in two rows of six each. JPT P. 1046