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OILFIELD TECHN
OLOGY MAGAZIN
E
AUGUST 2012
ww
w.energyglobal.com
VOLUME 05 ISSUE 06-AUGUST 2012
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ISSN 1757-2134August 2012 Volume 05 Issue 06
Copyright© Palladian Publications Ltd 2012. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.
On this month’s cover >>Oilfield Technology is audited by the Audit Bureau of Circulations (ABC). An audit certificate is
available on request from our sales department.
contents
Pipe coated with Bredero Shaw’s innovative Thermotite® ULTRA™ thermal insulation coating system is spooled in Norway for the Goliat project, the first project in the Arctic that requires wet thermal insulation pipe coatings. Thermotite® ULTRA™ is
an end-to-end system that includes both the line pipe and the field joint coating.
| 03 | EDITORIAL COMMENT
| 05 | WORLD NEWS
| 10 | FORECASTING THE WEATHER WINDOW John Mitchell, The Met Office, UK, discusses the role of specialist weather forecasting services for oil and gas operations in the North Sea.
| 14 | DECOMMISSION IMPOSSIBLE? Brian Nixon, Decom North Sea, explores the challenges and opportunities posed by the decommissioning of offshore oil and gas facilities in the North Sea.
| 19 | ROLE MODEL Tyson Bridger, Emerson Process Management, Norway, examines the role of reservoir modelling in EOR.
| 22 | SUBSEA CONTROL AND SIMULATION Simon Marr, Fugro Subsea Services Ltd, UK, introduces simulation tools for the subsea oil and gas industry.
| 27 | DISCIPLINED COLLABORATION Achieving accurate reservoir description through the integration of multi-disciplinary information is possible. Erick Alvarez, Laure Pelle and Jaume Hernandez, Senergy, UK, explain how.
| 33 | MOVING MOORING FORWARD Wolfgang Wandl, Viking SeaTech, Norway, investigates the significant cost and efficiency benefits provided by pre-laid subsea moorings.
| 35 | COMBATING CORROSION Glenn Weagle and Ron Maltman, Champion Technologies, Canada, analyse a new technology that is bringing precision to SAGD water quality management.
| 40 | LIGHTWEIGHT IS THE NEW HEAVYWEIGHT Kelly Soucy, Brett Huckerby and Karen Luke, Trican Well Service, Canada, explore the strengths of specially designed lightweight cementing solutions.
| 47 | REMOTE-CONTROLLED HOT TAPPING SUBSEA George Lim, T.D. Williamson, the Netherlands, discusses a new remote-controlled hot tapping machine that can be used to facilitate pipeline tie-ins by tapping into pre and post-installed tees, without diver assistance.
| 53 | PORTABLE PIPE COATING Paul J. Kleinen, Bredero Shaw, USA and Vlad Popovici, ShawCor, Canada, explore the practical and financial rewards that are offered by mobile coating technologies for offshore projects in this month’s cover story.
| 57 | CLEAN GREEN ANTI-SCALING David Wilson and Kelly Harris, BWA Water Additives, UK, discuss the development of a ‘green’ hydrothermally stable scale inhibitor for topside and squeeze treatment.
| 63 | THE POWER OF SCOUR R. A. Lind, Nortek, UK, and R. J. S. Whitehouse, H.R. Wallingford, UK, explain why it is vital to understand and monitor the effects of scour on offshore structures.
| 68 | ENSURING INTEGRITY Gordon McCulloch, INTECSEA Ltd, UK, gives us a look into the development of a model for asset integrity management in the oil and gas industry.
RISERLESS LIGHT WELL INTERVENTION
OPTIMIZING RESERVOIR DRAINAGE /AIN RISERLESS LIGHT WELL INTERVENTION
MEET US AT ONS 2012MEET US AT ONS 2012VISIT US AT STAND #507 IN HALL E TO LEARN MORE
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THE CAPABILITIES WITHIN EXPANDING
RLWIwe are the intervention in RLWI we are the intervention in RLWI t
Anna Scordos
Editor
Contact Information >> Palladian Publications Ltd,
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On 6 August this year, Nasa successfully completed the astonishing achievement of landing a US$ 2.5 billion ROV (arguably one of the most remotely operated
vehicles ever at a distance of 248 million km from its control room) on the surface of Mars. The purpose of the ‘Curiosity’ mission to Mars is to establish whether, at some point in its history, Mars could have supported life at a microbial level. Essentially, the rover’s task is to explore for the presence of hydrocarbons; specifi cally organic carbon compounds that constitute the building blocks of life. Amid scenes of excited jubilation at the successful execution of this exploratory endeavour, Nasa appears to have restored its own, and its country’s, reputation in the global public consciousness as a world leader in space exploration. John Grunsfeld, Nasa’s head of science has been quoted as saying, “There are many out in the community who say that Nasa has lost its way, that we don’t know how to explore, that we have lost our moxie. While [Curiosity] is certainly an international collaboration, this feat is something that only the US can do – and the rover is made in the USA.”
The exploration of space serves the advancement of mankind’s understanding of the universe, but clearly also carries with it the powerful weight of national pride. Space agencies around the world compete and collaborate with each other in their work to explore our solar system, just as global energy companies compete and collaborate to explore our own cold, hostile and remote regions here on Earth. The hydrocarbons that our industry is searching for at the moment are located in the Arctic, a region that endures a similar climate to Mars in terms of temperature. Mars’ surface temperatures can plummet to - 87 ˚C (- 125 ˚F) while the coldest recorded temperature in the Arctic is around - 68 ˚C (- 90 ˚F).
Aside from rivalry between nations to ‘claim’ their piece of the Arctic pie and establish for themselves improved geopolitical positions, the debate continues as to whether the companies choosing to explore and operate in the region are truly prepared to handle any technological failures that could lead to environmental damage. And despite investments of billions of dollars into state-of-the-art technology and equipment such as innovative horizontal drilling, advanced capping stacks and research into how spilled oil would dissipate and be collected in an icy ocean, failures do happen. Just ask Nasa. And, while ignoring the possibility of such failures is ‘optimism’ in the case of those launching and guiding Nasa’s unmanned probes into the vast emptiness of outer space, it would be downright reckless for oil companies operating in the Arctic to just go ahead and hope for the best. Contrasting with Nasa’s public image of exploration, we should not expect to see scenes of nervous OGCs crossing their fi ngers at the moment of fi rst production in increasingly diffi cult locations. Time and investment must continue to be channelled into researching and practicing solutions to all the potential problems the industry will face as it inevitably explores deeper into this region. Companies should also be prepared to walk away if, as Total’s head of development, Michel Hourcard explained in a recent issue of The Economist, they don’t feel prepared to take on the task: “Drilling in the Arctic is not being considered by us. Not at all. Our gases are enough for the moment. There are many technical challenges – there is too much ice, darkness and stormy weather.”
Exploration should continue, but continue with care. The last thing that anyone wants to hear again is, ‘Houston, we have a problem…’ O T
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world news
05OILFIELD TECHNOLOGYAugust 2012
inbriefDelays continue to hamper Shell’s efforts to begin its long-planned Arctic drilling programme. Despite managing to score a legal fait accompli against opponents of the programme (such as Greenpeace) by securing a court ruling that the US government’s approval of Shell’s oil spill response plan complied with federal law, the company’s plans have still yet to bear fruit.
According to a Shell spokesman, ice thickness in the Chukchi and Beaufort seas is at its highest level for more than a decade. Consequently, the ice has taken far longer to melt than usual, meaning that the brief window of time when drilling operations can take place has been significantly reduced.
Despite the adverse weather conditions, Shell remains optimistic that it can complete at least some of the drilling it had planned to perform this year. Curtis Smith, a spokesman for
Shell was quoted by Reuters as saying, “We’ve recalibrated what’s possible, based on weather and logistics this year. No matter how that turns out, we’re trying to make the most of the time that we do have in the theatre.”
In addition to unusually thick ice, delays have also hampered the permitting and approval of the company’s oil spill containment system. Despite reducing the safety standard by which the vessel, a refitted barge, will have to be judged (from a stationary offshore platform to a mobile offshore drilling unit), the US Coast Guard has yet to approve the required certification.
“It’s unfortunate that they may not be able to drill to depth, but that’s yet to be seen [...] The most important thing is that Shell demonstrate [...] that it can conduct safe operations in the Arctic” said Robert Dillon, an aide to Alaskan Senator Lisa Murkowski.
NIGERIAAccording to Andrew Yakubu, Managing Director of the Nigerian National Petroleum Corp., Nigeria’s production has reached an “all-time high” of 2.7 million bpd. According to Yakubu, “The security measures put in place by the federal government in the Niger Delta region was beginning to yield positive results.”
A 2009 amnesty for militants in the Niger Delta region saw production rise once more after attacks on oil facilities, which caused a 28% drop in output, began to decline.
SUDAN & SOUTH SUDANThe governments of Sudan and newly independent South Sudan have finally made an agreement over oil transit fees, over which a dispute threatened economic disaster and all out war between the two nations.
According to the South, a transit fee of approximately US$ 9.48 will be paid per bbl. of South Sudanese crude oil transported through Sudan’s pipelines. In addition to the per bbl. fee, a one-off payment of US$ 3.028 billion will be made by the South. Sabir Hassan, one of Sudan’s negotiators said that this was the equivalent of US$ 24 per bbl. in fees.
BRAZILBrazilian state player, Petrobras has signed chartering and operations contracts for 12 new offshore drilling rigs. The contracts with Sete Brasil, Queiroz Galvão, Petroserv, Odebrecht, Odfjell and Seadrill will ensure that the rigs are made with a minimum of 55 - 65% local content.
The rigs, due to arrive in 2016, will be able to operate in water 3000 m deep, drill up to 10 000 m and will primarily focus on the Santos Basin.
// Shell // Arctic drilling programme faces delays
India’s Ministry of Petroleum and Natural Gas has released a document outlining draft legislation for shale exploration in the country.
One of the most exciting aspects for international oil and gas majors is the fact that the legislation states that foreign investors would be eligible to bid on exploration rights and “Up to 100% participation by foreign companies and participation through unincorporated Joint Ventures would be permitted.”
Many oil producing countries limit the extent to which foreign oil companies can operate independently, with local-content laws, compulsory joint ventures, or restrictive contracts. Leniency towards foreign investors will likely make India’s debut shale bidding round (due 2013) an enticing prospect.
Thailand’s PTTEP moves one step closer to acquiring Cove Energy as it reports that it has received valid acceptances of its bid from shareholders whose combined stakes equate to 91.37% of Cove’s total issued shares.
With this latest announcement, PTTEP has met the minimum threshold, as set out in its initial offer, of 90% of Cove’s shares. The next step for PTTEP is to request that Cove’s shares are removed from trading on the London Stock Exchange.
PTTEP had originally been competing against a rival bid from Shell. However, Shell’s bid of £1.2 billion only secured 1.2% of Cove’s shares. Shell eventually pulled its bid and avoided a bidding war.
// India // Draft policy for shale exploration
// PTTEP // Cove bid nears completion
world news
06 OILFIELD TECHNOLOGY August 2012
diarydates
28 - 31 AugustONS 2012Stavanger, NorwayE: [email protected]://www.ons.no
17 - 20 SeptemberRio Oil & GasRio de Janeiro, BrazilE: [email protected]
08 - 10 OctoberSPE ATCESan Antonio, Texas, USAE: [email protected]/atce/2012
08 - 11 OctoberGastech 2012Excel London, UKE: [email protected]
04 - 09 NovemberSEG 2012Las Vegas, USAE: [email protected]
11 - 14 NovemberADIPECAbu Dhabi, UAEE: [email protected]/conference
20 - 22 NovemberPETEX 2012London, UKE: [email protected]
// Venezuela & Argentina // Oil alliance formed
President Hugo Chavez of Venezuela and President Cristina Fernandez of Argentina have formed a ‘strategic alliance’ between the state oil companies of their nations.
As part of the alliance the two firms, YPF (Argentina) and PDVSA (Venezuela) are to co-operate more closely in all areas. A joint statement that was later released said the aim of the alliance was “to identify strategic participation schemes for joint planning across the hydrocarbon value chain, both in Venezuela and Argentina.”
President Fernandez recently caused controversy after she led her government to nationalise YPF, Argentina’s largest oil company, which was at that point owned by Spain’s Repsol. The move was however, greeted with praise by the Venezuelan government, which has been involved in the nationalisation of its own oil
production. President Chavez was quoted as saying, “We celebrated in Caracas when we learned about the expropriation.”
As part of the agreement, PDVSA is to take part in projects to develop the vast shale oil and gas deposits that have been recently discovered in Argentina. For its part in the deal YPF will begin to operate in Venezuela’s huge Orinoco belt, the world’s largest single hydrocarbon reserve.
Representatives from the two companies are to meet in order to work on implementing the alliance.
The press conference at which the alliance between YPF and PDVSA was announced also served as a platform for President Chavez to refer to his country’s recent entry into the Southern Common Market (MERCOSUR), a trade block made up of Argentina, Brazil, Uruguay and Paraguay.
CNOOC has signed an agreement worth US$ 1.56 billion with China United Coalbed Methane Corp. (CUCBM) to explore for coalbed methane reserves in China. The contract is to last 30 years, with a preliminary exploration period of five years.
Almost 11 000 km2 are to be analysed during the exploration phase of the contract.
As part of Beijing’s ongoing strategy to ensure Chinese energy security, investment into unconventional resources has continued to grow. The Chinese government’s current goal is to double the amount of natural gas used overall, replacing ‘dirtier’ fuels such as coal and helping combat the high levels of pollution brought about by the country’s rapid economic development.
BHP Billiton, the world’s largest mining company has announced that it has had to shave off US$ 2.84 billion from the value of its assets in the Fayetteville shale, which it purchased from Chesapeake Energy Corp. in 2011.
BHP originally purchased the shale assets for US$ 5 billion when gas prices in the US were significantly higher than current levels.
Despite the writedown, a 2% drop in the company’s share price and the company’s CEO and head of the petroleum division foregoing their bonuses for 2012, Jac Nasser, BHP’s Chairman said, “Notwithstanding the prevailing environment we are confident in the outlook for the United States gas market and the role our shale assets will play in BHP Billiton’s portfolio in continuing to deliver long term returns.”
// CNOOC // Chinese CBM deal signed
// BHP Billiton // Shale asset writedown
AD00337P
world news
08 OILFIELD TECHNOLOGY August 2012
// Iran // US tightens sanctions on Iranian oil industry
// Total // KRG contract drives Baghdad to cancel// Global // Brent drops near US$ 108 per bbl.
// Devon // Profits down; JV confirmed
Total has announced that it has acquired a 35% stake in the Harir and Safen blocks in the region of northern Iraq known as Kurdistan. Marathon Oil Corp., will see its stake in both blocks fall to 45%. The company will remain operator of both blocks.
Annel R. Bay, Marathon’s VP of global exploration said, “We are pleased to have Total join Marathon Oil in exploring these high-impact exploration opportunities in the Kurdistan region of Iraq’s world-class hydrocarbon province.”
Despite the potentially lucrative nature of operating in Kurdistan, such a move risks angering Iraq’s central government in Baghdad, which views contracts signed between foreign companies and the Kurdistan Regional Government (KRG) as illegitimate. The KRG, however, says that the country’s constitution allows it to make such deals.
It is well known that signing such a deal would annoy the central government.
Chevron and ExxonMobil have both already been blacklisted by Baghdad for making deals with the KRG without permission. Both have been barred from bidding on contracts.
The risks were rather greater for Total, which already had a contract in place with Baghdad; a contract that is now in jeopardy. Abdul-Mahdy al-Ameedi, a spokesman for the Iraqi Oil ministry said, “We are working to cancel Total’s stake in the Halfaya contract. We will disqualify and terminate the contract of any company signing a deal with the Kurdistan region without the approval of the oil ministry.”
Contracts handed out at the last Iraqi licensing round expressly forbade companies from making deals with the KRG. However, the restrictive nature of the contracts that paid a set fee per bbl. (a system usually disliked by oil companies) caused many major companies to steer clear of the auction.
At the time of writing, Brent Crude has dropped in value towards US$ 108/bbl. Recent positive economic data from the US had actually helped boost Brent prices by approximately 3%; some analysts have pointed to profit-taking as the cause of the decline with investors keen to cash in on the earlier rise in prices.
Prices continue to be buoyed up by severely restricted exports from Iran and a maintenance-related fall in production in the North Sea. The shutdown of production from South Sudan’s oilfields have also placed additional pressure on global supplies. However, progress in talks between the two countries, means that production may soon start up again.
According to analysts from ANZ, “Brent is testing a longer term resistance at around US$ 109 a barrel.” If Tropical Storm Ernesto were to move towards the GoM and disrupt operations, prices could potentially hit US$ 111.
Devon Energy Corp. announced that it was to take part in a joint venture deal that would see the Japanese company Sumitomo Corp. take a 30% share in Devon’s Cline Shale and Midland-Wolfcamp Shale fields.
Sumitomo is to pay approximately US$ 1.4 billion in total for its role in the joint venture. The Japanese company is to pay US$ 340 million up front and invest the remaining US$ 1.025 billion in a drilling carry, which is expected to be realised by the middle of 2014.
This news was overshadowed by reports that earnings had missed predicted levels, which led to a 3.8% drop in the share price. The company posted a profit of US$ 477 million, compared to US$ 2.7 billion a year ago.
The US and its allies have continued to pile pressure upon the Iranian oil industry in a bid to strangle Tehran’s nuclear programme and prevent the country from developing a nuclear weapon; an objective that Tehran emphatically denies targeting.
The latest round of sanctions have been devised in order to make it even more difficult for the earlier sanctions to be evaded. The original sanctions had made the purchase of Iranian oil and oil products sanctionable and would see the perpetrator excluded from much of the international financial system.
The latest sanctions are designed to punish companies or organisations that have dealt with the National Iranian Oil Company, The Naftiran Intertrade Company or Iran’s Central Bank or
have helped Iran obtain US currency or precious metals.
These new measures have already seen two banks, the Chinese Bank of Kunlun and the Iraqi Elaf Islamic Bank, fall foul of the sanctions. Both of these banks are to be cut off from the US financial system. As one US politician put it, the new legislation “seeks to tighten the chokehold on the regime beyond anything that has been done before.”
According to some sources, Iran is now losing approximately US$ 133 million a day in lost revenue as a result of the constraints upon its oil exports.
Initially, there were fears that sanctions could cause a steep rise in prices and strain global supply, but a stumbling world economy and reduced demand has helped counter such effects.
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BOOTH #3516
A ccurately predicting a suitable weather window can make all the difference to the safety, successful
weather sensitive offshore operations. During offshore construction, transportation, heavy lift
operations and routine maintenance activities, the weather has a huge impact on the overall success of a project, and gives rise to a whole host of issues. The role of forecasters is to work closely with the oil and gas industry to reduce weather related risk.
help companies minimise health and safety risks, to protect
resource allocation. The application of expert, impartial advice and an in-depth
understanding of the science behind the weather and sea-states are helping the industry make their operations safer.
The ability to forecast the weather with increasing accuracy means forecast services are playing a more important role in the
offshore oil and gas industry. For weather sensitive tasks, delays due to weather downtime are reduced and therefore companies
A challenging environmentChangeable weather makes the North Sea one of the most challenging working environments in the world.
Statistics suggest that in a given 50 year period, (i.e. one in 50 year return) at the northern end of the North Sea wave heights could reach approximately 17 m (or 56 ft). During an extended period of stormy weather, the occasional wave could be even higher; these are known as ‘extreme waves’. In terms of wind, also within a 50 year return period, winds could reach up to 80 knots (or 92 mph); these do not include gust values, which can be even higher during stormy conditions. These conditions can pose a hazard to offshore operations and a risk to workers on platforms, vessels and helicopters operating in this area.
10
Forecasts are critical at different stages of a project, starting with the operational planning. Knowing how wind and wave conditions, such as wave height and wind speed, will be during the period of execution of a particular task is essential to
of suitable craft and derivation of suitable contractual
return on investment on that particular operation.Forecasts can help these companies minimise the risks
of their operations and maximise health and safety of their personnel, providing them with the necessary notice they require to take the appropriate measures needed to prevent any unnecessary disruption to their operations, as well as protecting the welfare of their staff.
the North Sea in 2010 was weather critical, and the culmination
continued uninterrupted production of oil and gas. This
weather window, was scheduled to take 12 days, involve 430 personnel on the Saipem S7000 crane barge and nine major lifts under dynamic positioning. This meant working in areas
time. For this reason, in addition to forecasts of wind strength and wave height, extra consideration was given to the wind
should it start to burn. The lift was ultimately completed to a high level of accuracy in a safe environment with no interruption to production.
Understanding the scienceAccurate forecasting demands a high level of science and expertise, as well as the capability to execute a number of complex calculations in a timely manner. Over the last three
11
12OILFIELD TECHNOLOGYAugust 2012
enabled enormous improvements in the sophistication of operational atmospheric and ocean wave forecasting models.
calculations per second.
marine forecasters based in Aberdeen is provided and during
Figure 1. Narrow country roads in Caithness, Scotland, meant that Subsea 7 had to transport a large tow head by sea from Nigg, Cromarty Firth, to Sinclair’s Bay.
Figure 2. Tow head attached to pipe bundles (up to 7 km in length) fabricated at Sinclair’s Bay.
Figure 3. Pipe bundles towed out to the Jura oil production fi eld.
management team.
Case study: Jura project - impacts of the weather on sensitive operations in the North Sea
Appropriate weather windows had to be determined to
tow head on the beach to attach the pipe bundle and then
on high water and roll-off was on low water. It is worth nothing
and understanding of the environment in which operations
the weather opportunities that would be available during the planned operations. O T
Quality runs deep.
Remote operation enables subsea access, reduces diver dependency and speeds execution.
Compact and lightweight for easy handling in adverse conditions.
Scan with your smartphone for a demonstration.
Quality runs deep.
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Performs from shallow depths down to 3,000 meters (9,842 feet).
Topside laptop control ensures total visibility for optimal accuracy and efficiency.
with the Subsea 1200RC Tapping Machine from TDW.
® Registered trademark of T.D. Wil l iamson, Inc. in the United States and in other countries. ™ Trademark of T.D. Wil l iamson, Inc. in the United States and in other countries. © Copyright 2012 All rights reserved. T.D. Williamson, Inc.
DECOMMISSION IMPOSSIBLE?Brian Nixon, Decom North Sea, explores the challenges and opportunities posed by the decommissioning of offshore oil and gas facilities in the North Sea.
Figure 1. DNS member, Perenco UK, safely executed the heavy lift removal of the Welland gas production platform in the southern North Sea.
14
There are many regulations impacting offshore oil and gas decommissioning.
Internationally they include OSPAR (the Oslo-Paris Convention), IMO (International Maritime Organisation) and the EU, while the Department for Energy and Climate Change (DECC) has responsibility for reviewing and approving all decommissioning programmes within the UK Continental Shelf. However, put simply, the current rules dictate that all man-made structures installed in northwest European waters have to be removed at the end of their economic life, unless
should be left in place.Recent changes announced by
the UK Treasury regarding tax relief for decommissioning are expected to provide certainty of government contribution to each project. This will provide greater assurance over liabilities on the one hand and thus help to stimulate late life acquisition,
those operators that are approaching
never wanting to increase the pace of decommissioning, it is hoped that this announcement will also result in a steadier rate of activity in the market, provide companies with more
pace of investment and innovation within the industry.
There are multiple reasons for the owners and operators of offshore oil and gas production facilities to defer the start of the decommissioning process. Decommissioning projects are expensive and
there is no return on the expenditure. New technologies have been successfully introduced over the years
far beyond their original design life. The ability to target and exploit marginal satellite reservoirs has increased
greater distances from the mother facility. The processing or transportation of third party oil or gas can also defer decommissioning. Decommissioning projects are complex, with technical, safety and environmental challenges, so rigorous and detailed planning and options appraisal add to the time taken
facility. And under current regulations there are no conditions to drive the start of the removal process, so there is no time pressure.
Opportunities and challengesDespite this, there is growing awareness in the countries around the North Sea that the industry is facing a bow wave of decommissioning activity in the coming years, as evidenced by the amount of planning and preparation currently underway in the sector. Professor Alex Kemp from the University of Aberdeen estimates the cost of decommissioning some
installations in the UK Continental Shelf alone to be £30 - £36 billion between now and 2040. On the one hand this represents a sustained business opportunity for the industry, and on the other hand a cost to the operators and UK Treasury of more than £1 billion per annum.
The industry is responding positively to this approaching programme with
planning and preparation of individual decommissioning programmes.
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16OILFIELD TECHNOLOGYAugust 2012
Different and often contradictory conditions – safety,
the strategy proposed for these complex projects, calling
New technologies, new techniques
decommissioning programmes:
Legacy and monitoring of sites following completion of
dismantling options, new designs for heavy lift and
are many and varied, and it is important to recognise that
Figure 2. A diagram mapping out the facilities, service types and technologies that are required in each phase of the decommissioning cycle.
order to highlight onshore yards that are active, or planning to
operators and contractors to select the most appropriate facility
Decomissioning as part of a lifecycle
lifecycle, and not treated as a separate project tagged on at the
programmes, one covering assets that may attract a derogation
to operating companies on the development of their plans for each
in a more consistent format and hence easier
that once this Standard Decommissioning
Overview
O T
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SPE is what you need.
For information about other SPE events visit www.spe.org/events.
Upcoming Americas EventsAttend these upcoming SPE events and meet with other professionals to learn about and discuss the latest E&P technical advancements:
SPE Liquids-Rich Basins Conference: New Technology for Old Plays
19–20 September 2012Midland, Texas, USAwww.spe.org/events/lrbc
Exhibit space and sponsorship opportunities are now available. For information visit the conference websites.
Society of Petroleum Engineers
www.spe.org
24–25 September 2012
The Westin CalgaryCalgary, Alberta, Canada
www.spe.org
SPE Hydrocarbon Economics and Evaluation Symposium
www.spe.org/events/lrbc
SPE Liquids-Rich Basins Conference: New Technology for Old Plays
19–20 September 2012, Midland Convention Center, Midland, TX, USA
Society of Petroleum Engineers
With the support of the SPE Permian Basin Section
This conference offers current operations practices and the development of tactics which are driving today’s exploitation of liquids-rich reservoirs. It will examine case histories and highlight innovative technologies and techniques applied throughout the drilling, completion, and production life of wells.
SPE Hydrocarbon Economics and Evaluation Symposium
24–25 September 2012Calgary, Alberta, Canadawww.spe.org/events/hees www.spe.org/events/curc
CALGARY TELUS CONVENTION CENTRE
30 OCTOBER–1 NOVEMBER 2012
CALGARY, ALBERTA, CANADA
SPE CANADIAN UNCONVENTIONAL RESOURCES CONFERENCE
SPE Canadian Unconventional Resources Conference
30 October–1 November 2012Calgary, Alberta, Canadawww.spe.org/events/curc
This symposium focuses on hydrocarbon and reserves evaluation and best practices and techniques to apply during global volatility. Experts from around the globe will share
their knowledge and present case studies on reservoir economics, market growth factors, and reserves, risk, and uncertainty.
This conference offers E&P professionals the latest techniques and best practices for discovering, developing, and producing unconventional resources in North America.
There are few sectors where the term ‘getting more from
less’ is more appropriate than in the oil and gas sector.
With demand continuing to outstrip supply and yet global oil and gas recovery rates still in the region of 20%, the last few years have seen a renewed focus on a wide variety of technologies to help improve recovery rates. Typical EOR (Enhanced Oil Recovery) technologies include gas injection, chemical injection and thermal recovery.
Furthermore, potential
recovery have never been higher. There are predictions that an oil recovery rate increase of just 1% would replace as much as three years of global oil consumption.
One previously overlooked means of extending reservoir life and increasing recovery rates, however, is that of reservoir modelling.
Reservoir models are becoming a default platform for examining and understanding subsurface geology. It is the reservoir modeller’s ability to build a realistic representation of the geometry of the reservoir that is vital for representing
correctly as possible. This article will examine
the latest developments in reservoir modelling and the key role it is starting to play in extending reservoir life and increasing recovery rates.
The many facets of reservoir modelling: embracing seismicThere are many elements of reservoir modelling that can provide crucial information towards future production strategies.
Just being able to see the distribution of porosity and the shape of the reservoir structure, for example, can make clearer how and where well placements should
Tyson Bridger, Emerson Process Management, Norway, examines the role of reservoir modelling in EOR.
ROLEMODEL
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20OILFIELD TECHNOLOGYAugust 2012
be made. Millions of dollars can potentially be saved by inserting proposed wells into the model, seeing how they need to be
The incorporation of 3D and 4D seismic into the reservoir model has also played an important role in combining seismic and well data to generate the most accurate and best-constrained models for describing which rocks are where.
It is this ability to leverage the seismic data and take it
- from reservoir simulation through to reservoir behaviour
reservoir modelling today.Emerson’s latest version of its reservoir modelling software
comes with new seismic inversion and seismic attribute tools. The inversion tool and increased automation allow geoscientists to use seismic data to create a rock property model quickly and accurately. In addition, these inversion tools are supported by new visualisation tools that enable modellers to extract maximum value from their seismic data through the creation of
the user through the facies modelling process.
Fracture modellingFracture modelling can also play a key role in helping operators understand their reservoir and as an input into EOR strategies.
enhancing the permeability of rocks and changing the
the world’s proven reserves of oil and gas are in carbonate or fractured reservoirs.
Despite the prevalence of fractures, however, conventional reservoir engineering techniques are often not suitable for a fractured reservoir development, due to the limited fracture data available.
As an alternative, fractured carbonate reservoirs are therefore often characterised through the integration of static data sets, including seismic, well cores and logs, petrophysical and geomechanical data, drilling and production data and data taken from analogue outcrops and regional maps.
Reservoir modelling software and a fracture-modelling module were used to develop a fracture model for a large Middle Eastern carbonate reservoir, despite not having a fracture data set in place and being reliant on geological concepts and geo-mechanics principles.
fracture attributes, such as aperture, length and width, density and fracture-surface morphology into the model, which was derived using analogue and geo-mechanics principles.
The result was a static model with the fracture permeability and sigma factor used for simulation purposes, for predicting reservoir behaviour, and for supporting EOR programmes. Figure 1 shows a discrete fracture network (DFN) of all the fracture sets.
Addressing the challenges of upscalingThe huge amount of data and highly heterogeneous descriptions of many oil and gas reservoirs bring with them a challenge of their own, with too many grid cells for effective reservoir simulation.
How can reservoir engineers upscale the models for
without losing the original structure of the geological model?Rock properties, such as porosity, absolute and relative
permeability all need to be upscaled accurately to ensure that
to the simulation model and is later provided as input to EOR strategies.
It is with this challenge in mind that a new methodology and algorithm has been developed to upscale the model as an irregular single layer simulation grid while still containing the geological structure of the original model.
The methodology was recently applied on a reservoir in the Middle East. In this particular example, the challenge was
2.5 million cell size simulation grid. The model included over 450 columns, over 250 rows, 300 wells and up to 75 faults.
the smallest variation changes in the model so that maximum heterogeneity could be kept if the two layers merged. At each stage of merging layers, the remaining heterogeneity was then calculated and converted to a percentage. Figure 2 illustrates how the heterogeneity is plotted versus model layers with the
minimised model layers combine with the maximum retained heterogeneity.
Figure 1. A discrete fracture network (DFN) of all the fracture sets.
Figure 2. How heterogeneity is plotted versus model layers in the upscaling of a reservoir model for simulation.
Through the application of the methodology on the reservoir, a highly accurate upscaled simulation model was developed with
of the simulation grid and the close correlation between the
The result is an excellent approximation of the high-resolution calculations performed in the original model within the simulation
Well correlationWell correlation tools are also playing an important role in allowing interpreters to handle complex geologies and realistic well geometries in a truly 3D environment and rolling out such
Roxar RMS, for example, comes with a well correlation system and interface that provides interpreters of well logs and
multiple wells, and log response snapshots or ‘ghosts’ can be
Increasing recovery ratesSo how are these new developments manifesting themselves in EOR programmes?
561.683.6992 | [email protected] | neptuneresearch.com
If you’re considering the pros and cons of composite solutions, consider that NRI has the most pros.
NRI has professional engineers on staff who evaluate hundreds of elements to determine the precise composite solution to guarantee your pipeline’s integrity. We invite you to speak to one of our engineers today and see why NRI’s innovative composite solutions and engineering know-how are recognized as the best in the industry.
worldwide to improve recovery rates and provide value and
is delivering recovery rates of up to 66% and is scheduled
systems such as RMS have also been adopted by operators
asset offshore Mexico, and BP’s Prudhoe Bay where recovery
fracture modelling, history matching, upscaling and simulation, 3D reservoir models have arguably become the most important decision-making tool exploration and production companies
O T
In an era characterised by the ‘peak oil’ phenomenon, much of the remaining oil and gas reserves lie in deeper, less accessible parts of the world’s seas and oceans. By 2006, over 3800
deepwater wells had been drilled worldwide and at that time deepwater production contributed 13.8% of offshore oil production
development particularly in the Gulf of Mexico, Brazil and the West of Africa, deepwater production is expected to grow rapidly over the next decade. All the construction and maintenance of production infrastructure installed in waters deeper than 300 ft is managed from the surface and relies heavily on remotely operated vehicles (ROVs) and advanced tooling capabilities. The management and control of installations at depths of up to 9000 ft is possible but is technically very challenging and much more expensive. As a result, operators pay greater attention to ROV pilot skills, offshore operations awareness, and to reliable, well-engineered solutions. Rigorous investigation and testing of designs in simulation before
deployment increases the likelihood of success and reduces risks to an acceptable level in what can be a very hostile and unpredictable environment.
The offshore oil and gas industry sets strict standards for
of production systems. This is due not only to the increasing complexity of the design of deepwater production systems – often multiple wells accessed via a template or clustered around
to the high costs of new developments and changing existing developments. Full scale system integration tests are not economically practical, so the oil industry applies modern simulator technologies for virtual testing of subsea systems to discover and
phases of projects, when the greatest savings can be made and there is time to improve designs and mitigate risk. Subsea services
SIMON MARR, FUGRO SUBSEA SERVICES LTD, UK, INTRODUCES SIMULATION TOOLS FOR THE SUBSEA OIL AND GAS INDUSTRY.
SUBSEA CONTROLAND SIMULATION
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contractors use modern simulation tools with models of deepwater systems to verify system functions and dynamic properties
range of environmental conditions. This includes model-based development of plant equipment and deepwater solutions for the design, installation and maintenance of safe deepwater production systems.
One such simulator is DeepWorks, which can act as an ROV trainer, an engineering simulator and a live operations visualisation toolset. The software’s ROV pilot training simulator uses dynamic simulation, with hydraulic and electrical component libraries to reproduce the actual subsea conditions and ROV tooling that characterise the physical environment and pressures under which ROV pilots work.
The simulator brings full force-modelled physics simulation to subsea scenarios so that remotely operated vehicles and other moveable subsea assets respond to electrical and hydraulic
demands, environmental forces and friction, just like the real thing. ‘Touch and feel’ interactivity gives ROV pilots the same graduated tactile response as if they were actually navigating the ROV, or deploying a tool such as a hydraulically activated nondestructive testing (NDT) measurement tool during a subsea inspection. Rehearsing operations across a wide range of conditions helps to
successful inspection, maintenance and repair operations. Being
ROV pilots to hone their skills quickly and allows ROV supervisors
operations based on an objective assessment of their performance.For planning purposes, running the engineering simulator on
a desktop PC provides a dynamic simulation engine that models the true hydrodynamic responses of offshore equipment when acted upon by environmental conditions. Engineers can quickly drag and drop components from the extensive libraries to build
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24OILFIELD TECHNOLOGYAugust 2012
subsea scenarios containing items such as vessels, pipes, cables and ROVs. Engineers can also add their own custom components
programme speeds up the evaluation of subsea engineering designs by simulating complex subsea interactions and collisions in great
By adding a real time module to the software, live monitoring of the topside and subsea operations with equal transparency
developments, giving a clear and accurate picture of what is really
location, with simulated data including pipeline location during a
3D world for subsequent review and for comparison with digital video records.
real time monitoring of ROV operations on its vessels and the engineering simulator for prototyping new tooling developments
Due to its wide range of applications across the whole upstream oil and gas process, simulation is now reaching many more parts of the business, resulting in shorter project lifecycles and enabling the
interface and removing the need for scripts and programming to be
account when designing a simulator. Simulators of this nature can be used not only for pilot training,
designs before new tooling is manufactured, and to test those designs in a full spectrum of simulated environmental conditions to
subsea worlds with vessels, pipes, cables and ROVs. Importantly for FSSL, the software can also be used to model ROV electrical and hydraulic circuit connections and component characteristics in
time and money.When companies encounter a subsea problem, a set of tools
ideas and mechanisms have never been used before, so being able to test a system before manufacture is of great value.
For training in fault detection and repairing, the underlying circuits
or components to test how well pilots understand their equipment.
is set up so that trainees can easily repeat a scenario until they get
returned to any point for review and detailed behaviour response analysis.
and effectively. Simulation and control technologies now provide operators with an unprecedented insight and ability to intervene directly in the design, development, deployment, operation and
speeding up production. O T
Figure 1. FCV3000 ROV operator console.
Figure 3. Simulation of an FCV3000 ROV carrying out NDT inspection of jacket tubulars.
Figure 2. Simulation of an FCV3000 ROV performing a complex intervention procedure.
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unconventionalwisdom
SPE Annual Technical Conference and Exhibition » 8–10 October 2012Henry B. Gonzalez Convention Center » San Antonio, Texas, USA
For 88 years, ATCE has been the leading technical conference in the E&P industry. Technical sessions, presented concurrently with an exhibition, focus on all phases of oil and gas exploration and production. Special events allow attendees to network and celebrate key successes in the industry.
Register Nowwww.spe.org/atce Society of Petroleum Engineers
Achieving accurate reservoir description through the integration of multi-disciplinary information is possible. Erick Alvarez, Laure Pelle and Jaume Hernandez, Senergy, UK, explain how.
SCIPLINTIONLLABORATI
DISCIPLINED COLLABORATION
A depends upon the appropriate integration of petrophysics, rock physics,
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28 OILFIELD TECHNOLOGYAugust 2012
disciplines are incorporated in the construction of a
Detailed and accurate petrophysical model
Figure 1. Traditional reservoir characterisation has limited communication between disciplines. Incorporating rock physics into the process improves integration and communication between all disciplines.
Figure 2. Petrophysics must be detailed, accurate, calibrated and representative of geological observations.
Figure 3. Rock physics analysis allows for the analysis of how petrophysical properties and seismic properties are related.
S Y S T E M S A C Q U I S I T I O N L I C E N S I N G P R O C E S S I N G I M A G I N G
Because our Z700 nodes are totally self-contained 4C recording units, we can easily deploy in congested waters at depths from 5m to 1000m, to bring you noise-free data to meet your survey specifications—quickly, efficiently and reliably.
True cable-free Z700 nodal acquisition: the efficient alternative to OBC.
30 OILFIELD TECHNOLOGYAugust 2012
characteristics are required to generate a useful petrophysics
Rock physics analysis
the theories often represent situations that are
μ
Quality check of seismic for AVO and preconditioning
Figure 4. Seismic data must be quality checked and improved before its use in RSC.
Figure 5. Blind testing enables the accuracy of the inversion results to be validated, above: blind test example in an acoustic inversion (Borgi and Hernandez, 2009).
Figure 6. Blind test example in an elastic inversion (Singh and Alvarez, 2009).
one can use the results of the rock physics
Seismic inversion
any statistical process, uncertainty and
Geological model update from seismic
The Strength of Experience...the Power of Innovation
DELMARDELMAR SYSTEMS, INC. Operations and Headquarters8114 West Highway 90Broussard, Louisiana USA 70518Tel: +1 337.365.0180 Fax: +1 337.365.0037
Technical and Engineering2424 Wilcrest Dr., Suite 225Houston, Texas USA 77042Tel: +1 832.252.7100Fax: +1 832.252.7140
Delmar Systems, Pty. Ltd.Perth, Australia
Delmar Sistemas de Ancoragem, Ltda.Rio de Janeiro, Brazil
Delmar North Sea Ltd.Aberdeen, Scotland
www.delmarus.com
For over 44 years, Delmar Systems, Inc. has been serving the oil and gas industry around the world. With an unwavering commitment to developing the most highly
Installed more preset mooring components worldwide than any other contractor.
than any other contractor in the world.
components available to support any mooring project.
Over 300 subsea component installations using the patented heave compensated landing system (HCLS).
Figure 8. Example of water injection and pressure build-up monitoring using 4D seismic (modifi ed from Marsh, 2000).
32 OILFIELD TECHNOLOGYAugust 2012
the uncertainties associated with the deterministic inversion and those associated with the co-simulation are difficult to ascertain, as they are combined in a single process. The other disadvantage is that minimum user input is required; therefore it is not easy to imprint the geological knowledge into the result.
Time lapse reservoir monitoringWhen the reservoir characterisation process
is essential to consider the use of 4D seismic to capture the reservoir variations associated with human activity. Time lapse seismic involves the acquisition of several 3D seismic surveys in different times, and by analysing the differences between those, it is possible to observe the changes in the reservoir related to changes in pressure and saturation.
The ability to obtain reservoir pressure and saturation changes using 4D seismic (which
allowing us to incorporate variations in the reservoir associated with injection water fronts, compartments
depletion and gas coming out of solution as a result of
With 4D seismic, the RSC process not only involves updating the geological model, but also requires direct interaction with the reservoir engineer to update the simulation model, improving history matching, and ultimately, providing more tools that allow us to make better decisions and achieve superior reservoir management.
SummaryTo reduce uncertainty, modern seismic-based reservoir characterisation projects must incorporate the rock physics element to improve integration and
Rock physics bridges the gap between seismic and reservoir modelling by establishing meaningful relationships between the seismic signal and the petrophysical properties in the subsurface, using the knowledge and understanding of geophysics, petrophysics, geology and reservoir engineering.
Traditional reservoir characterisation techniques rely mostly on qualitative estimations of the reservoir
estimate, and the incorporation of results carries a high grade of empiricism. The integrated rock physics-based approach described in this work, is one of the best quantitative tools to reduce uncertainty and obtain more accurate reserve estimates, whether looking for the best well placement or an update of the 3D reservoir model. O T
seismic properties are generated in time domain and the usual uncertainty in the depth conversion process is nowadays about 10 m, which in terms
The standard approach is to use advanced statistical techniques such as sequential co-simulation, using the seismic properties as a soft constrain; this way the variance among the statistical realisations can be reduced, leading to better P10, P50, and P90 estimates of recoverable reserves, as well as reducing the overall uncertainty, and ultimately resulting in a
such co-simulation and their use depends on the availability of data, reservoir characteristics, accuracy of the seismic estimations, and time.
Sequential co-simulation using the seismic properties as 2D maps: This is mainly carried out when the uncertainty of the depth conversion process is too high in this workflow; average property maps that broadly represent the distribution of the petrophysical properties in the reservoir are computed and without the need for depth conversion these maps can be used as soft constrain to co-simulate the distribution of properties at the desired resolution.
Sequential co-simulation using the seismic properties as 3D volumes: This is done mainly when the uncertainty of the depth conversion process is acceptable in terms of the resolution of the reservoir model, in this workflow; the seismic properties are converted to depth in 3D and directly used as soft constrain. This approach has the advantage of incorporating more vertical and lateral variability from the seismic properties, unlike the use of 2D maps, where the seismic only represents an average of the units to model
Stochastic inversion: In this process, the seismic inversion and co-simulation of the petrophysical properties occurs at the same time. Above seismic resolution, the process is equivalent to a deterministic inversion, and below seismic resolution the process is equivalent to using the inversion results to co-simulate using a 3D property as discussed in the previous point. The main disadvantage of this method is that
Figure 7. Incorporation of seismic-based properties in 3D through sequential simulation (Singh and Alvarez, 2009).
MOVING MOORING FORWARD
T he oil and gas industry can be very conservative when it comes to mooring, with many companies preferring to stick to tried and tested methods. However, for early adopters of
innovative mooring technologies, the rewards can be huge. Applying these new techniques can result in quicker repositioning of rigs,
The use of pre-lay mooring solutions, which can be applied in all but a small number of ultra-deep locations around the world, can
For example, the pre-lays being installed in Norway are enabling E&P companies to drill one or two extra wells a year, using the same
Pre-lays can be effective in the North Sea, the Barents Sea, Africa, Australia – in fact with the exception of few locations in South-East Asia and the really ultra-deepwater locations in Brazil,
pre-lay system means the mooring equipment can be installed prior to the arrival of the rig and then the rig simply hooks up to it when it reaches the location.
This avoids the process of having one anchor handling vessel holding the rig in position while three, or maybe even four other vessels, take the anchors from the rig and sail off to the next location to set the anchors before they are pulled in with the rig’s winch.
It is a relatively new technique and while some companies have been reluctant to switch from the systems they have been using relatively successfully for 20 years, oil majors including BP, Det Norske and Statoil are among the companies that have grasped the potential. In ultra deepwater and for drilling operations of up to 30 days, pre-lays are not the answer. However, with dynamic positioning vessels burning between 60 000 and 150 000 l of diesel a day, it can be a cost-effective solution for longer operations, particularly in the Norwegian sector of the North Sea. Norway currently imposes a
carbon tax (CO2) and a nitrogen oxide tax (Nox), which can amount to millions of dollars per year for each rig. That means for operations that require the rig to be on location for perhaps 45, 60 or 90 days, a pre-lay mooring option offers a more environmentally friendly and cheaper option as long as the rig can be safely moored.
Compare this to a conventional rig move, which requires a rig to remain on location and drill for up to 45 days. Firstly, a couple of anchor handling vessels are needed to pull the anchors out, which
embedded 10, 12, or even 15 m down in the seabed and it can be
vessel has to work for several shifts to get a single anchor out. The anticipated time for any anchor handling operation has
to be calculated in advance. This is because, depending on the regulations that apply (and these can vary from country to country), the estimated number of hours has to be multiplied by a factor, which is normally 1.5 or 2, to ensure that length of weather window. This is one of the most important issues when it comes to cost savings, which can be achieved by pre-lays. Therefore, if there is a weather window of 40 hours and the operation takes 20 hours then it has
encountered and the timescale is exceeded. In the Norwegian sector of the North Sea, for example, operations have to stop when the
For instance, there was an incident several years ago involving a rig move where there was a problem getting the anchor out and because the rig could not be moved to its next location as scheduled, the vessel had to remain onsite to keep the rig in position. The weather then got worse, which meant the rig move eventually
an extremely costly operation. Consequently, this delay was also transferred to the next E&P company.
Wolfgang Wandl, Viking SeaTech, Norway, investigates the significant cost and efficiency
benefits provided by pre-laid subsea moorings.
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With a pre-lay, the vessel could have gone out a week in advance when the weather was good, the waves were low, the sun was shining and at a time when the anchor handling vessel rates were low because these are spot market transactions. Such a strategy immediately makes this type of operation safer and cheaper, not least because it just takes one vessel instead of four to lay all four lines.
The work is then completed one to three weeks ahead of the required date when the weather conditions are good to ensure the mooring lines work. Then it is just a matter of disconnecting the rig at the old location, towing it to the new one and reconnecting it to the 8 or 12 mooring points, which are already in the water. The time requirement for this strategy is a fraction of the de-mooring and re-mooring operation.
If operators can get more drilling days out of every rig by using the pre-laying procedure, it would help the global supply situation
move, multiply this by the number of rig moves a rig makes in a year and then multiply again by the total number of rigs and it
industry. However, a new generation has to be persuaded of its value.
There may be a reluctance to spend money on an operation some companies might regard as ‘not vital’. But more can sometimes be less. It is not unusual for a rig day rate to be anything up to US$ 500 000, even if a rig is idle. So the investment in pre-lays
eliminates.
Changing behaviourThe conventional way of mooring is to have one set of equipment, which belongs to the rig and therefore is part of the rig rate. Pre-lays mean leapfrogging between the rigs’ own anchors and
may involve an additional cost but generates large savings.For instance, pre-laid moorings were installed off the
Ivory Coast, which helped save one company more than US$ 30 million. It certainly was not a typical operation and involved
soil instability as well as seabed obstructions. Instead of the rig moving between two drill centres 1000 m apart a number of times during the project, it was able to skid between two drill centres using only one taut leg system. This removed the need to run a traditional catenary system at both locations and reduced the time spent mooring. The rig was on location for a year and successfully skidded between the drill centres many times resulting in multi-million dollar savings on vessels and logistics.
Pre-lays do require massive anchor handling vessels, which are designed solely to cater for pre-lays and are different from conventional vessels. They are equipped with huge storage drums underneath the deck so that they can take three times the amount of mooring gear. Skandi Vega is one of the largest vessels of its type in the world at 110 m long and 24 m wide. In a recent operation, the Skandi Vega loaded 13 complete anchor systems in Norway to be used for pre-laying deep sea mooring equipment at a well east of Canada - the equivalent of loading around 2700 VW Golf cars onto the vessel. However, while specially designed anchor handling vessels like the Skandi Vega can handle a full pre-lay in one go, pre-lays can be so cost-effective that even a smaller handling vessel, that would have to make several journeys to deliver the equipment, would still save time and money.
InnovationsThere are a number of other technical innovations being developed
are generally made from nylon, polypropylene, polyester or a combination of all three. Threads of more modern materials such as Kevlar, Arimid and Dyneema can be added to the ropes to provide different characteristics and increase their strength. Fibre ropes are increasingly being used instead of chain because they are extremely easy to handle and very light, weighing only 4 kg/m underwater compared to chain at between 90 and 120 kg/m.
with the rig’s mooring.
but it has only really been widely available commercially for the last
the seabed because there is a risk that they could both damage corals and also be damaged themselves by the corals or any other
application to be safely stored on the seabed until mobilisation. It can then be picked up by an ROV in combination with a SPIN-buoy, which is acoustically released. A SPIN-buoy is shaped so it rotates vertically upwards through the water to the surface by itself, pulling
The SPIN-buoy pinpoints the position of equipment and allows an acoustic signal to be sent to the seabed to bring up the equipment eliminating the need for a vessel to use a grapnel to lift it
Another technological development is the Vryhof Stevtrack, which monitors an anchor’s behaviour during installation and
of drag anchors in deepwater or complicated projects from the
down, pulled and held. If the anchor can withstand the load in
accurately records the pitch and roll and load of the anchor so that there is no longer any need to rely on readings from old winches on a rig, some of which may be over 30 years old and inaccurate.
Last winter the winch readings on one rig were so inaccurate that the crew were unaware that three anchors were dragging. The use of state-of-the-art equipment might involve more capital outlay but it is much less expensive than the shutdown that ensued in this particular situation.
Looking to the futureOne vision of the future is that in a few years’ time all rigs will be moved between pre-lays; there will be large amounts of mooring equipment, which will not be recovered, instead it will be left laid
inspection but otherwise left on the seabed when not in use.One could also foresee a communication network on the
seabed similar to the mobile phone network on land. There are already many ‘stations’ on the seabed, which are able to send and receive signals. These stations will soon be able to speak to various parts of the equipment and identify load, position and any potential movement. All these technological developments point towards a new and exciting era in the mooring industry. O T
COMBATING CORROSION
Glenn Weagle and Ron Maltman, Champion Technologies, Canada, analyse a new technology that is bringing precision to SAGD
water quality management.
Maintaining boiler feed water (BFW) quality for once-through steam generators (OTSGs) is a key
(SAGD) operations. But many SAGD operators in Canada are running blind when it comes to protecting steam-generating
technology was unreliable in BFW.
crude oil or bitumen along with any water from the condensation
separated at the surface to its component streams. The water phase is recycled back and treated for use as boiler feed water.
The principal challenge behind maintaining BFW quality
production, which forces operators to acquire BFW for
and other contaminants. As a result, BFW used in most SAGD facilities is opaque slurry that confounds many SAGD
of oxygen.
measure. Chemical methods of protecting OTSGs from corrosion are well known and reliable. Many SAGD operators manage corrosion by adding a caustic to boost BFW
reactions, though strategies for accomplishing these
resources.
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36OILFIELD TECHNOLOGYAugust 2012
Of course, selecting the best treatment method for scavenging dissolved oxygen from an OTSG at any SAGD project must begin with determining whether oxygen is present in the system and in what quantities. Since only a few parts per billion (ppb) of dissolved oxygen in BFW can lead to severe corrosion problems, detecting and removing dissolved oxygen is a high-stakes objective that many SAGD operators struggle to achieve, even though they are running textbook OTSG operations.
Dissolved oxygen detectionThe most common methods used by SAGD operators to detect dissolved oxygen in OTSGs are polarographic and colorimetric techniques, which exhibit varying degrees of accuracy and ease of use.
In polarographic measurements, oxygen migrates through a permeable membrane into an electrochemical cell. In relatively clean water streams, instruments of this type can provide consistent and reliable dissolved oxygen measurements at the ppb level with little problem. Unfortunately, the membranes in polarographic instruments are quite sensitive to organic fouling, which limits their effectiveness in many SAGD operations.
Off-line colourmetric ampoules is another method frequently used to detect trace amounts of dissolved oxygen and is rapid and relatively easy to use. But it is prone to sampling errors. In addition, because colour development indicates the amount of dissolved oxygen present, the water samples cannot exhibit colour from organic contaminants. This requirement makes the method unsuitable for many SAGD facilities, because water sourced for BFW often has high total organic carbon content and can be dark brown in colour.
As a result, until recently, many SAGD facilities had no reliable way to directly measure dissolved oxygen in steam-generating systems, forcing operators to rely on indirect
residual present in BFW.
LDO detection trialWhile conducting research into oxygen-detection technology that could solve SAGD operators’ problems, heavy oil chemical treatment specialists learned that the sensitivity of a technology known as luminescent dissolved oxygen (LDO) detection had been enhanced by a manufacturer. To help SAGD operators eliminate a blind spot in their
operations-monitoring capabilities, they resolved to conduct a trial to evaluate the capability of upgraded LDO technology to detect dissolved oxygen at the ppb level in BFW.
An LDO meter and a polarographic instrument (the gold standard of membrane-based detection systems) were purchased from a manufacturer and the devices were used to detect and measure oxygen in a sample BFW stream. The polarographic device proved to be ineffective after a day and a half of use; the membrane became so fouled with organic solids as to require replacement and servicing. From an operational point of view, such frequent maintenance would have been impractical. By contrast, the LDO instrument effectively measured dissolved oxygen levels of 2 ppb in the BFW sample throughout the trial. After six weeks, the test was halted to check the calibration of the LDO instrument, and found it still to be completely in calibration.
The tests showed that advanced LDO instruments detect
phase shift that occurs as a result of oxygen quenching the
be attenuated by opaque water and the signal may become
decay is unaffected, generating a measurable signal detectable by LDO technology.
at low oxygen concentrations. So in opaque water, a signal is most likely to become somewhat attenuated only in high concentrations of dissolved oxygen. That means LDO technology is at its best when amounts of dissolved oxygen are low (less than 10 ppb) making it uniquely suited to protect OTSGs from oxygen-induced corrosion.
Early LDO applicationSince that revealing trial, LDO technology has been recommended for detecting and logging trace oxygen excursions in BFW at many SAGD facilities. In some instances, the technology has prevented the need for costly maintenance and even the loss of equipment.
In one early application, the operator of a SAGD pilot facility came discovered scale deposits composed of 50% haematite and 50% magnetite during inspection of a steam boiler, even though the facility was treating BFW with
re-started, an LDO meter was installed on the BFW line between the water-softener injection valves and the boiler, to sample and data-log oxygen levels.
The LDO device initially indicated that dissolved oxygen levels were near zero. But when a water truck arrived and started unloading water into the boiler system’s water tank, dissolved oxygen levels began to climb; within an hour of the delivery, the oxygen concentration shot up to
Data logged by the LDO instrument revealed the underlying cause of the corrosion problem revealed by the deposit analysis: oxygen excursions were occurring every time a load of water was delivered. Having the LDO meter online, logging dissolved oxygen data allowed
Figure 1. Dissolved oxygen in BFW.
Figure 2. BFW sample.
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38OILFIELD TECHNOLOGYAugust 2012
the operator to see precisely what was happening. Clearly, the
react all dissolved oxygen entering the boiler.To solve the problem, it was recommended that increasing
trucks unloaded. The second line in Figure 1 shows the results
the right-hand vertical axis had to be revised in order to show the sensitivity of the advanced LDO meter.
The source of this SAGD operator’s boiler corrosion most likely would not have been detected with conventional oxygen-sensing technology, which would have made solving the problem a less than empirical process.
LDO capabilities documentedSelected applications of LDO detection at other SAGD facilities are described in a technical paper, “Monitoring PPB Levels of
Figure 3. LDO meter.
Dissolved Oxygen in SAGD Facilities,” which was presented in June 2012 at the SPE Heavy Oil Conference Canada in Calgary. In summary, those applications were:
Case 1: The operator of a SAGD facility was recycling nearly 100% of produced water and wastewater, leading to highly opaque BFW containing high levels of organic contaminants (Figure 2). Dissolved oxygen was measured in the boiler feed water line after the hot lime softener, which was expected to de-aerate the BFW.
scavenger was required. A membrane electrochemical detector was installed, but operated for only two days before requiring
installed to sample and data-log dissolved oxygen in the BFW for an extended period of time, to determine long term oxygen-concentration patterns (Figure 3).
During a two month long test period, the LDO meter indicated that the dissolved oxygen concentration in the BFW was quite stable and within the target of less than 10 ppb (see Figure 2, BFW Dissolved Oxygen Study). But the LDO device did detect
in the sample loop, which caused the BFW sample to exceed
was re-established, the dissolved oxygen concentration measured by the LDO meter returned to the previous value. Otherwise, the dissolved oxygen concentration in the BFW remained constant and no BFW dissolved oxygen excursions were detected.
Case 2:At a SAGD facility using BFW in a closed recycle loop for a bitumen cooling heat exchanger, it was observed that the iron concentration in the BFW increased across the heat exchanger.
for the increase in iron. LDO meters were installed at the inlet
oxygen present in each stream. The LDO meters determined that the BFW stream contained 117 ppb of dissolved oxygen when it
that oxygen was being consumed in the heat exchanger (see Table 1, pretreatment, post-treatment data). In addition, the test revealed that: iron content of BFW exiting the heat exchanger increased
heat exchanger was less than 1 ppm, well short of the 25 ppm
concentrations at both the heat exchanger inlet and outlet were zero; iron levels dropped to 2.27 ppm at the inlet and 2.26 ppm at
results indicated that heat exchanger corrosion had stopped.
Case 3: Workers at a SAGD facility had detected corrosion in the source brackish water system and suspected dissolved oxygen excursions,
the system. A membrane electrochemical meter installed to detect dissolved oxygen became inoperative after a few days, and colourimetric assays were ineffective due to the high ionic strength of the water and the spot-check nature of that type of assay.
Table 1. Pretreatment, post-treatment data
Pretreatment
Exchanger in Exchanger out Difference
Total Fe 2.31 ppm 2.79 ppm 0.48 ppm
Dissolved O2 117 ppb 4 ppb 113 ppb
Sulfite residual <1 ppm
Post-treatment
Exchanger in Exchanger out Difference
Total Fe 2.27 ppm 2.26 ppm 0.01 ppm
Dissolved O2 <1 ppb <1 ppb
Sulfite residual 48 ppm
Dissolved O2, total Fe and sulfite residual were measured before and after the bitumen heat exchange cooler in Case 2. The dissolved O2 entering into the heat exchanger was 117 ppb and 4 ppb at the exit. This indicated that oxygen was being consumed in the heat exchanger. In addition, there was in increase in Fe found after the heat exchanger of 0.48 ppm. As well, the initial sulfite residual was less than 1 ppm. The sulfite target was 25 ppm. After correcting the sulfite injection, the dissolved O2 and Fe concentration across the heat exchanger was improved from the original observations. Dissolved oxygen was essentially zero at the inlet and outlet of the heat exchanger. Iron pick up across the heat exchanger dropped to essentially zero as well. This suggested that the corrosion was stopped.
Figure 4. The temperature and dissolved O2 concentration measured by the LDO meter at the Case 1 facility for over six weeks. There were two excursions detected. The first excursion was an artifact due to loss of cooling water to the sample loop. This resulted in high temperature BFW sample going to the LDO meter measurement cell. The second excursion was also an artifact due to the loss of water flow to the sample loop which was corrected by operations and the unit returned to normal operations. Otherwise the dissolved O2 concentration in the BFW remained constant and no boiler feed water dissolved oxygen excursions were detected.
Figure 5. Brackish water D.O. monitoring.
An LDO meter installed in the system to data-log temperature and dissolved oxygen concentrations detected two oxygen excursions
on Figure 5 by the red oval) was determined to be an artifact of sampling, because a concurrent spike in temperature occurred
excursion (indicated on Figure 5 by the green oval) was deemed to be a real spike in dissolved oxygen concentration, because a concurrent temperature increase was not observed, which
dissolved oxygen is monitored for extended periods of time, which previously was not possible at this site using typical ampoule based techniques.
ConclusionAll the cases cited above verify that advanced LDO meters are sensitive enough to accurately monitor and data-log trace amounts of dissolved oxygen in OTSG systems, where such measurements previously were not possible. Highly opaque BFW containing high levels of organic and inorganic contaminants does not appear to interfere with the LDO sensor.
Another unifying characteristic is that all of the problems detected by LDO meters were solved using well known, proven oxygen-scavengers. This suggests that the crucial factor in solving all the problems was not the chemistry prescribed, but the detection and monitoring capability of LDO technology.
These results indicate that LDO technology can play an important role in protecting SAGD facilities from oxygen-induced corrosion, by detecting excessive concentrations of dissolved oxygen in BFW before corrosion-related operating problems begin to crop up. O T
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LIGHTWEIGHT IS THE NEW
HEAVYWEIGHT Kelly Soucy, Brett Huckerby and Karen Luke, Trican Well Service, Canada, explore the strengths of specially designed lightweight cementing solutions.
40
Today’s exploration and production (E&P) companies are drilling to ever-increasing
depths. At these greater depths, the hydrostatic pressure of the mud system used while drilling or the cement slurry circulating during the cement job is increased. These higher hydrostatic pressures cause increased fracture propagation in weak formations, or the re-opening of natural fractures already present, resulting in lost circulation. Due in part to increasing environmental and regulatory pressure, along with the need to effectively isolate all zones from one another, E&P companies are moving towards designing production cement jobs with the intention of achieving cement returns at surface. Also, from an economics and environmental standpoint, attaining good cement returns to surface allows for retrieval of expensive invert mud from the hole for re-use on the next well.
Where losses encountered while drilling are not satisfactorily healed prior to the cement job, a likelihood of losing circulation during the cement job exists. The consequences of losing circulation during the production cement job vary, but the most immediate and perilous of these is the loss of well control and the potential for blowout. For the most part, previous lightweight cement systems relied on the use of a stage collar to increase the probability of cement returns. The stage collar is typically placed above the problematic zone and the cement is pumped in two stages, reducing overall hydrostatic pressure. Multistage jobs are generally an effective solution when dealing with losses; however, in order to optimise both fracture
41
42OILFIELD TECHNOLOGYAugust 2012
geometry and resultant production of a well, many of today’s fracturing operations require especially high rates and pressures during well completion. These high rates and pressures rely upon pump-down-casing techniques to effectively stimulate the zones. Stage collars, albeit seldom, can be unreliable and a potential weak link during these fracturing operations.
Meeting the need A need has evolved requiring cement pumping companies to deliver not only lower density cement systems to reduce hydrostatic pressure on formations, but cement systems that meet regulatory requirements for compressive strength development at shallow depths. These slurries must also have excellent properties in thickening time control, quick gel strength development, and ease of
up to the effectiveness expected of conventional non-lightweight cements, such as short transition time from liquid to solid, minimal to no free water, slurry stability, excellent ductility, low porosity, and excellent rheological properties.
Various lightweight cements, such as AccuLite™ 1200 (1200 kg/m3, 10.0 lbs/gal.) and AccuLite 1100 (1100 kg/m3, 9.2 lbs/gal.) have been developed with the properties listed above. Conventional low-density cement systems are successful for use down to 1320 kg/m3 (11.0 lbs/gal.). Below that, special low-density systems are required.
There are many excellent slurry designs that obtain the desired properties, but it is imperative that those properties achieved in the laboratory be
cements is to have great overall performance, but more importantly to have the physical characteristics, performance properties, and the
cement design.
Density control The advantages of a lightweight system begin with density control. Given that a primary concern is lost circulation and/or very weak formations, density and density control are critical. This means that the surface mix density of the design will remain the same as the cement reaches the maximum equivalent circulating densities (ECDs) in the wellbore. Rheologies are also just as critical. What is the point of pumping a low density slurry if it changes density as it is pumped? Density increase, due to fractionation of particles in the slurry, increases hydrostatics and effects rheological properties. Increased hydrostatics and rheologies are detrimental, as there is a risk of inadequately covering the annulus with cement.
Other properties are equally important, such as thickening time control. Slurry design must have the capabilities of controlling set times in cooler and hotter circulating temperatures. Figures 1 and 2 are
Figure 1. Thickening graph demonstrating set properties in a pressurised consistometer at 40 ˚C (104 ˚F).
Figure 2. Thickening graph demonstrating set properties in a pressurised consistometer at 80 ˚C (176 ˚F).
Figure 3. Gel strength graph at 40 ˚C (104 ˚F). Transition time from 100 lbf/100 ft2 to 500 lbf/100 ft2 is 26 min.
Figure 4. Gel strength graph at 80 ˚C (176 ˚F).Transition time from 100 lbf/100 ft2 to 500 lbf/100 ft2 is 25 min.
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44OILFIELD TECHNOLOGYAugust 2012
two thickening time graphs, demonstrating the set properties performed in a pressurised consistometer.
RheologyAs noted earlier, rheology is another important factor in the design. It is typical for cement service providers to aim for the highest strength possible for low density slurries. In doing that, the main design goal is to lower the water to cement
(w/c) ratio as much as possible. Conventional cements at such low densities would yield w/c ratios of approximately 300%. This amount of water results in poor compressive strength development. Not only does a high water content contribute to weaker strength, it also contributes to:
Long thickening times and transitions.
Poor fluid loss control.
High free water.
Poor slurry stability (settling).
High permeability.
Table 1 demonstrates the rheolgical properties of lightweight cements. Plastic viscosity (PV) and yield point (YP) remain low. These low rheological properties allow for low friction pressures, increasing the opportunity to obtain returns to surface.
TransitionsLightweight cements must also transition from a liquid to a gel to a solid quickly, in order to ensure that any risk of gas migration through the slurry is mitigated. As any slurry transitions from a liquid to a solid, it begins to lose its hydrostatic force. The cement starts to support itself on the formation and the casing, and at that point, any gas in hydrocarbon-laden formations has an opportunity to migrate into/through the slurry towards surface.
When designing and optimising lightweight systems, a target of < 30 minutes for gel strength development from 100 lbf/100 ft2 to 500 lbf/100 ft2 was used. Studies have shown that gel strengths of between 250 lbf/100 ft2 to 500 lbf/100 ft2 are
Figures 3 and 4 are gel strength development graphs.
Compressive strengthThe compressive strengths of low density blends are still very important. In many parts of the world, regulations and minimum requirements for compressive strength development are factors. Some areas require 48 hour compressive strengths of minimal 3.5 MPa (500 psi). Ultra-low density systems may require higher compressive strengths than shown on Figure 5. The technology is being further developed to provide more options for the more demanding wells. Cement designs with higher strengths and lower densities (< 1100 kg/m3
tested (see Figure 5). The compressive strength of a cement slurry is dependent
on the microstructure developed from the reaction products formed upon hydration of cement, and also their interaction with additional additives used in the formulated cement design. Figures 6 and 7 illustrate the microstructure of lightweight
a period of 48 hours. The hydration product that provides compressive strength is calcium silicate hydrate gel (C-S-H), and is typically the predominant product formed. C-S-H can have
slurry. Calcium hydroxide (CH) formed as a reaction product provides no strength on its own, but can react with silica rich additives to form additional C-S-H, increasing strength in the long term. Porosity (P) observed in the micrographs is due to the fact that reaction at
Figure 5. Compressive strength graph.
Figure 6. Microstructure of hydration products obtained on curing at 25 ˚C (77 ˚F) for 48 hours.
Figure 7. Microstructure of hydration products obtained on curing at 80 ˚C (176 ˚F for 48 hours.
Figure 8. Micrograph showing variation in particle size of spheres.
Figure 9. Micrograph showing expansive additive in cement matrix.
Table 1. Rheological properties
300 rpm 200 rpm 100 rpm 6 rpm 3 rpm PV (cP)
YP (lbf/100 ft2)
AccuLite™ 45 38 31 13 10 21 24
AccuLite™ 52 44 38 14 13 21 31
Out here isn’t the place to find out ifyou chose the right welding products.
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48 hours is still incomplete. Special lightweight additives used to
Case study
in remedial cementing costs and associated
O T
Table 2. Case study snapshot
energy companies™
cements
™
AUGUST 2012 ISSUE
http://www.energyglobal.com/magazines/register/oilfield-technology.aspx
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ONLINEN W
Hot tapping subsea pipelines plays a critical role in facilitating repair work
constructed in increasingly deep waters, carrying out pipeline interventions,
George Lim, T.D. Williamson, the Netherlands,
discusses a new remote-controlled
hot tapping machine that can be used to
facilitate pipeline tie-ins by tapping into
pre and post-installed tees, without diver
assistance.
REMOTE-CONTROLLED HOT TAPPING SUBSEA
47
48OILFIELD TECHNOLOGYAugust 2012
When pre-installed tees are present on the pipeline, the
not present, divers are required, but only to install the hot tap
pipelines in any water depth for operational, construction or
Subsea hot tapping: how it worksHot tapping involves drilling a hole into a live pipeline without
tapping procedure, a pilot drill is positioned in front of the
helps stabilise the larger hot tap cutter and retain the portion
When the valve is opened, the new connection is ready to be put into service.
Hot tapping challenges subsea
hot tapping professional on the vessel, and this professional
process. Although they are trained in hot tapping during the
viewing capability, the ability of the diver and hot tapping
challenges.
Adapting field-proven technology
Figure 1. Hot tapping is carried out via remote control with the Subsea 1200RC Tapping Machine.
Figure 2. The tapping machine is designed so that technicians control the system, and have a continuous view of subsea operations through a laptop computer onboard the DSV.
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50OILFIELD TECHNOLOGYAugust 2012
separate valve functions.
the rotation and position of the boring bar, and b) the position of the clutch cylinder.
However, no divers are required when a) pre-installed tees are present or b) post-installed tees are incorporated into the hot
Figure 3. The remotely operated vehicle stabs into the tapping machine control panel. A technician controls all tapping functions from a laptop computer.
Figure 4. The view of an actual hot tapping operation taking place. Technicians have a clear, continuous view of the entire subsea hot tapping process through the main window of the control program.
Figure 5. Tapping through a pre-installed tee.
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Tapping into pre-installed tees
without going to the expense of laying a new export line that extends to the shore or nearest hydrocarbon collection point.
Pre-installed tees are put in place during the pipe laying
leading end of the new pipe string and welded to the string,
and leak-tested to ensure tightness, and the tapping operation
can be leak-tested and all functions pre-tested before the
Tapping into post-installed teesA post-installed hot tap tee is one that is installed after the pipe
are energised by tightening longitudinal bolts. All bolting actions
Remote-controlled subsea fitting installation
disconnected at the valve interface and recovered to the surface.
Separating man from machine
tapping operations for repair and intervention, and on lines with
and costs are reduced. As operators delve into deeper and
O T
Figure 6. Tapping through a post-installed tee.
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SEARCH hundreds of international industry events on Energy Global
Paul J. Kleinen, Bredero Shaw, USA and Vlad Popovici, ShawCor, Canada, explore the practical and financial rewards that are offered by mobile coating
technologies for offshore projects in this month’s cover story.
The development of the offshore oil and gas reserves of the North Sea and - in the future - of the Arctic, raises
the challenges that operators and contractors are facing in these regions are those related to developing the pipeline transportation infrastructure required to move hydrocarbons
Most of the world’s pipelines, including offshore risers,
noted in one of the industry’s most comprehensive pipeline construction best practice handbooks published by the International Pipe Line & Offshore Contractors Association (IPLOCA), pipeline integrity for more than the nominal 25 - 35 years of service is an important aspect in any pipeline’s
during their service life because such failures could lead to
perception of pipeline failures is (generally) much worse than the actual human and economic failure costs, a lot of resources have been dedicated to protecting the pipes against any potential
1 The pipeline industry
with one or multiple functional roles, such as: anti-corrosion protection, mechanical protection, thermal insulation and
Portable vs. fixed coating technologies
new production regions are discovered and developed around the world, the traditional model is challenged, as the pipes have to be transported over longer distances to the project
and concrete weight coatings - reduce the quantity of pipes that can be transported from the pipe mill to the project location in
insulation coating, 25% more pipes could be transported in
PORTABLE PIPE COATING
COVER STORY
53
54OILFIELD TECHNOLOGYAugust 2012
Moreover, there is always a risk that the anti-corrosion or thermal insulation coating might get damaged during long haul
owner to coat the pipes as close to the offshore loading location
has therefore been developing new coating technologies that, while maintaining the highest quality and HSE standards, would
These innovative mobile pipeline coating technologies are
reducing pipe transportation costs, simplifying pipeline project logistics, providing end-to-end pipeline systems, and increasing
Mobilising concrete weight coatingsConcrete weight coatings have been developed and used during the last four decades to control the buoyancy of the offshore
prime candidate for mobile coating technology development
Although the obvious solution to control buoyancy would be to increase the wall thickness of the steel pipe, concrete coatings provide the industry with a heavy but better priced substitute that also protects the pipe against impact and
so it takes more volume than steel at equivalent weight, which reduces the number of pipes that can be transported in one trip
In order to avoid these additional logistic costs, the industry started to look for solutions to bring the concrete coating plant
processes for the concrete coatings is the compression coat
rotated and conveyed by support wheels at controlled rates
steel mesh and a PE outer wrap are simultaneously wrapped
The tensioned polyethylene outer wrap helps the complete
2
Continuous improvement of this side wrap concrete coating
coating plants can be up and running within two weeks of
coatings for offshore pipelines on a wide range of pipes from
demobilised, every component of the plant is repaired and
equipment is cleaned and quality tested before being crated and
Using mobile concrete coating plants for new pipeline projects
guaranteed coating quality anywhere in the world while avoiding
communities where the concrete coating plants are mobilised
concrete coating operations, such as: cranes, trucks, and
Mobile anti-corrosion protection and thermal insulation Brigden™ is a modular portable plant concept that is capable of
coatings using proven process technology while delivering the
This mobile plant is a turnkey coating facility assembled from process modules delivered in specially designed shipping
customised via the addition of more modules to the baseline
includes FBE and 3-layer anti-corrosion coatings, as well as
Electrical power can be provided from utility grid sources or can even be self-generated on site as per each project’s
structure is not a limitation as the modular design includes a complete steel frame fabric building capable of withstanding
Figure 1. Concrete coating applied by a portable plant.
Figure 2. Brigden™ facility installed for a flow assurance coating project.
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This type of portable coating facility is operated by a dedicated team of coating and engineering experts, trained in continuous improvement practices. The plant set-up and coating project execution are based on standard operating practices that are an integral part of the company-wide ShawCor Manufacturing System (SMS).
and safety of the environment were paramount in the design. The plant includes a process wastewater pretreatment system and has been demonstrated to operate without generating hazardous waste. The most recent Brigden mobilisation for
incident and injury free. The mobile plant has the same production capability as a
of 220 to 1066 mm (8 – 42 in.), lengths of 10.4 - 24.4 m (34 – 80 ft) and pipe weight up to 484 kg/m (325 lbs/ft). The plant comes
fully equipped with integrated facilities for raw materials storage, facility maintenance, and quality control and testing.
All phases of the coating operation, including surface
can be conducted in an enclosed area of 1700 m2 (18 000 ft2). A total area of 1.2 ha. (2.8 acres) is needed to set-up the entire facility, excluding pipe storage requirements.3
Finally, a mobile plant can also help increase the local content of the project, as most of the personnel involved in a coating project can be hired locally, as well as some of the coating materials and related services and handling equipment – front loaders, trucks, etc.
End-to-end coating solutionsField joint coating consistence and quality are critical for the long term integrity of an offshore pipeline’s coating system.
system are: excellent long term technical performance, perfect compatibility with the plant-applied line pipe coating, easy and consistent (same level of quality) application in any conditions and locations, and short application cycle time. Although the traditional approach was the manual application of these coatings, the selection criteria mentioned above have created incentives for specialised coating companies to automate the
O T
References1.
2. Concrete Engineering International
3. Oilfield Technology, August 2011.
Figure 3. Mobile field joint coating equipment on a spoolbase in Norway.
Clean green anti-scaling
David Wilson and Kelly Harris, BWA Water Additives, UK,
discuss the development of a ‘green’ hydrothermally stable
scale inhibitor for topside and squeeze treatment.
Concern for the environment has led to legislation that is driving the use of chemicals in the offshore North Sea oil industry. The increased awareness and scrutiny of the impact of chemical
discharge on the environment is likely to ensure adoption of these, or similar policies, on a global basis. The need for low toxicity,
biodegradable and hydrothermally stable scale inhibitors is increasing and greener chemistries are being sought to meet
these challenges. This paper describes a barium sulfate and calcium carbonate scale inhibitor that meets low toxicity
requirements and the present Norwegian ‘Y1’ criteria for biodegradation. Dynamic scale loop tests are used to
evaluate the inhibitor compared to a commercial ‘green’ inhibitor for carbonate and sulfate scales. Hydrothermal
studies performed under differing pH regimens
good potential for squeeze treatment under HPHT conditions in addition to topside application.
IntroductionScale control inhibitors play a major role
for many years in both squeeze treatment applications and also in the treatment of topside facilities. Once their job was
57
58OILFIELD TECHNOLOGYAugust 2012
complete, they were discharged into the sea. In recent years concern has arisen over potential damage to the environment from these discharged chemicals and the impact they may have on marine ecosystems. Re-injection of produced water has gone some way in mitigating the risk to the environment, however, there is still a need for greener chemistries to further reduce the impact.
International guidelines and regulations have been and continue to be put in place in various parts of the world,1 but there are differences of opinion, even between countries using the same regulations.2 The challenge for any green inhibitor is to not only meet or exceed these regulations but to also be able to inhibit mixed scale, both downhole and at the surface separation facilities.3,4 A global harmonised system needs to be put in place. If global agreement cannot be reached then it should be incumbent on operators, service providers and chemical manufacturers to voluntarily ensure that the best chemicals and practices be used to protect the environment.
In countries where no regulations are in place, self-regulation by the deployment of chemistries that meet the most stringent regulations and have been introduced in other parts of the world should be adhered to. The selection of chemistries should be
There appears to be a fundamental mismatch in requiring
temperatures being encountered downhole. Existing green inhibitors have not found wide acceptance for deployment as squeeze chemicals due to their inherent hydrolytic and thermal
has also shown a resistance to hydrothermal degradation
squeeze application in addition to surface treatments should be possible utilising this chemistry. It remains to be seen if further development of inhibitors can reach the harsher HPHT
presented in this article give hope for the future.
Experimental
Environmental testsEnvironmental testing was performed under GLP conditions at
performed are listed in Table 1.
Calcium carbonate threshold testThis test is designed to assess the performance of potential inhibitors under simulated Brent formation water conditions to inhibit calcium carbonate precipitation. Two synthetic solutions are prepared, one containing the scaling cations and the other containing the anions. The two waters are mixed in a 50:50 ratio. The anion solution is added to the bottle, followed by the inhibitor solution and then mixed. The cation solution is added with mixing and the bottles are shaken in a water bath
calcium remaining in solution is analysed by titration with EDTA solution. The water chemistry used in the test is presented in Table 2.Figure 4. Barium sulfate dynamic scale loop test.
Figure 3. Calcium carbonate scale loop test.
Figure 2. Calcium carbonate threshold test.
Figure 1. Dynamic test schematic.
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Greater Student Focus
Our theme for PETEX 2012 is ‘Global Frontiers, GlobalSolutions’. We’re promising a comprehensive programmeillustrating the latest global activity in exploration, fielddevelopment, reservoir management and unconventionalexploitation.There will also be a special interactive Plenary Session,
consisting of a panel of experts who will debate on the main societal challenges facing the industry today.Following the success from last time, PETEX will again host the Petroleum Geoscience Research CollaborationShowcase.
Building on the success of last time, PETEX will be hostingthe PESGB Graduate Career Fair, Student Lunch and newto PETEX 2012: The University Forum: a place forUniversities to interact with both students and industry.
For more information and to register for the eventplease visit our website: www.petex.info
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gist
er
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We will again be providing a special area for internationalrepresentatives, including: Oilcompanies; Ministries; Governmentsand Other promotional agencies.This designated space will provide
representatives with a forum to increase their exposure and promote licensing roundsand/or available acreage.
International Pavilion
Event Information
60OILFIELD TECHNOLOGYAugust 2012
It is then sparged with nitrogen to minimise head space oxygen
Results
Environmental tests
ow
> 70% biodegradable in 28 days (OECD 301A, OECD 301E).
> 60% in 28 days (OECD 301B, OECD 301C, OECD 301F or OECD 306).
on
ow
7
Figure 6. Barium sulfate dynamic scale loop test: effect of pH on the stability of PCA at 150 ˚C.
Figure 5. Barium sulfate dynamic scale loop test: effect of temperature on the stability of PCA at natural pH.
Calcium carbonate dynamic scale loop test
Barium sulfate dynamic scale loop test
Hydrothermal stability test
61OILFIELD TECHNOLOGY
August 2012
Figure 8. Calcium carbonate dynamic scale loop test: effect of temperature and pH on the stability of PCA.
Figure 7. Barium sulfate dynamic scale loop test: effect of temperature on the stability of PCA at pH 8.0.
Calcium carbonate threshold testInhibitor levels of 2, 4, 5 and 7.5 mg/l as solids were evaluated in this test and compared with that of polyaspartate
inhibition of the calcium carbonate deposition. As can be
an unusual observation that was reproduced in subsequent
from the 5 mg/l result could be due to a calcium compatibility issue of the PASP giving rise to particulate calcium PASP deposition. This deposition would exacerbate calcium carbonate crystallisation by providing growth sites and the subsequent lower dose level after PASP calcium salt
this water type.
Calcium carbonate dynamic scale loop testIn some ways, dynamic testing is less severe than the threshold static jar test, since replenishment of inhibitor with time favours improved results. In the jar test, the inhibitor concentration decreases with time once a crystal is formed, but in the dynamic test the constant inhibitor level throughout the test ensures that it is the growth inhibition mechanism that is being studied. The roughness of the metal surface acts as growth sites for initial crystal formation.
calcium carbonate dynamic scale loop test. Excellent
demonstrating the growth inhibition properties of the inhibitor.
whereas the PASP does not perform to an equivalent level even at a 2.5 mg/l dose level. Increasing the dose level to 4 mg/l for the PASP gives an inferior result to that obtained at 2.5 mg/l mirroring the increased dose level phenomena
dosage used.
Barium sulfate dynamic scale loop testThe primary mechanism in this dynamic pre-scaled test is that of growth inhibition where the inhibitor blocks off the active growing sites on the barium sulfate crystal surface. Poor growth inhibitors would therefore give poor performance in this test.
sulfate scale at 4 mg/l solids dose level, giving no pressure
graphically. As the pH of this system is being buffered at pH 5.5 one would not expect any calcium salt formation from the PASP, even with the higher calcium levels in this water.
Hydrothermal stability testAny chemical being contemplated as a potential squeeze inhibitor must be able to withstand the thermal and aquatic environment encountered in the reservoir for long periods of time, typically 12 to 18 months or longer, without breakdown.
for a period of three days. Performance testing using the barium sulfate dynamic loop test demonstrated no change
published elsewhere8 and higher pH conditions confer greater hydrolytic stability.
starting at natural pH and then pH 3.0 rising to pH 8.0 in one pH unit increments. Subsequent testing of these solutions in the barium sulfate dynamic scale loop test is presented in
is such that all activity against barium sulfate scale is lost
hydrolytic stability is improved and increasing dose levels can inhibit barium sulfate scaling. At pH 8 no degradation is
level requirements before and after hydrolytic stability testing, in the barium sulfate dynamic scale testing.
Having established a pH at which no change in activity
and the hydrothermally treated product, both still requiring 4 mg/l dose level to give complete barium sulfate inhibition.
62OILFIELD TECHNOLOGYAugust 2012
inhibition is maintained.
carbonate scale after the hydrothermal stability test was
Table 4. Synthetic seawater chemistry
Ion Concentration mg/l
Calcium 428
Magnesium 1368
Potassium 460
Sodium 10 890
Sulfate 2960
Choride 19 773
Table 2. Calcium carbonate test water
Ion Concentration mg/l
Calcium 350
Magnesium 56
Sodium 10 077
Potassium 283
Barium 50
Strontium 50
Bicarbonate 1000
Chloride 16 058
Sulfate 0
TDS 27 924
pH 7.8
Table 3. Barium sulfate test water
Ion Concentration mg/l
Calcium 636
Magnesium 634
Sodium 14 760
Potassium 446
Barium 120
Strontium 190
Bicarbonate 0
Chloride 26 930
Sulfate 530
TDS 44 246
pH 5.5
Table 1. Environmental tests
Study PCA
Toxicity testing
Marine algal growth inhibitionSkeletonema costatum EC50 72h (mg/l)
> 1000
Acute marine copepod toxicityAcartia tonsa EC50 48h (mg/l)
> 100
Toxicity to fishScopthalmus maximus juvenile LC50 96h (mg/l)
> 1000
Bioaccumulation log Pow
(OECD 117)< 1
Biodegredation % in 28 days(OECD 306)
68.6
activity with the 2.5 mg/l dose level giving equivalent results to the 2 mg/l non-heat treated sample and the 3 mg/l hydrothermal sample being equivalent to the 2.5 mg/l additive without heat treatment. It is also clear from these
natural pH of the product, pH 1.0, results in loss of activity against calcium carbonate. Increasing the pH to 7.0 and then pH 8.0 results in increased hydrolytic stability as demonstrated by the improving results at 2.5 mg/l dose level at these pH levels. Indeed at pH 8.0 the hydrolytic
level.Wat et al.9 have demonstrated that there is a possibility
of discarding perfectly acceptable squeeze inhibitor candidates by utilising the conventional type of test. The hydrothermal stability data presented here represent a worst case scenario regarding hydrolytic attack, as the molecules
on the sandstone/limestone surface. Obtaining positive
for the use of this chemistry in squeeze treatments.
Conclusions
and in some cases exceeding current regulations for ‘green’ chemistries.
efficient in the inhibition of both barium and strontium sulfates and calcium carbonate formation.
has been exemplified by its hydrothermal stability up
O T
References1.
Environments – Development Practices, Achievements and
on Health, Safety and Environment in Oil and Gas Exploration and
2.
3. D. Wilson and B.J. Hepburn, “An Alternative Polymer for Squeeze
Exhibition, New Orleans, LA.4.
5. D. Wilson, “Barium Sulfate Scale Inhibitor Evaluation Using a Tube-
‘Biodegradability in Seawater’, 17 July 1992. 7.
8.
9.
We Discarded Promising Products by Performing Unrepresentative Thermal Ageing Tests?”, SPE International Symposium on Oilfield
THE POWER Sediment transport takes place naturally
within the marine environment. This is due to the driving forces of currents and waves.
Variation in the transport of sediments gives rise to erosion and deposition. Couple this with the inclusion of a structure on the seabed and scour of the sediment, local to that structure, may occur.
Scour around a marine structure is the removal of sediment such as silt and sand, which can result in the formation of scour holes, which may compromise the integrity of the marine structure. A great amount of research has been undertaken in laboratory facilities to measure scour development
This has given scientists and engineers a broad understanding of the mechanisms for the development of scour at a marine structure, although conditions in the laboratory can never fully mimic the conditions present in the real world, which can lead to uncertainties about the scouring process. Considerable research has also been carried out outside of the laboratory and this has
is going on and not a continuous analysis, which again leads to uncertainties.
The oil industry has been dealing with the problem of scour for decades and the problem has
R. A. LIND, NORTEK, UK, AND R. J. S. WHITEHOUSE, H.R. WALLINGFORD, UK, EXPLAIN WHY IT IS VITAL TO UNDERSTAND AND MONITOR THE EFFECTS
OF SCOUR ON OFFSHORE STRUCTURES.
63
64OILFIELD TECHNOLOGYAugust 2012
where the seabed is predominantly sandy. Various methods have been developed in the industry for protecting against the development of scour holes, or for their mitigation but deciding on the correct solution requires detailed analysis of the site and at the moment there are still gaps in this analysis.
Design predictions of scour are made for structures and parameter values set, against which intervention options can be planned. One powerful tool in scour analysis, monitoring and prevention is an online system, which provides continuous measurements over an area around a marine structure. This type of system, coupled with a good software package can provide a continuous picture of what is going on at the seabed and consequently act as an early warning system for the integrity of the marine structure.
Scour in the laboratoryThere has been a considerable amount of computational and physical (laboratory) modelling carried out to determine exactly how predominantly granular soils react to the driving forces of currents and waves around a structure. For scour assessment the threshold velocity, bed shear or stream power are the key parameters, which control when sediment is mobilised or eroded
from the bed. Scour takes place around the structure when the threshold value is exceeded local to the structure.1
Hydrodynamic field
the obstruction caused by the structure is a key part of the scour process and can be observed in the relationship between the depth of scour at the structure and its width.
pattern with the addition of a marine structure will result in one or more of the following:1
Flow contraction.
Lee-wake vortices behind the structure.
Reflection and diffraction of waves.
Wave breaking.
Turbulence generation.
Pressure differentials in the soil leading to liquefaction.
For a circular pile, the principal features of scour (shown in
the horseshoe vortex at the base of the pile, a surface bow wave at the upstream face of the pile and wake vortices downstream of the pile. The horseshoe vortex can be seen to be effective at transporting sediment away from the scour hole with the
in the scour hole development.
Marine bed compositionCritical to any foundation design are geotechnical considerations. Scour in the marine environment is a physical process related to the movement of seabed sediment by the
described by geotechnical parameters, therefore, scour is of a geotechnical nature as it relates to the reduction in ground level around a structure.
In the laboratory, many experiments have been carried out researching the effects of different sediment classes. If sand is taken as the benchmark case then in general terms the
although muds and clays may be quite variable in their response depending on their cohesion and stiffness. Also it is expected, in some sediments that scour will increase with increased hydraulic forcing through storm waves, whereas in other sediments it may actually lead to a decrease in the scour depth. The role of wave-induced liquefaction (a phenomenon whereby a saturated soil substantially loses strength and stiffness in response to an applied stress) also needs to be considered; the soils subject to risk of liquefaction are indicated in Figure 2.2
Scour in the marine environmentOutside of the laboratory, marine soils are rarely found to be uniform in structure and can be multi-modal in their grading as well as exhibiting a varying amount of cohesion. Couple this with the high rate of variability found in currents and waves and assessing the extent of scouring in these real soils becomes far more complex and the methods available for assessment more limited.
Figure 1. Key hydraulic processes acting at a pile to cause scour.1
Figure 2. Conceptual model of the relative scour depth for different sediments.2
Under the patronage of His Royal Highness Prince Khalifa bin Salman Al Khalifa
Prime Minister of the Kingdom of Bahrain
Conference: 10 -13 March 2013Exhibition: 11-13 March 2013
Bahrain International Exhibition and Convention Centre
www.meos2013.com
18th Middle East Oil & Gas Show and Conference
Organisers
Conference Organisers
Call for papers
now open at
www.meos2013.com
Submission deadline:
2 September 2012
66OILFIELD TECHNOLOGYAugust 2012
Determining the potential depth of scour in complex marine soils, based on laboratory research using current prediction methodologies requires the use of several relationships and assumptions. This may limit the application of the approach to more complex situations, unless supported by information from additional studies of physical modelling (laboratory) and without information on the soil properties including their variation with depth, this method cannot be applied.3
Scour analysis techniquesScour around marine structures is well recognised as an engineering issue. Where scour is anticipated to cause problems with structural stability, scour protection is required.4, 5 Determining if and when this protection is needed is the problem.
variety of techniques used to routinely monitor scour at a marine structure. Visually (using divers or ROVs) and through acoustic methods such as Multibeam Echo Sounders or SONAR devices.
As shown in Figure 4, SONAR can provide a good 3D image of the structure. It gives detailed depths in graphical format, which allows for good analysis. With threshold velocity, bed shear and stream power being key parameters in scour assessment and the given variable nature of the marine environment, these three factors
needs to be introduced to obtain a full assessment of scour analysis.
Time scale of scour developmentScour development under waves and currents around offshore structures is a time varying process. Whether a scour hole will
a function of the hydrodynamic processes existing at any given time.
With current data sets from various SONAR instruments, we can see in many cases a general growth in scour, over a period of
datasets are snapshots of a point in time and not a continuous, online data stream, so caution should be taken when inferring a general reduction in scour depth with time, as this may just be a function of the prevailing conditions at the time of the survey rather than a general trend. Recent studies suggest that
combined current and wave conditions through time (Figure 3).6 In this example, the current generated scour depth is predicted to be much larger than the scour due to combined waves and currents.
Guidance on scourDNV and Germanischer Lloyd are two of the independent organisations responsible
conjunction with the existing regulatory regime they help to ensure an appropriate level of safety and reliability through offshore
requirements laid down in applicable rules and regulations are met during all phases of the asset’s design, construction and operation.
Figure 4. Snap-shot of scour at a marine structure (image courtesy of CodaOctopus using the Echoscope® real time 3D sonar).
Figure 3. Results from a model at prototype scale. Validation of this kind of detailed modelling requires continuous time-series data of environmental conditions and scour depths at the foundation.5
67OILFIELD TECHNOLOGY
August 2012
As of 2011, DNV guidance for scour at an offshore structure was based mostly upon published results from scale laboratory studies. This means that the need for scour protection at an offshore structure relies heavily on research carried out in waves or unidirectional
uncertainty about potential scour depth at marine structures, which means uncertainty about the need for scour protection. With the cost of scour protection being in the millions for some marine developments coupled to structural uncertainties, it seems that there is a potentially high price to pay for something that can be monitored at a relatively low cost.
Online scour monitorSystems such as the online Scour Monitor are capable of providing a relatively cheap acoustic, power-light, online, real time system with good graphical output, which can be accessed through the internet.
The instrument is comprised of four downward looking narrow acoustic beams,
series datasets are collected and recorded internally and/or can be output in real time, using RS 232 or RS 422 formats.
The four beams fan out in a single axial plane, normally orientated perpendicular to the face of the structure (Figure 5). Changes in seabed levels adjacent to the structure are measured and real time data can be displayed at base. Scour and subsequent depositional events, which might happen during storm
avoiding up-front the need for diver intervention.
ConclusionThe physical processes driving scour development in the marine environment have to be well understood to ensure that appropriate methods of predicting scour depth and extent are used. It is also important that the processes are well understood so that it is possible to implement effective scour mitigation or counter measures.3 Desk analysis, computational and laboratory modelling all have their role to play in determining scour response and mitigation measures.
The application of monitoring systems such as Scour Monitor could potentially reduce many of the problems associated with scour. In conjunction with metocean measurements it can help improve scour calculations, by giving continuous feedback of scour development and can therefore help in removing a lot of the uncertainties associated with modelling and snapshot data. This in turn allows for improved realism within engineering/FEED calculations, which should help improve installation time and reduce expenditure. On top of all this, these systems can
Figure 5. Nortek scour monitor attached to a pile. Providing an online real time picture of temporal scour development.
function as an early warning system and provide information for modellers and project operators alike, trying to assess scour formation and whether scour protection is required. O T
Note
article.
References1.
2. Proceedings Third International Conference on Scour and Erosion, November 1 - 3, 2006, pp. 52 - 59. ©
3.
pp. 11 - 20.4. 5.
London.6.
evolution of scour around offshore structures”. Proceedings of the Institution of Civil Engineers, Maritime Engineering, 163, March Issue,
ENSURING INTEGRITYGORDON MCCULLOCH, INTECSEA LTD, UK,
GIVES US A LOOK INTO THE DEVELOPMENT OF A MODEL FOR ASSET INTEGRITY MANAGEMENT IN THE OIL AND GAS
INDUSTRY.
68
This paper outlines a model for asset integrity management (AIM). As the technology has
progressed it has also evolved in ways that are perhaps outside
Drawing on operating companies, governmental bodies good practice,
principle and shaped it to suit the practicalities of the huge and diverse
the burgeoning diversity in terms of geographical, political and technological areas of asset development.
IntroductionAsset Integrity in its formal sense
the result of a co-ordination between the UK HSE (oil and gas regulator) and partners from industry such as
the larger operators in the North Sea. The aim of this collaboration was to decide how best to maintain the containment integrity of ageing oil rigs in the North Sea; as a result, the
produced. This document represented the culmination of the asset integrity
the year 2000. These included the a series of integrity activities called Key Programmes. To date there have been four of these programmes covering different areas of integrity concern:
Key Programme 1: hydrocarbon release campaign.
drilling operations.
Key Programme 3: asset integrity.
Key Programme 4: ageing and life extension.
As can be seen, these
69
70OILFIELD TECHNOLOGYAugust 2012
of investigation but each has in common a goal of the adoption of processes and behaviours that support safety and safe
being most relevant in maintaining asset integrity. Formulated during collaboration with the major operators these were laid
the following elements, each considered to be integral to asset integrity:
Integrity of piping repairs.
Awareness of personnel.
Valve failures.
Hydrocarbon containment.
ESDV issues.
Competence.
Mitigation systems.
Corrosion.
Ship collision.
The complete list of 42 areas seen as critical to asset
was an attempt to extend the life of operating assets safely into a production future beyond their design life. The earlier stages of projects and developments had not as yet been considered fully.
Oil and Gas Producers) is a body that develops guides and standard setting documentation for use by its members and others. With asset integrity it has produced two major treatise aimed at helping senior managers manage their upstream assets effectively.
Figure 1. The AIM model.
Figure 2. AIM life cycle model.
Literature reviewOwing to the relative infancy of asset integrity there is not a
easier to identify those particular groups and authors that have
documents come from the following sources and have been
KP1, 2, 3, 4 - HSE (UK) publications - the UK Health and Safety Executive collaborative publications created in unison with operators, academics, governmental bodies, contractors and suppliers. These documents are detailed and hold a lot of case specific advice. This is due in some part to the need of the HSE to be clear about its intent and
OGP publications:
Asset integrity: the key to managing major incident risks.
Process safety: recommended practice on key performance indicators.
Both of these publications can be considered high level, aimed at senior management, but they can also be said to have
they describe a methodology for the achievement of asset integrity - a subtle difference in objective and approach in comparison to the HSE.
The OGP expands on the UKCS and includes within its remit North America, but it is effectively a global approach and has at
Gaps in current approachesThe oil and gas industry has expanded within the last decade to
serve them, companies have been going to more remote, and less hospitable places to extract hydrocarbons. This activity has had several effects relevant to the current position of asset
The pursuit and extraction of hydrocarbons has been the
demand.
Areas of exploration have extended the operational frontiers
in unfamiliar countries or locations.
Arguably, staffing and resourcing the projects with the right
The combination of these three elements has not stopped or retarded the forward movement of asset integrity but have presented its model with a formidable obstacle, namely: developing AI at the same time as endeavouring to meet the technological and people challenges.
Trying to create an asset integrity system in the environment described above that is both usable and effective is
changing energy landscape is to have a system that across the board of activities is adaptable but still retains the core
necessity used a variety of different methods to achieve asset integrity.
Initially the approach developed was solely for the upstream activities of ageing assets, however, with the advent of the OGP
71OILFIELD TECHNOLOGY
August 2012
focussed on the operating phase of that lifecycle.Due to this hectic development and the need to focus on
hydrocarbon releases, several areas of importance have been
Common objectives: safety, and the containment of hydrocarbons as achieved by the managed stewardship of assets is the common objective and well catered for, but there are areas of asset integrity not addressed and
aspects of:
Technical and engineering.
Commercial and business needs.
Codes and standards application.
Legal compliance (global).
Environmental considerations (global).
Project support: supporting projects with defined application methods that are designed to ensure that the projects
tolerance.
Standardised definitions: asset integrity itself does not have an accepted definition. This leaves the way for misinterpretation and misuse.
Life cycle approach: this approach is mentioned within the current literature but only in part as the focus is on operations. The development of the wider life cycle areas would be supportive of the asset integrity objectives in operations.
International standards: at present there are no AIM standards.
with already mature industries such as nuclear, military and aerospace is considered essential for the ongoing development of asset integrity. Initially for the development of the technology but also to encourage common understanding.
Processes and procedure; there are, within the industry, processes to help achieve asset integrity but these fall into the category of management tools such as the Demming Cycle or commercial tools such as safety tools. That said, the gap here is the clear and pointed nomination of those activities that occur consistently throughout the life cycle.
Asset integrity management modelThe model for AIM that goes some way toward satisfying the
The AIM Model is comprised of six related elements as depicted in Figure 1. The elements, and their expected outcomes, are summarised below:
Element 1: establishing and sustaining AIM capabilities Management commitment to AIM and assurance is
communicated, understood and applied.
the company is actively encouraged.
Co-ordinating resource and implementation support tools are provided to all active projects.
Element 2: developing/updating asset integrity strategies Asset integrity execution strategies are adapted to suit
project specifics.
Asset integrity is fully integrated within the project delivery process.
Figure 3. The asset integrity documentation structure.
Element 3: establishing, targeting and implementing AIM programmes
Asset integrity management effort is aligned to business objectives.
Integrity management programs address all dimensions of asset integrity.
Element 4: conducting integrity assurance reviews Assurance is preferentially directed at areas of greatest
Overall assurance programme scope and focus reflect project exposure.
Element 5: establishing/controlling a repository for integrity assurance evidence
Integrity assurance information is stored for audit trail and reference purposes.
Element 6: ensuring continuous improvement
to support innovation, learning and continuous improvement.
Experience and best practices are shared internally, with venture partners and across the industry.
The life cycle approachFigure 2 shows the areas of asset integrity that apply to various stages of a development. Overall, asset integrity is from assess to abandon, however there are subdivisions in
these activities in a systematic way. The three main groups are design integrity, technical integrity and operational integrity (which includes decommissioning).
objectives of AIM these can be, but are not limited to:
Corporate/management level Corporate AIM system.
Project AIM programmes.
Operational AIM programmes.
Specialist areas Design integrity management.
Technical integrity management.
Operational integrity management.
Safety.
Legal compliance.
Environmental compliance.
Production optimisation.
Risk management.
Tools and techniques AIM model application.
Asset integrity assurance (AIA) reviews.
Safety case compilation.
Safety critical element analysis.
Asset integrity benchmarking reviews.
Asset integrity capability assessments.
Integrity management software for subsea or full field.
Compliance matrix provision.
Code and standards matrix provision.
Independent verification guidance.
Bow tie analysis.
SIL screening and assessment.
Reliability strategies.
Availability modelling.
RAM modelling.
Specialist support to projects and operations.
Specialist IM decommissioning services.
Project applicationTo ensure that any development is given the means to demonstrate its adherence to and its achievement of asset integrity there should be in place a robust and detailed corporate mechanism, that lays out the who, what, when, where and why. This, up front ensures that there is a mandate to resource and carry out the necessary steps that place the asset on a route to optimised asset integrity. Figure 3 maps not only the relationship between corporate and project documentation but the required documents and procedures that are required as a minimum for auditable corporate governance and correct project implementation.
It should be noted that the mandate and charter are clearly shown as inputs to this structure. The mandate is a document signed by senior and upper management to show commitment and to provide the distinct direction in terms of resource commitment and corporate objective. The supporting document to this is a clear statement of intent, a statement of position and a demonstration of how seriously the company takes asset integrity. This is called the asset integrity charter and it lays down the concepts and the objectives the company has with respect asset integrity. The charter is a 10 point guide detailing how it intends to integrate asset integrity into the business it conducts. O T
References1. OGP 2008 Asset Integrity, the key to managing major incident risks,
international association of oil and gas producers Report 415.2. OGP 2011 Process Safety, Recommended Practice on Key Performance
Indicators, International association of oil and gas producers Report 456.3. HSE Key Programme Handbook 2007.
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