oilfield technology april 2011
TRANSCRIPT
OILFIELD TECHN
OLOGY MAGAZIN
E APRIL 2011
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.energyglobal.com
VOLUME 04 ISSUE 03-APRIL 2011
ISSN 1757-2134April 2011 Volume 04 Issue 03
Copyright© Palladian Publications Ltd 2011. 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.
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contents
| 49 | THE CASE IN QUESTION Scott Beattie, Weatherford International Ltd, USA, looks at the benefits of a subsea drilling-with-casing system.
| 53 | FIGHTING FATIGUE Kenneth Bhalla, Stress Engineering Services, USA, explains the importance of riser and subsea fatigue damage monitoring.
| 57 | GREAT INTEGRATIONS Vincent Vieugue, Emerson Process Management, Norway, explains the growing need for greater integration and intelligence in subsea operations.
| 61 | PIPE DREAMS BECOME REALITY Cobie Loper and Mark Kalman, DeepFlex Inc., USA, introduce a new generation of lightweight, corrosion resistant flexible pipes.
| 64 | CHECKLIST FOR PRECOMMISSIONING Richard Shirley and Dan Vela, Mustang Engineering, USA, run through the process of precommissioning offshore facilities.
| 69 | SWITCHING TO ELECTRIC Jon Robertson, Saab Seaeye, UK, looks at the benefits of electric ROVs in comparison with hydraulic vehicles.
| 73 | ELIMINATING THE GAPS IN US OFFSHORE REGULATIONS Jogen Bhalla (USA) and Stephen Gale (UK), AMOT, and Ian Harrison, Pyroban, UK, highlight the importance of ignition source elimination and the differences in approach across the world.
| 78 | COMPANY NEWS
| 80 | AD INDEX
| 03 | EDITORIAL COMMENT
| 05 | WORLD NEWS
| 10 | BACK ON TRACK Gordon Cope, Oilfield Technology Correspondent, explains how technological innovations have opened up new plays in North America and expanded old ones; but environmental concerns and other factors complicate the future of this sector.
| 18 | DEEP WATER AHEAD? John Wishart, GL Noble Denton, USA, examines the future of the oil and gas industry and the challenges that lie ahead.
| 24 | SEAS OF OPPORTUNITY Luke Davis, Infield Systems Ltd, UK, considers the prospects of the offshore wind sector and its implications for the offshore oil and gas industry.
| 29 | AN ILLUMINATING EXPLORATION... Duane Dopkin, Paradigm, US, points out how full azimuth decomposition, imaging and illumination enhances deepwater exploration.
| 33 | IMPROVED IMAGING Gary Rodriguez, Sherry Yang and Laurie Geiger, TGS, USA, present a project to improve imaging in a low velocity trench area in the Gulf of Mexico.
| 38 | THE ROAD TO RECOVERY Brian Skeels, FMC Technologies, and Lars Farestvedt, MPM, US, consider solutions for maximising reservoir recovery in this issue’s cover story.
| 44 | LIFTING EXPECTATIONS Ian Anderson, Camcon Oil, UK, explains how artificial gas lift can assist in developing a long term strategy for subsea extraction.
FMC Technologies’ subsea well intervention system (RLWI) onboard the Island Wellserver in the North Sea. Workers connect a control umbilical to a well control package while the wireline
lubricator is suspended in the foreground. This system enables subsea workovers at half the cost and in half the time of the traditional method performed from a rig.
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Bringing Solutions to Surface
James Little
Managing Editor
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Just in case anyone was in any doubt, recent events have once again provided a poignant illustration of the significance of crude oil and its indisputable position as
the world’s most important traded commodity. The increasingly fine balance between supply and demand, driven by a number of rapidly expanding Asian economies, most notably China and India, coupled with a deep seated fear of supply disruption amongst energy traders, mean that any event that risks an outage, inevitably leads to a marked upswing in the price of crude. With much of the world still struggling to regain its feet after the recent global recession, an escalation in the price of crude oil has exerted considerable pressure on the fragile global economic recovery. Brent crude stood at US$ 122 at the time of writing, up from just below US$ 95 at the close of 2010.
This pattern is of course not unfamiliar. Let’s not forget, crude prices rose rapidly over a very short timeframe on the back of increasing Asian demand in 2008 to a high of US$ 147. However, events of the past year have been akin to a ‘perfect storm’ for the energy industry. From the Deepwater Horizon drilling rig explosion on 20 April 2010, and the ensuing moratorium on drilling in the Gulf of Mexico, to the ongoing, and far from resolved, chaos in the Middle East, and finally the devastating earthquake, tsunami and nuclear catastrophe in Japan, the energy industry has been thrown into an acute state of uncertainty and governments are being forced to re-evaluate their energy policies.
Whilst Opec has been able to compensate for the 1.6 million bpd of lost crude production from Libya, its overall spare capacity is fast being eroded. It is also struggling to match the high quality light crude that Libya was producing causing more pain for refiners who are forced to compete for scarcer resources. If problems within the region persist and spread to other nations across the Middle East and North Africa, then
Opec’s available reserves will quickly dwindle. Saudi Arabia, Opec’s largest producer and source of the majority of crude reserves, looks vulnerable at present with developing disturbances among many of its near neighbours including Bahrain, Jordan, Oman, Yemen, Syria and Jordan. So far, Saudi’s solution to internal strife has been the populist measure of providing hand outs to its citizens and boosting public spending. An action that will cost Saudi Arabia a total of US$ 129 billion or the equivalent of half of the country’s 2010 oil revenues. Whether this works remains to be seen, but without doubt it will lead to higher oil prices as Saudi seeks to finance this huge public expenditure, plus there is the danger of less investment in future production capacity, again leading to higher prices.
Price rises have not been limited solely to crude oil, with significant increases being seen in natural gas rates as Japan, the world’s largest buyer of LNG, has boosted imports following the damage to its Fukushima nuclear facility. With radiation still leaking from the plant, this crisis remains critical and has potentially set the nuclear industry back years. Germany, the US and even China have each put their nuclear programmes on hold which can only put more pressure on future oil and gas prices.
An end to the turmoil in the Middle East is vital to a stable oil price. Why? Because according to the IEA, the Middle East and north African region will contribute 90% of crude oil production growth over the course of the next 10 years, and if crude oil is the world’s most important traded commodity, then this region holds the key to crude production. For the first time, Opec, largely comprised of members from the region, will amass US$ 1000 billion this year in export revenues if the price of crude remains above US$ 100 a barrel. My guess is that it will achieve this milestone and more. Let’s just hope that the fledgling global economic recovery can withstand the pressure of an extended period of higher oil prices. O T
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world news
OILFIELD TECHNOLOGYApril 2011
05
inbrief
CGGVeritas has inaugurated a new open processing and imaging centre in Muscat, Oman, at a ceremony attended by clients and a delegation from the Omani Ministry of Oil and Gas. The new centre complements the company’s activity in the country and offers clients access to the latest processing and imaging technology and services.
Tailored to address the geologic challenges of the region, services are focused on the CGGVeritas unique 3D land seismic portfolio, including ultra high-resolution wide-azimuth technologies.
The centre also operates as a CGGVeritas University training centre, developing and delivering training initiatives with the Sultan Qaboos University, the Omani Ministry
USADow Oil & Gas, a business unit of The Dow Chemical Company, has introduced UCARSOL™ Shale H-100, a specialty amine blend designed specifically for treating natural gas from the Haynesville shale. This is the first in a series of new specialty amine blends Dow Oil & Gas is developing for the treatment of shale gas in North America.
ANGOLAVWS Westgarth, a subsidiary of Veolia Water Solutions & Technologies (VWS), has been awarded a multi-million dollar contract by Daewoo Shipbuilding & Marine Engineering Co. (DSME) for the design, supply and delivery of an Ultrafiltration system and a Sulphate Removal Package (SRP) system. The two treatment units, designed for DSME’s Floating Production Storage and Offloading vessel (FPSO), will be installed in the Cravo-Lirio-Orquidea-Violeta (CLOV) Fields, located Offshore Angola. The project completion is expected in January 2012.
IRAQPetrofac, the international oil and gas facilities service provider, can confirm it has been awarded a contract, in excess of US$ 240 million by Shell Iraq Petroleum Development B.V. for developments in the Majnoon Field, Southern Iraq. Under the competitively tendered contract, Petrofac is providing engineering, procurement, fabrication and construction management services for the development of a new early production system comprising two trains each with capacity for 50 000 bpd of oil, along with upgrading of existing brownfield facilities. Work on the project began in mid-2010 and is expected to complete during the fourth quarter of next year.
// Cuadrilla Resources // UK shale fracking
// CGGVeritas // Opens new centre in Oman
The first UK shale gas fracking operation is now under way at the Preese Hall shale gas well, near the seaside resort of Blackpool in North West England.
Cuadrilla Resources, an independent UK energy company undertaking the project, has said that fracking will take place in bursts throughout April, after which time the company will look to study how much gas subsequently flows from the test well.
Cuadrilla has asked to carry out operations at five sites, and has not required a permit for its current
fracking operations, because there is not deemed to be any possible risk to water supplies. Campaigners have raised concerns that the extraction process can contaminate local ground water, but an inquiry into possible risks at the site found that no unacceptable risks were being taken.
France has imposed a moratorium on shale gas drilling, while the German state of North Rhine Westphalia has asked ExxonMobil to cease fracking work until later this year while an expert opinion is prepared on possible impacts.
of Oil & Gas and international training organisations. In this way, CGGVeritas will step up its participation in the development of highly qualified Omani professionals; a key national programme.
Colin Murdoch, Executive Vice President, Processing, Imaging and Reservoir, CGGVeritas, said: “With over 35 years of experience in Oman, CGGVeritas has considerable knowledge of the region’s E&P challenges. Our new open centre will provide training and services of the highest standard, customised to help our clients maximise the return on investment they are currently making in very high-channel-count exploration and reservoir optimisation programmes.”
world news
06 OILFIELD TECHNOLOGY April 2011
diarydates2 - 5 MayOTCHouston, TX, USAE: [email protected]
23 - 26 MayEAGE Conference and ExhibitionVienna, AustriaE: [email protected]
15 - 16 JuneWorld Drilling Conference and ExhibitionCopenhagen, DenmarkE: [email protected]
30 August - 1 September3P Arctic 2011Halifax, Nova Scotia, CanadaE: [email protected]
6 - 8 SeptemberSPE Offshore EuropeAberdeen, ScotlandE: [email protected]/palladian
25 - 28 SeptemberMEOS 2011BahrainE: [email protected] www.meos2011.com
4 - 8 December20th World Petroleum CongressDoha, QatarE: [email protected]
// Statoil // Oil and gas discovery in Norway
ExxonMobil is likely to start oil exploration off the central coast of Vietnam towards the end of this month, according to a recent statement from state-run oil firm PetroVietnam.
The company has worked with the authorities of Danang city on safety issues surrounding the drilling and will begin work at Block 119 off Danang city. The drilling will be part of an agreement signed between ExxonMobil and PetroVietnam in 2007.
PetroVietnam has previously formed partnerships with Russia and several
other countries to exploit the reserves in these offshore oilfields. Other close by nations, such as Malaysia, Brunei, Taiwan and the Philippines all hold claims in the region. Worryingly, it has been claimed that Chinese patrol boats often harass and intimidate explorers in the area, having laid claim to the South China Sea and the area in which ExxonMobil intends to explore. However, US Defense Secretary, Robert Gate, has voiced his objection to any ‘intimidation’ of US energy companies operating in the region.
After a few recent dry well exploration failures in Norway, Statoil and Eni SpA have potentially made Norway’s biggest oil and gas discovery in 10 years at the Skrugard prospect in the Barents Sea. With as much as 250 million bbls of recoverable reserves, this discovery may prove bigger than the current holder of ‘Norway’s largest find’ title – Goliat.
Tim Dodson, Executive Vice President for exploration at Statoil, has been quoted as saying: “This opens a new oil province that can provide additional resource growth,” adding that the find was the “most important” exploration event in Norway in 10 years.
It is hoped that this new find will help meet targets to maintain Norway’s output and make the development of a second gas hub in the Norwegian Sea more likely. Statoil plans to drill a
delineation well in the area in 2012, as well as another exploration well in the same license. The company is currently considering the possibility of drilling more wells in the area this year.
The overall production of oil and gas in Norway is expected to decline from 2015 onwards, and has already fallen by 30% since 2000. The Norwegian Petroleum Directorate estimates that only 40% of the oil and gas on the Norwegian shelf has been produced, and that in 20 years time 40% of the production on the Norwegian continental shelf will come from resources that are as yet undiscovered. In the North Sea, half of the oil and gas has been produced; in the Norwegian Sea less than a quarter; while Snøhvit currently operates to exploit the resources in the Barents Sea.
// ExxonMobil // Vietnam oil exploration
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world news
08 OILFIELD TECHNOLOGYApril 2011
// Technip // Awarded North Sea contract
// Cupet // Expanding Cuban exploration in the Gulf of Mexico
Cuba currently depends on Venezuela for approximately 100 000 bpd of oil imports, and produces in the region of 21 million bbls a year of domestic oil, which supplies around half of its energy needs every year. After a long established position of energy dependency, Cuba has announced plans to drill five deepwater oil wells in the Gulf of Mexico beginning this summer, expressing confidence that its effort in exploration will be rewarded with major new hydrocarbon discoveries.
“We’re about to move to the drilling phase,” said Manuel Marrero, an official with the government authority tasked with overseeing Cuba’s oil sector. “We’re all really hopeful that we will be able to discover large reserves of oil and gas,” said Marrero, who added that the ventures would be undertaken with the help of unspecified foreign companies.
He said the deepwater wells were to be drilled between 2011 and 2013, and would be in waters ranging in depth between 400 m and 1500 m. State oil firm Cupet has said that the country is currently awaiting a platform constructed in China for one of its offshore projects, and has made assurances that any offshore well development will be handled with safety at the forefront. Cuba’s economic zone in the Gulf is geographically very close to the US state of Florida, and is divided into 59 blocks. 20 blocks are ventures with Repsol (Spain), Hydro (Norway), OVL (India), PDVSA (Venezuela), Petrovietnam and Petronas (Malaysia). Petrobras (Brazil) recently pulled out and Sonangol (Angola) recently signed on.
Studies estimate Cuba has probable reserves of between 5 and 9 billion bbls of oil in its economic zone in the Gulf of Mexico.
// Suncor // Investment in oil sands
Canadian energy company, Suncor, has received all requested approvals needed to finalise its strategic alliance with Total E&P Canada Ltd. The company aims to more than double its oil sands production in the next decade.
Suncor will receive approximately US$ 1.75 billion from the transaction, and has acquired a 36.75% working interest in the Total-operated Joslyn joint venture with Total now holding 38.25%.
ConocoPhillips will also move towards a focus in oil sands production in Canada. In response to a long period of relatively low natural gas prices, ConocoPhillips, the third largest natural gas producer in Canada, cut the number of new gas wells it plans to drill and will shift investment into increasing its oil sands output.
Technip has been awarded a full EPIC contract by RWE Dea, for the Clipper South gas field development in the North Sea. The field is located 70 km northeast of the Bacton gas terminal in 25 m of water.
The contract covers full project management, detailed pipeline design, installation and tie-in of a 15.5 km 12 in. production line and 3 in. methanol piggyback line from the new Clipper South platform to the existing LOGGS (Lincolnshire Offshore Gas Gathering system) platform.
UK and Saudi energy ministers have met recently to call on international energy markets to recognise that the high price of oil does not reflect the realities of supply and demand in the market.
In his first visit to the Middle East since taking office, UK Energy and Climate Change Secretary Chris Huhne met with Saudi Oil Minister Ali Ibrahim Al-Naimi. Mr Huhne said: “There could be no more important time to be in Saudi Arabia, whose response to events in recent months has been crucial for keeping the market supplied to meet global demand. There is no shortage of supply, and yet the price has remained high. International energy markets should understand that the current price of oil does not reflect the realities of supply and demand. Building greater understanding between consumer and producer countries is more important than ever in these present circumstances.”
// UK and Saudi Arabia // Discuss supply/demand
The contract builds on past experience with RWE: in 2008 Technip provided pipelay and umbilical installation for the Topaz field development, located in the Southern gas basin.
Technip’s operating centre in Aberdeen (Scotland) will execute this contract, which is scheduled to be completed in the fourth quarter of 2011. Genesis; a Technip Group company providing upstream oil and gas consultancy services, will also play a part in executing the contract through the provision of detailed pipeline design. Vessels from the Technip fleet will be used for the offshore installation campaign.
A N Y W H E R E . A N Y T I M E . E V E R Y T I M E .
Nantes, France [email protected]
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www.sercel.com
Gordon Cope, Oilfield Technology Correspondent, explains how technological innovations have opened up new plays in North America and expanded old ones; but environmental concerns and other factors complicate the future of this sector.
on trackBACK
10
The oil and gas sector is sending a clear message: North America is back on track. In the US,
full year oil production for 2010 averaged 5.49 million bpd, compared with 5.36 million bpd in 2009. In 2011, operators are expected to drill 44 714 wells, up from an estimated 43 038 wells in 2010. Service company Baker Hughes predicts that active US rotary rigs will average 1620 rigs per week this year, up from 1515 in 2010 and 1087 in 2009.
In Canada, the Conference Board of Canada noted that oil company profits jumped to C$ 8.5 billion in 2010, up from
C$ 1.7 billion in 2009, and will continue a healthy growth into the C$ 20 billion range by 2014. Alberta’s lease sales netted C$ 2.38 billion in 2010, exceeding the record set in 2005, and more than tripling the level from 2009. Husky, based in Calgary, raised its 2011 capital budget more than 20%, to C$ 4.86 billion. The Petroleum Services Association of Canada expects a total of 12 250 wells to be drilled in 2011, up from 11 350 in 2010.
In addition to a recovered economy, the oil and gas sector is riding high on the benefits of two major advances in technology; horizontal drilling and hydraulic fracturing. Thanks to advances in horizontal
11
12 OILFIELD TECHNOLOGYApril 2011
well technology, for instance, the average length of wells in Canada has grown 33% in the last three years, from 1200 m to 1600 m. And the number of fractures in some plays has advanced from one or two per well to over a dozen, dramatically increasing the ultimate expected recovery per well. Not only does this mean more hydrocarbons at less unit cost, it also opens up uneconomic plays that were once thought marginal due to economics.
Shale gasNowhere is this more evident than in shale gas. Geoscientists have long known that the dense, black rocks found throughout most basins in the world contain copious amounts of gas - often more than 100 billion ft3 per square mile - but that the impermeable nature of shale made it very diffi cult to produce economically. Less than a decade ago, however, exploration companies in Texas managed to combine a number of technologies, including horizontal drilling and hydraulic fracturing, in order to economically release the gas from the Barnett shale underneath Dallas, Fort Worth. According to the US Geological Survey, the success of the technology has more than doubled the 1300 trillion ft3 of existing reservoirs in North America, adding 1200 trillion ft3 of shale gas in the US and 500 trillion ft3 in Canada.
The Barnett shale play has plateaued at around 5 billion ft3/d, but several other new plays are gaining traction, including Louisiana’s Haynesville shale, the Fayetteville shale of Arkansas, and Pennsylvania’s Marcellus shale. Shell agreed to acquire the business of privately owned East Resources Inc. for US$ 4.7 billion in a deal that includes a major land position in the Marcellus shale play. ExxonMobil Corp. paid US$ 41 billion in an all-stock acquisition of XTO Energy Inc. Chevron acquired Atlas Energy and its extensive Marcellus gas play holdings for US$ 4.2 billion. By 2035, the EIA estimates shale gas could make up as much as 25%, or 16 billion ft3/d, of the country’s expected 64 billion ft3/d production.
Canada is just beginning to produce from shale gas. Petroleum companies are building infrastructure to handle up to 1.8 billion ft3/d from the Horn River Ordovician Muskwa formation and the Montney shale, located in northwest Alberta and northeast British Columbia. The Canadian Society for Unconventional Gas (CSUG) estimates that the entire country’s shale gas production could reach 5.3 billion ft3/d by 2020.
Shale oilShale oil, the cousin of shale gas, is also growing into a major unconventional source of hydrocarbons. The Bakken shale rests in the Williston basin that straddles North Dakota, Saskatchewan and Manitoba. The USGS estimates there are 3.65 billion bbls of recoverable crude oil in the Bakken. Thanks to rotary steerable systems (RSS), operators can target thin, high-grade veins that run for thousands of metres laterally. Hydraulic fracturing then releases the oil to the wellbore. With the current pace of drilling, the US Department of Energy predicts that North Dakota will soon overtake Alaska as the leading producer in the US, pumping up to 700 000 bpd by 2017.
The Eagle Ford shale formation in South Texas runs north from the US/Mexico border for several hundred miles. The average thickness of the shale is about 475 ft. The formation produces gas, gas condensate and oil, but it is the latter liquids that have made the Eagle Ford one of the hottest plays in North America.
The Macondo tragedyOn 20 April, 2010, the world’s largest man made oil spill occurred in the Gulf of Mexico. Transocean’s Deepwater Horizon semi-submersible rig, situated approximately 40 miles off the Louisiana coast, had just fi nished drilling an 18 000 ft well into BP Exploration’s Macondo prospect in the Mississippi Canyon block. Suddenly, a large volume of gas and oil raced uncontrollably up the riser, resulting in an immense explosion and fi re. 11 crew members were killed, and over a dozen injured. The stricken rig eventually sank, crashing to the ocean fl oor 5000 ft below.
The blowout preventer (BOP), a 25 t, fi ve story device designed to prevent runaway wells, failed to close. Around 50 000 bpd of thick crude began to spill out onto the seafl oor and make its way to surface, threatening wildlife, beaches and protected habitats. BP, state and federal authorities launched a massive clean-up campaign. BP also tried to staunch the well. After several failures (including attempts to activate the BOP, massive containment caps, and the injection of debris and mud), the well was fi nally sealed on July 15, 87 days after it fi rst began to spew. US government agencies estimate that approximately 4.1 million bbls of oil escaped.
In the wake of the tragedy, President Obama imposed a drilling moratorium on all federal leases at depths exceeding 500 ft. Thousands of employees were temporarily laid off. Lease sales were also cancelled, and lawsuits were brought against BP, rig operator Transocean, and service company Halliburton. While the oil clean-up proved mercifully short, the legal repercussions to the industry are expected to reverberate through the courts for several years.
The Macondo tragedy has resulted in a new focus on personnel safety, environmental and regulatory compliance in the offshore sector. Formerly, the MMS had been responsible for promoting offshore oil and gas development, enforcing safety regulations, and maximising revenues from oil and gas to the Treasury. Secretary of the Interior Ken Salazar reorganised the Department of the Interior’s Minerals Management Service (MMS), into the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE).
After the reorganisation, revenue collection was assigned to the Offi ce of Natural Resources Revenue (ONRR). Offshore oil and gas development duties were assigned to the Bureau of Ocean Energy Management (BOEM). Regulatory enforcement was assigned to the Bureau of Safety and Environmental Enforcement (BSEE).
The new structure will allow the agency’s permitting engineers and inspectors greater independence, more budgetary authority, and clearer senior leadership focus. It will also allow several new and enhanced compliance strategies, including inspection of rigs to ensure safe and environmentally responsible operations, real-time monitoring of the highest risk operations, such as deepwater drilling, and better inspections and enforcement tools to increase inspection coverage and effi ciency. A separate Energy Safety Advisory Committee (Safety Committee) will advise BOEMRE on a variety of issues related to offshore energy safety, including drilling and workplace safety, well intervention and containment, and oil spill response.
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14 OILFIELD TECHNOLOGYApril 2011
Apache, EOG, Petrohawk, ExxonMobil and Chesapeake are all investing heavily in the region. Drilling permits in the Eagle Ford jumped from 94 in 2009 to over 1000 in 2010, and the torrid pace is expected to continue through 2011. International companies are eager to invest. China’s CNOOC paid US$ 1.1 billion for a 33% stake in Chesapeake’s Eagle Ford acreage, and India’s Reliance spent US$ 1.3 billion to buy acreage and form a joint venture with Pioneer Natural Resources Co.
Oil sandsThe oil sands are another major unconventional play benefi ting from advances in technology. With over 170 billion bbls of recoverable bitumen, the oil sands of Alberta form one of the largest deposits of crude in the world. For the last several decades, oil companies have spent tens of billions to boost production to current levels of 1.65 million bpd. Traditionally, the majority of production has been through open-pit mining, where the mix of sand, clay and tarry bitumen is dug up, separated with warm water, then upgraded to high quality synthetic crude. Mining is only good where the bitumen rests within 75 m of the surface, however. Around 80% of recoverable bitumen requires in-situ methods of recovery. Over the last decade, thermal processes have come to the fore.
Steam assisted gravity drainage (SAGD) involves two horizontal wells being drilled, one above the other. Steam is injected into the top well to melt the bitumen, which then drains into the lower well and is pumped to surface. Advanced horizontal drilling using RSS allows extremely precise placing of the wells, maximising steam patterns and optimising recovery. Currently, mining production stands at 856 000 bpd and thermal in-situ at 794 000 bpd. By 2021, CAPP expects oil sands to produce 3 million bpd, (1.277 million though mining and 1.724 million through in-situ).
ProblemsIn spite of recent successes, the North American oil and gas sector faces a spectrum of challenges. In 2010, the world’s largest man made oil spill occurred in the Gulf of Mexico when the Transocean Deepwater Horizon semi-submersible rig suffered an immense explosion and fi re (see sidebar).
Environmental concerns also remain front and centre. Over the last 150 years, the amount of greenhouse gases (GHGs) in the atmosphere has risen from 280 ppm to 384 ppm, primarily due to the burning of fossil fuels. The UN’s Intergovernmental Panel on Climate Change (IPCC), an international consortium of environmental scientists, has concluded that this is causing global warming.
Most nations around the world signed the Kyoto protocol, agreeing to an emissions reduction to 6% below 1990 levels by 2012, and have since agreed to pursue more ambitious plans. The US, however, has followed its own path. Over the last several years, numerous bills in the Congress and Senate have come up with various targets, including instituting a cap and trade system to reduce emission by as much as 80% by 2050. Although the prospects of comprehensive environmental legislation have abated since the Republicans gained control of Congress, regulatory strength against emissions has been growing. Empowered by a Supreme Court ruling that GHGs fall under the jurisdiction of the Clean Air Act, starting this year, the Environmental Protection Agency (EPA) is requiring
new power plants and refi neries to consider GHG-reducing technologies, as well as major modifi cations to existing ones.
The growth of shale gas faces public concerns over hydraulic fracturing. During the process, several million litres of water are forced at high pressure down the wellbore and into the shale to create a network of tiny fractures that allow the gas to escape. In order for the water to penetrate further, it is treated with proprietary chemicals that decrease its viscosity. Some of the chemicals have been associated with cancer, and offi cials are worried that they may contaminate adjacent aquifers and drinking supplies. In August, acting under a directive from Congress, the EPA requested chemical lists from nine major service companies, including Halliburton and Schlumberger. There have also been calls to regulate hydraulic fracturing under the federal Safe Drinking Water Act. In Pennsylvania, protestors are organising to seek curtailment of shale gas activity in their state.
The oil sands are also under heavy pressure. Mining projects require large amounts of water in order to fl ush bitumen from a matrix of sand and mud. It taxes the hydrological system in the region, creates large tailing ponds, and threatens residents with trace toxins. Recently, Syncrude was fi ned C$ 3 million after 1600 ducks died in a tailing pond. Aboriginal groups situated downstream from the development have also long complained of higher incidences of rare diseases. Environmental groups have dogged provincial politicians and invaded facilities, claiming that it is ‘dirty oil’ due to the energy needed to clean and upgrade the bitumen. Various lawsuits are lodged against proposed pipelines designed to carry oil sands production south to the US and west to Asia.
But one of the major concerns is the persistent low price for natural gas. For the last several years, gas has consistently lingered around US$ 4/ million BTU, well below the replacement level of US$ 6 - 7 for many exploration regions. Unless production decreases or demand increases, the price outlook for the next several years is bleak.
The futureEnergy suppliers are looking for ways to reduce GHG emissions. One such technique is carbon capture and sequestration (CCS) in which large carbon emissions from stationary facilities, such as power plants, refi neries and oil sands upgraders, are fi tted with equipment that gathers CO2 so that it can be shipped to underground storage facilities for permanent isolation. The government of Alberta, for instance, has established a C$ 2 billion fund to help develop major CCS facilities that will capture and sequester up to 5 million tpy by 2015. Shell’s Quest project will see the Scotford oil sands upgrader in central Alberta capture 1.2 million tpy of CO2, transport it 10 km, and inject it 2300 m underground as part of an enhanced oil recovery (EOR) programme.
In the US, the Department of Energy will provide US$ 350 million to support the Texas Clean Energy Project, which will capture up to 2.7 million tpy of carbon from a proposed electric power plant near Midland-Odessa, Texas, and transport it to the Permian basin, where it will also be used in EOR.
In order to address concerns regarding hydraulic fracturing, the Pennsylvania Independent Oil & Gas Association (PIOGA) and the American Petroleum Institute (API) have formed a Marcellus shale public education alliance to provide facts about
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the tight shale gas resource’s energy and economic potential. The API is also working with industry groups and states to create a state-based voluntary chemical registry of hydraulic fracturing chemicals that would ensure effective regulation while protecting trade secrets.
Oil sands operators are striving to reduce environmental impact. Shell introduced a technique called ‘atmospheric fines drying’ that reduces the drying time for tailings pond material from decades to weeks. Canadian Natural Resources’ Horizon oil sands plant is injecting CO2 into its tailings pond water, which causes the silt to separate much faster. The clear water is then recycled back into the plant, reducing freshwater takeaway from the nearby Athabasca River. Syncrude has installed three large centrifuge machines, much like those already used in sewage treatment plants. The centrifuges separate clean water from the tailings ponds, producing an earth-like clay-cake.
Some oil sands producers are moving toward water-free extraction processes. Petrobank Energy & Resources, Calgary, has received approval for large scale production of in-situ bitumen using toe-to-heel air injection (THAI). The process involves igniting air that has been injected into the toe of a long horizontal well. Unwanted portions of bitumen partially ignite, warming higher grade bitumen, which is then collected at the heel of the well and pumped to surface.
Firming up the price of natural gas will be one of the greatest challenges. Producers could simply shut in uneconomic wells, but the recent global recession has left many petroleum companies too weak financially to turn off the cash flow.
The second option is to drill for less new gas. Companies with oil plays are focusing their budgets on high-priced crude, but the rush to acquire land for the shale gas play has left many companies with commitments to drill or lose exploration rights. Industry groups estimate that at least 150 rigs would have to be retired from the current 950 US rigs dedicated to gas drilling in order to bring long term gas production into line with demand.
There are several opportunities to increase demand. Gas could be exported as LNG. Cheniere Partners recently announced it is negotiating a long term contract with a Chinese firm to add liquefaction facilities to its terminal in Sabine Pass, Louisiana. The plan is to build up to four liquefaction trains, each with a capacity of 700 million ft3/d, or 3.5 million tpy. The LNG would be shipped to Chinese gasification facilities run by ENN Energy, which owns the distribution rights to 45 million potential customers. Liquefaction plants are expensive, however, and take several years to build; Cheniere envisions first shipments in 2015.
A viable option for increasing demand is gas-to-power, or GTP. The US consumes about 19 billion ft3/d to generate electricity. Although there is a surplus of gas-fired plant capacity throughout the country, the cost of GTP electricity is generally about twice that of coal, and is primarily used to supply peak load demand, due to the relative ease of start-up and shut-down. At around US$ 3/ million BTU, however,
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gas can compete with coal on a price basis for baseload demand. Some shale gas production is profitable within this range, and operators would have the option of locking in large volumes of production for extended periods.
Switching to gas also reduces a utilities carbon footprint; coal produces approximately twice as much CO2 per unit of electricity than gas. The main roadblocks to GTP growth are the state commissions that have the power to set electricity pricing. If a long term contract is more expensive than spot market prices, regulators may not pass the cost on to consumers, and the utility company takes the loss.
Thanks to a confluence of new technologies, massive unconventional resources and a renewed economy, North America’s oil and gas sector faces a promising future. But the challenges that remain, including carbon reduction, environmental protection, regulatory restrictions and legislative oversight, guarantee that the next few years will be replete with many a twist and turn in oilpatch fortunes. O T
Figure 1. Healthy investment: the GL Noble Denton sponsored report predicts healthy investment in new exploration and marketing opportunities over 2011.
18
Following a year of slow economic recovery, unstable price fluctuations and damaging incidents in the
Gulf of Mexico and China, the oil and gas industry is predicting healthy investment in new exploration and market opportunities over the next 12 months, according to a new report on the future of the sector published by the Economist Intelligence Unit and sponsored by GL Noble Denton.
Despite concerns over tougher industry regulation and increased operating costs, the 194 board-level executives and policymakers from some of the industry’s leading international companies that were surveyed for the report are optimistic that 2011 will be a key turning point for the industry, as operators prepare to drill deeper in new geographies. Indeed, 76% of respondents to the Economist Intelligence Unit’s research
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20 OILFIELD TECHNOLOGY April 2011
described themselves as either ‘highly’ or ‘somewhat’ confident about their company’s business outlook, compared with only 8% describing themselves as ‘highly’ or ‘somewhat’ pessimistic.
This renewed confidence in industry growth is largely thanks to a period of relative price stability, particularly in North America and the fast-growth economies in Asia. The largest proportion of industry executives surveyed (32%) saw South East Asia as offering the greatest opportunities for their business in 2011, while nearly a third (30%) of respondents to the Economist Intelligence Unit’s research saw North America as the most significant region. Additionally, emerging regions such as China and Brazil are underpinning oil demand as a result of their robust markets, with strong growth also predicted for India and the Middle East this year.
Uncertainty over regulationIt is positive to see that the industry still values the potential of North American production and, for larger oil companies in particular, the US Gulf of Mexico remains an attractive province, according to the Economist Intelligence Unit’s report. As we face the first anniversary of the Deepwater Horizon incident, the potential impact of the regulation following the biggest oil disaster in US history continues to feature heavily in industry debate, and the results of the Economist Intelligence Unit survey reinforce the industry’s feeling of uncertainty towards the effect of future legislation.
Figure 2. Challenge: rising demand for energy resources means companies are increasingly having to develop resources in more challenging environments, such as the deepwater offshore.
According to the report, the oil and gas industry recognises that increased regulation will follow the Macondo incident, but respondents to the Economist Intelligence Unit’s survey seem unclear when new legislation will appear and what effect it will have. A very large proportion (72%) of respondents to the research said that they expect regulation to become more stringent in North America in particular, while a substantial majority (68%) expects cost increases in general.
During a round-table discussion on the findings of the Economist Intelligence Unit’s report, organised by GL Noble Denton in London recently, European industry leaders voiced concern over how the increased cost of post-Macondo regulatory compliance may price smaller operators out of the market. A senior representative from an international oil company suggested that potential new regulation put into place after Macondo might have a pendulum effect, where operating costs will start off high before settling to a more manageable level.
The report also acknowledges that rising costs are likely to be more problematic for smaller E&P firms. Nearly two thirds of production in the Gulf of Mexico is accounted for by such companies, and proposals to raise the US$ 75 million cap on liabilities related to offshore oil spills will most likely hit them hardest as insurance becomes impossible or too costly to obtain.
Rising demand for energy resources means that companies are also increasingly required to develop resources in more challenging environments, such as the deepwater offshore. Reserves in these areas are becoming an increasingly prominent feature in global oil and gas production. With 20% of major oil firm portfolios now coming from deepwater positions, this will clearly have an additional impact on spending.
The longer term impact of Macondo however, looks set to be on companies’ operational strategy, with the report suggesting that their safety record will become a more important factor in gaining access to global reserves.
Participants in the recent round-table discussion felt that a non-prescriptive approach to legislation would be preferable to a rigid regulatory response to Macondo from the US government, helping operators to reduce risk through more effective mitigation processes.
Following the Piper Alpha disaster in the North Sea in 1988, the UK government’s response was to separate the regulator from the Department of Energy and ask operators to identify and reduce risks to ‘as low as reasonably practicable,’ in addition to justifying their actions to the UK Health and Safety Executive (HSE). This regulatory model was subsequently adopted in Australia and West Africa, but it seems that debate continues over whether it would work in the US.
Natural gas: a global ‘game changer’?Natural gas has gained a reputation as a relatively low-carbon ‘transition fuel’ in recent years. The global demand for LNG has grown as countries in Asia and Europe have sought to increase their supply options.
According to the Economist Intelligence Unit’s report, the emergence of large reserves of ‘unconventional’ gas in North America has proved highly attractive to oil and gas companies looking to replace declining production and,
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instead of an anticipated decline in the region, extraction has increased dramatically as new technologies have helped to unlock vast tight gas resources.
But some of the industry’s key players have disagreed with the report’s findings, which dub natural gas as an industry ‘game changer’. They suggest that companies may find that the cost of extracting unconventional gas from reserves such as those in the US will result in a weaker return on investment than originally expected.
The regulation of energy sources such as shale gas may also add cost to the process of extraction, with concerns being raised by some around the best practice for the controversial process of hydraulic fracturing. Currently regulated in North America by the individual states, the report highlighted the concerns of those worried that the potential addition of a further federal layer of regulation could slow operations in addition to resulting in subsequent price rises. The report also notes that there is an expectation for closer scrutiny of the environmental impact of unconventional gas, due to the fact that the techniques required to access it are still not fully understood.
Overall, the majority of the industry executives polled by the Economist Intelligence Unit expect a modest shift upwards in natural gas prices; especially as global demand is forecast to increase steadily over the next decade. Nearly one half (48%) expect an increase of at least 10% in gas prices, compared with just 7% who think prices will fall by 10% or more. Most of the rest (35%) expect prices to fluctuate around the current price range.
Developing the next generationThe increasing shortage of technical skills across the industry is another topic close to the hearts of many oil and gas professionals, and was raised among sector leaders at the recent round-table discussions on the Economist Intelligence Unit’s report. Now we are faced with a period of investment and expansion, there is an overall feeling that the sector will come against challenges as a result of its failure to attract, recruit and retain highly talented people.
There are a number of reasons why the oil and gas industry is likely to experience a skills deficit within the next 15 years; the success of the finance industry - pre-credit crunch - to recruit
talented graduates through the promise of high salaries and quick career progression have been detrimental to the oil and gas industry’s recruitment of ‘fresh blood’. The negative impact of the Macondo disaster on the industry has also played a role, alongside scepticism over the oil and gas industry’s efforts to support more environmentally friendly approaches to energy production and distribution among younger generations.
Before the recent economic crisis, when investment into the oil and gas industry was last at its peak, initiatives were implemented by players from across the industry, who came together to introduce and develop emerging talent in a co-ordinated manner. Alongside the economic downturn came sweeping budget cuts and this good work has likely been halted, but if a period of investment comes to pass, as forecast by the Economist Intelligence Unit report, the
industry could soon find itself returning to a situation in which demand for technical resource outweighs supply.
Participants in the round-table discussions agreed that the industry needs to work more closely together to address the skills problem, rather than trying to pursue each others’ technical staff. One industry association leader felt that the sector had lost its appeal to university graduates over the last 20 years, and while a number of oil and gas companies operate graduate programmes, the industry needs to do more to educate students at an even younger age about the innovations being developed to drive the sector forward.
Technical consultancies such as GL Noble Denton were also recognised as becoming increasingly important to the industry, in that they are able to provide the industry with consistent knowledge and advice during periods of talent deficit. Emerging nations such as India and China may also be depended upon more heavily to provide resource where more mature regions have difficulties in generating new industry talent.
With activity set to rise in the sector, companies need to focus on recruitment now, ensuring that the right talent is in place for the right price.
Cautious optimismIt is clear from the Economist Intelligence Unit’s report, and the debates that its findings have sparked since its publication that the oil and gas industry is extremely focused on its future challenges. It understands very well the need to find more innovative solutions to operating more safely, sustainably and efficiently.
It’s encouraging to see that industry executives expect to see an upturn in investment into the sector, despite fears of tougher regulation and a more costly operating environment. But it is also clear that the industry still has hurdles to overcome if it is to realise the full potential of that market growth.
The demand for energy is taking the exploration, production and distribution of oil and gas to tougher extremes of geography and climate; pushing the boundaries of the industry’s technical knowledge to its very limits. The success of key players in the industry in finding more innovative solutions to mitigate risk while remaining resourceful and sustaining activity will define their position and reputation in the market this year. O T
Figure 3. Natural gas: fast emerging as an attractive option for oil and gas companies looking to replace declining production - but is natural gas a global ‘game changer’?
Luke Davis,
Infield Systems Ltd, UK,
considers the prospects
of the offshore wind
sector and its implications
for the offshore oil and
gas industry.
24
Ever since oil and gas exploration and production activities kicked off in the harsh waters of the North Sea during the late
1960s, the region has been a major part of the global offshore energy supply chain. Indeed, with the demanding needs of North Sea operators as the primary driver, contractors have established themselves as leaders in their respective fields and, over the last 40 years of operation, generated a wealth of knowledge and skills within the region. Today, oil and gas production in the North Sea is in decline and though E&P activities are set to continue apace, driven in no small part by the rising oil price, the offshore wind industry is beginning to make the headlines.
This article discusses the prospects for the offshore wind sector and the competition and opportunities that exist between this nascent industry and its older, more mature cousin, the offshore oil and gas industry.
Offshore wind
Market potential and hurdlesThanks to a number of meteorological and oceanographic characteristics, the North Sea and the adjoining Baltic and Irish Seas are among the best suited and extensive offshore wind development regions in the world. Indeed, when examined on the global level, the region’s vast
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26 OILFIELD TECHNOLOGYApril 2011
areas of shallow waters with high, sustained wind speeds make the area quite remarkable.
Today, the European offshore wind industry is poised for rapid and sustained growth. Bound by ambitious renewable energy targets, EU member states have placed considerable emphasis on the rollout of offshore wind to derive 20% of its energy from renewable sources by 2020. Indeed, backed by government subsidies and incentive mechanisms, current developer aspirations and announced project plans are indicative of surging growth within the industry. Infield Systems’ cumulative installed capacity forecast highlights the rapid expansion of offshore wind going forward to 2015. Initially slow to take off, with little growth between 2000 and 2007, the industry is now gathering a strong head wind.
Quantitatively speaking, offshore wind offers enormous opportunities; in the UK alone there is currently a pipeline of projects nearing 50 GW, consisting of over 6500 potential turbines and supporting infrastructure spread across 36 developments. In Europe, this figure rises to over 150 GW, equating to over 25 000 turbines.
The capital required to deliver offshore wind on such a scale is staggering. Indeed, by 2015, Infield estimates an industry capex of around US$ 20 billion in Northern Europe alone. However, despite this robust outlook, the industry remains constrained by supply chain limitations and a lack of preconstruction finance. Given the youth of the offshore wind industry and the lack of confidence in the long term performance of the market, such constraints are not
surprising. However, these bottlenecks may also be attributed to the relatively low exposure to offshore wind of those players servicing the market. Indeed, many contractors realise a far greater proportion of their revenue from the oil and gas, civil marine and telecommunications industries compared to offshore wind.
Competition
Offshore wind vs. oil and gasIn many respects, the offshore wind industry sits at the same stage of development as North Sea oil and gas did during the late 1960s and early 1970s. However, the wind sector may benefit from the decades of accumulated knowledge that the oil and gas industry has produced. Concurrently however, with oil prices breaking the US$ 100/bbl mark and E&P activity starting a new up-cycle, offshore wind may also find itself in direct competition with the industry that holds the key to unlock the barriers to growth the sector is facing.
Indeed, many of the contractors servicing the oil and gas and wind industries are exposed to both markets. This is of particular significance for substructure fabrication, power cable manufacturing and offshore construction assets such as cable laying, heavy lift and transport vessels. Moreover, demand for these services in the Northern European oil and gas markets is expected to increase. The capex forecast illustrated in Figure 2 highlights the growth in both industries up until 2015.
The forecasted growth in demand for offshore oil and gas services given in Figure 2 excludes the requirement for decommissioning work. Given the vast network of ageing oil and gas infrastructure in Northern Europe, decommissioning demand is expected to coincide with increased demand for wind farm installation services, creating further competition for heavy lift vessels between the two industries.
Offshore construction and installation services should be regarded as one of the key bottlenecks in the offshore wind industry. The substantial capital required to increase capacity for offshore vessels, combined with a lack of confidence in the long term performance of the offshore wind industry, has made investors cautious in financing newbuild vessels targeted to offshore wind, nevertheless the success of contractors such as Seajacks and MPI Offshore is noteworthy. To date, this has meant that wind farm developers have often used oil and gas assets, such as those operated by Seaway Heavy Lift and Heerema, for installation services; however, competition for suitable vessels has been tough.
As a result of this stiff competition, developers have sought to vertically integrate in order to secure capacity within the supply chain. This has been achieved through the acquisition of contractors, such as DONG Energy acquiring A2Sea in 2009, or through the construction of assets such as RWE building its own installation vessels. Further down the supply chain, Scottish and Southern Energy bought a 15% stake in BiFab, the UK based fabricator of offshore structures. A developer’s access to guaranteed construction capacity will make projects more attractive to third party investors and increase the developer’s chance of securing preconstruction finance for the project.
Aside from competition for assets within the supply chain, the two industries will go head to head in a battle to attract
Figure 1. Northern European offshore wind cumulative growth forecast (Infield Systems).
Figure 2. Offshore wind versus oil and gas: Northern European infrastructure capex forecasts (Infield Systems).
and retain a skilled and experienced workforce. The presence of a skills gap in the oil and gas industry is certainly nothing new. Indeed, it is a key constraint that will be exacerbated by the development of the offshore wind industry. The wind sector is acutely aware of this potential shortfall and programmes such as the Beluga Offshore Training Academy are being developed to address the issue. This is of particular importance as contractors in the wind industry may struggle to compete with the deeper pockets found in the oil and gas sector.
Synergies and opportunities
Oil and wind in harmony Despite the competition for services, the petroleum industry will undoubtedly play a pivotal role in the development of offshore renewables. The oil and gas influence is first observed at the operator level. Oil companies are not only developing wind farms, they are also one of the major driving forces behind innovation in the industry. Indeed, companies such as DONG Energy, RWE, E.ON, Vattenfall and Centrica have all invested significantly in both offshore wind and upstream E&P. Moving further down the supply chain, these synergies continue with a host of contractors including engineering firms, fabrication yards and offshore construction companies having the knowledge and expertise to drive the industry forward.
An excellent example of oil and gas’ influence within the offshore renewables market can be found in Statoil’s development of the Hywind project. Inaugurated on 8 September 2009, Hywind is the world’s first, full-scale deepwater floating wind turbine. The project epitomises the synergies between oil and gas and offshore wind on a number of levels. To begin with, the project was conceived
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and developed by an international oil company, Statoil, whilst substructure engineering, fabrication and installation was undertaken by the subsea engineering contractor, Technip. Moreover, the technology employed for Hywind is a traditional floating platform design transferred from the oil and gas industry. The so called ‘Spar’ hull was fabricated at Technip’s Pori Yard in Finland, the same yard that has developed large oil and gas platforms including the Tahiti, Mad Dog and Holstein spars that have been installed in the US Gulf of Mexico.
Statoil is not the only oil company spearheading the development of offshore renewables; Shell has made a valuable contribution having developed the wind and solar powered Cutter platform, while Talisman and Scottish and Southern Energy completed the far-from-shore deepwater Beatrice wind farm. The former showcases the opportunities to marry the world of renewable energy and offshore E&P in the economic recovery of marginal hydrocarbons, while the latter underscores ‘big oil’s’ ability to push the operational boundaries of offshore wind energy.
Technological pushes from the oil and gas industry do not stop at the operator level. Indeed, the wealth of operational expertise that has been nurtured in the oil and gas sector during decades of offshore E&P activity provides a solid platform on which offshore renewables can be developed.
Indeed, Technip has recently launched a programme to develop a vertical-axis wind turbine. Known as Vertiwind, the project will see Technip, alongside Nenuphar, Coverteam and EDF, develop a vertical-axis floating wind turbine. This innovative project has the potential to reduce the cost of floating wind energy due to the simplistic design that negates the requirement for a large tower, nacelle, yaw system, pitch system and gearbox. Moreover, the
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design would allow the entire turbine and substructure to be assembled in the yard, thus reducing offshore construction time. With the Hywind project successfully completed, Technip is positioning itself as a major player in the fl oating wind energy market and signifi cantly contributing to the sector’s development.
There is also signifi cant opportunity for existing technologies to be transferred from the oil and gas industry to the offshore wind sector. Indeed, as wind farm developers move into deeper waters, the traditional monopile foundations will be replaced by jackets, tripods and trusses. Demand for these structures will create opportunities for oil and gas contractors from initial design through to fabrication and installation. Contractors such as the UK’s BiFab and the Netherlands’ Heerema have already taken advantage of these opportunities. BiFab was initially involved in the development of the Beatrice project and has since won a £12 million contract to design and manufacture two substation foundation
structures for RWE’s Gwynt y Mor wind farm offshore Wales. The yard has also secured an agreement with Scottish and Southern Energy to rollout at least 50 jacket substructures for wind turbines on an annual basis from 2014 onwards.
Conversely, offshore wind could stimulate the development of the oil and gas industry. One example is the cogeneration of offshore wind and gas assets. Such a project would involve the development of traditional thermal generating capacity, albeit in a marine environment, alongside offshore wind. In such a scheme the wind farm would provide the infrastructure, and hence the economic incentive, to develop a marginal gas fi eld, the product of which would fi re an offshore gas turbine. Power generated from both assets would be exported to shore via the wind farm’s transmission system. Cogeneration of this nature would tackle one of the key problems with wind energy; resource intermittency. An example of such a scheme, but one that fell by the wayside was Eclipse Energy’s Ormonde project. Ormonde
cogeneration plant was to be developed in the East Irish Sea but the project was re-evaluated, and subsequently reverted to a traditional wind farm following Vattenfall’s acquisition of Eclipse Energy in 2008.
Opportunities also exist to reuse existing offshore oil and gas structures within the renewables industry. Indeed, such structures have the potential to become integral components of the offshore wind infrastructure. Existing oil and gas platforms could be used as supply bases, operation and maintenance platforms or substations for a North Sea grid. The reuse of these structures would have obvious benefi ts to both parties.
ConclusionThe rollout of offshore wind at the pace desired by EU nations will create stiff competition for supply chain capacity and skilled workers within the oil and gas industry. Head to head battles for engineering, fabrication and offshore construction services may be the consequence unless the market sees increased investment in wind specifi c assets such as turbine and foundation installation vessels.
At the same time, however, the oil and gas and offshore wind industries will complement one another. E&P companies and their contractors are highly experienced in the offshore environment. As such, they are highly capable of developing solutions to new problems in addition to transferring established technologies and practices from one industry to the other. Moreover, the development of offshore wind will create a substantial and sustained demand for engineering and construction services. Contractors that position themselves correctly will stand to benefi t from the huge investment that is required if renewable energy targets are to be met. O T
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An illuminating exploration...Duane Dopkin, Paradigm, US, points out how full azimuth decomposition,
imaging and illumination enhances deepwater exploration.
Faced with replacing critical oil and gas reserves, energy companies are focusing exploration efforts in areas of challenging operational and
technical complexity. To conduct successful seismic programmes in these areas, substantial investments are being made to acquire wide and rich azimuth seismic data. These rich azimuth acquisitions, in turn, are combined with the latest seismic imaging technologies (e.g. Reverse Time Migration) to improve prospecting and return on investment for these costly seismic programmes.
Geophysicists ask a lot from their seismic data. Subsurface structures (e.g. salt, basalt) can be the genesis of multiple wave types (e.g. converted waves, multiples) and complex wave phenomena which distort the seismic image to the point where many iterations of velocity model building and seismic migration are required before selecting defensible prospects and drilling targets. In the deepwater
regions such as the Gulf of Mexico, this imaging problem is compounded by salt geometries that are highly irregular in shape in three dimensions. These salt bodies may be overlain or truncated by shale sequences that give rise to additional imaging problems as they often introduce a ‘directional’ velocity dependency referred to as anisotropy. Proper lateral and depth positioning of refl ected seismic events below these anisotropic generators require advanced velocity procedures to measure and model these parameters.
In the past decade, the industry has made huge investments in planning and acquiring seismic acquisitions that are both rich and wide in azimuth. These acquisitions are needed as geoscientists seek better reservoir defi nitions in deepwater regimes impacted by the geologic conditions described above. Benefi ts from these rich acquisitions have been acknowledged and documented, and
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OILFIELD TECHNOLOGYApril 2011
31
integrity and are limited in their capacity to extract subsurface attributes with azimuthal dependency.
Although there are many ways to decompose recorded seismic data, ray-tracing procedures provide a vehicle to simulate the subsurface ‘camera’. However, unlike traditional ray tracing procedures that are carried out from the acquisition surface, we need a rich ray tracing engine that can be initiated from any or every image point in the subsurface. This rich ray tracing ‘shoots’ rays in all angles and all directions so that we can ‘capture and preserve’ seismic data in an azimuthally continuous manner. It is carried out in a special reference system, referred to as the Local Angle Domain (LAD). By carrying out the ray tracing in this domain, we can decompose seismic data into two independent but complementary sets of full azimuth gathers. The first set of gathers (reflection) contains a continuous (360˚) sampling of reflectivity (amplitude) information as a function of reflection (opening) angle. These gathers provide the data structure to detect and measure velocity anisotropy, to predict lithology, to detect stress directions, and to update velocity models. The second set of gathers (directional) contains a continuous azimuthal sampling of the total scattered energy as a function of the dip and azimuth of local reflecting surface. Since the total scattered energy contains both continuous (specular) and discontinuous (diffracted) energy, we are able to easily differentiate and create images that emphasise these two components (Figure 1).
The combination of the two angle gathers, together with the ability to handle the full azimuth information in a continuous manner, enables the generation and extraction of high resolution information about subsurface angle dependent reflectivity in real 3D space. The complete set of information from both angle gather types expands our knowledge about both continuous structural surfaces and discontinuous objects, such as faults and small-scale fractures, leading to accurate, high-resolution, high-certainty, velocity model determination and reservoir characterisation.
Enhancing deep reflectors Full azimuth directional angle gathers represent a seismic decomposition of the total scattered energy wavefield into dip/azimuth angle bins at all subsurface points. These gathers contain information about both specular and diffraction energy. Specular energy is associated with reflectors from continuous interfaces. Diffraction energy is associated with non-specular
Figure 2. Comparison of conventional seismic depth image (left) and seismic depth image generated with full azimuth decomposition, imaging and specular weighting.
Figure 3. Point-diffraction ray tracing from a subsalt reflection image point. See text for expanded explanation.
directivity originating from local heterogeneities such as channels and fractures. The ability to decompose the specular and diffraction energy from the total scattered field allows for the creation of enhanced feature images from the fully recorded wavefield.
In the deep waters of the Gulf of Mexico, for example, the interpretation of subsalt reflectors is often challenging because of wave interference (e.g. multiples, converted waves), attenuation, ambiguities in velocity model definition, and complex wave phenomena. To compensate, we can use the
30 OILFIELD TECHNOLOGY April 2011
include improved multiple suppression, noise suppression and illumination of target areas. However, while the resulting seismic images inherit many of the benefits of rich and wide azimuth acquisitions, the application of current seismic imaging technology can fall short in exploiting the full potential of these acquisitions.
While advances in seismic imaging continue at a rapid pace, most of the solutions are limited in their ability to properly deal with the rich azimuthal sampling of data recorded at the surface. What is needed is a solution that allows us to better qualify and even quantify the expenditures that we make in seismic acquisition and imaging. The solution should assist us not only in understanding the implications of our assumptions and simplifications in dealing with wide and rich azimuthal data, but also help us assess where we can make changes that will have the most impact on our seismic programmes.
To achieve this objective, we need to give proper attention to the issue of mapping rich azimuthal data recorded at the surface to image points in the subsurface. Recognising the full potential of rich and wide azimuth seismic data acquired in deepwater exploration areas requires a significant ‘upgrade’ to our seismic imaging, characterisation and interpretation technologies. Much like a camera equipped for continuous recording at all angles and directions, this upgrade would provide a comprehensive decomposition of the recorded seismic data into physical domains that recover and preserve subsurface illumination in all orientations and angles in a continuous manner. If successful, we will introduce new seismic data representations that allow us to better understand subsurface illumination, to better qualify seismic images, to reduce the non-uniqueness of the seismic method, and to better describe the critical parameters of the velocity model.
Limitations of azimuthal sectoringMuch like the benefits of capturing images from a continuously revolving and pivoting camera, the benefits of sampling the subsurface with continuous azimuth are well understood. Azimuthal sampling of seismic data allows us to better detect and measure velocity anisotropy, to identify and separate
different wave types, to predict lithology from more meaningful seismic signatures, to detect stress orientations and intensity, and to understand the dependency of seismic acquisition on image quality (illumination). However, unlike the camera analogy, capturing seismic data at every subsurface point in all angles and directions (azimuths) is much more problematic. Computational and operational barriers often limit the solution to surface acquisition interpolation schemes followed by course acquisition sampling of surface azimuths (sectoring) rather than the desired
decomposition and imaging of seismic data to continuous subsurface azimuthal datasets.
Although intuitively attractive, the surface sectoring approach has severe drawbacks. Sector decisions (size and number) are often taken independently without consideration given to the subsurface. Instead, decisions are often taken out of convenience to accommodate project deadlines and application limitations of dealing with multi azimuthal data. More importantly, sectors formed over a range of surface azimuths lack the resolution and accuracy to properly use the entire recorded wavefield to uncover the information and data listed in the previous paragraph. This is particularly true when long offsets are involved. Finally, while easy to create, sectored datasets are processed independently and subsequently must be analysed and interpreted. Extracting a holistic interpretation from the analysis of these independent datasets is not straightforward.
To resolve these issues, we introduce a new seismic decomposition procedure that replaces images constructed from sectored source to receiver offsets and azimuth with data structures and images constructed from in-situ angle and azimuth data at any or all subsurface image points. The rich information from all angles and azimuths ensures more reliable analysis and significantly reduces reflector position uncertainty. The solution is designed to deliver a complete set of data containing accurate subsurface velocity models, structural attributes, medium properties, and reservoir characteristics.
A new seismic perspective All seismic imaging methods decompose seismic data into organised domains of subsurface data that provide the pathway for other data analysis procedures including velocity analysis, AVO(A), and other seismic characterisation solutions. These organised data domains (pre-stack gathers) can take many different forms with vertical sampling in time or depth, and spatial sampling in surface offset or subsurface angle. There are other representations of pre-stack gathers depending on the seismic imaging technology being used. However, other than forming gathers with the sectoring approach described above, all of these pre-stack gathers carry no directional (azimuth)
Figure 1. Decomposition and imaging in the local angle domain. Ray tracing reference (left), full azimuth reflection angle gather (centre) and full azimuth directional angle gather (right).
32 OILFIELD TECHNOLOGY April 2011
energy values computed from the full azimuth directional angle gathers as weighting factors in the creation of the final image. The high ‘energy’ values associated with the specular directions sharpens the image of the deeper reflectors (Figure 2) at the expense of the scattered or non-specular energy in the data. Additionally, the focusing of the specular energy we observe in the directional gathers serves as an indicator of velocity model error and accuracy. This full azimuth subsurface decomposition of the recorded wavefield into directional gathers provides the means to more precisely unite the fields of seismic imaging and interpretation in areas of complex wave phenomena.
Resolving anisotropic ambiguitiesModelling anisotropic velocity behaviour in deepwater exploration basins is critical for a more accurate lateral and depth positioning of reflected events beneath the anisotropic generating formations as well as for the creation of more interpretable seismic images. Full azimuth reflection angle gathers allow geoscientists to visualise the influence of anisotropy on the moveout of reflection amplitudes sampled continuously over all azimuths. The analysis of anisotropic behaviour can be visualised in three dimensions so that the sources of anisotropy can be better understood and the strength of anisotropy better appreciated. When coupled with the information and data contained in the full azimuth directional angle gathers, geoscientists are better able to differentiate between different types (e.g. VTI and TTI) of anisotropy.
Resolving illumination ambiguitiesSubsurface illumination analysis is a widely used technique in deepwater exploration areas to better understand the dependency of the seismic image on the seismic acquisition and velocity model description. When used properly, it can deliver information about imaging reliability, help define optimum imaging parameters, enhance acquisition geometry, and validate
Figure 4. Rose diagrams of ray-pair illumination intensity captured at acquisition surface (top) and subsurface image points (bottom). See text for expanded explanation.
prospects selected on the basis of amplitude or amplitude continuity.
Illumination analysis is routinely carried out with ray tracing procedures. Here, the rich ‘bottom-up’ ray tracing procedure described earlier is used to secure a uniform illumination of the subsurface and establish a mapping of subsurface angle parameters to surface geometry parameters. The result of this ray tracing procedure is a rich set of illumination factors (angle dependent) and physical ray parameters (e.g. geometric spreading, reliability factors) that are essential for quality control of imaging results, especially below complex structures such as salt bodies. Figure 3 shows an example of point-diffraction rays traced from a subsalt reflection point,
where only a subset of the rays arrive to the surface within the given aperture (green rays).
The full benefit of this type of illumination can be appreciated by the generation and evaluation of illumination Rose diagrams. Figure 4 (top) shows the ray-pair illumination intensity from three subsurface image points arriving at the surface from different distances and azimuths. The narrow azimuth acquisition geometry is clearly noted. Figure 4 (bottom), on the other hand shows the same ray-pair illumination intensity, this time at the subsurface, as a function of opening angle and azimuth. Note the poor correlation of orientation at crossline 325, reflecting a large translation in azimuth as rays pass from the surface through the salt. This provides a strong visual argument against using surface azimuthal sectoring as a procedure to deal with wide azimuthal data.
ConclusionsFull azimuth decomposition, imaging, and illumination provide deepwater exploration professionals an additional and powerful tool to evaluate subsurface complexities. The full power of the solution is realised in its ability to decompose the recorded seismic wavefield into the physically meaningful domains of reflection angle and reflection dips over a full and continuous range of azimuths. The solution is a well needed complement to a portfolio of existing deepwater seismic imaging technologies that collectively remove imaging uncertainty and improve the non-uniqueness of the seismic experiment. O T
References1. Koren, Z., I. Ravve, E. Ragoza, A. Bartana, and D. Kosloff, 2008, ‘Full
Azimuth Angle Domain Imaging: 78th Annual International Meeting, SEG’, Expanded Abstracts, 2221-2225.
2. Zvi Koren and Igor Ravve, ‘Full-azimuth subsurface angle domain wavefield decomposition and imaging, Part 1: Directional and reflection image gathers’, Geophysics, Vol. 76, No. 1 January-February 2011; P. S1–S13.
High quality seismic imaging is a key to successful hydrocarbon hunting. The creation of such images can be especially challenging in
geologically complex areas. This article presents a case study of an anisotropic prestack depth migration (APSDM) project that used high resolution, shallow tomography and anisotropic model building to solve complex imaging challenges for a large depth migration project in the Gulf of Mexico. Compared to previous processing in the area this enhanced work flow resulted in higher quality images and more accurate placement of events. The project consisted of approximately 553 OCS blocks of data in the Mississippi Canyon, South Timbalier, Ewing Bank, Grand Isle, Grand Isle South Addition and Ship Shoal South Addition areas (Figure 1).
The goals of this project were to improve the imaging of steep dips, salt boundaries and subsalt events, and produce a more accurate velocity model that would enhance event placement. A solution to the problems posed by the low velocity South Timbelier trench was critical to the success of the project. To this end the
IMPROVED IMAGINGGary Rodriguez, Sherry Yang
and Laurie Geiger, TGS, USA,
present a project to improve
imaging in a low velocity trench
area in the Gulf of Mexico.trench area, which was addressed in previous processing efforts with refraction statics, was modelled using high-resolution tomographic velocity inversion to produce a more accurate shallow velocity field. Additionally, APSDM was employed to better tie the seismic events with well information.
BackgroundThe survey is located in an area of the Gulf of Mexico with many complex surface structures and geologic challenges. To overcome these challenges, the previous processing used long period refraction static corrections and short period surface consistent static corrections applied in the time domain prior to migration. Figure 2 shows the bathymetry of the data area, with the trench area highlighted by the white box.
Traditional refraction statics solutions use static shifts to address the time delays caused by shallow velocity anomalies. However, the refraction solution causes sags in the resultant seismic image due to the longer travel times through the slow velocity layer. The refraction solution solves the travel time delay induced by the layer and applies a static shift to the traces so as to minimise the resultant time
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34 OILFIELD TECHNOLOGYApril 2011
sag. While these static shifts generally produce much improved time images deeper in the section, the time static applied is not kinematically correct for depth migration. In particular, this could lead to velocity distortions when solving for the depth velocity field. These distortions could affect the entire velocity model.
Therefore, when planning the velocity modelling approach for this project, it was decided that a high resolution tomographic inversion would be attempted to more correctly model the velocities in the South Timbalier trench area. If correctly modelled, a more stable velocity field and a more accurate depth image should be expected.
Since tomography cannot resolve the high frequency component of the shallow velocity variation, this part of the static solution, which derives from surface consistent residual statics, was retained.
The other key enhancement to the previous processing flow was the use of APSDM. Through the use of abundant check shot velocity information and anisotropic parameter estimation, well-calibrated velocities were used for migration. The use of a calibrated velocity field should ensure better well ties with the seismic data.
Initial anisotropic model buildingA total of 539 check shots were analysed for use as a starting point for building the initial velocity model. The check shot velocity functions were analysed and spurious trends edited. These edited check shot velocities were gridded, interpolated and smoothed to generate the initial vertical velocity model (Vz).
An isotropic Kirchhoff migration was run using the Vz model. The resultant image gathers were used in a two-parameter semblance scan. The semblance cube that was generated had three axes: depth, epsilon and delta (two of Thomsen’s weak anisotropic parameters)1. The maximum semblance on each of the depth slices occurs at the epsilon and delta values that best flatten the gather at that depth. A semblance cube was generated for each of the key well locations. The semblance cubes were automatically scanned to estimate the optimal epsilon and delta trends. These epsilon and delta values were then smoothed, interpolated and gridded to populate the 3D model. To verify the integrity of the epsilon and delta fields, these fields were used to remigrate the data, this time using anisotropic Kirchhoff prestack depth migration. Gather flatness, event focusing and well ties were checked. Another iteration of parameter estimation was run to refine the epsilon and delta fields, after which the initial anisotropic sediment model was complete.
High resolution trench tomographyThe resultant Vz, epsilon and delta fields were then used as a starting point for tomographic velocity updating. A full volume high resolution anisotropic prestack depth migration was run over the trench area. Typical model building runs output 10 m depth steps with 300 m between output offsets (input offset increment of 150 m). In order to correctly derive residual curvature estimates for the shallow data, a finer offset and depth sampling were deemed necessary. Consequently, for these iterations a depth step of 5 m was used, and the output offset increment was 150 m. Furthermore, the tomography inversion cell size was decreased compared to that of a typical work flow. Additionally, these early iterations were limited in depth to 4 km.
Figure 2. Water bottom showing trench area within the white box.
Figure 3. Map view of residual curvatures over low velocity trench.
Figure 1. Project area.
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The APSDM gathers were scanned for residual curvature. Figures 3 and 4 show the auto-picked residual curvature estimates that were put into the tomography velocity inversion. Over time, the deep trench, as shown in Figure 2, was filled in with slow velocity mud. The red residual curvature values in Figure 3 relate to positive move-out (increase in reflection depth with offset), implying that a velocity decrease is needed in this area. The curvature values along with derived dip fields were input into the first tomographic inversion. In evaluating the residual curvature picks it was noted that there was a strong correlation between areas of positive residual curvature and the previously derived refraction statics solution. A positive residual curvature requires a slowdown in velocity in order to flatten
gathers. A shallow slow velocity region is exactly what one would expect in the unconsolidated Timbalier trench area.
Figure 5 shows the velocity perturbation that was output from the tomographic update. The green region of this display is an area of negative velocity updates (velocity slowdown). Figure 6 shows the seismic data migrated with the initial velocity model. The white circle indicates the trench area. This correlates well with the regions of negative velocity updates that are shown in Figure 5.
Figure 7 shows the result of migrating with the updated velocity model. Below the trench area much better event continuity is evident. Faults are better imaged and reflectors appear more geologically realistic. The red arrow seen in Figure 6 highlights an event sag that is induced by the slow velocity anomaly. The red arrow in Figure 7 shows the same area after tomographic velocity updates. The sub-trench events do not have this velocity sag. This is contrasted with the image obtained by migrating with the data that had refraction statics applied before migration and velocity updates. This image is shown in Figure 8. The original migration using refraction statics appears to have false structures induced by distortions in the velocity model.
Velocity model updatingThe anisotropic sediment model was further updated with two passes of grid based tomography. These iterations went to a total depth of 12 km and were output with a 10 m depth step and a 300 m offset increment. For each of the tomography iterations, 3D anisotropic prestack Kirchhoff depth migration was run, and residual curvature analysis was performed on the resulting image gathers. Automatic dip estimation was performed on the stack volume for use in the tomography ray tracing steps. A new dip field was created for each of the iterations that were run. Any rays travelling through salt were not used in the tomography matrix solution. Vz was updated from the inversion results, and well ties was rechecked and recalibrated. After recalibration of the velocity field, the epsilon and delta fields were then adjusted in order to preserve both flatness of the resultant gathers and the ties to the check shots.
Accounting for the shallow trench area allowed for better imaging and placement of events around this region. Because the imaging was more accurate, sub-trench structures, including
Figure 4. Inline view of residual curvatures through low velocity trench.
Figure 5. Velocity update output from tomography.
Figure 6. Prestack depth migration with initial model.Figure 7. Prestack depth migration after shallow, high resolution tomography.
salt, were more correctly shaped and positioned. This in turn allowed for a more accurate dip fi eld. All of these improvements led to a more accurate migration in the shallow region, which, in turn, resulted in better tomographic velocity updates and improved imaging below the trench and throughout the project.
Salt model buildingThe salt geometry was quite complex. In order to correctly defi ne salt overhangs, the salt geometry was defi ned using four passes of APSDM. Initially, top of salt was picked on the image produced by migration with the fi nal supra-salt sediment velocity fi eld. At this stage, salt boundaries interpreted from the seismic images were checked against top salt events picked from well data. Vz, epsilon and delta were then adjusted accordingly in order for salt tops to image at the proper depths, while simultaneously preserving the image gather fl atness.
The fi rst base of salt was interpreted on seismic images produced after APDSM using the recalibrated salt fl ooded velocity model. A migration was then run with the fi rst top and base of salt inserted into the model, and second (deeper or overhung) salt tops were interpreted. Next, APSDM was run, which fl ooded below the second top salt. The second base salt was then interpreted, and the fi nal salt model was constructed using these four surfaces. The data was then migrated with the interpreted salt geometry.
Subsalt velocity model updatesA fi nal tomography pass was performed for the subsalt areas. In this iteration, sedimentary regions of the model, both under salt and away from salt, were updated. Tomography inverted for the velocity updates, which were subsequently added back to the previous sediment model. Salt was inserted back into the fi nal sediment model to produce the fi nal salt velocity model.
The fi nal imaging step was run with the anisotropic prestack Kirchhoff depth migration using an increased aperture. Turning rays were also used in the migration to better image steep dip salt fl anks.
ConclusionThe enhanced workfl ow for this project included using a well-tied anisotropic sediment model, anisotropic prestack Kirchhoff depth migration, modelling of salt bodies with overhangs, and iterations of both supra-salt and subsalt tomography, including two shallow, high resolution iterations. This methodology resulted in a high quality image with more accurate event placement and geologic structures. Salt boundaries and steep or overturned events were imaged much better than in previous processing. Deep structures and subsalt events were more geologically sensible and had increased continuity. Addressing the slow velocity zone using tomography rather than using a refraction statics solution resulted in better focused shallow faults and more realistic structures in the Timbalier trench area and beyond. O T
AcknowledgmentsThe authors would like to acknowledge Diane Yang, Quincy Zhang and Steve Hightower who worked on this project. The authors would like to thank those who helped review this paper, including Simon Baldock, Michael Ball, Connie Gough, Bin Wang and Zhiming Li. Thanks also to TGS for allowing this work to be published.
Figure 8. Previous isotropic WEM with refractions statics.
References1. THOMSEN L., ‘Understanding Seismic Anisotropy in Exploration and
Exploitation,’ 2002 Distinguished Instructor Short Course, Number 5, SEG, Tulsa, OK, USA.
BibliographyRODRIGUEZ G., YANG, S., YANG, D., ZHANG Q., and HIGHTOWER, S., ‘Anisotropic Depth Migration and High Resolution Tomography in Gulf of Mexico: A Case History,’ 72nd EAGE Conference and Exhibition, Expanded Abstracts, 2010.RODRIGUEZ G., YANG, S., YANG, D. , ZHANG, Q., and HIGHTOWER, S., ‘Improved Imaging through Anisotropic Depth Migration and High Resolution Shallow Tomography In Lieu of Refraction Statics in South Timbalier Trench Area of Gulf of Mexico: A Case History,’ 79th Annual International Meeting, SEG, Expanded Abstracts, 2009.WOODWARD, M., FARMER, P., NICHOLS, D., and CHARLES, S., ‘Automated 3D tomographic velocity analysis of residual moveout in prestack depth migrated common image point gathers: 69th SEG Expanded Abstracts,’ 1218 - 1221,1999.
The road to recovery
[COVER STORY]
For offshore oil and gas fi elds, well intervention and drilling sidetracks are methods to increase the oil production from existing wells. Operators can
signifi cantly improve offshore hydrocarbon recovery from both greenfi eld and brownfi eld reservoirs by installing subsea processing systems. Subsea processing presents signifi cant potential for cost savings by moving some of the traditional topsides fl uid processing to the seabed. Subsea separation and local re-injection of produced water and/or gas to the reservoir or to a
dedicated disposal zone will allow fl owlines and topside processing equipment to be used more effi ciently. Subsea gas/liquid separation and liquid boosting can increase the production rate in low energy reservoirs.
Treating the production fl ow at the seabed provides many opportunities to achieve more effective exploitation of oil reservoirs around the world. Subsea separation and boosting allows marginal reservoirs to be developed economically, and in some cases, can eliminate the need for surface host facilities. This is important as
38
Brian Skeels, FMC Technologies, and Lars Farestvedt, MPM, US, consider solutions for maximising reservoir recovery in this issue’s cover story.
the industry must turn to reservoirs that are not easily accessible in order to maintain energy supply.
The focus is now on addressing the challenge of how to cost-effectively produce oil and gas from offshore fi elds located in deeper waters and more remote areas.
The traditional way of improving asset value using subsea processing has been through installing a multiphase pump close to the well. Subsea multiphase pumping is an effective means to improve the economics by reducing back pressure on the reservoir, which
increases well fl ow rates and total recoverable reserves. However, it has been limited to applications in shallower water with shorter tieback distances. This is primarily because of the limitations in the pumping technology itself.
As offshore production moves to deeper, harsher environments, the use of surface structures is becoming prohibitive due to complexity and cost. This has led to subsea processing, which has created a new emerging market for processing equipment.
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40 OILFIELD TECHNOLOGY April 2011
Riserless light well intervention With the rising number of ageing subsea wells in the North Sea, the demand for efficient subsea light well intervention service continues to grow. Such service has been in operation in the Norwegian sector for the past six years and is currently experiencing exponential growth with the addition of several more intervention systems spurred by continued long term commitments.
FMC Technologies’ second generation Riserless Light Well Intervention (Mark II) makes interventions feasible in deeper water by reducing weight, optimising the size of pressure control and closure devices, and upgrading the control systems. It uses a compact, electric, ROV-style optic-electrical umbilical cable that can be disconnected quickly and safely without ROV assistance and stands up to rigorous heave compensation winches. Reconfiguration between wells and/or tasks is much easier and more efficient than it used to be.
Principles from the first generation were largely maintained for well barriers and overall system philosophy. To improve
operational efficiencies, the control system architecture was updated, mitigating the possibilities of time lost due to handling of the large diameter IWOCS electro-hydraulic umbilical. The approach was to remove on-deck based surface power generation equipment while replacing the maze of hydraulic hoses and fittings associated with the cumbersome IWOCS umbilical with the ROV-style cable. The subsea IWOCS controls powered by the cable feature the same distributed control architecture found on newer work class ROVs, taking advantage of IP routing and control.
Field operators have concluded that the intervention cost for individual production wells is paid back in less than 20 days of increased production. With strong HSE focus, comprehensive planning and training and the right technology, the RLWI operations have proven to be a cost-efficient increased oil recovery tool, which enhances the value of the operators’ assets in subsea fields.
Mark II has experienced success in water umbilical management, safer deck handling, efficiency from remote in-situ fluid delivery and hydrate control. Improved well control ‘barrier’ equipment now accommodates a third longer length wireline tools, as well as electric powered control system architecture by using the ROV-style cable. Autonomous grease injection capability, subsea monitored chemical injection and fluid exchange/flushing capabilities have reduced fluid wastage and contingency tankage requirements. These accomplishments are all due to the recommendations and lessons learned from first generation RLWI systems.
Through tubing rotary drillingAs the number of fields drilled with subsea developments increases and the need to increase production remains ever present, innovative technology to help operators produce more hydrocarbons out of existing reservoirs remains one of the industry’s top priorities.
FMC Technologies’ Through Tubing Rotary Drilling (TTRD) system makes it possible to enter a well and drill a sidetrack from the parent well without having to pull the tubing. A sidetrack well can be drilled from deep within the current well through the installation of a whipstock at the selected depth and the milling of a window in the liner. Since sidetracks are drilled below the production packer with the drill pipe conducted through the tubing, neither the tubing nor the Christmas tree needs to be removed.
Both the whipstock installation and the window milling can be achieved in one run. The TTRD system configuration allows drilling, well testing and completion to be performed through one system, compared to traditional methods that require the installation of two individual systems. The TTRD configuration consists of a tree adaptor, lower riser package, emergency disconnect package, Merlin riser, surface BOP, marine riser slip joint and surface flow tree.
Once the TTRD rig is mobilised, both TTRD and well interventions can be performed. The new stack configuration opens the door for improvements in other operational sequences and may also adapt to new drilling techniques in the future.
In subsea wells, damage to horizontal subsea trees has been a persistent problem. The TTRD system features fit-for-purpose protection sleeves for the seal areas in the completion, non-abrasive hard banding, bottom-hole assembly
Figure 1. Through Tubing Rotary Drilling (TTRD) system makes it possible to enter a well and drill a sidetrack from the parent well without having to pull the tubing.
Figure 2. MPM 3D Broadband technology detects accurately and rapidly to determine how the liquid and gas is distributed throughout the pipe.
Lonely?Turn to page 47...
42 OILFIELD TECHNOLOGY April 2011
designs that are not aggressive to the completion, and the Christmas tree and a crown plug with elastomer.
Typical costs for a new subsea well can range from US$ 40 – 50 million. The new drainage points created for one FMC customer using TTRD are estimated to cost US$ 10 million. Smaller reserve pockets are suddenly more economical and existing wells will have a longer life and a longer revenue stream. Additional benefits of TTRD include reduced fatigue exposure to the wellhead and more efficient operations with less handling of heavy equipment.
Multiphase metersThe MPM multiphase meters employ tomographic technology to significantly improve measurement accuracy and
measurement range for multiphase meters for topside and subsea applications. The self calibrating feature implemented in the MPM meter is a step change from conventional multiphase meters. This new feature is achieved through implementing salinity measurement functionality in combination with the in-situ fluid property verification. The MPM meter works equally well for multiphase and wetgas applications, for gas void fractions of 0 – 100% and water cut of 0 – 100%. The 3D Broadband® technology is employed to accurately and rapidly determining how the liquid and gas is distributed throughout the pipe, while at the same time determines precise flow rates of oil, gas and water. For slugging flow regimes, the MPM meter will automatically switch up to five times per second between the multiphase and wetgas modes, bridging a gap previously not covered by multiphase meters. The MPM subsea multiphase meter has been qualified through the stringent DNV RP-203 qualification process to an impressive 15 000 psi working pressure and 480 ˚F working temperature. The MPM meter has also been designed for 11 500 ft water depth.
MPM Subsea Multi Phase Meters utilise patented (seven patents) technology achieving significantly improved real-life measurement of oil, gas and water on the seabed. Through using the DualMode® automatic switching between multiphase and wetgas measurements, one meter can be used for the full field life even if the wells change from predominantly oil to predominantly gas, and as the water cut increases from close to zero to close to 100% in late life. The meter’s unique self calibration functionality furthermore automatically measures and
compensates for changes in the water salinity, eliminating the need for costly subsea sampling to calibrate the meter.
The MPM meter allows the operators to improve reservoir monitoring and increase recovery. Measuring miniscule amounts of water in gas wells extremely accurately (down to 0.002%), the operator can optimise and significantly reduce the amounts of chemicals injected to mitigate hydrate formation. With its significantly lower sensitivity to fluid property changes and the in-situ self calibration functionalities found in the MPM meter, the operator can reduce and often eliminate the need for subsea sampling. Not having to bring a sampling bomb to the surface from a 10 000 ft deep high pressure subsea well not only significantly reduces cost, but also removes a potential safety hazard. O T
Figure 3. Riserless Light Well Intervention makes interventions feasible in deeper water.
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The low-hanging fruit is long gone. Every day it’s more of a challenge to increase oil and gas recovery and production from aging, under-producing fi elds and complex new ones: arctic and ultradeep subsea fi elds; tight sands, shale and thermal oil sands; HP/HT, long distance, deepwater complex pre-salt or lower tertiary formations. Whatever the need, we have the technology – rigorously proven in the world’s toughest situations – to raise your recovery factor and production to unprecedented heights. Not some day. Now.
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There is little doubt that too often over the past two decades, subsea oil and gas production strategies have been guided by short-term
decision making – predominantly by fluctuating oil and gas prices.
It is, of course, vital to ensure that production in fields adheres to strict economic criteria. There is no sense, for example, in operating a field for many years that has reached its economic limit - namely when the production rate no longer covers the expenses incurred extracting the hydrocarbons.
Operators, however, are often quick to leave existing fields when they have reached recovery rates of around 30% (the recovery factor being the ratio of producible oil reserves to total oil in place for a given field), sacrificing these fields in the relentless search for ‘new oil’. And this is not helped by their ‘economic limit’ being a
moving target – fluctuating due to the influences of worldwide supply and demand.
The North Sea is an example of operators not doing enough to maximise their assets. How often has it been said over the past few years that North Sea oil is running on empty? And that we are dealing with the very dregs of the reservoir.
Yet, despite this, the last few years have seen renewed interest, albeit often from smaller players. According to the Norwegian Petroleum Directorate (NPD), there were 16 new discoveries on the Norwegian Continental Shelf (NCS) in 2010, with the NPD estimating that more than 50% of oil remains in Norway’s fields.
The same is the case on the UK Continental Shelf (UKCS) where the latest 26th licensing round led to the largest number of bids since the first round in 1964.
Lifting expectations
Ian Anderson, Camcon Oil, UK, explains
how artificial gas lift can assist in developing
a long term strategy for subsea extraction.
44
Oil and Gas UK, the trade association for the UK offshore oil and gas sector, believes that up to 25 billion bbls remain to be won from the UKCS.
It is these kinds of figures that leads one to the conclusion that many of the larger operators were premature when deciding to take leave of the North Sea in search of richer potential assets elsewhere – mainly due to a short term production strategy. It is also possible that incidents, such as the Macondo spill, may turn out to be an example of fast-tracking the search programme and pushing out the boundaries of oil and gas exploration too quickly.
The focus on EORThe last few years have seen more operators looking to next generation enhanced recovery techniques as a means of trying to meet and then alter the economic
limit of their fields. With new frontier regions increasingly remote, geologically complex and expensive, there is also an element of ‘needs must’.
In the North Sea, Norwegian operator, Statoil is a good example of how recovery rates can be significantly improved. The company has a target recovery factor of 65% for platform operated fields and 55% for subsea-operated fields and is starting to make good on these goals.
Similarly in the Middle East, ambitious targets are being set. Saudi Aramco’s President and CEO, Khalid A. Al Falih, has released a target recovery rate of 70% from its major existing fields and in Oman, oil production has actually increased by 17% over the last two years with much of this due to EOR techniques.1
Yet there is clearly more to do and few are satisfied with the current, albeit improving, levels of recovery.
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46 OILFIELD TECHNOLOGYApril 2011
Even in Norway, which boasts some of the highest recovery rates in the world, there is a concern over the inability to maximise oil and gas reserves. Bente Nyland, Director General of the Norwegian Petroleum Directorate, said in a recent press release: “We are still not satisfied. If we manage to recover just 1% more, this would mean revenues in the hundreds of billions for Norway.”
And these potential windfalls of enhanced recovery are clear worldwide. According to Oil & Gas Journal, an increase of 1% in recovery rates would replace three years of global oil consumption.
Closing the subsea information gap and countering well instabilitySo how can effective oil recovery strategies be employed, while still increasing these rates?
In answering this question, it is also important to tackle another issue – the widening recovery gaps between topside and subsea wells, with the latter generating average recovery rates of up to 15% less than their topside counterparts.
The high costs and risk profiles of subsea intervention are major contributors to this gap as are two ongoing threats - well instability and the lack of information on subsea wells.
Well instability can be due to a number of reasons, including water breakthrough; slugging – the accumulation of water, oil or condensates in the pipeline; or increased pressures in the well. While well instability rarely results in catastrophic scenarios, it can still be a major impediment to reservoir performance and recovery rates.
Linked to this is the lack of information from which many operators suffer, with regard to their subsea wells and key variables, such as temperature, gas flow or the amount of water or sand in the production flow. This information gap often translates into a production gap. The twin themes of well instability and the importance of generating vital, real-time information will be constant themes throughout the rest of this article.
Improving oil recovery strategies There are a wide variety of technologies on the market today trying to address oil recovery challenges – technologies normally coming into effect once primary and secondary recovery methods have been exhausted.
These include chemical injection, where chemicals such as alkaline or caustic solutions, are utilised; thermal injection where techniques are used to heat crude oil to reduce its viscosity; and newer technologies such as microbial injection.
Probably the most common form, however, is gas injection, where gases, such as CO2, natural gas or nitrogen, are injected into the reservoir in order to either push gases through the reservoir or decrease viscosity within the oil. Probably the most common form of gas injection is artificial gas lift.
The importance of artificial gas liftArtificial gas lift consists of injecting gas into the production tubing to reduce the impact of the hydrostatic pressure where the reservoir pressures are not sufficient to force the hydrocarbons to the surface. By reducing the density of the columns, reservoir liquids can enter the wellbore at higher flow rates. Artificial gas lift normally sits beside other forms of artificial lift, such as beam pumping, electric submersible pumps, and hydraulic pumps.
Whereas in the past, it might have been considered a secondary or tertiary technique, today, artificial gas lift can be, and often is, employed at any time during the productive life of the fields – sometimes even from the outset.
10% of wells in the US, for example, use some form of artificial gas lift2 and in Bahrain, 60% of oil wells use some form of artificial lift to generate 50% of the Kingdom’s total oil production.3 Spears & Associates estimated that the total global artificial lift market was worth US$ 6.9 billion in 2008.
While there are clear benefits to what has become an established technology, there are also limitations to artificial gas lift, many of which come back to the lack of information.
Operators usually have very little information on pressure and temperatures at the point of gas injection, as well as no control or flexibility to alter injection rates as production variables change.
The primary method of gas injection is still to be found in the ‘side pocket mandrel’ configured completions, where wireline interventions are used to change the operating valve when injection rate changes are necessary. Such interventions can be a long and cumbersome process, leading to damage to existing infrastructure (if the wire snaps, for example) and the halting of production as a new side mandrel unit is installed. These side mandrel tools also have no instrumentation onboard.
This lack of information and flexibility means that rather than providing more control of the stability of wells, artificial gas lift can actually cause greater instability.
This is due to the potential for artificial gas to increase the probability of dramatic flow fluctuations, unpredictable surges in liquid and gas production rates, and increased concerns over the integrity of the casing and tubing, leading to burst or collapsed
Figure 2. The Camcon digital artificial lift solution – APOLLO.
Figure 1. Key internal elements of Camcon’s digital artificial lift solution.
is easy
Bringing you the power of information
Energy Global
48 OILFIELD TECHNOLOGYApril 2011
casing strings and, in the worst case scenario, oil or gas migrating vertically towards the surface along the outside of the casing. While these issues could be dealt with if the artificial gas lift process was closely monitored at the point of gas injection onwards, the fact that the operator is ‘flying blind’ increases the risk.
Whereas in the past, incremental changes might have been suggested to meet these limitations, it seems clear that there is a genuine industry need for greater operator control over artificial gas lift operations. Operators need to have access to variable operating valve combinations, where decisions and modifications can be made in real time without intervention and without threats to well stability.
So if there are clear limitations here, why are companies not surfacing with new technologies?
One slightly conspiratorial answer is that this is exactly how the large integrated oil service companies like it – reduced risks and expenditure and a focus on developing their current business lines rather than embracing innovation. The results are products that simply squeeze better performance from an existing concept for short term gain and increased market share without tackling the fundamental long term challenges.
It is reasonable to conclude, however, that the opportunity to use ‘old’ technology solutions in different, new ways has now been exhausted.
Digitising artificial gas liftIt is against this global context and against some of the industry limitations already described, that Camcon Oil is in the process
Figure 3. Digital lift can be deployed in a wide variety of challenging geologies.
Figure 4. A comparison of the optimum performance of the dial solution compared to a side pocket mandrel system.
of developing a digital artificial lift solution that addresses many of the issues described above. Figure 1 provides an overview of the system, while Figure 2 outlines the product.
The solution is based around binary actuation technology (BAT), a technology that has been developed over the last few years and which also has applications for the automotive, manufacturing and life sciences industries. Central to the technology is a low energy pulse control that signals to switch an actuator between two stable positions to digitally operate a valve. Particular benefits include high switching speed and low power consumption.
This technology has now been customised for artificial gas lift and, as Figure 3 illustrates, can be deployed in a wide variety of challenging geologies and a wide variety of completion string geometries – far more than for a conventional gas lift.
The actuator is coupled to a gas flow control valve to enable that valve to be opened or closed remotely. This eliminates the need for side mandrel units and wireline intervention and is particularly important in bringing digital technology to artificial gas lift. Trials of the new solutions are currently taking place with a major oil operator who is providing support and access to its rig and multiphase test facilities.
The series of digitally operated valves enable the real time setting of injection rates and the extremely low power consumption ensures that all control signals are at low voltage. The technology can also be fitted straight into the tubing so it can be deployed far more flexibly – in fish-hook wells or where there are highly deviated sections. In this way, it can go where side mandrels cannot, as well as being superior in operation.
What the solution therefore achieves is to allow operators to vary injection rates in real time without wireline or slickline intervention, meaning no lost uptime, continuous production and reduced risk for operators. Figure 4 shows this comparison with the traditional side pocket mandrel.
As opposed to conventional gas lift, where operators have no knowledge of operating conditions at the point of injection, the live information allows operators to optimise extraction conditions, minimise gas usage across the reservoir, enhance oil recovery, and protect the wells from instability.
Taking into account the reduced cost of well interventions, the loss of production, wireline and slickline intervention incidents, and optimal usage of gas and associated compressor equipment, it should be possible to deliver an ROI of at least 20, and potentially increase recovery from individual wells by up to 30%.
The ability to alter conditions remotely and without intervention should have the capability to address the performance gap between topside and subsea wells. A digital artificial lift installation in a subsea well can have the downhole conditions remotely monitored, and injection conditions altered without the need to touch the wellhead. The result is a huge increase in operating flexibility.
This article has described just one element of a sustainable enhanced oil recovery strategy for the future. It is by embracing these new technologies that information gaps can be closed and recovery rates increased. Operators can also have more control of their subsea wells, and fields can become more economically viable. It is advances such as these that may lead to the future operators focusing on the long term development of resources. O T
References1. ‘EOR Enhanced Oil Recovery Worldwide’, SBI Reports, April 2010.2. www.rigzone.com.3. Inauguration of 2009 Middle East Artificial Lift Forum.
Determining operational and economic success in deepwater wells is
dependent upon shallow hazard mitigation. The industry’s first subsea drilling with casing (DwC™) system provides a unique solution to shallow hazards in deepwater drilling by expanding an already proven technology. Operators drilling in subsea environments can now effectively manage typical top-hole issues such as caverns, collapsed holes, fluid losses, ledges and rubble zones.
With testing complete and subsea operations at hand, the commercial introduction of Weatherford’s SeaLance™ DwC system is generating interest across global deepwater basins. The system enables a 20 in. casing string and its high pressure wellhead housing to be drilled to depth, cemented and released in a single run.
In doing so, the system extends the wellbore construction advantages of the DwC system to the physical and economic extremes of subsea operations. Because the system has the ability to drill through trouble zones, it offers significant value in costly deepwater applications.
The case in questionScott Beattie, Weatherford International Ltd, USA, looks at the benefits of a subsea drilling-with-casing system.
Figure 2. The SeaLance system extends the wellbore
construction advantages of the DwC system to the physical and economic extremes of
subsea operations.
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50 OILFIELD TECHNOLOGYApril 2011
In this environment, where the SeaLance system is aimed at mitigating multiple hazards in the upper portion of the well, the rewards include significantly reduced risk, improved efficiency and lowered costs.
Mitigating drilling hazardsAs the industry takes on increasingly challenging reserves, with most ‘easy’ prospects having already been drilled, the approach must be altered. At times, newer technologies must be deployed to minimise non-productive time (NPT) and make these reserves economically viable.
In areas where hole instability, loss zones or sloughing shales are a concern, DwC technology has been implemented to mitigate these problems that are expected with conventional methods. Having the casing constantly on bottom while drilling creates an environment where there is a mechanical smearing of cuttings against the wellbore by the large surface of the casing, thus reducing the previously
mentioned hazards.An estimated 10 – 40% of expenditures are still spent
drilling trouble zones. It has been proven, however, that trouble zones can be drilled, and sometimes avoided, if new drilling practices are used. To be successful, drilling hazards and associated potential risks must be understood.
Concept development The company entered a technology agreement with ENI in 2007 to collaborate on the development of a new deepwater technology with the unique capacity to mitigate shallow hazards. Such a technology would mean major improvements in the cost and capabilities for subsea drilling. It is a new mindset, a new way of doing things.
The project began as an endeavor to explore the idea of applying DwC in subsea application. Early development prospects for the system were supported by more than 1000 jobs and 10 years of DwC deployments in land, platform and other surface applications where performance has shown a 20 – 50% reduction in drilling time. But subsea operations offered significantly different demands on the technology.
Figure 1. The world’s first subsea DwC system mitigates shallow hazards in deepwater environments.
The process began with internal brainstorm sessions and consultations with ENI to pull the concept together. Continued collaboration and a significant investment in research and development greatly matured the design and brought it to the point of creating a prototype. The subsequent subsea solution the company produced is a promising multifaceted enabler for drilling deepwater prospects.
System components The system’s design draws on a diverse scope of resources. It combines proven DwC drill bit technology with an innovative running tool that enables deployment of the system below the rotary table for the first time and a retractable shoe joint (RSJ) adapted from the company’s cementing products.
The drillable casing bit is a proven technology frequently applied in land and shelf-type wells where a surface blowout
preventer (BOP) is used. This bit enables cement operations to begin almost immediately after bottomhole casing-setting depth is reached. Building a drive mechanism for the subsea system involved creation of a running tool.
This resulted in the first DwC system that can be deployed below the rotary table. Much like a liner hanger system, the tool locks into a dedicated setting sleeve below the wellhead, helps maintain casing tension and creates a torque path from the drillpipe through the casing to the bit. This process enables the entire string to be rotated to make the hole.
The RSJ enables the wellhead housing to be soft landed without rotation. This process is important because the hole must be drilled before the wellhead housing can be set.
With surface DwC systems, the hole is drilled to total depth (TD) with the casing and wellhead separate. Once on bottom, the string is pulled back and a joint or two of pipe is laid down. Then a joint with the wellhead is picked up, made up to the string, run and cemented.
In subsea operations, the same process does not work. The string would have to be pulled back to surface 1000 m
or more, and pulling casing out of the wellbore defeats a major reason for drilling with casing in the fi rst place.
To gain room at the bottom of the hole for landing the high pressure wellhead housing, the subsea DwC system required a means of drilling to TD and then somehow collapsing the string below the housing.
Applying the RSJ provided a starting point for approaching this obstacle. If fi ll or some other restriction is encountered a few feet from bottom, the RSJ can collapse a land without having to ream or disturb the sediment.
The outcome of these combined components extends beyond putting together a few widgets - it introduces a new way of drilling subsea wells that reduces risk and improves effi ciency. In deepwater drilling, the tendency is to apply the same methodology used in a conventional well - a very limiting approach.
Global deepwater solutions In 2010, the system’s trials were successfully completed in a test well at the Weatherford Technology & Training Centre in Houston, Texas, USA. Plans are now being made for trials in deep water.
Prospects range from the Gulf of Mexico to the South China Sea, and offshore Africa, Brazil and Australia. The scope is broad because every deepwater basin has potential applications.
Subsea advantages While changing the drilling methodology for subsea wells presents challenges, the system is already attracting attention
with some unique incentives and opportunities in the form of well integrity enhancements and cost savings.
While batch drilling may not be an instinctive technique in deepwater development, the system provides some strong new capabilities for achieving signifi cant savings. Combined with the advantages of shallow hazard mitigation, this approach is ideal for reducing the overall costs of subsea development programmes.
Shallow hazard mitigation capabilities cover several problems that have long vexed subsea drillers. These top-hole issues include caverns, collapsed holes, fl uid losses, gas and water fl ows, ledges and rubble zones. The system ensures the ability to land a long 20 in. string and have a better cement job as a result of being able to rotate it. By drilling, cementing and landing the high pressure wellhead housing in a single trip, NPT is reduced and the general integrity of the well is improved.
The system also promotes safer operations. By eliminating dangerous operational steps such as tripping pipe, personnel safety is enhanced. Since its design allows the surface casing and high pressure wellhead housing to rotate during subsea deployment, the system provides an inherently safer cement barrier, enhancing the foundation of the well.
Moving the DwC system into the subsea environment provides advantages in exploration and development applications. The new SeaLance system is designed for mitigation of shallow drilling hazards that signifi cantly reduce the risk and NPT to help control costs and enhance well integrity. The result is a new way of looking at deepwater operations and economics. O T
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FIGHTING
Kenneth Bhalla, Stress Engineering Services, USA, explains the importance of riser and subsea
fatigue damage monitoring.
A s offshore drilling and production facilities are pushed to operate in deeper waters, the equipment used in these facilities is exposed to harsher
environments. Moreover, as reservoirs with high pressure and temperatures are being developed, it is of the utmost importance that the integrity of each system used to drill and produce any field be maintained.
Given these concerns, accurate assessment of the present operating state and future life of equipment in these environments is essential for site safety and operation. Stress Engineering Services (SES) recently developed a data acquisition instrument - the subsea vibration data logger (SVDL), specifically to monitor dynamic structural response and fatigue in deepwater applications.
Providing assuranceVibration, and hence fatigue monitoring of drilling risers, completion risers, production risers, flowlines, jumpers,
manifolds and wellheads are critical and can provide assurance that ongoing and future operations can be performed safely.
Vibration can be in the form of wave-induced motions, vessel induced motions, vortex induced vibration (VIV), or flow induced vibration (FIV).
When performing drilling from mobile operating drilling units, such as semi-submersibles and drill ships, a wave fatigue assessment is performed by using requirements in API RP 16Q,1 which limits the significant dynamic stress range. In this case, no actual wave fatigue analysis is performed. VIV analysis or assessment may be performed to determine the damage rates on the drilling riser system from high currents; mitigation usually involves pulling more tension on the drilling riser or even utilising fairings.
Fatigue design and assessment for production risers are based on requirements in API RP 2RD,2 API RP 1111,3 and API RP 2A.4 Similarly, other API codes are utilised for the completion risers, wellhead, and subsea equipment.
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54 OILFIELD TECHNOLOGYApril 2011
A fatigue assessment is based on metocean data (wind, wave, current); statistical analysis is performed to determine annual and extreme events. However, if a location experiences an active storm, hurricane or loop current season; then it would be prudent to reassess the metocean data. If the metocean data is modified, then any previous fatigue assessment or design must be re-evaluated.
Additionally, fatigue design includes conservatism. Excessive conservatism can result in reduced operational windows and shorter service life, leading to increased operational costs and lost revenue.
Safe operationAdditional inspection costs can be mitigated by vibration monitoring and fatigue damage estimation from vibration measurements. Vibration measurement ensures safe operation by allowing monitoring of fatigue critical components, especially during inclement/extreme conditions, and allows rig crews to make prudent decisions based on actual fatigue damage estimates of a component. It is not sufficient just to take data using instrumentation. In addition, it is prudent to perform an analysis that predicts the expected mode shapes and fundamental frequencies of the system prior to deployment of the instrumentation. The instrumentation must be fit for purpose and packaged so that it will measure the expected/appropriate response without excess noise or offsets.
After deployment, proper data interpretation is a key component in understanding the quality of the collected data. Thorough data processing techniques and data quality checks have been developed by SES.
High quality dataSES has developed a number of accelerometer and strain gauge based tools to measure and assess fatigue damage. The SVDL is a new tool in the SES suites of solutions; it was developed to service the emerging need to collect high quality vibration data for extended periods under increasingly stringent subsea environments.
Housed inside the unit is a high quality tri-axial accelerometer. The accelerometer is constructed using a state-of-the-art MEMS process to achieve unprecedented sensitivity and resolution. Signals are passed through an aggressive low-pass analogue filter prior to being digitised by a high resolution analog-to-digital converter. In addition to signal filtering, oversampling techniques are employed to maintain the highest digitised signal quality. The long battery life, low power consumption, and large memory storage are well matched to maximise the deployed logging duration.
The data logger and clamping devices feature a low mass and high mechanical impedance structure. This ensures that the vibration signals collected by the logger are not distorted
Figure 2. Subsea manifold.
Figure 3. Modal deflection of a jumper system. Figure 4. Instrumented riser joint.
Figure 1. Subsea jumper.
by the mechanical characteristics of the logger system itself, even at high measurement frequencies of 50 Hz or greater.
Through a suitably designed clamping device, the SVDL may be mounted by an ROV to any structure of interest. Figure 6 shows an example of a low moment-of-inertia clamp developed for jumper pipe monitoring applications.
The data logger specifi cations include:
Sensors and electronics fully enclosed in a one-atmosphere aluminium subsea housing with redundant o-ring seals at each closure.
Depth rating: 10 000 ft seawater.
Exterior dimensions: 3.1 in dia. x 18.25 in. long (24 in. long including ROV handle).
Mass: less than 10 lbm.
Weight in seawater: less than 6 lbf.
All exposed aluminium surfaces hard-anodised.
Sensor is hard mounted to housing end cap to maximise coupling stiffness to measured structure.
Ported for nitrogen back-fi ll; includes pressure relief valve.
SES is in the process of developing a real-time fatigue monitoring system that will provide immediate assurance of operations; this system will be operational in autumn this year. O T
References1. API RP 16Q, ‘Recommended Practice
for Design, Selection, Operation and Maintenance of Marine Drilling Riser Systems’, 1st edition, November 1993.
2. API RP 2RD, ‘Design of Risers for Floating Production Systems (FPSs) and Tension-Leg Platforms (TLP)’, 1st edition, June 1998.
3. API RP 1111, ‘Design, Construction, Operation and maintenance of Offshore Hydrocarbon Pipelines’, 3rd edition, July 1999.
4. API RP 2A, ‘Recommended Practice for Planning, Designing and Constructing Fixed Offshore Platforms – Load and Resistance Factor Design’, 1st edition, July 1993.
Figure 5. Subsea vibration data logger.
Figure 6. SVDL data logger clamp.
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T here is little doubt that operators have a great deal to think about it when it comes to subsea operations today.
There is the remoteness and challenging conditions of the fi elds themselves – conditions that are often underlined by highly complex subsea production systems. The growth in popularity of smaller and older fi elds in the North Sea, which are often tied into existing infrastructure with long distance tiebacks, are one example of this increased complexity.
Other examples of challenging conditions include the deepwater fi elds of offshore Africa and Brazil with production and geological challenges, such as high pressure, high temperatures and sub-salt; the sour gas fi elds of the Middle East; and the rise in increasingly complex ownership structures with commingled streams and royalty allocations that must be measured by subsea systems.
Finally, there are the age-old threats to production and well control of water breakthrough, hydrates, sand erosion and corrosion – challenges that, if anything, are increasing.
Information and integration The level of investment in subsea operations over the last few years has been steadily increasing. Industry analysts Douglas Westwood forecast back in 2007 that US$ 25 billion will be spent annually in deepwater capital expenditure by 2012, with Africa accounting for 40%, North America 25% and South America 20%.
Great integrationsVincent Vieugue,
Emerson Process Management, Norway, explains the growing
need for greater integration and intelligence in subsea operations.
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58 OILFIELD TECHNOLOGYApril 2011
In terms of more specific subsea operations, Douglas Westwood predicted that more than 1000 additional multiphase meters – many of them subsea – will be deployed by 2015 and, in another report, that annual expenditure on ROV operations is likely to reach US$ 3.2 billion by 2014. According to one of the authors of the report, this is mainly down to ROV being “a more mature and advanced technology.”
While such levels of investment and recent technology advances should be encouraged, the sheer amount of data derived from subsea instrumentation has meant that some operators are reeling from the amounts of reservoir data that are produced. According to IBM Global Services, a single oil or gas field can generate up to one terabyte of data per day1 - data that must be collated, interpreted and used as input into further decision making.
And yet, while some levels of the reservoir are producing gigabytes of data, there are other important areas of the reservoir where the operators are quite literally ‘flying without instrumentation.’ For example, the detection of sand in the well stream is often based on approximations and guesswork around flow rates, pressure drops and temperature distributions.
There are also other areas of the subsea production system that are ‘no go’ areas to operators, once production is underway. One such example is the B annulus within the casing of an oil well, which is not accessible following the sealing and cementing of the casing.
Undetected high pressure behind the casing can lead to poor or deteriorating cement sealing and a loss of casing integrity which, in a worst case scenario, can result in oil or gas migrating vertically towards the surface and increasing the risk of a shallow blowout. To compensate for this, operators have spent millions of dollars shutting down wells, mainly due to their lack of information on pressures and inability to verify the barrier integrity.
Too often, the very technologies that are supposed to bring control to subsea production are viewed as commodities, procured in an ad hoc manner, and with no strategy as to where they fit in with other activities. Whether it is the downhole monitoring of wells, hydrate inhibition strategies, corrosion or sand erosion, or flow measurement, there is often a lack of integration across subsea production systems.
So how can we restore the balance and bring greater control to subsea production? How can we better manage the information that is created, yet ensure that there are no blind spots? And how can we ensure a more intelligent and integrated approach to subsea production?
While these may appear lofty ambitions, there is cause for optimism in areas such as hydrate control and corrosion monitoring, downhole monitoring, the management of information, and intelligent metering.
Hydrate control and corrosion monitoringHydrates – the crystals that are formed in high pressure and low temperature gas flows where water and natural gas are present –
are a significant obstacle to production control. They can cause blockages in tubing, flow lines or pipelines.
The rise in deepwater wet gas fields, with high pressures and temperatures and deposits, such as methane-based hydrate deposits in the Gulf of Mexico, also means that hydrates are on the rise.
The good news is that there are tools to combat hydrates, principally thermodynamic inhibitors such as methanol and ethylene glycol (MEG) and low dose hydrate inhibitors (LDHIs).
These inhibitors require a subsea system that tells the operator when the field is vulnerable - when there is a water production in the wet gas well, for example – and also provides an effective distribution system for their accurate injection. The latter is essential – LDHIs, for example, work at very low injection rates, whereas thermodynamic inhibitors tend to require higher injection rates and
concentrations. Get the dosage wrong and there is even a danger of increasing the likelihood of hydrate formation.
To this end, Emerson is paving the way for a greater integration between Roxar subsea multiphase and wet gas meters, which can detect the early onset of formation-water production in the gas flow, and injection valves, responsible for the flow and chemical dosage rates of hydrate inhibitors. The result is an integrated subsea production system and greater subsea control. Figure 1 shows a photo of the latest chemical injection valve.
There is also a need for greater integration of corrosion monitoring. Corrosion can lead to production losses, metal loss (which reduce the life of production and storage equipment), or safety and environmental setbacks, due to the corrosion of key infrastructure.
Today, Emerson’s corrosion monitoring activities, such as the company’s intrusive (probes and coupons installed with flow lines) and non-intrusive solutions (which are directly installed on the pipe walls) are also integrated with sand monitoring, pig detection and other downhole measurements instruments.
One example is Statoil’s Heidrun field on the Norwegian continental shelf, where, according
to the Norwegian Petroleum Directorate (NPD), “continuous efforts are being made to find new methods to increase oil recovery.”
The field makes extensive use of both intrusive corrosion probes and intrusive sand/erosion probes and also has a few locations with combined corrosion and sand/erosion probes. With a recent increase in sand production, Emerson has been working with Statoil to increase the field’s sand monitoring capabilities through a new sand management module. The module will allow Statoil to respond faster to changes in sand production conditions and establish maximum sand free production rates for production optimisation.
An intelligent downhole networkThese hydrate and corrosion monitoring solutions are part of an increase in predictive intelligence and integration across reservoir production monitoring.
Emerson’s Roxar downhole monitoring systems are now deployed in production, injection and observation wells, as well as
Figure 1. Roxar subsea chemical injection valve.
60 OILFIELD TECHNOLOGYApril 2011
in conjunction with the instrumentation of highly complex multi-zone intelligent wells.
Emerson’s intelligent downhole network, for example, allows operators to install 32 instruments on a single cable, with the network acting as a hub for downhole choke position indicators, additional third party sensors, and for the transmission of power and data. In this way, downhole reservoir monitoring can provide crucial information not only on temperature, pressure and water cut, but also gas fraction, sand rate, and flow velocity.
Multiphase meters are another example (Figure 2). Such meters are not only an effective alternative to well testing, providing critical real-time information on a well’s capabilities during production, but they can also have a significant impact on reservoir management across production operations. When integrated with gauges, sensors and other intelligent devices, the multiphase meter has the
Figure 2. Roxar third generation multiphase meter, the MPFM 2600.
Figure 3. A real-time multiphase measurement and subsea sensor system.
potential to become a critical component in measuring flow and production rates, and contributing to real-time decision making. Decisions such as choke setting and artificial lifts, for example, can then be based on all the necessary information.
Emerson recently installed its Roxar subsea multiphase meter on the Cascade and Chinook fields in the Gulf of Mexico. These meters will work alongside combined sand erosion and pressure and temperature sensor systems to provide the operator, Petrobras, with accurate and continuous online monitoring and valuable, real-time production information on the reservoir. Figure 3 shows an example of a real-time multiphase and subsea measurement system.
Improved information managementNo matter how well an operator integrates their instrumentation, they still need a system that not only brings all the information together, but also provides the necessary analysis tools to rigorously interpret that data.
With this goal in mind, Emerson has developed a Windows-based field monitoring system, which comes with a series of modules that cover many facets of operators’ subsea production systems, including flow assurance, sand and erosion, corrosion, simulation, production control, and virtual flow metering.
At the heart of the new system is a server that consists of algorithms and models for data validation, data conditioning, smart alarm handling and virtual instruments. Real-time sensor data is then fed and converted into visualisation tools for viewing and analysis.
The software provides an interface to all the instrumentation and the scalable architecture also allows remote connectivity, enabling multiple users to draw upon the same data and instruments. In this way, the operator can gain access to everything from individual data series from an instrument to complex expert guidance for choke settings.
The field monitoring system is also proving an important means of bringing greater intelligence to instrumentation. For example, through the self-diagnostics application within the field monitoring system, operators can configure flow meters, monitor status and alerts, troubleshoot from the control room, perform diagnostics, and manage calibration from a single application.
Another recent solution that has reached the testing stage, and which could be integrated into a field monitoring system in the future, is a wireless instrument that tracks pressure in the B annulus inside the well casing in subsea production wells. Through the field monitoring system, operators can track pressure, confront potential threats to well integrity, and ensure that no area of a subsea production system is a ‘no go’ area.
While this article has covered a number of different elements of the reservoir management and production process, there is one clear, overriding message – that there is a growing need for greater integration and intelligence in production operations.
It is encouraging that, while the subsea challenges continue to remain challenging, progress is indeed being made towards these goals, putting the operator where they should be – in even greater control of their production operations. O T
References1. ‘Meeting the Challenges of Today’s Oil & Gas Exploration and Production
Industry’, IBM Business Consulting Services.
Unbonded fl exible pipes with steel pressure and tensile reinforcement have been in operation for over 30 years but are facing serious challenges in deep
and ultra-deepwater as well as corrosive environments due to top tension limitations and corrosion fatigue. DeepFlex has developed a unique composite reinforced fl exible pipe technology that overcomes these issues and supports subsea developments as they move to more demanding environments. Testing and qualifi cation of an expanding operating envelope, in addition to proven fi eld performance, will address the future challenges of the industry. In offshore project developments, Flexible Fiber Reinforced Pipe (FFRP™) is a lightweight, composite reinforced solution that offers reduced risk, capital and operational costs.
A typical FFRP pipe structure includes the following pipe layers:
Liner: smooth bore conduit for conveying internal fluids. HDPE, PA 11, PA 12 or PVDF thermoplastic materials are employed for the liner, with the selection based on the application and temperature.
Anti-extrusion layer: prevents liner from deforming into gaps in the overlying non-interlocked hoop strength layer.
Hoop strength layer: provides internal pressure hoop resistance, external hydrostatic collapse resistance and resists radial compression installation loads. Either glass or carbon fi bre composite reinforcements are used for this layer, also selected based on the application and temperature.
Anti-wear layer: prevents wear of composite reinforcement due to contact/relative movement between adjacent layers. The innermost anti-wear layer may also provide a conduit for the fl ow of permeated gases to a vent at the end fi tting.
Membrane (intermediate sheath): prevents seawater intrusion into underlying layers, allowing the hoop strength layer to bear the external hydrostatic pressure. HDPE, PA 11 or PA 12 are employed for this layer, depending on the application and temperature.
Tensile reinforcement: provides tensile capacity; two layers wound in opposite helical directions assure torque balance. Either glass or carbon fi bre composite reinforcements are used for this layer.
Jacket (outer sheath): protects the FFRP™ structure against abrasion and mechanical damage. HDPE for static service and PA 11 or PA 12 for dynamic service.
Value propositionThe FFRP value proposition in the development of deep and ultra-deepwater harsh environments includes:
An enabling technology allowing more cost-effective development of deep and ultra-deep water oil and gas reserves. The composite fl exible pipe products offer the necessary resistance to both internal and external pressures, as well as the structural capacity to resist tension and bending in deep water. The pipe’s lightweight and high tensile strength combine to allow installation in water depths up to and beyond 3000 m. The reduced weight offers signifi cant project
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62 OILFIELD TECHNOLOGYApril 2011
savings for floating production systems including reduced cost of new build FPSOs, relocating shallow water FPSOs to deep water, disconnectable turret optimisation and low payload on existing deep water hubs allowing for more production within tension capacity limits.
Lowers installation costs and reduced project schedule risk. The FFRP™ provides a significant weight advantage over steel reinforced products. This weight advantage reduces the size and capacity of the equipment on the deck of the installation vessel, particularly the equipment known as ‘top tensioners’, which supports the weight of the pipe and controls its movement as it is lowered into the water. Larger top tension equipment requires larger installation vessels, which are fewer in number and have substantially higher operating costs. The lighter weight solutions allow for a greater number of potential installation vessels and a wider range of opportunities to secure a more cost-effective vessel at the required time. The greater number of vessels allows project flexibility and reduces schedule risk in the event of project delays.
Resistance to corrosion fatigue that reduces full life-cycle costs. Steel reinforced flexible pipe is susceptible to corrosion fatigue due to seawater ingress into the steel reinforcement layers especially when combined with the presence of H2S and CO2 that permeate through the inner thermoplastic layers. If the outer sheath of a steel reinforced flexible pipe is damaged in the splash zone, where cathodic protection is ineffective, the tensile armour reinforcement will corrode very rapidly, requiring rapid replacement of the pipe. With proper material selection, verified by comprehensive testing, the FFRP composite reinforcement is resistant to seawater and the annulus environment resulting from permeated gases condensing in the annulus, and can lower full life-cycle costs relative to competing steel-based pipe.
Technology developmentTechnology development is focused on the following three key areas to support the development and qualification of the FFRP for deep and ultra-deepwater offshore production environments:
Composite material development and testing.
Pipe structure qualification testing.
Model development and calibration.
Technology development is reviewed by an independent verification agency.
Composite material development and testing.
FFRP has been successfully deployed in applications where DeepFlex’s fiberglass reinforcement is qualified including low/moderate pressure and temperature applications. A comprehensive material testing programme is being executed to expand the operating envelope of materials for high pressure and high temperature. Fiberglass and carbon fibre composites are being tested to verify the characteristic resistance values, verify the partial safety factors used in the pipe design calculations, and address the potential failure modes and mechanisms based on the loads and environments that the material may be subject to over the FFRP service life. In order to develop the test plan to qualify these materials, DeepFlex used the following approach:
For each FFRP composite layer, load cases are identified. For each load case, the environment (fluid), temperature, loads, operating condition and layer stresses are determined.
Based on the previous point, and the guidelines in section 6 of DNV OS C501,1 and the layer geometry, construction and materials employed, define the potential failure modes and mechanisms that might be experienced as a result of those loads and environments.
Based on the previous point, and the guidelines in section 4 of DNV OS C501,1 define the tests needed to evaluate the material performance against the failure mechanisms.
Table 1. Planned test programme
Quantity of tests
Burst - straight 1
Burst - bent to minimum OBR 1
Axial tension with internal pressure 1
Collapse 5
Crush strength 5
Combined bending with tension 1
Bending stiffness 1
Torsional stiffness 1
Axial compression 2
Dynamic test - topside jumper loads 1
Dynamic test - FPSO catenary riser loads 1
Figure 2. The Urugua project.
Figure 1. The Afren Okoro Setu project.
OILFIELD TECHNOLOGYApril 2011
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Laboratory tests are performed on unidirectional composite strips and laminates, and on anti-extrusion tapes. The general approach is to:
Perform a variety of tests on unexposed samples.
Expose to fluids that are representative of fluids for offshore production for durations at design temperatures.
Test the exposed samples and analyse the results.
The analysis results are used to verify resistance of the composite reinforcement to potential failure modes, and update and validate the characteristic resistance and partial safety factors used in the design methodology, and fatigue data to be used in the service life analysis methodology.
Pipe structure qualification testingThe FFRP has been successfully deployed in shallow water operating environments and deepwater temporary applications. Qualification testing for these applications includes burst, collapse, tensile and bend tests. In addition, small-scale tests and mid-scale tests, which simulate the combined loading experienced in the critical anti-extrusion layer and hoop strength layer, are being conducted.
To expand DeepFlex’s operating envelope, a detailed qualification programme to API RP 17B2 is being executed to qualify deep and ultra-deepwater flowlines and risers for high temperature and high pressure applications. The programme will qualify the FFRP for 7 in. 5000 psi flowlines and riser in water depths of 2000 m and temperatures up to 90 ˚C. The testing programme is highlighted in Table 1.
Model development and calibrationPart of the overall qualification process for flexible pipes is the ability to accurately predict the mechanical and physical properties of the structure. These models are developed in-house and are calibrated by small scale, mid scale and full scale testing. Design methodology verification goals include:
The pipe performance and associated failure mode are predicted by the design methodology.
Potential failure modes based on expected in-service loads and environments are addressed in the design methodology.
Field deploymentsThe FFRP has been successfully deployed in all major offshore operating basins around the world. Some of the key applications are summarised in Table 2.
Two of the most demanding project deployments are the Afren Okoro Setu and Saipem Urugua projects. Some key elements of the projects follow:
Afren Okoro SetuFFRP risers have been successfully operating for over two and a half years in extreme dynamic service on the Afren Okoro Setu project offshore Nigeria. The field architecture for Okoro Setu
includes a well head platform connected to an FPSO with DeepFlex product.
The 4, 6 and 8 in. internal diameter dynamic risers connected to the FPSO are operating in a double wave riser configuration in a water depth of 19 m. Production at Okoro Setu has averaged 17 841 bpd and total gross cumulative production from the field (since start-up) at 30 June 2010 is 11.4 million bbls. During this period, a process uptime of 99.6% has been maintained, reflecting the excellent operational efficiency of the flowlines and risers.
Saipem, UruguaThe Urugua project included the successful deployment by Saipem of a downline solution for the commissioning of an export pipeline offshore Brazil. The FFRP delivered to Saipem was used in the commissioning of the 174 km, 18 in. Urugua export pipeline 160 km off Brazil in the Santos basin.
The FFRP downline offered a unique lightweight solution for this challenging deepwater commissioning project by lowering deployment costs and reducing operational risk. The 3 in. internal diameter downline was deployed in 1500 m of water by one of Saipem’s installation vessels, the Norman Cutter. The downline was connected to a subsea commissioning structure for over 40 days and operated successfully in very challenging weather conditions including seas of 5 – 7 m.
ConclusionThe FFRP solution offers substantial value for deep and ultra-deepwater environments. The light weight and corrosion resistance of DeepFlex pipe offers project and operational cost savings. The product has been proven in demanding field conditions and a comprehensive material and full scale test programme is ongoing to expand the operating envelope. The product offers a new tool to the design kit of subsea engineers to meet the challenges of deep and ultra-deep water offshore field development. O T
References1. DNV OS C501, Composite Components.2. API RP 17B, Recommended Practice for Flexible Pipe.
Table 2. DeepFlex projects
Project name Customer Deployment region
Pipe size (in.)
Design pressure (psi)
Water depth (m)
Deployment year
Petronius Chevron Gulf of Mexico 4 5000 N/A 2006
Bourbon Opale Maritima de Ecologia SA
Bay of Campeche
3 5000 N/A 2006
Genesis Chevron Gulf of Mexico 2 5000 N/A 2007
Mardi Gras BP Gulf of Mexico 2 5000 800 2007
Okoro Afren Nigeria 4 5000 14 2008
Okoro Afren Nigeria 6 5000 14 2008
Okoro Afren Nigeria 8 5000 14 2008
Arthit EMAS Thailand 8 2500 80 2008
Lyell CNR North Sea 4 5000 146 2008
Aries Swan Workover Vessel
Crossmar Mexico 4 5000 150 2008
J Ray McDermott Petro SA South Africa 4 1250 120 2008
Urugua Saipem Brazil 3 2900 1500 2009
Genesis Chevron Gulf of Mexico 2 4000 N/A 2010
PRECOMMISSIONINGCHECKLIST FOR
Figure 2. The precommissioning team is vital to maintaining project schedule.
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Effective precommissioning (PC) planning and initiation of PC activities provide a necessary bridge between earlier project
execution phases, including mechanical completion, and the final commissioning and startup of the facility. PC can be an essential mark between the transition from a discipline-based approach, to one that verifies the functionality of systems, regardless of their location on the facility. The planning required for an efficient PC of an offshore facility is typically started during the early stages of detail design and commences immediately after mechanical completion (MC) has been achieved, which itself follows the engineering design and construction phases.
Prior to initiating the PC actual work stage, the supervisor of the MC phase creates a formal document transferring the complete dossier of all activity of the system for handover to the PC team, along with a register or punchlist that indicates any remaining MC work that still needs to be completed or closed out.
Systems drivenWhereas mechanical completion includes the non-functional testing of equipment to confirm the integrity of its fabrication and installation to the intended design, PC verifies the mechanical completion, the functionality of the system as well as calibration of the instrumentation to the facilities’ controls and control systems.
Richard Shirley and Dan Vela, Mustang Engineering, USA, run
through the process of precommissioning offshore facilities.
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66 OILFIELD TECHNOLOGYApril 2011
While MC is completed by area or discipline, the PC phase will be turned over to specialists who can address confirmation by system, ensuring that it is complete and ready for final commissioning and startup. This phase can best commence efficiently after all of the components are in place so that systems, rather than individual pieces, can be verified. The PC contractor also engages the design engineering firm, vendors, manufacturers and operating personnel for support and their expertise. During the PC effort, there can be many activities completed during the onshore phase and then moved offshore for completion of the system checkout. Where practical, piping should be power flushed and dried; communication systems tested to the fullest extent possible; instrument and electrical loops will be verified; instruments will undergo initial and final calibration; pumps can be operated where possible; motors verified for proper rotation and can be run and tested (burned in); and rotating equipment can receive initial (cold) alignments.
The PC phase is vital to schedule adherence of the project and a necessity in helping to minimise cost overruns. Ideally, PC activities should be planned as part of the construction and earlier project execution strategy so there can be a smooth transition from structural, mechanical, electrical, instrumentation and controls fabrication to systems checks where scheduled work is maximised. This point in the project is when potential flaws of construction, uncompleted tasks and system inadequacies can come to light and be addressed early enough to minimise schedule delays. Without a thorough PC effort,
potentially time-consuming and expensive modifications can go undone onshore, only to be addressed in a much more difficult offshore environment.
Organisation and planning are keyThe selection of a PC team is one of the most important milestones that will need to be addressed. The team will be responsible for planning and supplying the critical support and leadership during this project phase. The leadership, as well as team members, should, therefore, be experienced with the planning, tasks, schedule and project drivers regarding startup, as well as its complexities.
After the project has determined the scope of work, the overall project schedule and startup drivers, an organisation chart needs to be established, defining the overall hierarchy of how the PC team fits within the overall project management team. Additionally, a roles and responsibilities matrix required for the upcoming activities should be established. There will need to be separate designators in organisational charts created indicating location for the onshore and offshore PC work due to potential differences in contractual arrangements, transportation, personnel housing, parts availability and numerous other issues. Only after the scope of work and organisational plan is in place can the initial schedule be prepared, establishing the critical milestones for handing off systems to the commissioning and operations teams. These milestones are often how the PC team and their progress will be measured.
The responsibility matrix is important to complement the organisation definitions. The level of the matrices vary from broad to detailed, but its main use is to identify not only the scope of work and supply, but also the responsibility and simultaneous operations (SIMOPs) that may occur. For the purpose of this discussion, getting to the matrix level of PC and MC interface, along with the other SIMOPs is wise early enough to best identify any potential holes during the different phases of work. As discussed previously, identifying the location of the PC work plays an important role in the responsibility of certain activities and interfaces. For example, due to contractual limitations as well as schedule drivers, the onshore MC work will take priority and the facility where the work is being performed would be the driver. Whereas offshore the MC work may still be the priority, the driver would be the operator. The matrix, therefore, can identify not only the task, but the responsibility of the work, whereas the details of the work are identified within the PC procedures and tracking database.
In the initial planning of the PC stage, a critical path should be evaluated to establish the procedures that will be optimal to success. Although the best laid plans always have their obstacles, a plan must be established as a starting point. A detailed list of required activities would be created by the PC team and coupled with the data developed earlier in the project by engineering and managed through an electronic project information management system. The PC contractor is responsible for maintaining the database, tracking progress critical for adhering to schedule and determining the status of the various activities.
Reference data provided by engineering and the other delivery teams will need to be organised by the PC contractor according to the identified systems and should reside in a location accessible to all who will be utilising it. Data includes, but is not limited to, PFDs, P&IDs, mechanical, electrical motor
Figure 3. Deck space and personnel management are critical parts of offshore PC activities.
Figure 1. Precommissioning addresses readiness by system rather than by individual pieces of equipment.
68 OILFIELD TECHNOLOGYApril 2011
and ISA data sheets, instrument and electrical loop drawings, wiring plans and elevations for skids and modules, as well as the manufacturer’s final data manuals for purchased equipment. A potential shortcoming is in not obtaining the interface data from outside of the topsides delivery team, e.g. subsea, export pipeline, communications, hull fabricators equipment. The key will be to provide a conscious effort to close these gaps early within the project so as not to impact the planned startup date.
The PC work normally is broken down into discreet, manageable systems. The systems are separated according to the logical process flow, rather than by a package vendor. For example, a heat media system might include a fired unit, heat recovery unit, storage unit and pumps, along with interconnect piping, instrumentation, controls and electrical, all of which have likely been supplied by different vendors and reside on separate skids. This systems breakdown is the logical process to verify construction, confirm the integrity of the design, and prepare the system for handover to operations as the phase goes forward. The organisation also allows for the commissioning of sub-systems within a system, without having to initiate work on the entire system. This avoids having to work around a finish to start on a system scenario, thus pushing the overall startup schedule past the desired outcome. The PC of utility systems is typically the first to be addressed and completed. This allows life support for the offshore personnel in addition to minimising the need for additional components to PC the process systems later.
It is essential that good record keeping and a detailed preventative maintenance plan be initiated and carried out through handover to operations during the PC phase. A job or activity card system is an output of the existing database system, resulting as an archive to the work performed as an as-built record. Task sheets record the subsystems and systems, which have been completely precommissioned and ready for handover to be integrated into the facilities operating systems.
In the overall PC work plan and prior to initiating the PC work, a meeting schedule should be established so that overall planning and progress can be regularly discussed and understood by all parties. Each of the participants should have a schedule that can be owned by them, reviewed intermittently
by the team and adjusted accordingly, so that progress coincides among all team members. The critical path should be reviewed at least weekly and recovery plans generated or updated as necessary.
POB managementAn important consideration in precommissioning is planning for the required number of personnel needed to undertake the offshore PC activities, the transportation requirements for the crews and their supplies, and the allocated personnel onboard (POB) space to accommodate them. While working during the onshore phase space is somewhat unlimited with the exception of interfaces with construction, offshore work presents a whole different set of challenges. Offshore, the PC team will have to work closely with all of the different work scopes onboard to understand each other’s schedules and manpower requirements. These would include topsides hookup and commissioning
(HUC), subsea flowline installation and testing contractors, and the export pipeline installation and testing contractors, as well as third party vendors, communications personnel and operations. During the offshore phase, depending upon timing and the hull type, a habitability inspection will be conducted by the US Coast Guard or similar regulatory body. The work plan will include in the overall schedule identifying work onshore, work offshore, work to achieve quarters habitation, Temporary Certificate of Inspection (TCOI), Final Certificate of Inspection (COI), and Handover to Operations. A variety of systems must be carefully planned for and put in place in order for approval of these various milestones. For TCOI these may include sufficient living quarters; temporary power generation; fire fighting, fire detection and suppression equipment; emergency evacuation equipment; potable water and sewage treatment provisions; and communications equipment. Planning for and precisely scheduling manpower is critical. If sufficient facilities are not available on the platform, ‘floatels’ or other means for housing personnel might be required at a significant extra cost. The critical nature of the work being performed offshore compared with the other activities along with the schedule must be evaluated in depth to determine the cost/schedule benefit and work plan for utilising a floatel. This also means weather limitations and transfer of personnel risks must be evaluated. Similarly, working space and delivery areas must be closely planned to accommodate the simultaneous operations (SIMOPS) being conducted during the precommissioning and subsequent commissioning operations.
ConclusionIn order for the PC segment to be successful, a good and detailed precommissioning/commissioning plan should be developed as early in the project as possible and good interface between all groups must be established. An experienced team, equipped with the necessary tools, database, organisational structure, defined responsibilities and procedures, can assure that the precommissioning segment is efficient and can keep costs and schedule in-line with expectations. O T
Figure 4. Successful PC work relies on detailed planning and defined responsibilities.
Jon Robertson, Saab Seaeye, UK, looks at the benefits of electric ROVs in comparison with hydraulic vehicles.
Smarter and more powerful electric ROVs are increasingly taking on the work of hydraulic vehicles. They bring significant savings to the oil and gas industry because they cost less,
require less deck space, fewer crew, are easier to use, and quicker to deploy. Driving this development are significant breakthroughs in electric ROV technology - power has been boosted, and control and redundancy have been enhanced. This means more power intensive tasks can be tackled because power is cleverly divided between thrusters and tooling, without loss of power to either. This is an advantage over hydraulic vehicles that can typically only use one or other at full power, but not both.
More power means that a new generation of electric ROVs has, for instance, enough tooling power to run a Merlin excavator on maximum load, while still operating its thrusters at full force, keeping the vehicle steady while driving it along.
For such a cable-laying dredging task, an operator would typically need a 150 HP hydraulic ROV that would take up twice the deck space.
A doubling of thruster power on top of the range electric vehicles means that the newest generation of vehicles are serious competitors to the hydraulic ROV systems and they can also operate to depths greater than 6000 m.
Power mythAll this contests the myth that only 100 HP and above hydraulic vehicles have the power for work class operations, whereas the truth is that the power rating relates only to the shaft power of the prime mover, not the power available to both thrusters and tooling, and so useful power is overstated on a hydraulic vehicle when compared with an electric vehicle.
Hydraulic propulsion is also very inefficient as the electrical power delivered to the hydraulic ROV needs converting
through a three phase electric motor to hydraulic power, then back to rotary power before turning the propellers – a process that loses over 30% of shaft power. Power in electric ROVs is not shared and is therefore available in full to thrusters and tooling at all times. The use of high efficiency brushless DC motor technology also means there is no significant loss in the transfer of electrical power to thrust.
The hydraulic vehicle also needs more power to counteract its high mass, and the higher drag on its meatier tether.
PerformanceWith a lift capacity of 240 kg, an electric work ROV can do all the tasks of 100 or 125 HP hydraulic, except heavy construction, although it can still play a valuable support role during such work.
Routinely, tasks carried out by electric work ROVs may include: hot stab connection and disconnection, dual point docking and free flying stab-plate connection, pre and post drilling site survey, guidance and orientation for BOP and riser connection, depth and orientation of wellhead and BOP stack, cleaning wellhead and bulls eyes, and changing out AX wellhead gaskets. It is ideal for IRM as access is easier; and for survey work, results can be more accurate when compared to using an acoustically noisy hydraulic work vehicle.
Switching to electric
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70 OILFIELD TECHNOLOGYApril 2011
Resident power and intelligent control means that the electric ROV can be fitted out with a host of tools and systems. These include a seven function position feedback manipulator and heavy duty five function grabber, a fluid injection skid, hydraulic hot stab, linear actuator override tool, quad actuator tool, torque tool, flying lead orientation tool, AX/VX ring change out tool, single or dual point TDU,
Figure 2. Thruster touchscreen page. An interface for control, configuration, statistics and diagnostics of a thruster. Statistical and diagnostic information is accessible remotely.
Figure 3. Primary flight screen. Gives the pilot feedback on navigation, auto-pilots, primary sub-systems and any critical errors or faults.
Figure 1. Smart and powerful electric work ROVs like the Saab Seaeye Jaguar are taking on the work of hydraulic vehicles.
6 in. rotary or 4 in. anvil cutter, HP water jet or cleaning brush tools, zip jet suction tool, along with custom tooling as required.
ReliabilityWhen comparing electric and hydraulic ROVs, reliability is a key issue: there is less to go wrong with electric. Typically, the top end electric ROVs also have dual redundancy systems. This means the whole system is duplicated and should one complete system fail, it is backed up by a second complete system, meaning the ROV can be kept working, and recovered safely afterwards. Self-diagnostics clearly display to the pilot any fault and the necessary remedial action to be taken.
Thinking for itselfIt is possible to configure intelligent electronic devices such that they can be interrogated remotely over the internet. This concept has been added to the latest fully distributed control system for electric vehicles, branded Intelligent Control of Nodes (ICON) by engineers at Saab Seaeye.
ICON allows each device within an ROV to think for itself and talk remotely to operators and engineers through a gateway into the heart of the vehicle. It means that through an enabled remote web interface, operators across the world can manage diagnostics, software upgrades and system inventory directly onboard the ROV wherever it is located. Engineers can also remotely interrogate devices onboard, and help the ROV operator resolve configuration issues in live time.
BuddyingElectric and hydraulic ROVs are not mutually exclusive. Each has a role to play and they often work together. In particular, a growing trend is to buddy a smaller electric ROV with a heavyweight work ROV. An operator can use the nippier electric ROV to swim about to give a clear view of the back and sides of the working area, adding to the safe and efficient completion of the task in hand. Additionally, it can act as a standby, low-cost resource, ready to help recover the work ROV should it get into trouble. It can guide a recovery strop, or untangle a snagged umbilical, and possibly complete or contain an interrupted task while the stricken ROV is repaired. This could bring considerable savings in time and cost by avoiding the need to outsource an expensive ROV/vessel for recovery of the hydraulic vehicle or completion of the task.
As a bonus, the operator gets a small yet powerful and intelligent resource that can also be used for a variety of other tasks including observation, manipulation, cleaning, inspection, mapping, profiling and monitoring.
Launch and recoverySafe launch and recovery of the ROV in various sea-states is vital during operations. Also, it is essential that under the waves, equipment does not get tangled up. This is especially true when the ROV is operating from a tether management system (TMS) and other ROVs are sharing the same patch of seawater. The current can cause problems: it can drift the TMS about until, when the ROV is due to return to the TMS, everything is the wrong way round. This problem has been solved by fitting the TMS with its own thrusters, along with a management system that controls the position of the TMS and also ensures it remains orientated to the ROV as it flies about its task.
A significant benefit is that multiple ROV systems can be launched from a single vessel without the fear of entanglement.
Vital roleThe vital role that electric ROVs now play in the industry means that growing operational demands will continue to extend their capability through innovation and increasingly intelligent power resources. O T
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ELIMINATING THE GAPS IN
Jogen Bhalla (USA) and Stephen Gale (UK), AMOT, and Ian Harrison, Pyroban, UK, highlight the importance of ignition source elimination and the differences in approach across the world.
H igh levels of uncertainty require larger margins of safety. The potential combinations of fuel-hydrocarbons, oxygen-air, and energy-ignition are
highly complex, making exact predictions of what is safe and unsafe, difficult and often impractical. The science needed to prove conclusively if combinations near explosive limits will be safe is not yet available.
The elimination of ignition sources is a well-known strategy to protect people, investments and the environment from fire and explosions because without the energy to ignite flammable gases, a hydrocarbon release (HCR) incident is far less likely to develop into a catastrophic failure situation.
This is not to say that ignition source elimination strategies should act alone. Indeed, elimination of ignition sources must form part of an overall safety strategy, which would also include gas detection, emergency shutdown protocols and evacuation strategies.
The objective of this article is to highlight the importance of ignition source elimination and the differences in approach mandated by law in different jurisdictions around the world.
The physics of how an explosion or fire is initiated cannot be disputed: simply put, fuel + oxygen + sufficient energy will lead to a fire. The elimination of the energy (ignition source) can avoid a serious hydrocarbon release becoming a fire and explosion. Current proven technologies can greatly reduce this risk. These technologies have been employed by leading oil and major companies outside the US both onshore and offshore for decades, but no effort has been initiated within the US.
Every organisation involved in the upstream oil and gas industry is responsible for ensuring its knowledge of and adherence to the most current applicable regulations and standards, wherever it conducts operations. Regulatory compliance, however, only represents a starting point for improved safety regarding fires and explosions. The real requirement is for a constructive means of ensuring that practical improvements and preventative measures are adopted.
Following the events of the Deepwater Horizon catastrophe, the oil and gas industry, particularly within the
US OFFSHORE REGULATIONS
73
74 OILFIELD TECHNOLOGYApril 2011
US, must evaluate its current principles, processes, policies and practices and determine how they can be improved.
Deepwater Horizon accident investigation hearings clearly indicated that a catastrophic loss of containment leading to a large hydrocarbon release was likely to have been ignited by the primary diesel generators located on the platform.
The elimination of ignition sources is a well known approach used in an overall safety strategy to protect people, investments and the environment from fire and explosions offshore. However,
where the approach should be applied on an oil platform and what type of equipment requires protection varies significantly dependent on geographical location, country, the oil company or even the oil platform.
Current practices for the determination of hazardous areas offshore Strategies to reduce hydrocarbon releases have been applied admirably throughout the world for the last 15 - 20 years with some effective results; however, the reality within the oil and gas industry is that significant releases still occur.
Area classification is applied to offshore platforms to determine the probability of an explosive atmosphere developing from hydrocarbon releases (i.e. determining hazardous area zones (IEC) and divisions (US)) and consequently where explosion proof equipment requires installing. Areas outside of these zones are defined as ‘non-hazardous’, while classifications in the US and rest of the world differ in terminology (Table 1), as does the definition of what equipment is deemed necessary to provide protection, the fundamental principles of classification remain very similar.
The main limitation of area classification is the general exclusion of the type of event that occurred on the Deepwater Horizon, as it is considered a catastrophic, unforeseeable or unpredictable release.
These kind of low probabilities and high consequence events in many cases have the potential to propagate the migration of flammable gases and vapours beyond classified areas where ignition sources are not controlled, hence the potential for ignition is high; a particular concern in these circumstances is the continued operation of internal combustion engines. In these circumstances, many jurisdictions, particularly Europe, employ legislation to implement platform fire and explosion risk management strategy. This determines the required level of active and/or passive protection to ensure equipment does not present an ignition hazard. However, the US federal regulations and associated enforcement agencies have not demonstrated the commitment to cover offshore platform safety in these situations.
Differences in standards of equipmentThroughout the world, the types of equipment requiring ignition protection within hazardous areas can vary from country to country. Explosion protection regulations and standards in the US are very similar to European equivalents for electrical installations but largely ignore risks associated with non-electrical ignition sources. Thus, in Europe and other parts of the world:
Both electrical and non-electrical equipment must be considered.
The principle of ignition risk assessment of equipment within a legislative framework rather than compliance with standards allows best available technology and processes to be applied to equipment, providing ‘safer ‘solutions for industry.
Differences in the standards can be further clarified by focusing on the standard of ignition hazard protected diesel engines in the US, compared to the standard provided in many other locations throughout the world.
Typical European installationCurrently within the US Federal Regulations, explosion protected equipment standards and particularly major incident fire and
Table 2. Ignition hazard protected diesel engine requirements
Typical US
Typical European (EN 1834-1)
X Exhaust flame traps Exhaust flame traps
X Exhaust spark arrester Exhaust spark arrester
X Exhaust temperature monitoring
Exhaust temperature monitoring
X Exhaust gas cooler Exhaust gas cooler
X Water-cooled turbo charger
Water-cooled turbo charger
X Coolant temperature monitoring
Coolant temperature monitoring
X Water-cooled exhaust manifold
Water-cooled exhaust manifold
X Explosion protected electrical components
Explosion protected electrical components
Engine overspeed monitoring and shutdown
Engine overspeed monitoring and auto-shutdown
X Anti-static fans, blades and belts
Anti-static fans blades and belts
X Explosion proof inlet manifold
Explosion proof inlet manifold
X Inlet flame arrester Inlet flame arrester
Inlet shutdown valve Inlet shutdown valve
Table 1. Area classification
US IEC/EN
Division 1 Zone 0 high probability of an explosive atmosphere
Zone 1
Division 2 Zone 2 lower probability of an explosive atmosphere
Figure 1. Reduced ignition sources on a typical European installation.
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76 OILFIELD TECHNOLOGYApril 2011
explosion risk management strategy falls considerably behind Europe and many other oil producing countries around the world.
Diesel engines located in a non-hazardous area are thought to be the likely ignition source for the explosion(s) onboard the Deepwater Horizon platform. An uncontrolled engine overspeed was reported just before the explosion in the generator room.
Internal combustion engine protection for hazardous area applications in the US does not afford the same level of protection as other best available technology standards applied throughout Europe, and many other locations throughout the world. Current EU regulations (EN 1834-1) require automatic engine overspeed shutdown protection for maximum safety in all offshore areas and other defined hazardous zones.
For the US offshore regulations, several standards were written around 1988 and are still in current use, to cover modification of diesel engine air intakes under the following MMS (now BOEMRE) sections of 30 CFR Ch II;
250.405: for engines on drilling rigs (2/20/03).
250.510: for engines on well completion platforms (9/14/09).
250.610: for engines on well-work over structures (5/29/98).
A study of current US offshore regulations250.405 regulation states that: “you must equip each diesel engine with an air intake device to shut down the diesel
engine in the event of runaway; (a) for a diesel engine that is not continuously manned, you must equip the engine with an automatic shutdown device.”
However, some gaps exist in this regulation: almost all engines on a platform or rig are ‘not continuously manned’, so for improved safety, all engines on an offshore platform should be classified this way.
Paragraph (b) states: “for a diesel engine that is continuously manned, you may equip the engine with either an automatic or remote manual air intake shutdown device.”
The limitations of this part of the regulation include:
The decision as to what equipment is ‘continuously manned’ is open to various interpretations, resulting in machines such as diesel welders being fitted with manual valves, where the welder operator could be working on a different deck or at considerable distance from the stop control.
Any manual method of stopping an engine that is accelerating towards destruction is inherently unreliable, as it completely relies on a nearby operator to decide that when they hear the ‘racing’ of the engine, they should approach it and push or pull a control. Esso Research rejected that option in 1970 due to the unpredictable result.
US Federal offshore regulators fail to recognise that a runaway diesel engine, depending on the richness of the environment, can explode within 30 seconds and so manual shutdown is not a safe solution.
Human nature for machinery operators would be to run away from the runaway engine to reduce their risk of death or personal injury due to imminent engine explosion.
Unlike ATEX, the US does not have an agency to test and approve products for the offshore industry. As such, contractors and rental companies usually select the least expensive solution for the diesel engine overspeed shutdown system and spark arrestors, and this further compromises safety. It is disturbing to see plastic slide type valves (as used for fish tanks or RV toilet pipes) have been installed and apparently, up until now, accepted by the US offshore inspectors (Figure 2).
RecommendationAll of these high risk situations that come from permitting manual devices would be quickly eliminated if the existing US offshore regulations were amended to require the benefit of automatic shutdown.
The US offshore regulators should immediately issue a safety alert that states:
“All diesel engines operating on the offshore platforms must have an approved air intake device to automatically shut down the diesel engine in the event of runaway. Manual devices are no longer permitted and must be removed and replaced with automatic shutdown system.”
“A remote control must be fitted to allow demonstration of the device in a running condition without over-speeding the engine. Operators are required to check the safe function of the shutdown system once a month.”
The lessons of the Deepwater Horizon accident investigation show that a runaway diesel engine is not only an ignition source, but a potential detonation source and can occur at low concentrations of gas. Existing US offshore standards for diesel engines are now outdated and are subject to misinterpretation. It would be a relatively simple and low cost process for companies supplying equipment to the US offshore oil and gas industry to
Figure 2. Engine with manual plastic slide valve (push to close) currently permitted in the US.
Figure 3. US-made spark arrestor test.
OILFIELD TECHNOLOGYApril 2011
77
upgrade their equipment to meet the proposed revisions.
The resultant step change in engine safety would be seen as the first step towards effectively eliminating the potential source of ignition that currently exists.
Diesel engine exhaust spark arrestorsAll diesel engines emit dangerous sparks produced by the combustion process or the ignition of carbon buildup within the exhaust system.
The technology of spark arrestors was originally developed for agriculture and forestry, adopted by the military and more recently by the petrochemical sectors, with various different designs such as screens, collection traps and cyclones available. However, the requirements and test procedures for the different products and the different requirements of different industries mean that not all products are suitable for the more severe applications. For example, the oil and gas industry recognised that when there was a gas concentration exceeding the lower explosive limit (LEL) a single low energy spark could detonate a gas cloud, whereas the forestry industry is concerned with larger higher energy sparks.
Over time, various organisations such as the US Forestry Service, OCMA, British Standards and later the European ATEX Directives, were developed with test procedures to determine the acceptable methods that would quench all sparks and cool them to be ejected at a safe size and energy state.
While some equipment currently working in US offshore waters has been fitted with spark arresters, these have usually been of the agricultural variety. Recent tests of one of the most popular types currently used (Figure 3) have revealed that not all sparks are cooled adequately before totally safe emission in an offshore environment where hydrocarbons are easily ignited.
To achieve elimination of exhaust sparks, the current rules for engines must be amended to state that diesel engine exhaust systems must be fitted with a spark arrestor designed and tested to emit no sparks during engine operation. Products certified as approved for international hazardous zones, including zone 2, should be allowed. The spark arrestor must be inspected monthly and replaced if any perforation of the body is detected.
Equipment with spark arrestors that do not meet this requirement should be removed or replaced as they are a safety hazard and can cause fire or explosion.
Exhaust sparks can be eliminated though the addition of an effective spark arrestor that will not perforate due to corrosion. It is relatively simple for engines working offshore to have this addition to remove this dangerous condition. Stainless steel cyclone type spark arrestors (Figure 4) are effective in preventing both sparks and corrosion.
Figure 4. Cyclone spark arrestor with certifications.
International variations Classified areas determine what level of ignition-protected equipment is required within these areas. Throughout the world, the types of equipment requiring protection can vary from country to country. Historically within the US, only electrical equipment and some specific products currently require protection under existing standards.
This approach within the US promotes misunderstanding and confusion with respect to what type and standard of equipment requires protection, or even whether equipment requires protection at all. Diesel engines offshore fall into this category and protection requirements are further confused due to the requirement being defined by location on the platform not by the probability of the engine coming into contact with an explosive atmosphere.
By contrast, within Europe and many other parts of world, particular emphasis is placed on the ignition risk assessment of the equipment covering
both electrical and non-electrical ignition sources. This approach is supported by product specific standards for high ignition hazard equipment. Diesel engines are covered by EN 1834-1, which is applied offshore throughout Europe and many locations throughout the world. No such approach or standard is applied to diesel engines offshore in the US.
Major hazard events, such as the hydrocarbon releases that occurred on the Deepwater Horizon, are considered throughout Europe by integrated fire and explosion risk management strategies. This may determine equipment such as diesel engines located outside of a classified area requiring ignition hazard protection to reduce the risk of a major release being ignited, therefore reducing the potential consequences of an incident. This approach has been mandated through European offshore legislation.
While US regulators have moved towards an approach with safety and environmental management systems (SEMS), which addresses lessons learned from previous events, there still appears to be a significant void with respect to the rigor afforded to European installations. These variations in international standards and approach cause confusion, particularly in the US, to the extent that platform safety is compromised; the standard of ignition protection related to diesel engines is a clear example of this. Best available technology for these products is known and well understood and applied throughout Europe and many locations throughout the world, yet they are rarely applied to US offshore installations.
This situation provides a need and opportunity for collaboration between US regulators and the oil and gas industry to create a globally accepted standard for these products. Then, through strong regulation and enforcement ensure the requirement is implemented to reduce the ongoing risks of such events as the Deepwater Horizon catastrophe ever occurring again. O T
78 OILFIELD TECHNOLOGYApril 2011
news
// Kudu Pumps // Making progression possibleO T
company news
Kudu, like many other service companies, has felt the brute force of the oil industry’s ups and downs. After all, how many companies get a national award and
then face insolvency in the same month? Kudu found itself in this position in early 1998 after the crash in oil price.
It is one of those Alberta entrepreneurial success stories that everybody loves. Two decades ago, a father and son team of gear-heads, Robert and Ray Mills, took Progressing Cavity Pumps for the oil patch from a residential garage in Calgary, Alberta, Canada, to the world’s second largest PCP manufacturer and distributor.
Robert started investigating PCP in the late 1970s and patented a novel PCP drive system in 1982. He was a pioneer in using PCP technology in sand laden heavy oil wells and high water cut (95% +) oil wells. His first install was in the first horizontal oil well in Wabasca, Alberta, Canada during a blizzard in 1988 for CS Resources. “They were going through a conventional pump jack per week due to
PCP systems are engineered to handle light to heavy oil, coalbed methane and de-watering applications.
high sand cut,” Robert says, whose PCP install ended up lasting over 12 years.
The Mills’ next hurdle was distribution. Initially an oil company could only purchase a PCP through a supply store. These supply stores refused to sell Kudu products so Robert and Ray ended up selling directly to the customer, which was unheard of at the time. “We were told it would never work,” says Ray. The Mills’ started peddling their wares and ended up redefining how PCPs were distributed in Canada.
Selling direct to the customer had another advantage; Robert and Ray learned first hand the challenges their customers were facing pumping oil. This led to Kudu heavily investing in developing new technology to solve customer problems. Kudu has maintained the technological lead ever since.
“My father and I have always been intrigued by finding a better solution to a problem, whether it’s using our existing equipment or sitting down with our customers and coming up with a new approach,” says Ray.
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A direct supply chain made the old distribution scheme less viable and prompted competitors to follow Kudu’s lead and stop selling to supply stores. Ray was doing the majority of installs at the time and Kudu was quickly gaining a reputation for being the knowledgeable PCP company and the ‘go to’ guys for difficult well applications.
“Kudu has always gone up against much larger and entrenched competitors,” says Ray. This holds true today. Kudu’s largest Canadian competitors have now been bought out by even larger multi-national oil service companies. “But we have always put a lot of effort into being an authentic service company. Meaning a collaborative relationship with our customers is key to our success.”
Soon, Robert and Ray moved from the garage to a small plant and then to a bigger plant shortly after. Business was good.
In 1998 the oil price plummeted and Kudu was shouldering high inventories and bumping up against its credit line. The
business at that time was 95% in Canada and suddenly 60% of the business went out the door.
At the end of this dark tunnel, Robert saw Lean Manufacturing which encompasses low debt and low inventory levels, geographic sales diversity, wider awareness of economic and industry cycles and a culture of employee engagement. “Give employees the tools and empowerment to succeed. They have valuable ideas on how to improve their area of expertise” Ray says.
These changes vastly improved Kudu’s prospects by increasing annual sales, enabling three acquisitions, reducing stock outs by 98% and eliminating bank debt all in the space of four years. They have grown to have 13 service centres in Alberta and Saskatchewan along with offices located in Russia, Romania, Kazakhstan, Oman, the USA and Australia. Perhaps most importantly, the company now conducts more R&D work in its field than any other, holding over 20 patents dealing with PCP technology in the artificial lift field. O T
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