Oilfield Technology June 2013

Advancing Directional Technologies

VOLUME 06 ISSUE 06-JUNE 2013

OILFIELD TECHN

OLOGY MAGAZIN

E

JUNE 2013

w

ww

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ISSN 1757-2134

contents

Copyright © Palladian Publications Ltd 2013. 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. Images courtesy of www.bigstockphoto.com.

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| 03 | EDITORIAL COMMENT

| 05 | WORLD NEWS

| 10 | OIL AND GAS: FROM RUSSIA WITH LOVE?Louise Taggart, AKE, UK, looks at how the upstream oil and gas industry functions in Russia, and considers challenges and opportunities inherent in operating in the country.

| 13 | MIND THE GAPSimon Drysdale, BP, UK, explains how investing in current talent is helping to bridge the skills gap in the global oil and gas industry.

| 18 | MANAGING THE HUMAN RESOURCELaura Drysdale, Change International Recruitment, UK, explains how the growth in demand for hydrocarbons has fuelled a boom in the deepwater market, which is stretching the limits of manpower availability.

| 24 | OPENING UP THE ARCTICMatt Corbin, Aker Solutions, UK, provides an overview of the development of a subsea gas compression system that could pave the way to easier operations in the Arctic.

| 27 | MAPPING OUT THE ARGUMENTSCyril Widdershoven, TNO, the Netherlands, shows how the arguments for and against the production of shale gas in the EU are mapped out, and explains the political-economic decisions that need to be made.

| 31 | CABLE FREE COLLECTIONDoug Crice, Wireless Seismic, USA, examines the growing range of cableless seismic systems available to operators, and compares these with traditional cable-based systems.

| 35 | NOT ALL ARE CREATED EQUALTyler Cobb, Baker Hughes, USA, reiterates the importance of selecting the correct drill bit from the perspective of operators and contractors.

| 41 | DRILL BIT DEVELOPMENTSTodd Bielawa and Jack Castle, Century Products, Inc., USA, outline some recent developments in drill bit technology that are helping operators continue to get the job done in ever-harsher conditions.

| 45 | GETTING A BIT MORECary Maurstad, Varel International, USA, takes a look at some of the latest advances in drill bit technology that are helping oil producers drill faster and further.

| 49 | MOVING ON WITH MWDSteve Krase, Ryan Directional Services, USA, gives us a look at a unique approach to MWD for unconventional wells.

| 54 | PUTTING UP BARRIERSPaul Hazel, Welltec A/S, UK, explains how improved annular barriers lead to better completions.

| 60 | KEEP ON YOUR TOESStephen J. Chauffe, TEAM Oil Tools, USA, examines a new hydraulic toe valve designed for a cemented environment.

| 65 | SEAL THE DEALSean Hollis and David Brown, CSI-Technologies, USA, show how common well repair problems can be overcome with an engineered sealant.

| 69 | FOAM-FREE CEMENTINGAmir Mahmoudkhani, Kemira, USA, explores the advantages of green innovations in defoamers for cementing applications.

Drilformance’s PDC drill bits and innovative downhole tools deliver consistent high performance. Operators turn to Drilformance when speed, directional control and a quality wellbore are fundamental to achieve project economics. The company’s innovative design methods continue to deliver advances in drilling technology that result in optimal economic returns for operators.

On this month’s cover >>

June 2013 Volume 06 Issue 06

© 2013 Halliburton. All rights reserved.

Solving challenges.™

PLUG AND ABANDONMENT

What’s your plug and abandonment challenge? For solutions, go to halliburton.com/welllock

Overcoming conventional P&A failures gave this operator a resin to celebrate.

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HALLIBURTON SOLUTION The low yield point of Halliburton WellLock™ resin enabled infiltration of the leak. The three-dimensional polymer network not only resisted gas channeling, but effectively displaced seawater and wellbore fluids, achieving a competent plug bond.

SOLUTION RESULTS Testing after the plug set demonstrated a competent seal compliant with regulations.

Case History:

3OILFIELD TECHNOLOGY

June 2013

Anna Scordos

Editor

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The UK will be a place for shale gas companies to see, and be seen, over the next few years. IGas is a leading onshore hydrocarbon producer in the UK, delivering

natural gas and crude oil to Britain’s energy market and has recently announced that it has previously underestimated the volumes of its gas resources in northwest England. The company has now predicted that its licensed sites in Cheshire hold approximately 102 trillion ft3 of shale gas. These volumes of reserves could meet British gas consumption demands for many years to come. In an interview with the BBC, Andrew Austin, the company’s Chief Executive, said, “We [Britain] import around 1.5 trillion ft3, we consume around 3 trillion ft3 a year. Assuming you could recover technically something like 10 to 15% of the shale gas in place, then it could move import dependency out for about 10 to 15 years.” The company will start drilling this year.

Many O&G players in the UK have strong hopes that the country will, at some stage, manage to replicate the success of the USA in harnessing the resource. Development of shale plays in Europe is slow, but the region’s markets are still affected by the huge shale exploitation in the US; last year LNG cargos were diverted from the US to Europe, which made gas from Russia expensive in comparison. But Gazprom is insisting that its gas is competitive now, and expects European exports to rise by 9.4% this year. The state controlled energy group is nothing if not confi dent. A recent Financial Times article quoted Alexander Medvedev,

Gazprom’s Deputy Chief Executive, as saying “Gazprom will continue to play a leading role as a gas exporter. As The Beatles sang, ‘All you need is gas’.” Inaccurate song quotes aside; European gas demand is actually on the decline, as, over recent years, Europe soaked up the surplus US domestic coal supplies sidelined by the shale phenomenon.

Oil & Gas UK, the leading representative organisation for the UK offshore oil and gas industry, released a statement last month revealing that companies delivering drilling, completion, testing and maintenance for oil and gas wells generated gross revenue of £1.9 billion (US$ 3.05 billion) in 2012, apparently the highest since records began in 1996. Spending on equipment and technology rose by approximately 5% from US$ 178 million to US$ 186 million. Well services contractors spent up to 90% of their annual capital investment on developing new technologies. The Rt Hon Dr Vince Cable, Secretary of State for Business, Innovation and Skills, acknowledged ‘The Long and Winding Road’ ahead for the UK O&G industry, saying: “These fi gures show just how valued the UK’s expertise in the oil and gas sector is across the world. They also emphasise the value and potential growth of the industry to make a stronger UK economy. We want to continue to attract investment into the supply chain so that we can compete internationally.” The UK will clearly be working ‘Eight Days a Week’ to maintain its competitive edge on the international O&G stage. O T

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05OILFIELD TECHNOLOGYJune 2013

world news

inbriefBP has revealed plans for US$ 1 billion of investment in its Alaskan operations over the next five years, including the addition of two new drilling rigs to its North Slope fields. The new rigs will push BP’s Alaskan total up to nine.

According to BP, the plans will “call for an increase in drilling and well workactivity, the upgrading of existing facilities and the addition of up to 200 new jobs in the state, giving a boost to both the company’s operations and the state’s economy.”

The company has also secured support from the other working interest owners (ExxonMobil, ConocoPhillips and Chevron) at Prudhoe Bay to begin the evaluation of an additional US$ 3 billion worth of development projects. These projects would continue for almost a decade. They are likely to involve the construction of new drilling pads and the drilling of more than

110 new wells.Janet Weiss, BP’s regional president

said, “Our announcement today should make it abundantly clear that BP is committed to being a part of [Alaska’s] future and to continuing to extend the life of North America’s largest oilfield.”

BP has claimed that the decision behind this new wave of investment in Alaska was a result of recent changes to the state’s tax law. The state’s tax laws changed in April, and have made oil and gas operations more appealing to investors. Changes included a 20% reduction in taxes collected on new oil production, and a new flat tax of 35% on profits.

Weiss explained that, “Now an improved tax structure is in place, oil and gas projects can once again move forward, keeping Alaska competitive in the midst of America’s recent energy renaissance.”

ARGENTINAThe Argentine government has signed an agreement with the Federal Organisation of Hydrocarbon Producing Provinces that aims to “guarantee the fulfilment of the objectives in the hydrocarbon sovereignty law. The law in question is designed to make Argentina self-sufficient in hydrocarbons within as little as four years.

The ambitious law could face significant hurdles in the form of a lack of drilling rigs and other equipment, as well as concern from foreign companies over the safety of their investments in Argentina in the wake of the nationalisation of Repsol’s YPF.

POLANDWlodzimierz Karpinski, Poland’s treasury minister has stated that despite setbacks in its development, successfully utilising the country’s shale reserves will remain a priority.

“The pressure on companies to invest in this area will certainly not be smaller, it could even be bigger, because this is a matter of national interest,” Karpinski was quoted as saying. Poland is believed to hold recoverable reserves of 346 - 768 billion m3.

IRANAccording to the Financial Times, Iran’s oil output has fallen to a 25 year low as Tehran’s major Asian customers have cut their imports in response to US sanctions.

China, India, Japan, South Korea and others have all dramatically reduced their imports of Iranian oil, purchasing just 750 000 bbls between them this April - down 30% on the figure for March. The US has provided 180 day waivers to allow time for Iranian customers to find new suppliers.

// BP // US$ 1 billion Alaska expansion planned

The international oil cartel, OPEC, has decided to maintain a production cap of 30 million bpd; this decision had been widely expected, but according to some sources, the ongoing shale oil boom in the US has begun to raise concerns.

Sources claimed that the countries that had been hurt most by shale oil had asked the group to look into ways of resolving the situation. However, OPEC’s Secretary General, Abdalla Salem el-Badri said that although a review into the impact of shale oil would be launched, it would be down to member countries to find their own solutions.

Several countries have already begun to seek alternative markets outside of the US.

Russia’s oil output in May rose slightly (a 0.1% increase) bringing the figure to 10.48 million bpd, partially supported by the country’s top producer, Rosneft, which had been further ramping up its output.

This figure matches Russia’s November 2012 output, but still falls just short of the country’s post-Soviet record of 10.50 million bpd. Rosneft pushed its overall production up by 0.15% as a result of growing output from its recently acquired Vankor field (which was obtained after the company bought out TNK-BP for US$ 55 billion). The company’s total output is 4.6 million boepd.

The country’s gas production fell by 1.7 billion m3/d, as a result of Gazprom’s output declining by 11%.

// OPEC // Cap to stay at 30 million bpd

// Russia // 2013 oil production record hit

06 OILFIELD TECHNOLOGYJune 2013

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world news

IGas announces significant rise in gas-in-place at UK shale basin

Northcote Energy - highly positive frac update

Challenges for oil and gas development in the Western Pacific

3 - 6 SeptemberOffshore EuropeAberdeen, UKE: [email protected]

22 - 27 SeptemberSEG International Exposition and 83rd Annual MeetingHouston, USAwww.seg.org/web/annual-meeting-2013

30 September - 2 OctoberSPE ATCENew Orleans, USAE: [email protected]/atce/2013

29 - 31 OctoberOTC BrasilRio de JaneiroE: [email protected]/2013 // Petrobras // Domestic production

on the rise; new pre-salt record set

Brazil’s state giant, Petrobras, has reported that domestic oil production rose by 4.2% in April to a total of 1.98 million bpd. The company’s total hydrocarbon production including natural gas rose by 2.6% to 2.55 million boepd.

According to Petrobras, “The output increased primarily due to the resumption of production on platforms P-09, PCE-1 and P-54, in the Campos Basin, following a scheduled shutdown in March, and the ramp-up in production on FPSO Cidade de Itajaí, in Baúna Field, Santos Basin. April’s most significant scheduled shutdowns happened on FPSO Espírito Santo, in Parque das Conchas, operated by Shell, and on FPSO Brasil in Roncador Field.”

The company also added that, “It is also important to note the increasing contribution of pre-salt areas, which have been adding to consolidated output results. A new pre-salt output record of 311 000 bbls of oil was set on 17 April. In addition to the daily record, Petrobras set a monthly record of 293 800 bpd in the pre-salt.”

Brazil’s pre-salt fields are believed to hold significant amounts of oil and could pave the way for Brazil to become a major hydrocarbon exporter.

Swedish company, Lundin Petroleum has completed another appraisal well at the Johan Sverdrup field offshore Norway and has found additional resources.

The well encountered an oil volume of approximately 12 m, which was described by the Norwegian Petroleum Directorate as having “very good reservoir quality.”

The company’s CEO and President said, “The latest [...] appraisal well provides a further important data point and will be incorporated into the latest reservoir model, which will be used to update resource estimates later this year.”

The well, located in water 112 m deep and drilled to a total depth of 2045 m, was drilled by the rig Bredford Dolphin.

The Syrian oil minister, Suleiman Abbas has revealed that the country’s oil output has fallen by 95% from pre-war levels to just 20 000 bpd (down from a figure of 380 000 bpd).

The Syrian government had been dependent upon oil as its main source of revenue until the EU imposed an embargo as punishment for attempts to suppress the uprising. Production took a significant hit after the government lost control of most of northern and eastern Syria, where the majority of the country’s oilfields are located.

The EU had recently agreed to allow the purchase of oil from the Syrian opposition. However, extensive smuggling operations and the influence of powerful local tribes will likely mean that the opposition will be unlikely to gain full control of the facilities.

// Lundin // Sverdrup appraisal well complete

// Syria // Production 5% of pre-war levels

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world news

08 OILFIELD TECHNOLOGYJune 2013

// Total // To partner with others in South Sudan

// US // Shale boom reduces hurricane threat

// PDVSA // US$ 4 billion loan signed with China

// Statoil // New fi nd near the Vigdis fi eld

// Kodiak // Acquires North Dakota assets

As well as bringing about a significant upturn in domestic oil and gas production, the US shale boom may have the unexpected advantage of making the oil and gas industry more resilient to hurricanes.

According to the EIA, the shift of the industry towards inland operations (away from exposed offshore facilities) will likely mitigate the overall impact of hurricanes on oil production. In the four years leading up to 2011, production in the Gulf of Mexico (GoM) accounted for more than a quarter of the US’ entire output; in 2012, this figure had dropped to 19%.

The EIA reports a similar scenario for natural gas, with 26% coming from the GoM in 1997, but accounting for just 6% last year.

Hurricanes however, are still liable to cause significant disruption if they make landfall; Hurricane Isaac (2012) caused at least 1.3 million bbls of production to be shut in.

Venezuela’s PDVSA has agreed a US$ 4.02 billion loan with China’s Development Bank Corp. (CBDC), the proceeds of which will go towards ramping up production in the Orinoco belt. The deal was signed by PDVSA’s President, Rafael Ramirez and CDBC Vice President Wang Yongshen.

Specifically, the money will be used to boost production at the Sinovensa field from 140 000 bpd to 330 000 bpd. PDVSA holds a 64.25% stake in the field, with China National Petroleum Corp. holding the remaining 35.75%. Increasing production at the field falls under PDVSA’s 2013 - 19 business plan, which is targeting at increasing Venezuela’s total production to 6 million bpd (up from 2.91 million bpd at the end of last year).

Chinese companies including CNPC have signed various agreements with PDVSA, which are designed to see each company boost its production by 1 million bpd by 2019.

Norwegian state player, Statoil has made a new oil discovery near the North Sea Vigdis field, however, after disappointing results, the commercial viability of the find remains in question.

According to the Norwegian Petroleum Directorate, “The objective of the well was to prove petroleum in Lower Jurassic reservoir rocks (the Cook formation), as well as to collect data in order to assess further development of the area.

The well proved a 24 m oil column in the Cook formation with somewhat poorer reservoir quality than expected. The size of the discovery is being evaluated regarding whether or not it may be commercially interesting.”

The well, which was drilled from a template at the Vigdis field, reached a total vertical depth of 2546 m, in water some 292 m deep. The drilling vessel was the Fred Olsen Energy-owned Bideford Dolphin.

Kodiak Oil & Gas Corp. has announced that it is going to spend US$ 660 million on assets in North Dakota, which were previously owned by Liberty Resources.

The acquisition covers 42 000 acres of both producing and undeveloped assets across the Williston basin, with coverage in both the Three Forks and Bakken plays. This will bring Kodiak’s total holdings in the Williston basin to 196 000 acres. The acquired acreage produces approximately 5700 bpd at present.

The Bakken and Three Forks formations are believed to hold a total of approximately 7.4 billion bbls of undiscovered, but technically recovered oil. North Dakota is now the second largest oil producing state in the US.

Total has announced that it will partner with ExxonMobil and Kufpec in order to search South Sudan’s Jonglei state for oil.

Total has held in a majority interest in the 120 000 km2 Block B in the region since the 1980s, but the long civil war between Sudan and the newly emerged South Sudan prevent the company from going ahead with exploration.

It was announced by the South Sudanese government last year that, in order to speed up development of the region, negotiations were taking place in order to split the block. The chairman of South Sudan’s parliamentary committee on energy and mining, Henry Odwar, announced that the block would be split into three: B1, B2, and B3.

Odwar was quoted as saying that,

“Now Total has gone ahead and, with a nudge from the ministry, engaged certain partners. ExxonMobil and Kufpec have been brought in to be partners in Block B1.” According to Reuters, a source with inside knowledge of the deal has confirmed that B2 is likely to be managed by the same partnership, and that the government has yet to decide on B3.

South Sudan has only recently resumed production from its fields after a 16 month hiatus brought about by a diplomatic spat with Sudan; at one point, the two countries were perilously close to all out war. Even since the resumption of production, tensions between the two nations are still high; recent attacks by militants on the border have only served to fuel suspicion.

The upstream oil and gas business is vital to the Russian economy. Last year, revenues from the hydrocarbon sector contributed approximately 50% of GDP and they

will remain even more vital as the government looks to pump more public money into military reform and social spending. Data from the Energy Ministry indicated that Russia’s level of oil output was the highest in the world last year, ahead of even Saudi Arabia. Output was edged up by increased production at Rosneft to a post-Soviet high of 10.4 million bpd, an increase of 1.1% on 2011 levels. However, future output may be constrained

Russia is to maintain its oil output levels in the longer term and

10 million bpd until 2020. In order to attract further investment, however, issues such as changes to the tax regime and corruption will have to be addressed so as not to hinder further growth in the upstream sector.

Production

to 655 bcm, attributed in part to a drop in production of 5.1%

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Louise Taggart, AKE, UK, looks at how the upstream oil and gas industry functions in Russia, and considers the challenges and opportunities inherent in operating in the country.

(26 bcm) at Gazprom. Gazprom’s position has also been weakened abroad, with exports constrained by continued stagnation in the European export market and by growing hostility towards its pricing structure, which pegs gas prices to oil indexes. Independent producer Novatek saw its own production levels rise 7.1% and such independent companies are expected to increasingly challenge Gazprom’s dominance in the coming months and years. However, the gas sector remains dominated by the Gazprom monolith. Although the downstream sector could be opened up, with discussion continuing over the possibility of liberalising

domestic market, the upstream market is likely to remain dominated by such domestic giants in the short term.

ExplorationOffshore exploration in the key Arctic region remains dominated by Gazprom and Rosneft, which hold the rights to some 80% of Arctic sections. The right to work on the continental shelf belongs only to companies with more than 50% state ownership; private companies are limited to entering only as junior partners without a stake in the operating licence. The government has also outlined plans to suspend the development of reserves in 20% of the

11


Arctic shelf, ostensibly in a further bid to halt private access to reserves. In May, the government awarded four exploration licences for the Barents Sea to Gazprom without the need for an auction.

Although some foreign companies have begun to secure upstream access in the Russian Arctic in the form of partnerships with Rosneft and Gazprom, the government will remain reluctant to open up these natural resources to foreign or private investors, except as junior partners brought in to provide technological

widely-publicised exit of BP head Dudley, will make foreign investors wary of entering the market as a junior partner with limited oversight.

Boosting investment

and changes will need to be made to encourage investment in the

is coming under growing pressure to loosen regulation and taxation

which have much higher exploration and extraction costs associated with their reserves. Russia’s tax system has undergone various changes in recent years, hampering oil companies’ efforts to make long term investment plans, with operators calling for a more stable and clear tax regime. The Finance Ministry has indicated it may move to gradually phase out oil export duties whilst simultaneously increasing the rate of mineral extraction tax (MET). The ministry is expected to announce its proposals on lowering the export rate by 2 – 3% annually in May. The proposal is expected to lower the crude export duty rate from the current 60%, and would also lower rates

However, in a bid to offset any losses in revenue, it would also intend to raise the MET. The MET increase could be as much as 5%.

The proposal has already attracted criticism from upstream operators and the tax is widely seen as a brake on investment needed to increase oil production. Russian oil companies have voiced concerns over the latest proposals, saying they would lead to a decline in oil output and result in less tax revenue. The

it by 6.4% last year. The amount of tax is calculated monthly for each extracted commercial mineral.

Another hurdle to investment in the upstream energy sector remains the wider operating and business environment. Russia has sought to develop a more investor-friendly environment than some of its other energy-rich neighbours, such as Kazakhstan. However, a number of issues can still pose a barrier to foreign investment in the upstream sector, both direct such as taxation and the regulatory environment, and more latent issues such as the political environment.

Political environmentRussia’s political environment has come under increased scrutiny following the disputed parliamentary elections in December 2011,

the collapse of the Soviet Union. The consequent perception of political instability, which some parts of the Western media were quick to erroneously label part of the wider ‘Arab Spring’,

consequently in the wider business environment. However, for the medium term at least, the status quo is unlikely to witness

at the helm of the government and although some changes have been brought in as a sop to the opposition movement, the political elite will remain well established. Although this will ensure a level of political stability, it in itself also engenders further issues. Political stagnation will ensure the continuation of the entrenched business elite, along with the implications that it brings for their vested interests. The business environment remains dominated by cronyism and widespread corruption. The US’ 2013 National Trade Estimate Report on Foreign Trade Barriers reported that corruption remains the key barrier to foreign investment in Russia. Although the government has sought to improve the business climate, corruption was reportedly continually cited as a major concern in both commercial and bureaucratic transactions. A number of recent political resignations following allegations of undeclared assets will do little to reassure investors that any

problem.The appointment of the next head of the Central Bank is also

Putin nominated his chief economic advisor Elvira Nabiullina to the position, raising concerns over the bank’s independence in its future monetary policy given her close links to the Kremlin and undermining hopes that the Central Bank would seek more independence.

Government involvementThe government is expected to retain its involvement in the upstream energy sector in the medium term, given its strategic importance to the economy. This was evidenced by the Rosneft

take control of assets including Samotlorneftegaz, the largest production facility in Western Siberia. Rosneft is one of the key actors in the government’s armoury of assets, majority-controlled by the state holding company Rosneftegaz. A possible partial privatisation of Rosneft continues to be mooted, with the most recent reports suggesting that the government could seek to sell a 19% stake in the company as part of its plans to speed up the privatisation process. Privatisation has been on the table for several years, most notably under the presidency of Medvedev, but has seen little real movement. A renewed sell-off

has been hit by a fall in tax revenues. The Economy Ministry has indicated that privatisation of state stakes could raise approximately RR 320 billion (US$ 10.2 billion) this year. According to the government’s mid-term privatisation strategy, the state energy holding company should start cutting its 69.5% stake in Rosneft this year, with a complete sale by 2016.

Future prospects for the upstream sector will remain stymied by vested government interests, the dominance of state-owned energy majors in exploration and extraction, and issues that affect business operations across the board, such as corruption. However, given the government’s reliance on the revenues from hydrocarbon reserves and the need to boost foreign investment in newer developments to ensure that production levels do not tail off in the future, it will at some point be forced to realise that private and foreign capital is vital for ensuring that the sector reaches its full operational potential. Technological know-how for

and investment capital will eventually tip the balance in favour of sector liberalisation. O T

The world of oil and gas has changed dramatically over

oil prices rose year-on-year, leading to both increased investment in existing infrastructure, and an appetite to look to new frontiers in an attempt to increase production to meet demand. In the past 10 years BP has been pushing the boundaries of exploration, from established geographies such as the Gulf of Mexico to the emerging such as Angola.

The uptick in oil prices is driven in part by the incessant increase in global demand for energy. The International Energy Agency predicts that demand for energy will grow by some 40% by

The future looks very bright for the oil and gas industry, but it certainly faces challenges. Attracting the right talent, with the appropriate skills, is a cross-sector challenge that has received an unprecedented level of attention amongst employers and in the media coverage over recent years. Whilst a great deal of talk and attention has been given to the need to recruit, there is

also a need to retain and maximise the capability of the existing workforce.

the industry needs to ensure that the global workforce is in a continual cycle of learning new skills and career development.

Bridging the skills gap; why are we where we are?With the constant focus on the need to bridge the apparent skills gap, many people within the industry ask ‘did you not see this coming’? Whether the industry had foreseen the challenge or not, the more important question is ‘why has a

skills gap and subsequent war for talent emerged’?

led to the current skills gap.The oil and gas industry has a history of hiring and training

the workforce based on the current oil price. Traditionally, when oil prices have fallen, workers have been made redundant as projects are delayed and workload drops, and when oil prices spike, the industry battles to acquire as much resource as

Simon Drysdale, BP, UK, explains how investing in current talent is helping to bridge the skills gap in the global oil and gas industry.

13


possible as it embarks on a talent acquisition programme. BP is moving away from this model and looking to invest whatever is required to ensure the right skills in the right places so that the company will be ready to adapt to both macro and micro economic changes.

Whilst planning and economic forecasting have a role to

last 15 years has seen the rise of graduates going straight to

a career on a trading platform over a production platform.

away from the oil and gas sector in recent years, and who can

engaging and educating tomorrow’s generation about the critical role oil and gas plays in the world and the fantastic career

build understanding of what needs to be done and encourage sector advocacy.

Need for formal learningIt must not be forgotten that whilst bringing new recruits and young talent into the sector is of paramount importance,

the continual development of the sector’s employees is of equal importance. Huge investment is required to ensure that

and development. It has developed and implemented global

allows graduates to sample three differing roles within the organisation, enabling consistent and structured learning

result has been huge cost savings for the business and more centralised training for recent joiners. A win-win situation.

Additionally, the company has recognised that the training of new talent needs to be extended beyond these three initial years and has subsequently developed and implemented the E&P eXcellence Programme for its staff.

development and aims to offer depth and increased operational capability.

As previously mentioned, a uniform approach to learning and development is required to ensure existing staff, from all

Figure 1. A drilling engineer on the Dada Gorgud rig in the Azeri Field, Azerbaijan, which drilled the AZB001 well. Image courtesy of BP p.l.c.

areas of the globe, have an ongoing and consistent career development programme. The BP Upstream Learning Centre in Houston is an example of this approach. The 65 000 ft2 centre, which is made up of 10 classrooms designed for over 300 students, opened in March 2010 and is viewed within the industry as being an example of the future of training. Last year, of the 14 900 people who were trained worldwide by BP, nearly 6400 passed through the doors of the centre. Technology is central to the offering with life-sized simulators, 3D visualisation capability, dual image displays, video capture and conferencing capability, and purpose-built broadcast rooms to allow teachers to deliver training in the

Need for multi-company learning By its very nature, the oil and gas industry has a history of being collaborative. Organisations form partnerships on the overwhelming majority of global projects and they rely upon and utilise a great number of service companies to ensure the global workforce remains mobile and adaptable to constant changes in their clients’ needs.

The oil and gas industry does better than many others at facilitating and encouraging learning and development across multiple organisations, and industry bodies, such as OPITO, are becoming increasingly important in encouraging and facilitating multi-company training programmes. That said, more could and should be done. Increasing the skills and capability for the sector as a whole is without doubt a positive for the organisations operating within it.

Need for informal learningWhilst monetary investment in employees’ learning and development is critical, formal programmes alone are not a proven recipe for success, and in some corporate cultures formal training become a ‘tick box exercise’. Informal learning, the passing on of knowledge to emerging talent, and fostering a collaborative culture is of equal importance. There is a need to ‘develop’ as well as formally ‘train’ employees and this can only realistically be achieved through structured mentoring programmes.

All graduates and new joiners are assigned a mentor and meet on a regular basis to discuss challenges that have been faced, both from the technical side and as part of the development of so called ‘soft skills’.

Outlook: what else can be done?The industry as a whole has come a long way in recent years. It has become better at formalising, standardising and collaborating in attempts to develop current and emerging talent. That said, improvements could certainly be made.

In order to maximise capability across the whole sector there is a need to move towards standardised international learning and development practices. Presently, even formal training differs by company and by country. Change cannot happen overnight, but standardisation should be a core area of focus for the industry over the next 10 years. All stakeholders have a role to play, from the international oil and gas companies such as BP, through to the regional and international industry trade bodies and societies. The result can only mean an increase in safety, capability and

O T

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I t looks likely that 2013 will herald a number of changes in offshore drilling, and in particular the deepwater market. High levels of investment across the board,

from virtually every major contractor and operator has resulted in the industry experiencing aggressive newbuild strategies to keep up with demand from operators; and rigs becoming more advanced in terms of their drilling depth and operational capabilities.

With an increase in ‘dual activity’ in water depths never before attempted, it is not just a matter of having

Image courtesy of BP p.l.c.

Laura Drysdale, Change International Recruitment,

UK, explains how the growth in demand for hydrocarbons has

fuelled a boom in the deepwater market, which is stretching the limits of manpower availability.

18

Managing the

advanced rig designs, but finding the shipyards that have the experience, and can deliver projects on time, whilst meeting client requirements.

A prime example of how the market is driving demand is the Saipem – Sacrabeo 9. The rig was specifically built to drill in extreme water depths offshore Cuba, and tap into reserves never drilled before. While this rig has yet to strike oil, the Cuban government is determined to continue in its quest to successfully drill in the region.

Last year, several contractors increased their asset portfolios through either newbuilds during the past two years, or acquisitions, or both.

The UK’s Ensco plc. is one such company that has embraced a buy-and-build strategy wholeheartedly. The company expanded its fleet by three new 8500 series rigs over the last year, and acquired Pride International, which came with two moored semisubmersibles, four DP semis and three DP drillships. Pride also had numerous deepwater DP drillships under construction

19


at the time of the acquisition. The end result is that Ensco now has two deepwater moored semisubmersibles and 17 DP semis and drillships, with two more drillships to be completed.

Transocean has also steadily increased its deepwater fleet. Over the past four years the company has gone from operating 12 moored rigs and 24 DP units (with eight rigs under construction at the time) to a moored rig fleet of 11, but an increase in its DP units of 12, taking the total to 36. This increase came about after acquiring two rigs from Aker Drilling and the delivery of several new rigs. The company still has a further two drillships under construction.

Noble Corp. also expanded its deepwater rig fleet, acquiring Frontier Drilling, which operated the Frontier Driller (now Noble Driller) moored semisubmersible. The acquisition included two shallow water drillships and an FPSO, and Frontier had three drillships under construction. Two of these drill ships were delivered – the Noble Bully I and Noble Globetrotter I – and the contractor still has five drillships under construction, three for delivery this year and two set for delivery in 2014.

Other organisations that have added to their portfolios include Norway’s Ocean Rig, which increased its deepwater

deepwater drillships scheduled for delivery this year.

Draining the personnel reservesHowever, newbuild plans are heavily reliant on operators being able to find the staff for these rigs, and with a finite number of experienced personnel within the market, companies need to plan ahead for the future.

It was reported last year that there could be up to 10 000 new jobs created by the end of this year in the North Sea’s subsea sector. And for a sector that is certainly booming, this was welcome news, especially as concerns have been raised about the number of suitably qualified candidates for the positions.

The subsea industry is outperforming other sectors and an increase in demand for candidates in this field is being seen. A survey by Subsea UK, which represents more than 250 companies, suggests that 50% of companies reported finding the staff they need has become very difficult, and 14% of operators said recruiting qualified personnel was almost impossible.

The industry supports around 50 000 jobs and is expected to grow by 40% in the next two years and there is an obvious skills gap that needs to be filled. The sector needs to continue to attract new talent in order to help meet the growing demand.

In order to fill the perceived gap in skilled shipyard-level maintenance crew, some organisations are looking outside the oil and gas industry and at other trade where skills are transferable – with the transport, military and heavy industry sectors being a breeding ground for the kind of skilled engineering and ship building graduates who are capable of moving sectors and making a positive impact for their employers.

A shortage of engineering graduates has created major issues across the sector. Reducing workforce pressures and ensuring that skilled staff are developed and retained within the industry is therefore vital to safeguard future prosperity in a hugely competitive market.

There are currently ‘pinch points’ in a range of highly specialised technical roles and people, who have experience of the sector, moving around different companies, rather than new talent being recruited. This can have a big implication in terms of cost inflation for companies and is not healthy for the wider economy, with premiums paid for some roles.

A large number of the young people coming into the sector need training, and the infrastructure and partnerships needed to bridge the skills gap are largely in place. However, it is likely to take a number of years to address the shortfall of skilled workers.

Finding experienced staff may not be the only hurdle that operators need to overcome – as recent research undertaken by Change Recruitment revealed that many workers perceived a lack of progression opportunities as a result of the global economy. With these frustrations bubbling over, 75% of respondents admitted to actively hunting for alternative employment and 44% specifically saying they were doing so in order to take a step up the career ladder.

Add to this the fact that almost half (48%) of oil and gas professionals questioned stated they had not received inflationary pay rises over the past two years, with a fifth (20%) saying they had received nothing at all, and it is hardly surprising that more than a quarter (26%) of respondents felt they were not appreciated by their organisation.

Nearly three quarters (73%) subsequently felt that they would be paid better if they worked for a different organisation, and over half (54%) also thought the benefits they received as part of their package would be better if they moved company.

The deepwater drilling market continues to be a very candidate skills-driven market. It has bucked the trend throughout a difficult time in the economy and has continued to grow despite setbacks in the market, which have stunted, and at times changed how business is done.

Candidates with industry experience are in a luxurious position of being in high demand and sought after and in many cases have the happy headache of multiple clients offering opportunities within the industry. This has driven salaries and competitive benefits packages up, and clients are finding that they have to work hard to keep their compensation in line with the rest of the market.

From the North Sea to the rest of the worldOne thing remains the same though: employers across the globe continue to look for North Sea experience, which can help to open up the rest of the world in terms of jobs and career development as it is still seen by the industry as the most advanced area in the world to work.

As it is a mature market, a number of company assets are ageing. This has led to a separate industry being developed to service these assets, which in turn requires a great deal of specialist expertise to look after the infrastructure.

However, the North Sea employment market still has some of its own challenges, and at present is thought to be short of personnel with between 10 and 20 years of experience. This could be because experienced personnel are more reluctant to make a move to a new role during an economic dip, and

back on their trainee intakes.The sector has remained fairly resilient in the face of the

economic situation, but a number of organisations have seen restructuring and even downsizing, resulting in a drop off of hierarchical positions.

they believed their career would have progressed further had the UK not been hit by recession; and two thirds said they would be prepared to work anywhere, including emerging markets, for the right career opportunity and remuneration.

established and emerging markets for those workers willing to take the plunge and move – and a marked increase is being seen in the number of people showing interest in opportunities available in Africa and the Middle East. The tougher jobs market in the UK has had a knock-on effect on the number of younger workers showing interest in moving overseas – and for many it is not just down to money, but the opportunities and career progression that working in another country offers.

Elsewhere, the East coast of Africa is proving to be very exciting, with a great deal of experimental drilling taking place. Many larger operators are tapping up contracts in this largely untested region, and 2013 could be a big year

in terms of what newer rigs are assigned to East Africa for drilling operations beyond the already established basins in Mozambique.

The booming ‘Golden Triangle’ areas of West Africa, Brazil and the Gulf of Mexico have been a primary focus for many of the world’s leading operators and their continued investment in exploration throughout the region is shaping the things to come both in 2013 and beyond.

Looking into the not too distant future for a snapshot, there are currently 178 drilling rigs in construction in South East Asia alone. If each of these rigs requires 500 employees, then there will be a huge number of jobs created.

fairly substantial changes to the industry. The bigger players have taken a back seat, allowing smaller operators to enter

to independent companies who can be more nimble and cost-effective in how they operate. By their very nature, the independent companies tend to have a smaller portfolio

Looking aheadOn the whole, the future continues to look promising for the industry. It will be interesting to see what impact renewable energy has in terms of talent attraction. While the green energy industry cannot compete in terms of remuneration, the renewables route might appear prosperous to some young engineers, and therefore could be one to watch this year. O T

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Matt Corbin, Aker Solutions, UK, provides an overview of the development of a subsea gas compression system that

could pave the way to easier operations in the Arctic.

24

Figure 1. Åsgard subsea gas compression station.

Developing technology to compress natural gas on the seabed and send it straight to shore - as an alternative to installing a large offshore

platform - has been a long term goal for the offshore industry. Now that goal is one step closer to becoming

Ormen Lange subsea compression pilot, designed and built by Aker Solutions. The technology could be the key to unlocking the Arctic’s oil and gas reserves.

According to the US Geological Survey, the Arctic holds 90 billion bbls of oil in reserves plus 47 trillion m3 of gas. But ice-infested waters combined with reservoirs hundreds of miles from shore make

technological challenge. Due to the ice and freezing cold, oil companies will, in many cases, have to rule out platforms on the surface of the sea.

The solution is to instead put the platform on the

under ice, and the facility is not dependent on

subsea compression in the Arctic reduces risk because it means no people offshore, no

a subsea compression system on the seabed is the Ormen Lange subsea gas

At Nyhamna, on the west coast of Norway, a large pit is currently playing vital part in a 25 year long technology saga. Inside the pit and

full-scale subsea processing and compression system. It is in the middle of a two year rigorous test

25


programme to ensure it can meet the demands of one of the toughest challenges ever set by the offshore industry.

This large subsea system, some 120 ft (36 m) long and weighing over 1000 t, is the pilot subsea compression plant for

UK’s gas requirements. Ormen Lange, operated by Norske Shell, came onstream in

September 2007 and reached plateau production in November 3 (70 million m3/d) of gas and

32 000 bpd of condensate to the Nyhamna processing plant in mid-Norway.

drive the hydrocarbons to shore, but that pressure will steadily decline, and later this decade gas compression will be required

decision must be made: should gas compression be achieved conventionally by locating compressors on the topsides of a new offshore platform, or could gas boosting be achieved entirely subsea by using the subsea pilot plant?

operating costs of a subsea station are more economical than those for a new deepwater compression platform. Another key advantage is that by locating the compression system on the seabed near to the subsea gas wells, the back pressure exerted on the gas reservoir will be much reduced, enabling greater production to be achieved.

Full-scale pilotSubsea compression is not a new concept, but despite the concept being mulled over by the industry for decades, it was not until 2006 that Aker Solutions was awarded the

The Ormen Lange pilot was built throughout 2010 at the company’s Egersund offshore construction yard.

The pilot consists of eight large subsea modules, grouped to form process, control and high voltage power systems. Together these make up a single full-sized compression train.

The modules for the pilot contain the essential equipment for solving the technology challenge. The entire system was put through months of testing at Egersund, before being disassembled and shipped to Nyhamna for reassembly in the 42 m x 28 m x 14 m deep test pit, where it is currently being put through its paces on ‘live’ Ormen Lange gas and condensate.

centrifugal machine, which will operate at 11 000 rpm. The compressor and its high speed electric drive motor are housed in a single, hermetically sealed enclosure which is pressurised with a barrier system to keep the motor and compressor spaces separate, and also to ensure clean operating conditions for the motor and bearings.

More than compressionAs important as the compressor and its reliable operation are to the project, there are many other new components necessary to create the overall system. One example is for achieving liquid separation and boosting.

A characteristic of all gas compressors is that they have a limited tolerance to the volume of liquids in the incoming gas

stream, which therefore must be controlled. The solution is to remove the bulk of the liquid condensate before it reaches the compressor, raise its pressure and inject it back into the gas export line downstream of the compressor.

Separation of the condensate is achieved in a 3 m diameter vertical separator upstream of the compressor. The condensate

the high pressure export gas line for transportation to shore. The separator also contains a system for removing sand from

vessel and to protect the compressor.

Power playThe Ormen Lange pilot is ‘all electric’ – there are no hydraulically operated components. The full compression station would be electrically operated and controlled, with

through a subsea power cable at 132 kilovolts, which would be stepped down by transformer to 22 kilovolts at the subsea station.

The list of sophisticated electrical components that had

long. High on that list are the variable speed drives (VSDs) for the compressor and pump, which would be controlled from

power cable. As gas production rates and pressures from the Ormen Lange reservoir change over time, the VSDs will regulate the speeds of the drive motors by varying the supplied voltage and current frequency, thus enabling the compressor duty to be changed and the pump speed to be regulated to control the liquid level in the separator.

And so to Nyhamna where all of the ingenuity and engineering effort that has gone into the Ormen Lange pilot is currently being tested. In February 2011, the Egersund yard shipped to the test site a purpose-built 900 t process module,

including slugs, to test the pilot. The Nyhamna test loop has 3

3/d) of gas per day, 11 300 bpd (1800 Sm/d) of

operating pressure.

industry has had to prove that subsea gas compression is the future.

technology will be there for platform-free production. O T

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Cyril Widdershoven, TNO, the Netherlands, shows

how the arguments for and against the production of

shale gas in the EU are mapped out, and explains

the political-economic decisions that need

to be made.

Europe’s shale gas future is still looking bleak. Ongoing discussions are not focusing on the economic and technical aspects of

a possible shale gas revolution in EU member countries, but on the political-environmental aspects. Perceived threats, not supported by independent assessments, taking into account the specific situation of a certain shale gas project in a country, are ruling the current debate. Instead of trying to find a bridge between techno-economics and environmental issues, the current debate is only polarising opinion. Some analysts are already stating that the current debate is no longer based on the possible pros and cons of shale gas, but on the perceived threat that shale gas could pose to a possible ‘green energy’ future, as indicated by

Mapping out the arguments

27


green politicians and lobby groups. The latter discussion is irrational and counter-productive in all aspects.

Navigating the argumentsTo set up a more fundamental discussion, Dutch independent applied science and technology company TNO has set up a so-called ‘Argument Map’. The company has, after in-depth assessments of the pros and cons of shale gas, devised a tool to summarise the arguments for and against shale gas production in different EU Member States. The main focus of this map is to bring clarity to the positions in the shale gas debate and promote a rational discussion. Instead of the ‘Argument Map’ only being presented in the Netherlands, the decision was taken to publish the map in Brussels, targeting a Europe-wide audience. Without taking any political or economic stand, the map explains, based on a literature review and input from experts from different backgrounds and Member States, the possible issues surrounding shale gas exploration and production in the EU. European and national policy makers, industry stakeholders and lobby groups, should take the current discussion to a much more abstract level to build up a possible co-operation framework. This is needed to address the vast amount of misconceptions in the public domain. The map could be a possible instrument to lay the ground for such an effort. Without setting up an open and rational discussion, uncertainty, fear of the unknown and mistrust of reputable, peer-reviewed scientific evidence, will keep on constraining

the current developments. Initiatives like the Argument Map can help to shed light on the shale gas debate. Also, TNO will be working with the European Research Agency to develop a European Research Programme on shale gas to bring more scientific evidence to the table, can help to shed light on the shale gas debate.

In the coming years, Europe will stand at the front of a major discussion on how to adjust to the ongoing shale gas revolution in the USA, the overall implications for the global gas sector and its technical challenges. At the same time, European politicians will have to adjust to the ongoing economic crisis hitting Europe, while addressing requests from its industry to make use of the possible low cost energy resources available on the continent. Until now the discussion has only been centred around environmental issues, largely due to the infamous American movie ‘Gas Land’, which has been showing a rather subjective view of shale gas operations and environmental consequences.

Taking stockSome moves already have been made by the EU to assess its options. In recent months, several major conferences have been held by the EU and stakeholders to address these issues. At a recent event at the European Parliament in Brussels, parties involved have been trying to look ‘behind the hype’ of shale gas and dispel myths surrounding the resource. Still, analysts have been disappointed until now, as most discussions again were full of exaggerations and

Figure 1. Argument Map: shale gas production in EU member states.

speculative positions. Anti-shale gas lobbyists have been playing the environmental disaster position if shale gas production would be allowed in Europe. At the same time, pro-shale gas groups have been exaggerating the impact of shale gas revenues on the European economy. Some have even been stating that European shale gas could be enough to bring about European energy independence, and revolutionise the continent’s economy. As indicated already by the ‘Argument Map’ (Figure 1), the truth will lie somewhere in the middle.

Shale gas production has the potential to bring additional energy resources to the market. Some European countries could be reaping the rewards, including potentially: Germany, Poland, the UK and maybe even the Netherlands. The total volumes available are as yet unknown, but even the most optimistic scenarios do not show Europe to be in the same league as the US, China, Russia, Algeria, Saudi Arabia or Jordan. Optimism has taken over from rational assessments by investors and operators. At the same time, negativism is only part of the discussion currently supported by anti-shale gas environmentalists, ‘NIMBY’ lobby groups or green politicians. The ‘Gas Land’ issue is not of any relevance to the European situation. The US shale gas revolution, in contrast to Europe, is based on ownership of the land, different environmental laws and investment regulations. The unexpected vast volumes available in the Bakken or other shale gas regions in the USA dwarf the potential of the European players. Geological specs of the

shale gas reserves in the USA are also different from the Netherlands or UK. Threats to ground water reserves in Europe are different from the USA or elsewhere in the world. Still, environmental issues should not be taken lightly, but approached in the normal way of technical and economic analysis through methods already in place for decades due to conventional oil and gas operations in the EU. Hence the set-up of the ‘Argument Map’, designed to bring a rational way of thinking to the current emotional debate.

When talking about the EU, the real discussion should focus on the available reserves. The need for an assessment by independent parties of the available reserves, the related costs and possible rewards, is needed to substantiate the future developments. Until now, most of the economics of shale gas have been not shown to the public. At the Brussels conference (EUP), one of the main messages presented was that the economics of shale gas are still unclear for European operations. At the same time, the size of shale gas resources both in the US and the EU have been vastly over-exaggerated, or current assessments are based on suppositions, which are somehow not the reality. Several analysts even have stated lately that there could be a false bubble in the gas sector, which is liable to blow up in the faces of the involved parties very soon. Still, the overall discussion at present is that the ‘green lobby’ was hoping to reap the expected reward of a high (and no longer economically viable) crude oil price, which would have seen a move towards green technologies. The high gas prices at

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the end of the 1990s and the first decade of the 21st century certainly gave way to this approach. However, the global economic crisis, the immense worldwide investments made in gas production and the unexpected boon of the shale gas revolution have resulted in plummeting gas prices. Economically, gas is the fuel for the future. Its availability, combined with low prices and geopolitical issues, have put the break on the run for ‘renewables’. The costs of wind, solar and biomass, are too high, especially when comparing them with gas prices.

The Green Lobby also is now confronted by another remarkable aspect. Europe’s race for renewables, supported by the ‘Energie Wende’ in Germany, and the multibillion Euro projects proposed by the European Union and its member countries, has not resulted at present in a reduction of emissions. The 2020 goals of the EU are not going to be reached, maybe the opposite will be the case. Renewable energy has not had the effect that was expected.

American exceptionalismThe USA however has become the leading example of good economic strategy implementation designed to support industry, create vast amounts of jobs, and (albeit unintentionally) reduce CO2 emissions. In stark contrast to the EU, China, India and others, Washington can brag about its emission reductions. No other country has been able to show these results. Geopolitical economists even have stated that the world should follow the USA. When looking at the emissions situation, Washington is leading the pack. Emissions can be reduced while at the same time supporting basic economic fundamentals, increasing investments in hydrocarbons, and creating jobs and energy independence. The need for US investments in renewables has become a minor issue. No economic factors or lobby groups are able to push for new solar or renewable investment schemes in the

Going for the ‘Golden Age of Gas’, as presented last year by the IEA in Paris, has become a reality in North America.

This success has, to the astonishment of several experts, not resulted in a ‘gas revolution’ in the EU. After decades of supporting gas-fuelled power generation, clearly functional in Northwest Europe due to indigenous gas production (Norway, UK, Germany and the Netherlands), Brussels now is betting on renewables. EU investment schemes for technology development in CCS, renewable energy (solar, wind), have been known for decades. However, success rates are still nothing to brag about. CCS projects in the EU are largely on hold, the ‘NIMBY’ issue is also a major factor here; Green lobbyists want to promote CCS, but ‘please, somewhere else.’ The lack of investment and support by the EU and the respective governments for conventional oil and gas technology development and production, has resulted in a lack of follow up to meet new challenges in the future. The tendency to only promote renewables, as shown by 2020 or the Dutch 2050

competent technology has become the main stumbling block for green projects in the EU. Investors and power generation

at the end of the 21st century, shareholders and clients need to be supplied at present. The shale gas revolution has not only caused America’s emissions to decrease, surprisingly it also has decreased renewables and gas consumption in the EU. The lack of demand for coal in the USA (and elsewhere) has brought down the global coal market prices. European power generation companies have been taking advantage of the latter,

European CO2 emission levels of course are showing tendency to go up further than ever before. The market has taken over, no EU emission strategy or CO2 pricing schemes will be able to prevent the latter on the short run.

Looking to the futureThis situation can be stopped, the solution is again to promote more natural gas or shale gas usage. As the IEA, and others, have been stating for years. The easiest, most cost-effective way to reduce emissions is to go for gas. Yes, gas is a hydrocarbon source of energy but it produces much lower emissions than other hydrocarbon resources. For Europe there is only one solution: to go for gas. Gas is the only applicable intermediate energy resource to bridge the conventional (high CO2) energy economy of the present and the unconventional/renewable energy situation wanted in future. If the EU does not take the necessary steps, the future of the European economy (and its citizens) looks bleak. It is possible that European emissions levels will be reached without shale gas, but it will be at the cost of prosperity and high unemployment rates. The current energy dependency of Europe’s basic industries is too high to gamble with renewables. In the short term (10 - 15 years), European companies, such as BASF, Unilever or Krups, will struggle to keep producing within the EU at current energy rates. Global competition is high, major American companies are already reinvesting in their home country to reap the reward of low shale gas prices. Europe’s economic future will not depend totally on shale gas in Poland or the Netherlands, but it will be a mistake not to take advantage of resources. Shale gas in Europe needs to be addressed in a rational way, not based on emotions or pure political assessments. If shale gas is technically and environmentally producible at economically interesting price levels, the right choice is to start production. At present, the answer is still out there, no specifics have yet been delivered.

The need for investment in setting up research and independent assessments of the available shale gas resources and their potential effects is clear; to prevent such investment would be foolish. John F. Kennedy’s dream to put a man on the moon also was confronted by opponents. Some even thought that the Apollo rocket would destroy the moon. It seems that current debates have the same irrational quality. Fracking, the ‘devil in disguise’ according to environmentalists and opponents, has been used for decades, also in Europe. Perhaps it is time to let Brussels play the part of Aladdin and ‘let the Genie out of the bottle’? Technical economic research is needed; the only Genie then to be found is perhaps a new gas revolution, Europe’s shale gas adventure. O T

Figure 1. Juggie deploying a cable-based seismic system. The difficulties involved in deployment are obvious, as are the safety risks.

A s a general rule, geophysicists are pretty creative - when they see a problem or envision a better way

to do things, they envision a solution. If the problem is generic to the geophysical industry, they might even develop the idea with the support of their employer or otherwise. Generally the idea is way ahead of the technology required to make it practical, or the industry is slow to adopt a method, and it is some time before it shows up in practice. The Vibroseis is

Conoco, years in development, and widely adopted perhaps 20 years later. 3D seismic took even longer because a lot of things had to happen to make it practical: the recording systems had to be developed to collect data from thousands of geophone groups, seismic contractors had to acquire the systems and methods to collect the data, software was needed to process the information on more powerful computers (and later individual workstations), and interpreters had to learn how to understand these new images.

Doug Crice, Wireless Seismic, USA, examines the growing range of cableless seismic systems available to operators, and compares these with traditional cable-based systems.

31


These innovations and countless others have resulted in continuous improvements in the way seismic data is collected and in the quality of the information about where the elusive hydrocarbons reside.

Considering cablesCables used in land seismic might be classed as an annoyance rather than an obstruction. In conventional 2D surveys, the maximum number of channels was limited to approximately 240, because the cables required two conductors for every geophone. The cables were broken up into segments short enough that they could be carried by one person. Surveys with more active channels were limited to an occasional oil company funded experiment, which was really multiple 2D surveys conducted in parallel.

The advent of 3D surveys exacerbated the problems multifold. Before 3D surveys could be practical, what are called ‘distributed systems’ were created to facilitate data collection with exponentially greater numbers of channels. Common distributed systems deployed small boxes spread out in the survey area. Each digitised the analogue signal from four, six or eight geophone groups. The data was

recording system, which at that point was more like a computer than an acquisition system.

of cables on an average sized survey. Consider the problems with cables: They require significant manual effort to deploy and retrieve

Animals, all kinds, chew on them, so the first part of each day is spent on cable maintenance.

Crossing highways and rivers is troublesome.

Permission to lay cables may not be available in patches of the survey.

Cables are difficult to use in urban environments with streets and buildings.

Permission is difficult or impossible in environmentally sensitive areas.

On the other hand, cable-based systems offer substantial

immediately, so the client representative can evaluate the quality of the seismic information. Cultural and wind noise can be monitored to see if the survey can continue. In desert areas without roads and few animals, it is possible to lay out huge

use multiple vibrator groups to achieve high productivity. But, for most surveys, eliminating cables is a desirable goal. Doing so has been a challenge.

For a long time, geophysicists have wanted to eliminate cables. As discussed earlier, the ideas came about well before the technology was available to provide a practical solution to the problem.

The dawn of cable-free systemsEarly attempts at cable-free seismic systems met with marginal success. Autonomous memory-based systems using magnetic tape storage were limited by cost, complexity, and environmental problems. Early radio-based systems were limited by the available bandwidth. Eventually, technology advanced, and costs came down, to allow development of practical

information was transmitted to a central recorder by VHF radio. The data was harvested by physically visiting the unit with

Figure 3. Wireless Seismic RT System 2 real time acquisition system at work in rough terrain in Columbia.

Figure 2. Geospace GSR autonomous recording system shown with battery and geophone. The GSR and second-generation GSX is the market leader in autonomous nodes.

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a second device. Some RSR units remain in use today, but they are approaching obsolescence because of the visitation requirement and the lack of replacement parts.

About the time the RSR was introduced, Vibration Technology, aka Vibtech, was founded to build a system to collect data wirelessly in real time. This system utilised WiFi technology using multiple towers, each able to communicate with clusters of local acquisition units. By

possible to create a wireless seismic system with enough stations to compete with a cable-based system.

In 2005, the cableless revolution really took off, with ION Geophysical’s announcement of FireFly. This event

acquisition systems. As is common with pioneering designs, there were initial problems.

In 2007, Geospace introduced the GSR, followed later by

purchased Vibtech and integrated it with their cable systems.

Catagories of cableless systemsThe cableless systems can be grouped into different types: Autonomous ‘blind’ nodes are deployed in the field where

they collect the data and put it in an internal memory in the unit. They must be picked up and brought to the central computer to retrieve data. The data from the individual units is sorted and combined with the data from the other units to construct the seismic record. Representative units are made by Geospace, FairfieldNodal, and AutoSeis. Instrument quality control is performed by either passing by the unit or connecting a separate device that checks the operation and battery charge level. The units can operate continuously in the field for a month or so, although the data cannot be examined until they are picked up.

Autonomous ‘nearsighted’ nodes operate in a similar fashion, but the data can be harvested wirelessly by visiting the unit in the field and transferring the data to a second device, usually wirelessly from a distance of many metres. Representative models are the Sercel Unite and the Inova Hawk. If the data is collected daily, the danger of lost data due to equipment failure or theft is minor.

iSeis Sigma fit in this group.

Real time nodes send the complete seismic data to the doghouse continuously. They are essentially equivalent to a cable-based system. Examples are the Wireless Seismic RT System 2 and the Sercel Unite system (when used with fibre connected multiple towers in real time mode).

Industry reactionSo, how has the industry greeted the advent of this new type of seismic system? It is safe to say that initial scepticism is evolving to acceptance, if not widespread enthusiasm. The blind autonomous nodes offer the easiest deployment – they

check their performance. To extract the data, users have to wait until it is time to roll the units, carry them back to the central computer, extract the data in a special rack into a computer, charge the batteries, and take them out to their next location. Deployment is easy, though it requires a little more skill on the part of the operator than does a cable system because of the

data (a common-receiver gather) does not lend itself to simple

a suitable record (a common source gather). Consequently, the initial tests to determine the sweep or shot parameters

supported by these units, and estimates must be made.Nonetheless, the autonomous blind systems are the leading

seller. Surprisingly, despite the expectation of fewer workers,

about the same as on a cable crew, but the survey proceeds two or three times as fast.

Sercel has done a good job on integrating their cableless Unite system with their cable systems. The units can be mixed on a survey to accommodate deployment problems such as a survey with a town located as part of the area of interest. The central recording system accepts data from the mobile harvesters and integrates it nicely with the cable data. Sometimes a single tower is put up to collect data from a local group of stations, but the logistics of distributing towers around the complete site are daunting enough that the preferred approach has been to use mobile harvesting.

Real time wireless systems such as the Wireless Seismic RT System 2 potentially eliminate all the perceived problems with blind systems at the expense of a little extra infrastructure, in the form of radio backhaul systems. The system has worked extremely well on some surveys because the initial geophysical tests are completed quickly, allowing the survey to proceed. Deployment is easy because the system can leap over roads, tracks, rivers and non-permit areas. If an individual fails, the

Wireless future?The industry is now seeing a transition in technology without a predetermined outcome. What will be the product mix between

Cable-free systems started to gain acceptance with purchases

systems. Now, there are reports of contractors retiring perfectly good cable-based systems because those surveys are not as competitive in the geophysical contracting market. According

some RSR and ARAM crews with autonomous nodes and

Global Geophysical has replaced all their cable-based acquisition crews with nodal systems. On the other hand, the

cable-based systems where the surveys are huge. O T

Early attempts at cable-free seismic systems met with marginal success.

Tyler Cobb, Baker Hughes, USA, reiterates

the importance of selecting the

correct drill bit from the

perspective of operators and

contractors.

For years, many in the drilling industry have claimed that drill bits are a commodity. It appears that many drill

bit suppliers these days are offering bits that have the same number of blades and cutter sizes, some form of leached cutters, design similarity and even their respective marketing propositions begin to blur together. It is only natural to assume they must all be fairly equal. The truth is that not all bits perform the same and selecting the right one can have a dramatic impact on drilling performance and overall well and drilling campaign costs. Much like a set of golf clubs, meal choice, or new pair of boots, it may make sense to choose based on lowest price to

35


spare the immediate budget pains, but the consequences of this choice could leave long term regrets. Similarly, despite the industry’s best intentions to reduce vendor costs, selecting the cheapest bit up front in many applications may end up costing the operator more than they bargained for. Understanding where the differences are in drill bits and becoming savvy in what makes those differences perform, is where operators stand to gain much. The keys to identifying real value in the drill bit world can be found in the categories of technology, reliability, quality and service assurance.

Technology

Smoke and mirrors vs. game changerFor those in the know, drill bit technology can be considered advanced. This is especially true when comparing drill bit-related patent activity to other high-technology classes such as aeronautics/astronautics and ships as shown in Figure 1. Similar to any technological industry, there will be those who make use of game-changing technology to add real value and those who employ smoke and mirror gimmicks, which add little documented performance to the product. Finding a game-changer amongst all the feature noise in the marketplace does not mean it necessarily has to look dramatically different in order to deliver big returns on the additional micro-investment toward bit price. Vital clues to potential game-changing technology worth

performance, industry papers and patents. A drill bit company who can provide supporting materials for all four of these topics very likely is offering a feature that is more than smoke and mirrors. Not only does the technology need to stand up as an individual performer in a controlled lab environment, but this measured lab

Furthermore, multiple industry papers, especially ones co-authored by operators, are some of the best signs in the

oil and gas industry that a technology is worthy of consideration. Finally, a patented product affords greater assurance that it is differentiable from competitors’ products.

Where is the value?

The best way to review the impact of innovation is to group the top innovators together versus all others, and then review a sample application data set. Figure 2 shows how the 318 utility patents that were awarded in 2011 are split between the top two organisations and the other 39 contributing organisations and

Consider a snapshot performance comparison from the Williston Basin, USA, with Figure 3 representing the performance of the top two innovating companies and Figure 4 representing all others. The results demonstrate a difference of 22% in rates of penetration (ROP), and 13% in distance drilled.

The bottom line is the enduring top performers in the industry are those who deliver the highest amount of new, quality technology in the form of novel intellectual property to the drill bit industry.

Reliability

How do we measure?Every operator knows one of the most important metrics in the drilling industry is reliability. And yet many believe the only important metric for drill bits is ROP. Times are changing, and it is time drill bits are held to the same standards as other downhole drilling tools. How can reliability be measured for drill bits? For tricone bits, many turn to the practice of measuring the statistical reliability of the bearings and seals in terms of thousands of revolutions (Krevs). With regard to polycrystalline diamond compact (PDC) bits, which lack any moving parts to constructively measure traditional reliability, it boils down to the concept of performance consistency. A drill bit manufacturer who consistently delivers high levels of PDC performance demonstrates that the spread between upper quartile and lower quartile results is relatively small. This consistency offers gains in terms of authorisation for expenditure planning and wellbore delivery timetables.

Where is the value?Imagine a bit drilling an 8000 ft section that reached total depth at an ROP of 200 ft/hr. Now compare that to the same bit drilling an identical successive well, but only at an ROP of 120 ft/hr. This comes to a difference of more than 26 hrs for interval completion. Beyond the immediate expense of 26 additional hrs of rig time, the resultant extended timetable can cause innumerable pains and headaches for successive service planning. With service companies all striving to increase their asset

crews that were originally planned for have now been on standby at additional cost, or worse, are no longer available, leaving the

Figure 1. Utility patents awarded per year by technology class. *Batteries includes thermoelectric and photoelectric i.e. solar panels. Source: USPTO.gov.


June 2013


operator/contractor scrambling to line up second-best options. This delay could mean higher costs, longer lead times and additional logistical consequences. The wiser, long term bit solution may in fact lie in using the manufacturer that can deliver drill bits that perform in a highly consistent manner, and this can only be determined through diligent measurement and analysis.

QualityQuality for drill bits can be segmented into two sources: original quality and sustainable quality. Original quality stems from three primary factors including quality of design, materials and manufacturing processes. The sustainable quality trait refers to the repair process. At a fundamental level, drill bits may be designed using similar methods, made from comparable materials, manufactured in a

related process and repaired likewise, but once the details are exposed, the differences are exponential.

Original qualityIt is no secret that drill bit designers around the world use sophisticated computer-aided design software to create their design models. The quality comes into play in the form of the proprietary modelling software each company custom builds for running simulations prior to manufacturing. Additionally, most bit vendors will hesitate to describe their particular recipes for drill bit success, but rest assured some employ extensive research and development resources dedicated to delivering consistent innovations in advanced materials to gain an edge over the competition. Beyond the design work and material sciences, each drill bit is only as good as their manufacturer’s equipment and skilled workforce responsible for machining and assembling. Most manufacturers are happy to host a tour of their facilities, and this is highly recommended as it gives insights into the rigor of their manufacturing, tolerances upheld throughout the process, and testing methods and capabilities. Some great questions to ask on the plant tour are: What is the extent of manufacturing traceability - if there is an identified failure, how can it be traced back to the particular component of concern?

How does their quality department function?

What sort of testing is undergone before releasing radical new designs to the field?

Sustainable qualitySo, the bit manufacturer has impressive simulation software, some of the highest quality materials and an impeccable manufacturing facility, but what happens

following run(s)? With the ever-increasing presence of the rental market for drill bits, the repair process has never been more important. Even the slightest variances in the cutter placement in the repaired bit can dramatically change the drilling characteristics or performance consistency of the drill bit. While repair centres may not always be open to

public tours, it certainly would be within reason to request the occasional analysis of consecutive runs for a particular drill bit to ensure it is delivering the consistency of performance one should expect from a high quality repair process.

Where is the value?

Much like the difference in car manufacturers, drill bit manufacturers all operate under different levels of quality from the materials they use, the manufacturing processes they employ, the tolerances they uphold, and the consistency of their repair centres. The value here ties back to the reliability of the bit and the consistency of performance, which was previously discussed. Also, much like the automobile industry, it is at least in part the consumers’ responsibility to conduct their

Figure 2. Percentage splits for utility patents awarded in drill bits (earth boring) in 2011. *Individual, nonaffiliated patents.**Others representing 39 organisations. Source: USPTO.gov.

Figure 3. Top two innovators’ performance in Williston Basin 8.75 in. PDC depth in 6000 to 12 000 ft. Source: Baker Hughes WebBITS data.

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own background research and comparisons to determine whether the variances in quality are fairly represented by the differences in pricing.

Service assurance

What service?The operator purchases a bit, the vendor makes sure it has

drilling performance, and then perhaps picks the bit up afterwards. What more to service is there? For some operators, this may seem a perfectly reasonable argument. To others, they realise the impact that a heavily experienced and resourced bit supplier can have on long term drilling performance. These bit manufacturing majors are not only employing some of the most experienced drill bit application engineers, but also have rigorous training and competency programmes to provide unparalleled service assurance when it comes to bit recommendations and drilling improvement support. Beyond the human capital, many of the biggest drill bit companies maintain remarkable records of wells drilled around the world. They are able to leverage this drilling data to identify opportunities for improvement and offer

especially true when they are provided with foot and time-based drilling data and formation evaluation information where they are able to identify the exact rock type the bit is having trouble in and make improvements in the design to maximise performance and reliability.

Where is the value?The real value of service assurance, which sets any particular bit supplier apart from another is the means by which that

Figure 4. Other innovators’ performance in Williston Basin 8.75 in. PDC depth in 6000 to 12 000 ft. Source: Baker Hughes WebBITS data.

service company is able to provide continuous improvement beyond what may be possible with other drilling tools. Several of the service companies have an iterative application/design process operators are invited to or can request to participate in. Since drill bits have a relatively short design and manufacturing cycle time (compared to some downhole tools), it is certainly possible to conduct several design iterations over the course of a

improvements in consecutive wells with higher quality and lower total cost per foot. Competition certainly is the lifeblood that drives improvements, but creating long term, performance-based relationships with a bit supplier can be extremely rewarding to an operator’s drilling campaign.

ConclusionFor drill bits, there is a large quantity of

service companies all reaching out to pedal their products. Some even make drill bits that look very similar to other more mainstream brands and occasionally even deliver comparable ROP. This can create a false impression that drill bits are all the same and have become a commodity product. Despite the occasional exceptions depending on the application challenges, the overriding evidence shows that for drill bits, the differences are deeper than the naked eye can see and include differentiating factors in technology, reliability, quality and service assurance. The sheer number of patents being pursued and awarded for drill bit technologies is evidence of the innovations being introduced to the industry. Like many other tools in the drilling environment, a critical metric of value delivery for drill bits is reliability, or performance consistency. High reliability can reduce

campaigns. Quality in design, materials, manufacturing, and repair should always be a consideration when making purchases or rental agreements that can affect the success rate of an entire operation on such a grand scale. Finally, operators should expect a level of service assurance from their drill bit vendor partners. Leveraging long term relationships with service companies can provide performance-enhancing design iterations and valuable application support for reducing total well-delivery costs. For operators and contractors alike, it is imperative to always be wary of the effects of drilling service selection purely on cost or convenience as the total cost of that simple decision may far exceed what was invoiced. Do not be deceived by appearances, because not all drill bits are made equally. O T

Todd Bielawa and Jack Castle, Century Products, Inc., USA, outline some recent developments in drill bit technology that are helping operators

continue to get the job done in ever-harsher conditions.

G rowth in the oil and gas industry has led to the development of new technologies and techniques as it pertains to the way in which wells are being drilled

and tools are being designed in order to get the job done. As more attention has been placed on the PDC drilling arena, many bit manufacturers have placed less emphasis on the large magnum bit technology. Whether it is for oil and gas, salt domes, storage or HDD applications, large hole openers and tri-cone bits remain integral components in the drilling arena worldwide.

In today’s competitive environment there is a need for ever changing, creative R&D offered with state of the art designs, especially in the magnum bit size range. The use

of larger carbide inserts and shapes has been expanded by design feature advances within the manufacturing process, such as: the latest technology hard facing materials and applications, vacuum sealed bearing technology and the continued development of tighter tolerances and synthetic lubricants.

As the wells drilled get more complicated, there is a growing need for durable, low torque tools.

Tungsten carbide insertsThe magnum bit arena has been dominated by milled tooth designs. However, technology and process improvements have led to an expanded availability of various

41


tungsten carbide insert (TCI) options to better serve the industry. When discussing

not to notice the larger more robust inserts that adorn today’s magnum hole openers and bits. Kennametal produces one of the largest carbide inserts for Century Products. At 1 1/8 in. diameter, this insert clearly dwarfs yesterday’s technology.

With the larger range of inserts, there is a new need for applying better grade selections.

The combination of improved grades and geometry has established new performance standards that eliminate many failure methods of the past.

By utilising the new design and grades available in the larger carbide inserts, it was possible to decrease the amount of carbides per cone while still offering the ability to load the insert with the required weight to fail the formations. The new design options allow them to achieve higher penetration rates without the traditional insert mode failures. Whether the requirement is for the crushing action provided by conical inserts or the aggressive scraping action provided by chisel shapes, the right combination can be offered to get the job done.

Latest technology in hard facing for milled tooth conesIn the magnum bit range, milled tooth bits are still the dominant IADC range called for. A proprietary material that has both spherical and cast carbides and the latest in

Figure 1. Tungsten carbide inserts.

Figure 2. 30 in. milled tooth design.

Figure 3. 24.75 in. Century hole opener.

application techniques to keep the highest concentration of tungsten material at the cutting surface without heat degradation, is used. The dominant problem in many MT applications is the ability to maintain gauge. Century’s bit design incorporates three rows of active tungsten carbide gauge cutting inserts. These back up the hard facing thereby extending the bit life and improving the overall penetration rate.

Sealed bearing vs. open bearingIn the magnum bit arena, non-sealed bearing (open bearing) bits are often utilised for pennies of savings on the initial bit price. However, sealed bearings offer significant performance advantages over open bearing products. The key feature of sealed bearings is the significant prevention of drilling fluids and abrasive formation cuttings from entering the bearing cavity. This is achieved by using elastomer O-ring seals, metal-to-metalseals, or highly engineered synthetic seals to prevent contaminated slurry from entering the bearings. In addition, the most technically advanced sealing systems are also vacuum-sealed, lubricated and compensated. This is achieved by pulling a vacuum on the bearing cavity before greasing. By applying this vacuum, it ensures no air pockets exist once the grease has been pumped in.

Non-sealed bearings are exactly what the name infers. Here the open bearing is susceptible to all the drilling fluids and soil matter in the hole without any lubrication available. Imagine any bearing being open and exposed to the extreme downhole conditions without protection. Open bearing bits do not last long and are not capable of handling today’s drilling performance expectations.

Considering their advantages over earlier open seal bearings in terms of quality, dependability and performance, it is easy to see why sealed bearing designs are preferred when these characteristics are important.

Century utilises seals made from HSN, which is the best available material for compression set and chemical resistance to the extreme downhole conditions. The largest cross section seal in the industry is utilised. This is a case where bigger is better. The tolerances offered, which are tighter than industry standards, give reduced axial play, which enhances seal life, and improves bearing performance. The close tolerance machine-matched components, crowned roller main bearings

system that reduces friction and dissipates heat under the high rotary loads encountered in the magnum bit lines.

Additional concerns for improving performance and specific design features Selecting the right bit for the application or the right company to trust for help with that selection is imperative to the overall success of a drilling operation.

As the industry continues to explore deeper, more sophisticated methods of well designs, there is a need for the advancement of drill bit resources to accomplish ever-greater feats. From larger more demanding surface applications to highly deviated well designs, there needs to be the proper product for every application. The biggest factors affecting performance are: durability, stability, performance and proper bit selection.

9:25AM

5:25PM

Case study

36 in. magnum bit required in South AmericaDue to safety and hole stability concerns, a 36 in. magnum bit was selected to drill the 65 m surface hole in a single pass. The customer had been using traditional 1-1-1 IADC code bits but decided to utilise the magnum 36 in. bit. Due to the improved gauge and hydraulic configuration the magnum bit drilled the 65 m surface hole in less than 35 hrs, where in previous wells it took up to 175 hrs due to deviation control issues. The ROP on the magnum bit was 1.87 m/hr versus 0.66 m/hr on the offset. One of the reasons for the improved performance is the 6-point stabilisation feature. While deviation was the concern with this application, the magnum line comes standard with the most durable gauge protection and the latest in hard facing materials offered. This allows the magnum series to perform well in the abrasive environments encountered in the Middle East and the sealed bearing technology offered will allow for the longer sections encountered in the North Sea as well. The bit graded out a 1/1/No/A/E/I/NO/TD and will be more cost-effective on the second and third runs in this field.

Technical considerations Hydraulics: a good general rule for flow is 30 GPM x

hole size = minimum; 50 gpm x hole size = maximum.

Example: 30 x 30 in. = 900 minimum GPM. 50 x 30 in. = 1500 maximum GPM.

Specific energy vs. torque: calculation for specific energy is as follows:

Where:

SE = Specific energy.W = Weight on bit.N = Rotary speed.d = Diameter of bit.PR = Penetration rate.

This calculation can be used to further examine the relationship of bit selection and proper design application to help ensure that the torque output necessary to fail the rock will not exceed the drill string limitations.

Example: a hole opener using 8 – 12 ¼ in. cutters will require more energy to fail the rock than a Century 5 cutter design. Add in the larger bearing and slower rotational cone speed and maximum performance can be achieved with lower torque for longer downhole drilling time.

SummaryDrilling wells for the oil and gas industry is not going to change in the future. What will change is the development of new technologies and techniques in the way the wells are being drilled. In order to be successful, companies need to stay ahead of the game. O T

an Astec Industries Company 2215 SOUTH VAN BUREN · ENID, OKLAHOMA, USA 73703 · PHONE 580.234.4141 · [email protected] · [email protected] · www.gefco.com

The is the most advanced and easy-to-operate rig in the world. The safe, efficient operation keeps your out of Danger Zones! for the rig, power packs, Driller’s Cabin and Pipe Handler makes for

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The has a hook load of 500,000 lbs. (226 Tonnes). The Top Head Drive, rig also features a Slip Spindle, prolonging the life of the pipe threads. The is equipped with a Self-Erecting Driller’s Control Cabin, Hydraulic Wrenches for Make Up & Break Out, Driller’s Cabin operated Pipe Handling System, 27 1/2 in. (698.5 mm) Master Bushing and Accommodates Range III Drill Pipe as well as Drill Collars & Casing to 20 in. (508 mm).

Cary Maurstad, Varel International, USA, takes a look at some of the latest advances in drill bit technology that are helping oil producers drill faster and further.

Bringing together advanced knowledge and understanding of PDC bit design with the latest manufacturing technology, the Katana series of steel

PDC bits embodies the latest in cutting structure design,

Katana bits are unlike other PDC bits, with smaller sizes

Katana bits are available with abrasion-resistant

and enhanced thermal stability, these cutters resist abrasive wear while maintaining toughness to deliver longer cutter

Katana bit cutting structures are designed utilising the

‘One BHA’ performanceIn addition to the Katana bit series, a new line of steel body

target shale formation through variable lithology, bits

45


curve sections of these shale wells on a single bottom hole assembly

on these bits allows designers to take full advantage of hydraulic

In terms of steerability, steel body bits can be designed with a

characteristics being two delaminated cutters on the outer shoulder

SPOT design upgrade

effective cutting structure to control bit behaviour as desired for

then determine how changing bit features and dimensions affect

Figure 1. Varel’s steel body VM513SH is dull graded 0 - 2, with only two delaminated cutters on the outer shoulder when pulled after drilling a One BHA run in the DJ Basin, from drillout to landing the curve in only 25.4 hrs, a total distance of 5580 ft, at an average penetration rate of 219.7 ft/hr.

Figure 2. Katana series steel PDC bits incorporate hydraulics optimisation. Also available in a ‘shankless’ configuration in many sizes, for minimisation of bit length for responsive drilling.

Figure 3. The solid tungsten carbide EdgeGuard pucks are brazed into the bit in strategic position to afford maximum wear resistance in high angle directional drilling, and can double bit life in some applications.

Making things harder: impregnated diamonds and hardfacingLast year saw innovations in

as well as in roller cone bit hardfacing, both of which hold

months and introduced last year,

high quality diamonds to create a more robust, less brittle diamond that is less likely to suffer breakage

remain ‘whole’ during drilling, the

tough Ordovician sandstone,

benchmark of the established

Roller cone bits with an edge

bits, increasing overall durability

in directional work demanding high

greater bit life due to reduced wear in high angle wells through abrasive

hardfacing with a series of tungsten

bit leg, around the shirttail and on

double roller cone bit life in the high angle wells, where directional demands call for high doglegs through the highly abrasive

O T

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An MWD system that was

Drilling automation and unmanned operation

Steve Krase, Ryan Directional Services, USA, gives us a look at a unique approach to MWD for

unconventional wells.

Moving on with MWD

49


people from the wellsite entirely. Although technical challenges remain, the reality of achieving total unmanned operation is not so much hampered by technology but more so by a reluctance to change by the industry itself. In order to accomplish full unmanned operation it must be demonstrated that personnel can be removed from the wellsite without reducing service quality or inadvertently introducing additional HSE risk for remaining wellsite personnel.

Downhole technologyIn order to achieve a reduction in directional drilling and MWD personnel at the wellsite it is important that the design of

designed with simplicity in mind and with a low operating cost to address the lower cost land market. Additionally, there are two more factors that must also be addressed. Firstly, the system must require little or no human interface to setup prior to running in the hole, therefore the downhole system must arrive at the wellsite ready for use. Secondly, the system must provide the real time measurements required by the drilling, geology and

real time measurements must also be available remotely to anyone that needs them to make decisions.

When drilling horizontal wells on land, the measurements provided by the downhole MWD system must be focused

placement, the applications of directional drilling, geosteering

measurements required for wellbore placement are readily available and have been since the late 1980s, most of the systems in the industry today were designed for use in the offshore environment. When compared to the onshore drilling environment the cost structure for drilling offshore is much higher. Subsequently the majority of the MWD systems available today are too expensive to operate cost-effectively in the

types of wells will be reliable, short in length for ease of transport

Directional drillingIt is generally accepted that MWD survey systems for accurate wellbore surveying have been available since 1978 when

the UK sector of the North Sea. Since that time, advances have been made to improve the accuracy and survivability of these

moving parts. Modern day sensors are much more accurate and reliable and utilise the latest in digital technology.

Drilling an unconventional reservoir typically requires

drilling wells that targeted conventional reservoirs. In addition to improved survey accuracy, increased frequency of surveys has proven to be a necessity to insure wellbore placement. Additionally, the ability to measure and transmit inclination surveys continuously and preferably in closer proximity to the bit than the position of the standard directional module, has also proven

and if these changes are unaccounted for in determining wellbore

GeosteeringSince the late 1980s when MWD technology development became focused on the replacement of openhole wireline logs

in developing sensors to aid in making real time decisions based

advances made in geosteering, which uses geologic information that, when compared to a geological model, enables decisions about correction to the well path to be made in real time. Most recently this includes sensor systems with azimuthally sensitive response, which enables the user to detect not only a change in bed boundary but also the direction from which a bed boundary

Drilling efficiency

quantities of this data from downhole to surface in real time to enable a reliable interpretation of what is actually occurring at the bit and or in the BHA. Although the measurements and how to make them are generally well understood, the interpretation of this data in a timely manner has been problematic; therefore most drillers have preferred to rely on surface measurements

Figure 1. Directional sensors. This photo shows the significant change in MWD sensors over time. The instrument in the lower left is a directional sensor from circa 1980 minus electronics and the instrument to the right is a present day directional module, which includes electronics.

Figure 2. The Ryan Directional surface system takes advantage of cloud computing to ensure database integrity and access to data for unlimited users.

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provide a useful interpretation of the data

there also exists a need for downhole

Minimising personnel requirements

allows for prioritisation of transferred data under

Conclusion

O T

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Time and again it is proven that safe and effective annular barriers are crucial to well management. Cementing is the industry’s conventional solution, but it can be a complicated, expensive and time-consuming undertaking. Swellable

shortcomings, as degradable polymers represent a risk in the typically harsh and unforgiving environment of a well. Horizontal drilling emerged in the 1990s and since then, drilling technology has continued to enable deeper and more complex

well designs. These advances in drilling technology go above and beyond the current capabilities of cement to provide a reliable annular barrier that will last throughout the lifetime of the well.

Currently, more than half of the world’s rigs are drilling horizontally. The growing desire for increasingly capable, extended reach

54

Paul Hazel, Welltec A/S, UK, explains

how improved annular barriers

lead to better completions.

55


A new conceptA novel solution, the Flex-Well™, has been designed to deliver cement assurance, zonal isolation and/or cementless completions in all types of environments, as well as allow long

well abandonment.The concept provides the operator with all the

components required to design and construct a

intricate as the operator needs in order to accomplish optimal reservoir drainage.

A central element of the solution is the Welltec® Annular Barrier (WAB™), which is a rugged, large expansion ratio, all-metal expandable barrier that can be used for a wide variety of applications, and delivers reliable annular isolation and maximised delta P capability across the entire borehole over the full life of the well, withstanding up to 10 000 psi and

Traditional completion methods have a number of

from installation, and further problems arise due to formation changes over time, as these impact cement causing it to

cementation and perforations is especially challenging and costly in HP/HT environments.

Due to its design, the WAB addresses many of the shortcomings of conventional completion methods, including

run, even in extreme environments. Installation time is considerably shorter and it allows for early production, as there are no swellable elastomers to wait on. Long term well integrity is secured due to its design, materials and testing, and it has many HSE advantages. The Flex-Well™ concept offers increased recoverables and reduces installation costs substantially, which opens the opportunity to exploit a new array of reservoirs that previously were not feasible – a potentially game changing development.

Unconventional challenges, unconventional solutions

entrepreneurial idea, the Well Tractor®, allowed deployment and operation of intervention tools into horizontal and highly deviated wells, without the use of coiled tubing or similar heavy-duty equipment. Today it is a widely accepted, industry intervention standard means of conveyance.

In a time where production is declining and the global

innovation. The primary driver behind the development of new technologies is a focus on how to do things safer and more effectively, allowing operators to manage their wells and

The Flex-Well system allows for multi-lateral well design and an unlimited number of zones across the reservoir. It can enable early production and increase ultimate recoverables without compromising the long term well integrity. The

associated with total well construction. The operator can overcome current and future drilling, deployment and production challenges, enabling complete, intelligent, extended reach, multilateral wells with extreme reservoir contact capabilities. With the introduction of the WAB, the Flex-Well vision is becoming a reality.

Beginning with better barriersThe WAB for cement assurance can be set in wet cement or at a later time in sections that are not cemented. It is installed as part of the liner or casing string, positioned at depths

hung off and the cement operation completed as normal. When setting in green cement, while the cement plug is

being bumped, additional pressure is applied to the well to expand the annular barrier. The hydraulic expansion of the barrier in the wet cement ensures conformance to the open

extrudes the cement away leaving only a WAB-to-formation or a WAB-to-casing contact. The relative high plasticity of the formation in comparison to the steel will ensure that steel-to-formation contact remains after release of the expansion pressure. Any cement trapped between the WAB and the formation will not experience relaxation of pressure when drilling mud is displaced. Removal of micro annulus will

and liners.Preservation of the intended zones of interest remains

the priority as well designs grow in complexity. No matter if the well is a producer or an injector, it is critical to protect

the introduction of contaminants. One contaminant results from the cementing operations or the cement slurry itself.

WAB for zonal isolation has been developed in conjunction with a number of global operators to address this.

Whether used for cementless completion or cement assurance, the annular barrier assembly is mounted on the exterior of the liner or casing, enabling a maximum diameter, full-bore liner with rotational capability to be deployed. After setting the liner hanger and under surface control, the outer, high-grade steel alloy sleeve of the barrier is hydraulically

In a time where production is declining and the global demand for energy is on the rise, the market needs innovation. The primary driver behind the development of new technologies is a focus on how to do things safer and more effectively.

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expanded to contact and conform to the open hole, while simultaneously working to harden the alloy. During the setting sequence, arrays of unique, pressure activated seals are energised against the formation, providing the hydraulic seal that allows the WAB to deliver a stable metal barrier with a maximised delta P capability across the entire borehole for the lifespan of the well.

From vision to realityThe idea of the annular barrier has been around for years,

reservoirs. Thus the WAB has been developed in close co-operation with a number of operators, addressing

environments. The outcome is a hydraulically expandable metal annular barrier, developed for the applications where swellable external casing packers are traditionally used.

The WAB allows for surface operation, advanced downhole monitoring and reservoir control, and re-stimulation of multiple zones stretching horizontally over more than 30 000 ft. of wellbore and potentially comprising more than 60 zones. It is a unique, single skin well completion liner, assembled on the outside diameter (OD) while maintaining full-bore inner diameter (ID). It provides long term robust and reliable zonal isolation in cemented or un-cemented wellbores and may be used in conjunction with casing as well as liners. It also provides higher differential pressure capacity and higher expansion ratio to running OD without compromising the ID. Consequently, it does not impair or

well maintenance to take place unhindered. Fast and safe deployment are key industry demands,

which are supplied through simple components and solid liner functionality. Due to the lack of control lines, installation can be

ensures safe well abandonment when required. The full-bore construction ensures the highest production rate capacity, and its rugged design and reliable nature allows for increased reservoir contact, and enables cementless completions.

Over the last two years intensive design and development work has been under way. One of the main challenges has been moving into the realm of plasticity theory requiring the involvement of external expertise combined with numerous laboratory tests. The challenge lies in the complexity of the interaction between the various components of the seal

components in isolated tests. During the development of the annular barrier, the

development and engineering team faced an array of challenges, including: Relatively low expansion pressures.

A requirement to hold a high delta P in collapse (production) pressure differential – a property in conflict with the expansion pressure specified above.

Choice of material and dimensioning of the expandable sleeve, capable of very high expansion ratios.

Design of outer seals with an ability to withstand high delta P across a wide temperature range after setting.

Preliminary engineering drawings were created based on intellectual property gathered over the course of many years

was performed in the initial development stages to simulate the expansion on the maximum required borehole size with the available expansion pressure.FEA considered the following parameters: Maximum allowed expansion pressure.

Maximum allowed outside diameter.

Setting temperature.

Minimum operating temperature.

Pressure differential in production mode.

Material selection.

Maximum and minimum borehole size.

While standard FEA analysis characterises the borehole as a rigid body, it is also possible to model the rock response to the expansion stresses ensuring it does not exceed the formation limits.

As the design was revised, the FEA analysis was re-run to ensure all the project challenges were met. Once the FEA was

the ISO 14310 V-3 testing protocol, which establishes the pressure-drop limit of 1% for the pressure-testing cycles. It is manufactured in accordance with ISO9001.

Case study: high pressure, cementless, zonal acid stimulationIn the North Sea an operator needed to deploy a liner across an 8000 ft horizontal section within a selected reservoir comprised of eight zones. The challenges were that the zones had to be completely compartmentalised and able to withhold up to 8000 psi delta P during an extensive acid stimulation job, as well as isolate a nearby water-bearing zone.

To improve economics and maximise reservoir exposure to the acid, cement was avoided as part of this solution. The baseline operation was built up from an extensive drilling and production database, and using the annular barrier completion solution, the well was projected to deliver

After an extensive engineering study, 16 of these wellbore annular barriers were installed on the operator’s line assembly and deployed in the well, sealing off the selected eight zones. Once the entire liner including WAB assembly reached the desired target depth, pressure inside the liner was increased to expand the WABs; an operation that took less than 30 min. With the zones completely isolated, the acid stimulation job

was achieved between each of the zones. The pressure was successfully contained within each zone while the stimulation job went from one zone to the next as designed. The zonal

temperature and pressure sensors located within each of the zones using independent readings.

Eliminating the need for cement in this project lowered the Capex and enabled the operator to achieve the desired, extended reach drilling target while overcoming the limiting equivalent circulating density (ECD) concerns. The planned productivity achievement was greatly surpassed and after six months of production, an average of 4500 bpd was achieved

O T

Stephen J. Chauffe, TEAM Oil Tools, USA, examines a new hydraulic toe valve designed for a cemented environment.

A large majority of North American long lateral wells are cemented and thus require initial toe injection before these multi-stage wells can be completed.

and time-consuming use of coiled tubing (CT) or tubing

into the formation.

test (DFIT) analysis.

open hole applications are desirable in completions that

allows the tool to function regardless of any residual or tail

higher operating pressures and temperatures than other tools.

Utica and Barnett shale plays. The tool has been tested more than 300 times and by more than a dozen operators

Traditional methods: plug and perf and tubing conveyed perforating

of these wells are cemented and require an initial toe

60

61

the current completion techniques utilised today – ‘plug and perf’ and ‘ball sleeve.’

The plug and perf method uses a combination of frac plugs and perforation clusters to complete the well. Once the lower most zone is hydraulically fractured, a frac plug (bridge plug) is pumped to depth and set. The zone above the frac plug is then perforated with wireline and subsequently hydraulically fractured. Completing wellbores using this technique requires an initial toe injection to

Historically, the initial toe injection is established with the use of TCP. With TCP, perforating guns are deployed on threaded pipe or coil tubing, often times below a snubbing unit. This technique is time consuming, costly and adds a safety issue with perforating guns on surface.

The ball sleeve method utilises ball-activated stimulation valves cemented in place along the lateral. In this case, which is similar to the open-hole scenario, individual balls are dropped to open each valve and subsequently hydraulically fracture each zone. Similar to the plug and perf method, an initial toe injection must

establish an initial toe injection typically results in all the ball-activated frac sleeves being drilled out in order for TCP to be run.

The next generation of toe sleeve technology is a sleeve that is

characteristics. The sleeve, once activated, fully opens regardless of whether or

not excess cement has been left in the lateral. The sleeve remains fully open as hydrostatic pressure is constantly applying an opening force, which is further secured with internal body-lock ring. The sleeve offers an alternative to costly TCP operations and allows for

The next generation: cemented sliding sleeve toe valveThe T1026 ORIO™ toe valve is a hydraulically actuated, hydrostatic-operated sliding sleeve, which is run at the bottom of a cemented casing completion. And, once activated, it is always open. Injection is established and subsequent treatment operations,

designed for a cement environment and functions properly regardless of the amount of excess cement left in the casing.

Unlike previous generations of toe sleeve, this tool is designed with three layers and not two. The only part of the tool that moves is the middle layer, thus mitigating the risk of premature opening while both running in the hole or during the cementing operation.

The patented middle layer piston is protected with

required to rupture one of the disks. When one or both of the disks burst, pressure enters into the middle layer and acts to push the middle piston down into the atmospheric chamber,

On previous generations of toe sleeves, the innermost piston moves within the inner diameter (ID) of the tool. This design is susceptible to both premature opening during the cementing operation and also failure if tail or residual cement is left in the low side of the casing. The new design mitigates that problem by having three layers. With the three layers, the middle layer moves into the protected atmospheric chamber. Excess cement does not affect the tool at all.

The utilisation of rupture disks allows the tool to actuate at very precise opening pressures. The pressure can be pre-set to within 2% of required actuation pressure. The surface actuation pressure is simply the disk rating minus the hydrostatic pressure in the casing at the tool. This

20 000 psi prior to actuation.

Field trials: Eagle Ford, Utica and Woodbine playsThe ORIO toe valve has been employed in almost every North American shale play, and internationally in China, Russia and Australia. The tool has been tested more than 300 times and by more than a dozen operators and has shown to save anywhere from US$ 80 000 to US$ 120 000 per well.

Utica and Woodbine plays. A total of 62 wells were reviewed. The wells were horizontal, with lateral lengths ranging

Figure 1. Top illustration: ORIO toe valve in closed position. Bottom illustration: ORIO toe valve in open position.

Figure 2. ORIO toe valve stimulating the production zone.

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from 4500 to 9000 ft in length. The tools were run on either 4.5 in. or 5.5 in. casing.

established allowing wellbore cleanup and subsequent plug and perf operations.

from being tested. The data captured illustrated designed opening

Next generation toe injection sleeves

eliminate the need for the costly and time-consuming use of CT or

opening pressures.

well. O T

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All over the worldOur membership combines the brightest minds in the E&P industry, giving you access to new people, new places, and new ideas from all over the world.

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Figure 3. T1026 ORIO™ toe valve.

Sean Hollis and David Brown, CSI-Technologies, USA, show

how common well repair problems can be

overcome with an engineered

sealant.

Time is not kind to wellbore equipment. Equipment like casing,

tubing, packers, control lines and wellheads can degrade over time due to operation in harsh environments. Corrosion and unplanned equipment failure can result in leaks, which require repair to protect the environment, maintain well productivity and ensure regulatory compliance.

Every year, hundreds of wells located on the Gulf of Mexico shelf develop leaks. These leaks can be located virtually anywhere in the well and under a variety of conditions. A large number of these are very costly to

are on wells that have been plugged and abandoned or on

this type of well is extremely uneconomical and is avoided as much as possible by operators. However, the issue poses operational problems, environmental hazards and regulatory compliance concerns.

A range of conventional options is available for repair, ranging from cement to mechanical solutions. Leaks in

wells can be in a variety of areas such as packers,

wellheads, cement plugs, primary cement, control lines

and other areas. Many of these areas provide significant sealing

challenges that are either too costly to repair with cement or mechanical devices or simply cannot be repaired by these methods. This issue creates the need for an easily applied, economical sealing solution that provides significant benefits to the operator. A unique and effective sealing solution has been proven to be effective in repairing a wide range of leaks in wells. This solution is a unique resin sealant that does not require a rig and can be placed in the well quickly and easily.

Novel sealant A simple solution to satisfy these sealing needs is the use of unique two-part resin sealant. This sealant has many characteristics that make it an ideal choice for sealing unique and difficult leaks. It provides excellent mechanical properties, unique placement options, and allows variable densities and cure times.

65


The resin sealant possesses mechanical properties that make it extremely effective at sealing leak paths in a wellbore. Many wells contain high wellbore stresses that can cause other sealing materials to fail. The resin sealant has over twice the compressive strength of a typical cement system1 and over six times the tensile strength.1

of the resin. The Young’s, or elastic modulus of the resin is extremely high. This allows the resin to deform under changing conditions without failing. It will also return to its original size and shape once the stresses are removed. The resin also has great shear bond qualities. This allows it to adhere and maintain a strong bond with casing, cement, and many other materials. The combination of these excellent mechanical properties allows the resin to maintain its seal even under extreme stress conditions.

The resin sealant is impervious to water or brines.1 This quality allows for more and

quite often a production packer between the production tubing and the casing will have a small leak. The leak is small enough to prevent sufficient circulation around the leak path but large enough to necessitate sealing. This essentially prevents the placement of typical sealing materials such as cement, but it is not a problem for the resin sealant. Because of the impervious nature of the resin, it can be pumped into annulus from the surface and allowed to fall on top of the packer. The resin sealant does not need to be pumped down to the packer as it will fall in a ‘rope’ through the annular brine and puddle on top of the resin. This method of placement has been proven to be very simple and effective.

The resin sealant is also impervious to gases. Many times, a sealant is needed to stop and seal bubbling gas. When the resin sealant is placed on top of a gas leak, the gas will bubble up through the resin until the resin develops enough gel strength to prevent any further gas intrusion. The resin is unaffected by the gas and does not allow the formation of channels like in cement. Once the gel strength of the resin sealant overcomes the gas bubbles, the resin continues to cure and form a solid, channel-free seal.

The density of the resin sealant can be adjusted by adding various lightweight or heavyweight additives. This allows the resin to have a density that can range from 7.0 ppg all the way up to 19.0 ppg. The use of weighting agents is useful in the leaking packer mentioned earlier. The resin sealant density must be weighted above the weight of the annular brine in order to ensure it falls to the top of the packer. While these additives add solids, the base

resin sealant is a solids free fluid. This allows it to be squeezed into extremely small openings and flow paths. And unlike cement, the resin sealant does not suffer from fluid loss or dehydration. This means the resin will cure regardless of the size, geometry and permeability of its flow path.

The cure time of the resin sealant can also be adjusted as needed. A wide range of downhole conditions can affect the handling and placement of any type of sealant. The resin sealant can be formulated to be

resin cures can be increased for squeeze applications or decreased for gas control.

All of these characteristics allow the resin sealant to provide a unique and effective sealing method. The resin sealant has been used in many applications such as to seal casing leaks, packer leaks, wellhead leaks, plug and abandon applications and many other applications. The successful placement of the resin sealant has been carried out with dump bailers, bullheading, pouring and by

may further the wide range of the resin sealant applications and placement techniques.

Field applicationA recent application for the resin sealant provided a very unique situation to seal. The well contained a control line that ran down the annulus of the production casing and production tubing to a subsurface safety valve. The top of the control line connected to a port inside the wellhead. This port connected to a nipple on the outside of the wellhead to allow pressure to be applied to operate the subsurface valve. This is a common setup in wells with subsurface valves. In this well, however, the production tubing and the control line had both parted 200 ft below the wellhead. Though the well was no longer under production, the operator of the well required the remaining control line to be

fully plugged in order to provide a barrier against formation pressure.

The well was located in shallow water in the Vermillion area of the Gulf of Mexico. The temperature at the wellhead

200 ft of the ¼ in. ID line would need to be plugged from the surface and the seal would have to be durable enough to withstand at least 3000 psi. Due to the narrow ID of the control line, a solution using resin sealant was developed. The low viscosity and solids-free formulation meant that the sealant could be pumped down this narrow opening without bridging or plugging. In addition, the physical properties of the resin sealant would provide an impervious barrier once setting inside the line. The resin sealant was designed to fill

Figure 1. Example of resin falling and roping through water.

Figure 2. Example of resin to seal a leaking packer.

Resin Plug

Gravel Pack

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200 ft of the ¼ in. ID control line. The required volume of resin sealant to fill the control line was only 1 gal. Due to the small volume of resin sealant as well as limited space and equipment on location, the placement of the resin sealant would be done with a hydraulic hand pump from a workboat.

The resin was designed and tested prior to the job to ensure sufficient placement time. No solids were added to the resin sealant to ensure it would flow easily through the small ID of the control line. Prior to pumping, the resin

sealant was mixed with an air-powered drill in a 5 gal. bucket. Once it was thoroughly mixed, it was then loaded into the hydraulic hand pump and pumped into the control line port on the wellhead. The resin was slowly pushed into the full length of the hanging control line. The slow pumping allowed the resin to build resistance in the control line as it developed gel strength and began to cure. Once the full volume of the sealant was displaced into the control line, the valve on the control line port was shut to keep pressure on the curing resin. A total of 36 hrs were allowed to pass before opening the valve to ensure the resin had fully cured. The control line was confirmed to be fully plugged, satisfying the operator’s requirements, and further repair operations commenced on the well.

ConclusionThe resin sealant provides an effective sealing method for a variety of well repairs. The excellent mechanical properties, wide temperature and density, adjustable set properties, the ability to fall through water and penetrate small voids gives the resin sealant a distinct advantage over other sealing methods. The resin sealant reduces costs by eliminating the need for a rig and other equipment. Field applications have proven the sealing ability of the resin sealant and future well repair projects will provide brand new challenges for sealing. O T

References1. Sabins, Fred, and Larry Watters. “Cement Alternative

Has Unique Properties.” E&P Magazine 4 June 2007: n. pag. Exploration & Production. 4 June 2007. Web. 01 May 2013.

The resin was designed and tested prior to the job to ensure sufficient placement time. No solids were added to the resin sealant to ensure it would flow easily through the small ID of the control line.

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Amir Mahmoudkhani, Kemira, USA, explores the advantages of green

innovations in defoamers for cementing applications.

Foams are stabilised dispersion systems containing gas as the dispersed phase and a liquid or solid or a mixture of both as the continuous phase. Most chemical additives needed to make

cement slurries are surface active molecules with an amphiphilic structure; on one hand soluble and on the other insoluble (or of limited solubility) in aqueous phase. This surfactancy is responsible for the stabilisation of air-liquid interfaces and the potential generation of excessive foam and air entrainment as shown in Figure 1. Such

additives, gas migration control agents and ductility improvement additives. Chemicals used to enhance cement grinding are also known to cause foaming to some extent.

Cement foaming, chemically entraining air in cement slurries to

of a conventional process. It can be viewed as an emulsion of air in the cement – water system or foam formation in the liquid phase and retained by the gel or solid network, or both. Origins of air in cement slurries include air already contained in the system and air entrapped during mixing. Reviewing literature on air entrainment revealed that it is clearly a complex process, which is affected by many factors such as the mixing regime, physical and chemical properties of oil well cements, water ratio and quality, dosage and properties of the foaming agent, other chemical additives and supplementary cementitious materials (SCMs), and a range of other parameters.

In well cementing applications, the reliable administration of defoaming chemistries is a key step in preventing excessive foaming

products that have been used in common operating conditions, often pose a risk to the environment. A new generation of ‘greener’ chemistries is needed either in liquid or dry forms to meet industry and environment regulations. Solid defoamers represent a particularly attractive alternative, as they are characterised by long term stability and ease of handling under severe climatic conditions.

Challenges with environmental regulationsCompliance with national and international environmental regulations

in the development of new, environmentally-acceptable chemicals. The most important institutions guiding these regulatory frameworks are (1) the US Environmental Protection Agency for US Gulf Coast/Gulf of Mexico and (2) the Oslo/Paris Commission (OSPARCOM) for North Sea and other European Countries. The OSPAR commission

to Pose Little Or No Risk (PLONOR) to the environment; some countries follow the guidelines more rigorously than others. Most of the service companies supply their customers globally; the need for greener technologies becomes a requisite to operate, as many state oil companies and international companies are looking into the North Sea regulations when establishing their environmental controls and legislations.

For the last few decades, the development of greener chemistries

69


Figure 1. Mechanism of foam stabilisation.

Figure 2. Systematic approach for development of green defoamers.

Figure 3. Graphical representation of foaming/defoaming patterns from FEAT data.

Table 1. Defoaming chemistries and their discharge conditions

Sample ID Discharge permits

Silicone A No

Silicone B No

Non-silicone C Yes (‘Yellow’ for Norway, ‘Gold’ for UK)

Non-silicone D Yes (‘Yellow’ for Norway, ‘Gold’ for UK)

necessary high performance standards and evolving restrictive regulations. Although one of the additives with the lowest dosage rate, defoamers and antifoams represent a particular challenge when looking into formulations with more environmentally-viable materials. There is a tendency to shift from non-biodegradable silicone based products. Non-silicone chemistries such as fatty alcohols, esters and phosphates that show less toxicity and better biodegradability, may represent viable solutions. However, the challenge of achieving a high performance and cost-effective product remains,

more strict and demanding. Kemira Chemicals is

global product safety requirements and promote greener, alternative chemistries without compromising

Using a systematic approach, different defoamer chemistries were evaluated for highly foaming systems. A series of non-toxic, biodegradable (more than

developed achieving ‘yellow’ banding for Norway and ‘gold’ for UK applications. In addition, a ‘Smart’ solid substrate with ‘green’ PLONOR banding was developed to be used as a carrier for the above chemistry. The ‘Smart’ dry technology is proving to be

of greener and even more cost-effective defoamers for cementing applications.

As shown in Figure 2, the process for development of green defoamers involves a systematic study and evaluation of active defoaming chemistries, formulating agents and diluents or carriers. Performance testing is also a key in development of green products

Testing methods for defoamersThere is currently no API standard for evaluation of defoamers for oil and gas cementing. Cementing service companies often use their own developed lab procedures, which often includes: Slurry preparation using API procedure.

Measuring slurry density using a mud balance or other methods.

Visual investigation of air-entrainment in cement for voids and channels.

Effects on other properties such as rheology, thickening time and compressive strength.

Comparison of performance against a defoamer currently used in the field as a benchmark.

A controlled approach has been developed for the evaluation of cement defoamers using a unique Foam and Entrained Air Test analyser (FEAT) and a more comprehensive blender foam test method that provide more insights into cement foaming and defoaming processes. More detailed description of the methodologies used can be found in the ‘References’ section of this article (Mahmoudkhani, 2011).

The blender test was designed to address the effect of shear rate, slurry volume and time on foaming during mixing of cement slurries. A clear protocol to evaluate densities of foamed slurries allow for much controlled testing and better reproducibility of the data.

Figure 4. Blender foam test data in the latex system. All defoamers are dosed at 0.2% BWOC.


June 2013

The instrument is temperature controlled, open atmosphere, and features an inline foam generation chamber to entrain air in the experimental media. Density is continuously recorded using a density

foamers, defoamers and antifoamers may be determined at any time by injection into the foam chamber. Figure 3 represents a schematic of the defoamer density–time curve obtained by the FEAT Technique.

curve with a downward slope (dinit to dmin) indicates the quickness with which the test media entrains air and foams. Defoamer is then injected at a chosen density or time noted on the graph. The initial density minimum (dmin) of the graph represents the time which the defoamer has begun to affect the media. The upward slope from this minimum (dmin to dmax) represents the quickness with which the defoamer acts upon the media to remove entrained air. The curve then generally peaks at the defoamer’s maximum effectiveness (dmax). An ideal defoamer would maintain the same density as the peak, whereas a real defoamer gradually loses effectiveness causing the

media.

Performance evaluationAs discussed earlier, a careful evaluation of the effectiveness of a product, either as an anti-foaming or defoaming agent, should

systematic evaluation requires separate testing under the different conditions. Both FEAT and blender tests were utilised here; while blender test evaluates defoamer capability on a cement slurry, FEAT analysis looks at the liquid mixing step prior to slurry creation. Non-silicone ‘green’ chemistries are then benchmarked to traditional silicone products.

Figures 4 and 5 show the blender and FEAT results for cement slurries with a gas mitigation control additive (a latex type product). For such a highly foaming latex, the selection of non-silicone products will be more effective than silicone chemistries and in particular a better option when defoaming properties are needed in the liquid mixing step prior to slurry creation.

cement slurries. They are often used at higher dosage in lightweight and ultra-lightweight cement slurries to provide adequate properties

Performance of silicone and non-silicone defoamers is evaluated

(PVA). As shown in Figure 6, silicone based defoamers were found to be not effective in PVA foaming systems, instead both non-silicone based defoamers exhibit superior performance as indicated by measured slurry density in comparison to the design density.

SMART dry defoamersLiquid defoamers are predominantly used in normal operating conditions, but dry defoamers are preferred in extreme climates, mainly due to ease of handling and storage, long term stability and uniformity. In dry defoamers, the active defoaming chemistry is loaded on the voids of a high surface area (solid) substrate. Consequently, the development of dry defoamers brings another level of complexity associated with the

Figure 5. FEAT analysis of silicone and non-silicone chemistries in the latex system.

Figure 6. Blender foam test data for API Class G Cement and PVA (0.9%) system. All defoamers are dosed at 0.2% BWOC.

Figure 7. Formulation of dry defoamers, effect of substrate structure on defoamer adsorption and release.

720

9701050

1330 12851400

adsorbent structure which strongly impacts defoamer release and subsequent performance. Although high surface area substrates (such as precipitated silica) are often chosen due to their high adsorption or loading capacities, they may lack performance owing to poor and slow release of the active defoaming chemistry from the

A careful selection of a substrate and active defoaming agent should address several aspects ranging from environmental


regulations and cost to operational conditions and practices such as dosage points, nature of additives used and the need of defoaming versus antifoaming functionalities. A solid substrate with ‘green’

release upon mixing in foaming media. Figure 7 illustrates the

(active defoamer uptake) and desorption (active defoamer release) kinetics to maximise performance.

on a low porous ‘smart’ substrate expecting faster release of the

dosages. It is noticeable how the liquid and ‘smart defoamer’ sample

defoamer.

ConclusionsAs local environmental legislations are under constant revision, it

challenge when chemical companies need to formulate effective

less. O T

References1. Mahmoudkhani, A., Bava. L., Wilson, B., “An Innovative Approach for

Macaé, Brazil.

Figure 8. Blender foam test on cement A slurry using 2% Dispersant and 20% Salt System. Liq (liquid defoamer), SD (Smart Dry Defoamer) and Dry (Traditional Dry Defoamer). Non-silicone liquid defoamer as active component.

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Oilfield Technology June 2013