oilfield technology october 2011

OILFIELD TECHN

OLOGY MAGAZIN

E OCTOBER 2011

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.energyglobal.com

VOLUME 04 ISSUE 07-OCTOBER 2011

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ISSN 1757-2134October 2011 Volume 04 Issue 07

Copyright© Palladian Publications Ltd 2011. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

On this month’s cover >>Oilfield Technology is audited by the Audit Bureau of Circulations (ABC). An audit certificate is

available on request from our sales department.

contents

| 45 | SCALE-FREE SHALES Ann Davis and Dewey Berger, Champion Technologies, USA, discuss how new frac chemistry prevents scaling in the Bakken shale wells.

| 49 | SUBSEA TRACER STUDIES Matt Wilson, Tracerco, UK, demonstrates different applications for radioisotope technology, to help offshore operators achieve effective pipeline flow assurance.

| 53 | TAKING FLOW ASSURANCE DOWNHOLE Terje Baustad, Emerson Process Management, Norway, explains how to reduce well intervention by taking flow assurance downhole.

| 56 | “HOUSTON, WE HAVE LIFTOFF!” Ian Anderson, Camcon Oil, UK, highlights the growing influence of digital artificial gas lift in flow assurance.

| 61 | PRODUCTION OPTIMISATION UPSTREAM AND ON STREAM B.A. Coward, Honeywell Process Solutions, UK, demonstrates the savings and benefits of using gas lift optimisation technology.

| 65 | SURVEILLANCE CHALLENGES IN EXPLOSIVE ENVIRONMENTS Willem Ryan, Bosch Security Systems, Inc., USA, introduces explosion protected video surveillance solutions in challenging environments.

| 70 | DECOMMISSIONING DIFFICULTIES AND DEMANDS Potential decommissioning expenditure in the UK Continental Shelf (UKCS) will be higher than initially forecast. Brian Nixon, Decom North Sea, UK, explains.

| 75 | HIGH PERFORMANCE, 1000 FT BELOW James Vultaggio, Trelleborg Offshore, USA, looks at the latest developments in syntactic foam insulation.

| 03 | EDITORIAL COMMENT

| 05 | WORLD NEWS

| 10 | INTELLIGENT INVESTMENTS Asia Pacific is rich in new opportunities. Richard Bailey, Executive Vice President for Asia Pacific, GL Noble Denton, explains.

| 16 | HUMAN CAPITAL OR HUMAN CRUNCH? Matt Underhill, Hays Oil & Gas, Australia, discusses global staffing in the oil and gas industry.

| 21 | THE WIRELESS EVOLUTION Mark Amelang, CGGVeritas Land, USA, demonstrates how cableless operations afford flexibility, HSE advantages, and improved imaging.

| 25 | NO CABLES ATTACHED The next revolution in land seismic data acquisition is here. Dennis Freed, FairfieldNodal, USA, explains.

| 29 | MWD RANGING Chip Abrant and Jonathan Lightfoot, Scientific Drilling, USA, consider ranging applications in the industry.

| 33 | THE PERFECT MATCH Claire Adam, Baker Hughes, UK, looks at concurrent drilling and completion fluid design and explains why an integrated approach improves well performance.

| 38 | THE TERRA INVADER Herrenknecht Vertical GmbH, Germany, goes offshore with modern hydraulic hands-off technology. Thomas Janowski explains.

| 41 | SHATTERING THE GAS CEILING Oilfield Technology Correspondent Gordon Cope, provides an insight into the controversial topic of fracturing, which has either revolutionised the energy sector in North America or imperilled its environment, depending on ones’ point of view.

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Contact Information >> Palladian Publications Ltd,

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‘Globalisation of energy demand’ is one of those buzz phrases that you can’t seem to avoid at the moment. The world’s energy balance

is certainly changing as surging demand in emerging markets, such as China and India, capture an ever greater share of the world’s oil and gas consumption. Nowhere is this more apparent than in China where annual car sales have increased from a meagre 2 million in 2001 to 18.06 million units in 2010. China’s Ministry of Industry and Information Technology predicts that by 2020 this figure will increase to 40 million units per annum with a total of 200 million registered vehicles on China’s roads by this date. In contrast, US annual sales have reduced from 17 million in 2001 to 11 million in 2010. For many of the world’s auto manufacturers China will soon become far and away their largest market. Mercedes Benz saw sales increase 115% in 2010 to 147 700 vehicles whilst Audi sold 227 900 vehicles, up 43%.

Clearly the challenge for the oil and gas industry will be to meet the escalating demand that will surely accompany such rapid expansion and which is by no means unique to China but is evidenced to a greater or lesser extent across all of Asia’s emerging economies. Whilst there are signs that saturation of car ownership, an ageing population and increasingly fuel efficient vehicles in the developed world are leading to a decline

in energy consumption, the overall global picture is of a tightening in the supply and demand balance that will inevitably lead to rising worldwide energy prices.

The Asia-Pacific region undoubtedly represents a significant opportunity for the energy sector that will only multiply as the ‘globalisation of energy demand’ gains an ever tighter grip on supply. This trend is identified in a recent report commissioned by the Economist Intelligence Unit and prepared by GL Noble Denton entitled, ‘Deep Water Ahead? The outlook for the oil and gas industry in 2011’. The findings of the report are discussed in this month’s regional overview beginning on page 10 of the issue. The article provides an insight into the challenges and opportunities facing the industry in this region and documents the increasing prominence of mega projects, often in geographically harsh locations, being pursued by a new breed of dynamic Asian internationalising NOCs, or INOCs, such as Malaysia’s Petronas or PetroChina. It certainly makes for interesting reading, as does our keynote article by Matt Underhill of Hays Oil & Gas, Australia, which begins on page 16 and provides a perspective on the thorny topic of recruitment; arguably an even greater challenge to the future of the oil and gas industry.

We will be attending the ATCE Conference & Exhibition in Denver, USA, later this month and look forward to seeing some of our readers there. O T

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world news

05OILFIELD TECHNOLOGYOctober 2011

inbriefMubadala Development, a strategic investment company owned by the Abu Dhabi government, has bought into a one-fifth stake of an oil exploration block in Tanzania, a nation that has yet to find any crude. Dominion Petroleum, the British oil exploration company selling the share, recently announced the deal.

However, according to analysts, the reason behind the US$ 23 million investment by Mubadala Oil & Gas, could be demand for natural gas.

“Although oil itself hasn’t been discovered in Tanzania, there are large reserves of natural gas, and that’s what is driving the interest in the country,” said Patrick Mair, the analyst for sub-Saharan Africa at the risk assessment group Control Risks.

Despite being the world’s fourth biggest oil exporter, the UAE has a growing need for natural gas to fuel its growing electricity demand.

GREECEIn a move that could raise up to e35 billion in revenues in the next two decades, the Greek government has approved plans for oil exploration and drilling in western Greece. The formal ‘open door’ invitation of interest to investors will be issued in January 2012 once procedures for seismic studies for possible hydrocarbon deposits have been completed.

ICELANDThe National Energy Authority of Iceland (NEA) has confirmed the opening of a second licensing round for oil and gas exploration and production on its continental shelf. The blocks on offer are in the Dreki Area, in the northeast, and the offer will remain open through to April 2012.

USAWith the Gulf of Mexico oil spill still fresh in many people’s memories, US authorities have announced they are looking to regulate the contractors of oil companies that work offshore, as well as the operators. “There is no compelling reason or logic not to do [this],” said Michael Bromwich, Director of the US Bureau of Ocean Energy Management, Regulation and Enforcement.

SRI LANKAAfter the discovery of a gas deposit by Cairn India Ltd, the country’s Petroleum Minister announced that Sri Lanka will soon tender for oil exploration in five blocks in the northwestern offshore Mannar Basin. Seismic data for the region reportedly shows more than 1 billion bbls of recoverable oil in a 30 000 km2 area. Sri Lanka produces no oil and is dependent on imports, which last year cost the country US$ 3 billion.

// Chevron // Solar oilfield project

// Mubadala Development // Tanzanian gas reserves

Overcoming cost overruns and delays, the US’s second largest oil company is now expected to unveil its solar oilfield project, which will serve as a showcase for the technology of Chevron-backed solar thermal company BrightSource Energy.

Chevron Corp. recently confirmed that three of its executives would attend the launch of the ‘demonstration project’ in Coalinga, California, USA, which is designed to use solar power to create steam to inject into wells to improve heavy oil flow. The project covers 26 ha., consisting of 7600 mirrors focusing sunlight on a 100 m tower.

Success in Coalinga would be a boost for solar thermal technology, as many other projects have been scrapped in favour of photovoltaic systems.

Under the agreement, which requires the approval of the Tanzanian government, the company will pay US$ 20 million for its stake and up to US$ 3 million of the costs of a seismic programme scheduled to begin this year.

Marné Beukes, an analyst at IHS Global Insight in London, noted that during the past year, smaller exploration companies have made a series of ‘significant’ gas discoveries and there are signs that Tanzania is considering plans to build an LNG plant.

East Africa is currently on the rise. Recently, China agreed to loan Tanzania US$ 1 billion to build a gas pipeline, and oil discoveries in Uganda are also helping to drive interest in the region.

However, there are concerns regarding threats to the offshore industry, as Somali pirates are moving farther down the African coast and up the oil production chain.

Marking the largest takeover by a Chinese oil company in North America, Sinopec has offered C$ 2.2 billion to buy Canadian firm Daylight Energy. The board is said to be supporting the deal, which must still be approved by shareholders and regulators.

Daylight is a junior oil and gas exploration company with large partially developed acreage in Western Canada. During the Q2 of 2011, the company produced 37 000 bpd, and reported oil and gas revenues of C$ 163 million.

“Chinese oil companies have signed around US$ 125 to US$ 130 billion in deals in the last two years, and I would expect they would do at least that much again in the next two years,” said Laban Yu, analyst at Jefferies in Hong Kong.

// Sinopec // Canadian acquisition

world news

06 OILFIELD TECHNOLOGY October 2011

diarydates30 October – 2 NovemberSPE ATCEDenver, USAE: [email protected]/atce

7 – 11 NovemberWorld Shale GasHouston, USAE: [email protected]

4 – 8 December20th World Petroleum CongressDoha, QatarE: [email protected]

16 January 2012 6th Annual Offshore Production Technology Summit 2012London, UKE: [email protected]

15 February 2012MTB Oil & Gas ForumDubai, UAEE: [email protected]

22 May 2012 MOC 2012Alexandria, EgyptE: [email protected]

23 – 25 May 2012OTE 2012Nanjing, ChinaE: [email protected]

// Anadarko Petroleum Corp. // Raising estimates

According to Canadian Offshore Petroleum (COP), the semisub Ocean Nomad has been on location at the Esperanza exploration prospect in block 22/15 of the UK central North Sea, waiting for a weather window to start drilling operations.

The Esperanza 22/15-D well marks the first to be drilled by the company under its UK North Sea joint venture with BG Group.

The well is designed to target light oil in the Palaeocene Forties sand.

Through paying an amount equal to 75% of the costs to drill the well, COP will acquire a right to purchase a 50% equity interest in the BG-operated block, which includes the Banks discovery.

After appraising the Camarao prospect, Anadarko Petroleum Corp., the largest US independent oil and natural gas company by market value, raised estimates of reserves at its offshore Mozambique fields.

In a statement, the company stated that the cumulative results of exploration have “substantially increased” the prospects of Offshore Area 1 of the deepwater Rovuma Basin. It is also confident the Windjammer, Barquentine, Lagosta and Camarao complex holds at least 10 trillion ft3 of gas – more than the proven reserves of the UK, according to BP Plc data.

“Our successful drilling programme offshore Mozambique continues to expand the already world-class resource potential of this frontier basin,”

// COP // Exploration prospect

Oil production has begun at the US$ 800 million joint venture Chim Sao project, offshore southern Vietnam. The project’s gross production rate is expected to level out at ~25 000 bpd from six wells.

Premier holds a 53% stake in the JV, Santos another 32% and PetroVietnam holds a 15% stake. In addition, the development includes a platform and floating processing, storage and offloading vessel.

Oil from Chim Sao, located about 310 km off Vietnam’s southern coast, will be exported via shuttle tanker and its gas will connect into the existing infrastructure via a subsea pipeline.

According to Santos, the group plans to undertake further exploration drilling and expects to add “significant resources to the project in the near future”.

// Premier Oil PLC // Oil in southern Vietnam

Vice President Bob Daniels said in the statement. “We are optimistic that our current resource estimates will increase, as we still have significant exploration and appraisal work ahead of us.”

Earlier, in August, Anadarko hired Technip SA and KBR, Inc. to design an LNG plant in Mozambique after appraising reserves in the Rovuma Basin. The partners, including Mitsui & Co. and Cove Energy Plc, may build as many as six trains, or LNG production units.

One of the partners, Cove said last year it would sell its 8.5% stake in the exploration venture to avoid development costs. Its shares jumped 11% to £0.74 in London.

According to estimates by Wood Mackenzie Consultants Ltd and Deutsche Bank AG, East Africa may hold as much as 40 trillion ft3 of potential gas resources.

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world news

08 OILFIELD TECHNOLOGY October 2011

// Oceaneering // New TQR facility in Scotland

All actions on the Chukchi Sea in the Arctic Ocean have been on hold until the litigation over the original Sale 193 EIS filed by environmental groups is resolved by the court. Work on a draft plan of exploration filed by Shell can begin once a decision is made.

“We believe the Chukchi plan we submitted in May is technically and scientifically sound, and we look forward to exploring this critical part of our Alaska portfolio in 2012,” Curtis Smith, a spokesman for the oil giant said.

The Beaufort Sea exploration plan has already received approval from BOEM, but this has now been appealed to the 9th Circuit Appeals Court by the environmental group, Earth Justice.

The US EPA has also issued air permits for Shell’s drilling vessels planned to be used in both the Beaufort and Chukchi seas, and those are still vulnerable to appeals.

According to Smith, Shell which has already spent “tens of millions” in advance preparation work, will not order a mobilisation for 2012 until a final ‘go/no go’ decision, expected later this month, is made.

Planning to drill in an area where oil has previously been discovered but not developed, Shell’s Beaufort Sea primary targets are in an area near Camden Bay, east of Prudhoe Bay. Since the company can take advantage of existing pipelines, the Beaufort Sea oil is considered to be the best prospects for near-term additions of throughput for the Trans-Alaska Pipeline System.

In the next couple of years, a new pipeline will be built farther east from Badami to the Point Thomson area, where ExxonMobil, BP and Chevron are working to develop a gas cycling and condensate production project.

In the long run, it is believed that the Chukchi Sea has prospects for much larger discoveries. However, extensive infrastructure will be needed, including a pipeline built from TAPS across the National Petroleum Reserve-Alaska and an undersea pipeline built 60 miles or farther into the sea.

Shell is not alone in the region: ConocoPhillips, Statoil and Repsol also have leases in the Chukchi Sea and are planning exploration.

// Shell // Facing appeals

TQR centre” explained Joao Melo, Test and Reliability Manager at Oceaneering Umbilical Solutions. “Part of this will provide a comprehensive ‘data shop’, generating analysis to add significant weight to our proposition as a complete one-stop-shop for umbilical manufacture, test and supply.”

The custom-designed testing machinery from AJT Equipment Ltd will permit technicians to study and understand corrosion and fatigue in umbilicals, with the aim to further increase their average 25 – 30 year lifecycle.

In addition to investing in equipment, the company also stressed the importance of recruiting, training and retaining talent. Greg Scott General Manager for Engineering, emphasised that Oceaneering “cannot stand still in [its] engineering capability.”

The company promotes student internships and partnerships with engineering colleges, and internally rotates engineers to extend knowledge.

It is part of the larger corporate vision of “sharing best practice across the company,” Houston-based Vice President, Chuck Davison explained.

On 21 September 2011, Oceaneering Umbilical Solutions opened the doors to its new test, qualification and reliability (TQR) laboratory in Rosyth, Fife, Scotland. An intimate gathering of journalists, local dignitaries, and local businesses were invited on a factory tour and student internship award ceremony, highlighting the company’s investment in ‘growing its own talent’.

The new 600 m2 TQR facility will house specialists to carry out performance tests to simulate the immediate and long-term stresses placed upon umbilicals in the challenging environments of the ocean floor, during the installation process, and even during the transportation of a 30+ km long chord from the factory onto vessels.

Previously much of this testing was subcontracted but the company has now invested US$ 2 million into its own TQR, a cost justified by the reassurance it will now be able to offer customers, who are increasingly more interested in risk-reducing data, statistics and results. The testing is carried out to industry standard ISO 135628-5.

“We have made a significant investment in new machinery for the

Oilfield Technology’s Cecilia Rehn at the TQR laboratory in Rosyth, Scotland.

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T he oil and gas industry has experienced a period of unprecedented volatility in recent years, with record prices followed by a crash and

subsequent recovery. High oil prices have led to a rise in exploration and production activity across the world, with the Asia Pacifi c region identifi ed as an emerging opportunity for the energy sector, both in terms of demand and supply.

In January 2010, GL Noble Denton, an independent technical advisor to the oil and gas industry, commissioned the Economist Intelligence Unit to research and publish a report that provided a unique view of the challenges that those working in the sector expected to face across 2011 and beyond.

Nearly 200 senior industry executives were questioned in order to provide insight and commentary as part of the report, Deep Water Ahead? The outlook for the oil and gas industry in 2011.

Those surveyed said they believed that the greatest opportunities for them would be focused in the emerging opportunities of the East, with the largest proportion of respondents (32%) identifying South East Asia as the most signifi cant region. That proportion rose to 58% when combined with China and the Far East.

10

Asia Pacific is rich in new opportunities. Richard Bailey, Executive Vice President for

Asia Pacific, GL Noble Denton, explains.

11

12 OILFIELD TECHNOLOGYOctober 2011

Australasia too has been identifi ed as a burgeoning region in terms of the opportunities it can offer the oil and gas industry. The rate of development in Australia’s upstream sector is expected to grow signifi cantly over the next 15 to 20 years, while the country is anticipated to become the second largest exporter of LNG by 2015. Currently, Australia’s top 10 projects total more than £100 billion of capital expenditure (CAPEX).

Large-scale projects such as Gorgon, Wheatstone and Ichthys are worth tens of billions of dollars. They have either already been granted environmental approval, or are expected to receive this soon.

These emerging markets have underpinned oil demand, boosting confi dence and enabling oil prices and capital expenditure to remain high. This confi dence in the sector was also highlighted by the Economist Intelligence Unit report, with the majority of survey respondents either ‘highly’ or ‘somewhat’ confi dent (76%) about their companies’ business outlook for 2011. This compares with just 8% who described themselves as ‘highly’ or ‘somewhat’ pessimistic. With the strongest demand coming from the East, it is no surprise that companies believe that their revenue growth will be increasingly focused on opportunities in the Asia Pacifi c region.

Natural gas Natural gas is one of the most important considerations for operators seeking to exploit opportunities in the Asia Pacifi c region. Asia is not just one of the largest consumers of natural gas; it is also considered the global hub for LNG design and component construction.

In the global context of rising energy demand, the report refers to natural gas as a key industry ‘game changer’, seen

as an affordable and relatively low-carbon source of energy also suitable for use in electricity generation. Its popularity has risen as Asia has sought to increase its supply options. While oversupply from US shale gas production and a surfeit of LNG (particularly from Qatar) has swamped the market of late, the report suggested that demand from Asia is expected to eat away at these reserves, with the impact expected to be a modest rise in natural gas prices.

The earthquake and subsequent tsunami in Japan in March this year impacted severely on the country’s energy sector, resulting in the need to import unprecedented quantities of LNG in the long-term in order to offset the loss of its nuclear power capacity. Already considered one of the world’s largest importers of LNG, demand is expected to rise further as a result. Much of the extra fuel is expected to come from Qatar, (see Figure 1), one of the world’s largest LNG producers, while other key suppliers include Russia (the island of Sakhalin, north of Japan), with important supplies also being generated from east Siberia and the Caspian region.

Workforce supply challengesWith LNG activity levels at an all-time high, a key challenge to the oil and gas industry in Asia is the provision of staff to supply growing demand for energy. Whilst there is an abundant supply of potential workforce candidates in the region, a lack of technical experience has proven a barrier to operations.

Some countries have started to address this challenge. Indonesia, for example, has openly enlisted in foreign technical expertise in order to maximise the potential results of technically challenging developments and the country is recognised for having a well-balanced approach to international involvement – more so than other Asia Pacifi c

Figure 1. Image courtesy of Ras Laffan Industrial City, Qatar. Qatar is one of the world's largest exporters of LNG, and is well positioned to help meet increased energy demand from Japan.

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countries. As with many developing regions, there is a high demand for project management experience. Malaysia in particular is home to several major LNG engineering projects, with a strong desire to attract technical expertise from around the world.

Meanwhile, the slowdown of activity in the Middle East as a result of political unrest has seen many Australian residents return to their home continent for employment, satisfying the high demand in this region for LNG, project engineering, and quality, procurement and construction personnel.

The rise of the Asian national oil companies The rise of the national oil company (NOC) has been a topic for discussion in the global oil industry for more than a decade. The Economist Intelligence Unit’s report found that rising energy prices and the growing scarcity of easy-to-access development opportunities have delivered greater advantages to state-owned companies than their international oil company (IOC) rivals.

In Asia, NOCs have emerged with a mandate to acquire steady supplies of oil and gas to ensure economic expansion continues uninterrupted, and IOC chiefs have identified this competition as one of the biggest corporate challenges in gaining access to new prospects.

Many IOCs understand that their relationships with NOCs are becoming increasingly important, with 34% of survey respondents holding the expectation that NOC policies towards IOCs will either be somewhat or significantly more restrictive across the remainder of this year.

NOCs themselves, however, are facing new forms of competition too. The new breed of Asian internationalising NOCs – or INOCs – have emerged as competitors over the past two years. Companies such as PetroChina and Malaysia’s Petronas, for example, boast healthy cash flows, self-sufficient, integrated operations and already function in a similar way to IOCs.

The report also acknowledged that in some cases, IOCs and Asian NOCs are collaborating in key resource opportunities. China National Petroleum Corporation (CNPC) and Petronas (Malaysia), for example, both won substantial stakes in five fields in Iraq’s first two licensing rounds, securing recoverable crude resources estimated at 13 billion bbls. The two INOCs joined with BP and Shell respectively in Iraq, forming formidable IOC-INOC partnerships that represent a potentially seismic change in the relationships between resource holders and foreign oil companies. For CNPC, exposure to its BP partnership will allow it to develop its own technical skills.

The report said these new market entrants have created consternation for NOCs and IOCs alike.

Australia The scale of projects in Australia in terms of CAPEX has the potential to run into tens of billions of dollars. Significant investment has been made into exploration offshore Northwest Australia in particular, while a number of gas discoveries have also been made in recent years.

Chevron, the company behind the development of the Wheatstone project, is extremely active in the region. A founding partner in the Northwest Shelf Venture, the company has been exporting LNG to customers in the Asia Pacific region for around 20 years and supplying natural gas to Western Australia for 25 years. Chevron is also leading the development of the Gorgon Project, Australia’s largest single

resource venture, with an expected economic life of more than 40 years from the time of start-up (scheduled for 2014).

Australia is also considered a growth centre by Shell. The company is developing large gas resources, while maintaining a substantial exploration portfolio off the coasts of Western Australia and the Northern Territory.

As the full-equity holder and operator of the WA-371-P permit, an area covering approximately 1000 km2 in the Browse Basin, Shell discovered the ‘Prelude’ gas field in 2007 and the ‘Concerto’ gas field in 2009. Between them, the fields have around 3 trillion ft of liquids-rich gas.

Tokyo-headquartered INPEX Corp. has also recognised the huge potential on offer in the Australasian region, working with joint venture partner Total to develop and explore the Ichthys Field in the Browse Basin offshore Western Australia. The field has the potential to be a world-class gas project, with the expectation for it to produce more than 8 million tpy of LNG and 1.6 million tpy of PG, with 100 000 bpd of condensate.

A floating production storage and offtake facility (FPSO) will be used to develop the field, with condensate transferred to a nearby FPSO via subsurface pipeline, where it will be treated and transferred to offtake tankers for export. Natural gas will be directed through export pipeline to onshore facilities for processing into LNG and LPG. A massive scale project, the mooring chain alone will take two years of the world’s production.

GL Noble Denton will work with the Queensland Curtis Liquefied Natural Gas (QGC) project, which is expected to supply more than 12 million tpy of LNG through the development of three LNG trains on Curtis Island. Gas will be supplied to the trains through a 500 km pipeline from the Surat Basin. The contract will see the company provide quality assurance oversight for the pipeline construction portion of the project, including onsite support to QGC to co-ordinate inspections.

With the rapid rate of development in Australia, labour availability is a critical consideration. Quick to recognise this however, the federal government has developed a range of training and re-skilling programmes aimed at bringing expatriate workers back to the region.

ConclusionThere are many uncertainties for oil and gas worldwide, influenced by the scale and cost of gas developments, the rate in growth of demand from China, the burgeoning opportunities in Australasia, the continued skills shortage and of course the risk of geopolitical conflict and natural disasters.

The growing importance of natural gas as a major energy source is demonstrated by the amount of investment being devoted to the sector across the globe, with increasing demand leading to new expansion and exploration projects around the world.

Meanwhile, Australasia and countries across the APAC region are becoming increasingly important in terms of the supply and demand of oil and gas worldwide. There is the expectation that the traditional global balance in activity will shift from Europe and North America to these emerging regions, where governments and state-controlled companies will play a major role in future activity.

These are all events that can influence activity and trends within the sector and, with plenty of exploration and development in the pipeline, it remains to be seen the exact role that these regions will play going forward. O T

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T imelines and cost blowouts on capital projects have been a major concern for CEOs in the oil and gas industry this year. The sheer magnitude of some of these projects

now means that their relative success or failure can have a material effect on the share price of the companies controlling them. Given that human capital is estimated to cost on average 30% of project value, it is without doubt mission critical to understand the supply and demand relationship within this, the most important asset in the world today – people.

This year’s Global Oil and Gas Salary Survey conducted by Hays Oil & Gas in association with Oil and Gas Job Search produced a wealth of much needed data and information, including not only salary levels and benefi ts data broken down by country, but also demographics and migration of skills within the industry.

At the time of writing, the oil and gas industry is going through a signifi cant period of growth, and rarely have so many countries and regions all been growing at such a rate.

It has been well documented that the developing world of the BRIC countries and others outside of the OECD are driving the ‘new economy’, and demand for oil and gas skills in these regions is undoubtedly at an all time high. However, since the turn of the year, there has also been a resurgence in demand from the more traditional regions of the industry; the North Sea, Gulf of Mexico and the Middle East. This has added to an overheated market and started to create skill shortages that will challenge even the most tenacious recruiter.

The issue that the industry now faces is whether supply can match demand for skills, both on a regional level as well as a global one. As with the demand for energy, the level of demand for skills is only going to increase. Of course the introduction of incentives and taxation to increase the use of renewable energy will temper that demand for oil and gas skills. However the EIA (Annual Energy Outlook 2011) estimates that the world’s energy needs will grow by a massive 50% between 2009 and 2035, and in the US in particular, 78% of this demand will still be met

HUMAN CAPITAL

16

Matt Underhill, Hays Oil & Gas, Australia, discusses global staffing in the oil and gas industry.

by fossil fuels (down from 83% in 2009). One can also assume that future consumers of energy will be more prudent in their use, however with the global population approaching 9 billion by 2035 (according to the UN World Population Prospectus 2010) this will surely only have a marginal effect.

Matching supply to the inexorable growth in demand is really where the battle grounds lie and the question that is occupying the minds of many of the industry’s stakeholders.

Supply of new talent into the oil and gas market is a complex mechanism, especially when considered against the backdrop of the world’s various competing industries. Hays has noted that free markets are adept at channelling money and the resulting resources to where it is needed most, and it is no coincidence that salaries in the oil and gas industry are currently running at a premium of 20% or more to other comparable industries.

With that said, it is important to consider that some of these competing industries will share many of the engineering disciplines that are present within those of oil and gas, and

will themselves be infl uenced by the same inherent demand that is driving energy – i.e. population growth. This battle has already commenced in Australia where oil and gas companies are slugging it out with those in mining, an industry with just as much at stake and arguably equally deep pockets. While this is good news for individuals, it is not so good for the project accountants who built their models based on labour cost estimates made before the pressure started to rise. At certain levels, salaries start to become uneconomical and will take their toll on the number of projects passing FID.

Therefore, the generation and development of skills (as opposed to hiring them in) is where many of the larger players in the industry are concentrating their investments. Technology Centres, company sponsored Universities and dedicated Colleges and courses are now becoming more common in the developing world as companies start to take a long-term stake in their own pipeline of skills. Brazil, India and China are the key recipients of such investment to date.

OR HUMAN CRUNCH?

17


The biggest impact on skills supply however is the ageing workforce. For many years the industry has been warning of signifi cant issues, with engineers who fi rst trained in the energy boom of the 1970s now approaching retirement. With the geographical focus of energy production changing globally, and more and more countries investing in their own long-term resources and supply chain, it is timely to analyse whether this is indeed the case.

Hays’ Global Oil & Gas Salary Survey 2011, conducted in association with Oil and Gas Job Search, provided salary levels and benefi ts data by country in addition to demographics and migration trends. It took data from over 11 000 industry professionals around the world, including demographic information, and as Figure 1 demonstrates, concern regarding the retirement of talent is unfounded when considered globally.

Figure 1 shows the breakdown of the sample pool by age compared to a demographic curve for the OECD nations, fi rstly in 2000 and secondly as forecasted for 2050. It indicates that the lower age brackets are being redressed at an equal rate to those being lost to retirement. Indeed the replacement ratio (those under 35 years of age compared to those over 50) is 1.31, which indicates a healthy number of new skills coming in to the industry and refl ects the fact that many of the nations coming into the industry for the fi rst time are focused on growing their own talent from the bottom up.

However, when looking at the same data for specifi c countries, the picture is not as reassuring. Figure 2 represents the demographics for those working in Australia, the US and the UK. Australia’s replacement ratio is 0.58, the UK’s is 0.78 and the US’s is a lowly 0.20. Thus, demographics is very much an issue in these countries.

So, what are the potential solutions for those organisations seeking to move forward with critical projects that face diminishing local talent pools and rising workloads?

Hoping the market will reset itself is one option, however like all free market economies any short fall in skills available will simply be refl ected in rising salaries. This has already been happening in both Australia and Brazil. In the survey results from 2011, Australia had for the second year running the highest salaries in the world at an average of US$ 143 700. Brazil’s salaries rose by a massive 12% in one year alone to just under US$ 100 000 equivalent. These will all add to project costs and may challenge many ‘Internal Rate of Return’ thresholds before projects pass FID.

This scenario of dramatically rising salary costs however ignores the ability of the market to migrate skills to where they are needed. (Both Australia and Brazil are faced with massive capital investment programmes, the key source of increasing staffi ng costs. However both also have barriers that have prevented the ‘free fl ow of skills’. In Australia tough visa restrictions play a part, as do stringent labour laws and to some extent remote work locations; and Brazil’s minimum local content and Portuguese language requirements both take their toll, ultimately providing upwards pressure on salaries.)

Figure 1. Percentage of oil and gas workers based on their age group globally.

Figure 2. Percentage of oil and gas workers in Australia, the US and the UK based on their age.

Figure 3. For many years the industry has been warning of signifi cant issues, with

engineers who fi rst trained in the energy boom of the 1970s

now approaching retirement.

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As we move through the second decade of the 21st century, recruitment markets are becoming more globalised. National boundaries, whilst still an issue to contend with are becoming less signifi cant. There is much evidence to suggest the market is already functioning this way. According to the Hays’ Global Salary Guide 2011, over 40% of those working in the industry are working outside of their home country. With over 6 million people estimated to work in the industry in total, this accounts for over 2.4 million currently residing overseas.

In times gone by, the vast majority of these would be experienced professionals working on lucrative expatriate salaries, enjoying one or more postings overseas before returning to their home countries. Yet today it is estimated that only a quarter of those working overseas are doing so under the tag of ‘ex pat package’. The remainder can be split evenly between those that have emigrated to reside in a new country, are globally mobile and working on local package short-term

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contracts, or are escaping low wages and/or standards of living in their own country of origin with temporary work in higher paying countries.

Any stakeholder of a major oil and gas project will be set up to resource from all of these talent pools: relocating internal staff to areas of demand; hiring temporary skills on contract to offset peaks in demand; and constantly seeking lower cost/better skilled labour from other locations to reduce costs.

Like most macro issues facing the industry, these are solutions best provided by multiple stakeholders in the industry working together. However, Hays has found that such collaboration is extremely rare and success limited. The reality will be that the industry’s leading/largest companies will provide most of the solutions working independently through signifi cant investment with the benefi ts cascading down the industry through suppliers and partners.

Sadly the investment required to set up your own university, or relocate multiple ex pats around the world to

fi ll critical roles is not available to most medium to smaller players. Consequently the majority of companies will have to rely on effective planning and astute hiring to meet this challenge.

This year Hays produced a white paper, ‘Bridging the skills gap’ that provides some assistance for those seeking to navigate their way through skills short markets. At its heart was a six-point plan:

Be flexible. Above all hiring needs to be pragmatic, both in terms of cost and quality.

Have a plan. Those that take a long lead in time to planning will benefit when shortages are at their most acute.

Create an employment brand. Gaining success in this regard allows the company to ‘punch above its weight’ when it comes to attracting talent.

Source far and wide. It is indeed a global market in oil and gas, and it is possible to find skills available elsewhere when they are in short supply locally.

Train and develop. Generation of skills will always take longer, but ultimately it is possible to reduce the dependence on external resources.

Focus on retention. It goes without saying the less you lose, the less you need to hire.

The combination of the size of investment currently being put into the oil and gas industry and the scale and number of subsequent projects underway as a result, are unprecedented. The latest resources boom will undoubtedly reshape the labour market as employers and the governments scramble to fi nd solutions to potential skills shortages. If you have not started to think about how you might fi nd the staff you need to deliver on plans, now may be a good time to start. O T

THE WIRELESS EVOLUTION

Mark Amelang, CGGVeritas Land, USA, demonstrates how cableless

opera

tions afford flexibility, HSE advantages, and improved imaging.

In June this year, a highly unconventional 2D seismic data acquisition was conducted in Mississippi, USA by CGGVeritas. Typically, an exploratory 2D seismic survey

is conducted in a sequential manner where individual lines of data are acquired as opposed to multiple lines shot simultaneously, as is the case with 3D data surveys. However, after more than two months of collaboration with the client and extensive modelling, an alternative 2D design

was proposed to take into consideration the local terrain, the imaging objectives, and the permitting restrictions, which included acquiring partial data on multiple lines that were spaced several miles apart from each other. The survey utilised both explosive and vibroseis energy sources, 4865 receiver points, and covered 148 miles in a densely populated city, residential communities, thick forests with major undergrowth, and commercial areas with

21


traffic and noise pollution from the local airport and highways. In the past, an acquisition of this magnitude would have been prohibitive from both an environmental and operational overhead point of view. However, with the evolution of ‘next generation’ wireless technology, crews now have the flexibility to adapt easily to the changing landscape with less invasive methods than in years past.

Two decades ago, the first radio seismic recording system entered the market and was widely accepted as an alternative to traditional cable-based systems designed to address obstacle avoidance and environmental sensitivity. The design was rugged and durable, but very large and bulky in comparison to today’s cableless equipment. The heavy casings were made of metal instead of the thick plastic manufacturers prefer now, and rather than being truly cableless, the ground units were connected to one another in clusters. While this certainly reduced the amount of cable deployed and simplified troubleshooting, it was not truly a wireless system by today’s standards. Using radio frequency data transmission, which sometimes required a license, the older technology could provide status updates on the quality and health of the equipment, but it could not send data packets in real time back to the recording trailer for QC. To view the data and ensure the quality of the shoot, the electronics had to be removed from the spread and transported to a transcriber before a tedious download of the data could provide a glimpse of the quality of the programme. Or at a minimum, they were manually connected to a harvesting device.

The advent of today’s wireless technology, with its smaller, more portable and lightweight design coupled with its ability to work autonomously or in conjunction with other cable-based recording systems, solves two basic problems for the industry.

HSE drives innovationFirst and foremost, it provides a cost-effective, HSE-friendly solution to acquiring data in restricted areas where terrain or the local environment might preclude the use of legacy radio systems or would limit the accessibility for cable-based operations. As was the case for CGGVeritas in Mississippi, cableless equipment provided the flexibility for the crew to operate without ‘clearing lines’ through vegetation and forests, and without impeding daily life in an urban setting.

With a smaller footprint, cableless equipment enables crews to work in ecologically sensitive environments, such as protected wildlife reserves or in rugged terrain where it would be difficult to deploy cables over sheer cliffs or in deep canyons. It also eliminated the problem of receiver lines being disabled by damage to cables caused by livestock or heavy farming equipment, which reduces the amount of time spent troubleshooting and decreases the number of personnel required for the shoot. The reduction of operational overhead during a complex programme affords greater efficiency in terms of acquisition production and reduces the crew’s HSE exposure. With a compact design and reduction in equipment weight, HSE risk is further decreased, as cableless equipment does not require as many crew members to deploy and retrieve equipment.

The flexibility for E&P operators to now access previously restricted areas encourages exploration and development of hydrocarbons in new regions. In the Pennsylvania Marcellus shale play, for example, cableless acquisition has been the predominant choice for seismic surveys because the area is characterised by undulating terrain, expansive farmland, urban environments, and oil

Figure 1. An HSE-friendly solution to acquiring data in restricted areas where terrain or the local environment might preclude the use of legacy radio systems or would limit the accessibility for cable-based operations, provides the ideal flexibility for hydrocarbon exploration.


and gas infrastructure. The operational complexities of seismic acquisition in this region are difficult to mitigate using conventional systems.

Imaging complexity and flexibilityThe second problem cableless acquisition addresses is accommodating the more demanding imaging requirements for complex reservoirs. There is a tremendous improvement in subsurface image resolution as more channels of equipment are deployed and new operational methods such as point-source, point-receiver are implemented.

Cableless systems provide the needed flexibility to adapt to survey designs with unique geometries tailored to the subsurface that are not restricted by cable lengths and paths. Many cableless systems can work autonomously in conjunction with cabled recording equipment to accommodate infill requirements in areas where laying cable would have been difficult. Additionally, cableless acquisition is not constrained to pre-determined receiver intervals, therefore near and far offsets are easily accommodated without the burden of mobilising, or potentially underutilising, additional equipment. Cableless systems have given the industry the ability to truly maximise reservoir illumination by offering the flexibility to produce image-driven, rather than equipment-driven, survey designs.

A standard complaint among service providers about legacy wireless applications is the inability to QC data in real time, and the necessity to adopt the method of ‘shooting blind’. Because

equipment had to be physically retrieved thereby taking it out of production in order to harvest the data, observers could not validate data quality during the acquisition. Blind operating made it difficult to verify the data was of acceptable quality and within satisfactory levels of harmonic distortion. If the data is of poor quality, then E&P operators are limited in their ability to make strategic drilling decisions for field development and the area may require a costly reshoot.

One of the most innovative and operationally liberating features of this new generation of cableless acquisition systems is the ability to support remote data harvesting during acquisition. While many of the systems still utilise transcribers to gather the raw data, state-of-the-art systems provide the ability to review and/or harvest data during production, in near real time. Crew personnel collect data via drive-by utilising vibrators or standard automobiles, fly-by when helicopters are used to transport equipment, or walk-by during normal crew activities. In production, data harvesting is a unique advantage for geophysical service providers as it provides an opportunity to make near real time, in-field adjustments to the programme based on the ability to QC not only the trace attributes, but the actual raw data as it is being acquired. E&P consultants on the programme can quickly review the data and make recommendations about the programme, which ultimately saves time and money.

Additionally, as survey designs become more complex and require operations with cable and cableless systems, data reconciliation can be a real challenge. Several of the wireless systems enable master-slaved operations, however they are recorded on two different platforms and will require additional time during processing to integrate the data accordingly. The use of one recording platform in a truly seamless integration provides a single data set with one SEG-D file created directly in the recording truck. This also improves data quality as it removes any ambiguity about the time, location, and signature recorded from the source and sensors, and further ensures data integrity. Observers can quickly see the entire spread during the acquisition eliminating the risk of missed records due to master-slaved operations.

ConclusionThe advent of new generation cableless acquisition systems offers many advantages to the service companies collecting seismic data and the oil companies that underwrite and use the data acquired. These systems improve the quality of data, reduce the footprint on the environment, minimise the impact on local communities and improve overall safety for the workers.

In addition, cableless systems dramatically improve productivity in difficult or restricted access areas and in some cases allow for the generation of seismic data where it was not possible before. Improved productivity and seismic data reduces drilling and production decision cycle-time and decreases exploration and production risks, ultimately reducing the time and cost to first production – a large financial benefit for oil and gas companies.

The paradigm shift to image-driven seismic acquisition design, from equipment-driven seismic acquisition design, is beginning to change common precepts of survey planning. Reservoir illumination is improving as a result and that means more dollars to the bottom line, and that is good for the entire industry. O T

Figure 2. In production, data harvesting is a unique advantage for geophysical service providers as it provides an opportunity to make near real time, in-field adjustments to the programme based on the ability to QC not only the trace attributes, but the actual raw data as it is being acquired.

cablesattachedThe next revolution in land seismic data acquisition is here. Dennis Freed, FairfieldNodal, USA, explains.

Cutting the cord. Severing ties. Going wireless. However you describe it, the act of replacing what once seemed to be an integral part of an industry’s operations with technological advances is revolutionary. Think smartphones and laptop computers.

Now, new options can have the same impact on an industry long burdened by bulky, expensive, environmentally unfriendly cables: land seismic data acquisition.

The burdens of conventionA conventional cabled land system requires a monumental amount of equipment. Take for example a typical 4000-channel seismic acquisition system with receiver-station spacing of 30 m (plus 10%).

This system requires 132 000 m (132 km) of in-line cable to house telemetry twisted-pair wires and, in most instances, power wires. The in-line cable alone weighs 6000 kg. Add in 33 m of geophone strings, each with six geophones, and this totals 132 km of cable and more than 15 000 kg. At 58 kg each, the 84 required power stations add an additional 4872 kg.

NO

25


This 4000-channel 2D line requires approximately 264 km of cable and weighs in at close to 25 900 kg. That is slightly under 6.5 kg per channel. Add three connections to each receiver station – two for telemetry/power and one for the sensor – and one connection for each power station, and quickly more than 12 000 connectors are reached. Even without considering any cross-line requirements for 3D operations, this is a lot of equipment to protect and maintain.

Complicating matters is the fact that weight is not the only issue with seismic cables. Consider simple logistics. Cable must always be cut to specifi c lengths, or takeout intervals. When there is not enough cable, planners and contractors have to redesign the project to account for the limits of the equipment at hand. When there is too much cable, it must be piled or coiled between receiver stations. This requires extra equipment, creates an environmental and operational burden, and can lead to seismic noise problems due to leakage.

Finally, further complicating matters, cables are easily damaged by natural and cultural causes, and connectors wear out. This halts production and requires fi eld crews to repair or replace the defective cables and connectors. Troubleshooting the spread becomes a continuing challenge and expense. The more time seismic crews spend acquiring data and not having to make repairs, the more effi cient the operation. Lost production is lost time, and lost time is lost money.

Working with what was availableCable has always been a burden, starting with the very fi rst crew. Production required massive amounts of it, and that required heavy, cumbersome equipment for transportation across treacherous terrain, often in harsh weather. Cable also placed a burden on the land being surveyed and, ultimately, on the individuals who used the acquired data.

Using cables for seismic exploration became an accepted, common-sense choice, mainly due to the lack of alternatives. Crews needed to wire together large moving mass-coiled seismic sensors, called jugs, and connect them to a magnetometer to translate the earth’s physical motions into squiggles on graph paper.

Thankfully, times are changing. Today’s sensors, from highly sophisticated velocity sensors to cutting-edge accelerometers, have dramatically improved. Acquisition output has evolved from those raw analog squiggles to digital representations on magnetic and optic media. Still, despite the signifi cant technological advances, very little changed regarding the use of cable. The vast majority of seismic data acquisition systems still required tonnes of it.

The next logical extension Recently, geophysical equipment manufacturers began developing and introducing acquisition systems to make cables obsolete. These new options not only eliminate the telemetry cables that carry data from the various remote units to a central location, they also eliminate remote-unit power cables and the analog cables that transmit signals from the sensors to the remote units. Some include systems that eliminate the need for a string of geophones.

These new cable-free systems are commonly referred to as nodal data acquisition systems. Nodes represent one of the most important technological advances in the industry’s history. They are rightfully generating a great deal of attention from an increasing number of contractors and oil companies worldwide.

A pioneering real-world exampleFor some time, crews have used cable-free autonomous nodes for offshore seismic data acquisition. Fairfi eldNodal fi rst acquired

Figure 1. Cable repair shop in operation. Figure 2. True cable-free nodes are entirely self contained, with all essential components sealed inside.

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data for BP in the Gulf of Mexico in 2005 using its cable-free Z3000 system, a 4C marine acquisition system capable of operation to depths of 3000 m. Today, a 1000-node Z3000 system is acquiring data in the Gulf of Mexico for Shell. In 2009, the company deployed over 1300 nodes, using its 4C Z700 system, for a long-term acquisition project in the Red Sea. That same year, the ZLand, the industry’s only truly cable-free nodal system for use on land, was developed.

The autonomous FairfieldNodal ZLand nodes are similar in concept to the company’s proven marine nodes working deep in the Gulf of Mexico. They are completely cable free, with all

the essential elements needed to acquire seismic data – sensor, batteries, control circuitry, A/D converter, filters, memory and a highly accurate clock to maintain timing – contained within each lightweight, self-contained node. This approach allows the seismic contractor to offer clients ultimate flexibility in layout design, whilst simultaneously reducing their exposure to the many hazards posed by deploying a conventional system with its onerous bundles of cables.

Toward a cable-free futureSeismic contractors finally have options that simply were not available even just a few years ago. In addition to the cable-free systems pioneered by FairfieldNodal, there are a number of commercially available ‘minimal cable’ systems. These systems are somewhat similar to traditional radio telemetry systems, with some using radios to transmit quality control data to a central station or to a field data collection reader. The systems eliminate the need for telemetry cables interconnecting the individual seismic data acquisition units to a central recorder, but still require cables connecting the individual pieces of equipment, such as a battery and sensors to a remote unit, and their operation may require a radio license. These connection cables, however short, are also still prone to the same hazards as the conventional seismic cables of the past.

The movement toward cable-free land data acquisition is on. These alternatives deserve serious consideration as productivity and HSE demands increase. It is time for a long-overdue revolution and a transition to simpler, more effective means of acquiring critical data. O T

Figure 3. 1134 nodes staged for field deployment.

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MWD RANGING

Chip Abrant and Jonathan Lightfoot, Scientific Drilling, USA, consider ranging

applications in the industry.

T his article explores the signifi cance of MagTraC MWD Ranging™, the process of using sensor data from a measurement while drilling (MWD) system

to calculate the relative position between two wellbores. The raw data taken from the MWD’s three-axis sensor package is used to determine the location of magnetic interference in the earth’s natural magnetic fi eld. Magnetic interference, as it applies to MWD Ranging, refers to localised anomalies to the earth’s magnetic fi eld caused by a casing string and/or fi sh in a nearby well. During drilling operations, this is often referred to as a ‘hot’ survey, meaning that the survey tool (i.e. MWD) is detecting magnetic interference, normally due to the presence of positive and negative poles that exist near the couplings on the casing string. The range of detection varies, but a key advantage of MWD Ranging is that the necessary data to determine the distance and direction to the source of the magnetic interference is available from most commercial

MWD systems. Casing connection ranging calculation points are typically used as the key ranging shots, while drilling a ranging well for avoidance or intercept applications. Casing joints are generally 40 ft long, so the larger natural magnetic fi eld at each casing coupling helps to provide many data points while drilling the new wellbore to ensure proper spacing is maintained. In instances of close proximity, such as an intercept application, the MWD sensors detect detailed magnetisation along the entire casing string, not just near the couplings. Using the MWD Ranging process allows MagTraC services to quickly and effi ciently obtain a fi x on the location of the offset well without adding any costly bottom-hole-assembly (BHA) or wireline trips for special tools, as is required with some ranging systems.

Scientifi c Drilling International (SDI) has worked for many years to establish and develop the process and capabilities of MWD Ranging. The method was achieved by developing

Figure 1. Many mature fi elds have closely spaced wells.

29


proprietary algorithms within computer software used to model and locate an offset target well relative to the well being drilled, without having to run any additional sensors or equipment into the wellbore. Since MWD data is readily available on nearly all directional drilling applications, the MagTraC MWD Ranging service can be provided on a global basis with very short notice. In many instances it can be carried out entirely offsite on projects anywhere in the world – a service referred to as ‘remote MWD Ranging’, greatly reducing the logistical and commercial issues related to mobilising personnel and/or equipment to a remote well site. As previously mentioned, although MWD Ranging works extremely well with the Scientific MWD, it works equally well with all other commercial MWD systems.

MagTraC MWD Ranging has two broad applications; firstly in clearance and avoidance and, secondly, in intercept. Both of these will be discussed in more detail in this article.

Clearance/avoidanceFigure 2 depicts an example of avoidance when drilling a new wellbore next to an existing well. This offset parallel position technique is commonly called twinning or also occasionally referred to as hand-rail wells. Several applications exist where parallel wellbores in a productive zone can aid in the recovery of natural resources.

One interesting application referred to as ‘frac-recovery’ is the process of drilling a low-cost directional replacement well into the region of a costly fracture stimulation zone of an existing well that has been rendered nonproductive. On the west coast of the US, the usual cause of these well issues is related to either tectonic occurrences or to field subsidence that causes casing collapse at intermediate depths, resulting in inability to produce the well (rod pump) (Figure 1). It has proven to be cost-effective to drill a replacement wellbore placed in close bottom hole (across production zone) proximity to the original wellbore. Essentially, it is more economically effective to quickly and efficiently drill the new well into the old (target) well stimulated zone, thereby restoring production without having to frac the new well.

Another key application of MWD Ranging is anti-collision or collision avoidance. Today many operators are drilling multiple wells from a limited surface location such as pad (onshore) or template (offshore). In some cases, these onshore project sites now have in excess of 60 wells per pad, similar to congested platform templates in the Gulf of Mexico and the North Sea. As the number of wells drilled from the pad or template increase, subsequent wells to be drilled have the increasing challenge of getting clear of magnetic

interference while near the surface, and at times where another well is crossed at depth while drilling to target locations. Having access to MagTraC MWD Ranging offers additional confidence that the new wells are drilled accurately versus drilling blind while in the zone of extreme magnetic interference. Figure 3 illustrates the potential complexity of wells drilled from multiple pads, as well as a high density pad. The ranging process in this case is very much the same as the parallel well case except the new well will be steered to avoid the offset well, as opposed to intentionally staying close to the target well. Again, MWD Ranging helps to ensure that the offset well’s actual location is known, allowing the new well to be safely and efficiently drilled while greatly reducing the risk of an unintentional collision.

A subset of the anti-collision application is occasionally referred to as ‘ghost well’ avoidance. In many mature basins around the world it is not unusual to unexpectedly experience magnetic interference when drilling a new well. Often this magnetic interference is an indicator of an unknown offset well. An operator may choose to take the chance and drill ahead and hope that the unknown well ‘goes away’, or invest a few hours of rig time to collect the necessary data to allow for MagTraC MWD Ranging to be performed in order to locate the ghost well relative to the well currently being drilled.

Finally, there is an MWD Ranging application referred to as ‘kick-off assurance’. In instances where a wellbore is being directionally kicked off in proximity to magnetic interference, whether from below a shoe with offset wells nearby, such as a platform template, or from a casing exit (whipstock or section), MWD Ranging may prove invaluable to guide the directional wellbore away from the offset wells (Figure 4). This application is likely to continue to grow as the multi-lateral market increases and as continued field development in the tight, unconventional plays continues to require downspacing in order to optimise reservoir drainage.

Intercepts Intercepts are an exercise in exact well placement, where MagTraC MWD Ranging is used to intentionally guide the well being drilled into a direct collision with an offset (target) well (Figure 5). Two of the most important applications of intercept wells are plug and abandonments (P&A) and relief wells. P&A wells are those requiring permanent abandonment without the ability to access the required plug depths through the wellbore, thereby not meeting regulatory abandonment requirements. A relief well refers to a remedial well that must be drilled in order to access a well that has been compromised beyond control.

Figure 2. Three-axis sensor package in MWD detects magnetic interference from an offset well.

Figure 3. Requirement for multiple wells to fully monetise the reservoir coupled with minimum surface impact, results in closely spaced wellbores.


In all parts of the world, many wells exist that require permanent abandonment. In fact, for 2011 in the US, it is estimated that nearly 40 000 wells are to be abandoned. At some point in the future, all wells will require permanent decommissioning. The decision to decommission is usually made when production of the resource has depleted to a level of noneconomic flow, without any other remaining productive zones available or accessible. Many of these wells are uniquely challenged because access to the well’s productive zone(s) is limited or not available due to a variety of casing issues, such as uphole casing corrosion, casing collapse, or casing wear caused by rod wear and/or excess well intervention work.

P&A interceptIn the Permian Basin of west Texas, there have been many cases where operators have used the MagTraC MWD Ranging service to successfully and permanently abandon wells to prevent future contamination of fresh water aquifers and other intervals exposed when the well was originally drilled. In these cases, after conventional remedial steps proved to be uneconomic and/or unsuccessful due to casing issues (corrosion, collapse, etc.), the problem well can be exited above the casing problem and guided to an intercept point below the problem. In some cases a new well is spudded nearby (typically 30 to 100 ft of surface location offset) and drilled directionally toward the well requiring abandonment. MWD Ranging is performed in order to guide the remedial well to intercept the older, damaged (target) wellbore at the appropriate depth(s). Once the casing of the target well is encountered, access to the target well is accomplished by either milling through the casing, or in many events, perforating into the casing to establish hydraulic communication allowing cement to be pumped. During these operations it is important to communicate with the appropriate regulatory body to ensure that all regulatory requirements for abandonment are met.

Relief wells are among the most challenging type of ranging application because of the urgent, and sometime high-profile nature to regain control of the well and minimise environmental impact. MWD Ranging proves valuable in these situations because it helps to efficiently drill a relief well that will intercept the target well, allowing for a permanent kill without requiring numerous round trips. The MWD Ranging service allows the relief well to be placed accurately and efficiently to the required depth of intercept. The faster that a relief well is placed in the appropriate position, the sooner hydraulic well control actions can be commenced. In the unfortunate situation when

wells are compromised, it is important to consider which technology should be used to quickly and efficiently resolve the problem and simultaneously minimise environmental impact and risk to personnel.

Remote operationsMagTraC is a global, rapid response service usable with any MWD system. The offsite, remote capability of this service is proven to be especially helpful anytime a standard magnetic MWD system has invalid surveys, as a result of being too close to another wellbore. When magnetic interference occurs, the MWD operator for any service provider can transmit the raw data values to a Scientific Drilling MagTraC Operational Support Centre, to get a target location of the offset well. The cost savings in this case are significant considering the alternative of drilling with no assurance and extra risk, or having to mobilise additional survey tools to reduce the positional uncertainty of the offset well(s) on location in an effort to find the cause. Lastly, Scientific Drilling provides planning assistance to help operators and other service providers better understand the ranging process and how it applies to their particular situation.

gMWD: magnetic and gyro sensorsUse of a gMWD (Gyro MWD) system further enhances the MWD Ranging process because the gMWD has both magnetic and gyro sensors in the same survey package. SDI’s Keeper gyro system provides the directional drilling team with an accurate measure of inclination and azimuth. The north seeking earth-rate gyro is unaffected by the magnetic interference caused by a target well’s casing magnetic field, allowing interference-free directional surveys and toolfaces during the close approach. This allows drillers to steer the BHA and eliminates the need to survey the well with a wireline gyro at the completion of the job. The magnetic sensor package records accurate magnetic field intensity measurements that are then used by the MagTraC software to calculate the position of the offset (target) well. The accuracy of ranging calculations continually improves as the well being

drilled moves closer to the target well. The combination of gyro and magnetic MWD coupled with MagTraC MWD Ranging allows an operator to drill new wells very close to others, with additional control and reduced uncertainty in the borehole position. This technology has become the industry standard for drilling wells on tightly spaced platforms and on onshore pad locations helping operators substantially reduce risk while also reducing surface impact. O T

Figure 4. Kicking off or Sidetracking a well in a congested area.

Figure 5. Intercepting a wellbore for P&A or relief well purposes.

PERFECT MATCHTHE

An impressive body of literature concerning drilling and completion fl uids has been accumulated and published over the last

several decades. The formulation and testing methodologies required to reduce risk and enhance productivity are much too specifi c to cover adequately in the space of one article. Therefore, this article will not focus on a specifi c design process, but will take an overview approach to the

main factors to be considered when designing a well fl uid programme, including reservoir geology, type of completion and stimulation considerations. A methodology will be demonstrated whereby the propensity to maximise reservoir performance is greatly enhanced when all wellbore construction variables are taken in account.

When drilling a well, effective fl uid design is a critical initial consideration. Varying geology

Claire Adam, Baker Hughes, UK, looks at concurrent drilling and completion fluid design and explains why an integrated approach improves well performance.

33


and completion types require different fl uid properties, and sometimes a single well can encounter a multitude of different conditions. All of these variables and their implications must be accounted for in the fl uid design.

A reservoir drill-in fl uid (RDIF) is a custom designed fl uid that is used to drill through the reservoir section of a wellbore. The purpose of this fl uid is to minimise the damage to the reservoir, which enables maximum production so that the well can generate the optimum return. To be able to do this, a fl uid has to be formulated to meet reservoir specifi c criteria.

Some of the basic attributes of an RDIF include fi lter cake deposition, fi ltrate invasion, fi ltrate compatibility and readily removable fi lter cake. The following is a brief discussion of each of these desirable characteristics.

Rapid deposition of filter cake The more quickly a fi lter cake is laid down, the less damage created in the reservoir. If the fi lter cake does not form quickly and effi ciently, fl uid and even whole mud can invade the formation, leading to extensive damage. To produce an effective fi lter cake, the fl uid’s solids must be the optimum size to bridge the formation pore throats. If the solids are too small to bridge, whole mud can enter the formation and if they are too large to form an effective bridge, a quantity of fi ltrate containing small solid particles can enter the formation; both conditions can cause extensive formation damage. An effective bridge will only allow clean fi ltrate to enter the formation, minimising damage — the optimum scenario.

Controlled filtrate invasion An effective fi lter cake will prevent excessive invasion of the fi ltrate into the reservoir. Clean fi ltrate is much less damaging than whole mud, but any fl uid invasion into the producing zone is not desirable and must be minimised.

Compatible filtrate Using a fi ltrate that is incompatible with the reservoir can cause instability in the wellbore, leading to mechanical problems. For example, many shales react with water, so inhibitors need to be used; oil or synthetic-based fl uids are another alternative.

Filter cake that can be readily removedThe fi lter cake needs to be easily removed when production is initiated so that the fl ow of oil or natural gas can be rapidly maximised. If the fi lter cake is not fully removed then some of the pore spaces will remain blocked, which will reduce productivity.

Reservoir studies optimise choicesTo achieve these requirements there are a number of factors for consideration. These include:

Type of formation: is it sandstone or limestone and what is the shale content?

The total length and tortuosity of the well path.

The type of completion that has been chosen (open or cased hole, screens, gravel pack).

Other factors to mention are the damage mechanism potential, the temperature and the annular hydraulics.

Figure 1. Filter cake destruction by applying mesophase post treatments.

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Navigation technologies now commonly used around the world. Based in Houston, Texas with operations facilities on six continents, SDI has a powerful combination of drilling professionals, experienced in both land and offshore jobs, and a deep portfolio of key innovative well placement and logging technologies – all readily mobilized to remote areas of the globe.

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Laboratory tests can be used to simulate the well conditions and, therefore, assist with the fluid design. It is then possible to test a number of options to ensure that the best fluid is used for each well. Experience can give insight into how different chemicals might react, but this approach can be unreliable. Specific testing on actual core will provide the most accurate information and lead to a fluid design that can reduce the risk of formation damage.

To further reduce drilling fluid damage, stimulation treatments can be used to disrupt filter cake integrity. Enzyme treatments are used with water-based RDIFs to break the polymers in the filter cake. Then organic acids can be formed in situ, their production delayed to allow various completion operations to take place before the filter cake is broken down. This delay mechanism also allows for the uniform destruction of the filter cake, ensuring the effective removal of a potential damage mechanism. A similar process can be used for oil-based filter cakes, using surfactants to change the surface wettability and organic acid to dissolve filter cake components, which stimulates production.

Testing for Ormen LangeThe Ormen Lange gas project in Norway required dedicated planning and fluid design. When it comes into full production, it will supply 20% of the UK’s gas requirement and will make Norway the second largest natural gas exporter in the world. Norway has very strict environmental legislation, and to minimise environmental impact the decision was made early on to use only water-based fluids. However, one downside of

Figure 2. Application of state-of-the-art investigative techniques to fully understand rock and fluid interactions.

using water-based fluids is the increased risk of gas hydrate formation when experiencing gas influx. The well conditions in this particular field exacerbate the problem with elevated hydrostatic pressure and low seabed temperature, inherent to the deepwater environment and the use of a subsea stack. These conditions instigated an extensive hydrate measurement programme and the use of saturated brines as the base fluid.

The RDIF technical requirements for this project were:

Minimal productivity impact.

Use of green or yellow chemicals (best environmental status, Norsok regulations).

Hydrate inhibition.

It was also required that the RDIF provide good hole cleaning, borehole stability and effective filtration control.

All of this was achieved with careful planning and extensive testing in a lab environment. Basic testing using API standard test procedures to optimise the fluid properties were carried out, as were thorough permeability, corrosion testing and compatibility testing. The resulting fluid formulations have allowed the trouble-free drilling and completion of the most productive gas wells in the world.

As drilling conditions become more challenging and environmental regulations more stringent, the fluid design for each well becomes even more critical and challenging. The investment of time and resources in the initial stages of the fluid design results in productivity optimisation, minimisation of downhole damage and environmental impact of the project. O T

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Figure 1. Impressions from the load test in the Port of Rotterdam – 250 t at the hook.

38

Herrenknecht Vertical GmbH, Germany, goes offshore with modern hydraulic hands-off

technology. Thomas Janowski explains.

The Terra Invader rigs are specifically adapted to customer and project requirements, offering high technical

standards based on offshore technology and a number of new developments. They are produced by Herrenknecht Vertical GmbH (a subsidiary of Herrenknecht AG), a company that designs and manufactures deep drilling rigs and equipment for wells down to 6000 m. Central features of the rigs comprise an optimised safety concept (hands-off technology) and flexible energy management, comprehensive automation of working processes to increase time savings, as well as integrated noise protection devices to benefit our environment. Since its foundation in 2005, the company started its business in the onshore deep drilling sector. In 2011, it took its first step into offshore with its modern hydraulic deep drilling rig type Terra Invader 250CL, named B-011, for Dutch customer Swift Drilling BV.

All deep drilling rigs are designed in such a way that a maximum degree of hands-off procedures can be realised. This reduces the risk of accidents on the one hand, and personnel costs on the other. For the Terra Invader 250CL this can be achieved, above all, by the automated pipe handling system.

This unique pipe rack provides the appropriate rods or casing on the catwalk at any time. The pipe handler picks them up and brings them directly into the well centre position where the hydraulic hoisting system takes over. This means that

The Terra Invader

39


the rig can be operated safely and with fewer personnel than conventional rope installations.

The control is semi-automatic and the pipe handling operator or the driller operates the system and the operations are documented in the electronic pipe book.

The complete pipe handling system is designed to handle drill pipes range 3 in super singles, drill collars and casings. The pipe handler is designed for picking up and laying down tubulars with a diameter of 2 in. to 24 ½ in. The maximum lifting capacity is 3 t.

Table 1. Project characteristics (North Sea/The Netherlands)

Project data Machine data

Location North SeaHerrenknecht Vertical Terra Invader 250CL

Drilling depthsUp to 6500 m (slim well)

Substructure Cantilever

Well diameter 3.5 in. Hook load 325 t

Employment

Oil and gas exploration, well cleaning/abandonment

Hoisting system1200 kW (1600 hp.)

Customer SWIFT DrillingTop drive performance

800 kW (1000 hp.)

Maximum tripping speed

350 m/h

Figure 3. Hyraulic pipe handler.

Figure 2. SWIFT 10 on its first location in the North Sea, 50 km west of the coast of Den Helder, The Netherlands. © Swift Drilling.

Pipe handling system in detail The basic idea is to have horizontal pipe boxes to fill up the

pipe rack. These boxes are placed beside the catwalk.

Within the boxes there are yokes. This is a steel frame in which multiple drill pipes can be stored.

Such a yoke is picked up with a pipe feeder system. The pipe feeder then transports the yoke to the catwalk, so that there are several pipes in an intermediate pipe storage installed beside the catwalk.

The catwalk picks up a single pipe and transports it to the hand-over position of the pipe handler.

The pipe handler then picks up the drill pipe and transports it from horizontal to vertical.

In the vertical position, the drill pipe is handed over to the elevator.

Afterwards, the pipe handler moves out of the well centre and the drilling process continues.

The Terra Invader 250CL is part of the SWIFT 10 jack-up drilling unit that was built by Swift Drilling, a joint venture between Fabricom Oil, Gas & Power and the Van Es Group, under commission of the Nederlandse Aardolie Maatschappij BV (NAM), which in turn is a joint venture of Shell and ExxonMobil.

The different parts of the SWIFT 10 were built all over the world and were brought together in the Port of Rotterdam in December last year for final assembly. In all, the construction and the engineering of the SWIFT 10 took approximately three years.

The drilling rig components of Herrenknecht Vertical GmbH were installed directly onto a cantilever at the wet dock in the port of Kehl, only 40 km away from the company headquarters in Schwanau.

This cantilever was then integrated into the ‘jack-up barge’, a movable offshore drilling platform with four hydraulically-movable legs.

The SWIFT 10 will be used to tap new wells and to work on existing installations. The platform is specially designed for use in the southern part of the North Sea. With only 50 to 60 crew members, it operates with a 50% lower headcount than a conventional drilling platform. Technically, it is adapted to the conditions in this part of the North Sea, with the automated pipe handling and reduced crane movements. Its first mission was situated in the ‘L13-block’ of the North Sea, located approximately 50 km west of Den Helder. SWIFT 10 has been shutting down a well definitively; good preparation for the more complex tasks to follow. Start of operation was on 27 May this year.

The second job of the jack-up drilling rig started at the beginning of September and consists of drilling a deviated development well with a measured depth of approximately 4800 m for gas exploration.

The SWIFT 10 will enable the continuation of exploiting the mineral wealth in the North Sea as efficiently as possible in the future. For years, the Dutch government has been pursuing a ‘small fields policy’, in order to preserve the large Groningen gas field. At NAM’s request, the SWIFT 10 was specially designed to exploit these small fields as optimally and efficiently as possible.

The Herrenknecht Vertical deep drilling rig from type Terra Invader 250CL, which is comparably light with a hook load of 325 t, can drill down to depths of 6500 m for slim hole wells and is therefore perfectly suited for the exploitation of these small fields with the SWIFT 10 platform. O T

Hydraulic fracturing, or fracking, has fundamentally changed the dynamics of oil and gas production in North America. As recently as 2005, gas production in the lower 48 states was 48 billion ft3/d, and annually dropping at a rate of 1 billion ft3/d. By

2010, however, it had climbed to 59 billion ft3/d. Much of that reversal can be attributed to the success of the Texas Barnett shale

play. Starting in the early 2000s, innovators such as Mitchell Energy began experimenting with ways to open up the gas-rich, but permeability-poor shales that lay beneath the Dallas/Fort Worth region. After much trial and error, Mitchell discovered that a large fracture using millions of gallons of water and hundreds of tonnes of sand was the key to releasing the gas. Today, thousands of wells produce approximately 5 billion ft3/d from the Barnett.

That success has led producers to focus on other shale plays, including Louisiana’s Haynesville shale, the Fayetteville shale of Arkansas, and Pennsylvania’s and New York’s Marcellus shale. ExxonMobil, for instance, has spent over US$ 40 billion to acquire land positions and production from shale gas (as well as other unconventional plays, such as tight sands and coal bed methane). Chinese oil and gas producer CNOOC recently paid Chesapeake Energy US$ 2 billion for its Texas shale acreage. Shell bought

SHATTERING THE GAS CEILING

Oilfield Technology Correspondent Gordon Cope, provides an insight into the controversial topic of fracturing, which has either

revolutionised the energy sector in North America or imperilled its environment, depending on ones’ point of view.

41


East Resources, Inc. for US$ 4.7 billion in a deal that includes a major land position in the Marcellus shale play. Chevron acquired Atlas Energy and its extensive Marcellus gas play holdings for US$ 4.2 billion.

IHS CERA, a consultancy, estimates that shale gas has more than doubled the amount of natural gas reserves and resources in North America, adding 1200 trillion ft3 of shale gas in the US and 500 trillion ft3 in Canada (to the 1300 trillion ft3 of existing conventional and tight reserves). By 2035, the Energy Information Administration (EIA) estimates shale gas could account for 16 billion ft3/d of production in the US, and 5 billion ft3/d in Canada.

Finding the right targetShale is a low permeability, fine-grained rock that contains varying amounts of carbonate, silica and kerogen (organic material). The gas forms when the host rock passes through high pressure and temperature regimes; the gas, which can be as high as 7% content, is adsorbed onto the surface of organic material, and dispersed in tiny pores.

However, because shale has low permeability, producing the gas is very difficult; it requires a multi-disciplinary approach, of which fracking is only one essential part.

High-grading shale gas plays is the first step. A 100 m thick shale can contain anywhere from 50 billion ft3 to 400 billion ft3 per square mile. Estimating gas in place is carried out through a combination of geochemistry screening of cores and chip samples, examination of mud logs for gas sniffs and well logs.

Mineralogy is also important; kerogen, or organic source material, can vary highly due to depositional environment, as can clay, silica and carbonate content. In addition to core and chip samples, explorers use resistivity, gamma ray, neutron density and sonic logs to determine silica and carbonate lithologies, and ECS spectroscopy measurements to measure clay content.

Experience has shown that shale gas production can be affected by the regional stresses and strains affecting the host rock. Areas of high stress, for instance, reduce potential production, while regions of low stress respond much better to fracking. A 3D seismic survey can extrapolate stresses measured near a wellbore over a larger exploration area.

Amplitude variation with offset (AVO) inversion of 3D seismic data allows for the creation of Poisson’s ratio (PR) volumes and maps which reflect the heterogeneity of the reservoir associated with grain size and mineralogy. A low PR level indicates a region with high quartz to clay ratio, which in turn signals higher porosity and gas content, ease of stimulation and higher production flows.

Bringing all the information together helps determine the ‘sweet spot’ for each shale, where production is highest. The best production from the Barnett shale, for instance, comes from regions that contain a high quartz to clay ratio, low stress and high kerogen.

DrillingOnce a prospective zone has been identified, engineers design a drilling programme to maximise production. Traditional vertical wells offer insufficient exposure of the wellbore to the reservoir; directional drilling must be used to increase penetration. Starting in the 1980s, steerable mud motors allowed drillers to control the direction of the well. The drill

bit on the bottom of the string rotates thanks to an attached turbine that spins from the force of circulating mud. By stopping periodically, the driller can measure the direction of the bit, then make corrections. Wells can be drilled horizontally for over 4000 ft into a reservoir.

Several advances have been made to directional drilling. In the mid-1990s, service companies began to develop rotary steerable systems (RSS) in which the drill string was kept rotating during directional drilling. The main component is the steering tool. There are two distinct types. A push-the-bit tool has a series of pads that rotate with the string and push on the side of the borehole and exert a force in order to deflect the bit in the direction the operator wants to drill. The point-the-bit tool has an electric motor that is offset on the drive shaft. The electric motor rotates in the opposite direction of the drill string, holding the shaft geostationary and keeping the tool face pointed in the desired direction.

The direction of the steerable tool is measured while drilling (MWD), using a directional module that measures inclination and azimuth using triaxial magnetometers and gravity sensors. The system contains a transmitter/receiver to send data uphole through the mud system and receive commands back downhole. Logging While Drilling, or LWD, enables the operator to keep the tool in the productive reservoir. RSS allows horizontal and directional holes to be drilled farther, faster. Not only does the company save up to 20% on the cost of drilling the well, it increases the amount of shale gas produced from the reservoir.

How fracturing worksAfter the horizontal wellbore section has been drilled and cased, a specialty service company is called in to oversee the hydraulic fracturing. Major frac service companies in North America include CalFrac Well Services, TriCan, FracTech, Baker BJ, Halliburton and Schlumberger.

CalFrac, based in Calgary, performed 2000 fracs in 2006, and 12 000 in 2010. “The exponential growth is due to the growth in horizontal wells,” says Chad Leier, Sales and Marketing Manager for CalFrac. “With a vertical well, we might do one or two fracs, but now, we might do 10 or more in a single horizontal well.”

Prior to arrival onsite, the service company puts together a frac plan. Chemistry technology specialists look at formation fluids and pressures, the type of rock, and then come up with a frac recipe. A frac fleet is then assembled and driven to site. A fleet is generally composed of six pumps, a fluid proppant truck, fluid tanks, a blender truck, and numerous worker protection vehicles. The frac fluid is mixed onsite. “Most of a frac is water, about 85%, then diesel and foam made from CO2 or nitrogen,” says Leier. “Additives might account for 1 l/m3.”

The target within the wellbore is isolated using packers, then perforations are made through the casing. The frac fluid is then injected at sufficiently high pressure to crush the rock into a fine matrix of interconnecting fractures. Concurrently, up to 300 t of sand or proppant is injected to help keep the fractures open. Service companies typically perform 10 or more fracs per well.

Operators are increasingly using microseismic surveys to monitor fracture stimulation. Sensitive geophones are lowered into nearby wells in order to record the noise caused by the expanding rock, giving feedback to the progress of the

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fracture. The information allows operators to determine the effectiveness of their fracture programmes.

ProblemsAlthough fracking has evolved into a highly efficient and safe technology, it faces many challenges. A single frac can use 1 million l of water, a serious drawback in arid regions. “Water is a focus for us,” says Leier. “We look at reduction, recycling, the use of hydrocarbon fluid alternatives and using produced water that is high in salt.”

A percentage of water from each frac is flushed back to surface, but it often contains contaminants and must be cleaned before it can be discharged to surface or re-used. “As part of water management, we look at recycling through microfiltration and RO, to the point where the water is clean enough to drink,” says Leier.

But a far greater controversy surrounds the nature of the frac fluid itself. Some of the chemicals used to enhance fracturing have been associated with cancer and officials are concerned that they may leak beyond the borehole boundaries and contaminate adjacent aquifers and drinking supplies. Authorities in Pennsylvania and Wyoming have discovered suspect chemicals in groundwater. In 2010, acting under a directive from Congress, the Environmental Protection Agency (EPA) requested chemical lists from nine major service companies, including Halliburton and Schlumberger. The EPA has also identified seven sites for case studies of potential impacts from hydraulic fracturing on drinking water supplies, including the Haynesville shale in Louisiana, the Marcellus shale in Pennsylvania, the Bakken shale in North Dakota and the Barnett shale in Texas.

At the White House, the Obama administration struck a panel and authorised its members to spend over US$ 20 million to assess the risks of fracking. Members include former CIA Director John Deutch, Environmental Defense Fund President Fred Krupp and Daniel Yergin, cofounder of CERA.

State governments have entered the fray. Michigan, Texas, Wyoming and Colorado have enacted legislation that variously calls upon operators to submit plans regarding where they are sourcing fresh water, what chemicals are being used in the frac water and the volume of water recovered.

New York’s Department of Environmental Conservation (DEC), which temporarily banned fracking of the prolific Marcellus shale, announced a new set of regulations in July. The new guidelines would continue the ban on high-volume hydraulic fracturing in the New York City and Syracuse watersheds, but allow the practice on 85% of Marcellus shale within the state. Where allowed, the guidelines emplace considerable restrictions, including enhanced well casing, water withdrawal permits, flow back water containment and disposal restrictions, and disclosure of all frac chemicals (subject to appropriate protections for proprietary information).

Other countries with shale gas potential are taking a cautious approach. After numerous protests in southern France, the French Senate passed a law banning hydraulic fracturing. Although the practice is widely allowed in Canada, the province of Quebec has banned fracking of the gas-rich Utica shale until it can be proven benign.

The US gas industry maintains that hydraulic fracturing has been safely used for six decades, but onerous and costly restrictions – and even moratoriums – could reduce or eliminate

shale gas drilling. “Protecting groundwater formations is a priority for us,” says Leier.

There are many controls in place regarding cementing and curing of the well casing. Replacing harmful chemicals is also being pursued. “We are working on green chemical additives, essentially commercial food additives, like guar gum,” he added.

Ironically, the success of shale gas may be its undoing. The growth in natural gas supplies has far outstripped demand, and that has had a dampening effect on the price of natural gas. While US production roughly meets consumption, North America has an integrated gas market, and over 10 billion ft3 arrives from Canada each day, saturating the market and filling up the 4 trillion ft3 of storage space long before the winter heating season starts. As a result, prices have tumbled from an annual average range of US$ 6 – 7 per thousand ft3 to under US$ 4, well below what many shale gas plays need to cover costs.

There are several ways to improve the price of gas. Some operators are shutting in production until gas prices improve. Another outlet for the gas is LNG exports. Cheniere Partners recently announced it is negotiating a long-term contract with a Chinese firm to add liquefaction facilities to its terminal in Sabine Pass, Louisiana. The plan is to build up to four liquefaction trains, each with a capacity of 700 million ft3/d, or 3.5 million tpy. Several companies are looking at building LNG plants at the Canadian deepwater port of Kitimat, British Columbia, in order to ship shale gas to Asia. Gas to power, or GTP, is also soaking up excess supply. Coal-fired plants in the US are already shifting to gas for baseload requirements, reducing their costs and carbon footprint at the same time. If federal GHG reduction legislation is enacted (such as a cap and trade bill, for example), GTP consumption could expand from 20 billion ft3/d in 2010, to 30 billion ft3/d by 2020.

In the meantime, exploration companies are switching away from gas and focusing on oil-rich shales. Targets include the Eagle Ford Shale in South Texas, the Bakken formation in North Dakota and Montana, the Niobrara shale in Colorado and Wyoming, and the Hogshooter formation in Oklahoma.

The Eagle Ford Shale produces liquid-rich natural gas. Approximately 1000 wells are being drilled and fractured in the formation every year.

In 1995, the USGS estimated that the Bakken formation contained 155 million bbls of technically recoverable oil. Today, thanks to the advancement of horizontal drilling and fracking, it estimates that 3.6 billion bbls could be recovered.

Apache recently drilled a 4000 ft horizontal wellbore into the Hogshooter and fracked the wellbore 20 times. Initial flow rates exceeded 1500 bpd and 3.2 million ft3/d of gas.

Purvin & Gertz, a consultancy, predicted that unconventional oil production from the Bakken, Eagle Ford, and other plays is expected to approach 900 000 bpd in 2015 and exceed 1.3 million bpd by 2020.

While industry participants estimate that the use of fracking is growing at over 20% annually, they are very much aware of the challenges to the sector and the work that they have to do to allay concerns. “Areas that don’t have a lot of traditional oil sectors, like France, don’t understand the process and put fracking on hold,” says Leier. “We must address that learning curve until they understand the facts.” O T

Interviews1. Chad Leier is the Sales and Marketing Manager for CalFrac Well Services.2. Don Santa is President of the INGAA.

New scale-inhibition chemistry, developed for hydraulic fracturing treatments in the brine and iron-saturated Bakken shale and introduced early this year, is

controlling chronic scaling issues long after flowback, replicating results of lab tests and solving a production problem that has plagued wells in the Williston Basin for decades.

In addition, independent tests in the lab of a large integrated oilfield service company found the new Bakken scale inhibitor does not degrade the carrying capacities of cross-linked gel frac systems, used widely to complete Bakken wells.

In most applications, the Bakken scale inhibitor is augmented by:

A broad spectrum biocide to treat bacterial contamination that can lead to souring of Bakken wells and corrosion of production system components.

SCALE-FREE SHALES

Ann Davis and Dewey Berger, Champion Technologies, USA, discuss how new frac chemistry prevents scaling in the Bakken shale wells.

An iron-control agent that reacts with the high amount of aqueous iron present in Bakken connate water to minimise the formation of iron carbonate and iron sulfide scales.

Post-frac monitoring of approximately 100 wells treated this year with the Bakken scale inhibitor has found residuals of the chemistry as long as 10 months after the wells were hydraulically fractured. No scale-related production failures have been reported at wells treated with the new chemistry, which is a blend of partially neutralised specialty phosphonates.

One of many Williston intervalsThe Bakken shale, which has been described by the US Geological Survey as one of the world’s largest continuous oil accumulations, is one of several petroleum-producing,

Figure 1. A chemist in Champion Technologies’ Dickinson, North Dakota, district lab, analyses a fluid sample from a Bakken shale well to test for the level of post-frac iron control still present.

45


sedimentary formations in the Williston Basin – among them the Lodgepole, Mission Canyon, and Red River – deposited by an ancient sea. Similar to the Williston Basin, the Bakken sprawls over parts of Montana, North Dakota, and South Dakota in the US and the Canadian provinces of Saskatchewan and Manitoba (Figure 2).

When the prehistoric sea withdrew from what is now the Williston Basin, some of the sedimentary geologic intervals it left behind trapped so-called sweet fluids; some trapped sour fluids. The common characteristic shared by all Williston formation fluids is that they are saturated with chlorides. Chloride content in Williston Basin geologic intervals is so high that wells are known to ‘salt off’, a condition in which production components become so heavily coated with scales of various types that blockages occur and corrosion mechanisms are activated. Scaling is such a problem in Williston Basin that operators frequently perform annular flushes in the wintertime to ward off scale-related production failures.

Wildcatters chasing the Bakken play drill vertically to depths of approximately 10 000 ft before turning the wellbore to the horizontal in a sandstone/dolomite geologic interval sandwiched between an upper shale and a lower shale interval (Figure 2). When a horizontal lateral in the middle sandstone/dolomite interval is hydraulically fractured, it yields light, sweet crude oil. The learning curve is steep in exploration frontiers as operators are not always certain which formations induced fractures are penetrating, so whether sandstone or shale is the source rock of Bakken crude is still under evaluation in some wells.

Producers also learned quickly that wells producing from the Bakken, just as wells producing from other formations in the Williston Basin, experience severe scaling issues. However, the composition of Bakken reservoir fluids resisted treatment with conventional scale inhibitors.

Bakken water chemistryField experience, combined with analyses of Bakken water chemistry, indicate Bakken shale wells are prone to calcium

carbonate and iron carbonate scaling. In addition, levels of iron concentration in Bakken reservoir fluids can exceed 200 ppm (Table 1).

Scale-forming conditions are triggered in Bakken shale wells as soon as fracturing water mixes downhole with incompatible formation water. Factors such as temperature, turbulence, pressure, CO2 content, pH, and concentrations of ionic species in the waters – which can vary wildly during fracturing operations, making accurate scale formation predictions extremely difficult – can contribute to scale precipitation.

Table 1. Bakken water analyses (ppm)

Bakken Brine 1 Bakken Brine 2 Bakken Brine 3

Na 90 822 93 353 92 236

Mg 1628 1920 1604

Ca 18 320 18 160 17 680

Sr 0 0 0

Ba 0 1 0

Fe 221 236 197

HCO3 232 134 220

SO4 289 281 289

Cl 176 853 181 388 177 839

pH 6.5 6.5 6.6

Figure 3. Bakken stratigraphy.1

Figure 2. Bakken map.1

Some parts of the Bakken formation contain as much as 50% clays. Dissolution of minerals in the reservoir can mobilise clays, which can plug pore throats of the formation and/or lead to significant formation damage during flow back. As mentioned above, due to the Bakken’s high levels of soluble iron content, iron sulfide scale (a known plugging agent) and iron carbonate scale can form as a result of metabolic activity by sulfate-reducing bacteria (SRB).

Scale inhibitors that had demonstrated their effectiveness in other US shale plays proved to be no match for the high brine, high iron, high calcium carbonate conditions of the Bakken shale.

New scale-inhibition chemistryIn late 2010, Champion Technologies embarked upon an intense research programme to develop new scale-inhibition chemistry that was compatible with gel fracs and capable of maintaining effectiveness in hostile Bakken reservoirs:

Dynamic Scale Loops (DSL) apparatuses were used to evaluate the performance of scale inhibitors on synthetic brine containing more than 200 ppm of iron.

A static bottle test was used to test the efficacy of inhibitor chemistries on both calcium carbonate and iron carbonate.

Compatibility testing of scale-inhibiting chemistries was performed using a synthetic non-scaling brine with scaling anions omitted to avoid interference with scale formation.

In the DSL tests, two scaling brines (one anionic and one cationic) were injected at equal rates into the apparatus where they passed through heating coils before mixing at a T-junction and passing into a scaling coil. An increase of differential pressure across the scaling coil indicated scale had begun to form and adhere to coil walls, reducing the coil’s capacity. Differential pressures were

recorded as a function of time and the blank scaling time was determined for each test brine. In a repeat test, each scale inhibitor was dosed into the anion flow and its concentration progressively reduced until scaling was observed during the test period.

To create anaerobic conditions for tests performed in the presence of iron, a nontraditional oxygen scavenger was added to the cations and both the cation brine and anion brine were purged with nitrogen for about 60 min., both before and after the addition of iron.

Although the Bakken brine chemistry had the potential to form both calcium carbonate and iron carbonate due to the high


levels of iron, the DSL did not differentiate among the scales that formed within any individual brine formulation. Furthermore, static bottle tests were performed to determine the efficacy of the scale inhibitors on both calcium carbonate and iron carbonate.

Static bottle tests were conducted at 90 ˚C (194 ˚F) using the same brine chemistry as in the DSL testing. Samples were dosed with a nontraditional oxygen scavenger and purged and blanketed with 1% CO2 in nitrogen to prevent iron oxidation during testing. A vacuum oven was used to further reduce the risk of iron oxidation.

Synthetic, non-scaling brine was used for all compatibility testing. In order to avoid interference of scale formation, the scaling anions were omitted. Samples of brine were dosed with experimental scale inhibitors at concentrations of 1%, 5000 ppm, 1000 ppm, and 500 ppm. The brine and inhibitors were mixed thoroughly and placed in an oven preheated to 90 ˚C (194 ˚F). Compatibility was rated by way of visual inspections at specified time intervals. Decline of solution clarity and/or formation of precipitates were considered to be signs of incompatibility.

Within weeks, researchers amassed evidence indicating that three trial scale-inhibitor chemistries based upon blends of speciality phosphonates could maintain effectiveness in the Bakken, despite the formation’s chronic scaling

tendencies and high concentrations of iron. Subsequent independent testing by an integrated service company – a leading provider of cross-linked gels for Bakken fracs – concluded the new scale-inhibition chemistry does not interfere with the performance of cross-linked gel systems.

Performance confirms lab findingsApplications in the field since the new Bakken scale inhibitor was deployed commercially early this year have fulfilled the performance promised by lab work.

Blended phosphonate scale inhibitors are being injected as a constituent of Bakken frac fluid in concentrations ranging from 480 ppm to 650 ppm, depending upon the characteristics of Bakken strata in the vicinity of the well or customer specifications. Treatment of frac water with the new scale inhibitor is recommended in combination with:

A broad-spectrum biocide, either on-the-fly or in frac tanks prior to treatment, particularly if the frac water has been static for several days. Bacterial contamination in Bakken wells can include, but is not limited to, acid-producing bacteria (APB), sulfate-reducing bacteria (SRB), and

slime-forming bacteria (SFB). Alternating biocides helps keep frac tanks clean. If not treated, bacterial contamination can lead to reservoir souring and corrosion.

An iron-control agent to minimise the formation of iron carbonate and iron sulfide scales. The iron-control chemistry must be compatible with cross-linked gel frac fluids.

Post-frac performance of the Bakken scale inhibitor is verified with a check list of sampling and testing procedures conducted at each treated well in accordance with industry standards. Each well treated with the new scale inhibitor is subjected to:

Monthly testing for scale inhibitor residuals, up to 14 months following hydraulic fracturing.

A complete water analysis, beginning in the second month following hydraulic fracturing; then monthly for the first three months and quarterly for a year if no problems are detected.

A bacterial enumeration using the API serial dilution method one or two weeks following hydraulic fracturing, then quarterly for a year.

Elemental analyses by inductively couple plasma (ICP) are used to help measure the cations in water samples. Ion chromatography (IC) has been added to test for anions in water samples and to help measure scale inhibitor residuals.

Table 2 shows the results of monitoring for post-frac scale inhibitor residuals at several wells. Post-frac data from wells fractured with the new Bakken scale inhibitor show much higher levels of residual scale inhibitor than competing scale-inhibition chemistry over the same time periods, well above the minimum effective dose (MED) of the new scale inhibitor.

Similar post-frac monitoring is under way at about 100 wells treated with the new Bakken scale inhibitor during hydraulic fracturing. Some of the wells are still showing scale inhibitor residuals above the MED rate after 10 months. Empirical data obtained from these Bakken wells substantiate the findings of researchers who developed the scale-fighting chemistry and no scale-related production failures have been reported. O T

Reference1. Energy Policy Research Foundation, Inc., The Bakken Boom: An

Introduction to North Dakota’s Shale Oil (3 August 2011).

Table 2. Monitoring post-frac

WellWeek after frac

Champion technologies scale inhibitor residuals (ppm)

Competing technology (ppm)

I

1 < 1

2 5

3 3

II

1 n/a

2 60

3 48

III

1 n/a

2 20

3 7

IV

1 113

2 92

3 80

V1 n/a

2 77

VI1 n/a

2 79

Figure 4. A Champion Technologies’ field technician on location at a Bakken shale well in the Williston basin of North Dakota monitors concentrations of scale inhibitor, biocide, and iron control agent injected on-the-fly during a hydraulic fracturing treatment.

SUBSEA TRACER

STUDIESMATT WILSON, TRACERCO, UK,

DEMONSTRATES DIFFERENT APPLICATIONS FOR RADIOISOTOPE TECHNOLOGY, TO HELP OFFSHORE

OPERATORS ACHIEVE EFFECTIVE PIPELINE FLOW ASSURANCE.

The rising demand for fossil fuels has resulted in an increasing number of subsea pipelines for the transportation of oil and gas. This, in turn, has led to

the development of different applications for radioisotope technology, to help offshore operators achieve effective pipeline fl ow assurance.

Well-established and radiologically safe techniques are not dissimilar to the way in which the medical profession use X-Rays and radioisotopes to diagnose clinical conditions. In the medical world, a patient can take a low energy barium meal so that an internal assessment can be made on the condition of the human’s internal system. Likewise, Tracerco can make similar assessments to process systems by the introduction of an appropriate isotope.

The company’s technology offers several types of inspection services for restrictions in a pipeline whilst in operation. The data will determine whether local restrictions in a pipeline have caused blockages and whether they are present in limited locations or distributed evenly

49


through the line. The total volume of deposits and percentage bore restriction within the pipeline can also be identified. Measurements can also confirm whether the annulus of a pipe-in-pipe system is dry or flooded with seawater or product since this can seriously effect production due to flow assurance issues.

As remaining reserves of oil and gas become more difficult to access and fields previously not regarded as economical to develop become viable, there is an increasing requirement to attain longer subsea tiebacks to production facilities. The flow

lines involved in longer tiebacks will become more prone to blockage from deposits, such as hydrates or waxes. For mature assets and for pipelines that require more routine inspection, non-intrusive measurements are essential as a tool to reduce unnecessary downtime.

Using techniques used in oil and gas processing for over 50 years, many different pipeline scenarios can be determined from outside of the pipeline. Problems arise however when the pipeline is buried, as in many subsea applications, and access to the pipe is difficult. Here tracer techniques, similar to a barium meal used in medical technology can be utilised to determine deposit location (and flow regimes).

Radioisotope applications Radiation is all around us all the time, whether from natural sources or from certain devices encountered in everyday life. When applied to industrial applications, Tracerco uses radioisotopes with enough penetrative power to pass through steel pipelines or process vessels. For flow assurance projects, the gamma ray particle that will penetrate through steel, is used.

For medical applications, a radioactive tracer is introduced into the human internal system, in this case by ingestion, and then examined externally to determine where any problem areas may be. It is possible to apply the same principles to pipeline systems to locate and assess flow assurance conditions.

Flow assuranceThis can be defined as the requirement to ensure satisfactory flow from the reservoir to the point of sale, and the desire to understand, map and study the volatile and unpredictable oil and gas flow from reservoir. This can be a challenge. The applications of the medical-based radioisotope techniques to flow assurance can be summarised as:

Identify, locate and quantify pipeline materials such as waxes, scales, sand, sludge, hydrates.

Assessing total pipeline deposits as part of a cleaning programme to increase production.

Accurately assess and quantify pipeline condition as per corrosion condition models.

Accurately assess and quantify pipeline condition prior to pigging campaign.

Identify and locate and pipeline restrictions such as stuck pigs.

Profile pipeline wax build-up over long time periods.

Assess and quantify flow measurements.

Liquid and gaseous tracing techniques are regularly used for all of the above in multiphase systems. The tracer used is designed to follow a particular material through a system. Sensitive detectors are strategically placed on the outside surface of a pipe (or other process system) and detect the selected tracer presence upon its flow past specific positions. These measurements can be used to directly measure fluid velocity, flow rate, phase distribution and deposit inventory.

Using Figure 1 as an example, by measuring the time interval between detector responses and knowing the distance between the detectors, the mean linear velocity can be calculated. If full bore turbulent flow can be assumed, then the velocity can be converted to volumetric flow knowing the pipe internal diameter. Accuracy will depend on the precise circumstances but the mean velocity can usually be measured to better than ± 0.5%.

Flow assurance techniqueThe application of Tracerco’s flow assurance technique can be summarised in the flowing steps:

Deploy GammaTrac detection units subsea at known intervals.

The units are deployed at strategic locations. This is critical when the pipeline is laid on a seabed that has many undulations or depth changes.

A suitable radioisotope is injected and its passage is recorded for analysis.

The data is gathered and evaluated by a fully qualified engineer present at the worksite, thus, providing instant feedback to the client.

Figure 1. Flow rate as determined by tracer injection and process in action subsea.

The basic principle of a tracer investigation is to label a substance or phase and then follow it through the system using suitable detectors. Looking at tracer studies from a problem-solving point of view, if problems of fl uid transport can be described in terms of ‘when?’, ‘where to?’ and ‘how much?’, then they can be solved by means of tracer techniques.

The basic requirements of a tracer are as follows: It should behave in the same way as the material under

investigation.

It should be easily detectable at low concentrations.

Detection should be unambiguous.

Injection and detection should be performed without disturbing the studied system.

The residual tracer concentration in the product should be minimal.

The criteria can be met by the use of radioisotope tracers and by careful selection of the most appropriate tracer for a particular application. Frequently, more than one radioisotope can be chosen and the factors that are important in the selection of the tracer are include the:

Half-life.

Specific activity.

Type of radiation.

Energy of radiation.

Physical and chemical form.

Whilst tracer studies are usually employed in basic fl ow measurement, it has also been successfully used in the area of fl ow assurance, where it is used to measure the location and

extent of solids within a pipeline. In this application, the fl ow rate through the system must be known and kept constant. Detectors are positioned at known distances apart along the pipeline. A pulse of tracer is added to the pipeline and its velocity past detector positions measured. Using the velocity and fl ow rate, the average bore size can be calculated between detector locations. This measurement can give critical information prior to any proposed pigging operations and provides operators with the confi dence to successfully run pigging campaigns, safe in the knowledge a pig will not get stuck and cause signifi cant production losses.

This technique is used when the total deposit inventory of long lengths of line needs to be known. Access is not needed to the entire pipeline (it can be buried or subsea), just specifi c positions for detector location. For example, a recent study of a 110 km pipeline between two offshore platforms was conducted with single measurement positions at each end of the line to give a total deposit inventory of the line. A similar study was conducted with subsea detectors deployed every 10 km along a 60 km pipeline to provide information of the total amount of deposit in each 10 km section.

Wax build-upThe use of the tracer study can be to determine wax build-up rates within oil lines, such that a pipeline cleaning pigging strategy can be implemented and production increased. By determining an accurate build-up rate, both time and money can be saved with any pipeline intervention and cleaning operation. The position and build up of waxes can reduce the fl ow and

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hence the profitability of the pipeline and also increase the risk of getting an object (such as a cleaning pig) stuck. The cost of removal and/or recovery of a stuck pig can be significant and is likely to involve many specialist third party contractors. The lost production time will cost the operator many millions and therefore prevention is better than cure.

In Figure 2, a study was performed year-on-year to assess the total pipeline wax content, and as can be clearly seen, the wax rates increased from 2005 to 2007. In 2008, results were

not obtained and the cleaning campaign reduced and as such the volume of wax in 2009 has had a detrimental effect on the production flow rates, reducing from 98 m3/hr to 36 m3/hr.

Flow profilingOffshore processing is a complex process and, with ever evolving fields and deeper wells producing more and more three-phase flows, its imperative that slugging is understood, monitored and controlled. With an array of in-field flow lines tied back to an FPSO, the need to understand and map slugging is also a key requirement for pipeline integrity. With real time data collection and analysis, a series of in-field flow lines can be accurately measured and monitored. The size and shape of slugs of material can be sent directly to the operations team, therefore alerting them to the potential for a process upset. Likewise, long-term slugging effects can have a detrimental effect on the pipeline condition and hence the data can be used to confirm modelling information.

Figure 3 shows slugging in an oil line over a 30 min. period. The measurement technique involves placing a frame over the pipeline and measurements taken every one-second to produce the density profile. As is shown above, the pipeline is running full to empty in a very short time frame.

Hydrate formationHydrates form within pipeline systems and have a detrimental affect on process operating conditions, resulting in lost production through blockage and restriction. The need to understand where and what size of hydrate plug or restriction is present in the pipeline can greatly assist the operator in getting the pipeline back into full production as soon as possible.

In the study below, the operator’s gas well started to produce water unexpectedly, much earlier than had been predicted. As such, a standard procedure of injecting methanol was started but unfortunately production stopped and a hydrate plug was suspected as the probable cause of the blockage. The operator then added a chemical to the line to clear the restriction, however, a build-up of pressure indicated that the chemical injection had little effect.

The real time, non-intrusive scan, (Figure 4) of the line showed the pipeline density profile and therefore the hydrate, methanol, chemical and gas could all be located and monitored during remedial operations.

SummaryRadioisotope technology offers powerful and well-proven techniques for determining flow assurance conditions. Until recently, direct measurements of pipeline contents were thought difficult, but many operators have used the technology recently and its use is rapidly increasing worldwide.

The important features of using radioisotope tracer techniques may be summarised as follows:

The techniques described above make process systems transparent, which means that rather than guessing at what might be happening, it will be possible to make accurate, informed decisions in respect of further intervention or mitigation.

Most pipeline systems/subsea production systems are extremely complex, the techniques described above allow the complexity of the system to be broken down into individual component modules and assessment made of the performance of the individual parts. O T

Figure 2. Wax deposit amounts and flow rates.

Figure 3. Pipeline slugging in oil line.

Figure 4. Real time, non-intrusive data provides a pipeline density profile.

time

One of the most widely used terms in the oil and gas industry today is that of fl ow assurance. From the multiphase transport of oil, gas and water

fl ows through pipelines to corrosion and sand monitoring technologies, hydrate prevention, subsea sampling and PVT analysis, fl ow assurance is all about the continuous and optimised fl ow of oil and gas out of the reservoir. Yet, while measuring production rates might be the most accurate means of determining the success of fl ow assurance, there is another equally important criteria – reducing the need for well intervention.

It is true that well intervention has undergone signifi cant changes over the last few years – from large mobile installations to lighter subsea well intervention systems without the need for a riser.

However, the costs involved (sometimes having to shut down production, for example, with rig costs being as much as US$ 1 million/day) and the added risks of intervening in deepwater HP/HT environments have made

TAKING FLOW ASSURANCE DOWNHOLE

TERJE BAUSTAD, EMERSON PROCESS MANAGEMENT, NORWAY, EXPLAINS HOW TO REDUCE WELL INTERVENTION BY TAKING FLOW ASSURANCE DOWNHOLE.

well intervention very much a last option in the eyes of many operators.

So how can well intervention be pre-empted? The author believes that the need for well intervention can be reduced by taking fl ow assurance further downhole into the reservoir.

The downhole information gapOne of the key reasons for well intervention is the lack of accurate downhole information, information that can often warn the operator of threats to production and fl ow assurance.

A lack of pressure and temperature information, for example, can result in the need for well intervention techniques, such as logging, perforating and plug setting. Completion components may also have to be replaced and wellbore access freed up if sand is not detected early in the well stream. The same goes for corrosion downhole, such as when unchecked water enters the production fl ow.

53


Another information gap that can have a major impact on flow assurance and offshore safety is the pressure and temperature within the annulus of an oil well.

The annulus is the space between two concentric objects, such as between the wellbore and casing or between casing and tubing, where fluid can flow. A completed well normally consists of at least two annuli, with the annulus B often located between different casing strings.

The annulus B is important because it is the area likely to see the first indication of high pressures further down the well if the cement seals behind the wellbore casing are of poor quality. The result can be oil or gas migrating vertically towards the surface along the outside of the casing, leading to uncontrolled gas escaping at the surface and an inevitable production shutdown before a serious safety issue escalates.

Real time intelligent monitoringSo how can such dangers be addressed and the need for intervention reduced? Today the greatest opportunities for improvement come with real time monitoring of the reservoir and generation of accurate information on the fluids that flow through it.

This requires taking reservoir monitoring downhole to monitor wells more closely. This is particularly important with the growing use of extended designer wells with multiple production targets and multilaterals with several branches. In such cases, the contribution from each producing well zone needs to be closely monitored.

The good news, however, is that today there is much greater predictive intelligence, automation and integration in reservoir production monitoring.

Emerson’s Roxar downhole monitoring systems, for example, are today deployed in production, injection and observation wells, as well as in conjunction with the downhole instrumentation of highly complex multi-zone intelligent wells.

In Statoil’s North Sea Gullfaks field, the company’s downhole pressure and temperature gauges have been in continuous operation since 1991, supplying real time data under various flow conditions and helping operators to accelerate production and reduce the risk of unplanned shutdowns.

This real time monitoring has been further developed into a fully integrated Intelligent Downhole Network (IDN), which allows operators to install up to 32 instruments on a single cable, all of which will provide input to manage a whole range of production wells or separate zones simultaneously.

In this way, the intelligent network acts as a hub for downhole choke position indicators, for additional third party sensors, and for the transmission of power and data. The IDN will communicate to all sensors, so if a failure of one sensor occurs, all other sensors will still be able to communicate to the surface.

The only way to continuously monitor the production performance parameters of each individually perforated zone of a multilayer well is by downhole sensors between each production zone. To this end, well control by permanently installed sensors will provide a cost-efficient alternative to logging operations.

WirelessThe growth in wireless technologies is also playing a key role in taking flow assurance downhole and preventing well intervention.

Emerson’s wireless solutions are today being utilised in thousands of installations around the world, enabling operators to increase the visibility of their assets. These wireless capabilities are now being taken downhole in the area of well integrity.

Wireless is behind a new sensor system that has been developed to measure pressure and temperature information behind the casing in the annulus B of subsea production wells.

The wireless sensor, which is based on the previously mentioned intelligent network, is attached to the same cable as the reservoir monitoring gauges and directly measures pressure behind the casing string. The system consists of an IDN to carry signals from the wellbore to the customer monitoring system with a Downhole Network Controller Card (DHNC) placed in the subsea structure and connected to a 0.25 in. electrical cable, coupled to a tubing hanger penetrator.

Other key components include a wireless reader, a wireless PT transponder Figure 1. Regular pressure monitoring with downhole gauges is becoming essential in subsea operations.

and antennas to monitor activity in the B annulus, and a transponder and reader carrier. The system has an accuracy of ±2.5 psi – ±0.18 ˚F and is qualified to last for a minimum of 20 years at temperatures of up to 302 ˚F and pressures up to 10 000 psi.

The result is a highly effective instrument for protecting well integrity and flow assurance – an instrument that can detect variations in pressure behind the casing, provide an early warning of such conditions, and allow intervention or other remedial actions to be planned and implemented in a timely manner.

Downhole multiphase metering However, there is one missing element of downhole reservoir monitoring. For all the importance of pressure and temperature, probably the single piece of data operators want to know most about, as part of their downhole reservoir monitoring activities, is the flow from individual wells and well zones.

This information has become even more difficult to obtain due to the rise in multilateral wells, with the ability to access flow rates from different zones and branches off a single wellbore remaining elusive to many operators. More often than not, one has to settle on data on total production flow rather than flow from specific well zones.

The company has developed a new flow sensor system that can generate multiphase flow measurements from downhole in the well. The new system, which is based on multiphase metering technology, provides multiphase measurements of fractions and flow rates from either single bore or multilateral well configurations. And in this way, water, oil and gas fractions,

and flow velocity can become as accepted a technology in permanent downhole applications as temperature and pressure already are today.

There are a number of operator benefits. The system will allow operators to control multiple production wells, measure the individual flow zones of oil, gas and water, and establish optimum flow rate control. Additionally, if there is water breakthrough or gas encroachment in a particular well, the problem can be detected early on and only the branch of the well closed down rather than the complete well.

Other warnings of transient behaviour, such as slugs, will also be detected earlier and actions such as injecting water or gas into the reservoir for improved sweep efficiency can be closely monitored with the injection rate in each individual reservoir layer being closely controlled. In this way, many of the causes for well intervention can be mitigated.

Multiphase measurements downhole can also be integrated with data from other instrumentation to provide a more intelligent downhole reservoir management system.

In this way, threats to production can be detected by the multiphase meter and then pinpointed by the downhole sensors. Once unwanted water or gas enters the well bore, for example, the downhole pressure and temperature gauges can help the operator locate the problem area for immediate remedial action.

Crucial roleThis article demonstrates the crucial role downhole monitoring plays in flow assurance today, negating the need for well intervention and ensuring a highly efficient and effective production process. O T

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READ about the latest developments in the shale gas sector on Energy Global

“Houston, we have liftoff!”

56

Ian Anderson, Camcon Oil, UK, highlights the growing influence of digital artificial gas lift in flow assurance.

There are few broader terms in the oil and gas lexicon today than that of flow assurance. A term originally used by Petrobras in the early 1990s, flow assurance today covers every aspect of oil and gas production that facilitates the successful flow of hydrocarbons from reservoir to refinery.

Traditionally, flow assurance engineers have tended to focus on the multiphase transport of oil, gas, condensates and water in the pipeline with the most popular flow assurance techniques including multiphase meters and sand, hydrate and corrosion control.

Artificial gas liftThis author would argue, however, that one of the other elements of flow assurance in the oil and gas sector today, and one that significantly improves the flow from reservoir to refinery, is that of artificial gas lift, the enhanced oil recovery technique used to lift reservoir fluids to the surface when wells are not able to sustain such pressures naturally.

With gas lift, gas is injected into the production tubing to reduce the impact of the hydrostatic pressure where the reservoir pressures are not sufficient to force the hydrocarbons to the surface. By reducing the oil viscosity and thus

57


allowing reservoir liquids to enter the well bore at higher flow rates, fields around the world can subsequently enjoy improved reservoir performance.

Furthermore, with the increased focus on increasing recovery rates as new oil becomes harder to find, gas lift is likely to be a key element of flow assurance for many years to come. Spears & Associates estimated that the global artificial lift market was worth US$ 6.9 billion in 2008 and this figure is only likely to have increased over the last few years.

LimitationsAs has been mentioned in previous articles (including in Oilfield Technology), however, traditional gas lift techniques come with certain limitations.

These include a lack of information on pressure and temperatures at the point of gas injection and little control and flexibility in altering injection rates, where wireline interventions and the changing of the side mandrel units tend to be used to change the operating valve when injection rate changes are necessary.

In addition, the settings of these valves are often based on experience and informed guesses, as well as an overriding assumption that the well will operate at a specific reservoir pressure, flow and water cut.

APOLLOIt is with these limitations in mind that Camcon Oil recently developed a new digital solution for artificial gas lift, APOLLO, which enables operators to vary injection rates in real time without production interruption and well intervention. APOLLO, the first of a new range of products to support digital intelligent artificial lift (DIAL) solutions, generates pressure and temperature information throughout the gas injection process – all features that current gas lift solutions cannot provide.

In this way, the new solution eliminates the need for side mandrel units and wireline intervention processes to initiate gas injection changes. Settings can be tuned as wellbore conditions change through the life of the installation, giving control across the reservoir in balancing gas usage and preventing instability.

Yet, what are the tangible benefits in terms of increased oil and gas recovery? Can we provide some specifics in regard to increased production as a result of digital artificial gas lift?

The rest of this article will examine how the digital artificial lift solution was put to the test through a simulation modelling test with production technology consultants, Laing Engineering Training Services (LETS).

Simulation modelling testLETS developed an example well based on a modern day subsea well in moderate water depths, drilled to a total depth of 17 600 ft MD (measured depth) and with a 4.5 in. x 5.5 in. production tubing string inside a 7 in. liner. The oil was a light 38˚ API fluid with a reservoir temperature of 260 ˚F. The key variables examined during the testing were the well productivity index, reservoir pressure and water cut. Each of these parameters can be expected to change over the life of the well.

While the gas lift unloading operation is a transient phenomenon, with pressures and temperatures changing over time, continuous gas lift can be adequately modelled as a steady state process. To this end, LETS used the analysis software, PROSPER™, to create production system models. PROSPER, developed by Petroleum Experts, is popular with many petroleum engineers.

The focus of the test was to analyse the selection of gas lift equipment that will balance the desire for optimal oil production with the requirement for maintaining well integrity and gas lift equipment functionality over the life of the well.

A number of well life scenarios were developed including early life, from one day to three months, where there would be high pressures and no water cuts through to mid-life at one year, where there would be water injection and low water cuts, and late life at three years where there would be a higher water cut (although scenarios with low water cuts were also explored).

Using these range of potential life of well scenarios, the test compared the performance of a standard, multi-mandrel gas lift design with Camcon’s digital artificial lift solution to identify the maximum practically achievable production rates alongside the maximum practically achievable gas injection rates. A typical gas lift design technique built in to the PROSPER programme – similar to those used by gas lift service companies – was selected to determine mandrel spacing and valve port size.

Analysis The analysis revealed a wide range of possible injection depths from 3000 – 17 000 ft MD, and a wide range of optimal gas injection rates from 1.0 – 8.0 million ft3/d. In order to make the comparative modelling exercise practical in multi-variable scenarios, however, 2.0 million ft3/d was selected as the allocated gas injection rate for comparison. It should be noted, however, that this digital solution provides a number of options to vary the injection rate.

When going through the different well scenarios, the analysis revealed that the benefits of gas lift on day one are relatively trivial with the well left to flow naturally without any gas lift assistance.

The two scenarios that derive most benefit from gas lift are at the early life stage after three months and the mid-life stage with water injection support. The mid-life stage is considered to be particularly important where reservoir pressure has fallen to an extent that it cannot support natural production.

At the late lifecycle stage with water injection support, however, it was not possible to inject 2.0 million ft3/d with conventional gas lift design. This was due to the concern that

Figure 1. APOLLO, the first of a new range of products to support digital intelligent artificial lift (DIAL) solutions.

injecting through the unloading valve may damage the valve. Subsequently, no injection took place.

Since the well is not capable of natural flow with this high water cut, the well must remain shut in, until either the reservoir pressure falls to the point that gas can be injected at the depth of the orifice or, conversely, reservoir pressure rises high enough to deliver natural flow. There was no such problem with the digital artificial gas lift solution, however, with the 2.0 million ft3/d being injected.

For each of these life cycle stages, it was clearly seen that the flexibility of the Camcon digital unit to move injection depth up and down the well in response to the changes in well production characteristics yields additional production. At times, this incremental production is worth over 1000 bpd, yielding significant extra cash flow, and in one scenario represented up to 110% more production.

The ability to open and close the DIAL units at will, and to vary the equivalent port size, meant that even greater production increments could be delivered in the scenarios where additional casing pressure or additional gas lift gas became available, since there was no concern over reopening unloading valves.

Furthermore, while the 2.0 million ft3/d was set as the gas injection rate for comparative modelling, this does fully not appreciate the potential of the digital artificial units, which provide the option of changing the effective port size by selectively opening a number of valves in an individual unit.

In order to capture this, a scenario was created where higher casing head pressure becomes available. A casing head pressure of 2000 psig and a gas injection rate of 3.0 million ft3/d

were therefore modelled for the two ‘mid life’ life cycle stages. With this higher casing head pressure and higher gas injection rates, the DIAL unit delivers even greater incremental production without any well intervention.

Summary So what can we learn from this analysis? The simulation modelling demonstrated the significant increases in oil production that can result from the deployment of digital artificial gas lift units instead of conventional wireline retrievable valves and side-pocket mandrels in a gas lifted production well.

It also illustrates the limitations of conventional gas lift solutions where the implicit design assumption is that the well will operate within specific reservoir pressures, flow and water cut parameters and that any changes can easily be accommodated by simple wireline intervention to change out gas lift valves.

It is clear that such assumptions cannot be made, where remote field locations, growing water cuts, and fast changing reservoir and well characteristics are increasingly common.

The result was that the digital units were seen to offer much greater flexibility than conventional equipment, as the achievable depth of injection could change in response to the inevitable changes in reservoir pressure and water cut over the lifetime of the well.

Flow assurance is clearly one of the most important focuses for technology innovation in the oil and gas sector today. Digital artificial gas lift has a vital role to play in this area, giving operators more flexibility and information in their gas lift activities and, most importantly of all, increased production rates. O T

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T echnology is de-rigueur in today’s process world. The average computer today is over 2000 times faster and has 500 000 times more data storage capacity than the

Apollo Guidance Computer. Indeed, an ordinary iPhone (weighing in at less than 5 oz.) has more processing power than the computer (at 70 lbs) that enabled the astronauts of Apollo 11 to land on the moon.

With grand visions of digital oilfi elds, e-Fields and i-Fields as the future, technology must be applied to the upstream industry. Historically, there has been a reluctance to accept technology in the online production space. It is now over 12 years since the fi rst online Advanced Control application was implemented offshore (Norway) and yet there are still very few global roll outs. This is an interesting juxtaposition – technology is absolutely necessary to fulfi l the corporate vision, yet this technology is not exactly embraced by those who need to adopt it in order to achieve that vision.

The upstream challengeUpstream production operations experience some unique operational problems that have historically negatively impacted on production rates. The use of modern technology (subsea tiebacks and fl exible risers) and the practice of producing from non-associated fi elds have introduced new challenges such as increased slugging, instability, and changes in the gas/oil ratio. All of these contribute to deferment through more regular trips and through equipment operating further away from its designed parameters.

One platform in the North Sea experienced full process trips daily, lowering availability by approximately 5% per year. On a platform producing ~70 000 bbls/d, this equates to a huge loss in oil production and therefore revenue and earnings.

A shifting mindsetYou used to hear people claim that “the upstream process is too simple to need optimisation or advanced control” and that

would be the end of the conversation. However, over time, people from downstream operations (where technology is widely used to stabilise and drive processes) have moved into the upstream production arena and have brought with them the awareness that technology can make a difference. This has resulted in some incredible benefi ts and, thus, more interest and openness to applying technology.

Challenge 1: gas lift optimisationFields and reservoirs age as time progresses, making enhanced oil production techniques necessary for the continued viability of the asset. Techniques such as gas lift optimisation can have a huge impact on the production rate of mature assets and can in some cases increase production up to 70 – 80%.

Gas lift optimisation is a complex subject because of the recycle nature of the gas injected into the mandrels in the riser. With gas lift, whatever gas is injected from the platform will return to the processing equipment with additional gas through increased production, and this impacts the gas lift compression circuit. Additionally, the amount of gas used to lift the well can reach an optimum point for the riser long before it reaches a physical constraint – so the optimisation of gas lift is essentially an unconstrained nonlinear optimum and is a dynamic point. This depends upon the bottom hole fl owing pressure (BHFP) of the well, the boarding pressure of the well and the capacity of the gas lift compressor as well as factors such as ambient temperature, the state of the gas turbine or drive mechanism, the overall pressure balance and the composition of the gas being used (molecular weight).

Optimisation must consider two factors, which in this case are very different from each other:

The settling time and dynamics of the reservoir, measured in weeks or months.

The settling time and dynamics of the processing equipment (separators, compressors and flow lines).

Production optimisationUPSTREAM AND ON STREAM

61


It can be argued that making short-term changes to things such as the gas lift rate to a single well will not have a signifi cant long-term effect on the overall reservoir production, provided that constraints such as the BHFP are honoured. The inertia of the reservoir and the overall passage of well fl uids through the reservoir structure all support this argument

When the gas lift rate is examined more closely, it can be seen that changes to the gas lift rate can increase or decrease the overall well production by 1 – 2%. When this effect is then multiplied across the entirety of the gas lifted wells, it can have a marked effect on the overall production rate for an asset.

Unconstrained nonlinear optimum has a signifi cant impact on optimising gas lift rates. The graph in Figure 1 illustrates how an increase in gas lift rate does not always increase the production rate. In fact, it can have a detrimental effect causing ‘choking’. This lowers the well production rate and means that a limited resource has been utilised for no overall gain in production.

The challenge is to determine the true shape of the curve in order to fi gure out the ideal allocation of incremental gas. Which well has the steepest gradient for the allocation of a fi xed volume of gas? Once this has been determined, the next question is how much gas is available to be allocated?

This problem becomes incredibly complex when the number of wells are considered – if an asset has 20 wells with gas lift, how to allocate available gas to increase production, and conversely, how to reduce the gas lift with the least consequence when the gas lift compressor is constrained (during the day, for example, when the ambient temperature is higher and poses restrictions on the gas turbine exhaust gas temperature)?

The traditional approach has been to run reservoir and fl ow line simulation software to determine the optimal gas lift allocation. This is a time consuming activity. Given the dynamic nature of the process, when one well is taken offl ine for interventions or well testing, or when the temperature or operating conditions change, the whole scenario needs to be re-optimised again.

Technology in the form of Multivariable Predictive Control or Model Based Predictive Control (MPC) has been applied across the hydrocarbon processing industry for approximately 30 years.

MPC is well known for solving linear constrained control problems. For example, where the characteristics of the process do not change over the operating range and the optimal operating point is somewhere in the corner of that range, MPC pushes the process to the optimal corner and thereby maximises profi t. However, gas lift optimisation does not have these characteristics and the challenge is to fi nd the optimal operating point in an unconstrained optimum.

Although not as common, MPC can also solve highly interactive, complex control problems where there is typically an over-specifi ed problem. For example, where there are more constraints than degrees of freedom or ‘handles’ on the process. This is the case in solving the gas lift optimisation challenge, so MPC may be able to help. Being a dynamic online technology that can write set points to multiple control loops simultaneously, MPC eliminates the arduous task of reallocating gas lift to wells whenever conditions change, providing that it can solve the issue of the nonlinear unconstrained optimum.

Honeywell recently modelled a Floating Production Storage and Offl oading (FPSO) asset using dynamic simulation. The simulation accurately refl ected the operating heat and mass

Figure 2. The relationship of gas lift rate change and production are closely coupled. Optimising gas lift is an iterative process where the recycle effect has to be considered.

Figure 3. These graphs represent the model for gas lift rate, bottomhole fl owing pressure and oil production.

Figure 1. Increasing lift gas injection rate can lead to a decrease in production.

balance to ±2 – 3% of actual. This provided a ‘virtual’ asset to work on from the operating companies’ offi ce with access to the remote operating data. The reservoir, fl ow line and gas lift models were run and then regressed to enable them to be fi tted into the simulation as spreadsheets, linking to the dynamic simulation at the gas lift location. This then provided a complete asset model – everything from reservoir to tankage – and enabled the operation to be perturbed (step tested) with no risk to operations. Changing the gas lift rate changed the well performance and production rate, which then had an impact on the processing equipment and the loading of the compressors and therefore the gas lift volumes that were available for allocation (Figure 2).

Using the model shown in Figure 3, gas lift curves for each well could be developed and coded into polynomial equations, which were run online in conjunction with the MPC Quadratic Program. By creating this dynamic ‘map’, the online application could solve the linear relationships between the compression and fi xed equipment on the vessel, the overall gas lift pressure balance and the individual optimum gas lift rates versus the total production rate. This provided a means to solve the unconstrained nonlinear optimum dynamically and therefore allocate the gas lift to achieve the optimum on a minute-by-minute basis.

The results revealed that running the MPC application inside the dynamic simulation demonstrated a 2 – 3% increase in oil production through smarter gas lift optimisation.

Challenge 2: sluggingSlugging fl ow regimes are a constant challenge to most upstream operators since they create periods where, equipment that is designed for a continuous three-phase fl ow (oil, gas and water), experience either all liquid or all gas fl ow. This results in compressors rapidly transitioning between stonewall and surge modes of operation, as well as the separators, which are expecting continuous fl ow, tripping high and then low.

The slugging regime can be caused by the terrain, where subsea tiebacks are used for production, or as a result of the reservoir production profi le changing over time, creating the specifi c conditions

for the aggregating fl ow, which causes slugging.

Two proven methods of preventing slugging are:

To control the pressure pulses from the riser to prevent the fluid agglomeration.

To intelligently control a riser choke valve to ‘shave’ the gas or liquid slugs and prevent them from arriving so rapidly in the separator.

There is also a third option: dealing with the produced material in a smarter manner.

In any normal upstream production site, hydrocarbon material moves through the sequential stages of the three-phase separation, each separator feeding the next, and each operating at a lower pressure and evolving more gas and removing water from the reservoir fl uids. Subsequent separators are typically smaller than the preceding one, which results in level control problems. Level control algorithms on the separators are typically tuned for tight level control and so they try and maintain level stability at the expense of the outfl ow of liquid, especially when the infl ow of liquid is highly variable, such as in a slugging situation. This results in rapid level fl uctuations and regular trips in the last stage of separation.

An added complexity is where there are two or three fi rst stage separators’ feeding common second and third stage separators – this type of arrangement is shown in Figure 4.

When slugs are inbound, they can be detected using densitometers on the inlet manifolds. These measure changes to the density of the reservoir fl uids: a clear precursor to the arrival of a slug to the separator. The graph in Figure 5 illustrates this correlation. This is real data from an FPSO that was experiencing regular trips because of the slugging issues previously described.

A feed forward signal warns of the arrival of either more liquid or more gas, and thus proactive action can be taken to negate the impact of changing gas-to-oil ratio on the process. Using MPC technology, the inventories across the separators can be balanced by controlling the level control valve position and modelling the relationships between the separators.

When the control loops are opened and the level control valves are manipulated directly, the levels in the separators become a set of consecutive

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integrators. That is, if the fi rst stage vessel increases, the opening of the level control valve will cause that level to drop, but the level in the next separator to increase. Similarly, the relationship between the second and third stage separators can be modelled and controlled. This means that, when coupled with the feed forward information from the densitometers, the inventory across the process can be managed more smoothly. In advance of a slug of material arriving in the separator, the MPC algorithm can reduce the level in the separators, to allow the surge in volume to be handled without approaching any of the trip limits. This approach is clearly shown in the graph in Figure 6, which highlights the stability of the process both with the technology turned on and also when it is turned off. What does this stability provide in terms of increased production? Approximately 2% increased production through reductions in deferment – which on a 60 000 bbls/d facility is a healthy increase in revenue and a substantial decrease in lifting costs!

Sustaining the benefitMPC is like mechanical equipment in that it needs support and maintenance to continue to operate as designed. With applications sitting in remote oil production sites, this can be a challenge. Again, technology provides a solution: internet-based remote support to ‘bring’ experts ‘onsite’. This not only solves the problem of getting experts to the remote sites, but also enables those experts to serve more sites – especially important given the rarity of these experts in upstream.

MPC technology simplifi es remote access because performance data is automatically archived and stored with the application. Making the data (including application status, performance, online time, degradation) available to the appropriate, qualifi ed people is therefore relatively simple, even if the expert is physically located on the other side of the globe. This enables the expert to analyse the information and provide guidance to the local resources to rectify problems, or more importantly, improve performance over time.

So how do you incentivise to ensure ongoing maintenance and performance of this type of application? Simple – you structure maintenance payments based on clear metrics including online time, time at constraints and overall performance. That way, both the vendor and the customer achieve benefi ts – one from improving the performance of their delivered applications, the other from the improved performance.

Critics may say that this technology is too complex and that all that is needed is a really competent, diligent operator. The graph in Figure 7 argues the point better than any technological argument could. It shows the result of implementing a simple MPC application using gas turbine capacity to increase overall production. The net effect on the platform was an increase in production of over 3500 bbls/d – a very clear, tangible and sustainable benefi t, with a substantial business case behind it.

ConclusionMore and more rapidly, the gadgets and technologies once considered science fi ction become the norm. Consider a GPS-enabled Blackberry and compare it to the GPS in James Bond’s Aston Martin in Goldfi nger.

Technology is now solving problems that were once thought to be unsolvable and with dramatic results. With declining oil production, increasing demand and limited resources (especially in the skilled workforce), a technology solution that can increase production by 2 – 3%, while at the same time reducing equipment wear and tear makes a whole lot of sense, wouldn’t you agree? O T

Figure 6. MPC increases process stability.

Figure 7. Implementing MPC demonstrates a clear increase in production.

Figure 4. Typical arrangement of three-phase separation, where slugging may cause rapid level fl uctuations and regular trips in the last stage.

Figure 5. Correlation between the increase in density and level controller output.

WILLEM RYAN, BOSCH SECURITY SYSTEMS, INC., USA,

INTRODUCES EXPLOSION PROTECTED VIDEO SURVEILLANCE

SOLUTIONS IN CHALLENGING ENVIRONMENTS.

Extraordinary considerations must be taken when using electronics in oilfi eld environments, as they often require explosion protected equipment. The term ‘explosion protected,’ refers to an electronic device that, after being properly installed

in a combustible atmosphere, will not cause an explosion even under fault conditions.The need for certifi ed explosion protected electronic equipment started in the early

mining days in 1913, when 439 miners perished in a disastrous explosion. It was the worst disaster in British coal mining history, and its cause was found to be the low voltage signalling bells, which in tragic irony, were brought in to improve communication and promote

IN EXPLOSIVE ENVIRONMENTS

SURVEILLANCE CHALLENGES

65


safety. It was then surprising to learn that these communication devices could ignite the methane gas that would typically permeate a coal mine.

Now, in the present day, there is a growing need to install various types of electronic equipment at industrial sites, including oilfields, and the equipment must be explosion protected. International standards have been put in place and are enforced by law to ensure industrial sites are using explosion protected equipment in areas that are deemed necessary.

There is also a growing need to have high quality and certified explosion protected surveillance equipment in a nation’s primary and secondary industrial facilities. In the UK, oil refineries, chemical plants and gas plants have long been monitored with video solutions for protection against terrorist attacks and crime. Globally, we have only begun to protect our facilities with video surveillance.

Moreover, the use of video solutions is an important tool in maintaining safe operation. For example, oilfield managers can monitor people, processes and equipment to ensure good operation and safety practices. Video solutions (instead of people) can be located where there are hazardous or unhealthy conditions. Automated areas can utilise smart video technologies to verify or trigger alarms if a process has gone awry.

Methods used for explosion protected devices include ‘flameproof’ and ‘explosion proof’ (used respectively in Europe and the Americas) or ‘intrinsically safe’. Certified explosion protected equipment using the explosion proof method is able to withstand an internal explosion in order to not let any flames escape the housing and ignite the surrounding areas. The external enclosure of this type of equipment would include flame paths, which are small gaps that extinguish the flames and cool hot gases, allowing the gases to escape the enclosure so that they are unable to ignite the outer atmosphere. Devices typically include switches, control systems, motors, transformers, lights and, of course, surveillance equipment. Intrinsically safe equipment use circuits, which are energy limited and incapable of producing a spark or any volatile thermal effects under normal or fault conditions. Devices typically include radios, measurement and control, actuators and sensors.

Industry standards There are various industry standards that are available for explosion protected surveillance equipment. In North America, standards are based on the ‘Class, Division’ system for hazardous locations. In Europe and other parts of the world, standards are based upon the ‘Zone System’ for potentially explosive atmospheres.

Classes, divisions and hazardous locationsIn North America, hazardous locations are identified by Class, Division, and Group as defined in the National Electrical Code (NEC) and Canadian Electrical Code (CEC). The system provides three Classes based on the type of hazard and explosive characteristics of the material, two Divisions based on the operating conditions and seven Groups based on flammability properties. Environments are further defined by 14 temperature codes for Auto-Ignition Temperatures of the flammable gases that might be encountered.

Table 1 shows a list of NEC/CEC codes in terms of types of flammable atmospheres, operating conditions, flammability properties, and temperature codes with detailed descriptions of what they mean. Oilfields are typically a Class I, Division 1 location.

The Temperature Code shown in Table 2 defines the maximum surface temperature of the equipment, which must not exceed the auto-ignition temperature of the gases present in the explosive environment. Acetylene gas, for example, has an auto-ignition temperature of 299 ˚C. Therefore, an explosion protected device installed where there is a potential air/acetylene mix must have a T-rating of T2A to T6, whereas a device installed in an area where crude oil is present must have a rating of T2C.

For Class I, Division 1 locations, the permissible protection methods include: explosion proof, intrinsic safety (2 fault) and purged/pressurised (type X or Y) methods. For Division 2 locations, the allowable methods are: hermetically sealed,

Table 1. NEC/CEC codes

Class

I Locations with flammable gas or vapour

II Locations with flammable dust

III Locations with flammable fibres or flyings

Division

1Explosive conditions exist under normal operating conditions

2Explosive conditions exist under abnormal operating conditions

Group

A Acetylene

B Hydrogen

C Ethylene, ethyl ether, cyclopropane, butadiene

DPropane, ethane, butane, benzene, pentane, heptane, acetone, methyl ethyl, ketone, methyl alcohol, ethyl alcohol

EElectrically conductive dusts: aluminium, magnesium, titanium, zinc, tin + others

FCarbonaceous dusts: carbon black, charcoal, coal, coke dusts

GAgricultural dusts: grain, flour, sugars, spices and certain polymers

Table 2. Maximum surface temperature of equipment installed in explosive environments

Temperature code ˚C

T1 450

T2 300

T2A 280

T2B 260

T2C 230

T2D 215

T3 200

T3A 180

T3B 165

T3C 160

T4 135

T5 100

T6 85

OILFIELD TECHNOLOGYOctober 2011

67

nonincendive, non-sparking, purged/pressurised (type Z) and any Class I, Division 1 method. This implies that any device made for Division 1 locations is suitable for use in a Division 2 environment.

The zone system In Europe and many other regions of the world, potentially explosive atmospheres are handled by using a zone system based off International Electrotechnical Commission (IEC) and European Committee for Electrotechnical Standardisation (CENELEC) standards. The EU adopted Directive 94/9/EC also known as the ATEX Directive to facilitate free trade in the EU by aligning legal and technical requirements across Member States. Table 3 shows the list of ATEX codes in terms of device groups, categories, temperature class, explosion group, and types of ignition protection with detailed descriptions of what they mean. Oilfields fall under the Zone 0 category.

Images in explosion protected environmentsMinimising the possibilities of accidental damage to equipment and ensuring security and safety of workers have become more prevalent concerns at oilfields over the years. Having reliable video verification of events allows operators to be in control of a potential crisis around-the-clock, even in the most difficult lighting conditions. In particular, surveillance equipment that provides the right level of detail can enhance the accuracy of tough judgment calls operators are forced to make during a crisis. Often a simple judgment call of whether one should send his fellow colleagues to investigate a site of concern can turn into a life and death situation in a matter of minutes in explosion protected environments.

Oilfields today are often controlled and monitored by a process system, more commonly referred to as a Supervisory Control and Data Acquisition/Distributed Control System (SCADA/DCS) process. Using real time video verification in a SCADA/DCS process can not only help analyse system efficiency but assist in scenarios where a proactive approach can be taken in potentially dangerous situations.

An increasing amount of camera installations are found on drill floors of offshore oilrigs, around critical processes at refineries, and near critical equipment, such as petroleum storage tanks. Generally, these locations have a range of difficult natural lighting conditions such as a bright ocean background over a dark foreground typically found on the deck of an offshore rig, shadows or uneven illumination. When problems occur in locations where it is challenging to capture

a good image, operators are unable to inspect visually what is going on and lose valuable time that might be needed to prevent a minor problem from becoming a major one. Different types of imaging and illumination technologies are available to handle the imaging challenges that are typically faced in explosion protected environments.

Modern imaging technologies, such as 20-bit digital signal processing, can expose details not visible to the naked eye in both day and night times. This 20-bit digital signal processing generates two images to produce the clearest picture for every scene: one long exposure resolves details in the scene’s darkest areas, while one short exposure captures the brightest areas. The processing then mixes the pixels from each image to produce the most detailed picture possible. The 20-bit digital

Table 3. List of ATEX codes with descriptions

ATEX zone

NEC/CEC division equivalent

Definition*Required device category

Atmosphere

0 1A place in which an explosive atmosphere consisting of a mixture with air of flammable substances in the form of gas, vapour or mist is present continuously or for long periods or frequently.

1 G

1 1A place in which an explosive atmosphere consisting of a mixture with air of flammable substances in the form of gas, vapour or mist is likely to occur in normal operation occasionally.

12

G

2 2

A place in which an explosive atmosphere consisting of a mixture with air of flammable substances in the form of gas, vapour or mist is not likely to occur in normal operation, but if it does occur, will persist for a short period only.

123

G

20 1A place in which an explosive atmosphere in the form of a cloud of combustible dust in air is present continuously or for long periods or frequently.

1 D

21 1A place in which an explosive atmosphere in the form of a cloud of combustible dust in air is likely to occur in normal operation occasionally.

12

D

22 2A place in which an explosive atmosphere in the form of a cloud of combustible dust in air is not likely to occur in normal operation, but if it does occur, will persist for a short period only.

123

D

* Per 1999/92/EC directive (ATEX 137).

Figure 1. This graph compares image quality at different processing rates; 20-bit digital signal processing delivers a virtually continuous variation of gray levels for exceptionally accurate image reproduction.

signal processing also uses state-of-the-art software to analyse and enhance each pixel (Figure 1).

Boosting camera performance Vast dark spaces in oilfi eld environments will challenge surveillance cameras and hamper threat detection. CCD and CMOS image sensors are designed to see light – producing pictures or videos in the process. If there is no light, there can be no picture, and what is lurking in the shadows can leave oilfi elds vulnerable to sabotage, property losses, and public health and safety hazards. While many surveillance cameras have very low lux ratings, which suggest effective operation under low light, active infrared illumination helps to improve their performance in the dark.

Active infrared illumination technology can help operators detect, classify, recognise, and identify targets not visible to the naked eye at night time. Infrared illumination is light that lays in the wavelength region of 700 to 1000 nm – invisible to the human eye yet an excellent light source for an infrared sensitive day/night camera. Combining an infrared sensitive camera with an infrared illuminator produces video that more closely resembles crisp, monochrome images captured during daylight hours. It is considered an inexpensive method of obtaining high quality images in low light conditions.

As an added benefi t, infrared illuminators consume less power and eliminate the light pollution that can occur with visible lighting. Typical outdoor lighting consumes between 200 and 1000 W per fi xture. Compare those fi gures to LED-based infrared fi xtures for video surveillance, which consume between 25 and 95 W, making

explosion protected equipment with modern LED lighting more energy effi cient.

Advanced infrared illumination technologyAdvanced active infrared illumination technologies supplementing explosion protected cameras ensure security and operational professionals’ high quality images in any lighting conditions, even in diffi cult night time and low light environments. These technologies are able to provide three key benefi ts. First, they can effectively illuminate the foreground and background – providing light where the camera needs it. Second, they can eliminate hot spots and underexposures, ensuring consistent lighting across any scene and enabling video analytics to immediately detect security and safety threats. Third, they can minimise LED degradation, ensuring quality data throughout the life of explosion protected surveillance equipment and across the operation temperature range of the product.

Surveillance related issues have been increasingly challenging, especially for explosion protected environments, and having high quality and certifi ed explosion protected surveillance equipment in a nation’s primary and secondary industries has been progressively more vital to the health of a nation’s infrastructure. It has not been easy for security and operational professionals to fi nd the right surveillance cameras for these environments, and it has been increasingly important for these professionals to have explosion protected cameras that perform fl awlessly in natural and artifi cial light. O T

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DECOMMISSIONING DIFFICULTIES AND DEMANDSA s a result of the changes in the taxation regime

earlier this year there will actually be fewer assets to be decommissioned during the period from now

until 2040. It follows that the increased decommissioning expenditure is due to cost increases, and not more fields ceasing production.

DNS commissioned Professor Alex Kemp at the University of Aberdeen to prepare a decommissioning report with the latest market projections and an analysis of the implications of individual decommissioning projects on major infrastructure hubs.

Initial findings released ahead of report publication, reveal decommissioning expenditure in the UKCS is now forecast to increase to £30 – £35 billion between now and 2040. This is an increase on initial projections, which put the cost of decommissioning North Sea oil and gas facilities at between £24 – 30 billion within the same period to 2040.

This increase in the cost of decommissioning, alongside the fact that between 400 and 700 fields in the UKCS are to be decommissioned from now until 2040, further enhances DNS’s mission to assist the industry in co-operating and collaborating in order to improve efficiency, encourage innovation and contain costs.

Expenditures on decommissioning have averaged approximately £300 – £400 million/yr in recent years and are now forecast to rise to over the £1 billion/yr mark within a few years. Industry analysts agree that the main decommissioning programme is no longer being deferred and that a steady increase in the number of projects can be expected over the coming years.

70

Potential decommissioning expenditure in the UK Continental Shelf (UKCS) will be

higher than initially forecast. Brian Nixon, Decom North Sea, UK, explains.

Figure 1. Perenco UK setting a standard for SNS Platforms Heavy Lift Removal.

71


Since its inception in 2010, DNS has grown to include approximately 160 members drawn from a wide spectrum of operators, major contractors, service specialists and technology developers. It was set up to tackle the main areas of weakness and the bottlenecks that are inhibiting decommissioning supply-chain capability.

With only 7% of projects completed to date in the UK North Sea, DNS is stepping up its work to help the supply chain win significant levels of the remaining work and has endorsed research to ensure the appropriately skilled people are available to carry out the work.

To establish the extent of the potential skills gap, DNS endorsed a PHD student at Robert Gordon University to research ‘Potential Skills Shortages in the UKCS Decommissioning Phase’.

Overall, the findings indicate a significant shortage of skilled and professional personnel over the next 20 years, if action is not taken immediately. The project’s findings also show a 32% shortage of skilled onsite personnel while results for offsite professional personnel differ greatly, indicating an initial 14% shortage rapidly tapering off over five years.

In addition, the study finds that skills shortages are not being caused by an ageing oil and gas industry workforce but by the increase in numbers of skilled people needed and greater competition between different industries, such as power infrastructure and nuclear, for trained personnel.

Recommendations from the study include: Additional data being provided on the schedule of UKCS

decommissioning.

Continued investment in attracting school leavers into careers in engineering.

Encouraging the oil and gas industry to sponsor students and apprentices.

Examining tax breaks for skilled and professional engineering personnel.

A skills steering group established by DNS has also commissioned in-depth research among its 160+ members into the skills and competencies they will require to enable decommissioning activity to take place.

Findings will be shared with the Engineering Construction Industry Training Board (ECITB) and OPITO, the Oil and Gas Academy, to assist them in considering what may be needed in

the design of decommissioning technician training modules and accreditation standards etc.

There has been huge concern regarding the potential engineering and technology skills shortages in the offshore energy sector and DNS is regularly asked if this will also impact offshore decommissioning. The outlook for the UK oil and gas decommissioning supply chain is promising. Over the coming decade, industry forecasts suggest that the level of activity in the North Sea will lead to capacity restraints in all areas. Many North Sea supply chain companies could therefore find themselves with a choice of business opportunities, ranging from support for ongoing oil and gas development and production, to the growing programme of decommissioning, and emerging offshore wind developments.

This in turn has created serious and exciting career opportunities for those with the right skills. DNS is working with its members to develop an assessment of the quality and quantity of skills that will be needed, from technicians to engineers and project managers, and look at that against the bigger picture of how the needs of decommissioning will fit with other offshore work and the renewables sector as these industries grow.

There are over 600 offshore oil and gas installations in the North Sea, 470 of which are in UK waters. These include subsea equipment fixed to the ocean floor, as well as platforms ranging from the smaller structures in the southern North Sea to the larger and heavier concrete or steel structures in the central and northern North Sea. Offshore, there are more than 10 000 km of pipelines, around 5000 wells and accumulations of drill cuttings. Associated with these operations are also 15 onshore terminals.

Many of these structures have been producing oil and gas for up to 40 years and are now coming to the end of the lifespan for which they were designed. A growing number of redundant oil and gas installations will be taken out of service and decommissioned over the next couple of decades or so.

Decommissioning expenditure varies considerably by region. The central and northern North Sea have considerably higher costs per installation due to the size and weight of large platforms with substantial sub-structures, compared to the southern North Sea, which has shallower water and generally calmer conditions.

In the remainder of this decade, the greatest number of fields to be decommissioned will be in the southern North Sea – some 10 to 15 fields/yr through to 2020, whereas the greatest expenditures will be made in the northern North Sea.

In the next decade alone it is forecast that approximately 120 installations could be decommissioned in the southern North Sea, compared to 80 in the central and northern North Sea, as well as 65 subsea and pipeline installations.

No two platforms are the same and all were designed for specific tasks so there is no ‘one size fits all’ approach to decommissioning. Identifying major platform components for possible reuse on other platforms is a challenge, as much of this equipment was designed decades ago and the specifications and performance will often be deemed inappropriate for modern installations.

However, some research is underway to review alternative uses of smaller jacket structures, with one possible concept being barriers intended to reduce coastal erosion. Alternatively, one or two platforms could conceivably be reused as electricity substations for offshore wind farms or for carbon capture and storage.

Figure 2. Perenco UK safely executed the heavy lift removal of the Welland gas production platform in the southern North Sea.

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Overall, the re-use of equipment or whole/partial installations are expected to be the exception rather than the rule. We live in a society that quite rightly encourages us all to progressively reduce, recycle and re-use. With regard to reduce, the Scottish Environmental Protection Agency has recently announced a 36% reduction in landfill waste from businesses and households between 2005 and 2009. The oil and gas industry has also contributed to the reduce concept with some innovative designs for lighter platform structures, which have resulted in marginally smaller carbon footprints. When it comes to recycling, early decommissioning projects in the North Sea have recorded an encouraging focus, with some impressive percentages being quoted. However on the UK Continental Shelf, re-use has not yet featured strongly. DNS believes this could be about to change.

To date, re-use has primarily been recorded in the Gulf of Mexico plus some examples in the Dutch Continental Shelf, but there are signs that some operators are considering this option in other locations, such as West Africa, Southeast Asia and in the UK and Norwegian Continental Shelves. At a Decom North Sea members’ event in June, companies heard about Perenco’s success in refurbishing the topsides of their Welland platform prior to re-deploying it on a new development in West Africa. Marathon Oil is also known to be seriously investigating the opportunities for re-use globally.

There would appear to be numerous possibilities to re-use all or part of redundant oil and gas production facilities if economic, environmental and social factors can be satisfactorily balanced. The accommodation modules from BP’s Northwest Hutton platform were refurbished and redeployed as office accommodation units at the onshore disposal yard. Clad vessels (perhaps designed for sour service) are likely to remain in good condition and be potentially suitable for re-use on new developments. Drilling derricks could be upgraded and modernised. Gas turbines and power generation sets are capable of being overhauled and put back into service.

It is clear that the industry must move to reduce its energy footprint, improve its environmental performance and help to reduce the overall costs of the decommissioning programme over the next 20 to 30 years. Surely, re-use must have a growing contribution to play in this ambition?

The body is ensuring the industry is prepared for the level of decommissioning activity ahead such as developing solutions to decommission these structures, taking into account the impact on the environment, the health and safety of workers involved, costs and technology required.

ConsultationEarlier this year, in-depth consultation was carried out with its board, members, partner organisations and industry generally to identify priorities for DNS action and set a course of strategic direction towards addressing these requirements in the years ahead.

Among the list of initiatives, a strong emphasis was put on the need to research and understand capabilities and skills gaps in the decommissioning market relating to people, processes and technologies, and then put in place mechanisms to address the issues and opportunities.

The outlook for the UK oil and gas decommissioning supply chain is indeed promising. Over the coming decade, industry forecasts suggest that the level of activity in the North Sea will lead to capacity restraints in all areas.

The recent consultation showed compelling support for DNS to look at increasing current activities, namely networking events which provide value to its members; regional and topical focus groups; industry communication and knowledge sharing; mapping the supply chain strengths and capabilities; further development of appropriate contracting models, and facilitating introductions across the industry.

In addition, a range of more strategic initiatives and opportunities have been identified and prioritised including the following:

Provision of detailed and reliable market intelligence drawn from existing industry sources and filtered to be easily accessible by members.

Facilitate groups of members to share information, form alliances, address technologies etc.

Research decommissioning in other sectors including nuclear and salvage, to study how they deal with timing uncertainty, identify areas for transfer of experience, cross business opportunities etc.

Be active with governments, regulators and operators on behalf of its membership.

Understand capabilities and gaps relating to people, processes and technologies, and then put in place mechanisms to address the issues and opportunities.

Promote existing capability, new capacity, case studies etc.

Engage with the financial investment community to understand their drivers – promote awareness of members capabilities and needs, facilitate introductions.

Look overseas to identify market opportunities and to promote member capabilities.

These initiatives are listed in line with the priorities established recently by board members. The next step is to scope out and assess the level and type of resource that will be required to progress and deliver them.

In accordance with the priorities identified, DNS has organised a programme of events, seminars and share fairs in collaboration with other energy development organisations and government agencies, with activity covering the northeast, Highlands and Central Belt in Scotland, and the northeast and southeast in England, where most of the potential supply chain for the decommissioning market is based.

Future outlookOne of the principle reasons for setting up Decom North Sea was to provide a mechanism for sharing noncommercial information and to establish a platform that would allow companies from across the industry to obtain consistent and clear information. This year’s strategy consultation, which involved all the new directors recently voted onto the board, has fully supported this. The body reports real drive and enthusiasm from the board in delivering these strategic objectives.

Additionally, its inception has been ideal in bringing decommissioning activities to the forefront and removing much of the uncertainty as to when projects are likely to take place, which in turn assists companies with planning and investment for new innovative technologies required. It brings together companies of all sizes who share the same ambitions and the networking is very beneficial to all involved. The forum successfully amalgamates the supply chain to bring new innovations and ideas to prospective decommissioning projects. O T

Saturation diving is a key task in the offshore subsea industry. Engineers are continually developing systems to improve the working and living conditions for the divers, as well as reducing the health and safety demands.

Extensive advances have been made in many essential areas such as breathing gases, liveaboard comfort and medical monitoring, with many of these innovations focusing on the hyperbaric liveaboard chambers on the support vessel deck.

New insulation technology developments are also making a contribution to improve operational and working conditions at the business end of the saturation diving system; the diving bell itself.

JAMES VULTAGGIO,

TRELLEBORG OFFSHORE, USA,

LOOKS AT THE LATEST

DEVELOPMENTS IN

SYNTACTIC FOAM

INSULATION.

Figure 1. Initial submersion of diving bell with Trident™ insulation during SIT qualifi cation testing.

PERFORMANCE, 1000 FT BELOW

HIGH

75


Reaching new depthsThe diving bell is, of course, operating under the most extreme conditions. It must offer the best possible combination of both protection and operational effectiveness when it is remotely deployed from the support ship.

Insulation is primarily required to provide thermal protection for the interior of the bell. However, the inherent buoyancy of foam means that it can affect the subsea weight of the module and the effective use of lifting and lowering systems. Accurate data for the buoyancy can assist the deployment operation of the bell.

Traditional standard resin insulation foams can be crushed by the depths at which the diving bells operate, changing and even destroying buoyancy; the extremes of saturation diving can be at 1000 ft (300 m). To resist the pressure and offer buoyancy, the offshore industry has developed syntactic materials, in which high strength glass microspheres are contained in a rigid matrix. In addition to providing buoyancy, these small bubbles also enhance insulation properties.

Properly specified, syntactic systems have been developed and verified to offer buoyancy down to 23 000 ft (7000 m).

High performance under pressureConsidering the integrity of the foam is vital. Water ingress must be eliminated at all costs, otherwise the buoyancy can degrade and the thermal insulation performance will worsen over time.

Reduced insulation performance can mean an expensive diving bell is less suitable for extreme depth use.

For improvements in insulation for a new generation of diving bells, specifically protecting divers from the cold while in the bell, manufacturers Unique LLC consulted with Trelleborg Offshore for the development of an innovative syntactic foam insulation solution.

The engineered Trelleborg syntactic foam insulation, and the company’s 3D modelling design capabilities, provides Unique System LLC with high accuracy thermal and buoyancy properties. This means it is possible to predict the thermal insulation thickness required and the uplift of the bell for accurate system buoyancy control.

The performance of previous insulation systems used was more difficult to predict. It was also susceptible to damage and water ingress, which could affect the thermal and buoyancy properties. In contrast, the Trelleborg polyurethane-based material has a high impact resistance and is impervious to water ingress under pressure. It is designed to eliminate any requirement for maintenance, so that life cycle costs are minimised.

In-depth requirementsThe Unique System diving bell is designed as a submersible decompression chamber for a three-man saturation diving team. It transports them from a ship’s live-in hyperbaric chamber down

Figure 2. Diving bell undergoing additional submersion tests.


to working depths with typical sea temperatures of between 9 ˚C and 20 ˚C (45 ˚F and 65 ˚F). Typical subsea tasks include pipeline repair, maintenance and inspection, cable maintenance, platform installation and removal.

The diving bell, which has a total volume of 194 ft3 (5.5 m3), is configured to include a bottom man way, measuring 31.5 in. (800 mm), as well as an external bottom man way hatch, also measuring 31.5 in. The bell features strategically positioned view ports to provide maximum natural light to the interior. The ports are protected with a perspex cover plate to the interior and exterior of the bell, providing impact resistance.

The interior of the diving bell includes stainless fold-up seats for each of the diving team members. The seats are designed to support a fully dressed diver and to provide optimal comfort and support for the diving team during all phases of the bell run. Small storage shelves and hooks are also provided within the bell and stainless steel standoffs are welded around the

circumference of the shell, these can also be used for additional shelving.

The Heliox (helium/oxygen) breathing mixture, for the diving bell atmosphere is supplied via an umbilical from the support ship. Heliox has a higher thermal conductivity than air, so good thermal insulation is essential for the divers comfort. As dive times in the bell are often 10 to 12 hrs, and the divers remain under saturation conditions for up to 30 days, their wellbeing is critical to mission success.

An environmentally safer solutionTrelleborg used its new Trident™ Insulation system, which is based on BASF’s ZEROHg™ glass syntactic polyurethane foam technology. Trident has been developed in a strategic alliance with BASF Polyurethane Solutions as the next generation of glass syntactic polyurethane for subsea structure insulation.

A principle concern with standard marine grade polyurethane is the use of mercury containing catalysts. Reduction of the accumulation of mercury in the marine environment and food chain has been a priority for several decades, and Trident with ZEROHg is a major step forward.

In addition, this new insulation system offers superior temperature resistance when compared to standard marine grade elastomers. This ensures it can be used in a wide number of applications, as well as helping to maintain its performance

over time, when subjected to temperature stress. The insulation has a depth rating of 9842 ft (3000 m) with a

hydrostatic crush pressure rating of 330 bar (4800 psi), offering an excellent depth capability for today’s offshore operations. The thermal conductivity of 0.161 W/mK (0.093 Btu/fthF) provides excellent insulation, the hardness of 93 Shore A ensures good impact protection and the density of 53 lbs/ft3 (850 kg/m3 ) is suitable for a wide range of insulation applications.

Successful techniqueKey to the successful use of Trident insulation for the diving bell was its application to the metal shell of the bell. Despite the size, shape and construction technique of the bell, with openings and protrusions, it was essential that the material pour was completed in a single operation.

The single pour technique was necessary to eliminate the possibility of any discontinuities or interface joints in the

Figure 3. Three person Unique Systems diving bell equipped with Heliox.

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insulation structure, to ensure consistency and to prevent water ingress into the material when under pressure at depth. Water ingress could affect the system’s thermal properties and integrity of the exterior coating of the diving bell.

Trelleborg engineers developed an innovative new pour method for an application of this size and complexity. The capability for achieving this size of mix, pour and application was achieved through a combination of considerable investment in systems and equipment and 30 years’ experience in offshore buoyancy and protection manufacture.

The BASF polyurethane base was supplied to Trelleborg with a long gel time so that the large surface area of the bell could be thoroughly coated. In addition, the polymer mix had been formulated specifically to reduce water absorption into the polyurethane during use.

One concern in the insulation application procedure was maintaining the integrity of the glass microspheres in the mix. The engineers therefore designed special mixing and dispensing nozzles to avoid crush damage to the microspheres, ensuring the material retained its integrity and performance.

Durable constructionThe underlying construction of the bell provides its core strength, which allows the safe transport of divers, equipment and breathing apparatus while offering protection from the changes

in pressure, temperature and the effects of currents and even storms.

The diving bell shell is constructed of ABS approved carbon steel, welded in carefully designed sections; the total weight of the insulation poured around the shell was 1300 lbs (600 kg). This project marks the first time Trident Insulation with BASF ZEROHg polymer technology has been used in a custom coating operation. It is also the first diving bell to be insulated using glass syntactic polyurethane foam and represents a significant advance in diver safety and reduced operating costs.

Multiple successesIn this project, several needs were combined: improved diving bell insulation for Unique System LLC, more environmentally friendly syntactic polyurethane insulation systems from BASF and better process techniques for one lift/one pour insulation applications on a very large and complex object from Trelleborg Offshore.

As a result, the development of improved diving bells has gone hand-in-hand with advances in insulation technology, benefiting a far greater spectrum of offshore and subsea applications. Collaborative development successes of this kind are a clear demonstration of the benefits of cross-fertilisation of ideas and disciplines. O T

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