oilfield technology volume 04 issue 06-september 2011 …

OILFIELD TECHN

OLOGY MAGAZIN

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BER 2011

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.energyglobal.com

VOLUME 04 ISSUE 06-SEPTEMBER 2011

There’s a New Energy at Global.

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One good ship deserves another.Global 1200 & 1201 at your service.

The Global 1201

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The Global 1200

ISSN 1757-2134September 2011 Volume 04 Issue 06

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

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contents

| 44 | MASS-PRODUCED MACHINERYPeter Sharpe, Shell, The Netherlands, discusses a joint venture project with CNPC to develop an ‘assembly line’ process for drilling wells.

| 47 | COST-EFFECTIVE CONNECTIONSBruno Lefevre and Mazhar Mahmood, VAM Drilling, USA, explain the benefits of selecting appropriate drill strings to help drilling contractors achieve target objectives with maximum safety margins in a cost-effective manner.

| 49 | NO MORE CRACKING UNDER PRESSUREFinite Element Analysis helps the industry develop and qualify equipment for extreme environments, in this case heat. Haining Pan, formerly of Schlumberger, Jose Caridad, Schlumberger, Singapore; and Shauna Noonan, ConocoPhillips, USA, explain.

| 52 | LIGHTENING THE LOADPhil Head, Artificial Lift Company Ltd, UK, reveals how rigless ESPs are the way forward for artificial lift technology.

| 57 | NUCLEAR SOLUTIONSTerry Graham, Zircotec, UK, demonstrates how a growing range of coating technologies, developed by the UK’s nuclear industry, are now providing solutions including resistance to heat, wear and even electrical insulation in oilfield applications.

| 60 | MOORING SOLUTIONS THAT GIVE MOREWolfgang Wandl, Viking Moorings, Norway, shows the importance of mooring solutions in exploration drilling.

| 65 | FPSO MOORING IN MARGINAL FIELDSDoug Davidson, Mooring Systems Ltd, UK, explains how Tri-Catenary mooring systems are proving to be a flexible and effective station-keeping and production system.

| 68 | KILOBYTE-SIZED COMMUNICATIONSandy Johnson, SatCom Global, UK, considers optimising communication for remote operations.

| 03 | EDITORIAL COMMENT

| 05 | WORLD NEWS

| 10 | BRAZIL’S BLACK GOLDArthur Ramos, Rodrigo Souza, Hege Nordahl and Adrian del Maestro, Booz & Co., Brazil and the UK, explain how to create a win-win local content strategy in Brazil.

| 16 | WASHED CLEANIvan Cooper, Golder Associates Inc., USA, describes a united approach to water management in shale gas.

| 21 | SECURING INSTITUTIONAL KNOWLEDGEDavid Muse, P2 Energy Solutions, USA, covers the importance of institutionalising tacit knowledge and providing the contextual relevance that enables a consistent, predictable operational environment.

| 25 | ADVANCING SEISMIC RESEARCH WITH MODULAR FRAMEWORKS

Felix Balderas, Geophysical Insights, USA, discusses how geoscientists can utilise the newest technology to solve today’s E&P challenges.

| 29 | TURNING CHANCE INTO PROFITLuc Sandjivy, Seisquare, France, suggests how to deal with uncertainty in reservoir management.

| 33 | CROSS-CHECKING THE CHECKLISTBill O’Grady, Athens Group, USA, discusses managing risks as high specification offshore assets are being drilled in deeper waters and harsher environments.

| 36 | SEEING IN THE DARKRon Boyd, Atlas Copco Secoroc LLC, USA, discusses how new technology could put an end to drilling blind.

| 41 | EXTERNAL CASING PATCH EXECUTIONSAndy Gorrara, READ Well Services, Norway, demonstrates how the application of an external casing patch in one of Statoil’s North Sea fields has reinstated gas tight seals on several wells, ensuring well integrity fit for field life.

This image shows one of the many rigs currently drilling multi well configurations where precision wellbore

placement technologies like MagTraC are required.

James Little

Managing Editor

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‘Brazil’s black gold’, is this month’s keynote article by consultants Booz & Co. Focussing on Brazil’s oil and gas industry, the article highlights the tremendous

growth potential offered by the nation’s substantial pre-salt reservoirs both in terms of financial reward and long-term industrial development. This excellent article, which I encourage you to read, begins on page 10 and is itself a prelude to the forthcoming OTC Brasil Conference and Exhibition running from 4 – 6 October 2011 in Rio de Janiero.

OTC Brasil is a brand new event put together by the Offshore Technology Conference (OTC), and is the organisation’s first to be held outside Houston, USA. That it has hit upon a rich vein is without question, with 292 confirmed exhibitors at the last count, from around the globe, occupying over 14 000 m2 of exhibition space, it is clearly a testament to the huge international interest the Brazilian oil and gas industry is currently generating. Please note that Palladian Publications Ltd, will be in attendance at the show and our regular oil and gas related publications, Oilfield Technology, World Pipelines and LNG Industry will be widely distributed amongst visitors and delegates in addition to our annual Portuguese language publication, World Pipelines and Oilfield Technology Brasil 2011, produced specially for this and for the Rio Oil and Gas Expo & Conference in Rio in mid-September.

So why the hype and why is the country attracting such interest? Essentially Brazil is a rarity in the current oil and gas arena. In the first instance, there are proven hydrocarbon reserves in a politically stable environment, in close proximity to major markets. This is very attractive to oil and gas majors who are increasingly being frustrated by a lack of access to new reserves by national oil companies (NOCs). Secondly, with the oil and gas trapped beneath approximately 7000 m

of sea water, rock and salt, the technical challenges in bringing these hydrocarbons to the surface are immense. Brazil’s National Petroleum Agency (ANP) and Petrobras and its partners, actively require outside assistance in the form of technology and oilfield services. On the face of it, it would appear the perfect marriage for all concerned. US President Obama recently summed up this sentiment during a visit to Brazil in May, “We want to work with you. We want to help with technology and support to develop these oil reserves safely, and when you’re ready to start selling, we want to be one of your best customers”.

With an estimated 100 billion bbls of oil in pre-salt reservoirs at the base of the Campos and Santos basins alone and with substantial further reserves in the Carioca, Guara, Cernambi, Parati, Caraba and Lara fields, Brazil’s over-riding priority has been to safeguard these extremely valuable and extensive reserves. So it was no surprise that as this issue went to press, it was reported that Brazil has formerly announced plans to reclaim a number of key exploration blocks that had been won in 2007 by companies such as ENI, Repsol, ONGC and the then Norsk Hydro shortly before Petrobras’ discovery of the first subsalt reserves in the Tupi prospect. These blocks, which are now known to hold substantially more hydrocarbons than originally thought, will be returned to the Brazilian Government and re-auctioned at a future date once an agreement has been reached on how royalties from oil production will be distributed between Brazilian states.

Clearly there is still much to play for within the Brazilian oil and gas sector ensuring that the inaugural OTC Brasil will be a fascinating forum for discussion and a beneficial addition to the calendar of key international exhibitions and conferences. O T

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world news

05OILFIELD TECHNOLOGYSeptember 2011

inbriefUkraine recently opened shale gas development to Western companies, assigning its first exploration contract to the Anglo-Dutch firm Shell in a deal worth up to US$ 800 million (e 555 million).

“In case of successful exploration work and the start of intense project development, Shell’s total investment under the agreement may come to US$ 800 million,” the state-owned Ukrgazvydobuvannya gas exploration company said.

With estimated reserves up to 1.5 trillion m3, Ukraine is widely believed by industry analysts to be one of Europe’s largest holders of the new energy resource.

However, the country lacks the necessary fracking technology and continues to rely heavily on gas imports from its eastern neighbour Russia.

USAA study by the University of Kansas has found that injecting a greenhouse gas into older oilfields could squeeze out millions more bbls of crude, according to the US Department of Energy. The DOE said the results mean as much as 500 million bbls of crude could some day be recovered from Kansas fields.

POLAND According to the US DOE, Poland has some 3700 billion m3 of recoverable shale gas – and a pressing energy security reason for extracting them. Currently, Poland imports around 70% of its annual gas requirement from Russia. Meanwhile, a future export market could be created in light of Germany’s decision to phase out nuclear power plants by 2022; raising demand for gas.

BRAZILBrazil’s development of recently discovered oilfields could spur a hiring boom in the sector, adding more than 2 million jobs to Latin America’s largest economy by 2020. Currently, the country’s oil industry supports approximately 420 000 jobs. This figure could rise to as much as 2.5 million jobs by 2020.

COLOMBIAColombia’s foreign minister recently said petroleum agencies from the Andean nation and Jamaica are conducting studies with a view to possible joint offshore oil exploration in their shared maritime area. The Colombian foreign minister said relations with Jamaica are “extremely important” because the two nations share an extensive maritime border and “something very unusual in international law, which is a common regime area of almost 15 000 km2” in the Caribbean Sea.

// PetroChina // Invests in Iran

// Shell // First shale gas contract in Ukraine

PetroChina is reportedly to invest US$ 8.4 billion to develop the Azadegan oilfield, 80 km west of Ahvaz, close to the Iraq border. Total investment in the project is US$ 12 billion.

Iran Oil Engineering General Manager Alireza Zeiqami says PetroChina will begin first-phase development of the Azadegan oilfield this year. Its 2011 target is to drill 185 wells.

The oilfield has reserves of 3.2 billion bbls of oil, including recoverable reserves of 5.3 billion bbls. Once construction is complete, crude oil capacity is expected to reach 600 000 bpd.

Iran Oil Engineering and Tokyo-based Inpex Corp. will respectively provide the remaining 20% and 10% of the total investment.

The agreement will see Shell drill up to 1000 exploration wells in northeastern Ukraine, each of which will run up to 6 km (3.7 miles) below ground.

Signing a broad agreement covering both oil and gas exploration, Shell launched its operations in Ukraine in August 2006. The company has previously operated by holding 50/50 stakes in local joint operations ventures, without acquiring rights to the fields themselves.

Other Western majors including Chevron and ExxonMobil have also expressed an interest in the country’s shale projects, and the Anglo-Russian joint venture TNK-BP signed a preliminary agreement with the government in October.

Statoil Petroleum AS has encountered a marginal discovery near the Sleipner East field in the Norwegian North Sea.

The well − situated in the Statoil Petroleum operated production license (‘PL’) 569 − was drilled 16 km northeast of the Sleipner field. Ocean Vanguard drilled the well and the licensees will continue to assess the discovery together with other nearby discoveries.

According to the preliminary approximation, the discovery in PL 50 holds between 0.5 and 1.5 million m3 of recoverable oil equivalent.

Statoil has been facing production glitches and is continuously shifting its focus to the still unexplored areas of the Norwegian Sea, projecting an equity production of above 2.5 million bbls/y by 2020.

// Statoil // Marginal discovery

world news

06 OILFIELD TECHNOLOGY September 2011

diarydates

25 – 28 SeptemberMEOS 2011BahrainE: [email protected]

4 – 6 OctoberOTC BrazilRio de Janeiro, BrazilE: [email protected]

30 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]

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

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

// ExxonMobil and OAO Rosneft // New alliance

Scottish drilling giant, KCA DEUTAG, is expected to unveil its first contract worth up to US$ 23 million (£14 million) with New York-listed Marathon Oil. KCA, which was founded more than 100 years ago, has grown to become one of the world’s

Following the official termination of the BP and OAO Rosneft alliance, ExxonMobil Corp. answered the call to become Russia’s largest oil producer’s new partner.

The two companies have teamed up to explore not only Arctic reserves, but also the Black Sea, the Gulf of Mexico and onshore plays in Texas.

A total of US$ 3.2 billion will be invested by ExxonMobil and Rosneft into initial offshore exploration in the Arctic Ocean and Black Sea. The deal between the two companies could result in as much as US$ 500 billion of investments in infrastructure, exploration and production.

“Access to new resources is the life blood of oil companies,” says Fadel Gheit, an analyst at

// KCA DEUTAG // Marathon contract

A consortium comprising of Beirut-based contracting firm Consolidated Contractors Company (CCC), along with the UK-based energy firms Cairn Energy PLC and Cove Energy, has been announced to bid for the rights to drill for oil and gas off the coast of Lebanon.

Cairn indicated that Lebanon’s offshore waters provide an

// British-Lebanese consortium // Drilling rights bid

Oppenheimer & Co. in New York. “Russia is one of the largest resources that’s still available. It’s like Exxon is now dating the girlfriend BP had a few months ago.”

Furthermore, this alliance could see Rosneft as the first major Russian oil company to develop US deposits. The company’s capabilities in both deepwater and shale oil operations, with which it is relatively inexperienced, will be tested.

ExxonMobil CEO Rex Tillerson says, “I take it as a strong statement of Russian intentions to create competitive conditions to attract investments.”

ExxonMobil and Rosneft’s preliminary exploration project is a US$ 1 billion venture in Russia’s Black Sea signed on 27 January earlier this year.

largest drilling contractors. This move pushes the firm into the ‘unconventional’ oil and gas sector.

The multi-million deal with Marathon is for shale gas drilling in Poland, marking the Aberdeen-based company’s first venture into the eastern European country.

opportunity for gas drilling, and minimised the impact of the maritime border dispute between Israel and Lebanon on offshore drilling operations and prospects.

The United States Geological Survey (USGS) has estimated that the Levant Basin Province has a mean of 1.7 billion bbls of recoverable oil and a mean of 122 trillion ft3 of recoverable gas.

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world news

08 OILFIELD TECHNOLOGY September 2011

// QGEP Participacoes // Exploration stakes // Shell // Shale gas exploration in South Africa

Royal Dutch Shell is facing tough opposition from farmers and environmental supporters as it has announced proposals to invest US$ 200 million in shale gas exploration in South Africa.

The company plans to explore for shale gas in the semi-arid Karoo region, which is currently under a moratorium on oil and gas exploration licenses introduced in April over ecological concerns.

Jan Willem Eggink, General Manager of upstream ventures for Shell’s South African unit, said he believed South Africa could have at least half of an estimated 485 trillion ft2 of trapped shale gas, enough to be commercially viable and allow the country to become energy self-sufficient for decades to come.

Currently, about 90% of the nation’s electricity is supplied by coal, a rate that is hampering South Africa’s efforts to meet the UN’s emissions reduction targets by 2020.

Eggink said that “If exploration efforts prove that shale contains commercially producible gas volumes, then South Africa could see production from this source within a decade”. This could help the country plug a chronic power shortage and reduce its dependence on coal-fired power plants in favour of a cleaner energy source.

Controversy over the plans centres on the potential impact of hydraulic fracturing. Farmers and conservationists fear the fracking will adversely impact the sparsely-populated region known for its rugged scenery and rare wildlife.

Shell has also vowed to not compete with farmers for scarce water resources but instead truck in water initially before trying to pipe it by using the brackish water found deep underground.

Eggink added that Shell would also consider paying landowners for access to their land, although no compensation policy was finalised yet.

// Eni SpA // Reopens Libyan link

Marking the first major resumption of a foreign-led petroleum operation following the ousting of Colonel Moammar Gadhafi, the Italian government has recently confirmed it expects a key natural gas import facility from Libya operated by Eni SpA to reopen by 15 October.

As 10% of Italy’s gas originates in Libya, the resumption of Greenstream from the Wafa field has been classed as critical. The field, which was never shut during the Libyan civil upheaval this year, is jointly operated by Eni and the Libyan National Oil Co.

Libyan officials have said the country could reach 300 000 bpd in the next couple of months. Other Western oil companies including Repsol YPF SA and German Wintershall AG, have sent representatives to assess conditions, with hopes to resume production before the end of the year.

According to the British Geological Survey, Britain has 150 billion m3 of recoverable shale resources. The US DOE is more optimistic and places the country’s shale resources at 560 billion m3.

Equally optimistic is Cuadrilla Resources, a UK-based company with a licence to explore for shale gas across 437 square miles of Lancashire.

While declining to give any figures, Mark Miller, Chief Executive of Cuadrilla, said: “They’re exceeding expectations.” The company will disclose its first estimate for the amount of shale gas inside its license area on 21 September.

Environmentalists are worried about fracking being linked to earthquakes and pollution. The government is more lukewarm: it wants to encourage nuclear power generation and renewable energy, not a new source of fossil fuel.

// Cuadrilla // Optimistic in the UK

QGEP Participacoes, the oil and natural gas arm of Brazil’s construction giant Queiroz Galvao, has signed a contract to buy a stake in an offshore exploration block from the local unit of oil major Royal Dutch Shell PLC.

The company will purchase a 30% stake in the BS-4 block in the Santos Basin, off the coasts of Rio de Janeiro and São Paulo. The block also includes federal oil company Petroleo Brasileiro and the local unit of Chevron Corp. Shell Brazil is expected to retain a 10% stake in the block.

The purchase price was not disclosed for the deal, and it is still

subject to approval by Shell’s partners in the block, as well as local oil regulators.

Chief Executive Jose Augusto Fernandes has previously said that the company wanted to use the nearly US$ 1 billion in cash raised in an initial public offering earlier this year to “grow quickly”.

Fernandes added that the company was “extremely interested” in the Brazilian National Petroleum Agency’s 11th round auction of exploration concessions, although Mines and Energy Minister Edison Lobao said that the auction would likely be pushed back to 2012.

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How can a rig that big operate reliably at any time?

Brazil’sArthur Ramos, Rodrigo Sousa, Hege Nordahl and Adrian del Maestro, Booz & Co., Brazil and the UK, explain how to create a win-win local content strategy in Brazil.

BLACK GOLD

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T he discovery of large ‘pre-salt’ reserves off the coast of Brazil will soon catapult the country into the ranks of the world’s major oil producers. Brazil, which already has an established

oil industry, understands that the potential long-term oil revenue growth needs to be channelled in ways that will promote broader domestic industrial growth.

Oil-producing countries that have been successful in building a strong local supply chain have done so by developing targeted industrial policies with the incentives and requirements needed to attract international players and strengthen their domestic infrastructure and capabilities.

Brazil is following this route as well, opting for a very straightforward policy that uses its concession-granting process to reward bidders that commit to high levels of locally-sourced products and services. Some industry operators understandably might view these local content commitments as a hurdle to overcome or a necessary evil. However, taking a more positive and proactive approach to working within the requirements can help ensure that an operator will play a central and profi table role in this budding and very promising market.

Boosting the stakesExisting large reserves and the government’s push to open the sector to competition have driven steady growth in Brazil’s oil industry over the past two decades, allowing the country to fully

shed its dependence on foreign oil in 2006. However, the recent discovery of vast pre-salt offshore deposits has been a true game changer, one that will more than double the country’s oil production from 2.37 million bpd in 2010 to an estimated 5.63 million bpd by 2020.

This tremendous opportunity has brought with it a signifi cant challenge for Brazil’s policy makers: how best to leverage the impact of greatly expanding offshore development to create a strong, competitive supply chain in Brazil. The sudden arrival of oil wealth in some developing countries has brought with it an ‘oil curse’, in the form of rapid exchange rate appreciation, poor governance in reinvesting oil revenues and political infi ghting.

However, Brazil, with its booming economy, political stability and recent history of successful industry reforms, is in a better position to avoid these pitfalls and join the small group of countries that have successfully transformed revenues from resource wealth into a strong, internationally competitive domestic supplier base. If Brazil is able to channel the investments it needs to make in order to develop a larger, stronger oil industry, into building its supply chain resources, the benefi ts to its economy could be enormous. The sector’s supply chain will not only serve the country’s offshore development needs but also expand its overall employment and exports.

A number of countries, most notably Norway and the UK, have successfully employed effective local content policies to

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12 OILFIELD TECHNOLOGYSeptember 2011

develop strong local supply chains, focused on the exploration and production of their offshore reserves. Both countries were blessed by the discovery of significant petroleum reserves in the North Sea in the late 1960s, but their economic situations at the time led them to take different paths to exploiting their newfound resources. Norway’s solid macroeconomic standing allowed it to focus on long-term goals and activities, such as developing a local economic cluster cantered on high technology and innovation. By contrast, the UK was encumbered by a balance of payments crisis and high unemployment; factors that led it to focus on accelerating exploration and production by attracting established operators.

Despite their differences, Norway and the UK both adopted specific mechanisms and policies aimed at creating a globally competitive local industry focused on much more than domestic sales. Local content policies succeeded in those markets because they were used as a means of building a strong and competitive industry supply chain, and not as an end, remaining in place for too long and eventually thwarting competition.

Challenges of ‘going local’ Looking to follow such leading examples, Brazil has designed its concession-granting policy with incentives for bidders to commit

to a substantial percentage of local content. The aim is to ensure that successful bidders will become partners and participants in building a domestic supply chain that will leverage the benefits of oil industry growth.

Operators preparing to work with these local content commitments must understand that any efforts aimed at ‘gaming the system’ will not pass muster. Booz & Co.’s extensive work in Brazil’s oil sector has revealed a deep commitment on the part of government leaders there to build a strong, competitive local supply chain. There should be no reason to doubt now that local content commitments made by operators in their bids and written into contracts will be enforced.

That said, good faith attempts to abide by local content requirements will have to account for the difficult challenge of working with a domestic supply chain that is not fully developed.

One key component of the challenge that operators face in delivering on their local content commitments is the price differential between local and international suppliers, particularly when it comes to procuring machinery and raw materials (Figure 1). In most cases, locally manufactured equipment is priced at a premium due to suppliers’ lack of scale and cost-saving technology and processes. At the same time, Brazil’s economy is booming,

Figure 1. Seawater Lifting Pump: composition of cost difference. (Source: Field research; ABIMAQ; interviews; Booz & Co. analysis.)

OILFIELD TECHNOLOGYSeptember 2011

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outpacing the growth of the global economy, so other high-growth industries such as mining are competing for the same resources in its local markets. These resources include labour: a shortage of skilled workers is developing in Brazil, affecting suppliers’ ability to add the requisite talent to meet the supply chain needs of a growing offshore oil industry.

The recent nature of the ultra-deep, pre-salt discoveries and the technical difficulty that development will pose may also make it more challenging to assess the profit potential. Suppliers will likely find it easier to invest to serve more established markets where they will have greater visibility into projected revenues and where profits can be realised in a shorter time than the seven to 10 year horizon the offshore oil industry typically requires in developing reserves.

Guidelines Despite these obstacles, the opportunity in Brazil created by the recent discoveries is tough for any operator to ignore. Given growing concern in the world about the socio-political stability in many energy-supplying countries, Brazil offers an attractive combination of new supplies and a stable democracy.

To reap the reward, operators will need to develop a comprehensive strategy that will assist Brazil in developing a strong and competitive supply chain. Establishing a clear understanding of the local content requirements and creating a plan to work within their constraints, will help operators turn the challenge into an advantage as they establish a competitive edge in this high potential market.

Booz & Co.’s experiences working with operators in the global oil industry has enabled the company to highlight five major guidelines for successfully managing local content requirements.

Get up to speed on the local supply chainOperators that are compelled to employ local resources must first assess the strengths and weaknesses of the domestic supply chain. Through such a study, they can determine the capabilities of each segment and identify specific areas where local suppliers have the greatest potential to become competitive in the international markets. In Brazil’s case, electric systems and subsea equipment manufacturing may provide an attractive starting point for this effort. Once these pockets of strength are identified, operators can adopt a long-term strategy to partner with selected local suppliers and demand the right incentives from government for working with them.

Promote co-ordination in procurementPetrobras is still the force majeure in Brazil’s oil sector – it was designated the sole operator of the pre-salt reserves – but a 1998 law that ended the company’s monopoly is opening up the industry to competition. In the coming decade, other operators will see their investments grow to approximately 20% of the total. Operators can achieve scale and win more favourable terms from local suppliers if they can form a united front in articulating the benefits to suppliers of diversifying their relationships. In some cases, local suppliers may be willing to invest in and develop their non-Petrobras operations; in others, the allure of a united block of operators not already served will help attract international suppliers to the Brazilian market. Operators can supplement this strategy by identifying suppliers with needed technological or manufacturing expertise and offering incentives for them to invest in Brazil.

Review ‘make versus buy’ policiesFor the most part, the petroleum industry is a case study in effective outsourcing. But in some developing markets such as Brazil, it may make more sense to ‘in source’ parts of the supply chain, particularly in the case where key equipment or services are not readily available. In these instances, an operator may be better off actively participating in the local supply chain in the short-term. For example, one can take an equity stake in a local company for the near-term and then sell off the operations to local investors when the company is mature and competitive.

Partner with existing players to promote the industry’s growthPetrobras is in a unique position in Brazil. Its ownership is split roughly in half between the government and private investors, so the company wears two hats. It needs to maximise profits for its shareholders while living up to its responsibility to the public by acting in ways that further public policy goals. As the primary developer of Brazil’s offshore reserves, Petrobras faces the same supply chain issues as other operators, including the mandate to participate in building a strong domestic supply chain, and therefore faces the same challenges – labour shortages, price disparities, infrastructure shortcomings. This positions the company as a natural ally for operators looking to raise issues with the government or support commonly beneficial industry-related policies.

Foster an open dialogue with policy makers and regulatorsA commitment to embrace local content requirements as a positive long-term strategic move, aligns industry operators with the needs and wants of Brazil’s policy makers and regulators and that should ease the development of an open and constructive relationship. One crucial way operators can sustain and strengthen this relationship is by working together to establish the parameters for success. Publicising industry benchmarks will help policy makers quantify the gap between local conditions and international standards, so they can develop the policy mechanisms necessary to close it. For example, they will want to know if a piece of equipment manufactured in Brazil is twice as expensive as one available on the international market because that situation hurts the country’s competitiveness. By the same token, operators should work with government officials to develop a structured ‘learning curve’ for complying with local content regulations so that they have enough time to develop the requisite in-market capabilities and steer clear of premature penalties.

SummaryCertainly, local content commitments present challenges to oil industry operators. However, if operators adopt a proactive and co-operative approach to building a local supply chain in Brazil, they will set themselves up to create value and strategic advantage in an attractive, high growth market. Not only that, but they will help all stakeholders – independent operators, Petrobras, local suppliers, government officials, and the greater public – share in the benefits that a robust, stable, and internationally competitive domestic supply chain will bring. O T

NoteAbout the authors: Arthur Ramos, Partner, and Rodrigo Sousa, Senior Associate, are based in Brazil. Hege Nordahl, Principal, and Adrian del Maestro, Principal, are based in the UK.

Founded in 1914 by Edwin Booz, Booz & Co. is a global management consultancy working with businesses, governments and organisations.

W ater impacts are becoming one of the biggest issues facing continued progress in shale gas development in North America. This article will consider the impacts of the

water issue, review what is being done, and look at a possible way to manage the situation. While the content focuses on activities in the Marcellus Shale in the Commonwealth of Pennsylvania, many of the principles are likely to apply to shale gas activities elsewhere in the world.

Water supply issuesFirst, consider the question of water supply. The ability to produce natural gas from deep shale formations, such as the Marcellus Shale, involves drilling to a productive zone several thousand feet (up to 3000 m) below the surface, then often kicking off to a gentle bend to the horizontal for an additional several thousand ft of horizontal drilling, followed by hydraulic fracturing of shale rock formations to extract natural gas.

This is an unconventional production type, defi ned in a National Petroleum Council working document as “Natural gas that cannot be produced at economic fl ow rates nor in economic volumes … unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or by using multilateral wellbores or some other technique to expose more of the reservoir to the wellbore.”

This ‘unconventional’ procedure enables the extraction of gas from the formation. Fracking involves the high pressure injection of 2 – 5 million gal. (7500 – 19 000 m3) of water at a very high rate. The water contains chemical additives and conductive sand or ceramics as a ‘proppant’ to keep the fractures in the formation open and allow the fl ow of gas. A successful unconventional well requires fracturing in the target formation of a vertical well, or in the productive zone of the horizontal leg of a horizontal well. The operation also requires the onsite management of the initial return of 15 to 30% of the injected frac water, which is also called

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fl owback water. Frac water will also return to the surface over a longer period of time as produced water.

Managing the availability of source water is critical to the success of an unconventional well. Pennsylvania is fortunate in having more surface water resources than any other state except Alaska, according to the Marcellus Shale Coalition. Yet even in relatively water-rich Pennsylvania, this volume of usage has an impact on other uses of that water, including maintenance of natural fl ow in streams and rivers.

Frac water comes from a variety of sources – including surface water, groundwater, industrial wastewater, stormwater, municipal wastewater, and the acid mine drainage (AMD) water fl owing from the area’s many current and closed mines, all termed ‘fresh water’. In an increasing number of cases, operational frac water is previously used and recycled frac water or produced water from ongoing gas production, treated to varying degrees and blended with fresh water. Most states require a relatively robust permit system to identify

water resources to be used in fracking, and the resulting impact on the environment. In Pennsylvania, a well permit requires water source approval from the Department of Environmental Protection (DEP), and the various river systems, including the Susquehanna River Basin Commission and the Delaware River Basin Commission, notifi cation to localities, and other requirements.

Generally, this water arrives at the drill site by lorry – possibly several hundred vehicle loads, each of about 4000 – 5000 gal. (15 – 19 m3). This often means large numbers of heavy vehicles travelling on roads that were designed for light rural traffi c, causing wear and tear on road surfaces. Other impacts of water-carrying vehicles include noise, exhaust emissions and traffi c congestion.

Therefore, many producers opt for a comprehensive master water management plan identifying water sources and water availability, including an overview of fresh water treatment and residuals management, water treatment for reuse as fracking water or other uses, and a water treatment residuals plan.

Ivan Cooper, Golder Associates Inc., USA, describes a united approach to water management in shale gas.

17


Impacts on other usersMany rural and small town residents and businesses in Marcellus Shale areas are dependent on wells for their drinking water. While many of the residential wells have not been tested for water purity, there are persistent claims that the shale gas industry is causing well water contamination.

These claims are made despite the fact that most rural water wells have depths measured in hundreds of feet, and most shale gas wells extend several thousand feet down – usually with many layers and thousands of feet of impervious rock between the fracking activity and the water wells’ capture zones. To prevent leakage of gas, frac fluid or produced water into groundwater supplies, well casing extends the full depth of the gas wells. That is why Pennsylvania requires predrill testing of nearby wells and other water features to establish a quality baseline before drilling commences. This testing also serves as a liability reduction technique for drillers. Shale gas well developers are cognisant of other concerns, including site and forestry issues, stormwater management, air emissions, noise and light pollution, trucking impacts, and waste management, including the potential for managing naturally occurring radioactive materials (NORM).

Water disposal issuesWhile only around 15% of the frac water is returned by flow back over the first week or two after a frac operation, a flow of water

continues through the life of the well. Other fluids to be managed include tophole water (water from drilling through strata containing uncontaminated groundwater), drilling water, and water-based drilling muds. Oil-based drilling muds are generally managed by reusing these expensive fluids at subsequent drill sites. If the frac or produced water cannot be used in subsequent frac operations due to the well frac schedule, then disposal may be necessary. Disposal options include deep well injection or reclamation.

Disposal to municipal wastewater plants is not a viable option. In May 2011, the Pennsylvania DEP asked natural gas drillers to refrain from sending frac wastewater to water treatment plants in the state, due to the inability of these plants to remove total dissolved solids (TDS) and bromine. The frac and produced water may contain high concentrations of bromides, a nontoxic salt compound that reacts with disinfectants used by municipal treatment plants and naturally occurring organics in streams to create brominated trihalomethanes (THMs). Exposure and ingestion of THMs has been tied to several types of cancer and birth defects.

Frac or produced water disposal to evaporation ponds, common in drier climates, is not an option in the cooler and wetter northeastern USA. However, for these waters to be disposed of underground, they must be pumped into a well that is approved for disposal purposes – and in the Commonwealth of Pennsylvania there are only a handful of wells approved for disposal. One reason for this limitation is that the rock formation must be suitable for receiving the water, and many of the formations in the state are too tight to be used for this purpose. Many nearby states, such as Ohio and West Virginia, have additional deep well options, but trucking water to these more remote locations substantially increases costs.

It might be possible to use a depleted well for disposal, but many of the older wells face integrity problems, and it would be impractical to recondition them to be permitted for disposal.

Water disposal has become an issue for the industry to the extent that currently, some companies are hauling their produced water to a disposal well in neighbouring states despite high costs for trucking and disposal.

Water treatment issuesChallenges are increasing with regards to water treatment as well. Treatment of frac and produced water may require removal of problematic substances. In many cases, the produced water contains corrosive substances, biological activity, and dissolved barium and other metals, which produce insoluble precipitates and other substances that tend to clog the formation, reducing the flow of natural gas.

Currently, companies involved in shale gas take a variety of onsite and offsite approaches to water treatment, ranging from filtering-out large solid particles to producing higher quality water by various techniques. At times, a lease may prevent onsite frac and produced water treatment, so the only option is offsite treatment or disposal.

Table 1 provides an overview of the range of major treatment options currently used, including estimated costs, with the technique employed relying on history and company practice. These costs are significantly impacted by the haul distance if an offsite treatment option is used. A limited haul distance was used in the cost calculation, assuming a haul distance within an hour’s drive of a well site for offsite treatment or disposal.

One of the challenges to water and wastewater management is the patchwork of regulations between states, related to the management of shale gas water sources and uses. With the

Figure 1. Frac water hauled to a well pad.

Figure 2. Frac and produced water treatment facility tests water before processing.

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proliferation of shale gas development in various plays around the world, areas with less developed infrastructure and regulations are looking to more developed programmes for guidance. Recently, delegations from places including Poland and China have visited Pennsylvania to learn how to manage the water impacts of shale gas activity. In addition to state-led regulatory programmes, the US Environmental Protection Agency (EPA) is reviewing the regulatory climate for a broader effort to regulate frac and produced water from gas drilling operations. EPA recently asked 26 states for information on how water and wastes are managed under the Resource Conservation & Recovery Act (RCRA). Currently, these wastes are exempt from RCRA regulations under the 1988 Bentsen provision of RCRA. Some officials believe EPA is heading towards regulating frac flow back water after drilling operations are completed. The EPA’s argument is that this water may not be covered under the drilling exemption, while produced water, drilling fluids and cuttings, and other drilling and production wastes should remain exempt. This effort may be redundant or

interfere with various existing state programmes in many western states as well as Pennsylvania, New York, Ohio and West Virginia. If these initiatives make their way to regulations, interference with proposed centralised treatment facilities may occur.

Is central treatment the solution?Water impoundment and treatment seems to be an area that can be resolved with some kind of central organisation. Currently, there are a limited number of centralised facilities that provide impoundment and storage services. Energy Corporation of America (ECA) has a number of centralised impoundments with pipelines between well pads to avoid trucking operations. The Pennsylvania DEP has received permit applications for at least 12 proposed treatment plants that would accept water from frac and produced water operations.

For example, Reserved Environmental Services in Mount Pleasant, Pennsylvania near Pittsburgh operates a physical chemical plant to treat wastewater from shale gas, including water-based drilling muds, frac water, and produced water. The wastewater from various shale gas operators is delivered as a regulated waste, treated by chemical precipitation to remove metals and particulates, disinfected, and is returned to operators. When the regulated waste is delivered back to a well site, the water is blended with fresh water and reused in fracking operations. The facility is also constructing a 15 million gal. (57 000 m3) impoundment to store large volumes of water if a client’s well site impoundment needs to be cleaned or immediately emptied because of a leak, and repairs are necessary.

A similar facility operates in Williamsport, Pennsylvania. TerrAqua Resource Management (TARM) built an 80 000 ft2 (7500 m2) facility to treat flowback and produced water using chemical and pH control processes. The TARM facility uses 96 separate tanks, each storing 21 500 gal. (81 m3) of water. The tanks store each client’s water separately, and the water is never commingled. The trucks return the same – but treated – water to each client. The facility obtained a special beneficial re-use permit. In each case, the solids are disposed of in landfills. Flash evaporation facilities have recently been used in McKean County, Pennsylvania and Taylor County, West Virginia by Purestream Technology. The evaporation units use waste heat from gas turbines, compressors or high efficiency burners to concentrate frac and produced water to TDS concentrations of 300 000 ppm while releasing low temperature steam. Similar units reclaim produced and flowback water using low pressure vapour recompression technology. Mobile treatment units, by companies such as Aquatech, are starting to appear.

Given the economic climate in much of Pennsylvania and nearby states, and the large numbers of disused industrial operations that have water treatment facilities that could be used to treat shale gas process water, treatment facility creation does not have to be a case of building everything from scratch.

With several impoundment and storage facilities, focused in areas where shale gas activity is the greatest, it would be possible to preserve water resources, minimise the need for disposal, reduce water hauling along roads, and reduce costs for members of the industry.

A co-operative approach to managing water issues by the shale gas industry can go a long way to improving relations with regulatory authorities, political leaders, NGOs and neighbouring residents. O T

Figure 3. Reserved environmental frac and produced water treatment plant in Mount Pleasant, Pennsylvania.

Table 1. Range of major treatment options

Treatment Where? RemovesCosts (US$/bbl)*

Issues

Deepwell disposal

Offsite EverythingUS$ 1.5 – US$ 8

Cost depends on distance

ClarificationOffsite or onsite

SolidsUS$ 1 – US$ 5

May include filtration, solids disposal, reuse by blending with fresh water

Chemical precipitation

Offsite centralised treatment

Solids, Ba, Cr, Fe

US$ .50 – US$ 4

Clarification, filtration, solids disposal, reuse by blending with fresh water

Thermal treatment

Offsite centralised treatment or portable units onsite

EverythingUS$ 4 – US$ 6

Pretreatment, reduced pressure evaporation/crystallisation, salt reuse (?), blend water with fresh water

*Assumes haul distance of 1 hr or less.

In the words of Einstein, “Information is not knowledge.” Those words have never been truer than when used to describe today’s technically advanced upstream oil and gas environment. After years of technical advancement and investment in databases,

connectivity, and functionally targeted applications, data is pervasive. What was once a tactical investment has become a fl ood of data. Useful information, yes, but still lacking the contextual relevance to address the needs of a younger, less experienced, workforce operating in an environment more dynamic and competitive than ever. Without contextual relevance, too much information creates chaos.

David Muse, P2 Energy Solutions, USA, covers the importance of institutionalising tacit knowledge and providing the contextual relevance that enables a consistent, predictable operational environment.

SECURING INSTITUTIONAL KNOWLEDGE

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Experts tell us that nearly 40% of the oil and gas workforce will turn over in the next 15 years due to retirement. Pressures are great to harvest this knowledge before it walks out the door. Simply having information, however, does not enable competitive advantage. Competitive advantage comes from what you do with that data, how you apply contextual relevance to it, and, ultimately, how you embed organisational best practices into day-to-day operations. This alone will help the new generation of leaders sustain present day operations and facilitate innovation.

To better understand how best to address this emerging issue, it is worthwhile to understand the difference between ‘explicit’ and ‘tacit’ knowledge. Explicit knowledge is data that is captured in documents, training manuals, rules, emails and written notes. It is easily captured and can be broadly distributed. On the other hand, tacit knowledge is knowledge embedded within an organisation. This is developed over time and resides in individuals, networks and communities. It is knowledge such as how to drive optimal ‘release-to-drill’

time at a given asset, or how to drive co-ordination between multiple disciplines within the context of varying equipment, dynamic subsurface structure, and budget constraints. Tacit knowledge is not easily made available in a best practice manual. This is why tacit knowledge is critical to retaining competitive advantage during the emerging demographic shift. How a company approaches the institutionalisation of its tacit knowledge will determine its future competitiveness.

Of course, one approach to retaining competitive advantage is to simply find more experienced employees. This trend has grown as oil and gas firms’ contractor populations

represent 50% or more of their employee base. This strategy, however, is a ‘stop gap’ measure at best. Within the inventory of human capital, experience is becoming scarcer and its cost is pressing traditional operating cost limits. To address this, companies have invested in a variety of training programmes to increase their capacity to transition new hires and close the productivity gap. This mainly addresses the ‘explicit knowledge’ needs of an organisation, while only peripherally addressing the interdisciplinary need to learn how to function as a collaborative organisation. Understanding how each individual discipline interacts with other disciplines, and how those unique activities contribute to the ongoing operational results, is what companies must retain.

The oil and gas industry was founded on disciplinary excellence, specialisation and the division of labour. Excellence in petrotechnical capabilities, followed by excellence in drilling, pretty much guaranteed successful operational results. One unintended consequence of this evolution was the formation of silos within organisations, resulting in wider and deeper divisions between disciplines. When simple systems evolve into complex systems with many more variables, deep divisions of labour frequently dilute productivity and work against an organisation. The complexity of today’s oil and gas operations requires a new approach to capturing the tacit knowledge of an organisation, an approach that enables embedding day-to-day operations to drive contextual relevance in each discipline. This is essential for the organisation as a whole to better understand individual contributions and their impact on corporate performance.

One perennial example of how a single silo can affect the entire process of a development is permitting. No one can drill a well until they have a permit. This requires employees in land, geology, engineering, and construction to be on standby, waiting to drill. But those stakeholders cannot move forward with their role in the drilling process until the permit is approved. To gain a permit, other actions may be required such as resolution of a surface disagreement, an environmental impact statement, or an archaeological report.

These activities could take a year or longer before a permit can be approved. As a result, all stakeholders involved in the drilling stage of an individual well must be kept up to date about the permitting status, because if a problem arises stakeholders need to shift other wells to a higher priority, otherwise costs

Figure 2. Theory of Knowledge Creation.1 According to this theory developed by Kujiro Nonaka and Hirotaka Takeuchi, tacit knowledge represents the accumulated knowledge of individuals, communities, and collaborative systems learned over time by employees. This knowledge, if not captured in an organisation’s routine operating systems, will walk out the door as baby boomers retire in the ‘Great Shift Change.’

Figure 1. The aging workforce.

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balloon. This underscores the importance of having the necessary workflow in place to assist in managing the business process, but it is even more important to provide insight into how the company is progressing against specific goals within that specific workflow. To use another analogy, knowing how to do something is not nearly as important as knowing why.

Another way to consider the importance of workflow process is with shale plays, where effectively geological risk has been replaced with execution risk. Shale plays almost always require a manufacturing approach to drilling, elevating the real question to, ‘how does one drill more wells with less resources?’

One way to systemise business practices in the oil and gas industry is to institutionalise core business processes, leveraging a new generation of workflow engines embedded within software. When global business processes are stored innately within software, tacit knowledge is maintained despite interdisciplinary movement of personnel across an organisation. This approach replicates core processes, provides visibility for financial control, and ultimately leads to better, faster decision-making, without relying on individuals to consistently execute core business processes.

Incorporating business process in software: Establishes a common information platform that crosses

functional disciplines.

Synchronises core goals across an upstream organisation.

Provides contextual relevance linked to efficiency goals.

Accelerates recovery of oil and gas from a reservoir by improving well lifecycle efficiency.

The Wellcore team at P2 Energy Solutions has delivered on this vision. By achieving a broad well lifecycle solution that addresses the specific needs of each discipline and the platform to enhance collaboration between operational divisions, Wellcore provides the organisational contextual relevance that ensures a new level of efficiency in a company’s field development cycle. From geology and

Figure 3. This example of the well lifecycle illustrates how technology solutions establish a framework for optimising workflow across the entire lifecycle of a well.

prognosis, through rig scheduling, various constituents may not need to know specific details of another discipline, but they all must work together on a platform to answer critical questions, such as:

Are we drilling the best mix of wells from the portfolio to assure land retention while maximising cash flow, ROI, and appropriate production and reserves growth?

Can we translate data from such operational measures as drill bit performance, production to hydraulic fracture volume, and production to horizontal borehole length into quantifiable business metrics that let us access our performance against plan?

Do our systems enable us to drive continuous improvement in our drilling cycle?

Do the systems we use embed best practices into our routine workflow as the company evolves?

P2 has proven that solutions, such as Wellcore, enable an entire organisation to understand each discipline’s relevant contribution to corporate objectives. More importantly, this allows for the capture and codification of a company’s explicit knowledge through advanced workflow and translation of data into consumable, actionable information. P2 believes future productivity will largely come from the way an organisation collaborates, its efficiency in translating information into value, and how its engagement of all disciplines work together to facilitate timely, well-informed decisions.

So should one challenge Einstein’s assertion that “Information is not knowledge?” Yes! The sooner it is recognised that data accumulation and traditional knowledge management only addresses a single component of the problem – explicit knowledge, the quicker organisations will institutionalise tacit knowledge and provide the contextual relevance that enables a consistent, predictable operational environment, regardless of tenure and background. O T

Reference1. Ikujiro, N and Hirotaka, T., The knowledge creating company:

How Japanese companies create the dynamics of innovation (New York: Oxford University Press, 1995), p. 284.

ADVANCING SEISMIC RESEARCH WITH MODULAR FRAMEWORKS

In many disciplines a greenfield project is one that lacks any constraints imposed by prior work. The analogy is to that of construction on ‘greenfield’ land where there is no need to remodel or demolish an existing structure. However, pure greenfield projects are rare in today’s interconnected world. More often one must interface with existing environments

to squeeze more value from existing data assets or add components to a process, manage new data, etc. Adding new technologies to legacy platforms can lead to a patchwork of increasingly brittle interfaces and a burgeoning suite of features that may not be needed by all users. Today’s challenge is to define the correct ‘endpoints’, which can join producer and consumer components in a configurable environment.

This article highlights a strategy used to develop new seismic interpretation technology and the extensible platform that will host the application. The platform, which is codenamed Paradise, includes an industry standard database, scientific visualisation and reporting tools on a service-based architecture. It is the result of extensive research and technology evaluations and development.

Geophysical Insights develops and applies advanced analytic technology for seismic interpretation. This new technology, based on unsupervised neural networks (UNN), offers dramatic improvements in transforming and analysing very large data sets. Over the past several years, growth in seismic data volumes has multiplied in terms of geographical area, depth of interest, and multiple attributes. Often, a prospect is evaluated with a primary 3D survey along with five to 25 attributes

Felix Balderas, Geophysical Insights, USA, discusses how geoscientists can

utilise the newest technology to solve today’s E&P challenges.

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serving general and unique purposes. Self-organising maps (SOM) are a type of UNN applied to interpret seismic reflection data. The SOM, as shown in Figure 1, is a powerful cluster analysis and pattern recognition method developed by Professor Teuvo Kohonen of Finland.1

UNN technology is unique in that it can be used to identify seismic anomalies through the use of multiple

seismic attributes. Supervised neural networks operate on data that has been classified so the answer is known in specific locations, providing reference points for calibration purposes. With seismic data, a portion of a seismic survey at each logged well is known. UNN however, do not require the answer to be ‘known’ in advance and therefore are unbiased. Through the identification of these anomalies, the presence of hydrocarbons may be revealed. This new disruptive technology has the potential to lower the risk and time associated with finding hydrocarbons and increases the accuracy of estimating reserves.

The company decided to build new components separately, then, with loosely coupled interfaces, add back the legacy components as services. In its efforts to build a new application for the neural network analysis of seismic data, Geophysical Insights struggled to find a suitable platform that met the goals of modularity, adaptability, price and performance. While in the process of building new technologies to dramatically change seismic interpretation workflow, an opportunity arose for a new approach in advancing automation, data management, interpretation and collaboration using a modular scientific research platform

with an accessible programming interface.

With this new technology concept underway, an infrastructure was needed to support a core technology and make that infrastructure available for others. To deploy their own core technology, they would potentially need databases, schemas, data integration tools, data loaders, visualisation tools, licensing, installers, hard copy, and much more. While not everyone would need the numerous lower level components, they would find that there is more work to be done on the supporting infrastructure than on the core technology itself. Without a platform, each vendor would have to undergo the long process of gathering requirements, developing, testing, and evaluating numerous frameworks, all for something that is not their core product. This is not only a major distraction from developing the core technology, but also an expensive endeavour that most are not ready

Figure 1. Self-organising map (SOM) attribute clusters.

Figure 2. A software framework for hosting oil and gas software applications.

to make, and in some cases perhaps a deal breaker for the project.

The company decided to move forward, developing a platform for itself that would be useful for others. The basic concepts around the chosen architecture are depicted in Figure 2. The goal was to build an affordable, yet powerful platform that could be used by small and large organisations alike, for building and testing new software technologies and shortening the time between design and deployment of new components. Developing a platform separate from the core component meant that it was possible to overlap the development activities for the core component and platform. This minimised the impact that changes in the platform had on the science component and vice versa, thus reducing delivery time. Similar platforms already existed but due to their price, these were out of reach for many smaller vendors and potential end users. Any vendor wanting to promote a simple tool integrated on pricey platforms would fi nd a limited audience based on who could afford the overall platform. End users would probably pay for extra but perhaps unused features. One of the company’s goals was for a modular, affordable overall platform. A vendor of a new component can choose to license portions of the Geophysical Insights’ platform as needed. A good software design practice is to include end users early in the process, making them part of the team. One thing that they made clear was their sensitivity to price, particularly maintenance costs.

The new generations are more accustomed to working with social collaboration and mobility tools. No longer can a

scientist bury himself behind a pile of literature in a dark offi ce to formulate a solution. With the changing demographics of geoscientists entering the workforce and declining research funds, the lag time between drawing a solution on the white board and when it can be visualised remotely across many workstations must be reduced.2 These are some of the challenges this platform tackles.

Design and architecture are all about trade-offs. One of the earliest decision points was the fundamental question of whether to go with open source or proprietary technology. This decision had to be made at various levels of the architecture, starting with the operating system, i.e. Linux versus Microsoft or both. Arguments abound regarding the pros and cons of open source technologies such as security, licensing, accountability, etc. In the end, although it was felt that Linux dominated server applications, when looking at the potential users, the majority would be using some version of Windows OS. This one early decision shaped much of the future direction, such as programming languages and development tools.

Evaluations were conducted at various architecture levels, taking time to try out the tools. The company designed data models and evaluated databases. For programming languages and development platforms, C++, C# with MS Studio IDE and Java with Eclipse IDE were evaluated to search for mixed-language interoperability, reliability and security. Java/Eclipse IDE did not meet all the set goals, instead better mixed language programming support was discovered between managed C#/.NET code and unmanaged

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Fortran for some scenarios. Other scenarios required multiple simultaneous processes.

At the GUI level, the company looked at Qt, WinForm and WPF. It was decided to use WPF because it allows for a richer set of UI customisation including integration of third party GUI controls, which was also evaluated. Licensing tools, visualisation tools and installers were also examined. (All of this is a bit too much to discuss here in detail, but Geophysical Insights advocates taking the time to evaluate the suitability of the technology to the application domain.)

The company also considered standards at different levels of the architecture. There is usually some tension between standards and innovation, so caution was needed about where to standardise. One component that appeared as a good candidate for standardisation was the data model. Data assets such as seismic and well data were among the data that needed to be worked with, but the information architecture also required new business objectives that were not common to the industry. For example, the analytical data resulting from the neural net processes. A data model was required, which was simultaneously standard, yet customisable. It also needed to have the potential to be used as a master data store.

Professional Petroleum Data Model (PPDM) is a great, fully documented, and supported master data store, which shares a lot of common constructs with several other proprietary data stores, and has a growing list of companies using it. PPDM builds a platform and vendor independent, flexible place to put all the E&P data. The company actively participates in that community, helping to define best practices for the existing tables while proposing changes to the model.

Research, including attendance and participation at industry conferences and discussions with people tackling data management issues, made it clear that the amount of data, data types and storage requirements are growing exponentially. The ‘high-water’ marks for all metrics are moving targets. It will be a continuing challenge to architect for the big data used by the oil and gas business. ‘Big data’ refers to datasets that are so large they become awkward to work with using typical data management and analysis techniques.3 Today’s projects may include working with petabytes of data. Anyone building a boutique solution today will have to be prepared for rising high-water marks, and if they depend on a platform, they should expect the platform to be scalable for big data and extensible for new data types.

Neural networks in general, when properly applied, are adept at handling the big data issues through multi-dimensional analysis and parallelisation. They also provide new analytical views on the data while automated processing eliminates human-induced bias, enabling the scientist to work at a higher level. Using these techniques, the scientist can arrive at an objective decision at a fraction of the time. In the face of a data deluge and a predicted shortage of highly skilled professionals, automated tools can assist in achieving the increasing productivity demands placed on people today.

The usefulness of a platform depends heavily on the architecture. Geophysical Insights has witnessed how rigid architectures in other software projects can become brittle over time, causing severe delays for new enhancements or modifications. However, business cannot wait for delayed improvements. Rigid architectures limit growth to small

incremental steps and stifle the deployment of innovations. Today’s technology change rates call for a stream of new solutions, with high-level workflows including the fusion of multi-dimensional information.

A well designed architecture allows for interoperability with other software tools. It encompasses the exploration, capture, storage, search, integration, and sharing of data and analytical tools to comprehend that data, combined with modern interfaces and visualisation in a seamless environment.

Good guidelines for a robust architecture include Microsoft’s Oil and Gas Upstream IT Reference Architecture. Another is IBM’s Smarter Petroleum Reference Architecture.

It was decided to implement the platform on Microsoft frameworks that support a service-oriented architecture. A framework is a body of existing source code and libraries that can be used to avoid having to write an application from scratch. There are numerous framework and design pattern choices for different levels of the architecture and too many for a review here. Object Relational Mapping is a good bridge between the data model and the application logic and the company also recommends N-Tiered frameworks.

Personnel who understand the business domain and the technology must carry out the implementation – otherwise one must plan to spend extra time discussing ontology and taxonomies. They must adhere to efficient source code development practices. The changing work environment will require tools and practices to deal with virtual teams, virtual machines and remote access. The company is using a test driven development (TDD) approach. This approach increases a developer’s speed and accuracy. It keeps requirements focused and in front of them, eliminating time spent on unnecessary features. It also enables parallel development of interdependent systems. In the long run, it yields dividends by reducing maintenance and decreasing risk. Using TDD, a developer can deliver high quality code with certainty.

Ultimately, the science has to come down to business. A good licensing strategy is one that will maximise revenues and allow users to buy products a la carte as opposed to a one-size-fits-all approach. Some vendors attempt to be creative with bundles for different levels of upgrades, but a configurable platform allows maximum user choice among available, even perhaps competing technologies. The market will favour vendors that innovate and manage data and licenses well.

Geophysical Insights’ neural network application presents an opportunity to examine seismic data in ways and means orthogonal to those of the legacy systems today. The research platform enabled the company to use this application as a configurable service. Making the right choices in information and application architectures and frameworks was the key to achieving the business objectives of modular services. The company can now move forward with additional science modules and tangential neural network processes, servicing a rapidly changing landscape, licensed to fit specific needs. O T

References1. Kohonen, T., Self-Organising Maps, 3rd ed. (2001).2. American Geological Institute, ‘Geoscience Currents’,

www.agiweb.org/workforce/currents.html (Accessed on 29 July 2011).3. The Professional Petroleum Data Management Association, www.ppdm.org

(Accessed on 29 July 2011).

A t a time when oil resources are becoming scarce and more and more costly to produce, operators are looking for better reservoir production and recovery. Managers must derive E&P strategies that

combine profitability and sustainability to make the best of the oil resources available.

When looking at it more closely, there are two ways for optimising reservoir management: improved technology and less uncertainty. The technological side is well documented and discussed in all oil forums as it has been the key factor in the past two decades for proving additional reserves.

The producing life of entire oil basins, such as the North Sea basin for example, has been drastically lengthened due to technological improvements; is this not addressing the way oil reserves are defined and computed? More information means less uncertainty, but to what extent is this valid and at what cost?

This article explores this uncertainty and shows how properly managing uncertainty can lead to profitability and sustainability.

Turning chance into profit

Luc Sandjivy, Seisquare, France,

suggests how to deal with uncertainty

in reservoir management.

29


Uncertainty in the E&P sectorOil and gas operators face uncertainty each time they make exploration and production decisions as they never know exactly where to find oil or how much there will be.

Uncertainty is at the heart of the E&P business and, as a result, E&P decision making procedures are not optimal.

Optimal decisions Optimal decision making is a procedure that would be ‘optimal’ if the oil resource was fully visible and accessible anytime and anywhere, which is never the case as it is is always hidden underground and only partially discovered or sampled. This kind of optimality

definition is specific to all natural resource management sectors and is one of their main characteristics.

In other words, if operators knew exactly where to find oil and how much was present, they would be able to optimise their development and production plans as a standard industrial cost/profit trade-off. No doubt optimality would depend on available technology, but it would not be impacted by uncertainty.

Impact of uncertaintyConsider an example elaborated from an actual exhaustive natural resource data set.

Suppose a company was asked to bid on the net value of 36 square blocks (size = 25), sampled by their central sample (size = 1) only. A block is profitable (positive net value) only if its average value is above 300 (in terms of US$ thousand).

How many blocks would the company select above US$ 300 000 average value and what is the expected profitability?

Profit = (Average block value - 300) x number of selected blocks x 25 (block size).

A straightforward answer is to select the blocks according to the net value of their central samples. Then select 10 blocks (average 10 blocks value = US$ 472 000), and one can expect a profit (net value) of: (472 - 300) x 10 x 25 = US$ 43 million.

Suppose the bid has been successful, and a company is awarded the 10 blocks.

10 blocks have been recovered (average 10 blocks value = US$ 358 000), and profit (net value) is: (358 - 300) x 10 x 25 = US$ 14.5 million.

These figures are still profitable but initial expectations have been divided by three. This is the impact of uncertainty.

Figure 1 displays the actual block values from which it is possible to compute the optimal selection and profit. Optimal selection is 11 blocks; average value is US$ 382 000; profit (net value) is US$ 22.5 million.

Notice that this optimal selection is out of reach unless there is direct access at the actual block values. In real oil E&P cases, this is not the case due to uncertainty.

What does this example illustrate?

Figure 2. U DO operational context.

Figure 3. The MoRe solution. Figure 4. Stochastic block model.

Figure 1. Actual block values and optimal selection.

The expectation of a US$ 43 million profit was simply unrealistic, and this should have been anticipated at the time of deciding which blocks to bid on.

The maximum US$ 22.5 million profi t resulting from an optimal selection of blocks (based on actual block values) should also have been anticipated at the time of making decision.

Uncertainty always leads to a loss when compared to optimality (several wrong blocks are always selected, and right ones are always discarded), and this is tricky as one can recover more than expected (although it is always less than in the optimal case).

Uncertainty in this fi eld almost always results in loss. Operators never recover what is expected from an oilfi eld, due to a lack of a direct access to the whole fi eld (optimality).

Understanding uncertainty The word ‘chance’ simply expresses a lack of knowledge at the time of decision making. In order to turn this into profi t, it is essential to fi rst understand how uncertainty works:

The U DO operational contextThe U DO operational context is

summarised in Figure 2. When making E&P decisions,

operators (O) are facing uncertainty (U), because the available information about the reservoir data (D) never matches the real reservoir (Re). In the previous example, at the time of bidding on the net value of the blocks, only the value of the central sample is available, not the actual values of the blocks.

To make sense and enable the decision making process the data (D) are fed into a model (Mo) that will mimic and replace the actual unknown reservoir to support the operational (O) decision making procedure. Model: the value of the central sample is considered as representative of the unknown true average value of the surrounding block. It will replace the unknown true block value when selecting the valuable blocks.

The operational decision (O) made from the model (Mo) is applied to the actual reservoir (Re), and because of uncertainty (U), the observed recovered output of the procedure never equals the one expected from the model (Mo). The 10 selected blocks show an actual net value of

US$ 14 .5 million; the expected value from the model was US$ 43 million.

The MoRe solutionNow that uncertainty has been understood, it is evident that at the time of making an E&P decision, the only choice left to the operator (O) is the choice of the model (Mo) as explained in Figure 3.

This means that in order to properly handle uncertainty (U), it is essential to make a decision from models (Mo) that are properly designed to quantify it. This is the purpose of stochastic modelling to minimise the unknown difference between the model and the reservoir; this is the way to turn chance into profi t.

The UDOMoRe compassThe UDOMoRe compass is a tool that points to the relevant stochastic model that enables one to properly address the operational issue (the U DO context) with consistent uncertainty quantifi cation (the MoRe solution).

Reverting to the previous example – at the time of bidding on the block values, suppose a company has contacted a ‘stochastic expert’ for advice.

With the same available information (35 sample data set), the ‘stochastic expert’ would activate the UDOMoRe compass and suggest that if the company were to bid immediately, with 35 sample information, it should bid from the block model in Figure 4, and only select 7 blocks (average 7 blocks value = US$ 367 000). Expected profi t would be: (367 - 300) x 7 x 25 = US$ 11.7 million.

The bid is much less attractive than before, but should the company decide to carry on, expected recovery would be: 7 blocks (average seven blocks value = US$ 374 000), and the profi t would be: (374 - 300) x 7 x 25 = US$ 12.95 million.

US$ 12.95 million recovered compared to US$ 11.7 million expected with only seven blocks, which makes sense according to the stochastic expert. However, the expert would have warned the company before: the level of confi dence on the block stochastic model is quite low (+/- US$ 100 000 confi dence interval around the current block estimated value).

Oil resource managementThe UDOMoRe compass can be used for making an E&P decision. Consider the example of implementing a new well when delineating a new discovery.

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The well has proved an oil discovery. The next operational issue is to consider the gross rock volume attached and where to best locate an additional well to prove additional reserve?

The usual way to address this E&P issue is to derive a base case depth model from the well depth markers and the geophysical interpretation and to compute gross rock volume above the oil contact identified at the discovery well. As uncertainty cannot be

handled using a standard depth modelling flow chart, alternative depth scenarios may be produced empirically.

Using a stochastic methodA similar depth base case would be produced (same velocity model assumption) but it would also display the confidence interval around it. This is displayed in Figure 5, where uncertainty (confidence interval) is figured as a shadow covering the depth model. The darker the shadow, the less confidence a company may have in the depth model.

And what is the impact of this uncertainty shadow on the volumetrics and location of the next wells? The same stochastic model leads to additional useful outputs:

GRV risk curve The GRV risked curve explores the GRV volume distribution that is consistent with the confidence interval. It enables the reading of probability 90 (certain) and probability 10 (uncertain) GRV figures that will guide the decision on the field development.

Probability mapThe probability map displays the impact of uncertainty on hitting the reservoir above the identified oil contact at the discovery well.

In bright green, areas with high probability to hit the reservoir above contact, in dim green, areas with low probability. It highlights the location of possible structural closure and guide the implementation of the next delineation well.

Remaining potential map The remaining potential map displays the areas with best potential to prove additional reserves. Areas with high potential to prove additional GRV are shown in bright purple. It guides the implementation of the next delineation well by locating the best structural locations for proving a maximum GRV.

Going stochastic?This article has presented a UDOMoRe understanding of how E&P uncertainty works. There is no magic behind it and no chance. Only operational E&P decisions need to be made, using available data that will never replace the actual hidden natural resource and the need for a profitable and sustainable production: stochastic E&P modelling is the safest way to match these expectations. O T

Figure 8. Remaining potential map indicating best structural location for additional well implementation.

Figure 7. Probability map to hit the top reservoir above the oil water contact.

Figure 5. Depth base case and attached uncertainty as a shadow. Figure 6. Gross rock volume expectation curves above contact and spill point.

Cross-checking the checklist

Highly integrated control systems (drilling, dynamic positioning, power management and subsea) are an integral component of fi fth and sixth

generation drilling assets. These systems have the potential to signifi cantly improve safety and environmental performance while reducing nonproductive time (NPT), but the complex software required to operate them often introduces new risks that can diminish this potential.

Currently, the oil and gas industry addresses complex, integrated systems risk through prescriptive, stand-alone design, testing and integration methods. These are not enough. In order to reduce systems risk to acceptable levels, the industry needs to implement a holistic, systems-orientated approach that recognises and addresses the residual risks that accrue along the system lifecycle.

Cross industry experienceMore effective control system software quality assurance and risk reduction processes are well established in other industries that rely on large, one-of-a-kind systems integration projects similar to high-specifi cation offshore assets (e.g. semiconductor fabrication facilities and aerospace manufacturing plants). These industries have implemented control system software quality assurance and risk reduction methods that are backed by international standards from IEEE, ISO and IEC, and go beyond standalone, prescriptive solutions. These methods have gained further validation through the introduction of integrated software classing standards by classing agencies such as the American Bureau of Shipping.

However, all of the aforementioned standards are process-generic, not solution-specifi c. Depending on the source of the standards, they include checklists and/or procedures – but they do not provide the specifi c implementation methods required to help ensure the most effective approach to control systems software specifi cation, development, testing, and integration for a specifi c project.

For example, the new class rules for integrated software control systems describe the requirements for typical software development lifecycle verifi cation and validation activities, and acceptance testing. The class rules are drawn from the original standards published by the IEEE, ISO and IEC. However, while they are very specifi c about the activities to be performed, none of the rules provide guidance as to what constitutes a

Bill O’Grady, Athens Group, USA, discusses managing

risks as high specification offshore

assets are being drilled in deeper waters and

harsher environments.

33


good requirement verification and validation process, or a good acceptance test. They simply require that these activities be performed.

Reducing systems risk in the oil and gas industrySpecificity is important in the oil and gas industry because the systems on each high-specification asset (even supposed sister ships) are different, and the definition of fit-for-purpose is dependent on many different criteria (e.g., where the asset will be drilling). A systems-oriented, holistic approach recognises, from the very beginning of a project, that all of the individual components being developed will eventually be integrated into a complete system. This helps ensure that each component is conceived, specified, designed and tested as a system. This is the most cost-effective way to reduce control systems software-related risk on offshore assets to adequate levels.

This type of approach to quality assurance and risk reduction starts with process-oriented standards and then incorporates solutions-oriented practices that have been proven to cost-effectively reduce risk on offshore oil and gas assets. This is achieved through three steps:1. Specification of the system use model through a

Concept of Operations (ConOps) document.

2. Contractual language that establishes clear expectations for software systems development, validation and verification.

3. A residual risk-based approach to validation and verification activities across the entire lifecycle.

The balance of this article describes this approach in more detail and defines how it enables asset owners to reduce risk by focusing on more effective early lifecycle preparation and planning, and implementing a systems approach throughout the entire asset lifecycle.

ConOps The creation of a ConOps document is the first step in a systems-oriented, holistic approach to risk reduction. This

document defines the system that the end user wants the vendor to build. This is an important step, because the ConOps document governs the entire system development, verification and validation lifecycle. It describes how the system will operate, from the end user’s perspective. The Software Requirements Specification (SRS), Software Design Specification (SDS) and validation and verification test plans are all generated from the document.

A good ConOps document should also include a determination of integrity level (IL) for all major software components (a concept taken from the IEC 61508/61511 standards that cover process and system safety). This forces the end user to specifically determine the acceptable risk levels for each component, as well as for the target system.

Strong contractual language The second step, implementing strong contractual language, sets the expectations for the project execution. Adopting holistic processes will impact the roles and responsibilities of all stakeholders

across the project lifecycle so it is important to contractually define specific expectations for:

How system requirements and design will be verified.

How and when risks and hazards will be identified through the FMECAs.

Where and when system verification and validation activities will occur.

How and when validation test plans will be provided.

The contract should also specify that a residual risk-based approach will be used for all verification and validation activities.

Residual risk conceptThe third step is the implementation of a residual risk-based view of validation and verification activities across the entire asset lifecycle. Acknowledging residual risk is important because it enables the development of specific targets and metrics for acceptable risk levels at all points in the project lifecycle, in addition to executable procedures and checklists. This allows risk levels to be determined and tracked as they increase or decrease throughout the course of the project.

Considering that the impact of residual risk shifts the focus away from following generic test plan procedures and checklists in order to detect defects that impact safety and NPT at acceptance testing and commissioning. Instead, the focus is on helping prevent those defects at the source – the design, development and integration of the system. The concept behind this approach is illustrated in Figure 1.

During a typical project lifecycle, risk is introduced during development phases and reduced (but not eliminated entirely) during the validation and verification phases. The single risk cycle shown in Figure 1 would occur many times as the project phases progress. The residual risk from one project phase becomes the inherited risk of the next project phase. Figure 2 provides an example of a risk scorecard.

These systemic risks build up over the lifecycle and result in safety, environmental and NPT issues that often remain undetected until later when they are most costly to mitigate or,

Figure 1. Residual risk concept. ©Athens Group 2011.


35

even worse, when an incident actually occurs, resulting in NPT or a health, safety or environmental (HSE) incident.

In a recent industry survey, 100% of respondents reported that software being delivered and tested too late in the newbuild cycle negatively affects NPT and safety incidents. 59% of respondents indicated that the development of software specific risk mitigation plans early in the lifecycle presents a large opportunity to reduce control systems software related NPT.1

Current versus recommended process examplesA good example of the value of this three-step approach is the comparison of a current approach to Factory Acceptance Testing (FAT) versus a FAT conducted using a holistic, systems-oriented approach.

A typical drilling control system (DCS) software FAT test plan is based on standard vendor templates that do not fully represent the end user requirements or use cases. Instead, the test plan typically focuses on verification that the internal software signals reach the correct PLC register addresses. While this is a crucial test, it should be performed as part of the internal software engineering test plan, not a FAT. This type of testing is focused on the DCS as an individual component test and does not meet the objectives of a FAT (i.e., to allow the customer to validate the DCS is performing to specified intended use, which is to control an integrated drilling system). As such, the typical DCS FAT does not provide adequate test coverage and does not address the risks introduced through the integration of the equipment.

A holistic lifecycle approach that implements the three steps would significantly improve test coverage at FAT and would provide residual risk metrics that help ensure successful issue resolution, as well as execution of the later lifecycle activities such as commissioning and site integration testing.

The ConOps document would provide a complete description of how the user wants the DCS to operate, including the integrity levels for each DCS software component. These descriptions provide the basis for the types of test plans and test coverage that will be required at all phases of the project, starting with the FAT and continuing throughout the lifecycle. From the ConOps document, the vendor can create a more appropriate SRS and SDS.

A well-written contract would provide specific milestones that all stakeholders expect to be met. In the case of the testing activities, the contract would specify that the SRS, once created, would be subject to end user review and approval through a requirements validation activity. The requirements validation activity includes verification that each requirement includes the specific tests that would be performed to verify that requirement. The contract would additionally require that an operational FMECA attended by the end users (not just the vendor design teams) be performed as part of the design verification.

With the ConOps document, SRS, requirements validation, design verification and FMECA complete, all the elements for a more effective FAT test plan are in place. Long before the FAT is ever scheduled, the stakeholders define and agree on the requirements that will be tested, the test plan for each requirement, and the expected test coverage.

Implementing this approach from the beginning of the project helps ensure that, when the FAT does occur, as much risk as possible has already been removed from the system, and the risk that remains is at a known acceptable level.

All the ensuing lifecycle activities (e.g. site acceptance testing, commissioning and site integration testing) gain similar benefits from the emphasis on early preparation and definition of expectations, and the use of the residual risk approach. These activities then become appropriate validations of operations rather than ‘bug hunts’ for errors in the control system.

A recent refurbishment and upgrade of an offshore asset provides a practical example of using a holistic, systems-orientated approach. At the start of the project, the specific concept of operation for the new DCS was clearly articulated. As a result, there was a full validation of the new DCS Human Machine Interface (HMI) requirements and verification of the design. During the design verification, two significant errors were found in the new HMI which, in turn, led to the discovery of control software capability omissions directly related to the HMI errors. It was determined that these errors would not have been discovered in a typical DCS FAT or during commissioning. In all likelihood, they would not have been found until the asset was functional and a potentially dangerous operational condition existed.

SummaryToday’s high specification offshore assets are drilling in deeper waters and harsher environments, and integrated control systems on these assets are complex, dynamic and mission critical. Now more than ever, the industry needs innovative processes that enable drilling contractors and operators to effectively minimise and manage the risks introduced by these complex systems. This need can be met through the holistic, systems-based approach outlined here.

To date, the industry has managed risk through standalone procedures and checklists. These are not enough. Late-generation assets must be designed, constructed, operated and maintained using a process that focuses on the unique characteristics of control systems. By addressing system requirements through a ConOps document, contractually specifying systems-related expectations, and addressing residual risk throughout the lifecycle, asset owners and operators can effectively minimise the risk that a safety and mission critical control system will malfunction, leading to an equipment failure or HSE incident. O T

Reference1. Athens Group, The State of NPT on High-Specification Offshore Assets:

Third Annual International Benchmarking Report (2011).

Figure 2. An example of a risk scorecard.

When does a technological achievement in a particular industry deserve the adjectives ‘game-changing’ or ‘revolutionary?’

Few would argue that those words should not be used in regard to the 25 September 1929 flight of Jimmy Doolittle of the US Army Air Corps. In that pioneering flight, from takeoff to landing, Doolittle used only instruments. In fact, he flew the test aircraft from beneath a hood that completely covered his cockpit. The safety pilot, Lt. Ben Kelsey, sitting in the front cockpit with a clear view, did not have to intervene during the 15 min. flight.

Doolittle’s contribution went beyond being a fearless test pilot. He was also the co-developer of the artificial horizon, precursor of the modern attitude indicator, which made ‘blind flying’ possible. Today we call it ‘instrument flight’; defined as flying by reference to instruments in the flight deck, and navigating by reference to electronic signals.

As for being a game-changer, newspapers heralded the flight with banner headlines such as ‘Fog Peril Overcome.’ Commercial aviation began to implement the lessons learned immediately to make air travel safer, and therefore more profitable, in inclement weather conditions. It was revolutionary.

Ron Boyd, Atlas Copco Secoroc LLC, USA, discusses how new technology

could put an end to drilling blind.

36

SEEING IN THE

DARK

And even though he would go on to win the Medal of Honour in World War II, it is the flight in 1929 that earned him lifelong recognition as an aviation pioneer.

Blind flying ‘down the hole’Doolittle’s accomplishment might be over-simplified as ‘being able to know where you are, even when you cannot see where you are.’ Is there an application of this principal in the drilling industry today, one that promises to be as revolutionary as Doolittle’s flight was to commercial aviation in 1929?

Atlas Copco Secoroc™ thinks that the answer is ‘yes.’ Secoroc, the Rock Drilling Tools division of Atlas Copco, began looking for a way to give drillers ‘eyes down the hole’ almost three years ago, along with its partner, SPC Technology AB, of Stockholm. It calls its solution EDGE.

Atlas Copco’s research and development teams began exploring technology that would take the guesswork out of deep hole drilling. Technology that sped up a new driller’s learning curve and brought relief to experienced drillers. Even the best drillers have to tolerate the stress of long shifts continually guessing what is about to happen to the bit, or drill string, or

37


hole, worrying over whether they could react in time to gauges and the inherent lag of reading cuttings coming up from hundreds, even thousands of feet from the bottom.

The development team started with the premise that each strike of a hammer on the bottom of the hole sends a vibration back up the drill string. They thought of it as a kind of sonar, with unique signatures reporting the characteristics of that particular hole at that particular moment in the drilling. These signatures were travelling at the speed of sound through the steel; for all intents and purposes, almost instantaneously.

The questions that the development team had to answer were ‘Can we capture it? Can we interpret it?’ The company’s partner in this endeavor, SPC Technology AB, brought some special capabilities to the table. SPC touts itself as specialising in software development and vibration analysis.

The Atlas Copco development team further defined the need for something such as EDGE by pointing to the challenges facing deep hole drillers every day, especially that of predicting changes that take place in holes at depths of 100 m or more. When the bit encounters a new type of rock formation that threatens to ‘shank’ the bit, the driller must make adjustments before this catastrophic failure. Or perhaps the problem is that the hole is not being flushed properly and the drill string is in danger of jamming. Again, intervention by the driller is necessary to avoid expensive downtime. Maybe the problem is a slight vibration caused by movement inside the chuck due to insufficient feed force, which gradually reduces cutting capacity.

When can drillers realise the problem, and when do they correct it? Any delay in the proper response can have expensive consequences. It is true that a veteran driller can make assumptions regarding what is happening at the bottom of the hole, based on experience. And some drillers do seem to possess a sixth sense that puts them in a class all of their own. But at best, these assumptions are educated guesses. They parallel the history of the great ‘seat of the pants’ aviators of Doolittle’s day. Doolittle himself was such an aviator, yet he was always looking for ways to be more accurate, to make flight safer, more precise, more productive. He looked for ways in which technology could give him ‘eyes’ when he was blind.

Figure 1. EDGE detailed display.

A closer lookThe EDGE Drill Monitor consists of a sensor, a data capturing and processing unit, and a ruggedised PC with an 18 cm display screen. It can be fitted to all types of deep hole drill rigs that use Secoroc DTH (down-the-hole) hammers.

The sensor is mounted on the drill head or rotation unit, which is connected by a cable to the data capturing unit mounted on the rig. The display PC is mounted next to the drill controls at eye level. The process starts immediately when the piston in the DTH hammer strikes the bit, creating vibration. The vibration is captured, processed and interpreted, and data is transmitted to the PC where it is displayed on-screen, graphically and numerically.

The spikes showing on the display can then be interpreted as representing different in-hole scenarios: for example, the sudden presence of a new type of rock or geological zone. This immediate and continuous feedback enables the driller to

optimise the drilling process from moment to moment.

EDGE in the oilfieldEDGE is aimed primarily at the oil and gas industries, where the majority of drilling is beyond sensory feedback from the surface. It also aims to make DTH hammer drilling feasible for more oil and gas drilling companies.

Percussion drilling typically provides improved penetration rates (from two to five times higher than rotary drilling) and can be used all the way to total depth. The bits are less expensive, and DTH drilling produces straighter holes. Since there is less weight in the drill-string, it is possible to drill deeper with smaller rigs.

Traditionally, however, only a few companies use DTH hammer drilling, because rotary drilling is easier to master, costs less in tooling and offers fewer formation complications for drillers at the bottom of the hole. Too, hammers and bits are more expensive than tricone bits, and are easier to damage. Training is also an issue. The benefits of percussion drilling have been reserved for those companies who could get and keep drillers expert in hammer skills.

But according to Atlas Copco Secoroc, EDGE has changed all that. Like the instruments in Jimmy Doolittle’s hooded cockpit, the EDGE sensor package makes it possible to monitor conditions at the bottom of the hole and react almost immediately, thus saving downtime as well as excess wastage of consumables.

Additionally, the combination of correct weight on bit (WOB) and revolutions per minute (RPM) allows the bit to cut efficiently for every blow of the hammer piston.

Fuel economy is improved by knowing that the hammer is always running correctly for the given conditions. Efficient operation optimises the use of air. The engine to run the hydraulics works less, as does the engine running the secondary compressors or boosters.

Improved training Today’s computer literate trainees are comfortable receiving performance information on a PC display, basing their adjustments on it, and immediately seeing the result of their

inputs. It is not a matter of accumulating years of experience and slowly developing the intuition to fi nally reach drilling standards. Teacher to student or driller to driller, the performance log is a clear, objective communication of what constitutes optimal performance.

For example, in Sweden, it normally takes six to eight months to train a driller up to standard profi ciency. Using the EDGE system, Swedish customers who were part of the test group for EDGE cut this training time dramatically. The geothermal well drilling company SYDAB recently trained a former truck driver to the standard for drilling profi ciency in just a few weeks.

Veteran drillers can enhance their skills as well. Even drillers with years of experience can get back to an optimum penetration rate quicker after making a connection because they can see the ‘sweet spot’ on the monitor rather than waiting for cuttings or circulation indicators. Drillers will not be counting on intuition but on a visual near-real-time display.

Is it a game-changer?Testing in Sweden and the USA was fi nished by the end of last year and early this year. The product is now commercially available, and the fi rst few customers are using the new drill monitor.

In the eastern USA, EDGE has been used in shale and limestone to depths of approximately 1130 m, and in the middle of the country in shale and sandstone to depths of approximately 1000 m. In tests, the EDGE data capture unit was able to receive a signal from its sensor from a depth of over 1800 m.

Technicians in the fi eld say that the system gives them feedback on exactly what the hammer is doing at depth, and enables them to adjust WOB, RPM, and other variables to get the best penetration and to save needless wear on bit and hammer.

The EDGE Drill Monitor will have to prove itself over time to justify the labels ‘game-changer’ and ‘revolutionary,’ but it is clear that the ability to ‘see’ via sensors thousands of feet down a hole being actively

T3 NEW MATERIAL

drilled has the potential to change the way deep hole drilling is done.

Like the pilots of Doolittle’s day, today’s drillers seem perfectly willing to take advantage of the extra capabilities that these sensors provide them. But one lesson being learned is that company drilling procedures that ignore some or all of the benefi ts of new technology will not benefi t as greatly as they would otherwise. Just as giving a pilot instrumentation on the fl ight deck, while keeping the same old policies would result in a 1930 airline falling behind the times, so too in 2012 with drill monitoring technology and the oil industry. O T

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PACIFIC BASIN OUTLOOKLucy Miller, Douglas Westwood Ltd, UK, describes the changing focus of the LNG market towards the Asia Pacifi c region.For further information go to www.energyglobal.com

SYRIAN SANCTIONS TIGHTENEDThe EU has tightened oil sanctions on Syria after the government started a fresh wave of crack-downs on dissent in the country.For further information go to www.energyglobal.com

GE ACQUIRES CONVERTEAM FOR US$ 3.2 BILLIONGE has acquired Converteam. The two companies compliment each other and should enhance GE’s existing capabilities as well as helping it break into fast growing regions such as Brazil and Russia where Converteam has already made signifi cant in-roads.For further information go to www.energyglobal.com

GULF KEYSTONE CONFIRMS DRILLING SUCCESS Gulf Keystone has proved the value of the giant Shaikan fi eld in Northern Iraq after conducting well appraisal tests at its Shaikan-2 well. Drilling is also continuing apace at its Shaikan-4 well. For further information go to www.energyglobal.com

EXTERNAL CASING PATCH EXECUTIONS

Andy Gorrara, READ Well Services, Norway, demonstrates how the application of an external casing patch in one of Statoil’s North Sea fields has reinstated gas tight seals on

several wells, ensuring well integrity fit for field life.

T he company’s external casing patch (HETS-EP) provides a life-of-well gas tight solution for reconnecting casing strings and has been deployed and held on contingency for more

than 50 wells in the UK, Norway, Denmark and Holland since commercialisation. The connection is capable of withstanding bi-directional axial loads at well temperature, whilst maintaining the pressure integrity and full internal diameter of the original casing.

The HETS-EP overshot is run on casing and landed over the casing stub in the well. The casing is then hydraulically expanded into the overshot to form the connection. It is currently available for 7 in., 9 in., 9 in., 13 in., 13 in. and 14 in. casings.

Application in a North Sea fieldREAD Well Services was approached and tasked with qualifying an effective and robust solution to enable Statoil to reinstate production in three wells, where corrosive fluids (pH3) along

Figure 1. READ senior technician working on the HETS tool.

control lines had compromised the integrity of the 9 in. casing string.

The specific requirements presented to READ by Statoil were to deliver a casing reconnection (using the HETS-EP) with a life-of-well, gas tight, metal-to-metal seal qualified to 5000 psi. The patch was also required to carry 300 000 lbs in both tension and compression at operating production temperature (100 ˚C) and have no reduction in internal diameter.

READ embarked on a project to validate and qualify the external patch using the ISO14310 standard with test parameters set specifically to meet Statoil’s requirements. This was in addition to the existing ISO13679 standard using a modified programme developed in the past for external casing patches. The project was a success and the results were beyond the original requirement. Internal pressure was qualified at 5510 psi (V1 gas) and the external pressure 5510 psi (V3 liquid) at 100 ˚C.

41


The HETS-EP was the preferred solution for Statoil because of the qualification criteria and actual results regarding both internal and external pressures.

Delivering the solutionStatoil prepared the well and the existing completion was removed. The 9 in. casing was then plugged deep and the damaged sections within the two completed wells (963 m, 2196 m) were cut and pulled. The casing stump was prepared by washing over with a ‘burn shoe’ and cleaning the cut area to ensure the outer and inner diameters and top of the 9 in. casing had all burs and sharp edges left from the cutting run removed, to enable the external patch to position itself over the stump cleanly.

A new casing section was run in hole with the HETS-EP located at the bottom of the casing string. The external casing patch ‘swallowed’ the stump of the cut 9 in. casing and the casing was then landed in the wellhead.

The expansion tool was run on drill pipe and the expandable system activated with water pumped from surface through drill pipe to the hydraulic intensifier and expansion tool.

Pressure was controlled at surface (up to a maximum of 5000 psi) and intensified downhole to achieve the desired expansion pressure of 24 500 psi above hydrostatic pressure. This high level of hydraulic pressure resulted in the controlled expansion of the 9 in. casing into the HETS-EP, creating the metal-to-metal, gas tight connection.

To validate the integrity of the new connection, a pressure test was carried out from surface (Well 1: 4350 psi, Well 2: 4440 psi).

ROIThe HETS-EP enabled the reinstatement of each well with a life-of-well gas tight seal. The reconnection of the 9 in. offered Statoil the ability to re-complete its wells without having to perform workovers or sidetracks.

The alternative would have been to cut and pull the 9 in. casing as deep as possible (above the top of the cement), and drill a sidetrack below the 13 in. casing shoe, then rerun the 9 in. casing, redrill the 8 ½ in. hole, rerun the 7 in. casing and recomplete the well. The EP solution has saved a significant level of rig time for each well.

Further applicationsAnother operator in the Norwegian sector has recently highlighted a requirement for a deep-set connection. The operator has its next deep sidetrack planned for Q3 2011 and would like to utilise the HETS-EP solution. The existing casing is 9 in. 47# L80, however the operator would like to change this to either 9 in. 53.5# L80, or a tapered string of 10 ¾ x 9 in. down to a depth of 4000 ft. The operator will then reuse the casing and sidetrack the well

below the 9 in. shoe. The EP connection provides a life-of-well gas tight connection for full well integrity.

By utilising the HETS-EP in this way, it will not be necessary to cut and pull the 9 in. casing and sidetrack below the 13 in. casing and re-drill the entire 12 ¼ in. hole section. The operator estimates that it will save 50 days of rig time on this workover which will be, potentially, a NOK 100 million saving for this sidetrack, and would be an attractive option for many future workovers.

Future developmentsREAD has already taken the HETS-EP technology and applied it to casing sizes from 14 in. down to 7 in. The same connection is also available as a liner tie back, providing metal-to-metal seals and removing the requirement for polished bore receptacles and seal-stems.

In addition, the company is investigating methods of developing its technologies in order to deploy across a wider variety of well types, environments, sizes, temperatures and pressures. For example, the company is looking at ways for all of its products to be suitable for use in horizontal wells, and as such is developing its products to suit coiled tubing applications. It is also enhancing its products to suit increasing ranges of temperatures and pressures. For greater breadth of applications, READ is currently developing the HETS-EP product to suit 4 ½ in. and 5 ½ in. casings, enabling operators to perform shallow or deep-set reconnections dependant on the requirements. This will offer significant cost/time benefits to operators. O T

1. The casing is cut and the upper section removed.

2. The HETS-EP is run on new casing, spaced out and landed in the hanger. The connection can be made under tension by running the HETS overshot with a grapple below, the casing stub being pulled up into the grapple with a spear run on drill pipe. Equally, the connection can be set in compression by sitting down the weight of the casing prior to connecting.

3. The HETS expansion tool is run on drill pipe and positioned on depth using an integrated latch mechanism that locates in the HETS-EP.

4. Hydraulic pressure is supplied, monitored and controlled from surface to operate the HETS tool and make the connection. Final expansion pressures are dependent on casing size and metallurgy.

5. The expansion tool is removed leaving a metal-to-metal gas tight connection with no internal casing restriction.

Figure 2. The installation sequence.

HETS-EP installationThe following sequence is an outline operational summary for HETS-External casing patch (HETS-EP) installation:

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Peter Sharpe, Shell, The Netherlands, discusses a joint venture project with CNPC to develop an ‘assembly line’ process for drilling wells.

MACHINERY

44

T o economically develop large fields that require hundreds, if not thousands, of wells, Shell Projects & Technology is turning to a century-old process that has helped

improve efficiency and reduce costs in the automotive and other industries: the assembly line.

Shell and its joint-venture partner, China National Petroleum Corp. (CNPC), are developing a system for mass-producing wells. Instead of using a massive, multi-functional rig with a trained crew to drill each well from start to finish, it would employ a group of smaller, truck-mounted rigs, each of which would perform a single step or series of steps in the drilling sequence. For example, one would drill the top part of the hole, another would drill the intermediate part of the well and a third would do the completion work.

The rigs would be controlled autonomously instead of being operated manually by a drilling crew and would have special tyres that would make them easier to move around the field. After each finishes its work, it would move onto the next well site, and the rig designed to complete the next step in the drilling sequence would move into place. As a result, multiple wells would be in various stages of drilling and completion throughout the field at any given time.

Unconventional fields, unconventional solutionsThe need for a dramatic new approach for field development resulted from a significant shift in the company’s onshore portfolio toward unconventional reserves. Instead of using a dozen very complicated wells, developing an unconventional field requires using a large number of relatively simple wells.

Drilling costs, in fact, represent the biggest expense in the exploitation of an unconventional reservoir. For example, Shell will drill 430 tight gas wells in the US in 2011 and will spend over US$ 20 billion in North America in this sector over the next five years. Between now and the end of the decade, the company plans to drill approximately 30 000 tight gas and coalbed methane wells globally, so it is critical to minimise drilling costs.

The solutions are standardised well design and automated field development. With this goal in mind, Shell began developing algorithms, or rules that precisely define a sequence of operations, to optimise drilling procedures and allow for them to be automated.

Its first significant success was the development, about a decade ago, of a soft torque rotary system with an

45


algorithm-controlled top drive. After some of the kinks had been worked out, the system became very successful. It resulted in faster drilling and fewer drill bit trips into the hole, which increased the life of the bit and led to significant cost savings. This led to the next step of looking at how to further control downhole processes.

The first outcome of this effort was the Supervisory Control and Data Acquisition Drill (SCADAdrill) System. Developed using existing automation and drilling tools, SCADAdrill is a control system that interfaces with existing rig controls to provide autonomous drilling, survey, directional drilling and hole-condition monitoring. It continuously monitors all of the parameters of the drilling process, evaluates them and makes operational decisions in much the same way as the driller does. This control system can be retrofitted to existing rigs fairly easily and can also be linked to a real time operations centre where drilling progress can be monitored.

SCADAdrill operations are monitored to make sure nothing goes wrong, but the person monitoring will not tell the system what to do. After each task, the work is analysed to see if the algorithms need improving, and then the updated software is sent to the other rigs in the field.

This control system has been tested successfully in two horizontal wells in a heavy oil asset in Canada and was deployed commercially in gas wells in The Netherlands and Pennsylvania, USA earlier this year. However, it is still in development.

The system will serve as the ‘brain’ of the well manufacturing system, controlling the specialised rigs. The design of these rigs would vary from project to project, starting from scratch with the perfect equipment to develop a field and then build it through the partnership with CNPC at the lowest cost with the optimum technology. The result would be a series of low-cost, repeatable wells across the entire field.

In addition to the rigs, Shell and CNPC are looking at automating other functions. For example, a system to monitor drilling fluids real time and decide when to treat them. This would ensure a more tailored way to treat these fluids while

drilling, securing more uniform properties but also minimising the use of chemicals.

Smarter, safer, smaller footprintWhat are the advantages of this system?

The automated control system will replace the directional driller, the measurement-while-drilling operator and the mud engineer. With human requirements reduced, the operations would be significantly safer with fewer errors, and the cost of recruiting, training and retaining rig personnel would be driven down dramatically. It also would address the severe shortage of trained rig crews, which has presented a significant obstacle to the development of unconventional reserves.

With this kind of supply-demand imbalance, service companies and drilling contractors charge a higher margin. The well manufacturing system will also have less impact on the environment than its conventional counterparts. Its footprint will be smaller, because the rigs will be smaller and fewer fixed installations would be needed. It will also operate out of a central processing facility, which will allow for more use of recycled water and will minimise emissions.

OverviewThe well manufacturing system is not the solution for every field. The ideal field would be one that requires a large number of wells to be drilled over a short period of time and is uniform enough for the standardisation concept to work. Coalbed methane and some heavy oil and shale plays fit that description.

However, it would not make sense to invest in a system such as this one to drill a field with, say, 20 wells. Those cases would continue to require the traditional model with service providers and drilling contractors doing the heavy lifting.

The equipment for the well manufacturing system is in the design stage now, and the majority of its rigs, services and drilling equipment will be manufactured or sourced by low-cost suppliers in China that are subsidiaries of CNPC. Manufacturing is scheduled to start in late 2011 or early 2012, with system deployment planned for 2013 in Shell and CNPC fields through an entity owned jointly by the two companies. O T

Figure 1. The Synergy rig in Schoonebeek is equipped with Shell’s autonomous drilling technology, SCADAdrill.

Cost-effective connectionsBruno Lefevre and Mazhar Mahmood, VAM Drilling, USA, explain the benefits of selecting appropriate drill strings

to help drilling contractors achieve target objectives with maximum safety margins in a cost-effective manner.

A s oil and gas exploration continues to expand into new and unexplored frontiers, complex horizontal and extended-reach wells are becoming a daily challenge for

drilling contractors today. When associated with high pressure/high temperature (HP/HT) downhole conditions, wells need high performing tools to ensure safety, productivity and superior performance. The nature of complex well profiles in combination with HP/HT conditions can result in very high stresses on the drill string, which requires greater safety margins in the drill string design. To ensure successful operation, drill strings with a higher tensile and torsional yield strength drill pipe body and superior torque capacity tool joints must be used.

The high financial risks linked to drilling operations and the high cost of rig use means that oil and gas companies need to mitigate risks and reduce total costs by optimising drilling programmes and drilling efficiency. One can improve drilling efficiency by increasing rates of penetration (ROP) and by lowering nonproductive time (NPT). Selecting the appropriate tools for your drilling programme prior to start-up can help guarantee the achievement of your targets within maximum safety margins and at reduced costs.

In order to optimise drilling performance, a number of factors regarding the drill string assembly must be taken into consideration:

Pipe and tool joint dimensions for hydraulic efficiency.

Pipe yield strength for torque and drag optimisation.

Pipe body, weld zone and connection mechanical properties for maximum tension and torsion capacity.

Other design related drill pipe features for improved fatigue resistance, serviceability and operating cost optimisation.

Design The VAM Express™ high torque connection brings together a reliable double-shoulder design and a high performance proprietary thread profile. The primary torque shoulder provides initial seal and pre-load during make-up to full recommended torque while the secondary torque shoulder provides high torque capacity. The connection allows for easy stabbing thanks to a laid-down stab flank. A back bevelled crest increases freedom of movement and allows easy connection make-up, while reducing the chance of wedging. Resistance to rotational-induced bending is increased by the connection’s elliptical root.

Qualification In order to guarantee superior performance, this design has been subjected to demanding engineering analysis, including the full

47


FEA model for pure torque loads and combined torque and tension loads. The connection was also subjected to live field tests in the Heather 1 – 5 wells during final stages of product development. The test conditions are outlined in Table 1.

Performance Higher Torque. Torque capacity that averages 150 to 200%

more than that of API connections.

Quick rig make-up. There are 6 – 7 turns from stab-in to full make-up; a performance similar to API connections but with 16% better trip-time as compared to other high performance double-shoulder connections.

Ease of use. Reduced stabbing damage due to enhanced clearance between box counterbore and pin nose with no need for stabbing or de-stabbing guides. Reduced wedging risk on threads.

Strength. Slim OD/ID to improve hydraulic performance.

Durability. Minimised damage risk on rig and reduced tong loss when a connection recut is required. Improved pin nose durability due to patented design including elliptical thread root that increases the connection’s resistance to rotational bending fatigue.

Complex environments

ShalesWells are drilled horizontally through the shale formation with high build rates, which puts further wear on the pipe. VAM Express allows users to optimise their drill string by providing high torque and the slim profile needed to successfully drill shale plays. The elliptical thread root is significantly better in dealing with fatigue, especially in the build section. The rugged thread, the fast make-up time and the fact that no stabbing guide is needed in make-up eases handling on rig and saves valuable time.

Extended reach drilling and horizontal drilling The primary need in extended reach and horizontal wells is torque. Because of the friction that a drill string encounters as it drills, more torque is needed as the well increases in length and in inclination. The drillable length of a horizontal, ERD, or uERD well is limited by the make-up torque of the drill pipe connection used. VAM Express provides the additional torque required to drill challenging well designs. In addition, VX’s enlarged

Table 1. Test conditions of the VAM Express™

Depth 18 150 ft

Hole size 6.5 in.

Section profile Vertical

Rig equipment Varco top drive and Iron Roughneck

Top drive torque Average 3300 ft/lbs

Top drive RPM 40

Drill pipe4 in., 14.00 lbs/ft S135 pipe, 4 in. OD x 2-13/16 in. ID tool joints, with VAM Express VX 39

Typical bottomhole assemblyDrill bit, turbine, stabiliser, 14 drill collars, jar, 3 drill collars, 6 HWDP

Thread compoundBestolife copper supreme special blend

Typical average rate of penetration 3 – 4 ft/hr

Results: Consistent running, no connection reject related to stabbing, make-up or

drilling operations, trip time in line with expectations.

ID provides hydraulic improvements because it reduces the pump pressure needed from the rig floor. Finally, VAM Express’ elliptical thread root, with fatigue performance equivalent to a circular root of approximately 0.065 in., reduces connection fatigue risk.

Field proven Ease of running and a net improvement in service life were immediately experienced from the very first drilling operation runs in Indonesia in 2006, with a VX 39 drill pipe rented by Weatherford International on behalf of Chevron. The drill string was composed of 500 joints of drill pipe and 30 joints of heavy-weight drill pipe. It was used by Chevron between May and October 2006, providing a six month period of analysis with excellent results.

More recently, VAM Express was used by Devon to develop the Polvo Project offshore Brazil. The Polvo project is a platform drilling rig located in an offshore block of the Campos Basin approximately 95 km off the Brazilian coast. The field has two distinct reservoirs and a sandstone reservoir to the east, as well as a carbonate reservoir to the southwest. It was discovered in 2004 and drilling began in March 2007 with a total of 32 wellbores, including ‘short reach’ and ‘ultra extended reach’ wells. The deviation spans from 3 – 7˚/100 ft DLS at inclinations of 30 – 92˚. Wellbores have been designed in 3D, in order to improve total reservoir exposure.

After the installation of the platform and the start of the drilling operations, the productivity of the sandstone reservoirs in the eastern part turned out to be higher than expected. Subsequent to the drilling of 12 wells and various lessons learned, the furthest extended reach well in the history of Brazil was attempted and successfully completed. The Pol-O wellbore was drilled to a total measured depth of 6489 m (2429 m TVD) and a vertical section step out of 5615 m. This wellbore still holds the record for the furthest reach wellbore in the history of Brazil.

Besides this, the Polvo project also attained the record for the fastest drilling in an 8.5 in. hole with 1610 m drilled within 24 hrs. This record was not only obtained through high on bottom ROP, but also through significantly improved make-up time (e.g, make-up time is halved as compared to similar connections) linked to the use of the VAM Express connection. VAM Express prevented drill string failure even after having drilled over 100 000 m of total well depth using the same drill string in highly deviated wellbores. Throughout the entire project, no twist-offs or back-offs have been observed.

The successful and efficient drilling of those extended reach wellbores has proven further reserves that can be produced by the Polvo platform with no need of another platform or subsea tiebacks. Current plans are to improve the top-drive to achieve higher torque, while staying with the same VAM Express connection size.

ConclusionThe VAM Express connection design has shown substantial improvements in mechanical performance and significant savings in operating costs thanks to its superior torque capability. This is up to two times that of API connections, resulting in optimum performance in the most demanding drilling environments. As a consequence of fewer recuts and refacing operations, its extended durability and reduced operating cost results in a valuable connection design for any drill operator. O T

No more cracking

Finite Element Analysis helps the industry develop and

qualify equipment for extreme environments, in this case

heat. Haining Pan, formerly of Schlumberger, Jose Caridad,

Schlumberger, Singapore; and Shauna Noonan, ConocoPhillips,

USA, explain.

Steam-assisted gravity drainage (SAGD) is a proven technique for producing heavy oil. Originating in Canada, the technique involves precisely drilling twin lateral

wells, one above the other. The laterals extend for great distances and must be kept precisely the same distance apart. Superheated steam is pumped into the upper lateral, heating the heavy crude and reducing its viscosity, so that it can drain naturally through the formation and down to the lower lateral where it is produced.

High temperature pumping is challengingSchlumberger Artificial Lift has been working to extend the temperature range of its REDA* Hotline* electrical submersible pumps (ESP). Previously, the maximum temperature rating for the equipment was 425 ˚F (218 ˚C). More than 700 pumps have been installed that meet that specification. However, the industry has demanded more.

In 2009, a new extended temperature range Hotline ESP system was developed and tested for operation at 482 ˚F (250 ˚C). The REDA HotlineSA3* system has since passed extensive testing while running at maximum rated temperatures, including strict third-party qualification requirements at C-FER Technology Laboratories in Canada, with collaboration and sponsorship by major heavy oil operator ConocoPhillips.

However, following the initial testing, the pump was disassembled and carefully inspected. The inspection revealed axial cracks in the ceramic keyless sleeves that are used to support the central shaft at intervals along its length. The sleeves help keep the shaft centred with a minimum amount

of friction. Due to the construction of ESPs, the sleeves are under compression. In fact, the entire drive shaft, together with its impeller stack, is designed so the thrust developed during pumping is transferred from each impeller to the shaft and then to a heavy-duty thrust bearing. The sleeves are constructed for keyless operation; nevertheless, they are not supposed to turn relative to the shaft when the pump is in operation. Accordingly, the sleeves are driven by a U-shaped notch that mates with a corresponding lug on the spacer (Figure 1).

A detailed look insideTo understand the issue, it is necessary to understand the basic ESP construction. The pump tested was a compression-built pump with 27 stages. Each stage contains a matched set consisting of an impeller and a diffuser. The impeller rotates with the shaft, driven by the motor. The diffuser is fixed to the pump housing and does not move or rotate. When the pump is constructed, all 27 impellers are spaced along the central shaft, with nine sleeves and spacers between them, at intervals to support the shaft radially, keep it centred, and provide bearing surfaces. Each sleeve on the shaft has a corresponding ceramic bushing on the diffuser. A compression mechanism keeps the impeller’s sleeves and spacers in place axially.

During the post-test inspection it was discovered that all nine ceramic sleeves had cracked axially right at the deepest point of the U-shaped notch. The cracks did not precipitate a pump failure. Nevertheless, it was decided to perform Finite Element Analyses (FEA) to see if a root cause could be identified so the sleeve-cracking could be suppressed.

49


One of the fundamental steps of failure analysis is replication. Engineers attempt to replicate the failure under tightly controlled conditions so they can measure and observe the failure mechanism. In some cases, engineers build a mathematical model on a computer and try to replicate the failure that way. To build a mathematical model, preliminary testing of components is required for validation purposes. For the Hotline investigation, both the FEA and testing were conducted.

The team first performed a static high temperature test on the same type of pump used in the field trials. A compression-built pump, without housing and diffusers was built and placed

in a precision-controlled oven. After initially heating the inner workings of the pump to 392 ˚F (200 ˚C), with no damage to the sleeves or spacers, the temperature was boosted in precise 18 ˚F (10 ˚C) steps, and held for 10 min. at each level. At the end of each step, the spacer and sleeve condition was carefully inspected. At 428 ˚F (220 ˚C), cracks were observed propagating from the notch area of the sleeves between the impellers, but not at those sleeves at either the head or the base. In fact, the head and base sleeves withstood 644 ˚F (340 ˚C) without failure. Friction marks were observed on the ends of the ceramic sleeves, indicating that the sleeves had been subjected to axial compression and radial friction at peak temperature. The engineers deduced that the axial compression was caused by the difference in the coefficients of thermal expansion (CTE) between the impeller stack and the shaft (Figure 2).

The impeller stack is made of alloys with higher CTE than the shaft; hence, it expands more than the shaft per unit length as the temperature rises. However, the stack was constrained to the shaft because of the pump construction, causing axial compression on the sleeve, which led to cracks. Moreover, the impellers/spacers had a higher CTE and a higher Poisson’s ratio than the sleeves, causing radial displacement of the impellers/spacers relative to the sleeves as temperature rose. The head and base sleeves had not been subjected to axial compression, therefore they were unaffected.

A simple compression test performed on a sample sleeve resulted in an axial crack propagating from the base of the notch. However, the axial stress level measured when the sleeve cracked was much lower than its Ultimate Compressive Strength (UCS). In contrast, the sleeve is relatively fragile in tension, which revealed that the failure mode was not simply axial compression, but rather hoop tension resulting from the axial load on the sleeve due to the U-notch geometry, thermal expansion.

Time to model and analyseIt was now time to model the sleeve mathematically and observe the effect of hoop tensile stress as a measure of sleeve cracking. The first FEA simulation modelled hoop stress on the sleeve under axial compression with radial friction between the impellers/spacers and the sleeve (Figure 3). The hoop tensile stress concentration at the base of the notch reached the sleeve’s Ultimate Tensile Strength and thus initiated cracking.

The FEA simulation was repeated without radial friction and showed a lower level of hoop stress. This result proved that interface friction plays an important role in determining the crack criteria.

Lastly, an impeller, a sleeve and a spacer were modelled and subjected to compression to simulate thermal axial stress as temperature rises. As it was expected, this FEA simulation showed that the axial mechanical response of an impeller mainly depends on that of the hub. This is an important assumption to simplify the impeller stack as merely three tubes. As a result, a simple thermo-elastic model was developed and experimentally verified to be able to predict the temperature at which the crack initiates in the sleeve.

The key point of the study was the revelation that sleeve cracking was caused by hoop tensile stress concentration. The interface friction also proved to be an important factor in the failure mechanism. Now that the root cause of the failure was identified, the next step was to address it by closely matching the CTE of the shaft with that of the impeller stack.

Figure 2. Axial crack propagating from the base of the notch following the static high temperature test.2 (Photo courtesy of Schlumberger.)

Figure 1. Keyless sleeve on the pump shaft has a U-shaped notch that engages a matching lug on the spacer.1 (Photo courtesy of Schlumberger.)

SummaryRoot cause analysis allows creating a design based on accurate predictions of failure mode and conditions. Thus the FEA and derived mathematical model can be used to select suitable pump components that reduce the axial thermal stress. After some experimentation, a sleeve-shaft-impeller combination was developed that survived temperature tests up to 536 ˚F (280 ˚C). The new alloy is currently being field tested and is expected to provide a commercially viable ESP for sustained high temperature operations encountered in SAGD production. O T

NoteThe Schlumberger and ConocoPhillips authors would like to acknowledge management for permission to publish this work and all the support received.

References1. Pan, H. et al, ‘Use of Failure Analysis Techniques to Improve Reliability

of Material Selection in SAGD Applications,’ Gulf Coast SPE Paper, [Figure 1].

2. Ibid., [Figure 4].3. Ibid., [Figures 7, 9, and 12].

Figure 3. (A) Contour of hoop stress in the sleeve mesh under axial compression. (B) Contour of hoop stress in the sleeve mesh under axial compression without friction. (C) Contour of axial stress in the stack mesh under axial compression. With these models any combination of critical stress can be modelled.3 (Graphics courtesy of Schlumberger.)

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TOTAL MOORING SOLUTIONSTOTAL INNOVATION

Phil Head, Artificial Lift Company Ltd, UK, reveals how rigless ESPs are the way forward for artificial lift technology.

52

Lightening

Electrical submersible pumps (ESPs) are the most efficient form of artificially boosting the production of fluid from the reservoir. Positioning the pump at depth in a well ensures the pump only has to remove the fluid in a liquid

state, be it single (oil) or two phase (oil and water). This is particularly advantageous in subsea applications, as it eliminates the need for complex seabed multiphase boosting systems.

Traditionally, ESPs have been deployed on the end of production tubing. This requires a rig for installation and removal. New rigless systems, including one developed by UK-based Artificial Lift Company (ALC), require a rig initially to deploy the production tubing and outer completion, to which is attached one half of a three phase electrical wet connector. All the other ESP hardware is deployed and recovered on slickline, internal to the production tubing. This means that once a well has been made ‘future proof’ for the technology, the rig is no longer required to disturb the tubing and completion equipment.

Rigless ESP benefitsThe most important benefits are financial and production related. The rigless ESP eliminates the need to schedule highly sought after rigs and their escalating rental rates. This can literally save hundreds of thousands of dollars, as well as shorten the project’s completion timeline. What’s more, production from the well is maintained with minimum downtime, maximising cashflow and revenue for the operator.

Another benefit is the fact that the well does not have to be killed during installation, as all the internal tubing components can be worked over on slickline using conventional live well intervention techniques. This is particularly well suited for the recently developed subsea workover systems operated from light well intervention vessels.

A further advantage of the ALC wet connector is that it is located in a side pocket window (similar to a gas lift valve). When the ESP hardware is removed from the well, full wellbore access is possible. This enables any remedial work to be performed on the reservoir, including wellbore cleanouts, coiled tubing drilling for well deepening or new lateral drilling, perforating, zonal isolation or stimulation.

Plus, because the side pocket wet connector is out of the main bore, it cannot be covered in debris or wellbore particulates, or damaged by tools intervening the well.

THE LOAD

53


Ideal circumstances for a rigless ESPThe rigless ESP is not for every ESP well. For example, if rig rates are extremely discounted or rig availability is not an issue, the costs might be prohibitive. From a well standpoint, if the well is benign (meaning there is a good local track record of ESP life), it would be very hard to justify the additional hardware and cost of a rigless ESP. However, many situations merit evaluating the use of a rigless ESP system:

Offshore Subsea: if a rigless ESP is combined with new subsea light well

intervention vessels, cost-effective access to a subsea ESP is now viable. This will extend the effective productive life of a subsea well and maximise the hydrocarbons produced from it. The subsea well has to be designed at the initial stage to have the necessary power line and completion hardware installed to accept a rigless ESP system. This way, as the reservoir pressure declines, the well is ready to accept the rigless ESP.

Satellite platform: these minimum facility platforms generally require a jackup to access the well. The rigless ESP slickline and pressure control equipment could be helilifted to the platform, enabling low cost change out.

Full facility platform: in the North Sea, for example, if the operator installs a rigless ESP, it could keep the rig clear for more heavy duty well work such as re-entry drilling, well deepening and milling.

Onshore Tough environmental regions: areas such as the Arctic, desert,

jungle or mountains make it extremely difficult to move a rig or heavy equipment. Additionally, significant cost can be saved by not having to maintain access roads suitable for heavy equipment.

Urban areas: wells located in sensitive urban areas are excellent candidates for a rigless ESP system. These locations create awkward, even hostile community relations issues if a rig is required.

Enabling technologyThe critical components of an ALC rigless ESP system include the following:

Compact side pocket three phase electrical wet connectorThe well is a hot and high pressure environment, with a sometimes aggressive combination of chemical compositions, either originating from the reservoir or introduced by the operator as part of the well maintenance programme. The permanent half of a wet connector has to be extremely simple to ensure it has a long life. The rigless ESP system has the advantage of always recovering the deployed half of the electrical wet connector, therefore, all the ‘clever’ technology to provide a rugged and reliable electrical wet connector system are incorporated in the retrieved slickline equipment.

It is important for the wet connector to enable full wellbore access and work with standard wellbore sizes. For the sake of completeness, the connector has the same electrical rating as a packer or wellhead feedthroughs.

Permanent magnet motor (PMM)To ensure practical deployment of a rigless ESP system, a compact permanent magnet motor was developed. The rigless ESP motor technology has been around for years in such premium applications as in aerospace, where size, weight and reliability are essential, as

Figure 3. Motor, seal and wet connector assembly prior to being installed into lubricator.

Figure 2. Illustration of well completion on left and internal rigless ESP components installed on right.

Figure 1. Live well installation of rigless ESP using slickline unit, lubricator and crane (rigless ESP inside lubricator).

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well as mass produced applications such as the cooling fan motor in laptop PCs.

ESPs traditionally have used induction motor technology. For a performance comparison, a 3.75 in. standard oilfield induction motor develops 50 kW (67 hp.) from a length of 14.45 m (47.4 ft) and weighs 600 kg (1542 lbs). The ALC 3.8 in. PPM produces 50 kW (67 hp.) from a length of 1.4 m (4.6 ft) and weighs 52 kg (112 lbs).

This difference in performance can be explained very simply: a permanent magnet motor has its excitation provided by a permanent magnet rotor and all the current in its armature is torque producing. Induction machines get their excitation from the armature current directly. For an induction motor, part of the current fed to the motor magnetises the circuit and is not torque producing.

Furthermore, induction machines require more cooling because of the significant electrical losses in the rotor due to current circulating in the squirrel cage in the AC nature of the field in the rotor laminations. Permanent magnet motors have very small electrical losses in the rotor due to the broadly DC nature of the field in the rotor structure.

Because of their efficiency, permanent magnet motors achieve much higher performance than induction motors and can have up to eight times the power output to a similar sized induction motor.

The ALC PPM is fully compatible with industry standard drives, requires no special position feedback such as an encoder or resolver, and does not require any special sensorless algorithms. This is an important characteristic, as other PPM motors require either a special drive or feedback sensors adding to the installation cost.

Typical installationTwo types of installation that are common for a rigless ESP include a rig installation and a live well installation.

Rig installation of completionThe first installation of the rigless ESP system requires a rig to install the production tubing and bottomhole outer completion.

The outer completion generally consists of a re-entry guide, an orientation and side pocket electrical wet connector, motor shrouds and a power cable that is clamped to the outside of the production

Figure 4. Rigless ESP synergy with light well intervention technology enables ESPs to be cost-effectively exploited in the subsea arena.

tubing all the way back to surface. The slickline deployed rigless ESP equipment is then installed through the tubing.

Live well installation of ESP equipmentDuring subsequent workovers, the well can be accessed using proven and practiced live well intervention techniques. This requires a lubricator (extends the well pressure vessel to above the Christmas tree) that is connected to a BOP, which in turn is connected to the crown flange of the Christmas tree. The rigless ESP system can be deployed in sections if there are length or weight issues. Slickline is then used to lower or retrieve the rigless ESP assembly into the well.

If the well is extended or deviated, coiled tubing or a wireline tractor can be used to walk the assemblies into the well and position at the required setting point. The rigless ESP system is fully compatible with the operation of either coiled tubing or a wireline tractor, and the lightweight motors assist with these deployment processes.

Similarly, the system is fully compatible with the various subsea well intervention systems currently in final development or in commercial use. This is a very exciting combination of technologies enabling cost-effective ESP systems to be exploited in subsea wells.

ESPs todayEfficient pump retrieval for reconfiguration, maintenance or replacement will be essential to the progress of ESP technology in deepwater projects. ESPs to be installed by Petrobras, with FMC, at the Gulf of Mexico Cascade and Chinook fields in 8800 ft of water will have horizontal caisson configurations and will be placed on the seafloor inside of cages. Retrieval and reinstallation will take place by means of a service boat deploying an ROV, with the cage and pump handled as a unit. Seabed pumping units that serve multiple wells are an effective deepwater boosting solution.

With the arrival of rigless ESP technology each individual well can have an ESP installed and placed at its optimum setting depth. For example, if a rigless ESP is placed in the well, providing a drawdown of 4000 psi, this additional lift might enable an extra 10 – 20% recovery of total oil in place. This is a significant benefit to the operator.

The futureThe challenge the industry faces is to maximise the cost-effective recovery of oil in place. Rigless ESP technology will enable an economic means of installing and retrieving in-well pumps.

Wells will be prepared for rigless ESPs, and will involve a two-stage well production solution. In the first stage, high reservoir pressure will provide the natural drive for production from the well. In the second stage, as reservoir pressure declines and natural well flow diminishes, production will then be augmented by means of the rigless ESP system.

This technology is currently being installed and evaluated by both national oil companies and international operators globally. In addition, engineering for several large subsea projects is currently in progress. Given its practical and financial benefits, rigless ESP technology should become a standard requirement for certain large niche applications; one that can provide significant benefits for the operator in terms of reducing the overall project costs whilst assisting in achieving the maximum recovery of hydrocarbons from the well. O T

Nuclear solutionsTerry Graham, Zircotec, UK, demonstrates how a

growing range of coating technologies, developed

by the UK’s nuclear industry, are now providing

solutions including resistance to heat, wear and

even electrical insulation in oilfield applications.

Figure 1. A growing range of coating technologies, developed by the UK’s nuclear industry, are now providing solutions including resistance to heat.

Novel surface coatings were one of many technologies developed by the UK’s Atomic Energy Authority (UK AEA) to solve performance and

reliability issues in the nuclear reactor and associated plant. Tough, easy to package and long lasting, they were ideally suited to challenging high temperature environments. With a thermal efficiency of less than 1.5 W/m K (compared with 4 W/m K for alumina), zirconia-based ceramic coatings are also very effective at inhibiting heat radiation from a

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metal surface. Zircotec, formally part of the government-owned UK AEA, grasped the opportunity to commercialise the technology beyond the power generation industry, leading to a number of other applications in motorsport, automotive and niche industries, such as aiding the drawing of fibre optic tubes within the furnace.

Now, the Abingdon-based company is also expanding its range of durable yet thin coatings to solve both new and existing challenges found in the oil extraction and refining industries. As this industry identifies more challenging fields to exploit, coatings including anti abrasive, electrical insulation as well as the option to replace more harmful coatings such as cadmium, could provide answers to the growing number of reliability questions posed.

The application processRefined and optimised over 30 years, Zircotec has used plasma spraying to apply its coatings and heat shield products. During plasma spraying, powder particles are injected into nitrogen or argon plasma with a flame temperature of circa 20 000 ˚K and a gas velocity of Mach 2 – 3. The company’s process provides a very short residence time for the particle in the flame and it is possible to adjust the parameters to ensure that the range of substrate materials that can be coated is nonetheless extensive. These can stretch from nylon at the lower end of the temperature

spectrum to beryllia at the top, though toxicity means the latter is not currently undertaken by Zircotec. Provided the material does not sublime nor is it transparent to UV, the particles will melt and quench as ‘splats’ on to the substrate. The experience derived from coating often intricate components for nuclear installations, means the company can ensure an even coating is built up in thin layers helping to reduce stress in the final coating, minimising failure in the field that inevitably leads to the unwanted downtime and disruption that can cripple oil extraction.

The coating is designed to be robust and is highly resistant to vibration and mechanical damage during its operational life. To survive the conditions experienced in oil extraction environments, careful control of process parameters and a proprietary bond coat is used to make sure the coating is extremely well adhered to the underlying substrate. Any attempt to coat directly onto a part without such pre-treating would result in very low bond strength. Further proprietary physical and chemical methods are used to prevent damage to the substrate during the application process.

A lighter future With the oil industry venturing into more hostile environments and deeper locations to recover oil, the ability to improve performance and reliability through the use of ‘fit and forget’

Figure 2. High temperature plasma-sprayed ceramic coatings can provide lightweight, easily packaged and highly durable thermal barriers suitable for a wide range of highly aggressive environments.

of 600 ˚C). For composite applications such as on structures, pipes or venting systems, the reductions are equally impressive; testing has shown carbon fibre surface temperature lowered by over 125 ˚C, crucially providing the ability for these light materials to be used in temperatures above their delamination point.

The highly corrosive environment of oil extraction means that composites are an attractive solution for offshore users. Composites are known to be stronger, and around six times lighter than copper nickel equivalents, if they are subjected to high temperature environments, they were often ignored for fear of damage. Zircotec believes that there is future potential for more use of carbon composites offshore in salt laden environments. Research suggests reducing pipe weight on the decks of a tension leg platform would improve buoyancy, leading to reduction in the amount of steel required and therefore cost. Like for like composites are known to be stronger, and approximately six times lighter than copper nickel equivalents. Other potential examples include the growing use of composite shovels, a switch made to save weight and avoid corrosion issues. An anti wear coating, such as molybdenum, could be applied to extend their life.

To achieve the latter, a metal coating to a composite offering a lightweight structural component that has excellent wear characteristics can be applied. Similar to the ceramic coating, a proprietary bond coat is applied to the composite before applying a top layer of molybdenum, aluminium, stainless steel or tungsten. These coatings are also being used on composite substrates to enable their use in environments where previously they would have failed or required higher levels of maintenance.

In line with the unique capabilities of the technology, the company offers oilfield engineers the opportunity to ‘engineer’ the coating. To suit specific customer requirements, engineers can adjust the coating properties both through thickness and across the surface of a component to cope with ‘hot spots’ and differing forms of heat transfer such as radiant, conductive or convective heating.

Unlike some processes or coating, only areas that need treatment are coated. This is more cost-effective and further minimises weight. It is also possible to build in a conductive sub-layer that will help to dissipate heat away from any concentrated high temperature areas, and can also help deal with transient heating situations. This means the company applies just the right amount of coating to deliver the necessary protection whilst minimising the weight impact of the coating. (As low as 0.03g/cm² according to Zircotec.)

Flexibility The growing work the company has carried out in the automotive sector has led to the development of a flexible ceramic supplied on an aluminium foil. Believed to be the first of its kind, ZircoFlex enables users to solve heat issues without having to send components for spraying. It can be cut, folded and bent to fit any shape and offers surface temperature reductions of 64% in single layer form and, up to 85% when used in its three layer variant. Very lightweight and flexible, it is an easy solution than can be applied in the field. The company has made installation easier in difficult to access plant equipment locations by also introducing a self-adhesive option and pre-prepared two and three layer derivatives. Good for applications in environments subjected to temperatures up to 500 ˚C, its usage in oilfield applications is likely to be extensive. O T

Figure 3. Zirconia-based ceramic coatings have their heritage in the UK’s nuclear industry.

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MOORING SOLUTIONS THAT GIVE

Wolfgang Wandl,

Viking Moorings, Norway,

shows the importance

of mooring solutions in

exploration drilling.

Drilling operators today are facing a myriad of challenges in their exploration operations. Such challenges include the greater need for accurate downhole measurements

in remote and geologically complex exploration areas, decisions as to what depths to install the well casing and the importance of accurate bit selection, and the need to drill exploratory wells as quickly and effi ciently as possible.

Go offshore into deep waters and such challenges can potentially multiply to include issues such as increased water depths, riser manipulation and extreme bottomhole pressures that, in some cases, can exceed 22 000 psi.

One of the biggest challenges in the management and control of exploration drilling today, however (and one that is

often overlooked), is the vital role today’s mooring solutions play. These are in two main areas: in mobilising and moving exploratory drilling rigs – normally semi-submersible drilling rigs – as quickly as possible from location to location and in developing innovative solutions for actual drilling operations.

According to ODS Petrodata and its weekly rig count, there are currently 625 mobile offshore drilling units under contract around the world (as of 24 June 2011). It is the exploration drilling rig counterparts, however, who perhaps provide the most signifi cant mooring challenges. There are a number of reasons for this.

Firstly, such rigs tend to move around with increasing regularity – often spending less than 30 days at a given location

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and moving as many as 10 times a year, as operators look to assess as many different prospects as quickly as possible. This is particularly applicable in regions, such as offshore Africa, Brazil and in Asia, as well as even the North Sea, which is currently seeing a resurgence in activity.

Moving with such regularity, however (especially taking into consideration other unknown variables such as the weather), increases the potential for delays and rising costs. This is particularly the case with the huge infrastructure and resources required in moving modern rigs, including everything from Anchor Handling Vessels (AHV) and Anchor Handling Tugs (AHT) through to the supply of chain, anchors, fi bre and other ancillary equipment for mooring systems.

For the operator, every day a rig is not connected to its mooring lines means not only a day lost in drilling but also a day of expending considerable resources without benefi t. The costs of Anchor Handling Vessels (AHV) can also be substantial.

A second challenge is that many offshore exploration drilling rigs also have to navigate around existing subsea structures – often due to the amount of exploration activity taking place around fi elds that are currently in production.

With the typical mooring spread for a semi-submersible rig being between eight and 12 anchor lines with a horizontal reach of up to 3000 m, mooring solutions providers need to be highly adept at navigating existing installations, such

Figure 1. The Spin Buoy ready for deployment.

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as pipeline networks, subsea tie-backs, water injection or gas injection wells, or multiphase pumping and subsea separation systems.

The North Sea is one such example of a region where a fl urry of new exploration activity (the recent licensing round for the UK Continental Shelf resulted in the largest number of bids since the fi rst licensing round in 1964) is taking place alongside older fi elds and infrastructure.

Recent exploration drilling rigs in the North Sea that Viking has supported include the West Alpha and West Epsilon rigs for Statoil in the Alve and Sleipner fi elds in the Norwegian North Sea and the West Phoenix rig, currently under contract to Total for exploration on the UK Continental Shelf.

Thirdly, there is the challenge of how mooring solutions can optimise drilling production. For example, when target areas are very concentrated and where already drilled wells need to be repaired, it is often the case that drilling locations are just a few thousand metres apart. It is in instances such as these that mooring providers need to provide innovative and cost-effective solutions.

And the fi nal challenge, as mentioned briefl y at the outset of this article, is that of securing exploratory drilling rigs and deploying mooring solutions in some of the world’s most remote areas, with high depths and unpredictable weather conditions.

So how are mooring solutions providers meeting these challenges and improving drilling management and control? There are number of developments, spurred on by mooring providers, such as Viking, which are improving the effectiveness of offshore drilling exploration.

Mobilising and demobilising exploration rigsWith assets at their most vulnerable during rig mobilisation and demobilisation as well as any problems leading to signifi cant cost increases, it is vital that mooring providers today apply innovative solutions to mobilisation and demobilisation.

Furthermore, there is also the issue of safety – so tragically highlighted by the Bourbon Dolphin tragedy in 2007 where an Anchor Handling Tug Supply Vessel (AHTS) capsized off of the coast of Scotland with considerable loss of life.

The growth of pre-set moorings, where the mooring infrastructure is established in advance of the rig’s arrival, has gone a long way to both speeding up and simplifying the mobilisation and demobilisation processes.

Pre-set mooring ensures greater precision and control over the positioning of the mooring solutions around existing infrastructure and also enables a more strategic approach to supporting offshore drilling rigs. For example, targets areas can be mapped out and mooring solutions put in place months in

Figure 2. The preinstallation of mooring lines for an Australian Operator – 23.6.

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advance, with unknown variables, such as the weather, tackled more directly by installing such solutions in the summer months, for example.

Recent examples of pre-set mooring applications that Viking has been involved in include Transocean’s Jack Bates rig, offshore Western Australia and a pre-laid mooring system on behalf of Kosmos Energy for the drilling unit Atwood Hunter in the Teak prospect, offshore Ghana. With this growth in pre-set moorings, Viking has also developed a number of new solutions to support them.

For example, the company is set to launch a complete fibre rope storage system, which will enable the fibre rope and the buoy in a pre-set mooring application to be stored safely on the seabed until mobilisation (the fibre rope will be stored in a bag).

This will lead to a simplification of pre-laid mooring operations, efficient and flexible handling and storage, and no requirements for specialised tooling and external cranes. And when the rope is ready to be retrieved and the AHV is ready for connecting the ground chain to the fibre rope or the rig chain, the new anchor retrieval buoy (known as the SPIN buoy) will be utilised. The SPIN buoy is brought to the surface through a coded acoustic signal, spooling off rope in a controlled manner.

Other solutions to improve mobilisation and demobilisation, whether on a pre-set or convention mooring application, are the Stevtrack Anchor Data Acquisition System and the QS connector (QSC).

The Stevtrack system provides a real time view of the anchor installation process underwater in order that the anchor can be correctly positioned on the seabed. Information displayed includes real time data on roll, pitch, water depth and pull-in force.

The QSC is a connection device based on automated wire line connections, replacing traditional shackles and links and promoting crew-free deck operations. Connection and disconnection is carried out in a deck cradle supported by a hydraulic-driven manipulator tool with all operations controlled from the vessel control room.

It is innovative mooring solutions, such as these, which are playing a key role in exploratory drilling management and control.

Supporting drilling operationsMooring solutions can also have a direct impact on the actual drilling programme itself, with significant cost savings. For example, Viking Moorings installed a pre-laid mooring solution for Noble Drilling’s Homer Ferrington semi-submersible drilling rig in the Baobab oil field, off the Ivory Coast. The Homer Ferrington rig had been asked by the operator, Canadian Natural Resources (CNR), to repair a number of wells affected by sand.

There were two separate drilling locations 1000 m apart. Rather than developing two completely separate conventional mooring systems, Viking developed a pre-set mooring solution where the rig could skid between the two drill centres.

The ability to access both drill centres from a single mooring pattern led to significantly improved mooring system performance with less riser downtime, less interruption to the drilling, and an optimisation of drilling services using batch drilling. The result was that the operator was able to deliver

four entirely new wells with cost savings estimated by CNR to be in the region of US$ 75 million.

Requiring access to solutions worldwideThe wide geographic scope of exploration drilling worldwide requires mooring providers with local bases and access to local personnel.

It is only then that challenges can be addressed as they occur and transportation costs and deployment time can be reduced by accessing equipment at local hubs rather than having it shipped across the world.

With this in mind, Viking today has a global footprint with an operational presence in Scotland; Norway; North, West and South Africa; Malta; Libya; Singapore, and Western Australia. Only last June, the company also signed an exclusive agency agreement with Canadian-based Newfoundland Offshore Services Limited (NOSO), to tap into the growing offshore Canadian market.

This global reach allows the company to support key target exploration areas. For example, a partnership in Egypt has ensured extensive storage space in Alexandria with the ability to ship equipment immediately to offshore exploration areas, such as the Gulf of Suez.

In Malta, the company has an extensive stock of mooring equipment, serving the central and western Mediterranean and the markets of Algeria and Tunisia – all drilling exploration targets. Finally, there is also a base in Ghana, the ideal stepping stone to large-scale deployments in Angola, Nigeria and Ghana itself.

By providing local equipment and local resources, mooring providers can continue to provide real added value to drilling contractors as they look to manage their exploration drilling operations.

ConclusionWhether it be moving rigs quickly and seamlessly or providing value to actual drilling operations, as in the case of the Ivory Coast, it is clear that mooring solutions have a vital role to play in successful offshore exploration and drilling. The next few years are likely to see even more developments in this area. O T

Figure 3. The Stevtrack Anchor Data Acquisition System displays real time data on variables, such as roll, pitch, drag length, penetration depth and pull-in force.

Doug Davidson, Mooring Systems Ltd, UK, explains how Tri-Catenary mooring systems are proving to be a flexible and effective station-keeping and production system.

FPSO MOORING IN MARGINAL FIELDS

T ri-Catenary mooring systems (TCMS) were first designed for extended well testing (EWT) in the North Sea in the mid-1990s. They provided a better and more cost-effective alternative to dynamic positioning tankers. After various EWT projects, the TCMS system was successfully

used to moor storage tankers and floating production, storage and offtake (FPSO) vessels. It provided an alternative to submerged turret production buoys, tower yoke mooring systems and conventional multi-line turrets for vessels up to 250 000 dwt, most notably for marginal fields where the field economics dictate a simpler, easy to deploy mooring system for fields with a limited production life.

The TCMS is based on three mooring legs radiating at more or less equal angles from a connecting node below the sea surface, with a single length of chafe chain rising from the node to a chain stopper positioned on the bow of the moored vessel. A key feature of many TCMS systems deployed to date is the existence of only one chain mooring line in any one direction, with the adjacent one being 120˚ away. The seabed end of each leg is typically held in place by a high holding power, drag anchor, firmly embedded by cross tensioning as an integral part of the standard

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deployment procedure. The mooring system allows the vessel to weathervane around the node in response to wave and wind movements.

Secure mooring systemParticularly when used with an FPSO, all mooring system design codes require there to be a means of safe positioning in the event of a single line failure. The TCMS offers a choice of options to ensure that there are no single point failure modes; this can either be with the use of additional mooring legs and a redundant chafe chain; or, as has been approved by a number of classification societies, a package of individual measures which together have been accepted as providing an adequate level of protection. One of these measures is an enhanced strength factor of safety for non-redundant systems, which is recognised in the latest version of the DNV Position Mooring Code OS-E-301. This measure takes advantage of the efficiency of this type of mooring system, where the peak mooring forces can be reduced

Figure 1. TCMS production tower on the Ikdam project offshore Tunisia, showing three risers and two umbilicals.

by ‘tuning’ the mooring system’s response to match the vessel’s response in severe weather. The TMCS can be tuned by the careful design of such factors as the length of the chafe chain and the mass of the node. Thus, use of larger components to increase the strength, and reduce the risk of equipment failure, is not financially burdensome.

By using three lines compared with other mooring systems including CALM buoys and turrets that have typically six, eight, or more legs, the TCMS is quicker to deploy and less ‘stiff’ than other tanker moorings. This ensures that the tanker’s natural fore and aft motions, with the right engineering, can be damped by the mooring catenaries and the pendulum effect of the chafe chain.

Flexible production systemWith the use of guide collars attached to the chafe chain, the moored tanker can act as an FPSO with multiple high pressure risers. The risers are unaffected by the degree of vessel offset experienced, as the riser catenary shape is affected by the movement only of the mooring node, which is considerably less than the vessel movement. The distance from the node to the tanker bow is a fixed

length (typically 40 – 50 m for a 90 000 dwt Aframax tanker). Horizontally, the node will move perhaps only 10 m, and vertically perhaps 25 m in extreme conditions. These sorts of motions are easily taken up with a lazy wave or steep wave design of riser shape. For some applications, it has been feasible to rely on the inherent stretch in bonded hoses to accept the node offsets – the right choice of bonded hose can have elastic stretch to as much as 40% of its original length – without structural damage or loss of integrity.

A single axial swivel on each riser is sometimes used depending on the amount of weathervaning anticipated; single axial swivels being much cheaper than multi-path toroidal swivels and with a much shorter delivery time.

So far, 11 TCMS systems have been deployed in applications ranging from extended well testing, oil recovery, and floating storage and FPSO production. One of the three FPSOs moored to a TCMS to date is the Lewek Arunothai FPSO Arthit Field in the Gulf of Thailand.


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Approximately 143 miles (230 km) offshore Songkhla in Malaysia, the Arthit gas and condensate field spans 1 million acres (4185 km2) across Blocks B14A, B15A and B16A. Moored at a water depth measuring 262 ft (80 m), the Lewek Arunothai FPSO field is operated by Thai oil and gas company PTT Exploration & Production (PTTEP). The Arthit FPSO TCMS also features four 8 in. Manuli bonded risers and one 8 in. DeepFlex bonded riser, plus a multi core hydraulic umbilical. The TCMS and riser system has successfully handled production levels of 370 million ft3/d of natural gas and 19 800 bpd of condensate.

As experience of the TCMS mooring system has increased, so the principle of providing a cost-effective mooring system for marginal fields has been developed for both deepwater and ultra-shallow water applications.

Getting into deep waterThe growing number of deepwater marginal fields in the Gulf of Mexico, offshore West Africa and Brazil, present both practical and economic challenges for independent operators. By their very nature, deepwater fields in water depths greater than 1000 m can be expensive to develop and so marginal fields lacking existing pipeline infrastructure are often neglected. Conventional deepwater mooring systems are complex and expensive to deploy at water depths greater than 1000 m. In addition, they often require substantial modifications to the FPSO, such as the addition of a mooring turret. In a marginal field, a turret capable of handling a small number of risers is inappropriate, whereas a deepwater TCMS, designed for four or five risers, is more practical. And with a lifetime of around seven years, compared with 25 – 30 years for more substantial deepwater fields, the TCMS mooring system provides a less complex mooring at half the cost of a traditional deepwater mooring system.

The differences between the shallow and deepwater TCMS are longer mooring lines based on synthetic fibre rope rather than chain, together with the addition of discrete buoyancy units that give the mooring system a wider profile and prevent clashing between the mooring lines and risers. The risers too are lengthened and hang off loads from the TCMS production tower maintained by changing the riser profile and enhancing the buoyancy. Subsea, the production risers can be supported by buoyancy tanks and connect to the FPSO via flexible jumpers, reducing tension on the production risers.

The major difference between the shallow water and deepwater TCMS is the ability to disconnect the bow-mounted riser production tower in the event of adverse weather conditions. The production system tower is designed to be fully disconnectable within eight hours and abandoned to 70 m water depth while the FPSO sails to a safe port. When the FPSO returns, and is on station, the tower is retrieved and reconnected to the bow of the vessel.

Ultra-shallow water productionFor ultra-shallow water projects at 55 m, the TCMS traditional three leg mooring system can be used. Each leg is typically made up of 500 m of Grade 3 chain connected to the mooring system node. This type of mooring project will be close to the shore and so the wave movements will be a good deal less than those found further offshore. In such shallow water, vessel rotation is restricted to ±90˚ movement either side of the mean

heading. The TCMS production tower is also shorter and less complex and supports a maximum of four risers/umbilical orientated in a lazy wave profile from either pipeline or subsea trees.

The flexibility of the Tri-Catenary mooring system offers independent operators a reliable mooring and production solution for offshore marginal fields. The opportunity to deploy the TCMS mooring system quickly and cost-effectively compared with traditional mooring systems presents a compelling case for operators wishing to maximise field production and profitability. O T

Figure 2. TCMS production tower on the Ikdam project offshore Tunisia.

Figure 3. TCMS production tower showing chafe chain, guide collars, risers and umbilical.

Kilobyte-sized

Sandy Johnson, SatCom Global, UK, considers optimising communication for remote operations.

COMMUNICATION

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Efficient communication has long been a challenge for businesses operating in remote parts of

the globe. The ability to exchange information and communicate with colleagues, friends and family has until now been restricted because of high costs and the lack of available bandwidth.

In the area of oil and gas exploration, competition for natural resources has driven exploration teams to distant and hostile environments. These companies need cost-effective, fixed and mobile satellite connectivity to keep them in constant contact with their remote teams, rigs, pipelines and offices worldwide. Always-on connectivity available 24 hours a day, seven days a week, 365 days a year between headquarters and sites around the globe is critical in order to keep operations running smoothly. Reliable communication is essential to maintain high productivity, safety and high employee morale.

In the harsh and often unpredictable environments where oil and gas teams are based, bandwidth is expensive and in short supply. Because the latest technologies generate large volumes of data that need to be transported securely from exploration sites, it is imperative that bandwidth is used with the greatest efficiency.

Additionally, recruiting and retaining qualified crew personnel is not an easy task in this specialised industry.

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Employees are working in isolated environments and the ability to keep in touch with family and friends is important for high crew morale. Companies must be able provide a full range of affordable communication services so personnel can communicate with home on a daily basis.

These factors, along with the requirements for solutions that are easily deployable, flexible and mobile, as well as the ability to integrate into existing communications systems are some of the challenges facing the industry.

The good news is that now there are solutions that meet all of these requirements and more, enabling oil and gas companies to achieve more for less.

The solutionThe latest solutions are based on a highly efficient Voice over Internet Protocol (VoIP) platform, which has been designed to specifically to meet the challenges of remote locations. These solutions optimise communications over the internet by using bandwidth more efficiently and giving users more control over how much data is consumed.

The new portfolio of products covers all aspects of communication, from VoIP calls and email to web browsing and instant messaging.

The core of the Horizon solution is an innovative technology that enables VoIP from only 2 kbps compared to 8 kbps from other G.729-based VoIP services today. The system is fully compatible with digital telecommunications standards.

Figure 1. New efficient communication solutions can provide access similar to what individuals would enjoy in a terrestrial environment.

It operates on a secure, reliable network that is capable of interconnecting any phone system over IP, delivering a scalable and versatile solution.

Bandwidth efficiencyThe key to delivering highly available, reliable and secure communication at an affordable cost is optimisation. Every part of the solution is optimised to use as little bandwidth as possible and consume minimal data.

Unlike traditional VoIP calls, which send the same amount of data in both directions regardless of whether someone is speaking or not, the solution detects and uses less data for silence. By sending ‘heartbeats’, at a data rate of just 0.25 kbps, users can tell that the line has not been dropped.

Users making VoIP calls can choose from three levels of call quality during a call to select the best balance between cost and performance.

Data efficiency extends to a range of optimised applications – email, web browsing and instant messaging. Email is 500 times more efficient than a standard email application. Web browsing is optimised with the removal of unwanted advertising and unnecessary http headers and image compression.

Users are informed of how much bandwidth they are using through a desktop application, which provides the volume of data consumed, and the costs incurred in real time after each mouse-click on a web page or word spoken in a call.

Easy to deployAnother key driver in the choice of communication solutions is that it should be easy to implement for new sites and relocating teams and require a minimum level of telecommunications expertise for voice and data set up.

The ruggedised hardware is designed for simple deployment and ease of use at all levels, from offi ce environments to harsh and extreme conditions. There is minimal equipment to be installed and calls can be made within minutes of set up. All that is required is a wired internet connection and main power supply and the unit connects with any 2-wire analogue telephone for integration with existing telephone systems. Additionally, up to eight analogue telephones can be connected for simultaneous calling over a single internet link – more than any other system today for the bandwidth available.

Users are allocated a unique number and a PIN to access services. Clients enter their PIN into a handset at their current location and all their calls and voicemails will be routed to that phone. This enables a ‘follow-me’ service where users can receive VoIP calls and voicemail on any of the solution’s phone regardless of the location.

Simple billingThose operating on exploration and recovery platforms over large geographies require fl exible billing options that allow easy reconciliation for personal and business communications. Billing systems should support both pre-paid and post-paid billing and central account management.

New solutions, such as Horizon, record all usage against each user’s PIN. This allows detailed call records per user rather

than per device enabling costs to be allocated and, if necessary, billed to an individual. Pre-paid and post-paid billing allows the staff to use pre-pay services for personal communications and post-pay services for business communications – all easily managed on one central account.

Improving crew welfare For employees working in oil and gas exploration, the ability to access the internet and stay in contact with home dramatically improves working conditions and quality of life. New effi cient communication solutions can provide access similar to what individuals would enjoy in a terrestrial environment. Multiple calling capabilities allow many employees to contact friends and family at the same time, rather than waiting in a queue to access a single connection.

Figure 2. The Horizon VoIP PBX box.

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New crew welfare initiatives are also driving the adoption of advanced communications. If businesses want to be perceived as an ‘employer of choice’, it is important that they provide employees reliable and cost-effective communications to stay in contact with family and friends.

Employees now have access to affordable voice and data services and employers have visibility and control of communication costs. Employers are able to offer benefits without the fear of expenditures spiralling out of control, as they look to recruit and retain the best staff.

Satellite backupFor oilfield operations connected by terrestrial communication, satellite backup solutions are vital for seamless failover communication during an unexpected outage.

In the current economic climate, businesses are looking to minimise costs so it is critical that backup communications limit amount of bandwidth required to provide the same level of service as the primary communication solution.

The emergence of bandwidth-efficient VoIP platforms and optimised data applications has enabled businesses to achieve a dramatic reduction in bandwidth for backup communications, while controlling costs and mitigating disruptions to production and risk.

Integrating existing systemsIn a highly competitive commercial environment, leveraging existing equipment is helpful in controlling capital expenditures for investment in new communication systems.

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Solutions that can integrate with existing digital and analogue tele-systems provide multiple benefits. A digital gateway interconnects any digital handset, PBX or server into the communication solution network to maximise the use of legacy equipment. A PRI server that enables least-cost routing for PSTN call termination greatly reduces international calling charges. This solution is well suited for organisations that have a high volume of calls going to one country such as calls from remote locations to a head office, or employees calling home to the same destination.

The flexibility of the technology also allows businesses to manage their own PSTN termination at their own rates or use as back-up purposes when local PSTN access is unavailable.

The server can be configured to handle multiple call-routing combinations and supports up to 240 simultaneous inbound/outbound calls. Additionally, it enables in-country lawful interception to meet local regulatory requirements where necessary.

All around benefitsIn the harsh and unpredictable remote environments where oil and gas companies operate, demand for services is ever increasing. Meeting these demands requires innovation, efficient use of bandwidth and the flexibility and scalability provided by today’s new high performance solutions.

Industry trials have demonstrated potential savings of 50 – 80% on existing communications costs as a result of this optimised voice and data environment.

Organisations requiring specialised communications for diverse global locations can now take advantage of a wide range of high quality low cost voice and data solutions. O T

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oilfield technology volume 04 issue 06-september 2011 …

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