Oilfield Technology September 2012

OILFIELD TECHN

OLOGY MAGAZIN

E

SEPTEMBER 2012

w

ww

.energyglobal.com

VOLUME 05 ISSUE 07-SEPTEMBER 2012

Reliable. Robust. Rugged.

T3 18-3/4” 15K 6091 BOP features the revolutionary T3 SAR® (Shear All Ram) Technology

System™ for maximum safety

+1-713-996-4110 or email sales@

ISSN 1757-2134September 2012 Volume 05 Issue 07

Copyright© Palladian Publications Ltd 2012. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

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

available on request from our sales department.

contents

FMC Technologies designed and manufactured this subsea separation system for Petrobras’ Marlim field. The system was installed last November in 2950 ft (900 m) of water, in the Campos Basin, offshore Brazil. This is the industry’s first application of oil and water separation technologies in deep water. It will become the first system to separate heavy oil and water and to

re-inject water into a subsea reservoir to boost production.

| 03 | EDITORIAL COMMENT

| 05 | WORLD NEWS

| 10 | RESOURCING THE FUTURE Mark Guest, OilCareers.com, UK, gives an overview of the challenges and opportunities raised by the skills shortage in the booming Australian and Asia-Pacific oil and gas industries.

| 15 | THE TECHNOLOGY BEHIND THE REVOLUTION Nadja Kogdenko, Energy Delta Institute, the Netherlands, provides an overview of the technology and practices that have fuelled the shale gas boom.

| 21 | SHALE GAS: ONWARDS AND UPWARDS? Elizabeth Shepherds, Eversheds, UK, outlines the future prospects of the shale gas industry in the European Union.

| 24 | WHAT YOU SEE IS WHAT YOU GET Oilfield Technology Correspondent Gordon Cope explains how advances in simulation and visualisation are helping the oil and gas industry target subsalt and unconventional plays.

| 30 | SEEING THROUGH SOFTWARE Gefei Liu and Cissy Zhao, Pegasus Vertex Inc., USA, explain how the use of advanced software can help engineers ‘see’ underground by predicting subsurface conditions.

| 35 | SETTING UP A SECURE CONNECTION Jim Brock, Michael Jellison and Andrei Muradov, NOV Grant Prideco, USA, explain how the strains of extended reach drilling are driving a demand for improvements in drill pipe connection design.

| 39 | INTELLIGENT IRON Alfredo Sanchez, Top-Co, USA, warns that failure to appreciate the importance of ‘dumb iron’ can lead to costly delays and even more serious consequences; both of which can be mitigated through the adoption of an intelligent engineering approach.

| 45 | THE NEXT GENERATION Eldar Larsen and Paul Hocking, BP Norge AS, Norway, explore the development of next-generation digital oilfields in the North Sea.

| 49 | CUTTING TO THE CORE... Ludovic Delmar, Halliburton, Belgium, takes a look at recent advances in the process of coring in HPHT environments.

| 53 | BLURRING THE BOUNDARIES OF SUBSEA INSULATION Grethe Hartviksen, Trelleborg Offshore, Norway, shows us how synthetic rubber-based solutions allow the offshore drilling industry to operate in increasingly hostile conditions.

| 57 | A WISE INVESTMENT Don McClatchie, Sanjel, Canada, asks why operators should bother taking coiled tubing beyond the basics.

| 60 | FINDING THE SWEET SPOTS Kevin McKenna and Ahmed Ouenes, SIGMA3 Integrated Reservoir Solutions, USA, explain how a predictive model can increase IP rates and EURs in shale oil and gas fields.

| 64 | AUTOMATION-DRIVEN OPTIMISATION Jim Gardner, FreeWave Technologies, USA, takes a look at automation technology considerations for optimising oil production.

| 69 | ACCESS ALL AREAS Drew Brandy, Inmarsat, UK, describes how advances in mobile communications technology can help meet the needs of remote workforces in the demanding oil and gas sector.

| 72 | CLOSING THE GAP Matthew Law, Expro, UK, analyses a new system designed to narrow the value recovery gap between subsea and dry-tree well intervention operations.

| 75 | KEEPING IT COOL Rollie Merrick, Hothead Technologies, USA, explains how biosensors make it possible to help protect hardhat workers from heat stress.

Anna Scordos

Editor

Contact Information >> Palladian Publications Ltd,

15 South Street, Farnham, Surrey GU9 7QU, UK Tel: +44 (0) 1252 718 999 Fax: +44 (0) 1252 718 992

Website: www.energyglobal.com

OILFIELD TECHNOLOGY SUBSCRIPTION RATES: Annual subscription £80 UK including postage/£95/e130 overseas (postage airmail)/US$ 130 USA/Canada (postage airmail). Two year discounted rate £128 UK including postage/£152/e208 overseas (postage airmail)/US$ 208 USA/Canada (postage airmail). SUBSCRIPTION CLAIMS: Claims for non receipt of issues must be made within three months of publication of the issue or they will not be honoured without charge. APPLICABLE ONLY TO USA & CANADA: Oilfi eld Technology Magazine (ISSN No: 1757-2134, USPS: 025-171) is published monthly by Palladian Publications Ltd GBR and distributed in the USA by SPP, 17B S Middlesex Ave, Monroe NJ 08831. Periodicals postage paid at New Brunswick, NJ. POSTMASTER: Send address changes to Palladian Publications, 17B S Middlesex Ave, Monroe NJ 08831.

comment

Managing Editor: James Little

james.little@oilfi eldtechnology.com

Editor: Anna Scordos

anna.scordos@oilfi eldtechnology.com

Editorial Assistant: David Bizley

david.bizley@oilfi eldtechnology.com

Advertisement Director: Rod Hardy

rod.hardy@oilfi eldtechnology.com

Advertisement Sales Executive: Ben Macleod

ben.macleod@oilfi eldtechnology.com

Business Development Manager: Chris Lethbridge

chris.lethbridge@oilfi eldtechnology.com

Production: Peter Grinham

peter.grinham@oilfi eldtechnology.com

Website Editor: Callum O’Reilly

[email protected]

Circulation Manager: Victoria McConnell

victoria.mcconnell@oilfi eldtechnology.com

Subscriptions: Laura Cowell

laura.cowell@oilfi eldtechnology.com

Admin/Reprints

[email protected]

Publisher: Nigel Hardy

A fter years of planned development, diffi cult and unsuccessful negotiations between partners and bad luck with global gas market dynamics, Gazprom’s

fl agship project, Shtokman, has fi nally been shelved. The main reason for the cancellation of the project is essentially the unfortunate reality that demand from Gazprom’s main intended market, namely the USA and Europe, evaporated somewhat with the onset of the shale bonanza in the US and the subsequent fall in the price of gas on the global market. The fate of Shtokman highlights that Gazprom just wasn’t able to react to market change in a way that could still turn it, and its partners, a viable profi t. Aside from unprecedented changes in the global gas scene, the Shtokman project has been dogged with reports of feuding partners, with Gazprom, Statoil and Total simply unable to agree on terms that would allow them to work together in developing the vast resources in this challenging area of the Barents Sea. The fi eld will surely be developed in time. The question remains as to how and by whom.

However, it is not all doom and gloom for the exploration industry by any means. Energy consultants Douglas Westwood have suggested that US$ 77 billion will be spent on the operation of subsea vessels until 2016, which marks a 63% increase on the preceding fi ve years. Their recent report says, “The deepwater ‘Golden Triangle’ of West Africa, Gulf of Mexico and Brazil is expected to account for 34% of global expenditure over the forecast period. Latin America is forecast to be the largest market with

spend of US$ 14 billion during 2012 - 2016: an increase of 94% on the previous fi ve year period.” The report predicts that North America has recovered suffi ciently to make its market into the world’s second largest.

Oil and gas exploration is currently a hot potato in the US in the run up to the US Presidential elections in November. The American Petroleum Institute is targeting swing states with commercials that ask the public to vote for candidates that promote a more relaxed regulatory oil and gas framework. So far, the US oil and gas industry has donated 87% of its election contributions to Republicans. Critics of President Obama have suggested that his oil and gas strategy has stymied the industry. Mitt Romney has suggested that he would largely support the oil and gas industry’s agenda.

On the other side of the Atlantic, opportunities in exploration offshore the Mediterranean appear to be opening up at a positive rate. In the past few years over 35 trillion ft3 of gas has been found offshore Israel and Cyprus and Italy has recently relaxed the ban that it imposed on oil drilling around its coast. There seem to be many players vying to explore the waters of the Mediterranean, which, with its relatively low geopolitical risk rating, seems like an attractive place to operate.

I hope you enjoy this issue of Oilfi eld Technology. If you’re reading this issue of the magazine at the SPE ATCE in San Antonio, please feel free to come and say hello; the Oilfi eld Technology team are exhibiting at booth number 1235. O T

Maximize your assets

To view the video, download a QR reader app for your smartphone and scan.

Some or all of the systems, methods or products discussed herein may be covered by one or more patents, or patents pending. Copyright © 2012 Packers Plus Energy Services Inc. All rights reserved.

Are your completions giving you reliable, repeatable results?Packers Plus’ patented open hole, multi-stage systems allow us to complete well after well with proven performance. As the industry leader,

our team will help you make better wells through innovation and operational excellence. With a well-known global track record, we can work

with you around the world in any environment or formation.

Since 2000, Packers Plus has completed over 7,750 open hole StackFRAC® ball-drop systems accounting for over 80,000 fracture stages.

Contact us today and let us help you maximize your assets.

Josh, Engineer, Eastern Hemisphere

world news

05OILFIELD TECHNOLOGYSeptember 2012

inbriefIndia’s state-run Oil and Natural Gas Corp. (ONGC) has announced that it has plans to invest up to US$ 20 billion to meet its current oil and gas output targets by 2030.

The Indian government has been encouraging state-owned companies to invest in foreign oil and gas assets in order to meet growing demand. The country currently imports 80% of its crude oil needs, but this figure is expected to rise to 91% by 2030.

ONGC has a long road ahead if it is to meet its output targets by 2030; the company produced 8.75 million TOE in the previous financial year, has plans to meet 20 million TOE by 2018 and eventually 60 million TOE by 2030. This is expected to be achieved largely through joint ventures and the acquisition of foreign assets.

A statement from the company clarified the situation, “As the

production targets are quite steep [the company] needs to concentrate on acquiring assets in the development and production phase initially and then concentrate on high potential exploration acreage and also venture capitalist types of opportunities.”

At least some aspects of ONGC’s investment programme may already have hit a snag, however. The acquisition of US hydrocarbon assets is likely to be delayed or even blocked outright because of the company’s investments in Iran and Sudan. ONGC’s Chairman and Managing Director, Sudhir Vasudeva said, “We are present in Iran and Sudan. Because of this there are restrictions. We are trying to find ways to circumvent that [...] We have a gas discovery in Iran and that has to be taken forward, which requires millions of dollars. We are weighing the pros and cons of that investment.”

UKDespite facing its worst annual decline in decades, the UK Oil and Gas industry is poised for a rebound, according to former Energy Minister, Charles Hendry. UK output dropped to 1.04 million bpd last year, down from a record of 2.9 bpd in 1999.

The minister was quoted as saying, “My expectation is that we will now see things beginning to move back up again [...] It may be plateauing but I would certainly expect us to see, from the discussions I have with the industry, some pretty positive feelings about the way in which the industry can move forward.”

SUdan & SoUth SUdanSudan and South Sudan have resumed talks with the aim of ending a number of ongoing disputes over their shared border, security issues and oil.

The two countries were engaged in border skirmishes earlier this year and came perilously close to all out war. The most recent dispute came about over a disagreement over oil transit fees.

The UN Security Council eventually had to intervene and order a ceasefire between the two oil producing nations.

UgandaThe Ugandan government has withheld approval of Tullow’s development plan, which would see the company share its oil licenses with CNOOC and Total.

Approval is likely to remain withheld until the companies agree to Uganda’s request for them to part-fund the construction of a 150 000 bpd refinery, initially to supply products for the domestic market. Peter Lokeris, Uganda’s Junior Energy and Minerals Minister said, “Oil is a finite resource and it would benefit the Ugandan people better if it isn’t rapidly exploited.”

// ONGC // US$ 20 billion in investments forecast

Gazprom has had to put its giant Barents Sea-based Shtokman natural gas project on hold, as partners Statoil and Total found that the costs of development were too high.

The main problem that the project faced was the US shale boom; much of the gas to be produced from Shtokman was destined to be exported to the US market, which is now saturated with cheap, domestic shale gas. In addition to US shale, Shtokman faced strong competition from more accessible assets offshore Mozambique and Tanzania.

Despite the setbacks, Shtokman remains one of Gazprom’s long term priorities, with the company hoping to target South East Asian and South American markets in the near future.

In the immediate aftermath of the storm, risk modelling firms suggested that the damage to the oil industry caused by Hurricane Isaac could be up in the billions. The US BSEE has, however, reported that despite some coastal refineries facing flooding damage, offshore facilities escaped relatively unscathed.

Eqecat, a risk modelling firm, had predicted that damage to industry assets could cost as much as US$ 1 billion.

The majority of offshore personnel were evacuated from oil rigs in the Gulf of Mexico along with a shutdown of 93% of oil production and 67% of gas production. Gulf Coast refineries were also shut down, cutting off 2.4 million bpd of processing capacity.

// Gazprom // Shtokman on hold

// USA // The cost of Hurricane Isaac

OT_September2012_05-09.indd 5 07/09/2012 09:13

world news

06 OILFIELD TECHNOLOGY September 2012

diarydates

17 - 20 September Rio Oil & GasRio de Janeiro, BrazilE: [email protected]

08 - 10 OctoberSPE ATCESan Antonio, Texas, USAE: [email protected]/atce/2012

08 - 11 OctoberGastech 2012Excel London, UKE: [email protected]

04 - 09 NovemberSEG 2012Las Vegas, USAE: [email protected]

11 - 14 NovemberADIPECAbu Dhabi, UAEE: [email protected]/conference

20 - 22 NovemberPETEX 2012London, UKE: [email protected]

27 - 30 NovemberOSEA 2012Marina Bay Sands, SingaporeE: [email protected]

// Shell // One step closer to drilling for Arctic oil

Shell has announced that it has been given the all clear to begin preliminary activities prior to drilling for oil offshore Alaska. The initial permit approved by the US Bureau of Safety and Environmental Enforcement allows Shell to begin the construction of safety features such as a mudline cellar, which is designed to ensure that the blowout preventer is sufficiently protected. The company will also be allowed to drill one of two casing strings into a shallow, oil-free zone.

Despite this step forward, Shell still does not have permission to drill for oil; something that the company has spent approximately US$ 4.5 billion on preparing for. According to James A. Watson, Director of the BSEE, “Shell’s applications for permits to drill into potential oil reservoirs remain under review and Shell will not be authorised to drill into areas that

may contain oil unless and until the required spill containment system is fully certified, inspected and located in the Arctic.”

Shell’s bid to drill in the Chukchi Sea offshore Alaska has attracted criticism from environmental groups and others concerned about the potentially devastating impact of an oil spill on the fragile Arctic ecosystem.

The delays that have hampered the company’s progress in the Arctic are also beginning to deter other oil and gas producers from moving to the region just yet. Tim Dodson of Norwegian company Statoil was quoted by the Financial Times as saying, “As long as Shell has not been able to show they can get the permits and start to drill, we’re a bit sceptical about moving forward. You need [to know] that they will be allowed to do it in a predictable manner.”

BP has unveiled a new system designed to greatly increase the amount of oil that can be extracted from oilfields.

The oil and gas industry is already familiar with a technique known as ‘waterflooding,’ where seawater is pumped into oil bearing formations to help bring more oil to surface. What makes the new system different is the use of desalinated water. Water that has had most of its salt content removed is more efficient at breaking the chemical bonds between oil and the rocks in which it is situated, thus making it easier to extract. Water with too high a salinity has the opposite effect.

The system is due for first use at the Clair Ridge development offshore Shetland, UK, where it is hoped it will produce an additional 48 million bbls.

Providence Resources has released further studies from its Barryroe field offshore Ireland. The studies cover two deeper reservoirs that could have the potential for an additional 780 million bbls.

John O’Sullivan, Providence Resources’ Technical Director was quoted as saying, “It is clear that more data are required over these intervals, however, the numbers are potentially material and provide room for significant resource growth in the Barryroe project in the longer term.”

Even without this upgrade, the main wells of the Barryroe field could access significant reserves, with the company estimating a 50% likelihood of at least 1 billion bbls and a 10% likelihood of 1.6 billion bbls in place. Barryroe was first discovered in the 1970s by Esso.

// BP // LoSal EOR technology unveiled

// Providence // Barryroe Upgrade

Whether drilling with a PDC or roller cone bit and regardless of the formation, Dyna-Drill power sections deliver the power you need to optimize ROP.

Dyna-Drill manufactures high-performance mud motor power sections from conventional to ultra torque. Stator rubber formulations developed by Dyna-Drill have produced innovations in elastomer durability resulting in products that serve specific applications which can be compounded to withstand the most punishing drilling fluids and downhole temperatures.

For nearly 50 years, Dyna-Drill has offered operators the most technologically advanced and efficient downhole motor equipment in the oil and gas industry.

www . d y n a - d r i l l . c o m / p o w e r s e c t i o n . a s p© 201 Dyna-Drill® Technologies

Proven performance for any application

Powerful. Proven. Dyna-Drill.

Power Section Sizes: 111/16 in - 111/2 in

world news

08 OILFIELD TECHNOLOGY September 2012

// Saudi Arabia // May have to import oil by 2030

// BP // US$ 11 billion investment in Egypt

// PDVSA // Plans to drill off Western Cuba

// USA // Shale boom could aid Obama

// Iraq // Kurdistan row: budget-cuts threat

BP has revealed plans to invest US$ 11 billion in a deepwater gas project offshore Egypt.

After finding samples from two separate plays in the Nile Delta that proved the existence of natural gas deposits, BP, in the process of drilling to more than 25 000 ft in order to reach reserves that could produce at approximately 1 billion ft3 per day and would represent 20% of Egypt’s total energy production. The project is expected to take 4 - 5 years to complete and once operational, the field will supply 40% of the country’s natural gas.

A survey by the US Energy Department has reported Egypt as having Africa’s third largest proven gas reserves at 77 trillion ft3.

The new Egyptian government has made attracting investment from major companies, such as BP, and developing the country’s fossil fuel reserves a key economic policy.

The Venezuelan state oil company PDVSA has begun exploring for oil offshore western Cuba after taking over the lease on the US$ 750 million Scarabeo 9 rig.

Rafael Ramirez, Cuba’s Oil and Mining Minister said, “It started and when we have the results, we’ll tell the country,” but declined to give any further details.

PDVSA will be the latest in a series of companies to search for oil offshore Cuba. PC Gulf and Gazprom Neft both found an “active petroleum system” at 4666 m, but neither was able to produce sufficient levels of hydrocarbons to make the venture worthwhile. Repsol also failed to make any discoveries earlier this year.

Estimates of the reserves offshore Cuba mostly range from 5 - 9 billion bbls, but the Cuban government predicts a higher figure of 20 billion bbls.

Cuba has divided its offshore exclusive economic zone into 59 blocks; 22 of these are currently contracted to foreign oil companies.

The continuing US shale boom could act as a boost to US President Obama’s chances of re-election this coming November.

It has been the goal of US presidents for decades to reduce the nation’s dependence on imported oil and only a few have managed it. During Obama’s presidency, US oil production has risen by 23%. Whether or not the increase is as a result of Obama’s policies or simply an “accident” as some have claimed, it looks set to help the president in the forthcoming election: The energy industry has become one of the main drivers of the US economy and unemployment levels in states impacted by the shale boom, such as Ohio and Pennsylvania (important swing states) have fallen.

Despite pressure from fellow Democrats and spending US$ 90 billion on alternative energy sources, Obama has made no real attempt to slow the use of hydraulic fracturing.

The Iraqi central government has threatened to cut the budget for the semi-autonomous Kurdistan region by at least US$ 3 billion to make up for losses accrued as a result of the region’s oil exports.

Prime Minister Nuri al-Maliki said that Kurdistan had failed to export the correct amount of oil and had therefore caused a loss of at least US$ 3 billion. According to Baghdad, Kurdistan had agreed to export 175 000 bpd, but this figure routinely fell to 100 000 - 120 000 bpd.

Kurdistan recently agreed to resume exports of oil as a “goodwill gesture” after a dispute arose over Kurdistan’s dealings with foreign oil companies. This most recent announcement could risk worsening relations once more.

Analysis by Citigroup has predicted that if current trends continue, Saudi Arabia, a country synonymous with oil production may actually have to import oil by 2030.

Though it may seem like complete fantasy, the facts behind the prediction appear to be solid. Although Saudi Arabia produced 9.9 million bpd in the previous month, the country relies on oil and oil related products for roughly half of its electricity generation; at present, this demand is set to increase at approximately 8% per year. In total, the kingdom uses nearly a quarter of all the oil it produces to supply domestic demand.

The country also consumes the entirety of its natural gas production and has so far refused to import gas from

abroad, unlike many of its oil-producing neighbours such as Kuwait and the UAE.

Further compounding the problem is the fact that domestic demand is fed by heavily subsidised oil, meaning that Saudi Arabian power producers have little incentive to move to other fuels. Oil is available anywhere from US$ 5 - 15/bbl., in stark contrast to current internationally traded prices which reside within the US$ 100 region. Domestic demand has been calculated to have cost the country US$ 80 billion in lost oil revenues.

The consequences of oil dependence have not been lost on the Saudi Arabian government, which has plans to spend US$ 109 billion on 41 000 MW of solar power generation. • Environmentally Friendly

• Superior Torque Reduction

• Compatible In Various Brines

VALERIE SUTHERLANDCorsiTech Account ManagerO�ce/Direct Line: 713-332-1521Cell Phone: [email protected]

TM

CorsiTech.indd 1 03/02/2012 08:46OT_September2012_05-09.indd 8 07/09/2012 09:32

Environmentally Friendly

Superior Torque Reduction

Compatible In Various Brines

VALERIE SUTHERLANDCorsiTech Account ManagerOffice/Direct Line: 713-332-1521Cell Phone: [email protected]

TM

RESOURCING THE FUTURE

10

MARK GUEST, OILCAREERS.COM, UK, GIVES AN OVERVIEW OF THE CHALLENGES AND OPPORTUNITIES RAISED BY THE SKILLS SHORTAGE IN THE BOOMING AUSTRALIAN AND ASIA-PACIFIC OIL AND GAS INDUSTRIES.

Oil and gas industry

Australia

11


Papua New Guinea

Japan

Indonesia

of natural gas daily and

Responsibility is part of our DNAUnderground shale formations may reduce the U.S. dependence on imported oil and gas. But developing these resources commands respect and responsibility for the local communities and the environment. We are committed to keep implementing technologies that meet the toughest efficiency and safety standards, today and in the future. For us, it’s a question of never being satisfied.

Discover more at neversatisfied.statoil.com

Always improvingNever satisfied

Malaysia

Singapore

Thailand

Conclusion

O T

TIME IS MONEY.

IT’S NOTHING NEW. YOU

NEED TO GET TO THE

TARGET FASTER, BECAUSE

THE LONGER IT TAKES,

THE MORE IT COSTS.

GETTING TO THE GOAL

EFFICIENTLY REQUIRES

INFORMATION; ACCURATE,

RELIABLE INFORMATION.

THAT’S WHERE WE COME

IN, WITH THE ORIGINAL

SURVEY ON CONNECTION™

MWD TOOLS, EXTREME

ENGINEERING WILL

GET YOU THERE, FASTER.

Next

Ge

ne

rati

on

MW

D S

yst

em

s

EXTREMEENG.COM

24/7 SUPPORT [email protected]

THE TECHNOLOGY BEHIND THE REVOLUTION

Shale gas reservoir development is a growing source of domestic natural gas production across the US. The combination of two innovative technologies,

horizontal drilling and hydraulic fracturing, has enabled economic production of the country’s indigenous unconventional gas reserves, drastically changing the national energy market. Hydraulic fracturing, commonly referred to as ‘fraccing’, is a proven technology that has been used for approximately 60 years on more than a million wells, allowing producers to recover natural gas and oil from deep shale formations.1 However, during the last decade, the application of this technology has been accompanied by debates on the associated risks and environmental impacts. This article aims to provide an overview of the main techniques used for shale gas production, its associated risks and environmental impacts as well as presenting a number of potential challenges for the new entrants into the shale gas business.

NADJA KOGDENKO, ENERGY DELTA INSTITUTE, THE NETHERLANDS, PROVIDES AN OVERVIEW OF THE TECHNOLOGY AND PRACTICES

THAT HAVE FUELLED THE SHALE GAS BOOM.

15


Conventional vs. unconventional The idea of producing natural gas from shale formations is not new; shale gas has been produced in the US in small quantities since the 1940s.2 However, due to the low productivity of shale wells and relatively high costs, the production of this gas was considered a small scale niche and therefore did not attract much attention from oil and gas majors. Techniques for natural gas production from shale have improved dramatically over time, most

geologist, combined the techniques of horizontal drilling and hydraulic fracturing, allowing greater yields of shale gas and

3

To understand the need for these techniques, the differences between conventional and unconventional gas production have

transformation of an organic-rich source rock.4

natural gas reservoirs gas is trapped in a porous rock (e.g. sandstone), sealed with an impermeable cap rock (typically a salt layer), which prevents the gas from migrating to upper layers. From such a conventional reservoir natural gas can be recovered

well typically reaches between 1500 and 3000 m beneath the surface and is exclusively vertical.5 Conventional natural gas reservoirs usually have high productivity due to two essential properties - high porosity and permeability. These two reservoir properties ensure that the gas can easily migrate through the reservoir pores to the wellbore.6 Conversely, gas shales (organic-rich shale formations) are characterised by a source rock

with low porosity and low permeability.7 Because of these poor

requires additional stimulation, such as hydraulic fracturing. The process of shale gas production begins with the drilling of

a vertical well. Since shale gas deposits are located deeper than the conventional gas reservoirs, this vertical section can reach

be drilled in the horizontal direction by using directional drilling equipment or a so-called ‘horizontal drilling technique’. This technique provides increased wellbore exposure to the deep reservoir area, allowing for a reduced number of surface drilling

used to drill the horizontal section of the well, which can reach up to 5 km in length, does not necessarily have to reach 90° for the well to be considered a horizontal well.5

another key technology, which enabled economic production of shale gas in the US. This technique is used to create additional

more easily towards the wellbore. When the horizontal well is completed and the well casings are set (in order to isolate the overlying zones and to guarantee well integrity), parts of the casing in the horizontal section of the well are perforated (Figure 1). The perforation is done by the use of a perforating gun, which ‘punches’ small holes in the well casing, cement and

is pumped into the well and pushed though the created

cracks in the rock formation are created, allowing the natural gas 8

Shale gas wells are usually fractured in stages, and each stage is designed to fracture the rock a certain distance (approximately 60 m) from the well.5

each stage in order to maintain pressure and achieve maximum

open when the pressure is relieved, allowing shale gas production

process, i.e. help to reduce friction, prevent bacterial growth and

the plugs are drilled out, the production wellhead is put in place and production begins.

The evolution of techniques Hydraulic fracturing is often referred to as a technology that has been used for decades in the gas industry. However, there are some major differences between the way this technology is used now and in the past.

Hydraulic fracturing, as it is currently used for shale gas production, was developed in the late 1990s. This technique is called ‘slick-water hydraulic fracturing’, since it uses a different mix of additives than previous methods, reducing the amount of gelling agents and adding friction reducers, which allow the

4 The modern technology is also known as high-volume hydraulic fracturing (HVHF), since it uses larger

3 to fracture a well, compared to 75 - 300 m3 used in the ‘original’ hydraulic

and horizontal length of the wellbore, as well as the number of fractures created along it.1

Figure 1. Hydraulically fractured horizontal well (not to scale).19

Figure 2. Effi ciency improvements in shale gas production. Best practices of Southwestern Energy Company in the Fayetteville shale formation.9

SDI offers “fit-for-purpose” solutions built in-house – down to the sensor level, and our application engineering group is constantly developing and implementing new technologies. That’s the power of Scientific.

Since 1969, Scientific Drilling International (SDI) has pioneered many Directional Drilling and Wellbore

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

Drilling Systems Directional Services MWD/LWD Services

Precision Surveying MWD Ranging Production Logging

Scientific Solutions

Scientific Drilling Services:

www.scientificdrilling.com

Drilling Challenges...


Over time, the use of both horizontal drilling and hydraulic fracturing techniques was perfected by small oil and gas service companies. Shale gas currently represents approximately 20% (138 billion m3) of total US gas production and is projected to reach 50% by 2035.9 Already with the current production level the US has taken the world’s top producer position and transformed from the world’s largest gas consumer to a potential gas exporter.

Developments in the shale gas industry can be seen in the example of the Southwestern Energy Company’s practices in the Fayetteville shale from 2007 to 2009 (Figure 2).9 Figure 2 demonstrates that in just over two years, the time required for drilling one horizontal well decreased by 45%, while the average length of a horizontal well section almost doubled, resulting in

At the same time, production costs (drilling and well completion costs) remained nearly unchanged, while gas transportation costs were very low, since the location of shale gas production sites in the US tend to be in the vicinity of large high pressure (HP) trunk lines. This combination of improvements allowed each rig to produce more wells on an annual basis, resulting overall in a more

9

World distribution of shale gas and current activities In the context of the advances described, the following question should be asked: are the world’s shale gas reserves large enough to sustain the current production boom? The US Energy Information Administration (EIA) in its recent report examined 48 shale gas basins in 32 countries and estimated a technically recoverable shale gas resource base in the assessed regions of 6622 trillion ft3 (tcf) or 187.5 trillion m3 (tcm).10, 11 However, it seems likely that the global shale gas potential is even higher, taking into account that such regions as Russia, central Asia, the

from the EIA analysis. To put these estimates in perspective, world proven natural gas reserves were approximately 6700 tcf (189.3 tcm) at the end of 2010,12 implying that solely shale gas resources can double this amount.

According to these estimates, the US holds approximately 862 tcf (24.5 tcm) of technically recoverable shale gas resources, which is about three times the amount of proven commercial reserves of natural gas and 40 years supply at present consumption rates.13

resources are located in China (1275 tcf), Argentina (774 tcf), Mexico (681 tcf), South Africa (485 tcf), Australia (396 tcf), Canada (388 tcf), Libya (290 tcf), Algeria (231 tcf), Brazil (226 tcf), Poland (187 tcf) and France (180 tcf).10 The amount of these shale gas resources that will be developed in the future mainly depends on demand, the reachable volume (taking into account social and environmental challenges) and developments in technology allowing shale gas to be extracted at lower cost.1

Currently, dozens of companies are involved worldwide in shale gas activities. Outside of the US, approximately 50 companies are currently active in shale gas exploration in Europe, including majors, such as ExxonMobil, Shell, Total, ConocoPhillips and Chevron, as well as small state oil and gas companies. The majority are involved in data acquisition for appraisal purposes. A number of international oil companies, led by Exxon, have already obtained exploration licences in Poland, Hungary, Germany, Romania, Sweden and the UK. However, most of the majors focus on Poland,

production of shale gas began), and which has already granted licences covering approximately 40% of its land in the hope of replicating the US experience.6, 14 The level of success of shale gas

In January 2012, Exxon decided to end its search for Polish shale 14

Outside of Europe, the domestic production of shale gas could help to resolve many countries’ growing dependence on energy imports. In this respect, China, the world’s biggest energy user, also hopes that shale gas could become an abundant and cheap new fuel source. Recently, Beijing has made shale gas a key part of its

3 in 2020.14 In March 2012,

gas in China. Other foreign oil and gas companies that have been negotiating joint shale gas exploration and production activities in China include BP, Chevron, Statoil ASA and Total.

Risks and environmental impacts associated with hydraulic fracturing As with immense gas production, the application of hydraulic fracturing raises many questions regarding its impact on human health and the environment. A 2011 report of the Tyndall Centre (a research organisation founded by seven universities in the UK) assessed the possible risks and impacts of hydraulic fracturing and shale gas drilling. Several key risks related to the use of water and the chemical compositions of the

In currently applied techniques, the volume of water

(approximately 20 000 m3) and on average 15% to 80% of the

surface after the fracturing procedure.5

consists of 98% to 99.5% water and sand, as well as a wide spectrum of additives (0.5 – 2%), depending on the conditions of

15 Until recently, these substances were generally considered proprietary knowledge of the drilling companies and were not disclosed. Currently, due to concerns raised about potential groundwater contamination, this situation is changing and a few states in the US already require or will soon require

potassium chloride, guar gum (commonly used in ice cream), ethylene glycol, sodium carbonate, potassium carbonate, sodium chloride, borate salts, citric acid (Vitamin C), glutaraldehyde, petroleum distillate and isopropanol.5 Even though these components are also used in such industrial sectors as cosmetics, food and in the household/detergent industry, several critics argue that their application in hydraulic fracturing puts groundwater and therefore, human health, at risk. Issues of

The US Environmental Protection Agency (EPA) is currently performing a large study, but its results will only be announced in 2014.14

Another risk associated with fracturing is the disposal of

additives, but also some heavy metals and radioactive elements absorbed from the fractured layers in the shale formation. Due to its potentially toxic nature, this water must be handled and disposed of appropriately.5

CASING DESIGN FOR EXCEL


Seismicity is another potential risk associated with hydraulic fracturing. According to Daly (2011),16 several cases of earthquakes have reportedly been caused by hydraulic fracturing. For instance, two earthquakes (2.3 and 1.5 on the Richter scale; the earthquake of 11 March 2011 in Japan was a magnitude 9.0) were recently registered in Lancashire, England. These tremors were a result of the fracturing activities of Cuadrilla Resources, according to a recent report from The Department of Energy and

for shale gas in the UK, Cuadrilla was required to suspend its hydraulic fracturing operations in the Lancashire area.14 Outside the UK, a strong rise in seismic events was registered in the US state of Oklahoma, an area where a large amount of fracturing activity has been performed.17

Due to these risks and environmental considerations, several countries in the world, particularly European countries such as France and Bulgaria, imposed a moratorium on hydraulic

environmental impact of shale gas development is performed. This decision was based on strong opposition and protests from environmental organisations and residents living in the vicinity of proposed shale gas development activities.

Main challenges for new entrants The risks associated with hydraulic fracturing are not the only challenges related to shale gas production. For other countries to be able to unlock their shale gas resource potential, several issues need to be taken into consideration. Depending on the country, geology can represent one of the major challenges to shale gas production. Shale deposits in the US are shallow and the basins themselves are large, which made the application of horizontal drilling and fracturing techniques a success.17 In other parts of the world, particularly in Europe, the geology is different and so is the population density, posing another potential challenge. For economically viable shale gas production, several drilling rigs and wells are required to be placed relatively close to each other, and new road and pipeline infrastructure needs to be developed. Countries with a high shale gas potential, such as China or Poland, are in general more densely populated than the US, leaving fewer opportunities for shale gas development. In order to reduce land use requirements, several technological approaches have been developed in the US, including a so-called ‘superpad’ approach. Instead of drilling evenly spaced vertical wells, ‘superpads’ engage a group of wellheads, which are clustered together, while the well shafts ‘splay out’ into the

technique, these additional costs may be offset by the reduced social costs associated with lower land use in densely populated areas.18

The US is a ‘home’ for many rig facilities companies and retains

Nevertheless, acceptance by local communities is likely to present a major challenge for the development of shale gas in other parts of the world, and particularly in Europe.17 This relates not only to the environmental impacts and risks associated with the use of fracturing techniques, but also to the question ‘what’s in it for me?’ In case of the US, the mineral rights are owned by local residents, which they can sell, making a substantial

offered US$ 5500 an acre, with 20% royalties on whatever gas

17 On the contrary, in many EU countries and other parts of the world, these rights are owned by the state, which

movement, and the landscape and noise pollution associated

especially when considering the scale of development required

impacts.

Concluding remarks The use of horizontal drilling in combination with

companies to economically produce natural gas from low permeability shale formations in the US. Nevertheless, the application of these techniques is often accompanied by many questions related to the risks involved and the associated environmental impacts. Even though both techniques are

research in order to entirely evaluate the environmental impact of shale gas production.

Besides the US, there is a high shale gas resource potential in other parts of the world, and several activities with respect to

initiated by oil and gas majors. However, due to the challenges discussed in this paper, the rapid replication of the American success in those regions is still questionable. O T

References: 1. TC Gasmap (2011). How will High-Volume (Slickwater) Hydraulic Fracturing

of the Marcellus Shale Differ from Traditional Hydraulic Fracturing? Available at http://www.tcgasmap.org/media/Hydraulic%20Fracturing%20Differences%20for%20Lobbying.pdf.

2. Atlantic Council (2011). European unconventional gas developments. Environmental issues and regulatory challenges in the EU and the US.

3. Ivanov, N.A. (2010). Shale gas. FAQ. Material for the seminar “shale gas revolution: risks and opportunities for Russia”.

4. Published in the Quarterly of the Energy Delta Institute, vol 3, December 2011.

5. Rahm, D. (2011). Regulating hydraulic fracturing in shale gas plays: The Case Energy Policy, 39, 2974 – 2981.

6. Gas Strategies (2010). Shale gas in Europe: A Revolution in the Making? Available at http://www.gasstrategies.com/files/files/euro%20shale%20gas_final.pdf.

7. Arthur, J.D., Bohm, B & Layne, M. (2008). Hydraulic fracturing considerations for natural gas wells of the Marcellus shale. Presented at The Ground water Protection Council 2008 Annual Forum, Cincinnati, Ohio.

8. Shell (2012). Information on hydraulic fracturing. Available at http://www.shell.com.

9. Bentek (2010). US Natural Gas Market Outlook: Technology Transforms and Industry. Presented to International Gas Union, Strategy Committee on February 26, 2010 in London.

10. EIA (2011). World shale gas resources: an initial assessment of 14 regions outside the United States.

11. Tyndall Centre (2011). Shale gas: a provisional assessment of climate change and environmental impacts. Available at: http://www.tyndall.ac.uk/sites/default/files/tyndall-coop_shale_gas_report_final.pdf.

12. IEA (2011). IEA statistics. Natural gas information.13. Financial Times (2012). A collection of articles on shale gas. Available at

http://www.ft.com.14.

shale-gas.15. Geny, F. (2010). Can unconventional gas be a game changer in European

16. Daly, J. (2011). US Government Confirms Link Between Earthquakes and Hydraulic Fracturing. Oilprice.com. 6 December. Available at http:// oilprice.com/Energy/Natural-Gas/U.S.-Government-Confirms-Link-Between-Earthquakes-and-Hydraulic-Fracturing.html.

17. Stevens, P. (2010). The ‘Shale Gas Revolution’: Hype and Reality. Chatham House. September 2010.

18. House of Commons (2011). Energy and Climate Change Committee. Fifth report on session 2010-12. Shale Gas. Volume 1. Available on the Committee website at www.parliament.uk/ecc.

19. Kopp Illustration, Inc.

ElizabEth ShEphErd, EvErShEdS, UK, oUtlinES thE fUtUrE proSpEctS of

thE ShalE gaS indUStry in thE EUropEan Union.

ShalE gaS: onwardS and

UpwardS?

Shale gas has been at the centre of an energy revolution in the US, with a dramatic effect on energy prices, energy security and job creation.

Whilst this has not gone unnoticed in the EU, Member States continue to take different positions on shale gas, ranging from Poland’s enthusiasm for shale gas to France’s reluctance even to allow exploration (although there are signs now of a much more balanced debate). What is noticeable at both EU and Member State level is an increasing scrutiny of the facts around shale gas. Various studies have been commissioned into different aspects of shale gas, including the relevant regulatory regimes as well as the environmental and technical aspects, to ensure that any decisions on the future of shale gas are made in an informed manner. So how is the landscape for shale gas developing in the EU?

Member States’ positions Poland is still seen as the Member State likely to be first to exploit its shale gas reserves on a commercial scale, the result of a combination of political will to achieve independence from Russia and favourable geology. More than 100 concessions for exploration have been granted to date, and a 1 billion PLN fund has been established to finance shale gas research and development. The government is still expected to announce a tax on hydrocarbon production shortly, to ensure what it describes as a fair return for Poland without discouraging investment by foreign companies with the means and the knowledge to realise Poland’s shale gas ambitions.

The approach of the UK, which was the first to carry out a detailed study, continues to be broadly favourable. The Department of Energy

and Climate Change (DECC) has recommended that hydraulic fracturing, the technology used to extract shale gas, should continue with appropriate safeguards and mitigation measures. The view of the Royal Society and the Royal Academy of Engineering is that hydraulic fracturing can be managed effectively, so long as operational best practices are implemented and enforced through regulation. The recent appointment of a pro-shale gas Environment Minister is a potentially significant development for shale gas in the UK.

In Germany, the approach is likely to be influenced by the results of two expert studies into the environmental impact of fracturing commissioned by the Federal Ministry for the Environment and the State of North Rhine-Westphalia. The Federal Ministry study has just been published, and recommends strict requirements for hydraulic fracturing. In particular, mandatory environmental impact assessment and a prohibition of hydraulic fracturing in drinking water and mineral spring protection areas is recommended. There is also a call for transparency in connection with the use of chemicals. The new Federal Minister for the Environment, Peter Altmaier, has recently presented a 10 topic plan entitled ‘With New Energy’ which summarises key energy issues until the Parliamentary elections in 2013. Topic Seven deals with hydraulic fracturing, mentioning a possible strengthening of the requirements around environmental impact assessment and a prohibition of hydraulic fracturing in drinking water protection areas. In the meantime, some individual municipalities in Germany continue to oppose hydraulic fracturing.

21


In France, the building blocks are now in place for shale gas exploration to move forward. In March 2012, the government published its expert study, which was clearly in favour of exploration, and a decree was issued setting up a Commission to evaluate the environmental issues involved in shale gas. Recent comments from the French Prime Minister, Jean-Marc Ayrault, have indicated that the debate is moving in a positive direction.

Elsewhere across the EU, shale gas continues to rise up the political and social agenda. In January 2012, shale oil and gas exploration through hydraulic fracturing was banned in Bulgaria until environmental impact concerns had been addressed. This ban (which has since been modified to allow research and development into shale gas activities) was in response to political and public opinion, however the government has been careful to leave the door open for shale gas in the future.

Other Member States, such as Denmark, Finland and Ireland, have not taken any formal position although the situation is kept under review.

What are the challenges for shale gas development?One of the biggest challenges is for industry to satisfy the public that shale gas can be produced in an environmentally safe manner, within the framework of a robust regulatory regime.

Hydraulic fracturing is nothing new. It has been conducted since the late 1940s, and every step of the process, not least sound well construction and the installation of multiple layers of steel and cement, is carefully planned, managed and monitored to minimise environmental impact. In fact, it is no different from conventional oil and gas extraction.

There is concern that there is an information gap in the EU, and it is essential for industry to engage with the public to educate, inform and ensure that there is information publicly available on hydraulic fracturing which is accurate and up to date. In the US, platforms such as ‘Energy in Depth’ run proactive research, education and public outreach campaigns, and a similar platform in the EU is underway. In addition, there is increasing interest in exploring the possibility of adopting a procedure in the EU along the lines of FracFocus in the US. FracFocus is a web-based national registry (fracfocus.org), run by the US Groundwater Protection Council and US Department of Energy. It allows the public to access information, on a well by well basis, on chemical constituents used in hydraulic fracturing. In some US states (Texas and Colorado), disclosure on FracFocus is a mandatory legislative requirement post application of the relevant fluid.

It is also critical to ensure that the conclusions reached by decision makers in the EU are based on accurate technical information.

Next steps in the EUThere is recognition that the impact of the technology involved in shale gas activities from an environmental, socio-economic and climate change perspective must be properly understood. The ‘Golden Rules for a Golden Age of Gas’, published by the International Energy Association in May 2012, call for “the highest practicable environmental and social standards” in relation to the development of unconventional gas resources.

Draft reports on different aspects of shale gas were issued in March 2012 by two committees of the European Parliament, the ITRE (Industry, Energy and Research) Committee and the ENVI (Environment and Public Health). Both these reports, due to be

voted on shortly, are likely to influence the debate. Neither draft calls for new regulation, but the ENVI draft report on “the environmental impacts of shale gas and shale oil extraction activities” takes the stance that further screening is needed of both EU and national law to assess their adequacy.

This debate around the adequacy of existing EU regulation continues, despite the conclusion of the European Commission’s study on the legal framework for shale gas (published in January 2012) that there is already a satisfactory regulatory framework in Europe for shale gas activities as they currently stand. The European Commission is proposing to carry out a further review of the regulatory provisions governing shale gas extraction in eight EU Member Countries, with the intention of proposing suitable regulatory measures, where necessary, by the end of 2013.

What about the economics?The economic significance of shale gas cannot be underestimated. Domestic gas production in the EU is falling, and there is increasing reliance on imports from outside the EU. France currently imports gas from Algeria, Russia and Norway, the UK from Qatar and Norway.

In the meantime, thanks to shale gas, the US may well become a LNG exporter, possibly to Asia and the Middle East. This is bound to have a huge impact on international gas flows and, by extension, gas prices, which already look set to continue to rise. The impact of shale gas can be seen in the recent decision to suspend development of the Shtokman field in Russia, which was originally being developed under the assumption that the USA was to become a major gas importer.

But it is one thing finding shale gas, and another generating commercially viable production from it. For example, geological factors may make shale gas in the EU more expensive to produce, and there are also infrastructure challenges. Other challenges include greater urbanisation in the EU, different land ownership rights from those in the US and lack of local expertise.

Pipeline infrastructure is variable across the EU, and less well developed in eastern Europe. Significant investment may be required in some countries to upgrade the network to cope with increased gas flows. Investment has already started in Poland to expand its domestic and transit infrastructure with EU support. In September 2011, a gas interconnector was opened between Poland and the Czech Republic, which could form part of an enhanced north-south gas corridor which may be required if Poland’s shale gas production should support exports.

Another concern is the limited supply of suitable drilling rigs in the EU. Many new drilling rigs will either have to be built or brought into Europe to drill the types and numbers of wells that commercial-scale shale gas production would require. However, commentators make the point that where there is demand, supply will follow, and this was certainly the experience in the US.

EU energy policyOne of the main focuses of EU energy policy is diversification to secure its energy supply. The 2050 Energy Roadmap published by the European Commission in December 2011 recognises shale gas as an energy source that could potentially lessen the EU’s import dependence and play an important part in the EU’s energy mix going forward.

The Commission has confirmed that gas has a key role to play in the transition to decarbonisation. In March 2012 natural gas was designated a low-carbon technology for receiving funding from the

Horizon 2020 programme, which will provide up to € 80 billion of funding for research and development.

The EU has committed itself to reducing greenhouse gas emissions to 80 - 95% by 2050 (compared to 1990 levels), and the Commission’s own projections show that current energy policies will deliver barely half of that target. Policy and investment decisions taken in the next 5 - 10 years are therefore critical to whether or not this can be achieved.

Proponents of shale gas argue that it has an important contribution to make in the battle to reduce CO2 emissions. Analysts believe that the significant shale gas reserves discovered in China could allow it to replace coal in power generation and industry, resulting in reduced CO2 emissions. In addition, the development of carbon capture and storage technology, although not yet commercially viable, has been proposed as a way of minimising CO2 emissions from shale gas fired power plants.

Conclusion Whilst energy prices and security of supply continue to dominate the headlines, the reality is that shale gas cannot be ignored without potentially damaging consequences to European energy security and prosperity. Whilst the EU hesitates, there is a risk that it could be left behind as other countries, not least China and Australia press ahead.

There is no doubt that shale gas will influence the global energy market, which in turn will impact on the EU. Outside the EU, China is very keen to take advantage of its large shale gas resources. It is offering subsidies to Chinese operators, introducing a gas floor price, encouraging Chinese companies to acquire stakes in US shale gas operators to bring the necessary technology to China and setting up joint ventures with Western companies to exploit reserves.

Whether the EU will in fact be left behind depends on how it engages in the debate. Member States need to allow shale gas exploration to advance, at least to understand the scale of the opportunity in the EU. There must be a concern that unless the EU is able to provide a favourable environment (including regulatory stability) for that exploration, US companies, which have the

0

5

25

75

95

100

Discover More F-J 140x230mm ad Oilfield Tech REV 02-24-12

Monday, February 27, 2012 9:40:41 AM

Fugro-Jason_Layout.indd 1 06/09/2012 15:52

technical expertise to help will look to easier targets, such as China and Australia.

Public acceptance is of course key. The Executive Director of the International Energy Association has recently commented that the US shale gas revolution can be expanded globally, but only if gas producers can convince the public as well as governments that extraction can be done safely and in an environmentally friendly way. Only then can there be any hope of replicating across the EU the job-creating, economy transforming effect which shale gas has had in the US. O T

WHAT YOU SEE IS WHAT YOU GET

Oilfield Technology Correspondent Gordon Cope explains how advances in simulation and visualisation are helping the oil and gas industry target subsalt and unconventional plays.

O ver the last decade, the oil and gas industry has undergone a revolution. Gone are the days when companies could pursue conventional plays such as

sandstone reservoirs and carbonate reefs; explorers now scour the earth for tight reservoirs such as shale gas and oil and peer beneath massive layers of salt for hidden crude. Their search has led to the discovery of billions of bbls of new crude reserves and hundreds of trillions of ft3 of gas. At the very foundation of their success are advances in two extremely important tools of exploration and production: visualisation and simulation.

VisualisationRecent advances in visualisation (Table 1) have occurred across a wide spectrum. According to Stephen Warner, Schlumberger,

tended to focus visualisation around a single reservoir, but it is now possible to go way beyond that. Using E&P software such as Petrel™, engineers can start at the regional level and then move

in the wellbore using the Techlog™ wellbore software platform. Working between these scales can give much-needed insight into the basin and the reservoir by accessing hundreds of gigabytes of information from thousands of wells at the desktop. To do this, the parallel power of PCs, multiple CPU processing, solid state discs and GPU rendering all have to be leveraged.

The second aspect is integration of disciplines. Traditionally, it was the integration of geophysics and geology, and more recently reservoir modelling and simulation that was focused upon. However, when it comes to unconventional and other more complex structural and stratigraphic plays, the speciality disciplines and analyses have to be brought in; for instance, geomechanics and basin modelling are very important to shale and structural reconstruction in pre-salt plays. This allows hydrocarbon generation and migration, as well as stresses and strains over time across the entire basin to be understood. All of these disciplines have to be brought together and visualised in a shared earth model to make informed decisions.

The third aspect is performance. Having a static visualisation is not enough. The power of the PC needs to be leveraged and

24

have full advantage taken of its capability to work interactively with the data. Making use of GPUs for advanced blending and multiple CPUs for processing enables advanced visualisation and rapid interaction with the data. This enables geoscientists

development outcomes.The fourth aspect is awareness. This is quite new in the

industry and allows technical professionals to visualise and access information that is not in a project. This is made possible through the use of software such as the Studio™ E&P knowledge environment. The ‘Find’ part of Studio works like an Internet

helps ensure that a project team gets all the relevant information available so that it can be integrated into analyses allowing for improved decision making.

which have the potential for tens of billions bbls of undiscovered

to integrate visualisation and computation. Modern workstations

capabilities. GPUs are also able to both perform computations and produce graphics.

® Geoshell™ technology allowing the interpreter to use incomplete interpretations of geologic features derived from seismic and well data to construct and visualise sealed ‘bodies’ representing

25


®

team members can share them with other disciplines to support

salt bodies to create a sealed structural framework for velocity

to improve the seismic imaging. Asset team members can share them with other disciplines to support and enhance iterative

GeoProbe® GeoShell™ software improves the cycle times of

Visualisation innovations have also allowed a wide array of professionals to effectively interact on a project. As

‘let’s create a visual environment that allows all the different disciplines to come together so that they can better understand

to the simulation. It is critically important. That is why there is such a focus on bringing the disciplines together with the best science

Simulation

has been the inclusion of optimisation to aid reservoir history

are trying to verify your reservoir model by matching it to past and current production and then predicting how the reservoir will act in the future. This helps you to pick the best rates of production and

often taking several weeks to choose reasonable assumptions

engineer must weigh time and

environment of uncertainty around these predictions.

Oil companies were aware that simulation models gave a ‘best guess’ solution with an

tended to raise scepticism regarding their value. They wanted a way of reducing risk and uncertainty when

academic research at petroleum engineering and mathematics

and service companies developed probability optimisation tools

injection rates and other variables. Objective functions can then

Schlumberger offers a reservoir simulator software that was initially developed in collaboration with Chevron and more recently

™in which the ability to simulate high resolution models of the

or stratigraphy and accurately modelling near wellbore effects in

makes clear: it is critical to run these models rapidly in order to

time new information becomes available and not just when the reservoir stops performing as predicted. The performance

advantage of additional processing power. This new simulator makes use of new computer hardware enabling improvements in

simulation software enables the user to simulate the complete

and allowing multiple models to be coupled together. These

logic to simulate multiple reservoir management scenarios. It can

2 processes.

Table 1. Definitions

Visualisation

professionals can even immerse themselves into the environment in order to manipulate and interpret

efficient way of producing them worked out.

Simulation Simulation software is used to help decide the best placement of wells and surface production facilities once a petroleum deposit has been discovered. Most reservoir simulation modelling tools work in the

and geophysicists use to create a static reservoir model of the field. The production engineer then uses

until he achieves a reasonable match.

Optimisation

rolling of a marble on an uneven surface to find the nearest low point. More powerful techniques are the

of each generation are used to ‘father’ subsequent generations. The best of these ‘children’ then in turn


simulate multiple porosities in unconventional plays. The current standard method for analysing fractured reservoirs is known as dual porosity, which takes natural fracturing and induced hydraulic fracturing into account in the simulation as though it were a different rock type to shale. There are, however, many different rock types found in unconventional gas and oil plays and multiple porosities;

mechanisms accurately. There are now technologies that can model up to 10 porosity types. The value to the operator is that

means it is much easier to make the right fracs at the right spacing.

A third trend is the increased capability to model the mixing

offshore operators use to lower capital costs is to tie in several separate reservoirs into one platform. However, as Crockett points out, “the oil and gas in different reservoirs can have differing amounts of various chemical compounds present, like methane, ethane and CO2

Classic multi-reservoir modelling uses almost identical

behaviour often deviates from the actual behaviour. Large deviations can mean that model predictions may not accurately

Traditionally, coupled modelling of reservoirs with surface facilities has relied on an iterative process where the simulation engineer conducts numerous runs, transferring data between the reservoir and surface facility models in a loosely coupled way. Systems such as Nexus allow for internal coupling of the reservoir

mixing and multi-porosity modelling features.

is the ability to better represent the subsurface geology and

structure, including faults, whilst providing more representative modelling of reservoir development and a more accurate picture

improved production forecasts, the ability to identify bypassed

water or gas breakthroughs, reduced uncertainty, greater sweep

that there is no value to extending a horizontal wellbore beyond a certain point, as you end up with production only at the heel and

can be interpreted to determine where to stop, based on the

The futureMary Cole predicts that in the future, the industry is likely to see an increased use of mobile devices accessing data remotely. The

on a mobile device, but future developments will allow for more

Steven Warner looks to the development of immersive visualisation where menus are removed and users interact directly with the data. One of the goals in immersive visualisation is to

looking for the ability to reduce or even remove repetitive mouse clicks. Just as importantly, immersive visualisation will provide a more intuitive way of working to allow greater creativity in tackling the increasingly challenging reservoirs that will be explored and developed going forward.

With the advent of a next generation reservoir simulator that

where the simulator can run in the background will begin to be seen. This will allow for reservoir engineers and production engineers to make improved decisions and counter performance issues in near real time, helping manage reservoirs to reduce production losses and increase overall recovery. Work is going on to enable extensibility for third parties and clients in order to expand the capabilities of software such as INTERSECT, allowing for proprietary or specialised simulator functionality.

In the long term, Halliburton foresees the integration of the

to simulation and economics. “We have moved a great deal in that direction; 20 years ago, the geosciences threw their earth model over a brick wall to the simulation engineer, who then did

says Crockett. “About a decade ago, companies began to appoint asset teams where the geosciences were in touch with the

“We are close to integration of the various disciplines, but not quite there. There is still a loose feedback between the earth model and the simulation. One of the challenges is that it still takes a long time for a simulation model to run on a desktop.

an overnight run, then analyse the result the next morning. We are working with multi-core processors and investigating GPU computing to decrease simulation run times from 12 hours to 2 - 3 hours, so that the simulation user can make and analyse multiple runs and also get feedback from an earth modeller

O T

Figure 1. Landmark’s GeoShell™ Technology representing complex salt-bodies in the Mississippi Canyon area of the deepwater Gulf of Mexico. Data provided and owned by TGS-NOPEC Geophysical Company.

Maximized recovery means maximized return on investment. And FMC’s subsea separation technologies, combined with water injection and boosting, represent a whole new way to maximize the reserves you can economically recover across a wide range of challenging conditions. So stop leaving all that oil in the ground. Discover the results only subsea processing can deliver. Learn more at www.MaximizeRecovery.com

TWO AWARDSfor subsea separation:

MARLIM & PAZFLOR

SEEING

THROUGH

SOFTWARE

30

GEFEI LIU AND CISSY ZHAO, PEGASUS VERTEX INC., USA, EXPLAIN HOW THE USE OF ADVANCED SOFTWARE CAN HELP ENGINEERS ‘SEE’ UNDERGROUND BY PREDICTING SUBSURFACE CONDITIONS.

Oil well drilling is one of the most fascinating engineering collaborations, with drill bits, tubulars, motors, mud and many other

components all playing a part. Most impressively, all the drilling processes take place under the ground, probably tens of thousands of feet, maybe even horizontally, away from the rig.

To keep drilling operations under control, many technologies have been developed that incorporate electronic, magnetic and radiation-based methods in order to understand the formation and downhole conditions.

the water. Drillers have some limited information, which includes hook load, surface torque, etc. However, they do not know the axial force along the string, whether the pipe is buckled, or if the torque on pipe connections exceeds the makeup limit. Experienced drillers may be able to sense downhole problems through the combination of brake vibration, noise or pump pressure, etc. But what is needed is something to bridge the gap between what can and cannot be seen. Drilling software serves as this bridge!

software has become an indispensable engineering tool in the design phase, real time monitoring and post job analysis. Using known operation parameters

such as ROP, RMP, mud weight, drilling string

software can predict pipe buckling, hook load, surface torque and casing wear accumulated in the previous set casing.

For drilling engineers, software is beginning to act as another set of eyes. Equipped with software, it is possible to not only understand what can be seen (why there is a certain hook load, surface torque, etc.), but it is also possible to see events that would have otherwise been invisible.

Torque and dragDrilling engineers use torque and drag software mainly for three reasons:

Design operation.

Onsite job monitoring.

Post-job analysis.

No matter what is on a user’s mind, they all want to trouble-shoot potential problems with ease.

The easiest way of presenting information is to use graphs. Whatever can be expressed in numbers may be expressed by charts, or in many cases, by 3D visualisation. This is especially true for drilling professionals as the operation occurs downhole.

Drillpipe buckling, tension and torsional failures

the drilling section. This educational graph is an

31


artistic way of showing potential problems. In daily life and work, one faces numbers and tables; one of the most effective ways to describe, explore and gain insight into the numbers is to picture them.

Drilling software has come to play an important role in bridging the gap between illustration and reality. For example, the buckled sections of a drill string can be best explained in Figure 2 where the red colour stands for the helically buckled section, while the yellow represents sinusoidal buckling.

The side force is closely related to the well trajectory including dogleg severity. Figure 3 demonstrates a side force distribution along the pipe. This is also the source of casing wear to be discussed later in this article.

Casing running and surge pressureNew drilling and completion technologies such as horizontal wells, extended reach drilling, slim holes, deepwater offshore drilling, etc., have a tremendous economic impact in our industry, but also challenge many aspects of drilling and completion operations.

For example, surge and swab pressures are normally high

and liners. Running liners in subsea casing strings with very tight tolerance can cause extremely high surge pressures. Closed end

to reduce the surge pressure against formation. However, engineers are still facing the same challenges of determining the surge and swab pressure for these wells using new technology.

The accurate prediction of surge and swab pressures is of great importance in wells where pressure must be maintained within narrow limits to ensure trouble-free drilling and completion operations.

One way to see the impacts of various operation parameters is by using a sensitivity study. Figure 4 shows the surge pressure for various running speeds. It provides allowable tripping speed to avoid formation breakdown.

Cementing job simulationA successful cementing job is one of the most important factors in the productive life of any well. Many software packages simulate the effects of various design parameters, and identify and correct potential problems before a job is actually performed. These models normally address a wide range of concerns, including free-fall, ECD and pump pressure

Centraliser placementA centraliser is a mechanical device used to position casing concentrically in the wellbore in order to provide a constant annular space around the casing. Proper placement of casing centralisers is one of the most important factors in obtaining a good primary cement job.

Engineers’ concerns are: can we achieve the required standoff? Are we using too many unnecessary centralisers? Do

the casing running?Centraliser placement software helps determine the

optimum number and placement of centralisers, and calculates the minimum casing standoff for both bow spring and rigid

Figure 1. Drilling problems.

Figure 2. Buckling.

Figure 3. Side force for a directional well.

Figure 4. Surge pressure prediction.

33OILFIELD TECHNOLOGY

September 2012

body types. The software not only models the engineering behind the casing sagging in a directional well and how wellbore trajectories, cementing slurry density, pipe weight, etc., impact the placement of centralisers, but also models how the presence of centralisers impact torque and drag when running the casing.

This kind of modelling is essential for operators and service companies to achieve their engineering goals with optimal costs and a good cementing job.

Tubing movementMost wells are completed and treated through a system of tubing and packers. Changes in temperature and pressure inside or outside the tubing will either cause a tubing length change (free motion condition) or induce forces in the tubing and on the packer (limited motion or anchored condition).

overpull available in tubing and where extreme pressure and temperature variations are not likely to occur, we normally can rely on past experience or general rules of thumb to avoid trouble; however, in deep wells, conditions become more critical and tubing and packer failures are more common.

Typical tubing movement software performs the length change, force distribution calculation and checks the tubing integrity for various conditions; the purpose of this is to provide the industry with easy-to-use tools to avoid tubing/packer failures.

Casing wear predictionIn the drilling phase, casing is the most costly part. On top of expensive casing material and costs likely to be encountered in cutting, pulling and replacing a worn or damaged string, casing wear creates more serious problems for operators due to its potential for catastrophic incidents such as oil spills, blow outs or the loss of a well.

Casing wear is caused by drillpipe movement inside the cased hole, especially the tool joint rotation against the casing interior. Since no truly vertical well exists (the whirring action of the bit always creates a micro-helical shape of well path), contact between drillpipe and its tool joint with casing ID is unavoidable.

The gravitational force acting on the drillpipe will always try to pull the pipe to the lower side of the wellbore, while the axial tension on the drillpipe, in a build-up section, pushes the pipe to touch the upper side of the wellbore.

Depending on the pipe weight, dogleg severity and axial force along the pipe, the drillpipe either touches the upper or lower side of the wellbore. Modelling can determine the direction and magnitude of side force on the wellbore. In this way, one can know if the drillpipe is touching the upper or lower side of the cased hole.

Under this side force, the tool joint of drillpipe is rotating against the casing inside, gradually removing steel from the casing wall and forming a crescent-shaped wear on the casing, as shown in Figure 9.

and drag along the drill pipe during drilling operations. From the torque and drag analysis, side force can be determined. For every incremental drilling interval, the amount of energy transferred from drillpipe to casing is calculated through

wear depth are obtained. Then the burst and collapse strength of the worn casing can be assessed.

Figure 5. Cementing job simulation.

Figure 6. Centraliser placement.

Figure 7. Tubing movement.

Figure 8. Side force distribution.


As one can imagine, casing wear deepens as the well is

along the previously set casing.Generally speaking, high dogleg will create high side force

the shape of dogleg severity. Higher RPM and lower ROP make more rotation time between tool joint and casing and will cause aggressive wear. Using graphics and 3D visualisation makes understanding and prediction easier.

Drilling mud reportingHistorically, mud engineers used paper forms to record mud properties every morning. With the introduction of Excel and other similar software, people began to take advantage

this approach is probably the organisation of numeric daily reports and generation of end-of-well recaps. Not to mention well comparison, which requires obtaining histories of drilling activities over periods of time of multiple wells in various geographical areas.

The modern approach in mud reporting is to use software with the database backbone to perform solids analysis and hydraulics calculations, as well as keep track of all inventory and costs and quickly generate reports. By looking at the end-of-well

the next well.Mud reporting software can streamline the mud operation

using case studies. Typical mud reporting software not only keeps track of inventories and costs, but also performs hydraulics calculations and creates daily reports at the click of a button. With the help of a database engine as a backbone, this software can handle multiple wells at the same time, so that well comparison becomes an easy routine.

ConclusionDrilling software is such an enabling technology that it can elevate entry-level engineers and amplify the experience of seasoned ones.

These software models can also serve as a valuable educational tool for new engineers without much experience in

allows engineers to identify potential trouble spots. If problems do arise, the software can help solve them before they get out of hand.

During the oil well drilling phase, cost overruns can easily occur due to unexpected issues related to pipe failure (torque and drag), loss of circulation (hydraulics), etc. These issues result in non-productive time (NPT), which is much more detrimental than the cost of a certain failed part. Considering the potential cost overruns, it is reported that oil companies

unexpected costs.Software makes drilling design and analysis more

transparent and visible to everyone. Through being able to see better and deeper, one can reduce both risks and costs whilst increasing success rates. O T

Figure 9. Casing wear mechanism.

Figure 10. Wear profile.

Figure 11. Casing wear animation (CWPRO output).

Figure 12. Final 3D wear profile.

SETTING UP A SECURE

CONNECTION

Directional wells, as a percentage of total wells drilled, continue to grow both onshore and offshore on a global basis. Offshore water depths have increased to over 10 000 ft, well depths have

exceeded 34 000 ft, and extended reach targets have pushed out to over 40 000 ft. Offshore extended reach drilling (ERD) is primarily driven by the presence of large and extended hydrocarbon reservoirs, relative poor productivity of vertical wells and the cost savings provided by limiting the number of platforms or by drilling offshore targets from land based rigs. The length of extended reach wells has been increased over the course of time. New world records for both total measured depth and total horizontal departure continue to be set. These wells are now pushing the limits of what can be achieved with today’s technologies.

One operator recently drilled multiple ultra-extended reach wells as it progressed towards the drilling of a record ERD well, at a length of over 40 000 ft. Such ERD requires a drill string that can provide the high torsional and tension capacity to overcome the high downhole drag and rotating friction that results from these extended reach sections. A drill string that can provide an optimum amount of hydraulic horsepower to remove the cuttings from the well and keep the hole clean is essential to achieve these ERD well depths.

Jim Brock, Michael Jellison and Andrei Muradov, NOV Grant Prideco, USA,

explain how the strains of extended reach drilling are driving a demand

for improvements in drill pipe connection design.

35


Designed for ERD, 5 7/8 in. drill pipe and second-generation proprietary rotary-shouldered connections, eXtreme® Torque (XT®), has helped operators push the industry’s drilling envelope by successfully drilling world class ultra-extended reach wells, including several world records. However, to reach new targets, operators are now demanding even more drill string performance.

In the US, shale formations have become an increasingly important source of natural gas for the last decade. Now the potential of shale gas and oil has gained interest in Canada, Europe, Asia and other parts of the world. Shale plays have become commercially viable due to several enabling technologies such as horizontal drilling and multi-stage hydraulic fracturing. Most wells are horizontal with long departures. Typical wells in the US Bakken Shale are 17 000 ft measured depth, 11 000 ft total vertical depth with a 6000 ft horizontal departure. Drilling these wells puts huge demands on the drill pipe and rotary-shoulder connections.

The second-generation rotary-shouldered connection has been one of the key technologies that has resulted in the success of shale drilling programmes by providing increased drilling torque, streamline connection dimensions and hydraulic performance necessary to drill extended horizontal hole sections. As horizontal hole sections have increased in length, so has the demand for a drill string with higher torsional capacity.

Drill string requirements

on drill pipe and rotary-shouldered connections. Long horizontal sections and corresponding high friction forces require high torsional strength from the drill pipe and rotary-shoulder

depth.Optimised hydraulic performance of the drill string is

also necessary to maintain good hole cleaning and cuttings removal in the extended horizontal sections. The use of proprietary rotary-shouldered connections with optimised

rotary-shouldered connections can also facilitate the use of a larger drill pipe than would be possible with API NC or FH connections. For example, 4 in. drill pipe with proprietary rotary-shouldered connections can replace 3 1/2 inch drill pipe API NC of FH connections providing improved hydraulics and increased drill string stiffness for the same casing size/bit

High-torque rotary-shouldered connections Rotary-shouldered connections incorporate an advanced, high-performance tool joint design that provides approximately 70% more torque capacity than standard API connections. The double-shouldered design is optimised for each drill pipe size. The connection’s increased torsional strength allows for the use of

with a smaller OD and larger ID compared to standard API

Like normal API rotary connections, rotary-shouldered connections spin-up freely from the stab-in to hand-tight position. In the hand-tight position the primary external shoulder makes contact. As the connection is made-up from the hand-tight to power-tight position, the box counterbore compresses and the pin base elongates elastically until the secondary torque stop engages. The secondary torque shoulder provides increased torsional capacity compared to a standard API rotary shoulder connection.

Just as for API rotary connections, the external (primary) shoulder is the pressure seal for the connection. Since the secondary shoulder functions solely as a torque stop and not as a pressure seal, minor damage to the secondary shoulder can be tolerated without adversely affecting connection performance. Any protruding metal caused by damage of the secondary shoulder that could impede contact between the shoulder

thread protectors when the pipe is racked back in the derrick is not required or recommended. Running and handling procedures of drill pipe with proprietary connections is straightforward and similar to drill pipe API rotary connections and can be handled by rig crews with minimal instruction.

advantages:

High torsional strength: the second-generation rotary-shouldered connection provides significantly higher torsional capacity than standard API connections.

Streamlined profile: increased torsional strength allows for the use of a streamline tool joint that is suitable for the pipe’s torsional strength. The second-generation rotary-shouldered connections can be configured with a smaller OD and larger ID compared to standard API connections without sacrificing torsional capacity. This can allow a larger drill pipe size to be used for improved hydraulic performance.

True flush inside-diameter: there is no gap or change in inside diameter from the box to the pin, resulting in a recess-free inside bore. This provides a smooth flow with less turbulence. It also eliminates the recess in other connections where cement and solids can be trapped.

Increased wear tolerance: because of the increased torsional capacity, the second-generation rotary-shouldered connection extends the service life of the joint by tolerating more OD wear before the drill pipe must be downgraded below premium class.

Figure 1. The fatigue resistant thread form compared to API NC thread form.

Deep Sea – High TechProducing large-diameter pipes for a deep sea environment is now more than ever a task that carries great responsibility and requires a high degree of sensitivity. EUROPIPE combines decades of experience with technological leadership. Our pipes withstand even the highest pressure levels and the most aggressive media.

EUROPIPE. Taking the challenge.

EUROPIPE GmbH · +49 208 9760 · An enterprise of the Dillinger Hütte and Salzgitter Mannesmann groups www.europipe.com


New connection improvements Utilising the technology that has been available since the original development of the second-generation rotary-shouldered connection, the new uLtimate™ series incorporates higher strength tool joints, an improved, fatigue resistant thread form and cold-rolled threads. The original second-generation rotary-shouldered connection tool joints

(SMYS) material. The tool joint material strength requirement was increased to 130 000 psi SMYS for the new series. The new series connections provide over 26% additional torque capacity in comparison to the original second-generation rotary-shouldered connection. Higher operational torque capacity is achieved by a combination of the higher strength material and by making-up the connection to a higher stress level. For a given steel alloy and microstructure, increasing yield strength typically results in a trade-off of a decrease in toughness. All other parameters remaining constant, decreases in material toughness and increases in the static stress level from the increased makeup torque, normally reduce the fatigue life of the connection.

To offset the possible reduction in fatigue resistance resulting from the increased tool joint yield strength and increased makeup torque, a more fatigue resistant thread form was incorporated into the new design. Stress concentrations, or stress risers, are areas on an object with increased localised stress. Stress concentrations can be sites for crack initiation if the concentrated stress exceeds the material’s theoretical cohesive strength. Stress concentrations occur at discontinuities within the material such as cracks, dislocations or metallic inclusions. Geometric discontinuities, such as sharp corners, holes, and changes in the cross-sectional area of the object, also cause an object to experience a localised stress increase. Stress concentrations occur in threaded connections at the sharp

roots. An enlarged root radius was incorporated into the thread form, as shown in Figure 1, to minimise these stress concentrations. Fatigue cracks generally start at stress risers, so removing these sharp radius corners increases the fatigue strength.

In addition to the fatigue resistant thread form, fatigue life

areas. Cold rolling is a form of work hardening, also known as strain hardening or cold working, which strengthens metal

Figure 2. The groove behind the pin shoulder identifies the uXT™ uLtimate™ Series connections.

by compressive plastic deformation. This strengthening increases resistance to crack initiation and crack propagation, which increases fatigue resistance.

Comparative full-scale fatigue testing, described in

resistance thread form and cold rolling the threads, not only prevents a reduction in fatigue life from the use of stronger material and higher makeup torque, but increases fatigue life above that of the original second-generation rotary-shouldered connection.

The new series of connections are fully interchangeable with the existing second-generation rotary-shouldered connections allowing the current inventory of tools, accessories and running and handling equipment to be utilised.

Improvements, such as higher material yield strength, fatigue resistant thread form and cold-rolled threads, cannot

connections and to differentiate them from the original second-generation rotary-shouldered connections a 1/8 in.

OD behind the pin external shoulder, as shown in Figure 2.

machined to the minimum tool joint diameter for premium class providing a visual indication of remaining allowable tool joint wear.

Validation testing The performance of the new series of connections was validated by full-size fatigue tests. A harmonic fatigue test machine was used to compare the relative fatigue resistance of the new series connections to the original second-generation rotary-shouldered connections (baseline). Connection specimens were machined and broken-in per standard procedures. Four baseline connection specimens for 5 7/8 in. drill pipe were made up to 55 600 - 56 600 ft·lb, 60% of the connection’s torsional strength. Four new series connection specimens for 5 7/8 in. drill pipe were made up to 81 267 to 82 267 ft·lb, 70% of the connection’s torsional strength plus an additional 15% to adjust for the thread compound’s friction factor (1.15). A bending moment of 424 000 in·lb was applied to all specimens. All samples were cycled to failure. Eliminating one outlier, the baseline specimens failed after an average of 571 276 cycles. The new series specimens failed after an average of 982 300 cycles; a 72% improvement. As expected, all specimens failed at the last engaged pin or box thread of the connection.

Summary Validated with physical testing, this new series of connections for 5 7/8 in. drill pipe displayed 45% more torque than the original second-generation rotary-shouldered connection

connections will help world class extended reach wells to now push out to even greater distances. The connections are also well suited for rigorous applications such as the current shale plays that require both high torque and high resistance to back-off. Both connections are fully interchangeable with existing inventories of accessories, tools and handling equipment. O T

T oo many engineers perceive primary cementing

attention to its critical importance. However, recent unfortunate

Common mistakes

engineers make when evaluating casing accessories:

Casing running vs. cementing

is an issue.

Standoff requirements

Technical data and testing methods

manufacturer.

INTELLIGENT

Alfredo Sanchez, Top-Co, USA, warns that failure to appreciate the importance of ‘dumb iron’ can lead to costly delays and even more serious consequences; both of which can be mitigated through the adoption of an intelligent engineering approach.

IRON

39


incomplete.

Computer simulations

As in any other computer simulation, the

Yet, frequently only the summary section

were set up, the assumptions that were

increases the risk of errors of omission

Price based purchasing

Continuous improvement

investment.

Operator-manufacturer relationship

minute communications are generally the norm.

Figure 1. Axial load analysis.

Figure 3. Polymer centralisers with reduced coefficient of friction and drag-reducing geometry.

Figure 2. Onset and development of buckling.


September 2012

Recent incidents

certainty how relevant each factor was, the fact that casing

Commission on the BP

Bureau of Ocean Energy

critical role this equipment plays.

illustrating the importance of primary cementing equipment,

Drilling challenges in today’s complex wells

challenges.

Buckling

Figure 4. Effect of tortuosity on standoff.

Figure 5. Float collar design.


portion of the string, particularly those in the lateral section. This

smaller centralisers in the lateral can potentially accomplish the

Reducing drag

casing is running in.

the tortuosity of the well. However, letting

wall. At the same time, some researchers

Tortuosity

performance of the centralisation programme

Even if working with an actual survey, there

manufacturer.

LCMThe use of lost circulation material, LCM, in

equipment as it may clog up the valve or prevent

off the valve.

Fit-for-purpose methodology

Case study 1: Barnett Shale

/

Figure 6. Actual casing running friction factors.

Figure 7. Typical torque behaviour in horizontal well cementing.

Every pipeline project brings its own, unique set of challenges. But the need for equipment you can depend on never changes. At CRC-Evans, we have built one of the most complete lines of high-performance pipeline construction equipment—from pipe bending to fi eld joint coating, and everything in between. So no matter what your project demands, you can be confi dent that you have the tools to complete the task.

At CRC-Evans, our total solution approach is unlike any other in the industry. Explore our complete portfolio of services at www.crc-evans.com.

A full line of confi dence. From a single source.

Miles of pipelines to date.

Supplier for every step of the way.


against the casing coupling as the casing was run.

Case study 2: Eagle Ford

increase in torque requirements as the heavier cement slurries

/ /

throughout the lateral section using polymer centralisers. The

Figure 8. State-of-the art flow loop testing facility.

Current and future laboratory testing

Closing comments

awareness of the increasing importance that equipment

equipment as well. O T

References

BP.

6.

7.

Eldar Larsen and Paul Hocking, BP Norge AS, Norway, explore the development of next-generation digital

oilfields in the North Sea.

B

GENERATION

THE NEXT

45


The company, on behalf of its partners, operates three field centres; the Valhall hub (consisting of the Valhall and Hod fields), the Ula hub (consisting of the Ula and Tambar fields) and the new Skarv field.

A digital infrastructure The installation of low latency high bandwidth fibre optic based telecommunications in 1999 underpinned the successful implementation of the Field of the Future technologies in the Ula and Valhall brownfield hubs.

The new Valhall Process Hotel Platform development includes the provision of a 294 km high-voltage direct current power (HVDC) cable, delivering 78 MW of power to the Valhall field. The HVDC cable was augmented to include its own fibre optic communications cable, adding a new dimension to the robustness of the fibre optic communications to the Valhall field, which opened up the potential for remote control of the field from shore.

Fibre optic communications were successfully implemented in the southern part of the North Sea and convinced the Skarv partners that it was important to provide similar wide bandwidth low latency communications to the field.

New greenfield facilities challenges

Valhall re-development project (VRD)In late 2004, due to subsidence at the seabed of the original processing facilities leading to subsequent reduction in the air gap between the bottom of the deck and the sea, work to commence the front end engineering of a new production and hotel platform for the Valhall field was sanctioned. This became known as the Valhall Re-development Project. With a life expectancy of 2050 and beyond, the project was considered the best alternative to resolving the subsidence problem, rather than to jack-up the old facilities. The project was implemented as a Field of the Future facility, making use of all the capabilities Figure 1. Valhall field centre with new process hotel platform to the

right.

Figure 2. Valhall production onshore control room.

OT_September2012_45-48.indd 46 07/09/2012 08:54

Skarv field development

Remote control

World’s Most Trusted Hardbanding

Duraband®NC100% REBUILDABLE

Decreases Downtime & Increases Productivity!

Unmatched ReliabilityExcellent Casing & Tool Joint ProtectionNo need to remove existing hardbandingRe-application costs up to 75% lower than competitive productsCuts NPT & Maintenance CyclesOnly Fearnley Procter NS-1™

over other existing hardbands

Duraband® NC Hardbanding

www.hardbandingsolutions.com

Uses: New Application and Re-Application to

Tool Joints

PERFECT FOR ALL HARDBANDING CONDITIONS

Highly D Sour Gas Well G T Wells

Available from most drill pipe manufacturers and rental companies and supported by nearly

Skarv’s ACE concept

Remote performance monitoring (RPM)

Lessons learned and challenges for the future

Conclusion

O T

Figure 3. Skarv FPSO.

www.energyg loba l . com/sec tors

READ about the latest developments in explorationon Energy Global.

Coring in high pressure, high temperature (HPHT) conditions through extremely abrasive rock formations challenges the reliability and technical capacity of conventional coring tools.

The process of coring under these conditions can generate excessive vibrations that can damage the coring bottom hole assembly (BHA) and compromise coring performance. One effect of vibration is jamming of the core in the core barrel. The core sample becomes stuck, reducing the amount of core recovered and requiring an unplanned trip out of hole. This is especially likely in tight multi-layer formations, where

wear on the tools, making it harder to successfully complete long coring intervals.

Ludovic Delmar, Halliburton, Belgium, takes a look at recent advances in the process of coring in HPHT environments.

49


these types of extreme conditions is the Rockstrong™ coring system. It incorporates anti-jamming features that represent a departure from conventional core barrel assemblies that rely upon an adjustable swivel that interfaces with a safety joint pin thread. This conventional design exposes the inner core barrel and core material to the same vibrations as experienced by the outer barrel, potentially leading to damage or jamming of the core material. In contrast, the swivel assembly shown in Figure 1 is designed to sustain much higher stress and vibration levels. The system incorporates a shaft that is independent of the outer barrel and isolated from vibrations. Pre-loading of the adjustment thread provides a higher resistance to fatigue while a spring dampening feature helps mitigate vibration transmitted to the inner assembly and core.

quality core samples whilst withstanding very high vibrations associated with ultra-hard and abrasive rock.

Preventing a jamJamming occurs when the core becomes stuck in the inner tube. Vibration of the coring BHA can create fractures in the core, and the fractured rock is likely to jam in the inner tube.

be tripped prematurely to surface to recover the partial core. The coring assembly must be redressed

objective. This can take up to 24 hours of rig time and would be costly on any operation, but especially so in HPHT and deepwater wells.

This new system has been designed to mitigate jamming of the core in the inner barrel. The spring dampening spacer component acts to absorb axial vibrations that cause jamming along the inner assembly. The shaft incorporates a pre-loaded double bearing system to hold the inner barrel in the most movement-free position possible, allowing the core to enter into a very stable inner barrel system.

Integrated performance factors

Coreheads (core bits)The new coring system can use any type of corehead (core bit). In the hardest, most abrasive formations, the system employs the latest generation diamond impregnated coreheads, which have demonstrated a proven ability to achieve fast penetration rates and long life in extreme conditions. These coreheads perform with a four-fold improved rate of penetration (ROP) and a life span 10 times longer than that of their predecessors. The increased longevity enables the running of longer core barrels and recovery of more core in a single run.

Inner barrel spacing

or aluminium, the thermal expansion of the inner tube differs from the steel outer tube. This difference must be taken into account when adjusting the spacing between the inner and outer

assemblies on surface. Thermal expansion increases with core barrel length. The inner core barrel assembly hangs off of a swivel assembly and should be shorter than the outer barrel/bit by a calculated distance called the spacing or the lead. Operating a longer core barrel at higher temperatures requires increased space-out capacity.

If the spacing is too short, there is a risk that the inner assembly will engage with the outer assembly. This would be detrimental to core quality as the inner assembly would rotate and transmit torsional force to the core sample. If the spacing is too large, the core will not be guided properly into the inner assembly,

invasion, core washing, or jamming.An additional advantage of this system is that it has

up to four times the space-out capacity of conventional coring assemblies. The extra spacing adjustment capacity of the swivel allows it to accommodate longer core barrels in higher temperature wells. As a further protection against the effects of high temperature, there are no rubber seals, which could degrade and deform after extended exposure.

Wide range of core diametersThe RockStrong coring system is also available in larger diameters than other coring tools. For example, the 5 1/2 in. system, which can be run in a 6 in. hole, produces a 3 1/4 in. core – approximately 50% more core material than the standard 2 5/8 in. result. The range of size options is shown in Table 1.

Optimised designBefore a coring tool is assembled and sent to the well, the design is optimised using MaxBHA™ software, a modelling application that allows every aspect of the BHA to be analysed for stress impacts. The

environment. The model accounts for each component in the BHA, so that the RPM range can be improved and stress can be minimised in critical components.

This design/modelling software was initially developed for use with directional drilling and measurement-while-drilling (MWD) tools. It has now been expanded for coring systems and reamers.

Based on an advanced understanding of BHA and drillstring dynamics, this enhanced capability enables the distance from the bit to be measured precisely and models maximum and minimum vibration levels to

achieve optimum coring performance in extreme conditions.The modelling process is based on both static and dynamic

parameters. The dynamic modelling focuses on whirl effects and calculates the critical rotary speeds for the BHA. Running at a critical rotary speed increases the risk of high vibrations that lead to tool failure. The model demonstrates these effects and its accuracy has helped reform certain accepted drilling practices that were increasing the risk of vibration-induced damage.

For example, one study of MaxBHA software performance tested the accuracy of the model against data provided by an MWD vibration sensor, as noted by David Chen.1 The rotary

Figure 1. RockStrong coring system.

PROVEN EXPERIENCE. TRUSTED RESULTS.WWW.CUDD.COM

SIMPLE TO COMPLEX,

WE DELIVER.From a simple cleanout to a complex well completion, Cudd Energy Services (CES) delivers an integrated portfolio of services to help enhance production.

Regardless of the complexity, our experienced professionals create a proven well plan to deliver on

We partner with companies who share our commitment to operational excellence to ensure the safety of site personnel, the community and the environment. With

return on your investment.

To learn more about our comprehensive portfolio of services, visit us at www.cudd.com today.

speed was varied to either approach or depart from critical RPM values. The model correlated well with the downhole sensor, but the most interesting result was the observation that reducing rotary speed did not consistently reduce vibration intensity. In fact, at certain critical RPM points, an increase in rotary speed accomplished two goals: an immediate reduction in vibration and the ability to sustain a good ROP that would not be possible at a lower rotary speed.

operating coring systems that are fully integrated into the BHA. The modelling process ensures that vibration is minimised by analysing the interactions between BHA components as well as their behaviour in a given wellbore environment.

Case histories: a wide range of coring conditions

98% recovery of high quality core in UK North SeaThe 2010 deployment of the new coring system in the UK North Sea was a success. The system cut a total of 501 ft of core in four runs with 98% recovery. These results demonstrate the system’s ability to prevent mechanical damage to the rock

Europe.

100% recovery in the Austin Chalk, TexasThe coring system was used to core 147 ft of the Austin Chalk formation in one planned run. The core bit selected for the run was an 8 ½ in. 6-bladed/13 mm PDC bit. The ROP for the core run was 15.1 feet per hour (ft/hr) on a 147.3 ft run, for a core

Single 60 ft run with 100% recovery in New MexicoA 60 ft core was obtained in the Avalon shale in New Mexico in one run, with an average ROP of 29.3 ft/hr. Both core recovery

run was an 8 1/2 in. x 4 in., 8-bladed/13 mm PDC bit.

Limestone/sandstone formation in Wyoming The 8 1/2 in. x 4 in. FC3643 6-bladed/13 mm PDC core bit was used in conjunction with the coring system to core 100 ft of the Shannon Limestone (a hard sandstone) formation in one run. The ROP for the core run was 13.8 ft/hr. The overall core recovery

792 ft in two runs with 100% recovery in Norway

runs of 442 ft and 350 ft respectively with 100% recovery at a

Very hard, abrasive quartzitic sandstone in AlgeriaIn nine runs, the coring system cut 1030 ft of a very hard and abrasive quartzitic sandstone with a 93% recovery rate.

100% recovery in AustraliaIn a single coring run in Australia, the coring system cut 180 ft of

This single coring run was conducted in a high temperature

Coring in high pressure/high temperature environmentsTechnical limitations of coring equipment and the need to core in increasingly harsh wellbore environments can lead to sharp increases in non-productive time (NPT) related to coring. It became clear that a new coring system, designed to ensure strong performance under severe conditions, was needed. This new coring system is built to minimise the vibration effects

that ensure that the entire BHA is optimised for the particular demands of coring operations. Overall, the coring system demonstrates an improvement over conventional tools and methods. The engineering applied to BHA dynamics helps ensure reliability. O T

References1. Chen, D. Paper #11945 - International Petroleum Technology Conference

- 2008.

Table 1. Range of possible core sizes

System specs (in.) 4 3/4 x 2 5/8 5 1/2 x 3 1/4 6 3/4 x 4

Hole size compatibility (in.) 5 7/8 - 7 6 - 7 8 - 9

Core barrel size (in.) 4 3/4 5 1/2 6 3/4

Core size (in.) 2 5/8 3 1/4 4

www.energyg loba l . com/sec tors

READ about the latest developments in drilling and production on Energy Global.

BLURRING THE BOUNDARIES OF SUBSEA INSULATION

Grethe Hartviksen, Trelleborg Offshore, Norway,

shows us how synthetic rubber-based solutions allow the offshore drilling industry

to operate in increasingly hostile conditions.

The need for high performance, robust and dependable products, has never been greater in the offshore industry, especially as it continues to move towards even more

challenging subsea applications. One area in particular, subsea thermal insulation, has an important role to play in ensuring the smooth running of a facility and as such, is a key element of many

get warmer and water depths get deeper, can the sector keep up? This article aims to show that the answer is ‘yes’ and that synthetic rubber-based solutions not only address these concerns and provide a reliable alternative, but are the only true choice for subsea thermal insulation.

Pushing the limitThe offshore oil and gas industry is notorious for continuously pushing the limits. The exploration of offshore gas/oil has been

wells be drilled deeper and reach further in order to provide more cost-effective and safe well completions. In addition, the need to extract more oil and gas than ever before and exploit ever harsher reservoir environments in new locations around the world, adds a further challenge.

As the water depth becomes greater and the reservoir is located

performance of oil and gas products, which must be able to cope

53


with much higher pressures and temperatures than their shallow reservoir counterparts.

require solutions, which not only offer superior performance, but are more cost-effective, with a greater focus on price and extended lifetime. Not long ago customers required products that could last

When it comes to selecting material to handle these challenges, rubber-based materials are, not surprisingly, becoming a more popular solution within the offshore industry, as rubber is an

temperature range and exceptionally high pressure resistance. It is a

an extremely long lifetime.

Keeping the flowSo, as exploration and drilling go deeper, the need for reliable and

element of deepwater developments. Effective insulation of subsea

processing costs. It also provides optimum defence against wax and hydrate formations.

up at the wellhead and is then transported through a combination of

Insulation is a necessary part of this process in order to avoid

of wax and hydrates occurs when the oil or gas composition is depressurised and exposed to the low seawater temperature at the seabed.

A hydrate is formed when crystalline water is stabilised and light hydrocarbon molecules are captured in the crystal lattice. Hydrates can be formed at high pressures and at temperatures around

would rapidly cool the oil, allowing the creation of hydrate and wax

or totally block oil production to uneconomical levels requiring shutdowns and/or corrective treatments; this will in turn cause unnecessary downtime and cost.

Thermal insulation materials are applied in order to prevent formation of hydrate and wax during a shutdown scenario. During

of the pipe and equipment, so engineers can have time to solve production problems and for methanol or glycol injection.

Sustaining production efficiencyThe increasing challenges faced by the offshore industry have spurred manufacturers to consistently push to develop products that can keep up with the demands of the offshore engineer.

solutions. If they are to stay ahead of the game, manufacturers must

to make existing products work even harder than they already do. As such, some leading manufacturers are reassessing subsea

thermal insulation materials, which have been successfully installed throughout the subsea oil and gas industry for many years, to see how best to enhance their performance in line with these growing demands.

The latest generation of subsea insulation solutions, an example of this dedicated improvement from one leading manufacturer, have a

and logistics, it now also allows for mobile production and can be

A layered solution

ageing and cathodic disbondment.The middle layer has been designed to provide the thermal

insulation protection and various compounds are applicable

k-value of 0.13 W/m2K up to 0.19 W/m2

of the rubber makes this an excellent choice with respect to thermal expansion.

The insulation layer is protected by the outer layer. This is a strong and robust layer that provides excellent seawater and

Figure 1. Trelleborg’s Vikotherm II is applied onto a pipe by the extruding process.

Figure 2. A diagram depicting the various layers of thermal protection for pipes.

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

The is a highly portable unit that features quick set up and occupies less area than conventional drill rigs. It has state-of-the-industry design with remote monitoring of all functions possible through the internet. Although this unit is specially designed for drilling in a confined space, it is a great package for multiple applications. Excellent for horizontal and vertical drilling.

unconventionalwisdom SPE Annual Technical Conference and Exhibition » 8–10 October 2012Henry B. Gonzalez Convention Center » San Antonio, Texas, USA

Register Nowwww.spe.org/atce Society of Petroleum Engineers

mechanical protection and has a successful track record as far back as the early 1970s in the North Sea.

The insulative elastomer coating system used is a development based on ordinary rubber technology and consists of a rubber

property, while maintaining its inherent rubber properties in respect to seawater resistance, pressure resistance, mechanical properties and temperature. By utilising a solid rubber-based coating, these new products have very good thermal insulation properties while providing maximum corrosion protection.

Standing the test of time

remain at the forefront of material development and lies at the heart of material advances and product solutions.

Whether within laboratories, witness testing or ongoing research and development, testing is a major focal point for all leading manufacturers. Given the numerous considerations that need to be made when evaluating the suitability of a material, it is important that a number of testing programmes are undertaken to ensure that the most appropriate material solution is chosen for any given application.

This can include material characterisation where a wide range of laboratory scale testing is undertaken to determine the

material properties and reaction at given simulated application and environmental conditions. Tests, which could include thermal conductivity and density, through to compressive strength and tensile properties, ensure that, in terms of material properties, the most appropriate material is selected for a given temperature and pressure combination.

Extensive test programming has been carried out on these next-generation insulation solutions to prove their integrity for the

as close as possible the in-situ conditions for operations.

are maintenance-free and will normally never be replaced.

ConclusionAs the offshore oil and gas industry continues to push the limits when it comes to demanding subsea applications, the need for reliable and durable solutions that deliver proven performance for critical thermal insulation installations, has never been greater.

a real risk during operation shut downs, solid rubber-based coatings provide a practically incompressible, seawater and impact-resistant solution that has very good thermal insulation properties and also provides maximum corrosion protection. They are designed to last

and will normally never be replaced, giving peace of mind to the offshore industry. O T

SEPTEMBER 2012 ISSUE

http://www.energyglobal.com/magazines/register/oilfield-technology.aspx

Available free of charge to registered readers:

ATTENTIONREGISTERED READERS

ONLINEN W

A WISE INVESTMENTDon McClatchie, Sanjel, Canada, asks why operators should bother taking coiled tubing beyond the basics.

One of the challenges faced by oil and gas companies in their daily operations is the selection of service providers and the appropriate level of technology for the operator’s particular

completion or workover activity. Nowhere is this more apparent than in the world of coiled tubing services. The coiled tubing service itself is often viewed by the oil company as a commodity service and rightly so in many cases. The value for the operator is generated by the selection of tools run on the end of the coil, the

which the intervention is designed. But which tool truly adds value? Which chemical actually shortens the job, makes it more successful or enhances the reservoir? Does the cheapest day rate necessarily equate to the lowest overall job cost? In 75% of jobs, a ‘smarter’ approach will result in a lower overall total cost. Here are a few examples where ‘business as usual’ or a ‘good enough’ approach is actually costing an operator some money or resulting in lost production.

Coiled tubing technology: an overviewSand cleanouts are probably the most common coiled tubing operation and consequently, are given the least amount of thought. The generic approach is to wash down through the tubing, slow down in the casing and periodically pump a slug of gel to sweep

the hole. If the returns start to fall off at surface, pump a bit of nitrogen to reduce the hydrostatics. The industry has been doing this for more than 50 years and it works well on vertical wells. In the 1990s, however, when horizontal wells became more commonplace, operators began to discover that they were not

gel and more frequent wiper trips, but this adds time, cost and increases the fatigue, thus shortening the life of the pipe.

and some of the more technically minded services companies revealed that by applying engineering design to the pump rates,

speeds, it was possible to reduce or eliminate the wiper trips and gel consumption, reducing total time and total cost. The hourly rate for a more technically capable coiled tubing service supplier may be 15% higher, but if the job is carried out 15% faster, the total cost of just the coiled tubing services will be 3 - 5% less and the total workover cost may be 10 - 15% lower. This approach though, does require an engineer to do some job design beforehand using a coiled tubing simulator and also a willingness for the oil company representative on location to deviate from the traditional rules of thumb. There have been a number of SPE papers written to this effect, SPE 112267 and SPE 149051 are two important examples.

57


Choosing the right tool for the job

Figure 3. Impact of drag reducer chemical.

Figure 1. Sand transport research at Oklahoma University.

Figure 2. Impact of pump pressure on CT life.


September 2012

Conclusion

O T

Figure 4. Real time downhole data.

Figure 5. Mechanical damage to pipe.

Kevin McKenna and Ahmed Ouenes, SIGMA3 Integrated Reservoir Solutions, USA, explain how a predictive model can increase IP rates and EURs in shale oil and gas fields.

SWEET SP TS

THEFINDING

60

For several years, discussions about shale oil and gas have, for the most part,

been associated with the US plays. As the search for shale resources accelerates around the world, many oil

companies are taking the opportunity to optimise production

challenges.

be especially sensitive to the local price of natural gas. Relatively small increases in average initial production rates (IPs) and estimated ultimate recovery (EUR) across a portfolio make a material impact on the long term

With the cost of hydraulic fracturing adding upwards of US$ 2.5 million to a single well, the search is on for technologies that truly optimise these key production metrics.

Early in the shale revolution, conventional wisdom held that operators should identify the optimal spacing and

orientation for horizontal wells and develop the

While this approach produces an orderly distribution of well

61


locations, it has been proven to not produce uniform production from those wells. On the contrary, production in adjacent wells

factors. Sweet spots matter in resource plays. Outstanding performance is achievable in shale reservoirs by building a thorough understanding of the subsurface from the available data and then optimising well planning, completion design and

What role do total organic content (TOC), rock brittleness, porosity, closure stress, natural fractures and pore pressure play in the success of a well (Figure 1)? Seismic data may

to provide all the needed information about these important

reservoir properties. Well logs and production information add

factors and unlock the resource potential of the play is critical.

drilling and completion costs and realise long term, predictable performance.

type, subsurface models identify and predict reservoir rock that meets the necessary criteria for highly successful wells. Success criteria are established through knowledge of rock-physics properties and correlation to production information, plus local

EURs. How valuable would it be to increase average IP rates and EURs by just 1%?

An ‘ideal’ shale well

A well must be drilled in a zone that has a high TOC, thus assuring the presence of oil or gas (assuming a favourable petroleum system).

The induced fractures resulting from the hydraulic frac job must intercept a natural fracture system and porosity.

The induced fractures must remain open for a sufficient period of time to allow economic volumes of hydrocarbons to be produced.

The SIGMA3

from geophysicists, geologists and reservoir engineers to accurately represent the subsurface at different scales. The

assembles those contributions to create a truly predictive model useful for planning future wells. Models tie all data together and are tested constantly with blind wells to validate their predictive capabilities.

Recent projects in North American resource plays have allowed the company to perform high-resolution inversions on pre-stack seismic data for rock physical properties. In the process, factors such as TOC, closure stress, rock brittleness, natural fracture density and porosity have been analysed for their weighted predictive capabilities for reservoir properties and production. In this way, the gap between geophysics and reservoir engineering is bridged, bringing great new value to seismic data in shale plays.

Figure 1. Understanding the shale puzzle.

Figure 2. Map showing cumulative Niobrara production (left). Map showing probability of 25 000 bbls cumulative oil (right).


September 2012

predictive models they can use to selectively plan well locations and frac jobs.

Geologists provide vital input from core, outcrop and well log data to create a fracture indicator log that ties seismic information to the physical properties of the earth. Pressure and completion data from reservoir engineers incorporate knowledge of historical reservoir production into the model. The geological model rigorously

to empirically test the validity of results against well data throughout the process. Well logs are analysed and used as

model accurately predicts the oil and gas that has already been produced.

revealed pore pressure as a key contributing factor affecting frac closure pressure and thermal maturation. This information

importantly, the models are iteratively tested against blind wells until they can predict them with high accuracy and precision; paving the way for asset managers to be able to predict

Field-tested workflow

on the Niobrara shale interval with the goal of understanding production drivers and optimising future well placement.

and density logs and only one core with some porosity and

post- and pre-stack seismic was available over the entire area and a full analysis of the available data could be performed.

deterministic and stochastic post-stack inversions, spectral

a different aspect of the information contained in the post-stack seismic that was then used in the modelling process. Key seismic horizons and faults were interpreted in time and used to

with the seismic attributes.Because naturally occurring fractures have been

documented as potential drivers of production in the 1 Continuous Fracture Modelling (CFM™)

indicator log was created based on well log and core data and

supervised neural networks. The CFM model accurately predicts the location, orientation, and density of fractures.

In this case, modelling showed that selected spectral imaging attributes, curvature and impedance all played a meaningful role in predicting natural fractures. When using pre-stack data and elastic inversion, rock mechanical properties,

such as lambda rho, mu rho and the derived rock brittleness, allow accurate modelling of the key rock properties that control the performance of the frac jobs and ultimately the performance

provides high-resolution Vp, Vs and density and additional rock properties that could be inverted directly from the pre-stack data.

fracture orientation and fracture density. By testing the model

established in the predictive capability of the work. A strong

permeability is strongly tied to natural fracture density in the model, natural fractures were determined to be an important

Further modelling of well productivity used cumulative oil

attributes, it was possible to derive a map showing cumulative oil in place for the area of interest. This map clearly shows hydrocarbon sweet spots, some of which have yet to be drilled (Figure 2).

reservoir rock is too ductile for a successful hydraulic frac job, the well will not perform well. By incorporating the brittleness model derived from the elastic seismic attributes, it is possible to identify rocks with good reservoir properties that also have brittleness

Facing the challenges of shale reservoirs

resource plays. Each shale is different and the factors driving

the best information available from all the data. As a result,

production metrics and optimise reservoir development and well performance. O T

Reference: 1. Cooper, S., Goodwin, L., Lorenz, J. ‘Fracture and fault patterns

AAPG Bulletin

Figure 3. Average brittleness in the lower Niobrara.

AUTOMATION-DRIVEN OPTIMISATION

Jim Gardner, FreeWave Technologies, USA, takes a look at automation technology considerations for optimising oil production.

There has been a dramatic shift in demand from natural gas to oil over the past few years and as a result, companies are beginning to pursue the more lucrative business of

oil production. The increased demand for oil brings the need to optimise and automate new production methods. In turn, producers

produce oil. Many have found that deploying an effective and reliable communications network will help streamline operations, as it allows for system monitoring and control on a real time basis.

Multi-well pads have become the standard for new shale exploration and production. For oil producers, this has created new challenges and new opportunities. The conventional wells had one well head per location. Now with advancements in directional drilling and multiple well head applications, there can be anywhere from 10 - 20 wells on one single location. Automation is at the forefront of this ideology, but there are many technology options on the market, making it extremely important for producers to choose the most appropriate communications option for their organisation’s needs.

64

Problems encountered

(RTU and PLC) on each well head quickly becomes redundant and excessively expensive. What is needed is a new way to automate

could handle multiple well heads. Many of these early attempts also used ‘hardwire’ and direct burial cable from each well head to the central controller. It did not take long for this approach to

prove problematic. In many cases, the wells were brought online at different times and the automation was added incrementally. With cable buried across locations from each well head, this meant bringing crews out to each location at different times, arranging to have backhoes dig trenches from each well head and in some cases, wiring from a previous installation was damaged during a second installation. Also, many new wells in the shale plays are rich with hydrocarbon liquids, which means increased tankage on each pad. Many of these locations have six or seven tanks gathering

65


liquids for 12 - 16 wells. This often meant the wiring from the well heads to the tank batteries had to be placed under the access roads for the trucks that transport the liquids from location to other facilities. This also became problematic, as the continued heavy

cables and caused the wiring to cease functioning. Depending on the locations and soils, some operators were replacing their buried cable in less than a year, which is an expensive proposition.

New approach, new criteriaOil producers along with automation engineers and technicians do not have the time to do ‘go backs’ for repair; their schedules are full trying to keep abreast of expanding production and new drilling programmes. What is needed is a ‘wireless solution.’ An ideal solution should be:

Cost-effective: preferably less than using a wired solution.

Easy to install: preferably faster than running wire.

Maintenance: free, reducing or eliminating the ‘go backs.’

Simple to install: one technician can configure and install several well heads per day.

Easy to use: must have a configuration template or wizard.

Must be ‘fail safe’: Device should be configurable to allow valve closure if communications are lost.

Selecting the ‘right fit’There are dozens of wireless instrumentation products that have

risen to the challenge of creating products to provide new solutions to the multi-well pad automation challenge. Each manufacturer has taken a different approach to solving these challenges, deciding which is right is about understanding what the system’s requirements are and how to match the differing products to a

Which data protocol will be used? Modbus is the most common for well head communications.

How many remote I/O points are needed to monitor on each pad (i.e. tanks, number of well heads, water meters, Electrostatic Discharge [ESD], separator, vapour recovery system, flare stack, etc.)?

How many I/O points are there at each well head (casing pressure, tubing pressure, surface pressure, intermediate pressure, valve control, plunger arrival, ESD switch, etc.)?

Does the technology allow the operator to terminate multiple devices on one I/O board such as casing pressure, tubing pressure, surface pressure all on one radio?

What RTU or PLC will be used: Does it have two or more communication ports? Does it support Modbus? etc.?

Is there a need to purchase a ‘data hub’ for this technology (US$ 2000 to US$ 3000 additional expense)?

Do the device and the protocol support ‘cry out’ alarms?

Will this technology be compatible with other radio systems for long range data collection or will they interfere with each other?

After answering these questions it is a good idea for the operator to ask the manufacturer and sales representative to do a ‘try and buy.’ A 30 day trial will answer any lingering questions about interference, cross talking wireless systems, ease of installation and versatility. Since wireless networks on a single pad are independent of each other it is easy to install several manufacturers’ equipment as a way to compare results. For instance, it would be good to test manufacturer ‘A’ on one well pad and manufacturer ‘B’ on a second well pad. Some experts strongly recommend keeping all the same equipment on each pad and comparing total automated solutions from one pad to the total solution on a second pad rather than a mix and match approach.

Communication layersMany of the operators of these multi-well pad locations are combining technologies to complete hybrid solutions that combine layers of communications. These layers are basically

see an Ethernet communication layer. This allows the producer to have multiple people and multiple departments access the data. It also allows the enterprise system (polling the host computer) to poll multiple locations at once. The beauty of Ethernet is it has IP addressability, meaning that each point in the system has a unique address and conversations can be routed to and from

data and getting it more frequently has become an addiction.

Figure 1. Operators of multi-well pad locations are combining technologies to complete hybrid solutions that combine layers of communications: Ethernet, serial and wireless I/O.

Be ready for 2014

THE GLOBAL ENERGY SECTOR JUST GATHERED IN STAVANGER. NOW IT’S TIME TO SECURE YOUR

STAND PLACE FOR ONS 2014. GO TO ONS.NO

MONDAY 25 - THURSDAY 28 AUGUST 2014


Most producers are searching for ways to optimise production, which requires data for casing and tubing pressures to be recorded and transmitted many times per day. With today’s smarter RTUs and PLCs this data can be collected on location through the wireless I/O radios once a minute if desired and then sent back to the host once per hour to provide the granularity necessary to produce meaningful trend analysis.

For many operators the second layer of communication is serial. This typically is a RS-232 or RS-485 communication protocol. All of the older RTUs and PLCs could transmit this protocol and the power consumption is between 1/3th to 1/10th of Ethernet radios. By combining serial with Ethernet at a data concentration spot, systems can be built that are fast and low power and meet data requirements (see Figure 1).

The third layer is the wireless I/O communications between the well head and the RTU or PLC. In most cases this is a Modbus communication, but also can be an instrumentation level signal such as analogue 4 to 20 milliamp or 1 - 5 volt analogue signals as previously discussed.

Wireless I/OWireless I/O is a more recent option for automating multiple well pads. Today, wireless I/O is recognised as an effective and reliable way to monitor and control plunger lift and organisations are starting to adopt it as an option for oil production. Technology manufacturers that have followed industry trends are aware of the decreased need for gas producing technologies and the increased demand for technologies that can monitor and control multiple wells on one pad in order to maximise oil production. Producers are often using advanced production techniques, such as hydraulic fraccing and directional wells. Oil comes in at a very high pressure, anywhere from 6000 – 10 000 lbs/in.2 of pressure during oil production. Wireless I/O radios have the ability to transmit

monitor casing pressure, tubing pressure, intermediate pressure and surface pressure. With wireless I/O, producers can carry temperatures, pressures and alarms from miles away back into the system. Many wireless I/O radios are now capable of transmitting data more than 60 miles with good line of sight communication paths. Wireless I/O technologies can also control the valve at

the wellhead. Because these wells are so

tanks and a tank battery per location. Some wireless I/O providers can transmit tank levels for multiple tanks, allowing for optimal control of valves. For example, should one tank become full, a wireless I/O solution will automatically instruct the valve to close and signal a new tank to open. Essentially, wireless I/O takes the information from the wellhead or the tank back to the controller. The controller then processes the data, reads the algorithms and makes decisions in which the wireless I/O data radio carries back to notify the valve of whether it needs to open, close or do nothing.

When producers are looking into wireless I/O, they must also consider that some manufacturers offer more variety and options than others. For example, there are manufacturers with radios that offer multiple I/O points, allowing for several temperatures,

pressures, etc. to be transmitted through one radio. It is more common to have just one I/O point, so depending on how many

who offers multiple I/O points, also known as I/O expansion. For example, a wireless I/O base may have two digital inputs, two analogue inputs, two digital outputs and two analogue outputs allowing the user to simply snap on a module that has up to 16 additional I/O points onto the radio. For oil wells, the ability to have I/O expansion is crucial because when measuring high

and intermediate pressures. I/O expansion helps increase the overall health of oil production systems by offering producers real time data that can be analysed for multiple pressure readings.

ConclusionIn oil production, advancements such as directional drilling allow for

production. However, in order to keep up with these advancements, a communication solution that can effectively monitor a variety of differing data points is essential. Wireless I/O and I/O expansion not only meet these needs, but offer perks such as a ‘fail safe’ method to handle communication failure. Additionally, wireless I/O also can transmit the data needed to control valves on oil tanks, preventing

technology can be a daunting task, so it is important for producers to be familiar with all the options in the market. Today, there are wireless I/O radios available at a fraction of the cost of buried cable,

and easy to install package. Choosing the right automation technology can be a daunting

task, so it is important for producers to be familiar with all of the options in the market. In fact, many operators of multi-well pad locations are merging technologies to complete hybrid solutions that combine several layers of communications. Today, communication technology manufacturers have risen to the challenge of creating solutions to effectively manage and automate multi-well pad infrastructure. Manufacturers have taken different approaches to solving these challenges, but deciding which is best is about understanding what the system’s requirements are and how to match

O T

Figure 2. Example of wireless I/O application for pressure, temperature and flow level readings.

When the summer lasts just six weeks and winter temperatures average -15 ˚C, the frozen expanse of Siberia is a harsh environment by any standard. As

workplaces go though, such hostile and inaccessible terrain is fairly typical for the oil and gas industry where important reserves of fossil fuels are increasingly being found.

Despite the growing popularity of alternative energy sources, demand for crude oil and natural gas has never been greater. These and other hydrocarbons continue as the mainstays of the world’s energy market, but long before the drilling can start – whether it is Siberia or the Gulf of Mexico – companies seeking to explore and develop new fields must first overcome the many technical and logistical problems presented by local geography and climate and none more so than the pressing need for reliable, robust communications.

In the early stages of an upstream operation, small teams of geologists and prospectors on the ground would be working quickly and moving often. In searching for new mineral reservoirs, they typically have the lengthy tasks of identifying and assessing new oil wells or gas reserves.

Highly mobile, the geoscientists know the quicker they can send data from the field, the quicker they will know where best to explore next. Everyone involved in the process, including contractors, is under pressure to reduce costs and increase profits by finding, assessing and rapidly exploiting reserves, to get the product to the consumer more quickly and more efficiently.

While working in some of the most remote parts of the world, many teams find themselves operating at the limits of modern mobile telecommunications, usually well beyond the reach of

ALL AREASACCESS

Drew Brandy, Inmarsat, UK, describes how advances in mobile communications technology can help meet the needs of remote workforces in the demanding oil and gas sector.

reliable fixed line or GSM wireless networks. Fixed satellite solutions, such as VSAT (very small aperture terminal), typically need a semi-permanent installation and even the ‘portable’ versions are relatively cumbersome and take time to configure. Although not an issue for static operations, the technology is really unsuitable for mobile workforces who need high speed connectivity from any location. Even handheld satellite phones fall short of providing high data and application support, such as video conferencing and video streaming, for example.

Opportunity costOne alternative that combines high bandwidth connectivity with the footprint of a laptop computer comes in the shape of Inmarsat’s BGAN (Broadband Global Area Network) service. The small terminals not only provide phone services, but with IP data rates up to 492 kbps, deliver broadband connectivity with simultaneous voice through a single, compact device on a global basis. It is also the first service to offer guaranteed data rates on demand for live video streaming and video conferencing.

The economics of oil and gas illustrate why BGAN is tailor made for the industry. With most analysts estimating that developing an oilsite, from exploration and appraisal to coming online, can cost anywhere between US$ 1 – 3 billion (and often with very long lead times), every unproductive day can significantly add to the final bill. Driven by the need for reducing exploration time and enhanced data gathering, portable satellite systems can act as a lifeline for organisations looking for heightened levels of productivity and to drive down costs.

69

70 OILFIELD TECHNOLOGYSeptember 2012

While VSAT is able to provide voice and data services at remote, permanent sites, one common drawback among high frequency systems is the disruption occasionally caused by poor weather, such as heavy rain or sandstorms. By operating at much lower frequencies, BGAN services do not have this problem and are reliable in any weather condition or climate. Moreover, some countries simply do not permit VSAT within their borders and if the system malfunctions, a specialist maintenance team is often required to fly in and fix it.

Batteries includedPortable systems, such as BGAN, can potentially have a broader role to play in remote operations, with applications ranging from the tracking of goods and vehicles using automated two-way telemetry, to telemedicine. In an offsite emergency, for example, medical information can be sent via BGAN to a medical centre to help consulting, or to enable remote medical procedures or examinations to take place.

Without the system, a mobile team with a low data capability would have to travel back to a site with a VSAT installation, or drive to the nearest town with a broadband connection, which could be many hundreds of kilometres away.

Weighing approximately a kilo or two, running off batteries and with a size comparable to that of a laptop computer, small mobile exploration teams can use BGAN to help them work faster and more efficiently – enabling them to speak at any time to colleagues at base, or elsewhere in the field. They are also able to send back highly detailed progress reports or photographs for immediate analysis.

Virtually thereWhile in a field camp, BGAN’s dual voice and data capability is able to provide a temporary communications hub, supporting a range of ‘enterprise class’ applications. This mobile office could provide voice, email, fax, online connectivity and remote, secure access to a VPN enabled corporate network. Safety is always a key consideration, so the ease of use and portability offered in systems

such as BGAN allow field teams to venture into high risk territory more safely, expanding their exploration capabilities, safe in the knowledge that they have access to reliable communications the minute they need it.

At unmanned sites, BGAN’s role can be extended to provide an ‘intelligent gateway’ for data gathered by sensors and actuators, enabling near real time status reporting on wells, rigs and other equipment in the field through SCADA (supervisory control and data acquisition) applications. BGAN can transmit data automatically to remote asset monitoring servers, where they are processed by back-end systems. Remote monitoring backhaul is already widely available over satellite links such as the company’s IsatM2M and D+, or GSM and GPRS. However, the broadband capability of BGAN and support for services such as live colour video, offer an alternative option that is significantly more powerful and flexible.

Playing it safeWith health and safety always a priority and insurance premiums typically reflecting this, BGAN helps organisations comply with strict regulations by ensuring the base camp is always equipped with a guaranteed voice and data link. This means that medical help can be summoned immediately, if needed and BGAN’s high capacity data connectivity lets it transmit live video to allow any offsite doctors, who may even be in another country, to quickly see and assess injuries.

Not only a dependable front line communication tool, helping companies comply with high standards of health and safety for their workers, BGAN can also show insurers that every reasonable precaution is being taken, (which may even result in lower premiums). It can also reassure workers, giving them a greater sense of security regarding their welfare and well being.

Upstream, downstream and video streamingAfter new fields have come onstream, BGAN can play an important, ongoing role. Certification engineers and inspectors who travel between remote installations and along pipelines to check for faults, or report on the progress of repairs, can use it as their primary means of voice and data communication. They can keep in constant contact with head office, and with other colleagues in the field who also have BGAN and use it to send emails, data, photos, video and diagrams. They can also connect peripheral devices, such as well and pipeline monitors to a BGAN to transfer data back to base and run data evaluation models and CAD programmes on their laptops, using it to feed the results back to base quickly and efficiently.

Mobile voice and data capabilities in the field help to improve decision making, increase productivity and reduce time to operation. The system is also backed by the company’s next generation satellites.

Reduced time to oilHelping to find and successfully exploit new sources of oil and gas underpins all upstream operations, with ‘reducing time to oil’ the mantra of every organisation. Mobile satellite communications technology – providing not only phone services but broadband data connectivity – can now fit into a rucksack and be up and running in approximately a minute. So whether it is upstream or downstream elements of the oil and gas value chain, both can benefit from the latest advances in satcom based broadband technology. Fully ruggedised and portable, these systems can lead to improved asset and supplier management, rapid decision making and contingency response, while contributing to the all important area of reduced capital and operating costs. O T

Figure 1. Mobile, rugged and always connected, even in the harshest terrain.

PETEX is the largest subsurface-focussed E&P conferenceand exhibition in the UK, attracting thousands of delegatesfrom across the world and across a spectrum of industrysectors, from super-majors to consultancies. Exhibitionspace is already 90% sold out!

Technical Conference

Biggest Ever Exhibition

Greater Student Focus

Our theme for PETEX 2012 is ‘Global Frontiers, GlobalSolutions’. We’re promising a comprehensive programmeillustrating the latest global activity in exploration, fielddevelopment, reservoir management and unconventionalexploitation.There will also be a special interactive Plenary Session,

consisting of a panel of experts who will debate on the main societal challenges facing the industry today.Following the success from last time, PETEX will again host the Petroleum Geoscience Research CollaborationShowcase.

Building on the success of last time, PETEX will be hostingthe PESGB Graduate Career Fair, Student Lunch and newto PETEX 2012: The University Forum: a place forUniversities to interact with both students and industry.

For more information and to register for the eventplease visit our website: www.petex.info

Re

gist

er

No

w!

We will again be providing a special area for internationalrepresentatives, including: Oilcompanies; Ministries; Governmentsand Other promotional agencies.This designated space will provide

representatives with a forum to increase their exposure and promote licensing roundsand/or available acreage.

International Pavilion

Event Information

It is widely recognised that while subsea well intervention is necessary, traditional methods can make it a time consuming and very costly activity, with drilling and semi submersible

rig costs running at up to US$ 1 million to US$ 1.4 million a day spread rate. There are more than 4000 oil and gas producing subsea wells worldwide and this number is increasing at a rate of approximately 500 a year. With many such wells over a decade old, intervention is crucial to allow for maximum oil and gas extraction.

The sustained rise of deepwater oil and gas explorations has made the challenge of cost-effective well intervention even more pertinent. The challenging conditions experienced at depth, in regions such as Asia, Brazil, West Africa and the Gulf of Mexico, mean many wells have been producing for several years without necessary intervention. This often results in sub-optimum production and ultimate recovery reduction.

CLOSING

A new systemIt was clear that the oil and gas industry required a step-change in technology and it was at 10 000 ft (3000 m) that the access challenge began.

The AX-S well intervention system has been developed to help provide a cost-effective well intervention solution designed to close

providing a safe, riserless and remotely operated subsea solution, which is cheaper both in simple day-rate terms and overall job terms.

designed to address some of the unique operating demands of the deepwater subsea environment.

The system, onboard the Havila Phoenix vessel, completed its

in Norway, in April. Preparations are now under way for well intervention jobs in the North Sea.

Matthew Law, Expro, UK, analyses a new system designed to narrow the value recovery gap between subsea and dry-tree well intervention operations.

72

technology that can operate in water depths of up to 10 000 ft (3000 m), which covers every subsea well across the globe. It

ultimate recovery from subsea wells. The system can help reduce subsea intervention time.

As a comparison, a typical deepwater intervention can take approximately 12 to 15 days using a rig, compared to only eight to 10 days using AX-S.

The equipment, which is 110 ft tall and weighs 220 t, is deployed onto a subsea tree with an active-heave compensated

pressure-contained subsea packages containing a well control package (WCP), a tool storage package (TSP), a wireline

THE GAP

Figure 1. The AX-S subsea packages on the back deck of the Havila Phoenix.

A hydraulic plug-pulling tool overcomes the risks associated with pulling and setting tree crown plugs, while a novel control umbilical overcomes the challenges of weight and subsequent deployment/handling system size.

There is also a fully enclosed pressure housing, with no dynamic seals between the wellbore and surrounding environments. The WCP is a dual safety barrier containing 7 3/8 in. shear seal and gate valves. If any safety issues arise, the operator has time to identify the problem and isolate the wellbore.

Positioned directly above the WCP is the TSP, which contains eight tool pockets, located around the inner circumference of the package. The tools are swapped on the seabed (in minutes rather than hours) and as they are held in a pressure-retained housing, no pressure testing is required after

73


The tools are run in the well by the WWP. Contained in a pressure housing means issues such as hydrocarbons leaking into the surrounding water and seawater ingress into the well are eliminated. The winch has 25 000 ft of mono-conductor e-line wire that conveys the various intervention tools into the well.

then circulated back into the well or more likely back to the host

customer, seawater can be mixed with the glycol in variable ratios

A control cabin on the vessel has a software controlled

a fully automated basis. The control system is comprised of all the hydraulic controls subsea meaning that there is no requirement for any hydraulic lines going back to the surface. To ensure operations

integral part of the system.

Figure 2. The AX-S system, onboard the Havila Phoenix vessel, completed is final commissioning successfully on a subsea well in a fjord (Onarheimsfjorden), in Norway.

Figure 3. The control room of the AX-S system.

bundle and handling system for deployment of the system has been developed that comprises three individual umbilicals helically wrapped around

provides greater strength

than wire rope alternatives. It is buoyant in water and therefore adds no additional weight to the overall deployment system. This also reduces the winch power consumption, surface equipment size and there is no torque in the lifting line that may prove hazardous in the management of vessel-based operations.

of its design. As the tool swaps are carried out on the seabed, back deck operations are far safer. Also it is only necessary to disconnect the running tool and umbilical from the support vessel to leave location, leaving the system as a fully pressure containing safety barrier on top of the subsea tree.

The system is more cost-effective than riser based alternatives because it is supported from a vessel, and is faster to operate than wire-through-water solutions, especially on horizontal trees. Studies carried out that indicate that it is an economically attractive solution for wireline intervention in deepwater wells and this step-change in philosophy brings

water regions as well. Subsea and deepwater well intervention is increasingly

important as operators look to extend reservoir life and maximise production, however with budgets being constantly scrutinised across the industry, increasing rig costs and declining availability mean intervention is an activity which could come under threat (or typically does not happen on subsea wells).

The AX-S system can help deliver a cost-effective answer to this dilemma and promote good practice and maximise reserves and value within the industry through the concept of increased intervention. The emergence of deeper water plays provides a ready and willing market for this technology.

Looking forwardWith the number of subsea wells increasing across the world, opportunities have opened up in both emerging and maturing subsea regions, such as West Africa, Brazil, the Gulf of Mexico, Australasia and India. These are potentially huge areas for the future development of the industry.

The aim of the AX-S system is to enhance hydrocarbon recovery by providing wet trees with the same opportunity for intervention and management as is available on dry trees. The system has the potential to transform the economics of subsea well production by providing a safe, cost-effective solution compared to traditional intervention methods. O T

KEEPING IT COOL

Rollie Merrick, Hothead Technologies, USA, explains how biosensors make it possible to

help protect hardhat workers from heat stress.

T he National Oceanic and Atmospheric Administration (NOAA) has

75


body by sweating; this is the most important response to an

Heat rash

Dehydration

Figure 1. Temperature biosensor on hardhat brow pad and smartphone dashboard.

Heat syncope

Heat exhaustion

Heat stroke

Unveiling the next generation of communications solutions for the oil and gas community.

November 6-8, 2012Houston Marriott Westchase

Houston, TX

www.OilComm.com

Oil Comm

20672

PRODUCTION SUPPORT VESSELEXPLORATION DRILLING

REGISTER TODAY WITH VIP CODE OILFIELD!


accidents appears to be higher in hot environments than in more

in a hot environment lowers the mental alertness and physical

Hardhat biosensors

Figure 2. Total OSHA inspections resulting in at least one citation for violations of safe heat exposure practices under the General Duty Clause or specific standards, 1986 - 2011.

Key questions to consider

www.energyg loba l . com/event s

SEARCH hundreds of international industry events on Energy Global

Does the crew ever work shorthanded?

Is this a safety violation?

How often must someone be called into work to fill the void of someone from suffering heat illness?

Would this be considered an overtime pay situation?

What is the cost in lost productivity when a worker succumbs to a heat related illness?

Does this productivity impact the project?

The customer wants the job done yesterday; has a heat related illness affected production schedules?

What were the costs, penalties and ramifications of missing a customer deadline?

When someone gets heat sickness, how many other workers get involved?

Does one heat related problem have the potential to bring the whole drill site to a standstill?

How long is a drilling site affected by a stoppage of slowdown due to heat issues?

Companies know what it costs per-hour to complete a job or service. Having one sick worker leave or slow down operations, even for a short period of time, is surely expensive.

Has your company suffered any heat related illness legal or financial liabilities?

If so, how much? (The liability of one incident could pay for helmet biosensors for many years).

How many workers have repeated incidents?

Is this a precursor to the worker eventually quitting?

How much does it cost to replace this worker?

Recruitment?

Training costs?

Personal Protection Equipment (PPE)?

There are many more areas to explore in looking for how heat related illnesses negatively affect a company’s productivity. However, the inverse scenario should also be considered: without heat being an issue to slow down or stop production schedules, could a company complete

while improving customer expectations and satisfaction? Could a drilling crew work with one less employee per shift because heat issues are under control?

Most companies look at heat illness as a binary issue, meaning that corporations feel comfortable with their employee heat controls until something goes wrong. This is a result of being reactive at the time of an emergency rather than proactive. Monitoring the temperature trends of all hardhat employees and taking preemptive measures is a far

Biosensors take the subjective nature out of the heat

is actually experiencing. Technology has caught up with the heat stress problem but only through proactive monitoring of employees and adherence to strict guidelines can the safety of hardhat workers be ensured. O T

CORSITECH 09

CUDD ENERGY SERVICES 51

DRILLING SOFTWARE 19

DYNA DRILL 07

ENERGY GLOBAL 52, 79

EUROPIPE 37

EXTREME ENGINEERING 14

FAIRFIELDNODAL 27

FMC TECHNOLOGIES OFC, 29

FUGRO-JASON 23

GEFCO 55

GEODYNAMICS IBC

HARDBANDING SOLUTIONS BY POSTLE 47

KUDU 02

OILCOMM 77

OILFIELD TECHNOLOGY 56

ONS 67

PACKERS PLUS 04

PETEX 71

ROBBINS & MYERS ENERGY SERVICES GROUP IFC

ROSEN OBC

SCIENTIFIC DRILLING 17

SPE ATCE 55

STANLEY CRC-EVANS ONSHORE 43

STATOIL 13

Advertisers Index

Oilfield Technology is audited by the Audit Bureau of Circulations (ABC). An audit certificate is available on request from our sales department.

www erf com 1 1 9 2-191

2012 GEO ynamics, nc.

Want to break free from the crowd?

VERSATILE.Always a leading innovator, ROSEN not only supplies pipeline customers

with the latest diagnostic and system integrity technologies but also offersflexible solutions and all-round support for plants & terminals.

www.roseninspection.net

EMPOWERED BY TECHNOLOGY

Oilfield Technology September 2012

Documents

Transcript of Oilfield Technology September 2012