Special Report – Next Generation Centralizer Solutions Centek

SPECIAL REPORT

Next Generation Centralizer Solutions Next Generation Centralizer Solutions A Big Business Needs Quality Solutions Drilling at Depth for Oil and Gas Supporting Drilling and Production Under-Reaming and Centralizing

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Published by Global Business Media

SIMPLY SMARTER. Your output is only as strong as your down-hole equipment.

With innovative single-piece construction, premium virgin steel, jigsaw joints and a heat treated stop collar, Centek centralizers contribute to greater well productivity by ensuring an enhanced cementation job.

Optimal. Reliable. Durable.

You only have to buy it once.

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SPECIAL REPORT: NEXT GENERATION CENTRALIZER SOLUTIONS

SPECIAL REPORT

Next Generation Centralizer Solutions Next Generation Centralizer Solutions

Contents

A Big Business Needs Quality Solutions Drilling at Depth for Oil and Gas Supporting Drilling and Production Under-Reaming and Centralizing

Foreword

2

John Hancock, Editor

Next Generation Centralizer Solutions

3

Cliff Berry, Global Business Development Manager, Centek Group

Sponsored by

Published by Global Business Media

Published by Global Business Media Global Business Media Limited 62 The Street Ashtead Surrey KT21 1AT United Kingdom Switchboard: +44 (0)1737 850 939 Fax: +44 (0)1737 851 952 Email: info@globalbusinessmedia.org Website: www.globalbusinessmedia.org

Cheap Is Dear In The Long Run Innovation Provides Solutions The High Price of Getting It Wrong The Role of Centralizers The Challenges of Under-Reaming The UROS Centralizer Centek Group

A Big Business Needs Quality Solutions

Publisher Kevin Bell

No Quick Profits in Offshore Oil and Gas A Real Growth Sector Life Extension Further and Deeper

Business Development Director Marie-Anne Brooks

Drilling at Depth for Oil and Gas

Editor John Hancock Senior Project Manager Steve Banks Advertising Executives Michael McCarthy Abigail Coombes Production Manager Paul Davies For further information visit: www.globalbusinessmedia.org The opinions and views expressed in the editorial content in this publication are those of the authors alone and do not necessarily represent the views of any organisation with which they may be associated.

Material in advertisements and promotional features may be considered to represent the views of the advertisers and promoters. The views and opinions expressed in this publication do not necessarily express the views of the Publishers or the Editor. While every care has been taken in the preparation of this publication, neither the Publishers nor the Editor are responsible for such opinions and views or for any inaccuracies in the articles.

8

John Hancock, Editor

10

Peter Dunwell, Correspondent

Complex Access in Difficult Places Finding Reserves then Exploiting Them Challenges

Supporting Drilling and Production

12

Francis Slade, Staff Writer

An Engineering Challenge Casing Geology Cementing

Under-Reaming and Centralizing

14

John Hancock, Editor

Hole Geometry Drilling – Not a Simple Process Under-Reaming – Back in Fashion for the Right Job Centralizers – Keeping Everything Where It Needs To Be

References 16

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SPECIAL REPORT: NEXT GENERATION CENTRALIZER SOLUTIONS

Foreword C

ENTRALIZERS AND centralizing solutions

through previously set casing before continuing into

might not be the most glamorous aspect of

an under-reamed well section.

oil and gas recovery onshore or offshore. In fact,

The second piece provides an overview of the

compared to some of the engineering equipment

growing offshore oil and gas sector and, in particular,

used, centralizers are fairly simple devices in their

the qualitative and quantitative programmes being

design and manufacture. However, they are aptly

deployed to better exploit known reserves, wherever

named as not only are they used to ensure that

they might be located. Established fields are operating

casings are centrally located in the well for effective

beyond their planned lives while new fields are

cementation and that tools are accurately placed

being opened beyond what might once have been

wherever in the well they are needed, but also they

considered a feasible distance from land. Peter

are central to the operation of a well.

Dunwell then considers the process at the pivot point

In this Report we have tried to get into centralizing

of oil and gas production, drilling holes into the ground.

solutions starting at the highest level in the industry and

Francis Slade continues our own drill into the subject

drilling our way (forgive the pun) through the logic of

looking at the complex engineering and support

the various processes to the operation of centralizers.

factors that put wells where they ought to be. Finally

The opening article looks at the advantages of a

we look at the wells themselves, boring them plus the

single piece centralizer over those with a simple

various methods, materials and equipment used to

latch. The single piece centralizer overcomes the

establish and then maintain their productive capacity.

problems caused by the movement from the older,

In particular, we look at centralizers, those devices that

vertical wells to today’s deviated wells, for which solid

bring structural balance to casings in holes and get

centralizers were not designed. Although centralizers

tools and materials to points in the well where they

are inexpensive items in themselves, the costs, if

are needed‌ the bottom of the well and the bottom

they fail, can be enormous, so choosing the right

of our own drill into the subject.

centralizer for each well is of paramount importance.

The article goes on to describe the Under-Reamed Offset centralizer (UROS), introduced by the Centek Group, which reduces drag forces on run-in-hole

John Hancock Editor

John Hancock joined as Editor of Offshore Technology Reports in early 2012. A journalist for nearly 25 years, John has written and edited articles and papers on a range of engineering, support services and technology topics as well as for key events in the sector.

Subjects have included aero-engineering, testing, aviation IT, materials engineering, weapons research, supply chain, logistics and naval engineering.

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SPECIAL REPORT: NEXT GENERATION CENTRALIZER SOLUTIONS

Next Generation Centralizer Solutions Cliff Berry, Global Business Development Manager, Centek Group The importance of correct centralization of tubulars in the wellbore

CLIFF BERRY, VP GLOBAL BUSINESS DEVELOPMENT, CENTEK GROUP

G

ETTING TO bottom with a casing / liner string is never as simple as you plan it to be. Well conditions, well geometry and torque all combine to make the process a lot less simple. Mud weights, friction factors in both cased and open holes also need to be considered and measured.

Other areas which need to be looked at are cementation, displacement efficiency, spacers, flushes, well cleanout, and adherence (or the lack of it!) to best practice as these can all lead to a poor cement job which in turn can cause back pressure in the annulus, loss of production and a shorter well life before an expensive unplanned for work over is required.

Cheap Is Dear In The Long Run The technology changed in 2001 with Centek’s introduction of the single piece centralizer. To understand the importance of this, we must look at the history. For decades, and even today, the simple latch on over-sized centralizer was the norm. These units are still widely used in the Industry, but they come at a price. They are the cheapest centralizers to use but they are also the centralizer type which causes the biggest headaches. Damage is regularly associated with this type of unit, mainly because the design was produced for vertical wells, which at the time of

the original design was what the Industry drilled.

From the mid-1980s wells started to become more deviated. This caused serious concern and downtime to operators when running casing strings, as the centralizers were not designed for deviated well geometry. The solution at that time was the solid body or rigid type of centralizer.

These were, and still are, reasonably effective in getting to bottom. Because they are undersized to a standard unit, claims of less drag are often disputed as the surface area in contact is far greater. They get to bottom, as they should, but at the expense of stand-off and displacement efficiency. Live annulus issues became common and still are. Poor stand-off in general leads to a poor cement job. This in turn causes channeling, poor filter cake removal and poor bonding to the formation. Rigid and solid body centralizers were better than the earlier latch-on types and quickly became the norm for most operators drilling deviated wells. Naturally, as they became an Industry norm everybody copied the original straight or spiral design. This led to many companies introducing different materials such as steel, plastic, composite, aluminum, zinc, and phenolic - the list is wide ranging. As the designs were virtually identical they quickly became a commodity at a commodity price. But they did not become the solution. The problems still remained and continue today when these units are used.

The solid centralizer has a problem when it emerges into the under-reamed section, because with its fixed diameter it is undersized for the under-reamed hole, producing much less effective centralization than a precisely fitting bow spring designed for that wellbore.

Understanding correctly what the customer requires is vital to be able to meet the demands of the job. However, surprising as it may seem, not all engineers are worried about getting a good cement job. In the US shale plays, some operators are happy to live with poor cementation just so long as the string gets to bottom. In other regions the cement job is seen as being of vital importance, as generally it should be. It is also worth noting that not all completions are

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SPECIAL REPORT: NEXT GENERATION CENTRALIZER SOLUTIONS

From the mid-1980s wells started to become more deviated. This caused serious concern and downtime to operators when running casing strings, as the centralizers were not designed for deviated well geometry CENTEK S2 CENTRALIZERS

necessarily cemented, and this is often the case in the US market.

Innovation Provides Solutions The solution to the problem was innovation. The capability to produce a unit that was designed for strength led to the single piece centralizer design.

Drag was an issue with run-in-hole (RIH) so the single piece unit was made to gauge. This was a first for a centralizer design. Restoring forces needed to be high so as to arrest pipe movement as the pipe conforms to the well bore geometry.

A further innovative design measure was to manufacture the units with an increased flow by area. This aids disposal of cuttings with better well clean out, as well as improving the cement sheath with less channeling so as to achieve superior isolation. Centralizers had to be made so as to allow for flexibility when encountering tight spots, for which oversized units were not designed and where solid centralizers simply could not pass through.

Blade design is also very important and a straight blade unit was found, after exhaustive testing, to be the best. Spiral blades tend to carry debris along and also increase drag, whereas a straight blade performs like a pair of skis. Centek’s design approach was to have a double curvature 4 | WWW.OFFSHORETECHNOLOGYREPORTS.COM

bow. This allows the unit to be round without a flat blade in contact with the formation. Flat blade or solid type units tend to dig into the formation creating additional RIH problems.

Wear was and is a major issue even today. Solid units, apart from steel ones, tend to wear rather easily, especially once under load due to the well geometry. This wear, both internally and externally, rapidly reduces further an already undersized unit.

Wear considerations are removed when using the Centek units as they are the only fully heat treated units of single piece design.

Torque and drag are other major considerations which have been taken into account by Centek in the design phase. The operator demands are high, rightly so, so design and manufacture become key to success. The Centek design is a proven tool to reduce both torque and drag. Drag will occur when centralizers are oversized to the wellbore or when smaller solid units push debris in front of them, like a piston.

The High Price of Getting It Wrong Lost time due to centralization problems is reaching sums in excess of $0.5 billion per year worldwide. Spiralling rig costs, of all types, including $1 million per day drill-ships, mean

SPECIAL REPORT: NEXT GENERATION CENTRALIZER SOLUTIONS

WELL DIAGRAM, ILLUSTRATING A TYPICAL EXTENDED HORIZONTAL LEG

downtime has become prohibitively expensive.

Centralizers in real terms are cheap, but when they fail due to damage, breakages or simply getting stuck down the hole due to fitting insufficient centralizers at the correct intervals, then they assume a consequential cost out of all proportion to their price. Centralizer failure costs a fortune! Most centralizer failures are due to choosing an incorrect unit for the job. An alarming fact is that everyday someone, somewhere, is pulling up pipes and leaving debris in the hole for the simple reason that the wrong type of centralizer was used.

The Role of Centralizers The job of a centralizer is to centre the casing in the wellbore so as to allow cement to circulate freely around the tubular and produce a robust cement seal, ensuring zonal isolation. Not rocket science, but if the centralizer isn’t strong enough to centre the pipe, or if it breaks, the consequences can be very expensive. If it breaks in a deviated well, centralization is usually completely lost rendering effective cementation impossible, added to which the centralizer may jam the pipe down hole. Stuck drill strings are one of the major contributors to drilling downtime, and a common cause of sticking down hole is a failed centralizer. A conservative estimate is that annually, 400 wells worldwide are affected by centralizer problems, at an average cost per well of around $1.5M producing a total annual loss of

$0.6B. This is a loss which is largely preventable.

Mud displacement is very important for achieving a good cement bond. The more central the pipe, the more efficient the mud displacement will be. In deviated and horizontal wells, if the tubular is not centralized it will lie along the low side of the borehole making it very difficult to circulate the cement around the pipe and achieve a uniform cement sheath. Poor centralization can also impair the cement bond by causing channeling, when the cement flows in channels on only some sides of the casing or annulus producing an inadequate seal. In addition, if the annular clearance is restricted in some sections, back pressure can result, necessitating pumping at a very slow flow rate during cementation in order to avoid fracturing the formation with consequent fluid loss.

The Challenges of Under-Reaming Under-reamed wells are among the toughest challenges a centralizer has to deal with. Underreaming is a widely used drilling technique for enlarging the diameter of a borehole in order to increase the size of tubular that you can put down.

A major problem with under-reamed wells is getting effective casing centralization in the under-reamed section. Conventional bow-spring centralizers that are wide enough to fit the underreamed section accurately often get damaged in passing though narrower casings. The bows get

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SPECIAL REPORT: NEXT GENERATION CENTRALIZER SOLUTIONS

The Centek design is a proven tool to reduce both torque and drag. Drag will occur when centralizers are oversized to the wellbore or when smaller solid UROS CENTRALIZER SIDE VIEW

units push debris in front of them, like a piston

compressed to such an extent that they lose their elasticity and can’t expand to the correct diameter of the under-reamed hole – a condition known as permanent set.

The latest generation of centralizers from Centek is manufactured from a single piece of heattreated steel giving a hardened and tempered surface that results in greatly reduced torque and drag losses, so abrasive wear caused by running to depth and rotating the tubular is virtually eliminated. These centralizers offer exceptionally high fatigue strength for axial forces and radial side loads on bows during tubular rotation.

Reducing torque ensures that casings can be rotated without wear, in both cased and open holes, at a deeper level than before.

Despite being fully compressed during passage through the casings, these one piece construction centralizers offer exceptional restoring force with a very high stand-off ratio once in the open hole. As low profile units they take up less annular space, so the ECD (Equivalent Circulating Density) signature is low allowing the operator to pump at a slightly higher rate improving well clean out.

When running casing, losses can result from not getting to bottom due to friction or mechanical interference, getting packed off or stuck, while extra trips and side-tracks, all add to well costs.

In addition, poor cementation due to inadequate stand-off causes improper cement placement resulting in production delays and early water entry directly attributable to incorrect tubular placement in the well-bore. All these problems can be resolved by ensuring correct centralization.

The UROS Centralizer In 2010 the Centek Group introduced its UROS centralizer, embodying a radical new design 6 | WWW.OFFSHORETECHNOLOGYREPORTS.COM

targeted specifically on under-reamed well sections, which optimises the balance between drag resistive loads and the performance required once in final position.

The UROS, or Under-Reamed Offset centralizer, is the answer to the oil industry’s need to reduce drag forces on run-in-hole through previously set casing before continuing into an under-reamed well section. The UROS significantly reduces initial insertion forces, a characteristic of bow type centralizers, and additionally delivers a substantial reduction in running forces when passing through previously set casings. Once through the compressed stage, the UROS reverts to normal centralizer operation in the open hole with the bows regaining their nominal outer diameter to maximise stand off. The UROS achieves a reduction in drag by its unique, patented bow design, in which the high points of the bows are offset alternately. This produces significant drag force reduction without reducing the strength of the unit or its capacity to centralize the casing once in the open hole. In the open hole the UROS’s characteristics are those of a gauge hole centralizer so maximising stand-off.

UROS centralizers are now increasingly being used in South American and Norwegian offshore operations. Many of the Norwegian wells have a high risk of wash-out sections (i.e. open-hole sections larger than the original hole size), generally caused by soft or unconsolidated formations.

Centek centralizers have proved remarkably resilient when casing has had to be pulled. On one occasion casing was pulled twice and each time the UROS centralizers were undamaged and the rig team could simply rerun the same centralizers. These centralizers are individually

SPECIAL REPORT: NEXT GENERATION CENTRALIZER SOLUTIONS

PULLED BUT UNDAMAGED UROS CENTRALIZERS

designed to fit each wellbore instead of relying on gauge hole design, and secure stop collar technology ensures there is no centralizer movement on run in or pull out.

The UROS is available in sizes from 7.5/8 in. through to 20 inch with additional sizes being continuously developed as required.

Centek Group Centek Group opened a US manufacturing subsidiary in September 2012 based in Oklahoma City, Oklahoma, USA. The 88,000 square feet plant is fully self-sufficient in all aspects of centralizer manufacture with its own heat treatment and laser cutting equipment.

The workforce has now grown four times to 92 operatives producing around 35,000 centralizers a month. The factory manufactures the widely used Centek S2 bow-spring centralizer for the US, Canadian and Mexican markets.

When choosing a centralizer careful consideration, including the use of modeling software, must be given to the flow by area, desired stand-off, well strength and geometry, the zonal isolation required, and the degree of centralizer flexibility needed to traverse known formations, as well as an evaluation of start and running forces. Centek uses its advanced simulation and modelling software to produce dynamic calculations which are used to design customised centralizers based on the characteristics of each well.

Biography of Cliff Berry Cliff Berry’s oilfield career started in 1979 with Halliburton in Brunei, Malaysia and Sarawak as a cementer and tool operator. He worked, also, offshore in the North Sea and Persian Gulf with Halliburton. He then worked for Diamond B (UK) Limited, a leading centralizer manufacturer in the mid 1980s. Cliff joined BJ Tubular Services as European Operations Manager working from the German office and successfully introduced BJ Tubular Services into Denmark, Hungary, and Holland in addition to growth in Germany. He joined Centek in 2001 as Sales and Marketing Manager responsible for worldwide sales and was appointed VP Global Business Development at Centek Group in June 2012. He can be reached at cliff.berry@centekgroup.com.

UK Office: Centek Group, Forde Rd, Brunel Industrial Estate, Newton Abbot, Devon, TQ12 4AE Tel. +44 1626 337636 Fax: +44 1626 353278 USA Office: Centek Inc, 5500 S.W. 36th Street, Oklahoma City, OK 73179 Tel. +1 405 250 8177 Email: sales@centekgroup.com Web: www.centekgroup.com

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A Big Business Needs Quality Solutions John Hancock, Editor Pushing technology to its limits means that equipment must be reliable and effective

The subsea offshore energy sector is going to be growing for some time into the future and, given the depletion and finite nature of most reserves accessible from land, producers will be looking to exploit ever more challenging conditions and depths

W

HILE THIS paper’s core focus is on Centralizing Solutions, in truth few aspects of offshore oil and gas can be viewed in isolation. Apart from the various technical and operational factors that need to be addressed and which are covered in this paper, we need also to consider the economic drivers that make any technology used in the sector worth developing and using, and the context in which equipment, in this case centralizers, can contribute to the larger picture of a prosperous and successful sector. With that in mind, we’ll open with an overview of the environment in which centralizing solutions have to work and contribute value.

No Quick Profits in Offshore Oil and Gas Oil and gas fields are not short term investments: on the contrary, to make a profit out of a field requires a very long commitment of up to 31 years, of which perhaps only 12 or 15 years will see the exploiting company achieve the kind of returns that make the whole operation worthwhile. Fidan Aliyeva’s 2011 presentation, Introduction to Oil & Gas Industry1, opened with a graph illustrating the life of an oilfield and starkly showing that peak production is an all too brief phenomenon.

However, with the steadily rising price of energy resources reflecting equally steadily rising levels of demand from a population growing not only in size but also in expectations of

FIG 1: OIL FIELD LIFE CYCLE. SOURCE FIDAN ALIYEVA

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life quality, what might have previously been unprofitable or low value production from a field can become worth exploiting. In one sense, the whole offshore oil and gas sector is a product of this economic fact. With offshore fields currently operating in the North Sea, the Gulf of Mexico and seas adjoining a number of US states, the Caspian Sea, Brazil, Canada, West Africa, South East Asia, Russia and the Persian Gulf to name but a few, plus new fields being discovered and developed all the time, offshore oil and gas is set to become very significant in the near-term.

A Real Growth Sector According to Jason Waldie, Associate Director at energy industry analysts, Douglas-Westwood, at the ‘Subsea Asia Conference’, Kuala Lumpur in June 20112, speaking about a growing side of the offshore carbon energy sector, the production and use of natural gas is set “to soar” in the period to 2021 with deep-water gas identified “to be of growing importance.” Part of this reflects the known quantities of exploitable carbon resources available beneath the oceans and part the fact that gas power plants require the lowest capital expenditure for the amount of energy they produce which fits well with the growing numbers and expectations of the population. Whether it’s oil or gas being produced, the subsea offshore energy sector is going to be growing for some time into the future and, given the depletion and finite nature of most reserves accessible from land, producers will be looking to exploit ever more challenging conditions and depths in order to win every possible drop of carbon-based fuel while longer term renewable resources are being developed.

In light of this reality, it’s natural that oil and gas businesses should endeavour to get the most value from all of the resources potentially available to them. There are several ways in which this can take place. In an increasing number of cases, the productive lives of oil fields are being extended as new technologies make it possible

SPECIAL REPORT: NEXT GENERATION CENTRALIZER SOLUTIONS

Getting the best from increasingly ‘used’ well bores will create a challenge for engineers charged with well development and maintenance for which the calibre and capabilities of the equipment at their disposal will become more important

subsea tiebacks to existing platforms. Therefore, platforms become ‘hubs’ and often their operational life is extended.”

Further on in the same article, it was explained, “More than half of the offshore oil and gas installations in the UK Sector of the North Sea have been operating for at least twenty years.

Most assets are approaching or operating beyond their original design intent. With the rise in oil and gas prices and advances in technology, there is an increasing requirement to extend the operational life of these assets.”

As well as extending the life for older fields there is another way in which growth can be achieved utilizing ‘in-situ’ facilities. As Offshore Technology explained in the March 2007 article, ‘Tieback Time’4, “Subsea tiebacks connecting new discoveries to existing facilities can extend the life of production infrastructure. They are becoming increasingly viable, both technically and economically… Exploiting new discoveries using existing production facilities is an important way of obtaining maximum value from existing infrastructure.” However, getting the best from increasingly ‘used’ well bores will create a challenge for engineers charged with well development and maintenance for which the calibre and capabilities of the equipment at their disposal will become more important.

Further and Deeper and viable to extract previously less accessible or less valuable reserves.

Key drivers of life extension programmes are demand and economics. Demand grows as populations swell and nations move from ‘third world’ to ‘emerging’ and ‘developed’ status.

The national production and improvement programmes accompanying development need to be fuelled which means that ever more oil and gas reserves have to be found and produced.

That, in turn, also drives the economic case for field life extension as increased demand meets finite resources, causing prices to rise. As a result, reserves whose exploitation might not previously have been worthwhile become economically exploitable. Also, with the cost of capital items being so great, purchasing new equipment and structures can significantly offset any economic benefit so the opportunity to access increased productive life from equipment already in-situ will be welcome.

Life Extension The Journal of Petroleum Technology, February 2012 edition3 sums up the situation. “To keep capital and operational expenditures at a minimum, there is an increasing requirement from operators to use existing infrastructure, and, consequently, there is a trend to use

As well as extending the life of current fields, operators are seeking oil and gas in ever more inhospitable environments. In the drive to develop further exploitable energy reserves to meet our growing needs during the time until renewable resources have been developed to a level of efficiency and utility comparable with current resources, producers are looking to ever more inaccessible and technically challenging reserves – and these are mainly subsea and offshore.

Estimates suggest that offshore oil production will account for 34% of the global total by 2020 and that, within that figure, 13% will be attributable to deep-water installations. A further dimension of stress can be added for those producers who plan to explore and exploit Artic reserves.

The ‘quid pro quo’ of this trend is that equipment will be under ever greater levels of stress and the consequences associated with failure will be ever more daunting. In such circumstances, the quality and effectiveness of equipment becomes even more critical than usual in this already demanding industry. And that, for the purposes of this paper, means the quality and effectiveness of centralizing solutions. As will be seen in the remaining articles, centralizers play a very important role in the development, preparation and continual operation of offshore oil and gas facilities.

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Drilling at Depth for Oil and Gas Peter Dunwell, Correspondent

Not all oil deposits are conveniently located under land or below shallow waters, which means that, while many of the more easily accessible fields are already well into their productive life, new reserves are increasingly located beneath deep oceans

Complex Access in Difficult Places

Finding Reserves then Exploiting Them

“… most of the world’s petroleum is trapped between 500 and 25,000 feet (152 and 7,620 meters) under dirt and rock.” Is how Robert Lamb describes the presence and location of oil and gas reserves in his article, ‘How Offshore Drilling Works’5 for ‘How Stuff Works’. That reality is what accounts for most of the high tech and very costly equipment, not to say the sophisticated processes and software solutions that are associated with any oil and gas extraction program. However, what it all boils down to is that in order to access oil and gas reserves, it is necessary to drill a hole in the Earth’s surface and then to maintain that hole to convey the product to the surface where it can be processed, refined, and used.

To compound these engineering challenges, not all oil deposits are conveniently located under land or below shallow waters, which means that, while many of the more easily accessible fields are already well into their productive life, new reserves are increasingly located beneath deep oceans and even beneath the Arctic ice. Nevertheless, every field, whether onshore or offshore… in shallow or deep water, passes through a number of life stages: exploration, proving reserves, building and installing structures, production and maintenance, decommissioning, and dismantling or making safe. At each stage different techniques and technologies are required and for this article we’re going to focus on drilling which, when conducted offshore in deep water and challenging conditions, can make particular demands of equipment such as centralizers.

While the presence of oil and gas reserves beneath the deep oceans has long been known, their exploitation has not, until relatively recent times, been deemed viable or feasible. However, with changes in the economic climate (see previous article) and technological advances, deep-water or deep well drilling is now considered both viable and feasible for an increasing number of remote offshore oil and gas fields.

Even before the engineering begins, as the ‘How Stuff Works’ article (see above) explains, “Once oil companies have identified a possible undersea oil deposit, they have to obtain drilling rights. Most of the coast and ocean belong to states or nations, so companies have to lease desired areas from the respective government.”

Then there is the task of locating oil and gas reserves. In another article for ‘How Stuff Works’ (‘How Oil Drilling Works’) Craig Freudenrich and Jonathan Strickland explain, “… geologists are the ones responsible for finding oil. Their task is to find the right conditions for an oil trap – the right source rock, reservoir rock and entrapment.”

Having obtained a license and established the offshore presence of oil and gas deposits, oil companies then identify the sites most likely to produce oil before taking a mobile offshore drilling unit (MODU) to the site to drill the initial well and establish whether there are economic oil deposits there. The part of the drill that extends below the MODU deck and through the water is called the riser. The riser allows for drilling fluids to move between the floor and the rig. Engineers lower a drill string – a series of pipes designed to drill down to the oil deposit – through the riser.” The centralizer plays a key part in ensuring this part of the system continues to function efficiently.

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There are four main types of MODUs: •A submersible MODU usually consists of a barge that rests on the sea floor at depths of around 30 to 35 feet (9.1 to 10.7 meters) in areas with calm water.

•A jackup rig sits on top of a floating barge and can extend legs down to the sea floor. Jackups can operate in depths of up to 525 feet (160 meters).

•D rill ships can pilot to the drill site then use anchors and propellers to correct for drift as the rig drills for oil. They can operate in deep water conditions.

•S emisubmersibles float on the surface of the ocean on top of submerged pontoons using several anchors to maintain orientation. Computers control the tension on each anchor chain to correct for drift.

All of this presents a number of engineering challenges whose complex characteristics are also reflected in the variety of drilling and production facilities available to the sector including fixed platforms, jack-up drilling rigs, floating drilling rigs, TLP (tension-leg platforms), spars and FPSOs (floating production, storage and offloading systems).

with several allowances for the offshore environment. A conduit made from lengths of steel pipe permits drilling fluids to move between the rig-at the water’s surface-and the sea floor.

This conduit is called a “riser.” The riser is fitted with ball-and-slip joints that permit the long string of riser pipe to move up and down and bend slightly with the wave-induced movement of the rig.”

With such levels of challenge and risk and the innate complexity of almost every solution applied in offshore drilling, accuracy and placement of drills and associated equipment become critical to the success of the operation.

As a result of this there several systems designed to bring higher levels of predictability and consistency in structures where neither of those might be an inherent quality. High on that list are centralizers which help manage difficult engineering tasks in holes subject to distortion from geological pressure or, simply, wear and tear.

Challenges Offshore drilling itself presents a number of unique challenges not only from the engineering point of view but also from the degree of environmental risk and high levels of potential damage should that risk become a reality.

Diamond Offshore6 explains some of the challenges; “Offshore wells are drilled in much the same way as their onshore counterparts,

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Supporting Drilling and Production Francis Slade, Staff Writer Casing and cementing provide access and stability through engineering

The production tubing is usually more resistant to corrosion and is not cemented into the casing so that any maintenance or remedial work or indeed well improvement can be managed

An Engineering Challenge An oil well is a complex piece of engineering and even the hole which connects the reservoir to the surface is far from a simple job. Within the hole – and lining it – will be a number of concentric casings, their diameters decreasing at each level of depth and all held in place by a special type of cement placed between the casing and the cut surfaces of the well hole. This means that engineers must ensure that, as well as each casing being capable of allowing the next concentric unit to be passed down, the whole borehole has to be of sufficient diameter to contain the casings at each level as well as the cement holding them in place and, hopefully, stabilising any local ground movement.

Casing Wells include a number of types and sizes of casing at different depths and for different purposes. Conductor casing supports drilling operations, transporting the drilled spoil back to the surface and facilitating cementing of the surface casing. Surface casing is probably the most important in regulatory terms inasmuch as, in offshore operations, it is what keeps the product from contaminating the water around the wellhead. Beneath that, a number of casing strings of reducing diameters support the drilling down to the reservoir and then provide the workspace within which production tubing can be installed.

Casing that is cemented in place aids the drilling process in several ways7: •P revents contamination of fresh water well zones.

•P revents unstable upper formations from caving-in and sticking the drill string or forming large caverns.

•P rovides a strong upper foundation to use high-density drilling fluid to continue drilling deeper.

• I solates different zones, that may have different pressures or fluids – known as zonal

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isolation, in the drilled formations from one another.

• Seals off high pressure zones from the surface, avoiding potential for a blowout • Prevents fluid loss into or contamination of production zones.

• Provides a smooth internal bore for installing production equipment.

Production tubing is often used without cement to contain production fluids and convey them to the surface from an underground reservoir.

Whereas the main casing with the cement serves an important structural and access purpose, being made of steel it can be subject to corrosion from the product and the chemicals contained within it. The production tubing is usually more resistant to corrosion and is not cemented into the casing so that any maintenance or remedial work or indeed well improvement can be managed.

Geology Geological uncertainties may make it difficult to predict the expected drilling environment. For example, crossing a fault line into a high-pressure region may necessitate a drilling liner whereas an intermediate string may be satisfactory if the fault is not encountered. Hole geometries are often selected to allow the options for an additional casing string if required8.

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“To design a reliable casing string, it is necessary to know the strength of pipe under different load conditions.”9 Also, as boreholes move away from the vertical to angled geometry to access ever more difficult reserves, it becomes increasingly challenging to ensure the correct placement of casing units, production piping and other equipment centrally within the borehole.

Cementing What holds the whole thing together, almost literally, is cement. It fixes the casings within the drilled borehole and stabilises that hole within the surrounding ground. However, like almost everything else in this business, cementing is not as straightforward as it sounds. Correctly installed it is part of the overall engineering of the well. As a result there are some fairly strict rules as to how cementing is carried out and to what standards. Typical would be the ‘Well Construction Standards’ issued by the UK Health and Safety Executive (HSE)10.

“All hydrocarbon bearing zones should be isolated from surface. For all cementing operations, whether primary, remedial or plugging, the cement should be placed and checks carried out to ensure that the cementing objectives are achieved…

Intermediate and production casing should, where appropriate, be cemented back to the previous casing shoe and preferably back to the mud-line for shallow strings…

Exceptions to the requirement for cementing back to the previous casing shoe are: • Where it precludes a later well sidetrack; • I n a subsea well where the casing annuli cannot be bled down (i.e. for thermal expansion where the leak-off gradient in the open hole beneath the casing shoe provides a pressure limit); •T o prevent losses or break-down of weak formations; • Or cuttings injection down a well annulus.

FIG 2: CASING PROGRAMME. SOURCE: SCHLUMBERGER & RIGZONE

The density of cement must be suitable for the proposed operation in question.”

Cementing takes place in the annulus, the space between the casing and the sides of the drilled hole. For optimum stability, it is important that the casing remains as close as possible to the centre of the hole to ensure equal protection and pressure resistance in the cement around the casing. Cementing is achieved by piping cement slurry through the insider casing and then out into the annulus through the casing shoe at the bottom of the casing string. To avoid the risk of cement coming back into the casing, a float, is placed above the casing shoe to act as a check valve.

“Sometimes the well is drilled in stages called a casing program. Here, a well is drilled to a certain depth, cased and cemented, and then the well is drilled to a deeper depth, cased and cemented again, and so on.”11 s we said at the beginning of this article, drilling a well and maintaining the hole in operation with strings of casings and production lines is a complex engineering feat for which any aid to accuracy will be welcome.

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Under-Reaming and Centralizing John Hancock, Editor Techniques that ensure the best building and operation of a well

The well is drilled using a length of slender steel pipes and other tools that, connected, comprise a ‘drill string’.

At the bottom of the string of pipes is a holeboring device called a ‘drill bit’. Heavy sections of pipe, called ‘drill collars’, add weight and stability to the drill bit

Hole Geometry Contrary to popular belief, there is no automatic link between drilling an oil well and realising a return, leave alone a profit. As previous articles in this paper have shown, there is much engineering to be considered in the context of drilling equipping and operating an oil well in any environment, but especially in offshore conditions.

These engineering tasks are often grouped under the heading ‘hole geometry’ and the profitability or not of an installation can turn on how successful the engineers are in achieving the best geometry for the well.

In the article ‘Hole geometry’ Petrowiki12 explains the whole process in some detail, highlighting the various steps in inputs that can make the difference between a successful and failed well.

As the article says, “The drilling engineer (and well planner) is responsible for designing the hole geometry … Hole-geometry selection is a part of the engineering plan that can make the difference between economic and engineering failure or success.”

Drilling – Not a Simple Process In the article ‘Offshore Drilling Basics’, Diamond Offshore13 manages to explain the drilling process succinctly and yet convey the complexity that accompanies every operation. “The well is drilled using a length of slender steel pipes and other tools that, connected, comprise a ‘drill string’. At the bottom of the string of pipes is a hole-boring device called a ‘drill bit’. Heavy sections of pipe, called ‘drill collars’, add weight and stability to the drill bit. Each ordinary pipe in the string is about 30 feet long and weighs about 600 pounds; drill collars can weigh 4,000 Pounds or more per 30-foot length.”

Even the drilled hole itself is not a simple cylindrical space bored into the ground. There are numerous different techniques used to ensure that each section of the hole is able

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to accommodate the equipment and material necessary for various stages of the process or, later in the well’s life, to help strengthen or stabilise the well, sometimes as part of a life extension programme. One of these is under-reaming.

Under-Reaming – Back in Fashion for the Right Job Referring to the Petrowiki article again, it neatly describes under-reaming as a, “… technique [that] enlarges the hole size in excess of the amount attainable with a drill bit… This technique does have applications in some areas. One important application involves running a liner in an open hole that might be considered too small without under-reaming…”

The UnderReamer (UR™) tool enlarges the hole by passing through [any] restriction and expanding the cutter arms which enlarges the hole to the prescribed diameter.14 This description from Halliburton continues to explain that the tool is activated by hydraulic force which opens the three cutter arms. Typical applications for the UR tool are enlarging a pre-existing pilot hole, such as when: •U nexpected remedial under-reaming jobs for running expandable casing/liners; • Gravel packing work-over; • Gravel packing for gas storage wells; • Coalbed methane applications; •T op hole section enlargement when a surface diameter restriction is present.

There are problems with an under-reamed well as Cliff Berry explained in ‘Engineer Live’15; “Underreaming is a drilling technique for enlarging the diameter of a borehole in order to increase the potential for achieving a good cement job.

A major problem with under-reamed wells is getting effective casing centralisation in the underreamed section.”

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But such problems should not deter operators from using the technique. The Petrowiki paper ‘Underreaming: Old Method With New Technology’16 opens with; “Underreaming is a highly underrated technology. It has been viewed primarily as an undesirable, yet often inevitable, cost in too many wells or standard methodology in remedial applications. Recent advances in deeper drilling have created the need for multiplecasing strings in straight and directional wells. As a result, the demand for more durable, reliable underreamers has increased. Underreaming allows the operator to run minimum clearance casing programs which optimize casing sizes and reduce tubular costs on multiple-string wells.”

Centralizers – Keeping Everything Where It Needs To Be Under-reaming and deep wells pose a particular challenge for one important tool in the well engineer’s tool box: the centralizer. To achieve

optimum effectiveness, casing strings need to be placed as near the centre of the well bore as possible. A poorly centred casing string might, at some points, be touching the formation through which the well has been drilled.

At those points there is a risk that an imperfect seal will occur, which can allow undesirable contaminations.

The task of centralizing falls to the centralizer, a device which keeps the casing in the centre of a well bore traditionally using a combination of bowsprings and a hinged collar to maintain centring pressure and allow some flexibility.

There are two types of centralizers. The older and more common design is the bowspring type described above, offering simplicity and low-cost for vertical or only slightly deviated wells but lacking the strength to support the weight of casing in wells with high degrees of deviation.

The second type of centralizer is the rigid blade design which works better in deviated well bores but costs more and works best in well bores that are already in good condition. Centralizers are available to fit all common casing and hole size combinations and are designed to offer least resistance to the bore or casing sides against which they are centralizing.

Centralizers can also assist with the accurate placing of tool strings and tools in the casing. In these events, the device used is most often a slip over Centralizer which is placed on the outside of the tool string. Tool centralisation can help to avoid any obstructions on the wellbore wall and can ensure the efficient placing of materials to provide maximum effectiveness. The centralizer might be a simple idea but it is a key component in the good running of a well.

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References: 1

Introduction to Oil & Gas Industry http://www.slideshare.net/fidan/oil-gas-disciplines go to slide 2/15

2

Jason Waldie at the ‘Subsea Asia Conference’, Kuala Lumpur

http://www.subseauk.com/documents/subsea%20asia%20-%20jason%20waldie.pdf 3

The Journal of Petroleum Technology

http://www.mydigitalpublication.com/article/Offshore+Oil+and+Gas+Installation%E2%80%94Aging+and+Life+Extension/951953/0/article.html 4

Offshore Technology, ‘Tieback Time’ http://www.offshore-technology.com/features/feature1033/

5

How Stuff Works http://science.howstuffworks.com/environmental/energy/offshore-drilling.htm/printable

6

Diamond Offshore http://www.diamondoffshore.com/offshore-drilling-basics

7

Wikipedia http://en.wikipedia.org/wiki/Casing_%28borehole%29

8

Petrowiki http://petrowiki.spe.org/index.php?title=Hole_geometry&printable=yes

9

Petrowiki, ‘Casing and tubing’ http://petrowiki.spe.org/Casing_and_tubing

10

Well Construction Standards UK Health and Safety Executive http://www.hse.gov.uk/foi/internalops/hid_circs/technical_general/spc_tech_gen_42.htm

11

Rigzone, ‘How Does Casing Work?’ http://www.rigzone.com/training/insight.asp?insight_id=333&c_id=24

12

Petrowiki http://petrowiki.spe.org/index.php?title=Hole_geometry&printable=yes

13

Diamond Offshore http://www.diamondoffshore.com/offshore-drilling-basics

14

Halliburton http://www.halliburton.com/en-US/ps/drill-bits/hole-enlargement/conventional-drilling/underreamer-heavy-duty-hole-enlargement-tool.page

16

Engineer Live http://www.engineerlive.com/content/22351

17

One Petro http://www.onepetro.org/mslib/servlet/onepetropreview?id=00018693

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