Special Report – Next Generation Offshore Intelligent Gas Lift Technology Camcon

Special Report

Next Generation Offshore Intelligent Gas Lift Technology

Digital Gas Lift Changes the Game Whatever It Is, It’s About The Money New Life from Old Fields Enhanced Oil Recovery (EOR) Gas Lift – The Offshore Game Changer

Sponsored by

Published by Global Business Media

SPECIAL REPORT

Next Generation Offshore Intelligent Gas Lift Technology

SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

Contents

Digital Gas Lift Changes the Game Whatever It Is, It’s About The Money New Life from Old Fields Enhanced Oil Recovery (EOR) Gas Lift – The Offshore Game Changer

Foreword

2

John Hancock, Editor

Digital Gas Lift Changes the Game

3

Ian Anderson, Camcon Oil

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 Publisher Kevin Bell Business Development Director Marie-Anne Brooks 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.

The Need to Increase Recovery Rates The Continuing Growth of Artificial Lift Real-Time Digital Gas Lift Operations – APOLLO Recent Simulation Modelling Analysis Installation in Oman Shifting the Economic Operating Point

Whatever It Is, It’s About The Money

7

John Hancock, Editor

Global Economic Growth Drives Demand Growth Full Value From Available Reserves Increasing Productivity Getting Older and Weaker

New Life From Old Fields

9

Francis Slade, Staff Writer

How to Get More Oil Extended Field Life Methods Used to Extend Field Life The Economic Case for Life Extension

Enhanced Oil Recovery (EOR)

11

John Hancock, Editor

Methods to Achieve Artificial Lift Not Just the Methods EOR Works

Gas Lift – The Offshore Game Changer

13

Peter Dunwell, Correspondent

A System That Works A Productive Boost And It’s Green Mechanical to Digital

References 15

© 2013. The entire contents of this publication are protected by copyright. Full details are available from the Publishers. All rights reserved.

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SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

Foreword A

s an industry, oil and gas production makes

fields now look more attractive to their owners and

use of the latest techniques and technologies,

operators. We consider how increased demand and

especially when they can improve productivity,

rising prices can mean that even quite small fields are

extend productive life or reduce costs. Intelligent

worth exploiting.

gas lift technology can contribute on all three fronts.

Then, Francis Slade looks at the area of field life

But like many systems, the process does not stand

extension. Given the presently low rates of exploitation

still: it has developed to match the demands of

of current fields, the exponentially growing levels of

the industry and to apply the latest technology to

demand (likely to be even faster as the recession

even further improve viability and productivity of oil

recedes into the past) and the fact that offshore

fields. In this Report, we cover not only the latest

oil fields are so expensive to develop and operate,

technology but also consider the contexts in which

getting the longest possible life from them makes

it is deployed and why.

sense on all levels.

The opening article looks at the problem of well

The article on enhanced oil recovery (EOR)

instability – one of the biggest challenges of operating

explores not only the technologies used but also the

in older fields and improving recovery rates. It goes on

application of EOR at all stages in a well’s life; albeit

to describe gas lift, a leading technology addressing

that the process is most often associated with wells

the issues of well instability and enhancing production

that have passed their productive best.

from today’s offshore fields. However, due to lack of

Finally, Peter Dunwell reviews gas lift and gas

innovation, gas lift has significant operator limitations.

injection, two similar technologies that help

These have been addressed by Camcon Oil, who

productivity in different ways. He looks at the way

have recently developed APOLLO, a new digital

the technology works, some of its drawbacks using

solution for gas lift. APOLLO is based around a

old technology and how new technology can help

proprietary Binary Actuation Technology (BAT),

to make it more effective. He also considers the

which provides greater flexibility than traditional gas lift

contribution it can make to a greener planet.

applications. Reports have shown that APOLLO can produce up to 110% increase in production compared to traditional gas lift equipment.

Our second article looks at the economic imperative that makes previously uneconomic or unviable

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 OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

Digital Gas Lift Changes the Game Ian Anderson, Camcon Oil There’s a strong industry need for greater operator control over gas lift operations and the ability to tackle fluctuating well conditions and potential instability. Camcon’s digital gas lift solution, APOLLO, is proving an important alternative to traditional gas lift operations.

Ian Anderson, Camcon COO

The Need to Increase Recovery Rates With no more ‘easy oil’ and an increasing focus on cost per barrel in production, operators’ attention is switching to improved recovery rates and extraction efficiency. Globally, recovery rates languish at 35% (Source: Statoil) leaving over 2/3 of reserves in-situ historically.

According to the Norwegian Petroleum Directorate for example, only 40% of the expected total recoverable resources on the Norwegian Continental Shelf (NCS) have been produced, with the remaining resources representing a substantial “potential of value creation for many years to come.”

The Middle East is another region where operators are renewing their focus on existing assets. Saudi Aramco, for example, have set recovery rate targets of up to 70% in certain fields and in Oman, significant recovery rates have already been achieved. Other high profile fields in the region include the offshore Satah field development project in the United Arab Emirates where the operator, ZADCO, has introduced gas injection and gas lift facilities.

One of the biggest challenges of operating in older fields and improving recovery rates, however, is that of well instability.

Well instability can result from a number of causes. These include the increased danger of water and gas breakthrough in the wells – something which can impact production capabilities significantly; slugging – the accumulation of water, oil or condensates in the pipeline; or increased well pressures.

Furthermore, as wells and reservoirs get older, liquid rates begin to decrease resulting in wells becoming more sensitive to flow instabilities.

At a time where there is often a wide range of conditions and fluctuating flow rates and pressures, the potential threats to reservoir performance and recovery rates are significant.

So how are today’s technologies addressing the issues around well stability and enhancing production from today’s offshore fields?

Leading the way is artificial lift.

The Continuing Growth of Artificial Lift Artificial lift remains the pre-eminent Enhanced Oil Revovery (EOR) technology today. According to a recent study by MarketsandMarkets of Dallas, the global artificial lift market, was estimated to be US$9.3 billion in 2012 and is forecast to reach $16 billion by 2018. A recent article by Texas Tech and Marathon Oil confirms www.offshoretechnologyreports.com | 3

SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

A recent article by Texas Tech and Marathon Oil confirms that 95% of the world’s producing wells rely on some form of artificial lift at some point in their production life cycles

that 95% of the world’s producing wells rely on some form of artificial lift at some point in their production life cycles.

While techniques such as ESP (Electrical Submersible Pumps) and multiphase boosting have tended to receive most attention, gas lift is also receiving recognition as a means of improving recovery rates. In gas lift, gases, such as CO2, natural gas or nitrogen, are injected into the production tubing to reduce the impact of the hydrostatic pressure where reservoir pressures are not sufficient to lift the hydrocarbons to the surface.

Gas Lift is particularly effective offshore with an unparalleled reliability, the ability to handle a wide range of flow conditions, contaminated fluids, high volume and HT/HP. However, due to a historic lack of innovation, it does come with significant operator limitations.

Side pocket mandrel gas lift requires wireline interventions to change the operating valve when injection rate changes are necessary.

Such interventions can be a long, costly and cumbersome process, leading to damage to existing infrastructure (if the wireline snaps, for example) and the halting of production as a new side mandrel unit is installed.

Furthermore, side mandrel tools have no instrumentation on board. The result is that operators have little to no information on pressures and temperatures at the point of gas injection and no control and flexibility over altering injection rates in real-time or depths as production variables change.

From an operating perspective, a significant drawback of side-pocket mandrels is the fact that they are Injection Pressure Operated (IPO) with the side pocket mandrel functioning at a pre-determined annulus gas pressure, which can lead to severe restrictions and increase the possibility of unstable offshore wells. Annulus pressure fluctuations can often create ‘multipointing’ injections and require resources to travel to the wellhead to choke the annulus gas supply to compensate.

All too often with such limitations, monitoring gas lifted wells is confined to being a basic ‘tick-box’ approach, focusing on wellhead pressure and the occasional fluid level or downhole pressure reading rather than any consistent real-time data.

It is this lack of flexibility in gas lift operations that requires operators to make assumptions about the field conditions where they operate and determines the gas lift design. And it is this lack of control which has led to the rise of alternative artificial lift mechanisms such as ESP in spite of their substantial drawbacks.

With offshore reservoirs constantly changing in regard to pressures, flow rates and water cuts, the case for real-time digital gas lift operations

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has never been stronger. These combine the reliability and robustness of Gas Lift with the flexibility of ESP.

Real-Time Digital Gas Lift Operations – APOLLO

Camcon’s APOLLO 1

It’s with these challenges in mind that Camcon recently developed a new digital solution for gas lift called APOLLO. APOLLO is in direct response to operators’ needs to have access to variable operating valve combinations in their artificial lift operations, where decisions and modifications can be made in realtime without intervention and without threats to well stability. Camcon believes that its new digital gas lift solution can deliver a Return on Investment of at least 20% and has the potential to increase recovery from individual wells by up to 30%.

APOLLO is based around a proprietary Binary Actuation Technology (BAT) consisting of a low energy pulse control which signals to switch an actuator between two stable positions to operate a valve, replacing the functionality of side pocket mandrels. Because each APOLLO unit has multiple valves, which can be operated independently from the surface, this eliminates the need for wireline intervention. Settings are tuned as well-bore conditions change through the life of the installation, giving greater downhole control of gas-usage and preventing well instability.

In this way, operators can vary injection rates and depth in real-time without production interruption and well intervention, and generate pressure and temperature information throughout the gas injection process. Furthermore, the

SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

electronically actuated valves don’t face the restriction of being Injection Pressure Operated.

The new digital solution also provides operators with continuous real-time information on pressure and temperature within the annulus and the production tubing at the point of gas injection.

Having live information allows operators to optimise operating parameters and minimise gas usage without expensive and potentially risky slickline intervention.

Another significant advantage of the new solution is that the orifice size is not fixed so that it can be varied on demand.

With traditional gas lift applications, operators often have to size the conventional gas lift orifice for a very limited gas injection range. Over the life of the well, a higher injection rate may be desirable but not achievable as a potentially impractical higher injection pressure will be required. Likewise, a lower injection rate may be desirable but not achievable as the lower pressure drop across the orifice may potentially lead to instability. APOLLO provides greater flexibility.

Recent Simulation Modelling Analysis A recent simulation modelling analysis, conducted

by Laing Engineering & Training Services (LETS), illustrates the benefits of APOLLO for delivering improved production rates at different stages of the reservoir lifecycle and within stable wells.

The report found that APOLLO can deliver as much as 1,000 BOPD (Barrels of Oil per Day)

more oil production from a typical well and, in one scenario, a 110% increase in production compared to traditional gas lift equipment.

The analysis compared the performance of a standard, multi-mandrel gas lift design with APOLLO to identify the maximum practically achievable production rates alongside the maximum practically achievable gas injection rates.

Several well life scenarios were generated.

These were between one day and three months – where there would be high, dropping to moderate, pressures and no water cut; mid-life at one year, where there would be water injection for reservoir pressure maintenance and low water cut; and a later life well at three years where the reservoir is re-pressured and there would be a higher water cut.

In all these contexts, APOLLO was able to adapt to the different conditions to ensure well stability and deliver increased recovery rates.

The analysis found that the two scenarios deriving most benefit from gas lift are at the early life stage after three months and the mid-life stage with water injection support.

Figure 1, for example, shows the BOPD comparisons at the three month life cycle stage for 3 potential PI values with APOLLO already showing increased BOPD. The mid-life stage is particularly important as reservoir pressure has fallen to an extent that it cannot support natural production. Here, figure 2 shows improved BOPD with APOLLO,

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SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

The new digital solution

which can also set higher injection rates at 3.0 MMSCFD.

Installation in Oman

also provides operators with continuous real-time information on pressure and temperature within the annulus and the production tubing at the point of gas injection

It’s on the back of these successful modelling results that Camcon recently oversaw the first deployment of APOLLO in a well in Oman with PDO (Petroleum Development Oman).

The deployment is part of a normal work over program for a high productivity well where the new intelligent gas lift method will be used to improve the production performance of the well.

Although a test installation, the equipment has been selected as the chosen method of lifting for the well. The installation has also taken place with the results expected over the next few months.

Shifting the Economic Operating Point There’s a strong industry need for greater operator control over gas lift operations and the ability to tackle fluctuating well conditions and potential instability.

It’s with this in mind that Camcon’s APOLLO is leading the way, providing an important shift in the Economic Operating Point of wells by bringing non-viable fields back into production, maximising the lifetime of existing oilfields, and providing realtime production support by monitoring the well’s flow conditions. The era of digital gas lift is well and truly upon us!

Contact

Camcon’s Offices

Camcon Oil Unit 6 Burlington Park Station Road Foxton Cambridgeshire CB22 6SA United Kingdom Tel: +44 1223873650 www.camcon-oil.com

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SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

Whatever It Is, It’s About The Money John Hancock, Editor Even the most advanced technology has to justify its cost in normal business terms

This paper is about intelligent gas lift technology but everything has to be in a context. In this case, growing demand for energy which, in the foreseeable future, cannot be wholly met from renewable or sustainable resources – with the possible exception of nuclear. Therefore, demand will have to be met from resources whose acquisition and application we are wellpractised… largely oil and gas.

Global Economic Growth Drives Demand Growth Despite recent noise about global recession, global energy requirements have risen inexorably with the continuing long term growth of economies at all stages in the development cycle and the ever increasing demands and expectations of rapidly growing populations.

As a typical and globally significant example, take the USA. In an FT online August 2013 article (available to FT subscribers) ‘US oil demand rises at fastest pace in two years’, Ajay Makan confirmed that, “Data from the International Energy Agency show that demand for oil in the US increased in four of the first six months of the year [2013]”. The article continued to state that, “Signs of recovery in the US economy have been associated with rising oil consumption in recent months…” Factor into that, growing instability in traditional Middle East oil and gas producers and it is easy to see why any technology to maximise the return from oil and gas fields, especially those in offshore waters, is going to attract interest.

The subsea sector is growing: industry analysts Douglas-Westwood1 has predicted that some $77 billion will be spent on subsea operations, new field development and well intervention in the period between 2012 and 2016. Whether it’s to support the latest subsea technologies or the on-going operation of life-extended subsea installations dating back to the 1980s, the demand for the means to get best value from those investments will remain high and growing as the industry grows.

According to Infield Systems’ latest research published in late February 20132, “… the subsea

industry is amongst the most promising in the offshore oil and gas world, with subsea capital expenditure (Capex) set to grow at a staggering 14.8% CAGR (compound annual growth rate) to 2017.”

Everything is driven by demand. “The subsea oil and gas market continues to grow at an increasing pace, as oil and gas operators continue to discover reserves in deeper water areas where the only economically viable recovery solution is a subsea development.” Was the conclusion of Infield ‘Subsea Well Intervention Market Report to 2017’3.

With these levels of investment to meet growing global demand, operators will wish to extract maximum value from exploitable reserves to which they have access.

Full Value From Available Reserves According to the Subsea Oil & Gas Directory review of The Subsea Industry4, “The subsea oil and gas industry is changing… towards marginal field development [and] smaller tie backs to already developed fields...”

Energy businesses have been driven to seek ways in which the most value can be economically extracted from reserves of carbon based fuels. In reality, most of the world’s carbon fuel reserves are already known but not all are yet exploited, usually because virgin reserves tend to be in inaccessible or inhospitable environments or the cost of lifting product out of established reserves is no longer economic. However, as we know, when the price is right and can be realised, producers will undertake extraordinary engineering and technology programmes in pursuit of product. And so it is with deep sea exploration for and production of oil and gas.

This has spurred an enormous growth in the offshore oil and gas sector. Much of the headline making progress has been in the area of finding new deposits and reserves but there are plenty of known reserves that could add significantly to global energy resources if a way could be found to further and profitably exploit them. www.offshoretechnologyreports.com | 7

SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

When the pressure differential is insufficient for the oil to flow naturally, some method of lifting the liquids, such as mechanical pumps, must be used to bring the oil to the surface

Increasing Productivity In this business environment, oil and gas suppliers will be looking at a whole range of options to increase production potential. How that potential is realised will depend on where exploitable reserves can be found. Sometimes it will mean extending the reach of production facilities to the more remote edges of a field; sometimes it will mean the simple life extension of an established field, using new technology to extract value from lower grade outputs and sometimes it will mean using the latest technology to economically exploit reserves previously deemed uneconomic.

Given the long lives of offshore fields (often longer than was ever intended); also, with the current trend to add new production facilities into old infrastructure in order to make less viable reserves economic to exploit, existing platforms might need to be equipped to handle products that were not in their original design specification or where the quality of the product has declined as the easier to lift reserves have been taken out.

Platforms might even be physically extended with the addition of or a link to another module in order to enable the structure to handle more of the production process. And, of course, increasing numbers of platforms are undergoing work to extend their operating life well into the 21st century in order to continue exploiting reserves that, with old technology, might not have been exploitable.

Getting Older and Weaker As fields age, their productivity falls. Canadian Oilwell Systems Company ‘Basic Artificial Lift’5 explains the phenomenon: “Reservoirs

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are typically at elevated pressure because of underground forces. The driving force in a reservoir is one of two main types: water drive or gas drive. A water drive reservoir is connected to an active water aquifer that provides the drive mechanism. A gas drive reservoir derives its energy from gas expansion; either from a gas cap or from gas breaking out of solution. Early in its production life, the underground pressure will often push the hydrocarbons all the way up the wellbore to the surface. Depending on reservoir conditions, this ‘natural flow’ may continue for many years. When the pressure differential is insufficient for the oil to flow naturally, some method of lifting the liquids, such as mechanical pumps, must be used to bring the oil to the surface.”

It isn’t only the fields whose economic exploitation is a driver. The assets used in the offshore sector are never cheap. They are usually engineered to the highest possible standards to operate in the challenging conditions and because failure carries unacceptable costs in lost production, shredded reputation and, worst of all, the risk of loss of life or of injury. High costs demand that maximum safe use is made of every asset. So, if the productivity of a reserve on which an asset is sited, deteriorates, there will be an enormous financial pressure to find means of re-establishing levels of productivity that, even allowing for the cost of any intervention, are still profitable.

It might be technology about which we are talking but, in the end, it all boils down to financial viability.

SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

New Life From Old Fields Francis Slade, Staff Writer Field life extension has become a process in its own right

How to Get More Oil There are several ways in which operators can produce more oil. One is to discover and exploit new reserves, but there numerous constraints on that, not least of which is that (Shale deposits apart) there are ever fewer undiscovered reserves in the world and those that there might be will, by definition, be located in ever less accessible places. Nevertheless, new reserves will continue to come on-stream for the next few decades at least and probably for longer as technology makes ever more difficult reserves both accessible and exploitable.

Another method is to bring on-stream fields that were initially thought uneconomic to exploit, usually because the probable product could not justify the full investment in field facilities, especially offshore. That is becoming less of an issue as older fields decline and the infrastructure used to exploit them becomes available for other fields at far less cost than that of new infrastructure. With long pipelines tying wells tapping smaller reserves back to established facilities, they can be profitable.

And yet another method is to improve the productivity of older fields where the natural pressure that once drove product to the surface has significantly declined with age and/or where the quality or viscosity of the product has made extraction increasingly difficult.

Extended Field Life Of the three methods above, the second two come under the broad heading of extended field life; i.e. profitably lifting product from a field after the end of its originally planned operating life. Patrick O’Brian, Group Director Strategic Business & Marketing at Wood Group Kenny, in his December 2012 Oil & Gas UK Presentation ‘Contribution of Subsea Technology to UKCS [UK Continental Shelf] Exploitation – Now and in the Future’6 said that “many UKCS projects have the potential for life extension… Subsea technology is making a very sizeable contribution towards the further exploitation and elongation of the UKCS, and will grow in this contribution into the future…. [and] Pipeline and riser transportation system technology continues apace to enable evermore

Another method is to improve the productivity of older fields where the natural pressure that once drove product to the surface has significantly declined with age and/ or where the quality or viscosity of the product has made extraction increasingly difficult difficult flow assurance conditions for: Higher temperatures and pressures… Longer, deeper and cooler tiebacks.”

Patrick O’Brian explained, also,“There is no ‘standard’ approach to recovering remaining North Sea reserves… While there are still ‘Greenfield’ projects; many projects are now ‘Brownfield’ developments or redevelopments… of abandoned fixed platform developments: e.g.

North West Hutton (Darwin).”

While he spoke principally about North Sea developments, as offshore fields across the world reach maturity and beyond, operators will wish to know whether new technology and the price of oil might make it worthwhile extending field life.

And among the challenges faced by any operator considering field life extension will be the matter of low flow rates as highlighted above. www.offshoretechnologyreports.com | 9

SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

To an increasing degree, well monitoring systems use the enormous processing power of modern IT systems to ensure that operators not only have the most up-tothe-minute reports of well conditions constantly updated, but that a wide range of conditions can be monitored

The journal Petroleum Technology, February 2012, addressed the challenges involved in keeping old fields running.7 “To keep capital and operational expenditures at a minimum, there is an increasing requirement from operators to use existing infrastructure... Therefore, platforms become ‘hubs’ and often their operational life is extended … Aging and life extension are major issues for the offshore oil and gas industry…”

One key element in achieving a successful extension to field life is going to be the continued operational integrity of infrastructure in the field.

If too much investment in new structures and equipment is needed to make the field usable past its design life, then the life extension programme might not be viable. But structures and equipment are not really in our brief here except inasmuch as they can support the technologies necessary to achieve continued production of fields whose natural productivity pressure might have declined or expired.

Methods Used to Extend Field Life Various methods are employed in field life extension but several of those are better suited to the onshore rather than the offshore environment.

One key management tool deployed in all fields but especially extended life fields is well monitoring. To an increasing degree, well monitoring systems use the enormous processing power of modern IT systems to ensure that operators not only have the most upto-the-minute reports of well conditions constantly updated, but that a wide range of conditions can be monitored and that they can be displayed in a user friendly manner for quick interpretation while clear dashboards make adjustments to the system and well very easy to achieve.

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James F Lea, Joe Woods, Herald W Winkler and Mark S Garrett in their World Oil article8, ‘What’s new in artificial lift?’ said of Well Monitoring, “In recent years, a growing emphasis has been placed on the timely monitoring, communicating and analyzing of well performance and production data [with the assistance of] new software and well monitoring equipment…

This software and hardware package takes advantage of the increase in laptop processing speed, memory size and screen resolution to generate, in real time, a quantitative visualization of the downhole rod pump operation, plunger motion, valve action and fluid flow… The new system’s miniaturized wireless instrumentation increases measurement flexibility, eliminates inaccuracies caused by defective cables and connectors, and greatly speeds up installation and tear-down.”

The Economic Case for Life Extension Whatever the technical issues to be overcome, demand and economics remain the two principal drivers of life extension programmes.

With more and more economies working to move from ‘third world’ to ‘emerging’ status (and, ultimately, on to ‘developed’), the requirement for energy to support that economic expansion means that ever more oil and gas reserves have to be found and produced which, in turn translates into ever greater demand. In part, that drives the economic case for field life extension because when increased demand meets finite resources, prices rise. And when prices rise, reserves whose exploitation might not previously have been worthwhile become economically exploitable.

SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

Enhanced Oil Recovery (EOR) John Hancock, Editor Having invested heavily in an oil production facility, it makes sense to use whatever methods are available to maximise productivity

Many of the world’s reserves of oil and gas have never been fully exploited. Indeed, according to some calculations, average recovery rates worldwide are at around 35% which means that some 65% of known reserves remain unrecovered. Part of the reason will be that, in earlier times, there was less economic pressure to recover hard to reach reserves when there were plenty of easily exploited fields capable of producing whatever the developed industrial world required. But that has changed with the shift in economic balance and overall global economic growth. There is a definite need to get the maximum product from any field.

Another reason for historically low rates of recovery might have been the technology needed to lift product from below the surface in ever more challenging conditions; or rather the absence of any such technology. Sub-sea and deep sea fields add significant top-side difficulties to the subterranean challenges that oil and gas producers have always faced. But, again, things are changing as technology and engineering make possible the exploitation of ever more difficult reserves. Technology also offers answers to the problems associated with aging fields, i.e. a decline in productivity to uneconomic levels as pressure falls and pollutants increase in density.

Although many fields in their early lives enjoy natural pressure to force oil and gas reserves to the surface, the industry has long employed artificial means to speed that process, help heavier products to the surface or compensate for any loss of natural pressure, usually a result of aging. Rigzone ‘How does gas injection work?’9 explains, “Typically, a well will produce at its highest production rate at the beginning of the production cycle; and then production will wane.

In an effort to increase production from both oil and natural gas wells, secondary production methods are employed. A type of Enhanced Oil Recovery (EOR), secondary production includes water flooding and gas injection.”

In a broader article, ‘What is EOR and How Does it Work?’10 Rigzone clarifies that, “Used

in fields that exhibit heavy oil, poor permeability and irregular fault lines, EOR entails changing the actual properties of the hydrocarbons, which further distinguishes this phase of recovery from the secondary recovery method. While water flooding and gas injection during the secondary recovery method are used to push the oil through the well, EOR applies steam or gas to change the makeup of the reservoir. Whether it is used after both primary and secondary recovery have been exhausted or at the initial stage of production, EOR restores formation pressure and enhances oil displacement in the reservoir. There are three main types of EOR, including chemical flooding, gas injection and thermal recovery.”

Methods to Achieve Artificial Lift Halliburton11 explains that artificial lift “is designed and operated to address individual customer production requirements and achieve a superior level of product performance and reliability.”

According to different conditions, a variety of pumps are employed including mechanical rod pumps, hydraulic pumps and progressive cavity pumps and, within each group, there are a number of differentiations and refinements.

Electrical submersible pumps (ESP) are very adaptable but there remain limitations as to what they can manage, especially when gas locks or internal corrosion are issues. But it isn’t only the devices for or methods of artificial lift that have to be considered.

Not Just the Methods In the World Oil article12 ‘What’s new in artificial lift’ the authors explain that, “Too often, the method used to select an artificial lift system is a ‘we’ve always done it this way’ decision process, rather than a strategic plan based on well optimization…

Proper selection of an artificial lift system should include an analysis of the individual well’s parameters and the operational characteristics of the available lift systems. Analysis should start when reservoir, drilling and completion decisions are being made; not after the well has been drilled www.offshoretechnologyreports.com | 11

SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

By most guesstimates there are well over a million [producing wells] globally. Of those, maybe 5% flow naturally.

The remaining 95% of producing wells rely on some form of artificial lift, at some point in their production life cycles

and completed. Different pumps and lift systems have unique operational/engineering criteria, but they all require similar data to properly determine application feasibility…”

Among those “parameters” above might be the level of well instability. This is a major issue when operating an extended life facility where unwanted gas in the well, water or oil pollution or variations in pressure can adversely affect the extraction system risking either loss of product and pollution or inability to lift product out of the well. At the start of their article, the World Oil authors (see above) “By most guesstimates there are well over a million [producing wells] globally. Of those, maybe 5% flow naturally. The remaining 95% of producing wells rely on some form of artificial lift, at some point in their production life cycles.”

EOR Works EOR has a number of significant advocates, including Matthias Bichsel, Director Projects & Technology, Royal Dutch Shell plc. “… I’d like to just mention enhanced oil recovery – a very powerful route to making the most of oil fields... At Shell we have a range of exciting EOR schemes in use and a number under development.

For instance, we have several steam injection schemes in the Middle East, Canada and the USA – where, as an example in California, we were able to improve the recovery factor from 10% to 80% in parts of the field. We are also currently commissioning a field in the Netherlands that was found more than 50 years ago, and EOR is breathing new life into it for another 20 or more years. In addition, in several countries we have chemical and miscible gas injection projects under way.”

The last word can go to Rigzone again (‘How does gas injection work?’ see above) “Somewhat similar to water injection, or water flooding, gas injection is a pressure maintenance program that can be employed on a reservoir at the start of the production process or introduced after production has already started to lessen.”

12 | www.offshoretechnologyreports.com

SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

Gas Lift – The Offshore Game Changer Peter Dunwell, Correspondent Making many fields more productive, helping older fields and even deploying green credentials, gas lift and gas injection can make a difference

A System That Works Among the systems used for enhanced oil recovery (EOR) and artificial lift, gas lift has proved its applicability to offshore use with a combination of reliability and in being able to handle a range of product conditions. However, the mechanical aspect of operation using side mandrels has often proved cumbersome. That said, a number of contractors, such as Baker Hughes offer gas lift as a13 “reliable, low-cost answer to extending well life and improving the economics of well development… [Properly designed and installed] a gas lift system [overcomes] declining natural reservoir energy. Injecting gas into the produced flow stream reduces fluid density so the bottomhole pressure once again will lift fluids to the production facility.” Schlumberger similarly confirms that14, “Gas-lift installations manage abrasive materials, such as sand, and can be used in low-productivity, high gas/oil ratio wells, or deviated wellbores.”

A Productive Boost Artificial gas injection is especially apposite when a well has passed its productive peak.

The SAS Global Forum Paper ‘Optimization of Gas-Injected Oil Wells’15, neatly sums up: “Artificial gas injection into aging wells boosts reservoir pressures, allowing for higher production rates.

For constrained gas flows and multiple wells, the solution of this problem becomes difficult and time intense.”

There are a number of methods and techniques used in gas lift: “These,” as the Hindawi paper, ‘A Survey of Methods for Gas-Lift Optimization’16 explains, “range from isolated single-well analysis all the way to real-time multivariate optimization schemes encompassing all wells in a field. While some methods are clearly limited due to their neglect of treating the effects of inter-dependent wells with common flow lines, other methods are limited due to the efficacy and quality of the solution obtained when dealing with large-scale networks… of difficult to produce wells.”

The same paper continues... “The introduction

of lift gas to a non-producing or low-producing well is a common method of artificial lift. Natural gas is injected at high pressure from the casing into the well-bore and mixes with the produced fluids from the reservoir. The continuous aeration process lowers the effective density and therefore the hydrostatic pressure of the fluid column, leading to a lower flowing bottom-hole pressure...

The increased pressure differential induced across the sand face from the in situ reservoir pressure… assists in flowing the produced fluid to the surface… The method is easy to install, economically viable, robust, and effective over a large range of conditions, but does assume a steady supply of lift gas.”

And It’s Green But gas lift is not only for older or life extended fields. Rigzone17 tells us that, “gas injection is a pressure maintenance program that can be employed on a reservoir at the start of the production process or introduced after production has already started to lessen”. Gas injection, a different but complimentary process to gas lift, can also be a contributor to green programmes.

Sometimes it serves as an economical way to dispose of uneconomical gas produced as part of an oil recovery process. This not only helps productivity of the prime reserve but also avoids the need to flare or burn off unwanted gas, a practice that is frowned upon in most places and even banned in some. Whereas gas lift involves pumping gas into a production well, gas injection is usually achieved through a designated injection well.

While it is not a prime purpose of gas injection, “it is thought that the oil and gas industry’s experiences and learnings may be of value in considering the injection of carbon dioxide for the purpose of geologic storage.”18

Mechanical to Digital The management of gas lift operations has, until recently, been a mechanical process using side pocket mandrels to control injection rates. This www.offshoretechnologyreports.com | 13

SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

Intelligent well technology was applied in India’s Panna field to a secondary recovery project with complicated well conditions

Camcon’s Digital Gas Lift Solution

means that when an injection rate change is required, a wireline has to be used to change a valve. Such a cumbersome process, by modern standards, not only adds unnecessary mechanical complexity to a gas lift operation but also is less controllable and, therefore, less able to react to changing conditions. Newer control systems that make use of current digital technology allow an operator to monitor and control injection rates in real time thus reducing the chances of failure and improving the responsiveness of the system.

Offshore magazine highlighted the latest developments19 – “The industry’s ability to remotely monitor downhole conditions in real time and to control the flow of fluids between the reservoir and the wellbore without physical intervention has been achieved through intelligent completion technology and continues to prove its value in unconventional applications.

Recently, intelligent well technology was applied in India’s Panna field to a secondary recovery project with complicated well conditions.

Using auto-gaslift, the operator reduced the capital expenditures related to conventional

14 | www.offshoretechnologyreports.com

gas lift infrastructure, lowered operating costs through minimized well intervention, and optimized production.”

Gas injection is one of the technologies making enhanced oil recovery (EOR) a viable option for offshore fields. So, for instance, the BP Mars B development in the Gulf of Mexico has been subject to a life extension project using20 “expanded water flood with gas lift”. In a similar vein, Shell’s restart of the Nelson platform in the North Sea21, “revealed that better gas lift optimisation could contribute to faster platform start-up following a shutdown. The existing optimisation workflow was labour intensive and non-transparent, and, therefore, unsuitable for real-time optimisation of the gas lift process. The field operators decided to introduce a process workflow based on an automatic optimiser system for the platform’s gas lift operations, and to address the lift-gas compression capacity.”

Gas lift is a technology that’s here to stay because it can add productive value to a field and all the more so when it is allied with the latest in digital control technology.

SPECIAL REPORT: NEXT GENERATION OFFSHORE INTELLIGENT GAS LIFT TECHNOLOGY

References: 1

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

http://www.subseauk.com/documents/subsea%20asia%20-%20jason%20waldie.pdf 2

Infield Systems, ‘Subsea Oil and Gas Sector Set For 14.8% CAGR Growth To 2017’ http://www.infield.com/news/subsea-oil-gas-sector-growth-2017

3

Subsea Well Intervention Market Report to 2017 http://www.infield.com/market-forecast-reports/subsea-well-intervention-market-report

4

Subsea Oil & Gas Directory http://www.subsea.org/subsea.html

5

Canadian Oilwell Systems Company ‘Basic Artificial Lift’ http://www.coscoesp.com/esp/basic%20artificial%20lift%20tech%20paper/Basic%20Artificial%20Lift.pdf

6

‘Contribution of Subsea Technology to UKCS [UK Continental Shelf] Exploitation – Now and in the Future’

7

http://www.oilandgasuk.co.uk/downloadabledocs/1394/2.%20Patrick%20O%27Brien,%20Wood%20Group%20Kenny.pdf 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 8

World Oil, ‘What’s new in artificial lift? http://www.worldoil.com/May_2013_What%E2%80%99s_new_in_artificial_lift.html

9

If that fails, enter ‘what’s new in artificial lift’ into your search engine and the article will be near the top.

Rigzone ‘How does gas injection work?’ http://www.rigzone.com/training/insight.asp?insight_id=345&c_id=4

10

Rigzone ‘What is EOR and How Does it Work?’ http://www.rigzone.com/training/insight.asp?insight_id=313&c_id=4

11

Halliburton, ‘Artificial Lift’ http://www.halliburton.com/en-US/ps/artificial-lift/artificial-lift.page?node-id=hfqelabr#

12

World Oil, ‘What’s new in artificial lift? http://www.worldoil.com/May_2013_What%E2%80%99s_new_in_artificial_lift.html

If that fails, enter ‘what’s new in artificial lift’ into your search engine and the article will be near the top.

13

Baker Hughes http://www.bakerhughes.com/products-and-services/production/artificial-lift/gas-lift-systems

14

Schlumberger http://www.slb.com/services/production/artificial_lift/gas_lift.aspx

15

SAS Global Forum Paper ‘Optimization of Gas-Injected Oil Wells’ http://support.sas.com/resources/papers/proceedings11/195-2011.pdf

16

Hindawi, ‘A Survey of Methods for Gas-Lift Optimization’ http://www.hindawi.com/journals/mse/2012/516807/

17

Rigzone ‘How does gas injection work?’ http://www.rigzone.com/training/insight.asp?insight_id=345&c_id=4

18

API http://www.api.org/environment-health-and-safety/environmental-performance/~/media/d68de1954b8e4905a961572b3d7a967a.ashx

19

Offshore magazine

http://www.offshore-mag.com/articles/print/volume-67/issue-1/drilling-completion/intelligent-well-technology-can-control-oil-reservoir-inflow-auto-gaslift-system.html

20

BP http://www.bp.com/en/global/corporate/investors/strategy/upstream-major-projects/gulf-of-mexico-deepwater/partner-operated-projects.html

21

Shell http://s05.static-shell.com/content/dam/shell/static/globalsolutions/downloads/media-centre/impact-online/2010-issue2/nelson.pdf

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