KNOW-HOW TECHNOLOGY INNOVATION - ugtu.net · Innovation is a state of mind, ... 50 WI15 repair project: Girassol water injection line repair. Pipeline Repair System – PRS 58 RACS

KNOW-HOWTECHNOLOGYINNOVATION

OCTOBER 2011

#1

2 TechnoHUB #1 / October 2011

EDITORIAL

Innovation is a state of mind, a quest for the unknown, the aspiration that we can always do better.

3October 2011 / TechnoHUB #1

Senior Vice President, Development, Total Exploration & Production

Best Innovators 2010 awards sponsor

In pursuit of that objective, Total Upstream decided to launch the new “Best Innovators” Prix by regrouping the many awards we had internally into a one and single prize, a one and single category, on a one and single platform. The quality of the dossiers and the commitment of the competitors were to be put on the frontline for rewarding the best submissions. We finally had more entries than ever, with more diversity than before, with all the activities of Total’s Exploration & Production and Gas & Power branches well represented.

The Jury scrutinized a hundred files, made their selection of the best entries, and had a full day meeting with the finalists to review the “innovations” in detail. I was thrilled by the passion of all the participants involved, whether they were in the jury or presenters. I was amazed at all the technical competency and communication skills

Innovation. This is the key driver today. In these times, when the world is changing faster and faster than ever, the important thing is to develop and to create in order to stay competitive in every field.

Michel HOURCARD

shown by the teams. Some came with the full team, some others with the complete equipment, transforming the meeting room into a lab! Innovation on “en marche”!

Innovation is a state of mind, a quest for the unknown, the aspiration that we can always do better. Let’s hope that this spirit of Innovation will thrill in 2012 even more than in 2011. I invite you now to read this new issue of TechnoHUB to share the culture of innovation that inspires us and remember: technology, technology, technology!


CONTENTS

Innovations

FIELD OPERATIONS

32 Ultrafiltration of produced waters and formation damage tests for reinjection into reservoirs: the two integrated pilots at Cap Lopez in Gabon

40 ECS (Energized Composite Solutions) technology: another take on carbon fiber

32/49GEOPHYSICS

6 Anisotropic depth imaging in a subsalt context of the Angolan deep offshore

6/14RESERVOIR

15 LIPS (Laser Induced Pyrolysis System): High-resolution logging of organic carbon on cores. Application to tar mats and to unconventional hydrocarbon resources

15/24DRILLING & WELLS

25 The STCA (Slurry To Cement Analyzer)

25/31


Patents

Edition : October 2011 //

TECHNOHUB Total’s Exploration & Production techniques [email protected] //

Publication Manager A. Hogg / Editor-in-chef D. Pattou assisted by V. Rogier (Rythmic communication) / Editing committee R. Henri-Bally, Ph. Julien, D. Le Vigouroux, M. Maguérez, F. Mombrun, P. Montaud, L. Stéphane, V. Lévêque / Photo credits Total, AGIP KCO, A. Lechon, B. Kampala, F. Mercier, F. Rey-Bethbeder, G. Leimdorfer (Rapho), L. Pascal, M. Dufour, M. Roussel, Obatala, Ph. Glorieux, P. Le Doaré, S. Compoint, S. de Bourgies, T. Bigex / Illustrations J. Duverdier / Translation Anglo-file / Design and production Bliss agence créative //

ISSN number pending

PATENTS 2010

102/103INSTALLATION INTEGRITY

50 WI15 repair project: Girassol water injection line repair. Pipeline Repair System – PRS

58 RACS (Riser Annulus Condition Surveillance) or how to guarantee the integrity of our flexibles in operation

68 Evaluating the severity of dents in pipelines or how to guarantee the integrity of damaged pipelines

HSE: SAFETY

77 Marine Awareness Campaign… introducing Captain Jack

85 ‘Winterization’ for a densely equipped LNG module

HSE: ENVIRONMENT

94 Chemical looping combustion: a disruptive path to reducing greenhouse gases

50/76 77/93 94/101


Anisotropic depth imaging in a subsalt context of the Angolan deep offshore

Jean-Luc BOUROULLEC [Total E&P Borneo B.V.]

Between 2005 and 2009, Jean-Luc headed the subsalt imaging group on Block 32, after holding several positions in exploration in both Head offices and affiliates (interpreter for the Angola and Congo affiliates, head of new projects in Indonesia). He then moved on to occupy the post of Exploration Manager for the Egyptian affiliate from 2009-2010, before taking up his current post (since January 2011) as Exploration Manager in Brunei (Block CA1). Originally a geologist, he soon incorporated geology and geophysics into his overall view of the ‘geoscience’ discipline.

Frank ADLER [Total]

Frank is currently a senior geophysicist and interpreter. He came to Total in 2003 as an R&D project leader for seismic tomography, after his career debut with CGG London, followed by a position with Schlumberger Cambridge Research.

He went on to join the ranks of the ‘Block 32 Subsalt Imaging’ team from 2007 to 2009, after which he became geophysics interpretation manager on an exploration project in the Caspian Sea.

Bertrand DUQUET [Total]

Bertrand is a geophysicist. He was recruited by Total in 2006 to hold a study supervision post in seismic imaging. After three years there, he became R&D project manager for ‘Seismic Imaging’ in 2009.

Yann PHILIPPE [Total]

Yann is a structural interpreter. He has spent the last ten years working on the seismic interpretation of the complex allochthonous salt zones in the Gulf of Mexico and later in the Gulf of Guinea.

He is now a project manager in New Ventures (part of the Exploration division of the Exploration & Production branch).

Victor MARTIN [Total E&P USA]

Victor is an exploration geophysicist. After several years in Head offices as part of the depth imaging team, he played a part in exploring the subsalt plays in the Angolan deep offshore.

He is now working on the same subject in the Gulf of Mexico as part of the alliance with Cobalt International Energy.

GEOPHYSICS

AUTHORS


For Total, seismic imaging below allochthonous salt has been an important issue for several years. It represents the key to unlocking additional resources waiting to be discovered in highly complex geological settings in the deep offshore, and also to reducing the appraisal and development risks of subsalt and nearsalt discoveries already in our portfolio.

In view of the stakes, Total E&P Angola put together a multi-discipline 2G team in 2008-2009, dedicated to the ‘Full PSDM’ project for a ‘3D-Long-Offset’ seismic survey acquired in 2007. The project set out with the following aims:

▪ To improve understanding of the seismic images and therefore be able to re-evaluate the main subsalt prospects

▪ To optimize the trajectories of the future exploration and appraisal wells

▪ To offer the teams tasked with developing Block 32’s SE development hub the advantage of fast-track Wide azimuth (WAZ) images acquired in 2009/2010, long (18 months) before the Full PSDM seismic cubes of the WAZ would be available.

The technical choices were bold and risky insofar as they had never before been applied at the same time on such vast volumes of 3D seismic data. They were the focus of considerable expectations, as they would have significant repercussions on the choice of new drilling campaign started at the end of 2009.

The work undertaken proved to be capital, significantly improving the ties with existing wells and repositioning the future appraisal wells on some fields in subsalt settings. It also had a positive impact on the re-evaluation of a number of subsalt prospects and fields and enabled the trajectories of the forthcoming exploration/appraisal wells to be adjusted/fine-tuned.

The WAZ seismic data on the subsalt fields of Louro and Mostarda-Ouest (Angola), which were available as early as April 2010, were the first to substantially benefit from the velocity model built for this project (anisotropic model including double allochthonous salt). The first results of the latest well drilled in this area seem very promising.

Philippe RENAUDExploration manager, Total E&P Angola

CONTEXT

WATCH THE VIDEOfor this project onwww.technohub-total.com


GEOPHYSICS

IN SHORT

Block 32 lies offshore Angola, in waters over 1,500 m deep. Most of the oil reservoirs recently targeted by our exploration staff are overlain by gigantic salt masses, a major obstacle for seismic visibility of their contents.

Reservoirs are effectively ‘seen’ in images obtained, after a processing phase, from recordings of seismic waves propagating in the subsurface. To be efficient, the images must be processed with the help of a description – in which accuracy is essential – of the waves’ propagation velocities in the subsurface. The problem with subsalt prospects is that the salt considerably hampers determination of those velocities.

Several attempts at subsalt imaging, between 2002 and 2006, had offered glimpses of potential petroleum traps, but the images were not clear enough to be useful in positioning the exploration wells. So in 2007, it was decided that another 3D seismic survey would have to be acquired.

A number of innovations went into the processing of the depth imaging. For the first time at this scale (5,000 km2), it effectively combined improved representation of the geometry of the salt bodies and a methodology for determining the seismic wave velocity in the sediments more precisely, in conjunction with extremely powerful new processing algorithms.

The outcome was a clearer seismic image, which improved regional understanding of the block and the visibility of certain prospects. This result was obtained in an extremely tight timeline for this kind of operation, by a cross-functional team of several different specialists (seismic processing, interpretation, structural geology). It has given us an excellent velocity model of the subsurface, a fine starting point for current and future processing.

This achievement shows our know-how – but also our technical boldness – in complex geological environments such as infra-salt reservoirs. The project has been a stepping stone in placing Total among the ranks of the leading majors in seismic imaging.


To discover oil, you must have adequate knowledge of the content and type of the subsurface and its component geological layers. We often depend for that knowledge – especially offshore – on seismic images which, once interpreted, can be used to build geological models of the subsurface.

As seismic acquisition is carried out from the land or sea surface, the propagation of seismic waves through a complex medium renders our knowledge of what lies below it more than uncertain. Infra-salt zones, as they are known, are an example of such a complex medium.

SEISMIC IMAGING IN COMPLEX ENVIRONMENTS

The inset entitled “Background regarding geological models”, p. 14, offers some basic definitions of seismic imaging by way of explanation for readers unfamiliar with the subject.

Conventional seismic processing techniques rely as a rule on one assumption, namely that wave velocity varies very little laterally. While this holds true for straightforward geological provinces, wave velocity soon varies laterally in more complex domains, rendering processing ineffective.

In some zones for instance, salt bodies are found below the mud line, as vestiges of incipient ocean formation. As it happens, wave velocity in salt is much higher than in the sediments that usually make up the sea floor subsoil. This change in velocity, combined with highly varying salt mass shapes, can considerably upset wave propagation, with a highly adverse effect on visibility of the reservoirs that lie below the salt layers.

This is the case on Block 32 in Angola, two thirds of which are covered by salt structures forming a canopy that has built up with the gravity deformation of sediments and salt on the slope of the Angolan margin.

MOUNTAINS OF SALT BELOW THE SURFACE

BLOCK 32 UNDER THE SALT DOME

Block 32 is located alongside Block 17 (fig. 1), where our discoveries dating from the 1990s, like Girassol, Dalia and Rosa, are now producing and where other projects (Pazflor, CLOV) are under study or on the way to first oil1.

fi g. 1: Map showing the large salt bodies present below the surface, offshore Angola (salt represented in pink). The salt extends over an immense area of Block 32, and at only a shallow burial depth below the surface as it is mainly allochthonous

1. first oil flowed in August 2011 for Pazflor and is scheduled in June 2014 for CLOV


Those discoveries were made in turbidite reservoirs, i.e. in thick deposits of sand carried far out to sea by the Congo River. The turbidites were later buried over geological time under depths of several thousand meters below the sea floor, after which they became saturated with oil – generated in deeper source rocks – and formed reservoirs. But, on Block 32, vast quantities of salt, initially buried deep below the reservoirs, rose towards the surface with the tectonic activity that followed sand deposition (fig. 2). What was originally an autochthonous salt (present in the place where it formed) then underwent mass displacement in some places to form, at the surface, allochthonous bodies (transported far from where they were formed) several hundred and, in some cases, several thousand meters thick.

In many places, the allochthonous salt canopy masks our view of the potential reservoirs, representing a major blind spot for exploration.

INITIAL DEPTH IMAGING RESULTS

The first advanced seismic processing, called depth imaging, was carried out locally from 2002 onwards, leading to initial subsalt exploration successes in zones where a sufficiently good image was obtained. It was based on computer programs called Pre-Stack Depth Migration or PSDM.

fi g. 2: Schematic section of Block 32

The algorithms involved are able to correct the images distorted by the salt, provided the wave propagation velocity in the subsurface is known, and the geometry of the salt bodies is therefore known. They have come to be very extensively used in the industry with the fast growth of high-performance computing capabilities, as the more accurate the algorithms, the more computing time they consume.

BUT A DETERMINATION TO DO EVEN BETTER

In 2006, the Total E&P Angola exploration team decided to acquire more seismic data on Block 32, in the hope of obtaining better subsalt images. The seismic survey lasted several months, finishing in summer 2007, and thanks to the efficient work of the processing team, the data were quickly prepared in readiness for a depth imaging project.

The project set out with the objective of providing better quality seismic images, rendering the depth and position of the potential reservoirs rendering more accurately. On top of this, in view of the ongoing exploration program on the block, it was essential to obtain the images fast so as to make the best possible use of them. The imaging project incorporated several methodological and technical innovations, without overrunning either costs or deadlines.

GEOPHYSICS


fi g. 3: Comparison of depth errors between imaged seismic events and the depths as measured in the wells, in an isotropic model (top) and for the anisotropic model in this project (bottom).

With the anisotropic model, the error is signifi cantly reduced.

TECHNICAL ADVANCES

DESCRIBE THE BEHAVIOR OF THE WAVES IN SEDIMENTS

The first element of progress introduced was a better description of the waves crossing the sediments.

Before this, the velocity models in sediments returned satisfactory images in areas with little or no salt. But it was evident from many wells drilled that, while acceptable in terms of quantitative geophysical criteria, the velocities did not always succeed in accurately predicting the depth of the geological intervals crossed while drilling.

The explanation for this lies in the kind of sediments found in the Angolan offshore environment, where seismic waves propagating parallel to the subsurface strata do not have the same velocity as waves propagating perpendicular to them. This is a widespread phenomenon, called anisotropy. It has been factored into the equation in some parts of the world for several years now, but is usually based on the assumption that the geological strata are horizontal (‘VTI’ anisotropy). This imposes the necessity of knowing not only the velocity but also the anisotropy parameters governing the difference between waves propagating perpendicular to and parallel to the layers.

On Block 32, even this adjustment does not prove correct, because the layers may have a steep dip; in fact they may even be vertical in some places, owing to regional tectonic activity and displacement of the salt. So using subsurface velocity models that assume VTI anisotropy actually results in lateral mispositioning of these steeply dipping domains, hence inappropriate well locations.

We therefore opted for a description of velocities in the subsurface based on ‘STI’ anisotropy.

This was the first time it was used at this scale (5,000 km2). This meant knowing, in addition to the anisotropy parameters, the dip of the sedimentary layers at every point throughout the subsurface. Several innovations were implemented for the occasion in terms of methodology:

▪ A new method of determining anisotropy parameters at regional scale

▪ The dips in the model were determined by a combination of automatic image analysis and seismic interpretations

▪ Lastly, the seismic velocities were updated by tomography, a technique for STI anisotropy still in its infancy at the time.

The efforts put into improving the description of subsurface velocities paid off in a substantial reduction of the difference between the depths of the reflections in the images and those of the corresponding reflectors encountered in the wells (fig. 3).

The depth imaging process is based on the idea that to obtain the best possible image it is essential to represent as accurately as possible the behavior of the seismic waves in the subsurface. This means, first, having a seismic velocity model reproducing as closely as possible the actual velocity in the subsurface and, second, running PSDM algorithms that use a minimum of approximations and are of the highest achievable accuracy. Three technical breakthroughs were harnessed to achieve this.


DESCRIBING THE GEOMETRY OF THE SALT CANOPY

The second technical development concerned the description of the geometry of the salt bodies. Most previous processing in Angola had adopted a simplified (‘single-iteration’) interpretation approach which did not factor in the full complexity of the salt structure’s shape.

One iteration involves steps that combine image calculation and seismic interpretation. Even this is a fairly lengthy, fastidious process, which is why the interpretation of salt bodies seldom goes any further.

In opting for a multiple-iteration approach, we were able to render the complex geometry of the salt bodies better and the image was particularly improved wherever several salt intervals were vertically superimposed (fig. 4). A few local projects in Angola and a number of bigger ones in the Gulf of Mexico had been carried out previously using this technique, but it had never before been applied at such a vast scale in a single project, owing to the extensive work the process involves. Figure 5 reveals, in three dimensions, the complexity of the salt bodies present on the block, appraised by means of multiple image-interpretation iterations.

USING NEW ALGORITHMS

The challenge was to keep computing time within reasonable limits, while seeking the best double-iteration accuracy. A new type of PSDM algorithm (‘beam migration’) was used for this. It can be carried out fast but with sufficient accuracy to run the intermediate iteration steps.This algorithm, only recently available for STI anisotropic models, played a large part in helping meet deadlines without compromising quality.

Lastly, a ‘reverse-time migration’ or RTM algorithm, more complicated but considered the most accurate, was used at the end of the project to obtain the final images in the most complex zones. In actual fact, there was no such algorithm for STI anisotropic models at the start of the project. We were expecting it to leave the R&D phase and being out in time for the final step in the project, and this was effectively what happened.

Use of these new algorithms in the STI anisotropic context was the third original technique of the project.

fi g. 4: Impact on the salt image of a single-iteration interpretation (left) or a double-iteration interpretation (center).

The salt bodies are shown in pink. The gray area in the schema on the right shows how much of the salt body is missed by a single iteration.

fi g. 5: 3D view of the allochthonous salt bodies (in purple) and a regional horizon over the whole of Block 32

GEOPHYSICS


fi g. 6: Comparison of a seismic image obtained before the project (left) and the fi nal image obtained at the end of the project (right).

In particular, the fl at refl ection circled in red on the fi nal image is clearly visible. The feature may be an oil/water contact in the reservoir.

fi g. 7: Comparison of a seismic image obtained before the project (left) and the fi nal image obtained at the end of the project (right).

The reservoir is far more accurately delimited in the fi nal image: the upper termination of the reservoir series is better defi ned (purple dotted line in the red area A), as is the hydrocarbon/water contact marked by a horizontal seismic refl ection (red area B).

ONE IMAGE FOR BOTH EXPLORATION AND DISCOVERY

Ultimately, the obtained image broadened local and regional knowledge of the block’s subsurface, revealing in greater detail a number of structural trends still poorly seen before.

At several spots where possible prospective structures had previously been identified, the image improved the visibility or clarified the geometrical consistency of the subsurface layers. We were therefore able to determine more precisely the prospective stakes and increase the chances of exploration well successes. Figures 6 and 7 show a comparison between the images available before the project and the new images the project produced on two different structures.

In both cases, the images are more consistent geologically. For instance, flat reflections that may represent the interface between oil (lighter, so on top) and water in the reservoir are more horizontal, more clearly defined and finish at top reservoir, which was not the case before. This gives us greater certainty regarding the nature of the reflections, which are a clear, telltale sign of oil present in the reservoirs.

Visibility is greater too, enabling the exploration staff to interpret the images with more confidence and consequently to appraise more thoroughly the risks of potential failure. One of the two prospects shown in the images has since been drilled, resulting in a discovery of a size consistent with our predictions.


Geological models serve many purposes, mainly upstream in the oil chain, where they are used for reconnaissance surveys in oil-bearing provinces for reservoir identifi cation, well location and reservoir model-building among others. They are based on the interpretation of seismic images.

Those images are obtained by what is known as seismic processing. This transforms raw seismic data, which seldom reveal a great deal as such, into images that can be ‘read’ by geosciences teams.

Seismic data are acquired by recording the refl ections – off the subsurface intervals when they change in nature – of seismic waves sent out by a device attached to a ship (or truck). The interfaces between layers of different nature are called ‘refl ectors’.

Seismic waves, comparable to sound, propagate faster or more slowly in the subsurface depending on its nature. One of the biggest challenges in seismic processing is to correctly estimate this velocity in the different layers in order to predict the depth and geometry of the ‘refl ectors’ with suffi cient accuracy. The precision of this wave velocity estimation is a prime contributor to the reliability of the images used to build subsurface models. Determining the velocity model is therefore a crucial step in seismic processing and the focus of the greatest processing effort.

Background regarding geological models

MORE

ConclusionThis project was designed to combine several cutting-edge techniques and focus them on attaining the best possible image using the seismic data available. Deadlines and budgets were respected, despite the innovations put into practice – and even developed – in the project and despite the difficulties inherent in their implementation.

The first images were even delivered two months ahead of schedule, suffering no loss of quality. This was made possible by an optimized organization and by constant interaction between all the project actors: a dedicated task force with a mixed membership comprising interpreters and structural geologists, the depth imaging team, the geophysics contractor and the exploration team in Angola.

The project deliverables included reference images at block scale and a velocity model. The latter will serve as the starting point for all future depth imaging projects: new seismic acquisitions

(such as the WAZ acquisition performed in 2009-2010 on the future first development zone of Block 32), new types of seismic processing (such as Full Waveform Inversion), etc.

The project also highlights Total’s savoir-faire in designing and developing new depth imaging methodologies – especially for infra-salt domains – and its capacity for conducting wide-scale projects allying quality and timely delivery. It has moved Total up a rung on the ladder of the leading oil majors in seismic imaging.

GEOPHYSICS


LIPS (Laser Induced Pyrolysis System):High-resolution logging of organic carbon on cores. Application to tar mats and to unconventional hydrocarbon resources

RESERVOIR

Gilles SERMONDADAZ [Total United Arab Emirates]

Gilles joined the Group in 1985 as operations geologist for the Paris and Aquitaine basins. After two assignments in Africa as a synthesis geologist (Congo) and a senior geologist (Cameroon) respectively, he spent several years exploring for acreage in South-East Asia. After spending time in R&D, he was put in charge, first, of a service in the Fluids and Organic Geochemistry department in Pau, then of the department itself. He is currently on expat in the United Arab Emirates in a position as Geosciences manager.

Dominique DUCLERC [Total]

Since 1983, Dominique has been working in the organic geochemistry laboratory of Total E&P’s scientific and technical center in Pau, France. She has actively participated in research and provided assistance to the subsidiaries, acquiring in the process a range of analytical competencies as well as in-depth knowledge of the geochemical context.

Daniel DESSORT [Total]

Daniel took his first professional steps in signal processing at the faculty of Medicine in the University of Bordeaux then moved on to the Strasbourg Neurochemistry Center. He joined the Group in 1984 to initiate a biomarker project in Exploration & Production. Originally at the head of an organic analysis laboratory, he has spent the last twelve years carrying out research and operational studies in organic chemistry. Since the start of his career, Daniel has published over 60 articles in international reviews.

Robert LE-VAN-LOI [Total]

After starting his career with a perfumer (extracting plant material, installing production units), Robert subsequently joined one of Total’s research centers (Chemicals branch), where he spent 14 years as an analyst (monitoring pollution, developing methods, etc.). In 2004, he took up the position of senior technician in the E&P technical center in Pau, France and works for the subsidiaries in a unit specialized in isotope measurements. His current project concerns LIPS acquisitions of gas shales.

LIPS is the result of a mutual effort, which has benefitted from the creativity, enthusiasm and competencies of each member of the team, both in organizing the project and in contributing original and suitable technical solutions.

AUTHORS


RESERVOIR

CONTEXT

Characterizing and understanding the content and distribution of organic carbon in sediments is a key element for the exploration and production of the new petroleum prospects offered by unconventional resources.

The LIPS sheds light on the matter against this backdrop by providing a high-resolution quantification of the hydrocarbon potential of new development targets. With this instrument we can obtain crucial information, in the shape of a quantitative log of the organic carbon contained in a core.

These measurements are equally useful for understanding the distribution of non-mobile hydrocarbons (tar mats) in a reservoir and evaluating their impact on productivity.

The device combines miniature technologies, which are becoming more prevalent, such as:

▪ Laser technology

▪ Instant detection of gas emissions.

As it is portable, measurements can be carried out in the laboratory or close to where the core sample was taken, eliminating lead times for transport to measuring laboratories.

As early as the design stage, the HSE aspect was factored into the equation as the use of a class IV laser required a specific design for safe operation. Approval by a certified body was a key step in the process of ensuring the validity of the technical solution.

After undergoing a validation stage, the LIPS has already been used to characterize bitumens, tar mats, oil shale and shale gas during operational studies on several zones of interest, and has provided essential elements of understanding.

The LIPS is a real breakthrough in terms of both the originality of the technology used and its unique ability to characterize carbon deposits.

Gilles BITOUNVice-President, Exploration Techniques, Total


IN SHORT

Oil shale encloses significant hydrocarbon reserves that have been little exploited to date.

Tar mats are layers composed of almost-solid, asphaltene-rich bitumen ranging from several centimeters to several meters thick in certain reservoirs. They cannot be produced and are a real source of problems as they reduce reserves and hydrocarbon mobility.

Gas shales are highly mature source-rock formations made up of extremely porous residual carbon acting as a gas sponge.

These three materials share a high organic carbon content, a critical indicator for:

▪ Assessing and mapping the quantity of hydrocarbons that can be produced by oil and gas shales at prospect scale.

▪ Understanding and modeling the horizontal and vertical distribution of tar mats in a reservoir.

▪ Quantifying the impact of tar mats on reservoir quality and fluid movements.

Unfortunately, current means cannot be used to produce a core log that is high resolution AND quantifies organic carbon.

To meet this need, a new instrument, the LIPS (Laser Induced Pyrolysis System), was designed, developed and successfully implemented at Total E&P’s Jean Féger Scientific and Technical Center (CSTJF) in Pau, France.

LIPS is an automatic measuring instrument that takes quantitative measurements of organic carbon or bitumen on cores at a resolution accurate to within a centimeter by:

▪ Pyrolyzing organic carbon using a powerful laser beam.

▪ Quantifying the products formed and ejected by the impact of the laser.

Despite a number of stumbling blocks encountered along the way since the start of the project in 2007, the innovative instrument is now available.

The LIPS has kept all its promises. Several operational studies have already been run at the CSTJF, each producing countless original and very significant results.

The domains potentially concerned by this new technology include Exploration/Appraisal, Development and Unconventional. A second model of LIPS is currently being designed.


RESERVOIR

Finding the exact location of fossil organic carbon deposits – such as tar mats, oil shale and gas shale1 – and measuring their richness is not as easy as it looks.

Tar mats2 are almost-solid, asphaltene-rich bitumens that can be found in certain reservoirs (fig. 1). Not only are they impossible to produce but they can actually cause problems as they reduce reserves and hydrocarbon mobility during production.

Oil shale2 and shale gas (fig. 2) belong to the family of unconventional fossil hydrocarbon resources which represent significant reserves that have been very little exploited to date.

EVALUATING ORGANIC CARBON CONTENT

Broadly speaking, the organic carbon in sediments is difficult to locate and quantify using logging techniques. Tar mats (in reservoirs), oil shale and shale gas vary widely in thickness, from a few centimeters to several decameters. Their common feature is their rich organic carbon content, generally evenly distributed (fig. 3).

1. For this type of rock (a source rock in gas genesis or post-genesis phase), the gas is stored in situ, as an adsorbed gas in organic matter or as a free gas in cracks and fractures. Measuring the residual organic carbon is therefore an important parameter for estimating shale gas productivity, its residual potential or the quantity of gas adsorbed.

2. see Glossary p. 24.

fi g. 2: Autun oil shale (France). Photo by Jean-Pierre Houzay

fi g. 1: Tar mats in a dolomite reservoir (dark areas)

fi g. 3: Oil shale (Green River Shales, carbonate facies). The darker levels generally indicate a high oil potential

fi g. 4: Location and highly schematic representation of tar mats in a reservoir. It is not always easy to detect tar mats with the naked eye.

Tar mats

Tar mats visible on the core


fi g. 5: Transmitted white light microphotograph of solid bitumen in the porosity of a carbonate reservoir in the Middle East

fi g. 6: Rock-Eval in the laboratory

fi g. 7: Bitumen in the porosity of a Middle-Eastern reservoir controlled by observing thin sections and by Rock-Eval analysis. In this example, the colors indicate the presence of metal oxides rather than bitumen. With Rock-Eval pyrolysis, the S2b peak and the residual carbon after pyrolysis may be assimilated to the quantity of heavy products found in the porosity.

1 mm

Acquiring these data is essential for:

▪ Estimating and mapping the amount of hydrocarbons that can be produced from oil shale at prospect scale. This parameter is directly related to the oil shale’s carbon content and depends on the thermal history of the organic matter it contains, but also on the lithology and facies, and even on climate cycles. A detailed quantitative measurement of organic carbon is therefore a good starting point for making a rigorous inventory of a prospect’s reserves. By simply heating oil shale, it is possible to evaluate its productivity (fig. 8 p. 20). Rock Eval (fig. 6) and Fisher tests (fig. 9 p. 20) are the methods currently still in use in the industry to obtain a quantitative evaluation. Unfortunately these processes include sampling, which requires prior preparation – often time-consuming, expensive and varyingly complex. Consequently, these techniques can only be applied to a very small number of samples, which has an effect on the sampling interval (in the best-case scenario, one point per foot).

▪ Locating shale formations with a high gas content, in which organic matter acts as a sort of gas sponge.

▪ Understanding and modeling the spatial distribution of tar mats in reservoirs and quantifying their impact on reservoir quality and fluid movements. Even though the stakes involved in more accurate location and quantification of tar mats remain to be evaluated, it is nevertheless a fact that tar mats are the ‘bad cholesterol’ of reservoirs. Their negative impact has been highlighted by several recent studies3,4 which show that a volume of 15% solid bitumen in the porosity of a reservoir (i.e. barely 3% of the rock volume for 20% porosity) is sufficient to drastically reduce permeability and therefore productivity.

However, there are currently no means of recording a core log that is both high-resolution and able to quantify organic carbon, which would present a solution to the problems above. Among laboratory techniques, the most efficient means currently available are Rock-Eval pyrolysis (fig. 6 & 7), thin section analysis (fig. 7) and composition of organic extracts.

Visual description of the cores is a complementary approach. It is useful because it is fast, but limited as it is only qualitative. In addition, bitumens are not always visible to the naked eye, and the correlation between the core’s color and the presence of bitumen in the reservoirs is not always obvious.

3. Real-Time Well Placement above a Tar Mat, Leveraging Formation Pressure While Drilling and Pyrolytic Oil-Productivity Index Technologies. Khalid M. Al-Salem, Said S. Al-Malki, Rabea A. Ahyed, Peter J. Jones and Peter M. Neumann. Saudi Aramco Journal of Technology, Fall 2008, pp 49-54.

4. How Much Tar is too Much? Novel Methods for Tar Identification and Quantification for Real-Time Reservoir Assessment. Peter J. Jones, Peter M. Neumann, Henry I. Halpern, Edward A. Clerke, Michael C. Dix, Rachad Zeriek, Isidore J. Bellaci, Nasser A. Al-Khaldi, Ridvan Akkurt, Mohammed N. Khamis, Said S. Malki, Salman M. Al-Qathami, Mohammed A. Al-Amoudi, and Khalid R. Al-Malki. GEO 2008 Middle East Conference and Exhibition, Manama, Bahrain.


RESERVOIR

fi g. 9: Fisher test apparatus

fi g. 8: Oil shale pyrolysis: a less sophisticated and more economical way of producing hydrocarbons

fi g. 10: View of the LIPS inside its cabinet (left). On the right, the laser impact positioning automaton.

CHALLENGES TAKEN ON AND INNOVATIVE SOLUTIONS

We looked for a technique for measuring organic carbon that would not only provide us with high-resolution acquisitions but would also be fast, little or even non-destructive, quantitative, robust and mobile so it could be operated outside of central services. Indeed, obtaining authorization from certain countries to export samples can sometimes be quite a challenge.

The ideal solution identified was a system that would take a great many micro-core samples and micro-analyze them on line. The ideal source of heat was found to be a laser, which concentrates high power on a very small surface, is almost instantaneous, can be used as and when required, is easily programmable, takes up very little room and affects only a tiny volume of the sample. And so the LIPS was born!

However commonplace its component parts (laser, detector… see fig. 10), their combination in the LIPS package is entirely original (fig. 11). Indeed, this explains the many stumbling blocks encountered throughout the project: HSE aspects, choice of the laser source, measuring and automation strategy, problems posed by pollution and the detection of products formed during the laser impact, calibration of the tool, data interpretation.

A quantitative high-resolution measurement of the organic carbon in these materials was therefore essential. A completely new instrument was designed and implemented in FGO5: the LIPS (Laser Induced Pyrolysis6 System). The domains potentially concerned by this new technology are Exploration, Appraisal, Development and Optimization of unconventional resources.

5. the Fluids and Organic Geochemistry department of the Development division, at the Exploration and Production research center in Pau

6. the pyrolysis of organic compounds is their thermal decompositionin the absence of oxygen


fi g. 14: Example of Rock-Eval calibration against the LIPS signal (L2 peak) for measuring total organic carbon.

fi g. 13: Photo of the the laser beam’s impact on the core surface

fi g. 11: Fisher test apparatus

7. High Resolution Logs of Tar Mats in Reservoirs using Laser Pyrolysis on cores. D. Dessort. XIII ALAGO Congress, Montevideo, Uruguay, Nov. 14th-19th, 2010.

8. High Resolution Logs of Organic Matter in Source Rocks & Oil Shales using Laser Pyrolysis on cores. D. Dessort, XIII ALAGO Congress, Montevideo, Uruguay, Nov. 14th-19th, 2010.

9. Enhanced assessment of the distribution of organic matter in unconventional plays using a new laser pyrolysis method. F. Gelin, D. Dessort, D. Duclerc and R. Le-Van-Loi. 2011 IPTC Bangkok, Thailand, 15 -17 November 2011 (submitted for publication).

10. photoionization detector (specific to alkenes and aromatics with a low molecular weight)

11. flame ionization detector (for detecting hydrocarbons)

12. thermal conductivity detector (universal)

The instrument is now fully operational and measures organic carbon on cores7,8,9 at centimetric resolution (fig. 12). It works on the following bases:

▪ Almost-instant pyrolysis of organic carbon using a high-power laser (20 MW/m2) directed at the surface of the core (fig. 12 & 13). By tearing off matter from the core on impact, the laser acts as a micro-sampler but also converts the solid organic matter into volatile organic compounds (VOC) – that may or may not be oxidized – nanoparticles and fullerenes.

▪ Collection of the products formed by the laser impact and transport to the detector.

▪ Detection of the products with an appropriate detector: up to now, a PID10 has been used, but other types of detector such as FID11, TCD12, PID, sulfur detectors and mass spectrometers have still to be tested.

▪ Automated data acquisition (several thousand closely spaced – ~1cm – measuring points).

▪ Quantitative analysis, after calibration of the LIPS signal (fig. 14), using known techniques (Rock-Eval, Fisher tests, etc.). For oil shale, the results are expressed as the percentage of organic carbon in the rock (or as the hydrocarbon yield for a given weight of rock), whereas for tar mats they are expressed as the proportion of solid bitumen. When the porosity is known, the percentage of bitumen in the porosity is calculated, as this basic information is vital for evaluating the effects of bitumens on reservoir quality.

fi g. 12: Schematic

and operating

diagram of the LIPS


RESERVOIR

OPERATIONAL APPLICATIONS

Several operational applications where the quantitative approach and high resolution of LIPS are a true added value have been developed.

▪ Oil shale: LIPS measurements of oil shale in the Middle East (fig. 15) and of the Green River shales (fig. 3 p. 18) are consistent with those carried out at lower resolution using Fisher tests or Rock-Eval. Thanks to the high resolution, very fine correlations can be made between facies, lithology and oil potential. It is quite possible that the regular oscillations in organic carbon content measured in this middle-eastern oil shale are related to climate cycles.

▪ Tar mats: the data acquired by the LIPS on this theme (Middle East and Central Asia, see fig. 16-18), represent a big step forward,

fi g. 15: Oil shale in the Middle East: example of a high-resolution log of hydrocarbon yield, expressed as a % of the rock’s mass. The blue dots are reference check points obtained from Rock-Eval. Excursions with a very high carbon rate are caused when the laser hits micro-cavities or stylolites that are very rich in organic matter. Zones with a very low petroleum potential correspond to carbonate facies. In the zones with high organic content, carbon deposition cycles can be observed, which may well be related to climate cycles.

fi g. 16: Tar mat zone in a Carboniferous reservoir in Central Asia. Comparison of the total organic carbon logs obtained with Rock-Eval (red points) and with LIPS (blue dots). In order to compare LIPS profi les (centimetric resolution) with Rock-Eval (sampling interval of 30 cm), the LIPS data in the right-hand graph were smoothed.

in view of the difficulties formerly encountered in quantifying bitumens and precisely locating tar mats in the reservoirs (fig. 18). With the wealth of data available, a statistics-based approach can now be used to answer the essential questions:

▪ What is the relationship between initial porosity and permeability and the presence of tar mats?

▪ What are the consequences of the presence of tar mats on the reserves in place (fig. 19)?

▪ What influence do bitumens have on permeability, wettability, the efficiency of acid stimulation and of electric log response?

▪ Shale gas: the first measurements carried

out are extremely encouraging and suggest that more extensive measurements could be made to better evaluate future prospects.


OUTLOOK: ENHANCED PRODUCTIVITY, NEW APPLICATIONS

A prime objective is to increase LIPS’ productivity so that long core lengths can be processed within a reasonable amount of time. This can only be achieved by reducing acquisition times and automating the loading of core boxes into the instrument. With this in mind, the next version of LIPS will include an automatic loader.

By adopting different sorts of detector, the system could be extended to other applications such as:

▪ The high-resolution analysis of organic sediments, which appear in varying quantities depending on the deposition and preservation conditions, salinity, sedimentation sequences13, the upwelling system and even on Milankovitch climate cycles. This application is feasible without any major modification to the current system. A device for measuring the 13C/12C ratio of the organic matter and an on-line sulfur detector may also be added to the system.

▪ The addition of an MS/MS-type mass spectrometer, which could help to map the flooding of a core by drilling mud (as has already been done for bitumens, fig. 20 p. 24).

▪ Shale gas14, which still needs to be more precisely evaluated. However, the system would not need to be modified in this case.

fi g. 17: Zoom on a tar mat zone in a Carboniferous reservoir in Central Asia. One can see here that the zones with the highest concentration of bitumen are not fl uorescent. The bitumen seems to be most concentrated in the transition zones between different color facies and in stylolites.

fi g. 18: Location of tar mats in a carbonate reservoir in the Middle East. Using the criteria defi ned by P.J. Jones et al (2008) for Arab D, permeability barriers in the reservoir can be located.

13. Organic Geochemistry of Irati Formation, lower Permian of Parana Basin. René Rodriguez, Egberto Pereira, Sergio Bergamachi, Hernani A.F. Chaves, Carmen Lucia Ferreira Alferes. XIII ALAGO Congress, Montevideo, Uruguay, Nov. 14th-19th, 2010.

14. For this type of rock (a source rock in gas genesis or post-genesis phase), the gas is stored in situ, as an adsorbed gas in organic matter or as a free gas in cracks and fractures. Measuring the residual organic carbon is therefore an important parameter for estimating shale gas productivity, its residual potential or the quantity of gas adsorbed.

fi g. 19: High-resolution 2D map of the bitumen content of a core section from a carbonate reservoir in the Middle East. Notice that the extreme heterogeneity of the bitumen content is clearly visible.


RESERVOIR

ConclusionThe LIPS is a new instrument that meets all HSE requirements.

It runs high-resolution and quantitative analyses on organic carbon in cores.

At the moment, the LIPS is a new measurement platform but it already has a very wide potential scope of application, of interest to many Exploration & Production projects (evaluation of new unconventional resources and of well productivity).

The LIPS is the essential link previously missing from our chain of quantitative evaluation of unconventional resources. Barely three years after the start of the project, several studies have already been successfully carried through (tar mats from Jurassic reservoirs in the Middle East and from Carboniferous reservoirs in Central Asia; study of Jordan and Colorado oil shales).

LIPS still has plenty of room for improvement in R&D and operational domains: new detectors and new applications in unconventional resources (shale gas), petrophysics and sedimentology.

GLOSSARYTAR MATS

Tar mats are found in oil reservoirs and are non-mobile, almost solid (viscosity > 1,000,000 centipoise) carbon-rich layers, slightly denser than water, which range from several centimeters to several meters thick. They are generally composed of asphaltene-enriched bitumens (precipitable heavy fraction of oils).

The bitumens that make up tar mats cannot be easily quantifi ed by electric logs and are frequently mistaken for hydrocarbons. They can be a serious source of problems in reservoirs.

The quantity and distribution of tar mats in reservoirs are important data that need to be taken into account. Several phenomena can cause tar mats to form, including:

▪Natural pyrolysis in reservoirs, either during thermal sulfate reduction or by pure thermal cracking. These phenomena tend to deposit carbon homogeneously throughout the reservoir (as in the case of Elgin-Franklin in the North Sea).

▪Gravity separation and accumulation of Asphaltene Precursor Entities, followed by their precipitation at the top of pre-existing permeability screens (including water bodies, impervious to asphaltenes). When tar mat layers form before the trap is structured, they are typically convex or inclined (as in several reservoirs in the Middle East). Asphaltene precipitation may be triggered by a drop in pressure in the reservoir or as a result of mixing with a lighter fl uid whose n-alkane content is higher. It is important to remember that this phenomenon may occur during production.

▪ The combined formation of bitumen and H2S by ether cross-linking, as is the case in certain reservoirs of Central Asia where bitumens are abundant and form highly impervious layers.

It is worth noting that biodegradation alone of oil in reservoirs forms heavy oils at the very most and is not suffi cient to form real tar mats.

OIL SHALES

Oil shale15 encloses considerable hydrocarbon reserves (probably > 2,000 billion barrels) and is generally a shallow rock formation, composed of black or dark gray laminas that can be more or less easily split (fi gs. 2 and 3 p. 18). It is made up of argillites or carbonates containing large quantities of non-mobile, immature or marginally mature (from several percent to several tens of percent of the rock’s weight) hydrocarbonous materials (kerogen). This organic matter needs to be pyrolyzed in situ or in ovens to produce relatively good-quality oil.

The exploitation of oil shale is by no means a new process. Industrial exploitation of the Autun oil shale, France, dates back to 1837, for example. The hydrocarbon yield (or petroleum potential) of oil shale is a key piece of information. It is generally obtained by pyrolysis (fi g. 8 p. 20):

▪ Rock-Eval, using several tens of mg of rock (fi g. 6 p. 19)

▪ Fisher tests, using several kilos of rock (fi g. 9 p. 20).

fi g. 20: By acquiring a large amount of data, it is possible to run statistical calculations. In this example, we calculated the volume of solid bitumen in the porosity for each reservoir layer (fi eld in the Middle East).

15. remember that oil shale and oil sands are two different things. The latter are simply reservoirs unearthed by natural erosion that generally contain biodegraded oil.


The STCA(Slurry To Cement Analyzer)

Jérémie SAINT-MARC [Total E&P Indonésie]

Jérémie is a senior drilling engineer for Total, posted currently at Balikpapan (Indonesia) where he oversees all the project studies for future offshore developments. He spent three years from 2001 with Altran (technology consultants) before joining Total as a junior drilling engineer in 2004. After 18 months on-site training as Rig Engineer and Night Company Man (Pakistan, Congo, Netherlands), he joined the Residual Gas Management R&D team, taking charge of the Well Integrity theme.

The new methods and technologies developed with his teams were instrumental in winning new contracts for Total (e.g. Surmont) and obtaining permission from the French government to use well RSE-1 to inject the CO2 from the carbon capture and storage (CCS) pilot at Lacq.

Grégory GALDIOLO [Total]

Grégory has been the manager of the Fluids and Cement laboratory at the Jean Féger Scientific and Technical Center (CSTJF) in Pau (France) since he joined Total in 2006. His role today in providing technical assistance to the affiliates draws on his ten years with Halliburton as Operations Engineer.

He has personal hands-on experience of responding to operating constraints in different geographical areas (France, Spain, Tunisia, USA, Algeria, etc.).

André GARNIER [Total]

André is Total’s cement specialist. He too is based at the CSTJF, where he often finds himself working alongside Grégory. André joined Total in January 2006 after 24 years with Schlumberger.

He held various positions with them: manager of the Client Support Laboratory (CSL) in Houston (Texas), cementing product & chemistry manager, again at the CSL, after a period as laboratory manager in New Orleans (Louisiana) and before that as senior development engineer in the Dowell Schlumberger R&D Center, France, where he developed in particular the CemCRETE technology.

DRILLING & WELLS

AUTHORS


The integrity of well architecture is vital for protecting the environment and for safeguarding the people operating or living in the vicinity of the wells. Integrity must of course be maintained throughout a well’s operating life – usually two or three decades – but must also last beyond the well’s final abandonment. The cement sheaths that ensure the interface between the formation and the casing isolate the formations holding mobile fluids from the surface and prevent fluid migration between the different geological layers. The same functionality is needed for injection wells, especially for acid gas injectors (CO

2, H2S) as envisaged in geological sequestration programs.

The quality of the cement sheath is critical for preventing the produced hydrocarbons and the injected fluids, from transiting into other formations (particularly shallow aquifers) or up to the surface. The industry has developed a good command of cement slurry, its placement, its hardening and its action in the short term (in relation to the well’s life or storage duration). But the wellbore and the well’s components will nevertheless be subjected in the course of their lives to different pressure-temperature cycles, which will embrittle and weaken the cement sheath and even damage it if it has not been correctly designed upstream before placement.

The first prerequisite for good cement sheath design is sound knowledge of several aspects: the state of the initial stresses in the cement once it has hardened, its mechanical characteristics under downhole conditions, and the loading cases that it will be submitted to. Until now, the cement’s mechanical characteristics under downhole conditions were estimations, based on measurements flawed by a systematic bias.

So far, the only way to measure the characteristics of cement hardened under downhole conditions was to transfer a sample from the maturing cell to the test cell, which meant subjecting it to load cycles that would modify its downhole properties. As regards the initial stress state in the cement, this was set arbitrarily since there were no other solutions to determine it. In bridging both these gaps, the STCA helps optimize the design of cement sheaths.

In addition, this new device will optimize oilfield development costs. The industry tends, effectively, to ‘over-design’, using special, highly expensive formulations. Thanks to the STCA, Total will be able to limit the use of special cements to cases where they are truly necessary, thereby limiting the CAPEX of projects. It will make an especially appreciable difference on heavy-oil applications requiring steam injection (Steam Assisted Gravity Drainage or SAGD), which involve drilling and cementing large numbers of wells with special cements. There, the STCA should enable us to design a perfectly adequate cement sheath with a standard cement.

Jean LASSUS-DESSUSHead of the Engineering Well Construction department(Total, Exploration & Production)

CONTEXT

DRILLING & WELLS



IN SHORT

Cement is one of the materials that contribute to well integrity. Made up as a liquid, it can be pumped easily into the well, where it will harden according to kinetics that depends on the downhole conditions, primarily temperature and pressure.

Cement is used to:

▪ Fill the spaces between drilled formations and casings

▪ Isolate the different formations crossed

▪ Protect the casings from corrosion

▪ Plug the well for good.

To properly fulfill its role as a barrier, the cement must mechanically withstand the loading cases it will be submitted to during its lifetime. It is therefore designed to develop, once placed and set in the well, the mechanical characteristics required to resist the different stresses sustained over the life of the well.

At Total E&P’s Scientific and Technical Center, we have developed an in situ system for measuring the cement’s mechanical properties under downhole conditions, the STCA (Slurry To Cement Analyzer). It is a world-first experimental device.

Until now, it was impossible to set cement and test it directly and mechanically under downhole conditions (P, T). Cement samples had to be moved back to atmospheric conditions between the maturing cell (where cement develops its properties at downhole conditions) to the mechanical testing cell (where its properties at downhole conditions are measured). This unloading/reloading cycle has the drawback of inducing micro-cracks in the material that significantly affect all subsequent measurements, mechanical or hydraulic.

The STCA avoids that artifact, thanks to a retractable mold which enables the cement to harden and be tested in the same receptacle, maintaining downhole conditions throughout the experiment.

With the STCA, Total will be able to determine not only the law of behavior of the cement as it sets – allowing it to continuously calculate changing stresses in it as it hardens – but also the initial state of stress, unknown at present.

In addition, the STCA will enable Total to select the cement best suited to the conditions of a well with the appropriate rigor, to guarantee its sustained integrity and hence the safety of the installations. This point is particularly important for wells submitted to difficult conditions (high temperature, high pressure, steam injection, acid gas injection, etc.) where service companies, simply because they have no suitable analytical instrument, tend to propose top-of-the-range cements, which are not necessarily the most appropriate in terms of integrity and are also more expensive for the operator.


Cement is a hydraulic binder, i.e. one that forms and hardens by chemical reaction with water. It is the main material used to ensure well integrity because it is easy to put in place; it is made up as a liquid and pumped into the well where it sets hard.

Cement is used to:

▪Fill the spaces between the formations drilled and the well casings, ensuring mechanical resistance and forming a barrier to fluid movement

▪ Seal off the different formations crossed, preventing the migration of fluids from one formation to another

▪Protect the casings from corrosion, again by preventing fluid movements

▪Plug the well definitively.

CHOOSING A SUITABLE CEMENT

CEMENTING A CASING

Cementing a casing means placing a cement sheath in the annulus between the casing and the formation, where it plays a crucial role in sealing the oil well.

The cement sheath is obtained by pumping into the well a liquid slurry made up from cement (powder), water and additives. Cement hydration, a complex phenomenon taking the cement from a liquid to a solid state and characterized by a porous skeleton, will then take place in the well, producing a hard cement that seals the annulus.

CEMENT UNDER STRESS

Throughout the life of a well – from its drilling to its abandonment and beyond – the cement sheath is exposed to various mechanical and thermal stresses. These stresses include those imposed by routine operations carried out inside the well (pressure tests, mud density changes, cold and hot stimulations, etc.) or phenomena stemming directly from the subsoil (reservoir compaction, tectonic movements, etc.). All of these stresses may damage the material composing the cement sheath (though the term ‘cement’ is improper), cause its mechanical properties and permeability to deteriorate, and therefore alter its contribution to the well’s stability and seal.

Knowing how the cement will behave under the well’s conditions and how this behavior will change over time is paramount. It is true for wells drilled to produce hydrocarbons but also for wells drilled to store greenhouse gases (e.g. CO2) in subsurface reservoirs.

Figure 1 shows the different cement-related problems that can cause loss of well integrity.

fi g. 1: Possible cement-related causes of well integrity loss

DRILLING & WELLS


SAGD – A SPECIFIC CASE OF EXTREME STRESSES

SAGD (Steam Assisted Gravity Drainage) is a thermal process employed to decrease the viscosity of and thus extract highly viscous oils (heavy oils). It consists in injecting superheated steam (from 180 to 250°C) through an injector well down to the oil reservoir, where the steam condenses and releases its heat to the surrounding environment. Thanks to this influx of heat, the viscosity of the oil is lowered enabling it to flow, under the effect of gravity, down to a producing well where it is pumped to the surface.

The steam injection process generates stresses liable to damage the cement sheath. The risk is that the integrity of the hydraulic isolation may be destroyed. An example of this phenomenon is shown in the two photos in figure 2, taken after lab experiments. Before application of the thermal loads (fig. 2a), the conventional cement sheath is intact. After application of the thermal loads (fig. 2b), the conventional cement sheath failed. When steam was injected, the casing expanded under the effect of temperature, generating stresses and ultimately tensile rupture in the cement sheath. As a result, the cement sheath was cracked from top to bottom, and its integrity was lost.

To prevent such a phenomenon from occurring in our wells, it is vital to properly design our cement sheath. To do so, we developed our own in-house software program, Sealwell, designed to define the mechanical properties the cement sheath must have in order to resist the different stresses it will undergo throughout the well’s life. Mechanical and physical properties of the various well features, such as terrains drilled through, casings used, and cement sheaths in place, are entered into Sealwell, along with the different stresses the well will be submitted to during its lifetime. Sealwell then computes the likelihood of one of these elements failing over time.

fi g. 2: Laboratory experiments applying SAGD-type thermal stresses on a conventional cement sheath

(a) before: sheath intact (b) sheath damaged.

(a) (b)

MECHANICAL TESTS

WITH UNLOADING BEFORE MEASUREMENT

The measuring methodology used to date consists of running static mechanical tests on samples of cement that have set in maturing test benches under pressure and temperature corresponding to the application conditions, and that have been returned to surface conditions, i.e. ambient temperature and atmospheric pressure, in order to prepare and instrument them. The inset entitled “Methodology for mechanical testing with unloading” - p. 30, sets out the main steps.

WITH THE STCA MEASURING CELL

Our innovation aims to achieve mechanical testing of a cement, directly in downhole conditions (P, T) and without unloading to atmospheric conditions. With the cell we have developed, the cement can be hardened and tested in the same receptacle thanks to a retractable mold.

The STCA was produced in the frame of the ‘cement’ actions conducted for the Management of Residual Gases R&D project, and is part of an overall project that centers on the Sealwell application.

It is a measuring device for running mechanical compressive strength characterization tests. These are conducted on cement samples subjected to conditions (pressure, temperature and fluids) identical to those found in oil wells, with no intermediate unloading-reloading phase between the maturing cell and the test cell, which used to be the state-of-the-art technology.


fi g. 3: The STCA Limits: 150°C, 70 MPa

The new system is unique, not only in the oil industry but also in the scientific world, as a means of measuring the mechanical properties of cement. It has been named the Slurry To Cement Analyzer, or STCA (fig. 3).

Before the STCA, mechanical testing involved ‘unloading’, i.e. returning the sample to ambient temperature and atmospheric pressure, between preparation of the cement and its mechanical testing, both of which are carried out under downhole pressure and temperature conditions.

Methodology for mechanical testing with unloading

MORE

The main steps in the methodology were as follows (fi g. A):

▪ Make up a volume of cement slurry ▪ Fill a mold, of a shape suited

to the type of static test to be conducted, with slurry

▪ Mature the slurry under pressure and temperature conditions to simulate the well, using the aging testbench

▪ Bring the sample back to ambient temperature and atmospheric pressure so as to be able to withdraw the mold from the aging testbench

▪ Remove sample from mold ▪ Cut and grind smooth (when

necessary) certain faces of the sample to improve their parallelism and/or perpendicularity

▪ Instrument the cement sample ▪ Place it in the test receptacle ▪ Bring the sample up to downhole

pressure and temperature again ▪ Run the mechanical tests at

downhole pressure and temperature.

DRILLING & WELLS

fi g. A: Mechanical testing with unloading


fi g. 4: (a) Hardening under pressure and temperature conditions (b) Retractable mold withdrawn (under pressure and temperature conditions) (c) Testing (under pressure and temperature conditions)

ConclusionWe expect a cement sheath to resist all the stresses, it will be subjected to over the life of an oil well. To determine that capacity, it is essential to know both the mechanical characteristics of a cement under downhole conditions and the initial stress state in the cement sheaths (or plugs), as a function of time. Our innovation puts that knowledge within the users’ reach:

▪ At the design phase, a user determines with SealWell the mechanical properties that the cement sheath should have

▪ The cement formulation is then fine-tuned by the service company

▪ Total (the relevant laboratory in the CSTJF1) validates the formulation, with the help of the STCA described above

▪ The service company proceeds with the cement job.

Combining the STCA with Sealwell software yields a tool of unprecedented capability. It can be used to rigorously assure the integrity of our cement sheaths in standard or difficult well conditions and to document the resistance of our wells for regulatory organizations.

It helps select the appropriate cement system to assure the sustained integrity of our wells and the safety of our installations. The STCA also has beneficial repercussions on our well costs, as it has been observed that the most technical – and therefore most costly – solutions proposed are not automatically those best suited to the specific well.

The different testing steps are recapped in figure 4: a volume of cement slurry is made up and poured into a mold that has a shape suited to the type of static test to be carried out. Once it has hardened under pressure and temperature conditions in the STCA (fig. 4a), the retractable mold is withdrawn, under the same conditions (fig. 4b), enabling mechanical tests to take place (fig. 4c).

LAW OF BEHAVIOR

When it is poured or pumped into place, the cement begins as a liquid, then becomes a gel and finally hardens into a solid. The laws of behavior governing the cement in its early ‘youth’ (as it sets, at these different early stages) were unknown until now.

Through the measurements taken on the cement as soon as it ceases to be a liquid, the STCA helps to determine the law of behavior of the young cement. It is therefore possible to calculate, continuously throughout its solidification, the evolution of both the mechanical behavior and the stress state of the cement.

More importantly, it is then possible to determine the initial stress state of the cement, which was neglected or poorly assessed until now.

(a) (b) (c)

1. CSTJF: Jean Féger, Scientific and Technical Center, Total E&P’s technical center, located in Pau (France)

32 TECHNOHUB / April 2011

Ultrafiltration of produced waters and formation damage tests for reinjection into reservoirs: the two integrated pilots at Cap Lopez in Gabon

Philippe COFFIN [Total]

Philippe is head of the R&D Water Management project for Total E&P and is based in Pau, France.

He has 30 years’ experience in the industry, and has held various positions worldwide in drilling, reservoir engineering, operations and business development.

Pierre PÉDENAUD [Total]

Pierre is a senior production engineer specialized in produced fluids and particularly water treatment. He currently works in the Production department, providing support to the subsidiaries and to development and R&D projects for matters related to water treatment.

He has now worked for Total E&P for 19 years holding technical and operational positions in Angola, Nigeria and at the Group’s Head offices.

Eric AUBRY [Total]

Eric is head of the Reservoir and Wellbore-Interface Laboratory, which is part of the Drilling Department.

He has 31 years’ experience in laboratory work, spent developing experimental equipment from lab to pilot scale and performing tests to evaluate damage to petroleum reservoirs with any of the drilling and completion fluids injected in a well or produced from oil and water reservoirs.

Samuel HENG [Total Petrochemicals France1]

Samuel is a production engineer with 10 years’ R&D experience in water treatment, and specialized in chemical oxidation and membrane processes.

He currently works in the Production department providing support to the subsidiaries and to development and R&D projects for water treatment issues. He worked in the water treatment industry in Europe and Asia for 5 years before joining Total.

David LE MIGNON [Petrocedeño]

David is currently working for the Planning and Development division of Petrocedeño (OPCO PDVSA) and is based in Puerto La Cruz (Venezuela) where he is in charge of the long-term plan.

He has 15 years’ experience in the oil & gas industry (13 years with Total E&P). He has held various positions worldwide in engineering, operations and development.

FIELD OPERATIONS

1. currently assigned to Total E&P

AUTHORS


Efficient water injection is a major concern for Total, not least because our operations involve producing from sensitive reservoirs. Our specifications regarding the quality of the waters we reinject and the way they are filtered are therefore very strict as we cannot afford to have reservoirs plugged. But obtaining compliance with those specifications is no easy matter on offshore installations where space and power are limited.

Yet reinjection is increasingly a necessity. It effectively contributes to maintaining pressure in the reservoirs and is a solution for meeting environmental constraints and the Group’s commitments with regard to the quality of production waters discharged to sea. The innovation presented in this article consists of using the ceramic membrane technology for ultrafiltering production waters. The project, brought to fruition by E&P’s Research & Development and carried out in cooperation with Petrochemicals and the membrane industry, achieves unprecedented qualities of filtration, with compact and easy-to-use equipment.

The tool is now ready for deployment at industrial scale. By allowing reinjection of production waters on the Group’s mature fields or on new offshore developments, it will contribute to limiting the footprint and cost of space-consuming installations for treating seawater and wastewater.

Might this technology not also be applied some day on the sea bed to avoid the complex transport of production waters through our subsea networks?

Bernard AVIGNONVice-President, Operations, Total Exploration & Production

CONTEXT



FIELD OPERATIONS

IN SHORT

Our operated fields currently produce more water than oil (1.6 Mb/d against 1.5 Mb/d) and in volumes, inexorably rising as our fields become more mature, that we expect to see double within the next ten years. In addition to this, international regulations are becoming more and more stringent as regards discharging this water into the marine environment. However, only about 16% of our production waters are currently re-injected into the reservoir to maintain pressure and the challenge here is to increase that proportion. Yet, deploying this process on a wider scale on our fields calls for an extremely fine, economical and efficient filtering technology to avoid plugging the wells and damaging the reservoirs.

It is in this context that our technical teams started using ultrafiltration with ceramic membranes, an innovative technology that is proving much more efficient than traditional techniques. Although it eliminates suspended particles as small as a few hundredths of a micron, it has never yet been used on oil production waters. This is therefore a first for Total and for the E&P industry as a whole.

A pilot ultrafiltration unit coupled to another pilot unit for testing injectivity on samples of reservoir rock, to assess the filtered waters’ plugging capacity, was installed on the Cap Lopez oil terminal in Gabon. Integration of the two pilots was achieved through cross-functional cooperation between E&P teams and also between branches (Field operations, Drilling & Wells, E&P R&D, Total Petrochemicals R&D, etc.). This innovative technology was then validated, after tests conducted from December 2009 to October 2010 by a multidisciplinary team with extensive support from the Total Gabon subsidiary.


The world oil industry produces three times more water than crude oil (roughly 240 Mb/d against 85 Mb/d), and water production increases as reservoirs grow more mature. At Total, our operated fields produce 1.6 Mb/d of water against 1.5 Mb/d of oil, and this figure is set to double in the next ten years. The water produced must then be pumped, separated, treated and injected or discharged in compliance with increasingly tough environmental specifications. At the same time, the laws of physics give us no choice but to inject volumes of water into our reservoirs (seawater for the most part) in order to maintain pressure. In the case of our recent offshore developments, water management represents a quarter of the global cost (CAPEX + OPEX).

The Produced Water Re-Injection (PWRI) currently applied on our fields uses conventional technologies combining several principles (gravity separation, cyclonic separation, coalescence, various filters…) whose efficiency and performances are limited. Filtration technologies efficient enough to prevent production waters – generally laden with hydrocarbons and various particles – from plugging our reservoirs, represent the stake underlying the two integrated pilots deployed on the site of the Cap Lopez terminal in Gabon at the end of 2009. These are aimed at increasing the volume of production water reinjected, presently only 16% (24% of the remaining water is injected into appropriate underground formations and 60% of it is discharged into the environment after treatment).

ULTRAFILTRATION THROUGH CERAMIC MEMBRANES

The presence of solid particles and oil in production waters causes rapid damage to the wellbore-formation interface. To prevent this from happening, the suspended particles must be removed before the water is injected. If damage were to occur, however, it is possible to switch to a fracture regime so that the necessary volumes of water can be injected at the required rate. But this solution may, on the one hand, give rise to partial sweeping and water ingress, and on the other have a severe impact on the cost of pumping equipment.

PRINCIPLE

Ultrafiltration has a particle separation threshold of one hundredth of a micron, which is over 8,000 times finer than a hair. Very high quality water is obtained as a result, and – thanks to the use of membrane, rather than traditional, technology – on a constant basis and with heightened flexibility. The cost, weight and bulk of the installations are also much reduced (these last two parameters also have an indirect positive impact on offshore projects). Thanks to progress made on the materials front, manufacturers can now market high-performance ceramic membranes at a more affordable cost. Figure 1 depicts one type of ceramic membrane and its porous structure.

Ceramic membranes are particularly stable from a thermal and chemical point of view and are used, among others, in the food industry (filtration of milk or wine for example) and in pharmaceuticals (concentration of active principles).

fi g. 1: (a) Porous multi-canal ceramic membrane made of silicon carbide (b) Observation of a ceramic membrane under a scanning electron microscope (cross-section, magnifi ed to x1,500)


OPERATION

The technology is based on the cross-flow filtration principle, as shown in figure 2: part of the water, called the permeate, passes through the membrane, and the water remaining (the concentrate) retains the hydrocarbons and solid particles. The recovery rate corresponds to the quantity of clean water recovered, as a proportion of the incoming flow-rate.

The global operating principle of the filtration is shown in figure 3, along with the cleaning means used. The membranes will obviously become clogged in the end, as is the case for any filter. There are two different cleaning protocols:

▪ Back Washing (BW): the system is rinsed with a countercurrent flow of clean, or additivated, water. The washing process takes place frequently (e.g. every thirty minutes) and lasts a few seconds at a time.

▪ Cleaning In Place (CIP): this advanced chemical cleaning process can be carried out, say, every three weeks for two hours.

FIELD OPERATIONS

TESTS ON THE CAP LOPEZOIL TERMINAL (GABON)

These tests were carried out in real conditions via two pilots, using actual production waters.

THE ULTRAFILTRATION PILOT

This served to test the membrane ultrafiltration technology on production waters from different fields (fig. 4).

THE INJECTIVITY PILOT

This second pilot (fig. 5) situated directly downstream, serves to run injectivity tests, making sure that the filtered water does not plug the reservoirs. This unit was designed such that it could be used on all Total’s production sites, particularly in explosive atmosphere zones (ATEX).

The water is injected at a constant rate through a representative2 sample or one from a reservoir (core), into a HASSLER-type cell: this makes it possible to apply a confinement pressure, a pore pressure and a specific temperature, representative parameters of the reservoir to be simulated.

2. quarry sample used for testing as few cores are taken in the reservoir, making those available all the more valuable

fi g. 2: Cross-fl ow fi ltration principle

fi g. 3: Block diagram BW = Back Wash, CIP = Cleaning in Place

THE PARTICULARITIES OF E&P

Although the technology is known for its wide range of industrial applications, there remained the need to define the optimum operating conditions, operating procedures and cleaning protocols for our production waters, whose complexity and physico-chemical composition are highly variable.

To adapt what was known about the technology to the specificities of water treatment in E&P, the decision was taken in 2010 to run different tests on a production site.


TEST RESULTS

ULTRAFILTRATION

The Cap Lopez ultrafiltration tests were aimed at trying out different membranes and fine-tuning the operating and cleaning parameters. The tests were spread out over eight months:

▪ 40 filtration tests, with modification of ten operating parameters

▪ 40 cleaning operations on the membranes, with different protocol settings

▪ Test of 8 membranes from two suppliers

▪ 2 different raw waters used (from the Rabi and Mandji reservoirs)

▪ 24 injectivity tests comprising a saturation phase and measurement of the initial permeability, then injection of the ultrafiltered water.

All the membranes selected gave satisfactory results in terms of the quality of the filtered water, as can be seen in figure 6 p. 38.

Above all, the chemical cleaning of the membranes is so efficient (over 90 ) that it only has to be done every 10 to 15 days. Figure 7 p. 38 shows the repeatability of the tests as well as this cleaning efficiency: the initial delta pressure is restored after each test.

INJECTIVITY

When it is put in place in the test cell, the sample is first saturated, under vacuum, with reconstituted reservoir water, making it possible to estimate its pore volume. Reservoir water is then injected to measure the sample’s initial permeability.

3. blanketing: introducing a cushion of neutral gas (production gas or nitrogen) over the gas in a tank or item of equipment operated at atmospheric pressure to prevent it ‘breathing in’ air from the outside if there is a fall in pressure, level or temperature. The ultimate aim is to avoid oxygen ingress.

CROSS-FUNCTIONAL WORK

To prepare and run these tests, a dedicated cross-functional, multidisciplinary team was set up, comprising specialists in water treatment, laboratory and wells, researchers from E&P and Petrochemicals, manufacturers, etc. Total E&P Gabon also gave a big helping hand to ensure the operation’s success.

During the tests, no major HSE incident was recorded. The team nevertheless had to deal with many technical hitches such as frequent power cuts on site, leaky valves, malfunctioning of nitrogen blanketing3, difficulties in purchasing chemicals, corrosion of injection pumps, computer breakdowns and so on.

Here again, the solidarity of the Gabon/Pau/Paris teams paid off and the initial test program went ahead 95% as planned.

fi g. 4: Ultrafi ltration pilot unit

fi g. 5: Injectivity test pilot unit


The injectivity index is calculated based on these permeability values using the formula:

The next stage of the test consists of injecting production water, ultrafiltered or raw, at a constant rate (fig. 8). During these phases all of the parameters applied (pressure, temperature, flow-rate) and pressure drops in the core are recorded. These values then contribute to calculating permeabilities.

(a) (b)

fi g. 6: Production water (a) raw (b) ultrafi ltered

fi g. 7: Effi ciency of the chemical cleaning of ceramic membranes

Injectivity =Permeability to production water

Initial permeability to water

The sample’s swept pore volume is also determined using the ratio of the volume of production water injected to the sample’s pore volume. The results obtained for different injected fluids can then be compared.

FIELD OPERATIONS

fi g. 8: Principle of injectivity tests


ConclusionIn the end, the ceramic membrane ultrafiltration process works in real conditions and achieves high-quality filtration of raw waters destined either for:

▪ Discharge, with oil and solid-particle contents much lower than current environmental standards, or

▪ Reinjection, to ensure that pressure is maintained without plugging the reservoirs.

In addition, the membranes’ operating parameters are suitable for application at industrial scale.

fi g. 9: Injectivity of fi ltered and non-fi ltered production water

fi g. 10: Injection side after the injectivity test: (a) raw production water: thick deposit of oil (b) ultrafi ltered water: slight deposit

Figure 9 shows standard results, presenting on the same graph an injectivity test using raw production water (black curve) and another using ultrafiltered production water (blue curve). The curve for raw production water shows that injectivity decreases continuously and significantly, thereby impairing the permeability of our sample, whereas with ultrafiltered production water, injectivity is stable and adverse effects very limited.

What’s more, when the cells are opened (fig. 10) a thick deposit of oil and solids can be observed on the injection side for raw production water, meaning that the oil has permeated the top of the sample. With ultrafiltered production water, there is only a very slight deposit, limited to the surface of the injection side.

The extent of plugging reached with certain waters and under certain conditions provides useful information as to the operation of our future industrial units. Total is already studying how the technology could be applied on a number of its sites.

We now also have an ATEX-compatible mobile laboratory to directly test injection waters on the operating sites of Total’s fields.

(a) (b)


ECS (Energized Composite Solutions) technology: another take on carbon fiber

Dominique DELAPORTE [Total]

Dominique works in the Technologies division (E&P Development).

He worked with specialists in the Advanced Techniques and Technologies entities to evaluate/qualify heated subsea line technologies. At present, he coordinates Technologies’ support for Total E&P UK’s Islay project, which can lay a proud claim to achieving the world’s first 100% subsea electrical trace heating in a PiP (Pipe-in-Pipe). The ECS project, a high-tech variant of electrical trace heating, is compelling proof of the Group’s capacities for finding efficient solutions.

Thibaud BIGEX1 [Total]

Thibaud joined the Group in 2008 to work on the Development of the Deep Offshore R&D project where he took charge of materials studies. His in-depth knowledge of composites was a major contributing factor in the creation and development of ECS technology. He is currently assigned to the Laggan-Tormore project, working in Norway on subsea equipment.

Alain LECHON [Total]

Alain has 30 years’ experience in subsea engineering for the offshore oil industry. He began his career designing subsea tools and robots on the first subsea developments (in Africa and Norway).

He went on to spend 10 years as a pipeline specialist, took part in laying the Canyon Express gas pipeline and ensured technical monitoring on the Girassol l15 pipe repair project. In 2009, he joined the ranks of the subsea team where he takes care of repair systems but also the architecture and design of subsea installations such as spools and jumpers.

Franck REY-BETHBEDER [Total]

Franck has been an electricity specialist with Total for 20 years. He spent 7 years in technical assistance to projects, 8 years in maintenance, 3 of them with subsidiaries and 5 in R&D where, among other things, he filed 5 patent applications. He is particularly interested in alternative solutions for producing heavy oils by electrical heating and new dry fracturing processes.

Jérôme WOIRIN2 [Total]

Jérôme was formerly head of the Development of the Deep Offshore project in Exploration & Production’s R&D department (2008 to 2010) and is now field operations manager of Total’s Dutch subsidiary. The quest for simple, tough and reliable solutions was the leitmotiv of his spell as project manager, where his operating experience was precious.

FIELD OPERATIONS

AUTHORS

1. currently assigned to Total E&P UK - LT SPS (based in Norway)

2. currently assigned to Total E&P Nederland B.V.


Trace heating is one of the new techniques identified by Total as a means of economically accessing difficult subsea resources. It is used for the development of the Islay field in the North Sea.

One of the major problems with subsea production is plugging of the lines carrying the effluents produced by the wells. This occurs when solids (hydrates, waxes) form at the low temperatures typically found in deep-sea environments. The standard response to this problem in development schemes is a combination of extremely thorough thermal insulation, chemicals injection and double flowlines, to enable production fluids to be replaced by inert ones in the event of prolonged shutdown. Trace heating drastically simplifies this type of architecture and substantially reduces costs.

Current trace heating technologies are based on conventional components, essentially copper wires and electrical connectors. The technology presented in this article is completely innovative and makes use of a material that is new to this field, carbon fiber.

Carbon fiber plays a dual role here, doing the job of both resistor and electrical connector. It offers a solution that is easy to put to work and has the necessary robustness and reliability. It also opens up prospects for any number of other applications such as ‘heated coating’ adapted to valves and other items of equipment with complex geometry.

This innovative concept has already given rise to four patent applications and is a perfect example of technological leadership. It is one of the newly emerging technologies that will give us access to new reserves and help cut our technical costs.

It is also the result of bold cross-disciplinary teamwork between different entities in Total Exploration & Production including R&D and specialists from the Technologies and Advanced Techniques departments in the Development division.

Daniel PLATHEYTechnologies manager in the Development division of Total E&P

CONTEXT



IN SHORT

Cross-disciplinary work with our industrial partner brought to light the electrical properties of carbon fiber, and its potential applications in heating.

Where carbon fiber had previously attracted attention for its mechanical properties, the innovation that we describe here hinges on the carbon composite’s electrical resistivity which enables it to be heated when a current is run through it (Joule effect).

This simple idea is certainly set to revolutionize the way we tackle the development of our deep offshore hydrocarbon fields, where the major risk is that of production lines becoming plugged by hydrates owing to the low temperature of the water. The solutions most commonly used today in the event of prolonged shutdown are massive inhibitor injection, insulation of the lines and replacement of the production fluid by an inert fluid. All of them are reaching their technical limits by now, are still expensive and complex to operate and also entail potential safety risks owing to the substantial stocks of inhibitor that have to be maintained.

The technology we put forward here differs from conventional electrical heat tracing on two counts: it uses non-metallic materials and is particularly robust. For an equivalent heating power, a copper filament can be replaced by a carbon fabric composed of thousands of micro-filaments, which improves heat distribution and assures redundancy, toughness and ease of implementation.

Four patent applications have already been filed to allow Total to exploit the full potential of this technology. A demonstrator, of a length representative of a production line, is now being built.

We have already received various requests for applications, despite the fact that we are still only at the laboratory testing stage so far. They are proof indeed that we have every interest in developing this bold, promising technology fast, and not just for the deep offshore.

FIELD OPERATIONS


Total, a leading player in the development and production of deep offshore oil fields, innovates constantly in response to their inherent challenges.

Deepwater resources are expected to account for 10% of world hydrocarbon output by 2015.

PREVENTINGPLUG FORMATION

Flow assurance – making sure that fluids flow smoothly from the reservoir to the floating production unit and preventing hydrates and wax from forming in the pipes – is one of the toughest challenges in the development and production of deep offshore oil fields. Constraints like these mean resorting to complex technological solutions and operating procedures, which must nevertheless remain compatible with our priorities of preserving the environment and safeguarding both people and assets.

To prevent hydrates and waxes from forming, a development scheme with double production lines – or loops – has to be used so that, if production is stopped for any reason, an inert fluid (dead oil) can be circulated instead of the production oil. To supplement this first level of protection, hydrate inhibitors such as methanol are injected, a process not without risks as the handling and storage of such substances can be dangerous.

Offshore resources will be more difficult to extract in the future as they will be produced from greater sea depths at lower temperatures, giving rise to the need for very long pipes. Ensuring their profitability will mean making every effort (within the limits of the priorities mentioned above, of course) to keep both investment and operating costs to a minimum.

Total has stretched thermal insulation technologies to their limits and now has no choice but to innovate to tackle the challenges of tomorrow’s long subsea tiebacks with step-out distances of up to several tens of kilometers. New development schemes are now being investigated, featuring innovative technologies such as electrical heating of production lines.


ELECTRICAL HEATING TECHNIQUES

Originally developed for industrial contexts at atmospheric conditions, electrical heating techniques for pipes have since been adapted for use in subsea applications, in response to demand from the oil industry.

They are all based on the principle of an electric current I, passing through a conductor with resistance R, these two parameters determining the heating power produced by the Joule effect: P= RI².

TRACE HEATING

The oldest technique, and the one most widely used onshore owing to its simplicity, is ‘trace heating’ – also known as ‘heat tracing’ or ‘surface heating’ – by an electrical heating element running along the length of the pipe. It protects pipes against freezing or temperatures too low for the fluids to be smoothly transported without solidifying.

Trace heating involves securing electrical cables, of a simple design-build, along the entire length of the pipe and covering them with an insulating material. It is extremely energy-efficient (fig. 1).

Trace heating is difficult to apply to subsea pipelines for two basic reasons: first, the necessity to achieve perfect electrical insulation on a pipe immersed in seawater (which is a good electrical conductor) and, second, the myriad electrical connections that are impossible to access, again owing to the marine environment. As a result, we have yet to see electrical trace heating make its debut on a subsea installation.

DIRECT HEATING

The Joule effect in this instance is obtained by passing an electric current directly through the pipe’s (steel) wall. The energy efficiency of this type of heating can be optimized by electrical coupling between two parallel conductors, i.e. between a power cable that will generate signals and the pipe that will receive them, but at the price of high supply voltage. This extremely high power in a single electrical circuit is something that has to be carefully managed.

Two architectures have been developed and built on this principle in a subsea environment.

fi g. 1: Principle of electrical trace heating for production lines

fi g. 2: Principle of direct heating on a single wet pipe

Direct heating on a single wet pipe

This configuration features a single pipe with an electric cable attached along its length (fig. 2). Electrical coupling then improves the heating capacity.

It has thus far proved impossible to guarantee total electrical insulation from seawater, a concept inherent in the architecture of this system. Galvanic corrosion is limited exclusively by electrical ‘sea-grounding’, involving a clever split of the currents between the steel line and the sea, which turns out to be highly costly in power terms. The result is low energy-efficiency and still the need for voltage levels of up to several tens of kilovolts!

FIELD OPERATIONS


‘ENERGIZED COMPOSITESOLUTION’ (ECS) R&D teams have been working for several years on possible applications of composites in all kindsof petroleum developments: semi-taut anchor lines for FPSO, TLP (Tension Leg Platform) tethers, tubulars, etc.

WHAT IS A COMPOSITE?

A composite material, often shortened to just ‘composite’, comprises a reinforcement material, which acts as the bracing framework to ensure mechanical strength, and a protective material called a matrix. The latter is usually a plastic (thermoplastic or thermosetting resin) assuring cohesion of the structure and onward transfer of loads to the reinforcement.

Depending on the application considered, the reinforcement may assume many shapes: short fibers (mat) or continuous fibers (cloths or multidirectional textures).

fi g. 3: Principle of direct heating on a concentric pipe (PIP)

fi g. 4: Copper fi lament and carbon fi ber

Direct pipe-in-pipe (PiP) heating

The two concentric tubes (fig. 3) that make up the PiP pipeline are electrically independent except at the ends of the line. They are each supplied with power in the middle of the line, so that two loops are formed, one in each half of the line, traversed by an alternating current (AC). In each loop, the electrical coupling between the inner and outer tubes optimizes the Joule effect.

Less developed than the single wet-stream pipe configuration, this architecture appears to offer much greater energy efficiency, because of the better thermal insulation. For want of adequate feedback however, this solution has received little support.

Among the most frequently employed are:

▪ Glass fibers, used in construction, watersports and various other non-structural applications. Their moderate production cost makes them one of today’s most commonly used fibers.

▪ Woven carbon fibers, used for primary structuring applications, are obtained by controlled pyrolysis of an organic or inorganic precursor, the most common of which is PolyAcryloNitrile (PAN). The prices of these fibers are still relatively high but have steadily fallen as production volumes have grown. They are found in many aerospace applications but also in competitive sports and leisure activities (Formula 1 racing, boat masts).

ELECTRICAL PROPERTIES OF CARBON FIBER

But what interests us in carbon fiber here is its electrical properties because, for an equivalent heating power, its electrical resistance is a thousand times greater than copper’s. As carbon fiber is also five times lighter and has a tensile strength ten times greater, a carbon cloth composed of thousands of micro-filaments can be used in place of a copper filament (fig. 4).

The working principle of the ECS (Energized Composite Solution) technology therefore consists in impressing an electrical current in the carbon fiber which, thus energized, will act a heating resistor.

One of the prime advantages of the ‘energized’ carbon fiber (ECS) lies in the reliability of the heating resistor. Even if it is damaged, the myriad interconnections between the carbon filaments will still assure electrical continuity. This redundant reliability is the major strong point of the ECS but not its only quality, as carbon fiber is also easier to deploy, even over very long distances, by means of successively deposited, continuous layers of composite. Compared with other technologies, it offers more even heat distribution due to the extensive heating resistor surface (composite layer) and ensures redundancy and robustness.


What’s more, the large number of interconnections between the carbon filaments means that electrical continuity is maintained in the event of damage.

APPLICATIONS OF THE ECS

Three deep offshore applications of the ECS have been identified. They correspond to the different patents filed by Total and are worth a mention here.

ECS COATING (PATENT 1)

The first application is in a composite ‘sandwich’ application (fig. 5), coating a substratum with a layer of carbon to obtain a heating envelope. Potential candidates for this are metal tubes (fig. 2 p. 44), valve bodies, separation vessels, and so on.

The ECS coating puts an ‘all-electric’ development scheme within reach, one stretching all the way from the zone in the well, where the ambient temperature no longer allows the formation of hydrate plugs, to the surface equipment including the subsea production components.

fi g. 5: Structure of the ECS heated coating

When the coating (matrix) of the composite is a thermoplastic resin, tubes can be joined by overlapping the interconnections between the carbon micro-filaments, so as to reconstruct the heating resistor’s electrical continuity either by straightforward thermofusing or by patch repairs. In addition to the possible applications in ‘Pipe in Pipe’ technology, this extends the scope of application to flowlines, regardless of laying method, and to all kinds of thermal insulation (fig. 6). Unlike thermally insulated metal pipelines, the self-heating carbon line offers active temperature management of the pipe.

fi g. 6: Joining tubes by non-metallic electrical connections

FIELD OPERATIONS


fi g. 7: Joining tubes by non-metallic electrical connections

3. see article on the subject entitled “Winterization for a densely equipped LNG module” - p. 85 in this issue

fi g. 8: Heating tube application, with a plain composite structure replaced by the ECS

ECS HEATING PANELS (PATENTS 2 AND 4)

Two patents applying the ECS technology to heating panels have also been filed. These structures may be rigid or flexible.

In the case of the rigid panel, the structure is a composite ‘sandwich’, with a heating element built into one of the layers. It could be used in Arctic conditions to protect equipment by preventing it from freezing (part of what is known as ‘winterization’3).

The flexible panel has the same kind of composite sandwich structure but, in this case, the resin is an elastomer (silicone for instance). The objective here is to form a flexible heating layer, isolated electrically from the outside and structured in the same way as the coating (fig. 7) but in this case without a substratum.

This type of flexible panel, in the same way as an electric blanket, could be used for example to heat items of subsea equipment or pipelines for hydrate dissociation purposes.

APPLICATION AS A NON-METALLIC HEATING TUBE (PATENT 3)

This application is based on ongoing R&D studies into how composites are utilized for their mechanical properties in various areas to do with the deep offshore: tubing, jumper, flowline, riser…

The principle here, as figure 8 illustrates, is to ‘energize’ part of the composite structure so that it gives out heat.


AN ONGOING TASK

A 30-meter-long jumper is currently being tested in the R&D laboratories to gain greater understanding of this new heating method on a scale-1 model and find answers to several practical and theoretical questions.

The jumper represents a subsea link between a wellhead and a manifold. The tests are an opportunity to observe at full scale how the heating system behaves in elbows and straight sections alike, as both the manufacturing process and deployment may cause substantial differences between measured values and those theoretically calculated.

FIELD OPERATIONS

SOME EXAMPLES

In the course of the preliminary studies, several prototypes were built to serve both in calibrating our models and for communication purposes. Figures 9 to 11 offer some examples:

APPLIED AS A COATING

APPLIED TO HEATING PANELS

USED AS A NON-METALLIC HEATING TUBE

fi g. 11: ECS 2 prototype composite structure: 6-inch ID composite tube, 1.5 m long – carbon fi ber, PA11 resin (nylon)

fi g. 10: ECS prototype panel: 1.5 m x 0.5 m sheet in polyester/carbon/polyester silicone resin

fi g. 9: ECS 1 prototype coating: 4-inch ID steel tube, 1.5 meters long with a glass/carbon/glass epoxy resin coating.


fi g. 12: Jumper prototype equipped with various sensors to study the type of ECS heating

The temperature-induced pipe dilation phenomena observed may occur in combination with the displacement phenomena (bending, twisting…) that the jumpers undergo at the production phase (fig. 12). These, together with the mechanical behavior of the heating material subjected to external stresses and its adhesion to the support tube will be important points to analyze.

The results expected from the study concern:

▪ The construction method: the objective is to validate all the construction options, to check feasibility at the required dimensions and to evaluate the limits of this type of setup.

▪ Workshop tests: these will be carried out in a closed room (airflow at less than 0.4 m/s) to calibrate and validate operation of all the sensors, the power supply and whatever other systems are necessary for the final tests.

▪ Tank tests (observations and measurements in real conditions).

ConclusionThe ECS technology is at present going through the qualification process designed to establish that it is mature and to optimize it. Once that milestone has been reached the prospects for use of the ‘Energized Composite Solution’ will be wide-ranging and will remain so as long as future developments include line heating in their flow assurance strategy.

Those prospects include all-electric heating for future field developments, which will considerably reduce – and possibly eliminate – the use of methanol, spelling improved safety.

Meanwhile, we are already being asked to investigate applications directed at various targets:

▪ Heating of the export line of a project in Uganda ▪ Heating of the GRP fire system on the

Shtokman FPSO

▪ Phase 2 of Shaz Deniz ▪ Heating of waxy fluids ▪ Trace heating of lines prone to corrosion under

thermal insulation. ▪ Topside line heating to prevent top of line

corrosion on gas pipes. ▪ Core preservation under HP/HT (high pressure,

high temperature) conditions.

But many more avenues have yet to be explored… The diversity of the requests reaching us confirms just how important it is for us to concentrate our efforts and develop this bold and promising technology quickly, for the deep offshore domain and many others.


INSTALLATION INTEGRITY

WI15 repair project:Girassol water injection line repairPipeline Repair System – PRS

Emmanuel BIGOT [Total E&P Indonésie]

Emmanuel started his offshore career on the UFL package of the Dalia project, working on the interfaces during the installation phase. He was then appointed to the Subsea Operations department of the New works division in the Angolan subsidiary, holding a position as Asset manager. He took the reins of several projects, including repair of the I15 injection line.

He is currently at the head of the Project Control & Support department (Projects division) of the Indonesian subsidiary in Jakarta, working on all of the site’s development projects.

Emanuel JOSÉ [Total E&P Angola]

Emanuel started his career as a Marine Surveyor at ABS (American Bureau of Shipping), in Korea and Singapore. He was involved in building new oil tankers and had the opportunity to work on the surveyor team in Korea’s largest shipyards, DSME & SHI, during construction of the oil tanker Sonangol Namibe for the national Angolan oil company Sonangol.

After 3 years, in 2008, he joined Total E&P Angola as Subsea Project Engineer, dealing mainly with repair and installation projects for Block 17. In 2009, he joined the Girassol I15 Project team where he was in charge of local content, SDF (Spool Deployement Frame) and Spool assembly.

Alain LECHON [Total]

Alain has 30 year experience of subsea engineering in the offshore oil industry. He started out in his career working on the first subsea developments in Africa and Norway, in the ‘Advanced research and techniques’ department, where he devised subsea robots and tools, before working for 10 years as a pipeline specialist. In 2002, he took part in the Canyon Express gas pipeline laying operation, the deepest offshore project in the Gulf of Mexico at the time.

In the last 5 years, Alain has designed a number of deepwater pipelines and he monitored the technical aspects of the repair project on Girassol’s I15 line. In 2009, he joined the subsea team where he works chiefly on repair systems and on designing and constructing spools and jumpers.

AUTHORS


Subsea pipeline repairs are complex operations. Developing an efficient fully subsea repair method for deepwater pipelines (under more than 1,000 m of water), with neither surface recovery nor production shutdown, is a real challenge.

The ‘W115 Repair Project’ represents a significant innovation, as no repair of this kind has ever been performed at such a depth before. It is an example of the technological advances achieved in the Oil & Gas industry, and especially for deep offshore contexts.

This project merits an award because it is a real innovation, never before implemented in the Group, and has required considerable R&D efforts (design, manufacture and testing of new subsea tools). The offshore installation performed by Total E&P Angola (TEPA) with its naval resources (FSV Bourbon Jade) was ultimately a complete success.

We can all be proud of this achievement, since it involved the first ever use of a number of subsea tools and the successful performance of several critical heavy lifts. The entire project was accomplished within the approved budget. The Company may now continue with water injection upon removal of the hydrates from the corresponding injection well, which will eventually improve the reserves recovery rate.

We would also underline the boldness shown by Total E&P Angola in performing this repair at such depth, using local vessels and entirely new subsea tools. Attentive listening to the Contractor’s needs and mutual support between several TEPA entities and Head offices were other key contributors to the success of this project.

Éric DAFLONTechnical Manager (Total E&P Angola)

CONTEXT



IN SHORT

In August 2004, after less than a year in service, the 12-inch water injection line WI15 on the Girassol field offshore Angola failed at a J-Lay collar located 3.3 kilometers from the riser tower in a water depth of 1,350 m. The consequence was a reduction in the reserves recovery, estimated to be around 10 million barrels in 2005.

Following investigations to determine the causes of the rupture, Total decided to launch the ‘WI15 Repair Project’ as a design competition. The result was that early in 2007, Subsea 7 was awarded a contract for the design, manufacture, testing and operation of a new deepwater pipeline repair system (PRS), installation of which remained under Total E&P Angola’s (TEPA) responsibility.

The PRS is a completely subsea repair, requiring no surface recovery. It comprises a set of equipment permanently deployed on the sea floor, together with a suite of ROV-deployed and recoverable tools. It works on the principle of installing a spool and associated equipment on the seabed adjacent to the damaged section. This is then cut out and the pipe ends lifted onto a temporary structure directly above the spool ends. The pipe ends are then prepared and lowered to align with the spool. The pipeline connectors are then moved into position over the spool-pipe intersection and actuated to grip and seal both sides of the intersection.

The PRS was installed offshore, safely and successfully, late in 2009 using TEPA’s Field Support Vessel, the Bourbon Jade. The key distinguishing features of this PRS were: the need for only a relatively small support vessel as platform for all deepwater repair operations; the development of new subsea equipment including reversible connectors; the high local content; and the potential to adapt the system to pipes of 6- to 16-inch diameter for future, short repair interventions not exceeding 20 days.



The Girassol field is situated offshore Angola and operated by Total E&P Angola1 (TEPA). The 12-inch water injection line, WI15, was found ruptured in August 2004, after 9 months of operation. The rupture was located in a section approximately 3.5 km from the riser tower at a water depth of 1,350 meters. After a detailed survey, the ruptured part of the pipeline was cut out and transported to a laboratory for analysis.

Investigations and analyses were carried out to determine the causes of the failure. The Company decided to launch a design competition to develop a repair system specifically tailored to deep offshore conditions. The project was dubbed ‘WI15 Repair Project’ and was conducted, initially, by the Technology department (project and subsea teams) in Total E&P Head offices, and later by TEPA’s subsea department.

Based on the results of the technical design competition and after approval from Sonangol and the partners, TEPA awarded Subsea 7 the contract to design, manufacture, test and operate a new deepwater pipeline repair system and to provide assistance to TEPA in performing the offshore repair.

DAMAGE

The failure in the pipeline is due to overstress and excessive bending during installation. The bend, combined with operating loads during six months, weakened the pipe, causing the rupture (fig. 1).

The different analyses highlighted several causes, the main one being the installation procedure; a possible initial crack was associated with an undercut on the J-lay collar. The secondary causes included fatigue pressure cycles (defective valve regulation) and lateral buckling, which caused the ultimate rupture.

THE REPAIR PROJECT

This project was extremely demanding in R&D terms (design/fabrication of completely new subsea machining tools) and this was indeed the first time a repair operation like this had been carried out at such a depth in the world. Several companies, based chiefly in Scotland, France and the USA, played a part in completing the project, with TEPA, Subsea 7 and oil states at the helm.

fi g. 1 : Girassol layout – Water injection line failure location

1. Angola’s national oil company, Sonangol, is Block 17 titleholder. Total is operator with a 40% share, alongside StatoilHydro, 23.33%; Esso, 20%; and BP, 16.67%.



fi g. 2: Pipeline Repair System - general overview

fi g. 3: SDF mud mat installation

PIPELINE REPAIR SYSTEM (PRS)

The repair principle basically involved connecting an M-shape spool 35 m long and 24 m wide to the existing pipe, using two connectors especially designed for the purpose (fig. 2). Their special feature is that they leave a gap between the spool and the pipe in place, which means that the spool does not have to be manufactured with millimetric precision. Several tools were also specially developed for this project.

The inset on p. 56, entitled “PRS components”, briefly presents the key pieces of equipment required to perform the deepwater pipeline repair.

OFFSHORE OPERATIONS

The installation offshore was performed within 20 days in three phases.

The first phase consisted of installing the two mud mats (17 x 12 m and weighing 34 tons each), as illustrated in figure 3.


fi g. 5: Spool positioning on the SDF

fi g. 6: Spool positioning on the SDF

fi g. 4: SDF, ECS & spool installation

2. abbreviations are defined in the inset “PRS components” p. 56

The second step was the installation of the SDF2, ECS and spool (fig. 4). To begin with, the SDF (60 m long and weighing 60 tons) is lowered and set down on the mud mats. Two End Connection Skids (ECS) – 20 m long, 35 tons – are then added on to the ends of the SDF. Finally, a spool (24 x 35 m) is lowered and precisely positioned on the SDF (fig. 5).

The third and final phase was to achieve and complete the pipeline connections. A Connector Installation Tool (CIT) is used to lower one of the two connectors into position on the first end of the spool. One end of the pipeline is lifted, aligned and set in position on the CIT. The remainder of the pipeline is then put in the horizontal position and lined up correctly by means of two lifting tools: the Pipeline Handling Frame (35 tons, see fig. 6) and a Pipeline Alignment Clamp (34 tons). The end of the pipeline undergoes subsea machining and is then re-aligned with the spool – once more using a Pipe Alignment Clamp. The connector is translated between the spool and the pipe (again using the CIT). Once the connection has been activated hydraulically and tested for sealing, the whole operation is repeated on the other end of the spool.

Note that the ‘web’ version of this article includes a 10-minute video clip showing the different steps of the installation.



MORE

CHALLENGES – TECHNICAL INNOVATION AND COMPLEXITY

This project entailed several challenges and implemented several technical innovations, for example:

▪ The repair was a completely subsea one, with no surface recovery (1,350 m water depth) and took only 20 days. No similar repair has been performed before at such depth and without previous metrology.

▪ The Coating Removal Tool (to remove the 3-mm polypropylene coating so as to

The ROV Interface Skid is located under the ROV and provides the means for the ROV to interact with and operate the other PRS assemblies.

The Pipeline Coating Removal Tool is used to remove the pipeline surface coatings, stripping them to the bare pipe metal.

The Pipeline Cutting Tool cuts off the ends of the pipeline at a predetermined location to facilitate connection to the spool.

The Pipeline End Preparation Tool is useful for removing any ragged edges from the end of the cut pipe, to minimize the likelihood of damage to the connector.

The Tooling Transportation Skid secures the tools for safe transportation between onshore and offshore sites.

A Hydraulic Powerpack and Control System is used for functional deck testing and to operate the component assemblies of the PRS.

The Spool Deployment Frame (SDF) supports the spool and provides the means of deploying it on the seabed. It also provides the location and reference for the pipe handling clamp assemblies and general alignment capability for the pipe/spool ends.

Pipeline Connectors are deployed on the ends of the spool-piece. The connectors are “grip” and seal type with elastomeric seals. The design is based on two standard connectors welded back-to-

back with a reversibility function. The connections are between the spool ends and the pipeline.

Pipeline Recovery Tools are used to lift the cut ends of the pipeline into pipeline guides on the spool deployment frame.

A Pipeline Alignment Clamp is located on the end of the spool deployment frame: it provides the means to secure and align the pipeline end with the spool-piece end.

The Pipeline Handling Frame, placed over the pipeline, provides additional support and alignment capability to the pipeline after the pipeline lifting clamps have been deployed.

At the end of the spool and pipeline, we also fi nd a Pipeline Alignment Tool to accurately measure any misalignment between them.

The Spool is 4 m x 22 m x 20 t with a shape optimized to absorb thermal pipeline expansion and to facilitate installation by the intervention vessel – the Bourbon Jade.

The End Connection Skids (ECS) are installed at both ends of the spool deployment frame and incorporate a pedestal for landing the spool, guide rails for the connector installation tool and a roller for supporting the pipeline span.

The Connector Installation Tool (CIT) is used to lower the pipeline connector to the seabed and slide it over the spool/pipe joint.

PRS components

allow steel-to-steel connection between the existing pipe and the connector).

▪ The retrievable connectors, which can be activated/deactivated several times.

▪ The Connector Installation Tool via which the connectors can be translated onto the spool and the existing pipe with zero buoyancy.

▪ The Pipe Alignment Clamp, to correct potential misalignment between the spool and the existing pipe without damaging the four seal barriers inside the connector.

▪ The PRS installation, using TEPA’s field support vessel, the Bourbon Jade.


LOCAL CONTENT

Initially, the plan was to build the spool, end connection skid, spool deployment frame and mud mats in Angola. But, for technical and financial reasons, only the spool (21 t, 35 m / 24 m) and the spool deployment frame (55 t, 60 m long) were ultimately manufactured there. The local content was still quite high, because in addition to the equipment manufactured locally, the vessel used was the affiliate’s own, chartered from local contractor Sonasurf.

ConclusionThe repair was successfully completed and now represents a milestone in deepwater interventions. The solution developed by TEPA/Subsea 7 has the potential to be used in a range of life-of-field applications, as the equipment and technology are fully transferable.

The project’s success highlights the technological advances that have been made in the oil industry, and also the massive involvement of Total in conducting research and development in the shape of the high-level studies required in this area.


RACS (Riser Annulus Condition Surveillance)or how to guarantee the integrity of our flexibles in operation

1. currently assigned to Total E&P Nederland B.V.


Jérôme WOIRIN1

[Total]

Jérôme headed the Exploration & Production R&D project called Development of the Deep Offshore from 2008 to 2010. He is currently field operations manager with Total’s Dutch affiliate.

His operating experience was a serious asset on the RACS project where he set his sights on finding simple, robust and reliable solutions.

Olivier COSSE [Total]

From 2009 to 2011, Olivier was in charge of the subsea equipment (and therefore the flexible lines) on the FPU Alima.

He now works as subsea production system specialist for pre-projects in the Development Studies division of Development (EP-D).

Benoît BALAGUÉ [Total]

After 6 years as an engineer designing flexibles with FlexiFrance (Technip) and Technip Oceania, Benoit joined Total’s ranks early in 2008 as a riser specialist in the Technology division of Development (EP-D).

Jean-Philippe ROQUES [Total]

Jean-Philippe has built up considerable experience working with Coflexip and Saipem in flexibles and umbilicals.

At present, he is a specialist in ‘flexibles, umbilicals and risers’ in the Technology division of Development (EP-D) of Total’s Exploration & Production branch.

Jean-Jacques BASSAFOULA [Total E&P Congo]

For nearly 30 years, Jean-Jacques has worked on practically every onshore and offshore site in Congo, at commissioning, start-up, then often ramp-up (for two or three years) and finally stabilization of the production installations.

On joining the Moho-Bilondo project in January 2007, he took part in the construction stage in South Korea, then in hook-up, followed by commissioning and start-up on the Congo site. At the end of June 2011 Jean-Jacques left the position as site manager/RSES (site safety-environment manager) that he had held until then on Moho-Bilondo.

AUTHORS


TOTAL SA has been working in Congo via its affiliate Total E&P Congo (TEP Congo) for over 40 years. It plays a leading economic role through its operated production (60% of Congo’s output, representing approximately 200,000 boe/d), the funds it invests in the country, its activities and the jobs it generates directly or indirectly. Like the Group, the affiliate conducts its operations in full compliance with environmental standards and pays particular attention to the safety of its personnel and the integrity of its installations. Ever since the dramatic accident on N’Kossa in May 2007, TEP Congo has been extremely sensitive to the specific issue of flexible integrity. It effectively has more flexibles than any other affiliate in the Group, most of them in operation on mature installations.

The solidarity sparked throughout the Group in the wake of the accident spurred an R&D project, launched in 2008, directed at developing a surveillance system for flexible pipe annuli. The Congo affiliate considered it only natural to play a part in this bold adventure from the start.

By combining cross-disciplinary competencies (specialists in operation and inspection of flexible hoses) and efficient communication between the affiliate, the Research group and the industrial partner (Schlumberger) about the requirements and constraints, we were able to develop and qualify a simple, tough and dependable system, one that is above all adaptable retroactively to flexibles in operation.

All these efforts were coordinated and channeled in record time to get a pilot up and running on the flexibles of the FPU Alima in December 2009. This system outperforms the one initially installed on the FPU Alima’s flexibles, firstly because it yields excellent, reproducible results and also because it is cheaper and simpler to install and use.

The RACS provides us with a system for monitoring the integrity of our flexibles, one that we have every intention of extending to other applications in the affiliate. It is also a world first acclaimed by our peers.

Jacques AZIBERTManaging Director, Total E&P Congo

CONTEXT




IN SHORT

For Total, assuring the integrity of E&P installations is a priority – as the project presented here plainly shows.

It all started back in May 2007, after an HP flexible production line accidentally ruptured on N’Kossa. Feedback pinpointed the absence of any system for keeping the annulus of the flexible lines under surveillance.

Realizing the scale of the problem at hand, Total set about tackling it head on. In early 2008, in the frame of its R&D project devoted to the Development of the Deep Offshore, the Group pioneered a cross-functional reflection on how to develop just such a surveillance system to guarantee the integrity of flexible hoses in operation.

The multidisciplinary work - federating skills in Total E&P Congo, the Technologies and Field Operations divisions and R&D – culminated in the development of the RACS system: Riser Annulus Condition Surveillance.

The RACS is a simple tool, robust and reliable, developed in partnership with Schlumberger. Its vocation is to detect in real time any rupture in the outer sheath of a flexible that has been damaged but also to monitor the diffusion of water and gas through the internal layer of polymer in the annulus of an operating flexible. It is based on a measuring principle directly derived from a technique used for monitoring hydrocarbon reservoirs.

A pilot RACS, concentrating everybody’s efforts, was installed on two flexibles on the FPU Alima in record time in December 2009. Its results outshine the performances of the Force Technology system installed at start-up.

The Group now has at its disposal a reliable tool for verifying the integrity of its flexible lines, one that can now be installed as a matter of course wherever it is considered necessary, both on new flexibles and on lines already in operation.

In recognition of the quality of the work achieved on this project, the RACS earned an OTC award from the industry in 2010.


Total uses a great many flexible risers for transferring its liquid, gas or multiphase effluents under pressure. We currently have around 172 in operation and the number will increase further in coming years as new fields are developed.

Whatever the operating mode (fixed structures or floating support vessels), all these risers are subjected to considerable stress, from the fluids circulating inside them but also from external environmental constraints (marine currents, swell or repeated deformations induced by the movements of the floating support vessels).

The risers are designed with a complex architecture, precisely to accommodate such highly dynamic behaviors. Unfortunately, until now, we have had no reliable, user-friendly way of continuously keeping track of their integrity.

This was the gap that R&D and the Technologies division (in E&P Development) in Head offices and Total E&P Congo (TEP Congo) decided to bridge, via the Development of the Deep Offshore project and a partnership with Schlumberger, to develop a system capable of continuously verifying the condition of the risers and guaranteeing their integrity.

RISKS ARISING FROM FLEXIBLES

FLEXIBLE RISER

A flexible is a pipe with a multilayered structure comprising two polymer sheaths with reinforcing steel armor between them. The outer sheath provides protection against the surrounding environment while the inner (pressure) sheath protects the armor from the fluid carried.

The two sheaths therefore form an annulus containing the armor. It is essentially this that endows the line with its mechanical resistance to internal forces, such as pressure, and external forces such as torsion and elongation of the line (fig. 1).

WATER INGRESS INTO THE RISER ANNULUS

The armor layers, made of wire with high mechanical performance, are sensitive to water, and the flexible’s service life will be strongly affected if corrosion – general or due to fatigue (a combination of gradual cracking and corrosion) – sets in. Water can penetrate into the annulus via two separate, unrelated phenomena: diffusion, followed by condensation, of production water through the pressure sheath, or damage to the outer sheath allowing seawater to flood the annular space.

▪ The former (diffusion of production water) is a known phenomenon, factored into the line’s design, but needs to be monitored and checked on throughout operation.

▪ The latter (line damage), must be detected as soon as it occurs.

fi g. 1: Standard section of a fl exible line



RISER SURVEILLANCE

The vast majority of flexible pipe ruptures are caused by damage to the outer sheath, which leads to water entering the annulus and corroding – ultimately rupturing – the line’s armor.

Until now, flexible riser surveillance was ensured by means of integrity tests, flow-rate measurements and inspections.

▪ The annular space is tested once or twice a year, depending on the line’s criticality, to check for damage to the seal and determine the quantity of water in the annulus. Testing campaigns are spot operations that are costly to run and do not offer continuous monitoring.

▪ Degassing is measured continuously – via the flexible riser’s vents – to determine gas diffusion through the inner sheath, but this provides no information as to the condition of the annulus.

▪ Inspections are conducted on the outer sheath of the flexible riser by human divers and ROV (Remote Operated Vehicules). These too are costly, spot operations that mobilize extensive logistics resources.

None of the testing and inspection means above reliably and continuously monitor the annulus of the flexible risers. E&P therefore made it a priority objective to develop a tool capable of detecting and monitoring the evolution of water penetration in the annulus in order to guarantee the integrity of these lines.

RACS AND HOW IT WORKS

The RACS, or Riser Annulus Condition Surveillance, tool was developed as the result of combined collaboration, both internal, between Total E&P’s Development (Technologies) and R&D divisions, and external, between Total and Schlumberger.

SCOPE OF WORK

The scope of work was defined in detail, specifying the following requirements:

▪ Regular measurement of the free volume and integrity of the annular space.

▪ Immediate detection, tripping an alarm, of any damage to the outer sheath.

▪ Use of reliable, tried and tested technologies.

▪ Possibility of retrofitting to any producing riser that has vent ports.

▪ System easy to use and results easy to interpret for the operators.

We observe that satisfying the first two points in this list would rule out the necessity for annulus testing campaigns and provide a much faster means of responding to damage than diving inspections.

OPERATING PRINCIPLE

The system is based on the measurement of natural diffusion of gas through the inner sheath, a technique directly derived from the one used for monitoring hydrocarbon reservoirs by tracking reservoir pressure buildup.

Figure 2 shows the operating principle, the broad lines of which are as follows:

▪ The pack, fitted with a mass flowmeter and a solenoid valve, is connected to the end of the flexible (fig. 3).

▪ To begin with, the solenoid valve is closed. This way, pressure builds up gradually in the annulus by diffusion of gas through the inner sheath until a predetermined ‘high’ pressure level is reached.

▪ On reaching this threshold, the solenoid valve is actuated and pressure in the annulus is thus vented down to a ‘low’ threshold.

fi g. 2: RACS operating diagram


fi g. 3: Photo of a RACS pack installed on the FPU ALIMA (Congo), photo J.P. Roques

fi g. 4: RACS operating curve

Pressure and temperature are measured when pressure buildup starts and when pressure release is completed (fig. 4), so that the mass flow-rate of the depressurizing gas can be calculated. The volume of the annulus can be recalculated from the three values for mass flow-rate, P and T.

USING ANDINTERPRETINGTHE RESULTS

With the measurements taken and processed by the software, the operating mode of a line can be characterized (fig. 5 – p. 64) and the line’s signature defined.

By measuring the frequency of the depressurizations and the time taken for the pressure to build up, and combining this with the calculated volume of the annulus, the slightest unusual event taking place in the line can quite easily be detected. Loss of integrity in the outer sheath will show up, for example, as faster pressure buildups and more frequent depressurizations, due to water ingress into the annulus.

Alarms are set based on several parameters, including: variation in the calculated volumes of the annulus; change in the depressurization frequency or in the slope of the pressure buildup curves; pressure in the annulus relative to the high and low pressure thresholds.

As these parameters are interconnected, it is also easy to check the severity of each event and interpret the measurement as natural and due, for example, to changes in the production parameters, such as pressure, temperature or flow-rate, or to a problem on the line. Table 1 p. 64 is a schematic guide to interpretation of the results obtained by the RACS.



INSTALLATION

Installation is shown in figure 6. A RACS pack (see fig. 2 p. 62) is installed on each riser to be monitored. A remote I/O junction box connected to each RACS powers the solenoid valve and the various sensors, and also transfers the measurement data to the final component, the acquisition and data-processing computer.

fi g. 5: Operating curve measured on site

table 1: Interpretation of the RACS measurements

fi g. 6 Installation diagram


QUALIFICATIONOF THE SYSTEM

VALIDATION IN THE LAB AND ON SITE

The project was developed in several stages, each sanctioned by a validation test.

The physical model and the selected measuring principle were first validated by means of straightforward volume measurements in the laboratory. The system used for a flexible annulus was then mounted on a spare flexible (6’’, 170 m long), at the Pointe Noire industrial base in Congo (September 2009).

Lastly, the system underwent final validation via a pilot installed on two risers aboard the FPU Alima on Moho-Bilondo (fig. 7). This ultimate qualification test targeted three objectives: validate the measuring and calculating accuracy of the system; confirm over a long period of use its performance and reliability; and, lastly, most important, obtain feedback from the operators as to the functionality of the system.

fi g. 7: Installation of the system aboard the Alima – Moho Bilondo (Congo)

THE PILOT ON THE FPU ALIMA

The Moho-Bilondo field was chosen for the following reasons:

▪ The affiliate had a particular interest in the project and the issue at stake (inspection and integrity of flexibles).

▪ Many different types of riser were in use on Moho, enabling the system to be tested on pipes with different behaviors.

▪ Annulus tests had been carried out on the lines since production start-up, furnishing a solid, reliable basis for comparison with the future results of the RACS.

▪ The FPU Alima was a new unit equipped with an annulus draining system, which would facilitate installation of the pilot.

The complete system (2 RACS packs, I/O junction box and computer) was installed aboard the FPU Alima in December 2009 for eight months.



The RACS packs were successively connected to the flexible production risers (4 of 8” diameter), gas export riser (6”) and oil export riser (15”). All six risers are connected to the FPSO at the surface. They are 1,000 m long and are laid at a depth of 600 m in what is known as a ‘lazy-wave’ configuration (fig. 8).

Volume measurements were taken as soon as the system was installed. Tables 2 and 3 show the measurements obtained from the RACS and at the previous annulus testing campaigns on the 8” production line (table 2) and the 6’’ gas line (table 3) for purposes of comparison.

RESULTS OF THE PILOT

There are different kinds of results. First of all, tables 2 and 3 together with figure 9 plainly show that the results obtained from the RACS concur perfectly with those obtained from previous annulus testing campaigns.

Next, the Alima Subsea team monitored the way the RACS operated and confirmed that the system worked well and that it produced good results in terms of both quality and reliability.

Finally, the Subsea team utilized the RACS in the course of the pilot phase for checking the integrity of the instrumented lines.

The results (fig. 10) confirmed that none of the outer sheaths were damaged, that the annuli of the oil export (15’’) and gas export (6’’) risers were dry, and lastly that the annuli of the oil production lines (8’’) were gradually filling with water, thereby corroborating the calculation hypotheses made at project phase (diffusion of production water).

fi g. 8: Riser confi guration on Moho-Bilondo

table 2: Results for the 8’’ production line

table 3: Results for the 6’’ gas export line


fi g. 9: Annular volume of a production riser: comparison of measurements from pressure tests and from the RACS

fi g. 10: Annulus volume measurements of the production riser by RACS

ConclusionThe RACS is at present the only system in the industry capable of continuously calculating the volume of the annular space and detecting, from topsides, any rupture in the outer sheath of a flexible line.

The RACS project was conducted jointly by various entities in Head offices and in Total E&P Congo – not forgetting Schlumberger of course – and culminated in the development of a tool that is technically dependable, efficient and meets operators’ needs. Not only this, but it was completed with an extremely short lead time between determination of the scope of work and delivery of the industrial solution. The system installed onboard the FPU Alimais to be maintained over and beyond the period set for the pilot operation, and the other risers on the vessel are to be instrumented too.

In enabling the affiliate to abandon annulus testing campaigns, there is no doubt at all that the RACS offers financial savings and at the same time improved control of the risers.

Better still, the system is now to be routinely installed on all the Group’s risers – hence on the ongoing projects Usan, CLOV and Egina – and also on existing risers, such as on Girassol.

Lastly, the RACS won an OTC award in Houston in May 2010 and is soon to be produced commercially for sale by Schlumberger.

BIBLIOGRAPHY

Joint communications by Total and Schlumberger announced this innovation to the industry, one delivered at the OTC 2010 (‘OTC 20973: Flexible pipe integrity monitoring: A new system to assess the fl exible pipe annulus condition’) which earned an ‘Award on New Technology’, and the other at the Rio Oil & Gas Conference in 2010 (‘Field Test of a Flexible Pipe Integrity Monitoring System’).


Evaluating the severity of dents in pipelinesor how to guarantee the integrity of damaged pipelines

Dominique POPINEAU [Total]

Dominique is a pipeline specialist in the E&P Technologies Division. With almost 30 years’ experience in pipelines, from design to construction and operation through to repairs, he has in-depth knowledge of the different stages of the life of a pipeline.

Paul WIET [Total]

Paul is head of the Total E&P Technologies Division’s ‘Pipeline’ specialty. He now has 35 years’ experience in the operational disciplines concerned with pipelines, in both affiliates and Head offices, offshore and onshore. Conscious that dents in pipelines represent a real challenge, he launched the EmpreinteTM program in 2005, to provide field operators with a reliable decision-aid tool as quickly as possible.

Jérôme WOIRIN [Total]

From 2008 to 2010, Jerome was head of the Deep Offshore Development project in the E&P branch’s R&D department.

He is now Field Operations Manager in Total’s Netherlands affiliate. His operational experience has served him well in his search for simple, robust and reliable solutions, a thread running throughout his mission as head of the project.


Jerome is head of the deep offshore development R&D dpt, and follows various projects. Owing to their overlapping activities, Dominique and Paul often find themselves working together, especially when it comes to investigating damage to pipelines.

In the deep offshore development context, they follow, with Jerôme, different projects which combine E&P development technologies and R&D, including this EmpreinteTM project.

AUTHORS


CONTEXT

“RELIABLE EVALUATION OF THE SEVERITY OF DENTS IN PIPELINES”

When any significant incident occurs on a pipeline carrying oil products it is essential to be able to rapidly and precisely evaluate whether the pipe has been damaged and, if it has, the extent of the damage and how urgent it is to repair it.

The solution often chosen consists of replacing the affected part of the pipeline for safety reasons, assuming the consequences this entails: inherent cost of the repair, the production lost in reaching difficult-to-access pipelines (deep offshore, desert zones) and the sometimes long lead-times for mobilizing the repair means.

The Empreinte™ software application, developed by Total E&P, combines the input of specialists from different technical backgrounds. It is used to calculate the damaged pipeline’s new maximum working pressure.

The point of an application like this for the profession is that it offers – whenever this can be done safely – an alternative to the conservative solution of systematically and immediately replacing the pipeline. The simulations run with Empreinte™ have been validated by experience. Repairs can now be planned, and consequently substantial savings made without affecting safety.

This application was developed as the result of an innovative approach to evaluating pipeline damage: it recreates the shape of the object that caused the dent (hence the name Empreinte – in French, the imprint made by something, such as a fingerprint) and accurately estimates the plastic flow phenomena which reduce the strength of the steel and can result in rupture.

A patent application has been filed for this program, which will be an extremely useful tool in the future for evaluating cases of major damage outside the traditional scope of codes and other damage evaluation methods.

Bernard AVIGNONVice-President, Operations at Total Exploration & Production



IN SHORT

Several years ago, after several pipeline accidents (most of them outside the Total Group), the oil industry invited work groups to investigate the subject of predicting the burst pressures of damaged pipelines. Damage evaluation guidelines were produced as a result but these remained general and conservative in approach and, above all, were applicable only to minor damage. Total, however, having observed far more serious damage on offshore pipelines, wished to go further and, in 2006, initiated a specific study as part of the ‘Deep Offshore Development’ R&D project.

This cross-functional work, initiated by the Technologies and R&D Divisions, culminated in the development of a predictive application, developed in conjunction with Tecnitas (a subsidiary of Bureau Veritas). The Empreinte™ application has three objectives: to model pipeline dents, calculate ultimate burst resistance and deduce a working pressure that includes an appropriate safety factor.

To evaluate damage to pipelines, Empreinte™ uses an innovative approach: from the measured damage, it recreates the shape of the object that created the observed dent, then reproduces the damage by calculation and finally predicts the rupture pressure.

The method was validated by a series of burst tests on pipes on which dent-type damage (some extending to more than 50% of the pipeline diameter) had been inflicted and metal loss deliberately induced.

The software application was used in real conditions for the first time when an explosion damaged an HP gas pipeline feeding an LNG plant. Where strict application of the damage evaluation codes dictated the conservative course of replacing the damaged section, Empreinte™ confirmed that the repair could be postponed. The plant’s production was therefore quickly resumed, minimizing LNG production losse (which might have attained between 100 and 200 million USD if the damaged section had been replaced immediately).

With Empreinte™ (patent pending), the Group now has a reliable tool for checking the integrity of its damaged pipelines.



Mechanical damage on pipelines may have disastrous consequences. As it cannot avoid all risks of damage, the oil industry obviously tries to prevent ruptures and their consequences: risks for the environment, plus, for the company, a high price to pay in terms of both money and image.

As a precaution, the conservative solution is generally to replace the damaged part. Though effectively preferable, this solution does have a substantial cost (the repair itself plus the related production losses), so it is advisable to adopt it only when absolutely necessary and to implement it at the time we choose. The main issue therefore lies in assessing the damage severity and the resulting risks as accurately as possible.

THE “STATE OF THE ART” IN THE EARLY 2000s

To address the issue, the industry initiated several studies into the prediction of burst pressures of damaged pipelines. Several damage evaluation guidelines were produced, such as the GESIP1 which assesses first damage and then the burst strength of the damaged pipeline.

These are all very useful, but only to a limited extent because they give very cautious estimations and are applicable only for minor damage (dents less than 7% of the diameter) of the kind typically found on onshore pipelines.

The problem still remains for offshore pipelines, on which the damage encountered may be much more severe and affect as much as 50% of the diameter (e.g. when snagged by an anchor). When this type of major damage is discovered on a pipeline, the decision taken is generally to stop production and replace the damaged section. This is very costly, particularly due to the time lost mobilizing the intervention personnel and means to carry out an unscheduled repair.

Some shutdowns are inevitable but others could doubtless be avoided if a rapid and reliable evaluation tool were available. The question was therefore “How can we evaluate the effect of a major impact, and reliably assess the mechanical strength of the damaged section of pipe without knowing what caused it?”

1. GESIP: guide to Surveillance, maintenance et réparations des canalisations de transport (Transmission Pipeline Surveillance, Maintenance and Repair) published by the French Oil and Chemical Safety Group (GESIP)


PIPELINE DAMAGE STUDY STRATEGY

A study was therefore initiated in 2006 by the Technologies and R&D divisions, as part of the ‘Deep Offshore Development’ R&D project, with the aim of designing a specific software application for the purpose. Preliminary discussions led to ideas on the following:

▪ Characterization of the damage: the geometry (measurement) of the affected pipe’s deformation is used to define a virtual ‘impactor’, by the finite element method

▪ Simulations by finite element calculation: this virtual ‘impactor’ is used in a finite element calculation to reproduce the deformation observed and to calculate the mechanical condition of the pipe section caused by the damage.

The Empreinte™ application was therefore developed with Tecnitas (subsidiary of Bureau Veritas) in the frame of this study. A patent application was filed for it by Total, and a partnership agreement was signed, ensuring that the application can be used throughout the Group, with royalties being paid to Total for each study carried out with Empreinte™ by Tecnitas for third parties.

HOW THE EMPREINTE™APPLICATION WORKS

Figure 1 describes the methodology.

REAL DAMAGE ANALYSIS

This is carried out in three stages: measurement of the real damage, digitization of the damage caused and creation of a virtual ‘impactor’ assumed to have caused the dent.

MeasurementPipelines can suffer impacts (see example in figure 2) in different environments (onshore, buried, subsea, etc.) and the methods for measuring them must be tailored to these conditions.

Digitization of the damageThis is done for calculation purposes. The block diagram in figure 3 summarizes the methods selected to digitize the damaged area.

fi g. 1: Diagram of the Empreinte™ methodology

fi g. 2: Example of damage to a pipe section before a burst test

fi g. 3: Characterization of the damaged surface



Creation of a virtual impactorA virtual impactor is created by the finite element method from the scatter plot in figure 4. Figure 5 shows the virtual impactor obtained from the previous damage (fig. 2).

fi g. 4: Scatter plot in the damaged zone (a) Longitudinal cross-section (b) Isometric view

fi g. 5: Finite element model of the virtual impactor

fi g. 6: Pipe sections after burst testing

(a)

(b)

DAMAGE SIMULATION

The finite element calculation simulates the impact made by the virtual impactor on the pipe in as-new(or as assumed before the damage) conditions. The aim is to find out how the impact affects the pipe’s mechanical strength. The inset ‘Burst simulation calculated by the finite element method’ (p. 74) gives more details on the method used.

This original approach allows an evaluation of the damage actually suffered by the pipe section, particularly during the transient phase of the impact when the deformation is greater than the residual deformation.

This phase is associated with phenomena such as pipe wall thinning, when the steel’s yield strength is exceeded locally, and with changes in the steel’s mechanical characteristics (strain hardening).

The characterization makes it possible to take a fingerprint (hence the name of the application) of the damage, enabling it to be represented in 3D.

The result of the digitization is a scatter plot. Figure 4 shows the scatter plot corresponding to the damage in figure 2.


The aim of the fi nite element calculation is to verify the mechanical strength of the pipe section after the impact, in particular by calculating its burst pressure.

The pipe’s conditions before the impact are taken into account: geometry, material law, boundary conditions, internal and external pressure, etc. Then the impact and the elastic return of the impactor are simulated, such that the calculated shape of the damage corresponds exactly to its real shape, as measured. Finally, the internal pressure is increased to the point of (virtual!) burst of the pipe.

Burst simulation calculated by the finite element method

MORE

The calculation steps are the following:

▪ Application of pipe conditions before impact (gravity, axial stresses, internal pressure, etc.)

▪ Simulation of impact with the virtual impactor (fi g. A)

▪ Withdrawal of the impactor and elastic return of the pipe, loss/no loss of metal associated with the impact

▪ Increase in internal pressure until the pipe bursts (fi g. B and C).

fi g. A: Displacements (left) and von Mises stress (right) at end of impact

fi g. B: von Mises stress at burst (left) and evolution of deformation with burst pressure (right)

fi g. C: Stress vs. pressure curves at different points of the pipe



VALIDATION OF THE SIMULATIONS AND ADJUSTMENT OF THE PARAMETERS

Test campaigns were run in 2006, 2008 and 2009, to validate the simulations performed in Empreinte™, more particularly the burst pressure predictions, and also to adjust the application’s parameter settings.

The tests were carried out on deliberately damaged pipe sections, combining dents (made with a hydraulic press, up to 50% of the pipe diameter) and machining (to simulate metal being torn off). The pipe was then pressurized until it burst (fig. 6 - p.73).

During the tests, specific monitoring (measurements: deformation, thickness, pressure, displacement, etc.) was also carried out to gather data for fine-tuning the model used by Empreinte™.

SAMPLES USED

The pipe sections used for these tests were chosen to reproduce the diameter (several pipe sizes: 12’’ to 24’’), thickness, steel grade and fabrication method (seamless and/or with longitudinal seam weld) corresponding to the real operating conditions of E&P pipelines.

Another important characteristic was the impact strength of the selected steels: tests on other research projects had shown a difference in behavior between old steels (over 30 years old) and modern ones (very fine grain, and representative of the pipelines operated by E&P), which have:

▪ Much higher impact resistance values and, in short, need substantial shock loads to reach rupture

▪ Much greater tolerance to major deformations, due to a high yield strength and rupture elongation.

TEST RESULTS

One of the conclusions of the burst test is that dents have a limited effect on the pipe’s burst pressure. The rupture always takes place in the thinnest part of the pipe, even when the pipe has undergone deformations exceeding 50% of its diameter.

Thickness variations are inherent in the manufacture

APPLICATION: DAMAGED PIPELINE OF AN LNG PLANT

Although Empreinte™ was initially developed for the deep offshore, it was first used at an LNG plant onshore, for a 38” HP gas pipeline that had suffered the effects of an explosion.

Initial application of the PDAM2 code had concluded that the section deformed by the explosion had to be replaced. The use of Empreinte™ enabled that replacement to be postponed to a later date and production to restart after minimal production loss by the LNG plant (whereas immediate replacement would have cost an estimated 100 to 200 million USD, mainly due to the time needed to mobilize personnel and equipment).

fi g. 7: Deformed pipe after explosion on LNG plant

of pipes, and slight variations – of the order of 0.5 mm – suffice to determine the rupture point. They may also result from the type of damage.

Accurately measuring the characteristics of both the damaged area and the pipe is therefore important for the accuracy of the burst pressure calculation and, in particular, for mapping the residual thicknesses. In addition, Empreinte™ can calculate the reduction in pipe thickness associated with major deformations.

A pipeline’s deformations or dents have another consequence: they affect resistance to pressure cycles (fatigue phenomenon). The present version of the application does not predict the consequences of metal fatigue but further development is planned.

2. PDAM (Pipeline Defect Assessment Manual): guide, similar to the French GESIP, published by the oil industry for the study of pipeline defects.


ConclusionThe methodology used in Empreinte™ has been validated by many burst tests on pipeline samples: the software application predicted burst pressure values that proved accurate, even when the deformation was extensive and outside the application range of other codes.

Although initially developed for deep offshore pipelines, Empreinte™ is also applicable to those onshore, as demonstrated by its application to the LNG plant pipeline. It will therefore be an extremely useful tool in the future for evaluating the severity of any damage which may be found on the pipelines.

The Total group now has a reliable tool for checking the integrity of any of its pipelines which may have been damaged. With the help of the Empreinte™ application, patented by Total, any affiliates encountering such a situation will be able to take a swift, reliable decision as to the urgency of replacing the affected section.



HSE: SAFETY

Marine Awareness Campaign… introducing Captain Jack

Derek LATTER1 [Total]

Derek started working in the offshore industry in 1976 and since then has served on most types of vessels from supply ships through anchor handlers and crane barges to diving support vessels. He was Captain of the vessel that found the German battleship Bismarck in 4,800 meters of water off the French coast.

In 1991, he moved to platforms in the North Sea, working for an oil major as head of the Platform Services Support department (logistics, hotel services, aviation, cranes, painting, scaffolding and maintenance, etc.).

Derek joined Total in 1998, working in Aberdeen. After a two-year secondment to Head offices as a marine specialist, he is now head of Deepwater Marine Operations in Nigeria.

Jean-Pierre BOYER [Total]

Jean-Pierre began his career as an anti-corrosion specialist in 1975, employed by a French marine coatings manufacturer, and rapidly became involved with the protection of both fixed and floating offshore platforms.In 1990, the company he was working for, La Seigneurie, became a part of the Total group to form an integrated Paints Division.

JP quickly became the contact point for both Total and Elf, a role he retained until the merger, and in 2003 he was invited to join E&P as Head of Marketing within the Internal Communication department, where his responsibilities included Project communications.

In 2008 he joined the HSE department as Head of Communication.As from September 1st 2011, JP will be retiring from all activities.

Roger MOESKOPS [Total]

Roger hails from Belgium and is a Captain of many years’ standing. He began his career with the Total group (Petrofina) in 1968 as a naval cadet, after which he became an officer aboard oil tankers and the drillship Petrel.

Following periods spent in Angola, the Democratic Republic of Congo (formerly Zaire), Dubai, Qatar and Indonesia, Roger has been working as a marine specialist at Exploration & Production HQ (Logistics and Operational Support division) since January 2010. In this role he is chiefly responsible for Marine training courses, auditing of Marine contractors and OVID (Offshore Vessel Information Database) inspections of support vessels.

Dirk MARTENS[Total]

Since the summer of 2011, Dirk has been appointed to Yemen LNG.

1. currently assigned to Total E&P Nigeria

AUTHORS


The ‘Captain Jack’ campaign is the result of collaboration between HSE, Communication and the Marine department (Logistics & Operational Support division) in Total’s E&P branch.

This awareness-raising support is a response from our marine actors, designed to put an end to the ‘inevitable’. It begins by courageously recognizing that marine accidents/events in our activities are our responsibility, goes on to define how to analyze incident reporting, and lastly addresses the issue of how to involve all stakeholders.

For me, Captain Jack is the first tangible result of cross-disciplinary work. Unfortunately, the subsidiaries did not all show the same extent of involvement, but as the current results have already reversed the trend (reducing collisions by 25%), this makes the margin for improvement all the greater.

Congratulations to all who played a part. We would like to see greater involvement from our clients (Drilling, New Ventures and Production) and believe this is possible.

The campaign is visible to personnel in all the subsidiaries. It will continue beyond the end of 2010 because it takes many years to change behavior while marine operations are vital to the continuing success of Total’s production, but also because we still have a lot learn about how to listen, to communicate and to analyze our risks better in order to make our marine operations safer.

Baudoin HERBOUTHead of the Logistics and Operational Support division (Total, Exploration & Production branch)

CONTEXT

HSE: SAFETY



IN SHORT

The past years have seen a substantial increase in the Group’s marine operations as a direct consequence of the expansion of E&P’s offshore activities. With this growth has come an unacceptable rise in marine incidents, nearly all stemming from two main root causes: human error and poor risk assessment.

To address this problem, the Logistics and Operational Support division (Total E&P, Operations) decided to launch a communication campaign aimed at raising awareness with respect to marine operations and reducing the risk of accidents. The objective was to improve our marine safety performance by setting examples of how marine activities should be carried out safely and by establishing with our contractors a common approach to reviewing our actions. Everybody working offshore or on offshore projects and participating directly or indirectly in marine activities needed to be encouraged to play an active part in improving safety in marine operations.

As the communication message needed to appeal to a broad public, a fun and interactive approach was chosen, to prompt a response from the target population. So the campaign was built around a fictional character called Captain Jack, the man setting the example of the good practices to be followed by all, based on five simple basic rules for marine safety.

The campaign was presented to the subsidiaries in January 2010, giving them ample flexibility to decide on the most appropriate means of delivering the message to their workforce and contractors. On the World Safety Day a contest was organized inviting everyone to contribute poster illustrations on the subject.

The campaign is ongoing and new material is issued regularly to keep the target group focused on the goal.


It is not unusual, in a company like Total, to think of innovation as the emergence of a scientific and/or technological concept or idea... but an ingenious or original way of tackling a subject and the common sense with which it is rolled out can also prove innovative in a number of areas recognized as ‘immaterial’. The HSE (Hygiene/Health, Safety, Environment) policy, and in this instance, its ‘S’ for Safety component, is one such area, where innovations are intended to safeguard property, and above all, people.

Is communication becoming a necessary and recognized skill, one which stands to be considered on a par with and flourish alongside the Group’s established technological know-how?

Has Safety become such a crucial issue in our organization and in today’s – not to mention tomorrow’s – oil and gas world at the very point when the problems of developing and producing the so-called ‘technological barrels’ will only grow, in an ever-more demanding environment and an increasingly difficult geopolitical climate?

So the question is: what is it about Captain Jack that enables this ‘good-looking guy’ to make such a lasting impression on marine activity in our subsidiaries and projects?

Maybe the answer to that is simply a mixture of the replies to the previous questions…

DRAWING ATTENTION TO THE FREQUENCY OF INCIDENTS

The number of incidents related to marine operations in Total’s E&P subsidiaries remained high in 2009. The branch’s HSE division was therefore asked to run an awareness-raising campaign to determine and publish the incident statistics, draw attention to the situation and initiate an improvement plan.

It soon emerged that in the subsidiaries most involved with marine operations, the success of the campaign depended extensively on the active support of middle management, and of Logistics, HSE and Internal Communication.

Another key to success: the goal of this campaign was not to serve up for the subsidiaries a ready-made solution ‘on a plate’ – as it would probably be quickly forgotten. The support material was sent out with tools that could be adapted to each subsidiary’s particular situation. The intention was that this approach would play a key role in raising awareness of safety issues in the subsidiaries, and for the long term, overcoming cultural, linguistic and geographical differences. The gamble paid off.

Lastly, analysis of the situation brought to light one more important factor that we needed to take into account: the majority of recorded incidents occurred during routine operations and can be traced back to human error.

HSE: SAFETY

Our campaign to raise awareness has been driven by an original – and deliberately offbeat – communication plan. Highly affordable in financial terms and easy to replicate, it was constructed by way of shared tools and flexible means. Its vocation is to remain deeply anchored in everybody’s behaviors and attitudes and to work in pursuit of a vital objective, the Safety of our operations.

Who could possibly resist such a likeable character or fail to respond positively as he urges us to unite our strengths and talents with the ultimate goal of improving Safety in E&P’s marine operations? Because that’s exactly what this is about!


THE COMMUNICATION TOOLBOX: OPEN, FLEXIBLE AND ADAPTABLE

A toolbox was created, featuring a 4-minute film, a presentation to be given at Safety meetings or any other pertinent occasion, posters, information sheets and stickers (fig. 2). Most importantly, it contains electronic versions of all these communication tools, which means they can be edited on the spot so as to conform to local requirements.

RALLYING AROUND CAPTAIN JACK

Our awareness drive was built up around a fictional character: Captain Jack (fig. 1), the figurehead, who sets a good example by following procedures and using good working practices.

EVERYBODY’S HERO

But, you may ask, why create a whole new character from scratch for the occasion? In response to an obvious contradiction which we soon became aware of:

▪ the job of ‘mariner’ does not really exist in the Exploration & Production structure,

▪ yet marine operations have a part to play from the very first to the last day of a field’s development (seismic acquisition, drilling, construction, field operations and so on).

And so it soon became obvious that what we needed was a unifying character; through him we can address a wide range of apparently unrelated actors, some only occasionally involved. We quickly put together a statement of requirements and sent it to our artist.

After a few trial runs and the necessary adjustments, our hero was born, and the ‘Captain Jack’ campaign, consisting of numerous communication aids, went into preparation.

HIS AUDIENCE

The campaign targets personnel – regardless of function or level of responsibility – directly employed by the subsidiaries or contractors and either directly or indirectly involved in the subsidiaries’ marine operations.

The objective is to heighten this population’s awareness of safety in marine operations, and keep it at the forefront of their minds. To bring down the number of accidents, subsidiary management intends to keep this campaign running throughout 2010, 2011 and 2012.

fi g. 2: Campaign publicity material

fi g. 1: Captain Jackfig 1: Captain Jack


HSE: SAFETY

The number of packs sent out was limited, however, to only two copies of each item for each subsidiary in a bid to be environmentally-friendly and avoid reams of printouts and expensive air transport. At the same time, all the necessary files were placed on the dedicated intranet site, available for the subsidiaries to download and produce locally.

Five poster templates were provided (fig. 3) to kick off the campaign in the subsidiaries. They can be adapted to particular themes or circumstances, or new posters can be created locally. There is just one restriction: all material must feature the picture of ‘Captain Jack’, the official E&P logo and the Total logo, in accordance with the current graphics charter. Specific text or further images may then be added into the central and lower sections, depending on requirements.

Giving the subsidiaries free rein leaves them at liberty to put their own stamp on the campaign, tailoring it to their own needs and printing out only the parts they consider necessary, yet without diverging from the original message.

fi g. 4: ‘Captain Jack’ competition at the 2010 World Safety Day

fi g. 3: The posters

provided

ALL HANDS ON DECK WITH CAPTAIN JACK

An article was published in E&P.mag, the Total E&P branch in-house magazine, to mark the campaign’s official launch in January 2010. In addition, to get the rollout off to a flying start, a competition was swiftly organized (World Day for Safety, April 28 2010), inviting everyone to suggest a text to go with a series of 5 posters illustrating high-risk situations.

80 teams took part (fig. 4), giving everyone the chance to put themselves in Captain Jack’s shoes, as individuals or a group, and express their own perceptions and words, effectively assuming a new perspective on high-risk situations.


WHAT WERE THE RESULTS? WHAT HAPPENS NEXT?

Did we achieve the expected results? Today we can consider that a trend is taking shape and heading in the right direction, and that the accident curve is marking a downturn (fig. 5). Clearly, the risks specific to marine operations have been identified and the rules redefined, in a fast-expanding environment. Every day, new contractors and crew members join the ranks of our operators on major offshore installations or production work sites.

fi g. 5: Since 2010 the Captain Jack campaign has been effective in reducing logistics-related vessel collisions

And effectively, these projects due for delivery in the near future will rapidly reach their cruising production speeds, i.e. exactly the level of routine flagged up as being the major cause of incidents and accidents. Are not identification and analysis of risks the first steps towards managing and controlling them?

A new phase of the campaign was launched mid-September: ships’ crews are to enjoy a coaching session on an ambitious scale by a group of instructors. A film will be shown to support the launch.

In 2009 =51 vessel collisionsIn 2010 (YTD Sep 2010) =27 vessel collisionsRemarks: Vessel collision is decreasing


HSE: SAFETY

ConclusionFor Total, the ‘Captain Jack’ campaign has already provided a wealth of information:

▪ We have been able to develop a new communication process based on sharing and exchange. Some of the innovations made available via Captain Jack have been reused in other campaigns to improve safety awareness, such as Total’s Golden Rules for Safety at Work.

▪ Head offices and Total E&P subsidiaries have been able to prepare the campaign rollout together, thanks to videoconferences organized either by continent or by geographical zone, a combined effort that has brought benefits for both sides.

▪ Captain Jack was introduced not simply as a Head office-issued tool but with the intention that personnel adopt – and even identify with – him, which has led to a fresh perspective on Head office-subsidiary relations. Out with the usual top-down approach, leaving the way clear for greater freedom of movement and confidence... and despite this, there has been no sign of anything going off the rails.

▪ The use of electronic versions of tools and support material is encouraged2 so that we reduce our carbon footprint by avoiding the air transport of several cubic meters of paper.

The campaign is ongoing and the Pazflor offshore production unit, in Angola, will soon be welcoming Captain Jack aboard. And – who knows? – one day we may be using this approach together with other operators on shared exploration and production zones (North Sea, Angolan or Nigerian deep offshore, etc.), or even via organizations like the OGP or OCIMF3. After all, if we have the same contractors, suppliers and even other partners, why not extend this to good practices in raising awareness on safety issues?

“LET’S WORK TOGETHER TO REDUCE MARINE INCIDENTS”would then become:

“TOGETHER, WE ACHIEVED SAFER MARINE OPERATIONS!”

2. as stated in the electronic version of this issue of TechnoHUB: www.technohub-total.com

3. OCIMF: Oil Companies International Marine Forum


‘Winterization’for a densely equipped LNG module

Gérard ALVINI and Maxime GEFFARD [Total]

Gérard and Maxime both work in the Rotating equipment and HVAC department of the Technology division in Total’s Exploration & Production branch. They are in charge of the aeraulic and thermodynamic studies for ‘winterizing’ LNG modules in what are known as ‘Extreme Cold’ environments.

HSE: SAFETY

AUTHORS


This project focuses on the ‘winterization’ of LNG – plant buildings or modules on projects that fall in the ‘extreme cold’ category.

It is an approach concerned not only with protecting all the equipment and operators exposed to extremely cold temperatures, but with solving the problem of dilution of hazardous LNG type pollutants inside densely equipped buildings or modules.

This innovation offers a number of enormous advantages, such as:

▪ Fulfilling the requirements set by Total for setting up bases in regions exposed to extremely low temperatures for a large part of the year.

▪ Offering controlled dilution, hence maximum safety, despite the very high volume congestion ratio of the installations.

▪ Reducing drastically both investment (CAPEX1) and operating costs (OPEX2).

▪ Being feasible in different industries whenever contaminant dilution needs to be controlled in densely equipped premises.

It is part of an overall research and development project developed and conducted by Total for several years now.

Bernard QUOIX Head of the Rotating Machinery departmentTotal, Exploration & Production branch

CONTEXT

1. CAPEX : CAPital EXpenditure

2. OPEX : OPerating EXpenses

HSE: SAFETY


IN SHORT

An LNG module with a high volume occupation ratio and containing hazardous light and heavy pollutants, in a location exposed to extremely low temperatures, has to be ventilated for safety reasons.

As there was no suitable solution available for this particular problem, an innovative option was put forward, featuring a combination of natural and mechanical ventilation.

Natural ventilation in the module will be provided by installation of fresh air intakes designed for very low-temperature environments where the number-one enemy is the wind.

Mechanical ventilation is assured by an extraction ventilation wall backed by secondary ventilators to avoid any dead air pockets in the module.

No heating will be provided in unmanned modules. The air velocity in the module will be very low, so personnel arriving for spot maintenance operations will find the temperature warm compared with the outside.

The proposed solution proved its aeraulic effectiveness during the leak simulations studied, by successfully diluting LNG gas clouds and reducing the probability of explosion from 10-3 to 10-4 for a leakage scenario corresponding to a ‘normal’ situation.

This simple, innovative solution effectively assures safety in densely equipped installations and considerably reduces both investment (CAPEX) and operating costs (OPEX).

It can be reproduced and replicated for any industry, wherever dilution has to be controlled in manned premises or buildings with a high volume occupation ratio.


Our new ‘Extreme cold’ projects, such as those in Russia or Canada that involve challenging technological constraints combined with harsh weather conditions, represent high stakes for Total’s development today.

Extreme cold means outside temperatures between -30°C and -60°C, wind speeds of 17 to 30 m/s, polar nights for several months in the year, heavy snowfalls…

Most of these gas projects entail building liquefied natural gas (LNG) processing plants. Total is developing a ‘winterization’ system to protect the equipment and people working in the units or modules from this kind of cold and ensure their safety in the event of gas leakage.

Picture a hall between 50 and 80 m long, 40 m wide and 20 m high and you will have an idea of what a module looks like.

THE PROBLEM

We know, from analyzing the way natural gas liquefaction modules work, that:

▪ If a leak occurs, both heavy and light gases are present in the module, which means addressing thermal stratification as well as dilution.

▪ The module is extensively equipped (fig. 1) and entails a choice of aeraulic system that must also ensure safety inside the module.

▪ Volume occupation is high but uneven over the whole height of the module, so that, once again, a stratification approach is necessary to make sure dilution is efficient from top to bottom.

A dilution approach demands very substantial fresh-air intake to the module to maintain the gas concentrations inside it at a low, non-explosive and therefore non-hazardous value.

fi g. 1: View of a module showing its volume occupation – Source Technip

AVAILABLE SOLUTIONS

From an aeraulics3 standpoint, there are two solutions:

▪ natural ventilation

▪ mechanical ventilation broached in a classical approach.

But the question arises as to whether they are really suited to the problem at hand.

HSE: SAFETY

3. Aeraulics is the study of fluid (like air and gas) flows


NATURAL VENTILATION

This is the most widely used solution as its low cost makes it attractive for all kinds of installations. In practice, over-simplified approaches and erroneous assumptions lead to its being often poorly implemented. Effectively, it is important to realize that:

▪ It will not work if there is no wind.

▪ Ventilation in highly congested buildings may work if the wind is moderate, but only if there is no low pressure area and no pockets of dead air. It is, of course, impossible to capture a pollutant in a negative pressure zone.

▪ Natural ventilation will produce only low dilution efficiency if the wind is moderate and the premises densely occupied.

▪ Aeraulic disruptions will increase, reducing the dilution efficiency afforded by natural ventilation if the wind is strong, whether congestion in the building is low or high.

Natural ventilation may be a suitable option in a limited number of scenarios but is unable to ensure real controlled safety in all situations, the more so that it is highly sensitive to variations in wind direction.

CONVENTIONAL MECHANICAL VENTILATION

This combines:

▪ Drawing air into the module via air handling units designed to filter, heat and blow fresh air into the module

▪ Extracting air from the module via exhaust ventilators.

When the technical room with all its aeraulic, thermal, hydraulic and regulating equipment and networks is added to the maintenance areas, this represents, depending on the type of module, a 40-60% increase in its initial surface area.

The surface area problem continues with the fresh air shaft and the main ventilation ducts connected to the air handling units, all of which are very large – cross-sections of up to 10 m – that seriously affect the way space is used in the module.

Lastly, this solution implies heating the fresh intake air. As this involves very substantial quantities, a heating unit of several tens of megawatts would be necessary to run conventional mechanical ventilation.

CONCLUSION REGARDING THE AVAILABLE SOLUTIONS

The two possibilities looked at above are unsuited to the LNG module, pose extremely difficult technical problems and entail high costs. An alternative solution had to be found.

THE NEW SOLUTION

The innovative solution is a combination of natural and mechanical ventilation consisting of:

▪ Fresh air intakes placed at the top and bottom of three of the module’s walls

▪ A wall of extraction ventilators assuring the principal ventilation

▪ Two secondary ventilations inside the module.

FRESH AIR INTAKE

In very cold countries, the number-one enemy is the outside wind. Its dynamics must be dampened to prevent the fresh air inlets from icing over and to minimize wind impact on the felt air temperature (wind chill effect). For example, a temperature of -33°C plus a wind speed of 17 m/s produces a felt air temperature for humans of -52°C.

Our fresh air intake solution is in three parts (fig. 2 - p. 90):

▪ Part 1 is a baffling section. Air traversing the baffling:

▪ Creates pressure drops, slowing and smoothing the dynamic flow of the outside wind

▪ Creates a barrier to snow carried by the wind.

▪ Part 2 is a plenum designed to further the process and smooth the velocity profile upstream of part 3, irrespective of the outside wind speed.

▪ Part 3 is a grid, which recreates the dynamics of the outside wind, dampened in parts 1 and 2.

Together, these three parts ensure all the advantages of natural ventilation while eliminating its drawbacks due to the outside wind.

Lastly, carefully located heating systems will help prevent the formation of ice likely to build up on, and obstruct the metal components of the fresh air inlet.


THE VENTILATOR WALL

A stratification approach is needed owing to the heavy and light pollutants present in the module. The module was divided into three sections from top to bottom (fig. 3). The bottom is dedicated to the heavy gas layer, the top to the light gas layer, with an intermediate layer in-between.

The extraction air flow in each zone is calculated specifically for the pollutants present in the zone so that flow remains perfectly stable, however congested the module’s volume.

The extraction ventilators are placed on the fourth wall, the one not fitted with fresh air intakes (fig. 5). They will extract air from the module while maintaining the stratification and stability of the low-velocity air flow (laminar flow) within it.

fi g. 2: Section view of the fresh-air intake

fi g. 3: Cross-section of the inside of the module showing the aeraulic layers and the dead air pocket

fi g. 4: Cross-section of the inside of the module showing the ventilation systems

SECONDARY VENTILATION

Secondary ventilation is provided to eliminate the dead air pockets in the module. Depending on the length of the latter, between 50 m and 80 m, the range of the ventilators on the ventilation wall may be insufficient to cover the entire length of the module. So in this case, there would be a dead air pocket on the side furthest away from the ventilator wall (fig. 3).

To overcome this problem, secondary ventilation is installed to eliminate the dead air pocket. A dead air pocket is an area in which a contaminant may stagnate and therefore build up, creating a real risk of explosion.

The upper secondary ventilation is there to feed

HSE: SAFETY


The stable fl ow is due to the fact that in immense buildings like these, and for this type of mixed convection problem, the inertia terms in the quantity of motion equation are nil and that velocity is therefore a linear value in the equation via the viscosity term and not a square value of the inertia term.

MOREthe ventilators high on the ventilation wall, while the lower secondary ventilation feeds the upper secondary ventilation (fig. 4).Combining these three ventilation areas corrects the velocity flows in the module (see inset) while respecting the stratification imposed, regardless of the occupation ratio in the module.

As a result, the flow is perfectly stabilized, circulating from the back to the front of the module.

The aeraulic efficiency of the proposed solution ensures that the gas clouds from top to bottom of the module are diluted in the leak scenarios normally considered by the operator. No other aeraulic system would have delivered this level of safety and air flow control inside the module at the same time.

Winterizing an installation involves confining many items of equipment. As these contain hazardous gases, the probability of explosion remains, however efficient the dilution provided. So installation of anti-explosion shutters on the walls is a must.

Emergency ventilation is provided in addition to this principal ventilation to ensure further air flow if a major gas leak were to occur in the module. It is installed at strategic positions in the module and its flow regime is adapted to its safety function.

It is important to bear in mind that dilution efficiency does not depend exclusively on the mass of air blown into the module, but also on:

▪ The type and amount of pollutant, its propagation velocity and pollution time

▪ The mass of fresh air drawn in to assure dilution

▪ The reaction time of the whole regulation loop before the emergency ventilation kicks in

▪ Diffusion of this mass of fresh air

▪ The pollutant concentration coefficient in the mass of fresh air

▪ Capture as close as possible to the source of pollution

▪ The volume occupation ratio in the building

▪ The shape factor of the building and wall effects.

fi g. 6: View of the module from the fresh-air intake walls side – Source P. L’Hopitalier

fi g. 5: View of the module from the ventilator-wall side – Source P. L’Hopitalier


TEMPERATURE CONSIDERATIONS

The modules are designed to be unmanned in normal operation. So do they need to be heated when the operators will actually spend very little time in them? The answer is no, which is why only those processes that require ambient heating will be outfitted with heating devices. A set of portable, explosion-proof heating devices will, however, be on hand for use during maintenance periods. But what happens to the human body in an unheated module under extreme cold conditions?

The human body remains at a fairly constant temperature of 37°C through a trade-off between heat received and lost. Heat is evacuated from the human body:

▪ Through the skin

▪ By the air exhaled

▪ In urine and feces.

Of these, the skin is the prime heat-loss vector, hence the importance of wearing the right kind of clothing.

A warmly dressed operator in an unheated module loses body heat chiefly by conduction, convection and radiation. Conduction is insignificant in this transfer phenomenon. Because the air velocity in the module is low, convection flow is also low. Because there is little difference in temperature between the walls of the module and the superficial temperature of the operator’s clothes, heat exchange by radiation tends towards zero.

In short, the sum of thermal exchanges between a human body and the unheated module is more or less nil.

An appropriately dressed operator entering the module from outdoors will therefore have an impression of heat, without the module actually being heated. However surprising this may sound, the explanation for this resides, quite simply, in the difference in air velocity inside and outside the module.

COLD ROOM TESTS

Extensive testing in cold rooms was carried out at temperatures ranging from -35°C to -60°C, with wind speeds between 15 and 20 m/s, as were 3D simulations and mock-up simulations.

Test campaigns are to continue, with other hypotheses and other volume occupation ratios for the modules.

HSE: SAFETY


ConclusionThis aeraulic solution ensures controlled dilution in the leak scenarios normally addressed by the operator, and therefore with maximum safety margins, despite the extremely high volume occupation ratio in the installations.

It reduces CAPEX by eliminating the necessity for investing in surface areas for:

▪ A technical room for each module (savings of between 40 and 60%)

▪ A fresh air shaft and guying for each module ▪ Heating facilities for all the modules (several

MW, depending on the type of module).

It saves on OPEX through:

▪ Energy consumption drastically reduced to the strict minimum required by the LNG process

▪ Increased operator work efficiency due to laminar air flow in the module.

This simple solution can be reproduced in different industries, provided dilution in densely equipped buildings is controlled. Local regulations applicable to the relevant site will naturally need to be taken into consideration for the studies addressing transposition of the solution.

This winterization response is part of a global research and development approach that Total has been developing and conducting over the past few years.


HSE: ENVIRONMENT

Chemical looping combustion: a disruptive path to reducing greenhouse gases1

Sébastien RIFFLART[Total]

Sébastien spent his first three years after arriving in the Group in 2005 as research engineer in the Thermal transfer and combustion team at the Solaize research center.

In 2008, he joined the Research division of the Gas & Power branch to oversee research studies directed at the development of CO2 capture processes. His activities revolve essentially around Chemical Looping Combustion (CLC) and other gas-separation technologies.

Hélène STAINTON [Total]

Since 2005, Hélène has successively held jobs as energy/utilities engineer and process engineer at the Feyzin refinery. From there, she moved on in 2009 to the Research division of Gas & Power, to work on development of CLC technology in the Gas and Carbochemicals team.

Hélène is currently seconded to IFP Énergies nouvelles (IFPEN) where she plays an active part in fine-tuning and conducting experimental tests.

1. this project won an honourable mention for “Leadership on an innovative technology”, one of the prizes awarded in 2010 by Total’s Group Technology Commitee (CTG)

AUTHORS


Against the backdrop of the fight against climate change, geological sequestration of CO2 is seen as a solution for a more climate-friendly energy system that can be rapidly deployed. The technique is still extremely costly, owing chiefly to the capture stage. Hence the interest in the breakaway Chemical Looping Combustion – CLC – solution for CO2 capture, which appears promising in terms of energy efficiency and cost savings.

With Total playing an active part in the development of this technology, the Group stands assured of a leading technical position in the reduction of greenhouse gas emissions.

The CLC process, developed in partnership with the IFPEN, will bring benefits for all the Group’s branches, through coal upgrading for Gas & Power, steam production for extracting heavy crudes for Exploration & Production, or furnace replacement for Refining or Petrochemicals.

CLC technology has successfully passed the laboratory demonstration stage of a 10 kWth pilot, and engineering studies are now under way in preparation for a forthcoming semi-commercial-scale pilot of 3 MWth.

Charles YACONOHead of the Processes engineering and catalysis theme in the Total group Scientific division.Facilitator in the Total CO2 capture network.

CONTEXT



IN SHORT

The Chemical Looping Combustion process – CLC – is a combustion technique with a CO2 separation phase built into the process. This specific feature minimizes the cost of CO2 capture, currently one of the major impediments to the development of CO2 Capture and Storage, advocated by the IPCC (Intergovernmental Panel on Climat Change) as one of the most promising means of reducing greenhouse gas emissions.

The technique makes use of a metal oxide to transport oxygen in the air to the fuel. The combustion effluents (CO2 + H2O) are then produced separately from nitrogen. What makes this technique stand out from other known CO2 separation techniques is the fact that no energy needs to be expended.

The process requires two reactors and a means of circulating the oxygen-carrying solid, a metal oxide. In the first reactor, the metal oxide is reduced in the presence of fuel, such as methane, coal or a liquid hydrocarbon. In the second reactor, the metal reduced by oxygen in the air is oxidized at a temperature of between 800 and 1,000°C depending on the case.

In 2008, Total and IFP Énergies nouvelles signed a partnership agreement to develop the CLC technology. The strategy adopted has been divided into three steps each of which is to culminate with the construction of a successively larger pilot to validate it until the process reaches the industrialization stage by around 2020. The first step, leading to construction and operation of a 10-kWth pilot running on gas feedstock, has been successfully completed. Trials are currently being carried out on a solid feed (coal).

The current focus is on sizing the 3-MWth pilot for the next step, to validate the technology in operation in 2013-2014. The final step before industrialization will be construction and operation of a demonstration unit with an approximate capacity of 50 MWth, planned for 2015-2018.

HSE: ENVIRONMENT


Fossil energies (gas, oil and coal) represent around 81% of the world’s energy consumption. Nearly 60% of global greenhouse gas emissions are due to fossil energies, whose use is expected to increase by almost 30% before 2030. Yet, in the past few years, the Intergovernmental Panel on Climate Change (IPCC) has established a clear tie between greenhouse gases and climate change. Reaction and effort at global scale are necessary to keep concentrations below the allowable thresholds.

CO CAPTURE AND STORAGE

CO2 is one of the main greenhouse gases, accounting for 80% of emissions, and most of it is produced by the combustion of fossil energies (in industry, transport and so on). Various actions have therefore been set in motion to reduce greenhouse gas release, one of the solutions being to recover and sequester the CO2 given off by industrial plants that use fossil fuels (CCS – Carbon Capture and Storage). CCS involves recovering CO2 from its production source and storing it in the subsurface instead of releasing it to the atmosphere. According to the International Energy Agency2 (IEA), CCS’ contribution to reducing CO2 emissions should reach approximately 20% by 2035.

In the overall chain of capture, transport and storage of CO2 in deep, gas-tight geological layers, the first step is the most expensive, representing as much as 80% of the chain’s total cost. The substantial quantities of energy consumed in the capture technologies available at present are the prime explanation for this high cost. Reducing this energy expenditure, and thus the capture cost, is one of the prime challenges of CCS.

CURRENT CCS METHODS

Conventional combustion flue gases comprise only 3 to 15% of CO2 diluted in the nitrogen found in the combustion air, but for storage purposes the CO2 must be concentrated at 95%, which is the goal of the capture phase. Two main techniques are considered:

POST-COMBUSTION

This consists of processing the fumes leaving a combustion installation so as to separate out the CO2. To do this, an amine-based solvent is used to capture the CO2 which is then freed when the solvent is regenerated by heating.

OXYCOMBUSTION

Another solution consists of substituting pure oxygen for the air in the combustion process, in a technique known as oxycombustion. In this case, oxygen is produced in an ASU (Air Separation Unit) where nitrogen and oxygen are separated by cryogenic distillation.

The result is a concentrated stream of CO2, free of nitrogen and ready for storage. This is the technology that was chosen for the pilot at Lacq.

2

2. see http://www.iea.org/papers/2009/CCS_roadmap_targets_(viewing).pdf


AN OBSTACLE: THE COST OF SEPARATION

The prime drawback of post-combustion and oxycombustion is that both technologies are highly energy-intensive as they demand large quantities of energy to capture the CO2. The first uses thermal energy to regenerate the solvent, the second electrical energy to power the cryogenic distillation compressors.

For purposes of comparison, the mean efficiency of an electric power station (ratio between the energy released by the fuel burnt and the electrical energy produced) is in the region of 41%. In the case of post-combustion and oxycombustion plants, efficiency drops to around 31% after capture and compression of the CO2 (a loss of 25% of the electricity produced).

AN ALTERNATIVE: CHEMICAL LOOPING COMBUSTION

This is where the development of Chemical Looping Combustion, or CLC, finds its raison d’être. It emerged recently as a promising new disruptive technology for producing energy and at the same time efficiently capturing CO2; in short, its energy penalty is lower than for existing capture technologies.

Figure 1 shows the energy penalty for CO2 capture and compression added to a coal-fired power plant. In comparison with the other techniques, CLC technology offers prospective energy gains of around 70%.

In reducing the energy consumed, we can reduce costs. Technico-economic studies, with sizing and costing taken from real industrial cases, confirm the economic advantage of this technology, which has been calculated to cost approximately 40% less than other capture processes.

THE CLC PROCESS

CLC is based on an innovative process involving the use of metal oxides to provide the oxygen needed for combustion. In practice, this amounts to using the oxygen carrier particles – in this case metal oxides – continuously circulating between two fluidized-bed reactors.

The first is an air reactor in which the oxygen carrier oxidizes on contact with air (hence the name air reactor or oxidation reactor). The solid particles then the oxygen to the second reactor (fuel reactor or reduction reactor) containing the fuel, where they release their oxygen and return to the first reactor to fulfill the same role in the next cycle.

fi g.1: Energy penalty – in % of net initial electricity produced – of CO2 capture and compression on a coal-fi red power plant for different capture technologies

HSE: ENVIRONMENT


Figure 2 shows the chemical looping combustion principle. As combustion is achieved with no direct contact between air and fuel but exclusively from the oxygen separated from, and then ‘freed’ by, the metal oxides, this closed redox (oxidation-reduction) loop produces highly concentrated emissions of CO2 without any nitrogen.

This technology may be likened to a kind of oxycombustion where the oxygen is supplied ‘free of charge’ solely by circulation of the solid, removing the need for the expensive and energy-intensive step of cryogenic distillation. The prime advantage of the process lies in the fact that the total energy freed in the two reactors is equal to the total energy that would have been released in a conventional combustion operation: zero energy is consumed for separating out the CO2.

POSSIBLE APPLICATIONS

One possible application of this technology is in steam production where it could recover part of the energy from both the solid and the flue gases leaving the two reactors. The system would replace traditional steam generators and the steam could then be used, for instance, to power a turbine which would subsequently produce electrical energy, as shown in figure 3, or be used directly for utility purposes on an industrial site.

fi g. 3: Production of electrical energy from chemical looping combustion

BACKGROUND OF THE TECHNOLOGYAND THE PROJECT

CLC technology was first proposed by Japanese academics in the early 1990s, after which the Swedish university of Chalmers engaged in a first round of experiments. Although these were conducted at only a small scale, the technology soon emerged as being a disruptive process. As far back as 2004, the International Energy Agency identified chemical looping combustion as one of the most promising options for capture technology3.

Development of CLC technology was initiated for Total in 2008 when the Group entered into a partnership with IFP Énergies nouvelles (IFPEN). Prior to that, between 2005 and 2008, Total, IFPEN and other partners had worked together, in the ANR4 project called CLC-MAT, on a key part of the process, the oxygen-carrying solid. The goal was to develop new supports that have high oxygen-transfer capabilities but are still mechanically stable, inexpensive and compatible with environmental constraints.

Since Total and IFPEN began their collaboration, an initial raft of tests has been run on a pilot installation, using gas feedstock. Since then, the partners have moved on to adapting the technology for solid feedstock, such as coal, an energy that is abundant at global scale and available from various sources.

3. see “Prospects for CO2 capture and storage”, IEA, 2004

4. ANR: Agence Nationale de la Recherche, France’s national research agency

fi g. 2: Process diagram for chemical looping combustion


RISING TO THE CHALLENGE

Particular attention was paid to a number of specific points to get the new technology up and running.

ENSURING CIRCULATIONOF THE SOLIDS

The first challenge facing us was to master the art of circulating the solid oxygen carrier between the two reactors at extremely high temperatures (the process requires temperatures between 800°C and 1,000°C). In this range, circulation cannot be controlled by mechanical valves like those customarily used in the industry.

Investigations were initiated for the development of non-mechanical valves, called L-valves, operated by injection of a vector gas. A mock-up of the process was produced (fig. 4), solely for the purpose of studying and learning to master the circulation of solids.

fi g. 4: Photograph of the mock-up for learning to master the circulation of solids

SELECTING THE OXYGEN CARRIER

The second challenge concerned the oxygen carrier, the crux of the technology.

An industrial facility uses large quantities of oxygen carrier, which is why it is important to develop a solid that has all the technical characteristics sought (extremely high carrier capacities and reactivity) but is not over-costly.

Experimental studies have already pinpointed a highly promising solid.

USING A SOLID FUEL

The third technical challenge we had to overcome centered on the changes necessary for powering the CLC unit by a solid fuel (coal for example).

In this case, the solid fuel is completely mixed with the oxygen carrier in the fuel reactor. So when the reduced solid is extracted for reoxidation in the air reactor, great care must be taken not to let incompletely burnt coal particles be carried along, as this would result in unwanted CO2 emissions in the air reactor.

Most of the unconverted coal must therefore be recycled in the fuel reactor. To do this, a dedicated carbon stripper is installed at the outlet from the fuel reactor to separate the coal particles from the oxygen carrier, an operation made possible by their different densities.

This equipment is essential for solid fuel-powered CLC units and significantly increases the efficiency of CO2 capture. Total and IFPEN have developed and patented a model that has demonstrated an efficiency rate of over 80% in recovering non-burnt particles.

HSE: ENVIRONMENT


PROGRESS STATUSOF THE PROJECT

CONSTRUCTION AND OPERATION OF A COMPREHENSION PILOT

The first stage in the project consisted of building and operating a 10-kWth pilot (fig. 5).

It was successfully completed on a gas feedstock. The results demonstrated 100% efficiency in capturing the CO2 emitted and 97% purity of the CO2 leaving the fuel reactor.

Tests are currently being carried out on a solid feedstock (coal) to validate the concepts and materials developed. As a preliminary to the switch to solid fuel, batch tests were run at IFPEN in a small batch reactor.

fi g. 5: Photograph of the 10-kWth pilot built by partners Total and IFP Énergies nouvelles

ConclusionThe research program for the first step will continue until the end of 2011 and include in particular operation of the 10-kWth CLC unit and its adaptation to a solid fuel (coal). The second step, involving design studies for the semi-industrial scale 3-MWth pilot unit, has just been launched and encompasses all the developments achieved to date. The pilot is the opportunity to validate the technological choices made. Construction is scheduled to commence in 2012 for start-up mid-2013.

If it is successful, we will then move up a scale, building a commercial unit with a capacity of more than 50 MWth which will last from 2015 to 2018. We may then look forward to seeing the industrialization of this innovative CO2 capture process by 2020.

This will eventually ensure for Total the benefit of an efficient CO2 capture technology, on average 40% less expensive than the other technologies considered. It is a technology of use to all the Group’s branches and one that will give Total and its partners a decisive advantage for the sustainable development of their activities.

They validated the use of solid fuels while offering the possibility of closely studying the reaction mechanisms, the keys to optimized sizing of an installation.

Total and IFPEN have developed a portfolio of patents in the process and published around thirty articles in scientific journals or international conferences.

THE NEXT STEP IS TO BUILD ANOTHER PILOT, THIS TIME 3 MWTH

The 10-kW stage was limited to mastering the technology without producing energy. At present, we are working at sizing an installation with a capacity of 3 MWth, to validate the technologies implemented at semi-industrial scale and run them over long periods.

The objective of this industrial pilot will be to demonstrate continuous operation of the CLC process at commercial scale and to produce energy by combustion of a solid fuel.

The construction decision will be taken at the end of 2011, on completion of the ongoing engineering study, for kick-off in early 2012. The goal is to build the industrial pilot unit for production start-up in summer 2013 and to operate through to the end of 2014.


PATENTS

Patents 2010

GAS SOLUTIONS

Fischer-Tropsch synthesis of hydrocarbons, e.g. for use in motor fuel production, uses catalytic plates with catalyst compartment containing catalyst supported on silicon carbide foam SAVIN SabinePHILIPPE RégisBOUSQUET JacquesSCHWEICH DanielLUCK Francis

Method for purifying gaseous mixtures containing mercaptans and other acid gasesANGLEROT DidierBONNE Jean-PatrickVU CatherineFREMY Georges

Liquefied natural gas producing method, involves providing natural gas, recovering part of heat from fumes produced by gas turbine, and producing vapor for vapor turbine by using recovered part of heatCHRETIEN Denis

Gas-liquid contacting method and column employing a combination of plates and packingsCHOMMELOUX BenedicteRAYNAL Ludovic HOANG-DINH Viep

ARTIFICIAL LIFT

Method for Controlling a Hydrocarbons Production Installation LEMETAYER Pierre

Method for extracting hydrocarbons from a tank and hydrocarbon extraction facility NDINEMENU FelixLEMETAYER PierreTOGUEM NGUETE Emmanuel

Ejector device for forming a pressurized mixture of liquid and gas, and use thereof LECOFFRE Yves MAJ GuillaumeMARTY Jacques

CARBOCHEMISTRY

Process for the production of synthesis gas RIFFLART SébastienPATIENCE GrégoryCHIRON François-Xavier

FACILITIES

System e.g. container for storing/transporting hydrocarbons, comprises external and internal metal structures with respective mediums, a power source, a wall separating the mediums, external and internal electrodes, and a binding element BRAZY Jean-Louis

Sulfide stress cracking source detecting and locating method for high elasticity limit steel in oil environment, involves carrying out identification on map of areas on duration higher to hour as sulfide stress cracking source CASSAGNE ThierryKITTEL JeanROPITAL FrançoisSMANIO VéroniqueFREGONESE Marion NORMAND Bernard

Method for separating two dispersed-phase immiscible liquidsRICORDEAU AlainBROCART BenjaminPALERMO Thierry NOIK Christine FALAPPI Stefano

Method for reducing the pressure loss of a liquid flowing in a pipe, taking into account the degradation of drag reducing agentsGLENAT PhilippePALERMO ThierryHENAUT IsabelleDARBOURET MyriamHURTEVENT Christian


Liquefied natural gas producing method for engine of jet aircraft, involves driving compressor by driving units, and transferring part of heat of fumes from gas turbine towards refrigerating machineCHRETIEN Denis

Sour gas treatment processCADOURS RenaudWEISS ClaireBOUALMATA Kamal

GEOSCIENCES

Estimation of lithological properties of a geological zoneBIVER Pierre D’OR DIMITRI ALLARD Denis

A carbon compound collecting system DESSORT DanielDUCLERC DominiqueLE VAN LOI RobertCASSAGNE Alain

An improved process for characterizing the evolution of an oil or gas reservoir over time GRANDI Andrea

HEAVY OILS

Method for the in situ high frequency heat extraction of hydrocarbons from an underground formation MAUDUIT Dominique REY-BETHBEDER Franck LEFEUVRE Serge

Method for treating hydrocarbonsDANG FabriceVAN KHOI Vu

Method for heating a hydrocarbons reservoirTOGUEM NGUETE EmmanuelLEMETAYER PierreMAUDUIT Dominique

Method for extracting viscous petroleum crude from a reservoirROCHON Jean

MINING

Reduced Asphaltene Loss for Paraffinic Froth Treatment REIPAS Ray STEVENS Geoff Tailings solvent recovery unitKAN Jianmin

The names mentioned here refer to authors currently or formerly employed by the Total group and, for some of the patents, authors from other companies or academic institutions that have collaborated with Total.



KNOW-HOWTECHNOLOGYINNOVATION

OCTOBER 2011

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