2006-2009 Triennium Work Report - International Gas...

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2006-2009 Triennium Work Report

October 2009

WORKING COMMITTEE 2: STORAGE

Chair: Dr Vladimir Onderka

Czech Republic

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PREFACE

This report presents part of the work carried out by the members of Working Committee 2 – Gas Storage (WOC2) of the International Gas Union (IGU). The triennium work program was partly based on the results gathered during several triennia in the past but also provides a lot of technical news, trends in development and a new role of UGS industry. The Triennium Work Program (TWP) has been split into three study groups (SG): SG 2.1 “UGS Database” Study group leader: Joachim Wallbrecht, BEB, Germany SG 2.2 “UGS Technology Improvements” Study group leader: Hélène Giouse, Storengy, France SG 2.3 “Intelligent UGS” Study group leader: Georg Zangl, Schlumberger Innovation Solutions, Austria The Committee has been chaired during the triennium 2006 – 2009 by Dr Vladimir Onderka, Manager of Technical Projects and UGS Development, RWE Gas Storage s.r.o., The Czech Republic. Hélène Giouse, Storengy, France, worked during the triennium as the Vice Chairman. Petra Grigelová, RWE Transgas Net, The Czech Republic, acted as the Technical Committee Secretary. The list of WOC2 members is given in Appendix 1.

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GENERAL TABLE OF CONTENTS PREFACE II TOPICS OF TRIENNIAL WORK PROGRAMME 2006 – 2009 IV ADDITIONAL WOC2 ACTIVITIES VI SELECTED CONCLUSIONS VII APPENDIX 1: LIST OF WOC2 MEMBERS VIII STUDY GROUP REPORTS X Report of Study group 2.1 “UGS Database”

Report of Study group 2.2 “UGS Technology Improvements”

Report of Study group 2.3 “Intelligent UGS”

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TOPICS OF THE TRIENNIAL WORK PROGRAMME 2006 – 2009 Underground gas storage is playing a more and more important role during filling gaps between the demand of gas on the market and existing supply. In Europe specifically the distances between gas origin in large gas fields and the consumption areas are increasing and possible interruption during winter season influ-enced views on the necessity of UGS. For example, safety of supply has become one of the main priorities of the European Union. The scope and process of forming the Triennial Work Programme was motivated by the following drivers:

- Increasing demand for UGS capacities worldwide - Changing the role of UGS (time, regions) - UGS contribution to the global energy balance, in terms of competitiveness, operational alternatives - Need for high technical efficiency - Need for high reliability, safety and environmental compatibility and contribution to sustainable de-

velopment. Moreover, the other aspects mainly based on the results from previous IGU triennia were taken into consid-eration:

- Existing large and known IGU UGS Database and basic analyses of trends in UGS industry - Technological progress in UGS development and operation - Increasing role of smart technologies in UGS - Large IT applications - Lots of information in IGU about UGS technologies from the past

Based on the above mentioned inputs, TWP was split into three study groups: SG 2.1: “UGS Database” The development of an IGU UGS database started in the Triennium 2000 – 2003 and brought a very clear picture and indications of the increasingly global trends of the UGS industry. Because of the database suc-cess it was decided to continue in further database extension in the following ways: Continuation in the IGU UGS database development in order to obtain a reliable picture of UGS worldwide and a background for additional analyses, benchmarking etc. covering the main parameters of storage res-ervoirs, output rates, capacities, type and number of production wells, surface facilities as well as basic in-formation about ownership and operators. Ø Scope of the development:

• Update of existing database (products & services in UGS, who are the consumers) • Resend questionnaire (validity data checking + update) • Splitting UGS between oil and gas fields • Incorporation of pipeline systems related to UGS • Enlarging the existing glossary of terms (if needed) • Point of view (economical, ecological, legal aspects of UGS industry) • Describing national trends of UGS industry • Enlarging UGS multilingual glossary

SG 2.2 “UGS Technology Improvements”

Applied technologies within the gas industry have been mentioned as a part of “Reviewing the Strategies for Natural Gas” for the Argentine Triennium. Moreover, the level of UGS technology can be considered as a

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key factor for efficiency, safety and liability of UGS operation. Among the terms of reference for S.G. 2.2 the following were mentioned:

• The intent of this particular group will be to review the technological improvements focusing on the following features: Well stability, Well potential, Remediation practices, Operational cost reduction, Horizontal drilling, Well completion and formation damage mechanisms and remediation practices.

Ø Scope:

• Refreshing existing data

• Improving existing data

• Trends in technology

• New technologies in down-hole logging, well-bore integrity monitoring, cement binding etc

SG 2.3 “Intelligent UGS” A large potential of IT and smart technologies have already been applied within the oil industry (E&P) and are one of the future potentials which have to fit with a changing roles in UGS. This means increasing pro-duction rates without huge additional investments, enabling fast swaps between injection and production, increasing the level of reservoir surveillance and on-line check of all the compounds within the UGS chain. This initiative of IT and production/reservoir engineering was called “Intelligent UGS”. The terms of reference and scope of this SG was set as follows:

Ø Describe possible connections between all technologies controlling the operation of UGS and utiliz-

ing existing knowledge and tools for optimization, automation and cost savings. Ø Scope:

1. Description of Dynamic data needs (reservoir, technology)

- purposes - ranges - frequency

2. The raw data validation and their security 3. Data filtering, modelling, sampling 4. Operation analyses, simulation, optimization 5. Tools for optimized UGS management 6. Automation, remote control and cost savings

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ADDITIONAL WOC2 ACTIVITIES Besides the above mentioned TWP activities WOC2 organized a workshop preceding each WOC2 meeting. The topics were mainly generated by WOC2 members and/or by actual needs or phenomena in the UGS industry. One of the main goals of the workshops was the participation of experts outside IGU, e.g. from various universities, consulting companies, associations (AGA). During the workshops the following topics were issued: - Prague, September 2006, “Legal and Regulatory framework of UGS Development and Operation” - Dallas, April 2007, Joint UGS workshop with AGA Biennial technical conference/exhibition - Rome, 2007, “Safety on UGS” - Salzburg, April 2008, “New Technologies for Old UGS Wells” - Paris, October 2008, “Numerical Applications for UGS – from E&P to Dispatcher” - Moscow, June 2009, “Case Studies and New Technologies”

Other contributions of WOC 2 members were related to support the following: PGC A: Sustainable Development Emissions mitigation, CO2 sequestration study and methane emission

control. PGC B: Strategy, Economics and Regulation, 2030 Energy Outlook Study. UN ECE: Cooperation on UGS European database development.

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SELECTED CONCLUSIONS The aim of all three study group reports of WOC2 was to hand over news about the UGS industry and exist-ing trends and extend the knowledge about potential technology to be applied on many UGS facilities world-wide. Moreover, WOC2 was willing to contribute information and analyses about new challenges for new and smart technologies reducing OPEX, improving reliability, safety and environmental friendly technology appli-cations. The intention of WOC 2 studies was to show the industry´s interest to solve the main energy tasks and contribute in reducing the main environmental impacts. SG 2.1. "UGS Database" is bringing a new UGS database filled with basic descriptions of 631 UGS facilities in the world with a total installed working gas volume of 352.593 mil.Nm3 of natural gas in the UGS World Data Bank. The report also contains a UGS World Map for interactive views of UGS locations, a UGS Glos-sary of the most frequent and relevant technical terms and a report on major trends in UGS business. SG 2.2. "UGS Technology Improvements" consists of two parts where Part 1 "Trends on New Technologies for UGS" in a comprehensive way describes the knowledge update from the past Triennia and consequently touches all possible topics related to UGS technologies including the views of the application up to the year 2030. Part 2 contains possible solutions of old well handling, a chapter dedicated to the global warming issue by reducing vented and flared gas, new development for salt caverns and widely discussed questions of carbon dioxide disposal. Within the last two topics are realized clear views of how the UGS industry can con-tribute to solutions of general importance. SG 2.3. “Intelligent UGS” presents new opportunities for increasing UGS efficiency based on the combina-tion of advanced IT technologies and “classic” reservoir engineering, simulation and reservoir surveillance. This particular report gives a picture about different statuses, plans and adoption of emerging technologies in the field of automated processes in proceeding steps and hierarchy of data mining, analyses and modelling as a background for fast and unbiased decision making realizing the full potential of a UGS, the surface and the reservoir. In addition to the WOC2 report I would like to emphasize that underground gas storage is a multidisciplinary job also touching other areas of energy business and because of that WOC 2 of IGU should continue to work closely with other international energy organisations such as the World Petroleum Council (WPC), the Inter-national Energy Agency (IEA) and UN ECE, Society of Petroleum Engineers (SPE) and Association of Amer-ican Petroleum Geologists (AAPG), Institute francaise du Pétrole (IFP) etc.

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APPENDIX 1 Members of the WOC 2: Chairman: Dr. Vladimir Onderka, RWE Gas Storage, The Czech Republic Vice Chairman: Hélène Giouse, Storengy, France Technical Secretary: Petra Grigelová, RWE Transgas Net, The Czech Republic SG.2.1. Leader: Joachim Wallbrecht, BEB, Germany SG.2.2. Leader: Hélène Giouse, Storengy, France SG.2.3. Leader: Georg Zangl, Schlumberger Innovation Solutions, Austria Members (in regional order):

Yoshizaki Koji Tokyo-Gas Co., Ltd. Japan

CHUNG So - Keul Korea Institute of Geoscience & Mineral Resoruces;Rock Engineering Team Korea

LEE Kangwon Korea Gas Corporation Korea

FUKAGAWA Hiroshi INPEX Japan

Khan Sergey OAO Gazprom Russia

Vlasov Sergei Gazpromenergodiagnostika Ltd. Russia

Ruban Georgy Scientific-Research Institute of Natural Gases and Gas Technologies-VNIIGAZ Russia

Grigoriev Alexander Scientific-Research Institute of Natural Gases and Gas Technologies-VNIIGAZ Russia

Akopova Gretta Scientific-Research Institute of Natural Gases and Gas Technologies-VNIIGAZ Russia

Vlasenko Nadezhda Scientific-Research Institute of Natural Gases and Gas Technologies-VNIIGAZ Russia

Pavlenkov Dmitry Gazprom Russia

Zayets Vitaly Ukrniigaz- Part time membership Ukraine

Bach Lars DONG Energy A/S Denmark

Olsen Osvald Arne Part time membership Norway

Giouse Hélène Storengy France

Wicquart Emmanuelle Storengy France

Marion Pierre Storengy France

Nieto Prieto Rosa Ma Enagas Spain

Martinus Gerard GasTerra B.V. Netherlands

Kuperus Y.A. N.V. Nederlandse Gasunie Netherlands

Damiani Vani Stogit - Part time membership Italy

Dijksman Niels Shell Netherlands

Spreckels Hermann E.ON Ruhrgas AG Germany

Wallbrecht Joachim BEB Transport und Speicher Service GmbH Germany

Grappe Jacques Geostock France

Lenk Gunar UGS Untergrundspeicher und Geotechnologie-Systeme GmbH Germany

Kreuz Michael OMV Gas GmbH Austria

Tancer Davorka Ina d.d. Croatia

Goryl Ladislav Nafta a.s. Slovak Republic

Borovička Vítězslav RWE Gas Storage s.r.o. Czech Republic

Onderka Vladimir RWE Gas Storage s.r.o. Czech Republic

Grigelova Petra RWE-Transgas Net, s.r.o. Czech Republic

Diósi Tomáš RWE Gas Storage s.r.o. Czech Republic

Blažej Radim RWE Gas Storage s.r.o. - Part time membership Czech Republic

Hristov Nikolai Overgas Inc. Bulgaria

Shterev Dimitar Bulgartrasgaz - Part time membership Bulgaria

Pavlova Marianna Bulgartrasgaz - Part time membership Bulgaria

Ognianov Rumen Bulgartrasgaz - Part time membership Bulgaria

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Silva Celso, Pereira El Paso Brazil

Rodriguez Juan Jose Repsol YPF Argentina

Samari Abdol Hossain National Iranian Gas Co., Iran

Chakeri Hasan National Iranian Gas Co., Iran

Mirzahosseini National Iranian Gas Co., Iran

Loghmani Mahmoud National Iranian Gas Co., Iran

Salavati Hussein National Iranian Gas Co., Iran

Nemati Mahmood National Iranian Gas Co., Iran

Samivand Masoud National Iranian Gas Co., Iran

Metzger Frederick Kinder Morgan Energy Partners USA

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STUDY GROUP REPORTS

24e Congrès mondial du gaz -CMG 2009 -Buenos Aires- 24th World Gas Conference - WGC 2009 ______________________________________________________________________________

International Gas Union

Triennium 2006 - 2009

Working Committee 2

- Underground Gas Storage -

Overview

Report Study Group 2.1 - UGS Database

The Basic Activity Study has been established for the first time as a part of the Triennium work programme 2000 - 2003 of WOC 2. The study work continued within Triennium 2003 – 2006.

Within the Triennium 2006 – 2009 further improvements of the UGS Database have been implemented by the Study Group 2.1 consisting of members of 13 countries. The Study Group report and the derived results have been presented during the World Gas Conference 2009 in Buenos Aires and are published as part of the WGC report 2009.

The world wide database on UGS facilities, including data about individual storage facilities in the world, and the graphical presentation of these data have been improved further. The geo-referenced presentation within the UGS World Map is available in Metric and English units, including UGS data from the USA and Canada. A glossary of relevant technical UGS terms has been developed and trends in the UGS business are discussed in the report.

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Content

The elements of the UGS Database Study are:

I. UGS World Data Bank - UGS in operation and planned II. UGS World Map - geo-referenced presentation of UGS data

o in Metric units o in English units

III. UGS Glossary - Glossary of relevant technical UGS terms IV. Study Report on Trends in the UGS business

The database and its visualisation cover the major part of the study.

This Data Survey 2009 developed by SG 2.1 covers an installed working gas volume of some 352 Gm³ operated in about 630 storage facilities all over in the world. This working capacity is presented in the following chart by regions.

UGS in the WorldWorking Gas Volume Distribution by regions

L. America & Caribbean

0,03 %North America

36 %

West Asia / Asia Pacific0,8 %

Europe24 %

CIS39 %

Europe West Asia / Asia Pacific North America L. America & Caribbean CIS

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The following table presents a summary of the installed working gas volume (106 m³) by nations:

NationNo. of UGS

Facilities

Total Installed Working Gas Volume

of UGS Facilities(106 m³)

USA 389 110.674Russia * 22 95.561Ukraine 13 31.880Germany 46 20.315Italy 11 16.755Canada 52 16.413France 15 11.913Netherlands 3 5.000Uzbekistan 3 4.600Kazakhstan 3 4.203Austria 6 4.184Hungary 5 3.720United Kingdom 6 3.700Czech Republic 8 3.073Romania 6 2.760Slovakia 2 2.720Latvia 1 2.300Poland 6 1.660Turkey 2 1.600Spain 2 1.459Azerbaijan 2 1.350Australia 4 1.134China 6 1.140Denmark 2 820Belarus 2 750Croatia 1 558Belgium 1 550Japan 4 550Bulgaria 1 500Ireland 1 210Portugal 1 150Armenia 1 110Argentina 1 100Kyrgyzstan 1 60Sweden 1 9

Total 630 352.480

* including 30 G m³ long-term strategic reserves

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UGS World Map (geo-referenced) The relevant UGS key data are available geo-referenced on the following UGS World Map in metric and English units. Brief instruction for the use of the UGS World Map (ArcReader) For the first access to the UGS Map, it is necessary to install the programme ArcReader of ESRI free of charge. Get ArcReader here: o from the added Setupfile o or via the original software ESRI weblink

http://www.esri.com/software/arcgis/arcreader/download.html. o or via the current software version for Windows XP on the CD under directory IGU-

2009-WOC2-SG2-1\Arcreader. After installation you can start to explore UGS data. Just click on the map!

UGS-World Map in Metric / English units

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A link will open a window to download the required GIS-files in a zip-archive. This zip-file has to be stored or extracted directly on your computer. In order to open the UGS Maps subsequently, navigate to the respective directory IGU-2009-WOC2-GIS including the downloaded local GIS-files and click on IGU-2009-GIS-Metric.pmf to open the UGS Map in metric units or alternatively click on IGU-2009-GIS-English.pmf in order to open the UGS Map in English units

http://www.esri.com/software/arcgis/arcreader/download.html


Subsequently the programme ArcReader opens with the following view:

The main window displays a map with information about different “layers”. All available layers are depicted in the “table of contents” in the left window. Depending on the scale different layers are visible. For navigation on the map (zoom in and out, etc.) please use the navigation toolbar. The helptics provide information which button to be tapped.

To derive more detailed information, as e.g. the storage location data, please click on or drag a box over a feature or place on the map you want to identify or or to navigate to.

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The attributes related to nations can be listed as e.g. in the following example:

or related to storage locations as follows:

Press the SHIFT key to add features to the current list. Use the dropdown list to control which layer(s) will be displayed.

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UGS World Data Bank

Explore UGS data in a MS-Access database

MS-Access Database

Select from the following table options:

UGS World Data in Metric units

� All 2009

� All in operation 2009

� All planned 2009

� Summary by Nations 2009 - in operation metric

� Summary UGS Key Data 2009 in operation metric

UGS World Data in English units

� Summary by Nations 2009 – in operation english

� Summary UGS Key Data 2009 in operation english

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Report on Trends

This start page just gives a survey and hints. More information and details can be derived from the report for further studies and analysis.

PDF-File Get Acrobat Reader here

Glossary

English Croatia Czech Dansk Deutsch Francais Italiano Japanese Portuguese Russian Slovak Ukrainian

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http://www.adobe.com/products/acrobat/readstep.html


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Contact

In case of any additional questions and recommendations respectively hints for improvements please contact:

Joachim Wallbrecht BEB Erdgas und Erdöl GmbH Riethorst 12 D-30659 Hannover Germany Phone: +49-(0)511 - 641-2294 Fax: +49-(0)511 - 641-2554 E-mail: [email protected]

mailto:[email protected]?subject=IGU%20Report

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NEW TECHNOLOGIES FOR UNDERGROUND GAS STORAGE

TRENDS AND HIGHLIGHTS

Study Group Leader Hélène GIOUSE (France)

Authors : Hélène GIOUSE (France) , Tomas DIOSI (Czech Republic) , Jacques GRAPPE ( France), Gretta AKOPOVA (Russia), Nadezhda VLASENKO (Russia)

Contributors : S.Khan (Russia), V.Onderka (Czech Republic); E.Kuperus (The Netherlands) Study Group 2.2 Members : FIRSTNAME SURNAME COMPANY COUNTRY

Gretta Akopova Gazprom - VNIIGAS Russia Lars Bach DongEnergy Denmark

Tomas Diosi RWE Gas Storage Czech Republic Hélène Giouse Storengy France Jacques Grappe Géostock France

Alexander Grigoriev Gazprom - VNIIGAS Russia Sergey Khan Gazprom Russia

Kangwon Lee Kogas Korea Mariana Pavlova Bulgartrasgas Bulgaria

Frederick Metzger KinderMorgan Energy Partners USA Juan José Rodriguéz Repsol YPF Argentina

Georgy Ruban Gazprom - VNIIGAS Russia Dimitar Shterev Bulgartrasgas Bulgaria So-Keul Skchung Kigam Korea

Nadezhda Vlasenko Gazprom - VNIIGAS Russia Sergey Vlasov OAO Gazprom Russia Vitaliy Zayets Ukrniigaz Ukraine

Thanks to: Claude CALIGARIS (GDF-Suez, France) Alexandre Volle (GDF-Suez, France), G.Kimmerlin (GDF-Suez, France),

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PART 1:

TRENDS ON NEW TECHNOLOGIES FOR UGS

1. UPDATE FROM PAST TRIENIUM A questionnaire was sent to 40 UGS operators. Several actions were taken to encourage more respondents; however the total number of replies to the 2006-2009 questionnaire “UGS Technological improvements” is 16, representing 9 countries. In spite of the limited number of respondents; the 16 returned questionnaires represents 75% (250/333 BCM) of the working gas in the world, and 75% (450/600) of all the storage facilities in the world. We believe that this is a very good representation of the opinions of the worldwide underground gas storage industry. Operators do not want their individual answers to be disclosed but to be presented statistically. Questions presented as boxes to tick have a good rate of answers. To interpret them, all the answers (1 to 5) are summed up for each question. This summary shows tendencies and interests of companies (see Annex 1). The majority of the open questions have not been answered. Many of the questions asked in this questionnaire are consistent to the 2003-2006 questionnaire: with the objective to be able to compare the evolution of the replies between these periods. The outcome of this comparison will be presented in this document. The main observation that can be made is the similarity between the answers given in the current and previous questionnaires. In general, predictions have shown to be too optimistic, the predicted evolution has not been implemented as fast as expected.

1.1 General Aspects

1.1.1 Which techniques are used to analyse the performance of your storage?

The main tools to assess today’s storage performance are monitoring, cost target and key performance indicators setting. The importance of cost target setting is expected to increase in future. In the near past, the situation was nearly the same but the “management appraisal” was more important than the key performance indicators. That means that quantitative measurements of the performance are more and more used by UGS operators to adapt and anticipate the competition of the market.

1.1.2 What new techniques will companies be interested in for the future?

CO2 sequestration has been indicated as the sole major interest for companies. The position of this subject is stable with respect to the past triennium, but what is new is the disappearance of the other interested subjects: in the last questionnaire, lined hard rock caverns and abandoned mines were interesting and these techniques where supposed to take more importance in the future. They are still of interest but their interest does not appear to be growing.

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1.1.3 What methods are used to preserve, improve and share the storage skills of experts?

This subject was of no interest 5 years ago. According to the survey things have changed and will continue to change in the future. The need to preserve, improve and share skills appears as a major concern for UGS operators.

To improve and share the storage skills of the company experts four areas of interest have been identified: organisation, networking of experts, technical development survey and document management systems. Information technologies could help companies to organize their Knowledge Management.

1.1.4 What technological improvements are important?

Almost all technological improvements proposed in the questionnaire are considered to be important as research topics:

- General items: Handling water production, Data mining (designing vs. operation monitoring and performance enhancement…), Prevention of hydrates formation, Enhancement of storage monitoring and surveillance.

- Subsurface items: Improved reservoir description, Reservoir management, Gas substitution (for cushion gas), Impact on aquifer water quality, salt cavern creep prediction, Improve salt cavern thermal modelling, Improve salt cavern thermal modelling.

- Wells item: Sand control (measurement, modelling, prediction?, remediation…), Well architecture, Study cement bond and integrity during life time of wells., Improve pipe and well casing integrity monitoring.

- Surface facilities item: Gas quality measurement, Development of existing storage facilities capacities, Performance description and forecasting of surface treatment and gathering equipments.

The exceptions are storing gas hydrate and abandonment methods for storage facilities. The interest for these techniques is currently poor, except for the future.

1.1.5 What is the main new technology which companies have spent effort on during the last three years? In which new technologies would companies welcome a technological breakthrough for the coming 5/10 years?

The answers are very different, in all fields of UGS activity. Ø Geophysics:3D seismic, seismic interpretation, gravity survey for monitoring Ø Reservoir modelling: Reservoir description, numerical simulation models, coupled simulation Ø Smart UGS: Data storage, enhanced data mining, expert systems, forecasting performance Ø Operations: enhanced monitoring, handling water production, Ø Wells: Water balanced coiled tubing drilling, improved well completion, horizontal drilling Ø New activities: CO2 sequestration, design of temporary UGS for associated gas.

1.1.6 Who play an important role in technology improvements for companies?

The storage operator, contractors and commercial companies providing services for oil and gas industries play a major role in technology improvements. Dedicated internal or external Research Centre is not very present in the answers.

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1.2 Geology, Geophysics and Reservoir Engineering

1.2.1 Which technologies are applied for better geological-structural definition of the trap?

2-D and 3-D seismic were the main technologies used in the past. In future 3-D seismic should remain but no more 2-D seismic. This answer is inline with previous questionnaires from which we can conclude the 2D disappearance has not occurred as previously predicted.

1.2.2 Which method is used to calculate limits for maximum working pressure of storages? Are operators considering increasing the maximum allowable pressure for their storage? What is the added value of maximum pressure above initial reservoir pressure?

Maximum allowable storage pressure strongly influences storage characteristics. This level is an indication of the potential utilization of storage capacities. The limitation on the maximum pressure is connected with the risk of gas spilling. In many countries legislative limitations are defined related to maximum allowable storage pressure. For depleted fields the pressure range for the storage operating cycle depends upon (1) the safe upper limit of the reservoir pressure (bottom hole or surface pressure), (2) the flow capacity of the wells, and (3) compression requirements when injecting gas into the reservoir or delivering to market. An increased maximum pressure will in general lead to an increased storage capacity and an increased maximum outflow capacity. It is often the easiest way to improve the value of underground gas storage. Unfortunately, in the 2003-2006 and in the 2006-2009 questionnaire, this question has few precise answers. It can be said that the maximum working reservoir pressure is determined:

Ø using Administrative rules or regional practices, Ø specific studies based on cap rock threshold or rock mechanics based on in-situ measurements

or core testing Ø or simply by reference to initial pressure (sometimes with a multiplicative coefficient). Ø Tubing design pressure could be checked too.

In the near past, only salt cavern operators were trying to increase their maximum allowable pressure. Now and in the future, both depleted field and salt cavern operators are investigating an increase of the maximum allowable pressure. UGS operators are not ready to communicate very precisely on maximum pressure, probably for two reasons: this parameter is directly linked with the monitoring of subsurface security controlled by public authorities, and to increase it gives a real competitive advantage.

1.2.3 Which type of reservoir modelling tools do you use?

For porous reservoirs, numerical and advanced reservoir simulations are currently used and will continue to be used for reservoir modelling. Other tools are not used much.. For caverns numerical models (finite element, 3D geo-mechanical calculations for uncommon cavern shapes, prediction of convergence) are currently used and will continue to be used. Thermodynamic modelling for prediction of gas pressure and temperature in caverns is little used at the moment, but it is a technique that should be used much more intensively in the future.

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This situation is consistent with the answers to the previous questionnaire: numerical (advanced) sub-surface simulation has become and will stay a necessary tool to develop maximum capacities. The effort spent by operators on this topic (see answers §1.1.2.5) A specific chapter on Cavern modelling tools is enclosed in this document.

1.2.4 What monitoring techniques are used to improve subsurface operations?

Gas quality monitoring, well testing, automated well pressure and temperature monitoring, real time well performance monitoring (flow, pressure) and water content monitoring are the main answers. The situation is not really different from the last questionnaire.

1.2.5 Which technical methods are used to improve the performance of UGS storage (except well techniques)?

Reduction of pressure losses due to flow, increasing of UGS reservoir capacity and fast change of operational mode are key points to improve the performance of all UGS’s. For porous media storages Ø avoiding gas spilling/losses in reservoir, Ø techniques of sand control Ø solutions used to reduce water influx Ø optimisation of gas volume area and increasing effective gas thickness

are important. For caverns Ø networking caverns Ø cascading unsaturated brines from one to another Ø using of blanket gas for leaching

was and are relatively important. The importance of reducing pressure losses due to flow is the same as in the previous questionnaire, also as the importance of change of operational mode. The answers for porous media storages are very similar. The main differences are in the specific responses to caverns. In the previous triennium, the answers were: Ø Leaching of new caverns to improve the performance keeping the main measure. Ø Enlarge existing caverns.

Current topics give more importance to a global optimisation of the salt cavern storage system, both for the brine process and the gas process, rather than the individual capacity of each cavern.

1.3 Wells A specific chapter on wells is enclosed in this document

1.3.2 Which kinds of well concepts are (will be) used? What are the problems with new concepts?

Vertical wells and directional drilling are the concepts used frequently in companies. This tendency will not change in the future. The importance of vertical and directional drilling was the same in the previous questionnaire. The difference is in the evolution which was forecasted in it: different kinds of well concepts like extended reach well, re-entry, multilateral well, and so on, was expected to become more and more important. The present questionnaire shows that these options for complex wells are used but they do not represent the basic design. Cement quality, formation damage, safety and hole stability are the main problems in implementing new well concepts. In the previous questionnaire, the problems were the same.

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Once more, technologies do not evolve so quickly and vertical wells are not out of fashion.

1.3.2 What techniques are applied to well completion?

Welded and mono-bore completions are the main techniques mentioned by companies. Welded completion should become more important in the future. The importance of sand screen and gravel-pack technologies which occupied the first two places in the past questionnaire decreases. It is interesting to remark that the welding technology which is so important today and for the future was not mentioned in the previous questionnaire.

1.3.4 Which stimulation technology is used to maintain and improve deliverability?

Acidification in conventional completion is the main technology used for maintaining and improving deliverability. The fracturing technology is also used by two operators.

1.3.5 Which new methods are used to ensure the integrity of subsurface equipment?

The two main methods (with almost the same number of answers) are: annulus pressure monitoring and cement quality determination (CBL/VDL). According the questionnaire no other important evolution is foreseen in future.

1.3.6 How are maintenance (and revamping) programs of wells managed?

The main method to manage the well maintenance program is on a case by case basis. But this method should evolve towards a long term planned maintenance program driven by a risk assessment value. At this moment this method is not yet used frequently.

1.4 Surface Facilities

1.4.1 What techniques are used to avoid hydrate formation?

No evolution appears in techniques used (in the previous questionnaire, in the present and in the future): methanol inhibition and gas heating are and should stay the main techniques to avoid hydrate formation.

1.4.2 What techniques are used for corrosion management?

In the same way as for hydrate formation, no particular evolution in this domain (in the previous questionnaire, in the present and in the future) : cathode protection, and in a lower degree, casing wall thickness monitoring on surface facilities are and would stay the main techniques on corrosion management.

1.4.3 What technology is used for gas treatment and gas quality management? What are the main drivers for the application of these technologies: reduction of atmospheric emission? Energy saving? Efficiency improvement?

New concept of TEG dehydration design and automation are the main technologies applied in this context. Their importance should increase in the future. This technology was not mentioned in the past questionnaire replies where focalised on traditional technologies which stay important, but far from the new concept of TEG dehydration: Several drivers are mentioned: efficiency, environment concerns, costs, high availability, gas quality.

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1.4.4 What improvements were carried out on compression performance?

Optimisation of operation conditions and use of electrical driven compressors are the main improvements mentioned. The use of electro-compressors should become more important in the future to improve flexibility of operations. This last technology didn’t appear in the last questionnaire, so its importance is relatively new, and probably funded on environment new preoccupations.

1.5 Safety. What methodologies are used to improve safety? Different tools are implemented to improve safety. Some tools are methodological such as: safety studies and audits, preventive servicing of technical installation, predictive maintenance, analysis of accidents (or near/miss accidents), personal training and best practices of engineering/operating maintenance. And some tools are equipment: automatic shutdown and safety valves. In the previous questionnaire, already, all indicated techniques were widely used.

1.6 Environment Technologies and methods to reduce the impact of hazardous factors on the environment

1.6.1 Impact on the air quality

Reduction of vented gas is and should stay an important technology to reduce impact of storages. Water disposal and Noise reduction are other important technologies in this issue, but at a lower level. Reduction of greenhouse gas effects and reduction of flared gas are in UGS operation seems important to operators and are foreseen to become even more. A specific chapter on flared and vented gas is enclosed in this document.

1.6.2 How to deal with the impact of storages on the aquifers, the impact of storages on the overburden aquifers:

Few answers have been given on the above mentioned topics. Operators of aquifer UGS´s monitor the water quality by regular physical and chemical analysis.

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2. TOWARD 2030

To contribute to the “2030 Natural Gas Outlook study”, a long term forecast on new technologies for UGS has been performed. As extrapolation of short to medium overview delivered by the questionnaire is considered less reliable, this analysis has been based on the input of the experts in study group 2.2. According to the experts no completely new technologies (or technological breakthroughs) are expected to be developed by 2030 for underground storage facilities, except for information technologies which are presented in a dedicated report. A list of completely new technologies (storage of other energetic fluids than natural gas as hydrogen or hydrates, drilling with lasers, etc.) has been submitted. However it is believed the list cannot be considered reliable for 2030. Implementation of new technologies is expected to be limited, and will follow development in the E&P industry due to the similarity of technology used. Available or emerging technologies are expected to be improved and more generally used for both existing and new facilities. We have divided these technologies into five branches.

2.1 Development of existing UGS Several parameters lead existing UGS to be key assets for the future:

Ø the NIMBY (Not In My Back Yard) factor makes it difficult to develop new infrastructures, especially in densely populated areas (as Europe),

Ø the economics: developing an existing UGS (brown field project) is generally much more profitable(and much quicker, less risky etc…) than creating a new one from scratch (green field project)

This is the reason why technologies which lead to improved capacity and performance of existing UGS will be of major interest.

2.1.1 Develop capacities and improve performance

Increasing maximum storage pressure could significantly increase the capacities, in particular for UGS´s created in depleted gas fields. Reservoir management, e.g. water control/management, improvement might lead to capacity increase. Substitution of cushion gas could be of interest as gas price is increasing. The cost of inert gas (e.g. nitrogen) could be probably lowered, if the demand is increasing for this type of operation. Seismic acquisition, processing and interpretation have been improved a lot in the past 5 years and is supposed to continue. The generalization of 3D campaigns on UGS and, in certain cases of 4D campaigns, will be a key factor to know better reservoirs and to improve capacity and working volumes through optimised gas placement.

Modelling will improve and provide operational tools to improve performance:

Ø a better coupled representation between subsurface physical phenomena (fluids mechanics, rock mechanics, thermodynamics)

Ø a better coupled modelling between subsurface and surface facilities Ø a better utilization of all data collected during operation to update models (see SG2.3

contribution)

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2.1.2 Develop deliverability

Ø Implementation of large diameter wells will lead to increased deliverability, but will only be

applicable in high permeability reservoirs and caverns. Methods to prevent water inflow could be identified as a potential field for improvement…

Ø Measuring and predicting temperature in salt caverns.

One of the main parameters that limits withdrawal and injection capacity in caverns is temperature. In the case the cavern is operated at high flow-rates (injection or withdrawal) the temperature of the gas varies rapidly and is difficult to predict. Measurements and operational models for caverns, incorporating thermodynamic and rock mechanical aspects and constraints could lead to optimised operation.

Ø Measuring physical parameters (such as pressure, temperature, sand production, water production) by permanent down-hole sensors will allow optimising the deliverability of wells.

2.2 Develop flexibility

The main key factors developing flexibility (i.e. changing rapidly withdrawal to injection, and injection to withdrawal and rates) are maintenance, operation procedures and operational models. But advanced technology on compression, as magnetic bearings, will help.

2.3 Increasing the life-time of UGS´s As said previously, existing sites for UGS´s have a strong value, because of the difficulties to create new facilities. Some UGS’s have been operating for several decades and most of them will be in this situation in 2030.To be able to predict, monitor and increase UGS life-time will be of major interest. The Life-time of different UGS equipment is quite diverse: the supervisory and data acquisition system (SCADA) has to be frequently up-dated, in contradiction wells have a longer life-time. During operation, salt caverns will creep and reservoirs might be slowly damaged . Technologies and methods that will be improved and developed:

Ø The monitoring and re-assessment of compressor and pipeline life-time (corrosion monitoring for example)

Ø Well integrity, casing and cementation are key points. New logging techniques for better cement quality and corrosion monitoring are expected, as well as efficient repair procedures and techniques. Of particular interest could be resins to seal micro leaks in defective cemented annuli.

One can note that the need for these logging tools is much greater in the storage industry than the E&P industry. On the other hand, the CO2 sequestration projects have to address the problem of well integrity on a long period of time. This gas is specifically aggressive for cement and steel. Some new methods and technologies could arise in this branch of research and development. To increase its ability to use new technologies, the underground gas storage industry has to build common research programs with other industries:

Ø other industrial industries to improve the monitoring and the assessment of the life-time of infrastructures,

Ø CO2 sequestration programs for the specific problem of the integrity of wells.

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2.4 Decrease the impact of the UGS on the environment (natural and human) As all industrial infrastructures, UGS's have to take into account the demand of governments and public opinion to insure security and preserve the environment. The operator has to comply to the rules in order to continue operations and as well to ensure his own investment. To reduce the environmental impact, best available technologies have to be generalized and improvements have to be applied. These improvements are expected for:

Ø Atmospheric emissions of natural gases and exhaust gases (NOx, CO, SOx, CO2). High efficiency and low emission gas turbines are expected in addition to increase reliability and less expensive.

Ø Noise reduction, this concerns compressors but also rigs and all surface facilities. Ø Impact on surface water. Ø The reduction, treatment and disposal of effluents will further on allow preserving surface water

resources. Ø The monitoring of subsurface water quality (especially for aquifer storage reservoirs) will be

developed to ensure long-term impact. Ø Wastes of production and consumption. Apart from the reduction of waste production by

optimizing processes, the main point is to prevent soil and water contamination through waste collection and storage in compliance with the requirements

Ø Security in the near vicinity of the facility. To reduce the risk outside the facility will be more and more important in every country. If not, UGS operators will be obliged to create a no-man-land around the facilities and the NIMBY effect will increase and be a real constraint to develop new UGS.

These impacts will increase CAPEX to develop new UGS. It is not so sure that this will increase OPEX, especially with the evolution of regulations asking the industry to pay for these impacts.

2.5 New technologies for new UGS New facilities will be built during the next years. The technologies described in § 1, 2, 3, for existing UGS´s will be applied. Some specific ones are needed for new projects:

Ø Drilling in strongly depleted fields (drill in fluids & cements) Ø Progress in completion techniques (expandable tubular, gravel packing in horizontal boreholes

etc…) Ø Progress expected from new cement formulations (“light” cements, expandable cements etc…)

reducing the possibility of gas leakage and durability in particular under difficult conditions (high P and T, pressure cycling etc…)

2.6 Developing specific technologies for UGS out of sedimentary basins

If we define converted gas or oil fields, aquifer reservoirs and salt domes or horizons as conventional reservoirs, that means that some specific technologies (available or to be developed) could allow to have storage capacities available in zones where geology is not favourable. These capacities will be rather small, mostly oriented as peak-shaving and expensive to create. They were supposed to be twice or three-time more expensive than conventional UGS:

Ø UGS in abandoned mines (coal or other mineral) are not new but this technology has to deal with

leakage problems intrinsic to the mining activity (new mines, however may take into account a future conversion to gas storage).

Ø Lined rock- caverns and LNG caverns (technology in the scope of PGC) will be more secure. These specific technologies are expected to contribute but to a very limited part, to total capacities.

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PART 2:

HIGHLIGHTS

1. TECHNOLOGY FOR (OLD) WELLS This part of the report is based on the answers of UGS operators to the questionnaire and on the outcome of a dedicated work-shop on this topic. Technologies for wells are clearly driven by Exploration and Production activity, even if specific uses of these technologies or adaptation of these technologies are developed for UGS. Analysing the requested feedback from gas storage operators, only limited implementation of brand new technologies is planned in the near future for UGS wells. This is partially driven by the fact, that most of the UGS operators are focused on capacity extension by brown-field projects evaluation, where the completion technology to be used is partially limited by historical installation.

Because UGS wells could be used several decades (more than production wells), in a more drastic way (because of cycles of injection/withdrawal) and with a demanding requirement for confinement, cased hole investigation is a key point for UGS wells. Gas well life depends directly on well integrity: cement bond and casing corrosion. These two parameters are to be monitored during the well lifetime. The behaviour of the UGS formation is also a key to optimise production rate in accordance to sanding issues and water production. For caverns, the optimisation of withdrawal rates is a driver to large diameter wells.

The technologies related to monitoring, well completion and repair, described in the following chapters as new are mostly available. However, their use for many operators refers to the future.

1.1 Monitoring and logging cased holes or completed wells For economical, technological and safety reasons, it is often necessary to perform through-tubing or through casing logging. This possibility is also to be considered when converting depleted reservoirs into UGS.

1.1.1 Reservoir management solutions

Through tubing gas detection Gas saturation of the reservoir could be monitored by specific blind –cased wells. The detection of gas in control aquifers is a key point for monitoring the confinement of the storage. The use of neutron tools is widely used to control the presence of gas behind the casing. However chemical neutron may not be used through tubing when the annulus is gas filled. The pulsed neutron technology overcomes this problem. The pulsed neutron technology has a huge safety advantage compared to conventional neutron tools as it does not imply the use of radioactive elements. Pulsed neutron technology eases logistics, reduces risks of exposure for users at the surface and risk for the well in case the tool gets stuck down-hole. The “conventional” pulsed neutron tool generates neutron from an accelerator. The tool estimates the decay of neutron energy via the spectrum of the gamma rays emitted during the neutron capture reaction (sigma). The sigma log is the sum of sigma contribution from the formation, from the saturating fluid and from the residual water. The measurement is quite effective in most cases. However problems are encountered in fresh water aquifers in which the distinction between reference log in water and subsequent log potentially in gas is difficult. New pulsed neutron tools have been recently developed to measure the un-captured thermal neutron

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coming back to the tool and no more only the Gamma rays resulting from the capture reaction. This technology is much closer to the chemical neutron technology and is not as much affected by the lithology effect which is predominant in low sigma formation (fresh water and/or low porosity).

Down-hole sanding detection

Sand production in UGS is a major issue for high porosity and permeability, and often unconsolidated reservoirs. Sand production detection is commonly performed at the surface using acoustic based tools for sand impact on the well head. This is quite effective but does not identify the sand producing layers. Neither does this method define the proportion of sand produced at the surface nor the amount of sand accumulated down-hole. New sonic based tools have been developed to detect down-hole the impact of sand against the housing of the logging tool. The “background noise” produced by the movement of the tool and the gas production is discriminated from the impact noise based on the sound frequency. The spectrum of sand impact noise provides information about the amount of sand produced and the energy of the sand while the sensor is at a known depth. Such understanding provides key information for eventual polymer treatment.

Through casing pressure measurement In some cases formation pressure behind casing can bring important information for reservoir monitoring. The use of formation testers in the casing is fairly common but results in the loss of casing integrity. Some new design tools overcome this problem with the automated plugging of the casing after the test. A rotary drill bit penetrates casing, cement and formation to enable a hydraulic link between the formation and the tool. From this hole, formation pressure and samples can be collected. Once the measurement is completed, the tool configuration changes automatically and a plug seals the hole. The success rating is quite high with more than 95% probability of seal.

Through casing resistivity measurement A key indicator to determine reservoir hydrocarbon saturation is formation resistivity measurement... Unfortunately such measurement was only feasible in open hole. New design tool enables the measurement of formation resistivity through the casing in some conditions. The principle, the depth of investigation and the vertical resolution can be compared to the conventional laterolog. In most cases the depth of investigation is much deeper than the pulsed neutron saturation tools. Limitation occurs when the well has been drilled with OBM, when reverse invasion profile (Rxo>Rt) is present or more generally when any “resistive material” is lying between the casing and the formation. This is quite important to consider in shallow aquifers saturated in fresh water. The lack of conductivity is a key limitation for such tools.

Through casing formation sonic/VSP measurement The measurement of sonic data in old wells is still possible when casing to cement and cement to casing bonds are good. Multi frequency tools are now available measuring compressional and shear waves in multi-frequencies. The de-convolution of casing arrival is now possible and formation response can be deducted. Further development of sonic enable axial and azimuthal measurement to be done. Such process provides anisotropic stress evaluation, fracture distribution etc... This can be attempted to recomputed time/depth law and re-evaluate potential seismic lines. The VSP tools have also improved over the few last years. For most service providers, the signal to noise ratio has been drastically improved and the processing can easily be performed through casing.

Through casing fracturing-testing The understanding of in situ stress magnitude is a key to build a proper geo-mechanical model and thus to operate UGS safely optimising the maximum pressure than the stored volume. Stress- tests are generally performed in open-hole but may be performed through casing by perforating the casing with multiphase guns (12spf to ensure azimuthal distribution). A patch can be set afterwards to

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restore well integrity. An important pre-requisite to perform this test in cased hole is the perfect condition of the cement especially its hydraulic isolation capacity. Stress test interpretation provides the following parameters: breakdown pressure, propagation pressure, instantaneous shut-in pressure (ISIP), closure pressure, reopening pressure and rebound pressure. The orientation of the fractures and therefore the direction of main stress cannot be defined in cased hole (no imager log possible).

1.1.2 Well integrity solution

Through tubing casing wear evaluation

The evaluation of casing wear through tubing is impossible using conventional ultrasonic imagers as the ultrasonic wave is directly reflected by the tubing walls. Recent development has been made by several logging providers on electromagnetic measurements. For most suppliers, a multi-frequency electromagnetic field is generated in the environment. Phase shift and amplitude are measured as well as tubing internal calliper to:

Ø Determine joints of casing having different weights or wall thicknesses Ø Locate casing collars and other casing hardware Ø Locate evidence of casing erosion and identify defects as being either internal or external (inside

string only) Ø Locate potential holes

Another advantage of these tools is the fact that they do not require to be logged in a liquid environment (unlike ultra-sonics). This is a key advantage when recording logs on a gas producing well or in salt cavities to avoid filling them up. The drawback is still a quite low resolution generally in the range of 1or 2in. These tools also require generally electromagnetic properties of the tubing and casings properties to be known. For old wells, an assumption must be done. However, considering that this new technology is growing, it would be advised to measure electromagnetic properties of the completion for all new wells.

Multi depth of investigation ultrasonic integrity evaluation The evaluation of cement and/or corrosion using ultrasonic imager is becoming quite common with single string of casing. The ultrasonic wave is generated down-hole towards the casing wall. The dissipation of the wave energy through the different reflection/refraction occurring on the mud/casing and casing/material behind casing interfaces enables an estimation of both casing state and cement mapping behind casing. The evaluation of cement behind multiple strings of casing was, until a couple of years, impossible. The use of flexural waves produces further depth of investigation and enables further analysis to be done. With analysis in addition to the cement evaluation, flexural reflections from the third interface may also define the position of the casing within the borehole or outer casing. Previously unavailable cased hole–environment geometrical information can help assess casing and cementing techniques, choose cut points on casing retrieval jobs, and provide context for other evaluation services run through casing.

Through tubing evaluation of caverns/gravel pack evaluation The use of pulsed neutron has also another outcome. As mentioned previously, the pulsed neutrons react with their environment. The gravel packs gravel is either sand (silicon dioxide) based or carbolite (aluminium) based. Both types of gravel respond well to the silicon activation logging technique. With a half life of 2.24 minutes the effect of silicon activation will still be strong long after inelastic scattering, thermal capture, and oxygen activation are long gone. Gravel pack logging uses a neutron source to activate the silicon laying outside the screens and minute or so later records the gamma ray signal strength which is roughly proportional to the amount of gravel in the annulus. The lack of silicon activation response can be used to evaluate the amount of gravel in the environment and hence, the quality of the gravel packs. This type of log is generally done just after the gravel pack job as the rapid filling of the void by fines or formation sand makes the analysis fairly difficult. However, on old wells suffering from sand production, the lack of silicon activation may be used as well to define the presence of cavern behind the screens.

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1.2. Equipment and devices

1.2.1. Pre-pack and Expandable Sand Screens

Pre-packed and expandable sand screens could be an alternative to the gravel pack sand control in some cases (for example in case of a new UGS well with down-hole pressure lower than hydrostatic), Extensive use of them is expected in the future.

Pre-pack sand screen A pre-pack sand screen assembly has resistance welded inner and outer screens concentrically mounted in radially spaced relation onto a perforated mandrel, thereby defining an annulus in which pre-pack gravel is loaded. The longitudinal spacing distance between adjacent turns of the inner and outer screens selectively exclude sand fines of a predetermined minimum size. The outer screen wire is substantially greater in size as compared to the corresponding dimension of the inner retention screen wire. The inner retention screen is radially spaced with respect to the perforated mandrel, thereby defining a bypass flow annulus. The effective inlet flow area through the inner retention screen is more than twice the effective inlet flow area through the outer screen. Accordingly, localized deposits of sand fines on the inner screen are effectively bypassed by the remaining flow passages formed across the inner retention screen. According to this arrangement, the dual screen pre-pack assembly excludes sand fines from inflowing formation fluid during the initial production phase following a gravel pack operation, without limiting production of formation fluid.

Expandable Sand Screens Expandable technology is a system for increasing the diameter of the casing, liner or sand screens of an oil well by up to 30% after they have been run down-hole. This expansion is done through cold working of the steel by a larger expansion tool. This expansion reduces the telescoping effect that traditional casing plans have (large diameter at the top and small at the bottom). The advantage of this expansion is that a larger diameter well bore is possible at total well depth versus a standard casing string. Expandable Sand Screen (ESS) is a new technology providing a unique solution to solving sand control issues. Its manufacture consists of three sandwich layers – the expandable base pipe, the filtration media and the outer protective shroud. The base pipe or EST (Expandable Slotted Tube) is capable of expanding up to 80% greater than its original diameter. This provides greater inflow area compared to that of the gravel pack based pipe in a similar installation. The ESS joints have integral expandable connectors, which ensure no blank pipe areas to obstruct flow. The four-filtration media strips covering the base pipe and connectors longitudinally overlap each other to provide a sand tight system after full expansion. The filtration media is a metal weave designed to provide maximum filtration / flow area, thus maximizing the resistance to plugging effects. The filter media is designed to support the formation of sand grain particles, preventing their departure from the well-bore. These grains naturally bridge the formation sand against the ESS, controlling sand influx in the process. The ESS makes full contact with the casing wall, thus eliminating annular sand fill and therefore minimizing perforation tunnel cavitations or collapse. The protective shroud ensures protection to the filtration media whilst running the equipment in hole. The features of the expandable sand screen are summarized as follows:

Ø Superior screen design for increased reliability and longevity. Ø Slim design to facilitate deployment. Ø Expansion makes full contact with the casing wall thus preventing tunnel cavitations or collapse. Ø System designed to resist erosion and plugging. Ø Large ID to maximize future well intervention options. Ø Large and uniform flow area to optimise production. Ø Simple deployment minimizes operation costs. Ø Lower interval accessibility

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1.2.2 Patches

Another application of expandable equipment is patches. Patches can be used to repair and to extend life of a well by cladding over perforated or corroded sections of casing. The expandable patch can be installed in multiple sections while maintaining large through bore internal diameter.

1.2.3 New Cements There is a very large number of wells worldwide that leak (either by the tubing or by the casing) or have sustained casing pressure (SCP). In Central Europe and Middle East hundreds of wells are reported to have trapped pressure that cannot be bled off. In the US and Canada there are thousands of wells leaking to surface, which may or may not be discharged to the atmosphere. Furthermore, 25% of all wells in the Gulf of Mexico have measurable sustained casing pressure. Additionally, remedial work fixing issues relating to cement failure has been estimated to be more than $50M a year in the US alone. Throughout the lifecycle of a well, planned cycle or operational changes can contribute to unknown damage to the cement integrity that is hard to identify or locate, including the generation of a micro-annulus. Regarding the survey performed for wells aged over 30 years, the failure origin distribution is in

Ø Cement isolation : 60% Ø Perforation plugged : 20% Ø Corrosion : 12% Ø Damaged or not suitable completion : 8%

Within flow paths, hydrocarbons can either migrate to surface, or become trapped below the wellhead leading to pressure build-up. Typical events occur during cementing, while perforating or stimulating, throughout the subsequent production, and even after abandonment.

Low density cements To cement efficiently and safely long casings, a fluid with a lower density than usual cements is of great interest. Low density cement are now available and could be used for UGS wells.

Self healing cement

An isolation system that is activated only when a cement integrity problem occurs would be a very interesting future solution. New cement is currently being developed by a service company to form a complete hydraulic barrier by swelling in the presence of hydrocarbon flow. Laboratory tests seem convincing and some pilot operations have been performed. Long term success is to be confirmed.

1.3. Well technology for caverns

Large wells The need for high deliverability and injectivity has entailed on many recent projects the implementation of large diameter wells (typically 13 3/8” production casing and 9 5/8” production tubing). The corresponding wellhead and completion equipment has been provided by equipment manufacturers and encompasses in particular 13 3/8” x 9 5/8” production packers and 9 5/8” Subsurface Safety Valves, frequently of the Tubing Retrievable (TR) Surface Controlled Subsurface Safety Valve (SCSSV) type. In the USA, even larger cavern wells are considered with extremely large size welded casings (e.g. 26”) and the caverns are operated through the production casing itself, and without packer / tubing completion. Practical guidelines and company rules have been revisited to support the limit set to the maximum gas velocity in the gas completion strings.

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Dual wells cavern operation is implemented on a few cavern sites.

Welded completions Welded gas completions are gaining ground (particularly in Germany), with an aim to minimize the risk of fatigue and gas leakage through joints under the alternate thermally induced loads applied on the completion string during the injection and withdrawal processes (high temperature and dilatation during injection, cooling and contraction of the string during production).

2. REDUCING WARMING IMPACT. MEASURES TO REDUCE VENT AND FLARED GASES

UGS operation, as all gas infrastructures operation, results in venting and/or flaring some methane. As the answers to the questionnaire show, the reduction of this gas is presently a target and will be a major one in the future. The reasons to take care of this gas are and will be multiple: to save money, to reach legal requirements or to participate on a volunteer basis to the reduction of warming impact. Here below we present different methods and technologies to achieve this reduction:

2.1 Use of mobile compressor stations (MCS) for pumping out natural gas from trunk gas pipeline

This technology will help minimize losses of natural gas during repair and maintenance of pipelines. Gas will be pumped out by MCS of required capacity and minimum possible weight characteristics.

One such operation on a big pipeline can help save several million m3 volume of reduced vent gases depends on the characteristics of a gas pipeline, concentration of methane in natural gas and factors that induced emissions of natural gas before repair of a gas pipeline. The volume is less for an operation on a UGS facility but could reach substantial amounts. This measure will help significantly reduce volume of vent gas replacing the current practice of gas discharging into the atmosphere during repair and maintenance operations.

Using MCS to utilize natural gas can be commercially efficient as it is stipulated by transfer of emission reduction units (ERU) and profits from using vent gases. Technology of using MCS during transmission of natural gas via pipeline grid is absolutely new for lots of operators. It requires specific extra-knowledge and relevant training of local personnel. This technology of compression was implemented by LMF (Austria) to transmit nitrogen via pipelines.

2.2 Compression technologies

Use of air or electric start system The use of air or electric start system for gas compressor units ensures reduction of vent gas discharges into the atmosphere. These systems comply with environmental standards and regulations.

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Installation of air or electrical start systems on existing equipment require high investments and are therefore unprofitable from an economic point of view. However there are positive ecological presuppositions associated with the reduction of vent gases. According to Natural Gas Star (USA) data compressed nitrogen can be used for start systems. This technology implies prevention of methane emissions from starters by replacing natural gas with compressed nitrogen. The system should be leak-proof enough to prevent nitrogen leakages. This technology can be used at gas compressor units with pneumatic gas starter. Compressed nitrogen completely prevents discharge of vent gases into the atmosphere during starts and its leakage through valves.

To reduce vent gas during shut-down A measure to reduce the amount of vented gas during de-pressurization of gas compressor units can be obtained by injecting (a part of) the pressured gas in the compressor module into the fuel gas system. De-pressurization of the compressor module takes place during maintenance and switching from operational into stand-by mode. In most cases this gas is evacuated into the atmosphere through the vent system. Using this natural gas as a fuel to ensure operation of other facilities leads to a reduction of vent gas discharged into the atmosphere. The implementation of this technology will require the installation of a dedicated system to discharge gas from the gas compressor unit into the fuel gas system.

High speed motors integrated in the compressor without methane emissions A new concept of an integrated motor/compressor system in which compressor, motor and magnetic bearings are enclosed in a hermetically sealed and pressure-tight casing has been developed. . The big advantage is the enhanced environmental compliance due to zero emissions of process or flue gases. No specific device to collect natural gas emission is needed.

2.3 Electric-driven or air-driven actuators for valves This equipment contributes to the prevention of methane emissions into the atmosphere when re-arranging valves by equipping them with remote operated electric hydraulic actuators or air-driven actuators. Emissions of vent gases are prevented. Pneumatic or pneumo-hydraulic drivers consume natural gas when the valves are actuated. Typical gas consumption for diameter 50 -300 mm is estimated between 0.03 - 15500 m3. Volume of consumed gas depends on installed equipment. This measure could be applied to almost all new construction projects and for revamping programs.

2.4 Flared associated petroleum gas (APG) As an example, in Russia, volume of flared APG can be evaluated between f 10 to 70 billion m3. The associated gas can be used through compression to produce power. Using APG as a fuel is a trend of high priority as this type of fuel is available. Taking into account high energy output required for oil production, APG can be used to produce electric power for industrial needs. This gas can be used locally or after transmission by the network. In case it is not possible because of the lack of gas infrastructures, the creation of a temporary UGS could be a valuable project.

3. NEW DEVELOPMENTS FOR SALT CAVERN UGS’s

Recent evolution of the Natural Gas industry has promoted the requirement for highly flexible UGS (Underground Natural Gas Storage) facilities, allowing modular development of the working gas capacity and quick cycling of the inventory. Salt caverns are an almost ideal response to such needs and have widely developed in recent years. For example among the 15 UGS projects currently in development in Germany 13 are related to Salt Caverns.

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The recently emerging operating model for salt caverns is evolving from a seasonal model with a few cycles per year to a high flexibility trading model with typically 10 cycles per year or more, which corresponds to a daily withdrawal or injection design capacity equivalent to some 10% of the cavern working gas. This performance requirement has triggered new technological development in the field of wells technology and of salt cavern geotechnical and thermodynamics modelling.

Designs of Salt cavern UGS's have largely benefited from recent challenging projects. In particular, technological progress has been achieved in the last few years in the field of in situ data acquisition and of coupled geo-technical and thermodynamics modelling:

3.1 New modelling approaches in rock mechanics As far as rock mechanics is concerned, standardized tests and interpretations are increasingly being implemented to characterize the elasto-visco-plastic behaviour of the salt material. Comparative approaches and benchmarking allow comparing results from different creep models (especially for the prediction of the long term creep evolution, and the evaluation of long term creep under low deviatoric stress); and wider agreement has been reached between the experts on damage and failure criteria of the salt. This point is becoming increasingly important, as the designers are pushed by the operators to specify an as wide as possible operating pressure range; and the impact of the minimum operating pressure combined with the frequency and the time during which the facility will remain at that pressure is a leading parameter for the determination of short term and long term creep effects, cavern closure and overall stability issues. 3D models (principally elasto-visco-plastic Finite Element or Finite Difference Analysis) have been developed in parallel with simplified but efficient and easy to run 1D axi-symetric dimensioning tools, which allow implementation of rapid but reliable sensitivity studies, prior to running the more elaborate 3D models. In some challenging cases in particular, such as caverns with exceptionally narrow pillars, 3D modelling can provide useful guidelines for detecting weak points and designing a monitoring program aimed both at reducing the uncertainty and at providing in situ information at the critical locations identified based on the model.

3.2 New modelling approaches in thermodynamics

As far as thermodynamics are concerned, the large pressure variations induced in the caverns by the rapid cycling of the working gas also impact the temperature of the gas in the caverns; and thermodynamics studies are now increasingly carried out to characterize the thermal evolution within a cavern during operation. This effort has followed the following main lines:

Ø Characterization of some thermodynamically relevant salt data (heat transfer coefficient, geothermal heat transfer, surface conductivity, shape effect, effect of the brine remaining in the cavern sump etc…)

Ø In situ data acquisition campaigns have been launched by some companies to accurately monitor the gas temperature in caverns and to follow its evolution during injection and production.

Ø Downhole optic fibre sensors have been implemented to that effect, and the results obtained have been interpreted and used to calibrate new simulation models to be used as prediction tools for the operators with a view to optimise performance of the facility. (e.g. hydrate formation, available gas for withdrawal following a given operating scenario etc…).

These measurements present some obvious shortcomings as the in situ temperature measurements in a salt cavern can only be made along the axis of the cavern, and cannot measure the radial temperature evolution and the convection effects (the cavern walls are from that perspective an important transfer interface between the geothermal gradient in the salt around the cavern and the cavern fluids within the cavern).

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However, they allow to indirectly evaluate local temperature variations resulting from changes in the cavern section and in the gas flow velocity. The modelling effort has encompassed both the leaching phase which results in lowering the temperature in the rock salt surrounding the cavern (leaching with cold water, endothermic dissolution process of the salt), thus resulting in lower leaching efficiency of the leaching water and the actual subsequent gas operation of the caverns. Some Computational Fluid Dynamics (CFD) models have been implemented to simulate the gas flow within the cavern and to evaluate in particular the effect of restrictions in the cavern (such as e.g. the cavern neck, or irregularities related to occurrence of insoluble “layers”) on the gas flow and on the thermodynamics evolution within the gas phase. The main applications of the above described R&D effort are:

Ø Evaluate the impact of the cavern temperature on the salt solubility and thus on the leaching efficiency and develop more accurate and reliable leaching simulators

Ø Support optimised strategies for the first gas filling with a view to maximize the working gas placement.

Ø Support computer aided cavern operation and optimisation of cavern performance (high flow-rates, quick change between production and injection mode, reliable, efficient hydrate prevention and real time prediction of working gas volume).

Ø Allow coupled thermo-dynamical and geo-mechanical modelling approaches and more realistic simulation and prediction of the caverns stability during operation.

As a result of the above efforts, some breakthrough has recently been achieved in the field of salt cavern thermodynamics and is now increasingly implemented in the UGS industry along two main directions:

Prediction of thermally induced tensile strains at the caverns wall during production at a high flow rate. Namely, the cooling of the gas resulting from pressure decrease and expansion is transferred to the salt and generates tensile stress which may in certain circumstances (e.g. a large temperature drop and/or shallow caverns) exceed the compressive stress prevailing by design at the cavern wall thus potentially generating salt failure and instability. Laboratory tests have been implemented to evaluate the magnitude of such effects and to assess whether they are likely to evolve within the pillar and to give raise to a progressive failure mechanism or conversely will reach equilibrium at a reasonable distance from the cavern wall. Furthermore the more representative geo-mechanical modelling of the caverns achieved allows a more aggressive approach of the cavern operating parameters such as maximum and minimum pressure and cushion gas.

Construction of expert simulation models (both proprietary models and models promoted by associations such as SMRI, AGA are being developed) to provide real time support to the operators and allow them to optimize the management of their caverns. Temperature namely impacts the inventory of the stored gas, the volume of the cushion remaining in the cavern, hydrate formation, etc… The recent predictive thermo-dynamical models developed are intended to be connected to SCADA and to provide real time support to decision making.

These models are able to introduce the leaching phase, the gas first filling and actual gas operation in the history matching process. The above technical evolutions have provided the cavern designers with new tools and approaches allowing them to more accurately design flexible caverns; and the operators can call on user friendly simulators allowing day to day optimum management of the main storage performance factors such as remaining producible gas at a given flow-rate or for a given production profile, evaluation of the impact on cavern closure of decreasing the pressure close to the minimum operating pressure etc…

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4. CO2 SEQUESTRATION: UGS OPERATORS COULD IMPLEMENT THE TECHNOLOGY BUT THE FRAMEWORK IS NOT READY YET

4.1 Introduction CO2 sequestration will be the more important new technology in the future according to the outcome of a survey on new technologies in UGS operator’s opinion. Their answers could be explained in two ways. First, they think that their industry, like other industries, has to deal with the rules on CO2 emissions. Secondly, they think that CO2 sequestration could be a new business opportunity for them. This is most probably the reason why they are so interested in this technology.

4.2 The CCS chain The Carbon Capture and Storage (CCS) is a chain of technologies, mainly applicable to large industrial emitters, under development. Different processes for capture are under development for example post-combustion capture, oxy-combustion and pre-combustion capture with H2 burning. Only the pre-combustion capture is applicable to existing or short term thermal power plants. The costs related to CO2 capture are dominant in the total CCS chain costs, it represent 75% to 80% of the total cost. Decreasing this cost is a key driver for CCS development however this is not the topic of this report. The second item is CO2 transportation, this technology is available. A (limited) CO2 network does exist in the USA. For long distance transmission CO2 could be brought in supercritical or liquid phase. The last topic is CO2 sequestration, or CO2 injection in the subsurface. We will go into more details about this step of the process, because it is precisely in this field that UGS technology could help.

4.3 CO2 sequestration. An available technology to optimize CO2 injection in oil reservoirs is not new: it was developed in the 1950’s for enhanced oil recovery (EOR) purposes. The technology has been improved by steps corresponding to oil prices increases. Several pioneering industrial demonstration projects have allowed validating the concept of CO2 sequestration for environmental purposes: Ø Sleipner (off-shore Norway) since 1996 (Statoil. 1 Mt CO2/year) Ø Weyburn (on-shore Canada) since 2000 (Encana, Petroleum Research Center, Natural Resources

Canada, University Of Alberta 1,8 Mt CO2/ year) Ø In Salah (on-shore Algeria) since 2004 (BP, 1Mt CO2 /year) Ø K12b (off-shore, the Netherlands) 2004-2006 (Proned-GDF Suez……) Ø Lacq /Rousse (on-shore France) (Total , under development)

Some significant projects (Sleipner, In Salah, K12b) , in terms of quantities, re-inject the CO2 produced from gas fields (of natural gas containing a high content of CO2) and not CO2 as product of combustion. Several research projects are currently running in all parts of the world on the subject to :

Ø find suitable sites Ø better understand physical phenomena Ø be able to monitor the injection sites Ø and develop methodologies to asses risks and obtain public acceptance

The three main types of reservoirs available to store CO2 are: Ø depleted oil and gas fields Ø coal beds Ø deep saline aquifers.

Even with a large uncertainty on the estimation, the following figures could be proposed for the final storage capacities of CO2 sequestration sites:

Ø average field or UGS: around 100 Mt CO2 Ø big field : around 500 Mt CO2

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Ø Saline aquifer: around 1000 to 10 000 Mt CO2

Only very big oil and gas fields have a real interest for long-term industrial projects. The injection in coal beds is not available at the moment. Only the saline aquifers could meet the needs to capture a significant part of the CO2 emitted in the world, even if one considered only the CO2 emitted by big plants (power station, etc..)

4.4 UGS operators have the capability to sequestrate CO2 To insure long term confinement, optimise injection and monitor the storage environment the following steps have to be gone through:

Ø multi-disciplinarily understanding of the phenomena (geochemistry, geo-mechanics, thermodynamics)

Ø identification, qualification and characterization of adequate sites (by geophysics, geology, reservoir engineering and public acceptance)

Ø predictive simulations Ø monitoring techniques Ø possibly remediation techniques.

These steps are quite similar to the steps needed to develop UGS facilities. The sciences and technologies that UGS operators use for natural gas storage, specially for aquifers storage, are a solid basis for CO2 sequestration projects. Nevertheless, CO2 projects have some specific challenges, with regards to natural gas storage facilities.

Ø The thermodynamics of the fluid stored. According to the depth, CO2 could be in gas phase or super-critical phase. Its flowing characteristics are specific. Its capability to dissolve in water is high, but gas dissolves in water too in a limited way.

Ø The chemical behaviour of CO2 is not neutral. The cement, the casing of injection wells are weak

points of the confinement of the CO2 storage. They have to be adapted or the monitoring of their integrity has to be adapted.

Ø The extension of the zone of storage. Demonstration projects have an extension similar to

average oil fields, average gas fields or UGS field, but industrial projects are able to store the CO2 emitted by power-plants for decades. It will be more extensive and probably not structurally trapped. The monitoring techniques have to be adapted in an extensive way (repeated – 2D seismic for instance)

Ø No withdrawal is needed for CO2 sequestration. For an UGS facility, withdrawal performance is a

key point. On the contrary, for CO2 sequestration, all the efforts will be dedicated to performances and reliability of injection. If injection stops, the emission plan and its production (power, concrete, steel) would probably stop very rapidly, if CO2 atmospheric emission is not allowed.

4.5. Long term projects Another common point with UGS activity will be the time necessary to develop CCS projects. These projects will be mid-term to develop and long term to operate. A typical time-table for such a project could be the following:

Orientation and pre-selection = 4 years

Ø geology, geo-dynamics, geochemistry, geo-mechanics, Ø preliminary risk assessment, Ø validation programs (complementary site investigation works)

Feasibility and basic studies : 7 years

Ø 3 D simulation, seismic campaign, exploration wells

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Ø Local risk assessment Ø Basic engineering Ø Monitoring plan Ø Pre-permitting activities

Construction : 4 years

Ø “Administrative” engineering and permitting Ø Detail design. Selection of contractors Ø Construction Ø Setting of monitoring array

Operation: several decades.

Post –operation (monitoring, abandonment) : several years.

4.6 Projects that need a consistent framework to be decided

CO2 sequestration could become a new business. We saw that the previous steps of the CCS chain are crucial, in particular the combustion capture for which technology challenges have to be overcome as far as the CO2 re-injection itself is concerned, the key drivers are:

Ø the economic model. According to the price of non-emitted CO2 and the costs of the CCS chain

(capture cost mainly), the remaining price for CO2 re-injection will develop or not. Ø the legal framework.

Ø A clear responsibility between CO2 emitters, transmission operators, storage operators and public authorities is crucial to have decisions made on CCS projects. The mechanisms to insure revenues to all these operators through the price of non-emitted or injected CO2 has to be clarified on a long term basis.

Ø The responsibility for the post-operation phase, i.e. the storage operator could not be hold responsible for the stored CO2 for the next 500 years, which is the minimum time expected for the CO2 to stay in the sub-surface. The public authorities have to take the responsibility for the long-term, after a convincing phase of monitoring and abandonment.

Ø Public acceptance could be a major uncertainty. Citizens have to be confident in the

confinement and the monitoring of the CO2 and have to share the political decisions on the sub-surface uses.

Ø Political decisions about the competition for the sub-surface are crucial. Are the saline aquifers really available for CO2 sequestration? Or do they have to be preserved for water resources or geothermal production? Or even for new aquifers UGS facilities? If they are available, are drastic requirements on the purity of CO2 to be imposed, leading to higher cost for capture?

4.7 Conclusions:

The next five years will be decisive for CO2 sequestration. The upstream of the chain has technology challenges (to reduce the cost of capture) and industrial challenges (to build new plants “ready to capture and store”) to win. The legal framework for transmission and storage has to be built. Its basis has to be a clear public and political acceptance. That means an active synergy and dialogue between: R&D institutes, emitters, storage operators, authorities and citizens. UGS operators can provide their technologies and know-how in the Carbon–Capture-and Storage Chain.

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ANNEX 1 Answers to the questionnaire. The answers (from 1 to 5 according to growing interest) have been summed up to have a global score.

1. General Aspects

1.1. Which techniques do you use to analyze the performance of your storage?

Technique

3-5 years ago

At present In 3-5 years

Cost target setting and monitoring 36 42 48,5 Benchmarking 14 20 32,5 3rd party evaluation 13 17 19 Management judgement 30 39 39 Key performance indicator setting 35 49 45 Data mining 18 28 29 Clients satisfaction surveys 20 27 33

1.2. What new techniques do you think your company will be interested in to use for the future :

Driver

3-5 years ago

In 10 years

In 15 years

Lined Hard Rock Caverns 1 3 3 Abandoned Mines 6 7 6 Storage as Gas Hydrates 3 3 4 Gas sorption onto solids 0 3 3 CO2 sequestration 3 17 12

Compressed air storage 0 3 0 Others (please describe) 0 0 0

1.3. What methods do you apply to preserve, improve and share the storage skills of your experts?

Methods

3-5 years ago


Organisation 21 26 29 GroupWare informatical system 10 13 16 Networking with experts 20 26 27 Technical development monitoring 22 30 35 Document management system (digitalisation,…)

13 22 26

Knowledge Management 7 12 15

24

Succession planning system (experts retiring)

11 18 21

Others (please describe) 0 3 3

1.4. What technological improvements do you think are important?

Research Topics


In 10 years

General Aspects Handling water production 25 26 26 Data mining (designing vs. operation monitoring and performance enhancement…)

23 25 24

Avoid hydrates formation 25 25 25 Storage as gas hydrates 7 8 10 Enhancement of storage monitoring and surveillance

28 29 29

Abandonment methods for storage facilities

9 11 19

Reservoir 0 0 0

Improved reservoir description 36 31 32 Reservoir management 34 33 33

Gas substitution (for cushion gas) 18 22 24

Impact on aquifers water quality 24 20 20 Creeping of salt cavern 19 23 20 Improve salt cavern thermal modelling

21 24 21

Specific geomechanical studies on cap rock

30 29 26

Well 0 0 0

Sand control (measurement, modelling, remediation…)

23 24 22

Well architecture 24 25 24 Study cement bond and integrity during life time of wells.

24 28 26

Improve pipe and well casing integrity monitoring

32 36 34

Surface Facilities 0 0 0 Gas quality measurement 35 35 33 Gas metering 35 38 34 Development of existing storage facilities capacities

29 35 30

Performance description and forecasting of surface treatment and gathering equipments

28 31 30

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1.5. Is your company involved in quality certification (for environment, safety or general quality enhancement)?

Yes (since?) No

ISO 14001 7 3 IS0 9001 9 5 OHAS 18001 3 5 Others (please describe) 2 2

1.6. To obtain these certifications, has your company implemented new technologies? Which ones? Please, specify.

These certifications are not important for our work

1.7. When using service companies, what are the requirements on these companies?

1.8. As a synthesis, what is the main new technology your company uses or spend effort on during the last 3 years?

1.9. Please, quote three areas of new technology in which you would welcome a technological breakthrough for the coming 5/10 years.

1.10. Who plays an important role or which organizations are in charge of technology improvements in/for your company?

3 or 5 years

ago At present

In 3 or 5 years

The storage operator itself (as a business unit)

14 15 16

A technical centre or a research centre belonging to your company

5 5 5

An external research centre working on JIP´s (Joint Industry Project)

5 6 6

Universities 4 8 5 Contractors and Commercial companies providing services for oil and gas industries.

13 17 14

Government bodies 2 5 1 Others (please describe) 0 0 0

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2. Geology, Geophysics and Reservoir

2.1. What technologies do you apply for a better geological-structural definition of the trap?

Please describe the type of improvement briefly (e.g. improved fault location uncertainty) and state the improvements preferably in absolute terms (e.g. before: +/-250 m, after: +/- 50 m).

Technique Tick the

technique used the last

5 years

Tick the technique which will be used in 3-5 years

2D-seismic 10 5 3D-seismic 14 13 4D-seismic (time lapse seismic) 0 5 Seismic attribute mapping 6 6 VSP, Cross Hole technology 4 7 Geostatistics 2 4 Reprocessing seismic 7 7 Re-interpretation 7 7 Other (please describe) 1 2

2.2. How do you determine limits for the maximum working reservoir pressure of your storage? Please, give a brief description separately for porous storage and for salt caverns

2.3. Maximum Pressure for storage

2.3.1. Have you increased or are you considering to increase the maximum allowable pressure for your storage?

Driver

3-5 years ago


UGS in aquifer 0 0 0 In Oil&Gas field 3 4 3 In salt caverns 5 3 3 In rock caverns 0 0 0

2.3.2. Please, quote the value of maximum pressure above initial reservoir pressure.

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2.4. Which type of reservoir modelling tools do you use? No model 0 0 Analytical (material balance) reservoir model

6 6

Numerical reservoir simulation 8 8 Advanced reservoir modelling 8 10 compositional, 0 0 geo-chemicals, 0 0 geomechanics, 0 0 integrated geological modelling 1 1 automatic history match, 0 0 uncertainty determination, 0 0 others… 0 0 Integrated surface and subsurface simulation/model for real time performance

4 7

Gas /gas mixing simulation for porous reservoirs

2 4

Finite element method to determine cavern stability

5 5

3D geomechanical calculations for describing uncommon cavern shapes

3 3

Thermodynamic modelling for prediction of gas pressure and temperature in caverns

3 6

Rock mechanics modelling predict cavern convergence

6 6

Modelling of leaching for salt cavern

6 6

Other (please describe) 0 0

2.5. What monitoring techniques do you use to improve subsurface operations?

Technique

3-5 years ago


Gas quality monitoring 40 42 43 Souring/bacteria monitoring 10 11 13 Ground level monitoring 18 18 18 Electromagnetic monitoring 6 6 6 Micro seismic monitoring 7 6 10 Micro biological leakage survey 3 3 4 Ultrasonic volume determinations for caverns

16 19 19

Automated well pressure/temperature monitoring

30 40 45

Well testing 33 41 37

28

Down hole video surveillance 19 20 23 Smart wells (permanent down hole gauges, use of optic fibre…)

14 17 24

Real time well performance monitoring (flow, pressure)

35 42 40

Real time sand production monitoring

17 19 20

Cased hole logging (e.g. GWC monitoring,…)

18 22 24

Water content monitoring 34 38 38 Automated gas quality monitoring 27 30 35 Others (please describe) 5 5 5

2.6. Which technical methods do you implement to improve the performance of your storage (except well techniques which are proposed in part 3 here after)?

Measures 3-5 years

ago at present in 3-5 years

For all types of UGS's Reduction of pressure losses due to flow

31 30 37

Pmax-increase (capillary threshold pressure concept,..)

19 25 20

Re-completions of wells (see 3.1) 15 17 22 Increase UGS capacity (inventory, operational wells, compression, dehydration & desulphurization capacity and efficiency…)

30 37 38

Optimize storage lay out by redesigning

17 21 21

Fast change of operational mode (injection/withdrawal)

20 29 38


0 0 0 For porous storages 0 0 0 Minimize cost of cushion gas (by using alternative cushion gases)

3 8 16

Avoiding gas spilling/losses in reservoir

22 24 25

Techniques of sand control to prevent the reservoir destruction

19 24 27

Solutions used to reduce water influx

18 24 30

Solutions to eliminate salt precipitations

9 9 11

Optimization of gas volume area and increasing effective gas thickness

17 20 22

Infill drilling 11 19 27

29


0 0 0 For caverns 0 0 0 Enlarge existing caverns by a second phase of leaching

1 5 4

Development of new technologies of leaching

2 5 3

Enlarging existing caverns 1 4 4 Leaching of lens shaped caverns in thinner salt layers

0 2 2

Networking of caverns 5 7 6 Sump sealing 1 2 0 High temperature leaching 0 2 0 Use additives in leaching process 1 3 1 Use blanket gas for leaching 7 10 9 Cascading unsaturated brine from one cavern to another

5 10 10


3. Well

3.1. Which kinds of well concepts are (will be) used in your company?

(Please describe the advantage in comparison to a conventional vertical well.)

Tick the relevant box

Well concepts at present in 3-5

years

Comments

Vertical wells 13 12 Horizontal wells 6 7 Extended reach wells 4 4 Directional drilling 9 10 Recompletion (larger size tubulars) 5 7 Larger well bores 3 3 Multilateral wells 1 4 Open hole completions 5 5 Coiled tubing drilling 2 4 Snubbing drilling 1 2 Underbalanced drilling 4 5 Sidetracks 3 6 Replacement of old wells by optimized new ones

2 3

Others (please describe) 0 0

3.2. Did you experience any problems in implementing new well concepts?

30

(Please describe your problems/experience separately for each applied new well concept) point Number of well

concept (See Q3.1)

Problem At present in 3-5

years

(last 3-5 years)

Cement quality 6 4 Formation damage 6 5 Hole stability 5 4 Safety related 5 5 Cost/Schedule overrun 3 2 Underperformance of well 2 2 Operability/Maintainability of well 2 2 Skills availability in services companies and in your own company

4 4


3.3. What techniques do you apply to well completion concepts?

(Please describe the advantage in comparison to a conventional completion.)

Tick the relevant box Comments (experience, advantages)

Concepts At present in 3-5

years

Coated tubing 0 0 Gravel packs technology 3 3 Sand screen technology 1 2 Monobore completion 5 5 Permanent downhole monitoring 1 6 Expandable tubulars 0 1 Welded completion 3 5 Other (please describe) 0 0

3.4. Which stimulation technology do you use for maintaining and improving deliverability?

Concepts Tick the relevant box Problems, experience, advantages

31

At present in 3-5 years

Conventional completion - acidizing 7 7 - fracturing 2 2 - fracpacks 0 0 - acid fracturing 0 0 - others (for example eliminations of the scale)

2 2

Coiled tubing applications 0 0 - acidizing 4 4 - fracturing 0 0 - fracpacks 0 0 - others (for example eliminations of the scale)

1 1


3.5. Which new methods are you using to ensure the integrity of subsurface equipment?

Tick the relevant box

Comments Technology

At present in 3-5 years

Regular inspection programme 7 8 Corrosion monitoring 7 8 Cathodic protection 8 8 Annulus pressure monitoring 11 11 Annulus fluid level control 5 5 Newly drilled well : 0 0 - Resistivity measurement 7 7 - Nuclear measurement 6 7 - CBL / VDL 10 9 - Pressure test 7 7 Cased hole logging : 0 0 Temperature 7 8 Spinner 5 6 Noise 6 6 CBL/VDL 5 5 Bore hole televiewer 5 7 Corrosion (US/EM) 6 6 Others (please describe) 1 1

3.6. How do you manage the maintenance (and revamping) program of your wells (Yes/No)?

32

3-5 years ago

At present

In 3-5 years

Case by case when a failure appears

10 8 6

Long term maintenance planned programme driven by budget

3 5 4

Long term maintenance planned programme driven by a “Risk Assessment Value”

3 3 7

4. Surface Facilities

4.1. What techniques do you use to avoid hydrate formation? Tick the relevant box Comments (experience, advantage)

Techniques At present in 3-5

years

Methanol inhibition 10 9 Glycol inhibition 6 5 Heat tracing 6 5 Gas heating 11 9 Others (please describe) 0 0

4.2. What techniques do you use on corrosion management? Tick the relevant box Comments

Techniques At present in 3-5

years

Stainless steel 1 1 Material choice 4 4 Chemical inhibitors 5 4 Wall thickness monitoring on surface facilities (indicate frequency)

10 9

Corrosion measurements by intelligent pigs in the gathering system

3 5

Cathodic protection 14 13 Coating 4 4 CO2/H2S/.. removal 4 4

None 0 0 Others (please describe) 2 1

33

4.3. What technology do you apply to gas treatment and gas quality management? Tick the relevant box Comments

Technology At present in 3-5

years

New concept of TEG dehydration designs (please, describe)

4 5

Utilization of no glycol dehydration (membranes, adsorption,…)

2 2

Desulfurization new process 0 0 Computer assisted optimization 1 2 Mechanical separation 3 3 Automation 5 6 Availability 3 3 Facility testing 2 2 Design changes 3 3 Dehydration with oxidizer 1 1 Others (please describe) 1 1

4.4. What is your main motivation for the application of technologies noticed in 4.3: reduction of atmospheric emission? Energy saving? Efficiency improvement? other (please, describe)? Environment affairs, costs, high availability

4.5. How do you use the compression on your storages (injection or withdrawal)?

Electrically powered compressors (Turbo- and Piston compressors), they can also be used for withdrawal

4.6. What improvements did you carry out on compression performance?

Tick the relevant box Comments

Measures At present in 3-5

years

Optimization of operation conditions (capacity, fuel, operating points)

6 6

Turbines 4 4 Use for power generation 4 4 Withdrawal expansion 5 5

34

New technology for compressor & engines

3 4

Heat recovery system. How do you use the recovered heat?

1 1

Adoption of Low NOx system 3 3 Use of electro-compressor 4 6 Others (please describe) 1 1

5. Safety

5.1. What methodologies do you use to improve safety?

Tick the relevant box Comments

Goals At present in 3-5

years

Safety studies and audits 13 13 Preventive (or regular) servicing of technical installations

10 12

Predictive maintenance 7 10 Automatic Shutdown (please, describe criteria of shutdown: pressure gradient, high pressure, low pressure, noise detection, gas detection, fire detection, …)

10 10 Fire and gas alarm,

0 0 Manual set of

0 0 At well head: 8 9

- subsurface safety valve 4 3 - two surface safety valves 2 3 - two wing valves 1 1

Safety analysis of critical operations

6 8

Enhanced monitoring 6 6 Periodical gas inventory and control of caprock tightness

5 5

Analysis and feedback of near/miss accidents

11 11

Detailed analysis and feedback of accidents

11 11

Best practices of engineering/operating/ maintenance

10 10

Participation to industry group about accident analysis

5 5

Personnel training 13 13 Incentive prime for goals/accident prevention

2 1


35

6. Environment Technologies and methods to reduce the impact of hazardous factors on the environment

6.1. Regulations and standards (authority regulation or home regulations) for sewage water, brine, waste of production and consumption. Please specify.

6.1.1. Standards of natural gas leakages from equipment Please specify.

Equipment m3/sec (

m3/h, m3/d )

valves (seals, stems, flanges, etc.) gem.

international Standards

other equipments

6.1.2. What measures and means does your Company use to decrease gas losses for own needs and gas losses in a gas field and compressor stations?

Measures and means Please specify

a) process needs b) gas losses

6.1.3. Methods and means of quantitative control of CO, CO2, NOx and SO2 emissions in combustion materials Please specify.

Matter Name of

control method, its action

Means of control

CO CO2 NOx SO2

6.2. New technologies

Please tick the relevant box the degree of importance (5 : most important, 0 : not important) New Technologies Effect

36

3-5 years ago

At present

In the near future

Technologies and methods of natural gas burning

18 26 29

Effluent and emission measuring procedures

29 35 37

Methods and means of pollutants neutralization (chemical, biological, thermal, etc.)

5 6 8

Reduction of greenhouse gas effects

22 34 46

Reduction of flared gas 29 42 45 Reduction of vented gas 39 43 49 Reduction of effluents 28 30 31 Water disposal 34 37 38 Close cycled systems 11 12 24 Monitoring of the aquifer water quality

16 18 24

Utilization of waste water for leaching

4 5 5

Minimization of brine disposal impact (leaching)

23 24 26

Noise reduction 33 35 38 Other (please describe) 0 0 0

6.3. Atmospheric air pollution, methods and means of control (Please specify) : Monitoring pollutants in the atmospheric air

Yes (by which methods?)

No

Industrial zones (working area) 5 5 Outside the industrial zone (settlements)

1 9

What technical means of control do you use?

Yes (please specify)

No

Stationary 4 5 Mobile 4 5 Remote 1 7 Do you use systems for continuous monitoring CO, CO2, NOx, SO2, etc.?

Yes (please specify)

No

37

INTELLIGENT UNDERGROUND GAS STORAGE

Study Group Leader

Georg Zangl (Austria)

Study Group 2.3 Members:

FIRST NAME SURNAME COMPANY COUNTRY Dmitry Pavlenkov OAO Gazprom Russia Radim Blažej MND Czech Republic Gunar Lenk UGS Germany Pierre Marion Storengy France

Ho-Yueck Kim SKEC South Korea Manuchehr Taheri NIGC Iran Sadrollah Ayoubi NIGC Iran Vladimír Onderka RWE Gas Storage Czech Republic

1 Business & Market Trend

a. Market Any investment has to be justified by a business need. This rule is not tied to a special industry it is generally applicable. In order to be able to establish reliable trends for the future, it is therefore necessary to understand the business trends as well. International gas trade is increasing due to rising global gas demand, declining gas reserves in Europe, the USA, and parts of Asia, lower gas transportation costs particularly for liquefied natural gas, requirements to diversify supply and higher gas prices. Furthermore, restrictions on CO2 emissions, the nuclear phase-out announced by some states, high emissions from coal-based generation, and barriers to rapid development of renewable generation, are factors that result in a high level of dependency on natural gas, not only in Europe. Europe as an Example To better understand the circumstances, the report takes a closer look at the situation in Europe. Natural gas accounts for 25% of primary energy use in the European Union. Nearly 60% of consumed natural gas in the EU is imported, with Norway, Algeria, and Russia constituting the bulk of natural gas exporters to the EU. The EU is far from having an integrated, liquid, open, and transparent gas market. The four largest companies in the EU account for almost 50 percent of the total production in the EU. Both in the external supply situation as well as the internal supply, a minority of companies control a large part of the market. Total traded volume in the EU is more than one third higher than total consumption, while exchange based trading for both spot and future products represents less than 10% of total traded gas volumes in the EU, OTC (over the counter) and bilateral trading making up the rest of total traded gas volumes. Trade volumes have increased in average by 45% from 2006 to 2007, with the smallest increase in the Netherlands (23%) and the highest increase in UK (61%)1. The gas exchange market in the EU is significantly less mature than power exchanges. Moreover, gas volumes on exchanges are insignificant compared to virtual and physical hubs, which are the focal point for trading.

1 Heren data 2006, 2007

38

Gas supplies to Europe remain dominated by long-term contracts (15 to 25 years) between incumbents, which are the main importers, and producing companies from exporting countries external to the European Union (Gazprom in Russia, Sonatrach in Algeria and Statoil in Norway) and countries from the EU, e.g. Gas Terra in the Netherlands2. One significant business trend is, that more and more energy providers are competing in the UGS market, which was in former times a pure E&P business. Together with liberation rules within EU, this results in a decoupling of the gas market into a season driven gas supply and a slowly but steady growing interest in trading gas as a broker business. Consequently, the traditional operating behavior will need to incorporate trading business processes to the existing swing supply activities. Even if the diversification of companies in the UGS business is growing, there is one main conclusion that can be drawn independently. As the gas market is growing, there is also an increasing demand of storage capacity, which will most likely continue over the next two decades. Another basic trend, which seems to develop without a dependency on the changing market situation, is the decrease of the reaction time respectively the time to provide a certain volume of gas to the market. Decisions will be made faster and that fact might have a strong influence on the fitness and strength of a company.

2 Executive Summary Based on the preliminary results of the questionnaires of the SG2.3, some interesting conclusions can be drawn. The development of new technologies in the data acquisition and instrumentation part of UGS operations is almost completed but some new technologies could emerge soon, especially in the field of transmitters, such as wireless connection (Wi-Fi transmitters). However, the topic is well understood and most UGS companies have a standard data acquisition system in place, which provides all necessary data for operations and monitoring. So far a few standard reservoir, well and surface facility modelling techniques have been established, most of them rely on proven and quite old physical and mathematical principles, but they are state of the art and fulfill all the requirements to mimic the real behavior sufficiently accurately. It has to be emphasized that the accuracy of these models is improved when field data are given by well-calibrated transmitters to adjust the models. However, many companies are not able to connect their different mathematical models (e.g. reservoir and well models with surface facilities models) mainly because of technical limitations. This leads to the conclusion that a tighter integration of different model types and brands will be seen coming in the next years. This is necessary to better understand bottlenecks and to optimize UGS production. The automation of updating the models with most recent data from production and injection is also a field, where great potential for improvement can be seen. If companies want to react faster to market needs, it will be necessary to get a faster assessment of the current condition of the UGS and to forecast production/injection scenarios for decision support. A huge amount of data is collected for each UGS every day. Manually manipulating those data and extracting valuable information is almost impossible. Automated processes for quality control, data aggregation, and data formatting are prerequisites for extracting information and guiding decisions from those measurements. Currently, very few companies have a system in place that allows engineers to use the real-time measurements beyond monitoring. The major change, which is required here, is the installation of high level decision support (expert) systems. They are connected to the existing monitoring framework to allow a better and proactive UGS management instead of only a proactive day-to-day operation. Further, almost all companies lack a knowledge capture system. The landscape of skilled reservoir engineers is changing already based on the unfavorable demographic distribution. Most skilled reservoir engineers are older than the demographic average. Their retirement will cause a destruction of UGS operations and management knowledge. Companies are increasingly become aware of this situation. They

2 Review and analysis of EU wholesale energy markets, ECORYS Nederland BV, Rotterdam, Dec. 2008

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are starting to install knowledge capture systems. Systems especially designed for such a purpose in the UGS domain do not exist and therefore some development is expected to be seen here.

3 New Technology Adoption Process

The goal of this study is to give an outlook on future technologies and their development. To be able to analyze the questionnaires and to understand the dynamics of technology renewals, it is necessary to understand how and at what speed new technology is adopted in this industry.

Company behavior toward adopting new technology can be described as shown in Fig. 1. The first groups to adopt new products are described as innovators. They account for a small portion of the whole population. They adopt new technology for the sake of wanting to test new technology.

After the new technology has been proven to work as advertised, the next groups to adopt the technology are visionaries. Visionaries, like innovators, buy into new product concepts very early in their life cycle, but unlike innovators, they are not technologists. They are people who find it easy to imagine, understand and appreciate the benefits of a new technology, and to relate these potential benefits to their other concerns. Whenever they find a strong match, early adopters are willing to go with this technology.

The next groups to adapt a new technology are the pragmatists. Pragmatists share some of the visionaries’ ability to relate to technology, but ultimately they are driven by a strong sense of practicality. They know that many new technologies may not prove viable or practicable, so they are content to wait and see whether other companies successfully integrate the new technology before they apply it themselves. They want to see well established references before investing substantially. This group is the largest—roughly one-third of the whole adoption life cycle.

The next groups are the conservatives. Conservatives wait until the technology has become an established standard or has gained widespread industry approval and support. Even then, conservatives require a lot of proof. Like the pragmatists, this group comprises one-third of the total population in any given segment.

The last groups to adopt new technology are the laggards. While small in size, the laggards are almost the same size as the innovators and visionaries percentage-wise. Laggards purchase new technology generally to protect investments and to replace worn-out products.

Figure 1: New technology adoption life cycle

What They Want What They Adopt

Innovators Revolution, Recognition, Research Trials

Visionaries State of the art Customized Solution

Pragmatists Evolution, Solve Problems Total solutions

Segment Not to be left behind Industry standards

Laggards Status quo Enhancement or extension of existing systems

Table 1: New technology adoption

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Technology Adoption

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Figure 2: New technology adoption in UGS

This question has been asked in a separate document and quite late in the triennium, therefore only a few companies have replied and sent their answer. Nevertheless it fits very well in a general trend. The question, whether a company culture allows early adoption of new technologies has been split into several areas, which are of special interest for this study group, namely into monitoring equipment, monitoring software, surveillance software and modelling software.

The numbers of replies are not enough to make a sound interpretation of each individual section, but taken together the trend is quite obvious. Most companies see themselves in one or the other segment as visionaries, sometimes as pragmatists, but rarely as conservatives or laggards. Drawing an envelope over all answers (see Fig. 2) reveals a shift in the technology adoption process from pragmatists and conservatives (red line = general business trend) towards visionaries. This shift (see arrow) allows the UGS companies to stay ahead of other industries. One example is the high level of instrumentation compared to the oil&gas E&P business.

Monitoring Surveillance Segment Equipment

Monitoring Software Software

Modelling Software

Innovators 0% 17% 17% 0% Visionaries 33% 50% 67% 50% Pragmatists 67% 33% 0% 33% Conservatives 0% 0% 17% 17% Laggards 0% 0% 0% 0%

Table 2: technology adoption questionnaire results

4 Identifying Business & Operations Processes

a. Knowledge Management (KM)

This industry deals with a huge amount of data and information. Data and information is not knowledge until the data is turned into information. Knowledge Management systems attempt to store the way in which this information is used.

Over the last few years, the topic of knowledge management has rapidly grown in importance among business managers and information systems practitioners. Business organizations worldwide increasingly recognize the effective use of knowledge as a key-differentiating factor and as the most important resource

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for potential economic success3. As a result, many IT companies are implementing new applications and techniques to better manage knowledge. Two types of knowledge, explicit knowledge and tacit knowledge can be captured by an organization for its intellectual capital. Explicit knowledge can be expressed in formal and systematic language, and therefore can be packaged and codified in the form of manuals, articles, patents, pictures, videos, audios, and software. However, tacit knowledge is typically embedded in individuals and generally transmitted through face-to-face exchanges, such as learning by accompanying, watching, and helping4 . As the UGS business decisions are very much focused on measured data, the possibility to setup an appropriate knowledge capturing system should be taken into consideration of every company.

Knowledge Management (KM) refers to a multi-disciplined approach to achieving organizational objectives by making the best use of knowledge. KM focuses on processes such as acquiring, creating, and sharing knowledge and the cultural and technical foundations that support them.

Knowledge Management may be viewed in terms of:

o People – How do you increase the ability of an individual in the organization to influence others with their knowledge

o Processes – Its approach varies from organization to organization. There is no limit on the number of processes

o Technology – It needs to be chosen only after all the requirements of a knowledge management initiative have been established.

Knowledge Management Drivers

The main drivers behind knowledge management efforts are:

o Knowledge Attrition: a high employee turnover rate creates high costs, which can be effectively minimized using knowledge management techniques.

o Knowledge Merging: corporate mergers coupled with the increased need to integrate global corporate communications require the merging of disparate and often conflicting knowledge models.

o Content Management: The explosion of digitally stored business-critical data is widely documented. Online storage for global companies will continue to grow exponentially. As the volume of digital information expands, the need for its logical organization is critical for purposes of information retrieval, sharing, and reuse.

o E-Learning: As the economy becomes more global and the use of PCs more pervasive, there has been a dramatic increase in e-learning, also known as computer based training. E-learning is closely linked to and overlapping with, but not equal to knowledge management. E-learning can be an effective medium for knowledge management deliverables.

b. Questionnaire Question 1 - Information Question 1.1.: How long does it take to deliver data/ information/ knowledge from measurement to the decision-maker?

As already mentioned in the summary, the level of data acquisition equipment is quite high. Hence, all UGS companies are able to access their data in a relatively short time, usually within one day. In most cases, operational decisions can be made within minutes or hours, management decisions within days.

Question 1.2.: Are you using a knowledge capture/management system?

Although all companies have installed a data capturing and storing system, less than 30% of the companies have installed a knowledge management system. This is an indication, that processes and decision-making are focused on the fast low-level operational decision cycles rather than the higher-level decisions. Not much attention is given to risks of knowledge loss arising from attrition or illness. Nevertheless the number of 3 Stewart, T.A, Intellectual Capital: The New Wealth of Organizations. Bantam Books, New York NY, 1998 4 Nonaka, I., and Takeuchi, H., The Knowledge-Creating Company. Oxford University Press, New York NY, 1995

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knowledge system users will raise to more than 70% in the next 3 to 5 years, based on the results of the questionnaire.

Question 1.3.: Do you have a data security system in place or planned, which allows restricted access to data depending on the job description of the user?

More than 90% of all companies have a security system in place.

5 UGS Operations: The Level of Automation

The UGS management cycle is a multidisciplinary practice, which involves in most cases detailed numerical modelling of each system component and analysis of the economic impact of significant changes in the operation strategy. During this cycle, various operational options and strategies are evaluated to determine optimal system design and operation.

Fig. 3 presents the three cycles from a time versus (relative) benefits in monetary term. Realizing these benefits requires the application of carefully selected workflows for each cycle. For instance, typical workflows for the fast cycle (focused on the operations) include well and equipment surveillance. For the medium cycle, production loss analysis and management, and well optimization workflows are essential. Finally, in the case of the long cycle, reservoir or even company wide planning & optimization workflows must be used to manage scarce resources and simulate strategic “what if” scenarios for the company, driven by business opportunities and economics.

Traditionally, workflows are run in isolation in the three cycles. Whilst bringing measurable benefits, it is clear, that running those workflows in silos will always lead to a suboptimum solution only.

The three cycles defined above must be performed faster and with less uncertainty to address the current challenges and help maximize the value of existing assets through production optimization and improved recovery. Recently the concept of automating workflows has been introduced in order to accomplish such goals.

Fig. 3 presents a hypothetical view of where reservoir management cycles must go when improved by this automation concept. For instance, the operational loop (fast loop) exceptions must be caught within minutes rather than hours to ensure minimal disruption to the operations and losses to production.

The evolution in Fig. 3 requires three key components: workflow automation, and breaking (or bridging) the barriers between the cycles through Workflow integration.

Figure 3: Improved UGS Management Cycles - Benefits vs. Time

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a. Reservoir Modelling

Questionnaire Question 2 - Reservoir – UGS Subsurface 2.1 How do you calculate working gas volume?

Storage deliverability is a function of the remaining working gas levels. As the working gas volumes decline (through production), the maximum possible deliverability also declines. In the extreme, low working gas levels may result in peak deliverability below late season demand requirements, resulting in curtailments. Even though sufficient working gas inventories exist, the reservoirs may not be able to deliver at the required rates. Therefore, the calculation and forecast of working gas volume and its deliverability are extremely important.

K.L. DeVries states, that latest technology models for salt caverns could improve the working gas capacity up to 20%5.

Hence the calculation method used is the key foundation for any optimization attempts to decrease the necessary amount of cushion gas and fully use the available working gas; it is also a benchmark for the readiness of the companies to incorporate the models into optimization loops.

As it can be seen in Fig. 4, most companies are using a numerical 3D model. More than 70% are using a 3D model, almost 30% are using a simple model (e.g. material balance), and 20% a p/z plot to model the working gas volume.

However most of the companies who use a p/z-plot also use a simple model (obviously to verify the calculations), therefore the sum of methods is larger than 100%. A few companies use all three methods.

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Figure 4: Reservoir Models for Working Gas Calculation

Questionnaire Question 3 - Reservoir modelling 3.1 What kind of reservoir model are you using? Which product?

The reason to ask for products and flexibility of switching to other models/products is that with this information it is possible to investigate how modular solutions are currently designed. A major influence factor for competitiveness in UGS will be the integration of all aspects (hence all models), the level of automation and optimization of the total UGS system (subsurface, line network and facilities). Understanding the landscape of solutions, which are already implemented, leads to valuable information about the technical feasibility and the adoption speed of any future technology. 5 K.L. DeVries, “Improved Modelling Increases Salt Cavern Storage Working Gas”, GasTIPS Winter 2003, Hart Publications, Houston, USA, 2003

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Reservoir Model Brand

7%

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PETEX SLB Halliburton ROXAR others

Figure 5: Reservoir Models for Working Gas Calculation

The majority of the companies (50%) are using a numerical simulator from Schlumberger, followed by 29% who have either not specified their product or they are using an in-house solution. 7% are using PETEX, ROXAR or Halliburton (see Fig.5) reservoir simulation software.

3.2 Is there a need to switch to a different product? How flexible are you to switch?

The answers to this question show clearly, that the companies have decided, which technology they want to use in the future for reservoir modelling. The willingness to switch products is zero %. A quarter of the interviewed companies did not provide an answer. The reason for the high declination could be that the user is currently not facing severe limitation with his product, and he assumes that this will stay the same for any future needs. It could also mean, that the user is confident, that the product development will adapt to the future requirements. Both options are inheriting a certain risk.

In the first case, the risk lies in the underestimation of the future technology developments to stay competitive. As it can be seen in the results of question 3.7 (level of automation) and question 4.2 (integration of surface and reservoir model) many companies are not at the state of the art of automation and integration. Anticipating future blockers in the deployment of those technologies should be done to mitigate the risk of losing competitiveness.

In the second case, the customer is assuming that the technology provider will enable all necessary capabilities. In this case, the customer creates a high dependency on a third party. If deployment blockers arise, the response time of third parties are usually long, which can result in a significant delay.

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Figure 6: Is there a need to switch reservoir model? 3.3 Do you have confidence in your model results?

The confidence the engineer has in his models directly influences the confidence he can have in his decisions. The quality of the models as well as the quality of the model-derived decisions is not necessarily

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related to the confidence the engineer has in his models. Nevertheless, the history match gives a good indication for the model quality, uniqueness and predictability. In this survey 70% of the replies indicated that the engineers have a high confidence (average of 90%) in their models. All companies who are using a 3D model (70% of all – see Fig.4) have answered this questions and replied with confidence factors between 70 and 100%. 30% either do not have a 3D model and hence did not reply to this question or did not answer the question for other reasons.

3.4 How do you validate your models? Which parameters are you mostly changing, when adjusting the model (= re-history match)?

Model validation is extremely important. Not only for long-term high level what-if scenarios, but even more for solving optimization problems or/and running the simulation model in an automated environment. If models are triggered automatically and the models have not been previously validated, the quality of the result cannot be guaranteed, hence it cannot be used for any decision-making. Regular model validation, e.g. comparing simulated and measured well performance, is absolutely necessary to achieve a sound basis for decision support.

This question was asked to investigate the possibility of automatically history match models, which need some adjustment over time to stay in the expected confidence level. The replies have been given mainly in regards to numerical simulators for porous media.

Most companies (40%) change permeability. Among the others companies:

o - 20% replied that the aquifer behavior provides the tuning parameters for re-history-matching

o - 20% use the relative permeability

o - 20% well performance parameters.

The variety in this answer is to a certain extent a surprise. On one hand it reflects the diversity of problems and challenges, which engineers are facing in the setup of their models, on the other hand it shows how different approaches are taken to improve the models, which probably are driven by the same parameter sensitivities.

3.5 How often do you run predictions/ forecasts (daily, weekly, monthly)?

This question indicates the usage and involvements of the subsurface models in all kinds of decisions, starting with intra-day or daily operational decisions ending with high-level management decisions. The more often predictions and forecast are run, the smaller the time increment between those runs, the more these models are used for short term decisions as well. As can be seen in Fig. 7 the number of companies who run their models at least in a weekly frequency is 25%. 20% use their model monthly for forecasts, the majority of companies (55%) uses it less than every two month. The maximum time range between forecasts is 3 years.

Forecast Frequency

once a day or weekly,

25%

monthly, 20%

2 to 6 month, 40%

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Figure 7: Forecast Frequency 3.6 Do you plan to run predictions/ forecasts more often? Yes/no

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Only 15% of the companies have answered the question with “Yes”. One reason might be the fact, that they are already triggering their forecasts in a high frequency (daily, weekly), which can be used for any kind of decision-making in operations. Another reason might be that the companies do not fell the need to increase the forecast frequency, because they assume that it would not add any value to the daily operations. One of the major conclusions of this study group is that automated handling of low-level processes and faster execution of integrated models will be a key factor to success. It seems that the awareness of this fact has to be raised.

3.7 What is the level of automation? (Are you triggering runs automatically? Is the data preparation part automated? Is the optimization (distribution of well production) automated? Is the result analysis automated?

This question in the section of “reservoir modelling” is mainly targeting the third and therefore slowest cycle of the description as given in the section “Identifying Business & Operations Processes - UGS Operations: The Level of Automation”. Increasing the turn around time of the slowest cycle definitely would result in the highest increase of benefit; therefore, this question is probably one of the keys for UGS companies to improve their operational efficiency in the next years.

Question 3.7 consists actually of several questions, which are combined in one section.

Is the data preparation part automated?

This part of question 3.7 relates to the automatic preparation of mainly transient input data for the simulation runs. Once operational data is collected, they have to be quality controlled, aggregated, and stored in a data-warehouse before they can be processed and reformatted to serve as new input for the simulation models. Traditionally, the preparation of the simulation input files is done manually. In times where the amount of collected data is increasing exponentially, it is easy to see, that this task is extremely time consuming, also prone to errors, if it is not automated. Once the input file generation is implemented in an automated process, it allows the models to be triggered automatically and in addition to trigger different model scenarios, e.g. a history matching = model validation run or a short-term forecast.

At the time of this survey, a very small number of companies had such a process in place, in total less than 15% of all analyzed questionnaires.

Are you triggering runs automatically?

The first part of the question, if simulation runs are triggered automatically is a good indication, whether the link between operational intra-day data and static reservoir or longer-term strategic management data has been established. Triggering the models automatically requires a number of pre-requisites as e.g. model management and standard procedures for model quality control.

Currently, a very small number of companies practice automated models, in total less than 15%, the same number as in the previous question.

Is the optimization (distribution of well production) automated?

Once the data preparation and the model triggering are automated, it is a small step to automate the use of the model to optimize the current operations. Well set-points (e.g. based on tubing head pressures) can be optimized obeying certain constraints (e.g. maximum gas velocity in the well, maximum bottomhole pressure drawdown).

The number of UGS companies, who have answered this question with yes is very low. Only 7% of the companies are in the position to automate the optimization.

Is the result analysis automated?

Importing and using the results of the simulation runs to process them in a notification system, similar to the raw data acquisition would be the final step of automation in the “slow” cycle. If model runs are analyzed automatically and the reporting of the results is based on exceptions, many runs can be triggered and processed without the intervention of an engineer. This step leads to a major improvement and reduction in the cycle time, so that the “slow” cycle can be moved into the medium or even fast cycle range, depending on the simulation speed. Hence, the major increase in benefit can be materialized in this step.

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The survey showed that this level of automation is in the very early phase of being adopted as new technology. Usually it is only accepted by companies who have a high interest in innovation and a high technical skill set in the company.

7% of all companies in the survey have established this level of automation.

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Figure 8: Level of Automation 3.8 What is your biggest problem in modelling?

The answers to this question are much diversified. Some companies mention a shortage in skilled staff, some address the history match, some reservoir characterization issues and some the input data quality. Also the extensive run-time of the models seems to be an issue.

Questionnaire Question 4 - Well & Surface facilities modelling 4.1 Are you using any software to model well and surface facility behavior? If yes, which product?

In the same way, as subsurface models are an appropriate tool to understand and optimize UGS operations in terms of the reservoir/cavern, the well deliverability and the surface network and facilities should be modeled to understand key performance indicators and bottlenecks.

60% are using well modelling software, 20% are not and 20% did not answer the question. 60% are using facility modelling software, 30% do not and 10% did not answer the question.

The product line is dominated by Petroleum Experts Ltd. (Prosper) and Schlumberger (Pipesim) on the well model side and by Aspentech (HiSYS) on the facility side.

4.2. Is your well/surface model connected to your reservoir model? (Yes/No)

The connection of reservoir, well and surface facilities is the prerequisite for a full system optimization.

30% of the interviewed companies stated, that their well model is connected, and in 40% of the cases the network/facility model is connected.

4.3 What kind of data do you use to validate your models?

The models are usually validated using field and operational data. Mainly pressure differences in flow lines are compared to model results.

4.4 Do you have confidence in your model results (0-100%)?

Similar as in question 3.3 the confidence the engineer has in his models directly influences the confidence he can have in his decisions. Again 70% of the replies indicated that the engineers have a high confidence (average of 85%) in their models, although the value is lower than for reservoir models (90%). The lowest

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confidence factor is 60%, the highest obviously 100%. 30% either do not have a model and hence did not reply to this question or did not answer the question for other reasons.

4.5 Which parameters are you mostly changing, when adjusting the model?

Not many answers have been received for this question. The main parameter, which are changed in the models are pipe characteristics like friction factors and in the case of well models well skin.

4.6 What is your biggest problem in modelling?

The answers to this question are similar to question 3.8 much diversified. Some companies mention a shortage in skilled staff, some mention that the software usage is too complicated and some state that the modelling software cannot fulfill all needs.

b. Reservoir Monitoring, Surveillance & Optimization

Available supervisory control and data acquisition (SCADA) systems enable information gathering on individual parameter values. Nevertheless, a single pressure gauge does not provide the complete picture about field performance and cannot be used directly for production optimization. Therefore, real time surveillance models that include reservoir performance and surface facilities constraints need to follow an implementation of a monitoring system.

By using a monitoring system, it is possible to view both downhole information and topside data simultaneously. This enables the operations team to monitor reservoir and well performance. The effect of the daily changes applied to different settings e.g. to each well can then be assessed and modified accordingly.

Better use of downhole data enables precise reservoir management through optimal well performance and opens up new windows of opportunity for further reservoir management improvements. Because the effect of even very small operational changes can be monitored and understood, the true value of each action can be evaluated.

Current levels of reservoir surveillance technology like down-hole gauges and fiber optics coming along with intelligent well completions create an increasing flow of data. Conventional software cannot help the knowledge worker to cope with high-frequency real-time data. Overloaded with data handling work, the knowledge worker in our industry is not capable to reveal the great potential inherent in this data.

The reservoir's response on the applied production strategy is measured with dramatically increasing resolution in time and space. Conventional reservoir modelling techniques like numerical reservoir simulation were developed to predict reservoir performance with a minimum of individual well production/injection information (i.e. monthly data).

While the well-specific performance data become available at a magnitude of 10.000 to 100.000 values per day, CPU time consumption and project turnaround time of numerical simulation models do not allow to be run in real-time.

Data preparation and quality control (QC) is the first crucial step in automating reservoir surveillance.

Monitoring of time dependent data is only useful, if the data is understandable to the engineer. In the case of high oscillation or other reasons of bad quality, it is very difficult for an engineer to detect the underlying trend of a data series and hence he will not be able to derive any conclusion from this data.

Continuously erroneous data could be caused by a gauge or reading failure. In this case, an alarm should be triggered by the notification system. If data gaps occur, again, an alarm can be triggered and the system can automatically suggest a replacement value.

Outliers can be produced by malfunctioning or improper adjusted gauges. The monitoring system should be able to detect these outliers and remove them. After this extensive data quality check, data need to be automatically merged to a handy time increment and finally stored on a server in the company's IT-infrastructure. In this way, high quality data are delivered on time at the engineer's desktop.

Usually monitoring systems have quality checks and an alarm system in place. However, QC rules commonly used are based on a single reading. Only after each reading (TAG) has been processed, the data

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are manually combined and compared by the engineer. This forms a severe limitation in the automation of the surveillance process, as the decision support information has to be put together manually.

Multi-parameter rules and models would allow complex cross validation of surveillance data, as outliers may be detected only in the context of other measured data.

The surveillance system should provide information about the quality of the data; sensor errors and transmission errors can be filtered. Statistical reports allow the engineer to evaluate reliability of data and sensors.

After data preparation, data has to be aggregated at a field sample rate to a rate, which reduces the amount of data without loosing meaningful reservoir behavior information. Experience has shown that time increments of 15 minutes to 1 hour are sufficient for reservoir surveillance.

Raw monitoring parameters have different

o quality

o frequency

o time delays (transmission)

o ways to be measured (sensors, manually edited).

Therefore, aggregation and interpolation of measured data is required. Better data leads to an increasing utilization of data in any decision support workflow.

A notification or event detection system allows to

o anticipate the actual reservoir performance and recovery mechanisms which will likely deviate from the planned model

o identify any discrepancies in performance as early as possible

o provide information regarding the cause of these deviations

o use all data available to identify these discrepancies.

Events in general are either discrepancies from expected trends (actual vs. predicted value), or violations of defined constraints.

Triggered actions can be of the following types:

o set alarm (information, warning, alert) in notification system

o execute surveillance software module, e.g. database reporting

o exchange data with 3rd party software and/or run this software

o trigger other slave tasks

o send e-mail or text message

Optimization

The SPE Real-Time Optimization Technical Interest Group (RTO TIG) developed a framework6 to classify the status at a given asset in the seven categories of “Real Time Optimization”:

1) Measurement; all direct or indirect physical measurements.

6 Mochizuki & al.: “Real Time Optimization and Assessment”, SPE 90213 (2004)

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2) Telemetry; transmitting sensed data over long distances.

3) Data handling and access

4) Analysis; applications used to model, simulate and predict the field behavior as well as optimizing the operation.

5) Visualization

6) Automatic control; control engineering

7) Integration and automation; integrating and auto-mating workflows to optimize the operation

Questionnaire Question 5 - Reservoir Monitoring 5.1 What kind of parameters are you permanently monitoring?

This question is asked in order to be able to understand the level of instrumentation. In addition, the level of instrumentation is really the basic prerequisite for further possibilities to understand and improve the current operation. Data is the corner stone of any engineering work. Availability, frequency, and quality are key to a successful operation.

Unfortunately, also here not all companies replied to this question. Nevertheless, it can be seen that only in two cases, the flow rate at reservoir level as well as the water level in the observation well 10% of the companies replied negatively (See Fig. 9). It can be assumed, that most companies are permanently monitoring well tubing head pressures and temperatures, valve positions and fluid rates (at different levels).

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Figure 9: Permanent Monitoring 5.2 What kind of monitoring software do you use?

55% of the companies have given their input to this question. The answers are much diversified. Every company is using a different SCADA system.

5.3 In which frequency are you measuring wells and facilities?

The majority of the UGS wells and facilities are equipped with a permanent monitoring system, which gathers data in a frequency of less than a minute (75%). A few companies’ measure data on an hourly basis and about 15% measure the data daily or in even longer time increments.

Measuring data in a one-minute time increment means, that for each TAG at least 1440 data points are taken. For time increments of 2 seconds, 43200 measurement points have to be processed per day. In a medium sized company, that leads to 1.5 GByte of data daily for a two second measurement interval.

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Data Frequency

less than 1 min, 75%

one hour, 8%

one day, 8%

longer than one day, 8%

Figure 10: Data Frequency 5.4 Are you sampling all data in the same frequency?

One measure to reduce this vast amount of measured data without loosing any information is the adaption to sample time increments, which are suitable for a specific measurement type. Less than 10% of replies indicate the use of such an option. Almost all companies are using a fixed standard frequency to sample their measurements.

5.5 Are you using any data quality control methods on your continuously measured data? If yes, which ones?

The survey shows, that companies are not very sensitive towards quality control of the acquired data. Only 15% have a system in place or are using the functionality to check the data quality. 25% did not answer the question.

Quality Control

15%

60%

25%

yes % no % n/a %

Figure 11: QC of Monitored Data

5.6 Are you aggregating the high frequency data to a lower frequency?

The usage of the acquired high frequency data (time increment is less than one minute) is very limited. Manual formatting and cleansing is cumbersome and time consuming. Therefore, some companies (50%) are already using automated processes to aggregate the data to higher frequency. However great care has to be taken, as data, which are not quality controlled upfront can lead to wrong aggregated values, which then again can result in a complete loss of information. This is especially a concern if the answers to this question are related to the 60% of companies who do not QC their data.

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Data Aggregation

50.00

25.00

25.00

yes % no % n/a %

Figure 12: Data Aggregation 5.7 Are you storing the high-frequency data in a permanent data-warehouse? If not, how long do you keep the high-frequency data?

The answer to this question is quite diversified. 65% of all companies have answered the question with a positive reply. Almost half of them have a data storage system in place that holds the data for more than a year, usually for several years (above 3 years). 17% are storing the high frequency data up to 6 months and only 8% less than a week.

Data Storage

not at all, 8%

less than a week, 8%

less than a year, 17%

more than a year, 42%

Figure 13: Data Storage Duration 5.8 Have you planned to increase the measurement frequency or/and number of devices / TAGs? Where and how?

This question should indicate, whether companies are still developing, extending or upgrading their monitoring system. Most replies here were negative, showing that the majority of the data is already collected automatically. In some cases (less than 15% of all) additional instrumentation is planned, e.g. on wellheads or gathering stations.

5.9 Do you have a system in place, which creates automatically alarms & notifications based on the most recent data?

60% of all replies noted, that there is an alarming and notification system in place. Some (25%) mention the use of a smart system, like an advisor. 15% do not have an alarming system in place.

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Automated Alarms

60.00

15.00

30.00

yes % no % n/a %

Figure 14: Automated Alarms 5.10 Is the data used for decision support?

This question in the combination with the previous one allows the differentiation, if the alarm system is used purely for monitoring incidents, e.g. the total loss of a piece of equipment, or if it is used in combination with other parameters as a kind of advisor or expert system. About 20% of the positive replies from this question overlap with the positive replies from the previous question. This leads to the conclusion, that a third of the companies, who have installed an alarming system are also using it as an advisory or expert decision support tool.

Data Used for Decision Support

35.00

15.00

50.00

yes % no % n/a %

Figure 15: Data used for Decision Support 5.11 What is the focus (main target) of your monitoring/automation strategy?

Currently, companies are focusing their monitoring forces on water production and to a certain extent to sand & corrosion control.

Monitoring Strategy

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

80.00

90.00

100.00

Sand control Corrosion / Cathodicprotection

Water Production Hydrate Formation

Perc

enta

ge

[%]

yes % no % n/a %

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Figure 16: Monitoring Strategy 5.12 What kind of data and in which frequency do you enter data manually into the system?

Manual data capture extremely delays the delivery of data and hence information to the engineer. Any kind of critical information should be transmitted and delivered automatically. Some companies are acquiring some data manually, but in all cases the data is not critical, e.g. pressures of observation wells.

5.13 Are you using the dynamic data for optimization of the UGS operations?

As can be seen from the RTO TIG ranking in the introduction of question 5, the last step (#7) in RTO consists of the integration and automation of workflows to optimize a business need. A considerable low number of replies (20%) indicate that they are practicing this final step of optimization.

Questionnaire Question 7 - Safety

The safety questions here are focused on the usage of real-time (or near real-time) data and model results to increase safety in operations.

7.1 What kind of safety monitoring system do you have in place? How do you monitor safety? Level of automation?

All companies, who have replied to this question (35%) have a automated system in place. 7.2 Do you monitor caprock tightness / pressure loss / leaking? If yes, how?

45% of all replies indicate that they monitor wells above the caprock. 30% did not answer the question and 25% have no monitoring wells active.

Monitoring Wells above Caprock

45.00

25.00

30.00

yes % no % n/a %

Figure 17 Monitoring Wells above Caprock 7.3 How does a safety control design in a digital environment look like?

The question is held very general; therefore the answers are quite diverse. The range of answers starts at continuous monitoring of anomalies in pressures and temperatures, sensors for sand control and ends at better environmental protection.

Questionnaire Question 8 - Key Performance Indicator (KPI) Questions

Key Performance Indicators (KPI) are financial and non-financial measures or metrics used to help an organization define and evaluate how successful it is, typically in terms of making progress towards its long-term organizational goals. A KPI is a measure that represents the condition of factors that directly influence the realization of the organizational strategy.

If a Key Performance Indicator is going to be of any value, there must be a way to accurately define and measure it. Because of the necessity to anticipate quicker to changes in the environment, organizations have to search for KPI’s measuring factors that are directly affecting the financial figures. Organizations are not solely steering on financial dimensions but also on other dimensions like technical issues and internal

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processes. If the actual value of these KPI’s differs from the target it will always have an effect on the financial performance.

8.1 Where is the highest impact of an “intelligent UGS” in increasing your performance?

The results of the last question can be seen in Fig.18. Most companies (almost 80%) voted for “Surface Maintenance” to have an impact on the company’s performance, but it was actually not rated as the most important KPI. The highest votes for importance have been given to “Safety” (30% +), but only from a little less than 50% of the companies. “Subsurface Maintenance” was also a popular choice, but rated as not so important as “Surface Maintenance”.

The three most important KPIs have been selected to be “Safety”, as already mentioned, “Reservoir Performance” and then “Well Performance”.

Key Performance Indicator (KPI)

0.00

10.00

20.00

30.00

40.00

50.00

60.00

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Energy costs SubsurfaceMaintenance

SurfaceMaintenance

Humanresources

Taxes Gas losses Depreciation Leasing safety Reservoirperformance

Wellperformance

Perc

enta

ge

[%]

Importance %

Answers %

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