December, 4/2018 · This consent does not extend to other kinds of cop-ying, such as copying for...

December, 4/2018

TS_OG4.indd 1 26.11.2018 15:02:52

Growing with Energy

DEADeutsche Erdoel AG, Überseering 40, 22297 Hamburg, Germany dea-group.com

Growing withResponsibility

Embracing responsibility, increasing efficiency and sustainable growth – these are the

ingredients of DEA’s success story. The Mittelplate Drilling and Production Island at the edge

of the Wadden Sea National Park in Germany is a good example of DEA’s approach towards

the environment. DEA is currently producing more than 50 % of Germany’s domestic crude

oil from Mittelplate and has been operating the field without any harmful influence on the

nature reserve for 31 years now. DEA takes responsibility towards humankind and the

environment in all its upstream activities – in countries like Germany, Norway, Denmark,

Egypt, Algeria and Mexico – every day.

DEA16014_AZ_Oil_Gas_A4_EN_rz_161024.indd 1 24.10.16 15:25

IISSSSNN 00334422--55662222 VVOOLLUUMMEE 4444, IIVV//22001188

Contents

OOiill && GGaass NNeewwss

International News 166

New Products / Processes / Literature 210

Event Calendar 212

PPrroodduuccttiioonn EEnnggiinneeeerriinngg

Gravel Pack Monitoring With a Strain Sensing Fiber Optic Cable

M. LIPUS, T. REINSCH, C. SCHMIDT-HATTENBERGER,

J. HENNINGES and M. REICH 179

BEER: Bio Enhanced Energy Recovery – Innovative Carrier Fluid for

Reservoir Optimization

K. KOGLER, M. PAVLOV and H. HOFSTÄTTER 186

RReesseerrvvooiirr SSiimmuullaattiioonn

Simulation of Reactive Transport Processes: Acidizing Treatments in

Carbonate Reservoirs

T. CVJETKOVIC, J.-O. SCHWARZ, L. CHENG, J. BECKER,

S. LINDEN and A. WIEGMANN 190

CCaassiinngg IInnssppeeccttiioonn

Assuring Vertical Casing Integrity with Pipeline Inspection Technology

B. HOSTAGE, D. SCHAPER and S. STOLTE 194

DDrriilllliinngg EEnnggiinneeeerriinngg

Differences in Cementing Oil, Gas and Geothermal Wells

Y. YADIGAROV 198

MMaarrkkeett AAnnaallyyssiiss

Russia’s LNG on the World Market: Starting the Penetration

E. M. KHARTUKOV 204

OIL GAS European Magazine was firstpublished in 1974 as an original international edi-tion of ERDÖL ERDGAS KOHLE.Since 2003 OIL GAS European Magazine is alsopublished as an integrated part of ERDÖL ERDGASKOHLE’s March, June, September and Decemberissues.

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Valid for users in the USA: The appearance of thecode at the botton of the first page of an article inthis journal (serial) indicates the copyright owner’sconsent that copies of the article may be made forpersonal or internal use, or for the personal or in-ternal use of specific clients. This consent is givenon the condition, however, that the copier pay $6.00 per article to CCC, 222 Rosewood Drive, Dan-vers, MA 01923, USA (ISSN 0342-5622).This consent does not extend to other kinds of cop-ying, such as copying for general distribution, foradvertising of promotional purposes, for creatingnew collective work or for resale.

Title:Johan Sverdrup RP 16/2 installedon the field

©Photographer: Bo B. Randulff,Roar LIndefjeld / Equinor

OG4_Innentitel.indd 3 26.11.2018 15:19:31

OIL GAS EUROPEAN MAGAZINE 4/2018OG 166

News

Jacket contract for Johan Sverdrup phase 2

Equinor and the Johan Sverdrup licencehave awarded a jacket contract for theprocessing platform for Johan Sverdrupphase 2 to Kværner. The contract value isaround NOK 900 million (approx. 92,5million €).“With this contract, Kværner and theNorwegian supplier industry has onceagain proved it is competitive in an inter-national market. In the first phase of theJohan Sverdrup development more than70% of the contracts were awarded tosuppliers in Norway. With this contractto Kværner, we expect an even highershare of Norwegian suppliers in the sec-ond phase of the development,” saysTrond Bokn, senior vice president for theJohan Sverdrup development.This is an EPC contract covering engi-neering, procurement and constructionof the steel substructure for the secondprocessing platform for the Johan Sver-drup field. The 12,300-t substructure will

be constructed at Kværner’s yard in Ver-dal and installed at the Johan Sverdrupfield during the spring of 2021.“The Johan Sverdrup phase 2 contractsawarded earlier this year will ensure ac-tivity at many yards along the Norwegiancoast in the years to come – primarily inHaugesund and Egersund and at Stord.With this jacket contract we can now alsoadd Verdal to this list,” he says.Kværner’s offices at Fornebu will be re-sponsible for engineering and design ser-vices. The contract will create around300 direct jobs in the construction peri-od.Both Johan Sverdrup phases combinedare, according to the consultancy AgendaKaupang, estimated to involve morethan 150,000 man-years in the period2015–2025.

Continuation of the improvement agenda intophase 2

Kværner has so far delivered three of thejackets for the first phase of the JohanSverdrup project. This contract meansthat Kværner will have delivered four offive jackets to the giant field when thesecond development phase is completedin Q4 2022.“As one of the main suppliers to JohanSverdrup, Kværner has contributed withseveral significant high-quality deliver-ies, on time and budget. And nowKværner has once again won a contractin strong international competition,” saysPeggy Krantz-Underland, Equinor’s sen-ior vice president for procurement andsupplier relations.“The improvement work in Johan Sver-drup, and in Equinor more generally, is aresult of close collaboration with oursuppliers. The contract with Kværner al-lows us to further build on this collabora-tion and the experiences from the firstphase of the project, to ensure continuedsafety, quality and efficiency in the nextphase of Johan Sverdrup as well,” shesays.The first phase of the Johan Sverdrupproject is expected to start production inNovember next year and includes fourinstallations with steel substructures: Autility and living quarters platform, adrilling platform, a riser platform and aprocessing platform.The second phase of the Johan Sverdrupproject will also have a jacket-based pro-cessing platform, and modifications aremade to the field centre to expand pro-duction capacity from 440,000 boe/d to660,000 boe/d.The contract is subject to approval of theplan for development and operation ofJohan Sverdrup phase 2 that was submit-ted to Norwegian authorities on 27 Au-gust 2018.

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NORWAY

Follow-on contracts awarded to Bilfinger in the North SeaBilfinger has received follow-up ordersfrom its contract partner, the Norwegianservice company Aibel, that are to tie inwith phase 1 of the Johan Sverdrup oilfield project. The overall scope of workincludes the offshore hook-up, installa-tion, and completion of the drilling andprocess platform as well as bridges con-necting the various offshore installationsof the field complex. In addition to thecontracts currently awarded, Bilfingerhas been assigned the task of exchangingthe flare tip on the Riser platform. Thiscontract includes the development of the

concept and methods, along with the ex-ecution of the work by industrial climb-ers.“The orders confirm the trust that our cli-ents have in our know-how and our ex-perience. We deliver extensive offshorecampaigns observing the highest safety,efficiency, and quality standards. Thecontract for the flare tip change-out bearswitness to our successful growth and thedevelopment of our capabilities as re-gards rope access”, said Tom Blades, ChiefExecutive Officer at Bilfinger. “And theyare further proof that we are on the right

track with our Bilfinger 2020 Strategy.”The Johan Sverdrup field is one of thefive largest oil fields located in the NorthSea. It is expected to hold 2.1 to 3.1 bil-lion b of oil, making the field one of themajor industrial projects in Norway forthe next fifty years ahead. The Norwe-gian energy company Equinor, formerlyStatoil, is the operator of the field. Thetotal contract value amounts to around €15 million, and the work at the JohanSverdrup field will secure more than 150jobs at Bilfinger in 2019.

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OIL GAS EUROPEAN MAGAZINE 4/2018

New oil discovery in the Johan Castberg licenceEquinor and partners ENI and Petorohave completed the Skruis explorationwell in the Johan Castberg licence. Thewell confirms a volume of 12–25 millionrecoverable barrels of oil. Skruis is thefirst operated exploration well drilled byEquinor this year in the Barents Sea.“This is an important discovery. It helpsto determine the size of the Johan Cast-berg resource base which is currently be-ing developed. Securing resources nearexisting infrastructure is an importantpart of Equinor’s ambition and strategyon the Norwegian continental shelf”,says Nick Ashton, Equinor’s senior vicepresident, Exploration, Norway & UK.“The Skruis discovery confirms the po-tential in this part of the Barents Sea.Over the past couple of years, we havelearned that exploration in the BarentsSea is challenging and takes patience. Westill have three Equinor-operated wellsand one partner-operated well left to drillin the Barents Sea. We also have a goodportfolio for the next couple of years. To-gether with the wells we drilled in 2017,this will help clarify the potential in theremaining part of the Barents Sea”, saysAshton.The partners will now further consider

tie-in of the discovery to Johan Castberg.The Johan Castberg field is planned forstart-up in 2022 and currently has fullcapacity up to 2026–2027. The timing ofa potential development of the Skruisdiscovery will be adjusted to this.“Through the Johan Castberg field devel-opment we open a new oil province inthe Barents Sea, enabling us to tie in thistype of small discoveries that will behighly attractive when the infrastructureis in place”, says Knut Gjertsen, projectdirector for the Johan Castberg develop-ment.Recoverable reserves in Johan Castbergare estimated at between 45–650 millionb. The volumes from Skruis and the Kay-ak discovery from 2017 are not includedin this estimate.The exploration drilling in the Skruis(7220/5-3) well was started on 27 Sep-tember by the Songa Enabler drilling rig.Production license PL532 Johan Castbergis located some 100 km north of theSnøhvit field, with first oil scheduled for2022.Equinor has ongoing operations on theprospect Intrepid Eagle in PL615 in theHoop area of the Barents Sea.

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NORWAY

Johan Castberg construction begins at Stord

Norwegian minister of petroleum andenergy, Kjell-Børge Freiberg, started cut-ting the first sheet for the topside of theJohan Castberg vessel at Kværner’s yardat Stord. The construction will create ma-jor ripple effects throughout Norway.“Johan Castberg is the next major devel-opment on the Norwegian continentalshelf and will open a new area in theBarents Sea for Equinor. Johan Cast-berg’s development will have ripple ef-fects equivalent to 47,000 man-years inNorway during the development phase.The value of Norwegian goods and ser-vices will amount to around NOK 25 bil-lion”, says Anders Opedal, Equinor’s ex-ecutive vice president for Technology,Projects and Drilling.In total, more than 2 million workinghours will be included in the construc-

tion of the topside, and it is expected togenerate jobs for 4,800 people.“Simultaneously, work will begin at anumber of yards along the entire Norwe-gian coast. Already, many small and largeNorwegian suppliers are in the process ofdelivering to Johan Castberg. This showsthe competitiveness and competencies ofthe Norwegian supplier industry in hardglobal competition, says project directorfor Johan Castberg, Knut Gjertsen.There will be extensive activity at theyards in Verdal, Egersund and Sandness-jøen in addition to Stord over the nextfew years constructing the many partsthat will form the complex topside. It willbeinstalled on the 200 m long FPSO ves-sel that will be producing on the Johan-Castberg field for 30 years from theplanned production start in 2022.Already the construction of the othertwo big puzzle pieces of the FPSO is wellunder way. The hull is under construc-tion in Singapore, and the turret is beingbuilt in Dubai. These will eventually ar-rive at Stord in 2020 for assembly andcompletion before the vessel is moved toits permanent home in the Barents Sea.The Johan Castberg partnership includesEquinor 50%, Eni 30%, and Petoro 20%

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Technology fora clear Future

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OG 168 OIL GAS EUROPEAN MAGAZINE 4/2018

First steel cut on Nova tie-back to Gjøa offshore platform

The Nova field, operated by Wintershall,was discovered in 2012 and is situated onthe northeastern Norwegian continentalshelf, approximately 20 km southwest ofthe Neptune Energy-operated Gjøa plat-form and about 120 km northwest ofBergen. Nova will be developed as a sub-sea tie-back connecting two modules tothe nearby Gjøa platform for processingand export. Gjøa will also supply lift gasto the field and water injection for pres-sure support.Arild Jåsund, Project Manager for Novaat Neptune Energy said: “The un-strand-ing of additional volumes from Nova, byusing existing Gjøa infrastructure, is not

only significant for the Norwegian econ-omy but also important in extending theproduction life of Gjøa itself. Further-more, the Nova tie-in works representthe largest modification ever conductedon Gjøa, and provide Neptune Energyand our contractors the opportunity toprove our capabilities in managing majorprojects in a safe and an efficient way.”First steel is a major milestone in thework to prepare for production of theNova field through the Gjøa platform.During the next two years RosenbergWorleyParsons will complete construc-tion of the Nova topside equipment, builtfor processing of Nova field hydrocarbons

and to provide water injection facilitiesvia the Gjøa platform. At peak the projectwill support engineering and construc-tion work for approximately 300 peopleat Rosenberg WorleyParsons. In May2020 the Nova module will be lifted onboard Gjøa by a heavy lift vessel fromHeerema Marine Contractors.Hjalmar Aslagsen, Project Manager atRosenberg WorleyParsons added:“Rosenberg WorleyParsons highly appre-ciates the trust shown to us by NeptuneEnergy and the Nova licence partners,through the initial FEED stage and intothe EPCIC phase of this important pro-ject. Our organisation appreciates thedual challenges of providing a robust andoptimal design, whilst executing con-struction with zero harm – both onshoreand offshore. We take great pride in de-livering a project that satisfies our cus-tomers’ needs and today’s early start offabrication is an important milestone to-wards safe and timely completion.”From January 2019, preparations willstart at Gjøa to receive the Nova moduleand other necessary equipment. In paral-lel with the work at Gjøa, Wintershalland their main contractors will completethe necessary underwater activities andriser installation so that three oil wellsand three water injection wells are readyfor use when the new module on Gjøastarts up. n

NORWAY

Wintershall acquires stake in the largest gas and condensate fields yet to be developedin the United Arab EmiratesWintershall will invest in one of theworld’s most important centers for oiland gas production: The company willtake a 10% take in the Ghasha Conces-sion al ong side the Abu Dhabi NationalOil Company (ADNOC) in the UnitedArab Emirates. The Hail, Ghasha, Dalmaand other ultra – sour gas and conden-sate fields such as Nasr, SARB andMubarraz are located in the Al Dhafraregion off the coast of the Emirate ofAbu Dhabi . Dr . Sultan Ahmed Al Jaber,UAE Minister of State and ADNOCGroup CEO, as well as Mario Mehren,CEO of Wintershall, have now signed aconcession agreement in the presence ofDr Martin Brudermüller, CEO of BASF.This marks the first time in Wintershall’shistory that it is to produce gas and con-densate in Abu Dhabi. The contracts todevelop the deposits of natural resourceshave been awarded by the Abu DhabiGovernment for a term of 40 years. AD-NOC’s other project partner, alongside

Wintershall, is the Italian noil and gascompany ENI , with a 25 % stake. Dr. AlJaber said: “Development of the Ghashaconcession area is a strategic priority forADNOC. The gas, extracted from theconcession area, at commercial rates, willmake a significant contribution to fulfill-ing our commitment to ensuring a sus-tainable and economic gas supply, andachieving our objective of gas self – suffi-ciency for the UAE.” “We are delighted tobe extending our activities in Abu Dhabiand our cooperation with ADNOC,”stated Brudermüller. “Through theagreement we are laying an importantfoundation for Wintershall’s growthstrategy,” said Brudermüller. Dr Al Jaber:“In common with ADNOC, Wintershallhas extensive experience of appraisingand developing ultra-sour gas resourcesin technically complex fields. It is a part-nership in which each company willbenefit from the experience of the otheras, together, we optimize costs and en-

sure we extract the maximum valuefrom all the available gas resources. Itbuilds on our long experience of sour gasproduction and strengthens our ambi-tion to establish a center of excellence, inAbu Dhabi, for sour gas development.”“We are delighted to be partners in thisproject, supporting ADNOC’s 2030 smartgrowth strategy”, stated Wintershall’sCEO Mario Mehren. “The project alsofits excellently with our strategy. Wehave been working since 2010 onstrengthening the Middle East region byinvesting here and developing it into another growth region for Wintershall.And we achieved an important mile-stone today by signing the contract . Weare proud that ADNOC is placing its trustin Wintershall as a partner. We want toestablish a strong and long-term coop-eration in Abu Dhabi. Together with AD-NOC, we will build up substantial pro-duction”, said Mehren.

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NORWAY

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OIL GAS EUROPEAN MAGAZINE 4/2018 OG 169

DENMARK

Start of construction of a new 100,000 t base oil re-refinery at the Port of KalundborgOn 16th November, the Mayor ofKalundborg, Martin Damm, brokethesoil to officially begin the construction ofa modern 100,000 t re-refinery designedto upcycle used oil back into base oil forthe production of new finished lubri-cants. The re-refinery is expected to beoperational by the end of 2019.The construction of this new used oil re-refinery in Kalundborg became a realityfollowing the establishment of an inter-national joint venture between Germanbased AVISTA OIL and Greenbottle fromthe UK. Together they formed and in-vested in a new Danish company thatwill be responsible for the building andoperation of this new facility.The new re-refinery will have a produc-tion capacity of ca. 100,000 t where usedoil will be transformed into high qualitybase oil. This base oil will then be used inthe production of new finished lubri-

cants. The re-refinery has been designedto meet the highest technical and envi-ronmental standards and with a strongfocus on safe operations. In being able toupcycle used oils into a highly desirableand valuable product, the new re-refin-ery will be a major contributor to themodern circular economy.The used oil raw materials for the newre-refinery are collected from car repairshops, industrial companies, ships andwaste recovery sites. The increased plantcapacity will require substantial volumesof feedstock from businesses throughoutEurope. These volumes will be securedand provided by the two owners who areleaders in their respective markets. AVIS-TA OIL with its network of companies isthe biggest collector of used oil on theEuropean continent and Greenbottle,through its subsidiary Slicker Recycling,the largest in the UK.

The powerful combination of two marketleading European owners together withthe experienced Danish workforce andestablished infrastructure makes this atruly exciting project.Managing Director of the new companyLeon Sloth Skovbo said: “We are proudto have reached this milestone and to be-gin the construction of our new re-refin-ery. It has taken a lot of hard work fromall of our dedicated employees – but thejourney has been worth it. We have suc-ceeded in securing investment that willonce again place Kalundborg at the heartof European re-recycling whilst increas-ing and securing local jobs. We look for-ward with confidence to many increasedactivities here in Kalundborg and to be-ing in charge of this significant environ-mental project.”

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BP receives OGA approval to develop Alligin field in North Sea

BP confirmed it has received approvalfrom the Oil and Gas Authority (OGA) toproceed with the Alligin developmentwest of Shetland, which will target 20million boe, and is expected to produce12,000 b gross of oil equivalent a day atpeak.Alligin is located 140 km west of Shetlandin a water depth of 475 m. It forms part ofthe Greater Schiehallion Area.The Alligin development will consist oftwo wells, which will be tied-back into theexisting Schiehallion and Loyal subsea in-frastructure, utilising the processing andexport facilities of the Glen Lyon floating,production storage, offload (FPSO) vessel.

It is expected tocome on stream in2020.The developmentwill include newsubsea infrastruc-ture, consisting ofgas lift and waterinjection pipelinesystems, and a newcontrols umbilical.The wells will bedrilled by the Deep-sea Aberdeen rig.Alligin (BP 50%operator; Shell50%) is part of a se-ries of infrastruc-ture-led subsea tie-back developmentsin the North Sea,

accessing new production from fields lo-cated near to established producing infra-structure.BP North Sea regional president Ariel Flo-res said: “We announced our intention todevelop Alligin in April and six monthslater we have achieved regulatory approv-al. Always maintaining our focus on safe-ty, we are modernising and transforminghow we work in the North Sea to fullyrealise the potential of our portfolio.”“Alligin is part of our advantaged oil story,rescuing stranded reserves and tying themback into existing infrastructure. Develop-ments like this have shorter project cycles,allowing us to bring on new production

quicker. These subsea tie-backs comple-ment our major start-ups and underpinBP’s commitment to the North Sea.”Brenda Wyllie, West of Shetland andNorthern North Sea area manager at theOil and Gas Authority (OGA), said: “TheOil and Gas Authority is pleased to con-sent to the development of the Alliginfield. This fast-tracked project will maxim-ise economic recovery through utilisingcapacity in the Glen Lyon FPSO and is agood example of the competitive advan-tage available to operators from the ex-tensive infrastructure installed in the UK-CS.”This is BP’s second North Sea develop-ment approval in the past two months.Vorlich, which targets 30 million boe, re-ceived regulatory approval in September.BP’s Clair Ridge development is expectedto start-up later this year. It is expected totarget 640 million b of resources and havea peak production of 120,000 b/d.BP also has 32% stake in the North SeaCulzean development, which is expectedto supply around 5% of UK gas require-ments. First gas is anticipated in 2019.Earlier this year, BP was awarded sevenlicences, five as operator and two as part-ner, in the North Sea’s 30th Offshore Li-censing Round. And in January, BP an-nounced two new discoveries in the NorthSea at Capercaillie in the Central NorthSea and Achmelvich west of Shetland.

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SHETLAND

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BELGIUM

ExxonMobil starts new unit at Antwerp refinery to produce high-value transportation fuelsExxonMobil has started operations of anew unit at its Antwerp refinery in Bel-gium to convert heavy, higher-sulfur re-sidual oils into high-value transporta-tion fuels such as marine gasoil and die-sel.The new 50,000 b/d unit expands therefinery’s capacity to meet demand forcleaner transportation fuels throughoutnorthwest Europe. The company’s in-vestment in the new coker will also helpmeet anticipated demand for lower-sul-fur fuel oil to comply with new stand-ards to be implemented by the Interna-tional Maritime Organization in 2020.“Our investment in Antwerp strength-ens ExxonMobil’s competitiveness andposition as a leading European refinerby expanding the refinery’s product

slate and increasing our ability to deliverlarger quantities of cleaner, higher-valuefuels to European customers”, said Bry-an W. Milton, president of ExxonMobilFuels & Lubricants Company. “The $ 2billion we have invested in our Antwerprefinery over the last decade has madethe facility one of the most modern andefficient in the world.”Other projects completed in Antwerpinclude a 130 MW cogeneration unit,which leads to reduced greenhouse gasemissions, and a diesel hydrotreater,which has increased the refinery’s pro-duction capacity for low-sulfur diesel toenable modern diesel engines to achievelower emissions standards.The delayed coker is the first of severalexpansion projects designed to strength-

en the competitiveness of ExxonMobil’sadvantaged facilities in Europe. Thecompany is currently constructing anew hydrocracker in Rotterdam thatwill upgrade heavier hydrocarbon by-products into cleaner, higher-value fin-ished products such as EHCTM Group IIbase stocks and ultra-low sulfur diesel.ExxonMobil is also considering an ex-pansion project at its Fawley refinery inthe United Kingdom that would includea new hydrotreater unit and associatedhydrogen plant to increase domestic die-sel production and reduce reliance onimported fuel.

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ITALY

The geothermal industry fear risks for investment in ItalyThe Italian government, in a draft decreethat includes negotiation on new supportschemes for renewables (Schema di de-creto sull’incentivazione delle Fonti diEnergia Rinnovabile, FER1), intends tounilaterally cut support to geothermalenergy in the country, a vicious attackagainst an industry that was born in Italy,has nearly 1 GWe of baseload renewableelectricity installed (producing 6.2 TWh/year), and employs 3000 direct workers,in addition to around 7000 indirect andinduced local jobs.The geothermal energy sector in Italy is alarge industry composed of SMEs andlarge companies. Geothermal energy iswidely recognized as a key renewablesource for climate change mitigation, andItaly is leading innovation in this sector,with more than € 20 million of public in-vestment for research, development andinnovation on geothermal energy duringthe last five years. This decision of theItalian government means to willinglyhandicap a leading and recognized estab-lished Italian industry.“With geothermal Italy has a great re-newable resource, that led to the emer-gence of a cutting-edge Italian geother-mal industry, which supports local eco-nomic and social development and thatnow helps other countries to developtheir own geothermal sector. It would bean enormous mistake, while everyone isfocusing on the energy transition, to takesuch a step back by cutting support to thegeothermal sector,” said Miklos Antics,President of EGEC, the European Geo-thermal Energy Council.“By supporting such a retroactive change

to support schemes, the Italian govern-ment undermines not only the great rolethat Italy’s geothermal sector has histori-cally played in the development of thesector globally, but also investor certaintyand confidence in geothermal energy, inaddition to jeopardising Italy’s energytransition”, said Alexander Richter, Presi-dent of IGA, the International Geother-mal Association.The decision to cut support to geother-mal energy has a direct impact on in-creasing carbon emissions, worsening airquality in the Tuscany region, cuttingjobs, reducing investment and economicdevelopment, and reducing Italy’s energysecurity. Indeed, on top of producingelectricity, Italy’s geothermal powerplants supply low-cost renewable heat toTuscan households and businesses, re-placing thousands of fossil fuel boilersand their associated NOx and particulatematter emissions.“This decision is in direct violation of theprinciples agreed by all European gov-ernments, including Italy, in the recastRenewable Energy Directive, to notmake retroactive changes to supportschemes for renewable energy sources,and to announce well in advance up-coming changes,” added Miklos Antics,President of EGEC.“The Global Geothermal Community isconcerned,” said Alexander Richter,President of IGA. “Geothermal energyrepresents an inexhaustible naturalsource of energy, which can play a sig-nificant role in meeting the world’s en-ergy needs of the future. Geothermal en-ergy is unique in its ability to serve mul-

tiple purposes in the global energy transi-tion and create additional value tonational economies by offering multipleuses of the resources, such as for heatingof residential and business properties,greenhouse operations, as well as by-products such as health and beauty prod-ucts, attracting tourism and deriving pre-cious metals, such as lithium from geo-thermal brines. We are convinced thatgeothermal can serve as a bridge towardsa sustainable future, supporting the tran-sition from a fossil-fuel to a renewable-based economy also in Italy. The decisionby the Italian government sends a devas-tating message to the international geo-thermal community, also in the contextof the Italian representation within theGlobal Geothermal Alliance of the Inter-national Renewable Energy Agency(IRENA) and the work of Italian compa-nies internationally.” n

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FRANCE

Implico integrates 88 service stations into the existing Certas Energy system landscape in FranceThe international software and consult-ing company Implico has integrated 88service stations into Certas Energy’s ex-isting system landscape in France. Thekey to the success was a combination oftwo factors: Firstly, the company’s SAPconsulting expertise in the oil and gasbusiness. Secondly, its cloud solutioniGOS (Implico Global Operation Servic-es). Together, they enabled the setup ofa secure service station supply and aquick linkage to the existing infrastruc-ture. Only six weeks passed betweenthe start of the project and the first suc-cessful booking.Certas Energy purchased the new sta-tions from Groupe Dubreuil in Septem-ber. Due to legal requirements, thecompany could not integrate the ac-quired sites into its French service sta-tion network straight away. Instead,

Certas Energy formed a new company,which had to be completely mapped inthe SAP system. Within a short time,Implico enabled Certas Energy to en-sure the logistic replenishment of theservice stations as well as the billing andbooking in SAP.“Integrating a large number of servicestations into a supply network is noteasy. Thanks to our clear focus on theoil and gas industry, we had the SAPcompetency to realize this sophisticatedproject successfully – and with iGOS,we also had the perfect tool for thistask”, says Klaus Wunsch, SAP TeamLead in Implico’s Customer SupportCenter.Johannes Buhre, Head of the iGOSteam at Implico, explains: “iGOS is notonly versatile, but also compatible withall common data formats. This makes

our solution especially suitable formergers and acquisition projects, whichare often very time critical. When part-nering with us, the customer requiresneither an IT team nor complex hard-ware. All data processing steps will beoverseen and carried out by us.”Within the given IT landscape, iGOSserves as both a filter and translator.Firstly, it collects and sorts the data setsof all communication partners involved.Secondly, it processes them and makesthem usable in SAP. All computing op-erations take place in the cloud. For thecustomer, this means a fast and secureproject implementation as well as calcu-lable operating costs.

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TUNESIA

OMV agrees to divest parts of its upstream business in Tunisia

OMV, the international integrated oiland gas company based in Vienna, hasreached an agreement to sell its 100%owned subsidiary, OMV Tunisia Up-stream GmbH, to a subsidiary of Panoro

Energy ASA, an Oslo-listed,London-based internationalindependent oil and gas com-pany. OMV Tunisia UpstreamGmbH holds 49% interests inthe Cercina/Cercina Sud, ElAin/Gremda, El Hajeb/Gue-biba and Rhemoura conces-sions in Tunisia and 50% ofthe shares in the Thyna Pe-troleum Services S.A. Operat-ing Company (TPS). Theagreement will be signedshortly following an equity

private placement exercise by Panoro.The agreed purchase price is US$ 65 mil-ion, subject to closing adjustments. Theeffective date of the transaction is Janu-ary 1, 2018. Average production of the

divested assets in 2017 was around 2000boe/d, net to OMV.The remaining stakes in the concessionsand in TPS continue to be held by theTunisian National Oil Company (ETAP).“The divestment represents a furtherstep in optimizing OMV’s upstreamportfolio”, said Johann Pleininger, OMVBoard Member Upstream and DeputyChairman of the Executive Board.OMV continues to be committed to Tu-nisia and the ongoing development ofits hydrocarbon resources in south Tuni-sia, in particular the development of theNawara Concession, involving gas fieldinfrastructure and a pipeline from a cen-tral processing plant in the Concessionto Gabes (approx. 300 km to the north).

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ANGOLA

Total inaugurates the Kaombo project and reiterates its commitment to the countryThe Angolan State Minister for Econom-ic and Social Development, ManuelNunes Junior, the Chairman and CEO ofTotal, Patrick Pouyanné, and the Chair-man of the Board of Directors of Sonan-gol, Carlos Saturnino, inaugurated theKaombo project, which came on streamin July and is located deep offshore onBlock 32. Located 260 km off the coastof Luanda, on Block 32, in water depthof around 2,000 m, Kaombo is the big-gest offshore development in Angola.The first FPSO, Kaombo Norte has a pro-duction capacity of 115,000 bopd. Thestart-up of the second FPSO of similarcapacity, Kaombo Sul, is expected nextyear. The overall production will reachan estimated 230,000 bopd at peak andthe associated gas will be exported tothe Angola LNG plant.A total of 59 wells will be connected tothe two FPSOs, both of which are con-verted Very Large Crude Carriers,through one of the world’s largest sub-sea networks. Together, they will devel-op the resources of six different fields(Gengibre, Gindungo, Caril, Canela,Mostarda and Louro) over an area of800 km² in the central and southernpart of the block.Total operates Block 32 with a 30% par-ticipating interest, along with SonangolP&P (30%), Sonangol Sinopec Interna-tional 32 Limited (20%), Esso Explora-tion & Production Angola (Overseas)Limited (15%) and Galp Energia Over-seas Block 32 B.V. (5%).During the ceremony, Total also an-nounced the continuation of its devel-opment program in the country, follow-

ing on from the launch of the Zinia 2project in May. The Group, along withits partners, has notably taken two in-vestment decisions on Block 17, locateddeep offshore 150 km off the coast ofAngola, to develop satellite fields thatwill be tied back to existing infrastruc-tures and will quickly bring additionalproduction.– The CLOV phase 2 project, which re-quires the drilling of seven additionalwells, with first oil expected in 2020and a production plateau of 40,000 b/d.

– The Dalia phase 3 project, which re-quires the drilling of six additionalwells, with first oil expected in 2021and a production plateau of 30,000 b/d.

Zinia 2, CLOV 2 and Dalia 3 will develop150 million b of additional resources tomaintain the Block 17 production pla-teau above 400,000 b/d until 2023, andfurther extend the profitability of thisprolific block, with over 2.6 billion b al-

ready produced. “As Angola’s principaloil partner, Total is proud to inauguratesuch a major deep offshore project asKaombo, which started up productionin July and marked a new milestone ofour history in the country,” stated Pat-rick Pouyanné, Chairman and CEO ofTotal. “I would like to recognize theleadership shown by the Angolan Presi-dent, João Lourenço, and the joint ef-forts of the authorities, Sonangol andthe industry to enhance contractualframework, which is an essential steptowards developing new projects. Thesanction of these new projects todaydemonstrates Total’s ongoing commit-ment to Angola and to the continueddevelopment of oil and gas resources inthe country.”

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OG 4 News+Pet.indd 172 26.11.2018 12:36:35

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ASIA

OMV and Sapura Energy enter into a strategic partnershipSapura Energy Berhad (Sapura Energy)and OMV signed a Share SubscriptionAgreement and a Shareholders’ Agree-ment to form a strategic partnership.Under the agreements, OMV Exploration& Production GmbH, a wholly-ownedsubsidiary of OMV Aktiengesellschaft, willbuy a 50% stake of the issued share capi-tal in a newly-formed joint venture com-pany, SEB Upstream Sdn Bhd. This isbased on a total enterprise value of up toUS$ 1.6 bilion which comprises an equityvalue of up to US$ 1,250 milion and debtof US$ 350 milion.OMV will pay US$ 540 milion for a 50%interest in SUP at closing by subscribing tonewly issued shares. In addition, the par-ties agreed to an additional considerationof up to US$ 85 milion based on certainconditions mainly linked to the resourcevolume in Block 30, Mexico at the time oftaking the final investment decision. Bothparties have also agreed to refinance theexisting intercompany debt of US$ 350milion.Sapura Upstream is a major independentoil and gas company based in Malaysiawith an expected life of field production ofapproximately 260 milion boe and stronggrowth prospects. Production and devel-opment assets are located in shallow wa-ters offshore Malaysia. Sapura Upstream’sproduction entitlement in 2017 was ap-

proximately 4.1 milion boe/a, from fieldsin Peninsular Malaysia. Sapura Upstreamhas two natural gas exploration and pro-duction blocks offshore Sarawak in a well-developed area with existing infrastruc-ture. The significant discoveries in itsSK408 fields offshore Malaysia between2014 to 2017 showcase Sapura Upstream’sstrong in-house upstream capabilities. Thedevelopment of the SK408 gas fields is ontrack and first gas is expected in 2020 witha significant ramp-up in 2023. This wouldlead to an estimated total plateau produc-tion entitlement of approximately 21 mil-ion boe/a which translates to approxi-mately 60,000 boe/d. In addition to itsO&G assets in Malaysia, Sapura Upstreamalso has access to exploration blocks inNew Zealand, Australia and Mexico.“The oil and gas demand is expected to in-crease by 20% until 2030 in Malaysia andOMV is taking the opportunity to capital-ize on this growing market. The coopera-tion will allow OMV to enter into a part-nership with a highly esteemed regionalindependent company and will supportour Upstream strategy towards establish-ing Australasia as a new core region”, saidRainer Seele, CEO and Chairman of theExecutive Board, OMV Group.Johann Pleininger, OMV Board MemberUpstream and Deputy Chairman of theExecutive Board: “This acquisition will

add attractive reserve volumes to ourportfolio and result in a significant near-term increase in production. As Asia Pa-cific is an attractive growing market, Ma-laysia will represent OMV’s platform forfurther regional growth.”“OMV’s expansion strategy into Asia Pa-cific bodes well with Sapura Upstream’slong-term growth targets. We believe thepartnership will create sustainable growthfor the business, realising synergies fromboth sides to achieve our vision of creatingthe largest regional independent O&Gcompany”, said Tan Sri Dato’ Seri ShahrilShamsuddin, President and Group ChiefExecutive Officer, Sapura Energy.As part of the agreement, the manage-ment of the partnership will be based inMalaysia and there will be equal repre-sentation from both sides for the board ofdirectors. OMV intends to fully consoli-date Sapura Upstream in its financialstatements.Completion of the transaction is subject toconditions including Sapura Energy’sshareholder approval, Petronas approvaland other third party consents as well asfinalization of the transaction documentsincluding ancillary agreements.

n

LYBIA

National Oil Corporation, BP and Eni agree to work to resume exploration in LibyaLibya’s National Oil Corporation, BPand Eni signed an letter of intent ex-pected to lead to Eni and BP workingtogether to resume exploration activi-ties on a major exploration and produc-tion contract in Libya.The parties agreed to work towards Eniacquiring a 42.5% interest in the BP-operated exploration and productionsharing agreement (EPSA) in Libya. Oncompletion, Eni would also become op-erator of the EPSA. BP currently holdsan 85% working interest in the EPSA,with the Libyan Investment Authorityholding the remaining 15%.Eni have existing exploration and pro-duction activities and infrastructure ad-jacent to onshore areas of the EPSA.Transferring the operatorship to Enicreates the opportunity for the resump-tion of activity following completion ofthe transaction and relevant regulatoryapprovals.NOC chairman Mustafa Sanalla com-mented: “This agreement is a clear sig-nal and recognition by the market of

the opportunities Libya has to offer andwill only serve to strengthen our pro-duction outlook. The agreement’s socialdevelopment guarantee is an importantsign of our joint commitment to ourstaff and the communities in which wework. This initiative will hopefully drivefurther inward investment and facilitatehigher production levels.”Bob Dudley said: “This is an importantstep towards returning to our work inLibya. We believe that working closelytogether with Eni and with Libya willallow us to bring forward restarting ex-ploration in these promising areas.”Claudio Descalzi said: “This is an impor-tant milestone that will help to unlockLibyan exploration potential by resum-ing EPSA operations that have remainedsuspended since 2014. It contributes to-wards creating an attractive investmentenvironment in the country, aimed atrestoring Libya’s production levels andreserve base by optimizing the use ofexisting Libyan infrastructure.”“This is an important step towards re-

turning to our work in Libya. We be-lieve that working closely together withEni and with Libya will allow us tobring forward restarting exploration inthese promising areas”, added Bob Dud-ley, group chief executive.The EPSA includes three contract areas,two in the onshore Ghadames basin andone in the offshore Sirt basin, coveringa total area of around 54,000 km2. Orig-inally awarded in 2007, work on theEPSA has been suspended since 2014.As part of the LOI, the signatories alsoreconfirmed their commitment to pro-mote technical training and other socialinitiatives in Libya.As set out in the LOI, the companies in-tend to finalise and complete all agree-ments by the end of this year, with atarget of resuming exploration activitiesin 2019.

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OG 4 News+Pet.indd 174 26.11.2018 12:37:58

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Total and Sempra Energy sign MOU for development of North American LNG export projects

Sempra Energy and Total S.A. have en-tered into a Memorandum of Under-standing (MOU) that provides the frame-work for cooperation in the developmentof North American LNG export projects.The scope of MOU covers continuing thedevelopment of the Cameron LNG lique-faction-export project in Louisiana andEnergía Costa Azul (ECA) liquefaction-export project in Baja California, Mexico.The MOU between Sempra Energy andTotal contemplates Total potentially con-tracting for approximately up to 9 milliont/a of LNG offtake across Sempra Ener-gy’s LNG export development projects onthe U.S. Gulf Coast and West Coast ofNorth America, specifically CameronLNG Phase 2 and Energia Costa Azul(ECA) LNG. Total, which is already apartner of Cameron LNG joint venturewith a 16.6% stake, also may acquire anequity interest in ECA LNG.“The U.S. is increasing its global leader-ship position in the production of oil and

natural gas”, said JeffreyW. Martin, CEO of SempraEnergy. “In large measure,the next step in fulfillingour country’s energy po-tential is the developmentof critical export infra-structure for LNG. SempraEnergy has a long-termgoal of developing morethan 45 million t/a of LNGexport capacity in North

America. That is why our relationshipwith Total is so important. We plan toleverage the competitive strengths ofboth companies to accelerate develop-ment of North American LNG exports toglobal markets.”“This relationship with Sempra Energywill support our goal of building a diverseportfolio of LNG supply options that of-fers our customers flexibility, reliabilityand low-cost North American naturalgas”, said Patrick Pouyanné, chairmanand CEO of Total S.A. “We are pleased tocollaborate with Sempra Energy and theother Cameron LNG co-owners to ex-tend the Cameron LNG project and tofurther enhance its competitiveness, butalso participate in the development of ex-port capacity on the West Coast of Mexi-co, which will benefit from synergieswith existing infrastructure and from asignificant shipping cost advantage forcustomers in Asia.”The $ 10 billion Phase 1 of the Cameron

LNG joint-venture liquefaction-exportproject includes three liquefaction trainswith approximately 14 million t/a of ex-port capacity under construction in Loui-siana. Commissioning of the first train isnow under way and all three trains areexpected to be producing LNG in 2019.Phase 2 of the Cameron LNG project,previously authorized by FERC and beingdeveloped jointly by the Cameron LNGco-owners, encompasses up to two addi-tional liquefaction trains and up to twoadditional LNG storage tanks with ap-proximately 9 million t/a of capacity.ECA Phase 1 is a one-train facility withan expected total export capacity of 2.5million t/a, utilizing the existing LNG re-ceipt terminal’s tanks, loading arms andberth. ECA Phase 2 is expected to haveadditional export capacity of 12 milliont/a of LNG. The ECA project is located inBaja California, Mexico and will be sup-plied with natural gas from the UnitedStates.Development of LNG export facilities issubject to a number of risks and uncer-tainties, including obtaining binding cus-tomer commitments, required regulatoryapprovals and permits, securing financ-ing, completing the required commercialagreements and other factors, as well asreaching a final investment decision. Theultimate participation by Total remainssubject to finalization of definitive agree-ments, among other factors. n

NORTH AMERICA

BP completes purchase of BHP assets in US onshoreBP has completed the $10.5 billion acqui-sition of BHP’s U.S. unconventional assetsin a landmark deal that will significantlyupgrade BP’s U.S. onshore oil and gasportfolio and help drive long-term growth.The acquisition – which was announcedin July and closed as scheduled on Octo-ber 31 – adds oil and gas production of190,000 boe/d and 4.6 boe of discoveredresources in the liquids-rich regions of thePermian and Eagle Ford basins in Texasand in the Haynesville natural gas basin inEast Texas and Louisiana.Following integration, the transaction willbe accretive to earnings, is estimated togenerate more than $ 350 million of an-nual pre-tax synergies and is expected toboost Upstream pre-tax free cash flow by$ 1 billion, to $ 14–15 billion in 2021.“By every measure, this is a transforma-tional deal for our Lower 48 business. It isan important step in our strategy of grow-ing value in Upstream and a world-classaddition to BP’s global portfolio”, said Ber-nard Looney, BP’s Upstream chief execu-

tive. “We look forward now to safely inte-grating these great assets into our businessand are excited about the potential theyhave for delivering growth well into thenext decade.”BP’s Lower 48 business also announcedthat it is changing its name to BPX Energy.The change marks a new era of growth forBP’s U.S. onshore oil and gas unit, whichhas operated as a separate entity since2015 and has achieved material improve-ments in operational and financial perfor-mance since then.“Our mission is to build an organizationimbued with a strong, inclusive, modernculture where everyone is respected, sup-ported, and encouraged to achieve theirhighest potential and career aspirations;an organization that leads the industry inthe protection of people and the environ-ment, while simultaneously creating sig-nificant value for BP’s shareholders”, saidDave Lawler, CEO, BPX Energy.The BP portion of the business’s newname reflects that it remains wholly-

owned by BP and a strategic businesswithin BP’s Upstream organization. The“X” stands for exploration – both thesearch for new oil and gas resources aswell as for new ideas and methods to fun-damentally improve the business.“We are exploring how to improve everyaspect of our business”, said Dave Lawler,CEO of BPX Energy. “Our mission is tobuild an organization imbued with astrong, inclusive, modern culture whereeveryone is respected, supported, and en-couraged to achieve their highest poten-tial and career aspirations; an organizationthat leads the industry in the protection ofpeople and the environment, while simul-taneously creating significant value forBP’s shareholders.”“While we have more to do, we havemade great progress toward our goals,while also delivering material value toBP,” said Lawler.

n

OG 4 News+Pet.indd 175 26.11.2018 12:37:58

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CANADA

Equinor successful bids for three new licences offshore Newfoundland

CanadaEquinor and its partners were thesuccessful bidders for new explorationparcels in the prolific Jeanne d’Arc basin,offshore Newfoundland.

Equinor will operate two exploration par-cels, NL18-CFB01-14 (Equinor Canada70%, Husky Energy 30%) and NL18-CFB01-15 (Equinor Canada 60%, Suncor

Energy 40%), totalling 4,126 km² and willparticipate in the Suncor Energy-operatedparcel NL18-CFB02-01, 1,425 km², (Sun-cor Energy 40%, Equinor Canada 30%,Husky Energy 30%).“We are pleased to have secured signifi-cant acreage and new exploration oppor-tunities offshore Canada. The successfulbids aligns with Equinor’s strategy of de-veloping our position in prolific basins”,said Tim Dodson, Equinor’s executive vicepresident for exploration.“These exploration investments provideEquinor an important opportunity to ad-vance our position in a region where wehave a well-established exploration port-folio while we continue to evaluate andmature our existing exploration assets inthe Flemish Pass Basin”, said Dodson.Equinor has been active in Canada since1996, and operates the 2013 Bay du Norddiscovery, located in the Flemish Pass Ba-sin. Equinor also holds an extensive ex-ploration and partner-operated develop-ment position offshore Newfoundland,with partnership interests in the produc-ing Hibernia, Terra Nova and Hebronfields.

n

EID Energie Informationsdienst GmbH Banksstr. 4 20097 Hamburg Tel. 040/303735-0 Fax 040/303735-35 [email protected]

EID Energie Informationsdienst GmbH Banksstr. 4 20097 Hamburg Tel. +49 (0) 40/303735-15 [email protected] www.oilgaspublisher.de

Exclusively for subscribersEach subscription includes access to the online archive viawww.oilgaspublisher.deIn the subscriber area, all articles, news and product informations can be viewed fromthe January 2000 issue searched, printed or archived by topic, title, keyword and author.

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INDONESIA

Total signs a Memorandum of Understanding with the state of Papua New Guinea

Total and its partners ExxonMobil and OilSearch have signed a Memorandum ofUnderstanding (MoU) with the Independ-ent State of Papua New Guinea definingthe key terms of the Gas Agreement forthe Papua LNG project.The MoU was signed during the Asia Pa-cific Economic Conference (APEC) in PortMoresby, in presence of Peter O’Neill,Prime Minister of Papua New Guinea, andPatrick Pouyanné, Chairman and CEO ofTotal. The proposed Gas Agreement is ex-pected to be finalized by Q1 2019.Total is the operator of the Elk and Ante-

lope onshore fields and is the largestshareholder in PRL-15 with a 31.1% in-terest, alongside partners ExxonMobil(28.3%) and Oil Search (17.7%), post theState back-in right of 22.5%.The Papua LNG Project will encompasstwo LNG trains of 2.7 million t/a each andwill be developed in synergy with the ex-isting PNG LNG project facilities. Total andits partners have agreed to launch the firstphase of the engineering studies of thisproject.“The MoU signed by the State of PNG andthe partners of the Papua LNG project is

an important step in all the parties’ com-mitment to the project”, said PatrickPouyanné, Chairman and CEO of Total.“Investing in LNG is a long term enter-prise and our objective is to be able tomake the project as competitive as possi-ble. Total being the second-largest worldprivate LNG player, we are fully commit-ted to the success of the Papua LNG pro-ject, which benefits from a favorable geo-graphical location close to Asian markets.”

n

BRASIL

Total enters the fuels retail sector with the acquisition of Grupo Zema distribution businessTotal has entered into an agreement withBrazilian company Grupo Zema to ac-quire its fuel distribution company ZemaPetróleo, its reseller and retailer arm ZemaDiesel as well as its importation companyZema Importacao.Zema Petróleo currently manages an ex-tensive branded network of 280 dealer-operated service stations and several oilproducts and ethanol storage facilities,most of them located in the states of Mi-nas Gerais, Goiás and Mato Grosso. It isalso carrying a supply activity to third par-ty retail stations in the same regions.With this acquisition, Total is stepping intothe largest South American market for the

retail of fuels and into the worldwide sec-ond largest low-carbon biofuels market.The Group intends to expand its activitiesin the area with the objective to doublethe number of branded stations withinfive years, particularly throughout theSoutheast and Central-West regions inBrazil.“This acquisition is in line with our strate-gy to expand in large growing marketsand in biofuels markets under our Climateroadmap”, commented Momar Nguer,President Marketing & Services and mem-ber of the Executive Committee at Total.“By entering the retail market today, Totalis also confirming its long-term commit-

ment to the Brazilian market. Driven byour dedication to our customers, we in-tend to bring our high-quality products,operational excellence and innovative of-fers & services to the Brazilian customers.”The rebranding of the current 280 servicestations will start in 2019 and new flag-ships stations will be open on selected lo-cations. Total will offer Brazilian consum-ers and business customers the company’sfull lineup of fuels, including its Total Ex-cellium premium fuel, hightech lubricantsand a broad range of products & services.This acquisition is subject to prior approv-al of the Brazilian competition authority.

n

OG 4 News+Pet.indd 177 26.11.2018 12:38:02

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ABU DHABI

Total and ADNOC join forces to launch unconventional gas exploration in Abu DhabiTotal and Abu Dhabi National Oil Com-pany (ADNOC) have signed a concessionagreement to launch an unconventionalgas exploration program in the high po-tential Diyab play that spreads over 6000km2 to the west of the prolific ADNOC on-shore concession, in Abu Dhabi.The concession allows for two explorationand appraisal phases for a period of up toseven years, followed by a 40 year devel-opment and production period. Total willoperate the exploration phase of this newconcession with a 40% interest, whileADNOC will hold the remaining 60% in-terest. In case of positive exploration, thismulti-Tcf opportunity will be developed instages in line with the growing gas de-mand in the UAE and potential export op-portunities.This agreement is a result of close cooper-ation between ADNOC and Total towardsidentifying ways of unlocking the uncon-ventional gas potential in Abu Dhabi, To-tal bringing its expertise, personnel andtechnical know-how.

“We are pleased to be the first internation-al company to pioneer unconventionalgas exploration in Abu Dhabi alongsideADNOC. This agreement consolidates ourlongstanding and strategic relationship ina country and region that we know well.We are committed to supporting the UAEin meeting its ambitions to unlock this sig-nificant unconventional gas resource”,said Patrick Pouyanné, Chairman andCEO of Total. “The Diyab play has the po-tential to be a high impact play rankingalongside the most prolific North Ameri-can shale gas plays, and is an excellent ad-dition to our exploration portfolio.”

Total in the United Arab EmiratesTotal has been present in the United ArabEmirates for almost 80 years and has builta strong presence, reflected by the sizeand diversity of its assets and partnerships.In 2017, the Group’s equity production inAbu Dhabi was 290,000 boe/d.In partnership with ADNOC, Total holds:– 20% in the Umm Shaif & Nasr and 5%

in the Lower Zakum 40-year conces-sions (former ADMA)

– 10% in the 40-year ADNOC Onshoreconcession (former ADCO)

– 15% in ADNOC Gas Processing (formerGASCO)

– 5% in ADNOC LNG (former ADGAS)– 24.5% in Dolphin Energy LtdIn addition, Total owns 100% stake andoperates the Abu Al Bukoosh field.In the power production sector, Total isalso a partner in the Shams project, theworld’s largest concentrated solar powerplant in operation (100 MW), inaugurat-ed in 2013, and since 2001 in the Taweelahwater desalination and power plant,which produces around 20% of Abu Dha-bi’s water and power consumption.The Group also has a leading position inthe manufacturing and marketing of awide range of automotive and industriallubricants with a blending plant in theUAE, supplying the whole region.

n

ASIA

Stepping up the LPG activity in south-east Asia

Equinor and Global Petro Storage (GPS)have entered into a long-term agreementfor a terminal and storage for LPG (Liqui-fied Petroleum Gas) volumes in PortKlang in Malaysia. GPS will build a newfacility to execute this agreement withstart-up of operations planned for mid-2021. Equinor will bring LPG to the ter-minal and sell into the domestic market inMalaysia as well as selling volumes tomarkets like Bangladesh, the Philippines,India, Indonesia and Vietnam.Equinor is already a significant LPG playerwith around 10 % of the global water-borne LPG volumes.

With the new terminal and storage Equi-nor aims to capture a larger share of theattractive LPG market in South-East Asia.LPG consists of the liquified gases propaneand butanes and is used for transport andindustrial purposes as well as cooking, hotwater systems and heating. Use of LPG isrecognized as being an attractive energyoption for reducing greenhouse gases aswell as improving indoor and outdoor airquality.“Malaysia is an attractive market and webelieve that we will be a competitive sup-plier to the wholesalers of LPG into thedomestic market. The terminal and stor-

age are also strategically located for blend-ing and selling to other growing marketsin the region”, says Molly Morris, vicepresident for Products and Liquids inEquinor ASA.“We will source LPG from the North Sea,North Africa, the Middle East and Austral-ia and utilize the opportunities the termi-nal and storage and our shipping positionsgive us to create value and strengthen ourcompetitiveness”, says Morris and contin-ues “This agreement is an example of howwe are pursuing our strategy for asset-backed trading”.As part of the agreement, Equinor willhave an option to acquire an ownershipshare of the new storage and terminal,where Equinor will be the only user.“Flexibility and robustness have beensome of our key drivers for entering inthis agreement”, says Giuseppina Ragone,vice president for Manufacturing andStorage in Asset Management and contin-ues:“The storage offers us considerable flexi-bility as it can receive gas tankers of allsizes and we can choose if we want toblend and prepare smaller quantities todeliver into the domestic market or othercountries in the region, depending onwhich is most attractive. This way, activeuse of our assets can add value to our LPGbusiness and be a long-term basis for val-ue creation”, Ragone says. n

OG 4 News+Pet.indd 178 26.11.2018 12:38:03

PPRROODDUUCCTTIIOONN EENNGGIINNEEEERRIINNGG

OG 179OIL GAS EUROPEAN MAGAZINE 4/2018

Gravel Pack Monitoring With a Strain SensingFiber Optic CableBy M. LIPUS, T. REINSCH, C. SCHMIDT-HATTENBERGER, J. HENNINGES and M. REICH*

AbstractAchieving and maintaining orehole in-tegrity is a challenge in the successful

and sustainable utilization of hydrocarbons,geothermal energy and sites for geological stor-age. Information about the integrity of casingand cement is mainly available from logswhich only produce data at the moment ofmeasurement and require running in holewith logging tools. This study investigates thepotential for real-time monitoring of a fiberoptic distributed strain sensor, which is per-manently installed behind the casing of a geo-thermal well. Each location of the fiber con-veys information about its temperature andmechanical stress state when interacting witha laser pulse, which is sent through the fiber.This article shows field data from a gravelpack installation and compares the results toconventional borehole measurement equip-ment during the completion of a geothermalwell. It was found that the mechanical strainacting on the fiber matches results from con-ventional downhole logging tools for densitymeasurements. Both downhole cable and cas-ing pipe experience measurable axial compres-sion at locations where wellbore fluid is beingreplaced by gravel. Moreover, observation ofthe strain response over the initial hours postcompletion of the gravel packing reveals anongoing movement of annular material (sag-ging and compaction of filter gravel pack).

IntroductionGeothermal energy provision mightplay a vital role in meeting the energy

demand of modern society. One key ad-vantage of geothermal power comparedto other renewable energy resources is itshigh availability factor. On average, geo-thermal power plants are operational75% of the time [1]. In comparison, en-ergy from wind (21%), solar (14%), hy-dro (42%) and biomass (52%) are farless reliable for constant energy provi-sion. The primary factor why geothermalenergy is not permanently available is

due to well intervention and mainte-nance of surface infrastructure (e.g.pumps and pipelines). With respect tothe well, the integrity of the installed tu-bular casing and cement is of utmost im-portance during the operational lifetimeof a geothermal well. In addition, subsur-face stresses resulting from, e.g. reservoircompaction, can lead to severe damageto the casing pipe [2]. In sedimentaryreservoirs, a gravel pack is usually in-stalled in the open hole section betweenthe slotted liners and the permeable res-ervoir horizon. It mitigates instability ofthe rock formation and reduces produc-tion of the sand phase [3]. Conventionalborehole measurements are conductedwith wireline logging tools, which re-quire shutting in of the well and enteringthe borehole with sensor equipment. Apossible method to optimize well inter-ventions is by installing fiber optic cablespermanently in the annulus between thecasing and cement. This technology al-lows quasi-continuous, real-time moni-toring of the subsurface infrastructure. Infiber optic sensing technology, the termdistributed refers to the ability to meas-ure anywhere along a continuous lengthof a sensing fiber.Over the last two decades, much workhas been published on the analysis of dis-tributed temperature sensing (DTS) inwellbore applications to assess the ther-mal properties of downhole lithologiesand water bearing fractures [4–6]. DTSdata was further applied to perform ce-ment job evaluations and well bore in-tegrity analysis during and after produc-tion tests [7, 8]. Distributed strain sens-ing (DSS) is a collective term that com-prises a range of technologies beingcapable of resolving mechanical strainalong a fiber. The oldest and most promi-nent approach for quasi-distributed fiberoptic strain sensing uses fiber bragg grat-ings (FBG). An FBG is formed by an arti-ficial, periodic change of the refractiveindex neff along a defined interval of afiber core with a grating period Λ. A nar-row band of the incident optical fieldwithin the fiber is reflected by successive,coherent scattering from the index varia-tion [9]. The strongest interaction occursat the Bragg wavelength λB according to

(1)

Strain sensitivity from the wavelength λBoriginates from the change in Λ due todeformation and from a change in neff

due to temperature and the strain-opticeffect [10]. Strictly speaking, FBG arepoint sensors, since the number of FBGthat can be multiplexed in a single fiber islimited. The primary limiting factor forthe number of gratings in a single fiber isthe optical budget. Previous publicationsshow results from a set of over 2000 grat-ings over a length of 190 m [11]. For truedistributed strain sensors, the mostprominent technology for DSS is basedon Brillouin Optical Frequency DomainAnalysis (BOFDA) [12]. Commerciallyavailable BOFDA systems provide a strainaccuracy of 2 µε at spatial resolution of 1m up to 50 km. This technology requiresaccess from both ends of a fiber.The fiber optic interrogator used in thiswork is an optical backscatter reflectom-eter (Luna OBR 4400) based on the prin-ciple of Optical Frequency Domain Re-flectometry (OFDR). This technique hasbeen described in detail in previous pub-lications [13–15]. In a nutshell, an OBRtrace is a spectral fingerprint of an opticalfiber at a given temperature and straincondition. Natural heterogeneity of mol-ecules that make up the glass fiber can beinterpreted as weak, randomly distribut-ed FBG with arbitrary grating periods.Although being random, the spectral re-sponse of the backscattered light is steadyand repeatable. Changing the tempera-ture or the stress state at any interval of afiber will lead to a linear shift in the spec-tral response ∆ν of the backscatteredlight. The correlation between a changein temperature ∆T and the spectral re-sponse ∆ν is caused by the thermal coef-ficient of the refractive index and thethermal expansion coefficient [16]. Thecorrelation between a change in strain ∆εand the spectral response ∆ν is caused bylength changes of the fiber. The spectralresponse is hence given by the followingformula:

1 1· ·TK T Kεν ε− −∆ = ∆ + ∆ (2)

where KT and Kε are the temperature andstrain calibration constants: KT= 0.801°C/GHz, and Kε=6.67 µε/GHz [17]. Becauseof the cross sensitivity of strain and tem-perature, an independent temperaturemeasurement on a separate fiber (e.g.

* Martin Lipus, Thomas Reinsch, Cornelia Schmidt-Hatten-berger, Jan Henninges, GFZ German Research Centre forGeosciences, Potsdam, Germany; Matthias Reich, TU Ber-gakademie Freiberg, Freiberg, Germany. E-mail: [email protected]

0179-3187/18/IV DOI 10.19225/181202© 2018 EID Energie Informationsdienst GmbH 2B effnλ =

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with a DTS system or a strain free fiber) isnecessary to correct for the temperatureeffect.Thorough mechanical coupling of thefiber with the environment has to be giv-en for DSS measurements, independentof which system is used for strain sens-ing. For example, it is not possible toquantify the behavior of a casing intervalwith DSS, if no bond between the twomaterials is given. Previous publicationsshow that axial compression, bucklingand shearing of a casing pipe can bemeasured when wrapping a fiber helical-ly along the outer diameter of the pipe[11, 18]. In the published cases, fibers areeither glued to the surface using epoxyresin or embedded into the material it-self.The preparation time for such an installa-tion is high and wet connectors are usedfor downhole implementation to connectthe prepared fiber optic installation to afiber that connects to the read-out unit atthe surface. In this study, it is shown thatDSS data can be obtained from a linearfiber optic cable installation connectedonly to the casing by several meterspaced clamping points. The cable is aconventional downhole cable, which isnot designed to pick up strain. In order touse the cable for DSS, the strain transla-tion from the outside of a multi-layer ca-ble to the fiber is assessed in two ways: bylaboratory experiment and analytical cal-culation. The calibration parameters,which were determined, are later used toanalyze the mechanical response of thefiber caused by gravel packing of a shal-low geothermal well.

Cable Strain CalibrationA fiber optic cable for downhole ap-plication consists of rigid layers that

protect the fiber from the harsh ambientconditions. These layers reduce the strainresponse of the fiber to external mechan-

ical perturbations. The strain response offiber optic cable deployed in the well inthis study was accessed analytically andexperimentally. A concept to estimatefiber optic coupling analytically is by cal-culating the mechanical stiffness of eachcable component individually and addingup the values to a cable specific stiffness.Special attention is given to the viscousgel filling layer between the fiber andsteel tube. Such a thixotropic fluid isused to protect the optical fibers duringmovement of the cable [19]. Previousstudies indicate that for low shear stress-es, the gel filling can be regarded as anelastic medium [20].Typically, gels are designed to have ayield point of 35−140 Pa depending onthe application [21]. Stresses below theyield strength result in elastic deforma-tion. The stiffness k of each component isdefined as the product of its cross sec-tional area A and its material specificYoung’s modulus E.

1 1

n n

i i ii i

k k AE= =

= =∑ ∑ (3)

The Young’s modulus was first intro-duced in Hooke’s law [22] and it de-scribes the force needed to generate acertain strain of a material:

Eσ ε= (4)

where σ is the stress and ε the strain.With respect to the stiffness k, the stress σis can be expressed as:

F kA A

σ ε= = (5)

A sketch of the cross section of the cableused in this study is shown in the firstsubplot of Figure 1. The experimental ap-proach was achieved by hanging an in-terval of the downhole cable vertically ina temperature stable laboratory (Fig. 1,right subplot). In order to approximatethe conditions that would occur at thebottom of a shallow well with 230 m

depth, a fiber optic extension of 190 m isconnected in between the OBR systemand the downhole cable sample, whichhas a length of 23 m. The cable is me-chanically clamped with a vice to keep itimmovable. At a distance of 1 m belowthe clamping point, an aluminum table isclamped to the cable. Pre-tension is ap-plied to the cable by hanging a mass of 2kg below the weight holder. This ensuresa straightened positioning of the rigid ca-ble to mimic the field installation. Aftermeasuring a baseline/reference trace, theweight on the aluminum table was suc-cessively increased (5 g, 10 g, 20 g, 30 g,40 g, 60 g, 80 g, 100 g, 150 g, 200 g, 300g). After each weight increase, one meas-urement was taken directly, a secondmeasurement after 5 min and a thirdmeasurement after 10 min. The weightswere subsequently removed one afteranother with resulting weights on the ta-ble of: 200 g, 150 g, 100 g, 40 g, 0 g.

Fiber Optic Field InstallationThree fiber optic cables were installedfor permanent use in a research well

for aquifer thermal energy storage inBerlin (ATES Fasanenstrasse, Gt BChb1/2015) (Fig. 2). The outermost cablewas installed to a depth of 192 m and lo-cated behind a conventional 11 3/4” steelanchor casing, which has a landing depthof 212 m. The cable was installed in aloop, so that two cable ends are accessibleat the surface. During installation, the ca-ble is fixed with a strapping machinetwice per joint, one close to the couplingand one in the middle. The joints have anominal length of ca. 11.5 m so that thecable clamping spacing is 5.75 m. Cen-tralizers were installed at every thirdjoint below the coupling. The anchor cas-ing was cemented with an inner string(stinger) cementation. The cement typewas class G Portland cement (CEM IIIB32.5).Subsequently, the well was drilled to 570m to reach the target reservoir horizon.However, due to inadequate reservoirproperties, a cement plug was pumped todevelop a shallower reservoir intervalfrom 222–227 m. The TOC of the cementplug is located at 259 m. A productioncasing was installed to 235 m. The pro-duction casing consists of a DN80 casing(steel grade: 1.4571, pipe thickness: 6mm) with a 10 m wire-wrapped screenand a crossover to 6 5/8” composite ma-terial (glass reinforced polymer). Twofiber optic cables were installed on theoutside of the casing. One of the cables isinstalled in a loop, containing two multi-mode fibers and one cable single endedcontaining both single-mode and multi-mode fibers. The cables were clamped tothe casing in intervals of 5 m. Addition-ally, two PE tubes with an OD of 4 cm

Fig. 1 Downhole cable cross section and experimental setup for strain calibration. Field cablemanufactured by nkt cables GmbH

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were installed, one to a depth of 211.5 mand one to 99 m. The deeper PE tube wasused later for cement injection and theshallower PE tube was used to lift re-maining fluids from the annulus afterwell completion.A gravel pack was installed to developthe filtered interval of the well. Gravelwas added into the annulus at the sur-face to fill the interval from the cementplug up to the transition to the anchorcasing at 212 m. The required gravel vol-ume was calculated from a caliper log-ging trip in the open hole section. Duringthe gravel packing, the setting height wasconstantly monitored with a wireline γγ-density-log inside the production casing.Once a setting height of 213 m wasreached, gravel addition and loggingwere stopped. A filling up to 212 m wasestimated from the remaining gravel,which was still in suspension in the an-nulus. The subsequent cement job wasscheduled for 10 hours after completinggravel packing.Just before the start of the cementation, aquality control on the setting height ofthe gravel pack was performed with a γγ-density-log. The measurement revealedthat the gravel head dropped by 4 m to adepth of 216 m compared to the earliermeasurement. Consequently, the sched-uled cementation had to be delayed byone day due to a remedial gravel packingoperation. After reworking of the gravelpack, the well completion continuedwith cementation of the shallower inter-val with a TOC at 105 m through thedeeper PE tube.

ResultsFirst, results from the fiber optic ca-ble calibration are shown. After

that, field data from the primary gravelpack. In the third part, data after primarygravel packing and the remedial gravelpacking operation are shown.

Stress transmission within a complex cableThe analytical solution for the cable cu-mulative stiffness k with the given cabledesign (Tab. 1) was calculated with Eq. 3and 5. It resulted in a value of k = 597 ±36 kN. For the experimental approach,the measured spectral shift ∆ν value wastranslated to strain according to Eq. 2.

Figure 4 shows the correlation of thespectral response of the downhole cableto mechanical strain for the analyticaland experimental approach (subplot onthe right). An example of the distributedstrain reading as a function of the loca-

tion along the cable is shown (subplot onthe left). The result indicates a good fitbetween the analytical calculation andexperimental measurements in the in-vestigated strain range up to 5 µε (equi-valent to a length change of 5 µm/m).The measured spectral shift shows a tem-poral variation after each weight place-ment. After starting with relatively highvalues just after weight placement, the∆ν reading reduces within the next 5−10min. It was observed, that after 10 min∆ν remains constant. At low deformationof the test cable (ε < 1·10-6), ∆ν driftsstrongly over time. At ε > 1·10-6, ∆ν indi-cates more steady and repeatable values.During weight reduction, ∆ν shows aneven lower drift over time at each weight

Fig. 2 Well design of the ATES Berlin (Gt BChb 1/2015) with fiber optic cable configurationafter completion (not to scale)

a) b)

Fig. 3 a) Cable clamping configuration 2 m above shoe of production casing. Cable is securedby a centralizer (MD: 233 m). b) Cable clamping configuration at cross over from DN80to 6 5/8”. Blue PE cement injection tube visible at the top. A centralizer above thecrossover location remains hidden in this picture (MD: 211 m)

Tab. 1 Design of the fiber optic cable that was installed in ATES Fasanenstrasse. TypicalYoung’s moduli (E) according to: [21, 23, 24]

Material Units ID OD Area A E k Sharemm mm mm2 kN/mm2 kN %

glass fiber 5 – 0.13 0.06 60 1 18 3.1gel – 0.63 1.80 2.53 1e-07 2 3e-07 0.0stainless steel 1 1.80 2.00 0.60 210 ± 10 3 125 21.0bronze wires 12 – 0.65 3.98 110 ± 5 3 438 73.4LDPE* 1 3.30 5.50 15.21 1 ± 0.84 3 15 2.5*low density polyethylene Σk = 597 ± 36

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step. There is also a better linear regres-sion between ∆ν and ε during weight re-duction, indicated by the R2 values. Theexperiment shows that a withdrawal of amechanical load to initial conditions re-sults in an offset. An apparent fiber elon-gation of 1.5 µε was observed on return-ing back to 0 g for the measurement after

10 min. The linear regression with an er-ror defined by the standard deviation forthe increasing weights is –0.086 ± 0.009GHz/µε including all values at 0,5 and 10min. During weight reduction this valueis –0.129 ± 0.004 GHz/µε. It was also ob-served, that the strain signal is not onlyconfined to the stretched interval, but

also enters regions beyond the clampinglocation by up to 20 cm. In these loca-tions, no hysteresis was observed and thestrain readings returned to the initialstate.

Strain response during primary gravelpackingFigure 5 shows the downhole data thatwas gathered during the gravel packingof Gt BChb 1/2015. The subplots showpairs of γγ-profiles and DSS measure-ments that were gathered contempora-neously. The γγ-profile at the start (19:50)shows a low density below 2 g/cm3 overthe interval of 206 m to 235 m. Localdensity spikes display the connectors ofthe casing joints where the fiber optic ca-ble is clamped to the casing. Over time,the gravel head shows by the γγ-data anincrease in density to 2.5 g/cm3. The lastprofile (21:50) shows that the settingheight of the gravel pack lies at 213 m.The DSS profiles show that the gravelpack generates a negative strain signal onthe cable (cable relaxation/compression).The location of the strain signal corre-lates to the setting height of the gravelpack. The strain profiles are segmentedinto intervals, which match the clampingpoints of the cable to the casing. A strainresponse has a local maximum in be-tween two casing clamps. The cable re-laxation from gravel lies between 4−8 µε.The final setting height of the gravel liesin between two cable-clamping pointswith a narrower spacing (213 and 215m). The maximum stretching in this in-terval is 2 µε.15 minutes after completing the γγ-logging, an abrupt change in the stressstate of the downhole cable is observed atthe depth interval 215−228 m (grey pro-file with marker in 6th subplot). From theclamping point at 215 m going down-wards, the cable enters a tensional re-gime. Temperature that were measuredwith DTS (Fig. 7) show no response tothe gravel packing and overall tempera-ture variations do not exceed 0.2 °C(equivalent to a strain value of 1 µε).Consequently, the spectral response ofthe DSS data is dominated by mechanicalnature.The caliper reading shows the boreholegeometry in the open hole section priorto the gravel packing (far right on Fig. 5).In the interval 215−218 m, a washoutexists, where the borehole diameter lo-cally enlarges by a factor 3.Strain response after primary gravel packFigure 6 shows the data that was gath-ered after the primary gravel packing andγγ-logging stopped. During this time nowork was carried out on the well site andthe borehole was shut-in. Simultaneous-ly the well temperature increased by 1°C(equivalent to a strain value of 5.5 µε) inthe interval 222−228 m. The DSS signal

Fig. 4 Results from cable strain calibration. Left subplot: Example of a distributed strain profileduring mechanical perturbation over an interval of 1 m with a mass piece of 100 g fordifferent times after weight placement (1 – top clamping location, 2 – weight holder).Right subplot: analytical and experimental result of the correlation of strain over spec-tral shift for the available down-hole cable

Fig. 5 Comparison of γγ-logging and DSS downhole monitoring data during gravel packing.DSS profiles are calculated relative to the mechanical state of a DSS reference tracemeasured at 19:40. Black horizontal lines in first subplot mark locations of joints and ca-ble clamping location. These locations mark the points where strain signals on the cableare mechanically isolated from each other. The last subplot depicts the borehole geom-etry

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shows a continuous increase in strainover time in the interval 216−225 m upto 18 µε. Areas above and below thatshow no change in the stress state of thefiber optic cable.

During adjustment of the gravel pack thefollowing morning, the DSS shows a re-laxation/compression at the locationwhere the gravel is present up to a depthof 211 m.

DiscussionCable performanceThe fiber optic cable, which was

tested and deployed in the field was notinitially designed to measure strain. Thegel filling between the fibers and the steeltube and various different surroundingmaterials result in a complex mechanicalinteraction across the cable layers. Thelaboratory experiment shows hysteresiswhen removing a mechanical load onthe cable. The likely reason for that isthat the gel filling deformed plasticallyduring elongation. During relaxation ofthe cable, the gel movement is probablythe driving factor that created an appar-ent compression of the cable. The cableshows a better performance duringweight reduction than during an increasein load, as depicted by the R2 value.The stiffness values ki for each cable layerfrom Table 1 are used to calculate theforce at the surface of the optical fiber,i.e. the interface to the gel filling, and theinterface of the gel filling with the sur-rounding steel tube. At an elongation ofthe cable by 6 µε, the shear stresses arecalculated to be 11 Pa and 4 Pa, respec-tively. These values are a factor 3 lowerthat the lowermost reported yieldstrength for gels. Nevertheless, the me-chanical deformation of the cable ismeasured over several minutes to hours.Over these timescales, a plastic deforma-tion is likely to occur, as observed duringmechanical load change in the field ex-periment (Fig. 4). These are strong indi-cations for a differential movement be-tween the fiber and surrounding rigidlayers due to plastic gel flow. Exemplary,the DSS trace also shows that the fiberstrain response goes beyond the clamp-ing location of the vice and weight holderduring load changes. Although these ar-eas are mechanically isolated from thestrained interval, the fiber experiences atensional force. This is an important fea-ture with respect to the analysis of thefield data, where clamping locations areregarded as a mechanical isolation.

Cable buoyancy change during gravelpackingResults from the primary gravel packingshow a match between the wire-line γγ-density-log and fiber optic DSS data. Atthe location where gravel has settleddown, a relaxation of the fiber optic cableis observed. At locations where the cableis clamped to the casing, the DSS strainresponse tends to remain unchanged andunaffected by the gravel. In the crossoverlocation from DN 80 production casing to6 5/8” composite material, the cable wasclamped to the casing in very short inter-vals (211−215 m) to prevent damageduring installation (Fig. 3). Because ofthat, the fiber is much more mechanical-ly isolated than in adjacent locations.

Fig. 6 Fiber optic response hours after the primary gravel packing and during the adjustmentof the gravel head on the subsequent day. DSS is corrected with DTS data to infer thepure mechanical component of the measurement. For comparison, the last DSS tracefrom Figure 5 (22:04) is depicted in grey. The reference trace for all traces depicted hereis the same as during the primary gravel packing

Fig. 7 Comparison of γγ-logging and relative DTS downhole monitoring data during gravelpacking. Just as in the DSS plot of the gravel packing (Fig. 5), temperatures are calcu-lated relative to the DTS trace measured at 19:40. Black horizontal lines in first subplotmark locations of joints and cable clamping locations. Temperature variation does notexceed 0.2 °C. The last subplot depicts the borehole geometry

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However, as shown by the laboratoryanalysis, clamping locations do not iso-late a mechanical signal completely dueto plastic gel movement in the cable. Theclamping locations at 220 m and at 225m show a peak strain relaxation right atthe clamping location, which is only pos-sible with a strain translation beyond theclamping point. In the following, an ex-planation for the fiber optic relaxation isgiven by calculating the reduction ofgravitational forces on the cable due tothe gravel pack. The fiber optic cable hasa weight of 63 kg/km and a diameter of0.55 cm. Hence its density is 2.65 g/cm3.The well bore fluid prior to the gravelpacking has a density of 1 g/cm3 and theaverage clamping point distance of thecable to the casing is 5 m. With the givenparameter, the maximum apparentweight can be calculated. While beingsubmerged in fresh water, a maximalstatic gravitational force of 2 N acts onthe cable at the top clamping location.This additional force acts on the fiberwhen the reference baseline measure-ment is taken. A subsequent removal ofthat gravitational force would lead to arelaxation/apparent compression of thecable leading to a ∆ν of 0.5 GHz and astrain (relaxation) of 4 µε. These valuesmatch the measured DSS readings duringgravel packing, which are in the range of4−7 µε. Instead of hanging freely in theliquid column, the cable is embedded ingravel, which compensates the gravita-tional pull.At the same time the well tubular mate-rial experiences axial loading due to thepull force of the casing. The casing shoeof the production casing (235–230 m) in-duces a mechanical stress of 340 kPa onthe wire-wrapped screen (230–220 m)while being submerged in well bore fluidwith a density of 1 g/cm3 (Eq. 5). Like thedownhole cable, the casing pipe will ex-perience axial compression due to the re-placement of fluid by gravel. Assumingthe force to be evenly distributed overthe cross sectional area of the wire-wrapped screen and using a Young’smodulus for steel of 200 GPa, the strainresults in 2 µε (Eq. 5). The assumptionsused for this calculation underestimatethe actual strain, since the mechanicalstress will focus on a smaller cross sec-tional area due to the helical geometry ofsteel within the wire-wrapped screen.The increase in mechanical stress willhence increase deformation of the pipe.

Cable tension due to gravel sagging andcompactionThe well completion schedule was de-layed by one day due to installation of aremedial gravel pack. Subsequent con-solidation of the gravel head after theprimary gravel pack was detected by theDSS data. DSS data, which was gathered

continuously, shows an abrupt stressstate change of the fiber optic cableshortly after termination of the γγ-density-log (see trace 22:04 in Fig. 5).The cable experiences extension in theinterval between 215−223 m. This couldbe explained by a sudden consolidationof the gravel. The caliper reading shows asevere wash-out between 215−218 m. Itis probable that gravel kept consolidatingand additionally filled empty voids whichwere not filled with the primary gravelpack. Next to that, the tension on the ca-ble increases over night, indicating steadyand continuous compaction of the gravelinside the annulus in the interval from216−225 m. DSS measurements duringthe secondary remedial gravel pack showa similar cable relaxation from 210−216m as observed during primary gravelpacking.

Conclusions and OutlookThis study shows a match of DSSdata and conventional wireline γγ-

density-logging data. That is because thecable and the casing pipe experience axi-al compression when the surroundingliquid is being replaced by gravel. Eventhough the cable relaxation is as small as6 µm/m, it is readily detectable with thefiber optic interrogator. In addition, thecontinuous DSS logging reveals subse-quent sagging and compaction of the an-nular material in real-time after thewireline logging terminated. This studyalso shows that DSS data can be acquiredand analyzed quantitatively, even for acable of non-optimized design. However,for future installations it is recommendedto utilize a cable designed for strain sens-ing in order to mitigate the hysteresisduring load changes and to further im-prove the spatial and strain resolution.Strain monitoring of the gravel packing isjust the very first operation measuredwith the fiber optic cable installation. Thenext step will be to analyse the strain da-ta measured during the subsequent ce-mentation of the production casing. Overthe lifetime of this well, DSS monitoringcan be applied whenever required.

AcknowledgementsThis study has received funding from the Europe-an Union’s Horizon 2020 research and innovationprogram under grant agreement No 654497(GeoWell project) and the German Federal Minis-try for Economic Affairs and Energy (BMWi) underfunding code 03ESP409A.

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[23] H. Kuchling Taschenbuch der Physik. Carl HanserVerlag GmbH & Co. KG (2011).

[24] F. Cardarelli: Materials Handbook, A Concise DesktopReference, 2nd Edition. Springer (2008).

M.Sc. Martin Lipus studied Petro-leum Engineering at the TU Delft(NL). Since 2016 he has been work-ing as a PhD student at the GFZPotsdam with a focus on distributedstrain sensing for wellbore integrity

monitoring.

Dr.-Ing. Thomas Reinsch is a re-search scientist at GFZ working onfiber optic sensing technologies forwellbore applications. He studiedphysics and geology at University ofCologne and has PhD degree in pe-

troleum engineering from Clausthal University ofTechnology.

Dr. Cornelia Schmidt-Hattenberg-er holds a doctoral degree in Phys-ics from Friedrich-Schiller-Universi-ty Jena. She has over 20 yrs. experi-ence in development and applica-tion of sensors for geotechnical

projects. She joined the GFZ Potsdam in 1993 andworked in the fields of scientific instrumentation,rock mechanics and environmental geotechnics.

Dr. Jan Henninges holds a doctro-ral degree in the field of AppliedGeophysics from TU Berlin. Since2001 he is research scientist atGFZ. His research is focused onmonitoring of dynamic subsurface

processes, particularly applying fiber-optic sensingtechniques in boreholes.

Prof. Dr.-Ing. Matthias Reichstudied process engineering at theTU Clausthal. He worked as a devel-opment and product engineer forBaker Hughes from 1986 till 2006.Since 2006 he holds the chair for

Drilling Engineering and Mining Machinery at the TUBergakademie Freiberg.


EID Energie Informationsdienst GmbH Banksstr. 4 20097 Hamburg Tel. +49 (0) 40/303735-15 [email protected] www.oilgaspublisher.de


ERDÖLERDGASKOHLE

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ERDÖL ERDGAS KOHLE


Lipus_OGEM4.indd 185 26.11.2018 13:24:47



BEER: Bio Enhanced Energy Recovery –Innovative Carrier Fluid for ReservoirOptimizationBy K. KOGLER, M. PAVLOV and H. HOFSTÄTTER*

AbstractEnergy politics changed in the lastyears, therefore a need in an environ-

mental friendly option to optimize reservoirsevolved. The formulation of the Bio EnhancedEnergy Recovery fluid (BEER fluid) itself isknown in the drilling industry for years. AsBEER fluid, it will be used with changed con-centrations in other application areas.The aim of this research project is an opti-mised, economically friendly method of operat-ing in the field of hydraulic stimulation andsand control using a carrier fluid, the BEERfluid, in combination with glass proppants.The fluid consisting out of four components(water, linear polymer, potassium carbonateand glass proppants) needs to be adjusted tokeep the outstanding properties of its compo-nents, like friction reduction, corrosion inhibi-tion or clay stabilization, but also to get aneconomically and logistically friendly productfor the oil, gas and geothermal industry. Ad-ditional requirements are a good transport ca-pacity for the proppants, compatibility withrock formations and reservoir fluids and thepossibility for a controlled breaking of the flu-id for well clean up after treatment. Labora-tory results and the optimisation of the BEERfluid for the first field test will be shown in thisarticle.

IntroductionWorldwide oil, gas and geothermal res-ervoirs need to be optimised. Strategies

to do so in an environmental friendlyway need to be found. Reservoir stimula-tion with innovative carrier fluids is oneway to do so. The so called hydraulicstimulation and its physics has notchanged significantly since the early1950’s. The first million wells were hy-draulically stimulated between 1952 and1992 and the first million fractures inhorizontal wells were done between1974 and 2013 [2]. So hydraulic stimula-tion is a well-known and an evolvingtechnology.

But how does it work in principle, how isthis artificial reservoir created within thehost rock? A minimum amount of “Pad-Fluid” needs to be pumped to create acrack and to generate enough width tostart pumping proppants into it. Ideallyproppants are pumped in increasing con-centrations. The last proppant concentra-tion pumped should be equal to the con-centration at the tip of the fracture (Fig.1) [1].The fractures evolving follows the maxi-mum stress, as shown in Figure 2.The proppant is the “main strain” of thetreatment, so it is the main engine be-hind the fractured well performance. Theproduction benefit comes from creatingadditional drainage area. The ideal prop-pant is cheap, has an infinite strength towithstand an extreme closure pressure atzero crushing, has a spherical shape tominimize embedment and spalling, has amono-size distribution for maximum po-rosity and therefore highest permeability,is chemically inert, has no HSE impact,gives the possibility to add special addi-tives and is oil/gas and water repellent toenhance fluid flow [2]. To meet all theseexpectations normal sand cannot beused, that is why in this article the usageof glass proppants is presented.Another challenge is to create the perfectstimulation fluid to carry the proppantsinto the wellbore and the created frac-tures. The goal is to keep it as simple aspossible, but still create a fluid whichbrings all needs. In general, there are twofunctions a stimulation fluid performsduring the reservoir optimization.First it is to transfer the energy of thestimulation pumps to the formation to

create fracs and second the fluid shouldtransport and suspend the proppants.Other important acquirements for thefluid are formation and native fluid com-patibility, it should be easy recoverable,environmental friendly, easy in use andit should be cheap.In the industry lots of additives like claycontrol, friction reducers, HT-stabilizers,surfactants etc. are used. In fact, not all ofthem are necessary and even not all ofthem work [2].Having all the requirements and chal-lenges in mind, the goal was to create astimulation fluid, here BEER fluid, whichcomplies all the needs.

Laboratory ResultsFormulation of the BEER fluidThe studied carrier fluid is composed

of four components, to be specific:– Water, as a base fluid– Linear polymer, for rheology, fluid losscontrol and carrying capacity

– Potassium carbonate as: weighting agent,corrosion inhibitor, clay stabilizer, sour

* Kerstin Kogler, Mikhail Pavlov, Univ. Prof. Dr. mont. Her-bert Hofstätter, Mining University Leoben, Department ofPetroleum and Geothermal Energy Recovery, Leoben, Aus-tria. E-Mail: [email protected]

0179-3187/18/IV DOI 10.19225/181203© 2018 EID Energie Informationsdienst GmbH

Fig. 1 Proppant concentration at differentstages [1]

Longitudinal FracturesTransverse Fractures

SS E

Fig. 2 Basic definition of transverse and longitudinal fractures [3]

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gas buffer, friction reducer,…– Glass proppants used for fracture open-ing.

Preparation of BEER-FluidWhile steering at approximately 1000rpm the linear polymer is added into 500ml of tab water. For preventing agglom-erates, this procedure should be carriedout very slowly (1.5 g/min). After 30min. of mixing, the K2CO3 is added. TheBEER fluid should be mixed for another15 min. If necessary, 0.5 ml of a polysi-loxane-based defoaming agent can beused.

K2CO3-density tableTo get a concentration dependent densitytable of K2CO3, the density was measuredwith an increase in concentration (10

times each 40 g using 400 ml water asbase fluid) under atmospheric conditionsat room temperature.Furthermore, it is necessary to find themaximum solubility of potassium car-bonate. K2CO3 is soluble up to a maxi-mum concentration of 1100 kg/m³.

pH-value at increasing K2CO3 concentrationsFigure 4 shows the influence of theK2CO3 concentration on the pH-valueand the temperature increase. The pH-value as well the temperature increasewith increasing concentration. The pH-value plays an important role in the sub-sequent addition of the polymer and itsswelling. Normally ordinary water isused as swelling agent (pH = 7.9 at 24°C), as K2CO3 might be added and dis-solved before it is exposed to the poly-mer, the change of the pH-value plays animportant role. A high pH-value couldalso lead to a reduction in viscosity of theBEER fluid. An important behavior seenwas an increase in volume of about 15%.This volume increase has to be consid-ered in the field design, concerning tankvolumes. As the fluid might foam, it isadvisable to have the tested defoamer,which is also environmantally friendly,on site to control the foaming process.

K2CO3 influence on viscosity of the BEER fluidFor the lab test in the HPHT-rheometer, a

temperature ramp (Troom–90 °C) wasused. The BEER fluid was blended usinga constant polymer concentration withvarying concentrations of K2CO3. Thedetailed test conditions for viscositymeasurements are shown in Table 1.Figure 5 shows the influence on viscosityof K2CO3 and Figure 6 shows the temper-ature resistance of the polymer used withdifferent K2CO3 concentrations. The pol-ymer breaks at a temperature of about120 °C when no K2CO3 is added. Addingpotassium carbonate leads to an increasein temperature resistance.As shown in Figure 6 there is an insig-nificant difference in viscosity using 150kg/m³ respectively 200 kg/m3 K2CO3.Thus, viscosity and also temperature re-sistance will not change with using moreK2CO3. If more viscosity and a resistanceto a higher temperature would be need-ed, tests with a combination of two linearbio-polymers have been made success-fully.

Proppant carrying capacity of the BEER fluidThe carrying capacity of the BEER fluidwas tested with varying polymer concen-trations at different temperatures using aproppant concentration of 500 kg/m³.Pictures #1 and #3 in Figure 7 show theresults after 30 min. and pictures #2 and#4 after 1h. A higher temperature wouldlead to a decrease in carrying capacity.

Tab. 1 Test conditions for the basic BEERfluid formulation

Pressure, psi 400Continuous shear rate, s-1 170Test temperature, °C Temperature rampGeometry set Rotor R1 / Bob B5Annulus, cm 0.241Bob radius, cm 1.599Bob height, cm 7.620Sample volume, ml 52Zero control, min Every 50 min

y = -0.0002x2 + 0.6882x + 1006.4

1050

1100

1150

1200

1250

1300

1350

1400

1450

1500

1550

100 300 500 700 900 1100

Density

[kg/m³]

Mass Concentration [kg/m³]

Fig. 3 Concentration dependent K2CO3 density

11.0

11.2

11.4

11.6

11.8

12.0

12.2

12.4

12.6

12.8

13.0

25

26

27

28

29

30

31

32

33

34

35

100 200 300 400 500 600 700 800 900 1000 1100

pH-Value

(-)

Tempe

rature

(°C)

Mass Concentration (kg/m³)

Temperature (°C) pH-Value (-)

Fig. 4 Increase in pH-value and temperature with increasing massconcentration of K2CO3

20

30

40

50

60

70

80

90

100

110

120

20 30 40 50 60 70 80 90

Viscosity

(cP)

Temperature (°C)

20 kg/m³ K2CO350 kg/m³ K2CO3100 kg/m³ K2CO3150 kg/m³ K2CO3200 kg/m³ K2CO3

Fig. 5 Influence of K2CO3 on viscosity

0

10

20

30

40

50

60

70

80

90

0 20 40 60 80 100 120 140 160

Viscosity

(cP)

Temperature (°C)

6 kg/m³ DuoVis; 50 kg/m³ K2CO3 6 kg/m³ DuoVis 100 kg/m³ K2CO3

6 kg/m³ DuoVis; 150 kg/m³ K2CO3 6 kg/m³ DuoVis; 200 kg/m³ K2CO3

Fig. 6 Influence of K2CO3 on temperature resistance of the polymer

Kogler_OGEM4.indd 187 26.11.2018 13:26:33



Breaker testsAs viscosity raises again with a decreasein temperature, it could be necessary touse a breaker to have no backflow ofproppants to the surface. The aim is tohave a viscosity lower than 10 cp after150 min. Breaker tests were made at dif-ferent temperatures (50–120 °C) usingdifferent breaker concentrations. In gen-eral, a higher concentration of breaker isnecessary with decreasing temperature.Figure 8 summarizes the breaker test re-sults. Also interesting is the impact oftemperature on the breaker reaction. Thebehavior of the curves shows a very sharpdecrease of the line at 90 °C whereas thedecrease gets smoother starting with 70°C and all lower tested temperatures.

Fluid loss testThe goal of the fluid loss test was to com-

pare the BEER fluid with and withoutadding silica or chalk for fluid loss con-trol. Using the standard fluid loss testprocedure, with a running time of 30min., every minute the volume of fluidcoming out of the measuring cell wasmeasured (Fig. 9). For the field test a pre-pad using 18 kg/m³ chalk should bepumped to prevent fluid loss.

Return permeability testTo see the effect of the BEER fluid onpermeability, a return permeability testin a core flood tester was elaborated us-ing a Perera sandstone core. The returnpermeability was 100% when the BEERfluid was already broken.

Glass proppantsDescription of the productThe samples received from SWARCO

were labeled as follows:– Glass beads 400-800 µm 1550345– Glass beads 400-800 µm H 1550346– Glass beads 400-800 µm H+ 1550347All the samples visually showed a perfectroundness and sphericity according toAPI RP 19C specifications. Under a mi-croscope the perfect roundness could beconfirmed for about 95% of the beads,with a few of them showing some inclu-sions of voids as shown in Figure 10. In asieve test the proposed size was testedand can be confirmed as well withinspecs. The big advantage is that the sizedistribution of the glass proppants lieswithin a window and has no size distri-bution like e.g. sand or ceramic prop-pants.Table 2 lists the densities, measured witha Micrometics 1340 Helium pycnometer.It can be seen that the coating has littleeffect on the density of the glass beads.

Crush resistanceThe crush resistance has been measuredaccording to the procedure recommend-ed in API RP 19C. A certain amount ofdry sample is placed in a cylinder inwhich a flat plunger contacts the beads ata pressure of 4000 psi (~276 bar). Theparticles collected after pressure throughthe finest sieve is the percentage of bro-

#1: 6 kg/m³ - 5 kg/m³ - 4 kg/m³@ 90°C after 0.5 hour

#2: 6 kg/m³ - 5 kg/m³ - 4 kg/m³@ 90°C after 1 hour

#3: 6 kg/m³ - 5 kg/m³ - 4 kg/m³@ 50°C after 0.5 hour

#4: 6 kg/m³ - 5 kg/m³ - 4 kg/m³@ 50°C after 1 hour

Fig. 7 Carrying capacity with changing polymer concentrations @90 °C and 50 °C

y = -0,01x + 1,2

y = -0.22x + 14.2

0

0.5

1

1.5

2

2.5

3

3.5

50 60 70 80 90 100 110 120

AMPS

Concen

tration(kg/m3)

Temperature (°C)

Fig. 8 Optimal breaker concentration @ different temperatures

0

10

20

30

40

50

60

70

80

90

100

0 5 10 15 20 25 30

Volume(m

L)

Time (min)

BEER

BEER + 5 kg/m3 silica



BEER + 6 kg/m3 chalk

BEER + 18 kg/m3 chalk

Fig. 9 Fluid loss test using different silica and chalk concentrations

Tab. 2 Density of glass beads

Type Density g/cm³Glass beads 400-800μm 2.4858Glass beads 400-800μm H 2,4851Glass beads 400-800μm H+ 2.4871Bulk Weight (for all) 1.7009

Tab. 3 Crush resistance of glass beads

Type % broken finesGlass Beads 400-800μm 0.61Glass Beads 400-800μm H 0.83Glass Beads 400-800μm H+ 0.33UniMin 20/40 9.56Accupack 16/30 7.32CarboLite 20/40 0.15Borovichi 20/40 0.28

Kogler_OGEM4.indd 188 26.11.2018 13:26:34



ken beads. According to API a percentageof broken fines up to 10% is acceptable.In Table 3 all the results of all tested prop-pants regarding to crush resistance areshown. All tested proppants are below10%, still there is a huge difference inquality which can be seen under the mi-croscope as shown in Figure 11.

P reparation of BEER Fluid for the FirstField TestFor the first field test the BEER fluid

should exceed our tested density. A den-sity of 1500 kg/m³ is needed. A summaryof the test conditions is shown in Table 4.This led to further tests and improve-ment of the basic BEER fluid formula-tion. To get such a high density an in-crease in K2CO3 concentration is needed.

Concerning the max. solubility and theupcoming decrease in viscosity of theBEER fluid with a too high amount ofK2CO3 a new formulation of the fluid wascreated. To achieve a density of 1500 kg/m³ not just K2CO3 but also NaCl was used(solubility 358 kg/m³). The maximumpossible concentration of NaCl and the ∆of K2CO3 was used to get the high densi-ty. To assure the temperature resistance acombination of two linear bio-polymerswas used.Further tests are still ongoing and will bepublished within the article about thefirst field test

A special thanks goes to Fangmann Energy Servic-es for providing their lab facilities. Furhtermore Iwant to thank Dr. Nils Recalde-Lummer and RolfBlock for their assistance during the lab tests.

References[1] BJ Services Company: Hydraulic Fracturing Manual,

2007.[2] H. Buijs, Wintershall, GSSPE Presentation, Hannover,

2017.[3] H. Abbas, Formation of Fractures Within Horizontal

Well, Rock Mechanics, 2011.

Kerstin Kogler has a MS degree inPetroleum Engineering of the Min-ing University of Leoben and is cur-rently writing her PhD thesis. Besideher studies she works as Editor-in-chief for the OIL GAS European

Magazine and the ERDÖL ERDGAS KOHLE maga-zine. Before she was three years stimulation engi-neer at Fangmann Energy Services.

A) Typical glass beads

B) Few imperfect glass beads

C) Some broken glass beads

D) Glass beads with inclusions

Fig. 10 Microscopic insight of glass beads

A.) Broken Glass Beads SWARCO

B.) Proppant Unimin 20/40 after Crush Test

C.) Proppant Carbo Light 20/40 after Crush Test

Fig. 11 A.) Glass Proppant, B.) Unimin 20/40 and C.) Carbo Light aftercrush test

Tab. 4 Test conditions for the first field test

Max. Temperature, °C 110Viscosity, cP 300Density, kg/m³ 1,500

Kogler_OGEM4.indd 189 26.11.2018 13:26:34

RREESSEERRVVOOIIRR SSIIMMUULLAAL TTIIOONN


Simulation of Reactive Transport Processes:Acidizing Treatments in Carbonate ReservoirsBy T. CVJETKOVIC, J.-O. SCHWARZ, L. CHENG, J. BECKER, S. LINDEN and A. WIEGMANN *

AbstractA particle/continuum approach for areactive transport simulation, which

can be carried out with the scientific softwareGeoDict on a state of the art desktop worksta-tion, will be presented. The model allows torun simulations directly on real rock struc-tures of representative size (REV). Using avery simple model for the chemical reaction, acomparable phenomenological dissolutionpatterns, similar to already published resultscan be achieved. High performance reliablenumerical solvers for the simulation of fluidflow and particle movement and an easilyadaptable MATLAB function to implementthe model for the chemical reaction are used.

IntroductionReactive flow is a phenomenon withimportant applications in the Earth

Sciences across multiple disciplines andin other application areas like compositematerials, filtration and electrochemistry.The common denominator of all applica-tions is the fluid flow through a porousmedium that leads either to dissolutionor crystallization in the porous medium.Applications in the Earth Sciences in-clude, but are not limited to stimulationof carbonate reservoirs, carbon captureand storage (carbon sequestration), gen-eration of ore deposits, remediation ofcontaminated soils, the design of sandcontrol screens, etc. The reactive trans-port model presented in this article issimilar to other particle-based models[3]. The major difference in our approachis the use of a concept called multiplicity,which allows to reduce the number ofparticles to compute. The capabilities ofthe model are demonstrated here for thespecific case of carbonate reservoir stim-ulation by acidizing the reservoir rock,although the code is designed to capturethe whole spectrum of reactive flow (dis-solution, crystallization).

Carbonate DissolutionThe injection of hydrochloric acid(HCl) into the rock is used to stimu-

late a carbonate reservoir by enlargingthe pore space with the objective of in-creasing the permeability. Depending onthe injection rate and the concentrationof the acid, different dissolution patternsdevelop in the rock, a visualization ofdissolution patterns was found by [4].With reactive flow simulations, thesepatterns can be predicted, and the injec-tion parameters can be determined, lead-ing to the most favorable dissolution ofthe reservoir rock and correlated perme-ability increase. For simplicity it is as-sumed that the dissolution of a carbonate(consisting of 100% calcite, CaCO3) byHCl proceeds exclusively according to thefollowing equation from [5]:

+ 2+3 3CaCO + H Ca +HCO→ (1)

Furthermore, in this example, it is as-sumed that the carbonate consists only ofcalcite and that other carbonate mineralsare not present. Furthermore it is as-sumed reaction 1 to be a first-order reac-tion, i.e. it proceeds at a rate that dependslinearly on only one reactant concentra-tion and in this specific case the concen-tration of H+-ions.

Model Description and ImplementationThe mineral dissolution process ismodeled as a combined continu-

um/particle approach, similar to themodel presented by [3]. The fluid isviewed as a continuum for which theNavier-Stokes equations are solved. Inaddition, the single H+-ions are modeledas discrete particles. The movement ofthe particles is a combination of the ad-vective fluid flow and Brownian motionof the particle itself. As not every singleH+ ion in the fluid can be simulated, theconcept of multiplicity was introduced.Multiplicity means that one particle inthe simulation behaves like a single H+-ion but it actually represents several inan adjustable ratio. Regarding the tran-sient part of the modeling, time is dividedinto portions of equal time steps that arecalld batches. So, every batch has a cer-tain time per batch. A certain fluid veloc-ity is prescibed at the inlet of the compu-

tational domain. From the given time perbatch and the fluid velocity together withthe H+-concentration and particle multi-plicity, the effective number of particlesinjected into the structure is computed(number of particles per batch). Regard-ing the modeling of the chemical reac-tion, we follow a particle along its paththrough the porous medium. If a particlecollides with a solid (voxel), a certainnumber of H+-ions is transferred from theparticle to the solid voxel and the solidvolume fraction of that voxel decreasesaccordingly. Once enough particles hit aformer solid voxel to dissolve it com-pletely, it becomes part of the pore spaceand contributes to fluid flow in the nextiteration steps. The number of hits thatone solid voxel can take before it is com-pletely dissolved, depends on the voxellength and its associated volume. Duringthe whole simulation process, the pathand the collision points of every singleparticle are tracked. Also the multiplicityof the particles and the dissolution stateof the solid voxels are tracked.The dissolution model was implementedusing the scientific software package Ge-oDict and MATLAB. GeoDict includes aMATLAB library was implemented toprovide an interface to facilitate commu-nication between GeoDict and MATLAB,this library is called GeoLab. The imple-mented workflow is shown in Figure 1.The workflow starts with the preparationof the rock sample. A µCT scan of a rocksample, given for example as an imagestack of grey value images is importedand segmented and a 3D-voxel-basedrepresentation of the rock sample is gen-erated. After this preparation step, theactual simulation is started. The first stepof the simulation process is a flow simu-lation to compute the flow field for therock structure. For a very efficient flowcomputation the LIR solver was used [6,7]. The streamlines of the flow field arethen used in the next step to computethe particle trajectories as a combinationof advective and diffusive motion. Thisincludes the collision points where a par-ticle hits a solid voxel. The computationof the particle movement is efficientlyimplemented in the GeoDict software(particle tracker). In the following step,the chemical reaction was modeled withMATLAB together with the GeoLab li-

* T. Cvjetkovic, Math2Market GmbH, Kaiserslautern, Ger-many/cvt engineering, Berlin Germany, J.-O. Schwarz, L.Cheng, J. Becker, S. Linden, A. Wiegmann, Math2MarketGmbH, Kaiserslautern, Germany. Lecture, presented at theDGMK/ÖGEW Spring Conference 2018, April 2018, Celle,Germany. E-mail: [email protected]


Cvjetkovic_OGEM4.indd 190 27.11.2018 13:42:46



brary. This allows to import and manipu-late the particle trajectories and the 3D-voxel structure. For every single particle,the trajectory and the collision points areimported. The rules for the chemical re-action are applied subsequently at everycollision point along the particle trajec-tory. At the collision point, a given num-ber of H+-ions are “transferred” from theparticle to the solid voxel and the multi-plicity of the particle is reduced by thisamount. We keep track of the transferredH+-ions in the solid voxel and in the par-ticles. After all particles are processed,the rock structure was updated. The solidvoxels, which have “collected” sufficientH+-ions for full dissolution are reassignedand become part of the pore space.The updated structure is saved on a diskand can be used for the next iterationstep. After the structure is updated, it canbe analysed for geometrical or physical

properties. For example, if the evolutionof the mechanical stability during the dis-solution process is of interest, a mechani-cal simulation can be performed aftereach time step. This analysis can be in-corporated directly using the GeoDictsoftware package for Digital Rock Phys-ics. At the end of each iteration step, theporosity is analysed. If the change in po-rosity exceeds a given limit, a new flowcomputation is conducted to update theflow field.In the case of a minor change in porosity,the previous result of the flow simulationis used. This saves a significant part of thecomputation time, similar to the ap-proach by [3]. The simulation continueswith the iteration loop until the desirednumber of time steps has been comput-ed.The following parameters must be speci-fied for a simulation:

– the H+-concentration of the injectedfluid (pH-value)

– the velocity of the injected fluid– the length of one time step/batch– the particle multiplicity– the number of H+-ions which are trans-ferred at a collision point

Numerical ExperimentsTwo numerical experiments usingthe mineral dissolution simulation

have been conducted. With the first ex-periment the model was verified by com-paring the created dissolution patternswith the patterns found by [4]. With thesecond experiment it is shown that theapproach can be used for large domainsto obtain solutions for rock samples ofrepresentative size, the so-called repre-sentative volume element (RVE). Theexperiments were carried out on a state-of-the-art workstation using the parallel-ization capabilities of GeoDict. A rocksample from the Grosmont formation,Alberta, Canada, was used which waspublished by [8] in a benchmark studyfor digital rock physics simulations.The original image volume is a1024x1024x1024 cube with a voxellength of 2.02 µm, see Figure 2 for a 3D-visualisation of the grey value image. Theimage was segemented using the GeoDictsoftware to generate a 3D-voxel-basedimage. For simplicity reasons the differ-entiation between the mineral phaseshave been neglected and it is assumedthat all solid phases are calcite. Two sub-domains were extracted, one smaller do-main of 256x256x362 voxels (Fig. 3),which were used to create the dissolu-tion patterns for verification and a largersub-domain of 512x512x512 voxels (Fig.4) to show the capability for the simula-tion on larger structures.In order to replicate the results from [4],four numerical experiments correspond-ing to the four distinct dissolution pat-terns have been conducted: face dissolu-tion, conical wormhole, wormhole anduniform dissolution. The forming of thepatterns depends on the process parame-ters fluid velocity and acid concentration.Therefore, four numerical experimentswith different settings for acid concentra-tion and fluid velocity have been con-ducted. The parameters used in the ex-periments are given in Table 1. About2000 particles were injected per timestep.In the second experiment, a dissolutionprocess on the larger sub-domain wassimulated to test the performance of thealgorithm. A larger sub-domain impliesan increased number of particles to com-pute, which is a challenging task for theparticle tracking algorithm and the flowsolver. For this simulation the same pa-rameters were used as for the wormhole

Fig. 1 Workflow of the implemented dissolution simulation




experiment and about 10.000 particles torepresent the acid concentration.

ResultsTo verify our model for mineral dis-solution, the obtained dissolution

patterns was compared with the onesfound by [3]. Figure 5 shows the resultsof the simulation as 3D-visualization.The four dissolution patterns are compa-rable to the ones published according to[3] (in [3, Fig. 3]). The difference regard-ing face dissolution is related to the dif-ference in simulation time, but the re-sults are comparable qualitatively. Thedifferences between the four dissolutionpatterns are observable in the porosityevolution. Figure 7 shows the evolutionof the porosities in flow direction. Theoverall solver runtimes for the dissolu-tion experiments are given in Table 2.The runtime for the face dissolution ex-periment is increased compared to theother experiments. This difference isbased on the low fluid velocity and there-fore on the diffusion dominated move-ment of the particles. Thus, the computa-tion of the particle trajectories takes moretime as their length is increased due todiffusive motion. Regarding the experi-

ment with the larger sub-domain with asize of 512x512x512 voxels and 10.000particles, the runtime was about 120hours on a workstation using a paralleli-zation of 16 processes. Figure 8 showsthe 3D-visualization of the dissolutionpattern at the end of the simulation after20 seconds (simulation time). The disso-lution pattern is equivalent to a worm-hole pattern. Due to the highly branchedpore space of that larger sample, the pat-tern is not clearly visible. In the 2D-viewof the dissolution evolution, the worm-hole pattern is easier to recognise.

Conclusions and OutlookIn this work a continuum/particleapproach is presented to simulate

the mineral dissolution process. Themodel was implemented using the scien-tific software package GeoDict, togetherwith the mathematical software MAT-LAB. The simulation of the fluid flow andthe particle movement are computed us-ing GeoDict and the modeling of thechemical process is implemented as aMATLAB function. Although the imple-mented model of the chemical reaction isvery simple, it produces comparable re-sults. Furthermore with the use of GeoD-

Fig. 2 3D-view of the grey value image ofthe original carbonate rock sample(1024x1024x1024) before segmenta-tion

Fig. 3 3D-view of the smaller sub-domainwith a size of 256x256x362 voxels.This sub-domain was used to repli-cate the dissolution patterns. The sol-id phase (calcite) is shown in grey, thepore space is rendered transparent

Fig. 4 3D-view of the larger sub-domainwith 512x512x512 voxels. The solidphase (calcite) is shown in grey, thepore space is rendered transparent

Tab. 1 Simulation parameters for the dissolution pattern experiments

Experiment Flow velocityin m/s

pH value Time stepin s

Simulation timein s

Face Dissolution 0.001 3.2 1.26 700Conical Wormhole 0.02 3.2 0.50 100Wormhole 0.1 3.2 0.05 20Uniform Dissolution 0.1 2.8 0.20 20

Fig. 5 Overview of the dissolution patterns of the smaller sub-domain with 256x256x362 vox-els. The dissolution patterns are formed by the solid voxels of the structure, which weredissolved during the acidizing treatment and are rendered in red. The wall of the originalstructure is shown in the background in grey. The visualization shows the end of the dis-solution state at the final simulation time

Tab. 2 Overview of the runtimes for the dis-solution pattern experiments

Experiment Overall Runtime in hFace Dissolution 50Conical Wormhole 36Wormhole 28Uniform Dissolution 29




ict, it is possible to run these simulationson a state-of-the-art workstation at areasonable runtime. The presented work-flow allows the easy incorporation of ad-ditional simulations or analysis steps re-garding the mechanical stability, electri-cal conductivity or other geophysicalproperties, which can be predicted usingthe software GeoDict.

References[1] GeoDict - The Digital Material Laboratory, Math2Mar-

ket GmbH, Kaiserslautern, Germany, http://www.geo-dict.com

[2] MATLAB, The MathWorks, Inc., Natick, Massachu-setts, United States, http://www.mathworks.com.

[3] Pereira Nunes, J. P., Blunt, M. J., Bijeljic, B. Pore-scale simulation of carbonate dissolution in micro-CTimages. Journal of Geophysical Research: Solid Earth121, 558–576, (2016).

[4] Maheshwari, P., Ratnakar, R. R., Kalia, N., Balakotai-ah, V. 3-D simulation and analysis of reactive disso-

lution and wormhole formation in carbonate rocks.Chemical Engineering Science 90, 258–274, (2013).

[5] Alkattan, M., Oelkers, E. H., Dandurand, J.-L., Schott,J. An experimental study of calcite and limestonedissolution rates as a function of pH from −1 to 3and temperature from 25 to 80°C. Chemical Geology151, 199–214, (1998).

[6] Linden, S., Wiegmann, A., Hagen, H. The LIR spacepartitioning system applied to the Stokes equations.Graphical Models 82, 58–66, (2015).

[7] Menke, H. P., Reynolds, C. A., Andrew, M. G., PereiraNunes, J. P., Bijeljic, B., Blunt, M. J. 4D-multi-scaleimaging of reactive flow in carbonates: Assessing theimpact of heterogeneity on dissolution regimes usingstreamlines at multiple length scales. Chemical Geol-ogy 481, 27–37, (2018).

Tom Cvjetkovic studied Compu-tational Engineering (M.Sc) andfollowed his interest in modellingand simulation as an ApplicationSpecialist at Math2Market GmbH,which develops the scientific soft-

ware GeoDict. There, he helped clients with soft-ware training, research and service projects tomake use of the powerful tools and possibilities ofdigital rock physics. After moving to Berlin, he isnow working as a freelance specialist for materialmodelling and simulation with GeoDict.

Fig. 6 Permeability evolution of the dissolution pattern experiments

Fig. 7 Porosity plot for the four different dissolution patterns. The po-rosity is plotted along the flow direction (z-axis) from left toright. The porosity of the original structure at the beginning ofthe simulation is shown in blue. The porosity in the intermedi-ate state of the simulation is shown in orange (dashed line).The porosity of the final state is shown by the green (dottedline)

Fig. 8 Dissolution pattern of the larger sub-domain with a size of512x512x512 voxels at the end of the simulation time (t=20 s).The dissolved solid voxels are rendered in red, the original sol-id wall is shown in the background in grey

Fig. 9 2D-visualization of the dissolving process at different timesteps for the 512x512x512 sub-domain. The 2D slices showthe view in a lateral direction with fluid flow from top to bottom.The solid structure is rendered in grey and the dissolved part inred


CCAASSIINNGG IINNSSPPEECCTTIIOONN


Assuring Vertical Casing Integrity withPipeline Inspection TechnologyBy B. HOSTAGE, D. SCHAPER and S. STOLTE*

AbstractPipelines in the oil and gas industries,as well as in the chemical and petro-

chemical industries, are regularly inspectedregarding their integrity. The technology iscalled “In-Line inspection” (ILI), in whichautonomous inspection tools are pumpedthrough the pipeline usually with the prod-uct. The main objective is to detect, locate andmeasure defect anomalies, such as metal loss,on the inner or outer surface. In principle,these same tools can be equally used in verti-cal as in horizontal installations, eventhough there are differences between theseapplications. This article describes an appli-cation of ILI technologies used for horizontalpipelines to the area of vertical pipe inspec-tion. 3P Services has provided ILI services formore than 25 years. Recently, ILI tools havebeen modified to provide a vertical inspectionand a simplified set-up created for job execu-tion. No drilling or work-over rig was re-quired. The set-up has been used in severalprojects. Like in pipelines, the adapted ILItools work autonomously in casing applica-tions since they are equipped with their ownpower supply, data processing and storage.The execution itself is effectively a wirelinejob without need for separate power supplyor data transfer through a cable. The worksite operation was planned together with theclient targeting at complete sets of high reso-lution inspection data. The measuring unit,equipped with different sensor types, ischangeable to cover individual tasks. Ultra-sonic (UT) and Magnetic Flux Leakage(MFL) technologies are typical for wall thick-ness measurements. Further technologies areavailable for specific detection of inner corro-sion, scaling and/or geometric deformations.The development and testing of tools for aspecific project is described. Operational les-sons learned and potential for further appli-cation are discussed.

IntroductionIn the last several years, 3P Serviceshas become aware that casing integ-

rity is becoming a sensitive matter and aconsequent growing demand for integ-rity inspections. There are trends indi-cating that inspections may be moreand more required in future. The casestudy presented in this article comesfrom the UK. Similar trends can be ex-pected in Germany. ILI results are nowacknowledged and regularly used inpipelines as the basis for calculations ofremaining life, life extension, fitness forservice assessments and service up-grades.Inspection intervals can be set afteranalysis of the severity of defects presentin a line. Necessary repairs can beplanned in advance. Routine operationscan be adjusted to incorporate preven-tive and mitigating actions. Applicationof ILI technologies to casings will allowthese same disciplines to be used todemonstrate and ensure casing integrity.

Technological Background3P Services has a profound knowl-edge in the area of ILI in the petro-

leum, natural gas, petrochemical andchemical industries through the entireenergy chain from upstream, midstream

and downstream. Experience rangesfrom field lines connecting wells to pro-cessing facilities, offshore productionloops in deep water to large diameteronshore transportation lines and longdistances. Inspections in downstreampipelines typically require somewhatsmaller diameters. More than 100 pro-fessionals cover the spectrum of disci-plines necessary to design, constructand test ILI tools as well as deliver theinspection service and reporting to op-erators.The tool fleet is highly modular and un-der constant improvement. A widerange of standardized components, suchas electronic modules, power supply,and sensor arrays, can be integrated andadapted to tool design and assembliesthat are specific to the pipeline to be in-spected. Diameters from 2” to 56” arereadily available.Figure 1 shows a variety of 3P’s ILItools. On the upper left a unidirectional4” tool for measuring the internal pipediameter is shown. On the upper right a18” MFL tool consisting of two modulesis shown. The first module (left) is atowing module. It is equipped with seal-ing discs and pulls the second module

* B. Hostage, D. Schaper, S. Stolte, 3P Services GmbH &Co. KG,Wietmarschen, Germany. Lecture, presented at theDGMK/ÖGEW Spring Conference, April 2018, Celle, Ger-many. E-mail: [email protected]


Fig. 1 ILI tools of different size

Hostage_OGEM4.indd 194 26.11.2018 13:49:37



through the line driven by the pressurebehind the seal. A power supply andelectronic to store all measurement dataare integrated in the towing module.The second module is the MFL meas-urement unit. The tool below shown inFigure 1 is a 48” bidirectional tool,which can be pumped in two directions.

Pipeline vs. Casing InspectionIn common with pipeline inspec-tion, the objective in casing inspec-

tion is to achieve a high resolution dataset about metal loss, girth weld and geo-metric integrity. Further interest is typi-cally on mechanical stress in the pipe-lines due to dents or ovality.There are, of course, differences be-tween pipeline and casing inspections,some of which are summarised in Table1.Some aspects of tool configuration aresimpler for vertical casings compared tohorizontal pipelines. Since flow of aproduct is not used to propel the tool,PU sealing elements are not required.The absence of bends means that thetool bodies can be made larger.Other aspects are more complicated.When inspection must be done underpressure, tool length may be limited bythe amount of space available for apressurized launch trap.Temperature and pressure gradients

may be greater in a casing applicationcompared to a similar pipeline, whichmay imply higher requirements for thetools with regard to robustness andmeasurement range.However, many solutions for such re-quirements have already been appliedto different tools in the fleet. Individualtools have been pressure rated to 350bar and temperatures to 100 °C. ATEXcertification can also be achieved for EXrated zones.

Case Study – LPG Storage Facility3P Services was asked to inspect200 m long casings of 12 3/4” and

20” diameter in an LPG facility (Fig. 2).Target of the inspection was a levelingcasing and a production casing. Thecavern is filled with LPG through the fillline. Possible LPG vapour is vented overthe vent line. Cavern pressure is con-trolled by pumping water over the levelregulation line.

Case Study – ILI Equipment for VerticalCasing InspectionThe objective of an inspection is to

deliver detailed, high resolution infor-mation about any defects throughoutthe entire length and circumference ofthe pipe. Sensors are arrayed to achievea fine mesh of measurement points to

detect and size pinhole and pitting fea-tures of 5 mm diameter and smaller.Distance between measurement pointsin axial direction is assured by the sam-pling frequency and speed of tool move-ment. Circumferential coverage is as-sured by sensor spacing with overlap-ping measurement footprints.Pipeline inspections use a sequence oftools to ensure that succeeding tools donot encounter a restriction that mayprevent passage or lodge a tool. An un-instrumented PROFILE tool equippedwith gauging discs serves to both cleanthe pipe and determine a minimum di-ameter. The next GEO tool measurespipe ID to detect and accurately locateand size geometric anomalies. Thesedata confirm whether the pipe bore issufficient to allow passage of the finalmetal loss tool.MFL magnetizer unit is relatively mas-sive compared to the pipe ID. This toollocates and measures internal and ex-ternal metal loss. A UT sensor array canalso be used to measure wall thicknessand metal loss features. A liquid coup-ling medium is required to provide ef-fective transfer of ultrasonic wave en-ergy from the tool to the pipe.Whether MFL or UT, metal loss features

Tab. 1 Differences in pipeline and casing inspections

Pipeline CasingTool movement pumped on cableSeal required yes noLaunch/receive traps present yes noTypical length 5 km to 100+ km 0.5 km to 5 kmTight bends present yes noTemperature/pressure gradients small largeChance to investigate results yes no

Fig. 2 LPG cavern schematic sketch Fig. 3 Schematic tool sketch




are reported with sizing values fordepth, length and width. A very highlevel of confidence in the results ob-tained by ILI in pipelines has beenachieved by the industry through manyyears of development and field verifica-tion of inspection data. This level ofconfidence is critically important for ap-plication in casing inspections since ac-cess to any detected defect is muchmore difficult.General layout of the tools used in theLPG casing inspections is shown in Fig3. The assembly comprises three mod-ules: electronic, power supply and dis-tance measurement; metal loss meas-urement; and an extra weight to ensurestability during lowering and recovery.

Case Study – Tool Assembly andQualificationFigure 4 shows the final assem-

blies of the GEO and UT tools. Dimen-sions and weights are indicated in Table2. The number of sensors used for eachinspection tool differs depending on thetype of sensor, the measurement objec-tive (metal loss, wall thickness, etc.),minimal defect/anomaly to be detectedand the size of pipeline.All sensors are distributed over the en-tire circumference to achieve 360 de-gree coverage. Each sensor sampled at1000 Hz giving a distance betweenmeasurements of 0.3 mm at the maxi-

mum speed used of 0.3 m/s. After de-sign and assembly of the tools, each toolis qualified in accordance of ILI stand-ards [1–2]. Objective of the tests is toprove the mechanical passage capabili-ties, run behaviour for the targetedpipeline and to perform dedicated toolcalibration. Defect detection and sizingability is proven and quantified in tests

using pipe joints in which representa-tive artificial defects have been intro-duced.Figure 5 shows a test pipe. The defectsin this test pipe are round with differentdepth and diameter. Performance eval-uation of a UT system is done in a teststructure containing liquid couplant.Together with historical data from tools

Fig. 4 GEO and UT tools

Tab. 2 Final assemblies of the GEO and UT tools

Dimensions of 20” toolsLength (mm) Weight (kg) Additional weight unit (kg)

GEO 2960 190 380MFL 3100 340 380UT 3600 170 380Dimensions of 12” tools

Length (mm) Weight (kg) Additional weight unit (kg)MFL 2300 218 110

Fig. 5 Pipe with reference defects

Fig. 6 Simplified set-up

1 2

34

5

Fig. 7 Setup for the 12” casing inspection.




of similar type, the test proves that theassembled and calibrated tool meets theperformance specification.

Case Study – Simple Set-up andInspection executionThe casing inspections took place

in 2016. The 12 3/4” casing was inspect-ed with an MFL tool. The 20” casing in-spection was additionally supported byan Ultrasonic inspection tool and there-fore benefitted from the strengths ofboth technologies. During the inspec-tion the casings were partially filledwith water, otherwise were empty. In

this particular case the preparationneeded was limited. The productiontubing and the pump were removed.Since there was no pressure at the cas-ing head, the entire operation could beperformed in the open casing withoutany pressure equipment and a very sim-ple set-up. A 5 t winch with a steel cableguided by two pulleys was used. Thecrane was placed next to the casinghead to hold one of the pulleys (Figs. 8& 9). One pulley was fixed at the casinghead flange with a sling. Since thewinch could only able to be placed on aloose gravel surface, it was further se-cured to an anchor to prevent anymovement.The tool movement was controlled bythe winch operator. The velocity of theinspection was between 0.1 and 0.3 m/son both directions. The simplified set-up for the inspection is shown in Figure7. The inspection tool is inserted verti-cally in the casing head. It is guided by asteel cable connected to a winch. Thissimple set-up was sufficient.The winch is connected to an anchor tiepoint to avoid any unwanted move-ment. The steel cable itself is guided bytwo pulleys and lifted by a crane. Usingthis set-up, tools can be lifted andlaunched with an optimal angle. Thetool is connected to the steel cable forthe entire operation.A weight at the bottom of the inspec-tion tool enables the measurement unitto enter the casing and provides a stableposition. The tool is lowered in the cas-ing at a speed of 0.1 to 0.3 m/sec to thelowermost position and then lifted out.Measurement data are collected in bothdirections. The two data sets are usedfor analysis. The inspection process isidentical for all described tools.The 20” casing was inspected with bothMFL and UT tools. Each inspection runlasted several hours. The entire opera-tion was completed in 2 days. A sepa-rate mobilisation achieved the 12 3/4”inspection.

Case Study – Inspection ResultsImmediately after the tool runs, asite report was delivered contain-

ing all relevant data about the inspec-tion performance including data qualityand completeness. A first report aboutthe status of the casing was available afew hours after the inspection. In the fi-nal report a detailed list of any metalloss or geometric anomalies was provid-ed showing the length, width, depth inthe pipe and distance to the casing head.Several charts and other statistics wereprovided to summarize the features aswell as charts with information of theinspection process (speed profile, rota-tion of tool, magnetization level or tem-

perature). All information can beviewed and evaluated within a clientsoftware.Figure 9 shows typical raw data of aMFL casing inspection. The magneticfield measured by a single sensor is dis-played by an individual line. The line onthe right side represents the speed pro-file. On the left side the distance to thecasing head can be seen. An increase ofmetal results in a decrease of sensor sig-nal. A metal loss feature results in anincrease of sensor signal. The horizontalblack line in the figure is caused by agirth weld. Further a mechanical cen-tralizer, centering the casing in theborehole, can be clearly identified in thedata.Both casing inspections delivered goodquality and complete data. All sensorsworked as expected. Some gaps in thewell documentation regarding wallthickness and installations could beclosed by means of the inspection re-sults.

Conclusion & View ForwardSeveral casing inspections 12” and20” have been concluded in shal-

low wells of an underground LPG stor-age facility. High resolution data on in-ternal and external metal loss as well asgeometric discontinuities were obtainedby means of ILI equipment. No devel-opment effort was required and theneed for tool modification was limitedbased on the existing fleet of pipelineinspection tools at 3P Services.While pressure and temperature en-countered in these shallow wells weremoderate, significantly deeper wells canalready be inspected. Components areavailable that work under temperatureup to 100 °C and pressure up to 350 bar.This corresponds to wells approx. 3000m deep.Inspection tools as assembled for thisproject can be operated from workoverrigs during regular maintenance workin any type of well. Having developedILI tools for small diameter pipelines (2”to 4”), an in-situ tubing inspection canbe done provided access to the tubinghead is granted.

References[1] API STANDARD 1163, “In-line Inspection Systems

Qualification”, (2013).[2] Pipeline Operators Forum, “Specifications and re-

quirements for in-line inspection of pipelines”,(2016) 203.

1

6

7

8

Fig. 8 Lowering 20” UT tool

Y0+5m

centralizer

girth weld

metal loss

Y0

Distance[m

]

Y0+1m

Y0+5m

Sensor No. [-]

Fig. 9 Sample of MFL sensor data


DDRRIILLLLIINNGG EENNGGIINNEEEERRIINNGG


Differences in Cementing Oil, Gas andGeothermal WellsBy Y. YADIGAROV*

AbstractRenewable energy with associated geo-thermal well drilling, producing hot

water for energy and heat generation, hasquickly become more than an idea and has be-come part of our daily routine. Only a fewyears ago enthusiasts were drilling here andthere for geothermal hot water, whereas pres-ently it has become a government and econo-my driven trend.There is a very popular concept for convertingoil and gas wells into geothermal wells and atthe same time a number of wells were drilledfor hot water and hydrocarbons were struck.There are limited guidelines for geothermalwells and instead oil and gas guidelines areused. If the well is designed for district heating,then there is a possibility of finding oil and ifaiming deeper for hotter water or steam, thenone can also hit gas.Well cementing is a critical part of the wellconstruction and well future integrity. Oftenneglected or poorly focused this then will be-come an issue when the well is not performingas it should, or when water leaks all over andthe current owners have to explain to the au-thorities and community about what wentwrong. Especially when wells are getting clos-er to the rural areas (geothermal is almostthere), the risk of being harmful is increasingprogressively.Do operators know the associated risks? Weshould remember, that oilfields exist now formore than 150 years, whereas the “hype” ofgeothermal drilling took off in the last 20years. They obviously cannot have the samelevel of experience. Most of the parties involvedin the geothermal activity have a non-drillingbackground, e. g. water drillers, fundingbanks, insurers, municipalities, although de-cisions taken at their level are often the mostimportant decisions.The first recorded oilfield cementing operationwas conducted almost 100 years ago. That firstoperation took place in 1903 when Frank F.Hill with Union Oil Co. mixed and dumped50 sacks of cement by bailer to shut off the wa-ter flow in a California oil well. After 28 days,the cement was drilled out and the well wascompleted successfully [1].The requirement of well geometry may be dif-

ferent, for example, the production casings ofoil & gas wells can be smaller than those ofgeothermal wells, because the geothermalwells require a big enough ESP pump cham-ber for higher pumping rates to stay economi-cal. Cementing geothermal wells can be lesscostly and less problematic. There may be amore economical cement available, e. g. forlow temperature district heating, but if whilstdrilling for water, gas or oil is hit, then a quickchange of plan can be very expensive.So what are the differences between oil-gasand geothermal wells with regard to cement-ing?

IntroductionWell cementing exists since well drill-ing began, 100+ years. It developed

from the simple mixing of water andportlandite cement to the current addi-tion of special materials, such as accelera-tor, retarder, thinner, dispersant agent,fluid-loss reducer, flow improver, lightingand weighting materials, etc. to enhanceits properties as the well drilling facesmore complex requirements (HTHP,over- and under-pressured formation,horizontal drilling, etc).In today’s oilfield, it would be wrong tosay “well cementing”, as the cement be-comes only a tiny portion of the mediumbeing pumped to seal the well. We aretalking now about blends: Blends of so-phisticated admixtures, each part ofwhich is responsible for various func-tions.Advanced simulations are in use to pre-dict the well and cement conditions forthe life of the well, living out the peoplewho are making it. That is why the re-sponsibility for leaving a proper productfor the future generation is not a myth.This article is dedicated to highlight thosedifferences, awareness and safety of thewell, thus for everyone involved. Ex-tended experience with both well typesin Europe and worldwide, case scenariosand lesson learnt, allow establishing adistinctive practical guide for owners ofthe well, project developers and authori-ties in respect of cementing and well in-tegrity.

EconomicsOilfields have a major advantageover geothermal wells – and that is

they are money earners. Return on in-

vestment (ROI) of an oilfield is muchmore efficient. An oil well with good re-serves can have a ROI of only a fewmonths, whereas a typical geothermalwell has an ROI of 10–20 years. In termsof market volatility, it is easier to plan awell for six months rather than for dec-ades. Currency, politics and environmentare issues, which are likely to changeover time.Oilfield operators are typically majorcompanies with substantial financial ca-pacities and reserves, whereas, geother-mal operators are municipalities, smallagricultural organizations, cities, etc. Thebudget is therefore not comparable. Thatis why an Authority for Expenditures(AFE) for geothermal wells will employscrutiny and will have a limited and low-ered budget. It is simply difficult to getcredit from the bank and insurance for awell, which is being planned for 3–5years and with a ROI of 20 years.However, there are new energy compa-nies starting up on this new wave of gov-ernment support. They are either spin-offs from oilfield companies or start up asunique energy producers. Those compa-nies are involved in all types of renew-able energy, namely wind energy, solar,marine, etc.One advantage of a geothermal well isthat it can generate profits for the well’sentire lifetime. The geothermal energysource is never exhausted. As our earthexists with its core temperature reaching6000 °C, we will continue to enjoy long-term geothermal heat. The well has to bestimulated and repaired and it will pro-duce for us lifelong natural clean renew-able heat. We cannot say this about oiland gas wells, which normally produce20–30 years until the reservoirs are de-pleted.

Setting Comparison CriteriaIn order to establish the scope of thisarticle, a clearer comparison is set by

comparing “apples” with “apples”:– Oil vs. GT well for direct use of water fordistrict heating (GTH), Temp. 50–90 °C

– Gas vs. GT well for power generation(GTP), Temp. above 110 °C.

The last casing section of most geother-mal wells is normally completed with aslotted liner and therefore without ce-mentation. This means the reservoir willnot be cemented. Cement from the upper

* Y. Yadigarov, DEUTECS GmbH, Oldenburg. Lecture, pre-sented at the DGMK/ÖGEW Spring Conference, April 2018,Celle, Germany and at the GLOBAL GEOTHERMAL ENERGYSUMMIT 2018, November. E-mail: [email protected]


Yadigarov_OGEM4.indd 198 27.11.2018 10:00:06



section, will however see the heat fromthe reservoir when production begins.The preferred temperature for powergeneration lies above 130 °C, as suchlower well temperatures will reduce orstop the power generation. The differenceto the required level has to be counterbal-anced with the use of an alternative fuel.

The article will review only onshore op-eration, where most geothermal drillingstake place.

Understanding Wellbore TemperatureDistribution CurvesThe cement slurry and then hard-

ened cement stone will experience welltemperature and this increases with thedepth: surface (ST) and bottom-hole(BHT) temperatures, whereby BHT isnormally higher than ST.A typical geothermal (temperature) gra-dient is approximately 3 °C/100 m plusST, for e. g. at 2500 m depth well tem-perature of 85–95 °C (Oil and GTH wells)and at a depth of 5000 m over 150 °C(Gas & GTP wells).Neat cement without additives will notbe able to go all the way down and willthicken in the cementing string. In orderto make it stay longer liquid at elevatedtemperatures, engineers add various ma-terials, such as retarders, dispersant etc.During the cement life, the hardened ce-ment may face temperature and varyingpressure changes depending on the welloperations, such as well stimulation, test-ing, injection, production. To meet theserequirements engineers have to add, forexample, dense, flexible, expanding ma-terials, etc. to the neat cement. Figure 1shows temperature distributions in a wellafter a drilling phase [2].

Requirements to be ReviewedIt takes some time to make a “good”proper cement. The process starts by

looking at the objectives of the well, intoplanning the well on paper and project-ing for the coming decades. “Good ce-ment” is a cement, which will meet itsobjectives:– Isolate various zones (zonal isolation)and protect drinking water horizon

– Protect casing metal from formationfluids, hence corrosion

– Protect the wellbore from collapsing.Project managers have to clearly identi-fy objectives and time period, when thecement has to stay “good”. One shouldneither underestimate nor overesti-mate.

Each section of the well will have its ownchallenges, which firstly the cement inthe liquid state (slurry) and then as astone have to face (Fig. 2). Cement slurryis pumped inside the casing, run all theway down to the casing shoe and thenlifted to its final depth (Fig. 2). It experi-ences changing temperature and pres-sure.Cement slurry requirements for safe op-eration are:– Density– Thickening time– Rheology– Fluid loss– Free fluid– Stability.Cement stone requirements for long lifeof the well are:– Compressive strength (also tensilestrength)

– Thermal conductivity

Fig. 1 Different temperature distributions in a well [2]

Fig. 2 Well cementing [3]




– Flexibility– Expansion– Self-healing– Permeability and porosity.The article will review these require-ments, which reveal some distinctive dif-ferences between oilfield and GT. Also,we will look at wellbore volumes, pump-ing rates and losses into formation.

O il Well vs. GTH WellDensity: This is when the cementslurry and during general operation

has to have a safe pressure window:above pore pressure at static and belowfracture pressure at dynamic conditions.If a geothermal well is not expected to hitgas, which is normally the case, then alocal cement should be given preference:CEM I or CEM III. There is no need forAPI Class G cement, which is commonlyused in the oilfield. But if gas (also for oilwells) may be present, it will requiresome special additives such as Latex gasmigration preventers, fluid loss agents,etc., which so far are only compatiblewith oilfield cements.CEM I (precisely CEM I 52,5 N) will workto a downhole temperature of 40 °C andCEM III (precisely CEM III/B 32,5 N-LH/SR) will work to a downhole tempera-ture of 90 °C. Local cement productioncan be sourced in the neighbourhood ofdrilling wells to reduce operational andtransport costs (Fig.3). As for the density,

the cement typewill define it. Con-struction cementcan be mixed with-out light admix-tures, like bentonite, to a density of 1500kg/m³ and still display good quality. Theshoe of each casing cementation has tobe specially cemented by (tail cement):hard and quick setting. Any densityabove 1750 kg/m³ will be sufficient andsuit the function of tail cement. Tail ce-ment will have little affect on hydrostaticand safety of the well, as the heavy slurryheight as a rule does not exceed 200 m.Also the annular space around the casingneeds to be cemented with low-watercontent, good quality cement.Thickening time: The time required toplace the cement slurry in place before itbegins to set is defined as the thickeningtime. This is the time when cement slur-ry stays in liquid form and can be movedfreely. In the geothermal operation wedo have a little bit more flexibility com-pared to oilfield cement. We do not haveto accelerate it (e. g. risk of gas migra-tion), nor retard (non-API cement slur-ries can be mixed lighter, hence be natu-rally retarded). Due to the changing ofthe temperature distributions from atemperature log taken directly after drill-ing, at the beginning of cementation jobsand up to the end of the cementationjobs, caution and proper labor experi-ments should be run to find out the exact

added amount of retarder or accelerator.Rheology: This is where we start to thinkabout mixability and friction (loss) pres-sure. Proper computerized flow model-ling taking well geometry and casingcentralization into consideration is a crit-ical step of cementing planning. In bothOil and GTH wells this defines good well-bore fluid displacement and cementplacement.Fluid loss: Losing excessive fluid into theformation can be dramatic in an oil well,due to filtrate contamination and forma-tion damage in the form of emulsion andcement particles. In water and GT wells,loss of the water part of a cement slurrycan necessitate changing the design ce-ment properties (density, thickeningtime, flow properties, etc.), but this isnormally not an issue for GT, because thecontact time between cement slurry andpermeable formation is rather short.There is no big need to have a perfectfluid loss value, unless it is relevant tooperation safety (liner cementation).Here the operator can save some costs, byapplying little fluid loss control polymers.A value below 600 ml/30 min at the de-sign temperature should be sufficient.Free fluid: As this parameter becomes crit-ical at elevated temperatures, we will re-view it for GTP.

Fig. 3 Cement factories in Germany (Source: VDZ)

Fig. 4 Compressive strength and permeability behavior of neat Port-land cement systems at 110 °C [4]

Fig. 5 Thermal conductivity of various cements [4].




Stability: When the operationis interrupted (stop pump-ing), the cement slurry shouldremain stable, not allowingfor solids to settle and waterto float. To achieve this theslurry has to be self-support-ing, by adjusting its rheologyparameters and density. Anti-settling agent as such shouldbe used, if laboratory resultsshow insufficient rheologyvalues.Compressive strength: As such acompressive strength of some1000 psi is enough to supportthe casing. Here it is impor-tant to talk about porosity,strength retrogression, whichwill be discussed later in thisarticle (GTP).Thermal conductivity: This isone of the most important pa-rameters for geothermal drill-ing. The well has to keep theheat collected downhole, in-sulate it and bring to the sur-face. Every degree lost intoformation over the period ofthe well life will accumulateinto a huge amount of capitalloss. Geothermal operatorsneed to evaluate each andevery possibility to addressthis facing cementing compa-nies. The lower the density,dry or gas-filled cement willbe better for the lower ther-mal conductivity (Fig. 5). So,using solid materials with lowdensity or foam cement iscrucial for every geothermalwell. Money spent on the ce-menting job will be much lessthan the pay back during thewell life.Flexibility: Flexibility is signifi-cant, when the well is ex-posed to pressure and tem-perature changes (we willleave fracturing aside). Thisbecomes very important at el-evated temperatures and thuswill be reviewed with Gas vs.GTP wells.Expansion: Every cement willshrink around 2–3%. The wa-ter well, producing hot water,is unlikely to leak through themicro channels opened due toshrinkage. In contrary to oilwells (having gas), water willhave higher friction forcesand not move in those spaces.A proper modeling and leakanalysis can be desirable toestimate the leak risk and im-plementation of costly mate-rials.

Self-healing: If cracks occur,due to operational activity orpoor quality cement, thenthey may be repaired by ma-terials added to the cementslurry as healing agents. Forwater wells, where the wateris normally saline, these heal-ing agents expand poorly. Ifthe operators really considerthis as a potential problem,proper laboratory analysisneeds to be performed on wa-ter samples of the reservoir tobe drilled through.Permeability and porosity: Typi-cally a geothermal well is of-ten stimulated with acid: nearwellbore treatment or matrixacidizing. If the contact areaof the cement is high then theacid will destroy it easily. Tokeep acid away from poresthe cement can be madeheavy by densification. Alsoblends of various particles siz-es make it difficult for the acidto invade the cement matrix.(Fig. 4)

Gas Well vs. GTP WellDensity: As for GTH thedensity plays a role on

many factors such as com-pressive strength, hydrostaticpressure, cement setting time,etc. More cement particles,hence higher resistance of thecement.But it would be difficult tohave high density cementslurries with the cement pro-duced by regional factories, asthey become unpumpable athigher densities. That is whyit makes more sense to useAPI Class G cement, especial-ly when it has to be dry-blended with silica. Lead ce-ment (filler cement) slurry, ifsuch required for the hydro-static safety of the well,should be designed between1600–1750 kg/m³ and tail ce-ment slurry at the shoe notless than 1900 kg/m³. If thewellbore is considered unsafewith designed high densities,then loss circulation materialsor two-stage cementation canbe implemented.Thickening time: As the wellenters the high temperaturezones (above 90 °C), this be-comes very critical for wellcementing. Here also, it is rec-ommended to use more pre-dictable API Class G cement,

Fig. 6 Formation conditions of various calcium silicates. [5]

Fig. 9 Compressive strength and permeability behavior of 16 lb/galClass G system stabilized with 35% silica [4]

Fig. 8 Comparison between compressive strength and Young’smodulus.

Fig.7 Influence of silica on compressive strength development [5]




since construction cement has a muchhigher turnover and perhaps less qualitycontrol in comparison with API stand-ards specially designed for deep drilling.Due to the absence of gas, the right-an-gle-set property of the cement slurry isnot important, and focus needs to bemade on operation safety.As mentioned before, due to changingtemperature distributions taken from thetemperature log directly after drilling andup to the end of the cementation job,caution and proper labor experimentsshould be run to find out the exact addedamount of retarder or accelerator.Rheology: As the density of the fluids(mud, spacer and cement) increases,their rheological parameters increase ac-cordingly. Here the number of availabledispersing agents commonly used in oil-fields will fulfill the purpose. The down-hole temperature will reduce the viscosi-ty of the cement. Reduction may lead toloss of fluid stability and control of fluiddegradation. Caution has to be taken onselection of the dispersant agent and itsconcentration, because some of them af-fect also the thickening time. Mud re-moval becomes more difficult with theporous formation, tending to yield athicker filter cake and more filtrate.Fluid loss: As with rheology, the fluid lossparameters will improve with increase ofdensity. But at the same time the hydro-static pressure of the cement column in-

creases, and this in turn will result inhigher differential pressure leading thefiltrate out of the cement slurry. Somefluid loss control materials are thus re-quired to control premium properties ofthe dense cement.Free fluid: In the experience of geother-mal drilling, free fluid had already playeda somewhat negative role. Excess waterin cement or undisplaced drilling mudcan be left behind the casing. During pro-duction such pockets of water-based flu-ids will expand when temperatures risein the well and the annulus. However, ifthe fluid cannot expand, the pressurewill rise andmay exceed collapse strengthof the inner string before the outer stringbursts [6].Casing failures such as collapse are theresult of combined loads and impuritiesin the casing and/or surrounding con-crete. Cracked or otherwise damagedconcrete can also cause external pressureload on the casing, for example if smallsteam channels form or if water is pre-sent in the annulus when the well is dis-charged [7]. Zonal isolation can be dam-aged and lead to leakage.Hence cementing such a geothermal wellrequires extra care, where cement slur-ries with no free fluid need to be plannedand the mud removal technique re-viewed.Stability: With temperature increase sta-bility will suffer. The cement will lose its

viscosity, thus requirements for stabilitycontrol agents (anti-settling) arise. Cool-ing the well can be also beneficial andthis can be achieved by a few hours ofwell circulation with drilling mud priorto the cement job. Despite the geother-mal well temperatures reaching 200 °C,it can be cooled down significantly,which will improve cement propertiesand make operation safe and economic.Compressive strength: Any cement stone attemperatures above 110 °C will experi-ence morphological changes. That is whythe addition of silica is important. Silicawill ensure sufficient compressivestrength of the cement stone and controlits permeability by formation of furthercalcium silicates (Figs. 6 & 7).Here complete cementation of the casingstring becomes important, as the unce-mented zones may creep or elongate un-der thermal expansion after bringing thewell into production [6].The amount of silica to be added is dic-tated by the temperature and may varybetween 30–43% by weight of cementreducing C/S ratio.Thermal conductivity: Thermal conductivi-ty for GTP can be taken as analogous toGTH. The difference in increased densi-ties for GTP is not however beneficial andleads to an increase in conductivity.Flexibility: With increase of temperature,changes in depth and pressure, the ce-ment stone will experience greater forcesfrom the casing. Cement cracking maylead in time to a total loss of bonding, re-sulting in formation fluids entering theexternal casing surface and resulting cor-rosion, or in extreme cases the cementcan be washed out leading to classicalbuckling due to wellbore cave in [8].The wellbore should be analyzed for theentire well life for temperature and pres-sure changes and subsequently modelledusing modern simulation software. Afterthis the required mechanical properties(Poisson ratio and Young modulus) ofthe cement stone can be achieved by ad-dition of flexible additives. Figure 8shows that a higher compressive strength(higher density) will result in higherYoung’s modulus (lower flexibility). Inavoiding mechanical damage, it was de-termined that cements with a high ten-sile strength to Young’s modulus ratio,and with a low Young’s modulus valuecompared to that of the rock, are the bestcements in terms of mechanical durabili-ty [9].When production begins, the heat fromthe reservoir quickly rises to the uppersection and heats up the entire hydro-thermal system (analogue to Fig. 1). Itcould easily be a temperature spike in ex-cess of 100 °C. This shock effect will gen-erate a huge force on the casing, there-fore on the cement, and lead to cementsheath cracking if not designed properly.

Tab. 1 Flexible additives decrease permeability of the final set cement [9]

Formulation Flexible Additive DensityLbm/gal

WaterPermeability

mD1 Without 15.8 0.00102 Without 14 0.00763 Without 12 0.13808 With 14 0.00159 With 12 0.0310

Tab. 2 Requirements to Geothermal well cement

Parameters GTH GTP

Cement type- CEM I up to 40 °C- CEM III up to 90 °C- Class G up to 110 °C

- CEM I up to 40 °C- CEM III up to 90 °CClass G up to 110 °C

- G+ Silica up to 175 °C1)

Density 1500 & 1750 kg/m³ 1600 & 1900 kg/m³Thickening time As operation required As operation requiredRheology Not critical CriticalFluid loss Not critical Not criticalFree fluid Critical CriticalStability Not critical CriticalCompressive strength Not critical CriticalThermal conductivity Critical CriticalFlexibility Not critical CriticalExpansion Not critical CriticalSelf-healing Not critical Not criticalPermeability & Porosity Critical Critical1) Such hydrothermal system needs to be thoroughly evaluated on temperature transmissivity, where all ce-mented casings will see the production heat. Silica added cement may be required for all cementations.




Expansion: Shrinkage and expansion ofthe cement results from the formation ofhydration products having different vol-umes compared to the hydrating compo-nents. The changes in external cementsample dimensions are referred to as bulkshrinkage and bulk expansion [10].Expanding cement systems will thereforework best in hard rock formations, whichare able to resist the expansion forces ofthe expanding cement. If the reservoirrock is considered as soft, then the use ofan expanding agent is dangerous andmay lead to self-destruction of the ce-ment sheath.Self-healing: Same as for GTH .Permeability and porosity: With the in-crease of density and hence the solidcontent, the compressive strength of thecement stone, both porosity and perme-ability will also improve (reduced). It isimportant to understand the effect of thetemperature on the cement stone andadd the necessary amount of silica intothe cement blend (Fig. 6, 7, 9).Volumes, rates and loss circulation: Most ge-othermal reservoirs are naturally frac-tured or porous, and have high permea-bility. It is therefore common to havelarge cementitious volumes, weak for-mation and losses into reservoirs. Excesscement slurries should never be derivedfrom experience in oilfield wells, butrather from caliper measurement withapplication of appropriate safety margins.Pumping rates within weak formationshould be lowered, in order to keep dy-namic and friction pressure as low as

possible. However, this is not always pos-sible, and does not correlate with largecement slurry volumes and thickeningtime. For this reason, low-density slurriesand loss circulation materials can oftenbe a good solution.

ConclusionEvery wellbore is unique. This arti-cle serves only as a basic guideline,

since each well condition may requirespecial attention to all downhole chal-lenges (salt formation, gas influx, weakformation, temperature anomaly, etc.).That is why good knowledge of the ce-menting and available cements is neces-sary for all partners involved in planning,drilling and running a geothermal pro-ject. Ideal zonal isolation and casing pro-tection for the geothermal well must bequickly setting, insulating, impermeable,flexible and softer than formation.

References[1] "California's Oil," API, Dallas (1948)[2] Eirik Karstad, Bernt S. Aadnøy, Temperature model

provides information for well control, Oil & Gas Jour-nal, (1998)

[3] Prof. Dr. Plank, Lehrstuhl für Bauchemie, TechnischeUniversität München

[4] Nelson and Eilers, Well Cementing, (1985)[5] HFW Taylor, The chemistry of cement hydration,

(1963)[6] D. Lentsch, K. Dorsch, N. Sonnleitner, A. Schubert,

Prevention of Casing Failures in Ultra-Deep Geother-

mal Wells, Proceedings World Geothermal Congress,(2015)

[7] Gunnar Skúlason Kaldal et al., Collapse analysis ofthe casing in high temperature geothermal wells,38th Workshop on Geothermal Reservoir Engineer-ing, (2013)

[8] Catalin Teodoriu, Why and When Does Casing Fail inGeothermal Wells: a Surprising Question? World Ge-othermal Congress, (2015)

[9] Le Roy-Delage S. et al, New Cement Systems forDurable Zonal Isolation, IADC/SPE Drilling Confer-ence, (2000)

[10] De Rozieres, J., Shrinkage and Expansion of Oil WellCements, Report of the API work group on shrink-age, (1995)

Yashar Yadigarov holds M.Eng inCivil Engineering specialised at Flu-id Hydraulics. He is an expert inwellbore cementing and stimula-tion, started his oilfield career in2002 with Schlumberger Caspian.

Yadigarov worked as an engineer, then technicalinstructor for Schlumberger UK Training Centre andlater as Technical Leader. Between 2009 and 2017,he was Senior Engineer, Engineering Manager andGeneral Manager with in a German service compa-ny. In 2017,Yadigarov founded DEUTECS GmbH andcurrently delivers various services to E&P compa-nies worldwide. Besides the technical knowledge,he owns an extensive experience with field opera-tion, management, personnel and training.



ERDÖLERDGASKOHLE

C61

83E




ERDÖL ERDGAS KOHLE



MMAARRKKEETT AANNAALLYYSSIISS


Russia’s LNG on the World Market: Startingthe PenetrationBy E. M. KHARTUKOV*

IntroductionRussia began to export LNG quite recently– at the end of March 2009. The first Rus-

sian LNG cargo for delivery to Japan has beensuccessfully loaded from the Sakhalin II LNGplant into the Energy Frontier LNG carrier.The Energy Frontier left the Prigorodnoye porton 29 March for the Sodegaura terminal inTokyo Bay, with a cargo of some 145,000 m³ ofLNG intended for Tokyo Gas and Tokyo Elec-tric. The LNG was loaded through the 805 mlong jetty at the Prigorodnoye port, which wasbuilt for the year-round export of liquefiednatural gas (LNG) and crude oil.

Sakhalin-2 LNG PlantThe Sakhalin-2 LNG plant is the firstof its kind in Russia. It is located in

Prigorodnoye at a coast of Aniva Bay, 13km east of Korsakov. Construction of theLNG plant was carried out by OAO Nipi-gazpererabotka (Nipigaz) and the Khim-Energo consortium, together with twoJapanese companies Chiyoda Corpora-tion and Toyo Engineering Corp. Theplant has been designed to prevent majorloss of containment in the event of anearthquake and to ensure the structuralintegrity of critical elements such asemergency shut-down valves and thecontrol room of the plant.The LNG project facilities include:– two 100,000 m³ (3,500,000 ft³) LNGstorage tanks

– an LNG jetty– two LNG processing trains, each withcapacity of 4.8 million t of LNG per year

– two refrigerant storage spheres, 1600m³ (57.000 ft³) each (gross capacity) forpropane and ethane storage

– a diesel fuel system– a heat transfer fluid system for the sup-ply of heat to various process consumers

– five gas turbine driven generators with atotal capacity of around 129 MW elec-trical power

– Utility systems including instrument airand nitrogen plants and diesel fuel sys-tems

– A waste water treatment plant to treatboth sewage water and coil-containingwater.

The LNG plant production capacity is 9.6million t of LNG per year. The project op-erator is examining the possibility of add-ing another train. A special gas liquefac-tion process was developed by Shell foruse in cold climates such as Sakhalin,based on the use of a double mixed re-frigerant. The plant has two double-walled, storage tanks. LNG is exportedvia an 805 m jetty in Aniva Bay. The jettyis fitted with four arms – two loadingarms, one dual purpose arm and one va-por return arm. The upper deck is de-signed for a road bed and electric cables.The lower deck is used for the LNG pipe-line, communication lines and a foot-path. LNG is pumped from the storagetanks into the parallel loading lineswhich are brought to the LNG jetty. Atthe jetty head, the pipelines are connect-ed with the jetty's four loading arms. Thewater depth at the tail of the jetty is 14m. The jetty will serve LNG tankerswhich have capacities of between 18,000and 145,000 m³. Loading operations areestimated to take 6–16 h, depending onvessel capacity. The jetty will be able tohandle loading of around 160 LNG carri-ers per year. The whole project is man-aged and operated by Sakhalin EnergyInvestment Company Ltd. (SEIC orSakhalin Energy comprising now – since2007 – Gazprom (50% +1 share), RoyalDutch Shell (RDS) Group (27.5% –1

share), Mitsui & Co. (12.5%) and Dia-mond Gas-Mitsubishi Corp. (10%).

Yamal LNG PlantOn December 9, 2017, the firsttanker loaded with liquefied natural

gas from the Yamal LNG plant has leftRussia for Europe. With a capacity ofnearly 20 million t/a, the launch of theYamal LNG plant has been an unmitigat-ed success, especially given that it is thefirst Russian LNG project in which Rus-sian shareholders have had a controllinginterest from the outset.The Yamal LNG is now the northernmostgas-liquefaction project existing in Rus-sia. Yamal LNG is a liquefied natural gasplant located in Sabetta at the north-eastof the Yamal Peninsula, Russia. In addi-tion to the LNG plant, the project in-cludes production at the Yuzhno-Tam-beyskoye (South Tambey) gas field, andthe transport infrastructure, includingthe Sabetta seaport and airport.The groundbreaking ceremony for theport construction was held in July 2012;however, construction of the port itselfbegan only in the summer of 2013. InDecember 2014, amid the 2014–15 Rus-sian financial crisis, the Russian govern-ment gave a 150 billion Rouble (morethan US $ 2.6 billion) subsidy to the pro-ject.The three-train Yamal LNG plant, de-signed to produce about 16.5 million t/a,started liquefying natural gas from the

* Eugene Khartukov, Moscow State University for Interna-tional Relations (MGIMO), Head of Center for PetroleumBusiness Studies (CPBS) and World Energy Analyses &Forecasting Group (GAPMER), and Vice President for theFSU of Geneva-based Petro-Logistics SA. E-Mail: [email protected]


Fig. 1 Main existing and planned LNG-liquefaction projects in Russia(Existing as of 1/1/2018) [1]

Khartukov_OGEM4.indd 204 26.11.2018 14:43:19



South Tambey field earlier in December2013. The export project’s first liquefac-tion train will gradually ramp up capacityto 5.5 million t/a. Phase II and III (eachwith a capacity of 5.5 million t/a) werecommissioned in the third quarter of2018 and the first quarter of 2019, re-spectively. The project cost is estimated atnearly US$ 27 billion.China is expected to take more than 4million t out of the total a year whenonce the plant hits full production capac-ity, CNPC said in a statement posted onits website.The first Yamal cargo is being carried bySovcomflot’s Arc7 ice-class LNG tankerChristophe de Margerie (named after To-tal’s recently died head) with a capacityof 172,600 m³. The LNG carrier is thefirst of 15 ice-class tankers built to shipcargoes from the Yamal LNG project. Ac-

cording to the vessel tracking data by themarine data provider, Vessels Value, theLNG tanker is scheduled to dock at theDanish port of Skagen around December17.To remind, Yamal LNG and Belgium’sFluxys LNG signed a 20-year contract fortransshipment of up to 8 million t/a ofLNG at the port of Zeebrugge with YamalTrade (a 100% subsidiary of Yamal LNG)to support year-round LNG deliveriesfrom the Yamal Peninsula to Asian-Pacif-ic markets. During a summer navigationperiod, Arctic-class LNG tankers will de-liver LNG directly to customers. In a win-ter, they will be placed in the ZeebruggeTerminal where Fluxys will provide ser-vices to transship LNG on conventionalgas-tankers for further delivery to cus-tomers in Asia via the Suez Canal. Ac-cording to Yamal LNG’s estimate, it will

take half as much time to ship LNG toAsian countries using the eastward routeas the westward one. However, this ben-efit will be fully realized only after Atom-flot commissions three universal nuclear-powered 60MWt ice-breakers (the Arkti-ka, Sibir and Ural) in 2019, 2020 and2021.Ice-breaking gas-carriers are necessarilyneeded here as the Yamal LNG is locatedabove the polar circle in the estuary ofthe Ob River, a wild, remote region thatis frozen for seven-to-nine months a yearand where winter temperatures can dropto as low as –50 °C.The Yamal LNG project entailed con-structing a plant with the capacity to pro-duce of LNG. The South Tambey field onthe Yamal Peninsula, with 2P reserves of927 billion m³ according to PRMS classi-fication, serves as the plant’s resource

Tab. 1 Commissioned, under construction, and planned LNG export terminals in Russia.

Name of the Project(No. of Trains)

Location Actual or ExpectedYear of Commis-

sioning

Operator LiquefactionCapacity,

in million t/a

Technology Type Actual or ExpectedInvestment,

in US $ billion

Sakhalin-2 LNG (2)South of theSakhalin Isl.

2009 SEIC 9.6Royal Dutch ShellDMR; onshore

10

Sakhalin-2 LNGExpansion (1)

South of theSakhalin Isl.

2018–2021 SEIC 5.4Royal Dutch ShellDMR; onshore

?

Yamal LNG (3)North-east of theYamal Peninsula

2017Yamal LNG (Novatek,Total, CNPC and Silk

Road Fund)19.8

Air Products and Che-mi-cals (AP-CI)'sC3MR; onshore

26.9

Arctic LNG (3)West of the Gydan

Peninsula2022–2025

Arctic LNG-2(Novatek and Total)

18.3 Linde; onshore 18

Baltic LNG (2)Port of Ust-Luga,the Leningrad

Region2018–2023 Gazprom 10–15

Royal Dutch Shell;onshore

11.5

Vladivostok LNG (2)

Lomonosov Penin-sula (near the cityof Vladivostok, thePrimorye Territory)

2018–2020 Gazprom 13.6 Onshore 13.5–15.7

Pechora LNG (2)

Port of Indiga,coast of the Pe-

chora Sea; the Ne-nets Autonomous

District

2018 (?) Alltech 4–8Air Products and

Chemicals (AP-CI)'sC3MR; onshore

> 4

Far East LNG (Sakhalin-1LNG) (2)

North-west coastof the Sakhalin Isl.

2019-2024 Exxon-Mobil 5–10 Air Liquide; onshore 12–15

LNG Terminal at Vy-sotsk/Primorsk port (2)

Vysotsk/ Primorskport, north-east

coast of the Gulf ofFinland, the Lenin-

grad Region

2018–2019 Novatek (?) 1.3–1.5 Air Liquide; onshore 2

Portovaya LNG (1)

The settlement ofSeleznevskoye,near Vyborg, theLeningrad Region

2019 Gazprom 1.5 OMZ; onshore 2.1

Shtokman LNG (2)

Near the settle-ment of Vidyaevo,coast of the Bar-ents Sea, the Mur-mansk Region

?

Shtokman Develop-ment (initially Gaz-prom, Total and Sta-

toil-Hydro)

15 Onshore 30

FLNG Gorskaya (3) Gulf of Finland 2017–2021 LNG Gorskaya 0.4–1.25 Proprietary; Floating ?

Norilsk LNG (1)Port of Du-dinka,the Yenisei River

? Norilsk-Gazprom 2 ? ?

Yakutsk LNG (1) Port of Ya-kutsk,the Lena River ? ? 1 ? ?

Anadyr LNG (1) Port of Ana-dyr, theBer-ing Sea ? ? 0.1 ? ?

Arkhan-gel’sk LNG (1) Port of Ar-khangel’sk, ? Sozvezdie Association 0.15 ? ?

Total (29) – – – 117.65–122.2 – > 93.1–98.3




base. The project is operated by YamalLNG, whose shareholders include nowNovatek (50.1%), Total (20%), CNPC(20%) and the Chinese state-run SilkRoad Fund (9.9%). The project is valuedat US$ 26.9 billion.Novatek, Russia’s second biggest gascompany (after Gazprom), purchased a51% stake in Yamal LNG in 2009. Twoyears later, Novatek increased its stake to100% only to sell a 20% interest to Total(France) soon after. In 2013, CNPC (Chi-na) joined the project by acquiring 20%,and the Silk Road Fund (9.9%) joined in2015.In 2010, Novatek and Gazprom enteredinto an agency agreement by whichGazprom Export was to transport gasacross the border for a commission fee,while Novatek would remain the pro-ject’s operator. However, by the end of2012, Gazprom Export had not signed acontract to supply gas from Yamal LNG.As a result, the project’s shareholders

were unable to use such contracts as col-lateral to obtain bank financing.In 2013, LNG exports were partially lib-eralized. The right to supply LNG abroadwas reserved to state companies operat-ing on the shelf and companies whose li-censes for field development as of Janu-ary 1, 2013, covered both LNG plant con-struction and transport of produced gasfor liquefaction. In addition to Gazprom,only Rosneft and Novatek met these cri-teria. As a result, in November 2013,Yamal LNG signed a contract with GasNatural Fenosa (GNF) from Spain to sup-ply 2,5 million t of LNG annually over 25years. Agreements were also signed withTotal (4 million t/a) and PetroChi-na (aCNPC subsidiary, 3 million t/a), as well aswith Novatek Gas & Power (2.9 milliont/a) and Gazprom Marketing & TradingSingapore (3 million t/a). By March2016, 96% of the liquefied gas to be pro-duced by the plant was contracted underlong-term agreements. In December

2013, Yamal LNG’s board made a finaldecision to move forward on the project,which at the time required capital invest-ments of US$ 26.9 billion.In 2014, Novatek became subject to theanti-Russia sanctions. Hence, the coreproject funders were Russian and Chi-nese state banks. In April 2016, YamalLNG signed a loan agreement with Sber-bank and Gazprombank for € 3.6 billionfor a term of 15 years. At the same time,an agreement was reached with the Ex-port-Import Bank of China and ChinaDevelopment Bank for loans. As a result,in April 2016, the Export-Import Bank ofChina and China Development Bank be-came the key partners for this project byproviding loans for € 9.3 bln.Launched in late 2013, the Yamal LNG isone of the largest and most complex LNGprojects in the world. But it is also one ofthe most competitive, as it leverages theimmense onshore gas resources of Rus-sia’s Yamal Peninsula.The project aims to tap natural gas re-serves of the enormous South Tambeygas and condensate field totaling morethan 4 billion boe. To do so, more than200 wells have been drilled and three liq-uefaction trains built, each with a capac-ity of 5.5 million t. Every year, nearly16.5 million t of LNG will transit throughthe port of Sabetta, with all LNG produc-tion sold to customers in Europe and Asiaunder 15- to 20-year contracts.At the start of 2018, the production ca-pacity of the project has been bumped upfrom the previously planned 16.5 milliont/a to 19.8 million t/a. The project wasstill expected to start exporting in 2022–2023.With the launch of the Yamal LNG plant,Russian exports of the liquefied naturalgas have grown more than 100% in thefirst three months of 2018. Russia has in-creased the LNG exports by 2.1 times, to9.8 million m³, while revenues surged toUS $ 1.3 billion.At present another huge LNG plant –Arctic LNG – is being built in Russia’s

Fig. 2 Operating, under design/construction, and possible LNG liquefaction plants andexisting bunkering terminals in Russia (as of the end of 2017) [2]

Fig. 3 LNG export capacity by Country in 2012-2022, in billion m³ [3]Fig. 4 World Trade in LNG by Region/Country in 2012-2022, in billion

m³ [4]




North – east of the Yamal LNG, on thewest coast of the Gydan Peninsula, in theshallow waters of the Gulf of Ob, the baylocated near the coast of the Kara Sea be-tween the peninsulas of Yamal and Gy-dan.

A rctic LNGConstruction of the plant began in2018. The plan is for three 5.5 mil-

lion t/a stages to be built: Stage 1 to becompleted in 2022, Stage 2 in 2023, andStage 3 in 2025.

This project will be less capital intensive(only US$ 10 billion) than the YamalLNG one – mainly due to the use of ad-vanced German technologies. Novatek,the project’s leader, will use Linde’s tech-nology of natural gas liquefaction, andhas purchased the necessary license fromthe Germans. Besides, the Russians areteaming up with the Italian companySaipem for the development of the gravi-ty-based structure (GBS), the installationwhich is to be installed on the seabed onthe Ob Gulf.The trains will rest on three stand-alone,ice-resistant platforms to be stationednear shore. The field itself is 40 km offthe platform. Before the produced gasgoes to liquefaction trains it must be pro-cessed by a gas treatment facility. Apartfrom treated gas, the treatment stage willbe producing condensate. The end prod-ucts – LNG and gas condensate – will beshipped directly from the platforms asthese will be installed with storage tanks.The Arctic LNG is to be ready for produc-tion by early 2023. It will be based onthree trains each with a production ca-pacity of 6.1 million t/a. Natural gas re-sources are based on the nearby Sal-manovskoye and Geofizicheskoye fields,and possibly also the Gydanskoye, East-Tambey and North-Ob fields. The pro-ject’s Front End Engineering Design(FEED) is reportedly to be ready by late2018 and a final investment decision tak-en before the end of 2019.With the Arctic LNG-2, Novatek willboost its annual production of LNG tomore than 34 million t. That liquefiednatural gas will all be shipped outthrough the Northern Sea Route (NSR),some of it going eastwards to Asian buy-ers. At the beginning of 2018 Novatekwas looking to bring Saudi Aramco on-board its second liquefied natural gas ex-port project proposed for the Arctic.Comments came following the memo-randum of understanding signed in earlyFebruary, that will see the companies co-operate on international projects includ-ing LNG.French oil and gas major Total has got in-terested in participating in Novatek’s sec-ond LNG scheme on Russia’s Arctic coast.In May of 2018, Novatek and Total signedan agreement in respect of participationof the French company in Arctic LNG-2project. The document was signed aftertalks between Russian President VladimirPutin and France’s President EmmanuelMacron in their presence.Novatek will sell the share of 10% in theArctic LNG-2 project to France’s Total,Chief Executive Officer of Novatek Leo-nid Mikhelson told reporters on the side-lines of the St.Petersburg InternationalEconomic Forum (SPIEF) of 2018.Thisfigure is indicated in the agreement forsale of 10% in the project to Total.

Tab. 2 LNG carriers used and planned to be used by Russia (as of the start of 2018) [5]

Vessel Name Year Built/Expected Delivery

Carrying Capacity,in m³

Charterer(s)

Energy Frontier 2003 119,393 (2) Tokyo Lng Tanker (1)

Clean Energy 2007 149,700 Gazprom

Ob River 2007 149,700 Gazprom, SEIC

Grand Elena 2007 147,968 NYK, Sovcomflot (1)

Amur River 2008 149,700 Gazprom, SEIC

Grand Aniva 2008 145,000 NYK, Sovcom-flot (1)

Grand Mereya 2008 145,964 MOL, K Line, Primorsk (1)

Yenisei River 2013 155,000Gazprom, Yamal LNG; Dy-

nagas LNG (1)

Lena River 2013 155,165Gazprom, Yamal LNG; Dy-

nagas LNG (1)

Clean Ocean 2014 161,881Yamal LNG, Cheniere; Dy-

nagas LNG (1)

Clean Planet 2014 161,814Yamal LNG; Dynagas LNG

(1)

Pskov 2014 170,200 Sovcomflot (1)

Clean Horizon 2015 161,870Yamal LNG; Dynagas LNG

(1)

SCF Melampus 2015 170,200 Sovcomflot (1)

SCF Mitre 2015 170,200 Sovcomflot (1)

Clean Vision 2016 162,000 Yamal LNG

Yamal Hull 2421 2017 172,410 Yamal LNG


Christophe de Margerie 2016 172,845 SCF (1)

Boris Vilkitsky 2017 172,000; 28,806 (2) Dynagas LNG (1)

Eduard Toll 2017 172,000 Teekay/CLNG JV (1)

Vladimir Rusanov 2017 128,806 (3) Yamal LNG




(1)Owner(s). (2) Gross Tonnage; summer deadweight – 73,795 dwt. (3) Gross tonnage; summer deadweight –96.958 dwt. (4) Gross tonnage; summer deadweight – 96.844 dwt.

Tab. 3 The world’s share of Russia’s LNG exports in 2010–2017

Year Russia’s LNGExports, in million t

World’s Total LNGExports, in million t

World’s Share,in %%

2010 1.9 222.2 0.92011 2.3 241.5 1.02012 1.4 237.7 0.62013 1.5 236.8 0.62014 3.4 239.2 1.42015 3.6 245.2 1.52016 3.7 263.6 1.42017 3.3 289.8 1.1




The Russian company plans to close thedeal as early as in the first quarter of2019.Recently, the Chinese CNPC has ex-pressed an interest in the Arctic LNG-2,as reported by Li Yueqiang, CNPC’s Inter-national Department Director-General.Chinese companies are discussing the is-sue of entering into a new project of No-vatek for the liquefaction of natural gas,said Russian Energy Minister AleksandrNovak on the TV First Channel on June12 after the Russian-Chinese summittalks.

O ther PlantsAlso under construction are Baltic,Vladivostok and Pechora LNG ter-

minals with combined expected capacityof 27.6–33.8 million t/a, let alone small-er-scale projects and ones, which are notbeing built but planned for after 2021possible starts.Altogether, the known Russian LNG pro-jects with nearly 30 trains can producequite soon up to impressive 122 milliont/a of LNG, the bulk of which is destinedfor exports (Tab. 1).Unsurprisingly, all Western analysts pre-dict a substantial growth both in LNG ex-port capacities and exports of LNG in/from Russia in the years to come (Figs. 3and 4).

LNG-CarriersAt present, a fleet of nearly 20 LNGcarriers owned mostly (wholly or

partly) by Sovcomflot is used by Russia toexport its LNG (Tab. 2).Dynagas Holding, the sponsor of DynagasLNG Partners, said that it has entered in-to long-term time charter agreements forfive ARC7 and four ARC4 carriers for thegiant Yamal LNG project. Dynagas willbuild five 172,000 m³ ARC7 LNG carriersat Daewoo Shipbuilding & Marine Engi-neering shipyard in South Korea whichwill be serving the Novatek-operatedYamal project under long-term timecharters, the company revealed in astatement. The vessels will be capable ofbreaking 2.1 m of ice in both the forwardand reverse direction.In addition, four of Dynagas’ existingARC4 LNG carriers will join the Yamalshipping fleet to support Yamal deliveriescommitted to Asian buyers from year2019 onwards and will be time-charte-red for a period of 15 years each. Besides,both Rosneft and Sovcomflot have al-ready placed orders of several ice-classvessels at the Zvezda shipyard on Russia’seast coast. The yard is heavily supportedby the federal authorities and is built tobe able to construct big-scale tankers, in-cluding those with ice classification.

LNG ExportAs for Russia’sLNG exports,

all revolves aroundGazprom, which isup to now the onlyRussian companypossessing the legalright to exportLNG. Therefore,Russia’s LNG ex-ports andGazprom’s LNGoverseas trade areabsolutely thesame – at least, sta-tistically, in actualnumbers, whichindicate a dramaticprogress in recentyears.Since the mid ofthe first decade ofthis millenniumand by 2014–2017annual exports ofLNG by Gazprom(or Russia) havegrown from a mere0.1 million t toover 3 million t de-livering to Japan,continental China,Taiwan, Kuwait,South Korea, India,Spain and Pakistanto mention onlymajor buyers (Fig.5).In particular, in2015–2017 Gazprominked long-termagreement withGAIL to deliver LNGto India and 8-yearsales and purchasecontract for floatingLNG terminal offCameroon with Per-enco, SNH and Go-lar. LNG fromGazprom portfolioalready supplies tosuch countries asKuwait, Thailandand the UAE (Fig.6).LNG and export ofgas by tankers arevery unusual forGazprom, whichhas two deep-rooted and well known gas“traditions”: “land and pipes”. Neverthe-less, at the beginning of 2018 Gazexport’shead Aleksandr Medvedev was reportedto state in Hong Kong that by 2025Gazprom would surely provide around6% the world’s LNG exports. Quite ahard but still realistic prediction, bearing

in mind the above mentioned plans toaggressively develop the country’s LNGbusiness, despite the fact that Gazprom’sall-time high share of global LNG tradewas only 1.5% (Tab. 3). The picturewould have been surely incompletewithout a coverage of Russia’s LNG pric-es, which scrambled up (in case of Japan)from US $ 99.53/m³ (or US $ 3.16/mmB-

Fig. 5 Gazprom/Russia’s Annual LNG Exports in 2005–2017, in milliont [6].

Fig. 6 Gazprom LNG portfolio in 2017 [7].

Fig. 7 Price competitiveness of Russian LNG in Japan and South Ko-rea




tu) in 2009, fob, to some US$ 7.5/mmB-tu in 2017, cif (Fig. 7). This may be com-pared with Germany border price forRussian NG, which stood at less than US$318.8/1,000 m³ (or a bit below US$ 8.5/mmBtu in 2009 (on the average) and de-creased to US$ 6.55/mmBtu in Decem-ber 2017. In its turn, according to US En-ergy Information Administration (EIADoE), an average annual fob price for USLNG was US$ 8.4/1,000 ft³ (or mmBtu)in 2009 and dropped significantly (downto US$ 4.69/1,000 ft³) in 2017.According to Russian and Japanese ana-lysts, the Russian Far East’s (Sakhalinand Vladivostok) LNG projects are fairlycompetitive compared with other majorLNG schemes worldwide (Fig. 8) and(which is of great importance) are locat-ed very close to Japan. That's why, de-spite the considerable drop in export

prices of US LNG,most Western ana-lysts fully agreethat “US-producedLNG cannot hold acandle to Russian[LNG] in Japan”.

OutlookAs for long-term projec-

tions, the Moscow-based Energy Re-search Institute ofthe Russian Acade-my of Sciences(ERI RAS) predict-ed in 2016 that by2040 Russia’s LNGshould grow up to

some 30 billion m³/a (14 million t/a) orup to 80 billion m³/a (37 million t/a) inits favorable scenario, while the same in-stitute foresaw in 2014 that by the sameyear that all the Russian LNG plantswould be producing 80–120 billion m³/a(37–55 million t/a) (Figs. 9 and 10)Too uncertain… Well, then let’s use BP’squite elaborative forecast, which wasprepared in 2018. According to the fore-cast of the company’s analysts, by 2040Russia’s LNG exports should reach some5 billion ft³/d (or almost 52 billion m³/aor nearly 24 million t/a) (Fig. 11). n

Prof. Khartukov is a leading inter-national expert on Russian and ex-Soviet oil and gas issues. During1970-82, he worked in various re-search centers, departments andenterprises of the USSR ministries

of geology, of oil and gas industry, of foreign tradeand of foreign affairs. Since 1980, teaches world oiland energy markets research at the Moscow StateUniversity for International Relations (MGIMO),USSR/RF Ministry of Foreign Affairs. Since 1984,heads the Moscow-based World Energy Analysis &Forecasting Group (GAPMER), advises and consultson oil and gas economics and policies and energypricing to various Soviet/ Russian ministries, inter-national agencies, foreign governments, private oiland gas companies, consulting firms and financialinstitutions, as well as to Gorbachev, Yeltsin and Pu-tin administrations; a member of the Council of En-ergy Advisors (USA) and Gerson Lehrman Group(UK) of energy consultants. In 1994-95 – Head ofRussia Energy Project, East-West Center, Hawaii,USA. Since 1995 – Vice President (for Eurasia) ofPetro-Logistics Ltd, Switzerland. Since 1996 – Gen-eral Director of (International) Center for PetroleumBusiness Studies (ICPBS/CPBS), Moscow, and Pro-fessor of Marketing, Management & Commerce atMGIMO. 2003-2012 – Director (for InternationalAffairs) of PetroMarket Research Group, Moscow.Obtained all his scientific titles (PhD, Doctor of Sci-ences and Professor) at the MGIMO respectively in1980, 1993 and 1994.

Fig. 8 Breakeven price of global LNG projects [9]

Fig. 9 Russia’s use of natural gas in domestic and foreign markets in2005–2040, in billion m³

Fig. 10 LNG production in the Russian federation in 2010-2040, in bil-lion m³ (in baseline and other Asia scenarios of ERI RAS)

Fig. 11 LNG exports by region and country in 1990-2040, in billion ft³/d[10]


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fe

n

MIXING

Reliable, proven and highly efficient mixing for the oil industryMixing is a vital part of many processes.How a mixer performs can affect finalproduct quality, productivity, processtimes and energy efficiency. There aremany factors in the design of a mixingsolution that will affect how well it op-erates. Understanding how to optimizethese can make a real difference toplant efficiency and profitability – andthis is where SPX FLOW can re-ally help.The SPX FLOW Lightnin® andPlenty® mixers and agitatorshave proven reliability and du-rability for oil, gas and petro-chemical applications and arewidely used in applications in-cluding drilling fluids, mudmixing and as pipeline staticmixers. The combination of ad-vanced technology and detailedprocess understanding makeSPX FLOW an ideal partner formixing solutions.Plenty heavy-duty side entrymixers are specifically designedand developed for tank storageand blending. Ideal for large di-ameter tanks or tanks withfloating roofs, which precludethe use of top entry mixers,they offer a cost-effective solu-tion for applications varying from ho-mogenization of clean fluids to crudeoil bottom sludge and water (BS&W)control. The mixers are highly efficientat converting energy into fluid motion,delivering greater output and reducedproduction costs. They do not suffersignificant energy losses at the pump,in the pipework, in the bends, or mostsignificantly, at the jet nozzles.To avoid drips on the ground and affordgreater environmental protection, the

Plenty side entry mixers have a wearresistant tank shut-off device with safe-ty check valve, which provides reliabletank closure for seal and bearing main-tenance under full tank conditions.Machined into the shaft as a singlecomponent instead of being welded on,this unique tank shut-off system is de-signed without compromise for assured

reliability. The mixers are further avail-able with a choice of seal options, in-cluding single, tandem and, for maxi-mum assurance against any leaks, dou-ble mechanical seals.From its Lightnin brand, SPX FLOW of-fers a wide range of mixers and high-efficiency impellers to meet broad ap-plication and industry needs. The high-ly reliable and popular Lightnin 70 Se-ries mixers have many standardconfigurations, an extended mechani-

cal seal range, and are one of the mostconfigurable and adaptable modelsavailable. They are well proven in pro-cesses including drilling mud andchemical processing.The wide variety of models, sizes andstandard options from SPX FLOW helpensure its customers get great value formoney from solutions that increase

mixing efficiency, optimizethe amount of energy used,and perform reliably tomaximize process uptime. Along history of serving theoil, gas and petrochemicalindustries means solutionsare designed with a clearunderstanding of legislativerequirements and applica-tion needs to ensure thebest options for process andbudget.The in-depth expertise SPXFLOW has in mixing is sup-ported by a continuous pro-gram of research and devel-opment to ensure productsoffer superb strength, relia-bility, safety and perfor-mance. A complete under-standing of the science ofmixing and advanced engi-

neering capability, further mean SPXFLOW can efficiently deliver highly ef-fective, bespoke solutions for even themost arduous of mixing processes. Cli-ents also benefit from a comprehensive,global service network, designed to en-sure their solutions remain reliable andoptimized throughout their lifetime.www.spxflow.com

n

EID Energie Informationsdienst GmbH Banksstr. 4 20097 Hamburg Tel. 040/303735-20 [email protected]

Follow us on LinkedInOIL GAS

EuropeanMagazine(International Edition of ERDÖL ERDGAS KOHLE)

OG 4 News+Pet.indd 210 26.11.2018 12:38:53

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FLARING

Bilfinger’s mobile flare stack reduces plant emissionsRapid, flexible, and variable solutions,whether for complete plants or individu-al sub-process systems, are playing anever greater role in the process industry.A good example is the self-contained, high-temperatureflaring system, deployable onshort notice, that the indus-trial services provider Bilfin-ger has developed as a prod-uct solution for the oil corpo-ration ExxonMobil. By com-bining sophisticatedtechnology with flexibilityand user friendliness, Bilfin-ger has met an as-yet unful-filled demand on the Ger-man market. Another com-pelling aspect of this newproduct is the high degree ofsafety it provides: By ensur-ing that excess flue gases areburned off without danger,the mobile flare stack reduc-es the throughput load of ex-isting plant systems.“Mobile systems are becom-ing more and more impor-tant. They can be deployedin flexible fashion, they aresafe to operate, and they areenvironmentally friendly,”said Hanno Wennekamp,Project Manager at BilfingerEMS. The mobile flare stackis securely mounted on atrailer vehicle, allowing it tobe rapidly transported to the desired de-ployment site. Both the body assemblyand the chassis of the trailer can be vari-ably adjusted to meet the specific re-quirements of each customer. Furtherfeatures sure to find favor on the marketis the flaring system’s availability and itsall-around uses, since it was conceivednot only for scheduled inspection, main-

tenance or repair work, but also for un-scheduled deployments, e.g. in responseto accidental gas leaks.The subsidiary Bilfinger EMS disposes

over the necessary expertise to manufac-ture mobile products tailored to specificcustomer needs within its own produc-tion sites. The industrial service providerhas significant experience in developingmobile solutions such as gas-scrubbingsystems, capacity & load-relief systems aswell as pump trailers, all of which havealready been placed into service success-

fully by various customers. The mobileflare stack is another logical step alongthis path. “In principle, the mobile con-cept can be carried over to any number

of plant strategies and, thanks toits flexible deployability, repre-sents a huge advantage for ourcustomers in terms of costs, tech-nology, and the time saved,”Hanno Wennekamp explained.The mobile flare stack’s design al-lows it to be autonomously oper-ated (by battery power) for sev-eral hours. The flaring system’sarm is raised to the desired heightby means of a hydraulic powertrain. A touch panel allows foruser-friendly operation. All therequired consumables, such as ni-trogen and propane, are carriedalong on board. The product solu-tion developed for ExxonMobilcan also be run on acid gas – amixture of natural gas and hydro-gen sulfide.The technical challenges involvedwere manifold. For one thing, thespecifications normally applicableto a high-temperature flaring sys-tem had to be transposed to amobile platform. Weight, temper-ature, and ease of operabilitywere critical considerations inthis context. Moreover, the engi-neers had to come up with acompact construction design thatwould make the product easily

transportable yet durable and robust atthe same time. Moreover, the mobileflare stack’s safe operability and readinessfor use had to be made resistant to trans-port-related shocks or vibrations and tothe effects of changing weather condi-tions.www.bilfinger.de

n

The concentrated power of SPX FLOW bolting systems and power team brandsThrough its Bolting Systems and PowerTeam brands, SPX FLOW provides a fullrange of safe, reliable, robust bolting andhydraulic power tool solutions. The toolsare both powerful and practical, using ad-vanced material technology to obtainstronger, lighter and smaller solutions tomeet the demands of industry.SPX FLOW Bolting Systems offers innova-tive, robust, reliable, efficient, hydraulictorque and tensioning solutions, which arewidely used in downstream oil & gas appli-cations, upstream subsea pipelines, blow-out preventer (BOP), nipple up/down ap-plications and many more. They also have

vast experience in flange management ser-vices and controlled bolting solutions to as-sist with construction, operation and main-tenance activities. Its leading solutions aresupported by a comprehensive range of ser-vices to help ensure safe, timely and cost-effective project completion.Power Team tools are widely used in manyheavy-duty applications and include every-thing from hydraulic pumps, cylinders,jacks and valves to torque wrenches,clamping components and specialty hy-draulic equipment. All are designed to givereliable performance with strong, concen-trated forces in demanding applications.

Power Team and Bolting Systems solutionsand services set a benchmark in industryfor reliability, quality and safety. Through aglobal distribution, and service network,which can provide local products, parts andservice in over 150 countries, they are ableto provide tools when and where they areneeded to keep oil industry projects run-ning smoothly. They also offer training andbolting rental- and most of the productrange is backed up by the lifetime ‘Power-thon Warranty’, further details of whichcan be provided on request.www.spxflow.com

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OG 4 News+Pet.indd 211 26.11.2018 12:38:53

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January15–16 January IOSF 2019 – International OpEx &Safety Forum, London, United Kingdom. https://www.europetro.com/week/iosf201923–24 January Maximizing Propylene Yields 2019,Barcelona, Spain.www.wplgroup.com/aci/event/max-imising-propylene-yields/29 –31 January LNG Bunkering Summit 2019, Am-sterdam, Netherlands. https://lngbunkering.iqpc.co.uk/28–30 January European Gas Conference, Vienna,Austria.www.europeangas-conference.com/

February5–7 February Subsea Expo, Aberdeen, UK. www.sub-seaexpo.com14–15 February GeoTHERM, Offenburg, Germany.www.geotherm-offenburg.de26–28 February International Petroleum Week, Lon-don, UK. www.ipweek.co.uk

March4–7 March DGG Annual Meeting, Braunschweig, Ger-many. www.eage.org5–7 March SPE/IADC Drilling Conference & Exhibi-tion, The Hague, netherlands.www.spe.org/en/events/drilling-conference/home/14–15 March ICOGPE 2019 : 21st International Con-ference on Oil, Gas and Petrochemical Engineering,London, UK. https://waset.org/conference/2019/03/london/ICOGPE18–22 March SPE Forum: Shaping the Next Wave inWell Plugging and Abandonment, The Hague, Neth-erlands.www.spe.org/events20–21 March SPE Workshop: Innovative ArcticTechnologies, Harstad, Norway.www.spe.org/events27–28 March European Fuels Markets & RefiningStrategy Conference, Frankfurt, Germany.www.wpl-

group.com/aci/event/fuel-market-refining-strategy-conference/27–29 March Offshore Mediterranean Conferenceand Exhibition, Ravenna, Italy. https://www.omc2019.it/28–29 March World Congress & Expo on Oil, Gas &Petroleum Engineering (WCEOGPE-2019), Milan, Ita-ly. https://scientificfederation.com/wceogpe-2019/in-dex.php

April8–10 April EAGE IOR 2019, Pau, France. https://events.eage.org/2019/IOR%2020198–11 April IOR 2019, Pau, France.www.eage.org9 April 4th International LNG Summit, Barcelona,Spain.www.lngsummit.org9–10 April IADC/SPE Managed Pressure Drilling &Underbalanced Operations Conference, Amsterdam,The Netherlands.www.iadc.org/event/iadc-spe-mpd-ubo-2019/16–17 April Global Congress on Renewable andNon Renewable Energy, Rome, Italy.www.cognizanc-escientific.com/renewable-non-renewable-energy/15–18 April NEFTEGAZ 2019, Moscow, Russia.www.neftegaz-expo.ru/en/22–24 April EAGE/DGMK Joint Workshop on DeepGeothermal Energy, Celle, Germany.www.eage.org22– 26 April Education Days Aberdeen 2019, Aber-deen, UK.www.eage.org25–26 April DGMK/ÖGEW Spring Meeting, Celle, Ger-many.www.eage.org28 April–2 Mai Sixth EAGE Shale Workshop, Bor-deaux, France.www.eage.org

Mai14 May SPE Norway One Day Seminar , Bergen, Nor-way.www.spe.org/events

June3–6 June SPE Europec featured at 81st EAGE Con-ference and Exhibition, London, UK.www.spe.org/events3–6 June 81st EAGE Conference & Exhibition 2019,London, UK.www.eage.org11–12 June Future Oil & Gas, Aberdeen, UK.www.fu-tureoilgas.com

September2–6 September Fourth EAGE Conference on Petro-leum Geostatistics, Florence, Italy.www.eage.org3–6 September SPE Offshore Europe Conferenceand Exhibition, Aberdeen, UK.www.spe.org/events

October21–25 October Education Days Oslo 2019, Oslo, Nor-way.www.eage.org

November5–6 November 5th CWC World LNG Bunkering Sum-mit, Hamburg, Germany.www.cwclngbunkeringsum-mit.com

FIND ALL EVENTS ONLINE: www.oilgaspublisher.de

Event Calendar

BIOPLASTICS

Thyssenkrupp commissions first commercial bioplastics plant for COFCO in ChinaTo reduce reliance on petroleum-basedplastics, thyssenkrupp has developed amanufacturing process for the bioplasticpolylactide (PLA). The world’s first com-mercial plant based on the patented PLA-neo® technology recently started produc-tion in Changchun, China. It is operated bythe Jilin COFCO Biomaterial Corporation,a subsidiary of COFCO, China’s largest foodand beverage group. The new plant pro-duces all standard PLA types, among otherthings for the production of eco-friendlypackaging, fibers, textiles and engineeringplastics.Sami Pelkonen, CEO of the Electrolysis &Polymers Technologies business unit ofthyssenkrupp Industrial Solutions: “The

bioplastics market will continue to grow inthe coming years, not least due to the in-creasing environmental awareness of in-dustry, governments and consumers. Withour PLAneo® technology we want to doour bit to make the plastics sector more sus-tainable and resource-friendly. With it weenable our customers to produce high-quality bioplastics with a wide range ofproperties – at a price that is competitivewith conventional plastics.”Polyactide (PLA) is a 100% bio-based andcompostable plastic which thanks to itsphysical and mechanical properties can re-place conventional oil-based polymers inmany areas. The starting material for PLAproduction is lactic acid, which is recovered

from renewable resources such as sugar,starch or cellulose.PLAneo® technology converts lactic acidinto PLA in a particularly efficient and re-source-friendly way. Another advantage isits transferability to large-scale plants withcapacities of up to 100,000 t/a. In develop-ing the technology, thyssenkrupp’s subsidi-ary Uhde Inventa-Fischer profited fromdecades of expertise gained from the con-struction of more than 400 polymerizationplants and extensive experience in thescale-up of new technologies. For the newplant in Changchun thyssenkrupp provid-ed the engineering, key plant componentsand supervision of construction and com-missioning. www.thyssenkrup.com n

OG 4 News+Pet.indd 212 27.11.2018 11:15:15

OUTSTANDING PEOPLEOUTSTANDING OPPORTUNITIES

Vermilion Energy is an established operator in conventional oil and gas exploration and production in Lower Sa-xony. Based on the strong growth of Calgary-headquartered Vermilion Energy Inc. with over more than 23 yearsin the exploration and production of oil and gas and with a global production level of over 80,000 boepd, it is ourgoal to further expand our asset base in Germany. Our priorities are health and safety, environmental protectionand profitability through HSE – exactly in this order. We also commit ourselves to the interests of the communitiesin the regions where we are active and we are proud to regularly be a „Best Workplace“.

Based in the Hannover office, Vermilion provides three excellent opportunities to join a growing team within anexciting and growth focused company.

Supported by a strong leadership team, our staff drive a high performing, engaged,collaborative and community-minded culture that is the single most important factorin our success. Be part of us.

For further information please visit our homepage www.vermilionenergy.com. Please applyby e-mail to Laura Schiffner – [email protected], HR Advisor Germany.

Excellence. Delivered Daily.

2018

SENIOR GEOPHYSICIST (F/M)Integration, interpretation and assessment of all subsurface data2D/3D structural interpretation, time to depth conversion and seismic reservoir characterizationEvaluate farm-in and business development

PRODUCTION/DEVELOPMENT GEOLOGIST (F/M)Subsurface geological evaluationsMaximize the value of the producing assetsAnalysis of operation results and risk assessments

PERMITTING AND LAND ADVISOR (F/M)Responsible for all permitting activities and land mattersCollaborate with all relevant governmental and non-governmental organizationsSupport business development projects

EEK10_U3_18_Aufbau.indd 1 27.09.18 15:20

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