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OilGasPublisher

C 6183 E
ERDÖL
ERDGAS
OILS
KOHLE GA
Dezember
HEFT 12, 2015
131. JAHRGANG
12
ZINE
MAGA
EUROPEAN
OF
ITION
NAL EDHLE
NATIO
INTER ERDGAS KO
ERDÖL
Aufsuchung / Gewinnung . Verarbeitung / Anwendung . Petrochemie . Kohlen- / Biomasseveredlung
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ERDÖL ERDGAS KOHLE
vorm. Allgemeine Österreichische Chemiker und Techniker Zeitung – Central Organ für Petroleum-Industrie
(Gründungsjahr 1883, Wien)
vereinigt mit Erdöl & Kohle, Erdgas Petrochemie
Technisch / wissenschaftliche Zeitschrift für
Aufsuchung und Gewinnung, Transport und
Speicherung von Erdöl und Erdgas,
Verarbeitung und Anwendung von Mineralöl
und Erdgas, Petrochemie, Kohlenveredlung
Enthält 4 x jährlich (März, Juni, September,
Dezember) das OIL GAS European Magazine
– Int. Edition of ERDÖL ERDGAS KOHLE
Organ der:
DGMK Deutsche Wissenschaftliche
Gesellschaft für Erdöl, Erdgas und Kohle
ÖGEW Österreichische Gesellschaft
für Erdölwissenschaften
Wissenschaftlicher Beirat:
Prof. Dr. Leonhard Ganzer, ITE, TU Clausthal, Clausthal-Zellerfeld; Univ.-Prof. Dr. B.
Geringer, Institut für Verbrennungskraftmaschinen, TU Wien; Dr. R. O. Elsen, RWE
Power AG, Essen; Univ.-Prof. Dr.-Ing.
W. Klose, Universität Kassel; Dr. Dipl.-Geol.
M. Kosinowski, BGR, Hannover; Prof. Dr.-Ing.
C. Küchen, MWV Mineralölwirtschaftsverband
e. V., Berlin; Dipl.-Ing. H. Langanger, Strasshof bei Wien; Prof. Dr.- Ing. C. Marx, Owingen/Clausthal-Zellerfeld; Prof. Dr. K.
Millahn, Montanuniversität Leoben; Dipl.-Ing.
A. Möhring, Vermilion Energy Deutschland
GmbH, Schönefeld; Prof. Dr.-Ing. M. Reich,
TU Bergakademie Freiberg; Prof. Dr. Dipl.Ing. P. Reichetseder, Hattingen; Prof. Dr. R.
Reimert, Engler-Bunte-Institut, Karlsruhe;
Prof. Dr. K. M. Reinicke, ITE, TU Clausthal,
Clausthal-Zellerfeld; Dr. P. Sauermann, Deutsche BP Aktiengesellschaft, Bochum
Redaktion:
Dipl.-Geol. Hans J. Mager (Chefredakteur),
Hamburg
Dr. Christoph Capek, Wien
Verlag:
EID – Energie Informationsdienst GmbH
Anschrift von Redaktion und Verlag:
Neumann-Reichardt-Straße 34
22041 Hamburg
Postfach 70 16 06, 22016 Hamburg
Tel. (+49-40) 65 69 45-0, Fax 65 69 45-51
E-mail: [email protected]
In Österreich:
c/o ÖGEW, Wiedner Hauptstraße 63
Zimmer 4208, 1045 Wien
Tel. (+43) 5 90900-4891, Fax -4895
Geschäftsführung: Stefan Waldeisen
Anzeigenleitung: Harald Jordan
Vertrieb: Margret Storbeck
Titelbild: GDF SUEZ E&P Deutschland
GmbH, Lingen
Bohrplatz Römerberg vor Sonnenuntergang
ISSN 0179-3187
131. Jahrgang, Dezember 2015, Heft 12
ERDÖL
ERDGAS
OILS
KOHLE GA
EUROPEAN
MAGAZINE
ION OF
L EDIT E
ATIONA
HL
INTERNERDGAS KO
ERDÖL
Aufsuchung / Gewinnung . Verarbeitung / Anwendung . Petrochemie . Kohlen- / Biomasseveredlung
Inhalt / Contents
Geologie / Geology
Georgia – Petroleum Geologic Link from the Black Sea to the Caspian Region
W. NACHTMANN, A. JANIASHVILI and Z. SURAMELASHVILI OG 185
Bohr technik / Drilling
Successful Workover Operations for Milling Permanent Bridge Plugs at 8000 m MD
– A Case Study
K. SOLIMAN OG 193
Erdöl-/Erdgasfördertechnik / Oil/Gas Production
BTEX Removal from Production Water using Associated Gas
M. VALKENIER, G. HINNERS, and G. THEMANN OG 198
Analyses of Operating Electric Submersible Pumps (ESPs) of Different
Manufacturers – Case Study: Western Siberia
A. SUKHANOV, M. AMRO
and B. ABRAMOVICH OG 202
Improvement of Oil Production Rate using the TOPSIS and VIKOR Computer
Mathematical Models
M. ALEMI, M. KALBASI, F. RASHIDI OG 205
Real Value of “Real Options”
A. ZICH, K. S. VEREVKIN, and D. A. SOZAEVA OG 210
Maschinen & Anlagen / M achiner y & Plants
Oil-Flooded Screw Compressors for Unconventional Gas
A. ALMASI OG 212
Diagnosis of Centrifugal Pumps using Vibration Analysis
M. MINESCU, I. PANA and M. STAN OG 215
Wartung & Instandhaltung / Maintenance & Repair
Smarter Work with “Smartphones”
S. CIERNIAK and M. DUMAN OG 219
Rubriken
Nachrichten / News
OIL GAS News
Produkte & Dienstleistungen / Products & Services
Bücher & Berichte / Books & Reports
Veranstaltungen • Termine / Events of Note
Tagungskalender/Calendar
Persönliches / Personal Notes
452
OG 178
459, OG 221
461
461
460, OG 224
464
Mitteilungen
Mitteilungen der DGMK • ÖGEW / Societies News
Bericht über die ordentliche Mitgliederversammlung der DGMK
Neue Mitglieder
463
463
465
Mitteilungen des FAM / FAM News
465
Nachrichten
DEUTSCHLAND
DVGW stellt Studie zur Wasserstoffeinspeisung ins Erdgasnetz vor
Einspeisung von bis zu zehn Volumenprozent Wasserstoff unkritisch
Power-to-Gas kann einen wichtigen Beitrag
zur Umgestaltung des Energiesystems leisten. Aufgrund seiner Kapazität ist das
500.000 km lange Erdgasnetz in Deutschland sehr gut für die Aufnahme und Speicherung von Wasserstoff aus erneuerbarem
Strom geeignet. Der Wasserstofftoleranz
des deutschen Erdgasnetzes kommt damit
eine entscheidende Bedeutung für die Einbindung von Ökostrom ins Gasnetz zu.
Vor diesem Hintergrund kommt eine Ende
Oktober auf der gat 2015 in Essen vorgestellte Studie zu dem Ergebnis, dass die bestehende Erdgasinfrastruktur für Wasserstoffbeimischungen im einstelligen Prozentbereich von bis zu 10 Vol.-% grundsätzlich geeignet ist. In diesem in Deutschland
und Europa bisher einzigartigen, von E.ON
und dem DVGW verantworteten Projekt
wurden dem Erdgas in einem Erdgasverteilnetz der Schleswig-Holstein Netz AG mit
seiner bestehenden Infrastruktur und Gerätetechnik über mehrere Monate steigende
Anteile an Wasserstoff zugemischt. Bislang
wurden direkte Netzeinspeisungen mit unveränderter Gerätetechnik nur bis 2 Vol.-%
Wasserstoff erforscht.
Das DVGW-Forschungsprojekt »Ermittlung
der Wasserstofftoleranz der Erdgasinfrastruktur und assoziierten Anlagen« überprüfte das Polyethylen-Netz vor und während der Einspeisung ohne feststellbare Auffälligkeiten.
Die Einspeisung erfolgte bei deutlich fluktuierender Erdgasabnahme in mehreren Stufen von 4, 6,5 und 9 Vol.-% Wasserstoffbeimischung. Durch begleitende Messungen an
zahlreichen Kundenanlagen konnte die
Wasserstoffkonzentration und Abgaszusammensetzung am jeweiligen Gasgerät erfasst werden. Neben den Messungen wurden
auch Rückmeldungen von Kunden bzw.
Handwerkern in der Analyse des Feldtests
berücksichtigt.
Die Ergebnisse waren eindeutig: Die Gesamtheit der Kohlenstoffmonoxid-Messergebnisse blieb praktisch unverändert und
liegt in dem Bereich, der auch durch die
Schornsteinfegerstatistik der letzten Jahre
ausgewiesen wird. Gleichwohl gebe es noch
Forschungsbedarf hinsichtlich einiger zentraler Elemente wie etwa Erdgasspeicher,
Gasturbinen und den Tanks von Erdgasfahrzeugen, so die Studie.
AGEB-Prognose: Anstieg des Energieverbrauchs um 1,7 %
Die Arbeitsgemeinschaft Energiebilanzen
(AGEB) rechnet in diesem Jahr mit einem
Anstieg des Energieverbrauchs in Deutschland um etwa 1,7 % auf rund 456 Mio. t.
SKE. Wie die AGEB in ihrer traditionellen
Herbstprognose ausführt, werden die erneuerbaren Energien mit einen Zuwachs von
knapp 9 % am stärksten zulegen. Es folgt
aufgrund der gegenüber der im Vorjahr kühleren Witterung und dem damit höheren
Wärmebedarf das Erdgas mit einem Plus
von etwa 8,5 %. Der Mineralölverbrauch
wird in etwa auf dem Niveau des Vorjahres
liegen. Während der Verbrauch an Steinkohle um rund 2 % zurückgeht, wird es bei der
Braunkohle ein leichtes Plus von knapp einem Prozent geben. Der Beitrag der Kernenergie wird weiter sinken.
In den ersten neun Monaten des laufenden
Jahres lag der Verbrauch nach ersten Berechnungen der AG Energiebilanzen um
rund 2 % über dem Vorjahreszeitraum. Insgesamt erreichte der Energieverbrauch nach
drei Quartalen eine Höhe von 333,0 Mio. t
SKE. Um den Temperatureffekt bereinigt,
hätte sich der Energieverbrauch im Jahresverlauf nur geringfügig erhöht.
Der Mineralölverbrauch lag nach neun Monaten um rund 1 % unter dem Vorjahreszeit452
raum. Der Verbrauch an Kraftstoffen stieg
um knapp 1,5 % und erreichte damit einen
Anteil von rund 60 % am gesamten Mineralölverbrauch. Der Absatz an leichtem Heizöl
sank um etwa 7 %. Damit haben die Verbraucher trotz niedriger Preise bisher keine Aufstockung ihrer Bestände vorgenommen. Der
Verbrauch an schwerem Heizöl stieg infolge
höherer Bezüge der Petrochemie deutlich
an.
Der Erdgasverbrauch verzeichnete ein Plus
von 10 %. Hauptursache des Anstiegs war
die im Vergleich zum Vorjahr bisher durchschnittliche und damit kühlere Witterung,
die den Einsatz von Erdgas zur Wärmeerzeugung ansteigen ließ.
Der Verbrauch an Steinkohle sank in den
ersten neun Monaten leicht um 0,5 %, während der Verbrauch an Braunkohle um 1,7 %
über dem Wert des Vorjahreszeitraumes lag.
Bei der Kernenergie gab es ein leichtes Minus von 1,3 %. Die erneuerbaren Energien
erhöhten ihren Beitrag um insgesamt 9 %.
Bei den sonstigen Energieträgern kam es zu
einem Plus von etwa 4 %. Der Ausfuhrüberschuss beim Strom erreichte eine Höhe von
129 PJ (rund 4,4 Mio. t SKE) und damit bereits nach neun Monaten den Wert des gesamten Vorjahres.
Drilling Simulator Celle hat
Versuchsbetrieb aufgenommen
An der Forschungseinrichtung Drilling Simulator Celle (DSC), die von der TU Clausthal zusammen mit dem Energie-Forschungszentrum Niedersachsen betrieben
wird, haben im Oktober die ersten Projekte
begonnen. Langfristig verfolgt der DSC mit
seiner Forschung das Ziel, Tiefbohrungen
auf Erdöl, Erdgas und Geothermie sowie unterirdische Speicher kostengünstiger und sicherer zu machen.
Die Forschungseinrichtung wird einen Software- und einen Hardware-Simulator aufweisen, deren Finanzierung das Land Niedersachsen übernimmt. Das wissenschaftliches Konzept wurde von Professor Joachim
Oppelt – er leitet den DSC und hat gleichzeitig die Professur für Tiefbohrtechnik, Erdölund Erdgasgewinnung an der TU Clausthal
inne – entwickelt. Im ersten Halbjahr 2016
soll der Aufbau im Wesentlichen abgeschlossen sein.
In den vergangenen Monaten gelang es bereits, zwei von der Industrie beauftragte Projekte für den DSC zu akquirieren. Mit den
beiden Projekten, die von zwei lokalen Vertretern internationaler bohrtechnischer
Dienstleister vergeben wurden, ist im Oktober begonnen worden. Im einen Fall handelt
es sich um ein Gemeinschaftsprojekt mit
dem Institut für Technische Mechanik der
TU Clausthal, Projektleiter ist Professor
Gunther Brenner. Die Arbeit beinhaltet Tätigkeiten im Bereich der computerbasierten
Strömungssimulation, die hauptsächlich am
Institut in Clausthal durchgeführt, aber vom
DSC mit betreut werden. Das zweite Projekt
ist deutlich praktischer ausgerichtet. Hier
werden am Drilling Simulator Celle in der
sogenannten »Flow Loop« in waagerechter
Bohrführung experimentelle Untersuchungen bzw. Messungen an Modulen neu entwickelter Untertage-Bohrsysteme durchgeführt.
Neue Rohrfernleitungen
zwischen Scholven und Marl
Evonik plant den Ausbau der Fernleitungsinfrastruktur zwischen dem Standort Gelsenkirchen-Scholven der Ruhr Oel GmbH
und dem Chemiepark Marl. Geplant ist die
Errichtung einer Pipeline, die zum Transport von Heizgasen verwendet werden soll.
Daneben wird ein Leerrohr gezogen, damit
bei einer nächstmöglichen Erweiterung keine neuen Verlegearbeiten erforderlich werden.
Die neuen Rohrfernleitungsanlagen werden
größtenteils parallel zu bestehenden Fernleitungen verlegt. Die Verlegearbeiten sollen bis voraussichtlich Ende 2016 abgeschlossen werden.
ERDÖL ERDGAS KOHLE, 131. Jg. 2015, Heft 12
NACHRICHTEN
Umfassende Investitionen in
weitere Erschließung der
Lagerstätte Speyer geplant
Das Konsortium aus GDF SUEZ E&P
Deutschland GmbH (ENGIE) und Palatina
GeoCon GmbH & Co. KG, das seit 2008 in
Speyer Öl fördert, hat sich entschieden, trotz
veränderter wirtschaftlicher Rahmenbedingungen an seinen Plänen zur Erschließung
des Erdölfeldes Römerberg-Speyer und der
Ausweitung der Produktion auf über 500 t/d
festzuhalten. Hierzu wird das Konsortium in
den nächsten Jahren einen dreistelligen Millionenbetrag in Bohrungen und die Optimierung der Betriebsanlagen investieren. Voraussetzung für die Erhöhung der Förderung
ist ein Planfeststellungsverfahren mit Umweltverträglichkeitsprüfung, für das beim
Landesamt für Geologie und Bergbau in
Mainz (LGB) ein Antrag eingereicht werden
wird.
Mit dem Basiskonzept sollen die bereits vorhandenen obertägigen Anlagen wie Speichertanks und Aufbereitungsanlagen auf
den beiden bestehenden Betriebsplätzen optimiert werden. Weiterer Bestandteil ist zudem die Errichtung einer etwa 3 km langen
Zusatzwasserleitung, um aus einem Brunnen bei Bedarf Zusatzwasser zu entnehmen
und zusammen mit dem bei der Erdölproduktion anfallenden Lagerstättenwasser in
die Lagerstätte zurückzuführen. Über weitere Schritte wird nach Umsetzung des Basiskonzeptes entschieden, das 2017 realisiert
werden soll. Der Transport des Rohöls zur
Raffinerie nach Karlsruhe erfolgt wie bisher
durch Tankkraftwagen.
Derzeit gibt es auf den beiden Betriebsplätzen in Speyer sieben Bohrungen, der aktuelle Plan für die Entwicklung des Erdölfeldes
sieht weitere fünf Bohrungen vor. Insgesamt
soll damit die Produktion mindestens verdoppelt werden.
ONTRAS startet Neubauprojekt
im Lausitzer Revier
Um die Energie-Infrastruktur in der Lausitz
weiter zu verbessern und zukunftsfest zu gestalten, baut die ONTRAS Gastransport
GmbH, Leipzig, seit Mitte Oktober 2015
zwei Ferngasleitungen neu. Sie führen vom
brandenburgischen Senftenberg bis in den
Spreetaler Ortsteil Spreewitz (südlich von
Schwarze Pumpe in Sachsen). Die neuen, jeweils rund 35 km langen und parallel laufenden Leitungen ersetzen vorhandene Leitungen, die durch mittlerweile gesperrte Kippengebiete ehemaliger Braunkohletagebaue
verlaufen.
Mit dem Vorbau der ersten Ferngasleitung
(FGL 19) wurde im November begonnen.
Die Arbeiten zur parallel laufenden, zweiten
Pipeline (FGL 20) sind ab März 2016 geplant. In der jetzt begonnenen Bauphase
2015/2016 werden zunächst diejenigen
Bohrstatistik
28
B ohrm eter (E rdöl/E rdgas ) in 1000 m
26
A k tiv e B ohranlagen (ink l.Geotherm ie)
24
22
20
18
16
14
12
10
8
6
4
2
0
7
8
9
10
11
12 J an
14
2
3
4
5
6
7
8
9
10
11
12 J an
15
2
3
4
5
6
7
8
9
Erdöl- und Erdgasproduktion im September
Erdgasproduktion* (in 1.000 m3)
September
Januar – September
2015
2015
Vorjahr
Zwischen Oder und Elbe
Erdölproduktion (in t)
September
Januar – September
2015
2015
Vorjahr
512
3.857
4.107
1.285
9.222
10.855
2.371
93.300
118.431
118.241
986.997
1.029.300
Zwischen Elbe und Weser
312.508
2.914.713
2.969.967
9.757
87.961
89.890
Zwischen Weser und Ems
206.733
3.286.769
3.610.252
15.612
148.342
156.485
Westlich der Ems
11.139
141.894
148.727
43.293
374.720
379.001
Thüringer Becken
1.152
10.000
9.687
–
–
–
217
1.809
1.964
16.419
151.433
140.839
Nördlich der Elbe
Oberrheintal
Alpenvorland
Gesamt
1.302
12.190
6.087
3.327
30.558
32.692
535.935
6.464.533
6.869.223
207.935
1.789.233
1.829.061
* inkl. Erdölgas – (9,7692 kWh/m3)
Quelle: WEG
Bohraktivitäten im September
Erdöl-Erdgas-Zahlen im August
Bohrmeterleistung
Explorationsbohrungen
Aufschlussbohrungen
Wiedererschließungsbohrungen
in m
–
1.197,0
± geg.
Vorjahr
0,4
Mineralölprodukte (Mio. t)
Feldesentwicklungsbohrungen
Erweiterungsbohrungen
Produktionsbohrungen
Hilfsbohrungen
–
–
–
1.197,0
Anzahl der Bohranlagen am 30. September
insgesamt
davon aktiv
Bohrungen auf Erdöl und Erdgas
Aufwältigungen
Speicherbohrungen
Geothermiebohrungen
Sonstige Einsätze
August
1/2015
bis
8/2015
32
17
3
12
–
1
1
Quelle: WEG
8,9
72,1
– Dieselkraftstoff
3,2
24,2
3,7
– Ottokraftstoff
1,6
12,1
–1,4
– Heizöl leicht
1,3
10,3
–3,7
– Heizöl schwer
0,4
3,5
38,8
– Rohbenzin
1,3
10,9
–6,5
– Flugturbinenkraftstoff
0,8
5,7
–1,3
Import
3,4
24,3
–0,3
Export
1,8
15,1
8,6
0,217
1,581
–2,9
7,8
60,8
3,8
381,75
–35.3
Rohölaufkommen
Eigene Förderung
Trassenabschnitte neu gebaut, bei denen die
bestehenden Leitungen derzeit durch Sperrgebiete verlaufen. Voraussichtlich 2017 soll
dann mit dem etwa 8,4 km langen restlichen
Bauabschnitt begonnen werden, in dem die
Bestandsleitungen seit jeher in gewachsenem Boden liegen.
Das Investitionsvolumen für den gesamten
Neubau beläuft sich auf rund 44 Mio. Euro.
%
Inlandsabsatz gesamt
Import
Grenzüberg.-Preis, EUR/t
Erdgasaufkommen (Mio. TJ*)
Inlandsförderung
1)
Import (Mio. TJ)
0,025
0,208
–3,8
0,354
2,777
24,5
Grenzübergangspreis, EUR/TJ
5.889,04
–11,2
3
* TeraJoule (35.169 TJ/Mrd. m )
Quelle: BAFA, WEG, eigene Berechnungen
453
NACHRICHTEN
GDF SUEZ E&P demontiert CO2-Injektionsanlagen im Feld Altmark
Forschungsanlage fehlt Rechtsrahmen
Seit 2009 ist die Anlage zur CO2-Injektion
im Altmark-Kreis in der Nähe der Ortschaft
Maxdorf fertig und betriebsbereit, doch die
behördliche Zulassung zur Inbetriebnahme
liegt bis heute nicht vor. GDF SUEZ E&P
Deutschland, eine Tochter der ENGIE-Unternehmensgruppe, wollte im Rahmen eines
Forschungsprojektes untersuchen, ob die
Einbringung von Kohlenstoffdioxid in die
Erdgaslagerstätte Altmark die förderbare
Menge an Erdgas gesteigert hätte.
Bereits seit 2012 verfolgt das Unternehmen
das Forschungsprojekt aufgrund des fehlen-
den Rechtsrahmens nicht weiter. »Wir arbeiten immer an Konzepten, um die Fördertradition in der Region noch möglichst lange
fortsetzen zu können. Dieses Projekt hätte
dabei helfen können, denn die Erdgasproduktion in der Altmark leistet einen wichtigen Beitrag zur heimischen Energieversorgung und sichert in der Region zahlreiche
Arbeitsplätze«, macht Unternehmenssprecher Dr. Stefan Brieske deutlich. Jetzt beginnt der Rückbau der Anlage. Ende November sollten dann die beiden rund 62 t
schweren Tanks abtransportiert werden.
Fernleitungsnetzbetreiber veröffentlichen modulares Konzept
zur Versorgungssicherheit
Mit einem umfassenden, modular aufgebauten System, das auf den beiden Pfeilern
(Netz-)Stabilitätsreserve und (Lieferanten-)Anreizsystem basiert, bringen die deutschen Fernleitungsnetzbetreiber neue Impulse in die aktuelle Diskussion zum Thema
Versorgungssicherheit. In ihrem Eckpunktepapier entwickelt die Vereinigung der Fernleitungsnetzbetreiber Gas e. V. (FNB Gas)
ihr eigenes Versorgungssicherheitskonzept,
das einen kosteneffizienten Weg zu einer
verlässlichen Gasversorgung in Deutschland für kritische Situationen aufzeigt.
»Unser Konzept zur Versorgungssicherheit
zeichnet sich durch mehrere Kernelemente
aus: Deutlich geringere Kosten für Erdgaskunden als bei einer strategischen Speicherreserve, Einbettung in den bestehenden regulatorischen Rahmen und ohne negative
Beeinflussung der Handelsmärkte«, nennt
Ralph Bahke, Vorsitzender des FNB Gas,
die wichtigsten Ergebnisse des Eckpunktepapiers.
Das Modul Netz-Stabilitätsreserve wird
über die FNB abgedeckt. Es sieht die Einführung einer FNB-Speicherreserve für Leistungsspitzen vor, mit der ein sicheres und
zuverlässiges Gasversorgungssystem als
Grundvoraussetzung für eine sichere Belieferung garantiert werden soll und zielt auf
lokale Netzstabilisierung ab.
Das Modul Lieferanten-Anreizsystem wird
über die Bilanzkreisverantwortlichen abgedeckt. Damit soll auch in einer Gasmangellage sichergestellt werden, dass alle vertraglichen und gesetzlichen Versorgungspflichten erfüllt werden. Der Einsatz von nichtmarktbezogenen Maßnahmen (z. B. Abschaltung) soll auch bei einer Gasmangellage soweit wie möglich vermieden werden.
Förderstränge in Etzel werden
verstärkt
Derzeit werden die Förderstränge an 28 Kavernen der IVG Caverns GmbH in Etzel verstärkt.
Nach dem Abriss zweier Förderstränge im
November 2014 hatte das Landesamt für
Bergbau, Energie und Geologie (LBEG),
Hannover, die IVG Caverns GmbH aufgefordert, vorsorglich ein Konzept zur Verstärkung der Kavernen mit vergleichbaren Fördersträngen vorzulegen.
Die Gaskavernen in Etzel sind durch ein
Mehrfach-Barrieren-System geschützt, so
dass selbst bei Versagen einer Barriere (z. B.
Leckage oder Abriss), die zweite dahinter
liegende Barriere in vollem Umfang wirksam ist.
Allerdings fällt bei Versagen einer Barriere
die Kaverne für die Erdgasversorgung aus
und muss aufwändig repariert werden, was
durch eine Verstärkung vermieden werden
kann.
Betroffen sind insgesamt 30 Kavernen in Etzel, darunter die zwei Kavernen, an denen
die Förderstränge abgerissen sind.
Das Konzept wird seit Ende September 2015
umgesetzt.
Dabei werden die fehlerhaften Schweißnähte in den Fördersträngen jeweils mit einem
innen liegenden Rohr überbrückt. Oberhalb
des zusätzlichen Rohres wird ein Sicherheitsventil zum Absperren des Gasflusses
eingebaut.
Die Arbeiten werden voraussichtlich im
vierten Quartal 2016 abgeschlossen sein.
Die IVG hat die Firma Halliburton mit der
Durchführung der Arbeiten beauftragt. Die
Planung und Bauüberwachung führen die
Fachfirmen ESK und DEEP/KBB durch.
ERDÖL
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gesucht, ausgedruckt oder archiviert werden.
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www.oilgaspublisher.de abgerufen werden.
NACHRICHTEN
Aus Koksofengas wird Backpulver
Eine völlig neuartige Technologie wurde im Rahmen eines Gemeinschaftsprojekts von der
Kokerei Schwelgern (KBS),
dem Anlagenbauer ThyssenKrupp Industrial Solutions und
der TU Berlin entwickelt. Auf
dem Werkgelände von ThyssenKrupp Steel Europe in Duisburg
ist eine Pilotanlage in Betrieb
gegangen, die eine Substanz
produziert, die auch als Backpulver einsetzbar ist. Das Versuchsaggregat nutzt Prozessgase, die bei der Herstellung von
Koks entstehen, und wandelt
diese in vermarktbare Stoffe
wie Düngemittel und Treibmittel für die Chemieindustrie um,
gleichzeitig wird der CO2-Ausstoß vermindert.
Technologie wandelt Prozessgas in verwertbare Stoffe um
Im Vordergrund bei der weltweit ersten Anlage ihrer Art
steht nicht, mit der Herstellung
des sogenannten Hirschhornsalzes in die Lebensmittelindustrie
einzusteigen. »Kokereien gibt
es auf der ganzen Welt. Wir wollen mit dem neu entwickelten
Verfahren den Betreibern die
Chance bieten, ihre Prozessgase
sinnvoll
weiterzuverwenden
und die Produktivität ihrer Anlagen zu steigern«, erläutert Dr.
Holger Thielert von ThyssenKrupp Industrial Solutions:
»Hierfür haben wir ein Verfahren entwickelt und patentiert,
das Koksofengase ressourcenschonend in verwertbare Stoffe
umwandelt. Dieses Verfahren
können wir weltweit vermarkten oder auch in bestehenden
Anlagen installieren.«
Am Anfang des neuen Verfahrens steht die Produktion von
Koks, neben Eisenerz der
Haupteinsatzstoff zur Herstellung von Roheisen im Hochofen. »Dabei wird in der Kokerei Kohle unter hohen Temperaturen ‚gebacken‘. Die in diesem
Prozess entstehenden heißen
Gase führen eine Reihe von
Stoffen mit sich. In der Versuchsanlage wird nun in ein einem komplexen Verfahren das
Koksofengas gewaschen. Unter
Beigabe von Kohlenstoffdioxid
entsteht Ammoniumbikarbonat
– umgangssprachlich Hirschhornsalz«, erklärt Dr. Thielert.
Die entstehenden Endprodukte
sind vielfältig einsetzbar: als
Stickstoffdünger, als Treib- und
Schäumungsmittel für Kunststoffe oder poröse Keramiken
und letztlich auch in der Nahrungsmittelindustrie.
Nach erfolgreichen Testläufen
unter Laborbedingungen wurden zwei Forscher der TU Berlin mit dem Bau der Pilotanlage
in Duisburg beauftragt. Für die
Testphase bietet die Kokerei
Schwelgern als Teil des integrierten Hüttenwerks von ThyssenKrupp Steel Europe in Duisburg optimale Bedingungen.
»Läuft hier auf der Kokerei alles
wie geplant, kann das neue Verfahren auch im Großmaßstab
angewendet werden«.
Die ersten Ergebnisse waren
vielversprechend: »95 % des im
Koksofengases
enthaltenen
Ammoniaks können genutzt
werden. Aus 15 m³ Koksofengas und 2 m³ Kohlenstoffdioxid
entstehen so pro Stunde 15 kg
Feststoffe«, erläutert Sebastian
Riethof, Wissenschaftler von
der TU Berlin, die Effizienz der
Anlage. Die Chemieprodukte
können so zu marktfähigen
Kosten hergestellt werden.
Reduktion von CO2-Emissionen
Laufen die Tests weiter erfolgreich, wäre dies ein echter
Durchbruch in Sachen Produktivität und Ressourceneffizienz
– auch für die Kokerei Schwelgern: »Schon jetzt werden hier
in Duisburg nahezu alle anfallenden Prozessgase möglichst
effizient verwertet«, erklärt KBSGeschäftsführer Peter Liszio.
»Gelingt es uns jetzt noch langfristig, sowohl aus den Koksofengasen am Markt absetzbare
Produkte für andere Industriezweige herzustellen und zugleich den CO2-Ausstoß des
Hüttenwerks zu senken, wäre
das ein echter Mehrwert, der
auch der Umwelt zugutekommt.« Deshalb könnten Idee
und Anlagentyp bei positivem
Fortschritt künftig auch weltweit zum Einsatz kommen.
Die Kokerei Schwelgern stellt
jährlich 2,6 Mio. t Brennstoff
für die Duisburger Hochöfen
her. Sie ist die modernste Anlage ihrer Art in Europa und besitzt die weltweit größten Öfen.
Die Kokereibetriebsgesellschaft
Schwelgern GmbH (KBS) ist
eine Tochtergesellschaft der
ThyssenKrupp Steel Europe.
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NACHRICHTEN
8. Ölwärme-Kolloquium – Hybride Heizsysteme haben
Marktpotenzial
Aktuelle Fragen der Ölheiztechnik rund um
die Themenbereiche hybride Energie- beziehungsweise Heizsysteme, die Definition
von Premium-Heizöl und Entwicklungstendenzen bei flüssigen biogenen Brennstoffen
prägten das 8. Ölwärme-Kolloquium, das
am 14. und 15. Oktober 2015 in Hamburg
stattfand. Redner von Viessmann und des Instituts für Wärme- und Oeltechnik waren
überzeugt davon, dass hybride Energie- beziehungsweise Heizsysteme künftig an Bedeutung gewinnen können. Aktuelle ÖlBrennwertheizungen lassen sich mit erneuerbaren Energien zu Hybridheizungen kombinieren. Oft wird Solarthermie als Variante
gewählt, doch Wärme und Strom wachsen
zunehmend zusammen, so dass Power-to-Heat auch für Individualheizungen
aufgrund größerer Flexibilität immer attraktiver wird. Unter Power-to-Heat wird sowohl
die Nutzung von Strom aus hauseigenen
Photovoltaik-Anlagen als auch von überschüssigem, »abgeregeltem« Strom aus dem
Energienetz zur Unterstützung der Wärmeversorgung verstanden. Hilfreich für Brennwertheizungen wie Hybridsysteme kann
ihre Online-Anbindung sein. Sie ermöglicht
und erleichtert die Überwachung und Regelung von Heizungsanlagen, das heißt sowohl
für die Wartung und Fehleranalyse durch
den SHK-Betrieb als auch die Statusbetrachtung und Steuerung durch den Hausbe-
sitzer aus der Ferne. Beispiele für die bestehenden technischen Möglichkeiten stellte
Buderus Deutschland vor.
In der Podiumsdiskussion zum Thema »Premium-Heizöl: Braucht die Branche einheitliche Anforderungen?« stellten Vertreter von
Additivherstellern, der Mineralölwirtschaft
und der Heizungsindustrie fest, dass »Premium-Heizöl« kein geschützter Begriff ist. Sie
beleuchteten unterschiedliche Facetten des
Themas und waren sich einig, dass eine einheitliche Definition von Premium-Heizöl
wünschenswert sei, um die Vorteile qualitativ
guter Heizöle für die Verbraucher transparent
zu machen. Fragen der Kennzeichnung des
Brennstoffs und der Erfüllung nachweisbarer
Qualitätskriterien, die beispielsweise die Betriebssicherheit von Heizungen unterstützen,
konnten in der Diskussion nicht abschließend
geklärt werden.
Hydriertes Pflanzenöl ist ein alternativer
Brennstoff, der unter bestimmten Voraussetzungen auch im Wärmemarkt eingesetzt
werden könnte. Erste Forschungsergebnisse
zu stofflichen und produktionstechnischen
Fragen der Markteinführung wurden vom
Oel-Waerme-Institut und der Technischen
Universität Bergakademie Freiberg vorgestellt. Veranstaltet wurde das Ölwärme-Kolloquium vom OWI Oel-Waerme-Institut
und dem Institut für Wärme und Oeltechnik
(IWO).
Wege zur weitgehenden Dekarbonisierung des Energiesystems
Um die Erwärmung der Erdatmosphäre auf
maximal 2 °C gegenüber dem vorindustriellen Niveau beschränken zu können, müssen
die globalen Treibhausgasemissionen in der
zweiten Hälfte des Jahrhunderts gegen Null
gehen (deep decarbonization). Wie, das untersuchen Wissenschaftler(innen) aus 16
Ländern, die zusammen für 70 % der globalen Treibhausgasemissionen verantwortlich
sind, im Rahmen des Deep Decarbonization
Pathways Project (DDPP). Nun liegt die Länderstudie für Deutschland vor. Darin analysiert und diskutiert das Wuppertal Institut
auch, wie eine adäquate Brücke in eine treibhausgasfreie Zukunft gebaut werden kann.
Die Studie arbeitet drei Hauptstrategien heraus, um die Treibhausgasemissionen in
Deutschland bis 2050 stark zu reduzieren:
– Umfassende Erhöhung der Energieeffizienz, d. h. sinkender Energieverbrauch
bei gleichbleibendem Nutzen in allen Endenergiesektoren
– Verstärkte Nutzung erneuerbarer Energiequellen im Inland (insbesondere erhöhte
Stromproduktion aus Wind- und Solarenergie)
– Weitgehende Elektrifizierung von Prozessen (z. B. strombasierte Wärmeversorgung, Elektrofahrzeuge) und mittel- bis
456
langfristig die Nutzung synthetischer Gase und Treibstoffe (Power-to-Gas/-Fuels),
die auf Basis erneuerbarer Energien erzeugt werden.
Eine weitergehende Dekarbonisierung (90
% und mehr bis 2050) ist möglich, wenn die
Energienachfrage auch durch Verhaltensänderungen gesenkt wird, z. B. im Verkehrssektor durch Verlagerung auf klimafreundliche Transportmittel, oder durch Änderungen von Ernährungs- und Heizgewohnheiten.
Eine weitere Strategie könnte laut der Studie
im Industriesektor die Nutzung der CCSTechnologie (Carbon Capture and Storage)
zur Reduzierung des Kohlendioxidausstoßes sein.
Ohne geeignete politische, institutionelle,
kulturelle und soziale Rahmenbedingungen
ist eine Dekarbonisierung nicht möglich, betont Prof. Dr. Manfred Fischedick, Projektleiter und Vizepräsident des Wuppertal Instituts. Vor allem gilt es stabile Investitionsbedingungen zu schaffen, die Gesellschaft
in den tiefgreifenden Veränderungsprozess
einzubinden und damit auch die öffentliche
Akzeptanz für notwendige Infrastrukturprojekte zu sichern.
http://wupperinst.org
FORSCHUNG
Neues Reaktorkonzept soll
Energieverbrauch drastisch
senken
Evonik startet mit Partnern Forschungsprojekt ROMEO
Evonik Industries verfolgt in dem jetzt gemeinsam mit acht Partnern gestarteten Forschungsprojekt ROMEO (Reactor Optimisation by Membrane Enhanced Operation)
das ehrgeizige Ziel, bei industriell bedeutenden katalytischen Reaktionen in der Gasphase bis zu 80 % Energie und bis zu 90 %
Emissionen einzusparen. Das neue Reaktorkonzept soll Herstellung und Aufarbeitung
durch den Einsatz von Membranen in einem
Schritt erledigen – eine Art 2-in-1-Reaktor,
bei dem das gebildete Produkt kontinuierlich aus dem Reaktionsgemisch ausgeschleust wird. Die EU fördert das Projekt im
Rahmen des Forschungsprogramms Horizon 2020 mit 6 Mio. Euro.
In den kommenden vier Jahren soll anhand
von zwei industriellen Prozessen in der
Gasphase – der Hydroformylierung und der
Wassergas-Shift-Reaktion – die technische
Machbarkeit des Reaktorkonzepts demonstriert werden.
Demonstrationsanlagen bei Evonik und
Linde
Evonik wird eine Demonstrationsanlage für
die Hydroformylierung aufbauen. Sie verwandelt Olefine und Synthesegas in Aldehyde. Linde dagegen will die Machbarkeit
anhand der Wassergas-Shift-Reaktion zeigen, bei der Kohlenmonoxid und Wasser zu
Wasserstoff reagieren. Wird für diese Reaktion CO beziehungsweise CO-haltiges Synthesegas aus Biomasse eingesetzt, wäre mit
dem neuen Reaktorkonzept ein Weg gefunden, um zum Beispiel aus Holzabfällen Wasserstoff zu erzeugen.
Kern des neuen Konzepts ist ein Hohlfaserrohrbündel-Reaktor: Auf einem speziellen
Trägermaterial soll ein homogener Katalysator fixiert und auf dessen Außenseite eine
Membran aufgebracht werden. Nachdem
am Katalysator die Reaktion stattgefunden
hat, können je nach Beschaffenheit der
Membran entweder das Produkt oder Nebenprodukte die Membran passieren.
Das Prinzip birgt zahlreiche technische Herausforderungen, angefangen bei der Beschaffenheit von Träger, Katalysator und
Membran bis hin zum modularen Aufbau des
Reaktors, der das spätere Up-Scaling erleichtern soll. Zum Konsortium gehören neben
Evonik die Friedrich-Alexander-Universität
Erlangen-Nürnberg, die RWTH Aachen, die
Technical University of Denmark, die BioEnergy2020+ GmbH (Österreich), die LiqTech
International A/S (Dänemark), das European
Membrane House (Belgien), die Agencia
Estatal Consejo Superior de Investigaciones
Científicas (Spanien) und die Linde AG.
1995 - Erdgasspeicher
Puchkirchen
2010 - Haidach II
(zweite Ausbaustufe)
2007 - Haidach I
2014 - 7 Fields II
(Oberkling und
Pfaffstätt)
2011 - 7 Fields I
(Nussdorf Nord,
Nussdorf Süd und
Zagling)
Chemie + Anlage = eine
Lösung: CAC
Ein halbes Jahrhundert Erfahrung, die Kompetenz von mehr als 250 Experten
für Verfahrenstechnik und Anlagenplanung, erfolgreiche Projekte auf
der ganzen Welt: dafür steht CAC. Mit dem ersten Erdgasspeicher für die
Rohöl Aufsuchungs AG legten wir 1995 den Grundstein für ein weiteres
Geschäftsfeld. Die 2010 finalisierte Anlage in Haidach ist mit einem
Arbeitsgasvolumen von 2.640 Mio m3 der zweitgrößte Erdgasspeicher Europas.
Wann dürfen wir für Sie planen?
www.cac-chem.de
NACHRICHTEN
ÖSTERREICH
POLEN
Weg frei für die geplante vollständige Übernahme von EconGas
durch OMV
Mehr als 1.200 km neue
Gasleitungen
Die Eigentümer der EconGas GmbH, OMV
(64,25 %), EVN (16,51 %), Wien Energie
(16,51 %) und Energie Burgenland (2,73 %)
haben eine substanzielle Einigung über die
zukünftige gesellschaftsrechtliche Struktur
der EconGas GmbH erzielt.
Eckpunkte sind die Übernahme der Anteile
von EVN, Wien Energie und Energie Burgenland im Ausmaß von 35,75 % an EconGas durch die OMV sowie die Fortführung
der bestehenden Kundenbeziehungen mit
EVN, Wien Energie und Energie Burgenland.
Bis Jahresende soll eine vertraglich bindende Vereinbarung vorliegen.
Die Transaktion unterliegt der Genehmigung durch die Aufsichtsräte der betroffenen Unternehmen und der kartellrechtli-
Das seit sechs Jahren laufende Investitionsprogramm zum Bau neuer Gasleitungen der
GAZ-SYSTEM S. A., wurde im Oktober
2015 abgeschlossen.
Die Zielsetzung von GAZ-SYSTEM war es,
in Polen neue Gasleitungen mit einer Gesamtlänge von über 1.200 km zu bauen.
Zusätzlich zu den neuen Gasleitungen hat
GAZ-SYSTEM auch zwei Kompressorstationen und 41 Gasstationen gebaut, um neue
Möglichkeiten für den Ausbau des polnischen Gasversorgungsnetzes zu schaffen,
dessen Liberalisierung zu ermöglichen und
Polens Energieversorgungssicherheit zu erhöhen.
Die ILF Consulting Engineers, München,
waren nach eigenen Angaben dabei an Planungs- und Überwachungsarbeiten von vier
Hochdruckgasleitungen beteiligt: Szczecin
– Gdañsk (201 km, 28″), Szczecin – Lwówek (189 km, 28″), Rembelszczyzna – Gustorzyn (176 km, 28″) and Lasów – Jeleniów
(18 km, 28″).
chen Behörden. OMV-Vorstandsmitglied
Manfred Leitner, verantwortlich für
Downstream: »Die geplante Übernahme ist
ein weiterer Schritt in der Restrukturierung
des Gasbereiches des OMV-Konzerns. Wir
erwarten uns davon eine deutliche Steigerung der Effizienz unseres Erdgashandelsgeschäfts.«
EconGas ist die gemeinsame Gashandelstochter von OMV, EVN, Wien Energie und
Energie Burgenland. Das Unternehmen ist
auf den Erdgas-Direktverkauf an europäische Geschäftskunden, an europäische
Großhändler und auf den Handel mit Erdgas
an internationalen Handelsplätzen spezialisiert.
Im Jahr 2014 hat EconGas 28,4 Mrd. m³
Erdgas in Europa und Österreich gehandelt.
TSCHECHIEN
Gasmärkte in Deutschland, Österreich und Tschechien gleichen
sich immer mehr an
»Perspektiven der fossilen Brennstoffe in
Europa« – unter diesem Thema diskutierten
Energieexperten in der tschechischen
Hauptstadt Prag die momentane Situation
des hiesigen Energiemarktes und auch die
zukünftige Rolle der traditionellen Energieträger im Energiemix der Zukunft.
»Die Gasmärkte in Deutschland, Österreich
und Tschechien nähern sich einander immer
weiter an, insbesondere im Hinblick auf
Preissysteme, Markttransparenz, Produktlandschaften, Marktregeln und die sehr
niedrigen Markteintrittsbarrieren. Obwohl
der tschechische Markt nur rund ein Zehntel
des größten europäischen Gasmarktes –
Deutschland – umfasst, treffen wir auch hier
auf die gleichen Herausforderungen wie in
unseren anderen Kernmärkten«, erläuterte
Hamead Ahrary, Leiter Sales Central Europe bei WINGAS, in seinem Vortrag vor Vertretern der tschechischen Energiebranche.
Der tschechische Markt durchläuft seit über
zehn Jahren einen fundamentalen Wandel
und ist von zahlreichen Einflussgrößen, wie
der Liberalisierung, Regulierung oder dem
Erdgas-Überangebot, teilweise neu geformt
worden.
So ist der Markt heute insbesondere von hoher Wettbewerbsintensität und einem entsprechenden Margen- und Preisdruck gekennzeichnet.
»Alle Marktteilnehmer sind daher nicht nur
gezwungen, diese Gegebenheiten zu akzeptieren und mit ihnen umzugehen. Darüber
hinaus müssen sie sich vor allem mit Blick
auf ihre Strategie, Struktur, Schwerpunkte
sowie Prozesse möglichst frühzeitig entsprechend positionieren, um gegenüber dem
Wettbewerb zu punkten«, führte Ahrary
weiter aus.
In den vergangenen Jahren ist WINGAS
auch in Zentraleuropa solide gewachsen, das
Unternehmen konnte seinen Erdgasabsatz
in der Region deutlich steigern.
MITTLERER OSTEN
ADNOC und Wintershall wollen gemeinsam zur Chemical
Enhanced Oil Recovery forschen
Die Abu Dhabi National Oil Company (ADNOC) und Wintershall haben ein Memorandum of Understanding (MoU) über eine
künftige Zusammenarbeit in der Forschung
und Entwicklung unterzeichnet. Hauptziel
ist die Entwicklung von cEOR-Verfahren
für die in den Ölfeldern der Region auftre458
tenden hohen Temperaturen und hohen Salinitäten in den Carbonatvorkommen.
Die Zusammenarbeit soll zu dem von Abu
Dhabi definierten strategischen Ziel einer
künftigen Endausbeute von 70 % aus seinen
Ölfeldern beitragen (s. auch Meldung auf S.
OG 181 in dieser Ausgabe).
WELT
Technologie-Outlook von BP
Mit dem jetzt erschienenen Technology Outlook hat BP einen weiteren internationalen
Report veröffentlicht.
Der Technology Outlook soll einen Weg aufzeigen, wie Energieversorgung sicher, bezahlbar und nachhaltig gestaltet werden
kann.
Er gibt dazu einen Überblick über die Technologien, die nach Meinung von BP das
Energiesystem der kommenden 30 bis 40
Jahre bestimmen werden.
Eine etwas detailliertere Übersicht wird
den Technologien gewidmet, die in der Ölund Gasindustrie das größte Potenzial haben.
Neben Forschungsergebnissen von BP kommen im Technology Outlook auch zahlreiche externe Experten zu Wort.
Die Ergebnisse beruhen auf dem heutigen
Wissen und können nur einen Ausschnitt abbilden.
Viele Technologien stecken noch in den
Kinderschuhen, wie zum Beispiel der Bereich Carbon Capture and Storage. Andere
Bereiche wie die Digitaltechnologie haben
bereits jetzt enorme Auswirkung.
Was sich jedoch feststellen lässt: Technologische Durchbrüche in anderen Sektoren
werden zunehmend an Einfluss auch für die
Energiebranche gewinnen.
Verschwimmende Grenzen zwischen Sektoren sind ein Trend, der gerade beginnt.
(www.bp.com)
OIL
GAS
EUROPEAN MAGAZINE
INTERNATIONAL EDITION OF
ERDÖL ERDGAS KOHLE
December,4/2015
LOOKING AHEAD.
We plan for the future. More than one-third of ROSEN employees work in research and development, creating innovative
products needed by the industry. An investment, we are
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www.rosen-group.com
ISSN 0342-5622
VOLUME 41
OIL
GAS
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Editor: Hans Jörg Mager
IV/2015
EUROPEAN MAGAZINE
INTERNATIONAL EDITION OF
ERDÖL ERDGAS KOHLE
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Oil & Gas News
178
221
224
Geology
185
The plant processes nitrogen-rich natural gas
to high-methane gas, purifies and liquefies
helium, compresses methane gas, and
produces LNG.
Georgia – Petroleum Geologic Link from the Black Sea to the Caspian
By W. NACHTMANN, A. JANIASHVILI
Region
and Z. SURAMELASHVILI
Dr illing
193
Successful Workover Operations for Milling Permanent Bridge Plugs
at 8000 m MD – A Case Study
By K. SOLIMAN
O i l / G a s Pr o d u c t i o n
198
BTEX Removal from Production Water using Associated Gas
By M. VALKENIER, G. HINNERS, and G. THEMANN
202
Analyses of Operating Electric Submersible Pumps (ESPs) of Different
Manufacturers – Case Study: Western Siberia
By A. SUKHANOV, M. AMRO and B. ABRAMOVICH
205
Improvement of Oil Production Rate using the TOPSIS and VIKOR
Computer Mathematical Models
By M. ALEMI, M. KALBASI,
and F. RASHIDI
210
Front Cover Photo: PGNiG SA, Warsaw, Poland
Natural gas processing plant Odolanow, Poland
International News
New Products / Processes / Literature
Calendar
By A. ZICH, K. S. VEREVKIN,
and D. A. SOZAEVA
Machiner y & Plants
212
Oil-Flooded Screw Compressors for Unconventional Gas
By A. ALMASI
215
Diagnosis of Centrifugal Pumps using Vibration Analysis
By M. MINESCU, I. PANA and M. STAN
Maintenance & Repair
219
Smarter Work with “Smartphones” By S. CIERNIAK and M. DUMAN
NORWAY
GREAT BRITAIN
Polarled pipeline now in place
40 Years of production at
Forties field
Polarled is the first pipeline on the Norwegian continental shelf that crosses the Arctic Circle and opens up a new highway for
gas from the Norwegian Sea to Europe. End
of September, the final pipe in the 482.4 km
pipeline was laid at the Aasta Hansteen
field at a depth of 1260 m in the Norwegian
Sea.
The pipeline, which has a diameter of 36″,
extends from Nyhamna in Møre og Romsdal
to the Aasta Hansteen field in the Norwegian
Sea and was laid by the world’s largest
pipelaying vessel; “Solitaire” from Allseas.
Polarled is the deepest pipeline on the Norwegian continental shelf. It is the first time
ever that a pipe that is 36″ in diameter has
been laid at such a depth. The pipeline’s capacity will be up to 70 million m³ of gas per
day.
Building for the future
In the initial stage, only the gas from Aasta
Hansteen will be transported through
Polarled but the pipeline has space for more.
Six more connection points have been installed.
“With this pipeline, we open up for the export of gas to Europe from a completely new
area, and with the infrastructure in place it
will also be more attractive to explore the
area,” concluded Håkon Ivarjord, project director for the Polarled development project.
THE NETHERLANDS
ExxonMobil to expand Rotterdam hydrocracker to produce
higher-value products
ExxonMobil will expand the hydrocracker
unit at its Rotterdam refinery to upgrade
heavier byproducts into cleaner, highervalue finished products, including EHCTM
Group II base stocks and ultra-low sulfur
diesel, to meet growing global market demand.
The refinery, operated by Esso Nederland
BV, will use ExxonMobil’s proprietary
hydrocracking technology and be the first to
produce EHC Group II base stocks in Europe, which are used in the production of
high-quality lubricating oils and greases.
ExxonMobil’s Rotterdam refinery plays a
key role in the region and marketplace as a
manufacturer of low-sulfur petroleum products and chemical feedstocks. Following the
expansion, the hydrocracking process will
use proprietary catalysts applied in a unique
refinery process configuration to efficiently
produce both high-quality base stocks and
ultra-low sulfur diesel.
The project’s environmental impact assessment has been approved and the site-permitting process is being finalized. Permits are
expected in early 2016. Pending receipt of
permits, construction is scheduled to begin
in 2016 and unit startup is targeted for 2018.
ROMANIA
Deep-water offshore gas field discovered
LUKOIL announced completion of the exploratory well Lira-1X and the discovery of
a gas field in the Lira offshore structure,
which is located at the Trident block
(EX-30) in the deep-sea Romanian offshore.
According to preliminary results of the analysis of drilling data and geophysical exploration, the Lira-1X delivered a productive
interval with an effective gas-saturated
thickness of 46 m.
According to seismic data, the area of the
gas field can reach up to 39 km², reserves
can exceed 30 billion m³ of gas,
The water depth within the block ranges
from 300 to 1200 m. The block has an area of
1006 km². The Lira-1X well is located at a
distance of about 170 km from the coast,
where the depth of the sea is about 700 m.
OG 178
The well was drilled to a depth of 2700 m
and was temporarily abandoned for further
evaluation.
The success of the Lira-1X well will reduce
the risk for further exploration on a series of
prospective sites with significant potential
reserves, located close to the Lira structure
and in other parts of the block. The program
of future works planned for 2016 includes
drilling an exploration well at Lira and reprocessing of seismic data to confirm the
size of the discovery and precise assessment
of its potential hydrocarbon reserves.
Exploration on the EX-30 block is conducted by LUKOIL Overseas Atash BV.
LUKOIL’s share in the project is 72%, while
PanAtlantic Petroleum Ltd owns 18% and
S. N. G. N. Romgaz SA owns 10%.
Apache Corporation reached a significant
milestone at its Forties field in celebration of
40 years since oil was first produced from
Forties Alpha and transported via the Forties
pipeline system to the onshore terminal at
Cruden Bay. The Forties field, which
Apache has successfully rehabilitated
through its Apache North Sea subsidiary, remains one of the key producers in the U. K.
sector of the North Sea.
Situated 177 km east of Aberdeen, Scotland,
Forties has seen activity since 1964 when the
area was initially licensed for exploration. In
October 1970, commercial oil was confirmed in the field with the discovery of an
estimated 1.8 billion b of oil, establishing
the U. K. North Sea as a major source of energy and revenue. It remains the single largest oil-producing asset within the U. K. Continental Shelf, surpassing 2.4 billion b to
date, and is one of the top-producing fields
in 2015.
Apache revived production from 40,000 to
60,000 b/d
Prior to Apache’s acquisition, the field was
expected to cease production by 2013 with
decommissioning operations commencing
thereafter. Production had declined to
40,000 b/d – less than a twelfth of its peak
production – by the time Apache assumed
operations in 2003. After addressing key issues impacting the five platforms of the mature asset base, Apache revived production
to more than 60,000 b/d by yearend 2004.
While Forties was estimated to contain
144 million boe of remaining reserves when
Apache acquired it from BP in 2003, the
company has since recovered more than
230 million boe and added critical infrastructure, including tying back new, operated, satellite-field discoveries, to extend the
field’s life expectancy by more than 20
years. Today – 12 years after Apache assumed control – the field continues to produce in excess of 52,000 b/d with a robust inventory of opportunities to pursue going forward.
OIL GAS European Magazine 4/2015
Moving Energy Forward
NORWAY
Subsea gas compression to boost Gullfaks recovery
Statoil with partners Petoro and OMV have
started the world´s first wet gas compression
on the seabed of the North Sea Gullfaks
field.
The unique technology will increase recovery by 22 million boe and extend plateau
production by around two years from the
Gullfaks South Brent reservoir.
“Subsea processing and gas compression
represent the next generation oil and gas recovery, taking us a big step forward,” Margareth Øvrum, executive vice president for
Technology, Projects & Drilling said.
In mid-September Statoil also started Åsgard subsea gas compression. The two projects are the first of their kind worldwide,
and represent two different technologies for
maintaining production when the reservoir
pressure drops after a certain time.
Subsea compression has stronger impact
than conventional platform-based compression.
It is furthermore an advantage that the platform avoids increased weight and the extra
space needed on the platform for a compression module. And it is an important technological leap to further develop the concept of
a subsea factory, says Statoil.
It is also possible to tie in other subsea wells
to the wet gas compressor via existing pipelines. The station has already been prepared
for new tie-ins.
“We see great opportunities for wet gas compression on the Norwegian continental shelf.
It is an efficient system and a concept that
can be used for improved recovery on small
and medium-sized fields. We are searching
for more candidates that are suitable,” says
Kjetil Hove, senior vice president for the operations west cluster.
The advantage of a wet gas compressor is
that it does not require gas and liquid separation before compression, thereby simplifying the system considerably and requiring
smaller modules and a simpler structure on
the seabed.
The system consists of a 420 t protective
structure, a compressor station with two
5-MW compressors totalling 650 t, and all
equipment needed for power supply and system control on the platform.
Extensive preparations had been made on
Gullfaks C before the subsea compressor
could be started, including modifications
and preparation of areas as well as installation of equipment.
Gullfaks licensees are Statoil (operator,
51%), Petoro (30%), and OMV (19%).
Ideal solutions for onshore or
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system is unbeatable.
POLAND
PGNiG and Qatargas sign a new supplementary agreement to the
LNG supplies contract
Polskie Górnictwo Naftowe i Gazownictwo
SA and Qatar Liquefied Gas Company Ltd
have signed a new supplementary agreement
to the LNG supplies contract of June 2009.
As in 2015, in the first half of 2016 Qatargas
will place the volumes defined under the
long-term contract on other markets.
PGNiG will cover any difference between
the LNG price specified in the long-term
contract and the market price obtained by
Qatargas.
Should the price be lower than PGNiG finds
satisfactory, any unsold LNG supplies will
be shifted to later years of the long-term contract.
The supplementary agreement also specifies the terms on which PGNiG S. A. and
Qatargas will agree LNG supplies in the first
half of 2016.
As announced by the project owner, Polskie
LNG, acceptance tests of all the critical systems at the LNG Terminal in Swinoujscie
that are necessary to receive the first delivery of liquefied natural gas have been completed. Currently, the project is at the
start-up stage and the first vessel with technical LNG is to arrive at the port of
Swinoujscie in December. Commercial deliveries are scheduled to start in the first half
of 2016.
CYPRUS
BG Group secures equity in Aphrodite discovery, offshore Cyprus
BG Group today announces it has taken a
35% holding in Block 12 offshore Cyprus
which includes the Aphrodite gas discovery.
This upstream position provides a potential
source of gas to Egypt where BG Group
holds equity in the two train LNG export faOIL GAS European Magazine 4/2015
cility at Idku as well as LNG offtake rights to
lift 3.6 million t/a. Operated by Noble Energy, the Aphrodite gas discovery is approximately 170 kilometres south of Limassol.
Completion of the transaction is subject to
certain regulatory approvals as well as customary closing conditions.
NETZSCH Pumpen & Systeme GmbH
Business Field Oil & Gas
Geretsrieder Str. 1
84478 Waldkraiburg
Germany
Tel.: +49 8638 63-1024
Fax: +49 8638 63-2333
[email protected]
www.netzsch.com
NEWS
GREAT BRITAIN
NORWAY
Apache announced significant reserves additions in the North
Sea
Statoil exits Alaska
Apache Corporation announced significant
discoveries on two exploration wells in the
Beryl area of the U.K. North Sea. The company also drilled two significant development wells in the Beryl area, from which no
reserves have been previously booked. Additionally, Apache announced a large discovery at its Seagull prospect, which lies approximately 80 km south of the company’s
Forties field.
The K and Corona wells are the first exploratory prospects drilled by Apache in the
Beryl area. Each discovery proves a separate
geologic concept that helps to de-risk additional drilling locations. Apache estimates
the K and Corona discoveries, combined
with the success at Seagull, represent likely
net recoverable reserves of 50 million to
more than 70 million boe. Future appraisal
drilling will enable the company to further
define the upside potential beyond 70 million boe. Apache’s proved reserves in the
North Sea at yearend 2014 were approximately 140 million boe.
GREAT BRITAIN
Ethane from US shale gas to the Fife Ethylene Plant in Scotland
In November INEOS Europe AG,
ExxonMobil Chemical Limited and Shell
Chemicals Europe B. V. signed a long-term
sale and purchase agreement to secure ethane from US shale gas for the Fife Ethylene
Plant (FEP) at Mossmorran in Scotland,
from mid 2017.
The Fife plant will receive ethane from
INEOS’ new import terminal in Grangemouth, Scotland. Access to this new source
of feedstock will help complement supplies
from North Sea natural gas fields. The
agreement will also ensure the competitiveness of the plant. Access to ethane from
shale production will provide sufficient raw
material to run UK steamcrackers to make
ethylene at full operating rates.
INEOS has committed £ 450 million to construct the new ethane import terminal at its
Grangemouth facility. An existing pipeline
will transport the gas from Grangemouth to
Fife.
The Fife Ethylene Plant is owned and operated by ExxonMobil and Shell has 50% capacity rights. The plant started production in
1985, and is one of only four natural gas-fed
steam crackers in Europe.
It was the first plant specifically designed to
use natural gas liquids from the North Sea as
feedstock. Alongside INEOS Grangemouth,
it supplies manufacturing in Scotland, the
rest of the UK and export markets with ethylene. It has an annual capacity of 830,000 t
of ethylene.
Statoil is optimising its exploration portfolio
and has decided to exit Alaska following recent exploration results in neighbouring
leases.
The leases in the Chukchi Sea are no longer
considered competitive within Statoil’s
global portfolio, so the decision has been
made to exit the leases and close the office in
Anchorage, Alaska.
The decision means Statoil will exit 16
Statoil-operated leases, and its stake in 50
leases operated by ConocoPhillips, all in the
Chukchi Sea. The leases were awarded in the
2008 lease sale in Alaska and expire in
2020.
POLAND
Over 1200 km of new gas
pipelines
GAZ-SYSTEM S.A. recently has finished
the construction of more than 1200 km of
new gas pipelines in Poland. In addition to
the new gas pipelines, GAZ-SYSTEM has
also built two compressor stations and 41 gas
stations, which provides new opportunities
for developing the domestic gas network,
enables its liberalization and increases Poland’s energy security.
For the last six years, ILF Consulting Engineers has been involved in the investment
program. ILF provided design and supervision services for four key high-pressure gas
28″ pipelines of a combined lenght of
approx. 590 km.
ROMANIA
NORWAY
OMV Petrom constructs a new water treatment plant in Suplacu
de Barcau oil field
More gas from Troll A
Part of the field’s redevelopment project which will be finalized in 2021
OMV Petrom started construction of a new
produced water treatment plant in Suplacu
de Barcau oil field. The investment for the
new plant amounts to approximately 17 million Euro and the completion is estimated
for December 2016.
Suplacu de Barcau is the largest oil field in
OMV Petrom’s portfolio accounting for approximately 10% of its current oil production in Romania and has been in production
for over 50 years.
The existing water treatment plant was built
in 1968 and will be replaced with a new plant
that will use the latest available technology
in the field. The new plant will have a capacity of 8000 m³ of water/day, in line with the
volume of residual water currently produced
in Suplacu de Barcau oil field.
The new installation is part of a significant
investment program for the redevelopment
OG 180
of the Suplacu de Barcau field, started in
2013 and expected to be finalized in 2021.
The investment program consists of 105 additional wells to increase the recovery factor
of hydrocarbons as well as a strong environment component that targets the reduction of
emissions and increase of energy efficiency.
In this regard, the company already finalized
investments in oil gathering points, pipelines, a combustion gas incinerator and modernization of boilers and compressors that
reduced the environmental impact of the operations.
The investments performed in the program
up to August 2015 amounted to 110 million Euro.
Future investments in the program will also
include further incinerators as well as the
modernization of oil processing and storage
facilities and the potable water plant.
The two new giant compressors that started
up on the Troll A platform will help increase
gas recovery by 83 billion m³.
The compressors ensure a daily export capacity from the Troll field of 120 million m³ of gas, totalling 30 billion m³ of gas
per year.
The compressors are an important measure
to meet the Troll field’s long-term production profile, currently extending from 2045
to 2063.
They are operated by land-based power from
Kollsnes west of Bergen, ensuring zero
emissions of carbon dioxide and nitrogen
oxides from the platform.
During the past 18 months Statoil has started
up low-pressure compressors on Troll A,
Kvitebjørn, Heidrun, Kristin, Åsgard and
Gullfaks, the last two on the seabed (see separate news).
This increases the recovery rate by more
than 1.2 billion b and extends the life of the
installations.
NEWS
NORTH AFRICA
MIDDLE EAST
AFRICA
Eni starts production from
“near field” discoveries in
Egypt
ADNOC and Wintershall to
cooperate in Chemical
Enhanced Oil Recovery
First Production from the Lianzi
Development offshore of
Congo and Angola
Eni announces the success of the “Nidoco
North West 3” well drilling, appraisal of
“Nidoco NW 2 Dir” discovery, in the Nooros
exploration prospect, located in the Abu
Madi West license in the Nile Delta. The
field, which is estimated to contain about
15 billion m³ of gas in place, beside to associate condensates, was discovered on July
this year and put into production after only
two months; it currently produces more than
15,000 boe/d. The production from the new
well was planned to start-up by the end of
November.
Within 2015, Nooros field will produce
30,000 boe/d and is expected to reach a plateau of 70,000 boe/d in the first half of 2016.
The gas and condensates are sent to the Abu
Madi’s treatment plant, about 25 km from
the discovery, and then routed in the Egyptian network.
Similarly to the discovery well, “Nidoco
NW3” was drilled from onshore to reach in
deviation the Noroos reservoir located in the
offshore shallow waters. The well encountered a 65 m thick gas bearing sandstone
layer of Messianian age with excellent
petrophysical properties.
At the Abu Dhabi International Petroleum
Exhibition and Conference in November the
Abu Dhabi National Oil Company
(ADNOC) and the German E&P company
Wintershall signed a Memorandum of Understanding (MoU) regarding future cooperation in research and development.
The project focuses on enhanced oil recovery using specialized chemicals for the oil
and gas industry.
Main goal is to jointly develop customized
solutions to meet the subsurface challenges
that are characteristic for the local oil fields
– high temperature and high salinity in the
carbonate reservoirs of Abu Dhabi. The
MoU forms the framework for a close cooperation of the two companies and comprises
a roadmap for the development of chemical
EOR methods.
Following successful lab results, a pilot test
in Abu Dhabi will be envisaged. The MoU
defines a further step of the cooperation between ADNOC and Wintershall.
The cooperation aims to contribute to Abu
Dhabi’s strategic target of reaching a 70%
ultimate recovery from its oil fields in the future.
Chevron Overseas Limited, has commenced
oil and gas production from the Lianzi Field,
located in a unitized offshore zone between
the Republic of Congo and the Republic of
Angola.
Located 105 km offshore in approximately
900 m of water, Lianzi is Chevron’s first operated asset in the Republic of Congo and
the first cross-border oil development project offshore Central Africa. The project is
expected to produce an average of 40,000 b
of crude oil per day.
The field, discovered in 2004, includes a
subsea production system and a 43 km electrically heated flowline system, the first of
its kind at this water depth. The system
transports the oil from the field to the
Benguela Belize – Lobito Tomboco platform in Angola’s Block 14.
Chevron Overseas (Congo) Limited is operator of the Lianzi Field and has a 15.75% interest, along with its affiliate Cabinda Gulf
Oil Company Limited (15.5%), Total E&P
Congo (26.75%), Angola Block 14 BV
(10%), Eni (10%), Sonangol P&P (10%),
SNPC (the Republic of Congo National Oil
Company (7.5%), and GALP (4.5%).
Genau 1.436 km nordwestlich von Berlin.
Erdgas aus Norwegen ist die emissionsarme und kosteneffektive Antwort auf
Deutschlands Energiefragen. Vor der Küste Norwegens befindet sich unsere größte
Plattform Troll A, von der aus jährlich 30 Milliarden m3 Erdgas zu Haushalten in ganz
Deutschland gelangen. Damit lassen sich mehr als 10 Millionen Einfamilienhäuser
ein Jahr lang versorgen. Mehr Information auf statoil.de
NEWS
AFRICA
NORTH AFRICA
Eni makes a new discovery
offshore Congo
BP to accelerate development of first phase of Atoll field in Egypt
Eni made a new discovery of gas and condensates offshore Congo, in the exploration
prospect of Nkala Marine, located in Marine
XII block, about 20 km off the coast and
3 km from the Nene Marine field, already in
production.
The finding, realized through the Nkala Marine 1 well, is expected to have a potential of
250–350 million boe in place. During the
production test, the well provided over
300,000 m³/d of gas and associated condensates. The well, drilled in a water depth of
38 m, encountered a major gas and condensates buildup in the pre-salt clastic geological sequence of lower Cretaceous age, crossing a hydrocarbon column of 240 m.
Eni will be starting the evaluation of Nkala
Marine through new delineation wells.
The exploration of the pre-salt sequences
continues to deliver new discoveries all
along the West Africa’s margin. Eni estimates the resources in place of oil and gas
discoveries made in the pre-salt Marine XII
block to be approximately 5.8 billion boe.
The production of the block, started last December, is increasing and it currently stands
at around 15,000 boe/d.
Eni, through its subsidiary Eni Congo, is the
operator of Marine XII block with a 65%
stake. The other partners are New Age, with
25% stake, and the Congolese state company Societé Nationale des Pétroles du
Congo (SNPC), with 10% stake.
BP has signed a Heads of Agreement (HoA)
with the Egyptian Minister of Petroleum regarding the acceleration of the development
of the recent Atoll gas discovery. The discovery (BP 100%) in the North Damietta
Offshore Concession in the East Nile Delta,
offshore Egypt was announced in March
2015.
The agreement is expected to enable first
production to be expedited from an estimated 1.5 trillion ft³ (42.5 billion m³) of gas
resources and 31 million b of condensates in
the Atoll field to the domestic market, with
production anticipated to begin in 2018.
Full field development of Atoll is expected
to consist of two phases. The first phase will
consist of two development wells tied back
to existing infrastructure, with production
expected to start up in 2018. Success of this
first phase is expected to trigger additional
investment and further wells to increase production.
BP expects to sustain its current oil production and double its gas production in Egypt
before the end of the decade to reach 2.5 billion ft³/d (25 billion m³/a) with partners,
which represents more than 50% of Egypt’s
current gas production. Development of
Atoll will be executed and operated by
Pharaonic Petroleum Co. (PhPC), BP’s joint
venture with EGAS and Eni.
The Atoll-1 deepwater exploration well discovery was BP’s second important Oligocene discovery in the North Damietta Offshore Concession in the East Nile Delta, following the 2013 Salamat discovery.
AFRICA
Production from Bonga Phase 3 project in Nigeria started
Shell Nigeria Exploration and Production
Company Ltd (SNEPCo) has announced the
start-up of production from the Bonga Phase
3 project.
Bonga Phase 3 is an expansion of the Bonga
Main development, with peak production
expected to be some 50,000 boe. This will be
transported through existing pipelines to the
Bonga floating production storage and
offloading (FPSO) facility, which has the capacity to produce more than 200,000 b of oil
and 150 million ft³of gas a day (1.5 billion
m³/a). The Bonga field, which began producing oil and gas in 2005, was Nigeria’s
first deep-water development in depths of
more than 1000 m. Bonga has produced over
600 million b of oil to date.
SNEPCo holds a 55% contractor interest in
OML 118. The other co-venturers are Esso
Exploration & Production Nigeria Ltd
(20%), Total E&P Nigeria Ltd (12.5%) and
Nigerian Agip Exploration Ltd (12.5%).
AFRICA
AFRICA
Eni to operate a new
exploration block offshore of
Mozambique
Statoil to explore offshore South Africa
Eni, through its subsidiary Eni Mozambico,
is the operator (34%) of the Joint Venture together with partners Statoil and Sasol (each
25.5%) and ENH (15%), which has been
awarded, following the 5th Competitive Mozambique Bid Round, the exploration and
development rights of the offshore block
A5-A. The block in the area called Angoche,
about 1500 km northeast of the capital city
Maputo, covers a total area of di 5145 km² in
a water depth between 200 and 1800 m and
is placed within an unexplored area of the
Northern Zambesi Basin.
Eni has been present in Mozambique since
2006 and is the operator of Area 4 with a
50% indirect quote, owned through its subsidiary Eni East Africa.
In Area 4, following an intensive exploration
campaign and appraisal, from 2011 to 2014,
were also discovered supergiant natural gas
resources, estimated in 2407 billion m³ of
gas in place.
OG 182
Statoil has completed a farm-in transaction
with ExxonMobil Exploration and Production South Africa Limited, acquiring a 35%
interest in the ER 12/3/154 Tugela South Exploration Right.
The remaining interests are held by the operator ExxonMobil (40%) and co-venturer
Impact Africa Limited (Impact Africa)
(25%).
The Tugela South Exploration Right covers
an area of approximately 9054 km². It is lo-
cated offshore eastern South Africa in water
depths up to 1800 m.
The farm-in represents a country entry for
Statoil into South Africa. Statoil enters in an
early exploration phase with a step-wise exploration programme. Work commitments
between 2015 and 2017 include the acquisition of 1000 km² of 3D seismic data and geology and geophysics studies. There are no
commitment wells during this exploration
period.
NORTH AMERICA
Successful appraisal of the Anchor discovery in the deepwater Gulf
Significant discovery in the Lower Tertiary Wilcox trend
Chevron Corporation announced the successful appraisal of the Anchor discovery in
the Lower Tertiary Wilcox Trend.
The original Anchor discovery well, located
in Green Canyon Block 807, approximately
225 km) off the coast of Louisiana in
1579 m of water, was drilled in late 2014 to a
depth of 10,287 m and it encountered 210 m
of net oil pay. Appraisal drilling began in
June 2015 and recently found 211 m of net
oil pay. To date, Chevron has confirmed a
hydrocarbon column of at least 549 m in the
Lower Tertiary Wilcox reservoirs at Anchor.
Complete appraisal of the field will require
further delineation wells and technical studies.
Benefit from experience
The new DEA – since 1899
As an international upstream company with German roots based in Hamburg, we rely on many years’ experience,
geological expertise, innovative engineering knowledge and high technology.
Environmental protection and safety have the highest priority when producing oil and gas. Transparent and
open dialogue is also important to us.
Any questions? www.dea-group.com
DEA Deutsche Erdoel AG
DEA_EN_210x297_Erdoel_Erdgas_Kohle.indd 1
Ueberseering 40, 22297 Hamburg, Germany
29.05.15 09:23
NEWS
NORTH AMERICA
Shell launches Quest carbon capture and storage project
Commercial operations of the Quest carbon
capture and storage (CCS) project in Alberta, Canada, started November 6. Quest is
designed to capture and safely store more
than one million tonnes of carbon dioxide
each year.
Quest draws on techniques used by the energy industry for decades and integrates the
components of CCS for the large-scale capture, transport and storage of CO2.
Quest will capture one-third of the emissions from Shell’s Scotford Upgrader, which
turns oil sands bitumen into synthetic crude
that can be refined into fuel and other products. The CO2 is then transported through a
65 km pipeline and injected more than
2000 m underground below multiple layers
of impermeable rock formations. Quest is
now operating at commercial scale after successful testing earlier this year, during which
it captured and stored more than 200,000 t of
CO2.
Quest was built on behalf of the Athabasca
Oil Sands Project joint-venture owners Shell
Canada Energy (60%), Chevron Canada
Limited (20%) and Marathon Oil Canada
Corporation (20%), and was made possible
through strong financial support from the
governments of Alberta and Canada.
Support from the local community was essential to building Quest. Shell initiated
public consultation in 2008, two years before submitting a regulatory application.
Quest has a robust measurement, monitoring and verification program agreed upon
with the government and verified by a third
party (Det Norske Veritas (DNV)).
Furthermore, Shell and the United States
Department of Energy will field-test advanced monitoring technologies alongside
the state-of-the-art, comprehensive monitoring program already in place.
IEA hails launch of Quest CO2 storage
project
The International Energy Agency (IEA) has
welcomed the launch of the world’s first
large-scale carbon capture and storage project.
“The launch of the Quest CCS project in Alberta, Canada, is remarkable, as it provides
another excellent example of the fact that
CCS is about so much more than just
coal-fired power,” IEA Executive Director
Fatih Birol said. “It can be used in many industrial sectors where no other solutions exist to significantly reduce the CO2 footprint.”
current proven fossil-fuel reserves cannot be
commercialised before 2050 if the increase
in global temperatures is to remain below
2 °C.
The world’s first CCS project, Sleipner,
started in Norway in 1996 and continues to
operate today, storing nearly 1 million
tonnes of CO2 yearly in the North Sea. CCS
projects are entering operation, under construction or in advanced stages of planning
in Australia, Canada, Saudi Arabia, the
United Arab Emirates and the United States,
bringing the world towards the threshold of
10 million t of CO2 captured and verified as
stored every year.
Projects in the pipeline to store 10 million t
The IEA believes that CCS plays a key role
in an ambitious, climate-friendly future energy scenario, accounting for one-sixth of
required emissions reductions by 2050. IEA
analysis also shows that without significant
deployment of CCS, more than two-thirds of
Quest amine stripper vessel (Photo: Fluor)
NETL’s 2015 Carbon Storage Atlas shows increase in U.S. CO2 storage potential
The U. S. Department of Energy’s (DOE)
National Energy Technology Laboratory
(NETL) has released the fifth edition of the
Carbon Storage Atlas (Atlas V), which
shows prospective carbon dioxide storage
resources of at least 2600 billion t – an increase over the findings of the 2012 Atlas.
Atlas V is a coordinated update of carbon
storage resources, activities, and large-scale
field projects in the United States. It showcases the progress that NETL scientists and
engineers have made with their partners toward wide-scale deployment of carbon storage technologies.
Atlas V highlights potential CO2 storage resources in saline formations, oil and natural
gas reservoirs, and unmineable coal seams.
For each large-scale field project, Atlas V
provides a summary of approaches taken,
technologies validated, and lessons learned
in carrying out key aspects of a CCS project:
site characterization; risk assessment; simulation and modeling; monitoring, verification, accounting, and assessment; site operations; and public outreach.
230 billion t of CO2 in depleted reservoirs
The refined CO2 storage estimate of
OG 184
2600 billion t reported in Atlas V represents
an increase over the 2380 billion t reported
in the previous edition. The increase is a result of improved accuracy and precision in
storage resource calculations, additional information from formation studies, and refinement of storage efficiency.
This vast resource has the potential to store
hundreds of years’worth of industrial greenhouse gas emissions, permanently preventing their release into the atmosphere. Of par-
ticular importance for U. S. energy security
is Atlas V’s finding that approximately
230 billion t of CO2 could be stored in depleted oil and natural gas fields. This storage
estimate equates to several decades’ worth
of emissions from stationary sources with
the added benefit of enhancing oil and gas
recovery.
For more than a decade, Regional Partnerships have been investigating the best possible CO2 storage sites.
Shell to halt Carmon Creek in situ project
Shell will not continue construction of the
80,000 b/d Carmon Creek thermal in situ
project located in Alberta, Canada.
Shell originally sanctioned the project in
October 2013 and announced in March 2015
that the project would be re-phased to take
advantage of the market downturn to optimise design and retender certain contracts.
Shell’s view is that the project does not rank
in its portfolio at this time. This decision reflects current uncertainties, including the
lack of infrastructure to move Canadian
crude oil to global commodity markets.
Shell will retain the Carmon Creek leases
and preserve some equipment while continuing to study the options for this asset. The
company expects to take net impairment,
contract provision, and redundancy and restructuring charges of some $ 2 billion as a
result of this decision. The project SEC
Proved Reserves estimated at 418 million b
bitumen at end 2014 will be de-booked and
the project estimated recoverable petroleum
resources will be classified as Contingent
Resources. Carmon Creek is 100% Shell
owned.
GEOLOGY
Georgia – Petroleum Geologic Link from the
Black Sea to the Caspian Region
By W. NACHTMANN, A. JANIASHVILI and Z. SURAMELASHVILI*
Abstract
Georgia, a country with plenty of oil seeps
and leaks, stretches from the Black Sea into
the Caspian Region. Oil has been produced
since the early 19th century, recorded production statistics exist since 1930. The current production of less than 1000 barrels of
oil per day (<50,000 t/a) ranks Georgia as
number 104 among the oil producing nations.
Since Georgia’s independence from Soviet
Union in 1991, quite a number of international oil companies have taken licenses and
pursued pretty diverging business strategies.
Classical E&P companies remained a minority compared to the number of ‘financial
investors’, sometimes more soldiers of fortune than wildcatters.
Georgia used to have an investor friendly
PSA policy; attractiveness of conditions for
new licenses has ceased during the last couple of years, although, to some degree, terms
are still negotiable.
Embedded between the High Caucasus and
the Lesser Caucasus mountains the Rioni
Basin towards the Black Sea in the west and
the larger Kura Basin near and east of
Tbilisi are the country’s two petroleum regions. Main producers are fields in the Kura
Basin with oil from fractured volcanoclastics of Middle Eocene age and from Upper Eocene to Miocene (shaly) sandstones.
Cretaceous carbonates bear oil but no production could be established yet.
The Black Sea shelf is still rather untapped –
a licensing round has been in preparation
for a few years without further announcement yet.
Georgian Oil & Gas Corporation (GOGC),
the state oil company, numbers the ‘prospective resources’in Georgia with 677 million t
of oil and 148 billion m3 of gas (status: end
2014).
Practically all oil prone areas of Georgia
are covered with licenses, held by local
and/or international operators; the exploration, appraisal and production activity is
concentrated on the vicinity of Tbilisi and
the easternmost part of the country. During
the recent years, most operators’activity and
investment regarding seismic acquisition,
drilling wells and well treatments was rather
modest. Beyond the known conventional resources some operators have started to have
an eye at Georgia’s considered shale oil potential in Maikop shales.
Technical challenges like complex geology,
demanding surface topography, varying
pressure gradients, difficult to produce reservoirs from very shallow to 5000 m depth in
combination with high environmental and
safety requirements contribute to a higher
risk and high cost for seismic and well operations. However, highly experienced professionals, utilizing state of the art technology,
shall be able to manage the risks properly
and keep necessary funds at a reasonable
level to, eventually, transfer at least some of
the “dream” potential to proved and recoverable reserves within a near to midterm
timeframe.
1 Introduction
For the petroleum industry, Georgia has
been a transit country for more than 100
years – the first oil pipeline from the oil
fields near Baku at the Caspian Sea to the
Georgian Black Sea harbor Batumi was
opened in 1904. After the end of the Soviet
Union in the early 1990’s, western compa-
nies quickly stepped into the oil play in
Azerbaijan – with the opening of the BTC
(Baku-Tbilisi-Ceyhan; Fig. 1) pipeline in
2004 a direct connection from the Caspian
oil fields via Georgia to the Mediterranean
Sea, and herewith to the European market,
was established. Today, also gas transport
from the Caspian towards the Black Sea respectively to Turkey and further to Europe
are partly completed (SCP – South Caucasus
Pipeline; Fig. 1) partly under construction
(TANAP – Transanatolian Pipeline) – more
pipeline connections through Georgia to
Turkey and the Balkan region are in a
planning phase [1].
But, what about oil and gas in Georgia?
Hydrocarbon exploration in Georgia started
about 150 years ago. The Middle Eocene and
Maikop (Oligocene to Lower Miocene) fields
in the Near-Tbilisi-Region were discovered
between 1939 and the 1970’s (Upper Eocene
fields: in the Norio, Patardzeuli, Teleti and
Samgori-Patardzeuli-Ninotsminda anticlines;
Maikop fields: in the Norio [1939], Satskhenisi [1956] and Samgori-ParadzeuliNinotsminda anticlines). In all cases, the
Maikop fields are located on the northern
flanks of anticlinal structures; traps are
structural as well as stratigraphic, faults and
thrust planes act as seals and as migration
paths.
The greater part of the Near-Tbilisi-Region
* Wolfgang Nachtmann, at Chair Petroleum Geology, Montanuniversität Leoben, Austria; currently with Central European Petroleum GmbH, Berlin, Germany; Alexander Janiashvili, Norio Operating Company, Tbilisi, Georgia; Zurab
Suramelashvili, CanArgo Georgia, Tbilisi, Georgia. Lecture,
presented at the DGMK/ÖGEW Spring Meeting 2015, April
22–23, Celle, Germany (E-mail: [email protected]).
0179-3187/15/IV
© 2015 EID Energie Informationsdienst GmbH
Fig. 1
Existing oil and gas transport systems through Georgia [1]
OG 185
GEOLOGY
is located on the eastern edge of
the Adjara-Trialeti zone of the
Lesser Caucasus. During the
Late Eocene to Miocene time,
the area was characterized by
continuous terrigenic sedimentation into a deep, semi-closed
sea with normal salinity to a
more isolated, shallower, saline
sea in an oxygen depleted environment with free H2S and frequent climate fluctuations.
Thick clayeysandy formations
(3–5 km), rich in organic matter,
were deposited.
The modern structure of the NearTbilisi-Region was formed after
the Styrian, Attic, Rodonian and
Valahian folding phases. Three
anticline trends are identified:
Kavtiskhevi–Norio–Martkopi,
Tabori–Varkeili–Samgori– Patardzeuli–Ninotsminda,
Teleti–
South Dome. Most folds are
turned to the south and complicated by faults.
2 Geologic Overview
(modified after [2])
Fig. 2
Geological Map of the Caucasus, petroleum prone Rioni and Kura basins belong to the Transcaucasian
intermountain depression (modified after [3])
Georgia, as part of the Caucasus region, is
located in an area of extensive continental
collision of the Eurasian and Arabic plates,
forming a part of the Alpine-Himalayan fold
and thrust belt. Ocean floor of the Tethys
Sea, as well as fragments and units of continental transition form a geologic melange of
Gondwana, Tethys and Eurasian terrains.
Today’s topography of the Caucasus region
is the (preliminary) result of a Late Cenozoic
orogenic phase that is still ongoing due to the
northwards movement of the African and
Arabic plates.
Three major tectonic units, subdivided into
smaller subunits, are to be differentiated
(Fig. 2):
1)Folded and thrusted system of the Greater
Caucasus (the main mountain ridge or
Greater Caucasus Anticlinorium)
2)Transcaucasian Intermountain Basin
(Georgian Basin): Neogene molasse respectively foreland-type basins opening
towards the west (the Rioni Basin towards
the Black Sea) and east (the Kartli-Kura
Basin near and east of Tbilisi into
Azerbaijan towards the Caspian Sea) hold
Georgia’s oil and gas potential and are
separated from each other by a zone of uplift
3)Folded system of Lesser Caucasus (AdjaraTrialetian folded zone, Artvin-Bolnisi
zone (block) and Lock-Karabakh poorly
folded zone).
Ad 1) The folded and thrusted system of the
Greater Caucasus is a complex geo-tectonic
unit. The morphologic highest part, located
at and across the border from Georgia to
Russia, consists of Pre-Cambrian (?) to Paleozoic metamorphites (gneiss and shists
OG 186
with intruded granite material). Late Paleozoic molasse sediments and shales of Early
to Middle Jurassic age overlay these rocks
unconformably.
Hercynian and Alpine sediments are parts of
the geological structure on the southern
slope of the Caucasus. Devonian to Triassic
sediments, cropping out in the central part,
in Svaneti, are characterized by clayeysandy rocks and biogenic limestone lenses
(“Dizi suite”). The oldest deposits of the Alpine cycle are Jurassic in age and overlie Triassic rocks concordantly, but older formations with an unconformity. The Lower Jurassic succession is characterized by shale
and sandstone (total thickness is about
5000 m). The Middle Jurassic (Bajocian and
Bathonian) consists of clayey-sandy and
thick volcanic-sedimentary formations, up
to 2200 m thick. Upper Jurassic to Cretaceous limestone as well as PaleoceneEocene clayey to sandy sections are developed in the northern and central parts.
Flysch sediments, 5000–7000 m thick, of
the same age are developed in the western
and eastern parts. Total thickness of sediment sequences of the Caucasian folded system is about 15 km. Tectonic faults, thrust
planes of southern direction are encountered
frequently. Overthrust folds with big horizontal displacement exist in the eastern part
of the system, in the Ksani, Aragvi, Iori
sub-basins and in the Tsivgombori ridge.
Ad 2) The Georgian Basin represents an
intermountain massif of Paleozoic age, divided into small compartments by tectonic
faults of different directions. Nevertheless,
its tectonic structure is less complicated than
that in the adjacent folded systems.
The highest point of the system, where
subsurface rocks are exposed, is the Dzirula
massif. The Crystalline Basement deepens
gradually to the west and east and is overlain
by younger formations. The folded system
dips into the Black Sea in the west and adjoins the Muhran-Tiriponi valley and Garekaheti-Iori hills in the east that continue into
Azerbaijan.
The Dzirula Massif is characterized by PreCambrian (?) to Paleozoic metamorphites –
gneiss, phyllite and magmatic intrusions
(granitoid and gabbroid). Reworked Late
Paleozoic to Triassic quartz porphyrite, continental volcanic rocks, sandstones and conglomerates are developed in the eastern part
of the massif; these rocks are transgressively
overlain by Lower Jurassic conglomerate,
sandstone, and red limestone transformed
into marble. Middle Jurassic (Bajocian) volcanic-sedimentary formations are present;
the Upper Jurassic is less extensively developed, characterized by gypsum-bearing
multi-colored clay. Carbonates with rare
volcanic successions of the Lower and Upper Cretaceous play an important role in
Georgia. These formations are rich in fauna
used for biostratigraphy. Cenozoic sediments, characterized mostly by terrigenic
origin, rarely limestone, marl and volcanic
rocks are the predominating formations. The
gypsum-bearing clay section of the Maikop
is interesting, since it contains manganese
deposits (Chiatura, Chkari-Ajameti). The
thickest (several km’s) and best developed
are the Neogene molasse sediments – erosional products from the Greater and Lesser
Caucasus. Ten small oil fields have been
discovered in the Miocene-Pliocene formaOIL GAS European Magazine 4/2015
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GEOLOGY
tions in the Near-Tbilisi-Region and GareKaheti.
Ad 3) The Adjara-Trialetian Folded Zone, located in the northern part of the Lesser Caucasus, is one of the most intensively studied
tectonic units in Georgia. It is west–east
trending and reaches from the Black Sea to
the Iori river valley east of Tbilisi. The zone
comprises Cretaceous and Paleogene formations. The lower part of the Cretaceous section (Albian-Cenomanian, partly TuronianLower Senonian) is mainly characterized by
volcanic sediments, the upper part by limestone and marl. A sandstone and shale sequence, so called Borjomi Suite (2500 m),
was formed at the beginning of the Paleogene. A thick volcanic sequence (about
4000 m) was deposited due to active submarine volcanoes in the Eocene (mostly in the
Middle Eocene) – for more details see chapter 4, Reservoirs. The Upper Paleogene is
mostly characterized by terrigeneous rocks.
A number of folds and several big tectonic
faults are developed in these formations.
The Artvini-Bolnisi Massif, south of Tbilisi,
is characterized by Paleozoic metamorphites, overlain by semi-continental volcanogenic formations of Carboniferous age.
Lower Jurassic shale, Upper Jurassic and
Lower Cretaceous limestone and marl have
limited distribution. All these rocks are
overlain by Upper Cretaceous clastic rocks
that are gradually replaced by volcanic rocks
and – higher up – by limestone of Senonian
age. Copper, zinc, barite, and iron deposits
were discovered in the Upper Cretaceous
volcanic rocks in the Bolnisi region.
The Artvin-Bolnisi Massif is tectonically
simple; Akhalkalaki and Khrami highs and
one big syncline between Khrami and Lock
massifs are identified there. Many tectonic
faults with different directions play a key
role in compartmentalization of the basin,
thus contributing to the formation of channel-type gorges cut into volcanogenic
sediments.
Fig. 3
OG 188
The Lock-Karabakh Zone is the southernmost region of Georgia, mainly represented
by the Lock massif. Unlike the Khrami massif, a thick sequence of Lower Jurassic clay
and sandstone and an even thicker suite of
Middle Jurassic volcanic rocks (up to 2 km)
are developed. The lower part of the Upper
Cretaceous is characterized by sandstone
and limestone, the upper part by volcanic
rocks on the northern edge of the massif. The
Lock massif comprises Early Paleozoic
phyllites and granitoide intrusions.
3 Paleogeographic and
Tectonic Development
(for details see also [4] and [5])
According to paleo-magnetic and bio-geographic data, during the Early and Middle
Carboniferous the northern part of modern
Transcaucasia (e. g. the Dzirula massif) was
located at the southern edge of the European
continent. South Transcaucasia and Iran
(Elburs) were located about 2500–3000 km
away, at the northern edge of Africa – Arabia. The huge area between these two was
covered by the Paleo-Tethys Ocean, dividing
Transcaucasia into two geological provinces.
A southern part – Iranian province (central
Armenia, Nahijevan) – was a passive continental ‘carbonate environment’ off-shore of
Gondwana. The Northern Caucasus is located to the north of the Sevan-Zangezur
ophiolite belt that was an active edge of the
European continent, consisting of island
arches of Transcaucasia and Greater Caucasus, intra-arch rifts and basins of the Greater
Caucasus.
In the northern, Caucasian province Hercynian folding, granitoid magmatism, regional metamorphism and “andesite” volcanism was intensive. Metamorphic zoning indicates the existence of north-vergent subduction zones along the southern edge of
Transcaucasia and island arches of the
Greater Caucasus. According to paleo-magnetic and bio-geographic data, the southern
province was displaced to the north, near to
the island arch of Transcaucasia, causing
narrowing of the Paleo-Tethys. The southern
part of the Tethys, Mezogea, was opened at
the same time in the Iranian province.
During Jurassic to Early Cretaceous, the
Transcaucasian inter-arch basin was opened
by several km’s, separating the Dzirula and
Lock massifs. Apparently the basin closed
soon, due to a folding phase in the PreEarly-Jurassic. The northern branch of the
Tethys, which is narrowing to the Transcaspian region, was bounded by Iran island
arches from the south.
In the Late Cretaceous to Eocene, a wide
“Andesite Belt” was formed due to permanent movement of Euro-Asian and African
continents, connected to the Zagros- Anatolia subduction zone. At that time the Sevan
residual subduction zone of ophiolite belt
still exists. At the backside of the Andesite
belt Burga-Black Sea-Adjara and TallishSouth Caspian intra-arch rifts are characterized by intensive basalt volcanism and deep
marine turbidite sequences. Folded structures of Turkey, Lesser Caucasus and Elburs
were bended in the Paleogene (Eocene?) due
to a movement of the Arabic plate. The modern structure of the Caucasus, including
Georgia, was formed after Late Alpine
(Neogene) compression, folding, uplift and
“andesite” volcanism.
4 Petroleum System(s)
(compare Fig. 5)
4.1 Source rocks
For most of the oil in Georgia the partly TOC
rich Oligocene to lower Miocene Maikop
and Upper Eocene shales are seen as the
source. Lower Jurassic shales are not yet
proved but considered as additional source
rock in parts of the country.
Schematic geological cross section across anticlines with distinct flower structures that hold oil in fractured
Middle Eocene volcanoclasts [4]
4.2 Reservoirs
Main producers are fields in the
Kura Basin with oil from fractured volcanic tuffs of Middle
Eocene age (Georgia’s biggest
oil fields, the Samgori-Patardzeuli, Ninotsminda, Teleti,
South Dome, Rustavi and West
Rustavi oil and gas fields with a
cumulative production of, so far,
some 25 million t of oil, were
discovered in these rocks in the
Near-Tbilisi-Region). Further
producing reservoirs are Upper
Eocene to Miocene (shaly-silti)
sandstones. Cretaceous fractured carbonates occasionally
also bear oil but no production
could be established yet (e. g.
East Kavtiskhevi, Manavi).
The Upper Eocene is characterized by fine- and mediumgrained, carbonatic, hard polyOIL GAS European Magazine 4/2015
GEOLOGY
These few attempts were not coordinated
and conducted by different operators and
service companies. They can only be the beginning of an industry wide learning process.
4.3 Traps
Fig. 4
Seismic zoom-in to flower structured anticline (compare Fig. 3), modified after [4]
mictic sandstones, Oligocene and Lower
Miocene by unsorted, mainly carbonatic
arenites.
Available data indicate that the main oil
zones of the Upper Eocene in the Ninotsminda and Patardzeuli fields are right below
thrust planes separating the Maikop from the
Upper Eocene. In the Ninotsminda structure, oil zones are also located in sandstone
sections developed in the upper (Tbilisi
Suite) and lower (Navtlugi Suite) parts of the
Upper Eocene. For successful exploration in
both formations the identification of thrust
planes across potential reservoir rocks appears to be a most promising tool. It seems
that also the Sakaraulo (Burdigalian) arenite,
developed west of Norio-Satskhenisi and to
the east of Satskhenisi-Ninotsminda, has a
significant hydrocarbon potential.
Reservoir quality is a main obstacle in Geor-
Fig. 5
gia’s oil and gas plays. The so far best producing reservoir, the up to 600 m thick Middle Eocene volcanoclastic sequence, has
zero matrix porosity. (Economic) production is only provided by heavily fractured
portions in tectonically stressed positions
like anticlines with steeply dipping flanks
(compare Figs. 3, 4).
Handicap of practically all sand-silt-shale
intercalations from Upper Eocene up to
Miocene is the widespread lack of clean
sand portions.
To improve production from these formations, a handful of fracs have been conducted
(three in the Taribani field in eastern Georgia, two in the Norio field near Tbilisi). The
results were rather ‘modest’to disappointing
– the target formations are either ‘too plastic’ or operators and service companies
failed in utilizing the proper technique.
Stratigraphic table with main hydrocarbon bearing formations in East Georgia [4]
Classical trap types in Georgia are structural
and stratigraphic ones plus combinations of
both.
Proved plays in the Rioni Basin are:
– Neogene terrigenous deposits in anticlinal
settings (Supsa-Shromisubani oil fields)
– Upper Cretaceous fractured limestones in
uplifts below the Neogene unconformity
(East Chaladidi oil field)
– Upper Jurassic subsalt sandstone-evaporite and limestone succession with sandstone pinch-outs (Okumi structure).
Proved plays in the Kartli and Kura Basin
are:
– Neogene terrigenous deposits in structural
or structural-stratigraphic closures (e. g.
Norio, Mirzaani, Satskhenisi, Taribani oil
fields)
– Middle Eocene fractured, partly compartmentalized volcaniclastic tuffs in anticlinal settings (e. g. Teleti,Krtsanisi, Samgori-Patardzeuli-Ninotsminda, Samgori
South Dome oil fields)
– Upper Cretaceous fractured limestones in
anticlinal structures (e. g. Kavitskhevi,
Manavi oil structures – no commercial
production yet).
5 Production
Until 1977, when the oil production from the
Samgori-Patardzeuli-Ninotsminda
field
complex some 20 km east of Tbilisi has
started, the overall oil production from
Georgian fields has languished for years
with daily rates of just a couple of hundred
barrels.
Between 1977 and 1984 Georgia experienced peak production rates of almost
70,000 b/d (equals some 3.3 million t of oil
per year) before overexploitation and insufficient reservoir management resulted in a
drastic rise of the water cut against a dramatic drop of the oil rate. Production from
the other fields has always stayed at a low to
rather marginal level.
Today’s oil production from just a handful of
fields is below 1000 b/d respectively some
135 t/d.
During the most recent years, international
as well as domestic operators drilled a couple of wells. Targets were the Middle Eocene volcanoclastics in the Samgori area
and the Miocene in Norio. Although initial
production from one of these wells was
250 b of oil per day without water, this rate
dropped within a few months to less than a
tenth plus a high water cut. Hence, the additional production from these new wells had
no mid to long term impact on the production trend.
OG 189
GEOLOGY
As of end of 2014, cumulative oil production
in Georgia amounts to 27.8 million t.
6 Underground Gas Storage
(UGS)
Since 2004, Georgia has repeatedly considered to build an underground gas storage. In
January 2015,“JSC Georgian Oil and Gas
Corporation (GOGC) has tendered a project
for the preparation of a feasibility study and
construction of a UGS project for the sake of
security of natural gas supply to the “protected” (household and thermal power generation) consumers of Georgia and to accommodate seasonal and short-term fluctuations in the demand for natural gas”. For
this purpose, the partly depleted Samgori
South Dome oil field (fractured volcanic
tuffs, oil with high water cut, water drive!)
shall be transformed to a UGS with a
planned turn-over-volume of 200 to
250 million m³ of gas [6]. Realization of the
feasibility study of this ambitious project
has been awarded to a French company. The
feasibility report has to be prepared by beginning of 2016, while construction of the
gas storage shall be completed in 2019 [7].
7 Reserves/Resources/Potential
For petroleum exploration purposes, Soviet/Russian experience was applied, as it
was soon understood that Georgia, geologically located just south of the Greater Caucasus Mountains, might have very similar reservoir conditions like well-known Russian
oil fields in Chechnya and Ingushetsia north
of the Caucasus. Georgia is trapped between
two major orogenic systems: the Greater
Caucasus in the north and the Lesser Caucasus in the south. Between these mountains,
the same sedimentary formations exist
which form petroleum systems of the
Northern Caucasus region.
7.1 Unconventional oil (shale oil)
Parts of the Maikop are compared with the
Bakken in the US and considered as a high
potential future target. Respective research
has just started [8]. However, the shales have
not undergone any significant thermal overprint leading to sufficient brittleness that
could support fracking of this rock; no intensive research yet.
7.2 Reserves/resources nomenclature
Regarding “reserves”, “resources” and “potential” a common language, comparable
with SPE and SEC standards, still needs to
be established in Georgia.
According to GOGC, the Georgian state oil
company, per end of 2014 Georgia has [9]:
– 2P reserves: oil – 7.3 million t
natural gas – 7 billion m³
(free & associated)
– Contingent resources (2C):
oil – 51.4 million t
natural gas – 15.4 billion m³
OG 190
– Prospective resources:
oil – 677 million t
natural gas – 148 billion m³.
A most recently published message of an operator in the eastern Kura Basin that his company “has identified combined prospective
natural gas resources of as much as 12.9 tcf
(365 billion m³) of gas-in-place, with as
much as 9.4 tcf (266 billion m³) of recoverable prospective natural gas resources” appears not to be considered in GOGC’s official numbers and still waits for an independent validation [10].
8 E&P Business Environment in
Georgia
The political situation in Georgia is considered stable; petroleum related state bodies
like the Agency of Natural Resources and
the national oil company GOGC are, in general, very open minded and supportive towards (potential) operators.
Onshore, almost all available blocks are
awarded to local or international operators;
offshore blocks shall be offered in a licensing round that is in preparation. Main activity and production is in blocks near Tbilisi
(Kura Basin).
Since 1996, petroleum licenses have been
awarded via PSA (Production Sharing
Agreement) regimes that used to be quite investor friendly; however, terms for new licenses have become less attractive during
the last couple of years, but are still, to some
degree, negotiable.
As Georgia’s petroleum potential has always
remained below the radar of larger international oil companies, players in Georgia are
smaller to mid-sized E&P companies as well
as ambitious investment groups with partly
strongly diverging business models and concepts. Cooperation of two or more companies via joint venture agreements are pretty
common.
Total investment of the E&P industry in the
post-Soviet time is estimated to be some
US$ 1.2 billion (verbal communication Mr.
Tevzadze, CEO of Georgia Oil and Gas
Ltd.). Compared to this investment the economic outcome has been very modest.
8.1 Challenges an operator may face
– Topography – impact on accessibility,
transport logistics, cost
– swampy areas along the Black Sea coast:
limited accessibility due to missing infrastructure and or environmental restrictions
– mountainous regions in central eastern
Georgia (e. g. Norio, Ninotsminda,
Manavi areas): limited accessibility due to
hostile morphology (steep cliffs, dense
and steep forests, limited number of viable
tracks or roads)
– Protected Areas, National Parks – impact
on accessibility, timing, cost
– Population – impact on accessibility of
certain regions, transport logistics, cost
in some areas, e. g. town of Sagarejo, peo-
ple can be extremely ‘sensitive’ and block
any activity (e. g. acquisition of seismic)
even against highest political interventions and official police support
– Service industry – impact on timely availability, cost; proper planning is crucial
due to the oversee able E&P activity in
Georgia, only a few service providers have
a base in the country. The nearest concentrations of service companies are in Baku,
some 500 km from Tbilisi, or in eastern
Turkey respectively, across the Black Sea,
in Romania.
Proper planning and call of service providers is mandatory for avoiding expensive
stand-by cost.
– Infrastructure – impact on oil & gas sales,
transport logistics, cost
For both, oil and gas, mostly old but reasonable production and transport facilities
are in place, especially around Tbilisi and
in the Kura Basin fields. There is no refinery in Georgia, hence all produced crude
oil is exported from Black Sea harbors
(transport from the fields to these harbors
is by train). Transit pipelines are operated
with pressures of 80+ bar and not accessible for the domestic production. Gas is
sold domestically.
– Skilled personnel – impact on quality, efficiency, success of work
– Senior technical staff with solid Soviet
time education normally belong to a company’s knowledge carriers but are hardly
familiar with state of the art technology,
often no or only limited English speakers
– Geoscience and petroleum engineering
education at the Tbilisi Technical University does not meet western standards and
requirements
– Company-internal respectively sponsored education/training of professionals
is essential for successful application of
modern technology and methodologies
9 Conclusion
Georgia has a substantial petroleum potential with well developed petroleum systems.
All discovered oil and gas fields as well as
prospective regions belong to the Transcaucasian intermountain depression comprising the Rioni Basin and the Kura Basin.
Rioni Basin: thickness of the sedimentary
sequence is some 8–9 km onshore and up to
15 km in the Black Sea. Onshore, three
small oil fields have been discovered with a
cumulative production of 143,000 t of oil.
Ambitious offshore drilling plans of 2004/
05 have not materialized as the existence of
sufficient reservoir rock appeared too uncertain. Drilling successes in the Romanian,
Ukrainian and Russian Black Sea areas face
a couple of (expensive) failures in Turkish
waters. The Georgian Agency of Natural Resources prepares an offshore licensing round
– the date of announcement is still unknown.
The Kura Basin, including its western Kartli
subbasin, extends eastwards from central
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GEOLOGY
[8]
[9]
[10]
[11]
Fig. 6
E&P license blocks onshore and offshore Georgia, Status: December 2014 (GOGC)
eastern Georgia into Azerbaijan and the
Caspian Sea with some of Azerbaijan’s most
prolific oil fields onshore as well as offshore. The sediment thickness reaches from
14–15 km in the east of Georgia to some
20–25 km in the center of the south Caspian
Sea. The Kura Basin holds 18 out of 21 formally registered oil/gas discoveries in Georgia including the country’s biggest field
complex
Samgori-Patardzeuli-Ninotsminda.
Ways forward: reservoir quality and ways to
improve the production rates, combined
with modern drilling and completion technology and state of the art reservoir management, are the keys to a significant mid to
long term increase of the domestic oil production.
Earlier this year, a deep well in Manavi
(~30 km east of Tbilisi; planned total depth
4500 m) was spudded to assess a huge
anticline with a several 100 m thick Cretaceous carbonate body from which some oil
was tested in two previous wells. Due to
technical problems, the well was abandoned
in late July 2015 without having reached the
target. Georgian geologists feel confident
that these Cretaceous carbonates belong to
an identical depositional environment north
of the Caucasus, in Chechnia, where excellent fracture porosity led to production rates
of up to 400,000 b/d [11]. In case of success
of this ongoing well the E&P industry in
Georgia should experience a strong kick into
an “oily future”.
Despite a total investment of some
US$ 1.2 billion, not one single new field has
been discovered in the post Soviet time.
However, operators with the right (geological) concepts, utilization of modern technol-
OG 192
ogies and well trained professionals and financially well funded have a realistic chance
to turn the tide and Georgia may become a
respected oil and gas producer that is not
only watching Azeri oil and gas transits from
the Caspian to the Black Sea and further to
Europe.
The authors are grateful to Irakli Tavdumadze and
Mevlud Sharikadze, both in Tbilisi, for their input to the
geological chapters. For his critical review of the manuscript and helpful hints for drafting this paper we thank
Reinhard Sachsenhofer, Montanuniversität Leoben,
very much.
References
[1] GOCHITASHVILI T.: Oil & Gas Infrastructure of
Georgia – Ongoing and Prospective Projects;
Presentation at GIOGIE Georgian Energy Conference, Tbilisi, Georgia (2014).
[2] TAVDUMADZE I., NACHTMANN W. (Editors):
Kartli – Field Trip Guide Book; AAPG Europe Regional Conference, Tbilisi, Georgia, 54 pages,
English and Georgian, Publishing House Universal, Tbilisi, Georgia (2013).
[3] ADAMIA S. (Editor): Geological Map of the Caucasus 2010; http://iv-g.livejournal.com/ 1104914.
html.
[4] NACHTMANN W., ADAMYAN A., SALAJKA I.,
SHARIKADZE M., SURAMELASHVILI Z.,
TAVDUMADZE I.: Are there “Hidden or Left
Over” Oil Treasures in Georgia?; Abstract and
Presentation AAPG Europe Regional Conference “Petroleum Systems of the Paratethys”,
Tbilisi, Georgia (2013).
[5] GAMKRELIDZE I., GAMKRELIDZE M., LOLADZE M., TSAMALASHVILI T.: New Tectonic Map
of Georgia (Explanatory Note); Bull. Georg. Ntl.
Acad. Sci., p. 111–116 (2015).
[6] GOGC Presentation: UGS Project – Pre-Proposal Meeting, Tbilisi, January 30, 2015.
[7] http://www.gogc.ge/en/page/french-company-
geostock-sas-will-prepare-the-feasibility-studyfor-the-underground-gas-storage, 08. 06. 2015.
ROBSON W.: Oil and Gas in Georgia – Untapped
Potential; Presentation at GIOGIE Georgian Energy Conference, Tbilisi, Georgia (2014).
GUDUSHAURI S.: Georgia’s Potential as Hydrocarbon Producer – Resources Assessment; Presentation at GIOGIE Georgian Energy Conference, Tbilisi, Georgia (2014).
Frontera and Naftogaz of Ukraine sign strategic
MOU for upstream and LNG cooperation (2015)
– http://www.energy-pedia.com/news/ukraine/
new-164311?editionid=101677.
NIBLADZE M., JANIASHVILI A.: History of Petroleum Geology in Georgia; Extended Abstract
and Presentation AAPG International Conference & Exhibition, Istanbul (2014).
Wolfgang Nachtmann earned
his PhD in geology at the Innsbruck University, Austria, in
1975 and has some four decades of E&P industry experience, primarily in central in
eastern Europe (RAG). 2013/
14 he acted as Geoscience
Manager and Business Developer in Georgia (MND
Georgia B. V.) in close cooperation with local and international oil companies. Currently, heis Managing
Director of Central European Petroleum GmbH (CEP)
in Berlin, Germany. Since 2002, he teaches petroleum
exploration & production geology related lectures at
the Montanuniversität in Leoben, Austria.
Alexander Janiashvili received
his Master degree from in HeriotWatt University of Edinburg in
Reservoir Evaluation and Management in 2005. He has large
experience in reservoir modeling and evaluation for multiple
oil fields in Russia (mainly
Western Siberia) in field development companies.
Currently, he works in Central Georgia and his main
working interest is oil and gas exploration in Georgia
from the structural modeling point of view.
Zurab Suramelashvili was
born in Mtskheta, Georgia, in
1976 and graduated in 2003 in
Exploration and Mining of Gas
& Oil Deposits, Gas Storage /
Petroleum Geology, Oil and
Gas / International Customs
Law at the Technical University
Tbilisi, Georgia. Since 1996 he works as a geologist
with CanArgo Georgia Limited. During his career he
participated in several conferences of AAPG and
CEEC and international job related trainings and
courses.
DRILLING
Successful Workover Operations for Milling
Permanent Bridge Plugs at 8000 m MD
– A Case Study
By K. SOLIMAN*
Abstract
World oil and gas demand is growing on a
continuous base. Simultaneously produced
water and maturity of producing fields are
increasing gradually, which creates a major
challenge for E&P companies. Economically it is very important to isolate reservoir
compartments with a high water cut, to
guarantee maximum oil production and an
effective utilization of processing facilities.
Having all reservoir compartments on the
nearby level of produced water would require opening isolated sections to increase
daily production. Additionally oil and gas
prices play a major role in reopening isolated pay zones. This was carried out in two
wells within the Mittelplate oil field, North
Sea. The Mittelplate oil field is located
within a highly sensitive environmental area
in northern Germany. To be precise, it is a
protected landscape for migratory birds
(Wadden Sea, UNESCO World Natural Heritage Site Enclaves).
Production of Dieksand (as part of Mittelplate oil field) extended reach wells started
2001/02, after three years of production.
Permanent bridge plugs were installed to
isolate lower reservoir compartments, due
to increased water cut. Milling those permanent bridge plugs, at a measured depth of
nearly 8000 m (26,240 ft), was executed in
2014. Those specific well bores are extended
reach wells, with a total measured depth of
nearly 9000 m (29,520 ft). To provide a circulation, upper compartments were killed.
Killing producing zones without damaging
the reservoir was one of the major targets.
After some eight years of production sand
deposition was an additional challenge in
both wells, resulting in higher operational
torques. Hence the cleaning operation had
to be customized to counter mentioned torque challenges.
Research confirmed that those were the first
two bridge plugs worldwide to be milled out
in extended reach wells, within a horizontal
section of 82° deviation, at nearly 8000 m
(26,240 ft) measured depth.
* Karim Soliman, DEA Deutsche Erdoel AG, Hamburg
(E-mail: [email protected]). Lecture, presented at the DGMK/ÖGEW Spring Conference 2015, Celle, Germany, 22–23 April 2015.
0179-3187/15/IV
Both heavy workover operations were a major success and supplemented a notable oil
production to the Holstein operational district. Challenges were solved through adapted engineering techniques and smart solutions. Within this article challenges, engineered solutions and results will be presented as a case study.
sand there are seven production and two disposal wells.
It has to be mentioned that the Mittelplate oil
field is situated within the UNESCO World
Natural Heritage Site Enclaves Wadden Sea.
This environmentally protected area is an
important resting domicile for migrating
birds. DEA has introduced and implemented
several guidelines and improvements to
guarantee maximum protection at the highest safety and environmental standards.
General Information about Mittelplate Oil Field
35.6 million m³ (224 million bbl) were successfully produced from the Mittelplate oil Aim of Workover Operation
field up till September 2015. This oil field is In 2014 two workover operations were carthe largest within the territorial area of Ger- ried out at Dieksand (Dks). The main purmany and creates a key pillar within the pose was to remove permanent bridge plugs,
structure of DEA. Nearly 50% of Germany´s which were installed back in 2005. Those
oil is produced out of this field.
permanent bridge plugs were installed to
Mittelplate is located roughly 8 km off the isolate lower reservoir sections, due to incoastline (Friedrichskoog, Schleswig-Hol- creased water cut (~50%). Newly perforated
stein) and 80 km North West of Hamburg. upper pay zones would allow significantly
This field was discovered in 1980 and took higher production rates with 100% oil and
up production in 1987. The first wells were lower processing expenditures.
drilled from the drilling and production platform Mittelplate A (MpA). To increase daily Dieksand 5
production rates and save limited drilling Drilling the extended reach well Dks 5
slots, a further drilling location was set up started in October 2000 and continued for
and started drilling from onshore in 1997. about four months for completion and handDieksand (Dks, onshore location) wells ing over to the production department. The
were planned and executed as extended well was then perforated (Dogger Delta) and
reach wells (ERW) towards the oil field finally got into production in February 2001.
Mittelplate. Those ERW´s were drilled This borehole was planned and executed
through a salt dome
(Fig. 1) with a maximum length of
9275 m (30,429 ft,
Dks 6).
Twenty production
and eight Injection
wells are situated on
the Mittelplate drilling and production
platform. Three of
the twenty producing wells from MpA
are configured as
duo-lateral
wells
with TAML 5 (Technology Advancement
of Multi-Lateral level
five)
completion,
saving limited drilling slots. In Diek- Fig. 1 Overview Mittelplate oil field
OG 193
DRILLING
with a total measured depth of 8895 m
(29,183 ft) and a true vertical depth of
2191 m (7188 ft). It was at this time the longest well ever drilled by RWE Dea AG.
Dieksand 7
For Dks 7 drilling started in April 2002 and
lasted for four and half months. At the end of
2002 it got into production, after successful
perforation of lower reservoir section
(Dogger Delta). This well has a total measured depth of 8450 m (27,722 ft) and a true
vertical depth of 2122 m (6962 ft).
Both wells have nearly the same casing design with 10 3/4″ / 9 5/8″ casing to surface
and 7 5/8″ / 7″ liner starting from ~3000 m
MD to total depth. The 7 5/8″ / 7″ liner is utilized for production purposes. A formation
isolation system with 7″ production tubing
is installed to protect the 10 3/4″ / 9 5/8″ casing from production fluid. This formation
isolation system gives the opportunity to
shut in the wellbore for ESP change without
any killing operation. The aim is to protect
and avoid any formation damage. Furthermore the formation isolation system allows
cleaning production tubing through circulation of washer. Both wells are classified as
long radius wells with a build rate between
2° to 5° per 30 m. Casing sections greater
than 80° have an approximate extent of
7200 m.
Performed Steps during
Workover Operation
Workover operations in Dieksand were carried out with KCA Deutag as a rig provider.
The T-207 (BENTEC-1500-AC) EURO type
rig was specified for that purpose. T-207 has
box-on-box substructure, which enables rig
moves and efficient rig-up and rig-down
times. This rig built in 2009 has a large
set-back capacity, The pick-up-lay-down
machine and a skidding system allow skidding with drill pipe in the mast. Using this
system T-207 was skidded from Dks 7 to Dks
5 with 6000 m (3 1/2″ DP 3500 m; 5 1/2″ DP
2500 m) of drill pipe in the mast.
Noise emissions played a major role during
rig selection, to minimize the impact on the
neighborhood and surrounding protected
landscape. T-207 fulfilled all requirements
regarding noise protection, due to measures
taken earlier (noise protected rig floor, fingerboard, shale shaker area, generators and
draw works). Additionally mud pumps were
noise protected using housing. Soundproofed walls were additionally installed on
three sides of the drilling pad to minimize
noise emission. Acoustic level microphones
were positioned in- and outside the drilling
pad to monitor noise. Noise pollution during
workover was below 55 dB on average at a
distance of 300 m.
Due to similar completion design of Dks 5
and Dks 7, planned operational phases were
nearly identical. Below the main operational
OG 194
sequences are listed. Some of those sequences are summarized.
1. Shut off ESP and isolation from piping
system
2. Hydrostatic equalization of wellbore,
followed by shut in of formation isolation system
3. Clean out of 3 1/2″ tubing from inside as
well as annular space 3 1/2″ to 7″ (annular space A). This was carried out
through circulation of adequate volumes
of washer
4. Removal of relevant X-mas tree equipment as solid block, adapter spool, gate
valves and piping system connection
5. Pull out of hole (POOH) 3 1/2″ tubing
hanger, 3 1/2″ tubing and ESP
6. Placement of adapted plugging pill
above formation isolation system (lubricator valve)
7. Opening formation isolation system and
killing the wellbore with adapted plugging pill
8. Remove of tubing head spool
9. POOH 7″ tubing hanger, 7″ tubing, formation isolation system and 5 1/2″ tail
pipe with seal steam
10. POOH 9 5/8″ packer with PBR and tail
pipe with steam
11. Cleanout of 7 5/8″ / 7″ liner section in
steps up to 1000 m (3280 ft)
12. Exchange of wellbore fluid from oil
based mud (OBM) to water based mud
(WBM)
13. Milling permanent bridge plug
14. Push down remaining part of permanent
bridge plug below lowest perforation interval
15. Perforation of additional reservoir sections
16. Run in hole (RIH) 9 5/8″ packer with
PBR and tail pipe with steam
17. RIH 5 1/2″ tubing with seal steam, formation isolation system, 7″ tubing and
7″ tubing hanger
18. Installation of tubing head spool
19. RIH ESP, 3 1/2″ tubing and 3 1/2″ tubing
hanger
20. Installation of X-mas tree equipment as
solid block, adapter spool, gate valves
and piping system connection
21. Handover for ESP start and production.
During planning and engineering phase several challenging steps were identified as
critical for success of operations. Challenges were a result of wellbore geometry as
extended reach wells and reservoir properties. Those could be summed up into three
major blocks:
1. Well killing/killing operation
2. Wellbore clean out
3. Milling operation.
Well Killing
Selection of plugging pill
To ensure a wellbore circulation after POOH
of formation isolation system, both wells
had to be adequately killed. Experience indi-
cated that application of a salt pill would not
lead to acceptable plugging of the formation, thus resulting in massive loss of
workover fluid into pay zones ending up in
negative production behavior.
Producing reservoir layers in Dieksand
wells have a relatively high permeability of
up to 10,000 mD and porosity between 17%
and 27%. Porosity, pressure conditions, permeability and length of perforation intervals
represented a challenging situation for well
killing. The focus was to carry out this job
with little or no damage to pay zones. For selection of adequate plugging pill, the current
state of influencing conditions had to be
evaluated.
The most influencing conditions to be reviewed were:
– Temperature conditions: In the case of
Dieksand 5 and 7 wells temperature distribution at perforation intervals ranges between 68 °C (155 °F) and 73 °C (163 °F)
– Pressure conditions: Static wellbore pressure ranges from 140 bar (2030 psi) to
160 bar (2320 psi) depending on investigated pay zone. In general both wells are
under hydrostatic pressure and static fluid
level is at roughly 500 m TVD (1640 ft)
– Porosity: For lower reservoir compartments in Dogger Delta porosity ranges between 17–27%. Within the upper compartments in Dogger Epsilon value ranges from
22–25%. Analysis showed that sampled
cores mainly consist of Quartz [SiO2]
~75%, Muscovite [KAl2(Si3Al)O10(OH,F)2]
~10% , Calcite [CaCO3] ~10% and other
minerals (~5%)
– Permeability: Both pay zones of interest
show relatively high permeability ranging
from 2000 mD to 10,000 mD, depending
on investigated sub-sand layers
– Perforation interval: Length of perforation
intervals (reservoir section above bridge
plug, Dogger Epsilon) are ~170 m for both
wells.
Several properties were determined by an
engineering team as essential to get a fit for
purpose performance from selected plugging pill. Below the most important properties are listed:
– Ability to build up a plugging filter cake
– Ability to withstand differential pressure
– Solubility of plugging pill
– Coherence during well killing operation.
To carry out efficient selection possible
plugging pill candidates were pre-evaluated
based on experience and historical data.
From the economical and technical point of
view the most interesting candidates were a
salt plugging pill and a lime scale plugging
pill. As previously mentioned the salt plugging pill provided inaccurate performance.
This type of pill was not really successful in
plugging perforation intervals, leading to
major challenges during earlier operations.
Lime scale showed good plugging behavior,
but dissolving the lime scale pill with acid
resulted in a chemical reaction with reservoir oil. This created high viscous fluids and
DRILLING
remarkable precipitations of asphaltenes, having a negative influence on
production behavior.
This fact disqualified that type of pill.
A modified salt pill
was then investigated as a possible
candidate to fulfill
the requirements of
well killing. Modifi- Fig. 2 Starting phase of dissolvent for candidate A
cation focused on selection of fit-forpurpose additives to improve the perfor- Additives for one cubic meter of water are
mance of the salt pill. According to investi- presented in Table 1.
gations, resin was a promising additive. Two
resin additives were selected for further in- Killing operation
vestigation. The ability to build up a filter For well killing the crux was ensuring cohercake was investigated in the DEA laboratory ence of plugging pill, so that it reaches perunder in-situ reservoir conditions. Porosity foration intervals compactly. Simulations
and permeability conditions were simulated indicated that large plugging pill volumes
according to evaluated circumstances to get have to be utilized to ensure that lighter mud
reliable results. The candidates displayed does not break through (while bull heading)
suitable filter cake build up. Average values towards perforation. So placement of pill
ranged from 2.5 mm to 3.5 mm. The candi- (above Lubricator Valve) in 7″ production
dates performed well regarding withstand- tubing was one of key factors for success.
ing differential pressure. Candidate A Pumping rates were limited to 300 l/min
showed fit-for-purpose behavior concerning avoiding mixing up or break through of
filtration volume over time. Comparing fil- plugging pill, spacer and oil-based mud.
tration volumes after 30 minutes showed Mixed up fluids have a negative impact on
45% (on average) better performance of plugging behavior and give unclear indicacandidate A than candidate B. Determina- tions of performance.
tion of filtration volume was carried out ac- After placement, the formation isolation
cording to API recommended practice system was opened and the plugging pill was
13B-1.
bull headed. Due to the pumping distance of
Investigations continued with the promising ~7200 m in the horizontal section (>80 °)
candidate A (AUSTONE II, AMC) regard- constant high pumping rates were imperaing solubility. One of the most important tive. This should ensure that the plugging
specifications was the necessary solubility pill reaches perforations compactly. Once it
in reservoir oil. This should ensure that the reached perforations pumping rates had to
modified pill gets dissolved during the pro- be adjusted to maintain constant pressure.
duction phase. Initial indications for dis- Well killing was successful in both wells,
solving in reservoir oil started at 20 °C. The once reaching perforations and setting the
dissolving rate improved further with in- plugging pill, losses decreased from 250 licreasing temperature. Figure 2 shows the ters in the first hour to zero liters after four
starting phase of pill dissolvent.
hours. Proper placement resulted into zero
To ensure coherence of plugging pill and losses over the whole workover period (~50
avoid mixing up with wellbore fluids, during days per workover).
pumping, additives like Xanthan were included. After detailed investigations, the
mixture and main contents of modified
plugging pill were fixed:
Torque and Drag
1. Modified starch (AUS-DEX HT): Main Experience from earlier workovers (Dks 5 &
function is to improve physical properties 7) indicated that torque and drag issues are
at reservoir temperature and reservoir not a topic to be considered for Dieksand
pressure; furthermore it supports stability wells. While setting permanent bridge plugs
of plugging pill
back in year 2005, torque values were at a
2. Xanthan (Xan Bore): Is a carbohydrate maximum of 22 kNm at the surface, having
and has the function of increasing viscos- sufficient buffer to weakest connection
ity for better pumping behavior
point (DP XO 4″ x 5″ @ 7 5/8″ top of liner).
3. Resin (AUSTONE II): Main component In 2014 torque and drag created a major
for plugging reservoir pores, this compo- problem in clean out operation. The main
nent could be dissolved by reservoir oil
reason for torque and drag issues was the
4. Salt (NaCl): Supports plugging of reser- outcome of sand deposition. Torque peaks
voir pores
reached 44 kNm (~8000 m drill pipe in5. Water: Works as a carrier medium for all stalled), resulting in a major risk of breaking
ingredients of modified plugging pill
weakest connection (DP XO 3 1/2″ x 5 1/2″
Table 1
Additives of modified plugging pill
Content
Salt
kg/m³
150
AUS-DEX HT
15
Xan Bore
7,5
AUSTONE II
106
at top of liner, maximum 24 kNm). Realizing that torque and drag issues could end up
in a fishing operation, a two-step approach
was adopted to solve the problem.
Step 1: Testing of torque values
To get a better understanding of torque behavior real time testing was carried out during workover operation. As mentioned before the weakest connection point is the drill
pipe X-Over 3 1/2″ 15,5# X 5 1/2″ 21,9# at
the top of 7 5/8″ liner with a maximum
make-up torque of 24 kNm. To test torque
development at 3000 m, DP 5 1/2″ 21,9#
were tested at different rotational speeds,
with and without pumping working fluid.
Investigations at Dks 7 resulted in torque
values reaching 36 kNm. On average the
torque was 28.5 kNm. This indicated that on
average 15.5 kNm torque (44 kNm minus
28.5 kNm) was generated over 5000 m of
7 5/8″ / 7″ section. The safety margin to maximum allowable torque was roughly
8.5 kNm at the weakest connection point.
Step 2: Reduction of torque.
Application of water based mud
Due to unpredictable milling conditions water based mud (WBM) was foreseen during
planning phase for permanent bridge plug
removal. A change from OBM to WBM was
planned to reduce torque and to minimize
losses of expensive OBM, due to open perforation intervals below permanent bridge
plugs. The assumption was that the plugging
pill utilized back in 2005 was completely
dissolved. Water based mud contained
mainly two components:
1. Fresh water
2. Friction reducer (AMC Torq-Free Xtra).
The friction reducer displayed excellent
properties, while replacing OBM by WBM.
The onsite circulating pressure decreased
from ~300 bars to ~210 bars (~3000 m DP
5 1/2″, ~ 5000 m DP 3 1/2″). Additionally the
torque decreased by 4 kNm with drill pipe at
top of bridge plug.
Application of drill string torque
reducer tool (DSTR tool)
The primary objective was to reduce the effects of high side forces thus counteracting
torque development along the well bore. The
main focus lay on the area between kick off
point (KoP) and end of build-up (EoB) in
10 3/4″ 51# casing section. This area typically shows highest casing wear and drill
pipe wear, thus torque build up. Results of
simulations for Dks 5 & 7 confirmed assumption.
OG 195
DRILLING
Fig. 3
Critcal side force Dks 5
Fig. 4
Critcal side force Dks 7
In Figures 3 and 4 the area of critical side
force can be clearly recognized, and is
marked in red. Areas marked blue have moderate side forces and a minimum influence
on torque build up. According to simulation,
side forces at some joints had a value of
900 daN.
To cover primary area of torque development DSTR tools were utilized. This tool
minimizes contact area between drill pipe
and casing. Additionally bearings are installed to reduce rotational forces. The
DSTR tool´s spacing and placement were
determined by curve length of each build up
section. In the case of Dks 5 & 7 they were
implemented into the drill pipe string from
100 m MD to 1600 m MD. At each stand one
DSTR tool was installed.
Decreasing surface torque is calculated
through simulations. One important input
factor was the casing friction factor. For Dks
5 & 7 the estimated friction factors lay between 0.22 and 0.27. Two Scenarios were developed for each of the wells. The first scenario was the one without DSTR tools installed (Fig. 5, red line). The second scenario
was simulated with DSTR tools in action
(Fig. 5, blue line). The estimated torque
without DSTR tools accumulated up to a
value 48 kNm. This torque rang was approved through operational measurements.
OG 196
Utilizing DSTR tools resulted in a reduction
to 36 kNm, which is an improvement by
27% in surface torque. During milling operation values were fluctuating between
32 kNm and 37 kNm, confirming simulation outputs.
main idea, during planning phase, was to
clean out liner section in maintainable steps
up to 1000 m. This should secure a reliable
clean out with moderate operational conditions.
On site investigation figured out that the
first sections below top of liner were significantly sedimented. Calculations resulted
in 20% volumetric proportion for first
250 m of 7 5/8″ / 7″ liner. Due to this fact
clean out steps were reduced to 250 m, to
avoid stuck pipe, pack offs and torque &
drag problems. Toward perforation the sand
deposition decreased to a volumetric proportion of 5%. So clean out steps were increased to 400 m. Integration of DSTR
tools resulted in a safe clean out operation
with no torque peaks.
Due to the length of the clean out string (up
to 7500 m) pumping rates were limited, because of pressure losses. Calculations figured out that the maximum pumping rate
would be 1000 l/min at 300 bar pumping
pressure. On site measurements confirmed a pumping rate of 1100 l/min at
300 bar. In the 7 5/8″ / 7″ liner flow velocities would be suitable for fines removal
(1.25 m/s). Having transported fines out
of the liner into the 10 3/4″ / 9 5/8″ casing
section, a pumping rate of 1000 l/min
would not be fully effective, since larger
particles would settle out.
Due to this fact the circulation tool (WELL
COMMANDER) was planned and installed
at 7 5/8″ top of liner. This tool allowed pumping rates up to 3800 l/min with a minimal
pressure drop (~140 bar). Boosting annular
velocity (2.5 m/s) ended up in adequate
fines removal in upper 10 3/4″ / 9 5/8″ casing
section.
Design of clean out BHA was very simple to
minimize operational risks. Configuration
was:
1. Taper mill
2. 3 1/2″ heavy weight drill pipe with implemented Jar and accelerator
3. 3 1/2″ drill pipe (250 m–5000 m)
4. Well Commander including ball catcher
5. 5 1/2″ drill pipe with DSTR tool in upper
section.
Borehole Clean Out
As previously mentioned borehole clean out
was determined as one of the critical operational steps, due to
wellbore trajectory
and extent. The main
focus was on the
cleaning operation
of 7 5/8″ / 7″ liner,
due to flow of reservoir fluids in this
section. Fines deposition was the major
topic; the expectation for volumetric
proportion was 1%
to 5% (1–2 cm precipitation).
This
phase consumed a
large portion of Fig. 5 String torque simulations for Dks 5. Red line indicates torque
simulation without DSTR tools. Blue line indicates improvement in
overall operational
torque within areas with DSTR tools. Horizontal axis represents
time (~30%). The
torque in Nm. Vertical axis represents measured depth
DRILLING
Fig. 6
Alpha Oil Tools, 5 3/4″ H-M Bridge Plug (model “P”)
Permanent Bridge Plug Milling
To plan a successful milling operation, material properties and recommendation of
bridge plug provider had to be considered. In
both wells permanent bridge plugs from Alpha Oil Tools were installed (Fig. 6). The
high pressure and temperature 5 3/4″ H-M
Bridge Plug (model “P”) was set by using
hydraulic power. The most important properties to be considered for milling operation
were cast iron construction and one-piece
slip.
With support of Smith International a
fit-for-purpose bit selection was carried out.
For this category of workover three types of
mills came into consideration:
1. Copperhead Bridge Plug Mill
2. Super Junk Mill
3. PIRANHA Mill.
After deeper investigation, the decision was
to carry out the milling operation with the
Copperhead Bridge Plug Mill. This mill was
chamfered to guarantee no damage to the top
of the liner. The Milling BHA was kept very
simple to minimize risk of failure. BHA set
up:
1. Copperhead Mill
2. Bit stabilizer
3. String magnet
4. String stabilizer
5. 3 1/2″ heavy weight drill pipe with implemented jar and accelerator
6. 3 1/2″ drill pipe
7. 3 1/2″ heavy weight drill pipe at top of
liner
8. 5 1/2″ drill pipe with DSTR-tool in upper
section.
Milling operations were carried out according to recommendations. Flow rates were
1100 l/min with ~200 bar pumping pressure. Torque fluctuated between 32 and
37 kNm at 80 RPM (improvement through
WBM and DSTR-tool). Exact evaluation of
plug position was challenging due to sedimentation of reservoir sand above. The first
5 3/4″ H-M Bridge Plug was milled out after
110 min at Dks 7 with Weight on Bit values
from 5 to 13 t. Indication for milling was not
clear at the beginning, thus WOB was moderately increased.
Taking lessons learned from Dks 7 into account WOB was increased at Dks 5 and varied from 10 to 18 t. This resulted in improved milling time of 50 min. Utilized copperhead mills for Dks 5 and 7 are presented
below. Impact of higher WOB could be
clearly recognized.
Fig. 7
Fig. 8
Copperhead Mill after milling BP Dks 7
Outcome of Workover
Operations
The average production parameters (Dks 5
& 7) before workover operations were
1950 m³ (12,265 bbl) daily with water cut of
83%. After milling both permanent bridge
plugs and perforation of additional reservoir
intervals, production rates were slightly increased by 100 m³/d (629 bbl) to 2050 m³
(12,895 bbl) daily with an average water cut
of 70%. 280 m³/d (1760 bbl) of additional
oil were gained through workover operation
increasing oil production for both wells by
84%.
Conclusions
Workover operations for milling permanent
bridge plugs on Dieksand 5 and 7 were a major success. Through precise evaluation several challenges could be identified and fit
for purpose procedures were engineered.
Three key points were determined during the
planning phase. The first challenge was well
killing, which was solved through adequate
plugging pill selection. Selection was carried out after lab experiments and consultation of various service companies. The selected pill performed as expected, which resulted in safe workover operations, zero
losses and no damage to pay zones.
The second challenge was wellbore clean
up. Because of significant sedimentation in
the production casing, clean out steps had to
be adapted. The planned steps for clean out
operation were initially 1000 m and these
were reduced in practice to 250 m due to
massive sedimentation. Sedimentation issues resulted in torque peaks generating a
major risk of breaking the drillpipe´s weakest connection at 7 5/8″ top of liner (5 1/2″ X
3 1/2″ DP). Torque issues were solved
through implementation of drill string
torque reducers. Those tools were installed
in upper section of the drill string resulting
in a reduction of surface torque values by
27%. Additionally a change in the mud system was carried out to minimize losses of expensive oil based mud. Water based mud
promoted reduction of torque values (reduction ~7%) and pumping pressures (reduction
~30%).
The third challenge was selection of suitable
mill and milling parameters. Selection was
carried out in cooperation with service companies. Lessons learned from the first milling operation at Dieksand 7 allowed an increase of weight-on-bit for Dieksand 5. The
direct outcome was a reduction of milling
time from 110 min to 50 min for the same
kind of bridge plug.
Overall both workovers were very successful regarding engineering, execution and
economics. The increase of oil production
was 84% in comparison to before workover
operations.
Karim Soliman is a graduate
of Montan University Leoben,
Austria. He holds a Dipl.-Ing. in
Petroleum Production Engineering and a Dipl.-Ing. in Industrial Management and
Business Administration.
Karim started his career with
DEA Deutsche Erdoel AG back in January 2014. He is
currently working at production district Holstein and
responsible for production & completion of oil wells.
Copperhead Mill after milling BP Dks 5
OG 197
OIL/GAS PRODUCTION
BTEX Removal from Production Water using
Associated Gas
By M. VALKENIER, G. HINNERS, and G. THEMANN*
Abstract
HDPE is a popular material for pipelines
due to its chemical resistance, flexibility and
durability; unfortunately a major drawback
has been identified: BTEX1) components are
shown to be permeable through HDPE.
BTEX is environmentally unfriendly as well
as genotoxic and carcinogenic, but is commonly found in oil production and thus could
pose a problem when transporting these fluids through HDPE pipelines. The driving
force of the BTEX components through the
HDPE can be severely decreased by reducing the concentration in the fluid, effectively
preventing permeation. A novel process has
been investigated to remove the BTEX components from production water. This patent-pending process was tested on a laboratory scale, in order to obtain a proof-of-concept. The process was eventually scaled to a
full-size system, which is currently installed
in an oilfield in Southern Germany.
It was shown that by using a desorption column in combination with conditioned associated gas, BTEX components can be removed from production water and recovered
together with aliphatic hydrocarbons in one
process step. The recovered hydrocarbons
are added to the oil, effectively increasing
production and avoiding handling of waste.
By using this technology a continuous process is provided by Wintershall, which does
not need foreign stripping gas or materials.
1 Introduction
Production water can contain a variety of
commonly found impurities such as BTEX1),
mercaptans and others. BTEX components
are a group of aromatic hydrocarbons, which
are environmentally unfriendly as well as
being genotoxic and carcinogenic [1]. It has
been shown that these components can permeate through an HDPE pipeline [1]. By decreasing the BTEX concentration in the production water, the driving force of the diffusion of BTEX through a HDPE injection
pipeline is severely decreased, effectively
preventing permeation. Wintershall's self* M. Valkenier, G. Hinners, G. Themann, Wintershall Holding GmbH. Lecture, presented at the DGMK/ÖGEW
Spring Conference in Celle, Germany, April 22–23, 2015
(E-mail: [email protected])
1)
BTEX: Benzene, Toluene, Ethyl-benzene and Xylene
0179-3187/15/IV
OG 198
imposed goal is to remove at least 80% of
BTEX from the production water. Existing
processes have the disadvantage that the
problem of BTEX is shifted from the production water towards waste-management.
A patent-pending process was investigated
in which the BTEX is removed from the production water in the context of an existing
Wintershall oil production plant in Southern
Germany with a production water flow of
~40 m³/h. First some applicable alternatives
are described, before selecting the process to
be used. Secondly, the theoretical background of the novel process is discussed and
the in-field process system is presented. Finally the performance of the system is analysed, compared with simulations and operation curves are constructed.
2 Process Selection
2.1 Adsorption
Removal of BTEX components is possible
by using an adsorbent such as activated carbon. The main challenge is the low selectivity of BTEX (compared to water) on
adsorbents. The combination of the low concentration of BTEX and more than ten times
higher aliphatic hydrocarbon contamination
in the production water can lead to high adsorbent consumption. Furthermore, if the
adsorbent is loaded with BTEX then it needs
to be disposed of by an external company,
hence the problem is shifted from the liquid
to the solid state. Additionally, since adsorption is not a continuous operation, the entire
process has to be installed redundantly.
2.2 Adsorption with biological
material
Biological material can be used to remove
BTEX components, such as in the Siemens
PACT process. The performance of this system can be increased by adding activated
carbon adsorbent. The inherent disadvantage of a biological system is the inertia of
the system; if an increase in BTEX is introduced, the bacteria will not multiply quickly
enough to prevent breakthrough from occurring. This effect is overcome by introducing
activated carbon adsorbent. Addition of regeneration of the activated carbon then
makes this process the most elaborate of the
presented solutions. Addition of activated
carbon regeneration makes this process the
most elaborate of the presented solutions.
2.3 Membranes
The demands on membranes when separating BTEX components from production water are high, since either a nanofiltration- or
a reverse osmosis process is required. The
low molecular weight of the BTEX components presents a major challenge. The driving force from these components out of the
water phase is extremely small. Furthermore, the small particles and contaminants
generally found in production water are a
major disadvantage for the sensitive membrane units.
2.4 Electrochemical oxidation
Electrochemical oxidation promotes reduction of hydrocarbons from reservoir water.
The speed of this reduction is determined by
the structure of the components, but can not
only be directed towards BTEX components. The principle of the process is similar
to electrolytic dissociation of water: a cathode and an anode are inserted into the water
and a current is applied. The formed
hydroxyl radical can oxidize the hydrocarbons into carbon-dioxide and water. The major advantage is that no other material has to
be added to the stream, only electricity is required. The disadvantage is that contact of
the production water with oxygen is unavoidable.
2.5 Desorption
The desorption process is relatively uncomplicated, with a column as the main component, which serves as a contactor for gas and
liquid. The vapour pressures of the BTEX
components is relatively low (80–140 °C).
The column conditions must come close to
the vapour pressure of the BTEX components. This can be done in three ways: either
increase the temperature, decrease the total
pressure or decrease the partial pressure using stripping gas. The major advantage is
that no rotating equipment is present (except
for the pumps) and the fouling potential is
low. Due to the simplicity of the process, this
technology was chosen to remove the BTEX
components from the reservoir water.
3 Process description
3.1 Theory
3.1.1 BTEX stripping
In 2011, various laboratory experiments
were performed to show a proof-of-concept.
OIL/GAS PRODUCTION
Fig. 1
BTEX removal percentage as a function of the temperature for various media using a test-column. The dots indicate measured data,
while the dashed lines help visualize the trend
In these experiments BTEX was removed
from production water at various temperatures and at atmospheric and vacuum conditions. In 2012, a small test-column was built,
which was filled with glass Raschig rings to
provide the system with a high specific surface area. BTEX was removed from production water whereby the temperature, pressure, vapour-to-liquid ratio, BTEX preloading and gas (associated gas vs. nitrogen)
were varied. In Figure 1, the BTEX removal
efficiency is shown for various stripping
media as a function of temperature.
From Figure 1 it can be seen that the BTEX
removal capability of pure nitrogen is superior to associated gas. However, if benzene
preloaded nitrogen is used as stripping gas,
the temperature has to be elevated significantly in order to have a BTEX removal efficiency similar to that of pure nitrogen.
Therefore in order to effectively use nitrogen as a stripping gas, it has to be either conditioned very deeply or fresh nitrogen needs
to be provided continuously.
3.1.2 Gas conditioning
In order to select the appropriate stripping
medium, the gas conditioning unit step
should be taken into account as well. The gas
conditioning can be done using compression
and cooling to separate the BTEX components from the stripping gas.
Firstly nitrogen is considered as a stripping
gas, since it has a high removal efficiency as
can be seen in Figure 1. In Figure 2 a nitro-
Simulated nitrogen-benzene dew-point curve for a benzene content
of 0.025 mol-%
gen-benzene dew-point curve is shown for a
mixture containing 0.025 mol-% benzene by
using Peng-Robinson.
From Figure 2, it becomes clear that in order
to remove small amounts of benzene from
nitrogen, high pressures and/or low temperatures are necessary. This can be verified by
a short-cut calculation: if an ideal mixture is
assumed, which consists of 0.025 mol-%
benzene, operated at 10 bar(g) and 10°C, the
partial pressure is 0.00275 bar(a). At these
conditions the vapour pressure is 0.06 bar(a)
[2]. From this it follows that for an ideal mixture to condensate a small amount of benzene, one needs very large pressures (and/or
low temperatures).
Secondly a hydrocarbon stream will be considered as stripping gas, which can be considered a non-ideal mixture. For the analysis, the ΣC3+ fraction is varied to identify the
difference between associated and natural
gas. Two phase envelopes for a light and a
heavy hydrocarbon gas are shown in Figure
3. Depending on the composition, a two
phase-region is reached with relatively high
temperatures and low pressures. By exploiting associated gases (higher molecular
weight and thus containing higher aliphatic
hydrocarbons), the aromatic hydrocarbons
can be recovered as part of a condensate.
Simulations indicate that benzene can be removed from the loaded gas stream at low
pressures when operating the separator at
10°C, as shown in Figure 4. The formed condensate consists of both the aromatic as well
Fig. 3 Phase envelope for a light and a heavy hydrocarbon gas
Fig. 2
Fig. 4
as the aliphatic hydrocarbons, which can be
spiked into oil or sold directly. Associated
gas is used as stripping gas due to its advantages over nitrogen.
3.2 Process flow diagram
The process flow diagram for the field system is shown in Figure 5.
The reservoir water is treated in the
desorption column at elevated temperatures,
hence two recuperator plate heat exchangers
are installed to decrease the load on two hot
water plate heat exchangers, which results in
an energy efficient process. All heat exchangers are designed to handle full capacity in order to perform maintenance operations without having to shut-down the entire
plant. Furthermore, it is possible to operate
the heat exchangers in series or parallel. After the production water has been conditioned in the column, it is cooled down by the
recuperator, an air-cooler and, if necessary, a
vapour-compression refrigeration system.
The last cooling step is required to ensure a
maximum injection water temperature of
30°C (required by operations), which is not
guaranteed by using only an air-cooler.
The associated gas coming from the
desorption column, thus containing BTEX
components, is mixed with the associated
gas coming from the initial oil/gas-separator
before entering the gas conditioning unit.
The (assumed) saturated wet gas is cooled
down before entering a knock-out drum and
is compressed by an oil lubricated screw-
Condensation of benzene in a hydrocarbon condensate at 10 °C
OG 199
OIL/GAS PRODUCTION
Fig. 5
Process flow diagram for the desorption column in combination with the gas conditioning unit
type compressor to 4.5–14 bar(g). This
range in pressure level is related to the need
for fuel-gas; the amount of fuel-gas available can be adjusted by the pressure level to
match the requirement for changing gas
composition (winter - vs. summer operation). The gas is cooled down to 10 °C and
the hydrocarbon-gas mixture is separated. In
this last step, the aromatic and heavier
aliphatic hydrocarbons will condensate,
thus obtaining a conditioned associated gas
which can be used to clean the production
water. The remaining fuel-gas is also used to
heat up the production water entering the
column.
3.3 Advantages and disadvantages
The advantages of removing BTEX from
reservoir water using a desorption process in
combination with a gas conditioning unit
based on condensate production are:
– Recovery of aromatic and aliphatic hydrocarbons in one process step
– Simultaneous cleaning of stripping gas
– No foreign stripping medium is required
– No waste disposal required
– Continuous process
– Adjustable BTEX removal rate
– Energy efficient operation (non-condensed gas is used to heat the water)
– Production water treatment in a single step
desorption.
The major disadvantage of such a gas conditioning unit is the fact that a compressor is
required in order to produce condensate.
In Figure 6 the main components involved in
BTEX removal are shown. It can be seen that
the compact design leads to an orderly
plot-plan.
4 Performance analysis
The performance of the in-field desorption
column will be compared with the process
simulations in this chapter. By obtaining an
adequate model, it is possible to optimize the
process, so that it can be operated in the most
cost-effective way.
4.1 Experiments
The essential variables of the desorption column are the
Fig. 6
OG 200
In-field BTEX removal unit. From left to right: pumps (front), gas
conditioning unit (back), desorption column and heat exchangers
Fig. 7
production water temperature, gas/liquid ratio and the gas conditioning pressure and
temperature. The compositions of the gas
and water are not constant due to the nature
of the operations and these effects are assumed to be balanced out by acquiring
multiple samples.
The column temperature was varied from 20
°C to 75 °C; the gas/liquid ratio from 1 to 2;
To simplify the experimental program, the
gas conditioning operation conditions were
held constant at 10 barg (average operating
pressure) and 10 °C (minimum practical
temperature). The amount of BTEX removed as a function of those parameters can
be seen in Figure 7.
Figure 7 indicates that by increasing temperature the BTEX removal approaches 100%
asymptotically. With a higher gas rate (increased gas loading) the removal increases
significantly at 45 °C, however at low (20
°C) and high temperatures (75 °C), the difference in removal rate is small.
For a higher gas/liquid ratio and/or higher
temperature it can be seen that 80% BTEX
removal can be achieved by the in-field
desorption column using conditioned associated gas.
4.2 Simulation
In order to (energy-) optimize the desorption
process, a simulation model was created. After comparing the results (Fig. 7) with various property methods, it became clear that
the non-idealities in the production water
caused the model to grossly under- or
over-estimate BTEX removal. One property
method was selected and tuned to fit the
available data. The experimental data and results from the simulation are shown in Figure 8.
From Figure 8 it can be seen that the model
can adequately predict the qualitative and
quantitative data of the desorption column.
The error bars in the graph indicate the uncertainty in BTEX removal due to changing
gas and water composition. Above 30 °C, the
relative error is 10%; from 50 °C onwards
the error is ~6% and decreases with increasing temperature; which is deemed sufficient
for optimization purposes.
BTEX removal as function of column temperature for two gas/liquid
ratios
OIL/GAS PRODUCTION
Fig. 8
Experimental data and simulations using a tuned property package
Fig. 9
4.3 Recommendations
By using the calibrated model, the system’s
response to other operating conditions can
be simulated. This can be used to create lines
of equal BTEX removal percentages as a
function of the column temperature and
gas/liquid ratio. The results can be seen in
Figure 9.
As can be seen in Figure 9, a higher BTEX
removal rate requires an increase in the column temperature or the gas/liquid ratio. Increasing the G/L ratio has a direct effect on
the electricity consumption of the compressor and increasing the column temperature
only consumes more (self-produced) fuelgas. Hence it was recommended that the column should be run with high temperatures
and a minimum G/L ratio, in order to achieve
the 80% BTEX removal goal most cost-effectively.
5 Conclusions
In the early stages of the project the decision
was made to expedite the desorption process
for removing BTEX components from the
production water. The idea of using conditioned associated gas as a stripping medium
in a desorption column was successfully
tested in a laboratory set-up. From this it became clear that the project was feasible and
finally the system was built at an existing oil
production plant in Southern Germany with
production water volumes of ~40 m³/h. Finally the performance of the full-size column was evaluated and the process optimized in conjunction with simulations.
Worst case constant-BTEX-removal curves as a function of the
column temperature and G/L ratio. The white area indicates the area
at which the model has been proven to be maximum 10% error.
The grey area designates extrapolated (unverified) results from the
model. The analysis was done at a constant benzene preloading of
138 ppm
The removal of
BTEX components
using a desorption
column in combination with conditioned associated stripping
gas was shown to be an excellent process in
the context of an oil producing field.
Wintershall’s patent- pending continuous
process can recover the aromatic and
aliphatic hydrocarbons in a single process
step; by adding this to the oil, production is
enhanced. Furthermore, using this novel
process averts usage of foreign material such
as adsorbents or nitrogen, thereby avoiding
the need for waste disposal. By raising the
temperature of the column, the gas/liquid ratio can be minimized in order to increase
effectivity and energy efficiency of the
entire plant.
References
[1] Koo, D. (2012), ‘Assessment and Calculation of
BTEX Permeation through HDPE Water Pipe’,
Plastics Pipe Institute.
[2] Goodwin, R.D (1988), ‘Benzene Thermophysical
Properties from 279 K to 900 K at Pressures to
1000 bar’, J. Phys. Chem. Ref. Data, Vol. 17, No.
4, p. 1541–1636.
Mark Valkenier grew up in The
Netherlands, where he studied
Mechanical Engineering at
Delft University of Technology,
obtaining a masters degree
with honors in 2014. Since
then, he works as a Project Engineer in the graduate program
of Wintershall Holding GmbH.
Georg Hinners is Head of Facilities Engineering with Wintershall Holding GmbH and responsible for all own operated
German O&G surface facilities.
He holds a Dipl.-Ing. degree in
Mechanical Engineering from
the Technical University of
Hannover in Germany. Georg works for Wintershall
since 1981 in all kind of planning and constructing
process facilities for oil and gas production.
Gerhard Themann studied Mechanical Engineering at the
Fachhochschule Osnabrück in
Germany, obtaining a Dipl.Ing. degree in 1995. Gerhard
has more than 20 years of experience in Facilities engineering. Since 2010 he works as a
Project Engineer for Wintershall Holding GmbH .
OG 201
OIL PRODUCTION
Analyses of Operating Electric Submersible
Pumps (ESPs) of Different Manufacturers –
Case Study: Western Siberia
By A. SUKHANOV, M. AMRO and B. ABRAMOVICH*
Abstract
These analyses were performed to investigate the efficiency of operating electric submersible pumps (ESPs) an oil field in Western Siberia. This field is considered to be
one of the most difficult in this region, as the
reservoir temperature in some areas reaches
anomalous values, and the amount of solid
particles in the majority of wells exceeds the
allowable value of 100 mg/l by 5–8 times.
The article shows the main causes of failure
of both ESP “X” and ESP “Z” of two different manufacturers. It considers the experience in almost 600 wells. The key efficiency
indicator of the ESP is measured by the turnaround time (TAT). In our case the TAT of
ESP “X” exceeds that of ESP “Z” by almost
3.5 times. Economically, it is estimated that
after the second failure of ESP “Z”, the costs
for workover operations, subsequent repairs
and washing out the wells already exceed the
costs of ESP “X”. Therefore, despite the high
purchase costs for ESP “X”, its further usage can achieve additional production of hydrocarbons in this oil field.
These analyses have been conducted together with the Institute of Drilling Engineering and Fluid Mining at the TU Bergakademie Freiberg.
cludes above-ground and underground
equipment.
Above-ground equipment: The transformer
converts the voltage up to the optimum values needed for ESP. The switchboard allows
manual or automatic switching on and off of
the ESP during target program. The junction
box is necessary for the connection of the cable line from the switchboard to the ESP. The
X-mas tree consists of various gate valves
and control elements. For control of the fluid
regime from the borehole a flow choke is in-
stalled in the manifold. The electrical cable
line carries the electric current from the surface to the electromotor of ESP (Fig. 1).
Underground equipment: The ESP consists
of a multi-stage centrifugal pump, pump intake, protector und submerged electromotor.
The electric motor drives the pump, whereby
liquid is raised to the surface through the
pipework. Also, a gas separator can be included additionally in the ESP. For monitoring the condition of ESP a telemetry system
is installed to determine temperature, pres-
1 Introduction
ESP usage remains one of the most advanced methods worldwide in the production of crude oil. In the case of ESP failure,
the costs for workover operations and subsequent repairs are nearly equal to the costs for
new equipment. For this reason, the choice
of quality equipment is very relevant for the
oil companies. The main criteria for selecting an ESP are price, availability of the necessary spare parts and high turnaround time
(TAT) of ESP operations.
ESP contains a chain of sequentially interconnected mechanisms operating in one system. Therefore, a failure of at least one of the
mechanisms leads to failure of the whole
system. The electric submersible pump in* M.Sc. Alexander Sukhanov, Prof. Dr.-Ing. Mohd Amro, TU
Freiberg, Germany; Prof. Boris Abramovich, Mining University St. Petersburg, St. Petersburg, Russia (E-mail:
[email protected], [email protected]).
0179-3187/15/IV
OG 202
Fig. 1
Well construction equipped with ESP
OIL PRODUCTION
sure and vibration.
The data from the telemetry system is
transferred through
the electrical cable
line to the electrical
panel of the switchboard in real time.
The float valve prevents a liquid flow
through the centrifugal pump back to the
wellbore in the event
that the ESP is
switched off. The Fig. 2 Turnaround time of ESPs 2011–2013
overflow valve is
necessary remove liquid from the pipework After a thorough analysis of all the wells
when the ESP is pulled out of the hole.
equipped with ESP over three years, we can
clearly see that the TAT of ESP “X” is much
higher than others. For example, the TAT of
2 Formation Characteristics
ESP “X” in 2011 and 2012 is almost four
The task was to investigate the efficiency of times higher than that of ESP “Z”. In 2013, it
operating the ESPs of two manufacturers exceeded ESP “Z” by almost 3.5 times. The
[1]. Due to its geological characteristics, the constructional features and the quality of
oil field is considered to be one of the most some of the manufacturing components of
difficult in this region, as reservoir tempera- the ESP, as well as their ability to work over a
tures reach anomalous values (150 °C) in wide range of downhole conditions can exsome areas and as the amount of solid parti- plain such a high TAT.
cles in the majority of the wells is 5–8 times The TAT decreases over the three years,
higher than the allowed value of 100 mg/l.
which can be explained by the aging of the
Pay formations in this oil field occur at equipment in the wellbore, whereby partial
depths of 2369 to 2409 m and are character- accumulation of salts in the working pump
ized by frequent alternation of sandstones, stages occurred and the high concentration
siltstones and argillite with clay layers. The of solids particles in the well fluid led to information thickness varies from 22 to 39 m. tense wear of the working pump stages and
The average porosity of the oil field reaches bearings. This is mainly due to running the
17.5% and the permeability is 14 x 10–3 µm2.
pump immediately after frac stimulation.
3 Turnaround Time (TAT) of
ESPs
The key efficiency indicator of the ESP is
the turnaround time (TAT). The TAT describes the non-stop operation of the ESP
between two workover operations of the
well, from the beginning of the first start until the stop for replacement. Figure 2 shows
the development of TAT of ESPs over time.
Fig. 3
4 Causes of Failure of ESP
Figure 3 represents the causes and their percentages of failure in this oil field.
The main reasons for failure are presented in
more detail below.
4.1 Impacts of saline deposits on the
ESP operation
The analysis shows that the main reason for
failure of ESP “X” was in more than 50% of
cases the accumulation of salts in the working pump stages followed by workover. In
comparison this factor for ESP “Z” reached
only 30%.
Such a high tendency can be explained only
by smaller size flow areas in the pump stages
of ESP “X”. Salt manifestations occur due to
overheating of the water present in the well
fluid. Overheated water can be explained by
undersupply of fluid; this means the inflow
into the borehole is less than the ESP is able
to pump.
The second reason for salt forming is the
mixing of reservoir water with water, which
is pumped to maintain reservoir pressure or
to kill the well using a different chemical
composition. Salt crystals are deposited not
only on the pump stages, but also on the
outer surface of the ESP, which impairs the
heat transfer and sometimes leads to
jamming in the production casing.
4.2 High concentration of solid
particles
About 20% of ESP failures from ESPs of
both manufacturers occurred due to high
concentration of solid particles. When the
concentration of solids in the well fluid exceeds the allowed norm, the lifespan of the
pump is significantly reduced. Furthermore,
high wear on impellers, diffusers in the inner
diameter, shaft sleeves, sleeves of the upper
and lower bearings, heel units and textolite
grooves occurs, which leads to increased
shaft vibration and premature failure of the
ESP. The reason for the occurrence of solid
particles can not only be the natural process
of destruction of the formation, but also the
recovery methods as well as stimulation
methods. When starting the ESP, a sharp decline in the bottom hole pressure occurs,
which e. .g contributes to removing frac
proppant with the well fluid from the reservoir. The sharp drop of bottom hole pressure
is also possible e. g. in low-density perforations.
Causes of ESP failure
OG 203
OIL PRODUCTION
4.3 Electrical breakdown of stator
winding of electromotor
Increased vibration of the pump shaft and
the rotor of the electromotor causes entering
of well fluid through the end seals into the
protector inside the electromotor. This leads
to an electrical breakdown of the stator
winding. During a short circuit, the pressure
in the electromotor abruptly rises causing
thereby a break of the diaphragm protector.
The failure rate due to this reason was about
5% for ESP “Z”, for ESP “X” it does not exceed 2%. Protectors of all manufacturers
have the same functions, with the exception
of minor structural differences. Protectors of
ESP “X” have not two, but three end seals
and diaphragms made of a material which
can withstand temperatures as high as
204 °C.
4.4 Insufficient flow of fluid to the
ESP
This phenomenon leads to a decrease of dynamic fluid levels in the well and to a reduction of the pressure at the pump intake. This
occurs when the gas enters into the pump in
two ways: either from the annular of the well
through the pump intake or from dissolved
gas which is released from the well fluid appearing when the pressure inside the pump is
below the saturation pressure. As a result,
pump starvation occurs and leads to a decrease in the current to a value close to the
idling current of the electromotor. The pressure drop across the pump causes closing of
the float valve and the pump begins to operate in a mode called “dry friction” resulting
in intense heat and increased wear of working components of the pump. This causes
8% of all ESP failures for both manufacturers.
4.5 Melting insulation extension cable
The reliability of extension cable depends
primarily on the thermal resistance of insulation material, as well as the ability to work
in a certain temperature range. Therefore,
not only the high bottom hole temperature,
but also the heat from the pump and the electromotor have an adverse effect on the longevity of the extension cable. Extension cables of ESP “Z” are able to withstand temperatures up to 120 °C, while the extension
cables of ESP “X” are designed for temperatures up to 204 °C. This cause of failure was
detected for ESP “Z” only. Its quote reaches
15%.
OG 204
4.6 ESP work in periodical duty
Periodic regime means the operation of
ESPs is not constant, but with frequent
stops. The frequency of starts and stops is
depending on the inflow of well fluid. For
example: 3hours pumping fluid, 8 hours restoring of static fluid level. Operating ESP in
this mode leads to premature failure of the
electromotor due to electrical breakdown of
the stator winding, as it is designed for
190–230 runs only. Periodic mode is used
only on ESP “Z”, which caused 6% failures.
Moreover, at the present time variable speed
drives (VSDs) are widely used which allow
avoiding periodical operation of ESP by
pumping well fluid in accordance with the
dynamic level of the well. VSD also provides a smooth start of the ESP, which prolongs the life of the electromotor. With the
invention of VSD, the task of selecting the
pump size has become much simpler. If the
rotation speed of the pump shaft changes for
example, it is possible to adjust ESPs to different inflow of crude oil from the formation, regardless of the number of pump
stages in the pump.
Other reasons for the failures, such as mechanical damage of electrical cable, pipework leakage, poor quality repair of the protector or the electromotor are indirect
causes, but also lead to failure of ESP.
5 Summary and Conclusions
On the basis of the performed analyses it can
be concluded that the usage of ESP “X” is
more favorable. TAT from ESP “X” exceeds
ESP “Z” by several times. Economically, it
is estimated that after the second failure of
the ESP “Z”, the cost of workover operations, subsequent repairs and washing out
the wells, are higher than the purchase costs
of ESP “X”. Despite the high costs of ESP
“X” (almost three times compared to ESP
“Z”) it is advisable to use this ESP to provide
additional production of crude oil in this oil
field.
References
[1] A. Sukhanov: Erhöhung des Reparaturintervalls
von Elektrotauchkreiselpumpen durch den
Einsatz gleichartiger Pumpen verschiedener
Anbieter in der Lagerstätte Prirazlomnoje.
Diplomarbeit, TU Bergakademie Freiberg, Sept.
2011.
Alexander Sukhanov, a PhD
student, received MSc degrees
from Tyumen State Oil and Gas
University Russia in 2003 and
from Freiberg University of
Mining and Technology, Germany in 2012. From 2003 to
2009 he worked with Schlumberger Logelco Inc. and Halliburton International Inc.
in Russia as an ESP field engineer and later as L/MWD
engineer. From 2012 to 2015 he was employed as an
Assistance Rig Manager at DrillTec GUT Ltd Company
and as Directional Drilling Engineer at Halliburton
Company Germany GmbH.
Mohammed M. Amro is currently Professor and Chair of
Reservoir, Production and Storage Engineering at Technical
University Bergakademie Freiberg in Germany. From 1999 to
2009 he was a faculty member
in the petroleum and natural
gas engineering department of King Saud University,
Riyadh. Previously, he worked at the German Petroleum Institute in Clausthal, Germany, and for Qatar
Drilling Co. in Qatar. Prof. Amro holds a BS, an MS
and a PhD in petroleum engineering from The Technical University of Clausthal in Germany. He is a member of Society of Petroleum Engineers (SPE) and German Society for Petroleum and Coal Science and
Technology (DGMK), Germany.
Boris N. Abramovich is currently Professor of Electrical
Energetics and Electromechanics Department at National Mineral Resources University (Mining University),
Saint Petersburg, Russian Federation. He received his PhD
degree in electrical engineering and his Dr.Tech. degree in electrical engineering from Leningrad Mining
Institute, Leningrad, Soviet Union, in 1971 and 1986
respectively. Since 1986, he has been a professor in
Leningrad Mining Institute, Leningrad, Soviet Union
and later in National Mineral Resources University
(Mining University), Saint Petersburg, Russian Federation. His research area covers the wide range of
power quality and electromagnetic compatibility
problems, power supply and consumption optimization problems, power supply reliability ensuring
problems, distributed generation problems. He is the
honorary figure of Russian higher education. He is a
full member of Russian natural science academy,
Russian mining science academy, International energy academy (Russia), International academy of
ecology, human and nature safety (Russia).
PRODUCTION
Improvement of Oil Production Rate Using
the TOPSIS and VIKOR Computer
Mathematical Models
By M. ALEMI, M. KALBASI, F. RASHIDI*
Abstract
Technique for Order Preference by Similarity to Ideal Solution (TOPSIS) and VIšekriterijumsko KOmpromisno Rangiranje
(VIKOR) are two important Multi Criteria
Decison Making (MCDM) methods, which
can be applied to facilitate selection among
a limited number of criteria to be processed.
Artificial lift is defined as any system increasing energy to the fluid column in a
wellbore with the aim of improving the production rate.
In this article, a novel software computer
method (by means of Visual Basic.net Coding) based on the two TOPSIS and VIKOR
mathematical models is presented for artificial lift selection in oil production, validated
with several specific oil field data to show a
good match between the two TOPSIS and
VIKOR models program final results and the
fields’ operational results. The application
of these models on the basis of MCDM scientific methods can perform the best artificial
lift method selection under the oil field circumstances.
As a comparison, the programs of TOPSIS
and VIKOR models artificial lift selection
were applied to an HP (Hydraulic Pump)
and GL (Gas Lift) respectively for an example oil field. Of course, it should be mentioned that as shown in this paper, we have
used the field data available in table 1, but
for more accuracy in results, we have also
privately used more input data of other fields
such as table 2 etc. Since the TOPSIS model
program results are closer to the field data
for artificial lift selection, as compared with
the results using the VIKOR model, then
TOPSIS is a better MCDM model for artificial lift selection.
1 Introduction
Any system adding energy to the fluid column in a wellbore to enhance production
from the well is called an Artificial Lift. Ma* Mehrdad Alemi, Department of Petroleum Engineering,
Amirkabir University of Technology, Tehran, Iran; Mansour
Kalbasi, Fariborz Rashidi, Department of Petroleum Engineering, Amirkabir University of Technology, Tehran, Iran,
Department of Chemical Engineering, Amirkabir University
of Technology, Tehran, Iran (E-mail: mkalbasi2000@jahoo.
com, [email protected]).
0179-3187/15/4
jor types of Artificial Lift are Gas Lift (GL)
design (Continuous Gas Lift, Intermittent
Gas Lift) and Pumping (Electrical Submersible Pump (ESP), Progressive Cavity Pump
(PCP), Sucker Rod Pump (SRP), Hydraulic
jet type Pump (HP)).
When a reservoir lacks sufficient energy for
oil, gas and water to flow from the wells at
desired rates, supplemental production
methods can help.
It may be economical at any point in the life
of a well to maintain or even to increase the
production rate by the use of Artificial Lift
to offset the dissipation of reservoir energy.
MCDM (Multi Criteria Decision Making)
refers to making decisions in the presence of
multiple, usually conflicting criteria. The
problems of MCDM can be broadly classified into two categories: Multiple Attribute
Decision Making (MADM) and Multiple
Objective Decision Making (MODM), depending on whether the problem is a selection problem or a design problem.
By now, the percentage usage of GL, ESP,
SRP, PCP and HP Artificial Lift methods
throughout the world amounts to 50%, 30%,
17%, >2% and <2% respectively.
Regarding earlier artificial lift selection procedures some researchers studied the following:
In (1981), Neely considered the geographical and environmental circumstances as the
dominant factors for Artificial Lift
Selection.
In (1988), Valentine used Optimal Pumping
Unit Search (OPUS), a smart integrated system possessing the characteristics of artificial lift methods, for artificial lift selection.
In (1993), Bucaram and Clegg studied on
some of the operational and designing factors based on artificial lift methods overall
capability comparison and design.
In (1994), Espin used SEDLA, a computer
program possessing the characteristics of artificial lift methods, for artificial lift selection.
In (1995), Heinze used the Decision Tree for
artificial lift selection, mostly based on a
longtime economic analysis.
The objective of the article is to compare and
to discuss the two TOPSIS and VIKOR
mathematical models as appropriate methods for artificial lift selection.
2 Materials and Methods
The usage of Artificial Lift methods
throughout the world has been recently reported by Weatherford Corp. Up to now the
percent usage of each of the artificial lift
methods throughout the world i. e. GL, ESP,
SRP, PCP and HP, as different artificial lift
methods amounts to 50%, 30%, 17%, >2%
and <2% respectively.
2.1 Some engineering applications of
TOPSIS and VIKOR models used up to
now
– Application of TOPSIS model as a data
classifier, the proposed model could provide additional efficient tool for comparative analysis of data sets. TOPSIS model
has been applied in Multiple Criteria Decision Analysis based on D.Wu’s data mining model. It has been applied in supply
chain complexity evaluation and simulation has been used to validate the proposed
model [1].
– Application of TOPSIS model as a new
model for mining method selection of
mineral deposit based on Fuzzy Decision
Making, the Fuzzy Decision Making
(FDM) software tool has been employed to
develop a Fuzzy TOPSIS based model.
Application of this model with various values (crisp, linguistic and fuzzy) of the deposit eliminated the existing disadvantages of other methods [2].
– Application of TOPSIS model in initial
training aircraft evaluation under a fuzzy
environment, the study has applied the
fuzzy MCDM method to determine the
weights of evaluation criteria and to synthesize the ratings of candidate aircraft.
Aggregated the evaluators’attitude toward
preference; then TOPSIS has been employed to obtain a crisp overall performance value for each alternative to make a
final decision [3].
– Application of TOPSIS model as a multi
criteria decision analysis of alternative
fuel buses for public transportation, the result has shown that the hybrid electric bus
has been the most suitable substitute bus
for Taiwan urban areas in the short and median term. But, if the cruising distance of
the electric bus extends to an acceptable
range, the pure electric bus could be the
best alternative [4].
OG 205
PRODUCTION
– A study attempts to present a method for
differentiating between multi-attribute decision procedures and to identify some
competent procedures for major decision
problems, where a matrix of alternative-measure of effectiveness and a vector
of weights for the latter are available. This
is done from an engineering viewpoint and
in the context of a transportation problem,
using a real case light rail transit network
choice problem for the City of Mashhad,
and the results are presented. Two concepts have been proposed in this respect
and used in this evaluation; peer evaluation and information evaluation, which are
investigated in this study [5].
– Application of VIKOR model as a Multi
Criteria Decision Analysis of alternative
fuel buses for public transportation, the result has shown that the hybrid electric bus
has been the most suitable substitute bus
for Taiwan urban areas in the short and median term. But, if the cruising distance of
the electric bus extends to an acceptable
range, the pure electric bus could be the
best alternative [4].
– The application of VIKOR model for the
selection of suppliers based on Rough Set
Theory and VIKOR algorithm, the proposed methodology consisted of two parts:
1) The RST was a fairly new methodology
developed for dealing with imprecise, uncertain, and vague information. 2) According to index systems for selection of
suppliers, VIKOR algorithm has been
used to select the best suppliers [6].
– Among popular MCDM methods, VIKOR
(Vlsekriterijumska
Optimizacija
I
KOmpromisno Resenje) has attracted
much attention to cope with complex
problems with conflict factors. The current study conducted a state-of-the-art literature review to embody the research on
VIKOR and its applications. The study
structure consists of nine categories: 1) design and manufacturing management, 2)
business and marketing management, 3)
supply chain and logistics management, 4)
environmental resources and energy management, 5) construction management, 6)
education management, 7) healthcare and
risk management, 8) tourism management, and 9) other topics. the last topic
contains information and knowledge
management, mine industry, etc [7].
3 TOPSIS/VIKOR Based Selection
In this article, a novel software computer
method based on the two TOPSIS and
VIKOR models has been presented for Artificial Lift selection in oil industry. It was essential to mention to the mathematical and
OG 206
3.1 TOPSIS model
The TOPSIS model was developed by
Hwang and Yoon [8]. This model is based on
the concept that the chosen alternative
should have the shortest Euclidean distance
Table 1
Example oil field input data
Condition
Example oil field
input data
(the designed program
default input data)
Number of wells
Production rate
Well depth
Casing size
from above: artificial lift methods designation; production, reservoir and well
constraints; produced fluid properties;
surface infrastructure constraints; and finally results by TOPSIS or VIKOR programs respectively
5
26000ssSTB
4500ssft
7"
Well inclination
Deviated
Dogleg severity
3–10 per feet
Temperature
Safety barriers
180–210ssF
2
Flowing pressure
100–1000 psi
Reservoir access
Required
Completion
Stability
Dual
Stable
Recovery
Secondary waterflood
Water cut
40%
Fluid viscosity
Corrosive fluid
Sand and abrasives
GOR
Less than 100 cp
No
Less than 10 ppm
450
VLR
Less than 0.1
Contaminants
Treatment
⇐
Fig. 1
logical strategy and calculations of these
models.
The designed program of artificial lift selection is shown in Figure 1.
Here we have used the same values of a selected oil field input data to determine the
TOPSIS and VIKOR results, because we
should enter constant input data of a selected
oil field to the software for the two models to
check their different results with each other
and compare with that field operationally
selected artificial lift method.
It should be noted that these two models
have the same input data and the resulted
weights of the alternatives relative to the criteria all quantities (both calculated by Entropy method) but different other strategies
and formulas for artificial lift selection and
consequently different final results.
From the two models, that software model
which has the same result as the field
data/result is the software model with more
accuracy. Of course, it should be mentioned
that as shown here, we have used the field
data available in Table 1, but for more accuracy in results, we have also privately used
more input data of other fields (Table 2).
Scale
Acid
Location
Onshore
Electrical power
Space restriction
Well service
Utility
No
Wireline
PRODUCTION
ties matrix (decision making matrix) respectively [10].
The relative scores of different methods relative to Production, Reservoir and Well constraints as well as Produced fluid properties
and Surface infrastructure constraints (all
the criteria) have been based on the
Schlumberger Company certain practical reports (Fig. 2), (Schlumberger Com.).
The value of 1 (good to excellent) has been
considered as 7 out of 10, the value of 2 (fair
to good) has been considered as 5 out of 10
and the value of 3 (not recommended and
poor) has been considered as 3 out of 10 in
the following.
Then, the normalizing of the resulted alternatives relative to the criteria quantities
matrix had to be done by equation (1), [10]:
V ij
(1)
nij =
m
Fig. 2
∑V
The alternatives versus the criteria for artificial lift selection (Schlumberger Com.)
from the ideal solution, and the farthest from
the negative ideal solution [8, 9].
The ideal solution is a hypothetical solution
for which all alternatives relative to criteria
attribute values (V ij ) correspond to the maximum attribute values in the database comprising the satisfying solutions; the negative
ideal solution is the hypothetical solution for
which alternatives relative to criteria attribute values (V ij ) correspond to the minimum
attribute values in the database.
i=1
The main procedure of TOPSIS model for
the selection of the best alternative from
among those available has been described as
below:
At first, it was required to allocate suitable
quantities (V ij ) scaled from 0 through 10 for
the alternative relative to the criteria qualities, (higher each of their qualities, more its
value out of 10), the number of the alternatives and the number of the criteria have
been considered as the number of matrix
rows (i) and matrix
Table 2
Examples for oil field input data (privately done)
columns (j) in the alternatives relative to
Condition
Salman Field
Nosrat Field
the criteria quantiProduction, Reservoir and Well constraints
Number of wells
50
Production rate
56000 STB
Well depth
8000–11,000 ft
Casing size
9 5/8"
Well inclination
All of cases
Dogleg severity
0–10 per feet
Temperature
180–210 F
Safety barriers
1
Flowing pressure
Greater than 1000 psi
Reservoir access
Required
Completion
Simple
Stability
variable
Recovery
Secondary waterflood
Produced-Fluid Properties
Water cut
Fluid viscosity
Corrosive fluid
Sand and abrasives
GOR
VLR
Contaminants
Treatment
Surface Infrastructure
Location
Electrical power
Fuel
Space restriction
SCADA
Well service
Then, the criteria quantities had to be
weighted by means of the Entropy method,
by equations (2) through (5), (Fig. 3), [10].
aij
(2)
Pij = m
a
∑ ij
i=1
(3)
d j = 1 − Ej
m
[
E j = − k ∑ pij Lnpij
d j i=1
Wj n
∑dj
]
(4)
(5)
j=1
where
m number of decision making matrix rows
6
4200 STB
7000–9000 ft
9 5/8"
All of cases
0–10 per feet
150–180 F
1
100–1000 psi
Required
Simple
variable
Primary
70%
Less than 100 cp
No
Less than 10 ppm
650
Less than 0.1
Scale
Acid
65%
Less than 100 cp
No
Less than 10 ppm
350
Less than 0.1
Scale
Acid
Offshore
Utility
Natural gas
Yes
No
Pulling unit
Offshore
Utility
Natural gas
No
Yes
Pulling unit
2
ij
Fig. 3
The resulted weights of the alternatives relative to the criteria all
quantities
OG 207
PRODUCTION
Fig. 5
Fig. 4
Above: The resulted separation of each alternative from the positive
ideal given by the Euclidean distance, e. g. HP is closest to the positive ideal; below: The resulted separation of each alternative from
the negative ideal given by the Euclidean distance, e. g. HP is farthest from the negative ideal
aij decision making matrix values
Pij decision making matrix values related to the sum
values of all matrix rows in each matrix column
dj uncertainty value
Ej entropy value
k 1/Ln(m)
Wij weighted criteria quantities.
The relative closeness of a particular
alternative to the
ideal solution could
be expressed in this
step as follows:
Multiplying the normalized matrix by the alternatives relative to the criteria resulted
weights diametrical matrix, the normalized
weighted matrix has been obtained [10].
Then, the positive ideal (best) and the negative ideal (worst) of each criterion had to be
obtained in this step [10].
Pi =
V
+
The highest value for as the best alternative for selection
min
⎧ max
⎫
= ⎨ ∑V ij / j ∈ J , ∑V ij / j ∈ J ' ⎬
i
⎩ i
⎭
= {V 1+ ,V 2+ ,V 3+ ,...V M+ }
max
⎧ min
⎫
V − = ⎨ ∑V ij / j ∈ J , ∑V ij / j ∈ J ' ⎬
i
⎩ i
⎭
= {V 1− ,V 2− ,V 3− ,...V M− }
(6)
(7)
i = 1, 2,..., N
where
J
(j =1, 2, …
, M)/j is associated with beneficial attributes
J’ (j =1, 2, …
, M)/j is associated with non-beneficial
attributes.
The separation of each alternative from the
ideal one has been given by the Euclidean
distance in the following equations (Fig. 4),
[10].
0 .5
⎧M
+
+ 2⎫
(8)
S i = ⎨ ∑ (V ij − V j ) ⎬
⎩ j=1
⎭
0 .5
⎧M
−
− 2⎫
(9)
S i = ⎨ ∑ (V ij − V j ) ⎬
⎩ j=1
⎭
i = 1, 2,..., N
OG 208
S i+
(10)
S + S i−
The highest value for
Pi has shown the best
alternative for selection (Fig. 5), [10].
On the whole, it
should be stated that Fig. 6 The resulted weights of the alternatives relative to the criteria all
quantities
the results vary with
regards to different
oil field parameters.
MCDM problems with conflicting (different
The TOPSIS and VIKOR models have some units) criteria, assuming that compromising
similarities and also some differences in is acceptable for conflict resolution, the determs of their mathematical equations and cision maker wants a solution that is the
results for artificial lift selection. As well, closest to the ideal, and the alternatives are
the VIKOR model is included and worked in evaluated according to all established critethe TOPSIS paper for determining the re- ria. This model focuses on ranking and sesulted normalized matrix weights by means lecting from a set of alternatives in the presof the Entropy method.
ence of conflicting criteria, and on proposing compromise solution [10].
According to the mentioned introductory
3.2 VIKOR model
notes in TOPSIS model, we have prepared
The foundation for Compromise Solution the decision making matrix for the rest of the
was established by Yu [11] and Zeleny [12] specific strategy of this VIKOR model.
and later advocated by Opricovic and Tzeng Now, the resulted normalized matrix had to
[13, 14]. The Compromise Solution is a fea- be weighted by means of a specific mathesible solution that is the closest to the ideal matical method such as the Entropy method
solution, and a Compromise means an (the weights calculation method is the same
agreement established by mutual conces- as TOPSIS model), (Fig. 6), [10].
sion. The Compromise Solution Method, The process of calculating and selecting the
also known as the VIKOR (Višekriteri- TOPSIS and VIKOR weights of the alternajumsko KOmpromisno Rangiranje) model, tives relative to the criteria all quantities
was introduced as one applicable technique (Figs. 3 and 6) is the same.
to implement within MADM [8, 9].
Then the following Ei , Fi, Pi parameters had
The VIKOR model was developed to solve to be calculated (Figs. 7, 8).
+
i
PRODUCTION
Fig. 8
Artificial lift selection graph for VIKOR model
artificial lift selection operational results and finally, a
considerable accordance between
this designed model
program final results and the fields
operational results
Fig. 7 The resulted alternatives Ei (above) and alternatives Fi values
(below)
has been found.
3. These two TOPSIS
and VIKOR mathematical models have
M
been known as proper computerized modEi = ∑W j (V ij ) max − V ij / (V ij ) max − (V ij ) min
j=1
els for the improvement of oil production
(11)
rate and artificial lift selection in oil industry.
4. As a comparison, the program of TOPSIS
Fi = Max m of
and VI- KOR models artificial lift selection results have been the application of
{W j (V ij ) max − V ij / (V ij ) max − (V ij ) min |
HP (Hydraulic Pump) and GL (Gas Lift)
i = 1,2,...,m }
(12)
for an example oil field data respectively.
( Ei − Ei − min )
As examined with the data from Tables 1
+
Pi = v
and 2, the TOPSIS model results are
E
−
E
( i − max i − min )
closer to the field data for artificial lift se(13)
( Fi − Fi − min )
lection, so compared to the VIKOR
(1 − v )
model, TOPSIS is a better MCDM model
( Fi − max − Fi − min )
for artificial lift selection.
Where i, j are the number of (rows) alternatives and (columns) criteria in the matrix respectively. (Vij) is related to the alternatives It is considerable to thank to the Petroleum/Chemical
relative to the criteria all quantities matrix Engineering Department of Amirkabir University of
values. (W j) is related to the alternatives rel- Technology, Tehran, Iran backing up to study on this sciative to the criteria all quantities matrix entific matter.
weights. v is introduced as the weight of the
majority of attributes strategy. Usually, the
value of v is taken as 0.5. However, v can References
[1] Jiang, W., Zhong, X., Chen, K., Zhang, S.: Fourth
take any value from 0 to 1.
International Conference on Fuzzy Systems and
The alternative with the lowest P i value has
Knowledge Discovery, 2007.
been considered the best alternative (Fig. 8).
[2] Samimi Namin, F., Shahriar, K., Ataeepour, M.,
[
[
][
][
]
]
4 Conclusions
1. In this article, a novel computer method
(by means of Visual Basic.net Code)
based on the two TOPSIS and VIKOR
models has been presented for Artificial
Lift Selection in oil industry.
2. The designed novel software computer
program based on the two models presented for artificial lift selection has been
validated with several certain oil fields
[7] Yazdani, M., Felipe, R. VIKOR and its Applications: A State-of-the-Art Survey. International
Journal of Strategic Decision Sciences 2014.
[8] Hwang, C. L., Yoon, K.: Multiple Attribute Decision Making: a state of the art survey. Springer
Verlag, 1981.
[9] Pimerol, J. C., Romero, S. B.: Multi Criteria Decision in management: Principles and practice.
Kluwer Academic Publishers, 2000.
[10] Rao, R. V.: Decision making in the manufacturing
environment: Using Graph Theory and Fuzzy
Multiple Attribute Decision Making methods.
Springer Verlag, 2007.
[3]
[4]
[5]
[6]
Dehghani, H.: The Journal of the Southern African Institute of Mining and Metallurgy, 2008.
Wang, T. C., Chang, T. H.: International Journal
on Expert Systems with Applications, Volume
33, Pages 870–880, 2007.
Tzeng, G. H., Lin, C. W., Opricovic, S.: Energy
Policy 33, 1373–1383, 2005.
Poorzahedy, H. Rezaei, A.: Peer evaluation of
multi-attribute analysis techniques: Case of a
light rail transit network choice, 2013.
Guo, J., Zhang, W.: Selection of suppliers based
on Rough Set Theory and VIKOR algorithm. International Symposium on Intelligent Information Technology Application Workshops, 2008.
M. Alemi is a Ph.D. student at
the Petroleum Reservoir Engineering Department, Amirkabir
University of Technology, Tehran, Iran.
M. Kalbasi is Professor in the
Chemical Engineering Department, Amirkabir University of
Technology, Tehran, Iran. He
optained his Ph.D. from Bradford University, England.
Fariborz Rashidi is Professor
of Chemical Engineering at
the Amirkabir University of
Technology, Tehran, Iran. He
received a Ph.D. In Chemical
Engineering from Imperial College of Science and Technology, London, England.
OG 209
OIL PRODUCTION
By A. ZICH, K. S. VEREVKIN, and D. A. SOZAEVA*
Abstract
This article reviews the project for the development (exploration) of oil and gas fields,
within which it becomes possible to implement additional projects capable of increasing the debit of oil wells. A key problem with
the implementation of such innovations in
the life cycle of the project is the complexity
of calculating the efficiency of implementing
innovations arising from the evaluation of
the project by classical methods. Therefore,
in this article, to improve the efficiency of
managerial decision-making at the management level of companies, it is proposed to
evaluate the investment attractiveness of the
project by the method of “real options”, in
addition to the classical methods of assessment.
Introduction
Energy objects are characterized by longterm investment period (20, 30, 40 years are
normal deadlines for the implementation of
projects). In an increasingly uncertain and
dynamic global market, classic methods of
evaluation such as NPV (Net present value)
do not allow full assessment of the profitability of a project. In this context, alternative methods for calculating project efficiency come to the fore. Such calculation
methods allow effective response to technological changes or competitive moves, or otherwise limit the losses from adverse market
movements. One of these methods is “real options”.
The study of the theory of “real options” is
carried out both in Germany and abroad.
There are studies in Russia, in the field of oil
and gas exploration and investment attractiveness of hydrocarbon raw materials, which
obtained widespread recognition. The companies, which use the real options method,
have high-level capitalizations (see Table 1).
For example, BP has achieved growth of capitalization of the company from 18 to 30 billion dollars. (i. e. +167%) for the period 1990
to C 1996. According to the company managers, this result was achieved through strategic
thinking and in addition, due to the method of
“real options”. [1]
In this article, we will try to develop an alter* Dr.-Ing. A. Zich, Energy Scientist, Dresden, Germany
(E-mail: [email protected]); K. S. Verevkin, CNIS
Gazprom, Moscow, Russia; D. A. Sozaeva, Research Support Center of SUM, State University of Management, Moscow, Russia.
0179-3187/15/IV
OG 210
native approach to assess the investment attractiveness of a project and evaluate the applicability of the method of “real options” in
the stage of extraction, within the project of
oil fields development.
New Possibilities during the
Life Cycle of a Project
To achieve the objectives scientific methods
of research such as analysis, synthesis,
mathematical, statistical and expert methods
of estimation were used.
The field development is known to be a long
process, which can reach 40-50 years. The
stages of a field development are:
1. Opening of the field
2. Evaluation of the field
3. Preparations for development
4. Extraction of mineral resources
5. Elimination/Preservation of wells.
Extraction of mineral resources is the longest stage. During the initial assessment, it is
not always possible to estimate reserves for
the implementation of innovative technologies to optimize production, because at the
stage of opening and evaluation of fields,
such technologies simply may not exist. Not
only do the technologies improve, but also
project data can suggest better organizational approaches as we showed in [2].
However, at a certain stage of the life cycle
of a project, by virtue of scientific and technological progress, the possibility of introducing additional innovative solutions
(changes) is usually provided. Such
changes, for example, may be implemented
in the project due to the new technologies
like e. g. the so called “Intelligent accompaniment of drilling operations” developed by
Schlumberger company.
The technology allows in real time to obtain
the necessary data on the structure of a reservoir, to make optimal decisions for wiring
and construction of boreholes, as well as to
seek opening deposits of smaller numbers of
well and horizontal sections [3].
The ability to implement such technology
within the exploitation phase (for e. g., by
10–12 years of production) creates the need
for change management in the project and
along with the positive effects, provokes additional risks. Thus, the management of the
company will have to answer the following
questions:
1. At whose expense will changes in the financing of the project be carried out;
2. Will the terms of the project be observed –
it is necessary to consider, if any implementation of additional project within the
main project will move the project’s
timeline;
3. Are there risks due to sharp increase in
production and consequently, the risks associated with sales?
Methodology for Evaluating
Projects
In order to provide for situations with possible implementation of innovative and rationalized solutions in existing long-term projects, to financially evaluate implications of
adopting certain management decisions related to the implementation of such changes,
it is necessary to develop a methodology for
evaluating projects and to allow in the project, provisions for making management
decisions.
One tool that allows you to reserve the right
to make management decisions in long-term
projects in the field of oil and gas production
is “real options”. Real Options is a method
of evaluating the investment attractiveness
of projects. This method appeared in the second half of the 20th century. Two basic models are used to evaluate projects by real options: Black-Scholes and binominal model
[4].
Both models offer the possibility of selecting events at certain times during
Table 1
Market capitalization companies, which are
the project. Re-evaluation investusing “real option” method [1, 3, 9–11]
ment project with the “real options”
carries the possibility of laying a
Country
Company
Market capitalization
larger number of risk identification
(billion US Dollars)
and management decision options
England
British Petroleum
118,3
in the project, which may lead to a
potential increase in profits and, as a
USA
ExxonMobil
356
consequence, the investment attracFrance
Total
118,5
tiveness of the project. (It happens
Switzerland
Schlumberger
106,37
because classic methods of evaluatBrazil
Petrobras
40,14
ing investment project do not take
Venezuela
PDVSA
–
into account consequences of imOIL GAS European Magazine 4/2015
OIL PRODUCTION
portant management decisions, which could
not be even planned at the beginning of the
project).
In order to use the method of “real options”
in the field, first of all, the use of a risk management algorithm approach was proposed,
which consists of five parts:
1. Identification of the option. At this stage,
options capable of influencing the investment project are identified. Particularly,
the main options: the option to defer a
project, the option to expand the project,
the option to abandon the project. (Option
to defer a project means that management
is waiting for a better opportunity to start
a project. They are waiting for the right
time to do it. Option to expand is used
when project is going well and it makes
sense to keep it going and make extra
profit. And option to abandon the project
is used when project has negative cash
flows and it would be better to withdraw
from it).
2. Qualitative evaluation. At this stage, there
is ranking of options; determining the
most important ones, those that may have
the most impact on the project.
3. Quantitative evaluation. As part of this
stage, a quantitative assessment of all options (major and minor), identified in the
earlier stages of evaluation; is carried out.
4. Planning the use of options.
5. The implementation of options and monitoring the results.
Example
According to this algorithm, in the course of
the Bashneft development project an evaluation was carried out of options to prove the
implementation of the innovative technology “intellectual accompaniment of drilling” for the Trebs and Titov field developments [5–7].
Furthermore, according to the algorithm,
calculations were performed, which confirmed that the laying of additional choices
(options) in the investment project ( to defer
a project, to expand a project and to abandon
a project) opens additional possibilities. In
this example, the calculation was performed
Fig. 1
Map of Trebs and Titov project
Table 2
Results of calculating project cost in consideration of the option premium
Conditions for
project
implementation
Without options
With options
Type of Option
Options for extension of project
Options for deposition of
project implementation
NPV = 29,764.892 thousand USD
NPV = 13,282.448 thousand USD
NPV + Option Premium =
55,016.53 thousand USD
NPV + Option Premium =
18,168.78 thousand USD
using the Black-Scholes model, and with the
help of the program for calculating value of
options, developed by the American scientist A. Damodaran, since it is the most adapted to the stage of hydrocarbons production
(mining) [8].
In particular, it was found that of the three
proposed options (to extend the period of
use of innovative technologies, for the deferment of an innovative project and the option
for the possibility of rejecting an innovative
project at any given time), a real bonus that
increases the efficiency of the project, is
contained only in two options – the extension and the deferment of the project. The
option to withdraw from the project was
dropped due to the fact that it did not present
any economic value.
For the implementation of the option to extend the project using intellectual accompaniment of drilling within the stage of field
development, named after Trebs and Titov
(Fig. 1), “Bashneft” will require an additional 3.3 million dollars. Assuming that
subsequently generated flow will be stable,
the expected additional profits will be
25,251.64 USD. In the case of the option for
the deferment of project, additional costs are
not considered. However, if the market situation is unfavorable and they would have to
use this option, then the additional income
will be equal to 4886.33 thousand USD (see
Table 2.)
Therefore, the calculation clearly demonstrates that using the “options” in the project
of “Intelligent accompaniment of drilling
operations” can significantly change the initial results of evaluating the investment attractiveness of the main project.
Remarks
However, it is necessary to also note the limitations that exist in the projects for production or mining of hydrocarbons, as regards
application of options – in particular, the
possibility of applying options on various
technological stages of production.
At the initial stage of a extraction project, the
option for the deferment of project is usually
considered, as well as the option to withdraw
from the project, which can be applied at all
stages of the project. The option to extend
the project cannot be applied, due to the fact
that prior to the decision to extend the project, it is required to collect the maximum
amount of information about the current
project, and at the initial stage, there is
simply not enough information.
At the final stage of the project for extraction or production of hydrocarbons, all types
of options may also be used. For example,
the option for the deferment of a project can
be used in case there were only hard to exploit hydrocarbon reserves and their production is not profitable in the current period.
However, one would expect that with the implementation of innovative technologies, after a while, it becomes easier to extract oil
and extraction would be profitable. The decision on the application of options for expansion and for withdrawal from the project
shall be based on information gathered
during the project.
As a conclusion, it is worth noting that applying evaluation of investment projects by
“real options” in the phase of hydrocarbon
extraction is a good tool. In the case of
proper and true application, “Options” allow
taking into account larger number of risks
and managerial flexibility than classical
methods for evaluating the investment attractiveness of projects.
References
[1] “McKinsey & Company” #1 2002 p 28.
[2] https://science1data1base.files.wordpress.com/
2015/08/paper.pdf.
[3] http://www.slb.com/~/media/Files/drilling/
brochures/mwd/optidrill_br.pdf.
[4] Damodaran A. The Promise Of Real Options//
Journal of Applied Corporate Finance, Morgan
Stanley.-2000.
[5] http://www.bashneft.com/press/releases/6117/.
[6] http://www.bashneft.com/press/releases/6346/.
[7] http://www.bashneft.com/production/production/
new_regions/.
[8] “Investment Valuation: Tools and Techniques for
Determining the Value of Any Asset” McGrawHill, 2002, Aswath Damodaran.
[9] http://www.statista.com/statistics/272709/top-
OG 211
OIL PRODUCTION / MACHINERY & PLANTS
10-oil-and-gas-companies-worldwide-basedon-market-value/.
[10] https://ycharts.com/companies/PBR/market_cap.
[11] https://ycharts.com/companies/SLB/market_cap.
Alexej Zich, as an energy scientist, initiated an open data
approach for environment protection technologies. He has
worked several years in the energy industry particularly in he
area of transmission and distribution. Hereafter he graduated to Dr.-Ing. at the Freiberg Mining Academy in
Germany in the department of geocurrents, production technology and storage technology.
Kirill S. Verevkin is working as
an engineer with CNIS Gazprom, Moscow, Russia. He received a PhD from the State
University of Management
(SUM). His sphere of interest
includes business analytics, oil
and gas extraction projects.
Dzhamilya A. Sozaeva is Researcher and Associate Professor at SUM (State University of
Management), Moscow,Russia. She received a PhD in Economics. Her sphere of interest
includes business analytics, oil
and gas extraction projects, regional innivation systems.
Oil-Flooded Screw
Compressors for
Unconventional Gas
By A. ALMASI*
Abstract
The technical and commercial advantages
of the API-619 oil-flooded screw compressors (using the fixed-speed electric motor)
have made them the compressor of choice
for the unconventional gas gathering applications. The minimum number of the compressor trains in a single station is recommended. Each compressor station should
preferably be located near the centre of the
coverage area.
Introduction
The unconventional gases (the coal-seam
gas, the shale gas, the tight-sand gas and
other) have become an increasingly important source of the natural gas in the world
over the past decade.
Recent studies point to high decline
rates/pressures of some unconventional gas
wells as an indication that the unconventional gas production may ultimately be
much lower than is currently projected. A
key point could be proper unconventional
gas compression units to compensate the
pressure decline and maintain the production at an acceptable level.
The nodal compression involves the use of
booster compressor (for example, the discharge pressure around 15–20 barg) to provide the required motive force to transport
the unconventional gas from the wells to the
centralized processing plants or the major
compression stations.
The gas engine driven compressors may
seem a good option for the nodal compressors. However, there are some issues which
discourage the gas engine drivers and support the electric motor drivers:
– Relatively high maintenance and low reliability of the gas engine
– Higher cost of the gas engine compared to
the electric motor
– Lower efficiency of the gas engine compared to the electric motor
– Large size/weight and high dynamic/shaking forces. The requirement of a large
foundation and many accessories/auxiliaries.
Usually the cost of the gas engine driven
compressor is around 20–60% higher than
the comparable electric motor driven com*Amin Almasi, Rotating Machine Consultant, Brisbane,
Australia (E-mail: [email protected]).
0179-3187/15/IV
OG 212
pressor. The option of the gas engine driven
compressor may be a good option for very
remote areas. However, the gas engine
driven compressor is usually not recommended. The nodal compressor should preferably be the electric motor driven compressor.
Figure 1 illustrates an example of a screw
compressor package for an unconventional
gas development project (in a very remote
area). The screw compressor is driven by a
12-cylinders gas engine through a gear unit.
Figure 2 illustrates an example of a screw
compressor for an unconventional gas development project. The screw compressor is
driven by an electric motor (direct drive).
Compressor Selection and
Design
Similar (identical) compressor packages
should be used. The minimum number of the
compressor trains in a single nodal station is
recommended. The spare compressor train
is not specified since the unconventional gas
development projects are marginally viable
and the cost should be minimized. All compressors for a medium size field (say about
20 km × 20 km) should be located in a single
nodal station to minimize the utility and the
accessories (the electric power facilities, the
soft start, the compressed air, the flare, and
others). Increased number of nodal stations
can increase the fixed costs and the manning
requirements. In addition, a single nodal station offers a better operational flexibility,
the ease in the operation/maintenance and
many other benefits during the design, the
installation and the operation. This single
nodal compressor station should preferably
be located near the centre of the coverage
area. However, the location of the nodal
compressor station is related to many factors
(such as the land availability and others) and
this ideal centrally located nodal station may
not be achieved. Usually a careful optimization regarding the location of the nodal compressor station should be done.
As compressors have the longest lead time as
far as gas gathering equipment is concerned,
it is desirable to minimize the number of
compressor trains and order them as soon as
possible. Using smaller compressors does
not usually translate into reduced lead times.
Even for the nodal compressors, the minimum number of the compressor trains could
translate to the minimum lead time. The lead
MACHINERY & PLANTS
times are dependent more on the compressor
manufacturer factory loading at the time of
order.
Reciprocating compressors have shown low
reliability and low availability. They have
demonstrated frequent unscheduled shutdowns and high maintenance costs/efforts.
The reliability and availability of reciprocating compressors are so low that in many applications, a spare compressor train is necessary. Reciprocating compressors are not
usually recommended for the unconventional gas services.
The nodal compressors have required a capacity range which is on the lower limit of
the centrifugal compressor coverage. A relatively high purchase/installation cost can be
mentioned for the centrifugal compressors
(compared to oil-flooded screw options).
From the preliminary pricing obtained, for
the nodal compressor applications, the cost
of the centrifugal compressors are approximately 1.3–1.8 times the cost of oil-flooded
screw compressors with the same capacity.
The nodal compressors require the flexibility with regards to the relocation and the
adaptability to different operating conditions. An important factor is the ease in the
relocation. The difficulty, the time required
and the high cost of the relocation should be
noted for the centrifugal compressors. For
the pressure ratios required in nodal compressors (the suction pressure: about
0.7–3 barg and the discharge pressure: approximately 15–23 barg), the centrifugal
compressor will probably require 3-sections
(3-stages or 3-casings). This differential
pressure can usually be achieved by single
oil-flooded screw compressor stage. Higher
number of the compression stage means
more inter-stage facilities/piping. The multistage requirement is raised as one of the
main reasons making the centrifugal compressor difficult to relocate and also making
the centrifugal compressor costly. The low
suction pressure limitations for centrifugal
compressors will lead to larger sized com-
Fig. 1
pressor units when
compared to oilflooded screw compressors. Less tolerant to varying conditions when compared to oil-flooded
screw compressors
should also be highlighted for the centrifugal compressors.
The nodal compressors are expected to
experience the suction pressure variation. This can be because of the wellhead processing facilities, new wells Fig. 2 An example of a screw compressor for an unconventional gas
development project. The screw compressor is driven by an electric
coming online (or
motor (direct drive)
some wells shutting
down), variations in
the gas production, a complex behaviour of compressor has many advantages over the
wells/reservoirs and others. The centrifugal dry type screw compressors and can genercompressors have less tolerance to varying ally be purchased for a lower cost. Nowasuction conditions than oil-injected screw days, there are several competent and capable vendors for oil-flooded screw comprescompressors.
The complex anti-surge systems and the sors. The dry type screw compressors should
complicated control systems for the centrif- only be used in specific applications which
ugal compressors could be a disadvantage the oil-free compression is absolutely necesfor nodal compressors. Another significant sary. It is not the case for the unconventional
issue associated with the centrifugal com- gas nodal compression services. The dry
pressors is the VSD (variable speed drive) screw compressor option is usually not specrequirement for each compressor train. The ified for the unconventional gas applicaVSD for each machine has an important ef- tions.
fect on the cost and the complexity. The dry The selected compressor type for the nodal
gas seal and the continuous requirement for compressor for unconventional gas is usuthe nitrogen supply should also be raised for ally the API-619 oil-flooded screw compressor (electric motor driven using the
the centrifugal compressors.
Based on the abovementioned details, the fixed-speed electric motor). The largest poscentrifugal compressor option is not usually sible oil-flooded screw compressor with
proper references should preferably be sespecified for the nodal compressors.
The dry screw compressors are expensive, lected.
complex, and special compared to the oil- The preferred design is to eliminate the comflooded screw compressors. Compared to pressor package enclosure (because of the
the dry type screw compressors, the access issues, safety problems and many
oil-flooded screw compressors enable much other issues/problems). The compressor
higher compression package should be supplied for the installaratios, a simplified tion at “Outdoor” (no enclosure, no roof and
mechanical design no shelter). If the generated noise is exces(such as the elimina- sive, a noise control solution should be fortion of the timing- mulated. The most convenient noise control
gear system), a more option is the local enclosure for the comefficient operation pressor (preferably provided by the comand an advanced re- pressor vendor) and the sound insulation of
liability. The dry the piping/vessels.
screw compressors
also require a specific drive speed Compressor Size, Soft-Start and
which means the ex- Auxiliaries
tra gear unit for the In essence, inside an oil-flooded screw comspeed-match when pressor, the compressed gas is mixed with
using the electric the oil and moves on to the primary oil sepamotor drivers. The rator. The oil separator acts also as the oil
oil-flooded screw reservoir. A relatively large mass of oil is adcompressor can be mitted with the gas to be compressed. The
directly driven by the oil acts as a lubricant between the contacting
An example of a screw compressor package for an unconventional
electric motor.
rotors, as a sealant of any clearance and as a
gas development project. The screw compressor is driven by a
The oil-flooded screw coolant of the gas during the compression.
12-cylinders gas engine through a gear unit
OG 213
MACHINERY & PLANTS
This cooling effect improves the compression efficiency and permits high pressure ratios in a single compressor stage. The discharge gas temperature can normally be controlled by the quantity of the injected oil, and
is below or around 100 °C.
The compressor cost depends on many factors such the vendor situation, the detail design of the compressor package, any special
project interest (for example, the interest of a
vendor to a project) and many other complex
factors (such as the technical, commercial
and market factors). Many proposals from
the compressor vendors usually indicate
+/–25% tolerances.
The compressor cost is reduced slowly with
the size. Usually, the cost/MW of the compressor is around 1.2–1.7 times for a compressor with the half size (1/2 size). In other
words, using two compressors with the half
capacity compared to a large compressor
(for example, using two 1 MW compressors
instead of the one 2 MW compressors) can
result in 20%–70% cost increase. The
abovementioned rise in the cost (20%–70%
cost increase) is based on normal (average)
market cases. Depending on vendor/compressor, some exceptions may be expected.
In addition of this compressor cost increase,
the costs for accessories and auxiliaries
(such as the foundation, the piping, the vessels, the supports, and others) and also the
cost for the operation/maintenance are much
more when more compressor units are employed. The overall efficiency of smaller
compressors is lower compared a large compressor because the frictions, the mechanical losses, and other losses are proportionally high for small compressors. Generally
smaller compressors are inefficient in the
operation compared to a large compressor.
As an indication (on average), when two
1 MW compressors are used instead of the
one 2 MW compressors, the total cost of
ownership would increase 40–80%. Another
key factor is the use of 1/2 size compressor
cannot usually eliminate the VFD (variable
frequency drive) soft-start requirement. The
VFD soft-start requirement should be studied case by case depending on the electrical
OG 214
grid characteristics and the compressor details, but using 1/2 size (or even sometimes
1/4 size) most often cannot eliminate the
VFD soft-start requirement.
The “soft-start” (VFD) is usually required
for the nodal compressors. Single VFD
“soft-start” system for the bank of the nodal
compressors is generally recommended.
The (single) VFD “soft-start” system should
be designed with high reliability and proper
redundancy, particularly for the mechanical/auxiliary systems associated with the
VFD “soft-start” system. Special attention is
required for the VFD cooling system redundancy (for example, robust dual-pumps
design cooling system).
The unconventional gases are usually near
the saturation (saturated with water). Also
the gases could contain fine particles. The
oil-flooded screw compressors are capable
of digesting low levels of entrained particles
and the liquid. However, the oil-flooded
screw compressors cannot tolerate the liquid
carryover and the fine particles above certain levels. Soft particles tend to form sludge
with the oil and block the internal passages.
The liquid carryover can cause erosion at the
inlet end of the rotors. More seriously the
liquid can be trapped within compressor oil
loop and it can dilute or emulsify the oil. The
inlet separator (the separator upstream of the
compressor) is necessary. The inlet separator (the suction/upstream separator) should
be provided and should be properly sized for
the screw compressor package. This inlet
separator serves a dual purpose. It prevents
the liquid enters the compressor. It also collects the gas contaminations. Excessive high
concentrations might jeopardize the compressor component life. Each compressor
package requires its own inlet separator installed near the oil-flooded screw compressor. The compressor package (the compressor skid) should be installed on a concrete
foundation. The compressor skid should
preferably include ancillaries, vessels and
others. The air-cooler is usually installed
separately.
It is recommended to design the nodal compressors with a low suction pressure capabil-
ity (even the zero suction pressure capability) in a way that the nodal compressor can
facilitate the gas collection even for the lowest possible well pressure. To extend the gas
gathering system life time (particularly for
the end of life, when the wellhead pressure
declining), it is recommended to consider
provisions for the future installation of extra
nodal compressors with the low suction
pressure capability which can provide the
power and the capability to collect low-pressure gases from the wells at the end of their
life.
References
[1] Bloch, H. P., Geitner F. K.: Compressors: How to
Achieve High Reliability & Availability, 2012
(McGraw-Hill, USA).
[2] Brown, R. N.: Compressors Selection and Sizing,
Third edition, pp 120–220, 2005 (Gulf Publishing
Company, Houston, USA).
[3] Davidson, J., Bertele, O.: Process Fan and Compressor Selection, pp 112–145, 2000 (Mechanical Engineering Publications Limited, London,
UK).
[4] Forsthoffer, W. E.: Forsthoffer’s Best Practice
Handbook for Rotating Machinery, First edition,
2011 (Elsevier, Oxford, UK).
Amin Almasi is a rotating machine consultant in Australia.
He is chartered professional engineer of Engineers Australia
(MIEAust CPEng – Mechanical) and IMechE (CEng
MIMechE) in addition to a
M.Sc. and B.Sc. in mechanical
engineering and RPEQ (Registered Professional Engineer in Queensland). He specializes in rotating machines including centrifugal, screw and reciprocating
compressors, gas turbines, steam turbines, engines,
pumps, offshore rotating machines, LNG units, condition monitoring and reliability. Almasi is an active
member of Engineers Australia, IMechE, ASME, and
SPE. He has authored more than 100 papers and articles dealing with rotating equipment, condition monitoring, offshore, and reliability.
MACHINERY & PLANTS
Diagnosis of Centrifugal Pumps Using
Vibration Analysis
By M. MINESCU, I. PANA and M. STAN*
Abstract
Vibration analysis is a diagnostic method
frequently used during operation of equipment. The analysis of the failures produced
by vibrations indicated the existence of specific finger prints and related equipment vibration spectra. Modeling and identification
of these particular aspects in the spectrum of
vibration help to control the operation of petroleum facilities and build them in a safe
manner. The operating status for a centrifugal pump can be considered for the purpose
of analysis as the mechanical vibrations produced in the impeller shaft bearings or propagated through the suction and/or discharge
piping. The paper presents vibration analysis of the working vibrations of centrifugal
pumps both single- and multi-stage in a simulated pipeline network.
1 Introduction
During the operation of equipment or facilities of various categories, vibrations may occur, which once exceeding a certain limit,
may lead to shortening the life of the equipment. Moreover the noise associated with
these vibrations can be a factor affecting
human health.
Generally, the most important parameters of
the oscillatory motion can be considered as:
– Pulsation – dependent on initial conditions
– Amplitude – the size parameter characterizing the vibration
– Effective speed/accelerators – parameter
shows vibration energy
– Intensity of elastic waves, which changes
very little with the frequency of movement.
The vibration level of the pumping aggregates, expressed by the value of effective
speed is measured at significant positions on
the pump. The sources of vibrations in a dynamic machine can be multiple:
– Failure of bearings
– Impeller dynamic imbalance
– Misalignment
– Gear defects (faulty gear)
– Resonance (stiffening inappropriate, ineffective technologies, wrong design)
– The flow of fluids through pipes/ pump.
Centrifugal pumps are characterized by low
vibrations because of their working princi* Mihail Minescu, Ion Panã, Marius Stan, Petroleum Gas
University of Ploiesti, Romania (E-mail: mminescu@
upg-ploiesti.ro)
0179-3187/15/IV
ple (rotation parts
only). This is why,
vibration analysis of
these
particular
pumps allows identification of existing
problems much easier than with reciprocal pumps for example.
Centrifugal
pumps are very common in the oil industry with applications
ranging from drilling rigs, refineries
and special appliances.
Fig. 1
Operating scheme of a single stage centrifugal pump: 1 – shaft;
2 – wedge; 3 – screw nut; 4 – wear ring; 5 – impeller; 6 – vane;
7 – diffuser; 8 – diffuser vane; 9 – volute; 10 – packing; 11 – suction
nozzle; 12 – reducer; 13 – discharge nozzle
2 Process Centrifugal Pumps
Figure 1 shows the configuration of the single stage centrifugal pump used for the first
set of experiments. Fluid enters the pump
through the suction nozzle 11. The impeller
5 is fixed into the shaft 1 (wedge 2 and screw
nut 3) and rotates. The liquid is centrifuged
by the impeller outwards and is collected via
the diffuser 7 and led to the volute 9. High
pressure liquid exits at the discharge 13.
The functional parameters of a pump do not
remain at constant values throughout its life.
This is explained by the fact that the factors
that contribute to wear increase over time.
The wear on centrifugal pump components
is in two categories, namely mechanical and
chemical. Whatever the nature of wear is, it
has the effect of changing the geometric
shape of parts, which is reflected in the final
modification of the hydraulic pump funcTable 1
tional parameters (flow, pressure, and pumping head), hence changing the vibration frequency. Centrifugal pump components that
wear out frequently are presented in Table 1,
according to [13] .
3 Centrifugal Pump Vibration
Measurement
The major source of vibrations is the rotor itself. Due to high rotational speeds, any misalignment of the pump components may
lead to vibrations. The assessment of the
technical condition and reliability of a dynamic machine involves gathering all technical information on instrumentation and
control equipment. This data acquisition
must be done when the pump is new, in order
to use these as a reference. If no reference
Main causes of wear on parts and subassemblies of centrifugal pumps and wear characteristics of data (after [13])
No.
Item
Causes of the failures and effects
1
Impeller
Pinching, indenture, discontinuities in shape, thin wall, camber of the
hub bore, deformation of the keyway
2
Shaft
Portion of the seals rub, rub portion rings (rubber seals), the par ts
which come into contact with fluid from the pump are subject to
corrosion
3
Wear ring
Wear due to abrasive action of particles that flow through the gap
between ring and rotor
4
Soft gaskets
Wear due to friction at the contact surface wear bushings, are
replaced and not repaired
5
Mechanical seal
Wear on the friction surfaces of the stationary ring and mobile, no
repair but replacement
6
Bearings supporting
Wear balls and taxiways are replaced, wear causes include:
excessive loads, speeds too high, insufficient lubr ication, and
improper installation
OG 215
MACHINERY & PLANTS
Table 2
Example of alarm limits, according to [7]
Bandwidth
Alert
mm/s – PK
Alarm
mm/s – PK
Absolute Fault
mm/s – PK
Alarm limits for 1200 rpm and higher
Overall
3.81
1× Narrowband
2.54
2× Narrowband
1.27
3× Narrowband
1.01
1× Gear mesh
1.27
Rolling-element bearing
1.27
Blade/vane pass
1.27
7.62
5.08
2.54
2.03
2.54
2.54
2.54
15.95
10.16
5.08
3.81
5.08
5.08
5.08
Alarm Limits for 300 to 1199 rpm
Overall
2.54
1× Narrowband
1.27
2× Narrowband
0.51
3× Narrowband
0,25
1× Gear mesh
0.51
Rolling-element bearing
0.76
Blade/vane pass
0.76
3.81
2.54
1.27
0.76
1.01
1.27
1.27
7.62
5.08
2.54
1.52
2.03
2.54
2.54
Fig. 2
Location of vibration sensors on horizontal multistage pump with
ten rotors
CASE 5: Single stage The pump used for this experiment uses the
pump cavitation
same setup as for bearing failure as shown
The case considers in Figure 5a and allows visualization of
The values in this table have been divided by 20.5 to compare with RMS
the cavitation situa- cavitation via the transparent inlet pipe
values. PK refers to peak measured value, typically peak filtered.
tion, which is a cause (cavitation was induced by throttling the
of degradation of suction valve).
exists, alarm limits may be used (see Table centrifugal pumps. It can be revealed by the The mixture of air and fluid entering into the
frequency spectrogram, Figure 6, in which pump can be controlled permanently. We
2).
The measured values, compared with per- there are a series of signals at high frequen- also noticed a loud noise when operating the
pump under these conditions.
missible levels recommended by the manu- cies with high amplitudes.
facturer or dynamic equipment standards Table 3 Results from analysis of multistage (ten impellers) centrifugal pump vibrations (CASE 1)
ISO 10816 and ISO 2372, indicate whether
(overall vibration)
the equipment operates safely. Basically, to
Discharge
LEFT – Bearing 1
RIGHT – Bearing 2
determine the overall level of vibration meapressure
(speed 2960 rot/min)
(speed 2960 rot/min)
surements are performed on all equipment
[bar]
Vibration velocity
Vibration velocity
sites on the three relevant directions (Fig. 2)
horizontal
vertical
axial
horizontal
vertical
axial
by placing the sensors at inlet or outlet of the
[mm/s]
[mm/s]
[mm/s]
[mm/s]
[mm/s]
[mm/s]
pump.
The typical defects that can be detected in10
0.130 / UAL 0.354 / UAL 0.154 / UAL
0.124 / UAL 0.242 / UAL 0.106 / UAL
clude:
8
0.261 / UAL 0.390 / UAL 0.272 / UAL
0.129 / UAL 0.122 / UAL 0.125 / UAL
– Dynamic imbalance
6
0.302 / UAL 0.380 / UAL 0.288 / UAL
0.121 / UAL 0.117 / UAL 0.129 / UAL
– Faulty alignment (parallel or angular, shaft
3
0.279
/
UAL
0.327
/
UAL
0.257
/
UAL
0.120 / UAL 0.128 / UAL 0.143 / UAL
problems)
– Electro-mechanical problems
*UAL Under Alarm Limit
– Faulty gear (symptom reducers / multipliers)
Table 4
Experimental results from analysis of multistage (three impellers) centrifugal pump
– Specific defective bearings (bearings or
vibrations (CASE 2) (overall vibration)
sliding)
Speed
Bearings 1
Bearing 2
– Specific resonances related to equipment
[rot/min]
Vibration velocity
Vibration velocity
or assemblies etc.
horizontal
vertical
axial
horizontal
vertical
axial
The vibration analysis data, performed us[mm/s]
[mm/s]
[mm/s]
[mm/s]
[mm/s]
[mm/s]
ing the VIBROTEST 80 device, is shown in
1010
0.235 / UAL 0.077 / UAL 0.211 / UAL
0.149 / UAL 0.053 / UAL 0.124 / UAL
Tables 3 to 5 (Figs. 3, 4).
Furthermore, two other cases (4 and 5) have
1220
0.279 / UAL 0.106 / UAL 0.161 / UAL
0.130 / UAL 0.110 / UAL 0.138 / UAL
been simulated including man made fail1450
1.144 / UAL 0.443 / UAL 0.788 / UAL
0.990 / UAL 0.251 / UAL 0.564 / UAL
ures: bearing failure and cavitation. The two
1800
1.365 / UAL 0.593 / UAL 0.992 / UAL
1.293 / UAL 0.378 / UAL 0.772 / UAL
simulated failures have a clear characteristic
and can be used as “finger prints” for pump
diagnostics.
Table 5
CASE 4: Single stage centrifugal pump,
bearing failure
In Figure 5a a single-stage pump with the
possibility to induce bearing defects is
shown. The test conditions are as follows:
speed 1020 rpm, pump geometry: 8 vanes
impeller, 3.8 barg discharge pressure,
2.4 l/s flow rate. Figures 5b and 5c show the
finger print of a good bearing, whereas the
bearing train and ball frequencies are
clearly seen.
OG 216
Speed
[rot/min]
Results from analysis of single stage centrifugal pump vibrations (CASE 3) (overall vibration)
Bearings 1
Vibration velocity
horizontal
vertical
[mm/s]
[mm/s]
Bearing 2
Vibration velocity
horizontal
vertical
[mm/s]
[mm/s]
Gland
1010
0.237 / UAL
0.123 / UAL
0.203 / UAL
0.077 / UAL
0.130 / UAL
1220
0.230 / UAL
0.125 / UAL
0.168 / UAL
0.107 / UAL
0.139 / UAL
1450
1.485 / UAL
0.726 / UAL
1.273 / UAL
0.683 / UAL
0.571 / UAL
1800
0.706 / UAL
0.472 / UAL
0.524 / UAL
0.173 / UAL
0.383 / UAL
MACHINERY & PLANTS
Fig. 3
Location for sensors S speed;
1,2 – rolling bearings
Fig. 4
Sensor placement scheme for singlestage pump vibrations; S speed;
1,2 – bearings
ble or inadmissible, but also can provide information on what is defective and where it
is located. The values (Tables 3–5) of the
overall vibrations compared with the permissible levels recommended by the literature (Table 2) or standards (ISO 2372 and
ISO 10816, see Fig. 7) indicate that the
pumps work safely (cases 1–3). After the
analysis of vibration, carried out on the three
types of centrifugal pump, namely: single
stage pump, multiple stage horizontal pump
with four impellers and ten impellers, we
found out that these machines did not require repair since the vibrations are within
the limits prescribed.
The research conducted on the cavitation [2,
3, 5, 6, 9] is added to the known condition to
avoid this phenomenon:
NPSH a > NPSH γ
(1)
where NPSH a is net positive suction head
available and NPSH γ net positive suction
head required, a condition referring to the
suction conditions:
S ss =
Fig. 5
Single-stage pump vibration bearings evaluation a) test equipment; b) vibration spectrum
before bearing replacement; c) vibration spectrum after bearing replacement
4 Discussions
To highlight the cause of the fault (important
in maintenance works) the spectrogram (frequency domain measurement) is used,
where the recorded signal is split up into
components of different frequencies. The
vibration signature associated with the frequency of the shaft, blades, bearings etc. is
unique and exceeding the limits indicates
the necessity to replace / repair the component. A loud noise associated with a defect in
the bearing, see Figure 5 a), provided verification, highlighted in Figure 5 b). It is noted
that the alarm limit is reached at a frequency
corresponding to the value of 0.5 X (half of
the frequency of rotation of the shaft). This
frequency is associated with the frequency
of the bearing cage. After removal of the
“bad bearing” (cracked cage) and replacing
it with a new one, the amplitude of the vibration speed decreased from 1.2 to 0.15 mm/s
(Fig. 5 c). Mechanical vibrations due to
weakened bearings are the most dangerous
because they lead to additional loads by
shock on the shaft and the other bearings.
Diagnosing mechanical weakening by the
vibration analysis method has several advantages such as lower maintenance costs,
increase of operational safety, reducing wear
on bearings, etc.
The vibration measurements may indicate if
the vibration (RMS) is normal, still admissi-
Fig. 6
Q
4
NPSH γ3
(2)
Suction specific speed Sss is needed to be calculated in accordance with API 610 Appendix A; it is the suction specific speed based
on NPSH γ at full diameter and BEP (Best Efficiency Point) flow. The importance of the
Sss is presented in Figure 8. It shows the close
link between the Sss and the reliability of a
centrifugal pump. The failure rate is half at
the value of Sss below 11,000 (units used in
the equation (2): rpm – speed value, gpm –
flow value and feet – net positive suction
head required) compared with the values of
failure rate Sss at above 11,000 and this limit
was imposed for practical operation.
Table 6 shows a short overview of the parameters used to reproduce each one of the
cases. The calculated Sss values are between
3400 and 6400 rpm gmp1/2/ft3/4, which means
that the pump has a failure frequency of 0,42
to 0,53 according to Figure 8.
Single-stage pump frequency-domain of vibrations during cavitation. (speed 1040 rpm, 8 vanes
impeller)
OG 217
MACHINERY & PLANTS
Fig. 8
Fig.7
Matrix which characterizes the severity of
vibration
5 Conclusions
The article presents and analyses the actual
working of single and multi-stage centrifugal pumps in a pipeline network.
“Finger prints” could be generated for specific cases such as cavitation or “faulty bearing”.
Vibration monitoring of industrial pumps
shows that with low investment costs, there
is a large saving potential, through failure
prediction and early detection of pump
malfunctions.
As cavitation is a very dangerous phenomenon for the mechanical integrity of pumps, it
is shown that vibration analysis can identify
this condition and, when integrated in a control system, can regulate the pump parameters to avoid cavitation.
References
[1] Guiseppe Aiello, s. a.: Real time assessment of
hand–arm vibration system based on capacitive
MEMS accelerometers. Computers and Electronics in Agriculture, Volume 85, July 2012.
[2] Hallam, J. L.: Centrifugal Pumps: Which Suction
Specific Speeds are Acceptable?. Hydrocarbon
Processing, April 1982.
[3] Henshaw, T.: Suction Specific Speed Part 1, 2,
and 3. Pumps and Systems Magazine, 2009.
[4] Hirschberger, M., James, I.: A Review of Nss Limitations – New Opportunities. 25th International
Pump Users Symposium Proceedings, 2009.
[5] Karassik, I. J.: Centrifugal Pump Operation at
Off-Design Conditions. Chemical Processing
Magazine, 1987.
[6] Karassik, I. J.: Setting the Minimum Flows for
Centrifugal Pumps. Pumps and Systems Magazine, March, 1994.
[7] Mobley R. K.: Root Cause Failure Analysis.
Butterworth–Heinemann, Boston, 1999.
[8] Ravindra Birajdar s. a.: Vibration and Noise in
Centrifugal Pumps – Sources And Diagnosis
Methods. 3rd International Conference on Integrity, Reliability and Failure, Porto/Portugal,
20–24 July 2009.
[9] Stables G.: Cavitation and Pump NPSHR: Proceedings of the 25th International Pump Users
Symposium, 2009.
[10] Stan M.: Analysis the significance of reliable experimentally determined distribution laws. 3 rd
Symposium with international participation Durability and Reliability of Mechanical Systems,
Targu-Jiu, ISBN 978-973-144-350-8, Mai, 20–21
2010.
[11] Steven J., Hrivnak, P.E.: Associate Mechanical
Engineer. Tennessee Eastman, Eastman Chem-
OG 218
Table 6
The influence of the suction specific speed (Sss) over failure rate according [9]: left)
and [2]: right) – the values in brackets represent the number of centrifugal pumps tested
Pumps characteristics
Case Speed Flow rate1) Head1)
rpm
gpm
ft
1
2
3
4
5
1)
2960
1450
1450
1020
1040
22.0
114.4
132.6
38.0
38.8
at best efficiency point;
106.9
65.3
29.4
125.0
129.9
2)
NPSHr1)
ft
Head2)
ft
Flow rate2)
gpm
Sss
rpm
gmp1/2/t3/4
η1)
–
D2
Mm/
4.8
7.5
3.5
1.3
1.3
325.6
93.7
51.9
145.0
150.7
29.4
148.8
173.8
50.7
51.7
4,289.0
3,422.6
6,525.1
5,170.6
5,323.0
0.43
0.70
0.67
0.52
0.52
120
209
200
416
416
maximum value; D2 impeller diameter.
ical Company, Centrifugal Pump Vibrations: The
Causes – Vibration.org.
[12] Volk, M.: Pump Characteristics and Applications,
2nd Edition, CRC Press, 2005.
[13] Stan, M., Buca, S.: The Vibration Analysis Diagnostics Centrifugal Pumps. Analele Universitatii
“Constantin Brâncusi” din Târgu Jiu, Seria
Inginerie, Nr. 4/2011.
of Drilling and Extraction Equipment. He holds a Ph. D.
in technical sciences, with a specialty in oilfield equipment, a M. Sc. in mechanical engineering and a M. Sc.
in computer science, both from the Oil and Gas University of Ploiesti. Mr. Panã is author of more than 120
publications from which more than 80 are peer-reviewed and of ten books in collaboration or as single
author.
Mihail Minescu is Professor at
Petroleum & Gas University of
Ploiesti, Romania. He is head of
the sub-department for Manufacture of Technological Equipment and dean of the faculty of
Mechanical and Electrical Engineering. He teaches courses on
the manufacturing of the petroleum equipment topics
such as: Study and Engineering of Materials, Material
Processing, Manufacture of Technological Equipment.
He holds a Ph.D. in technical sciences, with a specialty
in oilfield equipment, a M.Sc. in mechanical engineering and a M.Sc. in computer science, both from the Oil
and Gas University of Ploiesti. Mr. Minescu is author of
more than 150 publications from which more than 100
are peer-reviewed and of ten books in collaboration or
as single author.
Marius Stan is Lecturer PhD.
Eng. at Oil and Gas University of
Ploiesti. Since 1991 working as a
faculty in the Mechanical Engineering Department from the
Faculty of Mechanical and Electrical Engineering at the Oil and
Gas University of Ploiesti. Until
2015 he was engineer at SC Neptun SA Campina and participated in the design of speed reducers, screw pumps,
screw compressors and oil field equipment. Between
1996 and 1997, Mastère Spécialisé en Exploration Production, Ecole Nationale Superieure du Petrol et des
Moteurs, Rueil Malmaison, France, obtained in 1997. Between 1999–2000 he participated in the elaboration “Process for the preparation of a cement and swelling associated test device WO 2002010086 A1“ at the Clausthal
University of Technology in Germany. In university teaching courses, scientifical research, design and consultIng
activities in the area of oil drilling and production
equippement; drilling rig installations of large size;
topdrive system; coiled tubing system; oil management;
environmental protection; logistics, reliability and safety
of the oil equippement in exploatation. He holds a Ph. D.
in technical sciences, with a specialty in oilfield equipment from the Oil and Gas University of Ploiesti. Dr. Stan
is also an experienced specialist in drilling equipments
engineering, drilling facilities and drilling technologies
topics. He is author of more than 50 publications from
which more than 20 are peer-reviewed, and four books
specialized courses .
Ion Panã is Associate Professor at Petroleum & Gas University of Ploiesti, Romania. He is
head of the sub-department for
Hydraulic and Pneumatics
Equipment and vice dean of the
faculty of Mechanical and Electrical Engineering. He teaches
courses on the petroleum equipment topics such as:
Gathering, Transport and Distribution of Hydrocarbons, Hydraulic and Pneumatic Machines, Numerical
Simulation of Petroleum Systems, Mechanical Design
MAINTENANCE & REPAIR
Smarter Work with “Smartphones”
By S. CIERNIAK and M. DUMAN*
1 Introduction
Today’s smartphones – available to everybody at acceptable cost – now have much
more processing power than NASA’s computers during the times the first man landed
on the moon.
In addition to this, the functionality of these
devices is growing rapidly. Only a short time
ago the so called GPS tracking function was
recognized as highly attractive, today nobody is surprised that the “Small Computer
Smartphone” can calculate “step functions”
and manages all operations via simple voice
control. In addition, the type of use has
changed. At the beginning of the smartphone era, all functions of the office applications were implemented visually unchanged
on the smartphones. Today there are an increasing number of applications developed
specifically for use on smartphones.
In addition, short message services and chat
programs such as WhatsApp or Twitter continue to replace classical email functionality.
New specific functions have already been
developed and new applications are promoted by the expansion of transmission
technologies (e. g. LTE). Thus, many more
applications become available on mobile
phones and some applications already solve
the classic desktop applications.
Currently it is expected that worldwide
1.5 billion smartphones will find buyers in
the coming year, whilst the sales of the classic desktop computer decline.
Having this background in mind, the question arises to what extent technicians and engineers in the world of oil and gas grids and
pipeline nets and the related grid-bound infrastructure will use smartphones in the
short term for their operational practical
day-to-day work.
2 Mobile Applications for the
Grid-bound Infrastructure of
Oil and Gas Pipeline Systems
It is typical for the grid-bound infrastructure
of oil and gas pipeline systems that the
whole system as such is decentralized, that
means that the infrastructure extends over an
area of many square kilometers. For the operation of this infrastructure it is a must to
have a so called “area organization”. All
modern companies target a digitally optimized business process through available IT
* Siegmund Cierniak, Consultant, Aachen, Germany
(E-mail: [email protected]); Metin Duman,
GATTER 3 Technik GmbH, Dortmund, Germany (E-mail:
[email protected]).
0179-3187/15/IV
Fig. 1
Pipeline engineers at work on site
solutions, which support the main ideas of
being up to date (i. e. Workforce Management (WFM) and Geographic Information
Systems (GIS)). In order to avoid media
breaks, specific mobile data collection and
output devices will be used. Moreover, these
hard and software tools are also linked with
the financial hard and software systems in
order to ensure efficient processes in total.
Due to the need to operate continuously in
some cases with ancient infrastructures, the
achievement of the aforementioned targets
represents an enormous challenge to the operator. It is not possible to interrupt the operating system in order to merge new data and
then later realizing the optimized processes.
All digital transformations must be implemented cautiously and taking into account
the interactions with other processes.
Against this background it is clear that all
grid operators are focusing their strategies
on the organization of the so-called area operation (work scheduling, debugging, pipe
line information) and its link with their related commercial systems. It should be
noted that in addition to this the implementation of this strategy is also influenced by
third parties (e. g. it has to be taken into account that new legal requirements have to be
fulfilled).
3 Technical Calculations made
with “Smart Phones”
In practice it is pretty normal to act with a variety of self-developed calculation programs. These calculations are, however, so
far carried out for the various tasks in everyday practice, but largely in the offices and
not directly on site.
Due to the reasons described above, these
calculation programs are generally not in the
main focus on the digital strategy of the
companies. Nevertheless, the efficient and
high-quality processing of these tasks is of
great importance, because these tasks are essential to ensure the functionality of secure
network operation.
Due to the extensive proliferation of socalled “Office software” the implementation of technical engineering calculations is
normally nowadays given by means of
spreadsheet programs.
A disadvantage of these solutions is often
the lack of quality assurance of most of the
self-programmed calculations. In addition
to the non-existent documentation, the development of solutions for system updates is
often missing or even totally questionable.
Very often the possibilities of the software
are not optimally utilized due to a lack of
programming skills.
Usually, the development of these calculation programs is therefore not based on a
structured process but only an individually
motivated “trouble shooter”.
The transfer of these (mostly only company-internal) calculation programs to mobile applications is an excellent approach
and is therefore a chance to utilize more sensible optimizations based on simultaneous
use of engineering know-how and also the
know-how of informatic techniques.
The “trivial” transfer using a “standard” laptop is of course possible, but does not match
the potential options and possibilities
achievable with a smartphone.
The benefits of implementation using
smartphones are at the onset evident, since
their use is much more comfortable and flexible in the field and on-site. It is certainly a
not to be underestimated advantage that
smartphones are small in size and weight.
Smartphones are today already practically
always in man’s hands (on site) and do not
need “boot” time while the notebook or the
laptop is stored in the company car, far from
the construction site.
Furthermore, the user interface, significantly improved during the last years, plays
an important role, thus also increasing the
comfort dramatically. At this point it should
be also noted that there are much more useful advantages, i. e. voice control as an important example.
Important and decisive for the use of smartphone apps compared to the laptop, however, is the additional use of features of the
original basic calculations.
Using smartphones it helps dramatically to
add a couple of photos to further illustrate
the situation and also to store the GPS coordinates or a map with a few clicks. The quality of results of all engineering tasks becomes much more professional. The immeOG 219
PIPELINES
Fig. 2
App FREESPAN
diate and direct sending of messages, photos
and calculation results is a further advantage
of smartphones in comparison to the mobile
computers. Unforeseen situations or faults
can already be documented. It is also possible without delay to commission -already on
site- subsequent tasks.
Therefore, the use of smartphones is much
more comfortable and flexible in the field
than all other available working tools. First
applications – already available by Apps4Grids – support already a few field engineers (practitioners) on sites.
Two examples using such mobile apps will
be explained later.
3.1 Example “Free Span”
Nearly 100% of all grid-bound infrastructures, such as gas supply systems, were laid
underground. To have a precise knowledge
of the state is very important, but this is often
only possible during or after a visual inspection.
For this reason it often occurs, for example,
that the extent of excavation has to be enlarged to repair damaged pipe coating and all
of this during the time of the mentioned activity (Fig. 2).
The site management team has to decide in
advance, what length of the pipe can be exposed without additional support. The app
“FREESPAN” calculates based on only a
few parameters (pipe diameter, wall thickness, material, etc.) the maximum allowable
deflection of the pipe, and thus supports the
necessary decisions of the responsible person-in-charge on site. Due to this app as a
mobile application the repair work will become much more efficient and safe.
Fig. 3
OG 220
Parameters for calculations
(www.apps4grids.com)
3.2 Example “Rating of corrosion”
Many gas pipes are made of steel, so it could
still happen today that parts of pipe lines corrode despite presence of highly sophisticated state-of-the-art protection techniques
such as pipe plastic wraps and cathodic corrosion protection. It happens that we observe
the appearance of local wall thickness reductions. The engineer’s job is to evaluate the residual capacity and thus the stability of the
gas line based upon different calculation
methods such as ASME B31 G or DNV-RPF101, developed by norm institutes and
authorities.
Based on these calculation methods it is possible to calculate the residual capacity and
stability of a gas pipe with local wall thickness reduction. These calculation methods
require only a few input parameters (Fig. 3)
to achieve the desired results. To apply these
methods as a mobile app for the practitioner
on the site is an ideal basis for decision-making. Thus, a decision at short notice is possible and if necessary repair activities can be
carried out immediately and if necessary
other actions can be implemented promptly
and efficiently.
4 Conclusions
For today’s technicians and engineers in operational practice smartphone applications
are a must. These apps represent a valuable
addition for many applications, thereby facilitating the decision-making process directly on site. On the other hand, the mentioned apps do not replace the existing company internal IT solutions. Without question
following an intense examination of the
practical use and weighing up
the low cost for the purchase of
apps against the achievable
high flexibility, one can highly
recommend the purchase and
use of these apps.
Furthermore it is worth mentioning, that interactions with
other users, for example, via a
web portal, are already well-es-
tablished functions, useable for the development of the respective apps. Besides the exchange of experience with already available
applications it is an excellent way to formulate new tasks with this approach.
Maybe there are tasks that are reserved for a
special group of users. Thinking for example of the use of iPads in the Apple Store,
which is restricted to the sales process. That
has to be realized for example, for competitive reasons or obligations to maintain confidentiality. Based on smartphones the realization of company-specific duties can be
achieved easily.
Finally, based on the shown benefits in
grid-bound infrastructures it is anticipated
that there will be an enormous growth in
on-site smartphone use in the very near
future.
Literature
[1] DNV-RP-F101: Corroded pipelines, January 2015.
[2] ASME: Manual for Determining the Remaining
Strength of Corroded Pipelines, B31G-2012.
[3] Schneider: Bautabellen für Ingenieure (mit
Berechnungshinweisen
und
Beispielen),
Werner-Verlag, Köln, 21. Auflage, 2012.
[4] Dubbel: Taschenbuch für den Maschinenbau,
Springer-Verlag, Berlin, 2014.
[5] APPS4Grids: www.apps4grids.com
Dr. Siegmund Cierniak has
more than 40 years of experience in the gas business. He
worked many years in the field
of rotating equipment in R&D,
Sales and Management at
well-known companies and ten
years at RWE in charge of future gas projects. He was many years President of the
EFRC (European Forum for Reciprocating Compressors). After his retirement (2013) he has been working as an active consultant in these sectors. He holds
a B.Sc. and a M.Sc. in Process Engineering as well as
a Ph.D. in Mechanical Engineering from the Aachen
University, Germany.
Metin Duman has worked for
large companies in the energy
sector in Germany and for a
technical service company in
Turkey as shareholder. He is a
manager with international experience and personal emphasis in business development,
strategic marketing and project management. Metin
Duman holds a M.Sc. in Electrical Engineering from
the University of Dortmund and has almost 20 years
of experience in the energy and services market. He is
Managing Director and Shareholder of GATTER 3
Technik GmbH, Dortmund/Germany.
NEWS
CONSTRUCTION
ENGINEERING
El Segundo Refinery Coke Drum Reliability Project is “Project of
the Year”
Pioneering fractured basement
reservoir development on the
UKCS
The Project Management Institute has selected Chevron’s El Segundo Refinery Coke
Drum Reliability Project as its 2015 Project
of the Year. Fluor served as the engineering,
procurement and construction management
contractor, in addition to performing initial
studies and front-end design work.
The project replaced six coke drums and incorporated seismic upgrades to the coker
structure at Chevron’s El Segundo Refinery
in California. The vertical project required
extensive scaffolding and 15 major lifts that
ranged from 166 to 500-plus t, and took
place at heights of more than 80 m. The project was completed four months ahead of
schedule, $7 million under budget, with no
serious injuries and with no disruption to the
plant’s operations.
“Through close collaboration with Chevron
and all stakeholders, we met a significant
challenge and helped deliver this project
ahead of schedule, under budget and, most
importantly, safely,” said Jim Brittain, president of Fluor’s Energy & Chemicals business in the Americas. “Fluor takes on the
world’s most complex and challenging projects, and the logistical and safety challenges
of this project were second to none.”
The project team developed an innovative
logistics plan to transport the new drums to
the site – reducing the distance from 35 to
7,2 km to minimize inconveniences to the
community. Once at the site, old drums were
removed and the new 29-m-tall drums,
which are three times as heavy as the Space
Shuttle Endeavor, were installed. The project also removed a 454 t,
six-derrick structure and cutting deck that covered the
coke drums. The removal
took place in one lift, with a
122 m tall crane, the largest
ever brought to Southern California.
The project used interactive
planning sessions, safety
commitment workshops, cutting-edge technology and
strict scaffolding safety
guidelines to complete with
no serious incidents or losttime injuries.
CARBON CAPTURE & STORAGE
Largest ever controlled release of CO2 from an underwater
pipeline
To fully understand the environmental and
safety implications associated with the development of CO2 pipelines, DNV GL is
conducting the oil and gas industry’s largest
ever controlled release of carbon dioxide
from an underwater pipeline at its full-scale
Spadeadam Testing and Research Centre,
located in Cumbria, UK.
The planned underwater release, scheduled
to start in January, is part of an international
Joint Industry Project (JIP) ‘Sub-C-O2’ to
develop safety guidelines on the use of offshore CO2 pipelines. Companies participating in the JIP are Norway’s Gassnova,
Brazil’s Petrobras, the UK government’s
Department of Energy and Climate
Change, the UK’s National Grid and DNV
GL. Italy’s ENI is expected to join the JIP in
early 2016.
This is the second experimental phase which
will run for three months and will involve releases in a 40 m diameter, 12 m deep pond at
the Spadeadam Testing and Research Centre, which is located in Cumbria, UK.
“This is the largest experimental investigation to date of underwater CO2 releases
which will study the effects of depth on measured and observed parameters,“ said Gary
Tomlin, VP Safety and Risk, with DNV GL
at Spadeadam. “The testing is designed
around what is already known about underwater natural gas leaks and the possible occurrence of CO2 hydrates collecting on
pipework. By using high-speed, underwater
cameras and other measurement techniques,
we can examine the configuration and characteristics of the released gas. It will allow us
to see whether it reaches the surface and analyse what happens.”
The first phase of experiments which involved small-scale, controlled CO2 releases
from a 3″ nominal bore pipeline in a 8.5 m
diameter, 3 m deep water tank were expected
to be completed by December.
UK engineering solutions provider, Costain,
is involved in a project which the Oil and Gas
Authority has recently lauded as “significant” for the future of the UK continental
shelf.
Costain has worked closely with Hurricane
Energy on hydrocarbon resources in naturally fractured basement reservoirs, to produce a number of field development options
for their Lancaster discovery, West of Shetland.
Globally, naturally fractured basement reservoirs are prolific oil producers, but they
represent a new opportunity for the UKCS.
Costain, in collaboration with Hurricane,
has defined an initial development concept
based around an Early Production System
(EPS). The primary objectives of the EPS
are to gain additional knowledge of the reservoir and minimise capital exposure, whilst
providing an economic return on the capital
invested.
The EPS concept takes into account the current low oil price environment which has necessitated the development of novel solutions and cost saving initiatives.
www.constain.com
PROCESSING
New Biturox® plant for SOCAR
The Austrian engineering company Pörner
signed a contract with SOCAR (State Oil
Company of Azerbaijan Republic) for the
design and supply of a Biturox® plant for the
Hey-dar Aliyev Refinery in Baku, Azerbaijan. The plant, for the production of quality bitumen, is part of a comprehensive modernization project and replaces the Biturox®
plant that Pörner delivered to Azerneftyag in
1995.
For the Biturox® plant, Pörner will provide
the license, basic engineering, pilot tests –
carried out in the Pörner research facility,
key equipment and commissioning support.
Using the latest off-gas treatment system,
and designed for an an-nual capacity of
400,000 t, this plant will meet the high demand for quality bitumen for the further expansion of the road network of Azerbaijan.
The Heydar Aliyev Baku Oil Refinery is located near the capital Baku and is currently
undergoing extensive modernization. The
annual pro-cessing capacity will increase
from 6 to 7.5 million tons. All grades of fuel
produced will comply with Euro 5 standards
and are quality feed materials for the
Azerkimya downstream plant, such as ethylene, propylene and butylene.
www.poerner.at
OG 221
NEWS
CONDITION MONITORING
SERVICES
Full diagnostic power on the PC
DNV GL wins frame agreement with Wintershall Norge AS
With OMNITREND Center, PRUFTECHNIK Condition Monitoring launches a modern, powerful and easy to use software platform.
It communicates with all the latest offline
and online systems of PRUFTECHNIK such
as the VIBXPERT device family, the
VIBRONET Signalmaster and the DNV GL
certified VIBGUARD and VIBROWEB XP.
OMNITREND Center is available in single
user or client-server versions, is ready for
cloud solutions, and provides powerful aids
like knowledge-based machine templates,
online and offline device managers. Statistical post processing methods help to monitor
the health of even the most complex machines.
The operator quickly gets an overview
about the status of his machine park using
interactive asset reports. Thanks to the flexible html format this information can easily
be shared.
www.pruftechnik.com
DNV GL, technical advisor to the oil and gas
industry, has been selected by Wintershall
Norge AS to provide a frame agreement for
global inspection services for its developments offshore Norway. The overall contract
is expected to exceed NOK 10 million
(approx $ 1.2 million).
The term of the contract is five years, with an
option for two, two-year extensions and covers all Wintershall’s projects on the Norwegian Continental Shelf. It will initially be
used for the ongoing Maria development.
DNV GL will perform inspection, test and
surveillance activities on a worldwide basis
as instructed by Wintershall Norge AS. The
scope of services includes: review of the in-
ENGINEERING
7-inch HMIs for hazardous area
applications now with
visualisation software Movicon
The only 7" widescreen HMI for Zone 1 hazardous area applications, the innovative
ET-208 operator interface, is now available
with Movicon, the HMI visualisation software solution for complex engineering
tasks.
Running a Windows Embedded operating
system, SERIES 200 R. STAHL HMIs offer
a highly versatile solution in their device
class. Movicon CE currently represents one
of the most powerful open software solutions on the market.
Thanks to the XML structure of this runtime
engine, Movicon- based projects are platform-independent and can be run autonomously on the HMI device, operator terminals, PDAs, smartphones or wireless systems (pocket PCs, handhelds).
This means maximum data transparency,
simplified project engineering for different
types of devices, and lower maintenance
costs.
www.stahl.de
OG 222
spection and test plan , examination of materials, products, manufacturing processes,
work procedures and/or services at Wintershall’s contractor’s premises. DNV GL will
also examine contractor’s procedures, documents, quality performance and compliance
with governing standards and specifications.
The frame agreement is now underway and
inspection and surveillance work is planned
to be carried out across a number of locations including Germany, Italy, Greece, Norway and Malaysia, where subsea equipment
components and structures will be manufactured.
www.dnvgl.com
SAFETY
HELPE upgrades safety at Aspropyrgos refinery
Greek oil company chooses HIMA safety systems, local partner to upgrade
emergency shutdown capabilities
Hellenic Petroleum (HELPE), one of the
largest oil companies in the Balkans, recently
upgraded the emergency shutdown capabilities of its Aspropyrgos Industrial Complex in
an Athens suburbwith the installation of six
HIMA safety systems by Solidus Assyst, a
Greek automation specialist.
The replacement of safety-related programmable electronic systems at the Aspropyrgos
refinery included the installation of four
HIMax® and 2 HIQuad systems from
HIMA.
The new systems protect the refinery’s FCC
complex, LPG spheres and circulation network, diesel hydrodesulphurization unit,
naphtha hydrodesulphurization unit and two
crude distillation units.
The HIMA safety systems integrate with the
refinery’s Yokogawa control system and
fully comply with the IEC 61511 standard.
Communication is accomplished with
Modbus Serial Link. The HIMA hardware
supports 3,030 I/Os.
Supported by HIMA, Solidus Assyst managed the project through engineering, construction, integration, programming, procurement, testing and training, decommissioning of old PESs, installation of new systems, commissioning and modifications.
www.hima.com
CYBER SECURITY
Emerson further strengthens protection of critical infrastructure
Emerson Process Management has joined
forces with Intel® Security to enhance and
strengthen its integrated cyber security solution to better secure the DeltaVTM distributed control system (DCS). This increased
layer of cyber protection is designed to help
safeguard critical assets and data.
This strategic relationship reinforces Emerson’s commitment to protecting infrastructure throughout the plant lifecycle and addresses the market demand for consistent,
proven industrial cyber security.
The DeltaV DCS has long incorporated builtfor-purpose control system firewalls and
network switches that provide easy-to-configure security and protection features to
help system networks remain available, reliable and more secure.
The new solutions provide efficient compliance measures and instant intelligence for
changing threat environments, along with
the power of real-time visibility and centralised management through a single platform.
www.emersonprocess.com
NEWS
RESERVOIR DEVELOPMENT
PIPE CONSTRUCTION
New HOSTAFRAC®SF 13213
delivers a step change for
flowback aid sustainability
Venture capital investment to produce innovative pipelines for
offshore production
Surfactant subsystem contains
sustainably sourced sugar-based amide
surfactants
Clariant, manufacturer of specialty chemicals, recently announced its new HOSTAFRAC® SF 13213 innovative chemical
flowback aid for hydraulic fracturing.
The new sugar-based surfactant dramatically
lowers the fluid’s surface and interface tension to significantly increase the flowback of
the hydraulic fracturing fluid. HOSTAFRAC
SF 13213 effectively lowers the formation
damage caused by emulsification of the fracture fluids in the reservoir. While as little as
13% of the fluid used during the hydraulic
fracturing process can be recovered without
flowback
aid
additives,
the
new
HOSTAFRAC SF 13213 increases fluid recovery levels to as high as 87%.
Offering significant sustainability advantages, HOSTAFRAC SF 13213 has earned
Clariant’s EcoTain® label for sustainability.
Products with this designation undergo a
systematic, in-depth screening process using 36 criteria in three sustainability dimensions: social, environmental and economic.
EcoTain products significantly exceed sustainability market standards, have best-inclass performance and contribute overall to
the sustainability efforts.
www.clariant.com
PROCESSING
Air Liquide offers G2GTM
gas-to-gasoline technology
Air Liquide Global E&C Solutions has entered into a global technology licensing agreement with ExxonMobil Research and Engineering. Under the terms of the agreement, Air
Liquide will market and license its proven
Lurgi MegaMethanolTM technology combined
with ExxonMobil’s proprietary methanol-to-gasoline (MTG) technology to transform natural gas into ultra-low sulfur gasoline.
The combination of technologies will be marketed under the trademark G2GTM.
The G2GTM technology transforms natural
gas, as well as other feedstocks, into motor
gasoline containing virtually no sulfur and
low in benzene content. The integration of
both Air Liquide Global E&C Solutions and
ExxonMobil technologies into one combined solution will minimize project interfaces, off sites and logistics complexities, as
well as overall investment for synthetic fuel
production. The G2GTM technology offer
will be licensed as an integrated solution and
will be deployed globally through Air
Liquide Global E&C Solutions’ network.
www.airliquide.com
Through its venture capital arm, Evonik has
invested in Airborne Oil & Gas (IJmuiden,
Netherlands). The specialty chemicals
group now holds a minority interest in the
Dutch company. The investment was made
jointly with HPE Growth Capital (HPE) and
Shell Technology Ventures. Airborne Oil &
Gas (AOG) possesses a unique technology
for the production of thermoplastic composite pipes for a variety of offshore oil and gas
applications.
The current offshore oil & gas infrastructure
consists of either rigid steel pipes or
so-called flexibles. The latter comprise of
multiple layers of steel and polymers. AOG’s
thermoplastic composite pipes dispense
with steel entirely and are therefore not susceptible to corrosion. They have extremely
high mechanical stability but are also flexible. As an added advantage they are lightweight and can be fabricated in lengths of up
to 10 km, which means that AOG’s pipes can
be installed relatively simply and cost effectively.
AOG’s thermoplastic composite pipes are
suitable and beneficial for a wide range of
offshore applications. A number of operators
have qualified AOG’s pipes for offshore oil &
gas transport lines, where the benefits of low
cost installation and the absence of corrosion
offer breakthrough improvements.
Excellent mechanical properties thanks to
unidirectional tapes
AOG’s pipelines consist of three layers: An
inner plastic pipe is covered with a composite of unidirectional tapes, which in turn is
sheathed by plastic.
Polymers such as
polyethylene, polypropylene,
polyamide 12 and PEEK
can be used. Unidirectional tapes are
thin plastic bands in
which continuous
reinforcing fibers
are embedded in parallel
alignment.
When a number of
such bands are
stacked vertically at
defined angles and
fused together, it results in an extremely
stable composite.
AOG’s special expertise lies in the design of
both the composite material and the finished
pipe, for a variety of applications: All the
layers are melt-fused to one another inseparably, which explains the outstanding mechanical properties of the pipelines.
www.airborne-oilandgas.com
METERING
New LACT control system designed to increase accuracy of liquid
hydrocarbon transfer
Liquid hydrocarbon transporting and storage companies, including truck and ship
loading facilities and pipelines, can now
transfer materials using an enhanced lease
automatic custody transfer (LACT) control
system designed for accuracy and safety.
The Thermo Scientific AutoLACT system
is designed to facilitate the transfer of liquid
hydrocarbon from storage tanks or trucks to
refineries or centralized processing facilities while accurately recording data for each
transaction. The AutoLACT system features
the market-proven flow computer capabilities of the Thermo Scientific AutoPILOT
Pro as well as an integrated human machine
interface (HMI) designed to ensure that operators capture each transaction in the system for true accountability.
www.thermoscientific.com/autolact
OG 223
NEWS
CALENDAR
December
International Petroleum Technology Conference (IPTC), December 6–9, Doha.
www.iptcnet.org
BBTC Mena – Bottom of the Barrel Technology Conference, December 8–9, Abu
Dhabi, UEA. www.europetro.com
The 2015 European Biopolymer Summit, December 9–10, Lonond, UK.
www.acieu.co.uk
January
The Future of Aromatics 2016, January
13–14, Amsterdam, The Netherlands.
www.wplgroup.com/aci
North Africa Downstream Summit, January 17–19, Cairo, Egypt.
www.northafricadownstream.com
9th European Gas Conference, January
19–21, Vienna, Austria.
www.europeangas-conference.com
Lignofuels 2016, January 20–21, Munich,
Germany. www.acieu.co.uk
6th Carbon Dioxide Utilization Summit,
February 24–25, Newark, NJ, USA.
www.acieu.co.uk
Black Sea Oil & Gas Summit, January
www.theenergyexchange.co.uk
February
18th annual E&P Information and Data
Management, February 3–4, London.
www.smi-online.co.uk
Energy Storage 2016, February 3–4, Paris,
France, www.wplgroup.com
International Petroleum (IP) Week, February 9–10, London. www.energyinst.org
6th Russia & CIS Oil & Gas Executive
Summit, February 17–18, Dubai.
www.europetro.com
7th International Gas Technology Conference – IGTC, February 17–18, Dubai.
www.europetro.com
ME-TECH 2016 – Middle East Technology Forum for Refining & Petrochemicals, February 14–16, Dubai.
www.europetro.com
March
STAR Global Conference 2016, March
7–9, Prague, Czech Republic,
www.cd-adapco.com
OG 224
International LNG Congress, March
14–15, London. lngcongress.com
Gasification 2016, March 23–24, Rotterdam, Netherlands. www.acius.net
June
2016 APPEA Conference & Exhibition,
June 5–8, Brisbane, Australia.
www.appea.com.au
April
Course: Petroleum Economics and Business, April 3–6, Abu Dhabi.
www.hoteng.com
wire 2016 / Tube 2016 – Int. Fairs, April
4–8, Duesseldorf, Germany.
www.wire.de; www.tube.de
LNG18 – 18th International Conference &
Exhibition Liquefied Natural Gas, April
11–15, Perth, Australia.
www.appea.com.au
Course: Introduction to Shale Oil and
Gas, April 18–22, Vienna, Austria.
www.hoteng.com
SIMONE Congress, April 20–22, Krakow,
Poland. www.simonecongress.com
July
Course: Advanced Well Planning, July
www.hoteng.com
May
International Downstream Week 2016
incorporating: Operational Excellence in
Refining, Gas & Petrochemicals Conference; International Downstream Technology & Strategy Conference; International
Bottom of the Barrel Technology Conference May 9–13, Madrid, Spain.
www.europetro.com
August
Course: Artificial Lift Systems, August
www.hoteng.com
September
European Bulk Liquid Storage 2016,
September 7–8, Tarragona, Spain.
www.acius.net
3rd Rotating Equipment Conference
2016, September 14–15, Duesseldorf, Germany. www.introequipcon.com
Int. Conference Catalysis – Novel Aspects
in Petrochemistry and Refining, September 26–28, Berlin, Germany.
www.dgmk.de
October
11th Global LNG Tech Summit, October
3–5, Barcelona, Spain.
www.lngsummit.com
International Conference
Catalysis – Novel Aspects
in Petrochemistry and Refining
September 26–28, 2016, Berlin, Germany.
organized by DGMK, SCI (Italy), ÖGEW (Austria) and GECATS (Germany).
www.dgmk.de
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Our success, as one of the leading land
drilling contractors in Europe, is based
on more than 125 years continuous
operational experience.
Oil & Gas Wells
Geothermal Wells
Underground Storage Wells
Workover
Integrated Project Management
Drilling Equipment Rental
KCA DEUTAG Drilling GmbH
Deilmannstrasse 1
48455 Bad Bentheim, Germany
Tel 05922 72 0
[email protected]
www.kcadeutag.com
Noise protection
for outdoor
installations
OUR EXPERTISE
SUPPORTS
YOUR SUCCESS
The design of these noise barriers makes them particularly suitable for temporary
enclosures of machines and drilling rigs.
Individual shielding of industrial outdoor areas, generally
A major advantage of our professional NoiseGard is that no
aimed at optimizing environmental and occupational health
foundation is required, so you do not have to bother about
and safety, has useful side effects, in addition to noise
underground cables, drainage channels, etc.
protection. For example wind forces acting on a drilling rig
may be attenuated or the outside world may be effectively
The system may be designed for different heights and any
sealed off, if confidentiality so requires.
length to provide complete fencing of industrial facilities and
events. Matching gate systems, entrances and emergency
exits will be adapted as required.
Individual requirements of acoustic or optical properties
may be implemented upon request. Depending on the
model, we offer to either rent or buy the systems.
noisegard.com
PRODUKTE & DIENSTLEISTUNGEN
Produkte & Dienstleistungen
VariAS-Ventilblock mit drehbarem Adapter vereinfacht das
Ablesen
AS-Schneider hat für einen Kunden aus der
Erdölbranche einen individuellen Ventilblock auf Basis der bewährten VariAS-Baureihe entwickelt. Der Anwender benötigte
für die Druckmessung in einer Förderanlage
einen Kugelhahn mit Block-&-Bleed-Funktion. Dieser musste über einen zusätzlichen
Prüfanschluss verfügen. Außerdem sollte
die Stellung des angeschlossenen Druckmessgeräts zur besseren Lesbarkeit flexibel
einstellbar sein. Eine bisherige Lösung mit
mehreren Kugelhähnen genügte diesen Anforderungen nicht.
Die geschmiedeten Double-Block-&-BleedVentilblöcke mit einteiligem Gehäuse ersetzen konventionelle Installationen aus mehreren Einzelventilen. Der VariAS-Block
wurde mit einem drehbaren Adapter am Eingang ausgestattet. Mit diesem lässt sich die
Stellung der gesamten Messanordnung flexibel verändern, Ventile und Druckmessgerät sind damit gut zugänglich. Das Messgerät ist direkt am Ventilblock angebracht. Die
Erstabsperrung erfolgt über einen Kugelhahn, und auch ein separater Prüfanschluss
mit einer Mini-Messkupplung ist in den VariAS-Block integriert. Dieser wird über ein
Nadelventil abgesperrt. Zur Entlüftung ist
zusätzlich ein kleines Entlüftungsventil
montiert.
www.as-schneider.com
TOTAL setzt weiter auf Service von Bilfinger Maintenance
Der Engineering- und Servicekonzern Bilfinger wird auch in den kommenden sechs
Jahren in weiten Teilen für die Instandhaltung der TOTAL Raffinerie Mitteldeutschland in Leuna verantwortlich sein. Das Gesamtvolumen des jetzt verlängerten Rahmenvertrags beläuft sich auf mehr als 100
Mio. Euro inkl. budgetierte Stillstandsund Projektleistungen.
Bilfinger Maintenance ist seit der Inbetriebnahme der Raffinerie im Jahr 1997 für
die Instandhaltung wesentlicher Teile der
Anlage zuständig.
»In dem neuen Vertrag werden zusätzlich
Tools und Methoden unseres Bilfinger
Maintenance Concepts, BMC®, zur Anwendung kommen, so dass sowohl der Betreiber als auch wir von sinkendem Instandhaltungsaufwand profitieren«, erläutert Hermann Holme, Geschäftsführer Bilfinger Maintenance.
www.bilfinger.com
Fachtagung für unterirdische Energiespeicherung
10. März 2016 | The Westin Bellevue Dresden
Bei der von der ESK GmbH or anisierten Ta un werden Vorträ e zu aktuellen Themen
,
g
g
.
Weitere Informationen:
E [email protected]
I www.rwe.com/esk
Sicherheitsnetz für Verkrustungen am Bohrlochrohr
Frankfurt am Main, November 2015–Ein
Weihnachtsbaum war Auslöser für eine außergewöhnliche Idee, welche die Arbeiten in
der Bohr- und Workoverindustrie sicherer
macht. UGS/VINCI Construction suchte
nach einer Lösung zum Schutz vor herab fallenden Bohrrohrverkrustungen und -ablagerungen bei Rohrzieharbeiten –
und entwickelte zusammen mit
GeostockEntrepose ein ebenso
einfaches wie kreatives System,
das Erinnerungen an den Christbaumverkauf weckt. Um den
Gefahrenherd abblätternderAblagerungen an Rohren möglichst auszuschalten, orientierte
sich das Team an den Netzmaschinen zur Verpackung von
Weihnachtsbäumen.
Während des Aussolprozesses
von Salzkavernen können sich
Anhaftungen in Form von zentimeterdicken Krusten am Rohr
bilden. Wird das Rohr aus dem
Bohrloch entfernt, kann es bei
der herkömmlichen Methode
vorkommen, dass sich die zuvor entstandenen Ablagerungen beim Ausbauender Rohre ablösen und zu Boden fallen. Dies führt zu
einer unmittelbaren Gefährdung der Mitarbeiter am Bohrloch. Darüber hinaus muss im
späteren Verlauf der Arbeiten die komplette
Außenfläche des Rohres mühsam von Abla-
gerungen befreit und das entfernte Material
entsorgt werden. Probleme, die mit der neuen Methode behoben bzw. vermieden werden.
Jetzt spannt sich beim Ausbau der Rohre aus
dem Bohrloch automatisch ein stabiles Netz
über diese; Ablagerungen können so nicht
mehr herab fallen. Auch das spätere Entfernen und Entsorgen der
Anhaftungen verläuft wesentlich
schneller: Dafür wird im Vergleich zur vorherigen Verfahrensweise nur noch ein Sechstel der
Zeit benötigt.
Die originelle Lösung überzeugte
auch die Jury des VINCI-Innovationspreises 2015, der dieses Jahr
zum achten Mal für konzerninterne Projekte vergeben wurde. Für
die ganzjährig einsetzbare Weiterentwicklung der Weihnachtsbaumverpackung konnte sich das
Projektteam der UGS GmbH über
eine Auszeichnung in der Kategorie »Sicherheit« freuen.
(Bild: UGS Mittelwalde)
459
VERANSTALTUNGEN
TAGUNGSKALENDER
18.–19. Januar 13. Internationaler Fachkongress
»Kraftstoffe der Zukunft 2016«, Berlin.
www.bioenergie.de
19.–21. Januar 9. European Gas Conference 2016,
Wien. www.europeangas-conference.com
20.–21. Januar Lignofuels 2016, München
www.wplgroup.com/aci/
21. Januar Schiefergas: 7. Energiekolloquium der
Chemie-Gesellschaften, gemeinsam veranstaltet von:
DBG, DECHEMA, DGMK, GDCh, VCI, VDI-GVC, Frankfurt
am Main. www.dechema.de
27. – 28. Januar TAR 2016 – Turnarounds, Anlagenabstellungen, Revisionen, Potsdam. www.tacook.com
9. Februar Potenziale des unterirdischen Speicherund Wirtschaftsraumes im Norddeutschen Becken
(Projekt TUNB) – BGR-Hauskolloquium, Hannover.
www.bgr.de
2.–4. März 28. Deutsche Zeolith-Tagung, Gießen.
www.processnet.de/dzt28.html
9.–10. März 8. Workshop Gasmengenmessung –
Gasanlagen – Gastechnik, Rheine.
www.koetter-consulting.com
16.–18. März 49. Jahrestreffen Deutscher Katalytiker,
Weimar. www.processnet.org/katalytiker2016
13,–14. April UNITI Mineralöltechnologie-Forum,
Stuttgart. www.umtf.de
18.–21. April NEFTEGAZ 2016, Moskau.
www.neftegaz-expo.ru/en/
21.–22. April DGMK/ÖGEW-Frühjahrstagung
2016, Celle. www.dgmk.de
24.–27. April SMRI Spring Meeting 2016, Galveston,
TX, USA. www.solutionmining.org
2.–4. Mai Jahrestreffen Reaktionstechnik 2016,
Würzburg. www.dechema.de
9.–11. Mai DGMK-Tagung Konversion von Biomassen, Rotenburg a.d.F., www.dgmk.de
13.–15. September ProcessNet-Jahrestagung 2016,
Aachen. www.dechema.de
14.–15. September Rotating Equipment Conference
2016, Düsseldorf. www.introequipcon.com
25.–28. September SMRI Fall Meeting 2016, Salzburg, Österreich. www.solutionmining.org
26–28. September Catalysis – Novel Aspects
in Petrochemistry and Refining; Tagung des
DGMK-Fachbereichs Petrochemie mit SCI und ÖGEW,
Berlin. www.dgmk.de
9.–13. Oktober World Energy Congress 2016,
Istanbul. http://wec2016istanbul.org.tr/
26.–27. Oktober 20. Workshop Kolbenverdichter,
Rheine. www.koetter-consulting.com
8.–10. November gat 2016, Essen www.drgw.de
29. November – 1. Dezember Geothermiekongress
DGK 2016, Essen. www.geothermie.de
2017
Call for Papers
The Petrochemistry Division of DGMK announces its 24th topical Conference
with the general theme
Catalysis – Novel Aspects
in Petrochemistry and Refining
September 26–28, 2016, in Berlin, Germany
The Conference is jointly organized by the Petrochemistry Division of DGMK, the Division of
Industrial Chemistry of the Società Chimica
Italiana (SCI), ÖGEW Österreichische
Gesellschaft für Erdölwissenschaften and
GeCatS German Catalysis Society.
The scientific chairmen are Professor Dr. Stefan
Ernst (Technische Universität Kaiserslautern),
Dr. Ulrich Balfanz (BP Europa SE, Bochum),
Professor Dr. Matthias Beller (Leibniz-Institut
für Katalyse e.V., LIKAT, Rostock), Dr. Michael
Bender (BASF SE, Ludwigshafen), Dr. Harald
Häger (Evonik Industries AG, Marl) and Dr.
Mario Marchionna (Saipem S.p.A., San Donato
Milanese, Italy).
English will be the Conference language
throughout. The scientific program will consist
of Keynote Lectures (upon invitation only) by
renowned experts in the field, Oral Presentations and Poster Presentations. There will be no
parallel sessions and ample time for discussion.
The preprints with the manuscripts of keynote,
oral and poster presentations will be handed out
to registered participants at the Conference
desk in Dresden.
The Conference will address all scientific and
technical issues related to the general theme.
Particular emphasis will be on the following
topics: More recent developments in catalytic
refining processes, in particular with respect to
deep hydrotreating (HDS and HDN, i. e. of cycle
oils and heavy fuel oils), recent developments in
hydrocracking of heavy petroleum fractions and
in fluid catalytic cracking (FCC) for the use of
heavier feedstocks and the production of increased yields of light olefins from FCC. Moreover, contributions on recent achievements in
the synthesis of alkylate gasoline will be highly
welcome. Also, the challenges and opportunities arising from catalytic processing/coprocessing of biogenic feedstocks in the
refinery will be addressed.
Innovative applications of catalysis in petrochemistry will be discussed related to new developments in selective oxidation catalysis, selective
hydrogenations/dehydrogenations and the catalytic use of carbon dioxide, bioethanol etc. for
the synthesis of value-added products. Moreover, contributions on the catalytic production of
light olefins and aromatics from alternative
sources (e.g., methane, methanol) and related
topics are welcome.
Please send your proposal by May 1, 2016 to:
DGMK German Society for Petroleum and Coal
Science and Technology,
Attn. Dr. Gisa Tessmer / Mrs. Christa Jenke,
Überseering 40, D-22297 Hamburg,
Phone:+49-40-63 90 04-11 or -12,
Fax: +49-40-63 90 04 50,
Preferably by email to:
[email protected].
All proposals should contain the envisaged title
of the paper, the authors´ names and affiliations
including their addresses and a concise abstract. The complete proposal should not exceed one typewritten page. Please indicate if
you prefer oral presentation or a poster. Please
note that we intend to provide the accepted abstracts on our homepage. We therefore kindly
ask you to use the template for abstracts on our
website.
Please note that authors will not be exempt
from paying the Conference fee.
Dr. Gisa Tessmer and Mrs. Christa Jenke from
DGMK or any of the organizers will be pleased
to provide more information on any aspect related to the 2015 Conference of the Petrochemistry Division of DGMK.
9.–13. Juli 22. Welt-Erdöl-Kongress, Istanbul
Deutsches Erdölmuseum Wietze, alle Veranstaltungen
unter www.erdoelmuseum.de
460
Stefan Ernst Ulrich Balfanz Matthias Beller Michael Bender Harald Häger Mario Marchionna
BÜCHER & BERICHTE / VERANSTALTUNGEN
Bücher & Berichte
Geothermieanlagen
Bau und Berechnung von Erdwärmeanlagen
– Einführung mit praktischen Beispielen.
Autoren: Frieder Häfner, Rolf-Michael Wagner, Linda Meusel. Hardcover 49,99 Euro,
ISBN 978-3-662-48200-1
Unter den regenerativen Energiequellen für
die Gebäudeheizung und -klimatisierung
nimmt die Erdwärme (in Form von Erdwärmesonden etc. mit Wärmepumpen) den ersten Platz ein. Der jährliche Zubau von Erdwärmeanlagen hat steigende Tendenz.
Das Buch richtet sich besonders an private
Bauherren, Ingenieure und Firmen, die Anlagen planen und bauen. Die Schwerpunkte
liegen im Bereich Planen/Berechnen und
Bau/Qualitätssicherung.
Die Autoren charakterisieren die Erdwärmenutzung, beschreiben die üblichen technischen Anlagen dazu, mit Schwerpunkt auf
Erdwärmesonden (EWS) und ihre Einsatzmöglichkeiten. Danach wird die Berechnung von Erdwärmeanlagen (Einzel-EWS,
Sondenfelder) mit mathematisch-analytischen Verfahren und numerischen Simulationsverfahren dargestellt. Die dazu notwendige Software wird Online als Demo-Version bereitgestellt.
In einem weiteren Hauptkapitel werden der
Bau von Erdwärmeanlagen, technische Voraussetzungen, Anforderungen und Genehmigungspraxis dargestellt. Der Betrieb der
Anlagen und die vielfältigen Nutzungsmöglichkeiten für Heizen, Warmwasserbereitung, Kühlen ist in den Hauptkapiteln integriert.
Beispielhafte Anlagenmuster werden dimensioniert, bautechnisch beschrieben und
wirtschaftlich bewertet.
Bezug genommen wird u. a. auch auf den
spektakulären Schadensfall in der Stadt
Staufen, wo sich der Erdboden noch heute
infolge Gipsquellung hebt, sowie das Projekt SuperC der RWTH Aachen.
Statusreport »Regenerative
Energien in Deutschland«
In dem aktuellen »Statusreport 2015 Regenerative Energie in Deutschland« zeigt der
VDI den Stand der Technik und die sich abzeichnenden Tendenzen der regenerativen
Energien auf. Mit seinen Empfehlungen soll
der Statusreport helfen, die politische Diskussion um das Für und Wider des regenerativen Energieangebots zu versachlichen
und aus ingenieurtechnischer Sicht Hinweise zu geben, wo sich einerseits begrüßenswerte Entwicklungen abzeichnen und andererseits Tendenzen erkennen lassen, denen gegengesteuert werden muss.
Die Nutzung regenerativer Energien hat in
den letzten Jahren deutlich zugenommen.
Die Strombereitstellung aus erneuerbaren
Energien lag 2014 bei etwa 160,6 Terrawattstunden (TWh), das entspricht etwa 28 %
des Bruttostromverbrauchs. Dazu tragen die
Windenergie 35 % und die Bioenergie 31 %
bei. Die Fotovoltaik und die Wasserkraft haben einen Anteil von jeweils 22 %.
Im Jahr 2014 wurden rund 471 Petajoule
(PJ) an Wärme aus regenerativen Energien
bereitgestellt, was 10 % bezogen auf den
Endenergieverbrauch (ohne Verkehr) an
Brennstoffen entspricht. Dieser Beitrag
wird nach wie vor überwiegend durch biogene Festbrennstoffe (87 %) abgedeckt, ge-
folgt von Wärmepumpen und Solarthermie.
Der Fachausschuss »Regenerative Energien« (FaRE) der VDI-Gesellschaft Energie
und Umwelt (GEU) begleitet die Entwicklung der Nutzung des regenerativen Energieangebots in Deutschland und global seit
vielen Jahren. Dazu behandelt er neben technischen, ökonomischen und ökologischen
auch energie-, wirtschafts-, umwelt- und
agrarpolitische sowie soziale Aspekte im
Zusammenhang mit der Nutzung der erneuerbaren Energien als Teil des Energiesystems.
Der »Statusreport 2015 Regenerative Energien in Deutschland« steht kostenfrei zum
Download unter www.vdi.de/fa-re.
Veranstaltungen • Termine
Schiefergas: 7. Energiekolloquium
Die Chemie-Gesellschaften DBG, DECHEMA, DGMK, GDCh, VCI und VDI-GVC
veranstalten gemeinsam das 7. Energiekolloquium am 21. Januar in Frankfurt am Main.
Welche Möglichkeiten zur Erschließung unkonventioneller Vorkommen gibt es in
Deutschland und Europa. Bricht ein neues
Zeitalter der heimischen Energieversorgung
an oder sind wir nicht bereit die damit verbundenen Risiken zu tragen und was bedeutet dies für den Chemiestandort Deutschland?
Auf dem Programm stehen die Vorträge:
– Schiefergas und Fracking – Game Changer
oder Risikotechnologie (Stefan Ladage,
Bundesanstalt für Geowissenschaften und
Rohstoffe, GEOZENTRUM, Hannover)
– Schiefergas-Ressourcen: Entwicklung der
Frack-Technologie (Prof. Dr.-Ing. Mohd
Amro, TU Bergakademie Freiberg, Freiberg)
– Bedeutung unkonventioneller Vorkommen
für die Öl- und Gasindustrie (Kathrin Falk,
ExxonMobil Central Europe Holding
GmbH, Berlin)
– Fracking Chemikalien – Abwasserproblematik, aktuelle Wissenslücken und die
Rolle der Wissenschaft (PD Dr. Martin Elsner, Helmholtz-Zentrum München, Neuherberg).
Die Moderation übernimmt Prof. Dr. Kurt
Wagemann, DECHEMA e.V., Frankfurt am
Main.
www.dechema.de
19. Workshop Kolbenverdichter 2015 – Bericht
Der 19. Workshop Kolbenverdichter 2015
bot den zahlreichen Teilnehmern auch in
diesem Jahr ein vielseitiges Programm aus
Fachvorträgen, Versuchsvorführungen und
begleitender Fachausstellung.
Der jährlich stattfindende deutschsprachige
Branchentreff rund um das Thema Kolbenverdichter ermöglichte Betreibern, Herstellern und Dienstleistungsunternehmen aus
der Öl- und Gasindustrie, der chemischen
Industrie, dem Anlagenbau sowie der Forschung wieder einen interessanten Informations- und Erfahrungsaustausch.
Aus der Perspektive der Betreiber wurde
über Erfahrungen mit Überwachungssystemen, aber auch mit der Schmierung von Zylindern und Packungen sowie der Sanierung
von Fundamenten und Rohrleitungsbefestigungen berichtet.
Außerdem gab es wieder Themenbeiträge
»über den Tellerrand hinaus«. So wurden die
rechtlichen Aspekte der neuen Betriebssicherheitsverordnung vorgestellt und die
rechtlichen Grundlagen beim Umbau von
Maschinen thematisiert – eine Herausforderung für Hersteller und Betreiber.
Zwischen den Vorträgen hatten alle Gäste
Gelegenheit, die begleitende Fachausstellung sowie verschiedene Versuchsvorführungen zum Thema Schall- und Schwingungstechnik zu besuchen. So wurden u.a.
Effekte wie Torsionsschwingungen, akustische und mechanische Schwingungen dargestellt sowie deren Ursachen und mögliche
Lösungsmaßnahmen erläutert.
Der 20. Workshop Kolbenverdichter findet
am 26. und 27. Oktober 2016 in Rheine statt.
www.koetter-consulting.com
461
VERANSTALTUNGEN
Call for Papers
Die gute Resonanz auf die vorangegangenen Tagungen veranlasst den
DGMK-Fachbereich Kohlen- und Biomasseveredlung, zur Fachtagung
Konversion von Biomassen und Kohlen
vom 9. bis 11. Mai 2016 in Rotenburg a. d. Fulda
einzuladen.
Die Tagung wird sich wiederum mit innovativen Verfahren, Prozessen und
Anlagen zur Nutzung von Biomassen und Kohlen durch chemische und
physikalische, insbesondere thermochemische Konversionstechniken und
der Verwendung der erhaltenen Produkte in energetischen und chemischen Folgeprozessen, u. a. zur Herstellung von Kraftstoffen, befassen.
Schwerpunktthemen sind:
Verfahrens-/Prozesstechnik – Effizienz – Reaktionsverhalten – Produktqualitäten/Produktverwertung – Gasaufbereitung/Gasreinigung –
Bilanzierungen (Energie, Schadstoffe u.a.) – synthetische und thermische
Nutzung der erzeugten Gase – Synergien – Bio-Raffinerie – Alternative
Kraftstoffe – Betriebserfahrungen – Anlagenbau.
Neben der Vermittlung von Grundlagen technisch effizienter Konzepte und
neuerer Entwicklungen zur Nutzung von Biomassen und Kohlen wird dem
Erfahrungsaustausch mit Anlagenbetreibern und Konzepten zur Realisierung von Anlagen, die Biomassen und Kohlen effektiv umwandeln, ein
breiter Raum gewidmet werden.
Zwischen den Techniken der Kohlenveredlung und der Biomasseverwertung bestehen vielfältige Gemeinsamkeiten, die den Raum für eine interessante Fachtagung bieten. Kohletechniken sollen Eingang in die Biomasseverwertung finden.
Der DGMK-Fachbereich Kohlen- und Biomasseveredlung lädt daher zu dieser Tagung alle Fachleute ein, die sich mit der Technik der Umwandlung von
Kohlen und Biomassen befassen. Die Tagung wird in Zusammenarbeit mit
der Fördergesellschaft Erneuerbare Energien (FEE), Berlin, veranstaltet.
Vorgesehen sind:
Übersichtsvorträge eingeladener Referenten
Fachvorträge (ohne Parallelsitzungen)
Posterbeiträge
eine Podiumsdiskussion zu den Erkenntnissen der Tagung.
Vorträge und Posterbeiträge werden in einem DGMK-Tagungsberichtsband
veröffentlicht, der den Teilnehmern im Tagungsbüro ausgehändigt wird.
Die Konferenzsprachen sind Deutsch und Englisch. Eine Simultanübersetzung ist nicht vorgesehen.
Tagungsort ist das Hotel Rodenberg in Rotenburg an der Fulda (www.goebel-hotels.com/rotenburg/hotel-rodenberg), das hierfür in besonderer
Weise geeignet ist und den Klausurcharakter der ersten acht Tagungen in
Velen/ Westfalen aufgreift.
Der DGMK-Fachbereich Kohlen- und Biomasseveredlung ruft mit diesem
»Call for Papers« alle Fachleute auf, sich mit Beiträgen zu beteiligen. Er
bittet zunächst um Übersendung eines Abstracts von max. einer DIN A4Seite. Das Organisationskomitee wird aus den eingegangenen Beiträgen
Vorträge und Poster für das Programm der Tagung auswählen.
Bitte benutzen Sie zur Abfassung des Abstracts die auf unserer Website
www.dgmk.de verfügbare Formatvorlage. Wir beabsichtigen, die eingegangenen Abstracts mit dem Programm im Internet zu veröffentlichen.
Einsendeschluss für vorgeschlagene Beiträge ist der 15. Januar 2016.
Sie sind per Email [email protected] an die DGMK-Geschäftsstelle zu
richten.
Weitere Informationen erhalten Sie von der DGMK-Geschäftsstelle: Frau Dr.
H. Doloszeski, Überseering 40, D-22297 Hamburg,
Tel. 040 639004 71, email: [email protected]
Bitte beachten Sie, dass auch die Autoren die Teilnehmergebühr entrichten
müssen.
Organisationskomitee:
R. Abraham, Dortmund; Prof. Dr. F. Behrendt, Berlin; Dipl.-Ing. D. Bräkow,
Berlin; Dr. H. Doloszeski, Hambur; Dr.-Ing. R. Elsen, Essen; Prof. Dr. M.W.
Haenel, Mülheim a.d.R.; Prof. Dr. W. Klose, Berlin; Dr. S. Krzack, Freiberg;
Dr. H.-J. Mühlen, Herten; Dr. M. Specht, Stuttgart
Veranstaltungen
Internationale »Student Technical Conference« in Wietze
Am 5. und 6. November trafen sich in Wietze
Studenten, Professoren und Experten aus
der Öl- und Gasindustrie zu
einer technischen Konferenz.
Die Studenten aus acht Nationen hatten hier eine Gelegenheit ihre Arbeiten zum
Thema Tiefbohrtechnik, Lagerstättentechnik, Geothermie und Geowissenschaften
einem Fachpublikum zu präsentieren. Das Erdölmuseum
in Wietze gab dieser Veranstaltung einen besonderen
Rahmen. Nur wenige der
Teilnehmer wussten, dass in
Wietze die Wiege der internationalen Ölförderung ist,
462
mit der ersten fündigen Ölbohrung noch vor
dem Ölboom in den USA. Außerdem wurde
in Wietze das Rotary- Drilling erfunden und
entwickelt, welches heute noch weltweit im
Einsatz ist.
Ausgerichtet wird diese einmal
pro Jahr stattfindende Veranstaltung von der Deutschen
Sektion der Society of Petrolem Engineers (SPE) mit Sitz in
Celle.
Trotz des niedrigen Ölpreises
und der damit wirtschaftlich
schwierigen Situation in diesem Geschäft fanden sich genügend Sponsoren um die Veranstaltung zu fördern. Hierzu
gehörten u. a. die Wintershall
sowie die DEA Deutsche Erdoel AG.
M. Heil
MITTEILUNGEN
Bericht über die
ordentliche Mitgliederversammlung 2015 der DGMK
am 13. November 2015 in Hamburg
Der Vorsitzende der DGMK, Herr Thomas
Rappuhn, übernahm die Sitzungsleitung.
Er eröffnete die ordentliche Mitgliederversammlung 2015 am 13. November 2015 um
15.00 Uhr in Hamburg. Er begrüßte 24 erschienene Mitglieder. Frau Dr. Teßmer
übernahm die Protokollführung.
Vor Eintritt in die Tagesordnung gedachte
die Mitgliederversammlung der verstorbenen Mitglieder:
Dipl.-Ing. Peter Chromik, Hannover
Prof. Dr.-Ing. habil. Heinz Gloth,
Freiberg
Dr. rer. nat. Wilhelm von Ilsemann,
Hamburg
Dipl.-Ing. Fred-Harald Linde-Suden,
Jever
Dr. rer. nat. Klaus Naumburg,
Bad Soden-Altenhain
Prof. Dr. rer. nat. Eberhard Plein,
Hannover
Dr.-Ing. Gerhard Schmidt, Schwedelbach
Dipl.-Ing. Karlheinz Schönemann,
Ronnenberg
Dr. Armin Schram, Hamburg
Dipl.-Berging. Karl-A. Stelter, Hannover
Dipl.-Ing. Peter K. Stiller, Sarstedt.
TOP 1
Eröffnung der Mitgliederversammlung
durch den Vorsitzenden der DGMK,
Herrn Thomas Rappuhn
Der Vorsitzende stellte fest, dass zur ordentlichen Mitgliederversammlung in der
Zeitschrift ERDÖL ERDGAS KOHLE,
Seite 326 (131. Jahrgang, Heft 9, September 2015) ordnungsgemäß gem. § 10 Abs. 3
der Satzung form- und fristgerecht eingeladen worden ist.
Anträge zur Mitgliederversammlung aus
dem Kreise der Mitglieder sind dem Vorstand nicht zugeleitet worden.
Gegen die den Mitgliedern mit der Einladung in der Zeitschrift ERDÖL ERDGAS
KOHLE zugegangene Tagesordnung wurden seitens der Versammlungsteilnehmer
keine Einwände erhoben. Ergänzungen zur
Tagesordnung wurden nicht gewünscht.
Der Vorsitzende stellte fest, dass keine Satzungsänderungen auf der Tagesordnung
stehen.
Zur Beschlussfähigkeit der Mitgliederversammlung stellte der Vorsitzende fest, dass
die Mitgliederversammlung nach § 10 Abs.
7 der Satzung daher uneingeschränkt
beschlussfähig ist.
Der Vorsitzende stellte fest, dass laut Eintragungsliste am Saaleingang 24 Mitglieder der DGMK erschienen sind.
TOP 2
Verabschiedung des DGMK-Jahresberichtes für 2014
Auf Empfehlung des Vorstandes verabschiedete die Mitgliederversammlung einstimmig ohne Aussprache den DGMK-Jahresbericht für 2014, siehe ERDÖL ERDGAS KOHLE, Seite 215–226 (131. Jahrgang, Heft 5, Mai 2015).
TOP 3
Entgegennahme des Berichtes der
Rechnungsprüfer und Feststellung der
Jahresabrechnung für das Geschäftsjahr vom 01. 01. 2014 bis 31. 12. 2014
Der Schatzmeister, Herr Dr. Ties Tiessen
verlas den Bericht der Rechnungsprüfer,
die nicht erscheinen konnten. Der Bericht
stellte Art und Umfang der von den Firmen
Wintershall Holding GmbH (Herr Jürgen
Scherf) und ExxonMobil Central Europe
Holding GmbH (Frau Marlies Schmetzer)
durchgeführten Prüfungen des Rechnungsabschlusses für 2014 dar. Nach dem Ergebnis dieser Prüfung bezeichneten die Rechnungsprüfer den Jahresabschluss der
DGMK für das Rechnungsjahr 2014 als
ordnungsgemäß.
Der Bericht wurde von der Mitgliederversammlung ohne Aussprache gebilligt. Die
Jahresabrechnung für 2014 wurde festgestellt; § 10 Abs. 1 der Satzung.
Der Vorsitzende sprach den beiden Rechnungsprüfern den Dank der Mitglieder für
ihre verantwortungsvolle Arbeit aus.
TOP 4
Entlastung des Vorstandes und der
Geschäftsführung für das Jahr 2014
Auf Antrag von Herrn Dr. Peter Seifried,
Seevetal, entlastete die Mitgliederversammlung ohne Aussprache einstimmig
den Vorstand für die Amtsführung im Jahre
2014; § 10 Abs. 1 der Satzung.
Des Weiteren entlastete die Mitgliederversammlung auf Antrag von Herrn Dr. Seifried einstimmig die Geschäftsführung für
die Amtsführung im Jahre 2014; § 10 Abs.
1 der Satzung.
TOP 5
Bericht des Vorstandes über die Entwicklung der Gesellschaft im laufenden
Jahr 2015”
Die Geschäftsführerin der DGMK, Frau
Dr. Gisa Teßmer, unterrichtete als Geschäftsführendes Vorstandsmitglied die
Versammlungsteilnehmer über Tätigkeiten
und Arbeitsergebnisse der Gesellschaft im
laufenden Jahr 2015.
In der Gemeinschaftsforschung werden
derzeit 58 Projekte bearbeitet. Davon entfallen 29 auf den Fachbereich Aufsuchung
und Gewinnung und 29 auf den Fachbereich Verarbeitung und Anwendung.
Die im laufenden Jahr durchgeführten Veranstaltungen sind alle sehr erfolgreich verlaufen. Für das kommende Jahr sind bereits
wieder fünf Tagungen in der Planung.
Der Urban-Verlag, in dem seit 1985 die Organzeitschrift der DGMK, ERDÖL ERDGAS KOHLE erscheint, wurde an den Verlag Moderne Industrie verkauft. Damit endet die Geschichte des Urban-Verlags, der
seit 1971 von der Familie Vieth geführt
wurde. Frau Dr. Teßmer dankte Herrn Thomas Vieth für die gute Zusammenarbeit in
den letzten 20 Jahren.
Frau Dr. Teßmer berichtete über eine Ehrung der Gesellschaft. Der Georg-Hunaeus-Preis 2015 wurde an Herrn Dr. Jonas
Wegner verliehen.
Frau Dr. Teßmer schloss ihren Bericht mit
dem Dank an alle, die ehrenamtlich in den
Gremien der DGMK und in den Bezirksgruppen mitarbeiten und an die Mitarbeiter
in der DGMK-Geschäftsstelle.
TOP 6
Bericht des Vorstandes über die Finanzlage der Gesellschaft mit Ausblick auf
2016 und Genehmigung des Haushaltsplanes für 2016; Erlass einer Beitragsordnung für 2016
Herr Dr. Tiessen gab einen Überblick über
die Abschlusszahlen zum 30.09.2015 und
die vom Vorstand vorgelegten Haushaltszahlen für 2016, siehe dazu Tabelle 1. Die
Finanzentwicklung im laufenden Jahr ist in
Einnahmen und Ausgaben überwiegend
plangemäß. Der Haushaltsplan für das Jahr
2016 sieht insgesamt einen Abbau des
Kassenbestandes vor.
Der Vorstand empfahl der Mitgliederversammlung, die Beitragshöhe des Jahres
463
MITTEILUNGEN / PERSÖNLICHES
Tabelle 1 DGMK-Haushaltsplanung für 2016 – Gesamtübersicht über Einnahmen
und Ausgaben nach Arbeitsgebieten (Teilhaushalten)
Ausgaben,
Tabelle 2 DGMK- Beitragssätze für das Jahr 2016
T EUR
331
269
Fachbereich Aufsuchung und Gewinnung
1.368
1.323
Fachbereich Verarbeitung und Anwendung
1.124
1.105
509
491
Fachbereich Petrochemie
47
45
Fachbereich Kohlenveredlung
51
48
Deutsches Nationalkomitee des
Welt-Erdöl-Rates (DNK)
15
18
Gesamt-Konsolidierung
Mindereinnahmen
3.445
3.299
0
146
Summe
3.445
3.445
Zentralaufgaben
Fachausschuss Mineralöl- und
Brennstoffnormung (FAM)
2015 unverändert für das Jahr 2016 zu
übernehmen; siehe dazu Tabelle 2.
Nach diesem Bericht beschloss die Mitgliederversammlung einstimmig auf Vorschlag
des Vorstandes den vorgelegten Haushaltsplan für 2016 wie in Tabelle 1 angegeben
und die Beitragsordnung für 2016 wie in
der Tabelle 2 angegeben; § 10 Abs. 1 der
Satzung.
TOP 7
Wahl von Vorstandsmitgliedern
Am 31. 12. 2015 endet die satzungsgemäße
Amtszeit von Herrn Dr. Reinhold Elsen als
Leiter des Fachbereiches Kohlen- und Biomasseveredlung und Mitglied des Vorstandes. Auf Vorschlag des Vorstandes wählte
die Mitgliederversammlung bei offener
Wahl mit einer Enthaltung Herrn Dr. Elsen
für die Amtszeit vom 01. 01. 2016 bis 31.
12. 2019 erneut zum Leiter des Fachbereiches Kohlen- und Biomasseveredlung und
Mitglied des Vorstandes der DGMK, § 11
Abs.3 und § 13 Abs. 4 der Satzung.
Herr Dr. Elsen nahm die Wahl an.
Jahresbeitrag 2015,
Einnahmen,
T EUR
EUR
Vollzahlende persönliche Mitglieder
75,00
Studierende Mitglieder
15,00
Doppelmitglieder
58,00
Mitglieder im Ruhestand
43,00
Firmen
1.100,00
Mitgliedsverbände/Interessenvereine
330,00
Behörden sowie Körperschaften und
Anstalten des öffentlichen Rechts,
wissenschaftliche Institute sowie
85,00
kleine und mittlere Unternehmen
TOP 8
Berufungen in den Wissenschaftlichen
Beirat
Am 31. 12. 2015 endet die satzungsgemäße
Amtszeit von Herrn Prof. Dr. Bernhard
Cramer und Herrn Prof. Dr.-Ing. Georg
Schaub als Mitglieder des Wissenschaftlichen Beirats der DGMK. Der Vorstand
schlug vor, Herrn Prof. Cramer für die
Amtszeit vom 01. 01. 2016 bis 31. 12. 2019
erneut in den Beirat zu berufen.
Der Vorstand schlug des Weiteren vor, die
Herren Prof. Dr.-Ing. Andreas Jess, Universität Bayreuth und Dr. Volker Steinbach,
Bundesanstalt für Geowissenschaften und
Rohstoffe, für die Amtszeit vom 01. 01.
2016 bis zum 31. 12. 2019 in den Wissenschaftlichen Beirat zu berufen, § 15 Abs. 3
der Satzung.
Die Mitgliederversammlung beschloss die
vorgeschlagenen Berufungen ohne Gegenstimmen.
Herr Dr. Steinbach nahm die Berufung an.
Die Herren Prof. Cramer und Prof. Jess hatten vor der Sitzung erklärt, dass sie die Berufung annehmen würden.
Der Vorsitzende dankte dem ausscheidenden Herrn Prof. Schaub für seine Mitarbeit.
und Bildung verstärkt dem Ausbau des Geothermie-Wissensnetzwerks widmen.
ausgezeichnet, dem höchsten Ehrenpreis
des Bundesverbandes Geothermie.
Patricius Plakette geht an
Horst Rüter
Wechsel an der Spitze des
Aufsichtsrats der VNG AG
Prof. Dr. Horst Rüter wurde auf dem diesjährigen Geothermiekongress DGK 2015
für seine Verdienste auf dem Gebiet der Vernetzung von nationalen und internationalen
Wissensträgern und seine richtungsweisenden Leistungen bei der Entwicklung innovativer Methoden zu seismischen Untergrunduntersuchungen mit der Patricius-Plakette
In der Aufsichtsratssitzung der VNG – Verbundnetz Gas Aktiengesellschaft (VNG) am
10. November wurde Ulf Heitmüller, Leiter
der Geschäftseinheit Handel der EnBW
Energie Baden-Württemberg AG, zum neuen Vorsitzenden des Aufsichtsrates der Gesellschaft gewählt. Heitmüller gehört dem
TOP 9
Wahl der Rechnungsprüfer für das
Rechnungsjahr 2016
Auf Vorschlag des Vorstandes wählte die
Mitgliederversammlung nach vorangegangener Zustimmung der betroffenen Unternehmen nach § 17 der Satzung einstimmig
die DGMK-Mitglieder DEA Deutsche Erdoel AG und Shell Deutschland Oil GmbH
zu Rechnungsprüfern für das Jahr 2016.
TOP 10
Verschiedenes
Der Vorsitzende sprach den Mitarbeitern
der DGMK, den Mitwirkenden in den Gremien und seinen Vorstandskollegen seinen
Dank für die gute Arbeit und das Engagement aus.
Mit einem Dank an alle Anwesenden beendete der Vorsitzende die ordentliche Mitgliederversammlung 2015 der DGMK um
16.00 Uhr.
Persönliches
Neues Präsidium des Bundesverbandes Geothermie gewählt
Die Mitgliederversammlungen des Bundesverbandes hat ein neues Präsidium gewählt.
Einstimmig wiedergewählt wurden Präsident Dr. Erwin Knapek, seine Stellvertreter
Lutz Stahl und Leonhard Thien sowie
Schriftführerin Inga Moeck. Der neue und
alte BVG-Präsident bedankte sich herzlich
bei Horst Rüter, der nach langjähriger Amtszeit aus dem Präsidium ausschied. Rüter
will sich in der kommenden Amtszeit als
Sprecher des Fachausschusses Wissenschaft
464
Fortsetzung auf nächster Seite
PERSÖNLICHES / MITTEILUNGEN
Kontrollgremium der VNG AG im Rahmen
eines persönlichen Mandats seit 16. Dezember 2014 an. Er folgt auf Dr. Heiko Sanders,
der zum 30. September 2015 aus dem Vorstand der EWE AG (Oldenburg) ausgeschieden ist und den Vorsitz im Aufsichtsrat der
VNG AG niedergelegt hatte.
Hanns-Hofmann-Preis 2015 geht an
Erik von Harbou
Den Hanns-Hofmann-Preis der ProcessNetFachgruppe Reaktionstechnik erhält Jun.Prof. Dr.-Ing. Erik von Harbou von der TU
Kaiserslautern für seine herausragenden
Leistungen auf dem Gebiet der Aufklärung
komplexer chemischer Prozesse und deren
Zusammenspiel mit der Fluidverfahrenstechnik und der Thermodynamik.
Die Forschung von Erik von Harbou verbindet grundlegende methodische Arbeiten mit
der Untersuchung wichtiger praktischer
Fragestellungen. Dabei liegt der Schwerpunkt auf Themen der Reaktionstechnik, die
in Zusammenhang mit fluidverfahrenstechnischen und thermodynamischen Fragen
stehen. Von Harbou kombiniert Experimente mit fortschrittlichen Methoden der Modellierung und Simulation. Die Arbeiten haben zu zahlreichen wissenschaftlichen Publikationen geführt, haben aber auch eine
hohe Praxisrelevanz; das belegen die zahlreichen Industriekooperationen, an denen
Erik von Harbou beteiligt ist.
Mitteilungen des FAM
Mit Datum Oktober 2015 ist folgende Norm
herausgegeben worden, die im Verantwortungsbereich des FAM liegt:
DIN 51454
Prüfung von Schmierstoffen – Bestimmung von
Kraftstoffanteilen in gebrauchten Motorenölen –
Gaschromatographisches Verfahren
als Ersatz für DIN 51454:2015-06
Mit Datum Oktober 2015 sind folgende
Norm-Entwürfe herausgegeben worden, die
im Verantwortungsbereich des FAM liegen:
E DIN EN ISO 22854
Flüssige Mineralölerzeugnisse – Bestimmung der
Kohlenwassertoffgruppen und der sauerstoffhaltigen
Verbindungen in Kraftstoffen für Kraftfahrzeugmotoren und in Ethanolkraftstoff (E85) – Multidimensionales gaschromatographisches Verfahren (ISO/
FDIS 22854:2015); Deutsche und Englische Fassung
FprEN ISO 22854:2015
als Ersatz für DIN EN ISO 22854:2014-07
E DIN 51810-3
Prüfung von Schmierstoffen – Prüfung der rheologischen Eigenschaften von Schmierfetten – Teil 3: Bestimmung der Fließgrenze mit der Kippstabmethode
Mit Datum November 2015 sind folgende
Normen herausgegeben worden, die im Verantwortungsbereich des FAM liegen:
DIN EN 116
Dieselkraftstoffe und Haushaltheizöle – Bestimmung
des Temperaturgrenzwertes der Filtrierbarkeit – Verfahren mit einem stufenweise arbeitenden Kühlbad;
Deutsche Fassung EN 116:2015
als Ersatz für DIN EN 116:1998-01
DIN EN ISO 6743-4
Schmierstoffe, Industrieöle und verwandte ErzeugERDÖL ERDGAS KOHLE, 131. Jg. 2015, Heft 12
Bei der DGMK in Hamburg ist die Position
Wissenschaftlicher Referent (m/w)
Aufsuchung und Gewinnung
zum 1. Januar 2016 oder später zu besetzen.
Die DGMK ist die zentrale Anlaufstelle für den wissenschaftlichen/technischen
Informations- und Erfahrungsaustausch und für die Gemeinschaftsforschung im
Bereich Aufsuchung und Gewinnung von Erdöl und Erdgas.
Das Aufgabengebiet umfasst:
Betreuung der Projekte der DGMK-Gemeinschaftsforschung von der Projekteinreichung bis zum Projektabschluss, insbesondere: Projektkommunikation,
Organisation von Projekttreffen, Überwachung der Zeitplanung, Redigieren von
Berichten
Mitarbeit bei der Organisation der Frühjahrstagung der DGMK, insbesondere bei
der Erstellung des wissenschaftlichen Programms, beim Redigieren der Autorenmanuskripte für den Tagungsberichtsband und bei der Durchführung der Tagung
Übernahme von Aufgaben in der Mitgliederbetreuung/Mitgliederkommunikation
Anforderungen:
Abgeschlossenes Hochschulstudium, vorzugsweise Geowissenschaften oder
Petroleum Engineering, Bereitschaft und Fähigkeit in einem kleinen Team mitzuarbeiten, Flexibilität, Eigeninitiative, gute Kommunikationsfähigkeit, Organisationstalent, souveräne Beherrschung der deutschen Sprache in Wort und Schrift
Die Stelle ist vorerst auf ein Jahr befristet. Bewerbungen werden bis zum
15. Dezember 2015 erbeten, gerne auch per Email.
Kontakt: Dr. Gisa Teßmer, Überseering 40, 22297 Hamburg,
[email protected], Tel. (040)63900411
nisse – (Klasse L) – Klassifizierung – Teil 4: Familie
H (Hydraulische Systeme) (ISO 6743-4:2015); Deutsche Fassung EN ISO 6743-4:2015
als Ersatz für DIN EN ISO 6743-4:2002-04
Mit Datum November 2015 sind folgende
Norm-Entwürfe herausgegeben worden, die
im Verantwortungsbereich des FAM liegen:
E DIN 51821-1
Prüfung von Schmierstoffen – Prüfung von Schmierfetten auf dem FAG-Wälzlagerfett-Prüfgerät FE9 –
Teil 1: Allgemeine Arbeitsgrundlagen
vorgesehen als Ersatz für DIN 51821-1:1988-01
E DIN 51821-2
Prüfung von Schmierstoffen – Prüfung von Schmierfetten auf dem FAG-Wälzlagerfett-Prüfgerät FE9 –
Teil 2: Prüfverfahren A/1500/6000
vorgesehen als Ersatz für DIN 51821-2:1989-03
E DIN 51808
Prüfung von Schmierstoffen – Bestimmung der Oxidationsbeständigkeit von Schmierstoffen – Sauerstoff-Verfahren
vorgesehen als Ersatz für DIN 51808:1978-01
(zurückgezogen 2013-01)
E DIN 51575
Prüfung von Mineralölen – Bestimmung der Sulfatasche; vorgesehen als Ersatz für DIN 51575:2011-01
Mit Datum Dezember 2015 ist folgender
Norm-Entwurf herausgegeben worden, der
im Verantwortungsbereich des FAM liegt:
E DIN 51577-5
Prüfung von Schmierölen – Bestimmung
des Chlorgehaltes – Teil 5: Direkte Bestimmung durch optische Emissionsspektralanalyse mit induktiv gekoppeltem Plasma (ICP
OES)
Mitteilungen der
DGMK • ÖGEW
Neue Mitglieder
Dipl.-Ing. Sebastian Boor, Hannover
Annelies de Cuyper, TU Kaiserslautern,
Kaiserslautern
Dipl.-Ing. Reinhard Decher, Reinhard
Decher Gas-Engineering, Rockenberg
Chris Dontje, Balance Point Control BV,
NL- Emmen
DSG Drilling Solutions GmbH, Nordhorn
Stephan Estel, Dichtelemente Hallite
GmbH, Hamburg
Robert Frase, IAV GmbH, Ingenieurgesellschaft Auto und Verkehr, Gifhorn
Dipl.-Kfm. Jan-Martin Gonsior, MIDCO
Deutschland GmbH, Celle
Thomas Gröger, Helmholtz Zentrum
München, Oberschleißheim
Daniel Günther, Geophysik GGD mbH,
Leipzig
Frank Guthke, Wintershall Holding GmbH,
Kassel
Anthony Habash, Clausthal-Zellerfeld
Frederic Hildebrand, Clausthal-Zellerfeld
Dipl.-Ing. Karin Hofstätter, Barnstorf
Inera Tec-Innovative Chemical Reactor
Technologies, Eggenstein-Leopoldshafen
Paul Kangowski, Aachen
Holger Kinzel, planxty engineering & consulting Services GmbH, Peine
Jan König, Micon-Drilling GmbH, Nienhagen
465
MITTEILUNGEN
Anton Lehner, A-Gänserndorf
Hannah Lieder-Wolf, Hannover
Dipl.-Ing. Eckard Malt, DEA Deutsche
Erdoel AG, Hamburg
Benjamin Mees, CropEnergies AG, Mannheim
Nils Michel, Air Liquide Global E&C
Solutions Germany GmbH, Frankfurt am
Main
Christian Roth, TU Kaiserslautern,
Kaiserslautern
Reinhard Rothe, Vermillion Energy
Germany GmbH, Schönefeld
Dipl.-Ing. Karlheinz Russ, TÜV Süd
Industrie Service GmbH, Karlsruhe
Dipl.-Ing. Ralf Schairer, MiRO Mineralölraffinerie Oberrhein GmbH, Karlsruhe
Dr. Andreas Scheck, Wintershall Holding
GmbH, Barnstorf
Maxim Schubert, PVG GmbH, Gelsenkirchen
Martin Schuster, GWE Pumpenboese
GmbH, Peine
Dipl.-Ing. Jacobus Steijn, EWE Gasspeicher
GmbH, Oldenburg
Patrick Urban, Winsen/Aller
Dipl.-Ing. Ullrich Wältken, 5P Energy
GmbH, Hannover
David Wunsch, Corsyde Int. GmbH & Co.
KG, Berlin
Dipl.-Ing. Nirmal Sinha, Celle-Altencelle, 81 Jahre
Dipl.-Phys. Hermann Arens, Lingen, 75 Jahre
Dipl.-Ing. Walter Baudy, Hatzenbühl, 65 Jahre
Rainer Fahlbusch, Hannover, 55 Jahre
Dipl.-Ing. Dieter Simons, Celle, 80 Jahre
Dr. Birgit Müller, Lauffen, 55 Jahre
Dipl.-Volkswirt Heino Elfert, Bardowick, 80 Jahre
Dipl.-Ing. Albrecht Möhring, Schönefeld, 60 Jahre
Dipl.-Ing. Rainer Wilhelm, Lehrte, 65 Jahre
Dipl.-Geol. Reinhold Graf, Lachendorf, 60 Jahre
Dipl.-Ing. Alfons Heitker, Lingen/Ems, 80 Jahre
Dipl.-Geol. Helge Kreutz, Mölln, 60 Jahre
Alfred Idas, Hamburg, 85 Jahre
Dr. Günter Stober, Müllheim, 88 Jahre
Dipl.-Ing. Claus Chur, Nordhorn, 65 Jahre
Prof. Dr. Jürgen Gmehling, Oldenburg, 70 Jahre
Dipl.-Ing. Kurt Sackmaier, Barnstorf, 55 Jahre
Dr. Reinhard Gast, Havetoftloit-Dammholm, 65 Jahre
Dipl.-Ing. H.-E. Hartz, Rosengarten, 81 Jahre
Dr. Horst-Werner Zanthoff, Mülheim a. d. Ruhr, 55 Jahre
Dr. rer. nat Herbert Engelke, Salzbergen, 82 Jahre
Dipl.-Ing. Ulrich Moldenhauer, Köln, 85 Jahre
Dipl.-Ing. Heiner Ribbeck, Salzwedel, 70 Jahre
Prof. Dr. Dipl.-Chem. Rolf-D. Behling, Hamburg, 86 Jahre
Dr.-Ing. Thomas Franzen, Schweinfurt, 50 Jahre
Dr. Dipl.-Chem. Karl Michaelis, Ingolstadt, 89 Jahre
Dr.-Ing. Reinhard Hanisch, Eulau, 60 Jahre
Dr. H. Gondermann, Bochum, 86 Jahre
Prof. Dr. rer. nat. Christian Jentsch, Lübeck, 80 Jahre
Prof. Dr. Dr. h. c. Dietrich H. Welte, Aachen, 81 Jahre
Dr. Iulia Ghergut, Göttingen, 50 Jahre
Dr. Manfred G. Bullinger, Hamburg, 65 Jahre
Dipl.-Ing. Friedrich Heyer, Deisenhofen, 65 Jahre
Dipl.-Ing. Wolfgang Schaefer, Ahrensburg, 82 Jahre
Dr.-Ing. Holger Depner, Karlsruhe, 50 Jahre
Burkhard Helmig, Oelde, 55 Jahre
Dr. Dipl.-Chem. Johannes Elster, Hamburg, 87 Jahre
Dipl.-Ing. Wolfgang Roth, Mittenwalde, 60 Jahre
Ralf Heyen, Braunschweig, 50 Jahre
Rolf Goldowsky, Neuss, 55 Jahre
Dipl.-Ing. Joachim Hof, Stuttgart, 60 Jahre
466
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Black Sea and Mediterranean
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Internationale Fachmesse und Konferenz
16. - 17. März 2016 • Ankara, Türkei
22. - 23. September 2016 • Athen, Griechenland
ehemals
TUROGE
Global Oil&Gas Turkey
Global Oil&Gas Atyrau
ehemals Atyrau
Oil & Gas
15. Nordkaspische regionale
24. Internationale Öl- und Gasmesse und -konferenz
Ausstellung für Öl und Gas
12. - 14. April 2016 • Atyrau, Kasachstan
Global Oil&Gas Atyrau
Conference
KIOGE Kazakhstan
ehemals Oiltech
Atyrau
04. - 07. Oktober 2016 • Almaty, Kasachstan
PCVExpo
15. Internationale Fachmesse für Pumpen, Kompres-
10. Nordkaspische Konferenz für Erdöltechnologie
soren, Ventile, Servomotoren und Antriebssysteme
12. - 13. April 2016 • Atyrau, Kasachstan
25. - 27. Oktober 2016 • Moskau, Russland
OGU Uzbekistan
Global Oil&Gas Mangystau
20. Internationale Öl- und Gasmesse
10. Regionale Fachmesse für Öl und Gas
und -konferenz
18. - 20. Mai 2016 • Taschkent, Usbekistan
Global Oil&Gas Myanmar
ehemals
Mangystau Oil&Gas
ehemals Myanmar
Oil & Gas
08. - 10. November 2016 • Aktau, Kasachstan
OGT Turkmenistan
3. Öl- und Gaskonferenz
21. Internationale Öl & Gas Konferenz
19 - 20. Mai 2016 • Yangun, Myanmar
November 2016 • Ashgabat, Turkmenistan
Caspian Oil&Gas Azerbaijan
MIOGE Moscow
23. Internationale Fachmesse und
Konferenz für die Öl- und Gasindustrie
01. - 04. Juni 2016 • Baku, Aserbaidschan
14. Internationale Öl- und Gasmesse
27. - 30. Juni 2017 • Moskau, Russland
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Änderungen vorbehalten
2015 / 2016 -6.0

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