tapchi dau khi

Transcription

tapchi dau khi

VIETNAM
PETRO
Petro ietnam
An Official Publication of The Vietnam National Oil and Gas Group Vol 10 - 2010
ISSN-0866-854X
Geological evolution and aspects of the
petroleum potential of the underexplored
parts of the Vietnamese margin
PETROVIETNAM JOURNAL IS PUBLISHED MONTHLY BY VIETNAM NATIONAL OIL AND GAS GROUP
Contents
PETROLEUM EXPLORATION & PRODUCTION (2 - 49)
Geological evolution and aspects of the petroleum potential of the
underexplored parts of the Vietnamese margin
Recovery Mechanisms and Oil Recovery from a Fractured Basement
Reservoir, Yemen
Advancements in Basement Logging While Drilling (LWD) Techniques for
Formation Evaluation
Determination of shale resistivity based on 2-D geoelectric forward
modelling for evaluation of a low resistivity formation
Editor-in-chief
Dr.Sc. Phung Dinh Thuc
Deputy Editor-in-chief
Dr. Nguyen Van Minh
Dr. Phan Ngoc Trung
Dr. Vu Van Vien
Members of the Editorial
Board
Dr. Hoang Ngoc Dang
Dr. Nguyen Anh Duc
BSc. Vu Xuan Lung
Dr. Vu Thi Bich Ngoc
Dr. Hoang Quy
MSc. Le Ngoc Son
Eng. Hoang Van Thach
MSc. Nguyen Van Tuan
Dr. Le Xuan Ve
Dr. Phan Tien Vien
PETROLEUM PROCESSING (50 - 53)
Study of treating waste cooking oil for biodiesel synthesis using
heterogeneous catalyst Na2CO3/Al2O3
PETROLEUM TECHNOLOGY & CONSTRUCTION (54 - 70)
Applicability of GTL technology in Vietnam
Managing editor
MSc. Le Van Khoa
BSc. Vu Van Huan
Editorial office
16 th Floor, VPI Tower,
Trung Kinh Street,
Yen Hoa Ward, Cau Giay
District, Ha Noi
Tel: 84.04.37727108
Fax: 84.04.37727107
Mobile: 0982288671
Email: [email protected]
Float - over technology - A project enabler
POWER TECHNOLOGY (71 - 78)
Permanent mode analyses for the distribution
grid interconnection of a renewable energy
NEWS (79 - 84)
Rusvietpetro starts pumping oil in Russia
Russia to provide ESPO crude oil for Vietnam
Designed by
Le Hong Van
Dung Quat Refinery: Installing successfully blending crude
Seminar highlights safety in oil & gas industry
Publishing Licences No. 170/GP - BVHTT dated 24/04/2001; No. 20/GP - S§BS 01, dated 01/07/2008
PETROLEUM EXPLORATION & PRODUCTION
Geological evolution and aspects of the
petroleum potential of the underexplored
parts of the Vietnamese margin
M.B.W. Fyhn, L.H. Nielsen, H.I. Petersen, A. Mathiesen, L.O. Boldreel,
J.A. Bojesen-Koefoed, H.P. Nytoft, C. Andersen, N.A. Duc, P.T. Dien, N.T. Huyen
L.T. Huyen, N.T. Dau, L.C. Mai, L.D. Thang, H.A. Tuan, D.T. Huong, T.T.T. Nhan
P.F. Green, S. Lindström, S.A.S. Pedersen, D. Frei, L.V. Hien, I. Abatzis
MBWF: Geological Survey of Denmark and Greenland (GEUS)
Abstract
The Vietnamese margin includes a series of underexplored basins with a significant hydrocarbon
potential. The origin and the petroleum potential of the Song Hong, Phu Khanh, Malay - Tho Chu and the
Phu Quoc basins have been assessed by the ENRECA-group and new models are proposed.
Jurassic to Cretaceous Palaeo-Pacific subduction resulted in the creation of a magmatic arc that now
underlies part of the Vietnamese margin. The Phu Quoc basin formed in response to the build-up of the
magmatic arc. During the Paleocene - Early Eocene, plate collision terminated the subduction process
and resulted in inversion of the Phu Quoc basin.
Eocene - Oligocene left-lateral strike-slip faulting along the margin resulted in rifting and source-rock
deposition. Neogene thermal subsidence dominated in all but the Southern Phu Khanh basin and marine
deposition prevailed due to opening of the East sea. This resulted in widespread Miocene carbonate deposition along the East Vietnamese margin, whereas clastic deposition ruled in basins farther from open
seaways. Magmatism affected the margin from the Early Neogene and the associated Late Neogene
onshore uplift and denudation promoted offshore sedimentation rates.
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PETROVIETNAM JOURNAL VOL 10/2010
PETROVIETNAM
In the Phu Khanh basin oil seepages and an offshore oil discovery prove the presence of active petroleum systems. Source-rock maturation and petroleum expulsion occurred during the Late Neogene as
rapid sedimentation deeply buried source-rock intervals. In the northern Song Hong basin Miocene coals
and Palaeogene lacustrine source rocks are presently oil and gas generative, which has allowed time for
traps to form.
In the Malay - Tho Chu basin maturation modelling and FAMM analyses suggest that oil generation
peaked during the Middle Neogene and that the primary risks for the tested Miocene plays are oil expulsion prior to trap formation, migration pathways complicated by faulting and the distribution and amount
of matured source rocks in smaller grabens.
Introduction
1. Tectonic development
The Vietnamese margin is floored by a number of
sedimentary basins with a considerable petroleum
potential (Fig. 1). Most of these basins are in an early
state of exploration and the overall understanding of
their development is still limited. Geological information on the Vietnamese margin is fundamental both to
the evaluation of the petroleum potential of the area,
and the understanding of the geological development
of greater parts of SE Asia including the amalgamation
of SE Asia, the creation of the East sea and the farfield effects of the India-Eurasia collision (Tapponnier
et al. 1986; Briais et al. 1993; Rangin et al. 1995a;
Matthews et al. 1997; Lee & Watkins 1998; Nielsen et
al. 1999; Lee et al. 2001; Hall & Morley 2004;
Andersen et al. 2005; Fyhn et al. 2009a; b; 2010a; b;
Petersen et al. 2010).
1.1. Mesozoic to earliest Cainozoic ARC magmatism and foreland basin formation
A joint research group from the Geological Survey
of Denmark and Greenland (GEUS), Vietnam
Petroleum Institute (VPI) and universities in Denmark
and Vietnam has since 1995 worked to asses the geology and petroleum potential of the Vietnamese basins
based on analysis of vast amounts of seismic and
gravimetric data, basin modelling and analysis of well
data, source rocks and information from onshore outcrops, core holes, and seep oils. This study throws
light on the structural and stratigraphic development of
the Vietnamese margin addressing the regional tectonic mechanism driving the evolution of the Song
Hong, the Phu Khanh, the Malay - Tho Chu and the
Phu Quoc basins. The hydrocarbon potential of these
underexplored basins outlining the margin is similarly
addressed.
After the early Triassic the Sundaland core of SE
Asia had accreted through welding of Gondwana
derived continental fragments (Metcalfe 1996; Sone &
Metcalfe 2008). During the succeeding part of the
Mesozoic period Sundaland constituted a large
promontory bordered by the Tethys Ocean to the West
and the Palaeo - Pacific (Panthalassa) to the East (Fig.
2a). Vietnam outlines the eastern part of Sundaland and
Jurassic and Cretaceous Westwards subduction of
Panthalassa along E and SE Asia resulted in arc magmatism in a belt stretching from Japan across Vietnam
to Borneo (Fyhn et al. 2010b). The igneous basement in
the Cuu Long, the Nam Con Son and the Phu Khanh
basins and in the adjoining parts of Vietnam forms part
of this Jurassic to Cretaceous magmatic arc.
East of the igneous belt the Jurassic to Cretaceous
Phu Quoc basin stretching from Central Cambodia to
the central part of the gulf of Thailand formed as a
retroarc foreland basin linked with the build up of the
neighbouring magmatic arc. The Phu Quoc basin and
the coeval Khorat basin formed part of a larger continuous basin that became segmented due to Early
Palaeogene inversion and erosion (Fyhn et al. 2010b).
Basin inversion is indicated by a prominent angular
unconformity that caps the basin fill and is associated
with spectacular thrust faulting and folding. The structural complexity increases towards two deeply eroded
and more than 500 km long fold belts that confine the
basin to the East and West (Fig. 3). The level of eroPETROVIETNAM JOURNAL VOL 10/2010
3
sion becomes deeper towards these orogenic belts.
Palaeozoic and Lower Mesozoic igneous and sedimentary rocks therefore crop out on small islands and
onshore the mainland or subcrop towards the base of
the Cainozoic within the Kampot Fold Belt flanking the
basin to the East. Apatite fission track analysis on rock
samples from the Kampot Fold Belt demonstrate Late
Paleocene - Early Eocene uplift and denudation of
the area occurring in response to thrust faulting and
basin inversion. The contemporary shut-down of
Vietnamese arc magmatism and the suturing of the
Luconia Block to Borneo could indicate that the inversion was forced by the accretion of Luconia towards
Sundaland (Fig. 2b) (Fyhn et al. 2010a).
1.2. Eocene - Oligocene rifting and inversion
Mid-Cainozoic extension was focused within a
number of rift basins that fringe the Vietnamese margin. Eocene syn-rift sediments constitute the oldest
deposits encountered within these basins and indicate
the time of incipient rifting.
1.2.1. East Vietnam boundary fault zone
Rifting along the north and central Vietnamese margin are closely related with strike-slip movements
across the East Vietnam Boundary Fault Zone (EVBFZ)
that forms the offshore continuation of the Red River
Shear Zone (Fig. 1). Large-scale left-lateral displacement took place across the shear zone as Indochina
was extruded away from the collision front in response
to India’s indentation into Eurasia (Tapponnier et al.
1986; Leloup et al., 2001; Fyhn et al., 2009a; b). Pullapart rifting in the super-deep Song Hong basin
occurred during the Eocene-Oligocene in response to
left-lateral motion across the EVBFZ outlining the Song
Hong basin (Fig. 1) (Rangin et al. 1995a; Nielsen et al.
1999, Andersen et al. 2005; Clift & Sun 2006; Zhu et al.
2009). In the central part of the Song Hong basin basement are buried well below conventional seismic
recording depth (8 sec TWT) (Nielsen et al. 1999).
Gravimetric and refraction seismic data suggest a 1520km thick Cainozoic succession and extreme crustal
thinning across the central part of the basin (Vejbæk et
al. 1997; Shimin et al. 2009).
Farther to the South the EVBFZ continues into the
Phu Khanh basin, transecting the Western part of the
basin (Fyhn et al. 2009a, b) (Fig. 4). The crust thins
4
dramatically towards the fault zone and is only a few
km thick along the EVBFZ in the basin (Fig. 5) (Fyhn
et al. 2009b). The nature of the pre-rift geology
changes across the EVBFZ. Landward from the fault
zone a drilled igneous basement exists below the
Cainozoic succession whereas a stratified preCainozoic succession reflecting (meta) sediments constitutes the basis of the Palaeogene syn-rift succession east of the EVBFZ (Figs 6, 7). This juxtaposition
of the pre-Cainozoic basin-floor types seems to reflect
an Eocene to Oligocene left-lateral offset of more than
100km across the EVBFZ in the basin (Fyhn et al.
2009a). Seaward from the fault zone the stratified
basin floor is deeply down-faulted and the base of the
syn-rift succession is situated below conventional seismic recording depth in large areas (Fig. 4, 7). Towards
the South the EVBFZ breaks up into discrete SE-wards
splaying segments along the Tuy Hoa Fault Zone that
marks the termination of one of the largest Cainozoic
continental strike-slip zones on Earth (Fig. 1).
Recurrent inversion affected the Song Hong basin
starting from the Mid-Oligocene. The inception of
inversion occurred contemporary with the onset of
uplift of metamorphic core complexes along the trail of
the Red River shear zone onshore. The onset of inversion denotes a change from intense rifting to moderate
rifting and thermal relaxation following the initial inversion pulse in the Song Hong basin. Left-lateral movement along the EVBFZ therefore seems to have culminated during Eocene - Mid-Oligocene time. In the Phu
Khanh basin a distinct unconformity along the trail of
the EVBFZ indicates uplift and erosion comparable to
the Mid-Oligocene uplift affecting the Song Hong
basin. Most of the East Vietnamese margin thus
seems to have been affected by inversion during MidOligocene time from the Song Hong basin in the North
to the Cuu Long basin in the South (Fyhn et al. 2009a).
Although rifting continued in a narrow zone along the
EVBFZ in the Phu Khanh basin, rift induced subsidence decreased away from the EVBFZ following the
uplift; and at the end of Oligocene time rifting significantly decreased in the Northern half of the basin and
rearranged farther to the South.
1.2.2. Tho Chu fault zone
The Tho Chu fault Zone (TCFZ) constitutes a
NNW-trending fracture zone that transects the
PETROVIETNAM
Vietnamese part of the Malay basin locally referred to
as the Malay - Tho Chu basin (Figs. 1, 8). The TCFZ
is the dominant U. Eocene - Oligocene structure in the
North-Eastern part of the gulf of Thailand but is paralleled by a set of other large fracture zones. The NNWtrending fracture zones form prominent Eocene Oligocene flower structures associated with subordinate WNW-trending normal faults suggestive of leftlateral strike-slip movements (Fig. 9).
The TCFZ runs along the trail of the Upper
Paleocene to Lower Eocene Khmer Fold Belt that can
be traced all the way to onshore central Thailand.
Even so, a Northward continuation of the TCFZ has
not been reported, and a direct link-up with a strand of
the Mai Ping or the Three Pagodas shear zone
onshore Thailand is speculative. Left-lateral movement may thus have occurred across a very broad
shear belt in the North-Eastern gulf of Thailand compared to that concentrated along the EVBFZ outlining
the north and central Vietnamese margin. However,
the kinematic timing and the structural style of the
TCFZ and the other parallel strike-slip lineaments in
the Malay - Tho Chu basin indicate a direct relationship with left-lateral faulting in the basin and left-lateral shearing onshore associated with the collision of
India and Eurasia.
1.2.3. Neogene faulting and thermal sagging
In the Song Hong basin Neogene faulting was
moderate compared to Eocene - Mid-Oligocene rifting.
Even so, a continued left-lateral tectonic regime into
the Miocene is indicated by the E-W-trending extensional fault pattern located in between the NW-trending basin bounding Song Chay and the Son Lo/Vinh
Ninh faults. In the Northern part of the Song Hong
basin folding and reverse faulting took place during the
Miocene peaking during Late Miocene time. This has
been interpreted to reflect a change from left- to rightlateral shearing along the EVBFZ in the area during
the Late Neogene (Rangin et al. 1995a; Nielsen et al.
1999; Andersen et al. 2005).
Rapid Neogene subsidence is indicated by the
profound Miocene-Recent succession filling the basin.
In widespread parts of the basin the post-rift thickness
is in excess of 10km, which in places causes the older
deposits to be buried below conventional seismic
recording depth.
In the Phu Khanh basin the thickness of the
Neogene and the depth of the sea increases to the
East as rapid Miocene-Recent thermal subsidence
took place in the seaward part of the basin as compared to farther shoreward.
Even though rifting decreased dramatically following the Oligocene in the Phu Khanh basin, significant
faulting took place during the Early and Middle
Miocene. Rifting was concentrated in the southern part
of the basin facing the Nam Con Son basin and the
oceanic spreading ridge that propagated towards the
two basins, and not focused along the EVBFZ as during the Eocene - Oligocene period. Early Neogene rifting in the basin thus seems associated with seafloor
spreading that took place independent from left-lateral
strike-slip movements along the margin.
Rifting in the Malay - Tho Chu basin decreased
significantly at the end of the Oligocene and thermal
sagging came to dominate. However, moderate
Neogene extensional rejuvenation of older structures
5
occurred in the basin with increasing intensity towards the Northwest. The
post-rift thickness in the Malay - Tho Chu basin generally increases
towards the SW but rarely exceeds 3km. This is due to the fact that the
Malay - Tho Chu basin only constitutes the marginal part of the Malay
basin with far greater post-rift thicknesses across the central part of the
basin located outside Vietnamese acreage.
1.2.4. Neogene volcanism, uplift and fast sedimentation rates
Widespread and voluminous volcanism affected the East Vietnamese
margin from the Western central part of the Song Hong basin and
Southwards. The offshore volcanism is linked with late Neogene onshore
volcanism based on their coincident timing and on the offshore continuation of Late Neogene volcanic provinces exposed onshore. This indicates
that the onshore volcanic region centred in Southern Indochina continued
offshore and that the intensity of offshore volcanism equalled with subsequent onshore volcanism. Based on seismic interpretation it seems that
the modern volcanic activity of Southeast Indochina initiated offshore during early Neogene time and subsequently broadened and intensified
onshore during the late Neogene (Fig. 2) (Hoang & Flower 1998; Lee et
al. 1998). Offshore magmatism often revitalized older fault systems, which
has also been noted with onshore volcanism (Rangin et al. 1995b; Fyhn et
al. 2009a).
From around the Late Miocene offshore depositional patterns
changed, sedimentation rates increased and local uplift took place (Fyhn
et al. 2009c). Onshore studies reveal the onset of major uplift and denudation during the same period of time, which has been linked to the intense
magmatism of the region (Carter et al. 2000). This most likely reflects that
the majority of the onshore basalts erupted during the latest Neogene following magmatic intensification onshore (Barr & Macdonald 1981; Rangin
et al. 1995b; Hoang & Flower 1998). Contrary, most offshore volcanism
peaked during Early to middle Late Miocene time and recent magmatism
seems restricted to the Con Son Swell and possibly the Southern part of
the Song Hong basin.
2. Depositional development
Outcrop studies of Cretaceous strata on the Phu Quoc Island and
onshore Cambodia complemented by analysis of the fully cored 500 m
deep ENRECA-2 well on the Phu Quoc Island indicate a prevalence of
sandstones in the Phu Quoc basin (Fyhn et al. 2010a). Alluvial sandstones
with an average of ca. 10% rhyolite-dominated lithic fragments make up
the primary content of the up to ca. 4km thick Upper Jurassic-Cretaceous
sediments filling the basin. Only a few thin shallow marine sandstone beds
have been encountered in the otherwise terrestrial succession. The sandstone dominated succession intercalates with subordinate alluvial plain
and lacustrine silt and mudstone intervals. Coal fragments are abundant
at specific stratigraphic levels, but do not posses any source potential.
6
PETROVIETNAM
The Cainozoic rift basins along the Vietnamese margin are filled by
thick and varied sedimentary successions. Seismic facies analysis supported by well data indicates the presence of a broad range of sediment
types in the basins, signifying changing Cainozoic depositional systems in
the region (Figs. 10, 11).
Non-marine depositional environments with estuarine interludes prevailed during the Palaeogene syn-rift period due to the immature development of the East sea. The syn-rift succession is therefore dominated by
alluvial, fluvial and lacustrine deposits, of which carbonaceous lake successions and humic coals constitute the primary source-rock type in the
area. Restricted marine incursions occur within the syn-rift interval suggesting periodic connections with either the proto-East sea or the
youngest East sea that initiated during the Early Oligocene.
A pronounced transgression occurred during the earliest Miocene as
the East sea expanded and gradually approached the Vietnamese margin.
Widespread subaerially exposed areas became inundated, which promoted carbonate platform growth from the central Song Hong basin to the
central Phu Khanh basin, while terrigenous alluvial and shallow marine
deposition prevailed in the Northern Song Hong, Southern Phu Khanh, the
Nam Con Son, the Cuu Long and the Malay basins located farther to the
South from the initial East sea (Fig. 10b).
Local uplift in part of the North-Western Phu Khanh basin in the Middle
Miocene caused subaerial exposure of Lower Miocene - lowest Middle
Miocene platform carbonates. Consequently, carbonate growth retreated
Northward and was replaced by terrigenous deposition. During the same
period, the continued opening of the East sea introduced open-marine
conditions in the southernmost part of the Phu Khanh basin, which instigated the growth and deposition of carbonates like in the Nam Con Son
basin. Carbonate growth in this area was interrupted due to the endMiddle Miocene uplift probably associated with the termination of seafloor
spreading (Fig. 10c) (Fyhn et al. 2009a).
Carbonate deposition re-established subsequently on the Northern
Con Son Swell bordering the Southern Phu Khanh basin, whereas deep
marine siliciclastic deposition came to prevail farther offshore in the Phu
Khanh basin similar to the situation in the central Nam Con Son basin (Fig.
10d). At the same time alluvial and shallow marine deposition dominated
in the Malay - Cho Thu basin that like the Cuu Long basin was located farther away from the open-marine part of the East sea.
The depositional pattern along the East Vietnamese margin changed
considerably as sediment supply increased around Late Miocene time in
response to the southeast Indochinese uplift (Fig. 10e). Carbonate deposition was impeded by subaerial exposure of the Phan Rang Carbonate
Platform that covered the Northern Con Son swell. Platform growth only
re-established patchily during the subsequent transgression as the input of
terrigenous matter and inorganic nutrients to the area increased signifiPETROVIETNAM JOURNAL VOL 10/2010
7
cantly (Fyhn et al. 2009c). Nutrification of the surface
waters along the Con Son swell was controlled mainly
by intense onshore erosion and an orographic induced
change of the summer monsoon that triggered seasonal upwelling along the Con Son swell.
Consequently, carbonate platforms drowned offshore
south and central Vietnam throughout the latest
Miocene and Early Pliocene times. Siliciclastic dominated deposition subsequently took over in previously
carbonate dominated areas. This led to the establishment of a prominent shelf slope along the central and
South Vietnamese margin that prograded tens of kilometres eastwards during the remaining part of the
Neogene and characterizes the modern outline of the
margin.
3. Petroleum geology
Cainozoic lacustrine mudstones and coals/coaly
mudstones are the principal source rocks in the
Vietnamese and adjacent Chinese basins (Todd et al.
1997; Petersen et al. 2004; Andersen et al. 2005;
Bojesen-Koefoed et al., 2005; 2009). Potential sourcerock analogues occur onshore. Total Organic Carbon
(TOC) content and Hydrogen Index (HI) values of
immature Cainozoic lacustrine mudstone analogues
from the Dong Ho area and from the ENRECA-1 well
drilled in the onshore Song Ba trough mainly range
from 4 to 20 wt% and from 300 to 700mg HC/g TOC,
respectively, indicating that the organic matter largly is
composed of algal-rich kerogen (Type I/II) and is comparable to the lacustrine source rocks encountered in
offshore wells (Table 1) (Petersen et al. 2001; 2004;
2005; 2010; Nielsen et al. 2007). Onshore humic coals
display HI values up to 350mg HC/g TOC, compatible
with those sampled in offshore wells suggesting a
potential for oil generation. Data from these onshore
source-rock analogues thus emphasize that mature
Cainozoic lacustrine mudstones and coals/coaly mudstones provide excellent source rocks for oil and gas
generation in the region. These source rocks are interpreted to be abundant in the Palaeogene syn-rift of the
Song Hong, Phu Khanh and Malay - Tho Chu basins,
and sporadically present in Miocene deposits based
on well data and seismic interpretation (Matthews et
al. 1997; Lee & Watkins, 1998; Nielsen et al. 1999;
2007; Lee et al. 2001; Andersen et al. 2005; Petersen
8
et al. 2004; 2009; 2010; Fyhn et al. 2009a; b; 2010b).
3.1. The Phu Khanh basin
Oil from Cainozoic marly source rocks is the most
common seep oil in the Dam Thi Nai lagoon but lacustrine seep oils, comparable to oils produced from fields
in the Cuu Long basin and oils encountered in wells in
the Song Hong basin, were sampled as well by the
ENRECA Group along the lagoonal coast (Traynor &
Sladen, 1997; Bojesen-Koefoed et al., 2005; Fyhn et
al. 2009b). Biological marker distribution of the prevailing Dam Thi Nai oil exhibits characteristics resembling
extracts of Miocene marly source rocks in the Nam
Con Son basin deposited near reefal and intra-reefal
settings (Traynor & Sladen, 1997; Bojesen-Koefoed et
al., 2005). A compatible Early Miocene fore-reef setting is interpreted immediately offshore from the Dam
Thi Nai area based on seismic data in the Phu Khanh
basin (Fig. 10b) (Fyhn et al. 2009a; b). The “marly”
Dam Thi Nai Oil may therefore have originated from
Lower Miocene fore-reef marls deposited in the narrow
depression along the trace of the EVBFZ in the
Northern half of the Phu Khanh basin, which would
require a fairly simple 40 - 50 km up-dip migration
pathway for the seep oils (Fig. 10b).
2-D hydrocarbon modelling was carried out to give
a first assessment of the maturation and the hydrocarbon generation history of the successions potentially
sourcing the oil seeps in the Dam Thi Nai lagoon as
well as to illuminate the timing and control of hydrocarbon generation and migration in the Phu Khanh basin
(Fyhn et al. 2009b). Seismic interpretation and gravimetric modelling were used to constrain lithology,
ages, structures, crustal thickness, and heat flow, and
pre-defined standard PetroMod physical rock parameters were assigned in the absence of well data.
Modelling indicates that part of the syn-rift succession entered the oil window during the Palaeogene.
During the Early Neogene the level of maturation in
widespread areas only increased moderately.
However, as the sediment accumulation rate
increased during the Late Neogene, the potential synrift and Early Miocene source intervals were deeply
buried by prograding deposits, which forced the main
potential source intervals through the main oil window
and caused the majority of the Palaeogene syn-rift far-
PETROVIETNAM
ther seawards to be situated in the oil window. The
Late Neogene is therefore interpreted as the singlemost important period for oil and gas generation in the
Phu Khanh basin, although magmatic activity may
have influenced source maturation locally in the basin.
The Dam Thi Nai oil seeps and the recent White
Shark oil discovery in the central part of the Phu
Khanh basin indicate working petroleum systems within the basin. This is substantiated by numerous potential direct hydrocarbon indicators (DHI), such as gas
seeps, amplitude anomalies, flat spots and chimneylike features, mostly situated in various carbonate and
sand-prone intervals (Lee & Watkins 1998; Fyhn et al.
2009b). The ENRECA study has thrown light on a
series of structural and stratigraphic trap types situated in favourable positions relative to potential source
rocks. The traps mainly formed before or during Early
Neogene time, preceding the Late Neogene main oil
generation. The study further indicates that potential
reservoir rocks are composed of Miocene carbonates,
diverse sand-prone depositional facies ranging from
non-marine fluvial deposits to deep marine turbidite
sequences and fractured basement highs in the
Western half of the basin sealed by carbonate drowning sequences, transgressive shales and lacustrine
mudstones. A series of promising hydrocarbon plays
thus exist in the basin, many of which are located in
shallow water (Fig. 12).
3.2. The Song Hong basin
Analysis of the Song Hong basin carried out during
the initial phase of the ENRECA project suggested the
presence of working petroleum systems in the basin.
Oil-source correlations suggest the presence of a
Miocene coaly source-rock and a lacustrine mudstone
source rock (Nielsen et al. 1999; Andersen et al.
2005). Miocene intervals containing thick coal seams
encountered in wells were mapped out seismically
across a larger region of the basin. Similarly,
Palaeogene lacustrine mudstones with excellent
source potential crop out on Bach Long Vi and
onshore in the Dong Ho area. Reflector intervals situated within the syn-rift of the Song Hong basin composed of continuous, low-frequency, high-amplitude
reflectors interpreted as thick dominantly lacustrine
mudstone successions occur regionally along the rim
of the Song Hong basin and have been mapped out.
Early modelling of source-rock maturity and petroleum
generation indicated the likeliness of active petroleum
systems in the NE Song Hong basin (Nielsen et al.
1999; Andersen et al. 2005). Modelling further suggested late timing of maturation of syn-rift source rocks
along the basin margin and of post-rift coals situated in
the central part of the basin. This has allowed for
extended periods of time for post-rift structures to form
and to be sealed prior to hydrocarbon expulsion and
migration. A number of subsequent discoveries made
in recent years in blocks 102, 103, 106 and 107 have
confirmed the existence of these Cainozoic petroleum
systems in the area and the findings of the initial
modelling effort in the basin. Even so, a significant
gab in the understanding of the geology and the
petroleum systems of the Song Hong basins exists.
The ENRECA group is therefore in the process of
revisiting the Song Hong basin and plan to drill a fully
cored well in the syn-rift succession of the basin as
part of our activities
3.3. The Malay - Tho Chu basin
In the Malay - Tho Chu basin petroleum exploration began during the early 1970’ encouraged by the
successful exploration activities immediately South of
Vietnamese territory. The first well was drilled in 1994,
and since then, significant gas, condensate and oil discoveries have been made in several wells drilled in the
Malay - Tho Chu basin, but only a few discoveries are
as yet considered commercial. A re-evaluation of the
tested exploration strategies is therefore necessary in
order to optimize and focus future exploration.
Exploration has mainly aimed at Lower to Middle
Miocene fluviodeltaic sand reservoirs with Late
Neogene structural trapping mechanisms. Potential
source rocks have been interpreted to be alginitebearing lacustrine shales and humic coals situated in
the Palaeogene syn-rift and in the lowermost post-rift
successions.
Only few potential source-rock levels have been
penetrated by wells, but those that have, have suppressed vitrinite reflectance (VR) values compared to
VR values obtained from overlying Neogene coals.
Suppressed VR values may occur in alginite-rich rocks
and VR suppression is therefore particularly common
9
in lacustrine shales with high HI values. The maturity
trends of such VR datasets may not be well-constrained and produce abnormally low thermal maturity
gradients. Thus Fluorescence Alteration of Multiple
Macerals (FAMM) was applied in order to obtain reliable thermal maturity trends in rocks containing vitrinite with suppressed and enhanced VR values. By
combining conventional VR measurements and FAMM
data a revised and more accurate thermal maturity
gradient has been established (Fig. 14) (Petersen et
al. 2009).
2-D modelling of the maturation history of the
basin was carried out based on the revised thermal
maturity gradient, detailed seismic mapping, well information and custom kinetics for bulk petroleum generation; the latter determined from outcrop samples of
lacustrine source rock analogues and a terrestrially
influenced mudstone collected from wells (Petersen et
al. 2010).
The 2-D models suggest that most of the syn-rift
succession in the Vietnamese Malay basin is located
in or has passed through the main oil and gas windows. Syn-rift source rocks have therefore produced
and expelled significant quantities of hydrocarbons,
however, the main oil generation generally took place
during the y and Middle Miocene prior to formation of
structural traps in Late Neogene time.
2-D modelling of the hydrocarbon generation
therefore suggests that the main risks in the tested
play types are: 1) The timing of petroleum generation
relative to trap formation completed in the Late
Neogene, 2) Pervasive Neogene faulting, which may
have complicated petroleum migration to the structures and breached charged traps, and 3) The distribution and amount of matured source rocks in smaller
grabens. Based on the abovementioned and the presence of DHI’s, an untested alternative play type is proposed relying on syn-rift sandstones located up-dip
from and near source-rock intervals with Palaeogene
structural and stratigraphic trapping mechanisms that
did not experience subsequent Neogene deformation.
Summary and conclusions
Arc volcanism in and offshore South Vietnam is
associated with Jurassic to Cretaceous subduction of
the palaeo-Pacific. The Phu Quoc basin formed as a
10
retro arc foreland basin linked with the build-up of the
volcanic arc. Coarse grained non-marine deposition
prevailed in the basin, sourced from the coeval magmatic arc located east of the basin. Paleocene to Early
Eocene basin inversion is interpreted as a response to
suturing of Luconia to the Borneo - Vietnamese margin.
Left-lateral shearing along the Vietnamese margin
during the Eocene - Oligocene was forced by the
India-Eurasia collision. Rifting in the Malay - Tho Chu
and the Song Hong basins was a direct consequence
of left-lateral pull-apart rifting, and extension in the Phu
Khanh basin was greatly influenced by left-lateral
shearing across the EVBFZ that transects the Western
half of the basin and splays to the SE in the
Southernmost part of the basin. The EVBFZ makes up
the ca. 1000 km long offshore continuation of the
onshore Red River shear zone and thus outline the
North and central Vietnamese margin.
Rifting decreased at the Oligocene - Miocene transition and thermal subsidence became dominant in the
basins during Neogene time. However, rifting continued in the Southern Phu Khanh basin during the Early
Neogene in response to the propagation of the
seafloor spreading axis towards the Nam Con Son and
the Phu Khanh basins.
Non-marine to restricted marine deposition prevailed along the margin from the Eocene to the
Oligocene, and lacustrine mudstones and humic coals
with source rock potential were deposited during the
period. The marine influence increased during latest
Oligocene and Neogene time as the East sea
approached its present outline. Carbonates therefore
constitute a significant part of the Miocene along the
East Vietnamese margin, whereas clastic deposition
prevailed in the Northern Song Hong and the Malay Tho Chu basins situated near entry points of terrestrial input and farther from open sea areas.
Depositional rates increased significantly during
the Late Neogene in response to uplift and denudation
of Southern Indochina. The uplift was associated with
an intensification of volcanism in the region, which initiated offshore during the Early Neogene and subsequently broadened.
The Phu Khanh basin contains active petroleum
systems as indicated by the Dam Thi Nhai oil seeps
PETROVIETNAM
and oil tested recently in the central part of the basin.
Significant source rock intervals may be present in
the basin and include thick Palaeogene syn-rift
sequences interpreted to contain abundant lacustrine
and coaly intervals, and lower Miocene carbonaceous fore-reef marls.
Maturation modelling of the Song Hong basin suggests a regional petroleum potential in the basin.
Miocene oil-prone coals encountered in wells are
presently at a mature state in the distal parts of the
basin. Eocene - Oligocene syn-rift source rocks crop
out on the Bach Long Vi and at Dong Ho and are
expected to be abundant along the basin margin
based on seismic facies mapping. Maturation modelling indicate that these syn-rift source rocks are
presently oil to gas generating in widespread areas
along the basin margin, which has allowed considerable time for traps to have formed and been sealed.
In the Malay - Tho Chu basin FAMM analyses of
coals and carbonaceous mudstones has led to a
revised and steeper maturation gradient in the area.
basin modelling incorporating the revised maturation
gradient and new custom kinetic data for coals and
lacustrine source rocks indicate that the main risks for
the tested Neogene play types are: 1) The timing of
petroleum generation relative to trap formation completed in the Late Neogene, 2) The pervasive faulting,
which may have complicated petroleum migration to
the structures and breached charged traps, and 3) the
distribution and amount of matured source rocks in
smaller grabens. An alternative syn-rift play type is
therefore suggested, relying on sand reservoirs located next to source-rock intervals, and Palaeogene trapping mechanisms unaffected by subsequent Neogene
structuring.
Acknowledgements
Petrovietnam (PVN) and Vietnam Petroleum
Institute (VPI) are thanked for making data available
for this ENRECA project group and for permission to
publish. The ENRECA project (ENhancement of
REsearch CApacities in developing countries) was
funded by the Danish Ministry of Foreign Affairs
through Danish International Development Assistance
(DANIDA) grants. The ENRECA group was founded
in 2001 on the basis of the preceding cooperation
between the Geological Survey of Denmark and
Greenland (GEUS) and VPI since 1995. The present
ENRECA group encompasses GEUS, Institute of
Geography and Geology (IGG) University of
Copenhagen, VPI and PVN and Hanoi University of
Mining and Geology (HUMG) and Hanoi University of
Science (HUS). So far the ENRECA group has evaluated the geology and petroleum potential of the Song
Hong, Phu Khanh, Malay - Tho Chu and the Phu Quoc
basins along with the training of MSc. and Ph.D. students in hydrocarbon related geology/geophysics. In
the comming phase of the ENRECA project the Song
Hong basin is revisited in addition to continued activities on and offshore Southwest Vietnam. As part of the
activities a fully cored stratigraphic well is considered
to be drilled through the Palaeogene syn-rift succession in the Song Hong basin in order to test and
improve knowledge of e.g. source potential, sourcerock deposition and maturation, Palaeogene biostratigraphy and age of rifting, overall syn-rift sedimentology, petrography, provenance areas and recognition
of source-rock intervals from seismic data. The stratigraphic well is combined with and complemented by
structural and stratigraphic studies based on seismic
interpretation, basin modelling and outcrop analysis.
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13
Fig. 1. Simplified structural
outline of the region including
major basins, areas underlain
by oceanic crust. Insert map
illustrates greater SE Asia and
the outline of Sundaland. BLV
= Bach Long Vi; DH = Dong
Ho; EVBFZ = East Vietnam
Boundary Fault Zone; KFB =
Khmer Fold Belt; KPFB =
Kampot Fold Belt; PB = Pattani
basin; PFB = Phetchabun Fold
Belt; PRCP = Phan Rang
Carbonate Platform; SBT =
Song Ba trough; THFZ = Tua
Hoa fault zone
Fig. 2. Simplified reconstruction of the palaeogeographical
outline of SE Asia showing the
approximate position of the
modern landmasses as reference. (a) Late Mesozoic. (b)
Paleocene-Eocene.
(c)
Eocene-Oligocene. (d) Late
Oligocene-Early Miocene. (e)
Early Neogene. (f) Late
Neogene. See text for further
explanation. Modified after
Fyhn et al. (2009a) and
(2010a)
14
PETROVIETNAM JOURNAL VOL
PETROVIETNAM
Fig. 3. Map of the subcrop pattern at the top-Mesozoic unconformity in the Southern part of the Phu Quoc basin. Zones of
intense thrusting and folding outline the Kampot and the Khmer
Fold Belts that confine the outline of the Phu Quoc basin.
Simplified onshore pre-Quaternary outcrops are indicated, outlining the onshore continuation of the Phu Quoc basin, the Kampot
Fold Belt and the Mesozoic magmatic arc. Position of the ENRECA-2 well on Phu Quoc Island is indicated. Modified after Fyhn
et al. (2010a)
Fig. 4. Time-depth structure map to the pre-Tertiary
acoustic basement in the Phu Khanh basin area.
Dotted areas represent areas with basement concealed beneath thick volcanic successions or situated
below seismic penetration (8 s TWT). EVBFZ = East
Vietnam Boundary Fault Zone, THFZ = Tuy Hoa Fault
Zone. After Fyhn et al. (2009a)
15
Fig. 5. Density model across the EVBFZ (East Vietnam Boundary
Fault Zone) in the Northern part of the Phu Khanh basin. Gravity
and seismic data demonstrate a very thin crust underneath the
EVBFZ and overall seawards thinning of the continental crust of
Indochina. After Fyhn et al. (2009b)
Fig. 6. Seismic transect across the East Vietnam Boundary Fault
Zone (EVBFZ) in the Northern Phu Khanh basin. West of the fault
zone, the pre-Tertiary is composed of crystalline basement
whereas a sedimentary succession floors the Cainozoic east of
the fault zone. A tectonically disturbed Palaeogene syn-rift succession fills the structural low along the EVBFZ. Lower Miocene
carbonate platforms caps the igneous basement and the
Palaeogene rift sequence in areas. The carbonates are buried
beneath a prograding Late Neogene shelf and shelf slope succession. (From Fyhn et al. 2009a)
16
Fig. 7. Seismic section located east of the East Vietnam
Boundary Fault Zone in the Phu Khanh basin showing a distinct sedimentary pre-rift succession. The pre-Tertiary unit is
down faulted beneath conventional seismic recording depths
toward the centre of the basin and buried underneath a thick
Palaeogene succession. The syn-rift unit is covered by
marine Neogene deposits dominated by Late Neogene deep
marine sediments. Note the Neogene volcano farthest to the
South. After Fyhn et al. (2009a)
Fig. 8. Time structure map of the top of the pre-Tertiary
in and North of the Malay-Tho Chu basin. The Malay Tho Chu basin marks the Southern down-faulted border
of the Khorat Plateau. A series of NNW-trending continuous left-lateral fault lineaments transect the area and outline major structural lows in the basin area. Subordinate
WNW- to NW-trending fault lineaments connect the
NNW-trending faults and outline grabens and half
grabens. This fault pattern indicates a left-lateral sense
of motion across the larger NNW-trending faults. Position
of the ENRECA-2 well is indicated
PETROVIETNAM
Fig. 9. Seismic transect from the
Malay-Tho Chu basin across a NNWtrending Palaeogene graben bounded
by steep strike-slip faults and half
grabens confined by more gently dipping WNW-trending normal faults that
link up with the strike-slip faults at
depth. Deposition broadened across
the basement high following the
Palaeogene syn-rift period. Modest
faulting occurred during the Middle to
Late Miocene and certain faults pierce
the seafloor indicating modern fault
activity. After Fyhn et al. (2010b)
Fig. 10. Facies maps of part of the central and South Vietnamese margin. a)
Palaeogene facies map illustrating the
dominance of non-marine to restricted
marine deposits situated in fault confined depressions. b) Early Miocene
facies map mirroring the early Neogene
transgression triggering widespread
carbonate accumulations in the North
and alluvial to shallow marine siliciclastics farther South. c) Middle Miocene
facies map. Increasingly open marine
conditions in the South-Eastern part of
the area promoted carbonate growth.
Shallow marine siliciclastic sedimentation prevailed farther landward and to
the North where carbonate deposition
retreated due to magmatism and local
uplift. d) Latest Middle to Late Miocene
facies map. A transgression followed in
the wake of a late Middle Miocene uplift
in the South-Eastern part of the area.
This resulted in widespread carbonate
deposition across the Northern Con
Son Swell and deeper marine deposition in the Eastern part of the area.
Volcanism in the Phu Khanh basin and
alluvial to shallow marine deposition in
the Cuu Long basin continued during
the period. e) Latest Miocene-Recent
facies map. Siliciclastic supply
increased during the most recent time
of the basin evolution. This promoted
the build up of a prominent shelf slope
and inhibited carbonate production in
the region. Magmatism in the Phu
Khanh basin dropped during the period
whereas volcanism initiated to the
South. The Dam Thi Nai area is indicated. Modified from Fyhn et al. (2009a)
17
Fig. 11. Simplified stratigraphic columns for the basins
along the Vietnamese margin with main regional tectonic
events indicated. N. CSS = North Con Son Swell, NE. CLB
= Northeast Cuu Long basin, NE. MB = Northeast Malay
basin (Malay-Tho Chu basin), N. NCSB = North Nam Con
Son basin, PKB = Phu Khanh basin, SHB = Song Hong
basin. After Fyhn et al. (2009a)
Fig. 12. Schematic diagram summarising potential hydrocarbon play-types in the Phu Khanh basin. The potential plays
are based on source rocks primarily composed of
Palaeogene lacustrine mudstones and coals and Lower
Miocene marly mudstones. Various sand-, carbonate and
basement-reservoir types are outlined relying on both structural and stratigraphic trapping mechanisms. Modified after
Fyhn et al. (2009b)
Fig. 13. (a) Yükler-modelled Present-day maturation level for type I kerogene at the base of the interpreted Palaeogene synrift source interval in the North-Eastern Song Hong basin. (b) Present-day modelled maturation level for type III kerogene at
the base of the interpreted Palaeogene syn-rift source interval. After Andersen et al. (2005)
18
PETROVIETNAM
Fig. 14. Mean average VR values from a well in the South-Eastern part of the
Malay - Tho Chu basin and FAMM-derived EqVR values plotted according to
depth. Five of the VR values define a trend that has a very high correlation coefficient. The two deepest samples are omitted due to complications caused by VR
suppression and possibly cavings. The curve defined by the EqVR values includes
all seven samples. From Petersen et al. (2009)
Table 1. Source-rock parameters from on- and offshore carbonaceous deposits
used to qualify and predict hydrogen-index values in the petroleum modelling of
the Malay - Tho Chu basin. Modified after Petersen et al. (2010)
Locality
TOC
HI
Range
Average
(wt.%)
Range
Average
(mg HC/g TOC)
Age
Na Dương mine
Coal
50.2 - 56.3
~54
Lacustrine mdst
4.1 - 16.9
~10
Coal
50.9 - 66.9
~57
1.5 - 4.5
~2
Lac. mdst upper unit
0.8 - 8.2
~3.5
Lac. mdst lower unit
1.3 - 4.3
~3
31.1 - 47.8
~40
1.5 - 2.6
~2
1.08 - 7.44
~2.9
184 248
224
Miocene
539
Oligocene
294
Oligocene
346
Oligocene
519
Miocene
316
Miocene
199
Miocene
378 438
408
U.
Oligocene
120 252
180
U.
Oligocene
Cua Luc trough
441 690
200 357
Bach Long Vi island
Lacustrine mdst
195 462
Krong Pa Graben
Coal
222 796
99 - 454
111 342
Malay - Tho Chu
46-CN-1X well
Lacustrine mdst
46-NH-1X well
Terrestrially-infl. mdst
19
Recovery Mechanisms and Oil Recovery from
a Fractured Basement Reservoir, Yemen
Torsten Clemens, Nicolas Legrand
Joop De Kok, Pascale Neff
OMV E & P
Abstract
A tight naturally fractured basement reservoir in the Middle East contains an oil column of at
least 2950 ft. The field is characterised by two types of fracturing: Background fractures with a very
low effective permeability of less than 0.001 md and fracture corridors with an effective permeability
of up to 1 md. Except for some dissolution porosity related to fracture corridors, no significant matrix
porosity is encountered. About half of the oil in place is contained in the fracture corridors and half
in the background fractures.
The field has been in production since 2006. It is currently produced by depletion. Compositional
grading has been observed in the thick oil column. Despite the fact that the oil is at bubblepoint pressure at the top of the reservoir, no significant increase in gas/oil ratio (GOR) has been seen.
20
PETROVIETNAM
Introduction
Detailed
simulation
studies revealed that the
reason for the slow increase
in GOR is the low permeability of the background fractures. The low permeability
leads to viscous forces
being dominant over gravity
forces and hence almost no
gravity segregation of gas
and oil.
Due to the relatively low
viscosity contrast of the gas
and the oil in this field, the
gas mobility is not much
higher than the oil mobility
at low gas saturations.
Hence, oil and gas are produced effectively from the
background fractures into
the fracture corridors and
the reservoir pressure is not
depleting as fast as in reservoirs with higher viscosity
contrast between gas and
oil.
A number of reservoir
management
strategies
have been investigated. The
results indicate that the low
permeability of the fracture
corridors and very low permeability of the background
fractures results in challenging conditions for increasing oil recovery by water or
gas injection. However, the
efficiency of depletion drive
is higher than in conventional reservoirs.
In the past, fractured basement reservoirs were often considered
uneconomic. Due to increasing knowledge of basement plays and the
demonstration of successful cases around the world, fractured basement
reservoirs are becoming increasingly attractive to explorationists. An
overview of commercial hydrocarbon reservoirs in fractured basement
rocks is given by Batchelor et al. (2005). Typically, fractured basement
reservoirs are heterogeneous and have little to no matrix porosity. The
storage and production capacity is determined by the properties of the
fracture network.
The reservoir that is described in the paper is a tight naturally fractured
basement reservoir in the Middle East and has an oil column of at least
2950 ft with a small overlying gas cap. The basement rock mainly consists
of felsite, mafic rocks and granite. It is characterized by low porosity and
permeability. Most wells have a low productivity index considering that the
slanted wells have an openhole section of more than 1650 ft. The hydrocarbons have a viscosity ranging from 0.2 cP near the gas/oil contact to
0.4 cP lower down the reservoir, classifying it as light oil. Production from
this field started in 2007.
This paper presents the results and setup of a multi-disciplinary study
with the aim of optimizing production from this tight reservoir. Firstly, the
results of well models are presented, as they were used to study near wellbore behavior. Results from these well models were used to construct
Discrete Fracture Network (DFN) models. Details of the DFN are further
discussed followed by the implementation of the DFN into a sector model.
The simulation results of the sector model are presented in the last part
of the paper. The results include the investigation of depletion and gas
(re)injection as potential development strategies.
Well models
To investigate near wellbore behavior, fine gridded numerical black oil
simulation models were created. The main objective of these well models
was to increase the understanding of the permeability ranges within the
reservoir. Since the investigated wells are located more than a kilometer
apart and the produced volumes up to the point of simulation were small,
limited interference was expected between the wells.
The well models were populated with porosities derived using a core
calibrated correlation between P-wave slowness and total porosity. The fracture porosity was determined using Aguilera (Astesiano et al. 2005), Luthi(Luthi and Souhaité 1990) and DLL (Sibbit and Faivre 1985) methods. The
use of multiple, independent methods decreases the uncertainty concerning
the fracture porosity calculations. For the basement, an average porosity of
1.1% was observed, whilst in some cataclastic zones with mineral dissoluPETROVIETNAM JOURNAL VOL 10/2010
21
tion the porosity reached a maximum of 15%.
The well models were matched for bottomhole
pressure (BHP), gas oil ratio (GOR) and production
logging data. The main matching parameter was permeability. Due to the short production time, the history
match for the well models was insensitive to porosity.
Production logging (PLT) indicates a limited number of inflow zones in the well (Fig.1). The inflow zones
are linked to high fracture porosity. The high fracture
porosity zones are identified as cataclastic zones,
which are related to faults or fracture corridors (also
called swarms). The limited number of inflow points
can be explained by the large permeability contrast
between fracture corridors and background fractures
(also called diffuse or systematic fractures).
Matching both the BHP and PLT requires a low
average permeability together with a high permeability
contrast between fracture corridors and background
fractures. Assuming a background permeability of
0.01md whilst matching the BHP data provides too
much flow from the background fractures as can be
observed in Fig. 2. To achieve a good match for the well
models, the background fracture permeability has to be
in the order of 0.001 md or less. The effective permeability of a 10m thick gridblock representing a fracture
corridor was found to be in the range of 0.05 to 0.5 md.
Fig. 2. Depth versus measured (red) and simulated
(green) tubing flow rate. The simulated case assumes a
background fracture permeability of 0.01 md
Discrete fracture network (DFN)
The well models indicate a large permeability contrast between fracture corridors and background fractures. A dual-permeability approach was selected to
implement this contrast in a sector scale simulation
model.
Traditionally, a dual-permeability approach deals
with matrix and fracture properties (e.g. Warren and
Root 1963). In this case, the high permeability medium
is defined as consisting of fracture corridors. The background fracture system acts as low permeability medium. To model the high permeability medium, a DFN
approach was adopted. Using this method, the subseismic faults and fracture corridors were modeled as
discrete features.
Seismic scale faults, sub-seismic faults, fracture
corridors and background fractures are assumed to
show fractal behavior. Therefore, the distribution of the
fracture corridors was related to interpreted seismic
scale fault occurrences. Fig. 3 shows the fault pattern
and distribution from the fault network analysis. Three
major corridor sets were distinguished.
Fig. 1. Depth, lithology, aperture, fracture porosity, total
porosity, rate of penetration, gas shows, interpreted fractures from image logs, tubing oil and gas flow rates
22
The fracture corridor length was estimated from
power law regression of the fault length distribution.
Also, information from outcrop studies, core data,
borehole images, production logging, conventional
logging and drilling, such as mud losses and gas
shows, were used to constrain the DFN generation.
The fracture corridor porosity honors the log interpretation data, which indicates that 40% of the total pore
volume in the basement is situated within the fracture
corridors.
PETROVIETNAM
sentative for the entire field and only limited interference with other parts of the reservoir exists. The objective for simulating the sector model is to investigate
field development strategies.
The scaled up and dynamically calibrated DFN
was implemented as the high permeability medium of
the dual-permeability simulation model. Since the DFN
did not exactly match the inflow performance of all
wells, the permeability model was fine-tuned manually
to improve the history match.
Fig. 3. Fault pattern and fault distribution in a strike diagram (left) and map view (right)
Fig. 4. An impression of the DFN (in green, light blue and pink
representing the three major corridor sets) and the scaled up
permeability model for one direction with blue being low permeability and light pink being higher permeability
The DFN was scaled up and exported for implementation in the simulation model. The fracture conductivity and density were calibrated in several feedback loops to match well behavior. The result is a DFN
that gives a reasonable history match whilst honoring
statistical geological properties in a consistent manner.
An impression of the DFN and the scaled up model is
depicted in Fig. 4.
Sector model setup
Numerical simulation was performed on a sector
model. The entire field was not simulated due to a lack
of available data over a large part of the reservoir. The
simulated area was selected such that enough data
was available to create and match the fracture corridor
model. It is assumed that this part of the reservoir,
which covers about one third of the total field, is repre-
A constant permeability and porosity was
assigned to the low permeability medium. The permeability for the background fractures was derived
from the well models. The pore volume for this low
permeability medium contains 60% of the total pore
space of the basement, as was derived from log interpretation. Sensitivities concerning the background
fracture permeability and porosity are presented further in this paper.
The oil column in the reservoir has a thickness of
at least 2950 ft. Due to the extent of the column, compositional grading has to be implemented. For example, the viscosity changes from 0.2 cP close to the
gas/oil contact to more than 0.4 cP deeper in the
reservoir. Compositional simulation models compositional grading correctly, however, compositional, dualpermeability models often require large computing
times. To reduce the model runtimes, black oil simulations were performed. Compositional grading was
implemented by introducing thirteen depth dependent
PVT regions. The PVT tables were derived from a single Equation of State that matches the laboratory
experiments, pressure gradient and position of the
gas/oil contact. Water was not included in the model
since no free water was interpreted on logs. Also, no
substantial water production or aquifer support has
been observed.
Straight line relative permeability curves without
residual saturations were used in the simulation model
for both fracture corridors and background fractures. In
this case, the relative permeability of a certain phase
is equal to its saturation. These relative permeability
curves are generally used for the fractures in a dualporosity/dual-permeability model (e.g Kazemi 1976).
Whether this assumption is valid for a tight background fracture gridblock is questionable. However,
assuming straight line relative permeability curves
results in gas becoming mobile with low saturations.
23
This can be considered unfavorable for oil recovery
and is therefore adopted as a conservative base case.
Sensitivity on relative permeability will be discussed
further in this paper.
The Kazemi shape-factor (Kazemi 1976) was used
to model the fluid transfer between the high and low
permeability medium. In this case, as will be demonstrated below, gravity hardly plays a role in the fracture-matrix exchange. Hence the use of the Kazemi
shape factor is appropriate.
Rock compressibility is not included in this model.
A significant decrease in permeability due to the closing of fractures has not been observed to date. Any
compaction without reduction of permeability would
lead to pressure support. This can be considered as a
potential upside.
To investigate the depletion process in detail, slice
models were created. In these slice models, two flat
fine scaled 50m x 50m low permeability blocks are
stacked on top of each other and surrounded by higher permeability zones (for example Fig.6). All input
parameters represent the properties of the sector
model with the difference that the slice models are a
single permeability simulation.
The slice models are depleted by a well in the
upper left corner. Fig. 6 shows the oil saturation in the
model for a block permeability (representing background fracture permeability) of 0.00001, 0.001 and
0.1 md. The amount of produced fluids measured in
downhole volume is equal in the three cases.
Depletion
In this paper, two development strategies are discussed: Depletion and gas (re)injection. This paragraph deals with depletion. The fluid in the top of the
reservoir is saturated since a small gas cap is present.
Due to compositional grading, the saturation pressure
decreases with depth whereas the reservoir pressure
increases (Fig. 5).
Because of the low permeability in the basement,
the drawdown is large. Downhole pressures of about
800 psi have been observed. Since the bottomhole
pressure is smaller than the saturation pressure, gas
will come out of solution. Usually, due to the density
difference between oil and gas, the gas will migrate
upwards and form a gas cap. In the case described
here, both the density difference and the permeability
are low.
Pressure (psia)
1500
2000
2500
3000
3500
4000
4500
4400
Depth (ft)
4900
5400
Psat
Pinit
5900
6400
Fig. 5. Depth versus initial saturation (blue)
and reservoir pressure (red)
24
k = 0.00001 md
k = 0.001 md
k = 0.1 md
Fig. 6. Oil saturation after depletion for the slice models
with a background fracture permeability of 0.00001,
0.001 and 0.1 md
Fig. 6 shows that for a background fracture permeability of 0.00001 md, the 50m x 50m blocks cannot be
depleted effectively. The pressure drop in the background fracture block is such that the interior will be
essentially virgin. The outer part of the block is fully
depleted. What can also be observed is that gas/oil
segregation due to gravity forces is minimal.
For a background fracture permeability of 0.001
md, the blocks are depleted effectively. However, the
drainage rate is too low to achieve gas/oil segregation
in this limited amount of time. In this manner, gas saturation in the background fracture blocks can build up
to values exceeding 25%, even with straight line relative permeability curves and no critical gas saturation.
Another reason for the gas saturation to reach high
values is the favorable mobility ratio. The gas viscosity is only a factor 10 smaller than the oil viscosity.
PETROVIETNAM
A higher permeability will lead to more pronounced
gas/oil segregation, such as the slice model with a
background fracture permeability of 0.1 md. It has to
be noted that the time span in the depletion of the slice
models is small. What is less obvious from the figures
is that gas does segregate from the oil in the higher
permeable zones surrounding the background fracture
blocks.
Fig. 7. Produced GOR versus average reservoir pressure
for the slice model with a background fracture
permeability of 0.00001 md (blue), 0.001 md
(red) and 0.1 md (green)
Fig. 8a. Cross section of the sector model displaying the
oil saturation in the background fractures after
depletion
Fig. 8b. Cross section of the sector model displaying the
oil saturation in the fracture corridors after
depletion
When looking at the GOR for the three slice models (Fig. 7), the case for 0.001 md gives the most
favorable production behavior. The 0.00001 md case
only depletes the outer parts of the blocks resulting in
high gas saturation within that region. The high gas
saturation results in a mobility ratio favorable for gas
production. In the slice model with a background fracture permeability of 0.1 md, gas segregates and is produced when it has reached the top of the model.
The main drive mechanism for the low permeability model is solution gas drive. The gravity forces hardly play a role in the time of production. Usually, depletion with solution gas drive gives recovery factors
lower than 5% (Kortekaas and Van Poelgeest 1991;
Scherpenisse et al. 1994). In heavy oil, recovery factors of more than 10% can be achieved by solution gas
drive (Claridge and Prats 1995; Maini 1996). However,
also with reduced gas/oil segregation, the recovery
can be increased to values higher than 5%. As
described above, a main contributor to the high recovery is the favorable gas/oil mobility ratio.
The gas saturation buildup during depletion in the
tight background fracture blocks, as observed in the
slice models, can also be seen in the dual-permeability sector model. Fig. 8a and 8b depict the oil saturation
after depletion in the background fractures and fracture corridors respectively.
Also, the GOR does not increase as fast during
depletion as expected from a saturated reservoir. Fig.
9 shows the saturation pressure, initial reservoir pressure and reservoir pressure after recovering 2.8% and
6.5% of the oil initially in place. When a recovery factor of 2.8% has been achieved, almost the entire
reservoir section has a pressure below the initial saturation pressure. Nevertheless, the average produced
GOR only increases from 1350 scf/stb to 1490 scf/stb.
With a tight well spacing (about 100 acre), a well
GOR constraint of 5000 scf/stb and a minimum BHP of
25
Pressure (psia)
1500
2000
2500
3000
3500
4000
4500
4400
Depth (ft)
4900
Psat
5400
Pinit, GOR=1350 scf/stb
RF=2.8%, GOR=1490 scf/stb
RF=6.5%, GOR=2850 scf/stb
5900
often good candidates for gas oil gravity drainage (e.g.
Boerrigter et al. 1993). However, due to the low permeability in this reservoir, the drainage rates are small
and the drawdown in the wells is large. These factors
make the basement unsuitable for gas/oil gravity
drainage. Therefore, additional recovery due to gas
injection is limited.
6400
Fig. 9. Depth versus initial saturation pressure (Psat),
initial reservoir pressure (Pinit) and the reservoir
pressure after achieving a recovery factor (RF)
of 2.8% (RF = 2.8%) and 6.5% (RF = 6.5%).
The average produced GOR is mentioned in
the legend
1200 psi, a recovery factor of more than 10% can be
achieved by depletion alone. Gas injection might
increase the recovery. The following section presents
the results of investigating gas (re)injection as a potential development strategy.
Gas injection
Gas injection gives pressure support to the reservoir. However, injection can also lead to rapid gas
breakthrough in the production wells. Since there is no
gas available other than the produced gas, this section
only deals with re-injection of the produced gas.
Fig. 10. Cumulative oil production for the depletion
(blue) and gas injection (green) case
An issue with gas injection in this tight reservoir is
the injectivity of the wells. However, this issue is not
discussed further in the paper. The injection wells are
situated relatively high in the structure and as far away
from the production wells as possible. They are chosen such that they are able to re-inject large quantities
of produced gas.
Most simulation cases show an increase in recovery in the long term when re-injecting the produced
gas. The wells that benefit the most from gas injection
are the wells that are more favorable for gravity
drainage. They are generally situated downdip or are
mainly producing from the deeper part of the openhole
section. Also, they are often situated far away from the
injection wells. Incremental recovery can go up to 4%
of the original oil in place. An example of the increase
in recovery is observed in Fig. 10, where the cumulative oil production is plotted without produced liquid
rate constraints.
Fractured reservoirs with a large oil column are
26
Fig. 11. Cumulative oil production for the gas injection
case with a background fracture permeability
of 0.01 md (red), 0.001 md (green)
and 0.0001 md (blue)
Sensitivities
Sensitivity analysis was performed on several
uncertain parameters. This section does not discuss
all analyses performed, but does present the most
PETROVIETNAM
important findings. The most sensitive parameters are
total volume, background permeability, the volume of
the fracture corridors relative to the background fractures volume and the relative permeability curves.
Changing the shape factor or PVT (while honouring
the lab experiments) has a much smaller impact on the
recovery.
The amount of fluids initially in place influences the
total recovery. However, given a suitable well spacing,
the recovery factor of more than 10% for depletion will
be very similar.
Fig. 12. Cross section of the sector model displaying the
pressure in the background fractures after
depletion with a background fracture permeability
of 0.0001 md
tion and gas injection (Fig. 11). The same mechanisms
play a role as investigated in the slice models.
Decreasing the permeability by a factor of 10 has
a larger effect on the recovery during depletion. In
areas where the fracture corridors are non-existent,
the pressure drop becomes such that the reservoir
cannot be depleted effectively as can be seen in the
figure below (Fig. 12).
In the simulation model, the fracture corridors contain 40% of the total pore space. Reducing the relative
volume to 10% has only a limited impact on recovery
by depletion (Fig. 13). A large portion of the difference
can be explained by the fact that the total pore volume
is not exactly equal. The effect on the recovery by gas
injection is much larger. Since the volume of the fracture corridors is smaller, the gas will move faster from
the injection well to the production well during injection. The figure below includes a maximum oil production constraint.
Gas injection versus depletion
In most cases, simulation shows that gas injection
results in more oil recovery than for depletion alone.
However, there are some issues to this.
Firstly, there are limitations to the simulation itself.
The dual permeability approach is an approximation of
reality. Often, it has problems mimicking the high
velocities in the fractures that occur in reality. In other
words, the amount of time before gas breakthrough
occurs might be overestimated by adopting the current
approach.
Fig. 13. Cumulative oil production for the depletion(solid line) and gas injection (dotted line) case
with a relative fracture corridor volume of 40%
(red) and 10% (blue), including a maximum
oil production constraint
The background fracture permeability is a major
uncertainty. However, increasing the permeability of
the background fractures by a factor of 10 has a small
impact on the recovery of the field during both deple-
Secondly, there are large uncertainties on matters
such as fracture corridor density, volume of the fracture corridors relative to the background fracture volume and the permeability contrast between the two
media. All these parameters have an impact on the
recovery and the potential of gas injection. However,
the impact for gas injection is often larger than for
depletion (see the previous section). Therefore, the
uncertainty of recovery for gas injection is larger.
Conclusions
A discrete fracture network (DFN) was constructed
using all available data, including information from outcrop studies, core data, borehole images, production
logging, conventional logging and drilling. Together
with the results from well models, the DFN was implemented in a dual-permeability black oil simulation
model. Compositional grading was introduced with
27
depth dependent PVT tables. The simulation model on a sector scale was
then used to investigate development by depletion and gas injection.
Due to its low permeability, gas/oil segregation caused by gravity hardly plays a role in the background fracture network during depletion.
Additionally, because of the low gas/oil mobility contrast, gas saturation can
build up to values exceeding 25%, even when assuming straight line relative permeability curves and zero critical gas saturation. Simulation shows
that a recovery of more than 10% is expected for depletion in this tight reservoir on a field scale, which is exceptionally high for solution gas drive. Gas
injection can yield additional recovery, but the uncertainties are larger.
Acknowledgments
The authors would like to thank OMV for the permission to publish this
paper. We highly appreciated the discussions and input of Jan Steckhan,
Yannick Boisseau and the other team-members.
References
1. Astesiano, D., Godino, G. and Whitty, C. 2005. Petrophysics
Evaluation of the Loma la Yeguas Sill. Apply to Aguilera Method. VI
Congreso de Exploración y Desarrollo de Hidrocarburos, Buenos Aires.
2. Batchelor, T., Gutmanis, J. and Ellis, F. 2005. Hydrocarbon
Production from Fractured Basement Formations. www.geoscience.co.uk
3. Boerrigter, P.M., Leemput, B.L.E.C., Pieters, J., Wit, K. and Ypma,
J.G.J. (KSEPL). 1993. Fractured Reservoir Simulation: Case Studies, SPE
25615, SPE Middle East Oil Technical Conference. 3 - 6 April, 1993: 191
- 202.
4. Claridge, E.L. and Prats, M. 1995. A Proposed Model and
Mechanism for Anomalous Foamy Heavy Oil Behavior. Heavy Oil
Symposium, Calgary, Alberta, Canada, 19-21 June, 1995: 9 - 20. SPE 29243.
5. Kazemi, H. 1976. Numerical Simulation of Water-Oil Flow in
Naturally Fractured Reservoirs. SPEJ Dec, p. 317 - 326.
6. Kortekaas, T.F.M. and Van Poelgeest, F. 1991. Liberation of Solution
Gas During Pressure Depletion of Virgin and Watered-Out Oil Reservoirs.
SPERE Aug 1991, p. 329-335. SPE - 19693.
7. Luthi, S.M. and Souhaité, P. 1990. Fracture Apertures from
Electrical Borehole Scans. Geophysics, v. 55, n. 7, 821 - 833.
8. Maini, B.B. 1996. Foamy Oil Flow in Heavy Oil Production. J. of
Canadian Petroleum Technology, 35(6): 21 - 24.
9. Scherpenisse, W., Wit, K., Zweers, A.E., Shoei, G. and Van
Wolfswinkel, A. 1994. Predicting Gas Saturation Buildup During
Depressurisation of a North Sea Oil Reservoir. European Petroleum
Conference, London, U.K., 25 - 27 Oct 1994.
10. Sibbit, A.M. and Faivre, O.1985. The Dual Laterolog Response in
Fracture Rocks. Trans., paper T, SPWLA 26th Annual Logging
Symposium, 1 - 34, Dallas.
11. Warren, J.E. and Root, P.J. 1963. The Behaviour of Naturally
Fractured Reservoirs. SPEJ p. 245 - 255.
28
PETROVIETNAM
Advancements in Basement Logging While Drilling
(LWD) Techniques for Formation Evaluation
Abdul Fareed, Mike Bugni
Schlumberger
Cao Le Duy, Luong Duc Phong
Bui Thieu Son
Cuulong Joint Operating Company
Abstract
Accurate formation evaluation in fractured and
granitic reservoirs is always difficult using either wireline or logging while drilling (LWD) advance measurements. Drilling granitic basement reservoir is challenging because the severe shocks and vibrations
would, until recently, often cause LWD tools to fail.
Therefore, traditionally, limited and basic LWD measurements had been acquired while drilling or by tripin/wash-down methods. Advancement in drilling technology, by mitigating high shocks and vibrations, has
encouraged operators to acquire advance LWD measurements in drilling as well as trip-in modes, thus saving time by reducing logging runs. These new and
unique measurements significantly improve the
understanding of these fractured granitic reservoirs.
Advanced LWD measurements offer benefits over
past logging methods. These advanced and new
measurements (i.e., high resolution laterolog resistivity and borehole images and nuclear measurements
which include spectroscopy and sigma along with
acoustic measurements) provide the opportunity to
evaluate granitic basement reservoirs with confidence
in the LWD domain.
Two case studies from Su Tu Den and Su Tu Vang
fields in the Cuulong basin are used to illustrate
datasets recently acquired in while-drilling and washdown modes. High-resolution resistivity images, density image, ultrasonic caliper image and acoustic
measurements were integrated to evaluate fractures
having high probability of production contribution.
This technique demonstrates a completely new
approach for basement evaluation with while-drilling
measurements.
29
Introduction
Su Tu Den and Su Tu Vang fields are located in
Block 15-1, Cuulong basin, offshore Vietnam.
Hydrocarbons were discovered in these fields during
2000, but the exploration history dates back to 1975
with work by Deminex. These two field structures were
formed as a result of multiple intrusive events followed
by multiple tectonic events starting in Late Cretaceous.
(N. T. Long et al., 2005).
The lithology consists mainly of granite cross cut
by several dykes of basalt/andesite and monzodiorite. Often, these intrusive events were followed by
relatively younger intrusive events-pre- or post-tectonic events and these more recent intrusives add
more complexity to the reservoir evaluation. Quite
often, such relatively fresh intrusives are encountered as dykes and act as permeability barriers. (B.
Li et al., 2004).
Both of these fields have almost no matrix porosity and produce from fractures only, with average production of 30,000 bbls/day. The extensive studies on
fracture characterization that have been done to
understand the nature of these fractures and their productivity behavior demonstrate the effectiveness of
using borehole imaging tools and advance acoustic
measurements. (Luthi 2003, B. Li et al., 2004, Le Van
Hung et al. 2009). These studies have made substantial contributions and have resulted in greater understanding of basement producibility. As a result of the
30
studies, drilling inclined and highly deviated well trajectories became normal practice after 2001. Since then
it has become almost a routine drilling practice to drill
highly deviated and horizontal wells to achieve production goals by drilling wells penetrating through optimal
fracture orientations. These practices have proven to
be highly rewarding and have resulted in increased
production.
Drilling basement rocks in Vietnam has always
been challenging because of severe shocks and vibrations. In such a high-shock environment, LWD tools
were prone to electronic failures thus limiting operators
to the acquisition of minimum data for formation evaluation. By means of trip-in/wash-down methods, LWD
tools can be run in the bottomhole assembly (BHA),
enabling acquisition of fundamental logs for petrophysical evaluation. However, in deviated and horizontal borehole trajectories the chances of stuck/lost
BHAs are high, and, to eliminate the possibility of lost
radioactive sources, nuclear measurements were not
considered to be part of the BHA. Because of such
operational challenges, only propagation resistivity or
laterolog resistivity became the normal practice for
deriving petrophysical answers.
In this paper, two case studies demonstrate the
new technology applications for drilling and LWD
measurements for complete formation evaluation. The
data were acquired through trip-in/wash-down mode
as well as while drilling modes which include:
PETROVIETNAM
+ For case 1, Su Tu Vang field: High-resolution laterolog resistivity and images from the geoVision* tool
in wash-down and drilling modes.
+ For case 2, Su Tu Den field: Nuclear porosity,
propagation resistivity, density and photo-electric (Pe)
images; ultrasonic borehole image, sigma and spectroscopy measurements from the EcoScope* tool;
compressional and shear slowness from the
sonicVision* tool; and laterolog resistivity images from
the geoVision* tool. All three tools were attached to
one BHA for logging in wash-down mode.
Background - Basement Formation Evaluation
These days, advanced and effective methods are
available to perform formation evaluation in basement
reservoirs. To achieve this, continuous and rigorous
efforts have been applied to characterizing these fractured reservoirs. All fractures in the reservoir are characterized to determine their contribution to the productivity of the well by integrating logging data gathered
from various wireline tool measurements. Yet there are
many unknowns in understanding the basement lithology and differentiation of a productive fracture system.
This largely explains the formation evaluation challenges associated with these unconventional reservoirs. The complex and variable mineralogy makes the
determination of matrix properties, such as matrix density, and hence porosity very challenging.
The porosity and permeability in Vietnam’s basement reservoirs are highly heterogeneous and generally associated with tectonic fissures, faults, shrinkage
vugs, caverns or dissolved interstices (Luthi 2005).
Fracture porosity is the primary indicator of basement
productivity and very little (~2 to 5%) porosity is generally associated with weathering, leaching, dissolution
and diagenetic processes which occur dominantly at
the upper part of granitic basement.
Fractures associated with tectonic activity, i.e.,
faults / fractures, are of key importance. Therefore,
various classification schemes have been used to
evaluate fractures from outcrop scale down to microscopic size. The two broadly defined terms for fractures classification are macrofractures and microfractures. Macrofractures can be easily seen on outcrops
as well as on wireline image logs (UBI*/OBMI*/FMI*)
whereas microfractures can be observed under a
microscope and in SEM photomicrographs.
Microfractures can sometimes also be observed at
outcrops by the change in the rock’s color along the
microfractures because of groundwater movement or
percolating hydrothermal fluids (T. X Cuong et al.,
2005). The study of these microfractures is as important as the study of macrofractures as the microfractures provide both hydrocarbon storage capacity as
well as connection to the macrofractures, which contribute significantly in hydrocarbon production.
Borehole images have been used in the industry
for a long time, initially starting with ultrasonic borehole
imaging devices (UBIs) for formation dip and open
fracture identification for wells drilled with oil-base mud
(OBM) or water-base mud (WBM). After the introduction of resistivity images (FMS*/FMI*) in the 1980s,
use of UBIs became limited to wells drilled with OBM,
and FMS*/FMI* resistivity images became more popular for wells drilled with WBM because of their high vertical resolution and wider application range. However,
UBIs are still being effectively used to locate open fractures in hydrocarbon-bearing fractured reservoirs
(Singh S.K. et al., 2008, 2009).
Identification and classification for macrofractures
is commonly done by FMI* wireline resistivity image
logs. Various interpretation schemes are adopted by
geoscientists to group these fracture classes. The two
broad groups are bounding and discrete fractures.
Bounding fractures are then further classified into various subgroups, i.e., solution-enhanced continuous,
discontinuous or terminating fractures (B. Li et al.,
2004, N.T. Long et al., 2005). Solution-enhanced
bounding fractures are generally those having aperture range from 1mm to 2cm and are the most important fracture class in terms of relative contribution of
hydrocarbons in the wellbore (P.M. Tandom et al.,
1999, K. Tezuka et al., 2002, B. Li et al., 2004).
Significant amount of work to date has been done
studying fracture systems in Vietnam’s basement
reservoir and this work has been integrated with production and reservoir testing data. The studies reveal
that fracture aperture, fracture orientation, fracture
connectedness, maximum horizontal stresses in the
wellbore and drawdown pressures are all key indicators for productivity in a well (K. Tezuka et al., 2002, B.
Li et al., 2004, L. V. Hung et al., 2009). Fracture apertures and orientation are generally derived based on
FMI resistivity image logs, laterolog resistivity and
* Indicates a mark of Schlumberger
31
acoustic measurements (Sibbit
1995, P.M. Tandom et al., 1999),
whereas fracture connectivity and
stress-magnitude contrast between
horizontal stresses has been derived
through other methods.
secondary porosity through the
established multimineral relationship
with the core mineralogy and estimate permeability through modelbased reservoir properties and neural network techniques.
Another important aspect in
defining fracture properties is to
identify the fracture effectiveness,
i.e., open versus mineralized or clayfilled fractures. Acoustic waveform
techniques provide means to quantify fracture-related porosity and differentiate open versus filled fractures by analyzing low-frequency
content in the waveform (Sibbit,
1995). Stoneley slowness is generally sensitive to borehole enlargement,
and the response can attenuate the
same in an enlarged hole as in an
open fracture making differentiation
of the two difficult (P.M. Tandom et
al., 1999). Similarly, fractures filled
with clay minerals; e.g., zeolites, will
appear conductive on resistivity
images, making differentiation of
clay-filled and open fractures difficult
as well. Therefore, integration of
mud-log data for total gases and cuttings description for oil indication
play crucial roles in differentiating
effective versus non-effective fractures encountered in a particular well
(N.T. Long et al., 2005).
The importance of a single big
fracture contributing >2000 bbls/day
oil production, has been document
well by Luthi (2005), whereas the
significance of having many fractures of variable apertures and not
producing immediately after drilling
has also been reported by B. Li et al.
(2004). In their example, the studied
well did not produce hydrocarbons
initially, but started contributing a significant amount of oil after a few
months. This clearly suggests that
fracture density, aperture, and orientation are the fundamental factors for
formation evaluation. Methods of
fracture modeling workflow using 3D
seismic data and integrating borehole fracture density and orientation
are also a key to reservoir evaluation. This has been discussed
recently by M. Lefranc et al. (2010)
and Singh H. K. et al, (2008, 2009)
for granitic basement and carbonate
fractured reservoir, respectively.
Furthermore, conventional techniques to quantify reservoir porosity
(primary and secondary) and permeability do not work in these granitic
basement reservoirs. Therefore,
customized algorithms have been
introduced to derive the petrophysical parameters through BASROC
software (H.V. Quy et al., 2008).
BASROC software incorporates
standard logs [gamma ray (GR),
resistivity, neutron, density, sonic
(DT), etc.] to estimate primary and
32
This paper focuses on LWD
measurements and their applications for performing formation evaluation in these fractured basement
reservoirs. Apart from standard geological and petrophysical logs, some
new measurements in the LWD environment which can help further in
quantifying basement lithology and
matrix properties.
LWD Challenges for Basement
Logging
Granitic basement reservoirs are
extremely hard and abrasive formations in the Cuulong basin. Drilling
PETROVIETNAM
these reservoirs is slow, 10 to 20m/hr,
and produces a high amount of shocks
and vibrations. The shock level can
jump instantly from no shocks to
extreme shocks. Exposure of LWD tools
to the extreme shocks present in basement drilling for even short periods of
time can cause severe damage. Up
until recently, the SlimPulse* (MWD)
surveying and telemetry tool was the
only proven tool which survived under
these shocks and vibrations while
drilling, and the tool has been used
often for drilling these basement reservoirs. The SlimPulse* tool, however, is
not compatible with the new generation
LWD tools. This was the limiting factor
in acquiring LWD measurements in
while drilling mode for petrophysical
analysis.
In 2009 a step change occurred that
opened the door to advanced LWD
measurement acquisition in whiledrilling mode. This step change was the
introduction of Xceed vortex*, rotary
steerable systems. Previously, only
motors were capable of drilling directionally in basement. The bend in the
motor contributed to the shock and
vibration, which limited LWD capabilities. Xceed vorteX* is capable of drilling
directionally without the need for a bend
in the BHA. This has allowed the use of
TeleScope measurement while drilling
(MWD) service, which is the telemetry
system required to run advanced LWD
tools. To date, there have been many
successful runs using Xceed vortex*
and TeleScope* with LWD tools in basement.
Another challenge to LWD in basement is that basement rocks in the
Cuulong basin are of variable composition and range, i.e., felsic to mafic.
Multiple intrusive activities occurred in
the Cuulong basin, which makes it difficult to predict lithological boundaries
along the planned wellbore trajectory. In
highly deviated and horizontal wells, an
LWD resistivity log is acquired by a fast
tripping-in speed (100 to 150m/hr) after
drilling to the final target depth. This
practice ensures acquisition of petrophysical measurements from LWD tools
prior to running any subsequent logging.
Basement Formation Evaluation-LWD
Identification of reservoir storage
and production capacity is the key element to performing formation evaluation
in these complex reservoirs. The petrophysical elements required to evaluate
these granitic basement reservoirs are
different from those in conventional
reservoirs. The key elements to performing petrophysical analysis in a well
can be addressed by quantification of:
- Fracture/fault zones and their orientations.
+ Macrofractures (small versus
large scale).
+ Open versus filled fractures.
- Indication of hydrocarbon presence.
- Fresh intrusive/extrusive rocks
(dykes) and their cross-cutting relationships.
- Host rock mineralogy and alteration products.
By knowing the above parameters,
we can evaluate zones of reservoir storage capacity and producibility in a well
with confidence. A comprehensive and
multidimensional approach is required
to quantify these parameters.
Resistivity in basement can be
extremely high, (>40,000ohm.m) and
depends on the type of intrusive rock
composition. Relatively fresh felsic
intrusives can be of higher resistivity
than their mafic counterparts; therefore,
porosity transformation using resistivity
33
alone may not be representative. Secondly, measuring
formation resistivity in such an extreme environment
would also increase measurement uncertainty.
Laterolog resistivity devices are the preferred measurements compared to propagation-based resistivity
for high-resistivity formations. Propagation resistivity is
sensitive to dielectric properties of the rock because
dielectric constant decreases with a decrease in formation conductivity and, therefore, an assumed value
of dielectric constant that is too low, which results in an
erroneously low computed phase-shift resistivity (R.
Altman et al., 2008; Rasmus J. et al., 2003).
High-resolution laterolog resistivity and borehole
image logs provide fundamental measurements to
perform basement formation evaluation. Standard
density/neutron/DTc measurements help to estimate
basement primary porosity, while fracture apertures
are the second most important aspect in estimating
fracture-related porosity. Fracture apertures in granitic
reservoirs in Su Tu Vang and Su Tu Den fields in particular, and in Cuulong basin in general, vary from
<0.1mm to >50cm in size. Therefore, it becomes crucial not only to classify fractures based on their aperture sizes but also to differentiate whether these fractures are permeable (open).
2. Medium fractures: Continuous fractures that appear
on high-resolution image logs, partially continuous on
ultrasonic and/or density image logs.
3. Small fractures: Fractures that appear only on highresolution resistivity image logs.
Using all types of image logs, resistivity, acoustic
and density and Stoneley measurement, if available,
helps differentiate whether fractures are open or filled
with conductive minerals.
Conventional Approach for Formation Evaluation
Generally, laterolog average resistivity measurements are used to infer the formation porosity through
local transforms. These transforms are adopted with
experience and core and log integration to quantify
porous intervals and integrate them with the available
mud-log information. In Cuulong JOC, secondary
porosity was calculated based on a modified
Schlumberger Boyeldieu-Winchester model, or a simple back out of porosity from resistivity as follows:
Φ=
(
Rw
)
LLDC
1/m
Where:
In this paper, we propose to group natural fractures based on their opening sizes with the help of
high-resolution resistivity image logs and relatively
low-resolution density and ultrasonic borehole image
logs. A pragmatic approach is introduced to define
three categories of natural fractures:
m: Archie’s cementation exponent. If LLDC >
2000ohm.m, then m = 1.65, otherwise m = 2.
1. Large fractures: Continuous fractures that appear
on high-resolution resistivity image logs, ultrasonic
image logs and density image logs.
The basement contains many types of dykes that
range from aplitic to basaltic dykes. Their age ranges
considerably, from Mesozoic to Tertiary. Andesitic and
34
Φ: Porosity of basement
Rw: Formation water resistivity
LLDC: Deep laterolog, borehole corrected
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basaltic dykes are readily recognized by their gammaray, Pe, neutron and density signatures. The gamma
ray signature is particularly useful in identifying these
mafic dykes. The basic dykes are typified by the cool
gamma-ray response. Nearly 100% of the productive
intervals in the Su Tu Den and Su Tu Vang fields have
been related to fractured rocks of felsic composition.
Intrusive mafic dykes have a negative effect with
respect to the resistivity by lowering the measurement.
This is related to composition and hydrothermal alteration of the dykes. Instead of altering the porosities
associated with the dykes that have not been directly
measured, it is reasonable to assume the impact of
these zones with respect to net/gross. The resistivitydriven porosity can be modified through the use of
gamma-ray data as a volume of intrusives (V-intrusive) curve. A 100% dyke line is drawn where cool
dykes occur and a 100% granite line is drawn where
granite is present. The lithological description from
rock cuttings is used to verify the position of these
lines. The V-intrusive curve then defines any points
between the lines (0 to 100% granite). A 40% cutoff is
used to differentiate between basaltic dykes and granite. Since no reliable physical measurements of porosity exist, a reduction of 10% in porosity is applied in all
zones containing a V-intrusive value less than 40%.
In basement, a tight zone is defined as a noneffective porosity zone, and the porosity value in a
tight zone is block porosity and rejected by using
DTblock and RHOBblock cutoffs. DTblock and
RHOBblock cutoffs are determined as the most likely
value in tight zone.
From Vietsovpetro’s analog approach, DT* is used
to recognize macrofracture and microfracture zones.
DT* was calculated based on the DT distribution of noflow zones and flow zones. It is the cross point
between the DT distribution of no-flow zones and the
DT distribution of flow zones.
+ For microfracture zones: DTblock ≥ DT ≥ DT*.
+ For macrofracture zones: DT > DT*.
+ For tight zones: DT< DT block.
Advanced Approach for Formation Evaluation
Compositional variation in basement rocks can be
very homogenous to heterogeneous from one well to
the other within the same field. GR logs and GR image
logs may provide some insight to differentiating rocks
having marked differences in their radioactive mineral
contents, generally due to presence of potassium (K).
Mineralogy-based techniques using dry weights of Si,
Fe, Ca, Mg, S, Al, Ti and Gd logs can be used to derive
intrusive composition more effectively than the conventional methods defined above (L. GuoXin et al.,
2007). GR and GR image logs quite effectively provide
the contact angle between felsic/mafic dykes to define
the shape of intrusive bodies.
Further, the approach uses natural fracture groups
identified by using all image logs, as explained previously in this paper. Shear and pseudo-Stoneley measurements, low frequency contents in the waveform,
from a monopole LWD acoustic tool can be integrated
for quantification of fracture density, porosity, aperture
and potential intervals of hydrocarbon contribution
(Sibbit 1995, L.V. Hung et al., 2009). These results can
then be taken as input for a 3D model.
Case study 1: Su Tu Vang Field
The case study involves datasets from three highly deviated and horizontal wells in which geoVision*,
high-resolution laterolog, resistivity (GVR) was
acquired. All wells were drilled with WBM, Rm = 0.2 to
0.04 ohm.m at 300C. In well-A, GVR was acquired in
trip-in mode at ~120m/hr logging speed without rotating the BHA for 1880m for average resistivity. The BHA
was rotated over an 800m interval for average resistivity and image logs with the last 120m in while-drilling
mode. Similarly, well-B was logged for 3240m total, in
which the last 180m was logged in while drilling mode
at 8 ½ inch section total depth (TD). The success of
using the GVR in while-drilling mode encouraged the
use of the same BHA while drilling the next well, wellC. Well-C was logged in while-drilling mode using
Xceed vorteX* in eight different drilling runs that covered a~2400m logging interval over entire basement
section with no need to pull out of hole due to issues
with directional drilling (DD) or MWD/LWD equipment.
Various acquisition modes were employed
because of operational and economic sensitivities and
to reduce the calculated risks associated with the
drilling operation. Fig. 1 shows a GVR log example
from well-B, acquired in wash-down mode with
35
~40rpm BHA rotation. The formation resistivity is up
to 10,000ohm.m. Average resistivity from shallow,
medium and deep buttons and ring resistivity is displayed in track 3. Derived caliper from these measurements indicate borehole enlargement. However,
the image logs make it very clear that the average
resistivities from all three buttons are affected by
borehole breakouts. The breakouts are prominent on
the shallow button image, and are diminished on the
deep button image. Therefore, quadrant resistivity
measurements from deep-button measurements will
provide better means to evaluate formation porosity
using resistivity methods. Furthermore, breakouts in
the vertical direction indicate the in-situ minimum
stress direction, i.e., σv = σ3. Fig. 2 is the other example from the same well, well-B, in a fractured zone,
showing data acquired in while-drilling mode. Image
resolution is enhanced compared to wash-down logging. It is interesting to note that in the 6185 to 6187m
measured depth (MD) interval, fractures on the shallow-button image indicate larger fracture openings
compared to the deep-button image. This can be
attributed to enhancement in fracture aperture in the
near-wellbore environment.
Case study 2: Su Tu Den Field
In this case study, we describe the advanced
LWD logs acquired for the first time in basement. The
studied well was recently drilled in Su Tu Den, NE
field, where EcoScope* and sonicVision* tools measurements were acquired to evaluate their feasibility,
in terms of the quality of measurements as well as
cost, for advance basement formation evaluation
techniques.
The basement section of ~1500m was logged in
wash-down mode using following tools:
1. EcoScope*, a multifunction logging tool for complete petrophysical measurements.
2. GeoVision* laterolog resistivity for high-resolution resistivity and borehole images.
3. SonicVision* for monopole acoustic measurements.
Data were acquired at 100m/hr wash-down speed,
with the exception of a test zone, a 30m interval with
logging speed of 20m/h. The test zone was logged to
acquire high-density sampling for borehole images
36
and to allow reliable acquisition of spectroscopy measurements.
The study has also provided an opportunity to
compare high-resolution laterolog resistivity with propagation resistivity measurements.
Fig. 3 is a composite plot used to classify large
(open), medium (partially open) and small size fracture
sets by analyzing resistivity, ultrasonic caliper and
density images. The last track is the slowness-time
coherence plot from sonic measurements and shows
compressional, shear and borehole fluid arrivals. The
fracture at ~4388m, is large and open as it can be
seen on all image logs.
Fig. 4 is an example of small-size fractures visible
on resistivity image logs only. These fractures are
strike NW-SE and provide storage capacity for hydrocarbons. This is evidenced by shallow-button image
logs in which, because of insufficient mud pressure in
the borehole, formation is bleeding oil (Fig. 5).
Generally, fractures filled with clay minerals can also
be identified by analyzing a combination of these
images (Fig. 6). Identification of relatively fresh intrusives/dykes is equally important while performing
petrophysical analysis either by conventional or
advanced
methodology.
Generally,
fresh
intrusives/dykes are non-reservoir rocks and intrude
vertically or sub-vertically. Therefore, knowledge of
their distribution within the well and their orientation
provides detailed insight of the basement rock variation, and their presence directly affects the productive
interval (net reservoir) of the well. Fig. 7 shows an
example of a ~3m vertical fresh intrusive (dyke). The
dyke has no fracture indication on the resistivity image
and has no porosity.
Before performing any petrophysical analysis, it is
crucial to ensure the data is not affected by any borehole or drilling effects. Fig. 1 illustrated the borehole
breakout effects on resistivity logs whereas Fig. 8 indicates drilling artifacts on density, neutron porosity and
caliper logs. By looking at the average caliper log, it is
impossible to differentiate whether the borehole
enlargement is due to a fracture opening or due to
drilling affects. Likewise, bottom quadrant and average
bulk density measurements will be affected by borehole breakout. In this case, image-derived density or
other quadrant density measurements would provide
PETROVIETNAM
the unaffected measurements.
Acknowledgements
Fractures grouped into three main classes are
plotted in Fig. 9. It is interesting to note that the largeand medium-size fractures show relatively low dip
angle and are striking NE-SW whereas most of the
small fractures are dipping at higher angle and striking
NW-SE direction.
The authors would like to thank Cuulong JOC for
granting us permission for the release of the data and
providing the information about the geology of the
studied fields.
By integrating results derived from acoustic measurements and image-based fracture analysis techniques, fracture density and fracture aperture have
been quantified. Three main flow potential intervals
are identified in this well (Fig. 11).
1. Alan M Sibbit. Quantifying porosity and estimating permeability from well logs in fractured basement
reservoir. SPE 30157, 1995.
Spectroscopy measurements for various elements, acquired over the test zone, are shown in Fig.
12. The spectroscopy measurements provide the
basis for a geochemical approach in the identification
of various intrusive (dykes) bodies.
Conclusion and way forward
The two case studies highlighted the limitations
and strengths of using a single measurement over
integrated measurements to perform basement evaluation. The following conclusions can be deduced.
- Laterolog high-resolution resistivity is the fundamental measurement for estimating formation resistivity in basement.
- Borehole high-resolution image logs, ultrasonic
and density images provide means to classify large-,
medium and small-scale fractures.
- The combination of LWD measurements provides
information to differentiate clay-filled and open fractures.
- Identification of relatively fresh intrusives/dykes is
an important consideration to incorporate while performing basement evaluation.
- An integrated workflow using all type of borehole
images and acoustic measurements eventually provides the identification of potential flow zones.
- A geochemical approach is required to differentiate intrusive bodies of variable composition and their
dipping attitudes.
- Rotary steerable systems reduced the shocks
and vibration to within the safe LWD operating limits in
while-drilling mode.
References
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Nhuan, and Tran Duc Lan. Reservoir parameter evaluation for reservoir study and modeling of fractured
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Tamagawa, Amy Day-Lewis and Collen Barton. Roles
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FengPing, Yin ChangHai, T. J. Neville, S. Farag, Yang
X. W., and Zhu YouQing. Petrophysical characterization of a complex volcanic reservoir. SPWLA 48th
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7. M. Lefranc, A. Carrillat, and A. Carnegie.
Fractured basement characterization from multi-attributes guided integrated continuous fracture modelling
and discrete fracture network modelling. Extended
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March 29-30, 2010.
8. Nguyen Tien Long, Joel Guttormsen, Patrick
Jonklaas, II Kwon Cho, Tran Hung Dung, and Bingjian
Li. Fracture characterization of the Su Tu Den and Su
Tu Vang fields, Cuulong basin, Vietnam. ScienceTechnology Conference, Vietnam, 24-25 August, 2005.
9. P. M. Tandom, N.H. Ngoc, H.D. Tjia, and P.M.
37
Lloyd. Identifying and evaluation producing
horizons in fractured basement. SPE 57324,
1999.
CALI: Caliper from geoVision tool measurements
10. Raphael Altman, B. Anderson, J.
Rasmus, and M. G. Luling. Dielectric effects
and resistivity dispersion on induction and
propagation-resistivity logs in complex volcanic
lithologies. A case study: SPWLA 49th Annual
Logging Symposium, May 25-28, 2008.
DRHB: Density correction, Delta-Rho bottom quadrant
11. Rasmus J, Tabanou J, Li Q, Liu CB,
Pagan R, Pacavira N, and Higgins T. Resistivity
dispersion - fact or fiction?. SPWLA 44th Annual
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12. Singh, S. K., H. Abu Habbiel, B. khan,
M. Akbar, A. Etchecopar, and B. Mohtaron.
Mapping fracture corridors in naturally fractured reservoirs: An example from Middle East
carbonates: First Break 26, No 5, 109-113,
2008.
DTCO: Compressional slowness
DWAL: Dry weight concentration of aluminum
um
DWFE: Dry weight concentration of iron
DWGD: Dry weight concentration of
gadolinium
DWSI: Dry weight concentration of silicon
DWSU: Dry weight concentration of sulfur
DWTI: Dry weight concentration of titanium
IDD: Image derived density
13. Singh, S.K, M. Akbar, B. Khan, Hanan
A.H, Bernard M., Lars S., and Robert G.
Characterizing fracture corridors for a large
carbonate field of Kuwait by integrating borehole data with the 3-D surface seismic. AAPG
Search and Discovery article 40464 2009.
GRMA: Gamma ray, averaged from
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analysis using modern geophysical well techniques: Application to basement reservoirs in
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PEF: Photoelectric factor
RHGE: Matrix density from spectroscopy
measurements
RING: Ring resistivity from geoVision tool
Acronyms Description
ROBB: Bottom quadrant density
BDAV: Deep button average resistivity from
geoVision tool
ROP: Rate of penetration
BMAV: Medium button average resistivity
from geoVision tool
BPHI: Best neutron porosity
BSAV: Shallow button average resistivity
from geoVision tool
38
DEVI: Borehole deviation
S/T Plane Slowness-Time
coherency
projection plane from SonicVision tool
SIFA: Formation sigma from EcoScope tool
UCAV: Ultrasonic caliper averaged from
EcoScope tool
PETROVIETNAM
Fig. 1. Su Tu Vang field, GVR measurements through wash-down mode, ~120 m/hr. Average resistivity measurements
from shallow and medium buttons are borehole affected over breakouts interval. Breakouts at the top and bottom of the
hole suggest that minimum stress is nearly vertical (σv=σ3). Average quadrant (left, right, upper and bottom) measurements from shallow, medium and deep buttons are plotted on the first 3 tracks from right. Deep button/ring is affected in
this case. Caliper log is derived from all 4 resistivity measurements
Fig. 2. Su Tu Vang field,
GVR measurements in
while-drilling mode, ROP
~20 m/hr. High-resolution
images indicate numerous
small-scale natural fractures. Fractures appear on
all three images, indicating
that fractures are continued
away from the wellbore by
~5 inches. Further, some
fractures from 6185 to 6187
m, show aperture variation
from the shallow to the deep
image. This implies that
some of the small-scale
fractures were enhanced by
the drilling process in the
near-wellbore environment
39
Fig. 3. Large and open fracture
visible on all three images
(resistivity, ultrasonic and density). Shear slowness arrival is
distorted against the fracture
opening
Fig. 4. Slower logging (~20m/hr)
means high resolution images.
Small-scale fractures resolved
by GVR resistivity only. Fractures
are dipping at high angle and
striking towards NW-SE
Fig. 5. Small fractures as in Fig.
4. GVR shallow image affected
because of formation oil coming
in the borehole and affecting
most of the shallow-button measurements. Bottom quadrant
measurement from shallow-button reading formation where
borehole fluid is less. This also
provides a clue for oil presence
within these fractures
40
PETROVIETNAM
Fig. 6. Large (open) fracture response on image
logs at 4086 m. Zone ~2 m
above this fracture appears
to be filled with conductive/clay minerals. Smallsize fractures can be
observed on GVR image
between 4080 to 4082m
and 4093.7 m.
Fig. 7. Fresh intrusive (dyke) response on multiple
logs, i.e., GR, RING, Pef, BPHI, and sigma
Fig. 8. Drilling artifacts on the low side of the hole at 4145
and 4148 m. The average and bottom quadrant
azimuthal measurements are be affected, indicating
that borehole enlargement against these features
is not fracture related
41
Fig. 9. Stereonet projection and rose plot showing distribution of small-, medium- and
large-scale fracture sets. Two distinct fracture orientations are identified, i.e., NW-SE
and NE-SW. Most of the large and medium-scale fractures are relatively low dip angle
and are trending towards NE-SW
Fig. 10. Fracture analysis using GVR (deep), ultrasonic caliper and density images.
Right track is the cumulative fracture density logs from small, medium and large-fracture sets. Fracture zone from 4120 to 4180 m indicates a potential flow interval where
large and medium fractures are present
42
PETROVIETNAM
Fig. 11. Advanced technique for basement evaluation. Three potential flow zones
identified by the integrated analysis. Results indicate that zone-1 has the highest
contribution potential in the 3560 to 3580 m interval, zone-2 at 3460 and relatively low contribution from zone-3 from 4080 to 4180 m
Fig. 12. Elements dry weight percent of Al, Si, Ca, Fe, S, Ti and Gd for the interval logged at ~20 m/hr speed as a test case for 30 m intervals. The general,
WALK2 oxide closure model used for stripping the elements indicates ~35 to 40
wt.% Si,6 to 8 wt.% Fe and 6 to 8 wt.% Al
43
Determination of shale resistivity based
on 2-D geoelectric forward modelling for
evaluation of a low resistivity formation
Pham Huy Giao, Panupong Dangyeunyong
Geoexploration and Petroleum Geoengineering (GEPG) Program
School of Engineering and Technology
Asian Institute of Technology
Abstract
It is commonly interpreted that hydrocarbon is associated with a high-resistivity or a high-contrast
formation. In reality, however petroleum can be found in low resistivity or low contrast reservoirs. That
means we may miss some hydrocarbon zones by simply using conventional method of evaluation. With
the current economics of the oil and gas industry, it becomes increasingly important to find a way to do
44
PETROVIETNAM
better evaluation of the low-resistivity formations, which are quite commonly encountered in the Cuu
Long basin, offshore Vietnam. There are basically three main types of low resistivity formations due to
clay minerals, high capillarity and metallic minerals, respectively. In this study we deal with a case of the
first type, i.e., of low-resistivity formation due to thin shale lamina. The key point in our study approach
was we applied a two-dimensional resistivity forward modeling using RES2DMOD software to simulate
the resistivity logging process running along the borehole to find out the correct value resistivity of shale
lamina, which will be used for a better evaluation of water saturation. As a case of study the results from
a location in the Cuu Long basin are shown to illustrate our methodology, which is recommended to be
applied in practice…
Introduction
According to Berger (1995) a formation is considered as a low resistivity HC- bearing formation if: (i) the
measured wireline logging resistivity is from 0.5 to
5Ωm; (ii) there is not seen a clear contrast of resistivity between the HC reservoir and the adjacent zones
and he called it “a low-contrast pay sand”. The latter is
in line with Worthington et al. (1997), who considered
that a low-resistivity pay is a relative term rather than
an absolute descriptor and it exists when there is a
lack of positive contrast in measured electrical resistivity. So, the term low-resistivity pay includes low-resistivity-contrast pay. Worthington et al., (1997) suggested a low resistivity hydrocarbon formation is due to six
possible causes as follows: (i) Effect of laminated
sand/shale sequence; (ii) Effect of fresh formation
water: The resistivity value of fresh water is higher
than electrolyte water and equal to hydrocarbon bearing; (iii) High capillarity due to fine-grained silt, which
comprises of high irreducible water having low due to
its increased salinity; (iv) High capillarity due to internal microporosity (e.g., in carbonates, chert, chalk),
which leads to high specific surface area and high conduction on surface; (v) High capillarity due to superficial microporosity caused by clay minerals coating
quartz. This case is like a combination of two previous
causes of high irreducible water and high conduction
on surface; and (vi) Existence of conductive minerals
in rocks, and namely, when the iron-bearing minerals
exceed a critical level (e.g., for pyrite this is 7% by volume of solids) the resistivity of formation is low.
been used to describe any alternating sequence of
sediments that cannot be resolved by conventional
logging tools (Worthington et al., 1997). Having
established that the reservoir is laminated and the
laminations are smaller than the spatial resolutions of
the deeper sensing logging tools, the next stage is to
enhance those resolutions where possible, so that
the corresponding logs might be evaluated directly. If
the signal enhancing does not resolve the layer, we
should work on laminated sand model as described
in details in the following.
Assume a laminated reservoir, consisting of alternating layers of shale and sand as shown in Fig. 1.
Below is a derivation of an equation to evaluate the
water saturation in this case:
Front view
Fig. 1. Model of laminated shale
Vsh =
∑h
shi
ht
Model of low resistivity formation with laminated
shales
1 − Vsh
1 1 − Vsh Vsh
1 Vsh
=
+
⇒
=
−
Rt
Rsd
Rsh
Rsd
Rt Rsh
The word lamina describes a layer that is less
than about 15 cm thick. The adjective “laminated” has
⇒
(Eq. 1)
⎛ 1 V ⎞
1
1
= ⎜ − sh ⎟ ×
Rsd ⎜⎝ Rt Rsh ⎟⎠ (1 − Vsh )
45
Where: Rt is the resistivity of the HC-bearing formation measured by the logging tool, Rsd is the true
resistivity of the sand lamina, Rsh is the resistivity of
the shale lamina, Vsh is the shale volume, hshi is the
thickness of the shale lamina.
The resistivity of sand (Rsd) in Eq. 1 is the very value
one would like to use in evaluating the water saturation
for a clean sand formation, which is however can not be
read from the logging curve as the measured resistivity
is a lumped values of the rock mass, including the effect
from both sand and shale lamina. In this dirty sand
model the shale lamina would cause the apparent resistivity measured by well logging tool decreasing.
With further derivation as shown in Eq. 2 below we
can obtain the equation to evaluate the water saturation for a laminated formation:
Rsd =
⎫
⎪
a
⎪
m
⎬ ⇒ Fsd = m (1 − Vsh )
Φ ⎪
Φ
=
1 − Vsh ⎪
⎭
Fsd =
Φ sd
Fsd RW
F R
⇒ SWn = sd W
n
Rsd
SW
a
Φ msd
⇒ SWn =
⎛
a
(1 − Vsh )m × RW × ⎜⎜ 1 − Vsh
m
Φ
⎝ Rt Rsh
(Eq. 2)
⎞
1
⎟⎟ ×
⎠ (1 − Vsh )
One can write the above equation in a more compact form as follows:
∴ SWn =
aRW
Φm
⎛ 1 Vsh
⎜⎜ −
⎝ Rt Rsh
⎞
⎟⎟ × (1 − Vsh ) m −1
⎠
(Eq. 3)
spaces, including the flushed, invaded and virgin
zones depending on the radius of investigation or the
distance between the electrodes. To estimate water
saturation the Rt value in Eq. 4 can be read from the
LLD curve, but it is difficult to determine Rsh and its
effect in modifying the Rt. Our main idea is to determine Rsh based on a forward modeling with the help of
the software RES2DMOD (Loke, 2002), which is a 2D
forward modeling program that can calculate the
apparent resistivity for a user defined 2D subsurface
model. RES2DMOD could be used for many applicaions in Petrophysics or exploration geophysics
(Giao, 2009). In this study RES2DMOD is used to simulate the resistivity measuring process of the logging
tool along the borehole.
The workflow to estimate water saturation of a
low-resistivity HC formation employed in this study is
shown in Fig. 2, combining well logging interpretation
and electric forward modeling. For the latter, we will
build up a model of a laminated reservoir as shown in
Fig. 3 and perform many resistivity modeling runs
until we obtain a good matching between the measured resistivity curve and the numerically-calculated
one. The parameters of the model that gives the best
fit, in particular the resistivity of the shale lamina, will
be introduced in Eq. 3 or Eq. 4 to calculate the water
saturation.
Electric resistivity forward modelling for a location
in the Cuu Long basin
Resistivity measuring and modelling
The Cuu Long basin is a Tertiary rift basin on the
Southern shelf of Vietnam. It covers an area of approximately 25,000km2 (250 x 100km). The basin was
formed during the rifting in Early Oligocene. Late
Oligocene to Early Miocene inversion intensified the
fracturing of granite basement and made it become an
excellent reservoir. Most of the oil and gas production
in Vietnam comes from this basin. It is often that petrophysicist engineers have encountered the low-resistivity formation in this basin when doing the well logging
interpretation.
High Resolution Laterolog Array (HRLA) introduced by Schlumberger in 1998 (Smits et al., 1998) is
commonly used for resistivity logging: Was. It included
six array configurations with six depths of investigation. When the resistivity logging is conducted HRLA
will measure the resistivity of the near well bore
A data set consist of gamma ray, density, neutron
porosity and resistivity log for the depth interval from
1,650 to 2,200m were used as shown in Fig. 4a. For
electric modeling a more detailed interval from 2,100 to
2,120m, where there is a gas show as identified from
density and neutron porosity cross-plot, was selected.
For a = 1, m = 2 :
⎛ 1 V ⎞ aR (1 − V )
SW2 = ⎜⎜ − sh ⎟⎟ W 2 sh
Φ
⎝ Rt Rsh ⎠
(Eq. 4)
From Eq. 4 one can realize on one of the key problems here is how to determine a good values of the
shale resistivity (Rsh). And this is the central point our
study is focused on presented in the following parts of
this paper, using 2-D electric forward modeling.
46
PETROVIETNAM
Well logging data
(Gamma logs,
Porosity logs etc.)
RES2DMOD
Identification of reservoir zone
Create the geomodel of the
near-wellbore environment
for simulation
Forward Modeling by
RES2DMOD
Logs and core data
Petrophysical analysis
(e.g.,water saturation)
(b) 2100 - 2120m
Fig. 2. Workflow chart of methodology employed in this study
Fig. 4. The depth interval selected for well logging
interpretation (a) and resistivity forward modeling (b)
The reading step of the logging data is about 1.5m,
therefore we selected a dipole-dipole array of 1.5-m
spacing for analysis in RES2DMOD to simulate the
measuring procedure. The saltwater-based mud in
hydrocarbon bearing zone is considered with Rmf =
Rw, Rxo = 0.3Ω.m, Ri = 1.0Ω.m, hxo = 0.1m, hi = 0.2m
and hv = 1.0m. The water resistivity (Rw) can be determined using the Pickett chart as presented later.
Fig. 3. Geomodel of the near-wellbore environment
with multi-laminated shale
Thirteen geoelectric models were built up and run
by RES2DMOD as shown in Table 1. The forward
models have total length 21 meter corresponding to
the length of the selected zone from 2,100 to 2,120m.
During the analyses the resistivity of sandstone, shale,
flushed zone, invaded zone as well as thickness of
sand and shale lamina are changed. The true positions of shale lamina could be identified by the GR.
Table 1. Input parameters used in geoelectric forward modeling
(a) 1650 - 2200m
Geomodel
1
2
3
4
5
6
7
8
9
10
11
12
13
Rsd (Ωm)
1.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
100.0
Rsh (Ωm)
0.5
5.0
3.0
3.0
3.0
3.0
2.0
2.0
2.0
2.0
2.0
2.0
2.0
Rxo (Ωm)
0.3
1.0
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
0.3
Ri (Ωm)
1.0
3.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
1.0
47
After we input data into RES2DMOD a geomodel
is created as shown in Fig. 5. The light blue strips are
shale and dark blue strips are sandstone.
Rxo
Ri
Rsa
Rsh
Fig. 5. An example of a geoelectric model created
by RES2DMOD
Table 2. Summary of water saturation calculated
by different methods
Method
Archie
Indonesian
Laminated shale
Minimum
0.58
0.22
0.04
Maximum
1.00
1.00
0.67
Average Sw
0.85
0.55
0.27
The resistivity along the analyzed depth interval
(Fig. 4b) was calculated using the pole-pole configuration that simulates the HRLA tool. With the electrode
spacing used in the simulation equal to 1.5m, it is estimated that the resistivity comes from a 1.3-m distance
far from the well bore, i.e., d = electrode spacing x Ze
= 1.5m x 0.867 = 1.3m according to Loke (2002). The
results of some resistivity models are plotted versus the
log values (Rt) as shown in Fig. 6. It was found out that
resistivity of the model nos. 13 (Table 1) matched the
best with the log resistivity, consequently the resistivity
of shale lamina in this model will be used in the next
petrophysical analysis. With Vsh = 0.48 and Rw, =
0.05Ωm as determined from the Pickett chart with m =
2 the water saturation was calculated using three methods, i.e., Archie’s law (the upward arrow head),
Indonesian (the black star) and the laminated shale
model (the black square) as shown in Fig. 7. The water
saturation from Archie’s equation shows the highest
value for all depth levels, while the laminated shale
model gave the lowest value as summarized in Table 2.
Conclusions
Fig. 6. Comparison of resistivity curve calculated by
RES2DMOD with the measured logging curve (Rt)
Fig. 7. Evaluation of
water saturation
for the study site
48
In this study, first of all we reviewed and derived in
details the equation to calculate water saturation for a
laminated shale model, which is considered as one of
the basic types of low-resistivity reservoir. An innovative approach to determine the shale resistivity based
on geoelectric forward modeling was proposed and.
As the first step a geoelectric model was constructed,
consisting of flushed zone, invaded zone and an alternation of sand and shale lamina as illustrated in Fig. 3
and 5. We selected an interval from 2,100 to 2,120
meter depth at a location in the Cuu Long basin as a
case study, where there is evidence of a gas zone having low resistivity of about 2 to 3Ωm (as identified by a
crossover of RHOB and neutron and NPHI curves). A
total of 13 numerical models were run for this 20-m
long interval as shown in Table 2. The results of forward modeling were compared with the measured
resistivity as shown in Fig. 6 and it was found out that
the model number 13 gave the best fit. Based on the
resistivity computed from the numerical model a
quick petrophysical analysis was carried out for the
PETROVIETNAM
considered reservoir interval. The water saturation
was evaluated by Archie’s, Indonesian, and laminated
shale’s equations, respectively. The laminated shale
model gave the most optimistic water saturation. We
recommend this approach to be applied for the other
reservoir of low resistivity caused by thin shale lamina.
Acknowledgements
The help and useful discussions with Dr. Hoang
Phuoc Son and Mr. Mai Thanh Binh from Con Son
JOC are very much appreciated.
References
1. Berger, P., 1995. Detecting Hydrocarbons in
Low Resistivity Environments. Schlumberger.
2. Giao, P.H., 2009. Lecture notes in Petrophysics.
Asian Institute of Technology, Thailand.
3. Loke M.H., 2002. RES2MOD Ver 3.01 Geomoto
Software. www.geoelectrical.com.
4. Smits, J.W., Dubourg, I., Luling, M.G., Minerbo,
G.N., Koelman, J.M.V.A., Hoffman, L.J.B., Lomas, A.T.,
Oosten, R.K.v.d., Schiet, M.J. and Dennis, R.N., 1998.
Improved Resistivity Interpretation Utilizing a New
Array Laterolog Tool and Associated Inversion
Processing, paper SPE 49328.
5. Worthington, P.F., 1997. Recognition and
Development of Low-Resistivity Pay, paper SPE
38035.
49
PETROLEUM PROCESSING
Abstract
Nowadays, waste cooking oil is one of the sources of biodiesel
production. However, waste cooking oils purchased in the market are
very crude with high free fatty acid content. The appearance of free
fatty acids in crude waste cooking oil severely causes saponification
and interferes with the transesterification reaction. This article presents results of treatment process of waste cooking oil purchased
from restaurants in Hanoi. The objective of this study is to separate
free fatty acid from oil which is then used to synthesize biodiesel on
heterogeneous catalyst Na2CO3/Al2O3. The results showed that crude
waste cooking oil has been treated. The acid number of oil is reduced
from 6.16 down to 0.56 mg KOH/g.
Study of treating waste cooking oil for
biodiesel synthesis using heterogeneous
catalyst Na2CO3/Al2O3
Hoang Linh Lan
Nguyen Ngoc Diep
Le Thi Phuong Nhung
Vietnam Petroleum Institute
1. Introduction
Nowadays, in parallel with the
depletion of fossil fuels such as
petroleum and coal, one of the
problems facing humankind is global environmental pollution by flue
gas emission from internal combustion (IC) engines. Therefore, it is
extremely important to discover
new energy sources to gradually
replace exhausting fossil energy
resources, assure energy security
and reduce environmental pollution.
Using bio-fuels, especially biodiesel
due to dieselization tendency of
engines, is the solution currently
concerned by the whole world.
Biodiesel is mostly produced
from vegetable oils by transesterification reaction on homogeneous
lye catalyst. However, vegetable oil
is costly and its usage influences
food security. Meanwhile waste
cooking oil, considered as having
50
similar nature with vegetable oils,
costs less and is easily collected in
high quantity. It is estimated that 4
- 5 tons of waste cooking oil per
day can be collected in Ho Chi
Minh City. Furthermore, the use of
homogeneous catalyst in the production of biodiesel has some
drawbacks such as: Causing
saponification reaction, resulting in
difficulty of rinsing product, and
producing wastage due to unrecyclable catalyst. Hence, using waste
cooking oil to synthesize biodiesel
on heterogeneous catalyst will contribute to the development of the
economy and reduce environmental pollution.
Waste cooking oils collected
from different restaurants contain
impurities, especially free fatty
acids which need to be removed.
The high content of free fatty acid in
waste cooking oil reduces the
PETROVIETNAM
biodiesel production yield. According to some
published studies, waste cooking oil with acid
number below 2 mg KOH/g meets the requirement of material for producing biodiesel [1].
Therefore, crude waste cooking oil with acid
number of 6.16 mg KOH/g collected from restaurants in Hanoi has to be treated to decrease free
fatty acid content. Due to the acid number of
waste cooking oil is often less than 20mgKOH/g,
alkali solutions can be used to neutralize to
reduce this number [1, 2, 3]. Therefore, on the
field our study, waste cooking oil will be treated
by alkali solutions with evaluation of factors
affecting the process of treating. From there, the
most appropriate set of treating process conditions for Vietnamese waste cooking oils will be
determinated. Treated waste cooking oil with
acceptable value of acid number was used as
material to produce biodiesel on heterogeneous
catalyst Na2CO3/γ-Al2O3.
2. Experiment
2.1. Treating waste cooking oil
The waste cooking oil is neutralized using
alkali solution as follows:
+ Pour 100 mL waste cooking oil (filtered
through cotton to remove solid impurities) into
250 mL graduated glass. Stir and heat oil to
600C.
+ Eliminate free fatty acid in crude waste
cooking oil by pouring drop by drop 40 mL of alkali solution with calculated concentration. Maintain
temperature reaction at 600C in 15 minutes.
2.2. Production of biodiesel from waste cooking oil on
heterogeneous catalyst Na2CO3/γ-Al2O3 [4, 5]
Treated waste cooking oil and catalyst Na2CO3/γ-Al2O3
are poured in a tri-neck flask connected to a refrigerating
reflux and thermometer. All of which are placed on a magnetic stirrer. This mixture is stirred at 600 c/m speed and heated
to 400C. After that, methanol is added. Continue to heat the
solution to 600C and maintain this temperature during the
reaction. When the reaction is finished, stop stirring, cool the
mixture to room temperature and remove catalyst, excess
methanol and glycerin to obtain final product.
3. Results and discussion
3.1. Evaluation of factors affecting the process of treating waste cooking oil
3.1.1. Influence of neutralizing agent on the treatment of
waste cooking oil
Waste cooking oil is treated with different neutralizing
agents such as NaOH, KOH, Na2CO3 with the same concentration of 10%, the same times and temperature of rinsing
water. The results are shown below:
Table 1. Influence of neutralizing agent on acid number
and productivity
Neutralizing agent
Acid number, mg KOH/g
Yield of treated waste cooking oil, %
NaOH
0.56
85
KOH
0.57
85
Na2CO3
0.92
78
The results showed that among three investigated neutralizing agents, NaOH and KOH are better because of lower acid
number and higher yield of obtained treated waste oil. So,
NaOH as neutralizing agent will be chosen for the next investigations due to its popularity and easy-to-buy in the market.
3.1.2. Influence of NaOH concentration
+ Transfer reacted mixture into separatory
funnel.
The study of influence of NaOH concentration on acid
number and oil productivity is shown in Fig. 1.
+ Remove excess alkali solution in treated oil
by rinsing 100 mL-portion of hot water several
times (use phenolphthalein indicator to test pH).
It is inferred from Fig. 1 that when the solution of NaOH
10% is used, neutral oil has near minimum acid number and
+ Evaporate water remaining in treated
waste cooking oil at 1300C and obtain treated
waste cooking oil.
100
Yield of treated
waste cooking oil, %
+ Remove sulfate ions totally by rinsing hot
water.
6
+ Push out soaps from waste cooking oil to
advoid emulsification of rinsing water by sodium
sulfate solution 5% until rinsing water is neutral;
5
4
3
2
1
0
80
60
40
20
0
0
2
4
6
8
10
NaOH concentration, %
12
14
0
2
4
6
8
10
12
14
NaOH concentration, %
Fig. 1. Influence of NaOH concentration on acid number
and yield of treated waste cooking oil
51
100
6
Yield of treated
maximum yield. The reason is that
at that concentration NaOH in the
solution, the neutralization reaction
occurs thoroughly. Therefore the
decantation is clearer, making it
easier to recover oil and leading to
higher yield.
PETROLEUM PROCESSING
5
4
3
2
1
80
60
40
20
0
0
40
50
60
70
80
90
100
40
110
50
60
It is inferred from Fig. 2 that the
optimum temperature of rinsing
water is about 800C. At which temperature the obtained oil has minimum acid number and maximum
recovery capacity. It can be
explained that with low temperature
of rinsing water, the flexibility of
rinsing water is limited, leading to
low capability of decanting soap
and excessive alkali. Therefore the
soap and alkali are still dispersing
in oil, which reduces the capacity of
recovering oil. In contrary, with high
temperature of rinsing water, oil is
easily emulsified, which makes the
decantation not thoroughly lead to
a low capacity of recovering oil.
3.1.4. Influence of rinsing times
Oil is rinsed for certain times
before being determined acid number and yield. The results are
shown in Fig. 3.
It is inferred from Fig. 3 that
the more oil is rinsed, the lower
the yield is and so is acid number.
It could be easily explained that
as much oil is rinsed, a certain
52
90
100
110
Fig. 2. Influence of temperature of rinsing water on acid number
5
100
Yield of treated
The product of the reaction
after being decanted to eliminate
soap is then rinsed with hot water.
The influence of the temperature of
rinsing water in the range of 500C
to 1000C was investigated. The
results are shown in Fig. 2.
80
o
Temperature, C
3.1.3. Influence of temperature of
rinsing water
70
Temperature, C
o
4
3
2
1
95
90
85
80
0
0
1
2
3
4
5
6
7
8
9
Rinsing times
0
1
2
3
4
5
6
7
8
9
Rinsing times
Fig. 3. Influence of rinsing times on acid number
quantity of oil is eliminated in the residue water. Moreover, excess acid
is neutralized more thoroughly, which makes oil with lower acid number.
Basing on the results obtained, with 4 times of rinsing, the acid number
of oil was decreased to under 2mg KOH/g oil; with 5 times of rinsing,
this number is 0.91 mgKOH/g but the productivities were not changed
much (from 92% down to 90%). Therefore, the appropriate rinsing time
is about 5 at which the treated oil has an acceptable acid number and
high yield.
3.2. Analysis of quality tests of biodiesel synthesized from waste oil
Treated waste cooking oil is then used to synthesize biodiesel on heterogeneous catalyst Na2CO3/Al2O3. The effect of treament of waste cooking oil on the yeild of biodiesel synthesis process is shown in Table 2.
It is inferred from Table 2 that the lower of acid number of treated
Table 2. Yield of biodiesel synthesis process from treated waste cooking oil of
different quatities
STT
Acid number of treated waste
cooking oil, mg KOH/g
Yield of biodiesel synthesis,
%
1
6.16
32
2
3
4
5
3.25
1.97
0.91
0.56
63
90
92
95
PETROVIETNAM
waste cooking oil, the higher yield of biodiesel. Thus, the acid number
affects greatly the yield of biodiesel synthesis. Therefore the treatment to
reduce the acid number of the waste cooking oil is very necessary.
Some of the important physicochemical properties of synthesized
biodiesel are shown in Table 3.
Table 3. Quality tests of biodiesel synthesized from waste cooking oil
STT
Properties
Analysis method
0
TCVN 6594
(ASTM D 1298)
EN 14103
TCVN 3171
(ASTM 445)
TCVN 2693
(ASTM D 93)
1
Density at 15 C
2
Ester content
Kinematic viscosity
0
2
at 40 C, mm /s
3
4
0
Flash point, closed cup, C
6
Vacuum distillation end
0
point, 90% volume, C
Heat of combustion, kJ/kg
7
Cetane number
5
8
9
10
11
Total sulfur, % mass
Copper strip corrosion
0
at 50 C, 3h
Free glycerin, % mass
Total glycerin, % mass
Standard Biodiesel
by TCVN 7717:2007 [6]
Biodiesel
from waste oil
0.860 - 0.900
0.883
> 96.5
98.41
1.9 - 6.0
4.41
130 min
140
ASTM D 1160
≤ 360
351
ASTM D240
TCVN 7630
(ASTM D 613)
ASTM D 5453/TCVN
6701
TCVN 2694
(ASTM D 130)
ASTM D 6584
ASTM D 6584
-
41.079
> 47
52
< 0.05
0.005
No.1
No.1
0.020 max
0.240 max
< 0.001
< 0.001
The results in Table 3 show that the biodiesel produced from waste
cooking oil meets all specifications of Standard TCVN 7717:2007.
4. Conclusions
1. Waste cooking oil collected from restaurants in Hanoi has been successfully treated to acid number at 0,56 mgKOH/g oil with a yield higher
than 85%. The procedure is as followed: Neutralize free fatty acids in oil
with NaOH solution 10%, then rinse 5 to 8 times with hot water of 800C
and sodium sulfate solution 5% to eliminate excessive alkali and soap.
After that continue to rinse the obtained neutralized oil by hot water until
sulfate ions are totally eliminated. Finally evaporate water at 1300C to
obtain final product.
2. Experimental results show that the acid number of raw waste cook-
ing oils greatly influence the yields
of synthesizing biodiesels.
3. The biodiesel synthesized
from waste cooking oil meets all
specifications in the standard for
B100
in
Vietnam
(TCVN
7717:2007).
References
1. Hackleman D., Yokochi A.
Production of Biodiesel from waste
cooking oil. 2006
2. Hideki Fukuda et all. Review
Biodiessel fuel production by
tranesterification of oil. J. Biosci.
Bioeng. (2001), p.405-416
3. J. Van Gerpen, B. Shanhks,
and R. Pruszko Iowa State
University D. Clements Renewable
Products Development Laboratory
G. Knothe USA/NCAUR. Biodiesel
Production Techonology. August
2002 January 2004, NREL/SR510-36240.
4. http://www.biodiesel.org/pdf
files/emissions.PDF.
5. Staat, F.Vallet. Vegetable oil
methylester as a diesel subtitute.
Chem. Ind. 21, 863-865
6. TCVN 7717:2007. Nhiên liệu
diesel sinh học gốc (B100). Yêu
cầu kỹ thuật.
53
PETROLEUM TECHNOLOGY & CONSTRUCTION
Applicability of GTL
technology in Vietnam
Kazuhito Katakura, Yoshifumi Suehiro,
Yoichi Norisugi, Hitoraka Shimizu, Hirokazu Tada,
Technology Research & Development Division,
Japan Oil, Gas and Metals National Corporation (JOGMEC)
Abstract
Japan Oil, Gas and Metals National Corporation (refer to as
“JOGMEC”) has been developing Gas-To-Liquids (refer to as
“GTL”) technologies with Nippon GTL technology Research
Association (refer to as “Nippon GTL Association”) established
by six Japanese private firms including JX Nippon Oil & Energy
Corporation (refer to as “NOE”), which is a part of Three Core
Operating Subsidiaries of JX Holdings Inc. GTL technology is
effective in contribution to securing and diversifying alternate
fuel source. Furthermore, utilizing associated gas from offshore oil fields for GTL feed gas without flaring serves reducing global warming potential and corresponds to environmental regulations. Japanese novel GTL technologies have the following feature:
54
PETROVIETNAM
(1)
CO2 utilization:
JAPAN-GTL process can
utilize CO2 as GTL feed gas to
produce clean fuel. It is developed by JOGMEC and Nippon
GTL Association consisting of
six private Japanese firms
such as INPEX, NOE, JAPEX,
COSMO Oil, Nippon Steel
Engineering (refer to as
“NSE”), and CHIYODA (refer
to as “CYD”). The entire GTL
technologies have root in
Japanese companies. Its technical stage is at demonstration, of which the capacity is
500 BPD. After establishing it
as commercial level through
demonstration
project,
JAPAN-GTL is expected to
make its debut in the world.
(2)
Associated gas utilization:
The process of Advanced
Auto-thermal
Gasification
(refer to as “A-ATG”) is the
novel syngas production technology developed by JOGMEC, JGC, and Osaka Gas. It
consists of a new auto-thermal reforming catalyst with
ultra-deep desulfurization of
natural gas. A-ATG can realize
compact reactor to produce
syngas effectively. It may
allow to be loaded on FPSO on
producing GTL from associated gas at offshore oil field. Its
technical stage is at pilot
plant, of which the capacity is
65 BPD equivalent of GTL
products.
This paper addresses the
applicability of GTL technology in Vietnam and introduces
the current status of GTL technologies developed in Japan.
1. Introduction
to gain alternative fuel sources to
petroleum and achieve the diversification of primary energy supplies in energy security for Japan.
Besides GTL has a variety of
advantages: e.g.; it is available to
monetize stranded gas reserves
and contribute flaring reduction
for upstream business and it has
environmental advantages such
as sulfur free and aromatic free
and realizes efficient performance of diesel engines due to
very high Cetane Number and
furthermore enables to utilize the
existing infrastructure and facilities for downstream business.
GTL is anticipated to increase the
share of Global Liquid Production
in the future (Fig.1).
Energy stable supply is important issues for Japan in the view
that global energy demand is presumed to be increased, especially
by the nations of Asia. In the situation that our oil and gas self-sufficiency is in a low level, Japan
needs to propel research and
development together with an
exploration campaign for oil and
gas outside of Japan.
According to the report of EIA
2010, world use of liquids and
other petroleum grows from 86.1
mmbpd in 2007 to 110.6 mmbpd in
2035. In the transportation sector,
despite rising prices, use of liquid
fuels increases by an average of
1.3% per year, or 45% overall from
2007 to 2035. Meanwhile natural
gas is widely distributed throughout the world and proved gas
reserves are approximately equivalent to proved oil reserves.
Counting associated gas and
coal bed methane (refer to as
“CBM”), usable gas source
exceeds oil. We focus on gas
through emerging gas technologies for energy supply.
This paper addresses the CO2
utilization by JAPAN-GTL Process
through the introduction of
JAPAN-GTL Demonstration Test
Project in Niigata Japan (refer to
as “Demonstration Project”) and
the Collaborative Study between
JOGMEC and Vietnam Oil and
Gas
Group
and
Vietnam
Petroleum Institute on the
Applicability
of
JAPAN-GTL
Process (refer to as “Collaborative
Study”), and the associated gas
utilization by A-ATG Process as
one of repertoires of emerging gas
technologies under development.
GTL is one of emerging gas
technologies, with which natural
gas as a raw material can be converted into petroleum products. It
is an extremely effective method
Global Liquid Production - Million Barrels per Day
14
Gas-to-liquids
12
Coal-to-liquids
Shale oil
10
Extra-heavy oil
8
Biofuels
6
4
Fig. 1. Global Liquid
Production (2007 - 2035)
Bitumen
2
0
2007
2015
Bitumen
Biofuels
2020
Extra-heavy oil
2025
Coal-to-liquids
2030
Shale oil
Gas-to-liquids
2035
Source: Table 3, International
Energy Outlook 2010
55
2. CO2 utilization
2.1. JAPAN-GTL Demonstration
Test
Project
in
Niigata
(Demonstration Project)
JOGMEC has been tackling the
research and development of the
natural gas conversion technology
since 1998. JOGMEC made the
“Joint Research Contract” with
Nippon GTL Association established by six private firms on 25
October 2006 following the Yufutsu
Pilot Test Project (2001 to 2004) in
order to conduct the Demonstration
Project (500 BPD) scheduled 5
years with an eye toward potential
international development, 15,000
to 20,000 BPD.
The construction of the JAPANGTL Demonstration Plant in Niigata
(refer to as “Demonstration Plant”)
was completed in March 2009 and
it has been in operation since the
opening ceremony took place on 16
April 2009. The production of 500
barrels (about 80 kiloliters) per day
was achieved.
The JAPAN-GTL process contains three core processes:
Synthetic gas production section
(refer to as “Syngas”), FT (FischerTropsch) production section (refer
to as “FT”) and Upgrading (hydrocracking) section (refer to as “UG”),
which equip with proper catalysts
developed by CYD, NSE and NOE
respectively. They have been tested in the Demonstration Plant.
Naphtha, Kerosene and Gas Oil
are produced from natural gas
including CO2.
In these processes, Syngas
applies the steam (H2O)/CO2
reforming, which differs from Autothermal Reforming (“ATR”) or Noncatalytic Partial Oxidation (“POX”)
56
as used in conventional GTL
processes. As Syngas is capable to
directly utilize up to 40 mol % of
CO2 included in the natural gas, it
does not require any oxygen (O2)
generator and carbon dioxide (CO2)
removal unit. We presume that
those equipments reduction will
contribute the CAPEX reduction.
We have feed gas sources from
offshore gas field by subsea
pipeline (small CO2 content) and
LNG (CO2 free) in Demonstration
Plant. Liquefied CO2 is carried by
lorry from outside and it is adjusted
to around 20mol% through vaporizer for the demonstration operation.
The main characteristic of
C apacity (B PD)
J OGMEC
Nippon GTL INPEX
NOC
J APEX
COSMO OIL
NSE(←NSC)
CHIYODA
20,000~
15,000
JOGMEC（
J NOC)
JAPEX
CHIYODA
COSMO OIL
NSC
INPEX
500
7
JAPAN-GTL process is to apply
the steam/CO2 reforming in the
Syngas production, which is able
to efficiently use CO2 included in
the natural gas and to produce
Syngas with the molar ratio of
H2/CO = 2/1 suitable for FT synthesis with one pass reaction. Such a
process will make it feasible to
eliminate O2 generator and CO2
removal unit. Syngas process features a high resistance to Carbon
Formation and long life. Feed
molar ratio Hydrocarbon/ CO2/
H2O is 1.0/0.4 - 0.6/1.15 - 1.64 at
temperature (catalyst bed outlet),
865 - 895 degree Celsius and
pressure, 1.5 - 1.9 MPaG.
15,000∼20,000B PD
C ommer cial Plant
500B PD
Demonstr ation P lant
( Niigata,J A P A N )
7B P D
P ilot Plant
(Y ufutsu,J APAN )
0.01
L ab/B ench
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
2015
2020
Fig. 2. History of R & D Activities
• Conventional Process（Auto Thermal Reforming）
CO2Removal
Natural Gas
（
Containing CO2 =20%）
Sulfur
Removal
Syngas
Production
O2 Plant
Air
In case of Natural
gas containing
20% of CO2
Utilizing CO2
• JAPAN-GTL Process
Natural Gas
（
Containing CO2 =20%）
Main Feature
Utilizing CO2
No need for O2 plant
FT Upgrading
Synthesis
Syngas Production
Steam/CO2 Reforming
Sulfur
Removal
Syngas
Production
FT Upgrading
Synthesis
FT Synthesis
SBCR with Co Based Catalyst
Upgrading
Fixed Bed Reactor
with Pt Based Catalyst
Fig. 3. Characteristics of JAPAN-GTL Process
PETROVIETNAM
2.2. Collaborative Study on the
Applicability of JAPAN-GTL
Process to Vietnam Oil and Gas
Group Natural Gas Resources
(Collaborative Study)
study, JOGMEC suggested applying imaginary offshore gas fields in
Vietnam as the target gas
resources.
The following is the evaluation
flow of this study:
Small Preliminary Study based
on the work chain was conducted
through 2007 to 2009 between the
Parties; i.e. JOGMEC, Vietnam Oil
and Gas Group and Vietnam
Petroleum Institute.
(a) Assumption:
+ Assumed several cases for
offshore gas fields varying independent parameters for distances
from shore (50, 100 and 150km)
and water depths (50, 100 and
200m).
The aim of the study is to clarify the availability of JAPAN-GTL
process to offshore gas fields in
Vietnam. As specific offshore gas
fields were not nominated in the
+ Beside assumed GTL plant
with three different capacities;
7,500, 15,000 and 30,000 BPD,
each of which receives natural gas
with three different CO2 contents;
0, 20 and 40%. It is presumed to
have 330 days of annual operation
in 20-year plateau.
+ Created the matrix of case
studies of Base Case (at 15,000
BPD and 20% CO2) and alternative scenarios shown on the chart.
(b) Calculation at Upstream:
+ Calculated CAPEX and
OPEX concerning upstream (offshore) development of gas fields
including subsea pipeline, presuming daily gas production rate
(mmscfd) and gas reserves (gross)
(TCF), which should be recoverable reserves assuming 1.2 times
to the cumulative production in 20
years, required to the operation of
GTL plant.
+ Calculated gas sales price
appropriate for the upstream (offshore) development of gas fields
on the condition of securing 10%
Internal Rate of Return (IRR) and
15% IRR. Gas sales prices for
alternative scenario among 81
cases are interpolated by the
assumption proportional to the
ratio of Base Case.
(c) Calculation at Downstream:
Fig. 4. Work Chain
Table 1. Combination of the study
Alternative Scenario
Base
Case
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Plant Capacity (BPD)
15,000
7,500
15,000
30,000
CO2 (%)
Distance from shore (km)
Water Depth (m)
20
50
50
50
100
100
100
200
200
200
50
100
150
50
100
150
50
100
150
100
100
100
100
100
100
0
20
40
0
20
40
0
20
40
+ Calculated CAPEX and
OPEX of three capacities of GTL
plant in Vietnam in view of location
factor and plant price index.
+ Calculated such gas prices
required by GTL plant as to
achieve 10% IRR and 15% IRR of
GTL plant on the condition that
product sales price for Naphtha,
Kerosene and Gas Oil is taken
from 5 years average of
International Market (Singapore)
Spot Price; i.e. Naphtha: US$
69.88/bbl,
Kerosene:
US$
57
(e) Example of Results:
+ A part of result with the pattern of gas sales price (IRR10%)
and the gas price required by GTL
plant (IRR 10%) of this study is
shown on the chart.
A target source gas field
requires gas reserves to meet
more than 15,000 BPD capacity
GTL plant that is nearly equal to
1TCF class reserves. GTL has
impact to the distance from shore
rather than water depth. As an integrated approach, it will be more
profitable to place GTL Plant as a
Profit Center, rather than source
gas field.
50
100
200
150
100
50
150
100
50
0
50
100
200
Water Depth (m)
50
30,000BPD
50
100
200
150
100
50
0
150
100
50
0
Water Depth (m)
Water Depth (m)
Water Depth (m)
100
0
15,000BPD
Water Depth (m)
Water Depth (m)
150
0
50
100
200
50
100
200
150
100
50
0
50
100
200
150
100
50
0
50
100
200
Water Depth (m)
Water Depth (m)
Legend
Water Depth (m)
+ In the case gas sales price is
less than the gas price required by
GTL plant, GTL plant will be feasible to offshore gas fields in
Vietnam.
CO2=0%
+ Compared two kinds of gas
prices between gas sales price
including IRR (10% and 15%) and
the gas price required by GTL plant
including IRR (10% and 15%). We
have 4 patterns and 324 cases (81
cases x 4 patterns) are generated.
CO2=20%
(d) Economic Evaluation:
7,500BPD
CO2=40%
83.59/bbl and Gasoil: US$
81.08/bbl at Dubai Crude Oil: US$
64.29/bbl.
150
100
50
0
50
100
200
150
Preferable
100
N/A
50
0
50
100
200
Fig. 5. Availability of JAPAN-GTL process to offshore gas fields in Vietnam
Pattern: Gas sales price (IRR10%) and gas price required by GTL plant (IRR 10%)
Source: Elvidgeet al (GGFR): A fifteen year record of Global Natural Gas Flaring Derived from Satellite
Data, 2009
Fig. 6. Global natural Gas Flaring (BCM - BCF)
3. Associated Gas Utilization by
A-ATG Process
The natural gas resources are
to a large extent located far from
their markets. Some 30% of the discovered gas is considered stranded. An additional 20 - 30% of the
world’s proven natural gas reserves
are found in oil reservoirs (associated gas). This has so far been much
more economical to flare.
Global gas flaring reasonably
trends constant over last 16 years
shown on the chart. Trend in
58
Onshore flaring
Offshore flaring (FPSO)
Flaring at onshore and offshore
reduction started 4 years ago
(2006) and this trend is expected
to continue.
More major facilities at offshore FPSO (Floating Production,
Storage and Offloading system) is
getting, more increased the flaring
will be. We focus on A-ATG
Process and FT Synthesis, which
is recoverable to convert gas to liq-
PETROVIETNAM
uid to reduce flaring on FPSO.
A-ATG process is a novel syngas production technology that combines ultra-deep desulphurization with
Catalytic Partial Oxidation developed by JOGMEC,
JGC, and Osaka Gas. We have been developing AATG process at a pilot plant, of which the capacity is
65 BPD equivalent to GTL products. It can realize
compact reactor to produce syngas effectively.
Technical challenge emerges in applying it to a floating
plant together with FT Synthesis to be connected at
downstream. It will constitutes an offshore type of GTL
process utilizing associated gas from small and middle
sized offshore oilfields.
The most significant features of A-ATG process is
summarized comparing to the conventional process
that equipped with steam reforming reaction and ATR
reaction with a burner. The conventional process has
a pre-reformer for steam reforming, a fired heater to
provide heat necessary for steam reforming and an
ATR reformer with a burner. Meanwhile A-ATG
process is a very simple process that produces synthetic gas in only one fixed bed reactor.
4. Conclusion
4.1. GTL
+ GTL is anticipated to increase the share of
Global Liquid Production in the future.
+ GTL is an extremely effective method to gain
alternative fuel sources to petroleum and achieve the
diversification of primary energy supplies in energy
security for Japan.
+ GTL is available to monetize stranded gas
reserves and contribute flaring reduction for upstream
business.
+ GTL has environmental advantages such as sulfur free and aromatic free and realizes efficient performance of diesel engines due to very high Cetane
Number and enables to utilize the existing infrastructure and facilities for downstream business.
4.2. CO2 utilization
+ JAPAN-GTL Process is available to utilize CO2
included in natural gas up to 40mol%.
Source: JOGNEC TRC week 2009
Fig. 7. Share of offshore Facilities
+ JAPAN-GTL will be available to apply offshore
gas fields (1Tcf class of gas reserves) in Vietnam
including CO2 in view of a small preliminary study.
Next step will need more detailed study.
4.3. Associated Gas Utilization
GTL is a useful method to reduce gas flaring at
onshore and offshore. Especially A-ATG Process will
be available to reduce offshore flaring on FPSO.
5. Acknowledgement
We would like to take this occasion to express our
gratitude to Vietnam Petroleum Institute, who performed a greatly effort to the Collaborative Study
through 2007 to 2009.
Source: http://www.osakagas.co.jp/rd/sheet/181e.html
Fig. 8. Comparison between A-ATG Process
and Conventional Process
It will be a great pleasure for us to widely contribute Vietnam if you could give us an opportunity to
utilize a part of our cutting-edge technologies, which
will have an availability to develop gas fields in
Vietnam including CO2.
59
Float - over technology
- A project enabler
David Emery
KennethYeoh HockGuan, Philippe Weber
Technip
Abstract
A float-over operation consists of installing an integrated topside
directly from the transportation barge or vessel on to a pre-installed substructure, without the need for a heavy lift vessel. The main benefits of a
floatover operation are the ability to install fully completed and tested
onshore platforms utilizing a single transportation and installation means.
Therefore, this method is an economic alternative to heavy lift particularly
in cases of large topsides requiring multiple lifts with offshore hook up &
commissioning and in cases of remote lifts with high mobilisation/demobilization costs for heavy lift vessels.
During the 1980’s, Technip developed a topsides float-over methodology for its own EPCI contracts and installed decks onto steel jackets in open
seas using monohull barges or vessels by conventional ballasting operations in benign seastates. During the 1990’s, Technip adapted this method
to provide an efficient method of delivery and installation of the production
topsides in areas with severe swell conditions and location far away from
the major fabrication yards. This technology, called UNIDECK®, is based on
combining ballasting operations with the use of hydraulic jacks, to provide
60
PETROVIETNAM
a rapid and safe set-down of the topsides. Topside decks with a weight of up to 18,000 tonnes have
been installed by Technip using this method onto shallow water, fixed structures.
During the early 2000’s, with this increasing weight of topsides and the requirement for local content, came an emerging need to extend the envelope of applicability to deepwater developments and
hence, floating structures.
In 2006 in offshore Brazil, Technip successfully completed the first mating of a 23,500 tonne topside onto the floating P52 semi-submersible hull in a protected site- the first in a series of three sister deepwater oil production platforms for Petrobras. At the end of 2006, a catamaran configuration
was used by Technip in open seas to install, for the first time by float-over, the topside of Murphy’s
Kikeh spar deepwater platform.
Using a selection of these projects as case studies, this paper describes the innovative technologies and methods that have been developed and successfully applied by Technip for Topsides installation throughout the world during this past 20 years.
Introduction
Initially, float-overs were performed inshore, with
deck mating operations on concrete gravity base
structures built in the Norwegian fjords. Since the late
1970’s, float-overs have become more common worldwide partly due to the limited availability of large crane
vessels, which tend to operate in Europe and the Gulf
of Mexico, and to the benefit of onshore hook-up and
commissioning of large Topsides.
Technip understood the economical benefits of this
installation methodology for its own EPCI contracts. In
order to minimize the cost of the operation, topsides
float-over methodologies have been developed specifically for each particular project, depending of the layout, the topside weight, the environmental conditions
and the final elevation of the deck.
1. Passive float-over
During a conventional float-over in a benign environment, the monohull barge or vessel enters the steel
jacket’s slot and then transfers the Topsides loads to
the substructure by ballasting only. Once, the Topsides
is in contact with the pre-installed substructure and the
full weight is transferred, the installation barge or vessel then exits the substructure.
The first such operation achieved by Technip was
the central platform of the Ethylene Offshore Terminal
in Alexandria in 1987.
Then later in 1988, the operation for the relocation
of the Zakum accommodation platform was done in
Offshore Abu Dhabi. The platform was initially installed
on Zakum Central Super Complex as a self installing
platform (jack up elevated using strand jacks) in 1983.
The platform was relocated on to the Zakum West
Super Complex some 9 nautical miles away, using the
float over methods with a T-shape configuration of 2
barges connected by truss beams.
Since then a number of passive float-overs have
been successfully performed in particular by Technip
Asia Pacific.
1.1. Float-over detailed engineering
The engineering effort normally includes the following activities:
+ Structural engineering.
+ Detailed engineering of the operation.
+ Vessel preparations engineering.
+ Specification of the installation equipment.
+ Transportation engineering.
+ Procedures for the installation operation.
+ Supervision/assistance during the operation.
1.1.1. Structural design
The interface between the topside/jacket structures and their interaction with the vessel strength
being critical, an integrated study (structural and naval
architecture) with a complete model incorporating the
topside/jacket rigidity and the stiffness the barge and
61
its various components (hawsers, fenders…) is
required.
The Topsides support frames (Fig. 1) are designed
considering all of the following operations:
+ For the load out; the inclusion of vessel trim and
list with consequential distortion of deck.
+ For the transportation; the dynamic effects and
vessel-to-deck distortion.
+ For the deck lowering; the design of a guiding
system to cope with the horizontal loads (dynamic and
impact load at time of mating).
On the transport vessel, the grillage allows a distribution of the static and dynamic loads of the topsides
to the different locations of the vessel’s structural hard
points. In addition, the grillage is designed to optimize
the ratio between topsides weight and vessel strength.
The sea fastening of the topsides design takes into
account the various steps of the operations for a
sequential and quick installation or removal.
1.1.2. Design of equipment
* Mooring system on the vessel
enough to keep good control of the vessel’s position
and to maintain the second order wave induced
motions of the vessel to a low level.
The fairleads, sheaves and bollards are designed
and sized to satisfy all possible configurations during
entrance, mating and withdrawal of the vessel.
* Fenders inside the jacket
Fenders (Fig. 2) also called jacket leg protectors
are provided to absorb the vessel impacts on the jacket. The fenders are fitted with a steel shield to ensure
good contact on the vessel’s own fender (half pipe)
and to allow vessel level change during mating. A
small gap of about 0.2 to 0.3m between the vessel hull
and the shield is kept.
The capacity of the fender is defined in accordance with the vessel motions, the impact energy and
the vessel hull strength.
* Transition piece and guide cones
On top of each jacket leg (or pile) is installed a
transition piece (Fig. 2). This is composed of a guide
cone to facilitate the offshore installation and a thick
reinforcement.
The mooring consists of a combination of equipment that is sized to suit the vessel motion characteristics, the jacket rigidity and the environmental conditions of the site.
The guide cones are designed typically at an angle
of 450 and fitted at their base with a cylindrical to provide the final accurate centering.
The mooring lines connected to the jacket use a
winch with wire rope and a nylon tail to adjust the line
stiffness. The selected line stiffness avoids having resonance with wave periods (i.e. the degradation of the
vessel motions) and also avoids having high dynamic
peak loads in the lines. However the lines remain stiff
Finite element analyses are performed to check
the local strength of the transition piece.
The thick part of transition piece accepts the relatively high concentrated impact loads at the steel-tosteel contact without risk of local deformation.
* Leg mating units
One key element of a float-over installation is the
leg mating unit (Fig. 3) located at the interface
between the jacket and the deck.
The leg mating units perform 4 main functions during the mating phase:
+ Centering of deck legs during first phase of lowering.
+ Reducing the vessel/deck motions during lowering.
+ Reducing the impact load between deck and
jacket.
Fig. 1. Typical arrangement 4 substructures
and 2 grillage rows
62
+ Providing final accurate positioning (rigid guide)
PETROVIETNAM
room with information relayed from the vessel and
the mooring equipment, and knowledge of the environmental conditions. The information includes, in
particular:
+ Vessel attitude: Draught, heel angle and overall
centre of gravity.
+ Environmental conditions (wave, wind and current by reading of a rider buoy) and the weather forecast for the coming hours (12 to 36 hours depending
on the operation stage).
+ Live video covering the legs during the mating
operation.
+ Display of tensions in the mooring lines.
+ Vessel motions by gyrocompass.
The above data are assessed for the decisionmaking at each step of the installation operation. In
addition, contingency procedures are developed to
cope with any abnormal situations that may arise.
1.2.1. Vessel docking
Fig. 2. Typical fender and transition piece
of the deck legs onto the jacket pile.
* Deck Support units
On top of the Topsides support frames at the
interface with the deck, deck support units made of
elastomeric pads are installed to provide a soft separation at the end of the loads transfer during the floatover and prevent any damage of the Topsides in
case of re-contact.
1.1.3. Ballasting/de-ballasting system
Powerful integrated or external ballasting system
with suitable characteristics to perform float-over operations are required, i.e.:
+ Large flow rate (available on existing vessel).
+ Versatility.
+ Redundancy.
+ Centralised remote control.
1.2. Float-over operation
The whole operation is monitored from a control
The offshore installation starts by manoeuvring
and mooring the vessel outside the jacket using typically a combination of 4 anchoring lines connected to
anchors pre-tested.
Then, the 2 ‘stern longitudinal crossed mooring
lines’ are connected from the stern of the vessel to the
furthest piles of the jacket, to allow an accurate control
of the vessel’s stern while entering into the 1st row of
the jacket (Fig. 4).
By using winches on the deck, the vessel is moved
into the jacket. Once the stern of the vessel reaches
the 2nd row of the jacket, the 2 ‘bow longitudinal mooring lines’ attached to the first row of piles are connected to the vessel (Fig. 5).
When the vessel stern reaches the last row of the
jacket, the 2 ‘stern longitudinal crossed mooring lines’
are uncrossed. At the final position, the vessel is
moored inside the jacket by the 4 longitudinal lines and
4 transversal lines are added to the external piles. This
ensures an accurate positioning of the deck legs over
the jacket legs (Fig. 6).
1.2.2. Transfer of loads and vessel separation
At the beginning of the transfer phase, the deck is
rested on the deck support units located on the top of
63
the deck support frames. Then by
de-ballasting the vessel, the leg
mating units in the topsides legs
and centered by the entry cones,
come into contact on the jacket
legs. When about 50% of the topsides weight is transferred to the
jacket legs, the wave induced vessel motions reduce. At this stage,
the shock absorbers are at maximum compression, and the topside
and jacket legs come into steel to
steel contact.
The transfer of the loads onto
the jacket, along with the control of
the location of the COG is performed by controlling the ballasting
including the tide effect.
At the end of the load transfer,
a separation gap between the vessel and the deck is created
between the bottom of the
Topsides and the deck supports
units and is used to prevent any
risk of hard impacts.
1.2.3. Removal of the vessel
Then, the vessel’s draft is
adjusted, in order to keep a minimum under keel clearance above
the jacket’s cross bracing of 1.5m
and a safe freeboard of at least 1m.
The vessel is retrieved from jacket
with the assistance of tugs and the
2 bow mooring lines, leaving the
deck supported on the jacket.
Fig. 3. Typical guide cone with leg mating unit
cial technology, called the
UNIDECK®, which enables a very
short installation time in these
swell conditions (typically Hs =
1.5m in period of 10 seconds or Hs
= 1.2m in period of 14 seconds),
thereby ensuring a safe installation
operation as well as limiting the
risk of weather downtime.
2. Active float-over
The technology combines ballasting and jacking to improve the
stability of the heavy transport vessel during the transportation phase
and uses jacking to provide a quick
transfer of the integrated deck
weight onto the pre-installed jacket
in order to avoid high dynamic
impact loads.
Due to the long swell period
conditions in West Africa, a conventional float-over by ballasting
only is too slow and thus, not
advisable because it causes
excessive impacts between the
topside and the jacket. In the
1990’s, Technip developed a spe-
This technology, for which
Technip acts as an installation contractor, has been implemented in
West Africa with the COB-P1 production platform (9,500 tonne), the
Amenam Kpono AMP1 (11,000
tonne) and AMP2 (9,600 tonne)
platforms for TOTAL and the East
64
Area Project GN compression platform (18,000 tonne) for EXXONMOBIL.
2.1. Jacking system
The jacking system (Fig. 7)
using hydraulic cylinder jacks is
designed considering the following
features:
+ Fully reversible operation.
+ High reliability and redundancy of all major components.
+ The jacking operation can be
continued in case of failure of one
jack or hydraulic power unit.
+ Capability to allow rapid ram
retraction prior to barge removal.
+ Capability to continue lowering with damage to hydraulic
pipes/connections or electrical
failure.
+ Capability to achieve lowering
in case of a total electrical failure.
The hydraulic
designed for:
system
is
PETROVIETNAM
topsides legs engage into the tops
of the jacket legs, and a sufficient
residual gap is left to avoid any
hard impact. During the ballasting
operation, a real time tide measurement is used to adjust the ballast plan.
* Jacking until transfer of 50% of
the load
The installation of the topsides
onto the jacket is performed by
retracting the jack rods within
approximately one minute, over the
complete stroke (1.8m). The downwards motion has two effects:
+ It closes the residual gap.
Fig. 4. Vessel mooring prior docking
+ A slow jacking or lowering at
nominal speed of 60 mm/min.
+ A variable fast lowering up to
a speed of 1,800 mm/min.
+ A synchronization of all the
lifting axes in a window of less than
10mm in normal automatic mode
(if one axis is outside the window
the operation is stopped) to control
and minimize the dynamic stress
inside the topside structure. The
automatic mode is used for the
weighing, the load out operations
and the installation on site (initialization, slow movements, normal
lowering, rod extension for ballasting, and automatic cylinder return
modes).
2.2. Operations
2.2.1. Topsides Weighing
The weighing of the topside is
the first operation performed with
the jacking system where the actual weight and the location of the
centre of gravity are measured
with a very good accuracy.
A second weighing of the topside is performed as well as a test
of the jacking system at a high lowering speed over their full 1.8m
stroke, just few days before the
load out operation.
2.2.2. Load out
During the load out operation,
the jacking system is also used
allowing a precise monitoring of
loads and control per support in
order to compensate for vessel
trim and differential settlement.
2.2.3. Float-over
The same methodology as the
one for passive float-over methodology is used for vessel docking
but prior entry into the slot, the topsides is elevated with the jacking
system. At the final position, the
vessel is typically moored inside
the jacket by the 4 longitudinal
lines and 4 transversal lines.
* Contact between the topsides
and the jacket
By ballasting the vessel, the
+ It transfers part of the deck
load onto the jacket and, as a consequence, the vessel moves
upwards as the load on its deck is
reduced.
This resulted in the transfer of
about 50% of the topsides weight
to the jacket legs.
During the quick (i.e. normal)
downward stroke, stopping must
be avoided. This step is considered as the practical no-return
point (although the operation
remains theoretically reversible) as
it gets the topsides supported by
the jacket in a safe configuration.
At this stage, the vessel, the
jacket and the topsides behave as
a single body.
* Continuation of load transfer
After the 1st jacking down, the
vessel ballasting continues. To prevent any relative motion between
the vessel and the topside, the
jacks are progressively extended
and an additional 20% of the deck
load is progressively transferred
onto the jacket.
65
* Transfer of remaining load and vessel separation
Finally, the jacks retracted a second time to quickly transfer 100% of the deck load to the jacket and to
create a sufficient separation gap between the vessel
and the deck to prevent any risk of further impact during vessel removal.
3. Mating
Based on its extensive experiences for topsides’
float-over installation, Technip has in the early 2000’s
adapted this proven methodology to semi-submersible
units for their assembly by a mating operation of the
topsides onto the lower hull.
Fig. 5. Vessel docking
In June 2006 in Brazil, Technip successfully carried out the mating of a topsides (comprising a ‘deck
box’ plus modules) onto the hull (designated the ‘lower
hull’) of a semi-submersible production facility. This
was to be the most complex and critical operation of
the project.
ous de-ballasting.
The topsides of 23,500 tonnes was fabricated in a
dry-dock and lowered onto the FS1 barge, specifically
built for the project. The integrated deck box consists
of transverse and longitudinal primary steel grinders of
both trusses and plated bulkheads. On the top of the
deck box, the process, power generation and gas
compression modules were installed by lifting before
the mating operation.
3.2. Mating detailed engineering
3.1. Overall description of the operation
A brief summary of the main steps of the mating
operations is as follows:
+ Towing of the lower hull from shipyard to a sheltered area for mating site (Fig. 8).
+ Connection of the lower hull to pre-installed
anchor lines at the mating site.
+ Ballasting of the lower hull to 40m draft.
+ Towing of the topsides on barge to mating site.
+ Barge entrance in between the lower hull
columns (Fig. 9).
+ Positioning of the deck box openings above the
lower hull guide cones with enough clearance.
+ De-ballasting of the lower hull to insert docking
piles within deck box bottom flange.
+ Transfer of the topsides weight from barge to
mating supports located at lower hull top, by continu-
66
+ When 100% weight transfer is reached, ballasting of barge to increase clearance.
+ Barge withdrawal when clearance with topsides
is satisfactory (Fig. 10).
3.2.1. Structural design
* Dedicated barge for construction and mating
The FS1 barge has been designed for construction
and installation phases.
On the barge, the grillage design allows an even
distribution of the static and dynamic loads from the
topsides to the main bulkheads of the barge by inserting underneath the lower deck, a shaped wooden cribbing. This dunnage shape takes into account the
deformations applied by deadweight and ballasts to
both deck box and barge when floating.
During construction, the deck box is erected directly on the grillage with counter timbers. Before float out,
those pieces are removed by jacking up and down the
deck box. Finally, at float out stage, the deck box is
resting on the dunnage curved shape, exhibiting a
hogging deformation, ready for modules installation
and mating.
* Mating stools
After complete weight transfer from the barge to
the lower hull, the topsides is resting on 12 mating
stools (Fig. 11). Each column is fitted with 3 mating
stools, one in the inner corner, and the two others at
mid distance of the inner sides. This allows the operation to be reversed at any time and to tow back to the
PETROVIETNAM
yard without any particular actions
at mating site.
To reach a satisfactory compromise between bending moment
at column top and sagging of the
deck, the load applied on each
column is intended to be limited to
about 40% on the inner corner
stool and 30% on each of the
other two.
* Guide cone
Located close to each inner
corner-mating stool is a docking
pile, typically a tube appropriately
stiffened. At top of this pin, there is
a 45 degrees cone for insertion
within the corresponding hole of
deck box flange.
The docking pile is designed to
withstand design internal loads
generated by the relative deformations between the topsides and the
lower hull, during de-ballasting if
the gap is filled in. Moreover, the
design takes into account the
impact load at touchdown, and the
dynamic loads during towing the
assembled semi-submersible back
to the yard for completion work.
* Overall analysis
The studies for the mating
operation can be summarised as
follows:
+ Relative displacements and
deformations
between
the
Topsides and the lower hull.
+ Specification and follow up of
fabrication tolerances.
+ Definition of elastomeric
pads and shimming for load spread
at top of the columns.
+ Definition of butter pad thicknesses to be welded on docking
pin allowing to minimise gap and
internal load.
+ Calculation of expected
deflections during de-ballasting
sequences to control the applied
loads during weight transfer.
+ Strength checking of mating
stools and deck box.
3.2.2. Design of equipment
* Lower mooring system
During the mating operation,
the lower hull is temporary moored
at the mating site, by an 8 leg catenary mooring system made of wire
and chain.
Specific mooring procedures
are developed to moor the hull at
the mating site: Pre-installation on
site, connection to the lower hull
and then tensioning and equalizing
the lines’ tension without the possibility of using mooring winches.
The mooring system is also
designed to maintain the platform
on location after mating for spider
deck installation.
* Mooring system between barge
and lower hull
During the docking and mating
operations, the barge is moored to
the lower hull to provide good control of the relative displacements.
The mooring consists of equipment that is sized to suit the barge
and lower hull motion characteristics and the environment conditions of the site. The use of soft
systems for the mooring lines plus
the fendering system allows control of the positions with reasonable forces.
The fairleads, sheaves and
bollards are designed and sized to
satisfy all possible configurations
during entrance, mating and withdrawal of the vessel.
* Fenders inside the lower hull
Fig. 6. Vessel centered into the slot
Fenders of the type used for
jacket leg protection in conventional topsides/jacket float-over operations were installed on the lower
hull columns to protect both the
67
Fig. 7. Typical jacking system arrangement between 2 substructures of the same row
barge and the lower hull during the docking and mating.
* Lower Hull ballasting/de-ballasting system
The topsides mating operation is mainly done by
de-ballasting the lower hull. For this purpose, the platform ballasting system is adapted with additional systems to supplement the permanent arrangement.
In particular, the following modifications are
required:
+ Connections to the ballast system of a number of
compartments normally not used as ballast: Void tanks
in columns, chain lockers, fresh water tanks, and
diesel tanks.
+ Increased diameter of the bilge common line in
the columns so that it can be used to ballast the void
tanks.
+ Temporary centralised control room in one column.
+ Installation of temporary level transmitters in void
tanks.
+ Additional control displays and software mating
modules in the platform control system.
* Barge ballasting/de-ballasting system
The barge is ballasted simultaneously with the
lower hull de-ballasted. The main purpose of the barge
ballasting is to correct the deck eccentricity so that the
barge will remain on an even keel after load transfer.
* Ballasting/de-ballasting procedure and control
About 30,000 tonne of water ballast are emptied
during the load transfer, which took about 15 hours.
The procedure is developed with successive phases of de-ballasting of columns and pontoons in order
68
Fig. 8. Towing of the lower hull to mating site
to maintain hull deflection and load applied on centering pile within allowable limit.
4. Catamaran float-over
In November 2006, Technip successfully installed
in catamaran configuration (Fig. 12) the first spar topside float-over for the Murphy Kikeh Dry Tree Unit
(DTU). This installation was performed in 1330m water
depth in open water in the South China Sea, offshore
East Malaysia. The topside installation weight was
4000 tonne and the swell at the time of installation was
Hs of 0.7m at periods of 7 - 8 seconds.
Prior to Kikeh, the topsides of all other spars had
been installed using heavy lift vessels, which have limitations in terms of both their maximum lifting capacity
and their availability. The successful execution of the
Kikeh topside float-over installation has established
this method as a viable and cost-effective alternative
to lift installation.
It makes the catamaran float-over concept a
PETROVIETNAM
proven technology, promising a great future ahead by
providing an economical solution particularly for spars
requiring large topsides.
4.1. Float-over detailed engineering
During the float-over approaching and mating
operations, the catamaran system is designed for
potential bumping with the spar hull through specially
arranged fenders of different types and sizes (Fig. 13).
To support the operation, the following structural
design and analyses are carried out:
+ Design of the fender system on west side and
east side.
+ Design of the stabbing pin and the shock cells.
Fig. 9. Barge entrance in between the lower hull columns
+ Impact load calculation during collision between
the barges and the fenders on the spar hull.
+ Impact loads on shock cells, legs and grillage.
4.2. Overall description of the operation
The following steps are involved during the floatover operations:
+ The catamaran system is pulled toward the
moored spar hull with typically six lashing lines.
+ The catamaran system is aligned with the spar
hull by adjusting tension on the lashing lines (Fig. 14).
+ The spar hull rises when the ballast water is
pumped out from its upper tanks.
+ The receptacle on the spar hull starts to impact
the stabbing guides after the static gap is closed. For
Kikeh, these impacts lasted for about 8 minutes before
the motions were synchronized.
Fig. 10. Barge withdrawal
+ The tie-down braces are removed when 20% to
60% of the topside weight is transferred from the
barges to the spar hull.
+ De-ballasting on the spar hull continues until the
pins on the grillage are pulled out from the locking
plates of the forks, while the barges are pulled.
Conclusion
The float-over method is a well proven technology,
has been applied for both fixed facilities and floating
units and presents significant advantages over conventional derrick lift barge installations for an offshore
field development.
These advantages can be summarized as follows:
+ This method considerably reduces the cost of the
Fig. 11. Detail of guide cone and mating stool
69
integration, pre-commissioning and offshore commissioning works by allowing full onshore completion and commissioning of the deck as compared to a multi-module lifted topsides, hooked up and commissioned offshore.
+ Minimizes the installation costs of large Topsides by
utilizing a single transportation and installation means.
+ For floating units, it enables the fabrication of the
integrated topsides in a conventional topside yard at a
low level, when an integrated deck would be too heavy
for an elevating system.
Fig. 12. Catamaran configuration
+ It enables an integrated topsides installation when
the deck would exceed the capacity of existing derrick
barges.
+ As demonstrated by the successful installations of
the decks onto the lower hull of the P52 semi-submersible, and onto the Kikeh spar, the viability of the
float-over method on to floating substructures as well.
Acknowledgement
The authors would like to thank our Clients and the
management of TECHNIP for granting the permission to
publish this paper.
Reference
1. J.H. Sigrist and J.C. Naudin/TECHNIP.
Experience in Float-over Integrated Deck-Design and
Installation. Paper OTC 8121, presented at the Offshore
Technology Conference, held in Houston Texas, 6-9
May 1996.
Fig. 13. Catamaran System Approaching Spar Hull
2. J.H. Sigrist, P.A. Thomas and J.C. Naudin/TECHNIP. Experience in Float-over Integrated Deck-Flexibility of
the concept. Paper OTC 8616, presented at the Offshore
Technology Conference, held in Houston Texas, 1998.
3. C. Tribout, D. Emery, P. Weber /TECHNIP and R.
Kaper/DOCKWISE. Float-Overs Offshore West Africa.
Paper OTC 19073, presented at the Offshore
Technology Conference, held in Houston Texas, 2007.
4. D. Emery, P. Weber, L. Ferron, P.A. Thomas and
J.C. Naudin /TECHNIP. Mating of the Topsides onto
the lower hull - P52 semi-submersible. Paper OMAE
2008 - 57869, presented at the Offshore Mechanics
and Artic Engineering conference, held in Estoril,
PORTUGAL, 2008.
5. Michael Y.H. Luo, Liyong Chen and David
Edelson/TECHNIP. SPAR Topsides floatover installation-structural design and analyses.
70
Fig. 14. Initial Alignment between Topside and Spar Hull
PETROVIETNAM
Permanent mode analyses for the distribution
grid interconnection of a renewable energy
Tran Khanh Viet Dung
Vietnam Oil and Gas Group
Abstract
1. Introduction
The interconnection of renewable energies
with the utility grid has been one of the most
important R&D orientations for many years.
Majority of the utilities in the world were not conceived to accommodate the large-scale distributed generators (DG). The first studies in the literature showed significant effects and impacts on
the operation of the entire electric system.
However, they were complex, long convergences
or unable take into account the connected singlephase distributed generator. Moreover, the structure of the distribution networks depends on the
country. The presence of single-phase DG in
these networks involves impacts of the current,
resulting in its voltage. These impacts are harmful
to the equipment of the grid especially to the
three-phase machines connected to the utility.
As a consequence of the energy market’s
rapid growth, the distributed (dispersed or decentralized) generator (DG) develops in several countries, on the basis of cogeneration’s unit, renewable energies or traditional production, installed by
independent producers [1], [2]. Distributed generator systems are becoming more common as a
result of the increased demand for electricity and
the requirement to reduce the impact on the environment from traditional fossil and nuclear
sources of power production. A study by the
Electric Power Research Institute (EPRI) indicates
that in 2015, 25% of new electric generator will be
distributed [3]. They have a reverse power flow
capability and are operated in parallel with utility
power system. However, the DG’s interconnection
influences on the electric distribution system
because the utility grid was not conceived to
accommodate the distributed generator. The first
studies carried out on the introduction of this energy production form to large scales into the grid
showed significant effects and impacts on the
operation of the entire electric system:
In order to contribute to the system service
and the utility’s control, we present, in this paper,
robust methods’ analysis for permanent modes of
grid’s operation when multiple single-phase DGs
connected to the distribution three-phase utility.
These methods calculate power flows and unbalanced treatment. The analytical and simulation
studies were performed in order to validate the
accuracy of these methods. The results showed
that these methods behave well. The impacts of
voltage quality, the rate of unbalance are presented while comparing with the industrial software
and the standard in use.
Keywords: Renewable energy, distributed generator, distribution networks, impacts, voltage quality,
unbalance, islanding, correlation function.
+ Modification of the power’s transit and the
voltage quality [4], [5];
+ Impact on the selectivity of protective systems [6], [7];
+ Influence on the stability of the utility [8];
+ Problems of unbalance and islanding [9] [12].
The presence of the single-phase DG in the
networks, like their random distribution on the 3
71
POWR TECHNOLOGY
phases, involves impacts of the current, resulting in
impacts of the voltage. These impacts are harmful to
the equipment of the utility especially to the threephase machines connected to the grid. Therefore, the
regulations which limit these impacts are necessary
and essential. In this context, in order to contribute to
the system service and the utility’s control, this article
presents some scientific contributions towards the
interconnection of distributed generator to the electric
distribution network. These contributions are aimed at
developing a method to calculate power flow and
unbalance treatment of the three-phase utility integrated with single-phase DGs basing on the approaches
of impedance order reduction and identification of the
power’s direction.
2. Electric power system & standards
2.1. Overview of the electric power system
The electric system is structured in several levels
and characterized by the voltages adapted to these
levels [13]:
are fed by three wires. Thus, according to the connection carried out, they can supply their machine under
either 120V or 240V.
Primary Feeder
SUBSTATION
Distribution
transformers
120/240V
60 Hz
120/240V
60 Hz
120/240V
60 Hz
Fig. 1. Distribution network with distributed neutral
2.2. Interconnection standards review
+ Transport networks up to Very High Voltage
(VHV) carry the energy of the large production centres
towards the consuming areas (from 150 to 800 kV).
These networks are often inter-connected;
Requirements for the performance of the DG’s
interconnection have been clarified in the IEEE, UL,
IEC and other “National Standards” worldwide. Table 1
specifies the voltage and frequency limits, and clearing
times required by the IEEE Standard 1547 and the
Canadian Standard Association (CSA) C22.2 No.
107.1-01 for the connection LV systems [18], [19].
+ Repartition networks up to High Voltage (HV) manage, within the regional scales, the service road of the
delivery points to the distribution (from 30 to 150 kV);
Table 1. IEEE 1547 standard and the Canadian standard
requirements for interconnection system response to
abnormal frequencies and voltages
+ Distribution networks are the feeder systems of
the whole of the customers, except for some important
industrial customers which are fed directly by VHV and
HV networks. Two under-levels are distinguished:
Networks with Medium Voltage (MV: 3 to 33kV) and
networks with Low Voltage (LV: 110 to 600 V).
The distribution networks represent the link of the
power system where the development of the DG is
awaited the most. The structure of the distribution networks depends on the country where they are built.
Our study is concerned with the particular structure of
the distribution network [14] - [17]:
+ Principal feeder of the network is three-phase
and the neutral is distributed. However, the MV distribution is single-phase (Fig. 1);
+ Low voltage levels LV are associated with short
distance networks (i.e. 300 metres maximum) and with
the harmonization of LV equipment. The costumers
72
Canadian standard
C22.2 No. 107.1-01
IEEE 1547 standard
Frequency (Hz)
f < 59.3
f > 60.5
Voltage (% of
basic voltage)
V < 50
50 ≤ V < 88
110 < V < 120
V ≥ 120
Clearing time
(s)
0.16
0.16
Clearing time
(s)
0.16
2
1
0.16
Frequency (Hz)
Clearing time (cycles)
f < rated - 0.5 Hz
f > rated + 0.5 Hz
Voltage (% of
basic voltage)
V < 50
50 ≤ V ≤ 88
110 ≤ V ≤ 137
V > 137
6
6
Clearing time (cycles)
6
120
120
2
3. Permanent mode analysis
One of the most important permanent mode analyses is power flow. It allows the state of the network utility at a certain time to be known. A power flow’s study
in a complex utility consists of determining, initially, the
amplitude and phase of the voltage as well as the
active and reactive injected powers. Knowing the voltage (amplitude and phase) and the injected (active
and reactive) powers, we can then calculate the cur-
PETROVIETNAM
rents and powers in the lines and those provided by
the sources. If we consider a utility containing “N” sets
of bars, we will obtain “N” equations of power flow
given by equation (1):
n
⎫ *
⎧
= ⎨Y i V i − ∑ Yij V j ⎬V i
j =i , j ≠ i
⎭
⎩
Where S: Complex power
S
Network’s structure
Data base
*
ii
(1)
Step 1
Step 2
Y: Grid’s admittance
V: Voltage at node
They are non-linear equations, therefore, it is necessary to use an iterative method to solve them. To
date, there are two groups of method in the literature:
Step 3
+ Method based on the matrix form [20], [21];
Simulation
real-time
Matrix
method
Symmetrical
component
Network’s
configuration
MATLAB Environment
+ Method based on the network’s configuration
[22], [23].
The iterative methods based on the matrix form
are robust and applicable to all types of network
(radial network, mesh network etc). However, they
are sometimes complex and long convergences,
especially in the case of DG’s massive insertion.
Another method relying on the division of layers is
also presented. This method uses the network’s configuration instead of the matrix form in its calculation.
However, the weak point of this method is that it
could not take into account the DG connected to the
network and the authors only deal with problems of a
single-phase network.
With the aim of overcoming these drawbacks of
the existing methods, we propose in this section a
method which can be classified as one of the network
configuration methods. This method is based on the
approach of impedance order reduction and identification of the power’s direction which allows the calculation of power flows and unbalance treatment in a
three-phase radial system integrated with singlephase DGs.
Fig. 2 presents the diagram of the proposed
method. This method is explained analytically and
programmed in the Matlab environment. The validation of the method is carried out by comparing the
computed power flow’s results obtained by the proposed method with those obtained by the industrial
simulation software (EMTP, ETAP) which use the
matrix form in their calculation.
Power flow
Method’s
validation
Impact study
Unbalance treatment
Fig. 2. Proposed method’s diagram
3.1. Impedance order reduction
To calculate unbalances of current and voltage,
the negative sequence should be known. This stage
leads to the reduction of a complete matrix impedances (self and mutual) dimension of (5 x 5) to a symmetrical matrix component dimension of (3 x 3).
The model representing the impedance orders of
the distribution network application (3 wires of phase,
1 grounded neutral wire) is shown in Fig. 3.
Va
Ia
Za
Ib
Zb
Zab
Vb
Zac
Zbc
Vc
Ic
Zan
Zc
Zbn
Zag
Zcn
In
Zn
Ig
Zg
Zcg
Zng
Ig
Zg
Zbg
Fig. 3. Complete model
of impedance orders
73
POWR TECHNOLOGY
The complete matrix with the network’s self and mutual impedances is the matrix of the order (5 x 5) shown in equation (2):
⎛ Za
⎜
⎜ Z ba
Z = ⎜ Z ca
⎜
⎜ Z na
⎜Z
⎝ ga
Z ab
Z ac
Z an
Zb
Z cb
Z bc
Zc
Z bn
Z cn
Z nb
Z nc
Zn
Z gb
Z gc
Z gn
Z ag ⎞
⎟
Z bg ⎟
Z cg ⎟
⎟
Z ng ⎟
Z g ⎟⎠
(2)
This conclusion is important and makes
it possible to reduce the matrix of a complete impedance (5 x 5) to the impedance
order of (4 x 4).
We can now present the reduced
model in the form of Fig. 6.
Va
Zs
Ib
Zs
Ic
Zs
Zm
Vb
Za, Zb, Zc: Self impedances (Zs)
Ia
Zn, Zg: Neutral and ground impedances
Zm
Vc
Zij: Mutual impedances with i ≠ j (Zm)
This basic model is simulated with Matlab/Simulink/Power
Blockset (Fig. 4) to verify whether the return of the homo-polar current is essential via the neutral or the ground.
Zm
Z
Z
Z
In
Zn
Fig. 6. Reduced model
The nodal and mesh analyses give us
the equations:
Va = I a .Z s + (I b + I c )Z m − I n .Z + I n .Z n − (I a + I b + I c )Z
Vb = I a (Z s + Z n − 2Z )+ I b (Z s + Z n − 2Z )+ I c (Z s + Z n − 2Z )
Vc = I a (Z s + Z n − 2Z )+ I b (Z s + Z n − 2Z )+ I c (Z s + Z n − 2Z )
(3)
Fortescue’s transformation:
⎛ Va ⎞
⎛ V1 ⎞
⎜ ⎟
⎜ ⎟
⎜V2 ⎟ = F .⎜ Vb ⎟
⎜V ⎟
⎜V ⎟
⎝ c⎠
⎝ 0⎠
(4)
With matrix of transfer:
⎛1 a
1⎜
F = ⎜1 a 2
3⎜
⎝1 1
Fig. 4. Simulation’s model of the complete impedance
The obtained simulation results show that the homo-polar
current returns mainly by the neutral (Fig. 5).
(5)
Operator a:
1
3
a=− +
.i
2 2
80
(6)
By combining equations (3) with the
Fortescue’s transformation (4) and (5), we
have equations (7):
60
Currents
40
(A)
20
0
Z ground
1/10*Z
ground
1/100*Z
ground
Ground im pedances
I total
I return by neutral
I return by ground
Fig. 5. Homo-polar current returns
74
a2 ⎞
⎟
a⎟
1 ⎟⎠
1
(Va + Vb + Vc ) = 1 (I a + I b + I c )(Z s + 3.Z n + 2.Z m − 6.Z )
3
3
= I 0 .Z 0 ⇒ Z 0 = Z s + 3.Z n + 2.Z m − 6.Z
V0 =
1
V1 = Va + a Vb + a 2Vc = I1 Z s + Z n 1 + a + a 2 − 2.Z
3
1 + a + a 2 + Z m a + a 2 = I1.Z1
(
(
)
(
⇒ Z1 = Z 2 = Z s − Z m
) (
))
(
)
(7)
PETROVIETNAM
Start
Finally:
Network’s configuration
Find the nodes ends
Find the currents’s directions
Z1 = Z s − Z m
Z2 = Zs − Zm
(8)
Z 0 = Z s + 3.Z n + 2.Z m − 6.Z
k = 0 (initial estimate )
We can obtain the matrix of impedance (3x3), positive Z1, negative
Z2 and zero Z0 impedances which are then applied to our algorithm.
V
(0)
i ( abc )
(0)
S i ( abc )
(0)
= V n ; I i ( abc ) =
(0)
V i ( abc )
(0)
(0)
; I i ( 012 ) = F * I i ( abc )
3.2. Identification of the power’s direction
k=k+1
n
The second contribution of the proposed method is concerned
with the technique of identification of the power’s direction and the
application of the reduced matrix impedance (order 3 x 3) in the
calculations of power flow and the unbalance treatment. This technique includes three steps:
Step 1
(0)
S
(0)
i ( abc )
V
(0)
i ( abc )
(0)
V i ( abc ) = V n ; I i ( abc ) =
∑i
(k )
(k )
(k )
k =1
(k )
(k )
(k )
ΔV ij ( 012 ) = Finv * ΔV ij ( 012 ) ; V i ( abc ) = V
(k )
j ( abc )
(k )
− ΔV ij ( abc ) ;
k −1
k
V i ( a b c) − V i ( a b c) < ε
No
(0)
(k )
= 0 ⇒ I ij ( 012 ) ; ΔV ij ( 012 ) = I ij ( 012 ) * Z ij ( 012 ) ;
k
(0)
Convergence
; I i ( 012) = F .I i ( abc )
Yes
n
Step 2
∑i
(k )
k
= 0 ⇒ I ij ( 012 )
V i ( abc) ; I i ( abc) ; I ij( abc) ;Vi % =
k =1
(k )
Step 3
(k )
(k )
(k )
(k )
ΔV ij ( 012) = I ij ( 012) .Z ij ( 012) ; ΔV ij ( abc) = Finv .ΔV ij ( 012) ;
V
(k )
i ( abc )
=V
(k )
j ( abc )
− ΔV
(k )
ij ( abc )
V2
I
; Ii % = 2
I1
V1
Stop
;
Fig. 7. Algorithm flowchart of the
proposed method
SUBSTATION
115/23 kV, 50MVA
3.3. Algorithm flowchart
N0
L1
The complete iterative calculation stages of the proposed
method are illustrated in Fig. 7.
L2
N1
3.4. Results validation
N2
L12 L15
3.4.1. Specific distribution network’s application
L13
N4
The modelled network includes a substation of 115kV/23kV, 50
MVA which feeds a zone of a city (Fig. 8). It is composed of a threephase overhead line 477 MCM ACSR, a three-phase underground
cable 750 MCM Al and single-phase components 3/0 AWG AL. In
general, the low voltage (LV) portion is short and each customer has
a dedicated departure starting from the transformer. The principal
artery of the network is three-phase with a part in the overhead line
and a part in the underground cable. The network’s single-phase is in
the underground cable and supply various transformers. The representation of the DGs interconnected to the utility is made with current
sources and DG’s power factor FDG = 0.95. The phase and the amplitude of this source are selected in such a manner to have the desired
injection of active and reactive powers. The loads are modelled by
simple linear elements (resistances, inductances and capacitances)
with power factor Fload = 0.98 and each load’s power = 25 kVA.
L3
N6
N3
L4
N7
N17
Phase B
L17
L14
N18
L11
L16
N8
N19
L5
N20
N5
L18
Phase B
L6
N21
N9
L7
N22
N10
L19
L22
N13
L8
N11
L20
N23
L23
L9
N14
L21
N24
N12
L10
N25
L24
Phase A
N15
L25
N16
Phase C
Three-phase overhead line
Three-phase underground cable
Single-phase cable
Lx: Line number x
Ny: Node number y
Fig. 8. Distribution network’s application
75
POWR TECHNOLOGY
3.4.2. Proposed method v.s. ETAP, EMTP’s simulations
3.4.3. Voltage quality & Unbalance treatment
The power flow of the modelled network’s application were calculated using the proposed method and
were compared with the results obtained using specific software of grid’s simulation ETAP, EMTP (Fig. 9,
10, 11).
One of the most important impacts on the distribution network interconnection of a massively DG is the
voltage quality. This factor must be controlled to satisfy the customers’ requirements. To determine the limit
of the DGs’s integrated power and the geographical
provision of the sources distributed in order not to
exceed the thresholds provided by standards in use
(IEEE standards), we present below (Fig. 12 and Fig.
13) the parametric modeling results obtained on the
three phases of the network’s application with the
given electric parameters.
The results obtained are similar. The maximum
errors on the current and the voltage are 2.15(%) and
1.78(%) respectively. Thus, the method can be used in
the power flow study and calculation of impacts and
unbalance treatment.
30
1,06
25
20
5
0
L1A
L1B
L1C
L2A
L2B
Voltage (p.u)
1,05
Current (A) 15
10
1,04
1,03
1,02
1,01
1
Lines
N1
6
N1
4
N1
2
N1
0
N8
N6
N4
N1
7
N2
4
N2
2
EMTP
N2
0
ETAP
N1
8
Method proposed
0,99
Nodes
Fig. 9. Current in the three-phase lines (L1, L2)
25
Threshold Max
Without DG
DGs 25kVA all loads
11 DGs 25 kVA phase C
11 DGs 25 kVA at 11 nodes
11 DGs 25 kVA at node 17
11 DGs 25 kVA at node 16
20
Fig. 12. Voltage according to the DG’s geographical provision
15
Currents
10
(A)
5
16
N
14
N
12
N
8
10
N
N
N
6
4
N
17
N
24
N
N
22
0,8
20
Fig. 10. Current in the single-phase lines (L3-L11)
0,9
0,85
N
Method propose d
1
0,95
18
L3 L4 L5 L6 L7 L8 L9 L10 L11
Lines
N
0
Voltage (p.u)
1,1
1,05
Nodes
30
20
Cur ren ts
(A)
10
Threshold Min
DGs 25kVA all loads
Fig. 13. Voltage according to the DG’s power
0
L12 L14 L16 L18 L20 L22 L24
L ines
Method proposed
Fig. 11. Current in the single-phase lines (L12-L25)
76
Threshold Max
Without DG
The unsymmetrical provision of the massive connection’s single-phase DG to the three-phase distribution network is the cause of the unbalance problems.
The negative voltage sequence is harmful to the threephase machines connected to the utility grid. The regulation and a coherent technico-economic balance
PETROVIETNAM
results in limiting the ratio of negative voltage
sequence to positive voltage sequence to 2% (IEEE
standards). To deal with this problem, the symmetrical
components (positive, negative and zero sequences)
of the current and the voltage of network application
were calculated parametrically according to DGs’s
power and DSs’s provision. The rate of unbalance
which is defined by the ratio of negative sequence and
positive sequence was used to evaluate quantitatively
the level of unbalance.
I2
* 100(%)
I1
I i (%) =
(9)
I2: Current’s negative sequence
I1: Current’s positive sequence
Vi (%) =
V2
*100(%)
V1
(10)
network integrated with single-phase DGs. These
methods contribute to the system service and the utility’s control. The theoretical analysis and modelisation
of the proposed calculation algorithm were presented
and validated with the specific software of grid’s simulation. Furthermore, the effectiveness of the developed
method was used to calculate the voltage quality, to
treat the unbalance. The parametric study was performed and the limit of the power and geographical
provision of the integrated DGs in order not to exceed
the thresholds provided by the standards in use (IEEE
standards) was also presented. The results obtained
show that these methods are reliable and they give
satisfactory indices. Therefore, it is necessary to use
these results in the grid’s service system in order to
maximize integrated DG’s power and minimize the
impacts on the grid.
References
V2: Voltage’s negative sequence
V1: Voltage’s positive sequence
Fig. 14 presents the rate of unbalance’s voltage of
the network’s application according to the change of
the DG’s power and provision.
2,5
2
Rate of imbalance 1,5
(%)
1
0,5
0
Without DGs 11 DGs 11 DGs 11 DGs 11 DGs 11 DGs
DG 25kVA all 25 kVA 50 kVA 100 kVA 500 kVA 750 kVA
loads phase C phase C phase C phase C phase C
Case analysis
Fig. 14. Rate of unbalance
The results obtained show that the network’s voltage quality is within the allowed limit when the integrated DG’s power is low. However, the massive DG’s
connection to one phase only is the most influenced
case on the voltage quality and the unbalance of the
grid (Fig. 12). The limit of the voltage quality and the
rate of unbalance are reached when increasing the
DG’s power until approximately 11% of the total power
(50 MVA) (Fig. 13 and Fig. 14).
Conclusion
This paper presents specific methods to analyze
permanent modes of the three-phase distribution
1. M. Rabinowitz “Power systems of the future”
IEEE Power Engineering Review, Vol 20, No 1, Pages:
5-16, Jan 2000.
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IEEE Transaction on Energy Conversion, Vol 19, No 3,
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3. M. I. Marei, E. F. El-Saadany, and M. M. A.
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IEEE Power Engineering Society Summer Meeting,
2002, vol. 1, 21-25 July 2002, pages: 49-53.
4. J.A. Peças Lopes “Integration of Dispersed
Generation on Distribution Networks-Impact Studies”
IEEE Power Engineering Society Winter Meeting, Vol
1, pages 323 - 328, 27-31 Jan 2002.
5. Keane. A, Denny. E, O’Malley. M “Quantifying
the Impact of Connection Policy on Distributed
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Vol 22, No 1, Pages: 189 - 196, March 2007.
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Dispersed Generators” IEEE/PES Transmission and
Distribution Conference and Exposition, Vol 2, pages
709 - 723, 28 Oct-2 Nov 2001.
7. Shafiu, A. Bopp, T. Chilvers, I. Strbac,
G. “Active management and protection of distribution
networks with distributed generation” Power
Engineering Society General Meeting, IEEE, page(s):
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1098 - 1103 Vol.1, 6-10 June 2004.
8. J.G. Slootweg, W.L. Kling, «Impacts of
Distributed Generation on Power System Transient
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2002.
9. Dung Tran Khanh Viet “Interconnected
Renewable Energy System in Utility - Unbalanced
analysis”, in Conf CCECE 2006: Canadian
Conference on Electrical and Computer Engineering,
Ottawa, May 7/10/2006, pp. 2284 - 2287.
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pp.2045 - 2052, 1995.
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detection methods for Utility - Interactive inverters in
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PETROVIETNAM
Petrovietnam News
'-.,+!,+&)/-+(&+-/!'"!.*#/).%/.*/'--.(
V
ietnamese Deputy PM Hoang Trung Hai
hails the significance of the project
between Petrovietnam and Zarubezhneft, September
30, 2010.
Rusvietpetro, a joint venture between the Russian
firm Zarubezhneft and Petrovietnam on September 30
(local time) in the Nenetsky Autonomous Region of
Russia started extracting the first flow of oil.
Rusvietpetro was founded on February 21, 2008 to tap
oil in 13 fields in the Nenetsky Autonomous Region,
Northern Russia.
The project has an initial capacity of around 3,000
tons per day. It is expected that the total capacity will
reach over 1.5 million tons and 4.6 million tons per
year in 2011 and 2018 respectively. Under the contract
with Zarubezhneft, Petrovietnam holds 49% shares of
Rusvietpetro and can exploit oil in four lots with an
area of around 807 km2.
At the event, Vietnamese Deputy PM Hoang Trung
Hai said that Rusvietpetro would serve as a good example for future petroleum cooperation between Viet Nam
and Russia. The Vietnamese Government pledges to
attach importance and create every favorable condition
for business activities of Petrovietnam with Russian traditional partners, asserted the Deputy PM.
Meanwhile, Russian Deputy Energy Minister
Anatoly Yanovsky believed that the initial achievements of Rusvietpetro would create a solid foundation
for Petrovietnam and Zarubezhneft to continue applying the cooperative model to Vietnam, Russia, and
third countries.
(source: VGP)
'--.(/+)/!&).$,//&'$,/).%/)&/.,+*("
contract will be the foundation for the two sides to
expand cooperation, including the exchange of experiences in crude oil trading and processing.
The Deputy PM declared that the Vietnamese government supports the cooperation between
Petrovietnam and TNK-BP in exploring and exploiting
oil and gas in the two countries’ territories and in third
countries.
PV Oil General Director Nguyen Xuan Son said he
hoped that after the signing, TNK-BP will continue to
participate in oil processing, refinery and distribution in
Vietnam .
R
ussia’s TNK-BP Oil Group will provide the
first shipment of 100 tons of crude oil for the
Petrovietnam Oil Corporation (PV Oil) via the Eastern
Siberia-Pacific Ocean (ESPO) in November this year.
To this effect, a contract was signed between PV Oil
General Director Nguyen Xuan Son and Deputy
Chairman of TNK-BP’s Management Board Maksim
Barskiy in Moscow on September 29 at the presence of
Vietnamese Deputy Prime Minister Hoang Trung Hai.
Speaking after the signing ceremony, Deputy PM
Hai expressed his hope that the partnership between
PV Oil and TNK-BP will further develop and harvest
more results in the future.
He stressed that the signing of the ESPO crude oil
The contract was an initial step for the two companies to sign other agreements in order to boost cooperation and mutual investment, he added.
According to Petrovietnam President Phung Dinh
Thuc, Petrovietnam considers Russia a strategic area
and with the contract, TNK-BP has become the third
biggest partner of Petrovietnam and PV Oil, after
Zarubezhneft and Gazprom.
He informed that the first oil stream resulting from
the cooperation between Petrovietnam and
Zarubezhneft will run in the next several days.
Petrovietnam has so far signed 20 oil and gas contracts with foreign companies, he added.
(source: VNA)
79
NEWS
'*#/'(+/,.*,&/*-+(%%.*#/-',--'%%/%,*$.*#
&'$,/).%/!'"!/--+,"
crude oil with Bach Ho crude oil (Vung Tau) to
supply raw material for Refinery processing oil
and petroleum products. This is the first time that
Vietnamese engineers and technicians installed
successfully blending crude oil pump system at
Dung Quat Refinery. This success brings economic efficiency for the Project and opportunity for
developing of Refining and Petrochemical
Industry of Vietnam as well.
M
r. Nguyen Hoai Giang - CEO of Binh
Son Refinery and Petrochemical Co.
(BSR) said that, the installation of the 2 pumps
system for blending crude oil was finished by 10
engineers and technicians of Petrovietnam
Technical Services Corporation (PTSC) at crude
oil storage area of Dung Quat Refinery.
This blending crude oil pump system installed
in vertical direction was manufactured in Austria
with worth 2 million US dollars. This pump system
shall be used for blending sweet crude oil or sour
CEO of BSR also said that, at present, the
Refinery has blended imported sour crude oil that
sulfur component higher than sulfur component of
Bach Ho crude oil with Bach Ho crude oil in ratio
of 20:80 for processing oil and petroleum products. From August till now, Dung Quat Refinery
has imported total 350,000 tons of crude oil
through five (5) tankers from Azerbaijan Republic
and Malaysia for blending with Bach Ho crude oil
for processing oil and petroleum products that
supply demand of domestic market.
Khoi Nguyen
,".*(&/ .# %.# +-/-(,+/.*/).%//#(-/.*$'-+&
E
nhancing safety during offshore oil and gas
exploration and production was the main topic
of a seminar, hosted by the Vietnam National Oil and
Gas Group (Petrovietnam) in Ho Chi Minh City.
Petrovietnam’s Vice President Do Van Hau
recalled the Deepwater Horizon explosion which
occurred in the Gulf of Mexico on April 20, 2010,
killing 11 people and triggering the largest-ever oil
spill in the history of oil and gas exploration.
The incident set off alarm bells throughout the
industry and reminded management agencies and
the oil and gas industry to re-examine safety in the
sector, he said.
Hau said that over the past 30 years,
Petrovietnam and international contractors have
spared no effort in ensuring the safety of their staff
and the environment, stressing that there have
80
been no serious accidents so far.
However, following the Deepwater Horizon incident, safety in offshore oil and gas production has
become a special concern for the State and a priority task for the Vietnamese oil and gas industry.
The delegates, including managers and representatives from oil and gas joint ventures and services companies from Vietnam and overseas,
reviewed and recommended various measures to
ensure safety in the industry.
They also discussed the lessons learnt from the
oil spill in the Gulf of Mexico as well as its impacts
on the international insurance market and the risk
management measures and insurance policies
used by oil and gas companies.
(source: VNA)
PETROVIETNAM
- )&,/).%//#(-/-,'&.+/.*/-!)+%.# +
A
two-day meeting of the Council for
Security Cooperation in the Asia-Pacific
(CSCAP) study group on security and safety of offshore oil and gas installations was held in the central city of Da Nang on Oct.7 - 8.
CSCAP was established on June 8, 1993 in
Kuala Lumpur with the aim of building and boosting
trust and security cooperation among regional countries and territories via an informal diplomatic channel between scholars and research institutes.
Participants at the workshop discussed challenges of the sector, especially during installation,
operation and removal activities, and associated
safety risks to the seaborne activities.
Since its establishment, the organisation has
hosted many workshops and conducted significant
research on regional security.
They also put forward measures to boost regional cooperation in order to ensure security and safety for oil rigs and offshore installations.
Recommendations of its study groups will be
transferred to formal diplomatic channels, such as
the ASEAN Regional Forum, for policy-making considerations.
The workshop was jointly held by the Diplomatic
Academy of Vientam and Singaporean and
Australian CSCAP representatives.
As a CSCAP member, Vietnam has implemented its duties with full responsibilities in the spirit of
the CSCAP Charter.
The hosting of the workshop, held for the first
time, highlighted Vietnam ’s role in CSCAP as well
as in regional cooperation to ensure security and
safety for offshore oil and gas installations, and maritime safety.
In the past three years, Vietnam was appointed
co-chair of the CSCAP study group on countering
the proliferation of weapons of mass destruction and
hosted three group meetings in Vietnam.
It is expected to help enhance Vietnam ’s prestige in dealing with regional and global issues,
showing the country’s active involvement in the
international integration process.
Vietnam has also proposed the establishment
of study groups on water-source protection, the
first meeting of which is expected to be held in
early 2011.
(source: VNA)
.' )/ )&!)&(+,/ (*/ +$/ )*%'$,-/ ,")&(*$'")/*$,&-+(*$.*#/-/.+ //,+&).,+*("/(*$/
H
anoi - 25th October 2010, Mizuho today
concluded MOUs with Petrovietnam and
PVFC, and it is anticipated that these MOUs will
strengthen the relationship between all of the parties.
Under the MOU with Petrovietnam, Mizuho will
provide financial services for Petrovietnam’s investments by interfacing with the Japanese and global
capital markets, syndication debt market, multilateral agencies and ECAs, providing financing in particular for Petrovietnam’s interest in the Nghi Son
Refinery project.
Through the MOU with PVFC, Mizuho and
PVFC will focus on building close cooperative relationship between the financial institutions, sharing
investment opportunities, and collaborating on bank-
ing services and project finance.
Mizuho has extensive experience in Vietnam,
with the establishment of a Hanoi Branch in 1996
and a Ho Chi Minh City Branch in 2006. Mizuho is
participating in Petrovietnam’s Nhon Trach 1 Power
Plant syndication facility of 270 million USD and
Petrovietnam’s Dung Quat refinery syndication facility of 250 million USD, and has committed to joining
the syndication facilities for several of
Petrovietnam’s subsidiaries.
All parties look forward to working together in
close cooperation under the MOUs, which represent
a remarkable milestone in the relationship among
the three entities.
Ngoc Anh
81
NEWS
Oil & Gas Prices in the Global Market
Crude oil prices ($US/barrel)
Week
Crude oil grade
Spot prices
Brent Dated-UK
Oct.
11-13
Oct.
4-8
Sep.27Oct.1
Sep.
20-24
Sep.
13-17
Sep.
6-10
Aug.30Sep.3
Aug.
23-27
80.04
80.52
76.53
74.86
75.28
73.93
72.77
70.88
OPEC Basket
83.43
84.09
79.96
78.33
78.57
77.00
75.43
73.13
Bonny Light-Nigeria
Fateh-Dubai
Minas-Indonesia
Ural-Russia
WTI-US
Crude futures
st
Brent 1 (ICE)
84.88
80.72
83.85
82.43
82.31
85.61
80.63
83.88
83.15
82.37
81.45
76.59
79.88
79.11
78.33
79.87
75.38
78.22
77.68
74.03
80.24
75.96
78.67
78.43
75.51
78.65
74.61
77.21
76.73
74.65
77.13
73.63
75.95
75.27
73.88
74.91
71.27
73.98
72.75
73.13
83.95
84.13
80.82
78.53
78.76
77.68
76.24
74.23
WTI 1 (Nymex)
82.31
82.37
78.42
74.95
75.65
74.86
74.03
73.16
Term Crude Formulas
Arab Lt-US-cif
Arab Lt-EU -Med
Arab Lt-Far East-fob
83.31
82.88
80.03
83.37
83.07
80.04
79.33
79.26
76.15
74.93
76.04
74.86
76.41
76.33
75.45
75.55
74.95
74.10
74.78
73.62
73.03
74.08
72.18
71.28
st
Sources: PIW
Market data provided by Reuters
Oil products prices
Grade
Mogas 95-$/tone-Spot Rotterdam
Naphta-$/barrel-FOB Singapore
Gas Oil 0.5%S-$/barel-FOB Singapore
FO 3%S-$/tone-FOB Singapore
Oct’10*
742-766
80.5-83.5
92.5-93.3
475-477
Sep’10
686-715
73.3-76.5
85.5-88.8
442-452
Aug’10
660-730
72.0-74.0
84.2-91.2
440-473
Jul’10
675-702
67.5-70.5
82.5-86.8
430-454
Jun’10
688-710
70.0-72.8
82.0-85.5
433-443
* Note: For 18 st. days of Oct. Sources: Reuter. PIW
LPG prices ($US/ton)
Propane
Algeria
Saudi Arabia CP*
South China (Spot)
Japan (Spot.)
Butane
Algeria
Saudi Arabia CP*
South China (Spot)
Japan (Spot)
Oct’10
690.00
680.00
Oct’10
700.00
705.00
-
Sep’10
640.00
630.00
685.88
687.31
Sep’10
655.00
650.00
709.57
711.00
Aug’10
Jul’10
Jun’10
May’10
Apr’10
Mar’10
605.00
675.00
639.67
647.19
580.00
625.00
586.55
593.50
575.00
670.00
656.66
665.07
650.00
725.00
710.85
718.45
640.00
725.00
732.29
735.43
700.00
730.00
738.80
743.41
Aug’10
Jul’10
Jun’10
May’10
Apr’10
Mar’10
600.00
595.00
656.93
659.60
640.00
625.00
607.00
612.18
610.00
670.00
662.10
668.68
715.00
715.00
710.95
715.40
660.00
715.00
719.86
723.00
705.00
715.00
710.96
715.57
* Notes: CP = Contract Price; Sources: LPGW
82
PETROVIETNAM
Asia Pacific LNG prices ($US/mm BTU)
Sources of
Japan Import
From Abu Dhabi
- Alaska
- Australia
- Brunei
- Indonesia
- Malaysia
- Oman
- Qatar
Average
China Import
- Australia
- All sources
South Korea Imp.
- Qatar
- Malaysia
- All sources
Aug’10
Jul’10
Jun’10
May’10
Apr’10
Mar’10
Feb’10
Avg/09
12.09
13.36
12.34
12.70
8.85
12.59
7.37
13.23
11.30
12.11
12.52
11.71
12.46
9.09
12.49
10.19
12.66
11.32
10.83
12.02
11.89
12.19
9.28
11.86
6.53
12.26
10.48
11.98
12.58
11.40
12.47
10.04
12.15
8.34
13.01
11.39
11.85
12.43
11.72
12.39
9.34
12.16
6.99
12.93
10.98
11.72
12.02
10.79
9.82
9.17
11.48
7.70
12.26
10.42
10.58
11.68
10.68
9.31
9.01
11.11
6.70
12.44
10.16
8.93
8.39
8.82
10.30
7.45
9.49
6.87
10.91
9.01
3.55
6.24
3.78
5.65
3.55
6.08
3.31
7.28
3.22
5.95
3.33
6.03
3.22
4.62
3.23
4.43
13.58
9.25
10.85
13.31
8.84
10.51
13.28
8.20
10.17
13.23
9.74
11.09
12.85
11.21
10.91
11.24
8.25
9.79
11.04
7.06
8.98
12.51
7.92
10.37
Note: cif corrected; Sources: WGI
Natural gas prices ($US/mm BTU)
ICE-London
Contract
Month
Oct’10
Nov’10
Dec’10
Jan’11
Feb’11
Mar’11
Apr’11
May’11
Oct. 11
Oct. 4
Sep. 27
Sep. 20
Sep. 13
Sep. 6
Aug. 27
Aug. 23
7.56
7.85
8.05
8.01
7.84
7.71
7.67
7.34
7.65
7.93
7.91
7.71
7.66
7.60
6.95
7.36
7.79
8.07
8.06
7.82
7.71
7.56
6.55
6.97
7.44
7.78
7.76
7.51
7.40
-
6.56
7.09
7.55
7.90
7.86
7.62
7.43
-
6.42
7.06
7.56
7.82
7.77
7.54
7.35
-
6.32
6.98
7.44
7.75
7.69
7.47
7.22
-
6.50
7.15
7.66
7.90
7.85
7.63
7.33
-
Oct. 11
Oct. 4
Sep. 27
Sep. 20
Sep. 13
Sep. 3
Aug. 30
Aug. 23
3.60
4.01
4.28
4.32
4.27
4.23
4.27
3.72
4.04
4.25
4.28
4.23
4.20
4.24
3.91
4.14
4.31
4.32
4.26
4.22
4.24
3.82
4.00
4.24
4.42
4.43
4.36
4.29
-
3.94
4.17
4.45
4.64
4.65
4.58
4.50
-
3.94
4.17
4.46
4.65
4.64
4.55
4.49
-
3.81
4.12
4.44
4.61
4.60
4.53
4.45
-
4.08
4.28
4.54
4.68
4.67
4.60
4.51
-
Nymex-New York
Contract
Month
Oct’10
Nov’10
Dec’10
Jan’11
Feb’11
Mar’11
Apr’11
May’11
Sources: WGI
Offshore Facilities and Equipment Market
Oil import freight cost ($=USD)
From-To
Cargo size
Jul’10
dwt
WS
Persian Gulf-Japan
230,000
64
Persian Gulf-N.Europe
250,000
Persian Gulf-Houston
Jun’10
Apr’10
WS
$/th
WS
$/th
WS
$/th
1.60
104
2.59
80
1.98
100
2.50
45
1.40
62
1.94
55
1.71
70
2.17
250,000
52
2.18
68
2.88
57
2.40
62
2.65
W.Africa-N.Europe
125,000
87
1.47
114
1.93
130
2.19
119
2.00
W.Africa-Houston
125,000
76
1.73
107
2.44
123
2.79
116
2.65
65,000
131
2.71
128
2.65
150
3.11
146
3.03
N. Europe-Houston
$/th
May’10
Drewry Shipping Consultants Ltd. OGJ
83
NEWS
LPG Shipping rates
Spot ($US/ton)
nd
Cargo size
From-To
71,000 t
Persian Gulf-Japan
44,000 t
Persian Gulf-Japan
3,000 t
Tee-Lisbon
1,800 t
Tees-UK
1,800 t
Tees-Lisbon
st
nd
st
nd
st
2 .Hal.
Sep’10
1 .Hal.
Sep’10
2 . Hal.
Aug’10
1 . Hal.
Aug’10
2 . Hal.
Jul’10
1 .Hal.
Jul’10
35,00
34,00
34,00
31,00
34,25
36.00
35,00
34,50
34,50
33,00
36,25
38.00
67,00
69,00
69,00
71,00
71,00
71.00
44,00
47,00
47,00
50,00
50,00
50.00
88,00
90,00
90,00
95,00
95,00
95.00
($US 1000/cal.month)
nd
1st. Hal.
2 .Hal.
Sep’10
Cargo size
75-78,000 m3 modern
3
75,000 m older
3
54,000 m
3
35,000 m
3
12-15,000 m
3
3,200m to West
3
3,200m to East
Sep’10
700
700
700
600
500
225
220
700
700
700
600
500
225
220
nd
2 .Hal.
Aug’10
700
700
700
600
500
225
220
1st .Hal.
nd
2 .Hal.
Jul’10
700
700
700
600
500
225
220
Aug’10
700
700
700
600
500
225
220
1st .Hal.
Jul’10
700
700
700
600
500
225
220
nd
2 .Hal.
Jun’10
700
700
700
600
500
225
215
-EA Gibson -LPGW
North Sea offshore supply vessel dayrates (GBP)
Updated: 13 October 2010 20:35 GMT
Type
Large AHTS
Medium AHTS
Small AHTS
Large PSV
Medium PSV
Small PSV
Tug
6 - 13 Oct
10,000-15,499
10,333-10,849
6941-8370
8750-16,016
6800-12,399
5308-5553
29 Sep - 6 Oct
8500-14,466
1137-14,142
6716-11,800
7500-18,082
7500-12,000
8000-10,000
5308-5533
22 - 29 Sep
9600-18,599
10,000-14,142
12,000-14,250
10,000-15,000
5308-5308
15 - 22 Sep
12,399-56,830
14,983-14,983
6533-6696
16,500-22,000
10,000-20,000
15,000-15,000
4083-8166
Source: Seabrokers, Stavanger
West Africa ofshore supply vessel dayrates (USD)
Updated: 04 August 2010 17:48 GMT
Type
Small AHTS 3900-6000
BHP (Pre 1990)
Small AHTS 3900-6000
BHP (Post 1990)
Medium AHTS
7000 - 9999 BHP
Large AHTS 10,000 13,999 BHP
V. Large AHTS
14,000 - 18,000 BHP
PSV<1500 dwt
PSV>2900 dwt
Jun
May
Apr
Mar
7250-8000
7250-8000
7250-8500
7500-9000
10,000-11,500
10,000-11,500
9500-11,500
10,500-12,500
12,000-16,500
12,000-17,000
12,500-17,000*
8000**-17,000
13,000-17,500
13,000-18,000
1350018000
14,000-17,500
22,500-26,500
22,000-26,000
13,500-23,500
14,000-24,000
9500-10,500
13,000-16,000
10,000-11,500
13,000-15,500
10,500-11,500
13,000-16,000
7500**-11,000
14,000-17,000
* From April going forward, rates reported on this
size of AHTS are for post 1990 build vessels only
** Rates based on pre 1990 build tonnage
Source: Chart Shipping, Barcelona
84
Collected and edited by Mai Trang

tapchi dau khi

Transcription

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