Tạp chí của tập đoàn dầu khí quốc gia Việt Nam - Petrovietnam - Số 06 - 2011 pdf

Petro ietnam Te Giac Trang field: Geological features, reservoirs and field development concepts Biofacies and sequence stratigraphy, Oligocene to Pliocene, Cuu Long and Nam Con Son Basi

Petro ietnam

Te Giac Trang field: Geological features,

reservoirs and field development concepts

Biofacies and sequence stratigraphy, Oligocene to Pliocene, Cuu Long and Nam Con Son Basins, Vietnam

Dr.Sc Phung Dinh Thuc

Dr Nguyen Van Minh

Dr Phan Ngoc Trung

Dr Vu Van Vien

Dr Sc Lam Quang Chien

Dr Hoang Ngoc Dang

Dr Nguyen Minh DaBSc Vu Khanh Dong

Dr Nguyen Anh DucMSc Tran Hung HienMSc Dao Duy Khu

MSc Le Ngoc SonMSc Nguyen Van Tuan

Dr

Dr Nguyen Tien Vinh

Dr Nguyen Hoang Yen

MSc Le Van KhoaBSc Vu Van Huan

16 Floor, VPI Tower, Trung Kinh Street,Yen Hoa Ward, Cau Giay District, Ha NoiTel: 84.04.37727108

Fax: 84.04.37727107Email: tapchidk@vpi.pvn.vn

PVEP concludes a $200 million term loan facility with Vietinbank

Agricultural residues - 2 generation feedstock for ethanol production

in Vietnam

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CO management at Exxonmobil's labarge field, Wyoming, USA2

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31 Advanced drilling in HPHT: The TOTAL experience on Elgin Franklin

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PETROLEUM EXPLORATION & PRODUCTION

Te Giac Trang field: Geological features, reservoirsand field development concepts

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74 Development of a Kinetic Model for the Aromatisation of Propane and

Propene over H-ZSM-5 Catalyst under Deactivating ConditionsThe characteristics of Miocene sedimentary rocks in theWestern Cuu Long Basin

1 Introduction

The Cuu Long Basin lies just of shore from the Eastern

Sea coast of Southern Vietnam It is separated to the South

by a basement high, the Con Son Swell, from a larger

re-gion of several sub-basins comprising the Nam Con Son

Basin that straddles a large part of Vietnam’s territorial

wa-ters and partially overlaps into other basins in Malaysian

and Indonesian waters (Fig 1)

Basin initiation has been related to phases of sion associated with the collision of India and Asia causing

exten-‘extrusion’ in SE Asia along major lineaments, (Tapponier,

et al 1982) Movements in the Middle Miocene caused brief compression and basin inversion with a regionally recognised Middle Miocene unconformity

The sedimentary sequence of the Cuu Long and Nam Con Son Basins largely comprise heterogeneous but

Biofacies and sequence stratigraphy, Oligocene to Pliocene, Cuu Long and Nam Con Son Basins, Vietnam

Jim Cole

Tie-Point Geoscience

Abstract

order megacyclical tectonostratigraphical sequences bounded by regional flooding surfaces, dated as Late Oligocene, Early Miocene, Middle - earliest Late Miocene, Late Miocene and Plio-Pleistocene respectively

The section in both basins is non-marine to marginal marine over the Oligocene to Middle Miocene, where nology is the only viable microfossil group for age dating, though there are actually few good strict palynostrati- graphical markers However stratigraphical resolution is considerably enhanced by the recognition of progressive and recurrent palynofacies to mark biofacies zones An attempt has been made at relating these zones to transgres- sive, highstand and lowstand system tracts, making use of the known palaeoenvironmental limits of certain palyno- morph taxa whose analogues occur in modern environments

paly-In this way twenty-five regionally correlatable, possibly sea-level controlled, 3 rd order cycles have been nised within the five 2 nd order cycles This scheme is in its infancy and is open to refinement as more wells are studied, but is currently complete enough for application to any new well drilled in either basin It has already led to some radi- cally revised age assignments amongst legacy wells so far studied In addition, there are some important differences

recog-in sedimentary regime between the Cuu Long and Nam Con Son Basrecog-ins, reflected recog-in the palynofacies assemblages, particularly within the Late Oligocene and Early Miocene

Age constraining of sedimentary units is particularly important in petroleum exploration of the Vietnam offshore The section has a plethora of repetitive clastic lithologies The characteristics of some of these intervals as potential migration zones or stratigraphical traps (as detectable from fluid inclusion studies), need to be accurately delineated within a workable regional sequence stratigraphical scheme.

monotonously alternating sandstones and mudstones

that are dii cult to constrain and correlate

lithostrati-graphically and by wireline logs Major limestone units are

present in the Nam Con Son Basin (Fig 2)

Additional dii culties arise from the presence of few

age restricted microfossils for strict biostratigraphical age

determination Much of the interval of exploration interest

(Oligocene - Middle Miocene) is non-marine or marginal

marine, yielding only long ranging palynomorphs (Fig 3),

though more open marine sections in the later Neogene

yield good micropalaeontological and calcareous

nanno-fossil age markers Marine inl uence commenced earlier

and is more strongly evident in the biofacies of the Nam

Con Son than the Cuu Long Basin

Though most are long ranging, morphs are present in large numbers within most cuttings samples available from the Late Palaeogene - Early Neogene Many of them have analogues in the present day across a range of depositional settings making them valuable pa-laeoenvironmental markers This permits known palaeoecological controls to be taken back into the Tertiary in depositional environment analy-sis Fluctuations in the abundance and relative frequency of eco-specii c palynomorphs over

palyno-a strpalyno-atigrpalyno-aphicpalyno-al section palyno-are therefore palyno-a proxy

of environmental change and position with spect to the global sea-level cycle

re-Palynofacies and microfacies analysis (Fig 4) reveals a progressive overall trend of increas-ing and deepening marine inl uence through-out the Tertiary in both the Cuu Long and Nam Con Son Basins For this reason sea-level change must be a prime underlying mechanism in sedi-mentation Morley (1991) has indicated that two of the principle controls on vegetation distribution are orogeny and climate, factors themselves that are part under the control of sea-level change

Sequence stratigraphy provides a way of “…subdividing basin-i ll into a series of time and spatially related units, which of er a dynamic representation of lateral facies relationships

by tracing the evolution of depositional tems in response to transgressions and regres-sions forced by cycles of relative sea level change” (Courel et al 2008)

sys-This paper investigates the opportunity of using biofacies trends at a more rei ned level in sequence stratigraphical analysis Identii cation of similar biofa-cies trends across a number of intra-basin wells should provide several additional correlation tie-points If such trends can be demonstrated to be sea-level controlled, their value as time synchronous cross-facies stratal sur-faces can be validated In this way a number of supple-mentary time-lines become available to add to the FAD’s and LAD’s (i rst and last occurrence datums) from age diagnostic biostratigraphical taxa alone A sea-level driv-

Fig 1 Cuu Long Basin - Con Son Swell - Nam Con Son Basin, Vietnam

en sequence stratigraphical model may also provide a

means of inter-basin correlation between the Cuu Long

and Nam Con Son Basins

Morley (1991) used quantitative palynomorph zones

in improved stratigraphical resolution in the SE Asian

Ter-tiary and mentioned the elimination of

non-stratigraphi-cal quantitative events whose correlation lines cut across

good biostratigraphical correlation datums A

recommen-dation of a 4 well minimum database for initiation of a

quantitative local scheme within a basin was mentioned

with a further 4 wells, a total of 8 therefore, suggested

as the requirement for full elaboration and assembly of

a scheme erected on a series of quantitative events for basin-wide predictive purposes

2 Megasequences

Five megasequences based on gross palynofacies characteristics have been recognised within the Tertiary sequence of of shore Vietnam These have been given the sui x V and are numbered stratigraphically, V0 - Late Oli-gocene; V1 - Early Miocene; V2 - Middle Miocene to earli-est Late Miocene; V3 - Late Miocene and V4 - Plio-Pleisto-cene, (Fig 2)

These megasequences sulate Geological Stages based on the Geologic Time Scale of Grad-stein et al (2004), as revised from Haq et al (1988) and Hardenbol et

encap-al (1998) They are mostly placed

at Sequence Boundaries (SB) in sequence stratigraphy parlance at the shift from highstand systems tract (HST) to lowstand systems tract (LST) These are dated at:23.03 Ma - top Oligocene (Chattanian, Ch4/Aq1)

16.97 Ma - top Early Miocene (Aquitanian/Burdigalian, Bur5/Lan 1)

11.61 Ma – top Middle cene (Langhian/Serravallian, Ser4/Tor1)

5.33 Ma – top Late Miocene (Tortonian/Messinian)

0.05 Ma – top Plio-Pleistocene (Zanclean/Piacensian/Gelasian/Pleistocene)

Each of the megasequences V1 - V4 are marked at their base inception by a major increase in marine microfossils The actual biofacies boundary may then, be better dei ned using the scheme

of Galloway (1989) that places

Fig 2 Sequence Stratigraphy Scheme, Cuu Long and Nam Con Son Basins

sequence boundaries at l ooding surfaces This occurs

slightly younger in the section, with the exception of the

Miocene - Pliocene boundary (V3-V4) at 5.33 Ma that is

al-ready placed at a l ooding surface on the Geological Time

Scale of Gradstein et al (2004)

Megasequence boundaries at the initial

transgres-sive surface of the next transgrestransgres-sive systems tract (TST)

or maximum l ooding surface at the base of the ensuing

high stand systems tract (HST), as used in this study are

Megasequence V2 is dated as Middle Miocene to early

Late Miocene (Langhian, Serravallian and Early Tortonian)

Age of the upper boundary of this megasequence is

based on microfaunal and nannoplankton evidence The biozones of these marine microfossils are N16 and NN9 respectively (early Late Miocene) that are recognised to

be present in the upper part of V2 megasequence Microfaunal and nannol oral evidence is not available

at earlier stages than the Late Miocene due to the city of marine facies in the Vietnam basins A convenient major l ooding surface, post N16 for the V2 - V3 boundary occurs at 8.0Ma within the Tortonian Stage

pau-Megasequence V3 encapsulates the remainder of the Late Miocene, nannofossil zones NN10-NN11, (Late Torto-nian - Messinian) with its upper boundary, as mentioned

at a l ooding surface rather than sequence boundary, at 5.33Ma on the global scheme Megasequence V4 encom-passes the Pliocene and Pleistocene

3 Biofacies in sequence recognition

This section examines some of the eco-specii c nomorphs and palynofacies of the Vietnam Tertiary section and the way they might be expected to respond in within transgressive, highstand and lowstand systems tracts

paly-3.1 Transgressive system tract (TST)

Following lowstand sedimentation an initial l ing surface marks commencement of deposition of the transgressive systems tract, with back-stepping retro-gradational i ner grained shelfal sediments Ravinement erosion of the underlying sediments may occur with the pene-contemporaneous reworking, making the bound-ary appear less clear cut in terms of its biofacies

ood-Rapid creation of accommodation space leads to a distinctive shallow marine microfauna if underlying open marine ingress into the basin is near and strong enough Mangrove pollen with marine dinocysts and other marine palynomorphs such as chitinous microforaminiferal lin-ings may rapidly become an increasingly important com-ponent of each successive parasequence up through the sequence In more high angle beach settings, pollen of plants such as Casuarina, Marginipollis concinnus, Pandanii-dites sp and Echiperiporites estelae are particularly evident

If the basin remains in an interior continental setting

or is distal with respect to the direction of marine ingress, raised base level will be manifest by an increase in lacus-trine algae and pteridophyte spores of associated water-

logged terrain, such as Magnastriatites howardi

Fig 3 Palynofloral Zones, Cuu Long and Nam Con Son Basins

3.2 Highstand systems tract (HST)

Following the R-inl ection point of maximum rate of

sea-level rise, with the maximum l ooding surface,

sedi-mentation may continue over an area of plentiful

accom-modation space, but it can become more regressive,

pro-gradational in aspect Palynol oral assemblages will be

dominated by lowland freshwater pollen types and where

waterlogging persists in a non-marine setting,

pterido-phyte spores, including Magnastriatites howardi from the

aquatic fern Ceratopteris

Restricted basins or those distal to the open marine

realm may register continued high freshwater base level

from the earlier TST phase, recording raised lacustrine

al-gae in the biofacies as alluvial run-of tends to be trapped

and ponded within the basin

This is indicative of the highstand systems tract If

l ooding surfaces within the early phase of high stand sedimenta-tion are sui ciently open marine

in the later phase of 2nd order mal sag, they will yield correlat-able microl oral and microfaunal assemblages

ther-3.3 Lowstand systems tract (LST)

During falling stage sediment accommodation space is at a pre-mium This ef ectively reduces the area available for deltaic and coastal plain sedimentation, lead-ing to a reduction in mangrove and lowland freshwater pollen representation in the palyno-morph assemblages

Withdrawal of the sea from the shelf leads to incision as clastic detritus is conveyed to the slope and basin of the shelf edge Carbonate sedimentation

on the shelf edge may be moted Sediment by-pass of the shelf and upper slope may lead

pro-to non-sequences and higher energy of l ow as the ‘nick’ point erodes back over an increased al-luvial gradient If sea-level does not fall below the exist-ing shelf sediments of the earlier highstand, then a shelf margin wedge systems tract may be produced

With either shelf margin wedge sedimentation or shelf incision, coarser clastic lithologies tend to predomi-nate with the higher energy run-of alluvial l ow rates The winnowing ef ect of the current leads to dispersal and destruction of organic material Palynomorph as-semblages tend to be quite poor, coinciding with coarser clastic lithologies Where palynomorphs are present they are dominated by a lower diversity of taxa and a greater concentration of montane gymnosperm pollen such as Piceapollenites sp., Pinuspollenites sp Alnipollenites sp and Zonalasporites sp

Lowstand sedimentation coincides with glacial

maxi-ma, which in the tropics may lead to increased seasonality

Fig 4 Microfacies Scheme, Cuu Long and Nam Con Son Basins

with a more marked dry season Lowland everwet

rainfor-est pollen types may be reduced in favour of shrub l oras

dominated by fern spores and savanna grassland with

Monoporites annulatus

4 Biofacies of megasequences

In this section broad trends of environmentally

sig-nii cant taxa from a number of wells are examined in

terms of their value as sea-level indicators for both basins

This has permitted compilation of summary palynol oral

biofacies (palynofacies) for the Cuu Long Basin, (Fig 5)

and for the Nam Con Son Basin, (Fig 6) These diagrams

provide a general summary of correlatable ‘bioevents’ for

these two basins…

4.1 V0 Megasequence (Fig 7)

Sediments of the Palaeogene, rift-i ll V0

megase-quence, Tra Tan Formation of the Cuu Long Basin are

typi-cally characterised by the Oligocene marker taxon

Ver-rutricolporites pachydermus (an early morphotype within the Florschuetzia trilobata complex) with abundant fresh-water algae Bosedinia sp., Pediastrum spp and Botryococ-cus spp., with a very distinctive l uf y brown sapropelic organic matter (SOM)

The latter is highly organic and hydrogen rich, cal of deposition in meromictic (stratii ed) water bodies of lacustrine character Rare marine palynomorphs and ma-rine microfauna occur, but they are probably caved.This is a well known and a primary regional source rock of numerous back-arc, Pannonian and continental rift fracture basins around the periphery of the Sunda micro-plate of the Eastern Sea, Malaysia and Western Indonesia, (Cole & Crittenden, 1997)

typi-In the Nam Con Son Basin, studies to date have vealed very little of the Cau Formation section Samples that have been examined yield poor palynomorph recov-ery with V pachydermus and other freshwater pollen plus

re-records of the lacustrine alga diastrum Samples yield common inertinitic kerogen derived from coal seams indicative of freshwa-ter swamp deposition

Pe-4.1.1 SequencesThe V0 sequence in the Cuu Long Basin reveals some marked downhole changes in abundance

of the lacustrine algae cus, Bosedinia and Pediastrum in

Botryococ-a few wells thBotryococ-at hBotryococ-ave penetrBotryococ-ated

a good interval of the Late cene There are also changes in the kerogen type It is uncertain that these changes can be related

Oligo-to sea-level ef ects within these continental rift basins Morley (1991) has noted that mangrove taxa of the Florschuetzia group and the back mangrove taxon Dis-coidites borneensis may have had

a freshwater swamp origin in the Palaeogene

Sequences V0a, V0b and V0c have been tentatively recognised

Fig 5 Palynofacies Defined Genetic Sequences, Cuu Long Basin, Vietnam

pending further studies, but they may be more related to

local changes in water conditions, though base level

ef-fects within non-marine settings are known, (Cole &

Crit-tenden 1997; Cole et al 2005)

Very little of this sequence has been seen in the Nam

Con Son Basin, but its depositional facies is dif erent from

the Cuu Long Basin Lacustrine facies are present

repre-senting small ephemeral ponds and lagoons associated

with peatswamps, not the deep stratii ed semipermanent

lakes of the Cuu Long Basin

4.2 V1 Megasequence (Fig 8)

Early Miocene sediments are distinguished

palyno-logically by the occurrence of Florschuetzia semilobata

and F trilobata below the evolutionary appearance of F

meridionalis

The Bach Ho Formation of the Cuulong Basin records the i rst occurrence of in situ marine microfossils This ma-rine indication is only slight, in the form of rare dinocysts, chitinous foraminiferal linings in the palynomorph assem-blage, plus locally common occurrences of the brackish marsh agglutinating foraminifera Jadammina cf macre-scens and the gastropod Littorina spp in the microfaunal analysis There is an absence of open marine planktonic foraminifera and calcareous nannofossils

In the palynomorph assemblage freshwater trine algae remain very prominent, particularly Botryococ-cus spp and Pediastrum spp., but reduced occurrences

lacus-of Bosedinia spp There is a diversity lacus-of freshwater pollen and spore taxa, particularly Magnastriatites howardi Ker-ogen assemblages yield common amorphous kerogen (AOM) though not the SOM rich component seen in the

V0 megasequence the-less these lacustrine phases provide an im-portant subsidiary source rock facies, though to a lesser degree than in the syn-rift section

None-Dua Formation semblages from the Nam Con Son Basin yield an abundance of the lacus-trine alga Pediastrum spp, but not records of Botryo-coccus spp, or Bosedinia sp., indicative of smaller, less permanent, ephem-eral lakes that may have been subject to minor marine inundation Pte-ridophyte spores and gymnosperm pollen are comparatively common Marine palynomorphs are present in increasing numbers up through the megasequence and the microfaunal analysis re-veals J cf macrescens plus Elphidium cf tikutoensis and rare ostracods

as-Fig 6 Palynofacies Defined Genetic Sequences, Nam Con Son Basin, Vietnam

4.2.1 Transgressive Sequences

Transgressive sequences in the Cuu Long Basin (V1c

and V1f, Fig 8) are marked by an increase in mangrove

taxa and marine palynomorphs such as chitinous

micro-foraminifera and marine dinocysts A variety of lacustrine

algae (Bosedinia, Botryococcus and Pediastrum), plus acme

occurrences of the aquatic fern spore Magnastriatites

howardi occur

Semi-permanent lakes may have been at their greatest

extent, with sedimentation occurring across a broad

ac-commodation space of expansive lower coastal plain

Ma-rine l ooding events may have introduced maMa-rine

palyno-morphs and restricted brackish marine microfaunas to the

lower stratii ed layers of the lake allowing freshwater algae

to continue to thrive in the surface photic zone Damp

ar-eas of slow moving water courses on the lake fringes may

have favoured the aquatic fern Ceratopteris and

abundanc-es of its spore Magnastriatitabundanc-es howardi Inl ux of the

brack-ish intertidal marsh agglutinating foraminifera Jadammina

cf macrescens is most evident in the V1f sequence

These sequences in the Nam Con Son Basin are

char-acterised by prominent occurrences of the freshwater

algae, Pediastrum spp only indicative of smaller less

per-manent ephemeral lakes subject to greater and more

frequent marine inl uence than in the Cuu Long Basin

Surrounding areas may have been less choked by water-courses and more stable for

a greater diversity of phytes and clearer develop-ment of mangroves, but less favourable for lowland forest

pterido-to become established

4.2.2 Highstand SequencesHighstand sequences (V1a & V1d) are character-ised in the Cuu Long Basin by prominent lacustrine facies, but on a slightly reduced scale than seen in the TST, similarly of the lake fringing facies of Ceratopteris and its spore M howardi

Assemblages of lowland freshwater pollen and spores tend to be richer and more diverse These biofacies rel ect the development of stable plant communities and diverse habitats over extensive tracts of prograding upper and lower coastal plain, during this phase of diminishing rate of sea-level rise

In the Nam Con Son Basin marine inl uences are overall greater and lacustrine palynofacies, with M how-ardi lesser than in the Cuu Long highstand sequences V1a and V1d

4.2.3 Lowstand Sequences

In the Cuu Long Basin lowstands V1b and V1e are characterised by poor palynomorph recovery and diver-sity as shelfal accommodation space was rapidly reduced

In some cases lacustrine algae are common (as in V1e) probably indicating a non-sequence during lowstand, this interval not being distinguishable from the overlying TST

In the Nam Con Son Basin poor recovery interval V1e corresponds to higher run-of rates and reduced accom-modation space Raised percentages of gymnosperms in V1b plus freshwater pollen and spores, but reduced man-grove and marine inl uences may rel ect greater exposure

of terra i rma for upper coastal plain habitats and a ing of montane substrates

widen-Fig 7 Late oligocene (VO) Megasequence, Cuu Long and Nam Con Son Basins

4.3 V2 Megasequence (Fig 9)

Onset of the Middle Miocene is marked by a

pro-found biofacies change in both the Cuu Long Basin (Cuu

Long/Nam Con Son Formations) and Nam Con Son

Ba-sin (Thong/Mang Cau Formations) This has been related

to the 15.8 Ma l ooding event that brought in a marked

change in sedimentation style in both basins, an event

that occurred just above the base of the Middle Miocene

within the Langhian

In the Nam Con Son Basin (including the Northern

Nam Con Son Basin of MIA/block 4 area where

sedimen-tation was initiated over basement highs) thick intervals

of reef carbonates, clayey limestones, coquinoidal

lime-stones, mudstones and packstones (Areshev et al 1992)

were deposited The Nam Con Son Basin may have

be-come linked with the East Natuna Basin of Indonesia to the South where May & Eyles (1985) have documented Middle Miocene reefal carbonates

4.3.1 Lowstand SequencesSome of the thickest limestone development in the Nam Con Son Basin has been linked to lowstand sedimen-tation (sequence V2b), though in some areas of the basin clastics remained dominant

In the Cuu Long Basin no carbonates are tered as the basin remained landward of the shelf edge Sedimentation was characterised by valley incision and high sedimentation rates of coarse clastics in depocen-tres Sequence V2b yields abundant gymnosperm pollen indicative of greater upper coastal plain/montane inl u-ence in the depositional environment and it is poorly dis-tinguishable from the ensuing TST Sequence V2e is a poor recovery interval in some areas of the Cuu Long Basin, whilst sequence V2i is rarely observed, perhaps rel ecting a non-sequence during sediment by-pass at this time in the basin

encoun-4.3.2 Transgressive SequencesCuu Long Basin sediments of the V2c sequence are characterised by common mangrove pollen and

M howardi indicative of the creation of abundant ment accommodation space with wide tracts of lower coastal plain for these plants to l ourish

sedi-Nam Con Son Basin V2c sediments display a marked increase in marine palynomorphs but lime-stones are not always evident probably due to ravine-ment erosion and renewed extensive shelfal clastic sedimentation leading to inundation of former reefs This erosion, plus that of the underlying LST, may lead

to dii culty separating sequence V2c from the lying V2b

under-4.3.3 Highstand SequencesHighstand sedimentation in the Cuu Long Basin

is well represented by the V2a sequence that registers the earliest consistent marine palynomorphs in this basin plus horizons of prominent mangroves, all in response to the 15.8 Ma maximum l ooding surface The V2d HST is well represented in the Cuu Long Basin by a marked increase in M howardi, accompa-

Fig 8 Early Miocene (V1) Megasequence, Cuu Long and Nam Con Son

Basins

nied by prominent lowland rainforest pollen, a response

to wide development of lowland waterlogged habitats

at a time of maximum accommodation HST sequences

V2g and V2h are represented by increased numbers of

Pe-diastrum spp plus abundant and diverse freshwater

pol-len and spores, as similar responses to prograding

sedi-mentation over an area of wide accommodation space

following the decline in rate of sea-level rise

Sequence V2h occurs immediately following the

mid-Miocene unconformity (Tjia & Liew, 1996) and documents

a further stage of regional thermal sag with progressive

marine inl uence as indicated by an uphole increase in

marine and mangrove taxa

In the Nam Con Son Basin the V2a sequence is

indi-cated by an uphole increase in marine to

ter-restrial (M:T) palynomorph ratio, a much more

marked change than that seen in the Cuu Long

Basin This boundary also coincides with the

i rst appearance of limestones in the Nam Con

Son Basin, lithologies completely absent in the

Cuu Long Basin Shallow marine benthonic

mi-crofaunas (microfacies 3 - 4) indicative of an

in-ner to middle in-neritic palaeoenvironment occur

at the base V2 megasequence, where none are

seen in the Cuu Long Basin

The V2d sequence (coeval with an acme of

M howardi in Cuulong Basin) is marked by a

fur-ther uphole increase in marine palynomorphs

and mangrove taxa

The V2h sequence is dated as middle

Mio-cene (intra NN6 nannofossil zone) throughout

the Nam Con Son Basin Palynomorph analysis

reveals a further increase in marine taxa (M:T

ratio) within this sequence, with progressive

subsidence following the middle Miocene

in-version and unconformity This unconformity

shows diachroneity of its base and top across

the Cuu Long Basin from the apparent absence

of some sequences in some wells, but it

ap-pears to be an intra NN6 event

4.4 V3 Megasequence (Fig 10)

This megasequence is marked by a further

uphole increase in marine taxa in the

palyno-morph assemblage

An open marine, lower neritic to upper-?middle bathyal depositional palaeoenvironment is indicated by microfaunal evidence throughout the V3 sequences of the Nam Con Son Basin (Nam Con Son Formation, Fig 2) Very diverse and abundant deepwater planktonic and benthonic foraminifera of high planktonic to benthonic (P:B) ratio, microfacies zone 5 are observed

A further indication of restriction/restricted marine inl uence in the Cuu Long Basin is perceived from the ab-sence of these deep marine faunas of microfacies zone 5,

in the Dong Nai Formation

4.5 V4 Megasequence (Fig 10)

Rei ned foraminiferal and nannofossil zonations have

Fig 9 Middle Miocene - early Late Miocene (V2) Megasequence

permitted recognition of this megasequence, that forms

the major part of the sedimentary pile in the northern

part of the Nam Con Son Basin (MIA/Block 4 area)

Sedimentation in both the Cuu Long and Nam Con

Son Basins became linked as the coni nes of their former

basin margins were overstepped Sediments assigned to

the regional Bien Dong Formation are recognised in both

basins

The megasequence is dated as NN12 - NN19 and

N18 - N23 and includes a major Late Pliocene tectonic

event Sequences may be recognised on microfaunal,

palynol oral and nannol oral evidence of water depth

changes and intermittent input of terrestrial palynol oras

5 Conclusions

An attempt has been made to identify

corre-latable sea-level controlled biofacies events for

improved stratigraphical resolution in the

non-marine and marginal non-marine sections (Oligocene

to mid-Miocene) of the Cuulong and Nam Con

Son basins This has been achieved by

recognis-ing frequency trends of some environmentally

controlled, but long ranging palynomorphs and

microfaunal microfacies

It has been possible to demonstrate dif

er-ences between coeval sequer-ences in the 2 basins

Such provincialism is indicative of isolation and

separate autonomous basin i lling histories The

independent ef ects of marine transgression

and forced regression have been invoked An

overall sea-level control may permit correlation

of sequences between these unconnected

inte-rior fracture continental rift basins

These dif erences diminish into the Middle

Miocene, as progressive marine transgression

led to more regionally synchronous

sedimen-tation It was not until the Late Miocene that

planktonic and benthonic foraminifera plus

cal-careous nannofossils become abundant,

indica-tive of widespread marine transgression of the

regional thermal sag phase

These studies have allowed the assembly

of initial stratigraphical templates that provide

improved stratigraphical resolution through the

rapidly alternating clastics of the Cuu Long Basin

and clastics/carbonates of the Nam Con Son Basin, of shore Vietnam Tertiary interval

-This work has also permitted a revision of the age ing, with intervals of section previously assigned to the Oligocene now recognised as Miocene Intervals earlier dated as Plio-Pleistocene are now dated older, also within the Miocene This has led in some cases to more than dou-bling the previously identii ed Miocene section

dat-The biofacies templates provide a means of stratal calibration for future work on chemostratigraphy and l uid inclusion stratigraphy (FIS) These latter new methods may also provide independent verii cation of correlatable da-tums so far identii ed on biostratigraphical criteria alone

Fig 10 Late Miocene (V3) & Plio-Pleistocene (V4) Megasequences Cuu Long

& Nam Con Son Basins

6 Acknowledgements

Thanks are due to Marcus Jakeman, Phil Jones and

Claire Murphy for help with the palynology Nannofossil

work was done by Steve Starkie Microfaunal studies were

carried out by Graham Coles, who is especially

accred-ited for compiling and making available the microfacies

scheme

References

1 Areshev, E G., Tran Le Dong, Ngo Thuong San &

Shnip, O A., 1992 Resources in fractured basement on the

continental shelf of Southern Vietnam Journal Petrol Geol

15(4) 451 - 464

2 Bat, D., Quynh, H., Que, P H & Dong, T L., January

1993 Tertiary stratigraphy of continental shelf of

Viet-nam In: Proceedings of the 1st international seminar

on the stratigraphy of the Southern continental shelf

of Vietnam

3 Cole, J M & Crittenden, S., 1997 Early Tertiary

ba-sin formation and the development of lacustrine and

qua-si-lacustrine/marine source rocks on the Sunda Shelf of SE

Asia In: Fraser, A J & Matthews, S J & Murphy, R W (eds)

Petroleum Geology of Southeast Asia, Geological Society

Special Publication 126: 147 - 183

4 Cole, J M., Whittaker, M., Kirk, M & Crittenden, S.,

2005 EA sequence-stratigraphical scheme for the Late

Car-boniferous, Southern North Sea, Anglo-Dutch sector In:

Col-linson, J D., Evans, D J., Holliday, D.W & Jones, N S (eds)

Carboniferous hydrocarbon Geology: The Southern North

Sea and surrounding onshore Areas, Yorkshire Geological

Society Occasional Publication 7: 75 - 104

5 Courel, L; Rey, J; Cotillon, P; Dumay, J; Mauriaud, P;

Rabiller, P; Raynaud, J F; & Rusciadelli, G., 2008

Lithostratig-raphy from lithologic units to genetic stratigLithostratig-raphy

Stratigra-phy terminology and practice, Chapter 2 Editions Technip,

Paris 7 - 39

6 Galloway, W E., 1989 Genetic stratigraphic

se-quences in Basin analysis I: Architecture and genesis of l

ood-ing surface bounded depositional units Bull Amer Assoc

Petroleum Geol 73(2): 125 - 142

7 Gradstein, F M., Ogg, J G., Smith, A G., Agterberg,

F P., Bleeker, W., Coe, A., Cooper, R A., Davydov, V.,

Gib-bard, P H., Hinov, L., House, M R., Lourens, L., Luterbacher,

H P., McArther, J., Melchin, M J., Robb, L J., Shergold, J., leneuve, B R et al., 2004 A Geologic Timescale 2004 Cam-bridge Univeristy Press

Vil-8 Haq, B U Hardenbol, J & Vail P R., 198Vil-8 Mesozoic

& Cenozoic chronostratigraphy and cycles of sea level In: Wilgus, C.K., Hastings, B.S., Kdall, C.G., Posamentier, H W., Ross, C A & Van Wagoner, J C eds Sea level changes: An integrated approach 6Soc Econ Paleont Mineral sp pub 42: 71 - 104

9 Hardenbol, J., Thierry, J., Farley, M B., Jacquin, T H., De Graciansky, P C., & Vail, P R., 1998 Pmesozoic and Cenozoic chronostratigraphy charts In: De Graciansky, P C., Hardenbol, J., Jacquin, T H., Farley, M., & Vail, P R eds

- Mesozoic - Cenozoic Sequence Stratigraphy of European Basins; Tulsa SEPM Special Publicaton 60

10 May, J A & Eyles, D R., 1985 Well log and seismic character of Tertiary Terumbu Carbonate, Eastern Sea, Indo-nesia AAPG Bull 69(9): 1339 - 1358

11 Matthews, S J., Fraser, A J., Lowe, S., Todd, S P & Peel, F J., 1997 Structure, stratigraphy and petroleum geol-ogy of the SE Nam Con Son Basin, of shore Vietnam In: Fra-ser, A J & Matthews, S J & Murphy, R W (eds) Petroleum Geology of Southeast Asia, Geological Society Special Publication 126: 89 - 106

12 Morley, 1978 Palynology of Tertiary and nary sediments in SE Asia Proc 6th Ann Conv Indonesian Petr Assn 255 - 276

Quater-13 Morley, 1991 Tertiary stratigraphic palynology in Southeast Asia: Current status and new directions Geol Soc Malaysia, Bull 28: 1 - 36

14 Phan Trung Dien, Phung Sy Tai & Nguyen Van Dung, 1997 Basin analysis and petroleum system of the Cuu Long Basin on the continental shelf of Vietnam Proc

25th Ann Conv Indonesian Petr Assn 521 - 276

15 Tapponier, P., Peltzer, G., Le Dain, A Y., Armijo, R

& Cobbold, P., 1982 Propogating extrusion tectonics in Asia: New insights from simple experiments with plasticine Geol-ogy 10: 611 - 616

16 Tjia, H O & Liew, K K., 1996 Changes in tectonic stress i eld in Northern Sunda Shelf basins In: Geol Soc Spec Pub 106: 291 - 306

Facies and depositional environment determination

are fundamental work to be carried out when

geoscien-tists study any clastic reservoir for the purpose of

hydro-carbon exploration and development Such work can be

relatively straightforward when outcrop data is available

In the subsurface, however, it can be problematic when

only very limited core or sometimes even no core is

avail-able The idea of using wireline logs as sedimentological

tools can be traced back to the middle 1950’s when

geo-scientists and engineers studied the shape of SP and GR

curves in association with facies and environments (Serra,

2003) Since then, more studies were done in the use of

log patterns for grain size indication, vertical sequence,

fa-cies and environment determination (Visher, 1965, Serra,

1975, Galloway & Hobday, 1983) Each well log curve gives

a particular spectral picture of the rock properties

How-ever, we have to acknowledge that the use of any single

or combination of most available conventional open-hole

logs is often insui cient to clearly dei ne a facies or

depo-sitional environment due to the lack of some crucial

infor-mation such as the sedimentary structure and texture of

the rock

With the introduction of borehole image logs in the middle 1980’s, the accuracy for facies and environment delineation has been improved signii cantly through the integration of image data as part of the inputs for sedi-mentological interpretation It is unfortunate that the popularity of using the image logs for studying facies and environments is still far behind expectation until today Part of the reason why image logs were underutilized might be related to the lack of awareness and sui cient training of various image interpretation techniques to many end users Another part of the reason can be attrib-uted to the still limited case studies published with work-

l ow details explained

This paper aims to present a case study from l estuarine deposits to illustrate the log-based sedimento-logical characterization workl ow in detail It is expected

uvio-to help geoscientists uvio-to get a clear picture of what type of sedimentological information is available on images and how to use them in facies and environmental analysis, and ultimately explain how geological uncertainty can be re-duced with full integration of acquired image data with conventional open-hole logs in clastic reservoirs

Electrofacies and depositional environment interpretation for a clastic reservoir utilizing electrical image logs

Bingjian Li

Schlumberger Oil Field Services (Vietnam)

Facies are crucial inputs for depositional environment interpretation, reservoir property prediction and voir modeling Traditionally, fancies description for classic reservoirs has relied heavily on core data This is a time- consuming data acquisition process with high well cost This paper presents an alternative technique for electrofacies characterization of classic sands utilizing electrical image logs, together with a case study Electrofacies are deter- mined with integration of sedimentary structure and texture information interpreted on image logs and lithology from conventional open-hole logs Analysis of facies association, sequence trend and paleocurrent directions pro- vides satisfactory data to assist the depositional environment construction This case study along with the devel- oped workl ow promotes more complete use of the acquired borehole images and conventional open-hole logs with cost-ef ective solutions for electrofacies and environmental determination The presented data in the paper is from a

reser-l uvio-estuarine sequence but the approach devereser-loped can be appreser-lied in any creser-lastic reservoir in the reser-locareser-l Miocene or Oligocene formations in the subsurface of of shore Vietnam.

Abstract

Fig 2 Sedimentary structures detected on FMI images Plate A

(up-per) - Cross-bedding along with truncation surface and mud rip-up clasts (red arrow indicated) Plate B (lower) - burrows appear as white curved features on FMI

Facies and electro-facies

Facies refer to stratigraphic units distinguished by

lithologic, structural, and organic characteristics

detect-able in the i eld (Boggs, 1987) Electrofacies is dei ned

as “the set of log responses which characterizes an

elec-trobed and permits it to be distinguished from the others”

(Serra, 1972)

Workl ow for electrofacies determination

The workl ow for electrofacies used in this paper

includes determination of lithology from conventional

open hole logs, sedimentary structures and texture from

FMI images

Lithology using conventional open hole logs

Lithology can be dei ned using conventional

open-hole logs In the studied formation in this paper, it is proved

that the GR log is a good lithology indicator based on

pre-vious i eld experience The following GR cutof s have been

used for the major lithologies: 65 API or less for sand; 65

- 75 API for silt; 75 API or greater for shale Other logs, i.e

RHOZ, NPHI, PEF and FMI are also referred to for lithology

Fig 1 shows the dei ned lithology for the studied well

Sedimentary structure using FMI images

As commented by Selley (1970), sedimentary tures “unlike lithology and fossils are undoubtedly gener-ated in place and can never have been brought in from outside” Therefore, they are one of the key elements to

struc-be known for facies dei nition Many types of sedimentary structures can be recognized on borehole images with

or without core calibration They include predepositional structures such as various scales of erosional surfaces, primary or syndepositional such as organic structures formed in connection with an animal or plant organic ac-tivity (borrow, root traces, etc) and inorganic structures resulted in physical agents and postdepositional struc-tures such as slumping, mud-cracks, dissolution and con-cretions Fig 2 shows two examples of the sedimentary structures; one includes both predepositional, small scale erosional surfaces, as well as syndepositional inorganic structure, cross-bedding, (plate A), and another one is the syndepositional organic structure, burrows, (plate B) One needs to bear in mind that some structures might

be ambiguous on electro-images; for example small

1 m

Cross-bed sets

Truncation surface

Mud rip Mud rip- -up up up clasts clasts

Cross Cross bed bed bed set sset s t e e t

Cross Cross bed bed bed set s t sset e e t

Fig 1 Lithology definition for the studied well using GR data Track

1 - logs curves including GR, RHOZ and PEFZ Track 2 - depth in

me-ter Track 3 - lithology using previously defined GR cutoffs Track 4

- lithology defined for the entire logged zone

scale dissolution features and a pyrite nodule or small

shale clast might look similar (conductive) on images In

this case, a core calibration might be needed to ensure the

interpretation accuracy

Rock texture using SandTex*

A relative sorting index can be estimated from the

resistivity spectral analysis (SandTex* software) using the

electrical borehole images - FMI/FMS or OBMI (Newberry

et al, 2004) All points crossing the wellbore on

electro-images are grouped into three divisions - the “matrix”

frac-tion which is the background of the rock texture, resistive

fraction which is the portions having resistivities greater

than matrix and conductive fraction which has

resistivi-ties less than the “matrix” fraction SandTex* calculates the

actual resistivity represented by each of the fractions and

the percentages of the three fractions to derive a sorting

index Fig 3 gives an example showing the outputs from

SandTex*: track 1 is the fractional percentages, track 2

showing the peak resistivity as well as the upper and

low-er boundaries for a well sorted sand ovlow-erlain on the

vari-able density log display and the computed sorting index

(white curve) Fig 4 shows an example of an image

de-rived sorting index (black curve in track 2) having

reason-able agreement with the sorting index (red dot) gained from core analysis

Electrofacies analysis workflow

In this paper, an integrated workl ow is used to dei ne the electrofacies (Fig 5) First of all, lithologies are deter-mined using the conventional open-hole logs mainly GR data as described in the previous section above Second-

ly, sedimentary structures are interpreted on FMI images Thirdly, a sorting index is derived on FMI images using the SandTex* described above

Then electrofacies is determined for any particular zone by integrating the lithology, sedimentary structure and sorting index in the zone For example, a cross-bed-ded sand is dei ned if the zone has sand lithology (GR is

65 API or less in the studied well) and cross-beds observed

on FMI interpretation A relative sorting is indicated by the sorting index curve for sandstone facies only

Fig 3 Resistivity spectrum analysis display: Track 1 - percentages of

conductive fraction (blue), matrix fraction (tan) and resistive

frac-tion (red); track 2 - Variable density log display (VDL) of continuous

resistivity histogram showing peak distribution (orange) and upper

and lower bounds in yellow and sorting index in white line (from

Newberry, 2004)

Fig 4 Sorting index derived from borehole images against the

sorting index from core analysis (red dots in track 2) Track 3 - sistivity spectrum analysis displayed in VDL versus core mean grain size (white dots) (from Newberry, 2004)

re-Typical electrofacies observed in the studied well

There are seven types of electrofacies dei ned in the studied well as listed and described below

A) Mud rip-up clast-rich sandstones (MCSt)

X X bedded SST bedded SST

Electro Electro ff facies acies

Sedimentary Structure

Textural information

Laminated SH

Fig 5 Electrofacies determination workflow chart used in this study

Fig 6 Examples showing mud rip-up clast-rich sandstones (MCSt) and massive sandstones (MSt) Track 1 for both plates A & B - GR, BS

and borehole deviation Track 2 - depth (m), track 3 - RHOB and NPHI Track 4 - static FMI images Track 5 - Dip tadpole plot (0-40o scale) Track 6 - dynamic FMI Track 7 - Resitivity spectrum analysis VDL Track 8 - sorting index (yellow shaded zones as good sorted sands, purple shaded zone as poorly sorted and non-shaded zones as moderately sorted sands) Track 9 - Electrofacies and Track 10 - Lithology

Mud rip-up clast-rich sandstones (MCSt): It

usu-ally has higher GR reading than clean sandstones due to

the mud rip-up clast content The mud rip-up clasts have

various sizes and are usually quite angular (see Plate A in

Fig 6) They can be recognized well on FMI images as

con-ductive clasts The sorting is mostly poor for this type of

sandstone (see track 8 in Plate A, Fig 6) Massive

sand-stones (MSt): It shows low GR as clean sands and hardly

any sedimentary structure An example can be seen in

the upper section of the Plate A in Fig 6 Sorting is

usu-ally good for the massive sands Cross-bedded

sand-stones (CBSt): It is one of the most common facies in the

studied well It has low GR response as clean sands and

intensive cross-beds Fig 8 shows an example of four

dif-ferent sets of cross-beds separated by truncation surfaces

Some mud rip-up clasts might be observable at the base

of a truncation surface (see 471.4m of Fig 8) The

cross-bedded sands can be either well- or medium-sorted

Bed-ded sandstones (BSt): It has either low or slightly higher

GR than clean sands Horizontal or low angle bedding (or

lamination) can be observed on FMI images for bedded

sandstones An example of bedded sandstone is given in

Plate B of Fig 6 Bedded shale (BSh): It has high GR

read-ing (>75 API) with beddread-ing or lamination observed on FMI

images (see Plate A in Fig 7) Massive shale (MSh): It has

high GR readings (>75 API) without any bedding structure

observed An example can be seen in the upper section

of Plate B, Fig 7) Bedded silt (BSIt): It has a GR reading

between 65 API and 75 API with bedding or lamination

observable on images An example of such facies is given

in the lower section of Plate B, Fig 7

Depositional environment interpretation

One of the main goals for electrofacies analysis is to

reconstruct the depositional environment However, as

Walker (1978) pointed out, “many, if not most, facies

de-i ned de-in the de-i eld have ambde-iguous de-interpretatde-ions - a

cross-bedded sandstone, for example, could be formed in a

me-andering or braided river, a tidal channel, an of shore area

dominated by alongshore currents” Therefore, it is

impor-tant to analyze the facies association or sequence as well

as paleocurrent patterns for more accurate interpretation

on depositional environments

Paleocurrent analysis

Some sedimentary structures provide directional

Fig 7 Examples of bedded shale (Plate A), massive shale (upper

section of Plate B) and bedded silt (lower section of Plot B) Track details refer Fig 6

data that shows the direction the ancient current l owed

at the time of deposition For instance, the dip direction

of cross-bed foresets can be used as a good indicator for

paleocurrent l ow direction Additionally, directional data

has also environmental signii cance Bogges (1987)

sum-marized two basic types of paleocurrent pattern as shown

in Fig 9 as well as the environmental signii cance of

leocurrent patterns (Fig 10) In the case study in this

pa-per, the paleocurrent pattern is dominantly unimodal (see

track 5, Fig 11)

Sequence Analysis

An electrosequence by Serra (1970) meant “a depth interval thick-

er than the vertical resolution of the measuring tool, presenting a pro-gressive and continuous evolution between two extreme values of mea-sured parameter, tracing a ramp”.Environemental interpretation is commonly hampered by the fact that very similar facies can be produced

in dif erent environmental settings (Boggs, 1987) It is often impossible

to make a unique environmental terpretation based on a single facies Depositional environment reconstruc-tion can be improved if we study the facies associations and sequences once all individual facies have been dei ned The sequence in which fa-cies communally occur contributes

in-as much information in-as facies selves for depositional environmental interpretation

them-An overall i ning-upward quence has been dei ned based on sequence analysis utilizing the open-hole logs and interpreted electrofacies

se-in the studied well as showse-ing se-in Track

3, Fig 11 The i ning-upward sequence starts at 489m where an erosional surface detected on FMI with mud rip-up clasts as lag deposits above it and ends at about 451m where shale

is deposited The sequence indicates a decrease in transporting power of cur-rents during deposition

Depositional Environment Interpretation

A particular depositional environment is dei ned by a particular set of physical, chemical and biological param-eters that correspond to a geomorphic unit of a particu-lar size and geometry Traditionally environmental inter-pretation was based on outcrops or core in which those needed parameters might mostly be available Environ-

Fig 8 Example of typical cross-bedded sandstones (CBSt) Track details refer Fig 6

Fig 9 Paleocurrent data plotted as rose diagrams A - Bimodal pattern B Unimodal

pattern (From Boggs, 1987)

mental interpretation can be possible when sui cient

data extracted from images and conventional open-hole

logs described above is available with limited core

cali-bration or sui cient knowledge about the mostly l

uvio-estuarine settings based on previous core studies in the

i eld The sequence is therefore interpreted in details as

following

478.8 - 489m: The section begins with channel l oor

lag deposits (mud rip-up clasts, MCSt) on an erosional

surface at 489m, overlain by bedded sand (BSt) The lag

deposits are mostly poorly sorted but the bedded sands

seem moderately sorted These deposits were eroded by a

possible dif erent channel evidenced by another

erosion-al surface at 486.2m succeeded upward by channel l oor

mud rip-up clasts as lag deposits The overlain deposits

are mostly cross-bedded sands (CBSt) with minor bedded

sand (BSt) and massive sand (MSt) interbeds in the top

The cross-bedded sands are well - to moderately-sorted

The section is interpreted as stacked l uvial channel

de-posits with the top small interval from 474.8 - 475.4m as

possible levee or lateral accretion sediments The

paleo-current direction in this channel is dominantly due north

with a unimodal pattern

467.8 - 474.8m: The low section is comprised of

moderately sorted cross-bedded sands (CBSt) deposited

on an erosional surface at 474.8m The upper section is

consisted of interbeds of wellsorted bedded sands,

mas-sive sands and cross-bedded sands The azimuth of the cross-bed dip in-dicates an overall NNW paleocurrent direction (see track 5 in Fig 11) The section is interpreted as l uvial chan-nel deposits

455.6 - 467.8m: The base contact

of the section is gradual other than

an erosional one with the underlain channel deposits The electrofacies include interbeds of bedded sands (BSt), bedded silts (BSIt) and bedded shale (BSh) The section is interpreted

as lateral accretion deposits The muth of the lateral accretion beds are dominantly dipping towards SW

azi-451- 455.6m: The section is

com-prised of mainly bedded shale (BSh)

or mudstone and interpreted as l plain deposits

ood-447.3 - 451m: The section is comprised of bedded

silts (BSIt) and shale and interpreted as brackish bay shoreface deposits

In summary, the entire studied succession is preted as stacked l uvial channel deposits overlain by lateral accretion beds which are followed by l oodplain and brackish bay deposits in the upper part It is a i ning-upward sequence deposited in currents decreasing in transporting power as deposition progressed The plaeo-current l owed dominantly northward in the nearby well location area

inter-Other potential applications oh the paleocurrent data Better understanding on well location in respect to the sandbody geometry

Plot A in Fig 12 shows a theoretical dip azimuthal tionship between current beds and lateral accretion beds for wells in dif erent locations within a l uvial meandering point bar The left rose diagram in Plot C shows that the angle between current bed azimuth and and lateral ac-cretion azimuth is greater than 90o for the studied well in this paper This indicates that the well is likely located in the upstream part of the point bar as showing in the right cartoon in Plot C of Fig 12 An of set well can be recom-

rela-Fig 10 Environmental significance of paleocurrent patterns (Selley, 1978, Boggs, 1987)

Fig 11 Electrofacies and depositional environment interpretation results for the studied

well Track 1- GR & PEF Track 2 -depth (MD) Track 3 - sequence analysis result Track 4 -

dip tadpoles (0-40o scale) Track 5 - Dip azimuth rose diagram (current beds - light blue

and lateral accretion - red) Track 6 - sorting index (yellow shaded zone - well sorted, pink

shaded zone - poor sorted and the rest zone - moderate sorted) Track 7 - lithology Track

8 - FMI static images Track 9 - Electrofacies Track 10 - facies code Track 11 - facies

descrip-tion Track 12 - depositional environment interpretadescrip-tion.

mended to be placed towards the North of the current

well in order to trace the same point bar in the appraisal

or ini ll drilling Plot B is a cross section view of the channel

showing in Plot C (right) along the direction of E-W

Optimum position for injection wells

When water injection wells are required for

second-ary recovery for this type of reservoir, it

is recommended to place the injectors either on the upstream (South, refer plot C in Fig 12) and the downstream (North, refer to plot C in Fig 12) end

of the longitudinal sand bar for better sweeping ei ciency This is because t the favorable permeability direction is

at E-W due to the dominant northward cross-beds dip Water injection needs

to avoid going along with the able permeability direction with the producers within the high perm anisot-ropy reservoirs

favor-Conclusions

A log-based sedimentological characterization workl ow for electro-facies and depositional environment analysis is proposed in this paper Elec-trofacies is determined with integra-tion of sedimentary structural and tex-tural information interpreted on image logs and lithology from conventional open-hole logs Analysis of facies asso-ciation, sequence trend and paleocur-rent directions and patterns provides satisfactory data to assist the depo-sitional environment reconstruction

A case study from a l uvio-estuarine deposit is presented to illustrate the workl ow

This case study along with the developed workl ow promotes more complete use of the acquired bore-hole images and conventional open-hole logs with cost-ef ective solutions for electrofacies and environmental determination It is believed that the approach developed herein can be applied to any clastic reservoir in the local Miocene or Oligocene formations in the subsurface of of shore Vietnam

Temrms and dei nitions FMI - Is a Fullbore Formation MicroImager tool pro-

viding an electrical borehole images

SandTex* - Is a GeoFrame Geology module that

ana-lyze resistivity spectrum for deriving a sorting index

utiliz-ing electro-image logs like FMI, FMS or OBMI

OBMI - Is an Oil-base MicroImager tool used in

non-conductive, invert-emulsion mud environments

References

1 Boggs, Sam Jr., 1987 Principles of sedimentology

and stratigraphy Merrill Publishing Company, p.784

2 Galloway, W.E and Hobday, D.K., 1983 Terrige-nous clastic depositional envi-ronmental systems Springer, New York

3 Newberry, B., sen, S and Perrett T., 2004 A Method for Analyzing Textural Changes within Clastic

Han-4 Environments ing Electrical Borehole Imag-

Utiliz-es Gulf Coast Association of Geologic Societies (GCAGS)

5 Convention San nio Texas, USA, Oct 2004

Anto-6 Selley, R.C , 1970 cient sedimentary environ-ments 1st ed Chapman & Hall, London

An-7 Serra, O., 1972 raohies and stratigraphie In: Mem B.R.G M., 77, p 775-832

Diag-8 Serra, O., and Sulpice, L., 1975 Sedimentological analysis of shale-sand series from well logs

9 Serra, O., June 17-20,

1985 Lithology tion from well logs: Case stud-ies, SPWLA 26 Annual Logging Symposium

determina-10 Serra, O., et al, 2003 Well Logging and Geology, Editions Serralog P 436

11 Visher, G.S., 1965 Use of vertical proi le in mental reconstruction Bull Amer Assoc Petroleum Geol.,

environ-49, p 41 - 46

Fig 12 Dip azimuthal relationship between current beds and lateral accretion beds for wells in

dif erent locations within the l uvial point bar

The Te Giac Trang (TGT) Field is located in the central

part of Block 16-1, Cuu Long Basin, offshore Vietnam,

approximately 100km Southeast of Vung Tau City, near the

Bach Ho Field and Rang Dong Field (Fig 1)

Following the initial discovery by well TGT-1X in 2005,

six appraisal wells were drilled, all of which flowed oil at

commercial rates except for one, TGT-4X

Oil has been found in the Lower Bach Ho Formation

(Early Miocene) and Upper Tra Tan (Late Oligocene)

sandstone reservoirs (Fig 2) in 6 accumulations separated

by either dip closures or WSW-ENE faults From North to

South, the fault blocks have been named as H1.1, H1.2, H2,

H3N, H3 and H4 (Fig 3), and comprise stacks of numerous

individual reservoirs in thinly bedded sand layers of

lacustrine and fluvial origin

In the TGT field, the dominant structural features are

ENE-WSW trending en-echelon faults, which are primarily

listric in character, with a strike-slip component Most

faults die out upwards in the Lower Miocene strata but some extend through the Bach Ho shale into the Middle Miocene An example is the major fault separating the H1 fault block and the Hai Su Trang field in the North of the TGT field Some faults extend downwards to basement, whilst many sole out in the D Sequence shale (Fig 4)

At different structural horizons, the reservoirs have been subdivided into numerous compartments in fault blocks or dip closures combined The existence of the compartments was supported by the PVT and RCI data from many TGT drilled wells

A zonation scheme was developed for reservoirs in stacked sand systems in the fault blocks based on the log, biostratigraphic and pressure data As a result, these have been subdivided into four main zones with 56 reservoirs (Fig 5)

The Intra Lower Bach Ho 5.1 reservoirs are very thin, consisting of very fine- to medium-grained sandstones,

Te Giac Trang field: Geological features, reservoirs and field development concepts

Pham Tuan Dung, Pham Thi Thuy, Nguyen Manh Tuan, Branimir Gojsic

Hoang Long JOC

Abstract

The Te Giac Trang (White Rhinoceros) Field is located in the Northern part of Block 16-1 in the Cuu Long Basin approximately 100km Southeast of Vung Tau The field was discovered in 2005 and seven wells have been drilled during the exploration and appraisal period Individual reservoir intervals have been tested at rates of over 8,000 barrels of oil per day and 4 million standard cubic feet of gas per day.

The Te Giac Trang (TGT) Field is comprised of numerous separate fault block reservoirs of Early Miocene and Late Oligocene age The reservoirs are confined to some small areas over the field and composed of normally pressured, vertically stacked sand layers The reservoir zones are made up of vertically isolated geological complexes that preclude highly deviated or sub-horizontal development wells in the reservoir zones.

In order to optimise the field development, the reservoirs in the fault blocks were planned to be developed through two well head platforms One of them is located in the North of the field to develop reservoirs in the H1 and H2 fault blocks, the other, in the South, to cover reservoirs in the H3 and H4 fault blocks.

alluvial plain environments The reservoir quality is moderate to good with average porosity 17%.

The sands of the Intra Lower Bach

Ho 5.2 reservoirs are very fine- to grained, well sorted sands deposited in lacustrine and fluvial environments with reservoir quality from good to excellent with porosity from 18 to 24%, permeability

coarse up to 3.5 D from core analysis

The sands of the Upper Tra Tan Formation (C sequence) reservoirs are very fine- to coarse- and very coarse-grained sands, deposited in freshwater lacustrine and fluvial environments The reservoir quality is moderate to good with porosity from 13 to 18.5%, meanwhile the sands

of the Upper D Sequence reservoirs were deposited in the same environments as the C sequence, but with poorer reservoir quality

The above mentioned individual reservoir zones are isolated vertically which are strongly indicated by the RCI pressure data from the drilled TGT wells together with the presence of perched wet sands Furthermore, the RCI data also suggested that the oil zones are likely interconnected via a common aquifer (Fig 6)

Due to the low resistivity net pay of the reservoirs, an Integrated Petrophysical study has been conducted for better water saturation estimation and permeability model to assist in defining intervals for perforation in the future development wells

The subsurface field development concepts for the TGT Field are based on the following assumptions and considerations:

• The accumulations are in six laterally separated fault blocks (H1.1, H1.2, H2, H3N, H3 and H4) from North

to South along the field, which will be developed from two well head platforms

Fig 2 Generelised TGT Field Stratigraphic column Main reservoir sections

Fig 3 Top C Depth Structure Map

• The reservoir

zones are vertically

isolated, precluding highly

number of water injectors

have been incorporated

into the development

plan to ensure adequate

pressure support for

fault blocks after 12

• The possible proximity of the OWCs to producer

completion intervals may cause early water breakthrough,

so that requires early implementation of artificial lift

(gaslift) The optimised completion and perforation

strategy may be efficient to manage water production

from the production start-up

• The reservoirs in the fault blocks will be brought onto production in sequence to maintain the required production plateau

With the above considerations, the following development strategy has been developed and incorporated into the dynamic reservoir simulation models:

Fig 6 TGT-1X RCI Pressure Data Analysis

Fig 7 TGT Generalised Completion

Please note that although three Gas lift mandrels are show in this schematic, additional mandrels may be required to allow interchanging of dummy’s and live valves to optimese to optimise life of well gas lift

• Oil producers and water injectors are required

for each fault block to ensure pressure maintenance and

optimum oil recovery

• All the development wells vertically penetrate as

many reservoir intervals as possible in order to optimise

recovery and mitigate the risk associated with future well

interventions

• It is envisaged that wells will be completed

using monobore completion to allow for selective initial

and add-on perforations, future well interventions and

isolation of water producing intervals

• Based on the dynamic reservoir model, 3 major

completion intervals have been defined such as 5.2U, 5.2L

and C Sequence Where possible, additional intervals will

be perforated to achieve the production target rate and

also allow efficient reservoir management

• The reservoirs in the H1 and H2 fault blocks will

be developed through H1-WHP, and the H3N and H4 fault

blocks, located over 5 kilometres to the south of the H1

and H2 fault blocks, through a separate WHP (Fig 3)

To develop the above mentioned reservoirs in thinly

bedded sandstones, the design assumes a monobore

completion focusing on completion flexibility and

efficient reservoir management that allow off-rig and

under-balance perforation after running a completion

string that can result in the possibly lowest skin damage

to the reservoir (Fig 7) The proposed completion allows

initial selective perforation as well as well intervention to

shut off water producing zones Production Logging Tools

and pressure surveys will be run for production allocation

and reservoir management

Results of studies have shown that water break

through can be managed by selectively perforated

intervals that will reduce the gaslift requirement, if

water-cut can be controlled and pressure can be maintained

For reservoir management, permanent downhole

gauges and multi-phase flowmeters will be installed to

provide pressure data and well performance information

The well will be shut-in regularly for pressure survey in

order to collect data for well intervention and gaslift

optimisation

Conclusions

• TGT oil accumulations are located in six fault blocks from North to South of the TGT field The field is developed using two wellhead platforms tied back to

a FPSO with central processing and control facilities, including fluid separation, water injection and gas compression

• The individual reservoir zones in the TGT Field are made up of a geologically complex system of multiple stacked sands that are isolated vertically Oil producers and water injectors are required for each fault block to ensure pressure maintenance and improve oil recovery

• Water injection and gaslift have been planned for oil recovery improvements

• Monobore completion design for the TGT wells allows well intervention and increase in reservoir management options when required

• The Reservoir Management Program will focus on water production management and accurate production allocation to each oil bearing interval Well interventions will be conducted regularly to improve the accuracy of material balance calculations and history matching of well and field performance PVJ

References

1 HLJOC, February 2008 16.1 - Te Giac Trang Field.

Reserves Assessment Report

2 HLJOC, September 2008 Block 16-1, Te Giac Trang

Field Outline Development Plan.

3 HLJOC, August 2009, Block 16-1, Offshore Vietnam, Te Giac Trang Field, Early Development Plan

4 HLJOC, January 2010 Block 16-1 Te Giac Trang

Field Supplemental Hydrocarbon Initially In Place &

Reserves Assessment Report

5 HLJOC, July 2010 Block 16-1, Offshore Vietnam, Te

Giac Trang Field Field Development Plan.

1 Overview of the E and Franklin extreme HPHT i elds

The Elgin and Franklin fields present one of the most

extreme combinations of pressure and temperature

in the world (1100 bars virgin pressure and 2000C) and

remains today the largest HPHT gas condensate field

developed in the British Sector of the North Sea The field

lies approximately 200km North-East of Aberdeen in the

Central Graben area

Following the discovery and appraisal period, from

1985 to 1994, development started in 1996 with two

unmanned wellhead platforms tied back to a central

production facility Eleven wells were drilled and put on

stream, with deviation up to 500, for an average drilling

duration of 120 days These wells were all drilled before a

pre defined limit of depletion level has been reached, the

level at which the mud weight window closes calculated

on Elgin and Franklin as being 100 bars First oil took place

in 2001 Later, two satellite structures, Glenelg and West

Franklin have been drilled and put in production via the

existing installations, in 2006 and 2007 respectively

Advanced drilling in HPHT: The TOTAL experience

on Elgin Franklin (North Sea - UK)

To overcome this hurdle, intense engineering works have been carried out to better understand the impact of the depletion on compaction and fracturation gradients, to design and qualify new drilling mud systems combined with stress caging techniques and to prepare contingent solutions with the deployment of expandable and drilling liner technologies

As of today three infill wells have been drilled successfully, completed and put in production by TOTAL in the Elgin and Franklin fields on the UKCS (United Kingdom Continental Shelf) This has been achieved, through severely depleted reservoirs - with more than 800 bars depletion - and has opened the door for phased HPHT developments and deep exploration beneath depleted horizons.

The reservoirs consist of Jurassic sandstones deeply

buried at a depth exceeding 5300m The primary reservoir

is the Fulmar Reservoir fluids are gas condensate with a

bottom hole pressure of 1100 bar and temperature of

1900C The Fulmar reservoir is underlain by the Pentland

reservoir with bottom hole conditions of 1150bar and

temperatures of 2000C Despite the great depth, the main

reservoir shows significant porosity and permeability,

allowing strong productivity Up to 30% porosity and 1D

permeability are seen in some Fulmar layers

The individual wells on the field can produce up to a

maximum gas rate of 3.5 x 106 m3/day gas with associated

condensate Production will give surface conditions of

860 bar wellhead shut in pressure with an associated

surface temperature of 1800C In the produced effluent, 3

to 4% CO2 and 30 - 40 ppm H2S are present Initially, field

gas production reached 14.6 MNm3/d, with 24000m3/d

(or 150 000 boepd) of condensate

This combination explains the strong need of

technology and in depth engineering for these wells

2 The challenge of ini ll wells in an HPHT i eld

Infill wells may be needed for various reasons As for conventional field management, they may be used to increase the recovery factor, hence the reserves produced,

or to accelerate the delivery or to improve the drainage

In addition they may be required to replace wells which have failed On HPHT fields like Elgin Franklin, wells are exposed to multiple threats due to the large amount

of depletion that they will see One such threat is sand or solids production which can lead to erosion of equipment such as the Downhole Safety Valve, Christmas Tree or surface production piping Rock mechanics studies suggest that sand production is inevitable beyond certain depletion

Currently, no field-proven downhole sand control method can be implemented in the more severe HPHT wells Should such event occur, wells will have to be choked down and can ultimately be lost, which leads to a significant production loss

Another threat is the liner deformation because of the compaction triggering the buckling of the liner, or because

of tectonic movements along faults or bedding planes and eventually the liner may even be fully sheared off

Both phenomena have already been experienced in the North Sea in HPHT fields Down hole measurements showed that most Elgin Franklin production liners have suffered a loss of internal diameter of

up to 60%

Phased measurements indicate that these deformations are worsening with time An example of a liner deformation is shown on the right:

It may also be important to be able

to phase a development and not to be obliged to drill all wells before first oil or gas without any production history to validate reservoir management plans

In any case, drilling infill wells in HPHT fields remains a strong challenge In such field s it is not unusual to see very fast and important depletion As an example, the initial depletion rate reached 100 bars per six months in the Elgin/Franklin case This generates two types of issues:

+ The compaction of the reservoir impacts the stress

distribution even in the formations far above the reservoir

+ The mud weight window disappears

2.1 The consequences of the compaction

Depending upon the geometry of the structure, an

arching effect may develop between the compacted

reservoir and the surface where subsidence can be seen,

even if limited This will generates among other aspects,

areas of high shearing stresses, which may affect the

wellbore stability of the infill wells It may alsol reactivate

faults which can behave as paths for the hydrocarbons

initially contained in the underlying reservoirs As a

consequence, the infill wells may face high gas levels in

formation where the initial development wells did not

encounter any hydrocarbon

2.2 The mud weight window issue

For wells drilled before depletion, a mud weight

window exists between the pore pressure and the

fracturation pressure When depletion occurs the

fracturation pressure in the reservoir decreases along with

the pore pressure At the interface between the caprock,

which stays at virgin pressure, and the depleted reservoir,

the mud weight window decreases to end up by not existing anymore (as shown on the following figure, the mud weight window disappears with depletion)

According to your well configuration, differentially depleted layers will have to be drilled in the same section, with a high risk of kick and losses or a combination of shales and depleted layers will be seen with the high risk

of instability and losses In any case, drilling becomes complex, difficult and the probability of the occurrence of

a failure increases with the depletion Ultimately, drilling with conventional techniques, within the fracturation gradient, is not possible anymore and new design, techniques and procedures have to be implemented

On Elgin Franklin, Rock Mechanics studies estimated the depletion limit to 100 bars Until such time that the depletion was less than 100 bars, initial development well design was fit Beyond, questions came of the use

of additional strings, with the uncertainties on the right setting depth, of the feasibility of drilling above the fracturation gradient by reinforcing artificially the wellbore.Driven by the need of infill wells and consequently

of overcoming this 100 b barrier, a feasibility study was launched which concluded that drilling such wells was feasible and identified two possible architectures Based

on these results, the development phase was launched and a target was selected on the Franklin field

3 The ini ll well ing feasibility in Elgin- Franklin

drill-3.1 Uncertainties fication

identi-The Fulmar reservoir consists of three main units:

+ The C sands at the top have relatively poor characteristics: degraded permeability and presence

of vertical baffles

+ The B sands in the middle have the best properties

and are the main contributors to production

+ The A sands at the bottom are tighter, but can

include good layers at the top

Under the main Fulmar reservoir are the Pentland

sands with poor characteristics They are barely depleted

and remain close to virgin pressure

3.1.1 Geomechanical uncertainties

Rock mechanic experts were brought in to estimate

the two main rock properties necessary to design the

well: fracture gradient of the reservoirs and borehole

stability of the cap rock The fracture propagation

gradient (FPG) is close to the minimum horizontal stress

and can be modeled In the case of Elgin/Franklin, a full

scale rock mechanic model, coupled with the geological

and dynamic reservoir model, had already been built and

was used for this purpose It estimated the FPG at 1.65sg

equivalent mud weight

The fracture initiation gradient (FIG) is much more

difficult than the FPG to predict, therefore, it was used

only as an indication and considered as an uncertain,

but existing, margin On this well it was predicted to be

around 1.87 sg emw

Both gradients are functions of formation pressure As

such their profile suffers from the same uncertainty as the

reservoir pressure profiles

The other information requested from rock mechanics

was the borehole stability of the cap rock This allows

definition of the minimum mud weight one can use to

cross the transition zone without suffering unmanageable

borehole instability of the open hole above The amount

of information on the cap rock is even more limited than

on the reservoir

3.1.2 Geological uncertainties

Depending on the architecture selected, the top

reservoir depth prediction was critical to maximize

the success of the transition zone drilling Extensive

geophysical techniques were used to minimize the

uncertainty attached to this test prediction These

included, among others, thorough examination of the

seismic data and uncertainty studies on depth conversion

The prediction was given to +30m/-45m

On Elgin/Franklin some thin limestone layers (centimetric to decimetric) are often found gas bearing

in the cap rock They can be drilled underbalanced but sometimes require high mud weight to enable trips 3.1.3 Reservoir uncertainties: Defining the pore pressure profile

The monitoring of the average pressure of existing Franklin producers had shown a depletion of more than

600 bar of the main reservoir The pressure of the Fulmar B sands was confidently estimated at 500 bar at the planned reservoir penetration date The pressure of the tighter C sands was more difficult to predict

The highest uncertainty lies in the pressure transition profile between the cap rock, believed to have remained

at virgin pressure, and the reservoir section Is it at the very top of the reservoir or is the bottom of the cap rock affected by depletion through microfractures? How thick

is the transition zone, and how steep is the pressure gradient in this zone?

Considering all uncertainties, different scenari were envisaged A pressure profile along the well path was drawn and a probability of encountering higher pressure

at top reservoir was evaluated for each scenario

3.2 The well architectures retained

In order to tackle the drilling challenges described above, two different architectures were defined at the feasibility study On the left is architecture 1 retained

as primary On the right is architecture 2 retained as contingent:

The first one involves the use of a specially designed mud loaded preventively with specific Loss Circulation Materials (LCM) The technique is known as “borehole strengthening” Once the reservoir has been penetrated, the transition zone is cased off by a 7” liner

The second one involves the use of an expandable liner to cover most of the cap rock The transition zone is then drilled with a lower mud weight below the FPG The remaining opened cap rock would be short enough so that borehole instabilities can be managed The transition zone is then covered with a cemented 6 5/8” drilling liner

Once the reservoir has been penetrated, the 6-5/8” liner

is covered by a 4-1/2” liner When the transition zone is

covered, the mud weight can be decreased to a value just

enough to safely drill the reservoir

As the main difficulty was lying across the transition

zone crossing, the top architecture of the well was taken

as a standard Elgin/Franklin architecture as designed for

virgin pressure This allowed focus on the transition zone

crossing and gave a comfort factor, because this top

architecture is designed to hold well full of gas at virgin

reservoir pressure, regardless of the circumstances

3.2.1 Borehole strengthening - how does it work?

The borehole strengthening technique was already

used in the industry The principle is to create a fracture

by using a mud weight higher than the FIP and plug it on

creation, to prevent its further development The plug is

formed by loss circulation material (LCM) continuously

present in the mud The created fracture increases the rock stress locally, enhancing the hole’s ability to support high mud weight It is more commonly used with water based mud which exhibits high filtration values The high temperatures experienced on Elgin/Franklin dictate the use of oil-based mud As filtration of oil-based mud is very tight, the filtration from the fracture faces into the formation is virtually nil The consequence is that the plug

at the fracture mouth needs to be tightly sealing as soon

as it is created

The other difficulty is to define the width of the fracture

to seal Rock mechanics calculations show that there is a direct relationship between geometry of the fracture, width and length, and the amount of overpressure The higher the pressure, the wider the fracture, at a given length In our case, it was estimated that the mud could

be designed to form an efficient plug of 1mm width, while keeping reasonable rheological properties despite a high solid content

The mud was therefore designed and tested to be

able to seal a 1mm gap The LCM additives consist of sized

ground marble and sized graphitic material Laboratory

testing took place to adjust LCM additives relative

concentrations, to achieve a quick and efficient plugging

of 1mm slots As well as these in-house tests, tests were

performed in a third party laboratory

3.2.2 Mechanical back-up - High collapse expandable liner

and drilling liner

Expandable liners are now becoming widely used in

the industry to seal off weak zones to allow for increasing

the mud weight to penetrate deeper zones at higher

pressure This makes them work under a burst mode In our

case, the expandable liner had to work in a collapse mode

Expanded pipe has a low collapse capacity and this is one

of the limitations of the technique To increase the collapse

capacity to the required value close to 350b, a development

programme was undertaken with the selected provider

Although expandable liner has been run previously in

high temperature wells, the operator thought it prudent to

test the expansion system with high mud weight and high

temperatures This was done in a shallow well in a special

facility in Dallas The system was left soaking with 2.15

sg oil based mud at 1760C for 18 hours before initiating

expansion and expanding 18m of pipe Examination

of the seals and parts of the system afterwards showed

no significant degradation The system was declared

qualified for the application

The liner drilling technique was also becoming

available at the time development work was ongoing

This technique presented two main advantages: Firstly

there is no need to trip out of hole to run the liner leaving

the cap rock in an under balance condition for a long time

Secondly, it allows using a higher mud weight during

drilling If heavy losses were experienced when entering

the reservoir, and the hydrostatic applied on the cap rock

dropped, the formation may collapse With a drilled in

liner, it would collapse around the liner, leaving the hole

cased off Isolation behind the liner might be already

achieved by the collapsed formation

4 The implementation on Elgin/Franklin wells

Top sections were drilled as planned The 13 3/8”

casing was called 100m short at 3585m This resulted in a

LOT (leak off test) value of 1.84 sg emw instead of a planned 2.10 sg emw As drilling was progressing in the Herring formation, 150m before planned phase TD and 450m above top reservoir, the gas level suddenly increased The hole was stopped, and the production casing was run and successfully cemented at 4939m

The main consequence of this event was that this Herring high-pressure layer was now to be crossed in the 8-1/2” section Its required mud weight, confirmed when crossing it again to be 2.05 sg minimum, was considered too high to implement the borehole strengthening technique Therefore, the primary architecture was ruled out from the start of the 8-1/2” section A decision was taken to implement the contingent architecture

Running expandable liner

Prior to run the liner, a caliper was run in the open hole to estimate the best placement for the elastomer bonded pipes The hole proved to be mostly in gauge The liner reached TD without any problem The dart was dropped, The expansion process was initiated at a much higher pressure than expected, close to the burst pressure of the cone launcher element Once initiated, the expansion process went smoothly and the liner was installed as planned

Drilling with liner

Once the expandable shoe was cleared, and the stability of the well assessed, the 6-5/8” drilled in liner was run The well was displaced to the specially designed mud loaded with LCM originally designed for the borehole strengthening technique

The liner drilled the remainder of the cap rock and penetrated the reservoir at 5451m No more than 500 liters

of losses were noticed when penetrating the reservoir These very low levels of losses lead to questioning the top reservoir depletion Drilling was continued until 5484m where the liner hanger was about to hang on top of the expandable liner The liner was then cemented

Reservoir drilling

Having achieved the successful isolation of the transition between cap rock and reservoir, one could believe that the mud weight could be decreased to drill the remaining of the reservoir with a minimum overbalance

The mud weight was decreased down to 1.50sg prior

to drilling the shoe High levels of gas were experienced

as soon as the shoe was drilled Mud weight was raised

to 1.60sg and drilling continued on 40m, in the believed

poor productivity C sands, with still high gas levels The

well was displaced back to 1.86sg designer mud to allow

a safe trip out of hole

Logs showed the presence of good sands at the top of

the reservoir, covered only partially by the drilled in liner,

pressurized up to 1004b, forbidding lowering of the mud

weight

The only remaining option was to drill to final depth

with the designer mud The losses response plan was

updated accordingly, and drilling continued at a reduced

penetration rate into the remaining C sands, the B sands

and 55m into the A sands TD was reached at 5678m with

only a seepage losses rate noticed around 200 liters/hour

for a small period It is difficult to ascertain which of the

following happened:

- The borehole was fractured and the borehole

strengthening technique worked, or

- The designer mud increased the fracture

initiation pressure by creating a perfect seal between the

borehole and the formation, or

- The mud column pressure was below the initial

fracture initiation pressure

A final 4-1/2” liner was then run, and the well has been

completed, perforated and put on stream at an initial

17,000bbl/d

Conclusions

The first infill well was successfully drilled, completed

and perforated in an HP/HT reservoir after depletion of

660 b had occurred

Two different architectures were designed to achieve

this goal and all contingencies have been used

Despite a large amount of work performed to

reduce geological and reservoir uncertainties, surprises

were found The biggest surprises were found in the

overburden, long before reaching the reservoir Most of

them are believed to be a consequence of the reservoir

depletion

High permeability sands up to 100md were drilled with 660 bar overbalance without any significant losses The formation damage created by the designer mud, if any, was by-passed by the perforations

This success has opened new perspectives in the HP/

HT domain:

- It has permitted the development of additional reserves in the Elgin/Franklin reservoir Two additional wells have now been successfully drilled through even more severely depleted reservoirs, close to 850 b depletion

- It gave an assurance that wells that fail in future can

be replaced, thus securing production over the life of field

- On a wider perspective, phased HP/HT field developments can be contemplated This will impact HPHT field economics by allowing a reduction in pre-investments

Nevertheless, HPHT Deep infill wells are not and will never be a routine job Dedicated & integrated HP/HT teams (Drilling, Geologist…) combined with ‘while drilling reactivity’ is the key to success

Based on a more than 50 years HPHT experience, Total expertise now covers the full Exploration & Development workflow Further Deep Exploration & Production will require new technologies, hence more R&D

Note: The Elgin & Franklin fields are operated by Elf

Exploration UK Limited on behalf of itself and of its venturers:

Co-E.F Oil and Gas Limited*

Eni Elgin/Franklin Limited

BG International (CNS) LimitedRuhrgas UK Exploration & Production LimitedEsso Exploration and Production U.K LimitedTexaco Britain Limited

Dyas UK LimitedOranje-Nassau (U.K.) Limited

* E.F Oil and Gas Limited, a company in which the shares are held 77.5% by Elf Exploration UK Limited and 22.5%

by Gaz de France

1 Lithological characteristics of sediments

1.1 Classification and denomination

The result of the lithological analysis has shown

that within the research area there are three kinds of

sedimentary rocks as based on the classification diagram of

R L Folk (1974); arkose sandstone, lithic arkose sandstone

and litharenite feldspar sandstone in descending volume

respectively, with matrix content below 15%

1.2 Mineral components

The mineral component characteristics are defined

by thin section lithological analysis and X-ray analysis

combined with SEM analysis

Detrital grain component:

Quartz: The major components of samples

investigated are detrital quartz grains, accounting for

28% on average and ranging from 24% to 30%, among

which mono-crystals outnumber poly-crystals The quartz

component of the sandstone samples collected at the

interval below 2999.0m is higher than that of samples

collected from the interval above 2999.0 m This enabled

the authors to conclude that quartz content increases

with depth Only rarely do quartz detrital grains contain apatite, tourmaline, zircon or rutile In the carbonate cemented sandstone some detrital quartz grains have been corroded and replaced by calcite

Feldspar: Feldspathic detrital grain content ranks second just after that of quartz On average it makes

up 21.6% and commonly ranges from 20% to 24% Sandstones below 2999.0m are lower in feldspar content than sandstones above 2999.0m, and amongst which feldspars the most common is kali feldspar (13 - 17%) followed by plagioclase (3 - 6%) Most of thekali feldspar

is orthoclase while microcline is rarely seen Orthoclase and plagioclase are altered to clay and kaolinite to varying degrees In some samplescalciteispartially or completelyreplaced

Mica: Mica content in the samples is generally quite low (under 3%), yet for siltstone it can reach 14.8%, with biotite exceeding muscovite Most of the biotite is considerably chloritized

Rock fragments: Most of the rock fragments in the samples are of granite; in addition there are smaller amounts of volcanic rock, chert and metamorphic rock fragments

Tran Van Nhuan

Vietnam Petroleum Institute

Do Van Nhuan

University of Mining and Geology

The characteristics of Miocene sedimentary rocks in the Western Cuu Long Basin

Abstract

Based on X-ray diffraction, scanning electron microscope (SEM) and thin section studies of sandstone samples from recently exploited wells GK16-1-A and GK16-1-B, the authors have documented the lithological features and mineralogy of the Miocene sedimentary rocks in the Western Cuu Long Basin The provenance of these rocks is also clarified.

The lower sequence mainly comprises coarse and medium grained continental sedimentary rocks while the overlying sequence is mostly siltstone or clay stone mixed with sandstone of littoral lacustrine and marine origin.

Granite: Granite fragments consist of quartz, feldspar

and mica The granite rock fragment content varies from

0.6% to 40.2% with the most common proportion ranging

from 10% to 15%

Volcanic fragments: The two main varieties of

volcanic fragments in descending amounts are rhyolitic

and andesitic eruptive rocks respectively Their content

varies from 0.4% to 12.6% with the dominant range from

6% to 11%

Metamorphic rock fragments: The most frequently

seen metamorphic rock fragments are quartzite and

micro-quarzite accounting for a very low percentage

generally ranging from 0.4% to 1.6%, mostly below 1%

Accessory mineral components:

Accessory minerals exist in all samples but at a

low content They are mostly apatite, rutile, zircon and

epipointe, usually found in quartz fragments

Matrix components:

Matrix components include clay minerals and organic

materials that assume the role of attaching detrital grains

to each other They are present mostly in litharenite

feldspar sandstones with a rich matrix content (20.2% to

43%), in which the most common component comprises

clay minerals (20.2% to 42%) In other types of sandstone,

such as arkose and lithic arkosesandstone, their contents

are much lower (1% to 12%)

Cement and authigenic minerals:

The results obtained by thin section lithologic analysis

and scanning electron microscope analysis have shown

that in most arkose and lithic arkose sandstones, the

contents of cement and authigenic minerals are very low

as they are mainly occupied by rock-forming clay minerals,

quartz overgrowths, pyrite and carbonate minerals In

litharenite feldpathic sandstones they are rarely seen

Pyrites: Pyritic mono-crystals are octahedral with

an average size of about 1μm They amalgamate with

each other to form small patches whose diameters

are under 3μm to fill in intergranular pores Pyrite is

the earliest precipitated minerals in the diagenesis of

authigenic minerals It is present in many samples,

with a content ranging from 0.28% to 1.27%, mostly

0.4% to 0.5%; thus it exerts no effect on the porosity

characteristics of the rocks

Chlorites: Authigenic chlorites are often well developed and are present in most samples, accounting for 43.03% of the total content of clay minerals Chloritic mono-crystals are extremely tiny and create a thin mat, coating the detrital grains and intergranular pores

of quartz overgrowths In the chloritic scales, there are micro-pores which increase water saturation and complicate the shapes of pores and accordingly reduce the permeability

Kaolinite: Kaolinite mono-crystals are anhedral

to subhedral with sizes ranging from 2μm to 10μm, mostly 5μm to 7μm They are arranged face to face like

an elongate pack or book varying from 5μm to 10μm in thickness, some even amounting to 10μm to 30μm The aggregation of these crystals totally infills intergranular pores or coats the grain surface The visible porosity of this elongate stack is relatively good

In some areas seen, kaolinite is covered by illite The total content of kaolinite and illite occupies 4% to 8%, hence they do not significantly reduce visible porosity Nevertheless, the kaolinitic stacks (5μm to 7μm) may amalgamate with one another attaching on the pore walls and infilling them, which has greatly decreased the permeability and reservoir capacity of the rocks.Calcite: Calcite is often seen in the form of small, re-precipipated grains filling in pores and replacing feldspar

as well as volcanic material Calciticareas of larger size, are present attaching fragment materials The calcitic content

is generally very low, mostly under 1%, yet there are some

samples with a rich content of calcite, reaching 20% to 25% (plate 8)

Illite: Illite is not all authigenic since it was formed as

a result of the illitization of detrital clay grains and the coating of detrital grain surfaces The illitic content in the samples collected is very low; thus, it has insignificant effects on visible rock porosity

Quartz: Generally speaking, at the interval above 2845m, quartz overgrowths are poorly developed due

to the fact that chlorite inhabited the surface of detrital quartz grains in advance However, at the interval below 2845m, quartz overgrowths developed well and formed large crystals that partially or completely fill in the pores The quartz overgrowth content in the samples occupies just 2% to 4%, which leads to a reduction in visible porosity and rock permeability