XXII. THA AILAND D - Advanced Resources International

XXII. Thailand
XXII.
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
THA
AILAND
D
SUMMA
ARY
While
W
no sha
ale gas/oil exploration
e
activity
a
has been reportted to date in Thailand
d, this
large Southeast Asia
an country has
h significa
ant prospecttive shale ga
as and shale oil potentiial, in
at, Northern Intermontan
ne and Centtral Plains ba
asins, Figure
e XXII-1.
the Khora
ure XXII-1. Pro
ospective Shaale Gas and Shhale Oil Basins of Thailand..
Figu
Source: ARI, 2013
June, 2013
XX
XII-1
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
The
T
Khorat Basin
B
in northeast Thailand has a
an estimated
d 5 Tcf of rrisked techn
nically
recoverable shale ga
as resources, Table XX
XII-1. In add
dition, shale oil potentia
al in the Norrthern
Intermon
ntane and Ce
entral Plains
s basins cou
uld be substtantial but w
was not quan
ntified due tto the
paucity of
o available public data. Block faulting has dissrupted Thaiiland’s onshore shale basins
and may
y complicate
e future sha
ale drilling and developm
ment. Overrall, Thailan
nd’s shale gas/oil
potential is promising
g but needs to be better defined by ffurther data gathering and analysis.
Resource
Reservoir Properties
Physical Extent
Basic Data
Table XX
XII-1. Shale Gas
G Reservo
oir Propertiess and Resourrces of Thailand.
Khorat
Basin/Grosss Area
2
(32,400 mi )
Shale Form
mation
Geologic Age
Depositional En
nvironment
2
Prrospective Area (m
mi )
Org
ganically Rich
Th
hickness (ft)
Nett
Inteerval
Deepth (ft)
Aveerage
Reeservoir Pressuree
m
Nam Duk Fm
Permian
Marine
1,750
400
200
6,000 - 12,0000
9,000
Mod. Overpresss.
Avverage TOC (wt. %)
%
Th
hermal Maturity (%
% Ro)
Cllay Content
3.0%
2.50%
Low
Gaas Phase
Dry Gas
2
GIIP Concentration (Bcf/mi )
83.0
Riisked GIP (Tcf)
21.8
Riisked Recoverable (Tcf)
5.4
Thailand’s
T
gre
eatest poten
ntial appears
s to be shale
e gas depossits contained
d in Permian
n and
Triassic shale sourc
ce rocks in the Khorat, the countrry’s largest onshore sedimentary b
basin.
These shales can be locally thick,
t
organ
nic-rich, dry gas prone
e, deeply bu
uried, and overpressure
ed. Deposite
ed under shallow marine
e conditionss, they are likely to mine
eralogically b
brittle
and suita
able for hydraulic fractu
uring. The Khorat
K
Basi n has an exxisting gas p
pipeline netw
work,
local drillling rigs, and
d active inde
ependent oill and gas prroducers wh
hich could fa
acilitate shale
e gas
developm
ment.
Thailand’s
T
sh
hale oil pote
ential appea
ars to be m
more limited. Small iso
olated sub-basins
within th
he Northern Intermontane and Central Plainss basins con
ntain organic-rich shale
es of
Oligocen
ne to Early Miocene
M
age. These units
u
source
ed the basin
n’s conventio
onal oil deposits,
including
g the 30,000-b/d Sirikit-1 oil field. Th
hermally imm
mature oil shale depositts that are lo
ocally
June, 2013
XX
XII-2
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
mined att the surfac
ce may conttain mobile hydrocarbon
ns at depth
h. Howeverr, these low
w-rank
Tertiary shales
s
were deposited under
u
lacustrine sedime ntary conditions and ma
ay be high in
n clay
content with
w low “frac
ckability”.
INTROD
DUCTION
During
D
the pa
ast three de
ecades Thailand has bu
uilt up a substantial oil and natura
al gas
productio
on industry. The country
y produced 393,000 b/d
d of crude oil and liquidss in 2011 an
nd 3.6
Bcfd of natural
n
gas in
i 2011.1 Nearly
N
90% of
o its curren t petroleum output com
mes from offsshore
fields in the Gulf of Thailand
d, with only limited p
production ffrom small onshore ffields.
Approxim
mately 40% of Thailand
d’s primary energy co nsumption is supplied by natural gas,
including
g most of the
e country’s power genera
ation and gro
owing vehicle fuel usage
e.
Essentially
E
all of the oil and gas curre
ently producced in Thaila
and comes frrom conventtional
sandston
ne and carb
bonate reserrvoirs. While a handfu
ul of coalbed
d methane exploration wells
were drilled in Thaila
and during 2004-6,
2
witho
out commerccial successs, and some low-permea
ability
g targeted in
n convention
nal anticlinal traps in the
e Khorat, the
ere have bee
en no
carbonattes are being
reports of
o unconventional shale
e/tight oil or gas explora
ation & deve
elopment to
o date. The
e only
tangible sign of activ
vity for Thailand’s uncon
nventional rresources was an MOU signed betw
ween
a
PTTEP in January
y 2011 cov
vering poten
ntial joint sstudies of cconventional and
Statoil and
unconventional resou
urces in Tha
ailand and otther countrie
es.2
ARI’s
A
review
w of publishe
ed geologic
c literature i ndicates tha
at Thailand has three main
onshore sedimentary
y basins which may hav
ve unconven
ntional oil an
nd gas poten
ntial, Figure XXII1. These
e include the
e large Khorrat Basin in the
t northeasst; a series o
of smaller, issolated pull--apart
basins (s
such as Ma
ae Sot) in th
he Northern Intermonta ne Basin, w
where shale oil depositss are
being mined; and the
e similarly co
omplex Cen
ntral Plains B
Basin, which
h hosts the 3
30,000-b/d S
Sirikit1 oil field
d.
Permo-Triass
P
sic shale so
ource rocks in the Khorrat Basin, th
hought to have sourced
d the
overlying
g Permian carbonate
c
conventional
c
reservoirs,, may offer Thailand’s best shale
e gas
resource
e potential. These marine-deposite
ed shales arre thick, org
ganic-rich, w
within the dryy gas
thermal maturity
m
window, often over-pressur
o
red, and ma
ay be minera
alogically brrittle. The K
Khorat
Basin ho
osts an existing gas pipe
eline network, a local su
upply of suita
able drilling rigs, and a small
group of active indep
pendent oil and
a gas prod
ducers.
June, 2013
XX
XII-3
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
Oil-prone
O
sha
ale/tight res
sources in Thailand
T
ap
ppear to be
e less prosp
pective, alth
hough
available
e geologic in
nformation is scanter. The most o
obvious oil-prone shale
e potential is the
downdip extension of
o lacustrine
e oil shale (s
solid minera
al) deposits which are m
mined on a small
scale in the
t northern
n inter-monta
ane basins. Similar sha
ale/tight oil d
deposits also
o may be pre
esent
in the Central
C
Plain
ns Basin.
These
T
oil-prrone shaless appear less prospecttive due to their
lacustrine
e origin, low
w apparent thermal ma
aturity, as w
well as the general pa
aucity of pu
ublicly
available
e subsurface
e geologic da
ata.
1. KHO
ORAT BASIIN
1.1
In
ntroduction
n and Geologic Setting
The
T
Khorat Basin
B
in norrtheast Thailand appearrs to have tthe country’ss best shale
e gas
potential. Thailand’s
s largest ons
shore sedime
entary basin
n, the 35,000
0-mi2 petrolifferous Khora
at lies
e southern half
h of the Khorat
K
Plateau, a large roughly circcular physiog
graphic provvince.
within the
Ringed by
b mountain
n ranges, the
e Plateau ittself is relatiively flat witth 200-m avverage eleva
ation.
Drained by the Moin and Chi Rivers, the Khorat Pla
ateau receives less rain
nfall than ce
entral
Thailand, with more extreme dry
y and wet seasonality. The local e
economy of this rural arrea is
mainly ag
gricultural ba
ased, with fe
ew large citie
es or industrrial centers.
The
T
Khorat Basin
B
is sep
parated from
m the Sakon Nakhon Ba
asin to the n
north by the
e Phu
Phan antticline. The Khorat rests
s on the Indo
ochina tecto
onic micropla
ate, which iss bordered b
by the
Shan Th
hai and Sou
uth China plates
p
to th
he west and
d north, resspectively.
Its sedime
entary
sequence
e comprises
s a series of Late Cambrian through
h Recent stra
ata, which a
are interrupte
ed by
numerou
us unconform
mities and dominated by Permo--Carbonifero
ous, Triassic/Mesozoic, and
Tertiary/ Quaternary deposits. Figure
F
XXII-2
2 illustrates the stratigra
aphy and pe
etroleum sysstems
of the Kh
horat Basin.3 The shallo
ow marine to
o basinal Pe
ermian Saraburi Group iis considere
ed the
primary source
s
rock,, while the fluvial to lacu
ustrine Triasssic Kuchina
arai and Hua
ai Hin Lat Grroups
offer add
ditional sourc
ce rock pote
ential. Perm
mian dolomite
e and karste
ed limestone
es form the main
conventio
onal petroleu
um reservoirrs.
The
T
structura
al Khorat Ba
asin depress
sion was inittiated during
g the Middle
e Paleozoic,, with
widespre
ead deposittion of clas
stic and ca
arbonate se
edimentary rocks, beg
ginning with
h the
Carbonife
erous Si Tha
at Formation
n.4 Tectonic
c extension d
during the Ea
arly Permian
n broke the basin
apart into
o numerous horst and graben blocks separated by high-ang
gle normal fa
aults. Carbo
onate
reef depo
osits of the Pha Nok Kh
hao Formatio
on formed o
on regional h
highs, while clastic and sshale
June, 2013
XX
XII-4
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
deposits of the Na
am Duk Fo
ormation we
ere depositted in the troughs, w
with some a
areas
hing 20,000 feet thick. Mixed sediments of th
he Hua Na Kham Form
mation were then
approach
deposited
d during the
e Middle to Upper Perm
mian. Later basin-scale
e compressio
on and inve
ersion
caused regional
r
uplift and thrustting. Seism
mic and therm
mal maturityy data indica
ate that uplifft and
erosion removed
r
3,0
000 to 9,000 feet of sedim
mentary covver during this event.
Figure XX
XII-2. Stratigrraphy and Petroleum System
ms of the Khoorat Basin. Shhallow Marine Permian Saraaburi
Group iss the Primary Source
S
Rock. The Fluvial to
o Lacustrine TTriassic Kuchhinarai and Huuai Hin Lat Grooups
Also Have
H
Potential. Permian Do
olomite and Kaarsted Limestoones are the M
Main Conventional Petroleuum
Reservoirs.
R
Source: Thaailand Ministry off Energy, 2007.
June, 2013
XX
XII-5
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
Following the
e Indosinian orogeny, Ea
arly Triassicc continental and lacustrrine sedimen
nts of
the Kuch
hinarai Group began to unconforma
ably fill the e
extensional g
grabens of tthe Khorat B
Basin.
A second orogenic collision ma
arked by vo
olcanics folllowed, afterr which Late
e Triassic ffluvial
clastics were
w
depositted. A further erosional or non-dep ositional hia
atus occurred
d until the M
Middle
to Late Jurassic, after
a
which non-marine
e clastics a nd shales of the Kho
orat Group were
d. After a Middle Crettaceous periiod of deforrmation and volcanic evvents, evapo
orites
deposited
and clastics of the Mahasarakha
M
am Formatio
on were dep
posited. Fin
nally, the Te
ertiary Himalayan
out regional uplift
u
and ero
osion, removving up to 6,000 feet of rock.
orogeny brought abo
Figure XXII-3
3 shows a southwest-northeast o
oriented seissmic time ssection from
m the
western Khorat Basiin. It highlig
ghts possible Permian S
Saraburi Grroup and Triiassic Kuchiinarai
Group so
ource rock shales
s
and carbonates,
c
which
w
may b
be prospectiive for shale
e gas explora
ation.
These sttrata are ove
erlain by fluv
vial and alluv
vial clastic ro
ocks of the JJurassic Kho
orat Group; tthese
are not considered
c
prospective
p
due to theirr low TOC ccontent. No
ote significa
ant faulting o
of the
Saraburi Group and, to a lesser extent, Kuch
hinarai Grou
up rocks.
Figure XXII-4
4 is a south
h-north orien
nted seismicc time sectiion from the
e eastern K
Khorat
Basin. Here,
H
the low
w-TOC Carbo
oniferous Si That Forma
ation is overlain by posssible conventtional
reservoirrs of the Permian Pha Nok
N Khao Formation.
F
T
The primaryy Saraburi F
Formation so
ource
rock doe
es not appea
ar to be pres
sent in this part of the b
basin, while
e the Huai H
Hin Lat Form
mation
source ro
ock is relatively thin. These
T
Carboniferous, P
Permian, an
nd Triassic rrocks were block
faulted and
a
overlain by fluvial and
a
alluvial clastic rockks of the Ju
urassic Khorat Group. This
prelimina
ary informatiion suggests
s that the western
w
Kho
orat Basin m
may be more
e prospectivve for
shale gas
s exploration
n than the ea
ast.
Figure XXII-5 is a sch
hematic, no
on-directiona
al cross-secction of the Khorat B
Basin
ng conventional petroleum play conc
cepts. Note the Permo-Triassic sou
urce rock sha
ales illustratin
- the prim
mary targets
s -- are quite
e discontinu
uous, block ffaulted, and
d eroded in many portio
ons of
the basin
n. The patc
chy shale diistribution and structura
al and erosio
onal comple
exity are like
ely to
complica
ate shale gas
s exploration
n in the Khorrat Basin.
June, 2013
XX
XII-6
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
Figure XX
XII-3. Southweest-Northeast Seismic
S
Time Section in Weestern Khoratt Basin, Show
ws Permian Saraburi
Group an
nd Triassic Ku
uchinarai Grou
up Source Rocck Shales andd Carbonates, Overlain by FFluvial and Allluvial
Classtic Rocks of the
t Jurassic K
Khorat Group.
Source: Thaailand Ministry off Energy, 2007.
Figu
ure XXII-4. So
outh-North Seismic Time Seection from Eaastern Khorat Basin, Showiing Low-TOC
Carbo
oniferous Si That Formation
n Overlain by Conventional Reservoirs oof the Permian Pha Nok Khaao
Formatio
on. The Sarab
buri Formation
n Source Rock Does Not Apppear to be Prresent in this Part of the Baasin,
While th
he Huai Hin Laat Formation Source
S
Rock iss Relatively T hin. Note Siggnificant Faulting of the PerrmoCarbonifferous Sequennce.
Source: Thaailand Ministry off Energy, 2007.
June, 2013
XX
XII-7
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
Figurre XXII-5. Schematic Non-directional Cro
oss-section of the Khorat Baasin, Showingg Conventionaal
Petroleum Play Conceepts. Note thee Primary Perm
mo-Triassic Soource Rock Shales are Disccontinuous, B
Block
Faulteed, and Partlyy Eroded acrosss the Basin. This Structurral Complexityy may Compliccate Shale Gaas
Exxploration.
Source: Thaailand Ministry off Energy, 2007.
Although
A
the Khorat Bas
sin is overma
ature for oil, a small num
mber of con
nventional na
atural
gas disco
overies have
e been mad
de. These fields
f
target Permian ca
arbonate and Triassic cclastic
reservoirrs within antticlines and stratigraphic traps. N
Natural gas likely was ssourced by older
organic-rrich Permo-T
Triassic shalles, with gas
s being gene
erated during the Early T
Tertiary follo
owing
Cretaceo
ous burial, and then possibly migratiing along fra
actures and faults cause
ed by extenssional
rifting.5
es a detailed seismicc structure time map
p and strucctural
Figure XXII--6 illustrate
interpreta
ation of a sm
mall gas field in the central Khoratt Basin. No
ote the deep
p Triassic so
ource
rock “kitc
chen”, the up
plifted anticlinal fold thatt formed a co
onventional gas trap, an
nd the interp
preted
clockwise
e rotation alo
ong strike-sllip faults that created thi s local struccture.
Energy hollds several license bloccks in the K
UK-based
U
ind
dependent Salamander
S
Khorat
Basin. At
A last reporrt, Salamand
der was acq
quiring 3D s eismic, cond
ducting basin modeling, and
planning its first exp
ploration well in 2012-13 to test co
onventional Permian ca
arbonate targ
gets.6
Earlier th
his year Yan
nchang Petro
oleum, Chin
na’s fourth la
argest state--owned petrroleum comp
pany,
reportedlly entered into a contra
act with Thailand’s Min
nistry of Energy to exp
plore natural gas
opportun
nities in the Khorat. Coastal
C
Enerrgy and Hesss also havve interests in Khorat B
Basin
blocks bu
ut have not reported
r
activity in the past
p
two yearrs.7,8
June, 2013
XX
XII-8
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
Figure XX
XII-6. Seismicc Structure Tim
me Map and In
nterpretation of Small Gas Field in the Khorat Basin. Note
Deep Triaassic Source Rock “Kitchen
n”, Anticlinal Fold, and Inteerpreted Clockkwise Rotationn along Strikee-Slip
Faults.
Source: Salamander Energyy PLC.
1.2
Reservoir
R
Properties
P
(Prospectiive Area)
Thick,
T
organic-rich sourc
ce rock sha
ales and ca
arbonates off Permian a
and Triassicc age
occur at prospective
e depth in the
t
Khorat Basin, altho
ough mapping the loca
ation and sizze of
as is not po
ossible with current data
a. These sh
hales are th
hermally dryy-gasdepth-screened area
e or no liqu
uids potentia
al. Deposite
ed under sh
hallow marin
ne to
prone to over-maturre, with little
s
y conditions,, these shales are thou
ught to havve sourced the conventtional
basinal sedimentary
Permian carbonate and Triass
sic clastic reservoirs o f this regio
on, including
g two signifficant
producing gas fields..
Shallow
S
mariine shales also
a
occur in
n the Carbo
oniferous Si That Forma
ation, typica
ally at
depths below
b
13,00
00 feet.9
However,
H
ba
asin maturitty modeling estimates that this unit is
thermally
y over-mature and not prospective for shale g
gas development (Ro off 3 to 4%). The
Early Pe
ermian Nam Duk Forma
ation contain
ns several tthousand fe
eet of contin
nental to sh
hallow
marine sediments,
s
in
ncluding som
me organic--rich shale. TOC reporrtedly can e
exceed 3%, while
depth ranges from 8,000
8
to more than 10,0
000 feet and
d the formattion often iss over-presssured.
culated vitrin
nite reflectan
nce is over 2.5%,
2
thus tthe Nam Du
uk Fm is a potential dryy gas
The calc
shale tarrget that is unlikely to be prospective
e for liquids.
June, 2013
XX
XII-9
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
Fluvial and lacustrine deposits
d
of the Triasssic Kuchinarrai Group also have been
d as petroleu
um source ro
ocks in the Khorat
K
Basin
n, with high--TOC interva
als of unrep
ported
identified
thickness
s. The Kuchinarai Grou
up reportedly averages a prospectiive 6,500 to 7,000 feet deep
within the
e basin. Th
hermal matu
urity modelin
ng suggests it reaches tthe dry gas window, with no
liquids po
otential (Ro> 2.0%).
1.3
Resource
R
Assessmen
A
nt
As
A discussed
d above, the Permian Na
am Duk Forrmation conttains organicc-rich shaless with
suitable depth
d
and th
hermal matu
urity and app
pears to be tthe most pro
ospective tarrget for shale
e gas
developm
ment. Additiional shale gas
g potentia
al may exist in other orga
anic-rich sha
ales, such a
as the
Triassic Kuchinarai Fm,
F but thes
se were not assessed d
due to lack o
of data. The limited pu
ublicly
e data on th
he Khorat Basin
B
is nott sufficient tto constrain
n the region
nal distributio
on of
available
suitable thickness, depth,
d
TOC,, thermal maturity, and prospective
e area. Avverage value
es for
arameters we
ere estimate
ed and augm
mented by a nalogs with commercial North Ame
erican
these pa
shale pla
ays that have
e been more
e thoroughly studied.
A good North
h American analog
a
for th
he Nam Dukk Fm could b
be the Wolfcamp Shale iin the
1
Permian Basin, We
est Texas.10
These formations share sim
milar age (L
Lower Perm
mian),
onal setting (shallow ma
arine), thickn
ness (>1,000
0 ft), litholog
gy (high in ccarbonate, lo
ow in
depositio
clay), TO
OC content (average
(
3%
%), over-pres
ssuring (unccertain in the
e Khorat bu
ut assumed to be
0.6 vs 0.7 psi/ft for th
he Wolfcamp). The Kho
orat Basin a ppears to be
e structurallyy more defo
ormed
and faulted than the Permian Ba
asin but the difference
d
iss not extreme
e. Furtherm
more, the Perrmian
Basin Wo
olfcamp is le
ess thermallly maturity, ranging
r
from
m the black oil to wet ga
as windows,, thus
the analo
ogy is imperffect.
The
T Nam Du
uk Fm is well over 1,000
0 ft thick, w ith reported average 9,0
000 ft depth
h, 3%
average TOC, and fa
alls within th
he dry-gas th
hermal matu
urity window (Ro > 2.5%). The Nam
m Duk
n the basin due
d to uplift a
and erosion. Prospectivve area coulld not
is discontinuously present within
be rigoro
ously mappe
ed due to la
ack of data but
b is assum
med to be 5
5% of the Khorat Basin area
(~1,750 mi
m 2). Net organic-rich
o
shale
s
thickness also is u
uncertain bu
ut is assume
ed to be 200
0 feet,
much les
ss than 20% of formation
n thickness. Known to b
be over-presssured but not known to what
extent, th
he pressure gradient wa
as assumed to be 0.6 pssi/ft, slightly below the W
Wolfcamp an
nalog.
ARI assu
umed 6% po
orosity based
d on the Wollfcamp analo
og.
June, 2013
XXIII-10
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
Based
B
on the
ese data and
d assumption
ns, the Nam
m Duk Forma
ation in the K
Khorat Basin
n was
estimated
d to have 22 Tcf of risked shale gas in-pllace, with 5 Tcf of rissked, techn
nically
recoverable shale ga
as resources
s, Table XXIII-1. More d
detailed stud
dy is recomm
mended to d
define
and map
p these para
ameters and
d estimate the
t
full shalle gas resource potential of the K
Khorat
Basin.
1.4
Recent
R
Activ
vity
No
N shale gas
s activity has
s been reported in Thaila
and’s Khoratt Plateau.
2. CENTRAL PLA
AINS BASIN
N
2.1
In
ntroduction
n and Geologic Setting
Thailand’s
T
Ce
entral Plains
s Basin is located in th
he south-ce
entral portion
n of the cou
untry,
including
g the Bangko
ok region an
nd the highly
y productive
e rice-growin
ng regions o
of the lower Chao
Praya River. Coveriing a 25,000
0-mi2 area, the
t Central P
Plains Basin
n is not a co
ontinuous de
eposit
mprises a number
n
of small, deep
p, north-sou
uth trending
g and
like the Khorat but rather com
nuous half-grabens of Tertiary
T
age, formed due
e to transpre
essional pulll-apart tecto
onics.
discontin
The province includ
des the pro
ominent Ph
hitsanulok, S
Suphan Bu
uri, Kampha
aeng Saen, and
Petchabu
un petrolifero
ous sub-bas
sins, among others.
The
T
Central Plains Bas
sin is oil-pro
one and cu
urrently prod
duces oil from conventtional
Miocene sandstone reservoirs as
a well as pre-Tertiary
p
fractured grranites. Mio
ocene lacusstrined shales, wh
hich are orga
anic-rich and considere d the primarry source ro
ocks in this b
basin,
deposited
appear to
o have Thailand’s best potential
p
for shale oil exxploration. H
However, sh
hale oil prospects
which may be identtified by future work are likely to be limited in size, refllecting the small
discontin
nuous nature
e of the sub-basins.
uctural histo
Similar
S
to most
m
of Thailand’s basiins, the stru
ory of the Central Pla
ain is
punctuated by period
ds of extens
sion and sub
bsequent ero
osion. Lacu
ustrine shale
es and sedim
ments
were dep
posited durin
ng Oligocen
ne to Early Miocene
M
tim
me.11 An acttive margin developed in the
Middle Miocene,
M
de
epositing intterbedded fluvial sandsstones and mudstoness.
Alluvial-ffluvial
sedimentts were then deposited towards the end of th
he Tertiary a
and into the
e Quaternaryy. In
some are
eas, up to 26
6,000 feet off Cenozoic strata
s
have b
been preservved.
June, 2013
XXIII-11
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
Middle
M
Mioce
ene sandsto
ones (and more
m
recentlyy pre-Tertia
ary granites)) are the priimary
conventio
onal target in the variou
us Central Plains
P
sub-b
basins, such
h as at Sirikkit field within the
Phitsanulok Basin. Thailand’s
T
la
argest onsho
ore oil field, the Sirikit (n
now called S
S-1) comme
enced
productio
on in the ea
arly 1980’s, with over 250 wells driilled and 17
70 MMBO produced to date.
The oil is
s inferred to have been sourced
s
from
m the underllying lacustrrine shales. PTTEP acq
quired
the S1 fie
eld from Tha
ai Shell in 20
003 and plan
ns to extractt an addition
nal 40 to 50 MMbbls ove
er the
next 10 years.
y
Duriing Q3-2012
2 PTTEP prroduced an average 30,000 b/d of oil from Sirikit-1,
while continuing to drill new de
evelopment wells there.. PTTEP’s o
onshore foccus has bee
en on
d drilling and
d exploration
n techniques
s.12
advanced
In
n the Phitsa
anulok Basin
n, the main organic-ric h lacustrine
e shales com
mprise the Early
Miocene Chumsaeng
g Fm, which
h was depos
sited in a de
eep lake en
nvironment. Stratigraph
hically
nt sediments
s are also no
oted in the Suphan
S
Buri and other sub-basins, u
usually unna
amed.
equivalen
These type I/II sourc
ce rocks disp
play high to variable
v
TOC
C (average >
>2.0%13), wiith high hydrrogen
eaching ove
er 700 mg HC/g.14 Gross thickness averages 1,300 feet, with a net org
ganicindices re
rich shale interval of
o at least 600 feet.
eper parts o
of Central P
Plain basinss, the
In the dee
eng and Earrly Miocene lacustrine shales
s
may rreach maxim
mum depths of nearly 15
5,000
Chumsae
feet. Oil generation depths in th
he smaller Suphan
S
Buri Basin avera
age 7,000 fe
eet, suggestting a
large ran
nge in therma
ally mature depths
d
for liq
quids producction.
Figure XXII-7
7 illustrates the stratigrraphy and cconventiona
al petroleum
m systems o
of the
Central Basin.
B
Oligo
ocene Nong
g Bua and Sarabop
S
form
mations, the oldest sedimentary roccks in
the Centtral Basin, re
est unconfo
ormably on pre-Tertiary
p
basement. Fluvial to lacustrine shales
within the Oligocene
e to Early Miocene
M
Ch
hum Saeng Group act as the ma
ain source rrocks.
Clastic ro
ocks of the Oligocene Lan
L Krabur and
a Miocene
e Pratu Nam
m Nan forma
ations, depo
osited
under alluvial plains settings, are
e the conventional rese
ervoir targetss. These in turn are ove
erlain
by Late Miocene
M
to Recent alluvial fan dep
posits source
ed by region
nal uplift asssociated witth the
Himalaya
an Orogeny.
Figure XXII-8
8 shows a west-east
w
orriented, unin
nterpreted se
eismic time section from
m the
o
of nume
erous sub-b
basins within
n the overall Central Pla
ains Basin. The
Phitsanulok Basin, one
urce rocks are
a fluvial to lacustrine shales
s
within
n the Oligoccene to Earlyy Miocene C
Chum
main sou
Saeng Group,
G
which
h appear to be discontiinuously pre
esent on top
p of pre-Mio
ocene basem
ment.
Significant normal faulting may hinder
h
shale oil developm
ment in this basin.
June, 2013
XXIII-12
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
Figure XX
XII-7. Stratigraaphy and Petro
oleum System
ms of Thailandd’s Central Bassin. Fluvial too Lacustrine S
Shales
within th
he Oligocene to
t Early Mioceene Chum Saeeng Group aree the Main Souurce Rocks, w
while Alluvial P
Plain
Clasticss of the Oligoccene Lan Krab
bur and Mioceene Pratu Nam
m Nan Formations are Convventional Targets.
Source: Thailand Ministry off Energy, 2007
Figure XX
XII-8. West-East Seismic Tim
me Section in the Phitsanullok Sub-basinn within the Ceentral Plains B
Basin.
The Main Source Rocks are Fluvial to
t Lacustrine Shales
S
within the Oligocene to Early Mioocene Chum S
Saeng
Group
p, Discontinuo
ously Present on Top of Pree-Miocene Bassement. Notee Significant N
Normal Faultinng.
Source: Thaailand Ministry off Energy, 2007
June, 2013
XXIII-13
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
3. NOR
RTHERN IN
NTERMONT
TANE BASIN
3.1
In
ntroduction
n and Geologic Setting
Thailand’s
T
Northern Inte
ermontane Basin
B
is a la
arge looselyy defined area covering
g the
north-cen
ntral and northwestern portions
p
of the country. Similar to tthe Central Plains Basin
n and
quite unlike the relattively continu
uous Khoratt Basin, the Northern Inttermontane Basin comp
prises
numerou
us small an
nd complete
ely isolated structural ttroughs tha
at are sepa
arated by uplifts.
Several of
o these pull-apart basin
ns, such as the Fang B
Basin, produce oil in antticlinal traps from
conventio
onal sandsto
one reservoiirs that were
e sourced byy organic-ricch Miocene lacustrine sh
hales.
In additio
on, solid oil shale minerral resources near the ssurface in th
he Mae Sot Basin are u
under
small-sca
ale mining development
d
t. These orrganic-rich la
acustrine-de
eposited sha
ales may beccome
thermally
y more matu
ure and con
ntain mobile oil in the d
deeper troug
ghs, althoug
gh ARI could not
map this due to very sparse data
a control.
Mae
M
Sot Sub
b-Basin. The
T
Mae Sott Sub-basin of northwestern Thaila
and is one o
of the
more prrominent in
ntermontane
e basins in
n this topo
ographicallyy mostly rugged Norrthern
Intermon
ntane region. This north-south tren
nding basin extends over an area of approxim
mately
900 mi2, with one-third of the are
ea extending
g across the
e Moei River into Myanm
mar on the w
west.15
c
th
he topograph
hy of the ba
asin itself, w
which
Gently undulating hills and alluvial plains comprise
s about 650 feet above sea
s level.
averages
The
T Mae Sott Basin is div
vided into no
orth and sou
uth sub-basins, with the
e southern re
egion
having th
he thickest sedimentary
s
y section. It contains m
mainly non-m
marine Cenozzoic sedime
entary
units ove
erlying Permian to Jurassic carbonatte and clastiic rocks thatt were depossited in pull--apart
basins and
a
half gra
abens.
Th
hese units include the Mae Rama
at, Mae Pa
a, and Mae
e Sot
formation
ns, the latterr recognized for its oil sh
hale depositss.
exploration
Hydrocarbon
H
n of the Mae
M
Sot Ba
asin began with Swisss and Japa
anese
geologistts in the late
e 1930’s. In
n 1947 Thailland’s Depa
artment of M
Mineral Reso
ources condu
ucted
an oil sh
hale reserve
e evaluation.. During the 1980’s, th
he German and Japane
ese governm
ments
conducte
ed feasibility
y analyses of
o the oil sha
ale potentia l. Since 20
000 Thailand
d’s Mineral F
Fuels
Division has renewed
d its researc
ch on Thailan
nd’s oil shale
e deposits.
June, 2013
XXIII-14
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
Fang Sub-Basin. The crescent-shaped Fang Sub-basin in the far north of Thailand,
located about 150 km north of
o Chiang Mai,
M
is a ffault-bounde
ed intermonttane depoccenter
containin
ng Cenozoic sediments, Figure XXIII-9. The 220
0-mi2 trough
h trends NW
W-SE and bo
orders
a steep mountain
m
ran
nge to the ea
ast. The Fan
ng Basin is g
generally fla
at with slightlly rolling hillss and
an avera
age elevatio
on of 1,500 feet above
e sea level..16
A high geothermal gradient e
exists
througho
out the half-g
graben, evid
denced by ho
ot springs in
n the northern region. S
Site of Thaila
and’s
first commercial oil field, over 240 wells have
e been drille
ed to date in the Fang Su
ub-Basin.
Figure XX
XII-9. Stratigraaphy and Petro
oleum System
ms of Thailandd’s Central Bassin. Fluvial too Lacustrine S
Shales
within th
he Oligocene to
t Early Mioceene Chum Saeeng Group aree the Main Souurce Rocks, w
while Alluvial P
Plain
Clastics of Oligocene Lan Krabur and Miocenee Pratu Nam N
Nan Formationns are Convenntional Targets.
Source: Thaailand Ministry off Energy, 2007
During
D
the early Tertiary
y, extensional faults and
d rifting asssociated with
h the Indian
n and
Himalaya
an collision opened up the basin. Syn-rift seq
quences of alluvial-fluvial and lacusstrine
sedimentts were dep
posited durin
ng the Eoce
ene to Mioccene, followe
ed by post-rrift sequencces of
younger alluvium and
a
marked by a sign
nificant unco
onformity.
Overlying tthese rockss are
entiated grav
vels, sands, soils,
s
and clays of Quate
ernary to Re
ecent age. T
Total thickne
ess of
undiffere
the sedim
mentary sequence reach
hes 10,000 ft.
f
The
T stratigraphy of the Tertiary
T
rock
ks generally can be divided into tw
wo units, the Mae
Fang and underlying
g Mae Sot formations. Interbedde
ed coarse ssandstone and red to yyellow
claystone
e occur in th
he Late Mioc
cene to Pleis
stocene Mae
e Fang Form
mation; these
e were depo
osited
in an allu
uvial-fluvial environment
e
and average 1,400 feett thick. Belo
ow this unit, fluvial sandsstone
layers wiithin the Mae
e Sot Forma
ation have been
b
the prin
nciple reservvoirs for conventional oil field
June, 2013
XXIII-15
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
productio
on in the basin, beginning in the 19
920’s. As th
he Northern Intermontane region’s most
productiv
ve locale, th
he Fang Ba
asin has yiielded six o
oil fields, allthough the Pong Nokk and
Chaiprak
karn were ab
bandoned in
n the mid 1980’s. These
e reservoirs apparently were source
ed by
lacustrine
e mudstones
s and shales
s within the Mae Sot Fo
ormation itse
elf, most likely the main sshale
oil explorration target within the Fang
F
Basin.
3.2
Reservoir
R
Properties
P
(Prospectiive Area)
Mae
M
Sot Sub-Basin. The
T
Paleoce
ene Mae Ra
amat Forma
ation contain
ns mostly alluvial
conglome
erate, sand
dstone, lime
estone, and mudstone units that unconforma
ably overlie pre17
Tertiary strata.
s
Th
he Mae Ram
mat Fm is up
p to 700 fee
et thick and deeper than
n 3,300 feett (the
maximum
m total deptth of available well da
ata).
Overlyying the Ma
ae Ramat F
Fm is the U
Upper
Oligocen
ne Mae Pa Formation,
F
which
w
contains lacustrin
ne and fluvia
al deposits, including shales
and marls, along with prevalentt limestone lenses in th
he southern sub-basin. Minor oil sshale
w
the 30
00-ft thick Mae Pa Fm, a
albeit interbe
nts of
deposits can occur within
edded with large amoun
low-TOC
C strata. The
e Mae Pa Fm
F averages
s about 3,00
00 ft deep. O
at and
Overall, the Mae Rama
Mae Pa formations are not con
nsidered via
able source rocks due to lack of o
organic richness,
undeterm
mined shale thickness an
nd low therm
mal maturity.
The
T most org
ganically rich
h shale in the
e Mae Sot B
Basin is the M
Miocene Ma
ae Sot Forma
ation,
which is dominated by shale witth minor clas
stics. One interval with
hin the Mae Sot Fm con
ntains
y thin (10 to
t 15 feet) oil shales beds within
n sandy sh
hale assemb
blages, alth
hough
relatively
maximum
m thickness can exceed
d 33 feet. Rock minerralogy is dom
minated by quartz, feld
dspar,
calcite, dolomite,
d
and clay (prroportions not
n reported
d).
In the northern ssub-basin, tthese
lacustrine
e oil shale deposits are
e grey to grreen and ne
early 100 fe
eet thick. K
Kerogen con
nsists
mainly off exinite, with immobile oil
o content ra
anging from 2.5 to 62 ga
allons per to
on (1% to 26
6% by
weight). Oil shale grade
g
is highest in the middle-lowe
er section off the unit. T
This formatiion is
0 feet deep
p across mu
uch of the M
Mae Sot Ba
asin. Overa
all, the Mae
e Sot
typically about 2,000
on appears too
t shallow and
a immature for shale oil development, with Ro well below
w the
Formatio
0.7% thre
eshold.
Fang Sub-Ba
asin. The Mae
M Sot Formation of M
Miocene to P
Pliocene age can be divvided
e units: a lo
ower section
n of brown to
t reddish sa
andstone; a middle zon
ne of organicc-rich
into three
lacustrine
e claystone,, shale, and
d coal with interbedded sandstone; and an upp
per layer off gray
claystone
e, mudstone
e, and sands
stone along with fossil iinclusions. The conven
ntional sandsstone
June, 2013
XXIII-16
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
XXII. Thailand
reservoirrs have 25%
% porosity an
nd 0.2 to 2.0
0 Darcies of permeabilityy. The crude oil rangess from
16 to 38 degrees AP
PI gravity.18
The
T
rich bitu
uminous sha
ales of the middle unitt are the re
ecognized ssource rock, with
calculate
ed total orga
anic carbon averaging 15% (Type I or II).19 Grross formatio
on thicknesss can
be up to 2,100 feet,, while high--TOC shale intervals in
nterbedded w
with sandsto
one average
e 300
k (net). The formation was
w penetratted in conve
entional wellss at depths o
of 3,000 to 3
3,500
feet thick
feet, but these likely
y were drille
ed on structtural highs. Absent vitrrinite reflecttance data b
burial
m
su
uggests an Ro of 0.5%
% is not rea
ached until about 4,000
0-ft depth.
history modeling
The
minimum
m depth for mobile
m
oil ge
eneration (0.7% Ro) mayy be about 6
6,000 ft. Onlly a small po
ortion
of the Fa
ang Basin appears to meet
m
these screening
s
crriteria. ARI is unable to
o quantify su
uch a
prospective area give
en limited av
vailable data
a.
REFERE
ENCES
1
U.S. Energgy Information Administration,
A
Thailand Country Brief, February 20, 2013.
2
PTTEP, neews release, Maarch 18, 2011.
3
Polachan, S., 2007. “2007 : The 20th Bidding Round.” Thailand
T
Ministryy of Energy, Deppartment of Mineeral Fuels, June 19, 40
p.
4
Koysamraan, S. and Comrrie-Smith, N., 20011. “Basin Moddeling of Block L26/50, Easternn Khorat Plateauu, Northeast Thaailand.”
Departmeent of Mineral Fuels,
F
Ministry of
o Energy, Banggkok, Thailand, The 4th Petroleeum Forum: Appproaching to thhe 21st
Petroleum
m Concession Biddding Round, May 26 – 27, 8 p.
5
Schenk, C.J.,
C 2010. “Asssessment of Unndiscovered Oil and Gas Resoources of Southeast Asua.” United States Geoological
Survey, 722 p.
6
Salamander Energy PLC,, Macquarie Expplorers Conferennce, January 100, 2011, 22 p. (ccompany’s moree recent reports do not
mention thhe Khorat Basin.)
7
Coastal Ennergy, Corporatee Presentation, October,
O
2012.
8
Hess Corpporation, News Release,
R
November 2, 2012.
9
Departmennt of Mineral Fueels, “Thailand Peetroleum Provincces.” Ministry off Energy, Bangkkok, Thailand, 6 pp.
10
Fairhurst, B., Hanson, M.L.,
M
Reid, F., and
a Pieracacos, N., 2012. “W
WolfBone Play Evolution, Soutthern Delaware Basin:
Geologic Concept Modifiications That Have
H
Enhanced Economic SucccessAmerican A
Association of Petroleum Geoologists,
Search annd Discovery Artticle #10412, possted June 18.
11
Ronghe, S. and Surarat, K., 2002. “Acooustic impedancce interpretation for sand distribbution adjacent tto a rift boundarry fault,
Suphan Buri
B basin, Thailaand.” Bulletin, American Associaation of Petroleuum Geologists, vv. 86, no. 10, p. 7767-780.
12
PTTEP, 2012.
2
Managem
ment Discussion and
a Analysis of Operating Resuults for the Third Quarter of 20122, October 25.
13
An Integrated O
Patience, R.L., Rodriguess, S.L., Mann, A.L.,
A and Poplettt, I.J.F., 1993. “A
Organic Geochem
mical and Palyonfacies
Evolution of A Series of Lacustrine Sedim
ments from Thailaand.” ASCOPE 93 Conference Proceedings, Baangkok, p. 75-844.
June, 2013
XXIII-17
XXII. Thailand
EIA/ARI W
World Shale Gas and Shale Oil Resource Assesssment
14
Bal, A.A., Burgisser, H.M
M., Harris, D.K., Herber, M.A., Rigby, S.M., TThumprasertwong, S., and Winkkler, F.J., 1992.. “The
Tertiary Phitsanulok
P
Lacuustrine Basin, Thailand.” Nationnal Conference oon Geological R
Resources of Thhailand, Departm
ment of
Mineral Resources, Bangkok, p. 247-258..
15
Gibling, M.R., Tantisukrrit, C., Uttamo, W., Thanasuthhipitak, T., and Harluck, M., 1985. “Oil Shale Sedimentologgy and
Geocehem
mistry of Mae Soot Basin, Thailannd.” American Association
A
of Peetroleum Geologgists, v. 69, no. 55, p. 767-780.
16
Lertassaw
waphol, P., 20088. “Spatial Distribution and Relationship of Petrooleum Reservoirrs in the Fang O
Oil Field, Amphoee Fang,
Changwatt Chiang Mai.” Department
D
of Geology,
G
Chulaloongkorn Universi ty, 106 p.
17
Suwannathong, A. and Khummongkil, D., 2007. “Oil Shaale Resource in Mae Sot Basin, Thailand.” Coloorado School of Mines,
27th Oil Shhale Symposium
m, October 15-177, 8 p.
18
Settakul, N., 2009. “Fangg Oilfield Development.” Walailaak Journal of Sciience & Technollogy, vol. 6, p. 1--15.
19
Giao, P.H
H., Doungnoi, K.,
K Senkhamwonng, N., and Srihiran, S., 2011. “Assessment oof Petroleum Reesources for thee South
Fang Bassin: Uncertaintiees and Difficultiees.” Departmennt of Mineral Fuuels, Ministry off Energy, Bangkkok, Thailand, TThe 4th
Petroleum
m Forum: Approaaching to the 21sts Petroleum Conncession Biddingg Round, May 266 – 27, 74 p. June, 2013
XXIII-18