CHINA PETROLEUM EXPLORATION
Volume 21, Issue 2, March 2016
Main factors controlling accumulation of over-pressured gas reservoirs in
Block D, Myanmar
Shi Lei1, Li Fuheng2, Yin Jinyin1, Tian Naxin1, Guo Jinrui1, Zhu Weihua3
1. Sinopec Exploration & Production Research Institute;
2. PetroChina Research Institute of Petroleum Exploration and Development;
3. Research Institute of Exploration and Development, Sinopec Jianghan Oilfield Company
Abstract: Block D in Myanmar is located along the hydrocarbon-richest west deep depression zone in the Ayeyarwady Basin.
Presently, high-yield gas flows have been obtained through the testing of 3 wells drilled in the Taben Formation of the Eocene
System, indicating that this block has a certain exploration potential. However, this block features a low overall degree of exploration, a widespread presence of overpressure in major target layers of Eocene, complicated accumulation conditions and unclear
main factors controlling enrichment of hydrocarbon within an over-pressured system, thus significantly increasing future exploration risks. Through statistical analysis of worldwide representative overpressure hydrocarbon reservoirs and correlated analysis
(carried out in adjacent counterparts according to the latest geologic knowledge and exploration results regarding Block D), it is
believed that two sets of source rocks exist in Block D – Taben and Langshing. The autochthonously developed source rocks of
the Taben Formation are characterized by shallow buried depth and a low degree of evolution. Accordingly, the hydrocarbon is
theorized as originating from deep genetic depressions adjacent to the block or the source rock of the Langshing Formation. Accumulation inside the overpressure zone in Block D is primarily controlled by reservoir and preservation conditions. The effective
migration-transport system and spatiotemporal allocation are important factors for hydrocarbon enrichment. Block D lacks the
typical high-quality reservoirs of the Oligocene such as are found in the south Salin depression. Its major reservoirs feature the
medium-porosity, low-permeability sandstone common to the Taben Formation; therefore, high importance should be attached to
secondary pore and vertical fracture intervals in the overpressure system. The lower wall of the fault in Block D is an important
area of exploration due to its relatively good hydrocarbon preservation conditions.
Key words: Block D in Myanmar, accumulation conditions, overpressure, main factors controlling accumulation, area of exploration
The Ayeyarwady Basin, an important petroliferous basin
in Myanmar, has been discovered with some large oil and
gas fields, e.g. Yenangyaung, Letpando and Yawnghwe,
mainly in shallow Miocene and Oligocene sandstones. With
an area of 12,384 km2, Block D in the western Ayeyarwady
Basin had been successively prospected by Myanmar Oil
and Gas Enterprise (MOGE) and Idemitsu Kosan Co., Ltd.
with no discoveries at all. After taking over the block,
Sinopec has drilled three wells which yielded high-volume
gas flow from the Eocene Series, indicating a breakthrough
in petroleum exploration and some resource potential in this
region. However, there is little knowledge about its complicated reservoir-forming conditions, especially pervasive
overpressure in the Eocene formations due to insufficient
exploration as a whole. We need to understand what controls hydrocarbon accumulation and enrichment in
over-pressured reservoirs, in order to reduce the risks of petroleum exploration.
1. Regional geologic setting
Lying in the Chindwin River and Ayeyarwady River valleys, the Ayeyarwady Basin is 1600 km in a longitudinal
direction and 150200 km wide in a latitudinal direction,
with an area of 25.2104 km2. Tectonically, the basin lies
between the Arakan Mountains and the east plateau (Fig.1).
Eastward obduction of reverse thrusts at the west margin of
the basin gave rise to a series of folded structures with severe tectonic deformation weakening from west to east. The
whole basin is covered with Paleogene, Neogene and Quaternary deposits[12]. There are 3 secondary structural units
in the basin, i.e. west deep depression, middle uplift, and
east shallow depression (Fig.1). Oil and gas produced in the
basin mainly come from the Salin, Piya and Ayeyarwady
delta sags in the west deep depression, where 43 oil and gas
reservoirs have been discovered with proved oil reserves of
Received date: 14 Sep. 2015; Revised date: 24 Oct. 2015.
Corresponding author. E-mail: shilei.syky@sinopec.com
Foundation item: Supported by National Science and Technology Major Project “Large oil-gas field and coalbed methane development” (Grant No.
2011ZX05031-001).
Copyright © 2016, Petroleum Industry Press, PetroChina. All rights reserved.
2
CHINA PETROLEUM EXPLORATION
1.5108 t, proved gas reserves of 750108 m3 and total oil
and gas equivalent of 2.14108 t[34]. Block D stands in the
west deep depression and covers the south side of the
Chindwin sag, the salient at 22 north latitude, and the north
side of the Salin sag (Fig.1).
delta facies because water body was shallower than that in
the Late Cretaceous. The Langshing, Taben and Yaw Formations are good source beds. (3) From the Oligocene Epoch to the middle Miocene Epoch, inter-continental collision between the Indian and Eurasian plates made the
Myanmar massif continue to rotate clockwise. The basin
turned into an extrusion depression with structures extending in a nearly perfect north-south direction. Large-scale
marine regression occurred once again from north to
south[57]. Consequently, the Chindwin sag in the northern
basin and Block D were uplifted and exposed to denudation
at the earth’s surface; the Salin sag in the south was still in
littoral and neritic environments due to its low relief and
was deposited with interbedded sandstone and mudstone of
the Shwezetaw, Badaung and Okhmintaung Formations
from the bottom up in the Oligocene Epoch. In the early and
middle Miocene Epoch, the basin was deposited with the
deltaic-littoral-neritic sandstone of the Pyawbwe and Kyaukok Formations. (4) After the late Miocene Epoch, the
area which is now the Arakan Mountains was rapidly uplifted and underwent intense folding deformation due to the
sharp subduction of the Indian plate. The major sags in the
west deep depression were segmented and the basin was
strike-slipped as a whole by extrusion stress. At the end of
the Pliocene Epoch, the Arakan Mountains began to grow
and many thrust-nappe structures occurred due to massive
orogeny in the basin. Marine regression from north to south
gave birth to a fluvial environment with the braided-river
sandstone deposition of the Ayeyarwady Group.
2.
Fig. 1
Tectonic division of Ayeyarwady Basin
The Ayeyarwady Basin experienced four stages of structural-sedimentary evolution (Fig.2). (1) The whole basin
was a continental margin depression in the Late Cretaceous
and deposited with neritic-bathyal shale of the Kabaw Formation due to marine transgression from west to east and
from south to north. (2) From the Paleocene Epoch to the
end of the Eocene Epoch, the Indian plate drifted northward
and then came into contact with the south margin of the
Eurasian plate, or northern Myanmar. The basin was deflected and both flanks were uplifted and exposed to denudation locally. The lower part of the Paleocene Series was
lost due to marine regression in the early Paleocene Epoch,
giving rise to a regional surface of unconformity. Owing to
another marine transgression resulting from the subduction
of the Indian plate, the Ayeyarwady Basin was thickly deposited with the Upper Paleocene Pauhggyi Formation and
the Eocene Series. The sediments were mainly of neritic and
Vol. 21, No. 2, 2016
2.1.
Reservoir-forming conditions
Two sets of source rocks
There are two sets of source rocks, i.e. Taben and
Langshing, in the Eocene Series. The former set has been
confirmed.
Well drilling shows that the Taben Formation is composed of deltaic front argillutite in the lower part and coal
seams of swamp facies in the upper part. Dark mudstone
and shale occur extensively in the lower Taben Formation.
The maximum single-layer thickness is 13.5 m and cumulative thickness is 251.5 m. TOC content in argillaceous
source rocks ranges between 0.41.76% and the content of
chloroform bitumen “A” ranges from 0.00570.66%, indicating that argillaceous source rocks in the lower Taben
Formation have moderate to good properties. In the upper
Taben Formation, the average thickness of coal seams is
23 m and the maximum cumulative thickness is 43 m.
TOC content in coal seams is 22.4860.3% and the content
of chloroform bitumen “A” is 0.182.514%, indicating that
Shi Lei et al., Main factors controlling accumulation of over-pressured gas reservoirs in Block D, Myanmar
Fig. 2
3
Comprehensive stratigraphic histogram of Ayeyarwady Basin
coal seams in the upper Taben Formation have a high
abundance of organic matter and good properties. There are
mainly type-III kerogen and some type-II2 kerogen in the
Taben gas source rocks.
It is hard to delineate argillutite distribution in the
Langshing Formation because drilling data is unavailable.
As per regional deposition and outcrops at the west margin
of the block, it may be tentatively inferred that the
Langshing Formation is a non-coal-measure source bed.
Core-based measurements show TOC content in the
Langshing argillutite is 0.83% on the average and organic
matter is mainly of type-II1 and type-II2. The Langshing argillutite is a major set of source rocks in the Salin sag in the
southern block and the Chindwin sag in the northern block,
where TOC content ranges between 0.51.8% and vitrinite
reflectance ranges between 0.530.8%. Thus, it can be in-
4
CHINA PETROLEUM EXPLORATION
ferred that the Langshing Formation under the Taben Formation is another potential source bed in Block D in
Myanmar.
To date, both natural gas and light oil have been discovered in Block D. Natural gas was diagnosed to be coaliferous gas due to the presence of heavy ethane carbon isotope
from 26.11‰ to 23.7‰ and propane carbon isotope from
23.19‰ to 21‰. Ro was estimated by methane carbon
isotope to be from 0.841.08% for Wells Patolon-1 and Patolon-2. Crude oil yielded from Wells Patolon-1 and Patolon-2 is coal oil, which was diagnosed to be mature to
post-mature in light of two isomerization parameters of C29
sterane, C2920S/(20S+20R) and C29/(+), and is
likely generated by mature source rocks[810]. In spite of
large cumulative thickness and abundant organic matter in
the Taben mudstone and coal measure strata, the maturity is
low, with Ro only of 0.530.66%. Therefore, hydrocarbon in
Block D may originate in the Chindwin and Salin source
sags or deep Langshing source rocks with relatively high
maturity.
2.2.
Pervasive overpressure in Eocene reservoirs
Reservoir rocks in Block D concentrate in the Eocene
Series which includes the Tilin, Taben and Pondaung Formations from bottom up, especially in the Taben Formation.
Gas reservoirs have mainly been found in the Taben sandstone.
The Eocene Series in Block D is rich in deltaic distributary channel, mouth bar and distal bar sands[1115] with many
layers and large thickness. In general, sand thickness decreases from east to west. Sandstone thickness may reach
6001200 m in the Pondaung Formation and reach 200600
m and 300400 m in the Tilin and Taben Formations, respectively. According to well drilling data, the Taben reservoir porosity ranges from 8.529.5% with an average of
16.1% and the average permeability is 1.0 mD; the PonTable 1
Vol. 21, No. 2, 2016
daung reservoir porosity ranges from 1721% with an average of 14.6% and the average permeability is 4.8 mD; the
Tilin reservoir porosity ranges from 810% with an average
of 8.5% and the average permeability is 0.1 mD. In general,
the Taben and Pondaung sandstones have moderate petrophysical properties of middle porosity and low permeability;
the Tilin sandstone has the poorest petrophysical properties
of low porosity and extremely low permeability due to its
large buried depth.
Regionally the upper Eocene Series exhibits pervasive
overpressure and the pressure coefficient becomes larger
from the Chindwin sag in the north to the Salin sag in the
south. In the Indaw oilfield in the Chindwin sag and the
Letpando oilfield in the Salin sag, the top of the Yaw Formation functions as the boundary of pressure jump and abnormal pressure occurs below the top. Overpressure in
Block D may exist in top and bottom walls of major faults
as well as in mudstone and sandstone. Oil and gas have been
sealed inside the overpressure compartment (which is composed of middle Taben reservoirs and overlying and underlying mudstones as the top and bottom caps) and the pressure coefficient was measured to be up to 1.68. In view of
low permeability in middle Taben reservoirs, over-pressured
gas reservoirs in Block D belong to the over-pressured reservoir with low permeability inside the overpressure system.
2.3. Good reservoir-cap-rock assemblages
The Tilin and Taben Formations are locally rich in mudstone. In Well Patolon-1, the Taben mudstone thickness accounts for 78.5% of total formation thickness on the average,
and the ratio is 63.0% for the Tilin Formation; the
maximum single-layer mudstone thickness is 48 m and 13.5
m, respectively, in the Tilin and Taben Formations (Table 1).
Interbedded sandstone and mudstone of deltaic front subfacies constitute good reservoir-cap-rock assemblages in the
Tilin and Taben Formations.
Statistics of mudstone cap rock in Well Patolon-1
Formation
Pondaung Fm.
Taben Fm.
Tilin Fm.
Max. single mudstone
thickness/m
16.0
Ratio of cum. mudstone thickness to formation thickness/%
172.5
Cum. mudstone
thickness/m
51.0
241.5
79.0
22.0
32.2
Interval/m
Formation thickness/m
384.0~556.5
556.5~798.0
798.0~956.0
158.0
54.0
18.0
956.0~1242.5
286.5
212.5
46.5
1242.5~1488.5
246.0
150.2
28.0
1488.5~1828.0
339.5
300.8
48.0
1828.0~2056.0
228.0
204.5
20.8
2056.0~2274.0
218.0
172.3
11.0
3403.0~3600.0
197.0
87.6
13.5
3600.0~3734.5
134.5
55.0
9.5
3734.5~3798.0
63.5
38.3
10.9
78.5
63.0
Shi Lei et al., Main factors controlling accumulation of over-pressured gas reservoirs in Block D, Myanmar
The Pondaung Formation is mainly composed of thick
sandstone and mudstone thickness accounts for only 32.2%
of total formation thickness on the average (Table 1). Due to
the impacts of tectonic movement, the reservoir-cap-rock
assemblage in the Pondaung Formation is relatively poor
because the top of the formation has been corroded.
2.4.
Structural traps finalized at the late stage
Most traps discovered in Block D are faulted anticlinal
and anticlinal traps. For example, what have been found by
well drilling in the Patolon structure are anticlinal traps at
the bottom wall; the discoveries by well drilling of Yagyi-1
in the Mahudaung structure are faulted nosing traps at the
top wall.
The Ayeyarwady Basin came into being much earlier
than the traps. Over time, the basin has experienced
multi-phase tectonic-sedimentary reworking. Two tectonic
activities have had the largest impacts on hydrocarbon accumulation in Block D. One is the flexuring process at the
end of the Eocene Epoch which gave rise to a series of incipient structural traps, and the other is massive orogeny at
the end of the Pliocene Epoch, when many thrust-nappe
structures were shaped and finalized in the basin.
3. Main factors controlling hydrocarbon accumulation
Over-pressured gas reservoirs in Block D are
low-permeability reservoirs inside the overpressure system.
In most typical over-pressured reservoirs (worldwide), oil
and gas generally concentrate inside the normal-pressure
zone at the top of the over-pressured zone while only a few
reservoirs reside below the barrier or inside the
over-pressured zone (Table 2). Hydrocarbon enrichment inside the over-pressured zone needs some tough conditions,
such as the existence of thick mudstone or evaporite overburden, no massive tectonic movement afterward to destroy
the capping bed, and the likelihood of hydrocarbon accumulation in the reservoir with high porosity and permeability inside the overpressure system[1630].
3.1.
Reservoir properties
Hydrocarbon accumulation inside the overpressure compartment is dominated by reservoir properties; in other
words, hydrocarbon tends to gather in local reservoirs with
relatively high porosity and permeability. For example, in a
large Kela 2 over-pressured gas reservoir, natural gas
mainly concentrates in the over-pressured Cretaceous
Bashijiqike Formation (with the average pressure coefficient
of 1.952.20, porosity of 1520% and permeability of
5
200800 mD). The Bashijiqike Formation, with good reservoir properties inside the over-pressured zone, has abundant intergranular pores enlarged by chemical erosion; inter-pore connectivity is also good[1820]. The Mars oilfield in
the Gulf of Mexico is another typical field with overpressure. Commercial discoveries mainly concentrate inside the
over-pressured zone, where turbidite sandstones with high
porosity and permeability are saturated with oil and reservoir thickness is more than 100 m on the average[21].
In the Salin sag in the Ayeyarwady Basin, major payzones that have been discovered in large oilfields are Oligocene and Miocene sandstones with high porosity and
middle to high permeability. For example, major payzones
in the Letpando field are in the lower Oligocene Shwezetaw
Formation with an average porosity of 19% and average
permeability of 122 mD. The Yenangyaung field has 3 major payzones in the Oligocene and Miocene Series with the
average porosity of 30% and permeability of 318 mD. From
the Oligocene Epoch to the middle Miocene Epoch, when
the basin was an extrusion depression, large-scale marine
regression occurred from north to south and some local areas, including Block D, were uplifted and exposed to denudation at the earth's surface; consequently, the middle and
lower Oligocene Series were lost. The Salin sag in the south
was still in littoral and neritic environments due to its low
relief and there is no stratigraphic hiatus. Therefore, good
Oligocene reservoirs in the Salin sag are absent in Block D
where petroleum discoveries mainly concentrate in the Taben sandstone of middle porosity and low permeability.
Overpressure is pervasive in the Eocene reservoirs in
Block D. Porosity variation with depth for Well Patolon-1
shows good correlation between the existence of secondary
pores and an over-pressured zone (Fig.3). Overpressure has
two effects on deep reservoir properties. One is the preservation of primary pores because high-pressure fluids would
support some overlying load and the compaction of the
over-pressured strata would then be mitigated; the other is
the occurrence of mass secondary pores generated by acidic
pore water dissolution in high temperature and pressure
provided that pH value of pore water is decreased by acidic
components generated by thermal evolution of organic matter. In addition, the exchange and flow of dissolved matter
in the reservoir may also be strengthened by periodic discharge of over-pressured fluids, which would result in a
leaching effect and thus give birth to mass secondary
pores[1617]. For example, natural fractures, 5.8 m away from
the top of the coring interval 2137.252140.65 m in the Taben Formation in Well Thingadon-1, are completely filled
by calcite; the maximum horizontal fracture is 1.5 cm wide
(Fig.4). Reservoir properties in Block D are not promising
6
CHINA PETROLEUM EXPLORATION
Table 2
Vol. 21, No. 2, 2016
Distribution of typical overpressure oil & gas fields in China and abroad
Field
Tectonic
setting
Overpressure genesis
Oil & gas distribution
Proved reserves
Description
Penglai 19-3 oilfield in
Central Bohai Bay depression
Extensional
basin
Unbalanced compaction and
hydrocarbon generation
Shallow normal-pressure zone
at the top of the overpressured barrier
3.24108t
Over-pressured deep source rocks, hydrocarbon migration through faults and
accumulation in the shallow zone
Dongfang 1-1 and Dong- Transitionfang 22-1 gas fields in extensional
the Yinggehai Basin
basin
Unbalanced compaction
Shallow normal-pressure zone at
the top of the over-pressured
barrier or the flank of the
over-pressured zone
1427.84108m3
Hydrocarbon accumulation in the shallow normal-pressure zone at the top of
the over-pressured barrier or in the flank
of the over-pressured zone
Over-pressured field in
Extensional
Southwest Weizhou sag,
basin
the Beibuwan Basin
Unbalanced compaction
Over-pressured source rocks in the Eocene Liu 2 Member, hydrocarbon accuAt the top of the over-pressured
Oil: 87.4108t
8 3
barrier
Gas: 184.410 m mulation at the top of the over-pressured
barrier
Mobei field in the central
Junggar Basin
Foreland
basin
Over-pressured field in
Extensional
Xihu sag, the East China
basin
Sea Basin
Hydrocarbon generation
Close to the top of the
over-pressured barrier
Hydrocarbon generation
Transition zone from overpressure to normal pressure
Over-pressured fields in
Lijin, Niuzhuang and
Minfeng sub-sags in
Extensional
Dongying sag and Zhanbasin
hua sag, the Bohai Bay
Basin
Hydrocarbon generation
Mars oilfield, the Gulf of Extensional
Mexico
basin
Hydrocarbon generation
75% of oil layers distributing in an interval of 6-300 m over the
Oil: 2408104t
over-pressured barrier, hydrocarbon acGas: 76.98108m3
cumulation close to the top of the
over-pressured barrier
8
3
206.8710 m
Hydrocarbon migration from
over-pressured source rocks to normal-pressure reservoirs at the west
slope; the major direction of hydrocarbon migration in Xihu sag
Pervasive overpressure in source rocks,
various reservoirs at the top of the
At the top of the barrier or inside Oil: 22.88108t
over-pressured barrier, only lithologic
the over-pressured zone
Gas: 142.73108m3 reservoirs (mainly sandstone lens) occurring inside the barrier
Inside the over-pressured zone
8
1.1110 t
Over-pressured Pleistocene turbidite
sandstone with high porosity and permeability, oil-saturated reservoirs, oil
reservoir thickness over 100 m
Extremely high reservoir pressure, hydrocarbon accumulation inside the
over-pressured zone with overlying thick
gypsum capping bed
A deep-basin field, over-pressured Cretaceous reservoirs, gas-saturated reservoirs, no distinct gas-water contact
High-pressure fluids generated by deep
over-pressured source rocks are blocked
under the barrier. Gas chimneys occur in
some fields due to gas release through
the overburden fractured by
over-pressured fluids.
Kela 2 gas field in Kuqa
depression, the Tarim
Basin
Foreland
basin
Jonah gas field in the
Green River Basin
Craton
basin
Gas generation
Inside the over-pressured zone
12700108m3
Ekofisk condensate
field in the
North Sea Basin
Extensional
basin
Unbalanced compaction and
hydrocarbon generation
Under the barrier
1450108m3
Ya 13-1 gas field in the
Qiongdongnan Basin
Extensional
basin
Unbalanced compaction
and gas generation
Under the barrier
978.51108m3
Structural-stratigraphic gas reservoirs
with normal pressure, overlying
over-pressured capping bed of the Meishan Formation
Hutubi gas field at the
south margin of the Junggar Basin
Foreland
basin
Unbalanced compaction
and tectonic stress
Under the barrier
347108m3
Over-pressured capping bed, hydrocarbon accumulation under the barrier
Tectonic compression and gas
Inside the over-pressured zone
generation
in general; the focus should be on favorable sedimentary facies such as deltaic front and vertical intervals rich in secondary pores and natural fractures in the overpressure system.
3.2.
Hydrocarbon preservation
Hydrocarbon generation and expulsion in Block D
mainly occurred at the end of the Pliocene Epoch when
many reverse thrusts were generated by intense tectonic activities due to the impacts of the orogeny. These faults, with
large vertical throw and extension, even to the earths sur-
2840.29108m3
face, may destroy preexisting reservoirs. Some regions have
active surface gas shows exhibited as gas release in the lake.
The Yaw Formation overlying the Pondaung Formation
functions as a regional seal in the Salin sag, but in Block D
it is seriously corroded as a consequence of tectonic uplifting. During early exploration, 3 exploratory wells (Chinbyit-1, Padaukkone-1 and Padaukkone-2) were drilled at the
structural high in the top wall by MOGE targeting the Taben
and Tilin Formations. None of the wells had petroleum discoveries due to poor preservation resulting from anticlinal
top corrosion (Fig.5).
Shi Lei et al., Main factors controlling accumulation of over-pressured gas reservoirs in Block D, Myanmar
Fig. 3
Fig. 4
Porosity vs. pressure for Well Patolon-1
Photo of Taben Formation cores in Well Thingadon-1
The capping bed on the overpressure system should be
tough enough for hydrocarbon accumulation, otherwise it
Fig. 5
7
would be broken by overpressure. Local mudstone intervals
in the Tilin and Taben Formations may function as the capping bed with good sealing performance because the pressure coefficient (of 1.8) for over-pressured mudstone is
generally larger than that (of 1.6) for sandstone according to
well drilling data. At the bottom wall, with an over-pressured zone, the Tilin and Taben mudstones would be lithologic barriers and pressure barriers for hydrocarbon accumulation. In addition, relatively weak tectonic activities at
the bottom wall would also facilitate hydrocarbon preservation. Thus, the bottom wall should be a zone of interest in
hydrocarbon exploration, and in this way gas reservoirs were
found at the bottom wall of the Patolon structure (Fig.6).
E-W section crossing Wells Padaukkone-1 and Padaukkone-2
8
CHINA PETROLEUM EXPLORATION
Fig. 6
3.3.
Vol. 21, No. 2, 2016
Section of gas reservoir in the Patolon structure
Migration pathways and directions
Mudstone and coal seams of the Taben Formation have
been proved as source rocks in this prospect. The Taben
source rocks drilled in Block D are generally of low maturity, whereas oil and gas maturities more recently discovered
are normally higher than 1.0%, meaning that hydrocarbon in
Block D originated from the Salin sag in the south and the
Chindwin sag in the north. In the Eocene Epoch, Block D,
the Salin sag and the Chindwin sag were a unitary sedimentary system with the depocenter in Salin. Block D and the
Chindwin sag were elevated in the Oligocene Epoch and a
palaeohigh grew up between the north and south sags in the
middle and late Miocene Epoch. The palaeohigh was mostly
preserved despite some alteration by the structural belt in
north-south direction in the Pliocene Epoch, and was the
destination of hydrocarbon migration. Laterally, hydrocarbon may travel through and reside in permeable sandstone.
The Eocene Series in Block D contains abundant deltaic
sands with large thickness and lateral extension, which may
be the pathway for long-distance migration. In addition, oil
and gas from the deep Langshing Formation, a potential
source bed under the Taben Formation, may also move upward through the faults, cutting into the Langshing Formation and then accumulate in faulted anticlinal and faulted
nosing traps in the Taben Formation.
3.4. Relationship between hydrocarbon migration and
final shaping of traps
Due to extrusion stress in the east-west direction since
the Eocene Epoch, major faults in Block D (extending in a
near north-south direction with a fault throw of 5001000 m)
have cut off the Eocene and Pliocene Series. These faults
connect two source beds, the Taben and Langshing Formations, and may act as the pathway for upward hydrocarbon
migration.
From the end of the Eocene Epoch to the Oligocene Epoch, some detachment faults occurred in the Taben Formation and there was no large-scale thrusting and napping.
These faults became active and major faults cropped out at
the earths surface from the end of the Pliocene Epoch to the
Quaternary Period, when massive oil and gas moved upward along these faults into the traps finalized in the same
period. According to the history of regional hydrocarbon
generation, the Taben source rocks became mature in the
middle and late Miocene Epoch and generated and expelled
massive hydrocarbon at the end of the Pliocene Epoch.
Therefore, massive hydrocarbon migration and final shaping
of traps occurred basically in the same period, which is favorable for hydrocarbon enrichment.
4.
Conclusions
(1) There may be two sets of source rocks in Block D in
Myanmar, among which the thick Taben source rocks with
type-III and some type-II2 kerogens have been proved to
have a high abundance of organic matter. In view of their
shallow burial and low maturity, oil and gas production in
this area may originate in neighboring source sags. The
Langshing argillutite may be another potential source, according to very limited information from regional deposition and outcrops.
(2) The Eocene Series in Block D contains multi-cycle
deltaic sands with large thickness, middle porosity and low
permeability. Overpressure is pervasive in the Eocene Series.
(3) Hydrocarbon accumulation occurred at a late stage in
Shi Lei et al., Main factors controlling accumulation of over-pressured gas reservoirs in Block D, Myanmar
Block D. The Taben source rocks became mature in the
middle and late Miocene Epoch and generated and expelled
massive hydrocarbon at the end of the Pliocene Epoch. The
traps in an incipient form came into being at the end of the
Eocene Epoch and were finally shaped from the end of the
Pliocene Epoch to the Quaternary Period. Massive hydrocarbon migration and final shaping of traps basically occurred in the same period, which is favorable for hydrocarbon enrichment.
(4) For most over-pressured reservoirs worldwide, oil
and gas generally concentrate inside the normal-pressure
zone at the top of the over-pressured zone; only a few reservoirs occur inside the over-pressured zone. Hydrocarbon
enrichment in the over-pressured zone requires some tough
conditions. Natural gas accumulation in over-pressured
zones in Block D in Myanmar is dependent on reservoir
properties and preservation conditions as well as migration
pathways and the relationship between hydrocarbon migration and final shaping of traps.
9
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