BUILDING GEOLOGICAL MODEL FOR FRACTURED
BASEMENT RESERVOIR BY NPV AND HALO METHOD IN
FIELD X, BLOCK Y, CUU LONG BASIN
Summary
The oil reservoir in the Fractured Basement Reservoirs of the Cuu Long basin
has great oil and gas potential but has a rather complex geological structure, is an area
consisting of many intrusive magmatic rock systems divided by many fault systems.
These fractured reservoirs contain porosity and permeability systems that are
dependent on tectonic systems and are thus segregated into structural Block. Two
types of modelling approaches are the Net Pore Volume Model (NPV) and the Halo
Fault Model. The Net Pore Volume Model is used to generate OIIP volumes in a
structural Block based model using porosity and net/gross to describe the rock
volume in a probabilistic method. The Halo Fault Model is used to characterize the
reservoir with a fracture enhanced halo around lineaments described by seismic in
the reservoir. Both models are matched against well test and historical data and or
dynamic data to ensure quality and matched against conventional volumetric
approach.
Key word:
1. INTRODUCTION
The 3D geological model is to build the distribution of reservoir parameter for calculating the OIIP
and for further simulation study. From common understanding, porosity and permeability of
basement reservoir is strongly dependent on the density of fractures, distribution, fracture
apertures, factors of tectonic systems, hydrothermal processes and weathering. So in order to
logically model the basement reservoir, it is important to divide the basement reservoir into several
structural Blocks.
Structural Blocks are defined in the basement as zones containing similar
structural. The boundaries of structural Blocks are typically large tectonic features
that have structural relief and evidence of multiple phases of fault movement. Each
Block typically contains multiple sets of faults/fractures, trends and depth to top
Basement. Segment is defined in the structural Block based on intensity of
faults/fractures, fault types and their dominant trends. Segment’s boundaries are
arbitrary. In the case of the X field, Blocks are bounded by a set of NW-SE faults
dipping to SW. Each Block-bounding fault is a potential site for cataclastic gouge
formation. It can provide a potential barrier in the reservoir. Sealing capacity along
a fault may vary with depth or along strike. Four Segments are defined in the X field,
Block A. They have arbitrary boundaries and not actual fault/fracture set
boundaries. X field was divided into 5 structural Blocks C, B, A, D and E (Figure
1.1). The Block A was subdivided into 4 segments. Segments were defined from
seismic fracture characteristics (intensity, type, and trend). They are Segments A:
Green, Red, Yellow and Blue (Figure 1.2).
Blo
Blo
Blo
Blo
Blo
Figure 3.1: Basement Structural Blocks of X field
Figure 3.2: Segments in the Structural Block A of X field
Fractured Basement Reservoirs provide a unique challenge with respect to
reservoir modelling. These fractured reservoirs contain porosity and permeability
systems that are dependent on tectonic activities and are thus segregated into
structural Block. Hence, two types of modelling approaches are used to describe
the reservoir. These are the Net Pore Volume Model (NPV) and the Halo Fault
Model. The Net Pore Volume Model is used to generate OIIP volumes in a structural
Block based model using porosity and net/gross to describe the rock volume in a
probabilistic method. The Halo Fault Model is used to characterize the reservoir
with a fracture enhanced halo around lineaments described by seismic in the
reservoir. A fractured halo fault is applied to the lineaments and porosity and
permeability volume is produced. This is used to simulate fluid flow modelling. Both
models are matched against well test and historical data and or dynamic data to
ensure quality and matched against conventional volumetric approach to ensure the
total net volume. This thesis will deal with two types of these models.
2. The study area
Geographical location of Field X (Block 9-2), Cuu Long basin
Cuu Long basin is located mainly on the southern continental shelf of Vietnam,
part of the Mekong estuary area, with coordinates 90 - 110 north latitude, 106030' 1090 east longitude, 400 km long in the direction Northeast - Southwest, from the coast
of Phan Thiet to the mouth of the Hau River. The distribution area of the basin is about
36,000 km2, including blocks 09, 15, 16, 17 and a part of lots 01, 02, 25 and 31. [14]
Figure 1.1: Cuu Long basin [4]
Morphologically, the Cuu Long basin has an oval shape, curves towards the sea
and lies along the coast of Vung Tau - Binh Thuan. The Cuu Long basin is adjacent to
the mainland to the northwest, separated from the Nam Con Son basin by the Con Son
uplift, the southwest is separated from the Malay - Tho Chu basin by the Khorat Natuna uplift and the northeast is the Khorat - Natuna uplift zone Tuy Hoa slip cut is
separated from Phu Khanh basin (Figure 2.2). This is a basin with closed sediments
typical of Vietnam Bon, which is filled mainly by Oligocene - Miocene terrigenous
sediments and Pliocene - Quaternary shelf mantle. Their greatest thickness at the center
of the basin can reach 7-8km. [14]
Figure 1.2: Cuu Long Basin and Tertiary Sedimentary Basins off the coast of Vietnam
[4]
The X structure is located in Block 9-2 (Figure 2.6) in the Cuu Long Basin,
southeast of Vung Tau City, offshore Vietnam. The block covers an area of 1,370km².
Figure 1.3: X field is located in Block 9-2 [11]
Oil and gas extracted from X field is transported by a 25km-long undersea
pipeline system to oil and gas processing equipment at Bach Ho field. Crude oil is
processed and stored in a floating storage, then sold to tankers for transport to refineries.
The energy-rich gas from this field is processed offshore by AJOC and then transported
to onshore gas stations for distribution for domestic demand for natural gas, liquefied
petroleum gas and condensate. According to AJOC, the development of X field
connected to Bach Ho field Lot 9-1 is the first project in Vietnam using existing
facilities of Bach Ho field to minimize investment costs, creating a new way of
developing offshore oil and gas fields in Vietnam. [14]
Currently, A JOC has drilled 4 development wells at X field, and is conducting
assessment and locating wells for additional development wells at the cracked
foundation containing products. It is expected to exploit this mine within 20 years.
Structural - tectonic features
 Structural features
The Cuu Long basin is morphologically oval shaped extending from the
Northeast to the Southwest, the eastern limit is the East Sea of Vietnam, the West is
the Mekong Delta, the North is the uplifted zones of the Da Lat mass if, Kon Tum. In
the Cuu Long basin, the seismic strata that have been linked and mapped by
contractors are summarized as follows: Foundation, F, E, D, C, Bach Ho clay, BI.1, BI.2,
BII, A. The main structural elements in the Cuu Long Basin are clearly shown on the
maps from the base of the foundation to the top of the E.
Cuu Long basin is divided into 02 structural:
-
Lower structural:
This architectural layer is created by the eruption and intrusive formations of Triassic
- Kreta age, including granite, biotite, granodiorite, diorite and many places appear
rhyolite in the Hon Khoai, Dinh Quan and Ca Na complexes.
-
Upper structural:
This architectural layer is the Cenozoic sedimentary cover, made up mainly of Eocene
- Quaternary terrigenous formations. It is divided into 03 structural sub-layers with the
boundaries of non-conforming surfaces:
o Lower structure subsequence:
Including Ca Coi Formation and Tra Cu Formation (Eocene - Lower Oligocene). Most of
the coarse-grained sediments are located at the bottom, interspersed with finegrained particles above containing many VLHCs of continental origin, distributed in
narrow trenches running along the center of the basin (East and West of Bach Ho
structure), thick from 800 ÷ 2,200 m, formed when the collision between the Indian
microplate and the Eurasian plate in the middle Eocene period caused continental
crust cracking. The layers are distributed diagonally and irregularly overlapping the
ancient rocks.
o Middle structure subsequence:
Including Tra Tan Formation and Bach Ho Formation (Upper Oligocene - Lower
Miocene) with a wide distribution, covering up to the central trench, thickness from
900 ÷ 3600 m. The rather large thickness accumulated during this time is probably
related to the spreading activity of the East Sea floor (17 ÷ 32 million years), so this is
temporarily called the period of rift co-generation. The mostly fine-grained sediments
contain many VLHCs, which are quite good local barrier layers. The sedimentary
environment is mainly freshwater lakes, deltas, brackish coastal waters and shallow
seas. The uncomforting overlays on the ancient formations are less oblique, but tend
to increase in thickness at the center, and angular disconformity is evident at the edge,
especially at the northeast edge.
o Upper structure subsequence:
Consisting of 03 formations Con Son, Dong Nai and East Sea (middle Miocene Quaternary) uncomfortably covered the middle and lower architectural sub-layers.
The area is expanded quite a lot, related to the continental shelf development and the
recent spreading period is clearly shown on the maps from the base of the foundation
to the top of the E.
 Fault system:
The fault system in the Cuu Long basin is divided into 4 main groups according
to the respective directions: Northeast - Southwest, East - West, North - South and
small faults in different directions of the East Sea (Pliocene - Quaternary). The
sediments are mainly shallow sea interspersed along the shore, with a general
thickness of 1,800 ÷ 2,200 m with horizontal sediments, covering ancient sediments.
In the early Tertiary, the collision between the Indo-Australian and Eurasian plates
caused the formation and development of sedimentary basins in Southeast Asia,
including the Cuu Long basin. Most of the important faults in this basin are forward
faults inherited from the foundation, co-sedimentation development and all
disappeared in the late Oligocene.
Two fault systems with the Northeast - Southwest and East - West directions
play a key role in controlling the geological development history and the main
architectural elements of the basin. In which, the fault system with the Northeast Southwest direction is associated with the rifting stage and is the main factor
controlling the Dragon - Bach Ho central uplift zone. The East-West fault system is
younger than the previous fault system, and in many places, the East-West horizontal
shift is clearly visible. Especially at the intersection of fault systems, local compression
often occurs, leading to the appearance of reverse sloping faults.
Each fault system has different formation time, activity intensity, and
displacement amplitude. However, most of them were inactive at the end of the Early
Oligocene, with only a few faults remaining active until the Early Miocene such as in
the central and northeastern parts of the basin.
Figure 1.4: Map of foundation roof structure in Cuu Long Basin [4]
 Tectonic features
The division of structural units is based on the geological structure
characteristics of each area, corresponding to the difference in sediment thickness.
These structural units are usually bounded by faults or fault systems of considerable
amplitude.
If the Cuu Long basin is considered as a structural unit of level I, then the structural
units of level II are:
-
Main of Cuu Long basin: occupies more than 3/4 of the area. This is the
main subsidence part of the basin - where most of the oil and gas prospects are
concentrated. They include: Northeast ridge, West Bach Ho basin, East Bach Ho
basin, Northwest inclined slope, Southeast inclined slope, Central uplift zone,
Northeast divergent zone and Southwest divergent zone. The boundaries of the
structural units are shown in Figure 2.5.
Figure 1.5: Structural elements of the Cuu Long basin [5]
-
Bac Lieu differential basin: located at the southwest end of the Cuu Long
basin with an area of 3,600 km2.
-
Ca Coi differential basin: located mainly at the mouth of Hau river, has a
small area with a small thickness of sediment, about 2,000 m2.
-
Cuu Long uplift: located to the east of the Bac Lieu and Ca Coi differential
basin, separating these two basins from the main basin of the Cuu Long basin.
-
Phu Quy uplift: is an extension of Con Son uplift, located to the northeast
of blocks 01&02.
The local positive structures of grade IV are the main objects of oil and gas prospecting
and exploration of the basin.
Features of petrographic stratigraphy
The stratigraphy of the Cuu Long basin consists of pre-Cenozoic foundation
rocks and Cenozoic mantle sediments. The petrographic - sedimentary and
petrographic features of each stratigraphic unit are shown in the combined
stratigraphic column of the basin (Figure 5). To facilitate the work, search, exploration
and extraction of oil and gas, stratigraphic units are compared with seismic sets. The
seismic reflectors all coincide with the boundaries of the stratigraphic units. [15]
Dầu
Khí
Figure 1.6: General stratigraphic column of Cuu Long Basin [5]
 Pre - Cenozoic
The basement rock complex in the Cuu Long basin, which is pre-Cenozoic, has
heterogeneous composition, mainly intrusive magmatic rocks, including granite,
granodiorite, quartz granodiorite, monzonite, diorite, quartz diorite, tonalities with
magmatic and metamorphic rocks. The main mineral compositions include quartz,
potassium feldspar, plagioclase, biotite, muscovite, amphibole and hornblende.
Secondary minerals formed by hydrothermal activity are mainly zeolite, quartz, calcite,
sericite, chlorite, kaolinite. The surface layer of the basement rock is often strongly
weathered with a thickness of 4 m - 55 m. [15]
The lode rocks cut into the basement or fill the fractures, in some places cover
directly on the bedrock surface (block 16-1). The main composition is diabase, to a
lesser extent basalt in the Bach Ho and Rong fields, andesite and dacite in blocks 15-1,
15-2, with a thickness ranging from a few meters to several tens of meters.
The basement rock complex was discovered to accumulate oil and gas of
industrial value for the first time at Bach Ho field and was exploited in 1986, since then
the basement rock has become an important object of oil and gas prospection and
exploration in Vietnam. Cuu Long basin in particular, the continental shelf of South
Vietnam in general. [16]
In terms of lithology, they can be classified into two main groups: granite and
granodiorite - diorite. Based on the comparison of studies at many wells drilled deep
into the foundation with the results of research on intrusive magma complexes on land,
according to petrographic characteristics and absolute age, they are classified into 03
complexes: Hon Khoai, Dinh Quan and Ca Na. [16]
 Cenozoic sediments
Lying unconformably on the eroded, weathered crystalline basement rock
surface are Cenozoic or volcanic formations. Stratigraphy is described from bottom to
top, from ancient to young and is summarized in the stratigraphic column.

Ca Coi Formation (E2cc)
The sediments of this formation were formed in the continental environment:
deluvi, proluvi, alluvi with a thickness of 200 ÷ 400 m, described by Le Van Cu at well
CL-1X in the subsidence area of the Hau river. They include mainly: gravelstone,
multimineral sandstone, interspersed with thin layers of siltstone and hydromica chlorite - sericite clay. The lower part of the formation is cobblestone, gravel (main
components of gravel and gravel are andesite, rhyolite, mica slab and quacsite) while
the upper part is light-colored coarse-grained sand, gray-green claystone. [20] Fossils
of pollen spores were discovered including: Klukiosporites, Triporopollenites,
Trudopollis, Plicapollis ... belonging to the group of dry plants, common in the Eocene.

Tra Cu Formation (E31tc) – Seismic set F and seismic set EI
The Tra Cu Formation was established by Le Van Cu in 1981, 1982 at the Cuu
Long - 1X borehole, with a thickness of 250 m in Ca Coi area, Tra Cu district, Tra Vinh
province. The sediments of this formation include gravel beds interspersed with layers
of coarse-grained sand, powder and clay with colorful colors, thick layered structure,
bulk form and deposited in the environment of rivers, lakes, swamps or rivers. Delta.
The pebbles have andesite eruption rock composition, are well rounded but have poor
selectivity and grow widely in the northwest of the tank. Sandstone has poor roundness,
most of the purple particles with clay and calcite are cementitious materials. [21] The
top part also alternates layers of coal clay, coal lenses. Fossils of pollen spores include:
Trudopollis, Ephedra, Cycas, Ginggo... The paleontological analyzes of VDK for
today's wells all determine the early Oligocene age. These formations have a thickness
of 0 ÷ 1,500 m, covering the eroded surface of the foundation at a depth of 2,500 ÷
4,000 m. The upper boundary is improperly covered by the Tra Tan Formation and
extended to the edge.

Tra Tan Formation (E32tt) – Seismic set E, seismic set D and seismic set C
The Tra Tan Formation was established by Ngo Thuong San et al (1980) in well
15A–1X (drilled on Tra Tan structure/ structure 15A). The sediments of this formation
consist of thick black clay layers, alternating gray to ash-gray sand layers and black,
gray to light gray powder layers. The upper part also encounters coal lenses, coal debris,
even layers of coal clay 5 ÷ 7m thick, with pyrite, glauconitic. Sandstone has a fine to
medium grain, sometimes coarse grained with the main composition of quartz
(accounting for 25-35%), feldspar (from 25-40%) and rock fragments (from 10-25%)
is usually ackoz - grauvac sandstone, in some places, it is found in some places with
single-mineral quartz sandstone with silicon-cement composition. The siltstone,
claystone with thick layering in the form of blocks, with the addition of hydro mica
clay, chlorite and a little kaolinite. Pollen spore fossils include: F. Trilobite,
Verutricolporites, Ciccatricosiporites. Current VDK paleontological analyzes for new
wells all determine the Late Oligocene age for this formation. [21]
The Tra Tan Formation is directly covered on the foundation rock complex
around the large trench basin, or directly on the Tra Cu Formation in the center of the
trench valley, which is inappropriately covered by the Bach Ho Formation.
The Tra Tan Formation is divided into 3 different layers from bottom to top: the
lower Tra Tan layer, the middle Tra Tan layer and the upper Tra Tan layer.
-
Lower Tra Tan layer:
Associated with seismic set E consisting mainly of sandstone interlaced with claystone,
siltstone. Arkose, lithic arkose sandstone, fine-grained, medium - very coarse and
granular, planarity from semi-angular to semi-circular, fairly firmly bonded by
carbonate cement, clay, quartz. Dark brown - dark brown clay rich in organic matter.
The ratio of sandstone/claystone (sandstone accounts for 45 - 65%), increases gradually
from the center of the basin to the southwest in blocks 16 and 17. The sediments of the
strata can be inclined with large slope angles., which is accumulated in lakeside plains,
freshwater lakes and alluvi plains. The lower Tra Tan layer is an important oil reservoir.
-
Middle Tra Tan layer:
Associated with seismic set D consisting mainly of claystone, sandstone intercalated
siltstone and coal thin layers. Dark brown-black-brown thick claystone rich in organic
matter. The sediments of the strata can lie slightly inclined - highly variable, deposited
in the lake environment, deep lakes to bays, coastal plains, relatively wide distribution
area almost throughout the basin. The middle Tra Tan layer plays the role of the main
oil/gas generation layer, as well as the regional barrier layer of the Cuu Long basin.
-
Upper Tra Tan layer:
Associated with seismic set C consisting mainly of sandstone interlaced with claystone,
siltstone. Coarse-grained, gray-white sandstone, Dark-brown-black claystone rich in
organic matter rich in humid and saprobe, deposited in brackish lagoons, freshwater
pools and alluvial plains, poor Bosedinia spp, predominates in well sections. The upper
Tra Tan sediments are distributed throughout the basin, may be inclined - little change.
In many wells in blocks 01/97 and block 02/97, there are magmatic rocks, alternating
basalt layers, widely distributed. The upper Tra Tan sediments are important oil and gas
aquifers. [23]
Tra Tan Formation sediments are mainly accumulated in the environment of the
alluvial - coastal plain (lake) in the lower Tra Tan layer, gradually moving to deep lakes,
brackish lakes/pools - coastal plains in the stratosphere. Tra Tan in the middle and river
- coastal plain, lake in the upper Tra Tan layer. The sediments thicken towards the center
of the Cuu Long basin. Magma rock found in many drilled wells in the area of block
01/97 with the main composition is andesite, andesite - basalt. [23]
These sedimentary formations are of Oligocene age, widely distributed
throughout the Cuu Long basin, mainly thick in the central sinkholes and gradually
thinning towards the edge with a thickness of about 1,300 m, the upper boundary is a
regional mismatch. corresponding to the roof of the seismic set C. The area is wider
than the ancient strata. According to petroleum geologists, the claystone of this
formation has a very high to very high content and quality of VLHC, especially the
middle Tra Tan layer. They are good petroleum-producing strata as well as a good
barrier for fractured foundation rock in the Cuu Long Basin. Although the interlocking
sandstone layer has a permeability, porosity quality and a continuum that varies from
poor to good, it is also the object of the basin's remarkable oil and gas search. [23]

Bach Ho Formation (N11bh) – BI seismic set
The Bach Ho Formation was established by Ngo Thuong San and Ho Dac Hoai
in 1981 and named after the Bach Ho-1 (BH-1) well drilled by Mobil Company in 1974.
The sediments of the Bach Ho formation with a thickness of 100 ÷ 1,500 m are
widely distributed throughout the Cuu Long basin, corresponding to the BI seismic set,
encountered mostly in drilled wells from a depth of about 1,800 ÷ 2,000 m to about
2,800 ÷ 3,000 m. This formation includes all unconformable cover sediments above the
Tra Tan Formation and below the Con Son Formation. The lower boundary is
determined to be unconformable at the roof of the Tra Tan Formation – the roof of the
set C. The upper boundary is the roof of the "Rotalia clay layer" - the roof of the BI set.
Rotalia clay layer has a thickness of 30 m - more than 300 m (mainly in the range of 10
m - 150 m). Geologists of Deminex (1980) have called this clay layer Rotalia band. The
formation has a sediment thickness varying from 100 m to 1500 m (quite stable from
400 m to 800 m).
The characteristic fossils discovered: Rotalia, Ammonia... show that the
sedimentary environment is a coastal plain - shallow sea, in the upper part there is much
clay and much sand in the lower part. Current VDK paleontological analyzes for new
wells all date to the Early Miocene age.
The Bach Ho Formation is divided into 2 floors, including the lower Bach Ho
layer and the upper Bach Ho layer.
-
Lower Bach Ho layer:
The sediments are mainly sandstone, siltstone (accounting for over 60%), interspersed
with claystone layers. Sandstone white, opaque pink, slightly gray, fine-to-medium
grain, medium to coarse, very coarse, half-edge to semi-circular wear, moderate to good
selectivity, poor cohesion. Claystone dark gray, dark brown, reddish brown, yellow,
red. The cementation is kaolinite clay with little calcite cement, hydro mica, sericite and
carbonate. Gray to brown, light green to grey, siltstone containing carbonate clay,
porous to medium hard siltstone, rich in kaolinite, containing biotite and clay cement.
The sediments are accumulated in the marshy, riverside environment, they belong to
the middle part of the triangulation far from the estuary. Eruptive magmatic rocks are
found on the roof of the strata, common in the north of the basin, mainly in blocks 01/97,
02/97, a little in the Ruby structure, consisting mainly of basalt, andesite - basalt,
trachyte - basalt, andesite and tuff. [22]
-
Upper Bach Ho layer:
The sediments consist mainly of gray clay, greenish gray alternating sandstone and
siltstone. In the lower part, there is much sand, in the upper part there is much clay, at
the top is a claystone layer containing Rotalia "Rolatia clay layer" covering the whole
tank with a thickness of 30 m - more than 300 m (mainly in the range of 10 m - 150 m).
formed in the coastal plain environment - shallow sea. This is a very good regional
barrier layer for the central and northern part of the Cuu Long basin, gradually reducing
the ability to block to the southwest when the clay layer has changed into continental
mixed clay and powder. Red-brown claystone mixed with gray-green, white-gray,
yellow-gray, gray-pink, lilac, green speckled, thinly layered with little lime, some coals
in some places. Limestone-free, brittle, fragile, weakly bound siltstone and sandstone,
amorphous, clumps, sometimes hard, and schist containing mica flakes formed in
shallow marine environments, brackish puddles - coastal plains in canals and rivers in
the delta of the triangle. [22]
The sediments of the Bach Ho Formation deposited in the river, marsh, and
coastal plain environments in the lower part are transformed into shallow coastal
sediments in the upper part.
The Bach Ho Formation has sand layers interspersed with claystone layers, with
good permeability, porosity, and cohesion, which is considered an important petroleum
prospecting object in the Cuu Long basin. Oil is currently being extracted from these
sand layers, especially in the Bach Ho, Ruby, Rang Dong and Su Tu Den fields.

Con Son Formation (N12cs) – Seismic set BII
The Con Son Formation was established by Ngo Thuong San in 1980, Do Bat
(1993) determined including the Rolalia clay layer) identified the Con Son Formation
in the well 15B-1X.
The Con Son Formation is associated with the BII seismic set, which includes
all the sediments that do not conform to weak angles on the sediments of the Bach Ho
Formation. Sudden change of sedimentary material from Rotalia clay to solid block
sandstone, cement rich in lime, calcite, anhydrite and interspersed with thin layers of
claystone. The lower boundary is clearly shown on paleontological analyzes through
the sudden change of the sedimentary environment as well as the richness of
paleontological complexes when crossing the boundary. The lower boundary is defined
as the roof of the Bach Ho Formation (roof of the Rotalia clay layer) - the roof of the
BI set. [21] The upper boundary is defined as the thick sandy bottom of the Dong Nai
Formation sediments - the roof of the horizontal BII set.
Con Son Formation sediments mainly consist of thick layers of ackoz - lithic
sandstone with clay-cement, carbonate, rich in dolomite, anhydrite and calcite in the
lower part of the formation. fine to coarse grain, semi-sharp to round edge abrasion,
poor to moderate selectivity, poor to hard cohesion - very hard, bulk, alternating layers
of siltstone, layered clayey, Clay limestone accounts for nearly 5% and sometimes
meets thin coal layers, rich in glauconitic. Lots of rock shards, coal material, little pyrite.
Formation porosity ranges from 15 ÷ 20% with weak cohesion and permeability. [19]
However, there are no regional barriers here, so this formation and younger formations
do not have oil and gas prospects. Pollen spores belong to the complex Florschuetzia,
Acrostichum, Rhizosphere, abundant Foraminifera. Current VDK paleontological
analyzes for new wells all determine the Middle Miocene age for this formation. The
sedimentary environment is alluvial in the west, to the east is swamp - coastal plain.
The thickness varies between 250 ÷ 900 m.

Dong Nai Formation (N13đn) – Seismic set BIII
The Dong Nai Formation was established by Ngo Thuong San in 1980 at the 15G-1X well. The Dong Nai Formation includes all of the weakly unconformable cover
sediments on the Con Son Formation and below the East Sea Formation. The lower
boundary is adjacent to the Con Son Formation - the roof of the BII set, which is
determined by the thick sand layer at the bottom of the Dong Nai Formation with lower
gamma. The upper boundary is adjacent to the East Sea formation - the roof of the BIII
set, which is located at the bottom of the sand layer with thick layering, block form and
low gamma value. [19]
The formation has a thickness ranging from 500 to 750 m with the main
composition of sandstone interspersed with thin layers of claystone, limestone, dolomite
and thin layers of coal, containing many marine petrification. The lower part consists
of sand layers interspersed with thin clay layers, in some places there are small-sized
pebbles. The upper part is quartz sand of large size with poor selection, sharp grain. In
general, the level of cohesion is weak, sometimes even disjointed. Gray, light gray,
brownish grey, medium to coarse grained sandstone with occasional pebbles, composed
mainly of quartz, a few fragments of metamorphic rock, tuff and mounted pyrite crystals
with carbonate-clay, with thick layer or block structure, medium-poor selectivity and
round grinding. The brown montmorillonite clay layers are sticky, up to 20 m thick.
[19] In clay, sometimes brown coal or light gray powder is also encountered.
The weakly cohesive sediments of the Dong Nai Formation are formed in the
marsh environment - coastal plain in the western part of the basin and shallow sea riverbed in the eastern part, with typical petrification such as Dacrydium, Operculum.
The formation sediments are almost horizontal, inclined gently and without
displacement, without petroleum potential.

Bien Dong Formation (N2 – Qbđ) – Seismic set A
The Bien Dong Formation was established in 1982 by Le Van Cu and Ho Dac
Hoai. The sediments of the East Sea formations cover the Miocene sediments
inappropriately, widely distributed throughout the continental shelf of Vietnam, lying
almost horizontally, gently inclined, not displaced, with a thickness varying from 400
÷ 700 m, the degree of elevation. increasing thickness towards the East Sea. The main
composition of the formation is fine sand - powder - clay, the upper part of the sand
becomes coarser and the sand is mixed with powder, pink sand. [19] The top part is
Quaternary formations consisting of loose sand interspersed with light gray clay
containing a large amount of Foraminifera: ackoz sand, blue and white quartz sand with
medium roundness, poor selection, and containing many minerals glauconitic. The
mineral composition includes quartz, oligoclaz, octoclaz, mica with bright colored
carbonate-cement, mass in some sets.
3. METHODOLOGY
Fractured Basement Reservoirs provide a unique challenge with respect to reservoir
modelling. These fractured reservoirs contain porosity and permeability systems
that are dependent on tectonic activities and are thus segregated into structural
Block. Hence, two types of modelling approaches are used to describe the reservoir.
These are the Net Pore Volume Model (NPV) and the Halo Fault Model. The Net
Pore Volume Model is used to generate OIIP volumes in a structural Block based
model using porosity and net/gross to describe the rock volume in a probabilistic
method. The Halo Fault Model is used to characterize the reservoir with a fracture
enhanced halo around lineaments described by seismic in the reservoir. A fractured
halo fault is applied to the lineaments and porosity and permeability volume is
produced. This is used to simulate fluid flow modelling. Both models are matched
against well test and historical data and or dynamic data to ensure quality and
matched against conventional volumetric approach to ensure the total net volume.
This thesis will deal with two types of these models.
The workflow for this research is building structural model; Petrophysical modelling. After that
building model by both NPV, Halo method and calculating OIIP for each. In Halo method added
more step for upscaling and take the numerial simulation
3.2.1. Structural Modelling
Considering the scale of the geological objects to be realized and the runtime
for reservoir simulation due to computing speed, the grid configuration of X
Basement Geological model (3D Static Model) was optimized for the number of
cells with regardsto preservation of as much as possible the reservoir heterogeneities.
The 3D Grid of the X Basement Model was rotated at 45 degrees according to the NE
– SW direction as the main orientation of X structural development.
 Fault Modelling & Pillar Gridding
As mentioned above, the X structure is divided into 2 Blocks and 4 segments
in Block A. These Blocks and Segments boundaries are defined by faults and
bounded. In this stage of study, there are just 19 fault sticks that were used in the
process of fault modelling and of structural Block/Segment subdivision. The other
fault sticks (in segments) are used in property modelling for segment porosity
distribution.
Pillar Gridding is a process of building 3D grid of static model. The
horizontal grid size of X 3D geological model is 50m x 50m. This size is an average
value and has been used effectively and widely in 3D reservoir modelling of
neighboring basement reservoirs such as the Su Tu complex, Ruby, etc. The average
value of the vertical gridsize is 20 m.
 Make Horizons
The Make Horizons process is the first step in defining the vertical layering
of the 3D grid in Petrel. Both the top surface of X basement and the model base depth
surface of 5000m are used in Make Horizons. The reason to set the base of model
deeper than POWC is to have enough space for aquifer support in reservoir
simulation. The Top and Base horizons that were generated in the Make Horizon
process were correlated precisely with well markers. These horizons together with
the fault model were then used to construct the 3D structural framework.
 Layering
Layering is the final step in defining the 3D grid of the X model. The thickness
of the basement section was divided into 70 layers using the top down method. The
average thickness of each layer is 20m. This value was considered to optimise the
total number of cells but thin enough to preserve the vertical heterogeneities. It is
smaller as compared to other basement models (usually 50m).
3.2.2. Property Modelling
 Porosity modelling
This is a process of filling the cells of the grid with the porosity distribution
(called property population). The fractured granite reservoir is understood to contain
significant heterogeneities. The variations of fracture intensity require that the
reservoir volume be characterized as a composite of well and seismic information
following the Conceptual Basement Fracture Model. This conceptual model of X
should reflect the fracture distribution in the weathered zone of the upper part of
the basement and fault associated fracture system in the both upper and lower parts
as well as below the Structural Spill Point at 4620m TVDSS (Blocks A, B). The
final porosity model, as mentioned above, is the result of the combination of two
porosity models. They are the Net Pore Volume model and the Halo Faults model.
The Net Pore Volume model is built mainly using well information. Volumetric of
this model are used to compare with such values from the Hallo Fault Model. The
Halo Faults model is built using results from the tectonic/seismic interpretation in
combination with well data and its pore volume in principle should be in line with
that ofthe Net Pore Volume model. Property distributions in the Halo Fault model
are more detailed and realistic in representing fracture basement characteristics and
be used forupscaling and reservoir simulation.
 Model Validation
Theoretically, there are two QC methods for model validation and ranking these include static and dynamic. These tools are not only applied for QC model
but also for qualifying the upscaling process. Data and model validations were
carried out at every major modelling step. First of all, as soon as the data has been
imported into Petrel, they should be under strict quality control. Typical ways of
data QC are to display them in parallel with checking statistics, histogram, etc. In
addition, the general intersection was also used to view the data in cross section.
This is useful for QC’ing the structural framework and the property model. Another
important stepfor model QC includes checking for crossing pillars to make sure no
negative cell volumes have been generated. Depth synthetic data was used to
compare against raw data in order to ensure no depth mismatch.
3.2.3. Net Pore Volume Model (NPV)
Where multi-well penetrations are available the data can be summarized and
compiled into a consistent set of depth dependent functions. The NPV model uses
gross rock volume (GRV) that is generated from geologic/geophysical data and
porosity estimated from resistivity-based method plus NTG which is generated from
a combination of mud log, lithological and petro-physical information. Property
distribution of a structural Blocks/ Segments are populated by a composite set of
functions from individual wells (or just a well) relating to Maximum, Most likely,
and Minimum levels respectively.
Significant changes may occur between basement structural Blocks and
Segments (Segments within Block A), that are likely the result of different local
tectonic. A segment or block without well data will have a porosity characterization
assigned to it from a neighboring known Segment/Block (where well data is
available). Net/Gross distribution is also built using the same approach in a similar
fashion but relies more onstructural genesis that may not be from the same analogue
Segment/Block. In summary, net pore volume of areas where no well data is
available are a function of analogue segments which have similar structural genesis
and internal seismic characteristics.
3.2.3.1. Porosity versus Depth Estimation and Justification:
a. Methodology Description
In the X field, basement porosity of each well is calculated from resistivity
logs. In order to use the results of porosity interpretation for further 3D reservoir
modelling, the relationships of porosity vs. depth are required to be established for
each well, Segment and Block. Due to the heterogeneity of basement rock, resulting
from fracture distribution, the involvement ofsecondary materials, intrusives, etc.,
the variation of porosity with depth is not always decreasing. In order to capture
this variation and to reduce uncertainties, curves of porosity versus depth were built
with careful adjustments. Due to the large range of porosity variation, theoretical
curves should be generated as much as possible. However, at this stage of analysis,
just three key curves which correspond to Minimum, Most Likely and Maximum
cases are established. These relationships are likely exponential functions as
indicated in the Formula below:
𝐷𝑒𝑝𝑡ℎ = 𝑎 ∗ 𝑒 𝑏∗𝑃𝑜𝑟𝑜
(3.1)
Where:
Depth: distance from top of basement
Poro: porosity
a, b: constant factors
Workflow of establishing Porosity vs. Depth is conducted by the following steps:
 To establish curves of Porosity versus Depth with careful review of porosity
variations of each well.
 To establish curves of Porosity versus Depth for a group of wells which are
penetrating the same Segment (Segment application)
 To establish curves of Porosity versus Depth for regional basement
including Ruby, Bach Ho, Su Tu Den, Su Tu Vang and Rang Dong areas. This
is used forcomparison.
b. Porosity - Depth Relationship for Well
Results of porosity interpretation of 5 wells X-1X, X-2X, X-2XST and X-3X
and analogue data such as Y-6PST, and other regional data are used to plot the
porosity against depth on the scatter plot that has the same scale on both the y and
x axis. The X-3X porosity is only used for reference due to the lack of wireline data
available in this well (only LWD data acquired). Following careful review,
optimized representative curves of Minimum, most likely and Maximum Porosity
were generated. Some abnormal values of porosity have been observed. These
values may relate to granitic dikes or fault intersections. To account for them
correctly, it may need further specific study and examination of additional data such
as FMI/ DSI, core and etc. At this stage of the analysis, it is assumed that when the
depth from top of basement increases, the porosity will decrease. Three curves
(Minimum, Most likely and Maximum curves) of each well were generated and are
presented in Figures 3.5 to 3.9. The relevant functions are summarized in Table 3.2.
POROSITY – DEPTH RELATIONSHIP (X – 1X)
X – 1X
Max
Most Likely
Figure 3.5: Basement Porosity vs. Depth of X-1X well
POROSITY – DEPTH RELATIONSHIP (X – 2X)
X – 2X
Max
Most Likely
Figure 3.6: Basement Porosity vs. Depth of X-2X well
POROSITY – DEPTH RELATIONSHIP (X – 2XST)
X – 2XST
Max
Most Likely
Figure 3.7: Basement Porosity vs. Depth of X-2XST well
POROSITY – DEPTH RELATIONSHIP (X – 3X)
X – 3X
Max
Most Likely
Figure 3.8: Basement Porosity vs. Depth of X-3X well
POROSITY – DEPTH RELATIONSHIP
(X – 1X & X – 2X & SD - 6PST)
X – 1X
X – 2X
Figure 3.9: Basement Porosity vs. Depth of X-1X, X-3X & SD-6PST wells
Table 3.2.: Functions of Basement Porosity Vs Depth for all Wells in X field
Well
Case
Functions of Porosity Vs Depth from
Top Basement
Min
Depth = 5436.6e-263.16Poro
Most Likely
Depth = 93198e-198.02Poro
Max
Depth = 517341e-158.73Poro
Min
Depth = 156454e-400Poro
X-1X
X-2X
Most Likely
Depth = 357010e-250Poro
Max
Depth= 342440e-166.67Poro
Min
Depth = 3E+07e-1428.6Poro
Most Likely
Depth = 2E+06e-833.33Poro
Max
Depth = 268337e-500Poro
Min
Depth = 4797.8e-250Poro
Most Likely
Depth = 4234e
Max
Depth = 4027.5e-100Poro
X-2XST
X-3X
-142.86Poro
Porosity-Depth Relationship and application for Basement Reservoir
Basement Porosity with Depth curves generated for each and for combined Wells
are applied to each basement block in the X field and are summarized in the Table
below:
Table 3.3: Porosity – Depth relationship applied for X Segments and Blocks
Block/
Segment
A_Blue
Well
Case
Functions of Porosity vs. Depth
from Top Basement
Min
Depth = 156454e-400Poro
Most Likely
Depth = 357010e-250Poro
Max
Depth = 342440e-166.67Poro
Min
Depth = 3E+07e-1428.6Poro
Most Likely
Depth = 2E+06e-833.33Poro
X-2X
Block B
X-2XST
Max
Depth = 268337e-500Poro
Min
Depth = 109196e-666.67Poro
Most Likely
Depth = 1629024e-200Poro
Max
Depth = 164830e-147.06Poro
A_Red
A_Green
X-1X + SD-
A_Yellow
6PST
c. Porosity-Depth Relationship for Regional Basement
Results of porosity interpretation for X field basement are plotted together
with porosity of other Basement Fields such as of Bach Ho, Su Tu Den, Su Tu Vang,
Rang Dong and Ruby for comparison (Figure 3.10). As shown by this figure, the
porosity of X Basement reservoir is greater. This is reasonable based on the recent
drilling and testing information of X-3X, the longest basement penetration in the
Field.
X – 1X
X – 2X
X – 2XST
X – 3X
Figure 3.10: Porosity vs. Depth in the Basement of Cuu Long Basin
3.2.3.2. NTG versus Depth Estimation and Justification
a. Methodology Description
Based on current understanding, the Basement porosity is mainly generated
byfractures, and in turn fractures tend to develop more in shallower and crestal parts
of Basement structures and are less developed in deeper parts. Because of this, the
Net to Gross should have the same tendency as fracture distribution (or fracture
porosity). The calculated Net to Gross of Rang Dong, Ruby, Su Tu Den and Bach
Ho Fields demonstrates this observation.
An assumption is made prior to NTG estimation that when fractures are
plugged by clays, diagenetic minerals or not connected to each other, they are noneffective. In addition, Total Gas logs (TG) that respond to porosity are a function
of connected fracture systems those are hydrocarbon bearing. However, Total Gas
is affected significantly by some factors that make the interpretation of total gas
data more complicated. These factors are as follows:

Non-connected fracture system bearing hydrocarbons. These isolated features
may be broken out and opened by drilling penetration. As a result, fractures
become connected and may cause the total gas increase.

Gravity of drilling mud. The high gravity will flush the hydrocarbons into the
reservoir, thus causing the total gas to decrease.

Mud loss during drilling.

In addition, total gas may be also being affected by some other factors such
assurface equipment, borehole geometry and mud chemistry.
Due to the above factors, the Background Gas and Peak Gas should be estimated and
generated for each well at relevant depth intervals to cover variations as shown in
the Figure 3.11. Then, NTG can be estimated using the Background Gas and Peak
Gas. First of all, the cut-off line of TG is estimated and generated using (A) formula.
Any interval having TG greater than cut-off value and corresponding with good
porosity or hydrocarbon tested intervals are considered as Net Thickness. These
values are estimated for every 40m of total Basement section of all the wells in X
field. As soon as NTG has been estimated, similar to porosity, three curves of Net
to Gross versus Depth are generated with adjustments. They represent the
Minimum, Most likely and Maximum cases. The function that demonstrates the
relationship of Netto Gross and Depth from Top Basement is a logarithm function as
shown in the formula (B):
𝑇𝐺𝐶𝑢𝑡−𝑜𝑓𝑓 − 𝑇𝐺𝐵𝑎𝑐𝑘𝑔𝑟𝑜𝑢𝑛𝑑
𝑇𝐺𝑃𝑒𝑎𝑘 − 𝑇𝐺𝐵𝑎𝑐𝑘𝑔𝑟𝑜𝑢𝑛𝑑
=
1
3
(A)
𝐷𝑒𝑝𝑡ℎ = 𝑐 ∗ 𝐿𝑛 (𝑁𝑇𝐺 ) + 𝑑
Where:
TGBackground: Background gas
TGPeak: Peak gas
TGCut – off: Cut – off gas
Depth: Depth from top of basement
NTG: Net to Gross
c, d: Constant factor
(B)
Figure 3.11: Establishing the Background, Peak and Cut-off Gas values
b. Net to Gross – Depth Relationship of each well
As mentioned earlier, Net to Gross values of X Basement were estimated for
every 40m of basement section for all wells in X Field. Depending on each well,
either deep or shallow penetration, variations of Net to Gross with Depth are
demonstrated by three curves that represent the Minimum, Most likely and
Maximum cases. Results are illustrated in Figures from 3.12 to 3.16 and Table 3.4.
NTG – DEPTH RELATIONSHIP (X – 1X)
X – 1X
Figure 3.12: Basement NTG vs. Depth of X-1X
NTG – DEPTH RELATIONSHIP (X – 2X)
X – 2X
Figure 3.13: Basement NTG vs. Depth of X-2X
NTG – DEPTH RELATIONSHIP (X – 2XST)
N 2 G _X – 2XST
Figure 3.14: Basement NTG vs. Depth of X-2XST
NTG – DEPTH RELATIONSHIP (X – 3X)
N T G _X – 3X
Figure 3.15: Basement NTG vs. Depth of X-3X
NTG – DEPTH RELATIONSHIP (X – 1X + X – 3X)
N 2 G _X – 3X
Figure 3.16: Basement NTG vs. Depth of X-1X and X-3X
Table 3.4: Summary of NTG - Depth relationship of all wells in X
Well
Functions of NTG vs Depth
Case
from Top Basement
Min
Depth = -908Ln(NTG) + 3465.4
Most Likely
Depth = -989Ln(NTG) + 3980.2
Max
Depth = -1070Ln(NTG) + 4495
Min
Depth = -1020Ln(NTG) + 3600
Most Likely
Depth = -1005Ln(NTG) + 3900
Max
Depth = -1035Ln(NTG) + 4200
Min
Depth = -1080Ln(NTG) + 3000
Most Likely
Depth = -1080Ln(NTG) + 3500
Max
Depth = -1150Ln(NTG) + 4000
Min
Depth = -905Ln(NTG) + 3415
Most Likely
Depth = -837.5Ln(NTG) + 3307.5
Max
Depth = -770Ln(NTG) + 3200
X-1X
X-2X
X-2XST
X-3X
c. Net to Gross-Depth Relationship and Application for Basement Reservoir
Basically, the relationship of Net to Gross versus Depth for each
Block/Segment is constructed from NTG of each well. Similar to porosity, Net to
Gross distribution curves demonstrate a trend that decreases with Depth. For
Blocks/Segments without well data, the relationship of Net to Gross applied to them
are dependent on their similarity of fracture characteristics (density of fracture, HC
potential, etc) to the nearby Block/ Segment.
Table 3.5: NTG – Depth relationship for X Basement Segments and Blocks
Segment /
Block
A_Blue
Well
Case
The functions of NTG vs. Depth
Min
Depth = -1020Ln(NTG) + 3600
Most Likely
Depth = -1005Ln(NTG) + 3900
Max
Depth = -1035Ln(NTG) + 4200
Min
Depth = -1080Ln(NTG) + 3000
Most Likely
Depth = -1080Ln(NTG) + 3500
Max
Depth = -1150Ln(NTG) + 4000
Min
Depth = -1000Ln(NTG) + 3296
Most Likely
Depth = -1070Ln(NTG) + 4000
Max
Depth = -1105Ln(NTG) + 4500
X-2X
Block B
X-2XST
A_Red
A_Green
A_Yellow
X-1X +
X-3X +
SD-6PST
d. Net to Gross – Depth Relationship for Regional Basement
NTG values of basement wells in X field and some other basement fieldssuch
as Ruby, Su Tu Vang, Su Tu Den, Su Tu Chua and Bach Ho are used together to
generate a regional variation of NTG vs. Depth. It is clearly seen that the NTG of X
field is within the range of regional basement. The regional basement NTG vs.
Depth is shown in Figure 3.17.
X – 1X
X – 2X
X – 2XST
X – 3X
Figure 3.17: Basement NTG vs. Depth in the Cuu Long Basin
3.2.3.3.Results of NPV Modelling
The Net Pore Volume model uses gross rock volume (GVR) generated from
geologic and geophysical data. Applied against this volume is gross porosity from
resistivity porosity transforms and net/gross ratios generated from a combination of
mudgas, lithologic and petrophysical information. Properties within a structural
segment are represented by a composite set of functions from individual wells. The
reservoir is characterized with respect to gross porosity and net/gross function at
maximum, mean, and minimum levels. These are represented in the reservoir as a
lognormal function that decreases with depth and is consistent with the local field
data as well as analogues.
Table 3.6: NTG and Porosity Functions Applied to each X field basement Segments
and Blocks
MAX
Block/
Segment
Characterization
Wells
A_Blue
Max functions of porosity and net/gross
2X
A_Red
Max functions of porosity and net/gross
1X, 3X, Y6P
A_Yellow
Max functions of porosity and net/gross
1X, 3X, Y6P
A_Green
Max functions of porosity and net/gross
1X, 3X, Y6P
Block B
Max functions of porosity and net/gross
2XST
MEAN
Block/
Segment
Characterization
Wells
A_Blue
Mean functions of porosity and net/gross
2X
A_Red
Mean functions of porosity and net/gross
1X, 3X, Y6P
A_Yellow
Mean functions of porosity and net/gross
1X, 3X, Y6P
A_Green
Mean functions of porosity and net/gross
1X, 3X, Y6P
Block B
Mean functions of porosity and net/gross
2XST
MIN
Block/
Segment
Characterization
Wells
A_Blue
Min functions of porosity and net/gross
2X
A_Red
Min functions of porosity and net/gross
1X, 3X, Y6P
A_Yellow
Min functions of porosity and net/gross
1X, 3X, Y6P
A_Green
Min functions of porosity and net/gross
1X, 3X, Y6P
Block B
Min functions of porosity and net/gross
2XST