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MINISTRY OF EDUCATION AND TRAINING
HANOI UNIVERSITY OF MINING AND GEOLOGY



Pham Duc Thang





A STUDY ON SUITABLE SOLUTIONS TO ENHANCED OIL
RECOVERY IN THE LOWER MIOCENE FORMATION,
WHITE TIGER FIELD




Specialization: Petroleum Engineering
Code No.: 62520604




SUMMARY OF TECHNICAL DOCTORAL THESIS

Ha Noi - 2014

The study was completed at: Drilling and Production Department,
Petroleum Faculty, Hanoi University of Mining and Geology.




Advisors:
1. Assoc. Prof. Dr. Cao Ngoc Lam
2. Dr. Nguyen Van Minh



Reviewer 1: Dr. Nguyen Huu Trung


Reviewer 2: Dr. Nguyen Anh Duc


Reviewer 3: Dr. Tran Van Tan



The thesis will be defended in Assessment Committee of
University level which meeting at Hanoi University of Mining
and Geology in time hour date…. month year 2014

References to thesis at library: National library or Hanoi
University of Mining and Geology library



1
1. Statement of the problem
Lower Miocene is one of the major producers of White Tiger oil field
which so far has been producing from June 1986. The formation now is in
the final and declined phase with rising of high water-cut and water flooding
occurred throughout most the object. The production is mainly by secondary
method that is water injection to maintain reservoir pressure combining with
some mechanical methods which was no longer effective as the first
production phase. This formation has been produced of 6.36 million tons of
oil with the oil recovery factor is now at 15.5%. The potential for increased
oil recovery from lower Miocene after water injection is still very large. The
amount of residual oil remaining in the formation is about 28.3 million tons
of oil (accounting for 69% of initial oil in place).
In order to ensure that achieved production plan for fields in the next
years, the selection of appropriate methods to recover oil from lower
Miocene of White Tiger field is urgently needed in this period. Production
method by water alternating gas injection (WAG) was studied and selected
that is an appropriate and most potential method for enhanced oil recovery
in the lower Miocene of White Tiger field. This method not only increases
the oil recovery factor (increase sweep, pushing efficiency of residual oil)
but also take advantage of the low pressure gas quantity (level 2 after gas
separator of 100 m3) which currently have burned partly in White Tiger
field, contributing to environmental protection.
According to the forecast, oil production of White Tiger field will be

rapidly declined after 2012. In order to maintain the oil production due to
forward plan in the coming years is an extremely difficult task but it is very
urgent to meet the requirements and practices of production in Vietnam.
2. Objectives of the study
To enhance oil recovery for lower Miocene formation, White Tiger oil
field by applying water alternating gas injection (WAG).
3. Tasks of the study
In order to achieve its goals, the tasks of the study to be solved are:
- Overview of enhanced oil recovery (EOR) and water alternating gas
injection method.
- Status of production and selection of water alternating gas injection
method for lower Miocene, White Tiger field.
- Research by experiments and evaluate the efficiency of water alternating
gas injection method for lower Miocene, White Tiger field.



2
- Reservoir model and rerervoir simulation of WAG injection for lower
Miocene, White Tiger field.
4. Methodology of the study
- Folder method: processing and analysis of geological, geophysical, drilling
and production data to build an overview of research and application tertiary
method of WAG injection for lower Miocene, White Tiger field.
- Experimental method: buiding the exprimental model of pushing oil by
WAG injection on the combination core of lower Miocene, White Tiger
field to determine the technology indexes and evaluate the efficiency of
enhanced oil recovery of this method.
- Method of numerical simulation: model building, production simulation by
specialized software, history matching and production forcast, preliminary

evaluation of production efficiency of WAG injection to enhance oil
recovery for lower Miocene objects, White Tiger field.
5. Scientific and practical significance
5.1. Scientific significance
- A research, application project for a proposed solution to a rational
production to enhance oil recovery for lower Miocene objects, White Tiger
field from theory to experimental studies in the laboratory up to simulate
production.
- Find out optimization method to enhance oil recovery based on the actual
production and reservoir conditions. The results of the thesis will contribute
to clarify and enrich the EOR methods in general and in the lower Miocene,
White Tiger field in particular.
5.2. Practical significance
- The results of the study is urgently needed and meet the practical
requirements of oil and gas production which is now EOR for the lower
Miocene, White Tiger field as well as the others in Vietnam in declined
phase.
- WAG method has been applied very popular in the world, but in Vietnam
is still in the research of application phase. Therefore, the results of the
feasibility study will contribute to accelerating the investment in further
studies of the oil companies and the premise for applying into practice on a
large scale.
6. New contribution of the study



3
- The thesis has found Minimum Miscible Pressure (MMP) between oil and
associated gas of Miocene formation, White Tiger field and the solutions to
reduce MMP by mixing associated gas with available low pressure gas at

field to ensure the feasibility of applying the results in practice.
- Thesis has evaluated the efficiency of the method of Water Alternate Gas
(WAG) injection on physical modeling and reservoir simulation for
Miocene formation, White Tiger field.
7. The defending of new conclusions
- MMP of oil with associated gas of Miocene formation, Bach Ho field is
350 bar. MMP will achieve exactly the current reservoir pressure is 255 bar
by mixing 40% of low pressure gas (gas separation of level 2 at field) with
60% of associated gas. And while associated gas is enriched by LPG with
different mixing ratio, respectively: 5, 10, 20, 30 and 40% mol, MMP can be
decreased by respectively 315 bar, 291 bar, 238 bar, 185 bar and 140 bar.
- WAG injection before water injection could recovery from 70.5 to 80.2%
oil in the core sample, while only water injection has recovery efficiency of
about 55.5 to 60.5%. WAG injection at the time after the water injection
will make more oil recovery from 15.9 to 17.8%. The results of simulation
shown that the WAG injection schemes on northern Miocene models have
oil recovery factor increased from 2-10% and water cut down from 90-45%
compared to water injection method.
8. Database
The thesis was studed on the basis of documents, research reports,
review of geological, geophysical, designed production for the Miocene
formation, White Tiger field in particular and the White Tiger field in
general and a lot of material reports, studies, laboratory analysis of core
samples, fluid is taken from the Miocene formation, White Tiger field of the
authors; summarized reports of exploration and production activities in
Vietnam's continental shelf of Vietnam oil and Gas Group; articles and
scientific studies of the domestic and foreign authors which ware published
in professional journals.
9. Structure of the study
The dissertation consists of an introduction, four research chapters,

conclusions and recommendations, list of published works of the author and
reference list, appendices. The entire contents of the thesis are presented in
109 pages, including 23 tables, 85 graphs, drawings, and 91 references.




4
Chapter 1
OVERVIEW ON ENHANCED OIL RECOVERY AND WATER
ALTERNATING GAS INJECTION METHOD
1.1. Production phases
Production process in the oil field can be divided into three phases:
primary, secondary and tertiary phases. For each phases, the technologies
applied in the field will be varried.
1.1.1. Primary production phase
As initial reservoir pressure is greater than hydrostatic pressure or when
the initial reservoir pressure greater than the total pressure loss of the flow
from bottom hole to the surface, and then field oil will automatically flow
by its natural energy.
1.1.2. Secondary production phase
Process of water or gas injection to maintain reservoir pressure after
primary production phase called secondary production. These oil recovery
methods are also known as incremental recovery of conventional oil
(Conventional EOR).
1.1.3. Tertiary production phase (EOR- Enhanced Oil Recovery)
EOR methods with purposes to increase energy supplement for
reservoir, also create favorable conditions for oil recovery process by the
interaction of injected fluids (usually not in reservoir) with oil and rerservoir
rock. This interaction can reduce the surface tension between phases, dilates

significantly oil, reduce oil viscosity, reduce the possibility of the oil
wettability, increase sweep efficiency, reduce viscous fingering by
maintaining oil mobility and gravity segregation between interacted fluids.
Oil recovery efficiency is calculated by the following formula:
E = E
A
* E
V
* E
D
(1.1)
In which: E
A
: Area Sweep Efficiency
E
V
: Vertical Sweep Efficiency
E
D
: Displacement Efficiency
1.2. Water Alternating Gas injection method (WAG)
1.2.1. Minimum Miscible Pressure (MMP)
When gas injection to push oil, it occurs the process of mixing between
gas and field oil. The ability to mix and the efficiency of pushing oil
depend on the injection pressure. There is a critical point in the relationship
between the oil recovery factor and injection pressure that at this pressure



5

with high oil recovery and minimum injection pressure. At this injection
pressure, the oil is almost recovered and therefore injection pressure
increased higher than that, recovered oil is negligible.
1.2.2. The mechanism of mixing oil and gas
The mechanism of mixing oil and gas are classified into two main
mechanisms that are first contact miscibilty (FCM) and multible contact
miscibilty (MCM). In which multible contact miscibilty is devided into two
types that are condensing drive and vaporing drive.
Factors affecting the minimum miscible pressure are reservoir pressure,
reservoir temperature, reservoir oil components, reservoir oil density,
injection gas composition (enriched gas, lean gas and natural gas) and
injection gases (CO2, HC and N2).
1.2.3. The mechanism of pushing oil by water and gas (reservoir model)
For lower Miocene formation, pushing and trapping oil properties are
often studied on double channel model (model-Double and More Slobod,
1956). On the structural double model is simulated by two large and small
channels. This model is the water wettability model. The process of pushing
oil occurs on the model as follows:






For WAG injection method, mechanism of sweep and pushing oil
occur over the entire small and large channel by the water and gas
alternating injection which aim to increase the efficiency of oil recovery
compared to model of water injection or gas only. This demonstrates the
efficiency of WAG injection on the double channel model. In other words,
WAG injection is reality effective on all kind of sediments. Particularly,

miscible gas injection process may be more convenient when the surface
tension between gas and oil is 0.
In summary, the mechanism of pushing oil in capillary force model
dominantly as the sedimentary rocks which applied WAG injection will
have significant effect. For most types of rock that have small permeability
or high capillary force, the efficiency of WAG injection is larger show.

Oil
Oil
Oil
water
water
Water
water
Water
gas
Gas
Gas

Oil
Oil
water

6
1.2.4. Mobility ratio
When a fluid pushing the other, the mobility ratio (M) is defined as the
ratio of the mobility of displacing fluid ahead to that the mobility of
displaced fluid behind. If this ratio is greater than 1, this means pushing not
meet requirement as a caused result of viscous fingering. And for those of
mobility ratio less than or equal to 1, progress will occur as pushed piston.
In which:
M : Mobility ratio of WAG injection.

chat- day
: Mobility of water and gas.

chat-bi-day
: Mobility of water and oil.
K
w
, K
g
, K
o
: Permeability of water, gas and oil, mD.
μ
w
, μ
g
, μ
o
: Viscousity of water, gas, oil, cP.

1.2.5. The factors effect on the efficiency of WAG injection
1.2.5.1. The effect of injection speed
Blackwell et al (1960) observed that at the surface of pushed face of
oil/gas, viscous fingering was happened quite seriously, meanwhile at the
surface of pushed face of pushed face of water/gas was happened stable.
However, under high injection speeds then more oil was trapped by the gas
passing over oil without sweep. This behavior occurs because gas moved
too fast to water. With slower injection speed, water moved faster than gas
that caused reducing of gas sweep efficiency. With optimum injection
speed, gas and water will move at the same speed and the sweep effiency of
oil is the most effectively.
1.2.5.2. The effect of injection slug size
The size of the injection slug can be defined by injection volume for
each injection slug. In general, the volume of each slugs are calculated as a
percentage of pore volume (PV) or hydrocarbon pore volume (HCPV). The
total gas volume used for injection is the total volume of the injection slugs.
The majority of researches and applied results on the field, injection
slug size are applied to approximately 5% PV. According to that reseach,
total gas slug with about 40% PV is optimal for gas quantity when applied
in WAG injection.
 
 
Sowavg
w
w
o
o
Swavg
w
w

g
g
wo
wg
daybiChat
dayChat
KK
K
K
M































(1.2)



7
1.2.5.3. The effect of WAG ratio (water and gas ratio)
WAG ratio is determined by ratio between water slug volume and one
gas slug volume. In some researches before, WAG ratio is defined the
percentage of water to gas slug. In scope of this study, WAG ratio will
display under ratio of water volume with one gas volume.
1.2.5.4. The effect of wetability on the efficiency of oil recovery
According to the study on structured reservoir model with the different
wetabilities of Sohrabi et al at Heriot-Watt university that published on 2001
[75] was shown that the efficiency of WAG injection is higher than that in
water and gas injection on all model. On the types of watability model as
water wetability, oil wetability and combined wetability then the efficiency
of oil wetability model is highest and the efficiency of water wetability
model is lowest.
1.2.5.5. The effect of reservoir characteristics on the efficiency of oil
recovery

According to geologist, almost reservoirs were flooded in water for a
long time due to sedimental process. Therefore, oil reservoir is often
hetrogeneous and has a complex structure such as not the same permeability
and porosity with the different directions. There are divided into two main
effects on oil recovery that are the effect of Kv/K
h
ratio and the effect of
sedimental layers.
1.3. WAG projects in the world
Gas injection projects were implemented in so many places in the
world. Almost projects applied WAG injection by hydrocarbon gas (HC).
Magnus and Ula fields are operated by BP at northern sea that are new fields
applied WAG injection and achieved success [57, 89]. In Vietnam, WAG
injection method by hydrocarbon was studied and has been implementing
for pilot test at Rang Dong oil field and achieved the initial satisfactory
results [7, 62]. Based on oil properties, field reserves, the distance of gas
pipeline and investment costs for Magnus, Ula and Rang Dong fields it
would be considered to apply completely WAG injection for Miocene
formation, White Tiger field.
1.3.1. Magnus field with WAG injection project
Magnus field has started producing from 1993 and applied water
injection to maintain oil production of 150 thousands bbl/day until 1995.
Residual oil saturation after water injection is 25%, OIIP is 1.5 billions bbls.
Field has been applied 4 wells for WAG injection from 2002, minimum



8
miscible pressure (MMP) is 345 bar. Gas pipeline is 400 km of length from
gas fields in the west that is operated by BP. In 2010, oil recovery added by

WAG injection is 11.5 million barrels and contributed up to 40% oil
recovery for entire field.
1.3.2. Ula field with WAG injection project
Similar to Magnus project, the system of EOR injection of Ula field
have advantage conditions to apply with the key factors of reservoir
engineering and commerce. Ula field started producing from 1986 and
injected water from 1988. The research shown that WAG injection could be
recovered from 8-10% OIIP compared to water injection. Residual oil
saturation is high (35-50%), large OIIP (1 billions bbl) which are advantage
conditions to inject WAG. The gas source for WAG injection is at the field
and adding from Tambar and Blane field and one more Oselvar gas field in
2012. The commercial negotiation has made sure to carry out WAG
injection. In 2010, the addition of produced oil by WAG injection was more
than 23 million barrels (accounted for 2.4% OIIP) and contributes to 60-
70% oil recovery of entire field.
1.3.3. Pilot test project by hydrocarbon injection at Rang Dong field,
Viet Nam
Rang Dong field began producing from August 1998 in two main
subjects that are Miocene sandstone formation and fractured basement
rocks. Up to 2010, the field was produced about 82 million barrels of oil and
80 million cubic feet gas from lower Miocene formation with ultimate oil
recovery factor is 26.7%. The average of oil production currently is
approximately 16,000 barrels/day and 15 million cubic feet gas/day, the
water cut is 55% on average [7]. Water injection was carried out in 2006 and
so far field is now in the declined phase.
According to the initial assessment, the efficiency of WAG injection
method can increase oil recovery in this formation of about 10 million
barrels in the period of 2011-2020, equivalent to 35% of the total oil
recovery. WAG injection method has been studied by experiments with
MMP of associated gas is about 331 bar.

In general, WAG injection method performed the following
mechanisms:
- Increased pushing efficiency of oil recovery by maintaining reservoir
pressure. Mechanism of gas mixed with oil will reduce oil viscosity that
leads to increase pushing efficiency or increase oil recovery factor.



9
- Increase the oil sweep efficiency by reducing mobility that leads to reduce
viscous fingering and gravity segregation phenomena thereby increasing
sweep efficiency or increasing oil recovery factor.
- The mechanism of pushing oil by WAG injection method on double
channel model is dominant advantages of this method compared with other
methods for EOR. The mechanism of pushing and sweep of residual oil on
small and large channels make increasing the efficiency of oil recovery in
sedimentary model compared with water or gas injection only.
Chapter 2
THE STATUS OF PRODUCTION AND THE SELECTION OF
WATER ALTERNATING GAS INJECTION FOR MIOCENE
FORMATION, WHITE TIGER FIELD
2.1. Overview on White Tiger field
White Tiger is the largest oil field that located on the continental shelf
of Vietnam, block 09-1 of the Cuu Long basin, about 120 km from Vung
Tau southeast. The surface area is of 120-130 km2 with sea depth of 50 m.
Vietnam- Russia Joint Venture (VSP) directly manages and operates the
exploration and production activities at the White Tiger field. White Tiger
field has started producing from June 1986 from the Miocene, Oligocene
formation and granite basement. The original oil in place of White Tiger oil
field is about 611 million tons [29], accounting for 45.6% of all the oil

reserves of the Vietnam fields.
2.2. The characteristics of geology of lower Miocene formation
Lower Miocene formation belongs to Whiter Tiger field and its
developing is almost over the area of the field with the depth from 2759 -
2998m below sea level. The formations from top to bottom is 23, 24, 25, 26,
27 with its high production grade which were observed in the Northern,
Central dome and surround south areas. The initial reservoir pressure of the
lower Miocene in central dome in average value is 28.8 MPa when
converted it into absolute depth - 2810m. Initial reservoir pressure of the
lower Miocene in Northern dome is 29.3 MPa when converted it into
absolute depth - 2971m. The porosity of this formation varies from 1.9 to
33.5%, averaging of 17.7 %. The permeability of this formation varies from
0.5 mD – 1650 mD, averaging of 239 mD.
2.3. Original oil in place and recoverable reserves
Lower Miocene, White Tiger field includes 5 formations of 23, 24, 25,
26 and 27 and they are distributed into separated oil zones. According to the



10
approved reserves for production technology design and built for White
Tiger field dated 01/07/2011, the total initial geological reserves of the
lower Miocene, White Tiger field are 41,093 thousand tons. [30]
As calculated oil recovery for lower Miocene, White Tiger field at 31
December 2012, cumulated oil is 6.36 million tons, oil recovery is expected
to add of 6.37 million tons and with ultimated oil recovery factor is 31%.
The amount of residual oil remaining after secondary water injection was
28.35 million tons, accounting for 69% of original oil in place (OOIP) and
this is a high potential for tertiary production.
2.4. The status of production for lower Miocene, White Tiger field

The formation so far has been producing from June 1986 and it is
currently in the secondary and decline phase. Status of water flooding
occurred throughout most of this formation where at the northern dome is
82.8%, and the central dome is 44.3%. The production by water injection to
maintain reservoir pressure is no longer effective, although water injection
was reduced. As of 31 December 2012, Miocene formation was produced of
6.36 million tons of oil at current recovery factor is 15.5%.
2.5. The popular methods of enhanced oil recovery in Vietnam
The methods of EOR as reported by Talber (1983) [81] are based on the
principle of increasing sweep or pushing efficiency, or both. These methods
aimed to change the basic physical and chemical properties of the fluid in
the reservoir, such as surface tension, viscosity, wettability, mobility ratio
The application of the methods to increase oil recovery depends very much
on the specific conditions of each field. In order to select the suitable
methods of oil recovery, it should be based on oil properties, reservoir
conditions and recovered oil prices, especially economic and technical
efficiency to choose the appropriate method.
From actual data there may see the oil fields in Vietnam are appropriate
to apply methods of gas injection, CO2 injection, polymer injection and
surfactant and co-surfactant injection However, the application of methods
to increase oil recovery depends greatly on the specific conditions of each
fields.
2.6. Research and selection EOR methods for Miocene formation,
White Tiger field
As reported by Talber (1983) [81], based on reservoir conditions and
production status at the lower Miocene, White Tiger field found that the gas
injection method is most appropriate and applicable method of EOR by
injection of the three hydrocarbon gases, CO2 and N2. The thermal and

11
chemical methods are not suitable due to high temperature (100°C), oil
viscosity and low permeability of reservoir oil, deep depth of the lower
Miocene formation.
Table 2.5. Reservoir properties and conditions to apply gas injection for
lower Miocene formation as statistics by Talber

No
Reservoir property
Miocene formation,
White Tiger field
Condition to
apply
1
Oil density (
0
API)
32
> 31
2
Reservoi Pressure (psia)
> 2000
> 1030
3
Reservoir Temp. (
0
C)
100
> 32

4
Depth (m)
2700-2900
> 650
5
Viscosity (cP)
1-1,7
> 0,1
6
Oil saturation (%)
> 30
> 25
7
Permeability (mD)
> 10
> 5
2.7. The potential for increased oil recovery at lower Miocene
formation, White Tiger field
Methods of enhanced oil recovery by water alternating gas injection
(WAG) are very consistent with reservoir conditions and status production
for lower Miocene formation, White Tiger field. According to the initial
assessment, the efficiency of this method can increase about 10 million tons
of oil recovery from this formation in 2011-2020 periods, equivalent to the
total recovery that was achieved about 35%. This is a figure that is great
significance both in economic and technical conditions in reservoir
conditions of declined phase, preparing to finish production.
The application of WAG injection method is most appropriate because
this method not only increase the oil recovery factor (increase sweep and
push efficiency) but also take advantage of the low pressure gas which is
removed a part in White Tiger field and enriched gas injection.

2.8. Production situation, reserves and potential of gas gathering
Most gas fields were discovered on the continental shelf of Vietnam
which is mainly located in the Nam Con Son basin. A large amount of gas is
being produced in the Cuu Long Basin that is mainly associated gas. The
amount of gas reserves in place is approximately 18.8 trillion cubic feet.
However, there are a large number of associated gas at oil fields are
burned daily at present (Dai Hung, Hong Ngoc, Su Tu Den fields). If the
associated gas in these oil fields do not have planned to gather early that
would be a waste. In addition, gas burning would be affected worse to the
environment. Besides that, even the amount of low-pressure gas is being



12
burned in those oil fields that have existing pipeline must be gathered. At
the White Tiger field, where gas is brought to ashore, low pressure gas of
daily production is flaring up to 22,000 m3/d in 2013.
The construction of gas pipelines from the marginal fields to the shore
may not be effective due to smal gas quantity, but the construction of gas
pipelines that connecting between the fields would be ensure gas gathering,
using of the daily amount of burning gas, and providing for the fields when
required for gas injection. This gas gathering may again bring up an
economic efficiency and environmental protection. The use of this gas
source should be more specific and detail study about all the technical and
economic aspects.
In summary, based on analyses of oil production status, reservoir
characteristics, and oil properties, EOR method by WAG injection was be
selected as a suitable method to enhance oil recovery for Miocene
formation, White Tiger field. This method aim to reduce injection costs,
especially using of hydrocarbon gas and enriched gas with low pressure gas

that is existing in the field, LPG or condensate to apply for Miocene
formation, White Tiger field .
Chapter 3
RESEARCH BY EXPERIMENTS AND EVALUATION THE
EFFICIENCY OF WATER ALTERNATING GAS INJECTION FOR
MIOCENE FORMATION, WHITE TIGER FIELD
3.1. Laboratory preparation
3.1.1. Core sample
Core sampling was taken from the lower Miocene formation, White
Tiger field and was selected as appropriate for initial orientation. The core
sample is drilled and cut surface as plane plugs and how to join core plugs in
to form a long cylindrical composite core. Component sample (composite
core) would be a representative sample to apply for injection study.
After the drilling and cutting, core samples were washed and extracted
by Toluene on the sohlex device and finished until the solvent is not change
the color. And then 20 samples were taken to wash and extract by methanol
solvent. Extraction process aims wash soluble salts left in the core sample.
The process is only stopped when the solvent is tested by silver nitrate
without any salt precipitates.
The core samples after complete extraction were put on oven for drying
at a temperature of 70
o
C and a minimum time of 48 hours. Dried samples
were put on desicator to keep for non-wetting and to cool down.



13
Permeability and porosity of 20 core samples were then measured on the
CMS 300 of U.S. facilities in the laboratory of Vietnam Petroleum Institute.

In the entire samples, some selected samples for experiments, some
remained samples will be keeping for backup. Fundamental properties of
composite core that used in the experiments are: average permeability, K1:
206 mD, average porosity: 29.1%, initial water saturation: 26.8%.
3.1.2. Reservoir fluid sample
Oil and gas samples were taken from 920 well, MSP-9 at lower
Miocene formation. All 6 gas tanks of 20 liters and 3 oil tanks of 650 cc are
obtained continuously when tank pressure is stable. The conditions at the
time that taken samples as follows: Ptank = 12 bar; Ttank = 50
o
C; % water =
21.4%; GOR = 75.5 m3/ton.
At the laboratory of Vietnam Petroleum Institute the whole of the oil
and gas tanks were checked the quality before analyzing. Oil and gas
samples which were satisfactory will be measured the components on the
gas chromatograph. The reservoir oil was re-created by using parameters in
the calculations based on the component of measured oil and gas, the gas-oil
ratio at tank condition, gas-oil ratio at laboratory condition, gas gravity and
some other parameters. With mixing coefficient between oil and gas
separator is calculated, renewable reservoir oil based on sampling
conditions. Bubble point pressure is 150 bar, suitable for oil density is 0.76
(at 350 bar) and 0.87 (at 0 bar), oil viscosity at reservoir conditions is 2
mPa.s and reservoir temperature is 105
o
C.
The data analysis component of the reservoir oil showed the heavy
components accounted for 38.6% mol of C7+, lightweight components
represent less than 50%, which accounted for 34.5% mol of C1.
3.2. Experiment for Minimum Miscibilty Pressure
Laboratory testing for Minimum Misibility Pressure (MMP) is

especially important for experiments and calculations of capability when
applied to gas injection. This experiment is to find a lowest miscible
pressure but delivers high efficiency of oil recovery. Experiments were
conducted on Misibility Aparatus equipment of Vince Technology (France)
firm was installed at Vietnam Petroleum Institute in 1999.
3.2.1. Description of laboratory equipment
This equipment uses a 40 ft long sand column (slimtube). This is a soft
stainless steel tube with a diameter of 1/4 inch that containing of 160-200
mesh Ottawa sand.
Slimtube tube length 40 ft aim to reduce the influence of mixing zone
on the measurement results. Besides, the size of the pipe affecting to viscous



14
fingering problem, so device often made of pipe 1/4 inch. Porosity of the
sand tube is from 30 to 45% without affecting to the results of the
measurements but its permeability will affect to the measurement results by
the differential pressure between the head tube and bottom tube. With
slimtube as designed and gas injection from top to down, the efficiency will
ensure complete sweep of oil and gas in the tube.
The end of the slimtube is connected to a high pressure window that can
be observed oil flowing in the tube at different pressure levels. In some
cases, gas injection can be observed through of mixing zone by the color of
oil changes. The following window is attached the regulator output pressure
(pressure tranducer Back-PVC
300
). The pressure at this level is the needed
pressure to be measured for experiments run on this device.
The last part of the device is attached after the pressure regulator output

devices that measure the amount of gas and oil ejected from the slimtube.
Oil and gas escaping from the injection gas is measured by gas meter
equipment (gas meter-FQT400). Dead oil were put in 1 cylinder (T2) has an
accuracy of 0.1 cc. During the experiment, an electronic scale was reading
the weigh of cylinder. Thus, oil and gas ejected in the experiment was
strictly controlled.
A constant flow pump Gilson (P1) with a maximum pressure of 400 bar
can be achieved automatically and controlled by computer. Flow may reach
a maximum of 10cc/minute. The pump is designed to inject oil hydraulic
fluid under pressure and heat. This oil is pumped to the bottom of the piston
of cylinders containing oil (C2), gas (C1) and solvent washing (C3).
3.2.2. Experimental procedure
Samples of oil and gas after loaded in C1 gas cylinder and C2 oil
cylinder were installed in the combustion chamber to heat and reach
reservoir conditions by Gilson pump P1 to increase pressure by pushing the
oil to the top of the slimtube column sand and increasing output pressure by
manual pump P2 with the condition of input pressure is always less than the
output pressure in the process. Gas cylinders C1 was isolated by the system
of valve on the top cylinder (NV200) in pushing oil process. Increasing each
level pressure in oil pump is 20 bar. Increasing pressure process was
implemented until oil is pumped down continuously from the top of the sand
column to botom at a pressure of 190 bar and output pressure is set to 200
bar. Oil is injected continuously for several hours to make sure the oil is
completely saturated and no air in the entire system. Gas injection
experiment to find the minimum miscibility pressure mixing that is carried
out after the stability parameters in the reservoir temperature is 105
o
C and
oil saturation pressure of 150 bar.

15
Five experiments were carried out respectively in 5 different injection
pressure is 200 bar, 280 bar, 310 bar, 360 bar and 380 bar. After the pushing
pressure of the oil pump was stabilized at each level, oil cylinder C2 was
isolated by the top valve system of oil cylinder (NV204). Using the Gilson
pump P1 to inject associated gas from the gas cylinder C1 to the top of the
sand column to push oil pressure and find minimum miscibility pressure at
each pressure level. Gas injected oil in the slimtube through observation
window (LG206) to the output of the pressure regulator (back pressure
tranducer-PVC
300
). When the gas injection pressure is greater than the
output pressure of the regulator, oil and gas are recovered at the end of
equipment at each level pressure of the experiment. We can observe the
process of pushing and sweeping oil in the slimtube at all levels through
high pressure window. At the point of minimum miscible pressure, gas will
break through oil and can be observed by changing the color of oil. After the
experiment ended, the entire system is cleaned with solvent in cylinder C3.
3.2.3. Experimental results
Measured results at the laboratory are presented in Figures 3.6a, 3.6b,
3.6c, 3.6d, 3.6e.

Figure 3.6. Measured results the efficiency of gas injection with
different pressures
Results of MMP with 5 injection pressure are shown on Figure 3.7.
Injection result on Slimtube
at pressure 360 bar
0
5000
10000
15000
20000
25000
30000
35000
0 0.2 0.4 0.6 0.8 1 1.2
Gas injection , PV
Gas recovery, cc
0.0
0.2
0.4
0.6
0.8
1.0
Oil recovery, PV

Gas recovery Oil recovery
Injection result on Slimtube
at pressure 380 bar
0
5000
10000
15000
20000
25000
30000
35000
0 0.2 0.4 0.6 0.8 1 1.2
Gas injection, PV
Gas recovery cc
0.0
0.2
0.4
0.6
0.8
1.0
Oil recovery, pv
Gas recovery OIl recovery
Injection result on Slimtube
at pressure 200 bar
0
5000
10000
15000
20000
25000

30000
35000
0 0.2 0.4 0.6 0.8 1 1.2
Gas injection, PV
Gas recovery, cc
0
0.2
0.4
0.6
0.8
1
Oil recovery, PV
Gas recovery Oil recovery
Injection result on Slimtube
at pressue 310 bar
0
5000
10000
15000
20000
25000
30000
35000
0 0.2 0.4 0.6 0.8 1 1.2
Gas injection, PV
Gas recovery, cc
0
0.2
0.4
0.6

0.8
1
Oil recovery PV
Gas recovery Oil recovery
Injection result on Slimtube
at pressure 280 bar
0
5000
10000
15000
20000
25000
30000
35000
0 0.2 0.4 0.6 0.8 1 1.2
Gas injection, PV
Gas recovery, cc
0
0.2
0.4
0.6
0.8
1
Oil recovery, PV
Gas recovery Oil recovery
Figure 3.6 (a) Figure 3.6 (b)
Figure 3.6 (c) Figure 3.6 (d) Figure 3.6 (e)

16








Figure 3.7. The relationship between oil recovery factor and injection
pressure
Experimental results showed that the injection pressure of 350 bar is
MMP of associated gas injection with reservoir oil of this formation. At
MMP, oil recovery efficiency is above 90%, if the pressure continues to
increase is higher than this injection pressures, the oil recovery efficiency
did not increase significantly.
However, this MMP is higher than hydraulic fracturing pressure of
Miocene formation (320 bar) of about 30 bar (reservoir depth is 2800 m).
Therefore, in order to apply successfully for gas injection for the lower
Miocene, White Tiger field it needed to reduce MMP down to the current
reservoir pressure with enriched gas by mixing the gas associated with LPG
or other HC gas to reduce methane content (C1 component) down.
3.3. Experiment reducing MMP by reasonable gas mixing ratio
Based on simulation results, the author was conducted experiments to
reduce MMP down. The experiment was performed similar experiments to
find MMP above with associated gas injection. Injection gas composition is
mixed 60% of associated gas with 40% of low pressure gas and associated
gas was enriched by LPG with different mixing ratio, respectively: 5, 10, 20,
30 and 40% mol. Experiments were conducted respectively at the level of

different injection pressure is 200 bar, 220 bar, 241 bar, 280 bar, 310 bar,
360 bar and 380 bar.
Experimental results measured MMP with the injection pressure levels
are presented in Figure 3.8, Figure 3.9 and Figure 3.10.
Experimental results showed that the mixture 60% of associated gas
with 40% of low pressure gas MMP was lowered to 255 bar, 95 bar lower
than when gas injection not mixed with low pressure gas (350 bar) and 25
bar lower than the initial reservoir pressure is 280 bar. If the associated gas
is enriched by LPG with different mixing ratio, respectively: 5, 10, 20, 30
200
310
280
380
360
0.4
0.5
0.6
0.7
0.8
0.9
1.0
200 250 300 350 400
Injection pressure, bar
Oil recovery factor
MMP=350 barMMP=350 bar




17

and 40 mol%, the MMP can be decreased by respectively 315 bar, 291 bar,
238 bar, 185 bar and 140 bar. At the miscible injection pressure, oil was
recovered and attained at the highest of 70% recovery or more.








Figure 3.8. MMP using associated gas mixed with 40% low gas pressure







Figure 3.9. MMP using associated gas enriched with different rate
of % LPG








Figure 3.10. The relationship between MMP and mixture ratio LPG

with associated gas
3.4. Experiment of WAG injection on core samples
5% LPG
10% LPG
20% LPG
30% LPG
40% LPG
0.4
0.5
0.6
0.7
0.8
0.9
1.0
200 250 300 350 400
Pressure (bar)
Oil recovery factor

350
315
291
238
185
140
50
100
150
200
250
300

350
400
0 5 10 15 20 25 30 35 40 45 50
Mixing ratio LPG, %
Minimum Miscible Pressure-MMP, bar

200
241
220
380
360
310
280
0.4
0.5
0.6
0.7
0.8
0.9
1.0
200 250 300 350 400
Injection pressure, bar
Oil recovery factor
MMP=255 bar




18
The experiments for assessment and survey the efficiency of WAG

injection were conducted on relative permeability equipment of Vince
Technology that was installed in Vietnam Petroleum Institute in 1999. The
entire system is controlled by computer. The parameters of pressure,
injection flow, temperature, different pressure, the amount of gas, oil and
water collected in the injection process are recorded automatically.
3.4.1. Description of laboratory equipment
In order to applied successfully this method of WAG injection, the
equipment needed to re-design based on the existing equipment. Valve 3-
direction is very important in this experiment because it will ensure the
transition from injection gas and injection and vice versa quickly. Due to
existing equipment system in Vietnam Petroleum Institute does not
consistent with model system, mercury filters are installed to eliminate
mercury concentrations in samples during loading sample of the pump that
affect to machines and measuring results.
Unlike the other systems for measuring MMP, this equipment is
designed to use two high-pressure pumps, pressure pumps can reach 700
bar. The flow rate of pump is from a few cc/hour for up to several thousand
cc/hour. In addition, other parts are quite similar compared to eqipment for
measuring MMP such as controller of output pressure, oil sample
containers, and the device measures the amount of oil, water and gas
obtained.
3.4.2. Experimental procedure
The core samples after drying, extracting and measured prorosity and
permeability were saturated by formation water. Anh then, these core
samples were installed in the core holder respectively. All system is put in
oven to heat and reach reservoir conditions by increasing slowly overbuden
pressure and out put pressure. Increasing each level pressure in oil pump is
20 bar. Increasing pressure process was implemented until water is pumped
with pressure of 150 bar from bottom to top and overbuden pressure is set to
380 bar. The process of experimental injection was carried out after

parameters are stable at the reservoir temperature of 150
o
C. Water is
pumped for a long time to ensure that core sample was completely saturated
and no air in the core sample.
Oil is pumped into core sample as soon as water injection finished with
in put pressure and out put pressure is stable. Oil is pumped to inject water
form top to bottom that aim water is completely injected by oil. Oil also
pumped until the in put pressure and out put pressure is stable. This process
is applied for experiments of WAG injection with before water injection and



19
after water injection is finished. The oil recovery factor is evaluated for each
method.
The experiments of WAG injection with before water injection and
after water injection were applied all the same parameters of WAG
injection. Following the technical requirements of WAG injection, in order
to reduce the affect of segregation gravity in gas injection, gas and water
will be pumped in the direction from top to bottom. The following
parameters are applied as below:
One gas slug size : 0,05 IHCPV (initial hydrocarbon pore
volume).
WAG ratio : 1:1 (1 gas volume : 1 water volume)
Total injection gas : 0,4 IHCPV.
Total gas slug number : 8
Total water slug number : 8
Injection speed : 16,2 cc/hour
Declination angle of formation : 45

0

After finished completely oil saturation for composite core, the
experiment of WAG injection before water injection was carried out. Firstly,
gas is injected from top of composite core to bottom. After a time is just
enough to inject of 5% IHCPV, 3 directed valve is turned from gas injection
place to water injection place. Similar to that process for water injection,
after injection is enough of 5% IHCPV with the same time of gas injection,
3 directed valve is also tured to gas injection place again. This process has
been going on repetitive until finishing of gas injection quantity (0.4
IHCPV), then continuously to inject water ultil entire injection volume
reached 1.5 IHCPV then experiment is stopped.
3.4.3. Experimental results
The results of experiments with WAG injection before water injection
and WAG injection after water injection are presented in Figure 3.10 and
Figure 3.11.






Figure 3.10. The relationship between oil recovery factor and total
injection volume in WAG injection before water injection
0
0.2
0.4
0.6
0.8
1

0 0.5 1 1.5
Total injection volume, PV
Oil recovery factor
Oil recovery Gas recovery Water recovery




20









Figure 3.11. The relationship between oil recovery factor and total
injection volume in WAG injection after water injection
The results of these experiments showed that the efficiency of WAG
injection before water injection can obtained of 70.5 to 80.2% meanwhile
water injection is just obtained of 55.5- 60.5%. WAG injection after water
injection can be added of 15.9- 17.8%. This thing was proved the effiency of
WAG injection is very high.
Chapter 4
RESERVOIR MODEL AND PRODUCTION SIMULATION OF
WATER ALTERNATING GAS INJECTION FOR MIOCENE
FORMATION, WHITE TIGER FIELD
4.1. Geological and dynamical model of Miocene formation

The lower Miocene is a type of sandstones formation and is divided into
two distinct areas which is the northern areas including northern dome and
the southern areas including of central and southern domes, between these
two areas does not have the hydraulic connectivity, so has built two
hydrodynamic model corresponding to each dome. Geological model of the
lower Miocene formation is built on the structural map of top and bottom
reservoir of the base oil itself, maps of the basic parameters of the physical
and geological for each formation including porosity and oil saturation line
with updated reserve until 01 September 2012 [30]. The calculation of the
parameters of production technology for these formations is made on a
combination of the Eclipse software of Schlumberger Company. [71, 72, 73]
Hydrodynamic model of central and southern domes have the number
of grid cells of 99 × 282 × 52, the average grid size in the direction X, Y, Z
respectively 100 × 100 × 2m. The total number of grid model is 1,451,736,
of which computational grid is 162 587.
Numerical and hydrodynamic model of northern dome have the number
of grid cells of 99 × 282 × 52, the average grid size in the direction X, Y, Z
respectively 100 × 100 × 2m. The total number of grid model is 1,451,736,
of which computational grid is 67 966.
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1

0 0.5 1 1.5
Total injection volume, PV
Oil recovery factor
Water recovery Oil recovery Gas recovery




21
The input data in the model:
The relative permeability curves of the oil-water and oil-gas, used to
calculate the parameters on hydrodynamic model which is determined by
the resuts of core sample study of the lower Miocene formation. On the
hydrodynamic model, author has used 13 relative permeability curves to
perform the calculations for the regions. Using the capillary pressure values
from the experimental results of the 13 regions ranged from 0.5921 to
0.6322 MPa.
The properties of oil and rock field has been updated and put in the
model.
4.2. Conditions of hydrodynamic model
Modelling for produced objects is carried out with the given conditions
in wells and at the boundary of the objects. The parameters of the wells put
in the model include the location of the wells in the field, perforated
intervals; the day put wells into operation, operating history of the well, the
production characteristics of wells, recovery factor, the design of wells etc.
4.3. Production history matching
In order to recover the energy state of reservoir oil on the model, the
author conducted a study of the operated modes of formations separately
and the full field. Compressibility coefficient of rocks in the lower Miocene
formation are determined in the laboratory and ranged from 1.9 to 2.9*10

-
4
MPa
-1
. During the production history matching the value of the
compression coefficient has been taken as 2.0*10
-4
MPa
-1
for the central and
southern dome and 2.9*10
-4
MPa
-1
for the northern dome to calculate the
results of reservoir pressure more consistent with practice in the early stages
of oil production.
Results of hitory matching for production model shows that 85% of the
wells have been well recovery and meets the criteria set out in the technical
requirements for buiding of the production model.
Although, there are still some wells which is not good history matching
in the model, but according to the evaluations this model can be acceptable
to calculate production forecast for the next period.
4.4. Selecting object and WAG injection scheme
Based on the current production status until 2012, we see a clear
difference between the northern dome and the central and southern dome.
The northern dome was produced of 4030 thousand tons oil that accounted
for 63% of oil production of the entire lower Miocene formation (6363
thousand tons), the current oil recovery factor is 25% and the current water
cut is over 82,8% [30]. Therefore, the northern dome needs more priorities

that should focus on solutions to enhance the oil recovery more than central



22
and southern dome. Within the scope of this study, northern dome was
chosen as the study area for water alternating gas injection (WAG) by using
the component model of Eclipse-300 to recover the maximum amount of
residual oil remaining below the reservoir (69%).
After carring out of production history matching for lower Miocene
formation, White Tiger field by black model (Eclipse-100), the PVT
properties of reservoir oil as components of oil and gas reservoirs, the
viscosity, volume factor, GOR, are put in the software of component model
PVTi to create new PVT properties of reservoir oil before putting them into
component models and run the history matching for the component model of
northern Miocene.
Results of history matching of component model for northern Miocene
formation shown that the model is enough reliable and ensures to conduct
research and evaluate the efficiency of the WAG injection scheme on the
model. During injection, gas injection will be dissolve in oil that caused to
to reduce viscosity, surface tension stress, residual oil saturation and
increase the oil expansion, changing oil density around the injection well.
The change in oil saturation around the injection well was predicted and
calculated by multi-component model of Eclipse-300 of Schlumberger.
4.5. The simulation result and production forecast
As predicted from the results of the simulated running until the end of
field life (2030), the WAG injection scheme for northern Miocene formation
model has proven highly efficient oil recovery than that of water injection,
the oil recovery factor increased from 2-10% and reduces water cut from 90-
45% comparing to the method of water injection.

The option of lean gas injection with flowrate of 15 million cubic
feet/day and the option of enriched gas injection from 5-10% with a flowrate
of 10 million cubic feet/day for oil recovery factor is highest efficient and
oil production is 7,102,638 tons and 7,100,580 tons respectively and oil
recovery factor is 45%.







Figure 4.25. Production forecast for options until 2030
Time, year
Oil production rate, m3




23







Figure 4.26. Water cut forecast of injection options
The option of enriched gas injection with a flow of 10 million cubic
feet/day which have oil recovery efficiency is higher than 3% compared

with lean gas injection with the same flow of 10 million cubic feet/day.
CONCLUSION AND RECOMMENDATION
1. CONCLUSION
Based on the basis of theoretical studies, the experimental results, the
evaluation results based on model simulations of the thesis “A study on the
suitable solutions to enhanced oil recovery for Miocene formation, White
Tiger field”, the author has summarized some important conclusions as
follows:
1. MMP of oil with associated gas of Miocene formation, White Tiger
field is 350 bar. MMP will achieve exactly the current reservoir
pressure is 255 bar by mixing 40% of low pressure gas (gas
separation of level 2 at field) with 60% of associated gas. And
while associated gas is enriched by LPG with different mixing
ratio, respectively: 5, 10, 20, 30 and 40% mol, MMP can be
decreased by respectively 315 bar, 291 bar, 238 bar, 185 bar and
140 bar
2. The results of experiments showed that WAG injection before
water injection could recovery from 70.5 to 80.2% oil in the core
sample, while only water injection has recovery efficiency of about
55.5 to 60.5%. WAG injection at the time after the water injection
will make more oil recovery from 15.9 to 17.8%. .
3. Equipment system and production technology scheme of White
Tiger field is currently suitable with WAG injection technology.
Ensuring gas and condensate for injection is entirely feasible
because of the possibility of full self-sufficiency its gas and gas
Time, year
Water cut, %