ghiên cứu ứng dụng công nghệ bơm ép luân phiên nước khí hydrocacbon nhằm nâng cao hệ số thu dầu tại tầng miocene bể cửu long tt tiếng anh

MINISTRY OF EDUCATION AND TRAINING
HANOI UNIVERSITY OF MINING AND GEOLOGY

TRINH VIET THANG

RESEARCH FOR APPLICATION OF WATER
ALTERNATING GAS TO ENHANCED OIL
RECOVERY IN THE MIOCENE RESERVOIR, CUU
LONG BASIN

Major: Petroleum Engineering
Code: 9520604

SUMMARY OF TECHNICAL DOCTORAL THESIS

HANOI – 2019


The dissertation is completed at the Department of Drilling and Production,
Faculty of Petroleum, Hanoi Unniversity of Mining and Geology

Scientific Supervisors:
1. Assoc. Prof., Dr. Cao Ngoc Lam
2. Dr. Sc. Phung Dinh Thuc

Reviewer 1: Assoc. Prof., Dr. Nguyen The Vinh

Reviewer 2: Dr. Nguyen Hai An

Reviewer 3: Dr. Pham Xuan Toan

The thesis will be defended before the Academic Reviewer Board at the
University level at Hanoi University of Mining and Geology at …..of
date….month…., 2019

The thesis is available at the National Library of Vietnam or the Library
of Hanoi University of Mining and Geology.


1

INTRODUCTION
1.

Research Objective

Petroleum is an invaluable, unrenewable and fundamental resource for every country
around the globe, especially so for developing countries. In recent years, the amount of
newly discovered oilfields, especially those that are significant in reserves, is declining,
while many of the ones that are in production are reaching their final stages. Therefore,
around the world, Enhanced Oil Recovery (EOR) technologies are increasingly receiving
attention and resources from countries and companies alike.
Vietnam is a country with moderate oil production; the majority of which are from the
basement reservoirs within the Cuu Long basin. The main reservoirs are the fractured granite
basement and miocene, accounting for about 90% of the yearly oil production. After primary
production and secondary production (waterflooding), oil recovery factor for these reservoirs
range from 20% to 32%. More than two-third of the explored oil in place still remains
untouched. This is an opportunity for the application of EOR method(s) to unlock the
remaining oil in place. Application of EOR technologies for the producing reservoirs
mentioned above is the main focus, critical for meeting the energy demand. With the
application of EOR method(s), a modest 1% to 2% increase in recovery factor for large

reservoir is already comparable to a discover of a small reservoir. Moreover, as production
rate of the Miocene reservoir is already in decline, the need for researching an appropriate
EOR method for this zone is even more imperative. For these reasons, “Research for
Application of Water-Alternating-Gas to Enhance Oil Recovery in the Miocene reservoir,
Cuu Long Basin” is a crucial and prioritized research project with clear cut implications.
The main objectives of this work are to characterize in details the applicable condition
associate with Miocene properties and to come up with the an effective EOR method as well
as its application for this objective.
In order to successfully apply Water-Alternating-Gas (WAG) to enhance oil recovery
for this reservoir within the Cuu Long basin, the authors need to focus on:
➢ Literature researching to study existing EOR methods and their successful applications
around the world, to gauge their compatibility with the geological, rock, and fluid properties,
as well as the production configurations, found in the Vietnamese reservoirs, especially for
sedimentary reservoir.
➢ Researching available methods to determine Minimum Miscibility Pressure (MMP),
as well as the miscibility, near miscibility, and immisicbility mechanism for Vietnamese oil
reservoirs.
➢ Researching and evaluating the effects of reservoir properties on possible application


2

of Water-Alternating-Gas injection to enhance oil recovery.
➢ Researching and evaluating EOR effectiveness of Water-Alternating-Gas injection
and comparing it to those of other EOR methods, using Miocene’s reservoir simulation
model.
2.

Research Procedure
➢ Data collection: collecting, classifying, and processing available data to assess the

difficulties and complications affecting production.
➢ Literature review: researching existing EOR methods already applied around the world
and evaluating their applicability on Su Tu Den field. Focusing on solving the miscible/nearmiscible/immiscible mechanism, as well as how changes in various factors such as pressure
lead to changes in miscibility ratio or displacement within the Miocene reservoir.
➢ Laboratory work: utilizing Slimtube experiment to determine the minimum miscibility
pressure (MMP) of the in-situ oil sample native to the Mioxen reservoir.
➢ Reservoir simulation: utilizing numerical simulation to find the MMP and compare it
to the one determined from Slimtube experiment. Simulate dynamics flows of fluids for the
entire reservoir(s) of interest to evaluate and compare efficiency of different EOR methods,
such as gas injection or alternating gas injection.
3.

Research Subject
Research application of Water-Alternating-Gas to enhance oil recovery for the

Miocene reservoir, Su Tu Den field.
4.

Scope of Study
Mioxen reservoir of Su Tu Den field, Contract Block 15-1, Cuu Long basin, Vietnam,

operating of Cuu Long Joint Operating Company (CSLJOC).
5.

Defending Conclusions
Finding 1: By utilizing simulation model, the exactly MMP for the process of injecting

Water-Alternating-Gas into Miocene reservoir was successfully predicted.
Finding 2: Based on 9 different criteria, it was proven that Water-Alternating-Gas was

the most appropriate EOR method for Su Tu Den field.
6.

Scientific Significance
The thesis researchs of mechanism and application of Water-Alternating-Gas for

enhancing oil recovery was relatively new in Vietnam. Through this work, the authors
successfully explored the mechanism of fluid flow in formation with high degree of


3

heterogeneity, of the gas-water-oil interactions, of the injected gas and in-situ oil miscibility,
and of the macroscopic and microscopic displacement efficiency. Furthermore, the author
was also able to evaluate the degree of enhancing oil recovery on a particular subject when
applying Water-Alternating-Gas injection, from there being able to make recommendation
on application of EOR method on Vietnam’s oilfields.
7.

Field Application
This study provided substantial scientific reasonings to recommend employing Water-

Alternating-Gas for enhancing oil recovery in Miocene, Cuu Long, and to go forward with
piloting a Water-Alternating-Gas injection scheme in the South West area of Su Tu Den
field.
8.

Research Results
This work stemmed from the pressing need of Vietnam’s oil producing climate. Its

results contributed to the improvement of oil recovery factors for many zones and reservoirs,
especially Miocene.
➢ The optimal procedure to predict the in-situ oil’s MMP, as well as such value for the
target of interest in this work, was determined.
➢ Successfully studied the influence of reservoir parameters, geological structure,
geological properties, and previous production scheme(s), on the effective application of
Water-Alternating-Gas for sedimentary formation.
➢ Evaluated the effectiveness of applying Water-Alternating-Gas for enhancing oil
recovery and compared it to other EOR methods, using reservoir simulation.
➢ Results of this work were published and presented at the “International Conferences
on Earth Sciences and Sustainable Geo-resources Development” conference.
9.

Volume and Structure of this Manuscript
This thesis consists of an introduction, four chapters outlining the research procedures,

conclusions, recommendations, and references. It is 133 - page long, with 16 tables, 103
graphs, figures, and 112 references.


4

CHAPTER 1: OVERVIEW
Enhance Oil Recovery
All EOR methods aim to improve the microscopic and/or macroscopic displacement
efficiency, based on the viscous, capillary, and/or gravitational interactions of the injected
fluid(s) and in-situ fluid(s) as followed:

Figure 1.1: Interactions between Different Forces in EOR
Enhancing oil recovery helps mobilizing the capillary-trapped oil or rock-surfacetrapped oil in oil-wet formations, ultimately reducing the residual oil saturation.

Displacement efficiency improvement heavily depends upon capillary force and gravity
(figure 1.1). Moreover, EOR methods also improve the swept efficiency of the injected
fluid(s), especially in zones that are little-affected/unaffected during traditional
waterflooding.
Enhance oil recovery manages to push oil out of pores and out of un-swept zones by
injecting fluid(s) or changing the in-situ oil properties. These mechanisms of EOR are
defined and classified into microscopic and macroscopic displacement. Both microscopic
and macroscopic displacement efficiencies are affected by pore structure, reservoir fluids
properties, injected fluid(s) properties, and flow of fluids in porous media.
Flow in Porous Media
Stalkup (1983) devised the following formula to calculate the mobility ratio for
injection Water-Alternating-Gas in presence of water and oil in the formation:

M=

Chat −day
Chat −bi −day

 Kg Kw 


+
(
g + w )   g  w  Swavg
=
=
(o + w )  K o K w 


+

  o  w  Sowavg

In which:
M: WAG mobility ratio
𝜆𝑐ℎ𝑎𝑡−𝑑𝑎𝑦 : water-gas mobility ratio
𝜆𝑐ℎ𝑎𝑡−𝑏𝑖−𝑑𝑎𝑦 : water-oil mobility ratio
Kw, Kg, Ko: water,
permeability (mD)

gas,

and

1.2)

oil(


5

𝜇𝑤 , 𝜇𝑔 , 𝜇𝑜 : water, gas, and oil viscosity
(cP).
Macroscopic and Microscopic Displacement Efficiency
The topic of EOR mechanisms and associating phenomenon will be discussed in detail.
These phenomena mostly depend upon the flow of fluid through porous media and the
nearby solid/liquid has great effect on the flow velocity. As all oil reservoirs have both water
and oil, research in two-phase flow is crucial. The complex interactions between these two
during flow, as well as rock-fluid interactions, have great impact on the residual saturations
and the change in fluid composition during production. Different macroscopic oil recovery
mechanisms include immiscible, partially-miscible and fully-miscible. Capillary pressure

has the most impact on the fluid-fluid interfaces and is mainly responsible for the macro
phase and micro phase in the producing fluid.
Oil recovered from pores by being displaced by other fluid(s) is called microscopic
displacement efficiency (ED). On the other hand, macroscopic displacement efficiency or
volumetric swept efficiency is the volume of in-situ fluids swept out of the porous media by
the injected fluid(s). Volumetric swept efficiency (EV) comprises of two factors: areal swept
efficiency (EA) and vertical swept efficiency.
Soi – Sor
Ed =

EA = Ev x EI

Soi

Areal swept efficiency (EA) is the ratio of the area of contact between the insitu/injected fluids and the area of the entire reservoir.
Different EOR Methods
Based on the results of thousands of EOR projects implemented around the world, the
projects’ reservoir conditions, reservoir properties, and location (onshore/offshore), the
authors conclude that gas injection and chemical EOR are particularly suitable to the
geological conditions, rock properties, fluid properties, and producing settings in the
Vietnamese oilfields. Chemical EOR is mostly applied for sedimentary formations and
onshore reservoirs. One main drawback of this EOR method is its difficulties when carry out
in deep reservoirs (under high pressure, high temperature condition) or in offshore reservoirs.
This is due to the difficulties in manufacturing chemicals that can withstand temperature
above 80oC and the chemical affinity of seawater/formation water. Therefore, gas EOR,
particularly the Water-Alternating-Gas method, is deemed to be most fitting.
Theoretical Background of Gas Injection in Oil Reservoirs
In order to determine the right miscibility mechanism, the first concepts of miscibility
condition(s) and main miscibility mechanisms need to be understood. Figure 1.2 explains

6

briefly how MMP is determined. The author finds it appropriate to stay close to the real
reservoir conditions and fluid properties often found in Vietnam throughout this research.
Fluid compositions vary with depth and reservoir pressures is usually higher than bubble
point. Therefore, MMP also changes with depth, resulting from fluid composition and
pressure changes with depth. Different injection gases also result in initial MMP, how it
varies with depth, as well as the mechanism of miscibility.

Figure 1.2: Miscibility and Immiscibility Mechanics
At this point, the injected gas help improve oil recovery by: oil vaporization, decrease
oil viscosity, increase dissolved gas when pressure goes down, and decrease interfacial
tension between phases. The effectiveness of these mechanisms can be quantified through
monitoring the dissolve of injected gas in reservoir oil, oil swelling coefficient, and decrease
in oil viscosity. There are several methods of determining MMP: through Slimtube
experiment in the laboratory (based on recovery factor), or through numerical simulation
packages.
Conclusions
The laboratory setup to estimate MMP was built to simulate the temperature and
pressure condition in the reservoir. However, throughout the entire experiment, fluids inside
the Slimtube were only subjected to unchanging reservoir conditions. This setup was unable
to simulate the changes in miscibility and immiscibility along the lateral and longitudinal
direction. The Slimtube experiment simply estimated MMP through closely monitoring the
recovery factor as the experiment went on and the amount of oil/gas that did and did not
underwent miscibility. Fluid composition was also unchanged throughout the experiment,
which was unrepresentative of what happens on the field.
To address these issues, the authors built a procedure to simulate and estimate the
MMP using numerical method, one that could give a more accurate result to the sedimentary
reservoirs found in Cuu Long basin. Based on the statistics of EOR projects around the world

and the analysis on the factors affecting these projects, Water-Alternating-Gas was found to
be the most fitting method for the reservoirs of interest, given the rock, fluid, reservoir
properties and their offshore condition. To fill in the gaps in preceding works, both in


7

Vietnam and on the world, the authors set the following research targets:
➢ Researching and selecting the best EOR method for Miocene reservoir, Su Tu Den
field, Cuu Long basin.
➢ Researching and building simulation models to accurately predict the MMP for gas
injection EOR and comparing it to the predicted MMP from Slimtube experiment. These
models would also have a PVT and Slimtube displacement simulation.
➢ Researching, evaluating, and selecting the optimal gas composition for injection in
the Water-Alternating-Gas scheme.
➢ Developing a reservoir simulation model and utilizing it to evaluate miscibility/nearmiscibility/immiscibility at reservoir conditions with factors like reservoir heterogeneity,
saturation of oil/gas/water inside the reservoir, changes in pressure and temperature during
production, changes in fluid composition during production and execution of the EOR
project.
➢ Exploring different EOR project options, optimizing and comparing economical
gains between Water-Alternating-Gas injection scheme and other gas injection schemes.
➢ Evaluating and proving that miscible/near-miscible gas injection was suitable for
Miocene, given its geological structure, reservoir fluid properties, and rock properties.

➢ Validating the capability of Water-Alternating-Gas injection project to maximize the
additional oil recovery and the economic gains, using reservoir simulation.

CHAPTER 2: SELECTING THE OPTIMAL EOR METHOD FOR
MIOCENE SU TU DEN
Miocene Geological Properties

The STD Oil field consists of three main objectives, that including: Fractured granite
basement, Miocene (with pay zones B10, B9, B15) and Oligocene (C30). In which, pay zone
B9 of miocene resevoir includes thin thickness, grain size from fine to medium, depositional
environments range from distribulary channels to bay head delta deposits with associated
crevasse splay and overbank deposits (Figure 2.1).
B10 Miocene reservoir was discovered in wells SD - 1X, SD - 2X, SD -3X, SD - 4X,
SD - 5X, SD - 6X. The B10 interval is a 10-16m, and confirmed from results of log
interpretation and results of welltest. B10 is most potential in STD lower miocene for oil
production.


8

Figure 2.1: Structural Map of B10 Miocen, Su
Tu Den

Figure 2.2: Oil-Water Relative
Permeability Curves for Miocene

Rock and Fluid Properties
2.2.1. Rock Properties of Lower Miocene
Laboratory results for wettability, water/oil relative permeability, and rock
compressibility showed overall good rock properties (porosity was about 30%, and average
permeability was about 7,000 mD). Wettability was 0.18 and 0.28 for well SD-2X and SD3X, respectively. Rock compressibility was gathered and measured from 23 samples.
Laboratory analysis showed typical compressibility value felt between 4.5 and 11.9 E-06
(psi-1). Relative permeability curves and oil saturation curve showed this was a good target
for water injection (Figure 2.2).
2.2.2. Fluid Properties of Lower Miocene
During the DST testing, reservoir fluid in one phase was taken from well SD-1x, SD2X, and SD-3X along with the oil and gas samples taken from the separators. The main oil
properties in the Lower Miocene were shown in table 2.1:

Table 2.1: Oil Properties at Reservoir Condition
Properties
API Gravity
Bubble Point (psia)
GOR (scf/stb)
Oil Formation Volume Factor Bo at Reservoir
Pressure Pr = 2.500 psi
Oil Viscosity at Reservoir Condition (cP)

SD-1X
34,7
1.155
364

SD-2X
35,5
1.275
364

SD-3X
35,4
1.060
314

1,24

1,27

1,23

0,907

0,825

0,88

Oil in Place and Reserves
Evaluation of reserves and oil in place and classification of reserve was done through
volumetric calculation coupled with Monte-Carlo simulation.


9

Table 2.2: Volume of Oil in Place for Lower Miocene
Area
3X-6X
SD-1X
Total

Reserve
Classification
P1
P1
P2
2P

Volume of Oil in Place (MMbbl)
P90
P50
P10

29
33
37
147
159,1
171,8
37,9
44,5
51,8
213,9
236,6
260,6

Su Tu Den Current Production Status
The Lower Miocene had three main production zones: the West Zone, the main
production area (MPA) and the South-West Zone. Up until the this report was writen, the
reservoir was being produced by 12 wells: SD-10P, 11P, 14P, 15P, 20P, 23P, 26P, 1PST,
12PST and 8PST, SD-28P, SDNE-6P and injected by 3 injection wells SD-NE13I, SD-27I,
and SD-16IST. Well SD-8PST and SD-1PST were being produced with high water cut
(Figure 2.3).

Figure 2.3: Wellbore Pressure Profile

Figure 2.4: Injection Profile of Lower
Miocene South-West Su Tu Den

Previously Applied Improved Oil Recovery/Enhanced Oil Recovery Methods
At the moment, Cuu Long JOC are waterflooding the Miocene reservoir, Su Tu Den.
3 injection wells SD-NE13I, SD-27I, and SD-16IST were starting their operations back in
2011 and 2012. Well SD-NE13I is now closed due to not effectively replenish reservoir

energy.
Oil production rate would continue declining quickly due to the limitations of
traditional waterflooding. Gaslift was also not a suitable option due to the high water cut.
Thus, it was imperative to quickly come up with an appropriate EOR method, especially
when the effectiveness of injection wells was also in swift decline
Evaluation of Reservoir Properties and Selecting EOR Method


10

Based on reservoir conditions and production history at Miocene, the authors found
gas injection to be the most proper EOR method and Hydrocarbon is the gas of choice.
➢ Reservoir Structure and Connectivity
The reservoir structure of Lower Miocene is characterized by multi-sands and
separated to closure structure. Closure structure is blocked from three directions by faults.
The closed structure would be a beneficial for gas injection. When gas is injected, gravity
would bring it upward to the cap where it is trapped and undergoes gas cap expansion. Gas
injection well could be designed for both injection below the oil-water contact or above the
gas-oil contact.
➢ Formation Porosity-Permeability
Miocene zone has good porosity and permeability, with porosity ranging from 25% to
30%, and average permeability to be about 7,000 mD. These are favorable conditions for
gas injection, especially for Water-Alternating-Gas (WAG) injection. When gas is injected
after water, it would be more incline to reach oil that were un-swept by water.
➢ Reservoir Fluid Properties and Existing Production Scheme
Reservoir fluid is another deciding factor affecting the efficiency of any EOR project.
When gas is injected, miscibility/near-miscibility/immiscibility between the injectant and insitu oil takes place. This process reduces oil viscosity, wettability, increases the swept and
displacement efficiency. Furthermore, viscous fingering and gravity segregation are also
reduced by keeping a balanced mobility factor. Current production exhibits inability of
waterflooding to further recovery, while even risks flooding the production wells.

Comparing the oil recovered and oil in place and analyzing the remaining oil saturation led
to the conclusion that applying EOR could add another 2% to 5% to the ultimate recovery
factor, compared to existing waterflooding.
Screening and Selecting the Most Optimal EOR Method for Miocene Su Tu Den
Based on previously published data on EOR projects around the globe, Tabek’s work
on EOR screening criteria, and Miocene Su Tu Den reservoir fluids properties, the authors
made the decision to rely on 9 main criteria to justify the selection of Water-Alternating-Gas
for this reservoir (Table 2.3).
Table 2.3. Reservoir Properties and Criteria for Gas Injection for Lower Miocene Zone,
South-West Su Tu Den
No.
1
2

Reservoir Properties
Oil Gravity (oAPI)
Reservoir Pressure (psia)

Lower Miocene,
Su Tu Den
35,4
2.495

Criteria for Gas
Injection
> 31
> 1.030

Evaluation
Passed

Passed


11

4
5
6
7
8

Reservoir Temperature
(C)
Depth (m)
Oil Viscosity (cP)
Oil Saturation (%)
Permeability (mD)
Reservoir Structure

9

Production System

3

100

> 32

1.700-1.745

0,75-0,77
30
7.000
Closed
Separation and
treatment for gas

> 650
> 0,1
> 25
>5
Closed
Separation and
treatment for gas

Passed
Passed
Passed
Passed
Passed
Passed
Passed

Su Tu Den’s rock and reservoir properties were also imported into specialized
software to assess their impacts and contributions to the selection of the optimal EOR
method. The software’s recommendation is shown in figure 2.5 and figure 2.6 below.
Results pointed out that both chemical EOR and gas injection were suitable methods.
Immiscible gas injection had up to 83% success rate and chemical EOR (Surfactant, ASP,
Micellar) had up to almost 100% success rate. However, as pointed out earlier in this report,
chemical methods would be subjected to many challenges when executing in Miocene’s

conditions, given the high pressure, temperature, and chemical affinity of reservoir
brine/injected water. These factors would increase the project’s cost and risk, as chemicals
might degrade rapidly. From figure 2.6, it was also apparent that with reservoir temperature
above 200oF (93oC), chemical injection was relatively risky. In the case of Miocene Su Tu
Den, average reservoir temperature was already 184oF (84oC), with zones of almost 200oF
in temperature due to substantial thickness (almost 40m). Moreover, Su Tu Den was an
offshore field, so the logistical complications of transporting chemicals for injection would
also be a difficult problem to solve, especially when injecting polymer/surfactant needed
to be continuous for an extended time.

Figure 2.5: EOR Screening Results from
Specialized Software for Miocene

Figure 2.6: EOR Selection Criteria from
Specialized Software for Miocene

Water-Alternating-Gas remained the most suitable EOR method for Miocene
reservoir, Su Tu Den, at this time. The injected gas would be sourced from producing gas
of the same oil field. One big advantage of Water-Alternating-Gas was that there existed
an abundant supply of producing gas and natural gas in Su Tu Den and Su Tu Trang. The


12

production network between these fields was all operated by the same operator, CLJOC,
making it easy to divert and distribute the needed gas for Water-Alternating-Gas injection
in Miocene.

CHAPTER 3: BUILDING A SIMULATION MODEL FOR PREDICTING
AND OPTIMIZING WATER-ALTERNATING-GAS PERFORMANCE IN

MIOCENE RESEVOUR, SU TU DEN
Analyze and Evaluate MMP Experiment for Miocene Oil and Gas Sample
Production gas from well SDSW and Slimtube experiment was designed as followed:
- Sand pack length (m): 12.19;
- Inner diameter (mm): 3.68;
- Packing material: Quartz; Slimtube
porosity: 37.10%;
- Slimtube pore volume (PV, cm3):
80.41;
- Slimtube permeability (mD): 6,000.
- Injecting Pressure (psia): 8,000; 7,000;
6,000; 5,000; 4,000; 3,000.
- Total volume of injected gas is 1.4 PV.
Figure 3.1: MMP Estimation Experimental
Result with Different Injection Pressure
Experimental results showed that miscibility could be achieved with injection pressure
above 5,300 psia; below this point is near-miscibility and immiscibility.
This

experiment

setup

could

not

simulate

changes

in

miscibility/near-

miscibility/immiscibility along the longitudinal or the cross-sectional direction of the
Slimtube. Fluid composition inside the Slimtube was also unchanged, which was not
presentative of what would happen on the field. The flow of fluid inside the Slimtube was
also different from how it was inside the reservoir. Permeability and porosity of the Slimtube
setup, which was built from Quartz particles, were not of similar values to those found in the
reservoir of interest, making the estimated MMP inaccurate. In order to address these
problems, the authors developed a numerical simulation model that could predict the MMP
to a higher degree of accuracy, then applied it to the reservoirs of Cuu Long basin.
1. Built a PVT model for the reservoir fluids and injection gas of well SD-2X;
2. Utilized the equations of state (EOS) and phase diagram of the reservoir fluids and
injection gas of well SD-2X to estimate the MMP using specialized software;
3. Developed a Slimtube numerical simulation for Miocene Su Tu den;
4. Made necessary changes to optimize this MMP determination model for the best
accuracy possible;


13

5. Validated the numerical model by cross-checking its estimated MMP from with that
from Slimtube experiment;
6. Utilized the Slimtube model and PVT model to evaluate different MMP of different
injection gases at various pressures;
7. Picked the optimal gas composition for injection and injection pressure and evaluate
its efficiency on Miocene model.
Reservoir Fluids PVT Model and MMP Prediction Model

3.2.1. Reservoir Fluids PVT Model for Well SD-2X
The PVT model reproduced experimental results under field pressure, temperature,
and volume. This process used equations of state to calculate and adjust the physical and
chemical properties to match results from experiment.
3.2.2. Utilizing EOS to Estimate MMP for Different Injection Gas Composition
The miscibility mechanism of two phases is divided into the displacement part and the
mixing part. The condition for miscibility could be determined through a three-phase
diagram with the assumption that properties of all three pseudo-component remained
completely unchanged during mixing. This assumption was one of the biggest weaknesses
of basing our analysis on the three-phase diagram (figure 3.3).

Figure 3.3: Three-Phase Diagram

Figure 3.4 : STD Three-Phase
Diagram

Utilizing Miocene’s reservoir fluids and injection gas’ PVT model, equations of state,
and phase diagram, MMP, FCM (First Contact Miscible), and MCM (Multiple Contact
Miscible) were determined. Figure 3.4 shows the three-phase diagram of Miocene oil with
the dots being current temperature and pressure in the reservoir.
➢ Scenario 1: using dry gas or commercial gas, simulation model showed FCM to be
7,340 psia and MCM to be 7,305 psia.
➢ Scenario 2: using second stage separator gas, simulation model showed FCM to be
5,838 psia and MCM to be 5,542 psia.
➢ Scenario 3: using first stage separator gas, simulation model showed FCM to be 4,758


14

psia and MCM to be 4,510 psia.

➢ Scenario 4: using gas before entering the separator, simulation model showed FCM to
be 3,991 psia and MCM to be 2,004 psia.
➢ Scenario 5: using inert gases such as N2 or CO2, simulation model showed miscibility
could not be achieved.
3.2.3. Developing a Slimtube Simulation Model for Miocene Su Tu Den
This Slimtube model was built in the form of grid blocks to simulate the injection of
gas into the oil reservoir. This model was designed to have its configurations and properties
similar to those of the Slimtube in laboratory described above. Initial condition for all grid
blocks were set to reservoir pressure and temperature condition. The oil and gas mixture in
the first block would move and change its composition. It would continue move to the next
block and mix with the original oil there, before repeating the moving and mixing process
again. This would taken place repeatedly and continuously from the injector to the producer.
This model was able to address the drawbacks of the Slimtube experiment described earlier
and to give a more accurate MMP prediction for Miocene oil and reservoir conditions, with
different injection gases.
Slimtube simulation results
Injection simulations were run at 184oF and pressure between 1,000 and 7,000 psia.
➢ Case 1: using dry gas or commercial gas as injection gas, the simulation model
predicted the oil recovery factor and MMP of approximately 6,000 psia.
➢ Case 2: using second stage separator gas, the simulation model predicted the oil
recovery factor and MMP of approximately 4,500 psia.
➢ Case 3: using gas before entering the first stage of the separator, the simulation model
predicted the oil recovery factor and MMP of approximately 2,500 psia. This MMP value
was quite similar to the reservoir pressure.

Figure 3.5: Oil Recovery
from Slimtube Simulation for
MMP Estimation of Case 1

Figure 3.6: Oil Recovery

from Slimtube Simulation for
MMP Estimation of Case 2

Figure 3.7: Oil Recovery
from Slimtube Simulation for
MMP Estimation of Case 3


15

The Slimtube simulation was able to distinguish between miscibility and nearmiscibility, from which an accurate MMP estimation in presence of flow and compositional
changes could be achieved. At the end of the displacement process, it was observed that after
the mixing and displacing, the residual oil saturation inside the Slimtube was almost zero
(0). For the displacement process without miscibility, residual oil saturation was about 0.2.
➢ Case 4: using inert gas such as N2 or CO2 as injection gas, simulation result showed
no miscibility taken place at any pressure. N2 injection into the reservoir would be an
immiscible process.
Compare MMP from Different Prediction Methods
Experimental MMP

Table 3.1 Variation in MMP Estimation
PVT Model MMP
1-D Slimtube Model MMP

5.300 psia
Difference

7.350 psia
38.6 %

6.000 psia
13.2 %

Estimation made utilizing
laboratory Slimtube with
porosity of 37.8% and
reservoir oil and injection
gas taken from well SDSW23P

1. Error due to equation of
state at static contact
between the two phases
2. Estimation made using oil
and gas representative of the
reservoir of interest (SD-2X)

1. Variation due to changes
made to porosity to a more
consistent value with the
actual reservoir, averaging
about 30%
2. Estimation made using oil
and gas representative of the
reservoir of interest (SD-2X)

Results above proved that using simulation model to simulate Slimetube yielded
accurate MMP estimation at reservoir conditions. They also proved the effectiveness of
miscible injection over near miscible or immiscible injection.
These results also pointed out the limitations of calculating MMP using only the PVT
model. More importantly, this work was able to validate the development and application of

the numerical simulation model for the Slimtube, giving accurate MMP estimation for oil
reservoirs with different injection gases, and fully applicable for Miocene Su Tu Den.
Selection of the Gas Source and Gas Injection Scheme for Miocene Su Tu Den
From Slimtube simulation model runs, optimal usage of gas for injection was
determined. Based on Miocene’s pressure gradient with depth, porosity and permeability
distribution, and MMP estimation from Slimtube model, the authors concluded that injecting
hydrocarbon gas such as dry gas or enriched gas would not achieve miscibility, only nearmiscibility. In order to improve the efficiency of gas injection for Miocene, WaterAlternating-Gas needed to be applied. Water-Alternating-Gas would increase the downhole
pressure of injection wells, bringing the reservoir oil and injection gas closer to miscible
point. Moreover, injecting water before and after injecting gas also hinders the rapid flow of
gas, due to its low mobility factor, improving the swept efficiency of the injection process.


16

Conclusions
In this work, the authors explored and analyzed the difference in experimentally
determined MMP, MMP calculated from analyzing PVT model, and MMP estimated by
utilizing numerical simulation. The advantages and disadvantage of estimating MMP
experimentally were discussed in detail. Factors negatively influenced its outcome included
invariability of reservoir fluid composition and injection gas composition and Slimtube’s
fluid composition. Results showed that using Slimtube simulation model yielded more
accurate MMP estimation, under the reservoir properties and conditions. This simulation
model was also validated and was ready to be applied to determine the MMP for various oil
reservoirs in Vietnam with various injection gas compositions.

CHAPTER 4: APPLY WATER - ALTERNATING - GAS INJECTION FOR
MIOCENE SU TU DEN SIMULATION MODEL
Updating Simulation Model and History Matching
Miocene reservoir simulation model had 114,626 grid blocks in total, and was last
updated on 01/01/2015. Examining Miocene’s simulation model, the authors found it

successfully met the criteria needed for utilization in this research. History matching results
for Miocene, Su Tu Den was shown in figure 4.1.

Figure 4.1: Oil Saturation Distribution and History Matching Result
This model was ready and reliable for converting to a compositional model for
evaluation of different Water-Alternating-Gas injection schemes.
Converting from Black Oil Model to Compositional Model
Black oil model was not able to simulate changes in fluid composition from this grid
black to the next along the path from the injection well to the production well. However,
changes in reservoir fluid and injection gas composition would determine miscibility, near
miscibility or immiscibility. Compositional model could handle compositional and phase
changes of reservoir oil and injection gas from which more accurately reflected the fluid
mixture properties and fluid flow. History matching results was shown above and


17

difference in volume of oil in place between black oil model and compositional model is
less than 3%.
Analyzing Different Gas Injection Schemes and Sensitivity Analysis
Based on current field status, well SD-16I was in the most optimal position among
the injection wells to test gas injection and assess increase in oil recovery.
In order to evaluate how miscibility, near-miscibility, immiscibility, effectiveness of
gas injection, effect of reservoir fluid properties, injection well location affect oil recovery,
different injection and optimization schemes needed to be come up with and tested. These
different schemes are shown below in table 4.1.


18

Table 4.1: Different Gas Injection Schemes and Sensitivity Analysis
Water
Injection
Well
Water injection case: injection
water in well 27I and 16I

Gas
Injection
Injection
time
Well

27I 16I

Injecting
Injecting
Injecting Injecting Injecting Injecting
Below
Enriched
Water
CO2
N2
Dry Gas
OWC
Gas

Pressure

Injection

Volume

2023

Reservoir

14000
bbl/day

X

X

Scenario 1
Gas injection case: inject gas in
well 27I and water in well 16I
Scenario 2
Water-Alternating-Gas (WAG)
injection case: inject water in
well 27I inject gas-water
alternatively in well 16I

27I

16I

2023

Reservoir

5MMscf/day

X

X

X

27I

16I

2023

Reservoir

5MMscf/day

X

X

X

Scenario 3
WAG injection at 5 MMscf/d
case at well 16I, water at well
27I
WAG injection at 10 MMscf/d
case at well 16I, water at well

27I
WAG injection at 15 MMscf/d
case at well 16I, water at well
27I

27I

16I

3 years

Reservoir

5MMscf/day

X

X

X

27I

16I

3 years

Reservoir 10MMscf/day

X

X

X

27I

16I

3 years

Reservoir 15MMscf/day

X

X

X

27I

16I

2 years

Reservoir

X

X

X

Scenario 4
WAG injection for 2 years (5
MMscf/d) case at well 16I,
water at well 27I

5MMscf/day


19

WAG injection for 3 years (5
MMscf/d) case at well 16I,
water at well 27I

27I

16I

3 years

Reservoir

5MMscf/day

X

X

Water-Alternating-CO2
injection at 5 MMscf/d case at
well 16I, water at well 27I

27I

16I

3 years

Reservoir

5MMscf/day

X

X

Water-Alternating-N2 injection
at 5 MMscf/d case at well 16I,
water at well 27I

27I

16I

3 years

Reservoir

5MMscf/day

X

X

Water-Alternating-Dry-Gas
injection at 5 MMscf/d case at
well 16I, water at well 27I

27I

16I

3 years

Reservoir

5MMscf/day

X

X

Water-Alternating-EnrichedGas injection at 5 MMscf/d
case at well 16I, water at well
27I

27I

16I

3 years

Reservoir

5MMscf/day

X

X

X

Scenario 5
X

X

Scenario 6
X

X


20

4.3.1. Evaluation of Water Injection, Gas Injection, and Water-Alternating-Gas
Injection

- Base case water injection: inject water to maintain reservoir pressure for well SD-16I
and SD-27I with injection rate of 14,000 barrels/day.
- Scenario 1: inject gas for the entire life of well SD-16I with injection rate of 5
MMscf/day.
- Scenario 2: Inject gas and water alternatively in well SD-16I with 3 months of gas
injection (5 MMscf/day) alternating with 3 months of water injection (40,000 barrels/day).
Simulation models showed scenario 2 yielded better incremental oil recovered,
followed by gas injection then base case water injection.

Figure 4.2: Field Oil Recovery for Base
Case, Case 1, Case 2

Figure 4.3: Field Gas Production and Gas
Cumulative Production for Case 3a, Case 3b,
Case 3c

4.3.2. Evaluating and Selecting Optimal Gas and Water Injection Rate
- Scenario 3a: WAG injection with gas rate at 5 MMscf/day;
- Scenario 3b: WAG injection with gas rate at 10 MMscf/day;
- Scenario 3c: WAG injection with gas rate at 15 MMscf/day;
Simulation results showed that highest oil recovery was achieved when injecting dry
gas at 5 MMscf/day, even though the amount of gas injected was the least. This was due to
WAG injection being near-miscibility, rendering higher gas injection rate (10 MMscf/day or
15 MMscf/day) unfavorable due to not enough time for the injected gas to come into contact
and mix with oil. Gas breakthrough was apparent, with gas production rate at the producer
increased significantly at every gas injection cycle. Under the 5 MMscf/day gas injection
scenario, it took one year for the gas to reach the production well, a part of which already
mixed with the in-situ oil improving miscibility efficiency and ultimately oil recovery.
4.3.3. Evaluating Water-Alternating-Gas Efficiency at Different Injection Time
- Scenario 4a: WAG injection with gas rate of 5 MMscf/day and 2-year injection time.

21

- Scenario 4b: WAG injection with gas rate of 5 MMscf/day and 3-year injection time.
Simulation results showed that the longer the injection time, the better the improved
in ultimate oil recovery factor. Scenario 4b was effective and should be applied for well SD16I.

Figure 4.4: Field Oil Production Rate and
Cumulative Production for Case 4a, Case 4b

Figure 4.5: Field Oil Production Rate and
Cumulative Production for Case 5a, Case 5b,
Case 5c

4.3.4. Evaluating Gas Injection at Miscibility/Near-Miscibility/Immiscibility
- Scenario 5a: WAG injection using dry hydrocarbon gas;
- Scenario 5b: WAG injection using CO2;
- Scenario 5c: WAG injection using N2;
Simulation results, shown in figure 4.7, showed injecting dry gas to be most effective,
while injecting N2 or CO2 were quite similar in EOR performance. Immiscibility of injecting
N2 was clearly reflected in its EOR performance.
4.3.5. Comparing Effectiveness of Injection Schemes with Different Injection Gases
- Scenario 6a: WAG injection using dry hydrocarbon gas at rate of 5 MMscf/day;
- Scenario 6b: WAG injection using enriched gas at rate of 5 MMscf/day;
Simulation results showed injecting enriched gas yielded higher oil recovery compared
to when injecting dry gas. It was also observed that displacement efficiency of enriched gas
was better than that of dry gas, given the same reservoir fluids and conditions. Although both
scenarios were injection under MMP, efficiency still differed.

22

Figure 4.6: Field Gas Production Rate and Cumulative Gas Production for Case 6a, Case
6b
Conclusions
12 sensitive cases, evaluating the effectiveness of Water-Alternating-Gas, gas
injection at different rate or different composition methods were compared to each other and
to traditional water injection. Water injection would give relatively good ultimate oil
recovery at 34.4% (at 02/2014, water injection recovered 26.5% of oil in place) and good
swept efficiency. Examining Miocene simulation model proved that it was favorable to apply
miscible/near-miscible gas injection for EOR and that Water-Alternating-Gas was highly
suitable to the reservoir/rock structure, properties and fluid properties of Miocene Su Tu Den.
Water-Alternating-Gas had the highest EOR potential, increasing ultimate oil recovery
factor to about 36%, 2% to 5% higher than that of traditional water injection, and increasing
total oil produced to about 2 – 5 MMbbl (depending on original oil in place). Moreover, this
EOR scheme would also reduce water cut of production wells due to interruptive water
injection and reduce the risk of abandon well due to high water cut.
One of the factors hindering EOR performance of gas injection and Water-AlternatingGas injection when applying to Miocene was the current injection wells. In order to enhance
oil recovery for Miocene Su Tu Den, one of the production wells needed to be converted to
Water-Alternating-Gas injection well or one additional smart well needed to be drilled.
Numerical simulation results on Miocene Su Tu Den proved the effectiveness of
partial-miscibility of gas injection into reservoir at pressure below MMP. Results of
optimizing Water-Alternating-Gas injection rate showed that best EOR performance could
be achieved at 5 MMscf/d. Simulation model analyzing and evaluation verified that WaterAlternating-Gas was the most suitable EOR method for Miocene, Su Tu Den, both
economically and technologically.


23

CONCLUSIONS
This research explored and evaluated the application of Water-Alternating-Gas
injection for the reservoirs at Su Tu Den at near-miscibility. It analyzed the different
mechanisms of enhancing oil recovery and proved that Water-Alternating-Gas was the most
suitable EOR method for the reservoir of interest and was capable of achieving from 2% to
5% incremental oil recovered compared to traditional waterflooding. From the results
presented above, the authors came to the following conclusions:
1.

Experimental setup and results to estimate MMP in laboratory setting was assessed.

The authors also addressed the limitations of MMP estimation in laboratory environment
and by phase diagram by developing simulation model to calculate and estimate MMP
numerically in a way that reflected as accurately as possible the field conditions found in
Cuu Long basin.
This work pointed out the difference in MMP estimated through laboratory experiment,
by using PVT model, and by utilizing Slimtube numerical simulation model. Results proved
that the simulation model worked as intended and was able to accurately predict MMP for
oil reservoir and different injection gases, at reservoir conditions and properties. This method
also reduced the calculation error compared to that when using equation of state and phase
diagram to predict MMP.
2.

In this work, the authors evaluated the effects of geological structure, reservoir depth,

reservoir temperature-pressure, reservoir fluid properties, injection gas properties, flow of
fluid through the reservoir, optimization of injection process and injection gas composition,
etc… on the effectiveness of EOR process. This is coupled with evaluating the field
condition and production history of Miocene, Su Tu Den. Results showed that gas injection,
especially Water-Alternating-Gas, to be the most fitting EOR method for Miocene, Su Tu

Den.
Based on the evaluation and analytic of EOR projects around the world, the authors
selected 9 main criteria for Miocene to evaluate and select Water-Alternating-Gas as the
EOR method of choice. Both reservoir properties and production history of Miocene were
in accordance with the criteria for a successful application of Water-Alternating-Gas.
3.

The authors also built a compositional model to explore miscibility/near-

miscibility/immiscibility of dry gas, enriched gas, CO2, and N2 injection. Using this model,
it was proven that Water-Alternating-Gas was the most optimal method and gave the most
increase in ultimate oil recovery.
12 cases of gas injection, Water-Alternating-Gas injection, or gas injection at different
rates and different gas compositions were compared to each other and to traditional