POLITECNICO DI MILANO
Facoltà di Ingegneria Industriale e dell’Informazione
Corso di Laurea in Ingegneria Energetica
EXPERIMENTAL STUDY ON FOAM ASSISTED
WATER ALTERNATING GAS FOR ENHANCED OIL RECOVERY FIELD APPLICATION
Relatore: Prof. Fabio INZOLI
Co - Relatore: Ing. Leili MOGHADASI
Tutor aziendale : Dott. Martin BARTOSEK
Tesi di Laurea di:
Maria Elena SIMEONE
Matricola: 787525
Anno Accademico 2013 - 2014
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RINGRAZIAMENTI
Questa per me non è stata una semplice tesi, è stata più che altro un esperienza. Un esperienza lavorativa e di vita che porterò sempre con me. Per questo motivo ci sono molte persone a cui sento di dover dire GRAZIE.
Grazie Prof. Fabio Inzoli per avermi accolta con il sorriso dal primo giorno. Per avermi seguita e guidata in questo percorso con umiltà e fare paterno. Per aver sempre trovato il tempo per me, per i miei dubbi e le mie insicurezze.
Grazie Martin Bartosek, sei stato il mio mentore, il mio boss, un padre e il più delle volte un amico fidato. Mi hai aiutata sempre, anche quando avevi mille cose da fare, un momento per me lo trovavi. Mi hai fatta sentire a casa dal primo giorno.
Grazie a Baldo e Dario per avermi sempre supportata nella fase sperimentale. Per aver risposto sempre alle mie mille domande e curiosità e averlo fatto ogni volta con umiltà e con il sorriso. È stato un piacere lavorare con voi.
Thanks Leila, 12 months ago I met in eni a colleague. After few months that colleague became my friend and now is my sister. You supported me every time in this experience. You exhorted me to do always the best I could. You trusted in me, you prayed for me, you always helped me without asking something back. You putted all you forces in helping me with my thesis. Then, really thank you!
Grazie a Fabrizio, Martina, Mario e tutti i colleghi dei laboratori eni per avermi accolta con entusiasmo dal principio.
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Grazie Ale, per essere stato sempre al mio fianco in questa avventura. Per tutte le volte che il weekend non era il weekend, bisognava studiare, ma c’eravamo noi due e questo bastava a renderci felici. Non è stato tutto facile, ma non importava quanto io fossi arrabbiata o stressata, bastava un tuo sorriso per farmi scordare tutto. Grazie per l’amore quotidiano e incondizionato che mi regali giorno dopo giorno. Questo traguardo importante lo dedico a noi. Grazie Gigio!
Grazie mamma, da sette anni ormai 1000 km ci separano, ma per noi sono solo polvere. Non è passato giorno che non sentissi la tua voce. Mi sei stata vicina sempre, mi hai accarezzata da lontano. Tutte le volte che si è presentato un ostacolo mi hai presa per mano e lo abbiamo superato insieme. Grazie mamma, penso che non mi basterebbe tutto il tempo del mondo per ripagarti di tutto quello che hai fatto per me. Grazie Mà!
Grazie papà, per avermi sempre supportata e assecondata in ogni mia scelta. Per aver creduto in me anche quando le mie decisioni andavano contro quello che la gente credeva “giuste” per me. . Grazie Pà!
Grazie fratellino, questi ultimi anni per noi non sono stati una passeggiata ma io e te ci siamo dati la forza l’un l’altro per andare avanti. E piano piano ne siamo usciti più forti e più uniti di prima. Non so cosa abbia in serbo per noi il futuro, ma so che tu ci sarai sempre. Mentre ringrazio te non posso non ringraziare Alessandra, tu sei la mia sorellina acquisita. È sempre più raro trovare persone “limpide” come te. Grazie Ale.
Grazie Francesco e Antonietta, mi avete accolta dal primo giorno come una figlia. Avete gioito e sofferto con me, come una famiglia.
Grazie Rosalba, Francesco e alla piccola Silvietta, fratelli acquisiti e amici in questi anni. Mi avete regalato un sogno due anni fa.
Grazie ai miei amici di sempre, Andrea, Giandomenico e Fabrizio. Grazie per tutte le giornate, serate, nottate trascorse insieme. Non necessariamente a fare chissà che, semplicemente per il piacere di stare insieme. Grazie perché su di voi ho sempre potuto contare!
Grazie Anna e Peppe perché anche se siamo distanti per noi non cambia nulla. Siamo amici, è questo l’importante.
Grazie Ettore perché sono passati 14 anni e noi siamo ancora qui a raccontarci giorno dopo giorno come va.
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Grazie Francesca, sei stata la mia prima e unica vera coinquilina. In questo lungo cammino tu ci sei sempre stata. Grazie Fra per la tua amicizia sincera ed incondizionata.
Grazie Andrey, perché questa percorso l’abbiamo vissuto insieme, chi meglio di te sa quante ne abbiamo passate. Ci siamo dati forza a vicenda e tutto è passato più liscio
Grazie ai Bibliofriends, Antonio, Iacopo, Federico, Andrea, Lorenzo e Paolo. Senza di voi non avrei mai assaporato il piacere di studiare sodo finalizzato all’arrivo random della fatidica domanda “Pausa?!”. Grazie ragazzi per avermi reso le ore di studio molto più piacevoli.
Grazie Lidia. Grazie perché, anche se ci conosciamo da poco, mi sembra di conoscerti da sempre.
Grazie e tutti amici e parenti che hanno sempre creduto in me.
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CONTENTS
RINGRAZIAMENTI ........................................................................................ 3
LIST OF FIGURES ........................................................................................ 11
LIST OF ACRONYMS................................................................................... 13
ABSTRACT ................................................................................................... 15
EXTENDED ABSTRACT .............................................................................. 16
SOMMARIO ESTESO ................................................................................... 24
1 - INTRODUCTION ................................................................................ 33
1.1 Enhanced Oil Recovery (EOR) – Definition .......................................... 35
1.2 Gas injection EOR ................................................................................. 36
1.3 The aim of the thesis ............................................................................. 38
2 - DYNAMICS OF FLUIDS FLOW IN POROUS MEDIUM .................. 41
2.1 Multiphase flow and its importance in oil & gas industries .................... 42
2.2 Influence of medium and fluid properties on multiphase flow ................ 43
2.2.1 Porosity .......................................................................................... 44
2.2.2 Permeability ................................................................................... 45
2.2.3 Relative Permeability...................................................................... 48
2.2.4 Saturation ....................................................................................... 49
2.2.5 Relative permeability-saturation relationship .................................. 50
2.2.6 Wettability ...................................................................................... 51
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2.3 The displacement of fluids ..................................................................... 51
3 - FUNDAMENTALS OF WAG INJECTION ......................................... 54
3.1 Types of WAG injection........................................................................ 55
3.1.1 Miscible WAG injection ................................................................. 55
3.1.2 Immiscible WAG injection ............................................................. 56
3.1.3 HWAG ........................................................................................... 56
3.1.4 SWAG ............................................................................................ 57
3.2 Properties affecting WAG injection ....................................................... 57
3.2.1 Viscosity ........................................................................................ 58
3.2.2 Mobility and mobility ratio ............................................................. 58
3.2.3 Microscopic sweep efficiency ......................................................... 59
3.2.4 Macroscopic sweep efficiency ........................................................ 60
3.2.5 WAG parameters: Slug size, WAG ratio, WAG cycles ................... 62
3.3 Operational problems of WAG .............................................................. 63
4 - FUNDAMENTALS OF FAWAG INJECTION .................................... 67
4.1 State of art of FAWAG applications ...................................................... 67
4.2 Foam in EOR processes ......................................................................... 69
4.3 The physics of foam .............................................................................. 70
4.3.1 Foam stability and capillary pressure .............................................. 73
4.3.2 Foam generation mechanism........................................................... 74
4.3.3 The foam coalescence ..................................................................... 77
4.4 Gas mobility reduction .......................................................................... 77
5 - EXPERIMENTAL METHOD .............................................................. 80
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5.1 Fluids and chemicals ............................................................................. 82
5.1.1 WAG fluids and chemicals ............................................................. 82
5.1.2 FAWAG fluids and chemicals ........................................................ 82
5.2 Equipments ........................................................................................... 85
5.2.1 Core sample and core-holder .......................................................... 85
5.3 LPLT WAG experiment description ...................................................... 87
5.3.1 Experimental set-up ........................................................................ 87
5.3.2 Experimental procedure .................................................................. 89
5.3.3 Experimental Results ...................................................................... 90
5.4 LPLT FAWAG experiment description ................................................ 91
5.4.1 Experimental set-up ........................................................................ 92
5.4.2 Experimental procedure .................................................................. 93
5.4.3 Experimental Results ...................................................................... 94
5.5 HPHT Experimental set-up design ......................................................... 95
5.5.1 Experimental procedure ...................................................................... 97
6 - RESULTS AND DISCUSSION ......................................................... 100
6.1 Water recovery .................................................................................... 100
6.2 Pressure Drop ...................................................................................... 102
6.3 MRF.................................................................................................... 106
7 - CONCLUSIONS ................................................................................ 108
8 - BIBLIOGRAPHY .............................................................................. 110
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LIST OF FIGURES
Figure 1.1: World Annual consumption of the primary energy resources per
capita in the year 2013. The consumption is in tons oil equivalent (www.bp.com
June 2014) ...................................................................................................... 33
Figure 1.2: World Annual consumption of the primary energy in the year 2013
for different energy source .............................................................................. 34
Figure 1.3: a flow chart about the oil recovery sequences ............................... 36
Figure 1.4: contribution of gas (HC,N2 and CO2), chemical and thermal
flooding to the World’s EOR oil production .................................................... 37
Figure 2.1: Porosity schematic ....................................................................... 45
Figure 2.2: Effect of hysteresis on relative permeability. After (Bear 1972). ... 50
Figure 2.3: Schematic of miscible and immiscible flow in terms of oil recovery
....................................................................................................................... 53
Figure 3.1: Schematic representation of miscible WAG injection with carbon
dioxide ............................................................................................................ 55
Figure 3.2: Sweep efficiency schematic .......................................................... 61
Figure 3.3: Oil recovery for different WAG ratio and increasing the number of
WAG cycle ..................................................................................................... 63
Figure 4.1: differences between gas injection, WAG injection and FAWAG
injection .......................................................................................................... 70
Figure 4.2: A picture showing lamellae and plateau border of bulk foam with an
oil film (the black one) .................................................................................... 71
Figure 4.3: picture showing liquid, flowing gas and trapped gas of foam in
porous media .................................................................................................. 73
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Figure 4.4: Pressure distribution in the water phase ........................................ 73
Figure 4.5: Schematic of leave-behind mechanism showing gas invasion (A)
and foaming film (B)....................................................................................... 75
Figure 4.6: Schematic of snap-off mechanism showing gas penetrating a throat
(A) and bubble formation (B) .......................................................................... 76
Figure 4.7: Schematic of lamella division mechanism (A) and two bubbles
formation (B) .................................................................................................. 76
Figure 5.1: recipe of making 1 kg of SSW ...................................................... 82
Figure 5.2: pre-screened surfactants ............................................................... 84
Figure 5.3: ranking of surfactants from pre-screening ..................................... 85
Figure 5.4: core-sample .................................................................................. 86
Figure 5.5: schematic of pressure ports within the core-holder........................ 86
Figure 5.6: sleeve and core-holder .................................................................. 87
Figure 5.7: LPLT WAG experimental set-up .................................................. 88
Figure 5.8: WAG experimental results in terms of water recovery, inlet preeure
and outlet pressure .......................................................................................... 91
Figure 5.9: LPLT FAWAG experimental set-up ............................................. 92
Figure 5.10: FAWAG experimental results in terms of water recovery, inlet
pressure and outlet pressure ............................................................................ 95
Figure 5.11: HPHT experimental set-up ......................................................... 96
Figure 5.12: schematic of HPHT experimental sequences............................... 98
Figure 6.1: Water recovery results during core-flooding experiments ........... 101
Figure 6.2: The zoom of water production curve in the first injection cycle .. 102
Figure 6.3: Total pressure drop for each core-flooding experiments .............. 102
Figure 6.4: pressure drop into 3 different sections of the core ....................... 105
Figure 6.5: Mobility reduction factor into section 2 of the core ..................... 106
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LIST OF ACRONYMS
AOS Alfa Olefin Sulphonates
CAPB Cocoamido-Propyl Betaine
CGW Combined Gas/Water Injection
DADS Di Alkyl Diphenyl Disulphonate
EOR Enhanced Oil Recovery
FAWAG Foam Assisted Water Aletrnating Gas
FBET Fluorinated Betaine
GOR Gas Oil Ratio
HPHT High Pressure High Temperature
HWAG Hybrid Water Alternating Gas
LAS Linear Alkylbenzenesulphonates
LPLT Low Pressure Low Temperature
MMP Minimum Miscibility Pressure
MRF Mobility Reduction Factor
PV Pore Volume
SSW Synthetic Sea Water
SSWAG Selective Simultaneus Water Aletrnating Gas
SWAG Simultaneus Water Alternating Gas
WAG Water Alternating Gas
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ABSTRACT
Today, a main challenges of oil & gas industries is that the global growth of the
oil demand is starting to outpace the world’s oil production. This fact has put an
emphasis on identifying realistic solutions to meet future world energy demands.
Applying enhanced oil recovery (EOR) techniques in the existing fields is
indeed a key step to sustain the oil production level. One of the most accepted
and widely used EOR methods is gas flooding. Due to their low viscosities,
gases have high mobility which results in poor macroscopic sweep efficiency.
The injection of water after gas, helps to control the mobility of the gas and
stabilizes the displacement front. Following this idea Water Alternating Gas
injection has been conducted (WAG). This injection has also several problems,
which are early gas breakthrough and poor sweep efficiency. In recent years,
foam injection have been studied in the oil industry in order to mitigate the
negative effects on the production, due mainly to the high mobility of the gas
injected during WAG processes. This thesis has been conducted in eni E&P
LAIP laboratories. The main goal is the reduction in the gas mobility in Angolan
offshore reservoir. We performed several experiments o Foam Assisted Water
Alternating Gas (FAWAG) as an advanced EOR technique. We carried out
some preliminary tests in order to investigate the physics of foam during the
injection in the core without using oil. All the experiments have been executed
at low pressure, temperature. Also a high-pressure and temperature core flood
facility was designed to perform core experiments in presence of oil at reservoir
condition. Using results in terms of pressure drop in WAG and FAWAG
experiments, we were able to calculate the mobility reduction factor (MRF).
Considerable agreements were found between experimental result and theory.
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EXTENDED ABSTRACT
1 – Introduction
Today, a main concern of oil & gas industries is that the global growth of the oil
demand is starting to outpace the world’s oil production. This fact has put an
emphasis on identifying realistic solutions to meet future world energy demands.
Applying enhanced oil recovery (EOR) techniques in the existing fields is
indeed a key step to sustain the oil production level.
2 - Dynamics of fluids in porous medium
The study of multiphase flow in porous media is of great industrial importance.
Its applications include aquifer purification, containment of toxic and nuclear
waste, geological flows of magma, chemical reactions in catalysts, enhanced oil
recovery and the study of blood flow through capillaries.
The importance of studying multiphase flow in oil field production rises from
knowing that the reservoir rock contains two or more immiscible fluids in its
pore space. In addition, the development of an oil field often involves flooding
the reservoir rock with fluids that displace oil or gas.
Multiphase flow can be characterized by two parameters: residual saturations
and relative permeability. These parameters are the most important parameters
in reservoir engineering calculations, since they determine the rate of recovery
and ultimate recovery of displacement processes. It is important to define all the
parameters in term of rock and fluids to understand the physics of these
processes.
Porosity is the fraction of the total volume that is occupied by pore or
however void area. Total porosity (total) is relates to the total pore
volume that is filled with fluids. The interconnected pores that support
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the flow of fluids make up the effective porosity (effective) which is
numerically less than absolute porosity.
Permeability is a property of porous materials that quantifies the relative
ease with which a transporting substance can pass through the material.
The larger the permeability, the more fluid flow can be achieved through
the medium.
Darcy conducted many experiments on beds of packed sand using
different liquids, he observed the following relationship:
Saturation is defined as that fraction, or percent, of the pore volume
occupied by a particular fluid (oil, gas, or water).
Two types of fluid displacement are possible when two or more fluids in motion
occupy a porous medium:
Miscible displacement where the two fluids are completely soluble in
each other. The interfacial tension between the two fluids is zero and the
two fluids dissolve in each other.
Immiscible displacement where there is a simultaneous flow of two or
more immiscible fluids or phases in the porous medium. The interfacial
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tension between the two fluids is non-zero and a distinct fluid-fluid
interface separates the fluids within each pore.
3 - Fundamentals of WAG injection
WAG is an EOR method where water and gas injection are carried out
alternately in a reservoir for a period of time in order to provide both
microscopic and macroscopic sweep efficiencies and reduce gas override effect.
Due to their low viscosities, gases have high mobility which results in poor
macroscopic sweep efficiency. The injection of water after gas helps to control
the mobility of the gas and stabilizes the displacement front. WAG recovery
techniques combine the benefits of both water and gas injection.
The most common classification for WAG injection is the difference between
miscible and immiscible injection processes. Miscible or immiscible injections
are function of the properties of the displaced oil and injected gas as well as the
pressure and temperature of the reservoir.
During WAG injection it is important to taking into account reservoir
characteristics and fluid properties. WAG parameters and injection and
production well arrangement are two other important factors that affect the
WAG recovery process. In the following we will present some of these
parameters:
o Microscopic and macroscopic sweep efficiency, The microscopic
(displacement) efficiency and macroscopic (volumetric) sweep
efficiencies are used to measure the success of any flooding system. Are
defined as follows:
The fraction of oil that is removed from the pore spaces by the injected
fluid is referred to as the displacement efficiency, Ed:
The macroscopic sweep efficiency, Ev is the volume of the floodable
portion of the reservoir that has been contacted by the injected fluid:
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o WAG ratio, WR is defined as the ratio of injected water ( ,) to injected
gas ( , ):
An optimum value of WAG ratio allows a good mobility and thus
avoids problems caused by either an excess of water injected that may
lead to poor microscopic sweep and water tongue at the bottom of the
reservoir, or an excess of gas injected, which may rather result in a gas
tongue development (override) at the top of the reservoir and a very early
gas breakthrough
o WAG cycle, is a group of water and gas injection. The number of cycles
in the WAG injection affects the recovery of oil from a core or reservoir.
If everything else remains the same, the more WAG cycles applied, the
higher the recovery of the oil from the core or reservoir.
This injection has also several problems that are early gas breakthrough and
poor sweep efficiency. In recent years, foam injection have been studied in the
oil industry in order to mitigate the negative effects on the production, due
mainly to the high mobility of the gas injected during WAG processes.
4 – Fundamentals of FAWAG injection
At the end of chapter 3, we speak about the problems associated with WAG
injection. Foam injection can help standard WAG to solve these problems.
Foam is advantageous for controlling the mobility of gas in a porous medium. It
can be relatively cost effective considering the liquid only needs a concentration
in the order of one weight percent. Foam can reduce the effects such as
channeling, fingering, and gravity segregation by reducing the displacing fluids
mobility. It can also reduce the interfacial tension between the fluids.
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Foam is a dispersion of gas in a liquid solution. The gas is known as the
discontinuous phase, while the liquid is known as the continuous phase. Gas
bubbles are separated by thin liquid films called lamellae.
These mobility reduction mechanisms require multiple disconnected bubbles
and stable thin-liquid films between bubbles. Film stability is provided by
surfactant molecules that array themselves near gas-liquid interfaces where the
identically charged interfaces repel each other.
The mobility reduction is identified by the mobility reduction factor (MRF).
MRF is calculated from the steady-state pressure drops developed during foam
injection as follows:
ΔPfoam and ΔPno-foam are the measured differential pressure across the porous
medium with and without foam respectively in steady-state condition. An high
MRF corresponds to a strong foam
5 – Experimental method
Most of the work of this thesis is related to experimental activities which have
been carried out in LAIP laboratory of eni Company. The main objective of
performing the experiments is the evaluation of the reduction in the gas mobility
due to foam injection.
The conducted experimental procedures in this thesis are divided in different
several steps; we will introduce here only experiments that provide proper
results:
1. Designing of experimental set-up LPLT WAG injection.
2. LPLT WAG experiment.
3. Designing of experimental set-up for FAWAG injection.
4. FAWAG experiments at different surfactant concentration.
FAWAG at 2000 ppm of surfactant concentration
FAWAG at 5000 ppm of surfactant concentration
FAWAG at 10000 ppm of surfactant concentration
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5. Designing of experimental set-up for WAG and FAWAG experiment at
reservoir condition HPHT.
All the experiments were conducted at the same condition. We injected into the
core 2 PV of brine with a flow rate of 480 ml/h. Injection of 2 PV of brine is
considered as our standard which we applied it in injection of 2 PV surfactant
solution into the core to satisfy its adsorption capacity. After this we injected at
720 ml/h 1 PV of gas. Then we did others 2 cycles injecting 1 PV of brine
alternating with 1 PV of gas for a total of 3 WAG/FAWAG injections.
6 – Results and discussion
We present summaries of results in terms of MRF. This parameter gives us
important information regarding the goodness of using foam in EOR
application. MRF is the ratio between pressure drops in FAWAG experiments
to pressure drop in WAG experiment at steady-state conditions.
An important consideration, derived from the analysis of all experimental data
results, is that the section 2 is the one that better describes the process. The
section 1 is affected by inlet effect. This effect depends on the fact that two
different fluids are injected alternately into the core. The section 1 does not have
the time to adjust itself to a new regime. This also depends of the small length of
the core sample. The section 3 is affected by end effect. This effect is the
capillary end effect, is an important issue in core flood experiments, because it
can cause serious errors in the calculation of saturation and relative
permeabilities from pressure drop and production information.
Then in the following figure we will report MRF results mainly focused on the
section 2.
2
3
4
5
6
0 0.2 0.4 0.6 0.8 1 1.2
Mo
bil
ity
Re
dic
tio
n F
ac
tor,
MR
F
Surfactant Concentration, %w
MRF THIRD FAWAG CYCLE
MRF SECOND FAWAG CYCLE
MRF FIRST FAWAG CYCLE
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The figure shows that the MRF increases with increasing in surfactant solution
concentration. These three curves represent each FAWAG cycles. Looking at
the third cycle curve is easy to do an important consideration. That is, after three
FAWAG cycles the MRF rises with surfactant solution concentration. But the
slope of the curve from 2000 ppm to 5000 ppm is higher than the slope of the
curve from 5000 ppm to 10000 ppm. At this point is possible to conclude that
FAWAG injection with 5000 ppm of surfactant concentration is the best
configuration for our process.
7 – Conclusions and future challenges
Looking at MRF results is possible to observe that the trend of the MRF
obtained is in line with literature results. Then:
o By increasing surfactant concentration, the MRF will rise. Then, even if
the MRF grows with surfactant concentration, we chose 5000 ppm that
exhibit the best tradeoff between economics and efficiency.
o A surfactant solution with 10000 ppm of surfactant concentration is
convenient whenever we will decide to conduct only two FAWAG
cycles on field.
o The surfactant solution with a concentration of 2000 ppm has to be
excluded cause of its foam instability.
For futures HPHT experiments we suggest to test other surfactant screening also
evaluating some mixture of different types of surfactants. It is also important to
conduct both bulk and porous media surfactant experiments without oil and in
presence of oil. These experiments may give a useful surfactant screening
database that could be use in future application.
It is also interesting to investigate the gas mobility reduction by using miscible
injection, such as CO2 foam injection.
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SOMMARIO ESTESO
1 – introduzione
Attualmente, l’aspetto su cui si sta focalizzando sempre più l’attenzione delle
aziende che operano nel settore oil & gas, è che la domanda mondiale di petrolio
sta iniziando a superare l’effettiva capacità produttiva. Questo ha enfatizzato la
necessità di ricercare nuove soluzioni che possano soddisfare la domanda futura
di petrolio. L’applicazione di tecniche di recupero avanzato (EOR) rappresenta
la chiave per mantenere il giusto livello produttivo.
2 – La dinamica dei fluidi nei mezzi porosi
Lo studio dei flussi multifase riveste grossa importanza a livello industriale.
Diverse applicazioni riguardano purificazione di acquiferi, contenimento di
tossicità e rifiuti derivanti dal nucleare, flusso del magma terrestre, reazioni
chimiche nei catalizzatori, recupero avanzato di petrolio e flusso sanguigno.
In campo petrolifero l’importanza dei flussi multifase nasce dalla conoscenza
del fatto che le rocce serbatoio contengono all’interno dei pori due o più fluidi
immiscibili. Inoltre spesso diversi fluidi sono iniettati nel giacimento per
aumentare il recupero di olio o gas.
I flussi multifase sono caratterizzati da due parametri: saturazione residua e
permeabilità relativa.
Questi parametri sono molto importanti in quanto permettono di determinare il
fattore di recupero e capire quando i processi di spiazzamento hanno raggiunto i
risultati prefissati. È altrettanto importante definire altri parametri riferiti alla
roccia e ai fluidi che ci permetteranno di apprendere al meglio la fisica di questi
processi. Quindi nel seguito vedremo nello specifico i concetti di porosità,
permeabilità e saturazione.
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La porosità è la frazione del volume totale della roccia occupato dai
pori.
La porosità totale (totale) è relativa al volume totale dei pori occupati dal
fluido. I pori interconnessi, che vedono il flusso dei fluidi, portano alla
definizione di porosità effettiva (effettiva) che è minore della permeabilità
assoluta.
La permeabilità è una proprietà del mezzo poroso che quantifica la
facilità con cui un fluido attraversa il mezzo poroso stesso. Tanto più è
alta la permeabilità tanto più alto sarà il quantitativo di fluidi capaci di
attraversare il mezzo.
Darcy ha svolto diversi esperimenti su campioni di roccia utilizzando diversi
liquidi ed ha estrapolato la seguente relazione:
La saturazione è definita come la frazione percentuale del volume dei
pori occupata da un determinato fluido (olio, gas, acqua).
È possibile avere due tipi di spiazzamento dei fluidi, in cui due o più fluidi
occupana un mezzo poroso:
Spiazzamento miscibile, ha luogo quando due o più fluidi sono
completamente miscibili l’uno nell’altro. Le tensioni interfacciali sono
nulle e quindi i fluidi si dissolvono uno nell’altro
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Spiazzamento immiscibile, si ha quando c’è un flusso simultaneo di due
o più fluidi o fasi di uno stesso fluido nel mezzo poroso. In questo caso
le tensioni interfacciali sono diverse da zero e un’interfaccia distinta
fluido-fluido separa i fluidi nei pori.
3 – Principi fondamentali della WAG injection
La WAG injection è un metodo EOR in cui acqua e gas sono iniettati
alternativamente in una giacimento per un determinato periodo di tempo allo
scopo di migliorare l’efficienza di spiazzamento sia microscopica che
macroscopica e ridurre gli effetti di mobilità del gas. A causa della bassa
viscosità i gas hanno un alta mobilità che risulta in una bassa efficienza di
spiazzamento microscopica. L’iniezione di acqua dopo quella di gas permette di
controllare la mobilità del gas e stabilizzare il fronte di spiazzamento. Le
tecniche di WAG injection combinano entrambi i benefici derivanti
dall’iniezione di acqua e gas.
La principale classificazione per la WAG injection riguarda il tipo di processo di
iniezione; ovvero miscibile o immiscibile. Il tipo di iniezione dipende dalle
proprietà dell’olio spiazzato e del gas iniettato, oltre che da temperatura e
pressione del giacimento.
Durante la WAG injection è molto importante prendere in considerazione le
caratteristiche del giacimento e le proprietà dei fluidi. I parametri riguardanti la
WAG injection e la progettazione del pozzo produttore ed iniettore sono i fattori
fondamentali da cui dipende il processo di recupero di WAG injection. Nel
seguito vedremo solo alcuni di questi fattori, per la trattazione completa si
rimanda al capitolo 3.
o Efficienza di spiazzamento microscopica e macroscopica, l’efficienza
microscopica (o di spiazzamento) e l’efficienza macroscopica (o
volumetrica) sono utilizzate per misurare la bontà di qualsiasi sistema di
flussaggio in mezzo poroso. Sono definite come segue:
La frazione di olio rimossa dai pori a seguito dell’iniezione di un fluido è
definita come efficienza di spiazzamento, Ed:
27
L’efficienza di spiazzamento volumetrica, Ev il volume della porzione di
giacimento in cui è possibile l’iniezione che viene a contatto con il fluido
iniettato.
o WAG radio, WR è definito come il rapporto tra la portata di acqua iniettata
( ,inj) e la portata di gas iniettata ( , ):
Un valore di WAG ratio ottimale è necessario per raggiungere una buona
mobilità. Inoltre è possibile evitare problematiche relative all’iniezione
di un quantitativo eccessivo di acqua come, ad esempio, la riduzione
dell’efficienza di spiazzamento microscopica. Al contrario un eccessivo
quantitativo di gas porterebbe ad breakthrough del gas troppo veloce che
lo porterebbe ad affiorare precocemente in testa pozzo.
o Cicli di WAG, rappresentano gruppi di iniezione alternata di acqua e gas.
Il numero dei cicli dei WAG è importante perché determina il recupero
finale di olio. Infatti all’aumentare del numero di cicli di WAG il
recupero di olio finale aumenta.
La WAG injection ha però alcuni problemi tra i quali i più importanti sono, il
prematuro breakthrough del gas e la bassa efficienza di spiazzamento.
Negli ultimi anni ha preso piede l’iniezione di schiume che permettono la
riduzione della mobilità del gas.
28
4 – Principi fondamentali della FAWAG injection
Alla fine del capitolo precedente abbiamo visto come alla WAG injection
conseguano delle problematiche che l’iniezione di schiuma può risolvere.
L’utilizzo di schiume è vantaggioso in processi che prevedono il controllo della
mobilità in mezzo poroso.
La schiuma è generata dalla dispersione di gas all’interno di un liquido. Un
tensioattivo è utilizzato per vincere le tensioni interfacciali del liquido e
permettere al gas di entrare e quindi formare le bolle. Il gas è la fase discontinua,
mentre il liquido è definito come la fase continua. Le bolle sono tra loro separate
da un film sottile di liquido chiamato lamella.
Il meccanismo di riduzione della mobilità richiede la formazione di bolle
multiple disconnesse e un film di liquido stabile tra le bolle. La stabilità del film
dipende dalle molecole di tensioattivo the si dispongono lungo l’interfaccia
liquido-gas.
La riduzione di mobilità è identificata dal fattore di riduzione della mobilità,
ovvero l’MRF definito come segue:
I ΔPcon schiuma e ΔPsenza schiuma sono le differenze di pressione misurate a cavallo
del mezzo poroso con e senza schiuma, in condizioni stazionarie. Un alto MRF
corrisponde ad una schiuma solida e stabile.
5 – Metodo sperimentale
La maggior parte del lavoro presente in questa tesi è relativo all’attività
sperimentale svolta presso i laboratori LAIP di eni E&P. Lo scopo principale
dell’attività è stato lo svolgimento di flussaggi in mezzo poroso in assenza di
olio, al fine di valutare la riduzione della mobilità del gas a seguito
dell’iniezione di schiuma.
Sono stati svolti sia esperimenti di WAG injection che di FAWAG injection per
essere capaci, alla fine, di calcolare il MRF. Diversi esperimenti sono stati
condotti ma nel seguito verranno riportati ed analizzati solo gli esperimenti che
hanno fornito risultati utili:
29
1. Designing del set-up sperimentale della WAG injection a bassa P e bassa
T (LPLT).
2. Esperimenti LPLT WAG injection.
3. Designing set-up sperimentale LPLT FAWAG injection.
4. Esperimenti LPLT FAWAG injection a diverse concentrazioni di
tensioattivo.
FAWAG ad una concentrazione di tensioattivo di 2000 ppm
FAWAG ad una concentrazione di tensioattivo di 5000 ppm
FAWAG ad una concentrazione di tensioattivo di 10000 ppm
5. Designing del set-up sperimentale per WAG e FAWAG injection alle
condizioni di giacimento ovvero alta pressione ed alta temperatura
(HPHT)
Tutti gli esperimenti sono stati svolti allo stesso modo e nelle stesse condizioni
operative. A seguito di diversi esperimenti fini alla preparazione dell’impianto e
alla caratterizzazione della roccia sono stati iniettati 2 PV di soluzione acquosa e
successivamente 1 PV di gas. Questo rappresenta il primo ciclo di
WAG/FAWAG injection. Gli altri due cicli sono stati svolti iniettando
alternativamente 1 PV di soluzione acquosa e 1PV di gas. Il fatto di aver
iniettato nel primo ciclo 2 PV di soluzione acquosa è dovuto al fatto che il
tensioattivo tende ad adsorbirsi sulla roccia e, a seguito di esperimenti
sull’adsorbimento, si è scelto di sacrificare 1 PV iniziale per questa
problematica. Sebbene nell’esperimento di WAG injection ovviamente non ci
sia il problema dell’adsorbimento, abbiamo deciso di iniettare comunque 2 PV
iniziali per essere esattamente nelle stesse condizioni sperimentali.
30
6 – Analisi dei risultati
In questa sezione vedremo esclusivamente i risultati in termini di MRF, per tutti
i risultati sperimentali si rimanda al capitolo 6. Questo parametro da
informazioni fondamentali riguardanti la bontà dell’uso di schiuma in
applicazioni di recupero avanzato EOR. Si ricorda che l’MRF è dato
sostanzialmente dal rapporto tra le differenze di pressione lungo la carota negli
esperimenti di FAWAG injection e quelle relative alla WAG injection.
La carota utilizzata in fase sperimentale è divisa in 3 sezioni diverse e per
ognuna delle quali è stato possibile rilevare le differenze di pressione.
Un importante considerazione, derivante dall’analisi dei risultati sperimentali, è
che la seconda sezione della carota (la centrale) è quella che meglio descrive il
processo. La prima sezione risente degli effetti di imbocco dovuti al fatto che
due fluidi diversi sono iniettati alternativamente nella carota. In questo modo la
prima sezione non riesce a raggiungere uno stato stabile. L’ultima sezione
risente, invece, degli effetti di uscita dovuti essenzialmente alle pressioni
capillari.
Nella figura seguente viene presentato l’andamento dell’MRF nella sezione 2 al
variare della concentrazione di tensioattivo e del ciclo di FAWAG/WAG.
2
3
4
5
6
0 0.2 0.4 0.6 0.8 1 1.2
Mo
bil
ity
Re
dic
tio
n F
ac
tor,
MR
F
Surfactant Concentration, %w
MRF THIRD FAWAG CYCLE
MRF SECOND FAWAG CYCLE
MRF FIRST FAWAG CYCLE
31
La figura mostra chiaramente che, guardando al terzo ciclo, l’MRF aumenta
all’aumentare dalla concentrazione di tensioattivo. D’altro canto, prestando
attenzione al coefficiente angolare della curva, si nota come quest’ultimo sia
maggiore nel range tra 2000 ppm e 5000 ppm che in quello tra 5000 ppm.
7 – conclusioni e sviluppi futuri
Prestando attenzione al MRF è stato possibile stilare le seguenti considerazioni:
o Nell’ottica futura di implementare tre cicli di iniezione, la soluzione
migliore, in termini di miglior trade-off tra efficienza e costi, è quella a
5000 ppm di concentrazione di tensioattivo
o Un soluzione con concentrazione di tensioattivo di 10000 ppm può
trovare applicazione in un ottica futura di limitare i cicli di iniezione a
due.
o La soluzione di tensioattivo a 2000 ppm è da escludere in quanto porta
alla generazione di una schiuma debole e completamente instabile.
Per il futuro sono già in programma esperimenti ad alta pressione ed alta
temperatura in presenza di olio. Per questi esperimenti un suggerimento
potrebbe essere quello di svolgere uno screening più accurato dei tensioattivi in
modo tale da creare un database interno consultabile in future applicazioni.
Un'altra idea è quella di valutare, oltre ai singoli tensioattivi, un eventuale
miscela di questi ultimi per meglio rispondere alle esigenze del singolo
giacimento in cui l’applicazione FAWAG verrà implementata.
Un ulteriore ed interessante studio futuro potrebbe essere l’implementazione di
una FAWAG injection che sfrutta un gas miscibile come ad esempio la CO2.
32
33
1 - INTRODUCTION
The OPEC World Oil Outlook provides projections for the medium-term (to
2018) and long-term (to 2035) on an annual basis for oil demand and supply. It
demonstrates that fossil fuels will continue to play a major part in satisfying the
world’s growing energy needs.
World primary energy consumption, including oil, natural gas, coal,
hydroelectricity, nuclear and renewable energies, grew by 5.6% due to the
economic recovery in 2010 (www.bp.com June 2011). In 2013 energy
consumption grew by 2.3% (www.bp.com June 2014) reaching record levels for
every fuel type except nuclear power (Figure 1.1).
Figure 1.1: World Annual consumption of the primary energy resources per capita in the year
2013. The consumption is in tons oil equivalent (www.bp.com June 2014)
34
As shown in Figure 1.2, oil remains the world’s leading fuel, accounting for
33% of global energy consumption in 2012 followed by coal at 30% and gas at
24%.
Today, a main concern is that the global growth of the oil demand is starting to
outpace the world’s oil production. In 2013, the rate of growth of the oil demand
was 1.4%, which is higher than the increase in the global oil production for just
0.6% (www.bp.com June 2014). These figures cause concern how we can meet
the world’s oil demand in the coming years. The official reports state that most
of the thirty giant oil fields, accounting for half of the world's oil reserves, are
becoming mature and are experiencing a decline in oil production. It is
estimated that the reserves in sandstone and carbonate fields have respectively
around 20 and 80 years of production time left at the current production rates.
Moreover, the probability of new oil discoveries to replace the produced
reserves has gotten smaller in the last decades. The discovery rate of the giant
oil fields peaked in the late 1960s and early 1970s, but declined remarkably
Figure 1.2: World Annual consumption of the primary energy in the year 2013 for different
energy source
33%
24%
30%
4%7%
1%0% 1%
0%Oil
Gas
Coal
Nuclear
Hydro
Wind
Solar
Geothermal & Biomass
Biofuels
35
afterwards. Most likely, new large oil fields will be discovered in deep offshore
or in difficult-to-produce or environmentally sensitive areas, which eventually
will lead to new oil barrels becoming more expensive. These facts have put an
emphasis on identifying realistic solutions to meet future world energy demands.
Applying enhanced oil recovery (EOR) techniques in the existing fields is
indeed a key step to sustain the oil production level.
1.1 Enhanced Oil Recovery (EOR) – Definition
Typical crude oil recovery involves primary, secondary, and tertiary, or EOR
processes. In the primary recovery process, crude oil is produced by means of
the pressure differential between the high pressure reservoir and atmospheric
pressure above ground. Generally, primary production is followed by secondary
recovery techniques, which include water-flooding and pressure maintenance. It
is estimated that a recovery of 35% to 50% original oil in place can be achieved
by waterfl-ooding.
EOR is typically defined as oil recovery by the injection of materials not
normally present in the reservoir (Lake 1989). The focus of the process is on the
rock-oil-injectant system and on the interplay of capillary and viscous forces.
The goal of any EOR process is to mobilize remaining oil. This is achieved by
enhancing oil displacement and volumetric sweep efficiencies. Oil displacement
efficiency is improved by reducing oil viscosity or by reducing capillary forces
or interfacial tension. Volumetric sweep efficiency is improved by developing a
more favorable mobility ratio between injectant and oil remaining in the
reservoir.
In the following figure 1.3, there is a flow chart about the oil recovery sequences
36
Common EOR techniques include: Gas injection, chemical injection and
thermal recovery methods, among other innovative techniques such as microbial
and nanoparticle injection.
1.2 Gas injection EOR
One of the most accepted and widely used methods is gas flooding (Orr Jr
2007). Common gases include hydrocarbon gas, nitrogen and carbon dioxide. Its
use is mainly influenced by its availability in the field. Fig 1.4 shows that in
2010 the contribution of gas (HC, N2 and CO2) flooding to the World’s EOR oil
production was 39%.
Figure 1.3: a flow chart about the oil recovery sequences
37
The basic mechanism to increase oil recovery by gas flooding is a better
microscopic sweep efficiency compared to water flooding, leading to a further
reduction in residual oil saturation by gas (Lake 1989). Gas flooding EOR is
based on viscosity reduction and swelling of oil phase as well as lowering of
interfacial tension between oil and the displacing phase. It’s common to divide
gas EOR methods into miscible and immiscible floods. In miscible flood the
injected gas forms a single phase with oil and immiscible floods in which only
part of the injected gas dissolves in oil.
The problem of gas flooding EOR process is the adverse mobility ratio (Koval
1963, Wellington, Vinegar et al. 1988, Rao 2001, Farajzadeh, Andrianov et al.
2010). The gas has a very low viscosity compared to water and oil at the
reservoir conditions this means that the mobility of the injected gas is much
higher than that of the displaced oil. This cause instability in the gas front, the
growth of gas fingers through the oil, eventually reaching the production well,
and premature gas breakthrough.
All above mentioned behaviors contribute to poor volumetric sweep efficiency
during the gas EOR process and ad a direct effect a large amount of oil
remaining untouched.
Figure 1.4: contribution of gas (HC,N2 and CO2), chemical and thermal flooding to the World’s
EOR oil production
38
The WAG was originally proposed as a method to improve sweep of gas
injection, mainly by using the water to control the mobility of the displacement
and to stabilize the front. Since the microscopic displacement of the oil by gas
normally is better than by water the WAG injection combines the improved
displacement efficiency of the gas flooding with an improved macroscopic
sweep by the injection of water (Christensen, Stenby et al. 1998). This has
resulted in improved recovery (compared to a pure water injection).
WAG process is good but limited in applicability because water is also quite
mobile. The use of foam for mobility control shows considerable promise
(Patton, Holbrook et al. 1983). Foam injection can solve gas mobility control
problems by delaying early gas breakthroughs, reducing Gas Oil Ratio (GOR)
and store more gas in reservoirs building a bank behind oil (Skauge, Aarra et al.
2002, Spirov, Rudyk et al. 2012).
This advanced EOR technique is called Foam Assisted WAG (FAWAG), in fact
a surfactant solution is used instead of water to generate foam and improve gas
mobility control.
1.3 The aim of the thesis
This thesis has been conducted in eni E&P LAIP laboratories. The main goal is
the reduction in the gas-oil ratio (GOR) Angolan offshore reservoir. In this
reservoir the GOR is too high and this situation could reduce the production life
of the field. For this reason eni proposed a study about the reduction in gas
mobility using foam injection. For this, we improved an advanced EOR
technique that is the Foam Assisted Water Alternating Gas (FAWAG). In this
kind of process the foam helps the standard WAG by delaying gas breakthrough
and improving the sweep efficiency of the recovery process.
39
In the following, an outline of the thesis organization is provided.
Chapter 2, a review is given of some of the basic dynamics of fluids in porous
media. In particular we present about multiphase flow and its importance in
oil&gas industries. Then will see properties of rocks and fluids. At the end we
will introduce the different types of fluid displacements.
Chapter 3, we focus to describe WAG injection process. We will discuss about
WAG properties and also about problems related to WAG.
Chapter 4, we will introduce the fundamentals of FAWAG injection. The state
of art of EOR technique is presented. Also we will speak about the physics of
the foam and its properties.
Chapter 5, this chapter contains all the experimental parts of this work. It is
devoted to performing different EOR technique such as WAG and FAWAG
experiments. Here we will present materials, fluids and chemicals used in each
experiment. For each experiment we will present the description of the
experiments, the experimental set-ups and the procedure. Then at the end we
will see some numerical results for each experiment.
Chapter 6, we compare the results of WAG injection experiment s with
FAWAG injection experiments. We will discuss about different behaviors of the
foam versus standard gas injection. Then we analyze all the results in terms of
water production, pressure drop and mobility reduction factor.
Chapter 7, we will conclude the work and we will illustrate some possible future
application and modification of FAWAG processes.
40
41
2 - DYNAMICS OF FLUIDS FLOW IN
POROUS MEDIUM
The study of multiphase flow in porous media is of great industrial importance.
Its applications include (Love, Coveney et al. 2001): aquifer purification,
containment of toxic and nuclear waste, geological flows of magma, chemical
reactions in catalysts, enhanced oil recovery and the study of blood flow through
capillaries. The fluids may perform a variety of different functions. For example
in oil field applications, fluids may be required not only to displace oil or gas
and transport them to the surface, but also to act as coolants and lubricants for
the drill bit. Another example of a multifunctional fluid is blood that transports
salts and sugars in solution as well as white and red blood cells in colloidal
suspension (Love, Coveney et al. 2001).
Reservoir rocks are a part of the wild category of porous materials. We can find
porous materials in every scientific and technological field, from the geology to
the medicine. Hydrocarbons are trapped in reservoir rocks. All solid and
semisolid are “porous” to varying degrees excepted for metals, some plastics,
and some dense rocks. Porous medium is a material that has to achieve both:
It has to contain small areas, called pores that are free of solids, rooted in
the solid or semisolid matrix. The pores usually contain some fluid, like
gas, water, oil, etc., or a mixture of different fluids like foams.
42
It must be permeable to a variety of fluids to allow flow; that is, fluids
should be able to come in through one face of the material and come out
on the other side. In this case one refers to a ”permeable porous
material”.
The flow of fluids through a porous material is governed by geometrical
properties such as the porosity , the connectedness and tortuosity of the pore
space, as well as properties of the fluids. The flux is proportional to the applied
pressure gradient driving the flow and the constant of proportionality is called
Darcy’s constant or the permeability k, which has the dimensions of length
squared(Friedman 1976). In the following paragraphs we will see all the fluids
flow’s parameters in detail but before we will introduce the importance of
multi-phase flow in oil & gas industries.
2.1 Multiphase flow and its importance in oil & gas industries
The importance of studying multiphase flow in oil field production rises from
knowing that the reservoir rock contains two or more immiscible fluids in its
pore space. In addition, the development of an oil field often involves flooding
the reservoir rock with fluids that displace oil or gas. Important multiphase
displacement processes in hydrocarbon reservoirs include (Marle 1981):
1. Under the effect of production (i.e pressure drawdown), water from a
neighboring aquifer may encroach into the oil reservoir.
2. Crude oil often contains dissolved gases which may be released into the
reservoir rock when the pressure decreases.
43
3. Many development techniques use the injection of a fluid (typically
water, gas or a mixture of them) into some wells to displace the oil
towards other wells.
In order to predict the behaviour in these and other cases, it is necessary to know
the governing physical laws to describe multiphase flow. However, the literature
shows that there is still no agreement on the governing equations. The lack of
fundamental knowledge about multiphase flow is due to three reasons (Van
Wachem and Almstedt 2003):
Multiphase flow is a very complex physical phenomenon, where many
flow types can occur (eg. gas/solid, gas/liquid and liquid/liquid) and with
each flow type, several possible flow regimes can exist.
The complex physical laws and mathematical treatment of phenomena
occurring in the presence of the two phases (eg. interface dynamics,
coalescence and swelling of the wetting layers) are still largely
undeveloped.
The numerics for solving the governing equations and closure laws of
multiphase flows are extremely complex. Very often multiphase flows
show inherent oscillatory behaviour that requires costly transient
solution algorithms.
2.2 Influence of medium and fluid properties on multiphase flow
Multiphase flow can be characterized by two parameters: residual saturations
and relative permeability. These parameters are the most important parameters
in reservoir engineering calculations, since they determine the rate of recovery
and ultimate recovery of displacement processes. It’ s important to define all the
parameters in term of rock and fluids to understand the physics of these
44
processes. That is, we will see in the specific porosity, permeability and
saturation.
2.2.1 Porosity
Porosity is the fraction of the total volume that is occupied by pore or however
void area. We have to distingue the pore in two big categories, interconnected or
effective pore space where there is a continuos phase within the porous medium
and noninterconnected or isolated where pores are dispersed over the medium.
As a consequence we have two main definitions in term of porosity, total
porosity and effective porosity.
Total porosity (total) is relates to the total pore volume that is filled with fluids.
In some reservoirs (shaly sands and vuggy limestones) there are a number of
isolated pores which contribute to the overall pore volume but are not
interconnected so that they do not contribute to the flow of fluid through the
rock.
The interconnected pores that support the flow of fluids make up the effective
porosity (effective) which is numerically less than absolute porosity, that is, the
intercommunicating porosity excluding the pores containing irreducible
saturation(Wu and Berg 2003). Porosity can be generated by the development of
fractures, in which case it is called fracture porosity.
In the following of the thesis we will mention porosity as effective porosity.
45
For better understand the magnitude of the porosity an example could be the
sand on a beach, here the porosity is around 35-40% , going in the deep
underground the porosity is much lower, where the grains comprising the rock
have been fused together at high temperatures and pressures. In this case we are
in the range of 10-25%. Then the porosity value depends of the grains
disposition into the space. In the laboratory it’s possible to measure the
permeability directly on core samples (rock samples taken in the first step of
well drilling for laboratories tests) or estimated from so-called log
measurements, or down-hole measurements (Heslop 1975).
2.2.2 Permeability
Permeability is a property of porous materials that quantifies the relative ease
with which a transporting substance can pass through the material. The larger
the permeability, the more fluid flow can be achieved through the medium for a
given set of conditions. The earliest attempt at quantifying permeability was the
Figure 2.1: Porosity schematic
46
work of Henry Darcy in 1856. Darcy developed the first models to help our
understanding of the fluid conductivity of a porous medium. Since then his work
has been adapted and modified, but a complete universal picture remains beyond
our grasp. One of the main reasons for this is that permeability is a function of
the rock’s microscopic properties, including pore size and distribution, facies
type, shaliness and heterogeneity, such as non-connecting vugs and fractures.
Thus, permeability in a reservoir can vary from a few millidarcies (mD) to over
1000 mD within a few feet.
Darcy conducted many experiments on beds of packed sand using different
liquids, he observed the following relationship:
where:
q: average cross sectional velocity
Pin: pressure at upstream end of porous medium
Pout: pressure at downstream end Note:
μ: fluid viscosity
L: flow length of porous medium
k: absolute permeability
In SI units the unit of permeability is squared meter. In the petroleum industry,
the Darcy (D) is more convenient (since 1 D ~ 1 x 10-12
m2) the standard unit of
measure for permeability. It represents 1 cm2
of fluid with a viscosity of 1 cp
flowing through a 1 cm2 cross-sectional area of rock in 1 second under a
pressure of 1 atm per 1 cm length in the direction of flow. This intrinsic rock
property is called the absolute permeability when the rock is 100% saturated
with one fluid phase.
47
The most general formulation of the Darcy’s law including the gravity force is:
This equation is telling that the permeability of a porous medium is a tensor in
fact is the permeability tensor. If we apply a pressure gradient along the x-
direction, we can of course compute the average velocity qx, but also the
induced pressure gradients along the y- and z-directions, and the consequent qy
and qz. Obviously, for each direction we have a permeability kxx, kxy and kxz.
Darcy’s law is valid when the pressure gradient is sufficiently low, i.e. the
Reynolds number is low. We can identify a Reynolds Number for which the
relationship between the Darcy velocity and the pressure gradient begins to
deviate from linearity and thus, the permeability is not constant any more. This
is a first effect of inertia forces, but it shall not be confused with the transition
from laminar to turbulent flow, but just as a transition from Darcy to non-Darcy
flow. In particular, the Darcy’s law underestimates the pressure gradient needed
to obtain a certain flow rate. In order to take into account the inertia effects, the
Forchheimer equation has been proposed which adds a further term into Darcy’s
law.
Then it’s possible to tell that Darcy’s low is valid taking into account the
following hypothesis:
1. Reynold’s Number less than 1 (Singhal and Dranchuk 1977, Oak, Baker
et al. 1990).
48
2. Incompressible and homogenous fluids (van den Bosch and Seinfeld
1977).
3. Isotropic rock matrix (Auzerais, Ellis et al. 1990).
4. Darcy’s velocities do not change too much in the space (Bear 1972).
5. The value of the term should be more than a certain value
(Oak, Baker et al. 1990).
6. The average free path line of the fluid’s molecules is less and not
comparable with the average diameter of the pore space. So the Knudsen
Number must be less than 1 (so all the gases at low pressure are not
allowed) (Swami, Clarkson et al. 2012).
7. No chemical and physical iterations between rock and fluids (adsorption,
ionic exchange, etc.) (Allan and Mavko 2012).
8. The rock matrix does not deform (Auzerais, Ellis et al. 1990, Oak, Baker
et al. 1990).
2.2.3 Relative Permeability
Permeability is also measured in reference to a fluid phase when the rock is
saturated with a multiple-fluid phase. In a two-phase system, where fluids flow
simultaneously through the porous medium, the permeability of each fluid is
dependent on its own saturation (Muskat 1949, Dullien and Brenner
1991).Therefore the relative permeability term was introduced to relate the
effective phase permeability to the absolute permeability of a porous medium. It
is defined via Darcy’s law as follows:
49
where the subscript “p” stands for phase type, qp is the Darcy phase velocity, k
is the absolute permeability, krp is the phase relative permeability, Pp is the
phase pressure drop cross the core sample, is the phase density and g is the
gravity acceleration. The relative permeability characteristics depend on many
factors such as saturation, saturation history, wettability, capillary pressure,
initial water saturation, viscosity, pore geometry and interfacial tension. This
section discusses the influence of some of these properties on the two-phase
relative permeability.
2.2.4 Saturation
Saturation is defined as that fraction, or percent, of the pore volume occupied by
a particular fluid (oil, gas, or water). This property is expressed mathematically
by the following relationship:
Then we can obtain a saturation value for each reservoir fluids:
Where:
So: oil saturation
Sg: gas saturation
Sw: water saturation
50
Saturation, like porosity, is also a dimensionless parameter.
2.2.5 Relative permeability-saturation relationship
Relative permeability a strong function of the phase saturation. Figure 2.2 shows
relative permeability curves as obtained for different saturation histories. As the
saturation of the wetting phase increases, the relative permeability of the wetting
phase increases while that of the non-wetting phase decreases. The figure also
indicates that at some saturations (S wo & S nwo, i.e residual saturations), the
relative permeabilities are zero for wetting and non-wetting phases respectively.
This means at certain saturation, the phase becomes immobile and enhanced
techniques are required to re-mobilize the fluid and reduce the saturation.
The effect of saturation hysteresis on relative permeability shows that in a
strongly wetting system, the wetting phase relative permeability is primarily a
function of its own saturation which means the hysteresis of the wetting phase
relative permeability curves is much smaller than that for the non-wetting phase
(Figure 2.2).
Figure 2.2: Effect of hysteresis on relative permeability. After (Bear 1972).
51
2.2.6 Wettability
Wettability is the tendency of a fluid to spread or adhere to a solid surface in the
presence of other immiscible fluids. In the flow of two immiscible fluids in a
porous media, wettability is the tendency of one fluid to adhere to the surfaces
of the porous medium in the presence of the other fluid(Donaldson and Tiab
2004). It is important to note the wettability of reservoir rocks to the fluid
because the way fluids are distributed in the porous medium depends on
wettability. For instance, the wetting phase tends to filled up the smaller pores
while the non-wetting phase occupies the bigger pores (Ahmed and McKinney
2005). The distribution of the fluids will affect the recovery of the oil. When the
surface of the rock is water wet in a brine-oil reservoir, the water will tend to
occupy the smaller pores and wet the surface of the bigger pores. By occupying
the smaller pores, the water will force the oil from those pores. If however the
rock surface is oil wet, the oil will adhere to the smaller pores by displacing the
water. In such a case, recovering the oil will be difficult (Donaldson and Tiab
2004).
2.3 The displacement of fluids
Two types of fluid displacement are possible when two or more fluids in motion
occupy a porous medium (Bear 1972):
Miscible displacement: where the two fluids are completely soluble in each
other. The interfacial tension between the two fluids is zero and the two fluids
dissolve in each other. Therefore, in this type of displacement, there is no
capillarity; instead there is mixing (i.e. dispersion) of the two fluids. This feature
makes the miscible displacement a very efficient recovery procedure, where the
elimination of capillary forces might lead to total recovery of the displaced
phase (oil). In miscible displacement, when two fluids are in contact with each
52
other, a transition zone due to hydrodynamic dispersion is immediately created.
The compositions of the fluid vary from that of one fluid to that of the other
fluid across the zone.
Immiscible displacement: where there is a simultaneous flow of two or more
immiscible fluids or phases in the porous medium. The interfacial tension
between the two fluids is non-zero and a distinct fluid-fluid interface separates
the fluids within each pore. A capillary pressure difference exists at the interface
at each point on it. The flow of immiscible fluids in a porous medium can be
conveniently subdivided into two types: steady-state, where all the macroscopic
properties of the system are time independent at all points or unsteady-state
where the fluid and flow properties change with time.
In equilibrium steady-state flow of immiscible fluids the saturation of the
medium with respect to all fluids contained in the system is constant at all
points. Therefore, in steady-state flow there is no displacement of any fluid by
any of the other fluids in the pores. This means each fluid is flowing through its
own path without affecting on the flow of the other fluids (Figure 2.3).
However, in unsteady-state flow, the saturation at a given point in the system is
changing with time. Therefore, displacement phenomena fall into this type of
flow.
53
Figure 2.3: Schematic of miscible and immiscible flow in terms of oil recovery
As we told before the studying and understanding of multiphase flow are really
important in oil & gas field. In particular the huge context of this thesis, that is,
EOR. We already spoke before about the importance of EOR for oil & gas
industries then in the following we will see in the specific the WAG and
FAWAG processes to reduce the Gas Oil Ratio (GOR), improve the sweep
efficiency and enhance the oil production.
54
3 - FUNDAMENTALS OF WAG
INJECTION
WAG is an EOR method where water and gas injection are carried out
alternately in a reservoir for a period of time in order to provide both
microscopic and macroscopic sweep efficiencies and reduce gas override effect
(Rosman, Riyadi et al. 2011).
Due to their low viscosities, gases have high mobility which results in poor
macroscopic sweep efficiency (Hustad and Holt 1992). The injection of water after
gas helps to control the mobility of the gas and stabilizes the displacement front.
WAG recovery techniques combine the benefits of both water and gas injection.
The WAG injection results in a complex saturation pattern because two
saturations (gas and water) will increase and decrease alternately (Figure 3.1).
This gives special demands for the relative permeability description for the three
phases (oil, gas, and water) but we didn’t investigate these phenomena that are
out of the aim of this thesis.
WAG injection has been applied since the early 1960’s. Both miscible and
immiscible injections have been applied, and many different types of gas have
been used. To be correct it’s useful to know that WAG injection processes are
also called in the literature combined water/gas injection (CGW).
55
3.1 Types of WAG injection
The most common classification for WAG injection is the difference between
miscible and immiscible injection processes. Miscible or immiscible injections
are function of the properties of the displaced oil and injected gas as well as the
pressure and temperature of the reservoir (Lyons and Plisga 2004). Other less
common classifications include: Hybrid WAG injection and simultaneous WAG
injection (SWAG).
3.1.1 Miscible WAG injection
In this type of WAG process, the reservoir pressure is maintained above the
minimum miscibility pressure (MMP) of the fluids. MMP is the minimum pressure
required for miscibility to occur between two fluids. Miscibility occurs when the
two fluids mix in all proportions without the formation of interference between
Figure 3.1: Schematic representation of miscible WAG injection with carbon dioxide
56
them (Mehdizadeh, Langnes et al. 1989). If the pressure is allowed to fall below
MMP, miscibility will be lost. In the real field operation, it is often difficult to
maintain MMP and as a result there is back and forth between miscible and
immiscible WAG injection. The majority of WAG injections have been classified as
miscible and are mostly applied onshore, where wells are arranged in closed well
spacing (Christensen, Stenby et al. 2001).
3.1.2 Immiscible WAG injection
The purpose of this type of WAG injection is to stabilize the front and increase
contact with the unswept areas of the reservoir. The displacement of oil by
immiscible gas injection has higher microscopic sweep efficiency than by water.
However, the very high mobility of gas due to its low viscosity results in poor
macroscopic sweep efficiency and consequently poor recovery of oil during
immiscible gas injection. So immiscible WAG injection is applied to overcome
this problem because the water helps to control the mobility of the gas and
increase macroscopic sweep efficiency (Fatemi, Sohrabi et al. 2011). This type
of WAG injection has fewer records of field application. The experiment
performed with this study I’m going to explain is immiscible WAG and
FAWAG injection.
3.1.3 HWAG
HWAG injection has been applied during the last 30 years. This process consists in
injecting a large slug of gas followed by small slugs of water alternating gas. Even
though the results might be different, the same considerations as those reported for
traditional WAG can be applied.
57
3.1.4 SWAG
SWAG is a technique in which water and gas are co-injected into a portion or
the entire thickness of the formation, by using either a single wellbore or a dual
completion injector where the two phases enter the pore zone at different depths
(also called Selective SWAG - SSWAG). SWAG process appears to provide a
better control over the gas mobility than a traditional WAG, resulting in
improved sweep efficiency and steadiness of gas production and GOR (gas to
oil ratio) response [17]. In fact, considering that injected water and gas are at the
same pressure, the injection process seems more uniform, gravity effects are less
evident and, as a consequence, a better mobility control can be achieved.
Moreover, from a “producer” point of view, the producing gas-oil-ratio is
expected to have a smoother profile, since the presence of big slugs, which
increase the well-head pressure, are avoided. On the other hand, gas and water at
the same pressure must be injected through the well avoiding hydrates
formation. Furthermore, 1-D simulations have shown that a traditional WAG
injection has a better injectivity than a SWAG process (from 12% with small
slugs to 30% with larger slugs), especially in case of foam formation through
Surfactant-Alternating-Gas (SAG) processes (50% to 150% increase in
injectivity) because of the reduced mobility of three flowing phases – gas, oil
and water – in SWAG (Faisal, Bisdom et al. 2009).
3.2 Properties affecting WAG injection
During WAG injection it’s important to taking into account reservoir
characteristics and fluid properties (Latil 1980). WAG parameters and injection
and production well arrangement and are two other important factors that affect the
WAG recovery process. In terms of reservoir we already discuss about
reservoir’s heterogeneity, porosity, permeability, saturation and wettability.
58
Then in the following we will analyze fluid properties and behaviors, that is,
viscosity, mobility, sweep efficiency and WAG parameters.
3.2.1 Viscosity
Viscosity is the most important fluid property in EOR projects because it controls
the flow of fluids in the reservoir. It is defined as the resistance of the fluid to flow
(Ahmed 2010). The lower the viscosity of a fluid, the easier it can flow in porous
media and vice versa. The viscosity of crude oil is highly dependent on temperature,
pressure, oil gravity, gas gravity and gas solubility. If everything else remains the
same, the higher the viscosity of oil, the higher the residual oil saturation (Latil
1980).
3.2.2 Mobility and mobility ratio
The mobility of a fluid is the effective permeability of the fluid divided by the
viscosity of the fluid (Ahmed 2010). This can be expressed as:
Where:
: Mobility of oil [D/cP]
: Mobility of water [D/cP]
: Effective permeability to oil [D]
: Effective permeability to water [D]
: Relative permeability to oil [-]
: Relative permeability to water [-]
59
The mobility of the fluid (water, gas) injected WAG, affects the stability of the
displacement front, which in turn determines the volume of the reservoir to be
contacted. Adequate mobility control can lead to greater reservoir pore volume
being contacted during flooding. Contacting more un-swept zone of the
reservoir will lead to greater recovery efficiency.
The mobility ratio is the ratio of the mobility of the injecting fluid (e.g. water,
gas) to the mobility of the fluid it is displacing, such as oil (Ahmed 2010).
For the water injection:
Favorable mobility ratio (M < 1) will optimize WAG displacement. Favorable
mobility ratio can be obtained by reducing the relative permeability of the fluids
(water, gas) or increasing the gas viscosity.
3.2.3 Microscopic sweep efficiency
The microscopic (displacement) efficiency and macroscopic (volumetric) sweep
efficiencies are used to measure the success of any flooding system, be it water,
gas or WAG (Ahmed 2010). The fraction of oil that is removed from the pore
spaces by the injected fluid is referred to as the displacement efficiency.
60
Where:
Ed: displacement efficiency
Soi: initial oil saturation
Sor: residual oil saturation
Ed is bounded between 0 and 1. The rate at which Ed approaches 1 is strongly
affected by the initial conditions, the displacing agent, and the amount of
displacing agent. Fluid, rock, and fluid–rock properties also affect Ed (Lake
1989).
3.2.4 Macroscopic sweep efficiency
The macroscopic (volumetric) sweep efficiency is the volume of the floodable
portion of the reservoir that has been contacted by the injected fluid. These can
be expressed mathematically as:
The areal sweep efficiency is the fraction of the area contacted by the injected fluid
(Figure 3.2). The vertical sweep efficiency is the ratio of the sum of the vertical
height of the reservoir contacted by the injected fluid to the total vertical reservoir
height(Lake 1989).
61
The product of these two (areal and vertical sweep efficiency) gives the volumetric
sweep efficiency which is the fraction of the reservoir volume swept or contacted
by the injected water.
Where:
EV: volumetric sweep efficiency
ED: areal sweep efficiency
EI: vertical sweep efficiency
The total oil recovery efficiency, E is the product of the displacement efficiency, ED
and volumetric sweep efficiency, EV (Thakur and Satter 1998). Mathematically,
Figure 3.2: Sweep efficiency schematic
62
The recovery can be optimized by maximizing any or all of the three factors EA,
EI, ED (Christensen, Stenby et al. 2001)
3.2.5 WAG parameters: Slug size, WAG ratio, WAG cycles
These parameters are all important for effective recovery efficiency to be
achieved.
The slugs of water and gas injected must be controlled. Injecting too much
water will negatively impact the microscopic efficiency as injecting too much
gas will result to poor macroscopic sweep efficiency.
The WAG ratio, WR is defined as the ratio of injected water ( ,) to injected gas
( ,):
An optimum value of WAG ratio allows a good mobility and thus avoids problems
caused by either an excess of water injected that may lead to poor microscopic
sweep and water tongue at the bottom of the reservoir, or an excess of gas injected,
which may rather result in a gas tongue development (override) at the top of the
reservoir and a very early gas breakthrough (Arogundade, Shahverdi et al. 2013).
In field application, WAG ratio of 1:1 is the most popular (Jeong, Cho et al.
2014). Just to be clear this is a general assumption but the optimal value of WAG
ratio also depends on the gas availability and rock wettability of the reservoir
(Jackson, Andrews et al. 1985).
A WAG cycle is a group of water and gas injection. The number of cycles in the
WAG injection affects the recovery of oil from a core or reservoir. If everything
else remains the same, the more WAG cycles applied, the higher the recovery of
the oil from the core or reservoir. Figure 3.3 shows the oil recovery as a function
63
og Wag ratio and number of WAG cycles from the literature (Johns, Bermudez
et al. 2003).
3.3 Operational problems of WAG
In the production life of an oil field, some operational problems cannot be
avoided WAG injection is more demanding than a pure gas or water injection an
thus, some operational problems must be avoided during the production life of
an oil field. Most common problems in WAG applications are listed below,
following basis of operational reports of field applications (Christensen, Stenby
et al. 1998):
Early Breakthrough in Production Wells. Poor understanding of the reservoir
or an inadequate reservoir description can lead to unexpected events such as
early gas breakthrough. Several field cases report of early gas breakthrough
caused by channeling or override. These problems are difficult to solve, and the
wells are in some cases shut in long before scheduled. For offshore fields,
Figure 3.3: Oil recovery for different WAG ratio and increasing the number of WAG cycle
64
override can be very critical because the number of wells in the projects is
generally very limited.
Reduced Injectivity. Reduced injectivity means less gas or water injected in the
reservoir. This will lead to a more rapid pressure drop in the reservoir, which
again will affect displacement and production. The cause for reduced injectivity
could be a change in relative permeability owing to three-phase flow, wellbore
heating, and thereby reduced effects of thermal fractures during gas injection or
precipitates (hydrates and asphaltenes) formed in the nearwell zone. It is a
common trend that while reduced injectivity of water is observed after a gas
slug, the injectivity of the gas after a water slug generally is not a major problem
Sometimes injectivity is even increased. A more unusual injectivity increase was
found in Kelly Snyder (a carbonate reservoir), where injectivity was increased
owing to dissolved reservoir rock (Kane 1979).
Corrosion. Corrosion is a problem that must be solved in almost all WAG
injection projects. This is mainly owing to the fact that the WAG injection
normally is applied as a secondary or tertiary recovery method. The project will
then have to take over old injection and production facilities originally not
designed for this kind of injection. Only applications using CO2 as injection fluid
have reported severe corrosion problems.
Scale Formation. The occurrence of scales in WAG field trials is usually and
quite logically found when CO2 is the injected gas source. The scale formation
may stress the pipelines and can lead to failure (Brownlee and Sugg 1987).
Asphaltene and Hydrate Formation. Asphaltenes and hydrates may lead to
problems and disturbances in production. Although the problems connected with
the precipitations are the same, the factors influencing the formation are better
65
known for hydrates than for asphaltenes. Thus, hydrate formation normally can
be controller with methanol solvent treatment. In many cases, the problem could
be solved with solvent treatment at proper intervals. In a few cases wells have
been shut in, but in a majority of the cases reported production has not been
drastically influenced. The presence of asphaltenes may lead to production-
delays/stops and can thereby affect the economy of a project.
Different Temperatures of Injected Phases. It is normal that the temperatures
of the water and gas phases are different under injection. Temperature
differences because of the WAG process have resulted in stress-related tubing
failures (Wackowski and Masoner 1995).
As we saw before some of these problems could be fixed changing fluids, using
solvents etc. Other problems such as early gas breakthrough are difficult to
manage and predict in WAG processes. For this reason in this thesis we will
introduce another EOR process, substantially the aim of this work, that is,
FAWAG process. In the next chapter we will see the fundamentals of FAWAG
injection and we will explain the physics of the foam.
66
67
4 - FUNDAMENTALS OF FAWAG
INJECTION
4.1 State of art of FAWAG applications
The application of foam for mobility control was first proposed by Bond and
Holbrook (1958). Thereafter, many experimental and modeling studies have
been devoted to understand the mechanisms underlying foam mobility control.
This has been followed by many successful field applications where foam has
been mainly applied as diverting and mobility-reducing agents, for instance in
East Vacuum field in the US (Hiraski 1989, Patzek and Koinis 1990, Hoefner,
Evans et al. 1995, Patzek 1996), Oseberg and Snorre fields in the North Sea
(Aarra and Skauge 1994, Skauge, Aarra et al. 2002). In these applications gas
mobility is lowered by a greater factor in the high permeable layers compared to
the low permeable ones. The lowered gas mobility diverts at least part of the
displacing fluid into the other parts of the reservoir that are less-permeable and
have not been swept before. This leads to improvement in both vertical and areal
sweep efficiency, and thus to additional oil recovery from the unswept regions.
Until recently, experimental and modeling studies have been devoted to describe
the behavior of foam in the absence of oil, but comparatively few studies of
foam in the presence of oil have been done. There are still important and
unsolved questions regarding the stability of foam and its propagation in the
reservoirs containing oil. Available evidence resulting from the bulk foam
68
studies and full-field simulation suggests that the presence of oil can
significantly affect the success of foam-flood performance (Low, Yang et al.
1992, Schramm and Schramm 1994, Zanganeh, Kam et al. 2011). In fact, to
develop a practical foam process for a given field application where residual oil
saturation may vary from zero to 50%, any effect of oil on the behavior of foam
generation, propagation, and destruction is an important issue. Notwithstanding
the primary importance of oil on foam stability, the existing data in the literature
show a controversy about the ability of foam to generate and propagate when oil
is present in porous media. While several studies argued that the presence of oil
could be detrimental on foam stability (Minssieux 1974, Jensen and Friedmann
1987, Svorstol, Vassenden et al. 1996, Arnaudov, Denkov et al. 2001, Hadjiiski,
Tcholakova et al. 2001, Farajzadeh, Andrianov et al. 2012, Simjoo and Zitha
2013), others supported that relatively stable foam could be formed in the
presence of oil (Schramm and Schramm 1994, Mannhardt, Novosad et al. 1998,
Aarra, Skauge et al. 2002, Vikingstad, Aarra et al. 2006, Emadi, Sohrabi et al.
2011). It was found that oil saturation must be below a critical value before gas
mobility is reduced by foam (Jensen and Friedmann 1987, Svorstol, Vassenden
et al. 1996, Mannhardt and Svorstøl 1999), but this has not been supported by
other studies where the possibility of generating foam even at relatively high oil
saturation was observed (Farajzadeh, Andrianov et al. 2010, Andrianov,
Farajzadeh et al. 2012). In some studies the type of oil was found not to be crucial
for foam generation and propagation; instead the type of surfactant exhibited large
effects (Jensen and Friedmann 1987). This is not in line with other bulk and porous
media studies where foaming behavior was found to depend on the combination of
surfactant and oil types (Nikolov, Wasan et al. 1986, Raterman 1989, Vikingstad,
Aarra et al. 2006).
69
4.2 Foam in EOR processes
At the end of chapter 3 we spoke about the problems associated with many gas
injection projects, that main important are the inefficient gas utilization, poor
sweep efficiency and low incremental oil recovery due to viscous instabilities
(channeling or fingering) and gravity segregation. These are caused by rock
heterogeneity as well as the low density and viscosity of the injected gas. Foam
can be injected into the oil reservoir to mitigate these drawbacks (Blaker, Celius
et al. 1999).
Foam is advantageous for controlling the mobility of gas in a porous medium. It
can be relatively cost effective considering the liquid only needs a concentration
in the order of one weight percent. Foam can reduce the effects such as
channeling, fingering, and gravity segregation by reducing the displacing fluids
mobility. It can also reduce the interfacial tension between the fluids. Foam has
a selective property of blocking high permeable layers, which means it blocks
the high permeable (already swiped zones) layers, leading the fluid to un-swept
areas or layers. The selective property of foam targeting high permeable layers
can be very beneficial in a heterogeneous porous medium. The implementation
of foam as an enhanced oil recovery technique has been hindered because of a
lack understanding of the foams behavior in a reservoir. The effectiveness of
foam in reservoirs remains unpredictable, because of the complex nature of
foam and contradictions in foam studies. In naturally fractured reservoirs foam
can be used to create a viscous pressure drop in the fracture, which forces the
gas into the oil bearing matrix, thus accelerating oil production (Kovscek and
Radke 1994, Alvarez, Rivas et al. 1999, Farajzadeh, Wassing et al. 2010).
Figure 4.1 shows the beneficial effects of foamed gas compared to pure gas.
70
4.3 The physics of foam
Foam is a dispersion of gas in a liquid solution. The gas is known as the
discontinuous phase, while the liquid is known as the continuous phase. Gas
bubbles are separated by thin liquid films called lamellae. Foam can vary based
on multiple factors: foam quality, texture, and rheology (Marsden, Eerligh et al.
1967).
The foam quality, Γ is defined as follows:
where Vg is the gas volume and Vl is the liquid volume.
Foam is generally divided into two wide categories: foam in bulk and foam in
porous media.
Figure 4.1: differences between gas injection, WAG injection and FAWAG injection
71
In bulk foam, the size of a container is much larger than individual bubbles. This
sort of foam can be treated as a single homogeneous phase, with almost the
same velocities of liquid and gas (Calvert 1989). The thin liquid film is called
lamella (plural lamellae), which can be stabilized by the presence of surfactant
molecules. Lamellae touch each other or the solid wall at a region called a
Plateau border (Figure 4.2).
Foam disappears when lamellae break from high capillary pressure or when gas
diffuses through the lamellae, causing smaller bubbles to shrink until they
disappear. The thickness of a lamella at rest and at equilibrium is governed by
capillary pressure through the disjoining pressure (Weaire 2002), which is the
repulsion between the opposite surfaces of the lamella, caused by the presence of
surfactant (Figure 4.2).
In Porous media foam, the diameter of bubbles is comparable to or larger than
the pore size (Rossen 1992). Foam in porous media is defined as “a dispersion
of gas in a liquid such that the liquid phase is continuous, and at least some part
Figure 4.2: A picture showing lamellae and plateau border of bulk foam with an oil film (the
black one)
72
of the gas is made discontinuous by thin liquid films called lamellae” in
according to (Hiraski 1989).
Inside the rock the lamellae and its interaction with the pore walls are of central
importance when considering foam in a porous rock. There is, however, no way
to visually verify the existence of lamellae inside rock, but it can be observed
that when a gas is in contact with an aqueous surfactant solution gas mobility is
reduced (Prud'homme 1995).
Foam can also be classified as continuous-gas foam and discontinuous-gas
foam. Continuous-gas foam is one which there exist at least one pathway for gas
flow in pore network that is unblocked by lamellae. A discontinuous-gas foam is
one in which all pathway for gas flow are blocked by lamellae (Prud'homme
1995). For continuous-gas foams at low pressure gradient, gas mobility is reduced
because gas relative permeability is reduced by a fixed amount. At higher pressure
gradient lamellae are mobilized and either breaks, thereby increasing gas mobility,
or divide and reproduce, which leads to a discontinuous-gas foam of very low
mobility. There is no flow of gas at all at low pressure gradient for discontinuous-
gas foams. However, at high pressure gradient, gas may flow through some or all
pores, as all or part of trapped gas is mobilized. Thus the velocity of gas is not
proportional to pressure gradient in discontinuous-gas foam. The strongest and most
stable foam is thought to be a discontinuous-gas foam, and weak foam is associated
with continuous-gas foam (Friedmann, Chen et al. 1991)
In porous media, foam splits into liquid, flowing gas and trapped gas (Figure 4.3).
Flowing gas flows through the large pores, taking a small fraction of the liquid
along as lamellae and plateau borders; trapped gas bubbles reside in the
intermediate-size pores; and the majority of the liquid separates from the gas and
flows in the same small pores and pore corners as in conventional gas liquid flow.
Only a small amount of liquid is transported with gas as lamellae and Plateau
borders.
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4.3.1 Foam stability and capillary pressure
In porous media, foam exists as gas bubbles whose shapes conform to the solid
matrix. Each lamella contains two gas-liquid interfaces separated by the thin
film, and each lamella has a surface tension. This is the variable which is
significantly lowered when a surfactant is added to water. Moreover, in a water-
wet porous medium it is possible to notice the presence of water as both bulk
water in small pores and lamellae between gas bubbles (Figure 4.4).
Figure 4.3: picture showing liquid, flowing gas and trapped gas of foam in porous media
Figure 4.4: Pressure distribution in the water phase
74
The pressure difference between the bulk water and the gas bubble is expressed
as capillary pressure pc:
Where pg is the pressure inside the gas bubble and pb the bulk water pressure. At
equilibrium, the value of pc should be balanced by the disjoining pressure, Π:
Where h represents the film thickness and pf the average pressure inside the
liquid film. The disjoining pressure is characterized by attractive forces between
molecules, which lead to attraction between film surfaces, and repulsive forces,
due to the interaction of two same-sign charged interfaces. If Π exceeds the
maximum value Πmax, then the thickness becomes lower than its critical value
hcr and the film collapses. Then the stability of the foam is strictly dependents on
the capillary pressure, that is function of the surfactant formulation and
concentration, gas velocity, permeability of the porous medium, and presence of
oil (Khatib, Hirasaki et al. 1988).
4.3.2 Foam generation mechanism
In field applications, three different flow regimes have been encountered in
porous media and each of them results in totally different flow behaviors and
generation mechanisms (Sheng 2013):
Surface facilities and well itself, where inertial flow may create bulk
foam;
75
Near-wellbore region, where flow rates and pressure gradients are high;
Formation, far away from the injection well, where flow rates and
pressure gradients are much lower.
It is commonly accepted that, on the basis of what just said above, lamellae are
created by the three following mechanisms inside real porous media:
Leave behind
Leave-behind is a creation process that occurs in pore throats when gas enters
from separate directions in adjacent pore bodies as shown in (Figure 4.4). The
creation of leave-behind lamellae can be very effective in a three dimensional
medium, because the of many potential pore throats available for lamellae
creation. Albeit an effective creating process, leave-behind has proven not to
greatly reduce gas mobility, which means that this is a weak kind of lamellae
and a high amount of the lamellae are destroyed. Leave-behind only occurs
during a drainage process, when saturation of gas is increasing (Prud'homme
1995).
Snap-off
Surfactant solution accumulates at the pore throats and in the small pores where
the capillary pressure is higher for a water wet medium. As capillary pressure
decreases the water can bridge the gap in the pore throat and create lamellae
and is called snap-off.
Figure 4.5: Schematic of leave-behind mechanism showing gas invasion (A) and
foaming film (B)
76
For gas to enter a pore body through a pore throat it needs to exceed a certain
capillary pressure to force its way through the pore throat. When the gas enters
the pore body, the radius will increase and the capillary pressure will decrease.
This fluctuation in capillary pressure can cause a lamella to form in the pore
throat as shown in (Figure 4.5). This process is called snap-off. (Prud'homme
1995)
Division
When a lamella is pushed through a pore system it can suddenly reach a point
of several pore throats. The lamella then stretches and either breaks or makes
new lamellae in the different pore throats. The lamellae will take the path of
least resistance, which means that lamellae are created in the pores of least
resistance, forcing gas to take different paths or to displace the lamella.
(Prud'homme 1995)
Figure 4.6: Schematic of snap-off mechanism showing gas penetrating a throat (A)
and bubble formation (B)
Figure 4.7: Schematic of lamella division mechanism (A) and two bubbles formation (B)
77
4.3.3 The foam coalescence
In absence of oil, two mechanisms are mainly responsible for the foam
coalescence. Both mechanisms result in the formation of one big bubble from
two smaller bubbles which were initially occupying the pore space.
Capillary suction, Moving lamellae coalesce when they are rapidly stretched
across large pore bodies. For a given gas flow rate and capillary pressure, pore-
throats/pore-bodies combinations with large aspect ratios serve as termination
sites. Moreover, as the gas velocity or capillary pressure increases, an increasing
number of pores become termination sites (Farzaneh and Sohrabi 2013).
Gas diffusion, Gas diffusion coalescence occurs when two bubbles with
different curvatures are in contact. As the pressure on the concave side of a
curved foam film is higher than that on the convex side, gas diffuses through the
film and dissolves in the liquid present in the convex side. Thus, the gas diffuses
from smaller bubbles to less curved (bigger) ones.
While the first mechanism happens through a fast physical process, the latter
takes place through a slow diffusion process (Farzaneh and Sohrabi 2013).
4.4 Gas mobility reduction
Foam alters gas mobility in two ways. The first mechanism is associated with
moving bubbles and rearrangement of bubble interfacial area. Recall that a
lamella is a thin-liquid film that separates bubbles. Foam bubbles in porous
media are as large or larger than characteristic pore size; thus, bubbles and
lamellae completely span pores. This foam configuration is referred to as a
confined foam because of the constraining effect of the porous medium on foam
structure. Confined gas bubbles transport by sliding over lubricating liquid films
that coat pore walls and liquid-filled pore corners. At low bubble velocities
78
characteristic of flow in porous media, the pressure drop to drive a bubble at a
constant velocity exceeds that of an equivalent volume of liquid, thereby
increasing the effective viscosity of the gas phase. Additionally, surfactant
movement from the front of a moving bubble to the rear induces a
surface-tension gradient that slows bubble motion and so increases the effective
viscosity.
The second mechanism that reduces gas mobility is trapping of the gas phase.
The fraction of gas that is stationary in a foam is quantifiable using gas-phase
tracers. The most important factors governing bubble trapping include pressure
gradient, pore geometry, and foam texture; however, the dependence of trapped
fraction on these factors is not established. The fraction of trapped gas increases
slightly with gas velocity at a constant gas fractional flow. On the pore level, gas
flowing in the form of foam tends to flow through the high permeability and
high porosity zones.
These mobility reduction mechanisms require multiple disconnected bubbles
and stable thin-liquid films between bubbles. Film stability is provided by
surfactant molecules that array themselves near gas-liquid interfaces where the
identically charged interfaces repel each other. Foam films are meta-stable as
opposed to thermodynamically stable. The surfactant induced stabilizing forces
are sensitive to surfactant concentration, surfactant structure, and to ionic
strength of the aqueous solution (Apaydin and Kovscek 2000).
The mobility reduction is identified by the mobility reduction factor (MRF)
(Kovscek and Radke 1994). MRF is calculated from the steady-state pressure
drops developed during foam injection as follows:
79
ΔPfoam and ΔPno-foam are the measured differential pressure across the porous
medium with and without foam respectively in steady-state condition. An high
MRF corresponds to a strong foam (Vikingstad and Aarra 2009).
80
5 - EXPERIMENTAL METHOD
Most of the work of this thesis is related to experimental activities which have
been carried out in LAIP laboratories of eni E&P. The main objective of
performing the experiments is the evaluation of the reduction in the gas mobility
due to foam injection. We started the experiments by performing some
preliminary tests in order to investigate the physics of foam during the injection
in the core without using oil. All the experiments have been executed at low
pressure, temperature. Also a high-pressure and temperature core-flooding
facility was designed to perform core experiments in presence of oil at reservoir
condition. As it is mentioned before, the MRF is the ratio between foam
pressure drop in the FAWAG experiment to the water pressure drop in the WAG
experiment. WAG and FAWAG have been performed to determine the MRF at
the same condition in terms of temperature, pressure, chemicals, core properties,
gas flow rate, brine flow rate, pore volume and numbers of WAG cycles.
The conducted experimental procedures in this thesis are divided in different
steps, such as:
1) Designing of experimental set-up for low pressure (LP) and low
temperature (LT) for WAG injection.
2) WAG experiments at high gas flow rate, LP and LT to understand the
behavior of the equipment with WAG injections.
3) Experiments for the evaluation of gas and brine permeability.
4) WAG experiment at low gas flow rate, LP and LT to be able to calculate
the MFR.
81
5) Designing of experimental set-up for FAWAG injection.
6) Screening and choosing of the best surfactant from a list of candidate.
7) FAWAG experiments at different surfactant concentration.
8) Designing of experimental set-up for WAG and FAWAG experiment at
reservoir condition high pressure (HP) and high temperature (HT).
In the following we will see in the specific only experiments that provide useful
results. That is, WAG LPLT, surfactant screening, FAWAG LPLT, WAG and
FAWAG HPHT experimental set-up designing.
Before starting we will introduce the concept of pore volume (PV) about of we
will speak often in the following.
The PV has not to be confused with porosity although it depends on porosity. A
PV is a dimensionless parameter often used to interpret porous media injection
data. In graphical representation of data is used instead of time like independent
variable (x axis). It represents how much times, during the injection, the total
volume of the pore is occupied by the fluid. For example, 3 PV injected means
that the fluids were injected with an amount that is 3 times the volume of the
pore.
Where Q is the flow rate, t is the time and is the porosity of the core.
82
5.1 Fluids and chemicals
5.1.1 WAG fluids and chemicals
Fluids in WAG experiments consist of Nitrogen gas with a purity of 99.98% and
Synthetic Sea Water (SSW) as brine. SSW is obtained mixing distilled water
with salts and chemicals that are, NaCl, CaCl2, KCl, MgCl2∙6H2O, Na2SO4
and sodium azide (NaN3). Sodium azide it’s important to prevent the formation
of bacteria into the core. Figure 5.1 lists the recipe of making 1 kg of SSW.
Figure 5.1: recipe of making 1 kg of SSW
5.1.2 FAWAG fluids and chemicals
Fluids in FAWAG experiments consist of Nitrogen gas with a purity of 99.98%
and SSW mixed with different surfactants concentration to obtain a surfactant
solution.
The main objective of FAWAG chemicals are surfactants and their screening.
We selected surfactants from literature for the LPLT experiments. Another eni
laboratories is conducting accurate surfactant screening to select the best
surfactant mix for HPHT experiments.
The purpose of pre-screening was to evaluate and select suitable surfactants for
the project from a wide range of potential candidates figure 5.2, based on their
foamability in static bulk tests, compatibility with brine (solubility), adsorption
and environmental requirements. In the literature are evaluated several
parameters including: i) influence of brine composition on solubility and
83
foaming performance, ii) influence of oil on foam strength and foam stability,
iii) influence of temperature, and iv) static adsorption on rocks.
Potential candidate surfactants comprise two main categories: a) anionics
(sulphonates and disulphonates) and b) amphoterics (betaines). Characteristics
of anionic surfactants that make them considerable candidates for our project
are:
Proper foaming power
Proper stability
Low partitioning into the crude oil phase, and low adsorption
However, anionic surfactants may precipitate in the presence of salts, especially
divalent cations like calcium and magnesium. Conversely, amphoterics are good
foam boosters, practically insensitive to brine and tolerant to oils. Their main
potential drawback is their high adsorption on rocks.
More specifically, linear alkylbenzenesulphonates (LAS) are all-purpose
surfactants commonly used in foaming products (e.g. household detergents,
dishwashing and cleaning). These are relatively inexpensive surfactants with
good general performance and they have been proposed for a number of EOR
processes (Muijs, Keijzer et al. 1988). Alfa olefin sulphonates (AOS) have been
successfully used as foaming agents for controlling gas mobility in a North Sea
field (Blaker, Aarra et al. 2002). Amphoteric surfactants are excellent foam
boosters: a fluorinated betaine (FBET) has been previously studied as a foam
agent for controlling GOR (Vikingstad and Aarra 2009). We also evaluated a
commercial cocoamido-propyl betaine (CAPB) due to its effective synergistic
performance with anionic foamers (Mannhardt, Schramm et al. 1993). In the
next figure 5.2 there is a summary of surfactants behaviors previously discussed.
84
Regarding literature is easy to ranked surfactants for reservoir conditions (from
0 to 10, where 10 is best) using the results from each pre-screening criterion. In
the spider chart figure 5.3 only surfactants with good foaming properties are
illustrated:
o FBET has well compatibility and foaming performance but fails because
of its very high adsorption and cost when compared to AOS or LAS.
o LAS is a cost-effective surfactant, but fails because of its poor
compatibility with aquifer water.
o Both AOS C12-14 and AOS C14-16 perform similarly under all pre-
screening criteria. AOS C12-14 has even better brine compatibility and
adsorption than AOS C14-16.
Surfactant Abbreviation Type Pros Cons
Linear alkyl sulphonate C10-13 LAS AnionicGood foamer
BiodegradableNeutralization required
Alpha olefin sulphonate C14-16 AOS C14-16 AnionicExcellent foamer
BiodegradableCa
2+ intolerance
Alpha olefin sulphonate C12-14 AOS C12-14 AnionicExcellent foamer
BiodegradableCa
2+ intolerance
C10 di alkyl diphenyl disulphonate DADS C10 AnionicExcellent tolerance to brine
Low adsorptionCa
2+ intolerance
C12 di alkyl diphenyl disulphonate DADS C12 AnionicExcellent tolerance to brine
Low adsorptionPoor foam
C16 di alkyl diphenyl disulphonate DADS C16 AnionicExcellent tolerance to brine
Low adsorptionPoor foam
Fluorinated betaine FBET Amphoteric
Excellent foamer
Tolerance to crude oil
Tolerance to brine
High cost
Not biodegradable
High adsorption
Cocoamidopropyl betaine CAPB AmphotericFoam booster
Tolerance to brineHigh adsorption
Figure 5.2: pre-screened surfactants
85
Figure 5.3: ranking of surfactants from pre-screening
Being in line with literature results we decided to use AOS C14-16 as surfactant
in our LPLT FAWAG experiments.
5.2 Equipments
The experimental set-up consists of a Hassler type core holder containing the
Berea sandstone, double injection equipment, double effect piston displacement
pumps, two balances, a gasometer, high precision transducers and computers to
acquire and elaborate data.
5.2.1 Core sample and core-holder
Berea Sandstone core sample with 30,48cm (1feet) of length (L) and 5,08cm (2
inch) of diameter was used to perform the experiments (figure 5.4). This
Sandstone is a sedimentary rock whose grains are predominantly sand-sized and
are composed of quartz held together by silica.
86
The Berea sandstone core is located vertically inside the stainless steel Hassler
type core holder (figure 5.6) under a confinement pressure of 30 bars. Hassler
type core holders are defined as core holders that have radial pressure applied to
the core sample. These core holders are routinely used for gas and liquid
permeability and other core flooding experiments. The distribution plugs are
provided with a single inlet and outlet. Additional ports can be added as we did
for our experiments. As shown in figure 5.5, we have four ports for pressure
transducer in order to measure inlet pressure (Pin), outlet pressure (Pout), pressure
at 1/3 of core length (P1) and pressure at 2/3 of core length (P2).
Figure 5.4: core-sample
Figure 5.5: schematic of pressure ports within the core-holder
87
5.3 LPLT WAG experiment description
Oil recovery by WAG is dependent on the saturation cycles that occur in a core-
flood or in the reservoir. The importance of WAG experiment at low pressure
and atmospheric temperature is to measure the brine pressure drop and
determine the MRF. WAG experiment is also important to better understand the
early breakthrough phenomena and the importance of the foam injection to
delay this behavior of the gas due of its low viscosity.
5.3.1 Experimental set-up
The set-up used to carry out the core flow experiments is shown in figure 5.7. It
consists of a core-holder with inlet of fluids in the bottom. The core is under a
pressure of 30 bar that is the confine pressure to avoid that fluids take
Figure 5.6: sleeve and core-holder
88
preferential pathways. A pump provides this pressure (ISCO pump). Brine and
gas arrive to the core from two different lines. The injected brine comes from a
double effect piston displacement pump (Pharmacia Biotech P-500) at flow rate
of 480 ml/h. Nitrogen gas is supplied by the line at 7 bar with a pressure
regulator (KHP Series, Swagelok). Four pressure transducers are used to
monitor the pressure drop over the core segments with increasing length from
the core inlet (section 1: 10, 1±0.1 cm, section 2: 20, 2±0.1 cm and section 3:
30,4±0.1 cm). At the outlet there are two balances to collect fluids. Two
balances permit to manage the presence of different fluids and phases. Then
liquid production is monitored by weight. The fluids spread across a burette
connected to the first balance and then go down to the second balance. The gas
escapes from the top of the burette and goes into a gasometer which measure the
gas flow rate. All these devices are connected to a data acquisition system
(National Instruments) that is used to record pressure, liquid production and gas
and liquid injection flow rate. The experiments were at atmospheric temperature
(21±1 °C).
Figure 5.7: LPLT WAG experimental set-up
Pout
P2
P1
Pin
Gasometer
Vent
Balance
Balance
W0
ConfiningPressure
P
DATA ACQ.
InternalPressure
Ports
PregBRINE
Mix
BurettePhase sep.
OVENBY PASS
N2
89
5.3.2 Experimental procedure
In this section we describe the basic sequence of conducting core-flooding
experiments. The experiment has been started after full saturation of the sample
with brine. The system is maintained for 24 h in these fully saturated conditions
under a back-pressure of 1 to ensure the system is in equilibrium. The absolute
permeability to brine is measured by applying a sequence of different flow rates
and employing Darcy’s law. Next 2 pore volume (PV) of brine with a flow rate
of 480 ml/h was injected in the core. Injection of 2 PV of brine is considered as
our standard which we applied it in injection of 2 PV surfactant solution into the
core to satisfy its adsorption capacity. We did the same for WAG experiment
exactly at the same conditions. After this we stopped the pump and opened the
gas valve that was injected pre regulated conditions at 720 ml/h into the core for
1 PV. Then we did others 2 cycles injecting 1 PV of brine alternating with 1 PV
of gas for a total of 3 WAG injections. This choice was made to be in reservoir
condition in terms of injection where the flow rate is low, about1ft per day, and
the WAG injection is done injecting more or less 1 PV water and 1 PV gas. At
the end of the experiment the absolute permeability was re measured. The
absolute permeability was the same we obtained before the starting of the first
experiment then we chose to continue the experiment with the same core.
Using LabVIEW (programming environment really useful to convert and
elaborate information in terms of pressure, temperature, etc in digital data)
pressures, water mass and gas flow rate data were collected. Then we analyze
the results in terms of water production curve, gas breakthrough and pressure
drop that we will describe in the following of this chapter and in the next
chapter.
90
5.3.3 Experimental Results
Figure 5.8 depicts results of the water production with respect to pore volume
and pressure drop. This figure is divided into different sections that represent
WAG cycles, each section is identified by an abbreviation. For example, 2 PV
W indicates two pore volume of brine injected and 1 PV G indicates one pore
volume of gas injected. The blue color is for brine injection and red color is for
gas injection. In a secondary axis there are also inlet and outlet pressures. The
water production graph starts from 0 till less than 0.5 PV which brine,
depending to its permeability and saturation and porosity of the sample, needs to
reach the end of the core sample. The blue curve has a linear trend that depends
of brine flow rate. Conversely the red curve has a non-linear trend that indicates
that gas flow rate vary from inlet to outlet due the gas expansion, this is the
reason why we used an average flow rate for gas. The gas curve increases
immediately with a jump then, after less than 0.05 PV of gas injection, the red
curve reaches the plateau. This means that gas breakthrough was reached and no
more water could be produced. This is the reason why we need to improve the
gas viscosity to delay gas breakthrough that means improving in sweep
efficiency and enhancing in oil production. Looking at the black curve, that is
the inlet pressure, we are able to see when gas injection starts. In fact we have a
peak that corresponds to the opening of gas valve. Then the curve decreases
reaching a plateau at 0.5 PV till the end of injection that corresponds to a value
more or less of 0 bar. The decreasing in the first part of the curve is in line with
water production and with water saturation reductions. The green curve, outlet
pressure, is more or less always at 0bar.
In the next chapter we will discuss in details a comparison between WAG and
FAWAG, analyzing water production, pressure drops in all sections of the core
sample and the MRF.
91
Regarding the trend of water production curve, we were able to understand the
importance of using foam to help standard WAG injection processes.
5.4 LPLT FAWAG experiment description
In the previous paragraph we illustrated the WAG injection experiment and at
the end we analyzed the importance of FAWAG injection to reduce the mobility
of the gas. Therefore in the following we will describe FAWAG injection
experiments.
For FAWAG injection experiments, three different tests have been performed:
0
5
10
15
20
0
50
100
150
200
250
300
350
400
450
500
0 1 2 3 4 5 6 7 8 9
Pressu
re (bar)
Wa
ter
Pro
du
ctio
n (
g)
Pore volume (PV)
WATER PRODUCTION
PV BRINE
PV GAS
Pin
Pout
2 PV W 1 PV G 1 PV G 1 PV G1 PV W 1 PV W
Figure 5.8: WAG experimental results in terms of water recovery, inlet preeure and outlet
pressure
92
FAWAG injection with surfactant solution at 2000 ppm of surfactant
concentration.
FAWAG injection with surfactant solution at 5000 ppm of surfactant
concentration.
FAWAG injection with surfactant solution at 10000 ppm of surfactant
concentration.
We performed these three different experiments to understand which
concentration is the best selection to have reasonable trade-off between MRF
and economics aspects.
5.4.1 Experimental set-up
In the figure 5.9 is shown the scheme of FAWAG injection experiment set-up.
The only one difference you can see between FAWAG and WAG experimental
set-up is that in the FAWAG set-up we provided a graduated column to collect
the exceeded foam from the burette to avoid foam spread into gasometer. The
column has a 3 way bypass valve to be able to shift the foam flow in the column
and measure gas flow rate from the top of the valve.
Pout
P2
P1
Pin
Gasometer
Vent
Balance
Balance
W0
ConfiningPressure
P
DATA ACQ.
InternalPressure
Ports
Preg
Foamer solution
Mix
BurettePhase sep.
FoamReceiving cylinder
OVENBY PASS
N2
Figure 5.9: LPLT FAWAG experimental set-up
93
5.4.2 Experimental procedure
In this section we describe the basic sequence of FAWAG injection
experiments. We focused on one FAWAG experiment which is the one with
2000 ppm surfactant concentration, all other experiments are the same in terms
of procedure, obviously with changing the concentration of surfactant in the
solution. Before starting the experiment we measured brine permeability
changing brine flow rate and employing Darcy’s law to be sure that the core
sample is able to be used in the next experiment. The FAWAG experiment has
been started after full saturation of the sample with surfactant solution. Next 2
pore volume (PV) of surfactant solution at 2000 ppm with a flow rate of 480
ml/h was injected in the core. Injection of 2 PV of surfactant solution is
considered as our standard to satisfy surfactant adsorption capacity. After this
we stopped the pump and we opened the gas valve that was injected at 720 ml/h
into the core for 1 PV. Then we did others 2 cycles injecting 1 PV of brine
alternating with 1 PV of gas for a total of 3 FAWAG injections. At the end of
the experiment we washed the core sample injecting methanol for 24 hours to
clean all residual surfactant into the core sample and be able to start with the
next experiment. At this point we again measured brine permeability to be sure
that during the injection, the permeability of the core has not changed. We
continued the experiments by using 5000 ppm and 10000 ppm surfactant
concentration. Using LabVIEW pressures, water mass and gas flow rate data
were collected. Then we analyzed the results in terms of water production curve,
gas breakthrough, pressure drop and at the end MRF.
94
5.4.3 Experimental Results
Figure 5.10 depicts results of the water production with respect to pore volume
and pressure drop. As it is shown in figure 5.10, the graph is divided into
different sections that represent FAWAG cycles. Each section is identified by an
abbreviation. For example, 2 PV SS indicates two pore volume of surfactant
solution injected and 1 PV G indicates one pore volume of gas injected. Also
here the water production graph starts from 0 till more or less 1 PV, which
surfactant solution, depending to its permeability and saturation and porosity of
the sample, needs to reach the end of core sample. In this case we had 1 PV
instead of 0.5 PV which we obtained in WAG cycles. This behavior verifies the
fact that during the injection of surfactant solution, foam is starting to be
generated into the core sample. Then the brine solution needs more time to reach
the end of the core. The blue curve has a linear trend with a slope that depends
on brine flow rate. After 2 PV of surfactant solution injection, the blue curve
reaches the value of 150 g. As it is shown in figure 5.8, at the end of 2 PV brine
in WAG injection, we obtained 200 g of water production. This difference
indicates that 50 g of surfactant solution was starting to become foam into the
core.
Then looking at the first red curve is easy to understand the delay in the gas
breakthrough with respect to WAG injection. In fact the gas curve increases
immediately its value with an initial jump then the curve continues to rise till the
end of the injection that is more or less 1 PV. In the WAG experiment we
obtained a plateau behavior after less than 0.05 PV of gas injection. Comparing
water production curve of WAG injection with FAWAG injection, it may result
to have higher water production. Generally the objective of FAWAG injection is
to increase oil production not water production. Usually water production is
important in oil-free experiment to easily detect when gas breakthrough
happens.
95
In the next chapter we will discuss in details a comparison between WAG and
FAWAG, analyzing water production, pressure drops in all sections of the core
sample and the MRF.
5.5 HPHT Experimental set-up design
The last part of this thesis has been focused on the design of experimental set-up
for HPHT WAG injection and HPHT FAWAG injection in presence of oil. This
kind of set-up was made to be in reservoir condition in terms of pressure,
temperature, fluids and chemical. Then we modified the set-up for LPLT to
perform the test at reservoir conditions (Figure 5.11).
0
2
4
6
8
10
12
14
16
18
20
0
50
100
150
200
250
300
350
400
450
500
0 1 2 3 4 5 6 7 8 9
Pressu
re (ba
r)
Wate
r P
ord
uct
ion
(g)
Pore Volume (PV)
WATER PRODUCTION
PV SURFACTANT SULUTION
PV GAS
Pin
Pout
2 PV SS 1 PV G 1 PV G1 PV G
1 PV SS 1 PV SS
Figure 5.10: FAWAG experimental results in terms of water recovery, inlet pressure and outlet
pressure
96
Figure 5.11: HPHT experimental set-up
The set-up consists of a core-holder with inlet of fluids at the bottom and outlet
at the top. The core is under confine pressure up to 700 bar to avoid that fluids
take preferential pathways. An oven contains core holder to reach the desired
temperature up to 200°C. Brine, oil and gas arrive to the core from three
different lines. The injected brine and also oil comes from a double effect piston
displacement pump (Pharmacia Biotech P-500). Methane gas instead of nitrogen
gas is supplied by transfer cylinders at high pressure up to 600 bar. Pressure
transducers are used to monitor the pressure drop over the core segments with
increasing length from the core inlet (section 1: 10, 1±0.1 cm, section 2: 20,
2±0.1 cm and section 3: 30, 4±0.1 cm). At the outlet there are two balances to
collect fluid, to be able to do a mass balance and at the end to evaluate liquids
production. The fluids spread across a burette connected to the first balance and
then accumulate the second balance. In this way we obtain stratification on
fluids and then it is possible to calculate oil recovery by balances difference.
The gas escapes from the top of the burette and goes into a gasometer which
P
P
P
P
DATA
ACQ.
Back
Pressure
P1000
P1000
P1000
P1000
Oven
Core
GASOIL
Gasometer
Confining
Pressure
Vent
Pumps
Brine
cooling
Balance
Balance
W0
97
measures the gas flow rate. All these devices are connected to a data acquisition
system (National Instruments) that is used to record pressure, liquid production,
gas and liquid injection flow rate. The difference between HPHT FAWAG and
WAG experimental set-up is that in the FAWAG set-up we provided a
graduated column to collect the exceeded foam from the burette to avoid foam
spread into gasometer. The column has a 3 way bypass valve to be able to shift
the foam flow in the column and measure gas flow rate from the top of the
valve.
5.5.1 Experimental procedure
For performing the HPHT WAG tests, we selected the core sample which is
similar to reservoir rock.
The experimental producers for executing HPHT WAG are divided into
different steps. After selecting the core sample which is similar to reservoir
rock, brine and gas permeability have been performed. Then we saturated the
core sample with oil. The next step is performing WAG injection experiments as
scheduled for real field injection to achieve the residual oil saturation (SOR). The
aim of FAWAG is to increase the oil recovery. This experiment is useful to
perform after WAG experiments, which it can help to improve the recovery
factor. In this case, foam may help to increase the sweep efficiency by
enhancing the gas viscosity.
As it is shown in figure 5.12, there are 2 cycles of WAG and 2 cycles of
FAWAG in the scheme. This is just an indication to have an idea about
experimental sequences. The number of cycles will be decided during
experiments. Then FAWAG injection will take the scene when WAG injection
will not be able to recover more oil. From economic point of view, using the
98
surfactant is expensive, especially for surfactant transportation, stock and
mixing/injection plant.
In the next chapter we discuss about all experimental result. We will compare
between WAG and FAWAG injection. We will figure out more about the
reduction in gas mobility.
Satu
ration
1
Brine
Oil
Brine Brine
Gas GasGas Gas
Surfct Surfct Brine
Gas
Preparation WAG FAWAG WAG
water
oil
gassurfct
solution
foam
Time
Figure 5.12: schematic of HPHT experimental sequences
99
100
6 - RESULTS AND DISCUSSION
In this chapter we will analyze in detail all the experimental results. In particular
we will compare WAG injection with FAWAG injection. We will start with
water recovery, and then we will speak about pressure drop. At the end we will
present results in terms of MRF.
6.1 Water recovery
We conducted all the experiment in oil-free conditions. Water recovery graph,
which is shown in figure 6.1, is really important to understand the behaviors of
foam injection in porous media. The graph is divided in three different sections,
which indicate three cycles of WAG and FAWAG injection with different
surfactant concentration. In all the FAWAG curves, the water production graph
starts from 0 till around 1 PV that is the volume the fluid needs to reach the end
of core sample. Looking at WAG curve, we had 0 for less than 0.2PV. This
behavior verifies the fact that during the injection of surfactant solution, foam is
starting to be generated into the core sample. Then the surfactant solution need
more time to reach the end of the core. The same behavior occurs in other
cycles; obviously the curve is shifted upward. The importance is the constancy
of the water production curve during water injection.
101
In the figure 6.2 shows the zoom of figure 6.1 from 2 to 4 PV of the entire water
production curve. This zoom is necessary to understand the behavior of gas into
porous media. In the graph the gas injection occurs at the end of the linear trend
of the water production curve. Looking the graph after 3 PV the first curve
represents WAG experiment, the second curve FAWAG at 10000 ppm, the third
FAWAG at 5000 ppm and the last one is for FAWAG at 2000 ppm. In the WAG
injection experiment the gas curve increases immediately with a jump then, after
less than 0.05 PV of gas injection, the curve reaches the plateau. This means that
gas breakthrough was reached and no more water could be produced.
Conversely in the FAWAG experiment at 10000 ppm, instead of a jump, we
obtained a continuous growing of the curve up to the end of the gas injection. In
FAWAG experiment at 5000 ppm we had a jump, then a continuous growing of
the curve that reaches the plateau at more or less 1 PV. The trend of the
Figure 6.1: Water recovery results during core-flooding experiments
2 CYCLE1 CYCLE 3 CYCLE
102
FAWAG experiment at 2000 ppm is the same of 5000 ppm, then considerations
are the same.
Figure 6.2: The zoom of water production curve in the first injection cycle
Looking at figures 6.2, we can observer that FAWAG injection is an efficient
way to delay gas breakthrough. This means that foam is able to increase the
viscosity of the gas and consequently to improve also the sweep efficiency in the
oil recovery.
6.2 Pressure Drop
In this section we will analyze results of pressure drop. Pressure drop is
important to calculate the reduction in gas mobility. Figure 6.3 shows the total
pressure drop into the core from the inlet to the outlet.
100
150
200
250
2 3 4
Wat
er
reco
very
(g)
Pore Volume (PV)
WAG
FAWAG 10000 ppm
FAWAG 5000 ppm
FAWAG 2000 ppm
103
Figure 6.3: Total pressure drop for each core-flooding experiments
From figure 6.3 we can easily identify different types of injection. When brine
or surfactant solution injection starts the curve rises continuously. Then the
curve reaches the plateau, a steady-state condition is achieved. Looking at the
WAG curve the steady-state condition occurs after less than 0.2 PV. For
FAWAG experiments the curve reaches the plateau after more or less 1 PV.
This behavior can be explained by two reasons. The first one is the adsorption of
the surfactant into the core that means a delay in the fluid stability. The second
reason is that during the injection, foam is started to be generated into the core.
With this generating of the foam into the core, the time for reaching to steady-
state condition will increase because of existing two different fluids phases.
Gas injection can be observed at 2.5 PV, 5 PV and 7.5 PV points. These are,
starting points of gas injection. The gas pressure drop decreases with the
0
1
2
3
4
5
6
0 1 2 3 4 5 6 7 8 9 10
Pre
ssu
re D
rop
(b
ar)
Pore Volume (PV)
FAWAG 2000 ppm
FAWAG 5000 ppm
FAWAG 10000 ppm
WAG
104
increasing of PV for both WAG and FAWAG experiments. This behavior is due
of the reduction in saturation.
As it is mention in previous chapter, core sample is divided into three different
sections (see chapter 5). For all these sections, we were able to measure inlet
and outlet pressure. Then, as it is shown in figure 6.4, we had three pressure
drop curve for each section.
We analyzed the results of each section in terms of PV and pressure drop. The
section 1 is affected by inlet effect. This effect depends on the fact that two
different fluids are injected alternately into the core. The section 1 does not have
the time to stabilize to a new regime. This also depends of the small length of
the core sample. The section 3 is affected by capillary end effect. Capillary end
effect is an important issue in core flooding experiments, because it can cause
serious errors in the calculation of saturation and relative permeabilities from
pressure drop and production information. There are several studies regarding
these effects (Apaydin and Kovscek 2000). Then, based on the analysis the
results of each section, we observed that the section 2 can better describe our
core flooding experiments.
To discuss in details of the section 2 in the terms of pressure drop (Figure 6.4).
Blue and red curves are respectively for FAWAG at 2000 and 5000 ppm.
Looking this curve is evident that the process needs the third FAWAG cycle to
reach the higher pressure drop. For FAWAG at 10000 ppm, that is the green
curve, two FAWAG cycles are enough. In fact in the third cycle the pressure
drop is more or less the same. This behavior is because of stability of generated
foam at 10000 ppm.
105
3
2
1
Figure 6.4: pressure drop into 3 different sections of the core
106
6.3 MRF
The MRF is the most important result of this thesis. This parameter gives us
important information regarding the foam effectiveness for EOR application. As
we mentioned before, MRF is the ratio between pressure drops in FAWAG
experiments to pressure drop in WAG experiment at steady-state conditions.
In the previous paragraph we observed the section 2 is the best in terms of
results. Figure 6.5 depicts MRF results of the section 2.
The figure shows that the MRF increases with increasing in surfactant solution
concentration. These three curves represent each FAWAG cycles. In the x-axis
Figure 6.5: Mobility reduction factor into section 2 of the core
2
3
4
5
6
0 0.2 0.4 0.6 0.8 1 1.2
Mo
bilit
y R
edic
tio
n F
acto
r, M
RF
Surfactant Concentration, %w
MRF THIRD FAWAG CYCLE
MRF SECOND FAWAG CYCLE
MRF FIRST FAWAG CYCLE
107
there is different surfactant concentration. Looking at the third cycle curve is
easy to make an important consideration. After three FAWAG cycles, the MRF
rises with surfactant solution concentration. But the slope of the curve from
2000 ppm to 5000 ppm is higher than the slope of the curve from 5000 ppm to
10000 ppm. This result has an important economic consequence. In fact the
curve reported in the figure 6.5 is indicating us to find the best trade-off between
efficiency and cost of surfactant in the region. The red curve is related to second
FAWAG cycle. Here it is possible to see that 10000 ppm is the best one. In fact
the slope of the curve from 5000 to 10000 ppm is much higher than the slope
between 2000 and 5000 ppm. The blue curve is related to the first FAWAG
cycle and indicate low MRF. This behavior can be explained by foam stability
factor, independent from the surfactant concentration. The foam stability is not
sufficient to reduce effectively the gas mobility.
Regarding the results, FAWAG injection with 5000ppm of surfactant
concentration is the best configuration for our process. The further aim is
testing these three cycles of FAWAG injection for field application. The best
configuration of in the terms of surfactant solution is the one with high
concentration. For instance in our case the best surfactant solution will be the
one with 10000ppm of surfactant concentration.
108
7 - CONCLUSIONS
This thesis was mainly focused on the application of foam to reduce the mobility
of the gas that can affect oil production and associated gas handling costs. WAG
and FAWAG experimental rig was set-up. Several core-flooding experiments
were conducted at medium-low pressure to investigate foam behavior in porous
media. All the work was organized in three steps:
The first step was the WAG injection experiments to set-up experimental
rig and perform preliminary tests to characterize the core sections and obtain
WAG baseline data.
The second step was the execution of FAWAG experiments. The setup
for this experiment is similar to WAG. FAWAG experiments were characterized
by several flooding steps at different surfactant concentrations. The importance
of selecting the proper concentration for the foam will impact on efficiency and
economics. Pressure and phases flow rate data, were acquired and analyzed. We
observed consistency of results in terms of gas mobility reduction.
The trend of the MRF resulted is in agreement with results reported in literature:
MRF rises with increasing surfactant concentration; the lower surfactant
concentration should be avoided because adsorption and instability.
The third step was the setting-up the rig to perform WAG/FAWAG
experiments at reservoir condition HPHT. This could also be mentioned as
future challenge.
For future, more field representative condition experiments will be conducted on
pre-selected surfactant mixtures. Phases mobility, oil interaction,
thermodynamic miscibility, adsorption, foam stability, will be investigated.
109
110
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