i 

 

 

 

Application of foam flooding for residual oil production in 

the “X” oilfield 

 

 

by Stepan Verendeyev 

 

Thesis supervisor: Dr. Randy Doyle Hazlett 

Thesis co-supervisor: Dr. Sotirios Longinos 

 

 

 

 

 

 

Thesis submitted to the School of Mining and Geosciences of Nazarbayev 

University in Partial Fulfilment of the Requirements for the Degree of  

Master of Science in Petroleum Engineering 

 

 

 

 

Nazarbayev University 

29/04/2025 
 

 



ii 

 

 

ORIGINALITY STATEMENT 

I, Stepan Verendeyev, hereby declare that this submission is my own work and to the best of 

my knowledge it contains no materials previously published or written by another person, or 

substantial proportions of material which have been accepted for the award of any other degree 

or diploma at Nazarbayev University or any other educational institution, except where due 

acknowledgement is made in the thesis. 

Any contribution made to the research by others, with whom I have worked at NU or elsewhere 

is explicitly acknowledged in the thesis. 

I also declare that the intellectual content of this thesis is the product of my own work, except 

to the extent that assistance from others in the project's design and conception or in style, 

presentation and linguistic expression is acknowledged. 

 

 

Signed on __/04/2025 

  



iii 

 

ABSTRACT 

Foam is a known diverting agent capable of improving sweep efficiency.  It is speculated that 

foam flooding can also improve microscopic displacement efficiency in the reservoir core by 

the same mechanism. Recovery of trapped residual hydrocarbon fluid in the oilfield “X” core 

is investigated in this thesis.  To quantify the recovery of bypassed resources on the core level, 

the application of foam flooding was investigated in the reservoir core and contrasted with the 

same recovery process sequence on homogeneous sandstone and carbonate quarried outcrop 

core. The study was the first to identify promising foam formulations using atmospheric bulk 

foam stability tests and use such foaming formulations with and without nanoparticle addition 

in immiscible core flood tests with nitrogen (N2) and carbon dioxide (CO2) carrier fluids.   

Screening experiments of bulk foam stability were conducted as a precursor to core flooding 

studies. Foam half-life tests substantiated a negative influence of increasing salinity (NaCl) on 

foam stability. Appropriate baseline production from sequential water flooding and gas 

flooding preceded foam flooding assessments with both nitrogen and carbon dioxide gas 

options.  Such tests were conducted in both reservoir and outcrop cores. Oil recovery and 

resistance factor observations were compared between reservoir and outcrop core, N2 and CO2 

gas, and foam formulations with and without nanoparticle addition.  

The X oilfield experiments confirmed significant EOR potential with foam processes, 

especially by adding nanoparticles. Baseline studies on gas flooding prior to foam introduction 

showed that CO2 gas flooding is more efficient than N2 flooding, even at low pressure, 

presumably due to the presence of additional interaction mechanisms with CO2. Whether 

nanoparticles were present or not, the data showed that N2 foam was more efficient than CO2 

foam, as evidenced by higher Recovery-8.15 % of Original Oil in Place (OOIP) with N2 foam 

in “X” core samples compared to 2.45 % with CO2 foam. Moreover, recovery was improved 

with the addition of NP to the foam formulation, resulting in an average additional recovery 

factor of 5.05%. However, the higher apparent viscosity of N₂ foam with nanoparticles (about 

9 cP) must be carefully considered before field usage due to the associated mobility reduction, 

despite the dramatic increase in the recovery efficiency. In general, from the findings of this 

study, it appears that foam flooding is a feasible approach for enhancing sweep in the "X" 

oilfield.  



iv 

 

DEDICATION  

I dedicate this work to my mother, the person to whom I owe all of my achievements. 
  



v 

 

ACKNOWLEDGMENT 

I would like to express my sincere appreciation to my supervisor, Professor Randy 

Hazlett, for his constant support, professional advice, and guidance during the writing of 

this thesis. His combination of in-depth knowledge and outstanding experience played a 

pivotal role in the success of this effort. 

I am also incredibly appreciative of my co-supervisor, Dr. Sotirios Longinos, whose 

important counsel, direction, and mentoring have been crucial in defining my academic 

and personal development. 

I also wish to thank my thesis committee members for their valuable comments and my 

research group for their unending assistance. 

I am especially grateful to Dr. Azza Hashim Abbas (Grant No. 20122022) for providing 

the silica nanoparticles used in the experiments. 

And I must thank Nazarbayev University School of Mining and Geoscience for the 

facilities, and a high quality environment to accomplish this work. 

 

 

  



vi 

 

TABLE OF CONTENTS 

TABLE OF CONTENTS VI 

LIST OF FIGURES VIII 

LIST OF TABLES XI 

1. INTRODUCTION 1 

1.1. Problem Definition 1 

1.2. Objectives 1 

1.3. Hypothesis 1 

2. LITERATURE REVIEW 2 

2.1. Enhanced oil recovery 2 

2.1.1. Enhance oil recovery methods 2 

2.1.2. Foam injection 4 

2.1.3. Field cases of foam injection 5 

2.1.4. Foam injection in EOR: results and case study insights 6 

2.2. Geologic Context 11 

2.2.1. Geological overview of oilfield “X” 11 

2.2.2. Geological structure and lithology 12 

2.2.3. Paleontological data 13 

2.2.4. Tectonic features 14 

2.2.5. Analysis of oil and gas potential 14 

2.2.6. Structure of an oil reservoir in the granite massif of the “X” field 16 

2.2.7. Reservoir model and capacitive properties of granite massif 16 

2.2.8. Prospects for additional exploration of the field 16 

2.2.9. Analysis of fractured-cavernous reservoirs 17 

2.2.10. Fluid evaluation 20 

2.2.11. Well logs evaluation 21 

2.2.12. Core evaluation 23 

2.2.13. Hydrochemical water analysis 26 

2.2.14. Geological report 27 

3. METHODOLOGY 29 

4. RESULTS AND DISSCUSSION 38 



vii 

 

4.1. Foam stability test 38 

4.2. Oilfield  “X” core sample flooding results 39 

4.2.1. “X-10” Core flooding experiment results 39 

4.2.2. “X-13” Core flooding experiment results 47 

4.3. Outcrop core samples flooding results 50 

4.3.1. Berea core sample flooding result 50 

4.3.2. Indiana core sample flooding result 53 

5. DISCUSSION 56 

5.1. Mechanical properties of foam under atmospheric conditions: 56 

5.1.1. Foam column stability 56 

5.1.2. Foam heterogeneity effects 57 

5.2. Mechanical properties in porous media of “X-oilfield” 58 

5.3. Impact of lithology on EOR performance 58 

5.4. Foam flooding additives 62 

6. CONCLUSION 64 

7. FUTURE WORK 66 

REFERENCES 67 

 

  



viii 

 

LIST OF FIGURES 

Figure 1 Schematic of IOR from typical EOR response: (a) rate vs. time and (b) 

cumulative vs time [3] ...................................................................................................... 2 

Figure 2 Simplified classification of EOR method [6] ..................................................... 3 

Figure 3. Miscible flooding technique principal scheme [7] ............................................ 4 

Figure 4 – Schematic illustrating two types of crossflow during foam flooding [12] ...... 5 

Figure 5 - Comparison of gas, water-alternating gas (WAG), and foam injections [18] . 8 

Figure 6. Mangyshlak Peninsula. Layout of areas, ......................................................... 13 

Figure 7. Geological profile along the line of wells 30-25-12-10-13 [30] ..................... 15 

Figure 8. Model of an oil reservoir in the granite massif of the “X” area: ..................... 17 

Figure 9. Comparison of cubes of reflectors and diffractors imported into the 

interpretation project: a) cube of reflectors and diffractors b) joint representation of 

cubes of reflectors and diffractors with isochronous surfaces along horizons V1, V2 and 

VI. [31] ............................................................................................................................ 18 

Figure 10. Time slice of a cube of scattered waves from wells 24-11-1E-22-27 [31] ... 19 

Figure 11. Structural map of the top of the granite intrusion (left) and prospect map 

(index acoustic heterogeneity) oil and gas potential of granite intrusion: dark red color 

on the map on the right – the most promising areas [31]................................................ 20 

Figure 12 Results of spectral gamma-ray activity of a full-size core from the “X” 

oilfields well [33]. ........................................................................................................... 22 

Figure 13. Results of photo documentation of core 1m-18m from “X” oilfield well [33].

......................................................................................................................................... 23 

Figure 14. “X” oilfield well porosity distribution by depth ............................................ 24 

Figure 15. “X” oilfield well permeability distribution by depth ..................................... 25 

Figure 16. “X” deposit. Changes in groundwater salinity with depth [34]..................... 27 

Figure 17. Photo of homogenizer application to prepare nanoparticle (np) solutions .... 29 

Figure 18. Foam stability test setup [40] ........................................................................ 30 

Figure 19. Foam generation through using diffuser........................................................ 31 

Figure 20. Experiment flow of foam stability test: ......................................................... 31 

Figure 21. Oilfield “X” reservoir core plugs used in coreflood experiments. ................ 32 



ix 

 

Figure 22. Schematic of the SRP 350 core flooding apparatus setup for foam flooding 

by Vinci Technologies [56] ............................................................................................ 35 

Figure 23. Photo of core flooding experimental setup .................................................... 35 

Figure 24. Soxhlet extractor ............................................................................................ 36 

Figure 25. Foam stability test results .............................................................................. 38 

Figure 26. CO2 bulk foam generated by 0.1 % BIO-TERGE surfactant and 0.5 % of 

silica nanoparticles in 1 % NaCl [41] ............................................................................. 39 

Figure 27. Observed process, of foam pushing out the out, in transparent tube installed 

on outlet line ................................................................................................................... 41 

Figure 28 Comparison of foam texture of nitrogen generated foam (a) and CO2 

generated foam (b) .......................................................................................................... 42 

Figure 29. Indiana core sample (a) before and (b) after cleaning ................................... 42 

Figure 30. N2 application “X-10” core flooding experiment results apparent viscosity 

and RF vs PV .................................................................................................................. 43 

Figure 31. CO2 application “X-10” core flooding experiment results, apparent viscosity 

and  RF vs PV ................................................................................................................. 44 

Figure 32. N2 application “X-10” core flooding experiment results differential pressure 

and RF vs PV .................................................................................................................. 45 

Figure 33. CO2 application “X-10” core flooding experiment results differential 

pressure and RF vs PV .................................................................................................... 46 

Figure 34. N2 application “X-13” core flooding experiment results apparent viscosity 

RF vs PV ......................................................................................................................... 47 

Figure 35. CO2 application “X-13” core flooding experiment results apparent viscosity 

and RF vs PV .................................................................................................................. 48 

Figure 36. N2 application “X-13” core flooding experiment results dP, RF vs PV ....... 49 

Figure 37. CO2 application “X-13” core flooding experiment results dP, RF vs PV

............................................................................... Ошибка! Закладка не определена. 

Figure 38. N2 application Berea core flooding experiment results apparent viscosity and 

RF vs PV ......................................................................................................................... 50 

Figure 39. CO2 application Berea core flooding experiment results apparent viscosity 

and RF vs PV .................................................................................................................. 51 



x 

 

Figure 40. N2 application Berea core flooding experiment results dP, RF vs PV ......... 52 

Figure 41. CO2 application Berea core flooding experiment results dP, RF vs PV ....... 52 

Figure 42. N2 application Indiana core flooding experiment results apparent viscosity 

and RF vs PV .................................................................................................................. 53 

Figure 43. CO2 application Indiana core flooding experiment results apparent viscosity 

and RF vs PV .................................................................................................................. 54 

Figure 44. N2 application Indiana core flooding experiment results dP, RF vs PV ....... 55 

Figure 45. CO2 application Indiana core flooding experiment results dP, RF vs PV .... 55 

Figure 46. N₂ foam flooding apparent viscosity comparison .......................................... 59 

Figure 47. CO₂ foam flooding apparent viscosity comparison ....................................... 60 

Figure 48. N₂ foam flooding recovery factor comparison for foam flooding ................. 61 

Figure 49. CO₂ foam flooding recovery factor comparison for foam flooding .............. 62 

 

 

  



xi 

 

LIST OF TABLES 

Table 1. reservoir technical properties [33] .................................................................... 11 

Table 2. Hydrochemical analysis of water from well of the “X” oilfield ....................... 26 

Table 3. Bio-terge surfactant and salinity variation for foam test stability .................... 32 

Table 4. Core sample parameters .................................................................................... 33 

Table 5. Dodecane physical and chemical properties [27] [28][29] ............................... 33 

Table 6. “X-10” core flooding recovery factor increment comparison table ................. 44 

Table 7. “X-13” core flooding recovery factor increment comparison table ................. 48 

Table 8. CO2 and N2 foam Berea core sample flooding comparison .............................. 51 

Table 9. Indiana core flooding recovery factor increment comparison table ................. 54 



1 

 

1. INTRODUCTION 

1.1. Problem Definition 

The oil production in oilfield "X," which started in 1980, is now nearing the end of its 

productive phase. A large amount of oil remains trapped within the reservoir's porous media 

(residual oil). Traditional water flooding methods have proven ineffective in recovering this oil 

due to the geological challenges presented by low matrix permeability and the presence of high-

permeability channels. These issues limit the recovery factor (RF) and hinder further 

production. 

1.2. Objectives 

The objectives of this study are to: 

 Introduce bulk foam screening criteria to determine the criteria for promising foaming 

formulations. 

 Evaluate the stability of the foam under experimental conditions in porous media and 

its effectiveness in improving the recovery factor, particularly in cores with potential 

reservoir challenges, such as low matrix permeability and high-permeability channels. 

 Demonstrate and quantify the improvement in microscopic displacement efficiency in 

one-dimensional core floods using foam flooding techniques. 

 Compare the performance of reservoir cores with standard sandstone and carbonate 

outcrop materials. 

 Compare the performance of nitrogen and carbon dioxide immiscible displacement with 

and without foaming agents. 

1.3. Hypothesis 

It is hypothesized that the foam used in core flooding will remain stable throughout the 

displacement process and will help to mobilize and recover the remaining oil trapped in the 

core. Additionally, the addition of nanoparticles to the foam formulation is expected to improve 

the foam stability and increase the overall recovery factor by reducing the mobility of the 

displacing fluid, thereby providing more uniform oil displacement. 



2 

 

2. LITERATURE REVIEW 

2.1. Enhanced oil recovery  

 Enhance oil recovery methods 

Enhanced Oil Recovery (EOR) is a set of advanced techniques designed to extract 

additional hydrocarbons from reservoirs after primary and secondary recovery methods 

have been applied. Primary methods use natural reservoir energy, while gas injection 

and waterflooding are common secondary methods that add energy to the system. Once 

secondary techniques become uneconomical, it is necessary to implement enhanced oil 

recovery (EOR) methods in order to further maximize oil recovery [2], [3]. The 

application of an Improved Oil Recovery (IOR) or EOR process to alter a declining oil 

rate in light of a defined Economic Limit (EL) is shown in Figure 1.  

 
Figure 1 Schematic of IOR from typical EOR response: (a) rate vs. time and (b) cumulative vs time [3] 

The three primary categories of EOR techniques are miscible gas, chemical, and thermal 

methods [6], as illustrated in Figure 2. 



3 

 

 
Figure 2 Simplified classification of EOR method [6] 

The main objective of thermal techniques like in-situ combustion, steam flooding, and cyclic 

steam stimulation (CSS) is to decrease oil viscosity in order to increase its mobility within the 

reservoir [3]. Chemical EOR encompasses techniques such as alkali flooding, polymer 

flooding, surfactant flooding, and their combinations, e.g. Alkaline-Surfactant-Polymer (ASP) 

flooding. According to Sheng (2013) [5], these methods concentrate on improving sweep and 

displacement efficiency by changing the interfacial tension between water and oil.  Miscible 

gas methods, such as carbon dioxide (CO₂) injection and hydrocarbon gas injection, involve 

introducing gases into the reservoir, which become miscible with oil either on first contact or 

through multiple extraction contacts with crude oil, substantially reducing oil viscosity and 

improving displacement efficiency [1][7].  The process is illustrated in Figure 3. 



4 

 

 
Figure 3. Miscible flooding technique principal scheme [7] 

Chemical techniques have demonstrated significant promise in domains where environmental 

factors or reservoir temperature limitations make thermal techniques less attractive. Chemical 

EOR has attracted a lot of attention because of improvements in injection techniques and 

chemical formulation developments that have significantly raised its economic viability and 

efficiency [4]. 

 Foam injection  

Foam injection is a specialized chemical Enhanced Oil Recovery (EOR) method in which gas 

and surfactant solutions are injected into reservoir formations as foam. Foams, defined by a 

segmented gas phase in a continuous liquid phase stabilized by surfactants [9], significantly 

decrease gas mobility in porous media. In heterogeneous reservoirs with high permeability 

contrast or unfavorable mobility ratio, gas mobility control is advantageous, as foam enhances 

the mobility of injected fluids and enhances sweep and displacement efficiency [8]. 

The primary mechanism of foam flooding is the generation of a quasi-stable foam structure in 

reservoir pores, which reduces gas mobility to a large extent. Foam enhances the effective 

viscosity of injected gas to reduce gas channeling and viscous fingering, two recurrent issues 

seen in gas injection processes. Consequently, foam injection improves conformance control, 



5 

 

ensuring more homogeneous oil movement through the reservoir, as illustrated in Figure 4.

 

Figure 4 – Schematic illustrating two types of crossflow during foam flooding [12]  

Foam stability is affected by several important factors such as surfactant type and 

concentration, gas composition, reservoir temperature and pressure, salinity, oil presence, and 

reservoir rock properties [10]. Laboratory studies and reservoir simulations are key before 

implementation, because optimal foam formulations are customized to specific reservoir 

characteristics. Nitrogen (N₂), carbon dioxide (CO₂), and, in some cases, hydrocarbon gases are 

commonly used for foam flooding, and their selection is dependent on operational economics 

and reservoir compatibility [18]. 

Selecting the appropriate surfactants which can provide long-lasting stability and desired 

interfacial properties at reservoir conditions is paramount for successful foam injection. The 

application of foam flooding technology has been broadened as a result of emerging 

developments in chemical formulations for improved performance in harsh environments, like 

high-temperature, high-salinity reservoirs [11]. 

Such fundamental concepts lay the groundwork for the subsequent analysis of foam injection 

applications in this section, which involves discussing the findings from the prior research and 

case studies. 

 Field cases of foam injection  

Foam injection has been successfully implemented in several oilfields around the world, 

demonstrating its effectiveness in enhancing oil recovery. For example, results from the Snorre 

Field in Norway show that foam-assisted water-alternating-gas (FAWAG) techniques 

significantly improved the effectiveness of the sweep and conformance, which resulted in 

increased oil recovery [14]. In the United States, foam flooding was used successfully in 

Prudhoe Bay, Alaska, where injection of CO₂ foam increased oil recovery rates significantly, 

with reduced gas channeling and improved reservoir sweep efficiency [13]. 



6 

 

While foam flooding is a proven technology elsewhere, there is still a strong research gap on 

the use of foam flooding for Kazakhstani reservoirs. There are no detailed case studies or 

explicit documentation of foam flooding implementations in Kazakhstan. Thus, this study was 

designed to fill this knowledge gap by evaluating the feasibility and effectiveness of foam 

flooding in Kazakhstan's oilfield X located in the Mangystau region. Overall, novelty of the 

current study is found in innovative analysis and applied assessment of foam injection in 

Kazakhstani reservoir core, which offers valuable knowledge and a methodological approach 

for potential broader regional implementation. 

 Foam injection in EOR: results and case study insights 

Foam injection is an Enhanced Oil Recovery (EOR) technique that involves injecting a mixture 

of gases (e.g. CO₂, hydrocarbon gas, air, or steam) and surfactant to generate foam in the 

reservoir. This foam reduces gas mobility and diverts the flow into oil-rich zones, improving 

sweep efficiency. Over the past decades, numerous laboratory studies, field pilots, and 

simulations across the world have documented higher oil recovery, improved gas utilization, 

and viable economics with foam EOR. Major findings from global foam injection research, 

with verifiable sources from journals, industry reports, and conference papers were investigated 

and applied in the current research. 

2.1.4.1. Sweep Efficiency increase  

Many studies report significant incremental oil recovery when foam is applied, as foam blocks 

high-permeability “thief” zones and forces injectants into unswept regions: 

North Sea (Snorre Field) – The largest foam-EOR project to date, foam was applied during a 

water-alternating-gas (WAG) flood to control gas breakthrough. No major operational issues 

were encountered, and oil production rates increased. The foam treatment produced an 

estimated 250,000 standard m³ of additional oil, approximately 1.6 million barrels [18]. This 

showcases foam’s ability to recover substantial oil volumes by improving conformance in a 

mature offshore field. 

Northeast China (Huanxiling Heavy Oilfield) – After conventional steam flooding had reached 

a 33 % recovery factor, nitrogen-foam injection was piloted to target remaining oil. Over a 33-



7 

 

month pilot, foam recovered an extra 5.5 % of the original oil in place (OOIP). Scaling up to a 

9-well pattern for 54 months yielded a total of 9.75 % OOIP incremental oil [18]. Notably, 

foam-injection wells showed higher injectivity and oil rates than waterflood wells, indicating 

foam can boost production even after water/steam flooding cycles [18]. This case demonstrated 

foam’s effectiveness in heavy oil EOR, beyond traditional gas floods. 

Colombia (Cusiana Field, Volatile Oil Reservoir) – In a mature gas-injection project with high 

gas-oil ratios, a surfactant-alternating-gas (SAG) foam pilot was conducted in one injector well. 

Within 2–3 months of foam injection, oil rates in connected producers increased (or decline 

rates flattened) and GOR dropped in three offset wells [16]. The incremental oil due to foam in 

the first cycle was about 30,000 STB [16]. Although modest in volume, this was achieved in a 

high-recovery, late-life reservoir.  

United States (CO₂ Foam Floods) – Field pilots in CO₂-flooded reservoirs have consistently 

shown improved sweep and additional oil when foam is used for mobility control. For example, 

a Denbury Resources CO₂ flood pilot on the U.S. Gulf Coast used foam to remediate a high-

permeability zone. In one producer well, GOR was cut by nearly 4 times and oil output more 

than doubled during foam injection, with benefits lasting well beyond the pilot period [22]. 

Across the pilot pattern, oil production was maintained while GOR fell, greatly improving CO₂ 

utilization efficiency [22]. This translated into significant CO₂ savings (less recycled gas 

needed) and confirmed that foam can increase oil recovery by diverting CO₂ into previously 

bypassed zones [22]. Earlier CO₂-foam trials in the 1980s–90s (e.g. Rangely and North Ward-

Estes fields in the USA) similarly documented reduced gas channeling and incremental oil [15], 

[20], laying the groundwork for today’s larger-scale pilots. 

2.1.4.2. Gas Mobility Control and Efficiency Improvements 

A primary benefit of foam in EOR is its ability to drastically improve gas sweep efficiency and 

conformance: 

Reduced Gas Channeling and GOR – Foam increases the resistance to flow in high-

permeability streaks, delaying gas breakthrough and lowering produced GOR. In the Snorre 



8 

 

FAWAG project, injecting foam into a thief zone diverted gas to oil-saturated layers, resulting 

in a sustained oil rate uplift [18].  Processes compared are illustrated in Figure 5. 

 

Figure 5 - Comparison of gas, water-alternating gas (WAG), and foam injections [18] 

In the Denbury CO₂ flood pilot, wells that previously had to be shut in due to excessive GOR 

were able to produce with acceptable gas levels after foam treatment [18]. Across multiple 

pilots, foam has proven to constrain gas cycling – for example, CO₂ injectivity was intentionally 

reduced by 40–85 % in a West Texas foam trial, sharply cutting gas production in problem 

wells and improving overall flood efficiency [20]. By spreading CO₂ or injected gas more 

uniformly, foam increases the amount of oil contacted per unit of gas injected, making the EOR 

process more efficient. 

Improved Sweep and Contacted Oil – By plugging high-flow pathways, foam forces the 

injectant to invade lower-permeability zones that contain remaining oil. Field logs in 

Colombia’s Cusiana pilot confirmed that after foam injection, the target high-perm layer’s share 

of gas flow dropped from 49 % to 17 %, indicating injection was diverted into previously 

bypassed layers [16]. This deep diversion of flow translated to new oil production, as evidenced 

by the temporary ramp-up in oil from surrounding wells [16]. In the Gulf Coast CO₂-foam pilot, 

average oil rates stayed constant (instead of declining) while using less gas, implying that foam 

pushed CO₂ into unswept pockets of the reservoir to liberate additional oil [22]. Overall, foam’s 

mobility control leads to more uniform sweep of the reservoir, addressing a common 

shortcoming of gas injection EOR (which often leaves heterogeneities under-swept) [22]. 



9 

 

Higher Post-Flood Recovery Factors – Several foam projects achieved notable increases in final 

recovery. The Chinese heavy oil pilot reached nearly 10 % of OOIP extra recovery beyond what 

steam flood alone accomplished [18]. In the North Sea, implementing foam after waterflood 

and initial WAG added 250,000 standard cubic meter of oil that would have been otherwise 

unrecovered [18]. These case studies underscore a trend: foam injection can extend the 

productive life of a flood and capture incremental oil once conventional methods plateau. 

2.1.4.3. Operational Feasibility and Economic Considerations 

Research and field experience indicate that foam EOR can be practically implemented and 

economically beneficial under the right conditions: 

Operational Success in the Field – Foam injection has proven operationally feasible in diverse 

settings (offshore platforms, onshore fields, deep wells with high temperature, etc.). For 

instance, the Snorre FAWAG pilot was executed offshore with no major issues [18], and the 

onshore Cusiana SAG foam was pumped via coiled tubing into a deep, high-pressure well 

without incident [16]. After foam treatments, injectors generally recover their injectivity within 

days to weeks, meaning the foam does not permanently damage the formation. In Cusiana, the 

injector well returned to its normal injection rate ~2 weeks post-treatment, confirming low risk 

of plugging the reservoir completely [16]. Such findings have built confidence that foam can 

be deployed safely and repeatedly if needed. 

Cost Effectiveness and Gas Savings With the foam-based conformity control, it is also 

relatively less expensive and easier to implement than mechanical alternatives. Foam can be 

injected through existing wells, is relatively low-cost and has no potential to damage the 

reservoir, like gel plugs or well recompletions [22]. Field tests have demonstrated large CO₂ 

savings when foam and the gas were used for supplementary EOR operations [22]. By 

providing higher oil recovered per injected gas volume and reduced recycled gas [22], foam 

economizes costs in gas EOR surges. For example, air-foam injection is being investigated as 

a low-cost format of EOR, because air is abundant and unmetered. This choice of foam gas 

alone pushes economics up. The low cost of gas and the stimulating effect of foam to control 

mobility and air for low-medium oil oxidation makes air injection with foam economically 



10 

 

attractive in low-permeability reservoirs [17], this method is “more economical and feasible” 

for recovering remaining oil in a particular type of reservoir. 

Good Project Economics: Several foam experiments have published good project economics 

or, at least, incremental oil behind the expense. The extra oil (millions of barrels) from the 

Snorre FAWAG project obviously outweighed the cost of the surfactant [18]. The operator in 

Colombia noted a potential way to "improve the economic value of the project" [16] by reducing 

operational complexity, such as not being overly selective in foam placement. With a well-

selected candidate (high GOR issue, heterogeneous reservoir, etc.), the incremental oil revenue 

and/or gas cost savings usually balance the chemical and injection costs of a foam, allowing 

foam-EOR to be a profitable investment. 

2.1.4.4. Emerging Trends in Foam EOR Research 

The success of foam injection in many EOR contexts has led to continued research to improve 

foam performance and expand its use: 

Nanoparticle stabilized foams: A major technical target is the enhancement of foam stability 

in challenging reservoir conditions. Adding nanoparticles (like silica and polymers) makes 

foam compositions more stable to high temperatures, salt, and oil presence [18]. Research 

shows irreversible adsorption of nanoparticles at gas-liquid interfaces can not only thicken 

foam films, but can delay coalescence, allowing the foam to survive longer in the reservoir [18]. 

Preliminary tests indicate that nanotechnology-injected foams have mobility control at greater 

depths into the formation, potentially benefiting EOR efficacy. 

Broaden Applications: Researchers are exploring foam EOR in challenging and 

unconventional reservoirs. For example, a recent field pilot injected a hydrocarbon-based foam 

into a tight shale oil reservoir in an "industry-first" experiment to see whether foam can mobilize 

oil in "unconventional" formations [18]. Since foam may allow more CO₂ to be trapped in the 

formation during oil production, CO₂ storage (carbon sequestration) co-optimization is also 

being examined [22]. Additionally, hybrid foam processes combining low-tension polymers, 

alkaline compounds, or surfactants with foam are being explored to achieve simultaneous 

sweep conformance and mobilization of the residual oil [15], [18]. 



11 

 

Global Adoption and Learnings: The foam-EOR research has been a truly global pursuit with 

contributions from North America, Europe, Asia and the Middle East. The Siggins Field test in 

Illinois in the 1970s and pilots in Canada, the US, Europe and China in the 1990s have yielded 

decades of best practices and lessons learned from the field [18]. This understanding has just 

begun to be applied by contemporary pilots to generate more effective foam injection (ideal 

surfactants, slug sizes, injection schedules), such as in the carbonate fields of Oman, the low-

perm reservoirs of China and the mature fields of Latin America. In summary, this trend shows 

increasing confidence of foam EOR as a method to improve oil recovery while increasing the 

efficiency of gas flooding, making it both technically and economically viable. 

2.2. Geologic Context  

 Geological overview of oilfield “X”  

Oilfield “X”, located in geologically complex and multifaceted states, represents a source of 

interest in the exploration and development of oil and gas resources. Since its discovery and the 

first geological discoveries made at the end of the 20th century, its deposit has attracted the 

attention of specialists distinguished by its reservoirs and structure. The “X” field plays an 

important role in the oil and gas sphere of Kazakhstan, which determines its uniqueness for the 

national energy sector. Based on detailed studies, including analysis of cores from field wells 

carried out in 2018, basic data on the structure, mineralogy and petrophysical characteristics of 

productive horizons were obtained. Core material with a total area of 180 meters from one well 

was carefully studied at the Center for Scientific Laboratory Research of the KazNIPImunaigas 

branch of KMG Engineering LLP, where standard and special core studies were carried out. 

During the study of this core, the following indicators were identified in the Table 1.  

 

Table 1. reservoir technical properties [33] 

Porosity (%) Permeability (µm²) Grain density (g/cm³) 

5,14 0.0001 -0.0005 2.62 -2.71 

The average porosity of the rocks is about 5.14 % to 5.47 %, indicating low porosity of the 

reservoirs. Permeability values range from 0.00014 to 0.00021 µm², highlighting the limited 

filtration properties of the rocks [33]. The density values of rock grains were found to be from 

2.62 to 2.71 g/cm³, which indicates the predominance of heavy minerals [33]. These 



12 

 

characteristics and the results of special laboratory tests of the core emphasize the complexity 

of the geological structure of the field and the need for an integrated approach to its 

development and operation. Oilfield “X”, due to its unique features, is an important object for 

geological science and the oil and gas industry of Kazakhstan, providing new data for the 

research and development of such complex geological objects. 

 Geological structure and lithology 

In the Mangyshlak region, deep wells uncovered marine gray sediments of late Paleozoic age, 

which demonstrate a complex material composition, a significant degree of secondary 

transformations and dislocation. These deposits are part of the folded base of the Turan platform 

and have undergone post-sedimentary transformations corresponding to the stages of deep 



13 

 

metagenesis and greenschist metamorphism [32]. For a visual representation of the geological 

structure and location of research wells in this area, the well map is representing in Figure 6.  

 

 
Figure 6. Mangyshlak Peninsula. Layout of areas, 

on which the foundation is exposed by drilling. 

Black circles are areas where rocks were exposed under Triassic sediments 

lower structural tier of the foundation [32] 

 

 Paleontological data 

The deposits have not been characterized paleontologically, but their position in the section, as 

well as the presence in the fragments of granite destruction products, the age of which in the 



14 

 

Oymashinskaya area is determined to be Carboniferous, allows us to assume their Late 

Paleozoic age [32]. 

 Tectonic features 

Paleozoic deposits of the Zhetybay-Uzen stage are characterized by the boundary conditions of 

metagenesis and early stages of greenschist metamorphism, which confirms their inclusion in 

the upper structural stage of the basement of the Turan platform [32]. 

The base of the Mesozoic deposits of Mangyshlak includes a dislocated Paleozoic basement 

with two main rock complexes: the lower, more highly metamorphosed, and the upper, which 

is lower molasse with Carboniferous-Early Permian spore-pollen complexes [32]. These data 

provide the basis for the development of new techniques for predicting and searching for 

minerals in this geologically complex region. 

 Analysis of oil and gas potential  

In the context of the study published by Krupin (2011), special attention was paid to the study 

of the petroleum potential of the basement, especially granitoids, which represents a key aspect 

for assessing the prospects of the “X” field in comparison with similar geological structures of 

the world level. This analysis included an in-depth study of the lithological composition, 

textural features of the rocks and their geochemical characteristics. It is represented in 

geological profile along the line of wells 30-68-13 illustrated in Figure 7, made it possible to 

identify specific features characterizing high hydrocarbon potential [30]. 

It was found that the granitoids of the Field “X” deposit are characterized by a certain degree 

of metamorphization and changes caused by tectonic activity [30]. These processes have led to 

the formation of porous and fractured structures in rocks, which contribute to the accumulation 



15 

 

and preservation of hydrocarbons. An important aspect is the high level of permeability of these 

granitoids, which is a critical factor for the formation of effective hydrocarbon reservoir. 

 
Figure 7. Geological profile along the line of wells 30-25-12-10-13 [30] 

In addition, analysis of the organic carbon content in basement rocks indicates the presence of 

favorable conditions for the generation of hydrocarbons. Geochemical studies of the rocks 

confirm that the migration of hydrocarbons occurred under conditions conducive to their 

concentration in cracks and pores of granitoids, which in turn indicates the high potential of the 

oilfield “X” for oil and gas production. 

The study also highlights the importance of understanding the geological history of the region 

and the influence of ancient tectonic events on the formation of the geological structure of the 

field. Comparison with data on other fields in the world showed that similar geological 

processes and conditions could contribute to the formation of similar hydrocarbon reserves in 



16 

 

granitoids, which makes the “X” oilfield a promising target for geological exploration and 

exploitation.  

Thus, a detailed analysis of the oil and gas potential of the foundation at the “X” oilfield, based 

on a comparison of its geological, geochemical and tectonic characteristics with analogues in 

other parts of the world, demonstrates the significant potential of this deposit. Additionally, the 

study focuses on aspects such as granitoid depth, age and evolution, which together with 

geochemical data provide valuable information about the processes that led to the formation of 

potential hydrocarbon reserves. 

One of the key points of the study is the analysis of the dynamics of hydrocarbon migration and 

the mechanisms of their accumulation in granitoids. The use of advanced methods in 

geochemistry and petrophysics has made it possible to clarify the migration paths of 

hydrocarbon flows in basement rocks, revealing the features of their distribution depending on 

the characteristics of fracturing and porosity of the rocks. These results highlight the importance 

of microstructural studies for understanding the potential of deposits in complex geological 

conditions. 

 Structure of an oil reservoir in the granite massif of the “X” field 

The “X” oilfield, located in the south of Mangyshlak, is a unique example of an oil deposit in 

a granite massif. Based on long-term and field exploration, a reservoir model was developed 

that included granitoid intrusions as the main oil production target. 

 Reservoir model and capacitive properties of granite massif 

Research has shown that the formation of the capacitive properties of a granite massif is 

controlled by a number of factors, including heat shrinkage and the tectonic-caisson effect. 

These processes promote the formation of fracturing and porosity in granite, making it an 

effective reservoir for oil accumulation. The article examines in detail the model of a reservoir 

in igneous rocks and offers recommendations for additional exploration of the deposit [31]. 

 Prospects for additional exploration of the field 

Modern methods of seismic exploration and interpretation of geological data, including CSP 

(Common Scattering Point) technology, have made it possible to identify new promising areas 



17 

 

in the basement granitoids and Middle Triassic carbonates. This data can significantly increase 

the efficiency of exploration for oil and gas-bearing reservoirs in the “X” field. 

 Analysis of fractured-cavernous reservoirs 

The analysis carried out allows us to assert the existence of sheet-like areas of decompaction in 

the granite massif, which are the main reservoirs of oil. These zones are characterized by 

increased permeability and fracturing, which is confirmed by both drilling data and geophysical 

characteristics of the section: Figure 8 shows a model of an oil reservoir in the granite massif 

of the “X” area. 

 
Figure 8. Model of an oil reservoir in the granite massif of the “X” area: 

A – structural diagram of the reservoir in plan, B – geological sections, 1 – deep wells (a – exposed 

basement rocks, b – produced fountain inflows from granites); 2 – isohypsum on the roof of 

granites, m; zones: 3 – decompaction in granites associated with heat shrinkage phenomena, 4 – 

crushing associated with discontinuities; 5 – granites: a – coarse-crystalline, b – fine-crystalline; 6 

– metamorphic rocks; 7 – discontinuities; drilling fluid absorption intervals: 8 – insignificant (10–

15 m³/day), 9 – medium (from 10 to 40 m³/day), 10 – strong; 11 – open hole formation testing 

intervals, 12 – perforation intervals; 13 – wells under drilling or construction;  

the nature of the resulting fluid according to IPG: N – oil, NV – oil and water, RNG – solution, oil 

and gas; character of the resulting fluid when tested in a column: PN - oil overflow, NVN - slight 



18 

 

influx of water from oil, FN – oil gusher; NV – minor influx of water, NN – minor influx of oil, 

NV – oil and water; C – layer “dry” [31] 

Figure 9 shows a comparison of reflector and diffractor cubes imported into the interpretation 

project. 

 
Figure 9. Comparison of cubes of reflectors and diffractors imported into the interpretation project: a) cube of 

reflectors and diffractors b) joint representation of cubes of reflectors and diffractors with isochronous surfaces 

along horizons V1, V2 and VI. [31] 



19 

 

Figure 10 presents a time slice of a cube of scattered waves across wells, which contributes to 

a deeper understanding of the distribution of fractured-cavernous reservoirs. 

Figure 10. Time slice of a cube of scattered waves from wells 24-11-1E-22-27 [31] 

 

Figure 11 shows a structural map of the top of the granite intrusion and a map of the oil 

and gas potential of the granite intrusion, highlighting the most promising areas for further 

exploration and development. 



20 

 

 
Figure 11. Structural map of the top of the granite intrusion (left) and prospect map 

(index acoustic heterogeneity) oil and gas potential of granite intrusion: dark red color on the 

map on the right – the most promising areas [31] 

 

These illustrations are important for understanding the structure of the reservoir and confirm 

the hypothesis about the vein and reservoir nature of oil-bearing zones in the granite massif of 

the “X” oilfield. 

  Fluid evaluation 

Assessing changes in the average values of fluid properties of productive horizons in the 

reservoir and surface conditions is a key aspect in the development of oil and gas fields. As part 

of this study, the properties of formation fluids of Triassic productive deposits of the “X” 

oilfield were analyzed. Analysis and comparison were carried out based on the results of studies 

of oil and gas samples, taking into account the parameters approved in the project documents. 

The study showed that oil from the “X” oilfield is characterized by high gas content and 

volumetric coefficient. The saturation pressure for the T2 formation was 253 MPa, and for the 

granite intrusion - 189 MPa. Thermodynamic conditions of occurrence and high gas content 

contributed to the low density and viscosity of the reservoir oil. For example, in the Triassic the 

density was 0.715 g/cm³, and the viscosity was 0.42 mPa*s. Degassed oil of the Middle Triassic 

and granite intrusion shows a light composition, which led to low density and viscosity values, 

as well as a positive pour point. The density of oil from the T2 horizon was estimated at 0.8365 

g/cm³. The low content of asphalt-resinous substances with a high content of high molecular 



21 

 

weight paraffin hydrocarbons indicates the high quality of oil from the “X” oilfield. Gas from 

the “X” oilfield dissolved in oil is characterized by a high content of propane-hexane fractions 

and a significant content of ethane. Component analysis showed the presence of carbon dioxide 

in concentrations that differed from other deposits in the region. The results of studying the 

properties of reservoir fluids at the “X” oilfield confirm the high quality of oil and gas. Analysis 

data can be used to optimize the development and operation of the field, as well as to plan 

further research to improve the efficiency of hydrocarbon extraction. 

 Well logs evaluation 

At the Center for Scientific Laboratory Research of KMG Engineering LLP 

"KazNIPImunaigas" standard and special comprehensive studies of core from the “X” oilfield 

were carried out [33]. The core material, totaling 180 meters in volume, underwent a 

comprehensive assessment including core acquisition, spectral gamma scanning, daylight and 

ultraviolet photo documentation, macroscopic characterization and selection of cylindrical 

samples for further analysis. 

The use of an SPGL-300 spectral gamma scanner to analyze a 180-meter-long core provided 

data on the natural radioactivity of the rocks result that is presented in Figure 12. This stage 

made it possible to determine the content of thorium, potassium, and uranium in the rocks, 

which is key for further interpretation of the lithological composition.  

 



22 

 

 
Figure 12 Results of spectral gamma-ray activity of a full-size core from the “X” oilfields well [33]. 

Photo documentation in Figure 13 provided visual evidence of the condition of the core, 

important for confirming macroscopic observations and lithological analysis.  

  



23 

 

  
Figure 13. Results of photo documentation of core 1m-18m from “X” oilfield well [33].  

As a result of the macroscopic description, the main types of rocks were identified: tuff 

sandstone, tuff siltstone, carbonaceous and micaceous siltstone, which indicates the diversity 

of sediments in this well interval. Standard laboratory tests of the core included determination 

of mineral density, porosity, permeability, carbonate content and lithological description of the 

samples. Research data confirms the high filtration and reservoir characteristics of the reservoir 

rocks of the “X” oilfield, which is the basis for optimizing further development of the field. The 

studies of core from the “X” oilfield demonstrate the complexity and diversity of the geological 

structure of the field. Data obtained from gamma ray spectral scanning, macroscopic 

characterization and standard laboratory analyzes provide valuable information for geological 

modeling and reservoir development. 

 Core evaluation  

An in-depth study of core from well of the “X” oilfield were carried out on 82 cylindrical 

samples covering various depth intervals of the well. An UltraPoroPerm-500 device from Core 

Lab Instruments was used to determine the mineralogical density of grains, open porosity 

coefficients and absolute permeability of rocks using helium and nitrogen, respectively. 

The determination of mineralogical density and open porosity by helium was carried out on a 

porosimeter of the UltraPorePerm 500 installation, where the volume of the mineral skeleton 

of the samples was determined using helium according to the Boyle-Mariotte law. The 

measurements made it possible to calculate the volumes of the mineral skeletons of the samples 

and, accordingly, their open porosity (Figure 14). The instrument calibration process was 

carried out immediately before measurements, ensuring the accuracy of the data obtained. 



24 

 

 

 
Figure 14. “X” oilfield well porosity distribution by depth 

To determine the absolute permeability to nitrogen, the UltraPorePerm 500 permeameter was 

used. Core samples were placed in a Hassler core holder, on the side surface of which a 

hydrostatic pressure of 276 MPa was applied. The permeability of rocks to gas was calculated 

using the Darcy equation. These tests allowed us to evaluate the ability of rocks to transport gas 

through their structure (Figure15). 



25 

 

 

 

  
Figure 15. “X” oilfield well permeability distribution by depth 

Detailed lithological descriptions of all 82 samples provided a comprehensive characterization 

of the studied rocks, including their textural and structural features, which is critical for 

geological analysis and interpretation of rock formation conditions. Standard and special 

studies of core from well of the “X” oilfield deposit provided valuable information on the 

mineralogical density, open porosity and absolute permeability of the studied rocks. The data 

obtained are of significant importance for further geological modeling of the field and planning 

its development. 



26 

 

 Hydrochemical water analysis 

As part of the hydrochemical analysis of water from well No. 68 of the “X” oilfield, a test was 

performed to determine the component composition of the water. The study was carried out in 

a hydrochemistry laboratory using standard analysis methods in accordance with GOST and 

other regulatory documents. 

As a result of hydrochemical analysis, the following results were obtained: The pH value was 

5.3, indicating an acidic reaction of the water (GOST 26449.1-85 clause 4). The measured 

density of water is 1.092 g/cm³ (GOST 18995.1-73). A high content of calcium (Ca2+), 

magnesium (Mg2+), the sum of potassium and sodium (Na+ + K+), and chlorides (Cl-) was 

determined, which indicates significant mineralization of the water. The calcium content was 

98196 mg/dm³, magnesium - 15808 mg/dm³, the sum of potassium and sodium - 386630 

mg/dm³, chlorides - 814290 mg/dm³. The calculated total salinity of the water reached 1317124 

mg/dm³, highlighting the high degree of salinity. Defined as Cl-Ca, which characterizes the 

water as calcium chloride. Calculated at 6200 mEq/L, which indicates high water hardness.  

Table 2. Hydrochemical analysis of water from well of the “X” oilfield 

pH 5.3 

Density 1.092 g/cm³ 

Mineral composition 

The calcium content was 98196 mg/dm³, magnesium - 

15808 mg/dm³, the sum of potassium and sodium - 

386630 mg/dm³, chlorides - 814290 mg/dm³ 

Total mineralization 1317124 mg/dm³ 

Total water hardness 6200 mEq/l 

 

The results of hydrochemical analysis of water from well of the “X” oilfield demonstrate high 

mineralization and water hardness, which has significant consequences for the design of water 

treatment and drainage systems during field development. The Cl-Ca water type emphasizes 

the predominance of chloride and calcium in the mineral composition, which is an important 

factor in the analysis of water corrosivity and the selection of equipment materials. 

An important element of the analysis is the study of changes in groundwater salinity with depth, 

which is visually presented in Figure 16 of the article. This graph not only clearly illustrates the 

increase in water salinity as one goes deeper into the earth's crust, but also emphasizes the 

complex relationship between geological processes and the hydrochemical composition of 

formation waters. The figure 10 clearly shows how water salinity gradually increases in the 

upper layers, which may be due to the penetration of surface water and its interaction with 



27 

 

rocks. However, in deeper layers, in particular in pre-Jurassic sediments, there is a sharp change 

in this trend. This indicates the presence of other processes affecting the composition of 

formation waters, such as deep degassing of the Earth and volcanic activity, which can 

introduce rare and valuable elements into the waters [34].  

 
Figure 16. “X” deposit. Changes in groundwater salinity with depth [34]  

 Geological report 

The “X” oilfield, with its unique geological structure and complex of geophysical, 

hydrochemical and petrophysical characteristics, is of significant interest to both the geological 

community and the oil and gas industry. The variety of studies and analyzes carried out 

emphasizes the complexity and multifaceted nature of the object under study, requiring a 

multidisciplinary approach for its understanding and development. The core study provided 

important information about the porosity, permeability and mineralogical composition of the 

rocks, which is critical for assessing their reservoir properties and hydrocarbon recovery 

efficiency. Hydrochemical analysis of water revealed high mineralization and hardness of the 

 Groundwater of Middle-Upper Miocene deposits 

 Groundwater of Albian-Cenomanian deposits 

 Groundwater of Jurassic productive deposits 

o Groundwater of Triassic-Paleozoic sediments 



28 

 

water, which requires special attention when planning water treatment and disposal systems. 

Petrographic and mineralogical studies of rocks have provided detailed data on their textural 

and structural features and processes of secondary transformation, which contributes to a deeper 

understanding of the conditions of rock formation and their properties. Analysis of reservoir 

fluids, in turn, highlighted the compositional and thermodynamic conditions of reservoir oil and 

gas, which are key to developing and maintaining production. In general, the results of studies 

of the “X” oilfield provide a valuable database for further geological modeling, development 

and optimization of hydrocarbon production methods. This data not only facilitates efficient 

field development, but also makes a significant contribution to scientific knowledge about such 

geological objects, allowing for improved methods of exploration and exploitation of oil and 

gas resources. 

  



29 

 

3. METHODOLOGY 

3.1. Bulk foam stability test 

The foam stability test was dedicated to screening foam formulations that could be applied to 

further experiments. Due to connate water hardness issues and the incompatibility of 

multivalent ions with many surfactants, it is assumed that preconditioning of the reservoir is 

needed and would be conducted during the late stages of water flooding. The experiment 

evaluates how the different concentrations of NaCl, bio-surfactant, and nanoparticles in distilled 

water affect foam stability. Nitrogen acts as a gas for foam generation. The following equipment 

is used during the experiment: a magnetic stirring device, a homogenizer (Figure 17), a 500 ml 

volumetric flask, a highly permeable diffuser as a foam generator, and a digital camera.  

 

Figure 17. Photo of homogenizer application to prepare nanoparticle (np) solutions 



30 

 

The foam half-life time experiment design consists of two parts: preparation of solutions and 

generation of the foam, followed by subsequent documentation of the pattern of its degradation 

(Figure 18). The solution is prepared by sequentially dissolving NaCl, bio-surfactant, and 

nanoparticles in distilled water. Each stage of preparation is accompanied by stirring the 

composition using a magnetic stirrer for half an hour at a speed of 250 rpm. Due to the difficulty 

of dispersing nanoparticles in a solution, it is necessary to leave the solution for 15 minutes in 

an ultrasonic homogenizer, resulting in increased transparency of the solution. When the 

solution is ready, it is placed in a volumetric flask with a diffuser lowered inside; gas is supplied 

through the diffuser which, passing through the prepared solution, forms a column of foam 

(Figure 19).  

 
Figure 18. Foam stability test setup [40] 

 

After the column reached a volume of 500 ml, the nitrogen supply was stopped, and the process 

of foam degradation was monitored. The pattern of foam degradation is captured by the camera, 

with special attention paid to the behavior of the foam when reaching the 400 and 300 ml levels 

(Figure 20).  

 



31 

 

 

Figure 19. Foam generation through using diffuser  

 

 
a) 

 
b) 

 
c) 

Figure 20. Experiment flow of foam stability test: 

a) The foam column at the start of experiment, b) The foam column during the experiment, c) The foam column 

at the end of the experiment 

 

The effects of increasing salinity and nanoparticle concentration on foam stability were 

examined. Two expected effects were considered: the detrimental effect of increasing salt 

concentration and the benign effect of increasing nanoparticle concentration on foam stability. 

To investigate how different concentrations of surfactant and sodium chloride affect foam 



32 

 

stability, the experiments were repeated with different proportions of surfactant and salt. Table 

3 shows the combinations examined. 

Table 3. Bio-terge surfactant and salinity variation for foam test stability  
 

BIO-TERGE surfactant, 

% 

0,1 

0,25 

0,5 

0,75 

a) 

NaCl % 

0,005 

0,25 

0,5 

1 

2,5 

3,5 

b) 

 

The graphs allow us to determine the most effective solution of the foam for conducting further 

experiments of core-flooding.  

3.2. Core description 

The second type of experiment conducted is core flooding. The purpose of the core flooding 

experiment is to identify the efficacy of foam generation and propagation in porous media and 

how foam interacts with the residual oil from prior displacement processes. For the core 

flooding experiment, we use a solution for foam generation, the composition of which was 

determined from half-life tests conducted previously. One-inch diameter core samples collected 

from the “X” oilfield, by core drilling technique, are shown in Figure 21. 

 

Figure 21. Oilfield “X” reservoir core plugs used in coreflood experiments. 



33 

 

Table 4. Core sample parameters 

 

 d
ia

m
et

er
 

le
n

g
th

 

V
o
lu

m
e 

D
ry

 

w
ei

g
h

t 

W
et

 

w
ei

g
h

t 

W
a
te

r 

w
ei

g
h

t 

V
o
id

 

v
o
lu

m
e 

P
o
ro

si
ty

 

P
er

m
ea

b
il

it
y
 

D
ep

th
 

 mm mm mm3 g g g mm3 fraction mD m 

Indiana 38.1 73.2 83400 190.1 201.7 11.63 11630 0.14 24  

Berea 38.1 73.8 83900. 181 195.5 14.42 14420 0.17 195.3  

“X-15” 37.6 52.7 58500 131.9 140 8.14 8140 0.08 0.15 3178.93 

“X-13” 37.6 53.1 59000 134.6 139.3 4.74 4740 0.14 0.2 3178.36 

“X-10” 37.7 54.0 60200 135.5 143.6 8.03 8030 0.13 0.45 3177.37 

 

For visual coloration of dodecane, an insignificant amount of heavy oil was added. Dodecane 

properties are given in Table 5. 

Table 5. Dodecane physical and chemical properties [27] [28][29]  

Chemical Formula C₁₂H₂₆ 

Molecular Weight 170.34 g/mol 

Appearance Colorless liquid with a mild aliphatic hydrocarbon odor 

Melting Point Approximately −10.0 to −9.3 °C (14.1 to 15.2 °F)  

Boiling Point Approximately 214 to 218 °C (417 to 424 °F) 

Density at 20 °C 0.7495 g/mL 

Viscosity at 25 °C 1.34 mPa·s 

Vapor Pressure at 25 °C 18 Pa 

Flash Point 71 °C (160 °F) 

Autoignition Temperature 205 °C (401 °F)  

Refractive Index at 20 °C 1.421  

Water Solubility Less than 1 mg/mL at 25 °C 

Odor Gasoline-like to odorless 

Critical Temperature Approximately 385 °C 

Critical Pressure Approximately 18 bars 

 

  



34 

 

3.3. Core flooding experiment  

A core saturator is needed to prepare the core for further flooding. The core flooding experiment 

is conducted using the “Core Flooding System (CFS-350)” by Vinci Technologies. The 

apparatus is presented in the FOAM EVAL-HPHT Foam Analyzer setup, which allows for the 

measurement of parameters such as gas flow rate, liquid flow rate, and volume injected in real 

time, which is needed to obtain a reliable evaluation of efficiency. The experimental procedure 

begins with the preparation of the core sample, which is essential for subsequent flooding 

experiments. First, the core must be placed in a core saturator filled with 1% NaCl brine under 

vacuum conditions. This step ensures the complete saturation of the core sample. As part of the 

apparatus setup, the core sample is placed in the core holder, and to avoid channeling or 

flooding the fluid side of the core, the confining pressure is set at a value of 300 PSI. The next 

step is to charge the accumulator with oil. When the equipment is completely assembled, the 

flooding operation should be started. The flooding starts with oil injection. The oil is injected 

until no more brine is produced. At the end of the oil injection, the rock sample is in conditions 

that maximally replicate the initial conditions of the reservoir with initial oil and connate water 

saturation. As foam flooding is a tertiary recovery method that is applied at the very end, 

conventional flooding techniques, such as water flooding and gas flooding, should be conducted 

first. The gas and water flooding designs differ from initial oil flooding only by the liquid 

injected into the core-gas and water, respectively. The influence of capillary pressure end 

effects in the flow-based approach was studied by conducting brine injection at different flow 

rates. Higher flow rates reduce the capillary effect and help in the evaluation of displacement 

efficiency under viscous flow conditions, whereas lower flow rates emulate capillary-

dominated conditions, resulting in more selective oil displacement. After conventional water 

flooding, the core will be in the condition of residual oil and high water cut, which most 

accurately reflects the current condition of the oil reservoir of the “X” oilfield. After water 

flooding, gas flooding proceeds to the point of residual oil to gas flooding. For conducting the 

foam flooding experiment, simultaneous injection of nitrogen and foam solution is needed 

(Figure 22). 



35 

 

 

Figure 22. Schematic of the SRP 350 core flooding apparatus setup for foam flooding by Vinci Technologies 

[56] 

 

 
Figure 23. Photo of core flooding experimental setup 

Additionally, to investigate the lamella hardness effect of foam on the recovery factor, foam 

flooding is repeated but with the addition of 0.1 % nanoparticles into the foam solution. The 

flooding is conducted until the oil production stops. During the experiment, the data is collected 

in real-time automatically by Vinci Technologies software with the possibility of subsequent 

data export. For the data analysis, the charts of pressure difference vs. pore volume injected and 



36 

 

recovery factor are built in one plot. Such a plot is created for each flooding step, i.e., for water, 

gas, foam, and foam with nanoparticle addition. From the charts, it is possible to evaluate the 

pressure difference response to the production of additional oil during the continuous flooding 

that is necessary for the evaluation of flooding process efficiency. After core flooding with N2 

application is finished, the core is carefully cleaned by the Soxhlet extraction method with the 

application of toluene solvent (Figure 24) to prepare the core for the duplicate experimental 

suite, but with CO2 gas instead of N2. 

 

 
a) 

 

b)   

Figure 24. Soxhlet extractor 

a) Photo of extraction process b) Cleaning setup[54] 

  



37 

 

3.4. Experimental analysis 

From flooding experiment data, graphs were plotted of the recovery factor and pressure 

difference from the flooding experiment as a function of pore volumes injected. Additionally, 

plots of recovery factor against apparent viscosity with increasing pore volume injected were 

generated. The estimated apparent viscosity (since the flooding was modeled a single-phase 

flow), was computed by means of Darcy's law.  

𝜇𝑎𝑝𝑝 =
𝑘 ∗ 𝐴 ∗ ∆𝑃

14700 ∗ 𝑄𝑡 ∗ 𝐿
 

Where: 

𝜇𝑎𝑝𝑝 (𝑐𝑃) − 𝑎𝑝𝑝𝑎𝑟𝑒𝑛𝑡 𝑣𝑖𝑠𝑐𝑜𝑠𝑖𝑡𝑦 

∆𝑃 (𝑝𝑠𝑖𝑔) − 𝑝𝑟𝑒𝑠𝑠𝑢𝑟𝑒 𝑑𝑟𝑜𝑝 

𝑄𝑡 (𝑐𝑐
𝑠⁄ ) − 𝑖𝑛𝑗𝑒𝑐𝑡𝑖𝑜𝑛 𝑓𝑙𝑜𝑤 𝑟𝑎𝑡𝑒 

𝐿 (𝑐𝑚) − 𝑐𝑜𝑟𝑒 𝑙𝑒𝑛𝑔ℎ𝑡 

𝐴 (𝑐𝑚2) − 𝑐𝑜𝑟𝑒 𝑐𝑟𝑜𝑠𝑠 𝑠𝑒𝑐𝑡𝑖𝑜𝑛 𝑎𝑟𝑒𝑎 

𝑘 (𝑚𝐷) − 𝑝𝑒𝑟𝑚𝑒𝑎𝑏𝑙𝑖𝑡𝑦  
 

Darcy’s law is used in that it is a reliable method to describe fluid flow through porous media 

and to obtain an understanding of the effect of viscosity on flow dynamics during the 

displacement process.  In such an approach, the apparent viscosity captures overall mobility, 

which is a combination of fluid viscosity and saturation-dependent relative permeability.  This 

enables comparison of performance across cores of vastly different permeability that would be 

difficult to understand in terms of pressure drop. 

  



38 

 

4. RESULTS AND DISSCUSSION 

4.1. Foam stability test 

Figure 25 illustrates the foam half-life time for the various salinity and AOS surfactant 

concentrations. From the figure, it is obvious that the half-life time differs only at the very low 

salinity until 1 %, and with increasing salinity, half-life time variation shrinks and is drastically 

reduced. From the figure could be observed that the dependence of foam half-life time is not 

directly dependent on surfactant concentration for concentrations above 0.1 %. The maximum 

foam life time corresponds to a surfactant concentration of 0.25 %, while the concentration of 

0.75 % represents a typical value of half-life time. However, at the salinity of 1 %, the trend is 

reverses with 0.75 % surfactant concentration giving the best results. This phenomenon can be 

attributed to the negligible dependence of foam stability on surfactants concentration above the 

critical micelle concentration (CMC) of 0.3 g/L [55]. Since 1 % salinity is selected as 

representative of reservoir brine, the typical result using less chemical is chosen for core flood 

experiments. Core flood experiments using foaming formulations were, hence, conducted with 

0.25 % surfactant and 1 % brine. 

 

Figure 25. Foam stability test results 

The foam that was just generated has bubbles in the range of 0.5 mm in diameter, while at the 

final stage of the experiment, the bubbles could reach 10 mm in diameter (Figure 20). 

 

0

50

100

150

200

250

300

350

0 0.5 1 1.5 2 2.5 3 3.5

F
o
am

 h
al

f-
li

fe
 t

im
e,

 m
in

 

NaCl, %

0.1% surfactant concentration 0.25% surfactant concentration

0.5% surfactant concentration 0.75% surfactant concentration



39 

 

To better understand the difference between N2 and CO2-generated foam stability at 

atmospheric conditions, results from a similar experiment conducted by Bello et al. 

(2022) with CO2 generated foam are presented as Figure 26.  

 

Figure 26. CO2 bulk foam generated by 0.1 % BIO-TERGE surfactant and 0.5 % of silica nanoparticles 

in 1 % NaCl [41] 

By comparing the data, it is feasible to determine that the half-life of nitrogen foam 

containing 0.1 % silica nanoparticles and 0.1 % BIO-TERGE surfactant in 1 % NaCl was 

16.6 % longer than that of CO2 foam using the same chemical solution. 

 

4.2. Oilfield “X” core sample flooding results 

 “X-10” Core flooding experiment results 

Figure 33 illustrate how the apparent viscosity and recovery factor change with the pore 

volume (PV) injected and the pressure difference required to flow at the chosen constant 

rate. The flooding scheme started core preparation to achieve the starting condition of 

initial oil saturation at immobile brine saturation. This is followed by displacement 

experiments starting with brine injection, followed by gas injection, foam injection, and 

final foam flooding with nanoparticle addition. Waterflooding was conducted in order to 

produce residual oil condition as the starting point for any enhanced oil recovery 

methodology, as the brine injection is the most conventional secondary recovery 

technique that is applied in the majority of the field. Reservoir brine was represented by 

400

600

800

1000

1200

1400

1600

0 100 200 300 400

F
o
am

 v
o
lu

m
e 

(m
l)

Time in minutes



40 

 

a 1 % NaCl solution with the assumption that reservoir preconditioning was necessary to 

suppress divalent ion interactions with added foam stabilizers. To investigate how the 

viscous forces, affect the flooding process and eliminate capillary end effects, the brine 

flooding was conducted in 3 stages: 1 cc/min, 2 cc/min, and 3 cc/min injection flow rate. 

From the figure, the effect flow rate on the pressure drop could be clearly obtained. Each 

step of the flow rate increase is accompanied by an increasing pressure difference 

response, accompanied by additional recovery and corresponding saturation-dependent 

relative permeability changes. As observed in Figure 30, the total recovery factor (RF) 

achieved after brine injection was 15.36 % after 15.5PV was injected. By this step of 

injection, the reservoir is in the terminal condition of secondary recovery which is needed 

for further recovery techniques and comparison of EOR flooding techniques. 

To examine the foam flooding effect, it is needed to treat the foam flooding as an 

independent technique to separate foam flooding recovery mechanisms from those of gas 

flooding. Thus, gas flooding was performed after waterflooding as a natural injection 

sequence prior to a decision to initiate foam flooding to resolve conformance issues in 

gas flooding.  Thus, nitrogen gas flooding was conducted after reaching waterflood 

residual oil saturation. Figure 30 shows that with a 1 cc/min gas flow rate, a recovery 

efficiency of 29.3 % was achieved in nitrogen gas flooding. From the gas flooding 

pressure drop response, the moment of the gas breakthrough could be observed. After a 

cumulative effect of 30 PV of fluid injection, the curve acquired a plateau trend, followed 

by stabilization at a significantly lower pressure drop than waterflooding, which is 

explained by lower resistance to gas flow through a porous media. The graph reached a 

plateau in recovery factor coincident with gas breakthrough. With an established residual 

oil to gas flooding terminal condition, the results of the subsequent foam flooding can be 

assessed independently. 

The foam flooding without nanoparticles increased oil production from 29.3 % to 35 %. 

The foam was generated by simultaneous injection of 0.25 % surfactant solution and 

nitrogen. The flow rate was established as 0.6 cc/min for foam solution injection and 0.4 

cc/min for N2 gas injection, with the total flow rate fixed at 1 cc/min. This gas fractional 

flow was chosen based upon the observed stability of foam exiting the core flood in 



41 

 

screening tests (see Figure 30). In the plateau phase for recovery, the apparent viscosity 

reached 6.5 cP. With the expectation of higher-pressure difference responses with 

increasing flow rate and the challenges of foam stability control, the flooding was 

conducted using only one flow rate.  

 
Figure 27. Observed process, of foam pushing out the out, in transparent tube installed on outlet line 

The effect of foam lamella integrity on residual oil production was investigated by adding 

silica nanoparticles into the solution. For a fair comparison, the flooding design remains 

the same as foam flooding without nanoparticles. From the flooding diagram can be 

observed that 0.1 % nanoparticles in the foam solution allowed production of an 

additional 3.3 % of oil with a total oil produced value of 38.3 %. The apparent viscosity 

at the steady flow reached 8.5 cP, which is 23 % higher than in foam injection without 

nanoparticles. The character of production collected in outlet line changed significantly 

with the addition of nanoparticles to the foam flooding formulation (Figure 28). From the 

pressure response, it can be inferred that adding nanoparticles into the foam solution 

allows for an increase in lamella resilience that in turn leads to significantly higher 

propagation pressure to support a fixed injection rate. The results of nanoparticle 

application demonstrate a positive effect on the production of residual oil, but only if 

reservoir displacement processes can support such a pressure drop. 

  



42 

 

 
a) 

 
b) 

Figure 28 Comparison of foam texture of nitrogen generated foam (a) and CO2 generated foam (b) 

To examine the distinctions between the application of CO2 and N2 foam, core sample 

"X-10" was cleaned using the Soxhlet extraction method (Figure 29) and the injection 

sequence was repeated with CO2 instead of N2. 

 
a) 

 
b) 

Figure 29. Indiana core sample (a) before and (b) after cleaning 

 



43 

 

 
Figure 30. N2 application “X-10” core flooding experiment results apparent viscosity and RF vs PV 

 



44 

 

 
 

Figure 31. CO2 application “X-10” core flooding experiment results, apparent viscosity and  RF vs PV 

 

Table 6. “X-10” core flooding recovery factor increment comparison table 

 

 

RF 

N2 CO2 

Water flooding 1cc/min 9 10.1 

Increment +5.5 +4.9 

Water flooding 2cc/min 14.5 15 

Increment +0.86 +4.5 

Water flooding 3cc/min 15.36 19.5 

Increment +13.94 +14.7 

Gas flooding 1c/min 29.3 34.2 

Increment +5.7 +1.8 

Foam flooding 1cc/min 35 36 

Increment +3.3 +4.4 

Foam np flooding 1cc/min 38.3 40.4 



45 

 

 

 
Figure 32. N2 application “X-10” core flooding experiment results differential pressure and RF vs PV 

 



46 

 

 
Figure 33. CO2 application “X-10” core flooding experiment results differential pressure and RF vs PV 

The shift from nitrogen to carbon dioxide as the gaseous phase in the core flood experiment 

(Figure 30) introduced significant alterations in the observed pressure and recovery dynamics, 

reflecting the distinct properties of CO2. Notably, CO2 injection alone yielded higher 

incremental oil recovery, in stark contrast to the moderate increase observed with nitrogen gas.  

This difference may be attributed to several factors, including: (1) the higher solubility of CO2 

in oil, leading to swelling and viscosity reduction but also potential trapping of CO2 within the 

pore space; (2) the potential for CO2 to alter the interfacial tension between oil and water, 

affecting capillary forces and displacement efficiency; and (3) the potential for CO2 adsorption 

onto the rock surface, altering wettability. The lower increase in the pressure drop during CO2 

foam injection, coupled with the "bumpy" pressure curve, indicates differences in foam stability 

compared to the nitrogen foam system. In particular, CO2 may diffuse through lamellae quickly 

and also has a tendency to change the wettability as compared to N2 foam which contributes to 



47 

 

the reduced foam quality. The nanoparticles have a higher proportional impact on oil recovery, 

further highlighting the complex interplay of fluid properties, interfacial phenomena, and pore-

scale interactions in CO2-based enhanced oil recovery. Ultimately, the success of CO2 foam for 

enhanced oil recovery is more complex. The change in nanoparticles can also be higher. 

However, CO2 foam is generally less stable. 

  “X-13” Core flooding experiment results 

 
Figure 34. N2 application “X-13” core flooding experiment results apparent viscosity RF vs PV 

 



48 

 

 
Figure 35. CO2 application “X-13” core flooding experiment results apparent viscosity and RF vs PV 

 

Table 7. “X-13” core flooding recovery factor increment comparison table 

 RF 

N2 CO2 

Water flooding 1cc/min 26 24.32 

Increment +5.8 +6.18 

Water flooding 2cc/min 31.8 30.5 

Increment +5.9 +9.4 

Gas flooding 1c/min 37.7 39.9 

Increment +10.6 +3.1 

Foam flooding 1cc/min 48.3 43 

Increment +6.8 +3.8 

Foam np flooding 1cc/min 55.1 46.8 

 



49 

 

 
Figure 36. N2 application “X-13” core flooding experiment results dP, RF vs PV

 
Figure 37. CO2 application “X-13” core flooding experiment results dP, RF vs PV 

 



50 

 

 

4.3. Outcrop core samples flooding results 

 Berea core sample flooding result 

 
 

Figure 38. N2 application Berea core flooding experiment results apparent viscosity and RF vs PV 

 

 

 

 



51 

 

 
 

Figure 39. CO2 application Berea core flooding experiment results apparent viscosity and RF vs PV 

 

Table 8. CO2 and N2 foam Berea core sample flooding comparison 

 

 

RF 

N2 CO2 

Water flooding 1cc/min 24.13 24.88 

Increment +2.77 +2.77 

Water flooding 2cc/min 26.9 27.65 

Increment +1.9 +2.5 

Water flooding 3cc/min 28.8 30.15 

Increment +3.32 +8.35 

Gas flooding 1c/min 32.12 38.5 

Increment +3.08 +0.7 

Foam flooding 1cc/min 35.2 39.2 

Increment +2.1 +0.9 

Foam np flooding 1cc/min 37.3 40.1 
 



52 

 

 
Figure 40. N2 application Berea core flooding experiment results dP, RF vs PV 

 

 
Figure 41. CO2 application Berea core flooding experiment results dP, RF vs PV 

 



53 

 

 Indiana core sample flooding result 

 
Figure 42. N2 application Indiana core flooding experiment results apparent viscosity and RF vs PV 

 

 

 



54 

 

 
Figure 43. CO2 application Indiana core flooding experiment results apparent viscosity and RF vs PV 

 

Table 9. Indiana core flooding recovery factor increment comparison table 

 

 

RF 

N2 CO2 

Water flooding 1cc/min 25.1 24.13 

Increment +2 +2.77 

Water flooding 2cc/min 27.1 26.9 

Increment +1.7 +3.33 

Water flooding 3cc/min 28.8 30.23 

Increment +3.33 +4.77 

Gas flooding 1c/min 32.13 35 

Increment +3.07 +0.9 

Foam flooding 1cc/min 35.2 .35.9 

Increment +2.1 +1.1 

Foam np flooding 1cc/min 37.3 37 

 



55 

 

 
 

Figure 44. N2 application Indiana core flooding experiment results dP, RF vs PV 
 

 
Figure 45. CO2 application Indiana core flooding experiment results dP, RF vs PV 

 

 



56 

 

5. DISCUSSION 

The work was conducted to compare the viability of N₂ and CO₂-based foams flooding 

formulations in the “X” oilfield. Four key aspects influencing foam behavior, and by 

extension, enhanced oil recovery outcomes, were highlighted: (1) mechanical properties 

of foam under atmospheric conditions, (2) mechanical properties of foam in porous 

media, (3) impact of lithology on EOR performance, (4) performance of foam boosting 

additives. Differences observed between CO₂ and N₂ foam performance highlight the 

features of each type of foam which should be considered before application as EOR 

technique. 

 

 

5.1. Mechanical properties of foam under atmospheric conditions: 

 Foam column stability  

According to the measured data, the CO₂-generated foam's half-life is significantly less 

than that of the N₂-generated foam. Essentially, under the same conditions, the carbon 

dioxide-based foams decomposed far faster than the nitrogen-based ones. This 

experimental finding aligns with a comparison found in the literature: Compared to N₂-

foam, CO₂-foam is significantly less stable (has a shorter lifetime) for a given surfactant. 

In accordance with the fact that CO₂ has a significantly higher solubility in the aqueous 

phase (about one to two orders of magnitude greater than N₂), Farajzadeh et al. discovered 

that the half-life of a foam made from CO₂ was significantly less than that of a foam made 

from N₂ under similar conditions [42].  

The stability of foams is mainly governed by the strength of the very thin liquid 

films (lamellae) and the liquid-draining rate from the foam films. As foam is 

produced, liquid will drain from the lamellae under the influence of capillary and 

gravitational forces. Liquid from the films is pushed into the Plateau border 

channels through gravity and capillary suction [43], leading to the gradual 

thinning of the lamellae. The disjoining pressure, or the forces that separate the 

https://www.osti.gov/servlets/purl/2418205#:~:text=On%20the%20other%20hand%2C%20Figure,was%20estimated%20from%20the%20values
https://www.osti.gov/servlets/purl/2418205#:~:text=On%20the%20other%20hand%2C%20Figure,was%20estimated%20from%20the%20values
https://vdoc.pub/documents/enhanced-oil-recovery-field-case-studies-6imbh4qfd4k0#:~:text=be%20useful%20when%20the%20author,Marangoni%20effect%3A%20The
https://vdoc.pub/documents/enhanced-oil-recovery-field-case-studies-6imbh4qfd4k0#:~:text=be%20useful%20when%20the%20author,Marangoni%20effect%3A%20The


57 

 

liquid films, falls off as the films become thinner. In the end, the films burst; 

there’s nothing to keep them apart but the distance,  which is no longer sustainable. 

 Foam heterogeneity effects 

Experimentally, foam generated exiting coreflood tests with CO₂ was observed to contain 

larger, more heterogeneous bubbles, whereas N₂-derived foam consisted of smaller, more 

uniform bubbles (Figure 28).  

This distinction can be explained by capillary pressure (Pc) effects described by the 

Young–Laplace equation: 

𝑃𝑐 =
2𝛾

𝑟
    (1) 

where: 

𝛾 - is surface tension; 

𝑟 – is radius of single bubble;  

Thus, smaller bubbles have a greater internal pressure (Laplace pressure) , and as 

a result, their liquid films are stronger and they are much more resistant to 

coalescence [48], additionally , reports show that sub-millimeter bubbles are stable 

orders of magnitude longer than multi-millimeter bubbles. In contrast, large 

bubbles have lower Pc, resulting in their films being relatively more susceptible to 

rupture and gas can diffuse from small high-pressure bubbles into larger low-

pressure bubbles (Ostwald ripening)  [49]. As a matter of fact, foams with wide-

range bubble size distributions undergo coarsening more quickly, as larger Pc 

disparities drive gas transfer, while a more monodisperse (homogeneous) bubble 

size distribution slows down coarsening and increases foam stability [50]. 

Moreover, the enhanced solubility of CO₂ in the aqueous phase promotes the 

diffusion of gas and growth of bubbles in the foam coarsening of CO₂ foams [46]. 

Thus, the fine, high-Pc bubbles of the N₂ foam remain relatively stable (against 

coalescence and coarsening), while the larger, low-Pc CO₂ bubbles are prone to 

merging and growing, in agreement with the observations of differences in bubble 

size and foam stability. 

https://cgl.org.cn/auto/db/detail.aspx?db=706211&rid=446707&agfi=0&cls=0&uni=True&cid=0&gp=8&showgp=True&prec=False&md=93&pd=6&msd=93&psd=6&mdd=93&pdd=6&count=10&reds=sofia%3Buni%3Bbg#:~:text=The%20larger%20bubbles%20coalesce%20for,less%20than%2050%C2%A0s
https://cgl.org.cn/auto/db/detail.aspx?db=706211&rid=446707&agfi=0&cls=0&uni=True&cid=0&gp=8&showgp=True&prec=False&md=93&pd=6&msd=93&psd=6&mdd=93&pdd=6&count=10&reds=sofia%3Buni%3Bbg#:~:text=The%20larger%20bubbles%20coalesce%20for,less%20than%2050%C2%A0s
https://boulderschool.yale.edu/sites/default/files/files/%5B3%5Dstability.pdf#:~:text=Gas%20diffusion%20%E2%80%A2%20bubble%20volumes,film%20%E2%88%86P%20%3D%20%CE%B3%20r
https://boulderschool.yale.edu/sites/default/files/files/%5B3%5Dstability.pdf#:~:text=Gas%20diffusion%20%E2%80%A2%20bubble%20volumes,film%20%E2%88%86P%20%3D%20%CE%B3%20r
https://www.frontiersin.org/journals/energy-research/articles/10.3389/fenrg.2022.1012728/full#:~:text=phase%2C%20and%20the%20polydispersity%20of,the%20mass%20transfer%20driving%20force
https://www.frontiersin.org/journals/energy-research/articles/10.3389/fenrg.2022.1012728/full#:~:text=phase%2C%20and%20the%20polydispersity%20of,the%20mass%20transfer%20driving%20force
https://pmc.ncbi.nlm.nih.gov/articles/PMC10282000/#:~:text=respectively,solubility%20is%20a%20likely%20explanation
https://pmc.ncbi.nlm.nih.gov/articles/PMC10282000/#:~:text=respectively,solubility%20is%20a%20likely%20explanation


58 

 

Neighboring bubbles merge together, leading to larger bubbles and overall foam collapse 

[44]. Classical foam decay involves liquid drainage-induced film thinning followed by 

film breakage and bubble coalescence [44]. These processes occur in both CO₂ and N₂ 

foams, but their rates can differ depending on gas properties.  

5.2. Mechanical properties in porous media of “X-oilfield” 

To investigate how CO₂ an N₂ foam flooding work in porous media, the two cores 

collected from the field were investigated in core flooding experiments. In these low-

perm pores, it is conjectured that CO₂ foam could not sustain a continuous lamella 

structure: gas threads quickly reconnect into continuous slugs, causing premature 

channeling through preferential pathways as evidenced by only ~1.6 cP apparent 

viscosity reached. By contrast, the stronger N₂ foam maintained a dispersed bubble 

morphology that substantially resisted flow ~4.8 cP, creating an effective gas-blocking 

network that diverted flow into unswept regions. From the apparent viscosity change 

profile, it is reasonable to assume that CO₂ foam degradate approaching 1.5 cP effective 

viscosity, as if reaching the critical capillary pressure. If the foam is not resilient, Kam & 

Rossen’s population-balance model predicts foam collapse back to a single-phase gas 

flow[53]. Indeed, X-ray CT visualizations by Farajzadeh et al. (2009) show that when 

foam lamellae destabilize, gas fingers through the rock, bypassing oil [42]. Thus, N₂ 

foam’s finer texture and more robust lamella propagation yield superior pore-scale 

trapping and sweep, whereas CO₂ foam remains too weak to invade and exit narrow 

throats without rupturing, resulting in poor sweep and a limited incremental oil recovery 

of 2.45 %.  

5.3. Impact of lithology on EOR performance  

In order to evaluate the effect of lithology on EOR performance, the identical 

foam flooding design as for the granitoid “X-field” cores were employed for the 

sandstones in Indiana and Berea outcrop cores. Although the Indiana and Berea cores 

exhibit similar filtration properties, their oil recovery and apparent viscosity profiles 

during foam flooding did not differ markedly. The additional oil recovery in both 

sandstone samples was 0.7 % for Berea and 0.9 % for Indiana with CO₂ foam, and 3.08 

% and 3.07 % with N₂ foam, respectively. While the apparent viscosity profiles varied 

https://oaktrust.library.tamu.edu/bitstreams/6294d41d-12e9-4a94-b6c8-7ce33c3aef7b/download#:~:text=Pugh%20has%20listed%20out%20the,2013%29%20If
https://oaktrust.library.tamu.edu/bitstreams/6294d41d-12e9-4a94-b6c8-7ce33c3aef7b/download#:~:text=Pugh%20has%20listed%20out%20the,2013%29%20If
https://oaktrust.library.tamu.edu/bitstreams/6294d41d-12e9-4a94-b6c8-7ce33c3aef7b/download#:~:text=Pugh%20has%20listed%20out%20the,2013%29%20If
https://oaktrust.library.tamu.edu/bitstreams/6294d41d-12e9-4a94-b6c8-7ce33c3aef7b/download#:~:text=Pugh%20has%20listed%20out%20the,2013%29%20If


59 

 

somewhat, the general trend remained the same. For instance, the stabilized apparent 

viscosity during CO₂ foam flooding in Berea was around 1.1 cP (with a peak of 1.7 cP), 

whereas in Indiana it stabilized at approximately 0.5 cP (with a peak of 1.8 cP) (Figure 

46). 

 
Figure 46. N₂ foam flooding apparent viscosity comparison  



60 

 

 
Figure 47. CO₂ foam flooding apparent viscosity comparison 

In contrast, flooding tests on the “X-oilfield” granitoid cores displayed slightly different 

yet more consistent patterns. The recovery factors achieved in the “X-10” core was 1.8 

% for CO₂ foam and 5.7 % for N₂ foam, while the “X-13” core yielded 3.1 % for CO₂ 

and 10.6 % for N₂ (Figure 48). It appears that foam performance was generally more 

effective in the “X” cores, likely due to their higher heterogeneity and correspondingly 

greater need for mobility control. Additionally, the apparent viscosity profiles in the “X” 

cores were more uniform, lacking the pronounced peaks seen in the outcrop cores-

possibly another consequence of the granitoid samples’ complex pore structure. Notably, 

the absolute apparent viscosities for CO₂ foam in both “X-10” and “X-13” remained 

below 2 cP, yet for N₂ foam, the apparent viscosity rose to 6 cP in “X-10” and only 1.1 

cP in “X-13,” indicating that permeability can strongly influence foam flooding behavior. 

  



61 

 

 

 
Figure 48. N₂ foam flooding recovery factor comparison for foam flooding 

 



62 

 

 
Figure 49. CO₂ foam flooding recovery factor comparison for foam flooding 

5.4. Foam flooding additives  

In order to investigate the effect of additives on foam flooding efficiency, an additional 

flooding test was carried out after the baseline (conventional) foam flooding. The only 

difference from the initial experiment was the addition of 0.1 % silica nanoparticles to 

the foam solution. By strengthening foam films and boosting their viscoelasticity, the 

nanoparticles improved the foam's ability to control mobility and make it more resilient 

against collapse [53]. By adding these nanoparticles, average oil recovery rose to about 

5.05 % for N₂ foam flooding and 4.1 % for CO₂ foam flooding, showing that nanoparticles 

improve recovery for both types of foam.  

 However, this modest improvement in oil recovery led to a considerable rise in apparent 

viscosity. Specifically, in the “X-10” core flooding tests, nanoparticle addition increased 

the apparent viscosity to 4.3 cP (a 33 % increase) for N₂ foam and 2.4 cP (a 37 % increase) 

for CO₂ foam. In the “X-13” core, the apparent viscosity rose to 9 cP (a 30 % increase) 

for N₂ foam and 2.2 cP (a 20 % increase) for CO₂ foam. Although nanoparticles present 



63 

 

a promising avenue for enhancing foam flooding performance, these results suggest that 

their application can lead to a steep surge in apparent viscosity-potentially exceeding 

what the core (and by extension, the reservoir) can accommodate under real-field 

conditions. Consequently, while nanoparticles offer clear benefits, a careful evaluation 

of potential drawbacks is crucial prior to large-scale deployment. 



64 

 

6. CONCLUSION 

Various experiments were conducted to investigate the ability of foam application to 

improve oil recovery at the “X” oilfield. Experiments involved the investigation of bulk 

foam properties at atmospheric conditions and foam behavior during core flooding. A 

foam half-life test was conducted to estimate the most compatible solution that could be 

applied for flooding. Core flood experiments investigated the performance and potential 

mechanisms participating in the flooding process. Furthermore, the core flooding process 

was designed to investigate the role of different lithology and nanoparticle impacts on the 

flooding process. Based on the results of the experiments, the following conclusions were 

reached: 

 
 Viable foam formulations were screened in foam bulk tests. The optimum 

concentration was determined as 0 % sodium chloride (NaCl), 0.25 % BIO-

TERGE surfactant, and 0.1 % silica nanoparticles. The solution marginally 

demonstrated the longest foam half-time in comparison with other concentrations 

– 310 min. 

 Regardless of the core sample or lithology tested, foam exiting the core in CO2 

flooding had a much coarser texture than N2 foams. 

 Regardless of the core sample or lithology tested, foam collected from the outlet 

line after CO₂ flooding is colored by oil color while bubbles collected after N₂ are 

white without a trace of oil. This indicates the tendency of CO₂ foam to 

chemically interact with the surrounding fluid. 

 In bulk foam tests with 0.1 % BIO-TERGE surfactant and 0.1 % silica 

nanoparticles in 1 % NaCl, N₂ half-life was 16.6 % longer than CO2 foam. 

 A comparison of the N₂ and CO₂ foam flooding results demonstrate that N₂ foam 

is more efficient. Thus, the average increment in recovery reached after N₂ foam 

flooding applied at "X" core samples is 8.15 % and 3.08 % for outcrop core 

samples, while for CO₂ the values are 2.45 % and 0.8 % respectively.  

 A comparison of the N₂ and CO₂ foam with silica nanoparticle flooding results 

demonstrates that N₂ foam is more efficient. Thus, the average increment in 



65 

 

recovery reached after N₂ foam flooding applied at "X" core samples is 5.05 % 

and 2.01 % for outcrop core samples, while for CO₂ the values are 4.1 % and 1 % 

respectively.  

 A comparison of the foam flooding results demonstrates that “X” oilfield core 

samples have the potential for additional oil recovery by foam flooding.  

 Comparing performance across lithologies, after N₂ foam with nanoparticles 

flooding, 17 % more additional oil was produced from “X” oilfield core samples 

in comparison with outcrop cores. CO₂ foam with nanoparticles flooding 

demonstrated 10.4 % more additional oil produced in “X” core samples than in 

outcrop core samples. 

 The application of nanoparticles significantly improves foam efficiency. The 

addition of 0.1 % silica nanoparticles during CO₂ foam flooding increased the 

recovery factor by 2.5 % OOIP on average. Application of silica nanoparticles 

during N₂ foam flooding increased that parameter by 3.6 % of OOIP. 

  High values of apparent viscosity reached during N₂ foam flooding with silica 

nanoparticles flooding experiments require careful consideration before field 

implementation, as the average apparent viscosity during N₂ foam with silica 

nanoparticles flooding reached a maximum of 9 cP.  

 The average apparent viscosity during CO₂ foam with silica nanoparticles 

flooding reached a maximum of 2.4 cP, making the application of silica 

nanoparticles during foam flooding more plausible. 

 While the N₂ foam core flooding results demonstrated better results in comparison 

with CO₂ foam, immiscible CO₂ gas flooding is more efficient than immiscible 

N₂ flooding. The average recovery factor for CO₂ gas flooding was 36.9 %, while 

the N₂ average gas flooding efficiency was 32.8 %. 

  



66 

 

7. FUTURE WORK 

For better understanding of complex problem foam mechanics and exceeding limitations 

of the current study, the next scope of investigation is proposed: 

 Screen different surfactants (other than Bio-Terge) for foam flooding. 

 Study the effect of different nanoparticles (other than silica nanoparticles) and 

concentrations for foam flooding. 

 Repeat experiments with miscible gas and miscible foam flooding. 

 Investigate foam diversion mechanisms. 

 Simulation foam flooding experiments in commercial simulators. 

 Pilot test foam flooding implementation at the oilfield in Kazakhstan where thief 

zones are identified. 

 Investigate the effect of temperature on foam flooding efficiency. 

 Study surfactant adsorption in core. 

 Conduct the foam flooding experiment as a secondary recovery method. 



67 

 

REFERENCES 

[1] Blunt, M., Fayers, F.J., Orr, F.M., 1993. Carbon dioxide in Enhanced Oil Recovery. 

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