1. Foam Assisted Surfactant-Alternating-Gas Injection for
Heavy Oil Recovery through Permafrost
Adel Aziz
Leonid Pryt
Vladyslav Ferderer
Department of Petroleum Engineering, University of Alaska Fairbanks
Antonio B. Mejia Jr.
Department of Petroleum Engineering, University of Houston
Submitted to—
Dr. Obadare Awoleke
Department of Petroleum Engineering, University of Alaska Fairbanks
Mr. Owen Guthrie
Instructional Designer, University of Alaska Fairbanks eLearning
1

2. Table of Contents
EXECUTIVE SUMMARY 3
PROBLEM STATEMENT 3
LITERATURE REVIEW 4
TECHNICAL APPROACH 5
WELL COMPLETION PROCESS 5
PERMAFROST AND CASING PROTECTION 5
PACKER FLUID AND HEAT EXCHANGE 5
TUBING INTEGRITY 6
CEMENT TYPE 6
OPTIMIZING HEAT EXCHANGE 6
DRILLING AND STIMULATION 7
SAND CONTROL AND PERFORATIONS 8
MISCIBLE GAS INJECTION 9
RESERVOIR PRESSURE DISTRIBUTION 9
ARTIFICIAL LIFT PROPOSAL 10
SURFACTANT ALTERNATING GAS 10
INTERFACIAL TENSION REDUCTION 10
LABORATORY CHEMICAL SCREENING 11
INJECTION SEQUENCE AND TECHNIQUE 12
PEER REVIEW SUMMARY 12
REFERENCES 13
NOMENCLATURE 14
PROPOSAL AUTHORS 14
TECHNICAL PAPER REVIEW 15
2

3. 3
Executive Summary
Drilling strategies significantly impact production capacity. Underbalanced drilling (UBD) condition will
be used to prevent formation damage. UBD is a drilling approach that mitigates formation damage by using low
wellbore pressures compared to higher reservoir fluids pressure to establishing a significant pressure gradient
for fluid flow. A vertical well will be drilled to a depth of 4500 feet, followed by branching of two deviated
sections. The first deviated section will be used as an injection well at a depth of 4700 feet. The second deviated
section, production well, will be at placed at a shallower depth. Implementing multilateral wells will reduce the
environmental footprint at the surface. Coring will permit PVT testing to evaluate formation volume factor, and
phase envelope. ISOTHERM, a packer fluid developed by Schlumberger, will be set at depth of 4500 feet.
Components for the production casing include production tubing, injection tubing, and tubing to circulate cold
fluid to prevent heat loss from annulus to permafrost.
Well-bore isolation is indispensable to maintaining permafrost integrity. First, G class cement will be used
in cement slurry to provide early strengthening at low temperatures. Insulated production tubing through a
secondary pipe will provide optimal heat transfer returns thereafter. The ISOTHERM tubing will be placed
adjacent to injection and production tubing, and will serve its purpose as a conduit for continuously circulated
thermal insulation fluid.
Foam assisted surfactant-alternating-miscible gas injection will be used to lower heavy oil viscosity and
interfacial tension (IFT), while overcoming gravity segregation and reservoir heterogeneities. In the context of
this document, “foam” is defined as gas-liquid dispersions stabilized by surfactant additives. Carbon dioxide is
miscible at pressure greater than 1070 psi. Due to its geographic abundance in the North Slope, CO2 was
selected to lower heavy oil viscosity. The amount of required CO2 will be determined based on lab tests,
specifically core floods. Perforation generated foam injection will play a pivotal role in reducing gas mobility,
lowering IFT, and confining thief zones. Flowing bottom-hole pressure must be preserved at bubble point
pressures for injected miscible CO2 to maximize gas miscibility and maintain subsequent flow rates and
viscosities. Produced fluids will be lifted to the surface using cavity progressing pumps; this provides a solution
to issues related to insufficient bottom-hole pressures which provide tubing intake pressures and consequently
significant flow rates. Additionally, sand production is a challenge due to permeability distributions within the
reservoir. Installation of 5.5 stainless-steel wool completions will be used to mitigate and monitor this
challenge. This approach provides improved sand retention, higher permeability at the sand face, and
sustainable productivity.
Problem Statement
Substantial amounts of heavy-oil reserves can be found in Alaska’s North Slope region. Oil production in
arctic environments presents a variety of challenges that impact recovery processes. Thermal enhanced oil

4. recovery (EOR) methods provide a solution to producing heavy oil. However, thermal methods are impractical
in the presence of the permafrost in North Slope, AK. Integrity of the permafrost layer must be maintained as it
provides structural support to the surface-processing infrastructure. This research provides a comprehensive
proposal to produce heavy oil through permafrost. Strategies for producing 1000-10000 centipoise heavy oil at
average an reservoir pressure of 1450 psi are discussed. Additional conditions include a permeability range of
500-2000 mD with an average porosity range from 25% to 35% and an average reservoir temperature of 65
degrees Fahrenheit. Commercially-feasible production of heavy oil will require significant reduction in crude
oil viscosity, preservation of permafrost, and efficient application of injected CO2 and surface-active agents.
Furthermore, casing and cement type will be designed with maximum thermal properties in mind to maintain
structural integrity on all fronts. Operational factors that will lead to failure are poor cement bonds, improper
clean outs, and flushed zones. From a completions point of view, attention will be placed on mitigating a mode
of failure resulting from immobilized oil or sand; formation stimulation is considered to assuage resistance to
flow.
Literature Review
Drilling through deep permafrost involves complex thermo-mechanical interaction between fluids, drill
string and formation. From a completion standpoint, permafrost behavior associated with thawing and
refreezing is the single most important factor influencing well design in arctic environments. Understanding the
thermal and mechanical response of permafrost is imperative to arctic well completion and design. Studies
examined addressed concepts and mechanisms related to understanding permafrost behavior. Present-day
methodologies and equipment used in arctic drilling and completions influencing structural design, adjacent
environments, and effects on permafrost in down-hole operations are discussed.
Mechanisms for reducing crude oil viscosity at various reservoir conditions have been the fundamental
concerns in unconventional oil recovery. Injecting CO2 gas was found to be effective as it is miscible at
pressures greater than 1070 psia and less prone to gravity segregation compared to other gases like N2 and SO2.
Sand management is an important procedure in hydrocarbon (HC) recovery. In recent years, sand management
has been studied closely and has impacted recovery processes, well completion techniques, and solid removal
technologies. Developments in predictive computer simulation for sand production as well as instrumentation to
prevent formation failure have resulted from case studies. Furthermore, down-hole equipment to block
formation material from entering the well-bore, and monitoring techniques have been developed in response to
sand production.
Performance versatility of surfactants and their application in environmental remediation highlight this type
of oilfield chemistry as a viable option for unconventional HC recovery. Independent application or co-injection
with miscible gases such as N2 or CO2 generating in-situ liquid-gas dispersions have provided favorable results
in oilfield studies. Synchrony between field conditions and chemical interaction augment time investments
4

5. required for this mechanism. Through execution of performance analysis from phase behavior and PVT fluid
simulations, successful HC recovery across various challenges has been observed.
Technical Approach
Well Completion Process. Polar environments require certain processes in preparing injection and production
wells prior to their induction. Running and cementing casing is necessary for isolation of the wellbore from the
reservoir and for flow control from desired formations. Perforation of the casing follows cementation and
provides a conduit between the reservoir and the wellbore. High formation permeability requires the installation
of sand control systems that filter the formation debris from produced fluids during recovery. Installing tubing
and packers is necessary to seal and protect the well from erosion and corrosion.
Permafrost and Casing Protection. Although more complex, implementation of refrigeration coils around
double-walled casings, especially conductors casing, containing solid polyurethane insulation is subjected to
detailed risk analysis. Fortunately they are deemed viable for arctic conditions and thermal insulation required
in flow assurance and operational stability. Additionally, refrigeration coils are cost effective alternatives that
provide improved stability for the conductor casing while at the same time allowing control over surface
foundations. Double-wall pipes can be checked routinely for total integrity using a pressure-based annulus leak-detection
system providing continuous integrity monitoring of both inner and outer pipes on pass/fail basis.
Inner pipe maintenance is much similar to single-walled pipes. Supplemental to operational stability, double-walled,
insulated casing provides better heat transfer and less thawing relative to single-walled casing. Collapse
rating of permafrost casing must be greater than the difference between external freeze-back pressures and
internal packer fluid pressure; for this reason, stronger casing design is encouraged (Randell, 2000). Permafrost
preservation and wellbore integrity must account for the effects from frost heaving in the casing design strategy.
Cast-in-place concrete piles utilizing steel casing or similar pile-driving techniques should be implemented, in
order to form a firm foundation for the outer wall. Load bearing capacity of surrounding strata is increased via
soil displacement at the pile base (Prezzi, 2005).
Packer fluid and Heat Exchange. Selection of gelled, oil-packer fluid of high density within the isolated
annulus results from factors influencing production; heavy oil flow rate, production tubing, injection tubing, and
permafrost dynamics. ISOTHERM packer fluid developed by Schlumberger provides easy placement and
displacement protection against low-temperature-related production problems. The ISOTHERM system lowers
thermal conductivity and arrests thermal convection to avoid annular pressure buildup from all sources
including the production string. The value added from ISOTHERM is primarily seen in its durability and
recyclability after long-term aging. In this proposal, recycling of ISOTHERM liquid is a priority. ISOTHERM
tubing placement will be adjacent to injection and production tubing and functionality-wise provides continuous
circulation of fluid for temperature control. Surface equipment necessary for use of ISOTHERM are addition
valves in the oil-well christmas tree, storage tanks for displacement and fluid cooling, and heat exchangers
5

6. within the storage. Determining the amount of time it would take for the ISOTHERM temperature to increase
by 1 degree would be based on the system pipe and insulation diameters, volume of isotherm liquid, and the
thermal resistances of each, respectively.
Tubing integrity. Thaw prevention in the permafrost layer requires additional tubing installations in the
wellbore. Moreover, packers will be set below the sandy layer, and the annulus of production casing will need
to be filled with packer fluid to cool down production and injection tubing. The reason for installing additional
tubing is to pump out ISOTHERM packer fluid at temperatures where its performance is compromised.
Similar to casing integrity, the pipe-in-pipe (PIP) concept may be used in production and injection tubing to
minimize heat transfer while preserving overall wellbore integrity. Production tubing is temperature dependent;
therefore insulating the line by using a secondary pipe will mitigate heat transfer and secure production. With
respect to surfactant-based foam injection into the formation, inner capillary tubing vertically-centered within
gas injection lines will be arranged as a pipe-in-pipe to optimize foam generation in perforations. Vanadate-based
coatings of MnMgZn-phosphate composition will comprise the corrosion inhibitor profile for this venture
(Darley, 1988).
Cement type. Arctic cements must hydrate and set at sub-freezing temperatures to bond with the formation,
support the casing, and prevent freeze-back buckling. Cements generate heat hydration levels of 100-120 cals/g
therefore, selection of a cement formulation that would generate this amount of heat at a rate that would allow
the cement slurry to maintain its original temperature is imperative. Gypsum-based cements with ground-sulfated
clinker additives and/or Class G cements (60% gypsum, 40% Class G) in cement slurry- provide early
strength at low temperatures, while Class G strengthens the sand over time. Sulfated clinkers reduce possible
low moisture content and control free water that can be seen in potential thawing zones of permafrost.
Alternative to gypsum-based cements are ‘high-alumina’ cements with Class-G cement additives. High alumina
cements generate heat in much higher quantities and at much faster rates that gypsum cements. This
characteristic can be utilized in cold environments with greater presence of unconsolidated sands, for rapid
strengthening and quick setting (Goodman, 1978).
Optimizing Heat Exchange. For annular systems of length (L), at steady-state conditions with constant thermal
conductivities (k), heat transfer (q) can be expressed using Equation-1 and Equation-2.
(1)
(2)
Where ‘r1’ and ‘r2’ represent radii of the annular section; ‘Rk’ represents thermal resistance in the system.
Overall heat transfer coefficient involves a modified form of Newton’s law of cooling and can be expressed in
Equation-3, 4, and 5. Overall heat transfer in insulated tubes in a convective environment is illustrated in
Figure-1. Workable designs are obtained over the allowable ranges of the design variable in order to satisfy the
given requirements and constraints. In order for the system to be optimal, modeling and computer simulations
6

7. will be required. Objective functions that are optimized in thermal systems are frequently based on: weight,
size, rate of energy consumption, heat transfer rate, efficiency, costs, safety, durability, and performance.
(3)
(4)
7
(5)
Figure 1: Convective Heat Transfer through Insulated Tubing
Finding the global maxima of the optimum design domain result in desired outputs shown in Figure-2 and 3.
(Kreith, 2000).
Figure 2: Design Domain Constraints
Figure 3: Optimum Design Output
Drilling and Stimulation. The vertical section of the well will be drilled down to 4500 feet followed by two
parallel, lateral well-bore sections; one for injection of displacing fluid and the other for produced fluids.
Turbodrills with soft formation bits and non-magnetic drill collars will be used to drill the permafrost and
mitigate sloughing problems. Well placement is shown in the CAD rendering in Figure-4. The reason for this
type of drilling and completion design is because production of heavy oil will require some type of formation
stimulation. Stimulation will be executed using the injection section of the well. The producing section will be
perforated and sand control systems will be installed. Injection wells will only require perforations for injection
of miscible displacing fluids into the pay zone. Drilling must be conducted in UBD conditions to prevent skin
damage caused by mud invasion into the formation. Surface-controlled, subsurface safety valves (SCSSV) will
be placed below the base of the permafrost to shut-in the well in event of damage and provide additional
precautionary measures against thaw-subsidence, freeze-back, or hydrate-decomposition. Application of oil
based ‘Bentonite XC Polymer-KCl’ mud and controlled hydraulics serve the purposes of increasing the yield
point, inhibiting mudstone and shale swelling, depressing the freezing point, and exhibit excellent hole cleaning

8. with good rheology at low temperatures (Goodman, 1978). Initiation of air-stable, high quality foam can be
used to increase drilling rate and minimize permafrost melting. Packers will be installed inside of the production
casing at five different locations. A set of packers will be set up at about 4500 feet below the ground, to prevent
escaping ISOTHERM packer fluid into the formation. The other sets of packers will be installed at the starting
points of the deviated section and at the end of the coil tubing.
Figure 4: Well Completion Schematic (Not to Scale)
Sand control and Perforations. Running wire-line logging tools is required to be able to distinguish distribution
of permeability and lithology within the reservoir. In very high permeability reservoirs, perforations have a dual
functionality; stimulate the well and provide sand control. Sand control will be set only for producing horizontal
sections of the well, because the sand production leads to numerous problems including erosion of down-hole
tubulars, valves, fittings, and surface low lines. “In almost every case, economic heavy oil production depends
on effective sand control” (Halliburton, 2009). Heavy-oil and sand production has some unique technical
challenges such as high temperatures present in thermal recovery, thermal cycling issues, lifting of high-viscosity
crude, produced water and solids management, inflow performance, and environmental stewardship.
The well completion strategy that was implemented by Mansarovar Energy centered on implementing and
running 5.5 in. stainless-steel wool as the sole means of sand control. “The main selection criteria that drove
this decision was the improved open-flow area of this type of sand screens that provided an improvement the
4% open-flow area of the slotted liner to 40% OFA of the screen selected” (Huimin, 2011). This technique
provided improved sand retention, higher permeability at the sand face, and improved productivity per well.
8

9. On the other hand, production of sand during oil production is a major concern and benefit for both
conventional and heavy oil production operations. “ It is now well known that sand influx enhances production,
yet it can cause problems such as increasing difficulty in well work-overs, well cleanup, and additional costs for
sand & waste disposal”, (Zhang, 2004). However, in our situation injected inhibitors will reduce the viscosity of
the heavy oil thus there is no need to produce sand to increase permeability of the formation. Accordingly,
running 5.5 in. stainless-steel wool completion strategy will be the best option to control sand influx.
Miscible gas injection. Producing heavy oil at North Slope, Alaska is more complex as thermal enhanced oil
recovery cannot be used in the presence of permafrost. A significant complication to producing heavy oil is its
very high viscosity that is composition dependent. Therefore, to be able to produce heavy oil lowering of
viscosity at reservoir conditions to initiate flow from the formation to the wellbore is important. To reach lower
viscosities, inception of miscible gas injection accompanied by surfactant injection will support the overall
goals. During the drilling process, core samples have to be extracted in order to run a PVT analyses on the
resident crude oil for the purpose of to constructing a phase envelope and evaluating the bubble point pressure.
The reservoir pressure must remain above the CO2 bubble pressure in order for the miscible gas to dissolve into
the crude oil thereby lowering its viscosity. The geographic location of the reservoir in the North Slope,
presents operators with readily available CO2 gas, which will be injected in the horizontal injection well shown
in Figure-4. Most gases become miscible only when their densities are high, generally greater than 0.5 g/cm3.
Thus, they work best at high pressure. For CO2 gas the minimum pressure is 1,070 psig. At this point CO2 gas
becomes supercritical and it is a gas and liquid with no phase distinction (Kulkarni, 2003). CO2 density is high
enough for it to be a good solvent for oil. Compared to crude oil, CO2 gas is less viscous. Because CO2 is
lighter, it has a tendency to escape to the top of the formation. Subsequently, surfactant-alternating-gas injection
will provide reduced gas mobility. Moreover, using foam will reduce IFT. Lower mobility will prevent carbon
dioxide from escaping to the top of the formation (Kulkarni, 2003). Lab experiments must be conducted at
reservoir conditions to determine crude oil viscosity before and after CO2 injection in addition to verifying the
quantities of miscible gas necessary to achieve targeted viscosities. Flowing bottom hole pressure is important
in evaluating the flow dynamics from formation to wellbore.
Reservoir Pressure Distribution. The flow between the reservoir and wellbore is given by IPR equations, which
are functions of viscosity as well as pressure difference between average reservoir pressure and flowing bottom
hole pressure. Flow is inversely proportional to viscosity and directly proportional to pressure difference. To
increase flow towards the wellbore, the flowing bottom hole pressure (FBHP) of the producer, must be as low
as possible. In other words, the drawdown must be maximum in order to increase flow towards the wellbore to
overcome the fact that permeability in the horizontal direction is higher than permeability in the vertical
direction. On the other hand, flowing bottom hole pressure must be above bubble point pressure to keep the
injected carbon dioxide gas soluble in the crude oil so it maintains lower viscosity. Ideal bottom hole pressure
must equal bubble point pressure. However, the flowing bottom hole pressure must overcome the intake
9

10. pressure. The oil viscosity being above 1000cp is very high, so the intake pressure must also be high. Therefore,
artificial lift methods must be installed to lift the oil to surface.
Artificial Lift Proposal. If flowing bottom hole pressure is insufficient to provide the required tubing intake
pressure, progressing cavity pumps must be introduced to lift all fluids to the separator or storage facilities.
Volumetric flow rates from progressing cavity pumps are proportional to the rotation rate. Therefore, one
important disadvantage of the progressing cavity pump is that it only handles low flow rate; flow rate is
proportional to low levels of shearing being applied to the pumped fluid. Subsequently, these pumps are very
beneficial to lifting viscous crude oil and require minimal maintenance.
Surfactant-Alternating-Gas. Globally, the use of water-alternating-gas (WAG) injection has proven successful
in reduction of gas-to-oil ratios for conventional oil reservoirs. Unfortunately, the use of WAG or continuous
gas injection (CGI) often results in sweep inefficiencies for unconventional heavy oil reservoirs. When injection
of CO2 results in limited heavy oil displacement, incorporation of chemical enhanced oil recovery techniques is
beneficial. Upon successful completion of vertical and horizontal drilling and cementing schedules,
implementation of a chemical flood will present a favorable option in heavy oil recovery through permafrost;
specifically foam-assisted enhanced oil recovery. Surfactant flooding is susceptible to channeling within
reservoirs having heterogeneities in permeability and naturally-occurring thief zones or fractures. Early
breakthrough of injected surfactant into producer wells results in reduced oil recovery, differential application
of injection fluids into non-target zones, and ultimately inefficient asset management. Considerations such as
these lead to screening for multipurpose and versatile injection fluids. The purpose behind CO2 and surfactant
application is to minimize the loss of oil productivity. Heavy oil displacement is optimized during surfactant-alternating-
gas (SAG) injection by initial displacement in high permeability pay-zones. Mobility reduction in
high permeability “thief zone” is mitigated by CO2-foam injection into the target zone for direct oil
displacement. Figure-5 shows the benefits to using foam alternating CO2 injection versus CGI using CO2.
Injection of miscible gas CO2 and anionic foaming surfactants will reduce resident crude oil viscosity and
interfacial tension. Since clastic minerals and rock surfaces are generally negatively charged, adsorption is
minimized in application of a high quality, stable, CO2-foam formulated using anionic surfactants. Furthermore,
in the presence of dense CO2, optimal surfactant formulations mitigate asset downtime caused by gravity
segregation, gravity override, and sweep inefficiency despite mobility control. Foam stability and quality are
impacted by dense and viscous CO2, appropriate combination of the two phases will establish favorable
displacement in the reservoir (Lee, 2013).
Interfacial Tension Reduction. With consideration given to conditions where miscible gas supply is adversely
affected and onset of gas cap development in a state of fixed reservoir and fluid properties, an alterable
parameter is interfacial tension. The need for reduction of interfacial tension is rooted in arrival at a
supersaturated state between CO2 and heavy oil; fixed viscosity; subject to fixed reservoir conditions. At these
conditions, the capillary number (NC), a dimensionless ratio of viscous to surface forces and fluid velocity, must
10

11. be increased in order to establish adequate flow of hydrocarbons. Capillary number is defined in Equation-6.
Relationships between capillary number and Darcy flow are shown in Equation-7 (Kumar, 2013). From the
relationship it is evident that an ultra-low interfacial tension can significantly improve HC flow rates into
producer wells.
(6)
11
(7)
Figure 5: Cumulative Oil Recovery, FASAG vs. CGI Mechanism
Laboratory Chemical Screening. Prior to executing a field pilot test for foam application, a comprehensive lab-scale
program must be considered. Successful field application of foam assisted SAG in heavy oil reservoirs
with similar conditions can be found in the Wilmington Field, California trial conducted by Long Beach Oil
Development and Unocal Corporation in 1984. The success of the Wilmington Field trial is attributed to
improved reservoir fluid distribution from appropriate foam delivery. Screening appropriate surfactant
formulations includes phase behavior analysis under reservoir and surface conditions. Surfactant phase behavior
analysis must be conducted at both reservoir and surface conditions to evaluate overall fluid stability and avoid
separation of phases at elevated reservoir temperatures. The ideal surfactant formulations will be aqueous
solutions of primary and co-surfactant systems diluted in oilfield brines having a mean total dissolved solids
(TDS) content of about 30,000 ppm, which is equivalent to 3% reservoir salinity. The overall total surfactant
concentration in the reservoir will be at least 0.3% and no greater than 1.0%. Once a stable surfactant
formulation is discovered, the solubility potential with the heavy crude oil must be evaluated. One method to
evaluate the degree of solubilization for the surfactant-crude oil system involves emulsification.
Microemulsions are isotropic, thermodynamically stable, heterogeneous multicomponent immiscible fluid
systems that generate a third phase characteristic of ultra-low interfacial tension values. (Lake, 1989) Since
evolution of emulsions in the producer well is expected from SAG techniques, understanding solubility will
give insight into potential emulsion breakers useful in produced fluids separation phase. Potential avenues for
separation mechanisms include use of horizontal treaters in conjunction with membrane separation
technologies. Further information regarding separation technology is not provided as this subject is beyond the
scope of this proposal. Understanding phase behavior characteristics will project solubility and mobility

12. potential for foam-capable surfactants. Further investigation of stable surfactant formulations will be conducted
on a spinning drop tensiometer with the surfactant solution being the outer phase and the heavy crude being the
inner phase. Using the surfactant formulations that generate the lowest possible IFT value, further fluid analysis
must be conducted using microfluidics and core-flood experiments. The purpose behind additional performance
testing is to observe the fluid behavior in the micro and macro scale using the CO2-enriched “live” crude oil;
this enables improved resolution of performance in the reservoir. From microfluidic analysis, certain injection
sequences where responsible for recovery of 90% of residual oil (Emandi, 2011).
Injection Sequence and Technique. High recovery ratios were achieved by injection of 3% salinity brine
followed by a concentrated surfactant slug having concentration of approximately 0.5%. Displacement of oil
achieved by co-injection of CO2-surfactant foam and CO2 gas flooding on alternating 2 day and 15 day injection
periods. Horizontal completions enable application versatility of wells as injectors, producers, or hybrids. A
hybrid well in this context is one that can be designed to function as both injector and producer based on the
reservoir fluids flow dynamics. The technical approach will explore the use of horizontal wells as both injectors
and producers by implementing a modified push/pull process of injected CO2 and anionic surfactant slugs for
achieving target recovery of heavy oil. Push/pull processes require the simultaneous injection of recovery fluids
into the formation on order of 5%-25% pore volume followed by a “soaking” period (Alston, 1988). During the
soaking period one well is shut-in and converted to a producing well while continued injection follows in the
other well. The producer well will be brought online and desired cyclic stimulation of heavy oil can be obtained
using dense CO2 (Lim, 2002). Building on the proposed recovery technique will be achieved by designing
backward compatible horizontal wells with tools for improved functionality; suggested by the peer reviewer.
Peer Review Summary
Originally injection time ratio of surfactant to CO2 injection was 2 days and 15 days respectively. Dr.
Konstantinos Kostarelos adjunct professor with the University of Houston, Petroleum Engineering Department
reviewed the paper and suggested that using foam at the early stages of injection to be problematic. With a high
viscosity resident fluid, it will be difficult to develop pressures to drive the foam and displace the tar.
Subsequently, we must consider injection of only surfactant OR only CO2, so that sweep is NOT the best
(unfavorable endpoint mobility ratio) but pathways develop through the viscous oil. With the breakthrough of
the surfactant or CO2, weak foam can be used to improve the sweep efficiency and can be increased.
Additionally, use of a push/pull technique in the injector and producer wells may provide improved oil-flow
long term. This would demand a higher amount of surfactant, however, a surfactant recycle option after
recovery could keep the cost of surfactant down to the point of making the strategy economically viable.
12

13. 13
References:
1. Suman, G.O., Jr., Ellis, R.C., and Snyder, R.E., Sand Control Handbook, 2nd ed., Gulf Publishing Co.,
Houston, TX, 1983.
2. Michael, J.E., Daniel, A.H., Christine, E.E., and Zhu, D., Petroleum Production System, 2nd ed., Pearson
Education Inc., Westford, MA, 2013.
3. Zhang, L., and Dusseault, M.B., “Sand Production Simulation in Heavy Oil Reservoir,” SPE Paper
64747, presented at the International Oil and Gas Conference and Exhibition in Beijing, China,
November 7-10, 2000.
4. Huimin, Ye., Mauricio, P., Carlos, P., Nicholas, L., Schlumberger., “ Innovative Well-Completion
Strategy for Challenging Heavy-Oil Wells within Mature Fields Requiring Sand Control in Columbia,”
SPE Paper 149966, presented at the SPE Heavy Oil Conference and Exhibition in Kuwait December 12-
14, 2011.
5. Prezzi, M. and Basu, P. "Overview of Construction and Design of Auger Cast-in-Place and Drilled
Displacement Piles." Proceedings of the 30th Annual Conference on Deep Foundations , Chicago , IL ,
pp. 497-512. (2005).
6. Moritis, G. 2000. EOR Survey: EOR weathers low oil prices. Oil and Gas Journal, March 20, 2000.
7. Orr, F M, Johns, R T, Dindoruk, B, “Development of Miscibility in Four-Component Vaporizing Gas
Drives”, SPE 22637, Presented at the 66th Annual Technical Conference and Exhibition of the Society
of Petroleum Engineers held in Dallas, TX, October 6-9, 1991.
8. Randell, C.; McKenna, R.; King, A. An Engineering Assessment of Double Wall Versus Single Wall
Designs for Offshore Pipelines in an Arctic Environment; 00-C4-Final; C-Core Publication: St. Johns,
NF, Canada, 2000.
9. MI SWACO, A Schlumberger Company. 2014. Packer Fluids - ISOTHERM (1999 Revision)
http://www.slb.com/services/miswaco/services/completions/packer_fluids/isotherm.aspx
(accessed 28 October 2014).
10. Goodman, M. 1978. World Oil’s Handbook of Arctic Well Completions, 1st ed. Houston, TX: World
Oil.
11. Prezzi, M.; Prasenjit, B. 2009. Design and Applications of Drilled Displacement (Screw) Piles. Joint
Transportation Research Program, Purdue University, West Lafayette, Indiana (September 2009).
12. UFGS, Cast-In-Place Concrete Piles, Steel Casing. 2008. Washington, DC: USACE.
13. US Army Corps of Engineers. Pipe Installation Operations. In Pile Construction – Field Manual 5-134.
Chapter 4, pp 4.1-4.34 Fort Monroe, VA: USACE.
14. Dier, J. S. 1969. Techniques for Setting Drill Rig Piling and Surface Casing Under Permafrost
Conditions. In Technical Memorandum 96. Proc., 3rd Canadian Conference on Permafrost, CPC3-163.
Yukon, Canada. NRCC.
15. Parker, M. Peattie, E. 1984. Pipe Line Corrosion and Cathodic Protection, 3rd Ed. Houston, TX: Gulf
Publishing Company.
16. Parisher, R. 2002. Pipe Drafting and Design, 2nd Ed. Boston, MA: Gulf Professional Publishing.
17. Darley, H. and Gray, G.; 1988. Composition and Properties of Drilling and Completion Fluids, 5th Ed.
Houston, TX: Gulf Publishing Company.
18. Burns, R. 2001. Advanced Control Engineering, 1st Ed. Oxford: Butterworth-Heinemann.
19. Baker Hughes. Progressive Cavity Pump Systems. http://www.bakerhughes.com/products-and-services/
production/artificial-lift/progressing-cavity-pumping-systems-pcps. (accessed November 14,
2014)
20. Madhav M. Kulkarni. 2003. Immiscible and Miscible Gas-Oil Displacements in Porous Media.
Louisiana State University, Baton Rouge, Louisiana (August 2003).

14. 21. Kreith, F. 1999. The CRC Handbook of Thermal Engineering, 1st Ed. Boca Raton, FL: CRC Press.
22. Lee, S. and Kam, S. 2013. Enhanced Oil Recovery by Using CO2 Foams. In Enhanced Oil Recovery
Field Case Studies, ed. J. Sheng, Chap. 2, 23-62. Oxford: Gulf Professional Publishing.
23. Kumar, S. et al. 2013. Alkaline Flooding. In Enhanced Oil Recovery II: Processes and Operations, ed.
E.C. Donaldson, G.V. Chilingarian and T.F. Yen Chap. 9, Sec. 4, 223-226. Amsterdam: Elsevier
Science Publishers B.V.
24. Lake, L.W. 1989. Enhanced Oil Recovery. 1st edition. Englewood Cliffs, NJ: Prentice Hall.
25. Rosen, M.J. and Kunjappu, J.T. 2012. Emulsification by Surfactants. In Surfactants and Interfacial
Phenomena, 4th ed, Chap. 8, 336-344. Hoboken, NJ: John Wiley & Sons, Inc.
26. Emadi, A. et al. 2011. Mechanistic Study of Improved Heavy Oil Recovery by CO2-Foam Injection,
Presented at the SPE Enhanced Oil Recovery Conference, Kuala Lumpur, Malaysia, 19-21 July. SPE-
143013. http://dx.doi.org/10.2118/143013.
27. Turta, A.T. and Singhal, A.K. 2002. Field Foam Applications in Enhanced Oil Recovery Projects:
Screening and Design Aspects. J. Can. Pet. Technol. (10) http://dx.doi.org/10.2118/02-10-14.
28. Alston, R.; Hoyt, D.; Bou-Mikael, S. 1988. Modified Push/Pull Flood Process for Hydrocarbon
14
Recovery. Canada Patent No. 1,299,092.
29. Lim, G.; Kry, R.; Lebel, J.; Kwan, M. Cyclic Solvent Process for in-situ Bitumen and Heavy Oil
Production. US Patent No. 6,769,486.
Nomenclature:
Acronyms
CAD
CGI
EOR
FBHP
HC
IFT
IPR
PIP
PVT
SAG
SCSSV
TDS
WAG
Computer Aided Draft
Continuous Gas Injection
Enhanced Oil Recovery
Flowing Bottom-hole Pressure
Hydrocarbon(s)
Interfacial Tension
Inflow Performance Relationship
Pipe-In-Pipe
Pressure, Volume, Temperature
Surfactant Alternating Gas
Surface-Controlled Subsurface Safety
Valves
Total Dissolved Solids
Water Alternating Gas
Variables
hn
K
k
L
NC
Q
qk
Rk
r
ΔP
Tn
ΔT
μ
σ
Heat Transfer Coefficient
Permeability
Thermal Conductivity Constant
Length (Heat/Fluid Transfer path)
Capillary Number
Flow Rate (fluid)
Heat Transfer
Thermal Resistance
Radii (annular sections)
Pressure Difference
Temperature (annular sections)
Temperature Change
Fluid Viscosity
Interfacial Tension
Proposal Authors:
Aziz, Adel is a senior undergraduate studying Petroleum Engineering at the University of Alaska Fairbanks.
Research interests include drilling technologies and business production technologies.
Ferderer, Vladyslav is a senior undergraduate studying Petroleum Engineering & MBA at the University of
Alaska Fairbanks. Research interests include drilling technologies and business management.
Mejia Jr., Antonio is a junior undergraduate studying Petroleum Engineering at the University of Houston.
Research interests include colloidal chemistry for application in enhanced oil recovery.
Pryt, Leonid is a senior undergraduate studying Petroleum Engineering at the University of Alaska Fairbanks.
Contributor to current research program exploring gas hydrate production.

15. Technical Paper Review:
Reviewer: Dr. Konstantinos Kostarelos Date: 30 November 2014
1. What problem was addressed in this research proposal?
There is one main problem with several consequential ones. The main problem was to develop a strategy
for the recovery of heavy oils (highly viscous). The targeted reservoir poses additional concerns: the
protection of the permafrost, the depth of the payzone (which adds pressure and temperature issues),
2. What are the major results and conclusions?
The major result is a holistic strategy for development of this resource that considers environmental
protection while maximizing the economic benefit.
3. What evidence supports these results and conclusions? How was this evidence obtained?
The strategy cited references throughout, which are used as a basis for arguing the success of the
approaches. Although this strategy has not been utilized to date, the logic of each technology used for this
strategy provides a coherent argument for its development to the point of field-scale deployment. Each
technology may need some additional research and development, however, their use together can be brought
to bear on the problem.
4. List limitations of the results and conclusions, e.g., that result from assumptions made.
Costs are not a part of the proposal, and this is most serious limitation. I mention this although I also
acknowledge that it is difficult to assign a cost to the proposal when still in the concept phase. Once
additional development is made, additional research and specifics are better-known, a detailed cost analysis
will be needed. At this point, however, perhaps some consideration of cost—perhaps a comparison to the
SAG-D approach that has been studied further could be used as a benchmark—would bolster the argument
for this proposal.
5. How can these results or conclusions be applied in practice?
This question seems out-of-place here; the proposal is an approach that is to be applied at a specific field,
with potential applications world-wide.
6. How are the problem and solution important to the petroleum industry? How can the industry
15
benefit from this proposal?
An approach that could be used for heavy oil recovery in Alaska will find use in several locations such as
Venezuela, Canada and the Middle East. For this reason, an industry-wide benefit can be realized from a
solution to the problem.
Additional Reviewer Comments:
1. The proposal contains some grammatical errors and has some points that are not clear. Although not a
significant number, they detract from the proposal and should be corrected – time should be spent at the
Writing Center or with an adviser to correct them.
2. There are some punctuation errors: sentences have two spaces between them; commas are missing in
places; the formatting of the citations is incorrect; hyphens are missing in places.
3. Paragraphs are to have one main idea. Start with an introductory sentence (that is linked to the previous
paragraph), that mentions the idea, and develop the idea within the paragraph. A closing sentence
summarizes the paragraph and leads to the subsequent paragraph. In many places, the paragraphs are a
collection of ideas and this doesn’t work well.

16. 4. In terms of technology, I think the idea of using foam at the early stages of injection to be problematic;
the highly viscous foam has benefits as mentioned in the proposal, but they are benefits to be gained for
conventional reservoirs. Here, with a high viscosity resident fluid, it will be difficult to develop
pressures to drive the foam and displace the tar. In addition, the problems in lifting the tar and
transporting the tar could be address with a small variation to the strategy. Consider early injection of
only surfactant OR only CO2, so that sweep is NOT the best (unfavorable endpoint mobility ratio) but
pathways develop through the viscous oil. With the breakthrough of that surf or CO2, a weak foam can
be used to improve the sweep efficiency and can be increased. This would demand a higher amount of
surfactant, however, but a surfactant recycle option after recovery could keep the cost of surfactant
down to the point of making the strategy economically viable.
16