Journal of Petroleum Science and Engineering 135 (2015) 484–497

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Journal of Petroleum Science and Engineering

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A novel chemical additive for in-situ recovery of heavy oil usingwaterflooding process

Omid Mohammadzadeh a,n, Ioannis Chatzis b,1, John P. Giesy c,d,e,f

a DBR Technology Center – Schlumberger, Edmonton, AB, Canadab Department of Chemical Engineering – University of Waterloo, Waterloo, ON, Canadac Department of Veterinary Biomedical Sciences and Toxicology Centre – University of Saskatchewan, Saskatoon, SK, Canadad Department of Zoology and Center for Integrative Toxicology – Michigan State University, East Lansing, MI, USAe School of Biological Sciences – University of Hong Kong, Hong Kong, Chinaf State Key Laboratory of Pollution Control and Resources Reuse, School of the Environment, Nanjing University, Nanjing 210046, PR China

a r t i c l e i n f o

Article history:Received 10 June 2015Received in revised form29 September 2015Accepted 8 October 2015

Keywords:Chemical-assisted waterfloodingCorefloodInterfacial tensionSalinityThermal stability

x.doi.org/10.1016/j.petrol.2015.10.00905/& 2015 Elsevier B.V. All rights reserved.

esponding author.ail address: omohamma@uwaterloo.ca (O. Moesent address: Kuwait University, Kuwait.

a b s t r a c t

Chemical-assisted waterflooding is injection of specialty chemical(s) along with water to enhance theproductivity through a series of mechanisms. There are several mechanisms responsible for increasedultimate recovery of such a process compared to the traditional waterflooding process including in-situemulsification of oil, conformance control and treatment of adverse mobility ratio, reduction of Inter-facial Tension (IFT) between the in-situ oil and the injecting phase, and wettability modification to fa-cilitate recovery of oil by enhanced relative permeability values. Although chemical-assisted water-flooding has been applied since the early 20th century, it has not been until recently that applicability ofthis process has been tested for recovery of heavy oil using preliminary macro-scale as well as pore-scalestudies. A new chemical technology (i.e. IPC Technology as referred in this paper) has been developed. Aproprietary mixture of surfactants is used in several techniques associated with surface extraction as wellas in-situ recovery of heavy oil and bitumen. This formulation of solvents and surfactants is reusable, lowfoaming, non-flammable, not acutely toxic and non-carcinogenic. A systematic study, based on a series ofcoreflood tests, was designed and conducted to assess efficacy of IPC in the ultimate recovery of differenttypes of oils by use of IPC-assisted waterflooding. Effects of IPC on IFT between oil and IPC solutions atdifferent brine salinities/hardnesses and IPC concentrations were determined. Compatibility of IPC withdifferent brine hardnesses and salinities was determined. IPC technology was particularly effective inrecovering heavy oil. The performance of IPC as an additive during waterflood at elevated temperaturefor recovery of heavy oil was also investigated. For this particular purpose, thermal stability tests wereconducted to determine the threshold temperature below which the formulation is thermally stable.When production performance of IPC-assisted waterflood was compared with alkali flooding and acommercial surfactant, IPC gave superior ultimate recovery.

& 2015 Elsevier B.V. All rights reserved.

1. Introduction

A recent estimate of recoverable oil and bitumen, using pri-mary and commercially-proven Enhanced Oil Recovery (EOR)technologies in Canada, is about 178 billion barrels, with oilsandsproduction contributing about 85% to the total (NEB, 2006). Al-though these are significantly large reserves, they are consideredto be only a fraction of the total available resources, which is es-timated to be more than 1.5 trillion barrels (NEB, 2004). The

hammadzadeh).

largest deposits are located in the Western Canada SedimentaryBasin (WCSB). The significant difference between recoverable re-serves and available in-situ resource estimates is the amount of oiland bitumen for which there is no proven, commercially viableEOR technology for extraction.

Chemical flooding is an EOR technique that involves injectingslugs of dilute chemicals into a formation to increase microscopic(i.e. pore-level) and macroscopic (i.e. sweep) efficiencies of thedisplacement process. Three main classes of chemicals are typi-cally used: (1) alkalis; (2) surfactants and (3) polymers. Severalother types of chemicals, such as scale inhibitors and co-solvents,can also be added to the formulation if necessary. Each class ofchemical has a different primary purpose when added to the

O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497 485

formulation of the chemical “slug” injected. The main purpose ofadding alkali to the injected water is to generate surfactants in situupon contact with the reservoir oil through saponification of thenatural acids that exist in the oil phase. Surfactants, added at thesurface or generated in situ, reduce IFT between oil and water,hence mobilizing the oil phase which is trapped in porous mediaby capillary forces.

The concentration of active surfactants in the injected water isusually between 0.05 and 2 wt%, depending on the type of che-mical, its cost and design parameters of the EOR process. It is ty-pically necessary to reduce IFT by three to four orders of magni-tude, attaining 10�2–10�3 mN/m, to achieve significant reductionin residual oil saturation. At least two other mechanisms, not di-rectly related to reduction of IFT, can also contribute to increasingrecovery of oil by use of flooding with surfactants. Wettabilitymodification and in-situ emulsification of oil as a result of thepresence of chemical provide flow conformance and favorablemobility ratios especially when more viscous oils comprise thedisplaced phase. Sandstone reservoirs are typically naturally wa-ter-wet. However, sandstone formations containing heavy oil areoften found to have neutral or mixed wettability. Some chemicalshave the ability to change the wettability of formation rockthrough chemical reactions, ion exchange or adsorption mechan-isms. Changes in wettability lead to changes in the pore-scale fluiddistribution patterns and relative permeability to oil and water,and often results in re-mobilizing previously trapped oil. In-situemulsification of oil can also reduce the residual oil saturation,hence facilitates increased oil flow towards the production wells(Chatzis et al., 1983; Somasundaran and Hanna, 1979; Johnson,1976; Mayer et al., 1983; Shah et al., 2010).

Initial wettability of the porous structure and any furtherchanges due to the presence of surface active agents in the che-mical flood significantly affect performance of EOR processes(Morrow , 1990). Vijapurapu and Rao (2003) performed an ex-perimental study on the effect of chemical flood and brine onspreading and adhesion behavior of the crude oil on dolomitesurfaces. Anionic surfactants change the wettability of the calcitesurface to intermediate/water-wet condition compared to that ofthe cationic surfactants (Seethepalli et al., 2004). Mechanisms re-sponsible for changes in wettability have been described followinga chemical EOR process in carbonates (Wu et al., 2006). Effect ofpore wettability on pore-scale mechanisms of oil recovery as wellas on the topology of the trapped wetting and non-wetting phasesthrough dilute surfactant flooding of porous structures have beendescribed with different wettability conditions (Jamaloei andKharrat, 2010a and 2010b).

One limitation of surfactant-based EOR processes is sensitivityto salinity of the reservoir fluids as well as that of the injectedflood. Several studies have been performed to study effects ofsalinity on performance of surfactant flooding. There have alsobeen studies of effects of divalent ions on IFT values (Bansal andShah, 1978a; Kumar et al., 1984). Effects of optimum salinity anddivalent ions on IFT and surfactant phase retention have also beeninvestigated (Bansal and Shah, 1978b; Glover et al., 1979; Guptaand Trushenski, 1979). IFT values were found to be proportional toconcentrations of divalent ions in connate water and it has alsobeen demonstrated that optimum salinity is not constant in brinescontaining divalent ions. Because of interactions between divalentions and petroleum sulfonates, precipitation followed by re-dis-solution of the precipitates at higher concentrations of the sur-factant occurred (Celik et al., 1982). Evolution of precipitates, dueto contact of petroleum sulfonate with divalent-ions in connatewater, might also result in greater recovery factor of the surfactantflooding (Agharazi-Dormani et al., 1990).

The objective of this study was to evaluate enhancement ofrecovery of different types of oil by use of a proprietary chemical

additive during waterflooding process. Although different me-chanisms contribute to enhanced productivity of chemical-as-sisted waterflooding, the focus in this paper is on the ability of theIPC formulation to reduce IFT between in-situ oil and the displa-cing phase. Incremental oil recovery associated with this chemicalwas also compared against those of two commercial chemicaladditives through a series of coreflood tests.

2. Materials and methods

The IPC formulation (Patent US 2013/0157920 A1) is a pro-prietary, liquid cleaning, degreasing, and disinfecting concentratecomposition, comprised of: (1) caustic soda in a range of about0.181% to about 5.45% by volume; (2) a de-emulsifier in a range ofabout 0.028% to about 9.09% by volume; (3) an alkyl glucosidesurfactant of about 0.090% to about 7.27% by volume; (4) aphosphated alkyl ethoxylate surfactant of about 0.028% to about1.81% by volume; (5) a tridecyl alcohol surfactant in a range ofabout 0.363% to about 9.09% by volume; (6) a non-polar bondingagent of about 0.028% to about 1.81% by volume; and, (7) waterforming the remainder percentage by volume. The IPC formulationused as an additive during waterflooding, was characterized todescribe its bulk physical properties and partitioning behavior inaqueous and oleic phases, and thermal stability. These tests werecomplemented with a set of tests to evaluate recovery of differenttypes of oils by IPC-assisted waterflooding. Compatibility of IPCwith brines of various salinities and hardnesses was investigated.Interfacial tension between oils and solutions of IPC in brine wasmeasured. Once these parameters had been optimized, a series of1D coreflood tests were conducted to determine overall effec-tiveness of IPC in producing the original oil in place (OOIP).

2.1. Physical properties of IPC

Density and viscosity of IPC were determined at ambientpressure and three temperatures. To understand how the IPCmixture partitions between aqueous and oleic phases, bench-topvolumetric tests at ambient temperature were conducted. Forvolumetric partitioning tests, measured volumes of heavy oil,deionized water, toluene, and IPC were added to a 100 mL cen-trifuge test tube and mixed by vigorous shaking until a homo-geneous phase was formed, then centrifuged for 30 min. Volumeswere measured and photographs were taken. However, the volu-metric partitioning tests were inconclusive.

2.2. Thermal stability of IPC

The maximum use temperature of a chemical is an approx-imate threshold temperature value at which it begins to decom-pose. A series of tests including Thermal Gravimetric Analysis(TGA), Differential Scanning Calorimetry (DSC), Simulated Dis-tillation (SD) and Carbon Number Distribution (CND) determina-tion were used to characterize IPC. The TGA and DSC tests candetermine the onset and degree of thermal degradation and theSD test determine the volatility of the chemical. The CND test candetermine the range and relative amounts of each carbon unitfrom C1 to C30þ (or possibly C60þ) in IPC. Since these thermalstability tests cannot determine if the effectiveness of IPC is di-minished at elevated temperatures, other tests were used to assessseveral EOR processes at elevated temperatures. For the purpose ofchemical-assisted waterflooding, effectiveness as a function oftemperature was assessed based on optimizing parameters such asIFT and coreflood tests.

One SD test using a Gas Chromatographic (GC) technique and aCND calculation was attempted in this study. In addition, two TGA

O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497486

and two DSC tests were conducted on IPC. For the latter two tests,baseline tests with empty pans and with local carrier water usedto manufacture the chemical were also conducted and then usedto correct the thermal stability threshold values. Samples wereheated from ambient room temperature at a nominal rate of 5 °C/min. One of the TGA tests and one of the DSC tests were conductedunder a Nitrogen atmosphere so that thermal decomposition intovolatile constituents by pyrolysis could be detected. The other twotests were conducted under air, and indicated the temperatures atwhich portions of the sample are oxidized.

2.3. Evaluation of IPC as an additive in waterflooding process usingcoreflood tests

Efficacy of IPC as an additive during waterflooding process wasdetermined using 1D coreflood tests. For this purpose, compat-ibility of IPC with several mixtures of brine with different ionicconcentration/salinity/hardness was studied. Solutions were in-spected visually for incompatibility. Samples were stored in anoven at constant temperature and were observed periodically forat least one month. Studies were focused on reduction in IFT be-tween displacing and displaced phases. Therefore, relevant testswere designed and conducted to quantify the effectiveness of IPCin reducing IFT between brine and oil. Three different oils, light oil(A), medium oil (B) and heavy oil (C), were used in this study(Table 1). The reason for testing three types of oil is that IPC, due toits PH, has the potential to interact with components of medium-and high-viscosity oils to further reduce IFT in-situ and this effectcan be specific to the type of oil studied. To evaluate stability andintegrity of reduction of IFT, these tests were repeated after severaldurations of ageing. During the oil preparation stage, the dead oilsamples were cleaned by centrifugation. The cleaned dead oilswere then characterized in terms of density and viscosity at typicalreservoir temperature as well as total acid number. For each oilsample, two similar fresh brine solutions, one for IFT test andanother for assessing repeatability after ageing, were prepared,followed by making IPC in brine solutions. Three concentrations ofIPC (2, 10, and 30 wt%) prepared in a 1 wt% NaCl brine were tested.The IFT values between individual oils and IPC solution in brinewere measured by use of the Spinning Drop method. In addition, abaseline measurement of IFT between brine and oil in the absenceof IPC was conducted for each oil type using the Pendant Droptechnique. All measurements were repeated using the other batchof IPC in brine solution which was aged at constant temperatureand the results were compared with the original data obtainedusing fresh solutions.

To evaluate the effect of salinity of brine on reduction of IFT,three additional tests were performed with light oil A by use of a

Table 1Properties of oils used in IFT measurement tests.

Temperature (°C) Light OilA

Medium OilB

Heavy OilC

Density, kg/m3 15 °C 806.4 948.5 986.920 °C 802.7 942.1a 983.740 °C 794.7 932.1 971.5

Viscosity, mPa � s 15 °C 2.37 928 22,80020 °C 2.15 737a 12,50040 °C 1.83 150 1620

Acid number (mgKOH/g)

0.07 1.20 1.13

a Measured at 25 °C.

2 wt% IPC in brines with 0.5, 2, and 4 wt% NaCl concentration.Some other additional tests, one with medium oil B and one withheavy oil C, each with 2 wt% IPC solution in 4 wt% brine, were alsoconducted. Stability of IPC solution in maintaining reduced IFTvalues and the effect of ageing on reduction of IFT were evaluatedby repeating these measurements for medium-viscosity oil B aswell as heavy oil C with IPC solutions that had been aged for aperiod of six weeks. All these measurements were conducted at20 °C.

One dimensional coreflood tests were conducted to assess theeffectiveness of the IPC formulation in increasing ultimate re-covery of oil through displacement during waterflooding. Fivecoreflood tests were conducted with a variety of oil types at am-bient temperature and one coreflood with heavy oil at an elevatedtemperature. In the first coreflood test, heavy oil C with thegreatest viscosity was used in an IPC-assisted waterflood at 21 °C.In the second coreflood, a commercial alkaline material was usedto recover heavy oil C at room temperature (21 °C). In the thirdcoreflood, recovery of heavy oil C with the aid of a commercialsurfactant flood was determined at room temperature. Corefloodtests 2 and 3 were conducted for comparison with the results ofcoreflood test 1 in which IPC was used as the chemical additive. Incoreflood tests 4 and 5, IPC-assisted waterflooding was used torecover light oil A and medium-viscosity oil B at temperaturesbetween 20–30 °C. In the last coreflood test, IPC was used as thechemical additive to recover heavy oil C at an elevated tempera-ture of 200 °C.

A complete coreflood test was composed of initial waterfloodstage, followed by chemical flood stage and an extended water-flood. A shut-in period for soaking was also considered after thechemical flood. A mixture of synthetic silica sand and a reservoirsand from a heavy oil field, mixed in equal proportions, was usedto simulate the porous media. The sand was packed in confine-ment lead core sleeves measuring 30.5 cm (i.e. one foot) long by3.81 cm (i.e. 1.5 in.) diameter, and then was placed in the over-burden vessel (i.e. core holder) and was confined under differ-ential overburden pressure. The dry core was then saturated withCO2, evacuated and was subsequently checked for possible leaks.The core was then saturated with 4 wt% NaCl brine solution tomeasure initial pore volume and porosity. During the brine flowtests, the absolute single-phase permeability to brine was mea-sured. Each core was then saturated with dead oil and was agedfor a period of at least three weeks at room temperature to allowfor chemical equilibration between brine, oil and rock. The coreprepared for the elevated temperature test (i.e. test # 6) was agedat 200 °C. Conditions were then adjusted to an operating pressureof 2,500 kPa, overburden pressure of 5,000 kPa and a pre-de-termined operating temperature. Finally, different flood stagesincluding initial waterflood using 4 wt% NaCl brine, followed bysubsequent chemical flood and a prolonged waterflood wereconducted during which data were collected including oil andwater production as a function of fluid injected, injection andproduction pressures as well as pressure drop across the core. The4 wt% NaCl brine concentration was selected based on the resultsof compatibility tests and IFT measurement tests.

3. Results and discussion

3.1. Physical properties of IPC formulation

The density of IPC is similar to those of many oil reservoirbrines at the temperatures studied (Table 2). Kinematic viscosity ofIPC at the same temperatures is also presented (Table 2). The dy-namic viscosity of IPC is approximately 3 cP at standard conditionsof one atmosphere pressure and 15 °C, which is approximately

Table 2IPC density and viscosity at different temperatures.

Temperature (°C) Density (Kg/m3) Viscosity (cSt)

15 1067.4 2.7925 1065.3 2.5640 1058.1 2.24

Fig. 2. Derivative TGA signals of samples of IPC under Nitrogen and air.

Fig. 3. DSC traces of samples of IPC under Nitrogen and air.

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3 times that of water under similar conditions. It was assumed thatIPC exhibits Newtonian behavior although it was not tested fornon-Newtonian behavior. This seems a valid assumption con-sidering the fact that most dilute solutions, especially when mixedwith water, exhibit Newtonian behavior.

Amounts of IPC partitioned into the oil phase as a function ofchemical ratios were measured in bench-top volumetric parti-tioning tests. In conclusion, although IPC partitioned into the oleicphase for some of the mixing ratios, the tendency of IPC to par-tition correlated neither with the water/chemical volume ratio,nor with the oilþtoluene per chemical volume ratio used in thesepartitioning tests.

3.2. Thermal stability of IPC

Thermograms of the two TGA tests are shown (Fig. 1). Themajority of the sample vaporized just below 100 °C as a volatilesolvent or solvent mixture. The remaining material appeared to bestable at temperatures greater than 200 °C, above which thesample began to lose weight at a rate that gradually increased withtemperature until the rate peaked around 310 °C. This event can beseen more clearly in Fig. 2 which shows the time derivative of thesignals shown in Fig. 1. The derivative of the TGA signal takenunder air was similar, except that it showed weight loss peaking ata lower temperature of about 265 °C, which is consistent with theoxidation of paraffinic hydrocarbons. There was essentially noweight change above 360 °C, but only about 1.5 wt% of the samplewas remained at this temperature condition. The sample amountthat was left behind appeared to be a white, crystalline mineral.The peaks that appear in Fig. 2 just above 100 °C and at 150 °C arethought to be due to the irregular vaporization, because they werenot reproduced on the trace under air, and are therefore notsignificant.

DSC response to IPC was determined under both Nitrogen andair atmospheres (Fig. 3). Except at temperatures near 300 °C underair, the responses were endothermic, either because of heat ab-sorption through evaporation, or as an indication of the normalheat capacity of a material being heated. The exothermic peak

Fig. 1. TGA traces of samples of IPC under Nitrogen and air.

around 305 °C corresponds to the oxidation peak seen by TGA(Fig. 1). An attempt was made to isolate the effects produced bythe non-aqueous components, by subtracting the thermal analysissignals that were observed for the carrier water samples fromthose taken for the chemical samples. The results, which arepresented in Figs. 4 and 5, revealed that a substantial amount ofIPC that boiled off below 100 °C was not water. The overall

Fig. 4. Difference in TGA traces of water and IPC under Nitrogen.

Fig. 5. Difference in DSC traces of water and IPC under Nitrogen.

Table 4Results of IPC compatibility tests with different brines.

Brine # 5 vol% IPC @22 °C

50 vol% IPC @22 °C

5 vol% IPC @75 °C

50 vol% IPC @75 °C

1 Cloudy (bot-tom 4 mL)

Cloudy (bot-tom 2.5 mL)

Cloudy (bot-tom 4 mL)

Cloudy (bottom2.5 mL)

2 Cloudy (bot-tom 4 mL)

Cloudy (bot-tom 2 mL)

Cloudy (bot-tom 4 mL)

Cloudy (bottom2 mL)

3 Cloudy (bot-tom 10 mL)

Cloudy (bot-tom 32 mL)

Cloudy (bot-tom 6 mL)

Cloudy (Crystalline,90% vol.)

4 Clear Clear Clear Clear5 cloudy (bot-

tom 10 mL)cloudy (bot-tom 26 mL)

cloudy (bot-tom 10 mL)

Cloudy (2 phase)

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conclusion of these tests is that any surface active agent in IPCformulation will begin to degrade at temperatures greater than220 °C. If the EOR processes involve any form of steam injection,then at best IPC could be used only in the shallower oilfields inwhich pressures are less and the saturated steam temperature isnear or below 200 °C; otherwise, these surface active agents willnot survive long enough to be effective in the heated region of theoil reservoir.

3.3. IPC – brine compatibility and stability

The purpose of these tests was to determine chemical com-patibility and stability of IPC in common oilfield brines solutions.Two concentrations of IPC, 5% and 50%, were tested with fivebrines of various mineral contents (Table 3). Each test was con-ducted at two different temperatures: room temperature (22 °C)and 75 °C. Test vials were observed for a period of 1.5 months.Results for compatibility and stability tests are provided (Table 4).Four of the five brines showed signs of incompatibility. Brines withthe greatest salinity and hardness levels (brine #3 and #5) had themost severe precipitation (Figs. 6 and 7). Precipitates formed im-mediately upon contact of IPC with these two brines and did notsignificantly change with time. The mixture of IPC with brine #3emitted a strong ammonia smell. Increasing the concentration ofIPC increased the amount of solid precipitate in the highly salinebrines #3 and #5, and slightly decreased the amount of solidprecipitate in the brines of lower salinity (#1 and #2). This is likelybecause the amount of precipitate-forming ions is limited in theless saline brines. The amount of precipitate at room temperaturewas similar to that of the elevated temperature at similar levels of

Table 3Brine analysis.

Parameters Unit Brine #1 Brine #2 Brine #3 Brine #4 Brine #5

Bicarbonate mg/L – 1130 – – 794Chloride mg/L 11143 8900 106000 3047 48500PH PH units 7.93 5.78 7.07TDS mg/L 18288 16300 295000 5020 82600Calcium mg/L 65 57 7080 14 1800Magnesium mg/L 80 85 1020 0 930Potassium mg/L – 50 3700 0 670Sodium mg/L 7000 6000 90200 1959 27300Barium mg/L – 0.09 1.7 – 35.8Iron mg/L – 0.05 48 – 1.1Manganese mg/L – 0.02 2.7 – 1.1Sulfate mg/L – 760 540 – 2

brine concentration; however, the nature of the precipitate wasdifferent. The precipitate in the 50 vol% solution of IPC with brine#3 had a crystalline structure after a period of 1.5 months at 75 °C.The solid precipitate in the 50 vol% solution of IPC with brine #5formed two phases after a week at 75 °C. Brine #4 appeared to becompatible with IPC, likely due to its low content of divalent ions(Ca2þ and Mg2þ).

In order to check which ions in brine solutions are responsiblefor severe solid precipitation in the presence of IPC, four solutionsof 5 vol% IPC in various single-salt brines – sodium bicarbonate,magnesium chloride, calcium chloride and sodium chloride –wereprepared (Table 5). Precipitation occurred in solutions that con-tained divalent ions (Fig. 8). Therefore, it can be concluded that IPCis incompatible with brines of medium and high hardness whendivalent ion concentrations are greater than 150 ppm. It is possi-ble, however, that slightly acidic or alkaline conditions could im-prove the tolerance of IPC to the divalent ions.

3.4. IFT Measurements for IPC solutions in Brine and Oil

The purpose of these tests was to evaluate IPC for its ability tolower IFT values between brine and oil (Tables 6–8 and Figs. 9–18).For all types of oil used in this study, a typical trend in IFT vs. IPCconcentration is observed: addition of IPC to the binary of water–oil system decreased the IFT value from its original value (i.e. inthe absence of chemical). However, the observed trend was notmonotonic, and an optimum value of chemical concentration wasfound in which IFT reached a minimum. This trend was expectedbecause IPC is a formulation containing surface active agent(s) sothat addition of IPC to the solution will decrease IFT betweenchemical solution and oil. Reduction in IFT as a result of the pre-sence of IPC was more significant with greater viscosity crudecompared to the lighter oils. An increase in salinity of brine up to4 wt% NaCl also led to greater reduction in IFT values, whichmeans that optimal salinity of brine with the employed oil types isgreater than 1 wt%. For both medium-viscosity and heavy oils,there was an apparent optimal concentration of IPC between 0 and10 wt% at which IFT reached a local minimum. It is possible thatthis optimal concentration of IPC chemical is even lower than2 wt%. The typical concentration range for surfactants in fieldchemical EOR projects is from 0.05 to 2 wt%, with most of appli-cations utilizing between 0.1 and 0.3 wt% of active surfactant.

In the case of light oil at a constant level of brine salinity, thegreater the chemical concentration, the smaller the IFT. Techni-cally, it is better to use the maximum chemical concentration, butthis might not be economical. Considering the typical values of IFTneeded for a successful chemical-assisted waterflood test (i.e.0.01–0.001 mN/m or even less), even the IFT value at the max-imum concentration of IPC (i.e. 0.41 mN/m) is not sufficient toachieve desired values. It is important to consider that just one ofthe mechanisms responsible for the effectiveness of chemical-

Fig. 6. Compatibility tests of IPC with brine #3 (after 1.5 months).

Table 5Compatibility of IPC with single-salt brines.

Brine 2 wt%NaHCO3

1 wt% MgCl2 1 wt% CaCl2 2 wt%NaCl

5 vol% IPC @20 °C

Clear Cloudy (bottom12 mL)

Cloudy (bottom30 mL)

Clear

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assisted waterflooding, i.e. reduction in IFT value as a result ofaddition of chemical, is discussed in this paper. Considering theseresults, IPC was not successful in achieving the desired IFT even atthe maximum concentration used when light oil A was used in themeasurements. The employed brine concentration of 1 wt% NaClwas not the optimum salinity for lowering IFT.

Reducing IFT beyond that of brine–oil mixture by use of IPC wastotally different when intermediate-viscosity oil B and heavy oil Cwere used. When these oils were tested against IPC in brine so-lutions with different chemical concentrations, an optimumamount of IPC in brine was obtained that caused the largest de-crease in IFT. Considering the intermediate-viscosity oil B, it wasdetermined that an IPC solution of 2 wt% in brine was optimal

Fig. 7. Compatibility tests of IPC wi

with a minimum IFT of 0.38 dynes/cm. However, IFT was stillgreater than the target value for a chemical-assisted waterflood of0.01–0.001 mN/m or less. In this particular test, salinity of brine(i.e. 1 wt% NaCl) was not optimal. When another test was con-ducted with a brine composed of 4 wt% NaCl, it was determined

th brine #5 (after 1.5 months).

Fig. 8. Compatibility tests of IPC with single salt brines at 22 °C.

Table 6IFT values for light oil A with fresh IPC in brine solutions.

NaCl concentration in brine,wt%

IPC concentration in brine so-lution, wt%

IFT, mN/m

1.0 0 15.741.0 2 1.111.0 10 0.771.0 30 0.410.5 2 0.962.0 2 0.964.0 2 0.83

Table 7IFT values for medium-viscosity oil B with fresh and aged IPC in brine solutions.

NaCl concentrationin brine (wt%)

IPC concentration inbrine solution (wt%)

IFT (mN/m)

Fresh brinesolution

Brine solutionaged for6 weeks

1.0 0 16.72 –

1.0 2 0.38 0.451.0 10 0.65 0.651.0 30 0.52 0.454.0 2 0.34 0.32

Table 8IFT values for heavy oil C with fresh and aged brine solutions.

NaCl concentra-tion in brine(wt%)

IPC concentra-tion in brine so-lution (wt%)

IFT (mN/m)

Freshbrinesolution

Fresh brinesolution(repeatedtests)

Brine solu-tion agedfor6 weeks

1.0 0 58.25 – –

1.0 2 0.14 0.20 0.411.0 10 0.61 0.55 0.581.0 30 0.40 0.48 0.744.0 2 0.07 0.03 0.11

Fig. 9. Effect of IPC concentration on dynamic IFT data for light oil A with 1 wt%NaCl brine at 20 °C.

Fig. 10. Effect of brine salinity on dynamic IFT data for light oil A with brine so-lutions at constant IPC concentration of 2 wt% at 20 °C.

Fig. 11. Equilibrium IFT vs. IPC concentration for light oil A.

O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497490

that IPC performed slightly better at greater brine salinity com-pared to the lesser salinity. For the heavy oil C which has viscosityin the range of crude in Lloydminster heavy oil reservoirs, IPCworked efficiently and the drop observed in IFT compared to theother two previous cases was greatest. The IFT obtained betweenheavy oil C and 2 wt% IPC solution in 1 wt% NaCl brine was thesmallest value obtained (i.e. 0.14 dynes/cm). Similar to the cases oflight and intermediate-viscosity oil, the brine salinity was notoptimum as far as the effectiveness of IPC in lowering IFT is con-cerned. When similar concentrations of IPC were tested in the

Fig. 12. Equilibrium IFT vs. brine salinity for light oil A.

Fig. 13. Effect of brine salinity and IPC concentrations on dynamic IFT data formedium-viscosity oil B (fresh IPC in brine solutions).

Fig. 14. Effect of brine salinity and IPC concentration on dynamic IFT data formedium-viscosity oil B (aged IPC in brine solutions).

Fig. 15. Effect of brine salinity and IPC concentration on dynamic IFT data for heavyoil C (fresh IPC in brine solutions).

Fig. 16. Effect of brine salinity and IPC concentration on dynamic IFT data for heavyoil C (aged IPC in brine solutions).

Fig. 17. Equilibrium IFT values versus IPC concentration for medium-viscosity oil B.

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presence of greater salinity (i.e. 4 wt% NaCl), the IFT was reducedby 50%.

Repeatability of IFT results was checked. Measurements of IFTwere repeated after 6 weeks of ageing. It was expected to see si-milar or slightly lower values after this ageing period. Except fortwo single measurements, i.e. heavy oil C with chemical con-centrations of 2 and 30 wt% which showed an unusually largeincrease in IFT after aging, the expected trend was observed andthe difference in IFT values before and after ageing was within 5–7% of the original values. The “rule of thumb” for chemical EOR isthat a two-fold decrease in IFT results in approximately a 10% in-crease in ultimate recovery of oil. It is typically desired to have IFT

Fig. 18. Equilibrium IFT values versus IPC concentration for heavy oil C.

Table 10IFT values for solutions of several commercial sur-factants with heavy oil C.

Chemical name IFT, mN/m

Ethomen 18–25 1.86Rhodacal DSB 2.40N-85 0.96Bio-Terge PAS-8 S 2.84Arquad T-50 0.22a

a after 70 min, IFT increased to 0.68 mN/m.

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values in the range of 10�2–10�3 mN/m or less. According to thisestimate and results of IFT reduction only, IPC could be consideredfor chemical EOR in a field containing heavy oil “C”, depending onthe salinity of in-situ brine. IFT reduction with oil types “A” and “B”was not sufficient to the extent of providing significant benefitsthrough the reduction of capillary forces. However, it is possiblethat improvement in oil recovery could still be achieved throughoil emulsification and/or alteration of formation wettability by theuse of IPC as an additive.

3.5. Coreflood experiments

Six core displacement experiments were conducted. Some de-tails about properties of rock and fluid are listed (Table 9). Threeoils were used: light oil A, medium-viscosity oil B and heavy oil C(Table 1). Five coreflood tests were conducted at ambient tem-perature and one experiment was conducted at 200 °C. To com-pare performance of IPC to other commercial products that arecurrently being used in EOR processes, two baseline corefloodexperiments were conducted: one with a mixture of two alkalimaterials (sodium carbonate and sodium hydroxide) and the otherone with a commercial surfactant, Arquad T-50, that was selectedfrom among five different commercial surfactants based on their

Table 9Rock and fluid properties for the coreflood experiments.

Test No. 1 2 3Oil Light oil A Medium oil B Heavy oil C

Brine 4 wt% NaClChemical 2 wt% IPC 2 wt% IPC 2 wt% IPCTemperature, °C 22 22 22Core length, cm 30.8 31.3 30.9Core diameter, cm 3.81 3.81 3.81Initial permeability, mD 7.2 7.8 7.4Porosity, % 38.76 40.5 36.2

ability to reduce IFT between brine and oil (Table 10). One addi-tional surfactant was also tested and found to be effective in re-ducing IFT. However, it was not used in the coreflood experimentsbecause it had not been used in the EOR processes in the past.Results of the core displacement experiments are provided (Ta-bles 11 and 12, Figures 19–28).

The greatest incremental recovery over the initial waterfloodwas 16.4% of OOIP for heavy oil C in the ambient temperaturecoreflood when IPC was used (RUN #3, Table 11, Figs. 19 and 20).This oil also had the least IFT with IPC solution in brine. About 4.5%OOIP of additional oil was also recovered in the coreflood withmedium-viscosity oil B in RUN # 2 when IPC was added to theinjection mainstream (Table 11, Figs. 19 and 20). Practically, noadditional oil was recovered in the corefloods with light oil A (RUN#1 with a minor enhancement of only 0.68% of OOIP in incre-mental oil recovery) and the one at elevated temperature of 200 °Cwith heavy oil C (RUN #6 with a minor enhancement of 1.48%OOIP in incremental oil recovery) in the presence of IPC as anadditive (Table 11, Figs. 19 and 20). Failure in recovering more oilin these two corefloods was likely due to the fact that the initialwaterflood recovery associated with these two tests was verygreat. In the former test, the great initial waterflood recovery isdue to very small value of in-situ oil viscosity whereas in the lattercase, it was due to reduced viscosity of heavy oil as a result ofheating. Therefore, the remaining oil saturations, and conse-quently relative permeability to oil, at the beginning of the che-mical flooding stage were significantly less compared to the othercoreflood tests.

The greatest ultimate recovery factor was observed in RUN #6(i.e. 56.96% of OOIP) in which in-situ viscosity of heavy oil wassignificantly reduced with the aid of thermal heating and the factthat microscopic sweep efficiency was also enhanced with thepresence of IPC in the injection mainstream due to reducing theIFT value (Table 11 and Fig. 19). The coreflood test with heavy oil Cat ambient conditions was affected more by addition of IPC to theinjecting phase during the chemical flooding stage of the process,with an incremental oil recovery of 16.4% of OOIP, followed bycorefloods using medium-viscosity oil B, heavy oil C at elevatedtemperature, and light oil A with incremental oil recovery valuesof 4.5%, 1.48%, and 0.68% of their associated OOIP values, respec-tively (Fig. 20).

4 5 6Heavy Oil C Heavy Oil C Heavy Oil C

1 wt% Na2CO3 þ 1 wt% NaOH 1 wt% Arquad T50 2 wt% IPC22 22 20031.3 30.9 30.73.81 3.81 3.816.3 5.4 5.136.43 35.78 41.1

Table 11Recovery efficiency of coreflood tests with IPC as an additive.

Process stage during coreflood Light oil A Medium oil B Heavy oil C Heavy oil C at 200 °C

So % OOIP recovered So % OOIP So % OOIP recovered So % OOIP recovered

Initial oil saturation stage 0.622 0.0 0.847 0.0 0.940 0.0 0.690 0.00Initial waterflood stage 0.320 48.48 0.629 25.7 0.833 11.4 0.294 55.48Chemical flood stage 0.319 48.76 0.615 27.4 0.685 27.1 0.287 56.55Extended waterflood stage 0.316 49.16 0.591 30.2 0.678 27.8 0.284 56.96

Table 12Performance comparison of IPC to commercial surfactant Arquad T-50 and alkalineadditives using 1D coreflood experiments with heavy oil C.

Process stageduringcoreflood

IPC Alkaline Arquad T-50

So % OOIPrecovered

So % OOIPrecovered

So % OOIPrecovered

Initial oil sa-turation stage

0.940 0.0 0.910 0.0 0.937 0.00

Initial water-flood stage

0.833 11.4 0.817 10.3 0.826 11.79

Chemical floodstage

0.685 27.1 0.695 23.7 0.729 22.13

Extended wa-terflood stage

0.678 27.8 0.693 23.8 0.722 22.97

O. Mohammadzadeh et al. / Journal of Petroleum Science and Engineering 135 (2015) 484–497 493

Two coreflood experiments, both with heavy oil C, were con-ducted with typical chemical additives that have been used inchemical EOR processes: (1) RUN #4 with alkali (2 wt% solution ofthe 1:1 mixture of sodium carbonate and sodium hydroxide) as anadditive, and (2) RUN # 5 with a commercial surfactant “ArquadT-50” as an additive which was selected from among five differentsurfactant chemicals based on the achieved reduction in IFT value(Table 10). Production performance results of these two corefloodsare listed in Table 12 and plotted in Figs. 21 and 22. Both of thesetwo additives resulted in significant incremental oil recovery (i.e.11.18% of OOIP for Arquad T-50 assisted waterflood in RUN #5 and13.5% OOIP for alkali flooding in RUN #4). However, the corefloodtest with IPC as an additive (i.e. RUN #3 with an incremental oilrecovery of 16.4% of OOIP) exhibited superior performance com-pared to these two chemical additives at similar operating con-ditions and rock and fluid properties (Table 12 and Figs. 21 and

Fig. 19. Effect of oil type on recovery efficiency of IPC-a

22).For each particular coreflood test, results of instantaneous re-

covery factor, in terms of produced percentage of OOIP as afunction of PV injected, are plotted along with pressure dropacross the core for different production stages including initialwaterflood, chemical flood, and prolonged waterflood stages as-sociated with each core displacement test (Figs. 23–28). The in-cremental recovery plots, during the chemical flooding stages as-sociated with all these tests, correlate very well in dimensionlesstime, in terms of pore volume injected, with an increase in pres-sure drop across the cores. This behavior indicates that additionalvolumes of oil were being mobilized and transported through thecore towards the producing end as soon as chemical was injectedinto the mainstream, i.e. commencement of chemical floodingstage, in each particular coreflood test. In general, the pressuredrop plots across the core for all six coreflood tests are in goodagreement with the incremental recovery plots, i.e. the greater theincremental recovery value is, the greater is the moving averagevalue of the pressure drop plot at that particular process time (i.e.pore volume injected).

4. Conclusion

A number of tests including thermal stability, physical proper-ties determination, compatibility of IPC with brine, IFT measure-ment and coreflood displacement experiments were conducted todetermine the effectiveness of IPC for chemical-assisted water-flooding process. The following conclusions are obtained:

1. About 80 wt% of the chemical was lost by 85 °C in an opensystem of TGA testing unit. However, the weight-loss trend ofthe chemical was almost stable at higher temperature range up

ssisted waterflood during full life of the coreflood.

Fig. 20. Effect of oil type on recovery performance of IPC-assisted waterflood during chemical flood stage of the coreflood experiments.

Fig. 21. Effect of chemical additive on recovery performance of chemical-assisted waterflood using heavy oil C during the full life of the coreflood tests.

Fig. 22. Effect of chemical additive type on recovery efficiency of chemical-assisted waterflood to recover heavy oil C during chemical flood stage of the corefloodexperiments.

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Fig. 23. Oil recovery and pressure drop along the core during full life of coreflood #1 to recover light oil A using IPC-assisted waterflood.

Fig. 24. Oil recovery and pressure drop along the core during full life of coreflood #2 to recover medium-viscosity oil B using IPC-assisted waterflood.

Fig. 25. Oil recovery and pressure drop along the core during full life of coreflood #3 to recover heavy oil C using IPC-assisted waterflood.

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Fig. 26. Oil recovery and pressure drop along the core during full life of coreflood #4 to recover heavy oil C using alkaline assisted waterflood.

Fig. 27. Oil recovery and pressure drop along the core during full life of coreflood # 5 to recover heavy oil C using Arquad T50 surfactant assisted waterflood.

Fig. 28. Oil recovery and pressure drop along the core during full life of coreflood # 6 to recover heavy oil C using IPC-assisted waterflood at elevated temperature of 200 °C.

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until 220 °C. It is concluded that any surface-active agents in IPCwill begin to degrade at temperatures greater than a thresholdtemperature of 220 °C.

2. IPC formulation, in its original form, has densities similar to oilreservoir brines and viscosities about three times greater thanwater at the same temperature and pressure conditions. IPC canbe used as an agent to avoid the adverse mobility ratio duringwaterflooding of heavy oil reservoirs by making the injectingdisplacing phase more viscous, and at the same time, it can beused as a surfactant to reduce the interfacial tension. All thesecharacteristics have the potential to improve oil recovery withthe aid of IPC-assisted waterflooding.

3. From the IFT measurement tests, it was found that IPC wasequally or more effective in reducing IFT values at concentrationof 2 wt% than at greater concentrations, suggesting that theoptimal concentration of IPC may be lower than 2 wt%. LesserIFT were achieved in tests in which 4 wt% NaCl concentrationwas present in brine samples, and therefore optimal salinity forIPC chemical was above 1 wt% Total Dissolved Solid (TDS) forthe brine and oil samples tested. This is a positive result, sincemost of the heavy oil reservoirs (for which the IPC appears to beeffective) have brines with salinities in the range of 40,000–100,000 ppm.

4. Coreflood displacement experiments and IFT measurementsindicated that IPC can be very effective in improving heavy oildisplacement efficiency in ambient temperature (22 °C) condi-tions in which the greatest incremental oil recovery wasachieved (i.e. 16.4% of OOIP). However, the application of IPC atelevated temperature of 200 °C with the same oil did not show asignificant improvement on oil recovery after injection of overone pore volume of chemical solution due to the fact that theinitial waterflood stage recovered most of the oil and the re-maining oil saturation in the core was low at the time when thechemical flood was started.

5. IPC was moderately effective in recovering additional oil in thecoreflood experiment with medium-viscosity oil B. In total, 4.5%of incremental OOIP was recovered after the expiry of thechemical flood as well as that of the extended waterflood stages.This number can be significant if applied to the field; however,results of 1D coreflood experiments cannot be directly upscaledto the field conditions. Additional work, such as larger scaleexperiments, a larger variety of oils and numerical simulationwill need to be tested before any practical trend can be ob-served with certainty.

6. The amount of oil recovery using IPC was compared with thoseobtained by alkali and a commercial surfactant flooding whenheavy oil C was used. These results, along with the typicallyachieved incremental recovery values associated with surfac-tant-type chemical additives lead to the conclusion that IPCdoes have a potential in chemical EOR applications for in siturecovery of heavy oil.

Acknowledgment

The research was supported by a Grant fromWestern EconomicDiversification Canada (Project # 411342) and Enterprise Sas-katchewan (Project # 411347). The authors wish to acknowledgethe support of an Instrumentation Grant from the Canada Foun-dation for Infrastructure. JP Giesy was supported by the CanadaResearch Chair program and the Einstein Professor Program of theChinese Academy of Sciences.

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