Polymer Flooding

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Mechanistic Modelling of the Alkaline/Surfactant/Polymer Flooding Process at Sub-Optimum Salinity Conditions for Enhanced Oil Recovery Seyed Mojtaba Hosseini-Nasab, Chaitanya Padalkar, Elisa Battistutta, and Pacelli L.J. Zitha Ind. Eng. Chem. Res., Just Accepted Manuscript • DOI: 10.1021/acs.iecr.6b01094 • Publication Date (Web): 27 May 2016 Downloaded from http://pubs.acs.org on May 29, 2016

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Industrial & Engineering Chemistry Research

Mechanistic Modelling of the Alkaline/Surfactant/Polymer Flooding Process at SubOptimum Salinity Conditions for Enhanced Oil Recovery S.M. Hosseini-Nasab*1; C. Padalkar2; E. Battistutta3; P.L. Zitha4 1- Delft University of Technology, Department of Geoscience & Engineering, Petroleum Engineering Group, [email protected] 2- Delft University of Technology, Department of Geoscience & Engineering, Petroleum Engineering Group, [email protected] 3- Delft University of Technology, Department of Geoscience & Engineering, Petroleum Engineering Group, [email protected] 4- Delft University of Technology, Department of Geoscience & Engineering, Petroleum Engineering Group, [email protected]

Abstract Alkaline-Surfactant-Polymer (ASP) flooding is potentially the most efficient chemical EOR method. It yields extremely high incremental recovery factors in excess of 95% of the residual oil for water flooding on the lab scale. However current opinion is that such extremely high recoveries can be achieved at optimum salinity conditions, i.e. for the Winsor Type III microemulsion phase characterized by an ultralow interfacial tension (IFT). This represents a serious limitation since several factors, including alkali-rock interaction, the initial state of the reservoir water and the salinity of injected water, may shift the ASP flooding design to either under or over-optimum conditions. A recent experimental study of ASP floods, based on a single internal olefin sulfonate (IOS) in natural sandstone cores with varying salinity from sub-optimum to optimum conditions, indicated that high recovery factors can also be obtained at sub-optimum salinity conditions. In this paper a mechanistic model was developed to explore the causes behind the observed phenomena. The numerical simulations were carried out using the UTCHEM research simulator (University of Texas at Austin) together with the geochemical module EQBATCH. UTCHEM combines multiphase multicomponent simulation with robust phase behavior modelling. An excellent match of the numerical simulations with the experiments was obtained for oil cut, cumulative oil recovery, pH profile, surfactant, and carbonate concentration in the effluents. The simulations gave additional insight into the propagation of alkali consumption, salinity, surfactant profiles within the core. The study showed that the initial condition of the core is important in designing an ASP flooding. Due to uncertainties in the various chemical reactions taking place in the formation, an accurate geochemical model is essential for operating an ASP flooding in a particular salinity region. The simulation results demonstrate also that for crude oil with a very low total acid number (TAN), the ultralow IFT and low surfactant adsorption can be achieved over a wide range of salinities that are less than optimal salinity. The results provide a basis to perform better modelling of the sub-optimum salinity series of experiments and optimizing the design of ASP flooding methods for the field scale with more complicated geochemical conditions.

1. Introduction Early research showed that to recover waterflood residual oil, it is vital to increase the capillary number as the capillary forces have the main responsibility for oil entrapment after water flooding during immiscible displacement inside porous media1. Capillary numbers are dimensionless values defined by the ratio of viscous forces and capillary forces. Alkali-surfactant-polymer (ASP) flooding is an emerging technology to increase production from oil reservoirs potentially as the most efficient chemical-enhanced oil recovery (cEOR) technique2. In this method, a combination of alkali, surfactants and polymer is used to recover capillary-trapped oil and to improve sweep efficiency. Polymers increase the viscosity of the drive water in order to give stable displacement of crude oil and considerably improve the volumetric

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sweep efficiency of the reservoirs. The property of surfactant used in this application is to reduce the interfacial tension (IFTs) between the displacing phase and crude oil to an ultralow value (< 10-3 mN/m). Alkalis induce the formation of soaps by interaction with a crude oil that exhibits a high total acid number (TAN), and they also reduce surfactant adsorption on the rock by increasing the pH of the injection solution. The generated in situ soap in combination with surfactants allows ultralow IFTs to be reached which results in considerable quantities of the trapped oil to be mobilized3. As global oil prices increased from the early 2000s, research into polymer and ASP flooding resulted in a number of successful field applications. An incremental oil recovery of 20%, 24.0% and 26.8% were reported for the Daqing oil field2,4, the Karamay oil field5 and the Tanner Field6. ASP flooding provides a distinctly higher recovery factor than polymer flooding on a reservoir scale (5-10%). Every oil field typically requires its own combination of chemicals in order to maximize oil recovery. Several authors have investigated ASP flooding, focusing on the composition of surfactants or the design of ASP slugs7–9. Their works relied on coreflood experiments to determine the optimum parameters for achieving maximum oil recovery. A generally successful laboratory approach to chemical EOR has shown that when ASP chemical formulation (i.e. surfactants, cosolvent, alkali, polymer, and electrolytes) in contact with crude oil provide good phase behavior in terms of creating microemulsion at optimal salinity, ASP flooding results in high recovery of waterflood residual oil from the sample reservoir cores. Characterization of oil/water/surfactant phase behavior has been described by Winsor10. He indicated that phases change from Type II- (oil in the excess water phase), Type II+ (water in the excess oil phase) and Type III (the bicontinuous oil/water phase) as the salinity increases. Based on the salinity limits, Type II(or sub-optimum) is below the lower salinity limit of Type III and Type II+ (or over-optimum) is above the upper salinity limit of Type III. Much work in the literature indicates that ultralow IFTs are observed with Type III, which consists of excess oil and excess water phases separated by a microemulsion phase. The salinity concentration at which equal amounts of oil and water are solubilized in this (middle phase) microemulsion is referred to as optimal salinity. Conventional studies show that in order for ASP floods to achieve maximum oil recovery, then chemicals must be injected at optimum salinity under Type III phase behavior conditions11,12. However, several factors including alkali-rock reactions, the initial salinity state of the reservoir water and salinity of the injected water may shift the ASP flooding design to either under or over-optimum conditions. Some researchers have indicated that the different phenomena involved in the ASP flooding mechanism are not that simply correlated. They have found that (equilibrium) IFT is not the dominant factor controlling oil recovery, but instead other factors such as the mobility ratio and surfactant retention are important. Thus, the equilibrium IFT between the injected surfactant fluid and crude oil as present in a phase behavior experiment could be a representation of the phases in contact within a particular porous medium, but this may not be true for all systems13. Recent studies have shown that high oil recovery is also possible at non-optimum salinity conditions7,14,15. This was also the case in the series of experiments conducted in which the highest oil recovery was observed under Type II- or sub-optimum salinity conditions in the work by Battistutta et al.16 Thus new studies often contradict the conventional early studies. Hence there is no clear ASP flooding strategy defining the region of salinity that is favorable for an efficient process. Each phase type has advantages and disadvantages associated with oil recovery, depending on the relative permeabilities and other parameters (see Table 1). Arhore has found experimentally that an sub-optimum flooding recovered more oil than an optimum-salinity flooding (80% vs. 68% of residual oil after a waterflood), but this may have been caused by the in situ salinity being slightly higher than the ASP salinity due to in situ mixing with the initial and injected (waterflooding) brine17.

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Table 1. Advantages and disadvantages of three types of microemulsion systems for surfactant-based flooding EOR

Winsor phase types

Advantages

Disadvantages

Type II- (Sub-optimum)

Low surfactant trapping and adsorption3, Benefit of the Low Salinity flood

Bypassing of remaining oil due to capillary diffusion and high mobility

Type III (Optimum salinity range)

Lowest interfacial tension (IFT), Emulsification and high miscibility

Formation of second liquid phase, Coalescence and liquid crystal

Type II+ (Over-optimum)

Higher oil relative permeability than Type III, High miscibility of oil and ASP slug

Surfactant entrapment in oil phase, Oil-Wet behavior in relative permeability

Opposite salinity gradients are also applied to maximize oil recovery, i.e. injecting an ASP at higher salinity, i.e. Type II+, in combination with a low-salinity formation brine or polymer drive to move the system towards Type II- through Type III18. Indeed, the salinity requirement of a chemical flooding system usually varies during a process because of various phenomena such as adsorption, dispersion and mixing of fluids. Thus it is physically possible for two mechanisms (for instance, Type III and Type II-) to be operative for similar conditions in the ASP EOR process. This could result in losing the optimal salinity during the floods, but oil recovery might not decline when other mechanisms such as low surfactant adsorption on the rock and less surfactant trapping in the oil phase at sub-optimum salinity conditions are functioning. Lastly, researchers at CIPR (Norway) reported the use of Low Salinity Surfactant (LSS) flooding as an EOR technique14,19,20. The addition of surfactant to a low salinity brine resulted in additional oil recovery in core flooding experiments, even though IFT was not ultralow (less than 10-2 mN/m). The amount of additional oil recovered with this system was comparable to the amount of oil recovered when the salinity of the system is increased to the optimal salinity (and ultralow IFT), but surfactant retention was much lower, possibly due to better solubility of the Internal Olefin Sulphonate (IOS) surfactant at lower salt concentrations. The implication is a possibility for a potentially better and more successful surfactant flooding in the Type II- region if a significantly lower retention outweighs the disadvantage of interfacial tensions being higher20. However, LSS flooding suffers from the limitation that it requires a significant salinity reduction in the available water in most cases. A series of ASP core flooding experiments performed at different salinities in the Type II- (sub-optimum) vs. Type III (optimum salinity) phase behaviors have been presented in the companion paper16. The aim of this experimental program was to determine the dependence of oil recovery and surfactant retention on salinity and IFT variations. This coreflood study reported higher recovery factors at sub-optimum (2.5 wt% NaCl) than at optimum conditions. Therefore the question arises as to how this sub-optimum condition will affect the incremental oil recovery factor. To further understand this outcome, this paper aimed to investigate this salinity condition by developing a numerical model in a chemical flooding simulator. The optimization, interpretation and integrated design of this EOR method are essential when considering the complicated phase behavior and the complexity of physics and crucial parameters involved in the ASP EOR process. This requires a predictive model with appropriate physics to fully understand the underlying mechanisms driving the ASP EOR performance. The objective in this paper is modelling of a laboratory ASP coreflood experiment performed at sub-optimum salinity to give a better understanding of the process for these sub-optimum salinity conditions and its effectiveness over other optimum salinity techniques. The reason for this choice is that in spite of the fact that ASP flooding had the lowest salinity, it produced the highest incremental oil recovery. Sheng’s15 comprehensive literature review introduces UTCHEM as the most practical tool for the mechanistic simulation of ASP flooding. UTCHEM simulator is a research 3D chemical flooding reservoir simulator for multiphase and multicomponent systems. This simulator was used to interpret the ASP coreflood experiment sub-optimum salinity conditions by the



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simulation of various parameters. In this paper the ASP flooding process was modelled by including the surfactant phase behavior as a function of salinity, temperature and cosolvent concentration, fluid rheology, oil desaturation, rock fluid interaction such as cation exchange, and geochemical reactions. To take into account the effect of geochemical reactions occurring in the core, EQBATCH, the built-in geochemical model of UTCHEM, was used through which the initial equilibrium based on the formation composition, the CEC (cation exchange capacity) and HEC (hydrogen exchange capacity), are calculated21. EQBATCH takes into account the geochemical reactions existing in the ASP flooding such as alkali precipitation with divalent cation, in situ soap generation, and alkaline consumption by ion exchange reactions. The numerical simulation will also try to uncover the sensitivities of oil recovery to the amount of injected surfactant, effective salinity profiles in the core and the uncertainties in developing a reliable model.

2. Experiment Materials and Methods The alkali used in this study is sodium carbonate (Na2CO3, Merck, 99% pure); the cosolvent is a secbutyl alcohol (SBA, Merck, 99% pure); the polymer is Hydrolysed Polyacrylamide, Flopaam™ 3330S and the surfactant is a C20-24 Internal Olefin Sulphonate, ENORDET™ O242 (Barnes 2010). The salt used for the brine preparation consists of sodium chloride (NaCl, _99% pure).The crude oil had the following properties (at 52 °C): density 0.856 g/cc, viscosity 3.4 ± 0.7 cP, TAN 0.05 mg KOH/g oil. The Bentheimer core was used to perform the experiments. Their mineralogy and physical properties were measured and described in Table 2. Table 2. Physical properties and mineralogical composition of Bentheimer sandstone core

Mineralogy Quartz

Clay

weight % 94.40

weigh t% 2.70

Physical Properties

Feldspar

Carbonate Minerals

Others

Porosity

Permeability

Diameter

Length

Pore Volume

weight %

weight %

weight %

%

Darcy

cm

cm

cm3

2.4±0.1

0.5±0.1

--

25±0.1

3.50±0.2

3.8±0.1

38.35±

93±0.2

The setup used for the coreflood experiments is shown in Figure 1. The core holder was placed vertically in an oven operated at 52 ± 1° C. A back pressure regulator and collector of produced fluids are at the end. Differential pressure transducers were placed near the inlet of the ISCO pump, inlet of the piston pump line and just before the core-holder to measure the pressure drop over the core for different injection profiles. The cores used were cut from Bernheimer-type sandstone and examined in a CT scan to detect the presence of any anomalies such as cracks or uncharted elements as shown in Figure 2. The coreflood procedure is shown in Table 3. The core was flushed with CO2 at the start of the experiments in order to remove air and ensure that 100% brine saturation was reached. This is one of the most commonly used methods to do this. More information about all the series of ASP coreflood experiments at suboptimum and optimum salinity conditions in the Bentheimer and Berea sandstone rock can be found in the companion work of this paper16.


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Figure 1. Schematic of the experimental setup used to perform ASP coreflood experiments

Figure 2. Three dimensional image from the cross section of core obtained by the medical CT Scan apparatus.

Table 3. Summary of injection profile and basic properties for ASP coreflood experiments Injection Step

Pore Volumes (PV)

Flow Rate (cc/min)

Back Pressure (Bar)

Temperature (°C)

CO2 flushing Brine saturation Permeability test Oil injection Water flooding ASP injection Polymer injection

10 2.5 7 0.48 2.58

1 1-5 1 0.25 0.25 0.25

0 25 5 5 5 5 5

21 52 52 52 52 52 52

Injection Direction Bottom to Top Bottom to Top Bottom to Top Top to Bottom Bottom to Top Bottom to Top Bottom to Top

3. Results and Discussion 3.1. Geochemical Model To take into account the effect of geochemical reactions that occur during ASP flooding, EQBATCH, the geochemical module of UTCHEM was used. The mineralogical composition of the rock used in this study was used to develop the geochemical model. Dissolution–precipitation reactions, homogenous aqueous reactions, soap generation, ion exchange reactions with rock minerals and micelles are the key features of the ASP flood geochemical interaction for numerical simulation of the process. However, in this paper precipitation of divalent cations was ignored due to their low concentrations. The dissolution of quartz was not considered due to the pH in the experiments, which was not high. In situ generation of



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soap was not included due to the low acid number of the crude oil (

Polymer Flooding

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