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Improved oil reservoir sweep with viscoelastic surfactants Joris van Santvoort, and Michael Golombok Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b01932 • Publication Date (Web): 14 Sep 2016 Downloaded from http://pubs.acs.org on September 22, 2016
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Energy & Fuels
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Improved oil reservoir sweep with viscoelastic
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surfactants
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Joris van Santvoortᵃ*, Michael Golombokᵃ ᵇ
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ᵃ Technische Universiteit Eindhoven, 5612 AZ Eindhoven, The Netherlands
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ᵇ Shell Global Solutions International B.V., 1031 HW Amsterdam, The Netherlands
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*Corresponding author
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Abstract
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Viscoelastic surfactant solutions increase oil recovery by selectively modifying the viscosity of
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the injected displacing fluid in different zones of the reservoir. We demonstrate that flow
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resistance in high permeability zones is increased whereas no significant change in viscosity
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occurs in low permeability zones. This greatly reduces injected fluid losses via the high
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permeability route. In two phase flow in sandstones, recovery increases by about 25%. Efficiency
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also increases by a factor of 3 as shown by the large reduction in injected volume at
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breakthrough. Consequently less fluid is lost through high permeability thief zones. Recovery is
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increased in carbonates as well but the efficiency is depleted due to apparent changes in wetting.
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The reduction in injected fluid before breakthrough has the potential to prolong the economical
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lifespan of water wet reservoirs.
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Energy & Fuels
1. Introduction
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In secondary oil recovery water is injected into the reservoir to drive oil towards a
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production well. Water-flooding typically yields 15-35% incremental absolute recovery of the
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original oil in place (OOIP).1 This relatively low efficiency largely stems from reservoir
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heterogeneity where high permeability zones and/or fractures cause preferential flow paths with
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low flow resistance. These preferential paths act as ‘thief zones’ through which the bulk of the
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displacing fluid flows.2 Oil in the low permeability layers is bypassed and becomes stranded.
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Eventually breakthrough is reached via these high permeability zones and the injected fluid will
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be produced from the reservoir. From this point most of the fluid injected into the reservoir does
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not contribute to recovery. Nearly all of the water is lost through the thief zones without any
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displacement of additional oil. Also there is an increase in water-cut at the producer which
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increases post-processing costs. For these reasons many mature reservoirs become economically
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unattractive and have a relatively short lifespan.3
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Reservoir heterogeneity can be overcome by redirecting flow paths towards oil rich low
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permeability zones (conformance control). Typically thief zones are blocked by injecting
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polymeric gel or surfactant foam.4 The displacing fluid is subsequently diverted into the low
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permeability layers sweeping the reservoir more effectively. This process is expensive and
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relatively complicated since it requires extensive knowledge of the reservoir. Improper use can
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permanently block low permeability layers and prevent oil production.5
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In this study we investigate the use of viscoelastic surfactant (VES) solutions for
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conformance control. These fluids have a unique rheological behavior which makes them
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applicable as spatially self-regulating displacement fluids. Previous work showed that VES fluids
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can adjust the flow in a heterogeneous reservoir to create a more uniform flow front.6,7 Most of
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the previous work was single phase in homogeneous synthetic porous media. This paper focusses 3 ACS Paragon Plus Environment
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on oil displacement testing of VES fluids in real reservoir rock (carbonate and sandstone).
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Section 2 explains the nature of VES fluids, their unique non-Newtonian behavior and the
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potential for conformance control. The experimental process is outlined in section 3 and the
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results are discussed in section 4.
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2. Background
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Enhanced oil recovery (EOR) strives to overcome the challenges associated with water-
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flooding. Chemicals are typically added to the water to alter the properties and promote oil
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mobilization. One particular class of chemicals in EOR are surfactants which are used for
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reducing interfacial tension. However some categories of surfactants can also modify the
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rheological behavior of the fluid in which they are dissolved. In particular, viscoelastic surfactant
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solutions show non-Newtonian behavior.8,9 Worm-like micelles are formed at low concentration
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in the presence of organic salts. They create a polymer-like complex network which alters the
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structure of the fluid.10 Unlike polymers, worm-like micelles are not composed of unyielding
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chains and can thus freely break and reform. The ability to self-heal gives them a significant
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advantage during the injection stage into a reservoir where polymer might degrade.11
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The use of VES fluids for mobility control in oil reservoirs has been investigated with
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high-viscosity shear-thinning surfactant solutions.12 However, the rheological behavior of VES
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fluids extends further than merely shear-thinning. When the surfactants are dissolved in a specific
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dilute concentration range, they exhibit a unique shear-response. Experiments in Couette flow
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showed that VES fluids can have a non-monotonic shear-thickening/shear-thinning response.13,14
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The shear-thickening effect is caused by the formation of so-called shear induced structures (SIS)
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associated with the worm-like micelles mentioned above. These long-range connections cannot
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form under static conditions which explains the lower zero-shear viscosity.15 Once the shear rate
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becomes too high the SIS structures are mechanically degraded and the viscosity drops (shear
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thinning).
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Pressure driven flow experiments show that viscosity is selectively increased in high
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permeability zones. Darcy’s law (from which the apparent viscosity is derived) is, strictly
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speaking, not valid for non-Newtonian fluids, however it can be applied to assess the apparent
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deviation in response of the test fluid compared to the Newtonian base fluid in which the VES is
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dissolved. We compare the flow velocities ( ) of base fluid (i.e. fluid such as water or brine into
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which VES is dissolved) and the VES solutions velocity ( ) at identical pressure gradients
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(figure 1) through a core of permeability . The reduction in flow rate represents a resistance
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factor equivalent to the ratio of apparent to base fluid (brine) viscosities given by:15 =
=
(1)
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Note that the resistance factor is different from the mobility ratio which is also used in EOR. The
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mobility ratio uses the viscosity ratio between the displaced phase (oil) and the injected aqueous
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phase to analyze the effect of viscous fingering.16 The resistance factor on the other hand gives
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the added flow resistance when a non-Newtonian (in this case viscoelastic) fluid is used instead
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of a conventional Newtonian fluid.
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The resistance factor is used to compare flow resistance in high permeability ( ) and
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low permeability ( ) cores. For Newtonian fluids = since the viscosity is constant and
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thus independent of flow conditions. For VES fluids however it has previously been
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demonstrated that > .17 This disparity in resistance factor between cores of different
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permeability reduces the fluid lost through the preferential high permeability core. The resistance
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factor cannot simply be calculated from a Couette sheared flow response which is at best
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indicative that a particular solution may be interesting for a test in permeable pressure driven
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flow.
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The resistance factor in pressure driven flow is thus not exclusively a result of the shear
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response of the fluid.6 There are extra components such as viscoelastic effects which contribute to
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the apparent viscosity. This effect has been extensively investigated for viscoelastic polymer flow
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through porous media.18 Furthermore these viscoelastic contributions have been investigated in
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flow through converging/diverging geometries19,20 and flow past confined cylinders.10 This work
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concluded that at high flow rate the viscoelastic effect becomes dominant over the shear response
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which enhances the apparent viscosity.
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Previous work on VES fluids for conformance control showed that it is indeed possible to
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utilize them to partially overcome reservoir heterogeneity. The surfactant cetyl ammonium
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bromide (CTAB) in combination with an organic salt sodium salicylate (NaSal) shows the
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desired behavior in porous flow.6 Hydrocarbons partially destroy worm-like micelles although
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this can be overcome by increasing concentrations somewhat.21 The reservoir volumes where we
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wish to increase viscosity i.e. those already swept highly permeable sections, are where the oil
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content is already reduced to residual levels. These previous tests were performed in idealized
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porous media made of sintered glass beads. The behavior of VES fluids for oil displacement in
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real reservoir rock has not been investigated. In particular, as mentioned at the beginning of this
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section, the surfactants have two effects – the desired selective viscous enhancement as well as
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the more traditional EOR changes in interface tension. This means that the different wetting
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responses of carbonates and sandstones are an issue and this is one of the key aspects of the
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current study
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3. Experiments
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3.1
Materials
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Two different types of porous rock cores are used to simulate a heterogeneous reservoir;
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sandstone and carbonate. Sandstone rock is typically water-wet whereas carbonate rock is usually
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oil-wet.22 The petrochemical properties of the different cores can be found in table 1. For both
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sandstone and carbonate rock there are two cores with varying permeability to represent a
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heterogeneous reservoir. The chemicals used for the experiments are a cationic surfactant cetyl tri-methyl
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ammonium bromide (CTAB, ) and an organic salt sodium salicylate (NaSal,
!)
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mentioned above. These were purchased from Sigma Aldrich at a purity of >99.0% and >99.5%
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respectively. For two solutions synthetic seawater is used as a base fluid which was synthesized
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by dissolving 3wt% sodium chloride (NaCl) in demineralized water. We denote a solution
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containing " mM CTAB and # mM NaSal as an “"⁄#” solution. The following concentrations
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were used: 2/2 and 6/4 in brine as well as 30/10 in demineralized water. The viscous response
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and reproducibility of the different surfactant concentration VES fluids are tested in an Anton
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Paar MCR 302 rheometer with a double gap measurement system. For two-phase experiments we
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used decane ( ) with a purity of >99.0% purchased from Sigma Aldrich. The viscosity of
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decane at room temperature is lower than the viscosity of the displacing phase. This reduces the
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effect of viscous fingering and allows us to specifically target the effect of preferential flow.
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3.2
Parallel core setup
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The viscosifying potential of the VES fluids in a heterogeneous reservoir is simulated by
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placing two cores of different permeability parallel to each other (figure 2). The reservoir rock
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cores are placed inside the core-holder with a rubber sleeve wrapped around each. The sleeve is
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radially pressurized to 6 bar by compressed air. This forces a tight seal between the rubber sleeve 7 ACS Paragon Plus Environment
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and the cores to ensure axial flow. The core-holders are positioned vertically in a controlled
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temperature chamber to drive air out at the top and achieve maximum fluid saturation. VES fluid
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is pumped through both cores by a dual piston QX 6000 HC Quizix pump (pump 1). The pressure
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drop is measured by differential pressure transducers of type Rosemount 3051CD 4 (accuracy
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0.1%). A second pump is used to saturate the cores with decane before performing a
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displacement experiment. The effluent from both cores exits to fractional collectors.
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Two distinct types of experiments can be performed using this setup. The first experiment
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is performed to test the non-Newtonian response during single-phase flow of VES through
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sandstone and carbonate cores of different permeability. During these experiments the cores are
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tested individually. The second test is a parallel two-phase (VES and decane) displacement
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experiment to test the recovery efficiency of the heterogeneous system.
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Prior to each experiment the cores are placed in an oven at 250 ºC to ensure all fluids
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inside the cores from previous experiments are evaporated. After the cores have cooled down
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they are placed in the rubbers sleeves and positioned inside the core holder. The cores are then
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flushed with CO to displace the air trapped inside the pores. Next, pump 1 saturates both cores
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with brine. Then the brine permeability of the cores is determined by measuring the pressure drop
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at 5 different flow rates and applying Darcy’s law. This is done before each experiment to ensure
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the conditions have not changed due to prior experiments.
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3.2.1
Single phase flow
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The two cores represent two contrasting pathways in a reservoir between injector and
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producer wells. One pathway is low resistance (high permeability) and the other is high resistance
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(low permeability). For the single phase experiments, both cores are fully saturated with VES
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without any hydrocarbon present. The pump is set to stepwise increase flow rate through each
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core separately. At every point the resistance factor is calculated and the results of cores of
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different permeability are compared (equation 1).
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3.2.2
Hydrocarbon displacement
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Prior to the displacement experiment, the brine filled cores are saturated with decane
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injected from the top. During this saturation process effluent is collected and the displaced
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volume of brine is a measure for the original oil in place (OOIP) inside both cores – denoted by
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'(()* . After decane saturation the cores are left to soak for a period of 12 hours. Fluid is injected
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into both cores simultaneously at identical pressure and decane is produced – a volume '(+, . The
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recovery at any moment during the displacement process is:
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/01
-. =
(2)
//23
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-. is the combined hydrocarbon recovery from both cores. After break through, injected fluid
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leaves the core as effluent. This effluent is primarily injected brine and no more oil is displaced.
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Since flow rate will be highest in the high permeability core, this core will reach
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breakthrough first. Note that the flow through this core continues until both cores have been fully
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flushed. The injected fluid in the high permeability core does not contribute to the oil
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displacement. The amount of injected fluid at any moment is represented by '45 . The volumes of
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injection fluid used are often non-dimensionalised to the core pore volume 6'7,8 to give the
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pore volumes of injected fluid
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9'45 = φ:;<
(3)
=>1?
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For this analysis 1 pore volume is defined as the combined void space of both cores. The results
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are used to analyze the effectiveness of the VES fluids compared to a brine displacement. This is
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particularly relevant when breakthrough is reached in both cores– we define this point as 9' ∗ .
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Effective sweep of the parallel system of both cores is characterized by low values for 9' ∗ . 9 ACS Paragon Plus Environment
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4. Results and discussion
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4.1 Single phase calibration
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The resistance factor (equation 1) of the 2/2 solution flowing through contrasting
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permeability sandstone and carbonate cores is shown in figure 3. The 30 mD sandstone core has a
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nearly constant resistance factor of = 2 (figure 3a). In this core the flow rate does not become
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high enough for the VES fluid to become significantly viscoelastic. The 1600 mD sandstone core
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on the other hand shows a clear increase in resistance to flow with pressure gradient caused by
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the induced viscoelasticity of the fluid in that higher permeability rock sample. This leads to a
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reduction in flow rate. For example, at 0.5 bar/m the flow rate of VES in the high permeability
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core is reduced by = 10 compared to brine. By contrast, the flow of VES in the low
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permeability core at 0.5 bar/m is reduced by only = 2 times compared to brine. Flow is thus
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reduced more in the high permeability core decreasing the difference between the cores and
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creating a more uniform flow profile.
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The carbonate cores in single phase show similar results as the sandstone cores (figure
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3b). Here the difference in permeability (20 mD vs 130 mD) is less. However there is still a
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significant difference in resistance factor between the cores. At equal pressure gradient the
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resistance factor in the 130 mD carbonate core is higher than in the 20 mD carbonate core. This
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again leads to more flow reduction in the high permeability core which reduces the inequality in
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flow rate between the cores. However we shall see below that differential wetting interferes with
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this apparently favourable effect in carbonates. Note that the 130 mD carbonate core has a higher
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resistance factor than the 1600 mD sandstone core. This can be attributed to differences in the
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porosity of the cores. Carbonates have a wider range of pore sizes which increase the chance of
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flow within the viscoelastic response region. That along with vugs and dead-end cavities lead to a
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The 2/2 solution clearly shows selective retardation in high permeability zones in single
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phase. When applied to hydrocarbon displacement, previous work has shown that the
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concentration of components needs to be increased in order to overcome lipophilic absorption
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effects.7 6/4 solutions remained viscoelastic even when part of the surfactant molecules were
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adsorbed into the hydrocarbon phase.7 Under only shear (in Couette flow) this solution is mostly
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shear-thinning as shown in figure 4. By contrast, a 30/10 solution shows a more pronounced non-
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monotonic initially shear-thickening and then shear thinning behavior. These solutions then form
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the basis for subsequent two phase studies.
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4.2 Hydrocarbon recovery
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4.2.1 Sandstone
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Figure 5 shows the hydrocarbon recovery -. as a function of injected pore volumes for
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high and low permeability cores. For the brine base fluid case (grey diamonds), initially there is a
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rapid increase in recovery due to the decane displaced from the high permeability core. The
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recovery rate then drops significantly since the high permeability core is depleted and no longer
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contributes to the total recovery. From this point on decane is predominantly recovered from the
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low permeability core at a low rate. The high permeability core now serves as a thief zone
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through which displacing fluid is lost. After injecting 10.3 PV of brine, breakthrough is reached
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∗ in the low permeability core and both cores are fully flushed (i.e. 9'D,48 = 10.3).
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Turning to the VES solutions, the 6/4 solution (open triangles) shows an improved
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recovery curve compared to brine. The initial recovery curve is very similar since decane is
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mainly displaced from the high permeability core. After breakthrough has occurred in the high
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permeability core the local flow resistance gradually increases. This reduces fluid flow through
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the high permeability core and thus less fluid is lost while flushing the low permeability core. The
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30/10 solution shows an even better recovery curve. This is due to the increased surfactant 11 ACS Paragon Plus Environment
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concentration which results in faster formation of worm-like micelles in the presence of
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hydrocarbons. As fig. 5 shows, the 30/10 solution required the least amount of PV to be fully
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∗ ∗ ∗ flushed (i.e. 9'!/ < 9'I/ < 9'D,48 ).
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Figure 6a shows that initially the resistance factor of the 6/4 solution is approximately
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equal in both high and low permeability core. After enough VES is injected the resistance factor
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in the high permeability core increases and selectively reduces the local flow rate. This effect is
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gradual due to the adsorption of surfactants into the decane which become saturated when more
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fluid is injected. We quantify this by α, the change of resistance factor per unit of injected pore
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volume. Assigning the superscript hi and lo to high and low permeability rock respectively, we
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note that at least in the beginning α !/ > α!/ ≈ αI/ ≈ αI/
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There is reduced impact of hydrocarbon interaction for the 30/10 solution. More chemical
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can be sacrificed in hydrocarbon interaction while leaving sufficient concentration to retain the
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selective viscoelastic effect in high permeability rock. There are two effects here: first the high
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permeability rock has reduced oil content due to prior flooding and secondly, there are more
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surfactant molecules available to be “sacrificed” by hydrocarbon interaction while leaving
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enough over to provide the flow induced viscoelastic effect.
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4.2.2 Carbonate
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Figure 7 shows the results of the displacement experiments in carbonate cores. We
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compare these results with the sandstone core results (figure 5). Initial recovery rate is high
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which is caused by decane displacement from the high permeability core. In contrast to sandstone
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∗ cores, brine flooding requires the least amount of fluid to reach breakthrough. (9'D,48
