Review of Surfactant Enhanced Oil Recovery in Carbonate Reservoirs
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[a] Department of Petroleum Engineering， Texas Tech University， Lubbock， USA.
*Corresponding auhtor.
Received 1 January 2013； accepted 14 March 2013
Abstract
About half of proven conventional oil reserves are in carbonate reservoirs. Due to complex structures， formation heterogeneities and oil-wet/mixed wet conditions， etc.， the oil recovery factor in carbonate reservoirs is very low. There is increasing interest in improve oil recovery using surfactants， as the surfactant EOR has the potential after other EOR methods have been tried.
This paper reviews the models of wettability alteration using surfactants and upscaling models related to oil recovery in carbonate reservoirs. Chemicals used in carbonate reservoirs are reviewed. The field cases where surfactants were used to stimulate oil recovery are analyzed.
Key words： enhanced oil recovery； carbonate reservoirs； Wettability alteration； Chemical EOR
Sheng， J. J. （2013）. Review of Surfactant Enhanced Oil Recovery in Carbonate Reservoirs. Advances in Petroleum Exploration and Development， 6（1）， -0. Available from： URL： http：///index.php/aped/article/view/j.aped.1925543820130601.1582
DOI： http：///10.3968/j.aped.1925543820130601.1582
NOMENCLATURE
c ratio of the gravity force to the capillary force， dimensionless
Cpc capillary pressure end-point in Equation 4， m/t2
Csurf equilibrium surfactant concentration， m/L3， vol.% or mol/L pore volume
adsorbed surfactant concentration， m/L3， vol.% or mol/L pore volume
g acceleration of gravity， L/ t2
k permeability， L2， md or m2
kr relative permeability， fraction or %
Lc characteristic length， L， m or ft
Me* effective mobility at the displacement front （Swf）， L3t/m， md/cP
n exponent to define a relative permeability
NT trapping number， dimensionless
Pc capillary pressure， m/Lt2， Pa or psi
Pc* capillary pressure at the displacement front， m/Lt2， Pa or psi
R recovery factor （total oil produced/the original oil in place）， fraction or %
R* normalized recovery factor
S saturation， fraction or %
normalized saturation， fraction or %
Swf water saturation at the displacement front， fraction or %
Swi initial water saturation， fraction or %
t time， t， s or days
tD dimensionless time
tg gravity reference time， t， s or days
T trapping parameter， dimensionless
Greek symbols
Δ operator that refers to a discrete change
Φ porosity， fraction or %
ρ density， m/L3， g/cm3
μ viscosity， m/Lt， mPa?s （cP）
σ interfacial tension， m/t2， mN/m
θ contact angle， degree
w interpolation scaling factor for pc and kr， dimensionless
Superscript
n end-point
high at a high trapping number
low at a low trapping number
ow oil-wet
ww water-wet
Subscript
j phase j
j’ conjugate phase of phase j
r residual
INTRODUCTION
Currently， more than 85% of world energy consumption comes from fossil fuels and the World Energy Outlook shows that energy demand could rise by 53% between now and 2030[1]. Although most energy experts agree that the world’s energy resources are adequate to meet this projected growth， more reserves will be needed. This means the petroleum industry will have to increase recovery factors significantly from all types of reservoirs. Schlumberger Market Analysis 2007 shows that more than 60% of the world’s oil and 40% of the world’s gas reserves are held in carbonates[2]. BP Statistical Review 2007 shows that the Middle East has 61% of the world’s proved conventional oil reserves[3]； approximately 70% of these reserves are in carbonate reservoirs[2]. The Middle East also has 41.3% of the world’s proved gas reserves[3]； 90% of these gas reserves lie in carbonate reservoirs[2]. It is clear that the relative importance of carbonate reservoirs compared with other types of reserves will increase dramatically during the first half of the 21st century. The world has 3，000 billion barrels of remaining oil and 3，000 trillion SCF gas in place in carbonates. However， due to complex structures， formation heterogeneities and oil-wet/mixed wet conditions， etc.， the oil recovery factor in carbonate reservoirs is very low， probably below 35% on the average， and it is lower than that in sandstone reservoirs. Therefore， there is increasing interest to improve hydrocarbon recovery from carbonate reservoirs， as we are facing challenges to make up depleted reserves.
Although there is a great potential to improve oil recovery in carbonate reservoirs， the research in this area is very limited due to technical and economical challenges. Most of field development schemes in carbonate reservoirs are limited to water flooding and gas flooding with low ultimate recovery factors. A few surfactant-related EOR methods have been tried in carbonate fields， although more polymer flooding projects were carried out before 1990s.
Chemical EOR research in carbonate reservoirs has been focused on using surfactants to change oil-wet to water-wet to enhance water imbibition into matrix blocks. Wettability alteration results in spontaneous imbibition of water into oil containing matrix， thus driving oil out of matrix. These surfactants include cationics， nonionics and anionics. It has been found that anionic function to reduce IFT and associated buoyancy are very important mechanisms[4]. The problem is that such process is slow. Upscaling from laboratory results to field application need more research work to be done. If the process is deemed to be slow， forced imbibition has to be applied. The future research should be on the area to optimize different development schemes and EOR methods in carbonates.
In this paper， we first present the problems with carbonate reservoirs， followed by models of wettability alteration using surfactants. We then discuss the upscaling models related to oil recovery in fractured carbonate reservoirs. Chemicals used in carbonate reservoirs are reviewed. Finally we analyzed several field cases using surfactants to stimulate oil recovery.
1. PROBLEMS IN CARBONATE RESERVOIRS
The average recovery factor in both sandstone and carbonate reservoirs is about 35%. The average recovery factor in sandstone reservoirs is higher than in carbonates. Therefore， the average recovery factor in carbonate reservoirs is below 35%. Carbonate reservoirs present a number of specific characteristics posing complex challenges in reservoir characterization， production and management. Carbonate rocks typically have a complex texture and pore network resulting from their depositional history and later diagenesis.
Heterogeneity may exist at all scales-in pores， grains and textures. The porosities of carbonate rocks can be grouped into three types： connected porosity which is the porosity between the carbonate grains， vugs which are unconnected pores resulting from the dissolution of calcite by water during diagenesis， and fracture porosity which is caused by stresses following deposition. Diagenesis can create stylolite structures which form horizontal flow barriers， sometimes extending over kilometers within the reservoir， having a dramatic effect on field performance. Fractures can be responsible for water breakthrough， gas coning and drilling problems such as heavy mud losses and stuck pipe. Together， these three forms of porosities create a very complex path for fluids and directly affect well productivity.
In addition to the variations in porosity， wettability is a further heterogeneous characteristic in carbonates. The great majority of sandstone reservoirs are probably water-wet. However， the aging of carbonate rocks containing water and oil turns initially water-wet rocks into mixed-wet or even oil-wet. This means that oil can adhere to the surface of carbonate rock and it is therefore harder to produce. Most carbonate reservoirs are believed to be mixed wet or oil-wet.
2. MODELS OF WETTABILITY ALTERATION USING SURFACTANTS
One important mechanism using surfactants in carbonate reservoirs is to change wettability from oil-wet to more water-wet. Wettability alteration has been formulated with surfactant adsorption， and relative permeabilities and capillary curves are modified based on the degree of wettability alteration. Delshad et al.[5] used this parameter to modify capillary curve and relative permeability curves：
where w is the interpolation scaling factor， and Csurf represent the adsorbed and equilibrium concentrations of surfactant， respectively. The capillary curve and relative permeability curve are then modified：
where the superscript ww and ow denote water-wet and oil-wet conditions， kr is the relative permeability， and pc is the capillary pressure. These equations are proposed based on the assumption that surfactant adsorption on calcite rock surfaces increases water-wetness， although this assumption may not be generally valid. The capillary pressure pc is a scaled with the interfacial tension as follows：
where takes also into account the effect of permeability and porosity using the Leverett-J function[6]， ? is the porosity and k is permeability， σ is the interfacial tension， S is the saturation at the water-wet condition， the subscript j and j’ denote the phase j and the conjugate phase j’， respectively， and Epc is the exponent for capillary pressure. The above model is implemented in UTCHEM version 9.95[7]. In ECLIPSE 2009 version[8]， a table of w versus surfactant adsorption is input.
Another model explicitly including wetting angle effect was proposed by Adibhatla et al.[9]. In their model， a simple interpolation technique is used to consider the wettability effect on residual saturations and trapping numbers：
In the above equations， the superscript “low” refers to the parameter value at a low trapping number. To use the above equations， the residual saturation values of and Tj for a pair of base phases are needed. These base phases are represented with subscripts “b1” and “b2”. Without losing the generality， it is assumed the contact angle of the base phase b1 before wettability alteration is θ0， and the contact angle of the base phase b2 is （π-θ0）. Note that oil and aqueous phases are not distinguished （a dummy phase j is used）. The residual saturation at a low trapping number， ， and the trapping parameter， Tj， for phase j are calculated from the above equations， respectively.
Once and Tj at the altered contact angle q are obtained from the above equations， the residual saturation at a different trapping number NT is calculated by
where Srj is the residual saturation of phase j at the trapping number NT. The superscript “high” refers to the parameter value at a high trapping number. The trapping number is the capillary number including gravity effect which is discussed in detail in Sheng[10]. In this equation， is typically 0. Given the values of and Tj （the latter can be obtained by fitting experimental data）， Equation 7 yields the desaturation curve （Srj versus NT） that is similar to the capillary desaturation curve （CDC）.
Before we present an end-point kr of a phase at a trapping number， we need to discuss the relationship between the end-point kr and the conjugate residual saturation first. According to Delshad et al.[11]，
where denotes the end point relative permeability of phase j， the superscript low and high correspond to low and high capillary （trapping） numbers， respectively， and the subscript j’ denotes the conjugate phase of phase j. In Equation 8， it is assumed that the end-point relative permeability enhancements （and the later exponent decreases） are caused by the residual-saturation reduction of the conjugate phase as a function of the trapping number. However， the residual saturation of the conjugate phase may not be a good predictor for the end-point relative permeabilities and exponents， especially when wettability alteration is involved[12-15].
Combining Equations 7 and 8， we have
To derive an end-point relative permeability， ， at a trapping number NT， we have to consider two factors. One is the effect of trapping number； the other is the effect of wettability alteration. According to Equation 9， the effect of trapping number on at NT can be considered using the following equation：
where ， ，correspond to the end point relative permeabilities at NT， NT0 and a very high trapping number.
To include the effect of wettability， we may have
Here it is assumed that we have the relative permeability curves measured at a certain trapping number NT0 for a pair of base phases with the contact angle θ0 for the phase b1 and π-θ0 for the phase b2. Putting Equation 11 into Equation 10， we have the relative permeability curves with the trapping number NT and the contact angle θ：
Similarly， the exponents of relative permeabilities are
Equations 12 and 13 are just conceptual models that qualitatively capture the typical trends observed about the effects of trapping number and wettability on relative permeabilities. Note Tj’ is the trapping parameter of the conjugate phase of phase j and its value is evaluated with Equation 6 using the contact angle π-θ， where θ is the contact angle of phase j. Again， we assume that the end point value， ， and the exponent nj， for the phase j are correlated to the residual saturation of the conjugate phase j’ through linear interpolation. And the Brooks-Corey model is used to describe the relative permeability
The effects of IFT and contact angle on capillary pressure are described with the following equation：
where pc and pc0 are the capillary pressures， and σ and σ0 are the interfacial tension between oil and aqueous phases at the contact angle θ and θ0， respectively.
3. UPSCALING
Either surfactant diffusion process or surfactant induced gravity drainage process through wettability alteration and IFT reduction is slow. Therefore， upscaling the laboratory-scale to the field scale becomes very important. Since the pioneering work by Mattax and Kyte[16] who scaled capillary forced imbibition under specific conditions， several modified formulas have been proposed. Basically， the scaling group for capillary imbibitions is defined in terms of the dimensionless time defined as
where k is the rock permeability， ? is the porosity， σ is the interfacial tension between the wetting and the nonwetting phase， ? is the viscosity， t is the actual time， and Lc is the characteristic length. In the above scaling group， different authors defined ? and Lc differently[16-18]. Although they used different equations to define these parameters， they all used the squared characteristic length. In other words， the imibibition rate， thus recovery rate and total recovery， is inversely proportional to the squared characteristic length. Zhang et al.[19] verified Equation 17 in different core dimensions experimentally.
Cuiec et al.[20] performed experiments in low permeability chalk samples at high IFT and proposed a reference time including the gravity force as the ratio of viscous to gravity forces as
where tg is the gravity reference time， μo is the oil viscosity， and Δρ is the density difference between water and oil. Sheng[4] upscaled a base simulation model into several models by increasing the each dimension size by 2， 5 and 10 times using UTCHEM （version 9.95）. The model volumes are increased by 2， 5 and 10 times along each side. According to Equation 18， if we only change the model sizes， the only variable is Lc. Thus we calculate the normalized time by the real time divided by 2 in the case of “Enlarged by 2x2x2”， and similarly in the other cases. The results are shown in Figure 1. It shows that the curves of oil recovery factor versus the normalized time for the models of different sizes almost overlap each other. This indicates that the gravity is the dominant mechanism.
Note that corresponding to Equation 18， the dimensionless time can be defined as
To reduce anionic surfactant adsorption on carbonate rock surfaces， Hirasaki and Zhang[27] injected Na2CO2 with surfactants. The mechanism is that CO32- and HCO3- change the rock surface to negative surface. The role of anionic surfactants was to reduce the IFT between oil and brine. Once the IFT is reduced， the gravity drive can be enhanced. Gravity plays the role in oil mobilization. For the gravity effect to function， IFT must be reduced to lower capillary pressure so that oil drops can move upwards from the matrix.
Hirasaki and Zhang[27] also explained how adding Na2CO3 change wettability of carbonate rock surfaces. The zeta potential of the crude oil they used was negative for pH greater than 3. This is because of the dissociation of the naphthenic acids in the crude oil with increasing pH. The surface of calcite was positive for pH less than 9 when the only electrolytes were 0.02 M NaCl using NaOH or HCl to adjust pH. The opposite charge between the oil/brine and mineral/brine interfaces results in an electrostatic attraction between the two interfaces， which tends to collapse the brine film and bring the oil in direct contact with the mineral surface. Thus， this system can be expected to be nonwater-wet around neutral pH. However， the zeta potential of calcite was negative even to a neutral pH when the brine was 0.1 N Na2CO3/NaHCO3 using HCl to adjust pH. This is because the potential determining ions for the calcite surface are Ca2+， CO32- and HCO3-. An excess of the carbonate/bicarbonate anions makes the surface negatively charged. If both the crude oil/brine and brine/ calcite interfaces are negatively charged， there will be an electrical repulsion between the two surfaces， which tends to stabilize the brine film between the two surfaces. Therefore， a system with carbonate/bicarbonate ions may be expected to have a preference to be water-wet， compared to that in the absence of carbonate ions.
Xie et al.[28] compared the spontaneous imbibition rates using nonionics poly-oxyethylene alcohol （POA） and cationics （CAC）. Their results show that the additional recovery from POA was higher and faster with respect to the scaled time than that from CAC. The IFT of POA solution was 19 times higher than of CAC solution （5.7 versus 0.3 mN/m）. This observation indicates that， ideally， the wettability should be changed to some optimal water-wet condition with respect to rate and extent of recovery while keeping the IFT relatively high for imbibition.
The surfactant used in the Yates pilot was 0.3-0.4% nonionic ethoxy alcohol （Shell 91-8） and 0.35% Stepan CS-460 anionic ethoxy sulfate that were well above the critical micelle concentration （CMC） levels. The surfactant solutions injected were prepared with produced water in the concentrations of 3，100 to 3，880 ppm. The field results were reported positive， as evidenced by some pilot wells showing an increase in oil production over 30 bbl per day[38].
6.3 The Cottonwood Creek Field in Wyoming
The Cottonwood Creek field in the Bighom Basin of Wyoming is a dolomitic class II reservoir. The class II reservoirs have low matrix porosities and permeabilities. Oil was produced from the dolomitic Phosphoria formation. The reservoir thickness varied from 20 to 100 ft， and the average porosity and permeability were 10% and 16 md， respectively. The reservoir produced a sour crude oil of 27 oAPI.
Single-well surfactant stimulation treatments were initiated in Cottonwood Creek in August 1999. 500 to 1，500 bbl of a surfactant solution slug were injected， depending on the perforated interval. Typically， the injection period lasted 3 days with a one-week shut-in period （soak time）. Surfactant solutions were prepared using the nonionic POA at a concentration of 750 ppm， almost twice the CMC. Initial well treatments used an acid cleanup with HCl （15%） to remove iron sulfide （FeS） from the wellbore to avoid and/or reduce surfactant adsorption. However， production results were not encouraging. Therefore， acid pretreatment was eliminated later and surfactant concentration was increased of up to 1，500 ppm （to allow for potential losses by adsorption to FeS） in subsequent surfactant stimulations[28，39].
Single-well surfactant soak treatments were made at 23 wells. The general trend was that the oil recovery was increased. However， this increase is not significant. The problem was that 70% of the treated wells failed.
Oil recovery increase in Cottonwood Creek was believed to be due to wettability alteration to less oil-wet and not to a reduction in IFT， because the IFT of POA solutions with oil indicated 5.7 dynes/cm at ambient temperature. The minimum amount of surfactant used for a successful treatment was 60 lbm/ft of perforated internal on the basis of the analysis of 23 well treatments reported in the literature[28，39].
6.4 The Baturaja Formation in the Semoga Field in Indonesia
The Semoga field was discovered in 1996 and is located in the Rimau block in the South Sumatera. The field consists of three prospect formations： Telisa formation （tight sandstone）， Baturaja formation （carbonate） and Talang Akar formation （sandstone）. The Baturaja formation （BRF） is a carbonate reservoir with a proven volume of about 317，856 acre-ft （77 ft net pay）. There were 127 wells： 82 producers， 28 injectors， and 17 shut-in wells.
The production began in 1997 and oil production peaked at 36，200 BOPD in November 2001. Since then the production has declined owing to rising water cut. The average water cut before the surfactant stimulation was 86%， and some wells above 95% or even 100%. A laboratory study showed that the Baturaja formation was oil-wet. Huff and Puff surfactant stimulation was studied for this formation.
In this project， the surfactant was soaked for 7 days to allow a reaction with the hydrocarbon. The radial penetration designed for Well X-1 and Well X-2 was about 21 ft. The injection consisted of three steps：
（1） Preflush. The purpose of the pre-flush was to displace the reservoir brine which contained potassium， sodium， calcium and magnesium ions in the near-wellbore area， therefore avoiding adverse interactions with the chemical solution. The other purpose was to adjust reservoir salinity to favorable conditions for the surfactant. 100 bbls of produced water was injected in to each well.
（2） Main-flush. 9 bbls of surfactant and 451 bbls of water were injected in to Well X-1； and 9 bbls of surfactant and 536 bbls of water were injected in to Well X-2.
（3） Post-flush. In this phase the formation water was injected to displace the rest of the surfactant away from the wellbores at the end of stimulation. In the post-flush， 3 bbls of surfactant and 127 bbls of water were injected in to Well X-1； and 0.65 bbls of surfactant and 43.35 bbls of water were injected in to Well X-2.
This surfactant stimulation decreased water cut by about 8%， with an increased cumulative oil production of about 5，800 bbls over a period of three months. An extended study was proposed to further investigate the mechanisms[40].
6.5 Cretaceous Upper Edwards Reservoir （Central Texas）
A laboratory study was conducted to study the feasibility of ASP in the Cretaceous Upper Edwards reservoir， located in Central Texas[29]. The field was discovered in 1922. Over 950 development wells had been drilled. The water cut was 99%. The reservoir was preferentially oil-wet. The average permeability was 75 md. The formation water salinity was low （produced TDS = 12，000 ppm）. There was no anhydrate or gypsium. The reservoir temperature was 42 oC， the acid number was 0.34， and the crude oil viscosity was 3 cP. The ASP formula selected was：
0.4-0.5% Sodium tripolyphosphate
2% sodium carbonate
0.2-0.5% Petrostep B100
0.12% Pusher 700E
The injection scheme was： 0.1PV fresh water， 0.1 PV ASP， 0.2 PV polymer. The ASP flood recovered approximately 45% of the residual oil after waterflooding. No field trial was reported.
7. CONCLUDING REMARKS
Field application of injecting surfactants in carbonate reservoirs to stimulate oil recovery has been limited to only a few field cases. Field results in general showed positive response to surfactant injection. Surfactant injection is believed to change wettability from oil-wet or more water-wet and to reduce IFT. It is assumed that the wettability alteration is caused by surfactant adsorption on carbonate rock surfaces. The EOR mechanisms are related to capillary imbibitions and gravity drive enhanced by surfactant injection. Capillary imbibitions and gravity drive could be slow processes. Therefore， upscaling from laboratory results to field- scale application is important. Several upscaling models have been proposed. These models and even the drive mechanisms need more research work and field data for validation.
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