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ASP flood of a viscous oil in a carbonate rock
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ASP flood of a viscous oil in a carbonate rock
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Krishna Panthi, Himanshu Sharma, Kishore K. Mohanty ⇑
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The University of Texas at Austin, United States
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h i g h l i g h t s An ASP formulation was developed that gives ultralow IFT with a viscous oil.
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The alkali reduces anionic surfactant adsorption on dolomite without calcite precipitation.
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93–95% of the viscous oil was recovered in core floods.
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a r t i c l e 1 3 8 3 19 20 21 22 23 24 25 26 27 28 29 30 31 32
i n f o
Article history: Received 17 July 2015 Received in revised form 25 September 2015 Accepted 27 September 2015 Available online xxxx Keywords: Viscous oil Sodium metaborate Carbonate reservoir ASP flood Enhanced oil recovery Simulation
a b s t r a c t The goal of this work is to develop an alkaline–surfactant–polymer (ASP) formulation for a viscous oil (105 cP at the reservoir temperature) and compare secondary and tertiary ASP floods. Phase behavior studies were performed to find an ultralow interfacial tension (IFT) ASP formulation for the viscous oil. Static surfactant adsorption experiments were performed to compare the effectiveness of different alkalis in reducing adsorption. The surfactant formulation was tested with an outcrop vuggy dolomite core in both tertiary and secondary modes. Lab coreflood results were modeled in UTCHEM which used EQBATCH to model sodium metaborate geochemical reactions in a carbonate rock. Sodium carbonate and sodium metaborate were both found to be equally effective in reducing surfactant adsorption on crushed dolomite. Waterflood recovered about 47.8% of the oil in place and reduced the oil saturation to 43.8%. The tertiary surfactant flood increased the cumulative oil recovery to 92.7% whereby the oil saturation was reduced to 6.1%. The secondary surfactant flood was even more effective than the tertiary; the oil saturation was reduced to 3.1% and the oil recovery was 95.6% OOIP. Very low surfactant retention was observed in the ASP corefloods. UTCHEM simulations showed a reasonable match with the experimental results. Experimental data for surfactant phase behavior, polymer viscosity, and surfactant adsorption were critical in modeling the experimental results. Ó 2015 Published by Elsevier Ltd.
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1. Introduction
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About 60% of the world’s remaining oil is trapped in carbonate reservoirs and some of these oils are viscous [1,2]. Thermal methods are generally used to recover viscous oils from sandstone reservoirs, but mineral dissolution and precipitation can cause severe problems in carbonate reservoirs. Waterflood is not very efficient for viscous oil reservoirs due to viscous fingering leading to poor sweep efficiency. Therefore, chemical methods such as polymer flood or ASP floods are being considered. High molecular weight polymers viscosity the aqueous phase, reduce viscous fingering and bypassing [3]. Surfactants reduce the oil/water interfacial tension greatly so that the viscous forces can overcome the
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⇑ Corresponding author at: Petroleum & Geosystems Engineering, CPE 4.168, The University of Texas at Austin, 200 E. Dean Keaton St., Austin, TX 78712, United States. Tel.: +1 512 471 3077; fax: +1 512 471 9605 E-mail address: [email protected] (K.K. Mohanty).
capillary forces which help mobilize oil [4]. Alkalis form soap with viscous crude oils which are often acidic and also lower the adsorption of anionic surfactants [5–7] by making mineral surfaces negatively charged at a pH greater than 9, thus reducing surfactant requirement. Chemical flooding was developed in the past mainly for sandstone reservoirs with light oil [8–10]. Many ASP field tests have confirmed that the waterflood residual oil can be displaced by the use of alkaline–surfactant–polymer floods [11,12]. Particularly, the ASP field test in the Daqing field recovered about 20% additional OOIP after waterflood [13]. Recent research has led to the development of the surfactant systems which are suitable for carbonate environment [14,15]. Alkaline–surfactant–polymer [16] and alkaline-co-solventpolymer [17] formulations have also been recently developed for a few viscous oils. Most viscous oil reservoirs are not yet water flooded. Thus, it is important to compare the effectiveness of
http://dx.doi.org/10.1016/j.fuel.2015.09.072 0016-2361/Ó 2015 Published by Elsevier Ltd.
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Nomenclature ASP alkaline–surfactant–polymer ASFB alkaline synthetic formation brine cP centipoise CSE effective salinity HPAM hydrolyzed Polyacrylamide HPLC high performance liquid chromatography IFT interfacial tension IBA5EO isobutanol pentaethoxy IBA10EO isobutanol decaethoxy Soi initial oil saturation mD millidarcy Oil-ME IFT oil/microemulsion IFT
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secondary ASP processes with tertiary ASP processes. The conventional alkali used for chemical EOR is sodium carbonate (Na2CO3). However, in presence of gypsum, the carbonate ion precipitates as calcium carbonate. Sodium metaborate (NaBO2) may be used as an alkali in such cases as it is shown to tolerate gypsum which is commonly encountered in carbonate reservoirs [18]. NaBO2 gives a high pH (11) for 1000 mg/L concentration, sufficient to react with acidic components of oil and reduce surfactant adsorption in chemical flooding. The monomeric borate ion (B(OH)4 ) provides alkaline buffering at high pH. Further, NaBO2 is found to have less permeability damage and alkalinity loss compared to Na2CO3 when it is mixed with formation brine containing divalent ions [19]. Another important aspect of this NaBO2 alkali is its low cost, making it feasible to use in large scale oil recovery processes. The goal of this study is to develop an ASP formulation that can be used in a carbonate, viscous (105 cP) oil reservoir at the reservoir temperature of 38 °C. This formulation should be able to minimize surfactant adsorption, mineral dissolution/precipitation and maximize oil recovery. The phase behavior for the reservoir oil was studied with many surfactant combinations, to identify an ultralow IFT formulation, using NaBO2 as alkali so that it can tolerate gypsum or hard formation brine better compared to Na2CO3. Static surfactant adsorption experiments were performed with NaBO2 to compare with Na2CO3, in terms of reducing surfactant adsorption on a dolomite. The rheology of surfactant solution with and without polymer was measured. Then core floods were conducted in secondary and tertiary modes. The core floods were simulated by the mechanistic simulator, UTCHEM.
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2. Methodology
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2.1. Chemicals
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Commonly available and inexpensive chemicals were used in the surfactant formulation. Propoxy Sulfates (surfactants A, B, C) and an Internal Olefin Sulfonate (surfactant D) were obtained from Stepan. Both the surfactants A and B are tridecyl alcohol propoxy sulfates (TDAxPOSO4). Surfactant A has a larger number of propoxy groups than the surfactant B. Surfactant C is an alkyl propyl sulfate (xCyPOSO4). Surfactant D is an internal olefin sulfonate (xCIOS). Decaethoxy Isobutanol (IBA-10EO) and Pentaethoxy Isobutanol (IBA-5EO) were obtained from Dr. Gary Pope’s laboratory at the University of Texas at Austin. Triethylene glycol monobutyl ether (TEGBE) was obtained from Fisher Scientific. Polymer HPAM3630 was obtained from SNF. Its molecular weight was about 20 106 daltons and the degree of hydrolysis was 25–30%. NaBO24H2O was used as the alkali. The injection brine composition was softened sea water which was approximated by 30,700 ppm sodium chloride (NaCl) and 4800 ppm sodium sulfate (Na2SO4). The stock
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OOIP original oil in place KOH potassium hydroxide PV pore volume NaCl sodium chloride Na2CO3 sodium carbonate Na2SO4 sodium sulfate NaBO24H2O sodium metaborate tetrahydrate SFB synthetic formation brine TEGBE triethylene glycol monobutyl ether THF tetrahydrofuran WOR water to oil ratio
tank oil from the reservoir was highly viscous (800 cP), but the viscosity of live oil was about 105 cP; so the stock tank oil was diluted with decalin to get the viscosity of 105 cP at the reservoir temperature. The total acid number of the oil is 1.26 mg KOH (potassium hydroxide) per gm of oil.
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2.2. Phase behavior
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Surfactant phase behavior experiments were performed to identify a surfactant formulation which gives ultralow IFT with the oil and is aqueous stable at the optimum salinity. Aqueous solutions were prepared with 1 wt% surfactant (or mixture of two surfactants) mixed with the injection brine along with co-solvent and alkali. The alkali concentration was varied systematically (in a series of pipettes) keeping the other parameters fixed. Oil and aqueous solutions were mixed in appropriate ratios and the samples were equilibrated at the reservoir temperature and their phase volumes were observed. The solubilization of the oil and water in the microemulsion phases was calculated from the phase volumes. The interfacial tension was estimated from the Huh equation [20]. The phase behavior was studied as a function of waterto-oil ratio (WOR). Similarly, only aqueous solutions were prepared and kept at reservoir temperature to obtain the aqueous stability limits of surfactant formulations. The viscosity was measured at shear rates ranging from 1 to 100 s1.
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2.3. Static surfactant adsorption
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A Silurian dolomite core was crushed to 140–200 mesh size and carefully washed with DI water to remove impurities. The specific surface area of these samples was found to be about 0.4 m2/g by BET measurement. The surfactant combination which gave good phase behavior with oil was used to perform static adsorption experiment. Liquid samples were prepared by carefully adding required amounts of brine, surfactant and alkali. Static surfactant adsorption samples were prepared in glass vials by keeping the solid to liquid ratio equal to 1 (3 g each). The total amount of surfactants was varied from 0.25 wt% to 1 wt%, keeping the alkali concentration fixed. The salinity of the samples was kept close to the optimum salinity obtained from the surfactant phase behavior experiments (i.e., 35,000 ppm injection brine and some added alkali). 5000 ppm of NaBO2 (10,000 ppm NaBO24H2O) and 5000 ppm of Na2CO3 were used as alkalis and 5000 ppm NaCl was used for the base case. The samples were kept at room temperature for about 20 days and mixed gently from time to time. The supernatant solutions were then separated, filtered and analyzed with a high performance liquid chromatograph (HPLC) for the surfactant concentration. A calibration chart was prepared consisting of known surfactant concentrations and the areas obtained
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K. Panthi et al. / Fuel xxx (2015) xxx–xxx Table 1 List of coreflood experiments. Flood #
Core
Condition
Length (cm)
U (%)
k (mD)
Soi (%)
1 2
Dolomite Dolomite
New core Used core (from flood#1)
30.37 30.37
18.85 18.85
80.1 80.1
84 70.3
Table 2 Slug compositions in ASP corefloods. Chemical Surfactant A Surfactant B TEGBE HPAM3630 NaCl Na2SO4 NaBO24H2O
Waterflood brine (ppm)
30,700 4800
Preflush (ppm)
ASP (ppm)
Polymer I (ppm)
Polymer II (ppm)
30,700 4800 10,000
7500 2500 20,000 4500 30,700 4800 10,000
4500 30,700 4800 10,000
4500 30,700 4800
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from HPLC to obtain surfactant concentrations of the unknown samples. Surfactant adsorption was calculated based on the change in surfactant concentrations using the formula given below:
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surfactant adsorption ðmg=g rockÞ ¼ ðC 0 CÞ 10 M surf =M solid
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where C0 = initial surfactant concentration in wt%, C = final surfactant concentration in wt%, Msurf = mass of the liquid solution in grams, and Msolid = mass of solid in grams.
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2.4. Core preparation
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The core was about a foot long out-crop dolomite core and its properties are listed in Table 1. The core had a length of 30.37 cm and a diameter of 3.73 cm. The porosity was 18.8% and the permeability was 80.1 mD for brine. The pore volume was 62.6 cc. The core was first fully saturated with the formation brine and then flooded with the reservoir oil from the top and placed in a vertical orientation in an oven at the reservoir temperature, i.e., 38 °C. It was then flooded with oil at the rate of 1 ft/day from the bottom and the pressure drop was recorded. The core was then flooded with 3 PV of synthetic formation brine from the bottom at the rate of 1 ft/d and then 2 PV of the same brine was injected at the rate of 10 ft/d. The first step represents a waterflood at a typical field rate; the second step is conducted to identify any capillary end effect.
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2.5. ASP coreflood
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The ASP flood consisted of injection of an ASP slug (0.3 PV) followed by a polymer slug I (0.5 PV) at the optimum salinity which is followed by polymer slug II (0.5 PV) at the injection brine salinity which is further followed by just the injection brine for about 3 PV. The surfactant concentration in the ASP slug was
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1 wt%. The ASP Core Flood #1 was conducted in the tertiary mode whereas the ASP Core Flood #2 was in the secondary mode. The slug compositions are given in Table 2. In Core Flood 1, the waterflood was followed by the preflush and tertiary ASP flood. The core was cleaned and prepared for Core Flood 2 in the following manner after Core Flood 1: it was first injected with 2 PV of brine followed by 2 PV of THF, which was further followed by 2 PV of chloroform, followed by 3 PV of methanol, which was further followed by 2 PV of 0.1% sodium thiosulfate and finally flooded with about 10 PV of brine. The core was then flooded with oil and kept in an oven at the reservoir temperature, i.e., 38 °C. This core was then used in Core Flood #2. The second ASP flood was similar to the first ASP flood, but in the secondary mode. 0.3 PV of ASP at the optimum salinity (with 4500 ppm HPAM3630) was injected followed by the brine at the optimum salinity with 4500 ppm HPAM3630. This polymer slug was followed by about 0.5 PV of synthetic injection brine along with 4500 ppm HPAM3630 which was further followed by 3 PV of synthetic injection brine.
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2.6. Simulation
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These coreflood experiments were modeled using the Alkali–Surfactant–Polymer (ASP) module of UTCHEM 2011, the multicomponent, multiphase, compositional chemical flooding simulator developed by Delshad et al. [21] and Mohammadi et al. [22]. The interaction of metaborate with the reservoir rock and the aqueous species was included in these calculations using EQBATCH, the geochemistry module of UTCHEM developed by Bhuyan et al. [23]. The reservoir rock is approximated to be pure dolomite, that is, Calcium and Magnesium were supposed to be present in equal proportions. The acidic content of the crude was represented by a single pseudocomponent HAo as described by deZabala et al. [24].
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Table 3 Phase behavior study. Expt.#
Surfactants & cosolvents
wt% of surfactants & cosolvents
Winsor type/result
1 2 3 4 5 6 7 8 9 10
Surfactant Surfactant Surfactant Surfactant Surfactant Surfactant Surfactant Surfactant Surfactant Surfactant
1% + 1% 0.5% + 0.5% + 1% 1% + 2% 0.5% + 0.5% + 1% 1% + 1% 1% + 1% 0.5% + 0.5% + 1% 0.5% + 0.5% + 1% 0.5% + 0.5% + 2% 0.75% + 0.25% + 2%
Type I, some oil solubilization Type II Type I, some oil solubilization Type II Type I Type I Large oil solubilization but difficult to see type III region Thick type III region, but opt. salinity is 3.5% NaBO24H2O Thick type III region, but opt. salinity is 3.5% NaBO24H2O Thick type III region, opt. salinity at 1% NaBO24H2O
B + IBA10EO C + surfactant D + TEGBE B + IBA10EO C + surfactant D + IBA10EO B + IBA5EO A + IBA5EO A + surfactant B + IBA5EO A + surfactant B + TEGBE A + surfactant B + TEGBE A + surfactant B + TEGBE
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3. Results and discussions
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3.1. Phase behavior
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The different combinations of surfactants and co-solvents tested for suitable phase behavior are summarized in Table 3. The aqueous solutions of surfactant–cosurfactant–cosolvent in synthetic injection brine were mixed in pipettes with oil; the NaBO24H2O concentration in brine was varied for each formulation. The formulation of experiment #10 (0.75% surfactant A and 0.25% surfactant B) showed excellent phase behavior (Table 3) with all three Winsor phases at different concentrations of metaborate and was selected for the core floods. Fig. 1(a) shows the phase behavior of this formulation as a function of the NaBO24H2O concentration (0.25–2.5 wt%) at WOR = 1. At low alkali concentration, there are two phases: the bottom phase is the microemulsion; the top phase is oil (Type I). Three phases (water, microemulsion, and oil) exist at the intermediate alkali concentration (in 5 samples 0.75–1.75%); this is called Type III phase behavior. Two phases (water and microemulsion) exist at the high alkali concentration (Type II). This is the typical oil–water–surfactant phase behavior. Fig. 1(b) shows the water and oil solubilization ratios. The optimal alkali concentration is 1 wt% NaBO24H2O; the solubilization ratio (S⁄) at the optimum is 8. The interfacial tension in this system is estimated from the Huh equation, IFT (mN/m) = 0.3/S⁄2. The lowest IFT is 0.0046 mN/m. This IFT translates to a capillary number of 0.0007 for a water viscosity of 1 cp and a number of 0.07 for a water viscosity of 100 cp (due to inclusion of polymer) at 1 ft/d. This capillary number is adequate for mobilization of oil in porous media, as shown in the corefloods.
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a
0.25% 0.5% 0.75% 1% 1.25% 1.5% 1.75% 2% 2.25% 2.50
b
Fig. 2. Effect of water–oil ratio on phase behavior.
The phase behavior experiments were conducted at several WORs for this formulation. The effect of WOR on the type of phase behavior is shown in Fig. 2. A high WOR corresponds to a small oil% [=100⁄ oil volume/(oil volume + water volume)]; Type III phase behavior shifts to a higher salinity at a smaller oil% and shows a negative slope. This slope shows that the oil is active and has acidic components. A higher WOR corresponds to a lower amount of oil and thus less soap formation. Hence, the soap to synthetic surfactant ratio is lower at a high WOR. The effect of WOR on the phase behavior is important when dealing with acidic oils. 4500 ppm HPAM3630 was added to the brine at the optimal salinity (for WOR = 1). Equal volume of oil was then added to the surfactant–polymer solution. Mixing of oil, brine, surfactant and polymer at the optimal salinity resulted in three phases. Fig. 3 shows the viscosity of the pure oil, the ASP solution, the alkaline polymer solution (HPAM3630 in synthetic injection brine +10,000 ppm NaBO2) and the synthetic injection brine polymer solution. The oil viscosity is independent of the shear rate. The ASP and polymer solutions are shear thinning, but have the viscosity (at 10 s1) similar to that of the oil.
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3.2. Static surfactant adsorption
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The results of the static surfactant adsorption experiment are shown in Fig. 4. The surfactant adsorption is about 1.25 mg/gm of rock in the absence of any alkali. It is reduced by about half on addition of 5000 ppm NaBO2 or Na2CO3. The surfactant adsorption values of samples with Na2CO3 are similar to that with NaBO2, between 0.4 and 0.75 mg/gm. Given the additional benefits of sodium metaborate listed above, it was used in the coreflood experiments.
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S*=1%, *=8
Middle phase
Fig. 1. Phase behavior at 38 °C as a function of 0.25% to 2.25% NaBO24H2O. Each sample also contains 0.75% surfactant A, 0.25% surfactant B, 2% TEGBE in addition to the synthetic injection brine, WOR = 1. (a) Photograph of pipettes and (b) oil and water solubilization ratios.
Fig. 3. Viscosity of diluted oil, ASP solution, alkaline polymer solution, and brine polymer solution.
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Fig. 5b. Pressure drop during water flooding, Core Flood #1.
Fig. 4. Static surfactant adsorption results.
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3.3. Core floods
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Table 1 shows the initial conditions for the corefloods. Two ASP core floods were conducted with the outcrop core. Core Flood #1 is in the tertiary mode whereas Core Flood #2 is in the secondary mode.
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3.3.1. Core Flood 1 This core flood was conducted in the out-crop core with the reservoir dead oil diluted with decalin. The waterflood was followed by an ASP flood. Fig. 5a shows the oil recovery during the water flood. The initial oil saturation was 84%. Waterflood at 1 ft/ d rate reduced the oil saturation to 47% and recovered 43% OOIP in about 3 PV injected. The water injection rate was then increased by 10 times and 2 more PV were injected, whereby the oil saturation was reduced to 45.2%. Then 0.4 PV of preflush (brine at optimum salinity) was injected which further increased the recovery to 47.8%. The preflush was used so that the ASP slug starts at the right salinity. The pressure drop across the core during the coreflood process is shown in Fig. 5b. The pressure drop (at the rate of 1 ft/d) gradually decreased with the recovery of oil and was steady at about 2 psi and then increased to about 9 psi at the higher flow rate and further decreased to about 3 psi during preflush flood at 1 ft/d. The waterflood was followed by 0.3 PV ASP slug which included 0.75% surfactant A, 0.25% surfactant B, 2% TEGBE, 10,000 ppm NaBO24H2O, and 4500 ppm HPAM3630 in addition to the synthetic formation brine. Though the HPAM3630 is a large molecular weight polymer, no injectivity problem was observed in this particular core. After the ASP solution, a slug of 0.5 PV alkaline– polymer solution was injected which included 10,000 ppm
SFB@10 ft/day
5
Preflush
Fig. 6a. Oil recovery during tertiary chemical flooding, Core Flood #1.
NaBO24H2O and 4500 HPAM3630 in the synthetic injection brine. After the alkaline–polymer solution, 0.5 PV of polymer solution (without alkali) was injected which included only 4500 ppm HPAM3630 in the synthetic injection brine and at last only synthetic injection brine (about 3.1 PV) was injected. Fig. 6a shows the tertiary oil recovery during the ASP flood. In the beginning, no oil was produced because the core was at waterflood residual at the start of the surfactant flood. Oil bank broke through at about 0.3 PV injected. Oil cut increased to 78% for a short time and then decreased. Most of the oil was produced by 1.2 PV injection (6.6 PV including the waterflood); the residual oil saturation was reduced to 6.1% at the end of flood. Cumulative oil recovery for the waterflood including preflush was 47.8%; but at the end of the ASP flood it increased to 92.7% OOIP. Table 4 summarizes the oil recovery in the corefloods. Fig. 6b shows the pressure drop during the tertiary recovery. The pressure drop started at about 2 psi corresponding to preflush flow, increased to about 10 psi during the ASP injection, because of the high viscosity of the polymeric solution. It further increased to about 12 psi during alkaline polymer injection and further increased to about 23 psi during synthetic brine polymer injection. As the salinity decreases, the polymeric solution viscosity increases for the same polymeric concentration. Eventually the pressure drop fell to about 6 psi during the brine flood at the end. The high pressure drop during the ASP/polymer slug indicates a stable displacement of the oil bank. Fig. 7 shows the salinity of the effluent brine in Core Flood 1; both waterflood and chemical flood effluents are plotted together in this figure. The salinity plot shows that the salinity increases to the optimal salinity during the surfactant slug and then
Fig. 5a. Oil recovery during water flooding, Core Flood #1.
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Table 4 Oil recovery in coreflood experiments. Flood #
Type of Flood
Initial oil saturation (%)
WF oil recovery (%OOIP)
Net recovery (%OOIP)
1 2
ASP in tertiary mode ASP in secondary mode
84 70.3
47.8
92.7 95.6
Fig. 6b. Pressure drop during tertiary chemical flooding, Core Flood #1.
350 351 352 353 354 355 356 357 358 359 360 361 362 363 364 365 366 367 368 369 370 371 372 373 374
decreases. It also shows that there is mixing between the formation brine and the surfactant slug and the optimal salinity is not maintained throughout the surfactant slug. Fig. 8 shows the pH of the effluent brine; both waterflood and ASP flood are plotted together. The pH increases to about 10 when the preflush is injected and maintains the high pH condition throughout the surfactant injection. 3.3.2. Core Flood 2 In Core Flood 2, the ASP flood was done in the same core under the same conditions as Core Flood 1, but in the secondary mode (i.e., without a water flood). The core (after Core Flood #1) was brought to Swi, as described in the methodology section. The core was then flooded with 0.3 pore volume of ASP. It included 0.75% surfactant A, 0.25% surfactant B, 10,000 ppm NaBO24H2O, and 4500 ppm HPAM3630 in addition to the synthetic injection brine. After the ASP solution injection, 0.5 PV of the alkaline–polymer solution was injected which included 10,000 ppm NaBO24H2O and 4500 ppm HPAM3630 in the synthetic injection brine. After the alkaline-polymer solution, 0.5 PV of the polymer solution was injected which included only 4500 ppm HPAM3630 in the synthetic injection brine and, at last, only synthetic injection brine (about 3 PV) was injected. Fig. 9a shows the oil recovery during the secondary ASP flood. Most of the oil was recovered within the first 1.5 PV of injection. The residual oil saturation was reduced to 3.1% at the end of the flood. Cumulative oil recovery for the ASP
Fig. 8. pH of effluent brine, Core Flood #1.
Fig. 9a. Oil recovery during secondary chemical flooding, Core Flood #2.
Type III
Fig. 9b. Pressure drop during the secondary chemical flooding, Core Flood #2.
Fig. 7. Salinity of effluent brine, Core Flood #1.
flood was 95.6% OOIP. Table 4 summarizes the oil recovery in the coreflood. Fig. 9b shows the pressure drop during the ASP and polymer phases of the secondary coreflood. The pressure drop started at
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Fig. 13. Measured and calculated polymer viscosity.
Fig. 10. Conductivity and pH of effluents, Core Flood #2 (The solutions were diluted 20 times to measure conductivity).
Table 5 UTCHEM polymer and surfactant input parameters. Polymer parameters
Surfactant parameters
Ap1 = 700 Ap2 = 900 Ap3 = 1700 Sp = 0.38 c_ 1=2 = 0.8 P a = 1.8
CSEL7 = 0.6; CSEU7 = 1.3 Hblc71 = 0.03; Hblc71 = 0.07; Hblc72 = 0.03
Table 6 List of elements and reactive species. Elements or pseudo-elements
Fig. 11. Concentration of surfactants in effluent samples and cumulative oil recovery, Core Flood #2.
Independent species Dependent species Surfactant associated cations
379 380 381 382 383 384 385 386 387 388 389 390
about 10 psi, decreased a little bit and then increased to about 30 psi during alkaline polymer flooding and further increased to about 40 psi. The increasing pressure drop shows that the ASP flood was stable. The effluent pH and salt conductivity are plotted together in Fig. 10. The pH is almost constant from 1 to 4 PV and starts to decrease when sodium metaborate is no longer injected. The conductivity also starts to decrease after about 2.5 PV of injection. The effluent surfactant concentration is shown in Fig. 11. The individual surfactant concentrations are not shown here, but the two surfactants moved together through the core. The retention of surfactant in the core was calculated from the effluent surfactant
Calcium, magnesium, sodium, hydrogen (reactive), sulfate, tetrahydroxy borate, oleic acid Ca2+, Mg2+, Na+, H+, SO42, CO32, B(OH)4, HAo, H2O OH, H2CO3, HCO 3 , B(OH)3, HAw, A Na+, Ca2+
concentration by material balance. The retention was 0.127 mg of the surfactant per gram of the core which is a reasonably low value (<0.3 mg/gm) for field application. It should also be noted that the dynamic retention value is lower than the static adsorption values of 0.4–0.75 mg/gm.
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3.4. Simulation
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The surfactant phase behavior [8,9] is modeled in UTCHEM using the Hand representation of the ternary diagram[25] and the UTCHEM input parameters for these simulations were obtained from matching the experimental data. The comparison of the modeled and the measured solubilization ratio for water–oil-ratio (WOR) of 1 is shown in Fig. 12. The importance of obtaining phase behavior at different WOR is important because the optimal salinity changes with the ratio of soap and surfactant, as described by Salager et al. [26] and Mohammadi et al. [22]. Soap is the in-situ generated surfactant due to the reaction of the acidic components of crude oil and the injected alkali. The UTCHEM parameters for modeling polymer viscosity are based on the Flory–Huggins equation
397
l
0 p
¼ lw 1 þ Ap1 C 4l þ Ap2 C 24l þ Ap3 C 34l C Sp SEP
ð1Þ
and the Meter’s equation
lp ¼ lw þ Fig. 12. Measured and calculated solubilization ratios at water–oil ratio of 1.
l lw 0 p
1þ
c_ c_ 1=2
Pa 1
392 393 394 395
398 399 400 401 402 403 404 405 406 407 408 409
410 412 413
414
ð2Þ
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Table 7 Input for 1-D secondary and tertiary ASP flooding simulation. Number of grids Components present
Porosity Permeability Water viscosity (@ 38 °C) Oil viscosity(@ 38 °C) Residual oil saturation Residual water saturation Water endpoint relative permeability Oil endpoint relative permeability Injection Schedule
417 418 419 420 421 422 423 424
50 1 1 Water, oil, surfactant, polymer, chloride, calcium, magnesium, carbon (as carbonate), sodium, hydrogen (reactive), sulfate, B(OH)4, HAo 0.18 80 mD 0.85 cP 105 cP 0.43 0.30 0.05 1.0 0.3 PV ASP slug 0.5 PV polymer 1 0.5 PV polymer 2
The parameters were obtained from matching the experimental data. Note that Eq. (1) is the modified form of the original equation which takes into account the effect of salinity on polymer solution viscosity. Here Ap1, Ap2, Ap3 and Sp are the fitting parameters to obtain polymer viscosity for a particular polymer concentration at the zero share rate. c_ 1=2 and Pa in Eq. (2) take into account the reduction in polymer viscosity with shear rate, c_ , which is calculated from the Blaze–Kozeny capillary bundle equation [27]. There
is a reasonable agreement between the modeled and the measured viscosity, as can be seen from Fig. 13. The modeling parameters for polymer and surfactant are given in Table 5. Since the alkali plays an important role in ASP process by generating an in-situ surfactant and reducing surfactant adsorption on the rock surface, it is important to understand its propagation in the reservoir. In order to do so, it is important to model all the relevant alkali reactions that could lead to its consumption such as reaction with the rock surface. The geochemical species considered in these simulations are given in Table 6. For simplicity, some of the aqueous species that are less likely to be present under the experimental conditions were not considered in these calculations. The thermodynamic data was taken at the reservoir temperature, that is 38 °C, and EQBATCH was used to perform the equilibrium calculations. Other input parameters of the UTCHEM simulations are listed in Table 7. The comparisons of the experimental and simulated oil recovery data for the secondary and the tertiary ASP floods are given in Figs. 14 and 15, respectively. In the case of secondary ASP, only oil is produced at the start of the experiment, then the oil cut drops to about 0.6 which falls to zero in about 1 PV injection. In the case of tertiary ASP, the oil cut is zero until the oil bank breakthrough at around 0.25 PV injection, then it rises to about 0.5 before decreasing to zero again at about 0.8 PV injected, in the simulation. In both the cases, the simulation data matches reasonably well with the experimental data; the oil production continues for a longer time in the experiments. Experimental data for surfactant phase behav-
Fig. 14. Measured and simulated oil recovery, oil cut and residual oil saturation for the secondary ASP coreflood.
Fig. 15. Measured and simulated oil recovery, oil cut and residual oil saturation for the tertiary ASP coreflood.
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Fig. 16. Calculated oil saturation profile for the secondary and the tertiary ASP corefloods at 0.2 PV injection.
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ior, polymer viscosity, and surfactant adsorption were critical in matching the experimental results. Fig. 16 shows the simulated in situ oil saturation profiles at 0.2 PV injection for both the ASP floods. There are three saturation jumps in each case. At about xd = 0.075, oil saturation jumps from 0 to 0.13; This jump is between the oil left after solubilization and the residual oil saturation left after mobilization. The solubilization front moves very slowly and is irrelevant to oil recovery after 1 or 2 PV injected. The second jump is at about xd = 0.2–0.4; oil saturation increases slowly from 0.13 to about 0.6 (the oil bank saturation). The third jump is at xd = 0.72; saturation jumps from 0.6 to its initial value. In the case of secondary ASP flooding, the initial oil saturation is about 0.7 whereas for the tertiary flood, it is about 0.42. These saturation profiles are similar to those expected from the fractional flow theory of ASP processes discussed by Pope [28]. As salinity increases, the microemulsion phase behavior transitions from type I to type III to type II [29]. For a successful ASP operation, it is important to attain an ultralow IFT in the reservoir; Winsor type III microemulsion gives an ultralow IFT. It is necessary to have a correct salinity gradient in an ASP flood design to be able to encounter the type III region. The simulated salinity profile shows that type III salinity is achieved at the surfactant bank (not shown here). The presence of surfactant and type II salinity leads to ultralow IFT which mobilizes the oil. The presence of polymer controls the mobility and pushes the oil out in a stable manner. The simulated salinity profile shows that correct salinity gradient was achieved in the corefloods (not shown here). These experiments and simulations show that the secondary ASP flood is slightly more effective than the tertiary ASP flood. In viscous oil reservoirs, one cannot inject more than one or two pore volumes of fluid because of the high viscosity of the oil. Thus tertiary ASP floods would not be conducted after long water floods. One must consider secondary ASP floods or an ASP flood after a short water flood.
486
4. Conclusions
487
The contributions of this study are the development of an ASP formulation for a viscous oil in a carbonate reservoir using sodium metaborate as alkali, the comparison of sodium carbonate and sodium metaborate as alkali for carbonate rocks, the comparison of secondary and tertiary ASP floods, and modeling of the floods including geochemical reactions. The following conclusions can be drawn from this work.
488 489 490 491 492 493
An ASP formulation using sodium metaborate has been developed that gives low IFT and type III phase behavior with the viscous reservoir oil and the injection brine. Sodium metaborate was found to be equally effective as sodium carbonate in reducing surfactant adsorption on Silurian dolomite. Waterflood of the viscous oil in a carbonate core recovered about 47.8% of the oil in place and reduced the oil saturation to 43.8%. The tertiary ASP flood increased the cumulative oil recovery to 92.7% whereby the oil saturation was reduced to 6.1%. The secondary ASP coreflood in the same core reduced the oil saturation to 3.1% and recovered 95.6% of the oil in place. The secondary ASP flood should be considered if the reservoir is not already water flooded. Sodium metaborate was effective in the ASP formulation prepared in the softened injection brine for the carbonate rock with the hard connate brine. The UTCHEM simulation results (including the geochemical reactions) match well with the experimental results for both the secondary ASP and the tertiary ASP floods. Experimental data for surfactant phase behavior, polymer viscosity, and surfactant adsorption were critical in matching the experimental results.
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Acknowledgements
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The authors would like to thank the industrial affiliates of the Chemical Enhanced Oil Recovery Project at the University of Texas at Austin for the financial support.
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References
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[1] Akbar M, Vissapragada B, Alghamdi AH, Allen D, Herron M, Carnegie A, et al. A snapshot of carbonate reservoir evaluation. Oilfield Rev 2000;12(4):20–1. [2] Roehl PO, Choquette PW. Carbonate petroleum reservoirs. New York: SpringerVerlag; 1985. [3] Al-Dhafeeri AM, Seright RS, Nasr-El-Din HA, Sydansk RD. High-permeability carbonate zones (Super-K) in ghawar field (Saudi Arabia), identified, characterized, and evaluated for gel treatments. In: Paper SPE 97542 presented at the international improved oil recovery conference in Asia Pacific, Kuala Lumpur (Malaysia), 5–6 December; 2005. [4] Stegemeier GL. Mechanisms of oil entrapment and mobilization in porous media. In: Presented at the AIChE symposium on improved oil recovery by surfactant and polymer, Kansas City (Missouri); 12–14 April, 1976. [5] Nelson RC, Lawson JB, Thigpen DR, Stegemeier GL. Cosurfactant-enhanced alkaline flooding. In: Paper SPE 12672 presented at the Symposium on Improved Oil Recovery, Tulsa (Oklahoma); 15–18 April, 1984.
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[6] Hirasaki GJ, Miller CA, Puerto M. Recent advances in surfactant EOR. In: Paper SPE 115386 presentation at the SPE annual technical conference and exhibition, Denver; 21–24 September, 2008. [7] Liu S, Li RF, Miller CA, Hirasaki GJ. ASP processes: wide range of conditions for good recovery. In: Paper SPE 113936 presentated at the SPE/DOE improved oil recovery symposium, Tulsa (USA); 19–23 April, 2008. [8] Healy RN, Reed RL. Immiscible microemulsion flooding. SPE J 1977;17 (2):129–39. http://dx.doi.org/10.2118/5817-PA. SPE-5817-PA. [9] Nelson RC, Pope GA. Phase relationships in chemical flooding. SPE J 1978;18 (5):325–38. http://dx.doi.org/10.2118/6773-PA. SPE-6773-PA. [10] Panthi K, Mohanty KK. Effect of alkaline preflush in an alkaline–surfactant– polymer flood. Energy Fuels 2013;27(2):764–71. [11] Falls AH, Thigpen DR, Nelson RC, Ciaston JW, Lawson JB, Good PA, et al. Field test of cosurfactant-enhanced alkaline flooding. SPE Res Eng 1994;9 (3):217–23. http://dx.doi.org/10.2118/24117-PA. SPE 24117-PA. [12] Reppert TR. RTD 2(2) enhanced oil recovery in the north sea. In: Paper SPE 20219 presented at the SPE/DOE improved oil recovery symposium held in Tulsa (Oklahoma, USA); 22–25 April, 1990. [13] Shutang G, Qiang G, Lin J. Recent progress and evaluation of ASP flooding for EOR in daqing oil field. In: Paper presented at the SPE EOR conference at oil and gas. West Asia (Muscat, Oman); 11–13 April, 2010. http://dx.doi.org/10. 2118/127714-MS. [14] Levitt DB, Jackson AC, Heinson C, Britton LN, Malik T, Dwarakanath V, et al. Identification and evaluation of high-performance EOR surfactants. SPE Res Eng 2009;12(2):243–53. http://dx.doi.org/10.2118/100089-PA. SPE 100089PA. [15] Adibhatla B, Mohanty KK. Oil recovery from fractured carbonates by surfactant aided gravity drainage: laboratory experiments and mechanistic simulations. SPE Res Eval Eng 2008;11(1):119–30. http://dx.doi.org/10.2118/99773-PA. SPE 99773-PA. [16] Kumar R, Dao E, Mohanty KK. Emulsion flooding of heavy oil. In: SPE improved oil recovery symposium held in Tulsa (Oklahoma, USA); 24–25 April, 2010. [17] Xu H, Kim DH, Delshad M. Potential for non-thermal chemical augmented waterflood for producing viscous oils. In: Presented at the SPE western
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regional and AAPG pacific section meeting. Joint Technical Conference Monterey, California (USA); 19–25 April, 2013. Sharma H, Dufour S, Pinnawala GWP, Weerasooriya U, Pope GA, Mohanty KK. Alternative alkalis for ASP flooding in anhydrite containing oil reservoirs. Fuel 2015;140:407–20. Bataweel MA, Nasr-El-Din HA. Minimizing scale precipitation in carbonate cores caused by alkalis in ASP flooding in high salinity/high temperature applications. In: Paper presented at the SPE international symposium on oilfield chemistry at the Woodlands, Texas, USA; 11–13 April, 2011. Huh C. Interfacial tensions and solubilizing ability of a microemulsion phase that coexists with oil and brine. J Colloid Interface Sci 1979;71(2):408–26. Delshad M, Pope GA, Sepehrnoori K. A compositional simulator for modeling surfactant enhanced aquifer remediation. J Contam Hydrol 1996;23 (4):303–27. Mohammadi H, Delshad M, Pope GA. Mechanistic modelling of alkaline/surfactant/polymer floods. SPE J 2009;12(4):518–27. Bhuyan D, Pope GA, Lake LW. Simulation of high-pH coreflood experiments using a compositional chemical flood simulator. In: Proceedings of the SPE International symposium on oilfield chemistry, anaheim, CA; 20–22 February, 1991. deZabala EF, Vislocky JM, Rubin E, Radke CJ. A chemical theory for linear alkaline flooding. SPE J 1982;22(2):245–58. Hand DB. Dineric distribution: I. The distribution of a consolute liquid between two immiscible liquids. J Phys Chem 1939;34:1961–2000. Salager JL, Vasquez E, Morgan JC, Schechter RS, Wade WH. Optimum formulation of surfactant-oil-water systems for minimum interfacial tension or phase behavior. Soc Pet Eng J 1979;19(2):107–15. Sorbie KS. Polymer-improved oil recovery. Boca Raton (Florida): CRC Press Inc.; 1991. Pope GA. The application of fractional flow theory to enhanced oil recovery. SPE J 1980;20(3):191–205. Winsor PA. Solvent properties of amphiphilic compounds. London: Butterworths Scientific Publication; 1954.
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Contents lists available at ScienceDirect
Fuel journal homepage: www.elsevier.com/locate/fuel 4 5 3
ASP flood of a viscous oil in a carbonate rock
6
Krishna Panthi, Himanshu Sharma, Kishore K. Mohanty ⇑
7
The University of Texas at Austin, United States
8 9 1 1 12 13
h i g h l i g h t s An ASP formulation was developed that gives ultralow IFT with a viscous oil.
14
The alkali reduces anionic surfactant adsorption on dolomite without calcite precipitation.
15
93–95% of the viscous oil was recovered in core floods.
16
a r t i c l e 1 3 8 3 19 20 21 22 23 24 25 26 27 28 29 30 31 32
i n f o
Article history: Received 17 July 2015 Received in revised form 25 September 2015 Accepted 27 September 2015 Available online xxxx Keywords: Viscous oil Sodium metaborate Carbonate reservoir ASP flood Enhanced oil recovery Simulation
a b s t r a c t The goal of this work is to develop an alkaline–surfactant–polymer (ASP) formulation for a viscous oil (105 cP at the reservoir temperature) and compare secondary and tertiary ASP floods. Phase behavior studies were performed to find an ultralow interfacial tension (IFT) ASP formulation for the viscous oil. Static surfactant adsorption experiments were performed to compare the effectiveness of different alkalis in reducing adsorption. The surfactant formulation was tested with an outcrop vuggy dolomite core in both tertiary and secondary modes. Lab coreflood results were modeled in UTCHEM which used EQBATCH to model sodium metaborate geochemical reactions in a carbonate rock. Sodium carbonate and sodium metaborate were both found to be equally effective in reducing surfactant adsorption on crushed dolomite. Waterflood recovered about 47.8% of the oil in place and reduced the oil saturation to 43.8%. The tertiary surfactant flood increased the cumulative oil recovery to 92.7% whereby the oil saturation was reduced to 6.1%. The secondary surfactant flood was even more effective than the tertiary; the oil saturation was reduced to 3.1% and the oil recovery was 95.6% OOIP. Very low surfactant retention was observed in the ASP corefloods. UTCHEM simulations showed a reasonable match with the experimental results. Experimental data for surfactant phase behavior, polymer viscosity, and surfactant adsorption were critical in modeling the experimental results. Ó 2015 Published by Elsevier Ltd.
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52 53
1. Introduction
54
About 60% of the world’s remaining oil is trapped in carbonate reservoirs and some of these oils are viscous [1,2]. Thermal methods are generally used to recover viscous oils from sandstone reservoirs, but mineral dissolution and precipitation can cause severe problems in carbonate reservoirs. Waterflood is not very efficient for viscous oil reservoirs due to viscous fingering leading to poor sweep efficiency. Therefore, chemical methods such as polymer flood or ASP floods are being considered. High molecular weight polymers viscosity the aqueous phase, reduce viscous fingering and bypassing [3]. Surfactants reduce the oil/water interfacial tension greatly so that the viscous forces can overcome the
55 56 57 58 59 60 61 62 63 64
⇑ Corresponding author at: Petroleum & Geosystems Engineering, CPE 4.168, The University of Texas at Austin, 200 E. Dean Keaton St., Austin, TX 78712, United States. Tel.: +1 512 471 3077; fax: +1 512 471 9605 E-mail address: [email protected] (K.K. Mohanty).
capillary forces which help mobilize oil [4]. Alkalis form soap with viscous crude oils which are often acidic and also lower the adsorption of anionic surfactants [5–7] by making mineral surfaces negatively charged at a pH greater than 9, thus reducing surfactant requirement. Chemical flooding was developed in the past mainly for sandstone reservoirs with light oil [8–10]. Many ASP field tests have confirmed that the waterflood residual oil can be displaced by the use of alkaline–surfactant–polymer floods [11,12]. Particularly, the ASP field test in the Daqing field recovered about 20% additional OOIP after waterflood [13]. Recent research has led to the development of the surfactant systems which are suitable for carbonate environment [14,15]. Alkaline–surfactant–polymer [16] and alkaline-co-solventpolymer [17] formulations have also been recently developed for a few viscous oils. Most viscous oil reservoirs are not yet water flooded. Thus, it is important to compare the effectiveness of
http://dx.doi.org/10.1016/j.fuel.2015.09.072 0016-2361/Ó 2015 Published by Elsevier Ltd.
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Nomenclature ASP alkaline–surfactant–polymer ASFB alkaline synthetic formation brine cP centipoise CSE effective salinity HPAM hydrolyzed Polyacrylamide HPLC high performance liquid chromatography IFT interfacial tension IBA5EO isobutanol pentaethoxy IBA10EO isobutanol decaethoxy Soi initial oil saturation mD millidarcy Oil-ME IFT oil/microemulsion IFT
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secondary ASP processes with tertiary ASP processes. The conventional alkali used for chemical EOR is sodium carbonate (Na2CO3). However, in presence of gypsum, the carbonate ion precipitates as calcium carbonate. Sodium metaborate (NaBO2) may be used as an alkali in such cases as it is shown to tolerate gypsum which is commonly encountered in carbonate reservoirs [18]. NaBO2 gives a high pH (11) for 1000 mg/L concentration, sufficient to react with acidic components of oil and reduce surfactant adsorption in chemical flooding. The monomeric borate ion (B(OH)4 ) provides alkaline buffering at high pH. Further, NaBO2 is found to have less permeability damage and alkalinity loss compared to Na2CO3 when it is mixed with formation brine containing divalent ions [19]. Another important aspect of this NaBO2 alkali is its low cost, making it feasible to use in large scale oil recovery processes. The goal of this study is to develop an ASP formulation that can be used in a carbonate, viscous (105 cP) oil reservoir at the reservoir temperature of 38 °C. This formulation should be able to minimize surfactant adsorption, mineral dissolution/precipitation and maximize oil recovery. The phase behavior for the reservoir oil was studied with many surfactant combinations, to identify an ultralow IFT formulation, using NaBO2 as alkali so that it can tolerate gypsum or hard formation brine better compared to Na2CO3. Static surfactant adsorption experiments were performed with NaBO2 to compare with Na2CO3, in terms of reducing surfactant adsorption on a dolomite. The rheology of surfactant solution with and without polymer was measured. Then core floods were conducted in secondary and tertiary modes. The core floods were simulated by the mechanistic simulator, UTCHEM.
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2. Methodology
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2.1. Chemicals
112
Commonly available and inexpensive chemicals were used in the surfactant formulation. Propoxy Sulfates (surfactants A, B, C) and an Internal Olefin Sulfonate (surfactant D) were obtained from Stepan. Both the surfactants A and B are tridecyl alcohol propoxy sulfates (TDAxPOSO4). Surfactant A has a larger number of propoxy groups than the surfactant B. Surfactant C is an alkyl propyl sulfate (xCyPOSO4). Surfactant D is an internal olefin sulfonate (xCIOS). Decaethoxy Isobutanol (IBA-10EO) and Pentaethoxy Isobutanol (IBA-5EO) were obtained from Dr. Gary Pope’s laboratory at the University of Texas at Austin. Triethylene glycol monobutyl ether (TEGBE) was obtained from Fisher Scientific. Polymer HPAM3630 was obtained from SNF. Its molecular weight was about 20 106 daltons and the degree of hydrolysis was 25–30%. NaBO24H2O was used as the alkali. The injection brine composition was softened sea water which was approximated by 30,700 ppm sodium chloride (NaCl) and 4800 ppm sodium sulfate (Na2SO4). The stock
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113 114 115 116 117 118 119 120 121 122 123 124 125 126 127
OOIP original oil in place KOH potassium hydroxide PV pore volume NaCl sodium chloride Na2CO3 sodium carbonate Na2SO4 sodium sulfate NaBO24H2O sodium metaborate tetrahydrate SFB synthetic formation brine TEGBE triethylene glycol monobutyl ether THF tetrahydrofuran WOR water to oil ratio
tank oil from the reservoir was highly viscous (800 cP), but the viscosity of live oil was about 105 cP; so the stock tank oil was diluted with decalin to get the viscosity of 105 cP at the reservoir temperature. The total acid number of the oil is 1.26 mg KOH (potassium hydroxide) per gm of oil.
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2.2. Phase behavior
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Surfactant phase behavior experiments were performed to identify a surfactant formulation which gives ultralow IFT with the oil and is aqueous stable at the optimum salinity. Aqueous solutions were prepared with 1 wt% surfactant (or mixture of two surfactants) mixed with the injection brine along with co-solvent and alkali. The alkali concentration was varied systematically (in a series of pipettes) keeping the other parameters fixed. Oil and aqueous solutions were mixed in appropriate ratios and the samples were equilibrated at the reservoir temperature and their phase volumes were observed. The solubilization of the oil and water in the microemulsion phases was calculated from the phase volumes. The interfacial tension was estimated from the Huh equation [20]. The phase behavior was studied as a function of waterto-oil ratio (WOR). Similarly, only aqueous solutions were prepared and kept at reservoir temperature to obtain the aqueous stability limits of surfactant formulations. The viscosity was measured at shear rates ranging from 1 to 100 s1.
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2.3. Static surfactant adsorption
151
A Silurian dolomite core was crushed to 140–200 mesh size and carefully washed with DI water to remove impurities. The specific surface area of these samples was found to be about 0.4 m2/g by BET measurement. The surfactant combination which gave good phase behavior with oil was used to perform static adsorption experiment. Liquid samples were prepared by carefully adding required amounts of brine, surfactant and alkali. Static surfactant adsorption samples were prepared in glass vials by keeping the solid to liquid ratio equal to 1 (3 g each). The total amount of surfactants was varied from 0.25 wt% to 1 wt%, keeping the alkali concentration fixed. The salinity of the samples was kept close to the optimum salinity obtained from the surfactant phase behavior experiments (i.e., 35,000 ppm injection brine and some added alkali). 5000 ppm of NaBO2 (10,000 ppm NaBO24H2O) and 5000 ppm of Na2CO3 were used as alkalis and 5000 ppm NaCl was used for the base case. The samples were kept at room temperature for about 20 days and mixed gently from time to time. The supernatant solutions were then separated, filtered and analyzed with a high performance liquid chromatograph (HPLC) for the surfactant concentration. A calibration chart was prepared consisting of known surfactant concentrations and the areas obtained
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K. Panthi et al. / Fuel xxx (2015) xxx–xxx Table 1 List of coreflood experiments. Flood #
Core
Condition
Length (cm)
U (%)
k (mD)
Soi (%)
1 2
Dolomite Dolomite
New core Used core (from flood#1)
30.37 30.37
18.85 18.85
80.1 80.1
84 70.3
Table 2 Slug compositions in ASP corefloods. Chemical Surfactant A Surfactant B TEGBE HPAM3630 NaCl Na2SO4 NaBO24H2O
Waterflood brine (ppm)
30,700 4800
Preflush (ppm)
ASP (ppm)
Polymer I (ppm)
Polymer II (ppm)
30,700 4800 10,000
7500 2500 20,000 4500 30,700 4800 10,000
4500 30,700 4800 10,000
4500 30,700 4800
175
from HPLC to obtain surfactant concentrations of the unknown samples. Surfactant adsorption was calculated based on the change in surfactant concentrations using the formula given below:
176 178
surfactant adsorption ðmg=g rockÞ ¼ ðC 0 CÞ 10 M surf =M solid
173 174
179 180 181
where C0 = initial surfactant concentration in wt%, C = final surfactant concentration in wt%, Msurf = mass of the liquid solution in grams, and Msolid = mass of solid in grams.
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2.4. Core preparation
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196
The core was about a foot long out-crop dolomite core and its properties are listed in Table 1. The core had a length of 30.37 cm and a diameter of 3.73 cm. The porosity was 18.8% and the permeability was 80.1 mD for brine. The pore volume was 62.6 cc. The core was first fully saturated with the formation brine and then flooded with the reservoir oil from the top and placed in a vertical orientation in an oven at the reservoir temperature, i.e., 38 °C. It was then flooded with oil at the rate of 1 ft/day from the bottom and the pressure drop was recorded. The core was then flooded with 3 PV of synthetic formation brine from the bottom at the rate of 1 ft/d and then 2 PV of the same brine was injected at the rate of 10 ft/d. The first step represents a waterflood at a typical field rate; the second step is conducted to identify any capillary end effect.
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2.5. ASP coreflood
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The ASP flood consisted of injection of an ASP slug (0.3 PV) followed by a polymer slug I (0.5 PV) at the optimum salinity which is followed by polymer slug II (0.5 PV) at the injection brine salinity which is further followed by just the injection brine for about 3 PV. The surfactant concentration in the ASP slug was
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199 200 201 202
1 wt%. The ASP Core Flood #1 was conducted in the tertiary mode whereas the ASP Core Flood #2 was in the secondary mode. The slug compositions are given in Table 2. In Core Flood 1, the waterflood was followed by the preflush and tertiary ASP flood. The core was cleaned and prepared for Core Flood 2 in the following manner after Core Flood 1: it was first injected with 2 PV of brine followed by 2 PV of THF, which was further followed by 2 PV of chloroform, followed by 3 PV of methanol, which was further followed by 2 PV of 0.1% sodium thiosulfate and finally flooded with about 10 PV of brine. The core was then flooded with oil and kept in an oven at the reservoir temperature, i.e., 38 °C. This core was then used in Core Flood #2. The second ASP flood was similar to the first ASP flood, but in the secondary mode. 0.3 PV of ASP at the optimum salinity (with 4500 ppm HPAM3630) was injected followed by the brine at the optimum salinity with 4500 ppm HPAM3630. This polymer slug was followed by about 0.5 PV of synthetic injection brine along with 4500 ppm HPAM3630 which was further followed by 3 PV of synthetic injection brine.
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2.6. Simulation
221
These coreflood experiments were modeled using the Alkali–Surfactant–Polymer (ASP) module of UTCHEM 2011, the multicomponent, multiphase, compositional chemical flooding simulator developed by Delshad et al. [21] and Mohammadi et al. [22]. The interaction of metaborate with the reservoir rock and the aqueous species was included in these calculations using EQBATCH, the geochemistry module of UTCHEM developed by Bhuyan et al. [23]. The reservoir rock is approximated to be pure dolomite, that is, Calcium and Magnesium were supposed to be present in equal proportions. The acidic content of the crude was represented by a single pseudocomponent HAo as described by deZabala et al. [24].
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Table 3 Phase behavior study. Expt.#
Surfactants & cosolvents
wt% of surfactants & cosolvents
Winsor type/result
1 2 3 4 5 6 7 8 9 10
Surfactant Surfactant Surfactant Surfactant Surfactant Surfactant Surfactant Surfactant Surfactant Surfactant
1% + 1% 0.5% + 0.5% + 1% 1% + 2% 0.5% + 0.5% + 1% 1% + 1% 1% + 1% 0.5% + 0.5% + 1% 0.5% + 0.5% + 1% 0.5% + 0.5% + 2% 0.75% + 0.25% + 2%
Type I, some oil solubilization Type II Type I, some oil solubilization Type II Type I Type I Large oil solubilization but difficult to see type III region Thick type III region, but opt. salinity is 3.5% NaBO24H2O Thick type III region, but opt. salinity is 3.5% NaBO24H2O Thick type III region, opt. salinity at 1% NaBO24H2O
B + IBA10EO C + surfactant D + TEGBE B + IBA10EO C + surfactant D + IBA10EO B + IBA5EO A + IBA5EO A + surfactant B + IBA5EO A + surfactant B + TEGBE A + surfactant B + TEGBE A + surfactant B + TEGBE
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3. Results and discussions
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3.1. Phase behavior
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The different combinations of surfactants and co-solvents tested for suitable phase behavior are summarized in Table 3. The aqueous solutions of surfactant–cosurfactant–cosolvent in synthetic injection brine were mixed in pipettes with oil; the NaBO24H2O concentration in brine was varied for each formulation. The formulation of experiment #10 (0.75% surfactant A and 0.25% surfactant B) showed excellent phase behavior (Table 3) with all three Winsor phases at different concentrations of metaborate and was selected for the core floods. Fig. 1(a) shows the phase behavior of this formulation as a function of the NaBO24H2O concentration (0.25–2.5 wt%) at WOR = 1. At low alkali concentration, there are two phases: the bottom phase is the microemulsion; the top phase is oil (Type I). Three phases (water, microemulsion, and oil) exist at the intermediate alkali concentration (in 5 samples 0.75–1.75%); this is called Type III phase behavior. Two phases (water and microemulsion) exist at the high alkali concentration (Type II). This is the typical oil–water–surfactant phase behavior. Fig. 1(b) shows the water and oil solubilization ratios. The optimal alkali concentration is 1 wt% NaBO24H2O; the solubilization ratio (S⁄) at the optimum is 8. The interfacial tension in this system is estimated from the Huh equation, IFT (mN/m) = 0.3/S⁄2. The lowest IFT is 0.0046 mN/m. This IFT translates to a capillary number of 0.0007 for a water viscosity of 1 cp and a number of 0.07 for a water viscosity of 100 cp (due to inclusion of polymer) at 1 ft/d. This capillary number is adequate for mobilization of oil in porous media, as shown in the corefloods.
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a
0.25% 0.5% 0.75% 1% 1.25% 1.5% 1.75% 2% 2.25% 2.50
b
Fig. 2. Effect of water–oil ratio on phase behavior.
The phase behavior experiments were conducted at several WORs for this formulation. The effect of WOR on the type of phase behavior is shown in Fig. 2. A high WOR corresponds to a small oil% [=100⁄ oil volume/(oil volume + water volume)]; Type III phase behavior shifts to a higher salinity at a smaller oil% and shows a negative slope. This slope shows that the oil is active and has acidic components. A higher WOR corresponds to a lower amount of oil and thus less soap formation. Hence, the soap to synthetic surfactant ratio is lower at a high WOR. The effect of WOR on the phase behavior is important when dealing with acidic oils. 4500 ppm HPAM3630 was added to the brine at the optimal salinity (for WOR = 1). Equal volume of oil was then added to the surfactant–polymer solution. Mixing of oil, brine, surfactant and polymer at the optimal salinity resulted in three phases. Fig. 3 shows the viscosity of the pure oil, the ASP solution, the alkaline polymer solution (HPAM3630 in synthetic injection brine +10,000 ppm NaBO2) and the synthetic injection brine polymer solution. The oil viscosity is independent of the shear rate. The ASP and polymer solutions are shear thinning, but have the viscosity (at 10 s1) similar to that of the oil.
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3.2. Static surfactant adsorption
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The results of the static surfactant adsorption experiment are shown in Fig. 4. The surfactant adsorption is about 1.25 mg/gm of rock in the absence of any alkali. It is reduced by about half on addition of 5000 ppm NaBO2 or Na2CO3. The surfactant adsorption values of samples with Na2CO3 are similar to that with NaBO2, between 0.4 and 0.75 mg/gm. Given the additional benefits of sodium metaborate listed above, it was used in the coreflood experiments.
283
S*=1%, *=8
Middle phase
Fig. 1. Phase behavior at 38 °C as a function of 0.25% to 2.25% NaBO24H2O. Each sample also contains 0.75% surfactant A, 0.25% surfactant B, 2% TEGBE in addition to the synthetic injection brine, WOR = 1. (a) Photograph of pipettes and (b) oil and water solubilization ratios.
Fig. 3. Viscosity of diluted oil, ASP solution, alkaline polymer solution, and brine polymer solution.
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Fig. 5b. Pressure drop during water flooding, Core Flood #1.
Fig. 4. Static surfactant adsorption results.
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3.3. Core floods
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Table 1 shows the initial conditions for the corefloods. Two ASP core floods were conducted with the outcrop core. Core Flood #1 is in the tertiary mode whereas Core Flood #2 is in the secondary mode.
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3.3.1. Core Flood 1 This core flood was conducted in the out-crop core with the reservoir dead oil diluted with decalin. The waterflood was followed by an ASP flood. Fig. 5a shows the oil recovery during the water flood. The initial oil saturation was 84%. Waterflood at 1 ft/ d rate reduced the oil saturation to 47% and recovered 43% OOIP in about 3 PV injected. The water injection rate was then increased by 10 times and 2 more PV were injected, whereby the oil saturation was reduced to 45.2%. Then 0.4 PV of preflush (brine at optimum salinity) was injected which further increased the recovery to 47.8%. The preflush was used so that the ASP slug starts at the right salinity. The pressure drop across the core during the coreflood process is shown in Fig. 5b. The pressure drop (at the rate of 1 ft/d) gradually decreased with the recovery of oil and was steady at about 2 psi and then increased to about 9 psi at the higher flow rate and further decreased to about 3 psi during preflush flood at 1 ft/d. The waterflood was followed by 0.3 PV ASP slug which included 0.75% surfactant A, 0.25% surfactant B, 2% TEGBE, 10,000 ppm NaBO24H2O, and 4500 ppm HPAM3630 in addition to the synthetic formation brine. Though the HPAM3630 is a large molecular weight polymer, no injectivity problem was observed in this particular core. After the ASP solution, a slug of 0.5 PV alkaline– polymer solution was injected which included 10,000 ppm
SFB@10 ft/day
5
Preflush
Fig. 6a. Oil recovery during tertiary chemical flooding, Core Flood #1.
NaBO24H2O and 4500 HPAM3630 in the synthetic injection brine. After the alkaline–polymer solution, 0.5 PV of polymer solution (without alkali) was injected which included only 4500 ppm HPAM3630 in the synthetic injection brine and at last only synthetic injection brine (about 3.1 PV) was injected. Fig. 6a shows the tertiary oil recovery during the ASP flood. In the beginning, no oil was produced because the core was at waterflood residual at the start of the surfactant flood. Oil bank broke through at about 0.3 PV injected. Oil cut increased to 78% for a short time and then decreased. Most of the oil was produced by 1.2 PV injection (6.6 PV including the waterflood); the residual oil saturation was reduced to 6.1% at the end of flood. Cumulative oil recovery for the waterflood including preflush was 47.8%; but at the end of the ASP flood it increased to 92.7% OOIP. Table 4 summarizes the oil recovery in the corefloods. Fig. 6b shows the pressure drop during the tertiary recovery. The pressure drop started at about 2 psi corresponding to preflush flow, increased to about 10 psi during the ASP injection, because of the high viscosity of the polymeric solution. It further increased to about 12 psi during alkaline polymer injection and further increased to about 23 psi during synthetic brine polymer injection. As the salinity decreases, the polymeric solution viscosity increases for the same polymeric concentration. Eventually the pressure drop fell to about 6 psi during the brine flood at the end. The high pressure drop during the ASP/polymer slug indicates a stable displacement of the oil bank. Fig. 7 shows the salinity of the effluent brine in Core Flood 1; both waterflood and chemical flood effluents are plotted together in this figure. The salinity plot shows that the salinity increases to the optimal salinity during the surfactant slug and then
Fig. 5a. Oil recovery during water flooding, Core Flood #1.
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Table 4 Oil recovery in coreflood experiments. Flood #
Type of Flood
Initial oil saturation (%)
WF oil recovery (%OOIP)
Net recovery (%OOIP)
1 2
ASP in tertiary mode ASP in secondary mode
84 70.3
47.8
92.7 95.6
Fig. 6b. Pressure drop during tertiary chemical flooding, Core Flood #1.
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decreases. It also shows that there is mixing between the formation brine and the surfactant slug and the optimal salinity is not maintained throughout the surfactant slug. Fig. 8 shows the pH of the effluent brine; both waterflood and ASP flood are plotted together. The pH increases to about 10 when the preflush is injected and maintains the high pH condition throughout the surfactant injection. 3.3.2. Core Flood 2 In Core Flood 2, the ASP flood was done in the same core under the same conditions as Core Flood 1, but in the secondary mode (i.e., without a water flood). The core (after Core Flood #1) was brought to Swi, as described in the methodology section. The core was then flooded with 0.3 pore volume of ASP. It included 0.75% surfactant A, 0.25% surfactant B, 10,000 ppm NaBO24H2O, and 4500 ppm HPAM3630 in addition to the synthetic injection brine. After the ASP solution injection, 0.5 PV of the alkaline–polymer solution was injected which included 10,000 ppm NaBO24H2O and 4500 ppm HPAM3630 in the synthetic injection brine. After the alkaline-polymer solution, 0.5 PV of the polymer solution was injected which included only 4500 ppm HPAM3630 in the synthetic injection brine and, at last, only synthetic injection brine (about 3 PV) was injected. Fig. 9a shows the oil recovery during the secondary ASP flood. Most of the oil was recovered within the first 1.5 PV of injection. The residual oil saturation was reduced to 3.1% at the end of the flood. Cumulative oil recovery for the ASP
Fig. 8. pH of effluent brine, Core Flood #1.
Fig. 9a. Oil recovery during secondary chemical flooding, Core Flood #2.
Type III
Fig. 9b. Pressure drop during the secondary chemical flooding, Core Flood #2.
Fig. 7. Salinity of effluent brine, Core Flood #1.
flood was 95.6% OOIP. Table 4 summarizes the oil recovery in the coreflood. Fig. 9b shows the pressure drop during the ASP and polymer phases of the secondary coreflood. The pressure drop started at
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Fig. 13. Measured and calculated polymer viscosity.
Fig. 10. Conductivity and pH of effluents, Core Flood #2 (The solutions were diluted 20 times to measure conductivity).
Table 5 UTCHEM polymer and surfactant input parameters. Polymer parameters
Surfactant parameters
Ap1 = 700 Ap2 = 900 Ap3 = 1700 Sp = 0.38 c_ 1=2 = 0.8 P a = 1.8
CSEL7 = 0.6; CSEU7 = 1.3 Hblc71 = 0.03; Hblc71 = 0.07; Hblc72 = 0.03
Table 6 List of elements and reactive species. Elements or pseudo-elements
Fig. 11. Concentration of surfactants in effluent samples and cumulative oil recovery, Core Flood #2.
Independent species Dependent species Surfactant associated cations
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about 10 psi, decreased a little bit and then increased to about 30 psi during alkaline polymer flooding and further increased to about 40 psi. The increasing pressure drop shows that the ASP flood was stable. The effluent pH and salt conductivity are plotted together in Fig. 10. The pH is almost constant from 1 to 4 PV and starts to decrease when sodium metaborate is no longer injected. The conductivity also starts to decrease after about 2.5 PV of injection. The effluent surfactant concentration is shown in Fig. 11. The individual surfactant concentrations are not shown here, but the two surfactants moved together through the core. The retention of surfactant in the core was calculated from the effluent surfactant
Calcium, magnesium, sodium, hydrogen (reactive), sulfate, tetrahydroxy borate, oleic acid Ca2+, Mg2+, Na+, H+, SO42, CO32, B(OH)4, HAo, H2O OH, H2CO3, HCO 3 , B(OH)3, HAw, A Na+, Ca2+
concentration by material balance. The retention was 0.127 mg of the surfactant per gram of the core which is a reasonably low value (<0.3 mg/gm) for field application. It should also be noted that the dynamic retention value is lower than the static adsorption values of 0.4–0.75 mg/gm.
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3.4. Simulation
396
The surfactant phase behavior [8,9] is modeled in UTCHEM using the Hand representation of the ternary diagram[25] and the UTCHEM input parameters for these simulations were obtained from matching the experimental data. The comparison of the modeled and the measured solubilization ratio for water–oil-ratio (WOR) of 1 is shown in Fig. 12. The importance of obtaining phase behavior at different WOR is important because the optimal salinity changes with the ratio of soap and surfactant, as described by Salager et al. [26] and Mohammadi et al. [22]. Soap is the in-situ generated surfactant due to the reaction of the acidic components of crude oil and the injected alkali. The UTCHEM parameters for modeling polymer viscosity are based on the Flory–Huggins equation
397
l
0 p
¼ lw 1 þ Ap1 C 4l þ Ap2 C 24l þ Ap3 C 34l C Sp SEP
ð1Þ
and the Meter’s equation
lp ¼ lw þ Fig. 12. Measured and calculated solubilization ratios at water–oil ratio of 1.
l lw 0 p
1þ
c_ c_ 1=2
Pa 1
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398 399 400 401 402 403 404 405 406 407 408 409
410 412 413
414
ð2Þ
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Table 7 Input for 1-D secondary and tertiary ASP flooding simulation. Number of grids Components present
Porosity Permeability Water viscosity (@ 38 °C) Oil viscosity(@ 38 °C) Residual oil saturation Residual water saturation Water endpoint relative permeability Oil endpoint relative permeability Injection Schedule
417 418 419 420 421 422 423 424
50 1 1 Water, oil, surfactant, polymer, chloride, calcium, magnesium, carbon (as carbonate), sodium, hydrogen (reactive), sulfate, B(OH)4, HAo 0.18 80 mD 0.85 cP 105 cP 0.43 0.30 0.05 1.0 0.3 PV ASP slug 0.5 PV polymer 1 0.5 PV polymer 2
The parameters were obtained from matching the experimental data. Note that Eq. (1) is the modified form of the original equation which takes into account the effect of salinity on polymer solution viscosity. Here Ap1, Ap2, Ap3 and Sp are the fitting parameters to obtain polymer viscosity for a particular polymer concentration at the zero share rate. c_ 1=2 and Pa in Eq. (2) take into account the reduction in polymer viscosity with shear rate, c_ , which is calculated from the Blaze–Kozeny capillary bundle equation [27]. There
is a reasonable agreement between the modeled and the measured viscosity, as can be seen from Fig. 13. The modeling parameters for polymer and surfactant are given in Table 5. Since the alkali plays an important role in ASP process by generating an in-situ surfactant and reducing surfactant adsorption on the rock surface, it is important to understand its propagation in the reservoir. In order to do so, it is important to model all the relevant alkali reactions that could lead to its consumption such as reaction with the rock surface. The geochemical species considered in these simulations are given in Table 6. For simplicity, some of the aqueous species that are less likely to be present under the experimental conditions were not considered in these calculations. The thermodynamic data was taken at the reservoir temperature, that is 38 °C, and EQBATCH was used to perform the equilibrium calculations. Other input parameters of the UTCHEM simulations are listed in Table 7. The comparisons of the experimental and simulated oil recovery data for the secondary and the tertiary ASP floods are given in Figs. 14 and 15, respectively. In the case of secondary ASP, only oil is produced at the start of the experiment, then the oil cut drops to about 0.6 which falls to zero in about 1 PV injection. In the case of tertiary ASP, the oil cut is zero until the oil bank breakthrough at around 0.25 PV injection, then it rises to about 0.5 before decreasing to zero again at about 0.8 PV injected, in the simulation. In both the cases, the simulation data matches reasonably well with the experimental data; the oil production continues for a longer time in the experiments. Experimental data for surfactant phase behav-
Fig. 14. Measured and simulated oil recovery, oil cut and residual oil saturation for the secondary ASP coreflood.
Fig. 15. Measured and simulated oil recovery, oil cut and residual oil saturation for the tertiary ASP coreflood.
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Fig. 16. Calculated oil saturation profile for the secondary and the tertiary ASP corefloods at 0.2 PV injection.
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ior, polymer viscosity, and surfactant adsorption were critical in matching the experimental results. Fig. 16 shows the simulated in situ oil saturation profiles at 0.2 PV injection for both the ASP floods. There are three saturation jumps in each case. At about xd = 0.075, oil saturation jumps from 0 to 0.13; This jump is between the oil left after solubilization and the residual oil saturation left after mobilization. The solubilization front moves very slowly and is irrelevant to oil recovery after 1 or 2 PV injected. The second jump is at about xd = 0.2–0.4; oil saturation increases slowly from 0.13 to about 0.6 (the oil bank saturation). The third jump is at xd = 0.72; saturation jumps from 0.6 to its initial value. In the case of secondary ASP flooding, the initial oil saturation is about 0.7 whereas for the tertiary flood, it is about 0.42. These saturation profiles are similar to those expected from the fractional flow theory of ASP processes discussed by Pope [28]. As salinity increases, the microemulsion phase behavior transitions from type I to type III to type II [29]. For a successful ASP operation, it is important to attain an ultralow IFT in the reservoir; Winsor type III microemulsion gives an ultralow IFT. It is necessary to have a correct salinity gradient in an ASP flood design to be able to encounter the type III region. The simulated salinity profile shows that type III salinity is achieved at the surfactant bank (not shown here). The presence of surfactant and type II salinity leads to ultralow IFT which mobilizes the oil. The presence of polymer controls the mobility and pushes the oil out in a stable manner. The simulated salinity profile shows that correct salinity gradient was achieved in the corefloods (not shown here). These experiments and simulations show that the secondary ASP flood is slightly more effective than the tertiary ASP flood. In viscous oil reservoirs, one cannot inject more than one or two pore volumes of fluid because of the high viscosity of the oil. Thus tertiary ASP floods would not be conducted after long water floods. One must consider secondary ASP floods or an ASP flood after a short water flood.
486
4. Conclusions
487
The contributions of this study are the development of an ASP formulation for a viscous oil in a carbonate reservoir using sodium metaborate as alkali, the comparison of sodium carbonate and sodium metaborate as alkali for carbonate rocks, the comparison of secondary and tertiary ASP floods, and modeling of the floods including geochemical reactions. The following conclusions can be drawn from this work.
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An ASP formulation using sodium metaborate has been developed that gives low IFT and type III phase behavior with the viscous reservoir oil and the injection brine. Sodium metaborate was found to be equally effective as sodium carbonate in reducing surfactant adsorption on Silurian dolomite. Waterflood of the viscous oil in a carbonate core recovered about 47.8% of the oil in place and reduced the oil saturation to 43.8%. The tertiary ASP flood increased the cumulative oil recovery to 92.7% whereby the oil saturation was reduced to 6.1%. The secondary ASP coreflood in the same core reduced the oil saturation to 3.1% and recovered 95.6% of the oil in place. The secondary ASP flood should be considered if the reservoir is not already water flooded. Sodium metaborate was effective in the ASP formulation prepared in the softened injection brine for the carbonate rock with the hard connate brine. The UTCHEM simulation results (including the geochemical reactions) match well with the experimental results for both the secondary ASP and the tertiary ASP floods. Experimental data for surfactant phase behavior, polymer viscosity, and surfactant adsorption were critical in matching the experimental results.
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Acknowledgements
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The authors would like to thank the industrial affiliates of the Chemical Enhanced Oil Recovery Project at the University of Texas at Austin for the financial support.
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References
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