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Condensate blockage alleviation around gas-condensate producing wells using wettability alteration
Journal of Natural Gas Science and Engineering 62 (2019) 214–223
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Condensate blockage alleviation around gas-condensate producing wells using wettability alteration
T
Seyed-Ahmad Hoseinpoura, Mehdi Madhia, Hamidreza Norouzia, Bahram Soltani Soulgania,∗, Amir H. Mohammadib,c,∗∗ a
Department of Petroleum Engineering, Ahwaz Faculty of Petroleum Engineering, Petroleum University of Technology (PUT), Ahwaz, Iran Institut de Recherche en Génie Chimique et Pétrolier (IRGCP), Paris Cedex, France c Discipline of Chemical Engineering, School of Engineering, University of KwaZulu-Natal, Howard College Campus, King George V Avenue, Durban, 4041, South Africa b
A R T I C LE I N FO
A B S T R A C T
Keywords: Gas condensate Wettability alteration Gas wetting Condensate blockage Spontaneous imbibition Contact angle
In the current survey, a novel fluorocarbon-based wettability modifier chemical is proposed to alter the wettability of sandstone rock surface from liquid wetting to preferentially gas wetting condition. Several experimental tests describing wettability condition of the rock surface including static contact angle measurements, spontaneous imbibition and dynamic core flooding using water and n-decane fluids were conducted on untreated and treated sandstone rock to investigate the effect of the proposed chemical on surface wetting behavior. Adsorption of fluorinated chemical on sandstone surfaces was characterized using FTIR and SEM. Elemental analysis of rock surface after treatment was determined by EDX analysis and EDX map. After chemical treatment of sandstone thin section, contact angles of water and n-decane in air-liquid-rock system were altered from 0° and 0° to 151° and 101°, respectively. Spontaneous imbibition of water and n-decane as imbibing liquid fluids into the core sample saturated with dry air at room temperature on untreated and treated core showed that the ultimate amounts of liquid imbibitions were decreased to factors of 0.03 and 0.16 PV, demonstrating wettability alteration from strongly condensate-and water-wet to preferentially gas-wet condition, respectively. Also, the results of core flooding experiments demonstrated the improvement of liquid phase mobility as a result of treatment with proposed chemical fluid by factors of 3.85 and 3.5 for water and n-decane, respectively. The outcome of this integrated study proposes that fluorochemical agents can be considered as a promising candidate for possible field applications to alleviate both condensate and water blockage in gas condensate reservoirs by wettability alteration technique.
1. Introduction Gas condensate reservoirs make up a high percentage of gas fields. Water accumulation and condensate banking due to reduction of single phase fluid's pressure below its dew point pressure and existence of heavy hydrocarbon components in gas-condensate fluid in near wellbore region may lead to significant well productivity decline (Jin et al., 2016; Kumar et al., 2006; Najafi-Marghmaleki et al., 2016). In the literature, several remediation techniques have been proposed to alleviate the condensate accumulation and improve the productivity of producing well (Al-Anazi et al., 2003; Asgari et al., 2014; Mahdiyar and Jamiolahmady, 2014; Muladi and Pinczewski, 1999; Sanger and Hagoort, 1998; Marokane et al., 2002; Fishlock and Probert, 1996). Wettability alteration of region located in the vicinity of wellbore
∗
towards gas wetting state as a potentially permanent and long-term effective treatment method was first introduced by Li and Firoozabadi (Kewen and Abbas, 2000). Effect of type of wettability induced onto the rock surface on two phase fluid distribution and flow in porous media was the reason for introduction of the aforementioned method for liquid blockage remediation. The original surface characteristics of rock before treatment was in liquid wetting condition, therefore, the liquid phases, condensates and water, tend to imbibe into the smaller sections of the pores inside the rock. In the presence of gas-liquid-rock system in rock sample, the liquid phase was considered strongly wetting phase. Adhesion and imbibition of liquid droplets into the rock as well as spreading of liquid phase onto the rock surface was happened due to high capillary force of strongly wet condition in porous media and high surface free energy, respectively. These aforementioned conditions and
Corresponding author. Corresponding author. Petroleum University of Technology (PUT), Ahwaz, Iran. E-mail addresses: [email protected] (B.S. Soulgani), [email protected] (A.H. Mohammadi).
∗∗
https://doi.org/10.1016/j.jngse.2018.12.006 Received 10 February 2018; Received in revised form 4 December 2018; Accepted 5 December 2018 Available online 07 December 2018 1875-5100/ © 2018 Elsevier B.V. All rights reserved.
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drawdown in the vicinity of the wellbore. Rahimzadeh et al. conducted compositional single well simulations based on the real data obtained from lean gas condensate field. They investigated the effect of condensate blockage on well deliverability reduction and pressure drawdown in near wellbore region of gas condensate reservoirs followed by corresponding skin values. The dominant parameters evaluated in the developed models were rock properties (KH), rock-fluid properties and well production rate. Their simulations showed that pressure drop could be increased up to two times of pressure drop in tubing due to condensate blockage in poor reservoir quality (Rahimzadeh et al., 2016). More recently, Gahrooei and Ghazanfari investigated thoroughly kinetics of SurfaPore M adsorption onto sandstone surface and adsorption behavior model. They found that equilibrium adsorption data were in good agreement with Freundlich isotherm model, indicating multilayer adsorption of proposed chemical onto the sandstone grains. They also conducted displacement tests on two core samples with high and low permeabilities to study the performance of chemical treatment in different porous media. The results obtained in coreflooding section showed that SurfaPore M should be used in high permeability reservoirs and could cause permeability reduction in low permeability reservoir (Gahrooei and Ghazanfari, 2017a). A new hydrocarbon based solution of fluoropolymers was introduced for gas wetting of sandstone and carbonated rock surfaces and its effectiveness on wettability alteration towards gas wetting condition was investigated thoroughly using different experimental techniques including dynamic and static contact angle measurements, liquid phase spontaneous imbibition, core displacement tests and surface characterization methods such as SEM, EDX, EDX map and FTIR tests. They proposed for the first time application of hydrocarbon based wettability modifier for sandstone and carbonate rocks (Gahrooei and Ghazanfari, 2017b). Franco-Aguirre et al. successfully synthesized functionalized SiO2 nanoparticles using an anionic fluorinated surfactant Silnyl®FSJ that could induced the gaswet state on sandstone in tight gas-condensate reservoirs. After chemical treatment of the core sample, the gas mobility was increased 24%. Performance of the injected nanofluid was evaluated using displacement tests under gas-condensate reservoirs conditions. In addition, wetting condition of core samples before and after nanofluid injection was examined through contact angle measurements and spontaneous imbibition tests (Franco-Aguirre et al., 2018). In the current study, a new water based C8 fluorocarbon solution was introduced for gas wetting of sandstone rock surface and its effectiveness on wettability alteration of sandstone rock towards gas wetting condition was examined thoroughly. First, materials and experimental methods employed in the study are explained, then static contact angles of water and normal-decane phases on the treated and untreated sandstone thin sections were measured to study the impact of wettability modifying chemical on contact angle values as an early detection method. Sandstone rock was coated by proposed chemical and adsorption of chemical onto the rock surface was approved using surface characterization techniques including FESEM, EDX, and EDX map. Then, Fourier Transform Infrared (FTIR) Spectroscopy analysis was performed to detect the functional groups formed between proposed chemical and rock surface. Finally, core scale experiments such as spontaneous imbibition and unsteady displacement tests were performed to describe the effect of fluorochemical adsorption on gas-liquid flow behavior in porous media of rock.
strongly liquid wetting condition of rocks resulted in high value of critical condensate saturation up to 30%–50% and remarkable reduction in gas relative permeability (Anderson, 1987a, 1987b). After wettability alteration of reservoir rock towards intermediate gas wetting or preferentially gas wetting state, the interfacial tension (IFT) between solid surface and liquid phase was reduced greatly, therefore, the liquid droplets had no more tendency to imbibe and penetrate into the smaller void spaces of rock. Additionally, a portion of the liquid phase existing in near wellbore zone was pushed towards the production well due to the drag force acting on liquid phase in near wellbore region by high velocity gas flow. Critical condensate saturation was decreased due to the aforementioned factors and gas relative permeability reduction was avoided. Therefore, liquid blockage issue due to condensate build-up or water accumulation was alleviated in the regions where wettability of reservoir rock surface altered towards preferentially gas wetting state followed by no decrease in well productivity. Pore network modeling technique was performed by Li and Firoozabadi (2000) to investigate the impact of various influencing factors on the gas condensate producing well performance. They concluded that the wettability characteristic of reservoir formation around the wellbore should be considered as one of the main effective parameters in well productivity and deliverability of well could be increased up to a factor of 1.35 by wettability alteration towards gas wetting state. Wettability alteration of rock samples towards gas wetting state was first proposed by Li and Firoozabadi, as mentioned earlier (Kewen and Abbas, 2000). They altered the wettability of rocks using two commercial fluoropolymers, FC722 and FC754. Effect of wettability alteration of rock surface towards gas wetting condition on liquid and gas relative permeability curves was investigated by Tang and Firoozabadi (2000). They concluded that by employing the gas wetting condition on rock surface, the liquid relative permeability improves greatly but no definite result was obtained for gas relative permeability improvement. Gas relative permeability value may decrease or enhance at a fixed saturation (Fahes and Firoozabadi, 2007; Panga et al., 2007). Mousavi et al. (2013) altered the wettability of limestone core samples using fluorinated nano silica. Polymeric fluoro-surfactant was synthesized by Sharifzadeh et al. (2013) to make the pore walls of reservoir rocks gas wet. In their study, contact angle measurements of water and n-decane on thin slices of reservoir rock in the atmosphere and n-decane/waterair spontaneous imbibition tests were employed to analyze the effectiveness of synthesized chemical. Aminnaji et al. (2015) applied commercial oil and water repellent, namely SurfaPore M, on sandstone and carbonate core samples to induce gas wetness condition. The nanofluid chemical used in their study altered the wettability condition of both carbonated and sandstone core samples after treatment with chemical. They analyzed the applicability of proposed chemical by conducting dynamic and static contact angle measurements, liquid phase spontaneous imbibition, and dynamic coreflooding tests. In addition, EDX, EDX map and SEM analyses as surface characterization methods were performed to clearly demonstrate the adsorption of chemical on rock surface. Simulation study was performed on a huge gas condensate field located in south of Iran by Sheydaeemehr et al. (2014). They investigated the impact of three different relative permeability curves and determined the differences in three distinctive wetting conditions including strongly liquid, intermediate and preferentially gas wetting condition on field cumulative production. They concluded that wettability condition of reservoir rocks affected significantly well productivity and the best wetting condition found to be intermediate gas wetting. Field trial chemical treatment for condensate blockage alleviation of Saudi Arabian gas condensate reservoir was reported by Al Ghamdi et al. (Al Ghamdi et al., 2013). Well productivity was severely decreased due to liquid blockage. After chemical treatment with nonionic fluorosurfactant, gas and condensate flow rates were enhanced by factors of 1.75 and 4, respectively. In addition, flowing well head pressure was increased by a factor of 1.9 indicating decrease in pressure
2. Materials and experimental methods 2.1. Materials In this study, sandstone rock was used for evaluation of effectiveness of wettability alteration of rock surface towards gas wetting condition. In the static contact angle measurement tests, sandstone discs with 2–4 mm thickness were used and crushed powders of sandstone rock were employed for all surface characterization tests including 215
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Fig. 1. Schematic of the setup used for static contact angle measurement.
Fig. 2. Schematic of spontaneous imbibition setup for air-liquid system, (1): Electrical balance, (2): Data acquisition system, (3): Core sample immersed in liquid phase.
Fig. 3. Schematic of core flooding apparatus.
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Fig. 4. Static contact angles over a period of time for water-air system (below) and n-decane-air system (above) on sandstone thin section after treatment.
washed with toluene and methanol, then they were dried with nitrogen gas then placed in oven at 100 °C for 1 day. The clean, dried thin sections were submerged in Tubiguard Protect 5 w.t. % solution, and aged at 50 °C for 1 day. The glass container of thin sections submerged in Tubiguard Protect should be sealed carefully to avoid any vaporization. After that aging time of samples finished, the final treated substrates were dried with nitrogen gas then placed in oven at 70 °C for 24 h. For SEM, EDX, and FTIR tests, crushed sandstone powders were used. They were first washed with toluene and methanol then placed in an oven fixed at a temperature of 100 °C for 24 h to dry samples carefully. Clean sandstone powders were aged in chemical solution for 1 days at 50 °C, same as thin sections. Coated samples were dried with pure nitrogen gas and placed at 70 °C for 24 h and then used for SED, EDX analysis and FTIR. Fig. 5. Clear depiction of water and n-decane droplets on the treated substrate with proposed chemical.
2.2.2. Contact angle A first and promising method to study the wetting condition of rock surface was performed by measuring the contact angles for the sandstone samples before and after treatment with wettability modifier material. The schematic of the static contact angle measurement apparatus is depicted in Fig. 1. The contact angle measurement tests were processed in (water or n-decane)/air/rock systems at room temperature. Water and n-decane drops of 5 μL were placed onto the untreated and treated sandstone thin section. Photographs of liquid droplets placed on the rock surface were taken over a period of time until stable condition was reached using a digital camera (220x Dino-Lite Microscope) positioned at a horizontal viewing angle of the thin section. The obtained photographs by means of the digital microscope were processed using Lab-view software. The droplet volume was under control through entire contact angle measurement tests with a 5 μL syringe so that the impact of gravity and drop sizes of water and n-decane on contact angles were avoided. The measurements were repeated in 5 different positions over the thin section surface.
SEM, EDAX, EDX map, and FTIR. Brine and n-decane were used as representatives of water and condensate phases for hydrophobicity and oleophobicity investigation of the surfaces. Air and nitrogen were utilized as the gas phases in static contact angle and spontaneous imbibition tests. Outcrop sandstone core sample with porosity and permeability of 17.6% and 110 md, respectively, was used for spontaneous imbibition and core displacement tests. Core displacement tests were performed by laboratory made apparatus as shown in Fig. 3. Tubiguard Protect fluorocarbon manufactured by CHT Company in Germany was used as a water and oil repellent agent, to alter the wetting condition of sandstone rock from strongly liquid wetting to gas wetting. Tubiguard Protect chemical was based on C8 fluorocarbon. Adsorption of fluorocarbon onto the rock surface can lead to induce water and oil repellency to the substrate. Tubiguard Protect has a specific weight of 1 at 25 °C and was white-colored. It is worth mentioning that ionic character of Tubiguard Protect was cationic with a pH value of 4.5–6.5. Cationic character of Tubiguard Protect could improve the adsorption onto the rock surface with anionic characteristic.
2.2.3. SEM and EDAX analysis Energy dispersive X-ray analysis (EDXA, model TESCAN MIRA3, Czech Republic) technique was used for elemental analysis of the treated samples. Higher value determination of fluorine and carbon elements in EDX analysis was an indication of more chemical adsorption. In the next phase, EDX map of fluorine and carbon elements were recorded from the coated samples to investigate the coating quality. High resolution images of surface topography, with five different magnifications and great depth of focus, were acquired by means of a Scanning electron microscopy (SEM, TESCAN MIRA3, Czech Republic)
2.2. Procedures 2.2.1. Preparation of thin sections and treated samples Sandstone rock was cut into radial cross section thin plates by means of a trimming machine. Radial sandstone thin sections with a diameter of 3.7 cm and thickness of 2–4 mm were burnished with a grinder to have a smooth surface. Prepared thin sections were initially 217
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Fig. 6. SEM images of treated sandstone rock at different magnifications. A: 500x, B: 1000x, C: 1000x, D: 5000x, E: 10000x, F: 50000x.
Fig. 7. EDX analysis on sandstone rock after treatment with Tubiguard Protect chemical agent.
would occur. Then, the FTIR spectra of the sample was recorded using Attenuated Total Reflection Infrared spectrometer (Bruker Co., USA) in the spectral domain of 400–4000 cm−1 and resolution of 4 cm−1.
at room temperature. 2.2.4. FTIR analysis Adsorption of Tubiguard Protect fluorocarbon on sandstone rock surface could be confirmed by FT-IR analysis. To do this, a little amount of Tubiguard Protect-modified sandstone powder was mixed with KBr salt as a carrier for the sample in IR spectrum then pressed into a disk. KBr was optically 100% transparent in the range of wavelengths (4000400 1/cm) of IR measurement. Therefore, no interference in absorbance
2.2.5. Spontaneous imbibition Spontaneous imbibition test was proposed by many researchers to demonstrate the wettability alteration of rock from liquid wet to gaswetting condition. This test shows the tendency of liquid to imbibe into the core initially saturated with dry air. The amount of liquid imbibed 218
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not changed within 20 min. The water contact angle was measured at 180 min after placement on the sandstone substrate and a value of 151° was obtained. In addition, θC10-air decreased from its initial contact angle of 110°–105° within 20 min, whereas θ reduced to 101° over the 180 min. Clear depiction of water and n-decane droplets on the treated substrate is given in Fig. 5. The results obtained in this section demonstrated that the wettability modifier chemical was able to alter the wettability of rock surface towards preferentially gas wetting condition.
Table 1 The energy dispersive X-ray quantitative results of treated surface. Element
Line
Int
K
Kr
W%
A%
ZAF
Pk/Bg
C O F Na Mg Al Si
Ka Ka Ka Ka Ka Ka Ka
53.5 952.8 39.2 0.0 0.0 25.0 943.2
0.0252 0.4560 0.0189 0.0000 0.0000 0.0127 0.4871 1.0000
0.0129 0.2336 0.0097 0.0000 0.0000 0.0065 0.2495 0.5122
8.62 54.36 5.14 0.00 0.00 0.90 30.97 100.00
13.00 61.53 4.90 0.00 0.00 0.61 19.97 100.00
0.1496 0.4297 0.1888 0.4583 0.6201 0.7203 0.8057
5.46 70.81 3.39 2.00 2.00 2.84 28.68
3.2. Surface characterization experiments Different surface characterization techniques were applied in this study for clear depiction and representation of chemical adsorption on to the sandstone rock surface. SEM images of untreated and treated surfaces were obtained for heterogeneity characterization. In addition, for elemental analysis and determination of distribution of adsorbed elements on the coated surface, EDX analysis and EDX map were used, respectively. SEM images at different magnifications for sandstone rock before and after chemical adsorption following wettability alteration are depicted in Fig. 6. Comparison of treated rock SEM images with untreated rock clearly demonstrated that a film of chemical was formed on the surface of the rock coated with Tubigaurd Protect oil and water repellent chemical. As mentioned earlier, EDX analysis was utilized in this study. EDX analysis can be used as a surface characterization technique to verify the adsorption of desired chemical and determine the elements of formed layer on the sandstone rock after wettability alteration. EDX analysis of the treated rock is depicted in Fig. 7. It can be concluded from Fig. 7, that the fluorine and Carbon elements were detected on treated surface approving the layer formation on rock surface. Chemical layer formation on the rock surface may lead to reduction in surface free energy and liquid repellency inducement to rock surface. The energy dispersive X-ray quantitative results of treated surface are presented in Table 1. The results of the EDAX test can be used to identify principal chemical elements on the treated sandstone surfaces. In addition, EDX map of various elements on treated sandstone rock surface is depicted in Fig. 8. Pink and yellow dots in Fig. 8 indicate fluorine and carbon atoms which were constituting elements of Tubiguard Protect. Blue and green dots are representatives for Oxygen and Silicon atoms exist in virgin sandstone rock. It can be concluded from comparison of these images, a homogenous and uniform layer of fluorine network was formed on the rock grains due to adsorption of the Tubiguard Protect fluorocarbon on sandstone surface inducing liquid (water and oil) repellency on rock surfaces. Consequently, water and oil repellency characteristics can be induced by formation of coating on the rock surface which contains large amount of fluorocarbon groups.
into the core demonstrates the degree of wettability alteration towards gas wetting condition. The schematic of setup employed for imbibition tests is depicted in Fig. 2. As shown in the figure, the air saturated core was immersed completely in the liquid phase (water or n-decane). The change in weight of core, indicating the amount of liquid imbibition, was measured versus time using an electrical balance. Water phase used in this section was composed of 2 w.t. % NaCl to prevent clay swelling. Imbibition tests were conducted for untreated and treated sandstone rock. 2.2.6. Core displacement Core displacement test was applied in this study to determine the mobility of liquid phases in the initially nitrogen saturated core. Fig. 3 depicts the schematic of coreflood system designed for displacement test. In this section, liquid phases (water or n-decane) were injected at a flow rate of 120 cc/hr into the initially gas saturated sandstone core sample and pressure drops through the core were recorded using data acquisition system. Decrease in pressure drop during displacement test convey the message that, larger pores were occupied by liquid phase, indicating mobility improvement of liquid phases due to presence of lower capillary pressure in larger pores. The chemical treatment stage was performed by injecting 20 PVs of Tubiguard Protect chemical into the core sample at 50 °C. Exposing the rock surface to considerably larger amount of chemical agent by injecting 20 PVs of treatment fluid through the core can effectively render it water and oil-repellent. 3. Results and discussion 3.1. Contact angle The contact angle measurements as a first and promising analysis technique were conducted to evaluate the effectiveness of the Tubiguard Protect fluorochemical on the treatment of sandstone substrate. On the basis of water and n-decane contact angles obtained for the treated thin section over a period of time until stable condition in which were shown in Fig. 4, it could be concluded that employing 5 w.t. % Tubiguard Protect chemical as a wettability modifier agent resulted in satisfactory contact angles representing wettability alteration from strongly liquid wetting state to preferentially gas wetting condition. As demonstrated in Fig. 4, the contact angle of water droplet was
3.3. FTIR analysis FTIR analysis of fluorocarbon-modified grains is depicted in Fig. 9. The compressed alkali metal halide pellet method was used to measure
Fig. 8. EDX map of different elements on treated sandstone rock surface. 219
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Fig. 9. FTIR spectrum of Tubiguard Protect coated sandstone rock.
Fig. 10. Transient behavior of air-water spontaneous imbibition versus time into the air saturated sandstone core sample before and after wettability alteration with the proposed chemical for sandstone rock.
Fig. 11. Transient behavior of air-n-decane spontaneous imbibition versus time into the air saturated sandstone core sample before and after wettability alteration with the proposed chemical for sandstone rock.
the FTIR spectrum. Fluorocarbon-modified sandstone exhibited the major adsorption peaks as shown in Fig. 9. Possible existing functional groups were CeO stretch, carboxylate groups (1340–1440 cm−1), CeF stretch (1170–1215 cm−1), CeO bend, carboxylate (775–805, 715–735 cm−1), CeO stretch, carboxylate (1620–1695 cm−1), SieO stretch (830–955 cm−1), and OeH stretch (3200–3700 cm−1). These peaks convey the message that the fluorocarbon based chemical was adsorbed onto the rock surface. Consequently, on the basis of obtained results in surface characterization tests and manufacturer technical datasheet, surface active agent of Tubiguard Protect wettability modifier chemical contains carbon and fluorine atoms.
spontaneous imbibition tests. As mentioned earlier, imbibition test apparatus shown in Fig. 2 was employed for liquid imbibition measurements. The amount of liquids imbibed into the core sample was recorded then plotted in a diagram versus time. The liquids selected as representatives of water and condensate phases were 2 w.t. % NaCl brine and n-decane, respectively. The core sample was initially saturated with air before any imbibition test. Fig. 10 demonstrates the water-air imbibition test results before and after chemical treatment. The ultimate amounts of water imbibition into the core sample before and after chemical treatment were found to be 0.625 PV and 0.033 PV, respectively. After chemical treatment, the imbibition tendency of water phase into the core sample in the presence of air was decreased significantly, indicating wettability alteration of core sample from strongly water wet to gas wetting condition. Similar to previous figure, the obtained results of air-n-decane imbibition tests are demonstrated in Fig. 11. The imbibition amount of n-decane was decreased from
3.4. Liquid imbibition Effect of wettability alteration of core sample towards gas wetting condition with Tubiguard Protect was studied by conducting liquid-air 220
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Table 3 Basic assumptions for economic evaluation. Gas price (USD/Mscf) Production time (day) Downtime for injection (hr) Volume of treatment fluid injected (bbl) Price of TUBIGAURD PROTECT (USD/Kg) Concentration (wt %) Water Injection price (USD/bbl)
3.84 365 72 1119 13.2 5 10
Table 4 Gas flow rates before and after treatments. Cases
Gas flow Rate, Mscf/day
Blockage (Before treatment) Blockage (After treatment)
26,957.26 46,084.08
3.5. Core flooding Core displacement tests were conducted using coreflood setup shown in Fig. 3. Unsteady state displacements of liquid phases through the core initially saturated with nitrogen gas were performed to determine the liquid phase mobility before and after chemical treatment. Liquid phases were injected at a flow rate of 120 cc/hr through core sample initially saturated with nitrogen gas. The pressure drops of water and n-decane injection alongside the core were recorded and are demonstrated in Figs. 12 and 13, respectively. It could be seen from both figures that the pressure drop across the core sample decreased significantly after chemical treatment. Reduction of water and n-decane flooding pressure drop was an indication of ability of Tubiguard Protect to alter the wettability of core sample from liquid wetting condition to gas wetting. When water phase was injected into the untreated core sample under strongly water wetting condition, the water tends to occupy smaller pores (high pressure drawdown) followed by high capillary pressure. After chemical treatment of core sample, as water phase was injected into the treated core under gas wetting condition, water tends to occupy larger pores facing lower capillary pressure which resulted in lower pressure drawdown, therefore mobility of water phase was improved. Similar to water injection, after chemical treatment, as n-decane was injected into treated core sample under gas wetting condition, n-decane tends to occupy larger pores. Pressure drawdown of n-decane displacement through the core was reduced since lower capillary pressure exists in larger pores, therefore mobility of n-decane was improved. Therefore, inducing gas wetting condition in the core sample may lead to increase in endpoint relative permeability of liquid phases (water or n-decane) (Gahrooei and Ghazanfari, 2017b). On the basis of obtained steady state pressure drops, water and n-decane mobilities at residual gas saturation increased by factors of 3.85 and 3.5 for treated core with Tubiguard Protect, respectively.
Fig. 12. Pressure drop across sandstone core sample versus pore volumes injected for 2 w.t. % NaCl brine before and after treatments.
Fig. 13. Pressure drop across sandstone core sample versus pore volumes injected for n-decane before and after treatment. Table 2 Typical Parameters for the well. Average Porosity (%) Absolute Permeability (md) Initial reservoir pressure (psia) Formation thickness (ft) Treatment radius (ft) Reservoir Temperature (F) Dew point pressure (psia) rw (Wellbore radius, ft) re (External radius, ft) krg (Before treatment) krg (After treatment)
20 10 7000 100 10 300 3380 0.25 1000 0.21 0.359
4. Economic impact analysis To evaluate the economic impact and practical implication of the proposed chemical for the wettability alteration of near wellbore region which results in enhancement of a gas relative permeability on a representative producing well, some assumptions were made based on the Saikia and Santoso studies (Saikia, 2010; Santoso, 2015). Table 2 lists some typical properties that were assumed for the well. In order to flood the treatment fluid in the wettability treatment process, the producing well was turned into an injection well temporarily, therefore, the lost amount of gas production during downtime for injection was necessary to be considered in the economic analysis (downtime cost). In addition to the aforementioned associated cost for treatment, the cost of the applied chemical for wettability alteration (treatment cost) and injected water (water cost) as a chemical carrier
0.65 PV to 0.159 PV after treatment with Tubiguard Protect. Similar to water imbibition results, the tendency of n-decane to imbibe into the core sample initially saturated with air was decreased after chemical treatment. High degree of water imbibition reduction comparing to ndecane imbibition decrease reinforces contact angle measurement results. 221
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Table 5 Treatment, water, and downtime expenses and profitability of the treatment after one year production. Volume of treatment fluid (bbl)
Treatment cost (USD)
Water cost (USD)
Added revenue value (USD)
1119 Lost time (day) 3
117,427.86 Production rate (Mscf/d) 26,957.26
11,190 Downtime cost (USD) 310,547.63
26,368,985.52
phase mobility values enhanced after fluorinated chemical injection into the core compared with the system in the absence of the same, indicating that the chemical injection modified the wettability of rock surface from a liquid-wet to a gas-wet state.
should be considered in costs associated. Therefore, treatment costs, water costs, and downtime cost were defined in the expenses term to determine the profitability of the treatment. Basic assumptions for economic evaluation are given in Table 3. As can be seen in Table 3, the gas price was 3.84 USD/Mscf as of January 18, 2018 (US Energy Information Administration, 2018). Another is the price of the proposed chemical, which was 13.2 USD per 1 kg (CHT, 2017). The quantity of gas flow rates for cases before and after treatments are presented in Table 4. Incremental gas production after treatment which is difference between gas flow rates before and after treatments is as follows:
Appendix A. Supplementary data Supplementary data to this article can be found online at https:// doi.org/10.1016/j.jngse.2018.12.006. References Al Ghamdi, B.N., Al-Malki, B.H., Al-Kanaan, A., Rahim, Z., Al-Anazi, H.D., 2013. Field implementation of condensate bank removal using chemical treatment. In: International Petroleum Technology Conference. International Petroleum Technology Conference. Al-Anazi, H.A., Walker, J.G., Pope, G.A., Sharma, M.M., Hackney, D.F., 2003. A successful methanol treatment in a gas-condensate reservoir: field application. In: SPE Production and Operations Symposium. Society of Petroleum Engineers. Aminnaji, M., Fazeli, H., Bahramian, A., Gerami, S., Ghojavand, H., 2015. Wettability alteration of reservoir rocks from liquid wetting to gas wetting using nanofluid. Transport Porous Media 109, 201–216. Anderson, W.G., 1987a. Wettability literature survey part 5: the effects of wettability on relative permeability. J. Petrol. Technol. 39 (1) 453-451,468. Anderson, W., 1987b. Wettability literature survey-Part 4: effects of wettability on capillary pressure. J. Petrol. Technol. 39 (1) 283-281,300. Asgari, A., Dianatirad, M., Ranjbaran, M., Sadeghi, A., Rahimpour, M., 2014. Methanol treatment in gas condensate reservoirs: a modeling and experimental study. Chem. Eng. Res. Des. 92, 876–890. Fahes, M.M., Firoozabadi, A., 2007. Wettability alteration to intermediate gas-wetting in gas-condensate reservoirs at high temperatures. SPE J. 12, 397–407. Fishlock, T., Probert, C., 1996. Waterflooding of gas condensate reservoirs. SPE Reservoir Eng. 11, 245–251. Franco-Aguirre, M., Zabala, R., Lopera, S.H., Franco, C.A., Cortés, F.B., 2018. Interaction of anionic surfactant-nanoparticles for gas-Wettability alteration of sandstone in tight gas-condensate reservoirs. J. Nat. Gas Sci. Eng. 51, 53–64. Gahrooei, H.R.E., Ghazanfari, M.H., 2017a. Application of a water based nanofluid for wettability alteration of sandstone reservoir rocks to preferentially gas wetting condition. J. Mol. Liq. 232, 351–360. Gahrooei, H.R.E., Ghazanfari, M.H., 2017b. Toward a hydrocarbon-based chemical for wettability alteration of reservoir rocks to gas wetting condition: implications to gas condensate reservoirs. J. Mol. Liq. 248, 100–111. Jin, J., Wang, Y., Wang, K., Ren, J., Bai, B., Dai, C., 2016. The effect of fluorosurfactantmodified nano-silica on the gas-wetting alteration of sandstone in a CH4-liquid-core system. Fuel 178, 163–171. Kewen, L., Abbas, F., 2000. Experimental study of wettability alteration to preferential gas-wetting in porous media and its effects. SPE Reservoir Eval. Eng. 3, 139–149. Kumar, V., Bang, V.S.S., Pope, G.A., Sharma, M.M., Ayyalasomayajula, P.S., Kamath, J., 2006. Chemical stimulation of gas/condensate reservoirs. In: SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers. Li, K., Firoozabadi, A., 2000. Phenomenological modeling of critical condensate saturation and relative permeabilities in gas/condensate systems. SPE J. 5, 138–147. Mahdiyar, H., Jamiolahmady, M., 2014. Optimization of hydraulic fracture geometry in gas condensate reservoirs. Fuel 119, 27–37. Marokane, D., Logmo-Ngog, A., Sarkar, R., 2002. Applicability of timely gas injection in gas condensate fields to improve well productivity. In: SPE/DOE Improved Oil Recovery Symposium. Society of Petroleum Engineers. Mousavi, M., Hassanajili, S., Rahimpour, M., 2013. Synthesis of fluorinated nano-silica and its application in wettability alteration near-wellbore region in gas condensate reservoirs. Appl. Surf. Sci. 273, 205–214. Muladi, A., Pinczewski, W., 1999. Application of horizontal well in heterogeneity gas condensate reservoir. In: SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers. Najafi-Marghmaleki, A., Tatar, A., Barati-Harooni, A., Choobineh, M.-J., Mohammadi, A.H., 2016. GA-RBF model for prediction of dew point pressure in gas condensate reservoirs. J. Mol. Liq. 223, 979–986. Panga, M.K., Ismail, S., Cheneviere, P., Samuel, M., 2007. Preventive treatment for enhancing water removal from gas reservoirs by wettability alteration. In: SPE Middle East Oil and Gas Show and Conference. Society of Petroleum Engineers. Rahimzadeh, A., Bazargan, M., Darvishi, R., Mohammadi, A.H., 2016. Condensate blockage study in gas condensate reservoir. J. Nat. Gas Sci. Eng. 33, 634–643.
(31,578.50 – 26,957.26) Mscf/day = 19126.82 Mscf/day Incremental revenue per day is as follows:
19126.82 Mscf/day × $3.84/Mscf = $73,446.98/day Incremental revenue per year can be calculated as follows:
$73,446.98/day × 365 days = $26,808,150.912/year Table 5 details the costs incurred in wettability treatment option. Profitability of the wettability treatment after one year gas production is determined on the basis of calculated expenses term including treatment cost, water cost, and downtime cost. 5. Conclusion In this study, a new water based chemical comprised of fluorocarbon was successfully proposed for inducing gas-wetting condition on sandstone rock surface based on the interaction between cationic fluorocarbon and anionic characteristic of sandstone surface. The effects of proposed chemical on hydrophobic and oleophobic properties of sandstone rock surface were investigated and characterized by static contact angle measurements, imbibition tests, and displacement tests. Contact angle of liquid phases on the sandstone thin section indicated wettability alteration from liquid-wet towards gas-wet in all systems. The following conclusions can be drawn on the basis of the obtained results in this study;
• SEM images of untreated and treated surfaces were obtained for
• •
heterogeneity characterization. In addition, for elemental analysis and determination of distribution of adsorbed elements on the coated surface, EDX analysis and EDX map were used, respectively. Comparison of treated rock SEM images with untreated rock clearly demonstrated that a film of chemical was formed on the surface of the rock coated with Tubigaurd Protect oil and water repellent chemical. The fluorine and carbon elements were detected on treated surface approving the layer formation on rock surface. Chemical layer formation on the rock surface may lead to reduction in surface free energy and liquid repellency inducement to rock surface. Additionally, FTIR molecular structure analysis proved the presence of carbon and fluorine functional groups in proposed chemical surface-active agents. Ultimate amount of spontaneous imbibition of water and n-decane into air saturated dry sandstone core sample decreased remarkably from 0.61 and 0.64 pore volume to 0.03 and 0.16 pore volume for untreated and treated sandstone rock, respectively. Dynamic assessment of the proposed chemical showed that liquid 222
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Appl. Polym. Sci. 128, 4077–4085. Sheydaeemehr, M., Sedaeesola, B., Vatani, A., 2014. Gas-condensate production improvement using wettability alteration: a giant gas condensate field case study. J. Nat. Gas Sci. Eng. 21, 201–208. Tang, G.-Q., Firoozabadi, A., 2000. Relative permeability modification in gas-liquid systems through wettability alteration to intermediate gas-wetting. In: SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers.
Saikia, B.D., 2010. Surfactant-induced Flow Behavior Effects in Gas Condensate Reservoirs. Master's thesis. Louisiana State University, USA. Sanger, P., Hagoort, J., 1998. Recovery of gas-condensate by nitrogen injection compared with methane injection. SPE J. 3, 26–33. Santoso, B.D., 2015. Modeling of Near-wellbore Wettability Alteration for Gas Well Liquid Blocking Remediation. Master's thesis. Texas A&M University, USA. Sharifzadeh, S., Hassanajili, S., Rahimpour, M., 2013. Wettability alteration of gas condensate reservoir rocks to gas wetness by sol–gel process using fluoroalkylsilane. J.
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Condensate blockage alleviation around gas-condensate producing wells using wettability alteration
T
Seyed-Ahmad Hoseinpoura, Mehdi Madhia, Hamidreza Norouzia, Bahram Soltani Soulgania,∗, Amir H. Mohammadib,c,∗∗ a
Department of Petroleum Engineering, Ahwaz Faculty of Petroleum Engineering, Petroleum University of Technology (PUT), Ahwaz, Iran Institut de Recherche en Génie Chimique et Pétrolier (IRGCP), Paris Cedex, France c Discipline of Chemical Engineering, School of Engineering, University of KwaZulu-Natal, Howard College Campus, King George V Avenue, Durban, 4041, South Africa b
A R T I C LE I N FO
A B S T R A C T
Keywords: Gas condensate Wettability alteration Gas wetting Condensate blockage Spontaneous imbibition Contact angle
In the current survey, a novel fluorocarbon-based wettability modifier chemical is proposed to alter the wettability of sandstone rock surface from liquid wetting to preferentially gas wetting condition. Several experimental tests describing wettability condition of the rock surface including static contact angle measurements, spontaneous imbibition and dynamic core flooding using water and n-decane fluids were conducted on untreated and treated sandstone rock to investigate the effect of the proposed chemical on surface wetting behavior. Adsorption of fluorinated chemical on sandstone surfaces was characterized using FTIR and SEM. Elemental analysis of rock surface after treatment was determined by EDX analysis and EDX map. After chemical treatment of sandstone thin section, contact angles of water and n-decane in air-liquid-rock system were altered from 0° and 0° to 151° and 101°, respectively. Spontaneous imbibition of water and n-decane as imbibing liquid fluids into the core sample saturated with dry air at room temperature on untreated and treated core showed that the ultimate amounts of liquid imbibitions were decreased to factors of 0.03 and 0.16 PV, demonstrating wettability alteration from strongly condensate-and water-wet to preferentially gas-wet condition, respectively. Also, the results of core flooding experiments demonstrated the improvement of liquid phase mobility as a result of treatment with proposed chemical fluid by factors of 3.85 and 3.5 for water and n-decane, respectively. The outcome of this integrated study proposes that fluorochemical agents can be considered as a promising candidate for possible field applications to alleviate both condensate and water blockage in gas condensate reservoirs by wettability alteration technique.
1. Introduction Gas condensate reservoirs make up a high percentage of gas fields. Water accumulation and condensate banking due to reduction of single phase fluid's pressure below its dew point pressure and existence of heavy hydrocarbon components in gas-condensate fluid in near wellbore region may lead to significant well productivity decline (Jin et al., 2016; Kumar et al., 2006; Najafi-Marghmaleki et al., 2016). In the literature, several remediation techniques have been proposed to alleviate the condensate accumulation and improve the productivity of producing well (Al-Anazi et al., 2003; Asgari et al., 2014; Mahdiyar and Jamiolahmady, 2014; Muladi and Pinczewski, 1999; Sanger and Hagoort, 1998; Marokane et al., 2002; Fishlock and Probert, 1996). Wettability alteration of region located in the vicinity of wellbore
∗
towards gas wetting state as a potentially permanent and long-term effective treatment method was first introduced by Li and Firoozabadi (Kewen and Abbas, 2000). Effect of type of wettability induced onto the rock surface on two phase fluid distribution and flow in porous media was the reason for introduction of the aforementioned method for liquid blockage remediation. The original surface characteristics of rock before treatment was in liquid wetting condition, therefore, the liquid phases, condensates and water, tend to imbibe into the smaller sections of the pores inside the rock. In the presence of gas-liquid-rock system in rock sample, the liquid phase was considered strongly wetting phase. Adhesion and imbibition of liquid droplets into the rock as well as spreading of liquid phase onto the rock surface was happened due to high capillary force of strongly wet condition in porous media and high surface free energy, respectively. These aforementioned conditions and
Corresponding author. Corresponding author. Petroleum University of Technology (PUT), Ahwaz, Iran. E-mail addresses: [email protected] (B.S. Soulgani), [email protected] (A.H. Mohammadi).
∗∗
https://doi.org/10.1016/j.jngse.2018.12.006 Received 10 February 2018; Received in revised form 4 December 2018; Accepted 5 December 2018 Available online 07 December 2018 1875-5100/ © 2018 Elsevier B.V. All rights reserved.
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drawdown in the vicinity of the wellbore. Rahimzadeh et al. conducted compositional single well simulations based on the real data obtained from lean gas condensate field. They investigated the effect of condensate blockage on well deliverability reduction and pressure drawdown in near wellbore region of gas condensate reservoirs followed by corresponding skin values. The dominant parameters evaluated in the developed models were rock properties (KH), rock-fluid properties and well production rate. Their simulations showed that pressure drop could be increased up to two times of pressure drop in tubing due to condensate blockage in poor reservoir quality (Rahimzadeh et al., 2016). More recently, Gahrooei and Ghazanfari investigated thoroughly kinetics of SurfaPore M adsorption onto sandstone surface and adsorption behavior model. They found that equilibrium adsorption data were in good agreement with Freundlich isotherm model, indicating multilayer adsorption of proposed chemical onto the sandstone grains. They also conducted displacement tests on two core samples with high and low permeabilities to study the performance of chemical treatment in different porous media. The results obtained in coreflooding section showed that SurfaPore M should be used in high permeability reservoirs and could cause permeability reduction in low permeability reservoir (Gahrooei and Ghazanfari, 2017a). A new hydrocarbon based solution of fluoropolymers was introduced for gas wetting of sandstone and carbonated rock surfaces and its effectiveness on wettability alteration towards gas wetting condition was investigated thoroughly using different experimental techniques including dynamic and static contact angle measurements, liquid phase spontaneous imbibition, core displacement tests and surface characterization methods such as SEM, EDX, EDX map and FTIR tests. They proposed for the first time application of hydrocarbon based wettability modifier for sandstone and carbonate rocks (Gahrooei and Ghazanfari, 2017b). Franco-Aguirre et al. successfully synthesized functionalized SiO2 nanoparticles using an anionic fluorinated surfactant Silnyl®FSJ that could induced the gaswet state on sandstone in tight gas-condensate reservoirs. After chemical treatment of the core sample, the gas mobility was increased 24%. Performance of the injected nanofluid was evaluated using displacement tests under gas-condensate reservoirs conditions. In addition, wetting condition of core samples before and after nanofluid injection was examined through contact angle measurements and spontaneous imbibition tests (Franco-Aguirre et al., 2018). In the current study, a new water based C8 fluorocarbon solution was introduced for gas wetting of sandstone rock surface and its effectiveness on wettability alteration of sandstone rock towards gas wetting condition was examined thoroughly. First, materials and experimental methods employed in the study are explained, then static contact angles of water and normal-decane phases on the treated and untreated sandstone thin sections were measured to study the impact of wettability modifying chemical on contact angle values as an early detection method. Sandstone rock was coated by proposed chemical and adsorption of chemical onto the rock surface was approved using surface characterization techniques including FESEM, EDX, and EDX map. Then, Fourier Transform Infrared (FTIR) Spectroscopy analysis was performed to detect the functional groups formed between proposed chemical and rock surface. Finally, core scale experiments such as spontaneous imbibition and unsteady displacement tests were performed to describe the effect of fluorochemical adsorption on gas-liquid flow behavior in porous media of rock.
strongly liquid wetting condition of rocks resulted in high value of critical condensate saturation up to 30%–50% and remarkable reduction in gas relative permeability (Anderson, 1987a, 1987b). After wettability alteration of reservoir rock towards intermediate gas wetting or preferentially gas wetting state, the interfacial tension (IFT) between solid surface and liquid phase was reduced greatly, therefore, the liquid droplets had no more tendency to imbibe and penetrate into the smaller void spaces of rock. Additionally, a portion of the liquid phase existing in near wellbore zone was pushed towards the production well due to the drag force acting on liquid phase in near wellbore region by high velocity gas flow. Critical condensate saturation was decreased due to the aforementioned factors and gas relative permeability reduction was avoided. Therefore, liquid blockage issue due to condensate build-up or water accumulation was alleviated in the regions where wettability of reservoir rock surface altered towards preferentially gas wetting state followed by no decrease in well productivity. Pore network modeling technique was performed by Li and Firoozabadi (2000) to investigate the impact of various influencing factors on the gas condensate producing well performance. They concluded that the wettability characteristic of reservoir formation around the wellbore should be considered as one of the main effective parameters in well productivity and deliverability of well could be increased up to a factor of 1.35 by wettability alteration towards gas wetting state. Wettability alteration of rock samples towards gas wetting state was first proposed by Li and Firoozabadi, as mentioned earlier (Kewen and Abbas, 2000). They altered the wettability of rocks using two commercial fluoropolymers, FC722 and FC754. Effect of wettability alteration of rock surface towards gas wetting condition on liquid and gas relative permeability curves was investigated by Tang and Firoozabadi (2000). They concluded that by employing the gas wetting condition on rock surface, the liquid relative permeability improves greatly but no definite result was obtained for gas relative permeability improvement. Gas relative permeability value may decrease or enhance at a fixed saturation (Fahes and Firoozabadi, 2007; Panga et al., 2007). Mousavi et al. (2013) altered the wettability of limestone core samples using fluorinated nano silica. Polymeric fluoro-surfactant was synthesized by Sharifzadeh et al. (2013) to make the pore walls of reservoir rocks gas wet. In their study, contact angle measurements of water and n-decane on thin slices of reservoir rock in the atmosphere and n-decane/waterair spontaneous imbibition tests were employed to analyze the effectiveness of synthesized chemical. Aminnaji et al. (2015) applied commercial oil and water repellent, namely SurfaPore M, on sandstone and carbonate core samples to induce gas wetness condition. The nanofluid chemical used in their study altered the wettability condition of both carbonated and sandstone core samples after treatment with chemical. They analyzed the applicability of proposed chemical by conducting dynamic and static contact angle measurements, liquid phase spontaneous imbibition, and dynamic coreflooding tests. In addition, EDX, EDX map and SEM analyses as surface characterization methods were performed to clearly demonstrate the adsorption of chemical on rock surface. Simulation study was performed on a huge gas condensate field located in south of Iran by Sheydaeemehr et al. (2014). They investigated the impact of three different relative permeability curves and determined the differences in three distinctive wetting conditions including strongly liquid, intermediate and preferentially gas wetting condition on field cumulative production. They concluded that wettability condition of reservoir rocks affected significantly well productivity and the best wetting condition found to be intermediate gas wetting. Field trial chemical treatment for condensate blockage alleviation of Saudi Arabian gas condensate reservoir was reported by Al Ghamdi et al. (Al Ghamdi et al., 2013). Well productivity was severely decreased due to liquid blockage. After chemical treatment with nonionic fluorosurfactant, gas and condensate flow rates were enhanced by factors of 1.75 and 4, respectively. In addition, flowing well head pressure was increased by a factor of 1.9 indicating decrease in pressure
2. Materials and experimental methods 2.1. Materials In this study, sandstone rock was used for evaluation of effectiveness of wettability alteration of rock surface towards gas wetting condition. In the static contact angle measurement tests, sandstone discs with 2–4 mm thickness were used and crushed powders of sandstone rock were employed for all surface characterization tests including 215
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Fig. 1. Schematic of the setup used for static contact angle measurement.
Fig. 2. Schematic of spontaneous imbibition setup for air-liquid system, (1): Electrical balance, (2): Data acquisition system, (3): Core sample immersed in liquid phase.
Fig. 3. Schematic of core flooding apparatus.
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Fig. 4. Static contact angles over a period of time for water-air system (below) and n-decane-air system (above) on sandstone thin section after treatment.
washed with toluene and methanol, then they were dried with nitrogen gas then placed in oven at 100 °C for 1 day. The clean, dried thin sections were submerged in Tubiguard Protect 5 w.t. % solution, and aged at 50 °C for 1 day. The glass container of thin sections submerged in Tubiguard Protect should be sealed carefully to avoid any vaporization. After that aging time of samples finished, the final treated substrates were dried with nitrogen gas then placed in oven at 70 °C for 24 h. For SEM, EDX, and FTIR tests, crushed sandstone powders were used. They were first washed with toluene and methanol then placed in an oven fixed at a temperature of 100 °C for 24 h to dry samples carefully. Clean sandstone powders were aged in chemical solution for 1 days at 50 °C, same as thin sections. Coated samples were dried with pure nitrogen gas and placed at 70 °C for 24 h and then used for SED, EDX analysis and FTIR. Fig. 5. Clear depiction of water and n-decane droplets on the treated substrate with proposed chemical.
2.2.2. Contact angle A first and promising method to study the wetting condition of rock surface was performed by measuring the contact angles for the sandstone samples before and after treatment with wettability modifier material. The schematic of the static contact angle measurement apparatus is depicted in Fig. 1. The contact angle measurement tests were processed in (water or n-decane)/air/rock systems at room temperature. Water and n-decane drops of 5 μL were placed onto the untreated and treated sandstone thin section. Photographs of liquid droplets placed on the rock surface were taken over a period of time until stable condition was reached using a digital camera (220x Dino-Lite Microscope) positioned at a horizontal viewing angle of the thin section. The obtained photographs by means of the digital microscope were processed using Lab-view software. The droplet volume was under control through entire contact angle measurement tests with a 5 μL syringe so that the impact of gravity and drop sizes of water and n-decane on contact angles were avoided. The measurements were repeated in 5 different positions over the thin section surface.
SEM, EDAX, EDX map, and FTIR. Brine and n-decane were used as representatives of water and condensate phases for hydrophobicity and oleophobicity investigation of the surfaces. Air and nitrogen were utilized as the gas phases in static contact angle and spontaneous imbibition tests. Outcrop sandstone core sample with porosity and permeability of 17.6% and 110 md, respectively, was used for spontaneous imbibition and core displacement tests. Core displacement tests were performed by laboratory made apparatus as shown in Fig. 3. Tubiguard Protect fluorocarbon manufactured by CHT Company in Germany was used as a water and oil repellent agent, to alter the wetting condition of sandstone rock from strongly liquid wetting to gas wetting. Tubiguard Protect chemical was based on C8 fluorocarbon. Adsorption of fluorocarbon onto the rock surface can lead to induce water and oil repellency to the substrate. Tubiguard Protect has a specific weight of 1 at 25 °C and was white-colored. It is worth mentioning that ionic character of Tubiguard Protect was cationic with a pH value of 4.5–6.5. Cationic character of Tubiguard Protect could improve the adsorption onto the rock surface with anionic characteristic.
2.2.3. SEM and EDAX analysis Energy dispersive X-ray analysis (EDXA, model TESCAN MIRA3, Czech Republic) technique was used for elemental analysis of the treated samples. Higher value determination of fluorine and carbon elements in EDX analysis was an indication of more chemical adsorption. In the next phase, EDX map of fluorine and carbon elements were recorded from the coated samples to investigate the coating quality. High resolution images of surface topography, with five different magnifications and great depth of focus, were acquired by means of a Scanning electron microscopy (SEM, TESCAN MIRA3, Czech Republic)
2.2. Procedures 2.2.1. Preparation of thin sections and treated samples Sandstone rock was cut into radial cross section thin plates by means of a trimming machine. Radial sandstone thin sections with a diameter of 3.7 cm and thickness of 2–4 mm were burnished with a grinder to have a smooth surface. Prepared thin sections were initially 217
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Fig. 6. SEM images of treated sandstone rock at different magnifications. A: 500x, B: 1000x, C: 1000x, D: 5000x, E: 10000x, F: 50000x.
Fig. 7. EDX analysis on sandstone rock after treatment with Tubiguard Protect chemical agent.
would occur. Then, the FTIR spectra of the sample was recorded using Attenuated Total Reflection Infrared spectrometer (Bruker Co., USA) in the spectral domain of 400–4000 cm−1 and resolution of 4 cm−1.
at room temperature. 2.2.4. FTIR analysis Adsorption of Tubiguard Protect fluorocarbon on sandstone rock surface could be confirmed by FT-IR analysis. To do this, a little amount of Tubiguard Protect-modified sandstone powder was mixed with KBr salt as a carrier for the sample in IR spectrum then pressed into a disk. KBr was optically 100% transparent in the range of wavelengths (4000400 1/cm) of IR measurement. Therefore, no interference in absorbance
2.2.5. Spontaneous imbibition Spontaneous imbibition test was proposed by many researchers to demonstrate the wettability alteration of rock from liquid wet to gaswetting condition. This test shows the tendency of liquid to imbibe into the core initially saturated with dry air. The amount of liquid imbibed 218
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not changed within 20 min. The water contact angle was measured at 180 min after placement on the sandstone substrate and a value of 151° was obtained. In addition, θC10-air decreased from its initial contact angle of 110°–105° within 20 min, whereas θ reduced to 101° over the 180 min. Clear depiction of water and n-decane droplets on the treated substrate is given in Fig. 5. The results obtained in this section demonstrated that the wettability modifier chemical was able to alter the wettability of rock surface towards preferentially gas wetting condition.
Table 1 The energy dispersive X-ray quantitative results of treated surface. Element
Line
Int
K
Kr
W%
A%
ZAF
Pk/Bg
C O F Na Mg Al Si
Ka Ka Ka Ka Ka Ka Ka
53.5 952.8 39.2 0.0 0.0 25.0 943.2
0.0252 0.4560 0.0189 0.0000 0.0000 0.0127 0.4871 1.0000
0.0129 0.2336 0.0097 0.0000 0.0000 0.0065 0.2495 0.5122
8.62 54.36 5.14 0.00 0.00 0.90 30.97 100.00
13.00 61.53 4.90 0.00 0.00 0.61 19.97 100.00
0.1496 0.4297 0.1888 0.4583 0.6201 0.7203 0.8057
5.46 70.81 3.39 2.00 2.00 2.84 28.68
3.2. Surface characterization experiments Different surface characterization techniques were applied in this study for clear depiction and representation of chemical adsorption on to the sandstone rock surface. SEM images of untreated and treated surfaces were obtained for heterogeneity characterization. In addition, for elemental analysis and determination of distribution of adsorbed elements on the coated surface, EDX analysis and EDX map were used, respectively. SEM images at different magnifications for sandstone rock before and after chemical adsorption following wettability alteration are depicted in Fig. 6. Comparison of treated rock SEM images with untreated rock clearly demonstrated that a film of chemical was formed on the surface of the rock coated with Tubigaurd Protect oil and water repellent chemical. As mentioned earlier, EDX analysis was utilized in this study. EDX analysis can be used as a surface characterization technique to verify the adsorption of desired chemical and determine the elements of formed layer on the sandstone rock after wettability alteration. EDX analysis of the treated rock is depicted in Fig. 7. It can be concluded from Fig. 7, that the fluorine and Carbon elements were detected on treated surface approving the layer formation on rock surface. Chemical layer formation on the rock surface may lead to reduction in surface free energy and liquid repellency inducement to rock surface. The energy dispersive X-ray quantitative results of treated surface are presented in Table 1. The results of the EDAX test can be used to identify principal chemical elements on the treated sandstone surfaces. In addition, EDX map of various elements on treated sandstone rock surface is depicted in Fig. 8. Pink and yellow dots in Fig. 8 indicate fluorine and carbon atoms which were constituting elements of Tubiguard Protect. Blue and green dots are representatives for Oxygen and Silicon atoms exist in virgin sandstone rock. It can be concluded from comparison of these images, a homogenous and uniform layer of fluorine network was formed on the rock grains due to adsorption of the Tubiguard Protect fluorocarbon on sandstone surface inducing liquid (water and oil) repellency on rock surfaces. Consequently, water and oil repellency characteristics can be induced by formation of coating on the rock surface which contains large amount of fluorocarbon groups.
into the core demonstrates the degree of wettability alteration towards gas wetting condition. The schematic of setup employed for imbibition tests is depicted in Fig. 2. As shown in the figure, the air saturated core was immersed completely in the liquid phase (water or n-decane). The change in weight of core, indicating the amount of liquid imbibition, was measured versus time using an electrical balance. Water phase used in this section was composed of 2 w.t. % NaCl to prevent clay swelling. Imbibition tests were conducted for untreated and treated sandstone rock. 2.2.6. Core displacement Core displacement test was applied in this study to determine the mobility of liquid phases in the initially nitrogen saturated core. Fig. 3 depicts the schematic of coreflood system designed for displacement test. In this section, liquid phases (water or n-decane) were injected at a flow rate of 120 cc/hr into the initially gas saturated sandstone core sample and pressure drops through the core were recorded using data acquisition system. Decrease in pressure drop during displacement test convey the message that, larger pores were occupied by liquid phase, indicating mobility improvement of liquid phases due to presence of lower capillary pressure in larger pores. The chemical treatment stage was performed by injecting 20 PVs of Tubiguard Protect chemical into the core sample at 50 °C. Exposing the rock surface to considerably larger amount of chemical agent by injecting 20 PVs of treatment fluid through the core can effectively render it water and oil-repellent. 3. Results and discussion 3.1. Contact angle The contact angle measurements as a first and promising analysis technique were conducted to evaluate the effectiveness of the Tubiguard Protect fluorochemical on the treatment of sandstone substrate. On the basis of water and n-decane contact angles obtained for the treated thin section over a period of time until stable condition in which were shown in Fig. 4, it could be concluded that employing 5 w.t. % Tubiguard Protect chemical as a wettability modifier agent resulted in satisfactory contact angles representing wettability alteration from strongly liquid wetting state to preferentially gas wetting condition. As demonstrated in Fig. 4, the contact angle of water droplet was
3.3. FTIR analysis FTIR analysis of fluorocarbon-modified grains is depicted in Fig. 9. The compressed alkali metal halide pellet method was used to measure
Fig. 8. EDX map of different elements on treated sandstone rock surface. 219
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Fig. 9. FTIR spectrum of Tubiguard Protect coated sandstone rock.
Fig. 10. Transient behavior of air-water spontaneous imbibition versus time into the air saturated sandstone core sample before and after wettability alteration with the proposed chemical for sandstone rock.
Fig. 11. Transient behavior of air-n-decane spontaneous imbibition versus time into the air saturated sandstone core sample before and after wettability alteration with the proposed chemical for sandstone rock.
the FTIR spectrum. Fluorocarbon-modified sandstone exhibited the major adsorption peaks as shown in Fig. 9. Possible existing functional groups were CeO stretch, carboxylate groups (1340–1440 cm−1), CeF stretch (1170–1215 cm−1), CeO bend, carboxylate (775–805, 715–735 cm−1), CeO stretch, carboxylate (1620–1695 cm−1), SieO stretch (830–955 cm−1), and OeH stretch (3200–3700 cm−1). These peaks convey the message that the fluorocarbon based chemical was adsorbed onto the rock surface. Consequently, on the basis of obtained results in surface characterization tests and manufacturer technical datasheet, surface active agent of Tubiguard Protect wettability modifier chemical contains carbon and fluorine atoms.
spontaneous imbibition tests. As mentioned earlier, imbibition test apparatus shown in Fig. 2 was employed for liquid imbibition measurements. The amount of liquids imbibed into the core sample was recorded then plotted in a diagram versus time. The liquids selected as representatives of water and condensate phases were 2 w.t. % NaCl brine and n-decane, respectively. The core sample was initially saturated with air before any imbibition test. Fig. 10 demonstrates the water-air imbibition test results before and after chemical treatment. The ultimate amounts of water imbibition into the core sample before and after chemical treatment were found to be 0.625 PV and 0.033 PV, respectively. After chemical treatment, the imbibition tendency of water phase into the core sample in the presence of air was decreased significantly, indicating wettability alteration of core sample from strongly water wet to gas wetting condition. Similar to previous figure, the obtained results of air-n-decane imbibition tests are demonstrated in Fig. 11. The imbibition amount of n-decane was decreased from
3.4. Liquid imbibition Effect of wettability alteration of core sample towards gas wetting condition with Tubiguard Protect was studied by conducting liquid-air 220
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Table 3 Basic assumptions for economic evaluation. Gas price (USD/Mscf) Production time (day) Downtime for injection (hr) Volume of treatment fluid injected (bbl) Price of TUBIGAURD PROTECT (USD/Kg) Concentration (wt %) Water Injection price (USD/bbl)
3.84 365 72 1119 13.2 5 10
Table 4 Gas flow rates before and after treatments. Cases
Gas flow Rate, Mscf/day
Blockage (Before treatment) Blockage (After treatment)
26,957.26 46,084.08
3.5. Core flooding Core displacement tests were conducted using coreflood setup shown in Fig. 3. Unsteady state displacements of liquid phases through the core initially saturated with nitrogen gas were performed to determine the liquid phase mobility before and after chemical treatment. Liquid phases were injected at a flow rate of 120 cc/hr through core sample initially saturated with nitrogen gas. The pressure drops of water and n-decane injection alongside the core were recorded and are demonstrated in Figs. 12 and 13, respectively. It could be seen from both figures that the pressure drop across the core sample decreased significantly after chemical treatment. Reduction of water and n-decane flooding pressure drop was an indication of ability of Tubiguard Protect to alter the wettability of core sample from liquid wetting condition to gas wetting. When water phase was injected into the untreated core sample under strongly water wetting condition, the water tends to occupy smaller pores (high pressure drawdown) followed by high capillary pressure. After chemical treatment of core sample, as water phase was injected into the treated core under gas wetting condition, water tends to occupy larger pores facing lower capillary pressure which resulted in lower pressure drawdown, therefore mobility of water phase was improved. Similar to water injection, after chemical treatment, as n-decane was injected into treated core sample under gas wetting condition, n-decane tends to occupy larger pores. Pressure drawdown of n-decane displacement through the core was reduced since lower capillary pressure exists in larger pores, therefore mobility of n-decane was improved. Therefore, inducing gas wetting condition in the core sample may lead to increase in endpoint relative permeability of liquid phases (water or n-decane) (Gahrooei and Ghazanfari, 2017b). On the basis of obtained steady state pressure drops, water and n-decane mobilities at residual gas saturation increased by factors of 3.85 and 3.5 for treated core with Tubiguard Protect, respectively.
Fig. 12. Pressure drop across sandstone core sample versus pore volumes injected for 2 w.t. % NaCl brine before and after treatments.
Fig. 13. Pressure drop across sandstone core sample versus pore volumes injected for n-decane before and after treatment. Table 2 Typical Parameters for the well. Average Porosity (%) Absolute Permeability (md) Initial reservoir pressure (psia) Formation thickness (ft) Treatment radius (ft) Reservoir Temperature (F) Dew point pressure (psia) rw (Wellbore radius, ft) re (External radius, ft) krg (Before treatment) krg (After treatment)
20 10 7000 100 10 300 3380 0.25 1000 0.21 0.359
4. Economic impact analysis To evaluate the economic impact and practical implication of the proposed chemical for the wettability alteration of near wellbore region which results in enhancement of a gas relative permeability on a representative producing well, some assumptions were made based on the Saikia and Santoso studies (Saikia, 2010; Santoso, 2015). Table 2 lists some typical properties that were assumed for the well. In order to flood the treatment fluid in the wettability treatment process, the producing well was turned into an injection well temporarily, therefore, the lost amount of gas production during downtime for injection was necessary to be considered in the economic analysis (downtime cost). In addition to the aforementioned associated cost for treatment, the cost of the applied chemical for wettability alteration (treatment cost) and injected water (water cost) as a chemical carrier
0.65 PV to 0.159 PV after treatment with Tubiguard Protect. Similar to water imbibition results, the tendency of n-decane to imbibe into the core sample initially saturated with air was decreased after chemical treatment. High degree of water imbibition reduction comparing to ndecane imbibition decrease reinforces contact angle measurement results. 221
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Table 5 Treatment, water, and downtime expenses and profitability of the treatment after one year production. Volume of treatment fluid (bbl)
Treatment cost (USD)
Water cost (USD)
Added revenue value (USD)
1119 Lost time (day) 3
117,427.86 Production rate (Mscf/d) 26,957.26
11,190 Downtime cost (USD) 310,547.63
26,368,985.52
phase mobility values enhanced after fluorinated chemical injection into the core compared with the system in the absence of the same, indicating that the chemical injection modified the wettability of rock surface from a liquid-wet to a gas-wet state.
should be considered in costs associated. Therefore, treatment costs, water costs, and downtime cost were defined in the expenses term to determine the profitability of the treatment. Basic assumptions for economic evaluation are given in Table 3. As can be seen in Table 3, the gas price was 3.84 USD/Mscf as of January 18, 2018 (US Energy Information Administration, 2018). Another is the price of the proposed chemical, which was 13.2 USD per 1 kg (CHT, 2017). The quantity of gas flow rates for cases before and after treatments are presented in Table 4. Incremental gas production after treatment which is difference between gas flow rates before and after treatments is as follows:
Appendix A. Supplementary data Supplementary data to this article can be found online at https:// doi.org/10.1016/j.jngse.2018.12.006. References Al Ghamdi, B.N., Al-Malki, B.H., Al-Kanaan, A., Rahim, Z., Al-Anazi, H.D., 2013. Field implementation of condensate bank removal using chemical treatment. In: International Petroleum Technology Conference. International Petroleum Technology Conference. Al-Anazi, H.A., Walker, J.G., Pope, G.A., Sharma, M.M., Hackney, D.F., 2003. A successful methanol treatment in a gas-condensate reservoir: field application. In: SPE Production and Operations Symposium. Society of Petroleum Engineers. Aminnaji, M., Fazeli, H., Bahramian, A., Gerami, S., Ghojavand, H., 2015. Wettability alteration of reservoir rocks from liquid wetting to gas wetting using nanofluid. Transport Porous Media 109, 201–216. Anderson, W.G., 1987a. Wettability literature survey part 5: the effects of wettability on relative permeability. J. Petrol. Technol. 39 (1) 453-451,468. Anderson, W., 1987b. Wettability literature survey-Part 4: effects of wettability on capillary pressure. J. Petrol. Technol. 39 (1) 283-281,300. Asgari, A., Dianatirad, M., Ranjbaran, M., Sadeghi, A., Rahimpour, M., 2014. Methanol treatment in gas condensate reservoirs: a modeling and experimental study. Chem. Eng. Res. Des. 92, 876–890. Fahes, M.M., Firoozabadi, A., 2007. Wettability alteration to intermediate gas-wetting in gas-condensate reservoirs at high temperatures. SPE J. 12, 397–407. Fishlock, T., Probert, C., 1996. Waterflooding of gas condensate reservoirs. SPE Reservoir Eng. 11, 245–251. Franco-Aguirre, M., Zabala, R., Lopera, S.H., Franco, C.A., Cortés, F.B., 2018. Interaction of anionic surfactant-nanoparticles for gas-Wettability alteration of sandstone in tight gas-condensate reservoirs. J. Nat. Gas Sci. Eng. 51, 53–64. Gahrooei, H.R.E., Ghazanfari, M.H., 2017a. Application of a water based nanofluid for wettability alteration of sandstone reservoir rocks to preferentially gas wetting condition. J. Mol. Liq. 232, 351–360. Gahrooei, H.R.E., Ghazanfari, M.H., 2017b. Toward a hydrocarbon-based chemical for wettability alteration of reservoir rocks to gas wetting condition: implications to gas condensate reservoirs. J. Mol. Liq. 248, 100–111. Jin, J., Wang, Y., Wang, K., Ren, J., Bai, B., Dai, C., 2016. The effect of fluorosurfactantmodified nano-silica on the gas-wetting alteration of sandstone in a CH4-liquid-core system. Fuel 178, 163–171. Kewen, L., Abbas, F., 2000. Experimental study of wettability alteration to preferential gas-wetting in porous media and its effects. SPE Reservoir Eval. Eng. 3, 139–149. Kumar, V., Bang, V.S.S., Pope, G.A., Sharma, M.M., Ayyalasomayajula, P.S., Kamath, J., 2006. Chemical stimulation of gas/condensate reservoirs. In: SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers. Li, K., Firoozabadi, A., 2000. Phenomenological modeling of critical condensate saturation and relative permeabilities in gas/condensate systems. SPE J. 5, 138–147. Mahdiyar, H., Jamiolahmady, M., 2014. Optimization of hydraulic fracture geometry in gas condensate reservoirs. Fuel 119, 27–37. Marokane, D., Logmo-Ngog, A., Sarkar, R., 2002. Applicability of timely gas injection in gas condensate fields to improve well productivity. In: SPE/DOE Improved Oil Recovery Symposium. Society of Petroleum Engineers. Mousavi, M., Hassanajili, S., Rahimpour, M., 2013. Synthesis of fluorinated nano-silica and its application in wettability alteration near-wellbore region in gas condensate reservoirs. Appl. Surf. Sci. 273, 205–214. Muladi, A., Pinczewski, W., 1999. Application of horizontal well in heterogeneity gas condensate reservoir. In: SPE Asia Pacific Oil and Gas Conference and Exhibition. Society of Petroleum Engineers. Najafi-Marghmaleki, A., Tatar, A., Barati-Harooni, A., Choobineh, M.-J., Mohammadi, A.H., 2016. GA-RBF model for prediction of dew point pressure in gas condensate reservoirs. J. Mol. Liq. 223, 979–986. Panga, M.K., Ismail, S., Cheneviere, P., Samuel, M., 2007. Preventive treatment for enhancing water removal from gas reservoirs by wettability alteration. In: SPE Middle East Oil and Gas Show and Conference. Society of Petroleum Engineers. Rahimzadeh, A., Bazargan, M., Darvishi, R., Mohammadi, A.H., 2016. Condensate blockage study in gas condensate reservoir. J. Nat. Gas Sci. Eng. 33, 634–643.
(31,578.50 – 26,957.26) Mscf/day = 19126.82 Mscf/day Incremental revenue per day is as follows:
19126.82 Mscf/day × $3.84/Mscf = $73,446.98/day Incremental revenue per year can be calculated as follows:
$73,446.98/day × 365 days = $26,808,150.912/year Table 5 details the costs incurred in wettability treatment option. Profitability of the wettability treatment after one year gas production is determined on the basis of calculated expenses term including treatment cost, water cost, and downtime cost. 5. Conclusion In this study, a new water based chemical comprised of fluorocarbon was successfully proposed for inducing gas-wetting condition on sandstone rock surface based on the interaction between cationic fluorocarbon and anionic characteristic of sandstone surface. The effects of proposed chemical on hydrophobic and oleophobic properties of sandstone rock surface were investigated and characterized by static contact angle measurements, imbibition tests, and displacement tests. Contact angle of liquid phases on the sandstone thin section indicated wettability alteration from liquid-wet towards gas-wet in all systems. The following conclusions can be drawn on the basis of the obtained results in this study;
• SEM images of untreated and treated surfaces were obtained for
• •
heterogeneity characterization. In addition, for elemental analysis and determination of distribution of adsorbed elements on the coated surface, EDX analysis and EDX map were used, respectively. Comparison of treated rock SEM images with untreated rock clearly demonstrated that a film of chemical was formed on the surface of the rock coated with Tubigaurd Protect oil and water repellent chemical. The fluorine and carbon elements were detected on treated surface approving the layer formation on rock surface. Chemical layer formation on the rock surface may lead to reduction in surface free energy and liquid repellency inducement to rock surface. Additionally, FTIR molecular structure analysis proved the presence of carbon and fluorine functional groups in proposed chemical surface-active agents. Ultimate amount of spontaneous imbibition of water and n-decane into air saturated dry sandstone core sample decreased remarkably from 0.61 and 0.64 pore volume to 0.03 and 0.16 pore volume for untreated and treated sandstone rock, respectively. Dynamic assessment of the proposed chemical showed that liquid 222
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Appl. Polym. Sci. 128, 4077–4085. Sheydaeemehr, M., Sedaeesola, B., Vatani, A., 2014. Gas-condensate production improvement using wettability alteration: a giant gas condensate field case study. J. Nat. Gas Sci. Eng. 21, 201–208. Tang, G.-Q., Firoozabadi, A., 2000. Relative permeability modification in gas-liquid systems through wettability alteration to intermediate gas-wetting. In: SPE Annual Technical Conference and Exhibition. Society of Petroleum Engineers.
Saikia, B.D., 2010. Surfactant-induced Flow Behavior Effects in Gas Condensate Reservoirs. Master's thesis. Louisiana State University, USA. Sanger, P., Hagoort, J., 1998. Recovery of gas-condensate by nitrogen injection compared with methane injection. SPE J. 3, 26–33. Santoso, B.D., 2015. Modeling of Near-wellbore Wettability Alteration for Gas Well Liquid Blocking Remediation. Master's thesis. Texas A&M University, USA. Sharifzadeh, S., Hassanajili, S., Rahimpour, M., 2013. Wettability alteration of gas condensate reservoir rocks to gas wetness by sol–gel process using fluoroalkylsilane. J.
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