Investigation of formation damage by Deep Eutectic Solvents as new EOR agents

Author's Accepted Manuscript

Investigation of formation damage by deep eutectic Solvents as new EOR agents A. Mohsenzadeh, Y. Al-Wahaibi, R. Al-Hajri, B. Jibril, S. Joshi, B. Pracejus

www.elsevier.com/locate/petrol

PII: DOI: Reference:

S0920-4105(15)00093-5 http://dx.doi.org/10.1016/j.petrol.2015.02.035 PETROL2978

To appear in:

Journal of Petroleum Science and Engineering

Received date: 10 September 2014 Revised date: 7 December 2014 Accepted date: 23 February 2015 Cite this article as: A. Mohsenzadeh, Y. Al-Wahaibi, R. Al-Hajri, B. Jibril, S. Joshi, B. Pracejus, Investigation of formation damage by deep eutectic Solvents as new EOR agents, Journal of Petroleum Science and Engineering, http://dx.doi.org/ 10.1016/j.petrol.2015.02.035 This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting galley proof before it is published in its final citable form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

Investigation of Formation Damage by Deep Eutectic Solvents as New EOR Agents A. Mohsenzadeh1, Y. Al-Wahaibi1*, R. Al-Hajri1, B. Jibril1, S. Joshi2, B. Pracejus3 1

Department of Petroleum and Chemical Engineering, Sultan Qaboos University, Oman

2

Central Analytical and Applied Research Unit, College of Science, Sultan Qaboos University, Oman

3

Earth Science Department, Sultan Qaboos University, Oman

*

Corresponding Author: [email protected]

Abstract Chemical injection into oil reservoirs is considered as an effective enhanced oil recovery (EOR) method. Although some of the chemicals improve oil recovery, they may have side effects on reservoirs such as formation damage due to fluids incompatibility or chemical interactions with reservoir rocks and fluids. Since our previous work indicated promising results from Deep Eutectic Solvents (DESs; DES1 - choline chloride:glycerol = 1:2 and DES2 - choline chloride:urea = 1:2) on enhanced heavy oil recovery, we now examine the possible effects of these DESs on sandstone formation damage. Core flooding tests were performed at reservoir pressure and different temperatures to measure possible permeability changes by DESs injection. To understand the mechanisms of formation damage, different measurements were performed: Critical injection rate beyond which fines migration will take place, water shock effects on formation damage, dry core weight measurements before and after each core flooding tests, scanning electron microscopy (SEM), X-ray diffraction (XRD), and computed tomography (CT) scanning studies of fresh and treated core samples. Permeability measurements by core flooding tests showed that the water shock phenomenon caused severe damage (65% reduction in absolute permeability) when distilled water was injected after brine flooding. Both DESs showed positive effect on reducing the water shock damages at different temperatures, where DES2 was much more effective when compared with DES1. Core weight measurements confirmed that whenever permeability damages were higher, the amount of core weight increase was also high. Moreover, results of SEM and quantitative XRD showed that precipitation and deposition inside pores are the main sources of formation damage. In addition, CT-scanning images provided good comparisons between fresh and damaged cores. We observed that using DESs showed that despite the DES’s solutions role in preventing severe water shock damage and stabilizing the clays, there was still some formation damage caused by re-crystallization and precipitation processes reducing the permeability of the core samples.

KEYWORDS: Deep eutectic solvents, formation damage, permeability changes, core flooding

1

1.

Introduction

Formation damage is one of the most important reasons for declining well injectivity as well as productivity in oil and gas reservoirs. Several mechanisms responsible for formation damage are reported in the petroleum literature: fines and clay migration, clay swelling, fluid-fluid incompatibility, rock-fluid interaction, phase blocking, adsorption, scale formation, thermal stress, dissolution and precipitation reactions, effect of the net overburden stress pore deformation, and wettability alteration (Al-Mohammad et al., 2012; Mikhailov et al., 2010; Mojarad et al., 2005; Scott et al., 2007 and Patino et al., 2003). Formation damage may happen by drilling fluid invasion near the wellbore or during EOR activities in the field such as water flooding, chemical flooding, gas injection, and thermal methods.

Scott et al. (2007) reported that mainly in unconsolidated rocks, particles such as clays and precipitates are dispersed during fines migration and they may accumulate within the pores and throats causing blockage, restricting flow and result in decreasing permeability. Additionally, reservoir formation can be damaged due to clay swelling. Active clay minerals, such as smectite and illite could also react with the incompatible water-based fluids (injection of more-saline or less-saline aqueous fluids during drilling, completion, workover, wateflood or stimulation operations) and swell 600 to 1000 times their original volume. These swelled clays can create an impermeable barrier for fluid flow, block pores and throats leading to reducing permeability of formations (Brian et al., 2004; Jiaojiao et al., 2010; Al-Mohammad et al., 2012).

Near-wellbore formation damage could also be prompted by fluid-fluid interaction. Injection of incompatible water with formation brine could lead to scale formation like calcium carbonates. The formation of scale will plug formation rock by filtration of suspended scale particles from the water, or by the formation of a solid scale on the formation face (Mohammad et al., 2012).

Water blocking is considered as another mechanism of damage for formations with low-porosity and low permeability. It occurs due to the capillary effect associated with the development of micro-pores when the water based drilling fluid or EOR chemicals are injected into the formation. Originally, water adsorbs on the surface of water-wet rocks or occupies at the corner of micro-pores, while the oil and gas are in the middle areas and afford the flow passage. In the reservoirs with ultra-low permeability, when the filtrate of drilling fluids invades formation (developing micro-pores) or where the original water saturation is lower than the irreducible water saturation formed by the invasion fluids, the water blocking occurs due to the capillary effect of micro-pores for this type of formations. The water-blocking phenomenon may decreases effective permeability to oil (Bennion, 2002). To ease the water blocking effect, the filtration loss of drilling fluids should be monitored and reduced to

2

be as little as possible. Jiaojiao et al. (2010) reported that adding some IFT breaking agents (such as surfactant or alcohol) in the injecting fluid is quite helpful to minimize the water-oil interfacial tension, thus reducing the capillary resistance and preventing the damage induced by water blocking.

In addition, rock-fluid interactions including dissolution, precipitation, and pore and throat surface erosion during chemical injection may also cause formation damage. Small particles and precipitates can travel through the formation and initially plug the pore throats by bridging, thus creating internal pore restrictions and reducing the formation permeability (Mojarad et al., 2005).

Water shock is another phenomenon which causes formation damage. Reservoir rocks, especially sandstone formations containing clays (often kaolinite) are most susceptible to brine salinity. Change in salinity disturbs the equilibrium conditions in the rock-fluid system of porous media. Consequently, fine particles can be detached from the surface easily, move and trap the pore throat which eventually leads to a permeability reduction of the formation. Different clay stabilizers have been proposed such as the amine-based choline chloride, tetramethyl ammonium choloride (TMAC), Al/Zr-based stabilizers, and nano particles (El-monier and Nasr-el-Din, 2011; Habibi et al., 2012).

An alternative class of ionic liquids (ILs) called Deep Eutectic Solvents (DESs) have recently been discovered and investigated. A DES is generally composed of two or more components that are capable of self-association, to form eutectic mixture with a melting point lower than that of each individual component (Zhang et al., 2012). DESs are non-toxic, biodegradable, recyclable, non-flammable, environmentally friendly and. Therefore, DESs were employed in fields like extraction/separation, solvent development/reaction medium, hydrometallurgy, catalytic processes, electrochemistry, CO2 absorption, and pharmaceutical applications (Hayyan et al., 2013; Yue et al., 2013; Dai et al., 2013; Li et al., 2013).

In our previous study (Mohsenzadeh et al., 2014), for the first time, two Chloride-based DESs were shown to have significant effects on different oil recovery mechanisms in heavy oil/formation brine/Berea sandstone system. The tested mechanisms were emulsification, IFT reduction, wettability alteration and oil recovery factor by core flooding experiments at different temperatures. The wettability alteration of the rock surfaces from strongly oil-wet to neutral-wet condition as well as viscous forces were determined as the governing mechanisms leading to promising results in terms of heavy oil recovery enhancement. In this work, the possible positive influences of these two DESs on sandstone formation damage mechanisms are studied. Core flooding tests were performed at reservoir pressure and different temperatures to measure any permeability damage by DESs injections. To understand the mechanisms of formation damage, different tests were performed, namely: a) critical

3

injection rate beyond which fine migration will occur, b) water shock experiments by varying salinity of injectant from formation brine to distilled water, c) core weight measurements before and after each core flooding test, d) Scanning Electron Microscopy (SEM), e) X-ray Diffraction (XRD), and f) Core CT-scanning studies of fresh and treated core samples.

2.

Materials and Methods

2.1. Materials Formation brine was collected from an Omani oil field; its properties are listed in Table 1. It was filtered with 0.45µ filters (Millipore) to remove fines and sediments. All chemicals used for synthesizing the DESs (choline chloride, urea, and glycerol) were highly pure with AR grade (Analytical Reagents, Sigma Aldrich). The properties of synthesized DES1 and DES2 are presented in Table 2. Berea homogeneous and consolidated sandstone core plugs were used as a porous medium in the core flood tests. The core plugs were 3 inches long with 1.5 inches diameter, porosities varied between 18-20% and permeability ranged from 30 to 50 mD, respectively. To avoid any salt or oil contamination by plugging and cutting machines, the core plugs were cleaned using the Soxhlet extraction method, where chloroform and methanol were the solvents used as an azeotropic mixture in the proportion of (75:25). These solvents are constantly evaporated and condensed. The condensed solvent passes through the core sample removing all the oil and any other material from the core before returning back for another cycle. This process is repeated until a clear color solvent is obtained (Al-Sulaimani et al., 2011).

2.2. Formation damage test setup The formation damage tests were carried out in a high pressure/temperature core flooding apparatus (can handle up to 220˚C and 6000 psi; Fig. 1) which consists of: Isco syringe pump model 500D two high P floating piston transfer vessels high PT core holder that can house a core of 1.5 inch diameter and up to 6 inch length constant temperature air bath (oven) which can work up to 220 ˚C back pressure regulator digital pressure gauges and differential pressure transducers to measure injection/ production pressure and pressure drop across the core

4

2.3. Critical injection rate measurements In order to study the effect of fine migration on formation damage, critical velocity tests were carried out using six different flow rates ranging from 0.1 to 1.0 cm3/min to determine the maximum injection rate that can be used without causing any fines movement. The Berea sandstone core plug was saturated with distilled water under vacuum. Then, the saturated core was loaded into the core holder under reservoir conditions of 45 ˚C and 1200 psi confining pressure. Distilled water was injected and absolute permeability was calculated at each flow rate by measuring the differential pressure across the core. As shown in Fig. 2, for all tested flow rates no changes were observed in absolute permeability, which assured that no fines movement was caused.

2.4. Effect on absolute permeability Absolute permeability change after DESs injection is considered as formation damage indicator in core flooding tests. The tests were carried out at the reservoir confining pressure of 1200 psi. To study temperature effects, the tests for both DES solutions were performed at three different temperatures (45˚C, 60˚C, and 80˚C). The DESs were diluted 50 % (v/v) with formation brine. The fresh and dry core samples were weighted and saturated with brine under vacuum. Then, the soaked cores were weighed to calculate the pore volume and the porosity. Saturated cores were loaded into the core holder and the desired confining pressure and temperatures were set. In order to study the water shock effect, formation brine was injected at constant flow rate (0.4cm3/min) to measure the absolute permeability followed by distilled water injection and re-measuring the permeability again.

In another set of tests, the effect of DESs treatment on the water shock phenomenon was examined. This was done by injecting 3 pore volumes (PV) of DES solution and soaking for 12 h after brine flooding. This was followed by injecting distilled water and measuring the absolute permeability again. After each test, the core plug was unloaded from the core holder and dried in the oven at 80˚C. dry weight of each treated core sample was measured and compared with its fresh dry weight. The experimental conditions and results are presented in Table 3.

2.5. X-ray Diffraction (XRD) study XRD is normally utilized to study the rock mineralogy and composition and, particularly in our case, the clay components (<2µm). The XRD analysis provides good insights into mineral alteration processes (Ardian et al., 2010; Green et al, 2013). In this work, around 10g of core pieces were treated with DES1 and DES2 solutions for almost 12 h at constant temperatures of 60 ˚C and 80 ˚C. Both untreated and treated core samples were evaluated using Xpert Pro XRD system (Pan Analytical), at the Central Analytical and Applied Research Unit (CAARU), Sultan Qaboos University, Oman.

5

2.6. Scanning Electron Microscopy (SEM) study The SEM was used to examine the core samples at various magnifications, generally in the 100-10,000x range. These magnification levels are ideal to investigate alteration features observed in the original minerals resulting from fluid invasions, incompatibility, dissolution, and scaling (precipitations on rock surfaces). Generally, in this technique sub-samples of 0.5-1cm size are used for analysis (Green, 2013; Scott, 2007). Core sample pieces were aged in both DESs solutions for 12 h at constant temperature of 45 ˚C. Then, both the fresh dried and treated core pieces were analyzed by SEM/EDS to identify formation damage effects using field emission SEM (JEOL, JSM7600F), at CAARU, Sultan Qaboos University, Oman.

2.7. Computed Tomography (CT) Scanning study CT scanning has become an important tool in modern core analysis in a non-destructive manner. It has been used in the past for studying reservoir rocks and rock-fluid systems including mineralogy, porosity and density profiles, permeability mapping, viscous fingering, miscible displacement, gravity drainage, three-phase flow, relative permeability, and formation damage (Mogensen et al, 2001; Siddiqui et al, 2006). In formation damage testing, CT scanning is generally used to visualize suitable core sampling points, align the samples, and to check that the samples cut are representative and comparable to each other. Moreover, bedding features, homogeneities, cements, fractures, large grains, and large pores/vugs can be seen via CT scanning, hence allows determining the alteration (if any) within the core samples after treatment (Green et al, 2013). The medical CT-scan data are presented in an internationally standard scale called the Hounsfield unit (HU). The unit is based on the CT number (CTN) of air at −1000 and the CTN for water at 0 HU. The number measured by a CT-scanner depends on both the bulk density (ρb) and effective atomic number (Zeff) of the object scanned (Siddiqui et al., 2006). For this study we have used CT scanner model SIEMENS, SOMATOM SENSATION64 for 3-D scanning of different dried fresh and damaged core samples. The highest energy of 140 kV, 300 mA with 0.6 mm slice interval was used to scan (Isoteropic special resolution of CT scanner was 0.24 mm). The cross sectional images were analyzed by PHILIPS iSite Viewer software.

3.

Results

Formation damage studies were done through core flooding tests to measure any permeability damage at reservoir pressure and different temperatures for two DESs solutions. To understand the mechanisms affecting formation damage, different studies were carried out for fresh and treated core samples.

6

3.1. Effects of DESs type Core flooding tests were performed to measure the effect of DESs injection on absolute permeability at reservoir pressure and different temperatures. Results of permeability and core samples weight changes are shown in Table 3 and Fig. 3. In the brine tests, distilled water was injected after brine flooding without any DESs injection at different temperatures. This is referred to as brine treated core samples in this paper. These tests showed that severe formation damage (around 65%) was observed by changing the salinity from brine to distilled water. This significant damage is attributed to water shock effect where the salinity of the injectant is decreased drastically to lower than the critical salt concentration. Several researchers (Nasr-el-Din et al., 1998; El-Monier and Nasr ElDin, 2011 and Habibi et al., 2012) reported similar results where drastic damages (more that 55%) were observed while fresh water was injected into sandstone cores after brine flooding.

Permability damage in water shock tests were 60, 65 and 67.1 % at 40˚, 60˚ and 80 ˚C, respectively. The results of DESs injection showed that both DES solutions appreciably reduced the water shock effect in terms of permeability damage when compared with the brine-treated samples. As shown in Fig. 3, DES2 was more effective than DES1 in reducing the water shock phenomenon for all temperatures. The permeability reductions, when treating the core samples with DES1, were 25, 57.6 and 3.7 % at 40˚, 60˚ and 80 ˚C, respectively, while for DES2 the permeability only decreased by 2.2, 11.8 and 2.6 % at 40˚, 60˚ and 80 ˚C, respectively. Also, the weight measurements for dry cores before and after core flood runs showed that the weight of damaged cores increased when compared to fresh cores in each test (Table 3). Similar formation damage studies on sandstone cores were reported by several researchers on a range of permeability reductions up to 60 % using various chemicals injection such as brine flooding (Okoye et al., 1991; Moghaddasi et al., 2004), corrosion inhibitors injection (Allen et al., 1984), alkaline flooding (Valdya and Fogler, 1992; Alexie, 2000; Patino, 2003; Schember, 2004) and steam injection (Okoye et al., 1991).

3.2. Effect of Temperature on formation damage Results of permeability changes for brine treated samples showed an increase in permeability damage by increasing temperature. A previous study by Moghaddasi et al. (2004) reported a similar trend. They observed that during brine flooding at high temperatures, the precipitation rate increased and consequently the permeability reduced. Results of the temperature effect on permeability changes showed that for DES1 solution injection, the permeability reduction was 25 % at 40 ˚C, 57.6 % at 60 ˚C and 3.7% when the test was performed at 80 ˚C. A similar trend was observed for DES2 solution injection results, where the permeability reductions were 2.2, 11.8 and 2.6 % at 40, 60 and 80 ˚C, respectively.

7

For a more detailed examination of the temperature effect on formation damage, another core flooding test was performed with a different procedure: The same initial procedure for DES1 treatment at 60 ˚C was done and the permeability damage was measured by distilled water injection at 60 ˚C. Then, the temperature was increased to 80 ˚C and the affected permeability was measured again using distilled water. The absolute permeability for fresh core was 34.6 mD at 60 ˚C. It reduced to 14.6 mD (57.8% permeability reduction) after DES1 solution injection at 60 ˚C. However, by distilled water injection at 80 ˚C, the permeability increased to 31.3 mD (9.5 % permeability changes based on fresh permeability at 60 ˚C).

3.3. Quantitative XRD analyses Results of quantitative XRD analyses for fresh core samples and treated core samples with and without DESs solutions injections at 60 and 80 ˚C are shown in Table 4. These compositions were based on the bulk rock analyses and showed that quartz (96%) was the most common mineral in the cores. Comparison between fresh rock and treated rock samples shows that clay (kaolinite) concentration increased from 0.8% in the fresh sample to 2.1% in the brine-damaged samples. The amount of dolomite, anorthoclase and muscovite also increased marginally. However, the core samples treated with DES1 and DES2 solutions didn’t show changes in kaolinite concentration, while a dolomite increase was observed; this increase was highest in cores treated with DES1. In addition, the experimental data revealed that samples treated with DES1 or DES2 at 80 ˚C had a lower dolomitization than those at 60 ˚C.

3.4. SEM study SEM images of fresh material and treated samples (both DES1 and DES2) are shown in Fig. 4. Several grains and pore-filling clays were also analyzed by Electron Dispersive Spectrometry (EDS). These analyses helped in the determination of some unidentified mineral grains. In the untreated sample (Fig. 4a), quartz was the dominant mineral phase, accompanied by minor pore-filling cements of dolomite, kaolinite, and feldspar. Corroded quartz surfaces and further grain coatings were observed in DES1 treated samples (Fig 4b), while untreated material shows no or only minor corrosion. The EDS analyses revealed that the latter coatings include dolomite, feldspar, kaolinite, and quartz grains. Figure 4c illustrates the SEM images of a sample treated with DES2 solution where, when compared with DES1, only a mild corrosion of the quartz surface and minor coatings were observed.

3.5. CT-scanning Results CT scanning was carried out at 60 oC for four core samples including fresh sample, brine treated sample, and two treated samples with DESs solutions, where DES was injected between brine and distilled water flooding. Four representative radial and axial scan images are shown in figs. 5 and 6, respectively. The average Hounsfield Unit

8

(HU), as a quantitative indication of density, is also reported. Comparing the damaged core sample images with those of fresh ones indicate that the damages are non-uniform along the cores. In the CT-scan images, the damage can be identified by lighter grays and strain with higher HU values. The lowest average of radial and axial HU was 1326 (fresh material), while it was 1340 for the sample treated with DES2 (8.7% damage), 1361.5 for the sample treated with DES1 (58.4 % damage), and 1376 for the brine-treated sample (65% damage).

4.

Discussion

The change in core sample weight was found to be directly proportional to the amount of permeability reduction. SEM images (Fig.4) and CT scans (Figs. 5 and 6) support this finding by showing mineral precipitations (coatings) that led to pore plugging in the cores during DESs injections. Additional water adsorption on clay surfaces probably contributed to this effect, which ultimately resulted in the permeability reduction and the associated formation damage. Results of changing temperature during the coreflooding test indicate that parts of the precipitates formed at 60 ˚C were dissolved in distilled water at 80 ˚C (when the test was treated again at higher temperature in the same sample). A comparison between weights changes of treated core plugs by DES at 80 ˚C and at 60 ˚C suggests that amount of precipitation was less at 80 ˚C. In addition, the quantitative XRD analysis (Table 4) confirmed the temperature effect on the amount of precipitations. Okoye et al. (1991) reported similar observations for brine injections into the Berea sandstone, where reversible formation damage occurred at low temperatures. However, at temperatures above 93.3 ºC, the damage became more severe (up to 40%) and irreversible since hydrothermal effects dominated mechanical effects (such as fines migration). Comparison between fresh rock and treated rock samples shows that clay (kaolinite) concentration increased from 0.8% in the fresh sample to 2.1% in the brine-damaged samples, most probably because of clay formation that occurred in parallel to quartz destruction (higher SiO2-solubility under alkaline conditions; corrosion seen under SEM). However, since kaolinite also requires aluminium for its formation, a source of this element is also needed and is most likely found in decomposing feldspar (anorthoclase). The amount of dolomite, anorthoclase and muscovite also increased marginally due to re-crystallisation of various mineral components (muscovite probably derived its elements - K, Al, Si - from quartz and anorthoclase). However, the core samples treated with DES1 and DES2 solutions do not show changes in kaolinite concentration; while an increase in dolomite was observed (its carbonate content likely has originated from within the fluids). However, this increase in dolomite was highest in cores treated with DES1. Similar results were reported by Nasr-El-Din et al. (1998, 2011a,b) that although the clay stabilizers work well in stabilizing the clay, they still may cause some damages to the formation.

9

Conclusions Summarizing the results of our experiments and analyses, we are able to show that despite the DES’s solutions role in preventing severe water shock damage and stabilizing the clays, there was still some formation damage caused by re-crystallization and precipitation processes reducing the permeability of the core samples. The two tested DESs reduced these damages, DES2 yielded the best results.

References

1. Alexei, A. T., “Colloid Chemistry of In-Situ Clay-Induced Formation Damage”, SPE 58747, Presented at the 2000 SPE International Symposium on Formation Damage Control held in Lafayette, Louisiana, 23–24 February 2000. 2. Al-Mohammad, A. M., Al-Khaldi, M. H. and Al-Yami, I. S., “ Seawater Injection into Clastic Formations: Formation Damage Investigation Using Simulation and Coreflood Studies”, SPE 157113, This paper was prepared for presentation at the SPE International Production and Operations Conference and Exhibition held in Doha Qatar, 14–16 May 2012. 3. Al-Sulaimani, H., Al-Wahaibi, Y., Al-Bahry, S.N., Elshafie, A., Al-Bemani, A., Joshi, S. and Zaragari S.,”Optimization and partial characterization of biosurfactant produced by Bacillus species and their potential for enhanced oil recovery”. SPEJ, 16 (3):672-682, 2011. 4. Bennion, D. B., "An Overview of Formation Damage Mechanisms Causing a Reduction in the Productivity and Injectivity of Oil and Gas Producing Formations", Journal of Canadian Petroleum Technology, Volume 41, No.11 Nov. 10-15 2002. 5. Dai Y., Spronsen J. V., Witkamp G. J., Verpoorte R.and Choi Y. H.,”Natural deep eutectic solvents as new potential media for green Technology”, Analytica Chimica Acta 766 (2013) 61– 68. 6. El-Monier, I.A. and Nasr-El-Din, H.A., “A New Al-Based Stabilizer for High pH Applications”, SPE 143260, presented at the Brasil Offshore Conference and Exhibition held in Macaé, Brazil, 14–17 June 2011. 7. El-Monier, I.A. and Nasr-El-Din, H.A., “A study of several environmentally friendly clay stabilizers”, SPE 142755, presented at SEP facilities and challenges conference at METS held in Doha, Qatar, 13-16 February 2011. 8. Green, J., Cameron, R., Patey, I., Nagassar, V. and Quine, M., “Use of Micro-CT Scanning Visualisations To Improve Interpretation of Formation Damage Laboratory Tests Including a Case Study From the South Morecambe Field”, SPE 165110, This paper was prepared for presentation at the SPE European Formation Damage Conference and Exhibition held in Noordwijk, The Netherlands, 5–7 June 2013. 9. Habibi, A., Heidari, M. A., Al-Hadrami, H., Al-Ajmi, A., Al-Wahaibi. Y., Ayatollahi, Sh., “Effect of MgO Nanofluid Injection into Water Sensitive Formation to Prevent the Water Shock Permeability Impairment”,

10

SPE 157106, paper prepared at the SPE International Oilfield Nanotechnology Conference held in Noordwijk, The Netherlands, 12–14 June 2012. 10. Hayyan A., Hashim M., Mjalli F.S., Hayyan M., AlNashef I.M., “A novel phosphonium-based deep eutectic catalyst for biodiesel production from industrial low grade crude palm oil”, Chemical Engineering Science 92 (2013) 81–88. 11. Jiaojiao, G., Jienian, Y., Zhiyoong, Li. and Zhong, He,” Mechanisms and Prevention of Damage for Formations with Low-porosity and Low-permeability”, SPE 130961, This paper was prepared for presentation at the CPS/SPE International Oil & Gas Conference and Exhibition in China held in Beijing, China, 8–10 June 2010. 12. Mikhailov, N., Chirkov, M. ,”Formation Damage Kinetics and its Effect on Oil Reservoir Productivity”, SPE 128403, This paper was prepared for presentation at the SPE North Africa Technical Conference and Exhibition held in Cairo, Egypt, 14–17 February 2010. 13. Mohsenzadeh, A., Al-Wahaibi, Y., Jibril, B. and Al-Hajri, R. 2014. The Novel Use of Deep Eutectic Solvents for Enhancing Heavy Oil Recovery. Paper SPE169730-MS presented at the SPE EOR Conference at Oil and Gas West Asia held in Muscat, Oman, 31 March–2 April. 14. Mojarad, R.S.and Settari, A., “Multidimensional Velocity-Based Model of Formation Permeability Damage: Validation, Damage Characterization, and Field Application”, SPE 97169, This paper was prepared for presentation at the 2005 SPE Annual Technical Conference and Exhibition held in Dallas, Texas, U.S.A., 9 – 12 October 2005. 15. Mogensen, K., Stenby, E. H., Zhou, D.,”Studies of waterf looding in low-permeable chalk by use of X-ray CT scanning”, Journal of Petroleum Science and Engineering 32 (2001) 1 – 10. 16. Moghadasi, J., Jamialahmadi, M., Müller-Steinhagen H., and Sharif, A.,”Formation Damage Due to Scale Formation in Porous Media Resulting From Water Injection”, SPE 86524, This paper was prepared for presentation at the SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, U.S.A., 18–20 February 2004. 17. Nasr-El-Din, H.A., Al-MuIhem, A.A. and Lynn, J.D., “Evaluation of Clay Stabilizers for a Sandstone Field in Central Saudi Arabia”, SPA 39584, presented at the 1990 SPA International symposium on Formation Damage Control held in Lafayette, Louisiana, 13-19 February 1998. 18. Nengkoda, A., Habsi, M., Salmi, A., Annamalai, I., Ahmed, D., Sariry, S., Hadhrami, H., “ Learnt from Formation Damage Problems to Design Selection of Produced Water Treatment for First Full Field Development Steam EOR Oman”, SPE 131701, This paper was prepared for presentation at the SPE EUROPEC/EAGE Annual Conference and Exhibition held in Barcelona, Spain, 14–17 June 2010.

11

19. Okoye, C., Onuba, N.L., Ghalambor, A. and Hayatdavoudi, A., “Formation Damage in Heavy-Oil Formation During Steamflooding”, SPE 22980, This paper was prepared for presentation at the SPE Asia-Pacific Conference held in Perth. Western Australia, 4-7 November 1991. 20. Patino, O., Civan, F., Shah, S. N., David R. Zornes, Eugene, Spinler, A., “Identification of Mechanisms and Parameters of Formation Damage Associated with Chemical Flooding”, SPE 80271, This paper was prepared for presentation at the SPE International Symposium on Oilfield Chemistry held in Houston, Texas, U.S.A., 5–7 February 2003. 21. Schembre, J. M., and Kovscek, A. R., “Thermally Induced Fines Mobilization: Its Relationship to Wettability and Formation Damage”, SPE 86937, presented, at the SPE International Thermal Operations and Heavy Oil Symposium and Western Regional Meeting held in Bakersfield, California, U.S.A., 16–18 March 2004. 22. Scott, H.E., Patey, I.T.M. and Byrne, M.T,”Return Permeability Measurements—Proceed With Caution”, SPE 107812 , presented at the European Formation Damage Conference held in

Scheveningen, The

Netherlands, 30 May–1 June 2007. 23. Siddiqui, Sh., Nasr-El-Din, H. A., Khamees, A., “Wormhole initiation and propagation of emulsified acid in carbonate cores using computerized tomography” ,Journal of Petroleum Science and Engineering 54 (2006) 93–111. 24. Valdya, R.N., and Fogler, H.S., “Fines Migration and Formation Damage: Influence of pH and Ion Exchange”, SPE Production Engineering, November 1992, pp 325-330. 25. Yue D., Jia Y., Yao Y., Sun J., Jing Y., “Structure and electrochemical behavior of ionic liquid analogue based on choline chloride and urea”, Electrochimica Acta 65 (2012) 30– 36. 26. Zhang Q., Vigier K.D.O., Royer S. and Rome F.O. “Deep eutectic solvents: syntheses, properties and applications” , Journal of chemical Society Reviwers,Chem. Soc. Rev., 2012,Vol. 41, Issue 21, PP.71087146; DOI: 10.1039/C2CS35178A.

12

List of tables: Table 1: Brine properties

Density @ 25 ˚C

1.05

g/cm3

9

%Wt.

Sodium

25.083

kg/m3

Calcium

3.672

kg/m3

Magnesium

0.878

kg/m3

Iron

0.045

kg/m3

Chloride

47.722

kg/m3

Sulphate

0.247

kg/m3

Bicarbonate

0.079

kg/m3

Total salinity

Table 2: DESs properties

Density measurements Temperature ( ˚C )

Density (g/cm3)

25

45

60

80

DES1(chcl:Glycerol)

1.2141

1.2028

1.1943

1.1829

DES2 (chcl:Urea)

1.2185

1.2075

1.1945

1.1771

50 % (v/v) DES1 with brine

1.145

1.132

1.123

1.107

50 % (v/v) DES2 with brine

1.145

1.132

1.123

1.111

Viscosity measurements

Viscosity (cp)

DES1 (chcl:Glycerol)

390

111

55

40

DES2 (chcl:Urea)

250

63

34

14

50% (v/v) DES1 with brine

6.3

3.3

2.5

2.13

50 % (v/v) DES2 with brine

3.8

3

2.5

2.0

pH measurements pH

50 % (v/v) DES1 with brine

6.50

6.47

6.45

6.41

50 % (v/v) DES2 with brine

9.70

9.57

9.07

8.48

13

Table 3: Experimental conditions and results of formation damage tests by core flooding

Fresh Test No.

Chemical

Temperature Pressure (˚C)

(psi)

Core

Used

core dry core dry

porosity weight

weight

(g)

(g)

Fresh

Used

Weight

Perm.

core

core

changes Changes

perm.

perm.

(%)

(%)

1

Brine

40

1200

20.1

174.73

175.41

47.5

19

0.388

60

2

DES 1

40

1200

19.6

178.91

179.29

44

33

0.209

25

3

DES2

40

1200

20.4

177.66

177.7

31.6

30.9

0.022

2.2

4

Brine

60

1200

20.7

176.37

177.07

52

18

0.396

65

5

DES 1

60

1200

19.2

180.15

180.98

34.5

14.6

0.460

57.6

6

DES 2

60

1200

20.2

174.37

174.69

44

38.8

0.183

11.8

7

Brine

80

1200

19.8

175.57

176.28

37

12.17

0.404

67.1

8

DES 1

80

1200

20

177.67

177.79

40

38.5

0.006

3.7

9

DES2

80

1200

19.6

177.77

177.82

39

38

0.0028

2.6

Table 4: XRD results

Treated Treated Treated Treated Fresh Treated with DES1 with DES2 with DES1 with DES2 sample with brine @ 60 ˚C @ 60 ˚C @ 80 ˚C @ 80 ˚C Wt.% Wt. % Wt. % Wt.% Wt.%

Compound

Formula

Quartz

SiO2

96

92.6

94.9

96.2

95.8

96

Dolomite

CaMg(CO3)2

1.1

1.9

2.0

1.5

1.5

1.2

kaolinite

Al2Si2O5(OH)4

0.8

2.1

0.8

0.8

0.7

0.8

anorthoclase

(Na,K)AlSi3O8

2.1

2.6

2.3

1.5

2.0

2.0

0

0.8

0

0

0

0

Muscovite KAl2(AlSi3O10)(F,OH)2

14

List of Figures:

Figure 1:: Formation damage setup and schematic diagram

Figure 2:: Effects of injection flow rates on permeability changes

15

80

% permeability reduction

70 60 50 40

treated with brine

30

treated with DES1

20

treated with DES2

10 0 40

60

80

Temperature ( ˚C) Figure 3:: Effects DESs injection on permeability reduction at different temperature

Figure 4:: SEM images of (a) fresh sample, (b) sample treated with DES1, (c) sample treated with DES2

16

Figure 5: CT- scan Images (Radial sections) of fresh, untreated, treated with DES1 and DES2

sample

Flow direction

Fresh

Average Axial HU=1324 Treated with brine

Average Axial HU= 1380

Treated with DES1

Average Axial HU=1365

Treated with DES2

Average Axial HU=1344 Figure 6: CT-Scan Scan Images (Axial section) of fresh, untreated, treated with DES1 DES2

17

•

Effects of two DESs on formation damage were studied at reservoir conditions

•

The water shock phenomenon caused severe damage

•

Re-crystallization in the cores appears to be the main cause for formation damage

•

The tested DESs reduced the formation damage significantly

•

The DESs can play a major role in water shock prevention and as clay stabilizers

18