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SPE 160253 Formation Flow Impairment in Carbonate Reservoirs Due to Asphaltene Precipitation and Deposition during Hydrocarbon Gas Flooding Fahad I. Syed*, Shawket G. Ghedan**, the Petroleum Institute, Ahmed R. Hage***, Syed M. Tariq, Hesham Shebl, ZADCO Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the Abu Dhabi International Petroleum Exhibition & Conference held in Abu Dhabi, UAE, 11 14 November 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Hydrocarbon gas injection has proven to be one of the most efficient Enhanced Oil Recovery (EOR) methods, especially for tight and heterogeneous reservoirs with light to medium API oil, where water flooding is expected to be inefficient. Asphaltene precipitation and deposition, however, might occur due to pressure and fluids compositional changes with the gas injection. This complex phenomenon requires experimental and numerical investigation to understand the conditions at which flow impairment due to asphaltene formation damage may occur, resulting in lowering well flow capacity and in turn lower ultimate oil recovery. In this experimental study, low permeability carbonate rock core samples were flooded with hydrocarbon gas under reservoir conditions. The floods were conducted on core samples of two different lengths representing two different rock types based on average rock permeability and Pore Throat Size Distribution (PTSD). Additionally, these core samples were flooded at two different operating conditions to mimic the average reservoir and the wellbore flowing pressure conditions. As a prelude to these experiments, Asphaltene Onset Pressure (AOP) and Asphaltene Onset Concentration (AOC) of the oil under study with the injection gas were established through NIR, SARA and Titration analysis. Flow impairment due to formation damage by asphaltene precipitation and deposition was analyzed through permeability measurements before and after gas flooding. In all cases permeability reduction was observed. Permeability reduction was found to be function of rock types, reservoir pressure, and length of composite core samples. We assume that pore throat bridging by the larger size asphaltene particles caused higher permeability reduction in the samples of poorer rock types. Experiments conducted at lower pressures showed more damage. This is consistent with the lower AOC at lower pressure. Longer core samples give more time for asphaltene flocculation resulting in more asphaltene formation damage and more permeability reduction. Scanning Electron Microscopic (SEM) images of core plugs before and after the gas flooding process were found to be not conclusive with respect to direct detection of asphaltene deposition in the core samples and further work is planned to positively identify asphaltene deposition in the rock samples. 1. Introduction Asphaltene are the polar, polyaromatic and heaviest hydrocarbon fraction of crude oil that are soluble in light aromatic hydrocarbons and solvents such as benzene and toluene but insoluble in low molecular weight parafins 1-4. As a result of reservoir fluid depressurization, asphaltene particles may deposit on the formation rock surface and/ or to plug the rock pore throats. Another practical reason reported in the literature is the injection of different solvents for oil displacement during Enhanced Oil Recovery (EOR) processes, which often leads towards the reservoir fluid composition alteration and hence results in the Asphaltene flocculation and deposition 5-7. * Now with Zakum Development Company (ZADCO) ** Now with Computer Modeling Group (CMG) *** Now with Halliburton

2 SPE 160253 The well injectivity and productivity could be affected due to the deposition of asphaltene not only in the wellbores, surface pipe lines and the processing facilities but also due to the deposition in the formation near the wellbores 8-10. There are several factors that may lead to asphaltene precipitation in the reservoir. Along with the reservoir fluid properties and composition as well as the rock mineralogy and pore throat size distribution (PTSD), electro-kinetic effects due to streaming potential generation by means of reservoir fluid flow, asphaltene to resin ratio and the amount of formation brine and its composition, etc. are considered as the potential factors to contribute to formation damage due to asphaltene precipitation and deposition 8-12. Gas injection is considered as one of the best secondary and tertiary recovery methods to minimize the residual oil saturation (S or ), leading to higher oil recoveries in oil reservoirs 13. Several papers, however, concluded that the miscible and/ or immiscible gas injection causes changes in the reservoir fluid composition and hence the asphaltene precipitation leading to formation damage 14-18. Formation damage due to asphaltene precipitation and deposition may cause serious production losses due to reduction in well productivity. Most operators adopt the remedial solutions after evidence of asphaltene precipitation (such as chemical treatment and workover operations) rather than its prevention due to late detection of this problem 19. The dynamic core-flooding experimental analysis is one of the most effective methods that could be utilized to determine the potential of asphaltene precipitation and deposition in the formation rock core samples under reservoir conditions 19. This paper presents the results of a formation damage study for a reservoir due to asphaltene deposition as a result of hydrocarbon gas injection. This study consists of flooding live oil saturated core samples with hydrocarbon gas and monitoring any changes in the rock permeability due to possible asphaltene deposition, flocculation and precipitation. The study was designed to very closely mimic the future gas injection process in this reservoir by using representative core samples and reservoir fluids the real operating conditions. To increase the oil production rates and recovery from a tight part of a major carbonate reservoir, the operator is deliberating gas injection recovery mechanism. However, miscible and/ or immiscible gas injection may cause changes in the composition of reservoir fluids and hence the asphaltene precipitation, flocculation and possible deposition leading to formation damage. This study has been conducted as a part of flow assurance to quantify the impact of asphaltene induced formation damage which may result in loss of well productivity and hence the oil recovery. The aim of this project was to study the formation damage/permeability impairment due to the plugging of the rock pore throats by means of asphaltene precipitates. This paper starts by briefly describing the core flooding experimental setup and the steps that were adopted in this study. It, then, defines the phenomenon of asphaltene precipitation, flocculation and deposition into the reservoir rock core samples as function of the composition of the injected hydrocarbon gas and the resident reservoir fluid and their properties at two different reservoir operating pressures. The same flooding experiments were performed on core samples of two different rock types and two different length composite cores. 2. Experimental Setup and Work Flow The laboratory experimental setup was designed to perform all the steps under reservoir conditions. The experimental setup consists of high pressure and temperature core flooding unit (Fig. 1) with Hassler type core holder mounted into the oven as shown in Fig. 2; associated with high pressure injection pumps, and sensitive digital gauges for continues monitoring of pressure, temperature and flow rate during flooding. Fig. 3 represents the work flow for this study. The study was performed in three phases: Preparation and characterization of fluids and core samples. Flooding of core samples with series of fluid samples in certain combination, as listed in Fig. 3. Finally, the physical properties of the core samples before and after core flooding were analyzed. SEM images of the core samples before and after flooding helped to support the experimental results. 3. Rock Samples Characterization and Preparation Total of 16 core plugs with Packstone texture were provided from a giant offshore carbonate reservoir with a porosity range of 21-23%. The Pore Throat Size Distribution (PTSD), geological composition and texture, of the core samples were characterized on the basis of Mercury Injection Capillary Pressure Curves (MICP), Routine Core and Thin Section analysis. SEM analysis of the core samples was performed before and after gas flooding to detect any possible deposition of asphaltene in the pore and the pore throats of the rock pore spaces.

SPE 160253 3 Fig. 1: Core Flooding Unit (Oven with automatic Console) Fig. 2: Hassler Type Core Holder, Sample Fluids Cylinders & Fluid Separator. Fig. 3: Project Work Flow.

4 SPE 160253 3.1. Porosity-Permeability Relationship Fig. 4 presents the Porosity-Permeability cross plot of the core samples. Based on the Klinkenberg Permeability of the individual core plugs, two rock types were recognized as RRT A and B with the average permeability values of 2.61 and 1.52 md, respectively. 3.2. MICP Curves Analysis Fig. 4: Porosity-Permeability Cross Plot. The Capillary Pressure (Pc) was determined by using cleaned and dried trimmed core plugs with known pore volumes and permeability. The MICP curves were plotted as a function of incremental pore volume of mercury injected into the cleaned and dried trimmed sections. The MICP plots of RRT A and B are presented in Fig. 5 and 6, respectively. The derived PTSD of these rock types are presented in Fig. 7 and 8. Table 1 shows the average pore throat sizes of both the rock types. Table 1: Average Pore Throat Sizes Rock Types Avg. Pore Throat Size (!m) RRT A 0.788 RRT B 0.626 3.3. Thin Section Analysis By analyzing thin sections of all the individual core plugs, similar texture and lithology of Lime-Packstone was found. Intra- and inter granular porosity were identified that might have been formed as a result of partial dissolution. Over all analysis led to the belief that the inter granular porosity can be the primary porosity while some fractures were also found and might have been induced as a result of tectonic movements.

SPE 160253 5 Fig. 5: MICP curves of rock plugs RRT A Fig. 6: MICP curves of rock plugs RRT B Fig. 7: PTSD of rock plugs RRT A. Fig. 8: PTSD of rock plugs RRT B. Fig. 9: Thin Section image of RRT A sample. Fig. 10: Thin Section image of RRT B sample. 4. Reservoir Fluid Validation and Characterization

6 SPE 160253 Oil and gas samples were collected at surface from the separator that were recombined on GOR basis in the lab at the reservoir conditions of 3800/212 (Psi/ o F) to produce the live oil. Some traces of water were found in the oil and gas samples that were initially removed. After recombination, validation tests were performed for the verification of GOR, Bubble Point Pressure, P b, and the oil composition. While the Dead Oil (STO) and Formation Water samples were collected at surface conditions. Gas samples were collected at the separator conditions that were later subjected to the reservoir conditions. After gathering all the fluid samples, their physical properties were measured in the lab. 4.1. SARA Analysis Saturate, Aromatics, Resins and Asphaltene (SARA) contents were measured for the dead oil sample. While the asphaltene as the n-heptane insoluble fraction of crude oil was characterize by applying IP 143 (French Institute of Petroleum) procedure. Fig. 11 shows the weight percentage of the SARA contents. 4.2. Asphaltene Onset Concentration Fig. 11: Wt. % of SARA Contents. The Asphaltene Onset Concentration (AOC) of the reservoir fluid was studied at two different pressure values i.e. average reservoir pressure (P res =3850 Psi) and wellbore flowing pressure (Pwf=2850 Psi), while the system temperature was kept constant (i.e. T res =212 o F). The AOC at the defined pressure values were determined by means of titration of single phase live oil bottom-hole sample with the continuous injection of associated hydrocarbon gas, at a constant rate. Through light transmittance (by using NIR-SDS), the fluid mixture was continuously monitored for the AOC, as presented in Fig. 12. As shown in the figure, the fluid mixture exhibited an onset of asphaltene precipitation at 38.8 mole % of injected associated hydrocarbon gas mixture at 3850 psi, whereas the AOC for the same fluid was found at 37 mole% injection at 2850 psi of associated hydrocarbon gas at the Pwf, as shown in Fig. 13. 5. Coreflood Experimental Results Formation damage analysis through asphaltene precipitation, flocculation and possible deposition was performed through core flooding in the following six steps;

SPE 160253 7 Fig. 12: NIR Scan for AOC with continuous injection of associated hydrocarbon gas at P res. Fig. 13: NIR Scan for AOC with continuous injection of associated hydrocarbon gas at P wf. Six (6) successful core flooding experiments are presented in this paper, including a set of four (4) experiments conducted on short composite cores (2 core plugs) and a set of two experiments conducted on long composite cores (4 core plugs). Table 2 presents the physical properties of the composite cores, their respective rock types, and length. The rock types are distinguished on the basis of their average permeability and PTSD. The average length of the short and the long composite core samples were 3.5 and 8.7 inches respectively. Furthermore, the table shows the operating pressure under which the core flooding experiments were conducted. It also includes the complete summary of permeability variations that were observed in initial three (3) experimental steps. After measuring the reference permeability K eff-sto, the STO was flushed out of the core by means of live oil at the respective conditions (i.e. P res or P wf ). The deposition test was then performed by flooding the core samples with associated hydrocarbon gas at the same operating conditions. During this flooding step, continuous reduction in permeability was observed with the increase in differential pressure. Although the STO has been considered as a good solvent for the asphaltene, results showed considerable reduction in permeability post gas flood

8 SPE 160253 Table 2: Physical properties of Composite Core Samples Sample RRT L Composite Core P Opt. (Psi) " (%) K abs (md) K eff-sto (md) C B Short P res 22.13 1.743 1.067 D A Short P wf 23.84 3.143 2.517 E A Short P res 23.42 2.622 2.403 F B Short P wf 21.20 1.792 1.403 G A Long P wf 24.33 2.291 1.923 H B Long P res 22.26 1.434 1.347 Figs. 14 to 19 show the plots of!p variation due to the alteration in rock permeability with the pore volume injection of associated hydrocarbon gas. Table 3 presents a summary of final effective permeability (K final-sto ) measured through STO at the end of coreflood after gas flooding with the reference to their initial effective permeability (K eff-sto ). Fig. 14:!P variation in Sample C (RRT B) due to Gas Flooding at P res. Fig. 15:!P variation in Sample D (RRT A) due to Gas Flooding at P wf. Fig. 16:!P variation in Sample E due to (RRT A) Gas Flooding at P res. Fig. 17:!P variation in Sample F due to (RRT B) Gas Flooding at P wf.

SPE 160253 9 Fig. 18:!P variation in Sample G due to (RRT A) Gas Flooding at P wf. Fig. 19:!P variation in Sample H due to (RRT B) Gas Flooding at P res. Table 3: Alteration of Reference Permeability of the Composite Cores Sample RRT L Composite Core P Opt. (Psi) K eff-sto (md) K final-sto (md) C B Short P res 1.067 0.452 D A Short P wf 2.517 0.950 E A Short P res 2.403 1.201 F B Short P wf 1.403 0.403 G A Long P wf 1.923 0.377 H B Long P res 1.347 0.391 Fig. 20 shows the overall comparison of the permeability reduction at two different stages with respect to their reference permeability values. Green bars represent the final altered permeability after gas flooding with the reference of blue bars that represent the initial effective permeability that was measured by dead oil flooding at S wirr. Also these K eff values for all the 6 sets of core samples are presented with the reference of single phase K abs-liq that was measured by formation brine flooding at 100% brine saturation. Fig. 20: Overall Permeability Comparison at Different Stages. Visual examination of the composite core sample before and after core flooding shows (Fig. 21) that a more prominent black layer of precipitates was deposited at the inlet face of the core, while some deposits were also found at the outlet face.

10 SPE 160253 Before Flooding After Flooding Inlet Face Outlet Face Fig. 21: Composite Core Sample H, Before and After Flooding. Before Flooding 6. Scanning Electron Microscopic Analysis Asphaltene precipitation in the rock pore spaces has been inferred from experimental results such as permeability reduction. In this study, however, an attempt has been made to visualize the asphaltene deposition into the core samples through Scanning Electron Microscopic images (SEM). SEM images however, were not conclusive in this study. It was difficult to identify the deposits of asphaltene from the rock grains due to undistinguishable colors. Fig. 22 shows a complete set of SEM images that were taken before and after core flooding and it seems that the presence of some material (possibly asphaltene precipitates) shows gradual reduction towards the outlet face of the composite core sample. Outlet After Flooding Inlet Inlet Center Outlet Fig. 22: SEM Images for Pore Throats Plugging Analysis of Composite Core Sample E To confirm the observations through the SEM images, the presence of asphaltene precipitates in the recovered oil samples was analyzed by a high resolution microscope under lab conditions at two different contrasts of 300x and 400x as shown in Figs. 23 and 24. Blank dots oil sample (Fig. 23) was used as a reference. The solid particles can be observed easily in the following images, presented in Fig. 24, and IP 143 method was then applied to make sure if the observed particles were actually asphaltene precipitates.

SPE 160253 11 Fig. 23: Microscopic image of Blank Oil Sample. 7. Formation Damage Evaluation Fig. 24: Microscopic images of Effluents (Recovered Oil due to Gas Flooding). Flow impairment due to formation damage by asphaltene precipitation and deposition was analyzed through permeability measurements before and after gas flooding. Table 4 presents a summary of the overall formation damage evaluation in terms of permeability alteration along with their operating condition and the core sample statistics. Table 4: Formation Damage Evaluation Sample RRT L Composite Core P Opt. (Psi) K i (md) K final (md) K final / K i Formation Damage (%) C B Short Pres 1.067 0.452 0.424 57.66 D A Short Pwf 2.517 0.950 0.377 62.30 E A Short Pres 2.403 1.201 0.499 50.10 F B Short Pwf 1.413 0.403 0.285 71.48 G A Long Pwf 1.923 0.377 0.196 80.39 H B Long Pres 1.347 0.391 0.290 71.00 In all cases, permeability reduction was observed and found to be a function of rock types, reservoir pressure, and length of composite stack. The phenomenon of asphaltene flocculation and possible precipitation was pronounced in longer composite cores, higher drawdown, where asphaltene particles have longer time span to get flocculated and hence deposited. It is suspected that pore throat bridging by the large size asphaltene particles caused higher permeability reduction in the samples of poorer rock types with smaller pore throats. Experiments conducted at lower pressures showed more damage. This is consistent with the lower AOC at lower pressure. Longer core samples possibly might have given more time for asphaltene flocculation resulting in more formation damage and more permeability reduction. Fig. 25 represents the direction of permeability alteration depending on the factors discussed above:

12 SPE 160253!"#$%&"'()'*)+$#,$-."/"&0)1/&$#-&"'()23$)&') 1456-/&$($)+#$%"5"&-&"'(7) ) ) 8"96)+$#,):'%;) </''2$2)-&)8"96$#) =5$#-&"(9)+#$443#$ >'?)+$#,):'%;)*/''2$2) -&)8"96$#)=5$#-&"(9) +#$443#$ 8"96)+$#,):'%;) </''2$2)-&)>'?$#) =5$#-&"(9)+#$443#$ >'?)+$#,):'%;)</''2$2) -&)>'?$#)=5$#-&"(9) +#$443#$7 Fig. 25: Direction of formation damage due to asphaltene precipitation. Fluid titration studies indicated that the AOC s of the provided composition of single phase live oil were 38.8 and 37.0 Mol% with the associated hydrocarbon gas at the Pres and Pwf, respectively. It means that at low operating pressure (i.e. P wf = 2850 Psi), less amount of gas will be required to initiate the process of asphaltene precipitation as compared to that at high pressure (P res = 3850 Psi). Hence, continuous injection of gas would cause more precipitation. Similarly, in terms of PTSD, the permeability of the poor rock type (RRT B) was expected to be reduced comparatively more than the good rock type (RRT A) due to pore throat plugging, depending on the asphaltene particle size. The experimental results of this study give the operator of the subject reservoir, an indication of what to expect in the reservoir undergoing associated hydrocarbon gas flooding. These results should be further evaluated by the operator in terms of the dominance of the rock types in the reservoir, as well as the pressure under which the gas flooding operation will be taking place and the pressure distribution at different stages of the life of the reservoir. 8. Conclusion The main observations and conclusion drawn from this study are stated as follows: The reservoir fluid characterization and coreflood experiments were successfully conducted for the subject reservoir. Systematic analysis of the experimental results indicate permeability reduction during hydrocarbon gas flooding into the live oil saturated composite core samples, possibly due to the rock pore throats plugging by asphaltene precipitates. Within the same rock type, larger permeability impairment was observed at comparatively lower operating pressure. This is because of the lower AOC i.e. less amount of injection gas required to start drop outs of asphaltene precipitates at lower operating pressure. At the same operating pressure, the permeability alteration was found more pronounced in the rock core samples with comparatively smaller PTSD. Because of the greater residence time; the phenomenon of formation damage due to asphaltene precipitation and deposition was observed more pronounced into the larger composite core samples regardless of operating pressure and rock types. The workflow and coreflood methodology for assessing risk of asphaltene deposition can be applied for the evaluation of field development options. The approach combines information from different aspects of asphaltene precipitation and deposition (fluid characteristics, rock characteristics and flow dynamics) to give best estimation of the risk of productivity improvement due to asphaltene deposition.

SPE 160253 13 Nomenclature AOC Asphaltene Onset Concentration AOP Asphaltene Onset Pressure (Psi) EOR Enhanced Oil Recovery GOR Gas Oil Ratio (Scf/STB) K abs-liq Absolute Liquid Permeability (md) K eff Effective Permeability (md) K eff-sto STO Effective Permeability (md) K final-sto Final STO Relative Permeability (md) L composite Composite Core Length (inches) MICP Mercury Injection Capillary Pressure (Psi) NIR Near Infra Red - Light transimitance method for asphaltene detection P c Capillary Pressure (Psi) P Opt. Operating Pressure (Psi) P res Reservoir pressure (Psi) PTSD Pore Throat Size Distrabution (!m) P wf Wellbore Flowing Pressure (Psi) RRT Rock Type SARA Saturates, Aromatics, Resins and Asphaltene SEM Scanning Electron Microscope S or Residual Oil Saturation (%) S wi Initial Water Saturation (%) S wirr Irreducable Water Saturation(%) STO Stock Tank Oil Acknowledgements The research related this work and all the flooding experiments were performed in the Petroleum Institute and supported by ADNOC R&D Oil Sub Committee while all the samples and data were provided by Zakum Development Company (ZADCO). References: 1. Eric Y. Sheu, Oliver C. Mullins, Colloidal Properties of Asphaltenes in Organic Solvents, Asphaltene Fundamentals and applications; Plenum, Press, New York City, p.152, (1995). 2. Hischberg A., Dejong L.N.J., et al., Influence of Temperature and Pressure on Asphaltene Flocculation, SPEJ 11202-PA, p.283, (1984). 3. Mousavi S.A., Riazi M.R., et al., An analysis of methods for determination of onsets of asphaltene phase separations, Journal of Petroleum Science and Engineering, 42, p.145, (2004). 4. Liao Z., Geng A., Reviews; Asphaltenes in oil recovery, Chinese Science Bulletin, Vol. 45, No. 8, (2000). 5. Leontaritis K.J., Amaefule J.O., Charles R.E., A Systematic Approach for the Prevention and Treatment of Formation Damage Caused by Asphaltene Deposition, SPEJ 23810, p.157 (1994). 6. Roger M. Butler, Igor J. Mokrys Recovery of Heavy Oil Using Vaporized Hydrocarbon Solvents: Further Development of the Vapex Process, JCPT 93-06-06, p.56 (1993). 7. de Pedroza, T.M., Calderon, et al., Impact of Asphaltene Presence in Some Rock Properties, SPE ATS 27069, p.185 (1996). 8. Minssieux L., Core Damage from Crude Asphaltene Deposition, paper SPE 37250, (1997). 9. Kamath V.A., Yang Jiede, Sharma, Effect of Asphaltene Deposition on Dynamic Displacement of Oil by Water, paper SPE 26046 (1993). 10. Gonzalez G., Louvisse A. Maria, The Adsorption of Asphaltenes and Its Effect on Oil Production, paper SPE 21039, (2003). 11. Rayes, B.H., Penyeszi, T., Lakatos, I., Comparative Study of Asphaltene Adsorption on Formation Rocks under Static and Dynamic Conditions, paper SPE 80265, (2003).

14 SPE 160253 12. Kabir C.S., Jamaluddin A.K.M., Asphaltene Characterization and Mitigation in South Kuwait s Marrat Reservoir, paper SPE 53155 (1999). 13. Jashidnezhad, M., Prediction of Asphaltene Precipitation in an Iranian South Oil Field, paper SPE 2005-015, (2005). 14. Yi T., Fadili A., et al., Modeling the Effect of Asphaltene on the Development of the Marrat Field, paper SPE 120988 (2009). 15. Srivastava R.K., Huand S.S., Dong M., Asphaltene Deposition During CO 2 Flooding, SPE-POJ 59092 (1999). 16. Ghedan, S., Global Laboratory Experience of CO2-EOR flooding, paper SPE 125581 (2009). 17. Syed F. Iqbal, Tunio A. Haque, Ghirano N. Ahmed, Compositional Analysis and Screening for Enhanced Oil Recovery Processes in Different Reservoir and Operating Conditions ; International Journal of Applied Science and Technology, Vol. 1 No.4; July 2011, p143-160. 18. Kokal S.L., Selim G. Sayegh, Asphaltenes: The Cholesterol of Petroleum, paper SPE 29787 (1995). 19. Oskui G.P., Jumaa M.A., Abuhained A. Waleed, Laboratory Investigation of Asphaltene Precipitation Problems during CO2/ Hydrocarbon Injection Project for EOR Application in Kuwaiti Reservoirs, paper SPE 126267 (2009).