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Cite This: Energy Fuels XXXX, XXX, XXX−XXX
Re-equilibrium of Asphaltenes by Repressurizing after Precipitation in Natural Depletion and CO2 Enhanced Oil Recovery Schemes Hideharu Yonebayashi,* Takumi Watanabe, and Yoshihiro Miyagawa
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Technical Research Center, INPEX Corporation, 9-23-30 Kitakarasuyama, Setagaya-ku, Tokyo 157-0061, Japan ABSTRACT: In a series of isothermal depressurizing tests to measure asphaltene onset pressure (AOP), several depressurizing operations are usually conducted to multiple AOPs using the same lot of fluid subsamples. After one depressurizing operation is finished, the pressure/temperature condition is reset to the initial condition. Then, the next depressurizing run is performed. Before the next run, the fluid sample must equilibrate again by dissolving precipitated asphaltenes from the previous step. According to our many experiences with isothermal depressurizing tests for measuring AOPs, we know that redissolving asphaltenes depends highly upon the characteristics of a fluid sample. Some fluids redissolve asphaltenes quickly, while other samples need a lot of time. This study focused on fluid-dependent asphaltene re-equilibrium during a series of isothermal depressurizing tests. To investigate asphaltene re-equilibrium, the authors re-examined past experimental data for two types of crude oils. In the experiment, continuous power of light transmittance (PLT) was monitored for all stages in the series of AOP measurements. Two series of isothermal depressurizing tests were separately performed to evaluate CO2-induced asphaltene risks for two fluid samples. Three or four total steps of depressurizing were conducted in order of CO2 addition ratios: 0, 20, 40, and 60 mol %. After a depressurizing process finished, pressure was increased above AOP to dissolve precipitated asphaltenes. PLT profiles in equilibrium steps between each depressurizing step were compared from a viewpoint of equilibrium time and/or PLT profile fluctuation. One of the fluids showed quick re-equilibrium of asphaltenes and smooth PLT profiles, whereas the other took much longer to achieve equilibrium and had fluctuating PLT profiles. This information suggested that easyequilibrium-achievable fluids would be a preferred target for CO2 enhanced oil recovery because of its potential use of pressure control for mitigating asphaltenes. In the case of easy-equilibrium-achievable fluid, when a production problem is caused by asphaltene precipitation, repressurization by temporary shut-in and/or production rate control can be an effective mitigation.
1. INTRODUCTION 1.1. More Focus on CO2 Enhanced Oil Recovery (EOR). Among many types of EOR options, CO2 EOR is widely applied and recognized as a promising method. Furthermore, it is getting focus for not only its effectiveness at oil recovery but also the mitigation of greenhouse gas emissions by storage. The annual World Energy Outlook (WEO) published by the International Energy Agency (IEA) has some important insights. According to the latest version of the WEO,1 issued in November 2017, two scenarios related to climate change, i.e., current and new policies on CO2 emissions, might still be far from sufficient for avoiding severe impacts from global warming. The projected CO2 emissions in current policies are consistent with a world that experiences around 3 °C (2.5 and 3.5 °C) warming in 2100. The WEO proposed new policies in-line with the Paris Agreement Commitments, which were adopted by consensus in December 2015. However, even applying the new policies cannot reduce the projected CO2 emissions, which keep continuously increasing through 2040, as shown in Figure 1. Therefore, a further advanced scenario was provided in the WEO report to encourage nations to quickly take steps to limit warming to no more than 2 °C. This sustainable development scenario expects reduction of CO2 emissions by a combination of several ways, such as efficiency improvements, replacement with renewable energies, fuel switching, more nuclear power, and carbon capture and storage (CCS), as shown in Figure 1. CO2 emission reduction by CCS is expected to account for 9% of CO2 emission reduction in 2040. The CCS concept © XXXX American Chemical Society
Figure 1. CO2 emission reduction contributions between the new policies and sustainable development scenarios. This figure was obtained with permission from ref 1. Copyright 2017 IEA.
traditionally assumes storage in underground aqueous reservoirs; however, CO2 EOR has been recognized as a type of CCS. For this reason, CO2 EOR is expected to take a larger role in future EOR applications. 1.2. Asphaltene Risks and Mitigation in Oil Fields. Asphaltenes are a class of compounds in the heavy ends of Special Issue: 19th International Conference on Petroleum Phase Behavior and Fouling Received: August 10, 2018 Revised: September 28, 2018
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DOI: 10.1021/acs.energyfuels.8b02781 Energy Fuels XXXX, XXX, XXX−XXX
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Energy & Fuels crude oil. In addition, asphaltenes are insoluble in n-alkanes (npentane or n-heptane) but soluble in aromatics, such as toluene, and cause many operational problems in oil fields. Typical problems are production loss and formation damage as a result of plugging of tubing and flowlines and in situ asphaltene deposition, closing pore throats near wellbores. In situ asphaltene deposition also alters the wettability of reservoir rocks to more oil-wet, resulting in a deterioration of ultimate oil recovery. Several types of triggers can cause asphaltenes to precipitate, such as pressure change, temperature change, and compositional alteration. To tackle the issues of asphaltene precipitation triggered by pressure change, it is important to understand the threshold pressure between stable and unstable asphaltenes, which is known as the asphaltene onset pressure (AOP). Reducing operating pressure to below AOP causes asphaltene precipitation. To mitigate such situations in a reservoir, pressure management is often applied to maintain the reservoir pressure above the AOP. Another major destabilizing trigger is compositional change of crude oil. Mixing crude oil with injection gas alters composition directly. In addition, the vaporizing gas drive also alters crude oil composition through multiple contact processes.2 Therefore, asphaltene risks should be considered when planning gas injection EOR. CO2 is known as the injection gas with the strongest impact on asphaltene destabilization. In fact, asphaltene analysis is currently a part of CO2 EOR studies, as shown in Table 1. This survey reveals that the CO2-induced asphaltene risk has been studied from many aspects, such as simulation, core flood test, compatibility test, etc. Some reports concluded no influence;7,29 however, the majority of studies pointed out risks caused by CO2 injection. One of the severer cases observed concrete deterioration of porosity and permeability with accelerated asphaltene deposition in the pore throat,23 and another severe case lost oil recovery as a result of plugging of a high asphaltene content in the core.16 1.3. Asphaltene Reversibility. To consider asphaltene mitigation potential from a viewpoint of pressure management, it is important to understand asphaltene reversibility. In general, the asphaltene precipitation/dissolution process is recognized to be reversible. However, it highly depends upon fluid characteristics and growing from fine particles to large aggregations. In other words, it is commonly found as an irreversible process. There are many reference studies on asphaltene reversibility. Hammami et al. analyzed asphaltene precipitation/redissolution behavior in live oils using a visual pressure−volume− temperature (PVT) cell equipped with a solid detection system (SDS), which applied a laser light scattering technique.31 In their works, characteristics of a highly reversible process were observed for several Gulf of Mexico oils during isothermal pressure depleting/charging experiments. More recently, Mohammadi et al. reported similar types of depressurization/ repressurization analyses to evaluate asphaltene aggregation reversibility for single-phase sampled Iranian oils.32 However, both Hammami et al. and Mohammadi et al. assumed natural depletion conditions, which have solely pressure-dependent reversible processes. In these cases, asphaltene reversibility was discussed from a viewpoint of kinetic precipitation. Chaisoontornyotin et al. studied asphaltene reversibility from the kinetic viewpoint of temperature-induced aggregation.33 On the other hand, there are other studies including not only kinetic but also
chemical precipitation reactions. For example, Peramanu et al. studied the precipitation and redissolution of asphaltenes for Athabasca and Cold Lake bitumen with the addition and removal of solvents.34 The Athabasca bitumen showed significant hysteresis, while the Cold Lake bitumen did not. The solvent-reversibility experiments were conducted by observing the pressure drop across an in-line filter in a flowloop apparatus. Further comprehensive work was performed by Abedini et al. to analyze asphaltene reversibility as a function of thermodynamic factors in porous and non-porous media, with triggers of pressure, temperature, and/or liquid composition changes using n-heptane.35,36 In our study assuming CO2 EOR, we evaluated asphaltene reversibility in the near wellbore region and production stream tubing, where the highest asphaltene risk occurs as a result of CO2 breakthrough under depleted pressure conditions.
2. MATERIALS AND METHODS 2.1. Flow Assurance System. A commercially available apparatus, flow assurance system (FLASS, Vinci Technologies),37 was used for this study. In most recent works, AOPs are usually measured by a convenient laser light scattering technique. FLASS has five simultaneous measuring functions: laser light transmittance, particle count, particle size by optical measurement, and both density and viscosity by kinetic feature measurement. The solid particle size measurement takes not only optical change but also kinetic variation into account because the particle size growth counts for molecular dynamics. To mitigate uncertainty in measuring AOP, all types of data should be taken into comprehensive interpretation without relying solely on laser-light-transmitted data.38 Preparatory fluid aging was carried out at reservoir conditions until the fluid reached equilibrium. After the fluid was stable at reservoir conditions, a certain amount of subsample was introduced into the FLASS from the aging bottle at the constant aging pressure via a transfer pump. After the transfer, the initial starting condition was checked again in the FLASS. An isothermal depressurizing test then commenced by decreasing the testing pressure gradually at certain steps of designed pressure for measurements. In each step, the pressure was temporary maintained during monitoring of “power of light transmitted (PLT)”, “highpressure microscopy” (HPM) count/size, and density/viscosity. All measured results were recorded as digital data in the equipped personal computer (PC). A schematic of the main equipment in the FLASS is shown in Figure 2. 2.2. Oils. Two synthetic live oils were prepared using dead oils collected from two oil fields, A and B. Variation between dead and target live oil compositions were identified to estimate a lack of components to be adjusted. Four mixed gas, consisting of light ends (C1−C2), CO2, and N2, were prepared and added to the dead oil to reproduce the target compositions. Field A has three wells that have the same source rock in the same geological area, but fluid characteristics were slightly different from each. Well 3 has the lightest oil in field A. Field B has 10 times the asphaltene content (2.44 wt %) compared to field A (0.22 wt %). The oils had American Petroleum Institute (API) gravities of 40° and 30° in fields A and B, respectively. The fluid properties of dead oils are compared, as shown in Table 2. The IATROSCAN MK-6 (Mitsubishi Chemical Medience) was used to conduct quantitative analysis on organic mixtures: saturates, aromatics, resins, and asphaltenes (SARA), which were separated on thin-layer chromatography (TLC) and detected by a hydrogen flame ionization detector (FID). On the basis of SARA results, the colloidal instability index (CII)39,40 was calculated for each fluid. The CII can be expressed as the following equation to identify asphaltene-instabilizing potential in petroleum systems: CII = B
(saturates + asphaltenes) (aromatics + resins)
(1) DOI: 10.1021/acs.energyfuels.8b02781 Energy Fuels XXXX, XXX, XXX−XXX
C
20
Alian et al.
23
Adyani et al.22
Okabe et al.21
Hayashi et al.
Zekri et al.19
Dahaghi et al.18
Broad17
Middle Eastern field field in South China Sea Malaysian field
field in United Arab Emirates NA
South American Midle Eastern NA NA Dukan field (Qatar) Kupal (Iran)
Verdier et al.15
Okwen16
Rangley (Corolado) field in Middle East Jilin (China)
Weyburn (Canada)
Parra-Ramirez et al.12 Takahashi et al.13 Hu et al.14
Srivastava et al.11
Novosad et al.9 Srivastava et al.10
Choiri et al.
8
Correra et al.7
Gonzalez et al.6
A1 A2 A3 W1 W2 W3
well-A fluid
oil J1 oil J2 SA crude oil ME crude oil ASH77 C1/nC10
oil oil oil oil oil oil
oil 1 oil J2
0.42
0.07
3.9
0.97
0.2
0.66
41
41.4
NA
NA
31.7
34.3
NA NA 27 29 29.3 47.6 35−40
NA
3.9 1.68 1.82 9 9 4.82 0.19 NA
19 NA 29.0 29.6 29.5 28.6 29 36 31 34
19 29.5 NA NA 32 27 10
29−36 approximately NA
API gravity (deg)
16.8 1.82 5.4 5.3 4.9 5.0 4.8 4.0 4.9 2.83
16.8 4.9 NA NA 1.4 9 NA
oil 1 oil 2 oil 3 oil 4 live oil STO
NA Weyburn Iranian field Iranian field NA South American field in southeast Sicily NA Jilin (China) Midale (Canada) Weyburn (Canada)
Vafaie-Selti et al.5
Ying et al.4
4.0−5.0 approximately 1.49−1.8
Weyburn (Canada) fields in China
Nghiem et al.3
asphaltene content (%)
field
source
sample
100 100a 97a 97a 147 147 102
2176a 2321a up to 5500a up to 5000a 3256 3256 4735
a
2015, 2315, and 2615
98
a
95.6
70
1715−5015a 2915
129
121
4154
4000
71
66 66 20−110a 20−110a 25 and 65a 25 and 65a NA
2901, 3481, and 4206a 2901a 8702a 8702a NA NA NA 6000
100
3515
2393 2901a 2320 2321 2321 2321 2321 2321 2321 NA
a
20−190 20−150a 65 59 59 59 59 61 63 71
NA
1537 (1233−5076)a
a
59
temperature (°C)
2321
pressure (psia)
oil viscosity (cP)
0.8
0.26
NA
NA
5.5 (at 40 °C)
NA
5.8 6.1 NA NA 15.9 and 3.6 2.0 and 0.9 NA
NA
NA NA NA NA NA 40 (U) and 300 (L) NA NA NA 4.2 4.6 4.6 4.2 2.35 3.15 NA
NA
NA
Table 1. Asphaltene Studies for CO2 EOR, Summarizing Examples of CO2-Induced Asphaltene Risk findings
there is potential for asphaltene plugging when a high concentration of CO2 gas is injected three core flood tests showed 16−22% permeability reduction with 6−19% porosity reduction as a result of asphaltene deposits
asphaltene precipitation occurs during CO2 injection, and the properties of the heavy-end fraction are significantly reduced asphaltene precipitation depends upon the CO2 concentration and rapidly increases when exceeding the critical value; permeability reduction is mainly caused by mechanical entrapment asphaltene precipitates by CO2 injection; a lower permeability core shows lower asphaltene loss and higher oil recovery than a higher permeability core permeability reduction by CO2 injection is around 20% as a result of large deposition at the upstream of the core asphaltene is selectively deposited near the inlet of the core for CO2 injection
lower oil recovery obtained from ASH77 (with higher asphaltene content) as a result of reservoir pore blockage during CO2 flood
less CO2 is required to precipitate asphaltene at the higher temperature
precipitated asphaltene increases as CO2 increases; more deposits in the carbonate core than the sandstone core no precipitation during natural depletion; in the system of CO2 injected fluid, precipitation was observed under operating conditions
multiple contacts increase precipitates for the same CO2 concentration
the main factor on asphaltene precipitation depends upon the CO2 concentration; Vuggy matrix shows the highest asphaltene precipitation in the core during CO2 flood
CO2 generally destabilized asphaltene asphaltene flocculation as a result of CO2 was insensitive in the operating pressure; the CO2 concentration was important
a model based on Flory−Huggins polymer solution and Hildebrand solubility concept was applied for designing EOR by CO2 injection
no significant risk of asphaltene deposition in CO2 injection
CO2 can increase or decrease the stability of asphaltenes depending upon the characteristics of the fluid and temperature
the important phenomena associated with the dynamics of asphaltene precipitation are properly reproduced dynamic characteristic analyses show that higher accumulation of asphaltene deposits is mainly at the inlet of the core the proposed model can predict asphaltene deposition in terms of CO2 flood; as the amount of resin increases, more CO2 is needed for the same amount of asphaltene deposition
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DOI: 10.1021/acs.energyfuels.8b02781 Energy Fuels XXXX, XXX, XXX−XXX
Article CO2-induced precipitates would be enhanced because of the multiple contacts even asphaltene flocculation is observed in the PVT cell; no sever permeability reduction occurs during CO2 core flood tests because of the low asphaltene content AOP is detected by mixing with CO2, even not detected at natural depletion; phase envelope is predicted to increase the asphaltene unstable area as CO2 increases
CO2 injection increases asphaltene deposition in all pressure ranges
Modeling/experimental/operating conditions in the case of the absence of reservoir pressure and reservoir temperature.
NA NA 0.25 reservoir-X crude oil Abdallah30
Deo et al.28 Takabayashi et al.29
4.04 14.7 5.3 2.8 NA fluid II
field in South China Sea Jilin (China) Kuh-e-Mond Gachsaran NA offshore field in United Arab Emirates field-A in United Arab Emirates Pedersen et al.26
Table 2. Fluid Properties of Dead Crude Oil Samples field
A
B
well
well 3
well 4
(g/cm3 at 20.0 °C) (deg) (g/cm3 at 20.0 °C) (°C)
0.8189 40.423 0.8232 150
0.8761 29.278 0.8821 100
(wt (wt (wt (wt (wt (wt (wt
49.29 45.71 4.78 0.22 100.00 49.51 50.49 0.98
29.38 65.71 2.47 2.44 100.00 31.82 68.18 0.47
ρ API gravity at 60 °F specific gravity (15/4 °C) bottomhole temperature SARA analysis saturates aromatics resins asphaltenes total saturates + asphaltenes aromatics + resins colloidal instability index (CII)
%) %) %) %) %) %) %)
Compositional alteration when CO2 is added in each synthetic live oil is compared in Figure 3. 2.3. Isothermal Depressurizing Test Procedure. The isothermal depressurizing test procedure is shown in Figure 4. The temperature was assumed to be reservoir conditions, namely, 150 °C for well 3 fluid and 100 °C for well 4 fluid. First, baseline AOPs based on natural depletion (i.e., no CO2 injection) were measured for each synthetic live oil sample. Second, AOPs were measured with CO2 addition; the addition ratio varied from 20, 40, to 60 mol %. Those experimental evaluations revealed how CO2 injection impacted the asphaltene precipitation risk. All runs were performed as continuous steps using identical live oils. After completion of each depressurizing step, the pressure was returned to the original reservoir condition to redissolve the precipitated asphaltenes and to establish equilibrium prior to the next step. Equilibrium was confirmed by PLT and HPM.
3. RESULTS 3.1. AOP Measurements. Using the multiple techniques38 for a comprehensive interpretation of AOP, we simultaneously measured four types of data: PLT, HPM particle size, HPM particle count, and viscosity. As a typical measurement result for the natural depletion scheme, Figure 5 shows inflection
a
NA
3000a NA
182a approximately
65.9 35 and 90a 35 and 90a 71a NA NA 435, 870, 1450, and 2031a
NA 12.8 31 34 NA
15.5 4.0 0.10 fluid I fluid II fluid I field in GOM Gonzalez et al.25
Zanganeh et al.27
findings
1D simulation of CO2 injection causes asphaltene precipitates in the transition zone between gas and oil; the deposit plugs reservoir and decreases permeability
NA field in Kuwait Memon et al.24
API gravity (deg) asphaltene content (%) sample field source
Table 1. continued
7.71 1.05 1.0 approximately NA NA NA NA NA 97.8 97.8 95.6 8029 9342 2901 22.5 28.4 41.4
NA 90 NA 32.4
oil viscosity (cP)
Figure 2. Schematic of the main equipment in FLASS.
pressure (psia)
temperature (°C)
injection gas (CO2/NGL mixture) is not compatible with the original reservoir oil the effects of added gases on reducing asphaltene stability in the live oil are in the order of N2 > CH4 > CO2
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DOI: 10.1021/acs.energyfuels.8b02781 Energy Fuels XXXX, XXX, XXX−XXX
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profile changes, whereas the higher inflection points triggered smaller variation. The lowest pressure points were ordered in sequence of optical and kinetic observations in the depressurizing process. This observation sequence could be explained by detection resolution and the aggregating process of the asphaltene particle. Optical detection using SDS could detect smaller particles that were soon precipitated. After further depressurization, asphaltene particles aggregated and grew to bigger aggregates to be detected with the change of fluid viscosity. Thus, the PLT-based AOP was higher than the viscosity-based AOP. In Figure 6, in the case of well 4 fluid undergoing natural depletion, two inflection points were obtained at 3107 and 4527 psig from the HPM count profile. When the HPM size inflection point was taken into account, the lower value of 3107 psig was judged as the appropriate AOP because of its consistency with the HPM size-based AOP of 2388 psig. Those two AOPs were closer compared to the higher HPM count-based value of 4527 psig. Figure 7 shows the measuring results for well 3 fluid with 40 mol % CO2 added. There was a single inflection point in each HPM-based measurement; however, two inflection points were obtained from the PLT and viscosity profiles. When the HPMinterpreted inflection point was taken into account, the lower viscosity-based value of 4234 psig was judged consistent to the HPM-based AOPs. Consequently, those three AOP interpretations were valued over the PLT-based inflection points. Similar interpreting exercises were applied to the other cases, and consequently, all measurement results are summarized in Table 3. In the case of multiple inflection points, the final interpreted value is shown as a bold number. Similar to the previous study arguing a technique-dependent AOP manner,38 the trend of AOP results showed a consistent manner in which AOPs were detected earlier by an optical method (i.e., at a higher pressure) and, subsequently, by a kinetic method (i.e., at a lower pressure) during a series of depressurizing processes in the case of well 3 fluid under a low CO2 mixing ratio and well 4 fluid at 0 mol % CO2. Namely, the optical measurement using SDS can detect smaller asphaltene particles, and then aggregated particles can be kinetically detected by a viscometer. This variation was attributed to the minimum detection size of asphaltene particles of each technique. On the other hand, for a higher CO2 mixing ratio, the technique-dependent AOP trend was lost because of an increasing viscosity-based AOP compared to the opticalbased AOP. The loss of trend was considered to be attributed to alteration from the viscosity of the original live fluid as a result of CO2 addition. While lower in asphaltene content, AOPs were higher in field A, well 3 fluids than field B, well 4 fluids. In addition, as
Figure 3. Comparison of compositional alteration when CO2 is added (0, 20, and 40 mol %). The blue line represents well 3 fluid (field A), and the red line represents well 4 fluid (field B).
points in PLT and viscosity profiles and no signs in HPM profiles for well 3 fluid. On the other hand, no inflection points were observed in PLT and viscosity profiles but several inflection points were observed in HPM profiles for well 4 fluid, as shown in Figure 6. To mitigate measuring failures and/or other factors leading to unreadable data, the simultaneous measuring techniques were quite useful as mutual backups. The most appropriate inflection point was chosen as AOP using comprehensive data interpretation. For example, in Figure 5, for well 3 fluid with 0 mol % CO2, three inflection points were obtained at 3012, 4854, and 6473 psig from the PLT profile. Similarly, three inflection points were obtained at 2295, 3514, and 3787 psig from the viscosity profile. The lowest pressure (3012 and 2295 psig on the PLT and viscosity profiles, respectively) was located at the interface of drastic
Figure 4. Isothermal depressurizing test procedure. E
DOI: 10.1021/acs.energyfuels.8b02781 Energy Fuels XXXX, XXX, XXX−XXX
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Figure 5. Results of the isothermal depressurizing test for field A, well 3 fluid with 0 mol % CO2.
Figure 6. Results of the isothermal depressurizing test for field B, well 4 fluid with 0 mol % CO2. F
DOI: 10.1021/acs.energyfuels.8b02781 Energy Fuels XXXX, XXX, XXX−XXX
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Figure 7. Results of the isothermal depressurizing test for field A, well 3 fluid with 40 mol % CO2.
Table 3. Summary of AOP Results in Field A, Well 3 and Field B, Well 4 PLT-based AOP (psig)
HPM count-based AOP (psig)
HPM size-based AOP (psig)
viscosity-based AOP (psig)
CO2 concentration (mol %)
well 3
well 4
well 3
well 4
well 3
well 4
well 3
well 4
0 20 40 60
6473, 4854, or 3012 5544 5055 or 3803 5779
NDa 2107 ND NAb
ND 3717 4259 5176
4527 or 3107 4783 or 2621 4266 NA
ND 3631 4220 4902
2388 2647 5248 or 4237 NA
3787, 3514, or 2295 3059 5035 or 4234 5231
ND ND 5341, 4878, 4589, or 3771 NA
a
ND, not detected. bNA, not available.
shown in Table 2, the CII analysis revealed a higher index in well 3 fluid compared to well 4 fluid. Therefore, it made sense that well 3 fluid showed higher AOPs with an unstable range of the CII value. Higher AOP was synonymous with asphaltenes being more easily precipitated. 3.2. Asphaltene Precipitation/Redissolution Reversibility. During the series of isothermal depressurizing tests, including equilibrium periods, PLT had been continuously recorded as long as possible, as shown in Figure 8. The series of AOP measurements took approximately 8000 s for runs 1− 3, in the case of well 4 and 23 000 s for runs 1−4 in the case of well 3. The difference depended upon asphaltene redissolution. Each run time was around 1000 s for both fluids. On the other hand, equilibrium time had large discrepancy between well 4 and well 3 fluids. The equilibrium step after run 2 in well 4 showed 0 and an extremely low PLT as a result of malfunction of the recording equipment and other unfavorable reasons. Therefore, the PLT records or this run were not used. More details were evaluated in Figures 9 and 10. In run 1 for well 4 fluid, no AOP was detected and then it moved to the
equilibrium step prior to run 2. The PLT profile after run 1 smoothly decreased under the equilibrium condition: above the reservoir condition and reservoir temperature of 100 °C (see Figure 9). Equilibrium was shortly achieved within 1500 s. After the equilibrium step, CO2 was introduced into the FLASS at 1500 psig and then circulated at 4000 psig. During CO2 introduction, the PLT profile fluctuated; however, it returned to a stable behavior after circulation at 4000 psig. After run 2, the equilibrium condition was reproduced again at 4000 psig and 100 °C (see Figure 8). Because the run 2 measurement step was completed just before the weekend, the equilibrium step was decided to be maintained over the weekend. However, the PLT profile unfortunately failed to record between 3500 and 5800 s. The PLT recording was restarted at 5800 s; therefore, the PLT baselines were not identical between runs 1 and 2 and run 3. After restarting PLT monitoring, the profile was smooth and stable for more than 1000 s. This suggested that equilibrium had already been achieved. G
DOI: 10.1021/acs.energyfuels.8b02781 Energy Fuels XXXX, XXX, XXX−XXX
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Figure 8. Overall PLT trends through continuous isothermal depressurizing tests.
Figure 9. PLT profile during equilibrium after run 1 AOP measured with 0 mol % CO2 in field B, well 4.
frequent and minor fluctuations continued for more than 5000 s (see Figure 10b). After run 3, the PLT profile during the equilibrium step showed behavior similar to after run 2 (see Figure 10c). A comparison of those two profiles led us to realize that the fluctuation range was slightly larger for well 3 fluid than for well 4 fluid. Equilibrium was finally achieved by aging more than 4000 s. Consequently, according to the PLT profiles and their equilibrium periods, asphaltene reversibility was summarized as follows: (1) The PLT profile of well 4 fluid was smoother than that of well 3 fluid. (2) The aging period to achieve equilibrium was shorter in well 4 fluid than well 3 fluid. (3) Through visual inspection by HPM, the precipitated asphaltene particles were found to redissolve more easily in
In Figure 10a, after run 1 for well 3 fluid, it moved to the equilibrium step prior to run 2. During the equilibrium step, pressure was set at 5000 psig, which was above AOP at the reservoir temperature of 150 °C. Well 3 fluid showed unstable fluctuation in the PLT profile between 2000 and 5500 s (3500 s duration), instead of the smooth profile seen after run 1 in the case of well 4 fluid (1500 s duration). The fluctuation of the PLT profile disappeared after 5500 s time step, and it was almost stable at the 9000 s time step. Then, equilibrium was achieved by aging for approximately 7000 s. This duration was around 4.7 times that of well 4 fluid. Therefore, the asphaltene reversibility of well 4 fluid was considered higher than that of well 3 fluid. After run 2, the PLT profile had fewer large fluctuations compared to the equilibrium step after run 1; however, H
DOI: 10.1021/acs.energyfuels.8b02781 Energy Fuels XXXX, XXX, XXX−XXX
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Figure 10. PLT profile during equilibrium after runs 1−3 AOP measured with (a) 0 mol %, (b) 20 mol %, and (c) 40 mol % CO2 in field A, well 3.
well 4 fluid than well 3 fluid. (4) Therefore, asphaltene reversibility was considered better in well 4 fluid than well 3 fluid. (5) To argue asphaltene re-equilibrating behavior from a viewpoint of original crude oil light fractions without CO2, the cases assuming 0 mol % CO2 were compared between two synthetic live oil fluids. Despite the asphaltene content being higher in well 4 fluid (2.44 wt %) than in well 3 fluid (0.22 wt %), the colloidal instability was lower in well 4 fluid (stable, 0.9). Well 3 fluid (lighter oil with unstable CII) needed a longer time for re-equilibrium than well 4 fluid (heavier oil with stable CII). This fact matched the general theory that more lighter fractions make asphaltenes unstable. On the basis of the CII results, an influence of aromatics and resins was considered to work for well 4 fluid re-equilibrium quicker too, because well 4 fluid was 18 wt % higher than that of well 3 fluid. Saturates, which
usually posed more asphaltene problems, were also 20 wt % lower in well 4 fluid than well 3 fluid. These influences were considered to be maintained when CO2 increased. In the AOP results, well 4 fluid did not show AOP during natural depletion (i.e., without CO2), while AOP was detected for well 3 fluid. This higher asphaltene-stabilizing capability in well 4 fluid was considered to relate to its characteristic higher reversibility. A higher reversibility could be beneficial for asphaltene mitigation in cases where an asphaltene deposition problem would occur in production wells. A pressurecontrolling operation and/or temporary shut-in to repressurize would be counter actions. In the Marrat reservoir of South Kuwait, asphaltene issues were mitigated with repressurizing by water injection.41 In comparison of two oil fields A and B from a viewpoint of mitigation potential, CO2 EOR would be more favorably applied in field B (well 4 fluid). As another pressure I
DOI: 10.1021/acs.energyfuels.8b02781 Energy Fuels XXXX, XXX, XXX−XXX
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ACKNOWLEDGMENTS The authors thank ADNOC Offshore and INPEX Corporation for permission to publish this paper.
maintenance option, water injection, such as water-alternating gas (WAG), might be a preventative option to decrease asphaltene deposition problem risks. This asphaltene reversibility discussion was still useful for field A, which had less reversibility. Because of fewer remedial options for formation damage by not easily dissolving asphaltenes, more careful assessment was necessary in field A for justifying CO2 EOR application. For example, CO2 injection might be limited by selecting an area that contained the least asphaltene content fluid in the field. In general, the crest area might have less asphaltenes compared to the flank area as a result of gravity segregation. In such a case, crestal CO2 injection was considered to be a potential option. In the case of a compartmentalized field, accurate fluid characterization might provide an opportunity to consider selective CO2 injection. Moreover, a core test to perform CO2-induced formation damage evaluation was recommended. Furthermore, we are considering a way forward analysis plan to compare shapes of asphaltene molecule structures (e.g., island or archipelago types) between well 3 and well 4 fluids in reference to the latest reports discussing the molecular structure-dependent properties, such as easiness of deposition and/or aggregation, etc.42−44
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4. CONCLUSION Two series of isothermal depressurizing tests were conducted to evaluate CO2-induced asphaltene risks and reversibility (i.e., precipitation/redissolution) for two synthetic live fluid samples: (1) less asphaltene content but unstable CII fluid in field A, well 3 and (2) asphaltene-rich but stable CII fluid in field B, well 4. The tests were carried out using the FLASS that equipped SDS to measure laser light transmittance. To understand asphaltene precipitating behavior, PLT profiles were continuously monitored during not only the depressurizing process but also the repressurizing process for equilibrium. (1) The asphaltene-rich condition was concerned more risky prior to the AOP measurement; however, AOPs were higher in less asphaltene fluid (field A, well 3) than asphaltene-rich fluid (field B, well 4). This result came into alignment with the interpretation of colloidal instability for well 3 fluid that was judged more unstable compared to the well 4 fluid. From an aspect of lighter fractions, which usually posed more asphaltene problems, the result was consistent because well 4 fluid had lesser light fractions. (2) Well 4 fluid showed quick re-equilibrium of asphaltenes and smooth PLT profiles despite a higher asphaltene content than well 3 fluid. The stable CII of well 4 fluid was considered to contribute to a quicker reequilibrium process. The well 3 fluid, which had a lower asphaltene content but unstable CII fluid, took longer to achieve equilibrium and had fluctuating PLT profiles. (3) This information could provide useful suggestions for screening CO2 EOR target fields. Easy-equilibrium-achievable fluid would be a preferred target for CO2 EOR because of its mitigation potential by pressure control.
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Hideharu Yonebayashi: 0000-0002-6390-8740 Notes
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DOI: 10.1021/acs.energyfuels.8b02781 Energy Fuels XXXX, XXX, XXX−XXX
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DOI: 10.1021/acs.energyfuels.8b02781 Energy Fuels XXXX, XXX, XXX−XXX
