Evaluation of kinetics and Energetics of Thermochemical Fluids for

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Catalysis and Kinetics

Evaluation of kinetics and Energetics of Thermochemical Fluids for Enhanced Recovery of Heavy Oil and Liquid Condensate Olalekan Alade, Mohamed Mahmoud, Amjed Hasan, Dhafer Al-Shehri, Ayman Al-Nakhli, and Mohammed BaTaweel Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.9b00681 • Publication Date (Web): 30 Apr 2019 Downloaded from http://pubs.acs.org on May 1, 2019

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Evaluation of kinetics and Energetics of Thermochemical Fluids for Enhanced Recovery of Heavy Oil and Liquid Condensate. Olalekan S. Alade1, Mohamed Mahmoud*,1, Amjed Hassan1, Dhafer Al-Shehri*,1, Ayman Al-Nakhli2, and Mohammed Bataweel2. Department of Petroleum Engineering, College of Petroleum and Geosciences, King Fahd University of Minerals & Petroleum, Dharhan, Saudi Arabia. 2Saudi Aramco, Dharhan, Saudi Arabia. 1

*corresponding authors

Abstract An innovative approach in enhancing oil and gas recovery is the insitu heat generation through exothermic chemical reactions using thermochemical fluids. This study presents the kinetics and energetic analysis of typical thermochemical fluids (NH4Cl and NaNO2) and preliminary evaluation of performance in recovery of heavy oil and gas condensate. As a committed step towards understanding the performance of the fluids, the reactions between the fluids (with and without hydrocarbon fluids – heavy oil or liquid condensate) were monitored in a micro-reactor under different operating temperatures (Tr ≈ 20 oC, 40 oC,

55 oC, and 75 oC) in a close system. The data obtained was used in evaluating the

kinetic behaviour of the system. Core flooding experiments were also conducted for evaluating the recovery of gas condensate and heavy oil. Analysis of kinetics and energetics of the system show that the change in temperature ∆T as well as the enthalpy change ∆H of the system due to heat generation was ≈ 88 oC and ≈ 369 kJmol-1, respectively, regardless of the operating temperatures Tr. However, the time to reach peak conversion during the reactions was observed to reduce from 1064s to 382s as the operating temperature increased from 20 oC to 75 oC. Accordingly, the rate constant Kr (s-1) increased from 0.0013 s-1 under ambient condition to 0.0156 s-1 at Tr = 75 oC. The reactions were all first order; and has been estimated to have the activation energy Ea ≈ 35.5 kJmol-1 within the operating temperatures. Moreover, basic applicability of the

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chemical in condensate recovery (63% at injected PV of 2.1) as well as in the recovery of heavy oil (72% recovery, by injecting 1PV of the chemical) has been confirmed. Keywords: Heavy oil, Enhanced oil recovery, Thermochemical fluids, Kinetics, Energetics Introduction Fossil fuels including crude oil, natural gas, and the unconventional resources such as shale oil, heavy oil, and extra-heavy oil (bitumen) currently supply the highest portion of the world total world energy demand (Vaezi et al., 2011; Alade et al., 2016; Moslemizadeh et al., 2016; Xin et al., 2017). Thus, efforts to improve their recovery cannot be overemphasized. In particular, heavy oil is rich in high-molecular-weight asphaltene (20-60 wt.%), which is mainly responsible for its high viscosity that usually exceeds 1 million centipoises under initial reservoir conditions (Speight, 1999; Zhao et al., 2014; Alade et al., 2016). Generally, temperature has significant impact on the viscosity of heavy oil. Thus, commercial production of heavy oil has relied upon the injection of thermal fluid such as steam and hot water to reduce the viscosity and improve mobility. However, the major problems with surface generation and injection of thermal fluid is inefficient heat transfer due to loss to formation rocks, high-energy cost and CO2 emission (Abramov et al., 2009). In addition, operational difficulties may hinder surface thermal fluid generation in certain problematic environments. Hence, the need for alternative methods. On the other hand, based on the dictate of the reservoir thermodynamics (see Figure 1), essentially, when the bottom hole flowing pressure drops below the dew point, there occurs a sharp reduction in gas well deliverability due to condensate dropout (Ali et al., 2019; Ayub and Ramadan, 2019). This scenario ultimately leads to poor productivity


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of the gas reservoir. Available efforts (see Figure 2) to mitigate this problem include injection of solvent (Al-Nazi et al., 2019), pressure maintenance methods (Sayed and AlMuntasheri, 2016; Sharma et al., 2018) - huff and puff (gas cycling using nitrogen gas and supercritical CO2), hydraulic fracturing (Baig et al., 2005), and the use of chemical treatment to alter the wettability of reservoir rocks (Sayed and Al-Muntasheri, 2016; Ali et al., 2019). However, these methods have one or more inadequacies including cost, environmental issues due to corrosion, as well as health and safety issues (Sayed and Al-Muntasheri, 2016). In the recent times, an innovative and cost-effective approach for insitu heat generation through exothermic chemical reactions for thermal stimulation of reservoir has been proposed (Al-Nakhli et al., 2016, Babadagli, 2018; Hassan et al., 2018). Generally, the interest in thermochemical processes derives from the potential they offer for lower capital and/or operating costs and higher overall thermal efficiency compared to other methods. In the aspects of biofuel production, thermochemical approaches for liquefaction and conversion of substrates to useful products have been investigated (Yan et al., 2017). However, thermochemical treatment of the reservoir, especially for thermal EOR and condensate production, is relatively a new technology. Some of the reported investigations include Karandisha et al (2015) on the development new chemical treatment to enhance gas relative permeability through wettability alteration mechanism in carbonate formations. Furthermore, Al-Nakhli et al (2016) developed an innovative and environmentally friendly technology for heavy oil production otherwise referred to as EXOClean technology. Specifically, in this technology, certain concentration of aqueous solution of thermochemical reactants (NH4Cl and NaNO2) would be injected for heat


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generation according to the conditions of the candidate well or reservoir. As an advantage over the traditional steam flooding method, it was claimed that the generated nitrogen could be utilized to reduce the steam-oil ratio by increasing the heated area; hence, oil can be mobilized/recovered through thermal and mechanical forces/mechanisms. Notably, as a potential merit for its large-scale application for highly viscous oil, it was reported that the generated heat and pressure increased significantly from room conditions to 315 °C and 3,470 psi, respectively. However, successful application of thermochemical reaction method requires understandings of the kinetic and energetic behaviour of the chemicals. This will essentially provide useful information that could find applications in the design of the surface equipment, injection unit operations, process control and overall process economics. Therefore, the main objective of the present study is to analyze the kinetics and energetics of the reaction process; and present typical application of the technology in the recovery of liquid condensate and a viscous oil. 2 Experimental 2.1 Thermochemical reactions Series of batch experiments to generate heat using the thermochemical fluids (ammonium chloride NH4Cl and sodium nitrite NaNO2) were performed with and without heavy oil or gas condensate under different operating temperatures (Tr ≈ 20 oC, 40 oC, 55 oC, and 75 oC) in a close thermal insulated reactor. The schematic of the set-up is shown in Figure 3. Essentially, the experimental set up includes the cylindrical reactor, nitrogen gas cylinder for pressure control, heater and the temperature and pressure sensors interfaced with computer. Kinetic progress of the system was followed by


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collecting data for increase in temperature and pressure at every 2-seconds time interval. Pertinent kinetic and energetic parameters were calculated from the data. The stoichiometry equation of the reaction is presented in equation 1: NH4Cl + NaNO2 → NaCl + 2H2O + N2 + ΔH (heat) …

1

2.1.1 Kinetics analysis The Kinetics analysis proceeds from the general mass balance over the system. For a batch system, this can be expressed inform of an elementary rate expression as presented in equation 2:

[ ( )] ….

𝑅𝑥 = (𝐶𝑛𝑥)𝑘𝑜𝑒𝑥𝑝

―𝐸𝑎 1 𝑅

2

𝑇𝑟

The rate constant Kr is the temperature dependent term of equation 2, which can expressed as given in equation 3:

[ ( )] ….

𝐾𝑟 = 𝑘𝑜𝑒𝑥𝑝

―𝐸𝑎 1 𝑅

3

𝑇𝑟

2.1.2 Enthalpy calculation The enthalpy-change (∆𝐻) of the system can be expressed as follows (equation 4): 𝑃𝑖

∆𝐻 = 𝑞 + ∫𝑃0𝑣𝑑𝑃 …

4

Assuming constant pressure system, the expression above reduces to equation 5: 5 ∆𝐻 = 𝑞… The quantity of heat q (without phase change) can be calculated from the specific heat capacity Cp as given in equation 6: 𝑇𝑖

𝑞 = ∫𝑇0𝐶𝑃𝑑𝑇 …

6

where Ti and T0 are the initial and final temperatures of the system, respectively.


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2.1.3 Transient temperature modeling Taking energy balance over the system, the transient temperature change can be expressed as given in equation 7: 𝑑𝑇

∑𝑁𝑖𝐶𝑝𝑖( 𝑑𝑡 ) = (𝑄𝑟) – (𝑄𝑙) …

7

where 𝑄𝑟 (equation 8) and 𝑄𝑙 are the heat generation due to chemical reaction and heat loss, respectively. 𝑄𝑟 = 𝑅𝑥𝑣( ― ∆𝐻𝑟)…

8

Assuming a perfectly insulated system, i.e., there is no heat loss to the surrounding (adiabatic condition), equation 7 becomes: 𝑑𝑇𝑟 𝑑𝑡

=

𝑅𝑥𝑣( ― ∆𝐻𝑟) ∑𝑁𝑖𝐶𝑝𝑖

…

9

The transient temperature of the system can be simulated by coupling the energy balance and the mole balance equations. For a constant volume system, the mole balance is expressed as: 𝑑𝑥

𝑁𝑜 𝑑𝑡 = ―𝑅𝑥𝑣 …

10

where v is the volume of the reactor, No is the initial amount of reactant, and x is the conversion. The rate of change of conversion with time can be calculated from the rate constant, Kr, using equation 11 𝑑𝑥 𝑑𝑡

11

= 𝑘𝑟(1 ― 𝑥)…

Thus, the transient temperature of the system can be simulated by solving equations 9 and 11.


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2.2 Core flooding experiments Coreflooding experiments were conducted to evaluate the performance of thermochemical fluids in the recovery of liquid condensate and a heavy oil. Berea sandstone core sample was used in the flooding experiment. Tight core samples and condensate liquid were used in the flooding experiment for the condensate recovery. The core samples have an average permeability of 0.898 mD and porosity of 17.07%. In the case of the heavy oil recovery, the core sample has average porosity and permeability of 16% and 120 mD, respectively. The density of the liquid condensate and heavy oil are 0.934 g/cc (oAPI ≈ 19.9) and 0.785 g/cm3 (oAPI ≈ 47.2), respectively, at room temperature. Figure 4 (a and b) is the viscosity and density of the condensate and heavy oil, respectively, at different temperatures. The core sample was saturated with the condensate and heavy oil at high pressure. Then, the samples were aged for 4 days after saturation. Subsequently, thermochemical fluids were injected into the tight cores, and activator reagent was used to trigger the reaction. The coreflooding set-up is presented in Figure 5. 3 Results and Discussion 3.1 System kinetics and energetic performance Figure 6 is the temperature profiles of the system under the initial operating temperature ranging from ≈20 oC to ≈75 oC. From the profiles, as expected, it can be observed that temperature of the system increased due to heat generation from the thermochemical reaction. In addition, the figure also shows that operating temperature Tr increased the speed of the reaction. However, the change in temperature of the system


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due to heat generation was not significantly affected (∆T ≈ 88 oC). Furthermore, the speed of reaction in terms of conversion is presented in Figure 7. It shows that the time to reach peak conversion (tx) decreased from 1064s at ambient temperature (20 oC), to 486s, 450s, and 382s, under the operating temperatures 40 oC, 55 oC, and 75 oC, respectively. The evaluated kinetic parameters from the reaction system as well as the enthalpy change ∆H are presented in Table 1. As presented in the table, the rate constant Kr (s-1) increased with increasing temperature. Generally, it shows that the reaction rate may increase in 5-fold its speed (0.0013 to 0.0063) when operated under 40 oC, compared with operation at ambient temperature. The rate constant Kr (s-1) increased to 0.0156 s-1 at 75 oC. The understanding of this phenomenon is the Collison theory and increase in kinetic energy of the system as the temperature increases. The reaction is first order regardless of the operating temperatures. This simply shows direct proportionality between the concentration of the reactants and rate constant. Similarly, the activation energy of the reaction Ea is calculated as ≈ 35.5 kJmol-1 within the operating conditions. Moreover, the calculated enthalpy change ∆H due to heat generation during chemical reaction was ≈369 kJmol-1, irrespective of the operating temperatures. The above observations suggest applicability of the chemical under reservoir temperature up to 100 oC and above.

Finally, the performance profile of the system in the presence of liquid condensate and heavy oil is compared in Figure 8 (a and b). From this figure, the observed characteristics behaviour of the system in terms of heat generation (when condensate and heavy oil are present) shows a relatively lower temperature compared to the reaction without petroleum fluids. The temperature difference from the thermochemical fluid with condensate and heavy oil are ≈ 70 oC and ≈ 60 oC, respectively (see Figure 8a). The main 8 ACS Paragon Plus Environment

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reason for this observation is susceptibly due to heat transfer between the reactants and the hydrocarbon. However, it can be observed that more pressure was generated from the system when hydrocarbon was present. As presented in Figure 8b, under the condition of the experiment, the maximum pressure generated by the thermochemical reaction without petroleum fluids was 350 psi, while 920 psi and 995 psi were generated in the presence of heavy oil and condensate, respectively. This scenario is probably due to vaporization of the light components in the condensate and heavy oil, which contributed to the pressure increase as the reaction proceeded. And since the condensate is more volatile than the heavy oil (see Figure 4a and 4b for the viscosity and density of the condensate and heavy oil), it is expected that more gas pressure would be obtained from the condensate. The simulated results which describe the behaviour of the system using the coupled differential equations 9 and 11 is presented in Figure 9. 3.2 Recovery performance Coreflooding tests were carried out to study the effectiveness of thermochemical treatment in recovering the condensate liquid. Figure 10 shows the profiles of condensate recovery and pressures at inlet and outlet. 63% of the original condensate in place was recovered by injecting 2.1 pore volumes of thermochemical fluids. The inlet pressure increased significantly due to thermochemical reaction, and pressure generation. The outlet pressure was maintained at 400 psi using back pressure regulator. The condensate recovery could be attributed to several mechanisms such as viscosity reduction, immiscible displacement, and alteration of rock properties. Consequently, the hydrocarbon viscosity will be significantly reduced, and then the condensate liquid will be easily recovered. In addition, thermochemical treatment resulted in generating pressure


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pulses. The generated pulses can alter the rock properties, especially the permeability and capillary forces. Tiny fractures were observed in all core samples after flooding operations. The generated factures would contribute in recovering the condensate liquid, by decreasing the capillary forces that hold the condensate. Those fractures were developed due to rapid increase in the pore pressure when the thermochemical reaction was activated. As shown in Figure 1, the pressure at core inlet (orange curve) increased dramatically from 200 psi to 2300 psi, which led to create tiny fractures in the tight core samples. On the other hand, Figure 11 shows the recovery profile and the pressure drop during the thermochemical flooding. From this result, it can be observed that 72.3% of the heavy oil was recovered by injecting one pore volume of thermochemical fluids. It also shows that the pressure-drop across the core sample increased from 45.6 to 94.7 psi, at 1PV of the injected thermochemical fluids. This observation could be attributed to the mobilization of the heavy oil during recovery. Thereafter, the pressure-drop was stabilized at 63.7 psi. This trend of pressure-drop reveals that the thermochemical treatment dose not induce any precipitation or damage into the core sample during the recovery. 4 Conclusion The performance of thermochemical fluids (NH4Cl and NaNO2) have been evaluated considering the kinetics and energetics of the process. It was observed that the conversion of this reaction as well as the rate constant increased as the operating temperature increased. The reaction has been observed as first order regardless of the operating temperature. In addition, the change in enthalpy as well as the activation energy has not been affected by the operating temperatures. These observations suggest


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applicability of the chemical under reservoir temperature up to 100 oC and above. Moreover,

facile applicability of the chemical was also confirmed in enhancing recovery following 63% recovery of the condensate using injected 2.1PV and 72% of the heavy oil by injecting 1PV of the chemical. Acknowledgement The authors wish to acknowlegde Mr. Abdulsamed Iddris and Mr. Muhammadin for their technical supports. Cxo Cx Cp Ea ∆H n N Ni P 𝑄𝑟 𝑄𝑙 Kr K0 R 𝑅𝑥 Tr t tx T ∆T Tr TCF v x

Initial concentration of reactant (molcm-3) Final concentration of reactant (molcm-3) specific heat capacity (JC-1g-1) Activation energy (kJmol-1) Enthalpy change (kJmol-1) Reaction order (-) Amount of reactant (mol) Amount of chemical specie I at any x Pressure (psi) Rate of heat generation (kJs-1) Rate of heat loss (kJs-1) Rate constant (s-1) Pre-exponential factor (s-1) Gas constant (8.3144598 Jmol-1K-1) Rate of reaction (mols-1) Reaction operating temperature (oC) Time (s) Peak conversion time (s) Temperature generated (oC) Temperature change of the system (oC) Reaction operating temperature (oC) Thermochemical fluid Volume of reactor (cm3) Conversion (-)

Nomenclature


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under effect of ultrasound. Ultrasonics Sonochemistry, 16, 408 –

416. 2) Alade, O.S., Sasaki, K., Sugai, Y., Ademodi, B., Nakano, M., 2016. Bitumen Emulsification Using a Hydrophilic Polymeric Surfactant: Performance Evaluation in the Presence of Salinity. Journal of Petroleum Science and Engineering, 138, 66 - 76. 3) Al-Anazi, H.A., Walker, J.G., Pope, G.A., Sharma, M.M., Hackney, D.F., 2005. A successful methanol treatment in a gas-condensate reservoir: field application. SPEPF, 20 (1), 60–69. 4) Ali, N.E.C., Zoghbi, B., Fahes, M., Nasrabadi, H., Retnanto, A., 2019. The impact of near wellbore wettability on the production of gas and condensate: Insights from experiments and simulations. Journal of Petroleum Science and Engineering, 175, 215–223. 5) Al-Nakhli, A.R., Sukkar, L.A., Arukhe, J., Mulhem, A., Mohannad, A., Ayub, M., Arifin, M., 2016. In-Situ Steam Generation A New Technology Application for Heavy Oil

Production. SPE Heavy Oil Conference and Exhibition, 6-8

December, Kuwait City,

Kuwait.

SPE-184118-MS.

https://doi.org/10.2118/184118-MS.


DOI:

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6) Ayub, M., Ramadan, M.,2019. Mitigation of near wellbore gas-condensate by CO huff-n- puff injection: A simulation study. Journal of Petroleum Science and Engineering, 175, 998–1027. 7) Babadagli, T., 2018. Heavy oil: in Technology Focus. Journal of Petroleum Technology, 76 – 80. 8) Baig, T., Droegemueller, U., Gringarten, A.C., 2005. Productivity assessment of fractured and nonfractured wells in a lean/intermediate low permeability gas condensate reservoir. SPE 93136, SPE Europec/EAGE Conference. 9) Hassan AM, Mahmoud MA, Al-Majed AA, Elkatatny S, Al-Nakhli AR, Bataweel MA. Novel Technique to Eliminate Gas Condensation in Gas Condensate Reservoirs Using Thermochemical Fluids. Energy Fuels 2018; 32(12): 12843-12850. 10) Karandisha, G.R., Rahimpour, M.R., Sharifzadeh, S., Dadkhah, A.A., 2015. Wettability alteration in gas-condensate carbonate reservoir using anionic fluorinated

treatment. Journal of Chemical Engineering Research and Design,

93, 554–564. 11) Moslemizadeh, A., Dehkordi, A. F., Barnaji, M.J., Naseri, M., Ravi, S.G., Jahromi, E.K., 2016. Novel bio-based surfactant for chemical enhanced oil recovery in montmorillonite rich reservoirs: Adsorption behavior, interaction impact, and oil recovery studies. Chemical engineering research and design, 109, 18–31. 12) Sayed, M.A., Al-Muntasheri, G.A., 2016. Mitigation of effect banking:

a

critical

review.

SPE-168153-PA

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of 2016;

condensate 85-102.

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13) Sharma, h., Sheng, J.J., Shen, Z.A., 2018. Comparative Experimental Study of Huff-n-Puff Gas Injection and Surfactant Treatment in Shale Gas-Condensate Cores. Energy Fuels, 32: 9121−9131. 14) Speight, J.G. 1999. The Chemistry and Technology of Petroleum; Marcel Dekker: New York. 15) Vaezi, M., Passandideh-Fard, M., Moghiman, M., Charmchi, M., 2011. Gasification of heavy fuel oils: A thermochemical equilibrium approach. Fuel, 90, 878–885. 16) Xin, X., Li, Y., Yu, G., Wang, W., Zhang, Z., Zhang, M., Ke, W., Kong, D., Wu, K., Chen, Z., 2017. Non-Newtonian Flow Characteristics of Heavy Oil in the Bohai Bay Oilfield:

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Table 1: Enthalpy change and Kinetic Parameters Tr (oC)

∆T (oC)

tx (s)

∆H (KJmol-1)

Kr (s-1)

n

Ea (KJmol-1)

20

87.8

1064

368.8

1.30E-03

1

35.9

40

88.4

486

371.3

6.30E-03

1

34.8

55

87.3

450

366.7

1.00E-02

1

35.2

75

87.9

382

369.2

1.56E-02

1

36.1


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Figure 1: P-T phase diagram of a typical condensate system (adapted from Sayed and Al-Muntasheri, 2016)


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Figure 2: Summary of condensate mitigation schemes (Source: Ayub and Ramadan, 2019)


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Figure 3: Experimental set-up for thermochemical reactions


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160

Predicted viscosity ((T)^) 2 Condensate (R = 0.99) 2 Heavy oil (R = 0.99)

140

Viscosity (cP)

120 100 80 60 40 20 0 30

40

50

60

70

80

o

Temperature ( C) 1.00 Predicted density (Y = a(x)+b) 2 Condensate (R = 0.99) 2 Heavy oil (R = 0.99)

0.96 0.92 3

Desnity (g/cm )

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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0.88 0.84 0.80 0.76 0.72 0.68 30

40

50

60

70

80

o

Temperature ( C)

Figure 4: Viscosity and density of condensate and heavy oil at different temperatures


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Figure 5: Schematic of coreflooding setup used in the study


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180 160 o

Experimental temperature ( C)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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T20 T40

140

T55

120

T75

100 80 60 40 20 0

200

400

600

800

1000

1200

1400

Time (s) Figure 6: Temperature profiles under different operating temperatures (Tr)


Energy & Fuels

T20

100

Experimental Conversion (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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T40 T55

80

T75

60

40

20

0 0

200

400

600

800

1000

1200

Time (s)

Figure 7: Apparent conversion versus time


1400

Page 23 of 26

o

Experimental temperature ( C)

140

Generated pressure (psia)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

(a)

120 100 80

Temperature (TCF) Temperature (TCF + Condensate) Temperature (TCF + heavy oil)

60 40 20 0

200

400

600

800

Time (s)

1000

1200

(b)

1000 800

Pressure (TCF) Pressure (TCF + Condensate) Pressure (TCF + heavy oil)

600 400 200 0 0

200

400

600

800

1000

1200

Time (s) Figure 8 (a and b): Comparison of temperature and pressure profiles of the thermochemical fluids (TCF) with condensate and with heavy oil.


Energy & Fuels

o

Temperature ( C)

140

(a)

120

T20

100

T40 T55

80

T75

60 40 20 0 0

500

1000

1500

2000

2500

3000

Time (s) 1.2

(b)

Conversion (x)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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1.0

T20

0.8

T40 T55

0.6

T75

0.4 0.2 0.0 0

500

1000

1500

2000

2500

3000

Time (s)

Figure 9 (a and b): Simulated temperature and conversion profiles of the system different operating temperatures


Page 25 of 26

2500

60

2000

50 40

1500

30

1000

Pressure (psi)

70 Condensate Recovery (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

20 500

10 0

0 0.0

0.5

1.0

Condensate Recovery

1.5 Injected PV Inlet Pressure

2.0

2.5

Oulet Pressure

Figure 10: Profiles of condensate recovery, inlet and outlet pressures for continuous injection of thermochemical fluids.


Energy & Fuels

100

80

60

Recovery (% OOIP)

90

Recovery Pressure drop

80 40 70

60

20

Pressure drop (psi)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 26 of 26

50 0 40 0.0

0.5

1.0

1.5

2.0

2.5

3.0

Injected PV Figure 11: Profiles of heavy oil recovery and pressure drop during thermochemical flooding.


Evaluation of kinetics and Energetics of Thermochemical Fluids for

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