In situ steam and nitrogen gas generation by thermochemical fluid Injection: A new approach for heavy oil recovery

In situ steam and nitrogen gas generation by thermochemical fluid Injection: A new approach for heavy oil recovery

Energy Conversion and Management 202 (2019) 112203 Contents lists available at ScienceDirect Energy Conversion and Management journal homepage: www...

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Energy Conversion and Management 202 (2019) 112203

Contents lists available at ScienceDirect

Energy Conversion and Management journal homepage: www.elsevier.com/locate/enconman

In situ steam and nitrogen gas generation by thermochemical fluid Injection: A new approach for heavy oil recovery

T



Mohamed Mahmouda,c, , Olalekan S. Aladea,c, Mohamed Hamdyb, Shirish Patila,c, ⁎ Esmail M.A. Mokheimerb, a

Department of Petroleum Engineering, College of Petroleum and Geosciences, King Fahd University of Minerals and Petroleum, 31261 Dharhan, Saudi Arabia Department of Mechanical Engineering, College of Engineering, King Fahd University of Minerals and Petroleum, 31261 Dharhan, Saudi Arabia c Center for Integrative Petroleum Research, King Fahd University of Petroleum and Minerals, 31261 Dhahran, Saudi Arabia b

A R T I C LE I N FO

A B S T R A C T

Keywords: In-situ steam-nitrogen generation Thermochemical reaction Steam injection Net present value Heavy oil recovery

Thermal recovery techniques such as steam injection are very popular methods used for heavy oil recovery. However, several challenges including high cost of steam generation, low heat transfer efficiency and/or heat loss, geotechnical and environmental issues are threatening its sustainability. In-situ generation of steam and nitrogen gas through injection of certain exothermic chemical reactants (thermochemical fluids – TCF) can be employed to alleviate these challenges. The present investigation focuses on experimental, numerical simulation and economic studies to assess this novel technique, and to compare its performance with those of conventional steam injection methods. This comparison is based on the recovery factor (RF) and the net present value (NPV). It was generally observed that the proposed TCF injection performed better than the conventional steam injection method. From the core-flooding experiments, higher recovery was achieved through the TCF (RF: 82% of the oil in the core sample) compared with that of the steam injection (60% of the oil in the core sample) with 1.7 PV (pore volume) and 1.8 PV, respectively. In addition, from the field scale simulation over 10 years of production, the RF achieved using the proposed TCF injection method and the conventional steam injection methods are 50% and 40%, respectively; while the NPV are USD 9.8 × 106 and 2.4 × 106, respectively.

1. Introduction A good number of approaches has been introduced to recover heavy oil [1–3].Thermal recovery methods including surface steam generation and injection are the most efficient and widely used approach. However, there is a significant heat loss before the steam reaches the targeted area in the formation [4–10]. Specifically, about 20% of the net heat energy generated is lost at the boiler, mostly, with the flue gas [11]. In addition, 3% to 5% of the generated heat energy is lost in the steam lines from the boiler to wellhead. Furthermore, heat is lost in the wellbore from the wellhead to the reservoir; and the steam quality, inadvertently, dropped to less than 50% or as low as 10% in some cases [3,12–15]. A significant drop in the steam quality may cause melting of the Permafrost around the injection well, and collapse of the well to the casing; with potentially disastrous effects [16]. For example, in the

West Sak heavy-oil reservoir in Alaska North Slope, the conventional steam injection method is not practical for recovery of heavy oil, because the injected steam from the surface would have to cross approximately 2000 ft thick Permafrost layer. Nonetheless, there are other challenges such as high cost of steam generation and injection facility [17,18]; and the need for thermal-completion wells. Therefore, steam injection method is usually restricted to shallow reservoirs with limited depth (< 1100 m) and higher oil viscosity (> 50 cP). On the other hand, for deep reservoirs, in-situ combustion (ISC) or fire flooding is another efficient recovery technology for the highly viscous oil [19,20]. In the ISC approach, significant quantity of thermal energy is generated downhole through combustion/pyrolysis of heavy oil in-situ. This, essentially, reduces the viscosity and increases the mobility of oil [21–24]. However, this method also requires steam injection in the preheat circulation phase to improve its performance. Thus, in the recent times, because of the aforementioned challenges

Abbreviations: BHP, bottom hole pressure (psi); CMG, computer modelling group; COP, cumulative oil production; CSS, cyclic steam stimulation; EOR, enhanced oil recovery; ISC, in situ combustion; SGR, steam generation rate; NPV, net present value; OOIP, original oil in place; PV, pore volume; RF, recovery factor; SAGD, steam assisted gravity drainage; SOR, steam oil ratio; SQ, steam quality; STBD, stock tank barrel per day; TCF, thermochemical fluid ⁎ Corresponding authors. E-mail addresses: [email protected] (M. Mahmoud), [email protected] (E.M.A. Mokheimer). https://doi.org/10.1016/j.enconman.2019.112203

0196-8904/ © 2019 Elsevier Ltd. All rights reserved.

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not known to us. As earlier stated, conventional heavy oil recovery methods such as steam injection and in-situ combustion are not recommended in deep reservoirs because of the heat losses. In addition, these methods cannot be used in permafrost regions, in which they will cause severe integrity problem to both the completion and stability of the producing wells. The introduced method has no limitation with the heavy oil reservoir depth, it can be applied in both deep, moderate, and shallow reservoirs. Moreover, it can be implemented in cold and hot regions with no safety considerations or issues. It will save a lot of energy, which is required to generate the surface steam in the conventional steam operations. Therefore, the main objective of this work is to compare the performance of the TCF injection method for heavy oil with those of conventional steam injection method. Moreover, the work is conducted to investigate synergistic combination of TCF injection and the ISC method in the enhanced recovery of heavy oil. These goals have been achieved through experimental and numerical simulation studies.

Fig. 1. Illustration of thermochemical fluid injection for heavy oil production [26].

of steam injection method; compounded by unstable oil price, efforts are being made to introduce a more energy efficient and environmentally benign technology such as in-situ steam and nitrogen gas generation using thermochemical fluids (TCF) to replace the conventional steam injection. Generally, the interest in thermochemical process for the in-situ heat and pressure generation is derived from the potential they offer for lower capital and/or operating costs and higher overall thermal efficiency compared with the conventional steam injection method [25]. This technology can be used for different operations such as; hydraulic fracturing, recovery of deep and shallow heavy oil and tight oil reservoirs, and it can be applied to onshore and offshore fields. Compared with the conventional surface heat generation and injection methods, it has lower cost, less labor intensive and efficient thermal deliverability, since no steam facilities or plants are required and no toxic emission of GHG (greenhouse gas). As illustrated in Fig. 1, the TCF injection method essentially involves in-situ heat (or steam) and nitrogen gas (or pressure) generation through exothermic chemical reactions between aqueous solution of thermochemical reactants (e.g. NH4Cl and NaNO2). As an advantage over the traditional steam flooding method, it could be harnessed to reduce the steam-oil ratio by increasing the heated area; hence, oil can be mobilized/recovered through thermal and mechanical forces [26]. Thermochemical treatment of the reservoir, especially, for thermal EOR, is a relatively new technology; and has, therefore, been rarely reported. Apart from the preliminary expository work on EOR using the TCF approach presented by Al-Nakhli et al. [26], other available literatures using TCF injection include [27,28] for liquid condensate recovery and water blockage removal, respectively. Prior to the present work, numerical simulation of the process for field scale application is

2. Materials and methods 2.1. Materials Aqueous solution of thermochemical fluids (ammonium chloride NH4Cl and sodium nitrite NaNO2) were collected from the Saudi Aramco Company; and were used as supplied. The stoichiometry of the reaction is given in Eq. (1):

NH4 NO2 + NaCl. NH4 NO2 ⎤ NH4 Cl + NaNO2 → ⎡ → NaC Themolabile ⎣ ⎦ l + 2H2 O + N2 + ΔH (heat )

(1)

The reaction above produces an intermediate thermolabile product, which disintegrates immediately to sodium chloride (brine), nitrogen gas and steam. Thus, the by-products are environmentally benign. In addition, the chemical has positive effects on the reservoir rock. As shown in the NMR distribution curve and the CT scan presented in Figs. 2 and 3, respectively, because of the pressure pulses that were generated during the reaction, tiny fractures were observed in the core samples after treatment with the thermochemical. Notably, both figures showed enhancement in porosity; and that one major fracture was created in the core sample that will enhance the rock permeability. In addition, the fracture will create larger surface area for steam contact with the oil and rock. As an overall advantage, this will deliver more heat and reduce the heat losses.

Fig. 2. NMR signal distribution of the core samples before and after treatment with the thermochemical fluids (Porosity increased from 20 to 21.5%; Permeability increased from 150 to 800 mD). 2

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Fig. 3. CT scan for the rock sample before (A) and after (B) thermochemical treatment.

system of reaction investigated in this study proceeded at room temperature (≈30 °C). Typically, the reaction produces the temperature and pressure profile displayed in Fig. 6. The heat of the reaction (ΔH) has been estimated as ≈370 kJ/mol, with the activation energy (Ea) ≈36 kJ/mol and the rate order, n ≈ 1. 2.2.2. Thermochemical flooding and recovery experiments Heavy oil recovery through injection of thermochemical fluids and steam were compared using the experimental setup, which is shown in Fig. 7. The pore volume of the core is 40 cm3. The core was initially saturated with brine (30,000 ppm KCl) and then with the heavy oil, at 50 °C injection temperature, to achieve a connate water saturation of 8%. The oil volume was 37 cm3 and the remaining 3 cm3 is the water volume inside the core. Then, the samples were aged for 4 days after saturation. Subsequently, thermochemical fluids were injected, continuously, into the cores with the backpressure set at 100 psi. The cell temperature was set initially at 100 °C and the thermochemical injection increased the temperature of the cell to ≈170 °C. The same core used in this experiment was cleaned and saturated with the same heavy oil for the second experiment. In this case, steam at 200 °C, was injected into the core with the backpressure set at 100 psi.

Fig. 4. Viscosity-temperature relationship of the heavy oil. Table 1 Properties of the sandstone core used in this work. Rock and Fluid Properties

Core plug

Porosity Core Diameter Core Length Permeability

20% 2.5-inch 2-inch 150 mD

2.2.3. Numerical simulation Numerical simulation studies were carried out using CMG STARS, developed by the CMG (Computer Modelling Group) (https://www. cmgl.ca/stars). CMG STARS is an advanced reservoir simulation package, which contains various thermal EOR options including steam injection (such as Steam Assisted Gravity Drainage: SAGD, Cyclic Steam Stimulation: CSS, etc.), and in situ combustion (ISC). The simulator has flexibility to implement the in-situ heat and pressure generation through necessary modifications. The CSS production scheme was adopted in this study. The detailed descriptions of the simulation models are presented in the subsequent sections.

A heavy oil sample with 18.4 %w/w C7-asphaltene content, 12 °API, and viscosity 8000 cP at ambient temperature was used in the core flooding experiments. The viscosity-temperature relationship of the oil is presented in Fig. 4. The properties of Berea sandstone core samples used in the flooding experiments are provided in Table 1. 2.2. Methodology 2.2.1. Experimental study to assess thermochemical energy Batch experiments were conducted in a reactor, as shown in Fig. 5, to access the heat released from the exothermic reaction. The set up includes an insulated high pressure and high temperature (HPHT) cylindrical reactor, heater, and the sensors, which were interfaced with computer for temperature and pressure measurement. Equal volume of equimolar concentrations of the reactants were heated separately to 100 °C and pumped into the reactor, which has also been heated to 100 °C. The progress of the reaction was observed by collecting data for increase in temperature and pressure at equal time intervals through the data logger. The system was regularly calibrated using known pressure from the Nitrogen gas and temperature from the heater. Depending on the concentration and the pH of the reactants, the reaction may require temperature (ambient – 50 °C) to start. The particular

2.2.3.1. Steam injection versus TCF injection. Two simulation models were studied in this section with the main purpose of comparing the economic return of the thermochemical steam-nitrogen against the conventional steam injection in terms of the NPVs at the end of the project. Sensitivity studies were also carried out on the proposed method to determine the optimum steam-nitrogen ratio. Then, the maximum NPVs achieved by the in-situ thermochemical steam process and the conventional steam injection method were compared along with two other indicators of recovery performance viz. cumulative oil production (COP) and oil recovery factor (RF). In addition, the wellbore heat losses are considered in this work. NPV of each method at the end 3

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Fig. 5. The temperature profile obtained from the exothermic reaction. 1800 Temperature Pressure

of the project was taken as the main parameter to evaluate the performance. This was done for comparing the economic returns from the two recovery methods.

1600

160

1400

150

1200 1000

140

800 130 600 120

2.2.3.2. Description of simulation model. The simulation results presented in this article have been obtained using CMG STARS software 2017.01 (that is developed by Computer Modelling Group Ltd. CMG) [29]. CMG STARS is an interactive numerical simulation software that provides modeling for several reservoir processes including thermal, compositional, black oil and enhanced oil recovery processes. CMG also includes modules for laboratory scale processes simulations. The basic mathematical model employed in CMG simulation software comprises of the main conservation equations for mass and energy in addition to Darcy’s law, which governs the multiphase flow in porous media. The model also includes many other relations such as that for thermodynamic properties of the substances and kinetics of different reactions that are involved in reservoir’s oil flow and oil recovery processes. The CMG software also allow the user to integrate and use user defined functions whenever needed as part of the mathematical model. Brief outlines of the main governing equations used in CMG simulation software are given

Pressure (psia)

Temperature generated (oC)

170

400 200

110

0

100 0

100

200

300

400

Time (min) Fig. 6. The temperature profile obtained from the exothermic reaction conducted at 100 °C.

Fig. 7. Core flooding set up used in the experiment. 4

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hereunder.

Table 2 Reservoir and fluid parameters [31,32].

1. Mass Conservation Many species exist in different phases during the flow and reaction processes within oil reservoirs. Therefore, mass conservation equation for each species is developed and written for each species. This results in a set of mass conservation equations, which can be written for a species i existing in number of phases, π, and is involved in a number of reactions, nr, as shown in Eq. (2): π

∑ ρj uj xij =

− ∇.

j=1

∂ ∂t

π

π

nr

∑ ρj φf Sj xij − ∑ qij + ∑ rik j=1

j=1

(2)

k=1

where:

• ∑ ρ u x is the mass flux of component i in phase j. • ∑ ρ φ S x is the accumulated mass of component i in phase j. r is the rate of consumption/generation of component i in • ∑reaction k. • ∑ q is the mass production rate of component i in phase j. • S is the saturation of phase j and xij is mole fraction of component i π j = 1 j j ij π j = 1 j f j ij nr k = 1 ik

π j=1

Property

Value

Initial reservoir pressure at 900 ft datum, psi Total depth of the reservoir, ft Average reservoir temperature, °F Reservoir porosity, % Reservoir vertical permeability, mD Reservoir vertical permeability, mD Oil viscosity at 68°F, cP Oil viscosity at 104°F, cP Heavy oil gravity at standard conditions, API Reservoir rock compressibility, psi−1 Heat capacity of the reservoir rock, Btu/(ft3.°F) Thermal conductivity of reservoir rock, Btu/(ft.day. °F) Thermal conductivity of adjacent rocks, Btu/(ft.day. °F) Thermal conductivity of oil, Btu/(ft.day. °F) Thermal conductivity of water, Btu/(ft.day. °F) Thermal conductivity of gas, Btu/(ft.day. °F)

145 900 68 38 3000 7000 21 109 2 918 8 1.8 × 10−5 35.04 44 24 1.8 8.6 0.3

Table 3 Wellbore heat losses parameters.

ij

j

in phase j. 2. Energy conservation

The energy conservation equation governing the flow and reaction processes in the reservoir is given as: π

∂ ⎡ ∑ φ ρ SjUj + (1 − φv )Ur + φv Cs Us⎤⎥ ∂t ⎢ j = 1 f j ⎣ ⎦ π

= ∇ . (λ∇T) − ∇.

π

π

j=1

j=1

Value

Surface Temperature, °F Average geothermal gradient, °F/ft Casing and tubing depth, ft Well radius, ft Outer radius of the casing, ft Inner radius of the casing, ft Outer radius of the production tubing, ft Inner radius of the production tubing, ft

62.0 0.015 900 0.4075 0.292 0.265 0.12 0.102

nr

∑ ρj hj uj + ∑ ρj hj uj + ∑ qj h∗j + ∑ Hrk rik + qhc j=1

Property

simulated for 10 years (3600 days) and two sensitivity studies were carried out separately on the two recovery methods. The parameters used to estimate wellbore heat losses are shown in Table 3.

k=1

(3) where:

2.2.3.3. Economic evaluation: net present value. As stated earlier, the economic analysis was carried out using the net present value (NPV) as the main performance indicator. The NPV can be precisely defined as the difference between the present value of the cash inflow and the present value of the cash outflow over the time of that project [33]. NPV can be calculated mathematically [34] as follows:

• ∇. ∑ ρ h u is the advection or convection term and h is the enthalpy of phase j. • ∇.(λ∇T) is the conduction term and λ is the thermal conductivity of π j=1 j j j

j

the formation. π

• ∑ qh

∗ j j

is the heat source/sink, and h∗j is the enthalpy of phase j at

j=1

injection or production.

NPV =

nr

• ∑H

rk rik

is the heat source or sink due to reaction, and Hrk is the

k=1



μj

∇ (φj )

(5)

Ccap = Cf + Cex + Nw Cwcold + CSo

For multiphase flow, the relationship between the flow rate (flow velocity) and pressure gradient can be obtained using Darcy’s law [30].

vj =

CFn − Ccap (1 + r )n

where n is year index, r is the rate of annual discount, N refers to the project period in years and Ccap is the total initial investment or capital costs which is calculated as follows:

enthalpy of reaction k and rik is the rate of kth reaction. q hc is the heat loss source/sink term. 3. Darcy’s Law

−k krj

N

∑n=1

(6)

and

Ccap = Cf + Cex + Nw Cwtherm + CSG (4)

(7)

Eqs. (6) and (7) represent the capital cost for the conventional steam injection method and the thermochemical injection method, respectively, and CFn refers to net cash inflow during the year n, and is calculated as follows:

where, the subscript j, in the above equation, refers to the phase (water, oil or gas), vj is the velocity vector, K is the absolute permeability, kr is the relative permeability and μ is the fluid viscosity. The phase potential gradient has the form of ∇ φj = (pj − ρj g h) where p refers to fluid pressure, ρ refers to fluid density, g and h are, respectively, the gravitational acceleration and the block depth measured from a reference datum. The reservoir model used in the simulation study is a homogeneous 3D Cartesian model with one well, 31 grid blocks along the x-axis, 6 grid blocks along the y-axis and 20 grid blocks along z-axis were used in the simulation studies. All the parameters used were obtained from the literature [31,32] and are shown in Table 2. Both models were

(8)

CFn = Rn − En where Rn is the income of project in year n and is determined as: o

Rn = Pno Qn pro

(9)

And En is the cash outflows in year n and is calculated as: Wpro

En = Cn and 5

Wpro

Qn

S

S

o

+ Cn inj Qn inj + Cnop Qn pro + Nw CnSoh

(10)

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100

Value, USD 6

Description (Cost type)

1400 1200

Cf

1.0 × 10

Facility installation

CnSinj

10/bbl

Steam injection

CnWpro

5/bbl

Produced water treatment

Cnop

5/bbl

Other operating cost/bbl of oil

Cex Cw therm Cw cold CSG CSo

0.2 × 106 1.45 × 106 0.6 × 106 2.26 × 106 100 K 20 K/year/well

Exploration Completion and drilling for thermal wells Completion and drilling for non-thermal wells Steam facility generation, 20 years, 435 m3/day Thermochemical injection facility Thermochemical handling

CnSo h

320/Liquid m

CnSo inj CnW treat

3.3 × 106

3

Inlet pressure (psia)

Symbol

1600

Pressure RF

80

60

1000 800

40

600 400

20

Recovery factor (RF) % OOIP

Table 4 The input values used in Eqs. (2)–(7) and obtained from the literatures [17,18].

200

Thermochemical Water treatment facility for 600 m3/day capacity plant

0

0 0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Pore volume (PV) injected

En =

W W Cn pro Qn pro

+

S S Cn inj Qn inj

+

o Cnop Qn pro

Fig. 9. Recovery performance and injection pressure vs. pore volume injected for TCF injection at 100 °C.

(11)

Eqs. (10) and (11) represent the cash flow for the thermochemical injection and the conventional steam injection method, respectively. The input parameters used in Eqs. (5)–(11) are shown in Table 4 as collected from the literature [17,18]. The heavy oil price is assumed to be 75% of the light oil price [35].

TCF injection at 100 °C. Moreover, it can be observed from these figures that thermochemical flooding yielded higher recovery compared to the steam flooding. From injection of ≈1.8 PV of steam (generated at 250 °C) and 1.6 PV of the TCF (injected at 100 °C), the figures show that as much as ≈80% recovery was achieved using the TCF, while ≈60% was achieved from the steam injection. In addition, as shown in Figs. 8 and 9, higher pressure, and intermittent pressure surges, were observed from the TCF injection process compared with the steam injection. The pressure at the inlet of the core for the steam injection varies between 209 psia and 175 psia; while the inlet pressure was observed to reach ≈1500 psia; and, subsequently, fluctuated between 600 and 500 psia during the injection for TCF injection. The recovery mechanisms attributed to the TCF injection includes viscosity reduction, immiscible displacement, and alteration of rock properties. Moreover, as reported above, thermochemical treatment resulted in generating pressure pulses, which is an advantage over the conventional steam injection method. In addition, the generated pulses can alter the rock properties, especially the permeability and capillary forces. From one of the previous reports, due to rapid increase in the pore pressure when the thermochemical reaction was activated (typically from 200 to 2300 psia), tiny fractures were observed in all core samples after flooding operations [27].

2.2.3.4. TCF-air co-injection for in situ combustion. As a potential alternative to steam injection, which is conventionally used in preheating circulation phase of the ISC process, injection of TCF was also simulated. In this case, numerical simulation was performed by using the reservoir model used for the steam flooding process. The performance evaluation of the process was carried out by simulating the conventional steam-air injection in ISC, considering 15-day steam preheating circulation period at 300 °C and continuous air injection at 250 °C for 296 days. In comparison, TCF injection was also modelled in CMG STARS considering in situ steam generation and nitrogen gas generation for a period of 15 days; followed with continuous air injection for 296 days. 3. Results and discussion 3.1. Experimental studies: oil recovery from conventional steam injection vs. TCF Fig. 8 shows the oil recovery versus the volume injected for the continuous steam injection, while Fig. 9 is the recovery results for the

3.2. Simulation studies: conventional steam injection vs. TCF injection 3.2.1. Heat loss in the wellbore The simulation result for wellbore heat loss from the conventional steam injection is presented in Fig. 10. The figure shows that steam quality decreased, at the downhole, from 0.6 to 0.52. The cumulative oil production is 280 bbl. with injection and soaking periods of 15 and 5 days, respectively. In order to improve the quality of the steam, a modified injection scheme from the TCF injection is presented in Fig. 11. This figure shows that chain reactions could be triggered downhole to maintain steam quality at 0.6 minimum from 0.8. In this case, the cumulative oil production increased to 585 bbl. which is > 100% increase compared to the conventional steam injection with the same injection and soaking periods. Moreover, these results show that the proposed TCF injection approach is highly promising compared with the conventional steam injection technique.

Inlet pressure (psia)

200

60 50

150 40 100

30 20

50 10

Recovery factor (RF) % OOIP

70 Pressure RF

0

0 0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

3.2.2. Complete 10 of cyclic steam stimulations The recovery performance of the two techniques was analyzed using 10 cyclic steam stimulation (CSS). Each cycle consists of 16 days of steam injection, 2 days soaking and 8 days of production. As shown in Figs. 12 and 13, the rate of oil produced and the cumulative oil

2.0

Pore volume injected Fig. 8. Recovery performance and injection pressure vs. pore volume injected for continuous steam injection. 6

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Fig. 13. Cumulative oil production by thermochemical and conventional approaches.

Fig. 10. Simulation of conventional steam flooding with wellbore heat losses.

susceptibly, because the oil saturation around the wellbore, at the beginning of the production, is at its maximum, which eventually decreased from the second CSS cycle, as the oil saturation decreases; and water saturation increased due to steam injection. However, after the second CSS cycle, the oil production rate starts to increase gradually, as seen in Figs. 12 and 13. The reason for the observations above can be justified by the average temperature profiles of the reservoir, which are presented in Figs. 14 and 15a,b. From these results, as expected, one can see that the average reservoir temperature for the TCF injection scheme is higher than that of the conventional steam injection. This increase in reservoir temperature results in the reduction of the reservoir heavy-oil viscosity as shown in Figs. 15a and 15b. Therefore, the oil production rate is increased with time. From Figs. 15a and 15b, it can also be seen that the affected radius around the wellbore, in the case of TCF injection, is larger than the affected radius during the conventional steam injection. Hence, as observed earlier, the oil production rate and cumulative oil production that achieved when applying in-situ thermochemical are higher than that of the conventional case.

Fig. 11. Modified chain reactions, using TCF method, with the minimum steam quality of 0.6.

3.3. Sensitivity studies on the proposed recovery process This section presents the results from the sensitivity analysis of the proposed recovery process. Different operational parameters including in-situ steam generation rates (SGRs), nitrogen-steam ratio generated from the TCF reactions, number of CSS stages, production period in each CSS phase; and the quality of steam generated were considered. As stated earlier, the main performance indicator is the net present value (NPV) while monitoring the oil recovery factor (RF) and cumulative oil production (COP) from three different wells after 10 years of

Fig. 12. Oil rate produced by thermochemical and conventional approaches.

production from in-situ steam generated by thermochemical are much higher than the oil produced by the conventional steam injection method. Fig. 10 shows that the production rate, from the TCF injection, varied between 57 and 88 STBD compared with that from the conventional steam injection, which varied between 23 and 50 STBD. In addition, from Fig. 13, one can see that the cumulative oil production reached ≈4500 STB, from the TCF injection while ≈2300 STB was achieved from the steam injection method, after 260 days of production. Moreover, it can be seen that the maximum oil production rate is achieved in the first cycle (26 days) in both cases. This observation is,

Fig. 14. Average reservoir temperature. 7

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Fig. 15a. Change of oil viscosity after applying 10 CSS cycles on heavy oil reservoir using In-situ thermochemical method.

production.

200 and 500 STBD, respectively. This corresponds to the NPV of 6 and 10 million USD, respectively, as presented in Fig. 16b. However, as observed from these results, as the SGR increased beyond 1000; up to 2400 STB/D, the RF and NPV were observed to decrease to ≈48% OOIP and 8 million USD, respectively. This observation suggests that any additional increase in steam injection rate results in higher water

3.3.1. In-situ steam generation rate Fig. 16a and 16b show the RF and NPV obtained from different SGRs viz. 200, 500, 1000, 1500 and 2400 STBD. As shown in Fig. 16a, RF increased significantly from ≈38% to ≈50% OOIP for the SGRs of

Fig. 15b. Change of oil viscosity after applying 10 CSS cycles on heavy oil reservoir using Conventional seam injection from the surface. 8

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production with its associated cost of treatment. The reason for the observations above is illustrated in Fig. 17. The figure shows the variation of water rate and BHP with production time in the case when the SGR is assigned to be 2400 STB/D. In addition, this figure shows that most period of steam generation is dominated by the fracture pressure constraint. As the present modification requires, the insitu steam generation pressure increases with increasing insitu steam generation rates, SGR. Therefore, in this study, an increase in the SGR beyond 1000 STBD will require higher BHP, which is technically limited by the fracture pressure. Subsequently, this caused the RF and NPV to decrease as observed. 3.3.2. Nitrogen-steam ratio Different values of the nitrogen-steam ratio are applied to study the effect of nitrogen-steam ratio on the recovery performance of the in-situ thermochemical process. In this case, the values assigned were 0, 0.1, 0.2 and 0.5. Fig. 18 shows that the recovery performance (RF and NPV) is enhanced when nitrogen gas and steam are co-generated up to 20% nitrogen content. From Fig. 18a, the RF increased from ≈22% to ≈50% OOIP when the fraction of nitrogen gas generated increased from 0 to 20%. However, the RF decreased to 43% OOIP when the fraction of nitrogen gas was set at 50%, after ten years of production. On the other hand, Fig. 18b shows that the NPV after ten years of production increased to 10 million USD from 8 million USD as the fraction of nitrogen increased from 0 to 20%. However, when the nitrogen fraction increased to 50%, the NPV decreased very significantly to ≈0. The reason for the poor performance at 50% nitrogen fraction is attributed to the fact that the amount of steam generated is not sufficient to deliver the required thermal energy to reduce the viscosity. Therefore, the optimum nitrogen-steam ratio to be generated and injected is supposed to be between 10% and 20%. In addition, the heat distribution in the reservoir after 7 years of production, due to the injection of nitrogen gas, is compared in Fig. 19. It can be clearly observed from the figure that the nitrogen co-generated with steam (Fig. 19a) enhanced heat distribution better than the case without nitrogen co-generation (Fig. 19b). In other words, it could be suggested that the nitrogen-steam co-generation, which is the main

Fig. 16a. Effect of changing steam injection rate on the in-situ thermochemical performance (Recovery Factor: RF).

Fig. 16b. Effect of changing steam injection rate on the in-situ thermochemical performance (Net Present Value: RF).

Fig. 17. Pressure and rate constraints in the thermochemical process. 9

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Fig. 18a. Effect of fraction of in-situ nitrogen generation on the in-situ thermochemical performance (Recovery Factor: RF).

3.3.3. Number of Cyclic steam Stimulation (CSS) stages In order to study effect of CSS stages on recovery performance, different number of CSS stages (10, 20, 30, 40 and 50) were assigned to study their effect on the recovery performance of the proposed recovery process. The performance of the TCF system considering different cycle of CSS is presented in Fig. 21. As presented in Fig. 21a, giving the 10 years of production period, the RF using 10 CSS stages is 42% OOIP, while 20 CSS stages produce 65% OOIP. The value of RF obtained from 30, 40, and 50 stages of CSS is ≈80% OOIP. On the other hand, from

focus of the TCF technology, provides a good heat insulation effect in the reservoir because of low heat conductivity coefficient and large compressibility coefficient of nitrogen gas [36,37]. Moreover, Fig. 20 presents the effect of nitrogen co-generation on the steam-oil ratio, SOR (bbl/bbl), which is defined as the volume of steam required to produce one unit volume of oil. It could be observed that SOR is reduced after starting nitrogen-steam co-generation; and reached less than 1 bbl/bbl. after 4 years of production.

Fig. 18b. Effect of fraction of in-situ nitrogen generation on the in-situ thermochemical performance (Net Present Value: RF). 10

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Fig. 19a. Heat distribution in the reservoir after 7 years of production with in-situ N2 generation.

more than 13%, although the three cases achieved similar RF after 10 years of production. The reason for this behavior is illustrated in Fig. 22, which is the plot of cumulative steam-oil ratio (SOR) versus time for 30 and 50 CSS cases. This figure shows that after 2000 days of production, the SOR decreased to less than 2 bbl/bbl when 30 CSS stages case was implemented. While in the case of 50 CSS, the SOR was

Fig. 21b, the 10 CSS stages gave a NPV of 8 million USD, which increased to 18 million USD using 20 CSS stages. The value resulted in ≈28 million USD when 30 and 40 CSS stages were used. However, a lower NPV of ≈23 million USD was obtianed considering 50 CSS stages. Accordingly, from Fig. 19b, this shows that both 30 and 40 CSS stages achieved NPV that is higher than that achieved with 50 CSS by

Fig. 19b. Heat distribution in the reservoir after 7 years of production without in-situ N2 generation. 11

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Fig. 20. Effect of nitrogen injection on steam oil ratio.

Fig. 22. Effect of CSS stages on steam-oil ratio (SOR).

3.3.4. Effect of production time intervals In order to study the effect of production time interval on the recovery performance of the proposed in-situ thermochemical recovery processes, different production time intervals were simulated. Figs. 24a and 24b show the effects of different production time intervals viz. 6, 10, 15, 20 and 30 days over 10 years of production period on the performance of the TCF injection technique. From Fig. 24a, it can be observed the system produced between 75 and 80% OOIP after 10 years of production period, regardless of the time intervals. However, from Fig. 24b, the NPV curves clearly show higher NPV (between 24 and 26 million USD) for the time interval between 6 and 20 days, compared with ≈23 million USD, which was obtained from 30-day time interval. In addition, it can be observed from both cases that the highest values of RF and NPV could be achieved when the production time intervals in CSS assigned to be 15 days, followed by 10 and 20 days, with the least from 30 days.

Fig. 21a. Sensitivities to number of CSS stages for the TCF method (Recovery Factor: RF).

3.3.5. Steam quality effect In this section, the effects of different qualities of steam generated by the in-situ thermochemical reaction are presented. The simulation has been performed considering different steam qualities (SQs) with the associated generation cost. The mathematical relationship shown in Eq. (12) [38,39], and the cost parameters, presented in Table 5 [40], have been used to estimate steam generation cost depending on the specific enthalpy of generated steam at reservoir pressure and generated temperature.

Cs = Ce (hs − hfw )

(12)

where;

•C •C •h •h

is steam unit cost, $/lb, is energy unit cost, $/1000 BTU, s is specific enthalpy of steam at boiler pressure, BTU/lb, and fw is specific enthalpy of feed water, BTU/lb. s

e

Fig. 21b. Sensitivities to number of CSS stages for the TCF method (Net Present Value: RF).

Figs. 25a and 25b show the performance of in-situ thermochemical recovery process, the RF and NPV, respectively, under different conditions of steam qualities over the 10 years of production. Fig. 25a shows that there is no significant difference in the value of RF (≈80% OOIP) obtained from the three conditions of SQs (70, 80 and 90%) considered. However, as presented in Fig. 25b, the 70% SQ gave the highest NPV of ≈25 million USD, which is higher than those of 80 and 90% SQs. More so, it can be observed that, the 90% SQ condition gave higher NPV than 80% case. This is because there is little improve in oil recovery (as shown in Fig. 25a) compensated the higher cost of 90% SQ compared to 80% SQ. Therefore, it can be concluded that the optimum steam quality is 70%.

reduced to 2 bbl/bbl after 2800 days. In other words, the same amount of oil was produced in both cases but with less amount of steam injected in the case of 30 CSS than what is required in the case of 50 CSS stages. Furthermore, Figs. 23a and 23b show oil viscosity distribution in the reservoir for 10 and 30 CSS stages, respectively. It can be observed clearly from these figures that there is higher interconnection between the wells with higher reduction in the viscosity compared to those of the 10 CSS cases which shows that there are still non-stimulated areas between the wells; and that some portions of the reservoir are still unrecoverable due to the high oil viscosity. Therefore, 30 stages of CSS could be selected as the optimum cycle of operation.

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Fig. 23a. Oil viscosity distribution in heavy oil reservoir using 10 CSS stages.

3.4. Economic performance: steam injection vs. thermochemical fluid

Section 3.3.1. The RF obtained using the TCF and the conventional steam injection are compared in Fig. 26a. As expected, the figure shows that the proposed TCF method gave higher RF (50% OOIP) compared with that of the conventional steam injection method (RF = 40% OOIP) after 10 years of production. Accordingly, as shown in Fig. 26b, the NPV

In this section, the simulation results to compare the performance of the TCF and the conventional steam injection method are presented. This was performed over 10 years of production using the optimum steam generation or injection rate of 500 STB/D, which was reported in

Fig. 23b. Oil viscosity distribution in heavy oil reservoir using 30 CSS stages. 13

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Fig. 24a. Sensitivities to production time intervals for the TCF method (Recovery Factor: RF).

Fig. 25b. Sensitivities to steam quality for the TCF method (Net Present Value: RF).

Fig. 24b. Sensitivities to production time intervals for the TCF method (Net Present Value: RF).

Fig. 26a. Comparison of Recovery performance (RF) between the conventional steam injection and TCF injection method.

Table 5 Steam unit cost based on steam quality. Steam Quality, %

Steam Unit Cost, USD/Ton

70 80 90

12.04 12.99 13.95

Fig. 26b. Comparison of Net Present Value (NPV) between the conventional steam injection and TCF injection method.

achieved by the proposed and conventional methods are USD 9.8 × 106 and 2.4 × 106, respectively. Therefore, it can be inferred from these results that the recovery performance using the TCF gave project profitability which is 300% higher than what could be achieved using the conventional steam injection method. The main reasons for this observation are the high cost of steam generation facility for conventional steam injection compared to the proposed TCF method; lower SOR; and higher heat transfer/distribution efficiency from in-situ nitrogen gas which is co-generated with the steam.

Fig. 25a. Sensitivities to steam quality for the TCF method (Recovery Factor: RF).

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Development (R&D) Program (Research Pooling Initiative), Ministry of Education, Riyadh, Saudi Arabia. References [1] Kazemzadeh Y, Shojaei S, Riazi M, Sharifi M. Review on application of nanoparticles for EOR purposes: a critical review of the opportunities and challenges. Chin J Chem Eng 2019;27(2):237–46. [2] Shakiba M, Riazi M, Ayatollahi S, Takband M. The impact of connate water saturation and salinity on oil recovery and CO2 storage capacity during carbonated water injection in carbonate rock. Chin J Chem Eng 2018. https://doi.org/10.1016/ j.cjche.2018.09.008. [3] Willhite GP. Over-all heat transfer coefficients in steam and hot water injection wells. J Petrol Technol 1967;19(05):607–15. [4] Carpenter C. A review of improved-oil-recovery methods in north american unconventional reservoirs. J Petrol Technol 2018;70(01):42–4. [5] Guo K, Li H, Yu Z. In-situ heavy and extra-heavy oil recovery: a review. Fuel 2016;185:886–902. [6] Giacchetta G, Leporini M, Marchetti B. Economic and environmental analysis of a Steam Assisted Gravity Drainage (SAGD) facility for oil recovery from Canadian oil sands. Appl Energy 2015;142:1–9. [7] Zhao DW, Wang J, Gates ID. Thermal recovery strategies for thin heavy oil reservoirs. Fuel 2014;117:431–41. [8] Mozaffari S, Nikookar M, Ehsani MR, Sahranavard L, Roayaie E, Mohammadi AH. Numerical modeling of steam injection in heavy oil reservoirs. Fuel 2013;112:185–92. [9] Huiqing L, Hongling Z, Peixi W. Interpretation of temperature profiles during soak periods in steam-stimulated wells. Pet Sci 2007;4(4):74–9. [10] Zhengfu N, Huiqing L, Hongling Z. Steam flooding after steam soak in heavy oil reservoirs through extended-reach horizontal wells. Pet Sci 2007;4(2):71–4. [11] IOCC. Improved oil recovery. In: Commission IOC, editor. Interstate oil compact commission, Oklahoma City, USA. 1993. [12] Elbaloula HA, Musa TA. The challenges of cyclic steam stimulation (CSS) to enhanced oil recovery (EOR) in sudanese oil field. 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[17] Azad MS, Alnuaim S, Awotunde AA. Stochastic optimization of cyclic steam stimulation in heavy oil reservoirs. SPE Kuwait Oil and Gas Show and Conference. SPE 167378. 2013. [18] Frauenfeld TW, Jossy C, Bleile J, Krispin D, Ivory J. Experimental and economic analysis of the thermal solvent and hybrid solvent processes. J Canadian Petrol Technol 2009;48(11):55–62. https://doi.org/10.2118/130445-PA. SPE 130445. [19] Alade OS, Sasaki K, Sugai Y, Konadu KT, Ansah EO, Ademodi B, et al. Kinetics of thermal degradation of a Japanese oil sand. Egypt J Petrol 2018;27:505–12. https://doi.org/10.1016/j.ejpe.2017.08.001. [20] Jinzhong L, Wenlong G, Bojun W, Yongbin W, Jihong H. Feasibility study of in situ combustion huff and puff for EOR in super deep heavy oil reservoir. International petroleum technology conference Beijing, China: IPTC 16408; 2013. https://doi. org/10.2523/IPTC-16408-MS. [21] Jia H, Liu PG, Pu WF, Ma XP, Zhang J, Gan L. In situ catalytic upgrading of heavy crude oil through low-temperature oxidation. Pet Sci 2016;13(3):476–88. [22] Youtsos MSK, Mastorakos E. Numerical simulation of thermal and reaction waves for in situ combustion in hydrocarbon reservoirs. Fuel 2013;108:780–92. [23] Kök MV, Ocalan R. Modelling of in situ combustion for Turkish heavy crude oil fields. Fuel 1995;74(7):1057–60. [24] Moore RG, Laureshen CJ, Belgrave JD, Ursenbach MG, Mehta SR. In situ combustion in Canadian heavy oil reservoirs. Fuel 1995;74(8):1169–75. [25] Alade O, Mahmoud M, Hasan A, Al-Shehri D, Al-Nakhli A, Bataweel M. Evaluation of kinetics and energetics of thermochemical fluids for enhanced recovery of heavy oil and liquid condensate. Energy Fuels 2019;33:5538–43. https://doi.org/10. 1021/acs.energyfuels.9b00681. [26] Al-Nakhli AR, Sukkar LA, Arukhe J, Mulhem A, Mohannad A, Ayub M, et al. In-situ steam generation a new technology application for heavy oil production. 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Fig. 27. Comparison of Cumulative Oil Production (COP) between the conventional steam injection and TCF injection in the ISC process.

3.5. Conventional ISC with steam injection vs. ISC with TCF injection method Fig. 27 depicts the comparison of the cumulative oil production (COP) using the conventional ISC method (i.e. reservoir preheating using steam) with the COP using the proposed ISC-TCF method (i.e. reservoir preheating using TCF). As evident in the figure, the cumulative oil produced after 300-day period is about 280 m3 and 560 m3, from the conventional ISC and the ISC-TCF method, respectively. This can be attributed to the minimization of heat loss and more efficient heat transfer of the TCF technique compared to the conventional steam injection. In addition, the TCF technique is more favored in terms of combustion propagation since nitrogen is generated along with steam/heat. 4. Conclusions A novel heavy-oil recovery process, which is based on injection of TCF into the reservoir, has been investigated using experimental and numerical simulation approaches. The experimental study showed that the TCF method gave higher oil recovery (80% OOIP) compared to the conventional steam injection method (60% OOIP). From the simulation results, using the oil recovery factor (RF) and net present value (NPV) as the performance indicators, it was observed that the proposed TCF injection method performs better than the conventional steam injection methods under the operational conditions considered in this study. Specifically, the RF achieved using the proposed TCF injection method and the conventional steam injection methods are 50% and 40%, respectively, while the NPV are 9.8 × 106 and 2.4 × 106 USD, respectively. From the sensitivity analyses of the TCF injection method, it was observed that the optimum conditions are in-situ steam generation rates (SGRs) of 500 STB/D, nitrogen-steam ratio (generated from the TCF reactions) 10% or 20%, 30 stages of CSS, the production time intervals of 15 days, and the steam quality (SQ) of 70%, over 10 years of production. In summary, the performance of the TCF method can be attributed to lower steam-oil ratio SOR; and higher heat transfer/distribution efficiency from in-situ nitrogen gas which is co-generated with the steam. Declaration of Competing Interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. Acknowledgment The authors acknowledge funding from the Research and 15

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