# Thermal Hydraulic Analysis Using GIS on Application of HTR to Thermal Recovery of Heavy Oil Reservoirs

Authors: Yangping Zhou; Fu Li; Zhiwei Zhou; Yuanle Ma
Journal: Science and Technology of Nuclear Installations
 (2012)

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## Abstract

At present, large water demand and carbon dioxide (CO2) emissions have emerged as challenges of steam injection for oil thermal recovery. This paper proposed a strategy of superheated steam injection by the high-temperature gas-cooled reactor (HTR) for thermal recovery of heavy oil, which has less demand of water and emission of CO2. The paper outlines the problems of conventional steam injection and addresses the advantages of superheated steam injection by HTR from the aspects of technology, economy, and environment. A Geographic Information System (GIS) embedded with a thermal hydraulic analysis function is designed and developed to analyze the strategy, which can make the analysis work more practical and credible. Thermal hydraulic analysis using this GIS is carried out by applying this strategy to a reference heavy oil field. Two kinds of injection are considered and compared: wet steam injection by conventional boilers and superheated steam injection by HTR. The heat loss, pressure drop, and possible phase transformation are calculated and analyzed when the steam flows through the pipeline and well tube and is finally injected into the oil reservoir. The result shows that the superheated steam injection from HTR is applicable and promising for thermal recovery of heavy oil reservoirs.


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## Body

## 1. Introduction

Steam injection [1–3] is the most widely used and the most efficient process available today among the various enhanced oil recovery techniques currently being employed in heavy oil reservoirs and tar sand deposits. At present, fossil fuel such as oil, coal, and natural gas is burned to provide the energy to steam. Mostly, wet steam is adopted as the injection medium. The relatively large water demand and carbon dioxide (CO2) emissions have emerged as challenges of the steam injection for thermal recovery [4]. Superheated steam, compared with wet steam, has higher heat content and specific volume, by which for steam stimulation not only can the bottom hole steam quality and steam swept volume be increased, but also it is characterized by higher viscosity breaking, heat expansion, blocking, crude oil distillation rate, and oil displacement [5, 6].The High-Temperature Reactor (HTR) [7–10] has a distinct advantage in inherent safety, economics potential, high efficiency and potential usage for process heat application. The Chinese Module High-Temperature Gas-cooled Reactor (MHTGR), named High-Temperature gas-cooled Reactor-Pebble bed Module (HTR-PM) [11–13], based on the technology and experience of the 10 MW High-Temperature gas-cooled Reactor (HTR-10) [14, 15], will be started in the end of 2012 or later. The demonstration HTR-PM plant has two reactor modules, two steam generators, and one steam turbine which employ superheated steam as the driver power. The helical-coiled once through steam generator can produce the superheated steam. USA utility Entergy completed an economic analysis of using a HTGR (High-Temperature Gas-cooled Reactor) to generate hydrogen and process heat, and also electricity [16]. This study indicates that the cost of process heat or high-temperature steam produced by a HTGR can be competitive with the steam produced by normal fossil plant.In this paper, the design of the secondary loop after the steam generator of the HTR-PM is modified to fit the need of steam injection for thermal recovery. The superheated steam produced by the steam generator is divided into two branches. The main fluid is applied for steam injection of the heavy oil reservoirs and the other fluid will flow into a two-stage steam jet mixer in order to preheat the inlet water of the steam generator.In order to analyze the thermal hydraulic behavior of the HTR-PM for heavy oil thermal recovery, a Geographic Information System (GIS) embedded with thermal hydraulic analysis function is designed and developed. Then it is applied to analyze the thermal hydraulic process in a reference heavy oil field where two kinds of injection are considered and compared: wet steam injection by boiler and superheated steam injection by HTR-PM. The heat loss, pressure change, and possible phase transformation are calculated and analyzed when the steam flows through the pipeline and well tube and is finally injected into oil reservoirs. Two kinds of pipeline are considered: overground and underground. Four kinds of oil well structure are included: heat insulation tube with packer, heat insulation tube without packer, normal tube with packer, and normal tube without packer. Calculation results indicate that the superheated steam injection by HTR-PM is applicable and has obviously higher quality of steam stimulation than the wet steam injection by the conventional boiler. Namely, under the same mass flow rate, the steam injection by HTR-PM has characteristics of higher temperature, more enthalpy and larger specific volume than the wet steam injection by conventional boiler. Therefore, it will result in more intensive physical and chemical reactions between reservoir fluid and minerals, higher reduction of oil viscosity, and bigger expansion of crude oil volume, and so forth.Section2 of this paper introduces the modified HTR-PM design and strategy when it is applied to heavy oil thermal recovery of an oil field. Section 3 describes the GIS system which is embedded with thermal hydraulic analysis function. Section 4 explains the process and result of the thermal hydraulic analysis of superheated steam injection by HTR and its comparison with wet steam injection by boiler. Section 5 describes the conclusions of this paper.


## 2. HTR-PM for Heavy Oil Thermal Recovery

### 2.1. General Description of HTR-PM

The HTR-PM deploys two pebble-bed modular HTRs each with 250 MW thermal power. Two reactor modules are coupled with two steam generators which are connected to one steam turbine generator with 210 MW electric power. The reactor and the steam generator are installed inside two separate pressure vessels. The pressure vessels are assembled in a staggered, side-by-side arrangement and are connected by a horizontal coaxial hot gas duct. The primary pressure boundary consists of the Reactor Pressure Vessel (RPV), the Steam Generator Pressure Vessel (SGPV), and the Hot gas Duct Pressure Vessel (HDPV), which all are housed in a concrete shielding cavity as shown in Figure1. The main design parameters are listed in Table 1.Table 1
Major design parameters of HTR-PM [17].
Item
Value
Thermal power (MW)
2
×
250
Electric power (MW)
210
Active core diameter (cm)
300
Equivalent active core height (cm)
1100
Primary helium pressure (MPa)
7.0
Average helium temperature at reactor
250/750
inlet/outlet (°C)
Helium mass flow rate at full power
96
(kg·s−1)
Type of steam generator
Once-through
helical
Main steam flow rate at the inlet of
98
turbine (kg·s−1)
Main steam pressure (MPa)
14.3
Main steam temperature (°C)
566
Main feed-water temperature (°C)
205Figure 1
Primary loop of HTR-PM.As shown in Figure1, the thermal-hydraulic process related with the reactor and the primary loop of HTR-PM can be mainly explained as follows.(i)
Before entering the reactor vessel, the helium gas is driven by the helium blower, and the temperature of the inlet gas is around 250°C. After the helium flows through the hot fuel spheres in the reactor core, the temperature of it reaches 750°C. The hot helium exits the reactors and flows through the hot gas duct. The hot helium releases its thermal power to the water in the steam generator where it is cooled down to around 250°C. Then, the helium blower blows the cold helium through the outer coaxial pipes of the hot gas duct. Finally, the cold helium flows into RPV where it is heated again. In this way, a cycle of the helium flow is completed in the primary loop.(ii)
At the side of the secondary loop of HTR-PM plant, the water at a temperature of 205°C in the steam generator is heated to 566°C by hot helium and becomes superheated steam. Then superheated steam with a pressure of 14.3 MPa will drive the steam turbine and its conjoined generator in order to generate electrical power based on the Rankine cycle.


### 2.2. Status and Existing Problems of Conventional Steam Injection for Thermal Recovery

Steam injection is an established thermal recovery technique that has been applied successfully on many heavy oil reservoirs around the world. The process started in early 1960s with cyclic steam injection. The three main methods of steam injection are Cyclic Steam Stimulation (CSS), Steam Drive (SD), and Steam Assisted Gravity Drainage (SAGD) [2].The CSS is a simple and cheap method of applying thermal recovery process on a reservoir. It involves injecting steam into a well for several weeks, shutting the well in as long as necessary to allow the steam to heat the oil in the areas around the well, and putting the well back on production to recover the heated oil (Figure2). This process is repeated when the production from the well declines to a low level. The cycle is repeated many times until the ratio of oil produced to steam injected named Oil-Steam Ratio (OSR) drops to a level that is considered uneconomic. CSS was the first steam injection technique used in heavy oil reservoirs. It can be used as a limited pilot test on a well to investigate whether steam injection can enhance oil recovery in a particular field before undertaking more expensive pattern pilot tests that will require more wells and more equipment.Figure 2
Cyclic steam stimulation process.The scenario of the conventional thermal recovery technology uses the boiler to generate wet steam, which is shown as the bottom part of Figure3.Figure 3
Strategies for steam injection by HTR-PM and boiler.Conventionally, the boiler using fossil fuel such as coal, natural gas, and oil is utilized to heat water to wet steam for thermal recovery of heavy oil reservoirs. The water is driven by a pump and softened by the water-softening plant before entering the boiler. The steam out of the boiler will flow through the pipeline to a steam injecting station near the heavy oil well. Then, the wet steam will pass through the well head to the well tube. Finally, the wet steam will flow into the oil reservoir via the well tube which is usually several hundred meters long.Because of the limited thermal power of boilers and heat loss during steam transportation, the boilers are built near the heavy oil well to provide enough steam for thermal recovery. One boiler can only provide steam to a limited number of oil wells for steam injection. Usually, there are many boilers in a heavy oil field to provide steam to different heavy oil wells.The specific enthalpy of the steam or water can be indicated as(1)h(P,T,x)=h′(P)+xQ(P)+x∫TPTCP′′dt,
where P is the pressure of steam or water; T is the temperature of steam or water; x is the dryness of steam or water; h′(P) is the specific enthalpy of the saturated water at pressure P; Q(P) is the latent heat of vaporization of water at pressure P; TP is the temperature of the saturated steam at pressure P. CP′′ is the specific heat of the superheated steam at pressure P.The drynessx of wet steam can be expressed as
(2)x=msmw,
where ms is the mass of the steam component in the wet steam; mw is the mass of the whole wet steam.The conventional thermal recovery technology with dispersed steam supply and wet steam injection has the following shortcomings.(i)
The operation and management of a large number of small boilers is very expensive because of high labor expenditure and relative high price of equipment [18].(ii)
The conventional boiler is burning fossil fuel such as coal, natural gas, and oil to generate the steam, which has an environmental challenge of carbon dioxide emissions and large demand of water [4].(iii)
Loss of heat during steam transportation will reduce the heat capacity of injected steam and obviously worsen its quality since the velocity of flow is relatively slow and the specific enthalpy is low. Therefore, the heavy oil reservoirs cannot gain enough thermal energy even if a lot of water is consumed [5, 6].(iv)
The wet steam has low temperature and low specific volume which result in low stimulation efficiency [5, 6].


### 2.3. Strategy of Superheated Steam Injection from HTR-PM

The strategy of superheated steam injection by HTR-PM is shown as the top part of Figure3. Unlike the conventional steam injection method, all superheated steam will be intensively produced by one HTR plant which is located at several kilometers away from the heavy oil field in consideration of safety and engineering requirements. Then, the superheated steam will be delivered all over to the whole heavy oil field through the main steam pipeline with bigger pipe diameter and higher thermal insulation ability. The main steam pipeline will connect to normal pipelines at the diverging points. Finally, the steam will flow into the oil reservoirs through the steam injecting station, well head, and well tube.For the wet steam,x is less than 1 and the third part of (1) is zero. For the superheated steam, x is 1. Therefore, the enthalpy difference between the superheated steam and the wet steam at the same pressure can be shown as follows:
(3)h(P,T)-h(P,TP,x)=(1-x)Q(P)+∫TPTCP′′dt.From this equation, it can be found that the superheated steam has much more enthalpy than the wet steam whenx is not very close to 1 and TP-T is a big value. The thermal recovery technology by HTR with concentrated steam supply and superheated steam injection is predicted to have the following advantages.(i)
The operation and management of HTR for steam generation is relatively cheap.(ii)
The steam production by HTR emits less CO2 than the conventional boiler burning fossil fuel.(iii)
Loss of heat during steam transportation will not seriously worsen the quality of injected steam since the velocity of flow is relatively fast and the specific enthalpy is high. Therefore, the heavy oil reservoirs can receive much more thermal energy by superheated steam injection when the same mass of water is injected into oil reservoirs.(iv)
The superheated steam has higher enthalpy and higher specific volume which results in higher quality of steam stimulation [5, 6].


### 2.4. Adoption of HTR-PM for Heavy Oil Thermal Recovery

The design of the HTR-PM applied to thermal recovery of heavy oil reservoirs is shown in Figure4. The primary loop and the steam generator are kept as the original design of the HTR-PM in order to take advantage of its mature design. Originally, the secondary loop of the HTR-PM adopts a steam turbine system which generates electricity with a Rankine cycle. A two-stage steam jet mixer system is design to preheat the feed water of the HTR-PM.Figure 4
Modified design of HTR-PM for thermal recovery.In the secondary loop of HTR-PM, some basic parameters such as mass flow rate, inlet temperature, and outlet temperature of water should be determined by taking into account the original design of HTR-PM and need of heavy oil thermal recovery. Table2 shows the basic configuration when a HTR-PM or boilers are applied to thermal recovery of a reference heavy oil field. In order to maintain the safety of HTR-PM and oil field, the HTR-PM is located around 4 km away from the oil field to void the interaction when one of them is in a dangerous status. In this reference oil field, the number of injected wells at the same time is around 30 (20–40) and the mass flow rate of water to each well is around 2.31 kg/s (200 ton/day). A single reactor of HTR-PM can provide enough injected water since the flow out of the steam generator is 98 kg/s, around 8600 ton/day.Table 2
Basic configuration of injection.
Injection with boiler/HTR-PM
Number of used boiler/HTR-PM reactor at same time
15/1
Number of injected wells at same time
30 (20–40)
Number of boilers
100
Number of wells
6000
Initial temperature of steam (°C)
318.05/566
Mass flow out of each boiler/HTR-PM (ton/day)
200–800/6500
Mass flow rate of water to each well (ton/day)
Around 200
Initial pressure of steam (MPa)
11/14.3
Initial dryness of steam
0.725/1
Average length of main steam pipeline (km)
0/7.5
Area of reference oil field (km2)
20
×
20
Average length of branch steam pipeline (km)
0.8
Average distance from injection station to well head
0.2
Depth of typical well (m)
759.75The process in the modified secondary loop of HTR-PM can be described as follows. The water at 75.08 kg/s and 25°C is driven to the secondary loop by a pump. The water is purified and softened by a water treatment plant mainly consisting of several sand filters and several ion exchangers. The cool water is heated by the superheated steam from the output of the steam generator at a steam jet mixer. Then the water is pumped to a deoxidizer and heated again by the superheated steam at another steam jet mixer. Finally, the water at around 205°C and 98 kg/s, which is same as the original design of HTR-PM, is fed to the once-through helical steam generator. The output water of the steam generator at around 566°C is mainly divided in two branches. One fluid is deployed as feedback to the two steam jet mixers and the deoxidizer in order to heat the feed water instead of the conventional electrical heaters. The main fluid at 75.08 kg/s (6500 ton/day) and 566°C is provided to the superheated steam injection system for heavy oil thermal recovery.


### 2.5. Economic Comparison between Steam Injection by Conventional Boiler and HTR-PM

By considering the construction investment, fuel cost, and operating cost, the full cost of the steam injection by burning coal or natural gas can be estimated [18]. The construction investment and operating cost are converted to cost per ton steam injection which are shown in Table 3. The full cost of steam injection by HTR-PM can also be estimated [19]. In the same way, the construction investment and operating cost of steam injection by HTR-PM are converted to cost per ton of steam injection in the same Table. The full cost of steam injection with unit of $/t means the total cost for injecting 1 ton of steam.Table 3
Costs of steam injection by boiler and HTR-PM.
Injectionmode
Constructioninvestment ($/(t·y))
Fuel cost($/t or $/m3)
Operatingcost ($/t)
Full operatingcost ($/t)
Full costfor steam injection ($/t)
Coal
29.78
27.99
8.766
12.04
14.69
Natural gas
15.54
0.1541
10.45
14.50
15.88
HTR-PM
95.17
—
—
5.62
14.07
Time = 30 years, bank rate = 8%.For the uncertainty evaluation, if the bank rate rises to 10% and fuel cost decreases by 10%, the costs can be estimated as shown in Table4.Table 4
Costs of steam injection at lower fossil fuel price and higher bank rate.
Injectionmode
Constructioninvestment ($/(t·y))
Fuel cost($/t or $/m3)
Operatingcost ($/t)
Full operatingcost ($/t)
Full cost for steaminjection ($/t)
Coal
29.78
25.19
8.766
11.71
14.87
Natural gas
15.54
0.1368
10.45
14.10
15.74
HTR-PM
95.17
—
—
5.62
15.72
Time = 30 years, bank rate = 10%.From these results, it can be found that the steam injection by HTR-PM is still a competitive choice compared to the steam injection by the conventional boiler burning coal or natural gas even with lower fossil fuel price and higher bank rate.To consider the quality difference of the steam produced by the fossil fuel boiler or HTR-PM, the full cost can be changed to the enthalpy of injected steam instead of the mass of it. The full costs for steam injection by HTR-PM or burning coal or natural gas are shown in Table5, which shows the cost to provide 1 kJ enthalpy to the injected steam. According to this table, the steam injection by HTR-PM has an obvious economic advantage on the steam injection by conventional boilers burning coal or natural gas even with lower fossil fuel price and higher bank rate.Table 5
Costs of steam injection by considering enthalpy difference of steam.
Injectionmode
Full cost for steaminjection(mills/kJ)
Full cost for steaminjection under higher bank rate and lower fossil fuel price (mills/kJ)
Coal
0.00621
0.00629
Natural gas
0.00672
0.00666
HTR-PM
0.00402
0.00449
Time = 30 years, higher bank rate = 10%, lower fossil fuel price = 90% of normal price.


## 2.1. General Description of HTR-PM

The HTR-PM deploys two pebble-bed modular HTRs each with 250 MW thermal power. Two reactor modules are coupled with two steam generators which are connected to one steam turbine generator with 210 MW electric power. The reactor and the steam generator are installed inside two separate pressure vessels. The pressure vessels are assembled in a staggered, side-by-side arrangement and are connected by a horizontal coaxial hot gas duct. The primary pressure boundary consists of the Reactor Pressure Vessel (RPV), the Steam Generator Pressure Vessel (SGPV), and the Hot gas Duct Pressure Vessel (HDPV), which all are housed in a concrete shielding cavity as shown in Figure1. The main design parameters are listed in Table 1.Table 1
Major design parameters of HTR-PM [17].
Item
Value
Thermal power (MW)
2
×
250
Electric power (MW)
210
Active core diameter (cm)
300
Equivalent active core height (cm)
1100
Primary helium pressure (MPa)
7.0
Average helium temperature at reactor
250/750
inlet/outlet (°C)
Helium mass flow rate at full power
96
(kg·s−1)
Type of steam generator
Once-through
helical
Main steam flow rate at the inlet of
98
turbine (kg·s−1)
Main steam pressure (MPa)
14.3
Main steam temperature (°C)
566
Main feed-water temperature (°C)
205Figure 1
Primary loop of HTR-PM.As shown in Figure1, the thermal-hydraulic process related with the reactor and the primary loop of HTR-PM can be mainly explained as follows.(i)
Before entering the reactor vessel, the helium gas is driven by the helium blower, and the temperature of the inlet gas is around 250°C. After the helium flows through the hot fuel spheres in the reactor core, the temperature of it reaches 750°C. The hot helium exits the reactors and flows through the hot gas duct. The hot helium releases its thermal power to the water in the steam generator where it is cooled down to around 250°C. Then, the helium blower blows the cold helium through the outer coaxial pipes of the hot gas duct. Finally, the cold helium flows into RPV where it is heated again. In this way, a cycle of the helium flow is completed in the primary loop.(ii)
At the side of the secondary loop of HTR-PM plant, the water at a temperature of 205°C in the steam generator is heated to 566°C by hot helium and becomes superheated steam. Then superheated steam with a pressure of 14.3 MPa will drive the steam turbine and its conjoined generator in order to generate electrical power based on the Rankine cycle.


## 2.2. Status and Existing Problems of Conventional Steam Injection for Thermal Recovery

Steam injection is an established thermal recovery technique that has been applied successfully on many heavy oil reservoirs around the world. The process started in early 1960s with cyclic steam injection. The three main methods of steam injection are Cyclic Steam Stimulation (CSS), Steam Drive (SD), and Steam Assisted Gravity Drainage (SAGD) [2].The CSS is a simple and cheap method of applying thermal recovery process on a reservoir. It involves injecting steam into a well for several weeks, shutting the well in as long as necessary to allow the steam to heat the oil in the areas around the well, and putting the well back on production to recover the heated oil (Figure2). This process is repeated when the production from the well declines to a low level. The cycle is repeated many times until the ratio of oil produced to steam injected named Oil-Steam Ratio (OSR) drops to a level that is considered uneconomic. CSS was the first steam injection technique used in heavy oil reservoirs. It can be used as a limited pilot test on a well to investigate whether steam injection can enhance oil recovery in a particular field before undertaking more expensive pattern pilot tests that will require more wells and more equipment.Figure 2
Cyclic steam stimulation process.The scenario of the conventional thermal recovery technology uses the boiler to generate wet steam, which is shown as the bottom part of Figure3.Figure 3
Strategies for steam injection by HTR-PM and boiler.Conventionally, the boiler using fossil fuel such as coal, natural gas, and oil is utilized to heat water to wet steam for thermal recovery of heavy oil reservoirs. The water is driven by a pump and softened by the water-softening plant before entering the boiler. The steam out of the boiler will flow through the pipeline to a steam injecting station near the heavy oil well. Then, the wet steam will pass through the well head to the well tube. Finally, the wet steam will flow into the oil reservoir via the well tube which is usually several hundred meters long.Because of the limited thermal power of boilers and heat loss during steam transportation, the boilers are built near the heavy oil well to provide enough steam for thermal recovery. One boiler can only provide steam to a limited number of oil wells for steam injection. Usually, there are many boilers in a heavy oil field to provide steam to different heavy oil wells.The specific enthalpy of the steam or water can be indicated as(1)h(P,T,x)=h′(P)+xQ(P)+x∫TPTCP′′dt,
where P is the pressure of steam or water; T is the temperature of steam or water; x is the dryness of steam or water; h′(P) is the specific enthalpy of the saturated water at pressure P; Q(P) is the latent heat of vaporization of water at pressure P; TP is the temperature of the saturated steam at pressure P. CP′′ is the specific heat of the superheated steam at pressure P.The drynessx of wet steam can be expressed as
(2)x=msmw,
where ms is the mass of the steam component in the wet steam; mw is the mass of the whole wet steam.The conventional thermal recovery technology with dispersed steam supply and wet steam injection has the following shortcomings.(i)
The operation and management of a large number of small boilers is very expensive because of high labor expenditure and relative high price of equipment [18].(ii)
The conventional boiler is burning fossil fuel such as coal, natural gas, and oil to generate the steam, which has an environmental challenge of carbon dioxide emissions and large demand of water [4].(iii)
Loss of heat during steam transportation will reduce the heat capacity of injected steam and obviously worsen its quality since the velocity of flow is relatively slow and the specific enthalpy is low. Therefore, the heavy oil reservoirs cannot gain enough thermal energy even if a lot of water is consumed [5, 6].(iv)
The wet steam has low temperature and low specific volume which result in low stimulation efficiency [5, 6].


## 2.3. Strategy of Superheated Steam Injection from HTR-PM

The strategy of superheated steam injection by HTR-PM is shown as the top part of Figure3. Unlike the conventional steam injection method, all superheated steam will be intensively produced by one HTR plant which is located at several kilometers away from the heavy oil field in consideration of safety and engineering requirements. Then, the superheated steam will be delivered all over to the whole heavy oil field through the main steam pipeline with bigger pipe diameter and higher thermal insulation ability. The main steam pipeline will connect to normal pipelines at the diverging points. Finally, the steam will flow into the oil reservoirs through the steam injecting station, well head, and well tube.For the wet steam,x is less than 1 and the third part of (1) is zero. For the superheated steam, x is 1. Therefore, the enthalpy difference between the superheated steam and the wet steam at the same pressure can be shown as follows:
(3)h(P,T)-h(P,TP,x)=(1-x)Q(P)+∫TPTCP′′dt.From this equation, it can be found that the superheated steam has much more enthalpy than the wet steam whenx is not very close to 1 and TP-T is a big value. The thermal recovery technology by HTR with concentrated steam supply and superheated steam injection is predicted to have the following advantages.(i)
The operation and management of HTR for steam generation is relatively cheap.(ii)
The steam production by HTR emits less CO2 than the conventional boiler burning fossil fuel.(iii)
Loss of heat during steam transportation will not seriously worsen the quality of injected steam since the velocity of flow is relatively fast and the specific enthalpy is high. Therefore, the heavy oil reservoirs can receive much more thermal energy by superheated steam injection when the same mass of water is injected into oil reservoirs.(iv)
The superheated steam has higher enthalpy and higher specific volume which results in higher quality of steam stimulation [5, 6].


## 2.4. Adoption of HTR-PM for Heavy Oil Thermal Recovery

The design of the HTR-PM applied to thermal recovery of heavy oil reservoirs is shown in Figure4. The primary loop and the steam generator are kept as the original design of the HTR-PM in order to take advantage of its mature design. Originally, the secondary loop of the HTR-PM adopts a steam turbine system which generates electricity with a Rankine cycle. A two-stage steam jet mixer system is design to preheat the feed water of the HTR-PM.Figure 4
Modified design of HTR-PM for thermal recovery.In the secondary loop of HTR-PM, some basic parameters such as mass flow rate, inlet temperature, and outlet temperature of water should be determined by taking into account the original design of HTR-PM and need of heavy oil thermal recovery. Table2 shows the basic configuration when a HTR-PM or boilers are applied to thermal recovery of a reference heavy oil field. In order to maintain the safety of HTR-PM and oil field, the HTR-PM is located around 4 km away from the oil field to void the interaction when one of them is in a dangerous status. In this reference oil field, the number of injected wells at the same time is around 30 (20–40) and the mass flow rate of water to each well is around 2.31 kg/s (200 ton/day). A single reactor of HTR-PM can provide enough injected water since the flow out of the steam generator is 98 kg/s, around 8600 ton/day.Table 2
Basic configuration of injection.
Injection with boiler/HTR-PM
Number of used boiler/HTR-PM reactor at same time
15/1
Number of injected wells at same time
30 (20–40)
Number of boilers
100
Number of wells
6000
Initial temperature of steam (°C)
318.05/566
Mass flow out of each boiler/HTR-PM (ton/day)
200–800/6500
Mass flow rate of water to each well (ton/day)
Around 200
Initial pressure of steam (MPa)
11/14.3
Initial dryness of steam
0.725/1
Average length of main steam pipeline (km)
0/7.5
Area of reference oil field (km2)
20
×
20
Average length of branch steam pipeline (km)
0.8
Average distance from injection station to well head
0.2
Depth of typical well (m)
759.75The process in the modified secondary loop of HTR-PM can be described as follows. The water at 75.08 kg/s and 25°C is driven to the secondary loop by a pump. The water is purified and softened by a water treatment plant mainly consisting of several sand filters and several ion exchangers. The cool water is heated by the superheated steam from the output of the steam generator at a steam jet mixer. Then the water is pumped to a deoxidizer and heated again by the superheated steam at another steam jet mixer. Finally, the water at around 205°C and 98 kg/s, which is same as the original design of HTR-PM, is fed to the once-through helical steam generator. The output water of the steam generator at around 566°C is mainly divided in two branches. One fluid is deployed as feedback to the two steam jet mixers and the deoxidizer in order to heat the feed water instead of the conventional electrical heaters. The main fluid at 75.08 kg/s (6500 ton/day) and 566°C is provided to the superheated steam injection system for heavy oil thermal recovery.


## 2.5. Economic Comparison between Steam Injection by Conventional Boiler and HTR-PM

By considering the construction investment, fuel cost, and operating cost, the full cost of the steam injection by burning coal or natural gas can be estimated [18]. The construction investment and operating cost are converted to cost per ton steam injection which are shown in Table 3. The full cost of steam injection by HTR-PM can also be estimated [19]. In the same way, the construction investment and operating cost of steam injection by HTR-PM are converted to cost per ton of steam injection in the same Table. The full cost of steam injection with unit of $/t means the total cost for injecting 1 ton of steam.Table 3
Costs of steam injection by boiler and HTR-PM.
Injectionmode
Constructioninvestment ($/(t·y))
Fuel cost($/t or $/m3)
Operatingcost ($/t)
Full operatingcost ($/t)
Full costfor steam injection ($/t)
Coal
29.78
27.99
8.766
12.04
14.69
Natural gas
15.54
0.1541
10.45
14.50
15.88
HTR-PM
95.17
—
—
5.62
14.07
Time = 30 years, bank rate = 8%.For the uncertainty evaluation, if the bank rate rises to 10% and fuel cost decreases by 10%, the costs can be estimated as shown in Table4.Table 4
Costs of steam injection at lower fossil fuel price and higher bank rate.
Injectionmode
Constructioninvestment ($/(t·y))
Fuel cost($/t or $/m3)
Operatingcost ($/t)
Full operatingcost ($/t)
Full cost for steaminjection ($/t)
Coal
29.78
25.19
8.766
11.71
14.87
Natural gas
15.54
0.1368
10.45
14.10
15.74
HTR-PM
95.17
—
—
5.62
15.72
Time = 30 years, bank rate = 10%.From these results, it can be found that the steam injection by HTR-PM is still a competitive choice compared to the steam injection by the conventional boiler burning coal or natural gas even with lower fossil fuel price and higher bank rate.To consider the quality difference of the steam produced by the fossil fuel boiler or HTR-PM, the full cost can be changed to the enthalpy of injected steam instead of the mass of it. The full costs for steam injection by HTR-PM or burning coal or natural gas are shown in Table5, which shows the cost to provide 1 kJ enthalpy to the injected steam. According to this table, the steam injection by HTR-PM has an obvious economic advantage on the steam injection by conventional boilers burning coal or natural gas even with lower fossil fuel price and higher bank rate.Table 5
Costs of steam injection by considering enthalpy difference of steam.
Injectionmode
Full cost for steaminjection(mills/kJ)
Full cost for steaminjection under higher bank rate and lower fossil fuel price (mills/kJ)
Coal
0.00621
0.00629
Natural gas
0.00672
0.00666
HTR-PM
0.00402
0.00449
Time = 30 years, higher bank rate = 10%, lower fossil fuel price = 90% of normal price.


## 3. Design and Development of GIS with Thermal Hydraulic Analysis Function

### 3.1. Need of GIS with Thermal Hydraulic Analysis Function

It is easy to conclude that the concentrative steam supply by HTR has advantages over the conventional dispersed steam supply by boilers at the aspects of labor expenditure [18, 19]. In addition, it can also be predicted that the superheated steam can beat the wet steam because of higher specific enthalpy and specific volume [5, 6]. However, some results from actual engineering side are needed for answering the following questions.(i)
Will the quality of the steam by HTR be same as or even worse than the quality of the steam by boiler because of heat loss since the superheated steam has to flow through an extra main steam pipeline which is several kilometers long? If it is, the HTR design for thermal recovery technology will lose its most important strength over conventional technology.(ii)
The thermal hydraulic analysis of a whole actual oil field is rather difficult because the situation is very complex when the injected steam flows through the main pipeline, branch pipeline, steam injecting station, well tube, and so forth. The mass flow rate, temperature, pressure, and dryness of the steam change in a nonlinear manner in the process of the steam transportation, which cannot be simply considered as a process in one typical pipeline.(iii)
Since the superheated steam has higher specific volume than the wet steam, the velocity of flow of the superheated steam will be much higher than that of wet steam if the mass rate of injected steam stays the same. Is the pressure drop acceptable or not before the steam flows to oil reservoirs through the extended pipeline?(iv)
Should the main steam pipeline be placed over-ground or underground? Can the superheated steam injection fit for all kinds of well structures?A GIS with thermal hydraulic analysis function can play the role to answer the above questions. The GIS can serve the following functions.(i)
Management of geographic information of an oil field such as coordinates of HTR-PM, boiler, pipeline, steam injecting station, and reservoir.(ii)
Management of configuration information of HTR-PM, boiler, pipeline, and reservoir including pressure, temperature, mass flow rate of output steam of HTR-PM or boiler, geometrical and thermodynamics characteristics of pipeline and reservoir, and so forth.(iii)
Calculation of loss of heat, change of pressure, and possible phase change when the steam flows from HTR-PM or boiler to reservoir.


### 3.2. Structure and Function of The GIS

The structure and function of the GIS are shown in Figure5. The GIS with thermal hydraulic analysis function is developed based on component-based development where the third-party developed GIS component is embedded in it. It mainly consists of three modules.(i)
The thermal-hydraulic calculation module can simulate the change of thermal-hydraulic status of the steam from HTR or boiler to oil reservoirs. It can access the information of each geographic symbol in the GIS through temporary input/output file. In the GIS, the geographic symbols represent HTR-PM and various components of the oil field such as boiler, pipeline, steam injecting station, reservoir, and so forth. The thermal-hydraulic calculation module will be explained in Section4.(ii)
The data treatment module includes three sub-modules: database management module, cache management module, and input/output management module. The database management module can access the basic database, the configuration database, and the result database. The basic database stores the basic information of various geographic symbols in the GIS including name, ID, type, geometry, and so forth. The configuration database stores the information for the thermal hydraulic analysis such as inner diameter of pipeline, outside diameter pipeline, type of pipeline, type of well, heat conductivity of heat-insulating material, and so forth. The result database can save the thermal hydraulic analysis result of each symbol in the GIS. The input/output management module mainly reads and writes the temporary input/output files to provide data to the thermal-hydraulic calculation module and get results from the thermal hydraulic analysis. The cache treatment module gets the information from the database and provides it to the geographic information management module for finding the flow route of the steam out of the HTR or boiler.(iii)
The Geographic Information Management module can realize some basic management functions and advanced management function through the GIS component. The basic management functions can perform the zoom in, zoom out, move, centralize, and other functions for management of the geographic symbol. The advanced management function can determine the flow route of the steam out of the HTR or boiler according to the configuration of each symbol.Figure 5
Structure and function of the GIS.


### 3.3. How the GIS Works

The flow chart of the GIS is shown in Figure6. Firstly, the GIS will load the geographic information and configuration information from the basic and configuration databases. Then, the user can modify the configuration information of the geographic symbol by selecting the corresponding symbol through the GIS interface.Figure 6
Flow chart of the GIS.After the process of configuration, the flow route from the HTR or boiler to oil reservoirs will be determined according to the configuration since sometime dozens of oil wells out of thousand existing wells in the oil field will be selected for steam injection. The output of the boiler or HTR, such as temperature, pressure, and mass flow rate of steam, will be obtained. Then, the thermal hydraulic analysis will be carried out when the steam flows in the pipeline and diverging points before the Steam Injecting Station (SIS). After the treatment of flow at SIS, the thermal-hydraulic behavior of the flow in the pipeline and the oil well will be calculated. Finally, all the above results will be recorded for display and analysis.Figure7 shows the snapshot when the GIS works for thermal hydraulic analysis.Figure 7
Snapshot of the GIS.


## 3.1. Need of GIS with Thermal Hydraulic Analysis Function

It is easy to conclude that the concentrative steam supply by HTR has advantages over the conventional dispersed steam supply by boilers at the aspects of labor expenditure [18, 19]. In addition, it can also be predicted that the superheated steam can beat the wet steam because of higher specific enthalpy and specific volume [5, 6]. However, some results from actual engineering side are needed for answering the following questions.(i)
Will the quality of the steam by HTR be same as or even worse than the quality of the steam by boiler because of heat loss since the superheated steam has to flow through an extra main steam pipeline which is several kilometers long? If it is, the HTR design for thermal recovery technology will lose its most important strength over conventional technology.(ii)
The thermal hydraulic analysis of a whole actual oil field is rather difficult because the situation is very complex when the injected steam flows through the main pipeline, branch pipeline, steam injecting station, well tube, and so forth. The mass flow rate, temperature, pressure, and dryness of the steam change in a nonlinear manner in the process of the steam transportation, which cannot be simply considered as a process in one typical pipeline.(iii)
Since the superheated steam has higher specific volume than the wet steam, the velocity of flow of the superheated steam will be much higher than that of wet steam if the mass rate of injected steam stays the same. Is the pressure drop acceptable or not before the steam flows to oil reservoirs through the extended pipeline?(iv)
Should the main steam pipeline be placed over-ground or underground? Can the superheated steam injection fit for all kinds of well structures?A GIS with thermal hydraulic analysis function can play the role to answer the above questions. The GIS can serve the following functions.(i)
Management of geographic information of an oil field such as coordinates of HTR-PM, boiler, pipeline, steam injecting station, and reservoir.(ii)
Management of configuration information of HTR-PM, boiler, pipeline, and reservoir including pressure, temperature, mass flow rate of output steam of HTR-PM or boiler, geometrical and thermodynamics characteristics of pipeline and reservoir, and so forth.(iii)
Calculation of loss of heat, change of pressure, and possible phase change when the steam flows from HTR-PM or boiler to reservoir.


## 3.2. Structure and Function of The GIS

The structure and function of the GIS are shown in Figure5. The GIS with thermal hydraulic analysis function is developed based on component-based development where the third-party developed GIS component is embedded in it. It mainly consists of three modules.(i)
The thermal-hydraulic calculation module can simulate the change of thermal-hydraulic status of the steam from HTR or boiler to oil reservoirs. It can access the information of each geographic symbol in the GIS through temporary input/output file. In the GIS, the geographic symbols represent HTR-PM and various components of the oil field such as boiler, pipeline, steam injecting station, reservoir, and so forth. The thermal-hydraulic calculation module will be explained in Section4.(ii)
The data treatment module includes three sub-modules: database management module, cache management module, and input/output management module. The database management module can access the basic database, the configuration database, and the result database. The basic database stores the basic information of various geographic symbols in the GIS including name, ID, type, geometry, and so forth. The configuration database stores the information for the thermal hydraulic analysis such as inner diameter of pipeline, outside diameter pipeline, type of pipeline, type of well, heat conductivity of heat-insulating material, and so forth. The result database can save the thermal hydraulic analysis result of each symbol in the GIS. The input/output management module mainly reads and writes the temporary input/output files to provide data to the thermal-hydraulic calculation module and get results from the thermal hydraulic analysis. The cache treatment module gets the information from the database and provides it to the geographic information management module for finding the flow route of the steam out of the HTR or boiler.(iii)
The Geographic Information Management module can realize some basic management functions and advanced management function through the GIS component. The basic management functions can perform the zoom in, zoom out, move, centralize, and other functions for management of the geographic symbol. The advanced management function can determine the flow route of the steam out of the HTR or boiler according to the configuration of each symbol.Figure 5
Structure and function of the GIS.


## 3.3. How the GIS Works

The flow chart of the GIS is shown in Figure6. Firstly, the GIS will load the geographic information and configuration information from the basic and configuration databases. Then, the user can modify the configuration information of the geographic symbol by selecting the corresponding symbol through the GIS interface.Figure 6
Flow chart of the GIS.After the process of configuration, the flow route from the HTR or boiler to oil reservoirs will be determined according to the configuration since sometime dozens of oil wells out of thousand existing wells in the oil field will be selected for steam injection. The output of the boiler or HTR, such as temperature, pressure, and mass flow rate of steam, will be obtained. Then, the thermal hydraulic analysis will be carried out when the steam flows in the pipeline and diverging points before the Steam Injecting Station (SIS). After the treatment of flow at SIS, the thermal-hydraulic behavior of the flow in the pipeline and the oil well will be calculated. Finally, all the above results will be recorded for display and analysis.Figure7 shows the snapshot when the GIS works for thermal hydraulic analysis.Figure 7
Snapshot of the GIS.


## 4. Thermal-Hydraulic Models for GIS

### 4.1. Basic Model and Its Treatment

The whole flow route after the HTR or boiler consists of main steam pipeline, diverging point, branch steam pipeline, SIS, and oil well tube. The change of pressure, temperature, and flow rate occurs when the steam flows through the flow route. As boundary conditions, the pressure, temperature (dryness for wet steam), and mass flow rate of the steam are fixed at the outlet of the HTR steam generator or boiler.When analyzing the thermal-hydraulic behavior of the steam flow in the pipeline and well tube, some basic assumptions are adopted.(i)
The pressure and flow rate of the steam are analyzed based on quasi-steady state model.(ii)
Steam is compressible and treated as a continuum medium.According to the assumptions mentioned above, some governing equations can be formulated as follows.(i)
Mass conservation(4)uv=const.(ii)
Momentum conservation(5)gsinθdL+udu+dPρ=-λu22dLDi.(iii)
Energy conservation(6)dQ=gsinθdL+dh+udu.In (4)–(6), u is the flow speed of steam or water; v is the specific volume of steam or water; ρ is the density of steam or water; P is the pressure of steam or water; L is the length of the steam or water flow; λ is the friction resistance coefficient of the pipeline or well tube; Di is the equivalent diameter of the pipeline or well tube; g is the acceleration of gravity; θ is the angle between the flow and the horizontal direction; dQ is the heat absorbed per unit mass of steam or water; h is the specific enthalpy of the steam or water.λ can be calculated as follows [20]:
(7)λ=64Re(Re<2300)λ=0.316Re0.25(2300≤Re<80DiΔd,Re<8×104)1λ=2lg(Reλ)-0.8(2300≤Re<80DiΔd,Re≥8×104)1λ=-2lg(Δd3.7Di+2.51Reλ)(80DiΔd≤Re<4160(Di2Δd)0.85)λ=(2lg(Di2Δd)+1.74)-2(Re≥4160(Di2Δd)0.85),
where Re is the Reynolds number; Δd is roughness of tube wall.In the three conservation equations (4)–(6) in this model, the independent variables are pressure P and temperature T (dryness x for wet steam). The related differential equations are described by
(8)dPdL=f1(P,T)ordPdL=f1′(P,x)dTdL=f2(P,T)ordxdL=f2′(P,x).In order to get the above two equations, from the three conservation equations, the following expression of enthalpy and specific volume are employed:(9)dhdL=∂h∂PdPdL+∂h∂TdTdLordhdL=∂h∂PdPdL+∂h∂xdxdL(10)dvdL=∂v∂PdPdL+∂v∂TdTdLordvdL=∂v∂PdPdL+∂v∂xdxdL.From (4), (5), (6), (9), and (10), (11) and (12) are deduced for superheated steam or water (use x instead of T for wet steam) as follows:
(11)dPdL=BF+CEAE-BD(12)dTdL=AF+CEBD-AEordxdL=AF+CEBD-AE,
where
(13)A=v+u2v∂v∂P,B=u2v∂v∂TorB=u2v∂v∂x,C=gsinθ+λu22Di,D=∂h∂P+u2v∂v∂P,E=∂h∂T+u2v∂v∂TorE=∂h∂x+u2v∂v∂x,F=dQdL-gsinθ.Equations (11) and (12) are numerically solved by using a variable step four-order explicit Runge-Kutta method [21, 22]. For the superheated steam or water, the iteration equation (for the wet steam, use x instead of T) can be expressed as follows:
(14)P′=P0+l6(K11+2K21+2K31+K41),T′=T0+l6(K12+2K22+2K32+K42),K11=dPdL|P=P0,T=T0,K12=dTdL|P=P0,T=T0,K21=dPdL|P=P0+(l/2)K11,T=T0+(l/2)K12,K22=dTdL|P=P0+(l/2)K11,T=T0+(l/2)K12,K31=dPdL|P=P0+(l/2)K21,T=T0+(l/2)K22,K32=dTdL|P=P0+(l/2)K21,T=T0+(l/2)K22,K41=dPdL|P=P0+(l/2)K31,T=T0+(l/2)K32,K42=dTdL|P=P0+(l/2)K31,T=T0+(l/2)K32,
where l is the iteration length of L;  P0 and T0 are the value of the previous iteration step.


### 4.2. Calculation of Heat Loss

The structure of overground or underground pipeline is shown in Figure8. The structure of the heat insulation oil well tube is shown in Figure 9. There is a packer at the bottom of the whole well tube near the oil layer which is used to seal the cavity inside the sleeve. With the packer, the cavity will be filled with air only. Otherwise, water will occupy a partial height of the cavity. Different from the heat insulation well tube, the normal well tube does not have the heat barrier material and the thermal sleeve of Figure 9.Figure 8
Structure of overground or underground pipeline.Figure 9
Structure of insulation oil well tube.When solving the equations mentioned in Section4.1, the heat absorbed by the pipeline wall and the well tube wall should be obtained [23].For the case of heat which is lost from the steam or water through the overground pipeline wall to the atmosphere as follows:(15)dQo=2πRo4×Uo(Tf-Ta)dL,
where Ro4 is the outer radius of the thermal sleeve; Uo is the equivalent coefficient of heat transfer; Tf is the temperature of steam or water fluid; Ta is the temperature of atmosphere next to the thermal sleeve.U
o can be described as follows, in which the thermal resistance of convective heat transfer between steam/water and pipe and the thermal resistance of steam pipe and thermal sleeve are ignored:
(16)Uo=[Ro4ln⁡(Ro3/Ro2)λins0+1hc0]-1,
where Ro2 is the outer radius of the steam pipe; Ro3 is the inner radius of the thermal sleeve; λins0 is the coefficient of thermal conductivity of the heat barrier material; hc0 is the coefficient of convective heat transfer of air out of the thermal sleeve.For the case of heat which is lost from the steam or water through the underground pipeline wall to the earth(17)dQu=2πRo4×Uu(Tf-Ts)dL,
where Uu is the equivalent coefficient of heat transfer; Ts is the temperature of soil next to the thermal sleeve.U
u can be described as follows:
(18)Uu=[Ro4ln⁡(Ro3/Ro2)λins0]-1.For the case of heat which is lost from steam or water through the oil well tube wall to the earth(19)dQt=2πR7×Ut(Tf-Th)dL,
where R7 is the outer diameter of the concrete; Ut is the equivalent coefficient of heat transfer; Th is the temperature of soil next to the concrete.U
t can be described as the following kinds of situation in which the thermal resistance of convective heat transfer between steam/water and pipe and the thermal resistance of the steam pipe, thermal sleeve and sleeve are ignored.(i)
Heat insulation tube with packer(20)Ut=[R7R2Uins+R7R4(hc+hr)+R7ln⁡(R7/R6)λcem]-1.(ii)
Heat insulation tube without packerWhen the cavity is filled with air, it is the same as (20).When the cavity is filled with water as follows:(21)Ut=[R7R2Uins+R7R4hc+R7ln⁡(R7/R6)λcem]-1.(i)
Normal tube with packer(22)Ut=[R7R4(hc+hr)+R7ln⁡(R7/R6)λcem]-1.(ii)
Normal tube without packerWhen the cavity is filled with air, it is the same as (22).When the cavity is filled with water as follows:(23)Ut=[R7R4hc+R7ln⁡(R7/R6)λcem]-1,
where R2,R4,R6, and R7 are the outer radius of oil tube, outer radius of the thermal sleeve, outer radius of the sleeve, and outer radius of concrete, respectively; Uins is the equivalent coefficient of heat transfer of the heat insulation tube; hc is the equivalent coefficient of conductive and convective heat transfer in the cavity; hr is the coefficient of radiation heat transfer in the cavity; λcem is the coefficient of conductive heat transfer of the concrete.


### 4.3. Calculation of Local Pressure Change

For the case of superheated steam or water, the local pressure change can be described as follows:(24)Δp=λlud22v,
where λl is the equivalent local resistance coefficient; ud is the average flow rate of downstream steam or water.The value ofλl can be divided as the four following situations which are shown in Table 6 [20]:Table 6
Values ofλl in the case of steam or water.
Situation
Value
Sudden enlargement pipe or tube
λ
l
=
(
A
2
A
1
-
1
)
2
whereA1 is the sectional area of upstream flow channel;
A
2 is the sectional area of downstream flow channel.
Sudden contraction pipe or tube
λ
l
=
0.5
(
1
-
A
2
A
1
)
90° bend
λ
l
=
0.12
Valve
Gate valve
λ
l
=
0.2
Ball valve
λ
l
=
10.0
Control valve
λ
l
=
5.0For the case of wet steam,Δp can be obtained by treating the wet steam as the single phase mentioned above. Then, the local pressure change will be corrected as follows [20]. 								(25)Δps=Δp(1+BX+1X2),
where
(26)X=(1-xx)0.9·(v′v′′)0.5·(μ′μ′′)0.1,B=B1·(v′′v′+v′v′′),
where v′ is the specific volume of saturated water; v″ is the specific volume of saturated steam; μ′ is the dynamic viscosity coefficient of saturated water; μ′′ is the dynamic viscosity coefficient of saturated steam.The value ofB1 can be divided as the four following situations which are shown in Table 7.Table 7
Values ofB1 in the case of wet steam.
Situation
Value
Sudden enlargement pipe or tube
B
1 = 1.0
Sudden contraction pipe or tube
B
1 = 1.0
90° bend
B
1
=
1
+
35
D
i
l
wherel  is the
length of the bend
Valve
Gate valve
B
1 = 1.5
Ball valve
B
1 = 2.3
Control valve
B
1 = 1.0


## 4.1. Basic Model and Its Treatment

The whole flow route after the HTR or boiler consists of main steam pipeline, diverging point, branch steam pipeline, SIS, and oil well tube. The change of pressure, temperature, and flow rate occurs when the steam flows through the flow route. As boundary conditions, the pressure, temperature (dryness for wet steam), and mass flow rate of the steam are fixed at the outlet of the HTR steam generator or boiler.When analyzing the thermal-hydraulic behavior of the steam flow in the pipeline and well tube, some basic assumptions are adopted.(i)
The pressure and flow rate of the steam are analyzed based on quasi-steady state model.(ii)
Steam is compressible and treated as a continuum medium.According to the assumptions mentioned above, some governing equations can be formulated as follows.(i)
Mass conservation(4)uv=const.(ii)
Momentum conservation(5)gsinθdL+udu+dPρ=-λu22dLDi.(iii)
Energy conservation(6)dQ=gsinθdL+dh+udu.In (4)–(6), u is the flow speed of steam or water; v is the specific volume of steam or water; ρ is the density of steam or water; P is the pressure of steam or water; L is the length of the steam or water flow; λ is the friction resistance coefficient of the pipeline or well tube; Di is the equivalent diameter of the pipeline or well tube; g is the acceleration of gravity; θ is the angle between the flow and the horizontal direction; dQ is the heat absorbed per unit mass of steam or water; h is the specific enthalpy of the steam or water.λ can be calculated as follows [20]:
(7)λ=64Re(Re<2300)λ=0.316Re0.25(2300≤Re<80DiΔd,Re<8×104)1λ=2lg(Reλ)-0.8(2300≤Re<80DiΔd,Re≥8×104)1λ=-2lg(Δd3.7Di+2.51Reλ)(80DiΔd≤Re<4160(Di2Δd)0.85)λ=(2lg(Di2Δd)+1.74)-2(Re≥4160(Di2Δd)0.85),
where Re is the Reynolds number; Δd is roughness of tube wall.In the three conservation equations (4)–(6) in this model, the independent variables are pressure P and temperature T (dryness x for wet steam). The related differential equations are described by
(8)dPdL=f1(P,T)ordPdL=f1′(P,x)dTdL=f2(P,T)ordxdL=f2′(P,x).In order to get the above two equations, from the three conservation equations, the following expression of enthalpy and specific volume are employed:(9)dhdL=∂h∂PdPdL+∂h∂TdTdLordhdL=∂h∂PdPdL+∂h∂xdxdL(10)dvdL=∂v∂PdPdL+∂v∂TdTdLordvdL=∂v∂PdPdL+∂v∂xdxdL.From (4), (5), (6), (9), and (10), (11) and (12) are deduced for superheated steam or water (use x instead of T for wet steam) as follows:
(11)dPdL=BF+CEAE-BD(12)dTdL=AF+CEBD-AEordxdL=AF+CEBD-AE,
where
(13)A=v+u2v∂v∂P,B=u2v∂v∂TorB=u2v∂v∂x,C=gsinθ+λu22Di,D=∂h∂P+u2v∂v∂P,E=∂h∂T+u2v∂v∂TorE=∂h∂x+u2v∂v∂x,F=dQdL-gsinθ.Equations (11) and (12) are numerically solved by using a variable step four-order explicit Runge-Kutta method [21, 22]. For the superheated steam or water, the iteration equation (for the wet steam, use x instead of T) can be expressed as follows:
(14)P′=P0+l6(K11+2K21+2K31+K41),T′=T0+l6(K12+2K22+2K32+K42),K11=dPdL|P=P0,T=T0,K12=dTdL|P=P0,T=T0,K21=dPdL|P=P0+(l/2)K11,T=T0+(l/2)K12,K22=dTdL|P=P0+(l/2)K11,T=T0+(l/2)K12,K31=dPdL|P=P0+(l/2)K21,T=T0+(l/2)K22,K32=dTdL|P=P0+(l/2)K21,T=T0+(l/2)K22,K41=dPdL|P=P0+(l/2)K31,T=T0+(l/2)K32,K42=dTdL|P=P0+(l/2)K31,T=T0+(l/2)K32,
where l is the iteration length of L;  P0 and T0 are the value of the previous iteration step.


## 4.2. Calculation of Heat Loss

The structure of overground or underground pipeline is shown in Figure8. The structure of the heat insulation oil well tube is shown in Figure 9. There is a packer at the bottom of the whole well tube near the oil layer which is used to seal the cavity inside the sleeve. With the packer, the cavity will be filled with air only. Otherwise, water will occupy a partial height of the cavity. Different from the heat insulation well tube, the normal well tube does not have the heat barrier material and the thermal sleeve of Figure 9.Figure 8
Structure of overground or underground pipeline.Figure 9
Structure of insulation oil well tube.When solving the equations mentioned in Section4.1, the heat absorbed by the pipeline wall and the well tube wall should be obtained [23].For the case of heat which is lost from the steam or water through the overground pipeline wall to the atmosphere as follows:(15)dQo=2πRo4×Uo(Tf-Ta)dL,
where Ro4 is the outer radius of the thermal sleeve; Uo is the equivalent coefficient of heat transfer; Tf is the temperature of steam or water fluid; Ta is the temperature of atmosphere next to the thermal sleeve.U
o can be described as follows, in which the thermal resistance of convective heat transfer between steam/water and pipe and the thermal resistance of steam pipe and thermal sleeve are ignored:
(16)Uo=[Ro4ln⁡(Ro3/Ro2)λins0+1hc0]-1,
where Ro2 is the outer radius of the steam pipe; Ro3 is the inner radius of the thermal sleeve; λins0 is the coefficient of thermal conductivity of the heat barrier material; hc0 is the coefficient of convective heat transfer of air out of the thermal sleeve.For the case of heat which is lost from the steam or water through the underground pipeline wall to the earth(17)dQu=2πRo4×Uu(Tf-Ts)dL,
where Uu is the equivalent coefficient of heat transfer; Ts is the temperature of soil next to the thermal sleeve.U
u can be described as follows:
(18)Uu=[Ro4ln⁡(Ro3/Ro2)λins0]-1.For the case of heat which is lost from steam or water through the oil well tube wall to the earth(19)dQt=2πR7×Ut(Tf-Th)dL,
where R7 is the outer diameter of the concrete; Ut is the equivalent coefficient of heat transfer; Th is the temperature of soil next to the concrete.U
t can be described as the following kinds of situation in which the thermal resistance of convective heat transfer between steam/water and pipe and the thermal resistance of the steam pipe, thermal sleeve and sleeve are ignored.(i)
Heat insulation tube with packer(20)Ut=[R7R2Uins+R7R4(hc+hr)+R7ln⁡(R7/R6)λcem]-1.(ii)
Heat insulation tube without packerWhen the cavity is filled with air, it is the same as (20).When the cavity is filled with water as follows:(21)Ut=[R7R2Uins+R7R4hc+R7ln⁡(R7/R6)λcem]-1.(i)
Normal tube with packer(22)Ut=[R7R4(hc+hr)+R7ln⁡(R7/R6)λcem]-1.(ii)
Normal tube without packerWhen the cavity is filled with air, it is the same as (22).When the cavity is filled with water as follows:(23)Ut=[R7R4hc+R7ln⁡(R7/R6)λcem]-1,
where R2,R4,R6, and R7 are the outer radius of oil tube, outer radius of the thermal sleeve, outer radius of the sleeve, and outer radius of concrete, respectively; Uins is the equivalent coefficient of heat transfer of the heat insulation tube; hc is the equivalent coefficient of conductive and convective heat transfer in the cavity; hr is the coefficient of radiation heat transfer in the cavity; λcem is the coefficient of conductive heat transfer of the concrete.


## 4.3. Calculation of Local Pressure Change

For the case of superheated steam or water, the local pressure change can be described as follows:(24)Δp=λlud22v,
where λl is the equivalent local resistance coefficient; ud is the average flow rate of downstream steam or water.The value ofλl can be divided as the four following situations which are shown in Table 6 [20]:Table 6
Values ofλl in the case of steam or water.
Situation
Value
Sudden enlargement pipe or tube
λ
l
=
(
A
2
A
1
-
1
)
2
whereA1 is the sectional area of upstream flow channel;
A
2 is the sectional area of downstream flow channel.
Sudden contraction pipe or tube
λ
l
=
0.5
(
1
-
A
2
A
1
)
90° bend
λ
l
=
0.12
Valve
Gate valve
λ
l
=
0.2
Ball valve
λ
l
=
10.0
Control valve
λ
l
=
5.0For the case of wet steam,Δp can be obtained by treating the wet steam as the single phase mentioned above. Then, the local pressure change will be corrected as follows [20]. 								(25)Δps=Δp(1+BX+1X2),
where
(26)X=(1-xx)0.9·(v′v′′)0.5·(μ′μ′′)0.1,B=B1·(v′′v′+v′v′′),
where v′ is the specific volume of saturated water; v″ is the specific volume of saturated steam; μ′ is the dynamic viscosity coefficient of saturated water; μ′′ is the dynamic viscosity coefficient of saturated steam.The value ofB1 can be divided as the four following situations which are shown in Table 7.Table 7
Values ofB1 in the case of wet steam.
Situation
Value
Sudden enlargement pipe or tube
B
1 = 1.0
Sudden contraction pipe or tube
B
1 = 1.0
90° bend
B
1
=
1
+
35
D
i
l
wherel  is the
length of the bend
Valve
Gate valve
B
1 = 1.5
Ball valve
B
1 = 2.3
Control valve
B
1 = 1.0


## 5. Thermal Hydraulic Analysis for Thermal Recovery

### 5.1. Basic Configuration

Table8 shows the basic parameters and their values of the main steam pipeline and branch steam pipeline. There are four kinds of branch steam pipeline with different inner diameter and thickness according to their mass flow rate. According to the study, the thermal conductivity of heat barrier material is changed with the temperature of fluid [24]. When the temperature of the fluid is higher than 400°C, a linear relation is adopted in which the thermal conductivity will be increased with the rise of temperature of the fluid. Otherwise, the thermal conductivity is set as a constant. The thermal conductivity of the main steam pipeline is less than that of the branch steam pipeline.Table 8
Basic parameters of pipeline.
Parameter
Value
Roughness (mm)
0.014
Inner diameter (m)
0.4/0.3/0.2/0.1
Thickness (mm)
15/15/8/7
Thermal conductivity coefficient of heat
0.058 +t× 0.9E − 4  (t > 400°C)
barrier material (J/(m·s·K))
0.094/0.125 (t ≤ 400°C)
Thickness of heat barrier material (m)
0.13
Horizontal angle (°)
0
Position
Overground/underground
Height of bracket (m)
0.6/0.3
Cross-sectional area of bracket in thermal
0.004
sleeve (m2)Table9 shows the basic parameters and their values of oil well. Here, the values of basic parameters of all oil wells are set as the same value in order to compare the difference of heat loss, pressure change, and possible phase transformation of different designs. Actually, the values of basic parameters of different oil wells may be different to each other, such as height of well, roughness of well tube, and so forth. The effect of the joint is considered which will increase the heat loss when the well tube is the heat insulation tube.Table 9
Basic parameters of oil well.
Parameter
Value
Roughness of well tube (mm)
0.014
Inner diameter of well tube (mm)
62
Outer diameter of well tube (mm)
73
Thermal conductivity coefficient of heat barrier material (J/(m·s·K))
0.0443 +t× 1.39E − 4
Thickness of thermal sleeve (mm)
19.5
Inner blackness of cavity
0.9
Outer blackness of cavity
0.56
Inner diameter of sleeve (mm)
224.4
Outer diameter of sleeve (mm)
324.4
Thickness of concrete (mm)
30
Thermal conductivity coefficient of concrete (J/(m·s·K))
0.516
Length of each well tube (m)
10
Length of each joint (m)
0.13
Inner diameter of joint (mm)
60
Outer diameter of joint (mm)
76
Height of well (m)
759.75Table10 shows the basic parameters and their values of environment.Table 10
Parameter of environment.
Parameter
Value
Tundra exists
NO
Temperature of atmosphere and earth surface (°C)
20
Starting temperature of zone of constant
15
temperature (°C)
Starting depth of zone of constant temperature (m)
30
Temperature gradient of zone of constant
0.018
temperature (°C/m)
Wind speed of earth surface (m/s)
2
Thermal conductivity of soil except tundra
2.6528
(J/(m·s·K))
Thermal diffusivity of soil except tundra (m2/s)
9.972E − 07


### 5.2. Introduction of Result

The GIS embedded with thermal hydraulic analysis function is applied to analyze the thermal hydraulic process in the reference heavy oil field whose basic configuration is mentioned above. The heat loss, pressure change, and possible phase transformation are calculated and analyzed when the steam flows through the pipeline and is injected into oil reservoirs.Table11 shows the different scenarios and its serial number. Two kinds of injection are considered: wet steam injection by boiler and superheated steam injection by HTR-PM. Two kinds of pipeline are considered: overground and underground. Four kinds of oil reservoir structure are included: heat insulation tube with packer, heat insulation tube without packer, normal tube with packer, and normal tube without packer.Table 11
Different scenarios and their serial numbers.
HTR/PM
HTR-PM/underground
Boiler/overground
Boiler/underground
overground
Normal tube without packer
1
5
9
13
Heat insulation tube without packer
2
6
10
14
Normal tube with packer
3
7
11
15
Heat insulation tube with packer
4
8
12
16Figure10 shows the heat exchange of the 16 scenarios at different stages when the steam flows out of HTR-PM or boilers to oil reservoirs. The loss of heat is an average value since 30 oil wells are selected for injection and the loss of heat will be different when the steam flows to different oil wells. For the first 8 scenarios where superheated steam is provided by HTR-PM, the enthalpy of the fluid out of HTR-PM is around 3500 kJ/kg. After flowing through the main steam pipeline, the enthalpy of the fluid before entering the steam line goes down to 2800–2900 kJ/kg. Because of the loss of heat in the branch steam pipeline, the enthalpy of the fluid before the well head becomes less than 2800 kJ/kg. The heat loss in the well tube is determined by the structure of the well, where the biggest loss occurs in the normal tube without packer and the smallest loss in the heat insulation tube with packer. For the other 8 scenarios where the wet steam is provided by boiler, the enthalpy of the fluid out of boilers is less than 2400 kJ/kg. Since the fluid from the boiler does not flow through the main steam pipeline but directly flows into the branch steam pipeline, there are only three stages for the fluid provided by boiler. The features of heat loss of the fluid in the last 8 scenarios are the same as the first 8 scenarios.Figure 10
Heat of steam at different stages in the 16 scenarios.Figure11 shows the dryness of the fluid entering the oil reservoirs and the pressure change of the fluid after the steam flows through the main steam pipeline, the branch steam pipeline, and the well tube. The dryness and the pressure change are also average values since their values will be different when the steam flows to the 30 different oil wells. The dryness of the fluid entering reservoirs of scenarios 1–8 is much higher than that of scenarios 9–16. Especially for scenarios 2, 4, 6, 8 where the heat insulation tube is used, almost all oil reservoirs are injected by superheated steam (29 out of 30 wells). The pressure change of fluid of scenarios 1–8 is much higher than that of scenarios 9–16 since the fluid out of HTR-PM have to flow through an extra main steam pipeline which is several kilometers long.Figure 11
Dryness and pressure drop of injected steam in the 16 scenarios.


### 5.3. Discussion

(i)
For all 8 scenarios where the steam is provided by HTR-PM, the majority of the heat loss exists in the main steam pipeline since it is usually several kilometers long. Another reason is that the temperature of the fluid in the main steam pipeline is relatively higher than the temperature of the fluid in other stages, such in the branch steam pipeline and well tube.
(ii)
The heat loss of the fluid in scenarios 1–8 is much higher than that in scenarios 9–16. However, the heat of fluid entering the oil reservoirs in scenarios 1–8 is much higher than that in scenarios 9–16.
(iii)
In scenarios 5–8 and 13–16 where the pipeline is underground, the heat loss is less than that in scenarios 1–4 and 9–12 when the pipeline is overground. However, the difference between them is small. It shows that the underground pipeline has no obvious advantage on heat insulation over the overground pipeline under the present condition.
(iv)
From well head to oil reservoirs, the heat loss in the heat insulated well tube is much lower than that in normal tube.
(v)
The dryness of the fluid entering the oil reservoirs in scenarios 1–8 is much higher than that in scenarios 9–16. Especially in scenarios 2, 4, 6, and 8 where the insulation well tube is used, the fluid entering the majority of 30 oil reservoirs is superheated steam.
(vi)
In scenarios 1–8 where steam is provided by HTR-PM, the total flow resistance is much higher than that in scenarios 9–16 where the steam is provided by boiler. The main reason is that the fluid out of HTR-PM has to flow through an extra main steam pipeline which is several kilometers long. Another reason is that the specific volume of the fluid in scenarios 1–8 is relatively higher than that in scenarios 9–16.


## 5.1. Basic Configuration

Table8 shows the basic parameters and their values of the main steam pipeline and branch steam pipeline. There are four kinds of branch steam pipeline with different inner diameter and thickness according to their mass flow rate. According to the study, the thermal conductivity of heat barrier material is changed with the temperature of fluid [24]. When the temperature of the fluid is higher than 400°C, a linear relation is adopted in which the thermal conductivity will be increased with the rise of temperature of the fluid. Otherwise, the thermal conductivity is set as a constant. The thermal conductivity of the main steam pipeline is less than that of the branch steam pipeline.Table 8
Basic parameters of pipeline.
Parameter
Value
Roughness (mm)
0.014
Inner diameter (m)
0.4/0.3/0.2/0.1
Thickness (mm)
15/15/8/7
Thermal conductivity coefficient of heat
0.058 +t× 0.9E − 4  (t > 400°C)
barrier material (J/(m·s·K))
0.094/0.125 (t ≤ 400°C)
Thickness of heat barrier material (m)
0.13
Horizontal angle (°)
0
Position
Overground/underground
Height of bracket (m)
0.6/0.3
Cross-sectional area of bracket in thermal
0.004
sleeve (m2)Table9 shows the basic parameters and their values of oil well. Here, the values of basic parameters of all oil wells are set as the same value in order to compare the difference of heat loss, pressure change, and possible phase transformation of different designs. Actually, the values of basic parameters of different oil wells may be different to each other, such as height of well, roughness of well tube, and so forth. The effect of the joint is considered which will increase the heat loss when the well tube is the heat insulation tube.Table 9
Basic parameters of oil well.
Parameter
Value
Roughness of well tube (mm)
0.014
Inner diameter of well tube (mm)
62
Outer diameter of well tube (mm)
73
Thermal conductivity coefficient of heat barrier material (J/(m·s·K))
0.0443 +t× 1.39E − 4
Thickness of thermal sleeve (mm)
19.5
Inner blackness of cavity
0.9
Outer blackness of cavity
0.56
Inner diameter of sleeve (mm)
224.4
Outer diameter of sleeve (mm)
324.4
Thickness of concrete (mm)
30
Thermal conductivity coefficient of concrete (J/(m·s·K))
0.516
Length of each well tube (m)
10
Length of each joint (m)
0.13
Inner diameter of joint (mm)
60
Outer diameter of joint (mm)
76
Height of well (m)
759.75Table10 shows the basic parameters and their values of environment.Table 10
Parameter of environment.
Parameter
Value
Tundra exists
NO
Temperature of atmosphere and earth surface (°C)
20
Starting temperature of zone of constant
15
temperature (°C)
Starting depth of zone of constant temperature (m)
30
Temperature gradient of zone of constant
0.018
temperature (°C/m)
Wind speed of earth surface (m/s)
2
Thermal conductivity of soil except tundra
2.6528
(J/(m·s·K))
Thermal diffusivity of soil except tundra (m2/s)
9.972E − 07


## 5.2. Introduction of Result

The GIS embedded with thermal hydraulic analysis function is applied to analyze the thermal hydraulic process in the reference heavy oil field whose basic configuration is mentioned above. The heat loss, pressure change, and possible phase transformation are calculated and analyzed when the steam flows through the pipeline and is injected into oil reservoirs.Table11 shows the different scenarios and its serial number. Two kinds of injection are considered: wet steam injection by boiler and superheated steam injection by HTR-PM. Two kinds of pipeline are considered: overground and underground. Four kinds of oil reservoir structure are included: heat insulation tube with packer, heat insulation tube without packer, normal tube with packer, and normal tube without packer.Table 11
Different scenarios and their serial numbers.
HTR/PM
HTR-PM/underground
Boiler/overground
Boiler/underground
overground
Normal tube without packer
1
5
9
13
Heat insulation tube without packer
2
6
10
14
Normal tube with packer
3
7
11
15
Heat insulation tube with packer
4
8
12
16Figure10 shows the heat exchange of the 16 scenarios at different stages when the steam flows out of HTR-PM or boilers to oil reservoirs. The loss of heat is an average value since 30 oil wells are selected for injection and the loss of heat will be different when the steam flows to different oil wells. For the first 8 scenarios where superheated steam is provided by HTR-PM, the enthalpy of the fluid out of HTR-PM is around 3500 kJ/kg. After flowing through the main steam pipeline, the enthalpy of the fluid before entering the steam line goes down to 2800–2900 kJ/kg. Because of the loss of heat in the branch steam pipeline, the enthalpy of the fluid before the well head becomes less than 2800 kJ/kg. The heat loss in the well tube is determined by the structure of the well, where the biggest loss occurs in the normal tube without packer and the smallest loss in the heat insulation tube with packer. For the other 8 scenarios where the wet steam is provided by boiler, the enthalpy of the fluid out of boilers is less than 2400 kJ/kg. Since the fluid from the boiler does not flow through the main steam pipeline but directly flows into the branch steam pipeline, there are only three stages for the fluid provided by boiler. The features of heat loss of the fluid in the last 8 scenarios are the same as the first 8 scenarios.Figure 10
Heat of steam at different stages in the 16 scenarios.Figure11 shows the dryness of the fluid entering the oil reservoirs and the pressure change of the fluid after the steam flows through the main steam pipeline, the branch steam pipeline, and the well tube. The dryness and the pressure change are also average values since their values will be different when the steam flows to the 30 different oil wells. The dryness of the fluid entering reservoirs of scenarios 1–8 is much higher than that of scenarios 9–16. Especially for scenarios 2, 4, 6, 8 where the heat insulation tube is used, almost all oil reservoirs are injected by superheated steam (29 out of 30 wells). The pressure change of fluid of scenarios 1–8 is much higher than that of scenarios 9–16 since the fluid out of HTR-PM have to flow through an extra main steam pipeline which is several kilometers long.Figure 11
Dryness and pressure drop of injected steam in the 16 scenarios.


## 5.3. Discussion

(i)
For all 8 scenarios where the steam is provided by HTR-PM, the majority of the heat loss exists in the main steam pipeline since it is usually several kilometers long. Another reason is that the temperature of the fluid in the main steam pipeline is relatively higher than the temperature of the fluid in other stages, such in the branch steam pipeline and well tube.
(ii)
The heat loss of the fluid in scenarios 1–8 is much higher than that in scenarios 9–16. However, the heat of fluid entering the oil reservoirs in scenarios 1–8 is much higher than that in scenarios 9–16.
(iii)
In scenarios 5–8 and 13–16 where the pipeline is underground, the heat loss is less than that in scenarios 1–4 and 9–12 when the pipeline is overground. However, the difference between them is small. It shows that the underground pipeline has no obvious advantage on heat insulation over the overground pipeline under the present condition.
(iv)
From well head to oil reservoirs, the heat loss in the heat insulated well tube is much lower than that in normal tube.
(v)
The dryness of the fluid entering the oil reservoirs in scenarios 1–8 is much higher than that in scenarios 9–16. Especially in scenarios 2, 4, 6, and 8 where the insulation well tube is used, the fluid entering the majority of 30 oil reservoirs is superheated steam.
(vi)
In scenarios 1–8 where steam is provided by HTR-PM, the total flow resistance is much higher than that in scenarios 9–16 where the steam is provided by boiler. The main reason is that the fluid out of HTR-PM has to flow through an extra main steam pipeline which is several kilometers long. Another reason is that the specific volume of the fluid in scenarios 1–8 is relatively higher than that in scenarios 9–16.


## 6. Conclusions

In this paper, the strategy of superheated steam injection with a modified design of the secondary loop of HTR-PM is proposed for thermal recovery of heavy oil. A GIS embedded with thermal hydraulic analysis function is developed to analyze the thermal hydraulic parameters of this strategy. The present design of one single reactor of the HTR-PM can fit the need of thermal recovery of the reference oil field where around 20–40 oil wells out of several thousand wells are injected with steam at the same time. Of course, the number of reactors can be changed according to the steam requirements of other oil fields. Thermal hydraulic analysis on two kinds of pipelines and four kinds of well tubes in the reference heavy oil field shows that the strategy is applicable and promising(i)
Thermal recovery by HTR-PM is superior to that by conventional boilers since the heat and dryness of the fluid entering the oil reservoirs is much higher than that provided by conventional boilers, which can improve the quality of steam stimulation for heavy oil recovery.(ii)
The location of main pipeline (overground or underground) has no obvious influence on quality of injecting steam. However, the overground main steam pipeline is recommended on considerations of installation and maintenance.



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*Source: 676529-2012-11-22.xml*