Deliverable Wellhead Temperature—A Feasibility Study of Converting Abandoned Oil/Gas Wells to Geothermal Energy Wells

Abstract

Many oil/gas wells are abandoned or approaching their end-of-life. Converting them into geothermal wells can significantly improve the economics of oil/gas field operations and reduce carbon emissions. While such conversion has proven viable in some areas, this technology has not yet been considered in many other areas. It is highly desirable to investigate the feasibility of converting abandoned oil/gas wells into geothermal energy production wells in local geological conditions. A new mathematical model was developed in this study for analyzing the feasibility of converting oil/gas wells into geothermal wells. This model predicts the deliverable fluid temperature of a well by simulating the heat transfer from the geothermal zone through the wellbore to the surface wellhead, considering pipe and wellbore insulation. Factors affecting heat transfer efficiency were investigated with the model for a generic data set. Results indicate that without pipe insulation, the temperature of the returning fluid is very close to that of the injected fluid. The use of pipe insulation can significantly increase the temperature of the returning fluid. For a system with a thermal conductivity of insulation pipe Kp = 0.03 W/m-C, the deliverable fluid temperature can be increased from 30 °C to 124 °C. Adding an insulation cement sheath can efficiently further increase the temperature of the returning fluid. For a system with a cement thermal conductivity of 0.20 W/m-C, the deliverable fluid temperature can be further increased from 124 °C to 148 °C. Increasing the length of the horizontal wellbore in the geothermal zone from 2000 m to 8000 m can further increase the temperature of the returning fluid from 148 °C to 159 °C. Merely by increasing the vertical depth of the well from 7000 m to 7800 m, the deliverable fluid temperature can be enhanced from 148 °C to 161 °C. However, vertical depth is limited by the temperature-sensitivity of drilling technologies, such as the thermal stability of drilling fluids and downhole drilling instruments.

1. Introduction

Many oil/gas wells are abandoned or approaching their end-of-life, giving rise to the important question of how these wells may be used for economic benefit. Since some of the wells produced oil and gas at high temperatures, we can convert them into geothermal wells for district heating or power generation. If conversion is successful, the oil and gas industry can gradually transform itself into a fossil-geothermal energy industry. With increasing concerns about the contradiction between the effects of fossil energy consumption on air quality and the strong demand for energy for economic development, such conversion could cut carbon emissions for environmental benefit while promoting geothermal energy production to increase energy supply.

Several abandoned oil and gas wells were tested for geothermal energy production a decade ago [1]. Additionally, this technology has proven viable in some areas in the past five years [2,3,4,5]. However, this technology has not received attention in other areas. In 2021, the U.S. Department of Energy (DOE) selected four new projects to receive up to $8.4 million to establish new geothermal energy and heat production from abandoned oil and gas wells. This funding allowed existing well owners and operators to use their idle or unproductive wells to access otherwise untapped geothermal potential and convert oil wells into geothermal wells, supporting the nation’s goal to achieve a carbon-free grid by 2035. This conversion involves transforming suspended oil wells directly into geothermal wells. The candidate wells are no longer producing sufficient oil and, therefore, have become economically unviable, although they still produce a great deal of hot water.

Typically, in the lifetime of a well, oil production declines while water increases. The water produced from deep reservoirs is up to 90 °C at the surface. This hot water is usually reinjected into the reservoir to enhance production and maintain pressure. This means that the heat energy stored in the water is wasted. An alternative treatment is to extract the heat prior to reinjection for direct heat or electricity production. Li et al. proposed a process for extracting geothermal energy from low-permeability reservoirs [6].

New technologies have recently been developed for power generation from well fluids of relatively low temperatures [7]. In the Organic Rankine Cycle (ORC) method, the low-temperature geothermal fluid flows through the ORC unit (in which a heat exchanger transfers the heat to an internal fluid), which vaporizes due to its lower boiling point (e.g., pentafluoro propane has a boiling point of 15.3 °C). The vapors expand and drive a turbine to run a generator and produce electricity. The Climeon Heat Power 150 kW module can optimize low-temperature resources (70–120 °C). This system is flexible and easily scalable from 150 kW modules to several MWs for larger installations. This system requires a minimum of 10 to a maximum of 30 l/s flow rate. Based on the grade level of the geothermal energy resource and assessment of new technologies, the potential for converting end-of-life oil wells into geothermal wells is ranked high in most oil and gas fields. However, it is highly desirable to investigate the feasibility of converting abandoned oil and gas wells into geothermal energy production wells in local geological conditions.

The major concern with converting abandoned oil and gas wells into geothermal energy production wells is the deliverable fluid temperature at the surface wellhead. Prediction of deliverable fluid temperature should be made based on reliable mathematical modeling of heat transfer from the geothermal zone through the wellbore to the surface. Li et al. developed a closed-form mathematical model for predicting gas temperature when drilling unconventional reservoirs [8]. The model was verified by Li et al. by numerical simulation [9]. Shan et al. developed a mathematical model for predicting fluid temperature profiles in drilling gas hydrate reservoirs [10]. These two models consider annular insulation but not pipe insulation. Shan et al. presented a simplified mathematical model for heat transfer in underbalanced drilling with pipe insulation and without annular insulation [11]. Fu et al. presented a mathematical modeling of heat transfer in y-shaped well couples for developing gas hydrate reservoirs using geothermal energy [12]. The mathematical model does not consider the effects of thermal insulation on the efficiency of heat transfer.

In the present study, an analytical model was developed, considering both pipe and annular insulation, to predict the heat transfer from a horizontal wellbore in a geothermal zone through a vertical wellbore to the surface wellhead. This model was utilized to perform a feasibility study for the conversion of abandoned oil/gas wells into geothermal wells as a generic case. The effects of insulation and well depth on deliverable fluid temperature were also investigated.

2. System Description

Figure 1 is a sketch of a geothermal well converted from an oil/gas well. The vertical depth of the well is limited by drilling and completion technologies, especially drilling fluids that are subjected to thermal degradation of rheological properties due to geothermal temperature. The horizontal section is necessary to enhance heat transfer from the geothermal zone to the work fluid. Since the fluid temperature inside the pipe is lower than the fluid temperature in the annular space at the same depth, an insulation layer at the surface of the pipe is desirable to reduce heat conduction from the annular space to the pipe interior. In addition, because the temperature of the formation rock is lower than the fluid temperature in the annular space in the vertical section, an insulation cement sheath is necessary to reduce heat conduction from the annular space to the formation rock.

Assuming heat loss in the curve section of the wellbore is negligible, the fluid temperature deliverable to the surface wellhead can be analyzed by considering heat convection in the wellbore axial direction and heat conduction in the radial direction in both the vertical and horizontal sections. Since the temperatures in the annular space and pipe interior are interrelated, the temperatures of the counter-current flowing fluids in both the vertical and horizontal sections should be solved simultaneously. The differences between the horizontal counter-current flow and the vertical counter-current flow are that the cement sheath in the horizontal section, if necessary for wellbore stability reasons, does not need to have insulating properties and the geothermal gradient along the horizontal section is zero. Therefore, the heat transfer processes in both sections can be described by the same mathematical model but with different model parameter values.

3. Mathematical Model

For the wellbore configuration shown in Figure 1, where the depleted oil/gas well is converted into a geothermal production well after drilling deep into a geothermal zone, the injected water in the pipe is heated in the geothermal zone and returned to the surface through the annular space for district community heating or power generation. The feasibility of well conversion depends on the heat flow rate received at the annulus. The heat flow rate is proportional to the water flow rate and delivered water temperature. The delivered water temperature depends on the temperature of the injected water, the temperature of the geothermal zone, the heat transfer efficiency from the geothermal zone to the injected water, and the insulation performance of the pipe and the cement in the annulus. It is highly desirable to know the temperature profiles in both the annulus and pipe for identification of key factors affecting the deliverable temperature of hot water. The temperature profile of the returning fluid in the annulus can be solved mathematically together with the temperature profile inside the pipe. Heat transfer in both the vertical and horizontal sections of the wellbore can be described by the same mathematical model, with the exception that the geothermal gradient along the horizontal section is zero. The mathematical model is summarized in this section. Derivation of the model is detailed in Appendix A.

The temperature profile of the water inside the pipe (T_p) at depth/depth L is expressed as

$$T_p=C_1{\alpha }_p{e}^{r_{1}L}+C_2{\alpha }_p{e}^{r_{2}L}+GL+\frac{{\alpha }_{p}G+{\alpha }_p{\alpha }_a{T}_{\mathrm{g}0}-G\left({\alpha }_a+{\beta }_a\right)}{{\alpha }_p{\alpha }_a}$$

(1)

which shows that the water temperature increases non-linearly with length/depth L, due to the heating effect of the water in the annulus. The temperature profile in the annulus (T_a) at length/depth L takes the form of

$$T_a=C_1\left({\alpha }_p+r_1\right)e^{r_{1}L}+C_2\left({\alpha }_p+r_2\right)e^{r_{2}L}+GL+\frac{{\alpha }_{p}G+{\alpha }_p{\alpha }_a{T}_{\mathrm{g}0}-G{\beta }_a}{{\alpha }_p{\alpha }_a}$$

(2)

Which implies that the water temperature changes non-linearly with length/depth L, due to heat loss of both the injected water in the pipe and the formation rock through the annular cement sheath.

For simplicity of written equations, the coefficient groups in Equations (1) and (2) are defined as follows:

$$C_1=\frac{{\alpha }_p{\alpha }_a\left({\alpha }_p\Delta T_b-G\right)-\left[{\alpha }_p{\alpha }_a{T}_{\mathrm{p}0}-{\alpha }_p{\alpha }_a{T}_{\mathrm{g}0}-{\alpha }_{p}G+G\left({\alpha }_a+{\beta }_a\right)\right]r_2{e}^{r_2{L}_{max}}}{{\alpha }_p{}^2{\alpha }_a\left(r_1{e}^{r_1{L}_{max}}-r_2{e}^{r_2{L}_{max}}\right)}$$

(3)

$$C_2=\frac{-{\alpha }_p{\alpha }_a\left({\alpha }_p\Delta T_b-G\right)+\left[{\alpha }_p{\alpha }_a{T}_{\mathrm{p}0}-{\alpha }_p{\alpha }_a{T}_{\mathrm{g}0}-{\alpha }_{p}G+G\left({\alpha }_a+{\beta }_a\right)\right]r_2{e}^{r_2{L}_{max}}}{{\alpha }_p{}^2{\alpha }_a\left(r_1{e}^{r_1{L}_{max}}-r_2{e}^{r_2{L}_{max}}\right)}$$

(4)

$$r_1=\frac{{\alpha }_a+{\beta }_a-{\alpha }_p+\sqrt{{({\alpha }_a+{\beta }_a-{\alpha }_p)}^2+4{\alpha }_p{\alpha }_a}}{2}$$

(5)

$$r_2=\frac{{\alpha }_a+{\beta }_a-{\alpha }_p-\sqrt{{({\alpha }_a+{\beta }_a-{\alpha }_p)}^2+4{\alpha }_p{\alpha }_a}}{2}$$

(6)

where

$${\alpha }_a=\frac{\pi d_c{K}_c}{C_a{\dot{m}}_a{t}_c}$$

(7)

which represents the relative importance of heat conduction into the formation rock over heat convection in the annulus.

$${\alpha }_p=\frac{\pi d_p{K}_p}{C_p{\dot{m}}_p{t}_p}$$

(8)

which quantifies the relative importance of heat conduction to the water inside the pipe over heat convection in the pipe.

$${\beta }_a=\frac{\pi d_p{K}_p}{C_a{\dot{m}}_a{t}_p}$$

(9)

which describes the relative importance of heat conduction to the water inside the pipe over heat convection in the annulus.

In Equations (1)–(9), G is the geothermal gradient, T_g0 is the geothermal temperature at the top of the section, T_p0 is the temperature of the fluid inside the pipe at the top of the section, d_c is the inner diameter of insulation-cement sheath, K_c is the thermal conductivity of the insulation-cement, c_a is heat capacity of the fluid in the annulus, ${\dot{m}}_a$ is the mass flow rate in the annulus, t_c is the thickness of the cement sheath, d_p is the inner diameter of the pipe, K_p is the thermal conductivity of the insulation pipe, c_p is the heat capacity of the fluid inside the pipe, ${\dot{m}}_p$ is the mass flow rate in the pipe, t_p is the thickness of the pipe, and Dt_b is the difference between the temperature of the fluid in the annulus and the temperature of the fluid inside the pipe at the bottom of the section.

Since the bottom of the vertical section is the top of the horizontal section, the temperature profiles in the vertical and horizontal sections must be solved simultaneously. The following solution procedure is used in this work:

Step 1: Assume a value for the temperature difference Dt_b at the bottom of the vertical section and calculate T_p and T_a values along the length of the vertical section.

Step 2: Using zero for the temperature difference Dt_b at the bottom of the horizontal section and taking the calculated T_p-value at the bottom of the vertical section as the T_p0 for the horizontal section, calculate T_p and T_a values along the length of the horizontal section.

Step 3: Compute the difference between the calculated temperatures in the annulus and inside the pipe at the top of the horizontal section (Dt_bNew). If the absolute difference between the calculated Dt_bNew and the assumed Dt_b is less than a tolerance, the results are correct and the computation ends. If the absolute difference between the calculated Dt_bNew and the assumed Dt_b is not less than the tolerance, let Dt_b = Dt_bNew and proceed to step 1.

4. Sensitivity Analysis

Sensitivity analyses were performed with the mathematical model to predict fluid temperature profiles in both the annular space and inside the pipe with and without insulation.

Table 1. A Base Set of Model Parameter Values for a Non-Insulation Case.

Total depth (Lmax)	7000	m
Wellbore diameter (Db)	0.20	m
Inner diameter of cement sheath (dc)	0.1397	m
Outer diameter of cement sheath (Dc)	0.20	m
Outer diameter of pipe (Dp)	0.089	m
Inner diameter of pipe (dp)	0.078	m
Geothermal temperature at top of vertical section (Tg0)	20	C
Geothermal gradient (G)	0.0245	C/m
Thermal conductivity of insulation cement sheath in vertical section (Kcv)	0.5	W/m-C
Thermal conductivity of insulation cement sheath in horizontal section (Kch)	1.5	W/m-C
Thermal conductivity of pipe (Kp)	45	W/m-C
Fluid flow rate (Qp)	0.05	m3/s
Temperature of injected fluid (Tp0)	30	C
Heat capacity of injected fluid (Cp)	4184	J/kg-C
Density of injected fluid (rp)	1000	kg/m3

shows a generic data set for a non-insulation case. The thermal conductivity of the steel pipe is approximately 45 W/m-C. The thermal conductivity of the conventional cement concrete is approximately 0.5 W/m-C. For mortars with a cement-to-river-sand ratio of 1:2, their conductivity value is approximately 1.5 W/m-C.

Figure 2 presents model-calculated temperature profiles in the vertical section for the non-insulated system. It indicates that the temperature of the returning fluid in the annulus is very close to that inside the pipe. The deliverable fluid temperature is very close to the temperature of the injected fluid at the wellhead (30 °C). This is due to the heat loss, dominated by the high thermal conductivity of the steel pipe. It also shows that the temperature of the returning fluid in the annulus is lower than the geothermal temperature at depths greater than 2300 m. This is caused by the low temperature of the fluid inside the pipe. This is not a desirable situation. Figure 3 shows model-calculated temperature profiles in the horizontal section for the non-insulated system. It indicates a much lower temperature of the fluid in the annulus than the geothermal temperature, suggesting that the horizontal wellbore section is not long enough for heat transfer from the geothermal zone to the fluid.

Effect of Pipe Insulation. The thermal conductivity of pipe insulations, such as polyurethane foam, varies between 0.02 W/m-C and 0.04 W/m-C. Figure 4 provides model-calculated temperature profiles in the vertical section for a system with a thermal conductivity of insulation pipe K_p = 0.03 W/m-C. It shows that the temperature of the returning fluid in the annulus is much higher than that inside the pipe, due to the pipe insulation. The deliverable fluid temperature 124 °C, which is much higher than the injected fluid temperature of 30 °C. It also indicates that the temperature of the returning fluid in the annulus is still lower than the geothermal temperature at depths greater than 4800 m. Figure 5 presents model-calculated temperature profiles in the horizontal section for the system with pipe insulation. It again indicates a much lower temperature of the fluid in the annulus than the geothermal temperature. It again suggests that the horizontal wellbore section is not long enough for heat transfer from the geothermal zone to the fluid.

Effect of Insulation Cement. The thermal conductivity of insulation cement such as foamed concrete is between 0.10 W/m-C and 0.38 W/m-C [13]. Figure 6 provides model-calculated temperature profiles in the vertical section for a system with insulation pipe (Kp = 0.03 W/m-C) and insulation cement in the vertical section (Kpv = 0.3 W/m-C). The deliverable fluid temperature is 148 °C, which is much higher than the injected fluid temperature of 30 °C. It shows that the temperature of the returning fluid in the annulus is higher than the geothermal temperature at depths shallower than 5600 m. Figure 7 presents model-calculated temperature profiles in the horizontal section for the system with pipe insulation and insulation cement. It indicates that the temperature of the fluid in the annulus is still 30 °C lower than the geothermal temperature, suggesting that the horizontal wellbore section is not long enough for efficient heat transfer from the geothermal zone to the fluid.

Effect of Horizontal Wellbore Length. The above-described sensitivity analyses show that the horizontal wellbore section of 2000 m is inadequate for heat transfer from the geothermal zone to the fluid, even for the fully insulated system. It is necessary to increase the length of the horizontal wellbore to obtain hotter fluid. Figure 8 shows model-calculated temperature profiles in the vertical section for a system with full insulation and a horizontal wellbore of 8000 m. The deliverable fluid temperature is 159 °C, which is much higher than the injected fluid temperature of 30 °C. It indicates that the temperature of the returning fluid in the annulus is higher than the geothermal temperature at depths shallower than 6100 m. Figure 9 presents model-calculated temperature profiles in the horizontal section for the system. It implies that the temperature of the fluid in the annulus is only 19 °C lower than the geothermal temperature. However, drilling an 8000 m horizontal wellbore in a high-temperature geothermal zone could be difficult with current technology.

Effect of Vertical Well Depth.Figure 10 presents model-calculated temperature profiles in the vertical section for a fully insulated system with a horizontal wellbore length of 2000 m and vertical well depth of 7800 m. The deliverable fluid temperature is 161 °C, which is much higher than the injected fluid temperature of 30 °C. It illustrates that the annular fluid temperature also reaches 170 °C at depth 5000 m. Because the well depth of 7800 m is easy to drill, it is suggested that increasing vertical well depth is a better option than increasing horizontal wellbore length to achieve the safe fluid temperature. However, vertical depth is limited by the temperature-sensitivity of drilling technologies, such as the thermal stability of drilling fluids and downhole drilling instruments.

5. Conclusions

A new mathematical model was developed in this study for predicting the heat transfer from a geothermal zone through the wellbore to the surface wellhead, considering pipe and wellbore insulation. This model was employed to analyze the feasibility of converting oil/gas wells into geothermal wells with a generic data set. Sensitivity analysis with the model allowed us to draw the following conclusions.

• Without pipe insulation, the temperature of the returning fluid is very close to that of the injected fluid (30 °C). This is due to heat loss dominated by the high thermal conductivity of the steel pipe.
• The use of pipe insulation can significantly increase the temperature of the returning fluid. For a system with an insulation pipe thermal conductivity of K_p = 0.03 W/m-C, the deliverable fluid temperature can be increased to 124 °C, which is much higher than the injected fluid temperature of 30 °C.
• Adding an insulation cement sheath can efficiently further increase the temperature of the returning fluid. For a system with a cement thermal conductivity of 0.20 W/m-C, the deliverable fluid temperature can be further increased from 124 °C to 148 °C.
• Increasing the length of the horizontal wellbore can enhance the temperature of the returning fluid. Increasing the length of the horizontal wellbore from 2000 m to 8000 m can further increase the temperature of the returning fluid from 148 °C to 159 °C.
• Increasing the vertical depth of the well can significantly elevate the temperature of the returning fluid. Merely by increasing the vertical well depth from 7000 m to 7800 m, the deliverable fluid temperature can be enhanced from 148 °C to 161 °C. However, vertical depth is limited by the temperature-sensitivity of drilling technologies, such as the thermal stability of drilling fluids and downhole drilling instruments.