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Open Access Original Research
Sustainability Assessment of Power Generation from an Abandoned Oil and Gas Well in Alberta, Canada

Babkir Ali *

Donadeo Innovation Centre for Engineering, Department of Mechanical Engineering, University of Alberta, Edmonton, Alberta T6G 1H9, Canada

Correspondence: Babkir Ali

Academic Editor:  Andres Navarro Flores

Special Issue: Geothermal Energy Exploration and Production

Received: May 30, 2019 | Accepted: August 7, 2019 | Published: August 7, 2019

Journal of Energy and Power Technology 2019, Volume 1, Issue 3, doi:10.21926/jept.1903002

Recommended citation: Ali B. Sustainability Assessment of Power Generation from an Abandoned Oil and Gas Well in Alberta, Canada. Journal of Energy and Power Technology 2019;1(3):16; doi:10.21926/jept.1903002.

© 2019 by the authors. This is an open access article distributed under the conditions of the Creative Commons by Attribution License, which permits unrestricted use, distribution, and reproduction in any medium or format, provided the original work is correctly cited.


The main objective of this paper is to study the sustainability of power generation from an abandoned oil and gas well in the province of Alberta, Canada. Economic and environmental indicators were used for the sustainability assessment. A conceptual design for a pilot plant was developed, and the main parameters were determined. An abandoned oil and gas well represents the thermal power source through circulating water into an organic Rankine cycle (ORC) unit to generate electricity. The thermal power is extracted through a double-pipe heat exchanger configuration installed in an abandoned well and having the benefit of the already erected casing pipe. The ORC unit is with a maximum electric power capacity of 110 kW at water flow rate 22.1 l/s, and water outlet temperature 122°C. The levelized cost of electricity (LCOE) for geothermal power generation from an abandoned well was developed at different values of water outlet temperature in the range 77°C- 122°C and the corresponding LCOE range was 0.10 $/kWh- 0.54 $/kWh. Based on the same water outlet temperature range, a shift of power generation from natural gas to an abandoned well in Alberta would mitigate a range of 8600- 14800 tonnes of CO2 annually. Reservoirs in Alberta with high temperatures more than 150°C are recommended for installation of sustainable geothermal power generation system with large-scale power capacity in megawatts. The efficient high-temperature reservoir would lead to a more feasible, sustainable, and cost-effective system output.


Organic Rankine cycle; CO2 mitigation; electricity cost; geothermal; sustainable energy

1. Introduction

Abandoned oil and gas wells in Alberta represent a substantial environmental and economic burden if not utilized. Power generation from these types of wells using clean geothermal energy can significantly shift this burden to a positive, sustainable utility. In Canada, the province of Alberta is a hub of energy production with more than 300,000 existing oil and gas wells [1]. The consequent increase in abandoned wells threatens to contaminate surrounding groundwater, and methods to alleviate this threat has consumed a significant portion of the allocated budget [2]. Use of available abandoned wells for geothermal power generation with affordable power capacities could reduce this problem [3]. Drilling is the costliest unit operation in oil-well construction. The drilling unit operation in Alberta is estimated for vertical wells at a rate of 0.86 million $ per kilometer of depth [4]. Use of abandoned wells to generate geothermal power would take advantage of previously drilled constructs by saving the drilling cost [5]. Greenhouse gas (GHG) emissions can be substantially mitigated when renewable energy replaces conventional resources, making the protection of air and climate another reason to pursue geothermal power generation.

Geothermal power generation has low GHG emissions, small land footprint, and competitive water consumption. The capacity factor (actual electrical energy output over a given period to the maximum possible electrical energy output over that period) of geothermal power generation can be over 90%, which eliminates the need for a storage device and makes it more reliable compared to solar and wind energy [6]. The main disadvantages of geothermal power generation are its low conversion efficiency, high initial cost, and the fact that the high-temperature gradient of the reservoir limits the resource. The low geothermal gradient in some regions of Alberta is the main reason this renewable energy resource is economically infeasible [4].

Power generation technology is evolving, and low-temperature applications are enhanced to widen the scope of natural resources utilization. Organic Rankine cycle (ORC) and the Kalina cycle have been introduced recently as binary cycles to improve reliability and feasibility of power generation from a low-temperature source [7]. In these technologies, an organic working fluid is used to allow the power plant operating from a low-temperature energy source. The heat content of a liquid can be extracted and transferred to the working fluid. Isobutane, isopentane, propane, RF134a, and R245fa are working fluids used for ORC and water-ammonia mixture is used for the Kalina cycle. Both ORC and Kalina cycles have the same performance at the geothermal input temperature range 110 °C – 140 °C, while Kalina cycle performs less at the temperature lower than 100 °C [8]. The kinetic energy of the working fluid would rotate the turbine and generate electricity through the generator. The generated electricity can be used within the generating facility or connected to the grid.

New enhanced low-temperature technologies can be integrated with the geothermal resources from abandoned oil and gas wells in Alberta to achieve more sustainable power generation. The existed power generation mix in Alberta represents a drastic challenge for policymakers, public, and environmentalists due to the high GHG emissions from the dominating fossil-fuel based power plants [9]. Coal and natural gas are the primary fuels used in Alberta for power generation [10], and utilization of renewable energy technologies are receiving more encourages from the provincial government to mitigate GHG emissions from this sector [11]. More than half (55%) of the total net power generation in Alberta is covered by gas-fired power plants, 39% by coal, and only 6% by renewable energy and other sources [10]. Abundant availability of coal and natural gas in Alberta are the essential reasons behind the utilization of these resources in power generation, and any new proposed technology would face a sharp competitive edge regarding economic sustainability. A policy has been proposed to reduce the GHG emissions in Alberta by phasing out all coal power plants in Alberta by 2030 and increase the renewable energy share to 30% of the total generation [9]. A new proposed power generation technology for Alberta would not win in this competition unless treated fairly by multidisciplinary views of sustainability not only within a limited economic point of view. Impacts of power generation technologies on the environment, society, and economic should be integrated to achieve a more comprehensive sustainability assessment. The existed power generation mix of the jurisdiction in question as a reference would affect the sustainability evaluation of the new proposed technology drastically, and Alberta is thirsty for utilization of more renewables such as geothermal energy extracted from available natural resources. The resources available and different technologies of geothermal power generation were intensively investigated in the literature with a marginal focus on the exploitation of abandoned oil and gas wells in Alberta using ORC and double-pipe heat exchanger. The geothermal gradients profile of Alberta was developed, and Hinton-Edson, Steen River, Fort McMurray, and Northwest corner of Alberta are areas found with the highest gradients [12]. The range of the base temperature in the sedimentary basins is 20 °C – 190 °C according to the depth and with a gradual increase from East to the West of Alberta [4]. Enhanced Geothermal System (EGS) is studied to face the needs of hot water for oil sands in Fort McMurray, Alberta [13]. Utilization of the heat source originated from abandoned oil and gas wells was investigated in the literature for regions other than Alberta. Power generation from abandoned oil and gas wells in Texas is evaluated using water as the working fluid and the wellbore as the heat exchanger [14]. Reservoir represents the primary heat source and is the determinant factor for the maximum achievable system temperature. Amount of working fluid flows through the system is another determinant factor by controlling the performance and heat output. Bu et al. [15] assessed the feasibility of hot water production and power generation from geothermal energy based on the abandoned oil and gas wells, and they found that the reservoir temperature and the fluid flow rate are of the most two critical system design parameters. Abandoned oil wells are studied to generate power and found that there is a specific optimum value for the inlet velocity of the fluid to maximize the output power [16]. A range of electricity capacity 2-3 MW is estimated for generation from abandoned oil wells in the southern part of Texas [17], and 2.9 MW of power is technically possible from shut-down petroleum wells in Arun Field, Indonesia [18]. Kujawa et al. [19] investigated the possibility of extracting heat from an operating oil well with a depth of 3950 m through a double-pipe geothermal heat exchanger. Tian et al. [20] modeled power generation from abandoned oil wells using a double-pipe heat exchanger and in-situ combustion through injecting air. The working fluid used for power generation from abandoned wells is an essential factor in the process, and Nian and Cheng [21] have established an optimal selection procedure for different types of wells. The thermal energy of an abandoned oil or gas well in the Ahwaz oil field of Iran can produce 565 m3/day of freshwater from the sea [3]. Low-temperature geothermal resources based on abandoned mines and oil and gas wells in New Zealand are investigated as the potential for heat generation [22].

The low-temperature source was intensively studied in the literature. Bao and Zhao [23] reviewed the ORC working fluid selections and the associated physical and thermodynamic properties. Quoilin et al. [24] discussed ORC applications to cover combined heat and power from biomass, solar thermal conversion, and waste heat recovery, besides geothermal resources. Methodology to estimate ORC costs is assessed by Lemmens [25], and he recommended the development of correlations and multiplication factors for more proper results. The reservoir temperature is one of the essential elements in the selection process of the ORC, and the type of application affects the initial investment cost significantly [26]. The ORC technology operation is described as the same as a steam cycle with the difference that the working fluid of water is substituted by an organic fluid [27]. The environmental impacts of the different working fluids used with ORC systems in Germany are evaluated through a full life cycle assessment [28]. Thermodynamics laws, working fluid, and costs were used as determinant factors for the optimization of power generation from geothermal with a Rankine cycle system [29].

Multidisciplinary studies of sustainability for power generation from abandoned wells integrating economic and environmental indicators are scarce in the literature. Installation of geothermal systems for power generation from abandoned wells is still under early stage of research, and practical power plants using ORC and double-pipe heat exchanger have not been developed in Alberta [4]. Earlier studies conducted for geothermal energy in Alberta focused on the availability of resources for heat applications through EGS and overlooked other power generation technologies [1,4,13]. The new ORC technology can shift the focus to power generation from low-temperature resources in Alberta. This study is intended to fill the gap in the literature by evaluating sustainability through GHG mitigation and economic impact of power generation from low-temperature resources in Alberta. The novelty of the present study is the sustainability analysis of power generation from abandoned oil and gas wells in Alberta integrating economic and environmental benefits with a specific design for a pilot plant using ORC and a double-pipe heat exchanger.

The main objectives of this study are to:

  • Develop conceptual design parameters for a pilot plant.
  • Evaluate the feasibility of a pilot plant to generate electricity from a single abandoned well in Alberta.
  • Investigate the CO2 emissions mitigated compared to the current case of Alberta.
  • Conduct sensitivity analysis for the impact on the levelized cost of electricity (LCOE) by initial and operating costs.

2. Methods

The geothermal sensible heat capacity depends mainly on the water temperature difference, water flow rate, and the heat capacity of water. The thermal output power (Pth) is given by Wight and Bennett [14] as:

$$P_{th} = ρ* Q* Cp* (T2 - T1)$$

where (ρ) is the water density, (Q) is the water volume flow rate, (Cp) is the water-specific heat capacity, (T1) is the water inlet temperature, and (T2) is the water outlet temperature.

The conversion efficiency (ηcon) is the ratio between the electrical output power (Pel) and the input power to the ORC unit (Pth):

$$η_{con} = P_{el}/P_{th}$$

The net present value (Npv) was used to estimate the levelized cost of electricity (LCOE). Initial and operating costs were brought to the present value after the summation and correction of the costs for the time value of money [30,31]:


where (Cin) is the initial cost, (OMc) is the operating cost, (f) is the inflation rate, (i) is the interest rate, (n) is the lifetime in years, and (Sval) is the scrap value.

The total energy (Pg) in kWh during the lifetime of the system was calculated as:

$$P_{g} = 8760 * (P_{el} - P_{pmp}) * CF * n$$

where: (Ppmp) is the power of water circulating pump, (8760) is the total number of hours per year and (CF) is the capacity factor.

$$P_{pmp}=\frac{ρ* g* Q* h}{ηp}$$

where: (g) is the gravitational acceleration, (h) is the total head, and (ηp) is the pump efficiency.

The levelized cost of electricity (LCOE) was estimated from Eq. (3) and Eq. (4) as:


3. Design Description

The geothermal heat source would be represented by an abandoned oil or gas well selected in Alberta for the pilot plant. A region in Alberta with a reservoir temperature higher than 100 °C is recommended to achieve better performance. A double-pipe heat exchanger (field exchanger) would be used to convey heat between the recirculating water and the organic fluid. The existed casing of the well represents the outer pipe for the system. Another smaller pipe would be inserted along with the depth of the well concentric to the casing pipe. The inner pipe of the heat exchanger would be insulated from the outer casing pipe by inserting an intermediate pipe between them to make an air gap. Clean water would be injected through the outer casing pipe to the dead center of the well, heated by the surrounding rocks, and returned to the surface through the inner pipe. The heated water would be delivered to the ORC unit to generate electricity. Complete ORC unit would be brought to the site from a commercial supplier after setting and testing the output from the thermal systems. The test would cover the optimum design parameters in the injection and production points. Optimum water temperature and flow rate would be adjusted to estimate the required size of the ORC unit. The ORC unit would be connected to the heat exchanger to generate electricity. Figure 1 shows the schematic for the proposed double-pipe heat exchanger.

Figure 1 Cross-section of a double-pipe heat exchanger for water heating.

The hot water from the double-pipe heat exchanger would be supplied to the binary cycle through a heat exchanger to heat the working fluid. The heated working fluid rotates a turbine coupled to an electric generator. The expanded working fluid from the turbine would be delivered to the condenser, and the working fluid would be changed to the liquid phase by cooling in this stage. The condenser would be air-cooled, taking the benefit of cold weather and the low ambient temperature of Alberta. The liquefied working fluid would be pumped into the heat exchanger to start a new cycle. The hot water from the abandoned well and pumped back cycle loop would be in a separate loop from the binary cycle to avoid contamination due to the direct contacts between the two different fluids. Figure 2 shows the schematic diagram for the geothermal power generation from an abandoned oil and gas well.

Figure 2 Schematic of power generation from geothermal energy extracted from an abandoned well.

4. Input Data and Assumptions

Design parameters were determined in this paper according to the specifications of the ORC unit, oil, and gas abandoned wells, and weather conditions of Alberta. Design values were assumed, and then the water outlet temperature was variated to study the effect of the different reservoir gradients on the pilot plant performance and feasibility. The water inlet temperature was selected to suit Alberta’s weather conditions. Water outlet temperature, flow rate, and electrical output were chosen to match the maximum values from the ORC unit manufacturer. Power of the water circulating pump and the overall conversion efficiency were estimated based on the system parameters. The pipes of the heat exchanger are primarily assumed to be filled with water to avoid the enormous amount of power required to circulate water from the bottom to the top surface of the well. A similar assumption is considered by Bu et al. [15] when their initial condition calculations are based on the fact that injection and extraction pipes are full of fluid. The pump is needed in this case to circulate water only around the outer loop (Loop ABCD in Figure 2). The double-pipe heat exchanger would represent a storage tank, and the hot water would be on the top due to the thermosyphon process. Table 1 shows the design parameters of the pilot plant.

Table 1 Input data for the design parameters a.

The selected ORC unit is working with a water outlet temperature range of 77 °C – 122 °C, and the hot water flow rate range 6.3 l/s – 22.1 l/s. A profile of the output electric power (in kW) over these different parameters of water outlet temperature and the flow rate is given in Figure 3. The output power at a maximum flow rate 22.1 l/s has an increasing pattern with a range between 24 kW to 110 kW with the lower bound corresponding to the lowest temperature 77 °C and upper bound at 122 °C. The minimum flow rate 6.3 l/s gives a range of 15 kW to 70 kW corresponding to the working range of water outlet temperature.

Figure 3 System performance at different parameters.

Initial and operating costs were estimated for a single abandoned well to represent a source of geothermal energy for the power generation pilot plant. The total initial cost needed to start running the pilot plant was found to be $807,000.00. The significant cost in the pilot plant is contributed by the ORC unit, which represented more than half (52%) of the total initial cost. Inner and insulation pipes needed for the double-pipe heat exchanger contributed by 37% of the total initial cost. Total annual operating expenses were estimated to cover maintenance, repair, and operation of the pilot plant and found to be 7% of the total initial cost. Utilization of abandoned borehole for space heating in Switzerland is operative since 1994 for several years with a notable performance of the field exchanger systems [32]. Le Lous et al. [33] investigated the deep borehole heat exchanger parameters, performance, and materials over an operating period of 25 years and found that thermal conductivity of the inner pipe and the fluid flow rate are the most critical design and operational parameters. An Enhanced Geothermal System (EGS) plant with an expected life of 30 years is assessed in Western Alberta to compete with the thermal energy produced from natural gas [1]. The lifetime of the system in this study is assumed 20 years based on the literature and design life of the ORC unit [34]. The heat depletion of the well over 20 years is considered negligible based on the result obtained by Bu et al. [15] that after ten years of operation, the circulated liquid temperature decreased by less than 2 °C. Table 2 gives details of initial and operating costs.

Table 2 Input data for the feasibility assessment a.

5. Results and Discussion

The levelized cost of electricity and the amount of CO2 mitigated are considered in this study to represent economic and environmental indicators for the evaluation of sustainability. The costs developed for the system is of high uncertainty due to the expected change in many of the items and assumptions made for the initial and operating costs. This change would be more evaluated through the variation of the proposed costs to reflect the sensitivity of the system through the levelized cost of electricity. The developed indicators make ease of comparisons between the proposed power generation technology and other renewable and conventional-based sources.

5.1 Feasibility Assessment

The levelized cost of electricity (LCOE) was developed based on the estimated initial and operating costs. LCOE is an indicator used for power generation comparison, and it is the factor of proportionality between the costs and the amount of electricity generated over the entire lifetime of the power plant. Initial and operating costs must be both brought to the present value to estimate LCOE, which has been widely used for the economic assessment of power generation [35,36,37]. Figure 4 shows the LCOE trend at different water outlet temperatures.

Figure 4 LCOE profile based on the water outlet temperature.

The relationship developed between LCOE with the water outlet temperature T2 is found to be:

$$LCOE = 3.06513*10^{6}* (T_{2})^{-3.59771}$$

where LCOE is in $/kWh, T2 is in °C, and the determination coefficient R2 is 99.67%.

The complete range of LCOE is 0.10 $/kWh – 0.54 $/kWh. The minimum LCOE (0.10 $/kWh) is achieved at a maximum power output (110 kW), maximum water outlet temperature (122 °C), and water flow rate of 22.1 l/s. For comparison, LCOE for wind energy is declining from 0.04 $/kWh – 0.06 $/kWh to 0.02 $/kWh – 0.04 $/kWh and solar photovoltaic from 0.10 $/kWh – 0.20 $/kWh to 0.05 $/kWh [38]. For a fair comparison, geothermal power generation has a higher capacity factor (assumed in this paper 90%) which can not be achieved by wind or solar systems alone unless storage capacity or hybrid system is used. Carbon credit may also be in favor of geothermal energy, which is not considered while estimating the LCOE in this paper. Carbon credit would be more effective for large-scale facilities in Alberta emitting more than 100,000 tonnes of CO2 per year [39], and the contribution in LCOE is marginal in such small-scale power plants.

5.2 CO2 Mitigation Assessment

Most of the thermal power needed for oil and gas processes in Alberta is based on natural gas as a fuel source. The new technology for power generation would probably compete with gas-fired power plants. An amount of 53 gCO2/MJ would be mitigated when geothermal energy is replacing natural gas [4]. This metric is used in this paper to estimate the total annual GHG mitigation due to the utilization of geothermal energy for power generation replacing natural gas. The profile of mitigated amounts over different values of water outlet temperature is shown in Figure 5.

Figure 5 Mitigated CO2 emissions profile based on the water outlet temperature.

The linear relationship developed between MTIG with the water outlet temperature T2 is found to be:

$$MTIG = 138.9612*T_{2}- 2084.4179$$

where MTIG is the mitigated emission in tonnes of CO2 per year, T2 is in °C, and the determination coefficient R2 is 100%.

A range of 8600 – 14800 tonnes of CO2 could be mitigated annually from the geothermal unit studied in this paper corresponding to the variety of water outlet temperature 77 °C – 122 °C.

5.3 Sensitivity Analysis

The total initial cost in the base case (see Table 2) was estimated at $807,000.00 and variated in the sensitivity analysis to $450,000.00 as a lower possible value to cover only the cost and transportation of the ORC unit. The impact of this lowest possible initial cost is a reduction of 20% from the minimum LCOE (from 0.10 $/kWh to 0.08 $/kWh). Profile of LCOE at different total initial costs are shown in Figure 6. Figure 7 shows the effect of the operating cost on the LCOE. The total running cost is changed in the range 0 – $56,00.00 to study its impact on the LCOE. The minimum possible LCOE is 0.05 $/kWh at the maximum performance of the ORC unit of power capacity 110 kW, water outlet temperature 122°C, flow rate 22.1 l/s, and no operating cost of the system.

Figure 6 LCOE profile at different initial costs.

Figure 7 LCOE profile at different operating costs.

6. Conclusions

Geothermal energy in Alberta is a sustainable pathway of power generation if all pillars of environmental, economic, and social impacts are integrated for the assessment. Geothermal power generation from the unit discussed in this paper could mitigate 8600 – 14800 tonnes of CO2 per year compared to a similar power generated through the natural gas pathway. The carbon credit can add more economic benefit to the utilization of large-scale geothermal power generation, and the CO2 mitigated can be translated positively into the competitiveness of this technology with the conventional fossil fuel-based power generation.

Most of the initial cost for geothermal power generation system comes from the ORC unit (52%) and the pipes used for a double-pipe heat exchanger (37%). The limited highest power capacity of the ORC unit (110 kW) made the economies of scale not favorable at higher power generation of megawatts. The utilization of more wells for higher water flow rates would not affect the feasibility of geothermal power generation drastically in this case due to the requirement of multiple numbers of ORC units to cover the total generation. The LCOE range estimated in this paper for the base case scenario (0.10 $/kWh – 0.54 $/kWh) depends mainly on the water outlet temperature. The minimum possible LCOE for geothermal power generation from a single abandoned well in Alberta was found to be 0.05 $/kWh at the maximum performance of electric power capacity 110 kW, water flow rate 22.1 l/s, water outlet temperature 122°C, and no operating cost.

The unit studied in this paper is a small-scale of 110 kW and a low-temperature of 122°C, represented a prototype to make ease of developing a large-scale unit. It is recommended to investigate in the future research a large-scale ORC unit to integrate multiple abandoned oil and gas wells in Alberta with ORC units of higher power capacity. It is recommended to install the system in a reservoir with a temperature higher than 150 °C to improve the sustainability of power generation from a larger power plant. With this high-temperature range, a large-scale power generation in megawatts can be more sustainable and compete with other well-established renewable energy sources in Alberta such as wind energy. Economic and environmental pillars represented by LCOE and mitigated CO2 are covered in this study and life cycle analysis is recommended for the future research work to integrate other sustainability pillars such as land and water footprints of power generation from abandoned wells in Alberta.

Author Contributions

The author has completed all the work.

Competing Interests

The author has declared that no competing interests exist.


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