Elsevier

Applied Energy

Volume 113, January 2014, Pages 524-547
Applied Energy

Hot water generation for oil sands processing from enhanced geothermal systems: Process simulation for different hydraulic fracturing scenarios

https://doi.org/10.1016/j.apenergy.2013.07.060Get rights and content

Highlights

  • Low enthalpy Enhanced Geothermal Systems (EGS) can provide hot water for oil sands processing.

  • A 5 km deep EGS can generate hot water at temperatures above 60 °C over a period of 30 years.

  • The cost is competitive as compared to the burning of natural gas.

  • The cost effective way to create an EGS in granitic basement rocks was the stimulation of complex natural fracture systems.

  • The savings in greenhouse gas emissions as compared to the burning of natural gas are enormous.

Abstract

The oil sands in northern Alberta, Canada are home to one of the largest hydrocarbon deposits on earth. Huge amounts of hot water—around 50–60 °C—are needed for the current extraction procedure and processing technology. The current practice of obtaining water from the Athabasca River and heating it by the burning of natural gas creates severe economic and environmental costs. In fact, 6% of Canada’s gas consumption is used for this purpose. As seen, the generation of huge amounts of fossil energy through oil sands extraction requires a substantial amount of fossil energy consumption (natural gas). Geothermal energy has the potential to significantly reduce natural gas consumption and greenhouse gas emissions at competitive costs.

In this paper, we investigate how and whether or not the required hot water can be generated from the granitic basement rocks beneath the oil sands mining areas near Fort (Ft.) McMurray, located in the north east of Alberta. Hydraulic fracturing and resulting reservoir scenarios were simulated for different expected conditions in the region in order to find suitable fracturing strategies and conditions for an Enhanced Geothermal System (EGS). The simulations show that suitable fracturing treatments can increase the hydraulic performance of the system and that EGS heat generation can significantly reduce the environmental impact at comparable costs associated with the current processing technology. With this effort, significant reductions in greenhouse gas emissions and natural gas consumption can be achieved.

Introduction

The oil sands of northern Alberta are Canada’s main oil reserves and one of the major oil deposits on earth. Due to the recent increase in oil prices, the production of oil from these challenging sources became economical. 20% of these oil sands are mineable from the surface whereas 80% are producible only in situ [1]. Both processes need a significant amount of water with temperatures ranging between 40 °C and 50 °C for surface mining [2] and more than 200 °C for in situ recovery (SAGD process). Currently, the water is obtained from the Athabasca River and heated up to the desired temperatures by burning huge amounts of natural gas (6% of Canada’s gas consumption [3]) creating severe greenhouse gas (GHG) emissions (8% of Canada’s greenhouse gas emissions [4]). Potential technologies to significantly reduce these GHG emissions and save natural gas resources are carbon capture and storage (CCS), nuclear power (including waste disposal) and geothermal energy [5], [6], [7]. Besides the direct heating of the water for the oil sands processing low enthalpy geothermal energy can be used for air conditioning [8] and electricity generation [9]. In this study, the feasibility of engineered geothermal energy generation to supply the oil sands mining operations in the Ft. McMurray area with the necessary hot water is investigated.

Assuming a 10 °C temperature loss at the surface from the well to the application area, hot water at a temperature of 60 °C needs to be produced at the wellhead. Additionally, the assumption of a temperature loss of another 10 °C through the production well(s) (from formation to the wellhead) and a temperature drawdown of 30 °C within a lifetime of the geothermal system over ∼30 years, leads to a formation target temperature of about 100 °C. Presented in Fig. 1, this temperature is reached at about 5 km depth near Ft. McMurray due to the low geothermal gradient of approximately 20 °C/km.

Since the sedimentary cover has only a thickness of about 400 m in this region, 4600 m of the wells need to be drilled through granitic basement rocks (Fig. 1). The granitic rocks that form the geothermal (heat) reservoir are expected to have a very low permeability and porosity. Even though natural fracture systems, which could act as fluid pathways, may be present in that region, it is crucial to enhance the permeability of the rock in order to develop a sustainable and economical geothermal system. Without this technology, no energy production would be possible. Such an artificially altered geothermal system is commonly called Enhanced Geothermal System (EGS) or Hot-Dry-Rock (HDR) system [11]. Even though mostly hot sedimentary aquifers or high temperature EGS are considered to be economical [12] the direct use of the heat for oil sands processing represents a potential economic application of low temperature EGS.

The original concept of HDR systems was introduced in the 1970s by scientists of the Los Alamos Scientific Laboratory [13]. Our conceptual model of a pilot HDR project near Ft. McMurray consists of one injection well flanked by two production wells drilled parallel to the maximum horizontal stress. All wells are deviated (or horizontal) to allow the creation of multiple fractures perpendicular to the wellpaths. Only the injection well is stimulated to create different kinds of fractures or fracture networks.

The most commonly used methods to enhance rock permeabilities are hydraulic, chemical, and thermal stimulation techniques [14], [15]. Because of its relatively low temperatures, thermal stimulation is expected to be inefficient in northern Alberta. Chemical stimulation is also not promising because of the in-reactive behavior of granites. Therefore, hydraulic stimulation seems to be the most promising technology. Hydraulic stimulation was and is used to develop HDR systems in granites worldwide with varying success—e.g. Los Alamos, Ogachi, Horijiri, Rosemanowes, Soultz, Newberry, and Cooper Basin [11].

Hydraulic stimulation treatments may be divided according to the stimulation mechanism into tensile fracturing and shear stimulation [16]. Tensile fractures develop if the bottom hole pressure overcomes the fracturing pressure of the formation. In order to achieve long term fracture conductivity during production proppants (e.g. sand) are injected into the fracture together with the fracturing fluid [15]. Shear stimulation treatments are operated below the fracturing pressure of the formation. Critically oriented natural fractures fail in shear and the natural fracture conductivity is increased by self-propping of the displaced fracture surfaces. Often the latter mechanism is assumed to be valid in EGS environments, but tensile fractures may form additionally [17].

Hydraulic stimulation techniques can also be subdivided into the three major fracturing approaches: (1) Water fracturing, (2) hybrid fracturing, and (3) conventional gel-proppant fracturing. In water fracturing, large amounts of slickwater (water and additions like friction reducers and inhibitors) are pumped into the wellbore at relatively low flow rates without proppants or with only a small amount of proppants.

Different definitions of hybrid fracturing treatments exist. They include the injection of intermediate viscosity, linear or water-based gels, or the injection of slickwater to create the fracture followed by stages of gel to transport and distribute the proppant within the fracture. The proppant concentrations pumped here are relatively low.

In conventional gel-proppant treatments, high viscosity fluids and large amounts of proppants are used.

For the conditions in northern Alberta, slickwater and hybrid fracturing treatments seem to be the most promising. The main reason for this is the low permeability of the reservoir rock and the relatively high cost of conventional treatments. Conventional gel-proppant fracturing treatments are generally more applicable for higher permeability formations; however, all three treatment approaches are simulated and compared to each other in this study.

From 2006 to 2008 a consortium of oil sands producing companies (GeoPos) started to investigate the possibilities of using geothermal energy for oil sands extraction and processing. However, the project was closed due to economic reasons and no final conclusion was given. Now the question is revisited by a German–Canadian research collaboration (Helmholtz-Alberta-Initiative). First numerical studies showed that, in general, geothermal energy systems can be created and used for the oil sands energy demand [18], [19].

In the present study, fracturing simulations, reservoir simulations, economical, and greenhouse gas emission calculations are integrated to propose the most promising stimulation and reservoir engineering approaches for conditions expected in northern Alberta. Additionally, an improved reservoir simulation including wellbore modeling and an improved fracturing simulation using the discrete fracture network (DFN) model (MSHALE software) is included. Van der Hoorn et al. [20] conducted a similar study using hydraulic fracturing treatments for two limestone EGS projects in the Netherlands.

We begin with the parameter ranges for the simulations, which are mainly based on literature data. Then the methodology is described in detail and the results of the hydraulic fracturing sensitivity analysis, the hydraulic fracturing simulations, and the reservoir simulations are described. An integrated analysis of the stimulation design, reservoir performance, economical, and environmental aspects then leads to the proposed fracturing and reservoir stimulation concepts.

Section snippets

Methodology

Since no well has been drilled below 2.4 km in the Ft. McMurray area a sensitivity analysis of the reservoir parameters was performed using the commercial discrete fracture network hydraulic fracturing simulator MSHALE [21]. Synthetic data was used to simulate as closely as possible to the original values at a given depth of the basement rock. First, the stress confinement barriers necessary to prevent severe fracture height growth was studied. Second, the influence of each reservoir parameter

Data basis

As mentioned earlier, since little information is available about Precambrian basement rocks in the region of Ft. McMurray, most of the input parameters used for the simulations were typical values for granites as derived from the literature. Other input parameters were obtained from laboratory experiments on cores from the Hunt Well near Ft. McMurray (depth = 2400 m)—the only well deeper than others drilled for oil production purposes in the upper sedimentary layers [3]. Hence, the simulated

General considerations

Since fractures develop perpendicular to σh and parallel to σH [38], hydraulic fractures will develop approximately in the NE–SW direction as inferred from the World Stress Map [26]. Because of the low natural permeability of the granite hydraulic fractures should connect the production and injection wells if the stimulation target is to create a geothermal loop. Additionally, earlier studies showed that more than one single hydraulic fracturing treatment needs to be conducted [19]; hence,

Reservoir simulator

The thermal and hydraulic behavior of the reservoir was modeled using the thermal–hydraulic (TH) finite-difference (FD) reservoir simulator CMG STARS [22]. Fractures were implemented using the single porosity approach and wells were operated at a constant injection/production rate. Wellbore heat losses were simulated without additional insulation. The reservoir model with its initial temperature distribution for an example scenario is shown in Fig. 25. The parallel wells are shown in gray (I1,

Economic analysis

The economic target is set to provide geothermal energy at the same (or lower) price as natural gas. Currently in Alberta the gas price is $3 per GJ energy [47]. Assuming a gas plant efficiency of 50%, leads to $6 per GJ as a target value.

Because of the high initial costs, geothermal energy is becoming more competitive with project lifetime. Additionally, higher gas prices and CO2 certificates would make it even more competitive to the burning of natural gas.

Costs of geothermal projects can

Savings in greenhouse gas emissions

A major environmental issue in oil sands extraction and processing is the high amount of greenhouse gas (GHG) and especially CO2 emissions resulting from the combustion of natural gas in order to heat the river water used for these processes. Therefore, we compare the greenhouse gas emissions of the combustion of natural gas with the use of thermal energy from enhanced geothermal systems (Table 14).

Howarth et al. [51] published the most comprehensive study on greenhouse gas emissions from shale

Savings in natural gas resources

The second major environmental impact is the huge amount of natural gas that is used to heat up the water for the oil sands extraction and processing. To produce 1 GJ of energy, approximately 26.1 m3 of natural gas needs to be burned [18]. Using the simulated energy extracted in 30 years by the different optimized scenarios, between approximately 406,000 and 525,000 m3 of natural gas can be saved in 30 years of operation of a 3-well EGS system in northern Alberta (Fig. 31).

Conclusions

The applicability of low enthalpy enhanced geothermal systems for the hot water supply for the oil sands processing and extraction in north eastern Alberta was evaluated. For this purpose, hydraulic fracturing treatment and thermal–hydraulic reservoir simulations were performed to compare different reservoir permeability enhancement strategies technically, economically, and environmentally for a 5 km deep granitic rocks. The fracturing simulations were performed assuming tensile failure only,

Acknowledgements

This study was conducted under the Helmholtz Alberta Initiative (HAI) project. The authors are grateful for the financial support provided from the Alberta Government through this initiative. We thank Meyer & Associates for providing the fracturing software and CMG for providing the reservoir simulator for research purpose.

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