Solar assisted method for recovery of bitumen from oil sand

a, Anurag Bajpayee a, Andy Muto a, Vincent Berube b, Matteo Chiesa a,c,*

a

Department of Mechanical Engineering, Massachusetts Institute of Technology, 77 Mass. Ave, Cambridge, MA, USA

b

Department of Physics, Massachusetts Institute of Technology, 77 Mass. Ave, Cambridge, MA, USA

c

Program of Material Science, Masdar Institute of Science and Technology, Masdar, P.O. Box 54115, Abu Dhabi, United Arab Emirates

1. Introduction

The worldwide oil demand for oil has more than doubled since

1965 and has grown 20% in the last two decades alone to the current

level of 80 million barrels per day. This trend is expected to

continue with projections of 50% growth in the next 20 years

[1].

While the global oil demand continues to rise the supply from conventional

sources is declining, and the depleted reserves are not

being replaced with new discoveries

[2]. It has been reported that

the world has over twice as much supply of heavy oil and bitumen

as it does of conventional oil. Excluding oil shale deposits, it is estimated

that there exist 8–9 trillion barrels of heavy oil and bitumen,

of which 900 billion barrels are exploitable with existing technology

[3]

.

Canada alone, by some estimates, has 179 billion barrels of useful

bitumen which make it second only to Saudi Arabia in proven

oil reserves

[4,5]. The oil sands of Alberta are a huge natural resource

and with the price of oil rising to record levels, bitumen production

has increased dramatically in the past five years

[2].

Bitumen recovery from oil sands deposits involves either strip

mining the sands and extracting the oil, or pumping large quantities

of steam into the ground to extract the bitumen from the sand

which is then pumped out of the ground for upgrading. Traditionally,

the energy to produce the steam and hot water used in these

processes has come from natural gas

[6]. The use of increasingly

large amounts of gas for oil sands recovery presents a number of

economic and environmental problems. Steam generation and

upgrading processes will contribute large amounts of greenhouse

gas emissions while Canadian and regional environmental policies

seek long term reductions

[6,7]. Large planned increases in natural

gas consumption will also cause western Canada to become a net

importer of gas, with potentially serious impacts on regional natural

gas pricing and market volatility

[8]. This is likely to impact not

only the profitability of the oil sands business but also the price

and availability of natural gas in the region.

The presented work explores the feasibility and economics of

using solar radiation to power future oil sands production activities.

We propose a novel concept that utilizes solar radiation to

generate mid temperature steam for the stimulation of the formation.

The bitumen extraction method uses the thermal mass of the

oil sand formation for heat storage to allow for cyclic steam injection

during solar availability while yielding continuous bitumen

recovery. Moreover, the solar steam generation plant for bitumen

recovery produces no greenhouse gas emissions and dramatically

reduces operating costs by substituting solar energy for natural

gas as the boiler’s energy source. The following chapters describe

the proposed method and present the thermodynamic and economical

calculations that support the use of solar steam production

for bitumen recovery.

2. Energy requirements for bitumen recovery

Currently, bitumen recovery is primarily accomplished either

by surface mining followed by extraction through thermal

processing, or by in situ means such as steam-assisted gravity

drainage (SAGD)

[9,10,6]. The economics of surface recovery are

dominated by the cost of mining equipment, operations, and land

reclamation

[2]. The economics of in situ production are dominated

by the cost of natural gas used to generate steam

[6].

The use of enormous amounts of natural gas for steam generation

makes oil sands operations large single source emitters of

greenhouse gases. As concern about climate change grows and

CO

2 reduction targets come into effect; considerable reduction

in operational costs for oil sand production is required. Natural

gas production in Alberta peaked in 2001 and has been static

ever since

[11]. It is likely that its requirement in the oil sands

industry will be met by cutting back Canadian natural gas exports

to the United States or even importing natural gas from

Alaska.

SAGD is a major breakthrough in the oil sand recovery technology.

It is cheaper than similar steam-assisted production methods,

and recovers up to 60% of the available oil. The steam requirements

for SAGD fields vary significantly

[6]. The desired steam

generation pressure and temperature are affected by the geological

characteristics of the area, the distance over which the steam

must be transported, and the depth and quality of the bitumen reserve.

The steam temperature varies in the range of 250–350

.C,

while the steam pressure is limited by the fracture pressure of

the formation. Saturated steam is produced at sufficient pressure

to support control, distribution and injection processes. A typical

steam to oil ratio (SOR) measured in barrels of cold water to produce

a barrel of bitumen is between 2 and 4. The actual SOR for

any given well depends on the quality of the deposit and the specific

geology in the region

[6]. The present analysis assumes saturated

steam production at 6–10 MPa with a related SOR of 3. Thus

one barrel of bitumen is recovered for every three barrels of cold

water equivalent of steam injected. In situ SAGD recovery uses

about 1.0–1.5 Mcf of natural gas for each barrel of bitumen recovered

[12,13]

. An SOR of 3.0 corresponds to a natural gas intensity

of 1.3 Mcf/bbl.

3. Energy efficient method for the recovery of bitumen

The proposed bitumen recovery method harnesses solar radiation

to generate mid temperature steam that is used to stimulate

the formation. Solar thermal power plants employ point focusing

(solar tower) or line focusing (solar trough) systems to concentrate

sunlight as heat to generate steam which is then converted to electricity

[18]

. Line focusing systems can achieve concentrations of

70–100 times and operating temperatures in the range of 350–

550

.C. On the other hand point focusing systems use a field of distributed

mirrors called heliostats that individually track the sun

and focus the sunlight at the top of a tower concentrating the sunlight

600–1500 times and delivering temperatures of about 550

.C.

In either case the solar energy is often absorbed by a heat storage

fluid such as molten salts and then used to generate high temperature

steam for the power cycle

[14].

The proposed recovery method employs solar thermal power

technology where both the line focusing and the point focusing

techniques may be used. Unlike conventional solar thermal systems,

our method generates steam directly at mid-level temperatures

of 230–350

.C. Decreased radiation losses due to lower

temperatures at the receiver and the possibility of direct steam

generation with no intermediate heat storage fluid would enhance

the overall thermal efficiency of the system

[14]. The use of mid

temperature steam allows for the use of the proposed technology

even in locations with relatively low solar radiation such as Alberta.

This mid temperature steam generated throughout concentrating

system is injected into the oil sand formation where the

bitumen is extracted from. The required steam needed to stimulate

the formation will be injected at high rates during times of peak

solar radiation while little or no steam will be available during

nights. In a scenario of daily oil production of 10,000 barrels about

30,000 barrels of water need to be converted to steam and be injected

into the formation.

The injected thermal energy is absorbed by the formation, thus

causing the bitumen to decrease in viscosity and enabling it to be

pumped out. The formation acts as a large thermal mass with a

response time much longer than a day. Previous work on economic

implications of intermittent steam injection in the SAGD

process suggests that short term variations in steam injection

have negligible impact on formation chamber pressure and temperature

[17]

. Thus as long as enough energy is injected during

the period of solar availability the system may be operated continuously

to extract the desired daily amount of bitumen. Similarly

the larger thermal mass of the injection chamber allows

for continuous operation in the wake of seasonal changes. Work

by Birrel et al.

[17] supports the feasibility of intermittent steam

injection based on seasonal variations. It is shown for a plant that

has been in operation for one year, upon a 100% steam injection

shut-down for 60 days, the decline in daily bitumen production

is only 0.83%. For shut-down periods of 15 and 30 days, the

reductions are about 0.4% and 0.6%, respectively. Since the steam

injection is reduced (insolation values in the months of November,

December, and January are about 50%, 31%, and 47% of the

average insolation, respectively

[16]) and not completely shutdown

and since the low injection period is relatively short, the effect

on bitumen production due to seasonal variations will be

negligible.

The proposed method uses a similar well configuration as the

conventional SAGD with some variations. First, in order to account

for the variation in steam generation rates the steam injecting

well(s) allows for varying flow rates and/or has a larger flow cross

section area than that of the bitumen recovery well(s). Secondly,

the proposed configuration employs local steam injection as close

as possible to the location where the steam is generated and a centralized

oil producing facility where the oil is produced from multiple

horizontal wells. Schematics for the entire proposed system

and the upgrading processes without natural gas are depicted in

Fig. 1

.

3.1. Thermoelectric electricity generation

The energy required to inject the steam into the formation and

to recover the bitumen from the formation is a small fraction compared

to the energy necessary to generate steam. We thus propose

to generate the power necessary to run various pumping equipment

by means of Solar Thermoelectric Generators (STG). These

STG’s are installed at the solar focus point on the surface of the boiler

as illustrated in

Fig. 2. It must be reiterated that this will not

significantly affect the overall system performance as the electrical

power required here is only 5% of the total power supply. Thermoelectric

Generators are a robust, low maintenance option and are

easy to install as compared to a full blown steam turbine system

including a heat storage fluid

[15]. STG’s may also be able to utilize

other secondary sources of cold and hot fluid streams without significant

modification. Although the conversion efficiency of a solar

thermoelectric generator (STG) is relatively low compared to the

state of the art photovoltaic modules, the major advantage of using

this technology lies in the cogeneration of electric work and heat

[15]

. The STG module is directly mounted on the boiler therefore

the excess heat which is transferred through the module is used

to generate steam. The installation of an STG module represents

an additional thermal resistance between the solar radiation and

the steam. This inevitably leads to a temperature increase on the

hot side surface of the STG in order to provide the same amount

of steam at the required pressure and temperature.

4. Feasibility study for the proposed concept

Feasibility assessments of the concept from both a thermodynamic

and financial points of view are presented in the following

section for a development scenario in the Athabasca region of Alberta,

Canada.

4.1. Thermodynamic analysis

In common steam generation systems natural gas boilers are

used as the heat source. The proposed system uses concentrated

solar radiation instead to provide the required mid temperature

steam. In the SAGD bitumen recovery systems saturated steam between

60 and 100 bar is required. An oil production rate of

10,000 bpd requires that 30,000 bpd of water at 25

.C is converted

into saturated steam. At this rate production of saturated steam at

a pressure of 60 bar requires 147,632 kW

th of thermal power. If a

solar TEG module is employed the generated power yields

7,770 kW

e assuming 5% conversion efficiency for a temperature

difference of 200 K and an effective ZT

1 of 1 [15].

As argued earlier, since the effect of seasonal changes in solar

radiation is negligible, a yearly average value of insolation power

may be used for calculations. In Edmonton, the capital of the oil

sand industry in Alberta, Canada, the annual average insolation

power is reported to be 165 W/m

2 [16]. Consequently, with a collector

and receiver efficiency of 56.3% and 83.1%, respectively, Table

5.25 in

[18], 2.15 km2 of reflector area is needed to meet the

power requirements. If a NG fired boiler is replaced by the proposed

system the NG savings amount to 3.28 kg/s assuming a lower

heating value of about 50 MJ/kg and a boiler efficiency of 90%.

The energy required for the extraction of the bitumen using NG

amounts to 24.2% of the heating value of Bitumen, which is

41.8 MJ/kg

[19]. The resulting CO2 emission savings by not burning

the NG are 739 tpd using a CO

2 mass flow of 2.606 kg per kg of NG

[20]

.

4.2. Economic analysis

The current price of installing heliostats, including material and

labor costs, is estimated to be about $126/m

2 [18]. At this rate the

entire heliostat installation of 2.15 km

2 would cost about $271 M.

Other associated capital costs include those of building the structure

and its improvement, balancing of the plant, installation of

the receiver and the tower which includes piping, and installation

of the thermal storage, steam generator, electrical power generation

system (EPGS), and the master control system. The above costs

combined represent about 191% of the cost of heliostat installation

[18]

. Thus, the total capital investment amounts to a total of

$531 M. See

Table 1 for the detailed cost breakdown. The cost of

installing the thermoelectric generator module is not included in

our assessment, which focuses just on the costs related to steam

generation. Also, it is assumed that real estate costs in the Athabasca

region are negligible since the oil sands industry already owns

vast amounts of land.

To estimate the savings that the solar steam generation plant

would yield over the existing plant it is observed that the natural

gas fuel costs would be eliminated. The current natural gas

requirement is approximately 3.28 kg/s which will be saved. At

the current natural gas price of $0.60/ kg, this translates to savings

of $1.98/s or yearly savings of about $62.5 M. Further savings

would be realized in the scenario of carbon taxation; 2.606 kg of

CO

2 are emitted per kg of natural gas flow, which equals emissions

of almost 270,000 tons per year. Assuming carbon taxation of

4 cents per kg

[20], this would provide additional savings of

$10.78 M per year. Estimated savings are tabulated in

Table 2.

Given the above analyzed costs and savings and assuming an

amortization rate of 10% the return of investment (ROI) time for this

project would be about 20 years in the scenario of no carbon tax and

shortens further to 14 years if carbon taxation comes into effect.

Furthermore, Canadian tax law has provisions in effect from February

2005 that allow solar energy projects such as the proposed system

to qualify under Class 43.2 and depreciate by 50% every year.

The additional depreciation savings reduce the ROI time to 8 years,

making the project immensely attractive. A complete amortization

profile is shown in the

Appendix A. It is speculated that with further

advancements in technology, the cost of heliostats may reduce by

65%

[18]. Under such an optimistic scenario the ROI time for this

project may well reduce to between 5 and 9 years depending upon

the employment of carbon taxation and inclusion of depreciation

savings. It must be noted that the payback time calculated does

not take into account for any profits from oil sales and is thus the

payback time of any investment over and above what would already

be made to install an oil production plant.

5. Conclusion

Natural gas is currently the predominant fuel used to generate

steam, but it is rapidly becoming expensive due to short-falling supply

in North America. Alternative fuels such as coal, heavy oil, or by

products of heavy oil upgrading could be used, but simply burning

them would release large quantities of CO

2 unless capture and