Unlocking the value of the world's geothermal resources
Geothermal energy offers the compelling prospect of baseload power generation that operates continuously – regardless of weather conditions, and with negligible fuel costs and greenhouse-gas (GHG) emissions
It has the potential to help insulate energy consumers from rising oil prices and the cost of emitting GHGs. For many countries, it could also have strategic value, providing a secure source of energy.
But geothermal remains unattractive economically: investors are deterred by the large capital investments and high level of risk.
Geothermal projects centre on the exploitation of hydrothermal resources – reservoirs of naturally occurring hot water. Hydrothermal developments have tended to cling to areas of high tectonic activity, where hot-water reservoirs are abundant, naturally productive and, therefore, cheaper to exploit. The countries with the largest installed geothermal capacity – the US, Philippines, Indonesia, Japan and New Zealand – all lie on the Pacific Ring of Fire. Unfortunately, volcanoes and geysers are not usually near large population centres – and electricity markets.
A new form of geothermal exploitation
This could change with Enhanced Geothermal Systems (EGS), a new form of geothermal exploitation being tested in areas that are not hydrothermal, such as Australia and France. Unlike hydrothermal developments, EGS is an engineered reservoir system and does not require hot-water reservoirs. In its simplest form, the only requirement is a hot, dry rock to act as a crucible – such as basement rock typically found at depths greater than 3 km. Water is pumped down an injection well and heated in situ; it accesses a production well through natural or stimulated fractures and is produced to the surface, where it flashes into steam and is used to generate electricity. It is then re-injected, completing the closed-loop system.
EGS geothermal power plants have the potential to be sited closer to population centres, reducing transmission and infrastructure costs and providing developers with access to larger markets. This could transform geothermal resource exploitation into a process industry that can be adopted in many more locations than hydrothermal. Significantly, EGS could greatly benefit from existing oil and gas technology and expertise.
The fundamental structure of geothermal's project economics must change if the technology is to be widely adopted. Operating expenditure is low, but initial capital requirements are high enough to make net present value (NPV) and internal rate of return (IRR) inferior to those of rival technologies. Hydrothermal and EGS capture less than 1% of total investment in renewable technologies.
For example, a 50 megawatt (MW) hydrothermal project would yield an IRR of less than 11% and a profit-to-investment (P/I) ratio of 0.8, whereas a large oil and gas project would typically yield an IRR of almost 16% and a P/I of 1.5, according to Goldman Sachs' 170 Projects to Change the World 2007. EGS' returns are expected to be even lower than those of hydrothermal projects, at least initially.
The goal of geothermal exploration, whether for a hydrothermal or EGS development, is to identify high-temperature resources at a drillable depth, with high permeability, favourable fracture systems and sufficient water flow rates to transport the heat to the surface. As a result, site selection is critical to project economics.
However, geothermal developers face a higher degree of risk than oil operators at every step: databases with basic subsurface data that are considered a necessity by oil companies seeking exploration acreage are generally not available to the geothermal industry, according to the Geothermal Energy Association (GEA). EGS developers are also constrained by the limitations of interpretation software, which has been developed for systems that might bear hydrocarbons. In addition, while advances in thermally rated logging tools are being made, the high rock temperatures (greater than 250°C) encountered in geothermal drilling limit the use of downhole instrumentation. Detailed temperature-with-depth logging is not yet possible, making it difficult to understand the chemistry of rock/water systems in the reservoir itself.
Higher degree of risk
Given the extremely high degree of uncertainty involved in well siting and design, hydrothermal exploration success rates are around 25%, estimates the GEA. That compares with a worldwide oil wildcat success rate of 45% in 2003, according to IHS Energy, a consultancy.
To compensate for their scant understanding of the reservoir, geothermal operators must drill more exploration and appraisal wells to fill in their knowledge gaps. The key to improving the economic attractiveness of EGS lies in reducing reliance on drilling as the primary means for exploration and lowering the cost per well drilled and optimise asset productivity.
Reliance on drilling damages project economics by increasing capital expenditure (capex) – drilling accounts for 40% and 60% respectively of the capex of hydrothermal and EGS projects – and lengthens time to first steam, typically between six and eight years, reducing NPV. In addition, without a detailed reservoir model, well placement is not likely to be optimal and means the production facilities will not be the right size for the reservoir. Whether they turn out to be over-sized or under-sized, capital is wasted.
In the present operating environment, it could take at least 20 years for a prototypical 50 MW hydrothermal project to break even. EGS, with an even higher cost structure, is simply not economic at this point.
Technology can also have a significant effect on project NPV. Some of the tools being developed to improve the exploitation of oilfields may, with minimal adaption, be used to unlock value for the fledgling EGS industry. In recent years, the oil industry has expanded into heavy oil, carbonate and basement reservoirs, and ultra-deep reservoirs. Each of these segments has more in common with the challenges faced by geothermal operators than oil and gas projects have generally had in the past – providing geothermal developers with a near-term opportunity for improving their technology.
For example, as they target deeper reservoirs, oil and gas operators are becoming more frequently exposed to extreme temperatures and pressures – and difficulties with well control, logging and equipment wear and tear commonly encountered by EGS operators. Heavy-oil operators are pioneering research into high-temperature-rated instrumentation, logging, cement, artificial lift, casing and junctions for multi-lateral wells – all considered urgent priorities for EGS commercialisation.
Reducing risk and capex can be achieved by improving reservoir modelling. Carbonates and basement oil exploitation could yield useful technologies in fracture detection and mapping, and geomechanics. Enhancing understanding of the subsurface will reduce the number of wells drilled in the exploration and confirmation stages, by increasing success rates, and boost well productivity by allowing optimal well placement and improving the efficiency of water re-injection programmes in the production stage and optimally designing surface facilities for expected production rates, pressure maintenance, and scale/corrosion issues. Simply reducing the cost of each well drilled, even if the same number of wells is required, can improve lifetime NPV for a hydrothermal project by as much as 50%.
A more accurate understanding of the subsurface could also remove the convention that makes drilling a requirement for debt financing. Financiers typically require 25% of hydrothermal reserves to be proved through drilling before extending debt. If debt financing could be applied at an earlier stage of the project, this could boost NPV by up to a further 7% by reducing financing costs.
However, the greatest single influence on NPV is a commercial factor: the sale price of electricity. Following the 1997 Asian financial crisis, Indonesia compelled geothermal power producers to renegotiate electricity prices almost 50% below pre-crisis contracts. Geothermal electricity is now sold at an average of $0.045 per kilowatt hour (kWh). The hydrothermal industry instantly ground to a halt and remained paralysed until recent high oil prices and the partial removal of diesel subsidies made it more attractive.
But prices are still not high enough to trigger resurgence in exploration activity. No greenfield geothermal projects have been completed in the country since 1997. In an effort to rejuvenate the geothermal industry, the Indonesian energy ministry is considering schemes to raise the price of geothermal electricity.
In the Philippines, deregulation of the power market through the introduction of a build-operate-transfer scheme in 1990 encouraged private-sector power utilities to enter and fund hydrothermal plants. From 1990 to 1998, installed hydrothermal capacity more than doubled, from 888 MW to 1.86 gigawatts (GW). Following the crisis, the termination of high-cost independent power producers' contracts and the imposition of a royalty tax on the net proceeds from geothermal operations reduced investor interest in geothermal schemes. Only 22 MW was added to total installed hydrothermal power capacity between 1998 and 2005.
Conversely, the US' Production Tax Credit for Renewable Energy, worth $0.019/kWh, has been credited with doubling the number of announced hydrothermal projects in the US since it came into effect in 2005.
Industry players in every geothermal province expend great effort in seeking price supports, most commonly in the form of financial support at the exploration stage, support (subsidies or loans) in the development stage and tax credits or favourable purchase prices in the production stage. But the greatest degree of financial support for the geothermal industry is likely to come from the application of carbon-emissions pricing. Unburdened by fuel costs, geothermal projects enjoy lower operating costs than oil, gas, or coal-fired power plants – particularly in countries that have put a price on emitting carbon.
Geothermal projects may also gain new revenue streams through the sale of carbon-offset credits. Chevron's Darajat hydrothermal plant in West Java, Indonesia, for example, is eligible to receive 0.65m Certified Emissions Reduction credits a year.
Given the self-evident appeal of clean, renewable baseload power generation, it is important that, in parallel with technology development, a suitable regulatory environment is in place to encourage rapid commercial development. The effect of wider geothermal adoption could have a significant effect on GHG emissions and energy security. The US, for example, has the world's largest installed hydrothermal capacity, with nearly 3 GW. But, through the refinement of hydrothermal technologies, it has the potential to tap several times that figure.