Balancing supply and demand with energy storage and renewable energy

A large number of interconnected, intermittent generation sources operating over a large spatial scale may effectively smooth out the variability between individual generation sources. But, still variation will occur in output in the short and longer term.

Coupling intermittent renewable sources to a number of electricity production and storage sources could be used to meet the energy demand of a given facility or community, known as a hybrid power system. The power sources used depends upon the local geographical and temporal constraints, and can be used to meet demand from remote applications such as communication stations, military installations and rural villages. Full renewable power hybrid systems are in operation and have been mainly applied to remote hybrid systems in China. One of the most cost effective hybrid systems for a microgrid, a small-scale grid, is a photovoltaic array and a micro hydro turbine.

Therefore, more or less electricity is generated than meets demand. Excess electricity can be exported; dumped; stored as another form of energy and/or other electricity sources feeding into the grid can be modified accordingly. An electricity deficit can be met by electricity imports, ramping up or turning on of other electricity generating sources (backup power); and use of stored energy. Another option is to use demand management to balance supply and demand imbalances.

Storage is one of the more expensive options to balance supply and demand, but is increasingly more attractive in order to meet high renewable energy penetration targets. Another way countries are balancing their energy generation and consumption is by expanding the reach of their networks through imports and exports.

The potential for exporting and importing electricity depends upon the grid infrastructure, interconnections with other grids and the ability for the importers to absorb surplus electricity generated and exporters to meet any shortfalls in the importers electricity demand. For example, excess electricity generated from wind turbines in Denmark is exported to Norway, Sweden and Germany through grid interconnections.

In Norway and Sweden, the imported electricity is absorbed by reducing output from the countries’ hydro power plants or by using the electricity to pump water to higher elevations in a pumped storage plant. Electricity is also exported from Denmark to Germany. Although, with the expansion of wind power in Germany, it is unlikely that electricity will continue to be imported and exported in roughly equal quantities between the two countries.

Cost-benefit of carbon capture and storage (CCS)

As there are only a handful of small scale projects in operation, it is difficult to assess the cost-benefits of carbon capture and storage. Projections indicate that there is a clear cost-benefit for CCS and funding for projects could come through a levy on coal fuelled power plants. The Pew Centre on Global Climate Change in 2008 estimated that the construction of thirty 400 MW coal CCS plants at US $ 30.1 billion would save US $ 80 to US $ 100 billion by 2030 in abatement costs. In the same year, the European ‘Impact Assessment of the Geological Storage of CO2’ report estimates that building ten 400 MW coal CCS power plants would cost € 9 billion and would save € 60 billion in carbon abatement costs in the next twenty years.

McKinsey estimates that the lifetime costs for the first twelve commercial-scale coal CCS plants will be in the region of € 5 to € 13 billion. Considerably less than the estimated costs of for the EU to meet is renewable energy targets. For the UK, likely to be a major market for CCS technology, costs for CCS for coal are estimated to range from € 60 to € 90 per tonne of CO2 abated for the first commissioned plants, i.e. before 2015. Then, after 2020, costs for CCS are expected to fall to € 35 to € 50 per tonne of CO2 abated. Favorable compared to the abatement costs for renewables that are estimated to currently range from € 95 to € 205 per tonne of CO2 in the UK.

Support and prospects for carbon capture and storage (CCS)

Support for CCS is available worldwide, but with most focus on the EU, USA, Canada, China, Japan and Australia. Each region is focusing on a similar range of technologies and it is still too early days to determine which technology will come out on top.

The UN estimates through its BLUE roadmap scenario that US $130 billion will be needed over the next ten years in order to commission 100 demonstration projects, and a total of US $ 6 trillion between now and 2050 to get over 3,000 CCS projects off the ground.

Ocean Vessel Categories

Cape Vessels

Carrying Capacity: 140,000-170,000 t.

Common Use: Coal and iron ore. Not economical for fertilizer and grain.

Cape vessels are too large for the Panama Canal and many fertilizer/grain berths. When the demand for Cape vessels surged and then fell off, its affect on the freight market spilled over to vessels used for fertilizer and grain. A Cape vessel can replace two Panamax vessels.

Panamax Vessels

Carrying Capacity: 60,000-80,000 t. Built to the Panama Canal’s maximum dimensions. Common use: Coal, iron ore, fertilizer, grain and other bulk commodities.

Panamax vessels have a maximum width of 32.3 meters (105 feet). To sail through the Panama Canal, they can only load to a maximum draft of 39.5 feet tropical fresh water. They are customarily used in deep draft ports like those in China.

HandyMax Vessels

Carrying Capacity: 40,000-52,000 t.

Common use: Coal, iron ore, fertilizer, grain, steel slabs and other bulk commodities.

HandyMax vessels are similar to other vessels, but designed for smaller loads and ports like those in Brazil where there are restrictions on length, draft and storage.

Global bulk trade is measured in ‘tonne-miles’, which are equal to shipping one tonne of product one mile. For example, shipping ten tonnes of potash 3,000 miles would require 30,000 tonne-miles. Vessel space is bought and sold like other bulk commodities and when demand exceeds supply the price goes up. Ocean freight rates, like other commodities, are affected by a number of intangibles.

Fleet Size

The fleet size rises and falls as older vessels are scrapped and new ships are launched. In 2004, total fleet size was 327 million (mn) dwt, scheduled to increase with new capacity to 391 mn dwt by the end of 2007, with the addition of 40 mn dwt of capsize, 16 mn dwt of Panamax and 17 mn dwt of HandyMax

Smart Grid Cyber Security

One of the biggest concerns for smart grid developers is cyber security due to the reliance on IT communication networks. While the current grid is not immune to energy theft, fraud and malicious cyber attacks, the smart grid poses new security issues. It is more likely now that theft, malicious attack and fraud will be committed by people working remotely from a laptop several miles away, even in a different country, than someone physically manipulating meters. This makes it difficult to predict where attacks will come from.

Since the grid was first implemented in the US residents have stolen energy through various methods such as bypassing meters, using strong permanent magnets to slow meters down and inverting meters for a few days so that they run backwards. Committing malicious disruptions to the grid is relatively easy. Many substations in the US and the rest of the world are not well guarded and a man with a gun could easily fire several shots and bring the grid to a standstill. On a par with a tree fall or bad weather conditions causing disruptions to the grid system.

Several attacks on energy assets have been reported in recent years. Already there have been reported attacks on the US grid system from China and Russia, with the US Intelligence service rather than the utilities discovering most of the attacks. One major issue for the prosecution of cyber attacks is that the perpetrators of the crime may be located in a different country to where the attack occurred.

Nuclear power in Indonesia

Indonesia has the fourth largest population in the world and it is rising rapidly. Energy reserves are large, although oil is now depleting. Oil production has decreased steadily during the last decade, due to disappointing exploration and declining production in the large, mature oil fields. The country became a net importer of oil in 2004. Indonesia has the tenth largest natural gas reserves in the world and is the seventh largest exporter. There are large coal reserves, of which 85% is lignite and sub-bituminous and in 2004 Indonesia became the world’s second largest exporter.

It is difficult for Indonesia to maintain economic growth in line with the rising population and ever increasing demands for improved living standards. The income from energy exports is quickly consumed. The government is considering the nuclear option.

There are three research reactors in operation.

There have been several recent nuclear initiatives in Indonesia.

Indonesia is in the ‘Pacific Rim of Fire’, a highly unstable seismic region with a number of active volcanoes. A study has been conducted for the construction of a 7,000 MW nuclear plant in Java but this was shelved. Another 1,000 MW plant is under study and if approved could start operation by 2025. The project may be constructed by an IPP.

A potential timeline has been proposed for a nuclear power plant in Muria. A call for tenders for two 1,000 MW units was expected in 2010 followed by commissioning of the plants in 2016 and 2017. Units 3 and 4 of the Murcia plant are expected to be operational in 2023, following a tender in 2016.

In 2007 the PT Medco Energi Internasional (Indonesia) signed a memorandum of understanding with the Korea Electric Power Corporation and Korea Hydro and Nuclear Power Company (KHNP) to determine the feasibility of constructing two 1,000 MW units within the country for USD 3 billion. Therefore Korean involvement in nuclear power projects seems likely.

Shale Oil developments in the 2000s

In 2004 the Bureau of Land Management (BLM) formulated a Research, Development, and Demonstration (RD&D) Lease programme for the development of the country’s oil shale resources. This was supported in the 2005 Energy Policy Act and in 2005 nominations were solicited for 160 acre (65 hectare) tracts of public oil shale lands in Colorado and Wyoming. Out of twenty proposals received and evaluated by an interdisciplinary team including the Department of Energy and Department of Defense, five leases for projects using in situ technology were granted for Colorado to AMSO, Chevron and Shell and one lease for an ex situ project in Utah to OSEC. Once the projects have completed a successful demonstration, the lease size could be extended from 160 acres (65 hectares) to 4,960 acres (2,007 hectares).

In 2008 the land use plans were amended to make public land available for oil shale development and acreage in Utah for oil sand leases. Included in this were regulations that set the royalty rate for oil shale at 5% for the first 5 years then 1% every year to 12.5%.

Awardees for second round of 10 year RD&D leases for public lands in Colorado, Utah and Wyoming were announced in 2010: two in Colorado (ExxonMobil and Natural Soda Holdings Inc (NSHI)) and one in Utah (AuraSource). As with the first round, each lease covers 160 acres. These leases may be preferentially expanded by an additional 480 acres (194 hectares). Rules on water and energy use and other impacts for the projects have been tightened, with the inclusion more factors such as the timing infrastructure.

In 2011 the US and Estonia signed an Oil Shale Research Cooperation Memorandum of Understanding (MoU) for exchange of information on oil shale exploration and use.

Many US companies have been developing oil shale extraction technologies. An Oil Shale Alliance was set up between three oil shale technology companies:

  • Independent Energy Partners: heat oil shale using electricity generated from solid oxide fuel cells;
  • Petro Probe: heat oil shale with injected hot gas;
  • Phoenix Wyoming: heat oil shale in situ using microwave generators in boreholes.

Although, it appears that this organisation may have been disbanded.

Carbon emissions from unconventional gas

The carbon footprint of shale gas is not yet known and is thought to be highly variable depending upon:

  • Extraction process used;
  • Emission management;
  • Number of bore holes drilled to extract the gas;
  • Extent of hydraulic fracturing;
  • Extent of fugitive emissions of methane released as part of the fracturing process.

Where shale gas has displaced imports of natural gas, the estimated carbon footprint for transportation of the imported gas needs to be factored into account. It is expected that conventional gas production will have a lower carbon footprint than shale gas not including transportation to market.

In reality the term greenhouse gas emissions should be used instead of carbon emissions because of the potential leakages of methane gas during shale gas extraction. According to the International Panel on Climate Change (IPCC) methane is 72 times more power as a greenhouse gas during the first 20 years after its release than CO2. Therefore small leakage of methane can have a considerable effect.

Multi-pad drilling may reduce greenhouse gas emissions for shale gas drilling compared to drilling multiple single wells. The high efficiency of gas gathering and production facilities used in multi-pad drilling may make the CO2 emissions reduction more considerable. Furthermore, multi-pad drilling has a lower surface impact he the drilling of numerous wells.

Still little is known about the lifecycle emissions for shale gas, or coal or gas for that matter. What is known is that the carbon emissions for coal-fired power plants are considerable higher than that for gas-fired power plant on a like-for-like basis. Gas produced 45% less greenhouse gases and fewer particulates than oil or coal-fired power stations. But this does not include the carbon impact of mining the coal or producing the gas or the carbon footprint of transportation. Research conducted at the Cornell Institute suggests that when the entire lifecycle is taken into account natural gas may have higher lifecycle emissions than coal. This study is not backed up by extensive studies in the field.