Unconventional Gas

In recent years there has been an increase in unconventional gas production, specifically shale gas in North America to increase the country’s self-sufficiency in energy resources. The definition of unconventional gas as given by Law and Curtis in 2002 as ‘Conventional gas resources are buoyancy-driven deposits, occurring as discrete accumulations in structural and stratigraphic traps, whereas unconventional gas resources are generally not buoyancy-driven accumulations. They are regionally pervasive accumulations, most commonly independent of structural and stratigraphic traps’. Here unconventional gas refers to tight gas, coal bed methane, shale gas and methane hydrates. These are part of a category of frontier and unconventional oil and gas that have been attracting attention recently as conventional resources are becoming exhausted or inaccessible to non-state energy companies’. Frontier resources refer to conventional reserves in challenging locations such as extremely deep, cold and/or very inaccessible regions or are gas deposits which contain acid or sour gas.

The unconventional resources referred to here are nothing new and have been known about for hundreds of years, but have only recently become economically viable and is still not competitive with competitive gas, unless transportation costs are considered.

Coal bed methane (CBM) is methane trapped in coal deposits and is also known as coal seam gas. Most of the methane is adsorbed to the surface.

Tight gas is trapped in ultra-compact reservoirs with a very low porosity and permeability. Therefore, unlike conventional gas, tight gas can’t flow freely.

Shale gas is gas in the ‘source rock’, a clay-rich sedimentary rock with a low permeability, and is either adsorbed in the shale or in a free space in pores of the rock.

What is a source rock?

‘The source rock is the geological layer in which oil and gas are generated. It formed when organic-rich sediments were deposited on the bottom of oceans or lakes, then gradually covered over by additional sediment layers. As they became more deeply buried, the sediments were consolidated into rock, and the organic matter was transformed into oil and gas (oil and natural gas). The oil and gas tended to migrate upward through the pores and cracks of the surrounding rock, sometimes reaching the surface, but some of them were trapped under an impermeable rock barrier and collected beneath this “cap.” With time, the accumulation developed into a petroleum reservoir, the target of conventional oil and gas exploration.

In the case of gas shale, some or all of the gas released during the transformation of the biomatter stayed in place. To be a candidate for gas extraction, source rocks must have reached sufficient maturity to generate the gas, without yet having expelled it’.

Hydraulic fracturing or ‘fracking’

Productive zones are within the well are then isolated for fracturing where water and chemicals are injected under high pressure into the wells to fracture the rock. ‘Proppants’, usually sand or ceramics, in the injected water solution hold the fracture crack open to prevent their ‘healing’ and allow the continued release of natural gas. This gas is in two forms: ‘free gas’ which is released first and ‘adsorbed gas’ on the surface of organic matter, which is released when the pressure in the well drops.

The solution injected into the well also contains a very small quantity of additives such as gelling agents to cause the rock to crack, biocides to kill contaminating micro-organisms and surfactants to sterilise the well. Additives are also use to increase the efficiency of the process. Typically, these additives comprise of around 0.5% of the total injection volume. The composition of additives used depends upon the conditions of the well such as pressure, temperature and also the quantity of proppant used.

Total estimates for its operations an average of 30 ‘fracs’ are performed for each 1,000 metre well and each ‘frac’ uses 300 m3 of water, 30 tonnes of sand and 0.5% additives in the solution mixture. Therefore, the process is very water intensive, which is a big issue for water-stressed states where gas shale plays are located such as Texas. This water needs to be extracted from aquifers or trucked in to the site on access roads.

The initial production (IP) from the wells is high but tails off rapidly compared to conventional wells. This rate of decline typically follows a hyperbolic curve, as shown below for the Marcellus shale play. Therefore, a larger number of wells and repeated high-pressure fracturing is needed to maintain production compared to a conventional well. The recovery factor for unconventional wells is usually in the 5% to 40% range due to low permeability compared to above 90% for conventional wells.

Chinese Carbon Capture and Storage (CCS)

Chinese development of CCS project was spurred in 2005 through the formation of GreenGen, mentioned later, and the EU-China Near Zero Emissions Coal (NZEC) agreement. The latter was formed with the aim of demonstrating advanced, near zero emissions coal technology through carbon capture and storage (CCS) in China and the EU by 2020. To support this, a UK-China bilateral NZEC initiative was formed with an ambitious three phase process with the intention of commissioning a demonstration plant in 2014. Project players include nine Chinese partners (GreenGen, IET, THCEC, DTE, DCE, ZJU, NCEPU, WHU and TPRI) and four UK partners (IMP, DB, Alstom and Shell).

Shareholders from the energy sector including five power companies, two coal production companies and one investment company set up GreenGen, to promote high efficiency, low environmental emission plants. The group is developing a pilot IGCC demonstration project in the Tianjin Binhai New Development Zone. Many are also collaborating with international players to develop CCS such as the Huadian group and Duke Energy.

It is estimated that CO2 could be used to simultaneously recover more than 40 million barrels of oil and more than 12 gigatonnes of CO2 could be stored. The two sites with the most potential for both oil recovery and CO2 storage are Bohaiwan and Songlio of 18 billion barrels and 9 billion barrels respectively, and a storage potential of 5.4 gigatonnes and 2.4 gigatonnes.

For 90% of large stationary emitters it is estimated that a storage option is within 100 miles and for 85% within 50 miles. This includes 2,300 gigatonnes of onshore CO2 storage capacity in deep saline formations (2,290 gigatonnes), coal seams (12 gigatonnes), oil fields (4.6 gigatonnes) and gas fields (4.3 gigatonnes), and 780 gigatonnes of offshore storage.

However, re-combustion capture and the use of oxyfuels have the most potential due to their expected lower capital costs, levelised. CO2 could also be used for energy intensive industries such as iron and steel, ammonia, cement and ethylene production. The Chinese government is expected to introduce a target to reduce the country’s energy intensity by 20% in its eleventh five year plan. This roughly equates to a 306 mega tonne reduction in CO2 emissions.

Energy Storage in the US

Pumped storage is the main storage technology used in the US. The 1970s saw a large rollout of pumped hydro plants which were economically viable due to high oil prices, and high cost of intermediate load and peak energy. Costs for pumped hydro plants in the late 70s were estimated to be in the range of USD 110 to 280 per kW compared to USD 175 to 275 for natural gas combined-cycle generators of a similar capacity. In addition, the use of oil and gas fuel was restricted in new power plants under the ‘Powerplant and Industrial Fuel Use Act’. Therefore, there was sufficient base load capacity, but limit load-following and ‘peaking’ power plants.

Then low gas prices in the 1980s, improvements in gas turbine technology and the repeal of the ‘Powerplant and Industrial Fuel Use Act’ resulted in a move away from the construction of new pumped hydro and towards load following and peaking gas plants.

Currently the US has around 21 GW of pumped storage capacity. By 2025 it is estimated that an additional 10 GW of pumped storage capacity could be developed.

In recent years there has been an increase in new pumped storage projects and refurbishment of existing capacity. In order to meet state renewable portfolio standards (RPS) for grid-connected intermittent renewable capacity, storage capacity needs to be added to the electric grid.

The number of licences awarded for hydro projects have down in recent years, although many have an expiration date a long time in the future. During the first three quarters of 2010, ten hydroelectric projects have been granted a license and one hundred and four projects are pending pre-permits from FERC including seven pumped storage projects. Many of these projects may not come to fruition and not all projects need FERC approval to go ahead, and the majority are likely to be a relicensed project

Natural Gas Producers

There is a vast disparity in the volume of energy produced and consumed in the various regions of the world. The United States and Russia are the two giants of the natural gas world, being the highest and second highest producers and consumers in the world. The USA is the largest consumer and producer of natural gas, while Russia is the second largest consumer and producer. While exports in North America remain in that continent, primarily consisting of Canadian exports to the US, Russia is the largest exporter of natural gas in the world.

In the past year the natural gas market has been affected by the earthquake and tsunami in Japan creating an unexpected increase in demand and the Arab Spring reducing natural gas supplies. Demand may be reduced if a double dip recession occurs across the Euro zone and if current uncertainty remains. The current Iran-Israel conflict may escalate to cause conflict in the region. Israel has a nuclear missile that could potentially be used to know out Iran’s contentious nuclear facilities. If fighting between the two countries commences, Israel’s jets would have to be fuelled mid-air with the help of the UK or USA, brining more countries into the potential conflict. Although, whether the situation escalates to this level seems unlikely given the financial burden to the west of the Afghanistan and Iraq wars and current economic climate.

The US and Russia are the two biggest producers of natural gas collectively accounting for 37% of production in 2010. They are also the two biggest consumers of natural gas. However, the US has been increasing importing natural gas to meet demand and Russia is a net exporter of natural gas. In fact the US is the biggest importer worldwide followed by Japan and Germany. Production of natural gas is not expected to be constrained in the future, especially with recent shale gas discoveries in the USA and elsewhere. However, Russia has shut off gas supplies during conflicts with former USSR countries.

The United Kingdom Shale Gas Market (Historical Report Series)

The UK is a net importer of natural gas and has been a net importer since the 1970s. The only exception was a period in the mid 1990s to mid 2000s when production overtook consumption and new natural gas discoveries were reported. Since then natural gas production has been falling dramatically along with natural gas reserves. The R/P ratio for gas reserves in the UK is reported as 4.9 years.

In 2009 natural gas accounted for 47% of consumption as natural gas been increasingly part of the energy mix. The replacement of coal-fired plants with natural gas has resulted in 38% of primary energy consumption from natural gas.

LNG counts for a quarter of imported gas, and Norweigan imports for over half of all imports.

These imports could potentially be replaced by domestic unconventional gas production including shale gas. The Department of Energy and Climate Change has identified the best onshore shale resources as the Upper Bowland Shale of the Pennine Basin, the Kimmeridge Clay of the Weald Basin and the Lias of the Weald Basin. Many of these sites are located near well-protected beauty spots which makes gaining approval for shale gas projects extremely challenging.

Development of shale gas has been slow. Only three onshore oil and gas licences were awarded to shale gas projects in the 13th Round of Onshore Oil and gas licensing in 2008. The furthest along is the Preese Hall site owned by Cuadrilla Resources, where one exploration well has been drilled.

iGas Energy is the main developer of unconventional gas resources and has identified potential shale and coal bed methane resources in the UK. In 2005 its subsidiary, IGL, entered into a joint venture agreement with Nexen in Canada, which has experience developing coal bed methane. Based on the country’s current projects, NRG Expert expects that coal bed methane will be the company’s main focus for the foreseeable future.

Canadian Oil

Using the traditional method of calculation of conventional oil reserves, the world total is 1,333 billion barrels, of which 56.6% are situated in the Middle East, 14.9% in Latin America, 10.3% in Europe and Central Asia, 5.5% in North America, 9.6% in Africa and 3.2% in Asia Pacific. If oil sands are included, on a country by country basis, Saudi has the most reserves measured at 265 billion barrels at the end of 2009, then Canada at 176 billion barrels and Venezuela at 172 billion barrels. Canadian oil reserves are estimated as 143 billion barrels, which is more than the total oil reserves of fourth placed Iran (138 billion barrels) and fifth placed Iraq (115 billion barrels).

The National Energy Board (NEB) distinguishes between two types of non-conventional oil obtained from deposits of Canadian oil sands.

Bitumen (also known as crude bitumen) – ‘a highly viscous mixture, mainly of hydrocarbons heavier than pentanes. In its natural state, it is not usually recoverable at a commercial rate through a well’.

Upgraded Crude Oil (also known as synthetic crude) – ‘a mixture of hydrocarbons similar to light crude oil derived by upgrading oil sands bitumen’.

Canada’s ‘discovered recoverable resources’ of oil sands bitumen are quoted by the NEB as 49 billion m3 (over 300 billion barrels). Of the remainder (shown as ‘proved amount in place’ in the table above), 9,650 million m3 (9 billion tonnes) consists of synthetic crude recoverable through mining projects and 38,850 million m3 (36.3 billion tonnes) consists of crude bitumen recoverable through in-situ extraction.

Within these huge resources, the ‘remaining established reserves’ at end-2009 (shown as ‘proved recoverable reserves’ above) have been assessed by the Canadian Association of Petroleum Producers (CAPP) as 8,871 million barrels of mining-integrated synthetic crude oil and 4,706 million barrels of in-situ bitumen.

Bitumen deposits are located in Lower Cretaceous sandstones and in carbonates overlaid by Lower Cretaceous sandstones. The major deposits are in three geographic and geologic regions of Alberta; Athabasca, Cold Lake and Peace River, covering a 140,200 km2 area (14 million hectares). Of which only 0.3% is producing bitumen. Reserves are expected to extend over the border into the neighbouring Saskatchewan province. One oil company, Oil Sands Quest, estimates there could be the region of 50 to 60 billion barrels of bitumen located there.

Very little extra-heavy oil is located in the reserves and is of little economic value.