Hydrogen as Energy Carrier

Hydrogen as Energy Carrier

By Jurie Steyn and Christine Render

Introduction

Although South Africa lags European countries in terms of electric vehicle (EV) deployment, there are currently well over a thousand EVs on our roads. It is expected that the rise in numbers of EVs will accelerate in the coming years. In fact, the automotive industry’s goal is for 20% of all road vehicles to be EVs by 2030 and 35% of new vehicles to be EVs (Tyilo, 2019).

EVs can certainly help reduce carbon dioxide (CO2) emissions to the atmosphere, provided that the electricity they consume comes from renewable sources, i.e. wind, solar, hydroelectric or geothermal sources. Whilst EVs are excellent for short distances, range limitations, and the time required to recharge the batteries, reduce their practicality over long distances. To overcome the problem, charging stations are being installed along major routes in South Africa (Cokayne, 2019), but even with fast chargers, it still takes approximately 72 minutes to achieve an 80% charge.

Fortunately, there are other energy carriers, such as hydrogen, which are both clean and convenient.  Hydrogen is the most abundant gas in the universe, and the source of the energy we receive from the sun. The sun is essentially a giant ball of hydrogen and helium gases. In the fusion process in the sun, hydrogen nuclei combine to form one helium atom, releasing energy as radiation. Hydrogen is found only in compound form on Earth: combined with oxygen, it is water (H2O); combined with carbon, it forms organic compounds such as natural gas, coal, and petroleum. Hydrogen is also one of the most abundant elements in the Earth’s crust. Hydrogen, like electricity, is regarded as an energy carrier, not an energy source, because hydrogen as a gas (H2) doesn’t exist naturally on Earth. It requires much energy to produce hydrogen gas, but in this form, it can deliver or store tremendous amounts of energy.

In this article, we share some thoughts about a potential future hydrogen economy, discuss the different production routes for hydrogen, consider logistic implications of hydrogen storage and distribution, and describe some of the applications of hydrogen, and particularly transport applications.

Hydrogen economy

The term ‘hydrogen economy’ describes the vision of utilising hydrogen as a low carbon alternative energy carrier to replace traditional fossil fuels for transportation and heat. When produced from renewable energy sources such as solar or wind, hydrogen has zero CO2 emissions at the point of use. Hydrogen burns readily with oxygen, releasing considerable amounts of energy as heat, and producing only water as exhaust, as illustrated by the reaction:

2 H2 + 02 ➛ 2 H20 + heat

According to Potier and Chung (2019), “[c]lean hydrogen energy – that is, hydrogen produced from renewable and low carbon sources and/or produced with a low greenhouse gas footprint – can, as part of our primary world energy mix, help us achieve the Paris [Climate] Agreement goals while creating jobs and bolstering economies”.

Toyota (2019) presented their vision of a hydrogen economy at the launch of the hydrogen-fueled Toyota Mirai, a fuel cell vehicle (FCV), in 2019. Toyota’s vision of the hydrogen economy is shown in Figure 1.

Figure 1:  Sustainable hydrogen energy based society (Toyota, 2019)

Several interesting observations can be made regarding Toyota’s vision for a hydrogen economy, namely:

  • Hydrogen, electricity and fossil fuels play an important role, although the importance of fossil fuel for transport is much smaller than at present;
  • Electricity can be used to produce hydrogen via electrolysis, and electric power can be generated from hydrogen, and other fossil fuels;
  • Motor vehicles will be electric powered (EV), electric powered with a small hydrocarbon fueled engine to charge the batteries (hybrid vehicles or HV), plug-in hybrid vehicles (PHV), or hydrogen fuel cell powered vehicles driven by electric motors (FCV);
  • Natural gas and petroleum will still be used as fuels and to feed the chemical industries, but coal does not form part of the fossil fuel mix;
  • Nuclear energy is not included in the diagram and the deduction is made that nuclear energy is not considered to be a primary energy source for the future; and
  • No mention is made of carbon capture and storage (CCS) for fuels from carbon-based (fossil) sources, although this will probably be required.

The transition to a hydrogen economy would require trillions of dollars of investment in new infrastructure to produce, transport, store and deliver hydrogen to end users. The process could take several decades, because of the slow turnover of the existing stock of capital equipment that either makes or uses energy, as well as the sheer capacity that would need to be built. A hydrogen economy can become a reality if clean hydrogen can be produced, stored and transported on a technology proven and commercially viable scale.

Hydrogen production

Opening remarks

Hydrogen can be produced from fossil fuels, biomass, water, or from a mix of these resources. The annual global dedicated hydrogen production is around 70 million tons (IEA, 2019) with the largest consumers being ammonia production at 62,4%, oil refining at 24,3% and methanol production at 8,7% (Bhandari, Trudewind, & Zap, 2012). The use of hydrogen as an energy carrier is negligible.

Hydrogen is generally produced by steam or autothermal reforming of natural gas at consumer sites where large quantities of hydrogen are required. Globally, about 68% of hydrogen production comes from natural gas, 16% from oil, 11% from coal, and only 5% from electricity (Adolf et al, 2017). It is estimated that only a small fraction of the electricity used to produce hydrogen from water is from renewable sources.

In this section we’ll discuss some options to produce hydrogen. Hydrogen production technologies are shown in Figure 2, starting with different primary energy sources, and via several energy carriers. As stated above, thermochemical processes, like steam and autothermal reforming of natural gas, predominate.

Figure 2:  Hydrogen production from different energy sources

Each of the production technologies is discussed in more detail below.

Photonic processes

Photonic processes essentially use sunlight as an energy source to split the water molecule using either photocatalytic or photo-electrochemical means. The conversion from water to hydrogen requires a flow of free electrons, generated by the light source, that acts as an electric current to split the water molecule. Photocatalysis uses a direct heterogeneous catalyst and the photo-electrochemical process employs an electrochemical cell in which at least one of the electrodes is made from photoactive material such as titanium dioxide.

Photonic processes are not yet fully developed or commercially proven.

Photolytic processes

These processes include both direct and indirect bio-photolysis, which is the production of hydrogen from water by the action of light on a biochemical compound such as green microalgae or cyanobacteria. These light-sensitive microorganisms are used as biological converters in a specially designed photo-bioreactor. The advantage of bio-photolysis is the ability to produce hydrogen from water in an aqueous environment at standard temperature and pressure.

Photolytic processes are not yet fully developed or commercially proven.

Thermolytic processes

Water thermolysis is the single step thermal dissociation of water requiring temperatures above 2000 K. At 3000K and 1 bar, the degree of dissociation is 64%. The high temperature heat can be supplied by concentrated solar power or from the waste heat of nuclear power reactions. The main challenge of this production method is the separation of hydrogen and oxygen. Membranes can potentially be used below 2500 K and require the rapid cooling of the product stream.

Thermochemical water splitting cycles uses high temperatures and chemical reactions to produce hydrogen from water. The chemicals used in the process are reused within each cycle, creating a closed loop that consumes only water and produces hydrogen and oxygen. This process route has a more reasonable temperature requirement range of 600 to 1200 K and has no need for oxygen/hydrogen separation membranes.

Electrolytic processes

Electrolysis is the process of breaking down a feedstock, in this case water, into hydrogen and oxygen by electricity. The electrolyser consists of a direct current source of electricity and two noble metal electrodes, which are separated by an electrolyte, as illustrated in Figure 3.  Also shown in Figure 3 is the reverse reaction of electrolysis, namely the hydrogen fuel cell, where hydrogen and oxygen are reacted to produce electricity.

Figure 3: Principles of the electrolysis of water and the hydrogen fuel cell (Adapted from Minnehan & Pratt, 2017)

Noble metal electrodes, typically platinum, function as a catalyst to increase current density and rate of electrolysis reactions. Electrolysis can be carried out at room temperature (conventional electrolysis), or at higher temperature (1000 K to 1300 K) where steam is initially produced and then is dissociated to hydrogen and oxygen (high temperature electrolysis). The higher temperatures result in increased efficiency of up to 80%. Also, water is converted to steam using thermal energy and hence the electrical energy need is lower than that of conventional electrolysis.

Several types of electrolysers are available and are differentiated by the specific electrolyte used, and include:

  • Alkaline electrolysers (AE);
  • Proton exchange membrane (PEM) electrolysers;
  • Solid polymer electrolyte (SPE) electrolysers;
  • Solid oxide electrolysis cells (SOEC); and
  • Anion exchange membrane (AEM) electrolysers.

Fermentation processes

Fermentation processes fall into two categories: Photo-fermentation and Dark-fermentation. Biochemical energy, which is stored in organic matter, can be used by living organisms to extract hydrogen from water in the presence or absence of light. Photo-fermentation (with light) utilises carbon substrates such as organic acids as electron donors and hence is suited for hydrogen production from waste streams containing organic acids.

Dark-fermentation (in the absence of light) produces hydrogen using anaerobic bacteria on carbohydrate-rich substrates, mainly glucose. This process is cheaper than photo-fermentation as the process does not require solar input (the bioreactors are simpler). Dark-fermentation can be integrated into wastewater treatment systems to produce hydrogen. Acetate produced in dark-fermentation can be oxidised by photosynthetic bacteria to produce more hydrogen, hence a maximum yield of hydrogen can be achieved by integrating dark- and photo-fermentation processes.

Thermochemical processes

The most established and proven processes for bulk hydrogen production entails the conversion of methane (from natural gas) to hydrogen, carbon monoxide (CO), carbon dioxide (CO2), and water vapour via reforming. Based on the nature of the oxidant used in the reforming process, three different types of reforming can be identified, namely Steam Methane Reforming (SMR), Partial Oxidation (POx) or Autothermal Reforming (ATR) .

Pure water vapour is used as the oxidant for SMR. The reaction requires the introduction of heat, often supplied from the combustion of some of the methane feed‐gas. The process typically occurs at temperatures of 700 to 900°C and pressures of 3 to 25 bar. The product gas contains approximately 12% CO, which can be further converted to CO2 and H2 through the water‐gas shift reaction. SMR is the least expensive and most used process to produce hydrogen.

Oxygen or air is used as the oxidant for POx. If ambient air is used as an oxidant, the product gas also contains nitrogen. POx of natural gas is the process whereby hydrogen is produced through the partial combustion of methane (CH4) with oxygen to yield CO and H2. In this process, heat is produced in an exothermic reaction, and hence a more compact design is possible as there is no need for any external heating of the reactor. Partial oxidation has the benefit of not requiring a catalyst and is more sulphur tolerant.

The ATR process is a combination of SMR and POx and operates with a mixture of air and water vapour as the oxidant. The ratio of the two oxidants is adjusted so that no heat needs to be introduced or discharged. The outlet temperature from the reactor is in the range of 950 to 1100 °C, and the gas pressure can be as high as 100 bar. Again, the CO produced is converted to H2 through the water‐gas shift reaction.

Effectively all carbon entering the processes, described above, gets converted to CO2. Large scale hydrogen production using these processes would therefore require the establishment of carbon capture and storage (CCS) infrastructure in order to be environmentally sustainable. CCS necessitates the proximity of suitable underground geological structures for the storage of CO2.

Gasification of coal or biomass, followed by a water-gas shift reactor to increase the hydrogen yield, is also a viable route to hydrogen. Gasification of coal results in higher CO2 emissions and would need CCS infrastructure. The raw material costs are lower for this process route, but the capital cost is higher (due to gasification and air separation capital).

Storage and distribution

Hydrogen is the lightest and simplest element in existence: a hydrogen atom contains only one proton and one electron. Hydrogen also exhibits the highest heating value per mass of all chemical fuels, and is environmentally friendly. Hydrogen is a combustible gas and can form explosive mixtures with air, although it is not explosive by itself. Its most obvious safety-related feature is its high flammability and the broad ignition limits in hydrogen-air mixtures from 4 to 77 %. If pure hydrogen is brought together with air/oxygen and an ignition source, it burns almost invisibly.

One difficulty with hydrogen as an energy carrier is its low critical temperature of 33 K (-240 ℃), i.e. hydrogen is a gas at ambient temperature. The low density of hydrogen also has an impact on its transport. Under standard conditions (1.013 bar and 0°C), hydrogen has a density of 0.0899 kg/m3. If hydrogen is compressed to 200 bar, the density at 0°C increases to 15.6 kg H2/m3, and at 500 bar it would reach 33 kg H2/m3. Finding a cost-effective solution to the hydrogen storage problem is considered by many to be the foremost challenge for the hydrogen economy.

There are a few different approaches for hydrogen transportation and storage. Hydrogen can be stored as a compressed gas in high pressure tanks, as a liquid in cryogenic tanks (at 20 K) or as a pressurised liquid at slightly higher temperatures.  These methods are established technologies with several limitations, the most important being their energy intensive character. Hydrogen can also be stored in solid state compounds such as metal hydrides. Hydrogen storage in metal hydrides is considered one of the most attractive methods because metal hydrides contain the highest volumetric density of hydrogen. Hydrides reduce the risk factors of gaseous or liquid hydrogen. The metal hydrides also provide a safe method for fuel storage in hydrogen-powered vehicles. Light metals (Li, Mg, B, Al) can combine with hydrogen to form a large variety of metal-hydrogen complexes. LiBH4 is a complex hydride which consists of 18% mass of hydrogen.

Today, the transport of compressed gaseous or liquid hydrogen by lorry and of compressed gaseous hydrogen by pipeline to selected locations are the main transport options used commercially. A pipeline network could be the best option for large scale use of hydrogen, but requires a high level of initial investment. Local, regional and transregional networks are a possibility. Worldwide there are already more than 4500 km of hydrogen pipelines.

Blending hydrogen into natural gas pipeline networks has also been proposed as a means of delivering pure hydrogen to markets, using separation and purification technologies downstream to extract hydrogen close to the point of end use.

Applications of hydrogen

Opening remarks

Present and potential future applications of hydrogen can be grouped in three main categories as illustrated in Figure 4, namely:

  • Power and heat generation;
  • Industry feedstock; and
  • Passenger/goods transport.

Each of these is discussed in more detail below.

Figure 4:  Present and future hydrogen applications

Power & heat generation

In power generation, hydrogen is one of the leading options for storing renewable energy, and can help to buffer electricity networks which depend on renewable energy. When additional electric power is required, hydrogen can be converted to electricity by fuel cell, or by using gas fired engines for power generation. Power so produced can be fed to the power grid.

Hydrogen can be used in its pure form or blended in with natural gas. Blending it in with natural gas has the advantage that existing gas pipeline networks can be used to transport the hydrogen. Pure or blended hydrogen can be used in buildings and in industry for heat and power generation, with the highest potential in multifamily and commercial buildings. Longer-term prospects could include the direct use of hydrogen in hydrogen boilers or fuel cells, provided a pure hydrogen pipeline is available.

Industry feedstock

Hydrogen is predominantly used today as a feedstock in industrial applications like ammonia production, steel production, synthesis gas for fuel production, methanol production and for hydrocracking and hydrogenation processes in oil refining. Currently, most, if not all, of this hydrogen is supplied using fossil fuels, so there is significant potential for emissions reductions from clean hydrogen.

Various industrial gases play a vital role in producing high quality flat glass. The most common are hydrogen and nitrogen for the tin bath and oxygen in case of oxy-fired furnaces. Currently, these gases are mainly supplied by electrolysis or road transportation of compressed or liquefied gas.

Passenger/goods transport

In transport, the competitiveness of hydrogen as a fuel depends on the cost of fuel cells and refuelling stations. Hydrogen fuel cell forklifts have been in operation for years and significant progress has been made with hydrogen fuel cell vehicles, trucks, trains and buses. Some countries successfully operate fleets of hydrogen powered buses for public transport. Unlike more common battery-powered electric vehicles, fuel cell vehicles don’t need to be plugged in, and current models easily exceed 450 km on a full tank. They’re filled up with a nozzle almost as quickly as traditional petrol and diesel vehicles. While Honda, Hyundai and Toyota remain committed to hydrogen fuel cell vehicles, Elon Musk, CEO of Tesla, dismisses hydrogen fuel cells as “mind-bogglingly stupid” (D’Allegro, 2019).

Minnehan and Pratt (2017) completed a study into the viability of hydrogen as a fuel in maritime applications and concluded that today’s zero emission powertrains can meet the propulsion power and energy storage requirements of a wide range of vessels, from small passenger ferries and fishing boats to the largest cargo ships in the world.

Although a couple of small experimental aircraft powered by hydrogen have been built and tested, no definitive plans are in place to move away from fossil fuels for aviation. Hermans (2017) maintains that using liquid hydrogen has some specific advantages for air transport, namely safety, weight, and low hydrogen boil-off because the low outside temperature at cruising altitude reduces the temperature difference with the liquid. He concludes that using liquid hydrogen as a potential energy carrier for air transport deserves serious consideration.

Timing

So, when will we see this transition to a hydrogen-based economy? According to Gigler and Weeda (2018) it has started already, with major milestones expected over the next 25 years, as illustrated in Figure 5. Hydrogen use in industry is well established, but of interest is the forecast establishment of a synthetic fuels industry for shipping and aviation, based on hydrogen and CO2.

Note the graphic at the bottom of Figure 5: natural gas reforming will gradually give way for electrolysis as the preferred method for hydrogen production from about 2035. Carbon capture and storage (CCS) will be required for hydrogen produced by reforming in the interim.

Figure 5: Schedule of implementation for a range of hydrogen applications (Gigler & Weeda, 2018)

Concluding remarks

Hydrogen is important for being able to achieve the social challenge of drastically reducing CO2 emissions. Although hydrogen is widely used in some industrial applications, it has not yet realised its potential to support clean energy objectives. Moving to a hydrogen economy will take time and will only make sense if hydrogen can be produced economically from renewable sources, or from hydrocarbons with low emissions profiles, i.e.  when coupled with carbon capture and storage (CCS).

A major challenge is to reduce the costs for the production and application of hydrogen. This can be done by upscaling (creating critical mass) and by innovating. Focused research and near-term action is required to overcome remaining technological barriers and reduce costs. We need to spread the word about a clean hydrogen economy and (hopefully) more scientists, engineers and politicians will become motivated to participate.

References

Adolf, J., Fischedick, M., Balzar, C.H., Arnold, K., Louis, J., Pastowski, A., Schabla, U. & Schüwer, D. (2017) Shell hydrogen study: Energy of the future? Sustainable mobility through fuel cells and H2. Pdf document available from www.shell.de/h2study.  Downloaded on 10 January 2020.

Bhandari , R., Trudewind, C.A. & Zap, P. (2012) STE Research Report: Life cycle assessment of hydrogen production methods – a review. Institute of Energy and Climate Research, Jülich, Germany.

Cokayne, R. (2019) Shell to launch charging stations for electric vehicles in SA. Available from https://www.iol.co.za/motoring/industry-news/shell-to-launch-charging-stations-for-electric-vehicles-in-sa-19235648. Accessed on 15 February 2020.

D’Allegro, J. (2019) Elon Musk says the tech is ‘mind-bogglingly stupid,’ but hydrogen cars may yet threaten Tesla. Available from https://www.cnbc.com/2019/02/21/musk-calls-hydrogen-fuel-cells-stupid-

but-tech-may-threaten-tesla.html. Accessed on 27 February 2020.

Gigler, J. & Weeda, M. (2018) Outlines of a hydrogen roadmap, A publication of TKI Nieuw Gas, Optima Forma bv, Voorburg, Netherlands.

Hermans, J. (2017) The challenge of energy-efficient transportation. MRS Energy & Sustainability. Cambridge University Press, 4, p. E1. doi: 10.1557/mre.2017.2.

IEA (International Energy Agency) (2019) The future of hydrogen: seizing today’s opportunities. Available from https://www.iea.org/reports/the-future-of-hydrogen. Accessed on 15 February 2020.

Minnehan, J.J. & Pratt, (2017) Sandia Report SAND 2017-12665: Practical application limits of fuel cells and batteries for zero emission vessels. Pdf report available from https://energy.sandia.gov/wp-content/uploads/2017/12/SAND2017-12665.pdf. Accessed on 10 February 2020.

Potier, B. & Chung, E. (2019) World Economic Forum annual meeting: Three reasons why international cooperation is key to unlocking the hydrogen economy. Available from https://www.weforum.org/agenda/2019/01/cooperation-will-unlock-the-hydrogen-economy. Accessed on 15 February 2020.

Toyota (2019) Life cycle environmental activities for next-generation vehicles. Available from https://global.toyota/en/sustainability/esg/challenge2050/challenge2/lca-and-eco-actions/.  Accessed on 17 February 2020.

Tyilo, M. (2019) How geared up is South Africa for electric vehicles? Available from https://www.dailymaverick.co.za/article/2019-10-28-how-geared-up-is-south-africa-for-electric-vehicles/.  Accessed on 15 February 2020.

 

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Planning for Medical Emergencies during Project Implementation

Planning for Medical Emergencies during Project Implementation

By Jurie Steyn

Introduction

Responsible project managers actively manage risk to ensure that they have appropriate preventive and mitigation plans in place for identified risks.  Emergency response plans are an essential part of the mitigation plans when something does go wrong. Legislation in most countries require project teams to prepare emergency response plans for a range of potential emergency situations during project implementation. Emergency response plans are prepared to provide project site management and emergency response team members with a general guideline of the expected response to an emergency and an overview of their responsibilities during an emergency.

Emergency situations include construction incidents, transport incidents, fires and releases of contaminants to the environment.  The incidents mentioned can all result in injuries and medical emergencies. However, medical emergencies can also result from pre-existing medical conditions in members of the workforce.  Any medical emergency is undesirable, be it occupational or non-occupational.   In developed areas, with first-class medical infrastructure, it should be relatively simple to obtain the required specialist help with medical emergencies.  For greenfield projects on remote sites, or in third world countries, the desired level of medical assistance will probably not be available.

In this article, I focus on planning for medical emergencies during project execution in remote areas.  Planning for medical emergencies is a component of any integrated emergency response plan.

What constitutes a medical emergency?

There are many different definitions for a medical emergency.  Medical insurance companies tend to have a narrow view if they must pay for the transport of the patient (Riner, 2011).  For remote project sites, transport of patients to treatment centres can be very costly.

A medical emergency is regarded as the sudden onset of a medical condition, resulting from injury or natural causes, and manifesting itself by acute symptoms of sufficient severity (including severe pain) such that the absence of immediate medical attention could reasonably be expected to result in placing the patient’s health in serious jeopardy, serious impairment to bodily functions, or serious dysfunction of any bodily organ or part. In other words, there must be a chance of serious long-term consequences (even death) if treatment is not obtained immediately.

This definition is perfectly fine for the purposes of this discussion, although it can be asked who makes the final determination of whether it is an actual emergency.  Keep in mind that physicians or other medical practitioners might not always be available at the project site.  There is currently no internationally accepted definition of a medical emergency.

Occupational medical emergencies at the project site can include:

  • Open fractures and lacerations, resulting in bleeding that cannot be controlled by pressure alone;
  • Bleeding from internal injuries resulting in pain, distress and loss of consciousness;
  • Burns over large parts of the body, including chemical burns from hazardous chemical spills;
  • Ambient heat-related illnesses such as dehydration, heat exhaustion, heat cramps, and heat stroke (also known as sun stroke); and
  • Loss of consciousness from entering closed vessels.

Non-occupational medical emergencies at the project site can include:

  • Cardiopulmonary emergencies, including cardiac arrest, ventricular tachycardia and ventricular fibrillation;
  • Neurological emergencies, including seizures, unrelenting headaches and strokes;
  • Psychiatric emergencies, including hallucinations, suicide ideation, or any life-threatening behaviour directed at self or others;
  • Hypoglycaemia, or low blood sugar levels, in insulin-dependent diabetics;
  • Anaphylactic reactions or life-threatening allergic reactions, to foods, insect stings, medications and latex;
  • Sudden onset pain, possibly from appendicitis, gall stones or kidney stones;
  • Snake and spider bites, where the venom may cause bleeding, kidney failure, a severe allergic reaction, tissue death around the bite, and/or breathing problems;.and
  • Breathing difficulties and shortness of breath.

Of course, medical emergencies can involve a single patient, or multiple patients, depending on the nature of the incident that resulted in the injuries.

The medical emergency response plan

Opening remarks

In this section we’ll discuss what must be included in a medical emergency response plan, especially for projects in remote sites or in third world countries.  A medical emergency response plan is a roadmap for how to respond to, and transport an ill or injured person from the project site to a definitive care facility.

Figure 1 lists eight components or sections of a typical medical emergency response plan.  Each of these is discussed in turn below.

Figure 1:  Components of a medical emergency response plan

Project risk register

When operating internationally, each project location comes with its own risks. Many viruses are more prevalent in warmer areas of the world, and political instability can lead to violence and injury.  Ensure that site specific health and security risks are included in the risk register for the project so that these can be assessed, and preventive and mitigation actions can be put in place.

Knowing the types and symptoms of infectious diseases in an area (e.g. malaria and dengue fever) can help medical personnel identify deadly infections early.  If an area is known for poisonous snakes, spiders and scorpions, this must also be addressed in the project risk register.  Political instability and the potential for terrorism can pose serious risk to project staff.

The project risk register is a working document and is continually updated.  Make sure that new health risks identified for the project site are carried through to the medical emergency response plan.

Key contact information

This section of the medical emergency response plan should include the contact information for key project team members, relevant government departments, local emergency services, transport services, air evacuation support, telemedicine services and embassies. In addition to names and phone numbers for contacts, including e-mail addresses and even time zones can be helpful, especially when developing an emergency medical response plan for a remote project site.

Much of the contact information may be repeated in other parts of the medical emergency response plan, or included in flowcharts, but it is good to have all key contact information in one easily accessible place.

Site emergency response

If your company does not have a formal medical programme, you may want to investigate ways to provide timeous medical and first-aid services. If medical facilities are available near your worksite, you can arrange for them to handle emergency cases. In the case of project sites in remote locations, you will have to be able to provide primary emergency response. This means that several members of the project team must have adequate training in first aid. Treatment of a serious injury should begin within three to four minutes of the accident.

Depending of the remoteness of the project site, project scope, and the inherent project risks identified, it may be prudent to appoint a full-time paramedic, nursing staff and/or a physician on the project team. A facility with the appropriate first-aid supplies for emergencies should be available for medical staff to stabilise patients on the project site. Consult with a physician to order the appropriate first-aid supplies for the project. It is always beneficial for medical personnel to be accessible to provide advice and consultation in resolving health problems that occur in the workplace. Provide clear guidance about what should be done in case of a medical emergency. The paramedics should be given vital information about the nature of the emergency and the exact location of the response.

Consider purchasing a portable automated external defibrillator to deal with cardiac events. These are relatively inexpensive, easy to operate with limited training, and can save lives. Depending on the availability of a trustworthy ambulance service near the project site, it may be necessary to buy an ambulance for the project to transport injured or ill workers. At the very least, a suitable vehicle should be dedicated to the medical emergency response team

Recommended hospitals

A list of local hospitals, if any, is an essential part of every medical emergency response plan. The list should include the specialist competencies and capabilities of each hospital in order to make decisions regarding the best options for the patient. Depending on the distance between the project site and definitive care, it can be beneficial to include both a stabilisation hospital (interim) and a definitive care hospital (final).  Where there are no hospitals near the project site, a well-stocked and site-based emergency treatment centre is essential for stabilisation of patients.

The capabilities of each hospital should be thoroughly vetted by a physician before being included in the response plan. Some hospitals in third world countries may look impressive from the outside, but the quality of care may be lacking.

Expatriate project team members might insist on being transported back to their countries of origin for definitive care.

Medevac plan

Medical evacuation, often shortened to medevac, is the timely and efficient movement and en-route care provided by medical personnel to injured or ill patients being evacuated from the project site, or the scene of an accident, to receiving medical facilities using ground vehicles (ambulances) or aircraft (air ambulances).  The term is also used when transporting patients from a rural hospital to a better-equipped facility. An example of an air ambulance is shown in Figure 2.

The medevac plan lays out all the steps that should be taken when a medical emergency arises. The medevac plan is normally displayed as a flowchart, and should include the following steps (adapted from Remote Medical International, 2017):

  • Primary response: Who responds to the injured or ill party, when alarm is made and what are their responsibilities? Will there be anybody at the project site with medical training (i.e. a paramedic or physician)?
  • Evaluation: Evaluation of the injury or illness to determine if it’s a medical emergency. Who makes the call and what to do if the patient is treated on-site, but their condition worsens? Consider using telemedicine services when uncertain;
  • Evacuation: Decide on the preferred medical service provider and ensure you have the exact coordinates and fastest route to their facilities. Transport, or arrange for transport, of the patient by an evacuation provider to the medical service provider. Medevac plans should include information for both ground and air transport service providers. Note that the median charge for an air ambulance trip is approximately US$40 000 (Abudeff, 2019).
  • Dealing with expatriates: Expatriate project team members wishing to return to their countries of origin for definitive care, make the evacuation process significantly more complicated and may require the involvement of diplomatic resources.

This flowchart should be easy for anyone to follow, including non-medical professionals. The relevant project team members should be trained in the use of the evacuation plan and mock emergencies should be staged on an annual basis.

Figure 2: Example of an air ambulance

Diplomatic resources

Transport of seriously ill or injured patients across a country’s borders to enable expatriates to receive treatment in their home countries will often require assistance from diplomatic resources of the home country. It is therefore essential to have contact details of relevant authorities at the embassies of the home countries of expatriate project team members.

Address, GPS coordinates, phone number, email, website, and office hours should be included in the medical emergency response plan for each embassy. Ideally, the project team should visit the different embassies and obtain names and numbers of officials who can be of assistance during an emergency trans-border medevac.

Funding

Maintaining a medical presence, such as a paramedic or a physician, on a project site is expensive.  Depending on the remoteness of the project site, and/or the need for trans-boundary evacuation of expatriates, medevac expenditure can be extremely high. Somebody must pay for it.  Most project team members will have some form of medical insurance which may or may not cover the medevac cost. However, there will not be time for such negotiations in a real medical emergency.

The project company must be willing and able to pay for medevac cost up-front, even for non-occupational medical emergencies. Air ambulance services and helicopter services may require proof of payment before they even respond to a call-out. Attempts can be made at a later stage to recover the expenses from medical insurance.

Communication requirements

A good medical emergency response plan can be thwarted with an ineffective communication system. This means that reliable communication systems should be in place at the project site and that those to be informed of the incident are clearly indicated with their contact details.

The first requirement is a system to raise alarm and initiate the emergency response plan. Emergencies should be reported effectively to first response support teams, site and project management, patients’ families, project team members, and other interested parties.  Depending on the nature of the incident, it may be required to inform the Department of Labour of the host country.

Responsibilities of the project owner

It is the responsibility of the project owner and the project management team to ensure a safe work environment during project execution. This is normally well defined in government regulations, environmental and social impact assessments, company policy and project financier requirements.

As a minimum, project owners are responsible for the following:

  • Effective risk management: Identify and analyse risks and undertake the necessary preventive and mitigation steps;
  • Emergency planning: Plan for the worst possible scenarios as far as medical emergencies are concerned and be ready for whatever happens;
  • Safe work procedures: Develop safe work procedures for every activity on the project and enforce the use thereof;
  • Emergency response teams: Appoint, develop and train members of the project team as emergency responders;
  • Medical support: If medical support cannot reach the site within a reasonable time, the project owner should appoint medical professionals;
  • Medical equipment: A well-stocked medical facility should be available on remote project sites for stabilisation of ill or injured patients;
  • Transport: Dedicated transport, preferably an ambulance, should be available at the project site to transport seriously ill or injured patients;
  • Financial support: Allocate a portion of the project contingency for medical emergencies. Pre-approve the cost of medevac services;
  • Communication: Communicate openly and regularly to the families of injured or ill parties. Report injuries as required to the relevant government departments; and
  • Psychological support: Provide psychological support to the patient and families, as required, to enable them to work through the crisis.

Responsibilities of the individual

Where the project owner focuses on a safe work environment and safe work practices, individual team members are also responsible for their own safety, particularly as far as pre-existing medical conditions are concerned.

As a minimum, individuals are responsible for the following (adapted from Harvard Health Publishing, 2018):

  • Medical insurance: Project team members, especially expatriates and project consultants, should ensure that they have the appropriate medical insurance for the type and location of the work that they will be doing;
  • Primary care physician: List the names, addresses, and phone numbers for your health care team, especially your primary care physician and any specialists who treat you on a regular basis;
  • Medical history: List your current and past medical conditions and surgeries, major illnesses of your immediate family members, and any physical challenges or disabilities you may have (i.e. pacemakers or hearing aids);
  • Current medication: List all the medications and supplements you currently take. Write down the name, dose, and frequency of each medication. Having a list of medicines used can be beneficial because some can have side effects;
  • Emergency contacts: List your emergency contacts (note: more than one person, in case someone isn’t available). Include each person’s name, phone numbers, e-mail addresses, and relationship to you. Tell your emergency contacts in advance that you’re putting them on your list.
  • Living will: This details the kind of medical care you’d like if you’re unable to make your own health care decisions. It may be specific, stating if you want any life-sustaining treatments such as antibiotics or dialysis; or it may be more generic, simply stating whether you want to be on life support, or not; and
  • Health care proxy: Name your health care proxy, the person you designate to make your health care decisions if you lack the capacity to make them. Make sure to have a conversation with your designated proxy about what type of care is preferable. Without this conversation, the proxy will be at a loss at the time of emergency.

This information should be readily available in the individual’s personnel file, or a file at the emergency station.  One option is to have this information available on one’s phone, but the patient and phone may become separated during an emergency.

Concluding remarks

Planning for medical emergencies for a project takes time, effort and the input of several trained professionals.  It is essential to include the services of a physician on the planning team, preferably someone with extensive experience in the field of medical evacuation.

It is recommended to practice the medical emergency plan through the staging of mock emergencies. Things which seem logical to us when calm may not be so straight forward during times of crisis.

References

Abudeff, M. (2019) Emergency air lift to hospital could cost $40 000. Available from https://forum.facmedicine.com/threads/emergency-air-lift-to-hospital-could-cost-40-000.41901/.  Accessed on 6 January 2020.

Harvard Health Publishing. (2018) Are you prepared for a medical emergency? Available from https://www.health.harvard.edu/staying-healthy/are-you-prepared-for-a-medical-emergency. Accessed on 2 January 2020.

Remote Medical International. (2017) 6 Things to include in a medical emergency response plan for international project sites. Available from https://www.remotemedical.com/6-things-include-medical-emergency-response-plan-international-project-sites/. Accessed on 3 January 2020.

Riner, M. (2011) Definition of a medical emergency. Available from https://www.kevinmd.com/blog/2011/11/definition-medical-emergency.html. Accessed on 3 January 2020.

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Hydraulic Fracturing of Rock Formations – Part 2

Hydraulic Fracturing of Rock Formations – Part 2

By Jurie Steyn

This is the second of a two-part series of articles on the hydraulic fracturing of rock, also known as fracking. This is a technology that everyone has an opinion on, but few take the trouble to understand what it’s all about.

The two parts are as follows:

In this article, the debate regarding fracking is reopened, the geology and properties of coal beds are reviewed, fracking for coal-bed methane recovery is described, and the potential impacts of fracking are considered.

Introduction

Coal-bed methane (CBM) occurs as unconventional natural gas in coal seams. CBM was first extracted from coal mines as a safety measure to reduce the explosion hazard posed by methane gas in the mines. Today the methane is recovered from the coal seams and used as a source of energy. Because its combustion releases no toxins, produces no ash, and emits less carbon dioxide per unit of energy than combustion of coal, oil, or even wood, it is expected that CBM will grow in importance in our energy portfolio over the next decades.

It is estimated that about 85% of the world’s coal resources are unmineable because of economic, geological, environmental, or technical reasons (GTC, 2012). Such coal may be too deep underground, buried offshore, of poor quality, or the coal beds may be too thin. Most coal beds are permeated with methane, to the extent that a cubic meter of coal can contain six or seven times the methane that exists in a cubic meter of a conventional sandstone gas reservoir (Byrer et al, 2014). The CBM in the unmineable coal represents an excellent source of energy that can be recovered by vertical or horizontal wells into the coal seams. Depending on the depth and coal properties, some formations might require stimulation by hydraulic fracturing (fracking) to improve the delivery of CBM from such wells.

In this article, I touch upon the debate regarding fracking, review the geology and properties of coal beds, give an overview of fracking for CBM recovery and consider the potential impacts of fracking.

The ongoing debate about fracking

There are many books and articles on the technical aspects and economic benefits of fracking (Thakur, 2017; Robertson & Chilingar, 2017; Thakur, Schatzel & Aminian, 2014).  However, there are probably as many books and articles on the perceived adverse health and environmental consequences of fracking (CHPNY, 2018; Finkel, 2015; Bamberger & Oswald, 2014; Lloyd-Smith & Senjen, 2011).  Both sides make valid points, although the latter group tends to be more emotional in their arguments.

According to Holloway (2017) much negativity toward fracking is attributable to associated processes other than fracking. He postulates that the oil and gas industry has a narrow view of what fracking entails, whereas the general public is more inclined to include many more activities related to fracking (water and sand trucking, product and equipment transport and storage, water disposal). Several of the processes included by the general public are utilised in many, if not all, drilling practices, and are hard to put solely under the heading of ‘fracking’. In fact, many domestic water wells are fracked to improve yield. Be that as it may, emotions can run very high, as illustrated in Figure 1.

The visible face of opposition to fracking

Figure 1: The visible face of opposition to fracking (Johnson, 2015)

The bottom line is that if done irresponsibly, fracking and drilling can lead to many environmental and health problems for those in the vicinity. However, when done with knowledge of the geology and hydrogeology of the terrain, careful planning and engineering, and diligence in the execution of drilling and fracking, no meaningful problems should arise.

Vegter (2012) gives an impartial view of both sides of the debate in his book Extreme Environment and shows how environmental exaggeration can harm emerging economies.

Objectives of fracking

Most vertical wells do not produce gas until the permeability of the coal seam reservoir is enhanced through stimulation treatment. Stimulation of CBM wells is achieved by performing hydraulic fracturing. Fracturing is normally performed only once during the productive life of a well.

Stimulation or fracking of CBM wells is done to achieve the following objectives:

  • Remediate damage to the reservoir caused by drilling and cementing fluids infiltrating the reservoir matrix and natural fracture system;
  • Create new fractures in the coal matrix and prevent these from closing by injecting proppant to better access the natural fracture system of coal cleats and pores;
  • Open natural fractures wider and keep open with proppant to enable flow of gas and water from the cleats and pores to the well; and
  • Extending the life of low producing wells by performing a second and more severe stimulation.

Note that the primary purpose of CBM well stimulation is to connect the well to the natural fractures in the coal.  In the case of shale formations where there are no natural fractures, the objective is to create a fractured rock reservoir to access the shale gas contained in pores and adsorbed onto organic material.

Geology and properties of coal beds

Formation

Coal is a combustible sedimentary rock formed from ancient vegetation which has been consolidated between other rock strata and transformed by the combined effects of biochemical decay, pressure and heat over millions of years. This process is commonly called coalification and involves the alteration of vegetation to form peat, succeeded by the transformation of peat through lignite, subbituminous, bituminous, to anthracite coal. The degree of transformation or coalification is termed the coal rank.

Coal occurs as layers or seams, ranging in thickness from millimetres to many tens of metres. It is composed mostly of carbon (55 to 95 %), hydrogen (3 to 13 %) and oxygen, and smaller amounts of nitrogen, sulphur and other elements. It also contains water and particles of other inorganic matter.

Structure

All ranks of black coal are noted for the development of its jointing, more commonly referred to as cleat. This regular pattern of cracking in the coal may have originated during coalification. The burial, compaction and continued diagenesis of the organic constituents result in the progressive reduction of porosity and permeability. At this stage microfracturing of the coal is thought to be generated. The surfaces and spaces thus created may be coated and filled with mineral precipitates.

Cleats are fractures that occur in two sets that are, in most cases, mutually perpendicular. Through-going cleats formed first and are referred to as face cleats. Cleats that end at intersections formed later and are called butt cleats. Some of the characteristics of the structure of coal are shown in Figure 2.

The structure of coal

Figure 2: The structure of coal

At surface conditions, cleats are typically <0.1mm in width and are scarcely visible with the naked eye (Laubach et al, 1998). Cleats in coal are much more intensely developed than fractures in adjacent non-coal rocks.

Gas content

CBM is a gas, primarily methane, that naturally occurs in coal seams. It is formed during the conversion of organic material to coal and becomes trapped in cleats and micropores in the coal seam. Coal seams are, therefore, both the source and reservoir for CBM. The CBM is trapped in the coal seam in part by water pressure and in part by weak covalent Van der Waals forces. CBM exists in the coal seams in three basic states: as free gas, as gas dissolved in the water in coal, and as gas adsorbed on the solid surface of the coal.

Sorption is a physical or chemical process in which gas molecules become attached or detached from the solid surface of a material. Desorption is the process that occurs when free gas pressure drops, and adsorbed gas molecules start desorbing from a solid surface.

The amount of gas retained in a coal seam depends on several factors, such as the rank of coal, the depth of burial, the immediate roof and floor, geological anomalies, tectonic forces, and the temperature prevailing during the coalification process (Thakur, 2017). In general, the higher the rank of coal and the greater the depth of coal, the higher is the coal’s gas content. Actual gas contents of various coal seams to economically mineable depths of 1200 m are up to 125 m3/t. Gas content in coal is not fixed but changes when equilibrium conditions within the reservoir are disrupted.

Hydrostatic pressure

Pressure in sedimentary basins has two components, namely lithostatic pressure, which is the pressure caused by the weight of the overburden and hydrostatic pressure, which is an opposing pressure caused by reservoir fluid (Pashin, 2014).  Intrusion of groundwater into coals is a common occurrence, and coal beds act as regional aquifers in some areas.

Water removal from the coal bed is the principal mechanism by which coal is depressurised, and understanding the hydrology of CBM reservoirs and the ways in which coproduced water can be managed is essential for a successful CBM project. Gas and water production over time is illustrated in Figure 3. The produced water often contains high concentrations of salts and other organic and inorganic substances solubilised from the coal bed. The disposal of these waters can present environmental problems.

Gas and methane production over the life of a well

Figure 3:  Gas and methane production over the life of a well

CBM production can take place only when the reservoir pressure is reduced sufficiently to allow the gas to desorb. Gas flow to wells drilled into the coal seam takes place through natural fractures and fractures created by fracking, not through the relatively impermeable coal matrix.

Porosity and permeability

Porosity is the fraction of the total volume of a rock that can hold gas or liquid, i.e. it is the percentage of the bulk volume of the rock that is not occupied by solid matter. The face cleat in coal is the major fracture that stores and conducts gases, with the butt cleat the minor fracture. Most of the porosity of coal comprises the space taken up by these fractures. The porosity of the cleat system in coals ranges from 1% to 5%.

Next to gas content, permeability is the most important coal reservoir property for CBM delivery. Permeability is a property of porous media such as coal, and is a measure of the capacity of the medium to transmit fluids. It depends on the driving pressure differential, the area of the specimen, and the viscosity of the fluid. However, permeability in coal-bed methane reservoirs is a transient property (Thakur, 2017). As gas is produced, the coal matrix shrinks, thereby widening cleat apertures and improving both porosity and permeability.

Permeability continuum

Figure 4:  Permeability continuum (Adapted from Simpson, 2019)

The fracking process

Opening comments

An introduction to fracking was given in Part 1 of this series of articles (Steyn, 2019).  This covered the applications of fracking, described the chemicals and additives used in fracking fluid, and considered a method to classify fracking based on application, severity and impact.

In this section a brief description is given of some of the aspects of the stimulation of CBM wells by hydraulic fracturing.

Well completion and perforation

Vertical well drilling is normally done with small footprint air rigs due to low cost and low environmental impact. Small cuttings pits are necessary to capture returned solids and formation fluids carried back by the air stream.

Casing is installed into the coal bed to total depth and cemented in place. Cementing the casing provides pipe support, zonal isolation to protect against cross contamination, and well control. Once the casing has been cemented in the hole, slotting can commence to gain access to the coal formation. One method involves the use of a jetting tool where friction-reduced water (slickwater) and sand are pumped at high pressure through opposing jets to abrasively remove casing and formation (Rodveldt, 2014). Slots can be cut most efficiently going down by slowly lowering the tool in the hole while pumping. Slot lengths should not exceed 35cm, prevent compromising the integrity of the casing.  Another, more conventional method of gaining access to the coals seam is perforating the casing with explosive jet charges.

Fracking in 4 stages

Stage 1: Acid wash (Optional)

This stage is not required in all cases and depends on the geology of the coal and the extent of blockage of the natural coal cleats by cement.  However. It involves the pumping of a mixture of water and dilute acid such as hydrochloric or muriatic acid into the well and through the perforations in the wellbore into the coal face. This serves to clear cement debris in the wellbore and provide an open conduit for other fracking fluids by dissolving carbonate minerals and opening fractures near the wellbore.

Stage 2: Propagate fractures

This is also referred to as the pad stage and involves the pumping of slickwater or gelled water, without proppant material, into the well. The wellbore is filled with the water solution, fractures in the coalbed are opened and propagated, thereby creating pathways for the placement of proppant. Slickwater has fewer additives than gelled water, and is the preferred option in the USA.

Stage 3: Keep fractures open

Stage 3 is also referred to as the prop sequence stage. It consists of several sub-stages of pumping water with proppant material (mostly fine mesh sand with spherical particles) into the fractures created in Stage 2 to ‘prop’ or keep the fractures open after the pressure is reduced. Proppant material may vary from a finer particle size to a coarser particle size throughout this sequence. The pressure of the fracking fluid is typically around 172 bar for this stage. On completion, the pressure is reduced, fracking fluid returns to the wellbore and proppant is locked in position in the fractures.

Stage 4: Flush

Fresh water is pumped into the wellbore to flush out the fracking fluid, including flowback fluid from the fractures, to surface.  This is normally stored in a lined pit, before disposal.

Potential impacts of fracking

Opening comments

Irresponsible fracking of coal seams has the potential to cause harm to the environment and the health and safety of operators and the community.  I give a brief overview of some of the most mentioned potential impacts of fracking in the sections that follow.

Visual impact

Fracking for the economic recovery of CBM is generally performed at depths of between 250m and 1200m.  Most wells are fracked only once during their operating life of 20 to 30 years, and nobody gets to see the effect underground.  However, the visual impact has to do with the number of wells required to effectively recover the CBM.  Vertical wells are typically spaced at 400m to 500m intervals and this translates to many wells in a small area, as shown in Figure 5.

Visual impact of many vertical wells in a small area

Figure 5: Visual impact of many vertical wells in a small area

The number of wells can be drastically reduced by using directional drilling along the coal beds.  A significantly larger area can then be covered than with a vertical well, thereby reducing the visual impact.  However, horizontal drilling is not applicable in all cases and depends on the number and thickness of the coal seams.

Spills

A concern during fracking operations is the potential for spills or releases at the well pad site or during transportation. Prepared fracking fluid or chemical additives in their concentrated form pose a higher risk while being transported or stored on-site than when injected into the subsurface during the fracking process.

Sources of spills at the pad site include mechanical failures at the drilling/fracking rigs, storage tanks, pits, and even leaks or blowouts at the wellhead. Leaks or spills may also occur during transportation of materials, chemicals and wastes to and from the well pad. Soil, surface water and groundwater are the primary risk receptors. According to Holloway (2017), effective containment is a major factor in minimising the impacts on human health and the environment when a spill occurs. This can be further improved by using inherently safe and biodegradable additives in the fracking fluid.

Air pollution

Air pollution can occur during every stage of CBM development, from exploration to construction, operation, maintenance and final closure. Heavy equipment is used during site preparation to clear and prepare the well pad site and to create new roads. Generators are set up, and there are emissions from vehicles and generators if they are diesel powered, as well as increased coarse particulate matter and dust from the new roads and increased truck traffic on the roads.

During normal operation and maintenance activities, methane can be released from pipes and machinery.  Produced water also contains some dissolved gas which can be released to atmosphere.  During exploration and upset conditions, significant volumes of methane is routed to a flare system where the gas is combusted to form carbon dioxide.  All these aspects can be, and must be, carefully managed.

Silica Dust

Silica dust is an emission source that is becoming more of a fracking industry concern. The fracking process requires large volumes of sand as proppant. Therefore, many truckloads of sand must be offloaded and transferred before being mixed with water and other chemicals and pumped down-hole. The dust produced by the handling of sand, which may contain up to 99% crystalline silica, is a health concern due to the risk of silicosis, a progressive and disabling lung disease.  Sand stockpiles must be kept wet to reduce dust, and operators should be required to wear dust masks.

Groundwater pollution

A common concern expressed by potentially affected parties about fracking is that the process creates fractures extending past the target formation to aquifers, allowing fracking fluids to migrate into the drinking water supplies (Holloway, 2017).  This is unlikely because it would require the hydro-fractures to extend several hundred meters past the upper boundary of the coal seam.  After completion of the fracking process, the flow of water and gas is toward the CBM recovery well, and not away from it.

The US Environmental Protection Agency (EPA, 2004) concluded, after a multi-year study, that the injection of fracking fluids into CBM seams poses little or no threat to higher lying aquifers of potable water. In a review of cases of contaminated boreholes, they also found no confirmed cases that are linked to fracking fluid injection or the subsequent underground movement thereof.

Produced water impacts

Produced water from the coal bed, as well as flowback water from the fracking step, is commonly stored in pits or tanks on the wellfield before removal by truck or pipeline for reuse, treatment, or disposal. These options depend greatly on the quality of the water, which can vary from suitable for agricultural purposes to highly saline water.  These pits and tanks are possible sources of leaks or spills.

Produced water may also be stored in evaporation ponds, with or without an HDPE liner system. Current best practice calls for a triple liner system in evaporation ponds with leak detection.  Leaks of saline water into the subsurface will sterilise the soil and pollute upper aquifers in the long run.

Saline produced water should ideally be treated in a water treatment facility.  A policy of zero pollution and waste is recommended.  This implies that concentrated saline streams should be sent to evaporation ponds, or processed in a drying system to remove the salt from the water.  A plethora of options are available, and each should be customised for the unique characteristics of the site and the produced water.  Proper treatment and use of the produced water have proven to be highly beneficial

Gas in water wells

Opponents of fracking love to cite cases of flammable gas in water wells as this makes for interesting reading.  Although there have been many reported cases of gas in domestic water wells in the USA, almost all of these resulted from the unsafe storage of conventional natural gas in underground reservoirs, and none as a result of CBM recovery.

Gas explosions

The lower explosive limit (LEL) of CBM occurs when approximately 5% by volume of gas is mixed with 95% by volume of air. This translates into a serious explosion and fire hazard, especially where the gas can migrate into a confined space such as a room or an electrical vault. These hydrocarbon gases are often the result of leakage from gas pipelines. If the explosion (LEL) limit is met, a spark can quickly initiate a fire or an explosion.

A vast network of pipelines is normally part of any CBM development, and the risk of fires or explosions is always present. For this reason, the pipelines are normally buried underground to protect them from damage and methane detectors are used before any work is done.  However, the risk of an explosion is minimal in open spaces because methane is much lighter than air.

Induced seismicity

Pumping fluids in or out of the Earth’s subsurface has the potential to cause seismic events. Fracking into a moderately sized fault at a sufficiently high rate and pressure may produce enough seismic energy to create measurable signals at instruments very close to the fracking site.

Seismic events, when attributable to human activities, are called ‘induced seismic events.’ Seismic events are dependent upon the sub-surface geology of the site. The biggest micro-earthquakes directly attributable to fracking have a magnitude of about 1.6 on the Richter Scale, which is insignificant (Holloway, 2017).

Subsidence

The risk of subsidence is often mentioned when potential impacts of fracking are discussed, more so in the case of CBM production than for shale gas.  The reason for this is twofold: CBM wells are much shallower than shale gas wells and significant volumes of produced water must be pumped from CBM wells in order to release the gas.

However, no direct correlation has yet been found between CBM wells and surface subsidence. Remember that coal seams suitable for CBM recovery are at least 250m deep and that the coal itself is not removed, but only the water contained in the coal.

Site remediation

The common objective in the site remediation of drill pads and other infrastructure is to restore the site to its former condition and use (Holloway, 2017). Many countries require a mine closure plan which is updated at regular intervals.  The closure plan should make provision for plugging of production wells, the removal of all pipelines, cables, tanks, other equipment on site and the remediation of any contamination.  Closure plans must include an accurate estimate of the anticipated cost of closure and describe how provision is made to finance closure activities.  Well sites and access roads cover a small percentage of a CBM wellfield and will quickly revert to their natural state after closure.

It is normally expected that gas companies continue with groundwater monitoring for a period of at least five years after closure to ensure that there are no latent environmental problems.

Ranking of fracking intensity

Adams and Rowe (2013) proposed a terminology based on some of the physical aspects of fracking to allow clear differentiation between the many different types of hydraulic fracturing operations. This approach was described in more detail in Part 1 of this series of articles.

Based on this terminology, fracking of coal beds for CBM recovery can be classified as Type C(ap), meaning that additives and proppant are used in the fracking fluid.  In comparison, fracking of shale seams for gas recovery would be classified as Type D(ap) because of higher pressures and more intensive fracking.

Closing remarks

CBM reserves represent a major contribution to energy needs. However, gas recovery by fracking, requires responsible management to minimise any environmental effects. The industry is adapting, where possible, to fewer and more benign fracking chemicals to further reduce the impact of flowback and produced waters.

International economic, environmental, and technological advances over the past decade have led to the consideration of CO2 sequestration together with CBM recovery. The idea is to geologically sequester CO2 in coal seams, while at the same time recovering the methane already in them. The CO2 would be injected via wells drilled into the coal, and the CO2 would drive the methane out of the coal through other wells to the surface. This two-in-one idea is feasible because bituminous coal can store twice the volume of CO2 than it stores methane. The net result would be less CO2 in the atmosphere, no significant new methane added to the atmosphere, and enhanced recovery of methane to help pay for the process.

References

Adams, J. & Rowe, C. (2013) Differentiating Applications of Hydraulic Fracturing. In proceedings of the International Conference for Effective and Sustainable Hydraulic Fracturing (HF2013) which was held 20-22 May 2013 in Brisbane, Australia.

Bamberger, M. & Oswald, R. (2014) The real cost of fracking: How America’s shale gas boom Is threatening our families, pets, and food. Beacon Press, Boston, MA.

Byrer, C., Havryluk, I, & Uhrin, D. (2014) Coalbed methane: a miner’s curse and a valuable resource. In Thakur, P., Aminian, K. & Schatzel, S. (eds.). Coalbed methane: from prospect to pipeline. Elsevier Inc. San Diego, CA.

CHPNY. (2018) Compendium of scientific, medical, and media findings demonstrating risks and harms of fracking (unconventional gas and oil extraction), 5th ed. Concerned Health Professionals of New York & Physicians for Social Responsibility, New York, NY

Finkel, M.L. (2015) The human and environmental impact of fracking: How fracturing shale for gas affects us and our world. Praeger (an imprint of ABC-CLIO, LLC), Santa Barbara, CA.

EPA. (2004) Evaluation of impacts to underground sources of drinking water by hydraulic fracturing of coalbed methane reservoirs.  Report EPA 816-R-04-003 by the US Environmental Protection Agency.

GTC. (2012) Underground coal gasification: converting unmineable coal to energy. Gasification Technologies Council.

Holloway, M.D. (2017) Fracking. In Robertson, J.O. & Chilingar, G.V. Environmental aspects of oil and gas production. John Wiley & Sons, Inc. Hoboken, NJ.

Johnson, A. (2015) Fossil fuels: The key ingredient of environmental protests. Available from https://www.westernenergyalliance.org/blog/fossil-fuels-key-ingredient-environmental-protests. Accessed on 8 October 2019.

Laubach, S.E., Marrett, R.A., Olson, J.E. & Scott, A.R. (1998) Characteristics and origins of coal cleat: A review, International Journal of Coal Geology 35, 175–207

Lloyd-Smith, M.  & Senjen, R. (2011) Hydraulic fracturing in coal seam gas mining: The risks to our health, communities, environment and climate. National Toxics Network, Bangalow, NSW.

Pashin, J.C. (2014) Geology of North American coalbed methane reservoirs. In Thakur, P., Aminian, K. & Schatzel, S. (eds.). Coalbed methane: from prospect to pipeline. Elsevier Inc. San Diego, CA.

Robertson, J.O. & Chilingar, G.V. (2017) Environmental aspects of oil and gas production. John Wiley & Sons, Inc. Hoboken, NJ.

Rodveldt, G. (2014) Vertical well construction and hydraulic fracturing for CBM completions.  In Thakur, P., Aminian, K. & Schatzel, S. (eds.). Coalbed methane: from prospect to pipeline. Elsevier Inc. San Diego, CA.

Simpson, D. (2019) Coal bed methane (CBM) and shale. In Lea, J.F. & Rowlan, L. Coal well deliquifaction, 3rd ed. Gulf Professional Publishing (an imprint of Elsevier Inc.), Cambridge, MA.

Steyn, J.W. (2019) Hydraulic fracturing of rock formations, Part 1: Introduction and applications.  Available from https://www.ownerteamconsult.com/hydraulic-fracturing-of-rock-formations-part-1/.  Accessed on 20 September 2019.

Thakur, P., Aminian, K. & Schatzel, S. (eds.). (2014) Coalbed methane: from prospect to pipeline. Elsevier Inc. San Diego, CA.

Thakur, P. (2017) Advanced reservoir and production engineering for coal bed methane. Gulf Professional Publishing (an imprint of Elsevier), Cambridge, MA.

Vegter, I. (2012) Extreme environment: How environmental exaggeration harms emerging economies. Zebra Press (an imprint of Random House Struik (Pty) Ltd), Cape Town, RSA.

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Hydraulic Fracturing of Rock Formations – Part 1

Hydraulic Fracturing of Rock Formations – Part 1

By Jurie Steyn

This is the first of a two-part series of articles on the hydraulic fracturing of rock, also known as fracking. This is a technology that everyone has an opinion on, but few take the trouble to understand what it’s all about.

The two parts are as follows:

In this first article, the concept of fracking is introduced, different applications are discussed, the chemicals and additives used in fracking fluid are described, and a method to classify fracking according to severity and impact is considered.

Introduction

I have been planning an article on the hydraulic stimulation of gas wells in coal beds for a long time.  Hydraulic stimulation improves the delivery of coal-bed methane (CBM) from such wells.  The more I read about hydraulic stimulation, or CBM well conditioning, the more I realised that one first must understand hydraulic fracturing, or fracking. Hence this two-part series of articles.

Hydraulic fracturing involves pumping water and sand at high pressure into gas or oil-bearing rock to fracture it and open pathways for the gas or oil to escape to the receiving well. This is far removed from the mid-nineteenth century practice of ‘shooting’ a well, which used explosives instead of water, but the principle is the same. Drillers freed-up non-productive wells by creating underground explosions to loosen rock so that gas or oil could move freely. Fortunately, modern day fracking is far safer, controlled, predictable and environmentally friendly.

In this first article, I introduce the art of fracking, discuss different applications, describe the chemicals and additives used in fracking fluid, and consider a method to classify fracking based on application, severity and impact.

History of fracking

The first recorded case of fracking was in 1857 when Preston Barmore lowered gunpowder into a well at Canadaway Creek, NY, and dropped a red-hot iron down a tube, resulting in an explosion that fractured the rock and increased the flow of gas from the well (Morton, 2013).  Undoubtedly spectacular, but definitely not controlled or safe…

In 1866, Edward Roberts registered a patent, for exploding torpedoes in artesian wells. This fracking method was implemented by packing a torpedo in an iron case that contained 15-20 pounds of powder. The case was then lowered into the oil well, at a spot closest to the oil source. The borehole was filled with water to increase the effect of the blast and the torpedo was detonated from the surface by connecting wires.  This increased oil from the wells by up to 1200% within a week of the blast (Manfreda, 2015)

There was little innovation in fracking technology until the 1930s, when drillers started using acid to make wells more resistant to closing, and thereby increasing productivity. However, hydraulic fracturing of rock only began in the 1940s to stimulate the production of oil and gas from reservoirs that had experienced a decline in productivity. The first application was in 1947 in the Hugoton Field, Kansas, where petrol gelled with palm oil and crosslinked with naphthenic acid were combined with sand to stimulate the flow of natural gas from a limestone formation. Halliburton Oil Well Cementing Company obtained an exclusive licence in 1949 for the hydraulic fracturing process. In the first year of operations, 332 oil wells were treated with a combination of crude oil, petrol and sand. The wells increased production rates by 75%, on average.

Water-based fracking fluids was in use from 1953 and many different chemical additives were tried to improve its performance. By 1968, fracking was being used in oil and gas wells across the United States, albeit in less difficult geological formations.  The application of fracking expanded during the 1980s and 1990s, when it was used to stimulate methane extraction from coal beds.

In the mid-1970s, the US Department of Energy (DOE) and the Gas Research Institute (GRI), in partnership with private operators, began developing techniques to produce natural gas from shale (Smith, 2012). Shale rock presented a challenge because of the difficulty in accessing the hydrocarbons in tight formations. Techniques employed included the use of horizontal wells, multi-stage fracturing, and slick water fracturing. The essential chemical additive for slick water fracturing is the friction reducer.

Mitchell Energy achieved commercial success with the recovery of gas from shale formations using slick water, a low viscous mixture that could be rapidly pumped down a well to deliver a much higher pressure to the rock than before. A merger between Mitchell Energy and Devon Energy in 2002 brought a rapid increase in the use of fracking with horizontal drilling in shale. George Mitchell (1919–2013) has been called the “Father of Fracking”, although he can be more accurately described as the “Father of the Shale Gas Boom” (Morton, 2013).

Applications of fracking

Hydraulic fracking is used far wider than the oil and gas industry (Adams & Rowe, 2013). It is used to great effect in many different applications, including:

  • Water well production enhancement: Just as hydraulic fracking is used to increase the rate and efficiency of recovery for oil and gas, it can also be used to improve the yield of water wells in fractured rock aquifers. A section of the well is isolated using packers and water is introduced to generate pressures up to approximately 200 bar to wash out existing fractures and propagate them to connect with others within the aquifer. No chemical additives or proppants are used. This technique has successfully been done not only in the US, but also in India, Australia and South Africa;
  • Mining Applications: Hydraulic fracking also has mining applications where it can be used to induce controlled rock caving. In the event of a massive, un-fractured ore body, some form of pre-conditioning is needed to initiate caving and to reduce the size of caving materials. Hydraulic fracturing in boreholes drilled into the ore body is the preferred method of performing this preconditioning process. Fracturing pressures can be up to 700 bar. Fracking has also been proposed for uranium mining in which it will be used to inject substances that will dissolve the uranium so that it can then be pumped to the surface;
  • Rock stress determination: Hydraulic fracking can be used by geologists to measures stress levels within the Earth. A section of borehole is isolated between two inflatable packers and the pressure is raised by pumping fluid into it at a controlled rate until a fracture occurs in the borehole wall. The magnitudes of the principal stresses are calculated from the pressure readings. Normally only pure water is used, and pressures are typically a maximum of 400 bar but can be as high as 1050 bar;
  • Conventional oil and gas production: Hydraulic fracking has been used for many years to stimulate production from low yielding wells. Fracture stimulation in this industry typically uses injected fluid that includes chemical additives and proppant. The formations being treated is normally already permeable, and very high injection flow rates are necessary to build pressure in the treatment region. Injection pressures can be as high as 1 400 bar. The total volume of injected fluid is generally more than 1 ML;
  • Geothermal energy production: Hydraulic fracking is used in geothermal systems to enhance heat extraction to produce electricity. Geothermal energy production involves the injection of water in a well, heating the water by geothermal energy, and extraction of the same water as steam or hot water from a second well. Hydraulic fracturing is used to establish a flow pathway between the injection and extraction wells;
  • Carbon sequestration: Carbon capture and storage in suitable geologic formations is one way to reduce greenhouse gas emissions to atmosphere. The range of suitable geologic formations includes coal basins, depleted oil and gas reservoirs and saline aquifers. Hydraulic fracturing may play a role in this industry in future to improve access to these formations and enhance their carrying capacity;
  • Coal mine methane (CMM) drainage: CMM drainage is performed in coal seams prior to mining for safety and environmental reasons and can create an additional income stream. Hydraulic fracturing is used to enhance the production of methane from the coal. The scale of treatments varies widely, but are normally smaller than CBM stimulation fractures.
  • Coal-bed methane (CBM) extraction:Hydraulic fracturing in CBM wells is performed to open conductive channels and stimulate the flow of methane to the wellbore. The CBM reservoirs are closer to the surface than most conventional oil and gas reservoirs or shale formations, thus requiring lower pressures, less volume and fewer additives in the fracturing fluid. Fracture pressures are up to 350 bar and total injected volume per fracture ranges up to 500 m3.
  • Waste disposal in deep-wells: Hydraulic fracking is used to open op suitable areas in deep rock formations for the disposal of saline liquid waste, so called deep-well injection of liquid waste streams.

As the fracking technology continues to advance, it is likely to become applicable in currently unforeseen ways.

Stages of fracking

There is a range of hydraulic fracturing techniques and several different approaches may be applied within a specific area. Hydraulic fracturing programmes and the fracture fluid composition vary according to the engineering requirements specific to the formation, wellbore and location. A typical hydraulic fracture programme will follow the stages below as a minimum (Fink, 2013; FracFocus, 2019):

  • Spearhead stage:This initial stage is also referred to as an acid or prepad stage. It involves injecting a mix of water with diluted acid, such as hydrochloric acid. This serves to clear debris from the wellbore, providing a clear pathway for fracture fluids to access the formation. The acid reacts with minerals in the rock, creating starting points for fracture development;
  • Pad stage: The generation of the fractures takes place by injecting the pad, a viscous fluid, but without proppants, to break the rock formation and initiate the hydraulic fracturing of the target area;
  • Proppant stage:After the fractures develop, a proppant must be injected to keep them open. When the fracture closes, the proppant is locked in place and creates a large flow area and a conductive pathway for hydrocarbons to flow into the wellbore. Viscous fluids are used to transport, suspend, and allow the proppant to be trapped inside the fracture; and
  • Flush stage:The job ends eventually with a flush stage, in which flush fluids and other clean-up agents are applied. A volume of fresh water is pumped down the wellbore to flush out any excess proppant that may be present in the wellbore.

Components of fracking fluid

Opening comments

Fracking fluid is made up according to many different recipes, according to the preferences of the driller and the characteristics of the rock that is being fractured. In fact, op to 750 different components have been identified in fracking fluid. The natural gas industry supports the disclosure of what is used in the hydraulic fracturing process to interested and affected parties. The only proviso is that proprietary fracking fluid composition and business information is kept confidential.  Depending on the application, between 3 and 12 chemical additives are used in fracking fluid with a median of 10 additives (US EPA, 2015).

Nowadays, most fracking fluids are water-based. Aqueous fluids are economical and, if used with chemical additives, can provide the required range of physical properties. Additives for fracking fluids serve three purposes, namely:

  • They enhance fracture creation;
  • They enable proppant to be carried into the fractures; and
  • They minimize damage to the rock formation.

Although different compositions of fracking fluid are used for the different stages of fracking, a typical composition of such a fluid is shown in Figure 1.

Fig 1 Chemical composition of typical fracking fluid

 

 

Figure 1:  Typical composition of fracking fluid

Ninety percent of fracking fluid is made up of water, and another 9,5 percent is proppant. The remaining 0,5 percent of the fracking fluid is made up of chemical additives.  Although their percentages may be small, chemicals play a crucial role in fracking. The different components of fracking fluid are discussed below.

Proppants

Hydraulic fracturing creates fissures in the rock, but when the pressure of the fracking fluid is reduced the newly created fissures and cracks will close again.  Proppants are introduced into the fracking fluid to penetrate and keep the fractures open, thereby forming conductive channels within the rock formation through which hydrocarbons can flow.  A proppant is a hard and solid material, typically sand, small diameter ceramic materials, or sintered bauxites.  Sand has a relatively low strength, which can be improved by resin coating.

The proppant must stay in position and prop open the conductive channels for the productive life of the well.  The flowback of a proppant following fracture stimulation treatment is a major concern because of the possible damage to equipment and loss in well production rate. Proppant related degradation of the fracture conductivity can be caused by flowback, mechanical failure of the proppant grains, chemical damage or dissolution from the additives, and proppant embedment.

The shape and size of the proppant is important because shape and size influence the final permeability through the fracture. A wide range of particle sizes and shapes will lead to a tight packing arrangement, reducing permeability/conductivity. A controlled range of sizes and preferential spherical shape will lead to greater conductivity. Typical proppant sizes are generally between 8 and 140 mesh (106 µm to 2.36 mm), although a much narrower range is normally specified, say a 10/50 or 20/40 cut.

For the fracking fluid to be able to carry the proppant into the fractures, the fluid must be viscous enough to prevent the proppant from settling out before it has been carried to the desired position.

Chemical additives

The following is a list of the primary groups of chemical additives used in fracking fluid recipes:

  • Acids: Acids, like hydrochloric or muriatic acid, are used in fracking fluids to dissolve the minerals in the rock, soil and sand below the ground. This helps to initiate cracking and crack propagation.Typical acid concentration used is 15%. Acid also cleans out cement and debris around the perforations in the wellbore to facilitate the ingress of subsequent fracking fluids into the rock formation. Acid reacts with minerals to create salts, water and carbon dioxide.
  • Gelling agents: Gelling agents, such as guar gum or hydroxyethyl cellulose, are added to the fracking fluid to increase the viscosity; it effectively thickens the water. This enables the fracking fluid to accept higher concentrations of proppant, reduces the fluid loss to improve fluid efficiency, and improves proppant transport. The chemical structure of some gelling agents also allows for crosslinking. Gelling agents are broken down by breakers and returns with the flush water;
  • Crosslinkers: Occasionally, a cross-linking agent is used to enhance the characteristics and ability of the gelling agent to transport the proppant. These compounds may contain boric acid or ethylene glycol. When cross-linking additives are added, a breaker solution is usually added later in the frack stage to break down the gelled solution into a less viscous fluid;
  • Breakers:Breakers, like ammonium persulphate, allows for the breakdown of the gel polymer chains. Breakers can also be used to control the timing of the breaking of the gelled fluids to ensure enough time for proppant to be transported into the fractures. The gel should be completely broken within a specific period after completion of the fracking process for ease of flushing. Breakers react with gel and crosslinkers to form ammonia and sulphate salts which are flushed out;
  • Friction reducers:Friction reducers, like polyacrylic acid, polyacrylamide or mineral oil, are used in the production of slick water and minimises friction between the fracking fluid and the pipe, thereby reducing the pressure needed to pump fluid into the wellbore. Friction reducers remain in the rock formation where they are broken down by micro-organisms. A small amount may be returned with the flush water;
  • Clay stabilisers: Rocks within water-sensitive shale and clay formations absorb fracking fluid, which causes the rock to swell and drastically reduce formation permeability, as well as lead to wellbore collapse. Potassium chloride is a temporary clay stabiliser in freshwater-sensitive formations and helps prevent this swelling. Alternatives are choline chloride and choline bicarbonate, both of which are biodegradable;
  • Surfactants: These additives are used to decrease liquid/surface tension and improve fluid passage through pipes in either direction.Surface active agents, like isopropanol, are included in most aqueous treating fluids to improve the compatibility of aqueous fracking fluids with the hydrocarbon-containing reservoir. Surfactants are usually returned to surface with the flush water;
  • Scale inhibitors: Scale control prevents the build-up of mineral scale that can block fluid and gas passage through the pipes.A scale inhibitor, such as ethylene glycol, is used to control the precipitation of certain carbonate and sulphate minerals in pipelines.Most of the scale inhibitors will be returned to surface with the flush water;
  • Corrosion inhibitors:Corrosion inhibitors are required in acidic fracking fluid mixtures because acids will corrode steel tubing, well casings, tools, and tanks. Corrosion inhibitors, such as n-dimethyl formamide, and oxygen scavengers, such as ammonium bisulphite, are used to prevent degradation of the steel well casing. Most of the corrosion inhibitors will be returned to surface with the flush water;
  • Iron control agents:Iron control or stabilising agents such as citric acid or hydrochloric acid, are used to inhibit precipitation of iron compounds by keeping them in a soluble form. These agents typically react with minerals to create salts, water and carbon dioxide;
  • Biocides/Bactericides:Biocides/bactericides such as quaternary amines, amides, aldehydes and chlorine dioxide, are added to prevent enzymatic attack of the polymers used to gel the fracturing fluid by aerobic bacteria present in the base water. In addition, biocides and bactericides are added to fracturing fluids to prevent the introduction of anaerobic sulphate reducing bacteria into the reservoir; and
  • pH buffers: pH buffers, such as sodium or potassium carbonate, sodium hydroxide, monosodium phosphate, formic acid and magnesium oxide, help maintain the effectiveness of other components. Buffers adjust the pH of the base fluid so that dispersion, hydration and crosslinking of the fracking fluid polymers can be engineered. Because some buffers dissolve slowly, they can be used to delay crosslinking for a set period to reduce friction in the tubing.

Ranking of fracking intensity

Different applications of fracking technology have much in common, but can be differentiated based on some of the physical aspects of fracturing, namely:

  • Fracture Creation/propagation:This deals with reason for performing the frack. Are we simply trying to determine the strength of the rock formation, are we trying to propagate fractures, or simply open and clean existing fractures?
  • Volume of Injectate:Here we consider the total volume of fracking fluid used, as well as the injection flow rate;
  • Nature of the Injectate:The composition of the injected fluid is regarded as one of the major differentiating characteristics;
  • Hydraulic Pressure:Here we consider the maximum hydraulic pressure applied to the rock formation during fracking;

Adams and Rowe (2013) proposed a new terminology based on these aspects to allow clear differentiation between the many different types of hydraulic fracturing operations. Unfortunately, this approach is not in widespread use, but could enable practitioners, regulators and the general public to make a distinction between the many different operations.  The terminology and approach for ranking the intensity of fracking is presented in Figure 2.

Terminology for ranking the intensity of fracking

 

Closing remarks

Hydraulic fracturing isn’t new, and has been practiced for more than 100 years. It’s been improved upon and renovated over long periods of time. The application of fracking to gas resources in shale formations and coal beds is a factor of rising energy cost.

There is continual progress in minimising the impact of fracking on the environment. The use of acids in the fracking process is being reduced, or stopped altogether. Hydrocarbon additives to water-based fracking fluid is being phased out and replaced by more environmentally acceptable alternatives.

Current research into fracking and the use of fracking fluids focuses on the use of cryogenic fluids such as liquid carbon dioxide and liquid nitrogen. Work on the use of supercritical carbon dioxide is also at an early stage.

References

Adams, J. & Rowe, C., 2013, Differentiating Applications of Hydraulic Fracturing.In proceedings of the International Conference for Effective and Sustainable Hydraulic Fracturing (HF2013) which was held 20-22 May 2013 in Brisbane, Australia.

Fink, J.K., 2013, Hydraulic fracturing chemicals and fluids technology. Gulf Professional Publishing, Waltham, MA.

FracFocus, 2019, Hydraulic fracturing: the process. Available from http://www.fracfocus.ca/en/hydraulic-fracturing-how-it-works-0/hydraulic-fracturing-process. Accessed on 1 September 2019.

Manfreda, J., 2015, The real history of fracking.Available from https://oilprice.com/Energy/Crude-Oil/The-Real-History-Of-Fracking.html. Accessed on 31 August 2019.

Morton, M.Q., 2013, Unlocking the Earth –  a short history of hydraulic fracturing, Available from https://www.geoexpro.com/articles/2014/02/unlocking-the-earth-a-short-history-of-hydraulic-fracturing. Accesses on 30 August 2019.

Smith, T., 2012, Is shale gas bringing independence?Geo ExPro Vol. 9, No 2, p47.

US EPA, 2015,Analysis of hydraulic fracturing fluid data from the FracFocus Chemical Disclosure Registry 1.0. EPA/601/R-14/003, United States Environmental Protection Agency.

 

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Comparison of Coal-bed Methane to Other Energy Resources

Comparison of Coal-bed Methane to Other Energy Resources

By Jurie Steyn

Introduction

Our team has been working on a coal-bed methane (CBM) to power project in Botswana for many months.  The other day, a colleague asked me just how clean an energy source CBM really is.  A simple enough question, but perhaps not so easy to answer.

The only way to do this, is to compare the environmental and social impacts of CBM to that of other, non-renewable, energy resources.  Even then, one must keep in mind that every energy project is unique in terms of scope, location and impact.  Any direct comparison of energy resources will thus depend on some level of generalisation.

Although there are many different energy resources, I’ve decided to limit my comparison to the following five:

  • Coal and coal mining;
  • Oil extraction from reservoirs;
  • Coal-bed methane (CBM) from coal seams;
  • Shale gas (SG) from shale formations; and
  • Conventional gas (CG).

In this article, I’ll describe each of these resources briefly, consider some energy predictions, give an overview of the approach followed for the comparison, and present the findings.  Having spent 40 years in the petrochemical and energy industries, I feel confident that I have the experience to attempt a comparison of this nature.

Energy predictions

Global economic growth is partly supported by population growth, but is primarily driven by increasing prosperity in developing economies, led by China and India (BP plc, 2019).  BP plc (2019), in their latest Energy Outlook, predicts a steady growth in primary energy consumption to fuel this growth over the next 20 years, in what they refer to as the Evolving Transition scenario, as shown in Figure 1.

Note: 1 toe = 1 ton oil equivalent = 1 metric ton of oil = 1.4 metric tons of coal = 1270 m3of natural gas = 11.63 megawatt-hour (MWh) = 41.868 gigajoules (GJ).

Figure 1:  Primary energy consumption by fuel (BP plc, 2019)

Coal consumption is expected to decline by 0.1% per annum over the period, with its importance in the global energy system declining to its lowest level since before the industrial revolution.  This is supported by the fact that it is extremely difficult to obtain finance for energy projects based on coal.

BP plc (2019) estimates that renewables and natural gas will account for almost 85% of the growth in primary energy.  Renewable energy is expected to grow at 7.1% per annum and is the fastest growing source of energy.  Natural gas, at 1.7% growth per annum, grows much faster than either oil or coal, and overtakes coal to be the second largest source of global energy by 2040.  Oil consumption is expected to increase at 0.3% per annum over the next 10 to 15 years, before plateauing in the 2030s.

Calculating the percentage, or share, contribution of each or the energy sources of the total energy demand, allows one to generate Figure 2. Figure 2 more clearly shows the actual and anticipated decline in the share of total primary energy of coal and oil. Figure 2 also shows the actual and anticipated rise in the shares of natural gas and renewable energy.  The natural gas share represents the total of conventional gas, coal-bed methane and shale gas.

Figure 2: Shares of total primary energy (BP plc, 2019)

Description of energy resources

Coal and coal mining

Coal is a solid fossil fuel that was formed in several stages as the buried remains of land plants that lived 300 to 400 million years ago were subjected to intense heat and pressure over many millions of years. Coal is mostly carbon (C) but contains small amounts of sulphur (S), which are released into the air as sulphur dioxide (SO2) when the coal burns. Burning coal also releases large amounts of the greenhouse gas carbon dioxide and trace amounts of mercury and radioactive materials.

Coal can be mined from underground mines using a bord and pillar approach, where pillars of coal are left standing to support the roof structure, or with a continuous miner, where all the coal in the seam is extracted and the roof is permitted to collapse behind the mined-out area.  Coal can also be mined from open-cast mines where the covering layers of topsoil and rock are removed by drag-lines to expose the coal seams for blasting and collection.  An alternative to the latter approach is strip mining, where the coal is sequentially exposed in narrow bands, to reduce the environmental impact.Geological conditions determine the most cost-effective method of mining. 

Mining is one of the most dangerous jobs in the world. Coal miners are exposed to noise and dust and face the dangers of cave-ins and explosions at work.  Note that in this comparison, only the environmental and social impacts of the mining, preparation and storage of coal are considered, not including the downstream impacts of coal utilisation.

Oil extraction from reservoirs

Crude oil is found in underground pockets called reservoirs. Oil slowly seeps out from where it was formed millions of years ago and migrates toward the Earth’s surface. It continues this upward movement until it encounters a layer of rock that is impermeable. The oil then collects in reservoirs, which can be several thousand meters below the surface of the Earth.  Crude oil is frequently found in reservoirs along with natural gas. In the past, natural gas was either burned or allowed to escape into the atmosphere.

Drilling for oil, both on land and at sea, is disruptive to the environment and can destroy natural habitats. Drilling muds are used for the lubrication and cooling of the drill bit and pipe. The muds also remove the cuttings that come from the bottom of the oil well and help prevent blowouts by acting as a sealant. There are different types of drilling muds used in oil drilling operations, but all release toxic chemicals that can affect land and marine life.  Additionally, pipes to gather oil, roads and stations, and other accessory structures necessary for extracting oil compromise even larger portions of habitats. Oil platforms can cause enormous environmental disasters. Problems with the drilling equipment can cause the oil to leak out of the well and into the ocean. Repairing the well hundreds of meters below the ocean is extremely difficult, expensive, and slow. Millions of barrels of oil can spill into the ocean before the well is plugged.

Sulphur is the most common undesirable contaminant of crude oils, because its combustion generates sulphur dioxide, a leading precursor of acid rain. ‘Sour’ oils have more than 2% of sulphur, while ‘sweet’ crude oils have less than 0.5%, with some of them (especially oils from Nigeria, Australia and Indonesia) having less than 0.05% S.

Most oil spills are the result of accidents at oil wells or on the pipelines, ships, trains, and trucks that move oil from wells to refineries. Oil spills contaminate soil and water and may cause devastating explosions and fires. Many governments and industry are developing standards, regulations, and procedures to reduce the potential for accidents and spills and to clean up spills when they occur.

CBM from coal seams

Methane recovered from coal beds is referred to as CBM and is a type of natural gas that is trapped in coal seams. CBM is formed by microbial activity during coalification and early burial of organic rich sediments (biogenic process) and by thermal generation at higher temperatures with increasing depth of burial (thermogenic process). Methane is held in the coal seam by adsorption to the coal, combined with hydrostatic pressure of water in the coal cleats (cleats are natural fractures in coal). Production is accomplished by reducing the water pressure, allowing methane to be released from the cleat faces and micro-pores in the coal.

Coals have moderate intrinsic porosity, yet they can store up to six times more gas than an equivalent volume of sandstone at a similar pressure. Gas-storage capacity is determined primarily by a coal’s rank. Higher-rank coals, bituminous and anthracite, have the greatest potential for methane storage. CBM is extracted by drilling wells into the coal bed of coal seams of up to 500 m deep, that are not economical to mine.

Concerns over CBM production stem from the need to withdraw large volumes of groundwater to decrease coal seam hydrostatic pressure, allowing release of methane gas.  This water may contain high levels of dissolved salts and must be treated. In some cases, the coal seam is stimulated by limited hydraulic fracturing in order to improve methane movement to the well. Surface disturbances, in the form of roads, drilling pads, pipelines and production facilities impact regions where CBM extraction is being developed.  Subsurface effects from typical CBM extraction practices must also be considered. Because of the shallow depth of many CBM basins, the potential exists that well stimulation may result in fractures growing out of the coal seam and affecting freshwater aquifers.

Proper environmental management practices can minimise the effects of CBM production and make it more socially acceptable.  Innovative drilling technologies reduce damage to the surface. Better understanding of the surrounding rock properties improves stimulation practices. These options, plus responsible management of produced water, will lessen the impact of CBM extraction on existing ecosystems.

SG from shale formations

Shale gas (SG) is a form of natural gas found in sedimentary rock, called shale, which is composed of many tiny layers or laminations. Gas yield per well is low compared to conventional gas wells and many more wells are typically required for the same volume of gas production. 

SG is extracted from shale formations of between 1 and 4 km below the earth’s surface.  Because of the low permeability of shale rock, SG wells are drilled horizontally along the shale beds and hydraulic fracturing (fracking) of the shale is always required to liberate the gas and create channels for it to flow through.  Fracking involves the injection of fracking fluid (water, sand, gel, enzyme breakers, surfactants, bactericides, scale inhibitors and other chemicals) at high pressure down and across the horizontally drilled wells.  The pressurised mixture causes the shale to crack.  The fissures so created, are held open by the sand in the fracking fluid. 

Fracking of shale rock requires much larger volumes and chemical loading than the hydraulic stimulation of CBM seams.  The vertical growth of fissures can be up to 100m, compared to 4 to 10m for CBM. However, SG is typically extracted significantly deeper than CBM and, provided the geology and hydrogeology of the region is understood and considered in the fracking process, this need not have any detrimental effects on the surface or the potable water aquifers.

Surface disturbances in the form of roads, drilling pads, pipelines and production facilities, impact regions where SG extraction is being developed. The expected life of an SG well is much shorter than that of a CBM well.

Conventional gas

Natural gas obtained by drilling into gas reserves, is referred to as conventional gas (CG), to distinguish it from CBM or SG (unconventional gases). CG is trapped in porous and permeable geological formations such as sandstone, siltstone, and carbonates beneath impermeable rock. Natural gas was not formed in the rock formations, but has migrated and accumulated there. Conventional natural gas extraction does not require specialized technology and can be accessed from a single vertical well.  It is relatively easy and cheap to produce, as the natural gas flows to the surface unaided by pumps or compressors.

Natural gas deposits are often found near oil deposits, or with oil deposits in the same reservoir. Deeper deposits, formed at higher temperatures and under more pressure, have more natural gas than oil. The deepest deposits can be made up of pure natural gas. Natural gas is primarily methane, but it almost always contains traces of heavier hydrocarbon molecules like ethane, propane, butane and benzene. The non-methane hydrocarbons are generally referred to as ‘natural gas liquids’ (NGL), even though some of them remain gases at room temperature. NGL are valuable commodities and must be extracted, along with other impurities, before the gas is considered ‘pipeline quality.’

The benefit of CG is that it is cleaner burning than other fossil fuels. The combustion of natural gas produces negligible amounts of sulphur, mercury, and particulates. Burning natural gas does produce nitrogen oxides (NOx), which are precursors to smog, but at lower levels than fuels used for motor vehicles.

Approach followed for comparison

Parameters for comparison

The different energy resources were compared using 12 different parameters divided into two categories.  The first category consists of environmental parameters, as follows:

  • Air Pollution: This covers dust generation, greenhouse gas emissions during production and contribution to acid rain;
  • Water pollution: This considers the potential impact of the operation on surface waters and the effect on water users;
  • Groundwater impacts:The potential for cross contamination of water aquifers and the depletion of groundwater sources and its impact on current users;
  • Soil pollution: Potential impact of the operations on soil quality and use.  Does it impact the ability of the soil to be used for irrigation and livestock farming;
  • Visual impacts: This considers the overall size, longevity, lighting and dust impact of the operation on passers-by;
  • Biodiversity: The potential impact of the operation on the surrounding ecosystems, flora and fauna.

The second category consists of social, and socio-economic parameters, as follows:

  • Health risks: Are health risks to the workers and community due to the impacts the operation, identified and properly understood, and can these be mitigated;
  • Noise impact: Is noise from the operation expected to be a nuisance to the surrounding communities
  • Worker safety: What is the safety performance of similar operations elsewhere in terms of worker fatalities and disabling injuries;
  • Cultural impacts: What is the potential of the operation to impact on areas of high cultural significance to indigenous people;
  • Infrastructure: What infrastructure (roads, schools, clinics, fire station, etc.) is required to support the operation and what will it contribute to the community; and
  • Job creation: How many direct and indirect jobs will result from the operation and how sustainable is it.  In this case, more is better.

Forced ranking

An approach of forced ranking was used, whereby the different energy sources were ranked from best to worst for each of the 12 parameters described above. The best performer for each parameter was given a score of one and the worst performer a score of five.  Those in between, were given scores of two, three and four, depending on their rank.

In exceptional cases, where the impact of two, or more, of the sources were considered to have comparable impacts, the individual scores in question were totalised and averaged.  In other words, if energy sources ranked in positions two and three were considered to have almost identical impacts, each would be allocated a score of 2,5.

Elimination of bias

In any comparison, the elimination of bias is essential.  One way to reduce bias is to evaluate the different options against many parameters, as was done with the 12 parameters described above. 

Another way is to use several assessors, say four to six, when doing the evaluation, and reaching consensus on the ranking.  However, in this case it was not done and therefore I’m the only one to blame if my findings do not correspond with your opinions.  I have tried to be as fair as possible in ranking the energy sources.

Discussion of findings

The results of the evaluation of the energy sources against the environmental parameters are presented in Figure 3 as a 3-D column chart.  Remember that the impacts are not given absolute values, but results based on the ranking process.

Figure 3: Environmental impact assessment for various energy sources

From Figure 3, it is obvious that coal and oil score badly in terms of impact on the environment.  This is followed by natural gas from different sources, with conventional gas assessed as having the least impact.  CBM has a lower environmental impact for most parameters than SG, but because it is accompanied by high yields of mostly saline water from relatively shallow wells, the impact on the water and soil could be greater.

The results of the evaluation of the energy sources against the social and socio-economic parameters are presented in Figure 4. From Figure 4, the picture is not so clear.  Coal and oil again score the highest for most of the parameters considered.  However, in terms of number of jobs created and associated infrastructure requirements, they score the lowest, which means they require more personnel (a positive) and infrastructure.  CG is considered more dangerous than CBM and SG, because of the higher operating pressure and the known cases of blowouts.

The cumulative impacts of the energy sources are presented in Figure 5. In this case, the total score for the six environmental parameters for each of the energy sources was calculated and plotted. Similarly, for the six social parameters.  Lastly, the total score as shown by the grey column in Figure 5 reflect the totals for the environmental impacts’ score plus the social impacts’ score.  Coal is shown to be the least desirable source, followed by oil, SG, CBM, and CG.

Figure 4: Social impact comparison for various energy resources

Figure 5: Cumulative impacts of energy sources

Concluding remarks

Natural gas remains the energy source with the lowest negative social and environmental impacts.  Therefore, natural gas, is estimated to grow at 1.7% per annum, i.e. much faster than either oil or coal, and overtakes coal to be the second largest source of global energy by 2040 (BP plc, 2019).  Natural gas is a combination of CG, CBM and SG.  CG recovery is the overall winner in this comparison with the lowest social and environmental impacts.  In the second position we have CBM, followed by SG.  Even though SG is normally recovered at greater depths than CBM, the extent of fracking required to release the methane in shale is significantly more extensive.

Next in line is oil recovery from geological reservoirs. This is understandable when one considers the oil-related environmental disasters we have witnessed.  Associated gas is also continuously flared from drilling operations.  However, low yielding (i.e. nearly emptied) oil reservoirs can be used as a suitable geological formation for storage of carbon dioxide.  The action of injecting carbon dioxide into a low yielding well will temporarily boost oil production from such a reservoir.

It comes as no surprise that coal is the energy source with the greatest negative impact on the environment.  In terms of negative social impact, it also rates the highest, but by a very small margin.  This result helps us understand the current furore over coal and the difficulty to obtain finance for coal-based projects.

References

BP plc, 2019, BP energy outlook, 2019 edition.  Electronic document available from https://www.bp.com/en/global/corporate/news-and-insights/reports-and-publications.html.Downloaded on 10 April 2019.

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