The Importance of Engineering Management

The Importance of Engineering Management

By Freek Van Heerden

Introduction

The role of the engineering manager in projects was previously described using the ten knowledge areas of the Project Management Body of Knowledge (PMBOK) as a reference (van Heerden, 2018). In that article the responsibility of the engineering manager in each knowledge area was discussed without any attempt to specifically differentiate or highlight the areas where the engineering manager is the lead contributor in comparison to the project manager.

In this article we address the areas where the engineering manager must take the lead for a project to be a business success. We consider key work processes and capabilities that will provide for successful engineering management.

A successful project

In order to understand the importance of an engineering manager on a project, it is necessary to firstly elaborate on what constitutes a successful project. In the literature, a successful project is typically described as a project that meets cost, schedule and production objectives within a specific margin of, say, +-5%. While meeting these objectives would imply that a project has been successfully implemented, it does not guarantee that the resulting venture would be an economic success. Developing a project that achieves sustainable business success is what a project is about, not just executing an agreed scope.

While these metrics (cost, schedule and production objectives) are surely a good measure against which to compare the project implementation outcome, there may be other results that contribute towards a successful project, specifically as far as the business owner is concerned.

During project framing discussions, we often use the project management triangle of cost, schedule and quality to agree the primary drivers of a project. Want it fast and cheap? No problem, but the final product won’t be very good. Want it good and fast? All right, but it won’t be cheap. During these discussions, the problem has always been that the business owner wants the project as fast as possible, as cheap as possible and with the best quality, while the project manager tries to clarify in his mind whether cost, schedule or quality was the primary driver.

Ward (2014) argues that this “pick any two” idea is not true. He states that: “Upon closer examination, we discover that what little data there is to support this position is largely of the nature of a self-fulfilling prophecy. We sacrifice one leg of the triangle because we believe we must, then look on our results as proof that the outcome was unavoidable. It does not have to be this way. There’s no need to pick only two.”

Ward (2014) argues that a successful project should be: Fast, Inexpensive, Restrained and Elegant, abbreviated to FIRE. These terms are further explained below.

  • Fast: Fast focuses on the schedule and expresses that it’s important and beneficial to have a short project schedule. The precise definition of what is a short timeline will naturally vary from project to project, but Fast is about defining project objectives that can be satisfied on a short timeline, not one we know will require forever to accomplish. Fast is about disciplined project execution and not about rushing ahead;
  • Inexpensive: Being Inexpensive means designing processes, plants and organisations with cost in mind. It involves “solving problems with intellectual capital instead of financial capital” (Ward, 2014). It is not about doing a project cheaply, but rather about getting real value for money;
  • Restrained: Restrained implies a preference for self-control in considering the absolute minimum technical solution for a project. It implies tight budgets, small bur efficient project teams, short meetings, and short documents. No non-essential luxury items or infrastructure will be tolerated;
  • Elegant: An Elegant design should be “pleasingly ingenious and simple” (Ward, 2014). Start by stating project goals clearly and then incorporate mature, proven technologies into the design. Truly elegant solutions to project challenges are often surprisingly simple. We may not be able to avoid complexity entirely, but we can take steps to minimise it.

Returning to the metrics of project success, we see that there are more than just schedule, cost and production objectives (i.e. product quality and plant throughput).  This is reflected in Figure 1, where we indicate the use of the ‘standard’ metrics, as well as the FIRE metrics for determining project success.  There is obviously some overlap between measures like Cost (a ‘standard’ metric) and Inexpensive (a FIRE metric).

If one then considers the above ideas on what constitutes a good project, one can start to visualise the importance of the role that the engineering manager plays in pulling together the engineering effort to deliver a successful project.

Figure 1:  Metrics of project success

The engineering manager

Opening remarks

It is the engineers on a project that define the project scope and other requirements, design the equipment and ensure that the required quality is met. They determine the level of complexity, the ease of project execution and the cost associated with the scope and quality/standards required.  Thus, engineers play a crucial role towards the eventual business success of the project.

In developing a project, the effort of the engineers should be directed, co-ordinated and focused toward achieving the business objectives and delivering a successful project. It is the engineering manager, as the leader of the engineering team, that bears the brunt of this effort. We deliberately use the term ‘leader’, rather than ‘manager’. The engineering manager on a project is normally not a direct functional line manager, but rather the conductor/co-ordinator of the engineers assigned to the project. The engineering manager needs to lead, inspire, negotiate, cajole and convince the different engineering disciplines, and sometimes their line managers, during the project life cycle, to maintain focus on the business and project objectives.

In executing his/her work, the engineering manager must focus on:

  • Team alignment: Visualise the business intent and contextualise the business requirements so that the team understands it fully;
  • Scope of facility: Synthesise the integrated facility scope within the boundaries of cost and schedule;
  • Engineering execution plan: Develop and implement an engineering execution plan as part of the overall project execution plan;
  • Technical risk management: Identify, assess, rank, and manage technical risks holistically; and
  • Philosophies, standards and specifications: Contract and ensure appropriate design philosophies, standards and specifications are set, and met.

The role of the engineering manager is illustrated in Figure 2.

Figure 2: Role of the engineering manager

Each of these roles is discussed in more detail below.

Team alignment

The engineering manager is typically the person that interfaces with the business owner. He/she must understand what the business owner wants to achieve and then translate that understanding into “engineering talk”. Very often a business owner has a rough idea or concept in his mind, but that does not translate into a defined and executable project. The engineering manager plays a pivotal role as the interface between “the business” and “the project”, translating and communicating between the two parties and managing the relationship.

In order to do this translation, the engineering manager must have a good understanding of what the drivers of the economic and operating models of the facility are. In this way, he/she is the person that ensures alignment of people’s thinking and the total engineering effort through all the project stages.

The engineering manager must ensure that his entire team of engineers understand the business objectives and project objectives, and establish alignment.

Scope of facility

A scope of facility must be developed that will meet the business needs. In FIRE terms, it needs to be Restrained, Inexpensive and Elegant and it needs to be done Fast. The proposed solution must delight the business owner. Only once a scope is in place can the project manager determine the cost and schedule. The engineering manager must understand the boundaries of cost and schedule that will make business sense and guide the engineering teams toward developing a concept within the boundaries of cost, schedule, quality, reliability.

The description of the facility must be broken down into a facility breakdown structure, supported by individual work packages with appropriate details. Operating safety and environmental requirements must be properly translated into the engineering scope. Each work package needs to be written up in detail, reviewed and approved by at least the engineering manager, the project manager and the business owner. This scope definition package forms the basis for the total project cost.

Achieving approval is crucial as it aligns everybody on what the project will actually deliver (and not deliver) and is a crucial document through which changes are managed and scope creep (and thus cost and schedule overruns) prevented. A proper definition of how engineering scope changes will be managed and controlled is an essential element for a successful outcome.

Managing the development of the scope of the facility towards an optimised solution requires consideration of the complete business value chain during front-end loading of the project. Various techniques to support this effort have been described in previous insight articles (Render, 2016; Steyn & Buys, 2017; van Heerden, 2017; van Heerden & Steyn, 2015). The engineering manager should continually be on the lookout for an Elegant solution, keeping it “pleasingly ingenious and simple”.

Engineering execution plan

The engineering execution plan lays out all the methods, procedures, milestones, decision points and decision makers, as well as the resources required to complete the engineering work. A well-developed plan is essential in completing the work Fast. Exercising Restraint during the development of the execution plan means ensuring resource requirements, tools and decision-making processes that would adequately support the overall intent of achieving a successful project and business venture.

All too often the front-end development is marred by indecision and recycling of concepts, under the guise of reaching a proposal that is both technically and economically feasible. This often adds many months to the front-end development that can be mitigated through a focused drive by the engineering manager, always keeping the business objectives and boundaries in mind.

Technical risk management

We’ve published several articles on how to identify, assess and manage technical risks holistically (Steyn, 2018a, 2018b & 2018c).

In the article Planning for project risk management, Steyn (2018a) states that. “[l]ife is uncertain, and projects are unique, complex in nature, based on assumptions and done by people. Projects are therefore subject to a plethora of uncertainties, i.e. risks and opportunities, that can affect the project and business objectives. Although the activity is normally referred to as project risk management, it covers both risk and opportunity management. Potential positive and negative outcomes deserve equal attention.”

If production is delayed through technical problems, either during construction or start-up, the slower ramp-up of the revenue can have a devastating impact on the project finances and even on the owner company itself. Proactive identification and mitigation of risks can go a long way towards securing the expected outcomes. Engineering managers use various techniques like potential deviation analysis, innovation assessments and decision analysis techniques to identify potential risks associated with for example planning, technology maturity and technology selection processes.

Philosophies, standards and specifications

Van Heerden, Kriel and van der Walt (2016) maintain that “quality should always be the point of departure for any work and that, if a quality product is delivered, it will support meeting the business objectives in terms of cost and schedule.”

In the article Fit-for-purpose specifications for project development and implementation, Thirion (2017) maintains that “[e]very project has unique objectives that must be met by the project manager, who achieves this by managing deliverables such as cost, schedule and technical integrity of the project. After project completion, the business operates, maintains, and finally decommissions the plant. Specifications should contribute during project execution to minimise cost and schedule, and deliver technical integrity, and during plant operations to meet operations requirements such as maintainability, reliability, operability, throughput, product quality and safety.”

Standards and specifications are often blamed for cost overruns in that projects appear to be gold-plated. Considering the business objectives in terms of the facility life, reliability, maintainability and operability the engineering manager needs to guide the engineering fraternity towards the development of fit-for-purpose specifications. In this exercise it is necessary to not just consider the initial capital investment, but also the impact on the total life cycle cost of the facility. An Elegant solution would be one where the correct balance has been struck that provides for an affordable initial capital cost as well as an overall life cycle cost that will support a sustainable business solution.

Once the project requirements are set and detailed design, manufacturing and construction commences, an engineering quality plan is required to ensure that the deliverable does in fact meet the agreed quality. A proactive and thorough quality assurance plan will enable non-conformities to be identified early on with enough time to correct the defects. If critical defects are only discovered late during construction, it inevitably leads to long delays in start-up and will have a serious impact on the viability of the business.

Concluding remarks

In this article, we’ve highlighted five key aspects where we believe engineering management should play the leading role during a project, namely:

  • An aligned and directed engineering team, focusing on delivering a facility that will meet the business intent;
  • A facility scoped such that it will deliver the required project at an affordable cost, reliably and at the right quality;
  • An effective engineering execution plan to complete the work in an efficient way with the correct resources and competencies;
  • A risk management process that will prevent sudden and unexpected surprises and predetermined contingency actions should something go wrong; and
  • A facility designed and constructed using fit for purpose specifications.

Engineering managers who focus on these aspects will, during the development and implementation of projects, prove their value and contribution towards successful projects.

References

Render, C.L. (2016) Technology selection. Available from https://www.ownerteamconsult.com/technology-selection/. Accessed 20 January 2020.

Steyn, J.W. (2018a) Introduction to Project Risk Management, Part 1: Planning for project risk management. Available from https://www.ownerteamconsult.com/introduction-to-project-risk-management-part-1-planning/.Accessed 20 January 2020.

Steyn, J.W. (2018b) Introduction to Project Risk Management, Part 2: Identify, analyse, action and monitor project risks. Available from https://www.ownerteamconsult.com/intro-to-project-risk-management-part-2-identify-action-and-monitor-project-risks/. Accessed 20 January 2020.

Steyn, J.W. (2018c) Quantitative risk analysis for projects. Available from https://www.ownerteamconsult.com/quantitative-risk-analysis-for-projects/. Accessed 20 January 2020.

Steyn, J.W. & Buys, C.P. (2017) Project optimisation techniques: Site Selection for Process Plants. Available from https://www.ownerteamconsult.com/site-selection-for-process-plants/. Accessed 20 January 2020.

Thirion, C. (2017) Fit-for-purpose specifications for project development and implementation. Available from https://www.ownerteamconsult.com/fit-for-purpose-specifications-for-project-development-and-implementation/.Accessed 20 January 2020.

Van Heerden, F.J. (2017) Value chain optimisation. Available from https://www.ownerteamconsult.com/value-chain-optimisation/. Accessed 20 January 2020.

Van Heerden, F.J. (2018) Introduction to Engineering Management. Available from https://www.ownerteamconsult.com/introduction-to-engineering-management/. Accessed 20 January 2020.

Van Heerden, F.J. & Steyn, J.W. (2015) Select topics in value engineering: Standardisation in the process industry. Available from https://www.ownerteamconsult.com/select-topics-in-value-engineering-standardisation-in-the-process-industry/. Accessed 20 January 2020.

Van Heerden, F.J., Kriel, D. & van der Walt, D. (2016)  The project management triangle conundrum: selecting between quality, cost, time.  Available from https://www.ownerteamconsult.com/the-project-management-triangle-conundrum/. Accessed 20 January 2020.

Ward, D. (2014) F.I.R.E. – How Fast, Inexpensive, Restrained and Elegant methods ignite innovation. HarperBusiness Publishers, New York.

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The Importance of Engineering Management

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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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The Importance of Engineering Management

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Beyond Capex – Future proofing your IT investment for sustainable value delivery

Beyond Capex – Future proofing your IT investment for sustainable value delivery

By Gavin Halse

Introduction

Digitisation (the process of incorporating digital technologies into all aspects of the business) has become necessary for industrial companies to remain competitive.  The International Data Corporation estimates that more than half of all technology spending will go towards digital transformations in the next four years (IDC, 2019). Those that don’t make progress are likely to find their businesses increasingly under threat from competition by organisations that have a lower cost base, are more agile/responsive and that provide better service to their customers.  Digital transformation is a top-down initiative with 23% of CEOs owning or sponsoring their company’s digital transformation initiative (Solis, 2019).

In theory, a green-field capital project offers a unique opportunity to leap-frog industry competitors and implement robust and future proof IT systems.  A new facility will not have to deal with the legacy IT systems that other companies are trying to get rid of.    Within an existing organisation, a smaller “brown-field” capital project can serve as a catalyst for implementing new digital technologies in other parts of the enterprise. Capital projects are inherently concerned with the relatively short-term objective of delivering a new facility on time and within budget.  However, the primary goal of the owner team is also to deliver business value.  When considering that the new facility will operate for many years, how can the project team deliver a facility that is future proof?

In this article, I explore Smart Manufacturing and Industry 4.0, and the way in which these trends are impacting manufacturing.  I also demonstrate that for a new business to be future proofed against digital disruption, it needs to develop the necessary digital capabilities from the outset.  This needs to take into consideration the total value chain, from raw materials to production, and ultimately to meeting customer needs.  This is a vast and complex subject and this article can only serve as an introduction.

Constraints during capital project execution

There are several reasons why the capital project environment is not conducive to developing the necessary digital capabilities for a new business.  Capital project organisations (owners, EPC’s and sub-contractors) are fully aware of the requirement. However, as recent as 2017, McKinsey & Company identified reluctance by capital project stakeholders to adopt modern digital technologies (Fuchs et al, 2017). Specifically, they were weak adopters of advanced analytics, automation, robotics, information modelling and advanced document management systems.

Companies in sectors from government to manufacturing significantly reduced costs by aggressively pursuing digital transformation initiatives. In general, capital project organisations have previously not had the mandate to lead this type of process.   Owner operators are left to bring in consultants or draw on other corporate resources where these exist.   Often this is late in the project.

Typical capital project methodologies are concerned with delivering a new facility within the constraints of cost, quality and time.    Once a capital project is underway, design changes can become very costly.  Successful capital projects need to stay focused on efficient execution and need to remain, to a certain degree, isolated from business disruption.  Between the time the project is initiated and commissioning of the facility, there will be several major innovations in IT.  The project environment follows a waterfall methodology that is very different to the rapid cadence required by agile methodologies needed by an operating business that wants to contain costs, while at the same time retaining and growing market share.

Industry 4.0 and Digital Transformation

Manufacturing is being transformed around the world by digitising the way that products are conceptualised, designed, made, consumed and serviced.  Digital technologies are also impacting the operations, processes and energy footprint of factories and supply chains (Ezell et al, 2018).

The concept has evolved with slightly different emphasis in different countries, but is usually referred to as ‘Industry 4.0’ or ‘Smart Manufacturing’.   Industry 4.0 originated in Germany and refers to the convergence of digital and manufacturing technologies.   Smart Manufacturing refers to “fully-integrated, collaborative manufacturing systems that respond in real time to meet changing demands and conditions in the factory, in the supply network, and in customer needs.” (NIST, 2018).

Digitisation refers to the application of fast evolving information and communications technology to every facet of the manufacturing value chain.  The cumulative result of digitisation programmes across industry is changing the nature of global competition.   This process takes place before, during and after the capital project.  The challenge is to align the project deliverables to take advantage of these trends.

There are several emerging technologies that underpin Industry 4.0 and Smart Manufacturing.  Boston Consulting Group (BCG, 2019) has identified nine technologies that are having the greatest disruptive impact on industrial production, as illustrated in Figure 1.

Figure 1:  Nine disruptive technologies that are transforming industrial production (BCG, 2019)

The problem during a capital project is to identify exactly how these disruptive technologies could impact on the future business.    While this responsibility is in the owner team, developing the detailed requirements could prove difficult until the plant is commissioned and fully operational.   However, it is possible to ensure that, at minimum, the necessary infrastructure, platforms and skills are in place for continued digitisation to take place post commissioning.

We’ll consider two of the nine disruptive technologies in Figure 1 in more detail, namely ‘The Cloud’ and the ‘Internet of Things’.

The Cloud and Internet of Things

The biggest shift in business systems since the 1970’s has taken place over the past five years with a proliferation of data that is available for analysis in the cloud.

The source of much of this data is a result of many low-cost intelligent devices/sensors throughout the value chain.  This is commonly referred to as the ‘Internet of Things’ (IoT).  In the industrial context we normally refer to the IIoT or the ‘Industrial Internet of Things’.  IIoT devices are autonomous, industry grade computing devices that are connected to the internet.  The IIoT compliments and extends the traditional SCADA (supervisory control and data acquisition) systems found in a typical factory.  Unlike SCADA, IIoT data is processed and analysed using internet services.  IIoT data is also accessible by business partners given the right permissions.   Cloud computing allows for significant processing power to process and analyse this data. Prior to 2010, the computing hardware and software to do this was simply not an option for the average company.

The application of IIoT on the factory floor is estimated to increase productivity in traditional factories by as much as 25% (Gerbert et al, 2015).  Yet, many capital projects develop their operating cost models without taking this into account.

Re-imagine the future of manufacturing

As mentioned, a capital project is ultimately responsible for delivering business value to the owner.  The external environment will likely change significantly over the years during which the facility operates.

In the USA and China (in particular), Industry 4.0 is strongly associated with new ‘smart products’, internet ‘platforms’ and the new business models that are based on them (Kagermann et al, 2016). Smart productsare products that are equipped with sensors that measure and feedback customer usage information to the manufacturer.  This enables proactive servicing/maintenance and facilitates data driven new product development.  The motor industry is already adopting this approach – certain model motor vehicles already report usage data to service centres allowing targeted preventative maintenance strategies, as well as alerting owners to overdue maintenance. Platforms refer to central hubs through which companies transact.  The trading hubs typically own very few assets.  The best-known consumer examples are Amazon, Uber and Airbnb.  Despite the lack of ownership of any significant capital assets, these organisations can be major market disruptors.

In other regions, the emphasis might be slightly different.   For example, in Germany “Industrie 4.0” also refers to the integration of digital factories with intelligent supply chains.  Having the lowest cost of production is no guarantee of success. In the future business competitiveness will also depend on the strength of the entire industrial supply chain (of which your company will only be a small part).

Future manufacturing is likely to also be characterised by a continued move away from making products to delivering products as a service.  This trend is called ‘servitisation’ and offers manufacturers a way in which to differentiate their offering from what would otherwise become a commodity (such as electricity, chemicals, etc.)  These value-added services will also require new organisational capabilities.

This growing need for more customised services will require agile, responsive end-to-end operations.   Not all companies are at the same maturity level in this regard.  Maturity levels range from basic computerisation through to adaptability, as shown in Figure 2 (Shuh et al, 2017), which illustrates the typical stages in a digitalisation development path.

Figure 2:  Typical maturity levels in a digitalisation process (Shuh et al, 2017)

Owing to the many dependencies it is of course not realistic for a new industrial scale business to start up at level 6.  More likely, a new facility will be commissioned at level 3.  What is important for the capital project team is to ensure the operation is equipped with the resources, capabilities and systems to evolve quickly through step 4 to 6 as the plant ramps up to full production.

Digitisation through the Project Stages

Project phases and stages

The OTC Stage-Gate Model for a typical industrial scale capital project, showing the recommended phases and stages of development, is represented in Figure 3.

Figure 3:   Phases and Stages of development of a typical capital project

Arguably the most important time to charter the digital future of the new facility is when the business is conceptualised, i.e. in the ‘Initiation’ phase at the start of the project.

The initiation phase starts with the identification of a new business opportunity.  This is the ideal time to consider the impact of smart manufacturing and Industry 4.0.  During the project execution phases, certain design philosophies will need to be incorporated into the plant, the control and automation systems and the business systems, as well as in the staffing structures and skills.  It becomes increasingly difficult as the project proceeds to retrofit these later.

During initiation there also needs to be some consideration of customer outcomes and not just defining the product specification.  It is important to engage with prospective customers to ensure that at the end of the project the venture will deliver the right product/service. I’ve spent five years working on one industrial scale capital project where attention to customer outcomes and not just the product specification would have made a significant difference to the business success.  Six years after commissioning it turned out (after significant losses were incurred) that we were able to make a better and far more profitable product for an adjacent market using mostly the same equipment.

During the early business development/conceptualisation stage, it is a good idea to study examples of digital factories within your industry.  It is also a good idea at this stage to engage experienced consultants from the industry who can educate, inform and facilitate this process.

Having accepted the inevitability of Industry 4.0, the business leaders/entrepreneur should also decide whether to commit to establishing a digital culture.  Part of this will be to identify the type of skills the business will require to be future proof (Shuh et al, 2017). Bringing these skills into the project as early as possible is a good idea.

Opportunities for digital advantage across the value chain

In this section, I will identify some practical examples of areas across the business value chain where digitisation can be incorporated. A very simplified representation of a typical manufacturing value chain is given in Figure 4.

The following areas in the value chain are likely to have the greatest short-term impact by digitalisation (Adapted from MGI, 2015).

  • Operational efficiency / digital twin models: Use a digital twin model to run scenarios to optimise production, e.g. using IIoT together with SCADA data to centrally or remotely optimise operations;
  • Predictive and preventative maintenance: Through continuous monitoring and using predictive analytics, determine in advance when maintenance will be needed;
  • Intelligent supply chain: Data driven artificial intelligence-supported demand planning, forecasting and scheduling;
  • Logistics and distribution: Using IIoT to track materials in transport. Measure real-time inventory levels through the manufacturing process and combining with third party data (e.g. a 3PL or 4PL provider) for logistics optimisation; and
  • Health and safety: Real time tracking of workers and equipment when they move into dangerous areas or perform dangerous work.

 

Figure 4:    A typical value chain showing areas where digitisation could apply

Embedding digital systems into the new business

Industry 4.0 requires a level of integration across the value chain that sets a new bar in terms of system integration.  The business systems need to be horizontally integrated across the value network; and at the same time vertically integrated into the company’s internal business processes.  When designing a digitally resilient business, it is necessary to engineer the end-to-end digitalisation of the entire value chain (Kagermann et al, 2016).

In practical terms, this could mean that operational data from machines on the factory floor, warehouse management systems, logistics and transport systems is combined with data from adjacent (upstream and downstream) operations to provide real-time intelligence.  In some cases, the upstream and downstream data will belong to organisations outside the factory boundary.

This also means that traditional business systems such as supply chain management (SCM), enterprise resource planning (ERP) & customer relationship management (CRM) need to be connected to the plant as well as the systems of business partners and customers in a way that information becomes visible along the entire value chain.  Every system, technology and platform therefore need to be carefully selected during the capital project to enable this integration.

Incorporating digitalisation in the design philosophies

At the outset it is important that the digital strategy is incorporated into the design philosophies for the plant.  During the project the EPC and sub-contractors need to be aware of these requirements and take them into account when specifying equipment.  When the project is handed over, these philosophies will become baked into the operation and hard to change, making it important to get right up front.

The following are some considerations that should be considered when developing the design philosophies:

  • Create the connected enterprise: Design a robust and scalable IT infrastructure that is suited for the large data volumes anticipated in future.  Decide how you will secure the networks and mitigate against cyber-threats.  Decide how you will manage cloud aspects such as data sovereignty, security, flexibility, reliability and scalability;
  • Standardise on core technologies: Develop a standard for your core platforms (operating systems, databases, intranets, cloud servers and middleware). Develop standards for desktop computers, mobile devices and edge computing devices;
  • Next generation control, automation and business system design: Develop a unified enterprise architecture that will incorporate control and automation systems together with business systems. Select control and automation systems like PLC’s, DCS and SCADA that are cloud/IIoT ready and that conform to your architecture standards. Address data storage, automated data analysis (including AI), contextualised information delivery and visualisation/reporting. Decide how you will simplify and standardise task specific user interfaces to provide a common workflow and real-time capability across the business;
  • Decouple systems for maximum agility: Decide on whether you will implement an integrated system from a single vendor or whether you will utilise best-in-class applications. Decide on whether you will develop any in-house software applications or use only “off the shelf” software. Decide which specialised/unique software applications are necessary to provide you with a competitive advantage. Decide how you will incorporate open industry standards allowing for substitution in future. Decide how the business systems are to be implemented at enterprise, business and business unit level – i.e. implement as separate systems, or in a common, integrated system;
  • Ensure you have the appropriate experience, skills and expertise: Decide how you will select suitable vendors to be your strategic partners. Decide on which capabilities you will need to build in-house, and which can be outsourced. Pay attention to attracting and retaining digital skills in the organisation. Decide how the OT (operational technology) and IT (information technology) functions will be structured to work to a common set of objectives; and
  • Design for ‘planned obsolescence’: Decide how you will manage evolving open-source software within your systems. Decide how you will manage upgrades and planned obsolescence of technologies. Decide how to avoid proprietary solutions that results in vendor lock-in.

The fast-moving technological landscape will be difficult to exploit with in-house skills only.  It is important to decide on your IT outsourcing strategy early on for the following reasons:

  • Specialist skills: Outsourced specialised partners are more likely to have access to specialised information and communication technologies (ICT) skills and are exposed to industry best practices;
  • Career opportunities: Career development of IT professionals within your organisation may be restricted – an outsourced partner may provide the necessary opportunities;
  • Business focus: By outsourcing specialised IT functions, you can focus more on your business; and
  • Advisory function: A well-managed outsourcing relationship should result in you having access to a trusted advisor to the business.

However, a certain level of in-house expertise will also be required.   This might mean retaining in-house business analysis and development capabilities.

Closing Remarks

It has only been possible in this article to scratch the surface on the topic of digitisation, smart manufacturing and Industry 4.0.  However, it should be evident that digital needs to be incorporated early on into all aspects of projects having a long-term strategic outlook.

Industry 4.0 and smart manufacturing are relatively new concepts and it is still early days. There are many obstacles towards realising the full potential of these technologies, not least of which are legacy systems and entrenched practices in existing companies.  Other obstacles include lack of awareness, internal expertise, informed leadership and skills.

A project can only practically deliver a sub-set of the overall business requirement.  At some point an operator will take over the facility and become responsible for continuing to innovate along the digital path.  One major responsibility of the owner team is to ensure that this new business is adequately structured and empowered with the skills and technologies to be able to adapt and thrive in this environment.

References

BCG (Boston Consulting Group). (2019) Embracing Industry 4.0 and rediscovering growth.  Available at https://www.bcg.com/en-za/capabilities/operations/embracing-industry-4.0-rediscovering-growth.aspx. Accessed on 19 November 2019.

Ezell, S, Atkinson, R, Kim, I & Cho, J. (2018) Manufacturing Digitalization:  Extent of Adoption and Recommendations for Increasing Penetration in Korea and the U.S. Available at http://www2.itif.org/2018-korean-manufacturing-digitalization.pdf?_ga=2.55240739.942153429.1574144816-272321115.1574144816. Accessed on 19 November 2019.

Fuchs, S., Norwicke, J. & Strube, G. (2017) Navigating the Digital Future:  The disruption of capital projects.Available at https://www.mckinsey.com/industries/capital-projects-and-infrastructure/our-insights/navigating-the-digital-future-the-disruption-of-capital-projects. Accessed on 19 November 2019.

Gerbert, P., Lorenz, M., Rüßmann, M., Waldner, M., Justis, J., Engel, P. & Harnisch, M. (2015) Industry 4.0: The future of productivity and growth in manufacturing industries. Available at https://www.bcg.com/en-za/publications/2015/engineered_products_project_business_industry_4_future_productivity_growth_manufacturing_industries.aspx  Accessed on 19 November 2019.

IDC (International Data Corporation), (2019) Worldwide Spending on Digital Transformation Will Reach $2.3 Trillion in 2023, More Than Half of All ICT Spending, According to a New IDC Spending Guide. Available at https://www.idc.com/getdoc.jsp?containerId=prUS45612419. Accessed on 25 November 2019.

Kagermann, H., Anderl, R., Gausemeier, J., Schuh, G. & Wahlster, W. (Eds.) (2016) Industrie 4.0 in a Global Context. Strategies for cooperating with international partners.  Pdf document available from https://www.acatech.de/wp-content/uploads/2018/03/acatech_eng_STUDIE_Industrie40_global_Web.pdfAccessed on 19 November 2019.

MGI. (McKinsey Global Institute) (2015) The Internet of Things: Mapping the value beyond the hype.  Pdf document available from https://www.mckinsey.com/~/media/McKinsey/Industries/Technology%20Media%20and%20Telecommunications/High%20Tech/Our%20Insights/The%20Internet%20of%20Things%20The%20value%20of%20digitizing%20the%20physical%20world/Unlocking_the_potential_of_the_Internet_of_Things_Executive_summary.ashx. Accessed on 19 November 2019.

NIST (National Institute of Standards and Technology). (2018) Product definitions for smart manufacturing.Available at https://www.nist.gov/programs-projects/product-definitions-smart-manufacturing. Accessed on 19 November 2019.

Schuh, G., Anderl, R., Gausmeier, J., ten Hompel, M & Wahlster W. (Eds.) (2017) Industrie 4.0 Maturity Index – Managing the digital transformation of companies. Pdf document available from  https://en.acatech.de/wp-content/uploads/sites/6/2018/03/acatech_STUDIE_Maturity_Index_eng_WEB.pdf  Accessed on 19 November 2019.

Sollis, B. (2019) The state of digital transformation: Digital is an enterprise-wide strategic priority — but there’s work to be done. Available at https://insights.prophet.com/the-state-of-digital-transformation-2018-2019, Accessed on 25 November 2019.

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Crude Oil Market Dynamics 2019

Crude Oil Market Dynamics 2019

By Anton Putter

OTC published a series of three articles in early 2015 on the international crude oil market and price (Putter & Buys, 2015). This article is an update and follow-up on the 2015 articles.

We thought now would be an opportune time to give an update on what transpired in the oil markets over this intermediate period of 4½ years and take stock of what this might mean for oil markets into the future.  Readers who have not read the original articles are encouraged to do so. This article builds on information provided in those articles and we’ve tried to eliminate unnecessary repetition where possible

Introduction

The previous series of articles (Putter & Buys, 2015) were written shortly after the collapse in oil prices from above $100/bbl in middle 2014 to $45/bbl in early 2015.  Eventually the oil price decreased to below $30/bbl in early 2016, before gradually recovering to the current level of between $60 and $70/bbl.

The oil market and oil pricing into the future is highly relevant to the liquid fuel and petrochemical industry, especially as far as project investments are concerned.  Projects in these industries are very capital intensive and medium to long term oil pricing is critical in the assessment of these project investments.

Developments since the previous articles necessitated an update and follow-up, especially considering the recent attacks on Saudi Arabia oil facilities and the ongoing global environmental protests against fossil fuels. Current oil market dynamics are similar to the situation in early 2015.

In this article more information is provided on those factors impacting the oil market, with emphasis on those that have undergone changes over the past five years.  The factors covered are:

  • Climate change and energy needs;
  • OPEC influence;
  • USA shale oil;
  • Political impact and social unrest;
  • Conventional oil supply constraints; and
  • Upstream investment.

Oil price

The article starts with an update on oil pricing and some pointers on future oil pricing are provided under the closing remarks.

A graph showing the oil price from 1861 to 2018 is available in the BP Review of World Energy 2018 (BP, 2019).  This graph showed periods of stability, but mostly demonstrated the high level of volatility in the oil price over its history.  For this discussion, we’ll focus on the oil price fluctuations over the past 10 years, as shown in Figure 1.

Figure 1: WTI oil price from 2009 to 2019 in $/bbl (Macrotrends, 2019)

Reaching extremes of $26/bbl and $110/bbl over the last 10 years, the oil price continued to exhibit the high volatility experienced since the Yom Kippur War in 1971.  There is no reason to believe that this volatility will stop anytime soon.  All the factors driving the volatility remain in place.

The rest of the article focuses on the factors impacting the oil market, especially those factors where some change has occurred over the past five years.

Climate change and energy needs

Over the past five years there has been further global acknowledgement of climate change and the role that fossil fuels are playing in such climate change.  This is witnessed by the Paris Agreement signed in 2016 which aims to contain the rise in global average temperature to 1.5 °C above pre-industrial levels.  By middle 2019, 195 members of the United Nations had signed the Paris Agreement.

Despite this increased focus on oil’s contribution to carbon dioxide (CO₂) emissions, there has not been any noticeable change in the patterns of oil consumption.  Since the 2015 articles, the global oil consumption has grown from 93 million bbl/day to 100 million bbl/day by the end of 2018.  This growth over four years was slightly higher than the upper end of the range predicted previously of 1 to 1.5 million bbl/day growth per year.  The main reason for this growth in oil demand is the growth in world energy demand and the inability of renewable energy to provide this additional demand at present.  This is illustrated in Figure 2, showing global primary energy consumption over the past 25 years.

Figure 2: Global primary energy consumption (BP, 2019)

It is clear from Figure 2 that the world’s energy demand is still growing strongly (by 2.9% in 2018).  As shown in the previous series of articles, this energy demand is closely related to global GDP.  While the global GDP is on the increase (mainly driven by developing nations such as China and India), the energy demand also grows.  With renewable energy still only a small proportion of overall energy needs, even the spectacular growth of renewable energy cannot yet supply the incremental growth in energy needs, and the demand for fossil fuels will grow into the foreseeable future.

The constraints in growth of renewable energy is clearly demonstrated in Figure 3, which shows the relative fractions of global primary energy supply.  Despite the emphasis on renewable energy over the past 20 years, its contribution to global energy needs has still not reached 5%.  Over the past 10 years the annual growth in renewable energy has approximately been 15% per annum.  To reach a contribution of 20% to global energy needs (a level at which 15% annual growth in renewable energy should satisfy the annual incremental growth in total global energy needs) will take another 15 to 20 years.

Figure 3: Shares of primary energy consumption (BP, 2019)

Amongst the fossil fuels, most of the environmental pressure is on coal, and the consumption of coal has now roughly stabilised (with peak consumption probably achieved in 2013), with noticeable decreases in coal consumption expected by 2030.  The bulk of the world’s coal demand is consumed in electricity production, and the growth in electricity demand (3.7% in 2018) is currently made up from growth in gas consumption (overall gas demand grew by more than 5% in 2018) and growth in renewable electricity (14.5% growth in 2018, but off a low base).

Very little oil, or oil derivatives, is used for electrical power production and therefore oil demand is not much impacted by coal consumption decreases.  Oil mostly finds its way into the transportation industry, and today oil-derived fuels still dominate this industry.  Some replacement by natural gas is occurring and a lot of publicity is given to the fledgling electric car industry (with the electrical power for these electric cars then presumably generated from renewable energy sources).  This also highlights another important perspective on oil consumption relative to greenhouse gases: two factors must be simultaneously in place to reduce CO₂emissions from oil:

  • The number of electric vehicles must grow exponentially in replacing internal combustion engines, and
  • The electricity for these electric vehicles must predominantly come from renewable energy.

It would not contribute to greenhouse gas emission reduction if all internal combustion engines are being replaced by electric vehicles, but the electrical power for these electric vehicles come from coal-fired power stations, or even gas-fired power stations.  Similarly, ineffective would be the situation where all electricity is generated from renewable sources, but there is little or no replacement of internal combustion vehicles by electric vehicles.

An important aspect of environmental pressure on fossil fuels emerging over the past couple of years, concerns the investment in fossil fuel companies and financing of fossil fuel projects by international financial groups.  This culminated in the launching of the Principles for Responsible Banking on 22 September 2019 (UNEP, 2019).  The objectives of this initiative is probably best summarised in the words of the Executive Director of UNEP: “A banking industry that plans for the risks associated with climate change and other environmental challenges can not only drive the transition to low-carbon and carbon-resilient economies, it can benefit from it. When the financial system shifts its capital away from resource-hungry, brown investments to those that back nature as solution, everybody wins in the long term” (DBP, 2019).  Up to now, these Principles for Responsible Banking have been signed by about 130 international financial groups including Barclays, Citigroup, UBS, ABN Amro, Eurobank, Deutsche Bank, ING, and BNP Paribas.  Amongst the 30 banks that led the development of the Principles for Responsible Banking were two South African banks, namely Standard Bank and FirstRand.

It is becoming increasingly clear that it will be very difficult to achieve the objectives of the Paris Agreement on Climate Change by relying exclusively on renewable energy growth and improvements in energy efficiency.  Examples of  additional measures that could make a contribution to reduce the CO₂ concentration in the atmosphere, are nuclear power generation, the “greening” of the planet to absorb more CO₂ into vegetation, and the capturing (before or after emission) of CO₂ and sequestration thereof.  Successes with either of the last two options could bring some relief to the increasing pressure on fossil fuels.

OPEC influence

The Organisation of the Oil Exporting Countries (OPEC) remains a strong influence in global oil supply and plays an important role in balancing oil supply and demand.  Over the past 5 years the percentage of oil supplied by OPEC has decreased somewhat with the amount of oil supplied today (roughly 30 million bbl/day) unchanged from five years ago, but the overall global supply having grown from 93 to 100 million bbl/day.

Compared to the production of five years ago, there has been some movements in the production of the individual OPEC members.  Today there is significantly less oil produced by Iran (close to 3 million bbl/day less), and Venezuela (about 1.5 million bbl/day less).  Both declines are as a result of politics and sanctions, but there is a difference in that Iran’s oil production can quickly recover in case of sanctions being lifted, while Venezuela’s oil industry has suffered permanent damage and will take many years to recover.  These declines have largely been made up from increases in Iraqi oil production (about 1.5 million/day) and higher utilisation of the capacity of Saudi Arabia, UAE and Kuwait.  The net result is that OPEC today has appreciably less excess capacity in their system than was available in middle 2014.

The biggest impact of OPEC over the past five years was the attempt from late 2014 to early 2016 to slow down the development of the shale oil industry in the USA by flooding the world market with oil and forcing oil prices down.  The impact of this is clear from Figure 1, with oil prices crashing from over $100/bbl to less than $30/bbl within the space of 18 months.  In early 2016, OPEC reverted to their traditional approach of reducing output to balance the supply demand balance of the market.  The experiment of flooding the market with oil had a limited impact on the growth in the USA shale oil industry, but had a longer-term impact in reducing the oil price. Even today there is still an overhang of oil stocks built up during that period.  Additionally, the period of low oil prices has discouraged many oil development investments and the impact of that is still to be seen into the future.

Another result of the OPEC overproduction from end 2014 until early 2016, is that there is today appreciably more cooperation between OPEC and some non-OPEC members in balancing the world oil market.  This is especially significant in the case of Russia, one of the three large oil producers in the world.  Nowadays Russia often attends OPEC meetings and cuts back oil production in consultation with OPEC (mainly Saudi Arabia).  This has contributed significantly in stabilising the oil markets after the turmoil of the oversupply period.

Over the past five years there have been some changes to the membership of OPEC, but these are small oil producers and had a limited impact on the organisation.  Currently there are 14 members (soon to reduce to 13) compared to the 12 members five years ago.  The new members are Gabon (2016), Equatorial Guinea (2017) and Republic of the Congo (2018).  Qatar left the organisation in early 2019 and Ecuador has announced that it will leave OPEC at the start of 2020.

Oil revenue remains the main source of income for most of the OPEC members.  This revenue reduced significantly over the past five years (from $1 trillion in 2013 to less than $0.5 trillion in 2016 and $0.7 trillion in 2018), as demonstrated in Figure 4.

Figure 4: OPEC oil export revenue (IEA, 2019)

This decrease in revenue had severe impacts on most OPEC members and necessitated reactions such as shrinkage of government expenditure, reduction in social support programmes and infrastructure development, and reduction or elimination of fuel subsidies within those countries.  In many cases this led to political upheaval and social unrest as clearly evidenced in Venezuela, Libya, Algeria, Nigeria, Ecuador and even to some extent in Saudi Arabia.

Saudi Arabia has had a strategy of diversifying out of its dependence on the oil industry for at least 10 years.  This has led to big infrastructure and other expenditure with a high demand for capital.  Especially in the light of the decreasing oil revenue as discussed in the previous paragraph, Saudi Arabia has embarked on a process of partial privatisation of its oil and related assets. Over the past couple of years, the focus has been on the listing of ARAMCO (Saudi’s national oil company), but the first transaction executed was actually the sale of SABIC (Saudi’s main petrochemical company) to ARAMCO in early 2019.  Both these transactions somewhat lifted the lid on closely guarded information of the Saudi Arabia oil industry; firstly, via the initial prelisting statement of ARAMCO published in 2018 and secondly via the bond prospectus issued by ARAMCO during the financing of the SABIC transaction.  Some of the more pertinent information made available, include the following:

  • The royalty rate on Saudi oil production is a progressive royalty (based on Brent prices) of 20% up to $70/bbl, 40% between $70 and $100/bbl, and 50% above $100/bbl. As part of the initial purchase offering (IPO) and to boost the capitalisation value, the first royalty bracket might be reduced to 15%.
  • Previously the tax rate on ARAMCO was 80%; in preparation for the IPO this has now been reduced to 50%.
  • The average extraction cost of oil is $2.8/bbl and the upstream capital expenditure in 2019 equated to $4.7/bbl.
  • Surprisingly, the production from Ghawar is only 3.8 million bbl/day, appreciably lower than the previously assumed 5 million bbl/day. Not only does this confirm that Ghawar (and possibly many of the other older and bigger oil fields in OPEC) have entered the declining phase of the Hubbert curve), but it also casts some doubt on Saudi Arabia’s claimed spare production capacity.

USA shale oil and other new sources of oil

By far the biggest contribution to oil supply growth in the world over the past five years has come from the USA, and predominantly from the growth in shale oil.  As shown in Figure 5, the USA oil production increased by almost 7 million bbl/day, which is the bulk of the total demand growth in the world over this period.  This is phenomenal growth in production and the increase from 2017 to 2018 of 2.2 million bbl/day is the largest ever annual increase by a single country and leaves the USA today (with production of over 12 million bbl/day) as the country with the largest oil production in the world.

Figure 5: USA oil production (IEA, 2019)

The bulk of this growth in USA oil production has come from shale oil production with offshore (primarily Gulf of Mexico) oil production contributing less than 1 million bbl/day.  Furthermore, almost half of this growth in shale oil production came from growth in the Permian basin as demonstrated in Figure 6.  The annual production in the Permian of over 4 million bbl/day also then makes the Permian basin the largest single producing oil field in the world, surpassing the 3.8 million bbl/day produced by Ghawar in Saudi Arabia.

Figure 6: Permian oil production (IEA, 2019)

There are widely varying forecasts of future USA oil production.  At the basis of this uncertainty is the high speed at which new shale oil production wells can be brought online and the exceptionally high decline rates for these shale oil wells.  There seems to be consensus that shale oil production in the USA will peak at some stage, although the predicted dates for this varies from imminently, to only after 2030.  Several factors will play a role here, some of them itemised below:

  • Oil price: The common wisdom is that shale oil operators in the USA are losing money at current oil prices, with the industry in total never showing positive cash flow on an annual basis (mainly as a result of the fast development and high development costs);
  • Consolidation of industry: Over the past several years, there has been substantial consolidation in the shale oil industry, mainly as a result of the oil majors buying out the smaller operators.  The more conservative financial management of these large multinationals has slowed down the break-neck speed of shale oil development, as evidenced by the decline of the total number of drilling rigs in the USA from just below 1100 to about 850 over the past year; and
  • Limit of shale oil productivity improvements: Apparently the limit of how much oil can be produced from a single well and how fast these wells can ramp up, has now been reached.  Initial production rates over the first 30 days of a shale oil well’s life (IP-30 rates) were routinely increasing by up to 40% per year for most of the past decade.  This has slowed to 11% in 2017, 15% in 2018 and only 2% so far in 2019.  Interestingly, IP-90 rates have started declining in 2019.  Reasons for this turnaround include increasing interference amongst parent-child wells; limits to the extent of horizontal drilling, fracking and sand injection; and the declining impact of initially only drilling a parent well (in order to retain a lease) followed much later by the lower-producing child wells. Parent wells typically produce 10 to 40% more oil than child wells.

In the medium term, the future of shale oil in the USA will be determined by what happens in the Permian basin.  The production from Permian has not peaked yet, but Figure 6 shows that the rate of growth has slowed down.  This is confirmed by Figure 7, showing the year-on-year increases for Permian.

Figure 7: Permian year-on-year growth (IEA, 2019)

Although the current information and trends do indicate an imminent slowdown in USA shale oil production growth, this can again change very quickly due to the volatile nature of this part of the oil industry.  A trigger that could for example reverse the current slowdown in shale oil development, would be a significant oil price increase (to above $80/bbl for a minimum period of say a quarter).  Further potential positive factors for shale oil development are other fields still to be developed in Texas, New Mexico and northern Mexico.  In the rest of the world, there is limited potential for shale oil development in Argentina and China.

Over the past five years the biggest development other than shale oil, has been the deep-sea oil discovered off the coast of Guyana.  The first major announcement was made in May 2015 when Exxon announced the success of the Liza well in the Stabroek block.  Since then, more than 10 successful wells have been drilled in the Stabroek block with expected oil recovery from those wells at over 6 billion bbls.  Earlier in 2019, a successful well was also drilled in the Orinduik block and further discoveries are expected in the Guyana Suriname basin. Exxon expects to produce more than 750 000 bbl/day of oil from the Stabroek block by 2025 with the first oil to flow in early 2020.

Political impact and social unrest

Over the past five years, politics continued to have an impact on oil supply.  Many of these incidences are well-known and will not be elaborated on here.  In general, this led to a reduction in oil supply and it is expected to continue to impact oil supply negatively, at least into the medium term.  This includes the aftermath of the Arab Spring (still very influential in Algeria and Egypt), sanctions by the USA against Iran and Venezuela, rebuilding of Iraq oil production after two destructive wars, internal strife in Nigeria and Libya, and so on.

The political disagreement with the biggest potential impact on oil supply, is the ongoing and escalating conflict between Saudi Arabia and Iran.  Up to now, this has led or contributed to the brutal war in Yemen, the breakdown in relations between Saudi Arabia and Qatar (including sanctions imposed against Qatar by Saudi Arabia and some of its Arabian allies and the resignation by Qatar out of OPEC), attacks on oil and fuel carriers travelling through the Persian Gulf and the recent attacks on oil infrastructure within Saudi Arabia. The biggest threat of this conflict is disruption of tanker traffic in the Persian Gulf through which 20% of the world’s oil supply passes.

Closely linked to political upheaval is the impact of social unrest.  This was exacerbated over the past five years by the dramatic decline of the oil price through 2015 and 2016, and the resultant significant cutback on social programmes, infrastructure development and other government expenditure.  A typical example of this is the recent development in Ecuador where the country’s finances deteriorated to the point where emergency funding had to be obtained from the International Monetary Fund (IMF).  One of the conditions of this funding was the removal of fuel subsidies which led to a doubling of diesel prices in Ecuador and initiated substantial social unrest.  Within days after the start of the social unrest, Ecuador’s normal oil production of close to 550 000 bbl/day had been reduced by 300 000 bbl/day, Ecuador declared force majeure on all its oil export contracts, and Ecuador announced its intention to resign out of OPEC.  Since then an agreement has been reached between the government and the protesters to stop the protests in exchange for the discontinuation of the implemented austerity measures, but this is not a permanent solution.

Conventional oil supply constraints

As highlighted in the 2015 set of articles (Putter & Buys, 2015), it seems like conventional oil production (defined as on-land and in shallow water up to 200m deep) has peaked at about 80 million bbl/day.  This peak was already reached in 2005 and currently conventional oil production is still close to this peak.  This extended plateau is made possible by OPEC’s actions to contain oil supply (with almost all of OPEC’s oil supply originating from conventional oil).  At some stage the decline in conventional oil production will commence and put substantial pressure on unconventional oil sources to meet global demand.

The 7 million bbl/day growth in demand of oil over the period 2014 to 2018 was all supplied by unconventional oil.  The bulk of this growth was supplied by USA shale oil (2.7 million bbl/day) and deepwater oil (1.4 million bbl/day) as shown in Figure 8.  Also clear from this graph is that Rodger (2019) expects this growth in shale oil and deepwater production to continue for at least another four years.

Figure 8: Shale oil and deepwater oil output (Rodger, 2019)

Other major contributions to unconventional oil supply over this four-year period came from biofuels (roughly 1 million bbl/day), natural gas liquids (1.9 million bbl/ day) and tar sands crude (0.3 million bbl/day).  The contribution from tar sands was low due to limits imposed by the Alberta government on crude production in 2018 in order to relieve some pressure on the outgoing logistics systems.

Another factor causing increasing concern regarding future conventional oil supplies, is the resource replacement ratio.  As shown in Figure 9, the replacement ratio for conventional oil dropped to 21% in 2018.  This means that only one barrel out of every five consumed is being replaced by new resources. An even lower ratio is expected for 2019.

Figure 9: Replacement ratio conventional oil (Rystad Energy, 2019)

Upstream investment

The main reason for the dramatic decline in replacement ratio, is the limited investment in the upstream oil and gas industry.  According to Wood Mackenzie (2018), the industry needs to spend at least $600 billion per annum to meet future demand, which would be an increase of over 20% on current investment levels.  Other analysts such as the IEA (2019) estimate the future development cost requirement as high as $750 to $800 billion per annum, the level achieved in 2014 when the oil price exceeded $100/bbl.  Figure 10 below shows the dramatic reduction in investment since then.

The long-term forecast provided in the World Oil Outlook, as shown in Table 1, seems to be representative of various other market opinions, at least until 2035.  This indicates that another 10 million bbl/day of oil will need to be added to world supply over the next 15 years.  Then unconventional oil supply would have to grow by at least 50% over this period.  Especially since shale oil is expected to be only a fraction of this, the upstream expenditure will be much higher than has traditionally been the case.  Upstream investment in sources such as deepsea oil, biofuels and heavy oil processing (tar sands or Orinoco heavy oil) are substantially higher than in the case of conventional oil.

Figure 10: Investment in upstream oil and gas (IEA, 2019)

Table 1: Long-term oil supply forecast (OPEC, 2018)

Closing remarks

The crude oil industry is big and ongoing activities within the industry carries a tremendous amount of momentum.  Changes to the industry occur slowly, especially as far as capacity addition is concerned.  Normally the capacity utilisation within the industry is high at above 95%.  This is also the reason why oil prices can be so volatile in the short term with any substantial and unexpected production interruption threatening the ability to supply demand in the short term.  Furthermore, the oil market exhibits a low price-sensitivity, meaning that demand changes slowly in response to price changes.

In the short term (up to two years) the oil price might remain under pressure as a result of subdued demand growth.  Currently forecasts indicate growth in 2019 to be less than one million bbl/day.  Low global GDP growth and ongoing trade wars are probably the main reasons for the low oil demand growth.  On the other hand, the low level of spare capacity in oil production could lead to spikes in oil price if there are major supply disruptions.  As long as these oil disruptions are short term in nature (less than one or two months), these price spikes should also be short term in nature.

In the medium to longer term (two years up to ten years) the risks to the oil price seem to be on the upside.  The planning for supply growth (as typically shown in Table 1) seems to be based on a set of ideal condition for both oil demand containment and oil supply.  Any of several developments deviating from these ideal conditions could lead to an oil shortage and high oil prices for a sustained period:

  • Oil demand growth might not be as slow as predicted resulting from climate change efforts. Several developments could contribute to this underestimation, i.e. rate of growth of electric vehicles, more effective carbon capture and storage, lack of external financing driving up oil prices, and a faster decline in coal, or a slower increase in natural gas growth, than anticipated which drives up demand for oil;
  • Conventional oil supply starts declining at significant rates and insufficient non-conventional oil investments are in place to counter this;
  • Shale oil supply growth in the USA does not continue at the estimated high rates for the next five years, as currently estimated;
  • Climate activists prevent the required investment in unconventional oil projects (and possibly even some conventional oil developments) leading to oil shortages; and
  • Insufficient capital is spent on upstream oil developments for economic reasons.

Finally, there is always the possibility of a black swan event that could drive the oil price to “unimaginably high levels not seen in our lifetimes” in the words of Saudi Arabia’s Crown Prince Mohammed bin Salman (Turak, 2019).  This statement was made specifically in relation to the possibility of a war between Saudi Arabia and Iran, but there are also other events that could lead to this undesirable outcome.  With the USA becoming increasingly self-sufficient in oil supply and imports of crude oil from OPEC lower than at any stage over the past 50 years, the USA has less reason to ensure political stability in the Middle East, thereby increasing the probability of this black swan event.

References

BP.  (2019) BP Statistical Review of World Energy 2019 / 68th edition. Available from  https://www.bp.com/content/dam/bp/business-sites/en/global/corporate/pdfs/energy-economics/statistical-review/bp-stats-review-2019-full-report.pdf.  Accessed on 30 October 2019.

DBP. (2019) DBP makes climate action and sustainability central to its business through Principles for Responsible Banking. Available from https://www.dbp.ph/newsroom/dbp-makes-climate-action-and-sustainability-central-to-its-business-through-principles-for-responsible-banking/. Accessed on 31 October 2019.

IEA. (2019) World Energy Investment, 2019 Edition.  Report iea.org/wei2019, available from https://webstore.iea.org/world-energy-investment-2019 US Energy Information Administration.

Macrotrends. (2019) WTI Crude Oil Prices – 10 Year Daily Chart. Available from https://www.macrotrends.net/2516/wti-crude-oil-. Accessed on 31 October 2019.

OPEC.  (2018) World Oil Outlook 2040.  Report OPEC 978-3-9503936-6-8 by the Organisation of the Oil Exporting Countries.

Putter, A.H. & Buys, C.P. (2015) XTL Projects and the Oil price, Parts 1, 2 & 3. Available from https://www.ownerteamconsult.com/xtl-projects-and-the-oil-price/  Accessed on 30 October 2019.

Rodger, A. (2019) Why tight oil and deepwater are more similar than you think. Available from https://www.woodmac.com/news/feature/why-tight-oil-and-deepwater-are-more-similar-than-you-might-think/. Accessed on 31 October 2019.

Rystad Energy. (2019) All eyes on the Caribbean as replacement ratio dips to the lowest in decades.Available from https://www.rystadenergy.com/newsevents/news/press-releases/all-eyes-on-the-Caribbean-as-replacement-ratio-dips-to-the-lowest-in-decades/. Accessed on 31 October 2019.

Turak, N. (2019) Oil will hit levels ‘we haven’t seen in our lifetimes’ if Iran isn’t stopped, Saudi crown prince says. Available from https://www.cnbc.com/2019/09/30/oil-will-hit-unimaginably-high-prices-in-event-of-war-with-iran-mbs.html. Accessed on 30 October 2019,

UNEP. (2019) Principles for Responsible Banking. Available from https://www.unepfi.org/banking/bankingprinciples/. United Nations Environment Programme.

Wood Mackenzie. (2018) Upstream players need to boost spending to meet future demand. Available from  (https://www.woodmac.com/press-releases/upstream-capital-investment/).  Accessed on 30 October 2019.

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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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