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.


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


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.


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.


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).


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.


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.

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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.


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.


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.


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

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

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

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

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

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

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


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Comparison of Coal-bed Methane to Other Energy Resources

Comparison of Coal-bed Methane to Other Energy Resources

By Jurie Steyn


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

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

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

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

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

Energy predictions

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

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

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

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

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

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

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

Description of energy resources

Coal and coal mining

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

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

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

Oil extraction from reservoirs

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

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

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

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

CBM from coal seams

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

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

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

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

SG from shale formations

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

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

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

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

Conventional gas

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

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

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

Approach followed for comparison

Parameters for comparison

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

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

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

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

Forced ranking

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

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

Elimination of bias

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

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

Discussion of findings

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

Figure 3: Environmental impact assessment for various energy sources

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

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

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

Figure 4: Social impact comparison for various energy resources

Figure 5: Cumulative impacts of energy sources

Concluding remarks

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

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

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


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

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The Elusive Project Sponsor

The Elusive Project Sponsor

By Jurie Steyn


All projects are risky ventures: the larger and more complex the project, the higher the risk of an unsuccessful outcome.  It is generally accepted that a critical success factor for any megaproject (projects > $1 billion) is the presence and participation of an effective project sponsor (Barshop, 2016).  In fact, the Project Management Institute reports that the top driver of projects meeting their original business goals is an actively engaged executive sponsor (PMI, 2018).

According to the Association for Project Management (APM, 2006), the project sponsor is the primary risk taker and owner of the project’s business case.  The sponsor is tasked with ensuring that all benefits of a project are realised by the organisation’s top management.   The sponsor chairs the project steering committee, ensures that risks are properly managed, that obstacles faced by the project are dealt with, and is the person to whom the project manager is accountable. The project sponsor focuses on project effectiveness, while the project manager focuses on project efficiency (APM, 2006).

An average of 38% of projects do not have active executive sponsorship, which highlights the need and opportunity for executive leaders to be more involved in the realisation of strategy (PMI, 2018).  Barshop (2016) maintains that the main reason why companies lacked strong project sponsorship was that senior management of these companies did not understand the project sponsor’s role in project governance.

In this article, we consider several scenarios for the executive sponsorship of projects and suggest ways to deal with problematic or absent sponsors.

Four scenarios

Several books (Englund & Bucero, 2006; West, 2010), and many more articles (Christenson & Christenson, 2010; Schibi & Lee, 2016), have been published on project sponsorship which describe personality traits, required training, as well as the role and responsibilities of project sponsors.  Whilst it is true that an effective sponsor is essential for project success, it is also true that not all sponsors are equally effective.

Four scenarios regarding the effectiveness and availability of project sponsors are described, with ways to deal with potential problem. The scenarios are described in some detail in Figure 1.

Figure 1:  Four sponsor scenarios

The four sponsor scenarios are:

  • Effective sponsor: The effective sponsor knows what to do and has the executive power and resources to do it;
  • Ineffective sponsor: The ineffective sponsor can have gaps in his training and/or may be at a too low level in the organisation;
  • Missing sponsor: The missing sponsor has either left the project for other responsibilities or has not been appointed yet; and
  • Reluctant sponsor: The reluctant sponsor may meet all the requirements, but doesn’t want to accept the responsibility.

Each of these scenarios is discussed in more detail in the following sections. 

The effective sponsor

According to West (2015), the value of an effective project sponsor is the product of the value of the project to the organisation, and the role that the project sponsor plays in a successful project.  He states that above all else, it is the effectiveness of the project sponsor that is critical to a successful project.

Truly effective sponsors are hard to find and should be nurtured by their owner organisations and appreciated by the project manager and project team.  The effective sponsor will be of appropriate seniority in the organisation, work closely with and mentor the project manager, understand the basics of project management, negotiate support and resources for the project, and be able to make decisions based on facts. Depending on the size and complexity of the projects, the effective project sponsor may be able to sponsor more than one project. In most organisations the project sponsor will have other responsibilities which may lead to time constraints. The effective sponsor will be able to manage his/her time properly and obtain assistance when required.

An effective sponsor has some key requirements that must be met by the project management team.  They have a need to feel involved in the project process, require a constant stream of timely information, must be able to trust the project manager (and vice versa!), need help with managing their project commitments, and assistance with the preparation for meetings with stakeholders.

An effective sponsor will also be able to stop a project when there is no real justification to proceed, in other words when the intended business objectives are no longer achievable.  Stopping a project in the front-end loading phase, when there is no longer any justification to proceed, does not constitute a failure, but rather shows strength of character and a keen business sense on the part of the sponsor and his project management team.

The ineffective sponsor

As mentioned before, an effective sponsor is essential for successfully completing a megaproject.  The direct corollary is that an ineffective sponsor greatly increases the probability of an unsuccessful project in the form of schedule and cost overruns, and not delivering on the organisation’s strategic objectives.

Project sponsors may be ineffective for several reasons, some of which are listed below:

  • Uncertainty on the actual role of the project sponsor on a project;
  • Insufficient training in, or experience with, project sponsorship;
  • The sponsor may be unwilling/unable to make decisions;
  • The sponsor is at too low a level in the organisation to be effective;
  • Too busy with other management obligations and not available to project team;
  • Deliberately wasting time on less important matters to avoid sponsor responsibilities;
  • Preoccupation with personal matters which takes focus off the project; and
  • The sponsor may be reluctant to take on the role of sponsor (more later).

Some of these causes are relatively simple to overcome.  For instance, a sponsor who is insufficiently trained on the ‘why’ and the ‘how’ of sponsorship, and is willing to learn, can be trained.  Training can involve formal courses, or on-the-job training by other experienced sponsors.  Very experienced project managers can also lead and assist the ‘inexperienced’ sponsor, as illustrated in Figure 2.

Figure 2:  Assisting the ineffective sponsor (Adapted from van Heerden et al, 2015)

Sponsors who are unwilling to make decisions, may also be too low in the management hierarchy.  The project manager can attempt to deal with the problem by using a formal scope management procedure and taking the inexperienced sponsor through the motivation in detail.  If this does not deliver the desired results, or the sponsor is at too low a level to have an impact, the project manager will have to approach a trusted member of the organisation’s management team to discuss the concern and the potential negative consequences on the project.

Sponsors with insufficient time to deal with the project related matters can be addressed by discussions between sponsor and project manager.  If the reason is that the sponsor wants to remain in his/her comfort zone, training may be the answer.  If not, the project manager can offer to temporarily take on some of the sponsor responsibilities while the sponsor delegates some of the other responsibilities.  Sponsors who are preoccupied with personal problems can transfer some of the sponsorship responsibilities to the project manager or other subordinates. 

Lastly, sponsors who are reluctant to take on the role of sponsor will be discussed under a separate heading.

The missing sponsor

‘Missing’ sponsors are unavailable to meet project responsibilities (sometimes right from the start, or at some later point in the project) because nobody has been appointed to the position or they are otherwise occupied.  Sponsors can be ‘missing’ from the sponsorship function for any of the following reasons:

  • No sponsor has yet been appointed for the project;
  • An existing sponsor was moved or promoted to another function;
  • An ineffective or reluctant sponsor was removed from the position;
  • Top management does not consider it necessary to appoint a sponsor;
  • Medical or family emergencies, resulting in time away from the office; and
  • The sponsor may be overloaded with other projects and/or responsibilities.

There are ways to overcome the gap left by a ‘missing’ sponsor, although it places an additional burden on the owner project management team.  Several members of the project management team can act as project sponsor, as shown in Figure 3.

Figure 3:  Filling the gap of a missing sponsor (Adapted from van Heerden et al, 2015)

There are typically four key players in the project management team of any megaproject, namely the project manager, the business manager, the operations manager and the engineering manager.  Any one of these should be able to act as project sponsor.  When the sponsor post is expected to remain vacant for an extended period, the sponsor responsibilities can be divided up amongst the different managers.  Alternatively, each of the managers in the project team can rotate to the position of acting project sponsor for a specific period, say a month at a time.  Keep in mind that an acting sponsor in the place of a ‘missing’ sponsor can keep the project moving along, but can never be as effective as a dedicated and committed sponsor.

The structure for a programme is depicted in Figure 4, with similar acting arrangements as before.  Programmes are typically larger, more complex and subject to more uncertainty than projects, which implies that the need for a full-time sponsor is even greater if a successful programme is desired.

Figure 4:  The elusive sponsor of a programme (Adapted from van Heerden et al, 2015)

The reluctant sponsor

A reluctant sponsor, as the name implies, is a person who does not want to be in that position of responsibility.  Perkins (2015) refers to them as resistant sponsors, and states that resistant sponsors may be blatant or passive-aggressive in their efforts to block progress: indeed, a very dangerous situation.  In my opinion, having a reluctant project sponsor on board is far worse than having an ineffective or ‘missing’ sponsor.

Sponsors can be referred to as ‘reluctant’ for any of the following reasons:

  • They consider the project to be a career-limiting disaster;
  • They don’t wish to be tied down for the multi-year lifespan of the project;
  • They anticipate that the project will diminish their current responsibilities;
  • The project proposal was not their preferred option; and
  • They want to fulfil their prophecy that the project will be unsuccessful.

Reluctant sponsors can have very negative effects on project success and can demoralise project management teams (Perkins, 2015). This can lead to project team members leaving the project, rather than work in a toxic environment.

When dealing with a reluctant sponsor, the following approaches can be considered (Perkins, 2015):

  • Remain professional: Don’t resort to personal attacks on a reluctant sponsor. Rather blame the work processes and seek or offer solutions;
  • Keep the reluctant sponsor informed: Discuss matters requiring difficult decisions with the reluctant sponsor prior to formal meetings to avoid time being wasted during project steering committee meetings;
  • Document thoroughly: Project management practice requires the team to document agreements, motivate change requests, keep a risk register, list and follow up on action items, etc. Ensure that all documentation is timely and thorough with a reluctant sponsor;
  • Call in supporters: Ask high-level supporters of the project in the organisation to highlight the project’s value. Stubborn reluctant sponsors will find it hard to continue destructive behaviour in the face of continuous enterprise-wide support;
  • Informal engagement: Ask a senior member of the organisation’s management team, respected by the reluctant sponsor, to discuss the project with him/her. If the discussion is penetrating enough, reluctant sponsors may modify their destructive behaviour; and
  • Auto-ignition: Let reluctant sponsors destroy themselves through their actions. This is a risky, last-ditch effort, based on the hope that the rest of the organisation will recognise the reluctant sponsors’ poor decisions, and remove them from the sponsorship responsibilities.

Concluding remarks

Ashkenas (2016) states that the project sponsor should be the first appointment to be made when steps are taken to implement corporate strategy.  Before launching a new project, the sponsor and the project leader should meet to set, clarify, and align expectations. This is particularly important if the sponsor was not actively involved in the project initiation phase, and may not understand the background and risks.

Several authors have expressed the concern that due to the growing number of megaprojects in the world, good project sponsors are becoming increasingly difficult to find in the open market or inside the organisation (Merrow, 2011; Barshop, 2016).  Organisations are encouraged to train their executives for future roles as project sponsors.  If your company has a need for project sponsorship training, do not hesitate to contact us at OTC.


APM (Association for Project Management), 2006, APM Body of knowledge, 5th edition. Association for Project Management, High Wycombe, Buckinghamshire.

Ashkenas, R., 2016, Before starting a project, get your sponsor on board. Available from https://www.forbes.com/sites/ronashkenas/2016/05/09/before-starting-a-project-get-your-sponsor-on-board/#127c26f779c9. Accessed18 February 2019.

Barshop, P., 2016, Capital projects: what every executive needs to know to avoid costly mistakes and make major investments pay off. John Wiley & Sons, Inc., Hoboken, New Jersey.

Christenson, D. & Christenson, J. 2010, Fundamentals of project sponsorship. Paper presented at PMI® Global Congress 2010, in Washington, DC. Project Management Institute.

Englund, R.L. & Bucero, A., 2006, Project sponsorship: achieving management commitment for project success., Jossey-Bass, San Francisco, CA.

Merrow, E.W., 2011, Industrial megaprojects: concepts, strategies, and practices for success., John Wiley & Sons, Inc., Hoboken, New Jersey.

Perkins, B., 2015, 6 ways to cope with a resistant sponsor.  Available from https://www.computerworld.com/article/2883748/6-ways-to-cope-with-a-resistant-sponsor.html. Accessed on 14 February 2019.

PMI (Project Management Institute), 2018, 2018 Pulse of the profession. Project Management Institute, Philadelphia, PA.

Schibi, O. & Lee, C., 2015, Project sponsorship: senior management’s role in the successful outcome of projects. Paper presented at PMI® Global Congress 2015, EMEA, London, England. Project Management Institute.

van Heerden, F.J., Steyn, J.W. & van der Walt, D., 2015, Programme management for owner teams: a practical guide to what you need to know., OTC Publications, Vaalpark, RSA. Available from Amazon.

West, D., 2010, Project sponsorship: an essential guide for those sponsoring projects within their organizations., Gower Publishing Limited, Farnham, Surrey.

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The Widening Trust Gap in Projects

The Widening Trust Gap in Projects

By Jurie Steyn


This article was triggered by four recent events, which caused me to reflect on what the future holds for projects.  These events are:

  • A thought-provoking Insight Article on the future of project controls (Mattheys, 2018);
  • The Insight Article on the role and responsibilities of a project management office (PMO) (Taljaard, 2018);
  • Cenpower Generation’s recent termination of its contract with the construction company, Group Five, to complete the $410m Kpone power station in Tema, Ghana (Claassen, 2018); and
  • A second down-scaling in a period of four years of the engineering and project management departments at a petrochemicals company where I spent most of my working career.

Literature is freely available on future trends in project management and what would be expected from future project managers (Alexander, 2018; Evamy, 2017; Jordan, 2017; Schoper, Gemünden & Nguyen, 2016).  However, discussions on the widening of the trust gap and its impact on project success is extremely limited.

Keep in mind that I’m based in South Africa, and my observations might be unique to Africa and third world countries.

The trust gap

Independent Project Analysis (IPA) have been analysing megaprojects for over 30 years to determine the requirements for project success and to help their customers create and use capital assets more efficiently.  They’ve highlighted the crucial role that a strong, fully staffed, owner project management team, with the appropriate work and governance processes in place, plays in delivering successful projects (Merrow, 2011). It is the owner project management team that typically leads the front-end loading phase of projects.  Merrow (2011) emphasises the extraordinary degree of trust, cooperation and communication required between the owner organisation, as represented by the project sponsor, and the owner project management team.

van Heerden, Steyn and van der Walt (2015) build on these principles and propose a preferred structure for theowner project management team, as shown in Figure 1.  The owner project management team is shown as a collection of four blue triangles, representing business management, project management, engineering and operations, arranged in a larger triangle.  Below this, and shown as a red box, we have contracted in functional services, technology suppliers, and engineering and project management contractors.


Figure 1:  Trust gap between owner PMT and contractors(Adapted from van Heerden, et al, 2015)

I refer to the interface between the owner project management team and contractors, suppliers and service providers, i.e. the gap between the blue triangles and the red box in Figure 1, as the trust gap.  Obviously, the working relationship between these parties, responsibilities and deliverables must be described in numerous carefully worded contracts, but significant trust is essential for project success.

Before getting to the factors that contribute to a widening trust gap, let us first consider the different roles and perspectives of the owner organisation and the owner project management team on the one hand, and the contractors on the other.

Different roles and perspectives for owners and contractors

Owner organisations, and specifically the owner project team, have a different role and perspective than the contractors in projects.  This difference stems from the fact that owner organisations implement projects to achieve strategic business objectives, whereas contractors only focus on delivering projects which meet the agreed performance standards, on time and within budget.  A summary of the different objectives, roles and perspectives of owners and contractors is given in Figure 2.


Figure 2: Different perspectives for owners and contractors

Project scope changes can lead to cost overruns and schedule slip and should be diligently managed to that which can result in significant, demonstrated improvement to the project, or that which is essential to achieve safety and compliance objectives.  However, from the point of view of an engineering contractor, scope changes could mean thousands of extra, recoverable, engineering hours.  Scope changes can also be used as an easy excuse for schedule slip by contractors.

Current trends at owner organisations

Owner organisations can be public companies, private companies and state-owned enterprises (SOE). Owner organisations typically own and operate the production facilities and/or infrastructure delivered by projects.

Over the past number of years, we’ve seen a gradual eating away at the numbers and experience base of primarily the engineering and project management departments in owner organisations.  Reasons for this are plentiful, and range from the inability to raise capital for projects, to poor strategic vision for the company.  Restructuring of top management and personnel cuts in the operations department also result in fewer individuals in these areas being available to focus on capital projects. Business and operations management are important stakeholders in any project, and play a significant role in the commissioning of facilities and the running of a sustainable business.  This situation is reflected in Figure 3 as mice eating away at the underbelly of primarily the engineering and project management departments, and so widening the trust gap.


Figure 3:  Widening of the trust gap (Adapted from van Heerden, et al, 2015)

In SOE, most top positions are political appointments.  In South Africa and in the Gupta state-capture era, important project and tender decisions were often made by individuals with little or no project management or engineering background.  The primary focus seemed to be self-enrichment, and not project success. There are many instances where SOE’s ignored their own tender regulations when awarding contracts, for example, South African railways officials imported brand new locomotives from Europe worth hundreds of millions of rand, despite explicit warnings that the trains are not suited for local rail lines (Myburgh, 2015). 

In South Africa, we have the additional burden of complying with Broad-Based Black Economic Empowerment (BBBEE) requirements, with the implication that individuals with extensive experience are made redundant, or are replaced with candidates with limited experience.  Project management and engineering departments thus not only become smaller, but tend to be staffed with less experienced personnel.

Trends at engineering and PM companies

Referring to Figure 3, it is obvious that the widening of the trust gap is not only as a result of personnel cutbacks, loss of project and engineering experience, and greed from the side of the owner organisation.

The trust gap can also open from the side of contractors, suppliers and service providers, as illustrated by the erosion of the red box in Figure 3.  Some of the factors that can contribute to this erosion of trust are listed below:

  • Financial standing:Construction companies in South Africa are in a difficult situation at present and personnel cutbacks are frequent.  Companies are downsizing and/or put up for sale;
  • Bribery: Attempts at bribery of technology suppliers, service providers and contractors by personnel from state or owner organisations prior to the signing of a contract or during the execution thereof can lead to strained relationships and would impact the chance of project success;
  • Communication:Unclear project objectives and charter, from an immature or understaffed owner project management team, combined with ad hoc and incomplete communication will erode trust;
  • Interface management: Insufficient effort or resources for proper client liaison by contractors and service providers, most likely due to in-house cost cutting at the contractors and service providers;
  • Relationships: Soured relationships following a history of schedule and cost overruns on previous projects for same owner organisation.  This can also be a concern based on underperforming end-products from previous projects and outstanding claims;
  • Coordination:No experienced managing contractor to keep a project on track, despite poor decision-making from the owner project management team.  This is a certain recipe for disaster; and
  • Incompetence:Disregard of owner company tender procedures may lead to the selection of incompetent contractors and service providers, often with catastrophic results.

Impact of a widening trust gap

IPA measure five dimensions of project effectiveness in their assessments to determine whether a project is a success, or not (Merrow, 2011). If a project surpasses the threshold limit for failure on any one of these dimensions, the project is considered a failure.  The five dimensions are cost overruns (>25%), cost competitiveness (>25%), schedule slip (>25%), schedule competitiveness (>50%) and production vs. plan in year 2 of operation.  Project success is defined as a lack of failure.

As the trust gap widens, the probability of remaining below the threshold limit for failure on any of these dimensions decreases, i.e. the wider the trust gap, the larger the likelihood of an unsuccessful project. 

Closing the trust gap

Given the state of the South African economy and political uncertainties, the question is whether the trust gap can be reduced to improve the likelihood of project success.  Two options immediately spring to mind:

  • Eliminate corruption: Elimination of corruption in specifically SOE should receive attention at the highest level and proper governance should be instituted to ensure that tender procedures are always followed.  The decision of which contractor to employ should always be made by a team of professionals with the necessary experience and knowledge, and using a predetermined decision matrix; and
  • Use external resources: The southern African market is awash with highly competent engineers and project managers, many of whom were put on early retirement due to the factors described in previous sections.  Many of them are available as consultants to fill critical vacancies on owner project teams, especially during the early project stages. These are people who understand the business requirements and can translate strategic business objectives into clear project objectives.

The future of the Project Management Office (PMO)

Taljaard (2018) describes the roles and responsibilities of the PMO very clearly in his recent article.  Based on the trends described above, it is obvious that owner organisations must make a fundamental mind-shift where it involves project implementation.  Although all the PMO functions remain relevant, I forecast a downscaling of some of the functions, and a possible sharing of some of the PMO roles, like project portfolio management and optimisation by other senior business leaders.

I forecast a growth in the number and utilisation of owner project team support professionals.  Lastly, the role of the owner project sponsor will become increasingly important.  For large and complex projects, the project sponsor is seen as an executive, full-time position by competent individuals who have been trained as sponsors, understand the business objectives and can make decisions based on facts

Figure 4 is summary of my view of the future of the PMO and the project sponsor.


Figure 4:  The future of the PMO

Closing remarks

The widening of the trust gap is very visible in southern Africa and may be applicable in most third world countries.  The wider the trust gap, the lower the probability of project success… Fortunately, the widening can be curtailed by improved governance and the elimination of corruption, as well as the use of freelance project management and engineering professionals.

OTC, and other consulting groups like us, should see an increase in the demand for our services, once owner organisations make a mind-shift in their approach to projects.


Alexander, M., 2018, 5 Project management trends to watch in 2018. Available from https://www.techrepublic.com/article/5-project-management-trends-to-watch-in-2018/.  Accessed on 28 December 2018.

Claassen, L., 2018, Ghanaian power firm ends troubled contract with Group Five.  Published in BusinessDay of 2 December 2018. Available from https://www.businesslive.co.za/bd/companies/energy/2018-12-02-ghanaian-power-company-ends-troubled-contract-with-group-five/. Accessed on 28 December 2018.

Evamy, M. (ed),2017, Future of project management., Publication by the Association of Project Management, Arup and The Bartlett School of Construction and Project Management at UCL.

Jordan, A., 2017, The technology-driven future of project management: capitalizing on the potential changes and opportunities.Publication by Oracle, projectmanagement.com and Project Management Institute.

Mattheys, K., 2018, Insight Article 052: Disrupting project controls – fast forward 20 years.  Available from https://www.ownerteamconsult.com/publications/  Accessed on 14 December 2018.

Merrow, E.W.,2011, Industrial megaprojects: concepts, strategies, and practices for success., John Wiley & Sons, Inc., Hoboken, New Jersey.

Myburgh, P-L., 2015, SA’s R600 million train blunder.Available from https://www.news24.com/SouthAfrica/News/SAs-R600-million-train-blunder-20150704.  Accessed on 28 December 2018.

Schoper, Y-G., Gemünden, H-G. & Nguyen, N.M., 2016, Fifteen future trends for Project Management in 2025.Published in the Proceedings of the International Expert Seminar in Zurich in February 2016 on Future Trends in Project, Programme and Portfolio Management.

Taljaard, J.J., 2018, Insight Article 054: The project management office (PMO).  Available from https://www.ownerteamconsult.com/publications/  Accessed on 14 December 2018.

van Heerden, F.J., Steyn, J.W. & van der Walt, D.,2015, Programme management for owner teams: a practical guide to what you need to know., OTC Publications, Vaalpark, RSA. Available from Amazon.


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