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Company’s Revised Approach to Safety Strives To Make Standards More Natural

Published August 16, 2013

ExxonMobil has traditionally used industry standards driven by the US Occupational Safety and Health Administration (OSHA) to classify safety events on the basis of the treatment or restrictions provided. However, this treatment-based approach has limitations. With its focus on administrative reporting and incident-escalation management, the approach does not naturally resonate with workforce members to enable desired cultural changes. A hurt-based approach has been adopted to mitigate the limitations of the treatment-based approach.

Traditional Treatment-Based Approach

In the treatment-based approach to personnel safety, an incident, from the treatment or restrictions provided, is classified as a lost-time incident (LTI), restricted-work incident (RWI), medical-­treatment incident (MTI), first aid, no treatment, near miss, or unsafe act/unsafe condition. These are usually represented by the traditional safety pyramid (Fig. 1).

Treatment-based safety pyramid.

Benefits of this approach include

  • It provides historical metrics common across multiple industries.
  • It allows comparisons on a similar basis.
  • It is consistent with many government/regulatory-agency reporting requirements.

However, this approach also has significant limitations:

  •  It is not consistently descriptive of actual injury severity; for example, body damage such as a minor laceration, a sprained ankle, or a broken neck could each be correctly classified as an LTI, depending on the circumstances.
  • It does not have an integral potential injury severity; safety events with low actual consequence (e.g., minor hurt, near misses) are often overlooked or simply not reported.
  • It creates a blind spot relative to exposures for severe injuries by focusing solely on traditional safety metrics [e.g., total recordable incident rate (TRIR), LTI rate (LTIR)]; certain activities and activities managed by safety controls require greater exposure awareness.
  • It is not an enabler for a culture of caring; workers can perceive case-management priority to be about reducing the number of recordables (perhaps by minimizing treatment) and not about the elimination of all injuries.

Nobody Gets Hurt

The phrase “nobody gets hurt” was coined in 2000 and later adopted by ExxonMobil as the corporation’s safety vision for a workforce that believes all injuries are preventable and where all workers accept personal accountability for their own safety and are willing and able to intervene to ensure the safety of others. It was understood that progressing the vision would require long-term, visible commitment by safety leaders at all levels of the organization, from the executive office to the front line. It was understood that achieving the vision would be a journey, not a project or an initiative or a singular destination.

In May 2001, the new safety vision of Nobody Gets Hurt was discussed and an initiative was presented challenging the organization to achieve the vision as soon as possible. The objective was to eliminate all treatment-based incidents meeting the recording criteria for an injury or illness under OSHA recordkeeping requirements.

Management believed the primary concerns should always be the care for any injured person and the assessment of incidents to prevent future hurt. Unfortunately, some workers believed the most important question driving the case-­management process was “Is it a recordable or not?” This perception by some that safety was all about statistics was viewed as an obstacle to achieving the vision. A strategic navigational correction was needed in the journey to Nobody Gets Hurt to win over the workforce and enable the desired pervasive culture of safety.

Expectations of Safety Leadership

  • Safety leadership is not a task assigned to the safety department. Safety leadership is not a position or title reserved for senior management. Safety leadership is a value expected of every person within the workforce, whether employee or contractor. To move the journey toward a common safety vision, a few critical actions must be taken. These are ensuring that the leadership
  • Aligns with the vision
  • Believes the vision can be achieved
  • Personally and passionately commits to the vision
  • Sincerely promotes the vision to the workforce
  • Celebrates successes
  • From Compliance to Culture

An analogy of how a safety journey can progress is the evolution of seat-belt usage. Seat-belt use was not always regulated; older automobiles did not include them, and, if they did, they simply were not used (it was not in the culture). Once regulations were passed and it became against the law not to wear seat belts, people started wearing them out of compliance. People did not necessarily believe in seat belts; they simply used them to avoid the fines and penalties of noncompliance. Later, people realized that wearing seat belts had become a habit. People no longer had to decide consciously to wear seat belts each time they got into an automobile. Over time, some grew wiser and started wearing seat belts willingly; they now believed seat belts could save their lives in a traffic accident. Possibly, people started encouraging others to use them as well. Perhaps now people make sure their spouses, children, and guests always wear seat belts when in an automobile because that is simply the way things are done. That is a culture of safety.

Serious Injuries and Fatalities

A 2010 industry study found that traditional safety-pyramid principles were not driving elimination of serious injuries and fatalities (SIFs). Even though it is typical for many companies’ TRIR and LTIR to be trending downward, it is also very common for their fatal-­accident rates to be at a plateau or actually increasing. The idea that minor injuries could predict more-serious injuries is embedded in our culture; however, the study indicates that a reduction of injuries at the bottom of the pyramid does not correspond to a proportionate reduction of SIFs. This is because not all injuries have SIF potential. The study found that a relatively small subset, approximately 20%, of all incidents had the potential to be an SIF. This finding challenged the traditional thinking that focusing on eliminating incidents in general would ultimately reduce the more-severe injuries at the top of the pyramid.

The majority of injuries simply do not have the potential to become high-consequence incidents regardless of the circumstances surrounding the safety event. This is because underlying causes and factors for SIFs are different from those for less-serious injuries. SIFs are disproportionately related to certain activities (e.g., working at height, crane and lifting operations, man/machine interface) and to activities managed by certain safety controls (e.g., lock-out/tag-out, confined-space entry, energy isolation). Ensuring workforce awareness of the increased exposures generated by these types of work activities is critical in the elimination of SIFs.

Drivers for the Hurt-Based Approach

The hurt-based approach to safety was approved and implemented across all of ExxonMobil’s upstream companies effective January 2012. Critical drivers to adoption included

  • A proven 6-year history in ExxonMobil Drilling, showing improvements across all levels of the pyramid, including SIFs
  • Integral assessment of potential injury severity
  • Consistent description of actual injury severity
  • Resonance with workers to enable the desired safety culture based on caring for people
  • Natural safety language in most, if not all, global cultures—protect family, prevent injuries

A graphical analysis of the rate of workers hurt is provided in Fig. 2.

ExxonMobil Drilling: rate of workforce hurt, 2003–11.

From a high of 6.50 in 2004 to a low of 1.49 in 2011, Drilling’s total hurt incident rate (THIR) improved such that five fewer people were getting hurt for every 200,000 exposure-hours.


A graph of ExxonMobil Drilling’s serious injuries and fatalities on both an actual and a potential basis is shown in Fig. 3.

Potential vs. actual hurt.

The rate of actual high-­consequence safety events (SIFs) decreased, while incidents with high consequence potential decreased significantly.

Methodology and Process

In implementing the hurt-based approach across ExxonMobil’s upstream companies, slight modifications were made to the severity scale. These new hurt-based severity levels are shown in Fig. 4

ExxonMobil upstream hurt-based severity scale.

along with examples of the physical body damage typical of each level. The “Duration” column provides an additional resource to assist in determining the hurt level of incidents on the basis of the amount of time the injured person takes to return to normal duties without any decrease in work effectiveness or efficiency.

The process for determining the actual hurt level (AHL) of an incident is to contrast the actual physical effect, injury, or illness to a person against the hurt-based severity levels (Fig. 4) and assign an AHL. The determination of potential hurt level (PHL) is a more structured process but is still very simple. For PHL determination, the basic process is to

  • Use the actual safety event as it occurred (do not speculate on what could have happened at this point)
  • Use the actual hazards that existed at the time of the event (do not add fictional or additional hazards)
  • Determine any applicable pre-event mitigations in place at the time of the event
  • Discuss feasible-but-reasonable scenarios that would result in the highest risk to people, and consider to what level the pre-event mitigations in place would have reduced the severity of an injury in these scenarios
  • Use the hurt-based severity scale to assign a PHL, using the potential hurt that could have occurred in the worst-case feasible-but-reasonable scenario,
  • Document the PHL rationale (e.g., scenario used, mitigations in place, maximum hurt possible)

Mining the Diamond

The ExxonMobil Development Company implemented an initiative, called “mining the diamond,” to increase awareness of and prioritize action on high-­consequence potential safety events (Fig. 5).

Mining the diamond.

A safety event is considered a high-consequence event if it results in multiple fatalities (AHL5), a single fatality (AHL4), or a life-altering injury (AHL3). A safety event is considered a high-consequence potential event if there was feasible but reasonable potential for it to have resulted in multiple fatalities (PHL5), a single fatality (PHL4), or a life-altering injury (PHL3). By definition, a high-consequence safety event is also considered a high-consequence potential event because both the AHL and the PHL are 3 or higher. High-­consequence potential safety events are also known as PHL3+, or diamond, events.

It is critical that safety leadership focus on assessing every safety event, regardless of recordability, severity, or whether someone was actually hurt. However, that does not necessarily mean every safety event will yield enhanced value from a comprehensive, multidisciplinary team taking weeks to assess the event using the latest in incident-­investigation technology and methodology. Mining the diamond is the first step in prioritizing resources for a safety event that has occurred. The majority of safety events can be adequately assessed to learn lessons within 1–2 hours, yet some take several hours, a few take days, and the extraordinary event may take weeks. The majority of incidents can be assessed with less-formal, less-comprehensive investigation techniques. All safety events that fall inside the diamond, on the basis of their AHL3+ or PHL3+ rating, have the potential to maim or kill. These safety events warrant and require a detailed assessment to maximize lessons learned so that actions can be taken to prevent similar future events; therefore, all diamond events require in-depth root-causal-­factor analysis.

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 163757, “A Hurt-Based Approach to Safety,” by R.M. Smith, SPE, and M.L. Jones, ExxonMobil, prepared for the 2013 SPE Americas E&P Health, Safety, Security, and Environmental Conference, Galveston, Texas, 18–20 March. The paper has not been peer reviewed.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.

An Integrated Noise-Protection Program in Angola

Published August 15, 2013

An epidemiological study was developed to take into account specific employee habits while measuring the possible prevalence of hearing problems arising from earlier occupational exposure. During 30 years of war, Angolans were exposed to high levels of noise, a factor exacerbated by the offshore environment many workers now share. A population of nonexposed staff, largely administrative, was compared with a population of offshore workers. The results did not show any significant difference in hearing capabilities.


Noise-induced hearing loss (NIHL) is the most prevalent irreversible industrial disease, and noise is the most prevalent compensable occupational hazard. In developing countries, occupational noise and urban environmental noise are increasing risk factors for hearing impairment, which may lead to increased incidence of accidents at work.

Unlike most other occupational injuries, NIHL occurs without any visible exterior evidence or trauma and is perceived too late. While irreversible, it is fully preventable with proper job design, training, and protection measures. The estimated cost of noise to developed countries ranges from 0.2 to 2% of gross domestic product. However, there is a lack of accurate epidemiological studies on prevalence, risk factors, and costs of NIHL, particularly in developing countries.

In an audiogram, the decrease in the hearing threshold is detected at an early stage, allowing preventive measures to be taken. Changes in audiometric tracings are common and usually bilateral. Changes in the hearing threshold involve an initial notch at high frequencies of 3,000, 4,000, and 6,000 Hz, which, over 10 to 15 years of exposure, reach a maximum of 75 dB. Thereafter, medium and low frequencies are gradually affected up to a maximum of 40 dB.

Noise-Exposure Risks in Angola

Social and Environmental Exposure. During the civil war that ended in 2002, people were exposed to high noise peaks from gunfire, explosions, and tank battles. Throughout this period, no medical assessments or epidemiological data were available. There is no public law on noise pollution, and, in Luanda, nightclubs play loud music throughout the night from Thursday until Monday. Common transport buses have powerful sound systems, exposing drivers, riders, bystanders, and other commuters in numerous traffic jams to noise peaks. Traffic in Luanda during the week is heavily congested, and there is a constant cacophony of car horns and car alarms. Industry workers are exposed to noise during offshore drilling and production operations, onshore logistics operations, and air travel. Currently, there is no national labor legislation enforcing noise limits.

Total E&P Angola (TEPA) Rule. Table 1 provides limits based on European Directive 2003/10/EC concerning noise. In zones where the normal single-ear protection of the worker cannot reduce the noise below the occupational exposure limit (OEL) of 87 dB(A), double hearing protection is made mandatory by display of the safety sign in Fig. 1. 

Double-hearing-protection safety sign.

Hearing-Conservation Program

TEPA’s program consists of the following actions: an epidemiological study, noise and vibration studies on offshore facilities, direct and individual monitoring campaigns with noise mapping, noise-awareness campaigns, and mandatory audiometry during an offshore medical exam.

Epidemiological Study. The cross-­sectional study was conducted from ­August to October 2010 in Luanda. Subjects included Angolan offshore workers and a comparative group comprising administrative employees from offices in Luanda. Statistical software was used. A confidence interval of 95% with a beta error of 20% was accepted, with a 16% prevalence of hearing loss in the nonexposed group and a 2:1 exposed/nonexposed ratio in the proportion of 91:46. Simple random sampling was used for the offshore group, and paired samples matched by age were used for the administrative group. The study involved 164 employees (113 offshore, 51 administrative). Twenty-seven workers were eventually excluded from the statistical analysis. The analysis phase considered 92 (44%) out of 209 Angolan offshore workers and 45 (6%) out of 736 Angolan administrative workers, all male.

For the audiological assessment, a minimum of 14 hours of auditory rest was recommended before the audiometric test in order to reduce the possibility of a temporary drop in hearing threshold. Participants responded to an individual questionnaire about their family and personal history of hearing disease, lifestyle, and exposure to noise (both nonoccupational and occupational), and aired any hearing complaints. A bilateral inspection was conducted of the outer ear, the external auditory meatus, and the tympanic membrane. Hearing tests were followed directly by a screening for hearing abnormalities by a practitioner in general and family medicine. The audio­grams were then interpreted by a specialist in occupational medicine.

Data were processed using statistical software. For continuous variables, results were expressed as means, standard deviation, medians, and interquartile ranges. Categorical variables were expressed as frequencies and percentages.

Sociodemographic Characteristics. The population consisted of very young adults, 82% having worked at the company for less than 10 years; nearly half were younger than 30, and 82% were younger than 40. Nearly half the offshore population had been working at the company for less than 4 years, while half the administrative group had been working there for 2 years or less, indicating a statistically significant difference. Fig. 2

Offshore employees (92) distributed into homogeneous noise-exposure groups.

represents the distribution of the offshore group by activity, according to homogeneous exposure groups defined by the company.

Audiological Assessment. A clinical questionnaire examined the medical history and symptoms of hearing disease. In the occupational section of the questionnaire, there were no significant differences between groups in their responses on the use of firearms, military service, motorcycle riding, time spent in noisy environments outside the working environment, and previous hearing tests. The history of prior or current work performed in a noisy environment and the use of or recommendation to use ear protectors was significantly higher in the offshore group.

Comparison of Hearing Thresholds. With respect to the left ear, all mean values in both groups were less than 15 dB and the mean audiometric curves were similar at all frequencies, except at 500 and 8,000 Hz. At all frequencies except 500 Hz, the mean thresholds of the offshore group were slightly higher than those of the administrative group; at 500 Hz, the hearing threshold was significantly lower in the administrative group.

In the offshore group, the mean threshold extremes ranged from a minimum of 6.63 dB at 1,000 Hz to a maximum of 13.75 dB at 8,000 Hz. In the administrative group, the mean threshold extremes ranged from 5.89 dB at 1,000 Hz to 11.11 dB at 6,000 Hz. When we compare the mean curves of both ears in the two groups, we can see that the shape of the mean hearing thresholds matches the previous audiometric curves. When comparing both groups, we notice a significant difference in the median threshold analysis of both ears at frequencies of 500 Hz (p=0.002) and 8,000 Hz (p=0.023).

Results of the Study

The offshore group is young (median=30 years) and has been exposed to occupational noise for a short period of time at the company (median=4 years). The shape of its audiometric curve does not suggest noise-induced hearing loss and, at almost every frequency, is similar to that of the administrative group. In the left ear, a comparison of hearing thresholds (median) between offshore and administrative groups showed no statistically significant differences at frequencies of 1,000 to 8,000 Hz. The audiometric curves were almost flat and identical to each other. In the right ear, results were similar. These findings do not meet the criteria for noise-induced hearing loss (threshold >25 dB) and may be monitored in subsequent studies. With at least one hearing threshold above 25 dB, changes were found in 14% of the offshore group’s audiogram results and in 13% of the administrative-group results, though the difference between the two was insignificant.

Noise and Vibration Studies on Offshore Facilities. An internationally recognized company made noise and vibration studies onboard company floating production, storage, and offloading vessels (FPSOs). The studies resulted in color mappings of all decks in which the noisiest installations were distinguished. These zones on deck were clearly marked with ear-protection safety signs and floor painting. High noise levels are mainly present at pumps, valves, and pipes with turbulent fluid flow; at hydrocyclones and separators; and at compressors, turbines, and generators. Engineering controls to damp down noise and vibration were implemented as a result of the recommendations made in the report.

Direct and Individual Monitoring Campaigns With Noise Mapping. The company Industrial Hygiene Department organizes annual noise-­monitoring campaigns consisting of direct monitoring with a Class 2 noisemeter of the produced noise in decks, offices, and living quarters. The measurements are then extrapolated onto noise maps by use of specific-color balls in relation to the common personal protective equipment used onboard. Work in high-noise areas for a prolonged period of time requires a special work permit defining the permissible exposure time. Apart from the direct measurements, 10 volunteers from different similar-­exposure groups are individually monitored during 5 consecutive days using noise badges registering the noise above 70 dB(A). It is mathematically possible that a worker does not exceed the OEL calculated over the entire shift, but does go beyond the OEL during a part of the shift. For every 3 dB that the OEL plus attenuation from the ear protection is exceeded, the exposure time must be halved. Abseilers, mechanics, and electricians are the main job categories exposed to high noise.

Noise-Awareness Campaigns. During the monitoring campaigns and also during presentations to offshore and office workers, noise-awareness campaigns are organized in French, English, and Portuguese. The purpose is to familiarize the workers with the com­pany’s ­hearing-conservation program and to ensure that they protect themselves from noise both in the occupational environment and in their time off. Workers are also trained in use of a variety of ear-protection equipment.

Mandatory Audiometry During Offshore Medical Exam. Audiometric testing is an important part of hearing-preservation programs. It allows early identification of employees with increasing hearing deficits and prevention of future NIHL. All offshore workers are obligated to undergo an audiometry during their annual medical exam. Each worker has an individual Health Risk Assessment File that identifies major hazards to the examining doctor. Exposure to high noise levels is stated as one of these risks. At the time of hiring, new employees are also required to undergo an audiometry exam. The data of the audio­metry and the results from the noise-risk assessments are stored in a specific databank for 50 years.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 157292, “Integrated Noise Protection Program—From Noise Measurements to Epidemiology,” by Tania Batalha, Nico De Sadeleer, and Stephan Plisson-Saune, Total E&P Angola, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11–13 September. The paper has not been peer reviewed.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.

Legislation, Commerce, and Ethics Drive Design of Quieter Facilities in Australia

Published August 14, 2013

Legislation, economics, and ethics are major drivers behind the adoption of engineering noise controls during offshore-facility design in Australia. The global challenge facing noise advisers is to understand how these factors influence the adoption of engineering noise controls and to work closely with project teams to ensure that operational-noise risk is as low as reasonably practicable (ALARP). Implementing these controls during the front-end engineering and design (FEED) can ultimately protect a company and its workforce during facility operation and can turn major capital projects (MCPs) into valued legacy operations.


It is commonly said that “health and safety are good for business” without seeing substantiated claims. However, if health and safety truly are good for business, it should be demonstrably so. This may involve an evaluation of the costs vs. benefits of each health and safety initiative, as well as the feasibility of implementing them. One such initiative is hearing preservation.

Cost/benefit analysis (CBA) is an ­important tool that can be used to compare the net economic worth of various health and safety initiatives to determine how best to allocate finite project resources to maximize a project’s value. Various international cost/benefit models exist to help companies perform economic evaluations of health and safety initiatives. An Australian ALARP model recently used by Chevron Australia during the design of an offshore production facility in the North West Shelf of Western Australia is one of them.

Additionally, discounted-cash-flow (DCF) analysis is introduced as a means of supplementing conventional CBA to help decision makers determine when, during the lifetime of a project, engineering noise controls should be implemented to maximize a project’s net present value (NPV).

The decision to implement effective engineering noise controls is not based solely on economics, but it is a major driver behind the selection and implementation of proposals that can affect a company’s bottom line. Other key drivers are legislation and business ethics or cultural expectations.

Legislative Drivers

Noise legislation in the Australian offshore petroleum industry combines “goal-setting” and prescriptive requirements.

The goal-setting legislation, governed by the Offshore Petroleum and Greenhouse Gas Storage Act 2006, requires the registered operator of a facility to take all reasonably practicable steps to ensure that the facility is safe and without risk to the health of any person at or near the facility. In other words, the onus is on the operator to demonstrate that all reasonable steps have been taken to protect the health of any person at or near that facility.

With respect to noise management, this duty is supplemented by a prescriptive requirement under the Offshore Petroleum and Greenhouse Gas Storage (Safety) Regulations 2009. These prescriptive requirements are explicit in nature. Therefore, exposures above the exposure standard alone are not enough to establish noncompliance with the regulations; however, excessive exposures and noncompliance with the approved code of practice is.

The legislation as written does not require new offshore-facility designs to incorporate all reasonably practicable engineering noise controls to protect future workers. Rather, a person must first be exposed to a noise source before an operator is legally required to do anything about it. This may seem counterintuitive to best-practice facility design and suggests that the legislation is not a major driver toward quieter facilities; however, the reality is very different.

Should a proposed operator of a facility undertake a noise-exposure study during FEED and find that noise exposures would probably exceed the exposure standards when that facility is fully operational, they can do one of three things:

  • Implement all reasonably practicable engineering noise controls before the production phase of the facility
  • Implement some engineering noise controls but not all that are reasonably practicable
  • Do nothing (i.e., implement no further engineering noise controls before the production phase of the facility)

If a facility owner chooses to do nothing during FEED (Option 3), it is accepting that it would likely be allowing workers on the facility to be exposed to a level of noise in excess of the exposure standards. Therefore, Option 3 is likely to put the operator in a position of noncompliance when the facility becomes operational.

During the production phase of a facility, the onus is still on the operator to demonstrate to the regulator that all reasonably practicable steps have been taken to minimize noise exposures on the facility. However, it is potentially much more expensive to make this demonstration when the facility is operational than during FEED or even detailed design. If some controls are implemented before production (Option 2), it might lessen the effect of expenditure later on and potentially the likelihood and severity of regulatory intervention (regulatory risk), but it may still occasionally give rise to conditions in which workers are overexposed to noise.

Alternatively, Option 1 may be adopted, which involves the consideration and subsequent implementation of all reasonably practicable engineering noise controls before the facility’s production phase. This should be the design goal of any offshore facility in Australia because it is the most cost-effective and defensible approach to managing both regulatory and occupational-noise risks.

Fig. 1

ALARP diagram.

shows what is meant by the term ALARP. ALARP is determined when the risk to health has been reduced as far as can be achieved without the costs of implementing the control becoming disproportionately higher than the benefits of having it. Further cost is unnecessary and can be considered wasteful.

Commercial Drivers

Fig. 2

Cost vs. time in application of engineering noise controls.

indicates the general relationship between the cost of implementing engineering controls and flexibility to make design variations as an MCP progresses from FEED to operation.

During FEED, capital expenditure is the most significant cost that needs to be considered; however, as an MCP moves toward detailed design, should re-­engineering and variations be required, then additional labor and contractual costs can quickly mount. This can become compounded further if a retrofit is required during the production phase, with the introduction of further re-­engineering, variations, installation costs, piping modifications, commissioning costs, and loss of production.

Fig. 3

Cost comparison of implementing engineering noise controls during various phases of an MCP. The model presents costs in 2010 dollars and does not account for projected inflation, foreign exchange rates, or other cost factors, including the time value of money.

shows how an initial outlay of Australian dollars (AUD) 300,000 during FEED can increase to AUD 725,000 by the end of FEED if re-engineering and variations are introduced. In comparison, the identical changes made a few years later during operations could cost AUD 2,275,000 in 2010 dollars.

Therefore, considering appropriate engineering controls during FEED can significantly reduce the financial outlay compared with implementing the same controls later. Furthermore, strategic selection of engineering noise controls during FEED can dramatically reduce noise exposures when the facility starts production.

Incorporating DCF Analysis Into CBA. DCF analysis is a useful tool to assess the value of engineering noise controls because it can be used to demonstrate how investment decisions made during facility design can affect a company’s future earnings per share.

The workplace-interventions net-cost (WIN) calculator developed in Singapore evaluates the net costs of health and safety interventions, such as noise controls, by estimating net-annualized costs, adjusted for the investment costs of the interventions (labor and capital), anticipated productivity enhancements from the changes, and cost savings resulting from averted hearing loss (e.g., litigation, compensation, insurances, rehabilitation). The model is one example of a cost/benefit approach; however, another model is already being applied successfully in Australia and is gaining broad acceptance in the offshore oil and gas industry.

This model, originally developed by an Australian acoustic-engineering consultancy for evaluating engineering noise controls, works by weighing the benefits of each proposed noise control in terms of the overall reduction in noise exposure it provides vs. the costs or uncertainties associated with its implementation. The latter include:

  • Financial costs (i.e., What is the capital cost of the control?)
  • Operability costs (i.e., Does the control affect operation of the equipment?)
  • Maintainability costs (i.e., Does the control affect equipment maintenance?)
  • Process costs (i.e., Can the control affect overall facility performance?)
  • Project-execution costs (i.e., Is the project schedule affected?)
  • Occupational health and safety risks (i.e., Does the control increase or introduce certain occupational health and safety risks?)
  • Integrity of the solution (i.e., Is it proven or novel technology?)

The Australian-consultancy model (the ALARP model) may be used to demonstrate that noise risks are ALARP and is appropriate for this purpose. This is a distinct advantage over the WIN calculator because it can potentially satisfy a regulator that the intent of the legislation has been achieved. However, a disadvantage of the ALARP model is that it does not take into account potential cost savings that may be realized from averted hearing loss, potential productivity enhancements, or labor intervention costs for each proposed control.

The ALARP model could be enhanced by considering productivity effects, labor intervention costs, and savings associated with averted hearing loss and be supplemented by use of DCF analysis to determine when a control should be implemented during an MCP in order to maximize the NPV. Most likely, this will be during FEED for production-critical equipment. DCF analysis, therefore, is an important driver for determining when engineering noise controls should be implemented.

Ethical Drivers

Adverse noise exposure accounts for approximately 37% of all hearing loss in Australia, which is most commonly sourced from workplace noise and recreational noise. Therefore, operators of MCPs in Australia have a societal obligation as good corporate citizens to reduce their contributions to occupational exposure as far as is reasonably practicable. Because it is a very simple process to model noise exposures during facility design, it is becoming increasingly difficult for operators of MCPs to overlook noise control on the facilities they are designing.

An analogy that can be used to compare conventional facility design with an ALARP model for noise control is speeding in a motor vehicle. One may get into a vehicle and choose to speed. Every time one does so, one is breaking the law, regardless of whether one gets caught. This implies that speeding is unreasonable.

Designing a conventional facility where workers are likely to be exposed to unreasonable noise is really no different. Therefore, the ethical solution is to design a facility where people are not exposed to unreasonable noise levels in the first place. In order to do this, operators of MCPs should take all reasonably practicable steps to minimize hazardous noise before production, when noise exposures (hence risk) actually occur.

The analogy highlights an ethical dilemma facing operators of MCPs who may believe that speeding is not acceptable but that exposing workers to unreasonable noise is. In a real sense, a step change in safety culture is required to create a mindset that is intolerant of any level of hearing loss. This ought to be a key goal of any noise-­management ­program.

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156732, “Why Quiet? Legislative, Commercial, and Ethical Drivers Behind the Design of Quieter Offshore Facilities in Australia,” by Andrew Chandran, Chevron Australia, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11–13 September. The paper has not been peer reviewed.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.

Review of Water Use at Canada’s Oil Sands Points Toward Environmental Sustainability

Published August 13, 2013

Concerns have been expressed and published about the amount of water used in Canada’s oil-sands industry. The oil-sands deposits are geographically separated from population and agricultural centers in the province of Alberta and are within some of the most prolific river basins. Analysis shows that the amounts of water used by oil-sands operations are low and sustainable. A track record of continuous improvements at existing operations and the application of new technologies will maintain the sustainability into the future.


The three oil-sands deposits within the province of Alberta. In-situ oil-sands recovery takes place within all three deposits. Oil-sands mining is found only within the Athabasca deposit.

Canada’s oil sands are in three deposits in northern Alberta (Fig. 1). The oil-sands deposits hold 1.8 trillion bbl of oil with 169 billion bbl of economically recoverable reserves. This represents 97% of Canada’s oil reserves, which are the third largest in the world.

The term “oil sands” is used to describe unconsolidated bituminous sands. The oil saturation in the sands has very high viscosity and is commonly called bitumen or tar. The deposits are found within the McMurray, Clearwater, and Grand Rapids formations of the Mann­ville group. They are of varying depth, from near surface in some parts of the Athabasca deposit to more than 300 m deep in the Peace River and Cold Lake deposits. Where the oil sands are shallower than 70 m, they may be mined by surface strip mining. This represents 3% of the surface area of the oil sands and 20% of the reserves. The remaining 80% of reserves across all three deposits are accessible only by use of in-situ recovery methods. Both mining and in-situ methods are water based.

How Water Is Used in Canada’s Oil Sands

Because of the high viscosity of the bitumen within the oil sands (8–12°API, >50,000 cp), it does not flow easily and is difficult or impossible to recover with conventional oil methods. The vast majority of commercial operations rely on hot water or steam to reduce the viscosity of the bitumen to allow its recovery.

For in-situ methods, this involves the injection of steam into the oil-sands reservoir and subsequent recovery of the bitumen once it is reduced in viscosity. For mining, the water is used to slurry the oil, transport it, and finally separate it from the ore.

Water Use for In-Situ Oil-Sands Recovery Methods. In areas too deep for mining, oil is extracted from the reservoirs by use of steam injection. The two commercial techniques currently used for in-situ recovery are cyclic steam stimulation (CSS) and steam-assisted gravity drainage (SAGD).

A schematic showing the in-situ thermal oil-sands process of CSS.

CSS uses the same oil wells over multiple cycles to inject steam and to recover oil (Fig. 2). Each cycle consists of three stages. In the first stage, steam at approximately 300°C is injected under pressure into the reservoir. The heat from the steam then is allowed to equilibrate in a reservoir soak stage. In the third stage, the hot and lower-viscosity oil is pumped from the reservoir along with condensed steam and sent to a central processing facility. The cycle is then repeated. A typical multiwell pad at the Cold Lake operation will go through 8–12 cycles.

SAGD (Fig. 3)

A schematic showing the in-situ thermal oil-sands process of SAGD.

uses precision horizontal drilling to position horizontal well pairs such that one well is above the other within the oil-sands reservoir. The upper well is used to inject steam (at approximately 200–250°C) into the formation where it rises and percolates through the oil-sands deposits, creating a steam chamber. The steam displaces and heats the bitumen, which flows downward by gravity and is recovered by pumping the lower well.

For both CSS and SAGD, the water produced with the bitumen is separated and reinjected into the reservoir. The recycle rate depends on the supply and demand for steam in the operation, the quality of the produced water, and the technology used for water treatment. In all operations, if the produced-­water volume exceeds the steam-injection volumes, then water must be disposed of through deep-well injection. Usually, however, and always during startup of a new operation when there is little or no produced water, the volume of produced water is less than the volume required for steam. In these cases, new water volumes (called makeup water) are required to make up for the shortfall.

Water Use for Oil-Sands Mining. Fig. 4

A schematic showing the key steps, water sources, and process streams involved in an oil-sands mining oil operation.

is a schematic of how bitumen is produced from oil-sands mining operations. After the overburden is removed from above the oil-sands ore, large shovels capable of up to 100 t/load fill large haul trucks with capacities of up to 400 t/load. The haul trucks transport the ore to a crushing facility, where it is crushed and mixed with water to create a slurry that is transported by pipeline (called hydrotransport) to a central processing facility. The agitation and mixing during hydrotransport begin the process of separating the bitumen from the oil sands. At the processing facility, the bitumen is separated from the slurry and sent to an on-site upgrader or off-site refinery. The waste products consisting of residual bitumen, sand, fine particles, and water are sent to a tailings area, where the water is separated from the solids and recycled into the process. Traditional tailings technology uses tailings ponds to settle the solids from the water.

During the extraction process, the oil-sands ore is converted from a compact bitumen-bearing porous medium to a looser water-bearing tailings product. The bitumen is essentially replaced with water. However, because the tailings have more pore space than the original ore, the ratio of water used to bitumen produced is greater than unity.

The water sources for oil-sands mining operations include the recycled tailings water, Athabasca River water, groundwater, and surface water runoff. The largest overall water source is the recycled tailings water, which, after startup, represents approximately 80% of the water used in the operations.

Natural Availability of Water in Alberta’s Oil-Sands Areas

On a global scale, Canada has 7% of the annual renewable water supply and one of the largest per-capita water supplies, with an excess of 70 000 m3 available per person per year, an average drainage yield of 3.4 trillion m3/a, and national water usage of less than 10% of supply.

On the basis of 2009 numbers, the Canadian government has licensed or allocated 9.9 billion m3 of fresh water, or 7.6% of provincial supply, for use in Alberta. The oil and gas industry is allocated 830 million m3, which represents 8.4% of the provincial allocations and 0.6% of the provincial water supply.

The oil-sands industry is distributed across the northern half of the province, within the Peace, Beaver, and Athabasca river basins. The total water allocations in the Peace and Athabasca river basins are 0.4 and 4.3%, respectively. In all basins, the allocation to the oil and gas sector (which is dominated by oil-sands production in these three basins) is 3% or less of available average annual supply.

Actual Water Use, Forecast Water Use, and Continuous Improvement for Oil-Sands In-Situ Operations

The principal water sources for the in-situ thermal industry are recycled produced water, fresh surface water, fresh groundwater, and saline groundwater. With recycling performance of approximately 90%, recycled produced water is by far the largest water source used. For makeup water, historically the industry has relied on fresh water. However, over the past several decades and increasingly over the past 10 years, industry has been increasing the amount of saline makeup water as an alternative to fresh water.

Between 2002 and 2010, the growth in saline-water use has outpaced the growth in freshwater use to the extent that saline-water use has now exceeded freshwater use. In 2010, the total freshwater use was 17.5 million m3, which is split between the Beaver River basin (7.4 million m3), the Athabasca River basin (6.1 million m3), and the Peace River basin (4 million m3). These volumes correspond to only 0.02% of the average natural flows in these basins. Individually, the water use corresponds to 1.2% of Beaver River flows, 0.03% of Athabasca River flows, and 0.006% of Peace River flows.

In 2010, productivity for the in-­situ industry was 0.43 (17.5 million m3 of fresh water to produce 40.8 million m3 of bitumen). This value is used to project freshwater use. By 2030, this assumption results in a freshwater use of 78 million m3. However, given the trend toward saline water over the last 10 years, 78 million m3 is likely a high-volume case. If the trends over the last 10 years for reduction in fresh water are followed, then the resulting use in 2030 will be 38 million m3, with a freshwater-to-bitumen productivity of 0.21. These numbers represent a range of 0.04–0.09% of available average flows in the Peace, Beaver, and Athabasca basins and clearly represent a sustainable water use.

Actual Water Use, Forecast Water Use, and Continuous Improvement for Oil-Sands Mining Operations

All oil-sands mining occurs within the Athabasca River basin, as shown in Fig. 1. Similar to in-situ operations, the largest source of water used in the mining extraction process is recycled water. In general, approximately 80–90% of the water used to recover bitumen is recycled process-­affected water. Unlike in-situ operations, however, the use and storage of process-affected water and tailings in open mine pits and tailings impoundments on the surface limit the amount of saline water that may be used in the operation. For this reason and the potential for disruption of the extraction process by some salts, the principal source of makeup water for oil-sands mining is fresh water.

Approximately 71% of the fresh water is sourced from the Athabasca River. The remaining makeup water is sourced from fresh groundwater (6%) or surface water runoff collected at the mine (23%). These values vary with the weather and the season. Because oil-sands mines take a long time to design and construct after approvals and water licenses are received, the water allocations outpace development. For these reasons, actual water usage is significantly less than allocated water. During 2009–11, an average of only 22% of oil-sands-mining allocations was used.

Water use tracks bitumen production fairly closely. Peaks in water use typically correspond to the startup of new mines or to expansions. Mines have a higher water use in startup years because it can take time to build enough water inventory to start recycling from the tailings areas. To avoid this issue, mines can partly fill tailings areas with water before operation to enable the recycling system to function earlier. In either case, there is a peak in water withdrawals during mine startup.

Recent projections show mining production will grow to 1.33 million B/D (77 million m3/a) by 2020 and 1.89 million B/D (110 million m3/a) by 2030. Using the average productivity of 2.5, Athabasca River withdrawals are forecast to be approximately 6 m3/s (194 million m3) in 2020 and approximately 9 m3/s (277 million m3) by 2030. These represent 1–1.4% of the average annual flows at Fort McMurray. In 2009, the Oil Sands Developers Group conducted a projection for two very aggressive growth cases of 2.5 million B/D and 3.5 million B/D of bitumen by 2020. It was determined that water requirements could grow to between 11 and 16 m3/s or 1.5–2.5% of the annual average flows of the Athabasca River at Fort McMurray for the two cases. Thus, even aggressive-growth cases use a small percentage of annual average natural flows.


Summing all of the 2030 projected freshwater demands for both in-situ recovery and oil-sands mining results in a requirement of 428 million–469 million m3, which is approximately 0.4% of the provincial water supply and 0.5% of the natural flows of the three basins containing the oil-sands deposits. Given continuous improvement and advances in technology, it is expected that these projected volumes will drop. Nonetheless, current projections show that, by 2030, only 0.4% of the water in the province of Alberta will be used to produce 80% of Canada’s total crude-oil output.

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156676, “Water Use in Canada’s Oil-Sands Industry: The Facts,” by Stuart Lunn, Imperial Oil Resources, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11–13 September. The paper has not been peer reviewed.

For a limited time, the complete paper is free to SPE members at www.spe.org/JPT.

Extensive Environmental-Monitoring Project Relies on Integration of Several Networks

Published August 12, 2013

A comprehensive environmental-monitoring project in the Agri Valley in southern Italy has been developed to ensure continuous management of the environmental effects of Eni’s oil treatment center there. This project is able to control the environmental effects of exploration and production in a large area around the plant (100 km2). It is characterized by a complete integration of several networks, stations, and systems used to monitor simultaneously air quality, noise, odorous emissions in terms of olfactory nuisance, groundwater and soil quality, ecosystems status, and ecological biodiversity.


The area where the environmental-­monitoring project was developed is characterized by sites that have community-level protection, especially areas protected because of national parks, widespread woods, rivers and streams of high quality, and springs and ground­water of great regional and national importance for the production of safe drinking water.

Eni’s oil treatment center in the Agri Valley.

Eni’s oil treatment center in this territory collects the production from 24 oil wells, amounting to approximately 104,000 BOPD (Fig. 1). 


The environmental-monitoring plan consists of environmental-monitoring networks on more than 100 km2 at altitudes between 600 and 900 m. The system includes monitoring networks relevant to the following environmental variables:

  • Air quality
  • Biosystems
  • Bad odors
  • Noise
  • Microseismicity
  • Ecosystem
  • Air Quality

The network consists of four monitoring units placed 2.3–4.8 km from the oil center. The sites were chosen according to a model that predicted the spread of emissions from the oil center. The air-quality-monitoring stations were installed outside the plant to continuously identify the effects that production activities have on the quality of the air and to provide operational warnings to avoid any negative effect on the surrounding territory.

Each unit is provided with computerized instruments, allowing continuous monitoring of the levels of carbon monoxide, hydrogen sulfide, sulfur dioxide, ozone, nitrogen oxides, benzene, toluene, xylene, methane, nonmethane gases, volatile organic compounds, polycyclic aromatic hydrocarbons, and radon, and monitoring of meteorological standards (e.g., wind speed and direction, rainfall levels, humidity, temperature).

The data received continuously from the monitoring units are reported in real time on the Web and in the control room of the plant and are compared continuously with information on pollution standards taken from the chimneys of the oil center.


In close correlation with the air quality, a biomonitoring system focused on lichens has been developed. This does not consist of a direct detection of negative effects on the environment but allows measurement of any changes in the normal conditions of the components of the ecosystems reactive to pollution (in this specific case, lichens). In fact, lichens are specific indicators of biological effects of air pollution. As biological indicators, lichens are a useful instrument to ascertain the effects of pollution, eutrophication, climate change, and forest management.

The ecological variations caused by environmental pollution can appear in bodies at three different levels:

  • Morphological or structural variations
  • Increase of polluting substances
  • Alterations in the composition of animal and plant communities

The aim of the lichen biomonitoring network is to build a permanent pool of survey stations to determine the current conditions of the survey area (with particular reference to the atmospheric component), which will be kept as a reference point for evaluation of changes in the environmental conditions.

To decide the best locations for the network, the territory was divided into 1-km-wide cells. Following that scheme, 33 points in the Agri Valley affected by the presence of the oil center were identified.

The stations of the lichen biomonitoring network are used to determine the following indicators:

  • Lichen biodiversity through the application of the lichen biodiversity index, applied to assess environmental quality at the 33 stations
  • Bioaccumulation study on elements of environmental importance and toxicological interest in lichen transplants for the use of lichens as biomonitors for traces of atmospheric deposition (a lichen-transplant technique will be used to create detailed maps regarding the deposition of elements and the study of the relevant temporal changes)

Bad Odors

Electronic nose.

Within the environmental-monitoring plan, it has been the intention to determine potential odors disturbing people living near the oil center. The monitoring activity is divided into two stages. The first stage is to determine the concentration of unpleasant odors in gas samples by using a dynamic olfactometry, a discontinuous sampling method. The second stage, a continuous measuring method, uses an electronic nose (Fig. 2). 


The survey method uses a group of people who behave as sensors. Each examiner is trained and chosen according to sensorial and behavioral standards, keeping in mind the limitations of the regulation applied. The method is based on the identification, on the part of a test group, of the threshold of the sample’s olfactory result—that is, the limit within which, after having been diluted, the odor is perceived by 50% of the examiners.

For the malodorous sample to reach said threshold, an olfactometer is used. This instrument is able to dilute the sample of malodorous gas with neutral air, which is odorless, according to precise reports.

Together with the discontinuous-sampling odor monitoring and laboratory analysis, a continuous measuring campaign is conducted with electronic noses. An electronic nose is installed outside the plant next to one of the air-quality-­control stations to measure the olfactory effect of the same plant for 2–4 weeks.


The noise-monitoring system is made up of four measuring stations. Two are placed near the oil center to measure the noise directly related to the activity taking place inside the plant. Two others are placed next to the population centers near the plant. Each station contains a sound meter/analyzer for continuous measurement of the sound pressure level, maximum or minimum sound levels, peak sound pressure, and the noise spectrum. The measurements are taken at a height of 1.5 m from the surface of the station, in normal thermohygrometric conditions, related to the measurement site.


The network is made up of 14 detection stations distributed in an area of approximately 1500 km2 around the oil center, aimed at monitoring earthquakes with magnitudes less than 3 on the Richter scale. This network is important for the emotional well-being of the neighboring population because it eases concerns about the correlation between earthquakes and oil and gas operations.

The peripheral stations are provided with geophones. The signals acquired in each station are transmitted through a global system for mobile communications phone signal to the data-processing center, which extracts the following information:

  • Local earthquakes, those having an epicenter inside the network or less than 10 km from one of the stations
  • Regional earthquakes, those having an epicenter 10–100 km away
  • Nonregional earthquakes, those having an epicenter more than 100 km away


Soil, Subsoil, and Underground Water. Soil, subsoil, and underground-water monitoring is conducted to check the quality of the environmental matrix near the plant, to verify any infiltration of pollution, and to monitor the conservation of the territory to ensure sustainability of the oil activities in the Agri Valley.

The characterization of the soil and subsoil matrix is conducted through geological surveys for the local lithostratigraphical reconstruction and through soil samples taken for chemical surveys.

Surface Water and Sediments. The monitoring of surface water and fluvial sediments is conducted with respect to what is foreseen by Italian regulations and, in particular, considering the main water resources present in the area. For each point at which the surface water is measured, two samples are taken, one from the surface and one from deeper.

The monitoring activity allows determination of the quality for each survey period near each water source studied, guaranteeing, in time, continuous control of the characteristic ecological condition of the matrix.

Vegetation. The aim of the vegetation monitoring is to recognize not only the species but also the different types of habitats to which the species are bound for their survival.

A phytosociological method, which studies the geographical, physical, and biological distribution of the vegetable communities and their evolution in space and time, was used to identify and define vegetation habitats. The starting point is that no plant lives in isolation; but, with others of the same species, they create a population. Multiple different species (populations) make up a vegetation community, which presents the biological proof of the features of a certain habitat.

Phytosociology attempts to study vegetation communities (habitat), their distribution, and all the physical and biological relationships characterizing their evolution in space and time.

The method is based on three fundamental principles:

  • The vegetation groupings are characterized by a precise floristic composition.
  • Among all the species making up a community, some better represent the complex relationship among species, communities, and environment. These are defined by high-frequency differential and common features.
  • Said species can be used to form a hierarchical classification of groupings, in which the association is the fundamental element.

The methodology consists of two stages. In the first stage (analytic stage), through the picking of samples, the vegetation communities are analyzed from a qualitative (evaluation of the species present) and quantitative (evaluation of their abundance) point of view. In the second stage (synthetic stage), the different samplings are compared and the syntaxonomical elaboration is conducted, leading to a definition of the typology of the vegetation through the floristic, ecological, and statistical comparison of the samplings.

Macrofauna and Ground Micro­fauna. The superior vertebrates (birds and mammals) are particularly suitable for monitoring the quality of the environment on a large scale. The ubiquity of both classes, or, better, their adaptation ability in a large range of environmental typologies, allows their use in different conditions. Because they play a very substantial role in the trophic chains (food chains), studying them can provide information about alterations at a superior level (community and ecosystem).

Birds can provide excellent indications of both chemical pollution (as in the case of insectivores and rapacious birds) and alteration of habitat composition and structure (especially forest or ecotonal habitats).

The great amount of some species can supply quantitative indications on the availability of a certain habitat (low-selectivity target species), while other species that are more demanding about the specific composition and structure of the habitat in which they live supply qualitative/quantitative indications on the habitat available (selective target species).

Mammals (with the exception of bats), not having the capacity of bird dispersion, are much more sensitive to habitat alterations because, during their displacements, they can be impeded by the presence of altered environments that isolate still-suitable environments.


The environmental-monitoring project in the Agri Valley allows a continuous management of the environmental effects of the activities of the Eni oil treatment center. This project is unique in the upstream industry and represents a possible turning point in the oil and gas industry because of its capability to control all the environmental effects of exploration and production, especially in an environment with human communities, and because it can demonstrate the oil and gas industry’s commitment to business ­sustainability.

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156294, “Innovative Environmental Monitoring for Upstream Onshore Installation,” by Paolo Carnevale, SPE, and Silvia Di Croce, Eni, prepared for the 2012 SPE/APPEA International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production, Perth, Australia, 11–13 September. The paper has not been peer reviewed.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.

Management System Approach Aims To Meet Human Rights Expectations

Published August 10, 2013

A range of external expectations exists for companies to demonstrate how they respect human rights, including having business processes in place to prevent or mitigate human rights issues caused by the company’s projects or operations. The International Petroleum Industry Environmental Conservation Association (IPIECA) has responded to the emergence of external guidelines in connection to implementing human rights due diligence by improving existing management systems and processes.


United Nations Guiding Principles on Business and Human Rights. The ­United Nations Guiding Principles on Business and Human Rights were developed through an iterative process spanning 6 years and involving extensive stakeholder consultation.

In the first stage of the work, John Ruggie, United Nations special representative to the secretary-general, conducted 3 years of research to develop the global Protect, Respect, and Remedy Framework on business and human rights. Ruggie developed the framework to help clarify the distinct roles of states and businesses in human rights. It rests on three interdependent pillars—the state duty to protect against human rights abuses by third parties through regulation and legislation; the corporate responsibility to respect human rights through due diligence; and the need for citizens to have access to effective remedy, both judicial and nonjudicial.

The United Nations Human Rights Council endorsed the framework in 2008. Upon endorsement, Ruggie established the United Nations Guiding Principles. The principles supplement the framework by outlining how governments should meet their duties and how companies should demonstrate their responsibilities.

IPIECA’s Business and Human Rights Initiative. IPIECA launched a 3-year business and human rights project that leverages the collective experience and practical knowledge of its members. The objectives of the project are to

  • Support the organizational capability of IPIECA members in two focus areas, company due diligence and community-level grievance mechanisms
  • Serve as the authoritative reference body for the oil and gas industry on business and human rights issues, including the United Nations Guiding Principles on Business and Human Rights and other relevant external guidelines

The project is implemented through the IPIECA Human Rights Task Force, made up of 38 members from 20 oil and gas companies and associations. The task force implements four distinct programs.

Collaborative learning: IPIECA organizes technical workshops, with input from external experts, to support the continuous improvement efforts of its members.

Technical guidance: IPIECA develops and disseminates practical guidance and tools to assist members in managing human rights issues at an operational level.

Strategic resource: IPIECA provides technical expertise to relevant external initiatives and groups with the aim of sharing industry’s insights, experience, and knowledge.

Global engagement: IPIECA actively participates in global forums and initiatives to contribute to the growing body of knowledge and ideas on business and human rights issues.

Human Rights Due Diligence Process

Human rights due diligence processes are not a legal requirement but rather a good industry practice to manage issues and effects associated with business operations. The expectations for companies are

  • Respect human rights in projects or operations
  • Seek to prevent or mitigate potential human rights issues that may be directly caused by the company’s projects or operations, or seek to influence partners and suppliers
  • Have in place policies and processes to manage human rights issues
  • Commit to respect human rights with endorsement by senior leadership
  • Conduct assessments to identify potential human rights issues in projects or operations, have processes to manage the issues, and have a means to track the response
  • Communicate with stakeholders how issues are being addressed
  • Establish a grievance mechanism to address issues raised by the community

According to the principles, the due diligence process has four main expectations:

  • Assessing actual and potential effects
  • Integrating and acting upon the findings
  • Tracking responses
  • Communicating how effects are being addressed

Because human rights can cut across different phases of an oil and gas project life cycle; can be associated with different issues and potential effects; and are managed by different company functions, roles, and responsibilities, there is no one-size-fits-all approach to implementing human rights due diligence.

The business case for human rights due diligence is simple and straightforward: It is good business practice to know the potential human rights issues and effects associated with business operations and to factor them into management plans. This is especially important for oil and gas companies that may operate in countries over several decades and where local conditions and circumstances can change.

Some of the business drivers for improving human rights due diligence can be summarized as

  • Identification and management of potential effects on communities, positive and negative
  • Prevention of disruptions to construction and operations and improvement of business continuity, including providing reliable energy and managing budgets and schedules
  • Improvement of relationships with local employees and communities based on ongoing engagement and dialogue about project issues and other relevant concerns
  • Protection of employees, communities, and company assets from negative effects by providing a safe and secure operating environment
  • Creation of positive contributions to host communities (e.g., improving access to health, education, and livelihoods)
  • Protection of the company’s reputation in the country and internationally (e.g., by being a preferred employer and helping to ensure continued access to new markets and customers)

Organizational Reality

The goal—or hope—of many external guidelines and standards, including the United Nations Guiding Principles, is that they will be institutionalized by companies and broader industry. The process will likely undergo three ­phases—habitualization, objectification, and sedimentation.

Habitualization is a response to a given issue, problem, or challenge that may be pertinent to a particular industry. Objectification is when the practice begins to build up a perceived value within the organization. Sedimentation occurs when the practice starts to become part of normal business process and systems governance among different groups within the organization.

Implementing Human Rights Due Diligence Process

A human rights due diligence process can be framed as a “plan, do, check, act” methodology to manage human rights issues and effects. This methodology correlates with the existing ­management-system processes of many oil and gas companies.

  • It leverages existing mechanisms and governance structures.
  • It enables interaction with the company’s process leads, advisors, and other experts, thereby capturing and spreading relevant experience and technical knowledge and building ongoing support.
  • It minimizes unintended risks, such as identifying potential issues and effects without having a systematic way of managing them.
  • It helps companies to integrate identified potential human rights issues and effects with social, environmental, health, and other effects.

Key Components of Human Rights Due Diligence

The core process components of a human rights due diligence are

Vision/Objectives: A company’s vision and objectives for managing human rights are articulated and reinforced through a formal company code of conduct, corporate social responsibility policy, human rights policy, human rights statement, or some other formal mechanism.

Accountability: Because human rights issues cut across different company functions, appropriate roles and responsibilities, including accountability, are assigned. Company processes, programs, or tools should specify which department is responsible and what the associated roles and tasks are.

Assess/Plan: The assessment and planning includes identifying the phase in the project life cycle; taking inventory of existing processes, programs, and tools that can be used to assess potential issues and effects; collating and reviewing information from prior assessments or external sources; and conducting the assessment to identify, scope, and analyze potential issues and effects.

Implementation: Once potential issues and effects are identified and prioritized, findings should be incorporated into a management plan, which includes communication with internal and external stakeholders as needed, with the intent to properly address and close out the issue or effect.

Review: A set of indicators for monitoring, tracking, and evaluating the plan is built into the implementation process. There is no one-size-fits-all approach to the review process; it varies depending on the company’s existing processes and procedures.

Improve: Once the review is completed and the findings are properly scoped and analyzed, the areas of improvement serve as an internal engagement mechanism to enhance the existing process, procedures, or programs, such as internal or process review sessions.

Implementation Issues To Consider With Human Rights Due Diligence

Several implementation issues for conducting due diligence should be considered carefully, including

  • Clear and appropriate roles and local responsibilities: Because human rights may require cross-functional engagement, clear and appropriate roles, responsibilities, and accountability should be designated.
  • Legal and regulatory issues associated with human rights issues: IPIECA members are recommended to work in close consultation with key functions to properly assess the legal and regulatory context and inform implementation of their due diligence.
  • Handling sensitive information: Implementing due diligence can uncover sensitive, personal, and confidential information that should be handled carefully. Internal procedures for controlling documentation and the exchange of information are recommended.
  • Prioritizing potential issues and effects: Companies should consider prioritizing potential issues and effects to inform their management plans.
  • Engagement and communication: The assessment of potential human rights issues and mitigation measures should involve ongoing engagement and communications with potentially affected and concerned stakeholders.
  • Fit-for-purpose approach: Implementing a due diligence process may vary according to prevailing business processes of the company, size of the project, the prevalence of human rights issues, and the local context of the operations. In all cases, the due diligence process should be ongoing and iterative.

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 164979, “Management Systems Approach to Managing Human Rights Issues,” by Tam Nguyen, Chevron, Bert Fokkema, Shell, Julie Vallat, Total, and Roper Cleland, IPIECA, prepared for the 2013 SPE European HSE Conference and Exhibition, London, 16–18 April. The paper has not been peer reviewed.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.

Safety-Management Leading Indicator Results in Unintended Consequences

Published August 8, 2013

A metric based on a corrective-action-classification system initially appeared to be a valuable leading indicator for management purposes. However, after trial applications, it became clear that, when this metric was used to define performance goals, it had unanticipated consequences that cumulatively and insidiously caused more damage than the accidents it was intended to prevent. Category matching is an upgrade of that original metric and eliminates harmful unintended consequences of corrective-action classifications used alone.


Trailing indicators are by far the most common type of safety statistic. Governments, insurance companies, corporations, and essentially everyone who tracks accidents will record the number and type of injuries, plus the money spent on repairs, machinery replacements, wasted time, or other harmful consequences of accidents. Leading indicators are complicated by the fact that some dangerous acts (e.g., touching high-voltage switchgear) will always produce an accident with severe consequences while other dangerous acts (e.g., running a stop sign) might be repeated hundreds of times without causing an accident. In industrial work situations, no scientifically defensible equation exists where X dangerous acts produce Y accidents with Z fatalities.

The component parts of all accidents and the difference between leading and trailing indicators.

As shown in Fig. 1, accidents come in packages with four components. In reverse chronological order, they are (1) consequences, meaning harm (either injury or damage); (2) the accident itself, an unplanned event; (3) an act of people, not intended to produce the accident; and (4) the reason the accident was not anticipated. A broken leg is never an accident. It is an injury and the consequence of an accident. An accident is an unplanned event, and a fall is always an accident regardless of whether it causes injury. The vast majority of accidents cause little or no harm, but confusing an accident with its consequences is a major obstacle to preventing accidents because the target of corrective actions is not clear.

Accident-classification systems tend to describe accident consequences rather than the accident itself. This is important because corrective actions must change what happens before the accident. If a report states that the accident was an eye injury, then a corrective action would prevent the injury by enforcing existing rules about wearing eye protection. That would have no effect at all on preventing the unplanned event that produced the eye injury.

Precisely separating an accident into its component parts, as shown in Fig. 1, is helpful in focusing corrective actions on the right problem. Corrective actions that focus on preventing the accident will be very different from actions focusing on preventing the consequences of that accident.

In the 1980s, a search for meaningful leading indicators led to primitive methods for classifying corrective actions according to their effectiveness. The methods have evolved considerably since then, but the fundamental concepts remain the same. Basic management theory holds that managers change the course of events in three different ways—direct action, supervision, or management.

The original measurement system allocated points for corrective actions given on accident reports. Each stated corrective action was given one, two, or three points if it met definitions of direct action, supervision, or management, respectively. A weighted average of these points reflected the general strength of corrective actions, and two adjustment factors checked if reporting managers were sensitive to near misses and if they actually implemented the corrective ­actions. The result was an index, a number that was directly related to how well managers identified and solved operational problems.

The problems began when upper management set goals or performance standards on the basis of this index. A management type of corrective action is, in effect, a change in the laws the organization adopts for governing itself. For example, one oil company operating internationally set a standard that required managers to produce an index number that could be attained only by producing rule changes for an unrealistically high percentage of all their recordable accidents. Because nearly all accidents are already covered by rules, either internal or external, that requirement produced a redundancy in rules that increasingly became micromanagerial in nature; and, because rules must be enforced to actually be rules, the requirement amounted to force-feeding the bureaucracy that ultimately suffocates any organization.

Rethinking the Situation

Managers can only change acts of people—either what they do themselves or what their subordinates do. They cannot change physics, chemistry, geology, biology, mathematics, weather, geology, or any natural phenomena. They cannot change the properties of oxygen, fuel, or ignition sources, but they can change the acts of people that bring those fire components together. It follows that no corrective action is possible if an accident cannot somehow be expressed as a consequence of an act of people.

There is an important distinction between safety problems and accident-prevention problems. Both problems and corrective actions can be defined in terms of rules. Category 1 problems are the most common. They involve simple mistakes and violations of standard ­advice, general rules, or other ordinary good work practices that a person normally follows but simply overlooked, provided that the event produced only minor harm. Examples are spilled coffee, scraped knuckles, bumped elbows, twisted ankles, and similar minor events.

When such an event produces serious harm, it always means there is another problem to identify. For example, if coffee is spilled on delicate electronic equipment and causes major harm, then the issue is not the safety problem of spilled coffee but the accident-prevention problem of enforcing or generating rules keeping the potentially damaging coffee away from the electronic equipment.

Problems and corrective actions can be defined in terms of rules. Each act-of-people component of an accident must fit into one of these three categories or a corrective action is not possible.

Three categories of problems are identified in Fig. 2. Category 1 involves an individual following well-known, fully understood rules. Category 2 involves applying rules to other people. And Category 3 involves missing or inadequate rules.

Defining Corrective Actions

In the past, the term “corrective action” was defined as a plan or a prearranged schedule of events leading to attaining some objective. That overlooked the fact that an action must be a verb, not a noun. “To plan” is a verb, but “a plan” is a noun; and, a plan is simply a list of actions, not the actions themselves. A plan to launch a special satellite may involve hundreds of people arranging tens of thousands of detailed step sequences, but none of those steps are actual actions until the appropriate orders are issued and carried out. A launch plan is not a launch, and a planned corrective action is not an actual corrective action until an order is given. A better definition of a corrective action, therefore, is “Someone with authority and followup responsibility issuing an order to someone with the knowledge, skills, resources, and desire to carry out the order.” That correctly indicates that an action is a verb (“issuing”), instead of incorrectly declaring that an action is a noun (“a schedule”). A useful mnemonic device is that corrective actions must have COATS, meaning they must be in the same Category as the target problem and be an Order issued by someone with Authority specifying Times and Substantiation.

Game Playing

An ongoing problem with safety metrics is their tendency to become meaningless game playing. This happens when a new safety program announces, “Employees will get a reward (positive or negative) if this number is achieved.” That number might be any of the usual trailing indicators, but, whatever it is, there is always an incentive to stretch definitions or slant reports to achieve the target number, sometimes at the expense of accurately identifying and fixing underlying problems.

The great majority of accidents are already covered by policies, standard procedures, ordinary good work practices, or other rules. Generating new rules on top of existing rules has obvious harmful effects. It is also true that the majority of accidents are simple individual mistakes that can never be totally eliminated, and, as long as they have no realistic chance of causing serious harm, they do not merit management-type corrective actions or rule changes. Early applications of the original index required managers to maintain numbers that could be reached only by devising corrective actions meeting definitions of management, as opposed to supervision or direct action. The game then became managers looking for opportunities to report corrective actions and looking for easy actions that would satisfy requirements for being good management. They were soon compelled to report incidents that really did not need corrective actions and to report corrective actions that did not really have any positive benefits.

Category Matching

Most of the damage caused by using ­corrective-action classifications as a leading indicator can be avoided by simply making sure that both the problem and the corrective action are well-­defined and in the same category. This category-matching technique has a potential for becoming yet another game and, therefore, should not be used as a target for entry-level managers, supervisors, or safety advisors. It is useful as an analytical tool for midlevel or upper managers to improve accident reporting and make corrective actions more effective. It should not be kept secret from anyone, but not everyone needs to be involved in either calculating or using this analysis method, just as they do not need to be involved with computing receivable days, return on investment, turnover rates, or any other management metric.

Applying a corrective action of one category to a problem of a different category always causes harm, but it is often subtle and unnoticed. That point can be explained easily through training sessions based on category matching, but it is important to avoid blaming, too. If an individual violates a rule, whether general or specific, it does not necessarily mean culpability or intentional misbehavior. Most drivers can remember instances of being surprised to discover that they were exceeding a speed limit, had forgotten to turn their lights on, or had unintentionally violated some other rule. This is another reason category matching should be reserved for use by people not directly involved in the accident itself or in preparing the accident report.

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 164961, “Unintended Consequences of a Promising Safety-Management Leading Indicator,” by Carl D. Veley, SPE, vMBA Consultants, prepared for the 2013 SPE European HSE Conference and Exhibition, London, 16–18 April. The paper has not been peer reviewed.

For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.

Social Marketing Can Drive Safe Behavior

Published July 31, 2013

Is there a way to sell safety behavior like they sell cars? Apparently, safety system leaders can, through social marketing, an innovative concept developed in the 1950s and the 1970s in response to the growing concerns on how best to promote social good.

Elie Daher,  executive vice president and chief marketing officer for United Safety, explains this relatively new and innovative concept.

What is social marketing?

To understand social marketing, we need to go back to the very definition of marketing. Marketing is the process of planning and executing the production, pricing, promotion, and distribution of ideas, goods, and services to create exchanges that satisfy individual goals. Social marketing applies the same principles of marketing; but, instead of exchanging a product for financial gain, social marketing trades individual behavior change for the benefit of individuals and organizations. Examples of successful social-marketing campaigns include campaigns that have encouraged people to use seat belts and follow speed limits.

How can this work within the safety industry?

Social marketing has been found to be effective when behavior change is targeted to a specific group of individuals who share the same characteristics or behavior—in this case, workgroups.

Research has shown that the workgroup most susceptible to unsafe behavior is young workers. Thousands of workers suffer occupational injuries every year, but the 15- to 24-year-old age group has consistently exhibited the highest risk of injuries. The first step to social marketing is to understand why this behavior occurs.

Key factors that contribute to this behavior include young workers’ lack of familiarity with basic safety procedures, the lack of experience to recognize when a workplace situation is dangerous, and a desire to maintain a macho image to be seen as a competent worker.

What comes next after studying behavior?

We then have to identify the social-marketing matrix, often referred to as the four Ps—product, price, place, and promotion. Our products are the benefits of safe behavior, which include greater quality of life, both inside and outside of work. The price workers pay for adhering to a particular safety practice might be a slight reduction in the speed with which a job can be done. Thus, our materials must be able to demonstrate the value of safety, so that the price paid seems worth the safety that is being gained. The workplace is obviously the place where they are most likely to enact safety behavior; but, the benefits of safety behavior extend into their private lives by enhancing their quality of life outside of work.

What about the last P, promotion?

This is where social marketing departs from our traditional safety behavior programs. Another aspect of marketing that we will borrow is the customer-focused approach. Because young workers tend to spend much time interacting in social-networking sites, safety-system leaders must tap these channels to promote safety behavior. Promotion should be done through social-media channels, such as Facebook, Twitter, and YouTube, in addition to traditional media such as prints and posters. The promotion of behavior change among young workers must be in tune with their lifestyle to be able to capture their attention and ultimately influence their behavior.

Have any social marketing programs been successful in the oil and gas industry?

Yes, a few companies and safety councils have implemented social marketing. In 2008, Work Safe British Columbia examined the affect of occupational health and safety materials aimed at workers aged 18–24 in the US and Canada through content analysis and online and focus group discussions. In 2007, ExxonMobil also conducted a similar program for employees who frequently traveled to worksites around the world. Both programs used social marketing in one way or another to promote behavior-based safety to catch the attention of their target respondents.

Do you think social marketing will become popular in the oil and gas industry?

Why not? As an industry, workplace safety has never been more important. The public health sector has used social marketing for years with considerable success. Undoubtedly, the oil and gas industry has the financial capacity and human resources to implement and monitor social marketing campaigns effectively. With management support, safety leaders can easily carry out social-marketing campaigns tailored to specific workgroups (e.g., young workers, frequent travelers, and confined-space entry workers). If they can do it, we can, too.



International HSE Conference Extends Call for Papers to 22 July

Published July 16, 2013

The call for papers for the 2014 SPE international HSE conference has been extended to 22 July. The 2014 International Conference on Health, Safety, and Environment in Oil and Gas Exploration and Production is scheduled for 17–19 March in Long Beach, California.

The HSE conference has been the exploration and production industry’s premier event for the past 20 years. It focuses on challenges and advancements toward health, safety, the environment, security, social responsibility, and HSE management.

This year’s theme—The Journey Continues—will focus on the great accomplishments achieved over time as well as the lessons learned that will affect the future.

Paper submission categories include

  • Personal and Process Safety
  • HSE Management
  • Environment
  • Social Responsibility
  • Process Safety
  • Security and Emergency Response

If your proposal is selected, you could be a part of this respected international event, share your experience, and build fruitful relationships with key stakeholders in the industry.



SPE Holds First HSE Conference in Latin America

Published June 18, 2013

SPE is holding the first Latin American conference on HSE 26–27 June in Lima, Peru. The SPE Latin American and Caribbean Health, Safety, Social Responsibility, and Environmental Conference will bring together experts from two geographic locations to share best practices, technological advances, and new ideas for HSE.

Experts from Latin America and the Caribbean will conduct more than 50 technical and poster presentations that showcase the latest technological advances and innovative applications in HSE. The opening plenary session, “How to Address and Obtain a License To Operate in Sensitive Areas,” features an in‐depth discussion on social and safety risks, control and transportation of hazardous materials, wastewater treatment, and more.

The second day’s plenary session, “Measures and Improvements After Industry Accidents,” addresses the lessons learned from previous accidents and the latest measures and improvements in managing the prevention and response of oil spills.

“This conference is important to the Latin American and Caribbean regions,” said Carlos Arturo Rosas Mota, conference program committee chairman and HSE manager for Schlumberger Peru. “It is a great opportunity to share best practices and case histories and to learn from each other’s experience. Doing so will help us in our efforts to improve HSE performance for the betterment of the entire industry and all its stakeholders.”

Technical sessions, which will have simultaneous translation in English and Spanish, fall into five categories.

  • Environment: Topics include “Designing an Optimal Offshore Pipeline Route To Minimize Impacts on Coastal and Marine Biodiversity,” “The New Structure for International Oil Spill and Preparedness & Response,” and “The Challenges for the Treatment of Drilling Fluid Wastes Generated by E&P Industry in Brazil.”
  • HSE Management: Topics include “The Human Chain—A Different Approach to Behavior Safety Program Through the Use of Social Marketing Concepts,” “Assessing Risks and Regulating Safety Standards in the Oil and Gas Industry: The Peruvian Experience,” and “Building Strong Stakeholder Relations and Minimizing Operational Risks in the Oil and Gas Industry Through Market‐Based Certification.”
  • Social Responsibility: Topics include “The Social Side of Unconventional Oil and Gas in Latin America,” “Innovative Ways to Inspire New Employees to Embrace an HSE Culture,” and “Social Responsibility: A Comparative Study of Oil Majors—Who is the Best?”
  • Safety: Topics include “Integrity Management System Based on Risk Analysis: A Tool to Prevent Failures on Pipelines Which Cross Amazonian Jungles and the Andes,” and “A Study of Rollover Occupant Injury Mitigation Using Dynamic Testing To Evaluate Alternative Protection Systems.”
  • Health: Topics include “Improving the Health of the Workforce May Improve Work Performance,” “Cardiovascular Risk Impact in the Oil Industry,” and “Obesity in the Oil and Gas Industry Population.”

The conference includes an exhibition that will showcase some of the latest developments and trends in HSE.

New Water-Treatment Technologies Tackle Offshore Produced-Water Challenges in EOR

Published June 1, 2013
Polymer injection was used on the offshore Dalia field in Angola. Total E&P has contracted Technip to provide flexible pipe for the development project. Courtesy of Technip.

Polymer injection was used on the offshore Dalia field in Angola. Total E&P has contracted
Technip to provide flexible pipe for the development project. Courtesy of Technip.

The treatment of produced water can be challenging because of variability in both quality and quantity of the produced-water stream. Produced-water quality is dependent on the dynamics and constituents in the oil reservoir, including added injection chemicals and waterflood injection quality. As a consequence of the wide range of variability in both the produced-water quality and the final treated-water quality requirements, it is not easy to determine which technologies are most appropriate for effective treatment and handling—there is no “one size fits all” solution. Varying environmental and regulatory requirements for produced-water treatment as a function of region and location contribute added complexity in decision making. Finding the best treatment solution and wading through the multitude of emerging produced-water treatment technologies have become significant challenges for the upstream oil and gas industry.

Considering the current price of oil, there is renewed interest in enhanced oil recovery (EOR) and, specifically, chemical enhanced oil recovery (CEOR), which holds the potential to unlock millions of barrels of currently unrecoverable oil from offshore reservoirs. However, significant technical and regulatory challenges must be addressed before these techniques can be fully utilized by the industry. Driven by the urgent need for creative, cost-effective produced-water management solutions that protect public and private-sector interests, new treatment technologies are available that offer alternatives to traditional approaches. This is particularly applicable to the treatment of produced water in offshore EOR applications such as CEOR.

Evolving Needs in Produced-Water Treatment

As waterflooded fields mature and continue producing, the amount of produced water to be handled increases, often exponentially. The pressure on operators to manage these larger than anticipated flows of produced water is complicated by the fact that many treatment systems were not designed to handle the higher flows, or to achieve the level of treatment now required by more stringent regulation.

Today, produced water is the highest-volume byproduct associated with oil production, comprising as much as 98% of the total volume produced at the wellhead. Globally, an estimated 70 billion bbl of produced water is generated annually. Of this volume, only about 16% is reinjected. In 2008 alone, 19 billion bbl of produced water were discharged into the ocean. As environmental regulations are becoming more stringent for offshore discharge, the driver for produced-water treatment innovation is significant, and continues to increase as the industry plans for offshore deployment of CEOR. For example, the northeast Atlantic Ocean currently has a zero liquid discharge (ZLD) regulation in place for offshore production. According to a 2012 study, produced-water reinjection (PWRI) is the only viable technology that can fully address this type of regulation.

Statistics concur with this finding. A recent survey of operators implementing EOR reported that more than 50% of projects utilize produced water as the source water for EOR reinjection.

Today, water-based EOR, including low-salinity flooding (LSF) and CEOR, is experiencing increasing interest. In evaluating offshore water-based EOR, seawater is generally the most obvious and accessible water source for injection. But, when combining the produced-water regulatory drivers with the growing water-based EOR demands, produced water is expected to float to the top of preferred injection-water sources, if cost-effective treatment is available. Ideally, this water treatment would be highly efficient and able to handle unique aspects of EOR projects, particularly in offshore applications where weight and footprint are more important relative to other features of the treatment system.

Produced-Water Management Challenges in Offshore EOR

Some water-based EOR techniques, such as LSF will have negligible effects on the produced-water stream. But, conversely, a CEOR flood will significantly affect the produced water, and PWRI will be used in these projects. There are numerous produced-water management challenges in offshore CEOR applications, including: 1) technology issues surrounding the influence of CEOR chemicals on conventional produced-water treatment equipment; 2) regulatory requirements and marine environment considerations; and 3) reservoir health concerns when using PWRI. To address these issues, a higher level of produced-water treatment than currently practiced by the offshore industry will likely be required. Each issue is further addressed in the following text.

Technology Challenges

Produced-water management strategies are important to characterize to fully comprehend the criteria for effective produced-water treatment technologies for offshore applications.

Conventional offshore produced-water treatment is most often accomplished by hydrocyclones or gas flotation processes deployed downstream of a three-phase separator. As regulations become more stringent for final oil and suspended solids concentration, or as other forms of produced-water management such as PWRI are more heavily utilized, use of tertiary produced-water treatment for polishing is expected to increase.

To meet these objectives, conventional black walnut shell filters (BWSF) could be used for polishing. However, although the filters have tested successfully in the North Sea at pilot scale, the number of applications has been limited by technical design challenges related to weight, footprint, and backwash-water requirements. As a result, few full-scale offshore systems have been implemented. To help address these issues, new polishing technologies are being considered for offshore projects.

Regulatory Challenges

Current regional discharge requirements for offshore produced water are moving toward ZLD, and some regions have already mandated this requirement. The Norwegian Continental Shelf, regulated by the Norwegian Climate and Pollution Agency (KLIF), is moving to adopt an approach in which PWRI availability is targeted at 95%. Many of the systems currently in operation employing PWRI have achieved less than 80% uptime. Only a few of the operators surveyed were able to achieve 95% uptime.

Implementation of some forms of EOR, such as CEOR, can change offshore produced-water management practices. For instance, regulatory agencies have indicated that some alkali, surfactant, and polymer (ASP) CEOR chemicals may be categorized as highly harmful to aquatic environments. With regard to the North Sea, the proposed Oslo and Paris Convention for the Protection of the Marine Environment of the Northeast Atlantic (OSPAR) rules could categorize polymers and surfactant components of ASP as either black or “red” chemicals. Under this category and based on proposed risk-based permitting strategies, discharge of produced water containing these compounds would be unacceptable to OSPAR. Nongovernmental environmental organizations have also become aware of the likelihood of offshore CEOR operations and are sensitive to planned projects.

The siting of injection wells poses another challenge in the North Sea. Under current regulations, offshore produced water can be disposed of via injection into nonproductive formations to comply with Norwegian availability goals. This regulation provides operators with a secondary disposal alternative for CEOR produced water. The use of a nonproducing reservoir also allows the operator to use injection pressures beyond formation fracture pressure. The capability to operate at pressure above fracture pressure helps to ensure water-injection system availability. However, upgrading infrastructure to enable produced-water disposal into a nonproducing reservoir, particularly on older platforms, can be prohibitively expensive because of the cost of drilling additional disposal wells. By comparison, PWRI can be an economically attractive option.

Reservoir Health

If reinjection is the preferred form of produced-water management, project teams must carefully consider produced-water treatment requirements to prevent reservoir damage and oil resource degradation. If produced-water treatment is poor or ineffective, the reservoir may sour, scale, fracture, or plug. Similarly, if the produced water is to be blended with other injection fluids during a CEOR flood, these fluids should be closely scrutinized with regard to blending compatibility and overall blended-water quality objectives to ensure the CEOR flood is successful. If the reservoir loses injectivity during PWRI, the platform could be forced to operate at reduced capacity or shut down until injectivity can be restored.

Typical produced-water treatment approaches target oil and suspended-solids removal. PWRI requires less than 30 ppm oil in water and practical reservoir souring controls to be successful.

Produced waters can also contain elevated levels of sulfate and organics that can stimulate sulfate-reducing bacteria (SRB) growth in the reservoir during CEOR. SRBs convert sulfate to hydrogen sulfide, which may lead to reservoir souring and health and safety risks for platform operators, or other operational issues. Iron, which is detrimental to polymer performance, can also be present in elevated levels in the produced-water stream. A successful PWRI blending plan must compensate for these additional components during a CEOR flood.

Technologies and Strategies for PWRI in Offshore EOR

Fortunately, new technologies and strategies can be used to achieve a suitable water quality for PWRI during offshore EOR applications. When selecting treatment equipment, the impact of CEOR chemicals on conventional treatment equipment should be understood. As a result of anticipated treatment-system performance, a polishing step may be required, especially if PWRI is practiced and when further desalination is required for salinity control or for hardness removal. During a typical project, all identified treatment requirements should be evaluated as well as operation before and after CEOR chemical breakthrough.

Effects of CEOR on Conventional Offshore Treatment Systems

Two aspects of CEOR chemicals are especially challenging for conventional produced-water treatments systems that rely on gravity separation: 1) the ability of the surfactant to form emulsions comprising small stable oil droplets, and 2) the increased viscosity and non-Newtonian fluid effects from the polymer. An additional effect of EOR and specifically CEOR may be a change in oil properties when oil components that adhere to clays and rocks are released.

Stoke’s law depicts the effects of CEOR chemicals on typical produced-water treatment systems.

The true effect of the CEOR chemicals on the produced-water treatment is experienced after breakthrough has occurred—when residual chemicals and their properties are present in the produced-water stream. The timeframe for breakthrough is highly dependent on reservoir geology, conformance, and well spacing, and for this reason is difficult to estimate during early phases of project development.

The liquid density of CEOR chemical cocktails is controlled by monovalent dissolved solids such as sodium chloride in the CEOR injectant. Polymer, added to improve sweep efficiency, affects viscosity, while surfactant reduces the interfacial tension between the oil and water, forming emulsions. Because of the enhanced oil-droplet and emulsion stability, the performance of the three-phase separator (primary separation) is expected to decrease after CEOR chemical breakthrough.

Three conventional treatment approaches can be employed to improve the performance of the three-phase separator: additional settling time can be provided; production-fluid temperature can be increased; or additional demulsifier can be added. Because of the stability of the oil droplets and likely space limitations of existing platforms, the provision of additional settling time is often impractical offshore. Although acceptable operating temperature will vary depending on the hydrocarbon constituents, an existing separator system will likely have been designed for the anticipated maximum temperature range of the expected production fluid or maximum crude-processing temperature. For these reasons, additional residence time or operation at elevated temperatures may not significantly optimize the performance of the three-phase separator.

The most feasible of the three options is to provide additional demulsifier dosing capabilities to achieve acceptable three-phase separator performance. In addition to production chemicals whose interaction with demulsifier are well understood, selection of demulsifier must consider the anionic properties of the polymer which will generally react with cationic products, the type of surfactant used in the CEOR flood, and the produced-water composition to ensure compatibility and adequate performance in the application.

An assumption can be made that readily separable oil and gas components will have been recovered in the three-phase separator. The remaining produced water, which contains potentially elevated levels of relatively stable emulsion, is then treated by a secondary separation process, which will likely include gas flotation, typically induced gas flotation (IGF); compact flotation unit (CFU); or hydrocyclones. It is possible to treat viscous produced water, provided the design’s settling velocities or rise rates are calculated using the anticipated viscosity ranges after the polymers have broken through.

IGF and CFU processes rely on gas bubble and oil droplet contact. Coalescing plate interceptors (CPI) can be used as a pretreatment step to encourage the growth of larger droplets for IGF or CFU. The attachment of gas on the oil droplets is expected to increase the rise rate of the oil droplet since the combined mass density of the particle is lower. The combination of droplet and gas is reduced. However, droplet-size modification by the surfactant and increased viscosity from the polymer could largely offset the effect of attached gas in an IGF or CFU, and, as a result, oil-removal efficiency can be affected if CEOR chemicals are present.

The Need for Polishing

After secondary separation, CEOR produced water may require a polishing filtration step to remove fine particles or oil in applications where PWRI is performed and especially if salinity/hardness control is needed to improve the performance of the CEOR flood.

In CEOR applications, the filtration load in the polishing process is expected to increase because of  the reduced performance of the secondary separation unit. The additional load can have a significant effect, depending on the filter choice and design limits. For this reason, conservative design parameters should be adopted for filter solids loading.

BWSF could provide additional oil removal and has been shown to be compatible with CEOR chemicals in onshore applications. However, the current BWSF systems are not suited to offshore applications, and fine particles and oil droplets will remain in the treated-water stream after BWSF. These particles could be problematic during PWRI and could foul downstream salinity- or hardness-treatment processes. Other treatment technologies, such as specially coated filter media, cartridge filter coalescer systems, and micromedia filtration may provide more effective polishing of smaller oil droplets and fine particles for offshore application.

Ceramic membranes have also been considered for removal of fine particles and oil for offshore CEOR produced water, and their automated washing capabilities are expected to improve operations by eliminating frequent and operator-intensive cartridge-filter changeouts of more conventional technology. Frequent cartridge-filter changeout periods, which typically occur during upset events, can be operationally intensive and tend to generate a large amount of solid waste that must be disposed of at an onshore facility when other forms of filtration are not provided.

Because of the relatively high operating cost associated with cartridge-filter consumption and disposal in an offshore application, enhanced monitoring systems that utilize a combination of fluorescence, spectroscopy, and microscopy will be especially important for CEOR produced-water treatment systems. They provide particle size, differentiate between oil and solids, and identify changes in oil quality. They are expected to be used in many offshore applications, but appear especially well-suited for use in CEOR applications, where they are expected to help optimize operations, especially in cases where polishing filters are provided since they will enable tighter process control that will help to achieve treatment objectives. Where provided in CEOR applications, the monitoring systems should use a self-cleaning procedure to improve their performance and ensure a high level of measurement reliability.

New technologies or treatment processes that use existing technologies in new configurations have been shown to be effective polishing processes. For example, specialized polymeric membranes have leveraged findings from complex industrial water-treatment projects to remove targeted constituents and can be used to recycle polymer. Similarly, electrocoagulation, a process which uses electrical current to destabilize organics, iron, fine particles, and colloids has shown robust performance in CEOR applications. Polymer destruction is also possible using advanced oxidation techniques, and new hyperdense adsorbents are being piloted for offshore CEOR applications.

Concern for Reservoir Souring

The reliance on PWRI is expected to increase as the industry moves to offshore CEOR and resulting ZLD requirements. Critical components of produced-water treatment for PWRI are being identified based on current experience from onshore CEOR projects.

There are several long-term risks connected to PWRI, and the risk of reservoir souring is identified as one of the most important considerations. Based on experience with produced-water treatment systems and reported operational issues contributing to downtime in PWRI systems, the industry has actively sought secondary biological control measures. An alternative for the control of SRB-induced hydrogen sulfide production in water-oil systems is the use of repeated injections of nitrate. The effect of nitrate may cause the presence of chemolithotropic nitrate-reducing bacteria (which not only removes sulfide, but also suppresses sulfide formation by the SRB); competition between SRB and heterotrophic nitrate-reducing bacteria (hNRB) for common electron donors; and the direct inhibition of SRB when nitrite is accumulated during nitrate reduction by hNRB.

Benefits and Opportunities of PWRI During EOR

Although the use of PWRI in offshore CEOR projects is expected to be driven primarily by regulatory requirements, there are numerous potential benefits and opportunities associated with incorporating PWRI into offshore CEOR projects. These include simplification of chemical supply requirements, logistics for CEOR chemicals, a reduction in injectant-treatment system capacity, and regulatory advantages.

Depending on the location of an offshore CEOR project, the supply of chemicals and logistics surrounding injectant production can be reduced considerably through appropriate PWRI. Operators can achieve a net reduction in treatment-chemical consumption by substituting the use of mechanical and thermal processes, such as high-pressure pumps and double-loop heat exchangers, with equipment which will not shear or destroy beneficial polymers.

Although these techniques may be implemented to conserve polymer, polymer degradation is expected to occur in the reservoir and for other reasons, including the incorporation of iron into the produced water.

The PWRI stream can also be used to greatly offset the treated seawater capacity in an offshore CEOR project by blending prior to injection. The technologies are now available to tune, or customize, the treated water to compensate for the PWRI water chemistry and to ensure that the blended injection stream meets the CEOR-cocktail water chemistry requirements. The availability of the PWRI can thereby significantly reduce the seawater treatment capacity.

Summary and Conclusions

It is not surprising that oil and gas companies considering offshore CEOR are also considering PWRI as their primary form of produced-water management because it may be the most efficient and environmentally friendly option available.

Where PWRI is implemented, significant planning is required to ensure that the produced-water treatment system is capable of treating to high enough quality to maintain reservoir health. Implementation of new and emerging technologies is expected to enhance the appeal of PWRI, such that the industry will come to recognize it as a resource rather than an operating cost.

The effect of CEOR chemical properties must be considered in produced-water treatment, both for existing and upgraded treatment equipment and chemical options. Often, these effects are the last to be considered and may lead to schedule delays. Although the uncertainty and complexity of the produced-water stream is a barrier to implementation of offshore CEOR projects, the use of PWRI holds potential to resolve environmental hurdles, reduce seawater-treatment system capacity and ASP chemical consumption. For these reasons, advancements in produced-water treatment that facilitate PWRI technologies may be the project enablers that will lead to global implementation of offshore CEOR.

Water Management for Hydraulic Fracturing in Unconventional Resources—Part 1

Published May 31, 2013

This is the first of several articles on the subject of water management for unconventional hydraulic fracturing. These articles are intended to cover the major aspects of the subject, focusing on the technologies being used.

The first installment provides an overview of the critical issues. The subject will be placed in the context of other types of water treating in the oil and gas industry, as well as in other water treatment industries. The introductory material is necessary to lay the groundwork for the eventual discussion of where the technology is likely to go in the next several years. To be able to make that projection, it is necessary to fully understand the context of where the technology is today and how it got here.

Subsequent articles will discuss the different shale plays, the fluid characteristics, regulations, environmental impact, and water treating technologies.

Hydraulic Fracturing and Water Treating

Hydraulic fracturing (HF) is not new. Not counting the recent activity in shale and coal seam gas (or coalbed methane, as it is known in the United States), nearly 2.5 million conventional HF operations have been carried out in the world. HF of conventional oil and gas fields uses essentially the same fluids, in different proportions, rates, and volumes compared with the shale reservoirs. While the details are important from a water management perspective, the fact that similar fluids are used suggests that the historical experience is important in selecting water treating technology. In one form or another, HF has been practiced for at least 50 years.

Most of the conventional HF operations did not involve water treating of the flowback fluids. Most flowback fluids in conventional HF operations have gone to disposal wells or waste disposal sites. However, a significant number of HF operations have been carried out offshore, where water treating is common practice. Nearly all offshore HF operations involve water treating to prevent the contamination and upsets of the main processing system.

Historically, fluids besides water have been used, and many techniques have been tried. In the early days of HF, gelatinized petroleum (i.e., napalm) was used. It is still used to a limited extent today in vertical wells, where limited fluid volumes are required. Its advantage is that water handling is not required. However, given the volumes involved in unconventional HF, it is too costly. Also, safety considerations related to the handling of flammable materials have moved the industry from oil- to water-based fluids.

Pointing out that HF is not new is based on the observation that some of the water treating practices and technologies being promoted these days are difficult to rationalize. Some of the new technologies seem to defy scientific reason, yet are getting a surprising amount of attention. Some older technologies that have been discarded for good reasons are being resurrected. In some cases, incredibly high costs are being incurred. Operators seem to be learning the hard way what works and what does not.

The term unconventional hydraulic fracturing refers to HF in unconventional resource development. The generally accepted unconventional resources are shale gas, shale oil, coal seam gas, and oil sands (also known as tar sands). The permeability of a conventional oil and gas field is in the range of approximately 10 millidarcies to 0.1 darcy. Beach sand has a permeability of approximately 1 darcy. Concrete has a permeability of 1 microdarcy. The permeability of most of the shale reservoirs being developed today is generally less than 1 microdarcy, in the nanodarcy range (e.g., Eagle Ford, 100 nanodarcies; Marcellus, 10 to 100 nanodarcies; and Haynesville, 20 nanodarcies). Thus, the term unconventional is appropriate, but is not limited to the shales.

The oil sands are an unconventional resource that is either surface mined or developed using steam injection. They are never developed using hydraulic fracturing because the oil viscosity is too high. Opening high conductivity fractures will not make the oil flow. Heat is typically applied, in the form of steam, to lower the viscosity. Though this may seem completely different from water treating of shale HF flowback fluids, I will eventually discuss the similarities and point out that at least one important technology for shale has its origins in the Canadian oil sand fields.

Coalbeds containing natural gas can be developed with or without HF. When HF is used, obviously the productivity is higher. HF of coal seams uses the same fluid types as in shale and conventional reservoirs. Typically, coal seams are developed using vertical wells and the HF, if applied, is done only in a single vertical interval. Coal seams may also be acid stimulated before the HF—a common HF practice in conventional and shale reservoirs. Finally, the coal seams are usually nearly saturated with water, requiring extensive dewatering before gas will flow. Despite these differences, the fluid types are similar to those in shale and conventional HF operations.

For the most part, the fluids used in conventional and unconventional HF comprise the same set of ingredients. Most contain proppant, but not all. Most contain polymer and some also contain surfactant.

Polymer is one of the most important components from a water treating standpoint. Based on polymer types, there are four types of HF fluid:

  • Slickwater—partially hydrolyzed polyacrylamide (HPAM)
  • Linear polymer—polysaccharides, such as guar, hydroxyethyl cellulose, and xanthan
  • Gelled polymer—crosslinked polysaccharides
  • Hybrid—combinations of slickwater polysaccharides

Salinity is also important because many of the polymers work best in fresh water. Even if fresh water is pumped into the ground, the fluid that flows back (flowback fluid) may be highly saline. In that case, recycling will involve desalination, which is difficult in the presence of polymer. Solids are typically present in the flowback fluid. Thus, polymer type and concentration, solids, and salinity are the important properties of flowback fluid from a water treating perspective.

In formulating either an unconventional or a conventional HF, the polymers listed are typically used. There are sound technical reasons in that both types of HF use fluids from the same general set of ingredients, suggesting there is existing industry experience in dealing with these fluids. There is experience from polymer flooding in which HPAM is used and from other industries such as food, beverage, pulp, and paper.

Water Treatment and Management

From a water treating perspective, what is unique about shale? To date, the only economical technique for developing shale oil and gas is to drill long horizontal wells and apply HF to multiple zones along the horizontal run. The much higher volumes of fluid required for unconventional HF make it different from conventional HF. Whereas a conventional HF may require about 2,000 bbl of water per well, an unconventional HF may require between 50,000 and 120,000 bbl of water per well.

The high injection volume also gives rise to high fluid volume on flowback. Load recovery is the measure of how much of the injected fluid flows back. It depends on factors such as water saturation of the shale, leakoff rate of the fluids, and the development of a proppant pad. In the Marcellus shale, for example, water saturation is essentially zero and load recovery is roughly between 15 and 20%, with many cases falling outside of this range. Using these values, between 15,000 and 25,000 bbl of water are returned to the surface. This is more than the volumes for conventional HF operations, in which only a few hundred to fewer than 1,000 bbl of water typically flow back.

The flowback of a conventional HF and an unconventional HF (shale or coal seam) typically occurs at similar rates of roughly 1 to 3 bbl/min. The flowback rate is dictated by the necessity to keep the fractures open. When proppant is used, the fluid flowback rate must be slow enough to prevent viscous fluid forces from pulling proppant out of the fractures. Thus, both conventional and unconventional HF flowback operations occur at similar rates.

Fluid volume, not fluid type and flowback rate, is the unique feature of shale HF fluid management, compared with conventional and coal seam HF. In the next column, I will address how fluid volume affects the selection of technology. For now, fluid volume must be addressed.

Fluid volume affects key aspects of development, such as water sourcing (acquisition) and water disposal. Given the large fluid volumes, water management is required at an early stage of field development. This is a significant departure from traditional oil and gas field development, in which water production typically occurs after startup. Water treating facilities are typically added late in field life. Halldorson said, “With the shales, suddenly water management went from an afterthought to a driving force for unlocking hydrocarbon production.”

Water management for unconventional hydrocarbons requires that decisions be made at an early stage in the development of a field to minimize overall water management costs. When these decisions are not made early, or when they are not implemented in a timely manner, the number of water management options may be scarce and the cost of water management can escalate by an order of magnitude.

This was the early experience for some Marcellus shale operators who delayed water management planning and were forced to pay upward of USD 0.5 million per well in transportation and disposal costs. Through lack of planning, their only available option was to transport the flowback fluids several hundred miles by truck.

Brine handling is one of the riskiest activities involved in HF. It involves a high likelihood of the occurrence of a hazardous event, such as a truck crash, a spill, or leak of brine. Where trucking is concerned, it also has a significant effect on human life by significantly increasing traffic.

Developing a Water Management Strategy

Halldorson identifies five factors that dominate water management in shale HF:

  • Disposal
  • Fresh water
  • Regulatory and community concerns and regulations
  • Recycling and reuse
  • Transport

Decisions regarding each of these drivers must be agreed upon to develop a cost-effective water management strategy that minimizes environmental impact and is acceptable to local communities.

Nearly in parallel with Halldorson, a colleague and I devised a water management strategy that focuses on five key drivers.

  • Hydrology of the field (or region)—defines availability of fresh water
  • Regulatory requirements—define disposal options
  • Fracture fluid quality—defines the required quality of water
  • Flowback fluid characteristics—defines the treatment requirements
  • Stage of field development—defines the availability of technology

The similarity between the two lists is striking. Halldorson’s inclusion of community concerns is spot-on and something that I missed. He also noted that transport should be minimized as much as possible because of cost and risk.

A number of water management options are associated with each of the drivers. By providing the required input, the appropriate options can be refined. The next step is to populate a cost model from which the final water management strategy can be developed.

In general, a decision framework organizes the required data in a logical way and provides a logical sequence of decision making, which ultimately leads to an overall strategy. In the case of water management for HF operations, a decision framework defines the variables that affect water management options and suggests the best strategy, whether it be recycle, reuse, disposal, or beneficial use.

The hydrology of the region could otherwise be referred to as sourcing or acquisition of fresh water. The hydrology of the field defines the availability of freshwater sources. In some regions in which shale resources are found, there is a plentiful supply of fresh water, and an operator can acquire fresh water by simply filling a water truck from a municipal water supply for a relatively small cost. In the Marcellus region of the eastern US, this is the case.

In the western US, this is not the case. Many of the unconventional fields there have been drought-stricken for decades. Acquiring water from brackish or saline aquifers is an option. Reverse osmosis is used to generate fresh water. However, such water withdrawal may result in further lowering of the freshwater table. In those cases, the hydrology of the regional water system must be understood.

Considering this driver, the main question is whether there is a plentiful and inexpensive source of fresh water. If the answer is no, then options for acquisition of water must be considered, including the option to recycle or reuse flowback water.

Regulatory requirements and community concerns could be known as disposal of flowback and produced water. Regulations set strict constraints on the disposal of flowback and produced water, as well as the disposal of any waste generated from treatment of that water. In the US, as in many other countries, the detailed regulations are developed by regional government bodies. Often these regulations are based on past history of industrial development. If past activity has resulted in an adverse environmental impact, then permits for disposal wells are difficult to obtain. The adverse historical experience of associate mine drainage or acid mine drainage has had an effect on the Marcellus shale development.

Community concerns are no less important than regulations. Public pressure can slow down or stop certain disposal options or development. Community concerns start with environmental impact, but can include issues such as road traffic, transient workers, property value, fire and explosion hazard, and many others. The outcome of community activism does not necessarily result in the best overall outcome for the community and is, therefore, difficult to predict.

Considering this driver, the main question is whether disposal wells are available. If the answer is no, then options for disposal of water must be considered, including the option to recycle or reuse flowback water.

The quality of fluid required to perform a successful HF job varies, depending on the type of shale. Shale varies in quartz and clay content, brittleness and ductility, the pressure required to propagate a fracture, the extent of pre-existing microfracturing, and the extent of microfracturing that will occur as a result of the HF. These factors combine to dictate the optimal fluid type for achieving the required degree of enhanced production. The optimal HF fluid type may require freshwater makeup. For example, HF fluids based on nonionic HPAM are less sensitive to dissolved salts than the anionic form (which is typically referred to as a slickwater fluid). Some of the polysaccharides are also less sensitive to ion content.

For this driver, two questions must initially be answered. The first question is whether fresh water is required for makeup of the HF fluid. If so, then recycling of HF from flowback will generally require desalination. Desalination in the presence of polymers, surfactants, and other suspended solids generally requires the use of mechanical evaporation since membranes become fouled quickly.

If recycling of the flowback fluid is to be carried out, the characteristics of the fluid that flows out of the well are critical in determining the type of technology that will be successful.

As a general rule, the fluids pumped into the ground do not necessarily determine the fluids that flow back out of the ground. In some cases, there is a close correlation. In other cases, there is not. In the Marcellus Shale, for example, even freshwater HF fluids typically become saline through contact with the shale.

In the early stage of development of an unconventional field, a number of individual wells are drilled and completed. In the US, mineral rights are owned by the land leaseholders. Several wells will be drilled to either secure acreage or determine the extent of the hydrocarbon-bearing zone. Intensive in-field drilling and completion of isolated wells generally requires water treating equipment that is mobile. Such equipment is compact and placed on a flatbed truck.

As field development progresses, the leases become secure and the drilling campaign becomes more structured. Clusters of wells are drilled. It is then possible for several adjacent wells to be developed in sequence or simultaneously, facilitating the use of a modular water treating system. In this case, a daisy chain or hub and spoke type of water piping arrangement can be constructed to feed the water treatment unit and to convey treated water to the wells that require it. When a few or several wells are involved, the construction cost of a modular treating system becomes justified.

Later in field life, there may be many wells in relatively close proximity. Over time, the construction of a water conveyance network, together with a centralized facility, becomes justified. This is the current trend in the Marcellus shale. It has also been successfully implemented in the Pinedale anticline in southwestern Wyoming.


Developing a water management strategy for shale development is relatively straightforward. Five key drivers must be addressed. These define the extent of reuse and recycling that will be economically required, as well as the type of technology (mobile, modular, and centralized). A strategy must be developed early in the development of a field to avoid a costly lack of alternatives.

In the next article, I will discuss the technologies available for water treating of unconventional resources.