IPIECA Strives To Boost Industry’s Environmental, Social Performance

As an introduction to the IPIECA, what follows is an interview with executive director Brian Sullivan.

What is IPIECA?

We are a global oil and gas industry association that works with our members to improve the environmental and social performance of the industry. We have a wide membership which includes 36 individual companies, who together are responsible for more than half of the world’s oil output, as well as 16 associations, forming a network that represent more than 400 oil and gas companies.

Why was IPIECA formed?

IPIECA has been around for almost 40 years. Back in 1974, when the United Nations Environment Program (UNEP) was created, industry was asked to identify central points of contact. The petroleum industry was one of the first to act on this request, and, although there were already existing national and international associations concerned wholly or partially with environmental affairs, none of them covered all petroleum operations in a global context. As a result, in March 1974, IPIECA was established as the channel through which all parts of the industry could efficiently communicate with UNEP and subsequently with other related intergovernmental agencies involved in the implementation of the system-wide environment program.

Today, we remain the only global association involving both the upstream and downstream oil and gas industry on environmental and social issues and continue to be the industry’s principal channel of communication with the UN.

What does IPIECA do?

IPIECA provides leadership on environmental and social issues for the oil and gas industry by enabling performance improvements by developing, sharing, and promoting good practices and solutions, informing global policy and external stakeholders on relevant issues, and anticipating challenges for the industry by scanning and assessing emerging issues and developing actions.

Through IPIECA, our members work together to address a wide range of issues within three broad themes: climate and energy, the environment, and social responsibility. Specifically, we run working groups made up of around 500 representatives from our member companies focusing on issues including biodiversity, climate change, health, oil-spill preparedness, operations and fuels, sustainability reporting, social responsibility, and water. These individuals volunteer their time to progress industry knowledge and performance on these key sustainability issues. Furthermore we engage with external initiatives on behalf of the industry such as the Global Reporting Initiative (GRI), CDP (formerly the Carbon Disclosure Project), the International Integrated Reporting Council (IIRC) and many more. We also use our consultative status with the UN to represent the industry at the global level on environmental and social issues.

What does your name stand for?

One of the enduring legacies of our ’70s birth, or perhaps burden depending on how you look at it, is our name, IPIECA. Originally standing for the somewhat lengthy, International Petroleum Industry Environmental Conservation Association, from 2008, in recognition of the addition of social issues to our work program, we dropped the full title and became known simply as IPIECA, the global oil and gas industry association for environmental and social issues.

What have been your key achievements over the past couple of years?

There are many, but I’ll just highlight a few here, including our ongoing work on water management, business and human rights, oil spill response and sustainability reporting, as well as our input into the United Nations Conference on Sustainable Development (also known as Rio+20).

The IPIECA Water-Management Framework. IPIECA launched a new onshore Water management framework at World Water Week 2013 in Stockholm on 3 September 2013. Designed to enable oil and gas companies to prioritize and address key water management issues, foster best practice, and standardize data collection, the framework also provides a platform for broad external communication of achievements, goals and progress.

While the oil and gas sector consumes lower volumes of water than many other global industries, it remains a significant user, and recognizes the need for responsible management of water resources as a contribution to global sustainability efforts. To help companies across the industry address and respond to water management challenges, this framework has been developed to provide a practical cyclical process of planning, implementation, evaluation, and management review.

The Business and Human Rights Project. As SPE members know, the oil and gas industry operates in complex environments where human-rights issues are a central concern. In June 2011, IPIECA launched a 3-year project to provide members with a forum for sharing good practice on human rights due diligence and grievance mechanisms and to help oil and gas companies implement new and emerging international guidance on business and human rights.

This project, building on a decade of activity by IPIECA on business and human rights, focuses on peer learning, industry guidance, and participation in external initiatives. During the last 2 years, we have launched a number of publications designed to enhance the capability of oil and gas companies to manage human rights issues and their impacts in business operations including:

• Human Rights Due Diligence Process—A Practical Guide to Implementation for Oil and Gas Companies.
• Operational Level Grievance Mechanisms—IPIECA Good Practice Survey.
• Human Rights Training Tool (Third Edition)
• Guide on Integrating Human Rights Into Impact Assessment in the Oil and Gas Industry.

Fig. 1

The Global Initiative: Partnership for Enhanced Oil Spill Response. The Global Initiative (GI) program was established in 1996 by IPIECA and the International Maritime Organization (IMO) and today continues to expand its work on reducing global oil spill risk in priority locations. The program helps countries to develop national structures and capability for oil spill preparedness and response. In recent years, the GI has continued to build its existing programs in the Mediterranean, Caspian, Black Sea, and central Eurasia and west, central, and southern Africa, as well as expand into new regions including southeast Asia and China (Fig. 1). We are also currently scoping the potential for a specific program in East Africa.

Rio+20. At the United Nations Conference on Sustainable Development, ‘Rio+20’, held in June 2012 in Rio de Janeiro, world leaders joined 50,000 representatives from governments, the private sector, NGOs, and other groups to discuss how to reduce poverty, advance social equity, and protect the environment on an ever more crowded planet.

Fig. 2

IPIECA coordinated the oil and gas industry’s contribution to Rio+20 and the wider preparatory process leading up to it. From a process that began in June 2010, a set of messages and fact sheets were developed, demonstrating the industry’s commitment to sustainable development and describing how further goals can be achieved in the future. The oil and gas industry messages were presented at Rio+20 during an IPIECA session at the Business Action for Sustainable Development (BASD) Business Day. A panel (Fig. 2) offered a number of examples of how the industry is working to meet the challenge of providing essential fuels in ways that are environmentally and socially responsible.

Sustainability Reporting. Oil and gas companies have been among the pioneers of sustainability reporting and have provided leading examples of good reporting practices since the mid-1990s. In 2011 IPIECA, together with the American Petroleum Institute (API), and the International Association of Oil and Gas Producers (OGP) issued the second edition of the Oil and gas industry guidance on voluntary sustainability reporting. The Guidance provides a flexible framework which enables companies to effectively communicate material impacts to their stakeholders. IPIECA is now working to ensure that the Guidance remains up to date with progressing industry and external trends and developments, and will be releasing a 2014 edition with a number of revised and new indicators.

What’s next?

As well as maintaining and building on our existing work programs, IPIECA is continually considering emerging issues to add to our portfolio. Recent additions include examining the social dimensions of gas from shale projects; deliverables will include peer-learning workshops and guidance on managing community issues unique to shale gas development. Later in the year, we will be holding a workshop looking at the role of short-lived climate forcers in climate-change-mitigation strategies. Publications still to come in 2013 include guidance on mercury-emissions management, waste management and remediation, as well as an online compendium of energy efficiency practices for operations, which aims to improve industry knowledge of available measures.

Next year, we reach an important milestone; IPIECA will celebrate 40 years of championing best practice on environmental and social issues across the global oil and gas industry. Our anniversary celebrations will include a conference and gala dinner in London to showcase how IPIECA has harnessed the power of partnership to address key environmental and social challenges around the world. Building on the progress that has been made over the past 40 years, the conference will look ahead to what more can be achieved through IPIECA’s leadership in the 10 years to 2024, when we will celebrate our 50th anniversary. The event will feature high-level experts and industry leaders from around the world as speakers and will include interactive discussions among participants to help develop a strong vision for the future.

Learn more about IPIECA here.

Brian Sullivan joined IPIECA as the executive director in 2011 following a 23-year career with BP. He graduated in metallurgy and materials science from Imperial College London and was recruited into BP’s Refining and Marketing international graduate program in 1986. Over the course of 23 years, his career included assignments in London, Copenhagen, Budapest, Athens, and Johannesburg and business experience in more than 60 countries. During his time with BP, he has had a varied career of technical, commercial, financial, and leadership roles across the downstream value chain, including crude and products trading, marine fuels, lubricants, and alternative energy.

The Business of Kidnapping

James Reese, CEO, TigerSwan

Kidnapping is a serious and real threat when you travel to emerging markets and high-risk parts of the world. Criminals generate large profits and operate like a business. Kidnappers not only target executives for ransom or political gain, but also Western business associates from lucrative industries including oil and gas.

The number of reported kidnapping cases continues to grow each year. According to industry experts, there has been a dramatic increase in reported kidnappings in high-risk countries from 2012 through the first six months of 2013. The current top high-risk countries are Nigeria and Mexico. Mexico had 555 reported kidnappings between January and April 2013 compared with 417 incidents during the same time period last year. Yemen also placed particularly high on the list this year as its government remains unable to enforce its justice system or any authority.

Kidnapping can describe a wide spectrum of scenarios. Aside from the most common form of abduction, kidnap for ransom, criminals also engage in express (lightning) kidnappings where victims are temporarily detained and their bank accounts drained through coerced bank transactions. More disturbingly, kidnappers have begun abducting individuals and selling them to terrorist organizations who use the victims for political gain. Your company cannot afford to put you, the most precious commodity, in a vulnerable position.

Kidnappers look for easy targets. They observe and prey on travelers who create patterns and habits such as taking the same routes to and from work. Cell phone records, travel itineraries, and background information are often collected in dangerous countries with help from telephone service providers and corrupt local law enforcement. Something as simple as a tweet or Facebook post from a corporate employee or family member mentioning your whereabouts can lead to an attack.

The following simple steps can be taken to deter kidnapping while traveling internationally:

• Establish a crisis-management plan with your company before traveling abroad
• Learn about the geopolitical situation in the region you are traveling to
• Employ security professionals who can provide security-risk analysis and country-specific response plans before travel
• Conduct comprehensive due diligence on the individuals and companies you will be meeting with
• Arrange for qualified security to pick you up from the airport and provide secure transportation throughout your travels
• Maintain consistent communication with your colleagues while overseas
• Remain alert and aware of your surroundings while traveling abroad

It’s no secret the oil and gas industry is high-risk. You must travel to unstable and often third-world regions in order to maintain and expand your business. Talk to experienced professionals and conduct the necessary research and planning before traveling overseas. Safety is your No. 1 priority.

James Reese

CEO and Co-founder, James Reese has 28 years of demonstrated success leading, managing and organizing complex and multi-functional organizations with billion dollar assets and thousands of personnel. His leadership roles have spanned international and multi-cultured organizations and achieved success in areas of stability, instability and high threat. He led TigerSwan from a two-person, small business, to an international, multi-asset, medium sized global stability company with 250 personnel worldwide. Reese previously spent 21 years of his 25-year career in the Army Special Operations and was a decorated combat leader and a disabled veteran. Reese spent 20 years in key military command and staff leadership roles within the “DELTA FORCE,” Ranger Regiment and 1st Cavalry Division, and his last 10 as an Operator Officer within “DELTA FORCE.” He culminated his career as the Director of Operations and Chief of Staff for a 1,600 person Combined, Joint, Interagency Task Force (CJIATF) conducting combat operations in Iraq and Afghanistan. After 9/11, Reese was selected by the Secretary of Defense to serve as the military advisor for Special Operations to the Director of the CIA on planning and preparation for the invasion of Afghanistan and operation “Enduring Freedom.”

Founded in 2007 by former members of the US Army’s elite special operations unit Delta Force, TigerSwan specializes in corporate solutions across the entire spectrum of vulnerability management. TigerSwan’s Guardian Angel membership is an international corporate security program that enables you to travel safely and conduct your business globally. When travels take you to unfamiliar, unstable, or even dangerous regions, your safety is paramount. Guardian Angel membership services range from client tracking and monitoring to cultural liaisons and low-profile security details—anytime, anywhere in the world. For more information please visit www.TigerSwan.com.

Experiments on Large-Scale Fires Reveal Benefit of Greater Water Deluge

A series of 56 large-scale fire experiments in the range of 40–120 MW has been carried out in a generic offshore module. The effect of deluge fire-water application has been measured for different setups. Both deluge nozzle type and water-application rate have been varied in the experiments.

Introduction

The use of water-spray systems for firefighting is standard for most offshore oil and gas intallations. The requirements to and guidelines for control and mitigation of fires are stated in International Organization for Standardization (ISO) 13702, Petroleum and Natural Gas Industries—Control and Mitigation of Fires and Explosions on Offshore Production Installations—Requirements and Guidelines. Appendix C in ISO 13702 lists the recommended fire-water-­application rates for areas and rooms on an oil- or gas-­production installation. Typically, the minimum recommended water-­application rate is listed as 10 (L/min)/m². NORSOK Standard S-001, applicable for installations on the Norwegian continental shelf, states that the effect of deluge may be taken into account for process equipment and piping, provided that there is proper documentation of the fire-water effect (and that there are requirements to the reliability of the fire-water system).

In order to document the effect of the recommended fire-water-application rate, a set of full-scale fire experiments with application of fire water was carried out at SINTEF NBL.

Background

Today’s design of oil- or gas-production installations includes deluge-fire-­water systems as standard. These are costly and may require extensive maintenance. Despite the costs involved, little knowledge is available on the actual effect of fire-water systems under different operating conditions.

Appendix C in ISO 13702 recommends a typical water-application rate of 10 (L/min)/m². National Fire Protection Association (NFPA) 15: Standard for Water Spray Fixed Systems for Fire Protection recommends a design objective for control of burning of not less than 20 (L/min)/m². NORSOK S-001 refers to NFPA 15 but prescribes 10 (L/min)/m² for process areas and equipment surfaces and 20 (L/min)/m² for the wellhead area. American Petroleum Institute (API) 2030, Guidelines for Application of Water Spray Systems for Fire Protection in the Petroleum Industry, prescribes 20 (L/min)/m² where pumps are present and 10 (L/min)/m² for pipe racks and piping. To what extent do these water-­application rates actually affect the fire?

Quantification of Fire Loads

The characteristics of a fire are not trivial to measure. Different ways of measuring fire characteristics include

• Ability to extinguish fire
• Total heat-release rate (HRRtot), kW
• Convective heat-release rate (HRRcon), kW
• Total flame volume, m³
• Maximum flame temperature, °C, K
• Flame volume above a defined temperature (e.g., V at >1000°C), m³
• Maximum local heat fluxes, kW/m²
• Maximum global heat fluxes, kW/m²
• Flame volume above a defined heat flux (e.g., V at >250 kW/m²), m³
• Surface emissive power of a flame, kW/m²
• Temperature or temperature rise of flame-exposed objects, °C, K; or °C/s, K/s
• Smoke production, m³/s, g/s

In a full-scale field experiment, many of these parameters are difficult or impracticable to measure. How­ever, most of them are possible to derive from fire simulations using suitable software.

Experimental Setup

The 56 fires were in the range of 40–120 MW. The experiments were carried out in a 15×10×10-m generic process module (Fig. 1). 

Experimental-test rig.

The process module was equipped with nearly 200 thermocouples, 100 of which measured gas temperature. The rest measured temperature of equipment, structure, and exhaust gas.

Parameter variations addressed during the experiments were

• Hydrocarbon media (propane, diesel)
• Hydrocarbon leak rate (1 kg/s, 3 kg/s)
• Leakage location
• Leakage direction
• Water-application device (medium-velocity nozzles, high-velocity nozzles, high-capacity nozzles, and monitors)
• Water-application rate [10 (L/min)/m², 20 (L/min)/m²]
• Enclosure
• Wind
• Additives

Pictures of a 3-kg/s diesel-spray fire before and after activated deluge can be seen in Fig. 2. 

Pictures of a 3-kg/s diesel-spray fire before (left) and after (right) deluge activation.

Results

Here the fire-water effects are presented at a semiquantitative level on the basis of measured values before and after deluge water application.

The effect on maximum gas temperature is measured as K/K as an average of the 10 thermocouples with the highest readings. The effect on isotemperature volumes is a qualitative assessment based on ratios calculated as m³/m³ for volumes with temperatures higher than 1100 and 1000°C. The effect on isoheat-flux volumes is a qualitative assessment based on ratios calculated as m³/m³ for heat-flux levels larger than 250, 200, and 150 kW/m². The effect on external radiation level is based on ratios of heat flux derived from simulations.

A “negligible” effect indicates a factor of 0.95–1.00. “Small” indicates a ­factor of 0.80–0.95. “Clear” indicates a factor of 0.50–0.80. “Significant” indicates a factor lower than 0.50. The effects are presented in Table 1 for situations with little or no wind.

Comments and Discussion

As for equipment cooling, the experimental results vary to a large degree, from good effect to no effect. For jet fires, deluge water has no effect on the temperature in the hotspot of the flame. Results also vary with the flame shape and location of deluge nozzles.

It is not possible to conclude whether medium-velocity deluge nozzles or high-velocity deluge nozzles should be preferred. In general, medium-velocity nozzles seem to have their strength in reducing isoheat-flux volumes and external radiation. Isoheat-flux volumes are important because they are indirect measurements of heat-flux exposure of equipment and structure, possibly affecting the probability of escalation. High-­velocity nozzles seem to have their strength in equipment cooling and during windy conditions. As for wind, the differences in effects are significant in favor of high-velocity nozzles in the wind-speed range of 2–10 m/s, most likely because of higher nozzle discharge velocity.

In retrospect, the experiments would benefit from a narrower range of parameter variation and better-planned placement of thermocouples.

Deluge Water-Droplet Size

It would be of great interest to study the effect of an actual deluge system design from simulations. To allow for such simulations, one has to have an idea of water-droplet size, distribution, and velocity. Deluge water-droplet size and velocity have often been measured by phase Doppler anemometry (PDA). However, PDA has some weaknesses when it comes to measurement of nonspherical droplets. Statoil, therefore, is sponsoring a doctorate-level study at Telemark University College to develop a method for classification of deluge water droplets by photometry.

Summary and Conclusion

A total of 56 large-scale fire experiments with fire-water application have been conducted, with a wide range of parameter variation. The main findings are

• Deluge-water application has better effect on liquid-spray fires than on gas-jet fires.
• A deluge water-application rate of 10 (L/min)/m² will have negligible or little effect on the highest gas temperature in the fire.
• A deluge water-application rate of 20 (L/min)/m² has a documented more-favorable effect than an application rate of 10 (L/min)/m².
• For gas-jet fires, the flame-hotspot temperature will persist, independent of deluge configuration.
• The choice of medium-velocity or high-velocity deluge nozzles depends on the fire scenario.
• Medium-velocity nozzles have their strength in reducing heat fluxes and isoheat-flux volumes, thereby reducing the amount of equipment and structure exposed to high radiation load.
• High-velocity nozzles have their strength in equipment-cooling ability and a lower vulnerability to wind.

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 164973, “The Effect of Deluge Spray Systems on Large-Scale Fires,” by Stian Høiset and Eli Glittum, Statoil, 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.

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

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.

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

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.

Introduction

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.

Conclusions

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

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.

Introduction

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.

Biosystems

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.

Noise

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.

Microseismicity

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

Ecosystem

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.

Conclusions

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.