Talent & Technology: Soft Competency Development as a Global Challenge

Behrooz Fattahi, SPE, N. Milanovich, SPE, Susan Howes, SPE, Chevron Global Upstream;  Giovanni Paccaloni, SPE, Paccaloni Consulting International; and Ford Brett, SPE, PetroSkills

The global nature of the workplace in the petroleum industry has introduced a new challenge to our competitive business  landscape: the development of soft competencies as a critically important element in driving productivity. Soft skills as an element of sustainability brings success to individuals and organizations in a variety of workplace activities, such as forging alliances, creating a team harmony that produces collaboration and innovation, and managing and using the human and system components to influence outcomes and achieve business goals. As the nature of workplace engagement shifts, soft competencies provide individuals with the ability to manage the social, cultural, technical, and environmental expectations of both the individuals and their organizations.¹

In an October 2013 JPT article,² the Soft Skills Committee of SPE introduced the Soft Competency Matrix, which is governed by attributes stemming from progression in people capabilities and actions; growth and augmentation of human capabilities with age and experience; and socioeconomic, cultural, and traditional dimensions (Fig. 1 and fig. 2). The authors noted that while the first two elements were governed by a continuing journey through time and personal maturity dimensions, the changes in the third element could be abrupt depending on the attributes needed for the new work assignment.

Global Challenge for SPE

The use of the matrix allows individuals to measure their soft competency level against the expectation to identify current gaps and chart an improvement path. This is obviously a starting point for engagement to better manage and prepare for the ongoing changes and to save time to autonomy for our industry professionals. Moving from a world primarily defined by the location business needs and technical capabilities to one that also emphasizes soft competency as a requirement for success allows the employers to assess the competency gaps in their employees’ soft skills.

There are two major challenges for SPE to help these professionals achieve the expected levels of soft competencies:

• Applicability of the identified attributes at the global level
• Effective expansion of soft skills discussions and training around the world

It is recognized that the methodology described in Figs. 1 and 2 will have to be refined for various regions in the world based on regional cultures, traditions, and ways of life. We must emphasize that the intent of the Soft Skills Committee is not to standardize soft competency best practices globally, but rather to create a framework whereby productive conversations can start. The committee understands and adheres to the idea that soft competencies are practiced according to regional cultural traditions and preferences, and their best practices are determined only by the people from each culture.

To develop a better understanding of the nature and extent of the global variations, the committee conducted a workshop attended by 18 international professionals from a variety of oil industry disciplines including engineering, geology, and information technology. The participants were selected from among those who were born and raised in Asia Pacific, South and Central America, western Europe, eastern Europe, Africa, and the Middle East. They came to the United States as adults for advanced studies or to work. The participants were asked to examine the relevance and validate or modify the soft skills attributes listed in Fig. 1 for their regions. The conclusions from this exercise were:

• Although the majority of the attributes listed in the soft skills matrix were common among regions, there were a few unique attributes to be added for each region.
• Some of the attributes tend to have different connotations in different regions.
• Same attributes may be practiced in different ways.
• The degree of emphasis for some attributes is different for different regions.
• Even within the same region and often within the same country, background and cultural differences do exist, which in turn and to various degrees result in variations noted above.

An effective global expansion of soft skills discussions and training throughout the industry is another important challenge for SPE. An effective expansion means reaching a critical mass in the number of discussions and training of soft competencies to create a continuity and momentum in such a way that individual events around the globe become interconnected, relevant, meaningful, and consequential to others. Early this year, the committee conducted a survey of officers in SPE sections and student chapters worldwide to gauge the status of soft skills programming. Although the survey is still under way, the preliminary results indicate that while there is a demand for SPE programming on soft skills (Fig. 3), there is a lack of substantial and organized process by the Society to make such programming available to members as an important element of professional growth.

To build the momentum needed to propel soft skills to an equal footing with technical competencies, activities, discussions, and participation in soft competencies need to start at the members’ level and within SPE sections and student chapters. To achieve success, the discussions and training in soft competencies cannot be top-down driven. Bottom-up initiatives will be necessary to create the critical mass needed for effective global expansion. The committee’s role¹ will be that of a facilitator to assist in coordination of these activities, provide ideas, enable access to regional experts, and energize and maintain the activities within the soft competency world.

Path Forward

With the development of a soft skills matrix, the next step will be studying the issues critical to our industry professionals including gender diversity, professionalism and leadership, and ethics. Organizing discussions on soft skills topics in conferences, establishing a distinguished lecturers program, and in particular, the development of a robust training platform will be part of this effort as well.

The need for a robust soft competency training program is in line with SPE’s identified strategic priorities³ of capability development (to support the industry in dealing with the “big crew change”), knowledge transfer, promoting professionalism and social responsibility, and public education about the petroleum engineering profession and industry issues. The Society has already taken important first steps in establishing the SPE Leadership Academy, with a number of pilot short courses under development.

The design and implementation of a training program will have to be compatible with members’ demand. For an industry young professional, the road to achieving autonomy starts with developing task proficiency, followed by gaining self-awareness as a secondary capability, and eventually developing proficiency in later years to build and manage a complex array of relationships. These are necessary appropriate adaptive capabilities that leverage technical know-how in completing more complex tasks. To use a petroleum engineering analogy, if technical professionals are limited in their development of soft skills, it might be compared to a skin effect, which limits a well from achieving its full potential. The sequence and the pace of soft competency growth and its trend are shown in Fig. 4 and Fig. 5.

Early in their careers, technical professionals focus on the development and acquisition of technical skills to solve problems and deliver results.⁴ The early work assignments are generally constrained in terms of complexity and risk to the team or business unit. This allows for individuals to develop and to test the use of technical knowledge in general problem-solving endeavors. Thus, the focus tends to be on the achievement of the task through technical know-how. With time and demonstration of technical competency, projects and assignments grow to evolve in complexity and wider system implication. The problem solving and implementation of solutions not only have greater implications for the overall performance of a team or a business unit, but also require the cooperation and engagement of other stakeholders.

The increased complexity creates a potential for larger and longer-term business results with a corresponding risk of failure. The failure with more complex projects is not only relative to immediate business results, but also in the sustainability of relationships and business performance. Thus, more complex problems require greater self-awareness and management of relationships. Practically, the sustainable outcomes now require not only technical competency, but are dependent on how a technical professional interacts with others. To complete the triangle, the development of two additional capabilities is necessary: self-awareness and relationship management.

Developing self-awareness and the capability of recognizing and developing longer-term aspirations as well as getting clarity of one’s fundamental beliefs that limit and expand options for solving complex problems is an essential starting point during the first 3 to 5 years of a career.

The capability of leveraging and managing relationships can be summed up in the following question: How can I understand and help the other team members meet their needs and aspirations so that I have a greater chance of getting my aspirations met while achieving the task at hand?

Conclusion

While technical competencies deal with impersonal aspects of the work environment, the soft skills domain revolves around the professional and personal relationships in pursuit of business success. Recognizing this fact, this article describes the progress on providing a path forward for closing the soft competency gap, and the committee’s focus on globalizing the soft skills matrix. To achieve these goals, several clarifications are necessary. The clarifications are viewed as opportunities and challenges.

Opportunities are:

• Because of its global presence, SPE has the opportunity to facilitate the development of soft skills competencies in ways that suit the cultural and social expectations of specific regions. SPE has a long history and experience of facilitating the development of technical competencies worldwide, while balancing the generally accepted technical standards and specific needs of regions and business conditions. This experience and capability can now be used for soft competencies in moving from a 2D competency measured local work environment to a 3D competency measured global work environment.
• The incoming contingent of industry professionals is more keenly interested in developing their capabilities not only in technical disciplines, but also in the soft skills arena.

Challenges are:

• The mixture of the emerging importance of soft skills and the inherent breadth of disciplines (communication, diversity, leaderships, ethics, cultural preferences, etc.) within the soft skills domain, combined with the variety of ways of application and valuation creates substantial complexity.
• The barriers that continue to divide and create conflict among people (diversity including gender, race, beliefs, etc.), and biases about our differences and similarities will affect the pace of expansion of soft skill competencies.
• A fundamental paradigm that we hold regarding soft skills is that both the individual and system need to exchange relevant information required for adaptation, delivery of desired results, and sustainability of both the individual and the system. As such, communication is an essential vehicle for learning and delivering the results we are seeking to achieve.
• Over its history, SPE has mastered the nuances of language differences in the technical domain; in the world of soft skills, these differences will require more special attention. Our languages contain and encapsulate the cultural norms and expectations and thus will require broader awareness and sensitivity. It is important to remember that SPE does not dictate the whats and hows of communication, but provides the means for raising the awareness of cultural differences.
• It is recognized that the soft skills matrix was initiated within the North American cultural system and thus requires adjustments for the nuances present in the various geographic regions. To do this, each region has to make it credible in ways that work for that region, thus emphasizing the critical importance of initiating through and engaging the grassroots membership in this endeavor.
• Unlike the general transfer of technical skills, soft skills require the interaction between social constructs and individual knowledge, which in turn inform each other. Wisdom and knowledge are not held by an expert but are created through the interaction of members in pursuit of shared objectives.
• There are regional constraints and variations in the cultural capacity to adapt, which clearly defines what is negotiable and what is not.
• Recruiting regional soft competency experts to assist with the development of short courses and training will be a continuing challenge.

New EPA Regulations Offer Opportunities for Waste-Gas Emissions

By Stephen Whitfield

A new federal air-quality rule from the US Environmental Protection Agency (EPA), 40 CFR Part 60 Subpart OOOO, could have an effect on how the oil and gas industry handles waste-gas emissions. Facing the specter of tougher regulations, the agency is also seeking ways to turn the challenges those regulations pose into positives. Vent-gas management has become more important for companies learning how to operate under the new rule.

At a presentation hosted by the SPE Gulf Coast Section’s Health, Safety, and Environment study group, Jeff Voorhis, a business development and regulatory specialist at Hy-Bon Engineering, and Audrey Mascarenhas, the president and CEO of Questor Technology, discussed new approaches companies could take.

Commonly referred to as EPA Subpart Quad O, the rule states that a single storage vessel in oil and gas production, natural gas processing, or natural gas transmission and storage that has the potential for six tons per year or more of volatile-organic-compound (VOC) emissions must reduce those emissions by 95%. The EPA does not stipulate a way to do that, only that companies must do it. 

One method of compliance is through vapor recovery, which was the primary focus of Voorhis’ presentation. Hy-Bon specializes in the production of vapor-recovery units (VRUs) designed to comply with regulatory standards by eliminating the emission of stock-tank vapors into the atmosphere. These units capture diverse gas streams, including methane, carbon dioxide, and hydrogen sulfide.

A vapor recovery unit. (Courtesy of Hy-Bon Engineering.)

VRUs have several benefits, Voorhis said. They can capture up to 100% of the hydrocarbon vapors that accumulate in tanks, and those recovered vapors have a much higher BTU content than pipeline-quality natural gas. The recovered vapors can be more valuable than methane alone, and the recovery can reduce regulatory and liability exposure. 

Voorhis said that, from this perspective, companies can make money off of the emissions that they have to control anyway.

“The mantra to have is what gets seen by companies, by yourself, and by agencies gets measured; what gets measured, gets controlled; and the good news is… what gets controlled, can make you money,” he said. “You can become a profit center at your companies now.”

The value, however, depends on the BTU content of the gas and the way in which the gas is used. On-site fuel is measured in terms of fuel that must be purchased. Gas coming through a pipeline is measured by the higher price for rich gas. Gas from a processing plant is measured by the sale of natural gas liquids and methane, which can be separated, Voorhis said. 

Mascarenhas’ presentation focused less on Quad O and more on the general environment fostered by tighter EPA regulations, like Quad O or other regulations that set new performance standards for sulfur dioxide, hazardous air pollutants, and fugitive emissions from compressors. Like Voorhis, Mascarenhas said she believes there is potential for a win-win situation in which regulations are met and companies can generate profit. 

The combustion of hydrocarbons lay at the center of this opportunity, as inefficient combustion leads to an increase in VOCs, as well as an increase in greenhouse gases because the global warming potential of methane is 21 times that of carbon dioxide. Mascarenhas said that clean combustion can be measured independently and consistently at 99.99% and is auditable for regulatory compliance. It is cost-effective, low maintenance, and provides an air-quality benefit.

The capture by clean combustion of the excess energy being “lost” in waste-gas offers an avenue for profit, Mascarenhas said. 

“I think there’s a great opportunity on the combustion side, especially if you can do clean combustion because there’s this enormous opportunity to use the heat wisely,” Mascarenhas said. “I think it makes business sense, not just in terms of dollars and cents.”

The heat from clean combustion of typically flared gas at 99.99% efficiency has many uses, Mascarenhas said. The recovered heat can help with water vaporization, steam generation, and can serve as an alternative to diesel generators, which would further reduce emissions on wellsites. The heat from waste-gas can also be used for hydrate prevention and for heating up oil and water. This helps in fracturing operations, where water must be hot. And there is a lot of waste heat available: Mascarenhas said that a well burning 5 million standard cubic feet per day could generate 220 million BTU per hour of waste heat.

Stephen Whitfield is a Staff Writer for Oil and Gas Facilities. 

As Scarcity Hits, Water Tech Flows In

As Scarcity Hits, Water Tech Flows In

Trent Jacobs, JPT Technology Writer
Although the oil and gas boom in the United States owes much of its success to the abundance of cheap sources of fresh water, the status quo is beginning to change. Groundwater remains the main source of water for most onshore exploration and production companies; however, they are increasingly investing in produced and flowback water-­treatment technologies. Many of the same companies are also turning to brackish water sources in places where freshwater aquifers are becoming depleted, such as the Permian Basin that spans west Texas and eastern New Mexico. Brackish water, sometimes called fossil water, has less salt content than seawater, making it cheaper to treat, and is typically found in the same areas where hydrocarbons are developed.

“frac pit” in Glasscock County, south of Garden City, Texas. Fresh water remains the main source for hydraulic fracturing fluids; however, companies are increasingly turning to other water sources to support the rapidly growing shale fields in the Permian Basin. Photo courtesy of Chip MacLaughlin.

The Fasken Oil and Ranch in Midland, Texas, relies on produced-water recycling and brackish water for nearly all of its oil and gas operations at its primary operating area. In August, a larger operator in the area called to buy produced water from Fasken, said Jimmy Davis, operations manager at the family-owned oil company.

The friendly request exemplifies the increasingly desperate water situation that oil companies are facing in the Permian Basin, one of the most productive onshore area in North America. “They are in a fix for water,” Davis said. “I am starting to hear that over and over. What we are doing out here as an industry is using water to frac, and we are in a drought-stricken area so you have to find other means than fresh water to meet those needs.”

Based on the number of inquiries and activity that he is seeing from neighboring companies, Davis said he predicts that over the next few years, a majority of Permian Basin operators will turn to brackish and produced water as their primary sources. “If you are going to continue to frac like we are, that is what you are going to have to do to sustain it,” he said.

According to a market analysis report by Houston-based PacWest Consulting, onshore oil and gas companies in the United States spent USD 20.1 billion last year on water-management services. While only 4% of the spending was for water treatment, if projections hold true, then this year will mark the turning point. The report said that water treatment represents the smallest yet fastest growing segment of the water-management market with a forecast of 23% growth each year to USD 1.3 billion by 2016. “Prevailing drought conditions and long-term sustainability of freshwater sources is expected to steadily increase demand for treatment services,” the report concluded.

The increasing drilling and completion activity in the United States is driving water requirements for the oil and gas industry to new heights. Water for hydraulic fracturing is expected to grow at an average rate of 8% through 2016. Graph courtesy of PacWest Consulting Partners.

Pioneer Natural Resources, which estimates that it has more than 10 billion BOE of reserves in west Texas, finalized a deal in August with the cities of Midland and Odessa, Texas, to purchase between 340,000 and 360,000 B/D of municipal waste water. Neither of the two cities, which constitute the heart of the Permian Basin, treats its waste water for consumption, so Pioneer is not competing with the public for a freshwater source. A primary benefit of using municipal waste water is that it is essentially fresh water with only solids, biological matter, and traces of pharmaceutical chemicals that need to be removed.

Scott Sheffield, chairman and chief executive officer of Pioneer, told investors that his company will need up to 1 million B/D of water over the next 10 years. “This goes a long way to securing water sources that are non fresh,” he said in August. “Eventually, we want to be (using) over 75%—over the next several years—non fresh water sources.” To further supplement its water needs, Pioneer also recently began taking in almost 60,000 B/D from brackish wells for part of its Permian Basin operations.

The Fasken Oil Ranch is using treated produced water from this storage pit on its property in west Texas to fracture most of its vertical wells. The company began investing in the treatment infrastructure last year after deciding that it would no longer rely on the ranch’s freshwater wells for drilling or completion operations. Photo courtesy of Fasken.

Also in August, the Texas Railroad Commission, the state’s oil and gas regulator, hosted a water conservation and recycling symposium at which participating companies reported a collective water recycling capacity of 1.5 million B/D. The production companies that presented at the event included Pioneer, Apache, Laredo Petroleum, and Fasken.

“Due to the drought our state is currently experiencing, the importance of water conservation and scrutiny over water usage continues to grow, and the industry is doing their part in conserving this precious resource,” said Texas Railroad Commissioner Christi Craddick. “We know that industry technology in water recycling is changing the way energy is developed in Texas.”

In a subsequent press interview, Craddick said she expects some oil companies in Texas to end their use of fresh water within 5 years. “I think that’s not an unrealistic number, at least for the large companies,” she said.

Old Ranch, New Reality

Oil production from the Permian Basin was expected to reach 1.72 million B/D by September, an increase of 38,000 B/D from the previous month. And as the boom continues, so does the historic drought that began in 2010. The lack of rain and continued use of water for drinking, irrigation, and oilfield activity has left many west Texas aquifers at their lowest levels ever. The situation has caused many companies to rethink where they are getting their
water from.

At the 101-year-old Fasken ranch, freshwater scarcity has been a fact of life since its founding in 1913. Oil was first discovered on the 165,000-acre ranch in the 1940s and remains the core business of the family-run company that also leases its land for cattle grazing. The family is noted as owning the 25th largest land holdings in the US, counting additional properties in south Texas. But recently, the company has made headlines for its decision last summer to begin ending its reliance on fresh water for its drilling and completion operations and invest in new water-treatment technology. For Fasken, profitability was not a driver.

“We wanted to discontinue using fresh water, mainly because there is not that much fresh water on the ranch,” said Davis. “We wanted to preserve what water we have for the future generations that will inhabit the ranch.”

To operate four drilling rigs and complete two hydraulic fracturing jobs each week, the work crews need roughly 19,000 B/D of water. Davis said his company is meeting almost all of the demand on two fronts: a leased system recycles produced water from the ranch’s nearly 450 operating wells, and a newly installed system, also leased, treats brackish well water from a formation found 1,100 ft to 1,500 ft deep.

So far, more than 50 vertical wells have been hydraulically fractured at the ranch using the recycled produced water with no reported problems. By the end of the year, the company expects that it will have reached its goal of zero freshwater use for all of its oil and gas operations. A small amount of fresh water is still used to support operations in the most remote part of the ranch. Companies that adopted water-treatment technology, such as Fasken, have discovered that the solution does not merely involve one system, but layers of treatment and filtration systems.

To reuse produced water, Fasken first treats it with chlorine dioxide, an iron-oxidizing agent, to aid in the separation of oil and water and control bacterial growth. The water is then run through an electrocoagulation system that removes any remaining solids before it is moved into settling tanks. After the heavier solids sink to the bottom, the treated water is stored in a 120,000-bbl capacity pit as it waits to be used for hydraulic fracturing.

The company pays a fee of about USD 1.50 to USD 1.75 per barrel of treated produced water to the equipment owner. Davis said that it is more expensive than fresh water, but not by much. However, the brackish-water system is treating water for less than half of what it costs to treat the produced water. He said this cost savings is leading the company to study how it can use brackish water exclusively. A recent switch to a more robust membrane unit makes it possible to use treated brackish water for cementing jobs that require very low salinity.

To treat the brackish water, the ranch uses a nanofiltration system that has also been used in Africa to treat water for human consumption. Nanofiltration is a membrane technology that is most applicable for fluids with low solid content and uses pores a little larger than the membranes used in reverse osmosis. The main contaminant that nanofiltration removes before the water can be used as a fracturing fluid is sulfites, which lead to scaling. A primary consideration with the brackish water involves the waste stream. About 25% of the water is rejected and must be pumped down a disposal well.

Fasken Oil and Ranch in Midland, Texas, is using an electrocoagulation system to remove solids from its produced water (right) so it can be used for hydraulic fracturing of vertical wells in the Wolfberry shale in the Permian Basin. The treated water (center) is placed into a settling tank where the solids sink to the bottom before being discharged into storage pits. Photo courtesy of Fasken.

Fasken has a distinct advantage over some of its competitors in the area when it comes to water-treatment infrastructure. With more than 250 sq miles of contiguous land, the company runs its own pipeline network that brings produced water to the treatment site and it owns its disposal well. This eliminates disposal well costs, which Davis said are around USD 1 per bbl, and it means the company does not have to pay a third party to haul the water to a disposal site, which can cost between USD 85 and USD 100 per hour for a truck that can only carry 120 bbl at a time.

“For this to work most efficiently, you have to have a big enough area to produce from,” Davis said. “For the smaller operators, this is hard to do because most times, we in the oil business may have a square mile or section of land leases here and then it could be 10 miles away to the next lease.”

Still Testing Technology

Richard Crawford has been involved in water treatment for more than 20 years and is a production engineer on Concho Resources’ freshwater-management team in New Mexico. He has helped review water-treatment technologies that will allow Concho, a producer of shale plays in Texas and New Mexico, to use produced water instead of fresh water for hydraulic fracturing. Echoing the convictions of Fasken, Crawford described his company’s efforts to find produced-water solutions as driven by its responsibility to local stakeholders and conservation, rather than by economics. “We are trying to be good stewards of the community” and the environment, he said. “That is really the big push behind this. If you are looking for a financial win, it is going to be tough.”

Crawford explained that of the long list of water technologies that he has worked with or researched, none is price-competitive to fresh water—that is when it can be found. “Fresh water is becoming rarer and more difficult to obtain,” he said.

Fasken has a distinct advantage over some of its competitors in the area when it comes to water-treatment infrastructure. With more than 250 sq miles of contiguous land, the company runs its own pipeline network that brings produced water to the treatment site and it owns its disposal well. This eliminates disposal well costs, which Davis said are around USD 1 per bbl, and it means the company does not have to pay a third party to haul the water to a disposal site, which can cost between USD 85 and USD 100 per hour for a truck that can only carry 120 bbl at a time.

“For this to work most efficiently, you have to have a big enough area to produce from,” Davis said. “For the smaller operators, this is hard to do because most times, we in the oil business may have a square mile or section of land leases here and then it could be 10 miles away to the next lease.”

Fasken Oil and Ranch has found the mobile electrocoagulation unit that it uses to help meet its weekly requirement of 19,000 bbl of water to be an inexpensive solution for produced-water treatment. Nevertheless, the company said that the membrane treatment it uses for brackish-water recycling costs less than half that of produced-water recycling. Photo courtesy of Fasken.

Going down the list, Crawford said he has tested systems, such as mechanical vapor recompression, sonic ionization, and reverse osmosis membranes, and is now looking into forward osmosis. Each technology has advantages, just as each has its drawbacks. “Mechanical vapor recompression systems are great if you get a quality product,” Crawford said, “However, they are expensive, and it is a big piece of equipment. It is a full-fledged plant with a control room.”

The mechanical vapor recompression technology works by heating up the wastewater stream to the boiling point and uses a powerful vacuum to pull the water vapor into a heat exchanger in which it returns to its liquid state as clean water.

As Crawford pointed out, the downside of this technology is its size and complexity, which precludes it from being a truly mobile solution to offset hauling and infrastructure build-out costs. “They like to say it is mobile. But it has 10-in to 15-in flanges that have to hook up from one module to the next module to the next module. You are not going to move it by 4 p.m.,” if you begin at noon, he said. “My idea of mobile is, I want you (on or) off my site today.”

Some technologies are quite mobile however. Trailer-mounted electrocoagulation systems can be hooked up to special fracturing water tanks and become operational within a couple of hours. The business model for many oilfield water-treatment solutions is to charge a per-inlet-barrel fee. But the question that Crawford said vendors have trouble answering is what the real cost of treated water will be. He said some of the companies whose equipment he has tried advertised that the water can be treated for as cheap as USD 2 per bbl.

“That is on the inlet,” he said. “I do not care about that. I care about what comes out the backside.” For example, if 1,000 bbl of water goes into a treatment system and rejects 500 bbl as a waste stream, Crawford said he is only interested in the cost of the 500 bbl of usable treated water. Pricing the service this way will provide treatment companies with more incentive to improve recovery rates, he said.

Crawford also advises that before a company invests in water-treatment technology, it must have a plan for the disposal of its solid-waste stream. Calcium carbonates, sodium chloride, and sulfites are just a few of the substances that need to be removed from produced water, because they cause scaling tendencies and clogging problems downhole.

Other contaminants, such as radioactive isotopes of barium and strontium, can precipitate as solids from produced water. If concentrated through filtration systems, these normally occurring radioactive materials require hazardous disposal that can cost up to USD 550 per barrel.

Other methods of dealing with the solid waste include concentrating it into a slurry that can be taken to a disposal well site; others turn the waste into a cake that can be sold to cement plants for roadbed material. In one of its operations, Concho dilutes its concentrated waste stream with untreated produced water and injects it into a disposal well near its operations. Crawford said that when a disposal well is nearby, it improves the economics of a company’s water-treatment options.

The Future Looks Brackish

Dave Stewart, president and CEO of Stewart Environmental Consultants based in Fort Collins, Colorado, said many in the oil and gas industry are overlooking an enormous source of water from brackish wells. Stewart, who built Colorado’s first produced water treatment facility for reuse in 2001, said that the industry is suffering from increasing costs for freshwater usage and he expects this trend to only worsen.

Brackish and saline water can be found across the contiguous United States, particularly in states with the heaviest concentration of oil and gas exploration activity, such as Texas, Oklahoma, New Mexico, and Colorado. Image courtesy of United States Geological Survey.

In Texas, the top oil and gas producing state in the US, almost 800 municipal water districts have implemented rationing policies for public consumption and many have stopped selling water to oil and gas companies altogether. Stewart said that scarcity and state-imposed restrictions on water usage in New Mexico mean that even brackish water is now fetching the same prices as fresh water, which can be as high as USD 3 per bbl.

“As the price goes up, you start getting farmers who stop using it for irrigation and start selling it” to oil and gas companies, he said. “Environmental groups and agricultural groups are going to fight that tooth and nail. But if you take brackish water, which nobody uses, then you avoid that argument altogether and at a price that energy companies are already paying.”

Brackish water may also be the best option in New Mexico because of its strict regulations regarding produced water, which is always treated as a hazardous material even if it is treated thoroughly. Spills of treated produced water are treated just like spills of untreated produced water and can incur fines of hundreds of thousands of dollars. The New Mexico Legislature is expected to vote on new rules that will further regulate how and where produced water treatment sites can be set up, and even what equipment should be used.

What Stewart proposes is that when companies drill a well for oil and gas production, they should consider drilling a brackish well to meet their water needs. Using inorganic aluminum-based and carbon silicate-based membranes, Stewart said companies like his are able to treat brackish water for oil and gas companies for as little as USD 0.20 to USD 0.10 per bbl. Although the figure does not include capital-recovery costs, Stewart said, “That is a very acceptable price for an energy company.”

Brackish water is cheaper to treat because it does not need to be cleaned up as much as produced water, which typically has much more solid particulates. Once the multivalent ions including scale-inducing iron or barium are removed, the solution goes through a nanofiltration system and is then ready for hydraulic fracturing use. Furthermore, Stewart pointed out that there are few regulations governing the use of brackish water, because only a few parts of the world use it for human consumption. “The brackish-water sources around the globe double our water supply,” he said. “Eventually, we are going to get into that from a municipal standpoint as well.”

Mining the Water

Stewart said one of his goals is to create zero-liquid-discharge plants in the Captain Reef basin that straddles southwest Texas and eastern New Mexico. The brackish water from the formation is saturated with gypsum and Stewart’s company is able to extract it and then sell the treated water to companies for hydraulic fracturing, as well as the gypsum.

The company also sells the brine water, a byproduct of the membrane process it uses, concentrated with sodium chloride, to industrial companies that can use it in other processes. Stewart said the key to this type of water-mining operation involves knowing the input qualities and commercial opportunities in order to use 100% of the fluids.

Finding Ways to Fight Asphaltene Deposits

Rice University professor Walter Chapman said that the key to finding the solution to asphaltene deposits in wellbores and pipelines is to develop an effective model of phase behavior and deposition in crude oil systems.

Asphaltene deposits in wellbores and pipelines are an expensive and challenging problem for operators, and finding the source of this problem could have positive effects on both production planning and designs.

In a presentation hosted by the SPE Flow Assurance Technical Section on 16 September in Houston, Walter Chapman, a professor of chemical and biomolecular engineering at Rice University, said that the key to finding that solution was to develop an effective model of phase behavior and deposition in crude oil systems. His presentation focused on two main models developed at Rice: the perturbed chain form of the statistical associating fluid theory equation of state (PC-SAFT) and the asphaltene deposition tool (ADEPT).

PC-SAFT is useful in describing the phase behavior in a given system because it works well with the polydisperse, polyatomic nature of asphaltenes, Chapman said. The model allows engineers to form molecules of any desired shape or size, which can then associate with each other. The model, which is commercially available, has physical parameters for a range of hydrocarbon components—the number of beads that make up a chain, the diameter of a bead, and the van der Waals attraction from one bead to another—that can be used to characterize a norm.

Chapman said that phase behavior is also well-modeled by polymer solution models such as Flory-Huggins, in part because any equation of state is able to handle large sizes and asymmetry.

“Particle phase behavior is just regular solution theory,” he said. “Regular solution theory is actually pretty good, and it allows us to interpret those things.”

Unlike PC-SAFT, ADEPT is a simulator that predicts the occurrence and magnitude of asphaltene deposition in the wellbore that helps engineers better understand the rates of precipitation, aggregation, and deposition. Chapman called it a straightforward mathematical model that describes the changing composition of asphaltenes over time.

Chapman said there are other opportunities for improving the modeling process. He said ADEPT must be further tested, and case studies are required so engineers can determine how well the test worked. He is conducting a study of asphaltene plugging with DeepStar, a joint industry technology development project focused on advancing deep-water technologies. Other challenges are interfacial properties and better predictions at higher temperatures and pressures.

Chapman said a consortium on petroleum thermodynamics and flow assurance is currently taking place at Rice University. Led by Chapman and fellow chemical and biomolecular engineering professors Francisco Vargas and Sibani Lisa Biswal, the consortium aims to establish a forum for oil and gas companies to exchange ideas, conduct research, and develop more modeling tools and experimental procedures to help mitigate flow assurance problems.

“Rice is somewhat unique in that we have researchers in virtually all areas of flow assurance,” Chapman said. “What’s interesting about flow assurance is that there’s a lot of interaction between these areas, so having researchers that encompass this entire area allows us to better look at control strategies that can address some of these cross interactions.”

Stephen Whitfield is a Staff Writer for Oil and Gas Facilities. 

Automated Well Ignition Increases Safety for Well Blowouts

Automated Well Ignition Increases Safety for Well Blowouts

OCTOBER 1, 2014

United Safety

As demand and footprint of the oil and gas industry increases, the distance between facilities and populated areas diminishes. Companies also have to move into critical fields (high pressure and high hydrogen sulfide concentration). This means that special hydrogen sulfide protection measures need to be in place not only to ensure the safety of onsite workers but also to protect nearby communities.

The United Safety VulQan is a unique product designed to perform well blowout ignition.

The presence of hydrogen sulfide creates unique challenges for oil and gas operators, including the specialized drilling systems required and the health problems caused when hydrogen sulfide is released into the atmosphere.

A multitude of mechanical and procedural measures are in place to prevent any release. The standard hydrogen sulfide safety systems on the work site consist of detection measures to give early warning of hydrogen sulfide presence and breathing air equipment that the workers can put on for escape or to work safely in the presence of the gas.

“There is a long history of learning and progress with these onsite systems, and, overall, they are very effective when operated and maintained properly,” said Mike Gilbert, vice president, Middle East, for United Safety.

However, despite safety measures in place, accidents may happen. A blowout, for instance, occurs when the crew loses control of the well because of complications during drilling, allowing a free flow of gas or oil from the wellbore into the atmosphere. A large volume of hydrogen sulfide toxic gas can be released hundreds of feet in the air in a very short time. This gas cloud, or plume, is carried by the wind and will settle on lower grounds (hydrogen sulfide is heavier than air), creating very immediate health hazards or even death for anyone in its path. For example, a hydrogen sulfide blowout in chuandongbei gas field   in central China in 2003 resulted in an area of more than 25 km² being covered with high concentrations of hydrogen sulfide, killing 243 people, seriously injuring 9,000, and displacing more than 64,000 from their homes.

To avoid the consequences of a blowout, a combination of gas detection, safe evacuation, and well ignition (when necessary) is the best solution. Elie Daher, executive vice president for United Safety, explains “not one single safety measure can be ultimately effective in addressing hydrogen sulfide protection. There needs to be comprehensive planning and continuity in the measures taken from start to finish of these challenging projects.”

Depending on the magnitude of the blowout, the well may need to be ignited. When the hydrogen sulfide gas is burned, the byproduct, sulfur dioxide, is carried higher into the atmosphere by the heat and, therefore, disperses more readily, resulting in lower ground concentrations.

Therefore, a safe well-ignition solution needs to be part of any comprehensive critical well safety management system. Traditionally, this is done by a trained individual using a flare pistol from an estimated safe distance.

“As you can imagine, a blowout is an extremely dangerous, messy, and violent event. We’ve responded to many of them in our time. To put a human being in harm’s way to ignite these blowouts is becoming a thing of the past and is unnecessary with today’s modern technology” Gilbert said.

In order to ignite the well safely, companies can rely on automated well ignition system. In the event of a blowout, once the work site is evacuated, the designated person will activate the well ignition from a control unit, placed in a safe area. Once activated, there is a variable delay before the system discharges into the gas cloud, allowing time for personnel to retreat to a safe distance. The system will continue to discharge flaming gel at preset intervals to ensure continued and complete ignition of the well.

“There is no question, safely igniting the well release as soon as possible is the fastest and most effective way to reduce immediate danger to the communities and workers” Daher said.

The Shale Evolution: Zipper Fracture Takes Hold

Trent Jacobs, JPT Technology Writer

A horizontal well completion method known as zipper fracturing has been rapidly adopted over the last couple of years by companies in the Eagle Ford shale of south Texas. Instead of drilling and hydraulically fracturing one well at a time, the zipper method involves drilling multiple wells from a pad site and then hydraulically fracturing a stage in one well, while getting ready for the next, as wireline and perforation operations take place in another. The multiwell completion method earns its name from the zipper-like configuration of the fracture stages from wells drilled with relatively tight spacing.

This shaves days off the time it takes to complete a multiwell pad. Many companies in south Texas are now using the completion method on almost every new pad site they drill into, saving tens of millions of dollars per year while accelerating the development of their well inventories.

But the big prize may be that zipper fractures are increasing initial production and estimated ultimate recovery rates when designed so that the fractures stimulate the most reservoir volume possible. Tulsa-based WPX Energy, an independent operator of 160,000 acres in the San Juan Basin of New Mexico, told investors this summer that when the company switched to zipper fracturing, it averaged 420 B/D of oil production compared with 388 B/D from single-well completions. While not entirely sure if zipper fracturing is the direct cause of improved production, WPX said it expects that is the case.

A Halliburton crew performs a zipper-fracturing completion on three horizontal wells in the Eagle Ford shale of south Texas. The multiwell completion technique has been rapidly adopted by the unconventional industry as operators realize time savings and production benefits from stimulating more reservoir rock. Photo courtesy of Halliburton.



Mukul Sharma, a professor and chair in the petroleum department at the University of Texas at Austin (UT), said field data from Eagle Ford wells make it clear to him that zipper fractures are indeed improving initial production rates and the estimated ultimate recovery. Sharma said operators in south Texas have reported improved initial production rates ranging from 20% to 40% using the zipper method. “I would say that this is definitely the way people are going to be doing a lot of their fractures in the future,” he said. “What I think we need to do is understand better how it works—why it works. Once we understand that, we can apply it much more efficiently.”

Marathon Oil first tested the zipper method in the Eagle Ford shale 2 years ago. Today, at least 95% of the company’s pad wells are being completed with zipper fractures. This is saving Marathon an average of 4 days in completion time per pad. “Anything with two or more wells, we will zipper frac,” said Richie Catlett, completions engineering supervisor at Marathon. “From a completions standpoint, for us the main thing is efficiency. It cuts days off our operations, and that is the big reason we went to zipper fracs.”

The Eagle Ford is also where Schlumberger is doing its highest share of zipper fractures, but the company said there is significant momentum behind its adoption outside south Texas, including in the Permian Basin of west Texas and Williston basin in North Dakota. “Nearly half of the completions that we do today in North America are completed with what we call the zipper-fracturing method,” said Alejandro Peña, global chemistry and materials portfolio manager at Schlumberger.

As the use of this method spreads, the Eagle Ford shale remains the uncontested zipper-fracturing capital of the world. Two-and-a-half years ago, less than 25% of Halliburton’s completion operations in the Eagle Ford were zipper fractures. Since then, that share has grown to 85%. Bill Melton, a completions sales manager at Halliburton, said operators have been inspired to adopt the method more for its completion efficiencies than for its potential production benefits.

“By doing zipper fracs,” he said, “a customer can do six to eight frac stages a day. Whereas if they did each well for the entire length, and then switched over to the next well, they could only do three-and-a-half to four stages a day.”

Halliburton has even taken the zipper method south of the US border into Mexico for Petróleos Mexicanos, more commonly known as Pemex, where unconventional shale exploration remains in its infancy. The company believes that this could help develop Mexican shale fields, and those elsewhere, relatively quickly compared with the Texas experience, which took years of trial and error to achieve the near-record production levels seen today. “It takes advantage of all the learning that has already been done, and it accelerates their development cycle time,” Melton said. “Where it may have taken a year for a US operator to get to a 50-well volume, if they are doing pad drilling and pad completions,” non-US operators could be there in a third of the time.

Changes and Challenges

Companies using the zipper method have had to make a few operational considerations that do not apply to single-well completions.  When completing horizontal wells one at a time, once the fracturing job in an individual stage is finished, the wireline operation to set plugs and perforate the next stage in the wellbore normally takes 2 to 3 hours,  though it can last for as long as 5 hours between stages.

Clifford Phillips, an advanced drilling engineer at Marathon, said when doing zipper fracturing the break in stimulation operations may only last 15 minutes as workers switch from one well to another. “It is a big change operationally for the frac crew,” he said. “They go from having a huge amount of dead time in between fracs to almost no time at all.”

The constant rate of high-horsepower pumping has a downside for service companies; their pumping trucks are lasting about half as long when working on zipper fractures. Catlett also said zipper fracturing allows service companies fewer opportunities to perform maintenance on in-between jobs. “They have to either provide more pumps, which is getting to be a problem with the industry right now, or they are going to have to provide more efficient pumps that can last longer,” he said. “It is a challenge.”

With a lot of the extra workload shouldered by the service companies, one challenge for the operator is to make sure that a steady stream of sand or proppant is arriving to the pad site to keep up with the continuous fracturing. Marathon engineers said they like to keep enough proppant on site for at least four or five stages so that if there is an interruption in deliveries, the fracturing crew can keep moving, which increases truck traffic into and out of the pad site substantially.

As seen from above, the various types of completion methods that are used to develop shale formations. The modified zipper fracturing (MZF) is the latest evolutionary step taken by the industry to yield more production compared with the regular zipper fracturing and “Texas Two Step,” also known as alternating fracturing, where stages are stimulated out of sequence. Image courtesy of Mohamed Soliman/Texas Tech University.

There are some limitations to deploying the zipper method. On a five-well pad Marathon will only zipper fracture three wells at a time, and then the next two. This is because the crane it uses for the wireline operations only has a radius of 90 ft while the wells are spaced out at approximately 25 ft to 30 ft.

In terms of extra equipment, the only added system requirement is what is called a zipper manifold, which Dennis Donovan, completions engineer at Marathon, described as a “frac stack” turned on its side that redirects the fracturing fluids into different wells. “That way we are going down the line from one well to the next,” he said. And the cost of the manifold is easily offset by the money saved in rig time and other rental equipment.

A closer view of a Halliburton zipper-fracturing treatment shows the tight arrangement of pressure pumping trucks, wellheads, and wireline crane. The company said that in less than 3 years, the proportion of zipper-fracturing completions it does in the Eagle Ford shale of Texas has increased threefold to 85%. Photo courtesy of Halliburton.

Time Delay Critical

When hydraulic fractures propagate into a formation, a stress shadow is created inside the rock that acts like a force field, hindering the fracturing of another stage. As the fracture closes, the spatial extent and the magnitude of the stress shadow is reduced.

Sharma has been studying the role that induced unpropped fractures play in unconventional development for years and has found evidence suggesting that they not only exist, which has been a subject of debate, but they also penetrate into the rock farther than the propped fractures do. He said production history matching, tracer technology, and microseismic monitoring all indicate that induced unpropped fractures tend to form around the propped fractures and then close in a relatively short period of time.

This is important because Sharma believes it is the reason why zipper fractures work. “The stress shadow you see right after you frac the well can have a fairly large spatial extent, but over time this stress shadow will become confined to a region around the main fracture as the induced unpropped fractures close,” he said.

Allowing the stress shadow to shrink is believed to make fracturing the subsequent stage in a horizontal well more effective because there will be far less stress interference in the rock from the previous fracture blocking the new fractures.

When hydraulic fractures are closely spaced, the stress shadow effect can lead the fractures to grow away from one another and towards areas of lower stress, which may mean less rock is stimulated. To reduce the effect of the stress shadow, Sharma said some operators are doing four-well zipper fracturing instead of two-well.

“You can do Well 1, then 4, come back and do 2, and then do Well 3,” he said. “People have tried that and it seems to work.” By applying the method to four wells instead of just two, Sharma said the time delay between two adjacent fractures in the wellbore can be extended by a factor of five or six.

This example shows zipper-fracturing treatments for two wells in the sequence of A1, B1, A2, B2, A3, and so on. Image courtesy of Petróleos Mexicanos.

One way operators can plan and design for this is by using modeling software that includes the stress shadow effect from adjacent wells. In the past, most commercially available fracturing software modeled one well at a time. Over the past 2 years, Sharma said companies have realized that modeling horizontal well fractures in isolation is insufficient when planning for a zipper-fracturing program. As a result, UT now offers operators software that is able to model more than 100 fracturing stages in a multiwell pad.

Zipper Mechanics
Neal Nagel, chief engineer and principal at Houston-based OilField Geomechanics, started studying zipper fractures several years ago when operators needed help in figuring out why the completion method has increased production for some, but not for others. He said the big question that operators want to know is why does the interaction between two wells potentially increase production?

“There is a strong link between a hydraulic fracture and the natural fractures, and from a geomechanical perspective, we were looking at that,” he said. Using a series of numerical tools, called discrete element models, Nagel simulated and evaluated the interaction of hydraulic fracturing with natural fractures. Instead of doing this with a single horizontal well, the simulation was run with a dual-well configuration. What Nagel concluded from his geomechanical evaluations is that there are three primary factors that dictate how well a zipper fracture may perform. They are:

• Existence and conductivity of the natural fractures
• The impact the stress shadow may have on hydraulic fracturing between two wells
• Ability to change the pressure within the natural fractures between two wells

“It is those three issues combined that we think are the foundational and important issues when zipper fracs work,” he said. “When they do not work, one of those three things is essentially missing.”

Without natural fractures, Nagel believes that zipper fractures will have zero impact on production. He said one of the reasons that the zipper-fracturing method has taken off in the Eagle Ford shale more than in other areas is because of the prevalence of natural fractures. Unlike in the Barnett, Bakken, Marcellus, and Haynesville shales, operators in the Eagle Ford have reported more pressure communication between adjacent wells. This suggests that natural fractures in the Eagle Ford tend to exhibit greater communication over a longer range than in many other shale plays.

“For those situations like the Marcellus and Haynesville, where it is very uncommon to see operators report pressure communication between wells—that tells you the natural fracture system is not as pervasive or not as connected,” Nagel said. “That would mean that you are not going to be able to change the pressure between two wells. And without that pressure change, a zipper frac is unlikely to show much benefit.”

The image on the left shows the position of microseismic geophones and on the right are the microseismic events recorded during a zipper-fracturing sequence. Image courtesy of Research Partnership to Secure Energy for America, and Gas Technology Institute.

Also, to achieve a positive production outcome, the wells must be properly spaced, and the fractures need to be long enough so that they touch and overlap with one another, thus ensuring there is communication between adjacent wells.

An SPE paper published by Halliburton this year, which evaluated the benefit of zipper fractures in unconventional reservoirs ran simulations that showed when zipper fractures overlap the incremental recovery factor was in the range of 15% to 20%, compared with zipper fractures that do not overlap.

Based on the field data and case study work he has done, Nagel is convinced that pore pressure is the most important factor leading to a zipper fracture that nets higher stimulated reservoir volume and thus production. “When I create a hydraulic fracture, I am injecting at a pressure higher than the minimum in-situ stress, which, by definition, has to be greater than my pore pressure,” he said.

The effect of the increased pore pressure is that the natural fractures are induced to slip more, thereby increasing the permeability and flow capacity of the source rock, as Nagel’s research suggests, and is responsible for the higher productivity in zipper-fractured wells. He said these subsurface events can be detected and observed using microseismic technology.

“When zipper fracs work, we have a configuration where the pressure increase from the first well increases the pressure in the region of the second well,” Nagel said. “When we frac that second well, what it (increased pressure) does is make it easier for the natural fractures and weakness planes to slip; we see greater microseismicity, we see increase in flow capacity, and we see an increase in production.”

Modified Zipper Fracture

Before Mohamed Soliman became the chair at Texas Tech University’s petroleum engineering department in 2011, he worked for Halliburton for 32 years and holds 26 patents on hydraulic-fracturing technology.  One of the patents that Soliman received while at the company was for the alternating fracturing, a precursor to the more efficient modified zipper fracture, which also was designed to breakup as much rock to create more complex fracture networks.

Simulation results of two wells show the modified zipper fracture (MZF) increasing gas production by 44% more than the original zipper fracture due to the increased fracture complexity. Graph courtesy of Mohamed Soliman/Texas Tech University.

“We came up with alternating fracturing which is done from one well. You create a fracture, then you create another fracture, and then you go in the middle to create another fracture,” he said. “Needless to say, operationally this is not exactly what you would want to do.”

Soliman explained that technology has been created to lessen the complications involved with fracturing stages out of sequence but there are too many operational complexities to work through. “It can be done, but it is a headache,” he said.

When Soliman got to Texas Tech he and his research students took a look back at alternating fracturing and also the emerging zipper-fracture method to see if there was a way to net similar production results from alternating fracturing, but without the operational complexity.

What they ended up inventing was the modified zipper fracture that differs from a normal zipper fracture. Rather than having the fractures of two adjacent wells pointing toward one another, they are staggered so the fractures will overlap with one another. Soliman said that with the modified zipper fracturing operators get the benefits of alternating fracturing without all the extra work.

“You probably will have to have your horizontal wells a little closer than you would have in a regular zipper frac, or you create a fracture that is a little longer,” he said. “Another issue is that it will require more engineering work ahead of the drilling. You need to acquire some data, and do your homework.”

Soliman said he and a graduate student have created a simulation software to further study fracture attraction. The software has not yet been commercialized but Soliman said he expects to present it at future SPE conferences.

One of the most intriguing aspects of the overlapping fractures that Soliman has observed is that as the fractures propagate towards one another, once they are in very close proximity, they begin to show an attraction. Soliman said he has recently completed research work on this phenomenon and will publish the results later this year.

To verify their fracture model (left), which showed that as two fractures propagate towards one another they begin to demonstrate a physical attraction, researchers from Texas Tech University looked for other examples and found that the phenomenon is ubiquitous in the natural world. Image courtesy of Mohamed Soliman/Texas Tech University.


“If you have fractures coming fairly close to one another, they will actually turn around towards each other,” he said. “It is very interesting. It looks almost as if it does not make sense, but when you think about the calculations of how stresses change—it does.”