Industry and regulators have known for decades that the oil and gas industry sours sweet formations. What do our authorities do? Deregulate & lie to enable it.
Sulfide-producing bacteria dominate hydraulically fractured oil and gas wells Press Release by American Society for Microbiology, July 5, 2017,
Washington, DC – July 5, 2017– Researchers have found that the microbes inhabiting a hydraulically fractured shale formation produce toxic, corrosive sulfide through a poorly understood pathway. The team’s findings, published this week in mSphere®, an open-access journal of the American Society for Microbiology, reveal that the oil and gas industry may need new ways to monitor and mitigate sulfide-producing bacteria in fractured shales.
“This is a pretty inhospitable environment of high pressure, salinity and temperature some 2,000 meters underground. You’d think that microbes introduced during the fracturing process would die, but some of them make a good life for themselves,” says Mike Wilkins, an environmental microbiologist at The Ohio State University in Columbus and senior researcher on the study. “The industry spends a fair amount of money trying to keep microbes out of these systems.”
… Sulfide-producing microbes cause multiple problems for drilling operations. Hydrogen sulfide can “sour” a well and must be separated from oil and gas in an expensive process. Sulfides can be toxic to the workers on the drilling pad and can also corrosively degrade metal pipelines.
The microbes themselves can gum up the extraction process by filling in the tiny fractures with either biomass or excreted precipitates.
Wilkins’ team had previously found that one bacterial family in particular, Halanaerobium, dominated fractured well ecosystems. These bacteria can convert thiosulfates found in the environment to sulfide. The team, along with collaborators at West Virginia University and Pacific Northwest National Lab, decided to track sulfur cycling catalyzed by the microbial community found in a Utica shale formation well near Flushing, Ohio.
“The well continually pulls up fluids that have been sitting in the fractures for months, so it’s a good way to get a chemical and biological look at what’s going on down there,” says Wilkins. His team collected fluid samples during a 120-day period to measure both the sulfur-containing chemicals and the bacteria species present.
They found that, within 10 days after pumping and sampling of well fluids began, Halanaerobium reached nearly 100% dominance of the bacterial community and remained so for the next 100 days. The team then scoured the genes present to find possible enzymes capable of catalyzing sulfur reactions. They found multiple copies of rhodanese, an enzyme that can reduce thiosulfate to sulfite and elemental sulfur, and anaerobic sulfite reductase, an enzyme that reduces sulfite to sulfide. If Halanaerobium species used these two enzymes together, the microbes could be using environmental thiosulfate to produce sulfide.
To confirm this, the team cultured Halanaerobium isolated from well samples. The lab-grown bacteria produced both enzymes and when fed thiosulfate in the culture media, produced sulfide. Finally, the team measured a particular sulfur isotope that microbes prefer to consume and saw that it decreased in the well samples over time. “That’s a sign that the sulfur cycling seen in this well is a microbial process, rather than an abiotic one,” says Wilkins.
Current industry tests monitor for sulfide-producing microbes by detecting sulfate reduction activity only. “Sulfate-reducing bacteria are super common in seawater and groundwater and convert sulfate to sulfide,” says Wilkins. Halanaerobium, however, convert thiosulfate to sulfide. So today’s tests of this well, Wilkins notes, would mistakenly lead a well operator to think no sulfide is produced.
“Knowing which microbes are doing potential damage is important so that well operators can target them better,” he says. Halanaerobium have been found to dominate fractured well ecosystems from Texas to Pennsylvania, Wilkins says, so improved monitoring of their sulfide production could be key for well productivity nationwide. [Emphasis added]
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The study was funded by the U.S. National Science Foundation and the U.S. Department of Energy.
The American Society for Microbiology is the largest single life science society, composed of over 50,000 scientists and health professionals. ASM’s mission is to promote and advance the microbial sciences.
ASM advances the microbial sciences through conferences, publications, certifications and educational opportunities. It enhances laboratory capacity around the globe through training and resources. It provides a network for scientists in academia, industry and clinical settings. Additionally, ASM promotes a deeper understanding of the microbial sciences to diverse audiences.
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Microbial Control of Souring in Oil Reservoirs Dr. G. Voordouw, U of Calgary
The incidence of souring following water injection is a well recognized phenomenon by the oil industry and has led to the deployment of a variety of methods intended to contain SRB activity. Treatment of injection water with biocides such as gluteraldehyde and cocodiamines is one of the most common approaches for mitigation of souring.
The use of biocide is most successful in controlling SRB in surface facilities but is of limited success in the reservoir, due to occurrence of SRB in biofilms, which usually protects them from the action of biocide. Furthermore, frequent use of a biocide could lead to dominance or emergence of biocide-resistant strains of SRB. [Emphasis added]
The most likely cause of this souring is artificial fracturing and the increase in sour wells over time is due to, in part, the increase in hydraulic fracture fluid volumes from 5-10 m3/m to 25-35 m3/m (2012-2015).
Are authorities lying about the deadly problem or do they not read? Why no mention of the role industry plays in souring reservoirs?
[Assistant deputy minister for Petroleum and Natural Gas Division of the Ministry of the Economy] Dancsok said that in the past, most Saskatchewan oilfields were considered “sweet” and didn’t emit sour gas. But he said as they age they’re becoming sour and producing hydrogen sulphide at an increasing rate.
An oil and gas company failed to maintain an abandoned well that leaked sour gas near homes in Charlie Lake and Fort St. John last December, according to a new B.C. Oil and Gas Commission report.
Earlier this month, the regulator released the results of an investigation into a leak at a Terra Energy gas well near the Old Hope Road on Dec. 11, 2014. The leak may have started two weeks earlier.
Rick Koechl, a nearby landowner, recalled smelling foul odours similar to those of sour gas days before the leak was confirmed and residents were notified.
“It would come and go in terrible waves,” he said in a recent interview. “You wouldn’t know when it would return.”
Koechl said he alerted the commission to one well near his property, first drilled in 1966, and reopened in 2005 only to be abandoned when no gas was produced. Despite the tip, the OGC said it was unable to find the source of the leak.
It turned out, however, that gas was leaking from the well.
Since it was abandoned in 2005, the pipe welding had suffered fatigue, according to the commission’s investigation, and began to crack over time.
Terra Energy was responsible for inspecting the welds annually, however, the commission found the company had not done this.
…
Allan Norman, another nearby landowner, recalled hearing a loud noise on Dec. 11.
“It was just like a roar, an instant roar of pressure being released, like an oxygen bottle being opened up, how it blows and whistles,” said Norman.
According to the OGC report, the commission was notified of a potential leak at 9:30 a.m. However, it wasn’t until six hours later that the commission finally determined there was a leak in progress.
A local farmer had to provide his tractor to gain access to the well site, as Terra did not have the equipment on hand to do so, according to landowners.
At 6 p.m., more than eight hours after the initial report, landowners were notified. Terra went door-to-door notifying residents the leak was happening. …
The OGC began investigating the well after the leak was contained. It found that Terra’s emergency response plan identified the well as “sweet”—meaning that it did not contain hydrogen sulphide.
“What we anticipated was sweet, and it went sour,” Campbell said. “At the time, the wells around there were deemed to be sweet.”
[Encana sold a sour field near Rockyford to Harvest as sweet (yes, they lied to the company and AER). Encana had soured the field, and knew they had. Encana did not tell its “good neighbours” living next door, the “sweet” field had gone toxic.]
2014: Hydraulic Fracturing Additives and the Delayed Onset of Hydrogen Sulfide in Shale Gas
As natural gas production has shifted further from deep prolific gas reservoirs to shale gas, several questions are being addressed regarding fracturing technologies and the fate of chemical additives. A less investigated issue is the unexpected increase in produced hydrogen sulfide (H2S) from hot shale gas reservoirs. Understanding the source of H2S in shale reservoirs and managing low-levels of recovered elemental sulfur affects plans for future treatment, corrosion mitigation, and fracture fluid formulations. In this work we demonstrate that some typical ingredients of hydraulic fracturing fluids are not as kinetically stable as one might expect. Surfactants and biocides such as sodium dodecyl sulfate and glutaraldehyde are shown to undergo hydrolysis and thermochemical sulfate reduction reactions under moderate reservoir conditions, with H2S as the final product accompanied with long chain alcohols and hydrogen sulfate as long-lived intermediate species.
This finding suggests that fracture fluid additives can be responsible for the delayed production of natural reservoir H2S. [Emphasis added]
Biocides are critical components of hydraulic fracturing (“fracking”) fluids used for unconventional shale gas development. Bacteria may cause bioclogging and inhibit gas extraction, produce toxic hydrogen sulfide, and induce corrosion leading to downhole equipment failure. The use of biocides such as glutaraldehyde and quaternary ammonium compounds has spurred a public concern and debate among regulators regarding the impact of inadvertent releases into the environment on ecosystem and human health. This work provides a critical review of the potential fate and toxicity of biocides used in hydraulic fracturing operations. We identified the following physicochemical and toxicological aspects as well as knowledge gaps that should be considered when selecting biocides: (1) uncharged species will dominate in the aqueous phase and be subject to degradation and transport whereas charged species will sorb to soils and be less bioavailable; (2) many biocides are short-lived or degradable through abiotic and biotic processes, but some may transform into more toxic or persistent compounds; (3) understanding of biocides’ fate under downhole conditions (high pressure, temperature, and salt and organic matter concentrations) is limited; (4) several biocidal alternatives exist, but high cost, high energy demands, and/or formation of disinfection byproducts limits their use. This review may serve as a guide for environmental risk assessment and identification of microbial control strategies to help develop a sustainable path for managing hydraulic fracturing fluids.
2013 Presentation by ASSOCIATION OF AMERICAN PESTICIDE CONTROL OFFICIALS no longer available online, parts of it copied below:
http://www.aapco.org/meetings/minutes/2013/apr22/att8_purdy_acc_fracking.pdf
Bacteria development is one of the main concerns in unconventional gas and oil fields / reservoirs
Water Crosses All Operator Boundaries
Long-term microbial control required
The opportunity for microbial contamination exists throughout the life cycle of a well
Importance of Treated Water in Fracing
“Slick Water” Frac
•Frac Water Volume: 4 to 6 million gallons (7.5-15MM L) per well
•Source water:
•Municipal
•Pond
•Rainwater
•River
•Recycled flow-back water
•Residue from frac tanks
Source water that makes up 99+% of the average hydraulic fracturing fluid – often contains varying concentrations of bacteria that have the potential to cause problems with the additives being used and can lead to longer term problems in the well / reservoir.
Guar gum, polyacrylamide, polymers, or other organic components are present in frac fluids can serve as food sources for bacteria.
Importance of Treated Water in Fracing
Depending on formation:
10-40% of the water pumped into the well during hydraulic fracturing returns to the surface (“flowback water”)
Most flowback in first 30 to 60 days of the life of well.
To maintain production rates over the life of a well, common practice to refrac wells (workover) one or more times, typically at 3- to 5-year intervals.
Bacterial control is required to avoid souring of the reservoir, as well as to prevent the problems associated with biofilms and Microbiologically Influenced Corrosion (MIC).
Poor Water Quality Impact (Microbial)
Can affect integrity of the wellbore and surface production equipment
Can impart H2S to the produced gas stream from biogenic souring (well souring) from SRB.
Potential to aggressively attack the metal equipment used both down hole and on surface for producing natural gas and liquids from well =
Microbiologically Influenced Corrosion (MIC) – SRB, APB, others
Effects:
Induced well damage
Plugging (Reservoir conductivity) – biofilms
Emulsion problems – biofilms
Bacteria can degrade the gels, polymers, etc.
With some biocides, MIC and reservoir souring in as little as 1-3 months
Costs:
NACE estimates total costs attributed to all types of corrosion at >$200B
MIC estimated to account for as much as 40-50% of all internal corrosion
But I am adding a biocide…..
Unconventional gas fields presents new challenges:
1.MIC due to complex water production and use
2.Fluid reuse
3.Microbial contamination
4.Treated produced water compared to conventional gas fields
When biocide treatment was applied both to the frac fluids and produced fluids handled in the surface facilities to limit MIC and reservoir souring….is that enough?
After several years of operation treatment regime was such that yearly treatment costs were above $2M / yr. to try and address problems with MIC and reservoir souring.
2011: Finding value in formation water by Schlumberger, Oilfield Review Spring 2011, 23, No. 1
Pg 27:
Formation water composition plays a role in “souring,” a process in which H2S concentration increases in the reservoir.12 In many cases, souring is attributed to microbial activity; injected seawater provides a source of sulfate-reducing bacteria (SRB) and the formation water supplies nutrients in the form of low–molecular weight organic acids known as volatile fatty acids (VFAs).
The consequences of reservoir souring are potentially costly. Increased levels of H2S increase safety risks for oilfield personnel, decrease the sales value of produced hydrocarbons and increase corrosion rates in downhole equipment and surface facilities. An estimated 70% of waterflooded reservoirs world-wide have soured.13
2011: Understanding the Souring at Bakken Oil Reservoirs
Oil field reservoir souring is defined as occurring when increasing concentrations of H2S are observed in production fluids. This is a relatively well-known problem in the contemporary oil industry. However, the identification of the source of H2S is site-specific and requires a rigorous analysis.
The general causes of souring are geomechanical (fracturing and intrusion into another formation), thermochemical (e.g., mineral dissolution), biogenic (sulfur-reducing bacteria activity), or combinations thereof.
In all cases, the causes of excessive H2S production in previously nonsour environments are primarily anthropogenic and caused by certain operational practices. [Emphasis added]
[Refer also to: