Understanding the microbiology of hydraulically fractured shales

April 23, 2020
The microorganisms that inhabit fractured shale formations can cause inefficiencies in production, increased costs and potential environmental damage.

In the past 10 years, there has been a dramatic increase in the production of natural gas from onshore shale reservoirs, particularly in the U.S.

Natural gas is produced by hydraulic fracturing — a combination of vertical and horizontal drilling coupled with high-pressure injection of fluid. This approach forces open fractures in the rock, allowing natural gas that was previously locked away in unconnected pores to flow freely to the surface. 

Research over the past decade has highlighted the existence of active and dynamic microbial communities in the fractured shale environment. As with conventional oil production, microbial activity can threaten the integrity of extraction infrastructure, reduce the value of the hydrocarbon, and even negatively affect total hydrocarbon yields. At the same time, microbial activity within the formation of hydrocarbon-producing fields can also have a negative impact on the environment due to the increased chemical additive demand as well as the potential contamination of downhole aquifer systems. 

This article introduces the microbiology of hydraulically fractured shales and discusses the potential for negative microbial activity during gas extraction. A number of knowledge gaps hamper our progress in diagnosing and controlling microbial activity during shale gas extraction. This is where laboratory-based reservoir simulation can help. 

Hydraulic fracturing creates new microbial habitats in the subsurface

Over the past decade, a growing number of studies have reported the presence of active, dynamic and potentially economically harmful microbial communities in the production fluids of shale gas wells. These communities vary throughout the process — with diverse and predominantly aerobic bacteria in the injected fluids and a progressively lower diversity anaerobic, salt-tolerant community becoming enriched in flowback and produced fluids. 

Despite differences in age, formation history, depth and operational parameters, geographically distinct shale gas plays across North America harbor strikingly similar microbial communities.

Freshwater injected during fracturing interacts with salts and brines in the rock, resulting in brine-level salinity in produced waters. It is this high salinity that drives the microbial community to the low diversity consortia of salt-tolerant microorganisms observed across numerous formations. These salt-tolerant microorganisms are able to persist in the extreme downhole conditions over several hundreds of days, and some remain viable long after fluids have been recovered at the surface. The drilling and hydraulic fracturing of a shale gas well therefore introduces the microorganisms, energy sources, water and physical space required for microbial life to take hold and thrive in an otherwise limited microbial habitat. 

Some microbial processes have a negative impact on shale gas extraction 

Fractured shale microbiological communities are fascinating, and studying them can shed light on microbial survival and adaptation in extreme conditions. More importantly, the microorganisms that inhabit fractured shale formations can directly cause problems for production, resulting in reduced efficiency, increased costs and the threat of environmental damage. 

Collectively termed “biofouling,” these processes include the formation of corrosive metabolic byproducts, notably sulfide and organic acids, as well as the clogging/occlusion of fractures and the emergence of biocide resistance. The dominant microorganism in fractured shale communities, Halanaerobium, is capable of several such biofouling processes. For instance, strains of Halanaerobium isolated from produced waters can grow on guar gum, the most widely used gelling agent in fracturing fluids, and can couple this metabolism with thiosulfate (an oxyanion of sulfur) reduction, producing sulfide and organic acids as byproducts. 

Sulfide is a potent corrosive agent that sours gas — a problem much harder to remediate than oilfield souring. It is also highly toxic and flammable; hence, its presence in production fluids is especially undesirable due to the potential environmental and equipment damage via increased injection chemistry demand and corrosion of production systems. Although less corrosive than sulfide, organic acids such as acetic and propionic acid — common byproducts of carbohydrate fermentation — also contribute to corrosion. 

Steel well casings and surface infrastructure are vulnerable to these microbially produced corrosive compounds, which can shorten the life span of the well, increase the risk of spillages and increase the injection chemical demand of hydraulic fractured operations. Biocides are often added in an attempt to prevent microbial growth downhole; however, fractured shale microorganisms including members of the Halanaerobium genus have been observed to withstand biocide treatment of impounded produced fluids, and its reintroduction into injection fluids may lead to earlier enrichment of these bacteria, thus increasing the likelihood of microbially influenced corrosion in production systems. 

Microbial souring in oil and gas production

Microbial souring is a well-known problem in conventional offshore oil production, and research on the subject has a long history. In oil fields, sulfate-containing seawater, injected into the reservoir during secondary recovery, provides a ready supply of energy for sulfate-reducing bacteria (SRB) to “breathe,” generating hydrogen sulfide as a byproduct. The resulting microbially influenced corrosion causes huge costs in maintenance and repairs, and the value of the sour oil decreases. Tests for the risk of souring in oil fields focus on detecting SRB, either by quantifying the presence of viable SRB in bottle tests or by quantifying the genes (commonly dsrAB) that they use to produce sulfide. Easy-to-use test kits based on these approaches are now common and have aided effective control of souring in oil production.

Sulfide production during onshore gas extraction threatens similar consequences. However, the bacteria responsible are different and not detectable using conventional oil field tests. Unlike oil reservoirs, the fluids injected into shale gas reservoirs during hydraulic fracturing are usually freshwater-based. Depending on location and access to supply, this freshwater may derive from surface sources (such as lakes or reservoirs), rainwater, or even directly from mains water supply. These water sources have low or trace amounts of sulfates. As such, the main energy source used to power SRB is lacking. Sulfate may be present in the drilling muds used prior to hydraulic fracturing, and a proportion of which may remain in formation. Previous research has identified these muds as a source of SRB and the substrates they need to grow. 

Halanaerobium: The biggest souring and corrosion threat in shale gas extraction

Although some SRB have been detected in production fluids at low abundances, the high salinity conditions that develop after fracturing appear too harsh for SRB common to oil reservoirs. Some SRB have been detected in production fluids at low abundances, but it is the dominance of Halanaerobium that poses the biggest souring and corrosion threat in shale gas extraction. This group of bacteria “breathe” using thiosulfate instead of sulfate, but still “exhale” sulfide as the end product. This bacteria group has been found to dominate the microbial signatures of produced waters from numerous gas wells in North America studied to date.

Fractured shales remain a challenge to study

While the microbial communities recovered from flowback and produced fluids are well documented, it is extremely challenging to study their activity in situ. In this respect, fractured shales are something of a black box, and a number of knowledge gaps remain. 

First, it is not known whether communities detected in fluids colonize the fractures as biofilms, which would act to reduce the total gas yields from operations by reducing fractured shale permeability. Second, while it is known that input fluid additives are used by the microbial community for growth, it is not clear what effect pressure and temperature (P/T) have on microbial metabolic processes. 

Third, the contribution of shale geochemistry to persistent microbial activity remains to be evaluated. Shales are rich in organic matter, which can potentially sustain microbial communities in fractured shales long after additives have been depleted. Shales also typically contain pyrite, which could interact with oxidizing additives such as breakers to supply the microbial community with oxidized sulfur compounds that can fuel sulfidogenesis — the generation of hydrogen sulfide by microorganisms — long into the total lifetime of a production well.

Finally, the widespread occurrence of microbial communities in production fluids, despite the common use of biocides, highlights the need to better understand biocide efficacy in situ and the emergence of resistance. Biocide resistance in shale gas wells not only poses a continued biofouling threat to shale gas production, but also contributes to the growing global antimicrobial resistance crisis — and an increased demand for injection additives that can have a negative impact on surface water quality.

Given the difficulties of accessibility and monitoring of the fractured shale environment, there is a clear need for laboratory-scale model systems. By simulating the pressure, temperature and geochemistry of the system in purpose-built bioreactors, these knowledge gaps on the extent and control of biofouling can be addressed. Differences in input fluid chemistry, biocide efficacy and contributions from the shale itself can all be assessed in a controlled way and used to inform best practices. The application of genomic analyses can highlight key biofouling pathways and develop gene-based assays, similar to SRB test kits used in oil production. Biofouling during shale gas extraction can reduce efficiency and total gas yields and necessitate costly interventions. However, through targeted laboratory-scale research, these issues can be better diagnosed and controlled, resulting in more efficient, cost-effective production with reduced environmental impact. 

Extensive research program

With the need for laboratory-scale research clearly in mind, the author, Dr. Sophie Nixon, is embarking on an extensive research program with U.K.-based Rawwater Engineering Company Limited. The research will involve using a newly designed bespoke set of pressurized bioreactors to recreate the pressure, temperature and geochemistry found in the shale gas environment to develop a greater understanding of microbial activity in shales, the impact of input fluids, the ability of shales to support microbial communities, biocide efficacy and environmental impact.

Dr. Sophie Nixon is a Natural Environment Research Council (NERC) research fellow based in the Department of Earth and Environmental Sciences at The University of Manchester (U.K.). Her research interests center on the diversity, function and adaptation of microbial life in the deep terrestrial habitats, spanning pristine and engineered subsurface environments on Earth, and the potential for life on other planetary bodies. Dr. Nixon combines high-pressure subsurface simulation with geochemistry and genomic tools to understand the role of microbiology in these extreme environments.

Author’s note: In 2015, a short NERC collaborative pressurized bioreactor study conducted by Dr. Nixon and Rawwater was used to investigate whether guar gum could support biogenic sulphide production and assess the potential for organic additives to stimulate microbial souring of shale gas. The results served as proof of concept, not only to the proposed research that forms the NERC fellowship, but also the partnership with Rawwater that underpins it.

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