The complex demands of oil-and-gas production often require the development of customized chemical technologies, and CPI companies are rising to meet these challenges
The oil-and-gas and chemical process industries (CPI) are interconnected in that the oil-and-gas sector provides many of the raw materials that are the backbone for chemical manufacturing. However, the CPI also supplies many essential products for oil-and-gas production (Figure 1), from corrosion inhibitors to water-treatment chemicals and much more. As drilling and recovery technologies evolve, and market and regulatory demands place increased pressure on operators, CPI companies are developing technologies that are tailored to the needs of the oil-and-gas sector.
Adapting customized chemistries
Due to the wide variety of complex chemistries encountered across the breadth of oil-and-gas operations, Clariant AG (Muttenz, Switzerland; www.clariant.com) has been able to leverage technologies used in different specialty chemicals segments to benefit oil-and-gas producers. “Customers aren’t paying for chemistry, they are paying for problem-free production,” said Jon Rogers, global head of Clariant Oil Services at an event inaugurating upgraded blending and analytical facilities in Clinton, Okla. Rogers mentioned that Clariant has adapted specialty technologies used in the company’s pigments and personal-care product lines to create tailored solutions for oil-and-gas customers. Jonathan Wylde, head of innovation at Clariant Oil Services, further underlines this point with the example of glucamide, a sugar-based surfactant: “For instance, glucamides were originally developed for personal and homecare applications, such as dishwashing soap, hand soap and laundry detergent, and due to the superior surfactancy of this chemistry platform, applications in enhanced oil recovery were realized due to the ability of the glucamide chemistry to release oil from a rock surface.” Another example of this phenomenon includes Clariant’s adaptation of agrochemical technology into demulsifier products that lower the surface tension of oil and water, thus allowing coagulation of oil and its ultimate separation from water.
One of the most important factors in developing effective oilfield-chemical products is to understand that a user’s region and production method may bring with them very specific concerns. Clariant’s Clinton, Okla. site (Figure 2) is well suited to handle the particular production needs of shale processers in the U.S. Mid-Continental region. “This region contains a wide variety of production issues, from corrosion and scale to emulsions and paraffin. The issues are specific to each oilfield,” explains Kevin Wilson, regional laboratory manager at the Clinton site. “The high-grade instrumentation at the new laboratory allows for the efficient and accurate processing of oilfield samples,” he continues. The laboratory includes capabilities for Fourier-transform infrared spectroscopy (FTIR), as well as X-ray diffraction (XRD) and X-ray fluorescence (XRF) analyses, all in close proximity to users’ assets. Wilson cites an example where the Clinton site formulated a fit-for-purpose corrosion inhibitor that could tackle not only common corrosive agents like carbon dioxide and hydrogen sulfide, but also oxygen, relatively uncommon and difficult to treat in large quantities. “Oxygen poses a very high corrosion risk when present inside pipelines or surface production equipment. This particular customer had oxygen in their transmission lines without the ability to remove or block the oxygen contamination,” explains Wilson. The challenge was exacerbated since the amount of oxygen was too high for a traditional scavenger product, so an inhibitor to block the interaction of oxygen at the metal surface was the best option. The final inhibitor formulation included known corrosion inhibitors to target CO2 and H2S, as well as other additives to inhibit and passivate the abundant oxygen.
H2S is another troublesome species — not only is it corrosive, but it is also highly flammable and toxic. A common method for treating H2S is to use triazine scavengers, but triazine can introduce serious production issues. For instance, the high pH of triazine can cause the precipitation of calcium carbonate scale, and once the triazine is spent, it can become insoluble, creating downstream transmission issues, says Wilson. Furthermore, polymeric byproducts and amine release can create problems with corrosion, product contamination and low-temperature solidification. Clariant has developed a non-triazine-based H 2 S scavenger to address some of these concerns. “The pH of the non-triazine scavenger is closer to neutral, which prevents precipitation of pH-dependent species,” explains Wilson.
Beyond H2S scavenging, other issues plague shale production, including paraffin-containing gas streams, which can plug tubing and cause failures. “Over the last three years, the industry transitioned from the production of light, sweet, and easy-to-treat crude oil towards more complex combinations containing paraffinic components. This switch has resulted in an unprecedented increase in paraffin-related challenges,” explains Wylde. This evolution is pushing chemists to apply more advanced analytical techniques to characterize crude oil, since heavier paraffins are not detectable using traditional methods. These newer characterization methods include nuclear magnetic resonance (NMR) and matrix-assisted laser desorption/ionization time-of-flight mass spectrometry (MALDI-TOF), which can detect paraffin chains in excess of 100 carbons in length and determine a tri-modal distribution of paraffin in crude oil. “Clariant is currently undergoing work to elucidate the structural performance relationships between paraffin inhibitors and crude oils containing these higher paraffin species,” adds Wylde.
For deepwater applications, one of the major concerns is the control of gas hydrates, which are complex “ice-like” structures formed at high pressures and low temperatures that can potentially block critical subsea flow lines that otherwise would transport the hydrocarbon fluids and gases from the subsea wellheads. “Typically, gas hydrates are controlled using low-dose hydrate inhibitors that allow the uninterrupted production of oil and gas. These chemistries are required at relatively high concentrations,” says Wylde. However, he says that Clariant is developing a solution for tackling gas hydrates that works at much lower (parts per million) concentrations.
Enhancing oil recovery
Clariant’s Wylde mentions that chemical-enhanced oil recovery (CEOR) is another trending area. In CEOR, polymers are injected into an oil reservoir to increase production through the displacement of oil by injected water from the reservoir. Furthermore, surfactants can be co-injected in order to increase the sweep efficiency by lowering capillary forces in the reservoir rock and allowing otherwise trapped oil to be more effectively “washed” off the rock surface. Clariant’s Hostafrac line of products for shale CEOR features a surfactant backbone manufactured from sustainably sourced raw materials, including a sugar-based hydrophilic head and a lipophilic tail based upon coconut oil, says Wylde. Furthermore, the products are biodegradable, do not have a propensity to bio-accumulate and have been specially formulated to be free of benzene, toluene, ethylbenzene and xylenes (BTEX), as well as volatile organic compounds (VOCs).
In response to growing interest in CEOR, Kemira Oyj (Helsinki, Finland; www.kemira.com) is currently executing an expansion project in Botlek, the Netherlands to increase production capacity for polyacrylamide polymers used in CEOR, and recently signed a multiyear supply agreement with Chevron North Sea Ltd. The Botlek expansion is due to come onstream in 2019.
“Polyacrylamide flooding is a widely used CEOR method that injects water containing high-molecular-weight polyacrylamide polymers into the reservoir to improve sweep efficiency. The polymer increases the viscosity of the injection water, improving the mobility ratio between the water and the hydrocarbon trapped in the reservoir. The polymer solution migrates through the reservoir from the injection well to the producing well and ‘sweeps’ the oil in the reservoir into production,” explains Pedro Materan, senior vice president of Kemira’s global oil & gas business.
Some users may employ CEOR as a measure to improve recovery from an aging reserve once primary and secondary recovery methods have been exhausted, while others may design their fields to implement CEOR upon startup. For this reason, it is important that chemical providers are involved throughout the project lifecycle in order to tailor a solution to meet unique customer needs, considering many factors, including reservoir permeability, temperature, brine composition and oil-in-place viscosity. “Our early involvement in these projects ensures that our research and development teams can build a polymer aligned with the reservoir conditions that will deliver optimum performance when it reaches the field,” says Materan. And although laboratory analysis enables evaluation of a number of important polymer performance properties, such as filterability, viscosity, chemical and thermal tolerances and injectivity, the success of a CEOR polymer treatment goes beyond developing the chemistry in a laboratory. “The initial investment in polymer development can be lost without the correct field application,” says Materan. Kemira has developed specialized equipment for polymer dissolution and injection (Figure 3), which help to ensure that polymer integrity is maintained throughout injection and subsequent processing steps.
As operating companies are more willing to invest in polymer CEOR, Materan believes that the technology will continue to advance, enabling developers to broaden the operating range into more challenging environments, such as those with extreme temperatures or higher-salinity brines, and to better understand the longterm effects of these conditions on polymers, since they may be exposed to reservoir conditions for months or even years. “Projects previously deemed uneconomical can be revisited as viable development options. We are seeing this globally as new applications areas are being identified by existing and new CEOR operators. Newer regions, including Canada, India and South America are opening up to CEOR opportunities,” he adds.
In July, Linde LLC (Bridgewater, N.J.; www.lindeus.com) and Nissan Chemical America Corp. (Nissan Chemical; www.nissanchem-usa.com) unveiled the new Recharge HNP well-enhancement technology at the Unconventional Resources Technology Conference (URTeC) in Houston. The technology is the first to combine established gas-driven well-enhancement methods with nanoparticles. “It’s combining two chemistries that are known independently to help improve hydrocarbon recovery. We’re putting them together in downhole applications for stimulation or enhanced recovery because they work synergistically,” says Robin Watts, Chemistry & Energy program manager at Linde. Nitrogen or CO2 is used to drive Nissan Chemical’s nanoActiv HRT nanoparticles deep into a well where they can increase liquid flow by altering wettability and entering tiny fractures and pores in the formation that would otherwise be impenetrable using traditional technologies. “The nanoparticles are solid, so when you inject them downhole, they don’t work on a chemical basis, they work on a mechanical basis,” adds Watts.
Each nanoparticle is specially coated to encourage it to repel against other nanoparticles in solution, inducing Brownian motion. “Once in Brownian motion, when the nanoparticles approach a droplet attached to a surface, they will start working through disjoining pressure to release the droplet off the surface. This is very complementary to the mechanism of the injected gas to release and recover hydrocarbons,” explains Watts. She emphasizes that pumping gases like CO2 downhole with the nanoparticles synergistically helps to push the particles further into the well than previously possible, while CO2’s miscibility in downhole applications lowers viscosity and helps to introduce more hydrocarbons to the wellbore, providing hybrid benefits. “The technology is able to reach in and grab hydrocarbons that were not recovered using primary methods,” she continues. Furthermore, the technology is simple to implement in that it requires no special equipment and works very quickly. “With traditional Huff n’ Puff (HNP) enhancement processes, after injection, you must close up the well and soak it for some time, anywhere from a week to a month, and then you can start flowing back the well. With Recharge HNP, we usually only recommend 36 hours of soak time since the nanoparticles act so quickly,” mentions Watts. She emphasizes that this type of enhancement is especially important in unconventional wells where primary methods may typically recover just 3–7% of reserves.
The technology was commercially trialed with an operator’s existing horizontal wells in the Austin Chalk and Buda formations in Texas. The operator originally was considering injecting a small amount of nitrogen for secondary recovery, but the addition of nanoparticles along with gas showed promising response. This trial also showed strong correlation between the wells’ response and the treatment dosage, indicating that the solution could be tuned for specific downhole scenarios. For instance, dosage concentration can be altered for wells with extensive amounts of downhole water, and Nissan Chemical has also developed nanoparticle grades specifically for water-sensitive or high-temperature applications.
From seawater at offshore exploration sites to the water injected into hydraulic fracturing (fracking) reservoirs, handling large volumes of water is an essential part of oil-and-gas production, and invariably, this water will require some form of processing or treatment. Microbial contamination in fracking water is a major concern for operators in this sector. “When microbes grow, they form a biofilm that can plug fractures and limit hydrocarbon production, along with corroding equipment through microbially influenced corrosion. In addition to negatively impacting asset integrity and production rates, microbes also produce H 2 S, which has the potential to sour valuable hydrocarbons,” says Christina Pampena, regional marketing manager for Europe and North America for the Dow Chemical Company’s Microbial Control division (www.dowmicrobialcontrol.com).
Microbial control chemicals, such as biocides, can be applied to mitigate the growth of harmful bacteria and other microorganisms, but it is important that fracking operators understand how microbial control solutions work throughout a project’s lifecycle. According to Ken Wunch, energy technology leader at Dow Microbial Control, an effective biocide program should apply targeted combinations of chemistries to address specific site conditions during the different phases in hydraulic fracturing, from preparing the water through decontaminating the well to protecting the reservoir. For instance, initially preparing water with a quick-kill biocide like 2,2-dibromo-3-nitrilopropionamide (DBNPA) will help to cut down on the initial bioload of the water and enhance the performance of biocides used in later stages. “Designing a tailor-made microbial-control program requires technical and regulatory expertise. Countries and regions manage product regulations governing the use of biocides differently,” explains Wunch. The specific geologic conditions of a region, basin or individual formation may also dictate the optimal dosage level for each biocide, so an effective biocide program must consider factors like downhole temperature, water quality, compatibility with other fracking additives and the desired duration of control. For example, to tackle extreme environments, Dow Microbial Solutions is launching winterized versions of two of its biocide formulations that are designed to not freeze, even at temperatures as low as –40ºC. “These chemistries are especially effective in controlling slime-forming bacteria and sulfate-reducing bacteria in oil-and-gas operations,” adds Pampena.
While operators may be tempted to adopt low-cost, fast-acting microbial treatments, such as chlorine dioxide (ClO2) or tributyl tetradecyl phosphonium chloride (TTPC), Wunch suggests that applying such solutions alone may leave assets at risk for biofouling, corrosion and souring, since they will react quickly and lose efficacy downhole, as well as corrode equipment and potentially react with other completion additives, promoting the generation of toxic byproducts. Non-oxidizing biocides, such as those containing glutaraldehyde, also provide rapid control of microbes without corrosion risks, says Wunch. Furthermore, he explains, preservative biocide chemistries, such as tris(hydroxymethyl)nitromethane (THNM) or dimethyl oxazolidine (DMO), can be combined with glutaraldehydes to further enhance long term treatment efficacy if needed, since THNM and DMO’s heat stability enables them to perform effectively in a reservoir for several months.
Much work has gone into understanding the flow behavior of hydrocarbons during all phases of operations. Proppants are solid media — typically sand or ceramic particles — used to keep subsurface fractures open and aid flow. Hexion Inc. (Columbus, Ohio; www.hexion.com) has introduced an additive to address concerns with proppant flowback, which is when oil carries proppant materials out of the fracture along with oil. This phenomenon can cause fractures to shrink and can damage pumps and surface equipment. Flowback is increasingly concerning as longer lateral fracture lengths are necessitating more intense proppant injection. Also, proppants may often require specialty coatings to enhance their performance in certain applications. Earlier this year, Hexion introduced the industry’s first mobile coating plant for proppants — enabling in-basin resin coating services and improved logistics. There is no doubt that chemical technologies like proppants will continue to evolve apace with oil-and-gas production demands.
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