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Overcoming the challenges of tight/shale oil refining
Tight or shale oils are consid-ered opportunity crudes because they are typically less
expensive than crudes produced by traditional drilling methods. Processing these cheaper crudes offers today’s refiners obvious economic incentives, but they come with their own set of unique chal-lenges. Although tight and shale oils are not technically the same (shale oil is actually a subset of tight oil), for purposes of this discussion the term ‘tight oils’ will be used.
Tight oils have many physical properties in common, but the characteristics that differentiate them from one another are, in many cases, the root cause of a variety of processing challenges.
Figure 1 breaks down about 90% of US oil production over the last six years, as reported by the US Energy Information Association (EIA), and includes major produc-tion areas from both conventional and unconventional sources. Tight oils account for much of the growth in US production. This trend is expected to continue for many years, as well as expand globally. The focus of this article will be primarily on tight oils produced from the US Eagle Ford and Bakken fields, two regions with the highest production growth.
The term ‘tight oils’ is derived from the fact that the oil and gas deposits are tightly held within geological formations and are not free flowing, as the rock is very dense and not porous. Horizontal wells are used to greatly increase the well surface area exposed to hydrocarbon-rich deposits, and hydraulic fracturing is used to
The impact tight oil processing can have on a refinery, particularly the considerations that must be given to desalter performance, corrosion and fouling control
BRIAN BENOIT and JEFFREY ZURLOGE Water & Process Technologies
increase the porosity of the forma-tion and allow the hydrocarbons to flow. Production of tight oils would not be economically viable without these technologies.
The techniques used to extract tight oil supplies often result in the oil containing more production chemicals and increased solids with smaller particle size than conven-tional crudes. When introduced to the refining process, tight oils can stabilise emulsions in the desalter, increase the potential for system corrosion and fouling, as well as negatively impact waste water treatment.
Common tight oil characteristics:• Batch to batch variability• Gravity ranges 20-55°API• Low sulphur levels, but H2S can be an issue• Low levels of nitrogen• High paraffin content• Heavy metals (Ni & V) are low• Level of alkaline metals may be high
• Other contaminants (Ba, Pb) may be present• Filterable solids: greater volume and smaller particle size• Production chemicals or contaminants.
Eagle Ford and Bakken characteristicsAs previously noted, this discus-sion is primarily focused on Eagle Ford and Bakken crudes, highlight-ing characteristics they have in common, as well as those that make them unique.
Tight oil characteristics can vary greatly from batch to batch, even within the same type of crude oil supply. For example, Figure 2 is a photo of crude oil samples that were all sold as Eagle Ford crude. In addition, the range of API grav-ity for tight oils can be quite wide, from 20-55°, with most at 40° grav-ity and above.
Tight oil crudes, in general, have low nitrogen and high paraffin content. Heavy metals, such as
www.eptq.com Processing Shale Feedstocks 2014 37
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38 Processing Shale Feedstocks 2014 www.eptq.com
are not typically found in virgin crude oils. As a consequence of these dramatic variations in quality and physical properties, it is increasingly more important for refiners to be able to identify, inter-pret and respond quickly to changes in crude feed properties.
In general, today’s refiner is continually adapting to increasing variability in crude oil quality. Combine this with the blending of tight oils into the standard crude slate, and normal refinery opera-tions can be difficult to maintain. Processing these difficult blends can have a significant negative impact on overall profitability, affecting product quality, unit relia-bility and on-stream time. Determining how a new crude oil fits into a refinery operation requires a comprehensive under-standing of the physical properties and unique characteristics of that crude and how it will interact with the rest of the typical crude slate.
Figure 3 highlights tight oil distil-lation cuts compared to several common North American crudes. Note that residuum production is low compared to high volumes of gasoline and distillates. For refiner-ies that are configured for bottom-of-the-barrel upgrading, this can be a negative and limit the amount of tight oil that can be added to the crude blend. In order to balance the mix of products in the crude distillation tower to fit many refinery operations, blending tight oils with heavy asphaltic crude makes sense, as the blend can result in a desirable distillation profile for many refiners. However, this practice can also lead to compatibility issues.
Compatibility testsAlthough asphaltene stability has always played a role in crude blending, the high paraffin content of tight oils greatly increases the potential impact of asphaltene precipitation upon blending, and its negative impact on the refinery process. There are several estab-lished and developing test methods that can evaluate an oil, or a blend, for asphaltene stability.
The photos in Figure 4 show the
nickel and vanadium, are generally low, but alkaline metals (calcium, sodium and magnesium) may be high. This is highly variable as well. In addition, other contaminants such as barium and lead may be elevated. Filterable solids can be higher than conventional crude oils, with greater
volume and smaller particle size. Select samples of Bakken crude
have contained salt concentrations as high as 500 ppm, as well as non-extractable salts. Some samples of Eagle Ford crude have been shown to contain olefins or carbon-yls – both fouling precursors that
Figure 2 Tight oil variability (Eagle Ford samples)
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Figure 3 Distillation cuts: tight oils vs benchmark crudes
Initial mix Precipitation Flocculation and settling
Figure 4 Asphaltene compatibility test
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progression (from left to right) of a compatibility test performed on incompatible blends of oils that generate agglomerated asphaltenes. The initial mixing of the oils produces a homogeneous mixture. Over time, asphaltenes start to agglomerate such that they form a separate detectable phase in the fluid. Finally, significant agglomera-tion has occurred and asphaltene particulates are forming larger parti-cles. These precipitated asphaltenes contribute to fouling and can also stabilise desalter emulsions.
Another concern with tight oil handling is the potential for low temperature waxes to form. These waxes can contain very long-chain paraffins and isoparaffins, up to C-35. The subsequent formation of waxy sludge can be problematic in transportation; in storage tanks, impacting storage capacity and tank drains; as well as increasing the potential for fouling in the cold train.
Tight oils are typically low in sulphur but may, nonetheless, have high H2S (hydrogen sulphide) levels. Triazine-based H2S scaven-gers are commonly used upstream for environmental, health and safety (EHS) compliance. However, the triazine contaminates the crude and can contribute to emulsion stabilisation, amine halide salt foul-ing and under-deposit corrosion throughout the refinery. pH modifi-cation in the desalter can be very effective in removing these amines from the crude oil.
In addition to asphaltene instabil-ity, tight oils may introduce other contaminants that can adversely affect heat transfer throughout the refinery. Chemical treatment programs can effectively address many of the issues related to processing both Eagle Ford and Bakken blends, although the best treatment program for one blend may be very different from the best for the other. Critical understand-ing of the characteristics of the oils, as well as the blends being processed, is needed to properly address poor desalter performance, corrosion and fouling.
Figure 5 highlights the main areas throughout a refinery that are
impacted by the introduction of tight oils to the process, beginning at the tank farm. The presence of waxes, solids and blend compatibil-ity issues can lead to unloading problems, wax sludge build-up and tank drain plugging. Increased solids, salts and other contaminants contribute to fouling in hot and cold exchangers, furnaces and atmosphere columns.
Low yields of gasoils and resid-uum may mean that production rates of heavy ends will suffer and asphalt volumes will likely decrease. Likewise, low utilisation of heavy end upgrading and sulphur plants, due to a shortage of feed volume, can lead to turn-down limitations for these units.
Gasoline reforming can be nega-tively impacted because tight oils typically do not produce high octane products. In contrast, cata-
lytic cracking units may benefit, as tight oils make good feedstock for these operations.
In addition, the low porphyrin metal content may open up resid cracking as an option. Tight oils tend to make a bit less jet fuel, and cold flow properties of middle distillate products may change. Depending on what tight oils are blended, the cold flow properties can deteriorate or actually even improve. Since the production of both tight oil and tight gas are so closely aligned, typically as tight oil production increases, natural gas prices decease, improving fuel gas economics.
Finally, the wastewater treatment plant may experience operational difficulties when blending tight oils into the supply. High levels of solids and smaller particle size may challenge the primary waste treat-
ment equipment, which may require a redesign or a change in the chemical treatment program. Increased levels of COD, BOD and nitrogen load into the waste plant from contaminants removed in the desalter, such as solids, other contaminants and the H2S scaven-gers that are fed upstream, can place an additional load on the biological system. Also, the pres-ence of some heavy metal compounds may compromise discharge limits.
The specific challenges associated with the processing of Bakken and Eagle Ford tight oils are presented in three different sections: desalting challenges, corrosion and fouling. Practical field experiences with these crudes highlight what they have in common, as well as what sets them apart.
Crude oil desaltingDesalter performance has tradition-ally been measured by salt removal, oil dehydration and chloride control efficiency. However, the recent influx of opportunity crudes, has introduced tremendous varia-bility in the quality of the crude blends, prompting many refiners to rethink the role of the desalter. Refiners are now often running this equipment more as an extraction vessel, removing many more contaminants than just salt. While the individual desalter challenges may not be particularly new, the combination of issues is.
Compatibility problems can result from blending highly paraffinic crudes with asphaltenic crudes, which lead to asphaltene destabili-sation that can stabilise emulsions, as well as accelerate preheat and furnace fouling. Tight oils can cause wax precipitation, which can degrade desalter temperatures and plug cold train exchangers. Variability, due to raw salt and BS&W, can stabilise emulsions in the desalter, as well as impact corrosion control in the overhead system. Increased solids loading may exceed the desalter’s design capability, resulting in emulsion control issues, accelerated fouling of the preheat train and furnace, as well as more difficult phase
Tight oils can cause wax precipitation, which can degrade desalter temperatures and plug cold train exchangers
40 Processing Shale Feedstocks 2014 www.eptq.com
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Figure 5 Impact of tight oils on refinery-wide processing
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higher loadings can cause stabilised emulsions, which can lead to water carry-over in the oil and oily efflu-ent brine as well. Entrained oil in the effluent brine can cause prob-lems in the wastewater treatment plant. The solids are inorganic particles that are coated in oil. Wetting agents help strip the oil layer from the particles and make it easier for them to be removed from the desalter.
Desalter treatment programs can be combined or modified to enhance solids removal. One US Gulf Coast refiner wanted to improve solids removal to address downstream heat exchanger and furnace fouling. The modifications at the desalter included changes to the chemical program and to the operating parameters. Prior to the modifications, the desalter program had performed successfully with respect to salt removal and dehy-dration. However, Figure 6 clearly illustrates the benefit of the program modifications, with solids removal efficiencies approaching 90%.
When paraffinic tight oils are blended with asphaltenic crudes, the asphaltenes can destabilise and agglomerate, leading to emulsion stabilisation, increased oil in the effluent, as well as preheat exchanger and furnace fouling. The photos in Figure 7 illustrate the benefit of applying an adjunct chemistry, called a crude stabiliser, designed to condition the crude oil
remain in the crude and form amine hydrochloride salts in the crude tower and overhead system. They are especially troublesome when they form in the top pumpa-round sections.
Wetting agent adjunct chemistry can also be very helpful when processing tight oils. The fracking process used to extract tight oils increases the amount of entrained solids. Compared to those found in traditional crudes, these solids are smaller and the volume is typically higher as well. The increased solids loading can easily overwhelm the desalter’s ability to remove them. Loadings as high as 300 pounds per thousand barrels in the raw crude have been documented when processing certain tight oils. The
separation downstream in the primary wastewater and slop oil handling systems.
‘Tramp’ amines are defined as those amines not intentionally introduced to the crude unit for halide neutralisation. Tramp amines found in tight oil crudes are predominantly the result of triazines-based H2S scavengers. These amines can cause emulsifica-tion issues at the desalter, as well as increase the salt potential in the crude tower and overhead system. If not properly managed, severe corrosion can result when these amine salts form. Additional amines and ammonia can tax the waste treatment systems as well, due to nitrogen loading. Variable metals can cause catalyst poisoning at the FCC unit, as well as impact coke quality. As a result, GE Water & Process Technologies (GE W&PT) recommends a new paradigm with regard to treating desalters. It calls for the use of ‘multiple levers’ or select chemistries to address issues specific to a refinery site. These levers may include options such as split feed, which is primarily inject-ing the primary emulsion breaker into both the oil and the water, as well as using crude stabilisers, wetting agents, reverse emulsion breakers, amine/metals removal aids and pH modifiers.
Chemical programs have to be carefully evaluated, taking into account several considerations, including crude tank dewatering, slop system management and wash water quality. Even the make-up of the chemistry selected has to be taken into account when accessing the overall treatment program.
Application technology is another variable that can impact program performance. So, how and where chemical treatment is applied is almost as important as the selection of the chemistry itself.
Amine and ammonia removal can be improved by reducing the pH of the water and thereby help-ing more basic compounds partition into the water. There is tremendous benefit associated with removing amines at the desalter. If the amines or ammonia are not partitioned into the water, they
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42 Processing Shale Feedstocks 2014 www.eptq.com
overhead system. In some instances, overhead systems become so loaded with these amines that the traditional neutral-isers are actually turned off. Even with no neutralisers added, the pH remains well above control limits in some of these systems. The amine hydrochloride salts that form in this situation can produce corrosion rates in excess of 1000 mils per year under some conditions. Because of the concentration of the tramp amines and subsequent salt forma-tion, total system amine management is extremely critical to equipment reliability.
Figure 8 illustrates how and where these very corrosive salts might begin to form. In addition to H2S scavengers, there are several other sources of tramp amines. They can enter the system via:• Steam neutralisers • Slop oils charged back to the desalter• Sour waters used as desalter wash water • Atmospheric tower reflux streams.
Cold, wet atmospheric tower reflux streams can exacerbate this problem by recycling the various amines in the overhead system. Unless adequately purged, these recycled amines can concentrate up and lead to higher salt points and increased corrosion potential in the overhead.
Figure 9 details a deposit analysis from a failed pumparound exchanger at a US Gulf Coast refin-ery. The overhead system had experienced three corrosion-related failures within a two-year period. Prior to that time, they had not experienced an unplanned corro-sion event for decades. The results of the deposit analysis revealed that the neutraliser amine, probably from wet reflux, was the highest concentration; the second highest was the plant amine used for acid gas sweetening, coming in via the slop oil system; and the third high-est amine concentration was from MEA scavengers. The plant had previously been unaware of the amines from the MEA scavengers. The plant had maintained good desalter performance and chloride control in the overhead, yet the
and reduced use of ammonia as a primary neutraliser, the industry has witnessed a dramatic shift from traditional ICP (initial condensation point) or dew-point, corrosion mechanisms to amine salt corro-sion. Tramp amines are becoming considerably more prevalent, contributing to high pH corrosion, and increased fouling in overhead exchangers and fin fans.
Tramp amines Depending on the amine properties and concentrations, amine salts can form at, or even above, the system dew-point, making it difficult to control salt deposit-related corro-sion. In addition, when tramp amines are introduced, uncon-trolled acid neutralisation can occur and further contribute to salt build-up in the tower top and/or
and keep asphaltenes from precipi-tating. Here the adjunct chemistry is used independent of the emul-sion breaker to minimise the rag layer build-up in the desalter and to control the effluent water quality.
Corrosion and distillate maximisationIn today’s market, it is often an economic advantage to increase distillate production. Some refiners are lowering tower top tempera-tures to achieve distillate maximisation. While this will yield higher distillate production, it may also increase corrosion potential and reduce unit reliability. Corrosive salt formation and/or shifts in salt point temperatures can compromise crude unit integrity.
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Figure 8 Overhead corrosion mechanism
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represents temperature differences in degrees between the water dew points and the salt points.
The blue bars have a 10 degree difference or greater. Yellow indi-cates 0-10 degree differentials. The red bars are instances when the salt point actually fell below the water dew point in the system. Prior to December 2010, the refiner had experienced very high corrosion because of several instances when the salt point dropped below the water dew point. Recognising the impact salt point had on corrosion control, the output of the ionic equilibrium model was then used to
top temperatures have to be aware of the change in monitoring that should occur to optimise the economic benefits while managing the corrosion.
GE helped a US refiner define a new operating envelope in order to limit overhead corrosion and improve the unit’s economic balance. First, the relationship between the salt point and the water dew point was correlated using GE’s LoSalt* ionic equilib-rium model. Corrosion in the overhead was identified and quan-tified by overlaying the data. Each one of the bars in Figure 11
elevated amine concentrations increased the salt formation temperature to the point where it formed in the tower’s top pump- around section, resulting in the high corrosion rates.
Statistical salt analysis GE W&PT has developed a propri-etary technique to analyse the output data of ionic equilibrium models under different operating conditions to develop salt forma-tion curves. Ongoing amine mapping and amine speciation of the system is used to understand which amine is driving the salt point. Once the salting frequency of the system is established, custom-ised operating envelopes are developed to help maintain reliable overhead system control and increase operating flexibility.
In the following example (see Figure 10), GE helped one refiner manage atmospheric tower salt formation by generating salt point operating envelopes. These curves helped identify safe tower top operating temperatures while increasing distillate production. The lines represent MEA salt point boundaries at various tempera-tures. The data to the left or below the lines indicates that there is no salting occurring. The data to the right or above means that there is salting. Plotting the actual data with these lines can help determine the percentage of time the system is actually forming salt, depending on the system operating parameters. Since the salt point is a function of the concentration of both the acid and the base, it is imperative to manage both chlorides and amine concentrations in the overhead system to avoid forming salts and control corrosion. KPIs are then established around salt point boundaries instead of just chlorides alone, providing a more complete picture of the operation envelope needed to maintain system reliability.
With increased production of tight oils, tramp amine salt initiated corrosion is becoming more preva-lent in the industry. Refiners that are considering processing these lighter crudes or lowering tower
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Figure 10 Monoethanolamine (MEA) salting frequency
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44 Processing Shale Feedstocks 2014 www.eptq.com
Using proper characterisation methods to understand the root cause of the fouling can help deter-mine the most appropriate management strategies. When start-ing to process problematic crude blends or increasing a problematic crude type in a blend, effective baseline monitoring is extremely important to understand the status of the current system, as well as to anticipate what limitations may develop.
ConclusionIn closing, the unique challenges associated with processing tight oils can be overcome with a combi-nation of baseline and ongoing monitoring, defining and imple-menting new operating envelopes, and utilising multi-functional chemical treatment programs that provide refiners with the tools and the flexibility to address the specific process problems as they arise.
LoSalt is a mark of GE Power & Water.
Brian Benoit is the Hydrocarbon Processing Industry Leader for GE Water & Process Technologies. He provides customer technical support to the refining industry, with a principal focus on refinery best practices implementation, customer training seminars, refining technical audits and problem solving and troubleshooting. He has 24 years of experience in refinery process chemical treatment sales and support, as well as regional engineering technical support. Having spent his entire career with GE Water & Process Technologies, his areas of expertise include desalting, crude unit corrosion control, fouling control and primary wastewater treatment systems. Benoit holds a bachelor’s degree in chemical engineering from Louisiana Tech University. Email: [email protected] Zurlo is a Senior Project Manager for GE Water & Process Technologies, with 23 years of experience in process engineering, refinery treatment sales and services, hydrocarbon product applications and technical support. He currently provides global technical support to the refining industry, with a primary focus on refinery best practices, knowledge management, technology development, and alkanolamine programs. Prior to joining GE, he held various process engineering positions at Sunoco, Koch Refining, and Hercules. Zurlo holds a bachelor’s of engineering degree in chemical engineering from the Stevens Institute of Technology.Email: [email protected]
in toluene and are believed to be suspended by resins. The resins are polyaromatic compounds that are considerably lower in molecular weight than asphaltenes, and help to suspend the asphaltenes in the crude. When these resins become destabilised, such as upon heating or mixing with paraffinic crudes, agglomeration can occur in the desalter, the bulk fluid, the preheat train, or the furnace and cause foul-ing. The photos in Figure 4, mentioned earlier, show the results of a lab technique GE has devel-oped to help predict asphaltene stability. This test can be performed on-site to help determine the asphaltene precipitation potential of a specific crude or blend of crude oils, allowing refiners to better predict the behaviour of crude blends, as well as help set blending strategies.
Refiners employ many perfor-mance management strategies to reduce or mitigate equipment foul-ing, including operational and mechanical adjustments as well as anti-fouling chemistries. Some of the common operational or mechanical approaches are: reducing solids and salts by optimising desalter perfor-mance, increasing fluid velocities to minimise deposition potential, and modifying furnace flame patterns by cleaning or changing burner tips to maximise performance and mini-mise impingement that can cause coking.
Chemistries have been used successfully through the years to help reduce equipment fouling. GE recommends a multi-functional approach, tailored to the individual refinery and focused on addressing each specific issue with the most cost-effective program.
establish a new, safer operating envelope to reduce system corro-sion. Since that time, corrosion rates have been maintained at 5 mils per year or less, and the operating envelope is actively managed based on the calculated salt points as the system conditions change.
Fouling In addition to the desalting and corrosion challenges associated with processing tight oils, equip-ment fouling can be a major concern. The processing of lighter crudes, with low asphaltenes, is not typically thought of as being particularly problematic. However, there are specific issues associated with these crudes that have been identified to cause issues in the refinery process.
The cold train can experience wax precipitation, with the result-ant loss of heat transfer causing low desalter temperatures in addi-tion to increased pressure drop across the cold train heat exchang-ers. Also, increased preheat and furnace fouling potential can be experienced with these crudes due to asphaltene precipitation, metal catalysed polymerisation and/or solids deposition.
There are typically two types of fouling in the hot train and furnaces. Coke and inorganic solids are the primary culprits. The coke can result from asphaltene precipi-tation or polymerisation byproducts that fall out of the bulk fluid onto the tube surfaces and dehydrogen-ates. Metal catalysed polymerisation is somewhat rare in crude oil, but does occasionally occur due to sporadic spikes in the levels of reac-tive metals. Finally, high solids loading, common with these crudes, along with any carryover from the desalter can significantly contribute to fouling issues. Most refiners run years before fouling requires the furnace to be cleaned. Recently, some refiners have experienced as little as three months between turn-arounds to clean the crude furnace.
Asphaltenes and asphalteneprecipitationAsphaltenes are compounds that are n-heptane insoluble yet soluble
Effective baseline monitoring is extremely important to understand the status of the current system
