AM-14-13 Challenges and Solutions for Processing ... to enhance desalter operation, and present case...
Transcript of AM-14-13 Challenges and Solutions for Processing ... to enhance desalter operation, and present case...
American Fuel & Petrochemical Manufacturers 1667 K Street, NW
Suite 700
Washington, DC
20006.3896
202.457.0480 voice
202.457.0486 fax
www.afpm.org
Annual Meeting
March 23-25, 2014
Hyatt Regency Orlando
Orlando, FL
AM-14-13 Challenges and Solutions for Processing Opportunity
Crudes
Presented By:
Mike Dion
GE Water & Process
Technologies
The Woodlands, TX
This paper has been reproduced for the author or authors as a courtesy by the American Fuel & Petrochemical Manufacturers. Publication of this paper does not signify that the contents necessarily reflect the opinions of the AFPM, its officers, directors, members, or staff. Requests for authorization to quote or use the contents should be addressed directly to the author(s)
AM-14-13
P a g e | 1 ©2014, General Electric Company. All rights reserved.
Challenges and Solutions for Processing Opportunity Crudes
Abstract
The first line of defense for successful refinery crude unit corrosion and fouling control is optimal
operation of the desalter. Today’s opportunity crudes, including synthetic crudes, diluted
bitumen, diluted crude oils, and shale oils, vary greatly in terms of quality and the processing
challenges they represent. Additionally, crudes and their blends can be incompatible,
precipitating asphaltenes and high molecular weight aliphatic compounds. This precipitation
can increase the stability of emulsions and contribute to downstream fouling. Fluctuating crude
quality and compatibility issues elevate the importance and challenge to effective desalter
operation. This paper will outline some of the quality variations in crudes, describe several
methods to enhance desalter operation, and present case histories for improved desalter
operation with today’s opportunity crudes. Adopting an integrated approach to refinery
operations when processing opportunity crudes can help anticipate and negate many of the
negative impacts to downstream units, such as the waste water treatment plant, as well as
provide an opportunity to improve overall plant reliability, such as with the use of low salting
boiler amines to minimize crude unit overhead amine salt corrosion potential.
Opportunity Crude Variability
Crude oil purchasing represents ~85% of a refiner’s cost structure1 and, consequently, is a key
factor in achieving profitability goals. Opportunity crudes are those that trade at a discount,
compared to other similar crudes in the market. They therefore receive a lot of attention
because their lower cost directly impacts refinery profitability, while still allowing the refiner to
meet production goals.
In North America, shale oils currently represent one such opportunity crude. Eagle Ford is a
light sweet oil shale crude from West Texas. Samples from various LACT units (Lease
Automatic Customer Transfer unit: a collection site where custody transfer occurs) are shown in
Figure 1. As shown in the picture, Eagle Ford varies in color and paraffin content depending on
the location of the LACT unit within the oil field.
Figure 1 Eagle Ford Variation
AM-14-13
P a g e | 2 ©2014, General Electric Company. All rights reserved.
Due in part to tank storage limitations of transportation companies and the increase of
upgraders in Western Canada and Venezuela, blends of crudes are becoming more common.
Pipeline and logistic providers have finite storage capacity. Consequently, from their
perspective, utilization of storage assets is increased when crudes have less variety and are
more fungible. For example, WCS (Western Canadian Select) is a blend of various upgraded
crude streams. However, the crude seller has some flexibility in what streams to blend,
provided the final blend meets published specifications. Some parameter variations with time
are shown in Figure 2.
The blend components of the crude are usually considered proprietary. Some crudes, such as
LSB (Light Sour Blend), can include an opportunity crude, such as Bakken, as a portion of its
blend provided it meets its published assay specifications. Assay information is useful for
determining the amount of product that can be manufactured. However, it does not provide
much information on emulsification, fouling, or corrosion potential. Variations within a single
crude and variations in components of blended crudes add a high degree of complexity to
understanding the impact of processing opportunity crudes. Crude labels are losing their value
to infer, through experiential data, their processing impact. In this uncertain environment,
refiners should collaborate with their chemical supplier to better predict and address potential
processing issues.
Figure 2 WCS Variation
Source: http://www.crudemonitor.ca
AM-14-13
P a g e | 3 ©2014, General Electric Company. All rights reserved.
Crude Incompatibility
Crude oil is a complex mixture containing many compounds with a variety of structures.
Asphaltenes, high molecular weight cyclical polar compounds, are usually not soluble in crude at
a molecular level. They exist as micelles in solution. Resins, having a highly polar end with an
alkane tail, are adsorbed onto the asphaltene micelles, creating a stable colloidal solution.
Changes to pressure, temperature, and composition may affect the asphaltene-to-resin ratio of a
crude blend; depleting the compounds that help keep asphaltenes dispersed. Precipitation of
asphaltenes and high molecular weight aliphatics from these phenomena is commonly referred to
as “incompatibility” and can increase the stability of emulsions at the desalter, as well as
contribute to downstream fouling.
GE has developed a proprietary laboratory test to measure crude instability. Several
measurements are taken over a short time period at various heptane addition rates to determine
the “flocculation intensity.” The flocculation intensity is compared to a benchmark crude, known
to not have stability issues, to calculate a “relative instability number” (RIN). Measurements with
and without chemical additives allow the calculation of “relative chemical stabilization” number
(RCS). From this, a database can be populated to predict crude compatibility. An example of
GE’s proprietary crude compatibility predictive model is shown below.
Figure 3 Crude Compatibility Predictive Model
Case History
A North American refiner was experiencing issues when processing opportunity crudes. A thick,
viscous emulsion layer, due to crude incompatibility, hindered achieving desalter KPI’s.
Increasing the demulsifier injection rate was costly, with only incremental reduction in the rag
layer thickness. GE’s proprietary crude stabilizer was applied and resulted in a dramatically
reduced rag layer, thereby allowing the refiner to increase mix valve differential pressure (dP).
The increased shear enhanced salt and solids removal without processing problems related to a
AM-14-13
P a g e | 4 ©2014, General Electric Company. All rights reserved.
growing rag layer. A profile of the desalter swing-arm composition (Figure 4) highlights the
large emulsion layer and low mix valve dP prior to the introduction of GE’s crude stabilizer.
Once the crude stabilizer was employed, the emulsion layer thickness decreased and the water
level increased, allowing the refiner to increase the mix valve dP without the prior deterioration
in desalter performance.
Figure 4 Emulsion Thickness Reduction
Traditional asphaltene dispersants may contain phosphorous, calcium, or other metal impurities.
GE’s proprietary crude stabilizer is ashless, containing solely carbon, hydrogen and oxygen.
Problems associated with crude instability; which may manifest with thick viscous emulsions,
oily effluent brine, and poor salt and solids removal can be mitigated with the use of GE’s crude
stabilizers without the potential downstream risks associated with traditional chemistries which
may contain metal compounds.
Day 0.0 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 Mix Valve DP
1 0 0 0 0 0 0 1 1 1 1 3.0
2 0 0 0 0 0 0 1 1 1 1 3.0
3 0 0 0 0 0 0 1 1 1 1 3.0
4 0 0 0 0 0 0 1 1 1 1 3.0
5 2 2 0 0 0 0 1 1 1 1 3.0
6 0 0 0 0 0 0 1 1 1 1 3.0
7 0 0 0 0 0 0 1 1 1 1 3.0
8 0 0 0 0 0 0 1 1 1 1 3.0
9 2 2 2 0 0 0 1 1 1 1 2.9
10 2 2 2 2 2 0 1 1 1 1 2.0
11 2 2 2 2 2 0 0 1 1 1 2.0
12 2 2 2 2 2 0 1 1 1 1 2.0
13 2 0 0 0 0 0 1 1 1 1 2.8
14 2 2 2 2 2 0 0 1 1 1 2.5
15 2 2 2 2 2 0 0 1 1 1 2.6
16 2 0 0 0 0 0 1 1 1 1 3.6
17 0 0 0 0 0 0 1 1 1 1 3.1
18 2 2 2 2 0 0 1 1 1 1 3.0
19 2 2 2 2 0 0 1 1 1 1 3.0
20 2 2 2 2 0 0 1 1 1 1 3.0
21 2 2 2 0 0 0 1 1 1 1 3.0
22 0 0 0 0 0 0 0 1 1 1 3.0
23 2 2 2 2 2 0 0 0 1 1 3.0
24 2 2 2 2 2 2 2 2 0 0 3.0
25 2 2 2 2 2 2 2 2 0 1 3.0
26 2 2 2 2 2 2 2 0 0 1 3.0
27 2 2 2 2 2 0 0 0 0 1 7.6
28 2 2 2 2 2 2 2 0 0 1 10.2
29 2 2 2 2 2 2 2 0 0 1 13.0
30 2 2 2 2 2 2 2 0 0 1 15.3
31 2 2 2 2 2 2 0 0 0 1 12.1
32 2 2 2 2 2 0 0 0 1 1 12.0
33 2 2 2 2 2 0 0 0 1 1 12.0
34 2 2 2 2 2 0 0 0 1 1 12.0
35 2 2 2 2 2 0 0 0 1 1 11.2
2 WATER
0 EMULSION
1 OIL
Desalter Height (feet)
AM-14-13
P a g e | 5 ©2014, General Electric Company. All rights reserved.
High Metal Crudes
Some opportunity crudes contain high levels of metals. For example, DOBA crude has been
known to contain as much as ~200 ppm Calcium (Ca). These metals can be associated with
naphthenic acids, such as 2(R-COO-)Ca+2. Under normal desalter conditions, organically bound
metals are typically not extracted in the desalter effluent brine. This may contribute to metal
catalyzed fouling and catalyst poisoning, as well as jeopardize finished product specifications,
such as unacceptable metal content in anode grade coke. Chemicals can improve the
extraction of metals into the effluent brine, reducing negative downstream process concerns,
through either protonation or chelation.
Figure 5 Protonation Mechanism
GE has developed patented blends of products to incorporate both protonation and chelation
mechanisms to extract metals from metal naphthenates. However, many of these traditional
products can introduce volatile hydroxy acids. A portion of these acids will be present in the
desalted crude BS&W. Several common hydroxy acids are either volatile or will decompose
into volatile acids such as acetic or formic acid, increasing the acid loading and the risk of
corrosion in the overhead. To combat the elevated corrosion potential, higher neutralizer and
filmer dosages are usually required, which in turn, increases overall treatment costs. GE’s metal
removal program contains citric acid and consequently avoids the acid loading issues
associated with traditional chemistries. Any citric acid that is carried over in the desalted crude
will decompose to water and carbon dioxide.
While citric acid is relatively inert to the hydrocarbon phase, scaling may occur in the effluent
brine or bulk water phase of the desalter due to presence of metal-citrate salt. Scale potential is
a complicated science and will not only depend on temperature and pH, but also the ionic
strength of the solution. A conservative estimate of scale potential using distilled water is shown
below.
AM-14-13
P a g e | 6 ©2014, General Electric Company. All rights reserved.
Figure 6 Calcium Citrate Solubility
To address the scaling potential associated with the use of citric acid, a specially designed scale
inhibitor is included in GE’s metal removal product that can inhibit scale potential up to roughly
1,000 ppm of calcium in distilled water at a pH of 6.5 and a temperature of 120 oC. Additional
adjunct chemistries can be employed if needed when operating above this threshold.
Figure 7 Scale Inhibitor
From a purely protonation perspective, it would take stoichiometric amounts of citric acid to re-
protonate the naphthenate, thereby extracting the calcium into the effluent brine. With GE’s
unique program, chemical feed rates can be reduced to roughly half or less of the stoichiometric
quantity.
AM-14-13
P a g e | 7 ©2014, General Electric Company. All rights reserved.
Figure 8 Acid Blend Effectiveness
In the data above, with a DOBA blend, citric acid alone requires approximately 270 ppm to
achieve a calcium removal efficiency of 64%. At roughly half the dose, GE’s proprietary blend
achieved 53% calcium removal efficiency at an effluent brine pH of 6.6, with no detrimental
impact to water drop (WD) which correlates to emulsion resolution. The higher the water drop
the quicker the emulsion is resolved.
Extraction of metals into the effluent brine may also impact the waste water treatment plant.
The monovalent-to-divalent cation ratio (M:D) can impact the settling and dewatering in
biological treatment vessels.2 Generally, decreasing the ratio improves activated sludge effluent
quality, while increasing the ratio may increase polymer usage and costs. Extracting divalent
cations into the desalter effluent brine when processing high metal opportunity crudes should, in
theory, improve the efficiency of biological treatment facilities. However, once the crude slate is
changed to omit the high metal crude, biomass flocculation and separation may deteriorate.
Adopting an integrated approach to refinery processes can anticipate these changes and
reduce negative issues with downstream processing, not only on process side applications, but
also waste water and other utilities.
Solids
Solids, depending on their size and structure, can stabilize emulsions known as Pickering
emulsions. Solids that are not removed in the desalter may erode piping, contribute to fouling,
or poison downstream catalysts. Wetting agents are designed to improve solids removal.
Below are micrographs at 400 X magnification of raw crude, desalted crude with demulsifier,
and desalted crude with demulsifier plus a wetting agent.
Dosage
(ppm)
Water Drop
@ 32 min
Brine pH Ca removal
efficiency
(%)
Dosage
(ppm)
Water Drop
@ 32 min
Brine pH Ca removal
efficiency
(%)
Blank 7 7.8 5 Blank 7 7.2 5
136 7 5.5 21 138 7 6.6 53 ~ half stochiometric
177 6 4.4 28 176 6 5.2 61
217 6.5 4.3 46 215 7 4.5 70
272 6.5 3.9 64 292 6.8 4.1 70 Stochiometric
Citric Acid Alone GE's Proprietary Blend
AM-14-13
P a g e | 8 ©2014, General Electric Company. All rights reserved.
Figure 9 Wetting Agent Effectiveness
Case History
A North American refinery, operating a single stage chemical desalter (no electrostatic grids to
assist in emulsion resolution), was achieving ~38% filterable solids removal with a demulsifier
alone. The addition of GE’s proprietary wetting agent increased the solids removal efficiency
from an average of 38% removal to 55% removal.
Figure 10 Solids Removal Efficiency
Average Standard Deviation % in Control (>50% Target)
Pre-Wetting Agent 38.3 19.4 27.5
Post-Wetting Agent 55 6.8 87.5
Solids Removal Efficiency (%) Statistics
Chlorides
Some opportunity crudes, such as Bakken, may contain chlorides in significantly fluctuating
quantities. These chlorides may increase the hydrochloric acid loading in the overhead. While
monitoring pH and adjusting the neutralizer feed rate every 2-4 hours may be provide some
protection, the practice can also lead to either insufficient neutralization or, if the neutralizer is
overfed, higher salt points and the associated salt corrosion risk. For potentially volatile chloride
or acid loading, automating the neutralizer feed rate can help minimize corrosion and enhance
asset reliability. It should be noted that automation alone is insufficient for effective system
AM-14-13
P a g e | 9 ©2014, General Electric Company. All rights reserved.
corrosion control. The initial water condensation point, salt points, overhead water wash, and
other parameters should be considered when establishing safe operating envelopes. Once
established, amine mapping of water and crude streams can identify sources of high salting
tramp amines. Actions, such as the use of GE’s patent pending low salting boiler amine
technology, can change the safe operating envelope and improve refinery processing flexibility
without sacrificing asset reliability.
Figure 11 GE’s COMS* (Crude Overhead Monitoring System)
* Trademark of General Electric Company; may be registered in one or more countries.
AM-14-13
P a g e | 10 ©2014, General Electric Company. All rights reserved.
Figure 12
Planning Ahead
With the advent of blended crudes on the market, the ability to predict potential processing
issues has become more challenging. The installation of chemical injection systems, in advance
of processing new opportunity crudes, can accelerate the ability to quickly respond to
performance risks. Suggested chemical injection locations for the desalter are shown in the
diagram below. Collaborating with chemical suppliers to build predictive models based on the
properties of crudes rather than their label can identify likely concerns in advance and allow for
quick response to processing changes. Automating chemical feed systems, such as GE’s
COMS (Crude unit Overhead Monitoring System) for the crude unit overhead, can continuously
adjust chemical dosage in response to changes in pH and help improve processing efficiency
and plant reliability. Finally, embracing an integrated refinery operating philosophy, including
crude handling, hydrocarbon and process water treatment programs, and waste water treatment
plant operations, can enhance the reliability and profitability of the entire plant, when processing
opportunity crudes.
AM-14-13
P a g e | 11 ©2014, General Electric Company. All rights reserved.
Figure 13 Typical Chemical Injection Locations
References
1. AFPM / Refining 101 2. “The effect of cationic salt addition on the settling and dewatering properties of an industrial
activated sludge” John T. Novak, Nancy G. Love, Michelle L. Smith, Elliott R. Wheeler, Water
Environmental Research, Volume 70, Number 5. July/August 1998