am-14-13 challenges and solutions for processing ... to enhance desalter operation, and present case...

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Annual Meeting

March 23-25, 2014

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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)

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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

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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

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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

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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)

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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.

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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.

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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

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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

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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.

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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.

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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

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