11-Asphaltenes

8/13/2019 11-Asphaltenes

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INTEC ENGINEERING INC. DEEPSTAR.

MULTIPHASE DESIGN GUIDELINE

H-0806.35 11-1 1-Dec-00

11. ASPHALTENES

11.1 Introduction

The ASTM D-3279-90 (IP143/90) test defines asphaltenes as solids that precipitate when

an excess of n-heptane or n-pentane is added to a crude oil. Chemically, asphaltenes are

high molecular weight, polynuclear aromatic, polar compounds containing carbon,

hydrogen, oxygen, nitrogen, sulphur and some heavy metals such as vanadium and

nickel. Figure 11-1 gives a representation of an asphaltene molecule; however,

asphaltenes do not have a single, unique structure or molecular weight.

Unlike waxes, asphaltenes do not melt. Consequently, thermal methods such as

insulation, hot oiling, etc. do not work to prevent or remediate asphaltene deposition.

Figure 11-1: Theoretical Asphaltene Molecule


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11.2 Operational Problems Due to Asphaltenes

Asphaltenes can deposit in reservoirs, wellbore tubing, flowlines, separators, etc. The

deposits can interrupt and potentially stop production due to the formation of plugs.

Asphaltenes are suspended by resins as micelles in the crude oil. Resins are chemically

similar to asphaltenes on one end and similar to alkanes on the other. The first step in the

deposition process is flocculation (aggregation) of molecules. The asphaltene

flocculation point is the pressure at which asphaltenes first begin to precipitate at a fixed

temperature. At this point, the resins separate from the asphaltenes. An asphaltene with

resins present is illustrated in Figure 11-2.

Figure 11-2: Asphaltene with Resin

If the resins separate from the asphaltenes, then the asphaltenes will flocculate

(aggregate). Asphaltene flocculation may be irreversible. That means if asphaltenes have

flocculated in a sample container, it may not be possible to put the asphaltenes

completely back in suspension. Sampling procedures need to be carefully designed to

preserve the original temperature and pressure conditions.


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The resins can separate from the asphaltenes for several reasons. A few of these are

highlighted below:

11.2.1 Pressure Decrease

The resins can separate from the asphaltenes as the pressure drops from reservoir

pressure to the bubble point pressure of the fluid. The pressure decreases as the produced

fluids travel up the wellbore. Asphaltene deposition stops at the point in the wellbore

where the bubble point pressure is reached. As the pressure drops from the reservoir

pressure to the bubble point pressure the resins become increasingly soluble in the liquid

phase and separate from the asphaltene micelles. Below the bubble point, the likelihood

of asphaltene deposition drops dramatically.

Figure 11-3 illustrates the process described above in a pressure and temperature diagram

showing the region where asphaltene deposition is expected.

Figure 11-3: Asphaltene Flocculation Zone as a Function of Temperature and Pressure

Asphaltene deposition can begin deep in the wellbore while the pressure is well above the

bubble point. The potential and severity of the problem can be estimated using the graph

shown in Figure 11-4.


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Figure 11-4: Asphaltene Flocculation Zone as a Function of Temperature and Pressure

The greatest potential for asphaltene deposition occurs for low in-situ crude densities

with reservoir pressures much greater than the bubble point of the fluid (Reference 1). It

is important to note that density changes do not cause asphaltene deposition but can be an

indicator of potential problems.

11.2.2 Miscible Flooding with CO2or Natural Gas.

Asphaltenes can deposit during miscible flooding. The miscible gas dissolves into the

crude and decreases the density and viscosity so that the crude oil will flow more readily.

Unfortunately, this causes the micelles to become unstable with the resins more likely to

separate from the asphaltenes, which leads to the asphaltenes flocculating.

11.2.3 During An Acidization Process

If a crude oil containing asphaltenes comes in contact with a typical acid solution during

an acidizing job, asphaltenes can flocculate in the near wellbore region. Some wells have

been seriously damaged and even unrecoverable due to asphaltene flocculation during

acidizing. If the potential for the problem is recognized ahead of time, the service

company providing the acidizing job can typically formulate an acid mixture that will

minimize the flocculation. In addition, certain operational procedures can be


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implemented as well. For example, it is possible to push a batch of diesel or xylene into

the formation ahead of the acid. This will minimize contact between the in-situ crude oil

and the acid. Also, all chemicals to be pumped into a well (including diesel and xylene)

should be tested for compatibility.

11.2.4 Mixing of Very Different Fluids

Asphaltenes can flocculate when two hydrocarbon fluids are mixed. For example, a

problem may occur when a condensate is mixed with a black oil. This can occur

wherever fluids are being commingled (i.e., in a wellbore, flowline, separator or an

export line). This problem typically occurs when fluids of very different densities (API

gravities) are mixed. For an individual oil, the resin/asphaltene micelles may be stable,

but when another fluid of a lower density (high API gravity) is added, the density of the

entire liquid phase decreases. Resins are more soluble in lower density fluids and

consequently separate from the micelles to dissolve in the hydrocarbon mixture. When

the resins separate from the micelles, the asphaltenes aggregate (flocculate). The

likelihood of the micelles destabilizing in a particular oil can be estimated using the

asphaltene titration technique with a normal alkane or by titrating it directly with the

second hydrocarbon fluid. For live conditions (such as downhole), it is possible to mix

the two fluids directly under live conditions.

11.2.5 Gas Lift

Gas lift can be either detrimental or beneficial to an asphaltene problem. If a lean gas isused as the lift gas, then the lift gas will extract some of the light ends of the crude oil

into the vapor phase. This will result in increasing the density of the remaining liquid

phase which will promote the resins remaining attached to the asphaltenes and enhance

asphaltene stability.

If a rich gas is used, some of the heavier ends of the rich gas (i.e., butane, propane,

ethane, etc.) will dissolve into the liquid phase and decrease its density. When the

density of the liquid phase decreases, the resins become more soluble in the liquid and

separate from the asphaltenes. If enough resins separate from the micelles, thenasphaltenes will begin to flocculate. This is similar to asphaltene deposition caused by a

light gas (such as CO2) dissolving in the crude oil during a miscible flood.

11.2.6 Effect of Asphaltenes on Emulsions

Asphaltenes are polar compounds, which can interact strongly with water. Because of

this interaction, asphaltenes can cause emulsion problems. The emulsions can include a


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heavy tar type substance (the asphaltenes) and can be very difficult to break. In fact, it is

possible that the first sign of an asphaltene flocculation in the production system is an

emulsion problem showing up on the platform.

Any emulsions that are particularly difficult to break and appear to have a heavy tar typesubstance should be tested for asphaltenes. If asphaltenes are found to be enriched in the

emulsion, then it should be investigated as to where the asphaltenes are actually

flocculating in the system so that any necessary remedial action can be taken to prevent a

blockage.

11.3 Prevention and Remediation

The first step to preventing and managing asphaltene deposition is to estimate when and

where asphaltenes will deposit. Armed with that knowledge, potential solutions or

remediation methods can be evaluated to determine the most cost effective options.

11.3.1 Identifying Asphaltene Problems

This section outlines the strategy in determining whether asphaltene depositional

problems are present or not for both new and existing fields.

New Field Developments

The following are the steps to take in determining if asphaltene problems exist or not.

1. de Boer plot

2. Perform laboratory asphaltene measurements.

These measurements include a precipitant titration, composition, and SARA analysis.

For these measurements (assuming that they are at atmospheric pressure), wellhead or

separator oil samples collected under standard sampling procedures are sufficient.

The details of these tests are further discussed in section 3. If different fluids are going to

be mixed, then this may require measurements on the mixed fluids as well. Keep in mindthe points listed below:

Crude oils with low asphaltene contents may be more likely to have an asphaltene

problem than those with higher contents.

Crude oils with low specific gravity and high asphaltene contents are mostly likely to

have asphaltene problems.


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Reservoirs with pressures significantly greater than the bubble point of the fluid are

more likely to have asphaltene problems.

Table 11-1 shows a comparison between the compositional make up of oils with few or

no asphaltene problems and those with severe asphaltene problems.

Table 11-1: Comparison of Properties of Crude Oil Without AsphalteneProblems to One with Asphaltene Problems

Crude with no or fewproblems

Crudes with

severe problems

Name

North Sea oil 1

North Sea oil 2North Sea oil 3

North Sea oil 4

North Sea oil 5

North Sea oil 6

Kuwait oil 1Kuwait oil 2

Kuwait oil 3

Kuwait oil 41 - C3 37 mole %

C7+ >59 mole% 3 weight %* 26 weight % 11 weight % 3 weight %*


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For asphaltene flocculation measurements, single-phase samples are required. This is

because there is some evidence that asphaltene precipitation may not be completely

reversible. That means that if asphaltenes precipitate in a sample container it may not

be possible to get all of the asphaltenes back into solution when the sample is

reconditioned to reservoir conditions. Once the intermolecular forces that stabilize

the asphaltene resin micelle is broken, the micelles may not be resolubilized in their

original configuration. For the sample to be completely representative, the oil must

be sampled and maintained as a single-phase fluid. For these types of measurements,

it is suggested that you contact the laboratory where the measurements will be

performed as well as the company performing the downhole sampling. Several

vendors supply sampling systems, which are designed to keep the sample single

phase.

4. Identify the production scenarios & flow rates over the life of the field and if and

where production fluids are mixed.

5. Model the Production System.

While a computer model (using a program such as Pipesim or Pipephase) of the

production system will be needed for other issues, it is not specifically needed for

asphaltene management.

The main area of focus with or without a model will be where the pressure falls below

the bubble point pressure. These locations (across the choke, perforations, in thetubing, etc) are areas more prone to asphaltene deposition.

6. Model for Asphaltene Deposition

Using the laboratory measurements and/or modeling results, determine the

temperature and pressure region where asphaltenes will flocculate.

Modeling asphaltene deposition is not as well understood as hydrate, scale or wax

deposition modeling. A few models exist which can predict the phase behavior (i.e.,

the conditions where asphaltenes will flocculate) and when the mixing of fluids will

result in asphaltene flocculation, but none can predict the rate of asphaltene

deposition. There are several reasons why asphaltene models are less available:

Asphaltenes are more complicated chemically and therefore more difficult to model.


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While wax, hydrates and scale formation are common operational problems,

asphaltenes problems are less prevalent; consequently less effort has been put into

development of laboratory and modeling techniques.

Laboratory measurements primarily measure conditions where asphaltenes flocculate,but rarely are able to estimate the amount of asphaltenes that deposit on pipe walls.

Less field data is available for validation of asphaltene models.

There are only a couple of commercial models available and a few companies that have

in-house models. Please contact your company's resource person for recommendations

on asphaltene modeling.

Generic information about asphaltene models

Asphaltene models are designed to predict the conditions under which the asphaltenes

flocculate. In several of the models, the theory is that a critical number of resin

molecules are required to keep the micelle stable. When the number of resin

molecules drops below the critical concentration then the micelles are no longer

stable and the asphaltenes flocculate.

The models attempt to predict the conditions where the micelles drop below the

critical resin concentration. These models always require both compositional data as

well as an estimate of the critical resin concentration from laboratory data. Inaddition it is desirable to have actual asphaltene flocculation measurements on live

samples so that the model can be tuned.

7. Identify prevention/remediation options

Those options might include one or more of the following techniques:

Mechanical

Thermal

Chemical

Novel

These techniques are further discussed in the prevention and remediation section of

this chapter.


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Existing Field Developments

The first step in determining whether asphaltene problems exist or not is to determine the

symptoms.

Typically the first sign of trouble is an increase in pressure drop or decrease in flow rate.

This may occur slowly or very rapidly. Asphaltene deposition usually occurs over a

period of time. Typically asphaltenes form in the production system at a point between

the reservoir pressure and the bubble point. Often this pressure region occurs in the

wellbore. If the problem appears to be in the wellbore, before the pressure drops below

the bubble point, or at high temperatures, then asphaltene deposition is possible. If the

system is not in the hydrate formation region or below the cloud point (WAT), then

asphaltenes are the likely culprit.

Asphaltenes can coprecipitate with wax, so it is difficult to determine which is the

problem. If the asphaltene content of the deposit is greater than 30 percent, it is probably

related to asphaltenes.

11.3.2 Mechanical Methods To Control Asphaltene Deposition

Mechanical methods can be used to periodically remove asphaltene deposits in wellbores,

flowlines and production facilities; however, asphaltenes can be more brittle and harder

to remove than typical wax deposits. Asphaltenes can also form in the near wellbore

region, which are inaccessible by mechanical methods.

Pigging

Pigs can be used to remove asphaltene deposits. However, effective removal requires the

appropriate type pig be used and that pigging be performed on a regular, frequent basis.

The pig should be specifically designed for solids removal. This typically means that a

disk or cup pig be used since they can apply much more force on the pipe wall. Spheres

or foam pigs are not adequate for asphaltene removal. In addition a bypass pig (one that

allows part of the fluid stream to go through the pig) allows the removed solids to be

dispersed into the crude oil ahead of the pig. This prevents a solid buildup in front of thepig and decreases the likelihood of sticking the pig.

Wireline Cutting

Wireline cutting is an effective means of asphaltene removal if the wellbore is readily

accessible and if the required frequency is not excessive.


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Coiled Tubing

Like wireline cutting, coiled tubing can be used to remove asphaltene deposits provided

the deposit can be reached. At this point in time, the limit of coiled tubing is about 1

mile. New technology is being tested by DeepStar to extend the reach of coiled tubing.

11.3.3 Thermal methods for Asphaltene Prevention

Asphaltene deposition is not a strong function of temperature but rather a strong function

of pressure. So, thermal methods will not alleviate asphaltene problems. Unlike wax and

hydrates, keeping the crude oil warm rarely prevents asphaltenes. Similarly asphaltene

deposits do not melt so heat alone will not remove an asphaltene deposit.

11.3.4 Chemical Methods for Asphaltene Prevention and Remediation

Asphaltene Inhibitors

Asphaltene inhibitors have been developed to prevent asphaltene flocculation. They can

be added either continuously or through a squeeze treatment. Asphaltenes occur much

less frequently than scale, hydrates and wax; consequently, not as much effort and testing

has been put into asphaltene inhibition.

Asphaltene inhibitors are polymeric dispersants, which help stabilize the micelles, which

prevents the asphaltenes from flocculating. It is believed that the inhibitors act in the

same manner as the resins interacting with the asphaltenes and stabilizing the asphaltene

micelles in the crude oil. These asphaltene inhibitors have a stronger association with the

asphaltenes than the natural resins and are able to stabilize the asphaltenes through

greater changes in pressure, temperature, shear and chemical environment.

Asphaltene inhibitors can be squeezed into the formation or continuously injected

downhole. Squeezing the inhibitor into the reservoir can prevent deposition of

asphaltenes in the near-well bore area. It is important that the asphaltene inhibitors are

added to the crude oil before the asphaltenes become destabilized and flocculation

occurs.

Asphaltene Solvents

The good news is that unlike wax, asphaltenes are very soluble in aromatic solvents such

as benzene and xylene, even at seabed temperatures. This is very fortunate since

asphaltenes can form in the near wellbore region and the only way for remediating the

formation damage is to use a squeeze treatment of an aromatic solvent.


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11.3.5 Novel Methods for Preventing Asphaltene Deposition

During the past few years several novel techniques for the prevention and mitigation of

asphaltene deposition have been investigated. The incentive for these investigations is

that current mechanical prevention and removal techniques are considered to be eitherprohibitively expensive or not reliable enough or development of fields requiring long

tie-backs or subsea completions.

Novel techniques are considered to be those technologies that are not currently in

common use or widely accepted such as magnets, vibrating quartz crystals, acoustics, and

others. At this point in time, none of the methods have been proven enough to be

recommended as primary methods of mitigation or remediation. However, coatings can

be very effective at preventing asphaltene deposition.

11.4 Laboratory Testing

11.4.1 Common Asphaltene Tests

Asphaltene Content of a Crude Oil

There is one standardized test for determining the asphaltene content of a crude oil

described by IP143/90 or ASTM D-3279-90. In this test, the asphaltenes are precipitated

using an excess of a normal alkane solvent (such as n-heptane). It should be noted that

this is the standard definition of asphaltenes (i.e., solids precipitated during this test);

however, it is very possible that compounds such as very high molecular weight n-paraffins will also be found in the solids. None of the tests are standardized and vary

from laboratory to laboratory; consequently, they are only discussed here in generalities.

It has been shown that generally crudes with low asphaltene contents (


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In addition to determining the asphaltene flocculation point for an individual fluid, it is

also possible to use this technique to determine if mixing of "live" fluids will result in an

asphaltene deposit.

Asphaltene Titration Measurements

Often there is not sufficient "live" sample to generate an asphaltene flocculation phase

envelope. Models have been developed that use stock tank oil properties to predict the

pressure and temperature region where asphaltenes will flocculate. They require that the

stock tank oil be titrated with a normal alkane such as n-pentane. The volume of alkane

necessary to induce asphaltene flocculation at a give temperature and pressure will

indicate the stability of the asphaltene content of the oil and provide the solvency number

which is a necessary input information for an asphaltene model.

Once a particular oil has been assigned a solvency number, additions of oils or

condensates will either reduce or increase this solvency number. Reducing the oil's

solvency will increase the likelihood of asphaltene flocculation. This way oils can be

classified on a common scale and the compatibility of different fluids to a pipeline

determined.

Example of Asphaltene Titration Equipment

Figures 11-5 and 11-6 show an example of an experimental apparatus used for titrating

crude oils with lighter alkane solvents (such as n-pentane) to determine the volume of

alkane necessary to induce asphaltene flocculation at a give temperature and pressure.

This will indicate the stability of the asphaltene content of the oil and provide the

solvency number, which is a necessary input information for an asphaltene model.

Typically a "live" sample is reconditioned to reservoir conditions and the sample is

slowly depressurized while observing for asphaltene flocculation. The test method may

use one of a number of techniques for detecting the asphaltene flocculation including

visual observation, light scattering, filter plugging, etc. If a number of these

measurements are made over a range of temperatures, then an asphaltene flocculation

phase envelope can be generated as shown below.

In addition to determining the asphaltene flocculation point for an individual fluid, it is

also possible to use this technique to determine if mixing of "live" fluids will result in an

asphaltene deposit.


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Figure 11-5: Asphaltene Titration Lab Equipment

Figure 11-6: Flocculometer Detection System


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Compositional Analyses

Additional compositional analyses such as high-pressure liquid chromatography (HPLC)

or gel permeation chromatography (GPC) may be required as input into an asphaltene

model. The laboratory tests necessary may be specific to the model that you will be

using should be identified early in the project during the sample planning stage. Please

contact your company's resource person to identify the asphaltene model and tests that

they recommend.

11.4.2 Asphaltene Sample Requirements

Two kinds of samples may be required for asphaltene analysis. For asphaltene

flocculation measurements, single-phase samples are required. This is because there is

some evidence that asphaltene precipitation may not be completely reversible. That

means that if asphaltenes precipitate in a sample container it may not be possible to getall of the asphaltenes back into solution when the sample is reconditioned to reservoir

conditions.

Once the intermolecular forces that stabilize the asphaltene resin micelle is broken, the

micelles may not be re-solublized in their original configuration. For the sample to be

completely representative, the oil must be sampled and maintained as a single-phase

fluid. For these types of measurements, it is suggested that you contact the laboratory

where the measurements will be performed as well as the company performing the

downhole sampling. Several vendors supply sampling systems that are designed to keepthe sample in a single phase.

For titration measurements at atmospheric pressure, wellhead or separator oil samples

collected under standard sampling procedures are sufficient.

11.5 Field Examples

"Asphaltene Deposition Due to Miscible Flooding and Use of Inhibitors" Beaverhill

Lake Unite in Canada operated by Shell Canada.

Production of the field began in 1957. In 1989, phase 1 of the field was reconfigured into

a water alternated gas (WAG 2:1) drive and was commenced in early 1990. A miscible

solvent (liquified natural gas- LNG) was used consisting of 67% ethane and 33%

methane. Almost coincident with the LNG breakthrough, problems were experienced in

several producers with downhole equipment plugging, such as ESPs and rod pumps.

Compositional analysis of the solids revealed that the problem was caused by

asphaltenes.


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Initially wells were cleaned with a commercially available aromatic solvent by means of

circulating 2 m3down the annulus and squeezing it into the reservoir. This treatment was

repeated every two weeks. These solvent squeezes were costly due to production

interruption and treatment costs.

Asphaltene inhibitors were tested in the laboratory and in the field. Effective asphaltene

control was obtained at 66 PPM inhibitor resulting in both a technically and an

economically successful trial. Prevention of asphaltene deposition was achieved through

continuous injection through a capillary string resulting in no lost production.

11.6 References

1. SPE 24987, Screening of Crude Oils for Asphalt Precipitation: Theory, Practice, and

the Selection of Inhibitors, 1992.

Additional information reference to asphaltenes can be found in Asphaltene Literature

Database, by P. Ting, G. Hirasaki, and W. Chapman, 1999 (CD-ROM from DeepStar

4200).

11-Asphaltenes

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