SPE 165912

Organic Deposition: From Detection and Laboratory Analysis to Treatment and Removal Sima Sheykh Alian, Deleum Chemicals SdnBhd; Kulwant Singh, Deleum Chemicals Sdn Bhd; Anwarudin Saidu Mohamed, Deleum Chemicals SdnBhd ; M Zaki Ismail, PETRONAS GTS; Mona Liza Anwar ,PETRONAS GTS

Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Asia Pacific Oil & Gas Conference and Exhibitionheld in Jakarta, Indonesia, 2224 October 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any posit ion of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment o f SPE copyright.

Abstract

Organic deposition predominantly in the near well bore and in production tubing can create serious oilfield problems such as

flow restrictions, near wellbore damage, efficiency of crude processing units and etc. As the reservoir depleted over the time,

the solid deposition can lead to a steep decline in productivity of wells. The deposition of organic solids is one of many flow

assurance problems faced by operators in Malaysia. It has been observed that, after years of production, many fields in

Malaysia are suffering from organic solid deposition problem. This phenomenon is predominantly caused by changes in

temperature, pressure and composition/morphology of the crude oil over time. To perform organic deposit removal treatment

and prevention in the well, the nature of the solid should be characterized. If the deposit sample is organic mainly, it is

important to quantify the various organic fractions of the solid sample collected from the production facilities. This paper

explains how SARA analysis was modified to detect not only Macro-crystalline waxes (Saturates), asphaltene, aromatics and

resins but also micro-crystalline wax and naphthenates. The content of each of above component will affect the method of

treatment and the chemical formulation to treat the well. By knowing the composition of the solid sample along with Crudes Colloidal instability index (CII), Pour point and Wax Appearance Temperature (WAT), a customized chemical formulation

can be designed. Lab studies were performed on solid samples collected from several wells to detect the flow assurance

related issues prior to design of chemical formulation. With the analysis of the production data, history matching, and etc, a

customized chemical formulation was developed to treat the wells. The proposed chemical formulation consists of 2 specially

designed pills which would be simultaneously injected to the wellbore, which generates heat and ester once comingles. The

heat melts the deposits while the ester disperses the melted solid. The initial studies of the treatment showed promising

results; moreover the field implementation was very successful and proven significant increase in production rate. This novel

system that combines both thermal and physical energy, evidenced to work effectively for wide range of organic

compositions. Implementation of this system made it possible to restart the production from those wells which were idle due

to extensive organic deposits. This technique was also often used to rejuvenate the old wells with low production rate. This

paper discusses the diagnostic process and successful implementation of the proposed treatment in several oil wells in

Malaysia.

Introduction Deposition of organic particles during transportation, storage and processing of Crude oil is very common [1].Near wellbore

area and production tubings can suffer from serious damage due to solid deposition. Existence of solid organics along with

natural depletion can directly contribute to production decline. Organic solids caused flow assurance problem is one of the

major issues in mature fields. After many years of production natural driving forces are low. Therefore the production decline

is much expected. Probability of organic deposits in near- well bore region and in production tubing, can contribute to

production decline by causing flow constrain for reservoir fluids from wellbore to wellhead.

To address the flow assurance issues, nature of reservoir fluid and the key parameters affecting the stability of organic solids

should be well-understood .In hydrocarbon mixture, beside hydrocarbons, which are the predominant group, organic

compound of sulphur, nitrogen and oxygen and metal element consisting compound can be found [2].

2 SPE SPE-165912-MS

Petroleum constituents are classified under two major groups, volatiles (C6- fraction) and non-volatile (C6+ fraction). C6+

fraction are more complex compare to volatile group, in C6- fraction all components and even their isomers are well known

however when carbon number increases the possibility of multiple isomer combination increase too [2]. Due to this

complexity, the hydrocarbon mixtures are classified based on solubility class rather than their chemical class [3-4]. Another

reason is that: components like asphaltenes do not exist as purely identical molecules; therefore, it is more practical to define

them as a solubility class [5].

The non-volatile group is classified as paraffins (P), naphthenes (N), aromatics (A), resins (R), and asphaltenes (A).

Generally paraffins and naphthenes are reported under one group which is called saturates (S) [2]. Major oilfield problems

arise from deposition of saturates and asphaltene. The following section gives a brief overview about diagnosis of the organic

deposits.

Organic deposits diagnosis

The initial step for diagnosis and treatment of any solid deposit is to study the crude source of the sample. There are several

routine laboratory tests which are conducted on crude sample such as saturate, asphaltene , resin and aromatic (SARA)

analysis , Colloidal instability index (CII), Pour point, Wax Appearance Temperature (WAT), and rheology.

Dissolution Test

To test the nature of the sample, one of the routine tests is to examine the solubility of the sample in organic solvents, acid

and water. This is not a quantitative test however it is a helpful tool to examine the nature of the deposit sample. Samples

with predominant organic fractions are soluble in solvent while in-organic sample are dissolved in acids and clay in water.

This step is one of the initial steps to characterize the deposit sample. Since dissolution test is just an initial indication, it

should not be relied on without further analysis.

Volatility Test

To do any analysis and treatment, the volatile percentage of the sample is measured first. By heating the sample, the volatile

fraction (C6- fraction) will vaporize, remaining is the stable portion of the sample contains C6+ fraction.

SARA analysis

One method in characterizing crude oil is by separating it into smaller quantities or fractions, each of which has a different

composition from the rest. Each component would be defined based on its solubility in various solvents. Hence, the crude

oil is fractionated to four solubility classes (based on their solubility characteristics in polar and non-polar solvents). This

method, referred to collectively as SARA: saturates aromatics, resins, and asphaltenes. Saturates consist of non-polar

materials; and aromatics are more polarizable and have at least one aromatic rings [6]. Meanwhile, asphaltenes are known to

be the heaviest and the most polar fraction of petroleum. Although asphaltenes and resins are alike in molecular structure,

resins are less polar, less aromatic and have lower molar mass compared to asphaltenes [7]. SARA is performed on both

crude and solid sample.

Saturates

The petroleum wax consists of 2 primary groups: paraffin wax (C18-C36) and naphthenic hydrocarbons (C30-C60).

The difference in 2 groups is the structure of the crystals they forms, the crystal formed from paraffin waxes are

Macro-crystalline wax. Macro-crystalline waxes contain normal saturate alkanes with little iso-alkanes. This group

has the melting point of 60 C. On the other hand, microcrystalline waxes are formed from naphta. The branched-

chain paraffins are the major portion of the microcrystalline wax, however long naphthenic chains along with

Figure 1: Dissolution test with A: Acid, B: Solvent

A B

SPE SPE-165912-MS 3

aromatic paraffins play a role in crystal growth of the microcrystalline wax , their melting point reach to 90 C[8-

10]. Compare to macro-crystalline wax, microcrystalline wax has finest crystals, it is darker in colour, more viscous

and denser.

In normal SARA practice, microcrystalline wax is un-detected most of the time or reported together with saturates.

However when it comes to flow assurance, the concentration of microcrystalline wax play an important role to

design a suitable treatment, due to its distinctive structure and characteristics .

In modified version of SARA analysis, to separate the microcrystalline wax, the remaining residues on filter paper

are washed and filtered using boiling solvent; this is due to the high difference in the melting point of macro and

microcrystalline wax.

Asphaltenes

Asphaltenes are one of important solubility classes of crude oil , they are highly polar and aromatic with high

molecular weight. They are brown or black in colour (depend on the solvent used for asphaltene extraction) .Under

initial reservoir conditions Asphaltene is stable however changes in fluid composition , pressure and temperature

which happen during production life of a well ,may lead to asphaltene precipitation and deposition. Asphaltene

deposition occurs in the reservoir, wellbore, production tubing and even can lead to catalyst poisoning in refineries.

Due to complicated nature of asphaltene and complexity of asphaltene precipitation mechanism, asphaltene removal

is very expensive and has an adverse impact on the profitability of the operation .Asphaltene and wax precipitation

happen simultaneously in most cases. Wax layers are covering deposited asphaltene which makes a barrier to access

asphaltene directly. Deposited asphaltenes on tubing walls provide wax with a suitable condition to crystallize and

co-deposit [12, 13].

Resins

Resins are surface active, poly-disperse, polar and have a range of aromaticity [13]. The stability of asphaltene much

depends on resins since resins affect asphaltene aggregation and precipitation. They can, affect the quantity of

precipitation from gravimetric analysis, and decrease the size of asphaltene aggregates [14]. It is known that resins

do not precipitate themselves; normally they precipitate along with asphaltenes.

Aromatic

Aromatic compounds are common in all crude oils. They contain at least one or two aromatic rings-structures

similar to benzene.The atoms are connected by aromatic double bonds; they are polar but not as polar as asphaltene

and resins. They are mostly found in lower boiling point fractions [15]

Naphthenates

According to API Standard, naphthenic acid includes saturates with single/or multiple fused cyclo-pentane rings

with carboxyl group attached either to an aliphatic side chain or to a cyclo-aliphatic ring [16]. Although Total Acid

number is used to measure naphthenic acid of the crude ; but other factors (e.g. Dissolved H2S, dissolved CO2,

hydrolysable salts , inorganic acids , surfactant or other production chemical enhancements ), will affect the TAN

[17].

Naphthenic acid forms acid salts in presence of alkali. These salts or soaps are the results of reaction of metal

cations and naphthenates anions. In some cases, formed bound can break by acidification [18] Formation of these

salts is one of the new issues in oilfields. Known like any other deposits, naphthenates are capable of blocking the

pipelines and tubings and as a result major product drop or even production shutdown is expected. Immature, heavy

Figure 2: Macrocrystalline, Microcrystalline, and Crystal Deposit Network of Wax [8]

4 SPE SPE-165912-MS

oils with high naphthenic acid content present most naphthenates deposits problem. Besides, naphthenates deposits

are mostly observed at oil/water cut-off point, that is due to the fact that naphthenic acids and divalent (Ca2+

,

Fe2+

and Mg2+

) or monovalent (Na+, K

+) ions present in produced waters interact and lead to naphthenates deposits.

Heavy crude oils with high acid numbers mostly interact with divalent cations (i.e calcium naphthenates). On the

other hand, in light oils with low acid number the possibility of naphthenates formed with monovalent cations is

higher [19].

Naphthenates exist in crude oil have a very long chain with high molecular weight, in modified SARA analysis,

naphthenates are extracted by an organic solvent acidified with a carboxylic acid. The solution breaks the bond

between the cations and ions, so naphthenates are collected separately. After filtration of asphaltene components, the

residue on the filter paper is washed by the proper solution to extract naphthenates or after extraction of resins in

chromatography column, naphthenates are removed, if any left in the column.

Colloidal Instability Index (CII)

Normally, SARA fractions proportions in a crude oil can show the degree of stability of asphaltene. The high asphaltene content of the reservoir fluids is not the reason for asphaltene problem, but high saturate fractions may lead to asphaltene

instability [20]. In addition, it was reported that resins are responsible for asphaltene stability. When resin to asphaltene ratio

is high, there will not be any problem. However, once the ratio decreases, asphaltenes become instable and tend to aggregate

[21]. Colloidal Instability Index (CII) is another approach to identify asphaltene stability. It is the ratio of the total

asphaltenes and saturates to the total of aromatics and resins .If the value of CII is below 0.7, the crude oil is stable, but when

the CII is higher than 0.9, crude is considered unstable [22].

Wax Appearance Temperature (WAT) and Pour Point Temperature Wax appearance temperature (WAT) or cloud point is the temperature at which the first wax crystal appears. Determining

WAT is important because wax precipitates from crude oil when the operating temperature is at or below the WAT. Knowing

the WAT seems essential to treat wax deposition problems. Normally ASTM D2500: Standard Test Method for Cloud Point

of Petroleum Products is used to measure WAT [23].

According to ASTM D5853 11, the pour point of a crude oil is an index of the lowest temperature of handle -ability for certain applications. The purpose of the test is to study the cold flow behavior. This information is very essential in diagnosis

and treatment of the wax deposit problems, by knowing the pour point, proper thermo-chemical solution can be designed.

Furthermore for wax inhibitor design, pour point temperature plays an important role [24]. Both WAT and pour point are

performed on crude samples. Other routine tests for crude analysis are rheology and density measurements.

Mo

dif

ied

SA

RA

Saturates (macro-Crystalline wax )

Asphaltene

Resins

Aromatics

Naphthenates

Micro-Crystalline wax

Figure 3: Modified SARA Analysis

Ro

uti

ne S

AR

A

Mo

dif

ied

S

AR

A

SPE SPE-165912-MS 5

Organic Sample Analysis

Crude Sample Solid Sample

Organic Solid Deposit Treatment

To remove wax, asphaltene and resin; different approaches are used such as mechanical, chemical and thermal cleaning

methods. However due to several limitations, a new approach is proposed and applied in many filed with satisfactory results.

The proposed treatment is a thermo-chemical system. In this method, 2 pack system is designed to generate heat while

reacting (exothermic reaction), the generated heat is high enough to melt and dislodge the organic deposits. Besides, the

reaction between two pack systems is esterification reaction, produced ester and surfactant act as a solvent to dissolve and

disperse the deposits in a way that they remain dissolved and the possibility of re-deposition is eliminated. By using specific

additive the reaction is controlled (delayed). By delaying the reaction, heat can be used in the location of interest. The

proposed solution can be applied in oil well bore, and oil production and transportation tubings.

The 2 pack system uses organic formulations which has 2 main advantages 1. They have higher solubility for organic

deposits, 2. They are fully compatible with production system and process. The system uses a combination of heat, solvent

and surfactant to remove organic deposits more effectively. The generated heat is sufficient to dissolve and disperse the

organic deposits.

Pack 1 + Pack 2 Ester + Heat

Treatment Application

The two pack formulation can be injected in different manners: they can be simultaneously injected into the well inside the

tubing or in the well inside the flow line or pipeline. In wells where there is communication between lower part of the

production tubing and annulus, or where another tube is provided inside the production tubing, one formulation can be

injected in the production tubing and the other in the annulus. Where coil tubing unit (CTU) is used one formulation can be

injected in the coil tube and the other in the annulus between the production tubing and coil tube in bottom of the coil tube. In

all cases the generated heat from the exothermic can be carried down in the well where high accumulation of organic

deposition exists.

Prior to injection of formulation, a mixture of organic solvent (pre-flush) is injected to prepare the deposit surface for a better

reaction with the 2 pack system. When 2 pack systems are injected, it is allowed to soak for 12-24 hours, the chemical system

is carried to the affected area with another formulation called post flush. When soaking period is over, the normal production

is resumed. By doing so, the dissolved and dispersed organic deposits are carried away from the treated areas. To reach

higher temperature, one or both formulation can be heated prior to their injection.

This system is applied using a unique modular technology consisting of 3-4 small pumps. Such modular approach is most

suitable for offshore as it eliminates requirement for barge and other heavy equipment for well applications. For severe

problems for example pipeline de-clogging, a CTU may be deployed to inject the chemicals with a higher pressure force. This novel technology can be applied for cleaning the pipelines, tanks, vessels and etc.

SARA Melting point Dissolution test

SARA CII Pour Point WAT Compatibility Test TAN Free Water Content

Figure 4: Organic Sample testing

6 SPE SPE-165912-MS

Dissolution test with two pack thermo-chemical system

Before applying the 2-pack thermo-chemical system, it is necessary to perform dissolution test. The purpose of the test is to

evaluate the performance of the proposed thermo-chemical system for dissolution of the deposit sample. Initially one pack is

added to the solid sample .During the test the temperature is monitored closely, at this stage, thermometer indicates room

temperature, however after adding the second pack, temperature will rise. By adding additives, temperature rise can be

controlled from 120 to 200 C. As temperature increases, it will melt the organic deposits and at the same time, the produced

ester will disperse the deposits. The solution will be kept at room temperature to cool down. By transferring the solution to

another beaker, the flowability of the treated sample can be tested, besides another observation is to test if the sample will

solidify again at room temperature. Since the 2-pack solution acts at pour point depressant, therefore the possibility of

forming solid is very low.

Compatibility Test with two pack thermo-chemical system

If the crude oil is available, the compatibility of the chemical solution with crude can be evaluated. The possibility of forming

emulsion, solid and rags should be monitored. Several conducted studies show that applying the 2 pack system not only cause

any incompatibility, but also it is observed that after addition of the formulation and raising the temperature to 70-80 0C,

there is immediate separation of emulsified water from the crude sample.

Original Crude

Treated Crude Sample

Figure 5: Thermo-Chemical Application Method

Figure 6: Compatibility Test

SPE SPE-165912-MS 7

Case Studies

Case A

Well A is a single string oil producer which produces from 3 pay zones. From Oct 2007 onward, only one of the zones is

actively producing. Production rate declined from 1100 bopd to 600 bopd, moreover high well bore skin was observed. To

overcome the deposition problem, mechanical deposit removal was performed once in every 7 days and each job was taking

3 days at the rate of 8 hours/day. Mostly, organic deposits were found around the upper side of tubing. To perform the wax

cutting job, not only high volume of specialty chemicals was required for soaking purposes, but also mechanical cutting left

waxy fragments on the tubing surface and the improved production was not able to sustain for long period.

To formulate the treatment, crude and deposit sample was collected from the well. Modified SARA was performed to

characterize the nature of samples. Crude analysis showed the existence of micro-crystalline wax and naphthenates. Low

asphaltene content and high CII indicate the instability of asphaltene; therefore the case presents the high possibility of wax

and asphaltene precipitation. Presence of naphthenates can lead to forming a tough and stable emulsion.

Table 1: SARA Analysis for Crude sample, Well A SARA ANALYSIS

% Sample basis

Volatiles 25.8

Saturates

Macro crystalline wax (low mol. wt.) 40.70

Micro -crystalline wax (high mol. wt.) 05.26

Total Saturates 45.96

Asphaltenes (n-pentane insoluble) 01.47

Resins 09.60

Aromatics 12.40

Naphthenates 01.78

CII (colloidal instability index) 2.16

Besides crude analysis, deposit was tested too. Based on SARA results, sample is mostly consist of saturates, especially

Micro-Crystalline wax. Furthermore the high percentage of asphaltene precipitation was predicted due on high CII value. The

solid sample has high melting point (79.5 C) which can be due to high micro-crystalline wax.

Table 2: SARA Analysis for Deposit sample, Well A SARA ANALYSIS

% Sample basis

Volatiles 8.09

Saturates

Macro crystalline wax (low mol. wt.) 22.4670

Micro -crystalline wax (high mol. wt.) 38.088

Total Saturates 60.56

Asphaltenes (n-pentane insoluble) 10.68

Resins 6.11

Aromatics 8.38

Naphthenates 4.56

Based on the analysis results, well condition and production data, two pack thermo-chemical treatment systems was

proposed. High wax and asphaltene content of the deposit sample make it necessary to use a treatment which can melt and

disperse the organic deposit at the same time. Therefore the thermo-chemical treatment is the ideal solution for this case. To

confirm the performance of the treatment, dissolution test was performed. Dissolution test (solid sample with addition of

thermo-chemical solutions) showed high solvency effect while generated heat assisted to melt the sample , the temperature

was raised above the melting point therefore the organic sample was melted. Moreover the compatibility studies showed that

the formulation was completely compatible with crude oil and other well completion accessories.

The treatment was designed to be carried up to 2 ft behind the casing. Total of 52.5 bbl of chemicals was consumed; the well

test data showed 80% improvement in production. IPR showed noticeable improvement in production index (from 0.34 to

0.62). Significance of the treatment can be explained in term of financial aspect, the production was sustained for 12 months

without any mechanical cutting being required, in other word USD 100,000 was saved.

8 SPE SPE-165912-MS

Case B

Well B is consisting of three pay zones, with dual string oil producer. One of zones is produced through short string while the

other two zones are producing through the long string however Since March 2004, only one of the zones is producing

through the long string. Production declined from 2010 to 2012 production was dropped by almost 85%, and water cut

reached up to 62%.

Modified SARA analysis shows the sample is very rich in wax content. The high CII value suggests that instability of

asphaltene and high possibility of its precipitation.

Table 3: SARA Analysis for Crude sample, Well B SARA ANALYSIS

% Sample basis

Volatiles 32.40

Saturates

Macro crystalline wax (low mol. wt.) 51.38

Micro -crystalline wax (high mol. wt.) 6.876

Total Saturates 58.26

Asphaltenes (n-pentane insoluble) 4.30

Resins 15.89

Aromatics 18.43

Naphthenates 1.32

CII (colloidal instability index) 1.86

Analysis shows that the deposit sample has high wax and asphaltene content, besides the existence of naphthenates may

assist the formation of a strong emulsion. Melting point of the deposit sample is in average range (55.6C).

Table 4: SARA Analysis for Deposit sample, Well B

Like previous case two pack thermo-chemical treatment systems was found to be a suitable solution , high temperature

released during the treatment can easily melt the sample while the applied solvent can disperse the organic deposit and

provide the smooth flow. Dissolution and compatibility test were performed to test the efficiency of the treatment, results

indicated that the thermo-chemical system is effective in dissolving the deposit and also it is compatible with the crude and

completion accessories.

The application of the thermo-chemical had improved the production rate by 200 %( from 200 bopd to 600 bopd). IPR

analysis shows that the PI has increased from 0.11 to 0.40 and water cut reached to 42.4% from 61.6%.

Summary

To perform flow assurance treatment, sample analysis is very crucial to characterize the nature of the sample and formulate a suitable treatment.

When dealing with organic deposition issues, SARA analysis would be helpful in separating the sample in to different solubility fractions. Modified SARA analysis was developed to detect microcrystalline wax and

naphthenates which are overlooked in routine SARA procedure.

Treatment of deposits which contain micro-crystalline wax required higher temperature compare to macro-crystalline waxes, but thermal treatment will not be sufficient enough since asphaltenes and other organics will co

precipitate along with wax. The suitable treatment should be able to provide enough heat and as well act as a

surfactant to disperse the solid deposits.

SARA ANALYSIS

% Sample basis

Volatiles 70.94

Saturates

Macro crystalline wax (low mol. wt.) 9.4585

Micro -crystalline wax (high mol. wt.) 2.664

Total Saturates 12.12

Asphaltenes (n-pentane insoluble) 5.31

Resins 3.58

Aromatics 5.58

Naphthenates 2.19

SPE SPE-165912-MS 9

To treat the wells, pipeline and other production and processing facilities suffering from organic deposits specially wax and asphaltene, a 2 pack system was developed. The thermo-chemical system will generate heat and ester

which can melt and disperse the sample to ensure a smooth flow. The chemical formulation can be altered by adding

certain additives to generate more heat in case it is required.

The formulated chemical is highly suitable for high saturates contents (>10%), high WAT, pour point temperatures and CII of more than 0.9, besides it can act as an excellent demulsifier.

There are variety of methods for injecting the thermo-chemical system which makes it ideal for different condition and facilities. Execution of the job only requires small equipment which makes it economically feasible in offshore

environment, considering the limitations and logistic issues.

Acknowledgement The authors would like to thank Deleum Chemicals for their assistance and support. We also would like to express our

appreciation to PETRONAS for their supports and approval in publishing this work.

References

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56, 2000

[2] Asphaltenes, Heavy Oils, and Petroleomics

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http://tigger.uic.edu/~mansoori/Asphaltene.Deposition.and.Its.Control_html , 16.02.2010.

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Pacific Improved Oil Recovery Conference, Kuala Lumpur, Malaysia, 2001.

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[7] A. Rudrake, " Investigation of Asphaltene Metal Interactions," Doctor of Philosophy dissertation, Dep Chemical

Engineering, QueensUniversity, Kingston, Ontario, Canada, February 2008. [8] G.A Mansoori , Paraffin /Wax and Waxy crude . The Role of Temperature on Heavy Organics Deposition

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[12] H. K. Sarma, "Can We Ignore Asphaltene in a Gas Injection Project for Light-Oils?," in SPE International Improved

Oil Recovery, Kuala Lumpur, 2003

[13] K. J. Leontaritis, "The Asphaltene and Wax Deposition Envelopes," Fuel Science and Technology International,

Vols. 14, (No. 1 & 2), pp. 13-39, 1996.

[14] M. Sedghi and L. Goual, "Role of Resins on Asphaltene Stability," Energy Fuels, vol. 24, p. 22752280, 2012. [15] E. Y. S. O.C. Mullins, A. Hammami, and A.G. Marshall, Chapter 1 :Petroleomics and StructureFunction Relations

of Crude Oils and Asphaltenes in Asphaltenes, Heavy Oils, and Petroleomics: Springer, 2007.

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composition, Organic Geochemistry, 31, 2000 [18] Brient J. A., Wessner P. J., Doyle M. N., Naphthenic acids, 1995, in Encyclopedia of Chemical Technology Kirk-

Othmer, 4th edition, volume 16, Kroschwitz J. I (editor), John Wiley and Sons, 1017-1029

[19] Alan G. Marshall, Tallahassee; PriyankaJuyal; Mmilili M. Mapolelo ; Ryan P.Rodgers, Method For Identifying Naphthenates In A Hydrocarbon Containing Liquid , US 2010/0190260 A1 , Jul. 29, 2010.

[20] E. Rogel, O. Leon, Y. Espidel, PDVSA-INTEVEP; Y. Gonzalez, U. Metropolitana , Asphaltene Stability in Crude

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[21] G. A. Mansoori, Asphaltene Deposition and Its Control , The UIC Thermodynamic Research Labarotary, ChE & BioE Departments , University of Illionois at Chicago, 1997.

10 SPE SPE-165912-MS

[22] Andrew Yen, Y. Ralph Yin, Samuel Asomaning, "Evaluating Asphaltene Inhibitors: Laboratory Tests and Field

Studies," SPE International Symposium on Oilfield Chemistry, Houston, Texas, 2001

[23] Standard Test Method for Cloud Point of Petroleum Products, ASTM D2500 11.

[24] Standard Test Method for Pour Point of Crude Oils, ASTM D5853 11.

[25] Halim. N, Mohamad. J , Mohd. S, Misra. S, Singh.S, 2012, A method and system for removing organic

deposits,EP2459843 A1.

SPE SPE-165912-MS 11

Appendix A: CASE A

Table A1. Sample properties, well A

Case A

Wax appurtenance Temperature C (Crude) 55.4

Pour point C (Crude) 36

Melting point C (Solid ) 79.5

Figure A1: Production Trend (Case A)

Figure A2: Inflow-Outflow graph before and After Treatment (Case A)

12 SPE SPE-165912-MS

Appendix B: CASE B

Table B1: Sample properties, well A

Case B

Wax appurtenance Temperature C (Crude) 65.0

Pour point C (Crude) 65.0

Melting point C (Solid ) 55.6

Figure B1: Production Trend (Case B)

Figure A2: Inflow-Outflow graph before and After Treatment (Case A)

SPE SPE-165912-MS 13

Appendix C: Modified SARA Procedure

Soaked and filtered by C5-C7

+Maltenes feed to Chromatography Column

+ Mixture of organic solvent and Methanol

+ Organic Solvent

+Organic solvent acidified with a carboxylic acid

Resins

Aromatics Microcrystalline Wax

Naphthenates

Saturates

Crude/Solid

In-Soluble Soluble

Naphthenates

+Organic solvent acidified with a carboxylic acid

+Boiling Solvent