2006-ST-18-eng

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Gas Conditioning Advances

XVII Gas Convention, AVPG, Caracas, Venezuela, May 23 - 25 th, 2006

SYSTEMATIC STRATEGIES FOR CHARACTERIZATION OF UNDESIRABLE

DEPOSITS IN NATURAL GAS HANDLING AND TREATMENT SYSTEMS

Miguel Orea, Lola De Lima, Jenny Bruzual, Anix Diaz

Consultores Analíticos Integrales, ChemiConsult, C.A.

Centro Comercial Tibisay, Nivel 2do piso. Ofic. SP1, SP2 y SP19 Carrizal 1203.

Estado Miranda- Venezuela

E-mail: [email protected]

Telf: (+58212) 383-8743

Fax:(+58212) 383-8740

SUMMARY

During the last decade, a remarkable increase in the frequency of appearance of

undesirable deposits in natural gas handling and treatment systems has been

observed. Such deposits correspond to solid or semisolid materials of variable

chemical composition that usually appear in almost all the stages of these

processes. The most critical cases have appeared during the production of

natural gas associated to crude oil, causing depletion of fluid flow, damages to

facilities and equipment, and increments in costs related to the corrective and

preventive procedures.

This paper shows results obtained during the assessment of twenty-five

undesirable solid deposition cases occurred in year 2005 at the main stages of

natural gas handling and treatment plants located in Venezuela, Mexico, and

Canada. The samples were classified according to the place they were found (by

stages and attacked equipment) and by their composition. The characterization

strategy was based on the integration of several analytical techniques of

separation and molecular and atomic characterization (i.e. solvent extraction,

Multidimensional Liquid Chromatography, 1H and 13C Nuclear Magnetic

mailto:[email protected]

mailto:[email protected]

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Resonance (NMR), Infrared (FT-IR), X-Ray Diffraction (XRD), Mass Spectrometry

(MS), and X-Ray Fluorescence (XRF).

The results obtained permitted identifying the stages of the natural gas production

process, the components and/or the equipments associated to them with greater

susceptibility to present deposition problems. The suitable integration of different

analytical techniques for molecular and atomic characterization allowed the

establishment of the deposit chemical compositions, their origin, and possible

promoted deposition causes.

1 INTRODUCTION

In the petroleum world, a deposit is defined as any solid or semisolid material,

originated by the formation, the precipitation or the carryover of fine-particulate

material which accumulates in preferential points of the fluid transport systems.

Solid deposition has become a serious problem in petroleum operations in

Venezuela and world-wide, it has practically existed from the beginnings of

hydrocarbon production operations. However, it has increased remarkably during

the last 5 years in the crude exploitation units[1]

as well as in those related to

natural gas production.

Deposit formation mainly occurs in flow stations related to natural gas exploitation

units[2]

and in pipe lines and equipment downstream to them. From a business

point of view, deposits formation creates an endless number of complications

ranging from production reduction to important investments for removing and

cleaning purposes. When the solid precipitations have massively occurred, the

cleaning activities oblige operators to adopt corrective measures that consist in

total or partial shutdowns of plants or affected equipments. [1]

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This negative balance has made operators to be interested in characterizing these

solids, since it is the best route to design proper cleaning and recovery treatments

that could be applied on the affected area.

The natural gas production process begins in the reservoir, where generally,

petroleum, water, and gas are accumulated. The liquid (petroleum and water) and

associated gas leave wells and arrive at the Flow Station, specifically to a manifold

or general production pipe. Then, they are passed through separator systems

where gas-liquid separation takes place. The gas emerging from the separator top

is driven to a set of purifiers where any carried over crude oil residues are

eliminated.

[3]

If the gas stream that emerges from purifiers has important concentrations of CO2

and H2S, is treated with alkanolamines in an absorption system to reduce or

eliminate the presence of these polluting agents (sweetening stage). Then, the gas

stream enters into the glycol absorption system to reduce the water content

(dehydration stage). [3]

The clean gas is pumped to Compression Plants or Miniplants where it passes

through a series of separators to eliminate liquids or condensable liquids and to

increase pressure from ± 30 psig to approximately 2800 psig. At the exit of each

stage is placed a cooler and a purifier to lower the compression temperature (±

80°F) to avoid overheat and to induce separation of some condensable fractions

from the gas bulk. Then, the outlet gas arrives to a manifold where it would be

distributed and used properly.

Until now, and according to the number of cases studied in our laboratories, none

of the natural gas handling and treatment stages have escaped from the problem

of deposit formation, so that they have been detected from the beginning of the

process (in different points of Flow Stations) until the compression, going through

sweetening and dehydration plants.

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Solid deposit formation in gas production obeys to more complex phenomena than

those observed in crude oil handling. Nonetheless, the complexity is what makes

the problem attractive for the scientific research. For this reason, the main interest

of the current work is to present our experience in the characterization of solid

deposits based on the integration of several analytical techniques such as Solvent

Extraction, Multidimensional Liquid Chromatography, 1H and 13C Nuclear Magnetic

Resonance (NMR), Infrared spectroscopy (FT-IR), Mass Spectrometry, X-Ray

Diffraction (XRD) and X-Ray Fluorescence (XRF), with the purpose of trying to

establish general mechanisms to describe the formation of these deposits during

natural gas production operations.

2 EXPERIMENTAL

2.1 Samples

The analyzed samples were collected in diverse natural gas handling and

treatment plants located in Venezuela, Mexico and Canada. Table 1 indicates the

points where deposition occurred at each stage of gas production, the date andthe location.

In order to have a better understanding of the deposition phenomena, the fluids

(crude oil, amine and glycol solutions) in contact with the solid deposit were also

analyzed.

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Table 1: Origin and sample identification

Stage Deposition Location point Sample

Date

Month/year

Geogra-phic place

Manifold 1 1

Manifold 2 2

60 psig Separator Train 1 3


1200 psig Separator Train1 5

01/05 Canada










03/05 Mexico

1200 psig purifier outlet line 15

1200 psig inlet cooler line 16

1200 psig exit line 1760 psig Separator 18

500 psig Separator 19

Handling

1200 psig Separator 20

03/05 Venezuela

Amine Regenerator 21 04/05

Amine Heat Exchanger 22Sweetening

Amine System Puma 2306/05

Canada

Gas/Glycol contactor inlet 24Dehydration

Gas/Glycol contactor outlet 2511/05 Venezuela

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2.2 Reagents

All the reagents were analytical grade. The solvents used for the separations

(chloroform, methylene chloride, n-heptane, n-hexane, toluene, and methanol)were HPLC grade provided by J,T Baker.

2.3 Procedure

2.3.1 Humidity and Organic volatile compound content

A sample portion was weighed to the nearest of 0.1 mg and dried in an oven set at

80°C until reaching constant weight. Organic volatile compounds and humidity

losses were determined by weight difference with respect to the original sample.

2.3.2 Solubility Tests

A sample portion was placed in an oven set at 80°C until reaching constant

weight. Several weighed-dry- sample portions were treated with the following

solvents: Water, n-heptane, toluene and chloroform. Tests were performed at the

boiling temperature of each solvent. After filtration, insoluble fraction was dried in

an oven at 80 °C and weighed to determine the amount of sample nondissolved.

Dissolved sample amount was calculated by subtracting the nondissolved sample

%wt. from the 100 %wt. The solubility behavior of samples in the organic

solvents allowed their classification in organic, mixed and inorganic deposits.

2.3.3 Separation Procedure

Considering the solubility behavior and the classification of the samples, a suitable

separation scheme was designed. Generally, these schemes are based on

organic solvent continuous extraction (Soxhlet) of a dry sample portion to separate

the soluble portion from the insoluble one. In all cases, the soluble portion

comprised a complex organic compound mixture. Samples that could contain

asphaltenes were refluxed with n-heptane [4] to obtain the asphaltene and maltene

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portion. Afterward, the portion of maltenes was fractionated into Saturate,

Aromatic and Resins components by means of Multidimensional HPLC

techniques [5] to close the mass balance in SARA composition.

The insoluble portion corresponded, in most cases, to inorganic material. The

presence of insoluble organic material was observed only in three cases. The

separation of the insoluble organic material from the inorganic one was performed

using the H3BO3-HF digestion procedure reported by Robl and Davis. [6] This

procedure allowed the destruction of the inorganic matrix without producing

significant alterations to the organic material.

The asphaltene fractions were obtained from the organic soluble portions by

precipitation with an excess of n-heptano following the IP-143 standard procedure.

[4] The separation of Saturate, Aromatic and Resin fractions was carried out in a

modular liquid chromatograph with a multidimensional configuration similar to that

one reported by Carbognani and co-workers.[5]

The system consisted of a silica

gel packed column (particle size 32-63 µm, Macherey-Nagel) and two columns (25

cm length and 1.0 cm i.d), packed with cyano functionalized sílica gel (Nucleoprep

100-30 CN, Macherey-Nagel), an UV-Visible detector set at 254 nm connected in

serie to a differential refractive index detector. The solvents were supplied by a

solvent delivery pump (Waters, Mod. 600). The saturated and aromatic fractions

were eluted with n-hexane at a flow of 5,0 mL/min. and 10,0 mL/min respectively.

The strong resin fraction was eluted from the cyano columns by using a mixture of

chloroform and methanol 85:15 v:v at flow of 10.0 mL/min. The weak resin

fraction was eluted with methylene chloride (10 mL / min) from the silica gel

column and mixed with the fraction of strong resins.

2.3.4 Infrared Spectroscopy Analysis (FT-IR)

Samples were analyzed as liquid film on potassium bromide (KBr) windows or as

KBr tablets. Infrared spectra were acquired in a Nicolet instrument model Magna

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750 Series II, operated at Fourier transformed mode. A spectral interval of 4000-

400 cm-1 was used with a resolution of 4 cm-1.

2.3.5 1H and 13C Nuclear Magnetic Resonance Analysis.

The spectra were acquired in a BRUKER Nuclear Magnetic Resonance

spectrometer model ACP-400. The samples were dissolved in a suitable

deuterated solvent. 1H NMR spectra were obtained with 64 free induction decays

(FID) by sample, with a 30° pulse wide at intervals of 1 second. 13C NMR spectra

were obtained with 14000 free induction decays (FID) by sample, with a 30° pulse

wide at intervals of 2 seconds.

For acquiring 13C NMR quantitative spectra, approximately 400 mg of sample were

dissolved in a solution of Cr (III) acetylacetonate / deuterated chloroform (0,01 M).

Spectra were acquired using the one pulse technique (pulse of 30º), Inverse Gated

Decoupling (IGD) to eliminate the Nuclear Overhauser effect (NOE), and a

recovery time of 5 seconds between pulses. 8000 pulses were accumulated for

each spectrum (approximately 12 hours acquisition time).

2.3.6 GC/MS Analysis

The analyses were performed in a gas chromatograph connected to a mass

detector (GC/MS CHEMStation Hewlett-Packard model 6890/5973). 1,0 µL of the

sample to be analyzed was injected keeping the injection port at 300°C. Helium

was used as carrier gas at a flow of 1,0 mL/min. A 60-meter- DB5-capillary column

with a stationary phase film thickness of 0.25 µm and 0.25 mm of internal diameter

was used. The temperature program was as follow: 50°C for 5 min., then

5°C/min., until reaching the final temperature of 280°C that stayed the same for 15

min. The total ionic chromatogram corresponding to each sample was obtained in

continuous way SCAN in the 41-to-500-Dalton-interval.

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2.3.7 X-Ray Fluorescence Analysis (XRF)

The XRF qualitative analyses of sample insoluble portions were carried out using

a Philips MagiX-Pro spectrometer, equipped with a Rhodium anode tube.

Florescence spectra were obtained under Helium atmosphere by scanning with

the LiF200 crystal from 2θ = 20° to 2 θ = 140°, followed by GE crystal from 2θ = 80°

to 2θ= 147°, and with crystal PE from 2θ = 55° to 2θ = 147°.

2.3.8 X-Ray Diffraction Analysis (XRD)

The crystalline mineral composition of samples was determined from the of x-rays

diffraction pattern of the inorganic portion components. The analyses were

performed in a Phillips x-ray diffractometer using the dust-sample-method.

Experimental measurement conditions were: 20 mA and 40 kV, using a Copper

anode as excitation source.

2.3.9 Anion Determination by Ion Exchange Chromatography.

The separation and quantification of organic and inorganic anions: HCOO -,

CH3COO-, C2O4=,OHCH2COO-, Cl-, NO3

-, SO42- y S2O3

2- SCN- were performed in a

Metrohm Ion Chromatograph model 761 Compact IC equipped with a 4,6 cmlength-75 mm-internal-diameter-Metrosep Anion Dual 2 column. 2,0 mM NaHCO3

and 1,3 mM Na2CO3 solutions were used as mobile phases at 0,6 mL/min.

3 RESULTS AND DISCUSSION

3.1 Solubility Tests: Previous step for the separation scheme design

The deposit natures play an important role for the design of the most convenient

separation and analysis routes. Generally, the application of a given separation

scheme considers the information provided by the physical inspection of the

sample, the analysis of its solubility behavior in water and in organic solvents of

low, medium and high polarities, and the estimation of humidity and volatile

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organic compound content. Table 2 shows the results obtained from solubility

tests for each sample

The information extracted from solubility tests in chloroform allows making a first

classification of samples in terms of its chemical nature. For instance, samples

displaying some material soluble in this solvent in quantities equal or greater than

80 %wt. were considered as deposits of organic nature. Samples presenting some

insoluble material in chloroform in quantities equal or superior to 80 %wt. were

considered as deposits of inorganic nature. Samples between these two ends

were considered as deposits of mixed nature. It is worthy to point out that this

classification is not absolute because in some samples exist solvent insolubleorganic material (i.e. pre-asphaltenes, coke, etc.), which is accounted too as

inorganic material. This situation could generate an incorrect sample classification

if the analyst is not able to visually detect the presence of such insoluble material.

However, the criterion of chloroform solubility used to classify samples is helpful at

the time of designing the most suitable scheme of separation. Figure 1

corresponds to a graphical representation of sample solubility behavior in this

solvent.

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Table 2. Solubility behavior of solid deposits

Sol.= Soluble; Insol. = Insoluble

Water n-Heptane Toluene ChloroformSample Sol.

%WtInsol.

%Wt.Sol.%Wt

Insol.%Wt.

Sol.%Wt

Insol.%Wt.

Sol.%Wt

Insol.%Wt.

1 0,0 100,0 37,5 62,5 67,0 33,0 67,3 32,7

2 0,0 100,0 41.1 58,9 98,3 1,7 98,4 1,6

3 0,4 99,6 37,5 62,5 95,3 4,7 96,4 3,6

4 0,3 99,7 45,8 54,2 87,1 12,9 87,9 12,1

5 0,1 99,7 41,0 59,0 96,9 3,1 97,7 2,3

6 1,1 98,9 1,5 98,5 1,4 98,6 1,6 98,4

7 0,0 100,0 1,0 99,0 1,0 99,0 1,2 98,8

8 0,0 100,0 3,4 96,6 3,9 96,1 4,0 96,0

9 0,2 99,8 12,0 88,0 13,0 87,0 13,2 86,8

10 0,5 99,5 21,6 78,4 29,4 70,6 29,8 70,2

11 0,2 99,8 1,0 99,0 1,0 99,0 1,0 99,0

12 0,0 100,0 1,0 99,0 1,1 98,9 1,1 98,9

13 0,0 100,0 2,0 98,0 2,9 97,1 3,0 97,0

14 0,0 100,0 1,2 98,8 1,3 98,7 1,3 98,7

15 0,0 100,0 11,1 88.9 11,0 89,0 11,3 88,7

16 0,0 100,0 6,1 93,9 8,9 91,1 9,2 90,8

17 0,0 100,0 23,1 76,9 31,3 68,7 31,3 68,7

18 0,1 99,9 3,0 97,0 3,5 96,5 3,9 96,119 0,1 99,9 3,9 96,1 4,8 95,2 4,8 95,2

20 0,3 99,7 16,4 83,6 22,8 77,2 23,2 76,8

21 0,0 100,0 0,1 99,9 0,1 99,9 0,2 99,8

22 8,8 91,2 1,5 98,5 3,7 96,3 6,6 93,4

23 61,2 38,8 3,4 96,6 14,4 85,6 20,0 80,0

24 44,8 55,2 16,0 84,0 16,4 83,6 19,0 81,0

25 35,4 64,6 12,4 87,6 17,3 82,7 21,2 78,8

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Figure 1 Classification of deposit samples according to their solubility in Chloroform

As it can be observed, organic and inorganic deposits are located in the ends of

the curve, whereas the mixed deposits are located in the center of this one.

Figure 2 corresponds to a graphical representation of the relationship: Y = [ (nC-7

Insol %wt. /(Toluene Insol. %wt.) ] as a function of Toluene insoluble %wt. In order

to interpret these results, it is necessary to consider the solubility behavior of the

asphaltene family, who is defined operationally as the portion of crude oil that is

insoluble in alkane solvents like n-pentane or n-heptano and soluble in aromatics

solvents like toluene. [7]

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Figure 2. Relationship Y = [ (nC-7 Insol %wt. /(Toluene Insol. %wt.) ] as a function of

Toluene insoluble %wt.

For those samples that did not present insoluble material in n-heptane

(asphaltenes), the amount of soluble organic material in this solvent was very near

the amount that dissolves in toluene (Table 2). This means that the amount of

insoluble material in both solvents is very similar, and consequently the

relationship (n-C7 Insol. %wt.)/(Toluene Insol. %wt.) is approximately equal to

unity ( Y ≈ 1), as it is observed in Figure 2 for a significant group of samples. On

the other hand, those samples with a value of Y greater than 1 displayed

appreciable amounts of insoluble material in n-heptane that could correspond to

possible asphaltenic material.

These results, like the previous ones, serve as a base to design the more

appropriate separation scheme, since they suggest the inclusion of a n-heptane

precipitation step to isolate the insoluble asphaltenic material from the maltenic

portion in those samples with Y values higher than one. In the same way, the

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solubility behavior in water provides the suitable criterion to include a water

extraction stage in the separation scheme.

In summary, the information provided by solubility tests and the graphs of Figures

1 and 2 turns out useful to establish a first classification of the samples, to obtain

an estimation of the organic and inorganic material distribution (or inorganic+

insoluble organic) and to detect the presence of possible asphaltenic material. In

addition, it allows designing an optimal separation scheme based on the yields of

each portion and the maximum sample fractionation, with the unique purpose of

simplifying the spectroscopic characterization task.

3.2 Design of the separation scheme

In previous paragraphs it has been emphasized that samples have particular

characteristics that make applied separation procedures to be specific for each of

them. Considering the physical aspect and the solubility test results, the most

appropriate separation and characterization schemes were designed. By this way,

the separation of a deposit sample was conceived in two stages: a separation inorganic media followed by a separation in aqueous media. Organic extraction

implied the use of polar solvents like chloroform or toluene, Afterward; the residue

was further extracted with water only when samples presented appreciable

quantities of components soluble in this solvent. Depending on the sample nature

and on the amount available, the obtained organic extract was treated with n-

heptane to separate the asphaltenic and maltenic portions. Subsequently,

maltenic portion was separated into SAR (saturates, aromatics and resins) type

compound families by means of multidimensional HPLC technique.

In some cases, the insoluble portion resulting from the organic solvent extraction

was accompanied by an insoluble organic material. In order to estimate its

content, the insoluble portion was acid digested with H3BO3-HF to destroy the

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inorganic compounds without altering the organic components. [6] Figure 3

represents a global separation scheme that summarizes procedures used to

fractionate the deposit samples, as well as the conducted analyses for each

fraction. Separation steps framed in doted lines were optional and their application

depended, as we already said, on the sample nature

It is worthy to mention that continuous Soxhlet extraction technique was use in the

extraction steps. Despite of being time consuming, this technique has the

advantage of assuring a complete extraction and conserving the integrity of the

sample, as well as being economic. [8]

Figure 3. Global separation scheme for solid deposit samples

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After sample separation, the following step consisted in characterizing of the

obtained fractions. Table 3 summarizes results from the composicional analysis.

As can be seen, samples display a variant composition. In all the cases the

presence of water, volatile hydrocarbons and insoluble material were detected. In

most all cases, the presence of SARA type hydrocarbon was also observed, but

their relative contents do not follow any specific pattern. However, the detailed

analysis of the data allowed coming up with interesting conclusions: Of the 25

evaluated cases, the 80% appeared at the natural gas handling stage, 12%

occurred at the sweetening facilities and the 8% was detected at the dehydration

step. Below, the spectroscopic characterization findings are discussed.

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3.3 Natural Gas handling

At the stage of natural gas handling, 75% of the cases occurred in the separators,

15% in pipes lines and rest 10% at the manifold level.

In this stage, all the deposition cases displayed appreciable amounts of inorganic

material. The FT-IR, XRF, and XRD analyses performed on the Inorganic material

showed that it was a mixture of silicates and aluminosilicates with small amounts

of clay. As example, Figures 4, 5, 6 and 7 depict spectra corresponding to sample

number 6.

64

66

68

70

72

74

76

78

80

82

84

86

88

90

92

94

96

98

100

% T r a

n s m i t t a n c e

5001000150020002500300035004000

Wavenumbers (cm-1)

H 2

OH 2

Oν SiO-H

ν Si-O

δ Si-O-Si

δ SiO4

δ NO3-

64

66

68

70

72

74

76

78

80

82

84

86

88

90

92

94

96

98

100

% T r a

n s m i t t a n c e

5001000150020002500300035004000

Wavenumbers (cm-1)

H 2

OH 2

Oν SiO-H

ν Si-O

δ Si-O-Si

δ SiO4

δ NO3-

Figure 4. FT- IR Spectrum Corresponding to the Inorganic Portion of Sample number 6.

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Figure 5 XRF Spectra corresponding to the Inorganic Portion of sample Number 6.

LiF200 Crystal and GE Crystal.

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Figure 6 XRF Spectra corresponding to the Inorganic Portion of sample number 6. PECrystal and PX1 Crystal.

Figure 7. Diffractogram of the number 6 Inorganic Portion sample

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Only the 33.3 % of the deposits found in separators shown an appreciable content

of asphaltenes oscillating between 4,0 and 50 %wt. The two samples collected in

the manifold (samples No.1 and 2) also presented higher contents of asphaltenes.

Altogether, the 30% of the cases detected in the natural gas handling stage was

related to asphaltene deposition problems.

Recently it has been demonstrated that precipitated asphaltenes by well pressure

depletion are different from asphaltenes isolated from the crude oils by solvent

precipitation. Carbognani [9] has shown that asphaltenes found in solid deposits

are more aromatic and display higher molecular weight and greater polarity than

asphaltenes from the crude oil in contact with the solid deposit. In such sense, 13C

nuclear magnetic resonance technique claims to provide quantitative information

about the distribution of carbon type (aromatic carbon and aliphatic carbon) in

SARA fractions. Indeed, results of the 13C NMR analysis showed that the

asphaltenic fraction belonging to solid deposits were more aromatic than the

asphaltenes precipitated from the crude oil contacting them. Results indicated an

appreciable difference in the distribution of aromatic and aliphatic carbon. This

pattern was the same found by Carbognani and coworkers for the aromaticity

factor f (a)=(Caromatic/Ctotal).[9] Table 4 summarizes results of f (a) determined from the

13C NMR spectra of asphaltenes isolated from samples 1, 2, 3, 4, 5, 10, and 20

and the corresponding crude oils. Figure 8 depicts the 13C NMR spectra of

asphaltene fractions precipitated from sample number 3 and from the crude oil in

contact with it.

Table 4 Aromaticity factor of solid deposit and crude oil asphaltene fractions

Aromaticity Factor de (f (a)Sample No

Deposit Crude oil

1 0,634 0,556

2 0,686 0,506

3 0,628 0,527

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4 0,604 0,498

5 0,532 0,400

10 0,613 0,476

20 0,598 0,501

The fact of finding asphaltenes in these samples indicates that the deposition

mechanism is a combination of asphaltene flocculation phenomena with problems

related to finely solid particle carry over from nonconsolidated sands or fractured

formations.[10]

Several authors have reported that the presence of mineral matter

in petroleum fluid promotes the aggregation and precipitation of highly aromatic

asphaltenes, specially those minerals that contain appreciable amounts of iron

(clays). [11-12] Thus, the characterization of the asphaltenic fraction becomes of

extreme importance to control the flocculation phenomenon, because the chemical

composition and the structure of this fraction have a great impact on the behavior

of the commonly used asphaltene dispersant and asphaltene precipitation inhibitor

agents. [13]

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Figure 8.13

C NMR Spectra of asphaltene fractions isolated from sample number 3 and from the

crude oil in contact with it.

The characterization by GC-MS of the saturate and aromatic fractions separated

from samples with important asphaltene contents showed an enrichment of high

molecular weight paraffins (between C15-C38 ) and polycondensates aromatic

hydrocarbons. It is possible that these compounds, along with the resins, were

occluded within the asphaltenic matrix when precipitation took place.[14]

Saturate

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and Aromatic compound distributions in sample number 3 appear in Figures 9 and

10.

Figure 9 Characteristic m/z 57 Fragmentogram of alkanes detected in the saturated

fraction isolated from sample number 3.

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H CH3

C2H

5C

3H

7R =R H CH

3C

2H

5C

3H

7R = H CH

3C

2H

5C

3H

7R =R C

4H

9C H C

5H

11C HH CH

3C

2H

5C

3H

7R = H CH

3C

2H

5C

3H

7R =RR H CH

3C

2H

5C

3H

7R = H CH

3C

2H

5C

3H

7R =R C

4H

9C H C

5H

11C H

Tiempo (min.)

Abundancia

Ion 178.00

Ion 192.00

Ion 206.00

Ion 220.00

Ion 234.00

Ion 248.00

28.00 29.00 30.00 31.00 32.00 33.00 34.000

50000100000150000200000250000300000350000400000450000500000550000

600000650000700000750000800000

Tiempo (min.)

Abundancia

Ion 178.00

Ion 192.00

Ion 206.00

Ion 220.00

Ion 234.00

Ion 248.00

28.00 29.00 30.00 31.00 32.00 33.00 34.000

50000100000150000200000250000300000350000400000450000500000550000

600000650000700000750000800000

H CH3

C2H

5C

3H

7R =R H CH

3C

2H

5C

3H

7R = H CH

3C

2H

5C

3H

7R =R

Tiempo (min.)

Abundancia

Ion 228.00

Ion 242.00

Ion 256.00

Ion 270.00

34.00 35.00 36.00 37.00 38.00 39.00 40.00

10000

20000

30000

40000

50000

60000

70000

80000

90000100000

110000

H CH3

C2H

5C

3H

7R =R H CH

3C

2H

5C

3H

7R = H CH

3C

2H

5C

3H

7R =R

Tiempo (min.)

Abundancia

Ion 228.00

Ion 242.00

Ion 256.00

Ion 270.00

34.00 35.00 36.00 37.00 38.00 39.00 40.00

10000

20000

30000

40000

50000

60000

70000

80000

90000100000

110000

Tiempo (min.)

Abundancia

Ion 228.00

Ion 242.00

Ion 256.00

Ion 270.00

34.00 35.00 36.00 37.00 38.00 39.00 40.00

10000

20000

30000

40000

50000

60000

70000

80000

90000100000

110000

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Tiempo (min.)

Abundancia

Ion 252.00

Ion 266.00

Ion 280.00

RH CH3 C2H5R = H CH3 C2H5R =

39.50 40.00 40.50 41.00 41.50 42.00 42.50 43.003000400050006000700080009000

100001100012000

130001400015000160001700018000

Tiempo (min.)

Abundancia

Ion 252.00

Ion 266.00

Ion 280.00



39.50 40.00 40.50 41.00 41.50 42.00 42.50 43.003000400050006000700080009000

100001100012000

130001400015000160001700018000

Figure 10. Some identified aromatic hydrocarbons in the aromatic fraction isolated fromsample number 3.

3.4 Natural Gas Sweetening

One of the most common operations in the crude oil and petrochemical industry is

the sweetening of acid gaseous streams. The objective of the process is to

effectively remove, in a economic way, the acid gases (H2S and CO2) that arepresented in the gas bulk. Systems commonly use Monoethanolamine (MEA),

Diethanolamine (DEA) or Methyldiethanolamine (MDEA) solutions to absorb acid

gases. In the present work we analyzed solid deposit in contact with DEA

solutions.

According to our records, deposition in natural gas sweetening covered the 15% of

all the cases evaluated. Additionally, one hundred percent of samples studied

presented an inorganic portion composed by oxides and iron sulfides. Elementary

sulfur was detected in two of the samples.

In agreement with FT-IR, XRF and XRD results the main compounds found in the

sample’s inorganic portion of all the gas sweetening stage deposits corresponded

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to Pyrite (FeS), Magnetite (Fe3O4), Maghemite (γ-Fe2O3), Hematite (α-Fe2O3),

Goetite (α - FeOOH) and Lepidocrocite (γ-FeOOH), as shown in Figure 11 for

sample number 22. These results indicate the existence of a strong corrosive

activity in the amine absorption system.

On the other hand, by the GC-MS analysis of the organic portion (Figure 12), it

was possible to identify a series of nitrogen compounds such as Ethanol-

oxazolidine, Pyperazine, Hydroxyethyl-ethylendiamine (HEED), Diethanol-

ethylamine (DEEA), Hydroxy-ethoxy-ethyl-pyperazine (HEEP), Hydroxyethyl-

pyperazine (HEP), and Bis-Hydroxy-ethyl-pyperazine (BHEP). These compounds

have been reported as products derived from thermal degradation of DEA, so theyhave the particularity of lowering the amine solution ability to absorb acid gases

from the natural gas stream. In addition, they also act as complexing agents of

ionic iron species, favoring corrosion phenomena. [16-17]

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Figure 11 FT-IR Spectrum and Diffractogram corresponding to the inorganic fraction of sample number 22.

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Figure 12 Total ionic current chromatogram obtained by GC-MS during the analysis of the organic fraction of sample number 22.

To complement this point, several studies have pointed out that the dissolved

oxygen in the amine solution produces its oxidative degradation, thus generating

carboxylic acids such as formic, acetic and oxalic acids and increasing corrosion

levels.[18]

The characterization of the lean amine solution in contact with the solid

deposit (sample number 22) by means of ion chromatography techniques

confirmed the presence of formic, acetic and oxalic acid at levels of 34423, 2020

and 1600 ppm respectively. Maximum permissible levels are in the order of 500,

1000 and 250 ppm for each of them.

[19]

These results clearly demonstrates thatin this specific cases, the mechanism causing solid deposition in natural gas

sweetening facilities is a combination of corrosion phenomena with thermal and

oxidative degradation of the circulating DEA solution.

3.5 Natural Gas dehydration

Studied deposits from natural gas dehydration facilities were related to a solid

phase an accumulation at gas-glycol contactor inlet and outlet lines (Samples 24

and 25). In such cases, spectroscopic analyses indicated that both samples were

the same solid. FT-IR, XRF, and XRD analyses identified a serie of iron hydroxyl-

oxides and iron oxides that are probably derived from corrosion phenomena taking

place into the system. Figure 13 shows the FT-IR spectra of sample number 24.

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30

35

40

45

50

55

60

65

70

75

80

85

90

95

100

%T

60080010001200140016001800200022002400

Wavenumbers (cm-1)

Goetitaα-FeOOH

Maghemita

γ-Fe2O3

H2O

Lepidrocitaγ-FeOOH

30

35

40

45

50

55

60

65

70

75

80

85

90

95

100

%T

60080010001200140016001800200022002400

Wavenumbers (cm-1)

Goetiteα-FeOOH

Maghemite

γ-Fe2O3

H2O

Lepidocrositeγ-FeOOH

Figure 13 FT-IR spectra of the inorganic fraction of sample number 24.

During the solubility tests of samples 24 and 25 it was observed that a

considerable amount of material dissolved easily in water (Table 2). As a

consequence, an aqueous extraction step was included into the separation

scheme. Ionic species derived from organic and inorganic acids were identified by

ionic chromatography analysis of the aqueous extracts. The identified species

were the organic ions: glycolate, formiate, acetate, and oxalate; whereas the

inorganic ions were nitrate, chloride, sulphate and thiosulphate, as it is

demonstrated in the chromatogram of Figure 14.

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Figure 14. Anion chromatograms of the water soluble fraction isolated from samplenumber 24.

Analysis of the organic portion allowed identifying a glycol mixture and a small

amount of hydrocarbons, as it is observed in the 1H NMR spectra of sample

number 24 (Figure 15). Thus, diethylenglycol and triethylenglycol were identified

by CG-MS as the major components (Figure 16), together with a n-paraffin family

with chain length ranging from C18 to C38 (Figure 17).

Apparently, the deposition problem at the natural gas dehydration facility is related

to the glycol thermal degradation that produces carboxylic acids promoting

corrosion. On the other hand, the presence of high molecular weight paraffins and

an insoluble organic material (similar to coke) may come from a possible glycol

contamination with lubricating oil to the glycol system. It is probable that the

insoluble material had formed from the thermal decomposition of the lubricating oil.

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Figure 15 1H NMR spectra of the organic portion of the sample 24

Figure 16 Fragmentogram of ion m/z 45 characteristic of polyglycols detected in the

saturated fraction of sample number 24.

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25.00 30.00 35.00 40.00 45.00 50.000

100000200000300000400000500000600000700000800000900000

100000011000001200000130000014000001500000

Tiempo (min.)

Abundancia

Ion 57.00

P20

P23

P25

P26

P27

P29

P30

P32

P34

P36 P38

25.00 30.00 35.00 40.00 45.00 50.000

100000200000300000400000500000600000700000800000900000

100000011000001200000130000014000001500000

Tiempo (min.)

Abundancia

Ion 57.00

P20

P23

P25

P26

P27

P29

P30

P32

P34

P36 P38

H-(CH2)n-H Pn

Figure 17 Fragmentogram of ion m/z 57 characteristic of alkanes detected in the

saturated fraction of sample number 24.

4 CONCLUSIONS

Twenty-five cases of undesirable solid formation were evaluated in systems of

natural gas handling and treatment. From these cases, 80% occurred at the stage

of handling, 12% at the stage of gas sweetening and the rest 8% during

dehydration. Thirty percent of solid deposits found in handling facilities were

associated to a combination of asphaltene precipitation phenomena and finely

particulated sand carry over. The rest 70% was due only to finely particulated sand

carry over from the reservoir. On the other hand, at the natural gas sweetening

stage, deposit formation was governed by alkanolamine solution thermal and

oxidative degradation phenomena, which also produce corrosion problems.

The studied deposition cases related to natural gas dehydration were tied to glycol

thermal degradation mechanisms that yielded corrosive acid species and to a

probable glycol contamination by lubricating oils.

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Thus, the systematic integration of separation techniques and spectroscopic

characterization tools has allowed to determine the chemical nature of solid

deposits and the possible mechanisms that originated them. The obtained results

not only served to detect the main cause, but also contributed to understand the

problem from a chemical point of view and to come up with the best corrective and

preventive procedures.

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[2] Rivas, Orlando R. Desarrollo de una metodología sistemática para el

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[3] Gas Processors Suppliers Association, Engineering Data Book, Vol. I and

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[4] IP 143/90. IP Standards for Petroleum and its products. Institute of

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[5] Carbognani, L., and Izquierdo, A. Preparative and automated compound

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[7] Koots, J.A and Speight, J.G. Relation of Petroleum resins to asphaltenes.

Fuel,54(3): 179-184, 1975.

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[8] Janusz Pawliszyn. Sample preparation in field and laboratory:

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[9] Carbognani Lante and Espidel Joussef. Characterization of Solid Deposits

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Formation. Revista Visión Tecnológica, 1995. Vol. 3, No.1, 35-42.

[10] A. Cosultchi, E. Garciafigueroa, B. Mar, A. García-Bórquez, V. H. Lara and

P. Bosch. Contribution of organic and mineral compounds to the formation

of solid deposits inside petroleum wells. Fuel, 2002, 81, 4, 413-421.

[11] A. Cosultchi, P. Bosch and V. H. Lara Adsorption of petroleum organic

compounds on natural Wyoming montmorillonite. Colloids and Surfaces A:Physicochemical and Engineering Aspects, 2004, Vol. 243, 1-3. 53-61

[12] Teresa M. Ignasiak, Luba Kotlyar, Frederick J. Longstaffe, Otto P. Strausz

and Douglas S. Montgomery Separation and characterization of clay from

Athabasca asphaltene Fuel, 1983. Vol. 62, 3, 353-362.

[13] Leon, O.; Contreras, E.; Rogel, E.; Dambakli, G.; Espidel, J.; Acevedo,

S.The Influence of the Adsorption of Amphiphiles and Resins in Controlling

Asphaltene Flocculation. Energy & Fuels, 2001; 15(5); 1028-1032.

[14] Carbognani, L., Orea, M Fonseca, M. Complex Nature of Separated Solid

Phases from Crude Oils. Energy & Fuels, 1999; 13(2); 351-358.

[15] DuPart, M.S., Rooney, P.C. and Bacon, T.R. Comparing laboratory and

plant data for MDEA/DEA blends. Hydrocarbon Processing. April 1999.

[16] Blauwhoff, P.P.M.; Versteeg, G.F.; and van Swaaij, W.P.M. A Study on the

Reaction Between CO2 and Ethanolamines in aqueous solutions. Chem.

Eng. Science, 38, 9, (1983) 1411.

[17] Strazisar, B. R.; Anderson, R. R.; and White, C. M. Degradation Pathways

for Monoethanolamine in a CO2 Capture Facility. Energy & Fuels, 2003, 17,

1034-1039.

[18] Rooney, P.C.; Bacon, T.R.; and DuPart, M.S. The Role of Oxygen in the

Degradation of MEA, DGA, DEA and MDEA. 48th Annual Laurence Reid

Gas Conditioning Conference. Norman, Oklahoma, 1998

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[19] Rooney, P.C.; Bacon, T.R.; and DuPart, M.S. Effect of Heat Stable Salts on

MEDA Solution Corrosivity. Part 1. Hydrocarbon Processing, March, 1996.

pp: 95-103.

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