Asfaltenos y Tratamiento

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asphaltene treatment. Asphaltene inhibitors prevent the asphaltenes fromdepositing into the system. The inhibitors work by stabilizing the

asphaltenes, preventing their flocculation and/or deposition.

This paper describes the evaluation of a Gulf of Mexico (GOM) deepwater

crude oil to determine its asphaltene deposition potential. This paper

further describes a systematic evaluation of asphaltene inhibitors in thecrude oil at reservoir and at stock tank conditions.

Discussion:

Pressure compensated DST fluid samples were taken from a deepwater

well in the Gulf of Mexico. This well is sub-sea tie back located in 5400

feet of water with a 10-mile tie back to the host platform. During the

course of system design it was necessary to evaluate this fluid forasphaltene deposition potential. The steps used to do this evaluation are

summarized as follows:

(1) Assess asphaltene stability in reservoir fluids at realistic production

conditions of temperature, pressure and/or composition using PVTanalysis, High Temperature Gas Chromatography, SARA Analysis,

Isothermal Depressurization Study and Isobaric Depressurization

Study.

(2) Screen various asphaltene inhibitors and optimize respective treatmentconcentrations using representative dead oil samples at ambient

conditions (i.e. minimize cost) with the Flocculation Point ApparatusTest and Asphaltene Dispersant Test.

(3) Confirm/validate (independently) the effectiveness of the selected

candidate asphaltene inhibitors and respective dosage for live fluids at

realistic production conditions of temperature, pressure and/orcomposition using the Isothermal Depressurization Study.

For asphaltene stability evaluation it is important to take a representativeDST sample in a pressure compensated cell in order to maintain reservoir

conditions. The results of the PVT analysis and analyses on dead oil are

depicted below.

TABLE 1: Downhole Conditions

Reservoir

Pressure

Temperature B.P. Depth

7063 psia/69MPa 190F/88C 3390 psia/33MPa 14,8000ft/3031M


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Table 2: Measured Fluid Properties

COMPONENT MOL%

CO2 0.15

N2 1.15

C1 40.91

C2 5.67

C3 5.37

I-C4 0.79

N-C4 2.39

I-C5 1.19

N-C5 1.3

C6 2.29C7+ 38.78

Molecular Weight 101.7

In situ density (g/cm3) 0.8445

Table 3: SARA Analysis on Dead Oil

Saturates Aromatic NSO Asphaltenes C15+

47.1 32.1 16.8 4.0 53.2

Figure 1: Isothermal Depressurization Graph and Asphaltene Onset Point

0 10 20 30 40 50 60 70

Pressure (MPa)

LaserPower(ArbitraryUnits)

OIL 1 @ 80 .6 C)

OIL 2 @ 68 .3 C)

Bubble Point

Asphaltene Onset

~ 50.4 MPa

Redissolution onset

~ 24.4 MPa


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Figure 2: FPA of Dead Oil

SDS Isothermal Depressurization Test (Figure 1) indicates that theasphaltene onset pressure point is approximately 4000 psia, which is about

650 psia above the bubble point. The asphaltene onset point is the

pressure at which asphaltenes phase out of the oil and start to agglomerate,forming particles large enough to prevent transmittance of the light

through the SDS cell. Generally, the higher that onset point pressure is

above the bubble point, the more unstable the asphaltenes are in the crude.

The SDS Isothermal Depressurization Test also measures the amount of

asphaltene particles that can be filtered out. At the end of the Isothermal

Depressurization Test the oil was filtered at 3000 psia through a 0.2mfilter. The filtrate was washed with warm n-pentane. The extracted solidsweighed 360 mg. The solids were then analyzed and they were

determined to be 90% asphaltenes. The amount of asphaltenes extracted

from the oil was 0.62% of the mass of the oil tested. This amount wasconsidered to be significant.

The FPA (Figure 2) test also indicated that the asphaltenes in the oil wereunstable. The FPA gave a flocculation point value of 16 mL. Oils with a

flocculation point value of 20mL or less are generally considered unstable.

The SARA analysis (Table 3), which also indicates asphaltene stability,was inconclusive.

Overall, the tests indicated that the oil contained unstable asphaltenes andasphaltene deposition problems were likely. Because of the possibility of

asphaltene deposition in this system, asphaltene inhibitors were evaluated

F P A T e s t o f G O M O i l

1 6 . 5 9 6

0

0 .2

0 .4

0 .6

0 .8

1

1 .2

1 .4

0 5 1 0 1 5 2 0 2 5

V o l u m e o f I s o -o c t a n e ( m L )

Voltageoftransmittance(V)


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on this oil. The ADT test was used to screen the chemical inhibitors. Thebest inhibitor was ratio tested using the ADT test. The results of the ratio

test are listed below in table 4.

Table 4: ADT Asphaltene Inhibitor Ratio Test

Asphaltene Inhibitor (ppm) ppt mls %T

0 ppm (untreated) 1 31

100 0.9 31

250 0.7 24

500 0.2 17

750 0.05 13

1000 0.05 13

The ADT test showed that it would take between 250 to 500 ppm of theasphaltene inhibitor to stabilize the asphaltenes enough to prevent

deposition. These results were further validated on the FPA test (Figure3).

Figure 3: FPA Test With Asphaltene Inhibitor

The FPA results showed that with 400 ppm of the asphaltene inhibitor,

there was no flocculation point indicating that the asphaltenes in the oil

were completely stabilized.

Isothermal Depressurization testing was repeated using 500 ppm of

asphaltene inhibitor. The onset point was not significantly affected by theaddition of the inhibitor. The amount of asphaltene recovered through

filtration however was reduced from 360 mg to 24 mg. The filtered

asphaltenes were considered negligible.

F P A T e s t G O M O i l T r e a t e d w i th 4 0 0 p p m i n h ib i to r

0

0. 1

0. 2

0. 3

0. 4

0. 5

0. 6

0. 7

0. 8

0. 9

1

0 5 10 1 5 2 0 25 3 0

V o l u m e o f is o - o c t a n e (m L )

VoltageofTransm

ittance


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Conclusion:

A systematic experimental program was developed to critically assess andcontrol the potential for asphaltene deposition from reservoir fluids. Byfollowing the methodology, the GOM crude oil was successfully evaluated

for its tendency to precipitate and deposit asphaltenes under typical

production conditions. An asphaltene inhibitor that stabilizes theasphaltenes was also successfully evaluated.

References:

Allen, T. O. and Roberts, A. P. 1989. Production Operations: Well

Completions, Workover, and Stimulation (second edition), Oil & Gas

Consultants International., Inc. Chap 2, pp 11-19.

de Boer, R.B., Leerlooyer, K., Eigner, M.R.P. and van Bergen, A.R.D. 1995.

SPE Production and Facilities. 2:55.

Fuhr, B.J., Cathrea, C., Coates, L., Kalra, H., Majeed, A.I., 1991. Fuel.

70:1293.

Hammami, A., Chang-Yen, D., Nighswander, J. A., and Stange, E. 1995.

Fuel Sci. Tech. Inter. 13 (9):1167.

Hammami A. and Raines, M. A. 1999. SPE Journal, 4:1.

Hammami, A., Phelps, C. H., Monger-McClure, T. and Little, T. M. 2000.Energy & Fuels. 14 (1):14-18.

McClaflin, G. G. and Whitfill, D. L. SPE 12204 Presented at the 58thAnnual Technical Conference and Exhibition of the Society of Petroleum

Engineers in San Francisco CA, October 5-8, 1983.

Svetgoff, J. 1984. Oil & Gas J. (Feb 27):79.

Woo, G. T., Garbis, S. J., Gray, T. C. SPE 13126 Presented at the 59thAnnual Fall Technical Conference, Dallas TX, September 16-19, 1984.

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