water-assisted flow of heavy oil and gas in a vertical pipe

CANADIAN HEAVY OIL ASSOCIATION

SPE/PS-CIM/CHOA 97875 PS2005-395

Water-Assisted Flow of Heavy Oil and Gas in a Vertical Pipe A.C. Bannwart, SPE, and F.F. Vieira, State U. of Campinas; C.H.M. Carvalho, Petrobras-Cenpes; and A.P. Oliveira, GTEP/PUC-RJ

Copyright 2005, SPE/PS-CIM/CHOA International Thermal Operations and Heavy Oil Symposium This paper was prepared for presentation at the 2005 SPE International Thermal Operations and Heavy Oil Symposium held in Calgary, Alberta, Canada, 1–3 November 2005. This paper was selected for presentation by an SPE/PS-CIM/CHOA Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers, Petroleum Society–Canadian Institute of Mining, Metallurgy & Petroleum, or the Canadian Heavy Oil Association and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the SPE/PS-CIM/CHOA, its officers, or members. Papers presented at SPE and PS-CIM/CHOA meetings are subject to publication review by Editorial Committees of the SPE and PS-CIM/CHOA. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the SPE or PS-CIM/CHOA is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract The three-phase water-assisted flow of heavy crude oil with free gas (air) in a vertical glass pipe, at near atmospheric pressure and temperature conditions, is investigated, for possible applications to the articial lift of heavy oil. Water is injected so as to avoid oil-wall contact and reduce friction. The oil phase was a w/o emulsion with a viscosity of 5,040 mPa.s and a density of 971 kg/m3. For each combination of oil-water-gas flow rates, the flow pattern was determined using a high speed camera and the pressure gradient was measured with a differential pressure transducer. The results are presented in the form of flow maps based on superficial velocities and total pressure gradient plots, allowing comparisons with well known correlations. The main conclusion indicates the great viability of the water-assisted flow technique. Significant amounts of heavy oil have been discovered in offshore Brazil. Introduction Heavy oils are often defined as those having densities greater than 934 kg/m3 (<20 oAPI) and viscosities in the range 100-10,000 mPa.s at reservoir conditions of pressure and temperature [1]. They represent a significant part of the Brazilian oil reserves, which, according to the National Petroleum Agency (2002), are approximately 3.2 billion oil barrels and mostly located offshore. The exploitation of these reserves, with the usual recovery and artificial lift technologies tends to be economically unattractive or unfeasible, which is partly due to the lower market value of heavy oils. However, with the progressive decline of light oil production, the importance and, consequently, the price of these fossil energy sources will tend to increase.

The use of long horizontal length wells has been proposed to achieve high productivities but the injection of water in the reservoir tends to be not efficient, due to the unfavorable mobility difference between water and heavy oil [2]. Furthermore, in offshore deepwater fields, flow assurance problems such as hydrate, asphaltene and paraffin deposition risks indicate the need for improved thermal insulation and/or heat addition to the production line. However, water is readily available and its injection in liquid form requires low energy consumption.

The artificial lift method for heavy oils is also critical especially in offshore deepwater applications since the conventional PCP technology does not provide high enough flow rates and ESPs require high power to overcome increased frictional flow losses of heavy oil or w/o emulsions. Refinery requirements include removal of nearly all the water present in the emulsion.

This paper focuses the vertical upward three-phase pipe flow of heavy oil, air and water at several different combinations, in which water is injected to work as the continuous phase (water-assisted flow). A laboratory scale apparatus was built allowing flow pattern visualization and pressure drop measurement. Results are compared with some well-known oil and gas correlations and may be useful in either case when water is injected in the reservoir and forms a continuous phase in the production pipeline (BSW > 50 %), or when it is injected at pump exit, as in the oil-water “core flow” method [3-5]. No previous work on vertical three-phase oil-water-gas flow has been found. Experimental Setup and Procedure The experiments were conducted in the setup shown in Figure 1, at the School of Mechanical Engineering of the State University of Campinas. The apparatus consisted of a separator tank, individual lines and pumping systems for water, oil and air, which joined at an injector nozzle, followed by a 2.84 cm i.d., 2.5 m long vertical glass tubing for the three-phase flow. The oil flow rate was measured with a Coriolis mass flow meter, whereas the water and air flow rates were read in rotameters. Pressure data in the test section were measured with differential and absolute pressure transducers connected to a data acquisition system.

The oil utilized was a blend of crude dead oil with a viscosity of µo = 5,040 mPa.s and a density of ρo = 971 kg/m3 at 25oC. The oil phase was observed to be a w/o emulsion. The

2 SPE/PS-CIM/CHOA 97875

water used was tap water contained in the separator tank and the air was provided by an existing group of compressors.

The experiments involved combining air, water and oil at several different flow rates. For each set of flow rates video footage of the flow pattern was taken with a high-speed camera (1000 frames/s) and pressure data were collected. The experimental superficial velocities varied within the following ranges:

- oil: 0.02 < Jo < 1.2 m/s - air: 0.04 < Jg < 9 m/s - water: 0.04 < Jw < 0.5 m/s The experiments took place at ambient temperature and

near atmospheric pressure. In all runs, water was always injected first (in order to

make sure that it would be the continuous phase), followed by oil and air. The glass pipe was never observed to be fouled (hydrophilic behavior).

Two-phase oil-water tests were also run in order to evaluate the influence of the presence of a free gas phase in the flow.

Results

Three-Phase Vertical Flow Patterns. Since water was always the continuous phase and the oil phase was very viscous, a classification scheme for the three-phase flow patterns was done by individually describing the air-water and oil-water flow patterns. These two-phase patterns were:

A - Annular B - Bubble I - Intermittent

The three-phase flow pattern designation was formed by

by combining the air-water and oil-water designations. Six flow patterns were observed which are illustrated in Fig. 2 and mapped in Fig. 3.They can be described as follows:

a) Bg-Ao: Bubbly gas – Annular oil (Fig. 2-a) This pattern is similar to heavy oil-water core flow,

except that here gas bubbles are seen in the water phase. The oil-water interface is typically sinuous. This pattern occurs for high oil and low gas superficial velocities (Fig. 3).

b) Ig-Ao: Intermitent gas – Annular oil (Fig. 2-b) The gas phase forms large bubbles which partly

surround a still continuous oil core. This pattern occurs for high oil and moderate gas superficial velocities (Fig. 3).

c) Bg-Io: Bubbly gas – Intermittent oil (Fig. 2-c) The gas forms small bubbles and the oil forms large

bubbles. This pattern occurs for moderate oil and low gas superficial velocities (Fig. 3).

d) Bg-Bo: Bubbly gas – Bubbly oil (Fig. 2-d) This pattern was observed for low oil and gas

superficial velocities, but only when the water superficial velocity was higher than about 0.3 m/s, which was enough to disperse the oil into bubbles.

f) Ig-Io: Intermittent gas – Intermittent oil (Fig. 2-e) The gas and the oil both form large bubbles which are

very close to each other. Detailed observation shows that the oil bubble is sucked towards the low pressure wake behind the gas bubble. This pattern occurs for high gas and oil superficial velocities, and also for moderate gas and oil superficial velocities (Fig. 3).

e) Ig-Bo: Intermittent gas – Bubbly oil (Fig. 2-f) At high gas superficial velocities (Fig. 3) the gas forms

large, high speed bubbles and the oil is dispersed into small bubbles. This pattern is typically pulsating, indicating a transition to annular gas-liquid flow.

Annular gas-liquid (i.e. Ag-Bo) flow pattern was not

observed, since the superficial velocity of the gas phase in our experiments was lower than 10 m/s.

It was observed that the water flow rate had little influence in the formation of the above flow patterns, except in the case of Bg-Bo as explained. Total Pressure Gradient. Figure 4 presents the results for the total pressure gradient, which includes essentially the contributions due to gravity and friction. As can be observed, the greater the gas-oil ratio, the smaller the pressure gradient, indicating the dominant effect of gravity on the pressure gradient, since the patterns with lower pressure gradients have higher gas contents, higher velocities, thus higher friction losses.

Figure 5 shows the ratio between the single-phase oil pressure gradient and the measured three-phase pressure gradient. This ratio was always higher than one, ranging from about 1.5 to 35, indicating how much the single phase oil pressure drop would be reduced. The data points group naturally in inclined ‘lines’ where the superficial gas velocity is nearly constant, corresponding to the near vertical ‘lines’ of Fig. 3. On each of these ‘lines’, it can be observed that a decrease in the oil superficial velocity causes the reduction factor to decrease, as expected. It can be noted that the points of highest reduction factor do not always correspond to the ‘Annular oil’ (Ao) pattern. The reduction factor increases with increasing gas superficial velocities, since the three-phase pressure gradient decreases (Fig. 4).

Figure 6 shows the ratio between the two-phase oil-gas pressure gradient and the measured three-phase pressure gradient. In this case the oil-gas pressure gradient was estimated from traditional correlations used in the software PipeSim® (best estimation option). This reduction ratio is still higher than that of Fig. 5, ranging from 1.5 to 50. Apart from the fact that the correlations employed in the PipeSim program are valid for light oils only, this range of reduction factors is similar to the one observed in Fig. 5.

Figure 7 shows the ratio between the three-phase pressure gradient and single-phase water pressure gradient at mixture flow rate. This ratio is observed to be always lower than one, indicating the dominancy of the gravitational pressure gradient gain and the effect of the gas phase in the reduction of the total pressure gradient (Fig. 4). It can also be noted that this ratio tends to one if no gas is present, a result consistent with the observed by other authors [6].

SPE/PS-CIM/CHOA 97875 3

Since in our experiments water was always the continuous phase, comparisons were performed between the measured pressure gradient and the ones calculated by traditional oil-gas correlations included in the PipeSim® software, using water as the equivalent viscosity of the liquid phase. Five correlations were tested: Hagedorn & Brown (HB), Beggs & Brill (BB), Duns & Ros (DR), Revised Hagedorn & Brown (HBR) and Orkiszewski (ORK). The results are shown graphically in Figs. 8-12 and numerically in Table 1. As can be observed, all the tested correlations underestimate the pressure gradient, since the adopted liquid viscosity is lower than the effective viscosity of the liquid phase. Despite this, the Beggs & Brill (BB) and Duns & Ros (DR) provided the best agreement with the experimental data.

Conclusions An experimental study of the three-phase upward flow of heavy crude oil, water and air, in a vertical pipe was performed. The work consisted in visualizing the flow with the help of a high speed camera and measuring the total pressure drop at several different flow rates of the phases.

Six flow patterns were observed, all having water as continuous phase and allowing movimentation of the viscous oil (w/o emulsion of 5,040 mPa.s) with low pressure drop.

As regards the total pressure gradient, the following can be concluded:

- an increase in the gas superficial velocity causes a decrease in the pressure gradient, which is dominated by the gravity contribution;

- the reduction factor of the pressure gradient relative to the single-phase oil flow was in the range 1.5-35, and increases with increasing oil and gas flow rates;

- the reduction factor of the pressure gradient relative to oil-gas flow, calculated with correlations valid for light oils was in the range 1.5-50;

- the total pressure gradient is always lower than the single-phase water flow at the three-phase mixture flow rate, and decreases as the gas flow rate increases, at constant oil and

water flow rates;

- the comparison of the experimental pressure drop with five different oil-gas correlations, using water as the equivalent liquid viscosity indicated that all the tested correlations underestimate the experimental values, with the best agreement being obtained by the Beggs & Brill and Duns & Ros correlations. Acknowledgements The authors express their gratitude to Petrobras – Petróleo Brasileiro S.A., Finep – Financiadora de Estudos e Projetos, CNPq – Conselho Nacional de Desenvolvimento Científico e Tecnológico e Cepetro – Centro de Estudos de Petróleo da UNICAMP, Brazil, for their support in different parts of this work. References

1. Tissot, B.P. and Welte D. H.: Petroleum Formation and

Occurrence, second edition, Springer-Verlag, New York (1984).

2. Pinto, A.C.C. et al.: “Offshore Heavy Oil in Campos Basin: The Petrobras Experience”, paper SPE 15283 presented at the 2003 Offshore Technology Conference, Houston, May 5–8.

3. Charles, M.E. et al.: “The Horizontal Pipeline Flow of Equal Density Oil-Water Mixtures”, Can.J.Chem.Eng., 39-1 (1961) 27.

4. Bannwart, A.C. et al.: “Flow Patterns in Heavy Crude Oil-Water Flow”, J.En.Res.Tech. ASME, 126 (Sept. 2004) 184.

5. Rodriguez, O.M.H. et al.: “Pressure Drop in Upward Vertical Core-Annular Flow: Modeling and Experimental Investigation”, Proc. of the 11th International Conference on Multiphase Production - Multiphase’03, pp. 373-389, San Remo – Italy (2003).

6. Vanegas-Prada, J.W. and Bannwart, A.C., “Pressure Drop in Vertical Core-Annular Flow”, J.Braz.Soc.Mech.Sci., 23 23-4 (2001) 491.

Table 1 – Accuracy and precision of the tested lations in comparison with data (Γ stands for pressure gradient) corre

Correlation ( )∑ Γ−Γ

N

expcorN1

(Pa/m)

( )∑ Γ−Γ

N

expcorN21

(Pa/m) HB -1791 2291 BB -1209 1651 DR -1478 1825

HBR -1533 2009 ORK -1362 2502


Pressure taps

Pressure taps

Injector

Water

Oil

Window

Pump

Filter

Rotameters

Pump

Manometer

1’’

Frequency Inverters

Oil-water Interface

Oil Surface

Manometer Manometer

Set of rotameters

Retention Valve

AIR

3’’

Flowmeter

Fig. 1 - Experimental setup for study of three-phase flow

Oil Water Air

a) Bg-Ao

b) Ig-Ao

c) Bg-Io

d) Bg-Bo

e) Ig-Io

f) Ig-Bo

Fig. 2 - Flow patterns for vertical upward three-phase flow of heavy oil, water and air


0.0

0.1

1.0

10.0

0.0 0.1 1.0 10.0

Jg (m/s)

BgAoBgBoBgIoIgAoIgBoIgIo

Fig. 3 – Superficial velocity flow map for vertical upward three-phase flow of heavy oil, water and air – all water flow rates (p = 1.1 atm; T = 27 oC). The dashed lines are for qualitative purposes only.

1000

10000

100000

0.0 0.1 1.0 10.0 100.0 1000.0

Jg/Jo (m/s)

Tota

l Pre

ssur

eG

radi

ient

(Pa/

m)

BgAo

BgBo

BgIo

IgAo

IgBo

IgIo

1000

10000

1000

10000

100000

0.0 0.1 1.0 10.0 100.0 1000.0

Jg/Jo (m/s)

Tota

l Pre

ssur

eG

radi

ient

(Pa/

m)

BgAo

BgBo

BgIo

IgAo

IgBo

IgIo

Fig. 4 – Three-phase total pressure gradient as a function of the gas-oil ratio


1

10

100

0,0 0,1 1,0 10,0 100,0 1000,0

Jg/Jo (m/s)

Oil

/ 3-p

hase

pres

sure

grad

ient

ratio

BgAo

BgBo

BgIo

IgAo

IgBo

IgIo

1

10

1

10

100

0,0 0,1 1,0 10,0 100,0 1000,0

Jg/Jo (m/s)

Oil

/ 3-p

hase

pres

sure

grad

ient

ratio

BgAo

BgBo

BgIo

IgAo

IgBo

IgIo

1

Fig. 5 – Three-phase total pressure drop reduction factor relative to single-phase oil flow

1,0

10,0

100,0

0,0 0,1 1,0 10,0 100,0 1000,0

Jg/Jo

Oil-

gas

/ 3-p

hase

pre

ssur

e gr

adie

nt ra

tio

1

Fig. 6 – Three-phase total pressure drop reduction factor relative to two-phase oil-gas flow


0,1

1,0

10,0

0,0 0,1 1,0 10,0 100,0 1000,0

Jg/Jo (m/s)

3-ph

ase

/ wat

erpr

essu

regr

adie

ntra

tio

BgAo

BgBo

BgIo

IgAo

IgBo

IgIo

0,1

1,0

0,1

1,0

10,0

0,0 0,1 1,0 10,0 100,0 1000,0

Jg/Jo (m/s)

3-ph

ase

/ wat

erpr

essu

regr

adie

ntra

tio

BgAo

BgBo

BgIo

IgAo

IgBo

IgIo

1

Fig. 7 – Three-phase total pressure drop in comparison with single-phase water flow at mixture flow rate

HB

2000

4000

6000

8000

10000

12000

2000 4000 6000 8000 10000 12000Measured Pressure Gradient (Pa/m)

Cal

cula

ted

Pres

sure

Gra

dien

t (Pa

/m)

Fig. 8 – Comparison between measured pressure drop and calculated using the original Hagedorn & Brown (HB) correlation


BB

2000

4000

6000

8000

10000

12000


Cal

cula

ted

Pres

sure

Gra

dien

t (Pa

/m)

Fig. 9 – Comparison between measured pressure drop and calculated using the Beggs & Brill (BB) correlation

DR

2000

4000

6000

8000

10000

12000


Cal

cula

ted

Pres

sure

Gra

dien

t (Pa

/m)

Fig. 10 – Comparison between measured pressure drop and calculated using the Duns & Ros (DR) correlation


HBR

2000

4000

6000

8000

10000

12000


Cal

cula

ted

Pres

sure

Gra

dien

t (Pa

/m)

Fig. 11 – Comparison between measured pressure drop and calculated using the revised Hagedorn & Brown (HBR) correlation

ORK

2000

4000

6000

8000

10000

12000


Cal

cula

ted

Pres

sure

Gra

dien

t (Pa

/m)

Fig. 12 – Comparison between measured pressure drop and calculated using theOrkiszewski (ORK) correlation

water-assisted flow of heavy oil and gas in a vertical pipe

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