EFFECT OF A DRAG REDUCING AGENT ON PRESSURE DROP AND
FLOW REGIME TRANSITIONS IN MULTIPHASE HORIZONTAL LOW
PRESSURE PIPELINES
A Thesis Presented to
the Faculty of the Fritz J. and Delores H. Russ
College of Engineering and Technology
Ohio University
In Partial Fulfillment
of the Requirement for the Degree
Master of Science
BY
Robert M. Vancko, Jr.
March, 1997
ACKNOWLEDGMENTS
The author wishes to express his hghest appreciation and sincere gratitude to
Dr. W.P. Jepson for his supervision, advice and encouragement for t h s study.
The author would like to thank Dr. Tony Green for h s guidance and support.
Thanks also go to fellow graduate students of the NSF IIUCRC, Corrosion in
Multiphase Systems Center who helped in various ways in the completion of thss
project. Finally, thanks to A.D. Pallini for all h s help, advice, t e c h c a l assistance
and fiiendshp.
The author is grateful for the financial and t e c h c a l support fiom the NSF
IIURC, Corrosion in Multiphase Systems Center at O h o University and British
Petroleum.
Rob Vancko
Ohio University
March, 1997
TABLE OF CONTENTS
....................................................... iv
1 Introduction ....................................................... 1
2. PrevousWork .................................................... 5
2.1 Twophaseflow ............................................. 5
2.1.1 Gas-liquid two phase flow .............................. 5
2.1.2 Oil .W a t e r two phase flow ............................. 7
2.2 Three Phase Flow ........................................... 8
2.3 Drag Reducing Agents ....................................... 9
2.3.1 Single-phase d r a g reduction ............................ 10
2.3.2 Multiphase d r a g reduction ............................. 12
3. Experimental Setup ............................................... 15
List of Figures
3.1 Experimental Setup and Pocedure ................................. 15
3.2 Test Matrix .....................................................17
4. Results and Discussion
................................................... 21
...............................- 2 1
4.2 Batch Injection Effectiveness of DRA .................................21
4.2.1 Single Phase Flow.........................................- 2 1
4.3 Two Phase Annular Flow of Oil-Gas Mixtures ........................ - 2 3
4.3.1 Superficial Liquid Velocity = 0.08 m/s ......................... 24
4.3.2 Superf~cialLiquid Velocity = 0.15 m/s ......................... 25
4.3.3 Superficial Liquid Velocity = 0.25 m/s ......................... 26
4.1 Observations and Flow Visualizations
4.3.4 Superficial Liquid Velocity = 0.35 m/s
......................... 27
................................................. 29
...............................29
.............29
............. 33
Slug Flow Regime ......................................... 36
4.4 Multiphase Flow
4.4.1 Stratified Flow Regime
4.4.1.1 Superficial liquid velocity = 0.03 m/s
4.4.1.2 Superf~cialliquid velocity = 0.11 m/s
4.4.2
................... 36
...................38
4.4.3 Annular flow regime .......................................38
4.4.1 Superficial liquid velocity = 0.06 mls ..................... 38
4.4.2 Superficial liquid velocity = 0.28 mls ..................... 41
4.5 Flow Regime Maps ................................................ 42
4.6 Continuous Injection ............................................. 45
4.7 Interfacial and Surface Tension .....................................45
4.7.1SurfaceTension ........................................... 45
4.7.2 Interfacial Tension ......................................... 47
4.8 Shear Degradation of the DRA ..................................... 48
4.4.2.1 Superficial liquid velocity = 0.28 mls
4.4.2.2 Superficial liquid velocity = 0.56 mls
5. Conclusions
.
6 References
.......................................................51
...........................................................
108
LIST OF TABLES
.................... ......... 20
Table 3.2:
Experimental Test Matrix
Table 4.3:
Average Pressure Gradient Reduction in Two-phase,
Oil-Gas, Annular Flow
Table 4.4.1.1:
. .................. ............ 28
Average Pressure Gradient Reduction in Stratified Flow,
20% Oil, Vsl=0.03 rnls..
Table 4.4.1.2:
Average Pressure Gradient Reduction in Stratified Flow,
80% Oil, Vsl = 0.03 rnls
Table 4.4.1.3:
................. ... ......... 30
............................... 32
Average Pressure Gradient Reduction in Stratified Flow,
20% Oil, Vsl=O.11 mls..
..... ............... ......... 34
Table 4.4.3:
Average Pressure Gradient Reduction in Three-phase
Table 4.7.1:
..................................... 42
Surface Tension of LVT Oil and Water .. . . . . . .. . . . . . . . . . 47
Interfacial Tension of LVT Oil - Water Mixtures .. . . . .. . .. 48
AnnularFlow..
Table 4.7.2
LIST OF FIGURES
..................................... 53
.
2. Profile of Different Regions of a Slug ............................. 54
3. Gas .Liquid Two Phase Flow Patterns ........................... 55
4. Multiphase Flow Regime Map .................................. 56
1 Multiphase Flow Patterns
.
................. 57
6. Layout of the Experimental System ............................. 58
5 Drag Reduction Performance in Single Phase Flow
..................................... 59
.
8. Diagram of the Continuous Injection System ...................... 60
9. Pressure Gradient in Full Pipe Oil Flow .......................... 61
10. Pressure Gradient in Full Pipe Water Flow ...................... 62
11. Friction Factors in Full Pipe Oil Flow ........................... 63
12. Annular Pressure Gradient, Two Phase, 100% LVT Oil, 0 ppm DRA . 64
13. Annular Pressure Gradient. Two Phase. Vsl = 0.08 m/s ............ 65
14. Annular Pressure Gradient. Two Phase. Vsl = 0.15 mls ............ 66
7 Experimental Test Section
.
.............
67
.
.............
68
15 Annular Pressure Gradient. Two Phase. Vsl = 0.25 m/s
16 Annular Pressure Gradient. Two Phase. Vsl = 0.35 mls
..............
.
18. Annular Pressure Gradient. 40% Oil. Vsl = 0.03 m/s ..............
19. Annular Pressure Gradient. 60% Oil. Vsl = 0.03 m/s ..............
20. Annular Pressure Gradient. 80% Oil. Vsl = 0.03 m/s ..............
21. Stratified Pressure Gradient. 20% Oil. Vsl = 0.11 m/s .............
17 Annular Pressure Gradient. 20% Oil. Vsl = 0.03 m/s
.............
.
23. Stratified Pressure Gradient. 60% Oil. Vsl = 0.11 m/s .............
24. Stratified Pressure Gradient. 80% Oil. Vsl = 0.11 m/s .............
25. Slug Flow Pressure Gradient. 20% Oil. Vsl = 0.28 mls .............
22 Stratified Pressure Gradient. 40% Oil. Vsl = 0.11 m/s
69
70
71
72
73
74
75
76
77
............. 78
27. Slug Flow Pressure Gradient. 20% Oil. Vsl = 0.56 mls ............. 79
28. Slug Flow Pressure Gradient. 40% Oil. Vsl = 0.56 mls ............. 80
29. Slug Flow Pressure Gradient. 60% Oil. Vsl = 0.56 mls ............. 81
30. Annular Pressure Gradient. 20% Oil. Vsl = 0.06 mls .............. 82
31 . Annular Pressure Gradient. 40% Oil. Vsl = 0.06 mls .............. 83
32. Annular Pressure Gradient. 60% Oil. Vsl = 0.06 mls .............. 84
33. Annular Pressure Gradient. 80% Oil. Vsl = 0.06 mls .............. 85
34. Annular Pressure Gradient. 20% Oil. Vsl = 0.28 mls .............. 86
35. Annular Pressure Gradient. 40% Oil. Vsl = 0.28 mls .............. 87
36. Annular Pressure Gradient. 60% Oil. Vsl = 0.28 mls .............. 88
37. Annular Pressure Gradient. 80% Oil. Vsl = 0.28 mls ............... 89
.
26 Slug Flow Pressure Gradient. 40% Oil. Vsl = 0.28 mls
38. Flow Regime Map. 25% LVT Oil. 0 ppm DRA
39. Flow Regime Map. 50% LVT Oil. 0 ppm DRA
....................... 90
........................ 91
40. Flow Regime Map. 75% LVT Oil. 0 ppm DRA
........................ 92
41. Flow Regime Map. 25% LVT Oil. 25 ppm DRA
....................... 93
....................... 94
....................... 95
....................... 96
....................... 97
....................... 98
42 . Flow Regime Map. 50% LVT Oil. 25 ppm DRA
43. Flow Regime Map. 75% LVT Oil. 25 ppm DRA
44. Flow Regime Map. 25% LVT Oil. 75 ppm DRA
45. Flow Regime Map. 50% LVT Oil. 75 ppm DRA
46. Flow Regime Map. 75% LVT Oil. 75 ppm DRA
47. Continuous Injection dP. Annular Flow. 20% Oil.
Vsl=0.28m/s.
.................................................. 99
48. Continuous Injection dP. Annular Flow. 80% Oil.
.................................................. 100
49. DRA Surfactant Effect on LVT Oil and Water ....................... 101
50. DRA Surfactant Effect on LVT Oil .Water Mixtures .................. 102
51. Shear Degradation of DRA. 5 ppm ................................. 103
Vsl=028 mls.
52. Shear Degradation of DRA, 75 ppm
. .. . . . . . . .. . . . .. . . . . . . . . . .. . . . . . 104
LIST OF PLATES
........................... 105
Plate 2: 5 ppm DRA Degraded 120 Minutes. lOOx Magnification ............ 106
Plate 3: 75 ppm DRA. Degraded. 120 Minutes. lOOx Magnification .......... 107
Plate 1: Pure DRA. Fresh. lOOx Magnification
CHAPTER 1
INTRODUCTION
The flow of oil-water-gas mixtures in pipelines is a common occurrence in the
petroleum industry. Although wells initially contain only oil and natural gas, mature and
aging reservoirs produce increasing amounts of water and reservoir pressure may deplete.
Enhanced recovery methods may involve pumping natural gas into the well tubing to
reduce static pressure losses.
It is often not practical and very expensive to separate this oil-water-gas mixture at
the well site so the multiphase mixture is pumped through a single pipeline to a central
gathering station, where it can be separated. The distances the multiphase mixture must be
transported are often many miles and the pressure drop in these pipelines can be significant.
The oil and gas producing industries have traditionally used drag reducing agents (DRA's)
to help lower pressure gradients for the transport of single-phase liquids over long
distances. An example of DRA use in a mature production system, where the liquid and gas
are separated at the source, is the transport of oil in the 800 mile Trans-Alaska Pipeline.
DRA's have been very beneficial in reducing frictional losses, allowing a greater production
flow rate at an economical cost. DRA's have not been specifically designed for use in
multiphase systems where oil-water-gas mixtures are transported. Modern production
facility design requires the transportation of raw wellhead fluids to processing facilities, at
ever increasing distances, to remain economically viable.
The use of DRA's in this
application is novel, although it has been tried in existing systems without conclusive
results. Both the effects of DRA on flow regime and concentration requirements are
unknown, thus making an economic benefit analysis virtually impossible.
The benefits of DRA use in existing systems are increased production (without
mechanical modification), reduction of operating costs such as pumping power, reduction
of pipeline pressure while maintaining throughput, and to facilitate refinery debottlenecking
and loadinglunloading operations. The design benefits of DRA's in new systems are a
reduction in pipeline diameter and pumplpumping station capital costs. The deferment of
capital expenditure is also of economic value where pumps are introduced at a later stage
in the life of an oil field.
The four main flow regimes observed in multiphase liquid-liquid-gas flow are
presented in Figure 1. These are reported in the literature by Govier (1962), Lin (1984)
and Barnea and include bubble flow, stratified (smooth, wavy and rolling wave),
intermittent (plug, slug and pseudo slug), and annular flow.
Bubble flow is characterized by gas bubbles flowing in the upper part of the pipe in
a continuous liquid phase. Bubble flow is observed at high liquid and low gas velocities.
Stratified flow is identified as three separate phases with gas at the top and two stratified
liquid phases flowing along the bottom of the pipe. A smooth interface exists at low gas
and liquid velocities. When the gas velocity is increased, two dimensional waves are
formed at the gas-liquid interface. A fbrther increase in gas velocity causes the waves to
appear in the form of rolling waves, i.e. the wave is steeper at the front and rolls forward
along the pipe. Rolling waves can combine and result in larger roll waves, which may form
a slug.
Intermittent flow occurs as the liquid and gas velocities are further increased. The
intermittent flow regime is divided into plug and slug flow. Plug flow is produced by
increasing liquid velocity from smooth stratified flow. Plug flow is similar to stratified flow
except that there are regions where the liquid completely fills the pipe.
Increases in gas velocity result in rolling waves that bridge the pipe causing the
transition to slug flow. A diagram of a slug is depicted in Figure 2. Slug flow consists of
four zones: a stratified liquid film ahead of the slug with a gas pocket above it, a mixing
zone, the slug body and the slug tail. The blockage is accelerated and the slug front, where
the liquid film is assimilated into the mixing zone, is where high regions of turbulence are
created. This mixing zone entrains gas which is passed back into the slug body. After slug
passage, liquid is shed from the slug tail and mixed in with the incoming liquid to produce a
film on which the following slug will propagate.
The highly turbulent nature of slug flow, in the presence of water, results in
dramatic increases in the corrosion rates in pipelines. These high corrosion rates cause
losses due to damaged equipment and production shutdowns. Since many multiphase
pipelines are located in remote areas such as Alaska or subsea, the repair and maintenance
costs are high. For this reason, operating pipelines in slug flow should generally be
avoided. However, due to the high production rates needed, many pipelines do operate in
the slug flow regime.
A hrther increase in gas velocity produces pseudo slug flow. Pseudo slugs are
similar to slugs but are shorter and frothier with more gas entrainment.
At the highest gas velocities, annular flow is observed. In annular flow, the gas
flows in a core containing liquid droplets in the center of the pipe, with a liquid film
flowing around the pipe circumference. In vertical annular flow, the film of liquid flowing
along the outer circumference of the pipe is uniformly spread. In horizontal flow, the liquid
film along the bottom of the pipe is slightly thicker than that flowing along the top, due to
gravitational force.
This thesis examines the phenomena of drag reduction in large diameter, horizontal,
low pressure pipelines. Experiments were conducted to test the effectiveness, measured as
the reduction in pressure gradient, of the DRA for liquid velocities between 0.03 and 1 mls
and gas velocities from 3 to 17 d s , for five DRA concentrations. This included the three
main flow regimes: stratified, slug and annular. The results of these experiments are also
compared to those in the literature.
The ability of the DRA to reduce both the surface and interfacial tension of oil,
water, and oil-water mixtures was determined. Additionally, the effect of these surface and
interfacial tension reductions, on the flow regime transitions, were analyzed.
Flow regime maps were produced for several DRA concentrations, and the results
compared to those experimentally determined by Lee (1993), for the same liquid and gas
velocities, without DRA.
The shear degradable nature of the DRA was also tested.
CHAPTER 2
PREVIOUS WORK
In this chapter, the principles of two and three phase flow will be presented,
followed by a discussion of some of the important works published in the field of drag
reduction, relevant to this study.
2.1 TWO PHASE FLOW
2.1.1 Gas-liquid two phase flow
Two-phase gas-liquid flow patterns are generally classified into three categories and
are shown in Figure 3.
Stratified flow (including smooth, wavy and roll wave) is seen at low liquid and
gas velocities and is typified by two distinct phases; liquid flowing along the bottom and
gas flowing along the top of the pipe. Intermittent flow is encountered at higher gas flow
rates and includes both plug and slug flow. These are similar to the intermittent flow
regimes seen in multiphase flow. Annular flow occurs at relatively high gas velocities and
involves a core of gas flowing through the middle of the pipe.
Experimental work has been carried out for several fluid mixtures and pipeline
diameters to determine the flow regime transitions for horizontal flow. Baker (1954)
presented a flow regime map for small diameter pipes and several fluids. Wallis and
Dobson (1973) produced a similar map using air and water in their system. Mandhane et
al. (1974) have produced the most extensive set of experimentally determined flow regime
maps. Mandhane's map is based on 1178 flow observations for a two phase air-water flow
system. Mandhane also standardized flow regime maps, plotting superficial liquid vs.
superficial gas velocities. An example of a typical flow regime map is shown in Figure 4.
Brill and Mukherjee (1984) found liquid viscosity had a large effect on the flow
regime transitions and concluded that a higher liquid viscosity tended to shrink the
stratified flow envelope in the horizontal flow map.
Taitel and Dukler (1976) proposed a physical model capable of predicting the flow
regime transitions in horizontal two phase flow. Their model is based on a mechanistic
approach and includes five dimensionless groups to account for fluid properties, pipe
diameter, pipe inclination and fluid velocities. This model is currently the most widely used
in industry.
Lin (1984) found the pipe diameter played an important role in determining the
transition from stratified to slug and stratified to annular flow. He concluded that the
transition from stratified to slug flow resulted from the growth of small waves at gas
velocities less than 3 rnls. As the gas velocity is increased, slugs form if there is sufficient
liquid in the stratified film. Pipe diameter has a large effect on this transition.
The
transition from stratified-wavy to annular flow was shown to be relatively independent of
pipe diameter.
Jepson and Taylor (1989) showed that the transitions from stratified to slug flow
occur at higher liquid velocities in larger diameter (30 cm) pipelines. The transition from
slug to annular flow was observed at lower gas velocities in the larger pipelines. They also
concluded that the results from small pipe diameters could not be easily extrapolated to
larger pipes.
2.1.2 Oil-water two phase flow
Two phase liquid-liquid flow is broadly classified into two main flow patterns:
stratified (or segregated), and mixed flow. Stratified flow consists of two distinct liquid
phases separated by an interface. In general, stratified flow is encountered at low liquid
velocities. Mixed flow is observed at higher liquid velocities, where the two liquid phases
flow fully dispersed as a homogeneous phase, with no real change in concentration within
the pipeline. A detailed explanation of the various sub-categories of stratified and mixed
flow are reported by Malhotra et. al. (1995).
Russel et al. (1959) studied flow patterns of oil-water mixtures in horizontal pipes.
The research concentrated on the input oil-water volume ratio. They found three distinct
flow patterns: bubble flow, stratified, and mixture.
Charles et al. (1961) defined four flow patterns in equal density oil (1000 kglm]) water mixtures flowing in 2.5 cm pipes: water droplets in oil, concentric water with oil
flowing in the core, oil slug in water and oil bubble in water.
Arirachakaran et al. (1989) studied the effect of five oil viscosities (4, 7, 58, 84, and
115 cp) in oil-water mixtures, with tap water as the continuous phase, in 3.75 cm
horizontal pipes. They found the effect of viscosity on flow regime transitions and flow
patterns to be small.
2.2 THREE PHASE FLOW
Lee (1993) studied three phase oil-water-gas flow with oil viscosities of 2 and 15cp
flowing in horizontal pipes. She showed that the flow patterns and flow regime transitions
in oil-water-gas three phase flow differed from those obtained in both gas-liquid and oilwater two phase systems. There was also a large effect of fluid compositions on flow
patterns and flow regime transitions in the systems she studied.
For the 2cp oil (LVT 200), slug flow occurred at lower liquid velocities in oilwater-gas three phase flow than for both water-gas and oil-gas systems. At higher oil
concentrations, annular flow appears at lower gas velocities than two phase flow.
For the 15cp oil (Arcopak90), the transition to slug flow takes place between that
for water-gas and oil-gas flow. Annular flow occurs at a lower gas velocity than in the
water-gas system.
Increasing the oil concentration in three phase flow shifts the transition to slug flow
to lower liquid velocities, and the transition to annular flow to lower gas velocities.
Lee obtained a transition to annular flow that was significantly different from that
predicted by the Taitel and Dukler model. Higher oil cuts increase both the size of the slug
and annular flow regimes. Lee also showed that the Taitel and Dukler model for gas liquid
two phase flow does not predict the effect of a second liquid phase. Lee presented a model
to predict both the total liquid and water film thicknesses for oil-water-gas, horizontal,
stratified flow.
2.3 DRAG REDUCING AGENTS
The DRA used in this study is a long-chain hydrocarbon polymer in an aqueous
medium.
The polymer generally constitutes 10% of the slurry solution.
The upper
concentration limit is set by the need to inject the DRA with relative ease, as well as obtain
a reasonable dispersion time of solution. The active ingredient is a polyalphaolefin, and
thus does not adversely affect refinery processes. The degraded oligomers fall out in gas
oil and kerosene distillate, while the oil soluble ingredients decompose into diesel and
heavier products. The water and water-soluble products are removed by a desalter (Denys,
1995).
In solution the DRA is a viscoelastic, thixotropic, time-independent, non-
Newtonian fluid. The DRA is non-reactive, non-flammable and non-combustible (Lester,
1985).
The benefits of DRA use in existing systems are increased production (without
mechanical modification), reduction of operating costs such as pumping power, reduction
of pipeline pressure while maintaining throughput, and to improve refinery handling.
Operating systems with drag reducing agents may present problems, however. The
DRA molecular structure does not generally survive the high shear forces generated by
centrihgal or positive displacement pumps. Hence, the DRA must be injected after each
pumping station. The effectiveness of the DRA depends on several factors such as oil
viscosity, pipe diameter, and flow velocity, which indicate a dependence on the Reynolds
number. Drag reduction is generally only effective in turbulent flow and improves with
decreasing viscosity and pipe diameter, or with increasing Reynolds number.
The effectiveness of the DRA also depends on the oil structure. A DRA that
produces desirable effects with a certain oil may be ineffective with another, similar oil
(Lester). The ability of the DRA to disperse in the oil is also a concern, especially for
continuous injection flowlines. The maximum benefits of drag reduction are not obtained
until the DRA is hlly dispersed in the oil. Lester (1985) suggests that a nozzle be used to
inject the DRA directly into the turbulent core of the flow. The main drawback of injection
nozzles is cost.
The precise mechanism of how the DRA works is not well established. Generally
speaking, there are two theories: it may either act by directly reducing turbulence, or
alternatively by absorbing and returning stream energy which otherwise would have been
used to create turbulent crossflows.
2.3.1 Single-Phase Drag Reduction
Drag reducing agents (DRA's) were discovered by accident by Toms (1947).
Although it had been known that water-coal and water-pulp slurries could produce lower
friction factors than those of water alone, Toms' publication was the first to discuss DRA's
in otherwise Newtonian solution. Toms discovered a decrease in pressure gradient, for a
given liquid velocity, with addition of DRA until a minimum pressure gradient was reached.
Further addition of DRA increased the pressure gradient gradually, until it exceeded that of
the original solvent.
The first use of DRA's in oil fields was to reduce pressure loss while pumping fluids
downhole into fracture tight formations. Initially, DRA's were used in quantities in excess
of 600 ppm by weight. For these concentrations, an 80% reduction in drag was observed
in single phase flow (Virk, 1975). Since that time, the effectiveness of DRA's have been
tested at lower concentrations, mainly to reduce downstream problems, e.g. separating the
DRA from the oil-water mixture.
A new generation of drag reducing agents are currently being tested.. They have a
lower viscosity and are liquid slurries as opposed to viscous gels used previously. Liquid
slurries give improved drag reduction and are easier to inject into pipelines. These DRA's
have been tested under a variety of single and multiphase flow conditions with encouraging
results (Denys, 1995).
DRA's have been tested in single phase pipelines at concentrations between 5 and
60 ppm by several researchers (Chang, 1983; Virk, 1975). Results of two typical DRA's
used to reduce pressure gradient in large diameter crude oil pipeline flow are shown in
Figure 5. A 40% reduction in drag is achieved with 10 ppm DRA. Increasing the DRA
concentration to 60 ppm results in a 55% reduction in drag (Denys, 1995).
Chang and Darby (1983) studied shear degradation effects on polyacrylarnide DRA
solutions in 0.46 cm diameter tubes, and found the DRA to both age, losing effectiveness
after a few days, and to degrade when subjected to shear. They computed friction factors
for various DRA concentrations.
The friction factor for a Reynolds number of 104
decreases from 0.004 to 0.0035 as a concentration of 100 ppm DRA degrades. The
friction factors for the fresh DRA solutions were lower than both those of the solvent
alone, and those that had been subjected to pump shear.
Chang and Meng (1987) studied hydrolyzed polyacrylamide and guar gum drag
reducers in small diameter (0.1
- 4.0 cm ID) in concentrations from
10 to 500 ppm by
weight. They found a maximum in the drag reduction obtained for both polymer solutions
in the range of 50 - 100 ppm by weight.
Virk and Baher (1970) examined the effect of Reynolds number on polyacrylamide
and polyethylene oxide drag reduction. They defined four different flow regimes: laminar,
transition, turbulent without drag reduction, and turbulent with drag reduction. The DRA
was effective only in the most turbulent flow (Re > 40,000). They also concluded that the
drag reduction was proportional to the square root of the polymer concentrations studied.
The proportionality constant is currently unknown, but is characteristic of the polymer,
solvent and possibly the pipe. Finally, they attributed the maximum drag reduction to a
maximum boundary layer thickness. This is best observed when plotted on Prandtl-von
Karmen coordinates as a correlation for the maximum drag reduction asymptote:
2.3.2 Multiphase Drag Reduction
Scott and Rhodes (1972) investigated Polyhall295, a polyacrylamide polymer drag
reducer in co-current, two phase, gas-liquid slug flow. They used water and air flowing in
2.5 cm ID pipelines. They held the liquid Reynolds number constant at 13,000 and varied
the gas Reynolds number from 1500 to 6 100.
Drag reduction can be defined as follows:
APwithout D M
% drag reduction =
-
APwith DR4
* 100
(2.3.2.1)
APwithout DRA
We can define an efficiency factor for the DRA as follows:
% drag reduction
E~~
(2.3.2.2)
s
'dra
where:
ED,
= Efficiency factor
C,
= DRA
concentration
They found two phase drag reduction to exceed that of single phase flows for the
same superficial liquid velocities.
They measured drag reductions of 29 - 33% in single phase flow for Reynolds
numbers between 7,000 and 30,000. With a knowledge of slug frequency, geometry, and
velocity, they were able to separate approximately the contribution to the pressure gradient
of liquid wall friction and slug inertial effects. The accelerational energy term in slug flow
exceeded the frictional component of the axial pressure gradient in their experiments. In all
cases, the pressure gradient due to acceleration was greater than the frictional pressure
gradient in the slug flow regime. They found a maximum of 33% drag reduction to occur
at a polymer concentration of 68 ppm by weight and concluded that the polymer was shear
degradable, losing its effectiveness after 6 residence times.
Sylvester and Brill (1976) found a polyethylene oxide DRA to be effective in
reducing pressure gradient in annular mist flow of air and water. Their experiments were
conducted in 1.27 cm I.D. stainless steel tubing at 100 psi for a wide range of gas-liquid
ratios. They studied liquid velocities from 0.04 to 0.3 mls and gas velocities of 9 and 11
rnls, respectively. At DRA concentrations of 100 ppm and the highest liquid and gas
velocities, they observed pressure gradient reductions of up to 37%.
Sifferman and Greenkorn (1981) studied drag reduction of three polymers
(carboxymethyl cellulose, polyethylene oxide, and guar gum) in three different fluid
systems: single-phase dilute polymer-water solutions, two phase liquid-solid, and threephase immiscible liquid-liquid-solid solutions. Drag reduction was observed for all three
flow systems studied. At Reynolds numbers exceeding los drag reduction of up to 80%
was achieved for the dilute polymer system at concentrations of 0.3 wt% DRA. For the
liquid-solid system, drag reduction of 95 - 98% was achieved, indicating an additive drag
reduction effect for polymer solutions with suspended solid particles.
There is a conspicuous absence of drag reduction work for three phase oil-watergas flows.
CHAPTER 3
EXPERIMENTAL SETUP
3.1 EXPERIMENTAL SETUP AND PROCEDURE
Figure 6 depicts the layout of the experimental system. 1.0 m3 of oil and 1.8 m3of
water are held in a 3.5 m3 stratifjing aluminum tank. The less dense oil is pumped from the
upper portion of the tank, while the water is drawn off the bottom. The oil is pumped by a
5 HP carbon steel Ingersoll-Dresser herringbone gear pump. The oil flow rate is controlled
by controlling the amount recycled back to the tank. The water is pumped by a IngersollRand, 3 HP carbon steel centrifbgal pump. The water flow rate is controlled using a
control valve downstream of the pump.
The oil and water then flow into respective 7.5 cm ID PVC pipelines where liquid
flow rates are measured using orifice plates. Three orifice plates were fabricated with
diameters of 1.1 1 cm, 2.06 cm, and 3.5 cm to give a range of liquid velocities from 0.03 to
1.0 rnls.
The flow rates were measured using a Cole Parrner 5-7354 Series Pressure
Transducer, which measures pressure differentials of 0 - 15 psi. The pressure transducer
was calibrated using U-tube manometers with mercury (S.G. 13.5) and Meriam 175 Blue
fluid (S.G. 1.75) as the fluids.
Following the orifice section, the oil and water are combined in a tee. The oilwater mixture then passes into a 1 m3carbon steel mixing tank where carbon dioxide gas is
introduced.
The carbon dioxide is stored in a 20 ton liquid receiver and fed to the system at a
constant pressure of 25 bar. The carbon dioxide gas pressure is then regulated and the
flow rate is measured using a Hedland flow meter. After the gas temperature and pressure
are recorded, the gas is fed into the bottom of the mixing tank, simulating the flow from an
oil well.
The three phase oil-water-gas mixture flows into a 10 cm I.D., 10 m long plexiglass
section where pressure gradient, flow distribution, flow pattern and slug characteristics
(velocity and frequency) are monitored. The multiphase mixture returns to the tank where
the oil-water mixture stratifies and recirculates, while the gas is vented out the top of the
stratifLing tank.
The test section is shown in Figure 7 and consists of a series of three, 2m long, 10
cm I.D.,plexiglass pipe sections. Pressure taps are positioned at both ends (6.6 m apart) to
measure the pressure gradient in the pipe. U-tube manometers are used with mercury
(S.G. 13.5) and Meriam 175 Blue fluid (S .G. 1.75) as the fluids. Additionally, a Computer
Instruments Corporation series 7000 Bubbler System was used to measure pressure
gradients as low as 0.03 cm of water. The test section is fitted with a sampling probe
assembly in the center. The sampling probe is a 0.016 m diameter stainless steel tube
which can be positioned along a vertical cross section of the acrylic pipe. 0.016 m
diameter vinyl tubing connects the sampling probe to an acrylic tube fitted with valves at
each end to determine the liquid composition and void fraction of the multiphase mixture.
The flow pattern and slug characteristics are determined both visually and with the aid of a
high speed video camera. The high speed camera allows slug characteristics such as slug
length, slug frequency and Froude number to be easily determined.
For the first set of experiments, a DRA solution (concentrations of 5, 10, 25, and
75 ppm, respectively) was added as a batch into the top of the mixing tank. This is
downstream of the pump to avoid high shear conditions.
A continuous injection system was also implemented for comparison with the batch
injection results. A diagram of the continuous injection system used is shown in Figure 8.
The 10 cm I.D., 1 m long acrylic pipe is filled with approximately 10 liters of a 10:1 ratio,
oil to DRA solution. 1 bar air pressure is applied to force the DRA through 0.635 cm
diameter vinyl tubing directly into the pipeline slightly downstream of the mixing tank. The
pipeline is fitted with a pressure tap, so the DRA enters the pipeline near the top pipe wall.
Interfacial and surface tension measurements were taken for all oil compositions at
each DRA concentration, as well as for h l l pipe flow of both oil and water using a CSC70545-Du Nouy tensiometer. Liquid samples were gathered to determine the composition
at the bottom of the pipe for each flow regime.
3.2 TEST MATRIX
The experiments were conducted in a horizontal oil-water-gas flow system at
atmospheric pressure and at temperatures of 20" and 50" C. LVT 200 oil was used as the
first liquid phase (viscosity of 2 and 1 cp at 20 and 50" C, respectively) and water as the
second liquid phase. Carbon dioxide was used as the gas. The DRA effectiveness was
examined for five DRA concentrations (0, 5, 10, 25, and 75 ppm) and four oil
compositions (20, 40, 60, and 80%). Additionally, experiments were conducted for hll
pipe oil and water flows, as well as two phase oil-gas annular flow.
Superficial liquid velocities between 0.03 and 1 m/s and superficial gas velocities
from 3 - 17 m/s were studied. This range of liquid and gas velocities includes three flow
regimes: stratified, slug, and annular flow. Flow regime maps were plotted for DRA
concentrations of 0, 25 and 75 ppm for oil concentrations of 25, 50, and 7596, to compare
with experimental results obtained by Lee (1993).
The drag reducing agent used in this study is white in color and has an unusually
conglomerated consistency. It has a viscosity of 200cp, and a density of 970 kg/m3and
contains a surfactant. It is more solid than liquid but disperses when oil is slowly added to
the concentrated DRA. Dispersing the DRA into oil with a stirring rod is necessary to
facilitate injection into the experimental system. The mixture must be stirred gently to
avoid shearing. Once the DRA is dispersed in oil, it flows more easily, and is therefore
well suited for continuous injection flowlines. The DRA may be stretched to lengths in
excess of 5 m without breakage. When stretched, pulling in a perpendicular direction
creates a spider web-like structure. The DRA solution can be cut easily with scissors but is
otherwise difficult to handle.
Due to the specific gravity, together with the fact that the DRA disperses in the oil
(as opposed to dissolving), it settles between the water and oil layers, given adequate time.
The DRA concentration is calculated on a total liquid volume basis as follows:
where:
V,,
= Volume
C,,
= Desired
V,
= Total
of the DRA to be added
DRA concentration (ppm)
liquid volume of the system
The shear-degradable nature of the DRA was also tested. Once the DRA was
added, the pressure gradient in the pipeline was monitored for the following 2 hours. Table
3.2 summarizes the experimental test matrix.
Table 3.2: Experimental Test Matrix
Fluids
LVT200 oil, water,
carbon dioxide gas
Liquid Velocities (mls)
0.03 - 1
Gas Velocities (mls)
3 - 17
Flow Regimes
Two-phase annular, three
phase stratified, slug, annular
Oil Compositions (%)
full pipe oil, water
DRA Concentrations (ppm)
Other Parameters
Surface tension
Interfacial tension
Shear degradation
CHAPTER 4
RESULTS AND DISCUSSION
4.1 OBSERVATIONS AND FLOW VISUALIZATIONS
The DRA used in these experiments is white and has a conglomerated consistency,
which does not flow easily. In solution it is For this reason, the DRA was mixed slowly
with oil to facilitate addition to the system.
Liquid samples were taken from the bottom of the pipe during all the experiments.
For all liquid compositions studied, the composition of the liquid at the bottom of the pipe
was 100% water. For all of the DRA concentrations studied, the oil remains in a layer at
the top of the pipe for stratified flow, and for the stratified film region between slugs in
slug flow. The liquid composition in annular flow proved difficult to monitor accurately.
4.2 BATCH INJECTION EFFECTIVENESS OF DRA
4.2.1 Single Phase Flow
Figures 9 and 10 show the pressure gradient results obtained from single phase flow
of oil and water, respectively. The DRA is effective in reducing the pressure gradient in
both cases by approximately 50%. Increasing the concentration of DRA does not reduce
the pressure gradient substantially for the single phase flow of oil or water. The results
from 5, 10, 25, and 75 ppm DRA are all similar, yielding 50% reductions in pressure
gradient from theoretical values calculated by the Blasisus smooth tube equation:
where:
f
= the Fanning friction factor
Re = the Reynolds number
p
u,
= Liquid
density
= Average liquid velocity
D = Inside
diameter of the pipeline
Figure 11 shows single phase Fanning friction factors for LVT oil. Experimental Fanning
friction factors were calculated using the following equation:
where:
AP = The measured pressure gradient
L
= The length of pipe
over which the pressure gradient was measured
The experimental Fanning friction factors were compared to those predicted by the
aforementioned Blasius equation.
The Fanning friction factors of the DRA solutions are 9-18% lower than those
predicted by the Blasius equation for smooth tubes. For example, for a Reynolds number
of 1.5*104, the friction factor predicted by the Blasius equation is 0.007 while the DRA
sample yields a friction factor of 0.0064, a 9% difference. The friction factor results from
this study are also compared to those of Chang and Darby (1983), who studied a watersoluble polyacrylarnide DRA powder. They found 30% lower friction factors of 0.005 for
the same Reynolds number. The same trend is seen for Reynolds numbers between 1.0*104
and 4.0* lo4.
4.3 TWO PHASE ANNULAR FLOW OF OIL-GAS MIXTURES
The results for annular flow using 100% LVT oil at 20C and atmospheric pressure
are now presented.
The baseline pressure gradient measurements without drag reducing agent are
shown in Figure 12. It should be noted that for a superficial gas velocity of 5 mls, wavy
stratified flow is present rather than true annular flow, where the liquid film may not reach
the top of the pipe. At a given superficial liquid velocity, the pressure gradient increases
with an increase in superficial gas velocity. In addition, the pressure gradient in the
pipeline increases, with increasing superficial liquid velocity.
Results of the annular flow regime studies are presented in Figures 13 - 16 for all
four superficial liquid velocities studied.
4.3.1 Supeficial Liquid Velocity = 0.08 mls
For a superficial liquid velocity of 0.08 d s , the range of pressure gradients is 10 to
70 Pdrn. In Figure 13, without DRA,as the superficial gas velocity is increased from 5 to
11 d s , the pressure gradient increases from approximately 22 to 67 Pdrn.
At a gas velocity of 5 d s , which is close to the wavy - annular transition, doses of
5, 25 and 75 pprn of DRA reduce the pressure gradient to approximately 6 Pdm, a
reduction of 70%.
For a gas velocity of 7 d s , the pressure gradient is reduced from 30 to 14 Pdm,
with 5 pprn of DRA,a reduction of 50%. Adding more DRA up to 75 pprn only gives a
small, additional decrease in pressure gradient. The reduction ranged from 38 to 75% with
an average of about 55%. Similar results are noted for the gas velocity of 9 d s , where the
pressure gradient is lowered from 45 to between 23 and 27 Pdrn, i.e. a range of 40 to
50%.
At the high gas velocity of 11 d s , the DRA is not so effective, reducing the
pressure gradient from 67 to between 50 and 55 Palm, a decrease of 17 to 25%. Again,
adding
more than 5 pprn of DRA does not provide substantial improvement in the
effectiveness of the D M .
At a concentration of 10 pprn DRA, the DRA does not seem to be as effective as 5
ppm.
In fact, in many cases, there are only small reductions from the baseline
measurements being noted. However, hrther addition of DRA at concentrations of 25 and
75 ppm does again begin to reduce the pressure gradient. This is also seen at the higher
liquid flowrates. The tests have been repeated several times with the same results.
4.3.2 Superficial Liquid Velocity = 0.15 m/s
The pressure gradients are higher for annular flow at a superficial liquid velocity of
0.15 m/s than for 0.08 m/s. This is due to the higher height of the liquid film. A higher
liquid film gives more contact surface area between the liquid and the pipe. The range of
pressure gradients is between 7 and 105 Pdrn for the same range of gas velocities as for
the previous liquid velocity of 0.08 m/s.
The DRA is effective in reducing the pressure gradient in the pipeline by up to 33%
for this superficial liquid velocity. The same trend as for the previous liquid velocity of
0.08 m/s is seen, namely, the DRA is more effective at lower superficial gas velocities. For
example, at a superficial gas velocity of 7 m/s, as shown in Figure 14, the pressure gradient
decreases 33% from 30 Pdrn to 20 Pdrn as 5 ppm of DRA are added. At a higher gas
velocity of 9 rnls, a reduction from 40 Pdrn to 30 Pdm, or 25%, is seen in the pressure
gradient. An increase in the gas velocity of 2 m/s results in a reduction of 8% in the
effectiveness of the DRA. At the highest gas velocity of 11 m/s, a reduction of 12%, from
85 to 75 Pdrn is achieved with the addition of 5 ppm DRA. The DRA effectiveness
decreases with increasing superficial gas velocities.
Increasing the DRA concentration does not significantly reduce the pressure loss in
the pipe for this superficial liquid velocity. Doses of 25 and 75 ppm DRA, at a gas velocity
of 7 m/s, yield pressure gradient reductions of 26 and 53%, from 34 to 25 and 16 Pdrn,
respectively. The results obtained for a dose of 5 ppm at the same gas velocity yields a
pressure gradient of 22 Pdm, a reduction of 3 5%.
For superficial gas velocities of 5, 7, and 9 d s , respectively, the DRA is most
efficient at a concentration of 5 ppm, i.e. the pressure gradient reduction per ppm DRA is
larger. For all the gas velocities studied, the results obtained for 75 ppm are slightly better
than those with 5 ppm, but the improvement is marginal.
The effectiveness of the DRA decreases as the gas velocity is increased. For
instance, addition of 5 ppm DRA for a gas velocity of 5 d s yields a 50% reduction in the
pressure gradient, from approximately 30 to 15 Pdm. For a gas velocity of 7 d s , the
pressure gradient decreases from 30 to 20 Pdrn as 5 ppm are added, a reduction of 33%.
At the highest gas velocity of 11 d s , a 13% reduction in pressure gradient is achieved with
5 ppm, from 75 to 65 Palm.
Additionally, at this high gas velocity, the reduction of
pressure gradient in the pipe does not depend on the concentration of DRA as strongly as
for lower gas velocities.
4.3.3 Superficial Liquid Velocity = 0.25 m/s
Figure 15 shows the results obtained for a superficial liquid velocity of 0.25 mls.
At a concentration of 5 ppm, for a gas velocity of 5 m/s, the pressure gradient is reduced
from 34 to 22 Palm, a reduction of 35%. For higher gas velocities of 7 and 9 rnls, pressure
gradient reductions are from 44 to 30 P d m and 73 to 60 Pdrn, respectively, i.e.
approximately 30%. Higher DRA concentrations do not yield any improvement in pressure
gradient, and in some cases are less effective. For example, at a gas velocity of 7 d s and a
DRA concentration of 75 ppm DRA, the pressure gradient is reduced from 38 to 34 Pdm,
a reduction of 10%.
Several researchers (Virk 1975; Scott, 1972; Chang, 1987) have found a maximum
in pressure gradient reduction with an increase in DRA concentration using various drag
reducers, pipe diameters and liquidtgas velocities. The DRA concentration at which the
maximum occurs depends on polymer, pipeline and fluid characteristics, but typically
occurs around 50 ppm. Adding DRA beyond that point again begins to increase the
pressure gradient. This is the trend observed for the conditions studied. In this case, the
maximum pressure gradient reduction occurs at a DRA concentration of around 5 ppm.
At the highest gas velocity studied, 11 m/s, the pressure gradient reduction is lower
than for the lower gas velocities. The reduction is from 106 to between 90 and 100 Pdm,
i.e. 6 to 15%. This is the same trend observed for the two previous liquid velocities
discussed; the DRA is less effective at hlgher superficial gas velocities.
4.3.4 SuperFicial Liquid Velocity = 0.35 m/s
The results of the 0.35 m/s superficial liquid velocity pressure gradient experiments
are presented in Figure 16. Again, a DRA concentration of 5 ppm is the most effective in
reducing the pressure gradient in the pipeline. At a superficial gas velocity of 5 m/s, a
reduction from 37 to 27 Pdm, or 2796, is achieved. For a superficial gas velocity of 7 d s ,
the pressure gradient decreases from 52 to between 30 and 42 Pdm, a range of 18 and
42%. At a superficial gas velocity of 9 d s , the reduction in pressure gradient is from 95 to
between 67 and 80 Pa/m, i.e. 16 to 30%. For a gas velocity of 11 d s , the reduction is
lower with only 7 to 23% achieved.
Increasing the DRA concentration beyond 5 ppm does not yield lower pressure
gradients in the pipeline. This confirms the trend seen with all three previous liquid
velocities studied. Table 4.3 summarizes the average pressure gradient reduction for all
conditions studied. The reduction in pressure loss decreases with increasing superficial
liquid velocity. The DRA is most effective for the lowest liquid velocity studied. The
effectiveness also decreases with an increase in gas velocity.
Table 4.3: Average Pressure Gradient Reduction in
Two - Phase, Oil-Gas Annular Flow
Superficial Liquid
5 PPm
10 PPm
25ppmDRA
75ppm
Velocity ( d s )
DRA
DRA
0.08
25%
15%
20%
25%
0.15
22%
10%
18%
22%
0.25
19%
5%
5%
10%
0.35
15%
0%
0%
5%
DRA
4.4 MULTIPHASE FLOW
4.4.1 STRATIFIED FLOW REGIME
The results for the stratified flow regime are shown in Figures 17 - 24 for
superficial liquid velocities of 0.03 and 0.1 1 m/s, respectively.
4.4.1.1 Superficial Liquid Velocity = 0.03 m/s
For an oil composition of 20% and a superficial gas velocity of 4 mls, the pressure
gradient decreases 36%, from 11 to 7 Pdrn, as 5 pprn DRA are added, as shown in Figure
17. For a higher gas velocity of 7 m/s, the pressure gradient reduction is 50%, from 14 to
7 Palm. The DRA is effective at a concentration of 5 pprn for this flow regime, liquid
velocity, and oil cut.
The pressure gradient reduction increases as more DRA is added. The results for a
concentration of 10 pprn DRA and a superficial gas velocity of 4 m/s are better than those
with 5 pprn DRA, reducing the pressure gradient from 11 to approximately 6 Pdm, i.e.
45%. At a higher superficial gas velocity of 7 mls, the reduction is 5796, from 14 to 6
Pdrn.
Further increasing the DRA concentration to 25 pprn results in lower pressure
gradients than with either 5 or 10 ppm. For the same superficial gas velocities of 4 and 7
rnls, the pressure gradient reductions with 25 pprn are from 11 to 3 Pdrn, and 14 to 2
Pdrn, reductions of 72 and 85%, respectively.
At the highest DRA concentration of 75 ppm, the pressure gradient values are
similar to those obtained with 25 ppm, with reductions of 70%, from 11 to 3 Pdm, for a
gas velocity of 4 m/s. The percent drag reduction for each superficial gas velocity and
DRA concentration is summarized in Table 4.4.
Table 4.4.1.1: Average Pressure Gradient Reduction in Stratified Flow,
20% Oil, Vsl = 0.03 m/s
DRA Concentration (ppm)
Vsg = 4 m/s
v s g = 7 m/s
5
3 6%
50%
10
45%
57%
25
70%
85%
75
70%
85%
Figure 18 depicts the results for an oil composition of 40%. Addition of 5 and 10
ppm DRA have little effect on the pressure gradient in the pipeline. The pressure gradient
for these DRA concentrations remain at 13 and 16 Palm, respectively, for superficial gas
velocities of 3 and 5 m/s. Increasing the DRA concentration to 25 ppm for a superficial
gas velocity of 3 m/s reduces the pressure gradient by 50%, from 10 to 5 Palm. At a
higher gas velocity of 6 d s , an 80% reduction in pressure gradient is achieved, from 14 to
3 Palm.
Further increasing the DRA concentration from 25 to 75 pprn does not substantially
reduce the pressure gradient. The pressure gradient reduction remains at approximately
80%.
A higher oil composition of 60% is presented in Figure 19. As was observed in the
previous oil composition of 40%, 5 pprn of DRA do not decrease the pressure gradient in
the pipe. Adding 10 pprn DRA, however, does reduce the pressure gradient 30%, from 10
to 7 P d m at a superficial gas velocity of 3 m/s. At a higher gas velocity of 5 mJs, a
reduction of 28%, from 7 to 5 Pdm, in pressure gradient, is achieved. Further addition of
DRA to 25 pprn does not reduce the pressure gradient beyond the 10 pprn values. The
highest dose of 75 pprn DRA yields an average 55% reduction in pressure gradient. At a
superficial gas velocity of 3 m/s, a reduction of 70%, from 10 to 3 Pdrn is achieved. At a
gas velocity of 6 mls, a reduction from 7 to 4 Pdm, i.e. 43% is attained. This is similar to
the trend observed for an oil composition of 40%, higher DRA concentrations are need for
higher oil cuts.
For 80% oil, as shown in Figure 20, 5 pprn are again ineffective in reducing the
pressure gradient.
Addition of 10 pprn DRA, however, does yield an average 57%
reduction in pressure gradient. At a superficial gas velocity of 3 d s , the pressure gradient
is reduced 60%, from 15 to 6 Pdm. At a higher gas velocity of 5 m/s, the reduction is
from 12 to 5 Pdm, i.e. 58%.
Addition of 25 pprn DRA fbrther reduce the pressure gradient to 4 and 3 Pdm, for
superficial gas velocities of 3 and 5 m/s, respectively. This is a reduction of 73 and 75%,
respectively, in pressure gradient.
The pressure gradient reduction remains at
approximately 75% as the DRA concentration is increased from 25 to 75 ppm.
Table 4.4.1.2: Average Pressure Gradient Reduction in Stratified Flow,
80% Oil, Vsl = 0.03 m/s
DRA Concentration (ppm)
Vsg = 4 d s
Vsg = 7 mls
5
OYo
0%
10
60%
57%
25
73%
75%
75
75%
75%
An increase in the effectiveness of the DRA is observed at an approximate gas
velocity of 5 rnls. This is the beginning of the transition to annular flow and the liquid film
begins to spread evenly around the inside circumference of the pipeline. The decrease in
the pressure gradient at the beginning of the transition to annular flow implies that the
DRA has more of the pipe wall to act upon. For low oil compositions, the difference in
pressure gradient between the 0 and 5 ppm DRA is significant. This shows that the DRA is
effective at low concentrations for low oil compositions. This is unusual since the DRA is
generally considered oil soluble. However, a surfactant is present which reduces the
interfacial tension between the oil and water layers, allowing the DRA to disperse in the
water phase.
For higher oil percentages, the DRA is only effective at concentrations of 10 pprn
and above.
4.4.1.2 Superficial Liquid Velocity = 0.11 mls
The general trend of decreasing pressure gradient with increasing superficial gas
velocity for a superficial liquid velocity of 0.11 m/s is the same as for the previous
superficial liquid velocity for each oil composition. These trends are shown in Figures 21 24. The decrease in pressure gradient at high gas velocities is sharper for a liquid velocity
of 0.11 m/s than for 0.03 m/s. For example: comparing Figures 18 and 22 for 40 % oil at
25 pprn DRA and a gas velocity of 3.5 d s , the pressure drop increases 40%, from 4 to 7
P d m as the superficial liquid velocity increases from 0.03 to 0.11 d s . Increasing the liquid
velocity again increases the height of the liquid film, resulting in larger pressure gradients.
At an oil composition of 20% and a superficial gas velocity of 3 m/s, the pressure
gradient reduction between 0 pprn and 5 pprn DRA is 35%, from 17 to 11 Pdm, as seen in
Figure 21. At a higher gas velocity of 5 m/s, a reduction of 45%, from 17 to 9 Palm, is
observed. Increasing the DRA concentration to 10 and 25 pprn have little effect on the
pressure gradient in the pipeline. The pressure gradient reduction remains at 35 - 40% for
both DRA concentrations and gas velocities. The highest DRA concentration of 75 pprn
yields the lowest pressure gradients. A reduction of 53%, from 17 to 8 Pdm, is observed
for a superficial gas velocity of 3 m/s. At a gas velocity of 5 m/s, the pressure gradient
reduction is 73%, from 15 to 4 Pafm.
Table 4.4.1.3: Average Pressure Gradient Reduction in Stratified Flow,
20% Oil, Vsl = 0.11 m/s
DRA Concentration (ppm)
Vsg = 3 d s
vsg = 5 d s
5
3 5%
45%
10
3 5%
40%
25
3 5%
40%
75
53%
85%
Another trend observed is the increase in the effectiveness of the DRA with an
increase in superficial gas velocity. At gas velocities above 4 d s , the DRA effectiveness
suddenly increases. For example, at a gas velocity of 4 m/s and a DRA concentration of 5
ppm, the pressure gradient is reduced from 16 to 11 Pdm, a reduction of 3 1%. At a higher
gas velocity of 7 mls for the same DRA concentration, the reduction is from 16 to 7 Palm,
a reduction of 56%. This increase in effectiveness is seen for all DRA concentrations
studied for the given conditions. The effect is most obvious for a DRA concentration of 10
ppm, where a sharp decrease in the pressure gradient is seen at as the superficial gas
velocity is increased beyond 4 mls. The effectiveness of the DRA increases from 43% (16
to 7 P d m reduction) to 87% (from 15 to 2 Pdrn), as the superficial gas velocity increases
from 4 to 6 d s . This indicates that the DRA is acting in the region near the wall. At a
superficial gas velocity of 4 d s , the stratified flow regime is observed. As the gas velocity
is increased to 6 d s , a transition to annular flow begins to occur. This means that the
liquid in the pipe begins to spread evenly around the circumference of the pipeline, leaving
a core of gas (and hence less liquid) in the middle of the pipeline. Since the contact area
between the liquid and the pipe wall is increased, and the pressure gradient decreases, we
conclude that the DRA acts in the region near the wall for these flow conditions.
At an oil compositions of 40%, the pressure gradient reduction between 0 pprn and
5 pprn DRA concentrations is 35%. This agrees with the trend seen in Figures 17 and 18
for a superficial liquid velocity of 0.03 d s and the same oil compositions. Figure 17
shows that both 25 and 75 pprn DRA have an average pressure gradient of 4 Palm for the
range of gas velocities studied. Figures 21 and 22 show slightly higher pressure gradients
for the same oil compositions, due to the higher liquid flow rate. 5, 10, and 25 pprn DRA
are equally effective in reducing the pressure gradient, with an average reduction of 30%.
A hrther increase in DRA concentration, up to 75 ppm, results in the lowest pressure
gradients, with a reduction of 60%. A concentration of 5 pprn DRA is effective for low oil
cuts. The DRA is more effective for 20 and 40 % oil than for 60 and 80% oil.
For high oil cuts of 60 and 80%, there is no difference between 0 and 5 pprn DRA,
as seen in Figures 23 and 24, respectively. DRA concentrations of 10 ppm, and above, do
reduce the pressure gradient by approximately 50%. For higher oil compositions, a higher
concentration of DRA is necessary to reduce the pressure gradient noticeably. The DRA is
more effective for 20 and 40% oil than for 60 and 80% oil. This confirms the trend seen in
Figures 21 and 22 for the previous liquid velocity of 0.03 d s .
The general trend for the four liquid compositions and every DRA concentration
studied is a decrease in pressure gradient with an increase in gas velocity. This is due to a
decrease in the liquid film height in the pipe. The decreased liquid film height decreases the
contact surface area between the fluid and the pipe wall. Less contact area between the
fluid and pipe results in less friction, and hence lower pressure gradients. For example, in
Figure 17, for a DRA concentration of 75 ppm and 20% oil, the pressure gradient
decreases from 8 Palm to 2 Palm as the superficial gas velocity increases form to 6 mls.
This trend is seen for all DRA concentrations.
4.4.2 SLUG FLOW REGIME
Results of the slug flow pressure gradient measurements are shown in Figures 25 29.
4.4.2.1 Superficial Liquid Velocity = 0.28 mls
The pressure gradients range fiom 250 to 475 Palm in the slug flow regime at this
superficial liquid velocity. In general, an increase in the gas velocity increases the pressure
gradient.
This trend is seen for all oil compositions studied. The pressure gradient
reduction seen in stratified flow is not as noticeable in slug flow. As seen in Figure 25, the
pressure gradient for a superficial gas velocity of 3 d s and 0 ppm DRA is between 320
and 400 Palm. Addition of 5 ppm DRA reduces the pressure gradient to between 3 10 and
380 Palm, i.e. 3-5%. At a higher superficial gas velocity of 4 d s , similar pressure gradient
reductions are observed, with values fiom 350 - 420 Palm for 0 ppm DRA and 340 - 420
Palm for 5 pprn DRA, a maximum reduction of 3%. Addition of 10 pprn DRA for the
same superficial gas velocities does not improve the pressure gradient reduction.
Adding 25 pprn DRA reduces the pressure gradient for the lower superficial gas
velocity of 3 d s to between 270 and 330 Pdm, a reduction of 13%. At a higher
superficial gas velocity of 5 d s , 25 pprn are not so effective, with no reduction in pressure
gradient being noted. 75 pprn DRA reduce the pressure gradient in the pipeline to between
250 and 305 Palm, a reduction of 19-20%. At a higher superficial gas velocity of 5 d s ,
the reduction is 25 - 27%, to between 255 and 3 15 Pdm.
Figure 26 shows an oil composition of 40%, with similar reductions in pressure
gradient. For a superficial gas velocity of 3 mls, the pressure gradient is reduced from
between 440 and 540 P d m to between 350 and 430 Pdm, or 20%, as 5 pprn DRA are
added. A higher superficial gas velocity of 5 d s shows reductions of 16 - 19% for 5 pprn
DRA, from between 340 and 410 Pdrn to 275 - 345 Pdm. Addition of 10 pprn DRA
hrther reduce the pressure gradient to between 330 and 390 Pdrn (25 - 28%) for a
superficial gas velocity of 3 mls and to between 220 and 280 (32 - 35%) for a superficial
gas velocity of 5 d s . DRA concentrations of 25 and 75 pprn could not be tested for this
oil composition and flow regime, due to the suppression of slug flow caused by the DRA.
This will be discussed fbrther in Section 4.5.
The DRA is not as effective in slug flow due to the accelerational (as opposed to
frictional) pressure loss.
Since the DRA acts by decreasing fnction in the pipeline,
accelerational pressure gradients of slug flow are unaffected. The DRA does have a
positive affect on the flow, even though it does not reduce the pressure gradient in slug
flow as much: it shifts the flow regime transition from stratified to slug flow to higher
liquid velocities. This important aspect of the DRA action is discussed in detail in Section
4.5.
4.4.2.2 Superficial Liquid Velocity = 0.56 mls
The general trend of increasing pressure gradient with an increase in superficial gas
velocity is the same for 0.56 rnls liquid velocity as it was for a 0.28 m/s. This is confirmed
in Figures 27 - 29. There is no significant reduction in pressure gradient observed for any
of the DRA concentrations studied. Oil compositions of 20, 40 and 60% were tested, with
suppression of slug flow again occurring at the highest oil composition of 80%. Again, the
accelerational pressure loss in slug flow is largely unaffected by the DRA, which acts to
reduce friction.
4.4.3 ANNULAR FLOW REGIME
Results of the 3-phase oil-water-gas annular flow regime studies are presented in
Figures 30 - 37 for superficial liquid velocities of 0.06 and 0.28 m/s conducted at 20C and
atmospheric pressure.
4.4.3.1 Superficial Liquid Velocity = 0.06 m/s
An increase in gas velocity causes an increase in pressure gradient in the pipe for all
liquid compositions studied in the annular flow regime. The range of pressure gradients is
the same for each percentage of oil; between 10 and 100 Palm.
Figure 30 shows that for 20% oil and 0 pprn DRA,the pressure gradient increases
from 45 to 80 Pdrn as the gas velocity is increased from 10 to 14 d s . Addition of 5 pprn
DRA reduces the pressure gradient by an average of lo%, to values between 30 and 70
Pa/m, for the same range of superficial gas velocities. For a superficial gas velocity of 10
d s , addition of 10 pprn DRA fbrther reduce the pressure gradient in the pipeline to 26
Pafm and to 60 Pdrn for a gas velocity of 14 mls, reductions of 42 and 25%, respectively.
Addition of 25 pprn DRA does not fbrther reduce the pressure gradient for any superficial
gas velocity. At a superficial gas velocity of 10 d s , 75 pprn DRA do not reduce the
pressure gradient beyond the 25 pprn values. 75 pprn are effective, however, in reducing
the pressure gradient to 48 Pdrn (40%) at the highest superficial gas velocity of 14 d s .
This represents a 15% improvement over the 25 pprn values.
Figure 3 1 shows the pressure gradient in the pipe for an oil cut of 40%. For a
superficial gas velocity of 10 d s and 5 pprn DRA,a 19% reduction, from 48 to 39 Pdrn
is seen. For a higher superficial gas velocity of 13 d s , the reduction in pressure gradient is
greater, at 38%, from 108 to 67 Pdrn. Increasing the DRA concentration to 10 pprn
hrther reduces the pressure gradient to 27 Pdrn (44%) for 10 d s , and 60 Pa/m (44%) for
a superficial gas velocity of 13 d s .
There is no additional decrease in pressure gradient
at the higher DRA concentrations of 25 and 75 ppm. The magnitude of the pressure
gradient for 40% oil is the same as for 20%. The reduction in pressure gradient, however,
is greater for 40% than for 20%. This is best illustrated by the difference between 0 and 5
pprn DRA. At a 40% oil cut and 5 pprn DRA, a 20% reduction is observed in pressure
gradient.
The same conditions with 20% oil, results in a 10% decrease in pressure
gradient.
Results of the 60% oil experiments are shown in Figure 32.
For a DRA
concentration of 5 pprn and a superficial gas velocity of 10 d s , the pressure gradient
decreases from 48 to 42 Pdrn (13%). A higher gas velocity of 14 d s results in a 15 - 25%
decrease in pressure gradient, from between 93 and 109 Pdrn to 78 P d m . Increasing the
DRA concentration to 10 pprn results in a hrther decrease in pressure gradient. At a
superficial gas velocity of 10 d s , a reduction of 38%, from 48 to 30 Pdrn is observed. At
14 m/s gas velocity, a 19 - 3 1% reduction in pressure gradient is seen, from between 109
Palm to 75 Palm. The pressure gradient at a DRA concentration of 25 pprn and a
superficial gas velocity of 10 d s is 50% lower than the 0 pprn values, at 24 Pdm. A
higher superficial gas velocity of 14 m/s yields a 29 - 39% decrease in pressure gradient, to
a value of 66 Pdrn. A hrther increase in DRA concentration to 75 pprn does not decrease
the pressure gradient beyond the 25 pprn values.
For 80% oil, depicted in Figure 33, there is little pressure gradient reduction for 5,
10 or 25 pprn DRA. 75 pprn DRA, however, do decrease the pressure gradient by 27%,
from 33 to 24 Pdm, at a superficial gas velocity of 10 d s . A higher superficial gas
velocity of 14 d s yields a reduction in pressure gradient from 81 to 55 Pa/m, i.e. 32%.
For this oil composition, only the highest DRA concentration of 75 pprn is effective in
reducing pressure gradient in the pipeline.
4.4.3.2 Superficial Liquid Velocity = 0.28 m/s
The pressure gradients are higher for annular flow at a superficial liquid velocity of
0.28 rnls than for 0.06 m/s by a factor of two. The range of pressure drop is between 20
and 200 Palm for the same range of gas velocities. This is because the height of the liquid
film is greater, causing more contact surface area between the fluid and the wall, creating
more frictional pressure loss.
Figure 34 shows an oil cut of 20%. For a superficial gas velocity of 14 mls, 5 pprn
DRA reduce the pressure gradient lo%, from 210 to 190 Pdm. There is reduction in
pressure gradient to 125 Pdm, or 40%, as 10 pprn DRA are added. The reduction in
pressure gradient remains at 40%, however, after hrther addition of 25 and 75 pprn DRA.
Increasing the oil composition to 40%, as shown in Figure 35, for a DRA
concentration of 5 pprn DRA and a superficial gas velocity of 9 m/s, yields a 41%
reduction in pressure gradient, from 85 to 50 Pdm. For a higher gas velocity of 11 m/s a
43% reduction in the pressure gradient is observed, from 140 to 80 P d m . There is no
hrther reduction in the pressure gradient in the pipe as more DRA is added, up to 75 ppm.
The values for the pressure gradient as the concentration is increased from 5 to 75 pprn
DRA remain the same, at a 40 - 45% reduction.
Further increasing the oil composition of the liquid mixture to 60%, as shown in
Figure 36, reduces the effectiveness of the DRA at low DRA concentrations. This is the
same trend seen in Figure 32 for a superficial liquid velocity of 0.06 rnls and 60% oil. 5
pprn DRA do not decrease the pressure gradient in the pipeline. Addition of 25 ppm,
however, do decrease the pressure gradient from 75 to 58 Pdrn, or 23%, for a superficial
gas velocity of 10 m/s. A higher gas velocity of 13 m/s yields a 10% reduction in pressure
gradient, from 105 to 95 Pdm.
At an oil cut of SO%, as shown in Figure 36, there is a reduction in pressure
gradient only for the highest DRA concentration of 75 ppm. 5, 10 and 25 ppm DRA have
little effect on the pressure gradient. At a DRA concentration of 75 ppm, the pressure
gradient for a superficial gas velocity of 9 m/s is reduced 26%, fiom 57 to 42 Pdm. At a
higher superficial gas velocity of 11 m/s, a reduction of 16%, from 81 to 68 Pdrn is
achieved.
Table 4.4: Average Pressure Gradient Reduction in Three-phase Annular Flow
Liquid Velocity
5 PPm
10 PPm
25 PPm
75 PPm
0.06
6%
22 %
24%
25.1 %
0.28
15 %
18 %
18%
NA
(mls)
4.5 FLOW REGIME MAPS
Flow regime maps were determined for three liquid compositions (25, 50 and 75 %
oil) at DRA concentrations of 25 and 75 ppm. These flow regime maps are compared with
those experimentally obtained by Lee (1993) for the same liquid compositions without
DRA. The flow regime maps without DRA are shown in Figures 38 - 40, and those with
DRA in Figures 4 1 - 46.
The most important difference observed with DRA, which is valid for each
percentage of oil, is that the transition to the slug flow regime occurs at a higher liquid
velocities. As shown in Figure 38- 40 without DRA, transition to the slug flow regime
occurs for superficial liquid velocities above 0.22 m/s for the three liquid compositions
studied. Adding 25 ppm DRA shifts the transition to the slug flow regime to higher
superficial liquid velocities. With 25 ppm DRA, slug flow occurs at liquid velocities above
0.3 m/s for 25 and 50% oil, and above 0.5 m/s for 75% oil. Increasing the DRA
concentration hrther to 75 ppm (Figures 44 - 46) shifts the transition to slug flow hrther
to values above 0.5 m/s for 25 and 50% oil, and to 0.56 mls for 75% oil. This represents a
two-fold increase in superficial liquid velocity, without a transition to slug flow. The DRA
also affects the transitions to plug and pseudo-slug flow regimes, which occur at higher
superficial liquid velocities.
Due t o the higher liquid film height associated with a higher superficial liquid
velocity, the suppression of slugs is not as pronounced for the higher liquid velocity of 1
m/s as for 0.5 m/s. For this superficial liquid velocity it is possible to get slug flow for 20,
40, and 60% oil. Suppression of slugs is seen for a liquid velocity of 1 m/s, but only at the
highest oil cut of 80%. The presence of DRA in the liquid suppresses slug production for
the high oil cuts.
The shift in the transition to slug flow may be due to the surfactant present in the
DRA solution. A reduction in the surface tension of the oil and water allows the liquid film
to spread more easily around the circumference of the pipe. This allows a larger cross
sectional area for the gas to flow through, which lowers the actual velocity of the gas. A
lower actual gas velocity is less likely to develop roll waves in the liquid, which eventually
would propagate into slug flow.
Comparing Figures 38 - 40 with Figures 41 - 46, the presence of DRA does not
affect the gas velocity values of the flow regime transitions. For all oil compositions and
all DRA concentrations studied, the annular flow transition occurs at gas superficial gas
velocities between 8 and 10 m/s. This result agrees with those obtained by Lee (1993)
without DRA. The transition from slug flow to the pseudo slug flow regime occurs at
superficial gas velocities between 4 and 5 m/s for superficial liquid velocities above 0.3 d s ,
for 0, 25, and 75 ppm D M . Plug flow is seen for all oil compositions and all DRA
concentrations for superficial gas velocities between 1 and 2 m/s, again agreeing with Lee.
Slug flow is a flow regime in which the pressure gradient is very high. Reducing
the range of liquid velocities, for which slug flow exists, would result in lower pipeline
pressure gradients. Concentrations of 25 ppm DRA allow up to 0.5 m/s of liquid to flow
in the stratified regime, while only 0.22 m/s are obtained without DRA. This increase in
superficial liquid velocity, without a transition to slug flow, is valid for all three liquid
compositions studied.
4.6 CONTINUOUS INJECTION
Results of the continuous injection experiments are shown in Figures 47 and 48.
The drag reduction achieved with the continuous injection experimental setup is similar to
that obtained with the batch injection experiments. This shows that the drag reduction is
independent of injection method, batch or continuous, for the conditions studied. This is
usehl information for industrial situations where batch injection is either not possible, or
not economical. Continuous injection of the DRA is the most preferred method used in
industry today.
4.7 INTERFACIAL AND SURFACE TENSION
The results of the interfacial and surface tension experiments are presented in
Figures 49 and 50.
4.7.1 Surface Tension
As shown in Figure 49, the DRA is effective in reducing the surface tension of
water, even at low concentrations. Addition of 5 ppm DRA decrease the surface tension
from 68.9 to 46 dyneslcm, a reduction of 33%. Increasing the DRA concentration to 10
ppm further reduces the surface tension by 27%, an overall reduction of 51% from the 0
ppm values. For 75 ppm D R . a 60% reduction in surface tension was observed.
The DRA is effective in reducing the surface tension of LVT 200, as seen in Figure
50. Increasing the DRA concentration from 0 to 5 ppm results in a 2% decrease in the
surface tension from a value of 29.4 to 28.8 dyneslcm. As the concentration of DRA in
increased to 10 and 25 ppm, respectively, the surface tension continues to decrease to
values of 27.3 (7%) and 26.4 dyneslcm (lo%), respectively.
At the highest DRA
concentration of 75 ppm, surface tension reductions of up to 12% were obtained, to a
value of 25.6 dyneslcm.
The difference in DRA effectiveness between oil and water may help explain the
trend seen in the stratified flow regime, where the DRA is more effective for lower oil
percentages. This effect is also shown in Figures 9 (full pipe oil flow) and 10 (full pipe
water flow) where the reductions in pressure gradient are greater for the water than for the
oil.
A reduction in the surface tension of the oil, with the addition of DRA, may be a
contributing factor in explaining the mechanism of DRA drag reduction. A reduction in the
surface tension allows the liquid film to spread out, allowing more gas to flow through the
pipe. This spreading out of the liquid film resembles annular flow.
Table 4.7.1: Surface Tension of Oil and Water
Fluid
Concentration of DRA
(PP~)
Surface Tension
(dyneslcm)
water
water
water
water
water
LVT 200
LVT 200
LVT 200
LVT 200
LVT 200
4.7.2 Interfacial Tension
The effect of the DRA on the interfacial tension, between the oil and water phases, is
significant at low DRA concentrations with reductions obtained of up to 40 % for 5 ppm
DRA. However, hrther addition of DRA does not yield significant differences in the
results. A concentration of 10 ppm yields a 45% reduction in the pressure loss. Adding 75
ppm of DRA reduces the interfacial tension between the oil and water phases by a hrther
7%. This trend is verified in the pressure loss results, obtained in stratified and annular
flow, where 5 ppm is almost as effective as 10, 25, or 75 ppm.
Table 4.7.2: Interfacial Tension for LVT Oil - Water Mixtures
Concentration of DRA
Interfacial Tension
4.8 SHEAR DEGRADATION OF THE DRA
The shear-degradable nature of the DRA was tested. Once the DRA was added,
the pressure gradient in the pipeline was monitored for the following 2 hours. Figures 51
and 52 show that the effectiveness of the DRA for both 5 and 75 ppm DRA is time
dependent, i.e. it does degrade with time when subjected to shear from the pump. This is
illustrated on a microscopic level in Plates 1 - 3 . Plate 1 shows the fresh, pure DRA long
chain molecules. Plate 2 shows a sample of 25 ppm DRA after use in the system for 2
hours. The DRA no longer has a long chain structure. Instead, it is broken into very small
pieces. The same effect is observed in Plate 3 for a DRA concentration of 75 ppm. The
sample was again subjected to pump shear for 2 hours, then photographed. The DRA is
seen as small bits, with virtually no structure. After shear degradation, the polymer is no
longer a long chain molecule, but chopped into small pieces as seen in Plates 2 and 3.
Figure 5 1 shows the pressure gradient with time for a superficial gas velocity of 5
m/s and liquid velocity of 0.35 m/s at a DRA concentration of 5 ppm. The DRA reduces
the pressure gradient from 41 to 26 Pa/m. This pressure gradient remains constant for 10
to 15 minutes and then begins to increase with time. After approximately 40 minutes, the
initial pressure gradient of 4 1 Pa/m is again obtained.
At a concentration of 75 ppm, the DRA reduces the pressure gradient from 41 to
24 Pafm. The pressure gradient increases to its original value after approximately 60
minutes. The rate of increase is slower for a concentration of 75 ppm DRA than for the 5
ppm dose.
Once the liquid has flowed through the pump, the DRA begins to lose its
effectiveness. Calculations show that, after approximately 10 residence times (or ten times
through the pump), the DRA is virtually ineffective, and the pressure gradient returns to
the original 0 ppm values. The pump was turned off and the system left for 24 hours.
When restarted, the pressure gradient remained at the original value of 41 Palm. This
indicated that the DRA did not reformulate and was no longer effective.
The above agrees with the results obtained by several other researchers (Chang and
Darby, 1983) on similar drag reducing agents. The long chain polymers that act to reduce
turbulence are thought to be sheared in the pump and rendered ineffective. For this reason,
it is critical that the DRA be added to the system downstream of any high-shear conditions,
such as pumps or pumping stations.
CHAPTER 5
CONCLUSIONS
1. The DRA is effective in reducing pressure gradients in both full pipe oil and water flows
by up to 50%. 5 pprn are nearly as effective as 75 pprn in full pipe flow pressure gradient
reduction. Additionally, the friction factors in full pipe oil flow are lower than those
predicted by the Blasius equation.
2. The DRA is effective in reducing pressure gradients in two phase flow of oil and water
by up to 70%. The DRA is more effective for lower superficial liquid velocities. 5 pprn
DRA are nearly as effective as 75 pprn in reducing pressure gradients.
3. The DRA effectively reduces pressure gradient in stratified flow by up to 50%. 5 pprn
DRA are effective for low oil cuts of 20 and 40%. Higher oil cuts require higher DRA
concentrations for effective drag reduction.
4. In three-phase oil-water-gas annular flow, the DRA reduces pressure gradients by up to
25% at a concentration of 25 pprn for low oil cuts of 20 and 40%.
5. The DRA is more efficient in reducing the pressure gradient in stratified and annular
flow than in slug flow, due to the accelerational nature of slug flow pressure loss.
6. The DRA's effectiveness is independent of injection method, batch or continuous.
7. Suppression of the slug flow regime occurs with 25 pprn DRA for 25, 50, and 75% oil,
allowing the liquid flow rate to double without a transition to slug flow.
8.
The DRA reduces the surface tension of water and LVT oil by 60% and 15%,
respectively.
9. The DRA reduces the interfacial tension of oil-water mixtures up to 52%.
10. The DRA is shear degradable and loses its effectiveness after having circulated through
the pump more than two or three times.
Figure 1: Multiphase Flow Patterns
Bubble Flow
Smooth Stratified
Wavy Stratified
Rolling Wave
Plug Flow
Slug Flow
Annular Flow
Figure 3: Gas-Liquid Two Phase Flow Patterns
SMOOTH
STRATIFIED
- - \-STRATIFIED
WAVY
ROLLING
WAVE
PLUG
FLOW
SLUG
FLOW
ANNULAR
1
-
Slug
2
4
Superficial Gas Velocity (mls)
3
Stratified
5
6
Slug
Pseudo
7
8
Figure 4: Typical Flow Regime Map
Horizontal Multiphase Flow
9 1 0
H
-
I
4
C
L
C
V
e
Y
D
U
U
I
I
E
A. Water-oil separator
B. Liquid-gas mixing
tank
C. Pump
D. Orifice plate
E. 7.5cm ID PVC pipe
F. 1Ocm ID plexiglass
pipe
G. Gas feed
H. Gas outlet
F
Figure 6: Layout of the Experimental System
b
B
IG
A. Pressure Taps
B. Phase Composition Sampling
Tube Assembly
C. Waste Tarik
FLOW
DIRECTION
Figure 7: Test Section
Theorcncal
dP
0
5P P ~
0
10P P ~
+
Superficial Liquid Velocity (mls)
25 P P ~
A
75 P P ~
Figure 10: Full Pipe Pressure Gradient
100% Water
v
0 PPm
0
5 ppm
10 ppm
Superficial Gas Velocity (mls)
25 ppm
75 ppm
Figure 15: Annular Pressure Gradient
100% LVT Oil, Vsl = 0.25 m/s
'I
0 PPm
0
5 PPm
10 ppm
Superficial Gas Velocity (mls)
25 ppm
75 ppm
Figure 16: Annular Pressure Gradient
100% LVT Oil, Vsl = 0.35 m/s
Superficial Gas Velocity (mls)
Figure 17: Stratified Pressure Gradient
20% Oil, Vsl = 0.03 mls
0 ppm DRA
5P P ~
0
~ O P P ~
+
Superficial Gas Velocity (mls)
Z ~ P P ~
Figure 18: Stratified Pressure Gradient
40% Oil, Vsl = 0.03 m/s
0 ppm DRA
0
S P P ~
0
10 P P ~
+
Superficial Gas Velocity (mis)
25 P P ~
A
75 P P ~
Figure 19: Stratified Pressure Gradient
60% Oil, Vsl = 0.03 rnls
OppmDRA
0
S P P ~
0
10 P P ~
+
Superficial Gas Velocity (mls)
25ppm
A
75ppm
Figure 20: Stratified Pressure Gradient
80% Oil, Vsl = 0.03 m/s
OPP~DRA
0
5P P ~
0
10 P P ~
+
Superficial Gas Velocity (mls)
25ppm
Figure 21 : Stratified Pressure Gradient
20% Oil, Vsl= 0.11 mls
OPP~DRA
0
5P P ~
0
~ O P P ~
+
Superficial Gas Velocity (mls)
Z ~ P P ~
A
75 P P ~
Figure 22: Stratified Pressure Gradient
40% Oil, Vsl = 0.1 1 mls
OppmDRA
0
S P P ~
0
10 P P ~
+
Superficial Gas Velocity (mls)
25 P P ~
A
~ S P P ~
Figure 24: Stratified Pressure Gradient
80% LVT Oil, Vsl = 0.11 m/s
OPP~DRA
0
5P P ~
0
10 P P ~
+
Superficial Gas Velocity (mls)
25ppm
A
75 P P ~
Figure 25: Slug Plow Pressure Gradient
20% Oil, Vsl = 0.28 m/s
Superficial Gas Velocity (mls)
Figure 26: Slug Flow Pressure Gradient
40% Oil, Vsl = 0.28 mls
Superficial Gas Velocity (mls)
Figure 27: Slug Flow Pressure Gradient
20% LVT Oil, Vsl = 0.56 mls
OPP~DRA
0
5P P ~
0
10 P P ~
+
Superficial Gas Velocity (mls)
25 P P ~
A
75 P P ~
Figure 29: Slug Flow Pressure Gradient
60% Oil, Vsl = 0.56 m/s
Superficial Gas Velocity (mls)
Figure 30: Annular Pressure Gradient
20% Oil, Vsl = 0.06 m/s
6
OPP~DRA
7
0
8
10
11
S P P ~
0
10P P ~
+
Superficial Gas Velocity (mls)
9
25ppm
12
13
A
75ppm
14
Figure 33: Annular Pressure Gradient
80% Oil, Vsl = 0.06 mls
15
H i
to-i
•
OPP~DRA
0
5P P ~
0
10 P P ~
+
Superficial Gas Velocity (mls)
25 P P ~
A
75ppm
Figure 36: Annular Pressure Gradient
60% Oil, Vsl = 0.28 m/s
Superficial Gas Velocity (mls)
Figure 37: Annular Pressure Gradient
80% Oil, Vsl = 0.28 m/s
-'moo
".
""
b.
ddoo a o
a
2
1
-
Superficial Gas Velocity (mls)
Stratified
Slug
Figure 40: Flow Regime Map
75% Oil, 0 ppm DRA
,
2
3
4
Superficial Gas Velocity (mls)
Stratified
Slug
5
6
7
Figure 42: Flow Regime Map
50% Oil, 25 ppm DRA
8
9 1 0
'I
LVT Oil
•
Water
DRA Concentration (ppm)
Figure 49: DRA Surfactant Effect
LVT Oil and Water
DRA Concentration (ppm)
Figure 50: DRA Interfacial Effect
LVT Oil - Water Mixtures
105
Plate 1: Pure DRA, Fresh, lOOx Magnification
Plate 2: 5 ppm DRA Degraded 120 Minutes,
100s Magnification
Plate 3: 75 ppm DRA Degraded 120 Minutes,
100x Magnification
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1)
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