An Advanced Sand Control Technology for Heavy Oil Reservoirs
Transcript of An Advanced Sand Control Technology for Heavy Oil Reservoirs
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Graduate Studies The Vault: Electronic Theses and Dissertations
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An Advanced Sand Control Technology for Heavy Oil
Reservoirs
Zhang, Zhen
Zhang, Z. (2017). An Advanced Sand Control Technology for Heavy Oil Reservoirs (Unpublished
master's thesis). University of Calgary, Calgary, AB. doi:10.11575/PRISM/24806
http://hdl.handle.net/11023/3797
master thesis
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UNIVERSITY OF CALGARY
An Advanced Sand Control Technology for Heavy Oil Reservoirs
by
Zhen Zhang
A THESIS
SUBMITTED TO THE FACULTY OF GRADUATE STUDIES
IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE
DEGREE OF MASTER OF ENGINEERING
GRADUATE PROGRAM IN CHEMICAL AND PETROLEUM ENGINEERING
CALGARY, ALBERTA
May, 2017
© Zhen Zhang 2017
ii
Abstract
It remains a challenge to control sand production from interfering in the production of oil
and bitumen from unconsolidated formations in the upstream oil industry. The Wrapped
Punch Screen (WPS), when applied under the conditions of open-hole and unconsolidated
formations, can provide highly reliable sand control ability as well as lower costs,
compared to the Wire Wrap Screen and the Premium Mesh Screen. It can also lead to a
higher long term productivity compared to other open-hole completion methods. This is
due to its stainless-steel construction that offers highly anti-corrosive and erosion-free
advantages.
This study has investigated and compared different types of sand control screens commonly
used in heavy oil reservoirs, including the slotted liner screen, the wire wrapped screen
and the WPS screen in terms of the sand control ability, performance under pressure and
cost in the manufacturing process. Two experiments were conducted to compare the
pressure performance and fluid productivity of the slotted liner and WPS. Key
comparisons were based on six main evaluation points that are detailed Chapter 3, which
addresses design, and in Chapter 4, which provides a dynamic fluid production analysis.
iii
Acknowledgements
I would like to express my thanks and appreciation to my supervisor, Dr.Shengnan (Nancy)
Chen, for her support, patience and knowledge. I would also like to thank the members of
my committee, Dr. Mingzhe Dong and Dr. Ian Gates for their encouragement and the
insightful comments they provided at all levels of my research project.
I would like to thank my family for all the blessings they have provided during my studies.
My deepest thanks to Miranda, my wife, and Claire and Leo, my children, for their
overwhelming support, inspiration and love.
I would like to extend thanks and appreciation to Transmer Energy Services and Dr.
Shusheng LI, from the China Petroleum University, for their continued support and
encouragement, as well as for providing me with the tools and assistance that have enabled
me to complete my Master’s thesis and program.
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Table of Contents
Abstract ............................................................................................................................... ii Acknowledgements ............................................................................................................ iii
Table of Contents ............................................................................................................... iv List of Tables ..................................................................................................................... vi List of Figures and Illustrations ........................................................................................ vii List of Symbols, Abbreviations and Nomenclature ........................................................... xi
CHAPTER ONE: INTRODUCTION ..................................................................................1
1.1 Background ................................................................................................................1 1.2 Problem Statement .....................................................................................................4
1.3 Outline of Thesis ........................................................................................................4
CHAPTER TWO: LITERATURE REVIEW ......................................................................6 2.1 Overview ....................................................................................................................6 2.2 Causes of Sand Production ........................................................................................7
2.2.1 Degree of consolidation ...................................................................................10 2.2.2 Reduction of pore pressure ..............................................................................11
2.2.3 Production rate .................................................................................................11 2.2.4 Reservoir fluid viscosity ..................................................................................11
2.2.5 Increasing water production ............................................................................12 2.3 Effects of Sand Production ......................................................................................12
2.3.1 Accumulation in surface equipment ................................................................13 2.3.2 Accumulation downhole ..................................................................................13 2.3.3 Erosion of downhole and surface equipment ..................................................14
2.3.4 Collapse of the formation ................................................................................15 2.4 Sieve Analysis ..........................................................................................................15
2.5 Two common sand control devices .........................................................................19 2.5.1 Slotted Liner ....................................................................................................20 2.5.2 Wire Wrapped Screens ....................................................................................24
2.5.3 Slotted liner and Wire Wrapped Screens design .............................................28
2.6 Summary ..................................................................................................................32
CHAPTER THREE: NEW SAND CONTROL TECHNOLOGY – WPS SAND
CONTROL PIPE .......................................................................................................33 3.1 Introduction – WPS (Wrapped Punch Slots Screen) ...............................................33 3.2 Design methods of WPS sand control pipe .............................................................33
3.2.1 Building stable sand arches .............................................................................34 3.2.2 Oil fluid rate (OFA rate) ..................................................................................35 3.2.3 Anti-plugging ability .......................................................................................37 3.2.4 Anti-corrosion ability ......................................................................................39
3.2.5 Mechanical performance .................................................................................40 3.3 Manufacture process of WPS screen .......................................................................46
3.3.1 Introduction .....................................................................................................46
3.3.2 WPS screen material punching ........................................................................49 3.3.3 WPS screen material welding ..........................................................................50
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3.3.4 Screen Assembling ..........................................................................................51 3.4 Summary ..................................................................................................................53
CHAPTER FOUR: NUMERICAL ANALYSIS FOR PRODUCTION FLOW RATE
WITH DIFFERENT SLOT SIZES BETWEEN SLOTTED LINER AND WPS
SCREEN ...................................................................................................................54 4.1 Fluid production experiments ..................................................................................54 4.2 Fluid Turbidity (Wikipedia 2016) ............................................................................58 4.3 Fluid production rates tests ......................................................................................59
4.3.1 Fluid production rates tests – Test A ...............................................................59
4.3.2 Turbidity analysis during Test A .....................................................................65 4.3.3 Test B ...............................................................................................................66
4.3.4 Turbidity analysis during Test B .....................................................................73 4.3.5 Test C ...............................................................................................................76 4.3.6 Turbidity analysis during Test C .....................................................................80 4.3.7 Test D ..............................................................................................................82
4.3.8 Turbidity analysis during Test D .....................................................................87 4.4 Summary ..................................................................................................................89
CHAPTER FIVE: CONCLUSIONS AND RECOMMENDATIONS ..............................90 Reference………………………………………………………………….……………...98
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List of Tables
Table 1 Sieve Analysis Experimental Results (Hycal, used with permission) .................. 17
Table 2 Mechanical strength compression test samples data ............................................ 42
Table 3 Test sample details ............................................................................................... 56
Table 4 OFA (Oil Flow Area) difference ......................................................................... 56
Table 5 test sample size and related formation sand size .................................................. 56
Table 6 Turbidity Analysis during test A.......................................................................... 65
Table 7 Turbidity Analysis during test B .......................................................................... 74
Table 8 Turbidity analysis during test C ........................................................................... 80
Table 9 Turbidity analysis during test D ........................................................................... 87
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List of Figures and Illustrations
Figure 1.1 SAGD Well Pair Design (Alberta Energy, Oilsand 101) .................................. 3
Figure 2.1 The concept of stable sand arching (Weatherford, use with permission).......... 6
Figure 2.2 Erosion of downhole sand screen (Suman, 1991) ............................................ 14
Figure 2.3 Sieves and shaker testing equipment (Matanovic 2012) .................................. 16
Figure 2.4 Various sieves containing formation samples after sieving process (Rawlins
2000) ......................................................................................................................... 17
Figure 2.5 Sample of sieve analysis of uniform and non-uniform formation sands(Ott
2010) ......................................................................................................................... 17
Figure 2.6 Stand-Alone sand control screens in an open hole (Penberthy W 1992) ......... 19
Figure 2.7 Sand screen failure/damage from plugging of progressive screen plugging
(Bruist 1974) ............................................................................................................. 20
Figure 2.8 Slotted liner sand control screen pipe (Hinen Hitech Slotted liner) ................. 21
Figure 2.9 Slotted liner with different patterns (J.Xie, S.W. Jones, C.M. Matthews
2007) ......................................................................................................................... 21
Figure 2.10 Slotted liner straight cut and keystone cut ..................................................... 22
Figure 2.11 Flow convergence between single slot and gang slots (Wagg 2000) ............. 23
Figure 2.12 Wire Wrapped Screens (James Nurcombe 2009, used with permission) ...... 25
Figure 2.13 Sand screen failure/damage from corrosion and erosion (Dr.Shusheng LI,
2002) ......................................................................................................................... 26
Figure 2.14 Wire Wrap Screen sand bridging method ..................................................... 27
Figure 2.15 Wire Wrapped Sand screen failure/damage during the installation (World
Oil 2007) ................................................................................................................... 28
Figure 2.16 Wire wrapped sand screen failure/damage from a hot spot (World Oil
2007) ......................................................................................................................... 28
Figure 2.17 Formation sand size distribution plot (COBERLY 1937) ............................. 29
Figure 2.18 Effective screen control with well-sorted formation sand material
(Haskell 2010) ........................................................................................................... 30
Figure 2.19 Eroded screen and base pipe (Mathis 2003) .................................................. 31
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Figure 3.1 WPS Screen basic structure ............................................................................. 33
Figure 3.2 Sand control structure design ........................................................................... 34
Figure 3.3 Sand Arching analysis ..................................................................................... 35
Figure 3.4 OFA Calculation for Slotted liner with 400 micron slots width ...................... 36
Figure 3.5 OFA calculation for WPS screen with 400 microns punched slots................. 37
Figure 3.6 Punched slots design for maximum accessing angle ....................................... 39
Figure 3.7 Slotted pipe and perforated pipe ...................................................................... 40
Figure 3.8 Formation sand collapsed demonstration (Transmer Energy, 2012) ............... 41
Figure 3.9 Test of compression load for slotted liner and WPS sand control screen ........ 42
Figure 3.10 Test results of compression loads to slotted liner .......................................... 43
Figure 3.11 Test data for Slotted liner – before 60 KN ..................................................... 44
Figure 3.12 Test data for WPS with perforated base pipe ................................................. 45
Figure 3.13 punched steel flat sheet .................................................................................. 47
Figure 3.14 Cylinder shape and butt-welded along a linear seamline .............................. 48
Figure 3.15 Spiral welded punched slots screen ............................................................... 48
Figure 3.16 WPS screen punching unit............................................................................. 49
Figure 3.17 WPS screen welding unit............................................................................... 50
Figure 3.18 Perforated base pipe- API standard casing .................................................... 52
Figure 3.19 Finished WPS screen unit .............................................................................. 52
Figure 3.20 finished WPS screen jacket ........................................................................... 52
Figure 3.21 Rigid support end ring ................................................................................... 52
Figure 4.1 Sand Control Devices Fluid Production Test Unit Design .............................. 55
Figure 4.2 Sand control fluid production test unit ............................................................ 57
Figure 4.3 Turbidity grade samples .................................................................................. 58
Figure 4.4 Testing samples for of Test A ......................................................................... 60
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Figure 4.5 Flow rate Test A results for slotted liner and WPS screen .............................. 61
Figure 4.6 Test A-1 flow rates comparison ....................................................................... 62
Figure 4.7 Test A-2 flow rates comparison ....................................................................... 63
Figure 4.8 Test A-3 flow rates comparison ....................................................................... 64
Figure 4.9 Test A-4 flow rates comparison ....................................................................... 64
Figure 4.10 slotted liner and WPS testing samples of test B ............................................ 67
Figure 4.11 Test B-1 fluid production rate comparison .................................................... 68
Figure 4.12 Test B-2 fluid production rate comparison .................................................... 69
Figure 4.13 Test B-3 fluid production rate comparison .................................................... 70
Figure 4.14 Test B-4 fluid production rate comparison .................................................... 70
Figure 4.15 Test B-5 fluid production rate comparison .................................................... 71
Figure 4.16 Test B-6 fluid production rate comparison .................................................... 72
Figure 4.17 Test B-7 fluid production rate comparison .................................................... 72
Figure 4.18 Test B-8 fluid production rate comparison .................................................... 73
Figure 4.19 Test B-9 fluid production rate comparison .................................................... 73
Figure 4.20 Test C slotted liner and WPS testing samples ............................................... 76
Figure 4.21 Test C-1 fluid production rate comparison .................................................... 77
Figure 4.22 Test C-2 fluid production rate comparison .................................................... 78
Figure 4.23 Test C-3 fluid production rate comparison .................................................... 79
Figure 4.24 Test C-4 fluid production rate comparison .................................................... 79
Figure 4.25 Test C-5 fluid production rate comparison .................................................... 80
Figure 4.26 Test D slotted liner and WPS testing samples................................................ 82
Figure 4.27 Test D-1 fluid production rate comparison .................................................... 84
Figure 4.28 Test D-2 fluid production rate comparison .................................................... 85
Figure 4.29 Test D-3 fluid production rate comparison .................................................... 85
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Figure 4.30 Test D-4 fluid production rate comparison .................................................... 86
Figure 4.31 Test D-5 fluid production rate comparison .................................................... 86
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List of Symbols, Abbreviations and Nomenclature
Symbol Definition
A Area (m2)
API American Petroleum Institute
C Constant
CSS Cyclic Steam Stimulation
SAGD Steam Assisted Gravity Drainage
D10 Sand Diameter where 10% sands have diameters larger than this value
D30 Sand Diameter where 30% sands have diameters larger than this value
D40 Sand Diameter where 40% sands have diameters larger than this value
D50 Sand Diameter where 50% sands have diameters larger than this value
D70 Sand Diameter where 70% sands have diameters larger than this value
D90 Sand Diameter where 90% sands have diameters larger than this value
ID Inside Diameter
OD Outside Diameter
OCTG Oil Country Tubular Goods
PSD Particle Size Distribution
PSI Pounds Per Square Inch
Q Liquid Flow Rate
WPS Wrapped Punch Slots Screen
OFA Oil Flow Area
1
Chapter One: Introduction
1.1 Background
Heavy oil resources are found predominately in Western Canada, Venezuela, Russia, and
China. With the availability of conventional oil declining, heavy oil is becoming an
important energy resource. Recovery of such oil, however, faces many problems and
challenges. For example, many of heavy oil wells have sand production problems, which
requires the use of mechanical control methods, such as liners, screens or gravel packs, to
prevent formation sand from entering into production lines. The slotted liner is the most
common sand control tool used, due to its simplicity and low cost. Wire wrapped screens
and premium mesh screens offer better resistance to corrosion and better performance of
anti-deformation; their cost, however, sees them used only marginally. Determining low-
cost screens, with enhanced performance, has attracted significant attention in the research
of heavy oil sand control.
In unconsolidated formation conditions, the formation sand is produced through the
production of formation fluids. While small amounts of formation sand will not cause
significant adverse impacts, the more sand produced, the greater the likelihood of reduced
productivity and/or expensive maintenance to downhole and surface equipment. Excessive
sand production may also cause permanent failure of the wellbore and well equipment.
In Canada, oil sands and heavy oil/bitumen reservoirs are major resources. The viscosities
of heavy oil, typically situated near the border between Alberta and Saskatchewan, are
typically lower than 100,000 centipoises (cP), while the Oil sand and bitumen reservoirs
2
are unconsolidated formations with oil viscosities greater than 100,000 cP under reservoir
condition.
Depending on the recovery method, variable factors of recovery can be reached. Formal
recovery methods used for conventional heavy oil have a recovery factor between 5 to
10%; this factor can be improved up to20% by using enhanced recovery methods, such as
water flood, CO2 flood or polymer flood. Thermal recovery methods, like Steam Assisted
Gravity Drainage (SAGD), can reach 50% to 60% recovery factor of the oil sand; Cyclic
Steam Stimulation (CSS) can attain a 25% to 35% recovery factor. The surface mining
method, used in Alberta, may reach up to 90% recovery factor because oil sand is mined
with extraction equipment.
Alberta Reservoir Characteristics
SAGD and CSS thermal recovery methods are widely used in Alberta as over 80% of
Alberta’s oil sands are too deep to mine. The SAGD method is chosen when the solution
gas content is too low and cap rock is not strong enough for the higher steam injection
pressure. One of most important characteristics of bitumen is that it does not flow freely
because of its extremely high viscosity that is normally in the millions of cP. When bitumen
is in a thermal condition, the viscosity drops sharply. For example, the viscosity of bitumen
typically will drop to less than 20 cP when it is heated to 200 ℃.
Steam Assisted Gravity Drainage (SAGD)
The two major type of thermal recovery methods for heavy oil and bitumen recovery
processes are the CSS method and the SAGD method, which is the most successful and
widely used technology in the field. In SAGD process, steam is injected into the formation
3
from a horizontal injection wellbore and oil and other fluids (e.g., water) can be produced
from a lower parallel horizontal producing well due to gravity. During the continuous
injection of steam, a steam chamber will be developed for each steam injection well. After
the steam releases its latent heat to the cold bitumen at the interface, the steam condenses
and mobilizes bitumen, which has experienced a rise in temperature. Based on the character
of bitumen during the heating process, its viscosity thereby is reduced and all fluids flow
towards the producing wells. Figure 1.1 demonstrates the typical well pair design for the
SAGD production method.
Figure 1.1 SAGD Well Pair Design (Alberta Energy, Oilsand 101)
Most SAGD exploitation designs in unconsolidated reservoirs experience sand production
issues as described in Chapter One. Consequently, sand control method is needed during
production.
4
1.2 Problem Statement
The most common device used for sand control is called a Slotted liner. However, with
years of developments, this type of technology had met many problems especially in
thermal production environment due to the very limited oil fluid area(OFA) of slotted
liner, poor sand arching stability and low production rate. The Wrapped Punch Screen
(WPS) is the future alternative sand control technology to replace slotted liner as wrapped
punch slot screen oil fluid area is at least 3 times of tradition slotted liner with only 20%
mechanical strength lost. Sand arches stability is better than slotted liner because the 3-
dimension design of wrapped punch screen that can provide better support for stronger
sand arches when flow rate is over critical flow rate (Risnes 1984). The production flow
rates of wrapped punch screen theoretically 3 times higher than slotted liner at same
condition because oil fluid area is 3 times larger than slotted liner.
The thesis’ research addresses the following specific research aspects:
1. How to achieve a large Oil Fluid Area (OFA) for the WPS, compared to that of the
slotted liner sand control screen method?
2. How to build a stable sand arching system for the WPS technique so that the
performance of sand control can be enhanced?
3. Compare the fluid production performance of the slotted liner and WPS sand control
screen and evaluate the performance of WPS.
1.3 Outline of Thesis
The following is a summary of the contents of Chapters 2 to 5.
Chapter 2 provides a literature review, including well completion designs and sand control
5
methods for thermal recovery wells. This chapter introduces the importance of sand
control in heavy oil and oil sand production processes, the causes of sand production and
the impacts of sand production for downhole and surface equipment.
Chapter 3 experimentally analyze the following items for WPS, including the resistance
to compression load, anti-corrosion ability, opening area percentage calculation, sand
arching stability analysis, anti-plugging analysis and the fluid production resistance
analysis between the slotted liner new WPS sand control screens.
Chapter 4 discusses the fluid production and turbidity tests that demonstrate the fluid
production performance and sand control performance between the slotted liner and WPS
sand control devices.
Chapter 5 identifies the major conclusions and recommendations drawn from the research
and experiments to determine if the WPS sand control screen is a better technology for
heavy oil and oil sand recovery process.
6
Chapter Two: LITERATURE REVIEW
2.1 Overview
The basic concept in sand control is to build stable sand arches to prevent sand production.
(Hall 1970) The sand arch concept is used in the unconsolidated formation surrounding a
perforation structure. After some sand is produced from a formation, a sand arch is formed
that has enough strength to support the structure of the surrounding area, as shown in Figure
2.1. The sand arch’s stability is very complicated because the surrounding stress is constantly
changing due to shifts in flow rates, underground pressure, etc. (Ott, 2010).
Figure 2.1 The concept of stable sand arching (Weatherford, use with permission)
Formation sand arches behind perforation openings is a mechanism that can stabilize poorly
consolidated sand and prevent it from flowing into the wells. There is a limitation to the load
imposed by the fluid drag forces that can damage and reform the existing sand arches. Since
the flow rate is the key to stabilize the sand arches, production rates must be kept lower than
the critical flow rate (Risnes 1984) that will cause continuous sand influx. When fluid is
flowing through an unconsolidated sand towards an outlet opening, the drag forces have the
7
potential to cause sand to break loose, creating a cavity behind the opening. Figure 2.1
indicates that the arch formed by the inner surface of the cavity is stable up to a certain critical
flow rate (Tippie, 1974). When the production rate reaches the critical flow rate, the walls of
the cavity will cave, leaving behind a new arch and a greater cavity, which can take a greater
flowrate before it collapses. When arches collapse, the sand begins to flow like a fluid. An
idealized theoretical model is a spherical arch that can take hydrostatic stresses at great
distance (Cleary, 1979); however, even an ideal spherical arch has a critical point related to
flow rate. Thus, because sand arches are not reliable in preventing sand production, extra
devices are required to help formation sand form stable sand arches (Penberthy W and
Shaughnessy, 1992).
2.2 Causes of Sand Production
In unconsolidated formations, the production of formation fluids will likely be associated
with the production of formation sand. In some situations, small quantities of formation sand
can be produced with no significant adverse effects; however, in most cases, sand production
leads to reduced productivity and/or excessive maintenance to both downhole and surface
equipment. Sufficient sand production may also cause premature failure of the wellbore and
well equipment (Penberthy W and Shaughnessy, 1992).
Conditions that can cause sand production and the probable condition of the formation
outside of the casing after sand is produced can be determined by the factors that affect
the beginning of sand production. These factors describe both the nature of the formation
material and the forces that cause the formation structure to fail. Strength of sandstone is
controlled by (Ott, 2010):
8
1. Amount and type of cementation material holding the individual grains together;
2. Frictional forces between grains;
3. Fluid pressure within the pores of the rock;
4. Capillary pressure forces.
Several researchers have investigated the type of failure that is likely to occur in sandstone.
The nature of the failed perforation tunnel is indicative of a shear failure that will occur
when the compressive strength of the rock is exceeded. In addition, in weakly consolidated
sandstones, a void is frequently created behind the casing. These researchers concluded
(Risnes 1982) that the formation’s compressive strength should be a good indicator of sand
production potential and that sand production will probably cause a void behind the casing
that can be filled with gravel pack sand during a gravel packing operation. The mechanical
failure of unconsolidated rock surrounding a perforation is analogous to the failure of a
loose material surrounding a tunnel in soft earth. As the material over the tunnel yields, the
stress originally held in the yielded material is relieved and transferred to the more rigid
material surrounding the tunnel. A portion of the original stresses, however, is supported
by intergranular friction above the tunnel. To a certain extent, the arching concepts used
in tunneling apply to the unconsolidated rock surrounding a perforation. After some sand
is produced from around a perforation tunnel, an arch/bridge is formed that has sufficient
strength to support the structure of the surrounding material. Under certain conditions, the
production of a limited amount of formation sand can be tolerated to allow an arch to
develop, after which the production of formation sand stops. Figure 2.1 illustrates the
concept of a stable arch around a perforation (Risnes 1984); however, the stability of the
9
arch is complicated by the fact that the state of stress surrounding the perforation is
constantly changing due to changes in flow rate, reservoir pressure, producing water cut,
etc.
The solid material produced from a well can consist of both formation fines (less than 44
microns in diameter and usually not considered part of the formation’s mechanical
framework) and load bearing solids. The production of fines cannot routinely be
prevented and can be beneficial. Fines moving freely through the formation or an installed
grave pack or a sand control screen are preferable to plugging the formation, gravel pack
or screen. The critical factor to assessing the risk of sand production is whether the
production of load-bearing particles can be maintained below an acceptable level of
anticipated flow rate, drawdown pressures and producing conditions, such as cyclic
production (Penberthy 1992).
Generally, the three classifications of formation sands are:
1. Quicksand (completely unconsolidated formation sand)
2. Partially consolidated sand (has some cement particle present, but is only weakly
consolidated)
3. Easily cracked sands (semi-competent, well cemented and potentially
troublesome)
The factors that influence the tendency of a well to produce sand are the (Penberthy 1992):
1. Degree of formation consolidation
2. Reduction in pore pressure throughout the life of the well
3. Production rate
10
4. Increase in drawdown pressure
5. Reservoir fluid viscosity
6. Increase of water production throughout the life of the well.
These factors can be categorized into rock strength effects and fluid flow effects. Each of
these factors and their role in the prevention or initiation of sand production is discussed
in the remainder of this section.
2.2.1 Degree of consolidation
The ability to maintain open perforation tunnels is closely tied to the cementation of sand
grains around the tunnels. The cementation of sandstone is typically a secondary
geological process and, as a rule, older sediments tend to be more consolidated than
newer sediments. This indicates that sand production is often a problem when producing
from shallow, geologically younger tertiary sedimentary formations. Such formations are
typically located in the Gulf of Mexico, California, Nigeria, French West Africa, Italy
and China.
Young tertiary formations often have little matrix material (cementation material) bonding
the sand grains together and are generally referred to as being poorly consolidated or
unconsolidated. A mechanical characteristic of rock that is related to the degree of
consolidation is called unconfined compressive strength (UCS) (Tixier 1975). Poorly
consolidated sandstone formations usually have UCS that is less than 1,000 psi (Tixier
1975). Additionally, degrading the matrix material, which would allow sand production,
may change even well-consolidated sandstone formation. This can be the result of matrix
acidizing treatments or high temperature steam flooding (SAGD, CSS etc.)
11
2.2.2 Reduction of pore pressure
As mentioned previously, the pressure in the reservoir supports some of the weight of the
overlying rock. As the reservoir pressure is depleted throughout the producing life of a well,
some of the support for the overlying rock is removed. Lowering the reservoir pressure
increases the amount of stress on the formation sand itself. At some point, the formation
sand grains may break loose from the matrix, or may be crushed, creating fines that are
produced along with the well fluid (Veeken 1991). Compaction of the reservoir rock due
to a reduction in pore pressure can result in surface subsidence.
2.2.3 Production rate
The production of reservoir fluids creates pressure differential and frictional drag forces
that can combine to exceed the formation’s compressive strength (Wong 2002). This
indicates that a critical flow rate exists for most wells, below which pressure differential
and frictional drag forces are not great enough to exceed the formation’s compressive
strength and cause sand production. The critical flow rate (Risnes 1984) of a well may be
determined by slowly increasing the production rate until sand production is detected. One
technique used to minimize the production of sand is to choke the flow rate down to the
critical flow rate where sand production does not occur or occurs at an acceptable level
(Stein 1976).
2.2.4 Reservoir fluid viscosity
The frictional drag force exerted on the formation sand grains is created by the flow of
reservoir fluid. This frictional drag force is directly related to the velocity of fluid flow and
the viscosity of the reservoir fluid being produced. High reservoir fluid viscosity will apply
12
a greater frictional drag force to the formation sand grains than will a reservoir fluid with
a low viscosity. The influence of viscous drag causes sand to be produced from heavy oil
reservoirs that contain low-gravity, high-viscosity oils, even at low-flow velocities
(Veeken, 1991).
2.2.5 Increasing water production
As previously mentioned, sand production problems often emerge or become more serious
when water production begins. This may result from:
1. Disturbance of the cohesive forces tending to hold the sand grains together as the
water phase becomes mobile
2. Dissolving or softening of the natural cementing material
3. Increased drag forces due to two phase flow and mobility of the wetting phase
4. Increased total fluid production to maintain oil or gas producing rates increases
the drag forces across the sand.
Additionally, water production has been shown to severely limit the stability of the sand
arching around the perforation resulting in the initiation of sand production. (Risnes 1984)
2.3 Effects of Sand Production
The effects of sand production are nearly always detrimental to the short and/or long-term
productivity of a well. Although some wells routinely experience manageable sand
production, these wells are the exception, not the rule. In most cases, attempting to manage
the effects of severe sand production over the life of the well is not an economically
attractive or a prudent operating alternative.
13
2.3.1 Accumulation in surface equipment
If the production velocity is great enough to carry sand up the production tubing, the sand
may become trapped in the separator, heater treater or surface flow line. If a large enough
volume of sand becomes trapped in one of these areas, cleaning will be required to enable
the well to restore production. The well must be shut-in, the surface equipment opened and
the sand manually removed. In addition to the clean-out cost, the cost of the deferred
production must be considered. If a separator is partially filled with sand, the capacity of
the separator to handle oil, gas and water is reduced. For example (Veeken 2009), one cubic
foot of sand in an oil/water separator with a two-minute residence time will cause the
separator to handle 128 fewer barrels of liquid per day. If the ratio of oil to water entering
the separator is one to one (50% water), the separator will deliver 64 fewer barrels of crude
oil per day. At a WTI crude price of USD$50/bbl., this will add up to USD$1.168 million
worth of oil per year that is not moving through this single separator.
2.3.2 Accumulation downhole
If the production velocity is not great enough to carry sand to the surface, the sand may
bridge-off in the tubing or fall, filling the inside of the wellbore or casing. Eventually, the
producing interval may be completely covered with sand. In either case, the production rate
will decline as the well becomes sanded-up and production ceases. In situations like this,
remedial operations are required to clean out the wall and restore production. One clean-
out technique is to run a bailer on the end of slick line to remove the sand from the wellbore.
Since the bailer removes only a small volume of sand at a time, multiple slick line runs are
necessary to clean out the well. Another clean-out operation involves running a smaller
14
diameter tubing string or coiled tubing down into the production tubing to agitate the sand
and lift it out of the well via circulating fluid. The inner string is lowered while circulating
the sand out of the well. This operation must be performed cautiously to avoid the
possibility of the inner string being caught inside of the production tubing. If the sand
production is continuous, the clean-out operations may be required on a routine basis, as
often as monthly or even weekly. The result is lost production and increased well
maintenance costs.
2.3.3 Erosion of downhole and surface equipment
In highly productive wells, fluids flowing at high velocity and carrying sand can
excessively erode both downhole (see Figure 2.2) and surface equipment leading to
frequent maintenance to replace the damaged equipment. If the erosion is severe or occurs
over a sufficient length of time, complete failure of surface and/or downhole equipment
may occur, resulting in critical safety and environmental problems as well as suspended
production. For some equipment failures, a major workover may be required to replace
equipment or repair damage.
Figure 2.2 Erosion of downhole sand screen (Suman, 1991)
15
2.3.4 Collapse of the formation
Large volumes of sand may be carried out of the formation with production fluid. If the
rate of sand production is great enough and continues for a sufficient period, an empty
area, located behind the casing or openhole, can continue to grow larger as more sand is
produced. At a certain point, the overlying shale or formation sand may collapse into
this area due to a lack of structural material to provide enough support (Mathis 2003).
When this collapse occurs, the sand grains can rearrange themselves to create a lower
permeability than originally existed. This will be especially true for formation sand with
a high clay content or wide range of grain sizes.
For formation sand with uniform grain-size distribution and /or very little clay, the
rearrangement of formation sand will cause a change in permeability that may be less
obvious (Penberthy 1992). In the case of overlying shale collapsing, complete loss of
production is possible. In most cases, continued long-term production of formation sand
will usually decrease the well’s productivity and ultimate recovery.
The collapse of the formation is particularly important if the formation material fills or
partially fills the perforation tunnels. Even a small amount formation material will lead to
a significant increase in pressure drop across the formation near the wellbore for a given
flow rate.
2.4 Sieve Analysis
Sieve Analysis is a typical laboratory routine performed on a formation sand sample for
the selection of the proper size gravel (Ott 2010). The dry sieve analysis technique is
less accurate in measuring formation fines and is better for sand-alone screen design.
16
Figure 2.3 shows a typical sieves and shaker testing equipment for running a dry sieve
analysis.
Figure 2.3 Sieves and shaker testing equipment (Matanovic 2012)
This type of sieve analysis consists of placing 100 to 300 grams sample of a dry formation
sand at the top of a series of screens, which has gradually smaller mesh sizes. The sand
particles will fall through the screens until encountering a screen through which the grains
cannot pass. Weighing each screen before and after sieving (Figure 2.4), determines the
weight of the retained sand. The cumulative weight percent of each sample retained can be
plotted as a comparison of screen mesh size on semi-log coordinates to attain a sand size
distribution plot (Figure 2.5). From this graph, the 50% cumulative weight point gives the
median formation particle size diameter. This particle size, d50, is the basis of the sand
control device sand-size selection procedure. The standard rule is to use Coberlys’ criteria
(Coberly 1937) to select the slot size, which is based on the diameter of the grain size at
the 10 percent (d10) of the cumulative particle size distribution. According to this rule, the
slot size should be between 1 and 2 times the D10 or 2 to 3 times of the D50, depending
on the sorting of the sand.
17
Figure 2.4 Various sieves containing formation samples after sieving process (Rawlins
2000)
Figure 2.5 Sample of sieve analysis of uniform and non-uniform formation sands(Ott
2010)
The following table 1 gives us an experimental results of sieve analysis for retainer fraction
and cumulative fraction with accordance to the particle size.
Table 1 Sieve Analysis Experimental Results (Hycal, used with permission)
Particle
Size(in)
Particle
Size(Microns)
Cum.%
Sample 1
Cum.%
Sample 2
Cum.%
Sample 3
Cum.%
Sample 4
Cum.%
Sample 5
0.0787 2000.0000 0.0000 0.0000 0.0000 0.0000 0.1000
18
0.0662 1909.0000 0.0000 0.0000 0.0000 0.0000 0.1000
0.0557 1739.0000 0.0000 0.0000 0.0000 0.0000 0.3000
0.0468 1584.0000 0.0000 0.0000 0.0000 0.0000 0.5000
0.0394 1443.0000 0.0000 0.0000 0.0000 0.1000 1.0000
0.0331 1314.0000 0.6000 0.0000 0.0000 0.9000 1.6000
0.0278 1197.0000 3.7000 0.1000 0.8000 2.7000 2.6000
0.0234 1091.0000 10.4000 1.3000 3.7000 5.8000 3.9000
0.0197 993.6000 21.3000 4.6000 9.6000 10.6000 6.2000
0.0166 905.1000 35.7000 10.7000 18.6000 17.4000 9.9000
0.0139 824.5000 52.0000 20.0000 30.7000 26.3000 15.5000
0.0117 751.1000 67.7000 32.0000 44.6000 36.8000 23.5000
0.0098 684.2000 80.5000 45.7000 58.8000 48.4000 33.9000
0.0083 623.3000 89.4000 59.7000 71.7000 60.1000 45.9000
0.0070 567.8000 94.4000 72.4000 81.9000 70.8000 58.6000
0.0059 517.2000 96.6000 82.6000 89.0000 79.8000 70.6000
0.0049 471.1000 97.2000 89.9000 93.2000 86.8000 80.8000
0.0041 429.2000 97.2000 94.5000 95.4000 91.6000 88.6000
0.0035 391.0000 97.2000 96.9000 96.3000 94.7000 93.8000
0.0029 356.2000 97.5000 98.1000 96.9000 96.6000 96.9000
0.0025 324.4000 98.2000 98.7000 97.6000 97.9000 98.6000
0.0021 295.5000 99.1000 99.2000 98.7000 98.9000 99.4000
0.0017 269.2000 100.0000 100.0000 100.0000 100.0000 100.0000
From the result of sieve analysis, PSD (particle size distribution) is introduced to get the
relationships with slot width and particle sizes. The important parameters are following:
d50, d10, d90, d95, d40, d5
Sorting Coefficient(Sc) is d10/d95
Uniformity Coefficient (Uc) – d40/d90
Empirical selection criteria:
COBERLY(ROGERS): 1 to 2 x d10 or 2 to 3 d50
SAUCIER: 6.5 x d50
GILLESPI ET AL: Uc < 2 use d50, Uc~2 use d40, Uc> 2 use d30
SCHWARTZ: Uc<3 use d10, Uc> 5 use d40, Uc>10 use d70
19
2.5 Two common sand control devices
A significant number of downhole sand control devices are developed and used to control
formation sand; the slotted liner is the most popular. Stand-Alone Screens (SAS), as seen
in Figure 2.6, control formation sand in openhole wells.
Figure 2.6 Stand-Alone sand control screens in an open hole (Penberthy W 1992)
These sand control devices function as a filter. Unless the formation is well sorted, with
clean, large grain-sized sand, a sand control device completion may have an unacceptable
short producing life. In field, a “hot spot” may develop at some point in the formation
interface causing potential erosion and screen failure as shown in Figure 2.7.
20
Figure 2.7 Sand screen failure/damage from plugging of progressive screen plugging
(Bruist 1974)
Industry literature offers different measures for slot width or screen drawn from the results
of sieve analysis done with formation sand. The accumulated weight percentage of
particles larger than a certain diameter are used to obtain a size distribution that is plotted
on a semi-logarithmic scale.
2.5.1 Slotted Liner
The slotted liner is the most common tool used to solve sand problems in heavy oil wells,
as shown in Figure 2.8. Since the slotted liner is simple and low cost, its outer diameter is
less than the coupling diameter of the central pipe, making it easy to run in the well. Slotted
liners, however, are also problematic. Due to the structural characteristics of the slotted
liner, its performance under applied load is not as good as the other two screens.
21
Figure 2.8 Slotted liner sand control screen pipe (Hinen Hitech Slotted liner)
Slotted liners are manufactured by machining slot openings through oilfield tubulars with
small rotary saws. Figure 2.9 shows the various patterns fabricated (Xie 2007).
Figure 2.9 Slotted liner with different patterns (J.Xie, S.W. Jones, C.M. Matthews
2007)
Most slotted liners, have a smaller fluid area and a high pressure drop during production;
typically, they are less costly than wire-wrapped screens. Because slotted liners plug more
easily than other screens, they tend to be used where well production rate is low and
economics cannot afford to use wire-wrapped or other advanced screens.
To preserve the greater portion of the original strength of the pipe, the single-slotted and
staggered-row pattern is normally preferred. The staggered pattern provides a more
uniform distribution of slots over the surface area of the pipe body. The single slotted
22
staggered pattern is machine-grooved with an even number of rows around the pipe. The
slotted liner is normally 15.24 cm in length. (Xie 2007)
The slots can be straight or keystone cut.
Figure 2.10 Slotted liner straight cut and keystone cut
The keystone cut is narrower on the outside surface of the pipe than on the inside pipe.
This structures reduces the risk of plugging since any particle passing through the slot at
the outside of the pipe will continue to flow into the pipe rather than jamming within the
slot.
When the slotted liner is used as a sand control device, it is placed across the production
line and the formation sand mechanically builds sand arches, or bridges, on the slots.
Slots widths are normally from 300 microns to 650 microns, based on the particles’ sizes.
Sand control screen performance is usually evaluated based on the opening area presented
to the formation because of the flow loss. The flow loss through a slot on a certain area
of slotted liner is much less than that caused by flow convergence near the surface of the
slotted liner. Different slot spacing is an important feature that controls the extent of
flow convergence away from the liner and into formation.
Two cases using the single slot and gang slot are illustrated in Figure 2.11.
23
Figure 2.11 Flow convergence between single slot and gang slots (Wagg 2000)
Case 1 shows the flow convergence when one wider slot is located in a certain zone. Case
2 shows flow convergence with two slots that are only half that of the Case 1 single slot.
The open areas to formation are same for both. In Case 1, the flow convergence happened
further away from the liner; the extent of convergence and the slot spacing is almost
linear. This single slot generates about twice as much flow loss with the same opening
area as that of Case 2. This underscores why all sand control screen designs try to reduce
the slot spacing to reduce the flow loss. This paper also explores why the wire wrapped
screen and WPS perform so well. In addition to a large open area, the slots are very close
together, minimizing the extent of flow convergence and reducing flow loss.
Bridging theory explains that formation sand particles will form bridges on a slot with a
width less than two particles diameters. Under the same well production conditions, a
formation’s sand particles will bridge against a slot or hole or WPS punched slot if the
perforation’s diameter is less than three particle diameters. There are two main
mechanisms for plugging in slots (or screens):
Pore-throat plugging: The pore throats become filled with formation sand during the
24
fluid production or with precipitates produced by pressure reduction.
Slot plugging: The sand particles bridge in the slot, causing it to become an extension of
the reservoir material. The flows through the slot then shifts from open-channel flow to
Darcy flow with the increased pressure.
The formation sand bridges/arching formed will not be stable, especially for thermal
recovery methods such as SAGD, CSS etc. Regardless of the criteria used to determine
slot width or screen spacing, the bridges will potentially break down from time to time
when producing rate is changed or the well is shut-in, as in the case of the CSS production
method. Determining how to build better stable bridges or how to rebuild sand bridges is
another key element to evaluate the performance of slotted liner or other screens. A
potential disadvantage of using the slotted liner in high-rate wells is the possibility of
erosion failure occurring before a formation sand bridge can form, leading to enormous
workover costs.
2.5.2 Wire Wrapped Screens
In the 1970’s, wire wrapped screens (Johnson Screen) were introduced as the solution to
sand control, as can be seen in Figure 2.12. Wire wrapped screens differ from slotted
liners, in that the filtration medium and the body of the screen are separated. The base pipe
of the wire wrapped screen, with evenly distributed holes, greatly improves its
performance under stress. The filtration wire of the screen is made from stainless steel,
which improves resistance to corrosion. The wire wrap screen offers simplicity in
manufacturing, stable, reliable sand control performance and a working life span of 8-10
25
years. The 1% -3% flow area of the slotted liner is readily surpassed by the 8-14% offered
by the wire wrapped screen. The cross section of the wire is trapezoidal; the gaps between
wires are narrow at the screen surface and increase in width at the interior. It is self-
cleaning to help prevent plugging.
As indicated, more wire-wrapped screens are used in oil well downhole sand control
situations than any other type of screens. Wire wrap screens come in three variations:
standard pipe-based (pipe base is tubing or casing, shrink-fit pipe-based and rod-based.
Standard pipe-based wire wrap screens provide additional options for preventing the
formation sand production during the production period.
Figure 2.12 Wire Wrapped Screens (James Nurcombe 2009, used with permission)
The advantages of a wire wrap screen as compared to the slotted liner are much more
inflow area and less plugging potential. Normally, the wire wrapped screen’s opening rate
is from 7% to 10%. The conventional wire wrapped screens consist of an outer jacket,
which is fabricated on special wrapping machines that resemble a lathe. The wire wrap is
simultaneously wrapped and welded into longitudinal rods to form a single helical slot.
The jacket is placed over the rod and welded at each end to a supporting structural pipe
26
base, which conforms to API specifications, including perforation holes.
The main advantage of all wire wrapped sand control screens are the 304, 304L or 316L
stainless steel wire that provides more erosion and corrosion resistance than the slotted liner
screen. The slotting manufacturing process changes the metal’s material characteristics
around the machined slots, leading to corrosion issues.
Several cases report that slotted liners have been delivered to a well site with corroded
and plugged slots, with the resultant failures causing permanent sand control failure, as
shown in Figure 2.13. This problem of defective slotted liners cannot be properly handled
at the well site because most of the liner’s material is carbon steel N80. In some areas and
under specific well conditions, however, slotted liners may be the only economical sand
control device; the main reason is often cost related. If this is the case, proper care must
be exercised to maintain the condition and quality of the slotted liner pipes.
Figure 2.13 Sand screen failure/damage from corrosion and erosion (Dr.Shusheng LI,
2002)
On-site quality checks should be made on sand control screens/ liner s once delivered to
the field. Measuring the wire spacing, or slot width, is pivotal. A screen or liner should not
27
be accepted if the slot width tolerance is 50 microns larger or 75 microns smaller than the
well specifications A wire width spacing that is too large will not control formation sand;
openings that are too small will lead to plugging with dirty fluid, drilling fluid solids and
formation sand.
Wire wrapped screens present disadvantages as sand control devices.
Even though wire wrapped screens have a much higher oil flow area (over 10%) than
the slotted liner (2% to 3%) or the WPS screen (5% to 10%), the sand bridge stability
and anti-plugging performance are comparable. Figure 2.14 depicts the mechanisms
of sand arching at the wire wrapped screens. It can be seen that, large sands can
plug the slot, while the small sands cannot build stable sand arching under
pressures, which are main disadvantages of the wire wrapped screens.
Figure 2.14 Wire Wrap Screen sand bridging method
Wire wrapped screens can be damaged when installed through doglegs, high angles and
horizontal sections because the rod wrapping direction is perpendicular with the installation
direction, as indicated in Figure 2.15.
28
Figure 2.15 Wire Wrapped Sand screen failure/damage during the installation
(World Oil 2007)
Uneven spacing or slot deformation creates a weak point; a hole punctured into the wire
wrapped screen will lead to permanent failure of sand control. Figure 2.16 shows a typical
wire wrapped sand screen damage from a hot spot.
Figure 2.16 Wire wrapped sand screen failure/damage from a hot spot (World Oil
2007)
2.5.3 Slotted liner and Wire Wrapped Screens design
As these two general types of sand control devices perform the same function in downhole
sand control works, the following sections uses the term “screen” to encompass slotted
29
liners, wire wrapped screens and WPS screens.
Screens must be designed to allow formation sand grains to build packed, steady sand
bridges around them and then hold these in place during production. Because large
quantities of formation sand have the potential to damage the success of a sand control
work by uncovering the upper portion of the completion or creating a hole in the open hole,
proper screen designs are important. Screen openings (slot widths, wire wrapped spacing or
micron rating for WPS) should use the d50 or 50% from the formation sands size
distribution plot from a sieve analysis. The d50 means that the sieve size would be balanced
in the amount of sand formation it retains and allows to pass through. An example using
450 microns of d50 is shown in Figure 2.17.
Figure 2.17 Formation sand size distribution plot (COBERLY 1937)
The example in Figure 2.17 applies to a formation sand particle down to 262 microns; the
screen will retain 77% of the formation sand. Smaller sized formation sand initially passes
through the screen; however, as a sand pack develops from the formation sand, they will be
30
stopped by a combination of formation sand filtration and bridging on the pore throats. The
result is well sorted formation material.
This sand filtration and bridging phenomenon is demonstrated in Figure 2.18 and Figure
2.1. This typically happens when D40/D90﹤3 and formation fines (particles smaller than
44 micron) ﹤2% by weight.
Figure 2.18 Effective screen control with well-sorted formation sand material
(Haskell 2010)
The screen diameter needs to be as large as possible to increase the open flow and decrease
the annular flow outside the sand control device. Doing so enhances screen longevity.
This type of mechanical sand control designs is most effective with very weak, medium-
to-coarse formation sand particles. Uniform formation sands will quickly build up a
highly permeable sand arching zone around the screen (Risnes 1984). It is commonly
applicable for protecting pumps in shallow oil wells and heavy oil or oil sand wells
(mainly open hole). Technical problems and economics limit the effectiveness of other
methods of sand control, such as chemical methods.
31
When the formation sands are stronger and more uniform, the arching/bridging process
becomes inefficient. At a low sand influx rate, most of the formation sand particles pass
through the slots or wire wrapping spaces. Building sand bridges takes longer and the flow
path may become sand-cut or plugged with formation sand particles that are close to the
slot size, wrapped wire spacing or micron rating. When part of the screen is plugged
velocities and erosion in other sand control areas will increase. Figure 2.19 shows the eroded
screen and its base pipe.
Figure 2.19 Eroded screen and base pipe (Mathis 2003)
To avoid these problems, in deeper, more uniform formation sands, screens designed
with smaller slot openings are used to increase the chances for sand arching. This is also
the main reason why d50 of formation sand size is applied to determine the slot opening,
spacing or micron of screens. If smaller size or intermittent sand influx is expected,
screen openings should be small enough to stop the sand over the majority of the
formation sand size range. Screen erosion can be avoided before a zone of larger
formation sand particles accumulates. Because it is impossible to mechanically cut slots
32
below 300 microns (0.012 in), wire wrapped screens and WPS screen are usually used
under these conditions.
Although slotted liners and conventional wire wrapped screens are relatively low-cost sand
control methods and are very successful in medium-to-coarse-formation sand particles and
low strength sands, they may not be suitable under all circumstances. Chapter 3 sill discuss
the advance of the WPS screen, which allows for an outside diameter to be selected to permit
washover operations. The OD should be at least 2.5 cm or more than 3.8 cm smaller than
the production line drift ID; centralizers should be able to collapse.
2.6 Summary
Methods of sand control are summarized and the fundamental of sand control: the stability
of sand arches are introduced in this chapter. Reasons for formations sand production and
the negative consequences are also presented. Sieve analysis was identified as being most
useful in defining the slots size of sand control screens from PSD analysis. A review was
conducted on the disadvantages of two major sand control methods on the market that, in
turn, lead to ideas for designing a new product to replace current outdated sand control
technology.
33
Chapter Three: NEW SAND CONTROL TECHNOLOGY – WPS SAND CONTROL
PIPE
3.1 Introduction – WPS (Wrapped Punch Slots Screen)
Based on the problems associated with slotted and wire wrapped screens, the Wrapped
Punch Slot (WPS) screen was developed (Transmer Energy, 2012). As seen in Figure 3.1,
WPS screen is to punch the stainless-steel plate and roll it into a jacket, then weld on the
base pipe. Like the WWS, the WPS screen separates the filtration medium and the screen
body. The WPS screen combines the advantages and avoids the disadvantages of the slotted
liner and WPS. Details on the WPS screen design and manufacturing process are presented
in the following sections.
Figure 3.1 WPS Screen basic structure
3.2 Design methods of WPS sand control pipe
The design attributes include: Good performance to build stable sand arches; Stronger
mechanical performance as compared to the slotted liner; High OFA value; Good anti-
34
plugging ability; as well as good anti-corrosion performance. In this section, methods to
achieve these objectives are presented.
3.2.1 Building stable sand arches
An understanding of the concept of sand arching provides the theory for sand control.
The greatest challenge is how to build a stable sand arch to achieve the desired sand
control result because, at certain critical flow rates, the existing sand arches collapse and
new sand arches are formed.
Figure 3.2 shows the basic sand control design methods of the slotted liner, wire wrapped
screen and WPS screen jacket (sand control ability is from on the WPS screen jacket)
The slotted liner and wire wrapped screen provides only a 2D structure to build sand
bridges surrounding the screens. Such sand arches are highly reliable on the flow rate
because they do not provide extra support to existing sand arches. The WPS screen, with
perforated small slots on the screen jackets, naturally forms 3D sand bridges to surround
the screen. This provides better gravel packing quality to prevent formation sand from
entering production lines and potentially choking the crude. The slots act as a bowl-type
support from the bottom of the sand arches that, in turn, offer support to existing.
Figure 3.2 Sand control structure design
Most formation sands gather around the slots of the slotted liner or wire screen. When
downhole conditions change, notably the flow rate, existing sand arching around these
slots will face damage until new sand arches are established. Sand control failure occurs
35
due to arch instability.
The WPS screen offers a stable 3D structure to provide formation sand with enough support
to build solid sand arching; sand control functions well, even in downhole conditions that
vary widely. Figure 3.3 illustrates the benefits of the WPS 3D structure for building stable
sand arches under most conditions. It can be seen from the figure that, slots of WPS keep
open when large sands present, while small sands can build stable sand arching near slot
under pressure.
Figure 3.3 Sand Arching analysis
3.2.2 Oil fluid rate (OFA rate)
The slotted liner manufacturing process involves cutting slot lines on the tubing body. Due
to strength limitations and mechanical cutting difficulties, the ideal oil fluid rate can only
be 2% maximum because the pipe body strength will be reduced by 80%. Figure 3.4
illustrates the typical OFA calculation for a slotted liner.
36
Figure 3.4 OFA Calculation for Slotted liner with 400 micron slots width
The OFA calculation for a slotted liner is:
OFA% = (A x C)/ (B x D) x 100% Eq 3.1
where A is the single slot length; B is the single slot unit area length; C is the slot width;
and D is the single slot unit area width.
The above slotted liner OFA is:
OFA% = (4.0” x 0.015”) / (6.0” x 0.5”) = 2%
Sand control screens with perforated base pipes, like those found in the wire wrapped and
WPS screens, can provide a 6% to 14% opening area because most strength support comes
from the base pipe rather than from the sand control screen jacket. This factor provides the
best benefit for downhole fluid production due to the wider opening area, which is 3 to 7
times more than that of the slotted liner. Figure 3.5 shows a theoretical method to calculate
the opening areas of a WPS jacket.
37
Figure 3.5 OFA calculation for WPS screen with 400 microns punched slots
The red rectangle identifies one unit the OFA which contains one punched slot.
The OFA calculation for the WPS screen is:
OFA% = (A x B x 2)/ (C x D) Eq 3.2
where A is the punched slot length, B is the slots’ opening width; C is the unit area
width; and D is the unit area length.
The above WPS OFA is:
OFA% = (18.30mm x 0.4mm x 2)/ (7mm x 29) = 7.2%
The two examples show that at the same slot size of 400 microns, the OFA of the WPS
screen is over three times that of the OFA of the slotted liner screen. These are universal
equations for slotted liner and WPS screen OFA calculations. The slot opening size is the
only variable parameter of the design and it depends on the formation sand seize analysis.
3.2.3 Anti-plugging ability
During oil production, the formation sand, along with production solutions, enters
production lines. Most slotted liner screens use efficient straight cutting methods to
38
cut slots on tubing. This process, however, is problematic in that straight cutting slots
have a poor anti-plugging ability. The formation sand particles are easily trapped by
the slots having a low access angle and causing permanent plugging issues for the sand
control lines with very limited porosity. Reducing the potential of plugging caused by
formation sand is the focus of this section.
Figure 3.6 illustrates slotted liner designs with straight cut slots. In this case, small
amounts of formation sand particles plugged the slotted liner, which then caused the
entire filtration area to be blocked because the accessibility of straight cutting is very
limited.
To solve this issue, a new cutting method - “keystone” cutting - is used. Given mechanical
limitations, the access angle is a maximum of 200. Share edges at the top of the slot are
targets for damage by formation sand or for creating less sand arching stability as
demonstrated in fig 2.10.
These types of cutting methods still offered difficulties that were challenging to overcome
due to their 2D structure design. In unconsolidated formation conditions, formation sand is
usually very unstable during production, especially at high flow rates. Finding ways to use
sand control devices to control sand production is the major design purpose. The benefit of
increasing the access angle of the keystone cutting method to 200 minimizes the sand’s
potential to cause plugging in the production liner. yet does not. The theoretical maximum
39
accessing angle should be 900 but this is impossible using a 2D design. This knowledge lead
to the idea for the punched slot design shown in Figure 3.6.
Figure 3.6 Punched slots design for maximum accessing angle
Here, the formation sand access angle increases to a maximum of 90 degree, while the
bottom section of the punched slots provides the vertical support required to form stable
sand arches.
3.2.4 Anti-corrosion ability
Based on material analysis, the material commonly used for slotted liners in sour oil or
sour gas fields is normally N80 OR L80 material casing. Unfortunately, these products,
due to their carbon steel components, do not have resistance to withstand the high
temperatures and acidic (H2S) environments associated with thermal production methods.
From an economic standpoint, slotted liners should be the cheapest method to use as a
short-term sand control method in high acidic and temperature well conditions. When the
slotted liner is subjected to an acidic solution for a long term, corrosion will cause the width
of the slot to enlarge, resulting in sand control failure, as shown in Figure 2.2.
40
To demonstrate the results of material differences of slotted liner and WPS sand control
screens, we designed a comparison examination to evaluate their capacity to resist
corrosion anti-corrosion performance under an acidic (brine) environment. Two same size
samples of slotted liner and WPS screen were placed into 3% brine. After a year of soaking,
the slotted liner (material N80 carbon steel) revealed an annual corrosion depth of
0.10~0.15mm and a slot width change of 0.20~0.30mm. The WPS screen (Jacket material
SS304) showed an annual corrosion depth of 0.0005mm and slot width change of
0.001mm. WPS screen’s corrosion resistance is much stronger than that of standard carbon
steel. The decision to use a N80 carbon steel slotted liner was due to operation cost
considerations. Theoretically, stainless pipe can be altered to a slotted liner formation but
at 2-3 times greater cost.
3.2.5 Mechanical performance
The mechanical strength of the slotted liner, wire wrapped screen and WPS screen is derived
from the slotted pipe. The liner of the slotted liner carries many cut slots; the wire wrapped
screen and WPS screen use perforated pipe as their base pipe to maximize their structural
support. Figure 3.7 illustrates the devices’ differences.
Figure 3.7 Slotted pipe and perforated pipe
41
Because of the potential threat of formation collapse, triggered frequently during well
completion, especially in unconsolidated reservoirs, a compression test was designed to
demonstrate the strength different between the slotted and perforated pipes. Collapsed
formations create tremendous compression loads on the small area of the sand control screen
pipe body, leading to its deformation and subsequent failure in sand control. Figure 3.8
illustrates a collapse of formation sand.
Figure 3.8 Formation sand collapsed demonstration (Transmer Energy, 2012)
For the purpose of numerical analysis, an experiment was conducted to compare the
compression load performance of the slotted liner and the sand control pipe with the
perforated base pipe with the intent of reducing the risk of potential of sand control failure.
The specifications of the two screens - size, diameter, length, flow area and filtration
precision - are shown in Table 1. The hydraulic universal testing machine used in the
42
experiment has a maximum load resistance load of 300kN. A steel ruler is fixed on the
hydraulic universal testing machine to observe the deformation changes during tests. The
machine is adjusted to hold the sample screen; the load is increased ever 25kNbetween 0 to
300 kN and held for three minutes. Changes in ID deformation are recorded. This
experiment uses five samples of slotted liners and five samples of WPS screens to
demonstrate mechanical stress comparisons. Table 2 shows the test samples’ basic
parameters, including OD, length and slot sizes.
Table 2 Mechanical strength compression test samples data
Specifications Slotted Liner WPS Screen
Type 5 ½” 5 ½”
Max OD 140mm 146mm
Length 300mm 300mm
Slot size 250 microns 250 microns
Figure 3.9 Test of compression load for slotted liner and WPS sand control screen
43
Figure 3.10 provides data for the OD deformations of the slotted liner and WPS screen
under axial compression loads. Results reveals that the WPS screen with the perforated base
pipe were at least 4 times stronger than the slotted liner. Figure 3.11 shows the test results
of the relationship between the applied loads and deformation occurring in the slotted liner.
Figure 3.10 Test results of compression loads to slotted liner
Based on the data, the maximum compression load for test samples was around 60 kN.
After 60KN, mechanical failure on the slotted liner body decreased as the load decreased;
pipe OD deformation continued to increase.
The test focused on the relationship between applied load and deformation before 60kN.
After 60kN, the testing units were totally collapsed and the slot size was no longer uniform
at 250 microns, leading to sand control failure.
Data gathered before 60 kN, as seen in Figure 3.12, appointed to a numerical relationship
between applied loads and deformation:
0
10
20
30
40
50
60
70
80
90
0 10 20 30 40 50 60 70
Test 1
Test 2
Test 3
Test 4
Test 5
Def
orm
atio
n
Applied Load
44
Y= -0.0063X2 +0.8768X
where X is applied load in kN, Y is slotted liner deformation in mm.
Figure 3.11 Test data for Slotted liner – before 60 KN
Figure 3.13 shows zero deformation when the compression load was zero; it gradually
increased to over 30 mm deformation at 60kN load which was the breaking point of the
slotted liner.
Comparable compression tests were done with the WPS screen with data charted in Figure
3.14. The result revealed that the strength of the perforation pipe was almost 6 times stronger
than the OD size of the slotted liner.
y = -0.0063x2 + 0.8768x
0
5
10
15
20
25
30
35
0 10 20 30 40 50 60
Def
orm
atio
n (m
m)
Applied Load (kN)
45
Figure 3.12 Test data for WPS with perforated base pipe
The compression load increased gradually to the maximum capacity (300kN) and WPS
screen OD had only 27mm deformation. The numerical relationship from the test data for
applied load to WPS deformation is:
Y=0.0001x2+0.0602x
where X is applied load in kN for WPS screen, Y is slotted liner deformation in mm for
WPS screen.
An analysis of the data leads to the conclusion that WPS screens are at least 5 times
stronger than slotted liner screens. Based on real field applications, most slotted liners can
accomplish sand control at very early stages or in simple well completion environments.
When unconsolidated formation reservoirs developed, slotted liners show more failures
caused by formation sand collapses and compression load damages due to mechanical
y = 0.0001 x2 + 0.0602 x
0
5
10
15
20
25
30
0 50 100 150 200 250 300 350
Applied Load (kN)
Def
orm
atio
n
(mm
)
46
weakness incurred after cutting the slots on the casing pipe body. In extreme conditions,
unconsolidated formation collapse will place extremely huge applied loads on to any type
of sand control devices; the slotted liner and WPS screen will be destroyed by the
collapsing loads but the slotted liner’s slots will be increased to a much larger size as
compared to the initial design slot size. Full sand control failure will result. In contrast, the
WPS screen will be destroyed but because of the structural advantage of punched slots, the
collapsed section will be fully closed and will act as a section of blind pipe which will not
cause any sand control failure. When engineers choose well completion sand control pipes,
this feature of the WPS screen should be considered as a benefit. WPS or perforated base
pipe type sand control devices are highly recommended for unconsolidated formation
reservoirs with long horizontal open hole wells, which are most likely to face formation
sand collapse.
3.3 Manufacture process of WPS screen
3.3.1 Introduction
Slotted liner screens are conventionally manufactured with metal cutting machinery or
laser methods to cut slots in API standard casing to form various slotted patterns that
function as sand filters. Such cutting technologies, however, have very low efficiency and
the quality of screens cannot be fully guaranteed. The opening area of the screen is small,
falling in the range of 2%-3%. After the casing is slotted, its mechanical strength decreases
significantly and deformation happens when the slotted liner is run downhole for
completion as the slotted casing is unable to bear large external loads.
47
Traditional punched slots sand control screens are typically manufactured from a flat sheet
of material, mainly stainless steel, and the material is punched inward to form punched slots
in one area to form two fluid channels to allow for the passage of oil. These 3D punched
slots provide the perfect support to build sand arches to prevent sand production. Figure
3.13 depicts a punched steel flat sheet.
Figure 3.13 punched steel flat sheet
Once punched, the material is then folded into a cylinder shape and butt-welded along a
linear seamline. The strength of this contracture is extremely poor. Figure 3.14 shows the
typical fold and weld of the screen.
48
Figure 3.14 Cylinder shape and butt-welded along a linear seamline
The punched slots formed in the stainless material are normally at an angle to the axis of
the cylinder and a base pipe, which is underneath the screen. The longitudinal angle of
punched slots means that edges may be caught by hard points protruding in the wellbore.
To achieve higher strength in the cylinder, the spiral welding method is used, as shown in
Figure 3.15.
Figure 3.15 Spiral welded punched slots screen
49
The cylindrical screen is formed from a strip of material that is rolled in a spiral tube with a
spiral seamline. Strength is improved and the risk of sand control failure due to mechanical
strength of the sand screen jackets is decreased.
3.3.2 WPS screen material punching
Figure 3.16 shows one WPS screen punching unit for punching slots on screen material.
It normally includes an automatic rotatable feeding device, a feeding speed controller, a
speed and position control device, a punching head with punching tools, a support guide
and end winding device. A cooling unit is optional and other components for handing the
materials may be applied when necessary.
Figure 3.16 WPS screen punching unit
A roll of WPS screen material, such as stainless steel, with a certain width (normally 200
mm), is installed on the automatic feeding device. A specified length of material is passed
through the screen punching unit and connected to the winding unit which rolls the punched
screen when the punching process is completed. The screen punching unit is operated to
50
feed and punch the material, ensuring that most slots are distributed evenly. The punching
head and devices are adjustable to ensure the correct punching angle, which is parallel to
the longitudinal direction. The punching unit is also adjustable to accept different widths of
material to form different diameters cylindrical screens to fit over different diameters of
casing. To maintain the precision of slot size, the punching head and tools are periodically
trimmed or sharpened.
3.3.3 WPS screen material welding
The unit in Figure 3.17 is designed to manufacture a spiral-welded cylindrical screen. It
includes an automatically rotatable feeding device, a feeding speed controller, a spiral
forming roller, a welder and a cutting unit on a supporting base. Other components for
handling the materials may be applied when necessary.
Figure 3.17 WPS screen welding unit
A punched and rolled screen material, that has been prepared at a certain punching angle
for making the spiral-welded cylindrical screen, is transferred from the screening punching
51
unit to the feeding device. A certain amount of punched material is fed into the feeding
speed controller and is connected to the spiral forming roller. Once material is connected,
the forming and welding process start. The rotatable feeding device continuously feeds the
material through the spiral roller. The spiral shaped material transfers through the special
welder for spiral-welding into cylindrical shaped screens. During the welding process, a
continuous length of the cylindrical shape screen is supported by the supporting base and
cut into desired lengths by the argon-arc welding cutter.
3.3.4 Screen Assembling
The WPS screen contains a perforated base pipe, which is API standard casing (see Figure
3.18), WPS punched screen sections (see Figure 3.19 and 3.20) and rigid support rings
(see Figure 3.21) on both ends of each section of the screen.
Once the items are manufactured, the assembling process starts. The cylindrical WPS
screens are assembled with API standard casing and has box and pin ends. Perforated holes
are drilled along at least one portion of casing to let fluid flow from the formation to the
production line. The pattern of perforated holes on the casing can be either spiral or parallel.
The WPS screen has end rings normally slid onto the casing. After desired sections of WPS
screens are installed into position, both end rings will be welded onto casing to fix the
movement of WPS screen to form one piece of finished WPS sand control screen product.
52
Figure 3.18 Perforated base pipe- API standard casing
Figure 3.19 Finished WPS screen unit
Figure 3.20 finished WPS screen jacket
Figure 3.21 Rigid support end ring
53
3.4 Summary
The technology of the WPS sand control screen is discussed in this chapter. Specially
designed experiments are introduced to demonstrate the advantages of the WPS sand
control screen. The conclusions show that the WPS screen is superior to the slotted liner in
terms of its strength (3-4 times stronger), resistance to corrosion and erosion, and larger
OFA area. Compression tests fully demonstrated that the slotted liner did not provide the
most efficient or mechanically strong sand control performance. A description of the
manufacturing method of the WPS sand control screen and re-designs for higher efficiency
and better quality were also presented.
54
Chapter Four: NUMERICAL ANALYSIS FOR PRODUCTION FLOW RATE WITH
DIFFERENT SLOT SIZES BETWEEN SLOTTED LINER AND WPS SCREEN
The quality of the sand control tools is tested based on sand control ability and the
corresponding production performance. In early stage of oilfield development, perforation
methods were used to minimize sand production. Over time, stable sand arching systems
were built and used to provide sand control ability. Without any sand control devices,
however, the stability of sand arching was highly dependent on reservoir conditions and
flow rates. When the flow rate reached the critical stage, the inner walls of cavity collapsed,
forming a new arch with a greater cavity. A series of such collapses eventually ends with a
total collapse where the sand begins to flow like a liquid. Sand arches were usually formed
by the inner surface of the cavity and up to a certain critical flow rate. Figure 2.1
demonstrates the idealized theoretical sand arch: a spherical arch (Hall 1970).
4.1 Fluid production experiments
A special flow rate production experiment is designed to observe the production ability for
sand control screen devices related to different OFA and slot sizes, especially between
slotted liner and WPS screens, under the same test environment. From the basic design
method of the WPS screen, its theoretical OFA is 3 to 4 times larger than the slotted liner
for the same OD size of production pipes. Practical field applications, however, are required
to test if WPS screens can produce 3 to 4 times larger amount of mixed fluid than the slotted
liner under the same conditions. A special purpose test unit, shown in Figure 4.1, was
designed to see how flow rate related to OFA or different slot sizes.
55
Figure 4.1 Sand Control Devices Fluid Production Test Unit Design
Four test samples were set at once to observe each sample’s production rate changes
during the testing period to compare the screens’ production performance.
The development of the slotted liner and wrapped sand control screen did not improve
reinforcement of the sand arching structure because the arches always formed behind the
slotted tunnel; a 2-dimensional structure with a perforation tunnel.
A special testing unit was designed to prove that the WPS screen production performance
is better than the slotted liner screen because of larger OFA. The slot size and the OD size
of the WPS and slotted liner screen samples are the same, as identified in Table 3. Based
on the OFA calculation method, each OFA for different slot size are identified in Table 4.
Four individual tests were run for different slot size WPS and slotted liner screen with
different ranges of formation sand size, as seen in Table 5.
56
Table 3 Test sample details
TYPE WPS SLOTTED LINER
OD(INCH) 5 5
OPNNING RATE 5% - 8% 2.0% - 2.1%
SLOT SIZE(MICRON) 400, 500, 600, 700, 800, 900 400, 500, 600, 700, 800, 900
Table 4 OFA (Oil Flow Area) difference
SLOT SIZE (MICRON) WPS OFA % SLOTTED LINER OFA %
400 5.0% 2.0%
500 6.0%-7.0% 2.0%
600 6.0%-7.0% 2.0%
700 6.0%-7.0% 2.0%
800 6.0%-8.0% 2.0%
900 6.0%-8.0% 2.0%
Table 5 test sample size and related formation sand size
TEST SAND CONTROL SAMPLE SLOT SIZES FORMATION SAND SIZE
Test 1 400 microns slot size WPS and slotted liners 200 to 800 microns
Test 2 500 and 600 microns WPS and slotted liners 200 to 800 microns
Test 3 600 and 700 microns WPS and slotted liners 200 to 450 microns
Test 4 800 and 900 microns WPS and slotted liners 450 to 850 microns
From OFA comparisons, WPS OFA rates averaged 3 to 4 times larger than those of the
slotted liner OFA. Fluid production increased sharply or close to the WPS screen sample
when the slot size was over 600 microns. This result stems from the poor sand arch
satiability of the slotted liner with a large slot size. The sand arches continually collapsed
then flowed into the production line, like liquid flux, which was observed in the first two
tests of test 4. The slotted liner’s production rates were much higher than the WPS screen
and then sharply dropped to lower production rates.
57
Figure 4.2 shows the actual testing unit with the formation sand sample (a variable range
size of industrial sand) used as a simulation for an unconsolidated downhole condition. The
test samples are set at the bottom of the steel barrel then buried with a mixture of formation
sands. Water was the fluid media for testing. All test samples were connected with the pipe
at bottom and properly sealed in order to read accurate fluid rates during the tests.
Figure 4.2 Sand control fluid production test unit
The procedure saw two or four testing samples set into the test unit then covered by 20 – 25
cm of simulated formation sand. Water was pumped into the testing unit and kept level.
Production was put back online by opening the control valves underneath the test unit and
recording flow rates at certain time intervals. During the production step, the water level
was maintained to keep the pressure steady. At this point, the production ability between
the slotted liner and WPS screen could be compared. After each test cycle, the formation
58
sands inside of test unit were stirred to break sand arches then given 40 hours to settle down
in order to form new sand arches.
4.2 Fluid Turbidity (Wikipedia 2016)
During the fluid testing process, sand production combined with fluid production was
observed. The fluid turbidity test method was used to determine the quantity of sand
produced during the testing.
Turbidity is a measure of the amount of particulates suspended in water (“particulates” are
things like sand, silt and algal cells). The more suspended particulates there are in the water,
the cloudier it is, the higher the turbidity level and the harder it is for light to penetrate.
During our fluid test process, when sand was produced, the production fluid (mainly water)
is turbid. More sand production related to higher turbidity and to more sand arches
collapsing during the tests. Turbidity of the testing fluid was visually determined by the
productions’ fluid color, as depicted in Figure 4.3.
Figure 4.3 Turbidity grade samples
Turbidity level description:
Level 1 was clear water without any sand production;
59
Level 2 was a small amount sand production evident at the beginning of fluid
production tests and when most flow rates changed sharply, especially for the slotted
liner;
Level 3 was a fair amount of sand produced during the fluid production tests;
Level 4 & Level 5 were extreme conditions which occurred no more than 3 times for the
slotted liner when the slot size was over 700 microns. These high-level turbidities fully
demonstrated the sand arching collapse when flow rates were over critical flow rates. The
3D design punched slots sand control structure could provide more stability than the 2D
design.
4.3 Fluid production rates tests
4.3.1 Fluid production rates tests – Test A
In the first comparison test, only 400 microns slot size WPS and slotted liner screen were
used. The mixed formation sand size distributions were from 200 microns to 800 microns.
The water level was kept steady ensure constant pressure during the test. The WPS and
slotted liner’s height is 304.8mm. The tested slotted liner’s OFA was 2.0% - 2.1% and 5.0%
for the WPS screen. Figure 4.4 shows the two samples used in test A.
60
Figure 4.4 Testing samples for of Test A
Theoretically, for this type of fluid production test, the flow rates should be kept at a
certain rate because the sand arches and production environment are steady. Flow
rates for the two testing samples should differ because the OFAs were 2.0% - 2.1%
for the slotted liner and 5% for WPS.
Four rounds of tests were conducted for the two samples to attain more accurate flow rates.
Figure 4.4 summarizes the prediction that flow rates remained at a certain rate after the first
2 hours of the testing cycle. This is comparable to field work, where production rates are
at a steady state after the first 2-3 hours of running when we use sand control devices; the
flow rate will become steady at certain points after setting in place.
61
Figure 4.5 Flow rate Test A results for slotted liner and WPS screen
The major difference between the screens was the OFA percentage. In addition to its
formation sand influence for flow rate, the WPS production rates should be close to 4 times
higher than the slotted liner which was demonstrated in the first of the four tests. The flow
rates of the WPS were 2-4 times higher than the slotted liner. The slotted liner’s flow rates
were in the range of 5.0 to 10.0 l/min; the highest WPS flow rate was close to 27.0 to 28.0
l/min. Figure 4.6 to Figures 4.9 are show test data that support the analysis that the WPS
screen production rates were higher than the slotted liner derived from the benefit of a larger
OFA percentage.
62
Figure 4.6 Test A-1 flow rates comparison
Test A-1 results show an ideal flow rate comparison between the WPS screen and
slotted liner; the WPS flow rate was 4 times higher than the slotted liner, as designed.
Production rates decreased over time then entered a steady phase. The most likely
reason for the decrease is the building the sand arches. From the zero point to the
highest point of production took over 30 minutes, at which time sand arches were all
formed and choked a small amount of production, leading to production decrease.
After the first two hours of production, the flow rates of both screens were stable and
continued in a parallel model.
Test A-2 differed from Test A-1 in that the WPS screen production rate dropped but the
slotted liner production rate increased at the end (roughly the last hour of this test), as seen
in Figure 4.7.
63
Figure 4.7 Test A-2 flow rates comparison
When the flow rate of the slotted liner increased during the last hour, the WPS screen flow
rate decreased. The increase is related to the collapse of sand arches at certain critical flow
rates. During the last hour, sand production was insignificant, but present. The two flow
rates should correspond to each other as the total pressure drop of this test remained same.
Even so, the WPS production rate was still higher than the slotted liner, as the design
proposed.
Figures 4.8 and 4.9 are the flow rates records for Test A-3 and Test A-4. The WPS
production rates were better than the slotted liner because of OFA differences.
64
Figure 4.8 Test A-3 flow rates comparison
Figure 4.9 Test A-4 flow rates comparison
Based on Test A results, a WPS sand control screen with a slot size of 400 microns should
be highly recommended for wells with formation sand distributions from 200 ums to 800
ums.
0.0
5.0
10.0
15.0
20.0
25.0
0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00
Flo
w r
ate
(l/m
in)
Time(hour)
SLOTTED LINER
WPS SCREEN
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00
Flo
w r
ate
(l/m
in)
Time (hour)
SLOTTED LINER
WPS SCREEN
65
4.3.2 Turbidity analysis during Test A
Table 6 shows the entire turbidity change during Test A.
Table 6 Turbidity Analysis during test A
Slotted Liner-0.4mm WPS-0.4mm
Test A-1 flow rate(l/min) Turbidity flow rate(l/min) Turbidity
6.7 2 26.8 2
6.7 1 26.0 1
6.0 1 24.0 1
5.2 1 23.1 1
5.2 1 23.1 1
5.2 1 23.1 1
Test A-2 5.8 2 21.4 2
5.8 1 21.4 1
6.0 1 20.0 1
6.0 1 20.8 1
6.0 1 20.3 1
6.0 1 20.3 1
6.0 1 20.0 1
8.0 2 15.1 1
Test A-3 5.4 2 20.0 2
8.0 1 15.1 1
8.0 1 13.4 1
7.7 1 13.4 1
7.4 1 13.4 1
8.0 2 13.4 1
7.4 1 13.4 1
7.4 1 13.4 1
Test A-4 5.2 2 7.4 1
5.4 1 8.6 1
5.7 1 8.6 1
5.7 1 8.9 1
5.7 1 8.9 1
5.4 1 9.2 1
5.4 1 9.2 1
5.4 1 9.2 1
66
5.4 1 9.2 1
The beginning of each test was ignored because the testing formation sand was at unstable
conditions. Once a stable condition was reached, the turbidity of fluid was measured to
analyze the sand control performance difference between the devices. In Test A, the sand
control performance was very close. Turbidity changes were noted in Test A-2 when the
slotted liner’s flow rate increased to 8.0 l/min and in Test A-4 when its flow rate changed
to 8.0 l/min. Formation sands were visible in test samples. Test A was one testing approach
to see the sand control performance related to stability of sand control devices. Two red
marks was insufficient evidence to claim that the WPS is more stable than the slotted liner.
Eventually the flow rates should be back to stable phase and no sand production. The results
of Tests B – D are discussed.
4.3.3 Test B
Test A used a 400-micron slotted liner and WPS screen as test samples; Test B used a 500
micron and 600-micron slot size. The samples were placed into the testing unit with 200 to
840 microns of mixed formation sand, similar to Test A. Water levels are kept level to
maintain constant pressure. Opening rates were 2.0% - 2.1% for the slotted liner and 6.0%
- 7.0% for the WPS screen. Figure 4.10 shows the samples for Test B: 500 microns and
600-micron slot size for the slotted liner and the same for the WPS screen.
67
Figure 4.10 slotted liner and WPS testing samples of test B
Test B comprised nine groups of flow rate tests for comparison purposes, as shown in
Figure 4.11 – Figure 4.21. Results reveal that rule flow rates are dependent on the OFA
percentage; a higher OFA rate lead to higher flow rates. Some exceptions emerged in that
the slotted liners’ flow rates were close to or higher than the WPS flow rates. The slotted
liner and WPS production rate changes showed correspondence, as they did in test A. For
example, in Test B-1, the WPS screen with 500 µm slots experiences a sharp increase in
production rate; at same time, the slotted liner with 600 µm slots sees its production rate
sharply decrease.
Figure 4.13 illustrates the special case that happened at the end of testing. The flow rate of
the WPS screen 500 µm increased sharply, whereas the slotted liner 600 µm and WPS 600
µm flow rates decreased sharply. Evidently, corresponding relationships exist among the
test units in the same reservoir and the WPS screens production flow rates were still higher
than those of the slotted liners in this case.
68
Figure 4.11 Test B-1 fluid production rate comparison
Test B-2’s results (see Figure 4.12) were steadier than the previous test after the formation
sand was stirred to break the current sand arches system and build a new one. The 500 µm
WPS screen’s production rate was much higher than the same slot size slotted liner. The
production rates for the 600 µm WPS and slotted liner were quite close and, at some points,
the slotted liner production rates were higher. Small amounts of sand production were
visible in the slotted liner 500 µm screen at end of this section of testing. This collapse at
the end of the experiment which revealed formation sand flowing into slotted liner as a fluid
flux, explains why the flow rates of the slotted liner with 500 µm slots were higher than
those of the WPS with 500 micron slots. We also noticed that 500 µm slots size WPS flow
rates were higher than 600 µm WPS sample. From the design point, that wasn’t correct but
with dynamic condition changes and uncertainty influence of production, smaller slot size
WPS could produce more than larger slot size WPS.
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
0.0 1.0 2.0 3.0 4.0 5.0
Flo
w r
ate
( l/
min
)
Time(hour)
Slotted Liner 500 micron
Slotted Liner 600 micron
WPS 500 micron
WPS 600 micron
69
Figure 4.12 Test B-2 fluid production rate comparison
Results of Test B-3 results as shown in Figure 4.13 were very close. A sudden change in
flow rate also occurred, which was reflected in Test B-4 and Test B-5 (Figures 4.14 and
4.15). A question about the efficiency of the WPS screen emerged: does the WPS screen
offer better production rate performances in the lower ranges of formation sand size, from
200 microns to 500 microns?
0
2
4
6
8
10
12
0.0 1.0 2.0 3.0 4.0 5.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 500 micron
Slotted Liner 600 micron
WPS 500 micron
WPS 600 micron
70
Figure 4.13 Test B-3 fluid production rate comparison
Figure 4.14 Test B-4 fluid production rate comparison
0
1
2
3
4
5
6
7
8
0.0 1.0 2.0 3.0 4.0 5.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 500 micron
Slotted Liner 600 micron
WPS 500 micron
WPS 600 micron
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
0.0 1.0 2.0 3.0 4.0 5.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 500 micron
Slotted Liner 600 micron
WPS 500 micron
WPS 600 micron
71
Figure 4.15 Test B-5 fluid production rate comparison
Figures 4.14 to 4.15 show that the production rates of the four samples were very close;
solid examples of high efficient production rates did not appear. To ensure that errors did
not occur during testing, formation sands were re-stirred and the test unit was water-flushed
for 40 hours, after which Test B-6 commenced.
Test B-6 results were closer to our expectation that WPS screen production rates were higher
than the slotted liner: close to 2 times for 500-micron size slots. Results are shown in Figure
4.16. The production rates of the 600 micron slots WPS screen were still close to the two
slotted liner flow rate. That led us to question if the WPS screen and slotted liner production
rates will be close when the slot size is over 600 microns. Comparisons of the production
rate of Test B-7 (see Figure 4.17), B-8 (see Figure 4.18) and B-9 (see Figure 4.19), showed
that the 600 microns WPS screen has a better production performance than its companion
slotted liner. In field applications of production or steam injection wells, when formation
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
0.0 1.0 2.0 3.0 4.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 500 micron
Slotted Liner 600 micron
WPS 500 micron
WPS 600 micron
72
sand size shows a distribution from 250 microns to 850 microns, the WPS sand control
screen is recommended for use.
Figure 4.16 Test B-6 fluid production rate comparison
Figure 4.17 Test B-7 fluid production rate comparison
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
0.0 1.0 2.0 3.0 4.0 5.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 500 micron
Slotted Liner 600 micron
WPS 500 micron
WPS 600 micron
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10.0
0.0 1.0 2.0 3.0 4.0 5.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 500 micron
Slotted Liner 600 micron
WPS 500 micron
WPS 600 micron
73
Figure 4.18 Test B-8 fluid production rate comparison
Figure 4.19 Test B-9 fluid production rate comparison
4.3.4 Turbidity analysis during Test B
Table 7 records the turbidity changes during Test B. The WPS screen’s sand control
performance was much better than that of the slotted liner, based on flow rate stability and
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
0.0 1.0 2.0 3.0 4.0 5.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 500 micron
Slotted Liner 600 micron
WPS 500 micron
WPS 600 micron
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
0.0 1.0 2.0 3.0 4.0 5.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 500 micron
Slotted Liner 600 micron
WPS 500 micron
WPS 600 micron
74
fewer red marks of turbidity. Most red marks appeared when flow rates increased, providing
evidence that sand arches around the slotted liner collapse more often than those around the
WPS.
Table 7 Turbidity Analysis during test B
Slotted liner - 0.5mm Slotted liner - 0.6mm WPS - 0.5mm WPS - 0.6mm
Test
B-1
flow
rate(l/min) Turbidity
flow
rate(l/min) Turbidity
flow
rate(l/min) Turbidity
flow
rate(l/min) Turbidity
7.2 2 6.9 2 4.8 2 10.5 2
7.6 1 7.2 1 6.6 1 9.6 1
6.9 1 6.0 1 9.6 1 9.4 1
6.9 1 6.6 1 9.6 1 9.6 1
6.9 1 6.0 1 8.6 1 9.0 1
6.6 1 3.6 1 12.0 1 7.2 1
6.9 1 4.8 1 14.3 1 7.8 1
7.2 2 6.9 2 10.1 1 7.2 1
B-2 7.2 1 4.8 1 10.5 1 6.6 1
6.6 1 4.8 1 9.6 1 5.4 1
6.0 1 4.2 1 9.8 1 4.8 1
5.4 1 3.6 1 9.8 1 4.8 1
6.0 2 4.2 2 8.4 1 5.4 1
5.4 1 3.6 1 8.1 1 4.8 1
4.8 1 4.2 2 9.0 1 4.2 1
6.0 2 4.8 2 8.6 1 4.2 1
6.0 2 5.4 2 9.0 1 4.2 1
B-3 6.0 1 5.4 1 6.0 2 4.2 1
6.0 1 5.4 1 4.8 1 5.7 1
5.0 1 5.4 1 4.8 1 6.0 1
5.4 1 5.4 1 5.4 1 6.0 1
5.4 1 5.4 1 7.2 2 4.2 1
6.0 2 5.4 1 6.0 1 4.2 1
4.5 1 5.4 1 5.4 1 5.7 1
4.8 1 5.4 1 5.4 1 5.4 1
B-4 5.1 1 6.0 1 6.6 1 3.8 1
4.8 1 5.4 1 6.0 1 3.8 1
4.8 1 4.8 1 5.4 1 3.8 1
75
5.0 1 5.0 2 4.8 1 6.0 2
5.0 1 5.4 2 4.8 1 5.7 1
4.8 1 4.8 1 5.4 1 5.7 1
4.8 1 4.5 1 5.7 1 3.8 1
4.8 1 5.0 1 5.7 1 5.0 1
4.8 1 5.0 1 5.4 1 4.8 1
B-5 4.8 1 4.8 1 5.4 1 5.7 1
4.5 1 4.2 1 4.8 1 5.4 1
4.8 1 4.8 1 4.8 1 5.4 1
4.8 1 4.5 1 4.9 1 5.1 1
4.5 1 4.5 1 4.8 1 5.4 1
4.8 1 4.8 1 4.8 1 5.4 1
B-6 6.2 1 6.0 1 6.0 1 4.8 1
7.2 2 6.6 2 6.6 1 6.0 1
6.6 1 5.4 1 5.4 1 5.7 1
5.4 1 4.2 1 4.2 1 4.5 1
6.0 1 4.8 1 4.8 1 4.8 1
6.0 1 5.4 2 5.4 1 4.5 1
5.7 1 4.8 1 4.8 1 5.1 1
5.4 1 5.1 1 5.1 1 4.8 1
B-7 5.4 1 5.1 1 8.9 1 3.6 1
5.4 1 5.4 1 6.0 1 7.4 2
5.4 1 4.8 1 6.2 1 7.4 1
5.4 1 5.0 1 6.6 1 6.9 1
5.7 1 4.8 1 6.6 1 6.9 1
6.0 2 5.0 1 6.6 1 7.2 1
5.4 1 5.4 1 6.6 1 7.2 1
6.0 1 5.1 1 6.3 1 7.2 1
5.7 1 5.0 1 6.6 1 7.2 1
B-8 4.0 1 4.5 1 5.7 1 6.9 1
4.8 2 4.5 1 5.7 1 6.0 1
4.8 2 4.8 1 5.4 1 5.7 1
4.8 1 4.8 1 5.4 1 5.7 1
5.0 1 4.5 1 6.0 1 5.7 1
4.8 1 4.8 1 6.0 1 6.0 1
4.8 1 4.8 1 5.7 1 6.4 1
5.0 1 4.5 1 6.0 1 5.7 1
5.0 1 4.8 1 6.0 1 6.0 1
B-9 5.0 1 4.5 1 6.0 1 5.7 1
76
4.8 1 4.2 1 5.6 1 5.6 1
3.8 1 3.8 1 6.6 1 4.8 1
4.8 2 4.2 2 6.0 1 7.2 2
4.8 1 4.2 1 6.6 1 6.6 1
4.8 1 4.5 1 6.6 1 6.8 1
4.5 1 4.2 1 6.6 1 6.6 1
4.8 1 4.2 1 6.6 1 6.9 1
4.5 1 4.2 1 6.6 1 6.8 1
4.3.5 Test C
After the flow rate tests, new questions arose about the slot size and flow rate relationship;
namely, do flow rates of the slotted liner and WPS screen equalize over 600 microns. To
test the fluid production performance at slot sizes over 600 microns 600 and 700 microns’
slot size screens were placed into the testing unit with 200 to 450 microns of mixed
formation sand. The OFA rates2.0% - 2.1% and 6% to 7% for the slot liner and WPS screen,
respectively. Figure 4.20 shows the sample preparation.
Figure 4.20 Test C slotted liner and WPS testing samples
77
Most of the WPS screen production rates were higher than those of the slotted liner; few
production changes occurred, except for a couple of rapid flow rate changes during Test C-
4.
Test C-1 and Test C-2(Figures 4.21 and 4.22) offer an ideal example of the production
rates comparison of the slotted liner and WPS screen. After first hour of Test C, the flow
rate of Test C-2 remained flat and remained so for the duration. Production rate performance
was around 1.5 to 2 times higher than that of the slotted liner. A small amount of sand
production was detected in Test C-1, which may explain why the production rates in Test
C-1 were not as flat as those in Test C-2 because of sand arch collapse.
Figure 4.21 Test C-1 fluid production rate comparison
0.0
10.0
20.0
30.0
40.0
50.0
60.0
0.0 2.0 4.0 6.0 8.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 600 micron
Slotted Liner 700 micron
WPS 600 micron
WPS 700 micron
78
Figure 4.22 Test C-2 fluid production rate comparison
Figure 4.23 captures the flow rates results of Test C-3. During most of the test, flow rates
were steady and flat for both screens; after 7 hours running, the flow rate of the slotted liner
with 700 µm slots increased sharply and sand production was evident, pointing to collapses
in sand arches. Prior to the sharp flow rate increase, the flow rates of the slotted liner
decreased, which suggests plugging issues. After a certain point, the flow flushed out the
plugged slotted liner; sand arches started to collapse and flowed into the testing unit as
mixed flux. This sharp flow rate increase also caused Test C-4 flow rates be become
unsteady because of the correspondence among these testing samples in one test unit.
Figure 4.24 shows the flow rates of Test C-4.
0.0
10.0
20.0
30.0
40.0
50.0
60.0
0.0 2.0 4.0 6.0 8.0 10.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 600 micron
Slotted Liner 700 micron
WPS 600 micron
WPS 700 micron
79
Figure 4.23 Test C-3 fluid production rate comparison
Figure 4.24 Test C-4 fluid production rate comparison
Pre-test procedures to return samples to a normal, flat state were undertaken before starting
Test C-5, a fluid production rate comparison (Figure 4.25).
0.0
10.0
20.0
30.0
40.0
50.0
60.0
0.0 2.0 4.0 6.0 8.0 10.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 600 micron
Slotted Liner 700 micron
WPS 600 micron
WPS 700 micron
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
0.0 2.0 4.0 6.0 8.0 10.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 600 micron
Slotted Liner 700 micron
WPS 600 micron
WPS 700 micron
80
Figure 4.25 Test C-5 fluid production rate comparison
Tests C-1 to C-5 demonstrate that the production rates of the slotted liner will not increase
to come close to the level of the WPS screen. Most of the WPS screens samples with 600
microns and 700 micron slots production rates were higher than the slotted liners with the
same size slots. Of note is that the larger slot size of the slotted liner increases the possibility
of collapsing sand arches plugging issues, as seen in Tests C-3 and C-4.
4.3.6 Turbidity analysis during Test C
Table 8 contains observations of the devices’ sand control performances and are identical
to the last Test B. The WPS possesses more stability than the slotted liner, based on the red
indicators from the turbidity tests.
Table 8 Turbidity analysis during test C
Slotted liner - 0.6mm Slotted liner - 0.7mm WPS - 0.6mm WPS - 0.7mm
Test
C-1
flow
rate(l/min) Turbidity
flow
rate(l/min) Turbidity
flow
rate(l/min) Turbidity
flow
rate(l/min) Turbidity
33.4 2 38.2 2 43.6 2 47.8 2
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
0.0 2.0 4.0 6.0 8.0 10.0
Flo
w r
ate
(l/m
in)
Time(hour)
Slotted Liner 600 micron
Slotted Liner 700 micron
WPS 600 micron
WPS 700 micron
81
32.2 2 35.8 1 45.4 1 50.1 1
31.0 1 33.4 1 47.8 1 51.3 1
30.4 1 35.8 2 41.8 1 51.9 1
26.3 1 36.0 2 47.1 1 54.9 1
24.5 1 35.8 1 44.2 1 53.1 1
Test
C-2 23.9 1 35.8 1 44.2 1 53.1 1
24.5 1 35.2 1 44.8 1 52.5 1
23.9 1 35.2 1 44.2 1 51.9 1
23.3 1 34.6 1 44.2 1 51.3 1
23.3 1 34.0 1 43.6 1 51.3 1
22.7 1 33.4 1 43.0 1 52.0 1
22.7 1 32.8 1 43.0 1 52.0 1
22.7 1 33.4 1 43.0 1 52.0 1
Test
C-3 20.9 1 32.8 1 41.8 1 41.8 1
20.3 1 31.0 1 40.6 1 40.6 1
20.3 1 27.5 1 38.2 1 38.2 1
19.7 1 25.1 1 37.6 1 37.6 1
19.1 1 21.5 1 35.8 1 35.8 1
18.5 1 19.1 1 34.6 1 34.6 1
17.9 1 17.9 1 34.0 1 34.0 1
20.3 2 23.9 2 40.6 2 40.6 2
21.5 2 39.4 2 40.0 1 40.0 1
Test
C-4 28.7 1 22.7 1 37.0 1 68.0 1
23.9 1 27.5 1 37.0 1 68.0 1
18.5 1 34.0 2 36.4 1 68.0 1
17.3 1 32.2 1 45.4 1 47.8 1
16.1 1 31.6 1 46.0 1 27.5 1
16.7 1 27.5 1 46.6 1 27.5 1
17.9 1 23.3 1 44.8 1 29.8 1
15.5 1 22.7 1 44.2 1 27.5 1
10.1 1 21.5 1 43.0 1 24.5 1
Test
C-5 21.5 1 34.0 1 41.8 2 57.3 1
82
21.5 1 35.8 1 35.8 1 59.7 1
19.1 1 39.4 2 29.3 1 59.7 1
21.5 1 38.2 2 28.7 1 58.5 1
27.5 2 37.6 2 28.7 1 57.3 1
21.5 1 33.4 1 27.5 1 58.5 1
19.7 1 31.0 1 26.3 1 57.3 1
19.7 1 31.6 1 27.5 1 57.3 1
19.1 1 32.2 1 31.0 1 58.5 1
4.3.7 Test D
To ensure that the WPS screen production performance is better than slotted liner with slot
sizes over 600 microns, a Test D series was set for slot sizes of 800 microns and 900 microns
to observe the flow rates differences. The OFA rates of the slotted liner were 2.0% - 2.1%;
the WPS OFA rates were 6% to 8%. Figure 4.26 shows the samples for Test D.
Figure 4.26 Test D slotted liner and WPS testing samples
Test D involved five individual tests to observe production performance under large size
slots. The distribution of formation sand ranged from 450 microns to 850 microns. The OFA
difference between the screens was around 3 to 4 times. The steady production flow rates
83
were unanticipated: the flow rates of the slotted liner were much higher than those of the
WPS screen.
Analysis of date from Test D-1, D-2 and D-3 (Figures 4.27, 4.28 and 4.29, respectively)
reveal that the slotted liner had poor sand control ability as significant sand was produced
from the production lines. The slotted liner failed to provide any sand control function; sand
arches continuously collapsed, causing formation sand to flow into the production system.
Flow rates were especially high for Tests D-1 and D-2, at close to 70 to 80 l/min. Such high
rates are beyond the sand arch critical flow rate, thereby preventing the formation of steady
sand arches.
Figure 4.27 conveys the flow rate results when massive collapsing of sand arches occurred.
The flow rates of the slotted liner with 900 microns were almost 4 times more than that of
the WPS 900 microns, but was accompanied with significant sand production. At this point,
the slotted liner all sand control ability was lost and no steady sand arches were formed,
even though the production rate was highest. Figures 4.28 and 4.29 show the four samples
trying to balance their own production rates by stabilizing themselves. Although reaching
a stable status took time, the desired design results that the WPS had a higher production
performance than the slotted liner did appear.
84
Figure 4.27 Test D-1 fluid production rate comparison
In Test D-2 (see Figure 4.28), the slotted liner with 900 micron slots had the highest
production rate initially, but came with sand production due to the high flow rate causing
sand arches to collapse. After 4 hours of running, all samples flow rates were stable. The
WPS screen flow rates were higher than the slotted liner, a condition replicated in Test D-3
(Figure 4.29).
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
0.0 2.0 4.0 6.0 8.0
Flu
id R
ate
(l/m
in)
Time (hour)
Slotted Liner 800 micron
Slotted Liner 900 micron
WPS 800 micron
WPS 900 micron
85
Figure 4.28 Test D-2 fluid production rate comparison
Figure 4.29 Test D-3 fluid production rate comparison
After Test D-3, the testing unit was re-set in preparation for Tests D-4 and D-5 (Figures
4.30 and 4.31)
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
0.0 2.0 4.0 6.0 8.0 10.0
Flu
id R
ate
(l/m
in)
Time (hour)
Slotted Liner 800 micron
Slotted Liner 900 micron
WPS 800 micron
WPS 900 micron
0.0
5.0
10.0
15.0
20.0
25.0
30.0
0.0 2.0 4.0 6.0 8.0 10.0
Flu
id R
ate
(l/m
in)
Time (hour)
Slotted Liner 800 micron
Slotted Liner 900 micron
WPS 800 micron
WPS 900 micron
86
Figure 4.30 Test D-4 fluid production rate comparison
Figure 4.31 Test D-5 fluid production rate comparison
Based on all flow rates data from Test D, the WPS screen production performance is better
than that of the slotted liner. The sand control performance benefited from the 3D design
of punched slots, providing extra support for steady sand arches. The most significant issue
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
0.0 2.0 4.0 6.0 8.0 10.0
Flu
id R
ate
(l/m
in)
Time (hour)
Slotted Liner 800 micron
Slotted Liner 900 micron
WPS 800 micron
WPS 900 micron
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
16.0
18.0
0.0 2.0 4.0 6.0 8.0 10.0
Flu
id R
ate
(l/m
in)
Time (hour)
Slotted Liner 800 micron
Slotted Liner 900 micron
WPS 800 micron
WPS 900 micron
87
of Test D was the sand production for larger slot size slotted liner. Strong sand arches to
handle the high-speed flow rates were not able to form. Therefore, even at larger size slot
conditions, the WPS screen is recommended for sand control and production increase.
4.3.8 Turbidity analysis during Test D
The turbidity analysis in Test D intended to demonstrate sand control performance,
especially when slot sizes were at a maximum to handle the coarse sand range of 1mm.
Here, flow rates will be much higher than under normal formation sand condition, causing
sand arches collapse more easily. When flow rates were higher than the critical flow rate,
continuous collapse occurs and sand enters the production fluid. At this point, fluid flow
would have high turbidity, as is seen in Table 9.
Table 9 Turbidity analysis during test D
Slotted liner - 0.8mm Slotted liner - 0.9mm WPS - 0.8mm WPS - 0.9mm
D-1
flow rate (l/min)
Turbidity
flow rate (l/min)
Turbidity
flow rate (l/min)
Turbidity
flow rate (l/min)
Turbidity
36.4 2 75.2 3 35.8 2 17.9 2
26.3 1 71.6 2 35.2 1 22.0 1
26.6 1 71.6 2 43.0 1 22.7 1
29.8 1 66.9 2 34.6 1 20.9 1
28.6 1 65.7 2 37.6 1 21.5 1
28.6 1 71.6 2 37.6 1 25.0 1
D-2
31.0 2
66.9 2
41.2 1
18.5 1
20.3 1 41.8 2 29.3 1 27.5 2
22.7 2 37.0 2 28.0 1 13.7 1
17.3 1 21.5 1 26.3 1 21.5 1
17.9 1 15.5 1 25.7 1 17.9 1
28.0 2 16.1 1 23.9 1 22.0 1
17.9 1 16.7 1 25.0 1 23.9 1
88
17.3 1 17.9 1 23.9 1 25.0 1
16.7 1 17.3 1 23.3 1 23.9 1
D-3
18.5 1
14.3 1
23.9 1
20.9 1
14.3 1 21.5 2 26.9 1 16.7 1
25.0 2 18.5 2 23.9 1 11.3 1
18.5 2 18.5 1 26.3 1 16.7 1
20.3 2 20.9 1 27.5 1 11.9 1
19.1 1 15.5 1 25.0 1 13.1 1
12.5 1 10.1 1 16.1 1 12.5 1
11.9 1 9.6 1 15.5 1 11.9 1
11.3 1 9.0 1 15.5 1 11.3 1
D-4
11.9 1
9.0 1
13.7 1
11.9 1
10.7 1 9.0 1 14.3 1 11.3 1
10.1 1 8.4 1 14.3 1 10.7 1
10.7 1 8.4 1 13.7 1 10.7 1
10.1 1 8.4 1 14.3 1 11.3 1
10.7 1 8.4 1 13.7 1 10.7 1
10.1 1 8.4 1 14.3 1 11.3 1
10.1 1 8.4 1 14.3 1 11.3 1
10.7 1 8.4 1 13.7 1 10.7 1
D-5
11.9 1
10.1 1
14.9 1
11.9 1
11.3 1 9.6 1 14.9 1 12.5 1
11.9 1 10.1 1 14.3 1 12.5 1
11.9 1 10.1 1 16.1 1 13.1 1
11.9 1 9.6 1 16.1 1 12.5 1
12.5 1 9.0 1 15.5 1 13.7 1
11.9 1 10.1 1 16.7 1 13.1 1
12.5 1 9.6 1 16.1 1 12.5 1
11.9 1 9.6 1 15.5 1 11.9 1
Table 4.4 provides evidence that our speculation was correct, especially for 900-micron slot
size slotted liner. Sand flux appeared at the beginning of this test and turbidity was close to
89
3, with massive amounts of sand entering the production line. The condition did not
improve until high flow rates appeared, identifiable at the end of Test D-1. The resultant
over critical flow rates impeded sand arch stability and lead to their collapse. The WPS
screen in Test D incurred the same situation with very high flow rates but sand producing
maintained at the level 2 range for a short period. Sand flux appeared once during Test D-2
of the 900-micron slot size unit; sand production was brief, then disappeared. Flow rates
remained stable. It is reasonable to conclude that the WPS screen has much better sand
control performance and stability than does the slotted liner.
4.4 Summary
Chapter 4 focused on fluid production rates and turbidity. The four sets of tests and over
50 individual tests, proved, conclusively, that the WPS sand control screen fluid production
ability was much better – around 2 – 3 times on average - than that of the slotted liner.
Sand arch stability does need consideration. When flow rates were higher than critical fluid
rates, formation sand arches collapse continuously, allowing sand flux to enter production
lines and pose issues such as equipment failure and/or well abandonment. The results of
the WPS sand control screen fluid production was higher than the slotted liner and saw
little to no sand production. The WPS screen turbidity is much better than that of the slotted
liner, especially when production rates had significate changes. This phenomenon also
demonstrates that the 3D structure of the punched slots is advantageous to sand arch
stability.
90
Chapter Five: CONCLUSIONS AND RECOMMENDATIONS
The WPS sand control screen showed outstanding results and performance in sand control
functions and fluid production ability. It may become a viable resource for the industry,
particularly with the upgrades - in manufacturing efficiency and special screen patterns.
The conclusions of the study are as following:
1. The model of sand control screen recommended for use depends on the sieve analysis
and the reservoir PSD’s analysis. The standard rule is to use Coberlys’ criteria to select
the slot size. Per this rule, the slot size should be between 1 and 2 times the D10 or 2
to 3 times of D50, depending on the sorting of the sand.
2. An OFA comparison of different types of sand control devices was established; given
the same the OD size of base pipe, the typical difference between the WPS screen and
slotted liner is 3-4 times.
3. Plugging issues are common with straight cut slots. Even those upgraded with the
keystone cuts are problematic, based on their limited 200 maximum access. The new
WPS screen design of punched slots with 900 maximum angles on both sides saw a
significant reduction in plugging.
4. Corrosion problem are essential in slotted liner screens screen, especially in high acid
environments, because of their carbon steel oil casing pipe. Even L80 material leads to
corrosion issues. The wire wrapped and WPS screens have solved this problem by
using stainless steel material as outside jackets to reduce the impacts of high
temperature, high acid and high brine environments.
5. Mechanical strength is a challenge for sand control device. The slotted liner has
91
weakest mechanical strength because slots cut on the pipe reduce the strength of the
original pipe. a perforated base pipe offers stronger structure. Based on the tests
conducted, the perforated pipe base of the wire wrapped and WPS screens are 5 times
stronger than slotted liner. Enhanced strength can provide production security and
reduce the potential for damage during installation.
6. Based on the OFA, the, WPS design OFA should be around 3-5 times bigger than that
of the slotted liner. During the dynamic fluid production tests, most of WPS production
rates were higher than the slotted liner as expected by the original design. Several
special cases occurred during the tests where the slotted liner production rates were
much higher than that of the WPS screen and were accompanied by sand production.
These situations reinforced the mechanisms of sand arching: when flow rates are over
the critical rate that sand arches can withstand, the arches start to collapse and formation
sand flow enters in to production lines as flux. The slotted liners’ higher flow was that
outcome of sand arch collapse.
7. As observed during the flow rates tests, when slot widths increased (over 600 microns),
the production rates between the slotted liner and WPS were comparable, except in
those cases when the slotted liner experienced sand arch collapse. Overall, however,
the WPS screen flow production rates were significantly higher than that of the slotted
liner screen..
92
Recommendations for Future Studies:
1. Launch a computational fluid production analysis to understand more clearly the
flow activities through the WPS screen.
2. Choose testing fluids that align more closely to crude oil instead of using water as
testing media; sand arch collapse occurs more easily in a low viscosity environment.
3. Ensure that sand control and fluid production performance experience stable
conditions - high pressure drops, high temperatures and high acid environments - to
compile more accurate production data.
4. Develop a numerical relationship between flow rates and slot width to forecast the
production rate at different slot sizes.
93
Reference
1. Penberthy, W. and Shaughnessy, C., Sand Control, SPE Series on Special Topics,
Volume 1, 1992.
2. Alberta Energy Oilsands 101 http://www.energy.alberta.ca/OilSands/1719.asp
3. Hycal/Weatherford lab test of unconsolidated formations sands
4. WPS sand control screen, Transmer Energy Services Inc, 2012
http://www.transmerenergy.com/products/sand-control-device
5. Turbidity Wikipedia 2016 https://en.wikipedia.org/wiki/Turbidity
6. Rasmus Risnes, Rogland Reginal College, And Rolf K. Bratli and Per Horsrud,
Continental Shelf Institute, Sand Arching – A case Study.
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