An Advanced Sand Control Technology for Heavy Oil Reservoirs

University of Calgary

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Graduate Studies The Vault: Electronic Theses and Dissertations

2017

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 An Advanced Sand Control Technology for Heavy Oil Reservoirs (Unpublished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

vi

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

viii

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

ix

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 4.10 slotted liner and WPS testing samples of test B ............................................ 67

Figure 4.11 Test B-1 fluid production rate comparison .................................................... 68









Figure 4.20 Test C slotted liner and WPS testing samples ............................................... 76

Figure 4.21 Test C-1 fluid production rate comparison .................................................... 77





Figure 4.26 Test D slotted liner and WPS testing samples................................................ 82

Figure 4.27 Test D-1 fluid production rate comparison .................................................... 84



x



xi

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






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



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


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



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


WPS 500 micron

WPS 600 micron

69


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)



WPS 500 micron

WPS 600 micron

70



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)



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)



WPS 500 micron

WPS 600 micron

71


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)



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.



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)



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)



WPS 500 micron

WPS 600 micron

73



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)



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)



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


flow


flow


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)



WPS 600 micron

WPS 700 micron

78


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)



WPS 600 micron

WPS 700 micron

79



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)



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)



WPS 600 micron

WPS 700 micron

80


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


Test

C-1

flow


flow


flow


flow


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)



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)



WPS 800 micron

WPS 900 micron

85



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)



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)



WPS 800 micron

WPS 900 micron

86



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)



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)



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


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

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Documents

An Advanced Sand Control Technology for Heavy Oil Reservoirs