FP TJ Thesis 300508

DET TEKNISK-NATURVITENSKAPELIGE FAKULTET

BACHELOROPPGAVE

Studieprogram/spesialisering:

Petroleumsteknologi

Vårsemester, 2008

Student: Tommy Jokela

……………………………………...

signatur

Faglig ansvarlig: Erik Skaugen

Veileder: Francisco Porturas, Reservoir Engineer Reslink

Tittel på oppgaven: Betydningen av innstrømningskontroll anordning (ICD) teknologi i

horisontale sandkontrollkompletteringer

Englesk tittel: Significance of inflow control device (ICD) technology in horizontal sand

screen completions

Studiepoeng:

Emneord: Sidetall: 56

Vedlegg/annet: 0

Stavanger, 30.05.2008

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Significance of Inflow Control Device (ICD) technology in

horizontal sand screen completions

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Table of Contents

1 Summary ........................................................................................................................................................................ 7

2 Introduction ................................................................................................................................................................... 7

3 Horizontal well completion options and challenges .............................................................................................. 9

3.1 Introduction ................................................................................................................................................... 9

3.2 Completion options ...................................................................................................................................... 9

3.3 Well Clean up .............................................................................................................................................. 11

3.4 Cresting and Coning ................................................................................................................................... 12

3.5 Heel-Toe effect in a homogeneous reservoir ........................................................................................ 13

4 General information of the involved technologies ................................................................................................ 14

4.1 Introduction ................................................................................................................................................. 14

4.2 Sand Control ................................................................................................................................................ 14

4.3 Sand Screen ................................................................................................................................................ 14

4.4 Inflow Control Device (ICD) ...................................................................................................................... 17

4.5 Other available ICD designs ..................................................................................................................... 18

4.5.1 Nozzle type ICD without Screen .............................................................................................................. 18

4.5.2 Channel-type ICD....................................................................................................................................... 19

4.5.3 Tube-type ICD ............................................................................................................................................ 20

4.5.4 Orifice-type ICD ......................................................................................................................................... 20

4.5.5 Autonomous Inflow Control Device ........................................................................................................ 21

4.6 Integration with Annular Isolation ........................................................................................................... 21

4.7 Integration with Artificial Lift .................................................................................................................... 21

4.8 Integration with Gravel Pack .................................................................................................................... 22

5 Principles of the ICD technology ............................................................................................................................. 22

5.1 Introduction ................................................................................................................................................. 22

5.2 Pressure loss............................................................................................................................................... 24

5.3 Pressure loss in the formation ................................................................................................................. 26

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5.4 Bernoulli’s equation ................................................................................................................................... 26

5.5 Pressure loss through the ICD ................................................................................................................. 27

5.6 Production index, PI ................................................................................................................................... 29

5.7 Candidate Recognition .............................................................................................................................. 30

6 Simulation and analysis tool ..................................................................................................................................... 31

6.1 NeToolTM Simulation Program ................................................................................................................... 31

7 Field example from the North Sea ........................................................................................................................... 33

7.1 Introduction ................................................................................................................................................. 33

7.2 Qality control of data ................................................................................................................................. 33

7.3 Reservoir parameters ................................................................................................................................ 34

7.4 Results from the producer well evaluation ............................................................................................ 40

7.4.1 Non-Collapsed Annulus ............................................................................................................................ 41

7.4.2 Collapsed Annulus Scenario .................................................................................................................... 47

7.4.3 Water Breakthrough (Collapsed Annulus) ............................................................................................. 47

7.5 Converting the producer well into an ICD in injection mode .............................................................. 51

8 Conclusions ................................................................................................................................................................. 53

9 Recommendations ..................................................................................................................................................... 53

10 Acknowledgements ................................................................................................................................................... 54

11 Nomenclature ............................................................................................................................................................. 54

12 References .................................................................................................................................................................. 55

12.1 Written references ..................................................................................................................................... 55

12.2 Oral references ........................................................................................................................................... 56

12.3 Software....................................................................................................................................................... 56

Figures

Figure 1 Different completion options .............................................................................................................................. 11

Figure 2 Cresting of oil and gas contact in a horizontal wellbore [5] .......................................................................... 12

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Figure 3 The ICD technology reduces permeability variations in heterogeneous reservoirs................................. 13

Figure 4 The ICD technology eliminates the heel-toe effect in a homogeneous reservoir ..................................... 13

Figure 5 Flow of reservoir fluid through the sand screen ............................................................................................. 15

Figure 6 Location of sand screens in a horizontal well ................................................................................................. 16

Figure 7 Wire Wrapped ResFlow™ Screen with ICD ..................................................................................................... 17

Figure 8 Wire Wrapped ResInjectTM Screen with ICD [6] .............................................................................................. 17

Figure 9 ICD with nozzles from supplier 1 [13]................................................................................................................. 18

Figure 10 Channel-type ICD [10] ........................................................................................................................................ 19

Figure 11 Labyrinth-type ICD [20] ...................................................................................................................................... 19

Figure 12 Tube-type ICD [19] .............................................................................................................................................. 20

Figure 13 Orifice-type ICD [10] ........................................................................................................................................... 20

Figure 14 Open Hole Packers prevent annular flow and isolate zones with different ............................................. 21

Figure 15 Principle of the ICD-technology depicted as a garden hose with large holes [6] ................................... 23

Figure 16 Principle of the ICD-technology depicted as a garden hose with tiny holes [6] ...................................... 23

Figure 17 Standard completion versus ResInjectTM [8] ................................................................................................... 24

Figure 18 Pressure loss illustrated as a network of resistors [6] ................................................................................. 24

Figure 19 ICD interaction in a heterogeneous reservoir [14] ........................................................................................ 28

Figure 20 Modelling of the well with NEToolTM [15] ......................................................................................................... 31

Figure 21 Display of the simulation grid together with the proposed well trajectory. ............................................. 34

Figure 22 Attribute display showing the horizontal permeability ................................................................................. 35

Figure 23 KV/KH along the well trajectory .......................................................................................................................... 35

Figure 24 Oil saturation along well trajectory.. ............................................................................................................... 36

Figure 25 Attribute display of the water saturation ........................................................................................................ 37

Figure 26 Attribute showing porosity along well trajectory.. ........................................................................................ 37

Figure 27 Permeability variations along well trajectory.. .............................................................................................. 38

Figure 28 Pressure variations along well trajectory.. .................................................................................................... 39

Figure 29 Saturations profile along the well trajectory ................................................................................................. 40

Figure 30 Summary display of conventional completion: .............................................................................................. 41

Figure 31 Summary display of the ICD completion.. ....................................................................................................... 42

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Figure 32 Pressure comparison between a conventional completion and one with ICD’s. .................................... 43

Figure 33 Oil flow rate: conventional completion and one with ICD’s......................................................................... 44

Figure 34 Oil flux: Conventional completion (blue) and one with ICD’s (pink) ........................................................... 45

Figure 35 Oil flow rate: Conventional and one with ICD’s with 3 OH packers. .......................................................... 46

Figure 36 Oil flow rate after water breakthrough ........................................................................................................... 47

Figure 37 Water flow rate after water breakthrough ..................................................................................................... 48

Figure 38 Oil Flux Reservoir•Well: after the water breakthrough. ............................................................................... 49

Figure 39 Pressure Comparison between a conventional completion and one with ICD’s .................................... 50

Figure 40 Summary plot: ICD injection mode................................................................................................................... 51

Figure 41 Water flux: Conventional completion and one with ICD’s.. ......................................................................... 52

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1 SUMMARY

The increasingly popular horizontal wells suffer from unbalanced influx and injection profile. This can be

greatly improved by introducing Inflow Control Devices (ICD), which choke the inflow or outflow through the

ICD, thus balancing the production or injection profile along the well-bore.

Simulations with NEToolTM were performed to compare the performance of conventional Stand Alone Screen

(SAS) versus screens with ICD’s. The ICD completion minimizes the annular flow effectively and balances the

drainage profile. Further improvement in terms of reduced water cut and increased production was achieved

by adding open hole (OH) packers.

The water breakthrough simulation with ICD’s decreased water cut significantly compared to the

conventional completion (SAS). Oil production for the ICD completion with OH packers was also significantly

higher than for the conventional completion.

The injection simulation showed a more balanced injection profile along the well-bore using ICD’s. The

conventional completion had a high water flux into the high permeability/fractured zones, also called thief

zones.

2 INTRODUCTION

Horizontal and multilateral completions have become increasingly popular as the operating companies are

striving to maximise the oil production and minimise the number of wells. StatoilHydro’s TROLL field in the

Norwegian sector with its thin oil layer is a prime example of the application of this technology.

Optimising or balancing the inflow performance in long horizontal open hole completions can be challenging.

The main short-comings with this type of completion are:

• Poor well clean-up during production kick-off

• Heel’s region over-production, gas/water premature breakthrough

• Toe’s region under or lost production, oil bypassed/unswept regions

• Severe heel-toe effect during production in homogenous formations

• Internal cross-flow and under-production in heterogeneous formations

Ineffective removal of the mud cake during the clean-up will restrict the flow of oil into the well-bore.

Horizontal oil producers are susceptible to gas coning or water cresting during the well life due to the heel-

toe effect. Small differences in permeability and/or relative permeability and frictional losses along the well

bore often leads to early gas or water breakthrough.

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Conventional water injectors suffer from the inability to achieve even distribution of water into all zones.

Water – like any fluid – takes the path of least resistance leading to excessive flooding of high permeable

zones while the tighter zones (zones with lesser permeability) or the reservoir sections toward the toe of the

well are receiving little or no water at all. The risk of ineffective sweep of oil and early water breakthrough in

the adjacent producing wells is very real.

Should this happen in conventional wells, time consuming and expensive interventions would be required to

rectify the negative development. The time it takes to plan and execute the required interventions is often

several months. In the mean time the well is not producing or providing pressure support and sweeping the oil

as designed. Unless the problem is fixed in timely manner the non-optimized production or injection will not

only have an adverse effect on the production, but also on the recoverable reserves.

The inflow control device (ICD) was introduced as a solution to these difficulties in the early ‘90s. In recent

years ICDs have gained popularity and are being applied to a wide range of field types. Their efficiency to

equalize the flux along the well path as well as the outflow has been confirmed by a variety of field monitoring

techniques. The benefits of the ICD technology are:

• Better Initial Well Clean-up

• Delay of Water/Gas Breakthrough

• Decrease Water cut

• Zonal draining strategies for efficient reservoir management

• Better NPV / accelerated cumulative oil production

This thesis describes the inflow control device (ICD) technology, challenges, areas of applications, principles

of the technology and the tools and methods to perform the analysis. The advantages will be illustrated by

running analysis on real field data.

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3 HORIZONTAL WELL COMPLETION OPTIONS AND CHALLENGES

3.1 Introduction

This section describes the completion options and the production and injection related challenges in the

horizontal wells

3.2 Completion options

In the recent years, significant advances have been made in drilling horizontal wells. Geo-steering and

advanced measurement logging tools, form part of the today’s drill string, allowing real time steering and very

accurate placement of long horizontal wells. This offers significant benefits as the pay zone section of the

well-bore is to be placed within optimum distance from the oil gas contact (OGC) and the oil water contact

(OWC), to delay gas- and water breakthrough.

Horizontal and multilateral completions are today being applied to a wide range of field types. They have

proven superior to conventional solutions in many reservoir situations. The optimal completion technique for a

candidate well is determined by the reservoir properties, geological setting, rock mechanics, development

plan, and completion design [12].

An important part of the planning of a horizontal well is the selection of the appropriate completion technique

and design. The most common horizontal completion types are depicted in figure 1.

• Open Hole Completion are inexpensive, but it is limited to consolidated rock formations. Open hole

offers no production or injection control. Additionally this type of well is difficult to stimulate.

• Slotted or Pre-Perforated Liner offers a guard against hole collapse in unconsolidated formations.

The completion method is inexpensive and it also provides a path for intervention tools. The pre-

milled liner provides limited sand control by sizing of the slot width. As there is no zonal isolation

(open annular space) effective stimulation in this type of liner is difficult. Similarly selective

production and injection is not achievable. Coning, annular flow and hot spots are also known

problems.

• Slotted Liner with open hole packers provide zonal isolation. This, in addition to the above benefits,

allows more effective stimulation and better possibility for selective production and injection control

• Cemented and Perforated Liner provides good zonal isolation. Perforations designed to open

channels through the damaged section of the reservoir contribute to the productivity or injectivity.

This completion type offers better possibilities for selective production, injection and stimulation.

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• Stand Alone Screen Completions provide good sand control, but due to lack of zonal isolation

selective production, injection and stimulation are not possible. Coning, annular flow and hot spots

are also known problems.

• Stand Alone Screen Completion with open hole packers provides good sand control and zonal

isolation. This, in addition to the above benefits, allows more effective stimulation and better

possibility for selective production and injection control.

• Stand Alone Screen Completions with open hole packers and gravel pack provides enhanced sand

control and zonal isolation. Selective production, injection and stimulation are also possible to some

degree.

Please note that selective production, injection and stimulation, where referred to in above completion

options, require interventions, such as logging, cement and acid squeezes, straddling and/or plugging of

zones. This is both time consuming and an expensive activity.

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Figure 1 Different completion options

3.3 Well Clean up

One of the main challenges in long open hole completions is the formation damage caused by ineffective well

clean-up. Drilling a well causes formation damage and thus reduced effective permeability. Removal of drill

fluid, solids and mud cake from a long well-bore is not a trivial process. One of the main factors effecting the

hole clean-up is the completion design. Today it is common practice to run the screen liner in the reservoir

drilling fluid (RDF). The mud is conditioned prior to screen liner deployment to remove mud solids which would

plug the screens during deployment and flow back of the RDF. During well clean-up, the RDF mud cake is

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designed to lift off cleanly and be back produced to surface leaving a clean undamaged formation through

which to produce.

3.4 Cresting and Coning

Wells are often completed in zones which are underlain by a water zone and overlain by a gas cap. When a

well is put into production, a pressure sink is created around the well. The pressure sink can extend all the

way down to the water zone, and cause water or gas to enter the wellbore. This is called cresting (water) and

coning (gas), due to the shape of the interface (see fig. 2). If the water/gas, both being more mobile than oil,

penetrate the open hole interval, the gas and oil will block the production of oil from the rest of the open hole

section. Increased production of water or gas results in higher costs and a declining oil production [3, 4].

Figure 2 Cresting of oil and gas contact in a horizontal wellbore [5]

A variable permeability distribution along the well-bore (heterogeneous formation) also contributes to an

unbalanced fluid influx (See fig. 3). The ICD technology reduces the permeability variations by equalizing the

pressure drop along the interval. This will improve the sweep efficiency and prolong the wells production time

due to delayed water/gas coning.

Figure 3 The ICD technology reduces permeability variations in heterogeneous reservoirs

3.5 Heel-Toe effect in a homogeneous reservoir

Horizontal wells increases reservoir exposure and well-bore length; however, it comes at a cost. The heel-toe

effect occurs as a result of frictional pressure drop from fluid flow in horizontal sections. The frictional

pressure drop along the producing conduit creates a higher drawdown pressure in the heel section of the

well, causing an unbalanced fluid influx (see left hand side fig. 4). The ICD technology equalizes the pressure

drop along the interval and hence balances the influx along the entire well-bore [10].

Figure 4 The ICD technology eliminates the heel-toe effect in a homogeneous reservoir

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4 GENERAL INFORMATION OF THE INVOLVED TECHNOLOGIES

4.1 Introduction

This section describes the tools and techniques used in horizontal sand screen completions.

4.2 Sand Control

The goal of sand control is the production of reservoir fluids while preventing the production of formation sand

(load bearing particulates which make up the reservoir rock). Unconsolidated sands typically have high

permeability and porosity but low compressive strength. The sand particles in unconsolidated sands are

easily dislodged when the well is put on production (due to the drag forces exerted on the solids as fluids flow

past through the reservoir matrix). Also as the reservoir pressure decreases changes in the in-situ stresses

may initiate formation failure. The inability to control sand production over the life of the well can be extremely

costly as the sand produced with hydrocarbons will:

• Cause erosion of down hole completion components and topside surface facilities

• Deposit in the well-bore and surface facilities necessitating costly sand removal operations and

cleanouts

• Cause reduction in production or, in worst case, stopping it completely

Typical sand control methods are:

• Restrictive Production Rate

• In Situ Consolidation

• Resin Coated Gravel

• Gravel Pack

• Screens - Natural Sand Packing (OH)

• Fracturing for sand control

Even wells with successful sand control measures in place can / will produce small quantities of sand. For

offshore installations (especially subsea) where several wells produce into a common production system this

is critical. Sand must be first separated from the produced fluids and all oil removed prior to disposal.

4.3 Sand Screens

A sand screen is a tubing joint (also called base pipe) with a filter wrapped or attached onto it. The base pipe

is perforated in standard screens. If an ICD is added to the screen the base pipe is not perforated as the flow

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from the formation is directed through the IDC nozzles. There are two main filters; Wire Wrapped Screen

(WWS) and Dutch weave or sintered mesh laminate types (also known as Premium Screen).

The purpose of the sand screen is to retain or filter the formation solids, thus preventing the entrance of the

sand particles into the well-bore. The flow of the reservoir fluids is directed, using screen hanger and open

hole packers, through the filtering system of the sand screen (see fig. 5 and 6). The formation sand is carefully

analyzed and testing is performed to obtain the optimum sizing of the filter for a given reservoir sand.

There are several different sand control techniques. On the Norwegian Continental Shelf the sand screens are

run as part of the lower completion. The lower completion is run into the open hole section of the well-bore

(see figure 6). In some cases the void between the screen outer diameter and well bore is packed with gravel

to obtain better filtering of the produced fluids. This is called gravel packing. Open hole packers, such as

inflatable, Mechanical External Casing Packers (ECP), Constrictors or Swell Packers (SP) are used to isolate

sections of the reservoir and to prevent the annular flow. The entire open hole section is located in the

reservoir section of the well.

Solids DepositsFilter

Production Conduit

Perforated Base Pipe

Figure 5 Flow of reservoir fluid through the sand screen

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Figure 6 Location of sand screens in a horizontal well

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4.4 Inflow Control Device (ICD)

An inflow control device (ICD) is a device with nozzle or channels that restrict or choke the inflow of fluids

from the screen section. The size and the number of the nozzles are designed to balance the inflow profile

along the well-bore. ICDs are installed as an integral part of the sand screens. Figure 7 shows the Reslink’s

ResFlow™ ICD screen. Reslink’s ICD can have 2 to 4 nozzles per unit joint and can be mounted with different

nozzle sizes. Also outflow (injection) can be controlled and balanced by using a slightly different design.

Reslink’s ResInject™ (see fig. 8) helps to balance the distribution of injected water. The red arrows illustrate

the flow path through the sand screen and ICD assembly.

Figure 7 Wire Wrapped ResFlow™ ICD Screen [6]

Figure 8 Wire Wrapped ResInjectTM ICD Screen [6]

ICD

Sand Screen

NozzleICD

Sand Screen

Nozzle

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4.5 Other available ICD designs

The ICD shown in figure 7 and 8 (Nozzle-type ICD) is one of four ICD designs available today. The three other

designs are Tube ICD, Channel-type- and Orifice-type ICD. All these designs create a flow resistance, and

they can be mounted on a screen joint. This thesis will focus on the Nozzle-type ICD.

4.5.1 Nozzle type ICD without Screen

Supplier 1 offers an ICD with a slightly different design than Reslink’s ResFlow™ screen (see fig.7). On each

coupling (see fig.9-2) there are up to 8 nozzles (see fig.9-3). The nozzle size is predetermined to create a given

pressure drop at a given flow rate. The centralized OD of the coupling (see fig. 9-4) provides a minimum

standoff of the ICD from the Casing / open hole wall, allowing fluid to produce through all the nozzles [13]. The

drawback with this design is that it does not allow filtering of the fluids. Formation particles will erode out and

plug the nozzles..

Figure 9 ICD with nozzles from supplier 1 [13]

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4.5.2 Channel-type ICD

The channel-type ICD (see fig. 10) was developed by supplier 2. Instead of nozzles, this device uses a number

of helical channels with a preset diameter and length to impose a specific differential pressure at a specified

flow rate. Fluid flows from the formation through a limited annular space into multiple screen layers mounted

on an inner jacket. After entering the screen fluid flows along the solid base pipe of the screens to the ICD

chamber, where the chosen number of channels impose the desired choking. The last step in the process is

fluid entering holes of a preset diameter. Fluid can also enter a slotted mud filter. The filter prevents the

screen from being contaminated by kill mud during any future, well killing operation. The channel-type ICD

causes a pressure drop to occur over a longer interval than the nozzle and orifice-type ICD’s, an advantage

that will reduce the possibility of erosion or plugging of the ICD ports. One disadvantage is that the device

depends on friction to create a differential pressure, and this implies that the actual pressure drop created

will be more susceptible to emulsion effects [10].

Figure 10 Channel-type ICD [10]

Supplier 3 offers an ICD using labyrinths (see fig. 11) instead of channels. Like the channel-type ICD, the

labyrinth-type causes pressure drop to occur over a long interval which will reduce the possibility of erosion

or plugging of the ICD ports. The labyrinth ICD is designed to provide the required inflow control at flow

velocities below erosion limits [20].

Figure 11 Labyrinth-type ICD [20]

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4.5.3 Tube-type ICD

The tube-type ICD (see fig. 12) ,developed by supplier 4, consists of an annular chamber on a standard oilfield

tubular. When a screen is applied, the reservoir fluid is produced from the formation through the sand screen

and into the flow chamber. The requiered pressure drop is created by a set of tubes. After flowing through the

tubes, the flow proceeds into the pipe through a set of ports. Tube lenght and inside diameter are designed to

produce the differential pressure needed for optimum completion efficiency [19].

Figure 12 Tube-type ICD [19]

4.5.4 Orifice-type ICD

The orifice-type ICD (see fig. 13) was developed by supplier 5. Multiple orifices produce the required

differential pressure for flow equalization. Each ICD consists of a number of orifices of known diameter and

flow characteristics. The orifices are part of a jacket installed around the base pipe within the ICD chamber as

opposed to the nozzle-type ICD. By reducing the number of open orifices one can achieve different values of

pressure resistance. The flow characteristics are expected to be similar to the nozzle-type ICD [10].

Figure 13 Orifice-type ICD [10]

ICD Tube

Standard oilfield tubular Sand Screen

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4.5.5 Autonomous Inflow Control Device

Supplier 2 has developed an enhancement of the existing ICD design, the Autonomous Inflow Control Device

(AICD). As gas flows into a particular region of the well, the density decreases in the production fluid. This

triggers the AICD valve to close or restrict flow from this zone. This density-sensitive valve has been designed

to compliment the ICD. The system allows each screen joint to work independently, and coupled with open

hole packers AICD provides an autonomous system, which controls gas influx.The valve design is totally

mechanical and does not require an eletrical or hydraulic power source. The AICD could also be configured to

shut off water, hence reducing the risk of water coning [21].

4.6 Integration with Annular Isolation

One main advantage with the ICDs is the reduction of annular flow. Annular flow leads to the redistribution of

fines along the screen open hole annulus, leading to a low permeability pack in the near well-bore area

around the screens, impairing well productivity due to higher skins. However, ICD’s will only eliminate annular

flow as long as there exist a highly homogenous permeability distribution along the length of the horizontal

well-bore. This ideal situation is not always in place. Variations in permeability and hole size can trigger

annular flow even when ICDs are installed. To exploit the full potential of the ICDs one has to integrate the

ICDs with annular isolation (see fig.14). Most effective annular isolation in open hole completions is achieved

by use of open hole packers. The purpose of the open hole packers is to isolate zones with different

permeability, prevent annular flow and to direct the flow through the screens and ICDs. An effective

combination with ICDs and open hole packers will contribute to an effective influx and reduced possibility of

annular flow. Annular isolation systems being offered in the oil and gas industry, are: Inflatable or Mechanical

External Casing Packers (ECPs), Swell Packers (SPs), Constrictors and Expandable Packers [10].

Figure 14 Open Hole Packers prevent annular flow and isolate zones with different permeability

4.7 Integration with Artificial Lift

A system that adds energy to the fluid column in a wellbore with the objective of initiating and improving

production from the well is referred to as an artificial-lift system. Operating principles being applied in the

oil/gas industry include rod pumping, gas lift and electrical submersible pumps. These technologies are

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usually implemented to revive dead wells or to enhance the productivity of existing producers by lowering the

well bottom hole pressure and boosting the vertical lift energy. A disadvantage with this technology in

horizontal wells is that it will further aggravate the influence of pressure drop along the well-bore, hence,

encouraging increased coning of water or gas. To reduce this phenomenon one can use a combination of

ICDs with artificial-lift [10].

4.8 Integration with Gravel Pack

Gravel Pack is a sand-control method used to prevent production of formation sand. To reduce the potential of

sanding problems and to delay water/gas breakthrough, a combination of gravel pack and ICD’s would be

effective. ICD’s together with annular isolation eliminate annular flow, a primary cause of sand particles

becoming dislodged from the sand face and being transported along the annulus. Sand particles could cause

screen erosion, plugging and sand production related problems at the surface. Field experience with gravel

pack in horizontal wells has proven their ability to eliminate or minimize sand production [10].

5 PRINCIPLES OF THE ICD TECHNOLOGY

5.1 Introduction

This section describes the principles of the ICD technology and the applicable mathematical equations.

The main benefit of the ICD technology is its ability to balance the in- and outflow profiles along the long

horizontal well-bore. To illustrate this in simple terms, we take a garden hose, which represents a horizontal

water injection well, and put a plug at the end of it (see fig. 15). Holes of the same diameter are made at even

intervals along the length of the hose. When the water is turned on most of the water is jetted out through the

first set of holes and very little or no water comes out from holes located nearer the end of the hose. There is

just not enough energy / pressure left to push water further out towards the toe of the hose. In this case most

of the injected water would go into the zones close to the heel, while the zones at the toe would not receive

any pressure support. This would lead to an early water breakthrough in the zones that are receiving too

much water and ineffective sweep in zones that receive little or no water.

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Figure 15 Principle of the ICD-technology depicted as a garden hose with large holes [6]

If we change the large holes to very small ones, the same energy / pressure can evenly distribute the water

along the entire length of the hose (see fig. 16). The very same principle has been used for many years in

agriculture for irrigation, especially in regions where water is not found in abundance.

Figure 16 Principle of the ICD-technology depicted as a garden hose with tiny holes [6]

This same behavior is illustrated in figure 17. The drawing depicts a layered reservoir with variable reservoir

permeability and characteristics. The standard completion represents a well without ICDs, where injected

water will take the path of least resistance, i.e. into the high permeable zones, resulting in inefficient sweep of

oil. The completion with correctly sized ResInjectTM ICD nozzles distributes the water evenly, resulting in a

uniform sweep of oil (see fig. 17).

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Figure 17 Standard completion versus ResInjectTM [8]

5.2 Pressure loss

During production of reservoir fluid, the pressure will decline compared to original pressure. It is preferable to

produce as much oil as possible for a minimum loss of pressure. To choose the optimal completion options it

is important to understand the pressure losses from the formation and through the production conduit. Before

entering the tubing the fluid has to pass through several obstacles (see fig.18) [8]:

• Pressure loss in the formation

• Pressure loss in annulus

• Pressure loss in the completion

• Pressure loss in the tubing

Figure 18 Pressure loss illustrated as a network of resistors [6]

Standard Completion ResInject™ ICD

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Fluids in the formation always have a certain pressure, caused by the overburden pressure and the

hydrostatic pressure. To be able to control the flow of fluids from the formation, there has to be a pressure

difference between fluid in the well and fluid in the formation. These pressures are:

Ps = Static reservoir pressure

Pwf = Flowing pressure in the well

Static reservoir pressure (Ps) has to be greater than flowing pressure in the well (Pwf). Pressure drop from the

reservoir and into the well is then:

∆Pr = Ps - Pwf [8] (Eq. 5.2.1)

The pressure drop in the reservoir depends on the following factors:

• The flow rate (q); greater flow rate gives greater pressure drop (∆Pr)

• Permeability (k); reduced permeability gives a greater pressure drop (∆Pr)

• Viscosity (µ); well fluid with a high viscosity gives a greater pressure drop (∆Pr), than a well fluid with

lower viscosity (µ)

• Formation damage (S), resulting in reduced permeability (k) and a greater pressure drop (∆Pr)

• Completion options; pressure drop (∆Pr) depends on the choice of completion:

-Well diameter. If we increase the well diameter, pressure drop will decrease because the well fluid

will enter the well at an earlier stage, and we get a larger flow area (increased radial flow region)

-Variations in the perforations. The height of the perforated interval and the depth of the penetration

-Sand control equipment. Gravel packing, screens or a combination of these

-ICD’s. Regulate the pressure drop by using different nozzle sizes

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5.3 Pressure loss in the formation

Pressure loss in the formation is best described using Darcy law for the linear, horizontal flow of an

incompressible fluid:

∆ ∆ [7] (Eq. 5.3.1)

Where:

P: Pressure

V: Velocity

µ: Viscosity

A: Cross-sectional area of the filter medium in flow parallel direction

L: The length of the filter medium in flow parallel direction

K: Proportionality coefficient (permeability)

Q: Fluid flow rate

5.4 Bernoulli’s equation

To be able to size the ICD nozzles one needs to understand the law that explains the flow through a nozzle or

orifice. Bernoulli’s equation states that the static pressure ps in the flow plus the dynamic pressure, one half of

the density times the velocity V squared, is equal to a constant throughout the flow. The constant is called the

total pressure pt of the flow. Restrictions governing the use of Bernoulli’s equation: non-gelling liquid, steady

flow, incompressible fluid, no heat addition and negligible change in height [1].

[1] (Eq. 5.4.1)

Where:

Ps: Static pressure

Pt: Total pressure

V: Velocity

ρ:Density

Page 27 of 57

5.5 Pressure loss through the ICD

A completion with only screens will create little to no flow resistance from the annulus to the base pipe. The

ICD provides a significant resistance by influencing the flow from the sand-face to the base pipe (production

conduit), and thus influencing the flow from the reservoir to the sand-face. The pressure loss through the ICD

is generated by flowing fluid through nozzles. Static energy in the fluid is being converted into kinetic energy

and absorbed in the fluid downstream of the nozzle. The pressure loss through the nozzles is best described

using a part of the Bernoulli equation (Eq. 5.4.1) [8]:

∆ [8] (Eq. 5.5.1)

Where:

A: Cross-sectional area

q: Fluid flow rate

V: Velocity

ρ: Density

Page 28 of 57

Figure 19 shows the pressure drop graphically with the horizontal well-bore length along the x-axis and the

pressure in P (psi) along the y-axis. The reservoir is heterogeneous, hence different nozzle diameters are used

to regulate the permeability variations. The blue dashed line illustrates the average annulus pressure based

on the different nozzle settings. In high permeability zones a smaller nozzle diameter is used to choke the

inflow, hence stimulating the contribution from low to moderate permeability zones. This can be seen in figure

19 where the ICD has increased the pressure drop in the heel section and reduced the drawdown pressure

from the reservoir. The technology is self regulating and viscosity independent (nozzle-type ICD). From

equation (5.5.1) one can see that increased velocity will give increased pressure drop, which causes greater

resistance. This principle implies that the ICD reduces flow from high permeability zones and increase flow

from zones with lower permeability. Without the ICD’s there would be a higher drawdown pressure in the heel

section. This combined with the high permeability would result in a high contribution of oil from the heel

section and a limited contribution from the toe section.

Figure 19 ICD interaction in a heterogeneous reservoir [14]

Pressure (psi)

Measured Depth, MD (ft)

Pressure (psi)

Measured Depth, MD (ft)

Reservoir Pressure, PresReservoir Pressure, Pres

Heel ToeTypical Long Horizontal Well Completions Pressure profile

Tubing Pressure, PtbgTubing Pressure, Ptbg

Average annulus Pressure, Pann

At SandFaceAverage annulus Pressure, Pann

At SandFace

Heterogeneity / Permeability (mD)

Measured Depth, MD (ft)

Heterogeneity / Permeability (mD)

Measured Depth, MD (ft)

Heterogeneity / Permeability (mD)

Measured Depth, MD (ft)

Reservoir Drawdown,

∆PF1

Reservoir Drawdown,

∆PF1

Reservoir Drawdown,

∆PF1

ICD Design Pressure Drop

∆PN1

ICD Design Pressure Drop

∆PN1

ICD Design Pressure Drop

∆PN1

∆PF7∆PF7

∆PN7∆PN7

Page 29 of 57

5.6 Production index, PI

The production index (PI) shows the relationship between production rate and pressure loss between

reservoir and well. It is a measure of the wells production potential of well fluid [9].

For oil:

[9] (Eq. 5.6.1)

Where:

PI: Production index in m3/d/bar or bbl/d/psi (and d = 24-hour period)

q0: Production rate of oil in m3/d or bbl/d

qw: Production rate of water in m3/d or bbl/d

ps: Static reservoir pressure in bar or psi

pwf: Flow pressure in the well in bar or psi

When Reslink’s ResFlow nozzle ICD is introduced into the system we have

∆ [17] (Eq. 5.6.2)

Where:

q: Rate of oil

PDrawdown: Total pressure drop from reservoir to tubing in bar or psi

PReservoir: Reservoir pressure in bar or psi

FBHPScreen: Pressure drop between the filter and the base pipe before entering nozzles in bar or psi

ΔPNozzles: Pressure drop through nozzles in bar or psi

Page 30 of 57

5.7 Candidate Recognition

Current applications in both horizontal and/or deviated production wells to minimize coning of water and/or

gas. Homogeneous, heterogeneous, multilayered and thin oil column reservoirs are well suited for ICD

application.

Injection wells, either in horizontal and/or deviated injection wells to evenly distribute or balance the injection

along the well- bore in homogeneous and heterogeneous reservoirs. Here the main objective is to efficiently

add energy to the reservoir and to achieve uniform sweep of oil without exceeding or reaching fracture

gradient pressures, commonly occurring with conventional completions.

ICD technology adds value in reservoirs with declining production by injecting CO2 and water or both. Water

provides pressure support and the CO2 will fluidize remaining hydrocarbons, hence increasing the recovery

factor.

Page 31 of 57

6 SIMULATION AND ANALYSIS TOOL

6.1 NeToolTM Simulation Program

NEToolTM analysis software [11] is used to select the correct nozzle combination. NEToolTM is a program

based on equations of pressure loss in the reservoir, annulus and tubing. It is a toolbox for improved reservoir

management. The program can simulate different kinds of completion equipment in the well, and analyze the

results. Modelling from NEToolTM looks at the reservoir flow and the completion hydraulics. To get a full model,

data from upper completion will have to be imported. The flow from the near well-bore nodes (i.e. reservoir

gridblocks) into the well completion are represented by a specified number of nodes which can be connected

in a number of different ways in order to simulate flow through the annular space, through any completion

equipment such as ICD’s or through the tubing [10].

A limitation with NEToolTM is that it only creates a freeze-frame of the production in the well, and not the

production over a period of time. The program also anticipates stationary flow. To set up the lower

completion, data of the wells trajectory, and reservoir parameters like reservoir pressure and permeability will

be needed. The skin-factor can be set manually or be calculated from data on the reservoir damage. Fluid

properties like relative permeability and PVT will also have to be included. NEToolTM allow inputting different

ranges for the parameters that can be changed by the user to evaluate different scenarios. Figure 20 shows

the modelling principles of the NEToolTM simulation program[11].

Figure 20 Modelling of the well with NEToolTM [15]

Page 32 of 57

Diagram 1 illustrates the simulation flow diagram for NEToolTM analysis software. Parameters can be changed

to simulate different scenarios.

Diagram 1 Simulation flow diagram for NEToolTM

Page 33 of 57

7 FIELD EXAMPLE FROM THE NORTH SEA

7.1 Introduction

This section describes a simulation with real field data using NEToolTM. The simulations were performed with

four different objectives:

1. To compare the performance of a conventional Stand Alone Screen (SAS) with a completion

hardware using ICD’s

2. How zonal isolation (SP’s), Blank Pipe or other alternatives add value to the completion

3. After establishing the best case, evaluate how ICD’s will delay water breakthrough

4. Finally an example with ICD in injection mode will be shown to analyze the distribution of injected

fluids should a need for well stimulation arise

For all the scenarios a constant oil flow rate at 1500 Sm3/D is applied. Both non-collapsed and collapsed

annulus environments were considered.

7.2 Qality control of data

The reservoir grid was provided by Marathon Oil Corporation together with an alternative well trajectory. The

data set is from a field in the North Sea. Real field parameters will give more relevant and deterministic

simulations. Well trajectory data and PVT-data were imported to NEToolTM to create the fundament for the

simulations. Table 1 shows the reservoir and completion data.

Table 1 Reservoir and completion data

Page 34 of 57

7.3 Reservoir parameters

Figure 21 depicts the simulation grid. Upper section shows the horizontal projection of the well with pressure

distributions. The lower display section shows the vertical projection profile together with the well trajectory.

The pressure in the darkest red areas is about 227 bar, while the darkest blue grids have a pressure of about

206 bar.

Figure 21 Display of the simulation grid together with the proposed well trajectory and pressure

distribution attribute.

Well trajectory

Page 35 of 57

Figure 22 shows the horizontal permeability variations along the well trajectory. Notice the grey, which do not

contain data

Figure 22 Attribute display showing the horizontal permeability variations. The permeability along the

well trajectory varies from approximately zero Darcy in the darkest blue areas to 3,2 Darcy in the

lighter blue areas

In figure 23 vertical permeability (KV) relative to horizontal permeability (KH) is shown along the well trajectory.

The darkest red areas have a KV/KH ratio close to one. Blue grids have a KV/KH ratio varying between 0,00004

and 0,2, which implies a high horizontal permeability.

Figure 23 KV/KH along the well trajectory

Well trajectory

Well trajectory

Page 36 of 57

Figure 24 displays the oil saturation, where deep red colours indicate high oil saturation. Oil saturation in the

red grids varies from 0,7 to 0,9. The well is placed approximately 7 meters over the water contact showed by

the blue colour (very low oil saturation). The well trajectory is depicted through the grey horizontal line. As

can be seen from the grid some saturation data is missing from the toe section of the well (grey area without

grids). This is a source of error when performing simulations for different scenarios, and has to be taken into

consideration when evaluating the data.

Figure 24 Oil saturation along well trajectory. OWC approximately 7 m below the well trajectory.

Oil water contact

Page 37 of 57

Figure 25 display the water saturation. Dark red colours indicate high water saturation. In the blue grids the

water saturation ranges between 0,07 and 0,35. A very high resolution grid is used.

Figure 25 Attribute display of the water saturation

Figure 26 display the porosity along the well trajectory. Porosity average is approximately 23%. Over the

interval 4305 m to 4325 m the well is traversing a very low pay zone. This needs to be considered when

designing the well completion.

Figure 26 Attribute showing porosity along well trajectory. Red circle indicating low pay zone. Porosity

varies from 11,6% (dark blue grids) to 30,6% (dark red grids).

Below water contact

Above water contact

Well trajectory

Page 38 of 57

Figure 27 shows the permeability along the well trajectory. The permeability is showing variations along the

completion. The red colour is from the high resolution log and the light blue is the one that is up-scaled. The

permeability input is not the one extracted from the grid. High resolution log was selected in order to better

evaluate the performance of the completion (each section of the completion length is 12 m). Permeability is

varying along the completion trajectory from low to moderate to very high (0 7,5 D). In general the

permeability increases towards the toe, therefore the challenge for the completion is to stimulate production

from the toe section. The high resolution log reveals some zones with very high permeability values. For

instance at 4443 m the permeability reaches 7,5 D.

Figure 27 Permeability variations along well trajectory. High resolution log marked with pink colour and

the up-scaled log in blue.

Page 39 of 57

Figure 28 shows the reservoir pressure along the well trajectory. The pressure profile is extracted from the

reservoir grid, and that is why it shows a blocky response. The pressure averages about 207,50 bar and it

ranges between 207,35 and 207,66 bar.

Figure 28 Pressure variations along well trajectory. The x-axis show measured depth (MD) and the y-

axis show pressure in bar.

Page 40 of 57

Figure 29 show the saturations of oil and water along the well trajectory. The saturations are extracted from

the grid. The green bars show the oil saturation and the blue bars the water saturation. The oil saturation

varies from 0,8 to 0,5. The complement is the water saturation. There is no data at the grey zones, except at

3280 m where a section of cemented blank pipes is placed in the completion. The challenge in the completion

is to handle the saturation differences, and to achieve a balanced flux from the reservoir into the well. Water

cut reduction and early water breakthrough is one of the main challenges of the successful ICD completion.

Figure 29 Saturations profile along the well trajectory showing variability (could be due to previous oil

production, mature reservoir)

7.4 Results from the producer well evaluation

The first objective was to compare the performance of a conventional completion with SAS (Stand Alone

Screen) with a completion using ICD’s. Zones with cemented blank pipes (CBP) where kept at original

positions as per the Marathon well data (3280 m, 3765 m and 3765 m). A non- collapsed annulus (NCA) was

selected as the general comparison scenario. Two nozzle settings are used for the ICD simulations, 0,4137 cm

(diameter) from heel to 3280 m and 0,5402 cm to the toe of the well. The two ICD sizes were selected based on

permeability, saturations and reservoir environment. Consequently, pressure readings will be higher over the

first section of the well and lower towards the toe because of differences in nozzle sizes.

Page 41 of 57

7.4.1 Non-Collapsed Annulus

Non-collapsed annulus is a case where the formation sand has not collapsed onto the pipe or screens,

leaving an open annulus between pipe/screen and the formation.

Figure 30 Summary display of conventional completion:

a) Permeability profile along the completion, b) Reservoir Pressure (red) conventional tubing and

annular pressure with very low dynamic range (overlapping colour pink and blue), c) Oil flux rate,

where the conventional completion show high volume in the tubing and in the annulus, d) Gas flow

rate, similar response to the oil flow rate, e) Water flow rate, notice a high volume of water circulating

in the annulus, may cause screen erosion and hot spotting if the well is completed with only screens,

and f) Oil and water saturations.

Cemented blank pipes

Annular and tubing pressures Reservoir pressure

QO tubing

QO annulus

Cemented blank pipes

a)

b)

c)

d)

e)

f)

Page 42 of 57

Figure 31 Summary display of the ICD completion. Highlighted in red, the interval where annular flow is

slightly higher, it is because of the larger nozzle size. However this flow will be further minimised by

introducing OH packers. a) Permeability profile along the completion, b) Reservoir Pressure (red) ICD

completion annular (pink) and tubing (blue) pressure c) Oil flux rate, where the ICD completion show

high volume in the tubing and low in the annulus, d) Gas flow rate, similar response to oil flow rate, e)

Water flow rate, notice the low volume of water circulating in the annulus, and f) Oil and water

saturations.

Pressure differences are minimal being 2 bar for conventional and 2,5 bar for ICD. The ICD show a slightly

lower water rate and very similar water cut (about 19,5%). The standard completion has high annular flow.

ICD’s minimizes the annular flow and stabilizes the drainage profile. Annular and tubing pressures are

separated using the ICD, only disrupted in the areas where we have cemented blank pipes. From about 3800 m

to the toe the base case ICD completion still show increase in annular flow (highlighted in red), which will

require further optimization (OH Packers).

Annular pressure

Tubing pressure

QO tubing

QO annulus

f)

a)

b)

c)

d)

e)

Page 43 of 57

Figure 32 Pressure comparison between a conventional completion and one with ICD’s along the entire

well length. Notice: The highlighted red circle showing lower drawdown for both completions. a)

Tubing and annular pressure for both conventional and ICD completion, b) Reservoir pressure along the

completion, c) Drawdown pressure for both the ICD and conventional completion, d) Notice the

pressure drop along the completion with ICD’s are higher than in the conventional completion.

Therefore the ICD will enhance production at the toe part of the well, where conventional completions

usually are very passive.

The pressure plot show nearly a constant drawdown for the conventional completion, from 2,28 bar to 1,74 bar

in the toe. An insignificant pressure drop along the completion. The ICD completion have a uniform drawdown

pressure in the different permeability zones.

Conventional: Annular and tubing pressure

ICD: Annular pressure

ICD: Tubing pressure

Reservoir pressure

Conventional

ICD Cemented blank pipe

Cemented blank pipe

a)

b)

c)

d)

Page 44 of 57

Figure 33 Oil flow rate: conventional completion and one with ICD’s. Notice the difference in annular

flow for the two completion options

There is a better oil flow rate with ICD’s than just with a standard completion, because ICD’s minimize annular

flow. From 2750 m to around 4300 m the ICD completion has a considerable higher oil flow rate. The red circle

indicates the area to be further optimized. Toward the toe of the well the ICD still show annular flow, hence

the flow rate lies under the standard completion. Annular flow could lead to severe erosion and/or screen

plugging.

One single nozzle size acts differently in the reservoir because the permeability profile shows mainly two

zones. Therefore the simulation should try to equalize the flow in the heterogeneous reservoir, by stimulating

the low to moderate permeability intervals to produce more. At the same time to stimulate the toe part to

contribute to the production.

ICD Completion

Interval to be further optimised

ICD annular flow

Conventional: annular flow

Conventional completion: Tubing

Cemented Blank Pipe

Page 45 of 57

Figure 34 Oil flux: Conventional completion (blue) and one with ICD’s (pink)

Figure 34 show the oil flux with a conventional (blue) completion and one with ICD’s (pink). Between heel

section of the well to about 3750 m ICD oil flux is higher than conventional and vice versa towards the toe part.

The ICD has two nozzles size settings. Notice that these tests are processed using a Non-Collapsed Annulus

(NCA) option, furthermore the completion geometry of a conventional and ICD completions have different flow

dynamics along the well.

Conventional

ICD Completion

Interval to be further optimised

Page 46 of 57

Figure 35 Oil flow rate: Conventional and one with ICD’s with 3 OH packers located at 4055 m, 4435 m

and 4645 m. Notice how the performance of the ICD’s is enhanced and the annular flow (light blue) is

almost eliminated by introduction of the 3 OH packers.

As can be seen in figure 35 the annular flow output after installing 3 OH packers in the completion has

significantly reduced annular flow and enhanced oil recovery. The ICD completion with 3 packers (green line)

has now a larger oil flow rate than the conventional completion along the entire well. The water rate has

decreased with 12 Sm3/d and water cut has been further reduced by 0,55%. Table 2 shows the results of the

non-collapsed annulus scenario.

Table 2 Results of the non-collapsed scenario

Option: Non-Collapsed Annulus (NCA)Oil rate Gas rate Water rate GOR WCUT LGR Q res. total BHP[Sm3/d] [MMSm3/d] [Sm3/d] [Sm3/Sm3] [%] [Sm3/Sm3] [Rm3/d] [Bar]

Conventional 1499.9384 0.160193423 374.275916 106.800002 19.9697502 0.0116996957 2321.93425 205.1665871ICD base case 1500.25221 0.160226938 373.210219 106.800002 19.9208809 0.0116925559 2321.46966 204.5214831ICD BC packers 1499.96287 0.160196037 362.293092 106.800002 19.4545272 0.0116248566 2310.04788 204.4199563

ICD Completion

Conventional Completion: Tubing

Conventional: Annular flow

ICD: Annular flow

Interval further optimised

Page 47 of 57

7.4.2 Collapsed Annulus Scenario

Collapsed annulus simulation shows similar trend as the non-collapsed annulus stimulating low to moderate

permeability zones to produce more. The production profile shows a slightly lower oil flow rate for the ICD,

however the water breakthrough test will show higher performance.

Table 3 Results from the collapsed annulus scenario

7.4.3 Water Breakthrough (Collapsed Annulus)

A random interval was selected simulate early water breakthrough. The objective is to lift dry oil and extend

the production life of the well. The interval from 3885 m to 3925 m was selected for the simulation. Permeability

greater than one was selected for the interval. Saturations were changed to 0,3 for oil and 0,7 for water.

Figure 36 show the oil flow rate for both ICD and conventional completion.

Figure 36 Oil flow rate after water breakthrough: Conventional completion and one with ICD’s with 3 OH

packers at 4055 m, 4435 m and 4645 m

.

Oil rate Gas rate Water rate GOR WCUT LGR Q res. total BHP[Sm3/d] [MMSm3/d] [Sm3/d] [Sm3/Sm3] [%] [Sm3/Sm3] [Rm3/d] [Bar]

Conventional 1499.5718 0.16015427 362.599816 106.800002 19.4718797 0.0116273616 2309.74853 204.7396453ICD BC packers 1498.51081 0.160040958 369.066479 106.800002 19.761778 0.0116693709 2315.08373 204.2925893

Option: Collapsed Annulus (CA)

ICD Completion with 3 packers

Conventional Completion

Page 48 of 57

Figure 37 Water flow rate after water breakthrough: Conventional completion and one with ICD’s with 3

OH packers at 4055 m, 4435 and 4645 m

The ICD with a smaller size (0,4137 cm) delays the water efficiently in the first half of the well (see fig. 37),

while in the second half the larger ICD size (0,5402 cm) is enhancing oil production (see fig. 37). A compromise

had to be made. The ICD completion increases oil production from the toe section, but at the same time it

increases the water cut. Compared to the conventional completion, the ICD set up has decreased water flow

rate significantly. Water rate has decreased from 544,8 Sm3/d for conventional completion to 403,3 Sm3/d for

the ICD completion. Oil flow rate is 1096 Sm3/d for the ICD completion with OH packers and 955 Sm3/d for the

conventional completion. Figure 38 shows a reduction in water cut from 36% to 27% in favour of the ICD

completion.

Conventional Completion

ICD Completion with 3 packers

Page 49 of 57

Figure 38 Oil Flux Reservoir to Well: after the water breakthrough. a) Oil flux for ICD and conventional

completion, b) Gas flux for ICD and conventional completion, c) Water flux for ICD and conventional

completion. Notice the reduction of water flux in the water breakthrough area, d) GOR along well

trajectory, e) Water cut along well trajectory

Conventional Completion 36%

ICD Completion 27%

ICD Completion

Conventional Completion

a)

b)

c)

d)

e)

Page 50 of 57

Figure 39 Pressure Comparison between a conventional completion and one with ICD’s after the water

breakthrough. a) Annulus and tubing pressures for ICD and conventional completion, b) Reservoir

pressure along well trajectory, c) Draw down pressure for ICD and conventional completion, d)

Pressure drop across the completion for ICD and conventional. Notice the pressure drop for the

conventional completion is 0 bar

As a curiosity the reservoir pressure was already showing a lower trend in the WBT (water breakthrough)

area.

Table 4 Results from the water breakthrough scenario (collapsed annulus)

Option: Water BreakthroughOil rate Gas rate Water rate GOR WCUT LGR Q res. total BHP[Sm3/d] [MMSm3/d] [Sm3/d] [Sm3/Sm3] [%] [Sm3/Sm3] [Rm3/d] [Bar]

Conventional 955.153824 0.10201043 544.80438 106.800002 36.3213041 0.014703969 1789.52838 205.6592684ICD BC packers 1096.15866 0.117069747 403.298903 106.800002 26.8963198 0.0128082412 1828.58439 205.1852942

Conventional: annular and tubing pressure

ICD tubing pressure

ICD annular pressure

Conventional

ICD

a)

b)

c)

d)

Page 51 of 57

7.5 Converting the producer well into an ICD in injection mode

The completion layout was converted into an injector to evaluate the injection mode. Reservoir properties and

the hardware with ICD’s are kept at the original settings. Water injection rate of 1000 l/min was used in the

example. The injection pressure has to be below the formation fracture pressure. The fracture pressure is

nearly the same along the well trajectory. This helps to achieve more uniform distribution of the injected

fluids.

Figure 40 Summary plot: ICD injection mode. a) Horizontal (red) and vertical (brown) permeability, b)

ICD tubing pressure (brown), ICD annular pressure (green), conventional annular and tubing pressure

(pink and blue) and reservoir pressure (turquoise), c) Water flow rate for ICD (red) and conventional

(blue).

Figure 40 shows a summary plot for the injection simulation. At 4450 m the permeability is very high and the

section acts as a thief zone when injecting using conventional completion (SAS). Notice how the annular

pressure decreases when using ICD in this zone (see fig. 40 b). This shows the self regulating effect of the

ICD. The annular and tubing pressures for the conventional completion are equal along the well-bore.

ICD tubing pressure

Conventional: annular and tubing pressure ICD annular pressure

Reservoir pressure

a)

b)

c)

KH

KV

Page 52 of 57

As figure 41 shows, the ICD completion gives a more uniform injection distribution. This results in a better

injection performance. The conventional completion has a high water flux in high permeability zones and/or

fractured zones.

Figure 41 Water flux: Conventional completion and one with ICD’s. If the well have scale potential

deposition, a well treatment using the same configuration will distribute the anti-scale inhibitors evenly

thus extending the life of the well. The added benefit of ICD’s is the performance in producing and

injection mode without adding extra costs.

Table 5 Injection parameters

Water rate Q res. total BHP[Sm3/d] [Rm3/d] [Bar]

Conventional 1499.92916 1522.13377 208.2261854ICD BC packers 1500.00426 1522.19949 208.4124388

Option: Injection

Conventional completion

ICD completion

Balanced injection

and better injection

conformance

Page 53 of 57

8 CONCLUSION

The increasingly popular horizontal wells suffer from unbalanced influx and injection profile. This can be

greatly improved by introducing Inflow Control Devices (ICD), which choke the inflow or outflow through the

ICD, thus balancing the production or injection profile along the well-bore.

The ICD completion design shows higher performance in terms of reservoir inflow balance and efficiently

delaying early water breakthroughs, thereby reducing the water production over time.

Two nozzle size setting handles the differences in permeability and reservoir properties along the entire well,

thus stimulating the low to moderate permeability intervals to produce more. The well will have a longer

production life due to more uniform drainage. The optimum completion design – ICD’s with OH packers –

offers tangible benefits in terms of accelerated production and increased oil recovery. This thesis does not

consider the life cycle economics, but the simulations suggest a high potential for better NPV compared to the

conventional completion.

NEToolTM only provides a snap shot of the well performance. As stated in the recommendations, full well life or

even field life simulation using a dynamic reservoir model is required for more complete evaluation of

well/field performance and the economics. Having said this, the NEToolTM simulations offer guidance in

selecting the right type and size of completion. The benefit of the NEToolTM is that the simulations can be run

much more quickly than the ones with dynamic models.

Simulations were performed with NEToolTM to compare the performance of conventional Stand Alone Screen

(SAS) versus screens with ICD’s. The ICD completion minimizes the annular flow effectively and balances the

drainage profile. Further improvement in terms of reduced water cut and increased production was achieved

by adding the open hole (OH) packers. The OH packers eliminate the risks related to the annular flow; erosion

and/or plugging of the screens.

The water breakthrough simulation with ICD’s decreased water rate significantly compared to the

conventional completion (SAS). The water rate decreased from 544,8 Sm3/d (conventional completion) to 403,3

Sm3/d (ICD completion). Oil production for the ICD completion with OH packers is 1096 Sm3/d versus 955 Sm3/d

in the conventional completion.

The injection simulation showed a more balanced injection profile along the well-bore using ICD’s. The

conventional completion had a high water flux into the high permeability/fractured zones, also called thief

zones. This added benefit of using ICD’s can become important if stimulations are required later in the well

life.

9 RECOMMENDATIONS

Further work could include:

a. Evaluate ICD design with different Total Reservoir Rates (tested only with 1500 Sm3/d).

b. Alternative nozzle locations, e.g. every second joint if cost minimization is an issue.

Page 54 of 57

c. The best case defined in this thesis, could be the input for the dynamic simulator.

d. ICD in injection mode sensitivities with variable anti-scale inhibitors (tested only with 1000 l/m).

10 ACKNOWLEDGEMENTS

This thesis was written in cooperation with Schlumberger ResLink. Reslink is a Ålgård and Houston based

design and manufacturing company of screens and ICD’s. Reslink’s in-house reservoir department performs

simulations and evaluations of the ICD technology.

I want to thank Reslink for giving me the opportunity to write the thesis and especially Reslink’s Reservoir

Engineer Francisco Porturas, who has been my mentor throughout the process. His guidance and many

valuable advices have been of paramount importance. I also want to thank Professor Erik Skaugen at the

University of Stavanger for mentoring.

Special thanks to Senior Completion Engineer Tor Ellis, Marathon Oil for kindly providing the reservoir data

used in the simulations

11 NOMENCLATURE

ICD Inflow Control Device

SP Swell Packer

SAS Stand Alone Screen

NCA None Collapsed Annulus

CA Collapsed Annulus

NPV Net Present Value

ECP External Casing Packer

WBT Water Breakthrough

WCUT Water Cut

BHP Bottom Hole Pressure

OH Open Hole

OWC Oil Water Contact

CBP Cemented Blank Pipe

Page 55 of 57

GOR Gas Oil Ratio

LGR Liquid Gas Ratio

BC Base Case

RDF Reservoir Drilling Fluid

AICD Autonomous Inflow Control Device

WWS Wire Wrapped Screen

12 REFERENCES

12.1 Written references

1. National Aeronautics and Space Administration. [Online]. Bernoulli’s Equation. Address:

http://www.grc.nasa.gov/WWW/K-12/airplane/bern.html. [Downloaded 01/14-08] 2008.

2. Efluids bicycle aerodynamics. [Online]. Bernoulli’s Equation. Address:

http://www.efluids.com/efluids/bicycle/bicycle_pages/Bernoulli.jsp. [Downloaded 01/16-08] 2008.

3. Tor Austad and Jostein Kolnes. Reservoir Engineering – Part 2.

4. Frank Jahn, Mark Cook and Mark Graham.Hydrocarbon exploration and production. Developments in

petroleum science 46.Aberdeen, TRACS international ltd.1998.

5. Schlumberger. http://www.glossary.oilfield.slb.com/DisplayImage.cfm?ID=498. [Downloaded 01/22-

08] 2008.

6. Reslink Power Point presentation. “Next Gen of Flow Control with Sand Screens”. Workshop 5-6

September 2007.

7. Anatoly B. Zolotukhin, Jan-Rune Ursin. Introduction to Petroleum Reservoir Engineering.

Høyskoleforlaget. 2000.

8. SPE 106018. ICD Screen Technology Used To Optimize Waterflooding in Injector Well. A.G Raffn, SPE,

Reslink, S. Hundsnes, SPE, Statoil; S. Kvernstuen, SPE, T. Moen, SPE, Reslink. 2007.

9. Erland Jørgensen. “Produksjonsteknikk 1”. Vett & Viten AS. 1998.

10. SPE 108700. Inflow control device: Application and value quantification of a developing technology.

F.T. Alkhelaiwi, SPE, Heriot-Watt University and Saudi-Aramco, and D.R. Davies, SPE, Heriot-Watt

University. 2007.

11. DPR Power Point presentation. FORCE AWTC Seminar, 21-22 April, 2004. Advanced Wells - Lessons

Learned (application experience) and Future Directions/Opportunities.

Page 56 of 57

12. R.D. Fritz, M.K. Horn, S.D. Joshi. Geological Aspects of Horizontal Drilling. The American Association

of Petroleum Geologists, 1991.

13. Flotech products. [online]. http://flotechltd.com/data/FloMatik_C.PDF [Downloaded 04/30-08] 2008.

14. Reslink Power Point presentation. 03/26-08. “Advance Completions Application of Passive Inflow

Control in Horizontal Well Production”.

15. Institutt for petroleumsgeologi og anvendt geofysikk. Statoil ASA, and. Bergen. Eksperter I team,

Gullfakslandsbyen. “Kompletteringsløsning på GF B-17AT2”. Andreas Mathiassen, Atle Storaker, Tor

Erik Askeland og Trygve Adolfsen. Trondheim 9. Mai 2007.

16. SPE 112471. Inflow Control Device and Near Well Bore Interaction. T. Moen. SPE, Reslink AS and H.

Asheim, SPE, NTNU. 2008.

17. Completion – ICD: Modelling Workshop Saudi Aramco. Francisco Porturas.Reslink – Norway.

September 2007.

18. Optimising production in Horizontal & Multilateral wells 2008. The Ardoe House Hotel, Aberdeen, U.K.

29/30 January 2008. ICD Completions. Round Table Discussion. Tor Ellis, Senior Completion Engineer,

Marathon Oil.

19. RedTech. Enhancing the capabilities and economics of complex completions. [online]. Address:

http://www.halliburton.com/public/divisions/pubsdata/PO/RedTech/notes/Sand-Screens-

PodCast.pdf?linkType=Sand-Screens-PDF. [Downloaded 22.05.08] 2008.

20. Ziebel. Inflow Control Technology. [online]. Address: http://www.ziebel.biz/icd/ICD_Overview.pdf.

[Downloaded 23.05.08] 2008.

21. SPE 102208. Means For Passive Inflow Control Upon Gas Breakthrough. S.L. Crow, SPE, M.P.

Coronado, SPE, and R.K. Mody, SPE, Baker Oil Tools. September 2006.

12.2 Oral references

22. Francisco Porturas, Reservoir Engineer in Reslink

23. Timo Jokela, completion specialist in Schlumberger

12.3 Software

24. Microsoft Excel (2007)

25. Microsoft Word (2007)

26. Microsoft Power Point (2007)

Page 57 of 57

27. NEToolTM (version 2.9), a steady-state completion hydraulics and near-well-bore numerical simulator

for accurate calculation of well performance.