7.9 Vertical Flow Performance

KCP-RDS-CWE-REP-1002 Rev.: 03

Project Title: Kingsnorth Carbon Capture & Storage Project Page 1 of 33

Document Title: Vertical Flow Performance

Kingsnorth CCS Demonstration Project The information contained in this document (the Information) is provided in good fai th. E.ON UK plc, i ts subcontractors, subsidiaries, affi l iates, employees, adviser s, and the Department of Energy and Cl imate Change (DECC) make no representation or warranty as to the accuracy, rel iabil i ty or completeness of the Information and neither E.ON UK plc nor any of i ts subcontractors, subsidiaries, affi l iates, employees, advisers or DEC C shal l have any l iabil i ty whatsoever for any direct or indirect loss howsoever arising from the use of the Information by any party.

Vertical Flow Performance

Table of Contents Executive Summary ................................................................................................................. 2

Nomenclature ........................................................................................................................... 4

1. Introduction ...................................................................................................................... 5

1.1. Scope ........................................................................................................................ 6

1.2. Related Project Documents ...................................................................................... 6

2. Data Review ..................................................................................................................... 8

2.1. Formation Properties ................................................................................................ 8

2.1.1. Lower Bunter Properties ........................................................................................... 9

2.1.2. Overburden Formation & Thermal Properties .......................................................... 9

3. Initial Well Design .......................................................................................................... 11

4. Inflow Performance Relationship & Injectivity Index ................................................. 13

4.1. Gaseous Injection ................................................................................................... 13

4.1.1. Static Modelling ...................................................................................................... 13

4.1.1.1. Jones IPR Model .................................................................................................... 13

4.1.1.2. Multi-Rate Jones IPR Model ................................................................................... 13

4.1.1.3. Forchheimer IPR Model .......................................................................................... 13

4.1.2. Transient Modelling - OLGA ................................................................................... 16

4.2. Dense Phase Delivery ............................................................................................ 16

4.3. Inflow Performance Model Considerations ............................................................. 17

5. Well Performance & Injectivity ..................................................................................... 18

5.1. Gas Phase Delivery (Demonstrator) ....................................................................... 18

5.2. Dense Phase Delivery (Full System) ...................................................................... 22

5.2.1. Initial Dense Phase Injection – Steady State .......................................................... 22

5.2.2. Dense Phase Delivery – Transient Analysis ........................................................... 23

6. CO2 Injection Schedule ................................................................................................. 27

6.1. Additional Field Development Considerations ........................................................ 28

7. Conclusions ................................................................................................................... 29

8. Recommendations ........................................................................................................ 30

9. Mandatory References .................................................................................................. 31

10. Supporting References ................................................................................................. 32

11. Conversion Factors ....................................................................................................... 33





Executive Summary

This report presents the results from the Vertical Lift Performance (VLP) and Inflow Performance Relationship (IPR) carried out in order to determine the initial size and number of wells required to inject CO2 into the Hewett CO2 storage site (Lower Bunter formation).

The analysis was carried out using models developed in Prosper (for initial screening) and in OLGA (to ensure stable flow could be achieved). The conditions for which the analysis was carried out are shown in the table below.

Property Demonstrator

(Gaseous Phase) Full System

(Dense Phase)

Rate (te/day) 6,600 26,400

Max Delivery Pressure (barg) 35 79

Min Delivery Temperature (°C) 4 4

Min Ambient Temperature (°C) -6 -6

Hewett CO2 Delivery Conditions

The selection of the number of wells is based on a number of criteria, and not only the ability to inject the required rate per day. The first criterion is to ensure that the CO2 maintains a single phase in the wellbore. Another consideration is the BHIP with respect to the reservoir pressure. It is important not to have an excessive pressure differential across the sandface which would induce further cooling in the near wellbore and indeed should this be excessive may result in fracturing of the formation.

Next, the well count should not be increased more than is required, not only from an economical standpoint, but also from the engineered integrity of the storage site and complex. The more wells that are drilled into the storage site, the greater the potential for CO2 migration. Finally, the rate per well should be such that the velocities within the wellbore do not result in hydraulic erosion.

A base well design has been constructed with 7” tubing string and a deviation of 50 degrees through the reservoir. This allows for:

Minimising the initial number of wells required while allowing for flexibility in delivery

Ensuring drillability through the highly depleted Lower Bunter.

Areal spacing to minimise the effects of thermal interference between wells.

Use of wireline intervention

Inflow Performance Relationships have been developed for injecting gaseous and dense phase CO2 into the Lower Bunter.

For gaseous phase, the Forchheimer equations have been used with a Non-Darcy coefficient (a) of 2.3538x10

-6 psi

2/(Mscf/day)

2 and a Darcy coefficient (b) of 1.26467 psi

2/Mscf/day.

For dense phase injection, a PI of 2882 Sm3/day/bar (1250 STB/day/psi) was calculated based on reservoir and fluid properties.

Simulations in OLGA have shown that for a CO2 injection rate of 6,600 te/day in gaseous phase three wells (plus one contingency) are required with 7” tubing. The gaseous phase can continue with the above well configuration until the reservoir pressure reaches 33 barg based on a limiting WHIP of 35 barg.





Dense phase delivery will initially require eight wells (plus one contingency) with 7” tubing in order to inject the anticipated 26,400 te/day. This number will drop to six as the reservoir pressure increases.

A summary of the key pressures, temperatures and well count is given in the figure below:

0

20

40

60

80

100

120

140

160

0 10 20 30 40 50 60 70

Time (years)

Pre

ssu

re (

bar)

0

10

20

30

40

50

60

70

80

Tem

pera

ture

(d

eg

C)

Reservoir Pressure

BHIP

WHIP

BHIT

Dense P

hase

Gaseous P

hase

3 Wells 6 Wells8 Wells

CO2 Injection Schedule – Pressure, Temperatures and Well Count

While the demonstrator phase can be completed using 3 x 7” wells, it is recommended that a fourth well be provided as contingency to allow for intervention and maintenance work as well as variations in the supply and well availability.

A drilling program needs to be established and the risks associated with batch drilling all the wells versus drilling though an existing CO2 store examined.

Finalisation of the injection schedule needs to be completed following verification of individual well trajectories and tubing size based on tubing stress analysis and the completion design process.

The proposed 36” pipeline has a capacity of around 40,000 te/day in dense phase, but the implementation of this would require additional power stations with carbon sequestration to feed into the Kingsnorth CO2 pipeline. This increase in rate would require additional wells in addition to those defined in this report. While detailed analysis has not been carried out at this stage, a basic nodal analysis indicates that a total of 12 wells (plus one contingency) would be required for this higher volume.





Nomenclature

Variable Meaning

“ inch

API American Petroleum Institute

bara Bars absolute

barg Bars gauge

BHIP Bottomhole Injection Pressure

BHIT Bottomhole Injection Temperature

Bscf Billions of standard cubic feet

CCS Carbon Capture Storage

CO2 Carbon dioxide

deg Degrees

EVR Erosional Velocity Ratio

ft Feet

IPR Inflow Performance Relationship

m Metres

MMscf Million Standard Cubic Feet

MMscf/d Million Standard Cubic Feet per day

psi Pound per square inch

psia Pounds per square inch absolute

psig Pounds per square inch gauge

scf Standard cubic feet

TVDss True vertical depth Subsea (MSL or LAT)





1. Introduction

This report outlines the well requirements for injecting gaseous and dense phase CO2 into the Lower and Upper Bunter formations of the Hewett field. The intention is to provide an initial well design based on the rate requirements as well as identify the impact of wellhead pressure and temperature conditions and the subsequent pressures and temperatures that will be encountered at the sand face (bottomhole conditions). This report does not cover detailed well design with respect to casing and tubing sizes, weights and metallurgy although reference to these are made for clarity and cross reference.

The CO2 will be transported from the capture site at Kingsnorth approximately 270 km via a 36” pipeline to the Hewett field. The majority of this pipeline will be subsea, resulting in a cooling effect on the CO2 to 4 °C in winter. A schematic of the proposed system is shown in Figure 1-1 below.

Figure 1-1: Kingsnorth CCS System Schematic (courtesy: Genesis)

During the demonstrator phase, the CO2 will flow in gaseous phase at a rate of 6,600 te/day. At some point in the future delivery of the CO2 will change to dense phase, with rates increasing to 26,400 te/day.

As a result of the cooling in the subsea transport pipeline, the maximum pressure which can be provided at the wellhead at the Hewett platform is 35 barg during gaseous phase delivery. This is required in order to prevent CO2 condensing in the pipeline. During dense phase liquid phase delivery (i.e. above critical pressure, but below critical temperature), the maximum delivery pressure at Hewett will be 79 barg. This information is summarised in Table 1-1 below and graphically in Figure 1-2.

Property Demonstrator

(Gaseous Phase) Full System

(Dense Phase)

Rate (te/day) 6,600 26,400

Max Delivery Pressure (barg) 35 79

Min Delivery Temperature (°C) 4 4

Min Ambient Temperature (°C) -6 -6

Table 1-1: Hewett CO2 Delivery Conditions





0

10

20

30

40

50

60

70

80

90

100

-50 -40 -30 -20 -10 0 10 20 30 40 50 60

Temperature (deg C)

Pre

ssu

re (

barg

)

Full System

Hewett Delivery

Conditions

Demonstrator

Hewett Delivery

Conditions

Dense Phase

Region

Figure 1-2: Hewett Delivery Conditions with Phase Envelope

1.1. Scope

The scope of this project focuses around the vertical lift performance and inflow performance relationship for the wells. Specifically, it considers:

Quantification of the inflow performance relationship and injectivity index based on reservoir parameters

Determination of the vertical lift performance curves

Quantification of the impact of CO2 phase change during the project

Assess the impact of deviated wells on the injection of CO2

Determine the required pressure drop across the sandface

Define initial well casing and tubing solutions

Define the injection rates that conform with the facility design constraints

Determine the number of wells required for both the 400 MW (demonstrator) and 1600 MW (full system) phases

Develop a CO2 injection schedule for the project lifecycle

1.2. Related Project Documents

Interdependent project reports are as follows:

KCP-RDS-CWE-REP-1000 (Rev:03) Establish CO2 Supply Properties[M1]

KCP-RDS-CWE-REP-1001 (Rev:03) Injectivity – Wellbore Stability for New Wells[M2]

KCP-RDS-CWE-REP-1003 (Rev:03) Injectivity – Near Wellbore Issues[M3]

KCP-RDS-CWE-REP-1004 (Rev:02) Injectivity – Specify Initial Well Design Criteria[M4]





KCP-RDS-CWE-REP-1005 (Rev:02) Injectivity – Specify New Well Completions Criteria

[M5]

KCP-RDS-CWE-REP-1006 (Rev:01) Injectivity – Temperature Effect on Well and Reservoir

[M6]





2. Data Review

The following sub sections briefly outline the software used in the various analyses presented in this report, along with the data used for calculations.

2.1. Formation Properties

In order to model the injectivity of the CO2 into the formation, an understanding of the formation properties is required. The following sections present the properties for the Lower and Upper Bunter sandstones. Figure 2-1 below shows the location of the Lower and Upper Bunter sandstones relative to one another within the proposed storage complex. Note that these depths are based on the averages taken from the various wells within the field.

TVD

DEPTH SS

(Ave m)

Reservoir

/Seal

AVE Thickness

(m)

48.8

200 167.6

300

500

DEEP SALINE FM 30.5

600

1

800

900

1100

Potential CO2

Storage Site146.3

1200

10.7

CO2 Storage site 24.4

1350 21.3

1550

1725

STRATIGRAPHIC UNIT

North Sea (35m)

Speeton Clay

Lias

Undifferentiated

Dowsing Dolomitic Fm (Dolomite Stringers and

Rot Halite)

Triton Anhydritic Fm

158.5

Dudgeon Saliferous

134.1

SEAL

Upper Bunter Sand

SEAL 228.6

SEAL 222.5

Brockleschiefer MBR

Lower Bunter Sand

Zechstein Group

Lower Bunter Shale

Bunter Shale

Keuper Anhydrite

259.1

Winterton

SEAL

RESERVOIR 140.2Leman Sandstone

Figure 2-1 – Hewett Field - Generalised Stratigraphic Column

30.5





2.1.1. Lower Bunter Properties

At the proposed start of injection the reservoir pressure in the Lower Bunter formation of the Hewett field may be as low as 2.7 bara. The reservoir temperature is known to be 52.2 °C

[S1].

The Lower Bunter storage site has excellent (high) permeability and porosity. Table 2-1 below lists the properties which will have been used for the injectivity modelling:

Property Unit Value

Formation Top Meters 1249.7*

Formation Thickness Meters 24.4*

Permeability Milidarcies 1000

Rock Density Kg/m3 2600

Formation Thermal Conductivity W/m.C 1.834

Formation Heat Capacity J/kg.C 766.18

Reservoir Pressure at start of Injection Bara 2.69

Formation Temperature °C 52 *Based on average of well depths

Table 2-1: Lower Bunter Formation Properties

2.1.2. Overburden Formation & Thermal Properties

The well model (Prosper or OLGA) requires information not only on the tubing and casing sizes and depths, but also on the various formations through which the well will pass from surface to the sandface. The thermal properties of these formations will vary with formation type (i.e. sandstone, claystone, limestone etc.) and this needs to be considered in order to accurately model the heat transfer between the wellbore and the formation.

Table 2-2 below lists the formations top to bottom along with the formation tops, thickness and approximate thermal properties

[S2]. Note that all depths are taken from the mean sea

level.

Formation Rock Type Top (m)

Thickness (m)

Density (kg/m

3)

Conductivity (W/m.C)

Heat Capacity (J/kg.C)

Sea - 0 35.0 1027 3935.592

Undifferentiated (incld Speeton)

Sandstone 35.0 216.4 2650 1.83458 766.184

Lias Shale 251.4 259.1 2400 1.21151 937.843

Winterton Sandstone 510.5 30.5 2650 1.83458 766.184

Triton Shale 541.0 158.5 2400 1.21151 937.843

Dudgeon Anhydrite 699.5 30.5 2960 1.29805 1109.5

Dowsing Shale 730.0 134.1 2400 1.21151 937.843

Upper Bunter Sandstone 864.1 146.3 2650 1.83458 766.184

Bunter Shale (incld B‟schiefer)

Shale 1010.4 239.3 2400 1.21151 937.843

Lower Bunter Sandstone 1249.7 24.4 2650 1.83458 766.184

Table 2-2: Formation Depths and Thermal Properties

In addition to the thermal properties of the formation, the ambient air temperature has been taken as -6°C and the sea temperature was taken as 4°C. These temperatures are both





considered to be worst case winter temperatures and have been selected since they impact on the maximum pressure that can be managed in the pipeline system without crossing the vapour line from gas to liquid phase.

The thermal gradient for the formations from sea bed was taken as a linear gradient from 4°C at the sea bed to 52°C at the Lower Bunter (approximately 3.9°C per 100 m)





3. Initial Well Design

An initial well design has been constructed based on Prosper modelling which established an approximate tubing size and well trajectory. The indications from the static Prosper modelling showed that 3 wells with 7” tubing would be required to inject the required volumes of 6,600 te/day of CO2 into the formation. While other configurations of tubing size and well count are possible, the selection of this tubing size, well count and trajectory is based on the following:

Minimise the number of wells and subsequent potential CO2 migration paths.

Minimise drilling and completion costs

Allow flexibility in CO2 delivery rates

Utilise where possible field proven technology (e.g. standard tubing size)

In addition the trajectory of the wells has been based on the drillability of the formation[M2]

taking cognisance of the fact that the injection points for each well need to be aerially distant from one another to prevent interference effects from the CO2 in the near wellbore. A schematic for the initial well design is shown in Figure 3-1. Note that the formations are an indication only of the geological structure with the focus being on heat transfer and not accurate geological description. The well trajectory is given in Table 3-1. Note that the trajectory will be confirmed as part of Injectivity – Specify Initial Well Design Criteria

[M4] and at

this time additional sensitivities should be run in order to ensure the validity of the injection schedule presented here.

Measured Depth (m)

True Vertical Depth (m)

Horizontal Displacment (m)

Deviation (deg)

0.0 0.0 0.0 0

182.9 182.9 0.0 0

365.8 361.7 38.3 12

387.5 381.8 46.6 22

396.2 389.8 50.1 24

457.2 444.8 76.4 26

609.6 575.1 155.5 31

762.0 693.1 251.9 39

914.4 796.8 363.6 47

1066.8 894.8 480.3 50

1219.2 992.7 597.1 50

1371.6 1090.7 713.8 50

1432.6 1129.9 760.5 50

1463.0 1149.5 783.9 50

1493.5 1169.1 807.2 50

1524.0 1188.6 830.6 50

1554.5 1208.2 853.9 50

1645.9 1267.0 923.9 50

1676.4 1274.1 947.3 50

Table 3-1: Well Trajectory Depths





Mean Sea Level

0 mTVDSS

Sea Bed

35 mTVDSS

762 mTVDSS

62 mTVDSSUndifferentiated

Lias

Winterton

251.4 m

510.5 m

Triton

541.0 m

Dudgeon

699.5 m

Dowsing

730.0 m

Upper Bunter

864.1 m

Bunter Shale

1010.4 m

Lower Bunter

1249.7 m

1274.1 m

7”

26#

Tu

bin

g

9-5

/8”

47

# C

asin

g

30” 0.5”t Casing

13

-3/8

”6

1#

Casin

g

Ave

rage

Fo

rma

tion

TV

DS

S

Dep

ths f

rom

Pe

trel M

ode

l11

/3/4

”54

# C

asin

g

640 mTVDSS

1100 mTVDSS

1225 mTVDSS

1200 mTVDSS

Wall #1

Wall #2

Wall #3

Wall #4

Wall #5

Wall #6

Wall #7

Wall #8

Wall #9

Wall #10

Wall #11

Wall #12

Wall #13

Wall #14

Mid Packer

Top of Liner

Mean Sea Level

0 mTVDSS

Sea Bed

35 mTVDSS

762 mTVDSS

62 mTVDSSUndifferentiated

Lias

Winterton

251.4 m

510.5 m

Triton

541.0 m

Dudgeon

699.5 m

Dowsing

730.0 m

Upper Bunter

864.1 m

Bunter Shale

1010.4 m

Lower Bunter

1249.7 m

1274.1 m

7”

26#

Tu

bin

g

9-5

/8”

47

# C

asin

g

30” 0.5”t Casing

13

-3/8

”6

1#

Casin

g

Ave

rage

Fo

rma

tion

TV

DS

S

Dep

ths f

rom

Pe

trel M

ode

l11

/3/4

”54

# C

asin

g

640 mTVDSS

1100 mTVDSS

1225 mTVDSS

1200 mTVDSS

Wall #1

Wall #2

Wall #3

Wall #4

Wall #5

Wall #6

Wall #7

Wall #8

Wall #9

Wall #10

Wall #11

Wall #12

Wall #13

Wall #14

Mid Packer

Top of Liner

Figure 3-1: Initial Well Design





4. Inflow Performance Relationship & Injectivity Index

Before considering the tubing performance, as analysis of the Inflow Performance Relationship (IPR) was carried out based on the data outlined in Section 2. The IPR relates the rate which can be injected into (or produced from) a permeable rock given a pressure differential across the rock face. Thus the required flowing bottom hole pressure (FBHP) to inject at a given rate can be established for any given reservoir pressure.

4.1. Gaseous Injection

In order to obtain an initial indication of the IPR, PETEX‟s Prosper well modelling software was used. Note that this is a static modelling software package and as such can only be used to model steady-state conditions and not the transient effects associated with start-up and shut-down. In addition, transient modelling was carried out using SPT Group‟s OLGA software.

4.1.1. Static Modelling

Initial inflow performance modelling was carried out in Prosper in order to obtain a comparison between different IPR model types. The results of the comparison are outlined in the following sub-secitons.

4.1.1.1. Jones IPR Model

Jones IPR model, which is a modified form of IPR, was used for reservoir inflow calculations in Prosper for Lower Bunter. The equation for this model is shown below.

QbQaPP wfr

222

Equation 4-1 Where:

Pr Reservoir Pressure

Pwf Flowing Bottom Hole Pressure

Q Rate

a non-Darcy Coefficient

b Darcy Coefficient

In the right hand side of the equation the first term, a, is the turbulent (non-Darcy) coefficient and the second term, b, is laminar pressure drop coefficient. In this model 'a' and 'b' are calculated using reservoir properties such as permeability and formation height.

4.1.1.2. Multi-Rate Jones IPR Model

The Multi-Rate Jones is a convenient way to determine “a” and “b” from test points. In this model a number of test points are entered which are then fitted to the Jones equation for gas. The fit values of “a” and “b” are plotted on the IPR plot.

If actual test points are not available then Jones IPR data set can be used as test points to calculate turbulent coefficient “a” and laminar coefficients “b”.

4.1.1.3. Forchheimer IPR Model

The Forchheimer IPR model uses Equation 4-1 where turbulent coefficient “a” and laminar coefficient “b” are input to produce the IPR. Bearing in mind that the “a” and “b” coefficients





calculated with Multi-rate Jones are the same as the input for the Forchheimer model, it is possible to check that if Multi-Rate Jones results (“a” & “b”) are used in the Forchheimer model the shape of IPR curves are identical and calculated Absoloute Openhole Flow

1 (AOF)

potentials are the same as indicated in Figure 4-1. Thus the coefficients for the Frochheimer were determined through matching with reservoir parameters used as inputs for the Jones calculation.

0

10

20

30

40

50

60

70

80

90

0 5,000 10,000 15,000 20,000 25,000 30,000

Rate (te/day)

Pre

ssure

(bara

)

Jones

Forchheimer

Multi-Rate Jones

Figure 4-1: Comparison of IPR Equations from Prosper

In addition to assessing the variation between models it is also important to check that the shape of IPR (Jones & Forchheimer) is identical when running sensitivities i.e. changing reservoir pressure. This was confirmed using Prosper and is demonstrated in Figure 4-2 and Figure 4-3. The analysis shows that for the Lower Bunter properties the following Frochheimer coefficients should be used:

a (Non-Darcy Coefficient) 1.4076x10-11

bar2(Sm

3/day)

2

b (Darcy Coefficient) 0.0002131 bar2/(Sm

3/day)

1 The maximum rate that a well can produce or inject at the lowest possible bottom hole pressure.





Figure 4-2: IPR Curves for Changing Reservoir Pressure using Jones

Figure 4-3: IPR Curves for Changing Reservoir Pressure using Frochheimer





4.1.2. Transient Modelling - OLGA

OLGA does not have the Jones IPR model available. However it has Forchheimer IPR Model as part of the advanced well module, to calculate the pressure drop across the sandface. There are two options to enter the data:

Reservoir parameters such as permeability, etc. including non-Darcy Skin Factor (D),

Turbulent and laminar coefficients “a” & b”.

The non-Darcy Skin Factor was not available for the Lower Bunter reservoir therefore turbulent and laminar coefficients were used to build the IPR as calculated in Section 4.1.3.

Note: The naming convention for turbulent coefficient “a” and laminar coefficient “b” is different in OLGA - keywords CINJ for turbulent coefficient and BINJ for laminar coefficient are being used.

4.2. Dense Phase Delivery

In OLGA, inflow performance of CO2 is defined separately for „gaseous‟ and „liquid‟ phases. There are multiple choices available to enter gaseous IPR into OLGA. However, there is only one option to define the inflow performance for the liquid phase by means of a linear injectivity index. This is entered by the parameter “OILINJ” in STB/d/psi.

The linear injectivity index for lower bunter is calculated from reservoir and fluid properties by using Darcy equation in radial form.

75.0ln

1008.7 3

w

e

wfr

r

r

pphkq

Rearranging for PI

75.0ln

1008.7 3

w

ewfr

r

r

hk

pp

qPI

The Lower Bunter data used for well PI calculation are as follows:

k = 1000 md

h = 24.4m

re = 2000 m

rw = 0.155 m

μo = 0.065 cP





Using above equation and Lower Bunter reservoir data the PI is estimated to be 2882 Sm

3/day/bar (note that the S reflects that the volumetric component is based on standard

conditions and not reservoir conditions). This is also in agreement to PI calculated using the Prosper model.

4.3. Inflow Performance Model Considerations

The purely analytical models discussed in the above section are based on the inputs of reservoir pressure, thickness, permeability and viscosity of the injected fluids. They do not account for any chemical reactions with the mineralogy of the formation. It is note that such effects such as salt precipitation

[S3] or localised dissolution of minerals over time may increase

or decrease the permeability which will have an effect on injection performance.

The precipitation of salts is more common in deep saline aquifers where gaseous CO2 vaporises the saline formation water, leaving salt minerals behind which can reduce the permeability. However, injectivity is certainly not controlled by salt precipitation alone. During CO2 injection in an aquifer, the more viscous phase (formation water) is displaced by a less viscous phase (CO2), so the reduction in injectivity due to salt precipitation can be offset (at least partially) by increased mobility as a result of the replacement of water by CO2 in the near wellbore region.

The impact of dissolution of formation minerals in the presence of carbonic acid may increase the permeability, however the process is far too slow to affect the injection timescale and planned design life of 40 years.





5. Well Performance & Injectivity

The modelling of the injectivity was divided into two scenarios each with a slightly different set of requirements. The first scenario models the injection of CO2 when delivered in gaseous phase. This assumes that the choke is fully open so that there is minimal pressure drop and no Joule-Thomson cooling effects. The second is for delivery in dense liquid phase (i.e. above critical pressure but below critical temperature), where although there will be a Joule-Thomson cooling affect across the choke to reduce the pressure, this will be counteracted by heating prior to the pressure drop to maintain single phase in the wellbore.

5.1. Gas Phase Delivery (Demonstrator)

In order to prevent liquid drop out in the pipeline from Kingsnorth to the Hewett platform, the maximum pressure which can be delivered to the wellhead is 35 barg, allowing for a minimum sea temperature of 4 °C (winter) see Figure 1-2. Note that above this pressure, the cooling effect of the sea would result in liquid CO2 drop out in the wellbore. Under these conditions, the OLGA model was used to determine:

The minimum wellhead injection pressure (WHIP) required to inject CO2 gas for reservoir conditions at the start of injection (2.7 bara)

The maximum reservoir pressure into which CO2 can be injected when the WHIP is 35 barg using three 7” wells.

Note that the requirement from 3 wells is derived from a requirement to minimise the number of wells through the reservoir while ensuring a level of flexibility and allowing the use of field proved technology to ensure an economic solution. While a single well could be used for initial gas injection, the cost of drilling and completing such a large well and the limitations in delivery flexibility would out-weigh the minimisation of wellbores drilled through the formation.

While Prosper, as a static model, can carry out this analysis, it cannot determine if the flow will remain stable as the calculation method is based on nodal analysis as opposed to transient behaviour along the wellbore. Thus the OLGA models simulated injection for a total of 30 days to ensure stable flow.

In both cases, in order to meet delivery rate of 6,600 te/day, we assume 3 wells each injecting 2,200 te/day (3*2,200=6,600). In addition, the impact of increased reservoir pressure on wellhead pressure, bottomhole pressure and bottomhole temperature was also assessed. As preliminary input, a pressure curve from the reservoir modelling base case was used to determine the increase reservoir pressure over time.

For the range of cases run (i.e. increasing WHIP) the pressure and temperature along the wellbore from wellhead to sand face has also been calculated. These are shown in Figure 5-1. In addition the pressure and temperature profiles have been calculated along the wellbore and are shown in Figure 5-2 and Figure 5-3





0

5

10

15

20

25

30

35

40

45

50

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15

Temperature (deg C)

Pre

ssure

(barg

)

Increasing Reservoir Pressure

Increasing WHIP

LIQUID CO2

GASEOUS CO2

Figure 5-1: Pressure versus Temperature along Wellbore

0

200

400

600

800

1000

1200

1400

1600

1800

0 5 10 15 20 25 30 35 40 45 50

Pressure (barg)

Measure

d D

epth

(m

)

Increasing WHIP

Increasing BHIP

Figure 5-2: CO2 Pressure along Wellbore - Gaseous Injection





0

200

400

600

800

1000

1200

1400

1600

1800

0 2 4 6 8 10 12 14 16 18

Temperature (deg C)

Measure

d D

epth

(m

)

Constant WHIT

Increasing BHIT

Figure 5-3: CO2 Temperature along Wellbore - Gaseous Injection

Looking at these results over time, the maximum reservoir pressure that can be achieved using 3 wells with 7” tubing is 33 barg, and that based on initial reservoir injection analysis, this equates to 12 years of injection assuming no shutdowns and at a maximum continuous flow rate. For a project start data of 1/1/2017 this would allow continuous injection in gaseous phase until 1/1/2029. This is shown in Table 5-1 and Figure 5-4. Note that for initial injection conditions, the pressure drop across the sandface is high at over 13 bar

A total volume of 28.9 million tonnes could be injected during this period assuming no shutdowns. The required demonstrator volume of 20 million tonnes of CO2 could therefore be achieved within this period assuming approximately 30% downtime to allow for plant shutdowns, maintenance and load requirements. A planned schedule injection forecast is included in the full field reservoir model, based on shutdowns and load cases.





Year

Wellhead Injection Pressure

(barg)

Injection Rate

(te/day)

Bottomhole Injection Pressure

(barg)

Bottomhole Injection

Temperature (°C)

Reservoir Pressure

(barg)

Pressure Drop at

Sandface (barg)

0 27.6 2232 15.1 2.9 2 13.1

1 27.6 2214 15.8 3.3 5 10.8

2 28.0 2222 17.1 4.2 8 9.1

3 28.4 2218 18.6 5.4 10 8.6

4 29.0 2225 20.3 6.6 13 7.3

5 29.6 2223 22.2 8.0 16 6.2

6 30.3 2224 24.2 9.3 19 5.2

7 31.0 2220 26.2 10.6 21 5.2

8 31.8 2224 28.3 11.8 24 4.3

9 32.6 2222 30.4 12.9 26 4.4

10 33.4 2218 32.4 14.1 28 4.4

11 34.3 2231 34.5 15.0 31 3.5

12 35.0 2210 36.5 16.2 33 3.5

Table 5-1: Gas Injection Pressure & Temperature at Wellhead and Bottom Hole

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

0 2 4 6 8 10 12

Time (years)

Pre

ss

ure

(b

arg

)

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

Tem

pera

ture

(d

eg

C)

WHIP

BHIP

Reservoir Pressure

BHIT

Pressure Drop Across Sandface

Figure 5-4: Gas Injection Pressure & Temperature at Wellhead and Bottom Hole





5.2. Dense Phase Delivery (Full System)

On completion of the demonstrator project (~15 years), it is assumed that the system (pipeline and wells) will move to „dense‟ phase operation (also referred to as full system operation). The pressure at the compressor will increase such that the arrival pressure at Hewett will be 79 barg. Again, as a result of the cooling from the seawater around the pipeline, the arrival temperature will be 4°C. This means that while the pressure at the Hewett platform will be above the critical pressure of 73.7 bara, it will still be lower than the critical temperature of 31.1°C resulting in dense liquid CO2 arriving at the platform. It is intended to provide heating in order to move this liquid phase to dense phase prior to injection and as a result the CO2 will be heated from 4°C such that the temperature after the choke will be 32°C, or higher if required in order to achieve single phase injection in the wellbore.

In addition to the change in pressure, there will also be an increase in the rate from 6,600 te/day to 26,400 te/day. As a result there will be a requirement to provide additional well capacity for this increase in volumetric throughput.

5.2.1. Initial Dense Phase Injection – Steady State

Initial simulations were run for a reservoir pressure of 33 barg (i.e. the maximum reservoir pressure for which 6,600 te/day gaseous phase CO2 can be injected with three 7” wells). In order to quantify the potential number of wells required, the simulations were initially run in Prosper considering the following rates:

5 wells @ 5,280 te/day (99 MMscf/day)



Note that the rate in MMscf/day is included as Prosper cannot display rates in te/day. Furthermore the first pass results below do not allow for heating or cooling of the CO2 across the choke due to Joule Thomson effects. As a result, there is no increased density from cooling which results in conservative estimates of actual injected rates and thus well counts.





6 W

ells R

eq

uir

ed

5 W

ells R

eq

uir

ed

7 W

ells R

eq

uir

ed

IPR at 33 barg Reservoir Pressure

6 W

ells R

eq

uir

ed

5 W

ells R

eq

uir

ed

7 W

ells R

eq

uir

ed

6 W

ells R

eq

uir

ed

5 W

ells R

eq

uir

ed

7 W

ells R

eq

uir

ed

IPR at 33 barg Reservoir Pressure

Figure 5-5: Initial Review of Dense Phase Delivery and Injectivity

5.2.2. Dense Phase Delivery – Transient Analysis

A similar analysis was carried out in OLGA, but this time assuming that heating is provided to increase the CO2 temperature to 32°C or higher after the pressure drop at the choke. The results are shown in Table 5-2 for reservoir pressures of 33 barg to 136 barg.

Year Well

Count* WHIP (barg)

WHIT (°C)

Rate (te/day)

Reservoir Pressure

(barg)

BHIP (barg)

BHIT (°C)

Pressure Drop at

Sandface (barg)

12 8 47.0 32 3242 33 38 33.5 5

16 8 53.0 32 3230 50 53 40.9 3

25 8 63.0 32 3262 75 77 49.6 2

42 8 72.2 34 3252 100 102 57.7 2

55 8 75.2 34 3246 115 117 59.9 2

62 6 77.0 34 4282 125 127 58.8 2

67 5 78.5 34 5240 136 138 56.7 2 *Note that well counts do not include contingency

Table 5-2: Dense Phase Delivery with Increasing Reservoir Pressure





Note that the selection of the number of wells must be based on a number of criteria, and not only the ability to inject the required rate per day. The first criterion is to ensure that the CO2 maintains a single phase in the wellbore. Figure 5-6 below shows the pressure and temperature of the CO2 along the wellbore for increasing reservoir pressure.

35

45

55

65

75

85

95

105

115

125

135

145

20

25

30

35

40

45

50

55

60

Temperature (deg C)

Pre

ssu

re (

barg

)

CO2 Phase Envelope WHIP=47 barg & PR=33 barg

WHIP=53 barg & PR=50 barg WHIP=63 barg & PR=75 barg

WHIP=72.2 barg & PR=100 barg WHIP=75.2 barg & PR=115 barg

WHIP=77 barg & PR=125 barg WHIP=78.5 barg & PR=136 barg

Figure 5-6: Pressure & Temperature Along the Wellbore (Pr = 33 barg)

Another consideration is the BHIP with respect to the reservoir pressure. It is important not to have an excessive pressure differential across the sandface which would induce further cooling in the near wellbore and indeed should this be excessive may result in fracturing of the formation.

Next, the well count should not be increased more than is required, not only from an economical standpoint, but also from the engineered integrity of the storage site and complex. The more wells that are drilled into the storage site, the greater the potential for CO2 migration.

Finally, the rate per well should be such that the velocities within the wellbore do not result in hydraulic erosion. OLGA uses a simple velocity limit based on the equation:

Cve

Where:

ve critical velocity





C coefficient based on the material type

ρ density of the fluid

For carbon steel, values of C are usually taken to be 100. The ratio of the critical velocity to the actual velocity identifies whether erosion will be an issue or not (ratios of 1 or higher indicate that erosion is a potential issue.

The use of a limiting C-factor of 100 is based on API RP14E (1991)[M7]

and is useful for a quick first pass. However, an updated version of API RP14E suggests that values of 150 to 200 are suitable values. Furthermore, work done by Terziev and Taggart

[S4] suggest that a C-

factor of 620 be used for carbon steel, while most operators use 300.

OLGA calculates the Erosional Velocity Ratio (EVR) based on a C-factor of 100. Thus any values of EVR above 1 are considered to be at the hydraulic erosional limit. For the purposes of this analysis, the C-factor was taken as 300, thus EVR values provided by OLGA in excess of 3 are considered to provide erosional issues.

Taking all these factors into account, it is recommended that dense phase injection should commence with 8 wells. For other cases, with fewer wells, hydraulic erosion limits will be exceeded.

We note that while this is referred to as dense phase injection, the required pressure drop across the choke will result in gaseous phase in the wellbore until the reservoir pressures reach c. 100 barg, before becoming dense phase in the tubing. The pressures and temperatures along the wellbore for each of the dense phase delivery scenarios are shown in Figure 5-7 and Figure 5-8 overleaf. A summary of the delivery pressure and temperature versus time during dense phase injection is shown in Figure 5-9.

0

200

400

600

800

1000

1200

1400

1600

1800

35 55 75 95 115 135

Pressure (barg)

Depth

(m

)

Increasing WHIP

Increasing BHIP

Figure 5-7: CO2 Pressure along Wellbore (Dense Phase Delivery)





0

200

400

600

800

1000

1200

1400

1600

1800

30 35 40 45 50 55 60 65

Temperature (deg C)

Depth

(m

)

CO2 Heated to Prevent 2 Phase Flow in System

Increasing BHIT

Figure 5-8: CO2 Temperature along Wellbore (Dense Phase Delivery)

0

20

40

60

80

100

120

140

160

12 20 28 36 44 52 60 68

Time (years)

Pre

ssu

re (

bar)

0

10

20

30

40

50

60

70

80

Tem

pera

ture

(d

eg

C)

Reservoir Pressure

BHIP

WHIP

BHIT

6 Wells8 Wells

Figure 5-9: Dense Phase Delivery Pressure & Temperatures with Increasing Pressure





6. CO2 Injection Schedule

The results of the analysis have shown that there is a potential to have a standard well design for all phases of the injection life-cycle (i.e. gaseous injection during the demonstrator phase and dense phase injection during full system phase in later field life). The well design consists of a 7” completion in a deviated well which penetrates the reservoir at 50 degrees. The quantity of wells required in order to maintain the injection rates will vary throughout the field life.

Initially 3 wells will be required for gaseous phase injection at 6,600 te/day until the reservoir pressure increases to 33 brag. A fourth well will allow contingency to be provided in the event that one well needs to be shutdown during this period for intervention operations. This additional well will also allow the injection of gaseous CO2 beyond the 3 well limit of 33 barg reservoir pressure.

Once the delivery of gaseous CO2 to the Hewett platform ceases and dense liquid phase begins, eight wells will be required initially in order to inject at a rate of 26,400 te/day. As reservoir pressure continues to rise then the WHIP will continue to increase until the resultant increased density results in fewer wells being required to inject CO2 at the required rate.

A summary of this schedule in terms of injection pressures and well count is shown with respect to reservoir pressure in Figure 6-1.

0

20

40

60

80

100

120

140

160

0 10 20 30 40 50 60 70

Time (years)

Pre

ssu

re (

bar)

0

10

20

30

40

50

60

70

80

Tem

pera

ture

(d

eg

C)

Reservoir Pressure

BHIP

WHIP

BHIT

Dense P

hase

Gaseous P

hase

3 Wells 6 Wells8 Wells

Figure 6-1: CO2 Injection Schedule – Pressure, Temperatures and Well Count

A consideration which has not been addressed here is the timing of the construction of the wells. At initial conditions (gaseous delivery / injection) three wells are required to allow injection of the CO2 at a rate of 6,600 te/day. Once the rate (and delivery pressure) increase,





an additional 3 wells will be required. There are two antithetic aspects to be considered with regard to the timing for construction of these additional three wells:

1. If the wells are all drilled prior to commencement of injection, the additional wells will be left suspended for over ten years which is a risk with respect to well integrity.

2. On the other hand, if the wells are drilled on an as-required basis, the risk is associated with drilling into a pressurised CO2 store.

These two aspects and associated risks need to be evaluated before defining the final drilling schedule.

6.1. Additional Field Development Considerations

The injectivity scenarios defined in the sections above are based on two key assumptions:

Gaseous phase injection will continue throughout the demonstrator phase using 3 x 7” wells at a combined rate of 6,600 te/day.

At the end of the demonstrator phase, dense phase injection will commence at a rate of 26,400 te/day until the reservoir has been re-pressurised to the levels allowed for by storage integrity analysis.

It is recommended that 4 wells be drilled for the gaseous injection (demonstrator) phase to allow for contingency in the event of a planned or unplanned well shut-in. Furthermore, it is noted that the scenario assumed above may not be the case, with an option being that gaseous injection is required for longer. In order to allow gaseous injection to continue beyond the 33 barg reservoir pressure, the additional fourth well would permit this, allowing continued gaseous phase delivery at Hewett and injection of the same.

The design life of the platform / wells is 40 years. However, based on the planned injection schedule, the reservoir pressure will only have reached approximately 98 bara, leaving a significant volume of storage space for future injection beyond the 40 year design life. Note that this needs to be confirmed with the full field simulation model.





7. Conclusions

A base well design has been constructed with 7” tubing string and a deviation of 50 degrees through the reservoir. This allows for:

o Minimising the initial number of wells required while allowing for flexibility in delivery o Ensuring drillability through the highly depleted Lower Bunter. o Areal spacing to minimise the effects of thermal interference between wells. o Use of wireline intervention

Inflow Performance Relationships have been developed for injecting gaseous and dense phase CO2 into the Lower Bunter.

o For gaseous phase, the Forchheimer equations have been used with a Non-Darcy coefficient (a) of 2.3538x10

-6 psi

2/(Mscf/day)

2 and a Darcy coefficient (b) of 1.26467

psi2/Mscf/day.

o For dense phase injection, a PI of 2882 Sm3/day/bar (1250 STB/day/psi) was calculated based on reservoir and fluid properties.

Simulations in OLGA have shown that for a CO2 injection rate of 6,600 te/day in gaseous phase three wells (plus one contingency) are required with 7” tubing.

The gaseous phase can continue with the above well configuration until the reservoir pressure reaches 33 barg based on a limiting WHIP of 35 barg.

Dense phase delivery will initially require eight wells (plus one contingency) with 7” tubing in order to inject the anticipated 26,400 te/day. This number will drop to six as the reservoir pressure increases.

.





8. Recommendations

While the demonstrator phase can be completed using 3 x 7” wells, it is recommended that a fourth well be provided as contingency to allow for intervention and maintenance work as well as variations in the supply and well availability.

A drilling program needs to be established and the risks associated with batch drilling all the wells versus drilling though an existing CO2 store examined.

Finalisation of the injection schedule needs to be completed following verification of individual well trajectories and tubing size based on tubing stress analysis and the completion design process.

The proposed 36” pipeline has a capacity of around 40,000 te/day in dense phase, but the implementation of this would require additional power stations with carbon sequestration to feed into the Kingsnorth CO2 pipeline. This increase in rate would require additional wells in addition to those defined in this report. While detailed analysis has not been carried out at this stage, a basic nodal analysis indicates that a total of 12 wells (plus one contingency) would be required for this higher volume.





9. Mandatory References

[M1] Baker RDS; “Establish CO2 Supply Properties”, KCP-RDS-CWE-REP-1000 Rev:03 (October 2010)

[M2] Baker RDS; “Injectivity – Wellbore Stability for New Wells”, KCP-RDS-CWE-REP-1001 Rev:03 (October 2010)

[M3] Baker RDS; “Injectivity – Near Wellbore Issues”, KCP-RDS-CWE-REP-1003 Rev:03 (October 2010)

[M4] Baker RDS; “Injectivity – Specify Initial Well Design Criteria”, KCP-RDS-CWE-REP-1004 Rev:02 (October 2010)

[M5] Baker RDS; “Injectivity – Specify New Well Completions Criteria”, KCP-RDS-CWE-REP-1005 Rev:02 (October 2010)

[M6] Baker RDS; “Injectivity – Temperature Effect on Well and Reservoir”, KCP-RDS-CWE-REP-1006 Rev:01 (November 2010)

[M7] American Petroleum Institute; “API RP14E Recommended Practice for Design and Installation of Offshore Production Piping Systems” (October 1991)





10. Supporting References

[S1] FEED Briefing B - Kingsnorth Abated – Offshore Project Briefing, January 2010.

[S2] http://www.engineeringtoolbox.com

[S3] Mehdi Zeidouni, Mehran Pooladi-Darvish, David Keith, “Analytical Solution to Evaluate Salt Precipitation during CO2 Injection in Saline Aquifers”, International Journal of Greenhouse Gas Control, March 2008.

[S4] Ivo Terziev, Ian Taggart, “Improved Procedures for Estimating the Erosional Rates in High Offtake Gas Wells: Application of University of Tulsa Flow Loop Derived Correlations”, SPE 88492, October 2004





11. Conversion Factors

Dimension Multiply By To Obtain Comments

Length inches 0.02540 metres

feet 0.30480 metres

Area sq inches 0.00065 sq metres

sq feet 0.09290 sq metres

Volume

cubic inches 0.00002 cubic metres

cubic feet 0.02832 cubic metres

gallon 0.00379 cubic metres

barrel 0.15899 cubic metres barrel = 42 US gallons

Pressure

psi 0.06895 bar a - relative to atmosphere

g - relative to gauge

Temperature deg Fahrenheit (Tf-32) / 1.8 deg Celsius Tf – Temperature in

deg F

Mass lb 0.45359 kilogram

lb 0.00045 tonne

Density

lb/ft3 kg/m

3

ppg 119.82640 kg/m3 ppg = pounds per

gallon in US units

ppg 0.12 Specific Gravity

Energy BTU 1,055.05600 Joule

Power BTU/hour 0.29307 Watt

Flowrate

scf/day 0.028317 m3/day

scf/day 0.000053 Tonnes/day For CO2 only

bbls/day 0.117347 m3/day bbls = barrels = 42

US gallons

Thermal Conductivity

BTU-ft/hour/ft2/degF 1.73073 W/m/K

Specific Enthalpy

BTU/lb 2,327.79000 J/kg