Blowout and Kill Simulation Sample Report

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Well blowout and dynamic wellkill simulations

Exploration well 5505/5-5 NewField North (PL 555)SampleCo E&P

December 2010


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Customer:

SampleCo

Customer PO no.: Project:

N/A Project nr. 2010-800070

Document title: Doc. no.: WPA-DOC-2010-800070-00

Well blowout and dynamic wellkill simulation of exploration well 5505/5-5 NewField North

Conclusions:

This report summarizes the blowout and dynamic well kill simulations done for exploration well 5505/5-5 NewField North in

production license PL 555.

The well is to be drilled as a slightly deviated exploration well to test hydrocarbon potential in the Res-1 and Not formations.

Secondary targets include Res-1 and Res-2 formations. Based on client input, Res-1 and Res-2 are evaluated as potential producing

formations. Res-1 and Res-2 are treated as two formations, with common properties for Res-1 and Res-2.

The well is vertical down to last casing @ 3450 m TVD RKB. Top Res-1 is expected @ 3555 m TVD RKB. The formations are planned

drilled with an 8 section to TD @ 4031m MD/3930m TVD RKB. The well design considered includes a 36 x 30 conductor set @

475 m TVD RKB, 20 surface csg set @ 1350 m TVD RKB, 13 intermediate csg set @ 2380 m TVD RKB and a 9 reservoir csg set

@ 3450 m TVD RKB.

Sea depth at location is 364 m MSL. The expected fluid to be explored is gas/condensate.

The well is assumed drilled by the semi-submersible drilling rig West Phoenix, with a 39 m RKB-MSL air gap.

The scenarios investigated is (Section 3.2 for details)

- Kick scenarios partly penetrated Res-1- Swab scenarios fully penetrated Res-1 and Res-2

The worst case scenario is described by an open and unrestricted flowpath, and full penetration of Res-1 and Res-2 formations with

maximum permeability estimates. In such an unlikely event, the maximum blowout potential is found to be 4445 Sm/day of gas

condensate and 17.8 MSm3/day of gas. The risk weighted blowout potential is found to be 701 Sm/day of gas condensate and 2.80

MSm/day of gas for a surface blowout and 706 Sm/day of gas condensate and 2.82 MSm/day of gas for a subsea blowout.

Expected duration of a risk weighted blowout can be predicted based upon statistical data from the Sintef Offshore Blowout

database and industry experience values, and is found to be 13.1 days for a surface release and 23.4 days for a subsea release.

In case of a blowout that will have to be killed remotely via a dedicated relief well, simulations show that an unrestricted surface

blowout from fully penetrated Res-1 and Res-2 formations, through an open/cased hole, will have the highest pumping

requirements.

The worst case scenario can be killed by one single relief well, pumping 10.000 LPM of 2.1 sg mud to a total of 200 m to stop HC

influx. Total mud volume required during the operation, including 2 x bottom up circulation, is 693 m.

Note that the high kill fluid densities needed in the worst case scenario might fracture the formation, and operational procedures

should be prepared for circulation of lighter fluids to stabilize the well.

Rev. Date Description Created by: Approved by :

0 03.12.2010 First version V.Gruner T.Rinde


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Well blowout and dynamic wellkill simulation 5505/5-5 NewFieldNorth

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Contents

List of figures ............................................................................................................................................ 4

List of tables ............................................................................................................................................. 4

List of acronyms ........................................................................................................................................ 51 Background and Introduction ......................................................................................................... 6

1.1 Introduction ............................................................................................................................ 6

1.2 Objective of work .................................................................................................................... 6

2 Data & Information Collection ........................................................................................................ 7

2.1 Location and water depth ....................................................................................................... 7

2.2 Drilling facilities ....................................................................................................................... 8

2.3 Reservoir properties ............................................................................................................... 8

2.4 Reservoir fluid information ..................................................................................................... 9

2.5 Well design .............................................................................................................................. 9

2.6 Inflow Performance Relationship ......................................................................................... 11

2.7 Permeability sensitivity ......................................................................................................... 11

2.7.1 Res-1 permeability sensitivity ...................................................................................... 122.8 Res-2 permeability sensitivity ............................................................................................... 12

2.9 Water .................................................................................................................................... 13

2.10 Drilling mud and kill fluid ...................................................................................................... 13

3 Blowout Potentials and Duration .................................................................................................. 13

3.1 Blowout scenarios in general ................................................................................................ 13

3.2 Case scenario definitions ...................................................................................................... 14

3.3 Distribution of flowpath probabilities ................................................................................... 16

3.4 Blowout duration .................................................................................................................. 18

3.5 Risk process and distributions............................................................................................... 20

3.5.1 Permeability risking ...................................................................................................... 20

3.5.2 Final blowout risk procedure ....................................................................................... 21

3.6 Possibility for underground blowout .................................................................................... 23

4 Killing Methods of Blowing Wells ................................................................................................. 23

4.1 Design of the relief well ........................................................................................................ 24

4.1.1 Relief well data ............................................................................................................. 25

4.2 Dynamic wellkill through a relief well ................................................................................... 25

4.2.1 Simulation and model assumptions ............................................................................. 26

4.2.2 Simulation results Dynamic kill simulations .............................................................. 26

4.3 Pump and kill mud considerations ........................................................................................ 28

4.3.1 Possible kill sequence ................................................................................................... 28

4.3.2 Minimum pumping requirements on relief well drilling rigs ....................................... 30

4.4 Figures: Worst case gas-only kill scenario ............................................................................. 31

5 References .................................................................................................................................... 32

6 Appendix list ................................................................................................................................. 33


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List of figures

Figure 1: Map showing location of PL 555 Source: www.arcticweb.com................................................ 7

Figure 2: The semi-submersible drilling rig West Phoenix ....................................................................... 8

Figure 3: Illustrative well schematics for the 5505/5-5 NewField North exploration well [6] ............... 10Figure 4: IPR relationships fully penetrated Res-1 and Res-2 .............................................................. 11

Figure 5: IPR curves - Res-1 Permeability sensitivity ........................................................................... 12

Figure 6: IPR curves Res-2 Permeability sensitivity .......................................................................... 12

Figure 7: Possible blowout paths for the defined scenarios (Illustrative only). ..................................... 15

Figure 8: Blowout duration data from the Sintef Database and the Scandpower report 2010 [2]. ....... 19

Figure 9: NewField North Illustrative risk process for the surface release case. ................................. 21

Figure 10: Relief well - pump power vs. pump discharge pressure ........................................................ 28

Figure 11: Pump rate vs. BHP in possible kill sequence ......................................................................... 29

Figure 12: Oil/gas and mud content in 5505/5-5 during kill sequence .................................................. 29

Figure 13: Typical mud pump capacity ranges. ...................................................................................... 30

Figure 14: Illustrative summary of blowout and killing of the worst case kill scenario. ......................... 31

List of tables

Table 1: Reservoir data for 5505/5-5 NewField North [4], [5]. ................................................................ 9

Table 2: Fluid conditions for the expected fluid from exploration well 5505/5-5 [4], [5]. ....................... 9

Table 3: Probability distribution of flow paths from 20 years of historical data Floaters. .................. 16

Table 4: Risk criteria in duration distribution. ........................................................................................ 20

Table 5: Permeability risk distribution.................................................................................................... 20

Table 6: Permeability risking Kick scenario 5m reservoir exposure .................................................. 20

Table 7: Swab scenario - Permeability risk distribution ......................................................................... 21

Table 8: Permeability risking Swab scenario Full reservoir exposure ............................................... 21Table 9: Blowout rates and duration distributions for a potential surface release................................ 22

Table 10: Blowout rates and duration distributions for a potential subsea release .............................. 22

Table 11: Minimum bullheading rates in order to ensure displacement of gas. .................................... 24

Table 12: Kill data - Worst-case scenario - Blowout through open hole ................................................ 27

Table 13: Kill data - Blowout through drillpipe ....................................................................................... 27

Table 14: Kill data - Blowout through annulus ....................................................................................... 28


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List of acronyms

API American Petroleum Institute

BHA Bottomhole assembly

BHP Bottomhole pressure

BOP Blowout preventerCGR Condensate gas ratio

DHSV Down hole safety valve

DP Drillpipe

ECD Equivalent circulating density

GOR Gas oil ratio

ID Inner diameter

IPR Inflow performance relationship

LPM Liter per minute

MD Measured depth

MSL Mean sea level

N/G Net/Gross

OD Outer diameterOH Open hole

OIM Offshore Installation Manager

PWL Planned well location

RKB Rotary kelly bushing

sg. Specific gravity

TD Total depth

TVD True vertical depth

WBM Water based mud

WPA Wellpro Academica AS


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1 Background and Introduction

1.1 Introduction

This study is part of establishing input for required approval and contingency planning

purposes as required in NORSOK D-010 in terms of estimating the expected blowout ratesand their duration, as well as checking the ability to kill potential blowouts based on defined

scenarios and specified input for the well 5505/5-5 NewField North in PL 555.

Wellpro Academica AS (WPA), an independent and specialized competence center for fluid

modeling and simulation services, was contacted and asked to perform blowout and

dynamic kill analysis for different possible case scenarios during drilling of the exploration

well.

Main objective of well 5505/5-5 is to test hydrocarbon potential in Garn sandstones.

Secondary objective is Res-2 sandstones, Secondary-1 sandstones and Secondary-2

sandstones.

The well is to be drilled as a slightly deviated exploration well. The well is vertical down to

last casing, then slightly deviates to stay parallel to the main bounding fault. TD will be 100m

into the Secondary-2 sandstone. In case of success, the well will be a keeper.

No contract is currently made for drilling rig. There is an option to use West Phoenix after

drilling of NewField (SampleCo), and West Phoenix is used as default regarding rig related

information in this report.

The well design considered includes a 36 x 30 conductor set @ 475 m TVD RKB, 20

surface csg set @ 1350 m TVD RKB, 13 3/8 intermediate csg set @ 2380 m TVD RKB and 9

5/8 reservoir csg set @ 3450 m TVD RKB. A 8.5 section will then be drilled through the

potential hydrocarbon carrier formations. Top Res-1 is expected @ 3555 m TVD RKB.

The expected fluid to be explored is gas/condensate.

1.2 Objective of work

The objectives of this study are:

Calculate and present an expected range of potential blowout rates for the well,

including the worst case flow rates of oil and gas to surface.

Perform a sensitivity analysis with respect to possible blowout scenarios and presentestimates for the blowout rates for the different scenarios.

Estimate flow rate and duration distributions of the blowout rates based on updated

historical data and reliable distribution statistics.

Recommend needed kill fluid density and kill rates for one, or more, relief well(s) for

worst case and expected scenarios.

The flow rate and duration distributions will be estimated based on the Sintef Offshore

Blowout Database [3] and the latest approved evaluation of the Sintef Database data from

Scandpower Risk Management AS [2].


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WPA will perform dynamic kill simulations in order to document safe killing of a potentially

blowing well, including discussion on the relief well(s) and pumping requirements involved

in the blowout control operation as required in NORSOK D-010.

The Software package OLGA 6.2.7, considered state of the art within dynamic simulation of

multiphase flows, is utilized for the dynamic simulations. PVT is handled using PVTSim and

tuned based on customer input ([Error! Reference source not found.] and [Error! Referencesource not found.]). Blowout cases have been simulated by use of Prosper and verified in

OLGA in order to ensure correct estimates.

In case of a real blowout developing, a more detailed relief well study is recommended in

order to plan for reassessment of the planned relief well path and well intersection. From

experience, extra restrictions such as broken drillpipes or other downhole objects, e.g. fishes

etc., are often present in the flow path. The maximum blowout rates presented in this

report might be reduced by such restrictions. Experience also shows that reductions of the

near wellbore reservoir pressures tend to reduce the actual pumping requirements.

2 Data & Information Collection

2.1 Location and water depth

The well 5505/5-5 NewField North analyzed in this report will be drilled as an exploration

well in production license PL 555, west of Brnnysund. The water depth at location is 364

m. Figure 1 shows the location of the PL 555 in the North Sea.

Figure 1: Map showing location of PL 555Source: www.arcticweb.com
http://www.arcticweb.com/http://www.arcticweb.com/


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2.2 Drilling facilities

Drilling rig contract has not yet been signed. There is a rig tender being reviewed with two

contractors, Det Norske (Songa Delta) and Dolphin (Bredford Dolphin).The rig option is to

continue to use the West Phoenix after OldField. Negotiations are ongoing to determine the

best solution for the NewField North Rig. This report will assume West Phoenix as drilling rigfor 5505/5-5. The air gap of West Phoenix is (RKB-MSL) 39 m.

Figure 2: The semi-submersible drilling rig West Phoenix

2.3 Reservoir properties

The well is to be drilled as a slightly deviated exploration well, penetrating the primary

target Res-1 sandstones with the possible HC bearing formations. Top Res-1 is expected @

3606 m MD/3555 m TVD RKB. Expected reservoir pressure and temperature are 470 bar and

130oC, respectively.

The secondary target is Res-2 sandstones with expected top @3860 m MD/ 3724 m TVD

RKB. Expected reservoir pressure and temperature are 470 bar and 130oC, respectively.

The formations are planned drilled with an 8 section to TD @ 4031 m TVD RKB.

Table 1 shows the reservoir data used in the simulations for the well presented in this

report. Res-1 and Res-2 formations are treated in common in this report, and reservoir

properties are listed based on this.


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Table 1: Reservoir data for 5505/5-5 NewField North [Error! Reference source not found.], [Error!

Reference source not found.].Res-1 Res-2

Top formation m TVD RKB 3555 3724

Temperature @ res top C 130 130

Pressure BarA 470 470

FIT @ 20 csg sg 1.75 1.75FIT @ 9 5/8 csg sg 1.85 1.85

Gross interval depth meter 52 56

N/G ratio - 0.67 0.875

Net interval depth meter 35 49

Permeability mD 50-200 1-5

Productivity Index, PI Sm/d/bar - -

Skin - 0 0

2.4 Reservoir fluid information

The fluid properties expected to be explored are listed in Table 2. Res-1 and Res-2 are

expected to hold the same reservoir fluid, namely a gas with a GCR of 4000 Sm/Sm. Fluid

properties are based on customer input.

Table 2: Fluid conditions for the expected fluid from exploration well 5505/5-5 [Error! Reference

source not found.], [Error! Reference source not found.].Standard conditions Data

Condensate density at std cond.* kg/Sm 800

Condensate viscosity at std cond.* cP 0.328

Gas density at std cond.* kg/Sm 0.856

Gas viscosity at std cond.* cP 0.008

Gas to Condensate Ratio (GCR) Sm/Sm 4000*std conditions defined as 15C/1.0135 BarAReservoir conditions Data

Gas density at res cond.** kg/m 435

Gas viscosity at res cond.** cP 0.064

Bubblepoint pressure BarA 440Gas expansion factor, Bg Sm/Rm 0.0037**Reservoir conditions defined as 130C/470 BarA

Fluid properties are represented by a black oil model for all simulations presented in this

report, and tuned according to data listed in Table 2.

2.5 Well design

The well is to be drilled as a vertical exploration well with the following well design planned:

- 36 x 30 conductor set @ 475 m TVD, 20 surface csg set @ 1350 m TVD RKB, 13

3/8 intermediate csg set @ 2380 m TVD RKB and 9 reservoir csg set @ 3450 m

TVD RKB. The well is vertical down to last casing.

- A 8.5 section will be drilled through the potential hydrocarbon carrier formations

to TD @ 4031 m MD/ 3939 m TVD RKB

- OD for the DP used when calculating the blowout rates is 5

Figure 3shows an illustration of the planned well.


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Figure 3: Illustrative well schematics for the 5505/5-5 NewField North exploration well [Error!

Reference source not found.]

Alve North Well Diagram

Formations MD TVD CASING / LITHOLOGY/ Hole Size Casing and Cement MudRKB m SS m EXPECTED PORE PRESS Data Aquisition

Rotary Table 39Sea bed 403 364 36" x 42'' 36" x 30'' Conductor Pipe Seawater with high vis

sweeps

Class G 1.54sg Turned light XL 1.03sg

Conductor Point 475 43626'' 20" Casing, X56, 133# Seawater with high vis

sweeps

Nordland 520 481 Class G Lead 1.3 sg, tail 1.5 sg 1.03 sg

Casing Point 1350 1311

Kai 1420 1381 17-1/2" 13 3/8'' Casing, P-110, 72# VT WBMFIT ~ 1.75 1.45-1.55 sg

Hordaland 1699 1660 Class G Lead 1.3 sg, tail 1.5 sg

Rogaland 1919 1880

Springar 1996 1957

Tech Casing Point 2380 2341

12-1/4" 10-3/4" VM110, 65.7# VT OBM9 5/8" VM110, 53.5# VT 1.45-1.55 sg

Class G 1.9sg

Lysing 2832 2793

BCU 3274 3235 Kick off point

Prod Casing Point 3450 3411

Garn + Not 3606 3540 OBM8-1/2" 1.40 SG

Ile +Upper Ror 3665 3589 FIT ~ 1.85 One Core in reservoirPossibly 3 mini-DSTs

Tofte + Lower Ror 3748 3660 Log reservoirs guaranteed

Tilje 3790 3695 A 7" Liner may be run for future completionre 3908 3795TD 4031 3900


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2.6 Inflow Performance Relationship

The productivity index is sensitive to parameters such as permeability, penetration length,

N/G ratio, the productive height of the reservoir as well as mechanical skin, inflow

turbulence or skew drainage due to limited penetration. The productivity index is also a

transient parameter that tends to decline shortly after initiation of the production, or as inthis case, a blowout. This is caused by the reduction of the near wellbore reservoir

pressures.

When calculating the blowout potentials, the blowout rates for the different scenarios are

strongly dependent on the permeability, pressure, fluid viscosity and the consecutive

productivity index. Simulations are based on the most likely properties, as given in Table 1

and Table 2.

The IPR relationships for NewField North are given in Figure 4. The IPR relationships shown

are for a fully penetration of Res-1 and Res-2 formations, with the maximum expected

permeability estimates of 200 mD and 5 mD respectively. A blackoil gas model has beenused in the calculations.

Figure 4: IPR relationships fully penetrated Res-1 and Res-2

As Figure 4 shows, the total IPR, evaluated at 3555 m TVD RKB, has an absolute open flow(AOF) of just below 38 MSm/day/bar. Contributions from Res-2 are very small compared to

the much more productive Res-1.

2.7 Permeability sensitivity

Both reservoir sections investigated in this study, Res-1 and Res-2, are subject to

permeability uncertainties. A sensitivity analysis on reservoir permeability is performed and

presented.

0

50

100

150

200

250

300

350

400

450

500

0 5000 10000 15000 20000 25000 30000 35000 40000

Flowing

wellborepressure

[bara]

Gas Rate

[1000 Sm/day/bar]

Total IPR

Garn/Not

Ile/Tilje


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2.7.1 Res-1 permeability sensitivity

The Res-1 formations are modeled as one productive zone with common properties.

Reservoir permeability is subject to uncertainty and a permeability range of 50-200 mD is

used in the blowout evaluations in this report.

IPR curves applicable for the Res-1 formations are shown in Figure 5.

Figure 5: IPR curves - Res-1 Permeability sensitivity

2.8 Res-2 permeability sensitivity

The Res-2 formations are modeled as one productive zone with common properties.

Reservoir permeability is subject to uncertainty and a permeability range of 1-5 mD is usedin the blowout evaluations in this report.

IPR curves applicable for the Res-2 formations are shown in Figure 6.

Figure 6: IPR curves Res-2 Permeability sensitivity

0

50

100

150

200

250

300

350

400

450

500

0 5000 10000 15000 20000 25000 30000 35000 40000

Flowingwellborepressure

[bara]

Gas Rate

[1000 Sm/day/bar]

Garn+Not - 50 mD

Garn+Not - 100 mD

Garn+Not - 200 mD

0

50

100

150

200

250

300

350

400

450

500

0 500 1000 1500 2000 2500 3000

Flowingwellborepressure

[bara]

Gas Rate

[1000 Sm/day/bar]

Ile+Tilje - 1 mD

Ile+Tilje - 3 mD

Ile+Tilje - 5 mD


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2.9 Water

Expected depth of the gas/oil-water contact was not given. Conservatively the water

fraction in the simulations is assumed equal to 0.0%, whilst condensed water is accounted

for.

2.10 Drilling mud and kill fluid

No filter cake or formation damage, nor stimulation effects caused by the drilling fluids used,

which might decrease or increase the formation productivity, has been discussed in this

report.

In situations where a relief well is needed to re-establish the well barriers, i.e. situations

where connection to the well is lost or pumping cannot be done from the drilling rig for any

reasons, the kill fluid should be blended for minimum viscosity in order to minimize the

hydraulic resistance. Still, it is important that the density of the kill fluid is compatible with

the formation fracture gradient or that operational measures are established in order to

compensate for possible fluid loss situations after fulfillment of the killing.

In all kill simulations performed in this study a kill fluid viscosity of 10.0 cP is used. This is

assumed conservative with respect to the pumping requirements found.

3 Blowout Potentials and Duration

Blowout potentials are defined as the maximum expected blowout rates for various

scenarios. Most likely expected parameters are to be used, or a weighted distribution of the

same parameters. Whenever necessary, parameters and calculation results should be risked

in order to establish the most reliable probability distributions for expected rates.

The OLF Guidelines for estimation of blowout potentials [1] are used as basis for all flow

rate calculations presented in this report. Distributions of possible flowpaths are given in

accordance with data from the Sintef Offshore Blowout Database [3] and the latest

evaluation of the Sintef Database data in the report from Scandpower Risk Management AS

[2].

3.1 Blowout scenarios in general

A blowout is defined as an unwanted and uncontrolled flow from a subsurface formation

which is released at surface, seabed or into a secondary formation, and cannot be closed by

the predefined and installed barriers.

Blowout potentials, i.e. the expected rates of oil, water and gas, are highly dependent on the

scenario in which the blowout occurs. Lost pipe, junk or complex escape paths for the fluid

will result in dramatically lower blowout rates than a fully open 9 casing all the way from

formation to surface.

For the NewField North exploration well, an unrestricted blowout through the 9 casing,

with exposure to fully penetrated Res-1 and Res-2 formations, will result in a maximum

blowout rate of 4445 Sm3/day of condensate and 17.8 MSm3/day of gas. This rate is related

to the maximum permeability estimates of both Res-1 and Res-2, and is very unlikely to

occur. The risk process in Section 3.5 present risked blowout rates based on an underlying

risk process, where the permeability range presented in Table 1 is accounted for.


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This unrestricted blowout scenario will in this well set up a drawdown onto the formation of

more than 110 bars (11 MPa). This drawdown might induce a risk of collapse of the

surrounding formation, or initiate production rates of sand, both consequences that can

reduce the rate of fluids flowing from the well. Formation collapse might even kill the well

and thereby stop the blowout entirely.

3.2 Case scenario definitions

Hypothetical blowout scenarios have been investigated in this study, all relevant for drilling

operations. The analyzed case scenarios include blowouts through drill pipe, annulus and

open hole to drill floor and to seabed, implying several blowout scenarios. The last case is a

collective case for simulations of restricted flow.

In order to limit the number of scenarios to analyze, two main categories of incidents are

simulated and are intended to cover all possible scenarios conservatively. The two scenarios

are Kick and Swab, which covers all kicks when entering a formation and all swab scenarios

when pulling out of hole, respectively.

Kick scenarios are represented by a partly penetrated reservoir, while swab scenarios are

conservatively represented by a fully penetrated reservoir.

The following principles in selection of scenarios have been used as basis for simulation

cases:

Blowout through casing/open hole, reservoir partly penetrated, kick scenarios

Blowout through casing/open hole, reservoir fully penetrated, swab scenarios

Blowout through drillpipe, reservoir partly penetrated, kick scenarios

Blowout through drillpipe, reservoir fully penetrated, swab scenarios

Blowout through annulus, reservoir partly penetrated, kick scenarios

Blowout through annulus, reservoir fully penetrated, swab scenarios

Restricted blowout through topside leak, 64/64'' choke

All scenarios listed above have been investigated in this report.


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Figure 7: Possible blowout paths for the defined scenarios (Illustrative only).

A find in Res-1 and Res-2 is related such that a find in Res-2 is not possible with no find in

Res-1. This result in the following possibilities:

a) HC find in Res-1

b) HC find in Res-1 and Res-2

HC find in none is not evaluated in this report.

Based on this, the following definition is made for simulations performed in this study.

1) Kick scenarios are represented by a partly penetrated Res-1

2) Swab scenarios are represented by fully penetrated Res-1 and Res-2.

See Section 3.5.2 for illustration and results from final risk procedure.

For cases involving a partly penetrated reservoir, i.e. the kick scenarios, a gross penetration

pay of 5 meters is used. The N/G ratio is 1.0, which is considered conservative.

Drilling

BOP

Sealevel

Drilling

BOP

Sealevel

Drilling

BOP

Sealevel


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3.3 Distribution of flowpath probabilities

In order to establish the best possible statistical estimate for the well, a distribution

between all investigated scenarios and the expected duration for these are to be calculated

based upon the Guidelines from OLF [1]. The statistical values are found based on the Sintef

Offshore Blowout Database [3] and the annual report from Scandpower[2], that are basedupon a more comprehensive analysis of the Sintef database. Hence, irrelevant cases are

removed and probability distributions are adjusted according to observed trends.

Furthermore the operational experience from the Acona Wellpro group of companies, with

more than 25 years of relevant operations is implemented in the calculation of the

probability distribution. These evaluations and their weighting are discussed in detail below.

Table 3 summarizes relevant statistical findings from drilling-, completion and workover

activities from the Scandpower report from January 2010 [2]. In addition to the incidents

listed within drilling, incidents within both completion and workover activites are added to

expand the statistical foundation. These activities are considered to have a similar type ofbarrier system, with drilling mud as the first barrier and the BOP as the second barrier.

Table 3: Probability distribution of flow paths from 20 years of historical data Floaters.

When implementing these data for calculation of flow path distribution the following

assumptions and methodology have been used:

The number of incidents is relatively low and small variations might cause relatively large

alterations in the distribution coefficients, i.e. from one year to another as incidents older

than the limitations set are removed from the statistical material. The statistical uncertainty

will increase even more if some of the findings from the table above are considered

irrelevant for the operation that is to be analyzed.

In order to try predicting the probabilities for the different flow paths possible, a more

detailed analysis is needed. A well operation with dead well, defined as operation where

the fluid column itself is the primary barrier, includes the activities drilling operations,

workover operations and completion operations. Loss of well control in these operations are

initiated by, and limited to, formation kicks or losses caused by unexpected formation

Full Restricted Full Restricted

Outside casing 22.70 % 4.50 %

Outer annulus 18.20 % 4.50 %

Annulus 31.80 % 4.50 % 4.50 %

Open hole 4.50 %

Inside drillstring

Inside test tubing 4.50 %Annulus 4.50 %

Inside drillstring 4.50 % 40.90 %

Inside prod tubing 4.50 % 45.50 %

Outer annulus 27.00 %

Annulus 27.00 %

Inside drillstring 24.30 %

Inside prod tubing 16.20 % 5.40 %

Workover

(7.4 incidents)

Drilling

(22 incidents)

Completion

(4.4 incidents)

Data update: January 2009

Distribution - Floaters

Subsea Topside


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properties, lack of operational fluid control or swabbing of reservoir fluids from pulling out

of holeactivities or lack of heave compensation.

Since all these three incidents (kick or loss from/to reservoir, lack of fluid control and

swabbing) also are possible from completion and workover operations and that the

secondary barrier in these operations also includes the drilling BOP, the statistical data fromthese two groups are included in the statistical summary together with the data from drilling

operations.

In the final distribution used in this report, the outside casing and outer annulus flow paths

are neglected. Such rejection is supported by the fact that kick procedures are to be

established in order to minimize the risk of an underground blowout. Also, the modeling

process would be too complicated, in terms of describing the flow paths. Hence, reliable

modeling results are beyond reach.

Similar the flow through production/test tubing is interpreted as flow through open

hole/casing.

When drilling production wells, i.e. in mature areas, the risk of running into unknowns are

clearly lower than when drilling exploration wells, i.e. experiencing reservoirs with pore

pressure higher than the corresponding ECD which might induce a formation kick. The

formations pore pressures are provided through estimation for exploration wells. When a

formation kick is observed, an operational procedure normally instructs the driller to stop

further penetration and to close a secondary barrier in the drilling BOP. Furthermore the

kick will be circulated out through the choke lines. In the risk and weighting process it is

anticipated that such kick will be observed relatively shortly after penetrating the formation.

In this report a penetration depth of 5 meters is used, similar to half a joint of drillpipe,

assuming that the bit did not penetrate the formation when the drillpipe last was made up.5 meter penetration of top reservoir is assumed to be a conservative number.

In reality, the choice of penetration length into the reservoir, i.e. 5 m, is not of importance

when evaluating the probability distribution. In fact, it is the mechanisms leading to the

blowout that is important. For the partly penetrated case, the occurrence of a blowout is

due to a kick scenario in the well. For the fully penetrated case, a swab scenario leads to the

possible blowout. The loss of primary barrier by swabbing of reservoir fluids when pulling

out of hole can be caused by pulling to fast, insufficient compensation of the pumping rates

or by a combination of these. Borehole collapse or partly collapse of some strings or

formations might increase the risks of swabbing reservoir fluids. Theoretically such swabbing

may not be discovered before the BHA is at surface.

Accordingly, for this exploration well, the following probabilities are used between partly

and fully penetrated reservoirs.

Blowout initiated when the formation is partly penetrated 60 %

Blowout initiated when the formation is fully penetrated 40 %

For the kick scenarios, i.e. partly penetration, 5 m penetration is used, with a N/G ratio of

1.0, which is considered conservative.


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Note: It is worth to notice that the risk of flowing through OH, when penetrating top

reservoir only, is assumed irrelevant and the probability of this is given a 0.0 % value. This is

founded upon the fact that the top reservoir cannot be penetrated without having the DP

and the bit in the hole.

Therefore the flow path probabilities in the top penetration scenario, i.e. a kick scenario, aregiven the following values:

Blowout through drill pipe has a probability of 25 %

Blowout through annulus has a probability of 75 %

Blowout through open hole to surface has a probability of 0 %

Similar, the fully penetrated, i.e. swab scenario, are given the following probability

distribution:

Blowout through drill pipe has a probability of 21 %

Blowout through annulus has a probability of 62 %

Blowout through open hole to surface has a probability of 17 %

In all drilling operations, and most other well operations as well, a Blowout Preventer (BOP)

stack of valves and rams defines the secondary barrier against uncontrolled outflow of

reservoir fluids. The BOP testing program and its procedures ensure that a BOP stack is

experienced as extremely reliable equipment. This is further emphasized by the number of

independent rams in the BOP and the requirement for accumulator capacity. Based on this,

the risk of a total failure of the BOP is assumed to be very low.

Once a blowout has occurred, the BOP has failed or has not been activated. Given such

unlikely failures, and based on the OLF Guidelines for estimation of blowout potentials[1],

the following distribution has been used for partly or full BOP failure:

Restricted flow area has a probability of 70 %

No restriction has a probability of 30 %

The different consequences of a partial failure in the BOP are difficult to predict. In the OLF

Guidelines for estimation of blowout potentials it is proposed to model a partly failure as

95% reduction of the available fluid flow area. As restriction in available flow paths also can

be caused by pipe in hole, fish/junk or collapse of the borehole itself, Wellpro Academica

suggest that modeling of a partly failure is better described with a restriction similar to

64/64 flow area for all scenarios. This is justified by the fact that the remaining flow area

now is independent of the wellbore design or the size of the drillpipe used.

3.4 Blowout duration

A blowout may be stopped by several remedial actions. These are divided into the following

categories:

- Bridging, i.e. collapse of the near wellbore due to low pressure and/or high

production rates.

- Intervention from crew

- Subsea or topside attempt requiring additional equipment

- Drilling of relief well intersecting the blowing well


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If one or more relief wells are necessary to regain control of the well, the time needed for

mobilization and drilling may vary. We can assume that the relief wells can be drilled with

the same rate as the exploration well, but in addition ranging runs are required, e.g. with

electromagnetic ranging tools. The time required to run such equipment must be taken into

account. The time will depend upon drilling intersection depth, rig availability in general and

in the specified area and weather conditions.

For the 5505/5-5 NewField North well, drilling of one relief well is estimated as follows:

Decision to drill the relief well: 3 days

Termination of work, sail to location, anchoring and preparation : 12 days

Drilling relief well to intersection: 45 days

Homing in: 10 days

Total time to kill well: 70 days

Assumptions are made that the relief well will successfully kill the well after 70 days.

In order to give best possible distribution estimate, the probability distribution for the

different historical incidents must be found. The figure below is presented from the

Scandpower reported data from 2010 and presents the probability that a blowout is still

active after a certain number of days and several mechanisms may have been tried.

Figure 8 describes the probability of killing a well after a number of days based on the use of

one single kill mechanism.

Figure 8: Blowout duration data from the Sintef Database and the Scandpower report 2010 [2].

As can be seen from the figure above, multiple mechanisms may work together in order to

stop the blowout. Scandpower reports that 77% of all blowouts can be stopped by bridging,

70% can be stopped by intervention topside and 43% can be stopped by intervention

subsea, if the mechanism evaluated is the only mechanism to stop the leak [2].

Table 4 summarizes the risk criteria used in the distribution analysis in Chapter 3.5.

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 5 10 15 20 25 30 35 40 45 50

Percentage

Days

Wells still flowing after subsea attempts

Wells still flowing after topside attempts

Wells still flowing after natural bridging


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Table 4: Risk criteria in duration distribution.

Risk of a blowout duration of 2 days P2The blowout could be controlled by measures

performed from the existing rig

Risk of a blowout duration of 15 days P15The blowout could be controlled by bringing

in additional equipment

Risk of a blowout duration of 70 days P70The blowout will have to be killed by drilling a

dedicated relief well.

3.5 Risk process and distributions

From the detailed analysis presented in the previous section the probabilities for all relevant

scenarios were found. According to the OLF Guidelines for estimation of blowout

potentials all possible scenarios should be risked and blowout potentials shall be weighted

respectively.

Note: The overall probability of finding hydrocarbons in a well, which again introduces a

certain risk for a blowout shall be included either in the environmental analysis or in the

blowout analysis (this report). This value is neglected in this report and will have to be

included in the environmental analysis.

3.5.1 Permeability risking

The formations to be investigated in this report are all presented with a permeability range.

A log normal probability distribution gives highest probability for the low case, as shown in

Table 5:Table 5: Permeability risk distribution

Formation Low Medium HighRes-1 50 mD 100 mD 200 mD

Res-2 1 mD 3 mD 5 mD

Probability 50% 30% 20%

All Kick scenarios are risked according to the input in Table 5. The risked rates presented in

Table 6 and Table 7 (far right column) are used as input to the final risk process in Section

3.5.2.

Kick scenario 5m penetration of Res-1

Table 6 and Table 7 list gas condensate rates for the specified scenarios. The far right column

of the individual tables represents the risked rate of gas condensate for the range of

permeability. Risking of flowpaths are introduced in Section 3.5.2.

Table 6: Permeability risking Kick scenario 5m reservoir exposureUnrestricted Flowpath

50 mD 100 mD 200 mD Risked

[Sm/d] [Sm/d] [Sm/d] [Sm/d]

OH 5 mSubsea 635 1232 2156 1118

Surface 647 1243 2172 1131

DP 5 mSubsea 475 655 788 592

Surface 463 626 745 568

ANN 5 mSubsea 571 926 1255 814

Surface 576 933 1261 820

Restricted Flowpath

50 mD 100 mD 200 mD Risked

Sm/d] [Sm/d] [Sm/d] [Sm/d]

OH 5 mSubsea 424 543 621 499

Surface 423 540 616 497

DP 5 mSubsea 373 461 518 428

Surface 363 447 500 415

ANN 5 mSubsea 404 511 582 472

Surface 403 508 577 469

Note: The methodology for estimating most likely duration of a blowout are under

revision and the methodology are likely to be changed or updated later in 2010.


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Swab scenario Fully penetrated Res-1 and Res-2

To simplify the model and restrict the number of scenarios, the reservoir permeability of

Res-1 and Res-2 is modeled in a low, medium and high permeability scenario. I.e. all

combinations of permeability are not simulated. This leads to the following permeability

scenarios:

Table 7: Swab scenario - Permeability risk distributionLow Medium High

Res-1+Not / Ile+Tilje 50/1 mD 100/3 mD 200/5 mD

Probability 50% 30% 20%

Table 8: Permeability risking Swab scenario Full reservoir exposureUnrestricted Flowpath

50/1 D 100/3 mD 200/5 mD Risked

Sm/d] [Sm/d] [Sm/d] [Sm/d]

OH FullSubsea 2562 3570 4420 3236

Surface 2630 3649 4445 3299

DP FullSubsea 847 905 936 882

Surface 799 850 877 830

ANN FullSubsea 1406 1597 1708 1523

Surface 1411 1601 1712 1528

Restricted Flowpath

50/1 D 100/3mD 200/5 D Risked

[Sm/d] [Sm/d] [Sm/d] [Sm/d]

OH FullSubsea 651 681 696 669

Surface 653 679 691 668

DP FullSubsea 544 564 574 556

Surface 525 545 555 537

ANN FullSubsea 613 641 655 630

Surface 609 634 647 624

3.5.2 Final blowout risk procedure

The process diagram in Figure 9 shows the risk process which is implemented in the analysis

presented in this report, and the resulting weighted blowout rates of oil for a surface

release.

Surface release vs. subsea release

When drilling from a floater, anchored or dynamically positioned, the OIM will try to pull the

rig off from location shortly after an uncontrollable well integrity issue is unveiled and anysurface attempt to stop the flow has not succeeded or have been evaluated as unlikely to

succeed. This leads to the two different duration estimates for a surface and a subsea

release as presented in Table 9 and Table 10.

Figure 9: NewField North Illustrative risk process for the surface release case.

Step 5 Step 6

Total Risk

Oil blowout

potential

[%] [Sm/day]

0.00 % 1131

0.00 % 497

13.50 % 82031.50 % 469

4.50 % 568

10.50 % 415

2.04 % 3299

4.76 % 668

7.44 % 1528

17.36 % 624

2.52 % 830

5.88 % 537

100.00 % 701 Sm/day 2.80 MSm/day

0.43

0.08

0.13

0.00

0.440.59

0.10

0.17

0.27

0.13

0.45

Step 7

Risked oil

blowout rate

[Sm/day]

0

0

111148

26

44

67

32

114

108

21

32

Formation Penetration Flowpath

Step 8

Risked Gas

blowout rate

[MSm/day]

0.00

Step 1 Step 2 Step 3

BOP Status

Step 4

Yes

Kick - 5mGarn+Not

Swab - FullGarn+NotIle+Tilje

60%

40%

9 5/8"Csg

Annulus

Drillpipe

9 5/8"Csg

Annulus

Drillpipe

0%

75%

25%

17%

62%

21%

Restricted

Open

Restricted

Open

Restricted

Open

Restricted

Open

Restricted

Open

Restricted

Open

30%

70%

30%

70%

30%

70%

30%

70%

30%

70%

45%

70%


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All values in Figure 9 above are repeated in the tables below for improved readability. The

risked blowout rates and duration distributions are listed in the following tables; Table 9 for

surface release, and Table 10 for subsea release.

Table 9: Blowout rates and duration distributions for a potential surface release

Table 10: Blowout rates and duration distributions for a potential subsea release

The risk process illustrates the most likely expected blowout rates for an uncontrolled

blowout from the 5505/5-5 NewField North well. These values are risk weighted; therefore

both higher and lower rates may be experienced in a real blowout. The risked values arequalified numbers for likely volumes expected, and are to be used when evaluating the

possible environmental impact from the well.

As can be seen from Figure 9 and the tables above, the expected gas condensate blowout

rate from the NewField North exploration well is 701 Sm/day for a surface release point and

706 Sm3/day for a subsea release point. The corresponding risked blowout rates of gas are

2.80 MSm3/day for a surface release point and 2.82 MSm3/day for a subsea release point.

There is no significant difference in blowout rates between surface and seabed releases.

The risked durations for surface and subsea release, are 13.1 days and 23.4 days,

respectively.

Note: The risked blowout rates shall not be used for evaluating possible kill methods or

requirement.

The worst case scenario is described by the scenario with an open and unrestricted flowpath

and fully penetration of Res-1 and Res-2 formations with maximum permeability estimates.

In such an unlikely event, the maximum blowout potential is found to be 4445 Sm/day of

gas condensate and 17.8 MSm3/day of gas.

Step 5 Step 6

Total Risk

Oil blowout

potential

P2

t < 2 days

P15

t < 15 days

P70

t


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3.6 Possibility for underground blowout

An underground blowout is defined as uncontrolled flow from one or more formations, into

one or several formations. If the receiving formations are located above possible sealing

rocks, such a blowout might develop into an uncontrolled release to seabed.

In a well control situation, the formation below the last casing shoe could be exposed to

pressures higher than the corresponding fracture pressures. Based on lightest possible fluid

column from the reservoir to the casing shoe, an analysis is performed to evaluate possible

pressure conditions at the last casing shoe.

In the NewField North well, a 9 casing is planned set at 3450 m TVD RKB. At this casing

shoe, the fracture gradient is estimated to 1.85 sg, equivalent to 626 Bara. The fracture

gradient is estimated based on a provided FIT of 1.85 sg. This is considered conservative.

Assuming shut in with light gas from the Res-1 and Res-2 formations, with the reservoirs

expected pressurized to 470 Bara, the fracture pressure cannot be exceeded at the givencasing shoe depth.

Hence, based upon the given fracture gradients and expected formation pore pressures,

WPA has evaluated the risk of experiencing an underground blowout as less likely. Such

blowout has been disregarded from this report.

4 Killing Methods of Blowing Wells

A blowout can be divided into four main categories with respect to the remedial action

needed to re-control the well:

- Interventions from the rig

- Bridging

- Drilling of relief well

- Natural causes

Interventions from the rig

If the drilling rig is still intact and possible to work on, several remedial actions can be

foreseen as possible methods for killing of a blowout. Possible solutions are:

- Mechanical actions

- Dynamic actions

Mechanical actions can be installation of a new wellhead on top of the existing one,

installation of additional, or replacement of valves or closure of already installed valves, like:

- BOP valves

- Swab, master or wing valve in the X-mas tree

- DHSV

Possible dynamical actions from the drilling rig could be circulation of fluids or cement into

the well. High density fluid might kill the well hydrostatically, whilst high pumping rates

might kill the well hydrodynamically. Bullheading intends to pump at sufficient pumpingrates to overcome the rising velocity of the gas bubbles in order to displace the well fluids


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with kill fluids. Kill fluid may be lubricated, circulated or bullheaded into the wellbore

dependent on the actual status of the well. Table 11 shows necessary pumping rates needed

in order to ensure that all gas found in the wellbore will move downwards as fluid is pumped

into the same wellbore from topside connections. Table 11 is generic and for information

only, and assumes completed well with installed X-mas tree.

Table 11: Minimum bullheading rates in order to ensure displacement of gas.

Needed bullheading rates toensure gas displacement

Verticalwell

Deviatedwell

[LPM] [LPM]

9 casing 1350 2300

7 tubing 550 950

5.5 tubing 300 550

Bridging

The majority of blowing wells are killed by themselves because of bridging. According to the

Scandpower report approximately 77% of the historical blowouts could be stopped by

bridging if no other mechanisms or manmade attempts were initiated. Bridging mechanisms

might be:

- Sand or rock accumulates inside the wellbore

- Formation collapses due to high flowing rates and high drawdown pressure

- Formation of hydrates blocking the flow paths

Drilling of a relief well

If the blowing well cannot be controlled otherwise, a dedicated relief well will have to be

drilled. A relief well is to establish a secondary flow path directly into the blowing well,

wherein kill fluid can be pumped. Such action is extremely time consuming and involves

mobilizing of one, or more, new drilling rigs, anchoring, controlled survey and large volumes

of kill fluids pumped at high pumping rates directly into the blowing well.

Natural causes

Other possible mechanisms stopping a blowing well could be:

- Pressure depletion of the blowing reservoir

- Stopping of gas lift, gas- or water injection

- Coning of water or gas into the blowing well

4.1 Design of the relief well

Surface considerations

According to regulations a minimum spud distance from the blowing well is suggested to be

500 meter. Corporate regulations might be even more conservative, and the distance might

also be increased for better logistics and/or improved access for emergency and oil spill

vessels. Because of these elements, some companies recommend a minimum distance of

1000 1500 meters. The spud location should take into account wind, sea current and rig

anchoring. Normal caution procedures with respect to shallow gas, casing design and barrier

philosophy shall imply. The relief well drilling rig shall not interfere with any subsea

installations, pipelines or cables.


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The location shall be selected so that smoke, fumes, hydrocarbons or toxic gases may not

reach the relief well drilling rig. Therefore local wind and current patterns for the specific

area and time of the year must be addressed.

Normally, two relief well locations should be identified. In this report, 1000 meters are used

as horizontal distance from 9 casing shoe to relief well rig.

Relief Well design considerations

Normal drill pipe and equipment should be planned for. In this evaluation, a well design

similar to the main well is assumed.

Wellpath considerations

In order to minimize the blowout duration, the well path of the relief well should be as short

as possible. This also reduces the hydraulic power needed to deliver the necessary kill rate.

East-West direction is preferred, due to uncertainties in the survey tools. The well path

should be suitable for wireline service. Hence, inclination should be less than 60-65.

Pumping considerations

Pumping through both drillpipe and annulus is not recommended, because of the

importance of having control over the flowing bottomhole pressure. It is possible to utilize

the drillpipe in the relief well as a downhole pressure gauge. Water will be pumped at a low

rate and the topside pressure will be measured and the hydrostatic water gradient added.

The total volume of kill fluid needed for a dynamic kill operation is the sum of:

Volume of mud to fill the relief well

Required pump rate times the time to stop inflow (FBHP > PRESERVOIR)

Two hole volumes of the blowout well to ensure two proper bottom up

circulations

4.1.1 Relief well data

A relief well design similar to the production well is assumed. A simplified survey was

generated for the relief well, based on the below listed design.

A 9 casing is assumed set as the last casing @ 3350 m TVD RKB, approximately 100

meters prior to the intersection point, drilling a 8 OH into the blowing well just below the

9 shoe of5505/5-5.

4 kill and choke lines are assumed in the evaluated scenarios.

5/5 OD drillpipe is used in the relief well with a 60 meter BHA of 6.5 OD.

4.2 Dynamic wellkill through a relief well

Dynamic simulations were performed in order to design a suitable relief well capable of safe

killing of the maximum blowout rates from the well. Dynamic simulations are performed

utilizing the OLGA 6.2.7 software package, considered state of the art within dynamic

simulation of multiphase flows.

Main objective was to identify the worst case scenarios and their respective kill

requirements with respect to pumping rates and kill fluid density, assuming that the kill


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operation will have to be carried out through relief wells, intersecting the main well just

below the last casing shoe.

4.2.1 Simulation and model assumptions

A discussion on simulation choices follows. The simulation results are summarized in tables.

Several combinations of kill mud density and kill rates through the relief well are presented,

as well as various number of relief wells.

Reservoir fluids and their mobility

Due to the sea water gradient and the pressure gradient in the blowing well in this specific

case, the blowout rates for a surface release will be insignificantly higher than from a subsea

release. However, killing of a blowout with a surface release is more challenging than a

subsea release due to the higher pressure at the outlet of the blowing well in the subsea

case.

Therefore, the dynamic wellkill evaluations done in this report, where the blowout is killedthrough a relief well, is mainly performed for a blowout with surface release from a fully

exposed Res-1 and Res-2 formations. Killing of worst case openhole scenario is also

performed for blowout with subsea release due to the Subsea/Surface discussion performed

in Section 3.5.2.

The fluid column that will kill the well is generated between the last casing shoe and topside.

Depletion

In case of a real blowout developing, large volumes of reservoir fluids will be produced to

surface and the near wellbore pressure will deplete accordingly. The simulations presented

in this report do not include such depletion and will therefore be conservative compared tothe requirements at the time of the actual kill operation.

4.2.2 Simulation results Dynamic kill simulations

Blowout through openhole

An unrestricted surface blowout through openhole represents the most difficult kill scenario

evaluated in this report.

Simulations show that a surface blowout from fully penetrated Res-1 and Res-2 formations,

through an 8 openhole section and an open 9 casing set at 3450 m TVD RKB, can be

killed by means of one single relief well only and 2.1 sg mud, pumping 10000 LPM to a totalof 200 m kill mud to stop hydrocarbon influx from the reservoir. Estimated total volume

mud required during the operation, including 2 x bottoms up circulation, is 693 m of mud.

Note that high kill fluid densities needed might fracture the formation and operational

procedures should be prepared for circulation of lighter fluids to stabilize the well after

hydrocarbon influx is stopped.

The kill requirements found are presented in Table 12, and represent kill requirements for

an unrestricted blowout through an open hole, from reservoir to the surface/subsea release

point.


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Variations of kill rate and relief well designs are presented in order to unveil the possibilities

found to reduce the number of relief wells required to one single well. A variation in

drillpipe OD and kill-/choke line ID is presented.

Pump down through the inside of the relief well drill pipe can be done in order to increase

the flow area even more and hereby further reduce the hydraulic resistance. Please notethat this procedure should be considered with care, as the pressure reading as described in

Section 4.1 is lost. This option is reported used on the Montara blowout in 2009.

Table 12: Kill data - Worst-case scenario - Blowout through open holeBlowout path Release

point

Relief well info Reservoir

exposure

Minimum

Kill fluid

Density

Kill

vol

Total vol

req.

Min hp

req

Max

topside

press.

Total rate

req.

#

relief

wells

[sg] [m] [m] [hp] [bar] [lpm]

9 csg @

3450 m TVD

RKB

Surface9 csg, 5.5" DP,

4" kill and choke lines

Res-1

Res-22.0 226 794 < 500 < 50 11000 2

9 csg @

3450 m TVD

RKB

Surface9 csg, 5" DP,

4.5" kill and choke lines

Res-1

Res-22.0 226 794 < 500 < 50 11000 2

9 csg @

3450 m TVD

RKB



Res-1

Res-22.1 245 813 < 500 < 50 10000 2

9 csg @

3450 m TVD

RKB



Res-1

Res-22.1 200 693 7102 272 10000 1

9 csg @

3450 m TVD

RKB



Res-1

Res-22.2 342 835 7482 318 9000 1

9 csg @

3450 m TVD

RKB

Subsea9 csg, 5.5" DP,


Res-1

Res-22.2 212 551 7482 318 9000 1

9 csg @

3450 m TVD

RKB

Subsea9 csg, 5.5" DP,


Res-1

Res-22.2 234 573 5692 256 8500 1

Blowout through drillpipeThis case is defined as a blowout through the in-hole drillpipe, and assumes closed BOP with

no restrictions in drillpipe, or topside restrictions such as Kelly-cock or kick-stand, see Figure

7 for an illustrative example.

Killing of a blowout through the drillpipe does not require large kill rates or pit capacities.

Successful killing is performed by moderate rates with 1.5 sg mud.

Table 13: Kill data - Blowout through drillpipeBlowout path Release

point

Relief well info Reservoir

exposure

Minimum

Kill fluid

Kill vol Total vol

req.

Min hp req Max topside

press.

Total rate

req.

# relief

wells


5.5" drillpipe@ 3450 m

TVD RKB

Surface 9 csg, 5.5"DP, 4" kill and

choke lines

Res-1Res-2

1.5 46 225 < 500 < 50 2500 1

Blowout through annulus

This case describes a surface blowout through the annulus between the drillpipe and the 9

casing. See Figure 7 for an illustrative example.

Simulations show that blowout through the above specified annulus could be by moderate

kill rates, pumping 1.7 sg mud @ 4000 LPM.


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Table 14: Kill data - Blowout through annulus

Blowout path

Release

point Relief well info

Reservoir

exposure

Minimum

Kill fluid Kill vol

Total

vol req.

Min hp

req

Max topside

press.

Total

rate req.

# relief

wells


9 5/8" csg @

3450 m TVD

RKB

Surface

9 5/8" csg, 5.5"

DP, 4" kill and

choke lines

Res-1

Res-21.7 180 567 < 500 < 50 4000 1

9 5/8" csg @3450 m TVD

RKB

Surface9 5/8" csg, 5.5"DP, 4" kill and

choke lines

Res-1

Res-21.8 112 499 < 500 < 50 4000 1

4.3 Pump and kill mud considerations

4.3.1 Possible kill sequence

The dynamic kill operation requires large pump rates and heavy kill mud to overcome the

reservoir pressure. The graph presented in Figure 10show pump rates vs. gauge pressure on

the relief well mud pumps, in a possible kill sequence.

The kill sequence presented utilizes heavy 2.1 sg. kill mud until BHP exceeds the reservoirpressure in Res-1 and influx from the reservoirs is stopped. A that point, kill mud density at

the relief well rig is switched to 1.6 sg mud in order to prevent formation fracture.

When the BHP exceeds the reservoir pressure, the relief well pump rate is reduced to 1000

LPM during a circulation sequence to circulate all remaining hydrocarbons from the 5505/5-

5 well.

Figure 10 show pump discharge pressure and hydraulic power requirements during a kill

operation of a worst case scenario, where a less dense kill mud is utilized during the

circulation sequence, in order to prevent formation fracture.

Figure 10: Relief well - pump power vs. pump discharge pressure

Figure 11 represent the same sequence as for Figure 10, but show the pump rate and

bottom hole pressure (BHP) at Res-1 (3555 m TVD RKB).

0

100

200

300

400

500

600

700

0

1000

2000

3000

4000

5000

6000

7000

8000

0 1 2 3 4 5

Pumppressure

[bara]

Pumppower

[hP]

Time

[hrs]

Pump power

Pump pressure

BHP exceeds Pres of Garn/Not. Pump

rate reduced during circulation


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Figure 11: Pump rate vs. BHP in possible kill sequence

Figure 12 illustrates total oil/gas content and mud content in the 5505/5-5 well during the

proposed kill sequence. Circulation of mud should continue until all hydrocarbons are

evacuated from the well.

Figure 12: Oil/gas and mud content in 5505/5-5 during kill sequence

0

100

200

300

400

500

600

700

0

2000

4000

6000

8000

10000

0 1 2 3 4 5

Pressure

[bara]

Pumprate

[LPM]

Time

[hrs]

Pump rate

BHP - Garn/Not

Reservoir Pressure

0

50

100

150

200

250

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5

Volume

[m]

Time

[hrs]

Oil and gas content in well

Mud content in well

BHP exceeds Pres. Switch to

1.6sg mud at relief well rigBHP stabilizes at a pressure

equivalent to a 1.6 sg mud gradient


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4.3.2 Minimum pumping requirements on relief well drilling rigs

The engaged rig(s) to drill the relief well in order to kill the blowout scenarios evaluated for

the NewField North exploration well will have to meet the following minimum capabilities,

in order to ensure safe and reliable killing of a potential blowout:

No of drilling rigs: 1

Total pump capacity: 10.000 LPM @ 272 barg

Minimum horsepower req.: 7102 HP

Typical mud-pump setup: 4x2000 HP

Minimum pit capacity pr rig: 700 m

Kill and choke line dimensions: 4 ID

Figure 13: Typical mud pump capacity ranges.

4000

6000

8000

10000

12000

14000

16000

250 300 350 400 450 500

Pumprate

[LPM]

Pressure

[barg]

Typical mud pump capacity ranges

4 x 2200 HP mud pumps

3 x 1600 HP mud pumps


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4.4 Figures: Worst case gas-only kill scenario

Instalation: West Phoenix

Well no: 6607/12-2

Well type: Exploration

Well status: Planned

Date: 29/11/10

Revision no: 01

Prepared by: V.Grner

Approved by: T.Rinde

Killing of worst case

blowout rate scenario

Operation info

Comments/Notes

Worst Case ScenarioWell info

Blowout Rate: 17.8 Sm/day

9 " csg to seabed

403 meter - 21" marine riser

Totalt well & riser volume: 210m

Relief well info

9 " tapered csg in relief well

8 OH to intersection (~100m)

5.0" OD drillpipe

60 meter BHA 6.5" OD

2 x 4" ID kill / choke lines

75 meter 8" fixed surface line (ID =7.2")

Relief well length: 3731 m (Surface TD)

Intersection point: 3450 m TVD RKB

Pumping info

Total pump rate: 10000 LPM Minimum kill fluid density: 2.1 sg

Minimum kill volume: 200 m

Total volume required: 693 m

Minimum pump power pr rig: 7102 hP

Minimum surface pressure: 272 BarG

36" x 30" Conductor

475 m TVD

13 "csg

2380 m TVD RKB

Seabed 364 m MSL

8 OH

TD 4031 m TVD

RKB-MSL 39 m

Drilling

BOP

Sealevel

Top Garn/Not 3555

m TVD RKB

Intersection

3450 mTVD RKB

20" csg1350 m TVD RKB

9 " csg

3450 m TVD

RKB

Top Ile/Tilje 3724

m TVD RKB

Pres 470 bara

Pres 470 bara

Figure 14: Illustrative summary of blowout and killing of the worst case kill scenario.


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5 References

1. Nilsen, Thomas; OLF Retningslinjer for beregning av utblsningsrater og - varighet til

bruk ved analyse av miljrisiko - Rev. nr. 02, 15. januar 2007.

2. Blowout and Well Release Frequencies - Based on SINTEF Offshore Blowout Database,

2009, Report, Scandpower Risk Management. Report no. 80.005.003/2010/R3,

17.03.2010.

3. Sintef Offshore Blowout Database


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6 Appendix list

1. About Wellpro Academica AS


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Appendix 1: About Wellpro Academica ASWellpro Academica, established as a specialized competence center for fluid modeling and

process control, employs specialists, mainly with PhD degree and extensive backgrounds

from the industry. We have advanced software packages and simulation models available

for our clients.

Typical services provided by Wellpro Academica are:

Flow assurance simulations and advice

Computational Fluid Dynamics (CFD) simulations and advice

Dynamic wellkill analyses

Blowout analyses

Well and flowline simulations and optimization

Process simulations and de-bottlenecking

Well and flowline allocation services

Wellpro Academica personnel have a unique blend of competence. The company provides

senior modeling services to a wide range of the industry from solar and renewables, via

metallurgical, to the oil and gas industry. Our strength is the competence, the diversity and

the ability to transfer this know-how.

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