Blowout and Kill Simulation Sample Report

Well blowout and dynamic wellkill simulations Exploration well 5505/5-5 NewField North (PL 555) SampleCo E&P December 2010

Customer:

SampleCo Customer PO no.:

Project:

N/A

Project nr. 2010-800070 2010-800070

Document title:

Doc. no.: WPA-DOC-2010-800070 WPA-DOC-2010-800070-00 -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 ½ ” 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 ⅜” intermediate csg set @ 2380 m TVD RKB and a 9 ⅝” 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 a nd 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 Sm³/day of gas condensate and 17.8 MSm3/day of gas. The risk weighted blowout potential is found to be 701 Sm³/day of gas condensate and 2.80 MSm³/day of gas for a surface blowout and 706 Sm³/day of gas condensate and 2.82 MSm³/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 m³ to stop HC influx. Total mud volume required during the operation, including 2 x bottom up circulation, is 693 m³. 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

0

03.12.2010

Description First version

Created by:

Approved by :

V.Gruner

T.Rinde

Customer:

SampleCo Customer PO no.:

Project:

N/A

Project nr. 2010-800070 2010-800070

Document title:

Doc. no.: WPA-DOC-2010-800070 WPA-DOC-2010-800070-00 -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 ½ ” 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 ⅜” intermediate csg set @ 2380 m TVD RKB and a 9 ⅝” 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 a nd 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 Sm³/day of gas condensate and 17.8 MSm3/day of gas. The risk weighted blowout potential is found to be 701 Sm³/day of gas condensate and 2.80 MSm³/day of gas for a surface blowout and 706 Sm³/day of gas condensate and 2.82 MSm³/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 m³ to stop HC influx. Total mud volume required during the operation, including 2 x bottom up circulation, is 693 m³. 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

0

03.12.2010

Description First version

Created by:

Approved by :

V.Gruner

T.Rinde

Contents List of figures ........................................................ ......................................................... ........................... 4 List of tables ............................................... ......................................................... ..................................... 4 List of acronyms.................................................... ......................................................... ........................... 5 1 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 Permeability sensitivity ................................................... ...................................................... 11 2.7.1 Res-1 permeability permeability sensitivity ................................................... ................................... 12 2.8 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 Distribution of flowpath probabilities 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 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] ............... 10 Figure 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 p aths 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 ............................................... 21 Table 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 BHA BHP BOP CGR DHSV DP ECD GOR ID IPR LPM MD MSL N/G OD OH OIM PWL RKB sg. TD TVD WBM WPA

Revision: 0

American Petroleum Institute Bottomhole assembly Bottomhole pressure Blowout preventer Condensate gas ratio Down hole safety valve Drillpipe Equivalent circulating density Gas oil ratio Inner diameter Inflow performance relationship Liter per minute Measured depth Mean sea level Net/Gross Outer diameter Open hole Offshore Installation Manager Planned well location Rotary kelly bushing Specific gravity Total depth True vertical depth Water based mud 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 rates and 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 o f 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 present estimates 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! Reference source 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 Brønnøysund. 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 555 Source: 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 rig for 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 o RKB. Expected reservoir pressure and temperature are 470 bar and 130 C, respectively. The formations are planned drilled with an 8 ½’’ 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.]. Top formation Temperature @ res top Pressure FIT @ 20’’ csg FIT @ 9 5/8’’ csg Gross interval depth N/G ratio Net interval depth Permeability Productivity Index, PI Skin

2.4

m TVD RKB °C  BarA sg  sg  meter  meter  mD Sm³/d/bar  -

Res-1 3555 130 470 1.75 1.85 52 0.67 35 50-200 0

Res-2 3724 130 470 1.75 1.85 56 0.875 49 1-5 0

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 Sm³/Sm³. 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 Condensate density at std cond.* Condensate viscosity at std cond.* Gas density at std cond.* Gas viscosity at std cond.* Gas to Condensate Ratio (GCR)

kg/Sm³  cP kg/Sm³  cP Sm³/Sm³ 

Data 800 0.328 0.856 0.008 4000

kg/m³  cP BarA Sm³/Rm³ 

Data 435 0.064 440 0.0037

*std conditions defined as 15°C/1.0135 BarA

Reservoir conditions Gas density at res cond.** Gas viscosity at res cond.** Bubblepoint pressure Gas expansion factor, Bg **Reservoir conditions defined as 130°C/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 @ 1 350 m TVD RKB, 13 3/8’’ intermediate csg set @ 2380 m TVD RKB and 9 ⅝”’ 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 ½’’

Figure 3 shows an illustration of the planned well.

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Alve North Well Diagram MD TVD CASING / LITHOLOGY/ RKB m SS m EXPECTED PORE PRESS Rotary Table 39 Sea bed 403 364

Formations

Hole Size

Casing and Cement Data Aquisition

36" x 42'' 36" x 30'' Conductor Pipe Class G 1.54sg Turned light XL

Conductor Point

475

Mud

Seawater with high vis sweeps 1.03sg

436 26''

Nordland

520

481

Casing Point

1350

1311

Kai

1420

1381

20" Casing, X56, 133# Class G Lead 1.3 sg, tail 1.5 sg

17-1/2"

13 3/8'' Casing, P-110, 72# VT

FIT ~ 1.75

Hordaland

1699

1660  

Rogaland

1919

1880  

Springar

1996

1957

Tech Casing Point

2380

2341

Seawater with high vis sweeps 1.03 sg

WBM 1.45-1.55 sg

Class G Lead 1.3 sg, tail 1.5 sg

12-1/4"

10-3/4" VM110, 65.7# VT 9 5/8" VM110, 53.5# VT

OBM 1.45-1.55 sg

Class G 1.9sg

Lysing

2832

2793

BCU

3274

3235

Prod Casing Point Garn + Not

3450 3606

3411 3540

Kick off point 

OBM 1.40 SG

8-1/2" Ile +Upper Ror

3665

3589

Tofte + Lower Ror

3748

3660

Tilje Åre TD

3790 3908 4031

3695 3795 3900

FIT ~ 1.85

One Core in reservoir  Possibly 3 mini-DST’s Log reservoirs guaranteed  A 7" Liner may be run for future completion

Figure 3: Illustrative well schematics for the 5505/5-5 NewField North exploration well [ Error! Reference source not found.]

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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 in this 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 been used in the calculations. 500 Total IPR Garn/Not Ile/Tilje

450 400    e    r 350    u    s    s    e    r 300    p    e    r    ]    o   a    r     b   a 250     l     l     b    e    [    w 200    g    n    i    w    o 150     l    F

100 50 0 0

5000

10000

15000

20000

25000

30000

35000

40000

Gas Rate [1000 Sm³/day/bar]

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 MSm³/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.

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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. 500 Garn+Not - 50 mD

450

Garn+Not - 100 mD

400

Garn+Not - 200 mD

   e    r    u 350    s    s    e    r    p 300    e    ]    r    a    o   r     b     l    a 250     l    e    b     [    w 200    g    n    i    w 150    o     l    F

100 50 0 0

5000

10000

15000

20000

25000

30000

35000

40000

Gas Rate [1000 Sm³/day/bar]

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 used in the blowout evaluations in this report. IPR curves applicable for the Res-2 formations are shown in Figure 6. 500 Ile+Tilje - 1 mD

450

Ile+Tilje - 3 mD

400

Ile+Tilje - 5 mD

   e    r    u 350    s    s    e    r    p 300    e    r    ]    a    o   r     b     l    a 250     l     b    e    [    w 200    g    n    i    w 150    o     l    F

100 50 0 0

500

1000

1500

2000

2500

3000

Gas Rate [1000 Sm³/day/bar]

Figure 6: IPR curves – Res-2 – Permeability sensitivity

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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 ⅝” casing all the way from formation to surface. For the NewField North exploration well, an unrestricted blowout through the 9 ⅝” 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 MSm 3/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. Revision: 0

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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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Sealevel

Sealevel

Sealevel

Drilling BOP

Drilling BOP

Drilling BOP

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.

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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 based upon 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 of  barrier 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. Distribution - Floaters

Data update: January 2009

Drilling (22 incidents)

Completion (4.4 incidents)

Workover (7.4 incidents)

Subsea Full

Restricted

Outside casing

22.70 %

4.50 %

Outer annulus

18.20 %

4.50 %

Annulus

31.80 %

Topside Full

Restricted 

4.50 %

4.50 %

Open hole

4.50 %

Inside drillstring Inside test tubing

4.50 %

Annulus

4.50 %

Inside drillstring Inside prod tubing Outer annulus Annulus

4.50 %

40.90 % 4.50 %

45.50 %

27.00 % 27.00 %

Inside drillstring

24.30 %

Inside prod tubing

16.20 %

5.40 %

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 Revision: 0

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properties, lack of operational fluid control or swabbing of reservoir fluids from “pulling out  of hole” activities 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 from these 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 formation’s 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 Blowout initiated when the formation is fully penetrated

60 % 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, are given the following values:   

Blowout through drill pipe has a probability of Blowout through annulus has a probability of Blowout through open hole to surface has a probability of

25 % 75 % 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 No restriction has a probability of

70 % 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: Termination of work, sail to location, anchoring and preparation : Drilling relief well to intersection: Homing in: Total time to kill well:

    

3 days 12 days 45 days 10 days 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.

100% Wells still flowing after subsea attempts

90%

Wells still flowing after topside attempts 80%

Wells still flowing after natural bridging

70%    e    g    a    t    n    e    c    r    e    P

60% 50% 40% 30% 20% 10% 0% 0

5

10

15

20

25

30

35

40

45

50

Days

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. Revision: 0

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Table 4: Risk criteria in duration distribution. Risk of a blowout duration of 2 days

P2

Risk of a blowout duration of 15 days

P 15

Risk of a blowout duration of 70 days

P 70

The blowout could be controlled by measures performed from the existing rig The blowout could be controlled by bringing in additional equipment The blowout will have to be killed by drilling a dedicated relief well.

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.

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. 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. Note:

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

High

Res-1 Res-2 Probability

50 mD 1 mD 50%

100 mD 3 mD 30%

200 mD 5 mD 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 exposure

OH

5m

DP

5m

ANN

5m

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Subsea Surface Subsea Surface Subsea Surface

50 mD [Sm³/d] 635 647 475 463 571 576

Date: 03-12-2010

Unrestricted Flowpath 100 mD 200 mD Risked [Sm³/d] [Sm³/d] [Sm³/d] 1232 2156 1118 1243 2172 1131 655 788 592 626 745 568 926 1255 814 933 1261 820

OH

5m

DP

5m

ANN

5m

Subsea Surface Subsea Surface Subsea Surface

50 mD Sm³/d] 424 423 373 363 404 403

Restricted Flowpath 100 mD 200 mD [Sm³/d] [Sm³/d] 543 621 540 616 461 518 447 500 511 582 508 577

Well blowout and dynamic wellkill simulation – 5505/5-5 – NewField North

Risked [Sm³/d] 499 497 428 415 472 469

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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 distribution Res-1+Not / Ile+Tilje Probability

Low

Medium

High

50/1 mD 50%

100/3 mD 30%

200/5 mD 20%

Table 8: Permeability risking – Swab scenario – Full reservoir exposure

OH

Full

DP

Full

ANN

Full

3.5.2

Subsea Surface Subsea Surface Subsea Surface

50/1 D Sm³/d] 2562 2630 847 799 1406 1411

Unrestricted Flowpath 100/3 mD 200/5 mD [Sm³/d] [Sm³/d] 3570 4420 3649 4445 905 936 850 877 1597 1708 1601 1712

Risked [Sm³/d] 3236 3299 882 830 1523 1528

OH

Full

DP

Full

ANN

Full

Subsea Surface Subsea Surface Subsea Surface

50/1 D [Sm³/d] 651 653 544 525 613 609

Restricted Flowpath 100/3mD 200/5 D [Sm³/d] [Sm³/d] 681 696 679 691 564 574 545 555 641 655 634 647

Risked [Sm³/d] 669 668 556 537 630 624

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 any surface 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.

Step 1

Step 2

Formation

Step 3

Penetration

Flowpath

0%

60%

Kick - 5m

75%

Garn+Not 25%

9 5/8" Csg

17%

40%

Garn+Not Ile+Tilje

BOP Status

Drill pipe

9 5/8" Csg

Step 8 Risked Gas

Total Risk

potential

blowout rate

blowout rate

[%]

[Sm³/day]

[Sm³/day]

[MSm³/day]

0.00 %

1131

0

0.00

70%

0.00 %

497

0

0.00

30%

Open

13.50 %

820

111

0.44

70%

Restricted

31.50 %

469

148

0.59

30%

Open

4.50 %

568

26

0.10

70%

Restricted

10.50 %

415

44

0.17

30%

Open

2.04 %

3299

67

0.27

Restricted

4.76 %

668

32

0.13

Open

7.44 %

1528

114

0.45

Restricted

17.36 %

624

108

0.43

45%

Open

2.52 %

830

21

0.08

70%

Restricted

5.88 %

537

32

0.13

70%

70%

21%

Step 7 Risked oil

Open

Annulus Drill pipe

Step 6 Oil blowout

Restricted

30%

62%

Step 5

30%

Annulus

Yes

Swab - Full

Step 4

100.00 %

701 Sm³/day 

2.80 MSm³/day 

Figure 9: NewField North  – Illustrative risk process for the s urface release case.

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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 Step 2

Step 3

Scenario Prob. %

Flowpath

Status

Prob. %

0%

Kick - 5m 60 %

40 %

Garn+Not  Ile+Tilje

BOP Status Status

Step 5

Step 6

Step 7

Step 8

Total Risk

Oil blowout potential

Risked Oil blowout rate

Risked Gas blowout rate

[%]

[Sm³/d ay]

[Sm³/day]

Durationdistribution

[Mm³/day]

P2 t < 2 days [%]

P15 t < 15 days [%]

P70 t