mungo case study: unlocking the late-life field ... · unlocking the late-life field development...

Mungo Case Study:Unlocking the late-life field development with HDOBC seismic

Mark WilliamsDEVEX, Thursday 10th May, 2012

Mungo: Outline

• Introduction to the Mungo field

− Location within N.Sea

− Structure & Stratigraphy

− Overview Field History

• Mungo Imaging Progression

− Legacy datasets

− HDOBC justification

• Early HDOBC insights

− Effects on Static picture

− Dynamic influence

− New Opportunities

• Principal conclusions and Mungo’s immediate future

− Implications for Phase III

2

3

Top Structure (mtvdss)

Mungo:Field Introduction

• Equity: 69% BP, 13.6% Murphy, 12.4% Total, 5% JX NEPUK.

• Located in the East Central Graben of the Central North Sea, 143miles east of Aberdeen in 88m water depth.

• Discovered in 1989 by well 23/16a-3. On production since 1998.

• Development facilities consist of a Normally Unattended Installation (NUI) tied back 22km to ETAP Central Processing Facility.

• 13 producers

• 3 water injectors

• 1 gas injector (offline)

• Current development strategy:

− maximise oil production by maintaining pressure support from water injection with a future blow-down phase.

Mungo:Structure: ‘Ben’ Mungo

Top of reservoirto OWC

~ 1100m

Top Forties depth viewed from the SW

GOC 1680m tvdss

OWC 2640m tvdss

1000

1500

2000

2500

1000

1500

2000

2500

Mungo

SW NE

Metres Metres

GOC1680m

OWC2640m

DrillingProblems

Chalk

Paleocene

18 / ”58

13 / ”38

13 / ”38

173164

163160

177

160

162

172

169

163

161165

170168

174

171

176175

• Salt Diapir structure – draped Palaeocene sandstones overlying Cretaceous Chalk reservoir.

• Extensive oil column, ~965mtvd with a small gas cap.

• Reservoir dips ~40-650 (reaching 850 in SW)

• STOIIP ~420mmstb

• GIIP ~40bscf, solution 480bscf

• 39.30 API

• Structurally & stratigraphically complex

SW

Mungo Oil Column965m (tvd)

4

Top Forties Depth Map with fault traces

Mungo: Outline






− Legacy datasets








5

Mungo: HDOBCSeismic Roadmap

1991 ETAP 3DMungo Baseline

2005 4D

First Oil

2011 HDOBC processing (Full-

field)

2010 HDOBC

‘98 ‘99 ‘00 ‘01 ‘02 ‘03 ‘04 ‘05 ‘06 ‘07 ‘08 ‘09 ‘10 ‘12‘11

2011 HDOBC

2001 4D

1997 3D PreSTM+PoSDMprocessing

2002/3 3D PreSDM (Isotropic) processing1992 3D PoSDM

processing6

2010 HDOBC processing (East)2006 3D PreSDM (TTI)

processing

2007-8-9 spec 3D

2010 3D PreSDM (TTI) processing2006 4D PreSDM (TTI)

processing

2005 4D PreSDM (VTI) processing

2001 4D PreSTM+PoSDM

processing

‘91

Datasets used in pending seismic succession

Mungo: HDOBCHDOBC Justification

• Business justification

− Multi-well proposal for future Field Infill campaign (Phase III), 1st well scheduled for 2014).

− Maximise remaining field infill campaign, both Palaeocene reservoir & Chalk development.

− De-risk current Phase III infill targets and address any future potential.

− Realise up to ~30mmboe of resources; (10-20mmbbls Palaeocene in East, with circa. 10mmboe combined Palaeocene & Chalk in the West).

• Technical justification

− Improve the static image for optimum well placement.

− identify, quantify, prioritise and reduce uncertainty around infill drilling targets proposed for Phase III.

− better internal reservoir definition allowing identification of stratigraphic compartments and sand packages.

− inform potential options post Phase III.

− help characterise the chalk reservoir potential?

Palaeocene Potential

Mobile Oil HeightRemaining at 2023

E2 (165)2mmboe

W4(167)0-3mmboe

NE3,NE1 (165)2-4mmboe

SW1 (169)0-3mmboe

S1, SE1 (171)2-4mmboe

SE3

E1(168)2mmboe

N1(161)1mmboe

SE1 (174)0-2mmboe

Accel (174)2-4mmboe

HM Model (H5/33/173)With Phase 2 (W3,NW1,W1)

Mobile Oil Height(m)(So > 0.25)

W5(167)0-3mmboe

Mobile Oil HeightRemaining at 2023

E2 (165)2mmboe

W4(167)0-3mmboe

NE3,NE1 (165)2-4mmboe

SW1 (169)0-3mmboe

S1, SE1 (171)2-4mmboe

SE3

E1(168)2mmboe

N1(161)1mmboe

SE1 (174)0-2mmboe

Accel (174)2-4mmboe

HM Model (H5/33/173)With Phase 2 (W3,NW1,W1)



W5(167)0-3mmboe

7

Mungo: HDOBCHDOBC Justification

• HDOBC justification over Towed Streamer

− Acquisition uplift:

− Improved Signal to Noise ratio - sensors on seabed (quieter environment and stationary).

− Multi-azimuth illumination of 360deg structures for full wavefieldimaging.

− High fold with diversity of raypaths through subsurface.

− Allows detection of shear C-waves.

− Dominance of far offsets.

− Enhanced Low frequency signal.

− Ease of acquisition and survey repeatability.

− Processing improvements:

− Noise attenuation (denoise P&Z components independently, attenuation of backscatter noise).

− Demultiple via PZ summation.

− Improved Velocity modelling via Full Waveform Inversion -> better shallow model.

− Azimuthal diversity to optimise illumination.

N

0m 10000m5000m

1cm. = 1000 meters

6354000

6355000

6356000

6357000

6358000

6359000

6360000

6361000

6362000

6363000

6364000

6365000

6366000

6367000

43

20

00

43

30

00

43

40

00

43

50

00

43

60

00

43

70

00

43

80

00

43

90

00

44

00

00

44

10

00

44

20

00

44

30

00

44

40

00

44

50

00

44

60

00

44

70

00

44

80

00

22/20-322/20-3Z

22/20-5

22/20-6

23/16A-3

23/16A-4

23/16A-523/16A-5Y23/16A-5ZA01(W160)

A02(W162)

A03A03Z(W163)

A04(W165)

A05(W161)A06A06Z(W167)

WA07(W164)A08(W168)

A09

WA09Z(W169)

A10(W171)

A11(W170)

A12(W174)

A13(W173)WA15(W172)

WA16(W175)

A17A17Y(W176)A17Z

HRZ:(1285.71,3214.34) TSELE_TTI2_TWT_DEPTHTTI2

Top Sele Depth contours

N

0m 10000m5000m

1cm. = 1000 meters

6354000

6355000

6356000

6357000

6358000

6359000

6360000

6361000

6362000

6363000

6364000

6365000

6366000

6367000

43

20

00

43

30

00

43

40

00

43

50

00

43

60

00

43

70

00

43

80

00

43

90

00

44

00

00

44

10

00

44

20

00

44

30

00

44

40

00

44

50

00

44

60

00

44

70

00

44

80

00

22/20-322/20-3Z

22/20-5

22/20-6

23/16A-3

23/16A-4

23/16A-523/16A-5Y23/16A-5ZA01(W160)

A02(W162)

A03A03Z(W163)

A04(W165)

A05(W161)A06A06Z(W167)

WA07(W164)A08(W168)

A09

WA09Z(W169)

A10(W171)

A11(W170)

A12(W174)

A13(W173)WA15(W172)

WA16(W175)

A17A17Y(W176)A17Z

HRZ:(1285.71,3214.34) TSELE_TTI2_TWT_DEPTHTTI2

Top Sele Depth contours

HDOBC Survey Design

8

Mungo: HDOBC Acquisition Design

10 km

15 km

Sho

ts

Rec

eive

rs

0m 10000m5000m

1cm. = 1000 meters

5 km

Fiel

dO

utlin

e

Almost 75% of the field covered with 3

patches and 100% of the field covered with

4 patches (Two 6x10km patches and Two 7x8km patches).

Patch of 6 x 10km cablesspaced 400m

10km

2.4km

Patch of 7 cablesspaced 400m

8km

2.8kmMungo West:

Further ~50% coverage with 2

additional patches in the West providing

100% of field covered.

Mungo East acquisition:

~39sqkm HDOBC

~50% field coverage with 2 patches (1x

6x10km patch and 1x 7x8km patch) plus 1x 400m outboard cable

East acquired in 2010West acquired in 2011

• 50m receiver spacing• 400m receiver cable spacing • 50m x 50m source, dual source, flip-flop. • 3km shot offsets– limited to 7500m radius.• Acquired by RXT

• 25m receiver spacing• 400m receiver line spacing• 50m x 50m shot spacing.• Acquired by WesternGeco.

9

Mungo: Data succession1991 Towed Streamer

1991 TS acquisition, 2006 PreSDM reprocessing

W162 (A02)

A06 (W167)

W164 (A07)

W175 (A16)

W160 (A01)

W169 (A19)

W166 (A18)

20-5

A03z (W163)

20-3

20-3z

W161 (A05Z)

W170 (A11)

W165 (A04)

W176 (A17Y)

W168 (A08)

W174 (A12)

W171 (A10)

A09z (W169)

W172 (A15)

EWT 20-6

16A-3

16A-5z

16A-5

16A-5Y

W173 (A13)

W167 (A06X)

16A-4

Mungo Top Forties Depth map

W162 (A02)

A06 (W167)

W164 (A07)

W175 (A16)

W160 (A01)

W169 (A19)

W166 (A18)

20-5

A03z (W163)

20-3

20-3z

W161 (A05Z)

W170 (A11)

W165 (A04)

W176 (A17Y)

W168 (A08)

W174 (A12)

W171 (A10)

A09z (W169)

W172 (A15)

EWT 20-6

16A-3

16A-5z

16A-5

16A-5Y

W173 (A13)

W167 (A06X)

16A-4


Section view

Top Ekofisk

Top Sele

Top Ekofisk

Top Sele

10

Mungo: Data succession2001 Towed Streamer

11

W162 (A02)

A06 (W167)

W164 (A07)

W175 (A16)

W160 (A01)

W169 (A19)

W166 (A18)

20-5

A03z (W163)

20-3

20-3z

W161 (A05Z)

W170 (A11)

W165 (A04)

W176 (A17Y)

W168 (A08)

W174 (A12)

W171 (A10)

A09z (W169)

W172 (A15)

EWT 20-6

16A-3

16A-5z

16A-5

16A-5Y

W173 (A13)

W167 (A06X)

16A-4


W162 (A02)

A06 (W167)

W164 (A07)

W175 (A16)

W160 (A01)

W169 (A19)

W166 (A18)

20-5

A03z (W163)

20-3

20-3z

W161 (A05Z)

W170 (A11)

W165 (A04)

W176 (A17Y)

W168 (A08)

W174 (A12)

W171 (A10)

A09z (W169)

W172 (A15)

EWT 20-6

16A-3

16A-5z

16A-5

16A-5Y

W173 (A13)

W167 (A06X)

16A-4


Section view

2001 TS acquisition, 2006 PreSDM reprocessing

Top Ekofisk

Top Sele

Top Ekofisk

Top Sele

Mungo: Data succession HDOBC (Alpha) dataset

2011 HDOBC acquisition, 2011/12 Alpha processing

W162 (A02)

A06 (W167)

W164 (A07)

W175 (A16)

W160 (A01)

W169 (A19)

W166 (A18)

20-5

A03z (W163)

20-3

20-3z

W161 (A05Z)

W170 (A11)

W165 (A04)

W176 (A17Y)

W168 (A08)

W174 (A12)

W171 (A10)

A09z (W169)

W172 (A15)

EWT 20-6

16A-3

16A-5z

16A-5

16A-5Y

W173 (A13)

W167 (A06X)

16A-4


W162 (A02)

A06 (W167)

W164 (A07)

W175 (A16)

W160 (A01)

W169 (A19)

W166 (A18)

20-5

A03z (W163)

20-3

20-3z

W161 (A05Z)

W170 (A11)

W165 (A04)

W176 (A17Y)

W168 (A08)

W174 (A12)

W171 (A10)

A09z (W169)

W172 (A15)

EWT 20-6

16A-3

16A-5z

16A-5

16A-5Y

W173 (A13)

W167 (A06X)

16A-4


Section view

Top Ekofisk

Top Sele

Top Ekofisk

Top Sele

12

13

Mungo HDOBC vs. Towed StreamerRaw migration stack (Depth) comparison

Raw HDOBC (Alpha West) StackRaw TS (MMM) Stack

Top Sele

Top Ekofisk

Top Sele

Top Ekofisk

1. Higher resolution in overburden due to higher fold, improved S:N)

SaltSalt

GOC 1680m

OWC 2640m

W162 (A02)

A06 (W167)

W164 (A07)

W175 (A16)

W160 (A01)

W169 (A19)

W166 (A18)

20-5

A03z (W163)

20-3

20-3z

W161 (A05Z)

W170 (A11)

W165 (A04)

W176 (A17Y)

W168 (A08)

W174 (A12)

W171 (A10)

A09z (W169)

W172 (A15)

EWT 20-6

16A-3

16A-5z

16A-5

16A-5Y

W173 (A13)

W167 (A06X)

16A-4


W162 (A02)

A06 (W167)

W164 (A07)

W175 (A16)

W160 (A01)

W169 (A19)

W166 (A18)

20-5

A03z (W163)

20-3

20-3z

W161 (A05Z)

W170 (A11)

W165 (A04)

W176 (A17Y)

W168 (A08)

W174 (A12)

W171 (A10)

A09z (W169)

W172 (A15)

EWT 20-6

16A-3

16A-5z

16A-5

16A-5Y

W173 (A13)

W167 (A06X)

16A-4


Section view

2. Improved imaging and better continuity of the reflectors, especially on the flank of the diapirstructure, data being richer in low frequencies and illuminated better with rich azimuthalcontent.

3. Inherent demultipleadvantages during PZ summation of HDOBC superior to TS which requires post-migration demultiple

4. Broadband nature of HDOBC datasets will allow enhancement of high frequencies to maximise internal architecture of reservoir interval.

Mungo: Outline






− Legacy datasets








14

Mungo: HDOBC InsightsEarly structural highlights

Top Sele Coherency extraction (80ms) generated from Alpha MG data

Interpretation synopsis: Current interpretation based upon the West Alpha products

Red lines denote 2010 VIP faults major (solid) minor (dashed)

Additional undrainedterrace in Panel 12??

Existence of internal baffle to support dynamic connection between W175 (Inj) and W171 (prod)

Panel 9&10

Panel 12

15

Mungo: HDOBC InsightsReservoir Management : Assisting the dynamic history

16

• Reconciling the dynamic performance between Injector W175 and producer W171 situated in Panels 9 & 10.

• Producers W160 and W171 drilled in 2000 into in southern areas of field. Injector W175 drilled in 2005 to support both producers.

• Post W175, W171 displayed minimal pressure support whilst W160 demonstrated elevated pressure -> direct connectivity.

• A baffle between W175 and W171 was inferred although no features were evident from previous seismic datasets.

• HDOBC coherency extraction illustrates a clear lineation (radialfault) located between the two wellbores which corroborates the dynamic behaviour.

• Potential future injector to support W171?

Panel 9&10

Top Sele coherency (40ms windowed extraction)

W171W175

0

500

1000

1500

2000

2500

3000

3500

4000

4500

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Res

ervo

ir Pr

essu

re p

sia

W160W171

W160 Injection support trend

W171 Depletion trend

W175 Injection start-up

0

500

1000

1500

2000

2500

3000

3500

4000

4500

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Res

ervo

ir Pr

essu

re p

sia

W160W171



0

500

1000

1500

2000

2500

3000

3500

4000

4500

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Res

ervo

ir Pr

essu

re p

sia

W160W171





W175 Injection start-up

W160 expressed increase in pressure support post W175, W171 sustained much lower support and maintains on depletion trend.

Both wells show initial Pressure decline prior to W175.

W160


170

1000

2000

3000

4000

5000

6000

Mar-09 Jul-09 Oct-09 Jan-10 May-10 Aug-10 Nov-10 Feb-11 Jun-11 Sep-110

0.2

0.4

0.6

0.8

1

Alloc. Oil Rate - W161 Test Oil Rate - W166 Alloc GOR - W161Test GOR - W166 Alloc Watercut - W161 Water Cut - W166

W166

Mungo: HDOBC InsightsInfill Targets: Untapped resources in Panel 12?

• W166 producer, a single off-take point is situated in Panel 12.

• Producer W166 drilled in 2009 into undrilled area in north of field. MDT pressures ~-600psi indicate partially isolated communication to remainder of field.

• Well displayed rapid early Pressure decline, rate now reduced; mild decline with ~20%wcut -> aquifer influx.

• Mapped STOIIP ~28mmbbls, Material Balance suggests contacted oil volume of 6.66mmstb -> remaining resource.

• Well drilled deep on structure, near to the OWC with potential for up-dip resource and/or adjacent fault block.

• HDOBC coherency extraction illustrates baffle adjacent to W166 which may isolate the area and delineate a potentially undrained fault block.

Panel 12

Top Sele coherency (40ms windowed extraction)

Wcut has risen steadily to ~20%

Rapid initial Pressure decline

• Well currently Shut-in due to integrity loss.

• Potential future sidetrack location?

W166

A06


Mungo: Outline






− Legacy datasets








18

Mungo: HDOBC InsightsPreliminary conclusions

19

2010 HDOBC (East) Depth

High Fold, greater S:N -> better resolution combined with multi-azimuthal illumination gives a significant uplift in seismic image.

NB- this isn’t the final result!

Sharper character and better continuity of reflectors

Less noise and dominance of low Frequencies

• What has the uplift been?− Early indications are encouraging, observing some early uplift above

the conventional Towed Streamer datasets.

− Imaging:

− Clear uplift in image quality, higher S:N , higher fold and illumination with rich azimuthal content, less multiple -> better continuity of reservoir defining reflectors.

− Structure:

− Much improved image of the diapir, particularly on the steeply-dipping flanks. Reservoir envelope surfaces (Top & Base) are readily mapped (albeit poorer quality in SW).

− Internal architecture still remains a challenge -> function of thinning wedge, heterogeneity of individual reservoir packages and strong impedance contrasts of the Top & Base events.

− Salt body better imaged, particularly the canopy which control the up-dip pinch-out of the reservoirs. Extent of the events into the gas cap & thereby connectivity have always been uncertain.

− Dynamic reconciliation:

− Intriguing early observations that help reconcile both field & well performance. Assisting a fully integrated static and dynamic understanding.

Mungo: HDOBC InsightsWay Forward

Date: 10.05.12

Aug-12 Sep-122010 2011 2012

Nov-10 Dec-10 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Jul-12Mar-12 Apr-12 May-12 Jun-12

8.5mths

10mths12mths

8mths10mths

12mths

Mungo East product delivery

Mungo West Alpha delivery*

• assuming learning’s from Mungo East survey, plus double data volume.

4-5mthsFast track

Initial MGRaw MG

Final MG

Mungo West Beta delivery*

Raw

MG

: 3rd

May

Fina

l MG

: 6th

Jul

AVO

: 12t

hJu

l

Date: 10.05.12

Aug-12 Sep-122010 2011 2012


8.5mths

10mths12mths

8mths10mths

12mths




4-5mthsFast track

Initial MGRaw MG

Final MG


Raw

MG

: 3rd

May

Fina

l MG

: 6th

Jul

AVO

: 12t

hJu

l

Aug-12 Sep-122010 2011 2012


8.5mths

10mths12mths

8mths10mths

12mths




4-5mthsFast track

Initial MGRaw MG

Final MG


Raw

MG

: 3rd

May

Fina

l MG

: 6th

Jul

AVO

: 12t

hJu

l

20

• What’s next?− Final East & Alpha products evaluated so far.

− Raw Beta dataset due imminently, (Final Beta datasets due in July 2012).

− Static description & Phase III target selection will continue on the Alpha products in the interim to improve the integrated understanding.

− Static & Dynamic workflows has been built with this succession of datasets in mind, i.e. iterative and for quick static model refinement.

− Rank options and quantify uncertainty prior to final option selection.

− Detailed well planning (fault placement and final target selection) will utilise the Beta Final datasets upon delivery.

− Phase III infill drilling campaign potentially commencing 2014.

• Future?− Yet to quantify the final uplift of HDOBC over TS on

Mungo diapir, although early results look promising.

− Understanding of such a structurally complex field has certainly been enhanced by the step change in HDOBC technology.

− HDOBC subsequently acquired over Machar field in 2011.

− Potentially a future 4D HDOBC?

CGGV Alpha & Beta processing timeline – A succession of datasets

Mungo: HDOBC InsightsAcknowledgements

• Mungo Partnership: Murphy Oil, TOTAL & JX NEPUK.

• Co-author Steve Campbell & BP Seismic Delivery Team (SDT)

• Seismic Processors: CGGV

• ETAP Mungo Reservoir Team:

− Mary Ward, Alison Davies, Dave O’Gorman, Richard Pollard also Leendert Padmos and Marie O’Hanlon.

21

mungo case study: unlocking the late-life field ... · unlocking the late-life field development...

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