case study: establishing, predicting and modelling the...

$: Case study: Establishing, predicting and modelling the ...38559b81a8bdc9f7a43e-61cdd80dc1a7a416127c70ccd69fa98c.r12.cf1... · Case study: Lancaster development – making fractured$
Basement Reservoir Specialists

Case study:

Lancaster development –

making fractured basement

reserves viable

November 2017

Establishing, predicting and modelling the hydrodynamic fracture network of basement reservoirs during the exploration and early appraisal phase:

A case study from the

West of Shetland

Finding Petroleum Understanding Fractured Reservoirs & Rock January 23rd

Hurricane | Dubai Site Visit | December 2017 2

Presentation

1 The Lancaster reservoir

2 Relative magnitude of fluid pressure and lithostatic pressure

3 Magnitude and orientation of mean stress gradient

4 Fracture connectivity

5 Horizontal well results

6 Planned data acquisition

7 QA


Presentation







7 QA


0 10 20 30 40 50 km

Typhoon

Schiehallion

Foinaven

Shetland

Strathmore

Shetland Islands

Orkney Islands

SCOTLAND

Isle of Lewis

Isle of Skye

Aberdeen

Solan

Clair

410000 420000 430000 440000 450000 460000 470000 480000

6650000

6660000

6670000

6680000

6690000

6700000

410000 420000 430000 440000 450000 460000 470000 480000X/Y:

Meters

6650000

6660000

6670000

6680000

6690000

6700000

Warwick

Whirlwind

Lancaster

Halifax

Lincoln

Hurricane licences

Rona Ridge basement play

HEX-COR-BDV-PRS-0001-0 16


Lancaster well schematic prior to the 7Z well

205/21a-6

205/21a-4 205/21a-4Z

205/21-1A

P1

36

8 B

lock B

ou

nd

ary

Max ESP rate 9,800 stb/d 205/21a-6 (2014)

Mobile oil swabbed 205/21a-4 1,597m TVDSS

597m TVT (2017 CPR 1C OWC)


Oil Column Heights


205/21a-7

Wireline oil samples 205/21a-7 Deepest at 1,669m TVDSS

Hurricane | Dubai Site Visit | December 2017

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Exploration well 205/21a-4

Appraisal well 205/21a-4Z

Development well 205/21a-6

Top hole location Top basement penetration

205/21a-7Z (2016) Horizontal Well

•Hurricane’s second horizontal well planned as a producer

•Average well porosity expected to be :

- between 3.6% – 4.4 %

•Objective to repeat success of the 205/21a-6 horizontal well (2014) :

PI of 160 stb/psi

Maximum flow rate of 9,800 stb/d

Shell well 205/21-1A

Development well 205/21a-7Z

Appraisal well 205/21a-7


The case study - what did we need to know? •Confident that the reservoir would have similar performance to that previously

experienced

•Confidence that we understood what was making the reservoir work

•Key controls on fluid flow in Type 1 fractured reservoirs

– Relative magnitude of fluid pressure and lithostatic pressure

– Magnitude and orientation of mean stress gradient

– Connectivity of the fracture network


Presentation







7 QA


Lancaster - normally pressured environment

•All wells planned and drilled assuming a normal hydrostatic gradient

•No evidence of “over pressure” in either the basement or overlying clastic successions

•4Z drilled on balance

•Primary drive mechanism is therefore :

–Expansion of reservoir fluids

–Expansion of the aquifer


Presentation







7 QA


Limited borehole indicators 205/21a-7


Stress ratio = (2- 3)/(1- 3)

All fracture sets

H orientation

Stress ratio = (2- 3)/(1- 3) Stress ratio = (2- 3)/(1- 3)

Normal Strike-slip Reverse Normal Strike-slip Reverse Normal Strike-slip Reverse

Stress ratio = (2- 3)/(1- 3)

Regional Joints Cross Cutting Joints Large Open Fractures

Cost maps showing the predicted maximum horizontal stress orientation and structural regime. The top image shows all fracture run together, and the bottom three show the results split into joint types. The ~45 stress orientation of the regional joints corresponds to Hurricane’s understanding that SHMax is orientated to the northeast.

Stress Regime


•Limited core measurements and sonic waveform analysis indicate that preferential production is not associated with critically stressed or shear fractures

• Geophysical mapping and structural modelling indicate that the most likely model to constrain the current stress regime is a north easterly maximum horizontal stress resulting in a pervasive open (dilationary) joint system

• Ongoing work program to challenge this model and to develop a structural/stress model for the surrounding basement prospectivity

Stress Regime – working model


Presentation







7 QA


Fracture characteristics at different scales

Note: [x]

Core plug

Borehole

Dynamic well test 3D seismic survey

0 250 500 750 1,000 m

Microfractures

Joints Faults


1. 2009. Manual picking of high confidence faults for placement of initial exploration well

2. 2010. Post-drill. Lower confidence coherency faults confirmed by 205/21a-4. Combination of manual and FaultX coherency picked faults

3. 2014. Horizontal well confirms Ant Tracking results. Manual picking, FaultX coherency and Ant Tracking all combined

Fault map evolution

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1. 2. 3.


Ant Tracking matched to Wells •Ant Tracking extracted at top basement

surface correlates well with log-interpreted Fault Zones

• Indication that faults are generally vertical or near vertical

•Good confidence that Ant Tracking response is representing faulting

•Note that the Ant Tracking gives no indication of width of Fault Zones

Overburden Victory Fractured Basement Fault Zone Jurassic sand


Example of a single joint picked from electrical and acoustic image logs

Joints


205/21a-6 Joint Analysis by Facies Fractured Basement

Regional Joints Cross Joints >60° Cross Joints >20°,<60° Cross Joints <20° Large Aperture Joints

Mean dip/strike: 76⁰ NESW Mean dip/strike: 74.5⁰ EW and a

secondary trend NS Mean dip/strike: 47.9⁰ NESW

Mean dip/strike: 14.7⁰ NESW and a minor trend NWSE

Mean dip/strike: 61.9⁰ NESW

Fault Zones

Regional Joints Cross Joints >60° Cross Joints >20°,<60° Cross Joints <20° Large Aperture Joints

Mean dip/strike: 75.5⁰ NESW Mean dip/strike: 73.6⁰ EW and a secondary trend NNW/SSE

Mean dip/strike: 48.2⁰ NESW Mean dip/strike: 15⁰ NESW, NS and EW

Mean dip/strike: 66.5⁰ NESW


• Separation between the deep and shallow resistivity curves indicates invasion and demonstrates the reservoir is permeable

• NMR and density neutron porosity logs show clear responses to fractures

• High-resolution Platform Express density and resistivity illustrate how the standard resolution curves relate to the highest resolution image data

Sequential log analysis corroborates permeability


205/21a-4Z formation evaluation

•Comprehensive, high-quality log suite (LWD and wireline) acquired

• Integrated with well test and PLT data

70

m

11

0 m


Large Aperture Fracture Example (205/21a-4Z)

PLT


Picking SWC locations


Microfractures “captured” by sidewall core


Microfracture Porosity

Relics of calcite occlude vuggy/channel porosity. The porosity is readily interpreted as secondary porosity created by extensive dissolution of the calcite. Sidewall core porosity estimated to 4.1%.


Final PBU derivative match

205/21a-6 pressure build up analysis


DFN modelling

•History and PLT matched DFN models require there to be a hydrodynamically effective:

–A) fault network

–B) regional joint system

•No match achieved using regional joints in isolation and or faults in isolation


Conceptual reservoir model

Fractured Basement The intervening host rock is pervasively fractured and also contributes to fluid flow

Fault Zones Represent pervasively fractured volumes of rock that include preferentially enhanced aperture fractures and therefore improved reservoir characteristics. Fault Zones are associated with seismically-resolvable faults

Micro fractures and joints are present throughout the Fractured Basement and Fault Zones


Presentation







7 QA


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Exploration well 205/21a-4

Appraisal well 205/21a-4Z

Development well 205/21a-6

Top hole location Top basement penetration

205/21a-7Z (2016) Horizontal Well

•7Z Expected to encounter:

eleven fault zones

ne-sw striking permeable regional joints

Produce at rates similar or greater rates than 205/21a-6

PI of 160 stb/psi and maximum flow rate of 9,800 stb/d

Shell well 205/21-1A

Development well 205/21a-7Z

Appraisal well 205/21a-7


Seismic section through 205/21a-7Z

Top Victory

Top Kyrre

Top Basement

205/21a-7 NW SE 205/21a-7Z

ll

Well Facies Bateman Konen

Porosity (%)

Well Facies Bateman Konen

Porosity (%)

205/21a-4 FZ1 2.3 205/21a-7 FZ1 8.4

FB1 3.1 FB1 2.8

FZ2 7.2 FZ2 3.4

FB2 2.8 FB2 2.2

FZ3 4.4 FZ3 3.1

FB3 3.2 FB3 1.9

FZ4 4.1 All 3.6

All 3.9 205/21a-7Z FB1 4.0

205/21a-4Z FB1 6.7 FZ1 6.2

FZ1 3.4 FB2 2.6

FB2 4.8 FZ2 3.6

FZ2 4.4 FB3 3.0

All 4.4 FZ3 5.0

205/21a-6 FB1 3.7 FB4 2.6

FZ1 4.2 FZ4 5.4

FB2 3.5 FB5 3.4

FZ2 4.5 FZ5 5.4

FB3 3.3 FB6 4.0

FZ3 4.3 FZ6 5.4

FB4 4.4 FZ7 4.2

FZ4 5.5 FB7 2.6

FB5 3.2 FZ8 5.7

FZ5 5.3 FB8 3.0

FB6 3.7 FZ9 4.1

FZ6 3.4 FB9 2.8

FB7 2.6 FZ10 2.9

FZ7 6.7 FB10 2.1

FB8 4.5 FZ11 4.3

FZ8 5.1 FB11 3.0

FB9 3.3 FZ12 3.6

FZ9 8.5 FB12 1.6

FB10 3.8 All 3.8

FZ10 5.3 Lancaster (all wells)

FB 3.2

All 4.4 FZ 4.8

All 4.0

Porosity and Fault Zone summary

Field average

Fault Zone widths (MD)

7Z average


Regional joint distribution per well

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-2820

-2920

0 0.5 1 1.5 2km

205/21a-7

205/21a-7Z

205/21a-4

205/21a-4Z

205/21a-6


205/21a-7Z PBU Interpretation

Complex storage response – combination of wellbore and well connected fractures

Dual porosity dip

Late time drop

Tidally corrected derivative plot

P.I. 147 stb/d/psi Maximum ESP flow rate of 15,375 stb/d (constrained by flare boom) Stable natural flow rate of 6,520 stb/d achieved (constrained by critical flow through separator) No formation water produced


Summary of well results

•The 7Z well static and dynamic data corroborated the:

– conceptual reservoir model

– pre drill seismic fault interpretation (12 faults instead of 11)

–zonal properties (Fault Zone thickness and porosity) within expected ranges

•The high flow rates and associated high PI were consistent with the expectations from the 6 well

•The well was suspended as a future producer


Connectivity summarised •Fracture intensity does not appear to be controlled by

-Distance to fault zones

-Distance to fault zone boundaries

-Elevation (reservoir depth)

-Relative distance to top basement

•The above observations support the concept of early pervasive joint development which has been subsequently exploited by faulting

•Connectivity induced by the geometric disposition of joints is interpreted as being further enhanced by hydrothermal and epithermal processes


Lancaster geological history

Preserved Stratigraphy Eon Era Period Epoch

Ph

aner

ozo

ic

Cen

ozo

ic

Neogene Miocene

Palaeogene

Oligocene

Eocene

Palaeocene

Mes

ozo

ic

Cretaceous Upper

Lower

Jurassic

Upper

Middle

Lower

Triassic

Pal

aeo

zoic

Permian

Carboniferous

Devonian

Silurian

Ordivician

Cambrian

Proterozoic

Archean

Basement at Lancaster dated as a minimum of 2.3Ga

Hot fluid pulses enhance fracture network (hydrothermal processes)

Epithermal enhancement of fracture system

Oil charge (biodegraded)

Oil charge (undegraded)

Period of burial / deposition

Period of uplift / erosion

Key

? ?

Variscan Inversion

Caledonian Orogeny

Alpine Orogeny

Emplacement of plutonic TTG (tonalite-trondhjemite-granodiorite) gneisses. Resulting cooling creates joint system

Laxfordian compression results in extensive NW-SE shear faults

Brittle deformation along pre-existing planes of weakness – i.e. cooling joints – creating fault network. Repeated burial and uplift of basement reactivates faults

Regional ENE-WSW extension

Rona Ridge comprised of a series of island surrounded by a shallow sea, enhancing the fracture network through subareal exposure

Marine transgression. Deposition of Kimmeridge Clay source rock

Atlantic Rifting NE-SW extension

Pasteurisation of basement through burial (temperatures >80oC)

Lancaster basement uplifted by 1 – 1.5km, relaxation of pre-existing fracture network. Uplift coeval with charge (undegraded due to previous pasteurisation)

Renewed subsidence. Lancaster still receiving charge today


Presentation






6 Q&A


EPS Field Development •2 existing wells (205/21a-6, 205/21a-7Z)

•Base case initial production 20,000 bopd to avoid reservoir damage


RPS Energy CPR production forecasts

EPS production forecasts

Note: Chart data based on RPS Energy May-17 reserve cases which assume an EPS duration of 6 years. Under the scenario where the EPS is extended to 10 years, additional volumes would qualify as reserves

-

5,000

10,000

15,000

20,000

25,000

30,000

2019 2020 2021 2022 2023 2024

Dai

ly O

il P

rod

uct

ion

Rat

e (m

stb

/d)

3P 2P 1P

EPS Low Case EPS Base Case EPS High Case

Basement assumptions

OWC 1,597m TVDSS

(swab depth from 205/21a-4 well)

1,653m TVDSS (MDT oil gradient

intercept)

1,678m TVDSS (resistivity log, oil sample collected

lower)

Porosity 2.0% 4.0% 7.1%

Operational efficiency (/uptime)

80% 85% 90%

Plateau production rate

Gross (peak run-rate)

20,000 bbl/d falling to 14,000 bbl/d

20,000 bbl/d 20,000 bbl/d rising

to 30,000 bbl/d

Net (adjusted for operational efficiency)

16,000 bbl/d falling to 11,200 bbl/d

17,000 bbl/d 18,000 bbl/d rising

to 27,000 bbl/d

RPS Energy CPR Cases


Summary

•The effective fracture network at Lancaster has predictable static properties in the currently drilled GRV:

– a persistent ne-sw striking joint population

– pervasive hydrodynamic fracture network comprising microfractures, joints and fault zones

•Dynamic data supports the static observations:

–dual porosity response

–no identified permeability barriers

–high initial productivity index

•Long term data gathering and further modelling work is required to evaluate:

–dynamic properties of the reservoir in the vicinity of the current wells

–potential static and dynamic properties of the fracture network away from well control


Thank You

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