20 th annual williston basin petroleum conference

20th Annual Williston Basin Petroleum Conference

Russ BuettnerBakken Asset Team Subsurface Manager

Marathon Oil Corporation

Bismarck, North DakotaMay 23rd, 2012

Understanding Vertical & Horizontal Communication in the Bakken

AgendaHighlight Marathon’s Bakken results

Why are we focused on lateral and vertical communication?

Marathon’s Data Acquisition Overview

Observations that indicate communicationDuring both stimulation and production

Key data and analysis used to construct reservoir models

Calibrated simulation results that provide insight toward oil recovery potential

Invitation to Collaborate2

3

Striving for Performance Improvement

2008 2009 2010 20110

100

200

300

400

500

600

Gro

ss E

UR

(MBO

E)

Marathon Oil Corporation

2007 2008 2009 2010 20110

5

10

15

20

25

30

35

Frac Fluid (BBL/Ft)Stages (#)Proppant Density (x 10 lb/ft)

Souce: NDIC database

Completion Practices (1,600 wells)*MRO Per Well EUR by Year

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,0000

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90 Day Cum Oil (BBL)

Tota

l Fra

c Fl

uid

(MBB

L)

MRO Per Well Avg IP by Year

90 Day Cum Oil vs Frac Fluid*

* Source: NDIC database

2008 2009 2010 20110

200

400

600

800

1000

1200

BOPD

Industry

Recovery improvements have been made….but do we understand fundamentally why?

0 50,000 100,000 150,000 200,000 250,0000

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

12 Month Cumulative Oil Production (BBL)

Cum

ulati

ve D

istrib

ution

Fun

ction

2006 – 2011 Dunn County Middle Bakken Wells

Open Hole

6 Stage Completion

9 Stage Completion

19 Stage Completion

20 Stage Completion

Mean 12 Month Cumulative

Oil Production

(BBL Oil)

41,000 45,000 59,000 88,000 91,000*

2006 – 2007 Open Hole Wells

2008Staged Wells

2009Staged Wells

2010Staged Wells

2008 Stage Completion WellsAverage # of Stages: 6Average Proppant Density (lb/ft): 144


2006 – 2007 Open Hole Completion WellsAverage Proppant Density (lb/ft): 71


Staged Wells2011 Stage Completion WellsAverage # of Stages: 20Average Proppant Density (lb/ft): 228

2011 staged wells cumulative oil production based on extrapolation.

Why do more stages improve performance?-More uniform stimulation along the lateral-Increased Stimulated Rock Volume-Connections to bounding layers?

5

What is the potential of the Entire Bakken section?

Geologic Layers

Estimated STOOIP, MMBLS

Lodgepole 7 - 9

Upper Bakken Shale

4 - 8

Middle Bakken

8 – 12

Lower Bakken Shale

12 – 15

Three Forks 10– 15

Oil in place in at Typical 1280 acre DSU

• 5-15% RF of MB or TF is what we attribute to a development unit

• But is recovery limited to the horizon that the lateral is landed in?

40-60 MMBbls

6

Conceptual Single Well Recovery of All geologic layers vs. MB only

• All geologic layers are connected through the natural fracture and fault network

• Vertical drainage is more dominant than lateral

• Well EUR40 : 900 – 1,100 MBOE

• Geologic barriers between MB and TF and no drainage of bounding shales

• Lateral drainage is dominant

• Well EUR40 : 300 - 500 MBOE

High Side - Full Vertical Communication Low Side - Vertical Barriers constrain drainage to MB only

5,280ft 5,280 ftLimited areal drainagewith increased vertical connectivity

Broad areal drainagewith no vertical connectivity

Geocellular model based simulation with dual porosity and discrete fracture network

Model cross-section

UBSMBLBSTF

MB

7

• Geologic barriers between MB and TF. No recovery from shales

• Total wells per DSU: 3 MB + 3 TF

• DSU EUR40 : 2 – 3.5 MMBOE • MB Well EUR40: 200- 300 MBOE

• Geologic barriers between MB and TF. No recovery from shales


• DSU EUR40 : 3 – 4.5 MMBOE• MB Well EUR40: 150- 250 MBOE

Conceptual Full Development - What is Optimum Spacing?

• All geologic layers are connected through fracture networks


• DSU EUR40 : 4 - 6 MMBOE • MB Well EUR40: 700 – 1,000 MBOE

Full Vertical Communication Vertical Barriers

Optimum spacing depends on the degree

of vertical drainage

MB

TF

8

Bakken Data Acquisition & Integration

Core Facies DescriptionsSequence Stratigraphy Model

Petrophysics Core fracture descriptions

Fracture intensity[FI], orientation, relaxed apertures, morphology, kinematics

Borehole image logs Fracture counts, orientations, apertures, in-situ stress

Geophysics 3D/3C surface seismic

VSP (ZO,WA,FO) & MicroseismicLineaments

Grav & Mag attributes Surface Data (Landsat, Digital Elevation Model, etc)

GeochemistryRocks & Fluid Samples

Production Data (Pre- & Post-Stimultation)In-Situ Stress (Vertical DFIT/FET, Pp, Shmin)

Stimulation (Anomalous Stages, Inter-well Connectivity, Tracers in Vertical & Horizontal Wells)SCAL & Geomechanics

Multiple Plug Orientations, Dynamic & Static Elastic Properties (Anisotropy & Tensors)

Failure Data (MCFE)Permeabilities

Core Facies Descriptions& Petrophysics

9


Core Facies DescriptionsSeq-Strat Model, Facies definition for mapping & modeling


Fracture intensity, orientation, aperture descriptionBorehole image logs

Fracture counts, orientations, apertures, in-situ stress Geophysics

3D/3C surface seismicVSP (ZO,WA,FO) & Microseismic

Lineaments Grav & Mag attributes

Surface Data (Landsat, Digital Elevation Model, etc)GeochemistryRocks & Fluid Samples





Example of Core Description Vertical Core : Natural Fracture Intercept Rate

(Fracture counts) & Fracture Morphology

Horizontal Core

Fracture intensity

10





Borehole image logs Fracture counts, orientations

Geophysics 3D seismic & VSP’s

MicroseismicLineaments







Horizontal Image Logs & 3DFracture Corridors from Seismic

(curvature calibrated to image Log)

11






Geophysics 3D/3C surface seismic & VSP’s

MicroseismicLineaments







12









GeochemistryCore , Cuttings & Produced Fluid Samples





13










Production Data (Pre- & Post-Stimultation)In-Situ Stress (DFIT/FET)




Marathon Mylo Wolding 14-11H Middle BakkenMinifrac - G Function

10 20 30 40 50 60 70

G(Time)

8000

8100

8200

8300

8400

8500

8600

8700

8800

8900A

0

100

200

300

400

500

600

700

800

900

1000D

(0.002, 0)

(m = 11.42)

(64.54, 737.3)

(Y = 0)

Bottom Hole Calc Pressure (psi)Smoothed Pressure (psi)Smoothed Adaptive 1st Derivative (psi)Smoothed Adaptive G*dP/dG (psi)

AADD

1

1 Closure

Time41.90

BHCP8303

SP0.000

DP0.000

FE0.000

GohWin v1.6.511-Jul-10 03:23

14











Stimulation (Anomalous Stages, Inter-well Connectivity, Tracers in Vertical & Horizontal Wells)

Special core analysisGeomechanical rock properties

Matrix Permeabilities from whole core Sh

ear S

tres

s (ps

i) In

crea

ses

Normal stress (psi) Increases

15

Increased well density Preparing for and observing lateral communication during fracs Decompleting offset wells during fracs

Probable fracture corridors interpreted from gas shows and structure maps

Seismic is also helpful in detecting larger structural events

Curvature Map Suggestive of Natural Fracture Density

High Natural Fracture Density

AssumedN

Natural FractureInterpreted

Low Natural Fracture Density

Assumed

Gas Profile for Frac’d LateralOffset Lateral Distances to Frac’d Lateral

Fracture Corridor

“Probable” Fracture Corridors

2000’ Radius3000’ Radius

~50% of Near offset

decompleted wells

see pressure from offet

stimulation treatments

Structure from well data

Infill Wells

16

Completion Interference: Three Forks to Middle Bakken

Casing pressure in a Middle Bakken well increased from 75 to 3000 psi during stimulation of adjacent TF well

Pressure increases correlated with stages located in areas with high gas shows in the lateral

Three Forks Frac Pressures Up Offset MB Well Via Fracture Corridors?

Three Forks Lateral

Middle Bakken Lateral

Fracture Corridors

700’

Three Forks Lateral Stage Number

Middle Bakken Casing Pressure

Middle Bakken Well

Middle Bakken Well

Three Forks Well Three Forks Well

Infill wells

17

Production Interference – Middle Bakken interferes with Three ForksVertical Communication Occurs Through Natural Fractures?

Lodgepole

Upper Bakken Shale

Middle Bakken

Three Forks

Lower Bakken Shale

Middle Bakken well Three Forks well

Three Forks wellProduction communication

Middle Bakken wellPump installation

Middle Bakken well

Three Forks well

Three Forks well

Middle Bakken well

500 ft 250 ft

Instantaneous production interference

between nearby MB and TF wells

Horizontal Core Vertical Fractures in a Horizontal Cores

Horizontal Core Slab revealed intense fabric of micro-fractures

Wide aperture fluorescing fractures in intact core

Slabbed Core

Core Depth Increases

Core Depth Increases

18

19

Outcrops and Conceptual fracture models help explain communication observed in the field

₋ Fractures related to faults can penetrate geologic units

₋ Vertical drainage through fault related fractures should be expected

General outcrop display– not Middle Bakken

Bed contained fractures

Integrating natural fractures into a 3 dimensional geocellular model

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-Description of pervasive micro-fracture network

Characterization and understanding of all fractures both natural and induced is needed

to predict performance

- Description of Regional Fractures

-Inclusion of structurally related fractures (swarms-corridors)

Independent Fracture properties are included in a

dual porosity simulation.

Regional Fractures

Structural Fractures ShMax

21

Vertical Stress and Hydraulic Fracture ModelIntegrating field data to understand fracture growth

• Vertical stress and pore pressure in 5 layers (LP, UBS, MB, LBS and TF) were measured with DFIT tests

• Results used as inputs to hydraulic fracture simulation models

• Note marginal differences in pore pressure in each layer that also suggests that the layers are in communication

Predictive fracture models indicate containment of fracs within zone

• The created Xf that can exceed 1,000’, but the effective, propped fracture half-lengths are <200’

• Model does not include natural fracture description that can divert fracture growth vertically

10550

10575

10600

10625

10650

10675

10700

7500 9500

DEPT

H, ft

PSI

Closure Pressure

Pore Pressure

INCREASING

INCR

EASI

NG

LP

TF

MB

22

Geochemical Data - Stratigraphic intervals in the Bakken Petroleum System have unique geochemical fingerprints

-30.5 -30 -29.5 -29

10,500

10,525

10,550

10,575

10,600

10,625

10,650

10,675

10,700

10,725

10,750

Geochemical Signature

• Geochemical signature values can be sampled initially and over time

• Fluctuation would be indicative of contribution from bounding layers

23

Individual Well Reserve Evaluations – Which b-factor?Decline analysis also suggests vertical communication is occuring

0.0

1.0

2.0

3.0

4.0

5.0

1 10 100 1000 10000

b-parameter

Time, days

b-parameter vs. Time, days

0.0

1.0

2.0

3.0

4.0

5.0

1 10 100 1000 10000

b-parameter

Time, days

b-parameter vs. Time, days

Full vertical communication

• In this model, geologic units are connected vertically through fracture networks

• Simulation indicates that b-factors would stabilize near 2.

Vertical barriers between layers

• With no vertical communication between layers in the model

• Simulation indicates that b-factors will stabilize at around 1.0 (isolated MB well)

• This behavior is not being observed in areas studied

Well performance observations are between these two cases indicating partial vertical communication

24

Example - Calibrated Single Well Conceptual Model

• Vertical communication is modeled to occur through structurally related fractures• Vertical contribution is calibrated with geochemical based production allocation

• Propped hydraulic fractures are assumed to be contained in MB

• EUR40 : 600 -850 MBOE

Layer % Contribution Recoverable MBOE

Upper layers 5 - 15 50 - 100

MB 75 - 80 500 – 550

Lower layers 15 -20 100 - 200

History matching and geochem production allocation helps to understand how to constrain vertical

communication in the static model

Vertical Permeability resultingfrom fracture networks

Pressure depletion from a frac stage and through natural fractures

Challenge – How do we collaborate as developers of the Bakken to improve efficiency and oil recovery?

Acreage positions are secure in many areas

Sharing technical understanding and best practices will serve North Dakota and all of the Bakken stakeholders

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URAN_MW_FORE_ENHANCE.UNSMRY 16 Jan 2012

Date (YEARS)

OilP

rod

Rate

(STB

/DAY

),OP

RH(S

TB/D

AY)

200

400

600

OPROPRH

URAN 31-2H

History Match - Oil Rate

30 years depletion

TF MB TF MB

Pressure (Fracture Grid)

Acknowledgments

Marathon Bakken Asset teamDoyle Adams Faisal RasdiAhmad Salman

Upstream Technology – Bakken Integrated Reservoir Characterization Team

Sebastian Bayer Steve Buckner Jason ChenPhillipe Lozano

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20 th annual williston basin petroleum conference

Documents

stage fracs

average frac stages

increased frac fluid

years proppant density

higher fluid volumes

higher volumes

total fluid volumes

oil vs frac fluid