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www.oilgen.com Flow Mechanisms and Numerical Simulation Techniques applied to Shale Gas Reservoirs Laurent SCHIRRER, Oilgen Ltd AFES Shale Gas Seminar 4 th June 2013

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Flow Mechanisms and Numerical Simulation Techniques applied

to Shale Gas Reservoirs

Laurent SCHIRRER, Oilgen Ltd

AFES Shale Gas Seminar

4th June 2013

A quote

"the long-term production profiles of shale wells and their estimated ultimate recovery of oil and natural gas are

uncertain”

Source: “Review of Emerging Resources: U.S. shale gas and Shale Oil plays”, U.S. Energy Information Administration, July 2011

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Comments

� All petroleum production forecasts are uncertain� The EIA meant that production profiles of shale

wells were particularly uncertain, at least at time of writing in 2011. This was very true.

� Our aim is to explore the origin of these uncertainties. Our mission to provide the appropriate science and workflows to reduce them.

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Questions

� What is the State of the Art in the understanding of flow mechanisms for shale gas wells ?

� What are the forecasting techniques available to engineers and their limitations ? Is reservoir simulation applicable ? What are Formation Evaluation requirements ?

� “Shale gas engineering” as an emerging discipline: how “unconventional” is that ?

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Definition of shale gas reservoirs

Source: Schlumberger Glossary

Source: SPE Glossary

Note: the term “methane” is too restrictive, to our opinion

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Shale Plays are Unconventional

� The term “Unconventional” may refer to

» An unconventional reservoir (e.g. a source rock, of very low permeability, containing organic matter and adsorbed gas)

» The requirement of unconventional extraction methods to make the development of the above resources economic (e.g. horizontal multi-frac wells)

� Which definition do you like the most ?

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The economic impact of Shale Gas developments

� Shale Gas production triggered a gas price collapse in 2012

� The U.S.A. is becoming self dependent in natural gas

� As operators turned to liquid rich wells, a growing share of US domestic oil production, and worldwide production too, now comes from U.S. unconventional reservoirs

� “Shale Revolution” is gradually taking over “Shale Boom”

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The share of U.S. gas production from shale

reservoirs is predicted to continue growing steadily,

from 7.8 tcf in 2011to 16.7 tcf in 2040

EIA outlook 2011

EIA outlook 2013: upward revision

The US Shale Gas revolution:key factors

� Extensive onshore play types

� Technology Breakthrough & Experience

� Land System / Low taxes

� Extensive support chain

� Regulatory

� Market forces

European or non-North American specificities will lead to the consideration of new enablers to drive shale gas expansion.Among them: improved determinism in the evaluations of shale gas plays and their recovery (European plays won’t be evaluated “by the drill bit”, but with a lot of science)

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Shale Gas Engineering

� An emerging discipline» Leadership from Operators, Universities, Software

companies» Oilgen reviewed 71 papers, mostly written after 2008, to

develop its own models and workflows

� The U.S. shale gas boom was driven by pragmatism» Combination of play experience, technology trial and

errors, influx of capital, high initial rates

� The industry need for improved predictive methods is confirmed, above all in North America» Gas price collapse in 2012 to $2/mcf makes well economics

very sensitive to EUR (Expected Ultimate Recovery)

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Shale Gas Reservoirs

Unconventional rock

� Very low permeability

� Organic matter and adsorbed gas

� Water saturation unusually low (source rock)

� Over Pressured

� Often naturally fractured

Unconventional well

� Horizontal wells

» Sometimes vertical

� STIMULATED: multi-stage horizontal fracsare the norm

Where is the RESERVOIR ?Think Storativity and Flow Capacity

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US Shale Plays rock characteristics

Barnett Fayetteville Haynesville Marcellus Woodford Antrim

Area (km2) 12,944 23,300 23,300 245,944 28,478 31,067

Depth (000ft) 6.5 to 8.5 1 to 7 10.5 to 13.5 4 to 8.5 6 to 11 0.6 to 2.2

Height (ft) 100 to 600 20 to 200 200 to 300 50 to 200 130 to 220 60 to 120

Porosity (%) 4 5 8 8 6 9

Gas content, scf/t 325 60 to 220 100 to 330 80 250 40 to 100

GIIP, tcf 345 55 755 1600 78 80

GIIP, bcf/km2 26.7 2.4 32.4 6.5 2.7 2.6

Recoverable, tcf 61 38 116 200 32 20

Stated recovery factor 18% 69% 15% 13% 41% 25%

Modified from Steve Hennings, 2012

Note: The Antrim shale was among the four “old shales” that could flow economically on vertical fractured well technology, at a rate of 0.2 tcf/year in the mid 90’s.

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A multi-stage frac operation

� Up to 30 stages� Haynesville stats

» Average water pumped into a single stage 423,000 gallons

» Average number of stages 11.4

» Average per frac water use per well: 4.8 million gallons or 137,000 barrels

� Significant volumes displaced in near well area

Source: Schlumberger

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Stimulated Reservoir Volume (SRV)

� The specificity of most shale gas developments (but not all) lies in the artificial creation of a new reservoir medium

� Concept of Stimulated Reservoir Volume» Flow capacity and

Storage» Large contact area with

rock matrix» Well connected with

wellbore via primary fracture

See Ref: SPE148710Sketch of a Microseismic acquisition(Source: www.esgsolutions.com)SRV can be characterised from micro seismic, fracdesign and analysis, or production performance techniques.

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Is that what a shale gas model looks like ?

� This picture shows the design of a multi-stage horizontal fractured well I built in 2002

» Rock: tight North Sea sandstone 1 mD» Well: horizontal, 3 stage fracs, Xf=50m,

modelled with Local Grid Refinements (LGR)

� These simulation techniques from more than 10 years ago are at the origin of modern shale gas models

» LGR “recipe”, fracture flow, compositional EOS.

� Shale gas simulation incorporates much (much) more physics, though...

» For example SRV modelling, adsorption, fracture network, etc...

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Top view of a horizontal multi-frac shale gas well (not at scale)

Shale Gas Flow Mechanisms

Flow mechanisms Parameter Simulation1 Fluid phases CGR, Dew point Often compositional2 Fluid phase interraction Wettability, rel perm, pc,… May require hysteresys model (soaking)3 Matrix flow, Darcy Porosity, permeability Classic4 Desorption TOC, Lagmuir Isotherms Compositional prefered5 Diffusion (within organic matter) Diffusion Laws, eg CBM Advanced simulators only6 Natural fracture flow Frac density,conductivity, anisotropy Dual K7 Stimulated secondary fracture flow Frac density,conductivity, anisotropy Case-dependent8 Propped secondary fracture flow Conductivity, non darcy correlation Pseudoisation, non-darcy-correlation, LGR or Tartan9 Primary fracture flow Conductivity, non darcy correlation Pseudoisation, non-darcy-correlation, LGR or Tartan

10 Tortuosity Skin Connection fracture-tubing11 Tubing horizontal flow Friction, flow correlation Multi-segment wells12 Vertical flow Friction, flow correlation Lift performance curves

Primary fracture, propped Primary

fracture,un-propped

Secondary stimulatedfractures, propped or not

Natural un-stimulated fractures

Matrix

SRV

Tubing flowVertical flow

WellheadToe

1,2,3,4,5

6

Perf flow

10

9

8

7

11,12

©Oilgen Ltdwww.oilgen.com

Fracture, propped

Un-propped

Size: stimulation level

Legend

9 Flow mech. (see table)

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Shale gas numerical simulation

Flow mechanisms1 Fluid phases2 Fluid phase interraction3 Matrix flow, Darcy4 Desorption5 Diffusion (within organic matter)6 Natural fracture flow7 Stimulated secondary fracture flow8 Propped secondary fracture flow9 Primary fracture flow

10 Tortuosity11 Tubing horizontal flow12 Vertical flow

1,2,3

4,5 (later)

6

7,8

9 10

11,12

© Oilgen

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Example: Niobrara horizontal

� Model is used here to illustrate the effect on ultimate recovery of advanced stimulation techniques

» SRV simulation doubles ultimate recovery» Un-stimulated wells production is insignificant, but as expected

historically (a few 10,000 mscfd)» As for all reservoir models, the full benefits are reached when

calibrated to production data (history-match)

Gas Shale Reservoir SimulationHorizontal Well cases

Time (Date)

Gas

Rat

e (f

t3/d

ay)

2012 2013 2014 2015 2016 2017 2018 2019 20200

200,000

400,000

600,000

800,000

1,000,000

Bi-wing Hydraulic Frac + Stimulated Reservoir VolumeBi-wing Hydraulic Frac(No Hydraulic Fracture)

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SRV and Drainage Area

13,000 14,000 15,000

13,000 14,000 15,000

-8,000-7,000

-8,0

00-7

,000

0.00 325.00 650.00 feet

0.00 100.00 200.00 meters

User: OilgenScale: 1:5077Y/X: 1.00:1Axis Units: ft

2,0002,1252,2502,3752,5002,6252,7502,8753,0003,1253,2503,3753,5003,6253,7503,8754,0004,1254,250

Top view. Simulated Pressure after 10 years (psi) Top view. Extent of SRV model.

13,000 14,000 15,000

13,000 14,000 15,000

-8,000-7,000

-8,0

00-7

,000

0.00 325.00 650.00 feet

0.00 100.00 200.00 meters

User: OilgenScale: 1:5077Y/X: 1.00:1Axis Units: ft

1

101

201

301

401

500

600

700

800

900

1,000

In very tight formations, drainage area does not extent much beyond the Stimulated Reservoir Volume, but this may vary with local properties as each case is particular.

This case has a non-optimised frac spacing.“Depletion=recovery”

Matrix parameters (Niobrara formation)

Height (ft) 360Porosity (%) 6 to 9.5Permeability (mD) 8 to 60.10-5

TOC (%) 2.1 to 5.8

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Tools and techniques available to predict shale gas flow

DCA Type Curve (statistical) Type curves (Diagnosis plot), RTA Reservoir Simulation

Rationale "The observed decline is going to

continue"

"What happened

statistically is likely to

happen again"

A reservoir type model is fit to the

observed data / decline is informative

of underlying physics

Incorporates physics, hence

deterministicaly predictive

Type Empirical Empirical, fit on real data Theoretical fit of analytical model Physical model

Examples Arps (1945), Lee (Tex A&M 2010) Widespread The "linear model", Wattenbarger,

Blasingame,...

Each model can be customised

Applicability to shale gas Poor, as rates of decline are

notoriously changing with time

for shale gas !

Better. Good. V. good when excellent data

acquisition exists. Can be

deployed before produciton.

Limitation Not very predictive. Flow

mechanisms are phased with

time. These methods give to

much weight to near frac

mechanisms

Applicable play by play.

Require production

To work well, requirements of

permanent rate-pressure recording.

E.g. downhole gauge

As for all simulation problems,

the more parameters are

characterised a priori, the better.

History-match reduces

uncertainties but can not always

solve all of them.

Quality of forecast Poor Limited Lonf term prediction is the issue. These

models do not encompass all flow

regimes

Best. Uncertainties can be

quantified.

Value of information Poor Limited information on

reservoir

Good. It informs on parameters like

fractures, stimulated volume, etc...

Strong

Impact on economic

optimisation

Nil Poor Real impact if well used A key objective of simulation

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Example interactive type curve /diagnostic

Source: Fekete

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Formation Evaluation Requirements for Shale Gas

Reservoir Engineering

� The highlighted parameters should form the objectives of a good Formation Evaluation strategy, for best economic evaluation of reserves

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What reservoir simulation can bring to shale gas assets

� Well Design» e.g. what range of R.F. can be expected from such shale

play ? Optimum number of stages ? Frac spacing ? Will the well require a large Stimulated Reservoir Volume to be economic ?

� Post-frac diagnosis» Compare well to expectations and improve recipe

� Forecast EUR» Improve accuracy and provide range P90,P50,P10» Condensate ratio of Liquid Rich Shales

� Development optimisation» Drainage area ? Do I need that many stages ? Help define

play sweet spot

Example Savings: up to several $M per asset (e.g. reduce number of wells by 10%; suppress frac stages; increase EUR by 10%, etc...)Deployment costs of study is an order of magnitude lower than potential gains

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Have we answered our questions ?

� State of the Art» Industry has made tremendous progress in the past few years to understand shale gas

flow behaviour and spread knowledge.

� Techniques and workflows» Analytical reservoir engineering is very efficient to characterise flow, providing flow

forecast at low cost. Each technique has its own field of application and limitation to predict the long term performance of wells. Miss-use caused serious economic disappointments in the past, when they were the only available techniques.

» Reservoir simulation of shale gas is a commercially available technique becoming mature, thanks to recent research and development by software companies, operators and universities. It requires a high level of expertise. It is the ultimate tool to encompass physics and test scenarii. Deployment cost has significantly dropped recently, thanks to innovative “toolbox” developments by software companies. The limitations of reservoir simulation lie in our un-ability to assess all parameters... a normal situation in sciences, indeed.

» Key for success: data acquisition, value of information, integration of even more disciplines than for conventional reservoir engineering. The role of Formation Evaluation professionals is key.

� Shale Gas Engineering» Is an emerging discipline» Is anything but unconventional !

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Oilgen is a high-tech reservoir engineering & subsurface consultancy

Client-focused :: Independent :: Quality-driven

Oilgen Ltd 48 Queens Road Aberdeen AB154YE (U.K.)t: +44 1224 327047 f: +44 1224 327911 e: [email protected]

www.oilgen.com @oilgen

For more information on shale gas engineering, or if you would like to know more about some of the published material in this presentation, do not hesitate to contact us.