Shale Gas Fracture Optimization

CORPORATIONCORPORATION

George KingGeorge King

George E. King is a Registered Professional Engineer with George E. King is a Registered Professional Engineer with George E. King is a Registered Professional Engineer with over 38 years of experience. He started his career with Amoco in 1971. His technical background includes energized fracturing, acidizing, complex formation stimulation in many extreme environments.

George E. King is a Registered Professional Engineer with over 38 years of experience. He started his career with Amoco in 1971. His technical background includes energized fracturing, acidizing, complex formation stimulation in many extreme environments. stimulation in many extreme environments.

George has written over 60 technical papers, a book on completions and workovers, was a 1985 SPE distinguished lecturer and adjunct professor at the University of Tulsa

hi h h h hi

stimulation in many extreme environments.

George has written over 60 technical papers, a book on completions and workovers, was a 1985 SPE distinguished lecturer and adjunct professor at the University of Tulsa

hi h h h hiamong his many honors throughout his career.

George is currently a consultant with Apache in the area of stimulation and workovers.

among his many honors throughout his career.

George is currently a consultant with Apache in the area of stimulation and workovers.

2009 EPT Plan Presentation.ppt 02/16/2009 1

Shale Gas Fracturing – Combining Tracers and Shale Gas Fracturing – Combining Tracers and Microseismic to Optimize Fracture NetworksMicroseismic to Optimize Fracture Networks

George E. KingCompletions Consultant

George E. KingCompletions Consultant

Based on SPE Paper 119,896 and other well data

Are your fractures optimized?Are your fractures optimized? Can IP be tied to EUR? Only if frac network stays open! Can IP be tied to EUR? Only if frac network stays open!Can IP be tied to EUR? Only if frac network stays open!

Decline of 25% in 20 days in well w/ low rate frac (controlled frac h) - did not generate much frac network ?

Offset ell declined 50% in same time / high rate frac & did open the

Can IP be tied to EUR? Only if frac network stays open!

Decline of 25% in 20 days in well w/ low rate frac (controlled frac h) - did not generate much frac network ?

Offset ell declined 50% in same time / high rate frac & did open the Offset well declined 50% in same time w/ high rate frac, & did open the network , but didn’t prop it – had higher IP, but suffered faster decline and high water production!

Later wells were mid to high frac rates but used sand slugs slower rate

Offset well declined 50% in same time w/ high rate frac, & did open the network , but didn’t prop it – had higher IP, but suffered faster decline and high water production!

Later wells were mid to high frac rates but used sand slugs slower rate Later wells were mid to high frac rates, but used sand slugs, slower rate ramp for breakdown and faster sand ramp. Had flatter declines w/ low water.

Later wells were mid to high frac rates, but used sand slugs, slower rate ramp for breakdown and faster sand ramp. Had flatter declines w/ low water.

A d li f

Early High Rate Frac (70 bpm), 500 bwpd Produced Water

A one year decline of 80%! WHY?The feeder fractures were not propped

High rate frac w/ h control

were not propped.

Low Rate Frac (35 bpm), 30 bwpd Produced Water

Some Observations From 200+ Barnett Frac StagesSome Observations From 200+ Barnett Frac Stages

Tensile fracs & open natural fracs are easiest to extend. Can go out of zone in <1 minute when frac rate is ramped up too quickly.

High frac rates needed to increase complexity, but direct frac growth

Tensile fracs & open natural fracs are easiest to extend. Can go out of zone in <1 minute when frac rate is ramped up too quickly.

High frac rates needed to increase complexity, but direct frac growth g p y, gfirst!

Understand perf breakdown – w/ press analysis, tracer sand & microseismic

g p y, gfirst!

Understand perf breakdown – w/ press analysis, tracer sand & microseismicmicroseismic

Where frac barriers exist, use large pads, high rates and low sand volume.

microseismic

Where frac barriers exist, use large pads, high rates and low sand volume.

If no barriers => slower fluid ramp, faster sand ramp, build “barriers”.- Sand ramp must be tailored to the formation

If no barriers => slower fluid ramp, faster sand ramp, build “barriers”.- Sand ramp must be tailored to the formation- Sand ramp must be tailored to the formation.

- Mixtures of sand – 100 mesh + 40/70 or 20/40 used to plug “runaways”.

- Rate of press increase of 1 to 8 psi/min is good, faster press increase

- Sand ramp must be tailored to the formation.

- Mixtures of sand – 100 mesh + 40/70 or 20/40 used to plug “runaways”.

- Rate of press increase of 1 to 8 psi/min is good, faster press increase may signal impending screenout . Press drop may signal out-of-zone frac growth. may signal impending screenout . Press drop may signal out-of-zone frac growth.

Well Performance vs. Flow Regime for FWB Barnett WellsWell Performance vs. Flow Regime for FWB Barnett Wells Stress Anisotropyff

An optimum frac should return high IP and sustain

An optimum frac should return high IP and sustain 5 000

6,000NaturalFracture

pyShear Fractures

Present Worth

return high IP and sustain it to maximize NPV and EUR.

return high IP and sustain it to maximize NPV and EUR. 4,000

5,000

/d)

Drainage Only?

The performance of most fracs in the Barnett are good but optimization is

The performance of most fracs in the Barnett are good but optimization is 2 000

3,000

Rat

e (m

cf/

good, but optimization is still needed.

Does the plot indicate a

good, but optimization is still needed.

Does the plot indicate a1,000

2,000

Wel

l IP

RPropped Fracture Does the plot indicate a

frac performance problem that could show a disconnect in IP and

Does the plot indicate a frac performance problem that could show a disconnect in IP and

00.0 2.0 4.0 6.0

Well EUR (BCF)

Drainage ONLY

Stress Anisotropya disconnect in IP and EUR?a disconnect in IP and EUR?

pyShear Fractures

Present Worth

Plot by Jim Shuss

Frac Networking with Fracture Height ControlFrac Networking with Fracture Height Control

OK – what is happening? OK – what is happening?- Natural fractures are being opened, but not effectively

propped.

N t l f l i i d li d

- Natural fractures are being opened, but not effectively propped.

N t l f l i i d li d- Natural fracs closing as reservoir pressure declines and water is recovered.

- When and why does frac closure happen?

- Natural fracs closing as reservoir pressure declines and water is recovered.

- When and why does frac closure happen?When and why does frac closure happen?

- Can frac closure be controlled?

- What is involved?

When and why does frac closure happen?

- Can frac closure be controlled?

- What is involved?What is involved? Formation stresses, pressures, saturations and shale “fabric”

dominates.

What is involved? Formation stresses, pressures, saturations and shale “fabric”

dominates.

A flowback pattern from one wellA flowback pattern from one well

GasGas Lift

Days of Flow

More Typical – As the water drops, so does the gasMore Typical – As the water drops, so does the gas

Days of Flow Courtesy Rimrock Energy

What makes a difference in the wells?What makes a difference in the wells?

Classic shale gas candidate criteria

Where are the flow paths located?

Classic shale gas candidate criteria

Where are the flow paths located?

What factors affect well placement and design?

The fracture treatments themselves?

What factors affect well placement and design?

The fracture treatments themselves?The fracture treatments themselves?

The way we operate the wells?

The fracture treatments themselves?

The way we operate the wells?

Rough Comparisons of Gas Shales

Pay Barnett Marcellus Fayetteville Woodford Conasauga Devonian Antrim N Albany Lewis

Basin FW Appalachia Arkoma Arkoma BWB App Michigan Illinois San Juan

Location TX PA, WVA AR OK Ala, GA KY, NY, PA, WV

MI, IN, OH IN, KY CO, NM

Depth (ft) 6 to 9000+

4 -10,000’ 1500 to 6000’ 6 to 12,000’ 4 to 8,000’ 2 to 8000+ 0.6 to 2K+ 0.5 to 2K+ 3 to 6000

H, thick: gross/net

250: 50% 50 to 300 50-550: 50% 200 to 350 3000:? 30 to 300: 40% 160: 40 -60

180: 40 to 60

3000:?

Modulus, psi 7 to 9MM 4 to 7MM 3MM 3 to 5MM <2MM 3 to 7MM

BHT F 180-210 150-200F 120 to 160 180 100 to 140 80 80 130-170

Press Grad, psi/ft 0.4 to 0.5 0.3 to 0.55 0.35 to 0.4 0.43 - 0.46 0.4 0.2 to 0.4 0.35 0.43 0.25

Maturity, Ro, % 1.4+ gas 1.4 to 2+ 1.9 to 5 1.1 to 3 1.6 0.9 to 2 0.4 to 1.6 0.6 to 1.6 1 to 1.3

TOC, wt % 1 to 5 5 to 12 5 to 15 10 to 20 15 to 25% 3 to 20 3 to 20 3 to 20 0.5 to 2.5

Total Porosity % 1-8 1 to 7 1 to 5 1 to 5+ 2 to 5 2 to 10 5 to 15 0.5 to 5

Sw 0.1 -0.25 0.1 - 0.25+ 0.1 to 0.2 0.1 to 0.25 <0.1 0.1 to 0.25 0.1 to 0.3 0.1 to 0.3 0.1 to 0.8

Gas Cnt, scf/ton 100-500 80 to 250+ 150-225 250+ 60 to 100 40 to 100 40 to 80 15-45

Adsorb Gas, % 20 40 30 30 UNK 50 70 40 to 60 15 to 40

Water BWPD 10 -100+ 10 -100+ 0 0 0 20 to 100 5 – 500 0

Well spacing 80-160 80 to 160 40 to 80 80+ 40 to 160 40 to 160 80 80 to 320

GIP BCF/Section 30 to 40 30 to 50 55-65 110 5 to 10 8-16 7 to 10 90

Basin Res. (TCF) 25 to 250 275+ 10 to 15 10 to 50 225 12 to 20 2 To 80 100

EUR (BCF/well) 2 to 5 2 to 4+ 0.6 to 0.9 ? 0.3 to 0.5

Recovery Fact % 8-15+ 10 to 15+ 10 to 15 UNK 5 to 10% 10 to 20 20 to 60 10 to 20 5 to 15

data averaged from various sources

Gas flow path – from desorption to flowGas flow path – from desorption to flowGas flow path from desorption to flowGas flow path from desorption to flow

1 In many gas shales gas desorption is of smaller1. In many gas shales, gas desorption is of smallervalue than pore gas – NPV dominates.

2. Movement of gas through the shale matrix also of2. Movement of gas through the shale matrix also of lesser importance – it’s just too slow!

3. Recovering the stored gas in accessible natural g gfractures is the major current value.

Graphics source: Ron McDonald, Schlumberger

CORPORATIONCORPORATIONNatural Fractures – Primary and SecondaryNatural Fractures – Primary and Secondary

Shale outcrop in stream bedstream bed. Note the primary (blue) and(blue) and secondary (yellow) natural fractures. A third natural frac set can be seen at the bottom of th i t

2009 EPT Plan Presentation.ppt 02/16/2009 12Gary Lash –SUNY, AAPG

the picture.

What are we trying to do?What are we trying to do?

1. Possibilities in each part of the formation – barriers, faults, local variances. Take advantage.

2 Control the height of the frac if needed

1. Possibilities in each part of the formation – barriers, faults, local variances. Take advantage.

2 Control the height of the frac if needed2. Control the height of the frac if needed.3. Increase frac path width (complex frac)4. Maximize IP and EUR, minimize water production.

2. Control the height of the frac if needed.3. Increase frac path width (complex frac)4. Maximize IP and EUR, minimize water production.4. Maximize IP and EUR, minimize water production. 5. Understand the treating pressure “signature”. 6. Understand how to use the treatment variables:

4. Maximize IP and EUR, minimize water production. 5. Understand the treating pressure “signature”. 6. Understand how to use the treatment variables:

Where do you place the perfs? Acid, ball sealers, hydraulic diversion

P d l l d d

Where do you place the perfs? Acid, ball sealers, hydraulic diversion

P d l l d d Pad, slurry volumes and ramp-up speed Sand & liquid volumes – what is needed and usable? Rate – both stable rate and corrective rate changes

Pad, slurry volumes and ramp-up speed Sand & liquid volumes – what is needed and usable? Rate – both stable rate and corrective rate changes When and when not to push for isolation When and when not to push for isolation

Setting up frac stages and perfsSetting up frac stages and perfs

How to divide the wellbore?- If natural fractures are regular, a regular spacing is OK.

How to divide the wellbore?- If natural fractures are regular, a regular spacing is OK.

- If not, find where the nat. fracs are.

Methods of finding natural fracs (assuming that is good)

- If not, find where the nat. fracs are.

Methods of finding natural fracs (assuming that is good)g ( g g )- ROP and gas-shows from logs

- Ratios of methane-to-ethane, presence of C3 and C4 gas

g ( g g )- ROP and gas-shows from logs

- Ratios of methane-to-ethane, presence of C3 and C4 gasat os o et a e to et a e, p ese ce o C3 a d C gas

- 3D seismic interpretation – yes, it may indicate nat. fracs.

- Microseismic patterns from fracs

at os o et a e to et a e, p ese ce o C3 a d C gas

- 3D seismic interpretation – yes, it may indicate nat. fracs.

- Microseismic patterns from fracsMicroseismic patterns from fracs

- Tracers – both tagged sand and water markers

- Rock stress effects

Microseismic patterns from fracs

- Tracers – both tagged sand and water markers

- Rock stress effectsRock stress effects

Overlay all your data and look for patterns.

Rock stress effects

Overlay all your data and look for patterns.

Some Well Design FactorsSome Well Design Factors

Wellbore orientation relative to frac direction(s)?

D it k diff ? Wellbore orientation relative to frac direction(s)?

D it k diff ? Does it make a difference?

Do you really want the wellbore at 90

Does it make a difference?

Do you really want the wellbore at 90 degrees to the frac?degrees to the frac? Primary

Frac

Secondary Direction

Natural Fracs

Wellbore


Microseismic captured from sequential fractured wells. Microseismic captured from sequential fractured wells.

Note wellbore at a slight gangle to primary fracture direction keeps secondary f ffrac from following wellbore.

S Ri k


Source – Rimrock Energy – SPE

119896

Well Design – Vertical, Slant or HorizontalWell Design – Vertical, Slant or HorizontalHorizontalHorizontalHorizontal offers maximum contact but slant wells may require less technology and time will supportmay require less technology and time, will support

several fracs and can fit on smaller leases.


Fractures areFractures are vertical for the most part, but may follow themay follow the wellbore for a short distance in deviated wells.Fracture orientation is affected by ytectonic stresses in the rock.

2009 EPT Plan Presentation.ppt 02/16/2009 18 DHVI?

Tracer tagged sands are used periodically to analyze proppant breakdown points and

near well communications.

Tracer tagged pad & frac waters determine:• which intervals are broken down in each

of the perf clusters?

of the perf clusters• which intervals are flowing back first;

• which continue to flow with time;which continue to flow with time;

• which stay open compared to prod log.

Refrac

100012001400

Stage 1

Refrac Candidate?

0200400600800

1000

65 15 90 0 0 0

Stage 2

Stage 3

Stage 4

Stage 5

Stage 6Level of Use?

16 41 69 9812

5 014

8017

2019

3521

1522

9524

7026

2031

4534

9037

55no

t giv

enno

t giv

en

g

Stage 7

Stage 8

Until you understand.

What does micro-seismic really tell you?What does micro-seismic really tell you?

General location of sounds in/near the pay that are b t i (th t l l)

General location of sounds in/near the pay that are b t i (th t l l)above a certain energy (the gate level).

High and low energy events and high and low confidence events.

above a certain energy (the gate level). High and low energy events and high and low

confidence events.confidence events. A decent view of fracture extension, fracture

direction, fracture isolation, upper and lower frac f “f

confidence events. A decent view of fracture extension, fracture

direction, fracture isolation, upper and lower frac f “fpenetration, and fracture “flow path” development.

In some cases, it can tell you the effect of near-field and far-field stresses bedding planes and faults

penetration, and fracture “flow path” development. In some cases, it can tell you the effect of near-field

and far-field stresses bedding planes and faultsand far field stresses, bedding planes and faults. And many sounds totally unconnected with a frac.

and far field stresses, bedding planes and faults. And many sounds totally unconnected with a frac.

What is available from Microseismic?What is available from Microseismic?Complexity, Frac Height, Direction, Length, Faults Correlation to Treating Events (pressure, rate, proppant loading)

CORPORATIONCORPORATIONMore Complexity – Limited Downward GrowthMore Complexity – Limited Downward Growth

2009 EPT Plan Presentation.ppt 02/16/2009 22Courtesy Rimrock Energy


The frac had stayed in zone until this point – first 25% of events and the chart records a very slow, steady pressure rise. Then pressure starts to decrease as sand

concentration is increased..



Fracture goes into the Ellenberger. This corresponds with a drop in rate and a

rapid jump back to full rate.



Pressure starts to climb and fracture goes up and spreads


Microseismic vertical accuracy Microseismic vertical accuracy

Is MS accurate enough to depend on it? – It can be. Is MS accurate enough to depend on it? – It can be.

Left and Right: a frac

The comparison wells are ¾ mile apart.

Left and Right: a frac monitored from the vertical section of an offset producing well.

20% of events below pay.

Well produced 500 bwpd of 100,000 ppm water.

Left and Right: a frac monitored from a parallelmonitored from a parallel unfractured wellbore.

2% of events below pay.

W ll d d 30 b dWell produced 30 bwpd of 35,000 ppm water.


78487806

74867444

71247082

67626720

64006358

60385996

Production Logs – Understand Deviated Flow First!Production Logs – Understand Deviated Flow First!78067764772276807638

Stage 1

74447402736073187276

Stage 2

70827040699869566914

Stage 3

6 06636667865946552

Stage 4

63586316627462326190

Stage 5

59965924591258705828

Stage 6

25% W75% W 75% Gas10% G10% G5% G10% G

Production log & micro‐

10% Gas10% Gas

10% Gas10% Gas5% Gas10% Gas

Stage 5

log & micro‐seismic –hard to see connection /w/o treating pressure


Courtesy Rimrock Energy

OperationsOperations

How fast do you recover the water?

How hard do you pull the pressure down on the well?

How fast do you recover the water?

How hard do you pull the pressure down on the well?

When do you use lift? What type?

When do you refrac?

When do you use lift? What type?

When do you refrac?When do you refrac?When do you refrac?

ConclusionsConclusions

Spend the money early to understand the reservoir.

Place the wells to maximize the access to flow paths

Spend the money early to understand the reservoir.

Place the wells to maximize the access to flow paths within the reservoir

Monitor fracs –cheapest way to improve fracs quickly.

within the reservoir

Monitor fracs –cheapest way to improve fracs quickly.- Cost of the science is about 10% of well cost.

- Frac optimization should take about 3 wells with science $

- Cost of the science is about 10% of well cost.

- Frac optimization should take about 3 wells with science $

- Frac optimization has taken 10 wells w/o science $

- The difference in production between optimized and

- Frac optimization has taken 10 wells w/o science $

- The difference in production between optimized and unoptimized fracs is about 30 to 50%.unoptimized fracs is about 30 to 50%.

Shale Gas Fracture Optimization

Technology

Transcript of Shale Gas Fracture Optimization