Day 3 Pm - Production Forecasting & Decline Curves

PRODUCTION FORECAST & DECLINE CURVES

DAY 3 AFTERNOON


• We drilled a gas well that penetrated two layers of total net pay of 12m + 4.6 = 16.6 m. Now evaluate the formation gas flow rate potential?

–

– (use the excel sheet)

–

–

• How many mmscf of gas this formation & well can produce during its life time?

–

– (scratch your head)

–

ALL DEPTHS ARE mKB

13

12

SURF. CSG.

610.10

11

10

- from bottom up -

Coiled Tbg

1,850.5

9

8

7

6

5

4

3

2

1

2572.52

to

2584.7

2586.84

to

PBTD 2591.41

2,635.40

TOTAL DEPTH

2646.80

12 m

4.6 m

Production Forecast & Decline Analysis 2


Propagating pressure waves through the reservoir (Golan & Whitson, Well Performance, 1991)

Constant rate depletion

Constant pressure depletion


OBJECTIVES OF PRODUCTION FORECASTING

• For new wells

– Estimate well’s initial rate

– Assess well’s total production volume during its life

• For current producers

– Calculate remaining recoverable reserves

– Calculate original recoverable reserves

• For managing reservoir development

– Observe reservoir behavior, independently of operational activities

– Observe interwell communication

• For base management

– Detect operational problems



• Forecasting future production is a critical step of project economics

• Common useful tool: production decline curve analysis

• A “Decline Curve” refers to the production rate of a well vs. time

• Two major significant forecasts:

– Initial rate achieved by flow test & calculations

– Long term trend by tracking/modeling the existing production

Production History

Future Prediction

Flo

w R

ate

qo

Time

Production History

Future Prediction

Flo

w R

ate

qo

Time

Both forecasts require data measurements & formation re-evaluations; Decline curves & forecasting leads to the property’s future life, rate, cumulative volume (EUR or reserves) or fate



• Gradual changes in the production rate of a well can be caused by reservoir and wellbore controlled. They should be sorted out, as early as possible

• Reservoir related production declines:

– Reduction in the average reservoir energy (pressure)

– Increases in the field water cut in water drive pools

• Wellbore controlled production declines:

– Tubing or lifting efficiency/effectiveness reduction

– Perforation; near wellbore conditions (skin, was, salt, asphaltenes, sanding, dirts)

– Multiphasae flow in the wellbore (loading, plugging, water)



• Using past production history to predict future production

• If the history is short

0

1,000

2,000

3,000

4,000

5,000

6,000

12/6/99 4/19/01 9/1/02 1/14/04 5/28/05 10/10/06 2/22/08 7/6/09 11/18/10

Date

Gas R

ate

(m

cf/

d)

History

Future Forecast


0.0

1.0

2.0

3.0

4.0

5.0

Apr-2001 Jan-2004 Oct-2006 Jul-2009 Apr-2012 Dec-2014 Sep-2017 Jun-2020

Date

Gas R

ate

(m

mcfd

)

Gas Rate

Curve Fit

Forecast


• Once production begins, oil, gas, sometimes water, are flowing out of a reservoir, reservoir energy will be depleted, causing the production to decline.

• Decline trends are manifested by seeing a declining well head gas rate, oil rate, or a declining wellhead pressure or bottomhole pressure, or an increasing water-oil ratio (WOR), or a surge of production gas-oil ratio.

• Decline patterns are controlled by reservoir size, energy level, flowing rate, formation characteristics, fluid properties, and operating conditions.

• All wells, reservoirs, and fields, will exhibit production decline trend, as more hydrocarbons have been evacuated from a reservoir of fixed volume, structurally or stratigraphically.


ARPS DECLINE ANALYSIS

• Rate-time decline curve extrapolation is one of the oldest and most often used tools of the petroleum engineer.

• Empirical in original by Arp, with further development by Ramsay, Slider, Gentry, and Fetkovich.

• It starts with Arp’s empirical rate-time equation and assumes constant pressure conditions & boundary-dominated flow

Where:

b = decline curve exponent

Di = Initial decline rate, t-1

q = surface flow rate

t = time



• Early work by J.J. Arps (1945) from his field observations: – Exponential Decline

– Hyperbolic Decline

– Harmonic Decline

• Commonly called “Curve Fitting”; empirically established from wells or fields or pools

• Advantages:

– Easy to analyze and to forecast » Widely used in reserve evaluation & forecast due to its simplicity

• Disadvantages

– Too empirical, without thorough theoretical justification or in-depth understanding



• Exponential Decline

– Rate – Time

– Cum – Time

– Rate - Cum

)1()( tDip e

D

qtQ

tD

i eqtq )(

tDqtq i log)(log

D

tqqtQ i

p

)()(



• Hyperbolic Decline

– Rate – Time

– Cum – Time

– Rate - Cum

bip tDb

Db

qtQ /11)1(1

)1()(

b

i tDbqtq /1)1()(

bb

ii

p tqqDb

bqtQ

11 )(

)1()(



• Harmonic Decline

– Rate – Time

– Cum – Time

– Rate – Cum

)1ln()( tDD

qtQ i

p

tD

qtq i

1)(

)(ln)(

tq

q

D

qtQ ii

p



• Decline Exponent, b, identified/substantiated by field observations

Buick C-86-E Decline Forecast Modeling

10

100

1000

0 25 50 75 100 125 150

Days

Ga

s R

ate

(m

sc

fd)

exponential

hyperbolic

harmonic

0.164 Bcf

Exponential: b=0 fast decline; natural depletion; high pressure pessimistic commonly used as conservative estimate of the base case of proved reserves Harmonic: b=1 slow decline water encroachment/flooding aquifer supplies tight gas; low k rock b>1 also occurs, but always check if it is realistic Hyperbolic: 0<b<1 widely seen in a variety of rocks





SPE 28628

0 < b < 1 b = 0 b=1

“b” is dependent on reservoir drive, # of layers and their sizes, fluids, pressure, etc.


• Estimated Ultimate Recovery (EUR) – Assume the current trend will continue

– Use this trend-line to make forecast future production until it stops


q

Qp EUR

qab

abandonment

Production history



• Nominal Decline

– the fractional change of the oil production rate per unit of time

• Effective Decline

– the effective decline rate is a stepwise function where each step represents the reported production

q

dtdq

dt

qdD

/)(ln

dq

dt

q1

dt

q2

q3

q4

q5 qt

i

iie

q

qqD 1


ARPS DECLINE ANALYSIS FORECASTING

qi

tflat

qab

tlife

DNpflat

Npdecline

Nptotal=Npflat+NPdecline

RF = Nptotal/HIPqi

tflat

qab

tlife

DNpflat

Npdecline

Nptotal=Npflat+NPdecline

RF = Nptotal/HIP

Scoping Economics & Budgetary: Input: Output: Resource Volume Production Forecast Initial & Abandonment Rate Why “Exponential”? fast decline quick payback foreseeable


ARPS DECLINE ANALYSIS (Oil Exponential)

1

10

100

1000

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0

Year

Rate

(b

bl/

d)

Input:OOIP = 500,000 bbl (total oil-in-place)

t flat = 0.5 year (flate rate period)

q i = 500 bbl/day (initial rate)

q ab = 10 bbl/day (abandonment rate)

Expotential Decline

Output:Np f lat = 91,250 bbl (flat period cum production)

D = 0.4465 / year (annualized decline rate)

Np total = 491,825 bbl (total recoverable volume)

RF = 98.4 % (recovery factor)

Decline Duration = 8.8 years (life during decline period)

Project Life = 9.3 years (entire project life)

R/P Ratio = 2.7 years (reserve over production ratio)


ARPS DECLINE ANALYSIS (Gas Exponential) Input:

OGIP = 10.000 bcf (total gas-in-place)

t flat = 1.50 year (flate rate period)

q i = 10.00 mmscf/day (initial rate)

q ab = 0.10 mmscf/day (abandonment rate)

Expotential Decline

Output:Np f lat = 5.475 bcf (flat period cum production)

D = 0.807 / year (annualized decline rate)

Np total = 9.955 bcf (total recoverable volume)

RF = 99.5 % (recovery factor)

Decline Duration = 5.7 years (life during decline period)

Project Life = 7.2 years (entire project life)

R/P Ratio = 2.7 years (reserve over production ratio)

1

10

0.0 1.0 2.0 3.0 4.0 5.0 6.0

Year

Ra

te (

bb

l/d

)

1

10

0.0 1.0 2.0 3.0 4.0 5.0 6.0

Year

Rate

(b

bl/

d)



• Transient Flow – Flow within a reservoir has not reached the reservoir boundaries.

• Pseudo Steady State (PSS) – Flow within a reservoir has reached the reservoir boundaries. Boundary dominated flow.

• Time to Pseudo Steady State – the time it takes to reach boundary dominated flow.

• Multi-layered No-Cross Flow – production of multiple reservoir layers with no “in rock” communication.


PRODUCTION DECLINE ANALYSIS

• You must consider whether you have…

– a single layer or Multi-layer with no crossflow? » Multi-layers will have a longer time to PSS, and a “b” between 0 and 1.

– in transient or psuedo-steady state flow? DCA applies for PSS. » Use caution anytime you DCA during the transient flow period.

– is the reservoir depletion or waterdrive drive? » Forecast “b” and forecast cutoff is dependent on reservoir drive.

– is the rock permeable or tight? » Time to PSS increases for tight rock.

– is the reservoir going to see changing flowing pressure? » The decline trend will change with changing flowing pressures.


Advanced Production Data Analysis & Forecasting

• An Extension of Arps Empirical Equation

• Definitions of Dimensionless Variables:

– dimensionless rate qD

– dimensionless time, tD

FETKOVICH DECLINE ANALYSIS

i

Dq

tqq

)(

tDtD

tDDe

q1

bD

tDbq

/11

1

tDtD

)0( b)0( b



SPE 28628



0

1000

2000

3000

4000

5000

6000

7000

8000

9000

0 100 200 300 400 500 600

Days of Production

Gas R

ate

0

200

400

600

800

1000

1200

1400

1600

Cum

Gas

10

100

1000

10000

10 100 1000

Days of Production

Gas R

ate

10

100

1000

10000

Cum

Gas

Normally we plot q vs. calendar date or q vs. cum data for Arps decline on semi-log scale

If we replot q vs. days of production or cum vs. days of production on log-log scale, we are seeing Fetkovich trend



1.E+03

1.E+04

1.E+05

1.E+06

1.E-03 1.E-02 1.E-01 1.E+00 1.E+01

tDd

qD

d

1.E+00

1.E+01

1.E+02

1.E+03

QD

d

)](

)(

[

]5.

0)

/[ln(

)(

300

,50

wf

pi

psc

weff

esc

Dd

PP

PP

hk

T

rr

TP

tq

q

]5.0)/[ln(]1)/[(5.0

/00633.02

2

weffeweffe

wefftg

Ddrrrr

rCtkt

)]()([)(

)(8.63722

wfpipwetgsc

psc

DdPPPPrrChT

tGTPQ



)]()([

]2

1)[ln(1422

wfi

wa

e

MPDd

g

pmpmh

r

rT

q

qk

)]()([)(

54.56

wfiitMPDd

g

MPDd

ppmpmc

T

q

q

t

tV

gi

wp

B

SVOGIP

000,1

)1(


PRODUCTION DECLINE ANALYSIS

• Transient Flow

– Flow within a reservoir has not reached the reservoir boundaries.

• Pseudo Steady State (PSS)

– Flow within a reservoir has reached the reservoir boundaries. AKA - Boundary dominated flow.

• Time to Pseudo Steady State

– the time it takes to reach boundary dominated flow.

• Multi-layered No-Cross Flow

– production of multiple reservoir layers with no “in rock” communication.



actual time t

q

material balance time te

Q Q

te=Q/q

Constant Rate Decline Actual Decline

actual time t

q=dQ/dt

actual time t

Q Q

Rate Integral = Q/t Actual Decline

material balance time te = Q(t)/q(t) rate integral (normalized) q / (pi-pwf) derivatives - d(q/(pi-pwf)) /d(ln(te))


ADVANCED VARIABLE RATES/PRESSURES


FLOWING MATERIAL BALANCE


SUMMARY OF PRODUCTION & DECLINE

Arps Fetkovitch Blasingame Agarwal & Gardner

Flow Material Balance

Early Production

yes yes yes

Pseudo-Steady State

yes yes yes yes yes

OGIP yes yes yes

EUR yes yes

High K yes yes yes yes yes

Low K yes

Water Drive

yes yes


W-83 Well/Pool Production Data Analysis

MANAGING RESERVE UNCERTAINTY: W-83

• Reservoir Performance Uncertainty

– W-83 Case Study (Gas Well)

– Preliminary Proved and Non-Proved Reserve/Resources Booking & Progression

– Reconcile Production Data with G&G Data

» Drainage Area/Reservoir Tank Size

» Decline Pattern/Rate and Recovery Factor

» Scada Well Performance Monitoring

» Permeability and Well Deliverability

• Constant Reserve Calibration

– Geological Reserves vs. Performance Reserves

– Proved Reserve Promotion/Demotion

» Operation Limits (Mechanical and Economic)

– Well Work Execution Additional Reserve Addition


Descriptions Upper Cretaceous Naturally Fractured Sandstone Perf Depth: 2853 ~ 2560 mKB

Porosity: 4.3% Net Pay: 36 ft Sw: 40% Sg: 60% Tr: 68 oC (154 oF) Pr: 22,340 kPa (3240 psi) Gas Specific Gravity: 0.622 Gas Compressibility: 0.902 FVF: 212 scf/cf Gas Composition: C1: 94.12% C2: 3.37% CO2:1.5%

W-83




Producing zones

• Cretaceous and Upper Jurassic

– Low porosity, permeability

» Fine to coarse grained litharenites and conglomerates

– Cadotte is most predictable

» Blanket sands and conglomerate

» Coarsening upward sequence

– Falher is least predictable

» Narrow shoreline trends

– Gething channel sands and congl.

» Locally significant

– Cadomin conglomerate

» Laterally continuous

» Usually tight

– Nikanassin fluvio-deltaic clastics

» Numerous sands = most reserve potential



Structural Depiction & Fold Style


MANAGING RESERVE UNCERTAINTY: W-83 Similar Formation Production Performance Analogs

1

10

100

1,000

10,000

100,000

0 5,000 10,000 15,000 20,000 25,000

Cum Gas (mmcf)

Raw

Gas R

ate

(m

cfd

)

8-4-63-11W6

6-19-62-12W6

8-30-62-11W6

d-41-G/93-I-15

b-62-G/93-I-15

b-77-A/93-I-15

c-74-G/93-I-15

c-36-A/93-I-15

d-13-A/93-I-15

b-35-A/93-I-15

16-24-62-13W6

11-24-62-11W6

6 mmcfd

Notes:

1. Almost all those wells from Cadotte and

Cad/Nik formations show harmonic declines,

some rapid, others very slow

2. Short time flow test rates may not be

indicative of onstream production performance,

while the initial productions (the early months)

may be better indicate of ultimate deliverabilities

and thus PDP reserves



Analog Well/Formation Performance: IP Rates vs. Cum Gas

(IP rates used the average of the first three months onstream productions)

-

5,000

10,000

15,000

20,000

25,000

30,000

- 5,000 10,000 15,000 20,000 25,000

Cum Gas (mmcf)

Initia

l G

as R

ate

(m

cfd

)

Narraway

N Grizzly

S Grizzly

ARL 8-30

Cadotte

ARL 11-24

Cad/Nik

BP 16-24

Cadotte

Devon 6-19

Cadotte

CNRL c-74-G

Cad/Nik

CNRL b-82-G

Cad/Nik CNRL d-41-G

Cad/Nik

Anderson 8-4

Cadotte

CNRL b-35-A

Cad/Nik

CNRL b-77-A

Nik

CNRL d-13-A

Cad/NikCNRL c-36-A

Cad/Nik

Note:

Overall the higher the IP rates the

greater the cum gas productions

(and thus the greater the PDP

reserves), but the number of wells

in the study is still small to reach

a satisfactory confidence level of

the conclusion.



Deterministic Analysis Min ~ Most Likely ~ Max @PS

Key Knowns

Gas column height ? Structural or stratigraphic play? Sw (estimated from capillary pressures)

Business Cases

Full Cycle Success (unrisked): PS = 75% Raw Recoverable 10 ~ 14 bcf Initial Rate 6 ~ 8 mmcfd Failure (unrisked): PS = 5% Raw Recoverable < 2 bcf Initial Rate < 2.0 mmcfd


MANAGING RESERVE UNCERTAINTY: W-83 Input Summary Table:

Minimum Most Likely Maximum

Porosity 0.034 0.043 0.057

Average net pay thickness (ft) 30 36 65Top of Cadotte Subsea Elevation -1365 -1360 -1355

Abandonment Pressure 2000 4000 7000

Midpoint Column height for water product 150 258 315

Drainage Length of Structure 3 4 10

Reference Column height 230 310 350

constant 13.3 13.4 13.5

Output Summary Table:

Minimum Maximum Mean Std Dev

Category: Default

Recoverable Raw Gas (BCF) 0.562255 51.2969 15.7538 6.54448

Average Reservoir Pressure 22257.4 22406.6 22339.1 19.9629

Average Gas Saturation 0.404257 0.727438 0.59413 0.053572

Average Cadotte Formation Temperature 67.3961 70.0659 68.7686 0.310718

Formation Volume Factor 205.086 207.4 206.384 0.261089

Raw Gas Recovery Factor from Abandoment 0.702434 0.914044 0.821345 0.037001

Total Recovery Factor 0.0561453 0.798478 0.578282 0.10753

Hydrocarbon Pore Volume 450.791 8134.17 3075.58 1065.74

Recovery Factor based on dist. from h20 0.0700025 0.885129 0.688747 0.125756

Parameter in determining RF -2.85238 7.1184 2.23474 1.40961

Range in Column Heights 230.014 350 301.628 18.8855

Transition zone thickness from Porosity

Column Height for zone 1 63.0457 216.985 148.592 21.593

Area for zone 1 corrected for dip 646.668 4168.99 2680.28 514.056

column height for zone 1 161.811 239.258 206.024 10.6919

Transition zone corrected for pressure 108.561 160.024 131.728 9.64774

Gas Density

Z Factor 0.902 0.902 0.902 0

Original Gas-in-place (BCF) 3.90502 70.9246 26.747 9.2866Zone4



Drilling

High angle horizontal well (70 ~ 80 o) (5 o dip) Under balanced coil-tubing

Goals

To intersect natural fractures To maximize reservoir productivity


MANAGING RESERVE UNCERTAINTY: W-83 w-83 Drill Flow Rate vs Pressures (Choke Size: 54/64)

0

5000

10000

15000

20000

25000

0:00 1:12 2:24 3:36 4:48 6:00

Clock Time

Pre

ssure

s (

kP

a)

150

175

200

225

250

Raw

Gas R

ate

(e3m

3/d

)

BHP

WHP

Gas Rate

1 e3m3 = 35 mscf


w-83 Single Point Flow Test (Choke Size Varied)

0

5000

10000

15000

20000

0 4 8 12 16 20 24 28

Elapsed Time (hrs)

Surf

ace G

auge P

ressure

s (

kP

a)

0

50

100

150

200

250

Raw

Gas R

ate

(e3m

3/d

)

Tubing Pressure (kPa)

Casing Pressures (kPa)

Gas Rate (e3m3d)


Ojay 202/a-038-H/093-I-09 Buildup

10-3 10-2 10-1 100 101 102

10

510

610

7

Delta Pseudo-T (hr)

DP

& D

ER

IVA

TIV

E (

KP

A2

/PA

S/M

3/D

)

ENDWBS

PD=1/2

2006/01/02-0154 : GAS (PSEUDO-PRESSURE)

Linear-Composite Dual-Porosity 3-Zone

** Simulation Data **

well. storage = 0.00412 M3/KPA

Skin(mech) = -3.63

permeability = 3.38 MD

X-Interface(1) = 229. METRE

Mob.ratio(1) = 0.253

Stor.ratio(1) = 0.539




omega = 0.319

lambda = 0.140E-05

Perm-Thickness = 37.2 MD-METRE

Turbulence = 0. 1/M3/D

+y boundary = 150. METRE (1.00)

-y boundary = 298. METRE (1.00)

Initial Press. = 21837.0 KPA

Skin(mech)+DQ = -3.63

Smoothing Coef = 0.,0.

Static-Data and Constants

Volume-Factor = 5.425 M3/KM3

Thickness = 11.00 METRE

Viscosity = 0.01830 uPS.S

Total Compress = .2326E-04 1/KPA

Rate = 181000. M3/D

Storivity = .1100E-04 METRE/KPA

Diffusivity = 656.4 METRE^2/HR

Gauge Depth = 2448. METRE

Perf. Depth = 2507. METRE

Datum Depth = N/A METRE

Analysis-Data ID: GAU002

Based on Gauge ID: GAU002

PFA Starts: 2006-01-01 00:00:55

PFA Ends : 2006-01-24 20:30:03

Ojay 202/a-038-H/093-I-09 Buildup

-100. 0. 100. 200. 300. 400. 500.

14000.

16000.

18000.

20000.

22000.

24000.

Time (hours)

pre

ssu

res

(KP

A)

2006/01/02-0154 : GAS (PSEUDO-PRESSURE)

Linear-Composite Dual-Porosity 3-Zone

** Simulation Data **

well. storage = 0.00412 M3/KPA

Skin(mech) = -3.63

permeability = 3.38 MD







omega = 0.319

lambda = 0.140E-05

Perm-Thickness = 37.2 MD-METRE

Turbulence = 0. 1/M3/D

+y boundary = 150. METRE (1.00)

-y boundary = 298. METRE (1.00)

Initial Press. = 21837.0 KPA

Skin(mech)+DQ = -3.63

Static-Data and Constants

Volume-Factor = 5.425 M3/KM3

Thickness = 11.00 METRE

Viscosity = 0.01830 uPS.S

Total Compress = .2326E-04 1/KPA

Rate = 181000. M3/D

Storivity = .1100E-04 METRE/KPA

Diffusivity = 656.4 METRE^2/HR

Gauge Depth = 2448. METRE

Perf. Depth = 2507. METRE

Datum Depth = N/A METRE

Analysis-Data ID: GAU002

Based on Gauge ID: GAU002

PFA Starts: 2006-01-01 00:00:55

PFA Ends : 2006-01-24 20:30:03

Single Point Well test of Demonstrating Flow Assurance & Producibility


MANAGING RESERVE UNCERTAINTY: W-83 What was learned from the well test: Able to Produce Gas Commercially Formation Pressure from PBU = 21837 kPaa (3167 psi) Recorder Depth = 2448 mTVD MPP Depth =2550 mTVD Formation Pressure MPP = 21999 kPaa (3190 psi) Static Gas Gradient = 1.588 kPa/m (before & after flow/PBU) Temperature at Recorder Depth = 80 oC Formation Pressure from Previous Studies = 22340 kPaa Temperature from Previous Studies = 68 oC (depth reference to be checked)

t

invC

tkr

948

Parameters Example

k Permeability md 3.380

Porosity 0.0430

Viscosity cp 0.0177

Ct Compressibility 1/psi 0.000114

t Flowing Time hours 24.0

r Radius of Investigation ft 994.83

m 303.23


MANAGING RESERVE UNCERTAINTY: W-83 Total Effective Permeability k=3.38 md

Skin = -3.63 (connected to natural fractures)

Minimum Depth of Drainage Radius = 303 m (70 acres as a result of this flow test)

298 m

150 m

220 m


Initial Volumetric Bookings

Proved Drainage Area: 1124 acres (1.5 DSU) OGIP: 9.66 bcf Recovery Factor: 58% Raw Recoverables: 5.58 bcf Possible Compression Reserves Probable Additional Drainage: 1230 acres OGIP: 10.57 Recovery Factor: 58% Raw Recoverables: 6.13 bcf Note: Before on-stream, SEC allows 1+8 adjacent DSU, if believed capable producing; once on-stream, 1 DSU becomes converted to PDP while the adjacent 8 DSU remain to be PUD

W-83

1 DSU = 300 ha =741 areas



• Production Data: Rate and Pressure Decline Analysis

– WHP: inlet and pipeline pressure fluctuations

– Raw gas production decline: Arps decline analysis

– Integration of well pressure and production rate data » Fetkovitch: constant WHP when rate declines

» Blasingame: variable rate & WHP during production

» Agarwal-Gardner:

» Flowing Material Balance: late-time boundary-dominated flow

– Well head temperature

– Water gas condensation/water production » Transition water breakout

– IPR curves » Liquid loading







Results as of May 31, 2006 (45 days into the production)

Harmonic decline b = 1.56 Qi = 8,000 mscfd Index = 0.0162

MANAGING RESERVE UNCERTAINTY: W-83 W-83 Daily Production

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

24-Mar-06 13-May-06 2-Jul-06 21-Aug-06 10-Oct-06 29-Nov-06 18-Jan-07

Date

Raw

Gas R

ate

(m

mcfd

)

0

50

100

150

200

250

Raw

Gas R

ate

(e3m

3d)

mmcfd

May '06 Forecast

e3m3d



• Production Rate Decline Related to……

– Reservoir Production mechanism: natural depletion? water drive?

– Wellbore problems: liquid loading, multiple phase, non-hydrocarbon?

– Reservoir characteristics:

» Smaller reservoir tank? Compartmentalized?

» Misinterpreted reservoir parameters (net pay, transition)?

» Low matrix permeability? Lack of natural fracture networks/connectivity?

• “Proved” Reserve Calibrated and Re-Filed ……

– How much producible/economic reserve this well can “see”?

– New reserve/resource estimate and new forecast

– Well workover/facility options?

» Tubing size change? Acidizing/fracturing? Compressor?


W-83 Well Reserve Analysis (as of May 31, 2006)

Volumetric Estimates Performance Analysis

OGIP 9.66 bcf 2.22 bcf

RF 57.83%

Raw Recoverable 5.58 bcf 1.8 ~ 2.0 bcf

Defined Drainage 1124 acres 250 acres ?

Permeability 3.38 md (PTA) 0.4 ~ 1.5 md (RTA)

Skin -3.63 (PTA) -4.5 (RTA)

Netpay 36 ft (11 metres) 36 ft (11 metres)

Porosity 4.3% 4.3%

Sw 40% 40%

Without compression, the well will likely see (against the line pressure of 8500 kPa or 1250 psi)

a PDP reserve around 1.8~2.0 bcf in 3 years

by Christmas 2006, the cum production will be 0.95 bcf

With compression, at 3500 kPa (500 psi) well head pressure, the well will probably see

a total PDP reserve of 2.2 ~ 2.5 bcf in 3 years




Pr @June 2006

Pr @Oct 2006

8500 kPa Line Pressure

3500 kPa Line Pressure

We are here today

Pr @April 2006


concave downward reaching boundaries?

high reserve low reserve

high perm

low perm

early flow transient

late-time flow boundary-dominated








Results as of December 12, 2006 (240 days into the production)


W-83 Daily Production

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

24-Mar-06 13-May-06 2-Jul-06 21-Aug-06 10-Oct-06 29-Nov-06 18-Jan-07

Date

Ra

w G

as R

ate

(m

mcfd

)

0

50

100

150

200

250

Ra

w G

as R

ate

(e

3m

3d

)

mmcfd

May '06 Forecast

e3m3d



W-83 Production & Forecast

1,000

10,000

4-Mar-06 23-Apr-06 12-Jun-06 1-Aug-06 20-Sep-06 9-Nov-06 29-Dec-06

Date

Raw

ga

s R

ate

(m

cfd

)

0

200

400

600

800

1,000

Cu

m P

rod

uc

tio

n (

mm

cf)

Raw Ga Rate

Forecast

Cum Forecast

Cum Production

Christmas

0.95 bcf

2.2 mmcfd

we are here today



MANAGING RESERVE UNCERTAINTY: W-83 w-83 Well Gas Material Balance

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50

Cum Gas Production (bcf)

P/Z

, psi

Date P/Z Cum P psi

15-Apr-2006 3635 0 3255

15-May-2006 3430 0.209 3046

16-Jun-2006 3279 0.362 2901

16-Jul-2006 3125 0.484 2756

15-Aug-2006 2966 0.592 2611

15-Sep-2006 2804 0.688 2466

16-Oct-2006 2638 0.771 2321

15-Nov-2006 2470 0.85 2176

15-Dec-2006 2300 0.952 2031

Op Limit 529 1.625 508

If we are able to simulate & predict the performance of this well……

Then a follow-up in-production well pressure buildup should give an answer (by checking the current average reservoir pressure)

w-83 Well Power Outage between July 7-10, 2006

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

7-Jul-2006 7-Jul-2006 8-Jul-2006 8-Jul-2006 9-Jul-2006 9-Jul-2006 10-Jul-2006 10-Jul-2006

Date

Wellh

ead P

(kP

a)

WellHead P BTHP

kpaa kPaa

1.5 kpa/m

12022 15772

12140 15890

12267 16017

12389 16139


Modified Reserve Bookings

Proved Drainage Area: 250 acres? (0.34 DSU) OGIP: 3.26 bcf? Raw Recoverables: 2.22 bcf? Possible Compression Reserves: 0.5 bcf? Probable Resources (non-proved) Total Drainage: 2104 acres? OGIP: 18.08 bcf? Recovery Factor: 58%? Raw Recoverables: 10.58 bcf?

1 DSU = 300 ha =741 areas

W-83



MANAGING RESERVE UNCERTAINTY: W-83 w-83 Well Rate vs Cum Forecast

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

0 500 1000 1500 2000 2500 3000 3500

Cum Gas (mmcf)

Raw

gas R

ate

(m

cfd

)

Raw Gas Rate

Forecast

economic/ operation limits

Compression?



18 months

10-3 10-2 10-1 1.0 101 1022 3 4 5 6 7 8 2 3 4 5 6 7 8 2 3 4 5 6 7 8 2 3 4 5 6 7 8 2 3 4 5 6 7 8

Material Balance Pseudo Time

10-2

10-1

1.0

101

2

3

4

5

7

2

3

4

5

7

2

3

4

5

7

No

rmalized

R

ate

, In

teg

ral, D

eri

vati

ve

Blasingame Typecurve Analysisa-38-H cadotte 2007 october

10-4 10-3 10-2 10-1 1.0 1012 3 4 5 678 2 3 4 5 67 2 3 4 5 678 2 3 4 5 67 2 3 4 5 6 7 2 3 4 5 678

Time

10-3

10-2

10-1

1.0

101

2

3

4

6

8

2

3

4

6

8

2

3

4

6

8

2

3

4

6

8

Rate

, C

um

ula

tive P

rod

ucti

on

Fetkovich Typecurve Analysisa-38-H cadotte 2007 october

10-5 10-4 10-3 10-2 10-1 1.0 101 1022 3 4 56 8 2 3 4 56 8 2 3 4 56 8 2 3 4 56 8 2 3 4 56 8 2 3 4 56 8 2 3 4 56 8

Material Balance Pseudo Time

10-2

10-1

1.0

101

102

2

3

5

7

2

3

5

7

2

3

5

7

2

3

5

7

2

3

5

7

No

rmalized

R

ate

, D

eri

vati

ve

Agarwal Gardner Rate vs Time Typecurve Analysisa-38-H cadotte 2007 october

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 1.80 2.00 2.20 2.40 2.60 2.80 3.00

Cumulative Production, Normalized Cumulative Production , Bscf

0

1

2

3

4

5

6

7

8

9

10

11

12

13

14

Pro

du

cti

vit

y In

dex , M

Mscfd

/(10

6p

si2

/cP

)

0.000

0.001

0.002

0.003

0.004

0.005

0.006

0.007

0.008

0.009

0.010

0.011

0.012

0.013

No

rmalized

Rate

, M

Mscfd

/(10

6p

si2

/cP

)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

2200

2400

2600

2800

3000

3200

3400

3600

P/Z

* , psi

Flowing Material Balancea-38-H cadotte 2007 october

Original Gas In Place

LegendP/Z Line

Flowing P/Z*

Productivity Index

Decline FMB


Documents

Day 3 Pm - Production Forecasting & Decline Curves