Day 3 Am - Well Test Toward Reserve Evaluations

WELL TESTING TOWARD RESERVE EVALUATIONS

DAY 3 MORNING

FORMATION/RESERVOIR/WELL TESTING

• KEY ELEMENTS OF TECHNICAL EVIDENCE

– Reservoir Tank

– Hydrocarbon Column

– Reservoir/Formation Properties

– Fluid Properties

– Effective Drainage Area

– Economic Producibility (flow assurance)

– Recovery Factor

–Wells, Facilities and Operation Conditions

Well Test Toward Reserve evaluation 2

WHY WELL TESTING?

• Flow to the surface:

– Producibility

– Flow Potential (initial pressure, PI)

• Proved volume/Drainage Size

– Minimum connected volume

– Drainage area controlled by one well

– Depletion check

• Overall reservoir quality

– Potential impact of faulting and fractures (recovery factor)

– Reservoir surveillance to check connected reservoir size

• Fluid samples

– Hydrocarbons, water


• In its search for new oil and gas reserves the oil industry moves to more remote areas of the world and to technically challenging areas of deep water.

• To be economically viable, the newly discovered fields must be developed and exploited with very few wells.

• This forces the oil companies to concentrate on high quality reservoirs that yield highly productive wells with large reserves per well.

• High costs prohibit extensive appraisal activity and drive development decisions based on very few wells.

• These limited reservoir penetrations are often logged extensively using modern formation evaluation tools. However, the acquired data cannot confirm that the wells will drain sufficient reserves.

• Well testing still remains the only method for direct evaluation of reservoir connectivity over large distance from the well.

SPE 102483

TO TEST OR NOT TO TEST: TRUE BELIEVERS


TO TEST OR NOT TO TEST

• ENVIRONMENTAL CONSIDERATION…

– Quick and accurate pressures? reliable?

– Environmentally friendly? no flaring, no spills?


Well Test Toward Reserve Evaluation

• Key Technical Procedures

– Design a well test to understand » To prove it flow to an minimal period of time and monitor a stabilized

flow rate and wellhead pressure

» To have proper sequences to detect reservoir limit, if assumable

» To integrate the geological model into the conceptual reservoir tank and make assumptions (distance from the well to all potential boundaries)

– Potential material balance in reservoir management » To use the same pressure gauge to detect a potential pressure

depletion in the reservoir

» To construct P/Z vs. cum gas plot and map IGIP


Well Test Toward Reserve Evaluation

• Fundamentals

– Reservoir Tank Model:

» Cheese cake, shoebox

– Material Balance

» Record produced volume at surface while watch what pressure loss at the downhole

» All concepts about reservoir limit test, average pool pressure, minimal connected volume, require such material balance assumption


AVERAGE RESERVOIR PRESSURE

• Three Possible Scenarios:

– Well test data show closed-reservoir effects » Only in this scenario, reservoir connected volume can be estimated

– Well test data show no evidence of reservoir limit or boundaries

– Well test data show evidence of some sort of boundary effect, but no conclusively closed-reservoir characteristics » In these two scenarios, you need to assume reservoir boundary dimensions,

and make assessments of the “minimum connected reservoir volume” with the test data

Note: All reservoirs have boundaries; if a well test does not see boundary evidence, one can NOT interpret the current (average) reservoir pressure


RADIUS OF INVESTIGATION

borehole

Pf

r

formation pressure

depth of investigation

Pdd

drawdown pressure



t

invC

tkr

948

(oilfield unit system)

Input Matrix 1 bbl = 5.6146 cf

net pay = 150 ft

wellbore radius = 0.1 ft

oil flow rate = 177 stb/day

porosity = 0.15

Skin = 0

permeability = 10 md

total compressibility = 0.00000703 1/psi

viscosity = 1 cp

water saturation = 0.2

FVF = 1.2 RB/STB

flowing radius of connected connected

timeinvestigation area volume

hrs ft acres bbl

0.0001 1 0.00 4.4

0.01 10 0.01 438.0

1 100 0.72 43795.2

100 1000 72.16 4379518.2

1000 3163 721.62 43795181.5

10000 10002 7216.21 437951815.4



g

ets

k

rCt

2948

If we want to know how long it takes to reach the boundary of a fix-sized reservoir and arrives stabilization (pseudo-steady state flow)

gas gravity = 0.6

temperature = 210oF

pressure = 3500 psi

viscosity = 0.02 cp

total compressibility = 0.000247 1/psia

porosity = 0.1

Stablization Time vs Drainage Area

A = 40 A = 640

(acres) (acres)

K ts ts

(md) (hours) (years) (hours) (months) (years)

0.01 25946.53 2.962 415144.56 576.59 47.39093

0.1 2594.65 0.296 41514.46 57.66 4.739093

1 259.47 0.030 4151.45 5.77 0.473909

10 25.95 0.003 415.14 0.58 0.047391

100 2.59 0.000 41.51 0.06 0.004739

1000 0.26 0.000 4.15 0.01 0.000474

0.01

0.1

1

10

100

0 1 10 100 1000 10000 100000 1000000stabilization time (hrs)

reserv

oir p

erm

eabili

ty (

md

)

40 acres

640 acres


RESERVOIR CONNECTED VOLUME

tt

invC

tkt

C

ktr

94844

tSC

hkShrV w

t

winvinv )1(4)1(2

wwoort SCSCCC

Note: the connected volume under investigation during a well test has a lot to do with pore volume decompression as a result of the removal of certain reservoir fluids. Oil reservoirs (saturated or undersaturated) are more difficult than gas reservoirs for reservoir engineers to get right the total compressibility


t

invC

tktr

9484

1.6 km

1.6

km

800 m

640 acres / section

Wabamun Dolomitized Rock Cretaceous Tight Rock

viscosity = 0.02 cp viscosity = 0.017 cp

porosity = 15 % porosity = 8 %

Ct = 0.00025 1/psi Ct = 0.0005 1/psi

distance = 1600 m distance = 800 m

k (md) hours days k (md) hours days

1 19591.6 816.3 0.01 444075.4 18503.1

10 1959.2 81.6 0.05 88815.1 3700.6

50 391.8 16.3 0.1 44407.5 1850.3

100 195.9 8.2 0.5 8881.5 370.1

200 98.0 4.1 1 4440.8 185.0

A Devonian well, Leduc, Wabamun, Nisku, Swanhills, could take days for the pressure perturbation to travel across one section and reach the next spacing unit, through high-k conduit. It means that we could see well rate/pressure interference once the gas is onstream, & exercise gas material balance to estimate IGIP from all single wells, or from the entire pool

If we do not hit any permeable streaks in a Cretaceous formation, a transient flow will last from 1 year to possibly more than 10

years before any attempt to deplete the pressure of any one of the other three wells

within the same section

DRAINAGE AREA & DOWNSPACING


WELL TEST TOWARD RESERVE EVALUATION

• Only multi-well communication tests (interference or pulsing) give the most reliable assessment of effective drainage size.

– Deigned interference test: one active well (injector/producer) emitting pressure pulses to another adjacent monitor well whose downhole gauge receives pressure changes.

– Pulsing Test: a series of pressure up/down sequences from the active well is supposed to be “seen” from the monitor well.

– Hydrodynamics/Production: a new drill in the existing field allows to assess the initial pressure data

producer

monitor

R

Bookable Drainage Area: (depends on the drawdown at the monitor well & reservoir simulation results) • proved: 1.25 A ~ 1.5 A • probable: 2 A

2RπA


0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

15:00 04:00 20:15 05:30 02:30 17:30 03:30 13:00

Time of day (hrs)

Tubin

g P

ressure

(psia

)

0

2

4

6

8

10

12

14

16

Gas R

ate

(m

mscf/

d)

Clean-up

Sulphur

Sampling

Initial flow

Attempt

10 mmscf/d

10 mmscf/d

Flow for 6

hrs

14 mmscf/d

Flow for 12 hrs

4083 psi

(6hrs)

4094 psi

(8hrs)

4092

(17hrs) 4076 psi

FIELD EXAMPLE: GAS WELL-1

FIRST PBU SECOND PBU THIRD PBU



Two Lakes BP Two Lakes 3-3 AOF

10-4 10-3 10-2 10-1 100 101 102

10

-510

-410

-310

-2

Delta Pseudo-T (hr)

DP

& D

ER

IVA

TIV

E (

MP

SI2

/CP

/MS

CF

/D)

2006/09/01-0511 : GAS (PSEUDO-PRESSURE)

Linear-Composite 2-Zone

** Simulation Data **

well. storage = 0.0566 BBLS/PSI

Skin(mech) = 26.6

permeability = 5.58 MD

X-Interface(1) = 1310. FEET

Mob.ratio(1) = 0.00579

Stor.ratio(1) = 0.0111

Turbulence = 0. 1/MSCF/D

Initial Press. = 5914.36 PSI

Skin(mech)+DQ = 26.6

Smoothing Coef = 0.,0.

Static-Data and Constants

Volume-Factor = 0.6647 RB/MSCF

Thickness = 90.00 FEET

Viscosity = 0.02771 CP

Total Compress = .9155E-04 1/PSI

Rate = -10650. MSCF/D

Storivity = 0.0004944 FEET/PSI

Diffusivity = N/A FEET^2/HR

Gauge Depth = N/A FEET

Perf. Depth = N/A FEET

Datum Depth = N/A FEET

Analysis-Data ID: GAU001

Based on Gauge ID: GAU001

PFA Starts: 2006-09-01 00:03:18

PFA Ends : 2006-09-01 10:12:12


0. 100. 200. 300. 400. 500. 600.

-5000.

5000.

Time (hours)

MS

CF

/D


0. 100. 200. 300. 400. 500. 600.

0.

1000.

2000.

3000.

4000.

5000.

PS

I


SELECTION OF PRESSURES DATA (PSI)

Gauge-Data ID: GAU001


Total Raw points = 86212

Set 7 rates (max=100000)

Loaded 638 points (max=100000)

Pressure Select Mode: MANUAL

Rates Cum. Prod.= 2107759.00 BBLS












TEST SEQUENCE DERIVATIVE PLOTS FOR ALL 6 TRANSIENTS



TL3-3 All Three

10-4 10-3 10-2 10-1 100

10

-510

-410

-310

-2

Delta Pseudo-T (hr)

DP

& D

ER

IVA

TIV

E (

MP

SI2

/CP

/MS

CF

/D)

106/09/01-0511 : N/A




Skin(mech) = 26.6



Mob.ratio(1) = 0.00579











Rate = -10650. MSCF/D








PFA Starts: 2006-09-01 00:03:18

PFA Ends : 2006-09-01 10:12:12

TL3-3 All Three PBU

10-4 10-3 10-2 10-1 100 101 102

10

-510

-410

-310

-2

Delta Pseudo-T (hr)

DP

& D

ER

IVA

TIV

E (

MP

SI2

/CP

/MS

CF

/D)

106/09/03-1658 : N/A




Skin(mech) = 26.6



Mob.ratio(1) = 0.00579











Rate = 14200. MSCF/D








PFA Starts: 2006-09-01 00:03:18

PFA Ends : 2006-09-28 19:19:06

THREE DRAWDOWNS THREE BUILDUPS

WE HAVE DEMONSTRATED A GREAT RATE – PRODUCTIVITY BUT WE GOT NO UNAMBIGUOUS ANSWER TO PROVED VOLUME!


GAS WELL-2 FROM THE SAME POOL

0

2

4

6

8

10

12

14

16

18

0:00:00 0:00:00 0:00:00 0:00:00 0:00:00 0:00:00 0:00:00 0:00:00 0:00:00

Date

Ra

w G

as R

ate

(m

mscfd

)

3h45m3h

3h45m

18.5h



0. 200. 400. 600. 800.

-50

00.

5000.

15000.

Time (hours)

MS

CF

/D

0. 200. 400. 600. 800.

0.

1000.

2000.

3000.

4000.

5000.

PS

I


SELECTION OF PRESSURES DATA (PSI)







Rates Cum. Prod.= 2848957.00 BBLS













10-3 10-2 10-1 100 101

10

-31

0-2

Delta-T (hr)

DP

& D

ER

IVA

TIV

E (

PS

I/S

TB

/D)

PD=1/2

2006/01/27-0200 : OIL

CONNECTED RESERVOIR VOLUME

SPE 102483


• The test sequences that are not suited for evaluation of connected reservoir volume in reservoir appraisal:

– Reservoir limits tests

– Single-PBU tests

• The test sequence tailored for evaluation of reservoir volume is based on material balance considerations:

– Extract a certain volume of fluid from the reservoir

– Measure the change of reservoir pressure resulting from this production

– Given compressibility of rock-fluid system, translate the cumulative volume produced and the pressure change into the reservoir volume

CONSIDER PROVED CONNECTED VOLUME

SPE 102483


• Well Test Objective For Proved Volume:

– Prove that the well is connected to the reservoir volume Vt

• Well Test Design Goals:

– Design a well test that will provide sufficient information to conclude that the connected reservoir volume is indeed at least Vt

– Do not over design the test. Achieve this objective with minimum test duration, fluid production and flaring

• Input To Well Test Design:

– The reservoir volume to be proved by test Vt

– The targeted reservoir pressure change dP

– Expectations of reservoir, rock and fluid properties SPE 102483

WELL TEST DESIGN FOR PROVED VOLUME


• The volume of fluid to be produced during Main Flow Period:

• The duration of Main Flow Period

• The duration of Final PBU

PVCV tt

SPE 102483

wq

Vt

kSH

CVt

o

tt

4

WELL TEST DESIGN FOR PROVED VOLUME


SPE 102483

PTA ANALYSIS FOR PROVED VOLUMES

• Well test design to prove connected volume revolves around the following considerations:

– Produce appropriate volume of fluid

– Quantify the reservoir pressure change caused by this production

– Translate this pressure change into the connected reservoir volume

• Analysis of well test data does not normally follow this sequence directly.

– The reason: there is no simple way to translate the bottom-hole pressure into the average reservoir pressure needed to determine the reservoir volume


PTA ANALYSIS FOR PROVED VOLUMES

• An alternative approach – honor all the relevant test pressure data with a model that simulates the fluid flow in the reservoir during the test.

• The model is calibrated to reproduce:

– The relevant pressure transient behavior during each of the PBU’s

– Simultaneously reproduce the late time pressure data during the PBUs before and after the Main flow period

• This model then correctly reflects the volumetric properties of the part of the reservoir investigated by the test and is used to quantify the connected reservoir volume supported by the test data.



4-9 fi fth buildup derivative

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

10

510

610

710

8

Delta Pseudo-T (hr)

DP

& D

ER

IVA

TIV

E (

KP

A2

/PA

S/M

3/D

)

106/10/25-1557 : N/A

Smoothing Coef = 0.,0. Static-Data and Constants

Volume-Factor = 5.351 M3/KM3

Thickness = 29.87 METRE

Viscosity = 0.01900 uPS.S

Total Compress = .1131E-04 1/KPA

Rate = 320000. M3/D

Storivity = .2027E-04 METRE/KPA

Diffusivity = N/A METRE^2/HR

Gauge Depth = N/A METRE

Perf. Depth = N/A METRE

Datum Depth = N/A METRE



PFA Starts: 2006-10-22 16:27:29

PFA Ends : 2006-11-30 09:05:59



4-9 all buildup derivative

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

)

UNIT SLP

ENDWBS

STABIL

HALF SLP

FAULT


well. storage = 0.00355 M3/KPA

Skin(mech) = -3.83


Perm-Thickness = 29.0 MD-METRE

Half.Length = 60.5 METRE

Turbulence = 0. 1/M3/D

P-extrap. = 38092.6 KPA

+x Distance = 115. METRE

R(inv) at 0.7890 hr = 25.1 METRE







Rate = 320000. M3/D


Diffusivity = 267.4 METRE^2/HR






PFA Starts: 2006-10-22 16:27:29

PFA Ends : 2006-11-30 09:05:59


GAS MATERIAL BALANCE USING WELL TEST

• Only for gas reservoirs/wells, days of flow tests can be analyzed for “minimum volume”

• Record BHP pressure data when at least days of flow production are carried (single downhole gauge minimizes pressure reading errors)

• Compare the final buildup pressure with the initial pressure, construct P/Z vs. cum gas volume plot, estimate IGIP

• Caution: – Low perm reservoirs do not work

– Hours of flow do not work

– Low rate flows do not work

Pi

cleanup main flow

main buildup

Pave

Gp

Pi

cleanup main flow

main buildup

Pave

Gp

P/Z

IGIP gas volume Gp


• Evaluation of connected reservoir volume through the use of well testing requires an appropriately designed well test. The volume of fluid production during the test must be correlated with the reservoir volume targeted to be proved by the test.

• As a minimum, the test sequence must include two pressure buildup periods immediately before and after the main production period. These two pressure buildups provide the information that reflects the volume of the part of the reservoir investigated by the test.

• The PBU immediately following the main production period should be the longest of the two PBUs. It provides main data for pressure transient analysis.

WELL TEST FOR PROVED VOLUME


• The reservoir volume proven by the test is not a uniquely defined characteristic. The main uncertainty is associated with total compressibility. Non-uniqueness of test interpretation is also a contributing factor to this uncertainty.

• Evaluation of connected reservoir volume through well testing is most suitable for high quality reservoirs where materially significant reservoir volume may be proved in a test of reasonable duration.

• The use of well testing for evaluation of connected volume and reservoir connectivity discussed here is limited to single phase reservoir conditions.

• An appropriately designed and executed well test that confirms good reservoir connectivity may potentially decrease the number of wells required for appraising the field and reduce the overall cost of the reservoir appraisal program.

WELL TEST FOR PROVED VOLUME


• Non-uniqueness of PTA interpretations

– Turn it into an iteration procedure with geologic/geophysical pictures

– Minimize estimated parameters

– Create one major flow/buildup event

• Key assumptions

– Reservoir models: Shoe-box or cheese cake

– Total compressibility

• Other Important Considerations

– One gauge at the entire test event close to perf-depth (surface readout possible)

– Softwares with good features (Saphir, PanSystem, PIE)

WELL TEST CHALLENGES


virgin pressure

p1

p2

p3

p5

p4

TRANSIENT FLOW & MATERIAL BALANCE

Low permeability prohibits pressure perturbation waves to travel fast enough to influence the other wells


Wolverine Structure Well Testing to Map IGIP

WELL TEST TOWARD RESERVE EVALUATION Devon Wolverine d-66-D Production History

100

1000

10000

9-Nov-04 17-Feb-05 28-May-05 5-Sep-05 14-Dec-05 24-Mar-06 2-Jul-06 10-Oct-06

Cum Gas (mmcf)

Raw

Gas R

ate

(m

cfd

)

0

100

200

300

400

500

600

700

Cum

Gas (

mm

cf)


10-3 10-2 10-1 100 101 102 103 104

10

510

610

710

8

Delta-T (hr)

DP

& D

ER

IVA

TIV

E (

KP

A2

/PA

S/M

3/D

)

2000/11/18-0905 : GAS (PSEUDO-P with Mat.Bal.)






Rate = 84970. M3/D








PFA Starts: 2000-11-12 16:55:00

PFA Ends : 2004-05-11 08:00:00

-9000. -8500. -8000. -7500.

-20

000

.40

000

.80

000

.

Time (hours)

M3

/D

-9000. -8500. -8000. -7500.

-10

000

.10

000

.20

000

.30

000

.40

000

.

KP

A


SELECTION OF PRESSURES DATA (KPA)







Rates Cum. Prod.= 7887224.00 M3












A 2001 PBU test showed 6-7 log cycles: very low permeability

The current PBU test may not able to answer the drainage size question



-200. 0. 200. 400. 600.

-10000.

10000.

30000.

Time (hours)

M3

/D

-200. 0. 200. 400. 600.

-5000.

5000.

15000

.25

000

.

KP

A





















-200. 0. 200. 400. 600.

-10

000

.10

000

.30

000

.

Time (hours)

M3

/D

-200. 0. 200. 400. 600.

50

00.

10

000

.15

000

.20

000

.25

000

.

KP

A
























TRSC (South of the River) Cum Production

0

5

10

15

20

25

30

35

40 0

5

10

15

20

25

30

35

40

45

50

55

60

65

70

75

80

85

90

95

100

105

110

115

120

125

130

135

140

145

150

Bcf

Freq

uen

cy

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Ba

se

Up

Mo

de

l

P50 ~12 Bcf



TRSC Initial Rate South of the River (<= 2160 Hrs)

0

2

4

6

8

10

12

14

16

18

0

2

4

6

8

10

12

14

16

18

20

22

24

26

28

30

32

34

36

38

40

42

44

46

48

50

52

54

56

58

60

Mo

re

MMcf/day

Fre

qu

en

cy

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100% B

ase

Up

Model

P 50 ~ 14 MMcf/day



• four scenarios: OGIP RR RF

– Scenario 1: re-drill d-66-D, 15 bcf 10 bcf 68%

– Scenario 2: infill well 22.5 bcf 14 bcf 67%

– Scenario 3: south well 31 bcf 19 bcf 61%

– Scenario 4: north well 22 bcf 12 bcf 56%

• same reservoir parameters assumed; volumetric OGIP/IP rates from analogies

• key sensitivity analysis:

– k, IP rate, HZ length, recovery factor

• simulation results:

– RF ranges from 30% ~ 60%

– Controlling factor is permeability

– RF approaches 60% when k > 5 md

– RF stays in lower 30% if k < 1 md

– Horizontal wellbore (up to 1200 m) does help RF

– Real challenge: HZ wellbore to intersect frac swarms (to increase overall k)



K=0.1 md +/- 1000 m HZ OGIP=30 bcf RF=56% OGIP=14 bcf RF=43 % OGIP=10 bcf RF=35%

-2000

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

22000

24000

26000

28000

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Date

W ell 1 "wel1"

W olverine d-66-D redrill

W ell Data For W ell 1 "wel1"




-2000

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

22000

24000

26000

28000

0 2000 4000 6000 8000 10000 12000 14000 16000 18000

Cumulative Production, MMscf

W ell 1 "wel1"






0

2000

4000

6000

8000

10000

12000

14000

16000

18000

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Date

W ell 1 "wel1"






2000

2200

2400

2600

2800

3000

3200

3400

3600

3800

4000

4200

4400

4600

4800

0 2000 4000 6000 8000 10000 12000 14000 16000 18000

Cumulative Production, MMscf

Field Avg. Pressure/Z W ell BHP/Z




RATE VS. RESERVE

q1

G1

q2

G2

q3

G3

Although the entry rates for the three wells

are the same, the performances indicate

completely different reserves:

q1 = q2 = q3

G1 < G2 < G3

High entry rate wells may not be deliver

good reserves


RATE VS. RESERVE

q1

G1

q2

G2

q3

G3

Although the entry rates for the three wells

are different, the decline pattern and rate

may lead to the same reserve delivery:

G1 = G2 = G3

q1 < q2 < q3

Low entry rate wells may not be a bad well

and may deliver good reserves

3%

36% 70%



• Wolverine d-66-D Input Parameters

Initial Reservoir Pressure Pi= 33,289.7 kPaa

Reservoir Temperature T=100 oC

Pay Thickness H=15 metres

Porosity PHI=5%

Water Saturation Sw=25%

Z-factor Z=0.985

Production Time = 20 month = 14,400 hrs

Raw Gas Rate = 1.3 mmcfd = 38 e3m

3d

Skin Factor = -5 Perm = 0.16 md



• SCENARIO 1

13.3 bcf

259 ha

Scenario 1 640 acres

(1 DSU)

baseline

1726 x 2 metres

750 m

Buildup Time

3 wks 2 months 6 months 12 months 3 years

(500 hrs) (1440 hrs) (4320 hrs) (8760 hrs) (26280 hrs)

Average Reservoir Pressure 30343.9 30343.9 30343.9 30343.9 30343.9

Gauge Pressure at the end of buildup 23922 25774 27678 28776 30049



• SCENARIO 2

30 bcf

Scenario 2 582.4 ha

1440 acres

3895 x 2 metres

750 m

Buildup Time







• SCENARIO 3

Scenario 3 60 bcf

2880 acres

1164.9 ha

7766 x 2 metres

750 m

150 m

600 m

Buildup Time







• MODERN PRESSURE GAUGE ACCURACY AND RESOLUTION

– Accuracy: » Strain: +/- 0.1% of Full Scale

» Quartz: +/1 (2 psi + 0.01% of reading)

– Resolution (Precision): » Strain: 1~ 5 psi (practically, not gauge calibration/specs)

» Quartz: 0.1 ~ 0.5 psi (practically, not gauge calibration/specs)

– Repeatability:

What we need to see in a buildup test is to see a meaningful change of no less

than 100 kPa or 15 psi, for estimating the average reservoir pressure of the pool in this size



-15000. -10000. -5000. 0.

-10

000

.10

000

.30

000

.

Time (hours)

M3

/D

-15000. -10000. -5000. 0.

0.

50

00.

10

000

.15

000

.20

000

.

KP

A























-1000. -500. 0. 500.

-10000.

10000.

30000.

Time (hours)

M3

/D

-1000. -500. 0. 500.

0.

10000.

20000.

30000.

KP

A






















0. 2000. 4000. 6000. 8000.

0.1

0E

+1

40.1

5E

+1

40.2

0E

+1

40.2

5E

+1

40.3

0E

+1

4

Superposition(T)

M(P

) K

PA

2/P

AS

480. HR 12. HR 0.30 HR 0.0071 HR 480. HR 12. HR 0.30 HR 0.0071 HR

SLOPE


slope of the line = -.12E+11 KPA2/PAS/cycle

extrapolated pressure = 31304.8 KPA

extrapolated pressure = .561E+14 KPA2/PAS

R(inv) at 449.8 hr = 160. METRE

R(inv) at 564.9 hr = 179. METRE

prod. time=15720. hr at rate=35000.00 M3/D

Skin(mech) = -5.63



Turbulence = 0. 1/M3/D






Rate = 35000. M3/D








PFA Starts: 2004-08-12 17:39:57

PFA Ends : 2006-05-03 12:23:00

10-4 10-3 10-2 10-1 100 101 102

10

410

510

610

710

8

Delta-T (hr)

DP

& D

ER

IVA

TIV

E (

KP

A2

/PA

S/M

3/D

)

PD=1/2


Infinite Conductivity Vertical Fracture


well. storage = 0.00580 M3/KPA


Half.Length = 80.0 METRE

fracture-skin = 0.00500


Initial Press. = 33289.7 KPA







Rate = 35000. M3/D








PFA Starts: 2004-08-12 17:39:57

PFA Ends : 2006-05-03 12:23:00



10-4 10-3 10-2 10-1 100 101 102 103 104 105

10

410

510

610

710

8

Delta-T (hr)

DP

& D

ER

IVA

TIV

E (

KP

A2

/PA

S/M

3/D

)







Rate = 84970. M3/D








PFA Starts: 2000-01-15 13:13:13

PFA Ends : 2004-05-11 08:00:00

2006 buildup

2004 buildup

A 2006 well shut-in for pressure buildup was done to estimate the current average pressure level for OGIP estimation. The data was not conclusive, but gave some indication



Wolverine d-66-D Material Balance Reserve Estimate

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Cum (bcf)

P/Z

likely estimate

lower P*

higher P*

final shut-in

min reservepotentiallikely estimate

maxreservepotentialfinal shut-in

the final shut-in pressure of 22,900 kPa

after 3-wk PBU gives 3 bcf reserves

extrapolated pressures

likely reserves

15 bcf

min 11 bcf

max 21 bcf

8,500 kpa line pressure

It appears that d-66-D/b75-D, after on production for 18 months, may be seeing a larger volume



Class Exercise: Design A Well Test for Certain Volume Check

Documents

Day 3 Am - Well Test Toward Reserve Evaluations