Multi-Rate Multi-Zone Pressure Transient Testing

Mehdi Azari, Ph.D., P.E.Senior Advisor, Reservoir Engineering

Wireline & Perforating ServicesNovember 8, 2007

Well Testing Network, MTM #5Houston, TX, 7-8 November 2007

2

MRMZ Test Events

q = 0

PBU

Conduct flow after flow and pressure buildup in a multi-layered reservoir and monitor:• Layer flowrates and pressures downhole to detect flow stabilization• The corresponding fluid density, capacitance, and temperature • Surface flowrate and pressures

3

Outlinea. Reservoir, well, and tools review

– Well geometry– Well completions and wellbore data– Reservoir parameters– PVT

b. Design of the pressure transient testing– Estimation of stabilized flow

c. Gradient surveys at the end of the final pressure buildup– Fluid density confirmation– Cross reference check of several log acquisition

d. Stationary pressure transient testing and data quality checke. Pressure and rate data

– Adjusting the stationary data to a common datum– Pressure and rate synchronization

f. Layer rates and SIP plots (Emeraude)– Surface and downhole data comparison and validation

g. Pressure transient testing modeling and analyses (Saphir)

a. Reservoir, Well, and Tools Review

5

The Location of the Two SandsMD, ft

21,360.64

21,422

21,503

21,572

21,348

21,340

21,332

21,036

21,434

TVD, ft

16,033.16

16,045.57

16,103.75

16,223.94

16,055.38

16,168.4

16,039.37

15,820.51

16,112.87

Layer 1

Layer 2

h2 gross = 120.19’ TVD

h1 = 12.42’ TVDh1 = 16’ MD

h2 perf = 138’ MD

Halliburton Gauge Location for Stationary Runs

Location of the Downhole Gauge

h2 gross = 150’ MD

h2 perf = 111.07’ TVD

b. Pressure Transient Testing Design

7

Design Criteria

• Stay above Pb by a safety margin of 200 psi– The lowest designed pressure encountered for the

four sensitivity cases studied is over 2,200 psi higher than the bubble point pressure

– Then use a two-phase flow model of saturated oil with water production

• The pressure drop around wellbore should stay below the cohesive strength of the formation rocks and fines to prevent sanding and formation damage

8

Stabilization Time Determination

• The stabilization time for each flow period was assumed as when the designed flowing pressure reached to 2 psi of the final pressure

• A minimum of one hour of undisturbed pressure data for each flow rate change is required

• The stabilization time for the final pressure buildup was defined as when the infinite acting radial flow was established

• Minimum test duration for a homogeneous radial flow profile:

for pressure drawdown and injection

for pressure buildup and falloff

• A minimum of four hours of pressure buildup data is required

μ/khC)s(,t 111903503

2+

>Δ

μ/kheC00,t

s0.1425352 >Δ

9

Designed Flowrate Schedule

FlowrateSchedule Duration qo qw qt

hr STB/D STB/D STB/D

q1 @ 10% 2 1,148.2 38 1,174.72

q2 @ 20% 2 2,296.4 76 2,349.43

q3 @ 30% 2 3,444.6 114 3,524.15

q4 @ 40% 2 4,592.8 152 4,698.87

PBU @ 0% 4 0 0 0

10

MRMZ Design, History Plot

6700

6750

6800

k=500, S=0K=500, S=5 (ref)K=1000, S=0K=1000, S=5

0 2 4 6 8 10 12

0

2000

4000

History plot (Pressure [psia], Liquid Rate [STB/D] vs Time [hr])

11

MRMZ Design, Log-Log Plot

1E-3 0.01 0.1 11

10

100

k=500, S=0K=500, S=5 (ref)K=1000, S=0K=1000, S=5

Log-Log plot: dp and dp' [psi] vs dt [hr]

K = 500 md

K = 1000 md

S = 5

12

MRMZ Design, Semi-Log Plot

-4 -3 -2 -1

6680

6720

6760

6800

k=500, S=0K=500, S=5 (ref)K=1000, S=0K=1000, S=5

Semi-Log plot: p [psia] vs Superposition time

K = 1,000 md

K = 500 md

S = 5

c. Gradient Surveys at the End of the Final Pressure Buildup

14

Gradient Plot of P, T, Density, and Capacitance

Pay

zone

Inte

rval

15

Density and Deviation Angle Cross Plot

Pay

zone

Inte

rval

Pay

zone

16

Static Gradient Surveys

• Between 16,000’-7,000’ TVD the P gradient was 0.301 psi/ft

• The P gradient for the interval of 6,000’-1,000’ TVD was 0.28 psi/ft

• The density of a 31.5 oAPI oil with the given solution gas at the downhole P and T is 43.4734 lb/ft3

• This density is equivalent to 0.697 g/cc or 0.302 psi/ft

• At standard surface conditions the density for the 31.5 oAPI oil is 0.87 g/cc or 0.376 psi/ft

• The P gradient between the PL and the permanent downhole gauge after 5 hrs into the buildup is 0.303 psi/ft.

17

Influence of Well Angle and Flowrate on Density and Capacitance Reading

• Temperature is a “Fullbore Sample Tool” and well angle would not influence its data records

• Pressure readings are from the hydrostatic head of the fluids above it. Small amounts of water in the oil stream will not affect the values recorded

• Density, Capacitance, and Spinner readings are location dependent; well angle and fluid type disturb their values

• Stagnant or stratified water may exist on the low side of a highly deviated wellbore (trough) at low flowrates

• If the Density and Capacitance tools are not well centered they could read from the trough at low flowrates

• The accuracy of the Density and Capacitance readings should improve with flowrate in highly deviated wellbores

e. Pressure and Rate Data

19

Synchronized Pressure Data For All the Gauges and the Corresponding Flowrate Values

5600

5800

6000

6200

Shell Gauge

Halliburton Gauge

0 10 20 30 40

0

5000

History plot (Pressure [psia], Liquid Rate [STB/D] vs Time [hr])

Firs

t PL

Sur

vey

Sec

ond

PL

Sur

vey

Third

PL

Sur

vey

Four

th P

L S

urve

y

Fina

l PB

U

Gra

dien

t Sur

vey

Shu

t-in

PL

Sur

vey

Permanent Downhole

Gauge

20

The P, ΔP, and q for Both PL and the Downhole Gauges

6000

6100

6200

6300 Halliburton Gauge

Shell Gauge

Pre

ssur

e [p

sia]

85

Pre

ssur

e (d

iffer

ence

) [ps

i]

0

2500

5000

Rat

e [S

TB/D

]

20 24 28 32 36 40

Pressure [psia], Pressure [psi], Liquid Rate [STB/D] vs Time [hr]

Stabilized ΔP

Permanent Downhole

Gauge

21

Stabilized Pressure Difference Between the Two Gauges at Different Flowrates

70

75

80

85

90

95

0 1,000 2,000 3,000 4,000 5,000

Stabilized Flow Rate, STB/D

ΔP,

psi

Stabilized DP & q

f. Layer Rates and SIP Plots (Emeraude)

23

Emeraude Plots for the Shut-in Survey with CFS

• Geothermal T Grad. above Top

• Const T profile between Top & Bottom

• Layer 2 does not show any production

• T & q show downward Flow

• Velocity profile shows Layer 2 is taking fluid Layer 1

Layer 2

24

Emeraude Plots for the First Flowrate with CFS

• Geothermal T Grad. above Top

• Layer 2 show some production over entire payzone

• T & q show upward Flow

Layer 1

Layer 2

25

Emeraude Plots for the Fourth Flowrate with CFS

• Geothermal T Grad. above Top

• Velocity profile shows Layer 2 has higher flowrate

• T & q show upward Flow

Layer 1

Layer 2

26

Emeraude Data Used in Saphir Multilayer Analysis

Zone Rates from Production Logging Passes

1st PBU 1st Flow 2nd Flow 3rd Flow 4th

FlowTotal Combined

Flow, STB/DCFS 6 1,581 2,615 3,751 4,611ILS 5 1,525 2,610 3,682 4,533

Stabilized Separator

Flowrate, STB/D0 1,569.2 2,629.2 3,707.68 4,642.1

% Difference Downhole &

Surface+0.8 +0.53 +1.2 -0.7

Spinner type and flowrate validation

27

SIP Plot of the Total Liquid Production for CFS

Layer 1 Layer 2

Layer Pressure, psi

PI, RB/D/psi

g. Pressure Transient Testing Analyses (Saphir)

29

1E-4 1E-3 0.01 0.1 11

10

100

Log-Log plot: dp and dp' [psi] vs dt [hr]

Homogeneous Radial Flow Model Influenced by One Nearby No-flow Boundary, Log-Log Plot

30

Homogeneous Radial Flow Model Influenced by One Nearby No-Flow Boundary, Simulation Plot

5600

6000

6400

0 10 20 30 40

0

5000

10000

History plot (Pressure [psia], Liquid Rate [STB/D] vs Time [hr])

31

Homogeneous Radial Flow Model Influenced by One Nearby No-Flow Boundary, Semi-log and Layer Rates

-5 -4 -3 -2 -1

6100

6200

6300

Semi-Log plot: p [psia] vs Superposition time

0 10 20 30 40

0

4000

8000

12000Layer Rates 1 - (Stab)Layer Rates 2 - (Stab)Layer Rates 3 - (Stab)Layer Rates 4 - (Stab)Layer Rates 5 - (Stab)Layer Rates 6 - (Stab)Layer Rates 7 - (Stab)Layer Rates 8 - (Stab)Layer Rates 9 - (Stab)Layer Rates 10 - (Stab)M1 SandM2 Sand

Layer Rates plot: Downhole Rate [B/D] vs Time [hr]

32

Homogeneous Radial Flow Model Influenced by One Nearby No-flow Boundary, First & Final PBU Periods

1E-3 0.01 0.1 1 101

10

100

A14-Entire Data.ks3 - Shell-R-3F (ref)A14-Entire Data.ks3 - Model1-R-3FA14-Entire Data.ks3 - Shell-1st PBU

Compare files: dp and dp' normalized [psi] vs dt

Example 2

34

The Three Layer Example

Shale Shale

MD, ft

17,772

17,800

17,740.76

17,652

17,625

17,598

17,850

17,828

17,910

17,880

TVD, ft

15,918.54

16,011.70

16,059.23

16,147.28

16,036.79

16,099.29

15,940.26

15,896.82

16,081.67

16,123.31 h3 = 60’ MD

h2 perf = 54’ MD

h2 gross = 56’ MD

h1 perf = 52’ MD

h1gross = 54’ MD

Layer 3

h3 = 47.98’ TVD

Layer 2h2 perf = 43.27’ TVDh2 gross = 44.88’ TVD

Layer 1

h1 gross = 43.44’ TVD

h1 perf = 41.83’ TVD

Deviation

Halliburton Gauge Location for Stationary Runs

36.92

36.74

36.3

22 ft

120 ft

35

Gradient Plot of Density, Capacitance, and Wellbore Deviation

0

5

10

15

20

25

30

35

40

0 2 4 6 8 10 12 14 16

TVD, 1,000 ft

Incl

inat

ion

Ang

le

0.25

0.35

0.45

0.55

0.65

0.75

0.85

Den

sity

, g/C

C

Inclination Angle

Capacitance for Plotting

Density g/C C

Ocean Floor

Some Water

Temperature Effect

Phase Change

Pay

zone

P

ayzo

ne In

terv

al

36

The Synchronized Pressure and Flowrate Data

5600

5800

6000

Pre

ssur

e [p

sia]

0

2500

5000

7500

Rat

e [S

TB/D

]

06:00:00 11:00:00 16:00:00 21:00:00 02:00:0011/24/2006

Pressure [psia], Liquid Rate [STB/D] vs Time [ToD]

Firs

t PL

Sur

vey

Sec

ond

PL

Sur

vey

Third

PL

Sur

vey

Four

th P

L S

urve

y

Fina

l PB

U

Gra

dien

t Sur

vey

Shu

t-in

PL

Sur

vey

37

The SIP Plot for the Total Liquid Production Based on Average of the Two Spinners

y = -0.0952x + 6105.9y = -0.5544x + 6537

y = -0.1911x + 6154

5,550

5,650

5,750

5,850

5,950

6,050

6,150

6,250

6,350

6,450

6,550

-1,000 0 1,000 2,000 3,000 4,000 5,000

Downhole Flowrate, RB/D

Stab

ilize

d pr

essu

re, p

si

N SandO1 SandO2+ShaleLinear (O1 Sand)

Linear (N Sand)Linear (O2+Shale)

N:

O1:

O2:

Layer 1

Layer 2

Layer 3

Layer Pressure,

psi

PI, RB/D/psi

38

The Log-Log Plot of the Data and the Analysis Match for the Final Pressure Buildup

1E-4 1E-3 0.01 0.1 11

10

100

Log-Log plot: dp and dp' [psi] vs dt [hr]

39

The Plot of the Entire Pressure Data and the Analysis Match

5700

5900

6100

0 5 10 15 20 25 30

0

2500

5000

7500

History plot (Pressure [psia], Liquid Rate [STB/D] vs Time [hr])

40

The Semi-Log Plot and the Layer Flowrate Data Match

-4 -3 -2 -1

5650

5750

5850

5950

6050

6150

Semi-Log plot: p [psia] vs Superposition time

0 5 10 15 20 25 30

0

2000

4000

6000

Layer Rates plot: Downhole Rate [B/D] vs Time [hr]