1. eni Ss.p.aA.
upstream &
technical
services
2014-2015 Master in
Petroleum Engineering and Operations
Well Testing for Reservoir Management:
A Case Study
Author: Pratik Nityanand Rao
San Donato Milanese 15 October 2015

2. 2
Well Testing for Reservoir Management:
A Case Study
San Donato Milanese 15 October 2015
Author
Pratik Nityanand Rao
Division eni S.p.A.
Upstream & Technical Services
Dept. RESM
Company Tutors
Enzo Beretta
Giuseppe Tripaldi
University Tutor
Prof. Francesca Verga
Master in Petroleum Engineering & Operations 2014-2015

3. 3
 Project Background
 Discussion of the Case Study
 Conclusions
List of Contents
Well Testing for Reservoir Management:
A Case Study

4. 4
Project Scope
 To verify when the well testing interpretation of permanent
gauges is feasible and helpful for reservoir monitoring.
 To provide a preliminary field characterisation for the case study.

5. Considered Points
5
 Interference from nearby wells
 Inadequate build-up and drawdown durations
 Complex model

6. Interference from Nearby Wells
6
Drawdown Build-Up
 Drawdown interpretation is usually
more reliable because each well
defends its drainage area
 Build-up late time models are
usually disturbed by interference
from nearby wells
Shut-in well
Open well
Drainage area defended
Drainage area encroached

7. Build-Up and Drawdown Durations: Standard Approach
7
IARF (before reaching
boundaries)
Drawdown
(slope = 1)
Build-up
(reservoir
pressure
stabilises)
Sealing Barrier
Duration of radial flow is a function
of well location inside the reservoir

8. Build-Up and Drawdown Durations: Alternative Approach
8
IARF (before reaching
boundaries)
Sealing Barrier
Duration of radial flow is a function
of well location inside the reservoir

9. 9
Alternative Approach WorkflowConstraint
Start!
Using log-log plot,
match early and middle time models.
Set Initial Reservoir Pressure
(from WFT/RFT).
STEP2
Run sensitivities on boundary distances to match the
pressure history.
STEP1

10. 10
Complex Model
Analytical models are inadequate for matching in a single step
Step 1: Early + Middle time for
estimation of wellbore and bulk
reservoir properties.
Step 2: Middle + Late time for
estimation of boundary
distances.
Note: The two sub-models have to be consistent with the reservoir outer permeability because it
is present in the middle time model, which is used in both steps 1 and 2.
LateMiddleEarly

11. 11
List of Contents
Well Testing for Reservoir Management:
A Case Study
 Project Background
 Discussion of the Case Study
 Conclusions

12. 12
Well A Data
Gauge depth 2752 m TVDSS
Well Type Horizontal
Horiz. Net Length 200 m
Completion 7” – 5 ½”; Gravel Pack
General Information of the Field
A
B
2.7 km
Well B Data
Gauge depth 2753 m TVDSS
Well Type Horizontal
Horiz. Net Length 130 m
Completion 7” – 5 ½”; Gravel Pack
Reservoir & Fluid Data
Initial Reservoir
Pressure
372.9 bar
@ Gauge Depth
Lithotype Sandstone
Net pay 14 m
Porosity 23%
Fluid Type Wet Gas
CGR
15 bbl/MMscf
(0.000087)
STm3/Sm3
Specific
Gas Gravity
0.69
Gas FVF 0.0036 Rm3/m3
Gas Viscosity 0.029 cP
Total
Compressibility
1E-4 bar-1

13. Production History (1/2)
13
Field Production for Well A Alternating Production
for Wells A & B
Field
Rate
Well A BHP
Well B BHP

14. Production History (2/2)
14
Field
Rate
Well A BHP
Well B BHP

15. Build-Ups Comparison for Well A
15
Build-up from 05/10/2012 (~103 days)
Build-up from 19/01/2013 (~39 days)
Build-up from 09/03/2013 (~220 days)

16. Horner Match
Log-Log Match
Pressure History Match
Interpretation Model
Step 1: Well A Radial Composite Match
16
 Early Time: Wellbore Storage & Skin
 Middle Time: Radial Composite
 Late Time: Infinite Lateral Extent
Analysed
build-up
period

17. Well A Radial Composite Output
17
Inner Flow Capacity 2750 mD.m
Inner Permeability 200 mD
Outer Flow Capacity 560 mD.m
Outer Permeability 40 mD
Well Skin* -3.60
Total Skin -7.20
Interface Radius 350 m
Storativity Ratio 1
Mobility Ratio 5
Investigation Radius 3260 m
(*) The skin cannot be sub-divided into its components
(mechanical, geometrical and turbulence) because at
the horizontal well, the early time cannot be recognised
on the derivative plot.

18. Horner Match
Log-Log Match
Pressure History Match
Interpretation Model
Step 2: Well A Closed System Match
18
 Early Time: Wellbore Storage & Skin
 Middle Time: Homogeneous (outer kh)
 Late Time: Closed Rectangle
Analysed
build-up
period

19. Well A Closed System Output
19
Gauge Depth 2752 m TVDSS
Initial Reservoir Pressure 372.9 bar
Initial Fluid Regime 1.36 bar/10m
Average Reservoir Pressure 348 bar
Average Fluid Regime 1.27 bar/10m
Depletion 25 bar
Distance (+x) 860 m
Distance (+y) 2300 m
Distance (-x) 1300 m
Distance (-y) 5750 m
Area 17.40 km2

20. Well A Closed System Validation
20
Reservoir Area = 17.40 km2

21. Preliminary Estimate of the GOIP
21
Gas Originally In Place (GOIP) = 14.40 GSm3

22. GOIP from Geologist’s Method
22
 Area = 17.40 km2 = 17,400,000 m
 Net Pay = 14 m (Net-to-gross ratio already factored in)
 Porosity (f) = 0.23
 Irreducible Water Saturation (Swi) = 0.1
 Gas Formation Volume Factor (FVF) = 0.0036 Rm3 / m3
Gas Originally In Place (GOIP) = 14.00 GSm3
Area * Net Pay * f * (1- Swi)
GOIP = ----------------------------------------------
FVF

23. 23
List of Contents
Well Testing for Reservoir Management:
A Case Study
 Project Background
 Discussion of the Case Study
 Conclusions

24. 24
Conclusions (1/2)
CONSIDERED
POINTS
SOLUTIONS
APPLICATION ON
THE CASE STUDY
Interference from
nearby wells
To exploit long
drawdown acquisition (at
constant rate)
Well testing
interpretation was
performed on data that
was unaffected by
interference
Inadequate build-up
and drawdown
durations
Alternative workflow
based on pressure
matching needs:
Reliable initial pressure
from WFT/RFT
At least one build-up
acquisition
Applied
Complex model
1. Divide in sub-models
2. Numerical well
testing software
Option 1 applied

25. Conclusions (2/2)
25
 The standard approach for build-up and drawdown interpretation
cannot be applied to this case study
 The reservoir pressure at gauge depth (2752 m TVDss) after 0.6
GSm3 of cumulative production resulted to be 348 bar, with a
corresponding depletion of about 25 bar
 The average effective gas permeability for Well A was 40 mD
 The skin was about -4, which indicates that the well is not damaged
 The skin cannot be sub-divided into its components (mechanical,
geometric and turbulence) because at the horizontal well, early time
cannot be recognised on the derivative plot
 The preliminary estimate of GOIP was 14.40 GSm3 (after cumulative
production of 0.6 GSm3)

26. 26
Acknowledgements
I would like to thank the Management of Eni
Upstream and Technical Services for permission to
present this work & related results, and RESM
colleagues for the technical support & needed
assistance.
San Donato Milanese 15 October 2015