Pratik Rao - Thesis Presentation FINAL

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

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

Project Background

Discussion of the Case Study

Conclusions

List of Contents

Well Testing for Reservoir Management:

A Case Study

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.

Considered Points

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Interference from nearby wells

Inadequate build-up and drawdown durations

Complex model

Interference from Nearby Wells

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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

Build-Up and Drawdown Durations: Standard Approach

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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

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

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Alternative Approach Workflow C

on

str

ain

t

Start!

Using log-log plot, match early and middle time models.

Set Initial Reservoir Pressure (from WFT/RFT).

STEP

2

Run sensitivities on boundary distances to match the pressure history.

STEP

1

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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.

Late Middle Early

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List of Contents

Well Testing for Reservoir Management:

A Case Study

Project Background

Discussion of the Case Study

Conclusions

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

Production History (1/2)

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Field Production for Well A Alternating Production

for Wells A & B

Field

Rate

Well A BHP Well B BHP

Production History (2/2)

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Field

Rate

Well A BHP

Well B BHP

Build-Ups Comparison for Well A

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Build-up from 05/10/2012 (~103 days) Build-up from 19/01/2013 (~39 days) Build-up from 09/03/2013 (~220 days)

Horner Match

Log-Log Match

Pressure History Match

Interpretation Model

Step 1: Well A Radial Composite Match

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Early Time: Wellbore Storage & Skin

Middle Time: Radial Composite

Late Time: Infinite Lateral Extent

Analysed

build-up

period

Well A Radial Composite Output

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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.

Horner Match

Log-Log Match

Pressure History Match

Interpretation Model

Step 2: Well A Closed System Match

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Early Time: Wellbore Storage & Skin

Middle Time: Homogeneous (outer kh)

Late Time: Closed Rectangle

Analysed

build-up

period

Well A Closed System Output

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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

Well A Closed System Validation

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Reservoir Area = 17.40 km2

Preliminary Estimate of the GOIP

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Gas Originally In Place (GOIP) = 14.40 GSm3

GOIP from Geologist’s Method

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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

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List of Contents

Well Testing for Reservoir Management:

A Case Study

Project Background

Discussion of the Case Study

Conclusions

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

Conclusions (2/2)

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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)

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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