Pratik Rao - Thesis Presentation FINAL

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  • 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

    5

    Interference from nearby wells

    Inadequate build-up and drawdown durations

    Complex model

  • 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

  • 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

  • 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

    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

  • 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.

    Late Middle Early

  • 11

    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 ; 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 ; 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)

    13

    Field Production for Well A Alternating Production

    for Wells A & B

    Field

    Rate

    Well A BHP Well B BHP

  • Production History (2/2)

    14

    Field

    Rate

    Well A BHP

    Well B BHP

  • 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)

  • 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

  • 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.

  • 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

  • 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

  • Well A Closed System Validation

    20

    Reservoir Area = 17.40 km2

  • Preliminary Estimate of the GOIP

    21

    Gas Originally In Place (GOIP) = 14.40 GSm3

  • GOIP from Geologists 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

    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)

    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

    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