Reservoir Engineering Overview

Reservoir Engineering Overview

Presented by: Aung Myat Kyaw Reservoir

Engineer MPRL E&P

Pte, Ltd.

Myanmar Engineering Society20-Dec-2008

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Overview Objectives

Introduction to reservoir management and it’s benefits

Introduction to reservoir simulation and it’s benefits

Introduction to reserve estimation and it’s benefits

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Reservoir Management - Definition

The use of available resources (human, technological and financial) to maximize profits from a reservoir by optimizing recovery while minimizing capital investments and operating expenses(*)

(*)“Integrated Reservoir Management” by Abdus Satter, SPE, James E. Varnon, SPE and Muu T. Hoang, SPE, Texaco Inc., SPE 22350 JPT, December 1994

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Reservoir Management Approach

1. Timing

2. Integration of Geoscience and Engineering

3. Reservoir Management Process

4. Establishing Purpose of Strategy

5. Developing a Plan

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Reservoir Management Approach

1. TimingThe ideal time to start managing a reservoir is at discovery. However it is never too late to initiate a well-thought-out, coordinated reservoir management program. An early start not only produces better overall project planning, implementation, monitoring, and evaluation but also saves money in the long run, maximising the profits.

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Reservoir Management Approach

2. Integration of Geoscience and EngineeringSynergy and team concepts are the essential elements for integration of geoscience and engineering. Integration involves people, technology, tools and data.

Its success depends on the following An overall understanding of the reservoir

management process, technology and tools through integrated training and integrated job assignments.

Openness, flexibility, communication and coordination

Working as a team Persistence

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Reservoir Management Approach

3. Reservoir Management Process

Reservoir Management Approach4. Establishing Purpose of Strategy

a. Reservoir Characteristics

b. Total Environmenti. Corporate – goals, financial strength, culture

and attitude.ii. Economic – business climate, oil/gas price,

inflation, capital, and personnel availability.iii. Social - conservation, safety and

environmental regulations.

c. Technology and Technological Toolbox

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Reservoir Management Approach

5. Developing a Plan

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Integration for Effective Reservoir Management

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Standard Technology and Technological Toolbox

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It is becoming more recognized that reservoir management is not synonymous with reservoir engineering and/or reservoir geology. Success requires multidisciplinary, integrated team efforts. The players are everyone who has anything to do with the reservoir.

Legal

Land

Environment

Service

Research &Development

Gas andChemical

Engineering

Production &Operation

Engineering

Design &ConstructionEngineering

DrillingEngineering

Economics

ReservoirEngineering

Geology &Geophysics

Management

ReservoirManagement

Team

Legal

Land

Environment

Service

Research &Development

Gas andChemical

Engineering

Production &Operation

Engineering

Design &ConstructionEngineering

DrillingEngineering

Economics

ReservoirEngineering

Geology &Geophysics

Management

ReservoirManagement

Team

Conclusion For Reservoir Management

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Reservoir Simulation

As applied to petroleum reservoirs, simulation can be stated as:

The process of mimicking or inferring the behavior of fluid flow in a

petroleum reservoir system through the use of either

physical or mathematical models.

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As used here, the words petroleum reservoir

system include the reservoir

rockand fluids, aquifer, and

the surface and subsurface

facilities.

Reservoir Simulation

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MODELING METHODS

• Any problem is solvable if you can make assumptions- the key is determining the right assumptions.

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Decline Curve Material Balance Numerical SimulationField Measurements

Well Pressures * *Oil, Water, Gas Prodution * * *Production Logs *Well Tests *

Reservoir Description

Geometry *Petrophysical Properties *OWC's, GOC's *

Lab Measurements

PVT Properties * *Relative Permeability * *Capillary Pressure * *

Well Descriptions

Location *Completion Interval *Completion Changes *Stimulations *

DATA CONSIDERED BY MODELING METHOD

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Key Steps in a Simulation Study

1. Clear Objectives and Pre-planning

2. Reservoir Characterization

3. Model Selection

4. Model Construction

5. Model Validation

6. Predictions

7. Documentation

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Geology Data Quality & Quantity

Scale-Up Mathematical

•Objective of the study•Assess uncertainties•Data requirements and availability•Modeling approach•Limitations of proposed procedures•Resources

Project budget Time available Hardware Software.

Pre-planning the reservoir simulation study

SOURCES OF UNCERTAINTY IN SIMULATION

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Reservoir Characterization

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Geological Description

*Geological description must identify the key factors which affect flow through the reservoir.

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Fluid Characterization

Liquid

Gas

Pressure

Volume

Bubblepoint

FIRST BUBBLE

OF GASLAST DROP

OF LIQUID

Dew point

Fluid characterization defines the physical properties of the reservoir fluid mixture, and how they vary with changes in pressure, temperature and volume.

Steps to characterize the reservoir fluids:• Classify the fluid type• Determine reservoir fluid properties• Describe reservoir production mechanisms.

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23

h1-h2

h1

h2(Sand Pack Length) L

q

A

q

A

WATER

WATERWATER

Air Oil

SOLID (ROCK)

WATER

OIL

< 90

SOLID (ROCK)

WATER

OIL

Petrophysical Model

0.4

0

0.2

40 6020 80

Water Saturation (% PV)

Re

lati

ve P

erm

ea

bil

ity,

Fra

cti

on

1.0

0.6

0.8

Water

Oil

The petrophysical model defines where the volumes of oil, water and gas are locatedin the reservoir, as well as how fluids behave in the presence of the rock.To define the petrophysical model of the reservoir, you must determine:

• Rock Wettability• Capillary Pressure• Relative Permeability• Residual Oil Saturation• Fluid Contacts

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Model Selection

•The Black Oil Models (Primary depletion, secondary recovery and immiscible gas injection)

•The Compositional Models(CO2 flooding, gas injection into near critical reservoir, conden- sate reservoirs)

•The Chemical Flood Models ( Polymer/surfactant/Low-tension polymer flooding/Alkali/ Foam flooding)

•Thermal Models (Steam soaks/drive, In situ combustion)

•Dual-Porosity Models of Fractured Systems

•Coupled Hydraulic, Thermal Fracturing and Fluid Flow Models

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Model Selection

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Constructing the Reservoir Model

QC the geologic model for errors and problems

Scale-up the model

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Constructing the Reservoir Model

Zoning the geological model

Layering the zone

Making Local Grid Refinement

Model the attached aquifer to reservoir

Model the faults

Model the Wells and Adding the Wells data

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Model Validation

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Predictions

Important considerations when making reservoir model predictions:

Prediction cases shouldn’t exceed capabilities of the model.

Predictions need to be consistent with field practices.

Simulation yields a non-unique solution with inherent uncertainties from:

Lack of validation (e.g., reservoirs with sparse geologic or engineering data). Modeling or mathematical constraints because of compromises made in model selection. Inherent uncertainties in reservoir characterization and /or scale up to model dimensions.

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Documentation

Technical memorandum

Formal report

Presentation

Store data files

Share lessons learned with future project teams

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Reserves Estimations

• Reserves Estimations Rely on Integrity, Skill, and Judgment of Evaluator

• Reserves Estimations Are Affected by Geological Complexity, Stage of Development, Degree of Depletion of Reservoirs and Amount of Available Data

• All Reserve Estimates Involve Some Degree of Uncertainty and Is Done Under Conditions of Uncertainty

• Uncertainty Depends Mainly on Amount of Reliable Geologic & Engineering Data at Time of Estimate and Interpretation of These Data

• Reserves Estimates Will Generally Be Revised as Additional Geologic or Engineering Data Becomes Available or as Economic Conditions Change

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Resources

DiscoveredResources

Or Initial

Volume in Place

Initial Reserves

Unrecoverable

Volumes

* Currently Uneconomic Volumes* Residual

Unrecoverable Volumes

UndiscoveredResources

OrFuture initial

Volumes inPlace

FutureInitial

Reserves

FutureUnrecoverable

Volumes

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Initial Reserves

CumulativeProduction

Sales Inventory

RemainingReserves

RemainingProved

Reserves

ProbableReserves

Probable Developed

ProbableUndeveloped

PossibleReserves

Possible Developed

Possible Undevelpped

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Methods of Petroleum Reserves Estimations

EUR = ERR + Cum

EUR; Estimated Ultimate RecoveryERR; Estimated Remaining ReservesCum; Cumulative Recovery

EUR = OOIP x RF

EUR; Estimated Ultimate RecoveryOOIP; Original Oil-In-PlaceRF; Recovery Factor

• ANALOGY (Bbls per Acre Foot Period)• VOLUMETRIC(Bbls per Acre – Bbls Period)• PERFORMANCE (Bbls Period)

Simulation Studies Material Balance Studies Decline Trend Analyses

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Analogy (Barrels per Acre Foot Period)

Requirements : A field or well which is expected to perform similarly.Advantages : Fast, cheap, can be done before drilling.Disadvantages: Accuracy (Apples and Oranges)

decimal Factor,Recovery RF

RB/STB Factor, VolumeFormation Oil Initial oiB

decimal ,saturation water initial average wiS

decimal porosity, average

Foot Acreper BarrelsBAF

:where

RF7758BAF

oiB

wiS1

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Volumetric (Barrels per Acre to Barrels Period)

Requirements: A well. Logs and/or Core. Estimate of drainage area,recovery factor (analogy), fluid properties (minor).

Advantages : Minimal information. Can be done early in the life.Relatively fast.

Disadvantages: Requires assumptions (Area, Recovery Factor) whichmay not be true. May have gross errors.

EUR = OOIP x RF

EUR; Estimated Ultimate RecoveryOOIP; Original Oil-In-PlaceRF; Recovery Factor

RB/STB Factor, VolumeFormation Oil Initial oiB

decimal ,saturation water initial average wiSdecimal porosity, average

feet formation, ofheight AveragehAcres Area, DrainageA

Place-In-Oil OriginalOOIP:where

oiB

wiS1h A 7758

OOIP

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Decline Curves (Barrels Period)

Requirements: Production history (only).

Advantages: No assumptions about size, type or other properties ofreservoir. Need only production history. Fast, cheap. Very accurate under certain circumstances. Results inproduction versus time prediction.

Disadvantages: Well must be producing under “constant” conditions.Need at least 6 months history (better 2-10 years).Ambiguous (does not necessarily give unique answer).Can not be used under changing well conditions. Notapplicable to all reservoirs.

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Decline Curves (Continue)

197071 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99200001 02 03 04 05 06 07 08 09 10 11 12 13 141

10

100

1000

10000

CV

.Da

vgO

il, b

bl/d

Phase : OilCase Name : TPLb : 0.55Di : 0.05 A.n.qi : 67.0135 bbl/dti : 12/30/2006te : 04/30/2014End Rate : 1 bbl/dFinal Rate : 47.9872 bbl/dCum. Prod. : 5939.15 MbblCum. Date : 12/01/2006Reserves : 151.793 MbblEUR : 6090.95 MbblForecast Ended By : TimeForecast Date :

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Material Balance

Requirements: Pressure, Production history, fluid properties, rock properties (relative permeability required for prediction).

Advantages : No assumptions necessary for areal extent, thicknessrecovery factor. Low sensitivity to porosity, water saturation. Can be used to calculate oil-in-place, gas-in-place, recoverable reserves (and therefore recoveryfactor), water influx, gas cap size.

Disadvantages: Pressure not usually available. Predictions are verysensitive to relative permeabilities. Required more information than Analogy, Volumetric and Decline Curvemethods.

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Reservoir Simulation

Requirements: For each cell: permeability, porosity, thickness, elevation,initial saturation, initial pressure, rock compressibility.For each well: location, producing interval, productionrates versus time, pressure versus time.For each rock type: relative permeability of each phase,capillary pressure.For each fluid type: formation volume factors, viscosity,gas solubility, density.Reservoir description: faults, pinchouts, aquifers, layering.

Advantages: Ability to handle different rock and fluid properties indifferent areas of the reservoir. Can predict productionfrom individual wells. Once history match is obtained, canstudy effects of different producing schemes. Input datarequirements force close analysis of reservoir.

Disadvantages: Cost, time required to do study, amount of input data, non-unique match. Assumptions made to get match may notbe true in prediction runs. People tend to believe the answers.

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Conclusions

• If the Material Balance and Decline Curves say there is more oil-in-place than the Volumetric, then there are probably un-drilled locations.

• By comparing the results from the various methods, much can be learned about the reservoir, detach the faulty assumption and form a better picture of reservoir.

• Each reserves estimations method requires different data than others to arrive at same result and can be used to crosscheck answers.

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References

Integrated Petroleum Reservoir Management (Abdus Satter, Ph.D and Ganesh C. Thakur, Ph.D)

Reservoir Simulation Overview ( Dale Brown, Subsurface Director, Chevron Bangladesh)

Oil Property Evaluation (Thompson and Wright)

Determination of Oil and Gas Reserves (SPE monograph No-1)

Oil & Gas Reserves Estimations {Saw Ler Mu, ME(CSM)}

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