Reservoir Engineering Overview

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Reservoir Engineering Overview

Presented by: Aung Myat Kyaw Reservoir Engineer MPRL E&P Pte, Ltd. Myanmar Engineering Society 20-Dec-2008

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Overview Objectives

§

Introduction to reservoir management and it’s benefits

§

Introduction to reservoir simulation 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

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(*)“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

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Reservoir Management Approach

1. Timing

The 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 Engineering

Synergy 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 Appr

oach

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Reservoir Management Approach

4. Establishing Purpose of Strategy

a. Reservoir Characteristics

c. Total Environment

i. 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.

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Reservoir Management Approach

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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 and Chemical Engineering Production & Operation Engineering Design & Construction Engineering Drilling Engineering Economics Reservoir Engineering Geology & Geophysics Management Reservoir Management Team Legal Land Environment Service Research & Development Gas and Chemical Engineering Production & Operation Engineering Design & Construction Engineering Drilling Engineering Economics Reservoir Engineering Geology & Geophysics Management Reservoir Management Team

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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

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As used here, the words

petroleum reservoir

system

include the reservoir

rock

and fluids, aquifer, and

the

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MODELING

METHODS

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

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DATA CONSIDERED BY MODELING

METHOD

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Key Steps in a Simulation

Study

1. Clear Objectives and

Pre-planning

3. Reservoir Characterization

5. Model Selection

7. Model Construction

9. Model Validation

11. Predictions

13. Documentation

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Geolog

y 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

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Reservoir

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Geological

Description

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Fluid

Characterization

Liquid Gas Pressure Volume Bubble point FIRST BUBBLE OF GAS LAST 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

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h₁-h₂

h1

h2

(Sand Pack Length) L q A q A WATER θ θ WATER WATER Air Oil SOLID (ROCK) WATER OIL θ< 90° SOLID (ROCK) WATER OIL θ

Petrophysical

Model

0.4 0 0.2 40 60 20 80 Water Saturation (% PV)

Relative Permeability, Fraction

1.0 0.6 0.8

Water Oil

The petrophysical model defines where the volumes of oil, water and gas

are located

in 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

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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,

sate reservoirs)

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

Foam flooding)

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

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Model

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Constructing the Reservoir

Model

QC the geologic model for errors and problems

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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

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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:

v

_{Lack of validation (e.g., reservoirs with sparse geologic}

or engineering

data).

v

Modeling or mathematical constraints because of

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Documentati

on

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

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Methods of Petroleum Reserves

Estimations

EUR = ERR + Cum EUR; Estimated Ultimate Recovery

EUR = OOIP x RF EUR; Estimated Ultimate Recovery

OOIP; Original Oil-In-Place RF; Recovery Factor

•ANALOGY (Bbls per Acre Foot Period)

•VOLUMETRIC(Bbls per Acre – Bbls Period)

•PERFORMANCE (Bbls Period)

Ø Simulation Studies

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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)

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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

EUR = OOIP x RF EUR; Estimated Ultimate Recovery

OOIP; Original Oil-In-Place RF; Recovery Factor

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Decline Curves (Barrels

Period)

Requirements: Production history (only).

Advantages: No assumptions about size, type or other properties of

reservoir. Need only production history. Fast, cheap. Very accurate under certain circumstances. Results in

production 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

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Decline Curves

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10 100 1000 10000 CV .Da vg O il, b b l/d Phase : Oil Case Name : TPL b : 0.55 Di : 0.05 A.n. qi : 67.0135 bbl/d ti : 12/30/2006 te : 04/30/2014 End Rate : 1 bbl/d Final Rate : 47.9872 bbl/d Cum. Prod. : 5939.15 Mbbl Cum. Date : 12/01/2006 Reserves : 151.793 Mbbl

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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, thickness

recovery factor. Low sensitivity to porosity, water saturation. Can be used to calculate oil-in-place, gas-

in-place, recoverable reserves (and therefore recovery factor), water influx, gas cap size.

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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, production rates 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 in

different areas of the reservoir. Can predict production from individual wells. Once history match is obtained, can study effects of different producing schemes. Input data requirements force close analysis of reservoir.

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Conclusio

ns

•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

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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)}

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