Chapter 3 Seismic Methods for Reservoir Management

Chapter 3

Brown Field Reservoir Management & Surveillance School

Chapter 3-2

� Through an understanding of the basic principles underlying seismic methods, appreciate their strengths, weaknesses and uncertainties

� Appreciate how various types of seismic interpretation output can assist the reservoir surveillance engineer

� Know how interactive sessions with the reservoir geophysicist help to develop an understanding of reservoir geometry, architecture and property distribution, which in turn control reservoir fluid flow

� Appreciate the strengths and weaknesses of− 2-D and 3-D seismic data− Seismic attributes− Seismic slice maps− Vertical seismic profiling− Time to depth conversion− Cross hole seismic surveys− Seismic stratigraphy studies− Direct hydrocarbon indicators− Seismic amplitude maps− Time lapse (4-D) seismic

Instructional Objectives


Chapter 3-3

Fig 1a: Reservoir Scale(Nolen-Hoeksema, 1990)

Fig 1: Field Life Cycle(Nolen-Hoeksema, 1990)

Giga

Mega

Tw

o & T

hree

Dim

ensio

nal S

eism

ic

VS

P &

Crossho

le

Reservoir

Simulation

Core

Thin SectionMicro

Macro

Mega

Need

Exploration Development Production EnhancedRecovery

Simulation

Delineation

EOR Process Selection

Life Extension

Description

Reservoir Management

Well Placements

Reserve Estimates

Phase

Objectives

Seismic Methods in Reservoir Engineering


Chapter 3-4

� What is seismic data?

� The basic fundamental of rock physics and reflections

� Interaction between well data and seismic data

� Types of data: 2D, 3D, 4C and 4D

� Seismic attributes and their role in reservoir characterization

� Direct hydrocarbon indicators

� Advance technological applications such us 4D, 4C, AVO and Inversion

� Depth Conversion

Seismic Acquisition and Interpretation and itsRelationship to Reservoir Management


Chapter 3-5

What Is Seismic Data?

� When an energy source is released at the earth’s surface, the energy travels into the earth’s crust ~ seismic waves

� When certain boundary conditions are met the energy is reflected back to the surface

� Energy returning to the surface is recorded by hydrophones/geophones

� This is seismic data! Reflection and Transmission


Chapter 3-6

Acoustic Impedance

� The differences in the rock properties - density and velocity determines whether a seismic wave is reflected or transmitted (based on Snell’s Law)

� The boundary condition is called the impedance contrast


Chapter 3-7

Acoustic Impedance

� Without impedance contrasts then we would not have any seismic reflectors!

� What can create impedance contrast? Change in:

� Rock type

− Sand, shale, limestone, basalt

� Mineralogy

� Fluid content

− Water, gas, oil

� Combination of above gives different impedance contrasts

� Hence necessity for sonic and density logs in logging suites to calibrate seismic data

Impedance Contrast=ρ2 v2- ρ1v1

ρ1v1

ρ2 v2


Chapter 3-8

� (Reflection coefficient generated at interface)

� An ideal imaging system would be able to resolve RC impulse responses (spikes) at interfaces

� Energy sources used are not ideal and have a finite resolution

� Seismic trace measured represents the ideal earth impulse response smeared by the source pulse

Seismic Method – Imaging Principles

GEOLOGY ACOUSTICIMPEDANCE

IMPULSE RESPONSE

SOURCE SYNTHETICSEISMOGRAM

* =

EARTHS ACOUSTIC RESPONSE

Seismic methods use acoustic energy to image the earth and hence measure the acoustic response or impedance of rock units:

RC = (ρn+1vn+1 - ρnvn )/(ρn+1vn+1 + ρnvn )

Fig 2: Imaging Principles Rn, Vn = Density, Velocity Of Layer N


Chapter 3-9

� Shortest travel time will be recorded at S4

� Longest travel time will be recorded at S1 and S7

� Reflection event produced by point scatterer is a diffraction hyperbola


POINT SCATTERER

Consider acoustic energy reflected from a point scatterer P at time T

DATAS1 S4 S7

t P

Fig. 4 (Claerbout, 1985)

Fig. 2.5 (Claerbout, 1985)

S7S4S1


Chapter 3-10


� Infinite number of closely spaced point scatterers

� Diffraction hyperbola from neighbouring point sources overlap and destructively interfere to produce plane reflection event

Fig. 5 (Claerbout, 1985)

Plane Layers


Chapter 3-11

Seismic Processing

� Once the data has been recorded it has to be processed, and this takes time

� There are many different processing techniques

� Different problems require different solutions

� Not all problems can be solved by processing


Chapter 3-12


� Diffraction hyperbola from neighbouring point sources overlap and destructively interfere to produce plane layer event except at the edge of the fault

� Diffraction hyperbola produced remain in the recorded data

� Migration is a process which uses travel time and velocity information to remap diffraction hyperbola events back to their source of origin

Fig. 6 (Telford et al, 1984)

M

N G

F

PO

t = to + ∆t

t = to + 2∆t

t = to + ∆t

t = to + 2∆t

D

Ht = to + ∆t

t = to

t = to + 2∆t

BA

E


Chapter 3-13

Seismic Methods – Migration Example

0.0

0.5

1.0

1.5

2.0

2.5

0.0

0.5

1.0

1.5

2.0

2.5

0.6 1 7 13 19 25 31 35 43(a)

(b)

Unmigrated section (a)

� Diffraction hyperbola

� From faulted and sharply folded basement

� Note "smiles" ⇒ faults

� And "bow ties" ⇒ synclines

Migrated section (b)

� Basement reflector

� Correctly focussed

Fig. 9 (Telford et al, 1984)


Chapter 3-14

Two Dimensional vs Three Dimensional Migration

Fig. 14 (French, 1974)

� 2D migration section shows

"sideswipe" event originating from

object two which is outside of the plane

of the profile

� 3D migration takes account of

"sideswipe" events and section shows

that all objects have been correctly

imaged


Chapter 3-15

Fig 15 (French, 1990)

2D Migration Section 3D Migration Section

� Faults in 2D section are not clearly imaged or interpreted

� Faults are clearly imaged and easily interpreted in 3D section

Two Dimensional vs Three Dimensional Migration


Chapter 3-16Figure 8: Courtesy Professor Simon Lang

Typical 2D Seismic Reflection ProfileShowing Stratigraphy Of A Shelf Margin


Chapter 3-17

Particle Motion

Pressure Wave

Propagation of energy

P Waves (Primary)


Chapter 3-18

Particle Motion

Displacement

Propagation of energy

S Waves (Shear)


Chapter 3-20

� Acquisition is all about creating a

seismic wave and recording how

long it takes to get back to the

surface

� The seismic wave passes into the

earth where it is filtered and

modified based on the kind of strata

it passes through and the fluids the

strata are containingSeabed seismic data acquisition

Acquisition


Chapter 3-21

Two Dimensional Seismic Surveys

2D DataGrid

Common Depth Point (CDP) Position

Fig 10 (Ritchie, 1986) Fig 11 (McQuillin et al, 1984)

� Source and receiver array positioned and moved across surface

� Data acquired along lines which make up 2D grid (typical line spacing 1 km or more)

� Seismic section represents depth in time


Chapter 3-22

3D DATAVOLUME

� Source and a number of closely spaced parallel receiver arrays positioned and moved across surface (swath shooting)

� Small line spacings are used (typically 50 m)

� Seismic section represents depth in time but data volume is 3D (common depth cells) and allows sections in any direction to be generated

Three Dimensional Seismic Surveys

Fig 12 (Ritchie, 1986) Fig 13 (McQuillin et al, 1984)


Chapter 3-23

Land Acquisition

� Source and a number of closely spaced parallel receiver arrays positioned and moved across surface (swath shooting)

� The primary sources are dynamite and/ or vibroseis

� Dynamite has good penetration but the frequencies of the data cannot be controlled nor is the signal repeatable

� Vibroseis produce a signal by vibrating the ground at specified frequencies and periods of time

� Land acquisition is very expensive

− It is labour intensive and time consuming


Chapter 3-24

Land Seismic Survey


Chapter 3-25

Land Seismic Survey

� In land acquisition the source moves along the recording cable


Chapter 3-27

Marine Acquisition

� The source and recording cable are towed by the boat

� The source is fired at fixed distances and the streamer (recording cable) gathers the information

� Marine acquisition is much cheaper than land acquisition!


Chapter 3-28

Multi-component Data

Why Do We Need Multi-component Data?

� Shear waves do not travel through liquids, including gaseous phases

� Therefore, can be used to confirm presence of gas

� Can be acquired either as 2D or 3D data

� Expensive to obtain

� Ocean Bottom Cable (OBC) used offshore

� Becoming more common but often the multi-component data is not acquired

� OBC acquisition will be available this year in Malaysia


Chapter 3-29

4C Acquisition Offshore


Chapter 3-30

Resoultion


� The resolution, vertical and horizontal depends on two main factors:

− Frequency

− Velocity

� Good quality seismic data, with high frequencies may yield a vertical resolution of 15m

� Many reservoirs cannot be ‘seen’ on seismic

� Higher resolution data will allow a better seismic facies interpretation and a more accurate lithological prediction


Chapter 3-31

Seismic Scale Of Wavelets

Fig 3 Courtsey Proffesor Lang


Chapter 3-32

Resolution


Chapter 3-34

� The interpretation of seismic data consists of a structural

interpretation of the reflectors and the stratigraphic

interpretation of a package of reflectors

� The interpretation can be done on paper or on workstations

� The interpretation is done in the seismic time domain and

not depth

Seismic Interpretation


Chapter 3-35

2D Seismic Data

� Seismic lines are kilometres apart

� Structural mapping is possible

� Stratigraphic trends can be mapped

� Amplitude analyses not reliable especially if multi-vintage surveys are used

� Much cheaper than a 3D

� Can cover large areas

� Good for regional exploration

� Interpretation uncertainties are directly proportional to the seismic coverage (number of lines and the distance between the lines)

� Structural aliasing is a major risk


Chapter 3-36

Seismic Interpretation


Chapter 3-37


USES AND ADVANTAGES

� Delineate potential hydrocarbon bearing structures for exploration drilling

� Detect large scale structures/faults and stratigraphic features

� Data may be represented as:

− Time or depth structure maps at particular horizons

− Isopach maps (reservoir or sequence thickness maps)

− Amplitude analysis maps of subcropping reflectors at a particular interface

� Relatively cheap, quick, easy to acquire, process and interpret


Chapter 3-38

� Time structure map converted to depth structure map by multiplying one way travel time with velocity

� Note change in interpretation with change in data coverage


Data Representations

Seismic Grid

Time Structure Map

Depth Structure Map

1966 1967

Fig 16 Time Structure Maps (McQullin et. Al., 1984)


Chapter 3-39

ISOPACH INTERVAL 20 FT

LINCOLN COPIKE CO

POSSIBLE CLAY-FILLEDCHANNEL

SWEETWATER FIELD



Fig 17 Isopach Map (Anstey, 1980)

� Time difference between bottom and top reservoir reflectors x velocity

� Reservoir geometrical pattern is that of a meander and indicates deposition by river


Chapter 3-40

E

F

Kilometres

Boundary Fault

Area of Low Reflection AmplitudeArea of High Reflection Amplitude

EscarpmentSubcrop

Fig 18 Reflection Amplitude Map at Interface(Tilbury & Smith, 1988)

� Represents strength of seismic reflections below a particular interface (subcropping units)

� Areas of high reflection amplitude (red) are shales while low reflection amplitude (blue) areas are gas saturated sands

� Shows excellent correlation with projected gamma ray logs from goodwyn 7 & 8

� No further appraisal drilling was conducted because of the confidence placed in this map




Chapter 3-41

Limitations

� 2D processing does not account for "sideswipe" and leads to misties between migrated sections at intersection points

� Low density of data coverage:

− Minor faults and small scale stratigraphic features present are not imaged

− Ambiguity in tracing faults and contouring events between lines of grid

� Land surveys have additional limitations

− Misties due to surface topography and weathered layer

− Of limited use in fold belt or structurally complex regions



Chapter 3-42

3D Seismic Volume Interpretation

Top TIRRAWARRA

Top TOOLACHEE

Intra Poolowanna

M-2M-6

M-3

M-4M-10

M-9M-6

M-5

Q-1

Moorari Field, Cooper Basin; Nakanishi and Lang, APPEA, 2001

Fig 20: Courtesy Professor Simon Lang


Chapter 3-43

Interpretation Of Seismic Attributes Is Critical:What Is Sand? Need Wells!

Deepwater toe-of-slope splays in front of canyons; courtesy of Paradigm geophysical



Chapter 3-44

Focus on specific intervals and then move through the volume to visualise features

1km

W E

MFS20

SB20

SB30MFS20

SB20

SB10

LST20

Lowstand systems tract, amplitude trough onlapping on sequence boundary 20 (intra-Patchawarra unconformity)

Measuringamplitude trough

3D SEISMIC VISUALISATION (LST 20)

100

mse

c



Chapter 3-45

Correlate Surfaces To Logs And Interpret Systems Tracts

Intra Poolowanna

TopToolachee

SB30MFS20

SB20

SB10

TST30HST20

TST20

TST10

LST20

LST10



Chapter 3-46

3D Seismic Visualisation (LST 20)

Locate potential prospects and leads viewed in 3D

SB30MFS20

SB20SB10

LST20Prospect L20E

Prospect L20SW

LST20 above SB20 (intra- Patchawarra unconformity)

Measuringamplitude trough



Chapter 3-47

� Discovery well (Arauca-1) and step outs (Arauca-2,3,4) drilled on basis of 2D interpretation (all step outs were dry)

� 3D interpretation shows detailed faulting and improved contouring

Three Dimensional Seismic SurveysData Representations

Fig 25: Johnston, 1989

Time Structure Map(Based on 2D data)

Time Structure Map(Based on 3D data)


Chapter 3-48

3D Seismic Data

� Much higher density of lines

� Only metres apart

� Much higher confidence in structural and stratigraphic interpretation

� More “planes” can be interpreted

� Amplitude analyses possible

� More expensive than 2D

� Can be and should be used for exploration

� Always used for development purposes


Chapter 3-49

3D Seismic Data

A FAMOUS 3D MYTH

Many people think that 3D data eliminates imaging problems

3D data acquisition in poor data areas generates 3D volumes of poor data


Chapter 3-50

Two Dimensional vs Three Dimensional

Are These Two Maps The Same?

The two maps above are of the same area:

� A is from a 2D interpretation, and

� B is from a 3D survey

� 3D data gives more structural and stratigraphic detail


Chapter 3-51

3D Data

� 3D data allows all planes to be

examined: vertical and horizontal

� On 2D data the bright amplitudes may

have been seen but they couldn’t be

mapped and verified


Chapter 3-52

� As can be seen in the horizontal plane, the bright spots are in fact a channel

3D Data


Chapter 3-53

Horizontal Time Slices Cut Through The 3D Volume ShowGeologically Meaningful Features That Control Reservoir Distribution

Note meandering to sinuous channels filled with mud or coal (dark high amplitude), point bar or lateral bar sands with lateral accretion surfaces deposited within the

margin of the channel belt. Examples from Indonesia



Chapter 3-54


Fig 27: Reblin et. al., 1991

3D Perspective View� Example shows reservoir horizon

perspective view of the Dollarhide field,

Texas

� Colour shading represents "relief" and

shows that reservoir is folded and

faulted within an anticline

� Faults are clearly evident

� This display has helped reservoir

engineers develop a better

understanding of the field shape and

how the faults impact the ongoing CO2

flood project


Chapter 3-55

NS

� Example shows time slice through the Dollarhide field, Texas

� Time slice shows subcropping reflectors and faults and in this case represents a horizon-tal slice taken through an anticline

� Reservoir horizon is annotated in purple

� Intersected faults are shown in yellow

Fig 28: Time Slice (Reblin et. al., 1991)



Chapter 3-56

Fig 29: Time Slice (Johnston, 1989)

Inlines

Cro

sslin

es

Net Sand Map

Thi

ckne

ss In

Fee

t

110’

0’500’

N

Section through sandstone (blue area) deposited by river

Shows thick versus thin reservoir development

Fig 30: Isopach Map (Abriel et al, 1991)



Chapter 3-57

Flattened Horizon Slices Display Attributes(i.e. Amplitude Or RMS) Along Surface

Deepwater meandering channel with RMS display (root-mean square of amplitude);

Mayall and Steward, 2000

Deepwater meandering channel with amplitudedisplay; courtesy of Paradigm geophysical

Figure 31: Courtesy Professor Simon Lang


Chapter 3-58

Seismic Reservoir Monitoring

Fig 32: (NESTVOLD, 1992)

� Red areas are high amplitude events

associated with oil filled reservoir areas

� Blue areas are low amplitude events

associated with water flooded reservoir

areas

� Black circles are water injector wells

� Note water fingering along faults and

injector wells


Chapter 3-59


Chapter 3-60


Chapter 3-61


Uses and advantages

� Provides detailed reservoir / structural/ stratigraphic delineation

� 3D migration takes account of "sideswipe" events

� Dense nature of data volume allows unambiguous contouring and interpretation of faults

� Data volume may be represented as:− Time, depth structure maps or horizon slices at particular reflector as either contour

maps in 2D or 3D perspective view− Time slice showing subcropping reflectors and structures− Isopach maps (reservoir or sequence thickness maps)


Chapter 3-62


Limitations

� Areal coverage of survey much larger than objective area imaged (survey must be up to three times the area of the subsurface area to be imaged)

� Lines may not be long enough to image large faults or steep dips (a fault running to a 3 km depth would need a 15 km long line)

� Time required for, aquisition, processing and interpretation may not allow results to impact development drilling program

� Linear features appear on time slices in the shooting direction when positioning errors in NAV data of source/receiver locations exist

� Cost limits use to areas where discoveries have been made

Fig 33: (YILMAZ, 1987)


Chapter 3-64

Multi-Component Data

Why do we need Multi-Component Data?


� Therefore, can be used to confirm presence of gas

� Can be acquired either as 2D or 3D data

� Expensive to obtain

� Ocean Bottom Cable (OBC) used offshore

� Becoming more common but often the multi-component data is not acquired

� OBC acquisition will be available this year in Malaysia


Chapter 3-65

4C Acquisition Offshore


Chapter 3-66

Vertical Seismic Profiling

Structural detail on NW-SE VSP profile using 3-component Processing

� Source is located and moved on surface along line through well while receiver array is inside well

� Seismic section is of depth in time of region surrounding well location

Fig 34: (McQUILLIN et al, 1984) Fig 35: (JOHNSTON, 1989)


Chapter 3-67

Well Seismic Survey

Two types:

� Check-shot survey

− Geophone placed at a few strategic levels where the one-way time is recorded

− Good for T-Z inventory

− Low cost

� Vertical Seismic Profile (VSP)

− A more rigorous method

− More sampling points

− Multi-level, high density acquisition

− Allows a pseudo-seismic section to be generated

− High cost


Chapter 3-68

Vertical Seismic Profiles

� High density sampling ~ every 50m along the borehole allows a seismic section to be generated

� Direct comparison can be made with surface seismic data


Chapter 3-69

Vertical Seismic Profiles

Uses and advantages

� Delineate reservoir extent about well location

� Detect minor faults and other discontinuities that compartmentalize reservoirs

� "Look ahead" drill bit to confirm reflector type (amplitude analysis), depth and detect over-pressured zones (bright spots)

� Correlate well log and lithology with surface seismic reflections

� Acquisition, processing and interpretation is quick and may impact development drilling

Limitations

� Image area surrounding well location only (few km laterally, few 100m vertically beneath TD)


Chapter 3-70

Houston, We Have A Problem!

� What is the problem?

� Seismic data is a measure of the time it takes for a seismic wave to travel through the earth’s crust

� It Is Not A Depth Measurement


Chapter 3-71

How Do We Calibrate Our Seismic Data?

� If we are lucky we have well data

� If we are really lucky we have sonic and/or density logs

� If we have won the lottery we have check-shot and/or VSP data

Sonic Log Check-shot


Chapter 3-73

Basic Reflection Principles

� Seismic data is the travel time from the source to the receiver

� Seismic sections are time measurements NOT depth


Chapter 3-74

Depth Conversion

� Many methods can be used to depth convert:

− Single-velocity function

� In the simplest case a geophysicist can use the check-shot or VSP data from a well or number of wells

� Layer-cake Method

� Velocity Fields

− A more sophisticated method is to use the well-data and seismic or stacking velocity data to generate 3D velocity fields


Chapter 3-75

Well Seismic Ties

� With sonic and density logs a geophysicist can generate a “synthetic seismogram”

� Essentially a synthetic is seismic data based on “real” information from a well

� Check-shot data allows a direct depth-time match between the synthetic and seismic data through the well location


Chapter 3-76

Seismic-Well Tie


Chapter 3-77

Seismic-Well Tie

Fig 36: (PAULSSON ET. AL., 1992)

Fig 37: (LINES, 1991)

Tomogram illustrates a contrast between high velocity salt and low velocity sediments

� Source is located and moved within one well while receiver array is located in an adjacent well

� Seismic section is of horizontal distance between wells in time


Chapter 3-78

Crosshole Seismic Surveys

Uses and advantages

� Detects minor faults and small scale stratigraphic features

� Tomography or travel time inversion allows:

− Slices of inter well objects to be mapped

− Monitoring of steam fronts in reservoirs using steam recovery

− Location of reservoir heterogeneities which may contain localised oil pools

Limitations

� Limited horizontal resolution

� Accuracy of inversion algorithms depends on validity of inter well space velocity model


Chapter 3-79

Seismic Stratigraphic Studies

� Process of obtaining stratigraphic (sequences of sediments rather than structural information from seismic data)

� Sequences of sediments created by changes in depositional environment

� Acoustic impedance between sediment sequences allows stratigraphicexpressions to be imaged

Methods

� Seismic sequence analysis: depositional environment

� Seismic facies analysis: characteristic patterns of particular environment

� Seismic attribute analysis: reflection character and amplitude

Courtesy Professor Simon Lang


Chapter 3-80

Identify Seismic Surfaces And Reflection Terminations


Chapter 3-81

Seismic Stratigraphy – Sequence/Facies

Fig 43: (SHERIFF., 1980)

� B is a unit that thickens to the left

� A shows progradation from source to the right (deltaic)

� C thins onto the anticlinal structure

� D is fill in an ancient erosional channel

� Anticlinal structure is a gas field which produces from the reflector at 1.8 s


Chapter 3-82

Seismic Stratigraphy – Sequence/Facies



Chapter 3-83

Seismic Stratigraphy – Well Sitting

NEW DRILL LOCATIONS

DETUNED HORIZON SLICE

AM

PLI

TU

DE

LO

HI

1000’

N

Fig 44: (HALSTEAD & BERG., 1989)

� Reservoir units may not be in communication due to structure and depositional environment (infill drilling needs to be avoided)

� Colour isopach shows areas of thick reservoir development, selected as appraisal well locations and which flowed oil

Fig 45: (ABREIL et al., 1991)


Chapter 3-84

Seismic Stratigraphy Studies

Uses and advantages

� Delineation of reservoir sequences and non communication zones

� Siting of development/appraisal well locations

� "Direct" hydrocarbon indicators (bright, dim and flat spots)

� Reservoir monitoring (onset of flooding)

Limitations

� Thick rock sequences have no reflective interfaces and are "noisy“

� Thin rock sequences generate numerous reflections which interfere to produce complex and chaotic events

� Resolution of stratigraphic features depends on resolution of seismic survey with respect to geological scales


Chapter 3-85

Seismic Stratigraphy Studies: Hydrocarbon Indicators

Fig 46: (ANSTEY., 1977)

� Bright spotAcoustic impedance between shale and gas sand

� Dim spotAcoustic impedance between shale and gas carbonate

� Flat spotResult from gas/water, s/oil or oil/water contact

� Example shows bright spot, Velocity pulldown and multiple


Chapter 3-86

� Combined flat and bright spot

� Hydrocarbon water contact clearly visible

Fig 47: Courtesy Mr Andrew Mitchell

Reservoir Management Techniques & Practices:Direct Hydrocarbon Indicators

Gulf of Mexico


Chapter 3-87



Troll Field, Norweiagn North Sea

� Troll: massive gas field with thin oil column

� Clear flat spot at gas liquid contact

� Slight tilt due to velocity gradient


Chapter 3-88

Flat Spot

Bright reflectors and flat-spots - indicative of gas


Chapter 3-89

� Bright spot showing gas accumulation

� Interpretation requires well data for correlation



Gulf of Mexico


Chapter 3-90

� Bright spot showing gas accumulation

� Combined flat and dim spot

� Rare to see such clear examples of DHIs



Offshore China


Chapter 3-92

Seismic Amplitude

� They are a measure of the acoustic impedance contrast between 2 layers

� Remember: density and velocity differences

� Usually used to predict presence of hydrocarbons, especially gas

� With increased seismic resolution amplitudes are increasingly being used in seismic facies analyses


Chapter 3-93

Temana Central Saddle Amplitude Map


Chapter 3-94

Resak Field

Coherence Technology

Normal Seismic Amplitude


Chapter 3-95

Acoustic Impedance Inversion

� They are a measure of the acoustic impedance contrast between 2 layers

− Seismic data is band-limited

− Only a limited frequency range is seen

� Subsequent lack of resolution

� Inversion is a process of ‘changing’ the seismic data based on well logs

� Sonic and Density logs are a must

� Acoustic Impedence data is closely related to lithology, porosity, and pore fill

− Therefore, an extremely useful and important tool if the data allows an inversion to be done.


Chapter 3-96

Normal Seismic

Inverted Seismic

Inversion Technology: Bekok Field

Four Dimensionalor


Chapter 3-98

4 D (Four Dimensional)

� 4D or time-lapse seismic is a development tool to monitor the fluid levels in the reservoirs

� The analogy is of taking a series of photographs and comparing the differences over time

� Provides a means to evaluating production barriers/baffles

� Can be either 2D or 3D data

� Can be either a periodic survey or use permanently positioned OBC cables

� Acquisition must be optimum especially for amplitude analyses


Chapter 3-99

Reservoir Management Techniques & PracticesTime Lapse (4D) Seismic

Pre Production Vertical sectionPre Production

B80 reservoir horizon slice


Pliocene sandstone reservoir, Lena Field, Gulf of Mexico


Chapter 3-100

Pliocene sandstone reservoir, Lena Field, Gulf of MexicoDifference between 1983 and 1995 surveys


The anomaly in the difference horizon slice (right) corresponds well with the area of gas cap expansion after 8 years of oil production (left)

Reservoir Management Techniques & PracticesTime Lapse (4D) Seismic


Chapter 3-101

Seismic Methods In Reservoir Engineering

� The coverage of seismic methods and applications given in this course is not comprehensive

� Examples of seismic methods and data presented demonstrate the value of such information to reservoir management

� Petroleum engineers need to be aware of the importance of seismic data as a source of additional reservoir information

� Geophysicists are seismic data processing and interpretation specialists

CONCLUSIONS

Chapter 3 Seismic Methods for Reservoir Management

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Transcript of Chapter 3 Seismic Methods for Reservoir Management