Seismic Processing and Interpretation

Industrial Training Report

Student Industrial Project (SIP)

OFFSHORE GEOHAZARD ASSESMENT

USING HIGH RESOLUTION 2D SEISMIC SURVEY AT PROPOSED WELL LOCATION

DATE RELEASED:

14th August 2014

Written By:

MUHAMMAD HASIF SYAZWAN B. SHAMSUL

14912

PETROLEUM GEOSCIENCE

Industrial Training at:

FUGRO GEODETIC (MALAYSIA) SDN. BHD.


Muhammad Hasif Syazwan 14912 1

1.0 ACKNOWLEDGEMENT

Alhamdulillah, all praises be to Allah S.W.T, The Most Gracious, and The Most Merciful for

His Guidance and Blessing.

Firstly, the author would like to express special appreciation to Universiti Teknologi

Petronas (UTP) and Fugro Geodetic Malaysia Sdn Bhd (FGMSB) for providing the

opportunity to undergo a truly remarkable Industrial Training experience. Special thanks is

dedicated to FGMSB Deputy General Manager FGMSB, Mr Abd Hanan Ahmad Nadzeri and

Human Resource Executive, Mrs. Norlaili Abd Hamid, as well as Center of Student Industrial

CSIMAL.

Special acknowledgement is also given to the authors Host Company Supervisor, Mr.

Ricardo Caringal Jr; Geophysical Reporting Manager for his kindness and assistances during

the eight months of industrial internship. Not forgetting, a mentor and a friend, Staff

Geophysicist, Mr. Juzaili Azmi, for his guidance, support and advice in completing the

Geophysical Seismic Processing and Interpretation project. Last but not least, to all staffs of

Processing and Reporting Department FGMSB for their meaningful advises.

Last but not least, the author also would like to thank UTP Supervisor, Mr. Jasmi B. Ab.

Talib for spending his precious time to visit the host companies, give advice and evaluate

authors performance during the industrial training at FGMSB. This achievement would not

have happened without the support from all of the mentioned above.

Thank you to all.



2.0 TABLE OF CONTENT

Content Page Numbering

Host Company Verification Statement

1.0 Acknowledgement

2.0 Table of Content

3.0 List of Tables

4.0 List of Figures

5.0 Industrial Training Project Report

1

2

3

3

5

5.1 Abstract and Introduction 5.1.1 Objectives

5.1.2 Scope of Study

5.1.3 Problem Statement

5.1.4 The Relevancy of Project

6

12

13

15

16

5.2 Background and Literature Review

5.2.1 Feasibility of Project within Scope and

Time Frame

5.2.2 Critical Analysis Literature

17

17

18

5.3 Methodology

5.3.1 Research Methodology

5.3.2 Key Milestone

5.3.3 Gantt Chart

5.3.4 Tools/Equipment Required

21

21

22

23

24

5.4 Results and Discussions

5.4.1 Project Deliverables

5.4.2 Data Gathering / Data Analysis

5.4.3 Findings

32

32

62

83

5.5 Conclusion and Recommendation

5.5.1 Impact

5.5.2 Relevancy to the Objectives

5.5.3 Suggested Future Work for Expansion

and Continuation

84

84

85

86

5.6 Safety training and value of the practical

Experience

5.6.1 Lesson Learnt and Experience gained

5.6.2 Leadership, Teamwork and individual

activities

5.6.3 Business values, ethics and management

skills

5.6.4 Problems and challenges faced and

solution to overcome them

87

87

88

89

90

6.0 Reference 91

7.0 Appendices 92



3.0 LIST OF TABLES

TABLES

Table 1: Analogue Survey Parameters Table 2: Seismic Survey Parameters Table 3 : Parameters Table for Static Correction Table 4: Predicted Intermediate Lithology at the Proposed and Revised Well Location. Table 5: Summary of Fault Intersections at the Proposed and Revised Well Locations. Table 6: Amplitude Anomalies and Risk Assessment. Table 7: Gas Probability for the Proposed and Revised Well Locations. Table 8: Summary of Drilling Constraints Below the Proposed and Revised Well Surface Locations.

4.0 LIST OF FIGURES

FIGURES

Figure 1: Multibeam Data with Coalesced Pockmark and Isolated Pockmarks Figure 2: Side Scan Sonar Image with Pockmark Cluster. Figure 3: Multibeam Echo Sounder Image with Carbonate Outcrops. Figure 4: Side Scan Image of the Hamilton Shipwreck. Figure 5: Sub-bottom Profiler Showing Buried Channels. Figure 6: Sub-bottom Profiler Image of Faults. Figure 7: Offshore Geohazard Diagram. Figure 8: Demultiplexed Data of Line 10 shows the raw data that has been sequenced Figure 9: Example of the raw data after static correction. Figure 10: Zoomed-in Raw SHOT file for Line 10. Figure 11: Line 10 Near Trace Gather Display. Figure 12: Line 10 Equalised Brute Stack. Figure 13: Line 10 True Amplitude Brute Stack. Figure 14: Trial of Time Varied Gain(TVG). Figure 15: Normal Move-out gather. Figure 16: Muting of Line 10 Figure 17: Denoised True Amplitude Stack for Line 10. Figure 18: Image of Shot Gather during velocity picking. Figure 19: Image of Energy Samblance during Velocity Picking. Figure 20: Stack of the seismic line.

Figure 21: Trial of Different Gaps and Operator Lengths. Figure 22: Deconvolved True Amplitude Stack; 40ms operator length; 8ms gap. Figure 23: Deconvolved Equalised Stack; 40ms operator length; 8ms gap. Figure 24: Image of a before / after migrated stack. Figure 25: Line 10 Finalised Seg-Y(Equalized). Figure 26: Line 10 Finalised Seg-Y(True Amplitude) Figure 27: Example of equalized seismic section, SW-NE mainline ID-2D-L10, passing near the

proposed well location. Figure 28: Example of equalized seismic section, NW-SE cross line ID-2D-L59, passing near the

proposed well location..



Figure 29: Example of equalized seismic section, NW-SE cross line ID-2D-L61, passing near the revised well location.

Figure 30: Example of relative amplitude seismic section, SW-NE mainline ID-2D-L10, passing near the proposed well location.

Figure 31: Example of relative amplitude seismic section, SW-NE mainline ID-2D-L10, passing near the proposed well location(Top 1.1 ms TWTT BSL.

Figure 32: Example of relative amplitude seismic section, NW-SE cross line ID-2D-L59, passing near the proposed well location.

Figure 33: Example of relative amplitude seismic section, NW-SE cross line ID-2D-L59, passing near the proposed well location(Top 1.1 ms TWTT BSL).

Figure 34: Example of relative amplitude seismic section, NW-SE mainline ID-2D-L61, passing near the revised well location.

Figure 35: Tophole Prognosis For The Revised Well Location Figure 36: Tophole Prognosis For The Revised Well Location



5.0 INDUSTRIAL TRAINING PROJECT

5. 1 Abstract & Introduction

Geohazards have always been a major concern especially in regard of the offshore industry.

Every year, unwanted complications occur in the oil and gas industry which result in

catastrophic monetary and human lives lost. According to the International Center of

Geohazards 2010; a geohazard is defined as a geological state, which represents or has the

potential to develop further into a situation leading to damage or uncontrolled risk.

Geohazards are found in all parts of the earth and are always related to geological conditions

and geological processes, either recent or past. Important offshore geohazards include slope

instability and mass wasting processes (including debris flows, gravity flows); pore pressure

phenomena (e.g. shallow gas accumulations, gas hydrates, shallow water flows, mud diapirism

and mud volcanism, fluid vents, pockmarks) seismicity. Excess pore pressure development

appears a critical aspect in most of the offshore geohazards.

Again based on ICN, 2010; Submarine slope failure is the most serious threat on both

local and regional scales. In addition to damaging offshore installations, slope failures may also

cause devastating tsunamis. ICG personnel have for a long period been involved in the studies

of the Storegga Slide area, offshore Mid-Norway. These studies were triggered by the

discovery of Europe's third largest gas reservoir Ormen Lange within the slide scar.

One of the underlying factors in the occurrence basically revolves around pore pressure

as it directly controls the displacement of sediments and materials related to sea-bottom

movement. However, the ability to accurately measure, monitor and predict pore pressures in

offshore sediments is limited and rarely done. Therefore, it is important to improve our

understanding of excess pore pressure genesis (processes, migration), accurate measurement

and its implications.

Below are some of the common geohazards encountered in the oil and gas industry.



Seabed features- isolated pockmarks, pockmark cluster, coalesced pockmark, seabed

depressions, carbonate, coral, debris and shipwreck.

Isolated pockmark: It is caused by the degassing or dewatering process which creates hollow

pockets or holes on the clay sediments and can be an indicator of gas seepage activity.

Pockmark cluster: It is produced by larger activity of dewatering or degassing; individual

pockmark accumulated at a concentrated area. All individual pockmarks that are grouped close

to one another are characterized as pockmark cluster; classified as an indicator of gas seepage

activity.

Coalesced pockmark: It is the origin of pockmark cluster which in time has been eroded by

the sea water and all the individual grouped pockmarks slowly collapse and becomes attached

to each other to form coalesced pockmark. They indicate gas seepage activity.

Figure 1: Multibeam Data with Coalesced Pockmark and Isolated Pockmarks

Coalesced Pockmark

Isolated Pockmark

s



Figure 2: Side Scan Sonar Image with Pockmark Cluster

Pockmarks are identified as geohazards as they indicate unstable base which could lead to

punch through for the jack-up rig legs and also cause freespans for the pipeline which up to a

certain limit can lead to the breakage.

Pockmark Cluster



Figure 3: Multibeam Echo Sounder Image with Carbonate Outcrops

Carbonate: It is sediment rock which composes of carbonate materials. The carbonate itself

consist of three (3) types of minerals which are aragonite (CaCO3), calcite (CaCO3) and

dolomite (CaMg(CO3)2). The usual types of carbonate identified on the fields are limestone

and dolomite. One of the characteristics of carbonates is that it is harder than clay. It is

considered as a geohazard as if a certain location is present of carbonate regardless of buried

carbonates or not. The reason is because for jack-up rigs, carbonate outcrops can cause

slippage. Other than that, it could lead to an ineffective installation of anchors and seabed

infrastructure. In addition, it will cause problems when drilling the top hole section of a well

which includes dredging and ploughing difficulties.

Corals: invertebrate tiny animals which could build protective calcium carbonate skeleton. It

cannot be destroyed and is assumed as an endangered species which are protected by laws.

Oceana World Laws which covers the corals protection are: Coral Reef Conservation Act

(CRCA 2000), The Endangered Species Act (ESA 1973), National Environmental Policy Act

(NEPA 1970) and also National Marine Sanctuary Act (NMSA 2006).

Carbonate Outcrops



Figure 4: Side Scan Image of the Hamilton Shipwreck

Debris and Shipwrecks: Debris which is classified to be man made objects which are seen to

have clear geometrical shapes which includes shipwrecks is usually present by accidents. They

are a danger for anchor deployment.

Shallow Geological Zones- Channels, gas chimney, buried carbonate, faults

Figure 5: Sub-bottom Profiler Showing Buried Channels

Channels



Channels: this structure is usually filled with deposits from the geological time. It is usually

steep and has high degree slope. Channel deposits usually consist of sand deposits with gas

present at the bottom. It is a danger for jack-up rigs as it can cause slippage.

Gas Chimney: leakage of gas in the subsurface is due to poorly sealed hydrocarbon

accumulation. This anomaly can be clearly seen in seismic data where the data area is poor and

velocity pull down occurs. This is considered a hazard as it can lead to blowout.

Buried carbonate: part of carbonate rock that has been buried and overlaid by other sediments

in geological times. Under the Sub-bottom Profiler data it can be seen that buried carbonate

outcrops will show masking. This is significant for the drilling process as it affects the type of

drill bit to use whether it is roller cone or fix cutter and even the materials used such as

Polycrystallyne Diamond Cutter (PDC) bit or Thermally Stable Polycrystallyne (TSP).

Figure 6: Sub-bottom Profiler Image of Faults



Faults: it can be defined as fracture in the earths crust with significance displacement due to

compressional and tensional force. There are two basic faults which are normal fault and

reverse fault. These faults are a hazard as it can cause slippage when the spudcan of the jack-up

rig goes through.

All of these geohazards above can bring devastating affects to the oil and gas industry if left

unstudied. This raising awareness of safety in the industry has prompted offshore geohazard

assessments to be taken very seriously and the technology to go deeper and provide better

assessments is always improving.



5.1.1 Objectives

The main objective of the survey was to acquire data for shallow gas assessment and

delineate possible hazards at and around the proposed well location prior to rig / platform

placement. After the seismic data has been acquired and interpreted, recommendation by the

company is included as a precautionary step. In the end, the clients have the discretion in

whether to apply the recommendations apply a few modifications of their own. However, the

objectives of the whole project involve the acquisition, processing and interpretation of the

seismic data from the proposed well location. Below are the overall objectives:

1) To understand the acquisition of data from the field.

2) To process the SEG-D raw data obtained from field to an interpretable SEG-Y format.

3) To define the intermediate geological conditions within the survey area and delineate

possible constraints or hazards which are relevant to the installation of rig or platform, such

as shallow gas, palaeo-channels or faults.



5.1.2 Scope of Study

A high-resolution 2D seismic survey for a proposed well location was carried out

recently. The main objective of the survey was to acquire data for shallow gas assessment and

delineate possible hazards at and around the proposed well location prior to rig / platform

placement.

The area covers a 6.7 km by 4.3 km area with two (2) proposed well locations. After

initial assessment of the hazards below the surface location of the proposed well location, such

as near-seabed channel and fault intersections, a revised location was provided by the client for

hazard evaluation. The survey covered a 6.7 km by 4.3 km area, as shown in Error! Reference

source not found. below.

Two types of surveys were conducted on the area. The first was an analogue survey using

Single Beam Echo Sounder (SBES) and Multibeam Echo Sounder (MBES).

An analogue survey with the following specs in the table below.

Parameters Value

Survey Grid 6.7 km by 4.3 km

Main Line Spacing 50 m / 100 m (45 and 225)

Cross Line Spacing 50 m / 250 m (135 and 315)

Number of main lines and length 46 x 6.7 km

Number of cross lines and length 28 x 4.3 km

Total line km 428.6 km(excluding run-in and run-out)

Table 1: Analogue Survey Parameters



The models of the echo sounders for the SBES and MBES are the Odom Echotrac MKII and

the Reson Seabat 7101 respectively. The multibeam echo-sounder results are able to give

precise depths of the seabed and topography of the seabed. Combining this with the high

resolution 2D seismic survey gives comprehensive geohazard coverage of the area in question.

This report presents the result of the intermediate geological zone (high-resolution 2D seismic

data) within the survey area, focusing at the proposed well location.

Depths quoted in this report and all relevant charts are given in milliseconds Two Way

Travel Time (ms TWTT) unless stated. Corresponding depths in metres Below Sea Level (m

BSL) are given in brackets, based on the time-to-depth conversion curve derived from the

average velocity provided by BSP.



5.1.3 Problem Statement

Geohazards can play a significant factor in the overall risks associated with deep water

projects throughout the operational life of the field. Common geohazards include slope

instability and mass wasting processesing, shallow water flow, active channels and turbidity

currents, active faulting and seismicity, shallow (pressurised) gas and pockmarks, mud

volcanoes, gas hydrates, bottom currents and scour and complex seabed morphology (rock out

crops, coral, etc)

The key to addressing these risks is early identification of the geohazards and

consideration of their possible impacts on the field development - together with continual

refinement during the planning and design process as more data becomes available. This is by

far the most foolproof ways in reducing the risk associated to geohazards. The geohazard

impact zones defined in this assessment process can either be avoided or, where this is not

possible, inform the engineering design process to consider mitigating measures that reduce the

impact to an acceptable level.

Regardless on industry, health, safety and environment (HSE) has always been a priority

since the Lost Time Injury(LTI) contributes to a loss in capital, human resource depletion and

an overall loss of confidence in a company by shareholders and employees alike . In the oil

exploration field, a key factor for the safety issue is to identify geohazards encountered by them.

If geohazards are neglected or ignored, it may lead to unwanted and unfortunate events which

will cost valuable time, money and also energy for recovery.

It is hoped that tools can be developed allowing regional excess pore pressure fields to be

mapped in detail, for example through geophysical methods, geological interpretation or

observational or survey techniques. Once regional excess pore pressure fields are detected,

then sensors and instrumentation systems designed for both short-term measurements and

long-term monitoring may make specific measurements.



5.1.4. The relevancy of the Project

The site survey is a compulsory measure for the safe placement of the proposed well location.

Failure in conducting a proper geohazard assessment on the proposed well location could lead

to unforeseen disasters during the drilling process. This includes punch through, blow-outs,

slanting rig legs, etc. Conducting a geohazard assessment based on a systematic periodic

approach is able to greatly decrease the risk of such incidences occurring. Even during well

placement, a geohazard assessment is advised to be conducted before placement of well, after

placement of well and during on-going drilling. A well site assessment is a comprehensive site

survey report that describes the seabed and sub-seabed conditions for any offshore exploration

or appraisal well. This study is an essential part of ensuring effective well planning and safe

drilling operations

There have been many previous scenarios whereby drilling, appraisal wells or pipeline

routes have gone without proper geohazard assessments. This has led to severe casualties in the

oil and gas industry where health safety and environment (HSE) is of monumental importance.

Billions of dollars and thousands of lives at minimum have been lost up to this day in regards of

offshore safety. Reducing the risk of facing geohazards is just one of the many safety aspects to

be considered before offshore drilling, pipeline construction should be considered.



5.2 Background and Literature Review

5.2.1 Feasibility of Project within Time Range

The 2DHR project required about a month of survey by the Fugro Geophysical survey

vessel. Following this was the completion of the full report took another month to complete.

While the interpretation of the 2D high resolution seismic was less of a challenge to deal with,

the concern was regarding the processing of the seismic. For the author, seismic processing

was definitely a totally new subject to deal with. Although the general sequence of processing

such as stacking, deconvolution and were covered in terms of basic definition during

undergraduate studies, but the real practical side was definitely a new challenge to face in the

space of one month. The first part of the process was learning the basics of processing which

involved complex mathematical operations such as Fourier Tansforms, Laplace Transform and

other differential equation methods. Due to time constraint; only the basic functions covering

each processing step was covered. The second part was to learn how to use the Fugro

Processing in-house software which became more complicated since it only ran on Linux

operating software which had an entirely different inter-phase compared to the massively used

of windows. The third and final part was the interpretation and finally the write-up of the

project. Overall, the project was successfully conducted and reported given the tight time frame

which mainly revolved around understanding the processing process and executing them. The

seismic processing is definitely a delicate subject to deal with. The project was to mainly focus

on the processing of the seismic data while the interpretation would be playing a more minor

role. Although processing was covered in the undergraduate studies during the third year at

Universiti Teknologi PETRONAS, not much depth was reached as more time and focus was

given to the interpretation of seismic, besides volume interpretation (3D) and Amplitude versus

Offset (AVO). Since the data in this project involves 2D high resolution seismic, Volume

Interpretation was of slight relevance and Amplitude versus Offset was a far fetch. What

managed to be covered in the seismic processing studies was more of the basic concepts

involved in the processing and not the different parameters used during the sequences of the

processing what more their effects on the seismic. In the end, learning seismic processing using

Uniseis was definitely a real learning experience that is hoped to be more developed in the

future.



5.2.2 Critical Analysis Literature Review

In the upstream project evaluation overview there are 5 phases in a field life cycle which are

acquisition, exploration, development, production and abandonment. Accordingly, geohazard

assessment is classified in the pre-development phase. This is because after a site has been

chosen after exploration, identification of geohazards is a necessity for furthering towards

appraisal for the development process. Based on ICG (2010), geohazard can be defined as A

geological state, which represents or has potential to develop further into a situation leading to

damage or uncontrolled risk. ICG (2010) also reported and identified that important offshore

geohazards (Figure 10) includes (i) slope instability and mass wasting processes (including

debris flows, gravity flows); (ii) pore pressure phenomena (e.g. shallow gas accumulations, gas

hydrates, shallow water flows, mud diapirism and mud volcanism, fluid vents, pockmarks); (iii)

seismicity. Excess pore pressure development appears a critical aspect in most of the offshore

geohazards.

Figure 7: Offshore Geohazard Diagram

Based on the figure and information, ICG (2010) indicates that there are common geohazards

that usually occur offshore. These geohazards were taken and combined to form the Main

Offshore Geohazards diagram. Through this, the geohazards can be identified based on their

common characteristics in the seismic, side scan and multibeam data.



In addition, Laura Brother et al (2010) had done a research on gas-related geohazards. They

have done a research about gas that was identified in geophysical survey. The gas was identified

from the seismic profile data specifically based on sub-bottom profiler. Laura Brother et al

(2010) informed that specific instrumentation varies per survey; they generically refer to this

instrument as the seismic source. This acoustic energy travels through the water column and

the sound bounce back from the seafloor. Some of the sound energy penetrate further into the

seafloor and reflects off deeper boundaries between layers of different physical properties. The

boundaries of change of characteristic and physical properties of the layers are referred as

reflectors. Bedrock, sand, mud, and gravel have distinctive properties and form reflectors in

the seismic record. The boundary or the reflector can be recognized as it appears in high

amplitude because of change of phase. Another equipment is called a hydrophone which

receives the reflected sound at the water surface. The depth of penetration and resolution of the

sub-bottom profiling depends on the types of sources used. Relatively, chirp, pinger, boomer,

sparker and mini air gun are the sources which in order are increasing in penetration but

decreasing in resolution. The usage of these sources differs based on the objective of the survey.

The fundamental purpose of a side scan survey is to provide images of acoustic targets on

the seafloor. Basically the side scan sonar system consists of three units: a transducer which

forms the underwater unit and is better known as the fish, a steel wire reinforced cable acting

as transmission and tow cable simultaneously, and a dual channel recorder (Flemming, 1976).

Unlike radar images, the side scan receiver detects sound that is backscattered from the seafloor,

not reflected from the large scale planar surfaces like radar images (Johnson, 2001). From this

explanation it indicates that one of the advantages of the usage of side scan sonar is to identify

anomalies on the seabed which includes depressions and projections. Depressions in this case

include seabed depressions and pockmarks where else projections covers mounds, carbonate

bodies, structures, debris and etc. These digital image data are "correct" in the sense that all of

the acoustic targets are in the same undistorted spatial relationship to each other as they are on

the seafloor (Helferty, 2001). The development of side-scans sonar has evolved to the point

where we can now view these acoustic data as spatially correct images.

Processing simultaneous bathymetry and backscatter data, multibeam echo sounders (MBESs)

show promising abilities for remote seafloor characterization (Laurent, 2003).



High-frequency multibeam echo sounders (MBESs) provide a good horizontal resolution,

making it possible to distinguish fine details at the waterseafloor interface. However, in order

to accurately measure the seafloor influence on the backscattered energy, the recorded sonar

data must first be processed and cleared of various artifacts generated by the sonar system itself.

Usually installed under a ships hull, an MBES transmits a sound pulse inside a wide

across-track and narrow along-track angular sector; then a beam forming process

simultaneously creates numerous receiving beams steered at different across-track directions.

This spatial filtering allows us to pick up echoes coming from adjacent seafloor portions

independently (Baucher, 2003). One sounding is accurately computed inside each beam by

simultaneously measuring the beam steering angle and the echo travel time, according to

various estimation methods based on either amplitude or phase.

From the research above, methods that are used to identify geohazards are based on the common

characteristics of the geohazards which has been tabulated and also has been recognized from

the seismic profile data. In this project, those methods have been combined to produce a better

identification of geohazards in the survey area to get accurate and precise results.



5.3 Methodology

5.3.1 Research Methodology

The task given for the project involved in the geohazard assessment of the 2D high resolution

seismic survey involves:

1) Acquisition of data from field. The first part was the data acquisition from field. The data

was obtained from a 96-channel HTI SEAMUX Streamer and a 4 x 40 cubic inch Sleeve Gun

Cluster. The data was obtained in Society of Geophysicists Standard D(SEG-D) format. Below

is the list of parameters used in the acquisition.

2) Processing of the Seg-D data obtained from field. A suitable processing sequence is

chosen based on initial observation of the brute stack data. Processing the data is mainly used

to remove noise or disturbances from the data and maintain what is considered to be the actual

data from the site. The best approach to processing is to produce the best data quality for

interpretation while maintaining the originality of the data. In other words, the best seismic

processors produce good quality data with minimal steps. The processing was conducted at the

Fugro Geodetic(M) Malaysia headquarters.

3) Interpretation of 2D seismic data from the field. The processed 2D seismic data is used

for interpretation of the following components:

I) Geological structures

II) Geological Stratigraphy

III) Anomalies

IV) Top hole drilling conditions

Combining the information from all 4 sources is able to provide a comprehensive offshore

geohazard assessment for proposed well location. Any potential hazards are clearly reported

and viable recommendation of safety measures is stated to the client for their discretion.



5.3.2 Key milestone

Phase Month Task Description

1

Training

May Introduction to Seismic Processing

An overall outlook on the definition of processing, its function and the overall method.

May Study on each seismic flow sequence

Spend about one (1) week on the seismic processing flow such as brute stacking, denoise, deconvolution, velocity picking and migration.

June Introduction to Uniseis (Fugro in-house processing software)

Practice using Uniseis which runs on Linux to gain familiarity with the software.

2

Started Seismic Processing

June Pre-stack processing Filling database of parameters for initial loading of data besides applying static corrections and re-sequencing,

June Quality Checking(QC) data

Producing a brute stack and mute / filter seismic through de-noise.

July Post-stack Processing Velocity picking and reinserted velocities into the previous flow and applying final migration.

3

July

Review of Processing by Processing Geophysicists

Amendments were made based on the comments given by the seismic processor.

Interpretation of Seismic

4 July Interpretation of Geological structures and stratigraphy

Three (3) seismic lines were picked based on their structures and stratigraphy as highlight points of the offshore geohazard assessment.

July / August

Interpretation of anomalies and drilling prognosis

Anomalies that were a potential of being shallow gas were identified and a drilling prognosis combining the geology and anomalies was produced to find a substantial relation if any.

5 August Final Review of processing and interpretation

The overall processing and interpretation was commented by the Geophysical Reporting Manager. Amendments were made as adviced.

6 August Submission Submission of report to UTP Supervisor.



5.3.3 Gantt Chart

Month May June July August

Week 3 4 5 6 7 8 9 10 11 12 13 14

No. Task

1 Training

Introduction of Seismic Processing

Study Seismic Flow Sequence

Introduction to Uniseis

2

Started Seismic Procesing

Pre-stack processing

QC Data

Post-stack processing

3

Review of Processing

4 Interpretation of seismic

5 Final Review

6 Submission



5.3.4 Tools / Equipemt / Software Required

The site survey was carried out using Fugros long-term chartered geophysical survey

vessel. The vessel was positioned and navigated using Fugros Starfix High Precision (HP),

Starfix Multi-Reference Differential Global Positioning System (MRDGPS) and Starfix.Seis

navigation system.

High-resolution 2D seismic survey equipment consisted of HTI NTRS2 seismic recording

system, a 96-channel HTI SEAMUX Streamer and a 4 x 40 cubic inch Sleeve Gun Cluster. The

survey was performed in single pass operation where the echo sounders and high-resolution 2D

multichannel seismic system were concurrently acquiring data.

Parameters Values

Number of channels: 96

Group length: 12.5 m

Shot point interval: 12.5 m

Streamer depth: 2.5m(+/- 0.5m)

Source depth: 2.5 m (+/- 0.5m)

Sample rate: 1.0 ms

Record length: 2.5 s

Low cut filter: 4.5Hz, slope 6 dB/Octave

High cut filter: 412Hz, 215 dB/Octave

Source to near trace offset / centre of first active channel 15 m

Table 2: Seismic Survey Parameters

Another Fugro in-house software was used called Uniseis for the seismic processing. The

software runs on Linux operating system. Linux is opted as the Operating System (OS) for its

cost effectiveness and generally lower operational demands. Linux has also very few malware

and virus defects and thus is needless of an anti-virus system which usually consumes a lot of

RAM. Since it does not have a high demand on the OS, a need of software to clear the clutter

such as C-cleaner, Tune-up or Registry Mechanic is not required. Thus, the Linux operating

system is allowed the RAM to focus on the seismic processing software alone which is already

a very demanding process.



Navigation and Single Beam Bathymetric Processing

Real-time logging of navigation and bathymetric data was implemented using Fugros

Starfix.Seis navigation system. Processing of the acquired navigation and bathymetric data

was initiated on-board the survey vessel using Fugros in-house processing software,

Starfix.Proc, and was later finalised at the processing centre of Fugro Geodetic (Malaysia) Sdn

Bhd in Kuala Lumpur, Malaysia.

Post-processing involves cleaning and filtering of position data, analyses and corrections

of depth data, tidal height adjustment, automated data cleaning based upon statistical rules,

manual editing, controlled data thinning, and export of the final sounding data for further

processing and charting. Navigation track plots at a scale of 1:7,500; referred to the position of

the vessel datum, echo sounder transducer and digital first CDP were processed. This was used

for interpretation of the relevant geophysical data.

The first CDP (nearest Common Depth Point) navigation tracks were plotted for the

interpretation of the 2D high-resolution seismic data. The first CDP for the 2D high-resolution

seismic data is the midpoint between the seismic source and the centre of the first streamer

group (near offset).

Refer to Appendix B for details of the MV Amarco Tiger geophysical survey equipment offset

diagram.



2D High Resolution Seismic Data Processing

The 2D high-resolution seismic data was recorded in SEG-D de-multiplexed format. Quality

control of the 2D high-resolution seismic data was carried out on-board using Uniseis seismic

processing system. The processed data are of good quality. Due to the short duration of actual

field operations, seismic processing onboard the vessel could only be carried out in limited

stages. The final seismic processing that includes additional procedures has been carried out by

a processing house seismic data processing house. A listing of processing workflow is

supplied in the results.

The processed seismic data shows improved signal to noise ratio with better stacking response,

therefore events are more clearly defined. Amplitude anomalies are more significant and more

structural details can be interpreted from the final processed seismic data. The processed

equalised and relative amplitude migrated data was transcribed to SEG-Y format for

interpretation using SMT Kingdom Suite seismic workstation.

Water Velocity and Tidal Reduction

The sound velocity in seawater within the site was measured using the Valeport Midas

SVX2 velocimeter for the calibration of the echo sounders. The equipment uses digital time of

flight sound velocity sensor as well as salinity and density data in synchronised sampling to

produce accurate profiles. It is also fitted with conductivity sensor, temperature-compensated

pressure transducer and a temperature sensor. The manufacturer specifies that the system

measures sound velocity in the range of 1375 1900 m/s at a resolution of 0.001 m/s and

accuracy of 0.02 m/s.

Appendix C shows the derived profiles of the seawater velocity and temperature against depth.



The lead line method was used to check the draft of the single beam echo sounder

transducer the depths of the transducers below the marks on the vessel hull have been

established previously, and the draft was measured against these marks. Bathymetry sounding

data was reduced to Chart Datum (CD) Brunei Open Waters using predicted tides at Lumut.

The published harmonic constants are tabulated below.

Location : Lumut 5144

Latitude : 04o 41.00N

Longitude : 114o 27.00E

Time Zone : Local (GMT +08:00)

Table 3: Tide Harmonic Constants at Lumut.

Zo M2 S2 K1 O1

H(m) Go H(m) G

o H(m) G

o H(m) G

o H(m)

1.21 332 0.21 010 0.09 318 0.36 268 0.31

Chart Datum Brunei Open Waters (BOW) is 1.13 metres below mean sea level. Graphical plot

of the predicted tides during the period of survey is included in Appendix D.



Seismic Velocity Determination

All time to depth conversions for digital interpretation were based on the Time to Depth

Conversion Curve included in Appendix E. The curve is derived by estimation of Root Mean

Square (RMS) velocities against the selected velocity data from average velocity cube

provided by client.

Interval velocities, derived from the predicted velocity, generally increase with depth. The

interval velocity in the nth

layer was calculated using the Dix formula as follows.

( ) ( ) ( )

Where ( ) and ( ) are the predicted RMS velocities and and are

the known Two Way Travel Time (TWTT) associated with depth (TVDSS). The accuracy of

the depths derived using this method is dependent on the interval of stacking velocity reading

input. The error in the depths generally increases towards the centre of two provided readings.

The scatter plot of the stacking velocity value, Vint plot and the average velocity are

included in Appendix F. A time-depth conversion table and curve based on the interval

velocity at 5 ms TWTT interval is also included in Appendix E.



System Accuracy

Positioning System

The positioning of the vessel and survey equipment within the absolute coordinated reference

system was made possible using the Starfix HP and MRDGPS navigation system. The

Starfix.HP systems have been proven to give very accurate height observations with 95%

reliability percentage for vertical accuracies of 20 cm (HP). Starfix HP provides decimetre

level horizontal positioning accuracy at over 500 km range from reference station.

Accuracy in positioning depends upon the prevailing atmospheric conditions, the quality of the

base station coordinates provided, location of system antennae and the number of satellites

observed / available for the region. The above conditions were maximised as much as possible

during the survey operation to ensure precise and accurate navigation and positioning.



Seismic System

There are two types of resolution of interest in seismic systems: the vertical resolution (VR)

and the horizontal resolution (HR). The vertical resolution is defined as the point at which the

system has the ability to distinguish two pinching beds.

Theoretically, for the shallow geophysical seismic system the vertical resolution is

estimated to be of the dominant signal wavelength of the acoustic source. Once the thickness

of the unit is less than the wavelength, reflections between the upper and lower interfaces can

no longer be individually distinguished.

For the multichannel 2D high resolution seismic data the vertical resolution is a function

of frequencies, bubble pulse ringing, time depth conversion estimates, towing configuration

stability, the hydrophone characteristics and plotting accuracy. The vertical resolution of a

multichannel 2D high-resolution seismic system is defined as one quarter of the wavelength

().

VR = /4

Although the theoretical resolution may be defined by this relation, the actual recorded data

will be of lower resolution. Vertical resolution for the 4 x 4 array hull-mounted sub-bottom

profiler data is about 0.2 m and 2.0 m for the 2D high-resolution seismic data in the shallow

geological zone.

The horizontal resolution of sub-bottom shallow geophysical seismic system and multichannel

2D high-resolution seismic source depends on frequency (or wavelength, ) and the depth to

the reflector of concern. The acoustic pulse that insonifies a circular area on the seabed

describes the horizontal resolution of the source. The radius of this circle, known as the Fresnel

Zone (FZ), is dependent upon the dominant frequency of the acoustic source, the depth of the

reflector and the speed of the acoustic pulse.



A simplified method of obtaining the diameter of the FZ is:

FZ = (2z) 1/2

Where;

FZ = Diameter of Fresnel Zone

= Wavelength

z = Depth to reflector

The horizontal resolution of the multichannel 2D high-resolution seismic streamer (SHR)

depends on the group separation (x) and it is given as:

SHR = x / 2

32

5.4 Results & Discussions

The data obtained from the 2D High Resolution seismic survey was processed with a basic seismic

processing flow. One (1) seismic line from the field is used to illustrate the processing conducted.

Below is the summary of survey parameters.

ACQUISITION

Acquisition contractor: Fugro Acquisition mode: Single streamer cable, single array source Sample Rate : 1.0 ms Recording Length : 2.5 sec Group Interval : 12.5 m Shot Point Interval : 12.5 m No. of Channels : 96 Nominal Fold : 48

STREAMER CONFIGURATION Streamer Type : SeaMUX 24 Channel Active Streamer : 1200 m Group Length : 12.5m Streamer Depth : 2.5 m +/- 0.5 m Streamer Noise : Coherent Noise - ahead or behind - 10ub Feather Angle : Max 7 deg Near offset : 15.0 m No. of Birds / Spacing : 9 / 150 m Compasses at Bird no : 1, 3, 5, 7 and 9

RECORDING Tape Format : SEG-D 8036 24 bit Media Type : 3490E System : SeaMUX 2000 System Filter Delay : 29 ms Gun Delay : 30 ms LC Filter : 4.5 Hz, 6 dB/octave HC Filter : 412 Hz, 215 db/octave Near Trace : Channel 4 Aux. Channel : Ch1 (FTB), Ch3 (NF), Ch4 (FF)

ENERGY SOURCE PARAMETER Gun Array : 4 x 40 cu. inch sleeve gun clusters Gun Depth : 2.5 m +/- 0.5 m Gun Timing : Max +/- 0.5 ms Gun Pressure : Not less than 2000 psi

33

5.4.1 Project Deliverables

Below is the overall processing flow that was used for the processing of Line 10 from a certain field.

34

Loading the seg-D onto Uniseis

Objective: Loads raw data from storage (hard-disk or tape) onto Uniseis software for processing.

Description: The first step done is to load the SEG-D data onto the processing software in this case

Uniseis. SEG-D is a common raw data format of seismic data during acquisition recording. There are

also other seismic data formats such as SEG-A, SEG-B, SEG-C, etc. The final product of the

processing will be in SEG-Y which is commercially accepted in the oil and gas industry.

Produce Demultiplexed Raw Data

Objective: Display demultiplex data

Description:. Demultiplex data or DMX for short is the raw data which has been transcribed into

internal data format. Re-sequencing arranges the data from 101 onwards regardless on numbering

during survey. The first re-run of the line would begin with 1101, while a second re-run will start with

2101.

35

Figure 8: Demultiplexed Data of Line 10 shows the raw data that has been sequenced. As can be seen, the raw data is mixed up with the low

frequency noise.

36

Source and Receiver Static Corrections

Objective: Removes depth corrections and equipment delay

Description: System delay by gun and recording and depth corrections are made to the raw data.

System delay is obtained from field QC logs while the depth correction uses the equation below:

The frequency filter can also be specified at this point but at this point only frequencies that are too

low and too high are filtered. This is so that no relevant signal is left out.

Table 3: Parameters Table for Static Correction

Parameters Values

System Delay 57 ms

Depth Correction 3.91

Low Cut Slope; Low Cut Filter 18 DB/oct ; 5 Hz

High Cut Slope; High Cut Filter 72 DB/Octave; 412 hZ ;

37

Figure 9: Example of the raw data after static correction.

Low frequency noise previously present in the demultiplex file has been removed with filter

38

\

Figure 10: Zoomed-in Raw SHOT file for Line 10.

The top most received signal indicates the direct arrival while the sharp spikes below them show first return. The Near Trace Offset estimation is

important to ensure these do not overlap.

Indicates First

Return

Indicates Direct

Arrival

39

Near Trace Gather(NTG) Files

Objective: To obtain a general view of the geology in the area and check for gun miss-fires.

Description: NTG files plots one of the near channels in shot domain. Gun misfires is when gun fires

too early, too late or does not fire at all. This is indicated on the NTG section if displacments are seen

on the section.

Figure 11: Line 10 NTG Display:

As can be seen from the image, there are no displacements seen meaning the gun and recording system

is functioning accordingly.

40

Brute Stack

Objective: Enables us to have an outlook on the general condition of our seismic data and determine

the processing flow needed.

Description: Stacks data from all channels for the entire line and allows us to gain an initial

assumption on the geology and condition of our data. Two formats can be obtained from stacking

which is either Equalized or True Amplitude. True amplitude shows the compensation of signals that

have been attenuated or grown weaker as the signal travels further with depth. The signals are

predicted to be this way if attenuation did not occur. The true amplitude section allows us to identify

anomalies (unusual events) in the section since the amplitudes that stand out can be seen clearly.

Equalized form has also had the signals compensated due to attenuation and also equalized the signals.

This evens out the amplitudes making it easier to interpret the lithology, structures and stratigraphy.

Parameters involved:

1) Time Varied Gain (TVG): This is one of the scaling methods that adjust compensation or gain

recovery of the signals. The values it can be set to are dependent on the processing software used. In

the case of Unises, it ranges ranging from -5 to 5 for time and velocity respectively. The best signal

compensation is picked based on trial rounds.

2) Normal Move-Out correction: Normal Move-Out Corrections (NMO) is done to pre-stack data.

NMO basically uses a velocity function and calculates the NMO hyperbola at every time for every

offset of dipping seabed. It then shifts each sample back to the true "zero-offset" or true geometry

form. In the beginning, the velocity function that NMO is based on depends on the inserted velocities

by assumption. The basic rule of thumb is that velocity increase with depth in normal geology. The

velocity file is re-inserted with more accurate values once velocity picking is done.

3) Muting: Its purpose is to remove the stretched move-out caused by NMO. These regions of

velocities are not accurate and may cause even false structures to appear. Another purpose is to remove

direct arrivals (signals that do not travel through the subsurface) and leave on the data ranging from the

seabed and below intact. Muting may look like cutting of data for cosmetics, but it actually allows us

to be focused on the appropriate signals and not confused by the noise or unwanted signals.

41

Figure 12: Line 10 Equalised Brute Stack.

The amplitudes have undergone compensation then equalization. That is why all amplitudes seem nearly constant throughout the section.

This allows easier detection of structure, horizon and to predict lithology.

42

Figure 13: Line 10 True Amplitude Brute Stack.

Shows the original amplitude of the seismic after compensation. Anomalies are detected by comparing the amplitudes to the seabed since the seabed

usually has the highest reflection.. If the amplitude is comparable or higher than the seabed(supposedly is the strongest reflector), it can be

considered an anomaly.

43

Figure 14: Trial of Time Varied Gain

The five (5) sections above reveal different values of Time Varied Gains(TVG). The time and velocity values are (0,1), (1,-2, (1,0), (1,2) and (1,3) f

respectively. Among the five sections, the fourth and fifth sections have been over-compensated since noise starts to appear while the first and

second section is under-compensated The third section has been picked as the overall best as the signals are quite clear and noise is absent from the

data.

Noise

44

Figure 15: Normal Move-Out Gather

The move-out velocities. To show the true geometry of the seabed and subsequent layers, the velocities are adjusted or stretched. The more the

stretch the more inaccurate the velocity, and the more false the geometry,

Seabed being

stretched

45

Figure 16: Muting of Line 10

The above section shows two(2) sections, the left before muting and the right after muting. In the left figure, muting has been done to remove the

stretched velocities due to move-out on the upper left of the section and also the noise above the seabed. Muting can also be done based on water

bottom, CDP or;manual mute picking.

Muted region from

350ms for 96th trace

Noise above seabed has

been muted at 35ms

46

Time Frequency Denoise TFDN

Objective: Reduces noise and de-spikes data.

Description: Noise is considered as unwanted signals in our data. Among the sources of noise in the

survey can be either swell noise or equipment noise. Swell noise usually ranges from 20 to 25 Hz

while equipment noise can go as high as the the frequency of the survey. Detecting and eliminating

noise is important so that we do not interpret the noise as signals instead. Noise signals are usually in

isolated groups and follow a certain pattern.

47

Figure 17A: Data before Denoised

48

Figure 17B: Denoised data.

As can be seen, the spking above has been removes and the signal below has been enhanced since the overall scale has been lowered.

49

Velocity Picking

Objective: Collects Root Mean Square (RMS) velocity to correct NMO/

Description: Almost all processing sequences require an accurate average in velocity to operate. A

velocity file is prepared that lists the average velocity over time for the seismic line in question.

Initially, predicted velocities are input in the velocity file as a temporary use. These velocities can give

an early prediction since generally velocities increase with depth since the layers increase in density

with depth.

In order to establish the velocity field for the seismic line, a suite of velocity functions at

discrete positions along the line need to be determined. This is done through velocity analysis or

generally known as velocity picking. There are several methods of velocity picking as follows: The

velocities picked improve the move-out gather and provides more accurate geometry of the layers.

After velocity is picked, the data is re-stacked to use the corrected normal move-out.

i. Semblance display: An energy concentration display; usually with red being the area with

concentrated velocity. Semblance is used to pick the interval velocity.

ii. Gathers: Normal Move Out gathers that follow a hyperbolic shape of the velocity function

iv. Stack: A compilation of the signals across all channels.

Modern computer-aided velocity analyses make use of all the techniques above. From here, the

velocities of the intervals are picked and the values are transferred into the velocity file which had

been filled with assumed velocities before velocity picking .

50

Figure 18: Image of Shot Gather during velocity picking

During velocity picking, the best gather is the with the least stretch. This gives the most accurate

velocity. (Refer to yellow box with green line)

51

Figure 19: Image of Energy Samblance during Velocity Picking

Velocity increases with depth unless there are anomalies such as shallow gas, etc. Anomalies such as

salt domes cause a sharp increase in velocity if present.

Locations of high velocity

concentration are picked

based on the red colour spots.

A stair like structure is

achieved since the general rule

of thumb is that velocity

increases with depth.

52

Figure 20: Stack of the seismic line

The stack allows us to keep track of reflectors picked and also gives us a larger perspective on the

anomalies in the seismic. The stronger reflectors may indicate a change in the sequence while an

isolated group of amplitudes may indicate anomalies.

An interval of 80

CDP(500m) is chosen for

the velocity picking. The

interval used is usually up

to the client

During picking, the horizon acts

as a guide to pick the velocity.

53

Deconvolution Before Stack

Function of Deconvolution Before Stack:

i) Remove reverberations

ii) Compress wavelets to make the reflection more visible and enhance continuity

iii) Remove multiples

Description: 2 important parameters to take note are operator length and gap. The operator length

should be long enough to include at least two "bounces" of the maximum reverberation time to be

removed. A gap meanwhile is inserted into the filter that prevents the filter from changing the data

close to every reflector. A gap of 1 sample or less implies spiking deconvolution, any higher gap

implies predictive deconvolution. The gaps normally used extend from 2-10 samples of data and cause

less spectral whitening (and associated noise).

Predictive deconvolution is mainly used to eliminate multiples which usually appear at

intervals. A model is made to replicate these intervals and the deconvolution acts based on the model.

Spiking deconvolution is a general deconvolution that is applied across the section mainly to compress

wavelets so that they are more visible.

Parameters: Operator length: 40ms; Gap 8 ms

54

Figure 21: Trial of Different Gaps and Operator Lengths

There are 7 section in total with an operator length of 40ms, 50ms , 60ms , 70ms , 80ms , 100ms , 120ms and a gap of 8ms respectively. The

changes are very subtle to see cganges in the multiple. Thus focusing on an anomaly (the circles) makes it easier to see that the rightmost section

enhances the visibility of the reflection

Multiple of

seabed

55

Figure 22: Deconvolved True Amplitude Stack; 40ms operator length; 8ms gap

56

Figure 23: Deconvolved Equalised Stack; 40ms operator length; 8ms gap

57

Migration

Function of Migration is to:

i) Correct dip and position of dipping layers

ii) Collapse of diffractions

iii) Improve Resolution

Description: Migration is the process of reconstructing a seismic section so that reflection events are

repositioned under their correct surface location and at a corrected vertical reflection time. Seismic

migration is the procedure by which an image of the correctly positioned subsurface reflecting

interfaces is obtained from the seismic section. Migration is the process that moves the data on the

stacked seismic section to its correct position in both time and space. Even after NMO corrections.

reflections from dipping events are plotted in their wrong locations. To rectify this, the points need to

be moved "up-dip" along a hyperbolic curve with the shape of this hyperbola depending on the

velocity field. Migration works best in areas with dipping seabed and complex geology but it should be

applied in whatever case since it can improve resolution and as experienced processors quote;

insignificant migration is better than no migration at all.

There are several types of migration namely for different needs of the processor: Each of these

migrations has a nuique algorithm

i) Time Migration: Needed when the stacked section contains diffractions or structural dip. This

migration is valid for vertically varying velocities and acceptable for mild lateral velocity variations.

ii) Depth Migration: Needed when the stacked section contains structural dip and large lateral

velocity gradients.

iii) Pre-stack Partial Migration (PSPM): Post-stack migration is acceptable when the stacked section

is equivalent to a zero offset section. This is not the case for conflicting dips with different stacking

velocities or large lateral velocity gradients. PSPM or dip move-out (DMO) provides a better stack that

can be migrated after stack. However, PSPM only solves the problem of conflicting dips with different

stacking velocities.

iv) Full time migration before stack: The output is a migrated stack. No intermediate un-migrated

stacked section is produced.

58

Figure 24: Image of before/after migrated stack. Individual points on the stack are placed back in their correct location by hyperbolic velocity

function. As can be seen in the section that there are slight different placements of the data.

59

Output Seg-Y

Finally, after going through the processing sequence that has been set, the seg-Y output that is

produced is ready to be interpreted by an interpretation geophysicists. However, since a very basic

flow of processing was used in this particular case, the seg-Y outputs obtained were mainly a trial run

in order to understand and appreciate the processing. Processing is actually an art of producing the best

quality data for interpretation with the fewest amount of steps involved. This is always the biggest

challenge for every seismic processor.

For the seismic interpretation, an experienced processing house was appointed to carry out the

the processing and it is their Seg-Y outputs which be used in the interpretation. The processing flow

used by the processing house is as follows:

1. Reformat 2.5s, 1ms, 96 channels

2. System delay -55.67ms

3. Source and receiver static correction

4. Geometrical spreading correction VVT +5dB gain

5. Low cut filter 15Hz/18dB/Oct

6. 2 passes of swell noise attenuation and De-spiking

8. Linear noise attenuation (cut 400m/s) starting time below 500ms

9. Tau-P DBS, Gap length 12ms, operator length 120ms

10. Zero phasing applied

11. Q compensation Amplitude and phase Q 170 and reference frequency 250Hz + 10 dB gain

12. Velocity analysis every 500m grid

13. Kirchhoff PSTM with 1km, 75 degree dip

14. Final angle mute 40degree

15. Scaling 500ms gate

16. Final raw stack and Equalized stack were produced.

60

Figure 25: Line 10 Finalised SEG-Y(Equalized)

61

Figure 26: Line 10 Finalised SEG-Y(True Amplitude)

62

5.4.2 Data Gathering / Analysis

After the processing of the lines were completed, the next part was to interpret the processed seismic

line. The interpretation done involved the stratigraphy and geological structures, anomalies present and

also drilling prognosis.

Intermediate Geology

The acquisition of the 2D high-resolution multichannel seismic data was carried out in generally good

weather conditions and the 2.5 seconds data are of good quality with penetration down to

approximately 2 seconds.

Limitation of interpretation

The high-resolution 2D seismic data was analysed for potential hazards that may affect drilling at the

proposed well location.

The distribution of survey line intervals is such that only events of great enough size can be

identified. Discrete shallow gas pockets that fall between survey lines or smaller than the minimum

line intervals (100 m) are not likely to have continuities identifiable from the seismic dataset.

Geological structures and amplitude events within seismic attenuation zone are not likely to be

identified from the seismic dataset. The signal attenuation is generally associated with the chaotic

reflection area.

63

Intermediate Stratigraphy

Based on the acoustic characteristics of the high-resolution seismic data, the intermediate

geological zone has been divided into seven (7) separate sequences, namely Sequences I to VII,

separated by acoustically coherent reflectors, namely Horizons H1 to H6. The unit boundaries

are defined based on changes in the seismic reflection characteristics of each sequence and / or

prominent reflecting horizons (or unconformities, if any).

The general stratigraphy and structure of the survey area is best described by 2D high-

resolution seismic sections, in equalised migrated form.

Sequence I (Shallow Geological Zone)

Sequence I is the youngest deposits and relatively thinner sequence, which is acoustically semi-

transparent, characterised by generally weak parallel with well-laminated internal reflections.

Several buried channels near seabed are the most significant features observed within Sequence

I. The extents of these buried channels are not clearly defined due to limited resolution of the

2D seismic section but these occur generally within 50 m below seabed.

The base of Sequence I is marked by a moderate to high amplitude reflector, Horizon H1.

Several normal faults are observed to extend up to this sequence.

This Sequence I is interpreted to consist of clayey SILT and predominantly CLAY with SAND

intervals.

64

Sequence II

Sequence II is characterised by moderate to strong seismic impedance, with dipping reflectors

to northwest, intermittent reflections and some chaotic internal reflectors. This sequence is

inferred to consist of possible CLAY and SAND layers. Numerous normal faults could be

observed within Sequence II on the seismic sections, which are attributed to differential

compaction. Occasional strong reflectors are observed within this sequence but this amplitude

event is interpreted as due to lithological change.

A continuous and relatively coherent seismic reflector defined as Horizon H2 identifies the base

of this sequence.

Sequence III

Sequence III is characterised by moderate seismic impedance, reflectors that are dipping to

northwest with some irregular to intermittent internal reflectors. Occasional strong reflectors

are observed within this sequence but this amplitude event is interpreted to be lithologically

related. Numerous normal faults cut through the sequence and show displacement in reflectors.

It is interpreted to consist of possible CLAY interlayered with SAND.

The base of Sequence III is marked by a coherent reflector namely Horizon H3.

Sequence IV

Sequence IV is interpreted to consist of possible CLAY, grading to CLAYSTONE, interlayered

with SANDSTONE. It is characterised by moderate to high seismic impedance with reflectors

that are sub-parallel and dipping to northwest. The reflectors show displacements along

numerous faults that cut through the sequence. Occasional strong reflectors are observed within

this sequence but this amplitude event is interpreted as lithologic change. The base of Sequence

IV is marked by a strong and coherent reflector namely Horizon H4.

65

Sequence V

Sequence V is characterised by moderate to strong, well defined, laminated, northwesterly

dipping reflectors. This sequence is inferred to consist of possible CLAY, grading to

CLAYSTONE, interlayered with SANDSTONE.

The layers have been displaced by several normal faults that extend from shallower sequences.

The base of Sequence V is marked by a relatively strong reflector, namely Horizon H5.

Sequence VI

Similar with Sequence V, Sequence VI is characterised by moderate to strong, well defined,

laminated and northwest dipping reflectors. This sequence is displaced by several normal faults

that extend from shallower depth within the survey area.

Sequence VI is interpreted to consist of possible SANDSTONE interlayered with

CLAYSTONE. A coherent reflector, namely Horizon H6, marks the base of Sequence VI.

Sequence VII

Sequence VII is interpreted as the deepest sedimentary sequence seen on the data below

Horizon H6 down to the limit of the seismic record.

The upper half of Sequence VII shows similar seismic characteristics to the overlying

sequences, where moderate internal reflections with occasionally medium to strong internal

reflector are observed. The lower half of this sequence exhibits generally discontinuous

internal reflectors, which is associated with noise. Several normal faults were observed cutting

through the upper half of Sequence VII and extended upward to Sequence II. There may be

other faults within the sequence that could not be resolved due to lower resolution or noise.

The faults are attributed to differential compaction of the deeper sedimentary sequences.

This sequence is interpreted to consist of possible CLAYSTONE, SILTSTONE and

SANDSTONE.

66

It is to be expected that the degree of sediment compaction and consolidation would increase

with depth, and that this would be associated with a general increase in shear strength.

The predicted intermediate zone lithology at the proposed well locations is shown in the table

below

Table 4: Predicted Intermediate Lithology at the Proposed and Revised Well Location.

Horizon/

Sequence

Proposed Location Revised Location

Predicted Lithology TWTT

[ms]

Depth

[m BSL]

TWTT

[ms]

Depth

[m BSL]

Seabed 53 41 50 39

Sequence I Clayey SILT and predominantly

CLAY with SAND intervals

Horizon H1 111 89 97 77

Sequence II CLAY and SAND layers

Horizon H2 264 224 158 128

Sequence III CLAY interlayered with SAND

Horizon H3 480 442 398 355

Sequence IV

CLAY interlayer with

SANDSTONE grading to

CLAYSTONE

Horizon H4 898 924 845 860

Sequence V

CLAY interlayer with

SANDSTONE grading to

CLAYSTONE

Horizon H5 1234 1383 1231 1382

Sequence VI SANDSTONE interlayer with

CLAYSTONE

Horizon H6 1412 1653 1410 1663

Sequence VII CLAYSTONE, SILTSTONE and

SANDSTONE

67

Geological Structure

The general lithology across the entire survey area comprises uniform, conformable and

unconformable sequences of normally consolidated sediments. Sedimentary layers within the

intermediate geological zone are generally well defined. These include buried shallow channels

within the upper sequence (Sequence I) and predominantly laterally homogeneous sedimentary

sequences at the lower segment that dip to the northwest (Sequences II to VII). Sequences II to

VII appear to have been deposited in low-energy environment (deep water), which was

followed by episodes of high-energy deposition of sediments that formed Sequence I and

created several buried channels in the shallower section.

The buried channels within Sequence I indicate episodes of intermittent high-energy (shallow

water), post-depositional environment resulting in the formation of overlapping channels.

However, the extents of these buried channels are not clearly defined due to limited resolution

of the 2D seismic section.

Faults generally cut through the sequences throughout the whole survey area, mostly

concentrated within Sequences II to V. The interpreted faults strike northeast-southwest and

dip towards either northwest or southeast. The bottom extent of the faults could not be traced

due to decrease in seismic resolution, which makes small offsets not visible on time sections,

and seismic signal attenuation. For the same reason, other faults that may be present within

Sequence VII could not be resolved because of lower resolution and noise. The faults are

attributed to differential compaction of deeper sequences, possibly including Sequence VII, due

to the combined weight of the overlying sequences.

68

The fault intersection at each of the proposed location is summarised in table below:

Table 5: Summary of Fault Intersections at the Proposed and Revised Well Locations.

Well Location Depth of fault extending below well surface location

Proposed Iron Duke Blk

10 417 ms TWTT (373 m BSL)

1163 ms TWTT (1283 m BSL)

Revised Iron Duke Blk 10 None

Caution is advised while drilling through these fault intersections at the proposed well location.

On the other hand, none of the faults extends below the surface location of the revised well

location. Other faults that may occur within Sequence VII could not be resolved on the data

due to lower resolution at these depths. Faults may cause loss of fluid circulation.

Below are images of digital seismic lines passing through/ nearby the proposed Iron Duke Blk

10 well location and revised well location.

Proposed Well Location (offset 7 m NW) SW NE

Seabed

500 m

H2

H3

H4

Survey Area

H5

H6

Sequence I

Sequence II

Sequence III

Sequence V

Sequence VII

Sequence VI

Sequence IV

H1

Acoustic Masking

Example of equalized seismic section, SW-NE mainline ID-2D-L10, passing near the proposed well location. FIGURE 27

Tw

o W

ay T

rave

l T

ime

(T

WT

T)

NW SE

Survey Area

500m Proposed Well Location (offset 2 m NE)

Seabed

H1

H2

H3

H4

H5

H6

Sequence I

Sequence II

Sequence III

Sequence V

Sequence VII

Sequence VI

Sequence IV

Acoustic Masking

Example of equalized seismic section, NW-SE cross line ID-2D-L59, passing near the proposed well location. FIGURE 28

Tw

o W

ay T

rave

l T

ime

(T

WT

T)

Example of equalized seismic section, NW-SE cross line ID-2D-L61, passing near the revised well location. FIGURE 29

Tw

o W

ay T

rave

l T

ime

(T

WT

T)

Seabed

Sequence I

Sequence II

Sequence III

Sequence V

Sequence VII

Sequence VI

Sequence IV

H1

H2

H3

H4

H5

H6

NW SE 500m

Revised Well Location

Survey Area

72

Amplitude Anomalies and Risk Assessment

Three (3) levels of amplitude anomalies were found within the survey area between 57 ms and

441 ms TWTT (44 399 m BSL). The probability of these anomalies being gas related (gas

risk classification) is based on the following criteria.

Table 6: Amplitude Anomalies and Risk Assessment.

Probability of Being Gas Related Direct Hydrocarbon Indicators & Seismic Attributes

Low Moderate amplitude with 1 or 2 DHI's or very high

amplitude alone

Moderate High amplitude with 2 other gas diagnostics

High High amplitude with 3 or 4 other gas diagnostics

Features (other than high amplitude ) considered in gas hazard classification:

Negative phase and/or phase reversal at edges of anomaly

Acoustic masking of underlying horizons

Velocity or time sag of underlying horizons (Pull-down effects)

Significant frequency loss immediately below the anomaly

Flat spots, gas/water contacts, and any other hydrocarbon indicators

Sedimentary/geological structural evidence e.g. faults, good structural reservoirs

In addition, size, orientation and vertical connectivity (faults) to deeper accumulations were also considered in the classification

Anomaly Group 1 [57 97 ms TWTT (44 77 m BSL)]

Anomaly Group 1 is mostly associated with the base of buried channel within Sequence I and

appears as a widespread area and small patches within the survey area. The moderate to high

seismic amplitude show phase reversal among dipping and intermittent reflectors, reverberation

and attenuation of deeper reflectors. Several faults possibly extends to the large anomaly to the

west of the proposed well location but could not be reliably traced because of reflector

distortion and attenuation. While faults are known to be good conduits for gas migrating

upwards, there are no gas-related, anomalous reflectors identified along the faults in the deeper

section.

73

Therefore, the anomaly is more likely to be related to accumulation of biogenic gas at the base

of the buried channel. Possible gas seepages through the seabed from the widespread anomaly

to the west of the proposed location should be verified from anomalies on the sub-bottom

profiler data and related features on the seabed, such as pockmark clusters, that may be seen on

the side scan sonar data.

Overall, this anomaly group is classified as moderate to high probability of being gas related.

Moderate gas probability is attributed to some small patches including below the proposed

well location, but the large anomaly to the west of the proposed location is considered to have

high gas probability. While the biogenic gas may not be pressurised at these shallow depths,

gas is known to weaken sediments within which it occurs. Strength of shallow soils in this area

could vary significantly.

Anomaly Group 1 extends below the proposed well surface location at a depth of 66 ms TWTT

(52 m BSL) but none is found below the revised well surface location. The nearest Anomaly

Group 1 to the revised Iron Duke Blk 10 well location is at about 68m to the NE at a depth of

68 ms TWTT (53m BSL).


Anomaly Group 2 occurs within Sequence II and characterised by moderate amplitude without

any evidence of masking effect or velocity pull down. It is mainly identified within the upper

half of Sequence II throughout the survey area and is probably related to accumulation of

biogenic gas within the sequence.

Overall, this anomaly group is classified as low probability of being gas related.

The anomaly occurs as a single elongated patch near the NW limit of the survey area with the

nearest distance of approximately 2680 m WNW of the proposed Iron Duke Blk 10 well

location at depths of 240-355 ms TWTT (202-312 m BSL). The same nearest anomaly is found

at about 3405 m to the NW of the revised well location.

74


Anomaly Group 3 occurs within the top half of Sequence III and characterised by moderate

amplitude with evident phase reversal and attenuation of deeper reflectors. It is probably

localised accumulation of biogenic gas or organic materials associated with a thin interval of

locally dipping and irregular layers in the upper segment of Sequence III. It is found as two

small patches near the north eastern and south western corners of the survey area.

Overall, this anomaly group is classified as low probability of being gas related.

The nearest occurrence of the anomaly is found at approximately 1921 m SW of the proposed

Iron Duke Blk 10 well location at depths of 318-390 ms TWTT (276-346 m BSL). The same

anomaly is nearest to the revised well location at a distance of 2222 m to the SW.

The summary of gas probability is summarised in the following table:

Table 7: Gas Probability for the Proposed and Revised Well Locations.

Anomaly

Group

Depth

ms TWTT

(m BSL)

Closest distance

and direction from

the proposed Iron

Duke Blk 10 well

location

Closest distance

and direction from

the revised Iron

Duke Blk 10 well

location

Characteristics Probability of

gas

1

57 97

(44 77)

At location 66 ms TWTT (52

m BSL)

68m NE at 68 ms TWTT

(53m BSL)

Moderate to high amplitude, phase

reversal, reverberation, seismic attenuation,

association with channels

Moderate to High

(Biogenic gas)

2

239 259

(201 219) 2680 m WNW 3405 NW

Moderate amplitude , phase reversal

Low

3

332 441

(290 399) 1921 m SW 2222 m SW

Moderate amplitude, phase reversal, seismic

attenuation

Low

Proposed Well Location (offset 7 m NW) SW NE

Seabed

500 m

Survey Area

Anomalies Group 1 Anomalies Group 1

Anomaly Group 3

Anomaly Group 3

Example of relative amplitude seismic section, SW-NE mainline ID-2D-L10, passing near the proposed well location. FIGURE 30

Tw

o W

ay T

rave

l T

ime

(T

WT

T)

SW NE

Survey Area

500m Proposed Well Location (offset 7 m NW)

Anomalies Group 1

Anomaly Group 3

Anomaly Group 3

Seabed

Anomalies Group 1

Example of relative amplitude seismic section, SW-NE mainline ID-2D-L10, passing near the proposed well location

(Top 1.1 ms TWTT BSL). FIGURE 31

Tw

o W

ay T

rave

l T

ime

(T

WT

T)

NW SE

Survey Area

500m

Seabed

Proposed Well Location (offset 2 m NE)

Anomalies Group 1


Example of relative amplitude seismic section, NW-SE cross line ID-2D-L59, passing near the proposed well location. FIGURE 32

Tw

o W

ay T

rave

l T

ime

(T

WT

T)

NW SE

Survey Area

Proposed Well Location (offset 2 m NE)

Seabed

Anomalies Group 1


500m

Example of relative amplitude seismic section, NW-SE cross line ID-2D-L59, passing near the proposed well location

(Top 1.1 ms TWTT BSL). FIGURE 33

Tw

o W

ay T

rave

l T

ime

(T

WT

T)

Example of relative amplitude seismic section, NW-SE mainline ID-2D-L61,

passing near the revised well location FIGURE 34

Tw

o W

ay T

rave

l T

ime

(T

WT

T)

Anomalies Group 1 Anomalies Group 1 Anomalies Group 1

Revised Well Location

Survey Area

NW SE

80

Top Hole Drilling Conditions

Both the proposed and revised wells are located on a relatively flat seabed, underlain by high-

energy deposits within the upper sequence (Sequence I), and relatively low-energy deposits

within the lower sequences (Sequences II to VII), with predominantly laterally homogeneous

sedimentary sequences that gently dip to the northwest.

The potential hazards below the surface location of the proposed well include shallow gas

associated with shallow, buried channels and normal faults. However, none of these hazards

occurs below the revised surface location of the well. The following drilling constraints have

been forecast below the proposed and revised well surface locations:

Table 8: Summary of Drilling Constraints Below the Proposed and Revised Well

Surface Locations.

Proposed Well

Location

Potential

constraints Description

Well Location

Fault

Faults extend below surface location of well at 417 ms TWTT (373 m

BSL) and 1163 ms TWTT (1283 m BSL). Potential loss of fluid

circulation at the fault intersections.

Amplitude Anomaly

Anomaly Group 1 extends below the surface location of the proposed

well at 66 ms TWTT (52 m BSL). Moderate to high probability of

encountering gas (possibly biogenic) but not expected to be

overpressured due to shallow depth. Gas could have weakened the

shallow sediments.

Revised Well

Location

Fault No fault extending below surface location of well

Amplitud

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Seismic Processing and Interpretation