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.


1.0 ACKNOWLEDGEMENT 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 author’s Host Company Supervis or, 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, Azmi, for his his guidance, support and advice in completing 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 als o would like to thank UTP Supervisor, Mr. Jas mi B. Ab. Talib for spending his precious time to visit the host companies, give advice and evaluate author’s performance 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.

Muhammad Hasif Syazwan 14912

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2.0 TABLE OF CONTENT Content Host Company Verification Statement 1.0 Acknowledgement Acknowledgement 2.0 Table of Content 3.0 List of Tables 4.0 List of Figures 5.0 Industrial Training Project Report 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

Page Numbering 1 2 3 3 5 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

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5.3 Methodology Methodology 5.3.1 Research Methodology 5.3.2 Key Milestone 5.3.3 Gantt Chart 5.3.4 Tools/Equipment Required 5.4 Results and Discussions 5.4.1 Project Deliverables 5.4.2 Data Gathering / Data Analysis 5.4.3 Findings 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 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 6.0 Reference 7.0 Appendices

21 21 22 23 24 32 32 62 83 84 84 85 86


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87 87 88 89 90 91 92

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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..


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Industrial Training Report 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


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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 ma y 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.


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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 se epage activity.

Isolated Pockmark Coalesced Pockmark

Figure 1: Multibeam Data with Coalesced Pockmark and Isolated Pockmarks


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Pockmark Cluster

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.


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Carbonate

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).


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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

Channels

Figure 5: Sub-bottom Profiler Showing Buried Channels


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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 Muhammad Hasif Syazwan 14912

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Faults: it can be defined as fracture in the earth’s 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.


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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 fiel d 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.


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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 b y 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


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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.


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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 recover y. 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.


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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 an y 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.


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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.


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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, fl uid 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.


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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 t o 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). Muhammad Hasif Syazwan 14912

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High-frequency multibeam echo sounders (MBESs) provide a good horizontal resolution, making it possible to distinguish fine details at the water – seafloor 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 ship’s 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 ar e 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.


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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.


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5.3.2 Key milestone

Phase

Month

Task

Description

Training

1 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 t he 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.

Started Seismic Processing

2

3

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.

July

Review of Processing by Processing Geophysicists

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

Interpretation of Seismic

4

July

July / August

Interpretation of Geological structures and stratigraphy Interpretation of anomalies and drilling prognosis

5

August

Final Review of processing and interpretation

6

August

Submission


Three (3) seismic lines were picked based on their structures and stratigraphy as highlight points of the offshore geohazard assessment. 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. The overall processing and interpretation was commented by the Geophysical Reporting Manager. Amendments were made as adviced. Submission of report to UTP Supervisor.

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5.3.3 Gantt Chart Month Week No.

1

May 3

June 4

5

6

July 7

8

9

10

11

August 12

13

Task 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


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5.3.4 Tools / Equipemt / Software Required

The site survey was carried out using Fugro’s long-term chartered geophysical survey vessel. The vessel was positioned and navigated using Fugro’s 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: Group length: Shot point interval: Streamer depth: Source depth: Sample rate: Record length: Low cut filter: High cut filter: Source to near trace offset / centre of first active channel

96 12.5 m 12.5 m 2.5m(+/- 0.5m) 2.5 m (+/- 0.5m) 1.0 ms 2.5 s 4.5Hz, slope 6 dB/Octave 412Hz, 215 dB/Octave 15 m

Table 2: Seismic Survey Parameters

Another Fugro in-house software was used called Uniseis f or 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.


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Navigation and Single Beam Bathymetric Processing

Real-time logging of navigation and bathymetric data was implemented using Fugro’s Starfix.Seis navigation system. Processing of the acquired navigation and bathymetric data was initiated onboard the survey vessel using Fugro’s 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.


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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 car ried 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 a gainst depth.


26


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: Zo

Tide Harmonic Constants at Lumut.

M2 o

S2 o

K1 o

O1 o

H(m)

G

H(m)

G

H(m)

G

H(m)

G

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.


27


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 n th 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, V int 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.


28


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 at mospheric 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.


29


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 ¼ of the dominant signal wavelength of the acoustic source. Once the thickness of the unit is less than ¼ 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 r esolution 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 (λ). VR = λ/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, λ) 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.


30


A simplified method of obtaining the diameter of the FZ is: FZ = (2λz)

1/2

Where; FZ = Diameter of Fresnel Zone λ = 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


31

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: Acquisition mode: Sample Rate : Recording Length : Group Interval : Shot Point Interval : No. of Channels : Nominal Fold :

Fugro Single streamer cable, single array source 1.0 ms 2.5 sec 12.5 m 12.5 m 96 48

STREAMER CONFIGURATION Streamer Type Active Streamer Group Length Streamer Depth Streamer Noise Feather Angle Near offset No. of Birds / Spacing Compasses at Bird no

: SeaMUX 24 Channel : 1200 m : 12.5m : 2.5 m +/- 0.5 m : Coherent Noise - ahead or behind - 10ub : Max 7 deg : 15.0 m : 9 / 150 m : 1, 3, 5, 7 and 9

RECORDING Tape Format Media Type System Filter Delay Gun Delay LC Filter HC Filter Near Trace Aux. Channel

: : : : : : : : :

SEG-D 8036 24 bit 3490E SeaMUX 2000 System 29 ms 30 ms 4.5 Hz, 6 dB/octave 412 Hz, 215 db/octave Channel 4 Ch1 (FTB), Ch3 (NF), Ch4 (FF)

ENERGY SOURCE PARAMETER Gun Array Gun Depth Gun Timing Gun Pressure

: : : :

4 x 40 cu. inch sleeve gun clusters 2.5 m +/- 0.5 m Max +/- 0.5 ms Not less than 2000 psi

32

5.4.1 Project Deliverables

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

33

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.

34

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. 35

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 ;

36

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

Low frequency noise previously present in the demultiplex file has been removed with filter 37

\

Indicates Direct Arrival

Indicates First Return

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. 38

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.

39

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 “dip ping” 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.

40

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. 41

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. 42

Noise

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. 43

Seabed being stretched

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, 44

Noise above seabed has been muted at 35ms

Muted region from th

350ms for 96 trace

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.

45

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.

46

Figure 17A: Data before Denoised

47

Figure 17B: Denoised data.

As can be seen, the spking above has b een removes and the signal below has been enhanced since the overall scale has been lowered. 48

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 .

49

Figure 18: Image of Shot Gather during velocity picking

During velocity picking, the best gather is the with the leas t stretch. This gives the most accurate velocity. (Refer to yellow box with green line) 50

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.

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.

51

An interval of 80 CDP(500m) is chosen for the velocity picking. The interval used is usually up

During picking, the horizon acts as a guide to pick the velocity.

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. 52

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

53

Multiple of seabed

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

54

Figure 22: Deconvolved True Amplitude Stack; 40ms operator length; 8ms gap 55

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

56

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. 57

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.

58

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 400µm/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. 59

Figure 25: Line 10 Finalised SEG-Y(Equalized) 60

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

61

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 strat igraphy and geological structures, anomalies present a nd 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.

62

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 highresolution seismic sections, in equalised migrated form.

Sequence I (Shallow Geological Zone)

Sequence I is the youngest deposits and relatively thinner sequence, which is acoustically semitransparent, 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.

63

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 r eflector 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 name ly Horizon H4.

64

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. 65

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

Seabed

Proposed Location

Revised Location

TWTT [ms]

Depth [m BSL]

TWTT [ms]

Depth [m BSL]

53

41

50

39 Clayey SILT and predominantly CLAY with SAND intervals

Sequence I Horizon H1

111

89

97

77

Sequence II Horizon H2

CLAY and SAND layers 264

224

158

128

Sequence III Horizon H3

CLAY interlayered with SAND 480

442

398

355 CLAY interlayer with SANDSTONE grading to CLAYSTONE

Sequence IV Horizon H4

898

924

845

860 CLAY interlayer with SANDSTONE grading to CLAYSTONE

Sequence V Horizon H5

1234

1383

1231

1382 SANDSTONE interlayer with CLAYSTONE

Sequence VI Horizon H6 Sequence VII

Predicted Lithology

1412

1653

1410

1663 CLAYSTONE, SILTSTONE and SANDSTONE

66

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.

67

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 Revised Iron Duke Blk 10

417 ms TWTT (373 m BSL) 1163 ms TWTT (1283 m BSL) 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.

68

SW

500 m

Proposed Well Location (offset 7 m NW)

NE

Seabed Sequence I

H1

Sequence II

H2 Acoustic Masking Sequence III

H3

) T T W T ( e m i T l e v a r T y a W o w T

Sequence IV

H4 Sequence V

H5 Sequence VI

H6

Sequence VII

Survey Area

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

FIGURE 27

500m

NW

Proposed Well Location (offset 2 m NE)

SE

Seabed H1

Sequence I

Acoustic Masking

Sequence II


H2 Sequence III

H3

Sequence IV

H4 Sequence V

H5 Sequence VI

H6 Sequence VII

Survey Area

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

FIGURE 28

500m

NW

SE Revised Well Location

Seabed Sequence I H1

Sequence II


H2 Sequence III

H3

Sequence IV

H4 Sequence V

H5 Sequence VI

H6 Sequence VII

Survey Area

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

FIGURE 29

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 o f 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. 72

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.

73


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.

Depth Anomaly Group

ms TWTT (m BSL)

57 – 97 1

(44 – 77)

Closest distance

Closest distance

and direction from

and direction from

the proposed Iron

the revised Iron

Duke Blk 10 well

Duke Blk 10 well

location

location

Characteristics

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

2680 m WNW

3405 NW

Moderate amplitude , phase reversal

1921 m SW

2222 m SW

Moderate amplitude, phase reversal, seismic attenuation

Probability of gas

Moderate to High (Biogenic gas)

239 – 259 2

(201 – 219)

332 – 441 3

(290 – 399)

Low

Low

74

SW


500 m

NE

Seabed

Anomalies Group 1

Anomalies Group 1

Anomaly Group 3

Anomaly Group 3


Survey Area

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

FIGURE 30

SW

500m


NE

Seabed

Anomalies Group 1

Anomalies Group 1

Anomaly Group 3


Anomaly Group 3

Survey Area

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

NW


500m

SE

Seabed

Anomalies Group 1 Anomalies Group 1

Anomalies Group 1


Survey Area

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

FIGURE 32

NW


500m

SE

Seabed

Anomalies Group 1 Anomalies Group 1

Anomalies Group 1


Survey Area

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

SE

NW Revised Well Location

Anomalies Group 1

Anomalies Group 1

Anomalies Group 1


Survey Area

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

FIGURE 34

Top Hole Drilling Conditions

Both the proposed and revised wells are located on a relatively flat seabed, underlain by highenergy 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 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 Faults extend below surface location of well at 417 ms TWTT (373 m

Fault

BSL) and 1163 1163 ms TWTT (1283 m BSL).

Potential loss of fluid

circulation at the fault intersections. Well Location

Anomaly Group 1 extends below the surface location of the proposed well at 66 ms TWTT (52 m BSL). Moderate to high probability of Amplitude Anomaly

encountering gas (possibly biogenic) but not expected to be overpressured due to shallow depth. depth. Gas could have have weakened the the shallow sediments.

Revised Well Location

Fault

No fault extending below surface location of well No amplitude anomaly extends below surface location of well; the

Amplitude Anomaly

nearest amplitude anomaly is Anomaly Group 1, 68m NE at 68 ms TWTT (53m BSL)

Tophole prognosis for the proposed Iron Duke Blk 10 well location and revised Iron Duke Blk 10 well location are shown in Figure 35 and 36.

80

NW

SEISMIC SECTION AT PROPOSED WELL LOCATION LINE ID-2D-L59 X= 550 383.0 m Y = 573 113.0 m

TWTT [ms]

0

PICKED REFLECTOR SE

VERTICAL DEPTH BML [m]

BSL [m]

0

41

H1

INFERRED LITHOLOGY AND COMMENTS

I

48

Clayey SILT and predominantly CLAY with sand intervals

48

89

II

135

Possible CLAY and sand layers

III

218

Possible CLAY interlayered with sand

IV

482

Possible CLAY interlayered with SANDSTONE grading to CLAYSTONE

V

459


VI

270

Possible SANDSTONE interlayered with CLAYSTONE

VII

1661

Possible CLAYSTONE, SILTSTONE and SANDSTONE

53 111

200 Anomaly Group 1

INTERPRETED SHALLOW GAS HAZARD

THICKNESS [m]

250 m

Seabed 100

TWTT [ms]

E C N E U Q E S

H2

183

224

264

FAULT

332

373

417

H3

401

442

480

300 400 500 600 700 800

H4

900

883

924

898

1000 1100

FAULT

1242

1283

1163

H5

1342

1383

1234

1200 1300 1400

H6

1612

1653

1412

1500 1600 1700 1800 1900 2000 2100 2200 2300 Data Limit

2400

Notes: 1)

2)

3273

All de de pt pths and thickness below se seafloor are approximate and are based on stacking velocities provided by client All me measured depth is vertical de pt pth (VD).

3314

2400

Legend

High Potential For Encountering Gas Moderate Potential For Encountering Gas Low Potential For Encountering Gas Negligible Potential For Encountering Gas BML=Below Mud Line BSL=Below Sea Level

TOPHOLE PROGNOSIS FOR THE PROPOSED WELL LOCATION

FIGURE 35

SW

SEISMIC SECTION AT PROPOSED WELL LOCATION LINE ID-2D-L02 X= 551 062.0 m Y = 572 845.0 m

PICKED REFLECTOR

VERTICAL DEPTH

TWTT [ms]

BML [m]

BSL [m]

Seabed

0

39

50

H1

38

77

97

H2

89

128

158

NE

E C N E U Q E S

INTERPRETED SHALLOW GAS HAZARD

THICKNESS [m]

INFERRED LITHOLOGY AND COMMENTS

I

38

Clayey SILT and predominantly CLAY with sand intervals

II

51

Possible CLAY and sand layers

III

227

Possible CLAY interlayered with sand

IV

505


V

522


VI

281

Possible SANDSTONE interlayered with CLAYSTONE

VII

1651

Possible CLAYSTONE, SILTSTONE and SANDSTONE

TWTT [ms]

100 200 Anomaly Group 1

300 400

H3

316

355

398

500 600 700 800

H4

900

821

860

845

1000 1100 1200

H5

1343

1382

1231

1300

H6

1624

1663

1410

1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 Data Limit

2400

Notes: 1)

2)

3275

All de de pt pths and thickness below se seafloor are approximate and are based on stacking velocities provided by client All me measured depth is vertical de pt pth (VD).

3314

2400

Legend

High Potential For Encountering Gas Moderate Potential For Encountering Gas Low Potential For Encountering Gas Negligible Potential For Encountering Gas BML=Below Mud Line BSL=Below Sea Level

TOPHOLE PROGNOSIS FOR THE REVISED WELL LOCATION

FIGURE 36

5.4.3 FINDINGS

Based on the high-resolution 2D seismic data interpretation at the proposed well location, conclusions of the hazard assessment are as follows: The 2D high-resolution seismic data indicates that the geology within the survey area consists of 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.

There are numerous shallow, buried channels within Sequence I, but their extents are not clearly defined due to limited 2D seismic data resolution in the shallow zone. One of the channels extends to the proposed well location but not at the revised well location. Several faults cut through Sequences II to V. The interpreted faults strike in northeast-southwest direction and dip towards either northwest or southeast. Two faults extend below the surface location of the proposed well at depths of 417 ms TWTT (373 m BSL) and 1163 ms TWTT (1283 m BSL). Cauti on i s advised whi l e dr il li ng th r ough th ese faul t i ntersections because these may cause loss of f lui d cir cul ation.

None of the faults extends below the revised well surface location. Anomaly Group 1 extends below the proposed well surface location at a depth of 66 ms TWTT (52 m BSL).

The anomaly in general is considered to have moderate to high

probability of being related to biogenic gas within the whole area but with moderate probability of gas within the channel at the proposed well location. Biogenic gas may not be pressurised at these shallow depths but the gas could have weakened the sediments within which it occurs. There is no anomaly that extends below the revised Iron Duke Blk 10 well surface location. The tophole drilling condition at the proposed well location and revised location are shown in Figure 35 and 36. .

83

5.5 Conclusion and Recommendation

5.5.1 Impact

From the survey it can be said that the project has given large information on the geohazards that are present within the survey corridor. Through the survey, among the geohazards identified are biogenic gas, weakened sediment layers channels and numerous normal faults. A summary of the potential constraints during drilling are noted in the table below: Table 9: Summary of drilling constraints at proposed well locations.

Proposed Well

Potential constraints

Amplitude anomaly

Description

- Intersecting Anomaly Group 1 at 66 ms TWTT (51 m BSL) beneath location. High probability of being gas related.

XXX

Fault

Intersecting faults at 417 ms & 1163 ms TWTT (373 m & 1284 m BSL). Potential loss of fluid circulation at the intersection.

Based on the results and discussion made, caution is advised if drilling through proposed well location with vertical well since intersection with faults will cause fluid loss. Another recommendation is to assume a weakened sediment layer while drilling through anomaly Group 1 since biogenic gas while not pressurized, may have cause the pores in the sedimentary layer to be filled with gas. If the geohazard zones are defined based on the report cannot be avoided or not possible to avoid, mitigating measures will be undergone to reduce the impact in the certain level that can be accepted. Thus, the risk can be reduced to safer level. High risk can finally avoided and project can be run smoothly. The project makes known of the geological features, stratigraphy and anomalies in the area. It is comprehensive information for offshore exploration and appraisal well. This project is very vital to ensure well planning and safe drilling operations. 84

5.5.2 Relevancy to the objectives

Based on the report it can be said that the survey has fulfilled all of its three (3) prime objectives. The first objective which is to understand the acquisition of seismic data from offshore has been studied thoroughly in terms of their parameters. The acquisition is the most important part of any project since the processing and interpretation of data cannot change the quality of the data obtained. This being said, what controls the acquisition is actually the parameters used before acquiring data. An example would be that if the near-offset is set inaccurately, then the direct arrival and first return of the data would be mixed up and even the best processing cannot solve this problem. Thus, the parameters such as group interval, shot interval, sample rate and near offset have been carefully looked into. The second objective of processing the data has also been successfully achieved. Processing is not a magical sequence that can make the data of the highest quality by itself. In the end, it depends on how good the acquisition geophysicist has done his job first. However, in this particular case, the acquisition was done well and the processing from SEG-D to SEGY had been carried out successfully. Although a very basic flow was used, but it has made a author appreciative of the challenges faced in processing data to make it easier for interpretation and ultimately the detection of geohazards. Last but not least is the third objective which is to delineate possible constraints or hazards in the intermediate geological section which are relevant to the proposed well location. The 2D high resolution seismic has been interpreted with the help of senior interpretative geophysicists. Geohazards that have been identified are pockets of biogenic gas and also normal faults that intersect with the well location. Recommendations have been made in regards to this matter and the client has full authority to decide on their next course of action. Since all these objectives have been achieved, the project has been highly relevant and in fact could save the lives of the people working offshore as well as spare millions of dollars in cash by avoiding the hazards concluded from the project.

85

5.5.3 Suggested Future Work for Expansion and Continuation

For the continuation and expansion of this project, an extensive analogue sur vey is also highly recommended. The 2D high resolution survey carried out is able to cover up to 2.5 s in depth which is unlike an analogue survey that only covers the seabed and shallow areas. However, the seismic survey also gives less resolution prowess since resolution decreases with penetration. This is even more importance since the presence of biogenic gas can be further confirmed with an analogue survey. The analogue survey should include a side scan which will allow an interpretation of the seabed features. This is to make-sure that no hazardous debris, pipelines, trawls is found within a safe range of the proposed well location. Carbonate or rock outcrops that appear on the seabed can also be hindered. Besides that, a Sub Bottom Profiler (SBP) allows us to confirm the existence of biogenic gas in the shallow subsurface especially involving Anomaly Group 1. The presence of shallow gas within the shallow areas can also be detected as they are known to travel especially in an area of multiple faulting such as this one. SBPs are able to give us better resolution of the shallow subsurface since it sacrifices penetration. Another method which gives more certainty in the interpretation is carr ying out well logging which will give gamma ray readings. The data can then be correlated t o see whether it matches with the earlier interpretation. In the end, the analogue survey and also drilling a borehole log would be the most effective method to confirm and further evaluate the findings.

86

5.6 Safety training and value of the practical Experience

5.6.1 Lesson Learnt and Experience gained

During 28 weeks of Industrial Internship, there were many lesson learnt gained in FGMSB. These include leadership, teamwork, business understanding, safety exposure and others that will be discuss below. Industrial internship is a great program that gives a lot of chances to the students to understand and experience the real working life.

FGMSB has provided the author with vast experiences during industrial internship from technical and non-technical activities These include the Geophysical Site Survey Project, and pipeline surveillance which requires the author to learn from the basic of both project type The projects especially site survey project requires high understanding of basics geophysics and geology which all of these are used to interpret the geological hazards within the site survey. In completing the project, author managed to use several software that are related to the site survey project. Most of the software are Fugro in-house software which includes Starfix Workbench (Sonar Map) for Bathymetry and Side Scan Sonar, Starfix Interp for Sub Bottom Profiler and SMT Kingdom Suite which are third party software that used for 2D High Resolution Multi-channel Seismic Data Interpretation. The author also had a chance to do 3D seismic interpretation by using SMT Kingdom Suite software. All of this software gives the author a lot of experienced in term of Interpretation and technical part. Throughout this project, the author involves in all geophysical data interpretations and analysis, data examples until the reporting part.

Health, Safety and Environment (HSE) in FGMSB is a crucial part that all of the staffs regardless their level, have to learn . Dealing with international Oil and Gas Company, HSE is the top requirement for every job involved. The main HSE objectives and targets are zero fatality, zero lost time injury and zero environmental incidents. This company apply HSE in all activities and places including offshore and also in the office. Anything that possible cost harmful to people will be bring to the meeting and action will be taken immediately. Other than that, the author learnt about Fugro Management System, Fugro HSE Policy, Hazards, Risk Management and Nine (9) Fugro Golden Rules of HSE. Throughout this internship training, the author experienced HSE practiced in work environment.

87

5.6.2 Leadership, Teamwork and Individual Activities

Industrial Internship training in FGMSB gives the author a big opportunity to develop soft skills especially in leadership and team work skills.

During the completion of this site survey project, the author was attached with an experience geophysicist. Teamwork is highly practiced as we need to discuss a lot of things in order to make any decision. Making decisions is one of the crucial parts in data interpretation as we have to give and explain the reasons of the decisions. However, Most of the decision making are basically come from discussions among several geophysicist and senior geophysicist which lead to team work among us. From the discussions, besides improving author's discussion skill and confident, author gained valuable skills in this project especially in data interpretation.

During the project involvement, the author learnt about proactivtity and communication skills, which lead to the successful of the project undertaken. The author gained these valuable skills individually because the company did not give 100% guidance on the project. The author need to find the way individually and it gives a lot experienced about individual skills.

Besides going through the office works, the author also experienced in handling outside activity such as futsal match, which involved all the office staffs especially men. This activity can strengthen relationship between staffs, besides the author can develop leadership and communication skills.

For individual activities, the author needs to prepare data examples for every geophysical data for the better understanding to the client. All the data examples need the individual skills in collecting and presenting of the data itself.

88

5.6.3 Ethics and Management skills

Throughout the industrial internship training, the author learnt about management of FGMSB. The author has attended the Quality Management System Induction Program that was set for every new workers or trainees in this company. During this program, the author has learnt about International Organization for Standard (ISO), Quality Management System, Fugro Survey SEA Process Model, QMS Document Structure, Quality Policy and Objectives, Control of Documents, Control of Records and Continual Improvement. All of these knowledge are used during all the activities involved in the office. On top of everything, quality of works is the most important things when working in this company as the management will evaluate the staffs on their working performance. To achieve this high quality of working, author learnt on how to produce a high quality of project especially in interpretation and data examples. All works done must be adequated with Fugro quality management system and documentation. This is required to reach ISO r equirements.

Other than that, the author learnt about time management and work ethics in this company. The jobs that the author involved is strictly need to achieve the time allocated by the client. The author learnt about using time wisely to finish the project with good quality of data interpretations. Other than that, the author learnt about work ethic and professionalism in handling problem and manages the task given by the supervisor. This company has taught the author about professionalism in communication skills, work task and reliable work environment.

89

5.6.4 Problems or Challenges Faced and Solution Taken

In the period of completing the industrial internship training, there were some problems arose from technical and non-technical perspectives. The first problem was to adapt with the new working environment. It was hard to adapt because the author had to communicate and work with elder and more experience staffs who have different point of view in giving opinions. Time management, communication and work skills are also the problems faced by the author. In seven (7) moths duration of Industrial Internship make the author understand and mature enough to deal with the stated problems. To adapt with new environment culture of working, the author take a few weeks to familiarize with industrial process, terms used and activities involved. In order to solve the problems, the author always asked and discussed with the staffs regarding the matter especially in geohazard survey process and system as the author has no experience in this field.

Besides, time management also is another issue that the author needs to face and solve during industrial internship basically in finishing the project interpretation and reporting itself. Most of the time, the author need to finish the tasks given by geophysicists and learnt new software used for the project interpretation. With the helps of some geophysicists, the author managed to learnt and finished the task given by the geophysicist and supervisor on time.

One of the vital problems faced by the author is communication skills where the author have to communicate with staffs from different background. However, with all great exposures given to the author in handling various tasks or works, the author now can communicate with full confidence to the management committees, geophysicists and senior geophysicists and able to voice up opinions during discussions involved. Now, the author is able to communicate to various individuals with different background and different nature of works excellently.

90

6.0 REFERENCE

FUGRO (n.a) Side Scan Sonar Record Interpretation.

FUGRO (n.a) Seismic Reflection Data Interpretation.

FUGRO (n.a) FUGRO General Business Principles.

ICG (2010). Offshore Biohazards. Retrieved on 27 November 2013 from

http://www.ngi.no/en/Geohazards/Research/Offshore-Geohazards/.

Laura Brothers et al (2010). Development in the Gulf of Maine: Avoiding Geohazards and

Embracing opportunities. Retrieved on 27 November 2013 from

th

www.digitalcommons.library.umaine.edu Retrieved on the 20 of July 2014

Laurent Hellequim et al. (2003). Processing of High-Frequency Multibeam Echo Sounder Data

for Seafloor Characterization in IEE Journal of Ocaeanic Engineering, Vol. 28. 2003.

H. Paul Johnson (2001). The Geological Interpretation of Side-Scan Sonar. School of

Oceanography University of Washington, Seattle.

B.W. Flemming (1976). International Hydrographic Review: Side-scan Sonar : A Practical Guide.

National Research Institude of Oceanology Council for Scientific and Industrial Research, Stellenbosch, South Africa.

91

7.0 APPENDICES

A) Digital Field QC Log B) Digital Offset Diagram C) Profiles of Seawater Velocity and Temperature against Depth D) Tidal Conditions during Survey E) Time Depth Conversion Curve F) Scatter Plot

92

CONFIDENTIAL

Client : UTP

Project : 2DHR S

Hull-Mounted Echo Sounder

Recording Parameter

Acquisition Par

Type Draught

: Odom ET MK II :

Tape Format Media Type

: SEG-D 8036 24 bit : 3490E

Sample Rate Recording Length

Velocity

: 1542 m/s

System

: SeaMUX 2000 System

Group Interval

Tx Freq.

: 38, 200 kHz

Filter Delay

:29 ms

Shot Point Interval

Heave Comp.

: DMS 3.05

Gun Delay

:30 ms

No. of Channels

LC Filter

: 4.5 Hz, 6 db/octave

Nominal Fold

HC Filter

: 412 Hz, 215 db/octave

Near Trace

: Channel 4

Aux. Channel

: Ch1 (FTB), Ch3 (NF), Ch4 (FF)

Navigation Type:

: Starfix SEIS 9.1

Positioning Type

: Starfix

Date

Line Name

ID-2D-L54

Time (Local)

Tape No

1

Fix

Fi

SOL

EOL

SOL

EOL

FFN

17:18

17:48

101

514

99

Page 1

CONFIDENTIAL

Seismic Acquisition QC Log ismic Survey Campaign meter

Site :

Certain

Job No.: Energy Source Para

Streamer Parameter

: 1.0 ms Streamer Type : 2.5 sec Active Streamer

: SeaMUX 24 Channel Modul : 1200 m

Gun Array Gun Depth

: 4 x 40 cu. inch sle : 2.5 m +/- 0.5 m

: 12.5 m

Group Length

: 12.5m

Gun Timing

: Max +/- 0.5 ms

: 12.5 m

Streamer Depth

: 2.5 m +/- 0.5 m

Gun Pressure

: Not less than 200

: 96

Streamer Noise

: Coherent Noise - ahead or behind - 10ub

: 48

Feather Angle

: Max 7 deg

Near offset

: 15.0 m

No. of Birds / Spacing

: 9 / 150 m

Burst - 20 ub

Compasses at Bird no

: 1, 3, 5, 7 and 9

Random - 5 ub

e

HDG LFN

(deg)

516

135

Nav shot / File missed

(monitored on elect

Streamer Noise :

Streamer Depth

Feather Angle

Noise (µb)

Min

Max

Min

Max

SOL

EOL

2.2

2.9

7.5P

8.4P

8.170

5.130

END OF SURVEY

Page 2

First few Shots - 14

Total Timing Error

0

CONFIDENTIAL

S.FINAL

Vessel: BANANA BOAT

eter

Acceptance Y = Yes M = Marginal

eve gun clusters

N / B = Bad, Not To Be Process (NTBP) AB = Line Aborted Bad Traces

1) None at Start of days survey.

psi

2) No more than 2 at SOL

ronic device)

3) If a trace bad in first k m, it will be deemed to have been bad at SOL Misfire / Bad Shot

ub

Misfires : No more than 5 consecutive Total : 7% of total no. of shots per line

Total

Total

Total

Misfire

Autofire

Gun Bad %

0

0

0.00%

Geo Comments

Acc.

Line name in tape and soft copy header change to “ID --2D-L54”. High noise Channel no. 70

Y

Page 3

DIGITAL OFFSET DIAGRAM

Offset Distances from Datum

Sensors

COG

5.74 m

X

Y

Streamer Tow Point

-2.830

-25.890

CDP Tow Point

1.185

-26.005

Gun Tow Point

5.200

-26.120

CDP Point

1.185

-93.620

27.16 m

5.200 m

2.830 m

1.185 m 1.27 m

1.04 m 58.96 m 66.46 m

4 x 40 Cu inch sleeve gun

Lead in 73.96 m First CDP

Near offset: 15.0 m

Centre of the first active channel

Ch. 3

Ch. 15

Ch. 27

Ch. 39

96 channels streamer @ 12.5m

Ch. 51

Ch. 63

Note :

1. Drawing is not to sc ale. 2. Measurements are in metres. 3.

Bird no. 1, 3, 5, 7 & 9 are model 5011 compass bird, Bird no. 2, 4, 6, & 8 are model 5010 Digibird

4. Group interval = 12.5m, Shot interval = 12.5 m 5. Cable Length= 1200 m

Ch. 75

6. Gun to the center of first active channel = 15.0 m 7. Stern to 1st CDP 66.46 m

Ch. 87

Ch. 93

25 m stretch 75 m rope Tail buoy

SOUND VELOCITY PROFILE ( SVP # 1 / Brunei ) Client Project Job No Vessel Lo cati on

: Brun ei Shell Petroleum Company Sdn/. Bhd. : 2013 BSP 2D High Resoluti on Survey Campaign : S2928 : MV Amarco Tiger : Iron Duke Bl k 10 Area Date/Time (Zone) : 16/07/2013, 01:27

VELOCITY (m/s ec) 1540.0

1540.2

1540.4

1540.6

1540.8

1541.0

1541.2

1541.4

1541.6

1541.8

1542.0

0

Velocity Probe : Midas SVX2 Serial No : 27530 5

Temperature Minimum : 28.36°C Maximum : 29.49°C Mean : 29.40°C Velocity Minimu m Maximum Mean Depth

10

: 1540.88m/s : 1541.69m/s : 1541.13m/s : 43.8m

15

V E L O C I T Y P R O F I L E

W A T E R 20 D E P T H ( m )

T E M P E R A T U R E P R O F I L E

25

30

35

40

45

27

28

29

TEMPERATURE (°C)

30

31

32

PREDICTED TIDES - LUMUT CLIENT : BRUNEI SHELL PETROLEUM COMPANY SDN BHD PROJ ECT : HIGH RESOL UTION 2D SEISMIC SURVEY FOR THE IRON DUK E B LK 10 A RE A V ES SE L : M/ V A MA RC O TIGE R/ 11 -1 2, 1 6 – 1 7, 31 A UG, 1 & 8 - 1 2 SE PT 2 01 3

RE PORT N O. : S 292 8/ 201 3/ 04

Graphical Representation o f th e Predicted Tides (Lumut) During the Period of Survey Operations

APPENDIX C

IRON DUKE TIME / DEPTH CONVERSION CURVE (met re) ms TWTT 0

0 1 2

0 2 4

0 3 6

0 4 8

0 5 0 1

0 6 2 1

0 7 4 1

0 8 6 1

0 9 8 1

0 0 1 2

0

200

400

600

800

1000

1200

Time - Depth Curve 1400 ) L S 1600 B m ( h t 1800 p e D

2000

2200

2400

2600

2800

3000

3200

3400

Report No. S2928/2013/04

0 1 3 2

Seismic Processing and Interpretation

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