Seabed Seismic Techniques: QC & Data Processing Keys

Seabed Seismic Techniques QC & Data Processing Keys Mundy Obilor Jim

Imprint SEABED SEISMIC TECHNIQUES– QC and Data Processing Keys Copyright ©2014 Mundy Obilor Jim Publisher: JimArts, Norway, Tel:+47-948-81-969 All rights reserved.

ISBN: 978-82-998906-7-0 No portion of this book may be used for further publication without the written permission of the publisher as it is protected under the copyright laws.

Table Of Contents Seabed Seismic Techniques Imprint List Of Figures Preface Acknowledgements Chapter 1. General Perspective Introduction The gains at the seabed The Success Stories Chapter 1 Exercises Chapter 2. Seabed Seismic Techniques The same time series Full wave seismic basics PS wave mode conversion Common conversion point (CCP) Data acquisition 2C versus 3D-4C acquisition Sensor orientation and coupling Shear wave splitting Binning and CCP Chapter 2 Exercises Chapter 3. QC And Data Processing Keys The physics is different QC, the start of imaging The QC workflow QC procedure The processing keys PS wave velocity analysis From PZ summation to CCPS Stack Chapter 3 Exercises Chapter 4. The Challenges Of Seabed Seismic The bright future ahead Cost and time constraints

Deep target and the gamma constraints Data processing complexities HSE and the STOPS Bibliography Author's Other Publications

Acknowledgements

I

thank Professor Martin Landrø of Geoscience Department at The Norwegian University of Science and Technology (NTNU) for making available some standard student examination questions which are relevant to seabed seismic technology and also for the insight I got as a student, in the seabed seismic sections of his course, Seismic Data Acquisition and Processing.

Although this book is currently adapted to ePub2 format, I will still like to thank Peter Krautzberger and the Mathjax community. It might be difficult to get MathML render in many e-readers in favour of ePub 3 but their great work at Mathjax is ensuring that maths and equations can be displayed nicely and accurately across most modern browsers, saving Authors and Researchers the agony of embedding equations in image format as done in ePub 2 publishing.

I express sincere gratitude to some colleagues I have worked with who never got bugged with my numerous questions in the process of writing this book. Many thanks to Oliver Langton, John Ege and Anthony Elliston

Preface Seismic is still at its growing stage, and is growing at a rapid S eabed rate. It has been difficult coming across books that deal specifically on the subject— be it in acquisition, data processing, interpretation or as a whole. Lots of research and development work have been going on and have been very remarkable within the oil and gas industry. Despite this remarkable progress, the techniques of seabed seismic have found themselves mostly as sub-sections in publications, journals and within the academic circle. Several papers relating to seabed seismic have been published and are very remarkable as well.

In this book we dwell mostly on Ocean Bottom Cable (OBC) and Ocean Bottom Node (OBN), with receivers placed on the sea floor— hydrophones to measure pressure in water (p-waves), geophones or accelerometers to measure vertical particle motion (p-waves) and horizontal particle motion (s-waves). The discussion will mainly be on four components (4C) which more or less covers other multicomponent seismic techniques. Conventional streamer methods is not a focus in this book.

Whether you are used to the term OBC, OBN, OBS or multicomponent seismic, it is my hope that, as a professional, an executive, a student or a teacher, you will find this book beneficial, as a text book or as a reference material. The above-mentioned terminologies may be used interchangeably in this book, but the terms OBC and OBN will be referred to more often since they have been widely used amongst seismic operators. I advise that the reader digs into the referenced materials and publications for deeper insight into seabed seismic. The book is divided into four chapters, the first three chapters ending with a set of exercises that will be of tremendous help to students, teachers and trainees alike.

The first chapter is an introduction which starts with explaining in general terms, what seabed seismic is and gives its advantages over conventional marine seismic methods. Specific experiences or

implementation of seabed seismic methods in some oil fields are given. In chapter 2, some basic signal properties are given, the PS converted wave process explained, and the common conversion point (CCP) approximation formula derived. Basic acquisition techniques of seabed seismic are treated– including topics like sensor orientation, CCP binning and shear wave splitting. P-wave to S-wave velocity ratio (Gamma) is explained.

Basic fundamentals of QC and processing of seabed seismic data are treated in Chapter 3 where two model processing work-flows are showcased to explain the fundamental processing keys for a multicomponent seismic data. The improvement in seabed seismic technology has not been without hurdles. Some of the challenges facing this technology are treated in Chapter 4.

List of Figures Fig 1.1 — 4C node configuration.

Fig 1.2 — Tommeliten Field gas cloud Fig 1.3 — Alba Field impedance contrast Fig 1.4 — Stafjord Field structural imaging Fig 2.1 — Signal with the two frequency components Fig 2.2 — Signal corrupted with some zero-mean random noise.

Fig 2.3 — Corrupted signal with observation time doubled Fig 2.4 — Corrupted signal with observation time multiplied by 4 Fig 2.5 — P and S wave propagation Fig 2.6 — P to S wave mode conversion Fig 2.7 — Common conversion point (CCP) Fig 2.8 — CCP equation derivation for a subsurface layer Fig 2.9 — P-S travel time sketch Fig 2.10 — A seabed survey layout Fig 2.11 — Sensor orientation and coupling Fig 2.12 — Shear wave splitting Fig 3.1 — A different physics for 4C data Fig 3.2 — Summary of 4C QC Fig 3.3 — A raw shot display of 4 components (P, Z, X, Y) Fig 3.4 — Spotting abnormal channels Fig 3.5 — Common receiver station gathers Fig 3.6 — Shear wave velocity analysis Fig 3.7 — A model processing flow (PZ summation) Fig 3.8 — A model processing flow (CCP stack) Fig 3.9 — Figure for problem1 chapter3 exercises Fig 3.10 — Well logs for S- and P-wave velocities Fig 4.1 — OBC financial trend (2007-2010)

Terminologies P — Hydrophone component Z — Vertical component X — Inline component Y — Crossline component PS — P to S converted wave OBC — Ocean Bottom Cable OBN — Ocean Bottom Node 4C — Four components Vp — P wave velocity Vs — S wave velocity Vp/Vs — Gamma QC — Quality Control SEG — Society of Exploration Geophysicists OGP — Oil and Gas Producers HSE — Health, Safety And Environment

Chapter 1

General Perspective oil and gas exploration and production companies are T he continually seeking to recover reserves or hidden oil from areas that are difficult to access or from reservoirs that have proved more difficult to image, or even from areas that conventional seismic methods have been productively engaged. As these companies are mapping out strategies to tap more oil from existing fields, the technological methods involved are also changing and improving dramatically. Seabed seismic "has seized the geophysical industry's fancy since its semi-commercial emergence in the North Sea in the autumn of 1996."[1].

Introduction The objective of seabed seismic is to record both P-wave and PS converted wave data on the seabed. These mode converted records have proven to be very useful in seismic imaging. As an example, mode-converted shear-wave data and of course, better P-wave data acquired on the seabed allow for imaging where it is difficult in conventional seismic due to the presence of shallow gas and/or fluid in the pore spaces within rocks.

Notably, the ray path of mode-converted shear waves differ from the ray path of compressional waves. This provides a better imaging of the sub-surface target of interest; and since the P-wave and S-wave record independent measurements of the same subsurface, better images and rock properties can be uniquely ascertained. These often allow for improved reservoir characterization and lithology prediction. However, while seabed seismic data are generally of better quality than streamer data in the above regard, proper coupling of the sensors on the seabed and PS wave matching and separation, among other processes, are some of the challenging tasks during and after the data acquisition. Some of these tasks are treated in chapter 3.

How it all started In the late 1980s, The SUMIC (SUbsea seismic) technique was developed by the Norwegian operator, Statoil. It is a method whereby both shear waves and pressure waves were recorded by sensors fitted in the seabed (Berg et al. 1994). A prototype SUMIC sensor array was developed in 1992 and quite a number of acquisition tests were carried out in the Norwegian North Sea sector a year later. The surveys were 2D tests with the objective of imaging subsurface structure through gas chimneys. Over three decades down the line, a lot of improvements have been recorded in seabed seismic. As at 2009, Statoil alone "has performed 62 ocean-bottom seismic surveys, beginning with a Gullfaks trial in 1989" and the resulting data produced better imaging and feature resolution"(E&P, 2009).

What is seabed seismic?

Seabed seismic or ocean bottom seismic is a method whereby, in contrast to conventional marine seismic data acquisition, acoustic reflections are recorded by sensors placed on the seafloor.

Each receiver station on a seabed recording cable or node system comprises of three orthogonally oriented sensors and a hydrophone (hence the term four-component or 4C). At the best approximation, P-waves are detected primarily by the hydrophone and the vertical Zcomponent geophone or accelerometer while S-waves are more or less detected by the X- and Y- component geophones or accelerometers.

Figure 1.1 — A 4C node configuration on a survey grid showing P (hydrophone component) and X, Y, Z (inline, crossline and vertical components).

The simple assumption or logic is that the Z component receiver is placed vertically and will record mostly P-wave since shear wave particle motion is perpendicular to the P- wave particle motion. The X (inline) and the Y (crossline) components are oriented parallel to the seabed and thereby much more sensitive to shear movement than the vertical component. More often than not, shear wave leakages into the vertical comp are removed before adequate data processing.

As mentioned above, the basis is that in addition to P-waves, mode-converted shear waves (PS waves) which hardly travel in water or fluid are also recorded. These mode converted records, which are less-attenuated in gas than P-waves have proved to be very useful in seismic imaging. 4C OBC in particular has become a proven technology and the benefits of the technology, especially in 3D surveys are now being continually recognized and tapped into by oil companies— from playing important role in field development to improving better reservoir imaging and fault definition in existing fields. In fact, there have been a couple of success stories where

seabed seismic data has been a major factor in the solution of imaging problems (remarkable examples are showcased later in this chapter).

Typically, an ocean bottom cable acquisition consists of one, two or more vessels. The choice of one vessel both as a cable handling and as a source vessel has been used successfully, especially for sparse or short-term surveys. We can assume the case of three vessels— one acting as a source vessel, and one or two vessels used as cable/node deployment and recording vessels. This can vary depending on cost and availability of vessels, and of course, on the project management factors of budget, quality and time.

The Gains At The Seabed Seabed seismic is still a fragment of the overall oil exploration methods even though it has been more useful in producing reservoirs than in any other areas. This is why many business enthusiasts and experienced Geophysicists who do not yet apprehend the method are reluctant to embrace this prospective technology. Some interpreters who are grappling with seabed seismic fundamentals easily place the technology as the last option as it is practical to imagine that a P-wave or streamer data acquisition will yield sufficient evaluation.

Executives who are yet to identify the risks and benefits associated with seabed seismic are reluctant when it comes to approving exploration budgets that are not within the well-known horizon of conventional streamer method.

Indeed we can only but tap the many economic benefits from seabed seismic with a good understanding of, and integration with traditional seismic methods, bearing in mind that the implementation/acquisition cost of seabed seismic will continue to be in overall decrease and will stop being a scaring factor due to the continual operational efficiency— from sensor technology improvement to a much more robust imaging software availability. It suffices to say that seabed seismic will in the coming decades be an

excellent tool in reservoir monitoring and in 4D seismic.

There are several reasons that will make seabed seismic to continue gaining grounds in the oil exploration business. Primarily, it gives us a full-wave multi-component data (i.e. both P-wave and Swave data are acquired). In terms of environmental operations, acquisition of seismic data in obstructed areas have been possible by using either OBC or OBN methods. "It has helped to improve reservoir characterization and imaging through gas clouds; and one of its major advantages is that it offers the prospect of full illumination and high multiplicity of signals from the same subsurface points (high data fold)".[2]

The 12 benefits of seabed seismic With towed streamer techniques, seismic data can be acquired much quicker and it is more economical but the advantages of placing the receivers on the seabed cannot be overlooked. Let's look at what we can call the '12 major benefits of seabed seismic'.

1. Full-wave multicomponent data: The use of hydrophones and geophones (or accelerometers) enables both P- and S-wave fields to be acquired and processed. Interpreters find work easier by making comparison between P wave and PS wave image displays and analysis results.

2. Better signal-to-noise ratio (SNR): We obtain a better SNR resulting from higher fold and from receivers being placed on the quieter and less turbulent seabed as compared to streamer methods receivers positioned a few meters below the water surface.

3. Water layer multiple attenuation: Water layer multiple attenuation is improved from the combination of hydrophone (P) and vertical geophone/accelerometer (Z) components which is often termed as PZ summation.

4. Broader bandwidth: With seabed acquisition, we get a wider range of frequencies or what some analysts call "much lower

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lows" and "much higher highs", which is indeed interesting because one major advantage in 4C data is obtaining better low frequency signal.

Resolution of imaging challenges: Imaging challenges such as the presence of gas clouds and carbonates, and the existence of complex structures, all of which have been confronted by streamer techniques are better resolved. Examples are Tommeliten field (gas clouds), Valhall field (overburden layers that are highly gas-charged) and Alba field (P-wave impedancecontrast reservoirs) which have undoubtedly enabled operators to see some of the advantages of using seabed seismic. These examples are shown in this chapter as a few success stories.

Long offset data: Seabed seismic technology is an option to acquire long-offset data in congested producing areas because the receivers are stationary on the seabed when deployed and thus are almost independent of the presence of obstructions such as platforms and oil rigs.

Wide azimuth acquisition: Imaging is often improved by the use of wide azimuth illumination. 3D seabed seismic data acquisition methods offer a very cost-effective means of acquiring such data. It can be easily shown that the cost per square kilometre is cheaper in an OBC acquisition method than in a corresponding streamer method. Hence companies are showing an increasing willingness to spend extra resources to get extra data quality, and so in a way, 3D OBC/OBN is wideazimuth with the manner by which data is acquired.

Acquisition is possible in obstructed areas: Acquisition of seismic data in areas obstructed by platforms rigs, etc. is possible. The use of crooked cables in the form L-shape and Ushape (call them hybrid methods if you like) has been implemented in West Africa at the Usari field.

Improved reflectivity/lithology indication: Shear waves can provide very useful insights into the nature of subsurface lithology and pore-saturating fluids, pointing out reservoirs not previously known or seen by utilizing only P-waves.

Time lapse seismic (4D): For reservoir monitoring purpose,

permanent deployment of cables/nodes on the seafloor may be the cost-effective way to go. S-waves can help monitor timelapse variations because during production, and over a period of time, there is the possibility of a dramatic change in reservoir fluid saturation and pressure. So with multicomponent acquisition methods one can expect a much more accurate and sensitive 4D seismic monitoring.

11. Better P-wave data: The P-wave signal obtained from seabed seismic acquisition has often proved to be better than the corresponding P-wave signal acquired from conventional marine streamer method because the much quieter sea floor environment will significantly improve signal-to-noise ratio in the P-wave signal. Some regard this as better pressure wave data. By 2005, it had become quite clear that reservoir monitoring stands to profit from seabed seismic; and that apart from the shear wave component advantage of seabed seismic, one of the greatest benefits was in obtaining better pressure wave data.

12. Geometry advantages: Long range layout: Seabed seismic acquisition methods can surpass towed streamer methods with longer cable lengths (as in the case of OBC), and hence resulting in longer offsets.

Much longer cables can be deployed at a go whereas towed streamer techniques are subject to streamer length limits, commonly within 6–12 kilometre cables. This simply means that one can deploy and shoot into much longer receiver lines.

Receiver positioning: Accuracy is higher in seabed cables or nodes when it comes to avoiding cable rocking.

Variable shot patterns: It is possible to shoot seismic lines in the direction of the cables (swath method), across the cables (patch method) or even at any chosen angle to the cable layout.

Sample Question 1:— PS wave reflections.

1. Consider two horizons, A and B and using the PP and PS time ratio method, derive the equation above, which relates to the Gamma ratio as a function of the 2-way travel time. (Hint: assume d to be the distance between the two horizons and the angles θp and θs as interface reflected angles for P and S reflections).

2. Why is it misleading to use the above concept?

Calculate the average interval ratio if the time-thickness between the two horizons for PP and PS data are 2000ms and 3800ms.

The Success Stories The challenges confronted by conventional seismic range from the inability to recognise gas clouds to having vague lithologies. Seabed seismic data acquisition and processing gives more than revealing the existence of gas clouds and helping in the discrimination of lithology.

There are much more we can get from seabed acquisition in contrast with conventional streamer data. However, it's all about objectives!

When oil "majors" see the necessity to improving the imaging of an existing streamer data due to some obscurity or lack of adequate interpretation, they consider utilizing other methods like EM, OBC, OBN and even 4D. Seabed seismic has often been a choice. Again it's all about objectives. For example, in the Gullfaks 3D-4C 2002, part of the challenge was that within the survey, there was an area of strong amplitude and frequency attenuation, for which the OBC survey was acquired to improve imaging in this area.

For simplicity, we will review three positive results from Tommeliten, Alba and Stafjord fields in the Norwegian/UK sectors. In line with the objective of this book, we will look at each of these fields within two major perspectives: introduction of the field and the associated drilling challenges or the reason why seabed seismic acquisition was carried out. We will also highlight the acquisition summary and results. The purpose of this section is just to show that imaging can be greatly improved by investing in seabed seismic technology.

Tommeliten Field Gas Cloud The Tommeliten field discovered by Statoil in 1976 is situated in block 1/9 in the western part of the Ekofisk Area of the North Sea. The field consists of two distinct and separate structures, Alpha and Gamma. The water depth in the area is approximately 70 meters, and the areal extent is 7 square kilometres2 for Alpha and 4.5 square kilometres2 for Gamma[3] 1. The imaging challenges: In quite a number of surveys, gas cloud has been known to have obscured reflection events for Pwave data (from Tommeliten field to Usari field located offshore Nigeria) and so a good understanding of PS converted wave propagation through gas is fundamental. We recall that P-wave is more attenuated in gas than S-wave. The effect of gas on rock density is usually small but has no significant effect on shear modulus. Hence, shear waves are much less affected by gas than compressional waves. This means the amplitude of P waves passing through the gas is attenuated and thereby obscuring the deeper events as observed in Tommeliten field. In other words, we can infer that gas leakage from a reservoir into the overlying sediments will definitely affect any P-wave imaging. Figure 1.2 shows a comparison of conventional 3D streamer data and an inline component PS stack of seabed seismic data. Without zooming or going into detailed analysis, we see a better definition of the structure on the PS image.

Figure 1.2 — Tommeliten field example (image from lecture Notes, Seismic Data Acquisition and Processing, by Prof Martin Landro).

2. Acquisition Summary and Results: The seismic source deployed in the Tommeliten case was a conventional marine air gun array, towed within 6 metres water depth. Approximately 1480 common receiver gathers at 7 metres spacing were acquired for the Tommeliten Alpha structure. The comparison in the figure show a clearer PS image of the reservoir not available previously because a gas chimney distorted the image of the Pwave data. It happens to be one of the earliest examples that clearly shows an advantage of acquiring seabed seismic data— showing how the existence of gas cloud could obscure the details of sub-surface imaging. Obviously, the PS converted data (right) generated a clearer and a more useful image beneath the gas chimney, even at a glance.

Alba Field Impedance Contrast Alba field discovered in 1984 is located in the Central North Sea (UK)

with an average depth of 140 metres. It came on-stream in 1994. The field "consists of Eocene-age, high-porosity, unconsolidated turbidite channel sands sealed by low-permeability shales"[4]. The channel system spans approximately 12 kilometres long by 1.5 kilometres wide.

1. The imaging challenges: Before 1999, imaging the Alba reservoir with the existing conventional seismic data had been a major challenge in asset development. In a series of P-wave analysis, research and study, and a series of modeling, it was shown that 'there was a low P-wave impedance contrast between reservoir and shale' and this did not yield desired result on conventional P-wave data, so the challenge remained— which was to improve the seismic image in the field. One of the conclusions was that PS wave showed high-amplitude top and base sand reflectors, not observed on the P-wave data.

Figure 1.2 — Figure 1.3 — Alba field example (The Leading Edge Nov 1999).

2. Acquisition summary And results: The primary objective of the survey was to use converted shear waves to provide a better

image of the sandstone reservoir and shales within the reservoir.

Seabed seismic technology was deployed with the aim of obtaining a clearer image of the reservoir. Eventually, a successful 3D OBC acquisition was carried out in the field which yielded some very remarkable economic benefits. Figure 1.3 shows an example from the Alba Field. The top image shows the P data, and the lower shows the PS data. The striking discovery is that the top of the reservoir is not visible in the P data but as can be seen, it is very obvious in the PS data. On the left hand side are the log curves which corroborate this contrast.

Obviously, there is no change for Vp at the top of the reservoir but there is a change in Vs in the shear wave data.

The Stafjord Structural Imaging The Stafjord Field is believed to be where the worlds first 3D-4C seabed seismic survey has been carried out in 1996-1997. The oil field, discovered in 1974, is a large oil and gas field situated in the Norwegian sector of the North Sea and operated by the Norwegian company, Statoil. Within the Tampen Spur area, it spans the BritishNorwegian border in the Viking Graben and covers about 400 square kilometres and lies in approximately 150 metres water depth. The reservoir units are Jurassic sandstones of the Brent Group, Dunlin Group and Stafjord formation. Stafjord oil field has had a record of peak crude production of about 700,000 barrels of oil per day, one of the highest in Europe.

1. The imaging challenges: One of the main objectives of the 2002 survey was to improve structural imaging of a complex structure using P-waves. The East area of Stafjord field had a complex P-wave imaging problem and so acquiring multicomponent seismic data to provide a better structural imaging was a suggested way to go. Part of the objectives was to improve lithology/fluid classification by combining P-wave data and PS wave converted data. With previous data processing and analysis, the conventional seismic data over Stafjord field were

degraded by multiples[6]. In other words, improving the seismic imaging of structurally complex East flank became the main objective of the acquisition survey as the quality of the processed conventional seismic images was affected by gas in the overburden and multiples in the lower reservoir zones.

Figure 1.4 — Stafjord field example.

The bottom image of Figure 1.3 shows seabed seismic image of the Stafjord field of 2002 survey with improved definition of the East flank structure compared to the conventional 3D marine seismic image of 1997.

2. Acquisition summary and results: The 1997 Stafjord 3D-4C OBC survey covered approximately 10 kilometres for the receiver array, with two 5 kilometres cables on the seabed and separated by 300 metres with a receiver group distance of 25 metres. It was a swath method with the source lines separated by 100 metres, and laid out parallel with the receiver lines. It is important to note that after the 1997 success of the 3D seabed seismic survey, a much bigger 3D seabed seismic survey was carried out in 2002, making Stafjord field a good reference point

for a seabed seismic acquisition technique. It was about 120 square kilometres survey which, in addition, covered the remaining part of the East flank. The key acquisition parameters for the 3D OBC survey of 2002 are as follows: a. Receiver Line spacing: 300m b. Receiver Line length: 6000m c. Receiver Station spacing: 25m d. Source Line length: 3000m e. Max. Source line offset: 1200m f. Source Interval: 25m (flip flop) Reports have it that since the 2002 3D seabed survey, at least eight wells had been successfully drilled for which the seabed seismic technique was actively used for well planning.

Chapter 1 Exercises 1. Which of the following factors can affect data quality of seabed survey? a. Sensor design and seafloor conditions b. Shallow water depth or high Gamma ratio c. Sensor design is not important d. A and B 2. Vp/Vs ratio, when plotted against depth approximately resembles that of a a. A decaying exponential b. A straight line which turns to a decaying exponential after a certain time c. A circle d. None of the above 3. Which type of seismic wave hardly passes through fluids? a. Body wave b. P-wave c. S-wave d. Surface-wave 4. A reflector is defined by an upper medium having a velocity of 2000m/s and density of 2g/cc and a lower medium having a velocity of 2500m/s and density of 2.2g/cc. What is the reflectivity?

5. A seismic event emits both S waves and P waves which travel at different speeds through the Earth. The P wave travels at 9000 m/sec and the S wave travels at 5000 m/s. If P waves are received at a seismic station ST10 a minute before an S wave arrives, how far is it to the event centre?

Chapter 2