reading assignment 1- oil and gas basics

Written for BHP Billiton Petroleum Pty Ltdby Rick Wilkinson

SPEAKING

SPE

AK

ING

OIL&

GA

S

OIL&GASbhpbilliton.com

United States of America BHP Billiton Petroleum (Americas) Inc 1360 Post Oak Boulevard Suite 150Houston TX 77056-3020Tel: (1 713) 961 8500Fax: (1 713) 961 8400

United Kingdom BHP Billiton Petroleum LtdNeathouse PlaceLondon SW1V 1LHTel: (44 20) 7802 7000Fax: (44 20) 7802 7557

Australia BHP Billiton Petroleum Pty LtdCentral Park152-158 St Georges TerracePerth WA 6000Tel: (61 8) 9338 4888Fax: (61 8) 9338 4899

Printed June 2006

Written for BHP Billiton Petroleum Pty Ltdby Rick Wilkinson

SPEAKING

OIL&GAS

First published by BHP Petroleum Pty Ltd as Speaking of Oil in April 1988

Revised as Speaking of Oil & Gas in June 1995 and November 1997

This edition revised as Speaking Oil & Gas and published by

BHP Billiton Petroleum Pty Ltd in June 2006

© BHP Billiton Petroleum Pty Ltd in 1988, 1995, 1997, 2006

ISBN 0-646-45386-6

Printed in Australia

The cover is printed on 250 gsm Impress Silk which is produced in European mills with full ISO 9001,

ISO 14001 and Eco Management and Audit Scheme (EMAS) certifi cation. Primary fi bre is sourced from

sustainable forests and all pulp used is either Elemental Chlorine Free (ECF) or Totally Chlorine Free (TCF).

The text pages are printed on 130 gsm Revive Silk, the only Australian made coated paper that uses

35% recycled fi bre. Fibre is sourced from ISO 14001 certifi ed plantations and suppliers, and is bleached

using TCF and ECF technology.

INTRODUCTION iii

Contents

Foreword iv

Introduction 1

Chapter 1. Geology 3

Chapter 2. Surveys 18

Chapter 3. Drilling 43

Chapter 4. Evaluation & Production 69

Chapter 5. Permits 91

Chapter 6. Public Reports & Reporting 102

Chapter 7. Taxation, Pricing & Marketing 110

Chapter 8. Health, Safety, Environment & Community 129

Chapter 9. Economics 148

Chapter 10. Downstream Processes 155

Appendix 1. Petroleum Specialists 163

Appendix 2. Conversion Factors 167

Glossary 170

iv SPEAKING OIL & GAS

ForewordBHP Billiton Petroleum Pty Ltd is a subsidiary of natural resources company BHP Billiton. BHP, as it was then known, began in the petroleum business during the late 1950s when it gained title to explore a vast area of what was then frontier territory in Bass Strait, a stretch of ocean off southeastern Australia between Victoria and Tasmania encompassing three offshore sedimentary basins. In the second half of the 1960s BHP Billiton participated in an amazing run of discoveries in one of these basins — the Gippsland Basin — which catapulted the company to the forefront of Australia’s oil and gas industry.

With Bass Strait as a stepping stone, BHP Billiton has expanded rapidly over the last 40 years to become Australia’s biggest and most successful petroleum company, both at home and overseas, with interests and activities in a number of countries. In the 2005 fi nancial year, BHP Billiton produced 119 million barrels of oil equivalent (combined oil and gas) or about 326,000 barrels of oil equivalent per day. In June 2005 the company had proved reserves of 1407 million barrels of oil equivalent, and average reserves replacement for the three years 2002–2005 stood at 99 per cent.

In order to aid public understanding of the petroleum business, BHP Billiton commissioned journalist/author Rick Wilkinson1 to compile a handbook explaining the technical and regulatory aspects of the search for, and production of, petroleum in Australia. The book was fi rst published in 1988, then again in 1995 and 1997.

This revised 2006 edition brings the reader up to date with the latest technical advances and expands its coverage to include the key fi scal and regulatory petroleum regimes around the world.

1. Rick Wilkinson is the author of a number of books about the petroleum industry, including: A Thirst for Burning – the story of Australia’s oil industry; Where God Never Trod – Australia’s oil explorers across two centuries; Well, Well, Well – behind Australia’s wildcat names; and Once Upon a Wildcat – images from Australia’s petroleum story.

INTRODUCTION 1

IntroductionPetroleum is among the minerals that have been used by man since earliest times, certainly prior to metals and coal.

Names like ‘Sweat of the Devil’ and ‘Shining Water’ were coined by primitive peoples who made use of the unusual surface occurrences.

The use of petroleum during the ages

2 SPEAKING OIL & GAS

The word petroleum is derived from the Greek word ‘petros’, meaning rock, and the Roman word ‘oleum’, meaning oil.

Earliest uses included caulking boats, fuelling lamps and preserving mummies. Written reports on petroleum come from as far back as 4000 BC and its use is well documented from countries as far apart as Egypt, China and Mexico.

The modern era can be traced back to Edwin Drake’s 1859 discovery well in Pennsylvania, yet it is only in the last four or fi ve decades that there has been any real understanding of petroleum geology.

The technology to begin perfecting the search for, and exploitation of, oil and gas has an even shorter history and there are still numerous questions to be answered satisfactorily. Nevertheless petroleum has progressed from humble beginnings to be a cornerstone of civilization and the key element in an international industry.

There are signs that it will continue to be a major source of the world’s energy well into the 21st century.

GEOLOGY 3

Chapter 1. GEOLOGY

Sedimentary basinsSedimentary basins are fundamental to petroleum geology because most of the world’s commercial oil and gas fi elds have been found within them. The basins develop over tens of millions of years and gradually fi ll with fragmented material which hardens into rock layers within which petroleum is formed and trapped.

Normally the history of a basin begins with subsidence of the land which allows an invasion by the sea. Surrounding mountains and hills are slowly eroded by wind, rain and ice, aided by the internal stresses caused by heat and cold. Particles of rock are gradually washed down streams and rivers. These particles will be deposited as the rivers lose energy in a number of environments such as lakes, the sea or deltas.

A phase that occurs early in the history of the basin is transgression, where the sea extends over the land. As time goes by, the amount of sediment brought by rivers increases and begins to overtake the incoming sea.


The geological time-scaleCourtesy of Geoscience Australia

Eon Era Period Epoch Age* Record of Life

PHA

NER

OZO

IC

CA

INO

ZOIC

Quarternary

Recent 0.015

Pleistocene 1.8

Tertiary

Pliocene 5.0

Miocene 24.0

Oligocene 37.0

Eocene 53.5

Paleocene 65.0

MES

OZO

IC

Cretaceous 135

Jurassic 195

Triassic 235

PALA

EOZO

IC

Permian 290

Carboniferous 345

Devonian 410

Silurian 435

Ordovician 490

Cambrian 570

PREC

AM

BRIA

N

PRO

TERO

ZOIC Late 1400

Middle 1800

Early 2300

ARC

HA

EAN

>3800

Jellyfish Archaeocyathids

Conodonts Worms

BacteriaAlgae

GastropodsGraptolites

Trilobites

Corals Nautiloids

Baragwanathia(land plant)

Indicates forms extinctAll other forms range to the present

* Age at base of period or epoch in millions of years

Brachiopods

StromatoporoidsAmmonoids

Bryozoa

Fish

SharksLepidodendroids

Crinoids

Amphibians InsectsEquisetales

GlossopterisPelecypods

Echinoids Sponges Plesiosaurs

Dinosaurs

Foraminifera

OstracodsFerns

CycadsChelonids

Birds

Starfish

Marsupials

Man

Cetaceans

AngiospermsGrasses

Eucalypts

Conifers

(greatest age so far measured)

GEOLOGY 5

The subsidence fi lls, so that the newly arriving material is distributed around the edges to form mud banks, beaches and deltas at the river mouths. Slowly the shoreline builds up, pushing the sea back in a phase known as regression.

Such a period of transgression and regression is called a sedimentary cycle and there are many such cycles during the formation of a sedimentary basin. Layer after layer of sediment is deposited and compressed by the increasing weight of material above to form sedimentary rock.

The layers themselves will vary in composition — sand grains form sandstone, fi ne muds form shale, broken corals and shells form limestone. At times whole coral reefs fringing the coastline are buried, giving a hard core of limestone surrounded by sandstone and shales.

A rock is porous when it has many tiny spaces, or pores

A rock is permeable when the pores are connected


In other locations a nearby volcano may erupt and ash is deposited, forming a rock known as tuff. At times a basin may be cut off from the sea altogether to form an inland lake. Vegetation surrounding the still waters dies, rots, is deposited, buried and compressed with other sediments and may eventually form seams of coal.

The rocks formed in the basin have varying degrees of porosity and permeability and the coincidence of these two properties is one of the keys to petroleum accumulation. A rock is termed porous if it contains voids and cavities between individual grains. It is permeable if the voids are connected so that fl uid can fl ow through the rock.

Studies of sedimentary basins suggest petroleum is generated mainly in fi ne-grained shales or limestone on top of the more permeable part of a transgressive sequence, and below the more permeable part of a regressive phase. The more permeable rock is often associated with the near-shoreline environment and it is the minor fl uctuations within transgressive and regressive phases that bring the potential source rocks and potential reservoir rocks together.

Crude oilCrudes vary widely in appearance and consistency from fi eld to fi eld, ranging from thin yellow-brown mobile liquids to black viscous semi-solids. However they all consist essentially of hydrocarbons which are combinations of carbon and hydrogen atoms.

Classifi cation is based on composition and is grouped into three main types — paraffi ns, asphalts and mixes.

• Paraffi n-based crude is chiefl y composed of isomers of paraffi n and when distilled it leaves a residue of wax. Crudes of this type usually give good yields of high-grade lubricating oils.

• Asphalt-based crudes are mainly composed of naphthenes and very little paraffi n. When distilled they leave a solid asphalt residue. Crudes of this type yield lubricating oils with viscosities that are more sensitive to temperature than paraffi n-based crudes.

GEOLOGY 7

API gravity (degrees) = - 131.5 141.5

specifi c gravity (at 60˚ F)

• Mixed-base crudes, as the name suggests, contain substantial proportions of both paraffi n wax and asphaltic matter along with some aromatic hydrocarbons.

There is considerable overlapping of these types and most crudes also contain a variety of impurities. Hydrogen sulphide and sulphur are the most common and the most problematic to the environment, and to the cost of production/refi ning. Other impurities include carbon dioxide, nitrogen, oxygen and some trace metals.

A yardstick for comparing crude oils is the API gravity (API stands for American Petroleum Institute). This value, which has been adopted as an industry standard, is actually a measure of density and is related to specifi c gravity using the formula:

So, an API gravity of 10 degrees is equivalent to a specifi c gravity of one. The less dense the oil, the higher the API gravity, hence high gravity oils are known as ‘light’ crudes and low gravity oils are ‘heavy’ crudes. Australian and North Sea crudes tend to vary between 35 and 45 degrees API, whereas Middle Eastern crudes tend to be between 16 and 20 degrees API.

Natural gasNatural gas is a mixture of gaseous hydrocarbons. It is mostly paraffi nic and consists mainly of the simplest hydrocarbon, methane. It may also contain smaller amounts of ethane, propane, butane and some pentane, as well as impurities like sulphur dioxide, carbon dioxide and inert gases like nitrogen and helium.

Natural gas is generally found in conjunction with oil in a reservoir, but it can also be found on its own.


Liquefi ed Natural Gas (LNG)LNG is made by simply reducing natural gas to a liquid by cooling it to minus 161 degrees Celsius. This reduces the space natural gas occupies by more than 600 times, making the product easier to transport and store.

Liquefi ed Petroleum Gas (LPG)The hydrocarbons propane and butane are gaseous under atmospheric conditions, but they can be easily liquefi ed by slight cooling and/or compression. The resultant LPG is used as a motor fuel and an industrial fuel as well as for domestic and commercial purposes.

CondensateFluids are contained in subsurface reservoirs at very high pressures and temperatures. This pressure is released and temperature lowered as the fl uids are brought to the surface. Some of the gas content naturally condenses into a liquid during the journey and the resultant liquid is called condensate. At normal temperatures and pressures condensate is a light oil that can be refi ned into petroleum products and is therefore sold in the same way as crude oil. Wet gas contains signifi cant amounts of condensate, dry gas does not.

Petroleum formationMost petroleum geologists believe that oil and gas originate from organic matter of both plant and animal remains when it accumulates rapidly in fi ne-grained sediments under conditions of quiet deposition and a defi ciency of oxygen.

The best pointer to the source material is the occurrence of porphyrin pigments and nitrogen in petroleum itself. The only known source for porphyrin pigments is the red colouring matter of blood (hemin) and the green colouring of plants (chlorophyll). Nitrogen is the essential component of amino acids which are basic components of animals and plants. Thus the conclusion is that plants and animals are the main source material for petroleum.

GEOLOGY 9

An older and less popular theory proposes an inorganic origin which suggests petroleum hydrocarbons originate from volcanic gases, or even a simple reaction of carbon dioxide, water and catalysts with sunlight. Evidence for these theories is provided by methane gas which is found in volcanic gases as well as within the atmosphere of stars and in metamorphic rocks.

However the organic origin has by far the greatest following and geochemical studies indicate that petroleum is generated during the burial of sediment in a sedimentary basin. With increasing depth of burial the temperature of the source rock rises and, at a given heat value, the organic matter (referred to as kerogen) transforms into oil and gas. It is then driven from the source rocks during compaction in a movement known as migration.

The critical temperature at which crude oil is formed is generally in the range 110˚–130˚C. Oil is produced in the initial generation period, while gas forms at greater burial temperatures. Ultimately a source rock will be ‘burnt out’ if temperatures become too high. A source rock is mature when petroleum generation has begun, and post mature when it is burnt out. The area containing mature source rocks is often called the hydrocarbon kitchen.

Geochemical evidence also suggests that conditions favourable for signifi cant petroleum generation normally do not occur above burial depths of around 1500 metres from the surface, although some instances of a ‘threshold’ depth of 600 metres have been found.

Indications are that the chemical changes are brought about by the combined effects of temperature, time, pressure and also catalysts in the source rock, as well as in the rocks through which the petroleum moves. The petroleum may undergo further changes via all these factors after entrapment.


Petroleum migrationA vast majority of pores and cavities within rocks below the water table are fi lled with water. The balance may be fi lled with other liquids and gases.

The migration of oil and gas from a source rock to a reservoir rock is related to hydrology, fl uid pressures and water movement. The rate of water movement may be small and measured in mere centimetres per year, but the effect of the hydrodynamic conditions can be very important to the movement of petroleum through the rocks. Migration is split into two types — primary and secondary.

• The primary phase refers to movement from the petroleum source to the reservoir. The oil and gas that has been generated and trapped in pore water is squeezed out during compaction of the rock. In this process the petroleum tends to enter only the larger pores because there is less displacement pressure needed than there is to enter smaller pores.

• The secondary phase of migration takes place within permeable rocks and can be either lateral or vertical movement.

Oil migration

GEOLOGY 11

Once in a reservoir, gas and oil, being less dense than water, tend to move upwards. The upward movement continues until the hydrocarbons are restrained by a fi ne-grained, relatively impermeable layer. They can then follow the bottom of this layer until they either reach the surface where they form seeps, or they reach a position from which they cannot move further and are trapped.

The path of migration may cover tens or hundreds of kilometres and much recent study has been done to try and relate the size of the hydrocarbon kitchen, and hence the volume of hydrocarbons likely to be produced, to traps in the surrounding areas. For instance, if the kitchen is small, it is probable only the nearest traps will be oil bearing. If the kitchen is large and deep, gas may have replaced the oil in traps closest to the generation point and this oil may have been forced into more distant traps. It is also known that oil is often released from a source rock in periodic pulses — like a slowed down geyser. Time and migration can change the hydrocarbons such that different types of oil may be found in different traps along the migration path even though they all came from the same original source rock.

The characteristics of reservoir rocks and the types of hydrocarbon entrapments are at the heart of the petroleum exploration and production industry.

Petroleum reservoirsAny rock that has suffi cient porosity and permeability to contain signifi cant volumes of hydrocarbons is considered to be a reservoir rock. The porosity may occur between grains, within grains, or in joints and fractures. Porosity and permeability may be original or they may be due to alteration during burial or by later earth movements like faulting and folding. Sandstones and carbonates (limestone and dolomite) are the most common reservoir rocks.

The range of porosity in reservoir rocks is between one per cent and 40 per cent, while permeability can vary between less than one millidarcy and more than 1000 darcies. The textbook commercial oil reservoir will


have a porosity of 20 per cent or better and a permeability of more than 100 millidarcies. Gas production has lower requirements. However, there are many exceptions to the norm. Some reservoirs have little pore space, but contain oil and/or gas in fractures and fi ssures. Others have good porosity, but permeability is too low for production and they are produced via fractures. Permeability can also be stimulated artifi cially by mechanical or chemical fracturing.

Most reservoirs have marked differences in permeability from one layer to the next and, if they are produced too quickly, the hydrocarbons will only fl ow from the highly permeable layers. Oil or gas in the fi ner grained sections will be cut off by rising water and therefore be lost to production.

The most important characteristic for production, however, is the thickness of the reservoir. Some are massive homogenous sands, while others are thin stringers of sandstone interspersed with impermeable layers of other material. Thus the term net pay (total thickness of all the permeable layers), as opposed to gross pay (total thickness of the whole reservoir zone including both impermeable and permeable layers), is important in reservoir assessment.

Petroleum trapsTraps are generally grouped into three major categories — structural, stratigraphic, and a combination of structural and stratigraphic.

Structural traps

The simplest structural trap is one formed by the folding of rock layers into a dome or elliptical dome shape and is known as an anticline or an anticlinal trap. It is virtually a ‘buried hill’ and contour lines drawn in a plan view of the structure will be roughly circular or elliptical. Hydrocarbons may migrate into this structure from all sides, accumulating in the top where an impervious roof formation, called a cap rock or seal, brings migration to an end.

GEOLOGY 13

Anticlinal traps and spillpoints

The structure is rarely that simple in practice and it is usually complicated by faulting, complex secondary folding and changes of porosity within the reservoir. Up to 50 separate reservoirs have been recorded in some anticlinal traps.

A fault trap is formed when a fault plane (a line of displacement of the earth’s crust) interrupts the direction of migration of hydrocarbons. The accumulation occurs when the oil or gas is prevented from proceeding up-dip by fi ne-grained material in the fault itself, or by an impermeable layer adjacent to the reservoir on the other side of the fault.

However, entrapment will only occur if faulting pre-dates hydrocarbon generation and migration, and if the fault completely truncates and seals the reservoir. Some faults do not seal effectively and can become conduits or ‘escapes’ for hydrocarbons into higher formations, or even the surface. Often a fold component is present with faulting.


Salt layers have the ability to fl ow plastically at relatively low temperatures and, at depth, they are often less dense than the immediately overlying sediments. Because of this gravitational instability, salt tends to rise vertically, punching its way through the overlying sedimentary column. The so-called salt dome structure that is produced provides a number of trapping mechanisms including faults and anticlines at the head of the structure, against the impervious fl anks of the salt column itself and against the truncated, overturned or faulted layers along the fl anks. Salt dome traps are common in the Gulf of Mexico petroleum province.

Stratigraphic traps

Stratigraphic traps are defi ned as those in which the reservoir is sealed due to depositional or alteration processes rather than structural movements of the earth’s crust. They are more diffi cult to fi nd, but when discovered they have provided some of the largest fi elds in the world.

Trap in dipping strata formed by fault plane

GEOLOGY 15

Salt dome traps

Stratigraphic traps: organic reef embedded in shale, and wedged-out sand


A common stratigraphic trap is a buried coral reef which is sealed by the surrounding claystones and shales. Often the reef itself has extremely high porosity and permeability and can give prodigious fl ow rates when tapped. The Leduc fi eld in Alberta, Canada is an excellent example.

Another type occurs as a truncation, formed when erosion planes an exposed land surface and sediments are deposited directly on top during a later phase of the sedimentary cycle, thus sealing the older rocks. Where there is marked angular difference between the older and newer rocks, the contact is said to be an unconformity.

Unconformity or truncation traps

GEOLOGY 17

A further type of stratigraphic trap can occur when sandy river beds, deltas or beaches become buried as sand lenses. They form traps when they are surrounded by fi ner grained impervious sediments. Changes in the type and appearance of rocks (such as grain size) occur frequently in regressive and transgressive sediments. For instance, coarse grained sand is deposited in shallow waters, but the fi ne sediments are lighter and are carried further to be deposited in deeper waters. Thus a porous sandstone may gradually ‘shale out’, i.e. change into an impervious shale or siltstone.

Combination traps

Combination traps are those formed by both stratigraphic and structural means. In these cases the structure, whether it be a fault, anticline or just regional dip, does not form the trap alone. It must be associated with a stratigraphic component, such as a facies change or a truncation.

Types of oil and gas traps


Chapter 2. SURVEYSAn accumulation of oil and gas is the product of a whole series of chance events, including the presence of a source rock, burial of the source rock, a reservoir and a trap in the right geometrical and historical relationships. Predicting if and where all these critical events have occurred in the correct succession is no simple matter, and it is certainly not foolproof. Nevertheless, the petroleum industry has built up a series of survey techniques to minimise the risks and delineate bona fi de targets.

Field geologyThe traditional method of fi nding oil was by mapping the surface geology and studying the relationships of the various rock units. Efforts were concentrated on mapping visible structures and potential reservoir rocks in areas that had some indication of hydrocarbons — like surface seeps.

SURVEYS 19

Petroleum exploration onshore still begins with a scrutiny of fi eld geology, aiming to understand and predict the types of rock that might be expected in the subsurface, in prospects outlined by sophisticated geophysical means. Often the geological survey will begin with a review of large scale maps of the region and all previous smaller scale maps drawn, and reports written about specifi c areas of interest. This will be collated with aerial photographs and satellite imagery of the region in question. Geologists identify the rocks in outcrop and, if possible, map the boundaries of rock units along with any subsurface structural features. Even when the potential targets are offshore, it is often useful to sample and study rock outcrops on land that dip down under the ocean. More recently, the combination of electronic and seismic surveys and computerisation has enabled explorers to map and construct models of the subsurface in great detail and display these on the computer screen, in an effort to understand the formation and detect the presence of potentially petroleum-bearing features.

GeophysicsThe principle behind geophysical surveys is to identify a contrast to the general background of data taken from a given region. In other words, the geophysicist is looking for an anomaly in relation to the surroundings. Usually the geophysical data is presented and analysed as some form of image.

Non-seismic techniques

Gravity surveys

Gravity surveys aim to detect large-scale subsurface structures by means of the disturbance they produce in the earth’s gravitational fi eld at ground level. The technique involves measuring the force of gravity at points on the earth’s surface or alternatively by measuring gravity gradient data via airborne means. Variations in gravity are caused by changes in the mass (hence the density) of subsurface rocks in the vicinity of the measuring point. The gravity survey attempts to detect these variations in gravitational pull.


Gravity anomalies relate to geological structure. High values caused by dense rocks near surface

Gravity anomalies relate to geological structure. Low values caused by light rocks near surface

MIL

LIG

ALS

TRAVERSE DISTANCE

MIL

LIG

ALS

TRAVERSE DISTANCE

SURVEYS 21

Because density usually increases with depth, a structural uplift generally brings denser rocks nearer to the surface and laterally adjacent to less dense sediments. Such uplifts are usually associated with higher gravity readings than the surroundings although, in the case of salt domes whose very reason for rising is their low density, it will be marked by low or negative readings in relation to the surroundings. Gravity techniques were fi rst developed for detecting salt domes in the Gulf of Mexico region.

Station heights and water depths (in the case of offshore work) have to be accurately known, as does data on rock densities in the area under study, so that corrections can be made for elevation and terrain topography. Corrections are also made for latitude (the earth’s rotation and bulge at the equator produce an increase in gravity with latitude), earth tides caused by the sun and the moon (they depend on latitude and time) and density variations in the earth’s crust (which is generally more dense below oceans and less dense below land). The gravity measurements are then plotted on maps (nowadays on computer screens) and equal values are contoured with lines called isogals. If all the reductions have been made correctly, the resulting map should refl ect only gravity changes due to subsurface geological structure. The modern techniques produce contrasting colourations on-screen that clearly highlight the lighter and denser material.

Historically, detailed gravity surveys were conducted on the ground, using a helicopter in rugged terrain, or on a ship. Because of the large and rapid changes in acceleration from aircraft movements, airborne gravity surveys were not as reliable or accurate. However, with the development in the 1990s of the FALCON® airborne gravity gradiometer system by BHP Billiton (from US Navy technology), fast, cost-effective and detailed gravity surveys can now be acquired over large areas by aircraft. Where ground surveys may take months or years in very diffi cult areas, a FALCON® survey can be completed in a few days.

Since the new millennium, satellite gravity data (originally developed for military purposes) has been available for all oceans of the world and is now used extensively by petroleum companies for exploration of offshore


Surface vs Airborne Gravity

About FALCON®FALCON® is an airborne gravity gradiometer (AGG) that measures minute changes in the earth’s gravity. This technology has enormous benefi ts and gives BHP Billiton a unique competitive advantage in the search for mineral and hydrocarbon deposits. This competitive advantage is backed by BHP Billiton’s unique value-added processing and interpretation capabilities.

Three AGG systems have been built to date, and are currently operational in Cessna Grand Caravans.

* BHP Billiton has 10.5 exclusivity years for mineral exploration and 10 years exclusivity for hydrocarbons, beginning October 1999. This means Lockheed Martin cannot build this technology for other parties during this period.

SURVEYS 23

regions. The technique compares differences in sea levels and is based on the fact that the shape of the sea surface is controlled by the earth’s gravitational fi eld. Ridges and trenches on the ocean fl oor create variations in the height of the sea level and they can still be detected when corrections have been made for the effects of winds and currents. When a variation in sea level is detected where there is no rise or fall in the sea bed topography, then the anomaly causing the variation is under the sea bed. The data is then subjected to editing and image enhancement to produce colour maps of the structural composition of the earth’s upper crust.

In summary, gravity surveys are a useful primary exploration tool that can detect the gross outline of a basin, its structure and the depth to basement. It can also detect major faulting and folding, salt domes and shallow reef structures within the basin sediments.

Magnetic surveys

Magnetic surveys are similar in data acquisition and presentation to gravity surveys and the two techniques are often conducted together. The method depends on the fact that most rocks contain small, but signifi cant amounts of ferromagnetic minerals like magnetite, ilmenite and pyrrhotite. Rocks therefore have a weak magnetism which is partly induced by the earth’s magnetic fi eld and partly permanent. Thus a magnetic survey measures local variations in magnetic fi eld.

The most important fact in magnetic exploration for petroleum is that sedimentary rocks are nearly non-magnetic and have a very small response compared to basement rocks and intrusions of volcanic and igneous rock. Thus a magnetic anomaly generally indicates a lack of sediments and the survey technique is used to rule out areas that are of no interest for the petroleum explorer. They are particularly useful in outlining the regional framework of sedimentary basins. Recent advances can also give an indication of faulting (because magnetic minerals are often concentrated in a fault plane) and individual structural elements within a basin.


Satellite-derived Bouguer gravity for East Indonesia. Land areas are white, gravity values increase from blue to red. Dark blue area (left centre) is the Weber Deep — water depth in excess of 7000 metres.

Australian Continental Shelf

Satellite Gravity — East Indonesia

Satellite gravity image courtesy of GETECH, University of Leeds

SURVEYS 25

Once again, salt domes provide an opposite reaction. Salt is diamagnetic and tends to oppose the fi eld that is polarising it. This results in a magnetic low.

Magnetic surveys can be conducted on the surface using land vehicles or ships, but the most common technique for a more complete coverage is by air — generally fl ying at heights of 60 metres above ground and 80 metres above sea. Accurate positioning and elevation are critical — a need answered by today’s extremely accurate positioning systems and satellite navigation systems. Corrections can also be made for the high speed fl ight.

As with gravity, image enhancement and contrasting colouration can now produce visually strong maps of the structural elements of an area under study.

In summary, magnetic surveys are a useful primary exploration tool that can detect the gross outline of sedimentary basins as well as the depth to basement, basement faulting, the presence of volcanics such as sills and dykes and mineralised alteration zones sometimes due to the presence of salt domes and hydrocarbons.

Geochemical surveys

Geochemical surveys are often undertaken in conjunction with other survey techniques. Exploration geochemistry follows a path that begins with characterising oil or gas samples taken from wells, or seeps. In the marine environment seeps (small oil slicks on the surface of the sea) may be detected by airborne or satellite imagery and attempts can be made to obtain core samples (known as drop cores) by dropping core barrels into the sea bed at that location. The samples are analysed and grouped into types of hydrocarbons. Even in seeps where weathering of the hydrocarbons may have taken place, detailed analyses can identify the original hydrocarbons.

Once samples have been classifi ed into hydrocarbon ‘families’ the geochemist tries to correlate them back to source rocks in the basin. The data is built up into a computer model which is then tested in the fi eld.


For instance, if the presence of hydrocarbons has been detected, sampled and traced back to source in an area, the model can be used to predict migration paths (sometimes referred to as the basin’s plumbing) and point to parts in the basin where it would be worthwhile to look for traps with larger holding capacity. If there are no pre-existing wells or seeps to sample, analogues from another basin with similar or linked geological systems are often used to indicate where the same set of circumstances may be repeated. Most software for this work is available for PCs and the computer programs are off-the-shelf products. Geochemical modelling is an increasingly accessible tool for petroleum explorers.

Geochemistry can also be used directly in an area where a number of prospects have been delineated and there is little to choose between them in size or potential. The exploration company may decide to begin by drilling the ones that have a corresponding geochemical anomaly, or ones that modelling predicts have a higher chance of containing hydrocarbons. The investigation used is basically one of hydrocarbon gas detection. Despite the fact that an oil or gas reservoir is sealed in a trap, there is still some minute leakage of gas through the rocks to the surface.

The usual method of detection on land is to drive a hollow probe into the ground to a depth of a metre or so and draw off gases present at that depth through the seal at the top of the probe using a syringe. The sample is then analysed in a gas chromatograph. Any hydrocarbon values above normal background levels constitute an anomaly. Airborne methods are also used (albeit less commonly in recent years) both on and offshore where a chromatograph in a low-fl ying aircraft is employed to detect gas ‘halos’ emitted from subsurface structures.

Satellite imagery

The use of satellites in petroleum exploration has mushroomed in recent years, particularly in connection with geographic positioning, navigation and communications. But explorers have also found a niche in terms of satellite imagery where it is now possible to obtain very high resolution through the light spectrum. This can be used to present very detailed and

SURVEYS 27

accurate pictures showing bathymetry and topography. Landsat pictures can provide resolutions up to 30 metres on the ground incorporating eight spectral bands. The high resolution is useful in the study of modern depositional processes such as the formation, shape and extent of deltas to use as analogues for planning programs to explore the potential of subsurface deltaic sand reservoirs within buried coastal sediments.

Satellite imagery can also be used to detect offshore oil seeps. This is a visual technique and is based on light refl ected back off the water surface. If there is cloud cover, radar can be used. This detects patches of smooth water that may be caused by oil on the sea in an otherwise rough water surface (rough water scatters the rays and presents a ‘foggy’ image). Using several satellites, explorers can home in on the possible source of the seeps. This technique has been tried with some success in the Gulf of Mexico. The method can also be used for environmental monitoring, although care needs to be taken to fi lter out effects from false positives like algal blooms.

Radiometric surveys

Gamma ray spectrometer surveys are used to detect radiation emanating from concentrations of uranium and thorium which may be associated with hydrocarbons. Detection of subtle radiation patterns and anomalies may indicate surface hydrocarbons which, in turn, may point to subsurface accumulations.

The earth’s crust contains uranium, thorium and potassium randomly laid down during the formation of the planet. These elements emit gamma rays in the course of radioactive decay and contribute to the earth’s natural radiation background. Of the three elements, uranium is the most mobile, being water soluble and easily transported by groundwater. However when the uranium encounters organic matter, such as subsurface hydrocarbons, the ion becomes insoluble and immobile. Hence higher-than-background readings of gamma rays may indicate the presence of a hydrocarbon trap.

The anomalies can be identifi ed by airborne radiometric measurements using a spectrometer.


Controlled electro-magnetic (EM) surveys

Controlled electro-magnetic (EM) surveys, recently developed for marine petroleum exploration, involve sending low frequency electro-magnetic signals into the sea bed and measuring the response to determine the resistivity of the subsurface.

The Controlled Source Electro-Magnetic measurements (CSEM) method uses an electric dipole source to transmit low frequency electro-magnetic signals to a series of receivers on the sea bed that measure the electro-magnetic fi eld at the sea fl oor. As the source is towed over the receivers the variation and phase of the received signal indicates the resistivity of the subsurface structure down to depths of several kilometres.

The Controlled Source Audio-frequency Magneto Telluric method (CSAMT) uses an artifi cial signal source (usually in the range of 0.1Hz–10kHz) in addition to naturally occurring electro-magnetic source fi elds to determine the resistivity of the subsurface. This provides a stronger, more reliable signal and enables imaging of shallower targets than is possible with low frequency natural signals alone.

Both these technologies are increasingly being employed during the later, more detailed phase of exploration work to provide complementary information to conventional surveys and attempt to identify the fl uid content in defi ned reservoirs. They use the fact that there is a signifi cant contrast between resistive hydrocarbon-saturated reservoirs and the surrounding more conductive layers saturated with saline water.

Electro-magnetic techniques can also be used to defi ne the lower boundaries of salt bodies. Conventional seismic surveys generally outline the top of such structures, but the diffuse scattering of signals in the lower layers due to the presence of carbonates or basalts or even other thin salt ‘blankets’ often clouds the picture. The resistivity contrast between such layers and the sediments below can be identifi ed using the EM methods. By studying the variation in response as a function of frequency, the variation in resistivity as a function of depth can be determined.

SURVEYS 29

Overall, the improvements to all non-seismic survey techniques in recent years include better instrumentation, the advent of extremely accurate global positioning systems, improved computing power and processing algorithms, advanced visualisation techniques such as image enhancement and 3D visualisation and the ability to combine different data sets. All these techniques can high-grade areas for a more detailed examination through seismic survey work.

Seismic techniquesThe principal method geologists use to explore the subsurface, besides the direct and expensive process of drilling, is through the use of sound waves. Sound waves travelling through the earth are called seismic waves, a term originally used in reference to earthquakes. Just as ultrasound is used to investigate the shapes of organs within the human body, seismic waves are used to map out the geologic structures of the earth. While ultrasound penetrates a few centimetres into the body using very high frequency (short wavelength) sound waves, seismic surveys use lower frequency, longer wavelengths to look many kilometres into the earth.

There are two types of seismic survey: refraction and refl ection. Refraction surveys were common early last century for reconnaissance and salt dome exploration. They are seldom acquired nowadays, except for deep crustal studies, because seismic refl ection surveys provide far greater information and accuracy for hydrocarbon exploration.

A controlled pulse of sound is sent into the ground and a range of detectors are used to pick up the refl ected waves as they come back to the surface. In marine environments the main source of sound energy is an airgun array — a group of pistons which let out a pulse of compressed air. Typically this will be two or three litres in volume at a pressure of 2000 pounds per square inch (psi).


Seismic survey — diagram showing typical refl ection and refraction wave patterns

Typical marine seismic refl ection survey

SURVEYS 31

On land, vibrating trucks send out a controlled sweep of sound between six and 16 seconds long. This technique, which sends the vibrations through a large metal plate pressed onto the ground, has largely replaced the older method of a dynamite charge set off a few metres down a specially drilled shothole. By spreading the energy over a longer period of time (many seconds as opposed to a fraction of a second) the same amount of energy can be used without damage to the local environment. Seismic surveys have even been conducted on the Champs Elysées in Paris using a fl eet of vibroseis trucks without danger to life, limb or architectural heritage.

When planning a survey, the geophysicist carefully sets the geophone/hydrophone spacing to provide the required subsurface information. For instance, the maximum offset (the distance from the energy source to the furthermost group of phones along the grid line or the streamer) should be comparable to the depth of the deepest zone of interest. Conversely, the minimum offset should be comparable to the depth of the shallowest zone of interest.

Vertical section of 4-fold common depth point shooting


Average P-Wave Velocities

Material Velocity

feet/second metres/second

Weathered surface material 1,000–2,000 305–610

Sea water 4,800–5,000 1,460–1,530

Sandstone 6,000–13,000 1,830–3,970

Shale 9,000–14,000 2,750–4,270

Limestone 7,000–20,000 2,140–6,100

Salt 14,000–17,000 4,270–5,190

Granite 15,000–19,000 4,580–5,800

Metamorphic rocks 10,000–23,000 3,050–7,020

There are three distinct stages in the seismic technique — acquisition of data, processing, and interpretation.

Data acquisition

2D surveys

When exploring a new area where little is known of the subsurface geology, a 2D survey is usually performed. This consists of survey lines spaced one, two, fi ve or more kilometres apart.

Offshore the seismic vessel will sail along with seismic guns deployed close off the stern (so they are near the on-board air compression source), letting out pulses every 25 metres or so, with a 12 second gap between ‘shots’. Behind the guns is the recording cable (or cables) whose length is measured in kilometres. The cable contains groups of pressure sensitive hydrophones which record the sound waves as they are refl ected back from the geological layers. The recordings are a few seconds long and sampled every 1–2 milliseconds (thousandths of a second). Sound waves travel at about 1.5 kilometres per second through water and increase to 2–6 kilometres per second when they pass through rock layers.

SURVEYS 33

A 2D seismic survey was to be acquired in an area of known buried volcanic ridges.

Reprocessed aeromagnetic data was used to optimise the layout of the new 2D data and avoid wasted lines over these ridges.

Aeromagnetics — Sulu Sea case history


Onshore the recording devices are called geophones and they are placed at measured distances along a pre-surveyed seismic line from the shot or vibration point. Geophones (usually grouped together in arrays, with three or more connected electrically so that the array acts as a single sound detector) transform the returned seismic energy into electrical voltage which is then transmitted by cable to recording equipment housed in a vehicle accompanying the survey team. Typical seismic records will image 10 or more kilometres down into the earth.

Each time the seismic pulse meets a change in rock properties, for example going from a shale layer to a sand layer, part of the pulse will be refl ected back to the surface. This is called an event. By measuring precisely the difference in arrival time of a given event from the nearer and further hydrophone groups, the velocity of the rock material can be measured. The seismic measurements are made in time, so if the velocity and time are known, geophysicists can work out the depth of the event.

A seismic line looks like a cross section through the earth. Initially these are used to map structural traps where hydrocarbons may accumulate — at its simplest at high points of domes known as anticlines, but also places where faults or erosion cut off a reservoir. Stratigraphic traps, where the geology changes laterally from one rock type to another, such as a buried sandy channel, sand bar, or carbonate reef can also be mapped using seismic data.

3D surveys

In areas where the larger and more obvious traps are mapped, petroleum explorers are increasingly using 3D surveys to obtain greater defi nition. By placing survey lines much closer together, a more detailed three dimensional picture can be built.

To economically survey a given area offshore, increasing numbers of recording cables are being towed behind seismic vessels, with between eight and 16 cables now the norm. A pair of submerged towed wings pull the trailing array of cables 50–100 metres apart from each other, resulting in a typically rectangular acquisition system that is one kilometre or more wide and six kilometres long.

SURVEYS 35

The demands of deploying tens of kilometres of cables, along with the ability to repair and replace defective sections of the cables and the running of large compressors to generate the compressed air for the seismic sources, mean that seismic vessels have become extremely specialised and expensive-to-run ‘information factories’. A typical 3D survey covering 1000 km2 of ocean will take one or two months to acquire.

Marine operations

The cables stretching back six kilometres or more from the boat are affected by waves and currents. Depth controllers keep the cable within a metre or so of the desired depth, typically seven metres below the water surface. Towing the cable shallower than this makes it more susceptible to wave-induced noise, while towing deeper results in the loss of higher frequencies due to ‘ghosting’. This latter effect is where the water surface acts like a reversing mirror to the sound waves. The surface refl ection (or ghost) will cancel out the frequencies of later arriving refl ections. Thus, there is always a compromise between this and using results from a shallow cable capable of recording higher frequencies (and hence better resolution) but incurring more swell noise.

Currents displace the cables laterally and while a limited amount of cable steering is possible, any reasonable current may displace the ends of the cables by a kilometre or more. As the vessel sails up and down the survey area, there must be very accurate positioning of the boat and of each recording hydrophone along the cable. A buoy with a geographic positioning system is attached to the end of each cable and their position can be determined to within a metre or two.

When the vessel turns to make a second sweep across an area, there is always the danger of tangling the cables. Tangles can be diffi cult and time consuming to unravel. In bad weather it may not be possible to deploy a work boat to fi x the tangle and the equipment must be pulled back on board.


Because the seismic boat cannot turn quickly, a support vessel is normally kept on standby to alert other recreational, fi shing and commercial vessels that a seismic survey is being undertaken. The support vessel is also used to re-supply the seismic boat with fuel and consumables.

Crew changes are made every four to six weeks, and this is usually carried out by helicopter. The typical crew size for a large 3D seismic vessel is 60 personnel, evenly divided between the marine crew and the specialist seismic crew. Surveying continues day and night, so two shifts are required. With the larger, more modern vessels, there is enough space for theatres, gyms, saunas, single or two-person ensuite cabins and life on board is comparatively comfortable.

Land operations

The logistics of land operations can be a more time-consuming and expensive task, particularly in mountainous, jungle or remote desert terrain. In BHP Billiton’s Algerian desert leases for example, the activities take place many hundreds of kilometres from the nearest town. Roads must be made to enable the vibroseis trucks to reach their required locations. The geophones are laid out at specifi ed locations and the recording crew ensures the data is acquired correctly. All personnel need to be supplied with many litres of water a day in summer desert conditions. The base camp for operations may have hundreds of personnel to keep the seismic crew operating.

Overall, the emphasis in data acquisition on land or sea is on maintaining consistency so that changes seen in the recordings result from changes in geology and not from changes in technique.

Seismic processing

Processing centres are found around the world, but tend to be concentrated in cities close to exploration activity such as Houston, London and Perth, Western Australia.

SURVEYS 37

Sophisticated software and specialised skills are required to turn the raw recorded data into the fi nal image of the subsurface geology used by the seismic interpreters to make their drilling decisions.

Amplitude decay — sound waves, like ripples in a pond, spread out, losing energy as they go. The rock layers refl ect some of the energy and absorb preferentially higher frequencies. These factors cause the signal to decay with depth. The signal can be boosted, but ambient noise is also boosted.

Diffractions — near surface irregularities cause the sound waves to diffract and scatter, like rain drops on a car windshield scattering sunlight. Filters must be designed to remove this noise.

Multiples — these are a major problem, particularly on marine surveys. The water surface acts like a mirror, refl ecting all the upcoming energy from the desired rock-layer refl ections back down to generate secondary and tertiary images. In shallower water, trains of multiples are thus generated. Significant effort is required to predict and accurately remove these multiples.

Seismic trucks, Sahara Desert, Algeria


Refraction — when a sound wave passes from a material of one velocity to another it bends or refracts, like light going into water or glass. The amount of refraction depends on the contrast in velocity. In places like the Gulf of Mexico, salt bodies have a velocity often more than twice as fast as the surrounding rock layers. Being irregular in shape, they can bend the sound waves quite dramatically. It can take months of work to build an accurate model of the subsurface velocity which is then used to remove the distortion.

Anisotropy — sound waves can travel faster horizontally compared to vertically due to the layering in the sediments. This causes the sound waves to bend in an unpredictable way. In some cases the velocity may also vary with an orientation that is faster in one horizontal direction compared to another.

Timing errors — on land data, differences in the topography and degree of weathering cause the seismic signal at a given location to be delayed relative to its neighbours. On marine data, tidal changes during the survey are enough to misalign the refl ection events. Seasonal changes in water temperature can also infl uence the data. All these need to be measured and corrected for.

Migration — any non-horizontal refl ection will appear mispositioned in space. The steeper the dip and the greater the distance from surface, the larger the magnitude of this mispositioning. A process called migration attempts to reposition the events in their correct locations. The process is sensitive to the velocity of the sound waves and all of the above issues need to be addressed before this vital process can be applied.

Seismic processing software designed to deal with these and other erroneous effects on the data places high demands on computer resources. Indeed, the requirements for seismic processing have been a signifi cant factor driving computer evolution. Some of the pioneering computer companies were set up by geophysical companies to push the boundaries of hardware performance. The demands of image manipulation are now the main drivers of computer hardware and software.

SURVEYS 39

Seismic with interpretation

Seismic without interpretation or annotation or wells


Seismic acquisition, processing and interpretation probably exceed all other scientifi c data collection in terms of the amount of raw data collected. The demand for increasingly large 3D surveys, more sophisticated processing sequences and shorter turnaround time means that the traditional tape-to-tape processing is being steadily replaced by huge volumes of disk space measured in terabytes (1000 gigabytes) and petabytes (1000 terabytes).

The sheer volume of seismic data meant that literally truckloads of seismic tapes were used in the past to transport the data from acquisition to processing centre. Modern disk media hold vastly more data than previously, however it will be a while before there is an end to tapes as a storage and exchange media.

Seismic interpretation

The fi nal processed data is generated as a number of three dimensional volumes and turned over to a team of specialists for analysis.

Interpreters map key horizons.

Seismic stratigraphers infer the depositional environment from the shapes of the geological bodies.

Structural geologists recreate the structural history of the data by examining the relative positions of faults, unconformities and in some places the shape of the salt bodies. Salt, being lighter than the surrounding sediments, fl ows like an extremely viscous fl uid pushing up through overlying rock layers. This is slower than glaciers, but it does move over long distances in geologic time. The structural interpretation recreates the geometry of the geologic layers over time, predicting how hydrocarbons may have moved.

Basin analysts use the inferred depositional history and what is known of geothermal gradients to predict where, when and what type of hydrocarbon may have been generated.

Petrophysicists use well bore measurements to tie the seismic data to the well logs.

SURVEYS 41

Reservoir engineers build detailed models of reservoir properties. With the aid of repeat surveys (called 4D surveys), they also examine how a reservoir is drained and decide on infi ll drilling.

In better quality data, direct evidence of hydrocarbons can be deduced from subtle changes in the seismic refl ection strength (amplitude), particularly as measurements at different offsets can show signifi cant differences in refl ection strength depending upon the fl uid content of a reservoir.

The bright spot technique, for instance, derives its name from the fact that it shows up on the seismic profi le as a visually brighter refl ection. Bright spot identifi cation is based on the theory that oil or gas in the pore space affects refl ectivity of seismic waves. In other words, there will be an anomalous change of amplitude at the edge of the petroleum accumulation where the wave passes from hydrocarbons back into water-fi lled pores.

An associated indicator is called a fl at spot, where the refl ections are returned from a fl uid contact. This is more likely from a gas/water interface because there is a much greater contrast between velocities of seismic waves in gas and water than there is between velocities in oil and water. A fi rmer prediction can be made if two fl at spots are detected one under the other. One is potentially a gas/oil contact within a reservoir while underneath may be the oil/water contact.

Nevertheless, apparent direct indicators like bright spots and fl at spots can be caused by factors other than hydrocarbons such as coal seams and porosity changes between rock types.

Another technique is called amplitude variation with offset (AVO). This is defi ned as a variation in seismic refl ection amplitude with a change in the distance between the shot point (energy source) and the receiver that indicates differences in lithology and fl uid content in rocks above and below the refl ecting layer. Interpreters use this effect to try and determine the thickness, porosity, density, lithology and fl uid content of rocks.


Seismic interpretation systems are able to store the large volumes of data generated by the seismic survey and quickly manipulate them so that the interpreter can scan through it as horizontal or vertical slices. The systems can be used to generate semi-translucent 3D volumes so interpreters can better understand relationships between the features they are examining. They can change the colour, amplitude and orientation of the data. They can strip away geologic layers to look at the patterns on a horizon of interest. And they can stretch the data from time recording to depth, if this has not been done in the original processing.

Even so, seismic interpretation is subjective, particularly in new areas where there is little or no well control. A number of interpretations can be made from the same data depending on the number and experience of interpreters and the variation in guidelines and exploration philosophies in vogue at the time. It is at this point that a potential target can be condemned by one explorer, yet seized upon and made into a discovery by another.

Despite all the technical diffi culties and unknowns outlined above, amazingly detailed images of the subsurface can be made in areas of good signal penetration. Petroleum geologists today have vastly more information available to make their interpretations than their peers in academia or the mining industry. High quality seismic surveys covering thousands of square kilometres allow unprecedented understanding of the geological history to depths of 10–20 kilometres.

DRILLING 43

Chapter 3. DRILLINGOnce interpretive maps have been completed highlighting prospects worth investigating, the only way to fi nd out if hydrocarbons are present and in commercial quantities is by drilling. This introduces the most colourful side of the industry, both in terminology and activity.

Geologists, geophysicists and drilling engineers combine their professions to produce a well prognosis which is an attempt to predict the stratigraphic column (including the depths to each formation) that will be penetrated by the drill bit. In new areas the prognosis is more diffi cult than it is in drilled regions where subsurface information is available, but it still serves as a guide to the formations and conditions that may be encountered down the hole.

Prior to 1900 most wells were sunk either by hand digging or by cable tool (percussion) drilling. In the latter method the bit was dropped attached to a cable, raised by a surface winch and dropped over and over again. The weight of the bit penetrated the formation gradually, with pauses


from time to time to extract the fragmented rock cuttings from the hole. Percussion drilling in some areas was used until the late 1950s. However modern drilling is by rotary means whereby the bit is connected to lengths of pipe and mechanically rotated on the bottom of the hole.

Rig types

Essentially all rotary drilling units have the same components and the only real differences in rigs themselves stem from the medium in which they are used.

On land the large rigs can be broken down into a number of loads for transport to and from drilling locations, while smaller rigs are permanently mounted on a truck or trailer. When working in dense jungle or other areas inaccessible by surface transport, a heli-rig is used. It is simply a land rig capable of being broken down to load sizes that can be airlifted to location by helicopter — usually about 2000 kilograms per load.

Offshore rigs are of four types — submersibles, jack-ups, drillships and semi-submersibles.

Types of offshore drilling units

Bottom-supported Floating

Submersible Jack-up Semi-submersible Drillship

DRILLING 45

Semi-submersible drilling rig showing the intermediate columns

GlobalSantaFe’s GSF Development Driller I, semi-submersible rig


Elevation of a jack-up drilling unit

Jack-up rig — development drilling at John Brookes gas fi eld, Carnarvon Basin, offshore Western Australia Courtesy of Santos

DRILLING 47

THRUSTERS

BALL JOINT

BLOWOUT PREVENTER

DRILL HOLE

RISER

A dynamic positioning offshore drillship

‘CR Luigs’ ultra-deepwater drillship

TELESCOPING JOINT


Submersibles are fi tted with ballast tanks so they can be fl oated to shallow water locations, then ballasted to sit on the sea bed or lake bed to provide a stable drilling base.

Jack-ups arrive on location (usually towed by tugs) and mechanically jack their legs down to the sea bed, raising their hulls clear of the water for drilling mode. They are usually used in water depths up to 150 metres, although some of the larger units can drill in up to 300 metres.

Drillships are ship-shaped vessels usually with the drilling derrick placed amidships to drill through a central hole (moonpool) in the hull. Some early vessels were also equipped to drill over the side with the derrick mounted on rails so it could be skidded across the deck. The vessels have their own propulsion, although a variation — the drilling barge — does not have its own locomotion and has to be towed.

Drillships are either anchored or kept in position by a dynamic positioning system which employs computer-controlled propellers along the hull to continually correct drift in any direction. These vessels are used in medium to deep waters, but suffer the usual ship instability in rough weather.

Semi-submersibles are mobile vessels with superstructures supported by columns sitting on hulls or pontoons ballasted below the depth of wave action for drilling mode. For transport mode the hulls are deballasted to the surface. Anchoring can be conventional or via dynamic positioning. Some semi-submersibles have their own locomotion, but many are towed or placed on a barge (especially for long distance moves). These vessels are remarkably stable in rough weather and can be used in medium to deep waters.

Rig systemsNo matter what the transport or carrying mode, a rotary drilling rig has fi ve main systems — hoisting system, rotary system, circulation system, power system and blowout prevention/safety system.

DRILLING 49

The hoisting system consists of a winch (draw-works) on the rig fl oor. A wire rope (drilling line) is spooled around the winch drum and is run up to the top of the steel derrick, over the crown block and down to an attachment on the travelling block. This latter has a hook for attaching the drill string via a rotary swivel.

The draw-works are controlled from the rig fl oor and are used to raise and lower drill pipe, casing and tubing, or any other equipment run into the well. The exceptions may be logging tools. These are often run on a separate winch as a separate operation to drilling, although in modern systems they may actually be mounted in the drill string just behind the bit to enable a continuous logging record to be kept while drilling.

Drilling system


The rotary system has three main components. First is the rotary swivel for suspension of the drill string to the travelling block. Second is the rotary table located in the rig fl oor and turned mechanically. Its speed and direction is controlled by the driller. The third item is the kelly, a hexagonal or square hollow pipe about 15 metres long which is attached to the rotary swivel at the top and to the drill pipe at the bottom by tapered screw threads. A piece called the kelly bushing fi ts into the rotary table so the rotary motion can be transferred from the table to the drill pipe via the kelly. The kelly bushing runs freely up and down the kelly, but cannot rotate independently of the kelly.

Another method of rotating the drill string is a top drive system. This involves hanging a motor from the hook and connecting it directly onto the drill pipe from above. It imparts the rotation without the need for a kelly or rotary table. The method promotes faster drilling and is particularly advantageous during directional drilling programs.

The mud or circulatory system

DRILLING 51

An additional item in offshore drilling is the marine riser which is a large diameter tubular connection between the rig and the blowout preventer on the sea fl oor. It is a conduit for the circulation of drilling fl uids as well as a guide for running drill pipe and casing. It is fi tted with a giant shock absorber called a telescopic joint to allow for the vessel’s movement on the sea surface and it can be quickly disconnected if sea states become too rough for drilling to continue.

The circulation system pumps drilling fl uid down the well and consists of mud pumps, suction and storage tanks for the mud itself, a stand pipe which runs up the derrick, a kelly hose connecting the stand pipe to the swivel and a return mud line below the rotary table which returns mud from the well to the shale shakers. The latter item removes the drill cuttings before the mud is sent to the mud tanks for further cleaning by de-sanders and de-pitters to remove the fi ner debris before recirculation.

Blowout preventer stack


The power system to operate the rig is either a diesel motor via a direct drive compound system, or (particularly offshore) a direct current electric drive.

The blowout prevention system consists of a series of hydraulically-operated valves and pipe rams which are open to allow the mud to circulate during drilling, but which can be quickly closed around the pipe if excessive pressure (a kick) enters the well and threatens to circulate during drilling. If a kick occurs (i.e. excessive pressure from the formation being drilled suddenly entering the well), the pipe rams are closed to prevent this overpressure reaching the surface out of control. The last line of defence in such an emergency are the shear rams which, if necessary, cut right through the drill string and seal the well completely.

Well typesPetroleum industry wells are of three types — wildcat, appraisal and development.

A wildcat is the fi rst exploration well in a new or previously undrilled target. The term seems to have originated from 19th century drilling in the backwoods of the USA where drillers reported wildcats (pumas perhaps) lurking in the vicinity. If the well is the fi rst in a completely new region where there are no close reference points, it can be called a rank wildcat.

Appraisal (sometimes called delineation) wells are drilled as follow-up exploration wells on structures where wildcats have been successful. They are often located to try to provide a rough outline of the fi eld and evaluate its various parameters.

Development (or production) wells are drilled once the discovery has been appraised and judged economically viable. They are drilled specifi cally to tap the hydrocarbons at defi nite places in the reservoir.

On some occasions during a drilling program only a small diameter hole is required as an initial exploration tool because it is cheaper, or because conditions deem it more practical. This is referred to as slim hole drilling.

DRILLING 53

Another category of well — which can be a wildcat, appraisal or a development type — is the directional well. Depending on the purpose, it can be inclined at various angles up to and exceeding the horizontal, by introducing a bias down one side of the hole which causes the bit to defl ect away from the vertical. The early method involved placing an angled length of metal called a whipstock downhole to act as a wedge to change the bit direction.

In recent times a technique known as geo-steering has been introduced for directional wells. Instead of using a whipstock to change the well direction, modern techniques employ steerable motors mounted just behind the bit. They are powered by the hydraulic force of the mud circulating down the hole to turn the bit independently of the drill string (like the force of wind turning the blades of a windmill). The assembly includes a bend at the motor bearing housing so that the bit points at an angle relative to the well centre-line (typically 0.5˚–2˚). This allows the trajectory of the well to be changed when the bit is advanced by using the weight of the whole assembly pushing down on it, and is called sliding. In other words, the mud motor powers the bit so the drill string can be advanced without pipe rotation.

An even later variation of this technique is the rotary steerable system in which a sleeve with several hydraulic rams attached is mounted behind the bit. A pulse sent down through the mud tells onboard computers what rams to push in order to move in the desired direction. Changes are achieved by the rams jamming against the side of the hole, thus pushing the bit off in the opposite direction. The advantage of this system is that the drill pipe can be rotated in the hole independently of the mud motor rotating the bit. This enables a continuous operation and provides more control as opposed to the sliding system which must advance in stages, i.e. slide, rotate the drill string, slide, rotate the drill string until the desired new angle is achieved.


A relatively new directional drilling system is known as coiled tubing drilling. The steel drill string is a continuous piece of thin steel tubing wound onto a reel or spool. During drilling the tubing, with bit attached, is progressively wound off the spool and into the hole via a gantry erected over the wellhead. The technique does not require a drilling derrick. The bit is driven by a mud motor or turbine, but the steel tubing itself is not rotated. The fl exibility of the tubing enables the bit to be steered around tight bends to reach and stay within very narrow reservoir formations. Coiled tubing is generally used to probe various formations and can be directed in any number of directions from a selected point in wells already drilled by conventional means. It is often used to enhance production from existing producing wells by accessing reserves nearby.

Overall, directional drilling may be used to reach an offshore target from an onshore location (such as the Wytch Farm fi eld in southern England which extends out under Poole Harbour) or to reach outlying parts of a fi eld from a central platform offshore, or to kick off in several separate directions from a single surface wellhead in onshore work. It might also be a deliberate ploy to sidetrack around a lost bit stuck in the original well, or perhaps to seek a new part of the reservoir after the bottom of the original well has watered out and is no longer capable of producing oil. The extreme case is a well which is actually horizontal by the time it enters a reservoir. This exposes a longer section of the well to potential production (particularly in thin petroleum-bearing formations) than a normal vertical or moderately inclined well.

The term long reach well (or extended reach well) is used when the ratio of vertical depth of the target formation versus the lateral extension from the well head is biased to the extension. These wells (usually offshore) can be drilled into a target up to 10 kilometres away from the rig or platform.

DRILLING 55

Multi-casing oil well completion


Bit typesDrill bits can be divided into several classifi cations.

The rolling cutter bit (or tri-cone bit) for rotary drilling was fi rst successfully designed by Howard Hughes in 1909. It has hardened steel or tungsten carbide teeth of varying lengths and spacings, mounted on three roller cones. The cones are designed to attain maximum cutting rate without causing the teeth to clog.

For soft formations the teeth are long and widely spaced and the cones are offset such that their axes do not intersect at a common point. This offset produces a gouging action on the formation as the bit is rotated.

For progressively harder formations the teeth are shorter and more closely spaced, while the cone offset is made less and less until, for very hard rock, there is no offset at all. These bits rely on destroying the compressive strength of the rock being drilled.

The diamond bit, adapted from the mining industry, imparts a grinding action as the drill is rotated. The bit itself consists of industrial diamonds embedded in a metal matrix. It is long-lasting in all but the hardest formations, thus reducing the number of bit changes while drilling.

Diamonds are also used in core head bits which have a hole forged through their centres allowing a core of rock to pass through into a core barrel mounted directly on the drill pipe behind it.

The polycrystalline diamond compact (PDC) bits have come into use in the last 15 years or so and have dramatically increased penetration rates. PDCs are very durable man-made diamond cutters set into a body to produce a very aggressive cutting action.

As mentioned in the previous section, a relatively recent evolution is the use of downhole motors (and also turbines) attached to the drill string to turn the bit. The power to rotate is supplied by the circulatory drilling mud and it requires a greater pumping effort from the surface than in conventional rotary drilling. The drill pipe itself is also rotated slowly

DRILLING 57

Rolling cutter drill bit (tri-cone)

Tri-cone drill bit (end view)

Diamond core bit


and independently from the bit to prevent sticking. Generally mud motors rotate at 150–250 rpm, while turbines can rotate at 2000 rpm and are used when penetrating hard rock.

Hole sizesThe diameter of the drill bits used, and thus the hole itself, becomes successively smaller as the well is deepened. There are no hard and fast rules relating hole depth to bit sizes because much depends on the stability of the formations being drilled and the target depth of the well.

Nevertheless, it is usual to run through a series of sizes beginning with the spud in or surface bit of 36 inches in diameter for offshore wells and 26 inches diameter for land wells. Drilling then progresses through diameters of 26 inches, 17½ inches, 12¼ inches, 8½ inches, down to 6 inches.

In most wells the hole is cased (lined) with steel pipe to prevent cave-ins and to retain circulation of drilling fl uid. The casing is inserted prior to every bit diameter change and the casing sizes correspond to the bit sizes just mentioned: 40 inches or 30 inches for surface (conductor) casing, 20 inches, 133/8 inches, 9 5/8 inches down to 7 inches, the latter sometimes called a liner or production tubing if the well is a development well.

In slim hole drilling, diameters usually begin at 10 or 8 inches and end at between 5½ and 3 7/8 inches. Early slim hole work was limited to probing relatively shallow targets, but advancing technology and the use of special high-strength drill string able to withstand the high torque forces involved in rotary drilling now enables the bit to reach depth of 3000 metres and more.

CasingCasing is made up of lengths of steel pipe screwed together, much like drill pipe, which lines the well and acts as a pressure vessel establishing barriers between different producing formations and the surroundings.

The surface, or conductor, casing is anchored to the wellhead and each successively smaller casing size is ‘hung’ from the preceding one as the

DRILLING 59

hole is deepened. Usually casing is cemented into place against the well sides by pumping cement under pressure down the centre of the pipe and back up the outside. When set, the cement casing shoe left at the bottom of the well is drilled out, and drilling into new, deeper formation continues.

A specialised form of casing can be manufactured with a diameter profi le in the form of two D shapes. This is then pushed down over a wedge placed in the bottom of the hole to drive the two D sections apart making an inverted Y shape. This is used for drilling two lateral (directional) wells from the same location.

Drilling fl uidDrilling fl uid is often referred to as drilling mud — a term relating to earlier times when water used to help drill the well became mixed with drill cuttings from downhole to produce a muddy liquid. At fi rst the fl uid was discarded, but then explorers found the drilling was easier when using this natural mud. The discovery sparked experiments into variations of drilling fl uid. Today muds can be divided into several categories.

Water-based muds (fresh water and salt water) can be simple clay-water mixes, clay-water plus chemical additives, or numerous other combinations. The most commonly used clays are bentonite or montmorillonite, both of which are sodium aluminium silicates that expand to about 10 times their original volume when mixed with water.

For some operations (such as high inclination wells where there can be torque problems on the drill string as well as a danger of hole collapse) and in some geological formations (such as water-reactive shales), water-in-clay is not appropriate because it can destroy permeability and prevent accurate evaluation of a reservoir formation.

Sometimes specialised chemical mud, such as potassium chloride and polymer solutions, is used to counter these diffi culties.

Another category is oil-based mud. This can be an oil-in-water or water-in-oil emulsion. The oil used today is diesel, synthetic or pseudo (ester).


There are stringent conditions attached to the use of drilling mud, including strict regulations on the disposal of used materials. In the marine environment the spent mud is sometimes stored in containers and sent to shore for disposal, or it may be re-injected into a higher formation or into a dedicated hole already drilled for that purpose.

In some circumstances compressed air, or foamed air, or an inert gas like nitrogen is used as the drilling fl uid to prevent damage to a water-sensitive formation or when there is a risk of losing mud into a porous formation.

Drilling fl uid has fi ve important uses.

It can be weighted to prevent high pressure formation fl uids downhole from entering the well. Usually the weighting material used is barite, a dense, heavy sulphate of barium. However, care must be taken with the mud weight. If it is too high the drilling fl uid may break down the formation and escape into it. If it is too low there is a danger of the well being under-pressured and this could potentially result in a blowout. Having said that, there are some circumstances when using air or nitrogen as the circulating fl uid, that the well is deliberately drilled underbalanced. This allows formation fl uids to escape up the well to the surface where the fl ow is continuously monitored to detect hydrocarbons. However extreme vigilance and great control is needed to prevent a sudden inrush that might cause a blowout.

It cools and lubricates the bit and the drill pipe.

It acts as a carrier to fl ush drill cuttings up out of the hole, thus keeping the bit clear and allowing geologists to examine the formation being penetrated.

It coats the hole with a thin layer and acts as a semi-permeable membrane which prevents loss of mud into all but the most porous formations being drilled.

It prevents caving of loose formations.

DRILLING 61

In recent times an additional use for drilling fl uid is to transmit data up and down the well during a drilling operation. The messages are sent as coded pressure pulses that change the settings of the mud motor or the logging tools. Data from the tools is sent back up the hole the same way and decoded at the surface. During exploration drilling this enables geologists and engineers to get data quickly to enable continuous monitoring and adjustment of the program. During development drilling it can be used to provide an accurate ‘fi x’ on the location of the bit at all times and make corrections as necessary.

LoggingThe purpose of logging a well is to compile a comprehensive record while it is being drilled and immediately after it has reached its total depth. In this sense cuttings and core samples can be included in the category as well as the various electronic devices used to identify the formations and their properties encountered downhole. Three types of information are obtained through logging methods: rock type and porosity, fl uid content of the pores, and mechanical and fl uid fl ow conditions of the well.

Mud logging includes a routine geological examination of the drill cuttings as they are fl ushed from the hole, plus a comprehensive record of the variations in drilling rates, the variations in mud pumping pressure, the depths of formation changes and an analysis of the mud properties, including hydrocarbon content measured by a gas detector. Any oil in the cuttings causes them to fl uoresce under ultraviolet light.

Coring is usually restricted to a reservoir zone or to a section of interest encountered during drilling. Core is collected in a core barrel, which is a cylindrical tube about 20 metres long mounted just above the special coring bit. Once brought to the surface, core is examined on site by a geologist and then sent to a laboratory where porosity, permeability, hydrocarbon saturation, water saturation and detailed lithology (rock composition) are determined.


A variation of the technique is side wall coring. This is normally done after electric logging to take a sample from zones not evaluated by normal coring methods, but picked up on the log charts as sections of interest. A core gun containing up to 60 small core barrels about one inch in diameter is lowered into the hole. The barrels contain an explosive charge and are fi red electronically from the surface.

The charge drives the barrel into the side of the hole at the required depth and is retrieved by wire rope attachments when the gun is withdrawn. A core obtained in this way has a number of disadvantages in that the explosive force often destroys the texture of the formation sample and, because it is collected from the wall after drilling, it often has pore contents completely altered from the natural state. Nevertheless it is better than no core at all.

Electric logging is accomplished by lowering instruments called sondes down the well. Each type of sonde measures a different physical property of the rocks that have been drilled, such as electrical resistivity, self potential, natural radioactivity, sonic velocity and induced radioactivity.

Hydrocarbons in the rock are detected directly by an increase of resistivity when compared to the same rock containing water. They are indirectly detected by the various ways in which the responses of the sondes are caused to deviate from normal.

Taking a core sample

DRILLING 63

Electric logs measure the resistivity of the rock and also determine rock type. In general, shale has a low specifi c resistivity, while limestone and sandstone resistivity is relatively high. Oil and gas within a rock will increase resistivity because they are non-conductive materials.

Nuclear logs measure gamma rays and thermal neutrons and can be used to determine porosity (including fractures) and lithology in a given formation. They are also the only porosity determinants which can be used in a cased hole.

Acoustic logs measure the velocity of sound within the formation in the same way as seismic surveys on the surface detect changes in formations. Acoustic logging is mainly used for porosity determinations and to help in differentiating gas-bearing zones from liquid-bearing zones.

Other logs are run specifi cally to assess mechanical and fl uid fl ow conditions down the well. They include a calliper log (which measures well diameter), a cement bond log (which measures strength and bonding of cement to casing), a temperature log (which detects the top of the cement column outside the casing because heat is given out when cement sets), and the dipmeter (which measures the formation dip relative to the well), and a compass to determine the well orientation.

Electric logging


In earlier days the logging operation was performed separately to drilling. Wells were drilled to a given depth before the drill string was hauled out and the logging tools lowered to take their readings. This is known as wireline logging. More recently the logging operation is accomplished while drilling. The well is drilled to the reservoir or inquiry depth and then the logging tools are sent down to sit behind the bit and the motor. This technique is known as formational evaluation while drilling (FEWD). It provides immediate detailed information about the well and the formations it is passing through.

Thus the ‘business end’ of the drill string starts with the bit and its drive system (the motor, which can be 10 metres long and uses the hydraulics of the drilling fl uid to impart a rotation to the bit). The survey package (compass and orientation tools) come next and make up another 10 metre long section. Finally the formation evaluation tools make up the third 10 metre long package and contain gamma ray, resistivity, neutron density, acoustic, calliper and formation pressure tools.

One of the original and still the most important uses of logging is the correlation of equivalent strata from one well to the next, allowing accurate subsurface plotting. This in turn helps determine the formations present relative to other wells. It also indicates whether a well is within a particular geological structure, whether a well has reached a known horizon, the presence of faults and the existence of dips, folds, unconformities, thickening and thinning of formations.

TestingNotwithstanding all the logging techniques, the fi nal confi rmation of the presence and character of hydrocarbons is by producing a sample from the reservoir formation. There are two methods of obtaining such a sample, and both depend on allowing the natural pressure of the reservoir to drive the formation fl uids to the well collection point.

A wireline formation interval test involves lowering a test chamber on the end of a wire to the depth of the reservoir and sealing it against

DRILLING 65

the well walls using expanding rubber packers above and below. Pressure inside the chamber is atmospheric and a valve assembly, when opened, allows reservoir fl uids to fl ow naturally into the chamber. If there is no fl ow, a shaped charge is detonated, piercing the formation and opening a fl ow channel to the chamber.

The volume collected in these tests is small (about 10–15 litres), but it does give an indication of the formation fl uids in the reservoir. The test also records pressure of the incoming fl uid and some general extrapolations can be made about fl ow rates. The wireline test is particularly useful in locating hydrocarbon/water contacts and the extent of transition zones.

A drill stem test is more expensive and involves the lowering of a test tool into the well on the end of drill pipe. Packers again isolate the section to be tested and, when the valve is opened, the reservoir fl uid is allowed to fl ow into the drill pipe. It is then recovered when the pipe is pulled out at the end of the test. Alternatively the hydrocarbons may be allowed to fl ow to surface in a full production test where they are controlled via a series of chokes of different sizes. Pressure and volume of fl uids are measured. Oil is collected, while gas is fl ared.

An open hole test is one that is done on a part of the hole that has not been cased. In a cased hole the test is conducted through perforations shot through the steel walls at the level of the reservoir zone.

Often the test will be shut in after a time to allow the pressure in the reservoir to build up again after the initial fl ow. Then it is reopened for a second and even a third measurement. Continuity of pressure during a test run and rapidity of pressure build-up between tests give some indication of the permeability of a reservoir and its potential performance in full production mode.

Occasionally, when the discovery is small or marginal, companies will run a long-term production test, stopping and starting the well fl ow over a period of months to better determine the economics and overall viability of a full development program.


Acidising and fraccingThere are times when logs and testing techniques indicate that oil and/or gas is present in a reservoir, but the formation is not permeable enough to readily allow hydrocarbon fl ow.

If the reservoir is a limestone or a dolomite, an acid solution can be pumped down the well and forced into the formation. The acid etches into the carbonate rocks of the reservoir around the well, opening up channels and unlocking the hydrocarbons.

If the reservoir is a sandstone with low permeability, the formation can be forced open by pumping a specially blended fl uid (chemicals that don’t adversely react with the formation, even air and inerts like nitrogen) under great pressure downhole and into the formation until it literally cracks it open. The pumping pressure exceeds the formation strength. This technique is known as fracture stimulation or fraccing. Proppants mixed in with the fl uid (such as sand, aluminium pellets, even walnut shells in the early days) are also forced into the formation and they keep the new fractures open so that a path remains for hydrocarbons to fl ow to the well.

Abandonment or completionIf a well is dry, or if hydrocarbons found are non-commercial, the well is plugged and abandoned (P & A). This process calls for isolating various formations with cement, taking particular care to block the reservoir zones and any high pressure zones that may have been encountered.

Sometimes wells are suspended by setting cement plugs as a temporary seal. At a later date the well may be re-entered for evaluation and the cement plugs are simply drilled out using standard drilling techniques.

If the well has tested commercial hydrocarbons, it is usually completed as a producing well or suspended so that completion can be carried out at a later date. A completed well has production tubing installed and the well casing is perforated in the reservoir zone. A system of valves (known as a Christmas tree) is placed at the wellhead on the surface for later hook-up to the production system.

DRILLING 67

Offshore a successful well is often plugged and abandoned because it is not optimally placed for future development. Development drilling will be done later from one or two platforms at other locations on the fi eld, selected for ensuring an even drainage of the reservoir. The exception is for small fi elds offshore where subsea completions may be installed on each successful well, or where single-well platforms are used. In those cases the original exploration wells may be used as production wells.

Remedial workFew wells are textbook operations in practice and any number of problems can be encountered during drilling or testing.

Typical Christmas tree


Some of these include the drill pipe sticking in the hole, twisting off a section of drill pipe in the hole, the loss of equipment such as logging or test tools down the hole, washouts and loss of mud circulation into the formation and, most serious of all, formation fl uids overcoming drilling mud pressure causing blowout and possible fi re, explosion and equipment damage at the surface.

When there is a stuck pipe or equipment is dropped or sheared off downhole, the operator has three alternatives. They can fi sh for the obstruction with specially designed grappling, cutting, grinding and magnetic tools. Another option is to drill around the obstruction by deviating from a point a little above it (sidetracking). However, if a sidetrack is also likely to be diffi cult, the operator may decide on the third (albeit very expensive) alternative — drill a completely new well from the surface.

Loss of circulation and washouts in soft formation can also be diffi cult to contain and often the well program must be changed so that casing is run through the troublesome section earlier than originally planned. Recently a way around this dilemma has been provided by the development of ‘expanding casing’ which is made of very pure steel. Once in position over a bad patch in the well, a cone is pushed down through it to open out the diameter. This avoids the need to set the next casing size and thereby lose diameter for the next part of the hole.

An increase in the density of mud weight, and blowout equipment in working order, can usually overcome any sudden pressure infl ows in a well. In such events too, a lot depends on the experience of the drilling personnel. A crew trained in well control and blowout prevention can circulate a kick of high pressure out of the system using the valves and chokes in the well.

Another form of remedial operation is the well workover. This can either be a program of widening, cleaning or re-perforating an old abandoned well, or a producing well that has already had a long life and needs rejuvenating. The workover is usually carried out with a small drilling rig on land and on a production platform, or one of the four types of offshore rigs suitable for an offshore location.

EVALUATION & PRODUCTION 69

Chapter 4. EVALUATION & PRODUCTIONEvaluation of a discovery is still, strictly speaking, an exploration function and involves detailed appraisal work.

Reserves estimatesOnce exploration drilling has discovered an oil and gas accumulation, appraisal drilling is needed to determine whether or not it is large enough to be commercially viable. As the drilling results come in, the geological/reservoir engineering team makes an evaluation of the discovery and an estimate of the reserves. Naturally enough, the more well data collected, the more confi dence can be placed in the estimate.


Appraisal

Appraisal wells are sited to determine the physical parameters or dimensions of the fi eld. For instance, if the discovery well has successfully penetrated the crest of a structure, the appraisal wells will probably be drilled down the fl ank to establish the lateral extension in four directions by fi nding the oil/water contact. If the discovery well has penetrated a structural fl ank and already established an oil/water contact, then there is scope to drill an appraisal well closer to the crest (or up-dip) to try and fi nd a gas/oil contact point. This can indicate the true height of the highest and lowest point of oil in the structure (the hydrocarbon interval or pay zone). Sometimes oil may not have a gas cap and this can be determined by drilling on the top (crest) of the structure. A purely gas reservoir will be indicated if the appraisal fi nds a gas/water contact.

Appraisal work includes input from seismic mapping, downhole log data and well tests. The results are used to determine the oil/gas, oil/water and/or gas/water contacts and to indicate the horizontal and vertical dimensions of the trap. This in turn, enables an estimation to be made of the potential volume of oil and/or gas in place (in situ). However, the calculations are rarely straightforward. Complications arise through errors or uncertainties in seismic interpretation, faulting, lithological changes and erosional features. A general rule is: the thicker the pay zone, the more continuous it is likely to be. But this is by no means absolute.

Three other factors of major importance are net pay, porosity and hydrocarbon saturation.

Net pay thickness in the reservoir or reservoirs is the interval fi lled with hydrocarbons, and is generally derived from core or cuttings and logs or interpretations from test results.

Porosity is the capacity of a given volume of the reservoir to hold fl uids. An estimate is made from the well logs and core analysis.

Hydrocarbon saturation is also derived from well logs and is the fraction of the porosity that is hydrocarbon fi lled. The degree of confi dence in the estimate varies with the type of lithology, the type and quality of the logs and the availability of data from previous wells in the area.


Once the physical shape of the accumulation and volume of hydrocarbons in situ are known, it is possible to estimate the reserves (the proportion of hydrocarbons expected to be commercially recovered from the reservoir). Due to the nature of the fl uids, uncertainties in knowledge of the reservoir parameters and the limited number of wells that will be drilled, recovery is always much less than 100 per cent. For an oil fi eld, recovery will generally be 10–40 per cent, but it can in exceptional circumstances reach 70–80 per cent. Gas recovery is normally 50–80 per cent of the hydrocarbons in situ.

Recovery estimatesThe so-called recovery factor, which denotes the percentage of hydrocarbons in situ that will be recoverable, depends on three main items — nature of the fl uid, reservoir drive mechanism and productivity.

The nature of the oil or gas in a reservoir is described by chemical analysis of its components. For oil, measurements of the API gravity value, the pour point (the temperature at which oil changes from liquid to solid), the bubble point (the point, during decreasing pressure, at which gas begins to come out of solution with the oil), the viscosity and the gas/oil ratio (GOR) are also relevant.

The drive mechanism of the reservoir is the availability of natural means of supporting the pressure in the reservoir. There are three common types:

• A water drive occurs when water in the reservoir formation is directly in contact with the oil (or gas). As oil (or gas) is produced, pressure in the reservoir is reduced causing an infl ux of the water, which in turn sweeps through the pores of the rock and pushes the oil (or gas) out as it advances.

• A solution gas drive occurs where pressure support is provided solely by the oil. The drop in pressure caused by production releases gas from solution in the oil. As the gas expands, it displaces an increasing quantity of oil from the pores.


• A gas cap drive occurs when there is a large gas cap in direct communication with an oil zone. As the pressure is reduced, the gas cap expands and sweeps oil ahead of it.

Often the drive mechanism is a combination of these and other mechanisms. Water drive is the most favourable and solution gas is the least favourable. In all cases, pressure, and therefore production, declines with time.

Productivity is often the least predictable parameter. It is mainly a function of the reservoir permeability and fl uid viscosity. It can be determined in part from cores and interpretation of test results.

Reserves classifi cationCommon terms used when describing petroleum reserves in a fi eld are proved, probable and possible. They refl ect the confi dence that is felt about the reserves calculated. Proved reserves refl ect a very high degree of confi dence (90 per cent certainty and labelled P1 reserves). At the other end of the scale possible reserves have a very low degree of confi dence attached to them (10 per cent certainty or P3 reserves). Probable reserves represent the mid-range of confi dence (50 per cent certainty, or P2).

Companies sometimes also use a slightly confusing notation — 1P, 2P and 3P — when reporting reserve fi gures. Taken respectively these simply mean proved reserves only, proved plus probable reserves, and the sum of proved plus probable plus possible reserves.

Market potentialModern fi eld evaluation techniques also include preliminary marketing investigations. For oil discoveries, the fi eld operator will run a detailed assay to determine the exact nature of the crude, including a breakdown of its components and the type of petroleum products that may be obtained when it is refi ned. This step is also a check for any impurities in the crude that need to be dealt with to comply with companies’ strict health and safety programs, as well as to give an early start in establishing plans for their removal during any development stage. The assays are done on samples obtained upon discovery and during appraisal drilling.


The assay results are circulated to potential buyers to gauge interest and the possibilities for sale, if and when the fi eld is brought on stream.

For gas, assays to determine the nature and percentage of thecomponents (including any impurities such as carbon dioxide, nitrogen and sulphur compounds) are an important factor in establishing economic value. However, it is usual when dealing with gas accumulations to establish a market before development can take place. Hence an initial market evaluation, domestically and internationally, is often carried out in conjunction with fi eld appraisal work.

In some instances the results of market surveys can infl uence the nature of development plans and the design of the production facilities.

Once the reserves for a fi eld are estimated and declared viable, planning for development can begin. Sometimes the go-ahead to proceed to development will be given immediately. At other times a more cautious, stepped approach is taken which involves preliminary design (or feasibility studies) followed by a front end engineering and design (FEED) stage. The FEED stage provides defi nitive costs and technical data to enable a decision on whether or not to make a fi nal commitment to fi nance a full development plan.

Development drillingOffshore, petroleum engineers draw on their knowledge of the fi eld gained during the evaluation (aided by the computer-generated models based on the acquired data) to choose an optimum number of well locations to effectively and effi ciently drain the reservoir across the whole fi eld. Generally these wells must be identifi ed prior to actual development to permit proper design of the facilities. Wells can be vertical, deviated or horizontal and may be drilled from one or more central platform locations. Sometimes well slots on a platform are not used immediately. Rather, those wells are drilled at a later date when the engineers have some idea of the fi eld’s production history. For instance, they may be directed into spots in the reservoir where oil has been left behind, or to boost production from an area that is fl agging. Development wells can also be individual subsea completions and in this case it is often possible to re-use exploration wells as subsea production wells.


In the onshore sector, development drilling generally occurs in a more step-wise fashion. Additional wells are committed to and drilled only after the results of earlier wells are known. There is less need to commit to a full fi eld development at the very beginning. Wells are often vertical, although recent perfection of the horizontal drilling technique and the use of motorised bits has provided this option for use particularly in thin reservoirs. In onshore work it is generally possible to use successful exploration wells as producers.

Improved technology is blurring the former distinction between offshore and onshore development because some offshore fi elds can also be developed in a step-by-step progression using subsea completions and monopod platforms as an initial guide to future development options. Nevertheless, whether onshore or offshore, the number and spacing of wells will be determined by reservoir parameters, the fi eld size and, particularly in the case of gas, the commercial contract requirements.

Information obtained from development drilling improves the reliability of reserve estimates and further improvements occur as the fi eld is produced.

Production techniquesField production comes under three main headings — primary, secondary (or supplementary) and tertiary (or enhanced) recovery.

In primary recovery the reservoir pressure (drive mechanism) forces oil and gas to the well and hence to the surface under natural fl ow. Some fi elds may have several producing horizons, each with a different pressure, petroleum type and other variables that need separate production. This can be accomplished with separate wells. Alternatively, a dual or multiple completion can be established in the one well.

The latter methods are mechanically more complex and therefore more diffi cult to maintain, despite the fact that they are cheaper to install than drilling second and third wells using single completions in each zone.


A beam pump unit (nodding donkey)


Natural fl ow accounts for most of the world’s oil production but, as previously mentioned, only a portion of the hydrocarbons are recovered via this means.

Secondary or supplementary recovery is achieved in a number of ways. Re-injection is a method where reservoir pressure is maintained by returning natural reservoir fl uids such as water (water fl ooding) or gas to the producing zone via strategically placed wells in the fi eld that are dedicated to re-injection. This technique bolsters the main (primary) drive as long as possible.

Gas lift (or artifi cial lift) is also a means of extending natural oil fl ow. It involves increasing the amount of gas produced with the oil by injecting gas directly into the fl owing column in a well rather than into the reservoir. Gas lift is accomplished by using special valves set up at various depths and then controlling the amount of gas entering the fl ow stream. The increase in gas/oil ratio reduces the pressure needed to drive the oil to the surface.

Pumping is another form of artifi cial lift and is accomplished in three ways — a beam or rod pump (the familiar oil fi eld ‘nodding donkey’), a hydraulic pump or a submersible electric pump. The latter two pumps are installed in the well bore itself.

Tertiary or enhanced recovery involves oil production only. It is achieved by injecting fl uids which are not normally present into the reservoir with the aim of altering the properties of the oil to enable a greater proportion to be produced. Enhanced recovery methods are generally applied after primary and secondary techniques have been exhausted. The methods include injection of miscible fl uids like carbon dioxide and nitrogen and injection of complex polymers or steam. Another technique is in situ combustion, particularly for viscous oil. This involves igniting some of the oil in the underground reservoir to heat the remaining oil and render it less viscous and thus more able to fl ow to the wells.

These tertiary methods can raise ultimate petroleum recovery by 10–20 per cent under favourable conditions.


Diagram of dual completion in producing well

Gas lift operation


Production hardwareThe production process for oil and gas is generally the same onshore as it is offshore and any differences in technique are a matter of economics and designing an engineering solution to best deal with the fl uids involved. Space limitations offshore may also infl uence the process design.

Processing includes six systems — gathering, separation, treatment/storage, water treatment, safety, and utility handling facilities.

• The gathering system is a series of small diameter pipelines connecting to each wellhead and feeding into the main processing inlet.

• The separation system relies on the fact that oil, water and gas have different densities and will settle into separate layers. Internal devices in the separation vessels assist in speeding up the process.

• The treatment, storage and disposal system for oil and gas is usually split into two streams. Oil leaving the separation system is virtually free from dissolved gas and is termed ‘stabilised’. However, it may still contain water in emulsion form. Further treatment can remove this water using various techniques, including the introduction of chemicals or the use of electrostatic separation.

Gas leaving the separation system is saturated with water vapour and hydrocarbon liquids, with the amount of liquid depending on temperature and pressure. Water is removed with absorbing substances such as glycol. Special membranes remove carbon dioxide, and dehydration enables the capture of sulphur compounds. Nitrogen and hydrocarbon liquids, mainly ethane, butane and propane, are then separated using a refrigeration process until the various components condense out of the gas stream.

• The water treatment and disposal system involves further action on the water to reduce residual oil content to acceptable environmental levels before it is discharged. The methods may include de-aeration, fi ltration or chemical treatment, with time allowed for settling out of the two phases.


• The safety system includes installation of alarms, automatic shut-downs, back-up units on important equipment, exhaust (fl are) stacks and fi re fi ghting equipment, plus strict administrative procedures and frequently practised emergency containment and evacuation plans.

• The utility systems include power generation and facilities for normal services, all of which can be, and frequently are, powered by the gas or oil being processed in the plant.

Reservoir Gathering system

Separation system

Oil treatment

system

Water injection system

Pumping system

Storage system

Pumping system

GAS

GAS

WATER

WATER

OIL

SEA

Pipeline

Pipeline

Gas lift

Tanker

Gas re-injection

Gas dehydration

system

Gas liquids recovery system

Flare system

Possible production systems on an offshore platform

Oily water separation

system

Filtration system

De-aeration system

Compression

Compression


Facilities design and layoutOnshore, the individual production wellheads on a fi eld are connected by gathering pipelines to a main processing plant or to individual storage tanks if the fi eld is small. After processing, the oil is transported either by truck, tanker or pipeline to a refi nery. Onshore facilities are placed as convenient and in accordance with any civil planning and environmental considerations.

Some examples of production platforms

Depending on the volume, gas associated with oil production is either re-injected into the reservoir for pressure maintenance or processed and sent to market via pipeline. Small amounts of the gas can be used to generate power for the production facilities. Flaring unwanted gas is now a rare occurrence, especially on a long-term basis, as most authorities and companies view this as wasting a valuable asset. There are also environmental considerations to do with greenhouse effects and any fl aring generally requires a special permit.

STEEL PILED

CONCRETE GRAVITY

FLOATING GUYED TOWER

TENSION LEG


Offshore, there are various ways of tackling the production layout, space being at a premium on a production platform or production vessel. For medium to large fi elds it is common to have one or more fi xed platforms which house all the wellheads and the processing equipment, plus accommodation for the fi eld workers. A pipeline can then be run to shore to permit more extensive processing and storage and/or distribution. In some isolated oil fi elds, a short pipeline may be laid from a platform to a nearby buoy mooring system which is used to load the oil directly into offtake tankers.

BHP Billiton-operated ‘Griffi n Venture’, offshore northwest Australia

A fl oating production storage and offtake facility (FPSO)

BRIDGE & CONTROL

ROOMFLARE

UNIVERSAL JOINT ASSEMBLY

RISERCHAIN TABLE

ANCHOR CHAINS

ANCHORS

FLOWLINES & CONTROL UMBILICAL

MOORED STORAGE/PRODUCTION TANKER

SHUTTLE OFFTAKE TANKER

HAWSER

HELIDECK

FLOATING CRUDEPRODUCT HOSE

SUBSEA WELLHEAD


Offshore platform system

Douglas complex at BHP Billiton-operated Liverpool Bay Development, Irish Sea


Platforms vary in size, shape and type depending on the size of the fi eld, the water depth and the distance from shore. Most common is a steel structure with piles sunk into the sea bed, but there are also concrete and/or steel structures that are held onto the sea bed by their own weight (gravity structures) or converted jack-up exploration rigs that stand on the sea bed. Other systems employ fl oating vessels (usually ship-shaped) known as fl oating production, storage and offtake facilities (FPSO). Another type is a tension leg platform that is tethered to the sea bed by vertical cables and yet another is the guyed tower which is supported upright by radiating cables anchored into the sea bed, acting much like the guy ropes of a tent.

In fi xed platforms, the legs have a primary function of supporting the deck and its load of processing facilities. The leg structure also surrounds and protects the well conductors (hence the term jacket). Some fi xed platforms, particularly the concrete gravity type, also contain oil storage tanks in their bases or in the column legs.

If the water is shallow and land (or another platform) is nearby, small platforms may be used with the main processing facilities located ashore (or on a centrally-located master platform).

West Tuna concrete gravity based facility being towed out from Port Kembla to Bass Strait


In other cases, subsea production units are used. These sit on the sea bed and feed oil and gas into fi xed platforms or fl oating production and storage units via fl exible fl ow lines and buoyed marine risers. The fl oating facility can range from a vessel just for storage purposes to a disconnectable, self-propelled tanker. Processing is still done on the facility, not on the sea bed, although subsea processing is a developing technology. The subsea units may be open to the sea (a wet tree) or, in the past, encapsulated in a chamber under which pressure is kept at atmospheric levels to allow operators to enter and work under normal conditions (a dry tree). Dry chambers permitted manual intervention beyond diver depths and opened the door to deep water development.

Production engineering is continually pushing the frontiers of technology, especially in offshore applications. At the same time, the best designs include equipment and systems that are as simple as possible to improve reliability and avoid potential fl ow problems. Robust system design enhances economic performance. There is also consideration given to geographic location. If the fi eld is remote from infrastructure, such as West Africa or the North West Shelf off Australia, construction vessels have to be brought in especially and this may increase the overall cost of the project. On the other hand, in the active Gulf of Mexico or North Sea, many construction vessels are employed in the region and mobilisation costs to a project are much less.

As the industry tackles deeper and deeper water, FPSOs connected to subsea wellheads are replacing fi xed platforms as the main development technique. FPSOs allow the facilities to be placed over the fi eld. Platforms in shallow water often have longer tie-backs, while the reservoirs on the edge of the continental shelf are developed subsea. Oil fl ow lines between the wells and the production facilities can be up to 30 kilometres long and must combat pressure drop-off, heat loss and an increase in oil viscosity. For gas, the fl ow lines can be much longer (up to 200 kilometres) allowing production to fl ow directly to a shore plant rather than an offshore facility. In some instances artifi cial islands have been created for shallow water and Arctic applications.


There have also been recent advances in the remote control of subsea wellheads. Undersea umbilicals carrying the hydraulic, power and electronic communication cables can be up to 150 kilometres long. In the Arctic, work is being done to perfect an umbilical system that runs under the ice to connect with and control a subsea system 400 kilometres away. Steel tubes are replacing the thermo-plastic hoses of earlier umbilical design. Another emerging technology is the development of autonomous control systems where the umbilicals only carry the communication cables, and the power for operating the subsea valves is actually generated at the wellhead. Electric trees are also being developed for long distance and very deep water application.

An alternative technique is the use of remote controlled buoys stationed in the ocean above the subsea system, such as the East Spar fi eld off Western Australia. However these buoys are best for relatively short distances from the shore line. For ‘over the horizon’ applications, satellites are needed as relay stations to bounce the control signals. In addition, the logistics of supplying chemicals such as the injection of glycol or methanol at the wellhead to improve the oil fl ow rate from the subsea wells is more diffi cult with a remotely controlled buoy system.

‘Apache’ reel pipelay barge


PipelinesPipelines are an important part of all phases of production, from the gathering systems joining wells to process facilities and in the distribution system delivering oil and gas to refi neries and markets. Pipelines vary from simple steel tubes to state-of-the-art spiral-wound, fl exible lines. They may vary in diameter from 50 millimetres to two metres.

Laying of pipelines can be expensive, particularly offshore where sophisticated techniques are used to ensure the line is properly placed. The traditional approach offshore is to weld lengths of pipe together on a lay barge and progressively lower or slide the pipeline to its designated sea bed location. The pipe is guided and supported for a short distance after leaving the lay barge by a ramp called a stinger mounted at the stern of the vessel. It is possible to lay pipe in 1000 metres of water using these conventional techniques.

For deeper water, up to 2500 metres, a J-lay method is used whereby the pipe, still welded into a continuous length on the barge, is dropped vertically and then laid on the sea bed in a bowed incline (like the letter J). Lines of up to 700 millimetres diameter have been laid in very deep water with this technique using heavy lift/lay barges.

Other methods for shallower water include welding the pipe lengths together onshore and then pulling (or towing) the completed line into the desired location as one whole unit. For smaller (up to 150 millimetres diameter) lines, it is feasible to have the pipe delivered on a reel to a specially designed reel barge which then unrolls the line along the appointed route.

Onshore pipelines are also welded and laid in sections. Usually the onshore lines are buried, thus the laying operation is preceded by trench cutting and followed by burial.


Pipe-laying operations from conventional lay barge

Pipe-laying operations from conventional lay barge, ‘Semac I’


Many offshore lines are also buried, especially in shallow water where currents and tides may cause scouring and movement if laid on top of the sea bed. Sometimes, if not buried, the lines are given thick outer coatings of concrete to weigh them down. However, there is no need for weight coating in very deep water as the currents are less and the increased thickness of the steel needed to withstand the higher external pressures at depth adds suffi cient weight to keep them in place.

Petroleum pipelines are also coated with several layers of protective material and fi tted with cathodic protection devices that inhibit corrosion. Internal pipe maintenance and cleaning is conducted by sending a scrubbing device or pig (originally named because of the squealing noise early versions made as they traversed the line) through the pipeline at regular time intervals. Other, more sophisticated pigs are able to inspect the integrity of welds and the internal condition of the pipe as they move along.

Some pipelines, particularly from offshore oil and gas fi elds to shore production facilities, carry oil, gas and condensate together. This is known as multi-phase fl ow. At the shore end of the line a device called a slug catcher (a series of parallel horizontal pipes) slows down the fl ow and enables the liquid (oil and condensate) ‘slugs’ to be separated from the gas.

Remote operating vehiclesBeyond diver depths of 200 metres, major enabling technical advances in subsea work are typifi ed by the use of remote operated vehicles (ROVs). ROVs and remote tooling systems can be operated long distances from the mother ship or control point. This enables subsea construction work, such as connection of pipelines and production systems, to take place in very deep water. The ROVs are operated from the surface, usually via an umbilical. Cameras fi tted to their hulls enable the operator to guide the vehicles into position and then send signals to the mechanical arms to perform the given task. In recent times, digital systems and the use of mega-pixel chips have revolutionised the visibility of the onboard cameras.


In addition, capabilities of these vehicles developed for the military have been made more generally available and the offshore petroleum industry is developing autonomous underwater vehicles (AUVs). These are untethered, free-ranging vehicles that can be programmed to do a task, such as a grid pattern sea bed survey or a complete pipeline survey, and then be picked up later once the job has been completed. There is no longer any need to tow the vehicle during a survey, thus saving time which can be devoted to other work.

Coal Seam MethaneCoal seam methane (CSM, sometimes called coal bed methane or coal seam gas) is natural gas formed as part of the geological process of changing organic matter into coal. The CSM is generated either from a biological process resulting from microbial action or from a thermal process resulting from increased heat with the depth of burial of the coal seams.

Unlike conventional natural gas reservoirs, where the gas is trapped in the pore spaces within rocks like sandstone and limestone, the methane trapped in coal is adsorbed onto the surface of cleats or joints in the coal and held in place by the pressure of water within the seam. Thus coal is both the source and the reservoir for CSM.

The surface area of the cleats is very large, so coal can potentially contain more methane per unit volume than many conventional gas reservoirs. The amount of trapped gas is related to the coal type and the pressure and temperature of burial. However most coals have lower permeabilities than conventional gas reservoirs and the production rates are lower, often requiring some form of stimulation such as hydraulic fracturing.

This is achieved by drilling wells into the coal seam and pumping down large volumes of water and sand to produce new fractures and/or force open and extend the existing cleats and joints. Generally the fracturing extends for up to several hundred metres in all directions from the well bore. The sand helps to keep the fractures open.


However the gas trapped on the coal surfaces cannot be released until the water pressure holding it there is decreased. This is done by physically pumping water from the wells until gas comes free and begins to fl ow naturally up the wells. The time taken for gas to begin fl owing after starting the pumps can vary from several weeks to several months. The water can be re-injected into formations below the coal seams, or collected in dams at the surface where it is allowed to evaporate. Research is also being conducted into the potential for using the water for agriculture and other purposes.

CSM is typically found at shallower depths than conventional gas (200 metres –1000 metres compared to 1500 metres –4000 metres plus) and reaches the surface at very low pressure. It must be compressed before being sent through pipelines to market. Nevertheless, the shallower depths do enable the use of small truck-mounted rigs to drill the wells which improves the economics of an operation.

Wells are generally drilled in groups of fi ve — one central well and four surrounding it — called a ‘fi ve spot’. The four outer wells are designed to drain water away from the central well which can then fl ow gas to surface. Development of a CSM fi eld progresses when the four outer wells are themselves surrounded by newly drilled wells pumping water until the four also become producers and so on. A CSM fi eld can contain hundreds of wells during its lifetime.

Not all parts of a coal seam are conducive to CSM production and explorers concentrate on ‘sweet spots’ — areas that have the highest degree of natural fractures. These can be detected using the same geophysical techniques employed in conventional petroleum exploration. Sometimes a CSM operation is employed in advance of underground coal mining, the extraction of the gas lessening the risk of explosion during the mining operation.

CSM has become an important source of natural gas in the USA where it supplies about eight per cent of the nation’s gas demand. In Australia, CSM is being produced in the Sydney Basin of New South Wales and in the Bowen and Surat Basins of Queensland. The Queensland CSM fl ow supplies 30 per cent of the State’s gas demand.

reading assignment 1- oil and gas basics

Documents

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petroleum business

petroleum specialists

successful petroleum

forefront of australias

gas industry

chlorine free tcf