Drilling

Modern society is powered by the chemical energy locked in ancient hydrocarbons – yet few people realize that these fuels owe more to plankton than to the popular myth of dinosaurs. This article unpacks the true story behind petroleum’s birth, tracing the journey from microscopic life to the reservoirs that energize the world.

The microscopic protagonists of this tale live on in today’s oceans, lakes, and soils. Their remains, buried, cooked, and compressed over geological time, became the oil and natural gas that drive engines, heat homes, and forge countless plastics.

Microscopic view of various phytoplankton, including diatoms and green algal cells, representing the organic matter that forms fossil fuels.

1. The Biological Source: Plankton and Algae

1.1 An Ocean of Organic Riches

• Marine phytoplankton and zooplankton dominated Mesozoic and early Cenozoic seas, fixing solar energy into organic carbon that rained onto anoxic seafloors.
• Over millions of years, this detritus mixed with fine mud to form organic-rich sapropel, the precursor of kerogen.

Microscopic view of a planktonic organism with hair-like structures

1.2 From Sapropel to Kerogen

• Shallow burial (temperatures < 50 °C) sees bacterial alteration transform organic debris into kerogen, an insoluble, waxy complex.
• Kerogen type determines product: Type I and II (algal/marine) are oil-prone; Type III (terrestrial plant) is gas-prone.

2. Geological Alchemy: Diagenesis, Catagenesis, Metagenesis

Data after petroleum maturation studies.

2.1 The Oil Window

Kerogen begins releasing liquid hydrocarbons when vitrinite reflectance rises above 0.6%Ro, peaking near 1.1%Ro before oil yields decline as gas dominates.

2.2 Thermal Cracking and Gas Generation

Above 150 °C, heavy molecules fragment into methane, ethane, CO₂, and H₂S, explaining why deeper, hotter plays such as many tight-gas basins are gas-rich.

3. Migration: Journey to the Trap

3.1 Primary and Secondary Migration

• Overpressure from kerogen cracking expels oil into adjacent carrier beds
• Buoyancy then drives hydrocarbons updip through permeable sandstones or faults until sealed by impermeable cap rocks.

3.2 Timing Is Everything

Successful accumulations require trap formation to precede or coincide with migration; late faulting can breach reservoirs and vent hydrocarbons to the surface.

4. Trapping the Treasure

4.1 Structural vs. Stratigraphic Traps

• Structural: anticlines, fault blocks, salt domes fold or fault reservoir strata, creating closures that hold hydrocarbons.
• Stratigraphic: pinch-outs, unconformities, and reef buildups rely on facies changes rather than deformation.

4.2 Cap Rocks and Seals

Shales, evaporites, or tight carbonates provide the low permeability critical to preserving buoyant fluids over millions of years.

5. Debunking Abiogenic Myths

While minor mantle-derived methane exists, isotope signatures, biomarkers, and optical activity overwhelmingly confirm a biogenic origin for > 99% of commercial hydrocarbons.

6. Modern Exploration: Reading the Petroleum System

Exploration geologists integrate:

1. Source Rock Quality (TOC, kerogen type)
2. Thermal Maturity (Ro, Tmax)
3. Migration Pathways (seismic, basin modeling)
4. Trap Integrity (structure mapping, cap-rock analysis)

Advances in 3-D seismic and basin simulation now allow prediction of hydrocarbon phase, timing, and volume with unprecedented precision.

A diverse microscopic view of various marine plankton, including copepods and other organisms, fundamental to the origin of fossil fuels.

7. Environmental Time Capsule

The deep carbon cycle continuously buries and recycles organic carbon; petroleum deposits are merely waystations in this flux, reminding us that fossil fuels are finite snapshots of ancient sunlight.

Conclusion

Oil and gas are the result of a grand interplay between biology and geology: micro-scale life meeting macro-scale tectonics, heat, and time. Recognizing plankton—not dinosaurs—as the real ancestors of petroleum fosters a deeper appreciation of both Earth’s history and the energy choices shaping our future.

A detailed microscopic view of a water flea, a type of zooplankton, representing the ancient organic matter that contributes to fossil fuel formation.

Recommended Educational Videos

1. “Oil Formation – Science Learning Hub” – Animated overview of source, maturation, and trapping processes.
2. “How Natural Gas Is Formed” (YouTube) – Clear explanation of gas generation and migration in sedimentary basins.
3. PetroSkills “Petroleum System – Trap and Timing” – Professional module on pitfalls of exploration timing.

These resources complement the images above and provide dynamic visuals suitable for embedding in a WordPress educational post.

How do oil and gas form?

Oil and gas, which are fossil fuels, are formed over millions of years from the remains of ancient marine organisms like algae, microscopic animals, and plants. After these organisms die, they settle on the ocean floor and are buried under layers of sediment. In the absence of oxygen, these organic remains transform into a substance called kerogen. Over time, under immense heat and pressure, kerogen gradually converts into oil or natural gas. This entire process typically takes at least a million years.

What are oil and gas made of at a molecular level?

At the molecular level, both oil and natural gas are hydrocarbons. This means they are composed of hydrogen and carbon atoms.

How do oil and gas move within the Earth’s crust?

The constant pressure and movement of the Earth’s crust play a crucial role in the movement of oil and gas. This pressure squeezes oil and gas through the pores, or tiny spaces, between rocks. While some oil and gas naturally seep out onto the Earth’s surface, much of it gets trapped beneath the surface.

What are oil and gas reservoirs?

Oil and gas reservoirs are large underground formations where deposits of oil or gas accumulate. These reservoirs are often trapped by impermeable layers of rock or by geological structures like faults and folds within the Earth’s crust. They can be incredibly vast, sometimes as large as a city, and can be thought of as immense sponges filled with oil and gas.

How do geologists locate oil and gas deposits?

Geologists employ various survey techniques to find oil and gas deposits. These methods include seismic surveys, which use reflected sound waves to create a 3D view of the Earth’s interior, gravitational surveys, and geological mapping. Advanced technologies, such as four-dimensional projections and sophisticated graphic renderings of rock structures, are continuously improving the efficiency of finding conventional oil and gas deposits.

What is the difference between conventional and unconventional oil and gas?

Conventional oil and gas deposits are those that are relatively easier and less expensive to extract using established methods. Unconventional oil and gas, on the other hand, refers to energy resources that are currently difficult or costly to extract due to their location, type of rock formation, or other geological complexities.

Why are oil and gas considered non-renewable resources?

Oil and gas are classified as non-renewable resources because their formation takes millions of years. The rate at which they are consumed by human society is vastly greater than the rate at which they naturally form, meaning their supply is finite and cannot be replenished within a human timescale.

What are the future prospects for energy sources?

Given that oil and gas are limited energy resources, there is a growing focus on finding more efficient ways to extract unconventional oil and gas. Simultaneously, there is a significant push towards developing and utilizing alternative and renewable sources of energy, such as biofuels and solar power, to meet future energy demands.

Tests on oil and gas wells are performed at various stages of drilling, completion and production. The test objectives at each stage range from simple identification of produced fluids and determination of reservoir deliverability to the characterization of complex reservoir features. Most well tests can be grouped either as productivity testing or as descriptive/reservoir testing.

• Productivity well tests are conducted to;

• Identify produced fluids and determine their respective volume ratios.
• Measure reservoir pressure and temperature.
• Obtain samples suitable for PVT analysis.
• Determine well deliverability.
• Evaluate completion efficiency.
• Characterize well damage.
• Evaluate work over or stimulation treatment.

• Descriptive tests seek to;

• Evaluate reservoir parameters.
• Characterize reservoir heterogeneities.
• Assess reservoir extent and geometry.
• Determine hydraulic communication between wells.

Types of Tests

In this section we will deal with the most common of tests carried out and that is Clean Up then flow. It also covers the DST Test which is now only carried out on rare occasions.
When you talk about well testing only two things actually happen:
Drawdown – When you flow the well
Buildup – When you shut in and monitor the pressure
These two things are generally all that happens during a Well Test and it is the frequency with which they are carried out determines the type of Well Test.

Well clean up procedures

The purpose of cleaning a well as a preliminary flow operation to testing is to blow back into the well bore and to the surface extraneous fluids such as mud cake, mud filtrate, mechanically rock particles and most frequently, it is to unload well stimulation liquids-fluids such as spent acid or frac fluids which have been pumped into the formation.
The general characteristic of an “active well clean up drive”, or a clean-up flow in progress, is an increase in the well’s productivity, which results from the lowering of the saturation level near the well bore of the extraneous fluids, the corresponding increase in saturations and relative permeability of the formation fluids.
The initial phase of the clean-up sequence for a stimulated well may be characterized by low flowing wellhead pressures and recovery of large volumes of stimulation fluids.
As the clean up progresses, there is usually a rise in flowing pressure, a decrease in the rate of recovery of stimulation fluids and an increase in production of reservoir fluids.
The amount of pressure drawdown to be applied during the well clean up sequence should not exceed the level considered prudent for the largest test rate allowed for the well or approximately 30 per cent at the sand face due to danger of causing water coning or sand blasting into the well bore. This general recommendation does not apply to the initial stages when the liquid load in the tubing causes considerable hydrostatic back pressure at bottom hole. However, as the well’s productivity increases, the choke should be progressively adjusted to prevent excessive draw downs.

In the case of very low productivity wells, it may be necessary to flow them wide open in order to unload the liquids and also to adopt an off-and-on clean up procedure known as “stop cocking” in order to allow the well bore region to recover some of the formation pressure during the shut-in periods and use the higher initial productivity to achieve some degree of effective clean up action.
The well’s performance during clean up should be recorded with the same care and frequency as during testing operations in order to check on clean up progress and obtain preliminary information to assist in finalizing a testing program.
Once the choke has been set to a desirable opening, flowing tubing head pressures should be plotted versus log of flow time on a semi-log graph. Also, water and oil production should be tabulated, and the production rate regularly calculated, so that changing trends can be observed. Completion of clean-up will be marked by a stabilization of water production rate and no further increase of the well’s productivity.
There are no technical means of predicting the flow duration necessary to effectively
clean up a well. Only the observations and analysis of the flow characteristics during
the clean up period can give some measure of the clean up progress achieved.

The following are observations which may indicate nearing the end of the clean-up phase:

• BS&W of less than 0.1%. On gas wells obtaining shakeouts with 10%+ condensate.
• Salinity stabilization near salinity of formation water.
• BHP and/or WHP stabilization.
• Flow rate stabilization.
• Ph indicating 5 (or above) or neutral after acidizing.

In general, wells in the high productivity range tend to clean up faster than those at the other end of the scale.

The well flow should initially be directed to a tank or overboard through the gas flare line. Gas well cleaning up can be continued through the flare as the gas volume increases. In the case of an oil well, the flow should be directed to the burner once it is apparent oil has reached surface.
The cleaning up operation should be carried out with great care, bearing in mind the possibility of serious damage to equipment by abrasion (sand, mud, perforating debris, etc. brought up with the well fluids). It is advisable to use the choke manifold near the wellhead and to bypass all testing equipment (heater & separator).
Under no circumstances is the well to be cleaned up through the separator. Avoid exposing the equipment for prolonged periods to any fluids containing sand (e.g. after fracturization), or H2S if the equipment is not designed specifically for H2S service.
Normally after the initial clean up period the well will be shut in to build up pressure back to reservoir pressure and then flow testing can be carried out.

Drill Stem Test

A set of drill stem tools is an array of downhole hardware used for the temporary completion of a well. They are run as a means of providing a safe and efficient method of controlling a formation during the gathering of essential reservoir data in the exploration, appraisal and even development phase of a well, or to perform essential pre-conditioning or treatment services prior to permanent completion of the
well.
Two types of Drill Stem Tests are carried out they are:

• Open Hole Drill Stem Tests
• Cased Hole Drill Stem Tests

Open Hole Drill Stem Testing

If hydrocarbons are detected in either cores or cuttings during drilling or indicated by the logs, an open hole DST provides a rapid, economical means to quickly assess the potential of the formation. However, the technique requires the hole to be in very good condition and highly consolidated as the packer elements actually seal on the rock face. The open hole sections also limit the application of pressure on the annulus, therefore special strings are designed which are operated by pipe reciprocation and/or rotation. The Multiflow Evaluator System (MFE) is a self-contained open hole drill stem test string.
If drilling is not halted to allow testing when a potential hydrocarbon bearing zone is encountered, and alternative test method is to wait until the well is drilled to total depth and then use straddle packers to isolate the zone of interest.
Open hole drill stem tests gather important early information, but reservoir testing requires more data over a longer period. The extent of reservoir investigated increases with test duration. A key factor governing the duration of an open hole test is well bore stability. At some point the well may cave in on top of the packer and the string may get permanently stuck downhole, calling for an expensive sidetrack.
These hazards of well bore stability have been eliminated by testing after the casing has been set and, in many sectors, particularly offshore, cased hole testing has replaced traditional open hole drill stem testing.

Cased Hole Drill Stem Testing

As offshore drilling increased, floating rigs became common, increasing the potential for vessel heave to accidentally cycle traditional weight set tools and even un-set the packer. In addition, deeper more deviated wells make reciprocal tools more difficult to operate and control and thus jeopardize the safety of the operation. A pressure-controlled system was designed specifically for these applications, eliminating the need for pipe manipulation after the packer has been set, and eventually becoming
the new standard in drill stem test operations.

DST Tools

The basic tools on a DST String are as follows:
Paker – This provides a seal and isolates Hydrostatic Pressure from Formation Pressure much the same as for permanent completions.
Tester Valve – A test valve, run above the packer, isolates Cushion Pressure from Hydrostatic Pressure while running in the hole. It also helps reduce the effects of well bore storage which is an important element of interpretation. After the packer is set and the tester valve opened, flow to surface occurs.
Reverse Circulation Valve – A reverse circulation valve provides a means of removing produced fluids before pulling out of the hole. For redundancy, two reversing valves with different operating systems are normally run. In addition, reversing valves are used to spot cushion and acid treatments.
Slip Joint – A slip joint is an expansion/contraction compensation tool. It accommodates any changes in string length caused be temperature and pressure during the DST. The tool is hydraulically balanced and insensitive to applied tubing pressures. Slip joints have a stroke of approx. 5 feet, the total number of slip joints depends on well conditions.
Hydraulic Jars – A hydraulic jar provides the means of transmitting an upwards shock to the tool string in the event that the packer and lower assembly become stuck. The tool has a time regulated action as transferring rapid movement in a long string is not a simple matter. An upward pull activates a regulated oil flow until the hammer section is released thus giving a rapid upward movement and generating
the relevant shock.
Safety Joint – A safety joint is actuated only if a jar cannot pull stuck tools loose. By manipulating the tool string (usually by a combination of reciprocation and rotation), the safety joint, which is basically two housings connected by a course thread, can be unscrewed and the upper part of the string removed from the well.
Gauge Carrier – When run with a test string, both mechanical and electronic gauges must be placed in a carrier for support and protection. Carriers can either be of the above or below packer type.
Many more tools can be added to a DST string, depending on the requirements of the client.

PROGRAM DESIGN

1- Types of Casings and Functions

There are five main types of casings

· The Conductor Casing or stove pipe

· The Surface Casing

· The Intermediate Casing

· The Production casing

· The Production Liner System – Liner set through the productive interval and landed inside the casing on a hanger or with tieback to the surface

The main function of these casings are:

1. To furnish a permanent and gauge wellbore of precise diameter through which subsequent drilling, completion and production operations can take place
2. To allow selective production from heterogeneous formations without interformational flow
3. To allow the a means of attaching the wellhead system and Xmas tree to control and handle the produced fluid.

More specifically, the conductor/surface easing is used to :

• Control caving and washing out of poorly consolidated surface formations
• Furnish the means of handling the return flow of drilling fluid
• Protect fresh water sands from possible contamination by drilling fluid, oil/gas or formation water.
• Allow the attachment of BOP systems.

The main function of the intermediate easing is to seal off troublesome zones, which contaminate the drilling fluid or jeopardise drilling progress with possible hole problems
The production string or liner provides the means of segregating the pay section from all other zones and allow for selective production.

2- Casing String Design Considerations

Casing Strings are designed to withstand four principal types of loading ;

1. Collapse stress : Stress due to unbalanced external pressure on the casing . Most conservative approach is to assume casing is evacuated with external hydrostatic pressure imposed on the casing.
2. Burst Loading : This is is the condition of unbalanced internal pressure imposed by formation pressure with no external pressure through the annulus.
3. Tensile Loading : Each string suspending the weight of subsequent strings below it. Active at JOINTS.
4. Compression Loading : Active at JOINTS of two casing

Best approach is to have a combination string design to minimise cost. That is sometimes impracticable. May be convenient to use a single string system.

Casing Design Criteria

Design of a casing program is based on :
· specification of surface and bottom hole well locations
· size of production casing
· number and sizes of tubing string
· type of artificial lift system

Design specification includes :
· Bit sizes
· Casing sizes. grades and setting depths
· Design based on multiple combination sizes, grades, wall thickness, coupling type

Determination of Casing Setting Depths

Knowledge of geological conditions in a given area can aid the determination of casing depths. There are basically four major types of casing but the number of each type of casing and the setting depths are influenced by the geological conditions of the area. The principle of selecting the casing shoe setting depths starts with the knowledge of formation and fracture gradient. A typical plot of a projected fracture and production setting depths. A typical well
configuration with casing is shown in fig

Steps

1. A line representing the planned mud density programme is plotted This is Pore pressure plus trip margin(200-500psi or .5ppg) – Safety over pore pressure or equivalent mud density reduction during trip
2. Select Point a at required depth(To prevent kick)
3. Plot the fracture gradient profile
4. Plot a secondary safe working fracture margin line – This is fracture gradient less kick or trip margin.
5. Extend point a vertical and intercept the safe fracture margin line at point
   b. This is the equivalent safe mud density needed to drill to point a
6. To drill to point b and set intermediate casing, drilling fluid at point c is needed and will require surface casing to be set at point d.
7. The conductor casing SD is based on the amount required to prevent washout, etc.

Selection of Casing Sizes

The size of the casing string is dictated by the ID of production string and number of intermediate string desired.
For a given Production string O.D, the bit size must be greater than O.D. of casing joint to provide sufficient clearance.
Table 1 shows commonly used bit sizes. In special circumstances, other bit sizes can be used.

Selection of Casing Weight, Grade and Coupling

Load Conditions are: Burst, Collapse, tension, Compression, bending or buckling, thermal effect, kick Consideration

Surface Casing

1. Burst Loading – Based on maximum internal pressure under kick control condition.
   Design pressure = Fracture pressure + SF.
   Design assumes casing is evacuated of mud with gas in the casing
2. Collapse Design – Based on the most severe lost circulation problem
   · Uses maximwn possible external pressure to cause casing collapse due to mud weight. Ignores effect of cement or mud degradation.
   · Also assumes casing is evacuated with mud hydrostatic pressure acting externally.
   · Correction is made for axial tension

0.052rmax(D_k, – D_m) = 0.052 rp D_k

rmax,= maximum mud density anticipated at lost circulation depth
rp = equivalent pore pressure density of the LC zone
D_m is depth to which mud level would fall.

3. Tension design – requires consideration of axial stress correction is also made for bending stresses in directional wells.

Intermediate Casing

Intermediate easing is similar to surface in that its function is to permit final depth objective to be reached.
To minimise cost of casing, the following anticipation in line with illustration below can be anticipated.

rmax + 0.052rm(D_k, – D_m) = pi
Dm = depth of mud-gas interface.
pi = injection pressure opposite lost circulation zone.

Production String

Special Considerations
· Gas production in well
· Casing to withstand tubing leak near surface
· Depleted reservoir condition
· Tension consideration same as for other casings.

Casing Policy

Different types of casing schemes are used by different companies depending on the type of well, type of formation, lithology and stratigraphy; well depth, etc.
An appropriate casing design exercise involves careful determination of factors that influence casing failure under various conditions and selecting the most suitable, safe and economical casing strings. Design is based mainly on size and grade, which take into account the possible loads to be encountered. These include yield, collapse and burst pressure considerations. In many cases the design result in combination string selection. Nevertheless, companies generally evolve their own policy and are guided by official regulating policies of host country in the choice of appropriate string to use.

The policies generally cover:

1. Types of casings to use
2. Choice of single or combination string design.
3. Size of casings in 1’me with overall well plan.
4. Grades of casings and setting depths(Grades according to API in Table1)
5. Completion strategy In terms of especially presence of multiple pay sections, etc
6. Production strategy

In all the overriding parameters or factors are:
· cost
· Completion strategy
· Downhole conditions
· Presence of problem zones
· Availability of casing grades.

Choices of casing setting depths are based mostly on the analysis of formation pressure and temperature gradient profiles.

3- Cementing Operation Design.

Key Functions of Cementing are:

1. To afford additional support for the casing either by physical brazing or seal off of formation
2. To reduce casing corrosion by minimising contact between casing and formation fluid
3. To reinforce the junction of multilateral wells
4. Repair job through squeeze cementing

Types Of Cements

Class A: Depth = 6000ft; No special properties
Class B: Depth = 6000ft; Moderate to high sulphate resistance
Class C Depth = 6000ft; High early strength requirement
Class D: Depth = 6000 -1000Oft; Moderately high temperature and pressure

Class E: Depth = 1000Oft to 1400Oft High temperature and high pressure
Class F: Depth = 1 000Oft to 1600Oft; Extremely high temperature and pressure
Class G/Class h: Basic Cement up to 800Oft

Cement Additives

Wide range of additives to provide acceptable slurry properties such as
· density control : bentonite for reduction, pozollan
· setting time control
· lost circulation control
· filtration control
· viscosity control
· temperature control

Normal Terms

1. Percent Mix = Water Weight/Cement Weight X 100
2. Yield of Cement = Slurry volume per sack of cement.
3. 1 Sack = 94Ibm.
4. WOC – Waiting on Cement = Setting time
5. Accelerators – Reduces setting time
6. Retarders – Prolong setting time

Cement Placement Techniques

1. Casing Cementing/Liner Cementing
2. Cement Plugs
3. Squeeze Cementing
   

Casing Cementing

Here a conventional wiper plug method is usually used. Placement involves the following :

1. Bottom casing must have a cementing head with float collar
2. Bottom plug is dropped in until it hits the float collar.
3. Cement is displaced until pressure build-up causes rupture of diaphragm in bottom plug.
4. Slurry then flows out into annulus
5. At appropriate time top plug is dropped in and surface pressure builds up to indicate cement fillup.
6. Sometimes no wiper plugs are used.
7. Cementing can equally be done with coiled tubing.
   To perform this job requires a knowledge of :
   · Slurry volume
   · Sacks of cement
   · Mix water requirements
   · Additives requirements
   Design takes into account the fact that some cement would remain in float collar to be drilled out.

The bits and its performance are what rotary drilling is all about. When the bit is on bottom and making hole, it is making money-but only as long as it is an effective cutting tool.
To be an effective cutting tool, the bit must be in good condition. Weight must be applied to make the bit drill, and supply this weight is one function of the drill collars. The bit must be rotated, and rotation is the function of the drill stem and the rotary. Finally, the drilling fluid must cool and lubricate the bit as it removes chips and cuttings from the bottom of the hole.

Many variables affect bit performance, particularly the type of formations being drilled. These variables usually involve questions of economics, especially in the selection of a bit type that can drill most economically. Drillers want a bit that has a good rate of penetration (ROP), lasts a reasonable number of rotating hours, and drills holes the same size as the bit (true-togauge).
Essentially, the driller is looking for a bit that averages the most feet per hour and lasts the most hours possible. If the sides of the bit wear down, it will drill and undersize, or undergauge, hole. Out-of-gauge holes cause lost time for reaming, but can also stick the drill stem, cause a fishing job, and thus increase drilling costs.

In most situations, the objective is to get all the footage possible from a bit, thereby minimizing the number of round trips needed for bit changes. Situations occur in which only one or two bits are needed before pulling out for a survey running casing. For example, when making hole to set surface casing in extremely soft formations, only one bit may be needed, and occasionally, that bit may be used for several wells. Deeper drilling in harder rocks is more difficult. Trip time increases, and the driller will generally run a bit designed to drill these formations as well as to drill the surface casing cement left in the hole. In some instances, the cement may be drilled and then bits changed to drill that particular formation.

Formations vary in hardness and abrasiveness. If the bedded strata did not change, one bit best suited for that formation could be selected, and drilling ahead could begin. Usually, however, the strata are made up of alternating layers of soft material, hard brittle rocks, and hard, abrasive sections. Instead of changing bits every time a new type of formation is encountered a compromise bit that can drill through all types of formation is chosen. If drilling is taking place in a known field, information about the formations is available to the driller. If a wildcat well is being drilled, a process of trial and error will have to be followed in selecting bits.

The different types of bit that are generally available are Rock Cone bit, Diamond bit, polycrystalline diamond compact (PCD) bits and Drag bits. Roller cone, or rock, bits have cone shaped steel devices called cones that turn as the bit rotates . Most roller cone bits have three cones, although some have two and some have four. Teeth can be cut out of the cones, or very hard tungsten carbide buttons can be inserted into the cones. The teeth or tungsten carbide inserts will actually cut or gouge out the formation as the bit is rotated.
Diamond bits do not have cones or teeth. Instead, several diamonds are embedded in the bottom and sides quite efficiently. Drag bits are used to drill shallow, soft formations close to the surface. All bits have passages drilled through them to permit drilling fluid to exit.

A knowledge of formation pressure (or pore pressure ) is essential in drilling engineering, since, it affects casing design, mud weights, penetration rates, problems with stuck pipe, and well control. Of critical importance is the prediction and detection of high pressure zones where there is risk of blow out. Such zones are usually associated with thick shale sequences, which have trapped the connate water normally released during deposition.

A simplified model consisting of a vessel containing a fluid spring (representing the rock matrix) can describe the compaction process. A piston being forced down on the vessel can simulate the overburden stress. The Overburden (S) is supported by the stress in the spring (s) and the fluid pore pressure (r). Thus:

S = s + r

If the overburden is increased (e.g., die to more sediments being laid down) the extra load must be borne by the matrix and the pore fluid. In a formation where the fluids are free to move, the increased load must be taken by the matrix., while the fluid remains as hydrostatic. Under such circumstances, the pore pressure can be described as Normal, and is proportional to the depth and fluid density. If, however, the formation is somehow sealed so that the fluids cannot escape, the fluid pressure must increase above the hydrostatic value. Such a formation can be described as Overpressurized (i.e., part of the overburden stress being transferred from the matrix to the fluid in the pore space.). The grain to grain contact area cannot be increased due to presence of incompressible water, so the extra load must be taken by the fluid, thus increasing the pore pressure.

ORIGIN OF NORMAL PORE PRESSURES

Consider a layer of sediments deposited on the ocean floor in a fluid environment. As further sediments are laid on top, the grains are packed close together, thus expelling the water from the pore spaces. If this process is not interrupted, and the subsurface water is still continuos with the sea above via. the interconnected pores, the pressure will be hydrostatic. The hydrostatic gradient (psi/ft) varies according to the fluid density. Most oil field brines have a dissolved mineral content, which may vary from [o to over 200,000 ppm].

Correspondingly, the hydrostatic gradient ranges from 0.433 psi/ft (pure water) to about 0.50 psi/ft. In most geographical areas, the hydrostatic gradient is taken as 0.465 psi/ft (assuming 80,000 ppm of salt content). This gradient defines a normally pressurerized formation. Any formation pressure above or below this gradient may be called abnormal.

The bulk density of the rock must include the matrix, and the water in the pore space.

where,

Since lithology and fluid content are not constant, the bulk density will vary with depth.

The overburden gradient is derived from the pressure exerted by the rock above the depth of interest. This can be calculated from the specific gravity which vary from 2.1 (sandstone) to 2.4 (limestone). Using an average of 2.3 and converting to a gradient;

2.3 x 0.433 = 0.9959 psi/ft

For most calculations this is rounded up to 1 psi/ft. It is sometimes called geostatic gradient. It is unlikely that formation pressure could exceed the overburden gradient. however, it should be remembered that the overburden gradient may vary with depth due to compaction and change lithology and so cannot be assumed to be constant.

Types of Casings and Functions

There are five main types of casings

• The Conductor Casing or stove pipe
• The Surface Casing
• The Intermediate Casing
• The Production casing
• The Production Liner System – Liner set through the productive interval and landed inside the casing on a hanger or with tieback to the surface

The main function of these casings are:
1. To furnish a permanent and gauge wellbore of precise diameter through
which subsequent drilling, completion and production operations can take
place
2. To allow selective production from heterogeneous formations without
interformational flow
3. To allow the a means of attaching the wellhead system and Xmas tree to
control and handle the produced fluid.

More specifically, the conductor/surface easing is used to :

• Control caving and washing out of poorly consolidated surface formations
• Furnish the means of handling the return flow of drilling fluid
• Protect fresh water sands from possible contamination by drilling fluid, oil/gas or formation water.
• Allow the attachment of BOP systems.

The main function of the intermediate easing is to seal off troublesome zones, which contaminate the drilling fluid or jeopardise drilling progress with possible hole problems
The production string or liner provides the means of segregating the pay
section from all other zones and allow for selective production.