OVERVIEW
Introduction
Finding and producing oil and gas is usually considered to consist of the following phases:
1.
Exploration
2.
Evaluation
3.
Drilling
4.
Production
5.
Termination
Interactivity: Five phases in finding and producing oil and gas
Exploration involves the sciences of Geology and Geophysics. The geologist uses all available geological information about the region to evaluate the possibility of finding hydrocarbons, including knowledge of possible earlier or ongoing production of hydrocarbons in the same district. The term “hydrocarbons” covers both oil and gas and refers to the fact that oil and gas consist of molecules that contain only carbon and hydrogen.
If a promising field is found the right to produce hydrocarbons can be bought or leased for a certain time. If this is a success the lease can usually be renewed throughout the time it takes to produce the oil and gas, or the lifetime of the field. Before any wells are drilled the field is usually investigated by seismic, where the reflection of sound waves from different layers of rock is registered and analyzed. From seismic measurement the geological structures below the surface are mapped, this is the geophysical part. The results are interpreted, and the probability of finding hydrocarbons, and where to find them, are estimated by geologists, geophysicists, and reservoir engineers.
If the probability is good, one or several test wells are drilled at selected locations by a drilling crew, usually including drilling engineers. While drilling, rock and fluid samples are taken and reservoir properties are investigated by different logging methods. If hydrocarbons are detected they are produced for a short time to find a preliminary estimate of the production potential of the reservoir. This potential is estimated by reservoir engineers, mainly by analyzing the rock and fluid samples taken, interpreting the results from logging, by using flow rate and types of fluids produced, and by monitoring the pressure behavior in the well.
If the results are promising more test wells may be drilled. The main purpose of these wells is to map the border of the reservoir. It is now possible to calculate more accurately the amount of hydrocarbons present. A numerical simulation of the possible production from the reservoir (reservoir simulation) may also be performed. This also gives suggestions for good locations of the production wells to be drilled. If the result is satisfactory the oil company will probably develop the field, necessary surface equipment is mounted, and drilling of production wells is started. For offshore fields this might involve construction of platforms to carry the surface production equipment. Some of the test wells may turn out to be useful as production or injection wells, but as they are not situated below the platforms special arrangements must be used, they can be satellite wells, or produced by production ships. It might be more economical to plug those wells and drill new wells from the platforms instead.

To obtain the best possible performance of each well is mainly the responsibility of the production engineers. They are also responsible for the production equipment at the top of the wells, where oil and gas are separated and treated for transport. Especially at offshore locations this treatment is kept to a minimum, it is much cheaper to treat hydrocarbons at a refinery on land.
Rock properties
Interactivity: Hydrocarbons are found in sedimentary rock
Oil and gas are found in sedimentary rock. This rock consists of grains that have been deposited over long periods of time, often at the sea bottom. As new layers of deposits are laid down and former layers are buried deeper they experience increasing pressure and temperature. This may start a process of consolidation, where water in the spaces between the grains deposit minerals in the water on the surface of the grains.
Illustration: Process of consolidation
At the places where grains are pushed against each other they will fuse, see figure.
Illustration: Fusion of grains
Another process is re-crystallization and fusion at contact points. The resulting rock becomes stronger as the fusion of grains increases, and the spaces between the grains become smaller.
These spaces are called pores, and a rock containing pores is called porous. Porosity is the total pore space divided by the bulk volume, or the outer volume.
Interactivity: Fusion of grains creates a porous rock
The bulk volume contains both the pore space and the total volume of the grains. The symbol for porosity is usually the letter

. The porosity of sedimentary rock lies mainly between a few percent and up to 40 percent, 20 percent may be a representative value for a good reservoir rock.
Interactivity: Process of consolidation interactive
In practically all cases the pores in sedimentary rock lying below the sea or below the water table on land are filled with water, salt water below the sea and also at deeper levels below land. In a few cases the pore space is filled with oil and gas. The rock is then a hydrocarbon reservoir. In the petroleum industry this hydrocarbon reservoir is the target, to drill down into it and produce as much as possible of the oil and gas contained there. It is obviously desirable to have a reservoir with as high porosity as possible, as more hydrocarbons then will be present in a given volume of rock. But it is even more important that the hydrocarbons flow at a reasonably high rate towards the wells drilled.
Illustration: Pore spaces filled with hydrocarbons is a reservoir

Permeability is a measure of how easily fluids flow through the pores in a porous rock. The symbol for permeability is the letter k . The unit traditionally used is Darcy (D), or milliDarcy
(mD). For a sedimentary rock to be a useful reservoir rock it must not only have a reasonable high porosity, but also a relatively high permeability, if not the hydrocarbons will be produced too slowly to be of economic interest. Reservoirs with permeability lower than 10 mD are not considered good oil reservoirs, but may be produced if they contain gas because gas flows more easily than oil. Some reservoirs can have permeabilities up to 1000 mD and even more.
Interactivity: Useful reservoirs must have a reasonable porosity and high permeability
The grains in sediments are often produced by erosion of rocks, thereafter carried by water (or wind) to the place where they are finally deposited and buried. All types of rocks can be the source of these grains, for instance granite, lava, earlier formed sedimentary rocks, or earlier deposited sand or clay. Another source of grains is the chalk skeletons of small animals living in water. As they die the body disappears but the skeletons fall to the bottom and can over millions of years build up massive layers. If there are no deposits of other types of grains this gives pure chalk.
Illustration: Grains in sediments
There are basically four types of sedimentary rock:
Sand stone, grains are relatively hard and large, often giving good porosity and permeability.
Shale, from deposited clay where grains are very small, giving low porosity and extremely low permeability.
Chalk, skeleton grains, often giving good porosity and some times good permeability, but low permeability are often found even if porosity is large.
Salt, no porosity and no permeability.
Interactivity: Four types of sedimentary rock
Salt deposits can be formed when shallow seas in hot, dry climates are connected to the oceans. The salt seawater seeping in will evaporate and deposit its salt content on the bottom.
If this goes on for geological times (millions of years), massive salt layers can build up.
There is such a layer in the North Sea, below the hydrocarbon reservoirs produced in the
British and Norwegian sectors. As salt is less dense than the sedimentary rocks above it, it becomes hydrostatically unstable and rises slowly up in columns, forcing the rock above it up and away. The Ekofisk oil field is due to such a column of salt.
Illustration: Salt deposits
Hydrocarbon reservoirs
A hydrocarbon reservoir has the following properties:

Porous rock where fluids can be contained in the pore spaces. This is usually sandstone or chalk, but buried coral reefs are also a possibility.
A layer of cap rock above the porous rock. This must be a rock that is not permeable to oil and gas, if hydrocarbons can flow through it they will flow upwards because they are lighter than the water usually filling the pore spaces, thereby disappearing from the porous rock. The cap rock is usually shale, but salt is also a possibility.
The layer of cap rock must form a trap for the hydrocarbon fluids, there must be no upward path along the underside of the cap rock layer that makes it possible for hydrocarbons to flow up and around the cap rock. This will be the case if the cap rock layer is shaped like an inverted bowl, but other geological structures may also form traps, for instance faults.
Hydrocarbons must be present.
Hydrocarbons are mainly due to organic material buried in clay, often at shallow sea bottoms where rivers carries clay out into the sea. Dead plants and animals sinking to the bottom are buried by clay before they decay or are eaten. If this clay is buried deeper and deeper under newer sediments deposited on top, it turns into shale, where increasing pressure and temperature change the organic material to oil and gas, and a more solid residue that is left in the shale. When this takes place the total volume of the organic material products (oil, gas and residue) increases in volume. This might create cracks through the shale layer, making it possible for the hydrocarbon fluid to flow out of the shale and into reservoir rocks above or below the shale.
Interactivity: Oil traps in hydrocarbon reservoir
Shale producing hydrocarbon is called a source rock.
Interactivity: Shale producing hydrocarbon
Illustration: Shale producing hydrocarbon
In the North Sea there is basically only one of the several shale layers found there that is such a source rock. This is called the Kimmeridge shale layer. It is the source of almost all the oil and gas found in North Sea reservoirs. The main exception is the gas found in the Danish section. This gas comes from coal deposits below the salt layer deposited very early on, as described before. Coal can give off gas when heated sufficiently, but it will not produce oil.
Illustration: Shale producing hydrocarbon, Kimmeridge
The condition for deposits to form several kilometers of sediment is that the ground is sinking, deposits laid down at a shallow North Sea bottom are now found far below their original depth. This is a quite common process when deep layers of sediments are formed, such a region is called a basin, for instance the North Sea basin.
The observant reader might find it strange that oil and gas can flow downward in shale, while they will always flow upward in reservoir rock (if there is no upward path, they will stay in place). The reason for this will be discussed later on, but briefly explained it is due to a high overpressure in the pore spaces in shale. When cracks are opened this overpressure forces fluid to flow out of the shale in any direction along the cracks, also downward. In the

Statfjord field the oil is in a sandstone layer below the Kimmeridge shale. In this case the source rock is also the cap rock of the reservoir.
Illustration: Properties in a hydrocarbon reservoir
When hydrocarbons flow into the pore spaces of a reservoir rock they will displace the water already filling the pores. Rock usually prefers to be in contact with water, it is then called water-wet. A somewhat higher pressure of the hydrocarbon fluid than of the water is then necessary to displace the water. This pressure difference is called the capillary pressure. For oil and water it is defined as positive if the local pressure of oil is higher than the local pressure of water. This will be the case if the rock is water wet. In some cases the rock may become oil wet due to prolonged contact with oil. The capillary pressure is then negative.
For gas and any liquid (oil or water) the gas pressure will be largest, because gas is not wetting the rock. The capillary pressure is then defined as positive if the local pressure of gas is higher than the local pressure of liquid.
Illustration: Capillary pressure
For any given value of the capillary pressure a certain percentage of the pore spaces will be filled with hydrocarbons. This is called the hydrocarbon saturation, or oil or gas saturation if the fluid state is known. Generally the different fluids in the pore spaces are called phases, the usual possibilities are:
General value Irreducible value, see below
Water phase, saturation S
W
S
W R
Oil phase, saturation S
O
S
OR
(1)
Hydrocarbon gas phase, saturation S
G
S
GR
If no other fluids are present these phases fill all the available pore spaces: S
W

S
O

S
G

1 .
Illustration: A rock sample
These saturations may be local saturations, the saturations in a small sample of reservoir rock, or they may be average saturations over a larger part of the reservoir. In this connection a small rock sample must still be sufficiently large to contain a representative distribution of pore sizes, if not the local saturation values will be rather useless as a measure of the reservoir rock properties.
Illustration: Reservoir saturation
Illustration: A rock sample must contain a representative distribution of pore sizes
In a water wet reservoir the water will be mainly found in narrow pores and cracks where the contact surface with the rock is largest. As the oil pressure increases the water will be separated into these small regions with no connecting flow paths. The water left in the pore spaces is then no longer mobile and cannot escape however much the capillary pressure is increased. What is left of water is then called the residual water saturation, or the irreducible water saturation S
W R
.
Illustration: The irreducible water saturation

If the process is reversed, that is, water is displacing oil from the pore spaces, the oil is forced away from the pore surfaces and finally broken up into separate drops and trapped in the larger pore spaces. These drops cannot escape as separate units through the pore system, they are too large to pass through the narrowest pores. The oil that is left is then immobile and cannot be reduced any more. This residual oil saturation is called the irreducible oil saturation S .
OR
Illustration: The irreducible oil saturation
If the rock is oil wet we have the reverse situation, oil is filling the smallest spaces, and water is finally broken up into drops that fill the largest spaces as oil flows into the rock from the source rock. When oil is produced from such a reservoir it flows until it breaks up into separate drops filling the smallest spaces.
In a corresponding way we have irreducible gas saturations S . The irreducible saturation
GR depends also upon the displacing fluid. If oil is displaced by water in a water wet reservoir, oil is the non-wetting phase, but if oil is displaced by gas, oil is the wetting phase. This might give quite different irreducible oil saturations in the same reservoir, depending on whether gas or water are displacing the oil.
Illustration: The irreducible gas saturation
Definition of some basic terms:
-
-
Reservoir rock
Reservoir
Hydrocarbon reservoir
Formation
Consolidation
Rock with connecting pores, usually sediments
Any region of reservoir rock
Reservoir rock where the pore spaces are more or less filled with hydrocarbons
Common name for all types of rocks in the ground
Process of cementing or fusing grains in sediments
-
Consolidated rock
Unconsolidated rock together, giving a proper rock, not just sand or clay.
Common name for all types of sedimentary rocks in the ground
No consolidation, that is, the “rock” is still sand, clay or chalk grains
Overburden Formation material stress in vertical direction due to total weight of all overlying materials
-
Fracture pressure
Pore pressure
Well pressure
Minimum horizontal stress in the formation
Fluid pressure in the pores in sedimentary rock
Fluid pressure in well
Well shut-in The well is closes at the top, no fluids are flowing.
Bottomhole well pressure Fluid pressure in bottom of well. Usually this means the well pressure at the reservoir depth
Bottomhole well flowing Bottomhole well pressure when well is producing pressure
Well-head pressure Pressure in well at the top (at the well-head)
Illustration: The properties of a hydrocarbon reservoir

Pressures in rocks and fluids
Pressure measurements
Fluid is a common term for both liquid and gas. In both cases the pressure in the fluid is isotropic, at any point it is always equal strong in all directions. Also, at the same level the pressure is the same at different locations. This is not the case in rocks; there the pressure can have different values in different directions, and at different locations at the same level. In solids, like rocks, the pressure is often called stress.
Illustration: Pressures in rock differ from pressures in fluids
The unit for stress is the same as for pressure in principle, that is, it is a pressure unit. Any difference is in the size of the unit, as when choosing to measure lengths with the unit “meter” instead of the unit “decimeter”.
Here we will mainly use the SI unit system, based upon the meter, kilogram, and second.
Illustration: Pascal is the basic unit in the SI system
This system makes calculations much simpler than the American unit system, based upon the inch (= 0.0254 m), the pound (=0.4546 kg), and the second. The basic unit for pressure in the
SI system is the Pascal (Pa), defined as one Newton per square meter (N/m
2
). This is, however, an inconveniently small unit, here we will use bar = 10 5 Pa, both for fluid pressure and for the stress unit in solids.
The bar unit was introduced because it is approximately equal to the atmospheric pressure, one standard atmospheric pressure, 760 mmHg = 1.013 bar = 14.7 psi.
Interactivity: The bar unit
The last unit is the American unit for pressure, one pound per square inch (psi), where 1 bar =
14.5 psi.
Interactivity: The American unit for pressure is psi
In Europe the pressure unit MegaPascal (MPa = 10
6
Pa = 10 bar) has gradually been used more, and will probably be the standard “big” pressure unit in the future. In Norway the unit for stress in materials has traditionally been Newtons per square millimeter, which actually is equal to MPa.
Interactivity: MegaPascal (Mpa)
Finally, it should be noted that in practice pressure is measured with respect to a reference pressure. This can be vacuum, in which case the measured pressure is called absolute pressure (unit: bara (psia)), or more often the present atmospheric pressure, in which case the measured pressure is called gage pressure (unit: barg (psig)). The pressure difference can also be measured, in which case the unit is always just bar (psi). If the present atmospheric pressure is P
A
, the following rules apply:

-
-
-
bar + barg = barg bar + bara = bara barg – barg = bar
bara – bara = bar
bara = barg + P
A barg = bara – P
A
Example: In tank A the absolute pressure is measured to
43 bara, in tank B gage pressure is 67 barg, the atmos- pheric pressure is 1.008 bara. In tank C the pressure is
12 bar lower than in tank B.
Gage pressure in A: 43 bara – 1.008 bara = 41.992 barg
Pressure difference: 67 barg – 41.992 barg = 25.008 bar
Pressure in C: 67 barg – 12 bar = 55 barg
As pressure transducers measuring pressure against the atmospheric pressure are cheaper and more robust, they are preferred by the industry. The problem is, however, that the atmospheric pressure changes all the time. In the oil industry large pressures are often measured. For pressures considerably larger than 1 barg, or down to 1 barg if accuracy of pressure measurements is less than 1%, the atmospheric pressure can usually be set constant and equal to 1 bara.
Illustration: Pressure transducers
For pressure measurements downhole, down in the well, the atmospheric pressure is not readily available. Pressure transducers then uses as reference a chamber with a known gas pressure, or vacuum (absolute pressure). For some pressure transducers, for instance quarts crystals, no pressure reference is needed, but an insulated housing with temperature regulation
(constant temperature) is preferable.
Illustration: Atmospheric pressure is not available down in the well
Stresses in the formation
At any point in the formation the vertical stress
 v
is due to the weight of all the overlying material, including fluids in the pores, and also sea water at top in an offshore field.
Illustration: The vertical stress
This stress is always compressive and is also called the overburden P
O
. It can be calculated by:
P
O
  v
 
W h
W
 
F h (2) where:
 is the density of sea water,
W

W

1028 kg/m
3
can be used.

F is the average density of the formation including pore fluids,

F
is approximately equal to 2500 kg/m 3 , depending upon type of sediment, porosity, and type of pore fluid. h
W is sea water depth, this is zero on land. h is the depth to the point where the overburden is calculated, measured from the sea bottom.
Illustration: The vertical stress, the equation
For more accurate calculations the average density and thickness of each overlying layer of rock can be used to obtain the last term in the above equation. Note that the weight of air (the

atmospheric pressure) is not included. The proper unit in the above equation is therefore barg
(psig).
Due to elastic properties of the rock the vertical stress

will induce a horizontal stress v
 h in the formation.
Illustration: A horisontal stress in the formation
In addition there can be horizontal stresses induced by geological processes, as when tectonic plates are pushed against each other. As these processes seldom are symmetric they usually result in a variation of the horizontal stress with direction. The directions of minimum and maximum horizontal stress will then be perpendicular to each other. In most cases even the maximum horizontal stress will be smaller than the vertical stress, but exceptions are found.
In almost all cases all stresses in the formation will be compressive, compressive stress is therefore usually defined as positive for rock stress.
When drilling, the removal of rock in the well also removes the support of the hole sides and they will be pushed slightly inward, there is now no rock inside the hole to counteract the stress in the rock around the hole.
Illustration: Drilling removes the rock supporting the hole sides
This usually increases the tangential stress at the hole wall, except when the maximum stress is several times larger than the minimum stress. At the hole wall the tangential stress that is in the same direction as the original minimum stress may then even become negative, and the wall fractures.
Illustration: Large fluid pressure in the well
Illustration: Fracturing the formation
Perpendicular to these possible fractures the tangential stress may be so large that layers of rock are falling off, this process is called spalling. For smaller differences between maximum and minimum horizontal stress the only effect can be to make the hole slightly oval. This shape of the hole cross section, and eventually any fracturing and spalling, can be detected by logging the hole cross section. This gives important information about the horizontal stresses.
Fracture pressure P
F
If the fluid pressure in the well is sufficiently large, it will overcome the natural compressive stress in the rock, thereby opening up a fracture at the well. If the well pressure is larger than the minimum stress in the formation, this fracture can grow or propagate. The minimum stress is usually the minimum horizontal stress. The fracture will then be perpendicular to this stress direction, that is, the fracture is vertical and running out from the well in the direction of the maximum horizontal stress since this is perpendicular to the minimum stress. During drilling the well is regularly fractured by closing off the well at the top and pumping mud into it until it fractures, at least each time a casing is set. The well pressure when it fractures is registered, and in this way the fracture pressure in the well is mapped as a function of depth.

Illustration: Pore pressure is the fluid pressure in the pore space
Fracturing of the formation is to be avoided when drilling, because drilling mud will then be lost into the fracture, and whatever is left of it in the well may not have the flow rate needed to carry cuttings when it returns to the surface. In production, however, fracturing of the hydrocarbon reservoir can be used to advantage if the fracture can be kept open during production. Note that close to a producing well the pore pressure is always lower than the original, reservoir pressure. Any fracture opened by increasing the well pressure above the natural pore pressure will then close again. Some wells are naturally fractured, at the original reservoir pore pressure, but we do not need to fracture these.
To keep an induced fracture open during production mainly two methods are in use. In chalk or in rocks with streaks of chalk acid can be used to fracture the formation. The acid dissolves mainly chalk at the fracture walls, and often irregularly due to irregular chalk composition, leaving open channels when the fracture closes. In sandstone (and uniform chalk) hard particles are added to the fracture fluid, usually brine designed not to react with the pore fluid water. These particles, called proppants, are carried by the fracturing fluid and pumped into the fracture. When the fracture closes the proppants keep it from closing completely, leaving flow paths between these particles and the fracture walls.
Illustration: Two methods to keep an induces fracture open
Stresses and pressures in the formation are discussed at length in a special course in formation mechanics.
Pore pressure P
P
The fluid pressure in the pore spaces is called the pore pressure. At any given position in a hydrocarbon reservoir this pressure usually has different values for oil, gas and water. These pressure differences are the capillary pressures at the given position. At any depth the pore pressure is in most cases determined by the pressure of a water column from the sea surface and down to this depth, where the water salinity has the same distribution with respect to depth as the pore water in the formation. The reason is that any reasonably large reservoir is connected to the surface by permeable pathways, keeping the fluid pressure at this pressure equilibrium. For a reservoir filled with water the expected pore pressure P
P
at a depth h below the sea floor is therefore given by:
P
P
  w gh w
 
P gh where
 w is density of sea water (3)

P is average density of formation water h w is depth of sea water
The few exceptions are reservoirs completely surrounded by impermeable cap rock, these are sealed off and can have any pressure, depending upon geological history. Such a reservoir, sealed off at a certain depth, will to some extent keep the normal pore pressure at this depth, even if geological processes brings it closer to the surface, it will then have an abnormal high pore pressure. This can be very dangerous, especially if it is a gas reservoir. Fortunately, the bigger a reservoir is, the less is the probability that it is sealed off.
Illustration: Reservoirs surrounded by impermeable cap rock

Even though a reservoir is connected to the surface, the flow resistance in this connection may be very large. The time needed to reach pressure equilibrium might be thousands, even millions of years. Still, in geological time equilibrium is reached. When the reservoir is produced, however, the pressure falls dramatically through the few years or tens of years it is produced. The natural flow of water into the reservoir due to the pressure decrease there is in most cases too slow to be of much help. Today more and more reservoirs are given artificial pressure support, treated water or gas is pumped down to keep up the reservoir pressure when oil is produced (gas reservoirs are usually not treated in this way).
Illustration: Reservoirs are given artificial pressure support
If no pressure support is given the reservoir is produced naturally, the processes forcing oil and gas to the surface are called natural drive mechanisms. The percentage oil recovered is in this case usually between 15 and 40, depending upon type or types of natural drives present.
With artificial pressure support up to 60 per cent of the oil present can be recovered, even more if special chemicals or gases are injected. This will be discussed briefly in the reservoir engineering course.
Shale is formed from deposited clay, where solid particles are much smaller than for sand, the pore openings are very small even if porosity can be several per cent. This gives an extremely small permeability, where water flow due to pressure differences may take hundreds of millions of years before pressure differences disappear. Shale is therefore considered to be an impermeable cap rock, even though it is a porous sedimentary rock.
Illustration: Shale is considered to be an impermeable cap rock
When the deposited clay is compressed and turned into shale as it is buried deeper, permeability is rapidly reduced to the point where pore water can no longer escape. As the shale is compacted and the pores reduced in size, the water in them is compressed also, increasing the pore pressure above the natural water pressure at the shale depth. This is regularly seen in shale layers, the pore pressure is considerably larger than in reservoir rock at the same depth (remember that in reservoir rock the water can flow in and out, as this rock is compressed the water flow out when pore spaces are reduced).
Illustration: The pore pressure in shale
When drilling it is important to know the pore and the fracture pressures in the formation.
The pressure P w
in the well is at any depth h below the sea bottom given by the density
 m
of the drilling mud:
P w
  m g ( h
P
 h ) (4) where h
P
is the distance from the sea bottom to the mud return treatment system, usually on the deck below the drill floor. If this pressure is above the fracture pressure the well is fractured, resulting in loss of mud. If it is below the pore pressure, pore fluid will flow into the well. This might lead to loss of pressure control, that is, as the mud in the annulus is mixed with less dense pore fluid the average density in the annulus goes down, and according to the equation above the well pressure decreases. This increases the inflow of pore fluid, which again reduces well pressure, and so on. This is called a kick. Inflow of formation

water is usually not a big problem, but if hydrocarbons flow into the annulus the density of fluid decreases dramatically as gas expands and oil gives off expanding gas as pressure decreases. This might rapidly give a blowout. To safeguard against this a stack of valves capable of closing the annulus around the drill string is mounted on top of the wellhead during drilling, this is called the BOP stack, or just the BOP.
Illustration: A BOP is a stack of valves preventing a blow-out
If shale is drilled the well pressure should be kept above the pore pressure in shale also.
Illustration: Well pressure in shale
There is no big risk of rapid inflow of pore fluid from the shale, but the high pore pressure in the shale may disintegrate the shale at the borehole wall, collapsing it into the well. The general rule holds true here also, well pressure should be somewhere between pore pressure and fracture pressure.
Illustration: Well pressure should be somewhere between pore pressure and fracture pressure
At the few places where oil and gas is trapped the pore pressure diverges from the value expected in reservoir rock filled with water. The reason for this is:
Oil and gas are always found below a cap rock with no flow paths towards higher reservoirs or the surface. If such a path existed, oil and gas would have escaped.
Except for completely closed off reservoirs there is always water below the hydrocarbons.
The water is in hydrostatic equilibrium, that is, it has the pore pressure excepted at the given depth, as given by equation (3).
At the water-hydrocarbon interface, at the lowest level h
WH
of hydrocarbons, the pore pressure is also given by equation (3): P
PW H
  w gh w
 
P gh
W H
Above the interface the pressure decreases slower with increasing height above the interface than in water, because hydrocarbon fluids are less dense than water. The pore pressure at the top of the reservoir will then be larger than expected from equation (3).
Illustration: Divergent pore pressure
As an example we assume an oil reservoir with a gas cap, that is, there is gas above the oil.
The following data are found:
Density of water in the sea:
Average density of water in the formation:
Density of oil in the reservoir:
Density of gas in the reservoir:
Depth of sea above the reservoir:
 w
= 1030 kg/m
3

= 1050 kg/m
3
 o
P
= 700 kg/m
 g
= 160 kg/m
3
3 h w
= 80 m
Depth of water-oil contact:
Thickness of oil:
Thickness of gas, at top of reservoir: h
WH
= 2000 m h o
= 100 m h g
= 150 m
Here the oil-gas contact is 100 m above the water-oil contact, at a depth of h
OG
= h
WH
- h o
=
1900 m, while the top of the reservoir is at a depth of h
RT
= h
OG
– h g
= 1750 m. This gives:

Pore pressure at water-oil contact:
P
PW H
  w gh w
 
P gh
W H

( 1030

9 .
81

80

1050

9 .
81

2000 ) 10

5 
214 .
09 barg
Pore pressure at oil-gas contact, at a depth of 1900 m:
P
POG

P
PW H
  o gh o

214 .
09

700

9 .
81

100

10

5 
207 .
23 barg
Expected pore pressure at a depth of 1900 m in a water reservoir:
P
PW 1900

P
PW H
 
P gh o

214 .
09

1050

9 .
81

100

10

5 
203 .
79 barg
Expected pore pressure at a depth of 1900 m in a water reservoir from equation (3):
P
PW 1900
  w gh w
 
P gh
1900

( 1030

9 .
81

80

1050

9 .
81

1900 ) 10

5 
203 .
79 barg
Pore pressure at top of reservoir, at a depth of 1750 m:
P
PRT

P
POG
  g gh g

207 .
23

160

9 .
81

150

10

5 
204 .
88 barg
Expected pore pressure at a depth of 1750 m in a water reservoir from equation (3):
P
PW 1750
  w gh w
 
P gh
1750

( 1030

9 .
81

80

1050

9 .
81

1750 ) 10

5 
188 .
34 barg
Difference at reservoir top between actual pore pressure and expected pore pressure:

P
PRT

P
PRT

P
PW 1750

204 .
88

188 .
34 = 16.54 bar
Note that expected water pressure at the level of the oil-gas interface is calculated in two ways, from water height above the water-oil interface, and directly from equation (3), both giving the same answer. As is seen from the calculations the pore pressure is higher than expected in a water reservoir when one drills into a hydrocarbon reservoir. This increased pressure is accordingly a good indication that a hydrocarbon reservoir has been found.
Drilling and production platforms
For offshore fields drilling and production equipment is usually mounted on platforms, but ships can also be adapted for this use.
Illustration: Offshore, drilling and production equipment
There are basically two types of platforms:
Movable platforms, these can be moved around like a ship, having their own engines and propellers. When in use for drilling or production they have to be kept above the well. This can be done by anchoring the platform to the sea floor, and in addition they often have a dynamic position system based upon satellite navigation. If they move off their position the platform drive system is used to push them back. A special type called a “jack-up” has legs that can be pushed down to the sea floor and lift the platform up so it temporarily becomes a fixed platform. This type can only be used in shallow seas. All moveable platforms and ships have the wellhead on the sea floor, together with the well control equipment, either a BOP when drilling, or a control valve manifold called the Christmas tree when producing. The wellhead is connected to the platform with a riser that can be disconnected at the well head if the platform drifts off due to possible lack of position control in bad weather.
Illustration: Moveable platforms
Illustration: All moveable platforms and ships have the wellhead on the sea floor

Fixed platforms, these stands permanently on the sea floor. They are built at a shipyard and towed out to their desired position where they are lowered down to the sea floor. Fixed platforms have well heads on the platform, with all the well control equipment, and there is no need for a riser.
Illustration: Fixed platforms
Drilling and production ships are obviously always movable and are kept in position in the same way as movable platforms. The main technical advantage with ships is their larger speed, thus reducing the time spent in moving around. The main disadvantage is that they are more sensitive to wave movements than platforms. For a floating platform the main carrying capacity is due to air tanks some distance below the sea surface, where wave movements are considerably reduced.
The equipment on the platforms differs according to their use. Drilling platforms are equipped with a drilling rig (derrick), a mud pumping and treating system, and other equipment necessary for drilling. In addition they have a small production system because any well found to be producing hydrocarbons is tested by producing it for a short period. The main part of this system is a gas-oil separator. The produced oil is stored and the gas is vented to the atmosphere and burned. A drilling ship is equipped in the same way. All drilling platforms are movable; when they have finished drilling a well they are moved to the next well location.
Illustration: Drilling platforms equipment
A production platform has a more advanced production system, often with three or four production separators plus a test separator. In addition there are systems for purifying oil and produced water, and quite a big system for drying produced gas, including gas compressors.
Earlier on produced gas could be vented to the atmosphere and burned, but there is severe restrictions on that now.
Illustration: Fixed platforms stay permanently on the sea floor
Production platforms may have equipment for drilling wells, thus being able to drill their own production wells. But these might also be drilled by a drilling platform, saving the investment in drilling equipment on the production platform. In the North Sea virtually all production platforms are fixed platforms, the wellheads are then situated on the platform. The advantages of this are a more stable structure, no problem in keeping the platform over the wells, and ability to produce continuously even in bad weather.
Illustration: Drilling and production ships are kept in position
Production platforms may be moveable, the main problems with that is movement with the waves and problems in keeping position in bad weather. This might require production shut off and expenses due to lost production and possible problems in starting the wells producing again. Also, in extreme weather the platform may drift away and the connection to the well broken. The safety precautions due to this possibility, with the well head on the sea bottom and a riser to the platform is more expensive than for a fixed platform where the wellhead and connected equipment is on the platform, and where a riser is not required. These problems apply to production ships also. The advantage is mainly that it is possible to produce small

fields where production lasts a relatively short time compared to the lifetime of the producing facilities. The platform or ship can then be used to produce several small fields that could not support the expenses of a fixed platform for each field.
Illustration: Production platform equipment
Illustration: Electricity is the main source of energy
All platforms and ships are equipped with diesel engines producing power for generation of electricity, which is the main source of energy for all sorts of machinery used and, and for lighting and heating. The only exception is for some gas producing platforms, where compressors are used to give produced gas the feeding pressure for gas pipelines. These compressors, requiring a huge amount of energy, are often driven directly by gas turbines, using a small part of the produced gas as fuel.
All platforms and ships have living quarters for the crew, including bedrooms, living rooms and kitchen. The exception is found only on large oil and gas field where several platforms are in use. Only one of these may have living quarters, these might also be on a separate platform, which is safer.
Illustration: Living quarters
All moveable platforms and a major part of the fixed platforms are basically steel constructions. In the North Sea the large fixed platforms have a concrete support structure
(the legs of the platform), while the deck on top is a steel construction. As hydrocarbon fields in deeper water are considered for production special fixed platform constructions has been developed, or is under development. One of these is the tension leg platform, where the top structure is floating, but is pulled down some distance by steel rods anchored to the sea bottom. Movements due to waves are reasonably well compensated by increasing and decreasing tension in the rods induced by the now reduced platform movements.