Finding and Producing Oil and Gas Is Usually Considered to Consist of the Following Phases

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 valueIrreducible value, see below

-Water phase, saturation

-Oil phase, saturation(1)

-Hydrocarbon gas phase, saturation

If no other fluids are present these phases fill all the available pore spaces: .

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 .

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 .

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 . The irreducible saturation 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 rockRock with connecting pores, usually sediments

-ReservoirAny region of reservoir rock

-Hydrocarbon reservoirReservoir rock where the pore spaces are more or less

filled with hydrocarbons

-FormationCommon name for all types of rocks in the ground

-ConsolidationProcess of cementing or fusing grains in sediments

together, giving a proper rock, not just sand or clay.

-Consolidated rockCommon name for all types of sedimentary rocks in the

ground

-Unconsolidated rockNo consolidation, that is, the “rock” is still sand, clay or

chalk grains

-OverburdenFormation material stress in vertical direction due to total

weight of all overlying materials

-Fracture pressureMinimum horizontal stress in the formation

-Pore pressureFluid pressure in the pores in sedimentary rock

-Well pressureFluid pressure in well

-Well shut-inThe well is closes at the top, no fluids are flowing.

-Bottomhole well pressureFluid pressure in bottom of well. Usually this means the

well pressure at the reservoir depth

-Bottomhole well flowingBottomhole well pressure when well is producing

pressure

-Well-head pressurePressure 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.