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A petroleum reservoir or oil and gas reservoir is a subsurface pool of hydrocarbons contained in porous or fractured rock formations. Petroleum reservoirs are broadly classified as conventional and unconventional reservoirs. In case of conventional reservoirs, the naturally occurring hydrocarbons, such as crude oil or natural gas, are trapped by overlying rock formations with lower permeability. While in unconventional reservoirs the rocks have high porosity and low permeability which keeps the hydrocarbons trapped in place, therefore not requiring a cap rock. Reservoirs are found using hydrocarbon exploration methods.
- 1 Formation
- 2 Estimating reserves
- 3 Production
- 4 Drive mechanisms
- 5 See also
- 6 References
Crude oil is found in all oil reservoirs formed in the Earth's crust from the remains of once-living things. Evidence indicates that millions of years of heat and pressure changed the remains of microscopic plant and animal into oil and natural gas.
Roy Nurmi, an interpretation adviser for Schlumberger oil field services company, described the process as follows:
Plankton and algae, proteins and the life that's floating in the sea, as it dies, falls to the bottom, and these organisms are going to be the source of our oil and gas. When they're buried with the accumulating sediment and reach an adequate temperature, something above 50 to 70 °C they start to cook. This transformation, this change, changes them into the liquid hydrocarbons that move and migrate, will become our oil and gas reservoir.
In addition to the aquatic environment, which is usually a sea, but might also be a river, lake, coral reef or algal mat, the formation of an oil or gas reservoir also requires a sedimentary basin that passes through four steps:
- Deep burial under sand and mud.
- Pressure cooking.
- Hydrocarbon migration from the source to the reservoir rock.
- Trapping by impermeable rock.
Timing is also an important consideration; it is suggested that the Ohio River Valley could have had as much oil as the Middle East at one time, but that it escaped due to a lack of traps. The North Sea, on the other hand, endured millions of years of sea level changes that successfully resulted in the formation of more than 150 oilfields.
Although the process is generally the same, various environmental factors lead to the creation of a wide variety of reservoirs. Reservoirs exist anywhere from the land surface to 30,000 ft (9,000 m) below the surface and are a variety of shapes, sizes and ages. In recent years igneous reservoirs have become an important new field of oil exploration, especially in trachyte and basalt formations. These two types of reservoirs differ in oil content and physical properties like fracture connectivity, pore connectivity, and rock porosity.
A trap forms when the buoyancy forces driving the upward migration of hydrocarbons through a permeable rock cannot overcome the capillary forces of a sealing medium. The timing of trap formation relative to that of petroleum generation and migration is crucial to ensuring a reservoir can form.
Petroleum geologists broadly classify traps into three categories that are based on their geological characteristics: the structural trap, the stratigraphic trap and the far less common hydrodynamic trap. The trapping mechanisms for many petroleum reservoirs have characteristics from several categories and can be known as a combination trap.
Structural traps are formed as a result of changes in the structure of the subsurface due to processes such as folding and faulting, leading to the formation of domes, anticlines, and folds. Examples of this kind of trap are an anticline trap, a fault trap and a salt dome trap. (see salt dome)
They are more easily delineated and more prospective than their stratigraphic counterparts, with the majority of the world's petroleum reserves being found in structural traps.
Stratigraphic traps are formed as a result of lateral and vertical variations in the thickness, texture, porosity or lithology of the reservoir rock. Examples of this type of trap are an unconformity trap, a lens trap and a reef trap.
Seal/ cap rock
The seal is a fundamental part of the trap that prevents hydrocarbons from further upward migration.
A capillary seal is formed when the capillary pressure across the pore throats is greater than or equal to the buoyancy pressure of the migrating hydrocarbons. They do not allow fluids to migrate across them until their integrity is disrupted, causing them to leak. There are two types of capillary seal  whose classifications are based on the preferential mechanism of leaking: the hydraulic seal and the membrane seal.
The membrane seal will leak whenever the pressure differential across the seal exceeds the threshold displacement pressure, allowing fluids to migrate through the pore spaces in the seal. It will leak just enough to bring the pressure differential below that of the displacement pressure and will reseal.
The hydraulic seal occurs in rocks that have a significantly higher displacement pressure such that the pressure required for tension fracturing is actually lower than the pressure required for fluid displacement – for example, in evaporites or very tight shales. The rock will fracture when the pore pressure is greater than both its minimum stress and its tensile strength then reseal when the pressure reduces and the fractures close.
After the discovery of a reservoir, a petroleum engineer will seek to build a better picture of the accumulation. In a simple textbook example of a uniform reservoir, the first stage is to conduct a seismic survey to determine the possible size of the trap. Appraisal wells can be used to determine the location of oil-water contact and with it, the height of the oil bearing sands. Often coupled with seismic data, it is possible to estimate the volume of oil bearing reservoir.
The next step is to use information from appraisal wells to estimate the porosity of the rock. The porosity, or the percentage of the total volume that contains fluids rather than solid rock, is 20-35% or less. It can give information on the actual capacity. Laboratory testing can determine the characteristics of the reservoir fluids, particularly the expansion factor of the oil, or how much the oil expands when brought from high pressure, high temperature of the reservoir to "stock tank" at the surface.
With such information, it is possible to estimate how many "stock tank" barrels of oil are located in the reservoir. Such oil is called the stock tank oil initially in place (STOIIP). As a result of studying factors such as the permeability of the rock (how easily fluids can flow through the rock) and possible drive mechanisms, it is possible to estimate the recovery factor, or what proportion of oil in place can be reasonably expected to be produced. The recovery factor is commonly 30-35%, giving a value for the recoverable reserves.
The difficulty is that reservoirs are not uniform. They have variable porosities and permeabilities and may be compartmentalised, with fractures and faults breaking them up and complicating fluid flow. For this reason, computer modeling of economically viable reservoirs is often carried out. Geologists, geophysicists and reservoir engineers work together to build a model which allows simulation of the flow of fluids in the reservoir, leading to an improved estimate of reserves.
To obtain the contents of the oil reservoir, it is usually necessary to drill into the Earth's crust, although surface oil seeps exist in some parts of the world, such as the La Brea tar pits in California, and numerous seeps in Trinidad.
A virgin reservoir may be under sufficient pressure to push hydrocarbons to surface. As the fluids are produced, the pressure will often decline, and production will falter. The reservoir may respond to the withdrawal of fluid in a way that tends to maintain the pressure. Artificial drive methods may be necessary.
This mechanism (also known as depletion drive) depends on the associated gas of the oil. The virgin reservoir may be entirely liquid, but will be expected to have gaseous hydrocarbons in solution due to the pressure. As the reservoir depletes, the pressure falls below the bubble point, and the gas comes out of solution to form a gas cap at the top. This gas cap pushes down on the liquid helping to maintain pressure.
This occurs when the natural gas is in a cap below the oil. When the well is drilled the lowered pressure above means that the oil expands. As the pressure is reduced it reaches bubble point and subsequently the gas bubbles drive the oil to the surface. The bubbles then reach critical saturation and flow together as a single gas phase. Beyond this point and below this pressure the gas phase flows out more rapidly than the oil because of its lowered viscosity. More free gas is produced and eventually the energy source is depleted. In some cases depending on the geology the gas may migrate to the top of the oil and form a secondary gas cap.
Some energy may be supplied by water, gas in water, or compressed rock. These are usually minor contributions with respect to hydrocarbon expansion.
By properly managing the production rates, greater benefits can be had from solution-gas drives. Secondary recovery involves the injection of gas or water to maintain reservoir pressure. The gas/oil ratio and the oil production rate are stable until the reservoir pressure drops below the bubble point when critical gas saturation is reached. When the gas is exhausted, the gas/oil ratio and the oil rate drops, the reservoir pressure has been reduced and the reservoir energy exhausted.
Gas cap drive
In reservoirs already having a gas cap (the virgin pressure is already below bubble point), the gas cap expands with the depletion of the reservoir, pushing down on the liquid sections applying extra pressure.
This is present in the reservoir if there is more gas than can be dissolved in the reservoir. The gas will often migrate to the crest of the structure. It is compressed on top of the oil reserve, as the oil is produced the cap helps to push the oil out. Over time the gas cap moves down and infiltrates the oil and eventually the well will begin to produce more and more gas until it produces only gas. It is best to manage the gas cap effectively; that is, placing the oil wells such that the gas cap will not reach them until the maximum amount of oil is produced. Also a high production rate may cause the gas to migrate downward into the production interval. In this case over time the reservoir pressure depletion is not as steep as in the case of solution based gas drive. In this case the oil rate will not decline as steeply but will depend also on the placement of the well with respect to the gas cap.
As with other drive mechanisms, water or gas injection can be used to maintain reservoir pressure. When a gas cap is coupled with water influx the recovery mechanism can be highly efficient.
Aquifer (water) drive
Water (usually salty) may be present below the hydrocarbons. Water, as with all liquids, is compressible to a small degree. As the hydrocarbons are depleted, the reduction in pressure in the reservoir allows the water to expand slightly. Although this unit expansion is minute, if the aquifer is large enough this will translate into a large increase in volume, which will push up on the hydrocarbons, maintaining pressure.
With a water-drive reservoir the decline in reservoir pressure is very slight; in some cases the reservoir pressure may remain unchanged. The gas/oil ratio also remains stable. The oil rate will remain fairly stable until the water reaches the well. In time, the water cut will increase and the well will be watered out.
The water may be present in an aquifer (but rarely one replenished with surface water). This water gradually replaces the volume of oil and gas that is produced out of the well, given that the production rate is equivalent to the aquifer activity. That is, the aquifer is being replenished from some natural water influx. If the water begins to be produced along with the oil, the recovery rate may become uneconomical owing to the higher lifting and water disposal costs.
Water and gas injection
If the natural drives are insufficient, as they very often are, then the pressure can be artificially maintained by injecting water into the aquifer or gas into the gas cap.
The force of gravity will cause the oil to move downward of the gas and upward of the water. If vertical permeability exists then recovery rates may be even better.
Gas and gas condensate reservoirs
These occur if the reservoir conditions allow the hydrocarbons to exist as a gas. Retrieval is a matter of gas expansion. Recovery from a closed reservoir (i.e., no water drive) is very good, especially if bottom hole pressure is reduced to a minimum (usually done with compressors at the well head). Any produced liquids are light coloured to colourless, with a gravity higher than 45 API. Gas cycling is the process where dry gas is injected and produced along with condensed liquid.
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- Zongli, Liu; Zhuwen, Wang; Dapeng, Zhou; Shuqin, Zhao; Min, Xiang (2017-05-31). "Pore Distribution Characteristics of the Igneous Reservoirs in the Eastern Sag of the Liaohe Depression". Open Geosciences. 9 (1): 161–173. doi:10.1515/geo-2017-0014. ISSN 2391-5447.
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- Structural traps
- Schlumberger - Search Results
- The Oil Trap
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- Watts, N.L., 1987, Theoretical aspects of cap-rock and fault seals for single- and two-phase hydrocarbon columns, Marine and Petroleum Geology, 4, 274-307.
- Peter J. Ortoleva (1994). "Basin compartments and seals". AAPG Memoir. AAPG. 61: 34. Retrieved 15 March 2012.
- Waterdrive at Schlumberger Oilfield Glossary