PTRT 1472: Petroleum Data Management II Chapter 8: Reservoir Mechanics - Reservoir drives
Types of Natural Gas Reservoir Fluids Natural gas is petroleum in a gaseous state, so it is always accompanied by liquid petroleum. There are four types of conventional natural gases: Non associated gas from gas wells (reservoirs with minimal oil) Associated gas - (sometimes called gas-cap gas) is free gas in contact with the crude oil gas dissolved in oil under natural conditions in oil reservoir Dissolved gas - the portion of the gas dissolved in the crude oil; associated or dissolved gas is found with crude oil Gas condensate - gas with high content of liquid hydrocarbon at reduced pressures and temperatures; although they occur as gases in underground reservoirs, they have a high content of hydrocarbon liquids. On production, they may yield considerable quantities of hydrocarbon liquids 2
Classification of Wells Wells in the same field can be classified as gas wells, condensate wells, and oil wells - Gas wells: producing gas-oil-ratio (GOR) > 100,000 scf/stb; - Condensate wells: 5,000 < producing GOR < 100,000 scf/stb; - Oil wells: producing GOR < 5,000 scf/stb Oil Oil Wells Well Condensate Well Gas Wells 5,000 100,000 Gas Gas well Gas well Condensate well Oil well Oil well
Types of Wells
Types of Reservoir Fluids The reservoir fluids are water, crude oil (volatile and black), and natural gas (dry, wet, condensate, and hydrate) Dry gas usually from non-associated gas wells (reservoirs with minimal oil). The gas remains as single phase both in reservoir and surface conditions irrespective of bottom hole temperature and pressure. See phase diagram Wet gas contains a larger fraction of C 2 C 6. The gas remains as single phase in reservoir conditions irrespective of bottom hole temperature and pressure, but the heavy fractions condense at the surface in the separator. Gas condensate the heavy fractions condense in the reservoir as the pressure is reduced. Gas hydrate a solid formed by the combination of water molecules and gas C 1 -C4; looks like compacted snow and can form blockages in pipelines. Volatile oil - liquid in reservoir with larger portion being lighter and intermediate components which vaporize easily at surface separation; at low reservoir pressure, gas (known as solution gas) is released which can migrate as secondary gas cap; primary gas cap is free gas Black oil contains a lower fraction of volatile components; it requires a significant amount of pressure drop to release gas 6
Drawdown Pressure Reservoir pressure Well s reservoir pressure is key to well s natural flow capability. After a well has been completed, the initial pressure may be high, but as production depletes, the pressure reduces. It gets to a point where the natural pressure is not enough to produce; an artificial lift is then installed. A down hole pump might be installed while completing the well, whereby making it easier or unnecessary for work over job later.
Bottomhole Pressure The most basic formation test data are bottomhole static and bottomhole flowing pressure. - Static bottomhole pressure is the pressure at the producing formation when the well is shut in and pressure has built up to maximum level. - Bottomhole flowing pressure is the pressure at the producing formation face when the well is allowed to flow. - The ability of the well to produce its fluids depends on the difference between static shut-in and flowing bottomhole pressure, which production engineers call drawdown. Static Drawdown Buildup
Reservoir Description Reservoir Drives Oil production may initially flow to surface due to the pressure in the reservoir. Some oil pools do not have enough pressure to do this and need to be pumped. Depending on the reservoir drive mechanism, some wells that start flowing will later need to be pumped. Water may be produced with the oil. It is separated and disposed of by re-injection into a nearby unproductive reservoir layer. Oil can be recovered from the pore spaces of a reservoir rock, only to the extent that the volume originally occupied by the oil is invaded or occupied in some way. There are several ways in which oil can be displaced and produced from a reservoir, and these may be termed mechanisms or drives. Where one replacement mechanism is dominant, the reservoir may be said to be operating under a particular drive. Possible sources of replacement for produced fluids are: Expansion of unsaturated oil above the bubble point. Expansion of Rock and connate water. Expansion of gas released from solution in the oil below the bubble point. Invasion of the original oil bearing reservoir by the expansion of the gas from a free gas cap. Invasion of the original oil bearing reservoir by the expansion of the water from an adjacent or underlying aquifer.
Reservoir Drive Since all replacement processes are related to expansion mechanisms, a reduction in pressure in the original oil zone is essential. The pressure drops may be small if gas caps and aquifers are large and permeable, and, under favorable circumstances, pressure may stabilize at constant or declining reservoir off take rates. Pressure on fluids in a reservoir rock causes the fluids to flow through the pores into the well. The energy that produces the gas, oil, and water is called the reservoir drive or reservoir energy and comes from fluid expansion, rock expansion and/or gravity. The type of reservoir drive controls the production characteristics of the reservoir. There are five (three principal) types of reservoir drives: Gas cap expansion drive Solution-gas ( or dissolved-gas or depletion) drive Water drive Gravity drive Combination (or mixed) drive Frequently two or more mechanisms ( together with rock/ connate water expansion) occur simultaneously.
Reservoir Drive Producing oil and gas needs energy. Usually some of this required energy is supplied by nature. The hydrocarbon fluids are under pressure because of their depth. The gas and water in petroleum reservoirs under pressure are the two main sources that help move the oil to the well bore and sometimes up to the surface. Depending on the original characteristics of hydrocarbon reservoirs, the type of driving energy is different. Pressure on fluids in a reservoir rock causes the fluids to flow through the pores into the well. The energy that produces the gas, oil, and water is called the reservoir drive or reservoir energy and comes from fluid expansion, rock expansion and/or gravity. The type of reservoir drive controls the production characteristics of the reservoir. There are five (three principal) types of reservoir drives: Gas cap drive Solution-gas (or dissolved-gas or gas expansion or depletion) drive Water drive Gravity drive Combination (or mixed) drive Frequently two or more mechanisms ( together with rock/ connate water expansion) occur simultaneously.
Gas cap drive Partially or completely isolated from the pressure regime in the surrounding rock. Oil production causes the gas cap to expand and looses it energy. The temperature and pressure in the reservoir will drop and there will not be enough energy left to drive the oil out of the reservoir. Gas drive is not an efficient long-term production producer. The following can be done if there is no sufficient pressure left to drive out oil in other to increase the reservoir pressure: 1. Inject more gas 2. Ignite oil underground by injecting air 3. Install a down hole pump to pump oil to the surface 4. Inject gas into the well (gas lift) 5. Inject water and chemicals in some part of the reservoir All of the above method are called secondary recovery method.
Solution gas drive When a reservoir is below the bubble point pressure, there will be free gas as bubbles within the oil phase in reservoir. Gas dissolved in the oil (solution gas) expels oil into the well bore The reservoir pressure decreases as production goes on and this causes emerging and expansion of gas bubbles creating extra energy in the reservoir. These kinds of reservoirs are called as solution gas drive reservoirs. Crude oil under high pressure may contain large amounts of dissolved gas. When the reservoir pressure is reduced as fluids are withdrawn, gas comes out of the solution and displaces oil from the reservoir to the producing wells. The efficiency of solution gas drive depends on the amount of gas in solution, the rock and fluid properties and the geological structure of the reservoir. Recoveries are low, on the order of 10-15 % of the original oil in place (OOIP). Recovery is low, because the gas phase is more mobile than the oil phase in the reservoir. Water floods, carbon dioxide injection, and re-injection of produced gas or water can be used in nearly any reservoir to improve recovery efficiency.
Water drive Water drive is the result of water moving into the pore spaces originally occupied by oil, replacing the oil and displacing it to the producing wells. The water from the local water table pushes the oil to the oil well. Water is eventually produced as oil is driven out from the well and may cause what is known as water blocking in the well (Increase in the amount of water in the pore spaces blocks oil) Water drive before and after some production Recovery efficiencies of 70 to 80 % of the original oil in place (OOIP) are possible in some water drive reservoirs.
Gravity drive Gravity drainage may be a primary producing mechanism in thick reservoirs that have a good vertical communication or in steeply dipping reservoirs. 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. Gravity drainage is a slow process because gas must migrate up structure or to the top of the formation to fill the space formerly occupied by oil. Gas migration is fast relative to oil drainage so those oil rates are controlled by the rate of oil drainage. Recovery factor An aquifer drive mechanism usually maintains the reservoir pressure for some time but may drop off gradually.