Solution gas drive (dissolved – gas drive)
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.( gas is dissolved in the oil; as it expands it exerts a pressure which pushes the oil through the rock or sand; recovery is slow when this type of drive is encountered)
Fig. Dissolved gas drive reservoir
| DISSOLVED GAS DRIVE RESERVOIRS | |
| Characteristics | Trend |
| Reservoir pressure………………………….. | Declines rapidly and continuously |
| Surface gas-oil ratio ………………………... | First low, then rises to maximum and then drops |
| Water production……………………………. | None |
| Well behavior………………………………... | Requires pumping at early stage |
| Expected oil recovery………………………. | 5 to 30 % of original oil in place |
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. (gas has not only dissolved in the oil; a large amount of it has formed above the oil; as the gas expands, it pushes the oil through the rock or sand at a more rapid rate than when only dissolved gas is present.)
Fig. Gas cap drive reservoir
| GAS CAP DRIVE RESERVOIRS | |
| Characteristics | Trend |
| Reservoir pressure………………………….. | Falls slowly and continuously |
| Surface gas-oil ratio ………………………... | Rises continuously in up-structure wells |
| Water production……………………………. | Absent or negligible |
| Well behavior………………………………... | Long flowing life depending upon size of gas cap |
| Expected oil recovery………………………. | 20 to 40 % |
Aquifer drive (Water drive)
Below the hydrocarbons will be ground water, known as the aquifer. Water, as with all liquids, is compressible to a very small degree when under high pressure. As the hydrocarbons are depleted, the reduction in pressure on the groundwater, causes it to expand very slightly. Although this 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. (there is a large amount of water below the oil; pressure forces the water upward into the oil-bearing rock or sand and moves the oil ahead of it.)
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Fig. Water drive reservoir
| WATER DRIVE RESERVOIRS | |
| Characteristics | Trend |
| Reservoir pressure………………………….. | Remains high |
| Surface gas-oil ratio ………………………... | Remains low |
| Water production……………………………. | Starts early and increases to appreciable amounts |
| Well behavior………………………………... | Flow until water production gets excessive |
| Expected oil recovery………………………. | 35 to 75 % |
Comparisons of the three drive mechanisms show that water drive can be the most effective means of production. Oil recovery rates can reach 75% with a water drive. Under normal circumstances, several drive mechanisms assist in the production of any one reservoir ( Fig. ).
Fig. Combination drive reservoir
This is particularly important where one type of fluid drive declines but production is sustained by another type of drive with greater longevity. Fig. shows gas-oil ratio trends for various drive mechanisms as reservoir depletion occurs.
| Drive mechanisms | |
| bubble point (pressure) | температура давление насыщения (при которых газ начинает выделяться из раствора нефти) |
| combination drive | комбинированный режим |
| compaction drive | режим уплотнения пласта (упругий режим) |
| dissolved – gas (solution gas drive) | режим растворенного газа (естественный энергетический механизм, при котором энергия создается экспансией газа, который освобождается из раствора при падении давления в нефтяном пласте- коллекторе; этот газ вытесняет нефть, способствуя ее продвижению к скважине) |
| drive mechanism | механизм пластового режима |
| gas cap drive | режим газовой шапки (естественный механизм добычи нефти, при котором расширяющий газ, образующий газовую шапку, замещает нефть, находящуюся в той же формации, вытесняя ее к рабочим скважинам; такая экспансия газовой шапки происходит, когда давление в пласте падает в процессе выработки) |
| fluid injection | нагнетание (в пласт) жидкости |
| gas injection | нагнетание газа в залежь |
| hydrostatic pressure | гидростатическое давление |
| natural flow | естественный поток (фонтанирование) |
| pressure depletion | поведение пласта, эксплуатирующегося при режиме истощения |
| pressure energy | сила давления |
| pressure loss | потеря напора (потеря давления) |
| reservoir | пласт-коллектор; резервуар (нефтеносный\ газоносный пласт) |
| reservoir characteristics | параметры пласта |
| reservoir description | характеристика пласта |
| reservoir pressure | пластовое давление |
| reservoir simulation | пластовое моделирование |
| rock matrix | скелет породы |
| water drive (water reservoir) | водонапорный режим пласта |
| water injection | нагнетание (в пласт) воды |
A good virgin reservoir will be under sufficient pressure to initially push hydrocarbons to surface. However, as the fluids are produced, in a static situation, the pressure will fall off and production will quickly falter with it. However, the picture is not static and often the reservoir will respond to depletion in a way that will help to maintain the pressure for a short time. Failing this, artificial drive methods may be necessary.
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Artificial lift
Artificial lift involves the use of artificial means to increase the flow of liquids, such as crude oil or water, to the surface of a production well. Generally this is achieved by a mechanical device inside the well, such as a pump; decreasing the weight of the liquid/gas mixture via high pressure gas; or improving the lift efficiency of the well via velocity strings. Artificial lift is needed in wells when there is insufficient pressure in the reservoir to lift the liquid to the surface, but often used in naturally flowing wells (which don't technically need it) in order to increase the flow rate above what would flow naturally. The produced fluid can be oil and/or water, typically with some amount of gas included. The artificial lift provides additional energy to the system such that the fluids can be lifted to surface.
The most common method of artificial lift in oil wells is to use pumps. The most recognized type is the rod pump (also called a sucker rod pump, beam pump, or "Nodding Donkey") seen in land based oil fields world wide. The rod pump works by creating a reciprocating motion in a sucker-rod string that connects to the downhole pump assembly. The pump contains a plunger and valve assembly to convert the reciprocating motion to vertical fluid movement. This type of pump is used in low rate wells where 10's to 100's of barrels of liquid are produced per day. Other types of commonly used pumps are Electric Submersible Pump (ESP's), Progressing-Cavity pumps (PCP's), Jet Pumps, and Hydraulic Pumps. These pump systems must be installed in the well down hole. They also include a ground-level power-supplier device that can be mechanical (rod pumps and PCP's), electrical (ESP's), or even hydraulic (jet and hydraulic pumps). The alternative to adding in extra pressure - like pumps - is to reduce the weight of the fluid. This is the objective of gas lift, where high pressure gas is injected into the well at a very deep depth. By injecting the gas, the average density of the produced liquid/gas mixture decreases, and therefore the reservoir pressure is high enough to maintain flow.
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Why use Artificial Lift
Any liquid-producing reservoir will have a 'reservoir pressure': some level of energy or potential that will force fluid (liquid and/or gas) to areas of lower energy or potential. You can think of this much like the water pressure in your municipal water system. As soon as the pressure inside a production well is decreased below the reservoir pressure, the reservoir will act to fill the well back up, just like opening a valve on your water system. Depending on the depth of the reservoir (deeper results in higher pressure requirement) and the density of the fluid (heavier mixture results in higher requirement), the reservoir may or may not have enough potential to push the fluid to the surface. Most oil production reservoirs have sufficient potential to produce oil and gas - which are light - naturally in the early phases of production. Eventually, as water - which is heavier than oil and much heavier than gas - encroaches into production and reservoir pressure decreases as the reservoir depletes, all wells will stop flowing naturally. At some point, most oil production companies will implement an artificial lift plan to continue and/or to increase production. Most water production wells, by contrast, will need artificial lift from the very beginning of production because they do not benefit from the lighter density of oil and gas.
1. Sucker rod pumping – are the oldest and most widely used type of artificial lift for oil wells. In fact, approximately 85% of artificially lifted wells are produced by beam pumping equipment. About 79% of the oil wells make more than 10 barrels of oil per day and are classified as stripper wells. Sucker rod pumping systems should be considered for new, low volume stripper wells because operating personnel are usually familiar with thee mechanically simple systems and can operate them more efficiently. Sucker rod systems should also be considered for lifting moderate volumes from shallow depths and small volumes from intermediate depths. Most of the parts of the sucker rod pumping system are manufactured to meet existing standards, which have been established b API. The sucker rod string, parts of the pump and unanchored tubing are continuously subjected to fatigue. Therefore, the system must be more effectively protected against corrosion than any other lift system to insure long equipment life. The ability of sucker rod pumping systems to lift sand is limited. One of the disadvantages of a beam pumping system is that the polished rod stuffing box can leak.
Components
Every part of the pump is important for its correct operation. The most commonly used parts are described below:
· Barrel: The barrel is a large cylinder which can be from 10 to 36 feet long and a diameter from 1.25 to 3.75 inches. After using several materials for its construction, the API (American Petroleum Institute) standardized the use of 2 materials or compositions for this part which are carbon steel and brass, both with an inside coating of chrome. The advantage of brass against carbon steel, weather is a more soft material, is its 100% resistance to corrosion.
· Piston: This is a nickel-metal sprayed steel cylinder, that goes inside the barrel. Its main purpose is to create a sucking effect that lift the fluids beneath it and then, with the help of the valves, take that fluids above it and, progressively, out of the well. It achieves this with a reciprocal up and own movement.
· Valves: The valve has two components - the seat and the ball - which create a complete seal when closed. After trying several materials, the most commonly used seats are made of carbon nitride and the ball is often made of silicon nitride. In the past, balls of iron, ceramic and titanium were used. This last type of balls, made of titanium, are still being used but only where crude oil is extremely dense and/or the quantity of fluids is too much. The most common configuration of a rod pump, requires two valves, called the traveling valve and fixed or static valve.
· Piston Rod: It's a rod that connects the piston with the outside of the pump. Its main purpose is to transfer the engine produced by the "Nodding Donkey" above in a up/down reciprocal movement.
· Fitting: The rest of the parts of the pump is called fitting and is, basically, small pieces designed to keep everything hold together in the right place. Most of these parts, are designed to let the fluids pass uninterrupted.
· Filter: The job of the filter, as guessed, is to stop big parts of rock, rubber or any other garbage that might be loose in the well from going into the pump. There are several types of filters, being a common iron cylinder with enough holes in it to permit the entrance of the amount of fluid the pump needs the most commonly used.
| SUCKER ROD PUMPING SYSTEM COMPONENTS | |
| counterweight | противовес |
| crank pin bearing | |
| prime mover | |
| belt cover | |
| brake | тормоз |
| gear reducer | редуктор станка-качалка |
| pitman crank | шатун балансира |
| equalizer | стабилизатор (балансир) |
| walking beam | балансир |
| sampson post | стойка балансира |
| horsehead | головка балансира |
| wireline hanger(bridle) | приспособление для подвески насосных штанг |
| carrier bar | поддерживающее приспособление (несущий элемент) |
| polished rod | полированный шток |
| stuffing box | корпус сальника |
| tee | тройник (T-образная деталь) |
| casinghead | арматура установленная на устье скважины |
| casing strings | колонна обсадных труб |
| tubing string | насосно-компрессорная колонна |
| sucker rod | насосная штанга |
| rod pump | вставной штанговый насос |
Hydraulic Pumping Systems
Hydraulic pumping systems, such as Jet Pumps, transmit energy downhole by means of pressurized power fluid that flows in the wellbore tubular. This method of transmitting energy downhole is reasonably efficient. The two methods of converting the energy downhole is to have either a downhole hydraulic pump, which has a set of coupled reciprocating piston, one is powered by the injected fluid while the other pumps the wellbore fluid to surface. The jet pump works by taking the injected fluid and turning it into a high velocity jet that mixes with the wellbore fluid and helps lift it to surface.
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