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Hydrogen sulphide, million-1 ppm , not more 20 2. Mass fraction of methyl — and ethylmercaptan in sum, million-1 ppm , not more 40 Designation of oil according to GOST R The symbol of oil consists of four digits corresponding to symbols of class, type, group and type of oil given above.
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Yandex sets this cookie to store the date of the users first site session. Steam injection is commonly used for high viscous oil. The main objective of the steam injection is to heat up and force the oil to the wellbore by the pressurized steam depicted in Figure 5. Generally, the EOR methods are costly because of the required external energy resources and materials.
Consequently, the volume of heavy oil to be extracted from a reservoir rock is a function of economics [ 10 ]. As a result of this, engineers must start to study in more details the reservoir rock permeability, pore media, and oil viscosity, together with the reservoir heterogeneity, where all these issues affect the success of any recovery technique.
Overall steam injection efficacy is the product of the sweeping capability and displacement competence. Illustrating the thermal flooding technique source: Steam EOR 1. Jpg [ 8 ]. The notion of the CSS is that the steam is injected into the reservoir via a production well for a period of time. Then the well is closed and permitted to soak by steam for some period of time before it returns to production.
CSS was applied in many heavy oil wells in the Middle East. Various cycles were done in these wells. However, the total amount of produced water for each cycle was considerably less than estimated. Steam-assisted gravity drainage SAGD comprises pairs of a high-angle injection wells with an adjacent production well drilled along a parallel trajectory depicted in Figure 6.
Normally, steam is injected via the upper well. Once the steam rises and spreads, it will heat up the heavy oil trapped in the porous media, decreasing its viscosity. Then assisted by the gravity forces, the oil will be drained into the lower well where it is produced [ 11 ]. Generally, the steam injection involves two core approaches, cyclic steam injection, and steam flooding.
Illustrating steam-assisted gravity drainage source: Markham Hislop [ 12 ]. The fundamental idea of the cyclic steam injection CSC is to inject hot steam through a single well for a period of time. A CSC method contains three phases see Figure 7. The first phase is injection, through which a slug of steam is injected into the reservoir.
The second phase requires that the well is shut for some days to permit equal heat spreading to thin the oil. Finally, throughout the third phase, the thinned oil is produced over the same well. The same cycle process is repeated many times as far as oil production is still profitable. Commonly, the cyclic steam injection process is used widely in heavy oil reservoirs and tar sands and also can be used to enhance injectivity prior to steam flood process and in combustion processes.
Steam injection is typically used in both horizontal and vertical wells producing high viscosity as high as , cP. Normally in CSC wells, oil can be both viscous and solid. Cyclic steaming processes. First, steam is injected at high pressure; second, the steam thins the viscous oil; and third, the oil is produced up to the surface source: Lyz Hoffman [ 13 ]. Continuous steam injection is a new method to manage heat flow in the reservoir and to decrease the temperature of the fluids at production wells in that way avoiding shut-in made by high temperature Figure 8.
The best injection plan with different pressure and fixed steam quality has shown to have the biggest oil recovery given the same quantity of energy injected under various reservoir sets. Steam is injected at high temperature and high pressure via an injector well. It has lower thermal efficacy than CSC and needs a larger surface area. This method needs one well for steam injection and another well for oil production [ 15 ].
Diagram shows steam flooding source: Alhakiki [ 16 ]. The combustion process, also referred as fire flooding, challenges the recovery of more heavy oil by a flare-up of a part of the oil in place by injecting either oxygen, air, or chemical or by electrical shock see Figure 9.
This decreases the heavy oil viscosity and heats the oil in place, and the oil is moved out by a combination of steam, hot water, and gas drive. This method appeared always to be very suitable, mainly when we need to recover bitumen from tar sand deposits. This temperature can be observed at the combustion front [ 17 , 18 , 19 , 20 , 21 , 22 , 23 ]. Typically, the combustion technique is applied to hydrocarbon reservoirs of low API gravity oil.
Forward combustion includes a drive of the burning front in a similar direction as the injected air; where the reverse combustion includes a drive of the burning front opposite to the direction of the injected air. Schematic of combustion processes source: Rob Kendall [ 23 ].
Many previous studies proved the diluent injection with ESP can be an efficient artificial lift method for heavy oil reservoirs. It consists of injecting a light hydrocarbon liquid to reduce the oil density and viscosity depicted in Figure This recovery method makes use of several kinds of diluents injected downhole to decrease heavy oil viscosity in the reservoir. Normally the diluents used such as kerosene, naphtha, and light oil or may be injected into the drain and blended with heavy oil.
The diluted fluid is then returned back to the surface by a downhole pump such as progressive cavity pumps PCP. There are many diluent injection operations that extracted heavy oil of 7. For instance, a case study for extra heavy oil is produced from the meter horizontal section through downhole ESP pumps. In the diluent fluid injected at the bottom of the slotted liner, the diluent fluid transfers gradually in the horizontal part of the drain through the influence of the pressure differential created by pump process.
The heavy oil gradually moves from the reservoir to the liner and reaches the pump intake section with decreased heavy oil viscosity that is suitable for the pump efficiency. The mixed pumped fluid viscosity can be simply attuned by the rate of diluent injected downhole through the injection line. Schematic of downhole diluent injection method source: Arnaud Hoffmann [ 25 ].
Well artificial lift plan is a strategic aspect in the production of heavy oils. Obviously, some types of artificial lift was required in order for the oil to flow and return the flow rate of the oil to their normal rates to maximize the ultimate oil recovery. The choice of which artificial lift technique is to be used is very significant for the long-term profitability of the oil field.
An inappropriate selection of artificial lift can decrease production and raise the operating cost significantly. After a decision has been taken, it can be hardly changed whether or not the technique selected was suitable for the existing conditions. The selection procedure of the lifting method to be used, which are confined to the operating life of surface and downhole equipment, maintenance, environmental concerns, and cost.
Therefore, there are several configurations of downhole oil pump systems including pumps and drivers as described below. Hydraulic pumping is one of the artificial lift methods used since the early s. Hydraulic pumping systems can be used at different oil well production conditions Figure This type of pump was installed at different setting depths ranging from to 20, ft. The pump has surface speed drive box ranging from 15 to hp.
A schematic of the downhole assembly piston pump source: Cholet H, [ 26 ]. The basic operating process of the pump is that the power fluid is pumped from the surface facilities to activate the downhole piston together with a reciprocating piston pump refer to Figure The power fluid acts on a piston like a steam engine, and the power fluid could be oil or water.
The power fluid transfers to the piston and returns back to surface over another pipe if a closed loop power fluid is used. In the open power fluid design, the power fluid is combined with the production once flowing to the surface. To control the corrosion, chemicals can be injected downhole along with the power fluid.
The advantage of using this pump is the power fluid which can be heated for handling heavy oil. The pump is appropriate for deviated wells which might be difficult for other artificial lift methods. The pump surface facilities have a small footprint and can be assembled into one main battery to service many wells. Commonly, hydraulic pumps are applied primarily in very deep oil wells that are producing at great volumes which cannot be handled by using beam pump systems. Diagram of hydraulic pumping surface facility system source: SPE [ 27 ].
Generally, it can be used in low API oil gravity wells and in wells with high paraffin contents. Also used in the wells that failed to use any other artificial lift techniques or, because of well conditions. Hydraulic pumping systems are quite expensive, but they may have a good application where other artificial lift techniques may not be possible. A piston pump includes a motor at one end and a plunger pump at the other end Figure Hydraulic fluid is forced down the completion string at very high pressure and goes in a reciprocating motor.
The motor mechanism is piston-like pump which is forces the produced hydrocarbons to the surface throughout the casing annulus. Normally, the hydraulic fluid is used as a power fluid. Once both hydraulic fluid and produced fluids reach the surface, the hydraulic fluid is separated and reused again as the power fluid. Hydraulic piston pumps source: Conoco Inc. Jet pumps have been applied in the oil industry for more than 75 years. A jet pump is one of artificial lift methods, and it can be applied when depth and deviation of producing wells increase and reservoir pressure depleted Figure This pump can considerably reduce the risk of equipment failure in the wellbores because it has no moving parts.
The pump is set downhole and pulled up the well for retrieval by using pressurized fluid. Typical jet pump system source: Cholet H, [ 26 ]. Normally, this process is using a pump at the surface to generate high-pressure power fluid to be transmitted downhole via tubing or through an annular casing. The power fluid moves into the pump and goes via a nozzle, where almost the whole pressure of the power fluid is transformed into a velocity head if no loss happens.
Both production fluid and power fluid returned back to the surface over the production pipes. A jet pump is very suitable in specific conditions, for instance, when high production rates are preferred. The pump is suitable for handling viscous, corrosive, and heavy crude oils. Besides, locations where beam pumping units cannot be installed, such as inhabited regions, offshore oil fields, and gas lift, are not accessible. The pump is attractive in horizontal, deviated, deep, and high-temperature wells.
Also, it has excellent solid-handling capabilities and has long operational life average of 4 years. Moreover, it has tolerance for gas and solids production, and it has low installation and workover costs. Beam pump is an artificial lift pumping system applying power source at a surface to transmit the energy to a downhole pump assembly.
Producing heavy oil from shallow reservoirs using beam pump systems needs accurate design mainly for downhole assembly to get maximum production performance and maximize the run life. A beam and crank assembly creates reciprocating motion in a sucker rod string that attaches to the downhole pump assembly. The pump comprises a plunger and valve assembly to transform the reciprocating motion to vertical fluid movement.
Figure 15 shows typical beam pumps. Typical beam pumps source Conoco, [ 29 ]. The hollow sucker rod electric heating device can be divided into a pumping unit device, subsurface pump and screw pump hollow sucker rod device.
Tables 1 — 3 show the sucker rod electric technical data. PCP was developed in Currently, this pump is used to produce heavy oil in any kind of wells: vertical, deviated, or horizontal. A PCP is essentially made of two helical gears, one inside the other Figure Table 4 displays the lift selection guidelines.
The suitable use of each lift type is reliant to the type of the reservoir fluid, reservoir pressure, and production rate as estimated by inflow and outflow system. Progressive cavity pump source: John Martinez [ 28 ]. Lift selection guidelines John Martinez [ 28 ]. The external gear or stator has a double helical shape, one more than the internal single helical gear rotor. When the rotor is rotating, the fluid transfers together with the pump axis inside the cavities present between the rotor and stator.
The flow rate is a function of many parameters, for example, pumps eccentricity, rotor diameter, length of the stator pitch, and rotation speed. Manufacturers can provide a catalog of pumps with a wide range of well conditions as a function of reservoir fluid types, flow rates, pressure heads, and for any type of fluid viscosity. PCP is normally driven at the surface, but it can be driven by a downhole electrical submersible motor.
When PCPs are driven from the surface refer to Figure 17 , the stator is screwed at the tubing extremity, and the rotor is fixed to the drive string of sucker rods. On the surface, the drive head, absorbing the force of the sucker rods, is operated by an electric motor and a speed reducer. Most of the downhole assembly is driven in this way.
Typical progressing cavity pumping system source: SPE [ 27 ]. The PCP pumps can operate at high efficiency for high viscosity cruds, high sand, low productivity wells, and in horizontal and deviated wells. Besides, it has a small footprint on the surface. Besides, the pump has some disadvantages, where the pump has restricted production rate, lift depth, and temperature tolerance. In the case of horizontal and deviated well profile, where malfunction can cause tubing leaks made by wear or failure of the sucker rod drive shaft, the PCP is not allowed to pump dry, and the completion string must be pulled out of the well to change the pump.
An ESP is a centrifugal pump driven by a downhole electrical motor see Figure ESP surface facilities contain power system and transformers and connectors to the wellhead. Normally, ESP pumps are installed for high flow rates from to , bopd dependent on size and pressure gain and variable speed controllers.
These pumps are not suitable for very viscous untreated oil, but ESPs can be applied to lift oil production after injection of diluents fluids reduced the viscosity. The efficiency of the pump is very dependent on the design of the flow rate which must carefully be optimized based on the reservoir deliverability.
Moreover, the wellhead of the ESP system needs to have an electric cable entering. The downhole electrical submersible assembly contains an electrical power cable, motor, motor protector, and centrifugal pump. Typical electric submersible pump source: John Martinez [ 28 ]. Thermal recovery offers several limitations for ESP pumps because of the high temperature applied to the electric motor, electric parts, power cable, and pump assemblies.
Gas lift is a type of artificial lift techniques used to lower the producing bottom-hole pressure to achieve a higher oil production rate. The principle of gas lift method is that gas injected into the tubing string decreases the density of the fluids in the pipe and lets the two-phase mixture to flow up to the surface. There are two main kinds of gas lift techniques being applied today which are continuous and intermittent flow. Typically, natural gas is continuously injector under high pressure through tubing or through the annular between casing and production pipe into the pocket mandrels along the production tubing.
At high-temperature the multiphase flow will be produced at the surface refer to Figure Normally, gas compressor pressure and rate parameters are modified based on the gas lift constraint depicted in Figure Diagram of injection gas cycle for gas lifting well courtesy of Schlumberger. Diagram of a gas lift system courtesy of Schlumberger.
Gas lift is mainly appropriate for lifting fluids in wells that have a low amount of gas produced with the oil. Gas compressors are almost mounted to collect the produced gas and designed to be used for the gas lift system. The flexibility of gas lift, in terms of production rates and depth of lift, can seldom be matched by other methods of artificial lift if adequate injection gas pressure and volume are available. Gas lift is very suitable for highly deviated wells which produce sand and high gas-liquid ratios.
There is no other method that suitable for through-flowline ocean-floor completions as a gas lift system. Besides, wireline-retrievable gas lift valves can be replaced without killing a well or pulling the tubing. Individual well downhole tools are low-cost. The surface gas lift facilities for injection gas control are simple and need low maintenance and nearly no space for installation.
Usually, the reported high overall reliability and lower effective costs for a gas lift method are more to other techniques of lift. Pump monitoring is a crucial factor in prolonging the working life of all kinds of downhole pump systems. Advanced controller alarms can set parameters to reduce risk, extend pump working life and improve the total oil produced.
The pumping system needs more development to handle the operating cost, mainly for operation and maintenance either for single equipment or the whole system. Regularly, oil producers are just focused on the instant demands of the equipment, and they do not realize how the system parameters are affecting this equipment. A system method studies for both supply and demand sides of the system and how they can act together, shifting the attention from a single component to the total pumping system performance.
Normally, most types of pump failure are leakage, fouling, valve failure, and cracks in pipe chains. Assessing pumping system performance is required to solving such pump failure and finding enhancement opportunities. In endeavoring to find out solutions or search for techniques to develop pump performance, assessing only the components instead of the entire pumping system can cause analysts to manage potential cost savings.
For instance, although a pump may be functioning efficiently, it could be producing more flow than the system needs. Therefore, it is essential to evaluate system efficacy based on how the end uses are worked by the pumps. In the future, pumps need to be more reliable and proficient in functioning for a long time before requiring maintenance.
Pumps must be safer to work, use less space, use less power, less noise and temperature. Additionally, the need to improve corrosion resistance and as well as the reliability of working in the high-temperature environment. Consequently, pumps will be friendlier to the environment and running with less power to decrease their carbon footprint. As well, the use of more recycled materials with fewer consumables, in that way helping to decrease whole pumps costs.
Pumps are required to be easier to clean, overhaul, and reconstructed. Generally, there are several chances to increase the reliability, performance, and efficacy of pumping systems in the oil industry.
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