книги / Методы и технологии добычи нефти и газа

1.4. Oil and Gas Lift to Surface

Fluid (oil) rises to the surface due to reservoir energy. Such energy manifests itself by reservoir pressure and bottomhole pressure. Three cases are possible:

1)reservoir energy is sufficient for oil travel (migration) to bottomholes of producing wells, and for fluid lift to the surface;

2)bottomhole pressure is sufficient for fluid lift to the surface, but such pressure slightly differ from reservoir pressure, so, in case of low productivity factors, oil influx is low. Under reservoir drive, oil influx can be increased by reducing bottomhole pressure, but, in such case, such pressure will be insufficient for fluid lift; and

3)reservoir pressure is lower than pressure required for fluid lift.

In the first case, producing wells are operated under natural flow production, which is the most efficient and requires the lowest costs.

In the second case, wells can be operated by natural flow production or by well pumps. Application of well pumps makes it possible to provide additional energy in well from the surface, reduce bottomhole pressure, increase underbalance and fluid influx, i.e. increase well flow rates. But application of pumps increases well operation costs, that is why well operation method – by natural flow or by pumps – should be selected based on technical and economic assessment.

In the third case, well operation without additional energy is impossible, and that is why well pumps or gas lift production (additional energy is provided in the form of compressed agent – gas) is applied.

Producing well operation by pumps (sucker rod, electric centrifugal, screw, diaphragm, jet, hydraulic piston and other pumps) or by gas lift is termed artificial lift well operation.

Gas wells are operated by natural flow production: due to much lower gas density against oil density, gas well wellhead pressure can be significantly lower than that of oil well.

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1.5. Wellhead Stream Gathering and Treatment in Field

Oil production process flow diagram is shown in fig. 1.

Fig. 1. Oil Production Process Flow Diagram:

1 – production wells; 2 – satellite (АГЗУ); 3 – separator (1st stage); 4 – booster pumping station (ДНС); 5 – gas compressor station (ГКС); 6 – gathering station (ПСП), separator (2nd stage); 7 – water knock-down unit (УПСВ); 8 – crude oil treatment plant (УППН); 9 – tank farm (ТП); 10 – water treatment plant (УВП); 11 – modular booster station (БКНС); 12 – water distribution point (ВРП); 13 – injection wells; 14 – fresh water source; 15 – water-intake unit with water treatment facilities and pumping station.

I – wellhead stream; II – associated gas; III – separated water; IV – commercial oil; V – fresh water.

Oil (oil with water) produced from well 1 should be metered, i.e. well oil flow rate and well fluid flow rate must be determined. It is also necessary to determine gasoil ratio of well – this is amount of associated gas produced from 1 t or 1m3 of oil. All measurements are made automatically in satellite. In the satellite (2), at this or that period of time, one well flow is measured, if no flow meter is installed on its flow lines, while flows from other wells come to the working line without flow measuring. After the satellite, the combined flow of the given group of wells goes to the 1st stage separator (3) for associated gas separation. Separator pressure is slightly lower than wellhead pressure, and usually it is 0.4…0.6 MPa. Separated gas flows through gas line to the gas compressor station (5), which pumps gas to gas main pipeline (МГ).

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From the 1st stage separators, oil (oil with water) is pumped by the booster pumping station (4) to the gathering station (6) through oil gathering main. At the gathering station, associated gas is once more separated from oil in the 2nd stage separators. If water cut is high, oil flows to the water knock-down unit (7), and then to the crude oil treatment plant (8). In the crude oil treatment plant, oil is dewatered and desalted by demulsifying (breaking water-oil emulsion in oil and water), and, if necessary, stabilized (removal of volatile light ends). From the crude oil treatment plant, oil flows to the tank farm (9), and then to the oil main pipeline (МН).

Produced water separated from oil in the water knock-down unit and crude oil treatment plant, is directed to the water treatment unit (10), in which mechanical impurities and trapped oil are removed from it. Then water is pumped to the modular booster station (11), and from it water is directed via pressure water lines to the water distribution (12) and injection wells (13).

If amount of produced water is insufficient for maintaining reservoir pressure, fresh water is supplied to the reservoir pressure maintenance system after treatment (purification).

Process flow diagram of gas field is shown in fig. 2 (option of gas gathering and treatment process flow diagram).

ГСП

от скважин

Fig. 2. Process Flow Diagram of Gas (Gas Condensate) Field:

ГСП – gas gathering station; ПГСП – field gas gathering station; ГС – intake facilities of gas main pipeline (МГ).

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Gas from wells flows through flow lines to the group (areal) gas gathering stations, in which gas flow rates are measured; mechanical impurities, moisture (water) and condensate are removed from gas in separators; and gas is treated with reagents to prevent moisturizing in the gas-collecting line (ГК). From these stations gas flows through the gas-collecting line to the field gas gathering station (ПГСП) combined with the intake facilities (ГС) on the gas main pipeline. In the field gas gathering station and intake facilities, gas is treated to meet the gas main pipeline transportation requirements: drying and removal of impurities (СО2, Н2S and other).

2. FLUID AND GAS INFLUX

2.1. Fluid Influx

In case of radial linear flow (fig. 3), fluid influx can be determined by Dupuis formula which is based on the linear filtration law (Darcy law):

where k is permeability factor of reservoir with homogeneous filtration characteristics; h is reservoir thickness; µ is dynamic (absolute) viscosity factor under reservoir conditions; rс is well radius and rк is radius of reservoir drainage area (radius of boundary); Рзаб is bottomhole pressure and Рпл is boundary pressure (drainage area boundary).

Analytical model of fluid influx is shown in fig. 3.

Pпл

Pзаб

rс

rк

Fig. 3. Fluid Influx (reservoir drainage pattern)

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Formula (2) describes the case if h, µ and k are constant (identical) within the drainage area with radius rк, fluid is homogeneous (oil) and there is no free gas phase. Formulas for determining pressure in the reservoir (radius r) boundary can be derived from formula (2):

or

If we plot P against f(r) by formula (4), we obtain a curve given in fig. 4. Such curve is termed a cone of influence.

According to fig. 4, total underbalance ∆Рпл=Рпл–Рзаб includes two components

Fig. 4. P = F(r) Relationship

Distribution of pressure in reservoir around operating well

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According to fig. 3, fluid filtration rate becomes higher as well is approached, which corresponds to the well-known flow rate formula:

where w is filtration rate; f is area of reservoir section transverse to fluid paths (lateral surface of cylinder in fig. 3) with variable radius r.

The closer to the borehole wall, the lower f (f = 2πrh) and the higher w (at q = const). Curve 1 in fig. 4 becomes steeper as well is approached. At radius of bottomhole formation zone rОЗП, which is much less than radius of boundary rк, ∆РОЗП1 > ∆РУЗП2 , due to w and hydraulic resistance increase near the bottomhole formation zone, the curve 1 conforms to condition КОЗП=КУЗП (permeability homogeneous reservoir).

It is known that drilling mud filtrate and rock cuttings, which come into the bottomhole formation zone during well drilling and productive reservoir drilling-in, cause reducing КОЗП (clogging and other). At КОЗП<КУЗП we obtain a curve 2 (fig. 4). Since hydraulic resistances in the bottomhole formation zone increase as КОЗП decreases, at

∆РУЗП2 .

By analogy with Ohm’s law in electrical engineering, the fluid influx can be determined by formula:

Where R is hydraulic resistance of formation:

in other words, hydraulic resistance is a total of hydraulic resistance in the bottomhole formation zone (ОЗП) and hydraulic resistance in the remote zone of formation. By combining (2) and (7), we can put it down as follows:

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The lower КОЗП, the higher RОЗП and R, and resistance RУЗП is invariable.

Thus, under КОЗП decrease relative to КУЗП, the fluid influx (well flow rate) becomes lower.

Under КОЗП increase relative to КУЗП, the curve P = f(r) takes the form 3 (fig. 4), ∆РУЗП3 > ∆РУЗП1 and fluid influx becomes higher.

2.2. Gas Influx

Dupuis formula for linear filtration in gas well can be put down as follows:

where Р0 is atmospheric pressure and Т0 is standard temperature; z0 is real gas factor at Р0 and Т0, and z is real gas factor at Рbh and Т; г is dynamic gas viscosity at Рbh and Т; Q is well flow rate at Р0 and Т0.

Gas well flow rates are thousandfold higher than oil well flow rates, so gas filtration rate in formation, especially in the bottomhole formation zone (ОЗП), is high. At that, inertial forces occur, and under their action gas filtration obeys nonlinear filtration law. Considering nonlinearity, the gas influx formula is as follows:

The second member in the right-hand part of the formula (13) considers the nonlinearity of filtration, i.e. a share of general underbalance used for overcoming inertial forces. Filtration resistance factors А and В are determined by processing data of

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well test under steady conditions. If we omit a summand BQ2 , i.e. consider the gas filtration as linear, we obtain by combining (12) and (13) at AQ >> BQ2

3. OIL WELL PRODUCTIVITY FACTOR

Fluid influx formula (2) can be put down as follows:

where КП is well productivity factor which is a proportionality factor between q and

∆РПЛ

(16) For determining well productivity factor (КП), it is necessary to test well under several (4–6) steady-state modes. For each steady-state mode, q and bottomhole pressure Рзаб (at certain formation pressure Рпл) are determined (measured), and then a graph, which is termed Inflow Performance Relationship (fig. 5), is plotted.

If fluid filtration in reservoir obeys linear filtration law, i.e. formula (2) is true, and all modes corresponding to points in fig. 5 are steady-state, in the coordinates q and ∆Рпл we obtain a straight line coming out at an angle from the origin of coordinates. For each point in the graph the ratio q/∆Pпл is constant magnitude, and according to (15) this ratio is well productivity factor (КП).

α

∆Pплк K

∆Pпл

Fig. 5. Oil Well Inflow Performance Relationship

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According to fig. 5, well productivity factor (КП) =const, as

When well productivity factor is determined by the inflow performance relationship, well flow rate at the certain formation pressure Рf and predetermined bottomhole pressure Рbh cane be determined by formula (16).

4. OIL WELL OPERATING PRACTICE SELECTION

(Well Operation Engineering)

Well operating practice means a number of indicators which characterize well operation conditions and productivity. The main indicator is well flow rate, i.e. amount of fluid (oil) produced from well within a given time. In field, oil production rate is measured in t/d, and fluid (oil and water) production rate is measured in m3/d.

According to (16), well flow rate and drainage reservoir with certain reservoir pressure are characterized by value of productivity factor and bottomhole pressure. Therefore, in well operation engineering it is necessary to determine productivity factor and, then, select the most rational bottomhole pressure Рbh.

For productivity factor determining, well should be tested under the steady-state modes (with plotting Inflow Performance Relationship).

Selection of bottomhole pressure Рbh depends on number of factors, and all such factors constraint fluid (oil) withdrawal, i.e. constraint bottomhole pressure Рbh decrease in formula (16). Let us consider such factors and their roles in well operation.

1. Under reservoir conditions oil always contain dissolved gas (associated petroleum gas). Specific quantity of dissolved gas can reach hundreds and even thousands m3

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per 1 t of oil. If pressure decreases to bubble point pressure, gas begins transferring from the dissolved state to the free phase (fig. 6).

From Oil and Gas Reservoir Physics it is well known that fluid phase permeability becomes lower during fluid filtration in porous rock medium in the presence of free gas. Thus, in formula (2) for fluid (oil) influx determination, it is necessary to add fluid (oil) phase permeability, as permeability factor K, which is lower than absolute permeability K. If bottomhole pressure Рbh becomes lower than bubble point pressure Рbp, fluid influx can increase insignificantly or even decrease.

That is why it is recommended to maintain bottomhole pressure at the level Рзаб ≥ Рнас (bottomhole pressure ≥ bubble point pressure). Based on well operation experience, it is allowed to reduce bottomhole pressure Рbh to (0.70…0.75) of bubble point pressure Рbp, provided that productivity factor is not significantly

changed.

Гр

Гн

Грi

Fig. 6. Oil Degassing Curve:

Рнас – bubble point pressure; Гн – gas saturation of reservoir oil (at Р = Рнас).

2. Productive reservoir rock can be characterized by certain fracturing. Fractures, even with small opening, are highly conductive channels for fluid, so, efficient (total) permeability of such rock is formed by permeability of fractures and pores (fractures and porous matrix), and fracture permeability can be much higher than pore permeability. Fracture opening depends on fluid pressure in fracture: under decrease of such pressure, fractures are, partially or completely, closed, and fracture permeability becomes lower. If one or several fractures are drilled-in, the main fluid influx takes place through these fractures. If bottomhole pressure Рbh is decreased,

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