книги / Разработка нефтяных и газовых месторождений. Ч. 2

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.

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 modu-

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lar 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).

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).

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).

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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

where ∆РОЗП1 is a part of general underbalance used for fluid filtration in bottomhole formation zone (ОЗП); ∆РУЗП1 is a part of general underbalance in remote zone of formation (УЗП).

Fig. 4. P = F(r) Relationship

Distribution of pressure within reservoir around operating well

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.

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).

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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 constant reservoir pressure Рпл and bottomhole pressure Рзаб ∆РОЗП2 > ∆РОЗП1 , respectively (at ∆Рпл = const), ∆РУЗП2 < ∆РУЗП1 , fluid influx becomes lower at lower ∆РУЗП2 .

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

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:

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:

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or

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; µг 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 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

πkhT0 z0 к c

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

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 pres-

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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 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.

Fig. 6. Oil Degassing Curve:

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

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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, fractures are, partially or completely, closed, and, instead of flow rate increase according to formula (16), it can be decreased because efficient permeability becomes much lower in formula (2).

Minimal values of bottomhole pressure under which well flow rate is not becoming lower if underbalance Pr – Pbh is increased should be determined experimentally when well testing. It is not recommended to reduce bottomhole pressure lower than such minimal values.

3.Usually, oil contacts water-saturated part of reservoir in the bottom or in flanks. Water viscosity is, as a rule, lower than reservoir oil viscosity. Under high underbalance (high values of ∆Рr), water can flow to bottomhole from the bottom or breakthrough from flanks along the most permeable layers (stringers) of rocks. Together with water, oil inflows to well. In all cases, water content in oil well flow causes various problems: corrosion, formation of high-viscosity emulsions in wells and on surface (in the gathering system). On surface, it is necessary to remove water from oil and inject it both for its disposal and for maintaining reservoir pressure. If well is shutdown, water is accumulated in the bottom part of well, i.e. bottomhole, as water density is higher than oil density (water is heavier than oil), and penetrates the part of reservoir along which oil flows to bottomhole. When well is brought into operation, oil flows in porous rock medium (in bottomhole formation zone) which contains penetrated water. According to the fundamentals of Petroleum Reservoir Physics, oil filtration in the presence of water (another phase) in porous rock medium is worse. So, oil influx becomes lower. Thus, bottomhole pressure must be sufficient to prevent water breakthrough.

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4. Reservoir oil always contains asphaltens, resins and solid paraffin. Resins and paraffin are dissolved in oil, and asphaltens can be partially in dissolved state and partially in the form of dispersed fine particles. When oil flows from bottomhole to wellhead, oil pressure and temperature becomes lower. At the given temperature, which is termed paraffin crystallization point or paraffin saturation point, paraffin recovers from the dissolved state and crystallizes. Resins can recover from oildissolved state at higher temperatures, and it is promoted by oil-dissolved gas transfer to free phase. The lower well pressure relative to bubble point pressure, the less dissolved gas is in oil (fig. 6). Dissolved resin and paraffin retaining power of oil becomes lower. If bottomhole pressure is equal to bubble point pressure Рbp or lower, the transition of oil-dissolved substances to another state can start in the bottomhole, and rate of such transition becomes higher as oil lifts to the surface. As a result, the so termed asphaltene-resin-paraffin deposits are formed on the surfaces of tubing string and other well equipment. Asphaltene-resin-paraffin deposits can partially or completely cover tubing flow area, thus, creating serious problems in well operation. Asphaltene-resin-paraffin deposits are formed deeper as bottomhole pressure Pbh decreases, all other conditions being equal.

5. OIL AND GAS WELL OPERATING PRACTICES. PRINCIPLES OF ENGINEERING AND OPTIMIZATION

5.1. Oil Well Lift Method Selection

In selecting lift method, first of all, it is necessary to determine well flowing conditions, i.e. calculate minimum bottomhole flowing pressure. In the general case:

where ρf is fluid density within the bottomhole zone to depth Нs, at which well pressure is equal to bubble point pressure; ρm is average gas-fluid density within interval from section Нs to wellhead; ∆Рfpd and ∆Рmpd are, respectively, friction pressure drop within fluid and gas-fluid flow interval; and Рwhp is wellhead pressure.

If formation pressure is Рf > Рmin bhf , well is capable of flowing.

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