книги / Методы и технологии добычи нефти и газа

Dissolved Gas Drive

Gas drive, or dissolved gas drive, is typical for reservoirs characterized by gentle dip, absence of free gas and low rate of edge water encroachment.

High rate of fluid withdrawal, even under presence of edge water, is also conductive to gas drive, as, in such case, water can not occupy volume left by oil and does not play a role of driving force that displaces oil.

The main driving force of gas drive is gas dissolved in oil or dispersed in oil in the form of very small bubbles. Oil displacement mechanism is as follows: under bottomhole pressure decrease, gas bled from oil is expanding and flowing at significantly higher rate than oil partially pushes it, and partially carries it due to friction forces. Effect of such process is usually insignificant, and a part of gas energy is often depleted earlier than more or less amount of oil is withdrawn, and, at the same time, reservoir pressure drops. With reservoir development by dissolved gas drive, gas-oil factor increases at high rate for some time, and, then, after reaching some maximum, decreases up to complete reservoir depletion.

Gravity Drive

If reservoir energy is completely depleted, the only force that makes oil migrate is oil gravity. In such case, oil flows from the upper zones of reservoir to the lower part and accumulates in it. Drive of such reservoirs is termed gravity drive.

Various regions of reservoir can have different drives. For instance, to flank wells oil can be driven by edge water, and internal regions of reservoir can be drained under gas cap drive or dissolved gas drive.

4. GAS RESERVOIR DRIVES

The main sources of energy for gas reservoirs are edge water drive, elastic forces of water and rock, and pressure of expanding gas. Depending on dominant effect of this or that source of energy, gas reservoir drive can be water drive, elastic gas water drive and gas drive.

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Water Drive

The main source of energy under such gas reservoir drive is edge (bottom) water drive. Conditions for water drive in gas reservoir are similar to those in oil reservoir. If volumes of withdrawn gas and encroached water are equal, reservoir pressure does not decrease, and gas withdrawal is accompanied with gradual rise of gas-water contact. By scaling up gas withdrawal rate, the balance between volume of withdrawn gas and encroached water can be disturbed and elastic-water drive or gas drive can be established in addition to water drive. Thus, decrease of gas reservoir pressure under water drive depends on current withdrawal of gas.

Gas reservoir water drive is a rarity in nature.

Elastic Gas -Water Drive

The main source of energy under such drive is elastic forces of water and rock, and expanding gas. Action of elastic forces is dominant if reservoir permeability is not high, reservoir structure is heterogeneous and catchment area is at a significant distance from reservoir, i.e. hydrodynamic communication between gas reservoir and catchment area is poor.

Water and rock elastic forces action in reservoir is not instantaneous, since at first withdrawals of gas reservoir pressure is slightly decreased. Continuous and steady gas withdrawal is conductive to decrease of not only gas reservoir pressure but also pressure of surrounding edge water, thus, conditions for elastic forces of water and rock are created. Such forces act in the direction of reservoir. Edge water occupies the released volume of reservoir, and gas-water contact slowly rises.

Gas Drive

Under gas drive, gas is withdrawn by pressure created by gas expansion, and that is why gas drive is also termed expanding gas drive. Gas drive is typical for reservoirs associated with completely sealed lithologically and tectonically screened traps. As a rule, such reservoirs are not large.

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Gas drive can be characterized by decrease of reservoir pressure in direct proportion to gas withdrawal, because there is no external source for reservoir pressure maintaining in gas drive reservoirs.

Gas drive can prevail in reservoirs with water drive and elastic-water drive if gas withdrawal rate significantly exceeds water encroachment rate.

5. OIL AND GAS RECOVERY FACTORS

In the course of oil well operation, only a part of oil reserves, not all of them, is recovered. Ratio of recovered oil to original oil in place is termed oil recovery factor. Oil recovery factor depends on many factors: physical properties of rocks and reservoir fluids, reservoir drive, reservoir development indicators and parameters (well pattern, rate and procedure for putting of wells on production, fluid withdrawal rate and other), areal sweep efficiency and other. Therefore, oil recovery factors differ for various reservoirs with the same drive.

The highest oil recovery factor is under water-oil displacement. Usually, it is associated with large energy margin of edge waters that can be unrestrictedly large in comparison with energy margin of free gas compressed in gas cap and dissolved in oil. It is also due to high efficiency of water displacement because the ratio of oil viscosity to water viscosity is more favorable for oil displacement by water than by gas. And, finally, physicochemical interaction of water with rock and oil can also be conductive to oil recovery enhancing under water drive. Washing out and displacement properties of water are better than those of gas.

Efficiency of dissolved gas drive is lower than efficiency of any other source of reservoir energy. It is due to limited volume of gas in reservoir and low gas-oil viscosity ratio that promotes fast gas breakthrough because of higher mobility. Moreover, gas phase does not wet reservoir rock, and this causes increasing residual oil content.

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Gas cap drive is much more efficient. When expanding, gas migrates to bottomhole, and effective frontal drive is created under comparatively low gas saturation of reservoir. That is why, depending on the reservoir structure, oil recovery factors can be high in gas-cap reservoirs. But, in case of high heterogeneity of reservoir, oil recovery factor reduces under such conditions. Reduction of efficiency of gas cap expansion is mainly caused by gas non-wettability of solid phase or its low viscosity, and, as a result, gas breaks through large channels and more permeable zones of reservoir.

Gas-cap reservoir oil recovery factor is substantially impacted by angle of bedding. At steep dipping, conditions of gravitational separation of gas from oil are improved and gas drive efficiency is enhanced.

High oil viscosity against water viscosity causes oil recovery factor decrease. Studies show that, with oil viscosity growing, various local non-uniformities of physical properties of rocks appear and promote formation of small but numerous areas bypassed by water front and poorly encroached.

Reservoir oil recovery is significantly impacted by high specific surface of rocks. Oil hydrophobes the surface of solid phase, and part of film oil can be recovered only by applying a stimulation method.

According to experimental and statistic field data, oil recovery factors under different reservoir drives can reach the below values:

Gas recovery factor of gas and gas condensate reservoirs is, as a rule, higher than oil recovery factor. Unlike oil, gases weakly interact with porous rock medium surface, their viscosity is low (hundred and more times less than light oil viscosity); due to high elasticity compressed gas always has energy margin required for filtration in

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porous rock medium; and reservoir pressure can decrease up to approximately atmospheric pressure. So, gas recovery factor of gas reservoirs can reach 0.90–0.95 under gas drive, and 0.6–0.85 under water drive. Gas recovery factor under water drive is lower because a part of gas volume is arrested due to faster movement of injected or edge water.

The highest gas recovery factor of gas reservoir can be reached by minimizing reservoir pressure to value at which bottomhole pressure is near atmospheric pressure or even lower than atmospheric pressure (gas vacuum suction). But under such conditions, well flow rate become low due to low pressure difference (Рr–Рbh). That is why, based on technical and engineering considerations, gas reservoir development is stopped if bottomhole pressure becomes higher than atmospheric pressure.

6. FLUID AND GAS INFLUX

Under oil or gas reservoir development, oil or gas inflow is radial.

Inflowing fluid or gas passes in succession a kind of number of concentrically located cylindrical surfaces between impermeable roof and bottom of reservoir, and areas of these surfaces are continuously reduced as the bottomhole is approached. If reservoir thickness is uniform and structure is homogenous, fluid (gas) filtration rate is continuously increasing, provided that flow rate is not changed, and reaches maximum on borehole walls.

If flow rate increases, hydraulic resistance becomes higher. Therefore, under migration of volumetric unit of fluid (or gas) to well, energy consumption per unit of travel path is continuously increasing, or pressure difference (pressure gradient) per unit of travel is increasing.

Relationship between well flow rate and pressure difference (Pr – Pbh) is determined by Dupuis formula for radial steady-state flow of homogeneous fluid:

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7. PETROLEUM RESERVOIR DEVELOPMENT

BY RESERVOIR PRESSURE MAINTAINING METHODS

In the majority of cases, natural reservoir energy is not sufficient for high rate of oil withdrawal. Even under effective water drive, reservoir pressure is decreased during reservoir development, and this is indicative of reservoir pressure depletion. It is explained by the fact that volume of inflowing reservoir water is, as a rule, less than volume of recovered fluids.

If reservoir pressure becomes lower than bubble point pressure, gas bleeding begins, gas-oil ratio increases, water drive is converted to dissolved gas drive and well production rate significantly decreases, and, as a result, reservoir development is delayed for years.

In gas cap drive reservoirs, natural reservoir energy margin is comparatively low and reservoir pressure flashes down.

Dissolved gas drive can be characterized by reservoir pressure flashing down, low well flow rate and low oil recovery rate. The most effective measure for enhancing oil withdrawal rate and oil recovery factor is artificial maintenance of reservoir energy by water or gas (air) injection.

Reservoir energy maintenance prevent gas bleeding as reservoir pressure is maintained to be higher than bubble point pressure; under high pressure oil is better displaced from low permeable layers; reservoir life decreases; and oil production economics improves.

Methods of maintaining reservoir pressure by water or gas injection have received wide recognition in petroleum reservoir development. Gas should be injected to gas cap for maintaining reservoir gas cap drive, or it is necessary to create gas cap artificially in reservoirs if dip angle exceeds 10–15°. Water may be injected beyond oil drainage boundary, in zones adjacent to oil drainage boundary or within oil drainage

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boundary. In some cases, it is advisable to apply simultaneously a combined injection: gas and water injection.

Working agent can be injected at the initial stage of reservoir development. If reservoir is characterized by high elastic energy margin, injection can be applied at later stage.

In case of marginal flooding, water is injected through the special injection wells located along the perimeter of reservoir beyond oil drainage boundary. Production wells should be located within oil drainage boundary in rows parallel to outline.

Homogeneous sand or sandstone reservoirs with high permeability and not complicated with disturbances are most productive for perimeter water flooding. Perimeter water flooding of limestone reservoirs can not always respond favorably as some parts of such reservoirs are not interconnected with the rest area of conjugated channels and fractures.

Water injection can be also inefficient in high viscous oil production, because water viscosity is less than oil viscosity, and water will overdrive oil and breakthrough to wells, and premature flooding can take place.

In case of boundary water flooding, reservoir pressure balance is maintained or restored by water injection directly to the oil-saturated part of reservoir.

The below given types of boundary water flooding are applied in Russia:

•dividing by injection well rows into separate areas;

•barrier water flooding;

•dividing into separate blocks for independent development;

•center to edge water flooding;

•localized water flooding; and

•pattern water flooding.

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8. PETROLEUM RESERVOIR ENGINEERING ANALYSIS

AND CONTROL

Drilling out, development and facilities construction, and, properly speaking, oil and gas production can be started when a reservoir management program is approved and accepted for implementation. From bringing reservoir into development and right to the end of reservoir development, various studies are performed for specifying geological-and-physical reservoir characteristics and reservoir performance indicators.

1.Standard geophysical measurements of apparent resistivity of rocks and spontaneous potential in penetrated geological column in all step-out wells.

2.Formation testing by formation tester tools in exploration wells, and core sampling in the majority of wells.

3.Flow-after-flow testing for building-up inflow performance relationship curves for all production and injection wells. Practically all wells shall be tested by bottomhole pressure build-up method. Such test shall be repeated in 1–2 years or more frequently, if effective drainage area is impacted. Bottomhole pressure and reservoir pressure should be measured, in the average, one time per six months.

For petroleum reservoir analysis and control, it is very important to measure fluid movement profile and intake rate of well by flow meters and flow rate meters. Frequency of such measurements in each well should be from six months up to twelve months, and, if necessary, such measurements may be made more frequent.

It is required to measure oil and water flow rates in all wells.

Oil-water and gas-oil contact position is determined by neutron and neutron lifetime logging with frequency about one time per six months.

Based on the analysis of petroleum reservoir engineering and identification of deviations between design and actual performance indicators, various work and actions should be performed for bringing the actual drift of development with designed one. A set of such arrangements is termed petroleum reservoir engineering control.

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The process methods of petroleum reservoir engineering control shall include:

1.Change of production and injection well operation conditions by decreasing or increasing well flow rates and repressuring medium flow rate up to ceasing (shut- ting-in) well operation;

2.Interval bottomhole formation zone treatment for increasing fluid inflow from separate layers, or increasing flow rate of injected fluids;

3.Increase of injection pressure up to fracture opening pressure;

4.Isolation of particular interlayer; and

5.Cyclic formation stimulation and controlled change of filtration flows.

The control methods associated with partial change of field development system shall include:

1)Localized and selective treatment of development targets by agent injection through the special injection wells or pattern of wells used for selective stimulation of regions of reservoir; and

2)Well workover operations or packer equipment setting for partial enlarging or downsizing, i.e. changing development targets.

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Viktor D. Grebnev

1. OPERATION OF OIL PRODUCING WELLS. BASIC PROVISIONS

Wells are operated at the expense of formation (natural) energy or energy applied from the daylight surface. In the first instance, the method of fluid production is called flowing and in the second instance – lifting.

An oil formation or an oil-and-gas formation possesses a certain natural energy symbolized by Enat. Let us symbolize the energy applied from the daylight surface as Esur. The movement of fluid from the bottomhole to the place of collection can be expressed by the following equation: Enat + Esur = E1 + E2 + E3, where

E1 is the energy spent for lifting the fluid or gas from the bottomhole up to the wellhead;

E2 is the energy spent by the gas-and-fluid mixture when passing through the wellhead equipment (Christmas-tree);

E3 is the energy spent while the fluid and gas are moving over a pipeline to the collection tank.

Let us consider where the natural energy comes from. The oil or gas formation is found at a certain depth and is exposed to the action of a hydrostatic pressure equal to Ph = H ρf g, where H – well depth, ρf – fluid density, and g – acceleration of gravity.

Inside the oil or gas formation, fluid and gas move at the expense of the difference of pressures at the pool outline and in the bottomhole zone, i. e., the condition Ppool > Pbh. The mechanism of fluid filtration in the porous medium was first discovered by French scientists Darcy and Dupue by passing water through a sand filter for municipal needs. As a result of observations, they deduced a direct relationship between the fluid speed and pressure differential:

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