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Primary drive mechanisms

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Muskat defines primary recovery as the production period "beginning with the initial field discovery and continuing until the original energy sources for oil expulsion are no longer alone able to sustain profitable producing rates." [1] Primary recovery is also sometimes referred to as pressure depletion because it necessarily involves the decline of the reservoir pressure. This article provides an overview of types of reservoir energy and producing mechanisms (drive mechanisms).

Defining primary recovery

Primary recovery should be distinguished clearly from secondary recovery. Muskat defines secondary recovery as "the injection of (fluids) after the reservoir has reached a state of substantially complete depletion of its initial content of energy available for (fluid) expulsion or where the production rates have approached the limits of profitable operation." [1] One of the most popular secondary-recovery methods is waterflooding. Because primary recovery invariably results in pressure depletion, secondary recovery requires "repressuring" or increasing the reservoir pressure.

Primary recovery includes pressure-maintenance methods. Muskat defines pressure maintenance as "the operation of (fluid) injection into a reservoir during the course of its primary-production history." [1] The main effect of pressure maintenance is to mitigate the reservoir’s pressure decline and conserve its energy. The purpose of pressure maintenance is ultimately to improve oil recovery. The most common injected fluids for pressure maintenance are water and separator or residue gas. "Partial" and "complete" pressure maintenance describe the general effectiveness of a given pressure-maintenance operation to retard the rate of pressure decline. Partial pressure maintenance refers to fluid injection while a general state of pressure decline still exists. Full or complete pressure maintenance refers to fluid injection while the reservoir pressure remains essentially constant.

According to Muskat’s definition of pressure maintenance, secondary-recovery methods such as waterflooding are not strictly pressure-maintenance operations because they begin after pressure depletion. However, if water injection takes place before the end of pressure depletion, which is not uncommon, it is considered a pressure-maintenance method. If water is injected before the end of primary recovery, the reservoir is classified as an artificial waterdrive. Since Muskat first proposed his definition, others have loosely applied the term pressure maintenance to include any fluid-injection strategy at any stage in the reservoir’s production.

Types of reservoir energy

The following list outlines the major types of energy available for petroleum production.

  • Expansion of the reservoir fluids (oi, water and gas)
  • Expansion of the reservoir formation
  • Expansion of an aquifer if one exists
  • Gravitational energy that causes the oil and gas to segregate within the reservoir

Water within the reservoir refers to the water that is originally present within the reservoir at the time of discovery. Oil within the reservoir refers to the oil phase that is originally present at discovery or that may form from the condensation of volatilized oil upon pressure release. Likewise, gas within the reservoir refers to the gas phase that is originally present at discovery or that may form subsequently from the liberation of dissolved gas upon pressure release.

As mechanisms of energy release are provided by the drilling and operation of wells, reservoir pressure declines, fluids expand, flow is induced, and fluids are produced. The net volume of expansion of rock and fluids within the reservoir results in an equal volume of expulsed fluids. The water-bearing reservoirs that are sometimes adjoined to petroleum reservoirs are called aquifers. The expansion of water from the aquifer results in an overflow of water from the aquifer into the petroleum reservoir. The net overflow of water into the petroleum reservoir, in turn, results in an equal volume of fluid expulsion from the petroleum reservoir. Gravity segregation does not directly result in fluid expulsion but causes oil to settle to the bottom and gas to migrate to the top of the reservoir. By producing from only the lower reaches of the reservoir, this process affords a skilled operator a means to recover oil selectively and possibly recover more oil than would otherwise be recovered.

In ranking the types of energy in order of least importance to oil recovery, the energy of the compressed water and rock originally within the reservoir is probably the least important because of the relatively low compressibilities of water and rock. Of equal unimportance is the energy of the compressed oil, although the effects of compressed oil are slightly greater than the effects of compressed water and rock, as evidenced by the slightly greater compressibility of oil (10–5 per psi) than water (3 × 10–6 per psi) and rock (6 × 10–6 per psi). Of the energies of the compressed fluids, the effects of compressed gas are undoubtedly the most important because of the greater compressibility of gas. The effects of compressed gas are important even if there is not much free gas initially present, as in the case of an initially undersaturated oil reservoir. In these cases, gas will appear naturally during the course of pressure depletion because of the release of dissolved gas from the oil once the pressure falls below the bubblepoint pressure.

Gravitational forces can be a major factor in oil recovery if the reservoir has sufficient vertical relief and vertical permeability. The effectiveness of gravitational forces will be limited by the rate at which fluids are withdrawn from the reservoir. If the rate of withdrawal is appreciably greater than the rate of fluid segregation, then the effects of gravitational forces will be minimized.

The energy from the compressed waters of aquifers also can be a major factor even though the water has a low compressibility because the size of most aquifers tends to be much larger than the petroleum reservoir. Most oil fields have areas of less than 10 sq mile (6,400 acres), whereas aquifers often have areas of more than 1,000 sq mile. [1]

The energies discussed thus far represent "internal" reservoir energies (i.e., energies originally present within the reservoir and its adjoining geological units at the time of discovery). In addition to these energies, there may be important "external" energies (i.e., energies that originate from outside the reservoir).External energies imply the practice of injecting fluids into the reservoir to augment the reservoir’s natural energies. This practice is called pressure maintenance. The two most common injection fluids are compressed water and gas. The resultant action of injected fluids once inside the reservoir is much the same as the fluids originally present. The overall intention of injecting fluids is to add energy to the reservoir to recover more oil or gas than would otherwise be recovered. If gas is injected, it is clear that the intention is to recover more oil than otherwise would be recovered. In addition, the economic attractiveness of this practice relies on the expectation that the additional income derived from the increased oil production will more than offset the additional expenditures and lost or deferred revenues incurred by gas injection. The most common source of gas for gas injection is the gas produced from the reservoir.

Producing mechanisms

The general performance characteristics of hydrocarbon producing reservoirs are largely dependent on the types of energy available for moving the hydrocarbon fluids to the wellbore. The predominate energy forms give rise to distinct producing mechanisms. These producing mechanisms are used to help classify petroleum reservoirs.

In this section, these producing mechanisms are defined and delineated, although there is not a well-established consensus for some of these definitions. A petroleum reservoir rarely can be characterized throughout its pressure-depletion life by any single producing mechanism. A petroleum reservoir usually is subject to several producing mechanisms over its lifetime; nevertheless, the practice of describing a petroleum reservoir by its predominant producing mechanism is helpful.

Broadly, all commercially productive petroleum reservoirs are divided into either expansion drive, compaction drive, or water drive reservoirs. An expansion- or compaction-drive reservoir is a predominantly sealed reservoir in which the expansion of fluids and rock originally within the reservoir is responsible for petroleum expulsion from the reservoir. Fig. 1 shows the producing-mechanism system of classification.

In contrast, a waterdrive reservoir is an unsealed petroleum reservoir in communication with water-bearing reservoirs and in which there is appreciable movement of water from the water-bearing reservoir to the petroleum reservoir. If the rate of water intrusion into the reservoir is equal to the volumetric rate of fluid withdrawal from the reservoir, then the reservoir is more descriptively referred to as a complete-waterdrive reservoir. A complete-waterdrive reservoir often experiences, but does not necessarily imply, very little pressure decline. Complete-waterdrive reservoirs may require substantial pressure decline before the water-delivery rate can balance the production rate.

If the rate of water intrusion into the reservoir is substantial but substantially less than the volumetric rate of fluid withdrawal from the reservoir, then the reservoir is referred to as a partial-waterdrive reservoir. In all cases, when a waterdrive is the major producing mechanism, the reservoir pressure will be sensitive to the producing rate. If the reservoir-producing rate is too higher than the water-influx rate, the waterdrive will lose its effectiveness and the reservoir pressure will decline.

Waterdrives are also classified as edgewater or bottomwater drives, depending on the nature and location of the water encroachment into the reservoir. Fig. 2 shows a schematic of a bottomwater-drive reservoir. Because waterdrive reservoirs experience increasing water content and decreasing hydrocarbon content, they are referred to as nonvolumetric reservoirs. More generally, nonvolumetric reservoirs are reservoirs in which hydrocarbon pore volume (PV) changes during pressure depletion. Conversely, volumetric reservoirs are reservoirs in which hydrocarbon PV does not change during pressure depletion. Because waterdrive reservoirs involve water influx into the reservoir, they also are referred to as water-influx reservoirs.

Pressure depletion causes the internal stress within the reservoir rock to increase. This change produces changes in the grain arrangement and other phenomena that ultimately cause the pore volume of the rock to decrease. The contraction of the reservoir pore volume aids in expelling fluids from the reservoir. The terms "pore-volume contraction" and "rock expansion" are used interchangeably in this chapter to describe this phenomenon, even though very little grain expansion usually takes place. If this phenomenon is a major producing mechanism, the reservoir is a compaction-drive reservoir. Compaction-drive reservoirs are rare because the PV compressibility is usually less than the oil compressibility.

Expansion-drive reservoirs are further classified as oil- or gas-expansion-drive reservoirs depending on whether the oil or gas expansion is the predominant producing mechanism. Dry- and wet-gas reservoirs are gas-expansion-drive reservoirs because they do not contain any free oil at reservoir conditions. More descriptively, a gas-drive reservoir is one in which the expansion of free gas is the predominant producing mechanism. The expanding free gas may originate as initial free gas or as dissolved gas. An oil-drive reservoir, on the other hand, is one in which the expansion of free oil is the predominant producing mechanism. [1] According to these definitions, black-oil and volatile-oil reservoirs are not likely to be oil-drive reservoirs but gas-drive reservoirs because the expansion of gas is ultimately much greater than the expansion of oil. The oil in saturated, black-oil and volatile-oil reservoirs does not expand but contracts during pressure depletion because of the release of dissolved gas. Because the overwhelming majority of expansion-drive reservoirs are gas-drive reservoirs, the term oil-drive reservoir is rarely used. An oil-drive producing mechanism dominates in oil reservoirs only while they are undersaturated.

Gas drive reservoirs are further subdivided into either solution gas drive or gas cap expansion drive reservoirs. A gas cap expansion drive reservoir is a gas cap reservoir in which the expanding gas cap is responsible for the majority of the gas expansion. A gas cap is a free gas zone that overlies an oil zone. The free-gas zone may be pre-existing or may form during the depletion process. Pre-existing gas caps are called primary gas caps. Gas caps that are not originally present but that develop during the depletion process are called secondary or developed gas caps. Secondary gas caps can form from the upward migration of either liberated dissolved gas or from reinjected gas. Fig. 3 shows a schematic of a gas-cap expansion-drive reservoir.

Gas caps are also classified according to their displacement efficiency. At the most favorable extreme, the expanding gas displaces oil in a piston-like manner. At the other limit, the expanding gas displaces oil in a totally diffuse manner. The former are segregation drive or gravity drainage gas caps; the latter are nonsegregation-drive gas caps. The boundary between the gas cap zone and oil zone is the gas/oil contact (GOC). Segregation drive gas caps exhibit a GOC that moves progressively downward during depletion. In contrast, nonsegregation drive gas caps exhibit a GOC that appears stationary. The gas cap displacement efficiency depends on the producing rate and vertical permeability. Segregation drive gas caps tend to have high vertical permeability, while nonsegregation drive gas caps tend to have low vertical permeability. These two types of gas caps represent limiting cases. In reality, there is a continuum of character between these limits. The exact gas-cap character depends on the actual conditions.

Gas-drive reservoirs that are not gas cap reservoirs but are dominated by the expansion of solution gas are called solution gas drive or dissolved gas drive reservoirs. Fig. 4 shows a schematic of a solution gas drive reservoir. Gas drive reservoirs that are neither gas-cap nor solution gas drive reservoirs are called gas-drive reservoirs. For example, dry gas reservoirs are gas-drive reservoirs because they do not qualify as solution gas drive or as gas cap reservoirs. The practice of reinjecting dry gas into and producing wet gas from gas/condensate reservoirs is called gas cycling or cycling.

Recovery ranges

Table 1 lists the approximate primary-recovery range for the different producing mechanisms. The ranges reflect the rank of the reservoir energies. Black-oil reservoirs that exclusively produce by solution-gas-drive mechanism typically recover 10 to 25% of the OOIP by pressure depletion. The American Petroleum Institute reports an average primary oil recovery of 20.9% for 307 solution gas drive reservoirs. [2] In contrast, primary oil recovery from waterdrive, black oil reservoirs typically ranges from 15 to 50% or higher of the OOIP. Waterdrive, black oil reservoirs have yielded some of the highest recoveries ever recorded. The primary oil recovery from gas cap, black oil reservoirs varies widely depending on whether there is significant gravity drainage. The primary oil recovery from nongravity drainage, gas cap, black oil reservoirs ranges from 15 to 40% of the OOIP. In contrast, the primary oil recovery from gravity drainage, gas cap, black oil reservoirs ranges from 15 to 80% of the OOIP. Primary oil recoveries from gravity drainage, black oil reservoirs are among the highest of any black-oil reservoir. Pressure maintenance by gas reinjection is practiced commonly in black-oil reservoirs to improve oil recovery. Black-oil reservoirs subject to gas reinjection without gravity drainage typically recover 15 to 45% of the OOIP. If gas is reinjected in a reservoir with active gravity drainage, the primary oil recovery typically ranges from 15 to 80%.


  1. 1.0 1.1 1.2 1.3 1.4 Muskat, M. 1949. Physical Principles of Oil Production. New York City: McGraw-Hill Book Co. Inc.
  2. Bull. D-14, Statistical Analysis of Crude Oil Recovery and Recovery Efficiency, second edition. 1984. Dallas, Texas: API.

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See also

Material balance in oil reservoirs

Oil fluid characteristics

Solution gas drive reservoirs

Gas cap drive reservoirs

Water drive reservoirs

Water influx models

Material balance in water drive reservoirs

Compaction drive reservoirs

Oil fluid properties