Advanced Reservoir Management and Engineering Solution Manual

Gas Cap Drive

Segregation drive (gas cap drive) is the mechanism wherein the displacement of oil from the formation is accomplished by the expansion of the original free gas cap.

From: Advanced Reservoir Engineering , 2005

Performance of Oil Reservoirs

Tarek Ahmed , D. Nathan Meehan , in Advanced Reservoir Management and Engineering (Second Edition), 2012

4.1.3 Gas Cap Drive

Gas cap drive reservoirs can be identified by the presence of a gas cap with little or no water drive as shown in Figure 4.3. Due to the ability of the gas cap to expand, these reservoirs are characterized by a slow decline in the reservoir pressure. The natural energy available to produce the crude oil comes from the following two sources:

Figure 4.3. Gas cap drive reservoir.

(After Clark, N., 1969. Elements of Petroleum Reservoirs. Society of Petroleum Engineers, Dallas, TX).

(1)

expansion of the gas cap gas;

(2)

expansion of the solution gas as it is liberated.

Cole (1969) and Clark (1969) presented a comprehensive review of the characteristic trends associated with gas cap drive reservoirs. These characteristic trends are summarized below:

Reservoir pressure: The reservoir pressure falls slowly and continuously. Pressure tends to be maintained at a higher level than in a depletion drive reservoir. The degree of pressure maintenance depends upon the volume of gas in the gas cap compared to the oil volume.

Water production: Absent or negligible water production.

Gas–oil ratio: The gas–oil ratio rises continuously in upstructure wells. As the expanding gas cap reaches the producing intervals of upstructure wells, the gas–oil ratio from the affected wells will increase to high values.

Ultimate oil recovery: Oil recovery by gas cap expansion is actually a frontal drive displacing mechanism, which, therefore, yields considerably larger recovery efficiency than that of depletion drive reservoirs. This larger recovery efficiency is also attributed to the fact that no gas saturation is being formed throughout the reservoir at the same time. Figure 4.4 shows the relative positions of the gas–oil contact at different times in the producing life of the reservoir. The expected oil recovery ranges from 20% to 40%.

Figure 4.4. Gas cap drive reservoir.

(After Cole, F.W., 1969. Reservoir Engineering Manual. Gulf Publishing, Houston, TX).

The ultimate oil recovery from a gas cap drive reservoir will vary depending largely on the following six important parameters:

(1)

Size of the original gas cap: As shown graphically in Figure 4.5, the ultimate oil recovery increases with increasing size of the gas cap.

Figure 4.5. Effect of gas cap size on ultimate oil recovery.

(After Cole, F.W., 1969. Reservoir Engineering Manual. Gulf Publishing, Houston, TX).

(2)

Vertical permeability: Good vertical permeability will permit the oil to move downward with less bypassing of gas.

(3)

Oil viscosity: As the oil viscosity increases, the amount of gas bypassing will also increase, which leads to a lower oil recovery.

(4)

Degree of conservation of the gas: In order to conserve gas, and thereby increase ultimate oil recovery, it is necessary to shut in the wells that produce excessive gas.

(5)

Oil production rate: As the reservoir pressure declines with production, solution gas evolves from the crude oil and the gas saturation increases continuously. If the gas saturation exceeds the critical gas saturation, the evolved gas begins to flow in the oil zone. As a result of creating a mobile gas phase in the oil zone, the following two events will occur: (1) the effective permeability to oil will be decreased as a result of the increased gas saturation; (2) the effective permeability to gas will be increased, thereby increasing the flow of gas.

The formation of the free gas saturation in the oil zone cannot be prevented without resorting to pressure maintenance operations. Therefore, in order to achieve maximum benefit from a gas cap drive-producing mechanism, gas saturation in the oil zone must be kept to an absolute minimum. This can be accomplished by taking advantage of gravitational segregation of the fluids. In fact, an efficiently operated gas cap drive reservoir must also have an efficient gravity segregation drive. As the gas saturation is formed in the oil zone, it must be allowed to migrate upstructure to the gas cap. Thus, a gas cap drive reservoir is in reality a combination drive reservoir, although it is not usually considered as such.

Lower producing rates will permit the maximum amount of free gas in the oil zone to migrate to the gas cap. Therefore, gas cap drive reservoirs are rate sensitive, as lower producing rates will usually result in increased recovery.

(6)

Dip angle: The size of the gas cap determines the overall field oil recovery. When the gas cap is considered the main driving mechanism, its size is a measure of the reservoir energy available to produce the crude oil system. Such recovery normally will be 20–40% of the original oil-in-place, but if some other features are present to assist, such as steep angle of dip, which allows good oil drainage to the bottom of the structure, considerably higher recoveries (up to 60% or greater) may be obtained. Conversely, extremely thin oil columns (where early breakthrough of the advancing gas cap occurs in producing wells) may limit oil recovery to lower figures regardless of the size of the gas cap. Figure 4.6 shows typical production and pressure data for a gas cap drive reservoir.

Figure 4.6. Production data for a gas cap drive reservoir.

(After Clark, N., 1969. Elements of Petroleum Reservoirs. Society of Petroleum Engineers, Dallas, TX. Courtesy of API).

Well behavior: Because of the effects of gas cap expansion on maintaining reservoir pressure and the effect of decreased liquid column weight as it is produced out of the well, gas cap drive reservoirs tend to flow longer than depletion drive reservoirs.

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The Reservoir

Richard C. Selley , Stephen A. Sonnenberg , in Elements of Petroleum Geology (Third Edition), 2015

6.9.2 Gas Cap Drive

A second producing mechanism is the gas cap drive, in which the field contains both oil and gas zones. As production begins, the drop in pressure causes gas dissolved in the oil to come out of the solution. This new gas moves up to the gas cap and, in so doing, expands to occupy the pores vacated by the oil. A transitional zone of degassing thus forms at the gas:oil contact. Drawdown zones may develop adjacent to boreholes in a manner analogous to, but the reverse of, coning at the oil/water contact ( Fig. 6.55).

FIGURE 6.55. The gas expansion drive mechanism. A transitional zone develops at the gas/oil contact as pressure drops and the gas separates from the oil. Note the drawdown effect, which may develop adjacent to boreholes (C).

The production history of gas cap drive fields is very different from that of water drive fields. Pressure and oil production drop steadily, while the ratio of gas to oil naturally increases (Fig. 6.56). The gas cap drive mechanism is generally less effective than the water drive mechanism, with a recovery factor of 20–50%.

FIGURE 6.56. The typical production history of a field with a gas drive mechanism. For explanation see text.

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Reservoir Characterization Methods

Richard O. Baker , ... Jerry L. Jensen , in Practical Reservoir Engineering and Characterization, 2015

10.4.1.3 Gas Cap Drive

A typical production profile under gas cap drive with segregated gas flow is shown in Figure 10.4.6. The gas cap is a volume of highly compressible fluid and can provide considerable pressure support depending on its size. Reservoir performance again depends strongly on gas segregation. In general, more gradual pressure and oil rate decline than for solution gas drive can be expected. Once gas breakthrough occurs, the GOR is expected to continue rising. Water cuts are low. An example of a field with gas cap drive reservoir is shown in Chapter 11.

Figure 10.4.6. Characteristic production profile of a gas cap drive reservoir with segregated gas flow.

Individual well decline is usually hyperbolic with an Arps exponent of approximately 0.5 (Lefkovits and Matthews, 1958). However, individual well performance is strongly dependent on the structure of the reservoir and the distance between the well and the GOC. The permeability distribution is also an important factor because: (1) drawdown pressure is related to local permeability and coning is influenced by the drawdown pressure; (2) the extent of gas migration depends on the permeability distribution. When there is a laterally extensive gas cap blanketing the oil zone, pressure interference is common and can also affect the individual well decline rates. Production characteristics of gas cap reservoirs are summarized in Figure 10.4.7.

Figure 10.4.7. Production characteristics of gas cap drive reservoirs.

Recovery factors for gas cap reservoirs vary over a large range depending on pay thickness, the relative thickness of the gas and oil columns, permeability, and the ability to control the GOR. Generally, for reservoirs with small gas caps with low permeability, ultimate recovery factors are in the range of 5–20% because solution gas drive dominates the production profile. For reservoirs with large gas caps (m>0.3), thick oil columns (h>10   m), and high permeability, the ultimate recovery factor is usually greater than 30%. For high permeability and thick reservoirs in which gravity drainage dominates, the ultimate recovery factor can exceed 50%.

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Reservoir Characterization

Djebbar Tiab , Erle C. Donaldson , in Petrophysics (Fourth Edition), 2016

Gas-Cap Drive

When a gas cap is present, gas expands and invades the oil zone as a fairly uniform, vertically advancing front. The stability of the front and efficiency of oil displacement are functions of the gas and oil vertical mobilities, as defined using Darcy's equation:

(10.22) $\begin{array}{c}\hfill \begin{array}{ll}{u}_{\mathrm{g}}\uparrow =\left(\frac{K_{\mathrm{g}}}{{\mu }_{\mathrm{g}}}\right)\left(\frac{\mathrm{\Delta }P}{L}\right)\hfill & u_o\downarrow =\left(\frac{K_{\mathrm{o}}}{{\mu }_{\mathrm{o}}}\right)\left(\frac{\mathrm{\Delta }P}{L}\right)\hfill \end{array}\hfill \\ \hfill M=\left(\frac{K_{\mathrm{g}}}{K_{\mathrm{o}}}\right)\left(\frac{{\mu }_{\mathrm{o}}}{{\mu }_{\mathrm{g}}}\right)\hfill \end{array}$

Relatively low oil viscosity will enhance the downward counterflow of oil displacement. On the other hand, an unfavorable, or high, viscosity ratio promotes greater gas mobility which translates into the following: (1) Greater instability (gas fingering) occurs at the advancing front. (2) Increased bypassing of oil leads to reduced displacement efficiency (greater S _or). Gas is the nonwetting phase; therefore, it preferentially enters and occupies the larger pores, surrounding and trapping oil in smaller pores. This phenomenon is enhanced by the increasing velocity of the movement of gas. (3) The gravity-assist for vertical oil drainage drops, and greater vertical permeability aids the movement of the expanding gas downward, facilitating gravity drainage and improved oil displacement.

As the gas cap expands, the GOC and bubble-point pressure move downward (Figure 10.7a and b), and free gas develops at the top of the oil zone. The original solution gas evolves from oil as the level of the bubble-point pressure moves downward, and the oil volume in this zone shrinks as a result. Thus, the drive mechanism in the upper oil saturated (with gas) zone becomes a solution-gas drive. Eventually, the gas will move downward and completely encompass the oil zone.

Figure 10.7. (a) Gas-cap drive reservoir. (b) Expansion of gas downward as oil is produced.

Gas expansion is the source of the oil drive energy; therefore, production of gas should be minimized as much as possible. This means that wells producing higher in the reservoir (that begin production gas when the bubble-point level arrives at the well completion depth) must be taken out of production to conserve gas in the reservoir for greater overall oil displacement efficiency.

The relationship between the reservoir pressure and the gas-to-oil producing ratio, with respect to cumulative oil produced, is illustrated in Figure 10.8. As the production of oil increases, pressure declines slowly at first while the gas cap expands into the oil zone and the GOR increases gradually. When the gas cap expands downward, causing greater production of gas, the pressure begins to decline sharply in tandem with the ever-increasing GOR.

Figure 10.8. Behavior of reservoir pressure and gas-oil ratio as a function of the cumulative oil produced for a gas-cap oil drive mechanism.

The rate of oil production is one more major consideration for a gas-cap drive reservoir. The pressure draw-down in the vicinity of the wellbore is very sensitive to the rate of production. A high rate of oil production will create a considerable pressure difference between the wellbore and its radius of influence, which will result in a severe increase in gas production. Excessive gas production will (1) decrease the oil displacement efficiency and (2) decrease the ultimate recovery. The draw-down pressure at any point from the wellbore is equivalent to the slope of the curve (Figure 10.10). The slope imparts a horizontal pressure, toward the well on the gas, and the buoyant pressure acts vertically. Thus, the gas moves diagonally toward the well because the resultant pressure acting on the gas becomes much greater as the slope of the draw-down curve increases.

Example

Calculate the resultant pressure per foot of height for (1) a draw-down pressure with a slope equal to 0.4 and (2) a greater draw-down pressure with a slope equal to 1.0.

Solution (refer to example figure)

Slope   =   0.4

$\begin{array}{l}\mathrm{\Delta }{P}_{\mathrm{H}}=\frac{P_2-P_1}{L}=\frac{27.5-20.0}{1.0}=7.5\mathrm{psi}/\mathrm{ft}.\\ \mathrm{\Delta }{P}_{\mathrm{B}}=\left({\gamma }_{\mathrm{o}}-{\gamma }_{\mathrm{g}}\right)h=\left[\frac{\mathrm{lb}}{{\mathrm{ft}}^3}\frac{\mathrm{ft}}{144\mathrm{in}{.}^2/\mathrm{ft}{.}^2}\right]=\mathrm{psi}/\mathrm{ft}.\mathrm{of}\mathrm{height}\\ \mathrm{\Delta }{P}_{\mathrm{B}}=\left(0.2\right)\left(0.4/144\right)=5.6\times {10}^{-4}\mathrm{psi}/\mathrm{ft}.\\ R={\left({7.5}^2+{\left(5.6\times {10}^{-4}\right)}^2\right)}^{\frac{1}{2}}\approx 7.5\mathrm{psi}/\mathrm{ft}\text{.}\end{array}$

Slope   =   1.0

$\begin{array}{l}\mathrm{\Delta }{P}_{\mathrm{H}}=\left(39-29\right)/1.0=10\mathrm{psi}/\mathrm{ft}.\\ \mathrm{\Delta }{P}_{\mathrm{B}}=\left(0.2\right)\left(1.0/144\right)=1.4\times {10}^{-3}\\ R\approx 10\mathrm{psi}/\mathrm{ft}\text{.}\end{array}$

The net resultant force moving the gas toward the well is 2.5   psi greater for the steeper draw-down at a specific point away from the wellbore. The buoyant force, per foot of height, is very small, and thus, it is essentially constant in the reservoir; it becomes a significant factor as the height of the column increases [26,27].

The forces acting on the gas beyond a critical radius from the wellbore will have sufficient buoyance to move gas upward rather than toward the well. Consequently, there is a critical production rate for each well (in a gas-driving oil reservoir) beyond which gas production will occur, resulting in lower overall recovery.

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An Introduction to Enhanced Oil Recovery

Amirhossein Mohammadi Alamooti , Farzan Karimi Malekabadi , in Fundamentals of Enhanced Oil and Gas Recovery from Conventional and Unconventional Reservoirs, 2018

1.10.3 Gas Cap Drive

In the saturated oil reservoir with a primary gas cap, the dominant drive mechanism is gas cap drive. As the oil pressure decreases, gas expands and fills the extracted pore volume. By gas expansion, stored energy in gas is evolved and the gas oil contact comes down; therefore to avoid gas production from the cap, most wells are drilled in oil zones. High compressibility of gas causes a slow pressure drop in the reservoir. The level of pressure maintenance is relatively higher than the two abovementioned mechanisms. Ultimate oil recovery of the gas cap drive varies from 20% to 40% of original OIP.

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Oil Recovery

Russell T. Johns , in Encyclopedia of Energy, 2004

6.3 Immiscible Gas Injection

Immiscible gas injection in the reservoir is similar to the recovery process that occurs during a gas cap drive. Like water flooding, the volume and placement of gas can be controlled to improve sweep efficiency and maintain reservoir energy or pressure. Typical gases for immiscible flooding are methane, nitrogen, carbon dioxide, and air. Many of these gases are not completely immiscible with the oil. For example, carbon dioxide nearly always has some limited miscibility with the oil and, therefore, can swell the oil and reduce its viscosity, both of which can improve recovery. However, carbon dioxide is relatively expensive to inject as an immiscible gas and is generally not used in this way today.

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Special Core Analysis—Rock–Fluid Interactions

Richard O. Baker , ... Jerry L. Jensen , in Practical Reservoir Engineering and Characterization, 2015

8.5 Three-Phase Relative Permeability Correlations

Two-phase relative permeability data are sufficient for many reservoir applications, such as solution gas drive, gas cap drive, strong water drive, and waterfloods in undersaturated reservoirs. However, if a reservoir is under combination drive, three phases can flow simultaneously. In this case, three-phase relative permeabilities are required. Three-phase permeabilities are rarely measured. Instead, they are estimated using averaging techniques or correlations.

For all the methods discussed here, the water and gas relative permeabilities are determined from the respective water and gas saturations in the same way as for two-phase relative permeabilities:

(8.5.1) $k_{rw}^{\ast }=k_{rw}\text{at}{S}_w$

(8.5.2) $k_{rg}^{\ast }=k_{rg}\text{at}{S}_g$

in which k _ri and $k_{ri}^{\ast }$ are the two- and three-phase permeabilities of phase i, respectively. There are several methods for determining the three-phase relative oil permeability.

Averaging Method

The three-phase relative permeability to oil, $k_{ro}^{\ast }$ , is given by:

(8.5.3) $k_{ro}^{\ast }=\left(\frac{S_g}{S_g+S_w-S_{wi}}\right)k_{rog}\text{at}{S}_o+\left(\frac{S_w-S_{wi}}{S_g+S_w-S_{wi}}\right)k_{row}\text{at}{S}_o$

in which k _rog and k _row are the two-phase oil relative permeabilities in a gas-oil and a water–oil system, respectively. The two-phase relative permeabilities are determined at the oil saturation in the three-phase system, that is, S _o = 1   − S _g   − S _w .

Stone's Method I

To use Stone's Method I (Stone, 1973), the oil relative permeability endpoints must be identical in the water–oil and gas-oil systems; that is:

(8.5.4) $S_{orw}=S_{org}$

(8.5.5) $k_{rowe}=k_{roge}$

The three-phase relative permeability to oil is given by:

(8.5.6) $k_{ro}^{\ast }=S_{oD}\left(\frac{k_{row}\text{at}{S}_w}{1-S_{wD}}\right)\left(\frac{k_{rog}\text{at}{S}_g}{1-S_{gD}}\right)$

in which:

(8.5.7) $S_{oD}=\frac{S_o-S_{or}}{1-S_{wi}-S_{or}}$

(8.5.8) $S_{wD}=\frac{S_w-S_{wi}}{1-S_{wi}-S_{or}}$

(8.5.9) $S_{gD}=\frac{S_g}{1-S_{wi}-S_{or}}$

Stone's Method II

To use Stone's Method II (Stone, 1973), k _rowe   = k _roge   = k _roe . The three-phase relative permeability to oil is given by:

(8.5.10) $k_{ro}^{\ast }=k_{roe}\left[\left(\frac{k_{row}}{k_{roe}}+k_{rw}\right)\left(\frac{k_{rog}}{k_{roe}}+k_{rg}\right)-k_{rw}-k_{rg}\right]$

in which k _row and k _rw are evaluated at S _w , and k _rog and k _rg are evaluated at S _g . Note that Stone's Method II can give negative values. In this case, the relative permeability to oil is set to zero.

Figure 8.5.1 shows the three-phase oil relative permeabilities determined at a 20% gas saturation for the example from Section 8.4. The averaging method and Stone's I Method give similar results, while the Stone's Method II provides a conservative estimate of the three-phase oil permeability. It is recommended to use the averaging method or Stone's I Method unless there is evidence of low three-phase oil relative permeability.

Figure 8.5.1. Comparison of three-phase oil permeabilities determined from example core analysis.

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TERTIARY OIL RECOVERY: HOW COME IT'S CALLED THAT?

Claude R. Hocott , in The Future Supply of Nature-Made Petroleum and Gas, 1977

Water Drive

Water drive is generally recognized to be the most efficient natural displacement mechanism available to the operator. A water drive is similar to a gas-cap drive except that oil displacement occurs at an advancing water-oil front instead of at or behind a gas-oil interface. The greater efficiency of the water as a displacing agent is due largely to the greater viscosity of water in contrast to gas. Other benefits may be derived from the capillary forces effective during water drive in water-wet reservoir rock and from the fact that pressure maintenance is more frequently possible with natural water drive than with an expanding gas cap.

When the drive capacity of the advancing water is insufficient to maintain the reservoir pressure at or near original, the drive may be augmented by the injection of extraneous water, gas, or both. The result again is an assisted or enhanced primary recovery operation, by either augmented water or combination drive.

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Principles of Waterflooding

Tarek Ahmed , in Reservoir Engineering Handbook (Fifth Edition), 2019

Primary Reservoir Driving Mechanisms

As described in Chapter 11, six driving mechanisms basically provide the natural energy necessary for oil recovery:

○

Rock and liquid expansion

○

Solution gas drive

○

Gas cap drive

○

Water drive

○

Gravity drainage drive

○

Combination drive

The recovery of oil by any of the above driving mechanisms is called primary recovery. The term refers to the production of hydrocarbons from a reservoir without the use of any process (such as water injection) to supplement the natural energy of the reservoir. The primary drive mechanism and anticipated ultimate oil recovery should be considered when reviewing oil fields for possible development by waterflood. The approximate oil recovery range is tabulated below for various driving mechanisms. Note that these estimates are only approximations and, therefore, oil recovery may fall outside these ranges.

Driving Mechanism	Oil Recovery Range, %
Rock and liquid expansion	3–7
Solution Gas-cap drive	20–35
Gas-cap drive	20–45
Water drive	35–75
Gravity drainage	<   80
Combination drive	30–60

Volumetric undersaturated oil reservoirs: These types of reservoirs are identified by initial reservoir pressures that are greater than that of the bubblepoint pressure of existing crude oil systems. The main driving mechanism of a volumetric undersaturated reservoir is attributed to the expansions of the rock connate water, and the crude oil with pressure depletion. In most cases, this mechanism will not recover more than about 5% to 10% of the original oil in place. These reservoirs will offer an opportunity for greatly increasing recoverable reserves if other Improved Oil Recovery "IOR" displacement processes are favorable; e.g. polymer food, thermal recovery injection, …etc.

Solution gas-drive reservoirs: These types of reservoirs are initially existing at their crude oil bubblepoint pressures. For a solution gas drive reservoir, the main driving mechanism resulting from the expansion of the liberated solution gas as the reservoir pressure declines below the bubblepoint pressure. They are generally exhibit a relatively low crude oil recovery factors in the range of 20-35% and, therefore, a potential exists for a substantial additional recovery for developing the reservoir by water injection. In genera; they are generally considered the best candidates for waterfloods. It should be pointed out that developing the field by water injection can be viewed as an artificial water-drive mechanism. The typical range of the recovery factor of water-drive reservoir is approximately double of that of obtained from solution gas drive. As a general guideline, a waterflood process in a solution gas-drive reservoir will frequently recover an additional amount of oil equal to that of its primary recovery.

Gas-cap reservoirs: The presence of the gas-cap will limit the decrease of the reservoir pressure during production. The magnitude of the decrease in the reservoir pressure depends on the size and the areal extent of the gas-cap. It is possible that the primary driving mechanism resulting from the expansion of the gas-cap is quite efficient to the degree that the field can be effectively managed with production optimization without the need for water injection. In such cases, gas injection in the gas-cap may be considered as a pressure maintenance process to offset and balance high fluid withdrawal rates. Smaller gas-cap drives may be considered as waterflood prospects, but the existence of the gas cap will require greater care to prevent migration of displaced oil into the gas cap. This migration would result in a loss of recoverable oil due to the establishment of residual oil saturation in pore volume of the gas cap, which previously did not exist. If a gas cap is re-pressurized with water injection, it may require a substantial volume of water injection, thereby increasing the project life. However, developing a gas-cap reservoir with waterflood can be considered and may appropriate under one the following conditions:

○

The vertical communication between the gas cap and the oil zone is considered poor due to low vertical permeability

○

The existence of natural permeability barriers, such as sealing faults, can often restrict the migration of fluids to the gas cap.

○

Through the use selective well completion of injection wells to restrict the loss of injection fluid to the gas cap

Water-drive reservoirs: Many gas and oil reservoirs are produced by a mechanism termed water drive. Hydrocarbon production from the reservoir and the subsequent pressure drop prompt a water encroachment from the aquifer to offset the pressure decline. This response comes in a form of water influx, commonly called water encroachment, which is attributed to:

○

Expansion of the water in the aquifer

○

Compressibility of the aquifer rock

○

Charge of the aquifer from outcrop water-bearing formation that is located structurally higher than the pay zone

Strong water-drive reservoirs are not usually considered to be good candidates for waterflooding because of the natural water influx. However, in some cases a natural water drive could be supplemented by water injection in order to:

○

Support a higher withdrawal rate

○

Achieve more uniform areal sweep and coverage by better distributing the injected water volume to different areas of the field

○

Better balance Voidage and influx volumes.

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Primary recovery mechanisms and recovery efficiencies

Abdus Satter , Ghulam M. Iqbal , in Reservoir Engineering, 2016

Oil reservoirs

The primary drive mechanisms in oil reservoirs are as follows [1,2]:

•

Liquid and rock expansion drive

•

Solution gas or depletion drive

•

Gas cap drive

•

Aquifer water drive

•

Gravity segregation drive

•

Compaction drive

•

Combinations of the above

Liquid and rock expansion drive

When an oil reservoir is producing above the bubble point pressure, shown as line BB′ in Figure 5.1, the primary mechanism for oil production is the expansion of liquid and rock. Oil is undersaturated, and all the volatile components are dissolved in oil as long as the reservoir operates above the bubble point pressure.

During primary production, natural gas evolves at the surface facilities due to the reduction in pressure and temperature, resulting in low and constant gas–oil ratio. No significant water production is anticipated during primary production except in reservoirs where water saturation is high.

The oil recovery mechanism is dominated by the volumetric expansion of the reservoir fluids and rock above the bubble point when no other external driving mechanism is present. Expected recovery efficiency is relatively low, and typically varies from 1% to 5%, with an average of 3%.

Solution gas or depletion drive

When the reservoir pressure declines below the bubble point into the two-phase region (refer to Figure 5.1) due to production, dissolved gas starts to come out of the solution, and a free gas phase is formed. Below the bubble point the gas phase increases rapidly in the reservoir. The dominant recovery mechanism is known as solution gas or depletion drive. The gas phase is significantly more mobile than the liquid phase in the reservoir because the viscosity of the gas is much lower than the oil.

Reservoir pressure declines rapidly from early stages of recovery. The gas–oil ratio is initially low, and then rises to a maximum, and finally drops as most of the liberated gas is produced. Again, no significant water production is anticipated from the reservoir except where the water saturation is high.

Typical oil recovery due to solution gas drive ranges between 10% and 30%, with an average of about 20%. Once secondary recovery operation is initiated, further recovery of oil is attained (Figure 11.1).

Figure 11.1. Comparison between reservoir performances based on two scenarios.

(a) Solution gas drive alone and (b) solution gas drive followed by water injection (secondary recovery). Recovery is usually higher in the latter case.

In the early years of the twentieth century, many small reservoirs were produced until abandonment based on a primary recovery mechanism. Common approaches to boost production during declining well performance involved the utilization of pump, gas lift, well recompletion, and workover, among others. Many older reservoirs are still produced in the above manner. However, as the reservoir characteristics and fluid flow behavior were better understood along with the introduction of technological innovations, large complex reservoirs were subjected to waterflooding and pressure maintenance early on following a relatively short period of primary recovery. The timing and strategy for improved oil recovery (IOR) operations are based on building various scenarios of drilling additional wells and fluid injection. The ultimate recovery of petroleum is maximized by introducing additional energy into the reservoir, and the added assets far outweigh the costs associated with drilling and IOR operations.

Gas cap drive

A gas cap present at the time of the discovery of the oil reservoir is known as a primary gas cap. Certain oil reservoirs are discovered with an initial reservoir pressure below the bubble point pressure where a primary gas cap forms long before the reservoir is discovered and produced.

In case an oil reservoir does not have a gas cap initially, but one is formed later by the dissolution of volatile components present in the liquid phase, the gas cap is referred to as secondary. Liberated gas forms a gas cap above the oil zone. At that point, the reservoir is located within the two-phase region (as in points B″ and V″ in Figure 5.1). Since gas is lighter than oil, it rises above the oil zone due to gravity segregation.

During production by gas cap drive, reservoir pressure falls slowly and continuously. The driving energy is predominantly provided by the expansion of the gas cap as the reservoir depletes. The gas–oil ratio rises continuously in updip wells. Water production is nonexistent or negligible where the water saturation is irreducible. Production from the gas cap drive reservoir is due to the driving energy imparted by both solution and free gases, resulting in higher oil recovery than the solution gas drive alone. Oil recovery due to gas cap drive is typically around 30% but could be as much as 40%.

Oil recovery under gas cap drive is improved by (i) completing the wells in the oil zone as deep as possible, (ii) reinjecting the produced gas in updip wells, and (iii) shutting off the wells as the gas–oil ratio becomes significant (Figure 11.2).

Figure 11.2. Reservoir performance under gas cap drive.

Aquifer water drive

Certain reservoirs are in communication with an aquifer, which may provide significant natural energy for production. Three types of water drive reservoirs are encountered:

•

Peripheral water drive: The aquifer is located at the periphery

•

Edgewater drive: The aquifer is located at one edge

•

Bottom water drive: The aquifer is located at the bottom of the oil or gas reservoir

As an oil reservoir is produced, water encroachment into the reservoir occurs due to high aquifer pressure. This leads to favorable oil recovery. Reservoir pressure remains high, and gas–oil ratio remains low during production. Early water production is encountered at the downdip wells, and water production increases with time. Aquifer volume is quite large in comparison to reservoir volume, 10 times or larger than the reservoir.

Certain reservoirs experience bottom water drive where the aquifer is located below the reservoir. If the aquifer is below the oil reservoir, water coning into the oil reservoir results in lower oil recovery than what can be expected from a peripheral water drive.

Under favorable conditions, oil recovery efficiency under aquifer water drive could be as much as 50% or more. Hence, a strong influence by aquifer may be the most potent primary drive mechanism available in comparison to the others. Figure 11.3 presents the reservoir performance under aquifer drive.

Figure 11.3. Reservoir performance under aquifer water drive.

Gravity segregation drive

Oil drainage due to gravity and subsequent production can be found in certain steeply dipping or fractured reservoirs located at shallow depths. The phenomenon may also occur where vertical permeability is more than horizontal permeability. Under gravity segregation drive, reservoir pressure declines continuously. Gas–oil ratio remains low in downdip wells, but a high value is observed in updip wells. Water production is either not observed or negligible at the wells.

Oil recovery due to gravity segregation drive could be 50% or more. Combined with gas cap drive, a recovery factor of 80% is achieved in certain cases. However, total recovery volume could be low in reservoirs that produce by the mechanism of gravity drainage.

Rock compaction drive

Certain reservoir rocks are unconsolidated and have very high compressibility much above the normal range of 3–8 × 10⁻⁶ psi⁻¹. No significant decline is observed as the reservoir is produced and rock is compacted. Sizeable amounts of oil may be produced before the bubble point pressure is reached. Such a phenomenon is referred to as compaction drive. Certain North Sea and Gulf Coast fields are found to produce by compaction drive, although such reservoirs are not commonplace. Overpressured reservoirs may also produce by compaction drive.

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https://www.sciencedirect.com/science/article/pii/B9780128002193000115

Advanced Reservoir Management and Engineering Solution Manual

Source: https://www.sciencedirect.com/topics/engineering/gas-cap-drive

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