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8/10/2019 Articulos de Propiedades en Ingles

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volatile oils and retrograde gases- what is the difference?

part 3: in a continuing effort to describe the five different reservoir fluids, this segment of the

series will explain the differences between volatile oils and retrograde gases. an initial

producing gas-oil ratio of 3200 scf/STB and a heptanes plus composition of 12.5 moles %

appear to be good separation points between these fluids.

Part 1 showed that at reservoir conditions, volatile oils exhibit bubble points and retrograde

gases exhibit dew points. the article contained a graph initial producing gas-oil ratio plotted

against concentration of heptanes plus in the fluid. fig 1. is a portion of that graph with the

data points indicating that the fluid had a dew point or a bubble point at reservoir conditions.

the scatter in the data reflects the compositional differences among the fluids and the

difference in surface separation facilities and conditions.

In Fig 1, only three fluids have dew points at initial producing gas - oil ratios less than 3200

scf/STB, and only one fluid reaches a bubble point above this value. Therefore, a value of 3200scf/STBD appears to be a good cuttof between volatile oils and retrograde gases.

Only two fluids with heptanes plus compositions less than 12.5 mole % exhibit bubble points,

and only three fluids with concentrations above this value exhibit dew points. Thus, 12.5 mole

% heptanes plus is a useful dividing line between volatile oils and retrograde gases. Actually,

heptanes plus is a useful content has been observed as low as 10 mole % in volatile oils and as

high as 15 mole % in retrograde gases. these cases are rare and often involve unusually high

stock tank oil gravities.

Retrograde behavior has been observed in laboratory studies of retrograde gases with initial

gas - oil ratios over 150000 scf/STB, although the amount of retrograde liquid is small (less

than 1% of the reservoir pore space). Apparently, most gases that release condensate at the

surface probably release some condensate in the reservoir - probably very few true wet gases

exist. However, wet gas therory can be applied to retrograde gases that release small amounts

of liquids in the reservoir. This will be explored in Part 4 of thus series.

Fluid Permeabilities

The retrograde liquid formed in a retrograde gas reservoir at pressures bellow the dew point

of the gas is virtually immobile Fig. 2 shows the oil and gas relative permeabilities of a reservoir

containing a retrograde gas. The condensate in the reservoir is considered the wetting phase,so these relative permeabilities were measured in an imbibition process. Irreducible water

saturation was present at 25 volume %.

The use of fig 2. requires an estimate of the highest possible condensate saturation. Phase

diagrams presented in part 1 of the series show that the 50 volume % liquid line is almost

vertical just below the critical points of the typical volatile oil and all three typical gases.

Generally, this is true and shows that the maximum possible condensate saturation in a

retrograde gas is 50% of the hydrocarbon pore space. Of course, only the richest retrograde

gases, with critical temperatures very near reservoir temperature, release this much

retrograde liquid. Therefore, the total liquid saturation of the reservoir represented by fig 2.

will start at an irreducible water saturation of 0,25 and build to a maximum of 0,625 as


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pressure declines. Obviously the effective permeability to the condensate is almost zero

throughout most of this range. Little production of the retrograde liquid occurs as the reservoir

is depleted.

Fig 2 also depicts the rapid decrease in effective permeability to gas as total liquid saturation

inceases. Effective permeability to the nonwetting phase is much more affected by increases inthe wetting phase saturation of an imbibition process than in a drainage process. Many

operators notice a sharp decrease in the gas production rate soon after reservoir pressure

passes through the retrograde gas dew point pressure.

Fig 2 may not explain the whole story. Flow visualization research at Heriot - Watt University in

Scotland, using high - pressure glass micromodels and core flooding with gases and retrograde

liquids, shows that these fluids exhibit effective permeabilities that are sensitive to flow rate.

The condensate will not flow at low gas flow rates found throughout most of the reservoir. But

it does flow at high gas flow rates near the well bores. Although the condensate does not flow

with the gas in the main part of the reservoir, it will drain downward due to gravity forces idthe reservoir, does not contain, barriers to vertical flow. Apparently, flow rate sensitivity has

not been observed in conventional effective permeability measurements.

Even though the flow stream from the reservoir is virtually all gas, the surface producing gas -

oil ratio will increase after the reservoir pressure declines bellow the dew point. This is due to

the loss of condensate (that would have ended up in the stock tank) in the reservoir. The

gravity of the stock - tank liquid increases as reservoir pressure decreases because the

retrograde behavior in the reservoir removes some of the heaviest components from the gas.

These components do not get to the stock tank, and consequently, the stock tank liquid is

lighter (higher API gravity).

Special procedures for retrograde gases provide data suitable for retrograde gas reservoir

performance. Compositional material balance calculations, with factors of equatios - of - state ,

also can be used performance prediction.

The results of laboratory procedures are necessary for "tuning" the equation - of - state.

Convetional gas material balance equations can be used at pressures above the dew point if

the equivalent gaseous volume of the surface condensate is added to the produced gas and if

the surface condensate and gas are combined by calculation to determine the properties of

the reservoir gas.

At pressures below the dew point, the gas material balance equation is applicable if two phase

z- factors are employed to calculate the gas formation volume factors. An interesting

correlations of the reservoir gas at pressures below the bubble point.

Part 2 of this series set a maximum initial producing gas - oil ratio of 1750 scf/STB for black oils.

Values of heptanes plus concentrations between 19 mole % and 22 mole % correspond to this

ratio. So 20 mole % is a reasonable cutoff between volatile oils and black oils.


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Reservoir Gases Exhibit Subtle differences

Part 4: This segment of the reservoir fluids series describes the characteristics of wet and dry

gases. At an initial producing gas-oil ratio greater than 15,000 scf/STB, engineers can treat the

reservoir fluid as a wet gas. Gases with initial producing gas-oil ratios greater than 100,000

scf/STB can be treated as dry gases. Retrograde behavior has been observed in gases withinitial producing gas-oil ratios greater than 150,000 scf/STB. The quantity of retrograde liquid

in the reservoir is very small for gases this lean. If a gas has enough heavy components to

release condensate at the surface, the gas will probably release some amount of condensate in

the reservoir. This implies few true wet gases exist (liquid at the surface but no liquid in the

reservoir).

However the concept of a wet gas is very useful for engineering purposes. The gas material

balance equation can be applied for a wet gas by simply combining the surface gas and

condensate by calculation to determine the properties of the reservoir gas , and adding the

gaseous equivalent of the surface condensate to the surface gas production . If there is a stocktank gas, it is specific gravity (which will she relatively high) must be included with the specific

gravity of the separator gas or gases (weighted by gas production rates ) to obtain an esti

mate of surface gas specific gravity. If the gas production rate and specific gravity of the stock

tank vent gas are not known, a correlation is available.

The problem is determining a value of initial producing gas oil ratio above which an

engineering can assume that the wet gas procedures are applicable.

Fig 1 shows the relationship between normal gas z-factors and two-phase z-factors. The data

were taken from a retrograde gas laboratory report. Gas z-factors approach a value of 1 at lowpressures. Two-phase z-factors tend to continue decreasing at low pressures due to the

presence of the liquid phase. However, sometimes the two-phase z- factors tend toward a

value of 1 at low pressures, indicating the fluid acts like a single-phase gas (i.e., acted like a wet

gas) even though two phases are present.

Data from 131 laboratory studies of retrograde gases were partitioned into those for which the

two phase z- factors decreased at low pressures and those that had two-phase z-factors

tending toward 1 at low pressures. Fig 2a shows two phase z- factors for those retrograde

gases which have heptanes plus concentrations greater than 4 mole % Fig 2b gives two phase

z-factors for those retrograde gases which have heptanes plus concentrations less than 4mole% . Apparently, if the concentration of heptanes plus is less than 4 mole % the gas can be

treated as if it were a wet gas even though the laboratory reported the presence of some

retrograde liquid.

Fig 3 is part of a data set discussed in part 1 of this series. The heptanes plus concentration of

the gas is expected be less than 4 mole % when the initial producing gas-oil ratio is above

15000 scf/STB. Thus, if initial producing gas-oil ratio is above 15000 scf/STB, the reservoir, fluid

can be treated as if it were a wet gas.


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The effects of condensate volume on reservoir gas specific gravity and cumulative gas

production are insignificant when the yield od condensate is 10 bbl/MMscf or less (i.e., whe

the initial producing gas oil ratio is 100000 scf/STB or more).

Even though some condensate is produced to the surface and possibly some retrograde

condensate is formed in the reservoir, reservoir fluids with initial producing gas

oil ratios thishigh can be treated as dry gases. The surface gas specific gravity can be used to represent the

specif gravity of the reservoir gas, and the surface gas production rates can be equated

reservoir production rates.

Author`s note:

The previous articles in this section have detailed the difference between repairs of reservoir

fluids. Next month part 5 will compare the details amazing all five reservoir fluids.

Fig 1 , at lower pressures, gas z-factors approach a compressibility factor of 1 . The pressure of

a liquid phase causes two phase z

factors to decrease at low pressures. Occasionally, two

phase z- factors approach 1 at low pressure, indicating fluids that act like a singlephase gas.

In Fig 2a, laboratory studies reveal that retrograde gases with heptanes plus concentrations

greater than 4 mole % generally have two phase z-factors which decrease at low pressures. In

fig 2b, heptanes plus concentrations less than 4 mole % generally have twophase zfactors

that approach 1.0 at low pressures.

Fig 3, when the heptanes plus concentration is less than 4 mole %, the initial producing gas-oil

ratio will be greater that 15000 scf/STB, and the fluids can be treated as wet gases.

5. Revised GasOil Ratio criteria key indicators of reservoir fluid type

Part 5 the previous four articles in this series revealed the difference and similarities among

the five reservoir fluid in detail. This concluding article discusses guidelines for using field data

to determine the fluid type, the laboratory evidence that verifies fluid type and the production

behavior of the five fluids.

Table 1 gives the guidelines for determining fluid type from field data. Three properties are

readily available the initial producing gas- oil ratio (GOR); the gravity of the stocktank liquid

and the color of the stocktank liquid. Initial producing GOR is by far the most important of

the indicators and should be considered first, with the other two indicators used to confirm

fluid type. Stocktank liquid gravity and color are both indicators of the quantity of heavy

components present in the initial reservoir fluid. Darker colors are associated with the largest,

heaviest molecules in the petroleum mixture.

If any one these three properties fails to meet the criteria of table 1 the test fails and a

representative sample of the reservoir fluid must be examined in a laboratory to establish fluid

type.

The initial producing GOR guidelines given in Table 1 are somewhat different than rules

presented by other authors. The rationales for selection of the values in table1 are given in the


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previous articles in this series. These article are the first to present empirical evidence to

support the selection of GOR criteria for identifying fluid type.

Table 2 shows the expected laboratory analysis results of the five fluids. The oils will exhibit

bubble points, the retrograde gases will display dew points, and the other change throughout

the pressure range expected in the reservoir. The heptanes plus composition cutoff betweenblack oils and volatile oils (20 mole %) is not exact. Values from 19 to 22 mole % might be

observed. However, the cutoff of 12.5 mole %between volatile oils and retrograde gases is

fairly sharp. The compositions of 4 mole % and 0,7 mole % the other gases are based on

engineering applications. Some retrograde liquid will likely occur in the reservoir in either case.

Oil formation volume factor has been defined for use in oil material balance calculations. Since

these calculation procedures are not applicable to volatile oils, formation volume factor

usually is not measured for volatile oils. But one laboratory result that indicates the presence

of a volatile oil is an oil formation volume factor at bubble point pressure of 2 res bbl/STB or

greater.

Production characteristics

Production trends for the five fluids are shown in table 3. Producing GOR is constant for oils as

long as reservoir pressure is above bubble point pressure. Both oils exhibit increasing

producing GORs when two phases exist in the reservoir. This increase is due to the existent of

reservoir gas which has much lower viscosity and therefore, moves more easily than the oil to

the well bore. Off course, as reservoir pressure declines further, the mount of gas the

reservoir increases. This causes an increase in the effective permeability to gas and a decrease

in the effective permeability to oil. As a result, the radio of gas to oil in the reservoir flowstream increases

Gases

Dry gases associated with black oils leave the flow stream in the first stage of separation. The

retrograde gases associated with volatile oils release some condensate in the first stage

separation. Therefore, black oils typically have higher surface GORs than volatile oils during

most of the producing time. Notice the decrease in producing GORs for both oils late at the

end of the production period in table 3. This turn down is primarily due to the severe increase

in gas formation volume factor a low reservoir pressures.

Retrograde gases also demonstrate constant producing GORs early when the pressure is above

the dew point pressure of the gas. And retrograde gases have increasing producing GORs at

pressures bellow the dew point. However, the reason for this increase is different than for the

oils. Very little of the liquid released from retrograde gases in the reservoir will few. This is

liquid which would be a part of the condensate at the surface were it not lost in the reservoir.

Thus the condensate yield at the surface decreases and the GOR increases as reservoir

pressure declines during production.

The producing GOR of a true wet gas remains constant throughout the life of the reservoir as

shown in table 3. Remember, though , that guidelines for identifying a wet gas for engineering


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purposes cut fairly deep into the range of fluids that exhibits some retrograde behavior.

Therefore, an increase in GOR later in the production period of a wet gas might be expected.

Liquids

The changes In API gravity of the stock tank liquids during production, as shown in table 3, areinterpreting. These changes are often help in differentiating between black oils and volatile

oils. Stock tank gravity remains constant when the reservoir pressure is above the bubble point

pressure of the oil. However as pressure falls below the bubble point the trends are different

for black oils and volatile oils.

The increasing proportions of dry gas produced with black oils as reservoir pressure declines

strip some of the lighter components from the oil. Therefore, the gravity of the stock tank oil

gradually decreases throughout most of the life of the reservoir. This decrease is not significant

(usually about 2 API from start to end).

Late in the life of a black oil reservoir the gravity of the stock tank oil will increase. At low

reservoir pressures the gas which comes out of solution from the oil in the reservoir is rich

enough (wet gas) to release condensate when it is produced. This dilutes the stock tank liquid

with condensate causing the gravity to increase.

On the other hand, the increasing proportions of retrograde gas produced with volatile oils

release increasing quantities of condensate at the surface. This condensate mixes with the

decreasing proportions of produced oil, causing the gravity of stock tank liquid to increase.

This change in gravity can be significant, on the order of 10 or more API units. Therefore, the

trend of stock tank oil gravities is another indicator of fluid type between black oils and volatile

oils.

The gravities of the stock tank liquids produced with retrograde gases also remain constant

when reservoir pressure is above the dew point pressure of the gas and increase as reservoir

pressure declines below the dew point. The trend below the dew point, is a result of the

heavier components of the gas being lost to the retrograde liquid in the reservoir and,

therefore, not reaching the stock tank.

Part 1 of this series presented a set of data showing the effect of composition (represented by

the mole percent of heptanes plus in the fluid) on initial producing GOR. Using the same data,

fig 1 indicates the composition and initial producing cut offs for the five fluids. Therationalizations for these cutoffs have been explained throughout this series of articles.

Fig 1 , the effect of composition on initial producing GOR is indicated by composition cutoffs of

the five reservoir fluids.

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