Reservoir Engineering

1.  Phase Diagram

Understanding the phase diagram will help to:

• Classify reservoirs
• Classify naturally occurring hydrocarbon systems
• Describe the phase behavior of the reservoir fluid.

 

Cricondentherm – the maximum temperature above which liquid cannot be formed regardless of the pressure.

Cricondenbar – the maximum pressure above which n gas can be formed, regardless of the temperature.

Critical Point – this is the state of temperature and pressure at which all intensive properties of the gas and liquid phases are equal.

Phase envelope – the region wherein gas and liquid co-exist in equilibrium. The region enclosed by the dew and bubble point curve.

Quality Lines – these describe the pressure and temperature conditions for equal volume of liquids. All such lines converge at the critical point.

Bubble Point curve – the line separating the liquid phase region from the two phase region.

Dew Pont curve – the line separating the vapour phase region from the two phase region.

2.  Reserves

2.1.              Definition

The estimated volumes of hydrocarbons be it fluid, liquid and or gas that are anticipated to be commercially recoverable and marketable from the given date under existing economic conditions.

2.2.              Proved

Known reservoirs that can be estimated with reasonable certainty. They are considered proved if commercial profitability of the reservoir is supported by actual production values. The area considered proved is defined by drilling and fluid contacts. If undrilled then geological and engineering data can be used to determine the areal spread.

You can also have proved undeveloped reserves assigned to undrilled areas, so long as the locations are offset from proven well indicating a commercial formation, are known to be within productive limits of a formation, conform to existing well spacing and will be developed in the future.

2.3.              Unproved

Based on geological and or engineering data, but technical, contractual or regulatory uncertainties mean it can’t be classed as proved.

2.3.1.   Probable

Attributed to known accumulations and less certain to be recovered. It indicates reserves:

1. That exist a reasonable distance from proved reserves
2. That exist in productive formations but lack definitive tests
3. In a part of a field that is part of a productive formation but separated by a fault
4. To be obtained by IOR methods
5. That can be produced by primary recovery methods
6. Determined by infill drilling
7. That are dependent on workover or such intervention

2.3.2.   Possible

Associated with known accumulations that are less certain to be recovered than probable.

2.3.3.   Developed Reserves

Expected o be recovered from completed intervals, it include production from IOR methods

2.3.4.   Non-Producing Reserves

Shut In and behind pipe reserves. Reserves expected to be recovered after completion, or those completed but not producing or those that may require further completion work or re-completion.

2.3.5.   Un-developed Reserves

Expected to be recovered:

1. From proposed wells or new wells on undrilled acreage.
2. By the extending of existing wells into different reservoirs.
3. In due course depending on financial resources or the building of suitable infrastructure to facilitate the production.

3.  Reservoir Types

3.1.              Oil Reservoir

Reservoir temperature is less than the critical temperature of the reservoir fluids.

3.1.1.   Under saturated

Initial reservoir pressure is greater than the bubble point pressure.

3.1.2.   Saturated

Initial reservoir pressure is equal to the bubble point pressure.

3.1.3.   Gas-Cap

Initial reservoir pressure is below the bubble point pressure. In this case the reservoir is a two phase reservoir with the gas or vapour phase underlain by the oil phase.

3.2.              Gas Reservoir

Reservoir temperature is greater than the critical temperature of the hydrocarbon fluid.

4.  Hydrocarbon Fluid Classification

4.1.              Black Oils

A low shrinkage reservoir fluid that is made up of heavy, non-volatile hydrocarbons. They are usually dark in colour indicating the presence of heavy hydrocarbons.

4.2.              Volatile Oils

Contain many intermediate components relative to black oils. They have high initial gas oil ratios with stock tank gravities 40° API or higher. The colour generally lighter than that of black oils, brown too orange. Gas associated with this fluid tends to be rich.

4.3.              Condensate

Similar to volatile oils in colour with gravities in the range of 40° to 60° API. Condensate gas is usually a gas within the reservoir on account of the reservoir temperature being greater than the critical temperature of the fluid.

4.4.              Wet Gas

This refers to natural gas that contains significant heavy hydrocarbons typically the rule of thumb is that if the gas contains less (than 85%) methane, more ethane and other more complex hydrocarbons then it is labelled a wet gas. Despite a reduction of reservoir pressure due to production a wet gas remains a gas, no liquid forms within the reservoir.

4.5.              Dry Gas

Natural gas that occurs in the absence of any type of liquid or condensate hydrocarbons, including gas that has condensable hydrocarbons. There is no liquid formed in the reservoir or at the surface, the mixture is solely gas.

		Oils			Gases
	Units	Heavy	Black	Volatile	Condensate	Wet & Gas
Initial Fluid Molecular weight		210+	70-210	40-70	23-40	<23
Stock Tank Colour		Black	Brown-Light Green	Greenish-Orange	Orange-Clear	Clear
Stock Tank Gravity	°API	5-15	15-45	42-55	45-60	45+
C7 + Fraction	mol%	>50	35-50	10-30	1-6	0-1
Initial GOR	scf/STB	0-200	200-900	900-3500	3500-30000	300000+
Initial FVF	RB/STB	1.0-1.1	1.1-1.5	1.5-3.0	3.0-20.0	20.0+
Reservoir Temperature	°F	90-200	100-200	150-300	150-300	150-300
Saturation Pressure	psia	0-500	300-5000	3000-7500	1500-9000	–
Volatile Oil/Gas Ratio	STB/MMscf	0	0-10	10-200	50-300	0-50
Maximum Vol% liquid during Constant Composition Expansion	vol%	100	100	100	0-45	0
OOIP (bulk)	STB/acre-ft	1130-1240	850-1130	400-850	60-400	0-60
OGIP (bulk)	Mscf/acre-ft	0-200	200-700	300-1000	500-2000	1000-2200

Table 1  Tabular summary of hydrocarbon fluid characteristics.

5.  Gases

5.1.              Z- Factor

This is correction factor used to account for the discrepancy between real and ideal gases.

5.2.              Ideal Gas

• Volume of molecules is insignificant compared to the TOTAL volume.
• No attractive of repulsive forces between them.
• All collisions are perfectly elastic.

The ideal gas can be mathematically described by the equation:

Equation 1 Ideal Gas Equation

Term	Meaning	Units
p	pressure	psia
V	volume	ft3
T	absolute temperature	°R (Rankine)
n	Number of moles of gas	lb-mol
R	Universal gas constant (10.73)	psiaft3/lb-mol°R

5.3.              Real Gas

With increasing temperature and pressures the gas behavior deviated from the ideal gas. This means that mathematically we need to account for this deviation. This is done by a gas compressibility factor or simply a z-factor being introduced to the ideal gas equation, so it becomes:

Equation 2 Real Gas Equation

Term	Meaning	Units
p	pressure	psia
V	volume	ft3
z	Gas Compressibility Factor
T	absolute temperature	°R (Rankine)
n	Number of moles of gas	lb-mol
R	Universal gas constant (10.73)	psiaft3/lb-mol°R

6.  Recovery Mechanisms

6.1.              Primary Recovery

Oil recovery by any natural drive mechanism.

6.2.              Rock-Liquid Expansion

This is the result of both rock and liquid within the reservoir expanding due to the declining reservoir pressure. Such a reservoir is characterized by a constant gas-oil ratio. This is the least efficient driving mechanism.

6.3.              Depletion Drive

In this reservoir the principal source of energy is a result of gas liberation from the crude oil, and the subsequent expansion of the solution gas as the pressure is lowered.

6.4.              Gas-Cap Drive

Reservoirs with a gas cap and little or no water drive. They are characterized by a slow decline in reservoir pressure. The energy comes from two sources – expansion of the gas cap and solution gas.

6.5.              Water Drive

This is the result of water moving into the pore paces originally occupied by oil, replacing and then displacing the oil.

6.6.              Gravity Drainage

Occurs as a result of differences in densities of the reservoir fluids.

6.7.              Combination Drive

One where both water and gas are present to displace the oil toward the well. The two driving forces are depletion with weaker water drive and depletion with gas cap and weak water drive.

7.  Material Balance

One of the basic tools of the reservoir engineer for interpreting and predicting reservoir performance. When applied you can use it to:

• Estimate original hydrocarbons in place
• Predict future reservoir performance
• Predict ultimate hydrocarbon recovery depending on driving mechanism

The equation is structured to keep inventory of oil materials entering, leaving and accumulating in the reservoir.

Essentially:

Initial volume = volume remaining + volume removed

Bibliography

Ahmed, Tarek . 2001. Reservoir Engineering Handbook. Houston, Texas: Gulf Professional Publishing.

McCain Jr., Willliam D. 1990. Properties of Petroleum Fluids. Tulsa Oklahoma: PennWell Publishing Company.