IOR

1.  IOR Definitions

1.1.              Definition

This is the process of enhancing oil production by the injection of a fluid into the reservoir, specifically EOR is done using engineered fluids that utilize methods beyond natural energy and augmented natural energy. EOR is the result of the injection of gases or liquid chemicals and/or the use of thermal energy. The injected fluid supplements natural energy and interacts with the rock/oil system to create a favourable environment for oil recovery.

The process can be grouped into 5 main categories:

1.1.1.   Mobility Control

Based on maintaining favourable mobility ratios to improve the magnitude of macroscopic displacement efficiencies.

This is the generic term describing any process where an attempt is made to alter the relative rates at which injected and displaced fluids move through a reservoir. The aim is to improve the volumetric sweep efficiency of a displacement process. Usually expressed in terms of Mobility Ratio M. if M≤1.0 then the process exhibits mobility control. Generally as M is reduced volumetric sweep efficiency increases.

Most mobility control processes concentrate on improving the characteristics of the injected fluids. In many cases mobility control involves the addition of polymers to augment the fluid being injected.

1.1.2.   Chemical

The addition of chemical agents to affect the interfacial tension (IFT) and phase behavior to displace oil by improving microscopic displacement efficiency.

1.1.3.   Miscible

To inject fluids that are directly miscible with the oil or that generate miscibility in the reservoir through composition alteration.

1.1.4.   Thermal

Methods that rely on the injection of thermal energy or the in-situ generation of heat to improve oil recovery.

1.1.5.   Other

A catch all category that addresses any other process that is NOT covered by the other categories.

1.1.1.   Permeability

The ability of a porous medium (in this case a hydrocarbon reservoir) to allow fluids to flow through. The rock permeability usually denoted by the symbol “k”, is important because it controls the directional movement and the flow rate of the fluid through the rock. Permeability id mathematically defined by Darcy’s Law, it is the standard tool of the petroleum engineer when one considers the flow of hydrocarbons through a porous medium.

1.1.1.1.       Absolute

Permeability when saturated with only one fluid.

1.1.1.2.       Effective

Permeability to one fluid when two or more fluids are present.

1.1.1.3.       Relative

The ratio of effective permeability of one phase to some base permeability.

1.1.1.   Capillary Pressure

The pressure difference across the interface, f a fluid system, the wetting and the non-wetting phase.

1.1.2.   Interfacial Tension

The energy required to increase the area of the interface by one unit.

1.1.3.   Displacement Efficiency

It is the fraction of moveable oil that has been recovered from the swept zone at any given time.

1.1.3.4.       Microscopic

How well the oil displacing fluid moves once in contact.

1.1.3.5.       Macroscopic

How well the displacing fluid has contacted the reservoir containing oil.

2.  Concepts

2.1.              Wettability

The tendency of one fluid to spread on or adhere to a solid surface in the presence of a second fluid. If two immiscible fluids/phases are placed in contact with each other and a solid phase one of the two is more attracted to the solid phase. The more strongly attracted is the wetting phase.

2.2.              Amott Wettability Index

This is the test for wettability, it involves the measurement of the imbibition of and forced displacement of oil and water from cores.

  1. Core is immersed in brine for 20hrs. The volume of oil displaced (if any) by spontaneous imbibition of water is measured.
  2. Remaining oil in the core is displaced by water to Sor. Total amount of oil is displaced is summed, imbibition and forced displacement.
  3. The core is immersed in oil for 20hrs. The volume of oil displaced by spontaneous imbibition is measured.
  4. The water is displaced to the residual water saturation with oil and the total amount of water displaced by imbibition and forced displacement is measured.

2.2.1.   Imbibition

Increasing water saturation and in the wetting phase.

2.2.2.   Drainage

Decreasing water saturation and in the wetting phase.

2.3.              U.S. Bureau of Mines

A macroscopic means of wettability testing of a rock to a given fluid. Similar to the Amott method but takes into consideration the work required to do the forced fluid displacement.

2.4.              Channel Flow Experimental Observation

  • In porous media immiscible fluids move through its own networks of channels
  • Channels vary in diameter and are bounded by liquid-liquid and liquid-solid interfaces.
  • The geometry of the channels are altered by saturation.
  • Flow is streamline and devoid of Eddy currents.

2.5.              Welge Construction

  1. Plot relative permeability data,
  2. Calculate the fractional flow of water as a function of water saturation
  3. Plot fw Sw
  4. Draw tangent from Swirr to intersect with fw Sw curve
  5. Water saturation at producing end of the system at water breakthrough at the intersection of tangent and curve.
  6. Producing water cut at breakthrough. Same point as above on the y-axis.
  • Average water saturation in reservoir at breakthrough at intersection of tangent and curve when fw = 1.00. Read the Sw value.
  1. Oil-Water mobility ratio krw at average Sw; kro ahead of front.

2.6.              Buckley-Leverett

This is the application of the conservation of mass for the flow of fluids, in one direction. Essentially by measuring the amount of fluids put in and taken out/produced we can determine the mass of fluids accumulated within the reservoir and hence make a determination of how much oil was displaced.

This theory is correct when M<1 but could be used for M = 10.

2.6.1.   Fractional Flow

Knowledge of the Buckley-Leverett model led to the development of the fractional flow equation.

Assumptions:

  1. Horizontal Flow
  2. Negligible capillary pressure
  3. No mass transfer between phases
  4. Incompressible phases

2.6.2.   Frontal Advance

The basic equation describing the two phase immiscible displacement of a linear system.

2.7.              Leverett-J Function

This helps to account for permeability, porosity and wettability of the reservoir. This formula varies depending on the rock type.

2.8.              Break-Through

2.8.1.   Oil-Wet System

  1. Differential pressure promotes water infiltrating the larger pore spaces
  2. Water will flow through the larger channels. kro falls and krw
  3. After large volumes of water is pumped, Sor is reached.

2.8.2.   Water Wet System

  1. Water is the wetting phase and no flow will occur.
  2. Water moves in a piston like fashion displacing most of the oil ahead.
  3. Sor is reached, oil flow tends to cease.

3.  Screening Criteria

  1. Reservoir temperature and pressure
  2. Reservoir fluid properties
  3. Reservoir geology

4.  Water Flood

4.1.1.   Factors Influencing

  1. Reservoir Geometry
  2. Fluid Properties
  3. Reservoir Depth
  4. Lithology and rock properties
    1. Porosity
    2. Permeability
  • Clay Content
  1. Net pay thickness
  1. Fluid Saturation
  2. Reservoir Uniformity and pay continuity
  3. Reservoir Driving Mechanisms

For water flooding we must consider two equations:

  1. Fractional Flow
  2. Frontal Advance

5.  Thermal Recovery

Relies of the use of thermal energy to aid in the displacement of oil reserves. It does this by increasing the reservoir temperature and thus lowering the oil viscosity, which in turn helps to displace the oil to a well.

5.1.              Hot Water Floods

The injection of hot water into the reservoir, the hot water helps to improve injectivity by dissolving waxes and asphaltenes. They are used because the heat losses to the formation is less than that of steam and there is no override of the oil by the water as with the steam.

It works by viscosity reduction and thermal expansion, fw reduces with temperature and as such oil recovery is increased.

5.2.              Steam Injection

This is definitely one of the more common and easily identifiable methods of thermal oil recovery, it is however limited to depths of 3,000ft and injection pressures of around 1,50psi. it is also dependent on the ability of the reservoir to promote the advancing of the steam front as such permeability plays a part in its success.

One of the limitations of steam injection is the loss of heat energy, from the pipelines, that conduct the heat from the steam generation plant to reservoir. This is why reservoir depth is limited, beyond a certain depth heat losses to the piping and formation will reduce the effectiveness of the injected steam.

This is one of the most effective enhanced recovery mechanisms based on the quantity of oil recovered. The steam is a favourable method as the steam itself is a better carrier of thermal energy and the steam front higher temperature produces more favourable bahaviour

5.2.1.   Huff ‘n’ Puff vs. Steam Displacement

Steam is injected, the reservoir is allowed to soak, and the reservoir is produced from. In displacement the steam is used to displace the oil. In most cases the reservoir is started on a Huff ‘n’ Puff scheme and then transitions to a displacement scheme.

5.2.2.   Process Mechanisms

  1. Viscosity Reduction
  2. Distillation of lighter fractions
  3. Vapour drive
  4. Thermal Expansion
  5. Gravity drainage

5.2.3.   Stimulation

Carried out in cycles. During the injection and soaking the steam zone is pushed away from the wellbore. The steam zone becomes a hot water zone during the production. This is mainly used to prepare a well for further follow up processes.

5.2.4.   Displacement

The main purpose is to increase the ultimate recovery factor. The steam is used to displace the oil.

5.3.              In-situ Combustion

Thermal energy supplied tot eh reservoir by burning part of the crude oil in place.

5.4.              Electrical Heating

Uses electrical or electromagnetic energy to increase the reservoir temperature. They involve heating the formation to a temperature that will lower the oil viscosity to point where it can be displaced by steam. More research is needed into this area.

6.  Bibliography

Latil, Marcel. 1980. Enhanced Oil Recovery. Paris: Institut Francais du Petrole.

Teknica. 2001. Enhanced Oil Recovery. Calgary Alberta: Teknica Petroleum Services Ltd.

Willhite, G. Paul, and Don W. Green . 2003. Enhanced Oil Recovery. Richardson Texas: Society of Petroleum Engineers.

 

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