Question

For the following situations, choose a modeling method and explain why you would use it.
a. Designing a prosthetic limb

b. Routing a piping system for a building

c. Designing a one-of-a-kind machined part

d. Verifying clearances for an electrical substation located near an airfield

e. Mapping an oil reservoir

Answer 1

e. Mapping an oil reservoir

• To demonstrate reservoir properties in a plan view projection with objectives to promote optimal field development.

• The maps will be used for well placement, reserves calculation, reservoir performance monitoring.

• Mapping is part of reservoir characterization, therefore the results of which very depend on the expert’s working knowledge in applied geologic models.

TOP/SURFACE MAPS : –

Structure Map

Fault Map

Unconformity Map (Carried out by DG)

• THICKNESS MAPS : – Isopachous Map - Gross & Net

• OTHERS & COMBINED MAPS : –

Isoporosity Map

- Isopermeability Map

– Pressure Map

- Saturation Map

– Productivity Map

- Shale Map

– Net to Gross Sand Map - Etc.

BASIC KNOWLEDGEFOR RESERVOIR CORRELATION & MAPPING

• Log Analysis (electro-facies, reservoir parameters, stratigraphy, structure, etc.)

• Seismic Interpretation (structure, reservoir continuity, hydrocarbon indications)

• Sedimentary Facies, Depositional Environments & Sequence Stratigraphy

• Models Of Basins & Reservoirs, And Also Regional Geology Of The Mapped Field trends of sedimentation & major tectonic and it’s ramifications

• Basic Reservoir Engineering pressure regime, models, fluid properties and production performance.

• Basic Coordinate Systems/Geometry & Stereometric base map, well trajectory, lease boundary etc.

LOG ANALYSIS FOR RESERVOIR CORRELATION & MAPPING

• lithology / facies identifications & markers determination continuity, consistency, missing sections & repetition sections (faults or overturn)

• Depositional Environment

• Vertical Zonations – Top & Bottom – Flow Unit

• Fluid Contacts Owc, Goc & Gwc

• Reservoir Parameters Por, Perm etc

• Net Pay Thickness Determinations.

Reservoir Fluid Types Subtopics:

Black Oils

Volatile Oils

Condensate (Retrograde Gas)

Wet Gas (Rich Gas)

Dry Gas Typically,

there are five main types of reservoir fluids: black oil,

volatile oil, condensate (retrograde gas), wet gas, and dry gas. Each of these fluid types require different approaches when analyzing the reservoir, so it is important to identify the correct fluid type early on in the reservoir's life. Laboratory analysis is our primary method for determining and quantifying fluid type, but production information such as initial production gas-oil ratio (GOR), gravity of the stock-tank liquid, and the colour of the stock-tank liquid are also useful indicators.

Black Oils

Black oils are made up of a variety of components including large, heavy, and non-volatile hydrocarbons. The phase diagram is shown below. When the reservoir pressure lies anywhere along line 1 → 2, the oil is said to be undersaturated - meaning the oil could dissolve more gas if more gas were present. If the pressure is at 2, the oil is at its bubble point, and is said to be saturated - meaning the oil contains the maximum amount of dissolved gas and can't hold any more gas. A reduction in pressure at this point will release gas to form a free gas phase inside the reservoir. Additional gas evolves from the oil as it moves from the reservoir to the surface. This causes some shrinkage of the oil. Black oil is often called low shrinkage crude oil or ordinary oil. Black Oils Black oils are made up of a variety of components including large, heavy, and non-volatile hydrocarbons. The phase diagram is shown below. When the reservoir pressure lies anywhere along line 1 → 2, the oil is said to be undersaturated - meaning the oil could dissolve more gas if more gas were present. If the pressure is at 2, the oil is at its bubble point, and is said to be saturated - meaning the oil contains the maximum amount of dissolved gas and can't hold any more gas. A reduction in pressure at this point will release gas to form

a free gas phase inside the reservoir. Additional gas evolves from the oil as it moves from the reservoir to the surface. This causes some shrinkage of the oil. Black oil is often called low shrinkage crude oil or ordinary oil.

Black oils are dark in color indicating the presence of heavy hydrocarbons. It is characterized as having initial gas-oil ratios of 2000 scf/stb or less. Producing GOR will increase during production when reservoir falls below bubble point pressure, 2 → 3 as the gas evolves from the solution inside the reservoir and flows preferentially to the oil.

Volatile Oils

Volatile oils contain fewer heavy molecules and more intermediate components (ethane through hexane) than black oils. Volatile oils generally have initial gas-oil ratios in the 2000 to 3300 scf/Bbl range, and the stock tank gravity is usually 40° API or higher. The color is generally lighter than black oil – brown, orange, or green. Gas associated with volatile oils tends to be very rich and similar to retrograde condensate gas. The phase envelope for a volatile oil tends to cover a much narrower temperature range when compared to a black oil; but like a black oil, the reservoir temperature is always lower than the critical temperature for the fluid. As the reservoir temperature approaches the critical temperature a volatile oil will become more gas-like such that with even moderate depletion, a volatile oil reservoir can flash mainly to gas and have a relatively low liquid content.

Condensate (Retrograde Gas)

Condensate gas is very similar to volatile oils in terms of the colour (green, orange, brown, even clear) and gravity (40° to 60° API) of the produced oil. However, the reservoir temperature of a condensate gas reservoir is greater than the critical temperature of the fluid, and so where a volatile oil is a liquid at original reservoir pressure and temperature, a condensate gas is a gas. As pressure is reduced in a condensate gas reservoir, the fluid will pass through the dew point and large volumes of liquid will condense in the reservoir. Since the gas flows preferentially to oil, much of this oil will be unrecoverable. Consequently, it is important to recognize that a reservoir contains a condensate gas and re-inject dry gas to maintain reservoir pressure above the dew point to maximize recovery of the liquids. In the diagram below, the retrograde gas exists completely in a gaseous state inside the reservoir at point 1. As the pressure decreases, the condensate exhibits a dew point at point 2. As the reservoir further depletes and the pressure drops, liquid condenses from the gas to form a free liquid inside the reservoir.

Wet Gas (Rich Gas)

Natural gas that contains significant heavy hydrocarbons such as propane, butane and other liquid hydrocarbons is known as wet gas or rich gas. The general rule of thumb is if the gas contains less methane (typically less than 85% methane) and more ethane, and other more complex hydrocarbons, it is labelled as wet gas. Wet gas exists solely as a gas in the reservoir throughout the reduction in reservoir pressure. Unlike retrograde condensate, no liquid is formed inside the reservoir. However, separator conditions lie within the phase envelope, causing some liquid to be formed at the surface. This surface liquid is normally called condensate, and the reservoir gas is sometimes called condensate-gas, which leads to a lot of confusion between wet gasses and retrograde condensate.

Dry Gas

Natural gas that occurs in the absence of condensate or liquid hydrocarbons, or gas that had condensable hydrocarbons removed, is called dry gas. It is primarily methane with some intermediates. The hydrocarbon mixture is solely gas in the reservoir and there is no liquid (condensate surface liquid) formed either in the reservoir or at surface. The pressure path line does not enter into the phase envelope in the phase diagram, thus there is only dry gas in the reservoir. Note, the surface separator conditions also fall outside the phase envelope (in contrast to wet gas); hence no liquid is formed at the surface separator.