Original Oil and Gas in Place

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Del curso dictado por Duke University

Oil & Gas Industry Operations and Markets

1116 calificaciones

Duke University

Oil & Gas Industry Operations and Markets

1116 calificaciones

The oil and gas industry has an enormous impact on all aspects of daily life. Individuals, corporations, and national governments make financial and policy decisions based on the cost, use, and availability of these two natural resources. This two-week course looks at the two most fundamental aspects of the oil and gas industry, its operations and markets, each of which is addressed as a separate module in the course. In the operations module, the course provides an overview of the production of oil and gas, from initial exploration to final transport. The second module focuses on the forces that drive the industry's operations, the oil and gas markets, including the cost of wells, seasonal impacts on prices, and the role of oil reserves. After every lesson, learners will take short quizzes to test their newly acquired knowledge, participant in crowd-sourced discussions about global markets, and complete a final project.

De la lección

Oil and Gas Industry Markets

In this second module, the course shifts to the markets that drive Oil and Gas Industry operations. You will learn about the various costs of the core oil and gas industry activities, the factors that determine the prices that oil, gas and petroleum products sell for, and the effect that the amount of oil and gas remaining in the ground has on the future viability of individual companies to the Industry as a whole.

Original Oil and Gas in Place4:48

Resources vs. Reserves5:42

Access to Conventional Reserves5:45

Additional Types of Unconventional Resources5:54

Conoce a los instructores

Lincoln Pratson
Gendell Professor of Energy & Environment
Nicholas School of the Environment

Determining whether a well that's reached the casing point will produce enough oil

or gas to make completing the well economic requires being able to make

an initial estimate of the amount of oil or

gas present in the reservoir rock penetrated by the well.

While there are several ways of doing this,

the one that is typically done first is the volumetric approach.

This is because the volumetric approach is simple, requires the least data and

assumptions, and can be done quickly based on the geologic model of the reservoir and

the well's initial results.

The volumetric approach requires measurements and/or

estimates of the following parameters.

First you need the average horizontal area of that part of the reservoir that

contains oil and/or gas, a region I will henceforth refer to as the gross pay zone.

Second, you need the average vertical thickness of the gross pay zone.

Third, a percentage of this thickness that actually contains oil or gas is required.

This percentage is known as the net pay.

Fourth, you need the average porosity of the reservoir.

Fifth, you need the percentage of the porous base that is water.

Or the water saturation in the reservoir.

And, finally, you need the formation volume factor.

This last parameter is the fractional amount that the volumes of oil or

gas in the reservoir have been changed by the temperatures and

pressures in the reservoir.

Relative to the volumes that the hydrocarbons will

have at the Earth's surface.

Let's run through each of these parameters

starting with the average horizontal area and thickness of the reservoir.

To get a good estimate of these parameters, a well will need to be

drilled through the gross pay zone down to where the reservoir contains only water.

If the well stops above this level, the true thickness of the gross pay zone

will remain unknown until the well is deepened or another well is drilled.

The shape of the reservoir can be highly variable with an important

influence on the shape being the type of trap holding the oil or gas.

For example, a pay zone beneath a domal trap has a shape

that differs from a pay zone trapped by a fault through the reservoir strata.

Which is different in shape from the gross pay zone trapped by a lateral change

in rock type.

However, by using the geologic model of the reservoir and

the depths of the top and bottom of the gross pay zone determined from the well.

The average area and average thickness of the gross pay zone can be estimated and

then multiplied to arrive at a volume that should faithfully approximate

the actual volume of the gross pay zone regardless of the pay zone shape.

This volume is then multiplied by a set of percentages that

yield the volume of the gross pay zone that is just oil or gas.

The first of these percentages is the net pay which is that percentage

of the gross pay zone that actually bears recoverable oil and or gas.

This adjustment is done because reservoirs are typically made up of alternating

layers of rock not all of which contain producible oil or gas.

Due to low permeability and/or porosity.

The net pay zone is then the thickness of the reservoir that contains

recoverable oil and/or gas.

In turn, the net pay zone is multiplied by the porosity of the reservoir, which is

the volume of the reservoir that is void space within the rock and contains fluids.

So this point in the calculation,

yields the total fluid volume of the net pay zone.

The fluid volume is then multiplied by one minus the water saturation, or

the fraction of the fluid that is not water.

So we now have the volume of oil or gas.

This volume is in turn divided by the formation volume factor,

which converts the oil or gas from reservoir volumes to surface volumes.

Finally, the remaining volume is multiplied by a constant that converts

the surface volume into standard sales volumes, these being barrels for oil.

In cubic feet for natural gas here in the U.S.

Note that this calculation requires different formation factors and

surface volume constants for oil versus natural gas.

So the calculation needs to be done separately for the two hydrocarbons.

Using the appropriate values for these parameters.

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