Well Logging: Sonic Log
Although in reality, acoustic tools are more complicated than these. The tool in its simplest form operates by sending a sound pulse from a transmitter that passes through the formation and is picked up at a receiver at the other end of the tool.
The sonic log records the time T required for a sound wave to traverse a given distance of formation. In the english system, one foot known as the interval transit time and presented in microseconds per foot, this value depends on the lithology and porosity of the formation.
For a given formation, the interval transit time or slowness increases with increased porosity. Porosity from the acoustic log may be estimated from this chart based on empirical observations. The lines on the chart correspond to the matrix acoustic velocities of common reservoir rocks and the chart is only valid for consolidated formations and when the fluid in the pore space is water or dead oil. In unconsolidated sands, the sonic log will read more than the true porosity. Thus, a special chart must be used that contains compaction corrections. Gas in the formation will also tend to slow the sonic waves resulting in the log reading more than the true porosity.
Here, we see an acoustic log taken through an interval of sandstone. The top of the sand body is defined by deflection of the SP curve here at 12,112 feet. From other data we have determined that gas occurs in three porosity zones and that a gas water contact exists here at 12,142 feet.
The acoustic log is scaled from 50 microseconds per foot to 150 microseconds per foot. Since travel time increases to the left, thus porosity also increases to the left. Here, in the effective gas column, we read a travel time of 122 microseconds. Using our chart for a consolidated sandstones gives us a porosity value of 38%.
Remember, that gas in the formation will tend to slow the sonic waves resulting in the log reading more than true porosity.
Note that travel times are generally faster in the water saturated sand below the gas column averaging about 100 microseconds. Using our chart again, this reading gives us a porosity value of 31% which is closer to the true porosity value of the sand compared to the high porosity value determined in the gas column.
The sonic waves passing through the formation tend to find the fastest path through the rock matrix and around fluid-filled bugs and fractures. Thus, the acoustic log tends to ignore secondary porosity of this type and measures only primary or intergranular porosity.
Although in reality, acoustic tools are more complicated than these. The tool in its simplest form operates by sending a sound pulse from a transmitter that passes through the formation and is picked up at a receiver at the other end of the tool.
The sonic log records the time T required for a sound wave to traverse a given distance of formation. In the english system, one foot known as the interval transit time and presented in microseconds per foot, this value depends on the lithology and porosity of the formation.
For a given formation, the interval transit time or slowness increases with increased porosity. Porosity from the acoustic log may be estimated from this chart based on empirical observations. The lines on the chart correspond to the matrix acoustic velocities of common reservoir rocks and the chart is only valid for consolidated formations and when the fluid in the pore space is water or dead oil. In unconsolidated sands, the sonic log will read more than the true porosity. Thus, a special chart must be used that contains compaction corrections. Gas in the formation will also tend to slow the sonic waves resulting in the log reading more than the true porosity.
Here, we see an acoustic log taken through an interval of sandstone. The top of the sand body is defined by deflection of the SP curve here at 12,112 feet. From other data we have determined that gas occurs in three porosity zones and that a gas water contact exists here at 12,142 feet.
The acoustic log is scaled from 50 microseconds per foot to 150 microseconds per foot. Since travel time increases to the left, thus porosity also increases to the left. Here, in the effective gas column, we read a travel time of 122 microseconds. Using our chart for a consolidated sandstones gives us a porosity value of 38%.
Remember, that gas in the formation will tend to slow the sonic waves resulting in the log reading more than true porosity.
Note that travel times are generally faster in the water saturated sand below the gas column averaging about 100 microseconds. Using our chart again, this reading gives us a porosity value of 31% which is closer to the true porosity value of the sand compared to the high porosity value determined in the gas column.
The sonic waves passing through the formation tend to find the fastest path through the rock matrix and around fluid-filled bugs and fractures. Thus, the acoustic log tends to ignore secondary porosity of this type and measures only primary or intergranular porosity.
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