Drill gas units and hydrocarbon analysis

According to a paper by Carl Bright of iBall Instruments of Oklahoma in the United States, drill gas units are a relative percentage of an unknown mix of gaseous hydrocarbons in it multiplied by 100. Sometimes and in some areas (not Nigeria), it could contain toxic gasses like Hydrogen Sulphide and Carbon dioxide. This is why the term “Units” is used instead of a known value such as “Methane” (C1).

For instance, if there were 10% pure Methane in air, it would be defined as as 1,000 Gas Units on an instrument. If there were a mix of 5% Methane (C1), 2% Ethane (C2), 2% Propane (C3) and 1% Butane (C4) with the other 90% being Air, it would also be defined as 1,000 Gas Units on an instrument. Some companies use a half scale in which 10% of pure Methane in Air would be defined as 500 Gas Units instead of 1,000. Generally, this is to keep some people from freaking out when larger numbers are seen.

The electronic detection of hydrocarbons was invented around 1926 when Dr. Oliver Johnson working for Standard Oil invented a catalytic combustion sensor in common jars using a very thin piece of Platinum wire and placed it inside of a Wheatstone bridge. The wires were driven to high temperatures. The meter deflection would allow the user to detect the presence of flammable hydrocarbons in air. More so, without the component of an air percentage, there would be no combustion and no deflection on the meter. As this sensor technology was perfected over time, and evolved into more reliable and better equipment, many thousands of instruments were built and used for many years using Platinum and then also Nichrome wire filaments.

So improvement in the gas detection technology continued through time. As the electronic age emerged and the systems became more advanced, reliable and precise, the simple deflection on the face of a meter was not acceptable for long term logging while drilling a well. As the 70s and 80s came of age, more digital equipment found its way into the logging arena. As such, the semi digital equipment was not able to compute or display decimal points or parts of a percentage. In this age of digital technology, the gas detection sensors have been improved so much now that with a device designed to agitate the drilling fluid coming out of a well bore, the gas is extracted and signals sent to specialized device that interprets such into broken down units and percentages for proper identification of gas-bearing hydrocarbon reservoirs, drill gas analyses and post drilling analysis.

Drilling fluid or drilling mud is used to lubricate and cool the rock cuttings tip at the end of the drill string. This drilling fluid is also used to bring the rock cuttings back to surface. Deep in the earth at the producing formation layers, as the drilling and cutting head penetrates the formation, the entrapped gases in the formation are forced into the drilling fluid at tremendous pressures and temperatures. Much like carbon dioxide being released from a soda pop bottle when opened, as the drilling fluid is returned to the surface, the lower atmospheric pressures generally will allow these entrapped gases to escape from the drilling fluid. A gas extractor at the point of surface will allow for the enhanced extraction and collection of these formation gases for analysis.

If the Gas Unit is coming from drilling fluid or mud, it is usually comprised of some, part, or all of Methane, Ethane, Propane, Butane, Pentane and Hexane. Generally, at the vertical oil well drilling operation when at the top of a new productive formation, it will be comprised of almost all Methane. When at the bottom or oil-water boundary layer of the productive formation, it will usually contain a reduced amount but still mostly Methane with an almost logarithmic progression of heavy gaseous hydrocarbons. When drilling through oil producing formations, the heavy hydrocarbons will be present in much higher quantities.

At general atmospheric pressures and temperatures, anything above Hexane (C6H14) is not released from the drilling fluid since at such surface pressures and temperatures, it would generally remain a liquid in the drilling fluid and not be released by a gas extractor except in a fractional fume state. When hydrocarbons are pressed into the drilling fluid and returned to the surface, many of the entrapped gases remain in the fluid in solution. This is because in this situation, the drilling fluid, either water or oil based is the solvent and the entrapped gases are dissolved in it. There is a very good chance that an appreciable amount of these dissolved gases is still in the drilling fluid when it is pumped back down the drill string. As such, these recirculated dissolved gases can cause extended detection of heavy hydrocarbon gases.

To better extract gasses from drilling mud for analysis, the drilling fluid should be shaken, stirred or beaten vigorously in order to release the entrapped gases. The larger the container that holds the drilling fluid to be agitated, the more gas can be liberated from it. The more drilling fluid that will be in a container to be agitated, the more gas will be liberated from it. The more violent the agitation within the container that holds the drilling fluid, the more gas will be liberated. Having a gas sensor that encapsulates all these factors is having a good knowledge of the formation gas, circulation gas and their components.