While it is problematic to rate one H2S well control incident as worse than another, the Blowout at Lodgepole may be described as one of North America’s worst H2S well control releases due to the large flow rate of the well, high concentration of H2S, and the ubiquitous public awareness following the incident. During the response to the blowout, tragically, 2 of the well control specialists lost their lives and 16 other workers were hospitalized. Being aware of the hazards of H2S and its effect in this and other historical well control incidents can help us in the oil and gas industry to improve safe operations in the future.


When the target reservoir was reached, there was reason to believe it was expected to produce oil rather than the high H2S gas that the reservoir actually contained. While exploring for oil and gas during wildcat drilling there sometimes can be the ability to differentiate between an oil horizon and a gas horizon prior to drilling. These methods are varying in reliability and effectiveness based on the conditions of the fluids, geology involved, and the techniques used. Some techniques that would apply to locating a reservoir and determining whether it is oil or gas prior to drilling may include seismic, geostatistics, and outcrop studies. Let’s look closer at each of these methods:

  • Seismic: Active seismic uses a release of energy at the surface to propagate a wave downward. As the wave travels downward through the rock, they will have a certain velocity based on that type of rock and the fluid it contains. When the wave transfers from one rock into another or from one fluid type into another the velocity of the wave will very likely change. When the velocity of the wave changes at these faces then there can be a reflecting wave that travels upward back towards the surface. A network of sensors records the time and intensity of the waves returning to the surface. The combination of noise to signal ratio combined with the sensitivity of the sensors can sometimes give seismic the ability to differentiate between gas and oil or gas and water. This method does not give the ability to determine the composition of oil versus gas versus water or if there is any H2S present within the reservoir. Sometimes this method misses a gas horizon completely and merely is able to see the structure of the rock during the study without any inference to fluid data.
  • Geostatistics: One method of reservoir study is comparison to nearby reservoirs and geostatistics is the quantitative assumption of reservoir properties using the known properties surrounding that reservoir. The quality of the data in this method depends on how close and how rich your analog data is geographically to your target. Depending on the quality and closeness of the analog data, this can yield a wide variety of rock property and fluid data. This can help to assume flow rates, gas/oil ratios, water production, the presence of H2S, etc. In wildcatting, however, the closeness of this data is often low as the trial well is by definition far afield.
  • Outcrop studies: Outcrop studies can give a good idea of the subterranean rock composition and, when done meticulously, even the structure of the rock bodies. The fluid composition is often not able to be determined unless reservoir fluids are actually seeping. In many cases the fluids will not seep because of a sealing fault or other structural trap.

Note the commonality between these methods in that they give poorer quality of data when you are exploring farther afield and especially poor fluid data. Being unsure of the composition of the oil/gas ratio prior to wildcat drilling is typical and for H2S quantities to be completely unknown prior to drilling the initial test well would also be typical. So, while drilling a wildcat well the operator may be expecting and hoping for a sweet crude oil and instead discover sour H2S laden gas instead.

As the bit entered the wellbore, the first indication of a possible kick was the appearance of gas cut mud with associated H2S. Note that the interstitial hydrogen sulfide concentration of the reservoir was around 28% (280,000 PPM) H2S concentration. It appears that the crews were trained, although it is hard to conceive that the drill string and circulating equipment would be certified to handle H2S concentrations at that level. Extremely high H2S concentrations require corrosion resistant and sometimes exotic metallurgies. Typically, a high amount of chrome in the metal is used to prevent the hydrogen from the H2S from entering the steel matrix, this, however, makes the metal much more expensive so it is typically only used when H2S or another corrosive substance is expected.

While attempting to circulate the H2S laden gas kick using constant bottom hole pressure methods, the mud gas separator overloaded. It’s not immediately apparent whether or not the mud gas separator was H2S rated or not or even a thin walled separator.

As the well began to come into control, while circulating, the drill string parted at around 1,000-foot depth. Some factors that can cause the drill string to part include rotating or reciprocating compounded with the risk or hydrogen embrittlement from the high level of H2S entrained in the gas. It is unclear whether reciprocating or rotating was used, however these are common practice because they are known to be effective against differential sticking when circulating out a gas kick.


With the move for operators to perform more factory style pad drilling, higher deviations at shallower depths are required in many of the newer Eagle Ford wells. This provides a similar situation to our example above where our productive horizon has possible H2S at around 9,000 feet true vertical depth with a risk for a shallow drill string part. While drilling for gassier zones in the south with a higher geothermal temperature gradient this can also exacerbate the effects of H2S and stress well control equipment.


While continuing to attempt to circulate out the H2S gas kick, the short, parted, length of drill string became pipe light and started lifting out of the hole. Calculations have been alluded to that the remaining length of string was heavy enough based on reasonable pressures. What is typically neglected but often needed when calculating pipe buoyancy in these cases is the friction of the fluid wellbore working on the drill pipe. This worked out later, after the well blew out the crew opened the pipe rams attempting to use gravity to get the short string to fall into the hole. Calculations said that the pipe was heavy enough, however when the friction from the fluid flow was added into the equation the pipe actually moved upward, sparked against the rig, and ignited the blowout.


Well control incidents where H2S has been released have been reported to the Texas Railroad Commission. From what we can tell, operators and contractors have been very good at making sure that their workers have adequate H2S training and certification yet the risk for a further H2S risk remains. Throughout South Texas, there are a large number of ranches and small municipalities that may be exposed in case of a large hydrogen sulfide release. The major cities of San Antonio and Corpus Christi are farther from the core Eagle Ford shale production, but could be potentially affected in the event of a large H2S release as well.


With high quantities of H2S gas being released from the well, there was protection put in place to protect the surrounding public from H2S exposure. H2S monitoring was put in place starting at the wellsite and then emanating outward toward populated areas to make sure that affected people would take appropriate protections against H2S exposure prior to actionable levels being reached. Contingency plans were put into place to make decisions about which actions are needed before those H2S levels are reached. The people living in the affected areas would have to be educated about H2S and educated about what actions would need to be taken once H2S reached a certain level. In this case, the media seems to have indulged in some H2S information that may lean more towards hype than what is taught in training about the real physical effects of H2S. The effects of hype and misleading information in media is understandable if one were to read coverage of oil industry events in the news today.


Technology has greatly increased our ability communicate with others about H2S training and other hazards. This can be a double-edged sword when an incident unfolds, however, so training about the effects and properties of H2S and other oil and gas hazards is best in order to be proactive. The more proactive the communication, the better chance there is to get the right message about H2S out. In the event of a large scale H2S release reaching an urban center similar to the H2S release at Lodgepole, we can expect hype from at least some media outlets.

In the oilfield there has been an increase in technology to drive down the cost of new production within Eagle Ford shale wells. Many of these methods can continuously increase the complexity of the completion and operations involved. Increasing complexity is troublesome for well control as tubulars are used that: do not mate with blow out prevention equipment as well, have ported opening that can complicate circulation, or now they can actually have dissolving components. With continuing development comes depleted reservoir pressures and the need for artificial lift. Again, artificial lift can contain tools that can hinder the use of blowout prevention equipment when not planned for properly. With the application of all this technology, and larger sized fracs, Eagle Ford shale new drills are producing more and more. These larger wells, when drilled in H2S endemic areas, contain a higher risk of larger release of H2S. The use of proper planning, training, and technology, however, can mitigate the increase of these H2S well control risks.


Recommended training: H2S Monitor San Antonio H2S Class


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