Gas blowouts

According to the Illinois Environmental Protection Agency (IEPA), a series of gas blowouts has occurred at two waste injection wells in the state (Brower et al., 1989). In each case, well operators were injecting concentrated hydrochloric acid into a dolomite bed. At its plant near Tuscola, the Cabot Corporation injects acid waste from the production of fumed silica into the Cambrian Eminence and Potosi Formations below 5,000 ft (1,500 m) depth. Allied Chemical Corporation injects acid into the Potosi formation below about 3,600 ft (1,100 m). The acid, which is contaminated with arsenic, is a by-product of the manufacture of refrigerant gas. Since some of the blowouts have caused damage such as fish kills, there is environmental interest as well as operational concern in preventing such accidents. 

The blowouts seem to have occurred at times when especially acidic wastes were being injected. The acid apparently reacted with carbonate in the 

We can use reaction modeling techniques to test the conditions under which dolomite will react with hydrochloric acid to produce gas in the injection zones. Equivalent values of wt.% and molality for HC1 are  

To configure a model of the reaction of dolomite with 30 wt.% hydrochloric acid, we start REACT and enter the commands 

We then repeat the calculation for solutions of differing HC1 contents, according to the chart above. 

The first step adjusts the fluid s C02 fugacity to the atmospheric value, reducing pH to less than 10 by the reaction, 

After this step, dolomite appears only slightly undersaturated in the calculation results. In the second step, which simulates reaction of the formation into the equilibrated fluid, only about 2 x 10 5 cm3 of dolomite dissolve per kilogram of waste water. This result suggests that the plant s waste stream could have been neutralized inexpensively by aeration. 

The blowouts seem to have occurred at times when especially acidic wastes were being injected. The acid apparently reacted with carbonate in the formations to produce a C02 gas cap at high pressure. In some cases, the injected waste was more than 31 wt.% HC1. As a temporary measure, the plants are now limited by the IEPA to injecting wastes containing no more than 6 wt.% HC1. 

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There is some disagreement as to which parameter is most critical to gas blowout. Based on analysis of C02 phase behavior at different temperatures and pressures, Kamath and Salazar181 concluded that gas blowout becomes hazardous if the temperature of the injected HC1 exceeds 88°F. Panagiotopoulos and Reid182 concluded that HC1 concentration is the critical factor and that HC1 concentrations exceeding 6% will evolve C02 gas and create a blowout hazard. Both sets of investigators explained the circumstances of this case study in terms of their respective models. 

The most acidic solutions, as expected, produce the greatest CO2 fugacities. For the 30 wt.% fluid, the partial pressure of CO2 escaping from the fluid would approach 250 atm. Assuming a confining pressure of about 120 atm at the Allied well, solutions containing more than 15 wt.% HC1 are likely to exsolve CO2. The calculations indicate, on the other hand, that even the most acidic waste can be injected without fear of a gas blowout if it is first diluted by an equal amount of water. 

SINTEF, STF 88A82062. Risk of Oil and Gas Blowout on the Norwegian Continental Shelf. SINTEF, Trondheim,... 

Even when the water is shallow, it is not safe to send divers down because the structure may collapse while the diver is in the water. Moreover, if the wellhead has not been properly secured, a gas blowout could occur at any time—once more posing a great risk to divers in the vicinity. This means that ROVs (remotely operated vehicles) have to be used. (One estimate is that 85% of the remediation work is done by divers, the rest by ROVs.) Explosives are rarely used because of the potential impact on turtles and other marine creatures. Chemicals, including diesel fuel, that were on board the facility at the time of the platform collapse pose an environmental hazard and can be a safety hazard for divers in the area. 

It was notoriously difficult, however, to link HSE culture to major accident risks and process safety in any clearly communicated manner. In the fall of 2004, a serious gas blowout occurred on Statoil s Snorre Alpha platform. A catastrophic outcome was avoided only by chance, and by a hazardous rescue operation by the remaining crew. Poor HSE culture appeared as an important contributing factor in several post-event accounts, including a thorough investigation report commissioned by Statoil, as well... 

A few hours later a gas flow was observed in the well and the annular safety valve on the BOP was thus closed. The pressure under the BOP increased after it was closed, but soon after the well began to lose mud. Because of leaks in the 9 5/8-inch and 13 3/8-inch casings, the well pressure came in contact with formations behind the 13 3/8-inch casing, which then burst. There was gas under the platform outside the casing protection and the situation escalated with a gas blowout on the seabed. The well control operations became extremely diEcult and dramatic, but ultimately the eontrol of the well was restored. 

So far we have looked at conditions around gas blowouts at Snorre A in November 2004 and Gullfaks C in 2010 - that is, the sequence of events and analysis of causes and actions taken afterward. Now it is time to discuss whether the incident on Snorre A actually has relevance to what happened at Gullfaks G. 

In the aftermath of the gas blowout on Snorre A in 2004, Statoil carried out a major process whereby large parts of the organisation were involved in the interventions. Both technical and organisational measures were implemented. Most recommendations, however, were implemented in general and the Impact Report (2007) gave predominantly good testimonials on how the measures were received and evaluated. 

This gas blowout can be classified as a very serious near miss. Although no one was injured at the Snorre A blowout and there was no environmental or economic loss, the potential for catastrophe was high. 

Even when the water is shallow, it is not safe to send divers into a downers and leaners situation because the unstable structure may collapse while the divers are in the water. Moreover, if the wellhead has not been properly decommissioned, a gas blowout could occur at any time—once more posing a great risk... 

In the event of a sudden loss of mud In an Interval containing overpressures the mud column in the annulus will drop, thereby reducing the hydrostatic head acting on the formation to the point where formation pressure exceeds mud pressure. Formation fluids (oil, gas or water) can now enter the borehole and travel upwards. In the process the gas will expand considerably but will maintain its initial pressure. The last line of defence leff is the blowout preventer. However, although the BOP will prevent fluid or gas escape to the surface, closing in the well may lead to two potentially disastrous situations ... 

It generally is recommended, and often required, that gas dcicciiuii systems be installed in a fail-safe manner. That is, if power is disconnected or otherwise interrupted, alarm and/or process equipment shutdown (or other corrective action) should occur. All specific systems should be carefully reviewed, however, to ensure that non-anticipated equipment shutdowns would not result in a more hazardous condition tlian the lack of shutdown of the equipment. If a more hazardous situation would occur with shutdown, only a warning should be provided. As an example, a more hazardous situation might occur if blowout preventers were automatically actuated during drilling operations upon detection of low levels of gas concentrations than if drilling personnel were only warned. 

Add weighting material to rise density. Thin mud with water and thinners. Use degasser to clear gas from mud. Continue to circulate and avoid use of blowout preventers if possible. 

A blowout, which is the continuous flow of oil or gas to the surface through the annulus, is the result of a lack of sufficient bottomhole pressure from the column of circulating fluid and proper well head equipment. 

The hazard of well blowout is greatest if hydrochloric acid wastes exceeding certain temperature and concentration limits are injected into a carbonate formation. When carbonate dissolves in acid, carbon dioxide is formed. Normally, this gas remains dissolved in the formation waters at deep-well temperatures and pressures, but if the temperature exceeds 88°F or acid concentration exceeds 6% HC1, carbon dioxide will separate from the formation waters as a gas. The resulting gas accumulation can increase pressures to a point where, if injection stops or drops below the subsurface carbon dioxide pressure, a blowout can occur. 

Leahey DM, Schroeder MB. 1986. Predictions of maximum ground-level hydrogen sulfide concentrations resulting from two sour gas well blowouts. J Air Pollut Control Assoc 36 1147-1149. 

Flares are sometimes used after knockout drums. The objective of a flare is to burn the combustible or toxic gas to produce combustion products that are neither toxic nor combustible. The diameter of the flare must be suitable to maintain a stable flame and to prevent a blowout (when vapor velocities are greater than 20% of the sonic velocity). 

Most gas pressure parameters for vented HE explosions apply for open vents and the special venting configurations developed for suppressive shields (Refs. 17 and 19). If vents are covered with blowout or frangible covers, the peak gas pressures are essentially the same as in unvented structures, but venting times and gas impulses can be altered (increased), depending on the vent area, mass per unit... 

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