Microbial Fouling of Oil and Gas Wells Causing Corrosion.
One of the major concerns in the oil and gas sector is corrosion. This is often linked to the sulfate reducing bacteria (SRB). One reason for this is that the very reductive conditions encourage the SRB to generate hydrogen sulfide (H2S) gas. This gas is not only very stinky ("rotten egg" odor), but also will start off the process of electrolytic corrosion which can rapidly corrode steel. There is another group of bacteria that can also cause corrosion. These are the acid producing bacteria (APB). Under the same very reductive conditions that the SRB operate in, the APB can begin to degrade organics with the releases of short chain fatty acids that can also be corrosive. This activity happens when there is water present in the oil or gas and can be detected using the two barts designed to detect the aggressivity of SRB and APB in the water. Both of these BART™ tests are described in the section on the BARTs and so this site will be used to describe particular protocols expressly for the oil and gas industry.
SRB-BART™ test.
The first problem is that the water sample may contain hydrogen sulfide (H2S) gas. If there is gas in the water sample at greater than 20ppm then there is a possibility that the tests will react to that gas causing a precipitation of the black sulfide that is taken to indicate a positive. To vent off the surplus hydrogen sulfide (H2S) gas from the water sample, add 30ml of the sample to the outer tube for the SRB-BART™ test. Cap the outer tube without the inner test vial inside and shake the outer tube for ten seconds. This will cause the hydrogen sulfide to move out of the water sample into the air. Allow 20 seconds for the water sample to settle down and then add 15ml of the water sample to the inner test
vial (up to the fill line). Drain the remaining water sample from the outer test tube and insert the inner test vial back in and screw both caps down tightly.
Examine the test on a daily basis and there are three reactions that can be observed. These are:
• Blackening in the Base of the BART test (BB reaction). When this happens it means that the bacteria have been growing under very reductive conditions. If a CL reaction also occurs before (more commonly) or after (rarer) the BB reactions then this would indicate that the SRB are associated with other bacteria growing in a biofilm.
• Presence of black specks growing in a slime around the ball (more commonly on the underside than right up at the water line, as a BT reaction). This reaction is rarer in the oil and gas wells but does occur when the SRB are growing in less reductive conditions where there is some organic matter that is causing heterotrophic bacteria to grow. The reason for the BT reaction is that there is a slime-like biofilm formed under and around the ball and, once this has formed, conditions are now sufficiently reductive to allow the SRB to grow dispersed through the biofilm slime. Generally, these black specks form at only one or two locations but then rapidly spread as black speckles throughout the slime. Eventually a black band will form around the ball and the blackening may extend through out the bart (BA reaction).
• Cloudy growths (CL reaction) that are usually white but can sometimes be colored yellow, pink or orange. This reaction does not indicate the presence of SRB but does indicate that there are anaerobic bacteria in the water sample. Some of these bacteria may be APB and so the APB-BART™ test should be performed at the same time as the SRB-BART.
The time lag to the observation of the reactions is critical to understanding how serious the corrosion problem is relating to the biogeneration of hydrogen sulfide (H2S) gas. If there is a short delay before a positive detection (BB, BT or BA) of less than 5 days, that means that the SRB are very aggressive and likely to generating corrosive levels of gas. If the time lag to seeing a positive reaction is in the 6 to 8 days then the SRB are moderately aggressive. Time lags of greater than 8 days indicate a low level of aggressivity. There are a range of treatment strategies that are sometimes used to control SRBs in corrosive waters. If these treatments are effective, this will be observed in increases in the time lags to a positive detection occurring in the water sample taken after treatment. It should be remembered that water samples taken straight after a treatment are likely to be unreliable since there may be high populations of displaced and highly aggressive SRB in the water! A minimal time lapse before post-treatment testing for the effectiveness of a treatment should be at least 14 days after the treatment with 42 days a suitable lapse period.
APB-BART™ test
The acid producing bacteria grow in waters which are reductive and also contain organic material that can become fermented with acidic products. These products are usually the shorter chained fatty acids that cause the water to become mildly acidic (pH commonly ranging from 4.2 to 5.8). The APB-BART requires that the ware sample to be tested has a pH of at least 5.8 in order to ensure that the test can be reliably conducted. Water sample known, or thought to have, pH values of less than 6.2 should go through the following pre-treatment steps using the outer tube of the APB-BART:
1. Add 30ml of the water sample to the outer tube which is then capped.
2. Shake the tube gently for five seconds. This will allow the acid neutralizing chemicals time to dissolve in the water and bring the pH up by 2.0 units.
3. Allow the water to settle for 20 seconds.
4. Pour 15ml of the water sample into the inner test vial (water up to the fill line with the ball floating) and screw cap back on. Invert the tube for ten seconds to allow the dried reagent in the cap to dissolve in the water turning it purple.
5. Tip the residual water out of the outer and place the inner test vial back into the outer and cap. Observe daily for signs of acid production (purple color moves to a yellow - dirty orange). Note time lag to this event.
APB are highly aggressive if there is a positive detection of these bacteria in 4 days or less. Moderate aggressivity occurs when the time lag is between 5 and 8 days and a loss level of aggressivity occurs when the time lag is greater than 8 days.
There are a range of treatment strategies that are sometimes used to control APBs in corrosive waters. If these treatments are effective, this will be observed in increases in the time lags to a positive detection occurring in the water sample taken after treatment. It should be remembered that water samples taken straight after a treatment are likely to be unreliable since there may be high populations of displaced and highly aggressive APB in the water! A minimal time lapse before post-treatment testing for the effectiveness of a treatment should be at least 14 days after the treatment with 42 days a suitable lapse period.
Corrosion costs money, time and failures. Preventative maintenance using the APB- and the SRB- BARTs can save that money and time and also prevent failure through the appropriate treatment applications. The effectiveness of these treatments can be monitored using the BARTs judiciously after treatments. It has to be remembered that it is virtually impossible to "sterilize" a gas or oil well and so the bacteria will keep coming back. Preventative maintenance can provide a tool to control these invasions and minimize the consequences.
Microbial Fouling of Oil and Gas Wells Causing Plugging.
Plugging means the a well is losing its production because there is not enough conductivity into the well as a result of biofilms growth with subsequent encrustation and slime formations. It is a common experience for oil and gas wells to begin to lose their production capacity long before the reserves around the well have become exhausted. The general thought of bacterial plugging around an oil or gas well would sound far fetched given the extreme environments that exist at those locations. However, what would appear extreme to humankind may not, in fact, be extreme for the bacteria that have an almost infinite ability to adapt as a community!
The bottom line for plugging is that liquid water has to be available for bonding into the complex slime structures to form the "living quarters" for the microbes involved in the plugging. Oil even if it has only 0.1% water content can be literally "mined" for the water by the bacteria that grow within the oil in complex structures. Under some circumstances, the bacteria also use the paraffins and anthracenes (P/A) from the oil to coat these complex structures. When this P/A builds up (like a black goop), the wells production shuts down. To illustrate this, an example is given from some oil well fields in western Saskatchewan, Canada. Here, the rods going down the wells clog up with the P/A. This black goop gets thicker and thicker until the well stops functioning. In some experiments ran in 1997 and 1998, there was a body of evidence that shows this P\A black goop was really supporting structures for bacterial growth.
Finding an answer to the P/A problem
It was postulated that the P\A was simply a mass of paraffins and anthracenes that had become bioaccumulated around and within biofilms. To determine this, some P/A plugged 2" steel distribution pipe was treated with the surfactant CB-4. This surfactant has been used for years in the water well industry as a part of a technology to rehabilitate plugged water wells. CB-4 has a superior ability to attack and destroy the polymeric structures that support the biofilm particularly when the temperatures are elevated 40 or 50oC. The other factor is that the CB-4 becomes biocidal once the concentrations are raised above 0.7%. This technology therefore used a combination of heat and biocidal strength surfactant to attack the P\A black goop. At 57oC it was found that the P\A (left) become unstable and sheared away from the walls leaving the pipe clean again (right).
To examine the potential to clean up the rods coated with P/A from a well, two coated rods were treated. One (right) with just water that was heated up and the second with a CB-4 solution (left) heated at the same rate.
The rod being heated with the CB-4 solution discolored quickly and there was a significant swelling of the P/A compared to control. By 48oC, there was signs that the P/A was beginning to collapse and oil was oozing out from the black goop.
By the time the temperature reached 57oC, all of the black goop (P/A) appeared to have been stripped from the rods which were now clean. In field trials the treatment was so successful that the original manufacturers markings could be read.
What was surprising was the thick P/A plug that collected on the water lines as a thick disc. This disc was twice as thick where CB-4 had been used compared to the control indicating that the CB-4 had indeed increased the rate at which the P/A had been stripped from the rods.
Even more remarkable was the fact that on the underside of the plug, there was a mass of bacterial debris that had floated up the water column more slowly than the P/A and so collected on the underside. Photomicrography revealed structures that have also been seen in rusticles from the RMS Titanic and also from plugging water wells. Three basic structures were observed in the biological debris under the P/A disc. These included:
Thread like structures:
Sheath (Tube-like) structures:
Clusters of spherical (wax-like) structures:
This work suggests that bacteria may play a major role in the plugging of oil wells. CB-4 and the application of chemicals with heat is patented as the blended chemical heat treatment (BCHT™, ARCC Inc., Daytona Beach, FL) and this research was conducted under the sponsorship of Nautilus Explorations and Associates Ltd., Regina, Saskatchewan, Canada.