Casing failure mechanisms in geothermal wells

¶ … Abandoned Oil and Gas Wells

Geothermal Heat Production

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In "Geothermal Well Design, Construction and Failures," James N.A. Southon (2005) notes that the formation environment, for example, the presence of corrosive fluids, may cause a high temperature geothermal well to fail on the first heat up or contribute to a delayed failure. In this study, Southon presents a number of case studies from various geothermal developments in the Pacific -- South East Asia region, comparing large and standard diameter wells, to illustrate casing failure mechanisms and causes contributed to such failure.

Due to the high geothermal well temperatures, implementing code design requirements may not help reduce or eliminate the risk of casing failures. As the casing and cement utilized in the well constitute components in these type failures, manufacturers have developed design and construction techniques to minimize the risk of catastrophic failure of casing. In addition, Southon (2005) points out, studies confirm that using investigative techniques such as down hole video cameras reveals how failures may be categorized. Nevertheless, cement and casing design single-handedly cannot minimize the risk of failure.

Southon (2005) also investigates construction methods and contends that each oversight or even one slight deviation in implementing good construction techniques may cause casing failure. Southon identifies options used in geothermal wells, primarily "single string design and the use of the tieback liner arrangement" (Abstract). Compared to the cost of completing the well, when a geothermal well fails, the ensuing loss of production and repair cost may prove daunting. Along with comparing statistics of successful wells with those of failures, Southon assembles the statistics to present risk profiles for each design option and casing failure mechanism.

Table 1 summarizes failures of geothermal wells due to mechanisms common to them.

Table 1: Production Casing Failure Mechanisms (p. 1).

Casing Failure Mechanism

Conditions

Likely Depth

Casing implosion.

T and casing to casing entrapment of fluids.

Anywhere above shoe of outer casing (s)

Compression failure in casing

and/or couplings.

T and rapid heat up. Also an added condition is severe doglegs.

High temperature fields and shallow where ?T is greatest

Sulfide stress cracking.

Temperatures below 80 o C. And high stress areas.

Shallow with cold shut in conditions

Early (< 2 years) corrosion and/or casing holing (internal).

Sections with worn (thinned) casing or wells with very aggressive (low pH) production fluids.

For aggressive fluids the first sign of problems is corrosion at the well head.

Delayed corrosion (3 -- 5 years (internal))

Condensate level in shut-in wells.

At the water gas interface of shut-in wells.

Corrosion evidence after 5

years (external).

Corrosive fluid penetrating along micro-fractures in casing cement.

Any depth on the production casing

Microbial Activity and its Impact on Completion

Microbially induced corrosion (MIC), according to Lorenzo Martinez, L. Univ Nac Autonoma De Mexico, R. Torres, J.M. Sanchez Yanez and A.M. Vazquez (1996), all of the Univ Autonoma de Campeche, assert in the journal publication, "High temperature microbial corrosion in the condenser of a geothermal electric power unit," is currently recognized as an significant mechanism of material degradation. Martinez, Torres, Sanchez Yanez and Vazquez explain that "bacteria can grow in fluids with pH values as low as -1 and temperatures ranging from -20 to 99°C or higher. A variety of systems have been shown to develop MIC, including degradation in marine environments where sessile marine microorganisms colonize any surface" (Introduction section, ¶ 1). In turn, the resulting marine fouling facilitates the bacteria settling. Bacteria can grow and induce corrosion in water transport systems, as areas of stagnation and locations of low-flow velocity in metallic piping systems and storage occur.

In their study, Martinez, Torres, Sanchez Yanez and Vazquez (1996) present evidence of MIC in the condenser of a geothermal electric power unit, a reportedly unusual environment. The geothermal electric power unit works with steam at temperatures ranging from 40-150°C, with numerous components, including, but not limited to chlorides, sulfates, and iron. The he effect that corrosion and material problems may exert on production efficiency and downtime proves to be a vital consideration to the development of geothermal energy.

Peter A. Pryfogle (2005), Idaho National Laboratory, asserts in the journal publication, "Monitoring biological activity at geothermal power plants," concurs that microbial activity constitutes an operational issue in geothermal power plants that utilize evaporative heat rejection systems. Pryfogle explains that in geothermal steam plants, the condensed steam, as well as entrained liquid from cooling water, may contain impurities such as hydrogen sulfide, ammonia, carbon dioxide and a variety of dissolved solids. Although a considerable portion of these gases are eliminated from the condenser, some amounts partition into the liquid condensate used for cooling water makeup. "These dissolved gases, along with the dissolved solids, provide nutrition for microbial growth within the cooling water system. Some of the gases may require abatement in order to meet regulatory requirements" (Pryfogle, 2005, p. 1). An iron chelate, an organic acid, for instance, added to some systems to treat hydrogen sulfide dissolved in the steam condensate may also serve as a nutrient source for bacteria.

In a comparable manner, other chemical treatments applied to inhibit corrosion or scaling may also supply nutrients that encourage growth. The cooling water also cycles from reducing to highly oxygenated while being transported through the condenser and through the evaporative cooling system. Shifting from anaerobic to aerobic conditions influences biological activity as well. In addition, changes occurring in thermodynamic or chemical conditions may motivate microbial growth (Pryfogle, 2005).

Pryfogle (2005) further asserts that the consortia of microorganisms attach to the surfaces of critical components in geothermal cooling systems and form complex structures called biofilms.1 The development of biofilms can impact plant performance in a number of ways. Due to their relatively low thermal conductivity, biofilms add thermal resistance to the transfer of heat across the tube wall to the cooling water. (These films also have the ability to incorporate inorganic materials, such as calcium salts in the cooling water, stimulating their deposition.) As the biofilm accumulates on the tube wall, this material can rapidly become the dominant resistance to heat transfer. To offset this added thermal resistance a larger temperature difference is required to completely condense the steam. This larger temperature difference results in an increasing condensing temperature, which in turn increases the turbine exhaust pressure and decreases turbine power output; and consequently, plant revenues (Pryfogle, 2005, p. 2).

The majority of biological control strategies aim toward reducing the number density (cells per unit volume) of the bacteria present. Not all the bacteria in process streams, however, may prove damaging. Species of sulfur oxidizing bacteria, for instance, found in geothermal cooling tower basins, have been determined as capable to metabolize sulfide compounds and convert them to less toxic sulfate compounds. This may decrease the amount of chemicals needed for abatement. Ideally, an effective monitoring program would permit operators to "identify, track and control the 'activities', such as biofilm development or sulfur oxidation/reduction, of the microorganisms for the most cost effective mitigation of these problems in their plants" (Pryfogle, p. 3).

Waste Fluids

In the article, "Geothermal energy," Carol Stewart (2007) reports that the extraction process for geothermal fluids, such as gases, steam and water, for power generation generally eliminates heat from natural reservoirs more than 10 times the rate they may be replenished. One way to potentially improve this balance would be to inject waste fluids back into the geothermal system. According to Stewart, geothermal development may be significantly and irreparably, damage geysers, fumaroles (steam vents), hot springs, mud pools, sinter terraces, steaming ground, and other natural features. In addition, due to the underground contact between hot fluids and rocks, elevated levels of arsenic, boron, lithium and mercury may be found in geothermal fluid. If this waste is not injected into the geothermal field and instead "seeps" into lakes or rivers or lakes, the pollutants potentially damage aquatic life and make the water risky for drinking or irrigation.

Arsenic pollution, according to Steward (2007), constitutes a serious environmental effect of the geothermal industry. Geothermal fluids also releases dissolved gases into the atmosphere, with the primary toxic gases being carbon dioxide (CO2) and hydrogen sulfide (H2S). Both these gases, more dense than air, may collect in confined spaces, depressions or pits. Along with being identified as a hazard for people employed at geothermal stations or bore fields, they may also constitute a problem in urban areas. Nevertheless, geothermal extraction does not release nearly as much greenhouse gas per unit of electricity as burning fossil fuels, such as coal or gas, generate to produce electricity (Steward, 2007).

Lucas (2008) points out that all geothermal fluids piped up, albeit, are returned to the resource area through injection wells. As the injection wells extend to a depth to more than a mile, below the production zone and water table, cross contamination of groundwater systems is thwarted. Hydrogen sulfide, nicknamed "rotten egg gas" or "stink damp," colorless and somewhat heavier than air, constitutes another concern, as it may accumulate in low-lying areas of geothermal wells during temperature inversions or when prevailing trade winds are calm. "Individual odor thresholds range from 1 to 13 parts per million. Between 50 and 100 parts per million, it causes mild inflammation on the membrane joining eyeball and eyelid after an hour, loss of smell in two to 15 minutes and can burn the throat" (Lucas, ¶ 4-5). A person can tolerate a maximum concentration of 170 to 330 parts per million for approximately one hour without serious consequences. At 500 parts per million, however, the person loses reasoning and balance and possibly experiences respiratory disturbance. When a person is exposed to 700 to 1,000 parts per million for up to an hour, death may occur within minutes. Emissions In the journal publication, "A Guide to geothermal energy and the environment," Alyssa Kagel, Diana Bates, and Karl Gawell (2007), all of the Geothermal Energy Association, explain that the visible plumes rising from some thermal power plants consists of water vapor emissions (steam), not smoke. Geothermal power plants virtually do not release any air emissions as they do not burn fuel as fossil fuel plants. "A case study of a coal plant updated with scrubbers and other emissions control technologies emits 24 times more carbon dioxide, 10,837 times more sulfur dioxide, and 3,865 times more nitrous oxides per megawatt hour than a geothermal steam plant" (Kagel, Bates & Gawell, p. ii). Table** notes four significant pollutants that geothermal and coal facilities emit.

Table**: Average Geothermal Energy Production, 1990, 2003, and EIA Conversion Information (Energy Information Administration (EIA) cited in Kagel, Bates & Gawell, 2007, p. ii).

Geothermal plants do not directly emit sulfur dioxide, however after hydrogen sulfide is released into the atmosphere as a gas; it ultimately converts into sulfur dioxide and sulfuric acid. Consequently, sulfur dioxide emissions linked to geothermal energy evolved from hydrogen sulfide emissions (Kagel, Bates & Gawell, 2007). Currently, geothermal power plants routinely abate hydrogen sulfide, which results in more than 99.9% of the hydrogen sulfide from geothermal noncondensable gases being converted into elemental sulfur, which may in turn be utilzed as a non-hazardous soil amendment and fertilizer feedstock. "Since 1976, hydrogen sulfide emissions have declined from 1,900 lbs/hr to 200 lbs/hr or less, although geothermal power production has increased from 500 megawatts (MW) to over 2,000 MW" (Kagel, Bates & Gawell, p. ii).

Metallic, plastic

Valdez, Schorr and Arce (N.d.) stress that this equipment suffers from different forms of wear: erosion, abrasion, fatigue, disintegration, stress, aging, and particular wet corrosion. Several geothermal power plants in the Imperial Valley, CA use stainless steel, titanium alloy and cement-lined carbon steel tubes to prevent and/or minimize corrosion by acidic components and scaling by silica (Si02) in the casings of their geothermal wells. Silica is utilized as an additive for road pavimentation and roofing tiles materials. Calcite and aragonite scaling are frequently encountered in other countries geothermal well fluids. It is worthwhile to mention in the context of this work, the peculiar corrosion behavior of two salty water bodies: the Salton Sea, CA, and the Dead Sea ( called the Salt Sea in the Bible) Israel and Jordan. They contain an high concentration of mineral salts: 45g/1 and 280 g/l respectively. These massive desert seas, without a natural outlet, located at 60m and 400m below sea level, continually evaporate rising their salinity. As a result of this salt content, DO reach condition of hypoxia: 2 to 4 mg/l in the Salton Sea or anoxia: 0.1 mg/l in the Dead Sea. Therefore, the harvest of the solid Na, K and Mg salts in the evaporation ponds for the production of chemicals, fertilizers and Mg metal in Dead Sea Works plants is carried out by unprotected steel-made barges, pumps and pipelines without any practical corrosion (Valdez, Schorr and Arce N.d, p. 2).

Valdez, Schorr and Arce (N.d.) further explain that corrosion, scaling and fouling phenomena often appear simultaneously in equipment and installations handling geothermal wells and brines. Minerals scales and deposits, associated with brines composition and circulation, have a marked effect on corrosion. They occur in the brines depending on their physicochemical interaction with the equipment surface, the operational conditions such as pH (4 to 8), DO content (4 to 6 mg/l) flow -- regime and temperature (30 to 250 C). The mineral salt concentration affects the corrosion rate of carbon steel (Figure 1). The rate increases to a maximum at the concentration of seawater (3.5%) and then decreases nearing cero at the saturation concentration (25%) because DO content reaches a minimum value near zero (Valdez, Schorr and Arce N.d, p. 3).

Valdez, Schorr and Arce (N.d.) conclude that the cost of the aging infrastructure maintenance and repair are considerable and increasing. A recent NACE report estimated that 20 to 30% of this cost could be saved by application of corrosion control technologies. The principal means of corrosion control in the geothermal industry are correct selection of materials of constructions for equipment and structures, use of special paints, coatings and linings resistant to concentrated brines and cathodic protection by impressed current and/or sacrificial magnesium or aluminum anodes. Today, the main and fastest source of information on corrosion control of industrial equipment, plants and facilities is the internet Data bases and computer -- based expert systems, dealing with selection of materials, their properties and corrosion control for many environments and industries are listed in Roberge's Handbook (Valdez, Schorr and Arce N.d, p. 4).