Ceramic coatings can prevent corrosion

Corrosion has long been the bane of the oil industry. Now new approaches and coatings are resolving the difficulties and providing intriguing possibilities for offshore pipelines, explains Tony Collins of EonCoat.

In the oil and gas industry, corrosion accounts for over 25% of failures, according to a recent National Association of Corrosion Engineers (NACE) International report. Corroded pipe repair or replacement costs the industry over US$7 billion per year, based on estimates from NACE. This figure can double when lost revenue, productivity, and spill or leak cleanup costs are tallied.

As deepwater exploration accelerates, protecting offshore pipelines from seawater corrosion is becoming more vital than ever to preserve deeper and more costly oil and gas assets. While offshore pipelines supplement corrosion protection with cathodic protection, the main defense against corrosion remains external pipeline coatings, particularly fusion-bonded, epoxy-powder coatings.

"Corrosion is a major industry challenge," says Scott Justice, Tank Division operations manager of Bolin Enterprises Inc. (BEI), a Casey, Ill.-based pipeline and tank maintenance contractor serving the oil and gas industry.

While traditional corrosion protection has relied mostly on short-lived, physically-bonded coverings of substrate surfaces such as tapes, elaborate three-part coating systems (zinc, epoxy, and urethane), and cathodic protection, these merely attempt to lengthen the time before the steel asset inevitably rusts.

Now a growing number of proactive, oil and gas industry maintenance professionals are turning to a new category of tough, chemically-bonded, phosphate ceramics (CBPC) that can prevent corrosion, extend equipment life, and minimize the cost and production downtime required to recoat, repair, or replace corroded equipment.

New approach

"What caught my eye about [CBPC coating] was its unique adhesion and chemical properties," says Justice, who visited Wilson, N.C.-based EonCoat LLC to view its corrosion testing lab, processes, and procedures for its CBPC coating. "If its hard outer shell is breached or knocked off, it still has corrosion protection where traditional coatings do not. Whether its coating is aged, beaten, or banged around, it still protects the surface. If you remove the outer ceramic shell, the chemical bond with the substrate still stops corrosion at the surface."

In contrast to typical paint polymer coatings that sit on top of the substrate, the anti-corrosion coating bonds through a chemical reaction with the substrate, and slight surface oxidation actually improves the reaction. This makes it impossible for corrosion promoters like oxygen and humidity to get behind the coating the way they can with ordinary paints. The corrosion barrier is covered by a true ceramic shell, which resists corrosion, fire, water, abrasion, chemicals, and temperatures up to 1000°F.

While traditional polymer coatings create a film structure, which mechanically bonds to substrates that have been extensively prepared, if gouged, moisture and oxygen will migrate under the coating's film from all sides of the gouge. Moisture and heat are then trapped by the film, creating a "greenhouse effect," promoting corrosion and blistering. By contrast, the same damage to the ceramic-coated substrate will not spread corrosion because the steel is essentially alloyed. Its surface oxides have been converted into an inert, electrochemically stable metal incapable of supporting oxidation.

Ceramic coatings such as this consist of two, non-hazardous ingredients that do not interact until applied by a plural-component spray gun like those commonly used to apply polyurethane foam or polyurea coatings. Since the components are not mixed and do not meet prior to application, the need for hazardous volatile organic compound (VOC)-generating ingredients is eliminated, as are hazardous atmospheric particles and odor. This means that the work can be done in occupied areas.

"The results of the corrosion tank test were impressive," says Justice. Among the corrosion tests frequently run by the manufacturer of the CBPC product is one where the ceramic coating has gone more than 10,000 hours with no corrosion in a salt spray ASTM B117 test. "If the coating works as well as we hope, it could help to stop or minimize corrosion and extend the longevity of a range of oil and gas assets," adds Justice.

Independent electrochemical corrosion potential testing of the CBPC product also indicates its usefulness for offshore pipeline corrosion protection. Steel plates coated with EonCoat were placed in a beaker of saltwater by Dr. Ki Yong Ann, Dept. of Civil and Environmental Engineering, in a lab at Hanyang University, Seoul, Korea. When voltage was run through the solution and the corrosion rate determined by measuring current leakage across the coating in ma/sq m, the coated plates were found to have no corrosion potential. Any result below "2" is considered to have no corrosion potential, and the coated plates tested at 1.15 the first time, and 0.85 the second time.

For submerged offshore pipeline applications, an anti-fouling topcoat can be added to the CBPC coating, which enhances appearance and reduces barnacle growth.

Unlike organic, carbon polymerbased paints and coatings, which may give a foothold for corrosion causing microbes to grow, ceramic coatings are completely inorganic, so they are inhospitable to mold or bacteria. "Since EonCoat is inorganic, it cannot sustain mold or bacteria growth," says Justice. While not widely considered, the Achilles heel of many traditional corrosion coatings may be in how exact the environmental conditions must be during their application to meet specifications.

"A lot of coating products fail due to changes in temperature, humidity, dew point, and other atmospheric factors during application," says Justice. "As conditions change seasonally throughout the year, it can be difficult to provide perfect coating conditions."

Protective ceramic coatings can be applied on hot or cold surfaces, from 40-150°F in 0-95% humidity, excluding direct rain.

"Since the ceramic coating takes changes in temperature, humidity, and dew point out of the equation during pplication, it can be reliably used in tough environmental conditions that might otherwise compromise the corrosion protection of typical coatings," says Justice.

Cutting downtime

Shane Bartko, a director at TKO Specialty Surfaces, a Calgary, Albertabased tank, pipeline, and structure maintenance contractor, has used the ceramic coating for corrosion control on a variety of oil and gas projects. "To keep a corrosive coating working well, you want one that will be resistant to high temperature, abrasion, chemicals, UV sunlight, and other environmental factors," says Bartko.

The time saved on a corrosion coating project with ceramic coating comes both from simplified surface preparation and expedited curing time. "With a typical corrosion coating, you have to blast to white metal to prepare the surface," says Bartko. "But with the ceramic coating, you typically only have to do a NACE 3 commercial brush blast." Bartko explains that on coating projects using typical polymer paints such as polyurethanes or epoxies, the cure time may be days or weeks before the next coat of three coatings can be applied, depending on the product. The cure time is necessary to allow each coat to achieve its full properties, even though it may feel dry to the touch.

In contrast, ceramic coating is applied in a single coat, with almost no curing time necessary. Return to service can be achieved in as little as one hour.

"With the ceramic coating for corrosion protection, we're able to get facilities back up and running right away after spraying, sometimes in an hour," says Bartko. "That kind of speed in getting an oil and gas facility producing again can potentially save millions per day in reduced downtime. It makes sense to use the ceramic coating anywhere steel is used and may corrode, from pipelines and processing to storage." OE

Tony Collins is CEO of EonCoat, LLC, concentrating his time on commercial applications of Ceramicrete technology. Collins founded Turbine Generator Maintenance, Inc., an independent service provider for gas and steam turbines, in 1986 and sold it in 2007, after amassing customers in 47 states and 15 countries. Collins earned a BS in Mechanical Engineering (1978) from Georgia Institute of Technology.

Managed-pressure drilling riser stack integration

As the deepwater prospects being drilled today address ever more complex conditions, the drilling industry needs to adjust its technology to address the challenges that arise.

The use of conventional "open to atmosphere" drilling methods cannot identify and respond to some of the well events that are encountered in time to prevent them from becoming an issue that in many cases can result in the need to abandon the well.  For example riser gas, which occurs when a gas influx entrained in an oil-based mud breaks out of solution as it is circulated to the surface. This typically occurs about 2000-3000ft below the drill floor, at which point the gas is above the blow out preventer (BOP) in the riser and beyond conventional containment.  The gas can be vented by using the rig diverter system, but this practice is implemented as the very last step in an emergency response and is uncontrolled. One advancement in rig technology used to try and regain control in a situation of gas in the riser is the riser gas handling (RGH) system. Although RGH offers some element of control, it still adopts a reactive approach that does not offer a solution designed to prevent the gas from ever entering the riser.

Closing the loop

Integrating a below-tension-ring (BTR) rotating control device (RCD) into the riser permits the closing and pressurization of the annular returns flow, a key component for MPD. Photo: Weatherford.

Another approach is to integrate a rotating control device (RCD) into the rig's upper riser package, enabling the drilling loop to be closed and pressurized. This integration allows for the installation of a managed pressure drilling (MPD) system that monitors mass flow (flow into and out of the well), providing precise early detection of a hazard, and introduces a means to employ swift preventative measures before a situation escalates into a potentially catastrophic scenario.

One example is detecting an influx wherein an unexpected overpressure zone is encountered, resulting in an influx of reservoir fluid into the wellbore. The MPD software detects the imbalance and calculates what the equivalent mud density should be to balance the well. Automated chokes react to apply surface back pressure, repressing the influx and allowing the driller the time to apply the safest means of circulating the influx out of the circulating system.  MPD is a proactive process that circulates drilling fluid within a contained, pressurized system geared towards riser gas prevention as opposed to conventional drilling circulating systems that are open to the atmosphere and require a reactive human response.  The main components of an MPD riser stack system are:

• A rotating control device (RCD), which creates a pressure tight barrier in the wellbore annulus thus enabling containment and diversion of returning fluids.
• An MPD annular preventer–necessary when replacing the RCD element during a constant bottomhole pressure (CBHP) MPD mode and allows for riser gas handling if drilling open to atmosphere (without the RCD element).
• A flow spool–required during RCD installation to divert returns flow to the rig via a flexible armored hose or gas when drilling in a conventional open to atmosphere setting (no RCD bearing installed).
• An MPD/diverter manifold–required to apply different MPD techniques.
• Surface control system(s),–required to operate the aforementioned components as part of the MPD operations.

Combined, all MPD riser stack components should be automatically controlled by a central intelligent control unit responding to the unique wellbore signals being monitored, including return flow, to enable immediate detection of changes in fluid flow.  This can provide instantaneous detection and response enabling drilling decisions to be made before they escalate to an uncontrollable level.  
Traditionally, the RCD is installed atop the BOP, but on a deepwater vessel, a more sophisticated RCD can be installed below the tension ring as an integral part of the marine riser system. Within the closed loop created by the RCD, changes in pressure are easily detected and effected, while pressure and mass-flow measurements provide real-time data that generates manual or automated changes in choke settings.  Manipulation of the MPD choke manifold leads to changes in annular backpressure at the surface, which immediately increases or decreases downhole wellbore pressure.

MPD in its various forms, presents the possibility to operate in any of the following modes:

• Pressurized mud cap drilling (PMCD), which can be used to drill formations where total circulation losses make conventional circulatory methods impossible.
• Constant bottomhole pressure drilling (CBHP), which for deepwater operations provides the precise wellbore pressure control required to navigate extremely narrow drilling windows between pore pressure and fracture gradient. The ability to dial in and hold a specific downhole pressure without changing mud weight provides a high degree of control and a first response to many pressure-related problems.
• Returns flow control.
• Dual-gradient drilling (DGD)

MPD-enabled rigs
An MPD riser stack, integrated with the purpose of MPD operations, will be the foundation for the future development of floating rigs able to effectively address the challenges of ever-deeper drilling horizons. It enables drilling modifications in three key segments:

• Riser gas handling
• Early identification of downhole flow anomalies such as a kick, loss, breathing or ballooning events.
• A proactive suite of managed-pressure drilling (MPD) methodologies that are bringing non-traditional solutions to complex deepwater drilling challenges such as dealing with uncontrollable losses or navigating narrow pore and fracture pressure windows. 

Despite the success of MPD systems, and the potential they present, their use aboard semisubmersibles and drillships is limited by a host of cost, personnel and deployment constraints on the equipment caused by older rig designs. Extending these MPD advantages to a broader scope of deepwater wells can offer safety, operational and economic rewards, however equipment deployment can be hampered by the inability of deepwater drilling vessels, originally built for conventional open-to-the-atmosphere circulating systems, to readily accommodate it.

RGH/MPD manifold, permanently built into the rig and designed to function as MPD. Photo: Weatherford.

Future developments
Fully realizing MPD benefits in deepwater applications requires a focused industry effort to develop guidelines, procedures and standards for equipment procurement, rig modification and design and perhaps most importantly adequate training for rig personnel.  In the move towards a degree of MPD readiness, modified rigs will have enhanced RGH systems but to go to full MPD capability more upgrades are generally required.  In newly built rigs these needs can be readily addressed; however in existing rigs they can be problematic.

Addressing the problem of MPD readiness will mandate a degree of cooperation across the spectrum of the industry. The most obvious means of achieving this would be for the E&P companies to create the demand by requiring drilling contractors to standardize the integration of a RGH system,  not for riser gas handling as the primary task, but capable of incorporating an RCD (MPD riser stack) for the greater purpose of MPD operations. The greater value to the industry will be an MPD-enabled rig capable of efficiently operating under the daily procedures required during MPD operations once the circulating loop has been closed by the installation of the RCD element. An excellent example of this approach was the design of a newly built drillship which incorporated MPD as part of its capabilities to operate offshore Angola where total mud losses frequently occur.  The success of the project was the result of a collaborative effort between operator, contractor and service company. The installation of a few minor components in the MPD riser stack and rig surface equipment, enabled the rig to rapidly transition from "open to atmosphere with RGH" to full MPD capability thus providing a step change in the rig's capabilities – a transition process that saved 12-14 months rig up time.

In future it may be appropriate to promote a system where increased industry access to MPD capabilities would be driven by mandates set by local and international governing bodies as part of their assessment of  applications for deepwater drilling permits. In lieu of such commitments, a coordinated effort as described is required between the E&P companies, drilling contractors and service companies to create an MPD infrastructure and commitment to it in order to facilitate the ability to drill what would otherwise not be possible.

About the authors

Written by  Guy Feasey and Neal Richard, Weatherford Monday, 09 June 2014 18:18

Guy Feasey is Weatherford's global business development manager. Neal Richard serves as a MPD technical manager for North America at Weatherford.