Pushing the envelope in deepwater cementing

Reverse cementing, liquid additives are addressing narrow pressure windows and shallow-water flows, while new centralizers, subs are being engineered to get casing through increasingly tight restrictions

By Kelli Ainsworth, Editorial Coordinator

As operators continue exploring and developing deepwater resources, cementing challenges have increased exponentially due to the very narrow pore pressures and fracture gradients typically seen in deepwater wells. Not only do operators have to ensure they’re achieving the necessary zonal isolation and sufficient cement coverage, they’re also now dealing with increasingly thicker casing and the resulting tighter restrictions. Thicker casing has come about due to the industry’s desire to improve safety, said Iain Levie, Vice- President of Global Technical Services for Antelope Oil Tool. “Casing designs require more robust burst and collapse thresholds, so operators are moving toward thicker-walled casing.”

At the same time, operators are looking to maximize the final production string, said Tim Dunn, Well Construction Product Line Specialist at Weatherford. As a result, casing diameters are increasing, as well. “Casing sizes coming out now are pushing the envelope for the outer diameter (OD) to maximize the final production string,” he said. To get bigger and thicker casing strings deep into the well will require new technologies for cementing and running casing, he added.

In response to this challenge, service companies are developing close-tolerance slip-on centralizers and centralizer subs that can fully compress and allow casing to pass through tight restrictions – often with annular clearances less than half an inch – while still achieving good standoff when it enters the open-hole section below.

In addition, thicker casing is driving the development of sensors for cement evaluation that can accurately evaluate the cement bond. R&D efforts are also focusing on maintaining a low equivalent circulating density (ECD) to avoid exceeding the pore pressure and fracture gradient window. Innovative solutions, from reverse cementing techniques for deepwater to additives for lightweight cement, are also under development and will be commercialized later this year.

“Technology has progressed so much that we can drill in the most extreme environments, and the industry is constantly innovating and developing technologies,” said Crystal Wreden, Senior Technology Advisor at Weatherford. “So as drilling progresses, so will cementing equipment.”

Bringing reverse cementing to deepwater

The narrow pore pressure and fracture gradient windows common in deepwater wells often necessitate a lower bottomhole ECD while cementing to avoid taking losses. “Being able to reduce ECD during placement reduces your risk of exceeding the fracture gradient and breaking down the formation and losing cement,” Ms Wreden said.

Because conventional cementing techniques can require pressure that exceeds the fracture gradient in lost-circulation and weak zones, Weatherford has embraced reverse cementing in deepwater. Although the technique has been used on land and in shallow water, the CrossStream Subsurface Reverse Cementing system will be the first application of this technique for liners in deepwater.

The system, which remains under development, pumps fluid down the work string and diverts fluids into the lower annulus through a crossover tool. Returns are circulated up the inside diameter (ID) of the liner, and the crossover tool diverts them back into the upper annulus, resulting in a lower ECD bottomhole.

In conventional cementing, after cement is pumped down through the ID of the liner and then flows into the annulus, pressure is applied to lift the cement up into place within the annulus. “In the event that you have a weak formation and narrow pore/frac gradient, you run the risk that the pressure needed to place the cement conventionally will exceed your fracture gradient and you’ll break down the formation, then lose your cement,” Ms Wreden said.

The crossover tool, which is the heart of Weatherford’s reverse cementing system, can be set to a conventional flowpath or a reverse flowpath using radio frequency identification (RFID) tags. “One of the benefits of RFID is that it’s interventionless,” she said. RFID tags are programmed with a specific command for a specific tool and pumped downhole. When the tag reaches the tool its programmed for – in this case, the crossover tool – it will transfer the programmed command to the tools. “If you have the tool in a conventional position to run your casing in hole, you then pump down a tag to tell it to switch to the reverse position so that you can inject fluids down the annulus.”

Weatherford is currently running field trials on the CrossStream in the US, with additional field tests possible in Asia Pacific, West Africa and Brazil. The system is expected to become commercially available within 12-18 months.

In addition to developing technology to lower ECD when cementing, the company is focusing on how to achieve good centralization while running casing. As operators opt for increasingly thicker-walled casing to increase the casing’s collapse rating, it compounds the challenges around centralization, Mr Dunn said. “Well design requirements are  driving the OD of the casing further out and leaving very tight clearances,” he said. Centralizers need to be able to flatten to pass through these narrow restrictions, sometimes as narrow as 0.125-in., and then open up in the open-hole section with sufficient restoring force to give the required standoff, he explained.

In late 2015, Weatherford launched the VariForm line of bowspring centralizers to address the challenges of passing centralizers through increasingly narrow restrictions. These centralizers can be slipped onto the pipe and have the capability to nearly flatten during the run-in-hole through the previous casing before expanding in the open hole. The contoured bow profile reduces drag when running through casing.

The VariForm line also includes centralizer subs that are made up and run as an integral part of the casing string. They feature a profiled recessed area where the centralizer sits. As it runs through the restriction, it can be fully compressed into the recess. This means the OD of the centralizer does not exceed the OD of the casing. “If there’s anything your casing can pass through, the centralizer can pass through it, as well,” Ms Wreden said.

In 2015, the centralizer sub was run in a 3,000 ft of water in the Mississippi Canyon in the Gulf of Mexico. The well required an 11 ^7/8-in. casing to pass through a 12 ¼-in. previous casing before opening in the 14 ¾-in. open hole with a 60° deviation. The bowsprings on the centralizer sub collapsed into the recess, so the VariForm centralizer was able to pass through the ID of the previous casing. The bowsprings then expanded back out in the open hole and centralized the casing with a 70% standoff at a depth of 12,147 ft.

Proper centralization can reduce drag as one section of casing runs through the previous section. “When operators have problems running casing to total depth, it’s typically noted by an increase in drag because the pipe isn’t centralized; it’s being pushed down the hole against the pipe,” Mr Dunn said. “The drag forces create a lot of compression loading in casing and connections, so an operator’s ideal scenario is to minimize the amount of drag force generated when they’re running casing, especially in highly deviated wells.”

The VariForm centralizers have been shown to help minimize drag by providing good standoff. In February, the centralizers were deployed offshore Trinidad, where a casing string with a 9 ^5/8-in. OD was run through a 12 ¼-in. deviated wellbore. The centralizers provided 80% standoff and eliminated wiper trips, saving the operator 76 hours of rig time and an estimated $2.21 million compared with similar operations that required wiper trips.

Navigating tight restrictions

Casing sizes for deepwater wells are evolving, in particular as operators seek to increase their burst and collapse thresholds. As casing sizes evolve, so must centralizers. “Every time we have a different casing size, we have to build a prototype centralizer and test it,” Mr Levie said. “Over the last year and a half to two years, we’ve probably built and tested at least 200 different centralizer models as a result of those various casing sizes.”

In deepwater wells, narrow annular clearance and tight restrictions are common, and centralizer subs are often used because they do not add to the casing diameter. However, these subs can be costly and require being threaded to casing. Specially designed slip-on, or on-the-pipe, centralizers, which fit around the casing, can be up to two-thirds less expensive than centralizer subs and can replace the need for centralizer subs in some applications.

Regardless of which type of centralizer is used, however, they must achieve enough standoff in the hole to allow drilling mud to be properly displaced out by cement, so residual mud does not contaminate the cement and potentially impact the quality of the cement job. Achieving the necessary standoff can be even more challenging in deviated wells, where gravity will pull the casing to one side of the well. “If you don’t get good cement, you don’t get good isolation,” Mr Levie said. “You might have to go back in and squeeze cement, which could take several days and add substantial cost to the operations.”

Rotating casing can help it pass through tighter restrictions and aid in mud removal. Therefore, operators often seek out centralizers designed to enable casing rotation.

Antelope Oil Tool is focusing on developing on-the-pipe-solutions – slip-on centralizers for close-tolerance environments that add very little to the casing OD. “You have to have a centralizer that can compress down as it’s run through the previous casing section and then expand into the underreamed hole section in order to get the standoff that you need,” Mr Levie said. Although centralizer subs have historically dominated the market in environments with narrow clearances, Antelope said it sees an opportunity for slip-on centralizers to be used in  many deepwater applications as an alternative solution, when paired with a proprietary anchoring device.

In April 2015, the company introduced the CentraMax line of on-the-pipe-solution, bowspring slip-on centralizers and subs, which were engineered for close-tolerance environments with low annular clearance. “Our CentraMax centralizers are able to pass through annular spaces with clearance as tight as ^3/8-in. but still give sufficient restoring force in the underreamed section,” Mr Levie said.

Typically, bowspring centralizers are watermelon-shaped, but the company opted for a close-tolerance geometry. This allows the centralizer to achieve the desired running forces and stand-off requirements.

Welds, which are a potential point of failure in bowspring centralizers, have been eliminated in the design. “As the bow is compressed, a lot of force is transferred to that weld. So if there’s a place the bow’s going to fail, it’s most likely at that weld,” Mr Levie said. Rather than weld the bowspring to the collar, as is typically done, Antelope provides a single-piece design for its CentraMax centralizers.

Three models are offered. The PI1 is pushed into the restriction from behind with a limiting or anchoring device, and the PT1 is pulled into the restriction. The RT-1 is also pulled into the restriction but is designed so that the pipe can be rotated, utilizing an anchoring device in the middle of the end collars, which an operator might choose to do to help move the casing through particularly tight restrictions.

Earlier this year, the RT1 model was run during the primary cement job in the Gulf of Mexico, on the Walker Ridge field in 7,000 ft of water. The operator needed to run 16-in. casing through an 18.25-in. ID restriction at the supplemental hanger and through an 18.125-in. ID restriction at the 22-in. casing shoe track. The RT1 was fitted onto the 16-in. liner, which was run to 24,000 ft and centralized in a 21-in. underreamed hole with 22º of inclination. In the end, Mr Levie said, the operator reduced costs by an estimated 60% compared with running a centralizer sub.

When a slip-on centralizer is not an option in extremely tight restrictions, CentraMax also includes three models of centralizer subs that offer push-in, pull-through and rotating options. “Where there isn’t sufficient annular space between the casing that you’re running and the previous casing or some portion of the previous casing, then that’s where we would recommend running a sub,” Mr Levie said.

However, the company is still working toward developing slip-on centralizers for even-closer tolerance, with the goal of eliminating the need for subs. “Our biggest challenge is trying to find ways to address some of the tighter tolerances with our on-the-pipe centralizers.,” Mr Levie said. “That’s something we’re continually working on, trying to find methods of centralizing that don’t involve centralizer subs.”

Controlling pressure

In the surface interval of offshore wells, shallow-water flows from overpressured shallow sediments can be a challenge during casing and cementing operations. In deepwater, this challenge can be exacerbated because of the proximity of the overpressurized zones to the mudline, the relative water depth and deepwater drilling techniques. “When we go to cement across the section, we have to design a slurry that can keep the shallow-water flow in place and not let it penetrate or flow,” Simon Turton, Halliburton’s Strategic Business Manager for Cementing, said.

To combat the shallow-water flows, Halliburton has developed Deep FX-L, a liquid cement additive that enables the cement to reach critical gel strength in an average of 11 minutes and stem the shallow-water flows. It allows gel strength to build by virtue of the calcium-silicate-hydrate setting. Without the additive, Halliburton says, this would take hours. Critical gel strength is defined as 500 lb/sq ft.

“It’s assumed that when a slurry reaches that number, then it is impenetrable by gas, oil, water or by any other substance that might flow,” Mr Turton said. The additive has no known slurry limitations and can be used in both heavy and lightweight cements, according to the company.

The Deep FX-L additive has undergone field trials in the deepwater Gulf of Mexico, and Halliburton is currently commercializing this product.

The company is also developing additives to address challenges that occur further downhole. “We quite often find that the deeper we go, the lighter cement that we may need to use,” Mr Turton said. Lightweight cements with densities under 15.8 ppg are often used to achieve the lower ECD required to stay within the narrow pore pressure and fracture gradients common in deepwater wells.

There are a few ways to make a lightweight cement. The first is to add more water to the cement, but this can compromise the final properties of the cement, Mr Turton said. Adding a gaseous phase – using nitrogen, for example – can make a lightweight foam cement. However, there is often not enough space on the rig floor to accommodate the equipment required to add gas to cement. Such equipment includes tanks and potentially a nitrogen converter. The final option for creating a lightweight cement is to use a lightweight particulate additive.

Halliburton is preparing to launch a new lightweight particulate additive, Liquilite, later this year. It consists of hollow glass spheres suspended in a liquid phase and is added to the cement as it is going downhole. Existing light-weight cements use hollow glass spheres  blended in with dry cement before being mixed and pumped downhole. This creates an opportunity for the glass spheres to be crushed while  blending the cement and transferring the dry cement, especially as pressure is used for both of these two processes. Service companies then have to use additional spheres to compensate for glass spheres lost to crushing. With Liquilite, this crushing effect is avoided, allowing Halliburton to do away with extra glass spheres and, in turn, reducing the cost of the additive.

Both the Liquilite and Deep FX-L additives are added as the cement is pumped downhole, not pre-blended with the cement. This allows the operator to increase or reduce the amount of additive used on the fly, if needed. “If they don’t use it on the job, there’s no waste cost or disposal associated,” Mr Turton said. “It’s just the neat cement that’s left in the tanks and it can be topped off and then used on the next hole section.”

Halliburton’s Advantage-1 deepwater cementing unit, which was designed and built in 2015, can mix liquid additives into the cement as it’s pumped into the annulus. In addition to a 25-bbl, three-component mixing system, the unit features a six-pump liquid additive system with an automated metering and pumping unit. The PLC-based system can be run from a cabin that can be placed anywhere on the rig.

To ensure the system’s reliability, Halliburton built health diagnostics into the unit that perform predictive maintenance to alert the crew to any potential failures or issues before they occur. Diagnostic software monitors more than 300 parameters related to the system’s critical components and deliver alerts on any maintenance needs. “Reliability is a very important feature,” Mr Turton said. “The deepwater environment is one in which we need to operate perfectly every time we do a job.”

Measuring success

When it comes to evaluating the quality of a cement job, the density of the cement and the thickness of the casing can present challenges for traditional acoustic cement evaluation tools. These tools often either fail to properly detect the presence of lightweight or foam cements or perceive these cements as being poorly bonded to the formation or casing.

“Logging lightweight cement slurries has been a challenge in the industry for a long time,” said Rajdeep Das, Product Champion for the Integrity eXplorer cement evaluation service at Baker Hughes. On the flip side, these technologies can be confounded by heavy fluid, which interferes with the representative evaluation of the cement. Operators rely on accurate cement evaluation data to determine if cement has correctly bonded to the casing and formation and provided the needed zonal isolation. “It’s important for the operator to know if he has the zonal isolation to drill further,” Mr Das said.

In mid-2015, the company launched the Integrity eXplorer cement evaluation service, which uses electromagnetic acoustic transducers. These sensors generate and propagate shear and lamb acoustic waves along the casing itself, rather than through the borehole fluid, to provide acoustic measurements  of the cement bond to the casing. “This is the only type of transducer that can produce shear horizontal waves on the casing today,” Mr Das said. “These waves are the only true indicator of solids behind the casing.”

Operators commonly run into a problem when using traditional cement evaluation services to evaluate lightweight cement – which is often used in deepwater to minimize hydrostatic pressure in weak and depleted formations and in narrow pressure windows – or when cement becomes contaminated with borehole mud. Lightweight or contaminated cements have low acoustic impedance and, thus, can be misinterpreted as a partial or nonexistent bond by traditional cement evaluation services.

Today, approximately 30% of cement slurries used are lightweight while other cement may become contaminated during cementing. “The older-generation cement evaluation tools see this type of cement as a poor bond between the cement and the casing, which may not be the case,” Mr Das said.

When operators believe they’ve encountered poorly bonded cement, they often perform a squeeze job, which involves pumping a cement slurry and applying enough pressure to force it to fill any voids. “Using a service that can accurately evaluate these lightweight or contaminated cements saves our clients from performing any unnecessary squeeze jobs, which have been done a lot before because of the evaluation not being accurate,” he said.

The Integrity eXplorer’s electromagnetic acoustic transducers are the only type of transducers that are able to generate shear horizontal waves, according to Baker Hughes. Shear waves are better for evaluating lightweight cements than the compressional waves generated by conventional acoustic technology, Mr Das added. Shear horizontal waves are better able to detect the presence and amount of solids behind the casing. While traditional acoustic cement evaluation services often lose dynamic resolution at cement densities lower than 11 ppg, the Integrity eXplorer is reliable in densities as low as 7 ppg.

In addition, the transducers also generate lamb waves, which are able to detect the presence of a microannulus, a small micron-level gap between the cement and the casing. Most cement evaluation services would classify a microannulus as debonding in a regular run. “Correctly detecting it as a microannulus is very important, so that the operator can determine the need for any necessary remediation,” Mr Das said. Because traditional cement evaluation services would not be able to properly identify a microannulus, he said, operators would have to pressurize the casing and do an additional run to detect a microannulus. However, because the Integrity eXplorer’s transducers generate lamb waves, it can detect a microannulus in the same run as the cement evaluation.

Electromagnetic acoustic sensor technology also allows for quality cement evaluation in the presence of thick casing. “Deepwater is one of the prime markets where you use a lot of thick casing because of the high downhole pressure,” Mr Das said. “In terms of deepwater cement evaluation, I think that evaluating cement through thick casing is one of the biggest challenges that exists.” Thicker casing has a higher impedance to acoustic waves, which can be misinterpreted as the presence of greater amounts of cement. “The thicker the casing gets, the more critical it is to obtain accurate measurements of the annular material.  We believe this technology has overcome that hurdle and can provide the accurate measurements needed to be successful,” Mr Das said. DC

Variform and CrossStream are registered terms of Weatherford. CentraMax is a registered term of Antelope Oil Tool. Deep-FXL, Liquilite and AdvantageOne are registered terms of Halliburton. Integrity eXplorer is a registered term of Baker Hughes.

Epoxy resin sealant used to remediate failed barriers to improve life-of-well integrity

By Kelli Ainsworth, Editorial Coordinator

As the oil and gas industry continues to face financial pressure resulting from the low cost of crude, the historically resilient offshore market has complied by reducing new drilling activity and directing attention to existing assets. During this downturn, there has been a steady climb in activity focused on intervention and decommissioning. Potentially less obvious than the effort to increase output from existing producers, via intervention, has been the increased decommissioning and abandonment activity.

“This is likely a function of a number of things: availability  of personnel – previously in drilling – increased pressure from environmental regulators, and a reduced cost in rig rate and associated services … would seem to make this as good as time as any,” said Travis Baughman, Technical Sales Manager at CSI Technologies, a Wild Well Control subsidiary.

This increased activity in both well intervention and decommissioning has brought long-standing well integrity challenges back to the forefront. Working with old wells, whether through abandonment or recompleting/intervention, the repair of barriers that have failed over time is often required. These barrier types vary from compromised cement sheaths, leaks/cracks/holes in tubulars, packer leaks, etc. These particular failure mechanisms often exhibit very low injectivity and, subsequently, require low-volume, high-pressure treatment techniques.

This can be particularly difficult to repair when attempting to use a conventional cement. A cement slurry is a specific balance of liquid and solid components, which, once allowed to cure, create the desired solid mechanical barrier. Prior to cure, however, this balance of slurry components is susceptible to separation and contamination, which can ultimately compromise the treatment.

“Contamination is a leading cause of ‘low-volume’ remedial cement failures in any well configuration,” Mr Baughman said. “When you consider the increasing depths and restricted geometries of today’s ultra-deepwater drilling profiles, the risk of contamination is significantly increased.”    

ControlSEAL resin, designed in conjunction with Wild Well Control and CSI Technologies in 2005, was developed as a specific technology to mitigate these low-volume isolation challenges. Originally crafted as an urgent response to a hurricane season that resulted in downed platforms and damaged subsea structures in need of a high-performance sealant, the product has since found application in the intervention and abandonment industry.   

It is a hydrocarbon-based epoxy resin and is naturally immiscible in water-based fluids, demonstrating coalescing properties once static. These properties are critical to mitigate against the effects of contamination when small volumes are to be used. The product also demonstrates a Newtonian-type flow behavior and can be designed “solids-free,” allowing it to be pumped into tight places conventional cement systems would pack off. This allows it to penetrate deep into microannuli or microchannels where it will harden.

“ControlSEAL resin’s depth of penetration is significantly better than cement as solid separation known to occur across pressure drops or restricted flow paths does not alter the resin’s ability to achieve set mechanical performance,” Mr Baughman said.

The compressive strength of the resin is two to three times higher than that of conventional cement, while the tensile strength is four to five times higher in most cases. Because cements are particularly susceptible to tensile-stress failure, this particular mechanical property is specifically important. This, coupled with its innate chemical resistance, gives the resin advantages for improved life-of-well integrity compared with cement.

Resins have not replaced conventional cement systems, however. “I feel industry leaders are very diligent and responsible when it comes to modifying well construction/barrier techniques like that of casing and cement,” Mr Baughman said.

“In many minds, products like ControlSEAL are still very new. As technology continues to advance, we are now able to quantify some potential shortcomings in conventionally accepted cement systems while evaluating alternative materials for improvement. It is for this reason we are seeing a significant interest regarding the furthered evaluation and understanding of the ControlSEAL resin technology by industry leaders and regulators alike.

“As this information gap closes and the industry becomes more comfortable with the technology, I believe you will see an increase in use, like we are seeing now in abandonment and intervention operations, eventually coupled with conventional cement for primary well construction.”