Fluids management, accurate measurements boost solids control

Vacuum systems, thermal treatments reduce wastes as digital instrumentation paves path to optimization

By Joanne Liou, associate editor

Industry is placing more focus on solids control, recognizing that efficient solids control equipment provides an opportunity to cut costs associated with drilling fluid management, cleanup and disposal. Further, it’s more often being considered in early project stages, rather than being treated as an afterthought, as industry faces increasingly challenging drilling environments, as well as stricter regulations worldwide.

Approaching solids control from different angles, Apache Corp, Callon Petroleum, Cubility, FPUSA, Statoil and TWMA provide insight into innovative technologies and developments around solids control. Although improvements in key components, such as screens, continue to shape the traditional shale shaker, more advanced and out-of-the-box solutions are also being sought, such as ways to monitor fluid properties to further reduce drilling costs.

Innovating the shale shaker

The rising cost of oil-based mud (OBM) and a desire to minimize the waste stream continue to drive innovations in shale shakers and solids control, Danny Watkins, executive vice president at FPUSA, said. The company’s Vac-Screen System (VSS), which was launched in western Canada in 2010 before entering the US in late 2012, minimizes the waste stream by using a vacuum that creates negative pressure through shaker screens. The vacuum manifold installs underneath a shaker screen or attaches to the end of a shaker box, and it is compatible with most shakers available today.

“(The Vac-Screen) is rigged up on a primary shaker (at the rig site), so we take the last screen out of the shale shaker and install a metallurgical steel manifold under that screen,” Mr Watkins explained. With that manifold, a slight negative pressure through the screen is created with a vacuum through hoses, and the surface tension of the fluid on the screen is overcome to provide a dry screen for the cuttings to hit, instead of hydroplaning through drilling fluid. “This allows the cuttings to release the oil that adsorbed to them, which results in a significant decrease in the oil on cuttings when they hit the discard bin,” he noted.

The technology has been deployed on approximately 40 rigs in the Eagle Ford, the Wolfcamp, the Anadarko Basin, Granite Wash and Haynesville Shale. In Texas, where OBM costs approximately $150/bbl, recovery rates vary according to five primary factors: ROP, hole size, flow rates, number of shakers and screen mesh size. Generally, the VSS will recover 3 to 4 bbls per 100 ft of 8.75-in. hole drilled, but in some young formations, it has recovered more than 80 bbls in a day, according to Mr Watkins. A digital meter can be used to quantify the recovery rate.

FPUSA has completed field tests validated by third-party laboratories across the US since introducing the technology to this market in 2012 and continues to run tests with ongoing operations. Results show improved recovery rates compared with standard shaker screens and a 30% to 40% reduction of oil on cuttings, according to the company. In one test, a shaker was run without the VSS for 18 hours and pulled 12.5 bbls through the screens. The shaker was then run with the vacuum on for 18 hours and pulled 50 bbls through the screens.

In South Texas, the company said, the VSS has consistently minimized oil on cuttings by 30% to 40% over conventional shaker performance. “Retort tests (earlier this year) also showed a direct correlation between drilling rate and a reduction in oil on cuttings percentage,” Mr Watkins noted. “As drilling rates increase and the screens are flooded with drilled solids and fluid, the vacuum effect delivers higher rates of improvement over a conventional shale shaker.”

In West Texas, two operators using the VSS recorded a reduction in waste loads on each of their operations. Before VSS was deployed, the waste stream for a 7,500-ft lateral in West Texas generated approximately 24 to 27 OBM haul-off loads. The section where OBM was used included the kick-off point, the build and lateral. “With the use of the VSS, this has been reduced to between 18 to 20 loads, Mr Watkins told Drilling Contractor.

Callon Petroleum recently deployed the VSS in West Texas on nine  Wolfcamp wells on three wells pads, where they averaged 2,200 to 2,400 ft/day in the lateral section and showed recovery rates of 65 to 75 bbls/day. Russ Truby, drilling superintendent for Callon, said that sometimes the vacuum actually worked a bit too well.

While the goal was to create drier cuttings, the VSS sometimes resulted in cuttings that were too dry, making it a challenge to get the cuttings into the discard bin. “The cuttings were coming off so dry the roughnecks were having to shovel the slide from the shaker to the roll-offs continually,” Mr Truby explained. As a result, Callon moved the open top-box tracks (discard bins) closer to increase the slope on slides and installed polyurethane covers to help move cuttings off the shakers into the roll-offs.

FPUSA also has expanded application of the vacuum technology offshore and is currently on its fourth job. Most recently, the company partnered with a major service provider for two jobs on barge rigs in the Gulf of Mexico off the Louisiana coast. The main difference in offshore applications is integrating the VSS into a larger number of shakers, according to the company. “Typically land operations run two to three shakers, and offshore rigs can run anywhere from four to 10,” Mr Watkins explained. “We are still able to maintain a single vacuum to run a larger number of shakers, but the plumbing is more intricate.”

Decreasing footprint

Increasing throughput has been a focus for TWMA’s TCC RotoMill, a mobile thermal treatment unit for drill cuttings containing OBM. The largest current model can process up to 10 tons/hour, 24 hours a day. It was also a 950-kilowatt system when launched in 2001 but now can run up to 1,400 kilowatts within the same footprint. The processing temperature of the system reaches between 250°F and 260°F (482°C and 500°C) and is generated by mechanical energy to flash-evaporate the fluid phases of oil and water, Davie Garrick, TWMA director, explained. These fluids are then condensed and recovered separately throughout the process. No emissions are released during the process, and recovered oil can be recycled back into the drilling mud system.

The result is a dry, fine powder that typically retains less than 0.1% of hydrocarbons. “We’re actually getting the material prior to becoming a waste and treating that material to remove the hydrocarbons out of the material,” Mr Garrick said.

Noting a shift in attitude toward how cuttings are handled and treated, TWMA said companies are frequently considering solids control in the early project stages, not as an afterthought. This has given operators more options to effectively handle and treat drill cuttings, the company said.

This is especially important as many countries are tightening regulations. Angola, for example, is adopting a zero discharge policy. In West Africa, TWMA has been working with Glencore Exploration Cameroon in support of its regional drilling campaign offshore. Under this contract, TWMA delivered its first offshore thermal processing project for the energy industry in the region.

In the Middle East, TWMA has been assisting Zakum Development Co’s UZ 750 Project at Abu Dhabi’s Upper Zakum field. The goal is to increase oil production to 750,000 bbl/day by 2015 and sustain that rate for at least 25 years. TWMA’s five-year contract for this project, which commenced in December 2012, incorporates the design, commission and operation of an integrated environmental solution and reflects the emphasis operators are placing on environmental protection, Mr Garrick said.

The mobile onshore equivalent of the TCC RotoMill – the TCC RotoTruck – recently reduced its footprint, going from a two-trailer operation to one trailer through advances in the system’s cooling packages and electronic control systems. The technology has been commercial for approximately 15 years and is now being used in projects throughout Texas, Oklahoma and Pennsylvania and for the first time in Alberta and British Columbia, Canada. “Like most technologies, the TCC RotoTruck is getting smaller, lighter and faster,” Mr Garrick said.

Solids control equipment, drilling fluids management work in tandem for true efficiency

By Linda Hsieh, managing editor

As the industry drills increasingly deep wells with extended lateral sections, both offshore and in shale plays onshore, the role of solids control within the overall drilling process has become more critical than ever. Especially as operators push ROPs to drive performance, solids control systems must keep pace with higher flow rates. Further, they must do it while reducing costs, waste volumes and its operational footprint. One way to address such a tough challenge is to take a solutions approach that considers more than shakers and screens, M-I SWACO believes. In particular, the Schlumberger company understands that, in order to deliver true value, solids control systems must work in tandem with good fluids management.

“Our goal is really to maintain the properties of the drilling fluids at the optimum level,” Marc Kirschenbaum, business development manager for shakers, and mixing technologies for M-I SWACO, said. If you consider the multiple functions of drilling fluids – not just to bring cuttings to surface but also to control the formation pressure in the wellbore – it’s easy to see the vital role solids control plays in drilling optimization and wellbore integrity.

“These fluids are engineered for each application and for each lithology that you drill into. The integrity of that fluid and how it reacts to the different formations can create excessive waste at the drill site and keep bits from rotating efficiently,” Marc Francis, M-I SWACO director of global sales for ES drilling, said. “By keeping the low-gravity solids to a minimum , we can drill the well faster and with less nonproductive time.”

Solids control doesn’t happen in a vacuum, and the solutions approach also encourages M-I SWACO employees to exchange expertise with people in the organization’s drilling domain. The combined know-how from different disciplines can typically better support a drilling project’s overall objectives, Mr Francis said. Increasingly this also means getting solids control considerations into a project much earlier than well spud. “We are really a solutions provider driven by the need to reduce costs for both the operator and the drilling contractor and, at the same time, be able to meet environmental compliance issues,” said Gabriel Corcoran, solids control business line manager for M-I SWACO.

In many places today, for example, zero-discharge requirements mean waste has to be shipped or trucked away from the rig site. The less waste, the lower the associated costs. “That involves using efficient shakers with the best types of screens, and a solids control system engineered with the most efficient combination of centrifuges and dryers. The correct system will significantly reduce the cuttings volume that must be removed from the site,” Mr Corcoran continued.

Following the MD-3 triple-deck shaker, M-I SWACO recently introduced the MD-2 dual-deck shale shaker, which is under production at the company’s manufacturing facility in Kentucky. A key feature is the DURAFLO composite screens used with the new shaker. These three-layer screens combine a polypropylene frame with an internal reinforcing cage made of high-strength steel. “The screen is the ultimate component in the shakers, so providing very effective and efficient screens will have a significant impact,” Mr Kirschenbaum said.

The DURAFLO screens provide a flat-bed area that remains in continuous contact with the fluid, enhancing separation performance. “The flat bed is really the most effective platform to deal with higher capacities,” Mr Corcoran said. Although screen capacity is hard to quantify precisely given the multitude of factors that can influence any given operation, he notes that M-I SWACO has been able to double the capacity compared with older screens and shakers in some cases. This means that three to four conventional shakers could be replaced with just two higher-capacity units.

Extended screen life also has been recorded via a field trial using the DURAFLO screens with two MD-3 shakers. Out of a total 151 screens used to drill the 16,568-ft (5,050-meter) onshore exploration well in Oman, only four were scrapped due to wear. The remaining 147 were returned to the used inventory container. Excluding time to replace the three previous shakers with the two MD-3 shakers, time to complete the well was 127.75 days. This was 36.25 days fewer than planned.

Further, the company noted that, at the start of the 12 ¼-in. interval, a single shaker was able to process the well’s circulating volume with ROP ranging from 50 to 197 ft/hr (15 to 60 meter/hr) and flow rates of 872 to 925 gal/min (3,300 to 3,500 liter/meter). API120 size screens were used. The rig did not experience any mud losses due to screens overflowing.

In total, 2,799 bbls of cuttings were removed from the well. Including the four scrapped screens and the 36 screens on the shakers at completions, a total of 40 screens were consumed. Data from previous similar exploration wells indicated an average consumption of 115 screens per well for the three previous shakers. The DURAFLO screens also processed on average 287% more cuttings before being defined as “consumed,” according to M-I SWACO.

When screens do have to be replaced, the MD-2 shaker – similar to the MD-3 shaker – is making the task easier with a pneumatic screen clamping and sealing system. “With the push of a button or the turn of a lever, you’re able to load in the screens,” Mr Francis said. The system contains no moving parts, and the self-latching screens do not require any tools for installation. This means that personnel don’t have to climb inside the shaker or get into any uncomfortable or unsafe positions. “They can stay in one place on the discharge end of the machine – change all the screens, take the screens away,” he continued.

Mr Francis also emphasized that much work has been done on the shaker motions of the MD-2. “We’ve taken that linear motion and adopted an ellipse that gives you more of a rolling motion on the cuttings and a bit longer retention time on the screens,” he said. The new dual-deck shaker can switch between normal progressive and capacity balanced elliptical motions while drilling. Deck angles can also be adjusted while drilling.

“We’re all about providing flexibility,” Mr Francis said, adding that the MD-2 scalding deck uses the same screens as the primary deck. “This means that our customers can utilize that scalping deck to remove larger solids throughout the entire well, which helps to maximize the life of the screens on the primary deck.”

Looking to the future, M-I SWACO continues efforts to enhance automation and control of solids control equipment. “We see our clients talking about those things consistently. We’re listening to them and very much aware of their requirements and developing technologies in line with that,” Mr Corcoran said. Schlumberger’s acquisition of Geoservices in 2010, for example, brought with it technologies such as the CLEAR cuttings loading and wellbore stability surveillance service that continuously weighs cuttings as they come off the shakers. “By measuring what’s actually coming out of the wellbore, we can adapt our mud properties, solids control equipment and hole cleaning practices to positively impact overall drilling performance” Mr Francis said.

MD-2, MD-3 and DURAFLO are marks of M-I. CLEAR is a mark of Schlumberger.

Improving work environment

Taking a holistic approach to solids control, Statoil has maintained an increased focus on the reuse of drilling fluids and waste minimization since 1999. “Proper running and selection of solids control equipment is the main contributor to avoid excessive drilling waste being generated,” Tor Henry Omland, leading advisor at Statoil, stated. “If you can help minimize the amount of waste generated, you can show a direct fluid and waste treatment cost saving. Even more important is how proper running of solids control equipment contributes to more efficient drilling operations by keeping the drilling fluid in good shape at all times. Having competent people to run the equipment is therefore vital to any drilling operation.”

In 2005, Statoil initiated a feasibility study to help develop an alternative to

shale shakers – Cubility’s MudCube, which uses a revolving filter belt or screen rather than vibration to filter drilling fluid. With the vacuum conveyor system, cuttings are fed onto a rotating screen belt with a vacuum underneath the belt. Microvibrators reduce the yield stress and gel strength of the fluid, increasing separation efficiency. The equipment also enables remote monitoring and controls. Statoil completed tests offshore and onshore in 2010 and 2011.

The MudCube was launched for its first permanent installation in 2012 with Maersk Drilling, working for DONG and Talisman in the North Sea. Three MudCubes were installed on the Mærsk Giant, an ultra-harsh environment jackup, to replace four shakers. “The MudCube has a generally higher capacity than shakers,” which can handle a 17 ½-in. section with an ROP of 50 meters/hr, Asbjørn Kroken, vice president of engineering marketing and sales for Cubility, said. Maersk Drilling is currently drilling its fourth well with the system.

According to Maersk Giants’s rig manager Andreas Larsson, Maersk Drilling is using the MudCube to help meet regulations related to the work environment – noise and emission. “The work environment has dramatically improved,” Mr Kroken said. The MudCube removes the need for protective wear, such as earplugs and a breathing apparatus, since a vibrating shaker is not involved, and oil mist and oil vapor is eliminated.

Mr Kroken estimates that the life of screens on the MudCube is 30 to 40 times longer than those on a regular shaker. A typical North Sea well uses 100 to 150 screens, but only 10 screens were used for the MudCube over two wells, he said. Maersk Drilling, DONG and Talisman has seen a 90% reduction of fluid attached to the waste on the Maersk Giant, resulting in very dry cuttings. “This saved on the newbuild of mud because it’s not being wasted. It’s recycled,” Mr Kroken explained. “Now we have reduced the tonnage going back onshore by about 35% to 40%. They save on mud loss, reduced transportation and reduced treatment cost.”

An opportunity for operators and contractors to improve drilling performance is emerging in the field of “real-time” solids control efficiency monitoring, and at the center are more accurate and real-time measurements of multiple fluid properties to optimize drilling fluids management and reduce overall drilling costs. For example, excessive dilution is the direct result of inefficiencies in the operation of solids control equipment, which in turn drives up mud costs, dilution costs and waste management costs.

“Dilution will always cost more than it would if you had spent a little more money on the right solids control equipment to reduce the volume of dilution you need, which reduces the volume of wastes you have to manage,” Jason Norman, senior drilling engineer at Apache Corp, said.

Click here to read about how KEMTRON is simplifying solids control solutions.

To really capture the value of an optimized solids control system, however, involves investing in digital instrumentations that enable precise, real-time measurements of fluid properties. “I am very interested in innovative ideas and designs,” he said. By paying more in dayrates for quality solids control equipment, coupled with basic drilling fluid instrumentation, “we can reduce drilling times and significantly reduce direct mud additive costs, as well as dilution costs. This in turn gets us to TD in fewer days, which ultimately translates into placing more wells into production every year for the same capital cost. By properly managing the drilling fluids process using instrumentation, it is estimated that we can shave five days of drilling time from a standard 40-day well,” Mr Norman explained. “In my opinion, we can’t afford not to instrument our rigs.”

For the past six years, Mr Norman has been assembling a collection of off-the-shelf  instrumentation for the flowline, suction line and centrifuge to help optimize the solids control process. “If we can find all the instruments that can measure all our fluid properties in real time … a truly optimized process will be achievable,” he stated.

He has been using PLC technologies to monitor data more effectively to streamline the process and essentially eliminate the lag between conventional measurements and what is happening downhole in real time. As the cost of operations continues to increase, as industry takes on deeper waters offshore and where “well manufacturing” type of drilling programs are the norm, Mr Norman believes there is an opportunity for drilling contractors to better instrument their rigs in order to drill wells cheaper, faster and safer.

By adding instruments to the solids control equipment, the process can be measured, monitored and much more precisely controlled. Since there are only a few industry-accepted instruments, i.e., Coriolis meters, inline particle-size analyzers and inline rheometers, Mr Norman is searching for new technologies individually from outside industries, such as the food processing and chemical manufacturing industries. While standards and protocols to enable communication between digital instruments and PLC are widely used in other industries, such as the automotive industry, that have been using instrumentation for 50-plus years, there is still no industry-accepted guidance for such instrumentation in a drilling environment. In searching for instruments to apply to solids control equipment, outside industries have provided solutions. Finding the instruments is a challenge as dozens of instruments might be tested before finding the one that works.

High-capacity shakers save $65,000/well in South Texas study

Derrick Equipment Company recently introduced its Hyperpool four-panel shale shaker for drilling operations. The new shakers feature a screen compression system that uses retention pins to force the screen panel downward against the concave screen bed, producing positive and uniform screen-to-deck sealing. The system reduces screen panel replacement time to less than 45 seconds per panel, permitting complete shaker screen changes in under three minutes, according to the company.

In a four-well study, two Hyperpool shakers replaced three primary shakers and two drying shakers for a major operator in South Texas. Each well was designed for two casing strings with an 8.75-in. open-hole section ranging from 10,000 ft to 12,000 ft. Oil-based mud was used weighing between 11.5 lb/gal to 14.0 lb/gal. The Hyperpools averaged 15% dryer oil on cuttings than the original drying shakers, the company reported, and low-gravity solids concentrations averaged 1.8% lower by volume than on previous wells. Dilution requirements were reduced for the two-string well by 25% and saved an average US $65,346 per well in overall operating costs.

“This revolutionary shaker offers a significant step-change to the drilling process as exemplified by the substantial savings realized by both operators and contractors in their day-to-day drilling programs,” Mitch Derrick, president of Derrick Equipment Company, explained.

The single-side screen compression system is available in either left- or right-side operation. The drilling deck angle can be adjusted while drilling, which allows for performance optimization without interrupting operations. The screen deck angle can be lowered and raised from +2° to +8°, respectively.

The standard power source for the shaker incorporates Derrick Super G vibratory motors, which yield more than eight Gs of acceleration to the screen frame. The “greased-for-life” bearing system eliminates the need for any additional lubrication, reducing maintenance requirements and repair costs. Continuous sound output of the motors is 81 dBA. Optional Super G2 motors also are available. These feature a continuous oil-bath lubrication system at a reduced sound output of 78 dBA.

The Hyperpool shaker offers at least 40% more flow capacity over other equipment within the same footprint, the company emphasized. Fluid Centering Technology maximizes fluid throughput due to the machine’s concave screen bed design. The larger non-blanked API screen area, coupled with the elevated Gs, significantly increases capacity over conventional shakers, potentially reducing the number of shakers required while offering finer screening ability. The Hyperpool can be configured in three ways: primary shaker, mud cleaner or as a secondary dryer for further processing primary shaker discard.
Derrick, Hyperpool, Super G and Super G² motors are registered trademarks of Derrick Corp.

“I think it is important that all operators set aside some budget money to just source new instrumentation,” Mr Norman told Drilling Contractor. “The industry is changing, and the operators need to maintain control of it or the ‘low-cost solution’ will never become a reality. The operators need to own their own code, manage their own data. We need to be fully accountable for our own operation and process control, and instrumentation allows this control.”

Mr Norman has tested approximately 100 instruments for the measurement of all aspects of the drilling fluids process and found approximately a dozen that can measure with an acceptable level of accuracy and repeatability. The instruments were then further tested to determine lifespan and how that might be impacted in the field environment, with conditions such as vibrations and rig moves. Once an instrument passes the test, “we then write some control logic for the instruments, not so much for automation but to optimize the drilling fluids process,” Mr Norman explained. This is achieved by using the algorithms to collect real-time fluid parameters, such as density, pressure, temperature, rheology, water cut, particle size distribution, salinity and flow rate.

“We then use the PLC to provide an alarm/alert when a parameter falls outside of programmed specification. By minimizing the amount of mud dilution required, maximizing the amount of solids removed and minimizing the amount of waste generated, we were able to shave $100,000 per well off our mud bill,” he said, “and we are just getting started. We can measure dilution requirements in real time in order to achieve a zero balance.” Zero balance means the only amount of dilution added to the system is the exact dilution volume required to maintain a specific solids content dictated by drilling parameters and hole conditions.

Taking instruments from other industries, Apache has adopted a water-cut meter originating from the olive oil market, a rheometer from food processing and a particle size analyzer from paint manufacturing. Despite successes with these, however, Mr Norman said he’s still searching for non-intrusive instruments that have full open bore measuring capabilities. With non-intrusive instruments, “if you have a 12-in. pipe in your flowline, you don’t have a restriction in that 12-in. pipe; you have full open bore, and the measurement comes from the outside of the pipe,” Mr Norman noted. He is working with companies in Germany, Sweden, France and Australia on possible solutions, such as modifying a tool used to measure cookie dough so it can measure drilling fluids.

Mr Norman’s vision is to ultimately integrate the instruments into the rig itself so they can measure everything going in and out of the well in real time. This would involve putting the instruments on two spools – one for the flow line and another for the suction line. “If we build it into a spool piece and we build it right into a mud pump, then it would measure 24 hours a day without having any need for human intervention,” he explained.

Currently, Mr Norman has designed a spool to hold eight instruments measuring flow, density, rheology, particle size distribution, flow-water ratio, salinity, pH conductivity and electrical stability. Development is ongoing to consolidate the number of instruments necessary to measure the same parameters. Mr Norman believes the vision for an automated drilling fluids process will be much closer to reality with the testing work he is presently engaged in. “We’re going to be able to measure all of our fluid properties in real time and manage those properties so it’s a totally optimized process.”