A fluid situation
Hybrid OBM/WBM designs, flat-rheology systems among innovations in drilling fluids
By Katie Mazerov, Contributing Editor
The complexities of today’s oil and gas reservoirs demand new levels of sophistication for drill fluids, including fluids that improve lubricity and reduce risk and environmental impact. Hybrid designs that provide the operational performance of oil-based mud (OBM) and the environmental performance of water-based mud (WBM) are also sought, along with solutions for drilling through the narrow pressure windows of ultra-deepwater wells and materials that strengthen the borehole and provide stability in high-temperature and sour gas fields.
“Across the board, we are taking a more holistic view, looking at how fluid design can improve performance of the overall drilling operation – at the bit, with motors, rotary steerable systems, cement to achieve a good cement job and zonal isolation, and how the fluid works with logging-while-drilling tools to enable high-definition imaging,” said Brian Teutsch, Product Line Director, Drilling and Completion Fluids, for Baker Hughes.
For OBMs, which are still preferred in many unconventional plays, operators are seeking systems with more favorable rheological properties for greater lubricity. This helps to maximize penetration rates in the horizontal sections and minimize rotating torque, Mr Teutsch said. “Whereas operators have traditionally looked to motors, bits and pumping protocols to increase drilling efficiency in the unconventional plays, they are realizing that modifying the rheology of OBM can deliver a lot more efficiency by enabling additional flow rate and cuttings removal.”
The MPRESS invert emulsion system, introduced in early 2013, improves circulating pressure to allow higher flow rates and rates of penetration (ROP). It is suited for land operations using diesel OBM, challenging hole-cleaning situations or well paths that need maximum torque reduction. Operations where flow rate or circulating pressure is limiting drilling performance can also benefit. “With this system, we are seeing a boost in horsepower at the bit and an increase in motor torque without any further intervention from the operator other than the properties the drilling fluid system is imparting,” said Joe Szabo, Product Line Manager, Emulsion Fluids for Baker Hughes.
In the Granite Wash play, an operator converted a traditional OBM system to MPRESS after displacing the WBM in the upper hole section. As the system underwent conversion, the rheology improved, and the pressure-consuming viscosity decreased five units from 19 to 14 cP. This allowed an increase in flow rate and power transmission to the drilling assembly. The
system drilled 9,485 ft of open hole, including the 4,853-ft lateral section, to reach a total measured depth of 16,725 ft. Sliding rates were 25-50% higher than typically seen with traditional OBM systems, saving 10% in rig time. Both the lateral and curve sections were kept clean.
The NEXT-DRILL drilling fluid system can be formulated as a mineral oil and/or synthetic invert emulsion system to drill longer intervals with lower equivalent circulating density (ECD), less formation damage and less wear and tear on tubulars, according to Baker Hughes. A South Texas operator used this fluid system in six wells where severe breathing/ballooning problems had resulted in a 1,959-bbl mud loss using conventional drilling fluid. Mud loss declined in all the wells, and four of the wells showed no losses. Further, there were no ballooning issues, circulating pressure decreased, and the operator was able to achieve effective fracture gradients and greater solids tolerance for wellbore strengthening. This resulted in a 17% reduction in NPT.
High-performance WBMs provide environmental benefits yet are often not as simple to use at the rig site. To address that limitation, the LATIDRILL WBM system includes components designed to prevent sloughing shale and borehole enlargement.
For deepwater and other high-risk environments, Baker Hughes is field-testing a mineral oil and/or synthetic-based invert emulsion system. NSURE is designed to keep the rheology constant and predictable when temperatures vary widely between the bit and the riser, or cool down when the fluid is static, Mr Szabo added. The system is expected to be commercialized in late 2014 or early 2015.
An ‘eureka’ moment
Concerns regarding the use of OBMs, which are 80% diesel, have spurred development of a hybrid fluid system. Although advantageous in many formations, including high-temperature environments and very long laterals, OBMs have limitations, said Dr Buddy Gaertner, VP Business Development for ViChem Specialty Products.
“There is a misconception that using an OBM can solve all drilling problems by improving ROP and lubricity and reducing wellbore stability issues,” he said. “However, OBMs also have more stringent disposal requirements, and some evidence suggests they can increase the mechanical breakdown of shale.”
The use of emulsifiers in OBM can damage the pay zone, he said, by changing the formation from a water-wet to an oil-wet environment, leading to flow resistance. WBM, while not as effective in many drilling scenarios, is beneficial in controlling losses when it is pumped downhole, he noted.
In the Woodbine, an operator needed a fluid with benefits of both systems. To fill this need, ViChem developed the hybrid MHA (multi-hydroxyl alcohol)-based fluid. Since 2011, the fluid has been used to drill 50 wells in the Marcellus, Eagle Ford and Pearsall (southwest Texas) plays and the Permian Basin. It is now being field-tested in the Bakken. The Woodbine, located in the northern sector of the Eagle Ford, features a shrinking sand target flanked by shale formations that traditionally have required the use of OBM to drill the lateral sections. Landowners in the region, however, don’t want OBM used on their properties.
“We were having some luck in the area with various WBM formulations to drill laterals in the Woodbine sands, but in 2011, we established ViChem to reinvent the system.” The eureka moment came with the realization that heavy alcohols, which have some properties intermediate between oil and water, could be used in a WBM to incorporate a water-soluble hydrocarbon-base fluid, making it inherently different from conventional WBMs. MHAs are short-chain hydrocarbons similar to oil, which allow the fluid system to perform like an OBM while retaining its water solubility.
Earlier this year, the MHA base-fluid received the US Department of Agriculture (USDA) Certified Biobased Product Label, which verifies it meets or exceeds levels of renewable bio-based ingredient levels set by the USDA, or new carbon content derived from easily replaced agricultural, forestry or marine ingredients. “This is a green fluid system that has passed the tests of toxicity, biodegradability, safety and sustainability,” Dr Gaertner said.
The system has been shown to increase ROP and reduce time and costs over conventional WBMs, he said, while offering up to 98% of OBM performance. In the Woodbine, 40 wells with laterals between 6,000 to 7,000 ft and TD around 12,800 ft were drilled over a five-year period. The wells were drilled in the same formation with the same rig design, casing program and mud engineers at an average of 31 days per well using a conventional WBM.
In 2012, the MHA system was implemented in five subsequent wells. On average, the system drilled an additional 1,300 ft per well, increasing the lateral lengths to 8,000 ft and average TD to 14,100 ft. An average 11 days of drilling time was saved per well, according to ViChem.
Maintaining constant rheology
New fluid technologies are also targeting the challenging ultra-deepwater market. “Because the hydraulic window in ultra-deepwater wells can be very narrow, we need to have good control of the fluid properties so we don’t exceed the fracture gradients,” said Lee Conn, VP of Drilling Solutions for M-I SWACO, a Schlumberger company. This year, the company introduced the newest generation of its flat-rheology drilling fluid system, the RHELIANT PLUS synthetic-based drilling fluid system. It maintains optimum viscosity with temperature fluctuations that occur in the formation and riser and facilitates better hole cleaning, faster tripping and improved cementing operations.
“Traditionally, fluids were designed to become more viscous as the fluid temperature in marine risers cool, which increases overall pressure and ECD that often exceed the fracture gradient of the well, resulting in lost circulation,” Mr Conn explained. With greater temperature range flexibility, the RHELIANT PLUS system does not have that viscosifying effect.
This fluid system was recently launched in the Gulf of Mexico (GOM) and West Africa, where well depths commonly exceed 30,000 ft, bottomhole pressures exceed 20,000 psi and temperatures range from 300-375°F. An operator in Angola used the system to maintain flat rheology while optimizing hole cleaning in a high-pressure, high-temperature (HPHT) deepwater well. The system drilled the 17 ½-in. and 13 ½-in. sections and was then conditioned for the 8 ½-in. production section. Casing was run to the desired depth in one run in all hole sections, with the cement jobs completed with no losses.
In operations with narrow fracture windows, a growing trend is applying wellbore strengthening technology and specially sized materials to fluids; this can help to reduce downhole losses in drilling-induced fractures. The I-BOSS (Integrated Borehole Strengthening Solutions) wellbore strengthening technique seals and isolates fractures from further elongation and subsequent reopening, saving time and cost in drilling through depleted zones, according to M-I SWACO.
For the ultra-high temperature market, the RHADIANT ultra-HT drilling fluid system uses a high-temperature emulsifier and fluid loss agents to deliver improved fluid thermal stability characteristics, enhancing wellbore conditions. The system also has produced more efficient logging responses in wells where bottomhole temperatures approach 500°F. The system was implemented for an exploration well in the Gulf of Thailand, where bottomhole static temperatures up to 453°F was expected, along with high carbon dioxide and H2S.
This fluid system provided filtration control and excellent filter cake quality with stable rheological properties while drilling the 6 1/8-in. interval with no lost circulation or drilling problems. Seven open-hole wireline logging runs were performed with minimal issues over more than 90 hours.
Mr Conn noted that drilling fluid manufacturers continue to utilize alternative weight materials for drilling narrow hydraulic pressure windows. “On these types of applications, a critical feature of the drilling fluid design is that it must deliver a low ECD to minimize the risk of fracturing the wellbore, resulting in a lost-circulation incident.”
The WARP drilling fluid system, which uses micronized weighting agents, works to minimize ECD, resulting in less stress on the wellbore. The technology also can address barite sag, caused when barite gravitates to the low side of the hole, resulting in well imbalance. The smaller particles settle at a much slower rate, enabling the use of low-viscosity, high-density fluids. The system has been used effectively in the GOM and the North Sea to drill depleted zones in older wells.
Seawater-based fluids are valuable, Mr Conn added, because they provide flexibility to use the most economical water source available, especially in remote regions. “We see a number of our customers coming back to using water-based technology due to logistical constraints of supporting non-aqueous fluid systems in remote locations, as well as reduced environmental requirements associated when using water-based drilling fluid systems,” he said.
Changing the paradigm
Baroid, a product service line of Halliburton, is directing research and development dollars to develop solutions for the unconventional, deepwater and mature field market segments. “When designing a new fluid technology, it needs to have at least one of those core markets for consideration,” said Julian Coward, Strategic Business Manager for Baroid. “Typically, customers look at two areas for improvement when applying new technology on their assets. Firstly, they are looking to do the same for less cost. Secondly, they are looking to apply new game-changing technology to gain better access to reserves, drill in areas that have been inaccessible in the past or to meet more stringent environmental regulations. It ultimately depends on the operating company’s propensity for technology adoption.”
Baroid has several new technologies in various stages of development. The BaraPure system, which recently completed field trials for a major operator in an unconventional field in Alberta, Canada, provides a clay-free OBM. 
It replaces the necessity for salt with a biodegradable, hygroscopic internal phase. “With this system, we’re designing an OBM that performs more like a WBM,” Mr Coward noted. The technology is expected to be fully commercialized by the end of the year.
For the deepwater sector, the BaraECD system is an engineered fluid system with unique chemistry designed to control ECD in narrow-margin wells. “The BaraECD system is engineered to provide a low-ECD fluid that maintains a constant rheology at temperature and pressure while suspending weighting material, such as barite. This provides operators with the ability to drill more technically challenging wells, where rig spread rates are high and lost circulation and other wellbore issues are costly to remediate,” Mr Coward said. The system has been used in the GOM and recently was deployed on a challenging well in Norway.
A GOM operator also used this system to overcome several challenges, such as stuck production liners, lost returns and well control problems, in a high-angle deepwater well. The fluid’s rheological profile provided low, controlled ECD and low viscosity while maintaining adequate suspension properties to resist sag and prevent stuck pipe at the high angle. The system enabled drilling to continue in the narrow window, with no HSE incidents or NPT resulting from the fluid services.
In a second case, the fluid was used during a cementing job in a deepwater GOM well, where the operator had been experiencing losses due to low-pressured sands. The low-viscosity design created a fluid with a lower ECD than that of the cement. The operator was able to run the production liner with 100% return and the cement with a 90% return, eliminating the need for a liner top squeeze and saving more than $1 million in rig time.
Baroid is also engaged in a long-term project focused on providing operators with the capability to understand fluid properties in real time. This automated mud-monitoring system will have real-time capability to treat and correct fluid properties to an optimum level without the need for manual intervention. The first phase of the three-stage development is anticipated to be completed and commercialized by the end of 2014, Mr Coward said.
Ongoing innovation
Improving the economics of the drilling process, especially in the horizontal plays, has been a driver in Newpark Drilling Fluids’ R&D efforts to improve lubricity and fluids monitoring. Last year, the company introduced improvements to its water-based drilling fluid system, Evolution, in response to operators’ concerns with the cost, performance and environmental impact of diesel-based systems.
“We’ve adapted the Evolution system to work in brine-based fluids and achieve the same lubricity as OBM,” said Harry Dearing, VP of Technology and Marketing for Newpark. “In North Dakota, the system is being used with produced water (low-viscosity brine) as an alternative to OBM, reducing overall costs and improving drilling rates by about 50%.”
In the Wolfcamp play in West Texas, where brine drilling fluids have been used routinely, the improved lubricity provided by Evolution products is allowing operators to use brine to achieve the required density to 10 lb/gal. “In oil mud, this is achieved by adding commercial solids, such as barite. These solids increase cost and reduce drilling rate,” Mr Dearing explained.
In the Wolfcamp C formation in the central Permian Basin, the enhanced system was used to drill and run casing on a three-well project to measured depths of 14,560 ft, 14,614 ft and 14,645 ft. Using the Evolution brine, the operator drilled an average of 1,524 ft/day in the lateral and an average of 640 ft/day for the entire project. This represented a reduction of six days per well compared with offset wells using OBMs. Costs for the second and third wells were 45% less than the initial well due to the storage, treatment and reuse of the fluid. The operator has continued to use the system in other wells, according to Newpark.
Innovation is continuing with the original Evolution system, as well. In the Spraberry play in the Permian Basin, operators are using an enhanced Evolution freshwater system to achieve low fluid density and avoid lost-circulation issues. “Historically, low-density diesel muds were used but at great expense to the operator,” Mr Dearing noted. “This same technology is being adapted for use offshore, where lost circulation is especially problematic in depleted reservoirs where there is a narrow margin between mud density and the formation fracture gradient.”
At its new technology center outside Houston, Newpark is researching methods to improve monitoring of all lubricating qualities of drilling fluids. “The way we currently measure friction doesn’t cover all the frictional forces that occur during the drilling process,” Mr Dearing explained. “As operators transition from drilling 3,000-ft laterals to 7,000- or 10,000-ft laterals, the requirements for fluid lubricity increase.”
Newpark tests the lubricity of the drilling fluid, correlates lubricity to drilling performance and maintains lubricity within targeted ranges. “This gives customers more consistent performance than running fluids based on concentrations of additives,” Mr Dearing said. “If we know we’re achieving the targeted performance, we don’t need to adjust product concentrations.”
A Six-Sigma project recently analyzed the correlation between variations in lubricity measurements and fluid products. “If the measured coefficient of friction is within the statistical variability of the measurement, we continue to maintain the drilling fluid as planned rather than make unnecessary (and costly) additions to modify the friction coefficient,” he said.
MPRESS, NEXT-DRILL, LATIDRILL and NSURE are trademarked terms of Baker Hughes. RHELIANT PLUS, I-BOSS, RHADIANT and WARP are marks of Schlumberger. BaraPURE and BaraECD are trademarked terms of Halliburton. Evolution is a registered term of Newpark Drilling Fluids.
