Drilling/Frac Fluids

New, Environmentally Friendly Technology Using water-based fluids rather than oil-based muds goes far in demonstrating environmental stewardship while saving operating costs.

By Jerry Greenberg, Contributing Editor

nvironmental stewardship is one of the most popular reasons given by service companies and operators for developing new drilling mud and fracturing fluid formulations for use in the various shale plays around the US. It also is one of the reasons for development of a portable closed-loop system for recovering reusable oil-based fluid, which, in one case, reclaimed 77% of the available oil in the original drilling fluid volume. e environment was one of the reasons for a new water-based drilling fluid system developed for the Haynesville play, and a crosslinked fracture fluid that works with flowback and produced water that is used primarily in the Bakken Shale in Canada. Cost is always a factor, and many of these new drilling and frac fluid systems can save operators money by reusing water; eliminating potentially expensive trucking costs to transport contaminated freshwater or reclaimed water; and disposing of oil-based drill cuttings. At the same time, lower transportation costs usually mean fewer trucks through towns and reduced dependence upon local water sources, which is especially important in water-intensive shale plays where water is scarce.

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Water-based fluid for the Haynesville Shale Newpark Drilling Fluids recently launched a water-based drilling fluid system initially designed specifically for the challenges of the Haynesville Shale. e company is investigating its applicability to other shales. e clay-free formulation, dubbed Evolution, eliminates thermal instability and contaminant issues that have plagued conventional water-based fluids. Two components, EvoVis and EvoLube, provide the basis for the new system, which was developed from the ground up.

Baker Hughes’ Viking II PW fluid mixed from iron-rich source water. (Photo courtesy of Baker Hughes)

Drilling/Frac Fluids

The EvoVis viscosifier offers the appropriate viscosity to achieve barite suspension as well as hole cleaning and optimal rheology while also providing an inhibitive coating to drill cuttings. EvoLube drilling lubricant results in high ROPs in long horizontal production intervals. “The Haynesville imposes three basic demands on a drilling fluid,” said Del Leggett, director of client relations for Newpark. “Those demands are extremely high bottomhole temperatures, the presence of contaminants whose effects are aggravated by that high temperature, and the need for a great deal of lubricity for the long lateral section.” Meeting those demands in the Haynesville historically required the use of oil-based mud, the fluid of choice for the shale play due to its high-temperature stability and lubricity as well as its resistance to the effects of contaminants. Operators in the region, attuned to environmental stewardship as well as costs, were seeking an alternative to oil-based mud to meet the challenges effectively with an eye also on economy and logistics. “The environmental aspect of a water-based mud was near the top of the reasons for its development,” Leggett said. From a logistics point of view, water-based mud is simpler compared with an oil-based mud, Leggett noted. For example, oil-based mud is mixed at a remotely based plant and trucked to the well site. Used mud is trucked back to the plant and cuttings have to be disposed at an approved site. Water-based mud reduces costs and liability of disposing the fluid and cuttings. The cuttings can be returned to the land because the two main contaminants in oil-based mud – diesel oil and salt – are eliminated. The company began developing the application-specific water-based drilling fluid for the shale first by examining the geology and what is required to drill the particular shales. The company learned that while the Haynesville Shale requires less focus on fluid composition designed to inhibit hydratable clays that adversely affect wellbore stability, there are the challenges of high temperatures, contaminants, and lubricity. “Most Gulf Coast shales require a highly inhibitive drilling fluid to stabilize the well bore and prevent it from caving in,” Leggett said, “but that is not as critical an issue with the Haynesville, based upon its relatively low concentration of hydratable clays. “We developed and designed the fluid system to address all of the true challenges while still being aware of, but not concentrating on, issues that don’t exist in specific fields, such as inhibition (in Haynesville). That approach provides more latitude in system design.”

The RECLAIM mixing system extends the life of oil- and synthetic-based drilling fluids while reducing disposal and environmental costs. (Photo courtesy of M-I Swaco) Newpark did not design the system to mimic oil-based mud characteristics in a water-based system. “One of the things we identified when developing the system was: do we need a waterbased mud that works like an oil-based system, or do we need a water-based system that does the job?” Leggett asked. “There is a difference. “We designed the system to do the job,” he added. “The only things important to mimic were lubricity, extreme thermal tolerance, and resistance to contaminants found in that specific geology.” The company is investigating use of the water-based fluids system in other shale plays as well as conventional oil and gas fields in North America. The characteristics of the shales vary widely, and the system as it is presently designed is better suited to some plays than others. Newpark is looking to expand its use in other shales including Fayetteville, Barnett, Marcellus, Bakken, and Eagle Ford. “We are in the process of evaluating those shales to match system formulation to the geology of a particular geographic location,” Leggett said. “We want to be careful not to misapply the system, and we believe we can tweak the formulation and enhance some of its characteristics to get the system ready for other shales.

Drilling/Frac Fluids

solids in a non-aqueous fluid and remove them by centrifugation. During the fine solids removal process, fluid from the active drilling operation or from a storage location is transferred to the unit feed pump, which moves the fluid to the mixing system. At this stage, surfactant and flocculating polymer are added to the mud in predetermined concentrations through variable frequency drive injection pumps. The surfactant reduces the emulsion stability of the mud and water wets the solids, allowing the polymer to adhere to the fine solids. e flocculated mud stream is fed into the high-speed centrifuge, where virtually solidsfree recovered oil is returned to the active mud system or storage tanks. e solids stream, which contains the flocculated solids and a portion of the water phase, is discarded from the centrifuge and disposed. M-I Swaco also developed a pilot test unit for determining the optimum surfactant and flocculant concentrations for specific fluid. A scaleddown decanting centrifuge and chemical mixing system predetermines the optimal amount of chemical treatment and establishes expected recoveries and project performance. “e RECLAIM system is getting attention from shale play operators as they begin to deal Preparing to add EvoVis viscosifier and EvoMod rheology modifier to Newpark with higher costs associated with storage, transDrilling Systems’ Evolution water-base mud system. (Photo courtesy of Newpark) portation, disposal, and the constant dilution of drilling fluids,” Rabon said. “Other concerns include reduced ROP, which can increase stuck pipe and expensive “The Haynesville formulation may not work in other shales, nonproductive time, as well as possible reservoir damage potenbut it could be a good basis to begin.” tially resulting in lower average production. Recovering reusable oil-based fluid “ese concerns are the result of a high percentage of low-gravity drilled solids in the oil-based mud that cannot be eliminated The M-I Swaco RECLAIM closed-loop technology is a chemically enhanced solids removal process capable of extracting the through the rig’s solids control equipment,” Rabon added. Natural gas well construction in the Marcellus Shale play is majority of fine solids from oil-based or synthetic-based drilling fluids, and recovering base fluid with near-virgin properties. In subject to strict environmental regulations with limited waste the environmentally sensitive Marcellus Shale play, the process treatment and disposal facilities in the area. Oil-based mud losses has reclaimed 77% of the available oil in a used up oil-based to the formation are seldom experienced due to the stability of drilling fluid, reducing waste disposal costs and providing fresh the formation, resulting in reuse of drilling fluids across several wells. This can result in the buildup of low-gravity solids (LGS) base oil for new drilling fluid. “Development was initiated about five years ago, with commer- to the point where they cannot be removed by conventional solids cial release late last year,” said John Rabon, business development control equipment. NPT can result when a fluid system exceeds 15% LGS. Typical manager for M-I Swaco. “It is the only system that can separate an oil-base drilling fluid’s components through mechanical and chem- options for treating high LGS include diluting the fluid system, creating three to four times the original volume, or disposing of the fluid ical means.” e RECLAIM system is designed to remove the bulk of fine col- system and building a new system, both of which are expensive. One operator had 600 bbl of spent, ultrafine LGS-contaminated loidal particles and/or increase the oil-to-water ratio by applying the proprietary flocculants and surfactants to bind together the fine oil-based mud in a satellite storage facility. Dilution and disposal

Drilling/Frac Fluids

“e idea was to develop a fluid that would have viscosity at the surface and no viscosity aer the fluid goes through the perforations,” said Chuck Bell, region technology manager for East Texas. When the system is used with other fluid components qualified using the company’s SmartCare system, ShaleXcel fluid is a fit-forpurpose fracturing system comprised of additives that are physically safe and environmentally responsible, according to the company. Low residue on the formation assists in a quick cleanup. “It is a very versatile system in that the only real goal is to get an instant crosslink,” Bell added. “You can use multiple crosslinks as long as you can get an instant crosslink.” e system yields greater propped fracture area than slickwater systems, according to the company. e system, which is compatible with virtually all mix waters, also generates adequate viscosity to suspend and transport proppant from the blender through the perforations, eliminating proppant settling in pumping equipment, New frac fluid systems for shale plays flowlines, and horizontal laterals. “As you change types of proppants, for example, from a specific Baker Hughes’ new patent-pending ShaleXcel fracturing fluid system was launched in 2010. e fluid provides proppant transport gravity of 2.65 and increase that to 3.2 or 3.3 with ceramics, it from the surface pumping equipment through injection into the changes the flow characteristics of the fluid with the viscosity,” Bell reservoir before reverting to a low-viscosity fluid. e system said. “However, even with the heavier ceramic proppants, you have crosslinks rapidly to improve operational reliability and ensure less proppant settling with the viscosity and you still get your fracproppant transport in horizontal well bores. It is useful in hydraulic ture creation in the formation.” e system enhances performance with lower concentrations of fracturing operations in unconventional reservoirs such as shales gel while offering equivalent gel viscosities. Its ultra-low-polymer and tight gas sands and in horizontal or vertical wells. e fluid’s viscosity breaks within minutes of entering the for- loading and complete viscosity break leave negligible proppant pack mation to a slickwater-like viscosity, generating a complex fracture damage compared with typical crosslinked gel systems. e viscosity of the system in the formation is less than 5% of the network to improve stimulation effectiveness. surface viscosity with the breaker schedule. Also, no viscosity gain is noticed when adding a friction reducer. e system currently is used in the Haynesville Shale play, and it could be used in other regions, according to the company. “You could use the system the way it is formulated presently,” Bell said. “We performed tests with the system with freshwater, potassium chloride, and 6% salt, and while there is a slight degradation in viscosity as you add the chlorides and the salts, it still creates the viscosity we’re looking for.” Another crosslinked fracture fluid developed by Baker Hughes and used primarily in the Bakken Shale in Saskatchewan, Canada, works with produced or flowback water. e Viking II PW (produced water) fluid was developed to address water supply issues resulting from drought conditions in the region. “We developed this system in anticipation of freshwater shortages primarily in the south Saskatchewan provinces,” said Brad Rieb, region technical manager, Baker Hughes, Canada. “roughout the year, the region goes through extreme fluctuations in water Solids discard without RECLAIM treatment. (Images courtesy of M-I Swaco) quality, depending upon the severity of a drought, and costs would have been prohibitive since the nearest permitted disposal facility was about 1,000 miles away. e company treated all 600 bbl of the spent fluid on location in Troy, Pa. LGS in the feed mud totaling 18% volume/volume were reduced to less than 1% volume/volume. e company recovered 77% of the available oil in the original drilling fluid volume. e recovered base fluid was 99% oil, 0% water, and 1% solids with a density between 6.9 to 7.0 lb/gal, and was suitable for use as fresh base oil. Oil recovery took three days and completely emptied the storage facility, which reduced or eliminated daily tank rental costs. e recovered oil was successfully added to the active drilling fluid system, and reduced the volume of base oil required to be purchased for subsequent wells. e solids generated from the process were approved for landfill disposal by the Pennsylvania Department of Environmental Protection.

Drilling/Frac Fluids

ensure the fluid does not encroach upon the high water-bearing formation above the Bakken. This complicates fluid chemistry for two reasons. The resulting fluid velocity complicates proppant transport, making fluid viscosity a critical issue, particularly with reservoir temperatures around 158°F. Additionally, the low pump rate and long pump time require the fluid to maintain a strict rheology profile until job placement is completed.

Friction reducer for shale

Solids discard with RECLAIM treatment with rampant development of the Bakken, suitable water availability was becoming a question.” In developing Viking II PW fluid, the company took several produced-water samples from the Bakken Shale with large variations in chemical contamination before choosing the final polymer and crosslinker. e resulting system is water-tolerant, generates in excess of 400 cp initial viscosity, and can remain stable and predictable for 100 minutes, at which time it undergoes a dramatic break. It has been used in about 300 wells with an average 17 stages per well, for a total of about 5,100 stages. An average of 275 bbl of fluid per stage was used, translating into about 1.4 MMbbl of recycled water used in the system. “We saved 1.4 MMbbl of freshwater from being used in the fracturing operations,” Rieb said. e system offers environmental and economic benefits as well as operational benefits. One customer estimated it saved 10% to 15% of total stimulation costs resulting from reduced hauling, heating, and disposing of fluids. “One operator that had a constant source of produced water stored it in several tanks,” Rieb said. “Using the system was a money saving venture for the operator because it didn’t have to buy town water, which reduced transportation costs, and they didn’t disturb municipal roads.” Fracture fluid treatments in the Bakken typically are designed to place 17,600 to 22,000 lb of 20/40 proppant at a low pump rate, averaging 5 bbl/min. The low pump rate is necessary to

e Nalco Adomite Group addresses the challenges of oil and gas operations by providing development, evaluation, and simulation of chemical programs specifically aimed at challenging shale plays. e company conducts a thorough analysis of flowback and produced water, evaluates the fluid treatment, and verifies that the fracturing additives selected for a project are appropriate for the water type. is evaluation assures the compatibility of the additives being combined in the fluid system will not affect the performance of other additives. The company’s latest product for frac fluid systems using treated flowback or produced water is based upon its patented ULTIMER® polymer technology, winner of a Presidential Green Chemistry Challenge Award. Its latest additive, ULTIMER ASPFFR900, is being introduced to the industry this year. “We have made inprovements to our patented ULTIMER polymer technology so that it fits the needs as a friction reducer,” said Sandra Garcia-Swofford, global marketing manager for Adomite Chemicals. “It is specifically engineered for shale environments.” The friction reducer, engineered to perform in high levels of TDS, is not lithology specific and can be used in a variety of shales. The dispersion friction reducer has no mineral oils, which makes it more environmentally friendly, and it inverts faster in colder temperatures due to its unique properties, according to the company. The capability to invert quickly is useful in seasonal cold weather regions such as the northeastern US, allowing an operator to optimize the dosage and minimize over-injecting of fluids. Nalco introduced the friction reducer to several shale plays across the US, from Marcellus to Barnett, Haynesville, Fayetteville, Woodford, and Eagle Ford. Additionally, the company is active in several European shale plays. “We are well positioned in Europe and have several polymer plants to meet market needs,” Garcia-Swofford said. “We also have our European research center in Leiden, The Netherlands, where we have a large laboratory to perform water analysis.” I

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