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Technology Update

Mobile Mixer Adds Dry Friction Reducer to Fracturing Fluid at the Wellsite

A mobile system has been developed that mixes consistent solutions of powder-based friction reducers (FRs) at the wellsite and adds them to hydraulic fracturing fluid. The use of the system has achieved reductions in fracture stage cycle times of as much as 10% and significant cost savings, compared with the conventional use of oil-based liquid emulsion FRs in slickwater fracturing fluids.

In addition, the use of powder-based FRs reduces the potential of the FR solution freezing, settling, or gelling and eliminates the hazard of liquid FR spillage in work areas.

Water-soluble dry polyacrylamide can be used as an FR, with the selection of a polymer dependent on water quality. Dry FRs can perform in waters ranging from fresh water to high-brine produced water.

The challenge to developing the use of dry FRs in fracturing fluid was the ability to hydrate them on a treatment site. The PowderFrac mobile mixing and feeding system developed by SNF has performed successfully in the field since its initial deployment in the Barnett Shale of Texas during 2011. The system provides onsite storage, hydration, and dose control of the
powder FRs.

The mobile unit enables well operators to reduce logistics and labor costs, and the chemistry of the dry FR solutions is also less costly. Deployment of the mobile unit does not require the modification of equipment or infrastructure at the fracturing site. The unit was designed and built with field replaceable parts to ensure prompt, cost-effective vehicle maintenance while deployed.

The equipment includes a patented Polymer Slicing Unit (PSU) for rapid hydration of the dry FR. The PSU can operate at treatment rates up to 120 bbl/min. Additional equipment consists of two solution tanks, a 12,000-lbm dry storage container, a horizontal screw conveyor, water filter pots, water pumps, FR solution pumps, and a self-contained generator system that can be fueled by an onboard tank or the saddle tank of the tractor.

Safe deployment and operation is a crucial part of the unit’s design. All electronics capable of data recording can perform reporting and analysis. The mobile unit, 45 ft in length, requires no special transport permits and can be refilled with dry powder FR by a powder bulk truck.

The friction reduction from a polyacrylamide will be affected by water quality and salinity and any other additives in the fluid that interact with the polymer. Concentrations of FR are adjusted during the treatment to lower or raise the pumping pressure.

The unit is equipped with a remote starting and monitoring system in the control room. The operator sets the desired loading, and the FR dosing is controlled automatically by following the clean rate—the rate that signifies that the system has stabilized so that dosing can be increased to its targeted rate. The operator can change the loading easily at any point.

A user option allows the operator to upgrade the mobile unit to provide direct two-way communication with the data van, which enables a consistent data stream between the two units. The real-time monitoring tool can recall and replay a given job from saved archives.

The self-contained dry FR storage unit on the mobile system holds the equivalent of 5,000 gal (16 totes) of liquid emulsion. The elimination of this liquid handling cost reduces the cost of setting up the mobile unit.

Case History 1

Fig. 1 is a recording of one stage in a slickwater fracturing treatment with a dry polyacrylamide FR. The operator wanted to monitor the difference in performance of an emulsion polyacrylamide FR with a dry FR hydrated from the mobile unit.

Fracturing was started with the emulsion FR and about 64 minutes into the stage, hydrated dry FR was introduced. An immediate drop in surface treating pressure was observed. The pressure trace showed that the treating pressure with the dry FR was 4,300 psi compared with 5,000 psi with the emulsion FR at equivalent gal per thousand (GPT) of fracturing fluid. The treating rate was 109 bbl/min with the dry FR compared with 100 bbl/min with the emulsion FR. This resulted in a 10% reduction in the fracturing stage cycle. Dry FR hydrated with the mobile unit showed a 15% pressure drop.

The fracturing was successfully executed at the desired depths with pressures maintained. After the deployment, all 10 stages were successfully fractured and monitored, and the well was put on production.

Case History 2

Fig. 2 is a recording of one stage in a slickwater fracturing treatment executed with a dry polyacrylamide FR. The operator wanted to monitor the difference in performance of emulsion-based polyacrylamide FR with a powder FR hydrated from the mobile unit.

The friction reduction performances of the liquid and dry products hydrated in a blend of fresh and produced water (total dissolved solids @ 130K mg/L and CaCl2 @ 29K mg/L) are shown in the graph. The emulsion FR and dry FR used were polyacrylamide-based products. The pressure trace shows that the treating pressure for the dry FR was 5,500 psi, compared with 7,000 psi for the emulsion FR at equivalent GPT of fracturing fluid.

The fracturing was successfully executed at the desired depths with pressures maintained. After the deployment, all 20 stages were successfully fractured and monitored, and the well was put on production.


The use of dry FR has shown a reduction in cycle times by as much as 10% and typical fracturing stage cost saving of 30%. The technology eliminates the use of oil-based FRs and tote handling, thus reducing the potential for freezing, settling, and gelling. In addition, the use of dry FR eliminates the potential hazard of slippery work areas caused by spillage of liquid FR.

CLD Rigs, MPD Change Equation for Deepwater Well Control

Closed loop drilling (CLD) systems and managed pressure drilling (MPD) are challenging long-held industry ideas about well control. This realignment in philosophy is happening because of a unique ability to precisely monitor, analyze, and control wellbore pressure in real time.

These capabilities are the basis for a growing number of proactive and reactive methods and tools that are solving many conventional well control problems. This is particularly true in the extremes of deepwater drilling, in which managing wellbore pressure plays a principal role in safety, efficiency, and even the ability to drill the well. Fig. 3 presents many of the critical issues addressed by advances in MPD.

Although the number of deepwater MPD applications is relatively small, the advantages being achieved with closed loop systems are driving its increased use and the development of specialized deepwater MPD technology and drilling rigs.

Monitoring and Control

MPD reduces well control events and pressure-related wellbore problems by addressing two key challenges associated with conventional methods: the uncertainty of the predrill model and the inflexibility of the resulting well design and mud regimes. These challenges are overcome by a dynamic capability that is counter to static predrill models.

Uncertainty is reduced by very precise measurements of wellbore pressure profiles in real time. Just as important, MPD complements this information with equally precise real-time control. This dynamic solution is proving a key enabler for enhancing safety, efficiency, and operational capabilities in deepwater drilling.

To achieve these capabilities, MPD builds on the inherent characteristics of a closed loop system. Within this contained, pressurized wellbore environment, pressure is closely monitored. Pressure changes, such as those caused by an influx, loss, or ballooning, are rapidly detected and controlled in increments as small as a few barrels. Accurate fingerprinting of these minute pressure oscillations quickly identifies the event, which both informs an effective response and avoids a misdiagnosis that can exacerbate the condition.

The MPD control response is initiated at the surface by automatically or manually varying the annular backpressure by using a specialized MPD choke manifold. These changes within the closed fluid system are used to manipulate downhole pressure without the delay, cost, and imprecision of changing mud weight.

The ability to immediately dial in and hold the desired wellbore pressure changes the well control equation fundamentally with a new set of proactive and reactive pressure management options.

Micro influxes that are the precursor to well control events are quickly managed before they can escalate into a kick. When kicks occur, they are rapidly identified, controlled, and circulated out of the well. This mitigates a significant source of risk and nonproductive time (NPT).

In deepwater wells, precise pressure management is also critical to navigating narrow drilling windows between the pore pressure and the fracture gradient. Similarly, it is central to managing transitions between high- and low-pressure zones to avoid kicks and losses, and to optimizing casing setting depths.

Solution to Riser Gas

MPD monitoring and control is also solving the old deepwater well control problem of riser gas. Gas in the marine riser presents a significant challenge to conventional well control because it is above and beyond the effect of the blowout preventer (BOP) system. While gas handling systems and methods provide a solution, it is reactive in nature and limited in its control ability.

MPD’s proactive and reactive response to riser gas results in a safer, more effective solution. The proactive approach uses early kick detection and control capabilities to achieve a major reduction in the incidence of reservoir gas entering an oil-based mud system at depth and dissolving into it without being detected, only to come out of solution in the drilling riser and above the subsea BOP. Should gas occur in the riser as the result of an influx or entrained gas, the MPD system provides a controlled means of circulating it out of the riser and dealing with any remaining gas downhole of the BOP.

New Rigs and Technologies

This success in solving many of the problems that have stymied conventional well control is driving the development of new technologies, CLD-ready rigs, and industry guidelines. A major technical step in the deployment of CLD systems in deep water on dynamically positioned (DP) drilling vessels was the development of the industry’s first rotating control device (RCD) that is made up below the tension ring and integral to the riser package of a DP drillship.

A below-tension-ring (BTR) RCD was first deployed in 2010. The device contains the annular flow and redirects it to help form a closed loop circulating system, thus making the device a key component of a deepwater MPD system.

The availability of CLD-ready rigs is crucial to the adoption of the technology. To meet the demand, existing vessels can be refitted to accommodate a CLD system, while new CLD-ready designs, such as Stena Drilling’s DrillSLIM semisubmersibles and drillships, are entering the market. Rig availability will also benefit from the development of industry guidelines, procedures, and standards for equipment procurement, rig modification and design, and training.

Driving all of these developments are the impressive results being achieved with CLD rigs and MPD methods in deepwater applications around the world.

HP/HT Drilling

In drilling a high-pressure/high-temperature (HP/HT) well in the North Sea, MPD saved approximately 75 days compared with conventionally drilled offset wells. Five separate influxes were successfully managed over 9 days. The ability to quickly identify high-pressure, low-volume gas stringers while drilling enhanced safety and well control, reduced NPT, and eliminated the need for a planned liner section.

On the Norwegian Continental Shelf, a surface pressure of nearly 15,000 psi made pore pressure evaluation and kick detection critical to drilling an exploratory well. A key objective was setting the 9⅞-in. production-casing shoe as close to the reservoir as possible, facilitating the drilling of an 8½-in. section to total depth (TD) within a very narrow 0.4 ppg drilling window.

MPD helped avoid well breathing problems while maintaining an overbalanced wellbore. Using the closed loop system saved an estimated 10 rig days and USD 7.5 million while reducing risk and improving safety.

Narrow Windows; Total Losses

When planning a deepwater exploratory well in Indonesia, limited pore pressure and fracture gradient information caused significant uncertainty in the predrill model. MPD was selected as a means to monitor and manage pressure in the difficult conditions. The drillship application was enabled by the industry’s first use of a submerged rotating control device, Weatherford’s SeaShield Model 7875 RCD, which was used in a BTR installation as an integral part of the riser.

To drill the difficult well, the MPD constant bottomhole pressure method was used at first. In early drilling, a 2-bbl influx was detected and successfully processed out of the wellbore. When severe losses occurred deeper in the well, the MPD drilling mode was transitioned to pressurized mudcap drilling and the well was drilled to TD.

Riser gas was eliminated in drilling this and seven subsequent exploratory wells. There was no incidence of formation gas breaking out of solution above the BOP and inside the riser. The MPD control system algorithms detected at least five flow anomalies that were kept to minimal volume and safely circulated out of the well.

There was only one instance in which an influx was circulated out through the riser. The process started with closing the subsea BOP and the MPD annular BOP (located below the RCD at the top of the riser) to isolate the influx. The mud and influx in the riser was then circulated out through the automated MPD choke manifold and the rig’s high-rate mud gas separator. Once the influx was out of the riser, the mud was weighted up, the subsea BOP was opened, and the rest of the well was circulated to a higher mud weight while applying MPD control.

Borehole Instability

Recent experience in the deep waters offshore Ghana further illustrates the advantages of drilling with closed loop systems. While conventional drilling had failed in two attempts because of pressure-related wellbore problems, MPD enabled the well to be drilled without borehole instability issues, underreaming, or contingency liners. Riser gas was routinely mitigated.

The first drilling attempt encountered an unstable rubble zone and sharp pore pressure and fracture gradient changes. The well packed off several times because of sloughing shale and progress stopped. The main wellbore was plugged back and a sidetrack was drilled using a higher mud weight to prevent sloughing. Drilling eventually took a 16- to 20-bbl influx and the sidetrack was shut in.

The next attempt 4 years later used a CLD rig and MPD to control wellbore pressures, provide stability in the rubble zone, and successfully drill the well. In addition, the 14¾-in. section was drilled deeper than the planned objective, which allowed the 13⅜-in. casing shoe to be set deeper and eliminated the need for the 10⅝-in. section.

Deepwater Well Control

Real-time insight into the wellbore pressure environment combined with real-time pressure control form the pivot point for a new way of looking at well control. In deepwater applications, this perspective is quickly gaining ground as the advantages of CLD systems and MPD are fully understood, and the technology and rig systems become available. The operator, rig contractor, and service company work together to integrate the enhanced well control capabilities of the MPD system (Fig. 4), thus bridging the gap between traditional primary and secondary well control.