Despite limits, synthetic fluids still best bet for deepwater

John Candler, Manager of Environmental Affairs for M-I of Houston, performs simulated seabed tests designed to determine the toxicity of different cuttings piles. [24,736 bytes] Dr. James Friedheim, Manager of New Technology for M-I of Houston, explains how narrow fracture gradients hamper deepwater drilling operations. [14,118 bytes] M-I Mud Engineer performs mud check on a synthetic mud sample taken from a site offshore Louisiana. [27,483 bytes]

High-tech models may offer solution;
environmental factors drive innovation

William Furlow
Technology Editor
While synthetic drilling fluids, both first and second generation designs, have been getting a lot of attention in recent years, the innovations that drive fluid developments through the next millennium will be in response to tightening environmental restraints, rather than the requirements of drillers.

As the progress of drilling fluid design moves into a reactive rather than proactive mode, scientists as well as drillers will keep a closer eye on the governments who legislate offshore regions and ultimately dictate what fluids can go down hole.

Before this decade there were basically two types of muds: aqueous (waterbased) and non-aqueous. The non-aqueous fluids could be divided between those based on diesel and those based on mineral oils.

Technology has a way of expanding the perceptions of time so that this period before the introduction of the esther-based, first-generation synthetics seem far more than a half dozen years ago. But it was 1990 when these fluids were first used in the North Sea.

The development of the esthers was an effort to cut downtime by reducing the incidents of stuck pipe and lost circulation. At that time, the industry was cost driven, with each technological development securely lashed to the bottom line. Synthetics might cost plenty, up to $250/bbl, but they could reduce the number of rig days on a well, which translated to hefty cost savings.

Synthetic fluids also increased penetration rates and allowed rigs to discharge their drill cuttings, something prohibited for those using non-aqueous fluids. In addition, these fluids can be reconditioned and returned for credit so that the costs are reduced. For example, a company could purchase 2,000 bbl of fluid and end up reconditioning and returning for credit all but 750 bbl which would actually be purchased.

Lost circulation

With the innovation of the second-generation synthetics, which were less viscous by half than their first generation counterparts, drillers had what was close to a perfect tool. There were a few aqueous fluids which could match synthetics in some areas of performance, but overall nothing could beat a synthetic.

The only downside to these fluids, performance wise, is lost circulation. For all their performance qualities, synthetics are prone to lost circulation because they are compressible. As bore pressure increases, for example in deepwater environments with a heavy mud column, the synthetics transfer this pressure to the formation resulting in lost circulation.

This dilemma can be overcome in most cases through the use of high-tech computer programs and specially designed down-hole tools that have the ability to closely monitor downhole behavior of synthetics. When an operator knows the integrity of a hole then he can determine how fast he can circulate the mud without damaging the formation.

Shallow trouble

In addition to the usual functions expected of synthetic drilling fluids, shale inhibition, hole cleaning, and lubricity, deepwater applications make a number of unique demands. Deepwater applications include problems such as shallow gas and water flows, lost circulation/lower fracture gradients, and hole cleaning in riser sections. Dr. James Friedheim, Manager of New Technology for M-I of Houston, said that second generation synthetic fluids are a good start, but must be married to good engineering applications to overcome these obstacles.

Synthetic fluids have been successfully applied in the Gulf of Mexico. Reports from the field indicate these synthetics offer wellbore stability, reduced torque, reduced drag, and the ability to discharge cuttings into the sea. This synthetic, non-aqueous external phase mud does not allow hydration of reactive shale. This characteristic eliminates the problem of gumbo balls that can form at the bit and bottom hole assembly (BHA).

Most synthetics have a nonlinear relationship between viscosity and temperature because of external phase. At temperatures of 160° F, the viscosity of this fluid increases faster than that of a diesel or mineral oil-based mud. Beyond this threshold, the viscosity changes are minimized, allowing the system to carry cuttings away in lower temperature, upper areas of the hole where cuttings removal is more difficult because of the reduced annular velocities.

Because of the improved wellbore stability, these synthetic muds create better gauge holes allowing an increased annular velocity at a given flow rate. This improved velocity improves the hole cleaning characteristics of the fluid and reduces the incidents of stuck pipe, often caused by a buildup of the cuttings.

Synthetic muds, by nature, coat the cutting structures preventing cuttings build up, while cooling and lubricating the bit. Not only does this increase the bit life, but it also improves downhole torque.

The elimination of cuttings disposal aspects of these muds is a valuable feature, not only saving money spent on storing, transporting, and reinjecting these cuttings, but also increasing the drilling rate. Otherwise the drilling rate must be slowed to accommodate the collection of cuttings.

In addition to being environmentally friendly, these synthetic muds produce fewer cuttings by drilling more in-gauge holes. Because the mud can be reconditioned, it can be sold back to the supplier, and the user does not have pay for disposal.


Friedheim said deepwater is not a new frontier for the oil industry, but because of increased activity in these water depths it has come to the forefront of new technology. Regardless of how one defines deepwater (1,500 ft up to 6,000 ft), the challenges remain the same, only they are amplified by a longer water column.

Typically, the surface sediments in deepwater fields have a relative low fracture gradient. Shallow gas or water flows in deepwater wells are a common problem along with expandable dispersible clays. Because of these shallow water problems, large diameter holes are drilled to accommodate the many strings of casing required.

The first string of pipe, 26 in.-36 in., is set after drilling, while taking returns to the sea using only seawater with high-viscosity sweeps. The next two intervals, 20-in. and 13 3/8-in., are commonly drilled with a salt-enhanced water-based mud because fracture gradients are still low, non-dispersed polymer systems are controlled easily, and engineering is relatively straightforward.

The final intervals, 12-in. and 8-in., are often the longest and most difficult intervals because of increasing pore pressures. This is made more difficult, not only by the pore pressure, but by the presence of reactive shales. It is in these intervals, that the synthetic muds are enjoying the greatest application.

Hanging over the entire operation are the constant problems of hydrate formation and narrow fracture gradients/pore pressure margins. The pressure of the large mud column necessary to reach a deepwater formation, combined with the very low water temperatures of this environment, force operators to walk a tight rope between the high pore pressure needed to circulate the mud through the bore and the low fracture gradient of these unconsolidated sands. Weighted pills often are needed to hold the hole open long enough to run casing. Once this hurdle is cleared, it becomes a cementing problem.

It is not uncommon for a deepwater project to require respudding after losing control of shallow gas or water flows and failure to complete a successful cementing job. From a procedural standpoint, the best offense is a good defense. Friedheim said 3D seismic data helps engineers map a field in deepwater and choose the most suitable area to begin a drilling program. This careful selection process does not offer a solution, but minimizes the risk of tapping in to one of these hazards.

Hydrates formation

Gas hydrate formation is a major concern for operators because of the severe, and thus expensive, consequences they may have. These solid, ice-like mixtures of gas and water are formed by the combination of natural gas and water under pressure at low temperatures. These hydrates will form above the freezing point of the aqueous phase.

This formation can lead to blocked choke and kill lines, blocked blowout preventer valves, restriction of pipe movement, and loss of well control. If such hydrates form near the surface, they will liberate large amounts of gas upon decomposition, which could result in loss of well control and safety problems around the shaker and flowline.

Once hydrates form, an operator's options are very limited. Research into prevention seems to be the most promising avenue for fighting this phenomenon. For water-based muds, salts and glycol or glyserol additives are effective, Friedheim said. These muds work thermodynamically, suppressing the formation of gas hydrates to lower temperatures and higher pressures in the same fashion that they depress the freezing point of water.

Kinetic inhibitors are another form of additive that has been successful in preventing the formation of hydrates. Research has been done using a combination of these two formulas.

Another approach to the problem of hydrate formation is to eliminate the aqueous phase altogether. This is done by using an invert with a low activity brine phase. For this approach, synthetic muds offer the most suitable technical and environmental solution.

The tight margin between pore pressure and fracture gradient in water depths over 1,500 ft. is a result of the large water column above the sediment. The basic problem is that the margin of density that the drilling fluid must operate within is tighter in a deepwater environment and can generally tighten further at increased water depths.

The cold seafloor temperatures and heavy mud column in the riser raise the equivalent circulation densities, static densities, and pressure losses downhole for synthetics and water-based muds.

Second generation synthetics are about half as viscous as the first generation and have the added advantage, in a deepwater situation, of maintaining this lower viscosity at low temperatures. "If we just had the first generation of synthetics, we couldn't have used them in deepwater drilling because of these cold water temperatures," Friedheim said.

These second generation synthetics-based muds offer a thinner, cheaper alternative to the first generation products. The base fluids that make up this second generation are isomerized olefin and linear alpha olefin. Compared to esthers and poly alpha olefins, used in the first generation synthetic muds these second generation fluids have virtually half the viscosity at 40°C.

Tripping in deepwater

Proper tripping practices using synthetic-based muds in deepwater are crucial because the muds get thicker in this cold environment. These conditions can easily lead to formation fractures, lost circulation, and well control situations caused by surge and swab pressures when tripping, according to Friedheim.

Some of the time an operator saves using synthetic fluids can be dedicated to slower tripping, which will avoid many of these problems. Warming mud as pipe is tripped into the well will help prevent excessive surge pressures because it breaks the gel strength and reduces the mud viscosity.

While it is important to make a lot of short trips when using a water-based mud, to wipe the hole clean and keep it in good condition, this can be a big waste of valuable time when using a synthetic based fluid. This procedure can be eliminated because of the superior hole conditioning provided by synthetic based fluids.

Rob Valenziano, Petrofree L.E. Product Manager with Baroid Drilling Fluids said clients are so concerned with the possibility of fracturing a formation that they are increasingly asking for high-tech water-based muds in deepwater operations rather than taking a risk with the synthetics.

He said these muds are safer, but take much longer to get an operator to the production zone. It is not a matter of penetration rates, Valenziano said, but one of downtime and borehole stability. Valenziano agreed with Friedheim that synthetics pay off by saving rig days, but could backfire as a lot of product is lost downhole while setting casing.

Ultra low shear rates

Bill Smith, Director of Fluid Product Lines for Baker Hughes INTEQ said his company is working with a low shear rate viscometer for field application. This instrument which can be used to measure fluid viscosity at shear rates as low as .001 rpm and as high as 600 rpm provides enhanced capability over conventional field viscometers which only measure properties in a range of 3-600 rpm.

With this information, an operator can more closely predict tendencies of a given fluid to exhibit poor hole-cleaning characteristics and barite "sag", both of which can result in critical problems in the high angle and large diameter holes common in deepwater.

Barite settling occurs when a fluid inadequately supports weighting materials, resulting in a tendency for higher density fluid to be positioned on the low side of an inclined wellbore.

This phenomenon can occur in dynamic as well as static circulating conditions with all fluid types and can result in well control and/or lost circulation problems. This problem can prove more critical in deepwater environments where fracture tolerances and rapid pressure transitions are common.

Virtual hydraulics/rheology

Research has created a suite of software products that can assist in calculating equivalent circulating densities and pump pressures for synthetic-based muds and other types of invert systems. One package, developed by M-I, can more-accurately predict downhole mud rheology, static density, and pressure losses. Using these predictive tools, operators have been able to prevent expensive losses of synthetic fluids by preplanning and establishing guidelines for drilling and tripping.

Hole cleaning in riser sections is especially difficult in deepwater operations due to the large diameter riser extending 1,500 ft.-6,000 ft. below the rig floor. The balancing of fluid rheology and thixotropy is necessary to clean the riser and suspend the cuttings when the pumps are shut off.

At the same time, an operator has to ensure the mud is thin enough to avoid problems with downhole equivalent circulating densities while drilling, or excessive surge or swab pressures created while tripping. In addition to these concerns, attention must be given to the necessity of hole cleaning downhole when drilling a high angle or horizontal interval to avoid the formation of a cuttings bed.

To prevent hole cleaning problems in the riser section, Friedheim recommends two approaches that can be combined. One engineering solution is the addition of an extra pump to move fluid only through the riser section via a kill line. This can help increase the annular velocity in that section.

A drilling solution is to use a fluid specially designed to meet the rheological parameters required for good hole-cleaning in the intervals. Because the fluid running through the riser flows in a laminar flow regime, it is important to emphasize a low shear rate viscosity. Friedheim said he recommends 6 rpm and 3 rpm readings, as measured on the Fann Model 35A viscometer, to ensure the efficient transportation of cuttings. To suspend these cuttings in static conditions requires moderate and rapid gel strengths.

Other problems common to most wells, but more pronounced in deepwater drilling, such as torque and drag, differential sticking, and stuck pipe, should also be considered when choosing a synthetic fluid. Problems resulting from those causes are not only more pronounced in deepwater drilling, but, because of the greater expense in terms of day rates, more expensive.


Friedheim said he recommends synthetics that are isomerized olefin or linear alpha olefin based, while some contractors use inhibitive water-based muds such as salt/PHPA, glycol enhanced or silicate salt fluids, but his research shows the synthetics offer a wider range of advantages over the inhibitive water-based muds especially in terms of differential sticking, lubricity, wellbore stability, and rate of penetration.

The rate of penetration is often seen as key for drillers in such a high-cost theater. Friedheim said he has heard of drillers who bore right past areas of seepage preferring the cost of lost mud to the higher expense of down time. When one considers that five days off the drilling curve could cost up to $1 million in rig time alone, this logic seems sound. Friedheim is not against the use of inhibitive water-based muds, but an operator must weigh the costs of these muds against the advantages.

"The only way a synthetic can provide beneficial and cost effective is by avoiding severe downhole losses," he said in a recent paper.

Water-based muds are commonly used in deepwater exploration wells to obtain better formation evaluation data in the exploration stage. Logging and repeat formation testing procedures are made more difficult when dealing with some types of invert systems. The level of this difficulty depends on the specific base fluid and techniques used, but Friedheim said the most reliable fluid for such testing is still water-based.

Environmental element

Aqueous muds do not create cuttings piles because they dissolve in the water. Cuttings piles created by diesel or mineral oil based non-aqueous muds have been found to leach oil into the sea which is an environmental liability. Esther-based synthetic's (first generation) have what is considered good anaerobic degradation, meaning the piles created by these muds dissolve in water at a rate that is fast enough to minimize damage to sea life.

Reportedly, this rate is actually too fast, and may actually rob seabed creatures of oxygen in the water needed for life. The rate of degradation is a point of contention in the North Sea:

  • The UK favors rapid degradation of cuttings piles
  • Norway would rather see piles that degrade at a more moderate rate.
In the Gulf of Mexico such piles are not seen to be a problem because the Gulf is such a dynamic environment. Thanks to the large continental shelf and high volume of hurricanes and other tropical storms, cuttings piles do not stay in place long enough to do damage. Also, deepwater fields have the advantage of forcing cuttings to fall for 5-8 hours before reaching the sea floor, by which time they are so dispersed that piles do not occur. What happens to these cuttings is an environmental questions that is still being debated.

Simulation models have attempted to nail down where these cuttings end up. One study by the Bedford Institute of Oceanography in Nova Scotia, Canada resulted in a model that could predict the size and thickness of cuttings piles resulting from the discharge of oil-based muds.

In this study the size and horizontal displacement of the cuttings pile was directly proportional to the water depth. While other models account for such factors as current action and settling velocity, none took in to account the environmental impact of "washing" that affects cuttings as they fall through the water column.

If it takes cuttings eight or more hours to fall to the sea floor, then it is reasonable to assume, depending on the size of the cutting, that some of the mud will be washed away as it falls. If sea water penetrates the shale surface before the cuttings reach the sea floor then dispersion will begin. Once this occurs, the particulate size will be reduced to a point that the formation of a cuttings pile will be unlikely.

To this end, synthetics-based muds have a much lower dilution rate or volume than water-based muds due to their inhibitive nature. This means fewer cuttings will be dispersed into the fluid which in turn offers better wellbore stability, fewer washouts, and more stable fluid properties.

These traits mean less of the synthetics-based fluids will need to be discharged into the sea because most of the fluid can be reconditioned. From the standpoint of pull-through effects, these higher dilution rates of water-based muds mean more chemicals need to be transported to the rig, an environmental concern in itself.

Because many of the deepwater theaters are virgin to oil exploration and development, Friedheim said the industry is in a position to help establish environmental compliance and responsibility. In choosing a mud system, Friedheim said an operator must consider commercial, performance, and environmental issues.

In the Gulf of Mexico, the focus has been on regulating the "static sheen" created by cuttings, as a way to determine if there are hydrocarbons on the water surface, and tests on mysid shrimp to determine the toxicity of cuttings. While synthetics seem to perform well in both if these areas, it is not clear if the US Environmental Protection Agency will apply these tests to synthetics.

The agency is in the process of re-issuing discharge permits, something it does every five years. While the old permits did not list synthetics, the new permits will divide muds into four categories: water-based, oil-based, enhanced mineral oil-based, and synthetic.

These new permits were scheduled for issue in November of 1997, but have been delayed. The industry is awaiting this new issue to see what tests will apply to the synthetics. Regardless of the specifics in the Gulf of Mexico, it is clear that simply listing synthetics on the new permits has opened the door to further environmental regulation. While Friedheim said this was inevitable, it does not mean the Gulf of Mexico will go the same way as the UK North Sea.

In anticipation of this increased regulation, the industry is already busy both offering new methods of testing synthetics and performing studies to determine the environmental impact of different fluids. The increase in regulation is a global phenomenon. Even in areas such as offshore West Africa, where regulation has been relatively relaxed, there are signs that changes are coming.

Copyright 1997 Oil & Gas Journal. All Rights Reserved.

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