Special Report: New olefin-based drilling fluid improves operational, environmental profile

March 2, 2009
A nonaqueous drilling fluid system engineered with a low-viscosity synthetic internal olefin base resolved operational problems in drilling tight gas wells in the Basin Center area in Western Canada.

A nonaqueous drilling fluid system engineered with a low-viscosity synthetic internal olefin base resolved operational problems in drilling tight gas wells in the Basin Center area in Western Canada.

Compared to previously used conventional drilling fluids that contained a high kinematic viscosity base fluid, the new system based on C14 internal olefins (IO) provided a lower rheological profile and improved downhole pressure management. Accordingly, by eliminating the repeated gas influx and mud losses on trips caused by the severe well ballooning encountered in the area, the operator met both drilling and postdrilling objectives.

The high rheologies and equivalent circulating densities (ECD) associated with the predecessor system prevented the operator from meeting logging and other objectives, as well as causing troublesome, yet manageable drilling concerns.

More importantly, by eliminating or minimizing several environmentally suspect components, the new base fluid and its linear structure also exhibited comparably faster biodegradation, thus providing a smaller environmental footprint that encourages composting and other attractive disposal technologies. Further, because of its lower polycyclic aromatic hydrocarbons (PAH) content and associated higher flash point, the new system delivers an enhanced health and safety profile.

Drilling fluid drivers

Companies select a drilling fluid based on the technical demands of a specific application and local health, safety, and environmental (HSE) regulations. From a performance standpoint, the nonaqueous or invert-emulsion drilling fluids compared with their water-based counterparts have well-documented advantages.

While aqueous systems offer some environmental advantages, invert-emulsion systems enhance overall stability and possess the capacity to drill reactive shales with minimal wellbore destabilizing chemical interactions. Further, the use of a nonaqueous fluid (NAF) results in a tight or low fluid loss, a thin filter cake, a high degree of lubricity, and increased penetration rates compared with conventional water-based drilling fluids.

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Instead of the direct emulsion of oil in water that characterize water-based fluids, NAFs have an inverted nonaqueous external or continuous phase, while an emulsified brine or aqueous fluid comprises the internal phase. The external phase can include one of several base fluids, including diesel, mineral oil, highly refined mineral oil, and synthetic fluids. Aside from their respective operational advantages in certain applications, from an occupational health and safety perspective, NAFs differ from one another based on their polynuclear aromatic hydrocarbon content (Fig. 1).

The downside of using an NAF centers on the compressibility of oils and other nonaqueous base fluids that can cause density fluctuations. Furthermore, owing to the natural wettability of some basic drilling fluid components such as barite and other weighting materials, NAFs require wetting agents and other surfactants to suspend and maintain these materials in the continuous nonaqueous phase.

Often, these factors in tandem with the choice of the base fluid, emulsifiers, and viscosifiers can cause problems with respect to excessive viscosities and gel strengths. These problems can lead to difficulties in managing downhole densities and equivalent circulating density (ECD) that frequently result in whole fluid losses, stuck pipe, logging problems, and overall wellbore instability.

While NAFs were the ideal option for addressing the operational challenges of Western Canadian wells, problems arose related to high viscosity caused from an inappropriate base fluid selection. For example, while one 12,500-ft Basin Center gas well reached TD with some manageable issues, such as seepage losses, gas influx, surge-swab, and ECD concerns, the problems occurred when the rig attempted to log the well at TD. Severe well ballooning with repeated gas influx and mud losses on trips forced the operator to case and cement the well, forgoing the logging operation.

An end-of-well review traced the main causes of the problems to high rheology and high ECD, which the review attributed to the base fluid. As logging the well was one of the critical objectives, a solution to the high viscosity and gelation problem required an investigation into an alternative base fluid.

Laboratory investigation

Because ECD and lost-circulation management were the main technical drivers, the first approach looked at the effects of different base fluids on rheological properties. Typically, base fluids with a low kinematic viscosity provide a lower rheological profile that minimizes ECD effects more than fluids with high kinematic viscosity. Table 1 lists the kinematic viscosity and other physical properties such as pour point, flash point, and density of certain common base fluids found in Canada.

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The laboratory work compared three potential base fluids: Mineral Oil B, C14 IO, and Mineral Oil A, formulated to the 15 ppg used on an offset well in Alberta (Table 2).

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To ensure fluid homogeneity, the testing involved mixing each fluid on a single spindle mixer and shearing them for 5 min at 6,000 rpm. Afterwards, the procedure hot rolled the test fluids overnight at 250° F. with 200-psi N2 confining pressure. A Fann 35A viscometers at 120° F. determined the rheological properties before and after heat aging.

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The tests measured the high-temperature, high-pressure (HTHP) fluid loss at 250° F. on API filter paper with 500-psi N2 differential pressure. Further, the testing evaluated the effects of low-gravity solids on mud properties by treating each test mud with 45 lb/bbl of simulated drill solids (Table 3).

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A comparison of the rheological properties indicated that differences in kinematic viscosity and chemistry of the base fluid can have a large effect on plastic viscosity (PV), yield point (YP), and gel strength (Fig. 2). For example, C14 IO with a low kinematic viscosity (1.9 cst) resulted in low PV, YP, and gels, whereas Mineral Oil A and Mineral Oil B, having similarly higher kinematic viscosity (3.4-3.5 cst), resulted in a higher PV with slightly different YP and gels.

In addition, the PAH content of the base fluids may account for the difference in YP and gels observed between Mineral Oil A and Mineral Oil B. The former, having a high PAH content (10,000 ppm), seems to enhance the yield of organoclay more efficiently than Mineral Oil B, which has a PAH content of 600 ppm. By comparison, the C14 internal olefin contains no PAH.

For fluids without the simulated drill solids, the effect of the base fluid on rheology was similar to those with drill solids. The lab testing indicated C14 IO as better technically compared with other base fluids for management of ECD and lost circulation because of its low kinematic viscosity and rheological profile. Mud formulation, product, and product concentration, however, also may affect rheological properties, thereby requiring further modification of the C14 IO base fluid before engineering a final formulation for the targeted field application.

Compared with the original formulation used in the initial testing, the final formulation contains less organoclay but a higher volume of wetting agent and fluid-loss control additive. This formulation helps reduce further low-end rheology and gel strengths while maintaining sufficient fluid-loss control and solids tolerance.

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Table 4 shows the final fluid formulation and its properties after heat aging with solids contamination.

Field trial

Basin Center gas wells typically involve the drilling of the 121/4-in. top hole with unweighted gel slurry to about 1,800 ft before setting the casing. Next, the drilling of the 83/4-in. intermediate section generally uses an unweighted oil-based mud (OBM) to about 8,000 ft, at which point the next casing string is set. Drilling of the main 61/8-in. interval usually is with unweighted OBM, but at TD the driller may increase mud density to 15 ppg or higher. The last section often has logging and coring operations as required.

The offset well drilled before the C14 IO field trials suffered minor problems during drilling but severe problems during logging attempts. The operator deemed that the better rheological profile of the C14 IO system was a technical solution to this problem on subsequent wells. The solution led to lower ECD, reduced swab and surge pressures, and more manageable nonprogressive gels.

A high yield organoclay used during premixing enhanced and ensured rheology, thus the fluid did not require a polymeric rheological modifier. The system had an 85:15 oil-water ratio.

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The operator has completed two field trial wells with a third underway as of this writing. Table 5 compares the parameters from the two field trials against the offset drilled with the Mineral Oil A-based system.

The first field trial involved drilling and casing the intermediate section with a conventional unweighted 8.7-ppg Mineral Oil A-based OBM. Drilling out of the casing shoe used the same drilling fluid. For the main section C14 IO-based fluid, displaced the fluid for drilling out the shoe. The fresh fluid sheared through the bit homogenized fluid properties and once drilling commenced, the driller increased mud density rapidly to 11.7 ppg to contain gas influx. To enhance hole cleaning, the fluid needed occasional treatments with organoclay during directional drilling.

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The well reached TD with no major problems and the mud weight at TD increased to 13.6 ppg (Fig. 3). Compared to the offset, the overall rheological properties and HTHP fluid loss were noticeably lower, which the operator attributed partly to the lower mud weight and change of base fluid (Table 6).

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The field trial successfully collected full-size cores from several intervals towards the bottom of the well. Unlike the previous well, the drilling operation successfully obtained sidewall cores and wireline logs at TD. Consequently, the operator considered the first field trial a success by meeting the objectives set before the trial.

At the end of the well, the mud company returned the drilling fluid to the mud plant and centrifuged it to reduce mud weight for the next well.

The drilling of the intermediate section to 9,030 ft in the second field trial used the Mineral Oil A-based OBM from the previous well. An openhole displacement at this point placed in the hole the previous well’s reconditioned C14 IO-based fluid. A rapid mud weight adjustment increased the weight to 11.7 ppg.

Because of repeated high-connection gas, the driller raised the mud density incrementally to as high as 16.2 ppg half way through the section. The driller later reduced the mud weight to around 15.8 ppg to TD to combat seepage losses, which lost-circulation material alleviated. Two logging runs were problem free at TD.

The higher density used on the second field trial made the comparison with the offset well more realistic and clearly revealed the performance advantages of a low kinematic viscosity, low-PAH olefin compared with the conventional base fluid with high kinematic viscosity and high PAH. The rheological properties observed with the field trials are also in good agreement with the lab findings.

Environmental advantages

Improved drilling performance aside, C14 IOs also have inherent quality and HSE advantages compared with the traditional nonaqueous base fluids used in Western Canada. Environmental benefits include an optimized occupational health and safety profile with regards to the composition and quantity of vapors and faster and more complete degradation due to the chemical structure that provides more disposal options.

From a rig safety standpoint, the flash point of a base fluid is an important aspect. The industry considers fluids as flammable if their flashpoints are below 100° F. and combustible if they are between 100° F. and 200° F. Conversely, fluids with a flashpoint of more than 200° F. have become an unofficial standard for improved HSE. Moreover, a high flashpoint correlates with lower vapor pressures reducing personnel exposure. The C14 synthetic olefin has a flash point of 241° F., thus exceeding the unofficial standard.

The PAH content also is an important consideration, strictly from an environmental perspective. These carbon compounds have two or more fused aromatic rings. Although PAHs may constitute only a minor fraction of total hydrocarbons, these substances tend to persist and bioaccumulate. As a result, PAHs may remain in soils or sediments even when they were only a small fraction of the original mixture introduced to the soil.

Companies manufacture synthetic olefins from purified feedstock (ethylene). Synthetic olefins contain less than 0.001% PAH content by weight,1 which is the lowest level attained by any base fluid on the market. Disposal of this fluid has a relatively low effect on the environment, thereby effectively eliminating present and future PAH-related liability.

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Thus, C14 synthetic olefins degrade faster and more completely than many other nonaqueous base fluids, according to the results of several tests performed in a greenhouse lab.2 Fig. 4 shows gas chromatography scans of C14 hydrocarbons, containing 98% IO. The chemistry of these base fluids allows for degradation to nondetectable levels through volatilization and bioremediation.

Laboratory tests simulated the degradation of the base fluid applied to drill cuttings. The beginning concentration was 10% total petroleum hydrocarbons (TPH) by weight, which is a typical value for TPH retained on cuttings that shakers at the drilling rig remove.

The tests involved mixing the cuttings and fluid with peat moss and bacteria provided by the native soil from the area. The experiment maintained the mound moisture content at 70% field capacity. The tests included turning and aerating the mound once a week and keeping the nutrients in the appropriate range and ratio to ensure most efficient growth and reproduction of bacteria.

Because of these efforts, the temperature remained high throughout the experiment. Decreases in temperature correlate to lower than normal degradation rates and the consumption of the food source, thus proving the relationship between temperature and growth of the bacterial colony. The experiment lasted about 35 days, at which time only 0.49% hydrocarbons remained on the cuttings. This trace amount eventually degraded to undetectable levels.

A recent study determined the toxicity of six different base fluids ranging from diesel to olefins. The study involved initially applying each base fluid to clay soil at 2% by weight and bioremediating it for 90 days. Tests of the resulting material on various plant and animal species determined its residual toxicity. C14 IO showed no toxicity to barley, canola, or alfalfa in either categories of emergence or root elongation. This is true also for earthworm survival; furthermore, C14 IO was the only fluid to demonstrate no toxic effect in springtail survival.

Other fluids did not have the same favorable effects on each of these species, proving that C14 IO-based fluid is better in the category of nontoxic effects.

Accordingly, complete degradation and low toxicity make C14 IO fluids and other fluids of similar chemistry better suited for alternative methods of disposal, such as composting, land farming, vermiculture, and the use of bioreactors. In the past, companies considered attempts to bioremediate other types of nonaqueous base fluids unsuccessful due to excessively long treatment periods and incomplete degradation.

Fluids containing branched and cyclic hydrocarbon structures are not available as readily to bacterial degradation as linear molecules. Thus, one can attribute the failure of bioremediation projects mostly to unfavorable hydrocarbon chemistry.3

Fig. 4 compares the hydrocarbon fingerprint of C14 IO with that of a typical mineral oil. Notice that the mineral oil spectrum contains a large hump that represents the aromatic, branched, and cyclic components. Switching to linear C14 IO improves the probability that all residuals will degrade by the end of the bioremdiation process. Eliminating haul off and disposal will introduce additional cost savings to any land-based project.

References

  1. Environmental Aspects of the Use and Disposal of Non Aqueous Drilling Fluids Associated with Offshore Oil and Gas Operations, International Association of Oil and Gas. Report No. 342, May 2003.
  2. Lee, B., Visser, S., Fleece, T., and Krieger, D., “Bioremediation and Ecotoxicity of Drilling Fluids Used for Land-Based Drilling,” AADE-02-DFWM-HO-15, American Association of Drilling Engineers Technology Conference, Houston, Apr. 2-3, 2002.
  3. Curtis G.W., Growcock, F.B., Candler, J.E., Rabke, S.P., and Getliff, J., “Can Synthetic-Based Muds Be Designed to Enhance Soil Quality?” AADE-01-NC-HO-11, AADE National Drilling Technical Conference, Houston, Mar. 27-29, 2001.

The authors

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Eric van Oort ([email protected]) is planning and business improvement manager for the regional wells leadership team of Shell Exploration and Production, Houston. He previously worked at Shell Research in the Hague on shale stability problems and drilling fluid design. In Houston he has led the global borehole stability team, as well as the fluids team and the real-time operations center hubs for Shell E&P Americas where he worked on a large variety of different optimization projects. Van Oort has a PhD in chemical physics from University of Amsterdam.

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Jim Friedheim ([email protected]) is corporate director of fluids research and development for M-I SWACO, Houston. He previous worked for IMCO Services as a drilling fluids engineer in the Gulf of Mexico and South Texas as well as various other jobs within M-I Drilling Fluid. Friedheim has a PhD in organic chemistry from University of Texas at Austin.

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John Lee is a team leader of product application for M-I SWACO’s R&D department in Houston. He previously worked for IMCO Services in the field, R&D, and analytical departments. His specialization is clay mineralogy and shale stabilization, and he has developed various water-based and invert drilling fluid systems to enhance shale inhibition and wellbore stabilization. Lee has a PhD in geosciences from Texas Tech University.

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Kayli Clements is senior environmental scientist for MI SWACO, Houston, where she provides global support for onshore waste management issues through greenhouse research, technical knowledge, and customer involvement. Her areas of concentration are in beneficial reuse of drill cuttings and development of ecotoxicity tests to qualify fluids and additives for land-based drilling. Clements has a biological engineering degree from Louisiana State University.