Field Application of Lightweight, Hollow-Glass Sphere Drilling Fluid

Solids control system

Light weight solid additives (LWSA’s) for drilling-fluid-density reduction were tested in the laboratory and in a test yard in drillingrig-compatible equipment. The primary objective of the project since that time has been to test underbalanceddrilling products in actual field operations.

The LWSA tested consists of HGS’s manufactured in the U.S. and commonly used as a filler material for other lightweight products. The spheres have an average specific gravity of 0.37, collapse strength of 3,000 psi, and average 50 μm in diameter.

The fluid uses hollow glass spheres (HGS’s) to decrease the fluid density to less than that of the base mud while maintaining incompressibility. Concentrations of up to 20 vol% were used to decrease the fluid density to 0.8 lbm/gal less than normally used in the field.

Potential benefits of using these fluids include higher penetration rates, decreased formation damage, and lost-circulation mitigation. When used in place of aerated fluid, they can eliminate compressor usage and allow the use of mud-pulse measurement- while-drilling tools.

These and other recent advances in technology have spurred interest in underbalanced drilling to the highest level in 30 years. Industry-wide surveys indicate that more than 12% of wells drilled in the U.S. will intentionally use underbalanced techniques.


The U.S. DOE recognizes the benefits of advanced technology to the oil and gas industry. Consequently, the U.S. DOE manages a portfolio of drilling-related research, development, and demonstration projects designed to reduce cost and increase process efficiency. These drillingrelated projects support the department’s ultimate goal of developing the nation’s large natural-gas resource base and maintaining market-responsive supplies at competitive prices.

Underbalanced-drilling products are investigated because of their potential to increase drilling rate as well as for their potential to retain maximum well productivity by minimizing drilling-induced formation damage. LWSA fluids represent one such underbalanced-drilling technology.


Wells were optimum for the initial field tests because they were relatively shallow wells, allowing more than one well to be tested quickly with HGS’s. The wells would be approximately 1,200 ft deep and would require small volumes of mud. Initial indications were that only 200 bbl of mud would be required for each well.

The initial plan called for tests in three to four wells; however, during drilling of the first two wells, a much larger volume of mud was required than originally anticipated. After the second well was successfully drilled, all useful information had been gathered at this location, pre-empting the need for additional data collection.


The main objective of these field tests was to determine whether a well could be drilled with the LWSA in the drilling mud. Other objectives were to demonstrate the following.

  1. The ability to mix LWSA safely and easily into drilling fluid under normal field conditions.
  2. The compatibility of LWSA with conventional drilling fluids. 
  3. The durability of the LWSA during circulation downhole through conventional bits, mud motors, and surface equipment . 
  4. The ability to reuse or recycle the mud on more than one well. 
  5. The lack of detrimental effects on conventional drilling equipment. 
  6. The minimal environmental effect of the LWSA.

Pilot Tests

Pilot tests conducted by the mud company before the field tests demonstrated that LWSA additions of 10 vol% had very little effect on the rheology of the mud. The pilot test results demonstrated that no compatibility problems existed between the  LWSA and the base mud, allowing the field tests to proceed.

General Procedures

The LWSA was added to the first well at concentrations up to 10 vol% and to the second well at concentrations up to 20 vol%. In both cases, the LWSA performed better than expected. Attrition rate for the LWSA was less than 10%, exceeding expectations based on the manufacturer’s specifications. More than 40 samples were taken from various points in the mud system during the drilling operations of these wells; these were sent to a laboratory for analysis of HGS content of each sample.


Mixing the LWSA into the drilling mud was expected to be the most significant logistical problem. During yard testing, the product was added conventionally by dumping it into a normal mud hopper or by dumping it directly into the pit. However, the large volumes required for a full-scale field test precluded dumping the product.

The LWSA was mixed into the mud with the manufacturer’s recommended procedure for similar products. This mixing system used a conventional double-diaphragm pump to transfer the glass bubbles from the package into the fluid.

The initial mud volume was determined on site. The amount of spheres required to reach the desired volume percent was calculated, and mixing was begun. With the small volume of mud initially built, one to two 640-lbm boxes of spheres were required. By the time this was added, enough additional mud had been built to require further LWSA additions.

For both wells, the desired LWSA loading was reached after approximately three boxes of product were added (i.e., about 2.5 to 3 hours). At the rate the wells were drilled (approximately 60 to 80 ft/hr), product additions had to be made at the rate of about one box every 2 to 3 hours.

Environmental Concerns

The primary concern regarding environmental effects of the spheres, in particular while mixing them into the mud pit, was whether the LWSA would become airborne as dust because of its low specific gravity. This concern  was addressed by injecting the dry product through a hose lowered as deeply as possible into the conventional mud hopper on the mud pit system. No dust was produced while mixing the HGS’s.


General LWSA Mud Properties

The mud engineer normally controls the drilling fluid in the Midway-Sunset field by keeping the funnel viscosity (FV) of the mud in the 38 to 40 sec/qt range. If the FV is less than 38 sec/qt, additional gel (or bentonite) is added. If the FV is greater than 40 sec/qt, additional water is added or an attempt is made to “clean” the mud by dumping a sand trap from the mud-pit system.

The FV for the mud used in Well 1 varied from 34 to 44 sec/qt. This is a wider range than desired for the mud, but was acceptable. The FV measured in Well 1 was essentially independent of the LWSA concentration.

The FV measured with 13 vol% LWSA is about the same as that measured with only 3 vol% LWSA. The FV was higher than the desired range for most of Well 2, because the concentration of LWSA was higher in this well than in Well 1, reaching concentrations as high as 19%. In Well 2 increasing the volume percent of LWSA generally tended to increase the FV.

The American Petroleum Inst. (API) fluid loss was relatively unaffected by the addition of LWSA to the mud. Measured API fluid loss changed less than 1% during the drilling of these wells. This agreed with the laboratory tests. The measured plastic viscosity and yield point for these two mud systems were within acceptable ranges for drilling fluids.

Maintaining LWSA Concentration

In general, LWSA concentration in the drilling fluid was determined on the basis of the density of the fluid. As much as possible, all additions to and subtractions from the mud system were measured. The pit volume was always known because it was a compartmentalized steel tank. The mud engineer noted all dry-product additions.

A water meter was installed on the water-inlet line to the mud-pit system, and the initial meter reading recorded. The sand traps on the steel-pit system were dumped periodically to control the FV. These volumes were noted and accounted for in calculations of the volume percent of LWSA.

Because the pit system for this rig is relatively small (less than 90 bbl), a small change in volume of any one constituent can make a large percentage change in the concentration of that or any other additive.

The unknown parameters with the most impact (besides unmeasured losses) were the amount or volume of drill cuttings generated and the amount of drill cuttings dumped into the sump by the solids-control equipment. These volumes were inferred by use of history matching.

A spreadsheet was used to perform a volume balance. Parameters were varied until the predicted mud density matched typical or historical mud densities measured in this field. The matched values were then entered into the spreadsheet, and calculated volume percents of LWSA were compared with the known volumes being added to the mud.

The measured volume of LWSA added to the drilling fluid was used to calculate a theoretical mud weight (MW) in pounds per gallon. This result was compared with the actual measured MW to determine attrition of the LWSA.

When the theoretical or calculated MW matches the measured MW, no HGS’s are being lost in the system. Potential forms of LWSA attrition include breakage, loss downhole (either through loss of whole mud or through embedment in the wellbore wall), loss of whole mud at the surface, and loss through the solids control equipment.

MW (Fluid Density)

The calculated MW closely matched the measured MW at all depths in the first well, indicating minimal loss of LWSA. Initially, the measured MW’s were slightly higher than the calculated theoretical weights, indicating that some LWSA was being lost. At depths greater than 600 ft, however, measured MW was less than calculated MW.

For the second well, the agreement between measured MW and theoretical MW was excellent throughout most of the wellbore, indicating that no LWSA was being lost through attrition. Near the bottom of the well, the measured MW was higher than the calculated value, indicating that some of the LWSA was being lost.

Calculations show that as much as 17 to 32% of the LWSA was lost between 1,391 ft and total depth. Three phenomena explain this apparent LWSA loss:

  1. The mud motor was tripped out of the well at that depth. Again, as on the first well, 10 to 20 bbl of whole mud may have been lost and rebuilt at a higher density. 
  2. The pits were diluted, and the solids control equipment kept running even though mud was not circulating. This could have caused more fluid to be thrown into the sump than estimated. 
  3. The model may not be a perfect match, or some of the input parameters may not be exactly correct.

Volume Percent HGS

The volume of LWSA added was measured, and the volume remaining was calculated on the basis of measured MW. The theoretical and actual LWSA volume percent compared favorably through most of the wellbore in the first well.

The theoretical LWSA volume percent was nearly identical to the amount actually added from surface to near total depth for the second well. The theoretical and actual values deviated at depths greater than approximately 1,400 ft in both wells.

Weight Percent HGS

The results of the volume percent concentration analysis were confirmed by a laboratory analysis of samples taken from the returns line, the pit, and the overflow and underflow from the solids-control equipment. These samples were analyzed on the basis of weight percent. When conversion was made to volume percent the results were consistent with the on-site analysis.

For example, at a depth of 1,051 ft on Well 2 the concentration of glass bubbles in the mud was approximately 17 vol%, which corresponds to a concentration of approximately 4.2 wt%. Mud samples taken from the pit at that time had glassbubble concentrations of 3.8 wt%, indicating a loss of slightly less than 10%.

Effects of Solids-Control Equipment

Extensive work was carried out to determine the effect of conventional solids-control equipment on the LWSA. Earlier yard tests showed that the most desirable solids control system for LWSA muds consisted of a large-mesh-screen shale shaker (less than 100-mesh-screen size) and a high quality mud cleaner with a capacity sufficient to process the entire mud volume.

The shale shaker on the drilling rig had a screen size of 40 to 60 mesh. A mud cleaner with six 4-in. hydrocyclones and a 160- mesh screen was used to drill all wells in the field. The mud-cleaner screen was changed to 120 mesh at a depth of approximately 500 ft on the first well. The shale shaker worked well throughout the tests, but several problems occurred with the mud cleaner.

Because the formation being drilled had a tendency to disperse into the mud, the solids-control equipment alone could not completely control the drilling-fluid properties. So dilution of the mud with water and dumping of mud that was heavily contaminated with drill solids was a common practice on this rig. This “dump-anddilute” procedure made keeping track of all additions to and subtractions from the mud difficult, causing more LWSA to be used per barrel than might otherwise have been required.


Three main factors, other than product cost, will ultimately determine whether the use of LWSA is feasible: whether the rate of penetration (ROP) can be increased as a result of drilling with the lower-density mud, the ability to recycle whole mud containing LWSA, and the ability to recover the LWSA and reuse it on additional wells.

Two other factors can make the use of LWSA worthwhile: the mitigation of lost circulation and a decrease in formation damage because of drilling underbalanced. These tests did not provide any real opportunity to investigate these factors. The consensus of those involved was that these wells would not provide the best test of increasing ROP because they are very shallow and typically can be drilled in less than 2 days, with the ROP ranging from 50 to 100 ft/hr.

Recycling of LWSA Mud

Even though economic success on the initial field tests was not of paramount importance, the best chance of making the initial tests economical would be to recycle the fluid on multiple wells. Saving mud is a normal practice for oil-based drilling fluids because of their cost. The same practice will be appropriate for the LWSA mud. For this case, where only two wells were to be drilled, the cost of a separation unit could not compete with the cost of simply storing the small volume of mud between wells.

The drilling mud used on Well 1 was stored off site in an open-top, 500-bbl tank for 2 days. Approximately 100 bbl of the final mud from Well 1 was salvaged; the rest was either left in the hole or lost to the sump when the casing was cemented in the well. In a deeper well, where a large volume of mud would be involved, approximately the same amount would have been lost, but more mud would be salvaged.

The final mud that was transported to storage weighed 9.1 lbm/gal, which was greater than initially planned. The mud was heavier than desired because LWSA additions were stopped at approximately 1,400 ft because of the potential for a gas kick. 

Approximately 580 ft of hole was drilled with no additions of LWSA (i.e., about 33% of the total drilled). During this time, the mud weight was allowed to drift up as in a normal well. Total depth was reached at 1,780 ft with a mud weight of 9.1 lbm/gal, and the mud was stored for reuse. Further contamination from the tank and the transport trucks increased the mud weight to 9.2 lbm/gal by the time the fluid reached the steel pits for the second well. This fluid contained an estimated 7.8 vol% LWSA, reduced from approximately 13 vol% when additions of LWSA were halted at 1,400 ft.

The second well encountered a lost circulation zone at approximately 154 ft, even though available information indicated no lost circulation was expected for any of the prospective test wells. The total volume of loss was unknown. Lost mud was replaced “on the fly” while drilling continued.

Estimated volume lost was approximately 40 bbl, further decreasing the already minimal savings potential of recycling the mud. The lost circulation was cured with the addition of conventional lost-circulation material.

Recovery and Reuse of LWSA

Because of the condition of the solids-control equipment, the limited space available on each location for necessary equipment, and the recycling of whole mud, no attempt was made during these tests to recover dry LWSA for readdition to a future mud system.


On Well 1, the bottomhole assembly was tripped out and run back to bottom with no reaming required. Typically, these holes must be reamed to bottom after tripping at total depth. This indicates decreased frictional drag in the hole because of the presence of the LWSA.

This was expected because solid plastic and glass spheres are often used as mud additives to reduce friction in high-angle and horizontal wells. This is also consistent with laboratory tests that showed the LWSA reduces casing wear 60 to 70%.

On Well 2, more reaming was required after trips and more wall cake was circulated up than normal for the area, indicating that the wellbores in this field may require a higher MW to prevent shale sloughing.

The LWSA test mud was the lowestweight mud ever run in this field to total depth. The loss of large mud volumes on these wells during trips required much new mud to be built, decreasing the effectiveness of the test.

Analysis of the measurements made on the drilling fluid during the tests showed that the theoretical MW closely matched the measured MW. Accounting for all additions and subtractions to the mud system helped determine a theoretical MW at several points during the tests. These compared very favorably with measured data.


The field tests were successful and demonstrated the following.

  1. The LWSA can be easily and safely mixed into drilling fluid during field operations.
  2. New mud containing LWSA can be built in the field.
  3. The LWSA is compatible with conventional field drilling fluids.
  4. The LWSA can be circulated through a conventional roller-cone, insert bit with little or no destruction of the LWSA.
  5. The LWSA can be circulated through a conventional downhole mud motor with little or no detrimental effect to the LWSA or the motor.
  6. The overall survival rate of the LWSA was within an expected and acceptable range.
  7. The environmental effect of use of the LWSA was minimal.
  8. The LWSA had no apparent detrimental effect on any of the conventional drilling-rig equipment.
  9. The drilling-fluid system was very small (less than 200 bbl active volume), allowing accurate monitoring and measurement of additions and deletions.
  10. LWSA muds appear to be an economical alternative to aerated drilling fluid and should find increased use in the future.
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