INCREASING WATER-DRILLING HYDRAULICS HELPS IMPROVE DRILLING PERFORMANCE

James Andrew
Sutherland Shell Canada Ltd.
Calgary

Higher annular velocities are instrumental in reducing total drilling time. The higher annular velocities maintain a clean well to help prevent well bore problems.

Additionally, maximizing bit hydraulic horsepower and bit impact force result in higher penetration rates in Canadian hardrock-formation wells.

Shell Canada Ltd. conducted a practical field study to show the effects of elevated water-drilling hydraulics (increased annular velocities and bit hydraulic horsepower) on annular and bottom hole cleaning, penetration rates, bit life, and hole problems.

The data represent 36 development wells drilled in 4 years in the Virginia Hills oil field in central Alberta. Seventeen wells were drilled using conventional hydraulics programs, and 19 subsequent wells were drilled using substantially higher hydraulics.

The information collected is accurate field data.

The 36 wells are in geologically similar areas, and the wells had identical operating parameters, bits, and hole sizes.

The results quantify the benefits of improved hydraulics and challenge a number of negative arguments including:

Incremental fuel costs may be greater than savings from higher hydraulics.
Increased hydraulics may have little benefit in hardrock Mississippian and Devonian carbonates.
High annular velocities may cause severe borehole erosion.
High pump rates may increase pump wear and pump down time.

WELL DESIGN

The basic geology within the study area is similar to that of the entire Western Canadian basin. Thus, the results of the study can be applied to all of Shell Canada's plains operations.

In this area, the wells typically drilled approximately 5,900 ft of Cretaceous shales, 660 ft of Mississippian carbonates and shales, and another 2,950 ft of Devonian carbonates and shales. A short chert section at a depth of 6,230 ft and sandstone stringers at approximately 2,950 ft, 4,590 ft, and 5,740 ft caused accelerated bit wear and therefore required drilling at reduced rotary speed and weight on bit (WOB).

All of the wells had surface casing set at approximately 590 ft and then drilled out with 8 3/4-in. or 7 7/8-in. bits. The wells were then drilled to an average depth of 9,500 ft prior to running 5 1/2-in. production casing.

All of the wells used freshwater to drill as deep as hole conditions would permit before drilling fluid was converted to a mud system (mudding-up) for coring operations at 9,000 ft. Optimized drilling results from maximizing water drilling depth without running into hole problems, the worst of which is stuck pipe caused by poor hole cleaning.

INITIAL STUDY

Prior to the 19-well drilling program in 1988, Shell studied the drilling performance of 17 offset wells drilled during the previous 3 years. One significant problem noted in the study was that poor hole cleaning limited drilling performance. The symptoms of hole cleaning problems included the following:

Mud-up depth was limited by fill during connections, tight hole, and reaming.
Several instances of stuck pipe occurred prior to or just after mud-up.
Because torque and drag were high, routine additions of oil to the mud were required to increase lubricity.

In addition to the poor annular hole cleaning, bottom hole cleaning was less than optimal. Thus, for the subsequent 19-well program, several drilling design parameters were adjusted:

Average annular velocities were increased 78%, from 148 fpm to 262 fpm. This was partially accomplished by reducing hole size from 8 3/4 in. to 7 7/8 in.
Bit hydraulic horsepower was increased 128%, from 2.77 hydraulic hp/sq in. to 6.31 hydraulic hp/sq in.
Bit impact force was increased 150%, from 337 lb to 843 lb.

Substantial effort was made to maintain data accuracy by controlling as many parameters as was feasible. This was successfully achieved during the 19-well program, but the earlier wells had inconsistencies with regard to operating parameters, bit selection, and bit run intervals.

For the 19-well program, all bits were similar and were selected based on past successful performance.

WOB and rotary speed were similar for each bit interval on all holes.

Although previous wells were drilled with 8 3/4-in. bits and not 7 7/8-in. bits, similar operating parameters were used throughout, based on years of experience in the area.

RESULTS

With the changes in the hydraulics program, the 19 wells were drilled in an average 19 days/well compared to 25 days/well for the six wells of the preceding year and 29 days/well for the entire previous 17-well program.

The higher drilling efficiency was a result of reductions in rotating, trip, and problem times (Figs. 1-2). Fig. 3 reviews the number of wells drilled per year.

The 19 wells in the latest drilling program were drilled more quickly as a result of better hole cleaning. The mud-up depth increased from an average of 7,500 ft to 8,530 ft. Mud-up was ultimately controlled by petrophysical requirements and not hole conditions.

There were no instances of stuck pipe, and reaming time was minimal in the 19 wells. Total problem time was reduced 85%, from an average of 67 hr to 10 hr. Because torque and drag were minimal, oil additions to the mud were eliminated.

Additionally, the bottom of the well bore was kept cleaner, thereby increasing the bit efficiency. Average rotating time to core point decreased 32%, from 256 hr to 175 hr. There were corresponding increases in rate of penetration (ROP) of 15-80%.

BITS

A comparison of bit run performances over the previous 3 years shows the significant effect of increased hydraulics. The intervals are the averages of the depths drilled by all the bits from 1984 to 1989 (Table 1).

Bit No. 1 typically drilled out from the surface casing to a depth of 3,600 ft. Bit No. 1 showed a 30% increase in ROP from 103 ft/hr to 134 ft/hr.
Bit No. 2, which drilled from 3,600 ft to 5,900 ft, also had a 30% increase in ROP from 47 ft/hr to 58 ft/hr.
Bit No. 3, which drilled from 5,900 ft to 7,900 ft, experienced a 33% increase from 22 ft/hr to 29 ft/hr. This difference was partially a result of shallower mud-up depths necessary in earlier wells to alleviate the poor hole cleaning.
Bit No. 4 drilled from 7,900 ft to 9,200 ft and had an average 67% increase from 16 ft/hr to 26 ft/hr. A substantial portion of this increase was due to drilling with water longer for the last 15 wells.

The overall average decrease in rotating hours from surface casing to core point was 81 hr, with the best performance 111 hr less than that of previous years.

The combination of better bottom hole cleaning and faster penetration rates allowed all 19 holes to be drilled to the core point with four bits or less, whereas most previous wells required five or more bits to drill to the core point.

The final two wells of the program eliminated bit No. 4, yet the wells had competitive penetration rates which reduced total cost per foot.

Several nozzle configurations were used including three standard, three mini-extended, two mini-extended and one blank, two mini-extended and one center jet, and directed nozzles (the Reed Tool Co. Mudpick). Unfortunately, this comparison did not show consistent results.

At elevated levels of bit hydraulic horsepower and flow rates, it is possible that the additional benefit of improved bottom hole cleaning from nozzle configuration could be relatively small.

A study of the relative effect of bit hydraulic horsepower and jet velocity on penetration rate showed bit hydraulic horsepower to have a much greater effect. This suggested that bit hydraulic power should be maximized for optimum drilling. Because of scatter in available data, bit hydraulic horsepower could not be distinguished from bit impact force.

One well was drilled with a design to optimize jet velocity at the expense of bit hydraulic horsepower, resulting in the poorest average rotating hours of all wells drilled. It was drilled in 208 hr, significantly longer than the 19-well average of 175 hr and the program best of 146 hr.

The analysis also showed, contrary to previous opinion, that higher bit hydraulic horsepower increased ROP in medium-hard Devonian limestone/dolomite.

PENETRATION RATES

Three rigs of varying pump capacities were used for the elevated-hydraulics program. Because of pump limitations, Rig No. 1 ran lower pump rates and pressures than Rig No. 3 or No. 16.

Rig No. 16 was equipped with small-ID drill collars, and was therefore unable to match Rig No. 3's bit hydraulic horsepower levels with selected pump rates and working pressures.

A comparison of Rig No. 1 (lowest hydraulics) to Rig No. 3 (highest hydraulics) shows results similar to those found in Table 1, though less pronounced. Rig No. 3 maintained approximately 70% higher bit hydraulic horsepower levels, 20% higher jet velocities, and 17% higher annular velocities. This rig consistently drilled better than Rig No. 1 by an average of 12% for each bit run (Table 2).

Comparison of data from Tables 1 and 2 shows that the most significant gains in ROP (average 25% increase) were a result of the initial 65% increase in bit hydraulic horsepower. This is a comparison of hydraulic horsepower from wells drilled before 1988 to wells drilled by Rig No. 1.

Pumping equipment sized for drilling at hydraulic levels as on Rig No. 3 produced the highest gains. However, further benefits can be realized by working at even higher hydraulic levels, and the maximum level becomes defined by the point of diminishing returns. Because of pump limitations, this point was not found during this program.

PUMP WEAR

Rig No. 1 was equipped with two duplex Emsco D700 pumps and two Caterpillar D379 diesel engines. Rigs No. 3 and No. 16 were equipped with triplex pumps (two National 8-P-80 pumps on Rig No. 3 and one Gardner Denver PZ-8 and one PZ-9 on Rig No. 16) and each with three D379 Caterpillar diesel engines.

Rigs No. 3 and No. 16 had no problems operating under the specified conditions: flow rates of at least 475 gpm with both pumps operating and standpipe pressure of 2,200-2,300 psi. Neither rig suffered pump-related problems or accelerated head, liner, or valve seat wear.

Rig No. 1, however, experienced problems at these flow rates and pressures. Mechanical downtime because of worn gaskets and valve seats forced a reduction in pump rate to 409 gpm and in pressure to 1,740 psi to limit problems.

HOLE WASHOUT

Average hole size from four-arm calipers was plotted against jet velocity, bit hydraulic horsepower, annular velocity (gauge and actual), total drilling days, and waterdrilling days to determine the most important variable affecting hole washout. Although the data were quite scattered, high jet velocity and water-drilling days were common variables in all large boreholes.

All well data were arranged from highest to lowest jet velocity, and the median velocity was determined. All data points above this value were grouped together as Data Set 1 to find an average "high" jet velocity, and all points below grouped as Data Set 2 for an average "low" jet velocity.

Next, Data Set 1 was sorted from highest to lowest by the water-drilling days. The median was determined to separate the data above and below into groups, each with an average high and low value for water-drilling days. Data Set 2 was similarly sorted.

From a comparison of average hole washout for each of the four groups, it was found that the effect of jet velocity was about three times the effect of the waterdrilling days (Fig. 4).

The average increase in hole diameter was 2.3 in./well for the elevated-hydraulics wells compared to 1.9 in./well for the 1 7 holes drilled prior to 1988-89. Because the elevated-hydraulics wells were drilled with 7 7/8-in. bits rather than 8 3/4-in. bits, the actual average hole size was in fact smaller (10.2 in. compared to 10.7 in. for the 17 original wells).

Thus, the small additional enlargement, if a result of elevated hydraulics, was negated by the reduction in hole size from the smaller bits. Table 3 shows that the increased washout was minor compared to the benefits in annular and bottom hole cleaning from higher annular velocities.

FUEL COST

Each rig used an average of 211 gpd of fuel above the 977 gpd specified by contract and about 264 gpd over normal consumption. At a fuel price of $0.97/gal and a drilling rate of 19 days per hole, each well cost approximately $4,900 extra in fuel costs. This cost is minimal compared to the average reduction in drilling time of 6 days/well.

CONCLUSIONS

Shell Canada reported these results from the project:

Higher annular velocities substantially increased annular hole cleaning as shown by lack of stuck pipe, minimal torque and drag, less fill on connections, and increased mud-up depth.
Enhanced bottom hole cleaning was demonstrated by elimination of two bits to drill the same depth hole and by the increase in ROP.
Bit hydraulic horsepower and bit impact force, not jet velocity, should be maximized for higher penetration rates in similar formations.
Obtaining required annular velocity should be the first priority of an hydraulics program (at the expense of bit hydraulic horsepower if necessary).
Jet velocity and waterdrilling days were the most significant factors in hole enlargement for the geological environment and range of operating parameters used in the Virginia Hills area.
Various nozzle configurations had a minor effect at elevated hydraulics levels.
Accelerated pump wear was minimal using elevated hydraulics with properly sized and maintained triplex pumps.
Extra fuel costs associated with elevated hydraulics were small compared to overall savings from increased penetration rates and better hole cleaning.