Wallace White
Marathon Oil Co.
Lafayette, La.Alan McLean, Sandy Park
M-1 Drilling Fluids
Houston
Improved drilling practices, combined with the use of olefin-based synthetic drilling fluids, have dramatically reduced drilling time and costs in a difficult drilling area in the Gulf of Mexico. In the South Pass area, Marathon Oil Co. and other operators have had wells with long drilling times and high costs. While developing better drilling practices, Marathon reduced drilling days by 60% on one South Pass platform (Fig. 1) (76701 bytes). Continued refinement of these practices has led to two wells with record-setting penetration rates of 7,436 ft and 8,407 ft of 9 7/8-in. hole drilled in 24 hr each (OGJ, June 6, 1994, p. 41). On the second record well, a depth of 14,598 ft was reached just 12 days after spudding in.
In addition to the two wells with record penetration rates, routine drilling rates have also increased from the use of synthetic mud and careful drilling practices. Through application of these improved drilling practices, 2,000-3,000 ft/day can be drilled routinely. With proper planning, long intervals can be drilled quickly with a single bit run. The main goal is to drill the most wells for the least cost. Marathon achieves this goal by applying the experience gained on previous wells, properly training and involving the crews, and using innovative drilling systems. Improved drilling practices and systems are just one part of successful, efficient drilling. Rig site personnel are major contributors to safely and successfully drilling at high penetration rates for extended periods. The experience required to achieve this performance was gained over several wells and should not be expected immediately. The on site personnel must act as a team and have the confidence and proper mental attitude about what is going on downhole.
Because of the amount of activity associated with drilling up to seven stands per hour, rig crews and service personnel must be motivated and keyed in on doing their jobs safely and efficiently. Vigilance while drilling at penetration rates greater than 500 ft/hr (some reached 1,950 ft/hr) is essential to having any chance of detecting well bore instability or changes in formation pressures.
The need for adequate offset well data is another key factor. This information must be available and fully understood by the drilling team at the rig site. There is no time to formulate a strategy after drilling has begun. Each person on the drilling team must know his job and responsibilities before drilling operations commence.
DRILLING HISTORY
Marathon has extensive drilling experience in the South Pass area. The company has experienced drilling problems such as hole instability that has resulted in mechanical failures, bit balling, poor hole cleaning because of hole enlargement, stuck pipe incidents, and lost circulation.
Shales in the area contain up to 4017, reactive clays (Fig. 2) (40770 bytes). Because of the reactive nature of the shales, many inhibitive water-based muds have been tried with limited success.
Systems with low alkalinity and inhibitive systems using partially hydrolyzed polyacrylamide (PHPA) polymers, potassium inhibitors (KOH and KCI), and sodium chloride salt were all tried. Swelling and dispersion testing was conducted to try to determine the best inhibitive system. Several inhibitive water-based systems and diesel-based mud were tested (Fig. 3) (62909 bytes). As expected, the diesel-based mud was far superior to the water-based systems.
Diesel-based mud, however, was not used because of its environmental liabilities. Therefore, a synthetic-based mud system (Novadril) was selected as an alternative to in oil-based mud. Drilling practices had to be modified to take advantage of the benefits and limitations of the synthetic fluid.
SYNTHETIC DRILLING FLUID
The mud was a polyalphaolefin (PAO) synthetic and had several operational and environmental advantages for efficient drilling.
The major advantages of a synthetic mud system are well bore stability, the ability to discharge cuttings to the sea, and a reduction in torque and drag. Well bore stability is an important factor in the ability to drill fast and maintain a successful interval.
The PAO system has provided extremely stable well bores during drilling in the very reactive shales and clays in the South Pass area. The synthetic, nonaqueous external phase in contact with these shales provides excellent inhibition. Synthetic-based mud does not allow hydration of the water-sensitive shales. This lack of interaction between the mud and the shale has eliminated the problem of gumbo balls often formed at the bit and bottom hole assembly (BHA). With water-based muds, in contrast, packing off from bit balling is often a problem.
The improved well bore stability has resulted in gauge holes, which in turn allow an increase in annular velocity for any given flow rate. The higher annular velocity improves hole cleaning and reduces stuck pipe associated with cuttings bed buildup, often a problem with dispersed water-based muds and oil-based muds. The PAO system reduced torque and drag accordingly.
The PAO system has excellent heat transfer characteristics. Thus, the bit's cutting surfaces are cooled very quickly. PAO muds coat the polycrystalline diamond compact (PDC) cutting structures to help prevent cuttings buildup. The cooling, coating, and lubrication qualities of PAO help to increase bit life and reduce downhole torque.
CUTTINGS HANDLING
Equally important to fast drilling is the ability to discharge high volumes of cuttings directly to the sea. Eliminating the need for cuttings storage, transportation, or injection improves drilling economics. The PAO mud passes all current environmental regulations for discharge to the sea. The environmental acceptability of the mud eliminated the barrier to fast drilling that oil-based muds presently have because of cuttings handling and associated environmental risks,
During drilling of one South Pass well, approximately 365 tons of cuttings were removed from the well bore and discharged directly to the sea in 24 hr. Another 143 tons of cuttings were discharged in the next 24 hr (508 tons of cuttings removed and discharged in just over 2 days). Numerous cuttings boxes (about eighty-nine 25-bbl capacity boxes) would be required to transport this volume of cuttings and mud retained on the cuttings off the rig if an oil-based mud were used in place of the synthetic system. The logistics of handling this quantity of cuttings in special boxes or by other means would limit the drilling rate. (The rate would have been slowed to accommodate cuttings collection and logistics.)
On another South Pass well, more than 470 tons of cuttings were removed from the hole in less than 24 hr when 7,000 ft of 12 1/4-in. hole were drilled. This volume would equate to handling approximately 82 cuttings boxes in those 24 hr.
Drilling with the synthetic system reduces discharges of primary pollutants. Because the synthetic mud system drills more in-gauge holes than water-based mud, fewer cuttings are produced, lowering the cuttings discharge volume. Also, because the system is reused, no whole mud is dumped.
HOLE CLEANING
Hole cleaning and minimizing cuttings beds are common problems in drilling directional wells.
The PAO synthetic mud system has a nonlinear relationship between viscosity and temperature because of the characteristics of its external PAO phase. At temperatures below approximately 1600 F., the viscosity of this drilling fluid increases more rapidly than that of a mineral oil or diesel fluid. At temperatures greater than 160 F., large increases in temperature have less effect, and viscosity changes are minimized. These effects allow the PAO system to provide excellent cuttings carrying capacity in the lower temperature, upper sections of the hole. Annular sizes are larger in these sections, and cuttings removal is more difficult because of reduced annular velocities.
The synthetic system rheologies can be chemically modified to increase the low shear rate viscosities of the fluid. With respect to rheology, high initial gel strengths and increased 6 and 3 rpm readings can help reduce cuttings bed buildup.
The ability of the synthetic system to remove cuttings quickly during the first circulation and keep the cuttings from dispersing in the fluid phase is a major benefit in solids control. The large, competent cuttings produced when drilling shale with this PAO system and a PDC bit can be removed efficiently at the primary shakers.
Competent, large cuttings have a small surface area, thereby reducing the amount of synthetic mud discharged to the sea on the cuttings. Thus, the total volume of PAO mud discharged is low, reducing both the environmental impact and costs (by preserving as much of the mud as possible). Field experience has shown that less PAO mud adheres to cuttings than oil-based mud.
DRILLING PRACTICES
Several drilling practices were modified specifically for drilling long gauge-hole intervals with a top drive and PDC bit. Although gauge holes are advantageous, they also create several unique problems.
Marathon typically uses synthetic-based muds in drilling below surface casing in these difficult wells. Cement is displaced with seawater, and the synthetic-based mud system is displaced into the hole prior to drilling out of the surface casing. The surface casing shoe is tested using the synthetic system.
SHORT TRIPS
Short trips are eliminated as a standard practice while drilling with the synthetic-based fluid system. The objective is to drill the hole interval as quickly as possible and use the top drive to backream out of each new hole section.
Because of cuttings loads in the hole when drilling is stopped prior to tripping out of the hole or because of mechanical problems, the hole must be circulated until no more cuttings are observed at the shakers. This circulation is required because excessive cuttings in a gauge annulus will lead to hole packoff and stuck pipe.
While tripping out of holes with a diameter of 8 1/2 in. or less, the pipe should be pumped out (pulled up with the mud pumps on) of the hole to reduce swab pressures. Experience has shown that shales in stressed areas around salt domes tend to fall in if the pipe is merely pulled out of the hole instead of pumped out.
Conditioning trips between logging runs are typically eliminated because the PAO mud provides good well bore stability. Casing is routinely run without conditioning trips, if no problems are encountered during logging.
ANNULAR VELOCITY
Hole cleaning is a limiting factor to fast drilling. High annular velocities are needed to reduce cuttings loads in the annulus. Marathon requires a minimum of 175 fpm annular velocity in the open hole around the drill pipe. If this velocity rate is not possible, drilling rates must be reduced to avoid cuttings load in the annulus. To illustrate the importance of high annular velocities, on one well at a drilling rate 1,900 ft/hr with an annular velocity of 300 fpm, the hole attempted to pack off with a cuttings load of 8% by volume in the annulus.
Another advantage of high annular velocities is the elimination of cuttings bed buildup in long directional intervals.
In soft formations, jetting the bit to aid in cleaning the cutting structure is not required with synthetic muds. The field practice is to size the bit with the largest jets possible.
Flow rates are maximized during drilling below surface casing. The maximum rate is maintained until the pump pressure limitation is reached. When this limitation is reached, drilling continues using the maximum flow rate attainable with the maximum pump pressure.
SOLIDS CONTROL
The PDC cutting action generates large cuttings which are transported to the surface intact. The rig's solids control equipment must be able to handle large cuttings loads. There is no dispersion of cuttings into the mud system while they are being transported out of the hole.
For large-diameter holes, drilling rates can be limited by the number of primary shakers available. Generally for hole sizes 12/, in. or larger, the solids control system should have three primary shakers cascading onto linear motion shakers. Drilling large hole sizes with fewer shakers is possible, but the drilling rates will be limited.
The primary shakers remove 90% of all cuttings. These shakers are generally equipped with 30-40 mesh screens to allow high flow rates and still remove the large cuttings generated by the PDC bit. For improved efficiency, linear motion shakers should have fine mesh screens to aid in the removal of fine solids and sand.
Centrifuges should also be installed to remove the buildup of colloidal solids and return synthetic-based fluid to the system. A barite recovery unit can be used to process high volumes of the mud. The barite recovery unit's effluent is passed to a high-speed centrifuge to achieve a finer cut point. All solids are discarded, and the PAO is returned to the system for reuse as dilution volume.
For drilling long intervals at high penetration rates, two sets of centrifuges are used. Because of the large load of cuttings removed at the primary shakers, on many rigs the overboard line can be clogged at very fast penetration rates. As a minimum, a 3-in. seawater line is installed on each end of the cuttings trough. A full stream of seawater is pumped through each line during drilling.
BHA
On initial wells, the bottom hole assemblies (BHAs) had full-gauge stabilizers for directional control. The combination of stabilizers and standard-gauge bits to drill in-gauge holes caused some instances of stuck pipe. The stuck pipe probably resulted from the BHA physically wedging in the borehole where slight deviations in angle occur at sand/shale boundaries.
The most frequent stuck pipe occurrences were during backreaming out of the hole. This problem is being solved by using short-gauge bits with full-gauge PDC cutters and slightly undergauge wear pads along with roller reamers (Fig. 4). (35965 bytes) This combination allows the PDC cutters on the gauge of the bit to do the work while the roller reamers allow stabilization without wedging in the slightly deviated sections.
BHAs are limited to only the drill collars and measurement-while-drilling equipment needed to control the well bore directionally. BHA lengths are typically 45-90 ft, which reduces the chances of mechanical and differential sticking. The reduced length of large diameter tools also reduces swab and surge pressures.
Most packed hole assemblies consist of a bit, near bit roller reamer, pony collar, roller reamer, measurement-while-drilling tools, roller reamer, and jars. A string of 30 joints of heavy weight transition pipe is run above the jars for drilling weight. The drilling jars are the same size as the collars and are run in compression. By placing the jars in the drill collars, the maximum jarring action can be provided to the BHA. Spiral drill collars and transition pipe are used whenever possible to reduce contact area against the formation. Less pipe contact reduces the chances of differential sticking.
LOST CIRCULATION
Lost circulation is a large concern because of the cost of synthetic muds. Recovering from a serious lost circulation problem with a synthetic mud is harder than it is with water-based systems. In this respect, the synthetic system is more like an oil-based mud.
The PAO synthetic fluid's viscosity profile that benefits hole cleaning also increases equivalent circulating densities (ECDs), risk of formation fractures, and risk of lost returns. Even so, the system has been used successfully to drill depleted sands (4,000 psi overbalance) without significant losses. Fibrous lost circulation materials are typically used to minimize seepage losses and to seal sands.
Fractures in sands or shales present the greatest risk for lost returns. Mud losses can be large if a sand or sand/shale interface becomes fractured. These losses are hard to stop.
Great car has to be taken to avoid excessive sur and swab pressures as ECDs approach casing leak-off test values or formation fracture gradients. A 1.5-ppg margin between the shoe test and the ECD at the shoe will maintain formation integrity.
The ECD value monitored is the ECD of the mud and cuttings that are being transported. This ECD value can be much greater than the ECD for the mud alone during fast drilling. The following are some of the procedures that can help prevent lost returns:
- Monitoring trip rates
- Starting and stopping pumps slowly
- Rotating pipe when the mud pumps are started
- Staging in and circulating after long trips when the mud is cold
- Adding lost circulation material during drilling.
In some cases, mud losses are tolerated because the cost is offset by the large reduction in total days to drill the well.
THE AUTHOR
Since joining Marathon in 1989, he has worked on-site and staff positions on development and exploratory drilling operations. White received a BS in petroleum engineering from Mississippi State University in 1977.
Copyright 1995 Oil & Gas Journal. All Rights Reserved.