PLANNING LESSENS PROBLEMS, GETS BENEFITS OF UNDERBALANCE

March 20, 1995
A horizontal well planned to be drilled underbalanced required special procedures and countermeasures to prevent formation damage from the mud and downhole tool failures from high temperature. Drilling the well underbalanced helped reduce problems from lost returns and from solids entering and plugging the natural fractures in the Austin chalk. The high bottom hole temperature in the deep Austin chalk in central Louisiana complicates drilling, the mud program, and well design.

Robert A. Joseph
OXY U.S.A. Inc.
Houston

A horizontal well planned to be drilled underbalanced required special procedures and countermeasures to prevent formation damage from the mud and downhole tool failures from high temperature.

Drilling the well underbalanced helped reduce problems from lost returns and from solids entering and plugging the natural fractures in the Austin chalk. The high bottom hole temperature in the deep Austin chalk in central Louisiana complicates drilling, the mud program, and well design.

The well plan and procedures were developed from an extensive study of offset wells that had problems with excessive torque and drag, high bottom hole temperatures, drillstring and directional tool failures, large mud losses, downhole plugging and borehole collapse during production, and erratic production.

The first of this two-part series covers the planning, procedures, and well design to alleviate these problems. The next article, which will appear in a future issue, addresses complications during the operation and the equipment used.

In 1994, OXY U.S.A. Inc. drilled and completed the Monroe A No. 1, a 19,100-ft horizontal Austin chalk test well in central Louisiana. The Monroe A No. 1 is believed to be the first horizontal Austin chalk well drilled in an extreme abnormally pressured environment.

Before the Monroe A No. 1 was drilled, several other deep, but lower pressured, horizontal Austin chalk wells had been drilled in central Louisiana. These wells encountered several drilling problems and had poor production.

BACKGROUND

The Austin chalk is a naturally fractured limestone that parallels the Texas and Louisiana gulf coast. The chalk varies in thickness from 200 to 1,000 ft. In most areas of Texas, the Austin chalk is normally pressured.

More than 1,800 horizontal wells have been drilled in the Austin chalk formation in Texas during the late 1980s and early 1990s. These horizontal wells were drilled underbalanced with freshwater. They were typically drilled perpendicular to the natural fractures and had lateral displacements of 4,000 ft or more. The wells had true vertical depths (TVDs) ranging from 6,000 to 12,000 ft, depending on the location in the trend. Some wells had initial production rates as high as several thousand barrels per day, but the production typically declined rapidly.

Following these successes in Texas, four operators drilled six horizontal Austin chalk wells in central Louisiana (Fig. 1) (29908 bytes). The Austin chalk in these wells was encountered at 12,00015,500 ft with pore pressures of 12.0-13.0 ppg and bottom hole temperatures in excess of 300 F. The laterals varied from about 500 ft to 4,000 ft long. The best initial potential reported was 2,566 bo/d and 1,500 Mcfd of gas with a flowing tubing pressure (FTP) of 3,880 psi from the Cliffs Martin A No. 1 .1-3

OFFSET WELLS

After studying the trend and focusing on areas with good chalk shows in vertical wells, OXY U.S.A. Inc. acquired leases in Masters Creek field near McNary, La., with plans to drill a horizontal Austin chalk test well (Fig. 2) (34726 bytes). This site was selected because of encouraging Austin chalk shows and tests in three nearby vertical wells, which were drilled and abandoned in the late 1970s and early 1980s. These three wells all took kicks and had severe lost circulation when the Austin chalk section was being drilled with mud weights in excess of 17.0 ppg:

  • Gulf Wilson& Johnson No. 1 originally drilled in 1977 to 14,753 ft and redrilled in 1978 to 16,860 ft; 3,600 ft south of the Monroe A No. 1 surface location

  • Venture Wilson & Johnson No. 1 drilled in 1980; 3,800 ft southwest of the Monroe A No. 1 surface location

  • Venture Wilson & Johnson No. 2 drilled in 1982; 2.7 miles east-northeast of the Monroe A No. 1 surface location.

In each of these vertical wells, protection casing had been set into the top of the chalk. Mud weights ranging from 11.5 ppg in the first well to 17.1 ppg in the later wells were used to drill below protection casing. In each well, once the chalk's fracture zone was encountered, the well kicked, and the mud weight was raised in an attempt to kill the well. At that point, mechanical problems occurred in each well, resulting in large amounts of mud or cement being pumped into the chalk.

The Gulf Wilson & Johnson No. I well was drilled into the chalk's fracture zone with 11.5-ppg mud and kicked. The protection casing split at 6,013 ft with 15.5 ppg mud in the hole as the mud was weighted up to kill the kick, leading to lost returns and an underground blowout. The well was plugged back, sidetracked, redrilled, and ultimately completed and tested in the Austin chalk.

The Venture Wilson & Johnson No. I lost returns with a 17.1-ppg mud, took a kick, and had an uncontrolled flow for 5 min after the annular preventer rubber ruptured while the kick was circulated out. The shut-in casing pressure from this second kick was 9,200 psi. Subsequently, 17.4-ppg mud was bullheaded to kill the well. The well was completed open hole and tested at 600-1,500 Mcfd of gas.

In the Venture Wilson & Johnson No. 2, the open hole (Austin chalk) was squeeze cemented twice to regain circulation and kill the well after an unspecified amount of 17.2-ppg mud was lost to the chalk. A reportable well test was not obtained despite 5 months of flow testing and several treatments. A static bottom hole pressure survey showed only 10,408 psi, equivalent to 13.7 ppg, with a 325 F. static bottom hole temperature.

None of the three wells was commercial, but they were believed to have suffered significant formation damage because thousands of barrels of heavy mud had been lost to the Austin chalk in each well. The Gulf Wilson & Johnson No. 1 well had the best production test at 1,896 Mcfd of gas, 186 b/d of condensate, 225 bw/d, and 2,100 psi FTP on a 12/64-in. choke from perforations at 14,683-14,796 ft.

Furthermore, because most of the recently drilled central Louisiana horizontal Austin chalk wells were reportedly experiencing erratic production with some incidents of downhole plugging, it appeared that weighted water-based drilling mud could be plugging the fractures and causing formation damage.

WELL PLAN

Because all three vertical offset wells appeared to have encountered geopressured fractures, OXY's geoscientists were confident that Masters Creek field had excellent potential. The challenge was to drill a 4,000-ft lateral section through this extremely high pressured Austin chalk, while minimizing formation damage, to obtain an accurate appraisal of the chalk's potential.

The operational problems of the three vertical offset wells and the six Louisiana horizontal Austin chalk wells, however, created some skepticism about whether a 4,000-ft lateral could even be drilled in this area of the Austin chalk, let alone drilled without severely damaging the formation.

Because the Gulf well had the best production test, OXY decided to permit a 1.0 mile x 1.5 mile unit around the Gulf well (Fig. 2) (34726 bytes). The surface location was spotted 3,600 ft north of the Gulf well with the lateral aimed on a south departure toward and beyond the Gulf well and perpendicular to the chalk's fractures. The longest horizontal displacement that could be permitted, 4,630 ft, would be drilled, thereby providing a 4,000-ft lateral.

The top of the Austin chalk was projected to be at 14,390 ft. After setting of the 9/8-in. protection casing, a pilot hole would be drilled through the Austin chalk and logged to help pick the best fractures and best depth for the lateral. Then, the pilot hole would be plugged back and angle built to land the curve at the depth picked for the lateral, estimated at 14,647 ft TVD, approximately 100 ft above the base of the chalk. A 4,000-ft lateral would be drilled to a 18,967 ft measured depth (MD), at 14,774 ft TVD, on an 88.20 angle to parallel the estimated 1.8 regional dip.

The next step was to devise a well plan to accomplish the geological objectives while overcoming the numerous potential operational problems. These operational problems included the following:

  • Excessive torque, drag, and drillstring failures

    Excessive torque and drag and the inability to slide for oriented drilling were problems in some of the horizontal reference wells, particularly beyond 2,000 ft in the lateral. In some cases these problems led to drillstring failures and fishing jobs.

  • High bottom hole temperature

    The horizontal reference wells had static bottom hole temperatures of 240-320 F. The high temperatures significantly shortened the downhole life of mud motors and measurement-while-drilling (MWD) tools. For this well the calculated circulating temperature was 247 F. for a 300 F. estimated static temperature.

  • Marl section and bentonitic ash streaks

    A marl section at the top of the chalk and thin (1-5 ft) ash streaks within the chalk were probable sources of plugging problems during production. These zones tend to swell when exposed to water-based drilling fluid. All of the horizontal reference wells were initially completed open hole, and in some cases the marl at the top of the chalk was not cased off.

  • Mud losses to the Austin chalk

    Large quantities (estimated at 5,000 bbl) of mud had been lost to the chalk in some of the horizontal reference wells.

  • Erratic productivity

Some of the horizontal reference wells had high initial production, but others had low production from the start. Even the better producers eventually developed downhole plugging problems that curtailed production. The following were the suspected causes for the erratic productivity: drilling mud lost to the fractures, lack of fractures or poor-quality fractures, plugging caused by swelling or collapse of the marl or bentonitic streaks open to the well bore in uncased hole, and borehole collapse of the chalk itself.

The horizontal reference wells were drilled with 11.5-13.0 ppg water-based mud. With the water-based mud at high temperatures, the suspected damage mechanism was mud dehydration, which may leave bentonite, barite, and other solids in a semisolid state in the fractures. This semisolid would dehydrate and be less likely to breakdown and clean up under the differential pressures applied during production.

Because all the horizontal reference wells were initially completed open hole, they were particularly susceptible to formation collapse and plugging.

To minimize these problems, the following countermeasures were adopted for this program:

  • Drill a large hole, and set larger diameter casing at the top of the chalk (9 5/8 in. rather than 7 5/8 in. or 7 in.).

  • Run 9 5/8-in. protection casing as far as possible through the curve (between the 30 and 50 point). Fig. 3 (125380 bytes) shows the directional plan.

  • Use 5-in. high-strength drill pipe in the 8 1/2-in. hole to the end of the lateral.

  • If MWD failures become excessive, use wire-line-retrievable MWD probes to reduce the number of round trips with the drillstring.

  • Use a top drive to provide backream capability, reduce connection time, and reduce trip time during backreaming as the pipe is pulled out of the hole from the lateral.

  • Use a downhole-adjustable stabilizer above the mud motor in the lateral to minimize the amount of slide drilling.

  • Reduce drilling time and exposure time to high bottom hole temperatures (by virtue of the above six countermeasures).

  • Use minimum mud weights, use snubbing equipment to make trips, and avoid killing the well as much as possible.

  • Run a slotted liner in the horizontal section for testing and completion

WELL DESIGN

OXY planned to install a rotating head on top of the blowout preventers (BOPs) to facilitate underbalanced drilling, similar to the setups on the majority of horizontal Austin chalk wells. The plan was to try to drill with a drilling fluid density 0.5-1.0 ppg lighter than that required to balance formation pressure, while holding 500-1,000 psi back pressure under the rotating head.

The major difference in this proposed operation would occur during trips. Rather than kill the well by repeatedly bullheading heavy mud to keep the well from flowing, a snubbing BOP stack would be used to pull pipe under pressure all the way out of the hole. This procedure would eliminate having to pump mud back into the formation.

DRILLING FLUID

The drilling fluid for the Monroe A No. 1 had a difficult task. OXY expected the drilling fluid density to be 16-17 ppg for drilling and more than 17 ppg if the well had to be killed. The fluid would have to transport cuttings from a depth around 19,000 ft through a 4,500-ft lateral and curve section and remain stable in 300 F. temperatures. Additionally, the mud would have to remain fluid (not semisolid) in the Austin chalk's fractures for up to 45 days to increase the probability that it would flow back out of the fractures after the well completion.

A clear fluid was believed to be the least damaging fluid, but it was not considered because of personnel safety and economics. The estimated cost of the 16-17 ppg calcium/zinc bromide fluid that would have been lost to the fractures during drilling would have exceeded $2 million.

Using a limit of 1,000 psi for back pressure on the rotating head during drilling meant that the normal drilling fluid weight would have to be at least 16 ppg. Thus, a less hazardous, lower cost, lower density calcium chloride or calcium bromide brine was not a possibility.

In addition, the corrosive nature of the calcium/zinc bromide brines (at densities greater than 16.0 ppg) would likely accelerate failures in the downhole drilling tool components (MWD tools, motors, etc.) and pose a safety hazard to personnel.

Invert oil-based mud probably would have been less damaging than water-based mud, but this type of fluid was also ruled out for safety and economics reasons. Because the well would be drilled underbalanced, there would be a constant potential for formation gas to go into solution in the oil-based mud. The gas in solution would cause extreme pressure surges at the surface, making it difficult, if not impossible, to drill for extended periods. Furthermore, there would be an unacceptable safety hazard.

Thus, a dispersed polymer water-based drilling mud was selected. OXY accepted the greater potential for formation damage yet still searched for ways to make the water-based mud as nondamaging as possible.

The mud system would rely mainly on XCD (xanthan gum biopolymer dispersible) polymer for viscosity. Bentonite would be kept to a minimum, 5-10 lb/bbl, to enhance the potential for any mud lost in the fractures to stay fluid. Lignite, high,temperature dispersants and thinners, and PAC (polyanionic cellulose) material would also be used. Excess lime would be maintained during drilling of the chalk to neutralize the large amount of CO2 present in Austin chalk gas.

The XCD polymer would breakdown in a few days at high bottom hole temperatures, further reducing the tendency for the mud to solidify in the fractures. If the mud did perform in this manner in the fractures and did not maintain viscosity, there could be another damaging effect: the barite and drill solids could settle out or bridge and plug the fractures.

CASING PROGRAM

A 17 1/2-in. surface hole would be drilled to 4,450 ft and 13 3/8-in., 72-lb/ft, N-80 buttress surface casing set to cover the shallow sands and gumbo. As there would be a slight chance that the vertical fractures from the chalk could extend into the overlying formations and be encountered before the next string of casing would be run, 13 3/8-in. casing with a burst rating of 5,380 psi would be used to provide ample safety factor in the event of a high-pressure kick. The 13 3/8-in. casing shoe would be leak-off tested, with a minimum acceptable test of 13.5 ppg. A 12 1/4-in. intermediate hole would be drilled from 4,450 ft to 14,430 ft TVD, or a point approximately 40 ft into the top of the Austin chalk. The vertical hole would be drilled to about 13,950 ft with a low-solids nondispersed water-based mud.

Deviation would be controlled very closely in the vertical hole from spud to kickoff point (KOP) to ensure as straight a hole as possible. With an extremely straight vertical hole, drillstring drag would be minimized, which in turn would reduce the total drag during drilling of the lateral and improve the ability to orient and slide.

Starting at 13,950 ft, angle would be built at 10/100 ft up to 45 at the casing point. The anticipated mud weight at the 9 5/8-in. casing point was 10.5-11.0 ppg. A 9 5/8-in., 53.5-lb/ft, Q-125 Hydril type 563 casing string would be set into the top of the chalk at 45. This string was designed for drilling and production conditions with a burst rating of 13,250 psi and a collapse rating of 11,000 psi. The type 563 wedge thread was selected for its excellent compressive strength in the medium-radius hole and for its premium seal. Surface pressures up to 5,000 psi might be encountered during underbalanced drilling operations, and a tubing leak during production could impart a 9,000-10,000 psi surface pressure.

After setting of the 9 -in. casing, an 11-in., 10,000-psi BOP and snubbing stack, rotating head, and additional equipment required for underbalanced drilling would be installed. The 9%-in. casing shoe would be leak-off tested, with a minimum acceptable test of 18.5 ppg.

An 8 1/2-in. pilot hole would be drilled through the Austin chalk to 15,100 ft MD, holding the 45 angle. A "triple combo" and fracture identification log would be run to evaluate the Austin chalk. The pilot hole would be plugged back and additional angle built at a rate of 14/100 ft to land the curve approximately 100 ft above the base of the Austin chalk. A 4,000-ft lateral would be drilled through the fracture zone, attempting to parallel the dip, using a real-time gamma ray probe with the MWD tool for correlation with the pilot hole gamma ray.

COMPLETION

For completion, the well would be killed, and a 5 1/2-in., 23-lb/ft, P-110 Hydril 563 slotted liner would be set from the end of the horizontal to the kick-off point. The Hydril 563 connection was selected for its high torque rating and excellent compressive strength in the medium-radius hole.

It was anticipated that the liner would have to be rotated as it was run in the hole, thereby subjecting it to heavy compressive, torsional, and cyclic loading. After the liner was run, the 9 5/8-in. casing would be calipered. If the casing were worn significantly, a 7 in. production casing string would be run from the top of the 5 1/2-in. liner to the surface. A permanent packer would be set in the 9 5/8-in. casing immediately above the 5 1/2-in. liner, and the drilling mud displaced with 11.5-ppg CaCl2 packer fluid.

A 2 7/8-in., 6.5-lb/ft, P-110 CS-Hydril plastic-coated tubing string and a 10,000-psi full stainless steel tree would be installed for a production test.

Although there would be a potential for the well to be rate limited initially with 2 7/8-in. tubing, the 2 7/8-in. tubing would be the optimum size hydraulically for the majority of the well's producing life. The top flange on the tubing head would be 15,000-psi working pressure, because of the possibility that the well's shut-in pressure could exceed 10,000 psi. In that case, the tree would be changed to a 15,000 psi tree.

ACKNOWLEDGMENT

The author thanks Bill White, Carlos McCartney, Roger House, Jack Jorgenson, Bill Rose, Sid Langson, and John Dlouhy of OXY U.S.A Inc. for their excellent work in implementing this project. The author also thanks Bill Jones of Swaco Geolograph and Baker Hughes Inteq, Andergauge Drilling Systems, M-1 Drilling Fluids Inc., and Cudd Pressure Control for their assistance in the preparation of this article.

REFERENCES

  1. Durham, L.S., "Horizontal Action Heats up in Louisiana," World Oil, June 1992.

  2. Grimes, G.W., Cameron, P.E. 111, and Salzer, J., "How the World's Deepest Horizontal Well Was Drilled," Petroleum Engineer International, March 1992.

  3. Skelton, J.H., "Louisiana horizontal well taps oil in area of salt related fracturing," OGJ, July 6, 1992, pp. 88-90.

THE AUTHOR

Robert Joseph is the drilling manager for OXY U.S.A. Inc.'s southern region, with responsibility for onshore and offshore drilling operations in the southern U.S. and Gulf of Mexico. He worked for Cities Service Oil Co. and OXY U.S.A. from 1975 to 1989, Occidental International Exploration & Production Co. in 1989-1990, and OXY U.S.A. Inc. from 1991 to the present.

Joseph has held engineering, operations, and management positions in drilling and production in Houston, Bakersfield, Calif., and Muscat, Oman. He graduated from Penn State University with a BS in civil engineering in 1975, and is a registered professional engineer in California and Texas. Copyright 1995 Oil & Gas Journal. All Rights Reserved.