SECOND LATERAL IN HORIZONTAL WELL SOLVES WATER PROBLEM
Stephen A. Graham
Charles E. Graham III & Associates Inc.
Austin
Greg Nazzal
Eastman Christensen
Houston
To overcome a water production problem in the Austin chalk, Cachara Oil & Gas Co. completed the Krawetz Well B No. 2 in the Pearsall field, Zavala County, Tex., as a dual-bore horizontal well.
An initial medium-radius lateral well bore was successfully drilled using current downhole motor technology and had produced for a month before excessive water production became a problem.
Using a unique open hole whipstock/packer to kick off from the existing vertical hole, a second lateral was then drilled from Krawetz B No. 2 to be completed in a higher zone of the Austin chalk, thereby reducing water production.
HISTORY
The Pearsall field is located approximately 80 miles southwest of San Antonio (Fig. 1). The Austin chalk trends from northern Mexico through south-central and eastern Texas into Louisiana. Field development began in the early 1930s, and several technological advancements, as well as energy demands, have caused some peaks of activity throughout its history.
Up to the mid-1980s, over 2,000 straight holes were drilled in the Austin chalk. Typical production has been characterized by high initial rates (approximately 200 bo/d) followed by sharp declines after only a couple of weeks or months.1
The geology of the Austin chalk is generally characterized as an amorphous Cretaceous limestone. It also contains marl and shale of varying thicknesses.
The Austin chalk is about 500 ft thick in the Pearsall field, with porosity ranging from 3 to 12% and a low matrix permeability of about 0.1 md. Extensive vertical fractures extend throughout the field and provide the vehicle for transporting oil.2
In the Krawetz lease area, the Austin chalk is thought to contain extensive fractures, vertically oriented and aligned roughly parallel to a 60 azimuth (northeast to southwest).
The horizontal length of these fractures extends more than a mile in some cases, although the height of each vertical fracture or fracture system remains a source of debate.
The general consensus among those with horizontal drilling experience in the area is that most of these natural fractures do not extend from the base to the top of the chalk, but instead are limited to certain intervals within the cleaner limestone matrix.
Prolific oil production from early horizontal wells drilled in the B2 and C zones in the Krawetz lease area indicates these zones contain a high density of natural fracturing.
Thus, these two intervals-which, at the surface location of the subject well, extend from approximately 6,480 to 6,520 ft and 6,565 to 6,640 ft true vertical depth (TVD), respectively-have been primary targets in a number of drainholes drilled in the area to date.
Other wells were designed to traverse the B1 zone (6,360-6,480 ft TVD) through the C zone. Several recent drainholes have successfully targeted the B1 zone exclusively, indicating that significant fracturing also occurs in this zone.
DRAINHOLE NO. 1
The first horizontal well bore drilled in the Krawetz B No. 2, referred to as drainhole No. 1, kicked off at 6,060 ft measured depth (MD) in a 6 1/8-in. hole, becoming horizontal at 6,430 ft TVD. The well reached total depth (TD) at 6,558 ft TVD (9,726 ft MD) with 3,451 ft of horizontal departure (Fig. 2).
Most of the horizontal section in drainhole No. 1 was positioned below the upper B1 zone in the interval thought to contain the highest density of vertical fracturing. Reports from the horizontal drilling phase of the first drainhole indicated that approximately 12,000 bbl of fresh water were lost to the Austin chalk during drilling.
The completion interval was identified as 6,263-9,726 ft MD (6,434-6,558 ft TVD) in the lower B2 and C zones of the Austin chalk. Drainhole No. 1 was completed open hole from 5,980 to 9,726 ft MD, and between May and August 1990 it produced 40,656 bbl of oil and 20,780 bbl of water.
The well was eventually shut in due to excessive water production.
Prior to the extensive horizontal drilling activity in the area, the fractures below the upper B1 zone contained primarily oil and gas.
Subsequent to drilling horizontal wells which encounter fracture systems at different stages of depletion, a pressure/fluid equalization process occurs until all the fractures encountered by the communicating wells serve as one supply source.
Evidence of communication among the majority of the wells in the Krawetz lease area is substantiated primarily by oil-productive wells becoming watered out as offset wells are drilled. This is confirmed by the lack of salinity in the produced water.
Virtually all of the horizontal wells in the area have been drilled roughly perpendicular to the northeast-southwest fractures. Some of the wells have traversed the B1, B2, and C zones, but a number of drainholes have remained in one zone for the majority of the horizontal displacement. The drainhole paths of the horizontal wells have caused man-made communication to occur between different fracture systems located within the major chalk zones.
Because of this communication and the differences in the densities of gas, oil, and water, the lower B2 and C zones, by virtue of their location within the chalk, may serve as a temporary reservoir for most of the water introduced to the formation by horizontal drilling operations. Thus, the oil that occupied these reservoirs may have been flushed to the B1 zone by gravity segregation.
Drainhole No. 1 continued to be highly water productive even after recovering more than 20,000 bbl of drilling water, indicating the subject well was likely in communication with other horizontal drainholes being drilled to the north and west (Fig. 3). These wells also experienced lost circulation during drilling operations. In some cases, entire horizontal intervals were drilled without returns, causing fresh water losses of more than 70,000 bbl for a given well.
In addition, because of the tremendous volume of water lost during horizontal drilling operations in the area, it was believed that the excessive water production in drainhole No. 1 could be partially attributed to its relatively low position with respect to the top of the Austin chalk.
DRAINHOLE NO. 2
To reduce the prolific water production from the original drainhole, a second horizontal drainhole targeting a shallower zone was proposed. With drainhole No. 1 positioned below the B2 and above the C zones in the Austin chalk, drainhole No. 2 was proposed to target the upper B1 zone, approximately 110 ft above the original horizontal well bore (Fig. 2).
This second leg was planned at an azimuth of 305 (N55W), which is 21 azimuth to the left of the first leg.
Because of the likelihood of the fractures allowing communication between the two drainholes, a bridge plug was not set in drainhole No. 1.
To minimize workover operations prior to the redrill and to eliminate the need to set a cement plug for kick off, an open hole whipstock/packer tool, or orienting guide (OG), was utilized for drainhole No. 2 (Fig. 4).
The OG is a specially designed whipstock installed with an inflatable packer designed for axial loads greater than 20,000 lb.3 When oriented in the desired kick off direction and inflated, the OG is set and provides an angled surface from which to initiate kick off with the drilling assembly.
The second drainhole was drilled using the same bottom hole assembly (BHA) used in the original well bore (Fig. 5).
BHA
Both drainholes were drilled using Eastman Christensen's double adjustable (DA) downhole motor which contains two bends, fully adjustable at the rig site, to obtain a variety of build rates.4 The steerable motor's geometry is fixed by three points of contact: the bit, the bearing housing stabilizer, and the stabilizer above the motor (Fig. 6).5
Combining a double adjustable bent housing, the DA motor provides several configuration options for achieving a range of doglegs. Either sub can be adjusted to tilt angles from 0 to 2. The stabilized motor can achieve build rates up to 24.5/100 ft, depending on tool size.
Both drainholes also used Eastman Christensen's directional MWD (DMWD), which is fully wireline retrievable and does not require its own special collar. The 2-in. OD DMWD tool can operate in the steering mode providing tool face updates every 15 sec and full surveys every 30 sec or in the rotary mode with full surveys taken after each connection or as needed. Inclination and azimuth can be transmitted within 50 sec using either mode.
For the horizontal section of drainhole No. 2, a specially designed polycrystalline diamond compact (PDC) bit was used. The Eastman Christensen R482GN bit (IADC M675) is specially designed for horizontal drilling in formations in which standard PDC bits exhibit excessive torque or cutter spalling and fracture.
A shortened gauge length on the R482GN is tapered to the shank to minimize side forces, allowing easier orientation with steerable motors, and the natural-diamond gauge protection provides an active cutting surface for improved steerability and consistent hole size.
REDRILL
After caliper logs were run to measure hole gauge, the second well bore in the Krawetz B No. 2 was initiated using the retrievable OG to kick off below the 7-in. casing in the original vertical well bore.
With the OG at 6,038 ft MD, a Seeker rate-gyro check shot was made to confirm proper orientation, and 1,500 psig was applied to inflate the packer to set the whipstock assembly. The running tool was released and tripped out of the hole leaving the whipstock/packer assembly in place.
The well was kicked off using a 6 1/8-in. J33 bit and a DA motor configured with 1.5 on the top adjustable sub and 1.825 on the bottom sub to begin building the curve to horizontal. This BHA drilled 387 ft to 61.9 of inclination while turning from 269 to 290 azimuth. This section of hole was drilled in the oriented mode, although the 14/100-ft build rate was lower than anticipated.
At 6,425 ft MD, a polymer pill was pumped, and the BHA was tripped out. The DA motor configuration was changed to 1.75 on the top sub and 2 on the bottom sub to increase the build rate to 18/100 ft. The bit was changed out, and the first J33 bit was rerun. With weight-on-bit (WOB) increased from 22,600 to 35,000 lb, this assembly drilled 184 ft to 6,609 ft MD, building inclination to 88.5 while turning to an azimuth of 297.
With well bore inclination at horizontal, the BHA was tripped out and the DA motor configured to 0 on the top adjustable sub and 1 on the bottom adjustable sub to maintain angle and direction. A 4 3/4-in. stabilizer was added above the short nonmagnetic drill collar, and a new 6 1/8-in. R482GN bit was run. Short orientations were made until the well was turned to a 305 azimuth at 6,988 ft MD.
This assembly drilled 3,346 ft of hole, maintaining angle and direction to TD the second well bore at 9,955 ft MD (6,446 ft TVD) with an inclination of 87.1 and a final azimuth of 309.
The whipstock/packer assembly was removed without incident. The entire redrill process took 16 days, 12 of which were drilling.
RESULTS
After completing drilling operations of the second horizontal drainhole, production in Krawetz B No. 2 was reestablished using a beam-pump artificial lift system capable of lifting approximately 600 b/d.
In a 12-day test in October 1990, the well produced 5,754 bbl of oil and approximately 1,100 bbl of water. In November, 17,835 bbl of oil and 3,000 bbl of water were produced. However, in December, oil production dropped to 10,000 bbl and water production again increased, reaching 6,000 bbl.
The early results from the redrill operations were very disappointing.
The artificial lift system was eventually shut down as a result of excessive water production and the lack of an adequate disposal system. For the next month, the well was tested for 24 hr every 7 days to determine if the oil cut would improve. The first three of these tests continued to show excessive water production.
During this period, offset drilling rigs were still in operation and losing water returns (Fig. 3). It was theorized that the continued water production was possibly due to off set drilling operations. A fourth test yielded a significant oil cut of 80%. The operators considered this satisfactory and left the well pumping.
During November and December 1990, production averaged 466 bo/d and 150 bw/d, yielding a net revenue from sales of oil and gas in excess of $500,000 after royalties and operating expenses. This revenue was more than adequate to recover the cost of the redrill project.
ACKNOWLEDGMENT
The authors wish to thank Cachara Oil & Gas Co. and Eastman Christensen for permission to publish this article. In addition, the individual contributions of Phil Burge of Eastman Christensen and the personnel involved at the rig site are especially appreciated and gratefully acknowledged.
REFERENCES
- Pope, C.D., and Handren, P.J., "Completion techniques for horizontal wells in the Pearsall Austin chalk," SPE paper 20682, presented at 65th Annual SPE Technical Conference and Exhibition, New Orleans, Sept. 23-26, 1990.
- Corbett, K., Friedman, M., and Spang, J., "Fracture development and mechanical stratigraphy of Austin chalk, Texas," The American Association of Petroleum Geologists Bulletin, Vol. 71, No. 1, January 1987, pp. 17-28.
- Sheikholeslami, B.A., Schlottman, B.W., Siedel, F.A., and Button, D.M., "Drilling and production aspects of horizontal wells in the Austin chalk," SPE Annual Technical Conference, San Antonio, October 1989.
- Nazzal, G., "Planning matches drilling equipment to objectives," OGJ, Oct. 8 , 1990, pp. 110-18.
- Barrett. S.L., and Lyon, R.G., "The navigational conference," Dallas, February 1988.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.