Batch drilling program cuts time, costs for Liuhua development

George E. Gray, Kenneth H. Hall
Amoco Orient Petroleum Co.
Shekou, China

Huang Chang Mu
China Offshore Oil Nanhai East Corp.
Shekou, China

The efficiency of batch drilling operations and the appropriate use of technology, teamwork, and thorough planning helped cut several days off the time to drill each of 10 subsea wells for the Liuhua 11-1 development project in the South China Sea.

The rig-of-opportunity phase of development was comprised of batch drilling operations for 30-in., 133/8-in., 95/8-in. and 7-in. casing intervals.

The Liuhua 11-1 project is under development by operator Amoco Orient Petroleum Co. (AOPC) and partners China Offshore Oil Nanhai East Corp. and Kerr-McGee China Petroleum Ltd.¹ The Liuhua field is approximately 120 miles southeast of Hong Kong in contract area 29/04 of the South China Sea.

The Liuhua 11-1 field was discovered in January 1987 and was thoroughly tested during an extended drill stem test of the Liuhua 11-1-6 in 1989. The test was of a horizontal delineation well that was drilled in 1988.

The reservoir is comprised of carbonates of the Lower Miocene Zhujiang formation. The section above the reservoir is a thick sequence of Lower Miocene to recent marine claystones.

The overall development program calls for drilling and completing 20 subsea horizontal wells. The rig-of-opportunity phase was the initial phase of this development and used a contract rig to establish the subsea wellhead array and initiate drilling of the development wells. The wellhead array was the first critical step. It was the foundation for the "building block" construction process used to create Liuhua's subsea production system on the seabed.²

On Oct. 1, 1994, the semisubmersible drilling rig began the tow to location from Hong Kong. The water depth at the Liuhua site is 1,020 ft. Once the rig was on location, a sequence of batch operations was performed to set twenty-five 30-in. conductors.³ The rig drilled fifteen 133/8-in. surface hole sections and ten horizontal wells to total depth (TD).

After the blowout preventer (BOP) was run, the wells were drilled to TD by setting 95/8-in. casing into the top of the Zhujiang carbonate and setting approximately 2,500 ft of slotted 7-in. liner in the horizontal pay interval. All wells were temporarily abandoned awaiting future completion operations. The rig was released 154 days later on Mar. 3, 1995 (Fig. 1 [23553 bytes]).

Planning

Amoco brought drilling, operations, and subsea installation personnel, including contractor personnel, together early in the project to perform sufficient planning for this deepwater development. Most of the Amoco drilling operations team had worked together on exploration projects in the China Sea for 1 year before going full time to Liuhua 6 months prior to spudding the first well. Extensive man-hours were used in the planning stage to optimize the operation plan. The key products of that process were batch operations and optimization of the drilling plan for the Liuhua horizontal wells. The Liuhua 11-1-6 delineation well, with approximately 2,325 ft of horizontal section, was drilled with oil-based mud and cased to 7,085 ft in 25 days. The average for the first 10 development wells was 2,655 ft of horizontal section, drilled and cased to 7,566 ft in 13 days with water-based mud and seawater.

Conductor operations

Twenty-five 30-in. conductors were set using a special casing/drill technique: 20 conductors for wells, two piles to support the subsea manifold, and three piles for pipeline tie-in bases.

The 20 conductors and the two manifold piles were set as a batch of 22 as the initial development operation. The three pipeline tie-in base piles were set after ten wells were drilled to TD 4 months later.

The hole was drilled and casing set in one step using sophisticated acoustic positioning equipment. The 30-in. casing used Hunting Lynx SA and HD squnch-joint connections and used an inner 26-in. bit with a 91/2-in. motor drilling assembly that was approximately 4-in. longer than the conductor string. The technique is really a combination drill/drive procedure that relies on the soil strength to support the casing; no cement was pumped. The conductors had to be set within tight tolerances to ensure successful construction of the subsea installation from the floating production system (FPS) during the second half of 1995.

The first twenty-two 30-in. conductor strings were installed in less time than anticipated by the most aggressive estimates. All were within the tight positional and directional tolerances. The total duration of the conductor installation operations was 14 days and 6 hr, saving approximately 36 days as compared to conventional drill and cementing operations. The 14-day, 6-hr record was also faster than the estimates for successful casing-drill installation operations. It was expected to take a minimum of 24 hr for each conductor installation. The first three conductors were set in an average of 25.7 hr each, the next four conductors averaged 15.1 hr each, and the final fifteen conductors averaged 11.7 hr each (Fig. 2 [22421 bytes]).

Because of the repetitive nature of the batch setting procedure, all team members became totally familiar with the operation. They then contributed ideas to optimize the procedures, both on-site and "on the fly." The optimized procedures and the teamwork developed during the batch setting operations helped to shave almost 8 full days off the expected installation time of 22 days that would have been required using casing/drill techniques.

After the tenth well was drilled to TD, the second batch setting phase for three 30-in. piles began. The installation operations followed the procedures used to set the first 22 conductors. These three piles were only three joints long. Again, they were placed within the tolerances required.

This second phase was a short operation taking only 58 hr of rig time, or an average of 19.3 hr per pile. The reason this average was higher than the original batch setting operations was the time spent on rigging up, more than 15 hr. Each pile took an average of 14.2 hr after rigging up, which was below the 14.8-hr average time established in the first batch conductor operation.

Only one 26-in. bit was used for all twenty-five 30-in. conductors installed in the Liuhua field. The inclination angle was less than 1.0° for all conductors.³

Batch drilling operations

The authorized development plan was to drill five wells with the rig of opportunity and five wells with the FPS prior to first oil production. The efficiency of the batch drilling program made it possible to drill additional wells during the rig-of-opportunity phase.

The batch drilling operations consisted of two phases: first the 171/2-in. surface section and then the 121/2-in. and 81/2-in. sections, which were drilled together to minimize the number of BOP-to-wellhead connections. None of the wells in the rig-of-opportunity program used guide bases, and the BOP was landed directly on the 181/2-in. wellhead with only remotely operated vehicle visual assistance.

Surface hole section

Three separate phases of batch drilling 171/2-in. hole and setting 133/8-in. casing occurred during the rig-of-opportunity operations. The first phase was immediately after the 30-in. conductor array was installed. The second phase was initiated after the second well was drilled to TD. The third phase occurred after the tenth well was drilled to TD. In total, fifteen 133/8-in. casing strings were installed with the rig of opportunity.

The first batch program of operations included six surface hole sections. All were vertical hole sections drilled with the same bit. The wells were drilled with seawater and high-viscosity guar gum sweeps with returns to the sea floor. The 133/8-in., 72.0-lb/ft, K-55 casing strings were set at about 2,100 ft measured depth (MD) as the wells were drilled. The connection between the casing crossover and the 181/2-in. wellhead extension was a Dril-Quip HD-90 squnch-type connection, and the remaining casing connections were BOSS threaded connections. The squnch connection was placed in the string to limit the amount of rotation that the 181/2-in. wellhead assembly would need when it was picked up and ready to be stabbed into the crossover.

The cement jobs were identical, with a retarded lead slurry and a neat tail slurry. Returns to the sea floor were noted on every cement job. The 30-in. conductors did not slump at all before, during, or after these hole section operations.

The first batch phase of drilling 171/2-in. vertical well bore sections and setting 13 3/8-in. casing took only 10.5 days, or an average of 42 hr each. The fastest hole section, 11-1-12 (T5-D2), was completed in 21.5 hr.

The second 171/2-in. batch operation started after the failure of the BOP VX ring gasket retaining mechanism. This failure occurred at the completion of drilling the second well to TD. Four 171/2-in. holes were drilled, and their 133/8-in. casing strings were cemented in place. Two of these four hole sections were vertical, as were the six 171/2-in. hole sections of the first batch phase.

The other two were drilled directionally; one was nudged to a 10° inclination, and the other was built to 21°. The average build rate for both wells requiring directional work was about 2.7°/100 ft. All four holes were drilled with the same bit. The mud system and cement programs were identical to the sections drilled in the first 171/2-in. drilling phase.

There was no down time during the second 171/2-in. phase, and the four hole sections were drilled and cased in only 5.3 days, for an average of 32 hr each. The fastest hole of this phase was drilled in 26 hr.

The third batch of 171/2-in. drilling operations started after the installation of the three pipeline tie-in base piles. This was the last batch phase of operations which occurred before the release of the rig of opportunity. A total of five 171/2-in. hole sections were directionally drilled, and 133/8-in. casing was cemented in place. The inclination range at the 133/8-in. casing points was between 15 and 23°. Build rates ranged 2.8-3.4°/100 ft. All five hole sections were drilled with the same bit, and again the mud systems, the casing, and cement programs were unchanged.

The third phase of surface hole operations took about 6.9 days, for an average of 33 hr each, including a 26-hr fishing job resulting from human error. The entire fish was recovered in two runs. The fastest section in this phase of operations was completed in only 19.5 hr.

Fifteen 171/2-in. holes were drilled to TD, and 133/8-in. casing was run and cemented in each. Among these, eight intervals were vertical, and seven were drilled directionally. Proper anticollision methods were followed in both the planning and installation operations to ensure that none of these wells collided. The well designs (directional plans, bit selection, mud, casing, and cement) and operation plans were proven to be effective for the top hole sections of all of the Liuhua wells.

Only 22.7 days, or an average of about 36 hr each, were needed to install fifteen 133/8-in. casing strings during the rig-of-opportunity operations. The original estimates predicted that it would take 48-72 hr per hole section. This indicates that the batch drilling operations framework led to saving at least 12 hr per hole section, or a total savings of more than 7 days of operating time for 15 wells (Fig. 3 [26777 bytes]).

Intermediate and production hole sections

The original plan was to drill five horizontal wells to TD during the rig-of-opportunity drilling program. Actually, ten wells were drilled to TD in two batch phases of operations.

The first 2 wells were drilled to TD in the first phase, and the next 8 wells were drilled to TD in the second phase of batch operations. Although different problems surfaced on each of the 10 wells, all were drilled safely and economically. The wells were successfully placed in the reservoir within the Zhujiang carbonate B1 zone target limits defined by the project reservoir engineers.

The total time from landing the BOP to drilling and casing these 10 wells to TD and temporarily abandoning them was 108 days, or an average of 10.8 days each (Fig. 4 [27537 bytes]).

The wells were designed to have most of the directional work in the claystone above the carbonate and to have the 95/8-in. casing land in the carbonate. This would prevent hole stability problems during drilling the 81/2-in. horizontal production interval and running the 7-in. perforated liner (Fig. 5 [37162 bytes]).

Each Liuhua well design is a build-tangent-build-to-horizontal design. The first build, the tangent, and the second build sections are drilled in the 121/2-in. hole section. The third build-to-horizontal is drilled below the 95/8-in. casing shoe in the beginning of the 81/2-in. hole section. The 81/2-in. interval is a horizontal well bore extending at least 2,500 ft beyond the 95/8-in. casing shoe.

The batch drilling to TD began immediately after the sixth 133/8-in. casing string was cemented in place. The BOP and riser were run without guidelines and latched onto the 181/2-in. wellhead. The first four wells, which provided most of the significant operational improvements, are discussed in detail below to demonstrate how learning progressed.

First well

Because there were several untried plans in the drilling operation, the first well selected was not at the extreme limits of displacement, either short or extended reach. This well, drilled northeast of the location from the center of the manifold, was selected because of its moderate build rates, no turns in the well bore design, and medium displacement from the well slot.

The 121/2-in. hole section drilling operations and the 95/8-in. casing operations went fairly smoothly. This was the only 121/2-in. hole section drilled using a 95/8-in. motor in the directional bottom hole assembly (BHA). A stabilizer planned for the top of the motor had to be left out of the BHA because the motor/stabilizer combination could not be run through the 133/8-in., 72.0-lb/ft casing.

The lack of a stabilizer and problems with the drillstring compensator created erratic directional control. These factors caused higher-than-expected doglegs above and a lower-than-planned build rate below the tangent section. The first build rate averaged 3.5°/100 ft, and the second build below the tangent averaged only 4.0°/100 ft, vs. a planned 5°/100 ft build rate. This left the 95/8-in. casing at a 74° inclination rather than the desired inclination of 78°, creating problems in the subsequent 81/2-in. interval.

In the 81/2-in. hole on this first well, there was an unintentional sidetrack drilled immediately below the 95/8-in. casing shoe. This sidetrack occurred when an aggressive building assembly was pulled and replaced with a logging-while-drilling BHA. The second assembly would not reenter the hole drilled by the aggressive building assembly. This unintentional sidetrack was plugged, and a high-side sidetrack was drilled to TD.

Even while the high-side sidetrack was drilled, there were problems building inclination at an aggressive rate immediately below the 95/8-in. casing shoe. This prevented the well bore from entering the desired B1 target horizon above the specified lower target limit. There were also problems remaining in the B1 target horizon while the final section of horizontal interval was drilled.

Because of these problems, the final well bore had only 72% of the horizontal section in the high porosity B1 target horizon. Reservoir engineering concerns about staying within the B1 target horizon created the need to mobilize state-of-the-art, geological steering tools and replan the next nine wells, minimizing the build required below the 95/8-in. casing shoe. The new directional tools did not arrive until the fourth well.

The two hole sections for this well, including a temporary abandonment, were finished in 15 days, for a total time on this well of 19 days. This was 2 days faster than the previous horizontal well drilled in the field.

Second well

After the first well was temporarily abandoned, the BOP stack and riser were jumped to the second well, to drill it to TD, southeast of the manifold's location.

Once the 121/2-in. directional assembly was run, this section went well. Again, compensator problems caused erratic weight on bit; however, with an 8-in. motor and an undergauge stabilizer above the motor in the BHA, good directional control was possible.

The first build averaged 3.4°/100 ft, and the second averaged 4.6°/100 ft. The second build brought the 95/8-in. casing to an inclination of 81°, eliminating most of the build required below the casing shoe. Because the well had a higher inclination at the casing shoe, there were no problems building to horizontal after the casing shoe was drilled out. With the modified directional plans, 96% of the 81/2-in. section was placed in the desired high-porosity B1 target horizon of the carbonate.

The second well was drilled to TD and temporarily abandoned in just over 11 days of rig time. The 121/2-in. and 81/2-in. hole intervals were drilled in 9.5 days, approximately half the time originally expected.

Third well

After the second batch of 133/8-in. casing operations was completed, the BOP and riser were run to drill the third well to TD, southwest of the manifold's position.

In the 121/2-in. hole, compensator problems again caused erratic weight on bit which impaired steering. The first build averaged 3.6°/100 ft, and the second averaged of 2.6°/100 ft. A turn of 3.0°/100 ft was drilled throughout the second build section of this well. The 95/8-in. casing shoe inclination was 78° rather than the desired 83°, creating the need to build at a high rate below the casing shoe to enter the B1 target horizon. This low angle was the result of the carbonate top being encountered 23 ft above its expected depth. This caused problems in the subsequent 81/2-in. section.

The 81/2-in. section was not as successful in terms of placing the well bore in the desired B1 target horizon. Only 62% was placed in this zone, while 13% was drilled in the B2 zone below the target horizon, and 25% was placed in the A zone above the target horizon. The inability to build at high rates below the 95/8-in. casing shoe, brought on by low inclination at the 95/8-in. casing point, was the major cause for drilling below the B1 target interval. Also, the inability to steer due to excessive slack-off drag in the later stages of the 81/2-in. hole section meant that the only option left was to rotate to TD. This placed the final 600 ft of the horizontal section in the A zone above the desired horizon.

This well, even with its problems, took only 11.7 days to drill to TD, temporarily abandon, and get ready to move to the fourth well. Trouble was experienced with the liner hanger and an inflatable bridge plug. These problems caused 38 hr of lost rig time, which are included in the 11.7-day total.

Fourth well

The BOP stack was jumped to the next well slot to drill the fourth well to TD, northwest of the manifold's location. The fourth well was the longest-reach well drilled in these initial stages of the development project.

The 121/2-in. section went extremely well. A new polycrystalline diamond compact (PDC) bit drilled this interval, which exceeded 5,200 ft. The first build averaged 3.1°/100 ft, vs. a planned 3.0°/100 ft. The tangent interval was also drilled as planned, although the BHA had a 0.4°-0.6° dropping tendency in the rotary mode. Slight corrections were made through the tangent interval to alleviate this minor problem. The final build below the tangent averaged only 1.6°/100 ft. This low build rate was primarily caused by having to search for the carbonate top, which came in approximately 16 ft lower than prognosed.

The 81/2-in. interval went well; it was the first interval drilled with the geological steering assembly. The geological steering assembly, which provided real-time information at the bit, included inclination, gamma-ray logs, bit rpm, downhole weight on bit, compensated dual-resistivity logs, inclination and azimuth at the measurement-while-drilling sub, and compensated neutron density logs.

The most valuable information from a drilling perspective was the inclination at the bit data. It indicated to the directional driller the immediate effect of any directional correction. This removed much of the tortuosity from the well path, which reduced the drag and increased the control of the well bore as sliding became possible at greater depths. This also decreased the time required to drill the 81/2-in. hole section.

The real-time log data proved extremely valuable in determining where the actual B1 target horizon was in the carbonate. The B1 target horizon was not encountered until the well was drilled to 7,850 ft MD. This was 500 ft beyond the 95/8-in. casing shoe and was drilled entirely through the tight, top A zone of the carbonate.

The decision was made to pull back and drill an open hole low-side sidetrack. This sidetrack was drilled without setting a kick-off plug. Using inclination-at-bit measurements to assist this operation saved at least 1 day of rig time. This sidetrack was drilled successfully to the interval TD of 10,001 ft MD. The sidetrack placed a total of 93% of the final well bore in the desired B1 carbonate interval. Additional heavy-weight drill pipe was needed to push the liner to TD.

This well's 121/2-in. and 81/2-in. hole sections took just over 14 days, slightly slower than the revised expectations. The greatest accomplishment demonstrated by this well was that the longer reach horizontal wells can be drilled primarily with seawater and high viscosity sweeps to enhance hole cleaning. This well proved that an oil-based mud system is not necessary for Liuhua drilling. The elimination of oil-based mud created beneficial economic and environmental impacts for the project.

Fifth-tenth wells

The next six wells were drilled with no major problems. The average time from landing the BOP to temporary abandonment was 9.5 days. The slowest of these wells was the ninth well in the program. The ninth well had the shortest reach. This well took 12 days due to the carbonate coming in high, getting behind on the directional plan in the 121/2-in. hole, and inadvertently sidetracking the 81/2-in. hole.

The intermediate and production intervals were drilled, cased, and temporarily abandoned in 7.7 and 7.8 days in the fifth and eighth wells, respectively. The 81/2-in. interval in the eighth well required 16 hr to drill, with only 7 hr of on-bottom drilling time. The 2,789-ft section was drilled 100% in the desired B1 zone. The actual on-bottom rate of penetration was almost 400 ft/hr.

Application of technology

The previous horizontal well was drilled in 1988 with oil-based mud. These wells were all drilled with a partially hydrolyzed polyacrylamide (PHPA) mud system in the 121/2-in. hole to alleviate any reactive tendency of the claystone. Seawater with Xanvis sweeps was used in the 81/2-in. interval, as this fluid was the least damaging and most economical fluid for this interval. There were no mud-related problems encountered in this development drilling program.

The 121/2-in. sections were drilled primarily with three PDC bits. The three bits drilled a total of 26,405 ft of intermediate hole, for an average penetration rate of 96 ft/hr. As expected, the bit with 19-mm cutters drilled faster on average than the bits with 13-mm cutters. The bits with 13-mm cutters were more durable, drilling out the non-PDC-drillable float equipment. There were two milled-tooth bit runs, drilling a total of 2,540 ft, one in an unsuccessful attempt to improve directional control, and the other for sidetracking. The average rate of penetration for the milled-tooth bit runs was 52 ft/hr (Table 1 [15807 bytes]).

The 81/2-in. intervals were drilled primarily with milled-tooth bits. Initially, the wells were drilled with heavy-set PDC bits using 13-mm cutters. The PDC bits drilled 9,235 ft of 81/2-in. hole at an average penetration rate of 52 ft/hr.

A type 1-1-7 milled-tooth bit was run in the fourth well to reduce torque and minimize directional control problems. The bit performed well, and the decision was made to continue running milled-tooth bits in this interval. Eight type 1-1-5 and 1-1-7 milled-tooth bits drilled a total of 23,507 ft of 81/2-in. hole. The average rate of penetration for these bits, not corrected for off-bottom time, was 100 ft/hr (Table 2 [22375 bytes]).

The wells were cemented with neat tail slurries. It was recognized that this was a low-pressure oil reservoir that did not require the use of high technology and high cost horizontal cement slurries. The 133/8-in. cement jobs were circulated to the sea bed to help ensure the mechanical integrity required to support the subsea tree and production system. The 95/8-in. cement jobs were designed to bring tail cement 350 ft above the start of the second build section to provide a good quality cement job behind the tangent section for the completions. Enough lead cement was pumped to bring cement 250 ft inside the 133/8-in. casing shoe.

All ten 7-in. liners were run to bottom without any problems. The liners were slotted with 0.5-in. holes in a double helix pattern of 16 holes per foot. The liners were fabricated from 7-in., 23-lb/ft casing with a hook thread profile. Initially, problems were encountered setting and releasing from the hydraulic hangers due to the setting tool not being at the neutral point or in compression.

The first well was temporarily abandoned with a cement plug because of the unavailability of inflatable bridge plugs. The remaining wells were abandoned with inflatable bridge plugs. Several of these failed during setting operations primarily because of problems with unreliable shear pin stock. The problem was corrected by assisting the service company's quality control program for their shear pin stock and by increasing the pressure differential between the running tool releasing pressure and pump-out-plug shear pressure.

Overall results

The results of this initial phase of development far exceeded any predicted expectations. The quick pace of operations was accomplished without sacrificing quality. All of the conductors were placed within the required tolerance. The well bores are all usable with a high percentage of each well bore placed in the desired reservoir target horizon. Product quality, time savings, and cost savings resulted from batch operations, use of appropriate technology, planning, and the teamwork exhibited by the large, diverse group of professionals.

A major portion of the time savings throughout the rig-of-opportunity program can be attributed to the batch setting nature of the operations. For example, the BOP stack and riser were run only twice but were used on 10 wells. This represents a savings of nearly 13 days of rig time.

Another excellent example of how the batch mode of operations resulted in savings was in the conductor setting operations. It was estimated to take 1 day to set each conductor using the casing/drill method of installation. The overall time to set all 22 conductors using this method of installation was only 14 days and 6 hr. Nearly 8 days were saved because of the repetitive nature of the operation. Doing similar operations repeatedly led to a greater understanding of the procedures and created a framework for optimizing the installation procedures.

Overall savings of about 4.5 days per well are credited to the batch-setting mode of operation:

• 0.5 days for conductor operations

• 0.5 days for the 171/2-in. interval

• 1.5 days for the BOP and riser operations

• 1.0 day for the 121/2-in. interval

• 1.0 day for the 81/2-in. interval.

Additional time savings are credited to planning, application of the most current and appropriate technology, efficient logistic operations, effective supervision, and quick implementation of desired changes.

Acknowledgment

The authors thank China Offshore Oil Nanhai East Corp., China National Offshore Oil Corp., Kerr-McGee China Petroleum Ltd., and Amoco Orient Petroleum Co. for their permission to publish this article.

References

1. Bryant, J.H., Methvin, J.R., Dague, E.E., Zhu, M.C., and Wang, H.K., "Liuhua 11-1 Development-Field Development Overview," Paper OTC 8172 presented at the 1996 Offshore Technology Conference, Houston, May 6-9.

2. Hall, J.E., Wang, Z.S., Krenek, M.J., Douglas, L.D., and Macfarlane, A.M., "Liuhua 11-1 Development-Subsea Production System Overview," Paper OTC 8175 presented at the 1996 Offshore Technology Conference, Houston, May 6-9.

3. Herrmann, R.P., Coleman, R.A., Hughes, J.D., Huang, C.M., Zhang, M.J., and Macfarlane, A.M., "Liuhua 11-1 Development-Subsea Conductor Installation in the South China Sea," Paper OTC 8174 presented at the 1996 Offshore Technology Conference, Houston, May 6-9.

Based on a paper presented at the 28th annual Offshore Technology Conference in Houston, May 6-9.

The Authors