Effective reentry methods reduce costs and optimize production

Greg Szutiak, Dennis Walker
Baker Hughes Inteq
Calgary

Reentry technology has developed rapidly since these fields were first drilled. Careful planning and evaluation in applying current reentry methods are essential if costs are to be controlled while obtaining the substantial production increases that are possible. Overall project logistics must match the completion design, which in turn drives much of the drilling program. Considerations include existing casing size and weight, casing exit mechanisms, build rates, and well path to the target zone.

In drilling a 98.4-mm hole out of 114.3-mm casing, for example, dogleg severity must consider logging and completion requirements. Advances in bit and mud motor design and in formation evaluation measurement while drilling (Femwd) technology have dramatically improved the potential for operations in these smaller well bores and broadened the horizons of reentry wells.

A review of four reentry projects covering 19 horizontal wells in western Canada illustrates a number of planning considerations that can save an operator money while ensuring optimization of the production.

Kaybob field

The primary target of this Amoco Canada Petroleum Co. Ltd. horizontal reentry well in the Kaybob field was the Coquina formation of the Triassic Group. The Coquina formation consists of well-sorted pelecyod bioclasts with excellent interparticle porosity. It is derived from a moderate-energy environment and has localized deposition.

The Kaybob field consists of approximately 80 vertical wells and two horizontal wells. To date, including this case history, there have been two horizontal wells drilled in the Kaybob South field. This well was deemed a reentry candidate because of its proximity to the field's injection wells, the observed reservoir modeling, and geological control available.

The original vertical well was drilled in 1971 and cased as follows:

• Surface casing: 219.1 mm, K-55, 35.7 kg/m, ST&C to 192.85 m

• Intermediate casing: 114.3 mm, J-55, 14.3/17.3 kg/m, ST&C to 2,169 m (14.3 kg/m from 455.4 m to 1,738.8 m)

• Production liner: 114.3 mm, J-55, 9.67 kg/m, LT&C from 1,996 m to 2,150 m.

The open hole section was from 2,150 m to 2,297 m.

A service rig prepared the well prior to drilling the reentry. the existing tubing and anchor were pulled, followed by setting of a 114.3-mm bridge plug at 2,093 m. Approximately 8 cu m of cement were dump-bailed on top of the bridge plug. A mill was run in the hole to 2,016 m and milled 35 m of J-55, 17.3-kg/m casing in 15 hr (2.3 m/hr) with one set of knives. Gelled water drilling fluids were pumped at 0.6 cu m/min throughout the milling operation to clean the hole. The hole was circulated for 51/2 hr and subsequently displaced to clean, filtered fresh water.

A balanced, densified (2,100 kg/cu m) cement plug was mixed and pumped from 1,993 m to 2,080 m. The cement plug was tagged and polished to 2,013 m; the hole was displaced to diesel; and the service rig was released.

Drift surveys indicated a maximum inclination of 2.0° throughout the well, and 0.75-1.0° at the kick-off point (KOP). The milled section was specified at 35 m to allow for a possible second horizontal leg. This also ensured that the mud motor would be completely out of the casing for kicking off the well.

A 98.8-mm hole was planned, with a well path build-up rate of 24.0°/30 m to 72° inclination. A nonrotatable bottom hole assembly (BHA) was designed to drill the curve from 72.0° to 90° using a 16.0°/30 m build rate (Fig. 1 [39860 bytes]). To account for a regional updip of the Coquina formation, a continuous 0.69°/30 m build to 91.14° was planned (Fig. 2 [29890 bytes]). A 5.0°/30 m build and turn was incorporated in the well plan to maintain a specific radius from the existing well. To determine the possibility of a second, deeper Coquina cycle, a true vertical depth (TVD) drop of 16.7 m was planned from the original horizontal entry point.

The initial BHA consisted of the gyro tool and mud motor to kick off the cement plug. Once tagged, the cement plug's competency was questioned in light of the low weight required to drill it. Low weight on bit was required to kick off, and the bit was pulled on hours. To expedite the drilling operation, the gyro was run above the measurement while drilling (MWD) tool. By having the gyro behind the MWD tool, a trip was avoided once the well was kicked off. The gyro was sent by wire line to the surface and drilling continued. The gyro kick off required 50.75 hr.

A Navi-Drill M1X Ultra Series drilling motor drilled the 98.4-mm well bore out of the 114.3-mm casing. Real-time gamma ray logs were taken using a NaviGamma short radius Femwd tool. The curve continued per plan with the required build rates achieved until the Lower Fernie formation was encountered.

Two 15°/30 m doglegs were observed over three drilling singles. At this point, because the projected build rate requirement exceeded 30°/30 m to land at the specified TVD, the BHA was tripped to set the motor at the 3.2° tilt angle necessary to achieve the required build rate. After obtaining a 36.1° and a 34.7° dogleg, the BHA was tripped to adjust the motor to a rotatable setting. Rates of penetration exceeding the anticipated 4 m/hr were achieved in both the curved and horizontal sections, with penetration rates of 12 m/hr in the curve and horizontal section.

An invert mud system facilitated hole cleaning through the build section in Fernie and Nordegg shale, and also minimized shale effects while the hole remained open. The curve was landed at 2,100.8 m TVD and a 90° inclination following a vertical section of 87.66 m. At 90° inclination, the hole was circulated and displaced to a viscosified diesel polymer fluid system that was weighted to contain formation pressures.

The horizontal section was drilled within the specified TVD window (1 m), although a kick was taken at 2,184 m measured depth (MD). Increasing the mud weight to 1,050 kg/cu m controlled the kick, and drilling continued to a total depth of 2,439 m MD. The time from kick off to total depth was 9.8 days.

The well was successfully reentered and drilled with few problems. The build section to 90° inclination was cased with 60.43-mm tubing (uncemented) to 2,157 m MD, while the 281 m horizontal section was left open hole. TVD was maintained within 1 m. Initial production improved from the previous 3.2 cu m oil/day to 300 cu m oil/day, with gas production increasing from 500 cu m/day to 26,300 cu m/day (Table 1 [22568 bytes]).

Well preparation costs were $121,800 (all amounts are in Canadian dollars), and the drilling and completion costs were $603,303.

Golden field

The primary geological target of a Norcen Energy Resources high-angle reentry project in the Golden field was the Slave Point formation. This formation consists of a light to dark brown limestone interbedded with crystalline dolomite and shale laminate.

Stromatoporoids are found in abundance in the eastern and southern flanks of the Peace River Arch in northern Alberta. Of 22 existing vertical wells in this field, four had been abandoned because of low production, and another was operating below minimum economic criteria.

The vertical wells had been drilled at various times between 1975 and 1991. All were cased wells generally having the following parameters:

• Surface casing: 219.1 mm, J-55, 25.7 kg/m

• Intermediate casing: 139.7 mm, K-55, 20.8 kg/m

• Production liner: 73-mm EUE tubing landed at 1,500-1,600 m.

The project was to reenter three of the four abandoned wells, intersecting the third and fourth cycles of the Slave Point formation and reaching beyond the swept zone of the vertical wells.

The objectives for these wells included the following:

• Penetration of the formation beyond the swept zone of the existing well

• Qualification for the Alberta Royalty Holiday program by drilling 100 m at an inclination greater than 80°

• Avoidance of problem shale exposure in the Ireton formation at the casing point.

• Placement of production equipment as close to the target zone as possible.

Consistent well bore preparations applied to the three reentry wells. The rods, pump jack, tubing, and anchor were pulled from the wells, and the required modifications were made to the lease. A casing scraper was run in tandem with a gauge ring to clean the well bore and verify the casing drift diameter for safe casing exiting and directional drilling tool passage.

Once this procedure was completed, a permanent bridge plug was set to abandon the perforated interval. Cement was then dump-bailed to cap the bridge plug and prepare the hole for the whipstock and window milling procedure. The cement was polished, and a cement bond log and casing collar locator were run to verify position of the whipstock and location of the casing exit.

A whipstock and milled window were used to exit the 139.7-mm casing. The well path incorporated build rates exceeding 30°/30 m in a 120.7-mm hole. With a gyro tool for orientation, the wells were kicked off until inclination reached 4°. At this point, a conventional NaviGamma MWD tool was used for navigating the formation.

Inclinations were held to less than 90.0° on the three wells to allow for the intersection of additional cycles of the Slave Point formation at deeper depths. Total vertical section displacements ranged from 120 m to 240 m.

Build rates ranged from 29.3°/30 m to 32.8°/30 m, with hold angles of 83.4-90.0°. A 79.4-mm OD Mach 1X drilling motor was selected for the build interval, as it can be rotated at 30°/30 m while drilling.

A more powerful Mach 1XL motor (having reduced build rate capability) was used to finish the curve and drill the horizontal section. Both motors produced predictable build rates, and the adjustable kick off housing permitted flexibility in responding to well path correction requirements. Actual dogleg severity for the three wells ranged from 9.89°/30 m to 67.4°/30 m, with an average severity of 30°/30 m.

Two of the wells flowed oil at a rate of 3-5 cu m/hr during drilling. An oil-based drilling fluid controlled the shale while the curve and horizontal sections were drilled. Upon completion of the drilling operation, the hole was displaced with produced water. On one well, this resulted in tight hole conditions caused by shale swelling.

The 120.7-mm curves were completed with 73.0-mm and 88.9-mm, J-55, EUE liners. Liner connections were shaved to reduce drag and to assist in running the liner through doglegs of 67.4°/30 m in the build section. When possible, liners were run to total depth, with the liner top 20-30 m above the milled window.

These reentries were drilled with a service rig. The limitations of service rigs must be addressed during the planning phase. Key considerations include the following:

• Sufficient boiler size for winter operations

• Pumping and surface pressure handling capabilities

• Rig engine reliability and horsepower

• Crew experience in horizontal reentry applications

• Ability of power swivel to lock and allow accurate drillstring orientation during sliding.

Table 2 [21411 bytes] shows the production improvements of the three wells. The well costs were as follows: Well 15-36-86-15, $865,000; Well 6-7-87-14, $1.072 million; and Well 5-8-87-14, $791,000.

Rainbow Lake

For a Husky Oil Operations Ltd. horizontal reentry in 177.8-mm casing in Rainbow Lake, the producing formation is the Keg River limestone which underlies the anhydrite-dolomite sequence. Keg River limestone is bound on the fringe by the Black Creek salt and anhydrite. Keg River limestone in this pool can be cryptocrystalline to microcrystalline and exhibits various degrees of pinpoint-vuggy porosity. Two producing intervals within the Keg River formation are illustrated in Fig. 3 [35642 bytes]. The upper interval is more prolific and more permeable, while the lower interval, which is known to be oil bearing, may be extensively pyrobitumen plugged.

The original vertical well was drilled in 1972 and was cased and lined as follows:

• Surface casing: 244.5 mm, K-55, 53.6 kg/m, ST&C to 204 m

• Intermediate casing: 177.8 mm, K-55, 34.2/29.8 kg/m, ST&C to 1,939 m (29.8 kg/m from 1,183m to 2,018m)

• Production liner: 114.3 mm, K-55, 15.6 kg/m, ST&C from 2,018 m to 2,913 m.

The initial completion had perforated the Keg River formation, and a recompletion had perforated the Muskeg formation. In preparing for the new reentry, a service rig was moved in to pull the existing tubing, anchor, and straddle packer system and then to abandon the squeezed perforation intervals. This procedure consisted of setting a 114.3-mm permanent bridge plug above the Keg River interval and installing a cement plug above the Muskeg perforation intervals. The bridge plug was capped with approximately 8 linear meters of cement, resulting in a cement plug top at 1,773.67 m. A casing inspection log and cement bond log indicated no deficiencies.

The geological target of this horizontal well was a pinnacle reef of the Keg River formation (Fig. 4 [27955 bytes]). Approximately 700 m in diameter, the pinnacle reef is formed by the Sharky, Lower Muskeg, and Black Creek formations which consist of anhydrite with dolomite stringers. The vertical well is approximately 150 m from the reef edge.

Drift surveys indicated that no more than 3.0° of inclination existed at the kick-off point. After dressing the abandonment plug to a depth of 1,782 m, a gauge ring and casing collar locator log were run to verify proper location of the whipstock. A 139.7-mm OD bottom trip whipstock was run and aligned to an azimuth of 19.0°, and the window was milled using a 1,005 kg/cu m XCD/guar-gum/lime milling fluid from 1,774.66 m to 1,778.44 m. Three standard milling assemblies were required, with a total time for orienting and milling of 31 hr.

Prior to picking up the 158.7-mm BHA, a gyro survey indicated that at kick-off point the well was displaced 9.15 m along an azimuth of 233.14°, which was to the south and west of the required trajectory (see box). The well plan was revised to remain to the west but to land at the same TVD and horizontal entry point as planned originally. Time consumed for kick off and orientation was 32 hr.

After the desired target was reached, the 297-m horizontal section was drilled using a BHA with a string stabilizer run behind the adjustable motor (Box 1). A polymer/carbonate/lime drilling fluid system was used, with mud weights ranging from 1,005 to 1,040 kg/cu m. The horizontal section climbed 37.7 m TVD across the reef edge before penetrating the Black Creek salt. The well was logged using a drill pipe-conveyed wet connect system with a hole finder run at the base of the tool. A TLC tool failure occurred at 1,810 m MD, so completion of the logging program through the upper sections used conventional wire line tools. After logging was completed, saltwater in the hole was displaced with drilling fluid.

A low-quality reservoir was encountered; as a result, production figures were less than expected. This dense limestone reservoir, filled with pyrobitumen and asphaltenes, ultimately required an extensive completion and stimulation program.

After the cement was drilled and cleaned from the liner top, a stimulation assembly was run and latched onto an open hole inflatable packer. The packer had been run before the liner to allow for future selective open hole stimulation. The interval past the packer was swabbed with no inflow.

An attempt to bullhead squeeze a 15% HCl acid blend was unsuccessful in establishing an injection feed rate at 18.0 MPa. The initial annulus feed rate was 0.64 cu m/min at 17.2 MPa, and only 0.03 cu m/min at 15.0 MPa after disconnecting from the packer. During this sequence of events, the packer had moved down the hole 1.02 m. During respacing, the assembly could not be reconnected because rubber blocked the tool.

The rest of the hole was then acidized at a maximum pressure of 16.0 MPa. Swabbing dry produced only a trace of oil. Two intervals of open hole were then hydroabrasive jetted and the hole cleaned. The intervals were acidized with 10.0 cu m of a 15% blended HCl mixture. Swabbing initially produced oil cuts of 75%, but then dropped off to zero.

Three intervals of the liner were perforated using tubing-conveyed tools. The lower interval was selectively acidized, but swabbing produced no oil. Upper and middle zones were then acidized, but no improvement was obtained. Then, the upper two intervals were stimulated with 6.0 cu m of mutual solvent at 1.0 cu m/min at 11.6 MPa.

The well flowed a high gas rate and approximately 1.0 cu m oil/hr. The jetted open-hole interval was re-acidized with 15.0 cu m of mutual solvent to 15.0 MPa. Swabbing the well dry produced an oil cut of 98%. The final completion procedures consisted of running two hydraulic packers and a collet catcher sub (Fig. 5 [41014 bytes]).

Tables 3 [6144 bytes] and 4 [11474 bytes] and show the costs and production results.

House Mountain field

The House Mountain field has produced from three cycles of Alberta's Middle Devonian Slave Point formation for more than 30 years. It was put on waterflood in 1965. The Beaverhill Lake Group, in particular the Middle Devonian Slave Point member, ranges from a depth of 2,200 m to 2,590 m and is the primary producing zone. Consisting of a reef and shoal environment, the Slave Point formation is supported by a stromatoporoid platform (Fig. 6 [13206 bytes]). The reservoir is limestone, with no gas cap or aquifer, and has a porosity of approximately 10% and a permeability of 10 md.

Original oil in place is estimated at 60 million cu m, with current estimated recovery of 19 million cu m. The field was producing approximately 800 cu m oil/day from 20 horizontal and 146 vertical wells. Supported by 60 waterflood injectors, the horizontal wells are responsible for 25% of the daily oil production. These wells were originally cased with 139.7-mm OD and 114.3-mm OD casing, with more then 250 wells having the 114.3-mm casing.

The objective of Shell Canada Ltd.'s horizontal reentry project was to reenter 14 of the wells that had 114.3-mm OD casing, accessing areas of the reservoir that were unswept or poorly swept at the edges of the reef complex or where irregular waterflood performance was identified. One challenge was to avoid drilling in known problem shales such as the Ireton, Duvernay, and Majeau formations. The casing exit points for the wells had to be as low as possible for kicking off and drilling the build sections to avoid most of the problem intervals.

Selected wells were reentered using a standard preparation, drilling, and completion program to the extent possible. The program was similar to those described in the foregoing cases, with pulling of the rods, pump, tubing, and anchor, and then running a casing scraper with a gauge ring, and setting a permanent bridge plug to abandon the perforated interval. The plug was capped, and cement bond logs with casing collar locators completed drilling preparations.

Casing exits used bottom trip whipstocks and standard milling runs. Kick-off points were programmed, on average, 100 m above proposed horizontal entry points. Medium radius build sections comprised 20-25°/30 m build to 70-80° inclination, and 9-12°/30 m build to 85-90° at an entry point 70-100 m away from the vertical well. Horizontal sections varied from 400 m to 700 m long with geological constraints of 1.5-2.0 m TVD. Lateral windows of 50-150 m extended from the heel to the toe of the horizontal section.

Special 73-mm OD drill pipe with 23/8-in. HTSLH90 connections and a double-shouldered torque face were required to allow 45.7-mm survey tools to pass. The BHA consisted of a 79.4-mm OD Mach 1X motor, crossover sub bored for a float, two 6-m flexible nonmagnetic drill collars, one 3-m flexible nonmagnetic drill collar, an MWD pulser sub, two 6.2-m flexible nonmagnetic drill collars, and a crossover sub. The 73-mm OD drill pipe with 23/8-in. HTSLH90 connections ran to surface. Drilling weight on bit ranged 1,000-2,000 daN for kick off and 4,000-5,000 daN during drilling.

Average build rate for the curve sections to 70-80° was 21°/30 m, with a maximum dogleg of 33°/30 m. This portion of the build section was drilled in oriented mode. The same assembly was tripped and adjusted to drill the rest of the curve section to 85-90°. Actual dogleg severity ranged 6-15°/30 m. The Mach 1X and Mach 1XL motors used for the build section and the horizontal segment inclination to TVD were rotated at 40-60 rpm and oriented when required to control dogleg severity or respond to target TVD adjustments.

Modified ATJ-M33 Tricone bits were obtained to withstand side-loading forces encountered while rotating in the 22°/30-m curve sections. The 98.4-mm bits incorporated sealed journal bearings used in larger bits, as no 98.4-mm OD bits with sealed journal bearings were normally available. The modified bits lasted 20-25 hr in the curve sections and 30-35 hr in horizontal sections.

Drilling fluid for the reentries was an HEC/Drispac mud system. Mud weight ranged 1,020-1,050 kg/cu m. This system kept the hole clean and maintained a relatively stable borehole. Where control was required, brine water with calcium chloride and calcium carbonate was added to raise the mud weight to 1,600 kg/cu m.

Downhole hydraulic thrusters were used when drag became so significant that weight could no longer be transferred to the bit without stalling the motor. Typically, this point occurred after drilling approximately 400-500 m of horizontal section. The thruster was placed a single or three singles behind the BHA. In all cases, the thruster performed well and enabled drilling of the horizontal section to total depth.

A 79.4-mm OD MWD Navi-Trak tool was used in the curve and horizontal sections for navigation of the well path. The tool was run inside a nonmagnetic drill collar, and its 79-mm OD pulser sub was made up to the flexible collar. These tools performed well during the project, experiencing only two downhole failures.

On the first six wells, completions employed 73-mm EUE liners, but 60-mm EUE liners were used thereafter because tight hole conditions caused difficulty in running the larger liners. The 60-mm EUE liners reduced running problems. They were not cemented and provided communication with the horizontal section.

Once the liners were run, horizontal sections were stimulated with acid through 38.1-mm OD coiled tubing. A 15% HCl Nowferr acid blend was pumped at volumes from 200 l./min to 75 l./min. Three passes were performed on the horizontal sections. The first pass consisted of a jetting clean-out trip at 15-20 l./min and was followed by jetting-squeeze-jetting clean-out trips.

Typical artificial lift assemblies involved downhole gas separators, rod insert pumps, and sucker rods run above the liners to surface. One well used an electrical submersible pump installed in the casing. Downhole gas separators have been tested only for 6 months on 12 wells and have increased oil production and pump efficiency from 36% to 73%.

In this field, the 114.3-mm OD casing horizontal reentry encountered few problems. The one curve conventionally drilled and the horizontal section drilled underbalanced had disappointing production results.

The drilling rig, pipe, directional equipment, bits, and fluids program ultimately achieved project goals. Options for slim hole completions are restricted, but the completion program employed in these wells did result in higher pump operating efficiencies and substantial incremental oil to the surface.

Tables 5 [3862 bytes] and 6 [3770 bytes] summarize costs and production results for the 14 wells.

Recommendations

Several standard steps in the planning and execution of slim hole reentries can be drawn from these projects. Reentry projects in similar cases may have an improved chance of success if these steps are considered carefully in the early planning phases.

• Service rigs should be used to prepare the well for reentry to save on rig costs.

• Pressure ratings, drilling performance, and reliability of the drilling rig should be checked. High pressure losses and surface pressures must be considered.

• Experienced crews and accurate rig floor gauges are critical.

• Accurate geological interpretations of the play and target zone are required.

• Options other than a horizontal well bore through the entire zone of interest should be investigated.

• The use of the abandonment plug as a bridge plug for the whipstock packer mechanism, if possible, can save money. A one-trip whipstock can also reduce costs.

• If the well plan can be made less directionally specific at the horizontal entry point, the number of gyro check shots can be reduced.

• With sufficient internal casing diameter of 177.8-mm OD, a 158.8-mm hole should be drilled. This diameter will assist in the liner running operation.

• Recent motor and Femwd developments may allow high rotatable build settings and reduce the number of trips. These tools are rotatable at 30°/30 m and allow flexibility for the well path kick-off point, trajectory, and well path changes while drilling.

• A string stabilizer should be run behind the motor while drilling the horizontal section. This will help control dogleg severity and improve well path execution.

• Depending on hole conditions, reaming operations at total depth may not be needed.

• A resettable packer should be left downhole at total depth to provide service rig options for completion and stimulation work.

• Both a float shoe and a float collar should be run on all jobs.

• An hydraulic thruster should be at the well site as a backup if drag problems are encountered.

• A buildup pressure test should be performed on the reentry candidate to avoid unexpected pressures.

• The casing should be pressure tested.

• A cement bond log and a casing collar locator should be run to ensure that the section of casing above, below, and at KOP has competent cement for milling and sidetracking. If cement is absent or in poor condition, perforating or squeezing cement may be necessary.

• The drift diameter of the pipe should be no less than 50 mm to allow the gyro survey tool to pass through the BHA.

• In 114.3-mm casing reentries, a 60-mm EUE liner with beveled couplings can maintain an open flow area to the horizontal section. In 20-33°/30 m curves, this can reduce hang-up problems while running the completion.

• Downhole gas separators reduce costs, positively influence pump efficiency, and will increase oil production.

Thorough reentry preplanning with careful consideration of ongoing advances in bit design, mud motors, and Femwd technology can produce dramatic improvements in production of mature wells.

Acknowledgment

The authors thank Frank Radez for his editorial contribution.

Rainbow Lake drillstring configurations

Kick-off through curve

 89-mm drill pipe
 89-mm heavy weight drill pipe
 89-mm drill pipe
 121-mm drilling jars
 89-mm drill pipe
 121-mm circulating sub
 121-mm 3 89-mm-body nonmagnetic flex drill collar
 121-mm flow sub with DMWD probe
 121-mm 3 95-mm-body nonmagnetic flex drill collar
 121-mm-body UBHO sub
 73-mm drill pipe
 121-mm float sub
 121-mm Mach 1P/HF low-speed motor
 158.7-mm drill bit

Horizontal section

 89-mm drill pipe
 89-mm heavy weight drill pipe
 89-mm drill pipe
 121-mm drilling jars
 89-mm drill pipe
 121-mm circulating sub
 121-mm 3 89-mm-body nonmagnetic flex drill collar
 121-mm flow sub with DMWD probe
 121-mm 3 95-mm-body nonmagnetic flex drill collar
 121-mm-body UBHO sub
 73-mm drill pipe
 121-mm float sub
 140-mm-gauge 3 119-mm-body string stabilizer
 121-mm Mach 1C low-speed motor
 155.6-mm drill bit

The Authors