Ream-while-drilling tool cuts costs of three Venezuelan wells

Jorge Rodriquez Rothe
Lagoven SA
Maturín, Venezuela

Leandro J. Carré C.
Corpoven SA
Norte de Monagas, Venezuela

Ricardo Portillo
Hughes Christensen Co.
Maracaibo, Venezuela

Marcos Leal
Hughes Christensen Co.
Maturín, Venezuela

Lagoven SA ran the ream-while-drilling tool in an exploration well, saving almost $635,000 in total drilling costs, and Corpoven SA saved more than $145,000 by using the tool to enlarge the holes in two development wells.

The new ream-while-drilling (RWD) tool was used for the first time in Venezuela in Lagoven SA's exploratory well PTL-4X, in which an influx of formation gas in the top hole required an unexpected alteration of the original casing program. The modification of the casing program necessitated underreaming for the first time in the new field, located in the State of Monagas.

Because of the high-cost and potential hazards associated with conventional underreaming, Lagoven instead employed the RWD system, which successfully drilled and reamed the two targeted sections. On the basis of eliminating the additional 36 days of rig time and other expenses associated with the conventional reaming undertaken in similar wells in the area, the one-pass operation saved an estimated $634,834 in drilling costs.

Because of the success of the PTL-4X operation, Corpoven SA subsequently used the RWD system in the Mulata field, where offset wells traditionally required an average of 1,973 ft of underreaming. One tool successfully drilled and reamed two wells and remained in a condition suitable for reuse. Corpoven ran the tool under a rental agreement and saved $146,782, when compared to three Mulata offsets.

Reaming experience

When using standard reaming techniques to enlarge open hole sections, operators have normally drilled a pilot hole to the next casing depth and afterwards run an expandable-arm underreamer. In some cases, reaming the hole to its targeted diameter was more time-consuming than drilling the pilot hole.

Besides the direct costs associated with reaming, frequent downhole tool failures, in particular the loss of underreamer arms and pins, severely affected total well economics. Furthermore, the historically low penetration rates (ROPs) prevented operators from optimizing drilling efficiency.

Initial efforts to circumvent the economic and technical drawbacks of standard underreaming techniques focused on bicenter PDC bits.^1-5 Because of its unique geometry, a bicenter bit can freely move to one side of the hole during the trip through the casing and effectively drill a hole size larger than the inner diameter of the casing through which it passes.

Although a step-change improvement over standard underreaming, bicenter bits are not without operational problems that can negatively affect drilling costs. Warren, et al., perhaps best amplified the difficulties associated with the use of bicenter bits for opening holes.⁶ Foremost among the problems are deviation tendencies that make these bits extremely weight sensitive when run on rotary drilling assemblies. Because only stabilizers matching the pass-through diameter can be used, deviation control is difficult.

The cocking (walking) tendencies of bicenter bits generate unusual wear patterns, making it challenging to affect proper stabilization. This propensity places severe limitations on rotary speed, thus lowering penetration rates. Aside from low penetration rates, bicenter bits have not eliminated drillstring failures, abnormal tool wear, and instances where the reamed interval was not as large as that stipulated in the well plan.

In the majority of wells drilled onshore Venezuela, the shortcomings of bicenter bits in reaming operations were even more pronounced, particularly in the upper sections, which are highly prone to bit balling. As such, the shallower fluid courses of one-piece bicenter bits significantly restrict hole cleaning in those intervals. Furthermore, the abnormal pressure characteristic of Venezuelan wells requires the setting of maximum-diameter liners throughout the well bore to minimize hole loss. This requirement and the wide variance of formation composition require flexibility in the size and type of pilot bits and bottom hole assemblies. Standard bicenter bits do not afford this flexibility.

The ability to drill and ream in a single pass has become even more advantageous as the global trend toward deeper, high pressure, high temperature wells increases. Because of the extra casing strings and longer intervals often drilled through unstable or encroaching formations, operators have recognized the enormous economic advantages of simultaneous drilling and reaming.

Contemporary exploration trends and the documented limitations of both bicenter and traditional hole opening technology spurred the development of the ream-while-drilling tool.^6-8

RWD tool design

The ream-while-drilling (RWD) tool is a two-piece system that, unlike traditional underreamers, incorporates no moving parts (Fig. 1 [54521 bytes]). This design eliminates the risk of leaving metal parts, such as underreamer arms and pins, in the hole. The first section of the tool consists of the pilot bit; the second is essentially a tube incorporating either four or five fixed blades with PDC cutters. The position of fluid jets on only one side of the tool enables eccentric rotary movement to widen the pilot hole.

By virtue of the two-piece configuration, the type and size of both the pilot assembly and bit depends only on the design of the specific tool. Thus, either a PDC or roller cone bit can be used, depending on the formation composition.

The geometry of the RWD tool revolves around three interrelated diameters: pass through, drill size, and pilot bit (Fig. 2 [123248 bytes]).

The pass-through is the drift diameter of the casing or the liner through which the system must pass. Drill size is the final drilled hole diameter. The drill size of the targeted section, in conjunction with the pass-through diameter stipulated in the well objectives, determines the pilot bit diameter.

The geometry allows the tool to adapt easily to the maximum diameter of the liner or casing in which it must pass. Upon rotation, the tool is then able to widen the hole to its programmed final diameter.

The leading, or hole opening, blade creates a smooth transition from the pass-through size to the drill size, providing faster stabilization of the system. The pilot bit stabilization pad offsets the net imbalance force of the reamer blades, thus providing the additional stabilization not possible with bicenter bits. Basically, the stabilization pads force rotation around the center of the pilot hole, ensuring the drilling of a full-size well bore. Both the pilot hole size and the extent of the imbalance force generated determine the size of the gauge pad.

The reamer wing has carbide-supported edge PDC cutters. The shape of these new-generation cutters strengthens the diamond edge and delays the onset of fracture and cutter wear.9 By spreading the cutter arrangement across the profile of the tool, the RWD tool designers successfully facilitated even load distribution.

The cutter surfaces are highly polished, which is especially advantageous when sections prone to bit balling are drilled, such as those encountered in the upper hole of Venezuelan wells. Polished PDC cutters have a friction coefficient of 0.1, or that of ice sliding on ice.¹⁰ Polished cutters reduce the penetration rate limitations posed by the built-up edge that forms when an amount of drilled formation is not removed and subsequently attaches itself to the leading edge of the cutter. Polished cutters reduce the shear forces that restrict cuttings removal and limit penetration rates. The polishing process also removes any microscopic imperfections in the cutter, further enhancing cutter durability.

Well PTL-4X

The earliest design of the tool was run for the first time in Venezuela in exploration well PTL-4X in the Las Piedritas field in Monagas State, 51 km from Maturín. The primary objective was to evaluate the Ofícina formation, comprising medium/

hard shales and clay to sections comprising 100% shale with traces of pyrite, sandstone, and quartzite (Fig. 1 [19283 bytes]). Offset well data suggested the formations were ideally suited for drilling with PDC bits.

On the basis of seismic data and correlations from three offset wells, operator Lagoven had planned to drill standard hole sizes, employing a conventional casing program (30 in. X 20 in. X 133/8 in. X 95/8 in. X 7 in.). Lagoven was forced to alter the original casing program, however, upon encountering an influx of formation gas at 10,432 ft, while the 171/2-in. section was drilled.

Increasing mud weight to 12 ppg did not alleviate the condition, as a leak-off test at the 20-in. shoe disclosed 12.2 ppg of pressure. Lagoven decided to set casing at that point. An estimated 1,100 ft of the low-pressure La Pica formation remained open, requiring the setting of an 113/4-in. liner to cover the entire formation. From that point forward, the original program that called for the drilling of a 121/4-in. hole to set the 95/8-in. casing remained as planned.

The final casing program required reaming the holes to the programmed diameters. After analyzing hole opening experiences elsewhere in eastern Venezuela, Lagoven chose the RWD tool to drill and ream the 133/4-in. and 121/4-in. sections to conform with the final program.

133/4-in. interval

A 121/4-in. pass-through RWD system with a 97/8-in. IADC M323 (International Association of Drilling Contractors bit code) PDC pilot bit with polished cutters was run with water-based mud.8 9 Before the RWD tool entered this section, Lagoven drilled 192 ft of 121/4-in. hole, coring 66 ft. The RWD system was first used to ream this section, drilling 182 ft in 9.4 hr. The remainder of the section was reamed and drilled in three stages, largely because the operator desired intermittent inspection because the RWD tool was a new design being run for the first time in the area.

At 10,721 ft, penetration rates slowed, prompting the operator to pull the system and run electric logs and a six-arm caliper to determine if the RWD tool was drilling and reaming the hole to its programmed diameter. Upon determining the hole was in-gauge and drilled to the targeted diameter, and after finding no prospective zones, Lagoven subsequently suspended the logs. Examination of the tool showed 1% wear.

Lagoven again suspended drilling at 11,189 ft to run a single shot, which revealed a hole deviation of 1.98°. At that point, the RWD system showed 3% wear.

At 11,333 ft, the penetration rate again dropped dramatically-this time to 2.5 ft/hr. Nonetheless, drilling continued to the targeted interval depth of 11,630 ft, despite the continual influx of gas. The uninterrupted gas flow required sequential increases in mud weight to 12.9 ppg.

In the three runs, the RWD tool drilled a total of 1,195 ft in 262.5 hr for an average reaming and drilling penetration rate of 4.55 ft/hr. Table 1 [23259 bytes] summarizes the parameters used in drilling the 133/4-in. interval and the overall performance of the RWD tool. The caliper log, showed a minimum 13-in. hole diameter, which was consistent with the well objectives.

121/4-in. interval

In this section, a 107/8-in. pass-through RWD tool and an 81/2-in. IADC M433-type PDC pilot bit were run with oil-based mud. As in the previous interval, Lagoven ran the tool in three stages: the first to change the bottom hole assembly, the second to run logs, and the third upon completion.

Before the bottom hole assembly change out, the system drilled 1,845 ft in 156 hr at a sustained penetration rate of 11.82 ft/hr. The system was returned to the hole at 13,502 ft, where it drilled 1,298 ft in 111 hr for an average penetration rate of 11.69 ft/hr.

Expecting to encounter a regression zone around 14,800 ft and anticipated pore pressure of 10.5-11.0 ppg, Lagoven suspended drilling to run logs, including six-arm caliper (12.3-13.0 in.). At the time, the mud weight was 16 ppg to avoid the severe circulation loss encountered on offset well PTL-3X.

In the final segment of the interval (14,800-15,130 ft), Lagoven returned to the hole with a logging while drilling tool that detected a regression zone at 15,120 ft. In this third and final run in the interval, an 81/2-in. pilot hole was drilled to facilitate the running of electric logs, after which the RWD tool reamed to 121/4 in.

Because the previously drilled hole was the same diameter as the pilot bit, operating parameters were lowered to prevent potential damage to the reamer wing that could result from reaming a previously drilled open hole. The lower drilling parameters in the third stage resulted in a lower average penetration rate than that recorded in the previous two runs.

The parameters used in the three runs and the performance are summarized in Table 2 [24316 bytes]. The caliper log showed the hole was drilled to a minimum of 12.3 in., per the interval objectives.

Overall, the RWD tool drilled a total of 3,473 ft in 331.4 hr, for an average penetration rate of 10.48 ft/hr. Combining the 133/4-in. and 121/4-in. sections shows the RWD system drilling a total of 4,668 ft in 594 hr, for an average penetration rate just under 8 ft/hr.

After the third run, the RWD tool was graded 6,3,WT,S,X,I,BT,TD, and the pilot bit 1,2,WT,S,X,I,PN,TD.

MUC-65 and MUC-66

The MUC-65 and MUC-66 wells are part of the Pigap gas injection project Corpoven SA is developing in the Mulata field. Fig. 4 [16084 bytes] illustrates the lithology for Well MUC-65; shale is predominant in the Carapita formation. Well MUC-66 has similar lithology. Table 3 [7332 bytes] details the casing program.

Reaming the 22-in. and 17-in. sections was predicated on the need to complete the wells with 7-in. casing and to isolate the formations because of the wide range of reservoir pressure throughout the well bores.

The RWD technology enabled Corpoven to run 16-in. and 133/8-in. casing instead of larger, more expensive casing that would allow the pass-through of larger drill bits. The system included a 17-in. pass-through RWD tool and a 105/8-in. standard IADC M221 PDC bit.

Table 4 [22886 bytes] summarizes the drilling parameters and performance of the RWD system in the two wells, which included two runs in the MUC-66.

In the MUC-66, the tool drilled 108 ft to 5,823 ft, and then a cement plug was pumped to perform a leak-off test. Drilling with the new system continued uneventfully until 5,945 ft, whereupon mud weight was increased to 16.5 ppg to control gas flow. Beginning at 6,353 ft, Corpoven controlled the penetration rate as another means of contending with the content of formation gas.

Upon completion of previous well MUC-65, hole deviation was 8°, which was somewhat high compared to the direct offsets. To minimize this effect on well MUC-66, the drilling team eliminated one of the stabilizers between the pilot bit and RWD tool and another above the tool. Although deviation dropped to 6.5°, it remained somewhat higher than that in other wells drilled in the field.

A study of the different bottom hole assembly combinations used in the area is under way with the aim of developing a configuration that will minimize angle building tendencies in future wells. The caliper logs from both wells showed 100% of the hole drilled at the required 17-in., or larger, diameter.

When the bottom hole assembly was pulled, there was no indication of fracturing on any of the welded areas. Both the cutters and blades were pulled in basically green condition and were rerunnable.

Economic analysis

In determining the cost savings for the PTL-4X exploratory well, Lagoven relied on data recorded in similar wells drilled elsewhere in eastern Venezuela. The objectives of the three wells drilled previously in the new field did not mandate underreaming; therefore, a direct offset comparison is not possible. Lagoven determined it saved $634,834 based on the daily drilling costs associated with the average of 36 days required to enlarge identical open hole sections in wells drilled elsewhere in eastern Venezuela.

Taking the average 36-day reaming time into account, the costs are broken out as follows: $309,507 for rig costs, $47,332 for consultants, $66,000 for underreamer rental, $71,557 for mud logging, and $140,438 for drilling mud.

For the MUC-65 and MUC-66 wells, Corpoven compared them directly with offsets in the more developed Mulata field. Each of the offsets used in the comparison required underreaming of similar sections. Tables 5 [29589 bytes] and 6 [26044 bytes] compare the actual costs of drilling and reaming, respectively, for the three offsets used in the analysis.

In these wells, traditional hole openers were the only available options. Thus, the average reaming and drilling costs for the three offset wells was $163,735, or an average of $83.07/ft. Table 7 [5771 bytes] details the costs incurred in the MUC-65 and MUC-66.

The RWD tool drilled and reamed nearly as much footage at nearly half the cost per foot of that for the three offsets. By successfully reaming and drilling in one operation, Corpoven saved a total of $146,782 in both wells.

Acknowledgment

The authors wish to thank the management of Lagoven SA, Corpoven SA, and Hughes Christensen Co. for permission to publish this article. The authors also thank Jim Redden for preparation of the manuscript.

References

1. Quintana, J.L., "Bi-Center Bit Performance Reduces Drilling Cost in California," paper No. 23869, presented at the Society of Petroleum Engineers/International Association of Drilling Contractors Annual Drilling Conference, Feb. 18-21, 1992, New Orleans.

2. Casto, R.G., and Senese, M., "Use of bicenter PDC bit reduces drilling cost," OGJ, Nov. 13, 1995, pp. 92-96.

3. Kalloo, C.L., Attong, D.J., and Steele, H.E., "A Novel Design Bi-Center Bit Successfully Drills Deep Exploration Well Off the East Coast of Trinidad," paper No. 27471, presented at the SPE/IADC Annual Drilling Conference, Feb. 15-18, 1994, Dallas.

4. Myhre, K., "Application of Bi-Center Bits in Well Deepening Applications," SPE Drilling Engineering, June 1991, pp. 105-10.

5. Sketchler, B.C., Fielder, C.M., and Lee, B.E., "New Bi-Center Technology Effective in Slim Hole Horizontal Well," paper No. 29396, presented at the SPE/IADC Annual Drilling Conference, Feb. 28-Mar. 2, 1995, Amsterdam.

6. Warren, T.M., Sinor, L.A., and Dykstra, M.W., "Simultaneous Drilling and Reaming with Fixed Blade Reamers," paper No. 30474, presented at the SPE Annual Technical Conference and Exhibition, Oct. 22-25, 1995, Dallas.

7. Csonka, G., Tweedy, M.W., Cornel, S., and Anderson, M., "Ream While Drilling Technology Applied Successfully Offshore Australia," paper No. 36990, presented at the SPE Asia Pacific Oil and Gas Conference, Oct. 28-31, 1996, Adelaide, Australia.

8. LeBlanc, L., "Reaming-While-Drilling Keys Effort to Reduce Tripping of Long Drillstrings," Offshore, April 1996, pp. 30-32.

9. Cooley, C.H., and Meany, N., "The Development of a Fracture-Resistant PDC Cutting Element," paper No. 28312, presented at the SPE Annual Technical Conference and Exhibition, Sept. 25-28, 1994, New Orleans.

10. Smith, R.H., Lund, J.B., Anderson, M., and Baxter, R., "Drilling Plastic Formations Using Highly Polished PDC Cutters," paper No. 30476, presented at the SPE Annual Technical Conference and Exhibition, Oct. 22-25, 1995, Dallas.

The Authors