SPE 69498

OPTIMIZING DEVELOPMENT COSTS BY APPLYING A MONOBORE WELL DESIGN

Rodolfo García, Edgardo Alfaro, Alfredo Bernardis, Daniel Casalis, José Gallardo, SPE, Daniel Del Zotto, Perez Companc
and Adrián Alonso, Weatherford

Copyright 2001, Society of Petroleum Engineers Inc.

Above the Springhill is another productive formation called
This paper was prepared for presentation at the SPE Latin American and Caribbean Petroleum Magallanes. Magallanes is an oil and gas reservoir with a static
Engineering Conference held in Buenos Aires, Argentina, 25–28 March 2001.
pressure of 2500 psi at 1700 m depth. So far, this formation has
This paper was selected for presentation by an SPE Program Committee following review of
information contained in an abstract submitted by the author(s). Contents of the paper, as
not been developed.
presented, have not been reviewed by the Society of Petroleum Engineers and are subject to The first wells of the An Aike field were drilled to 600 m
correction by the author(s). The material, as presented, does not necessarily reflect any position
of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE with 133/8-in. surface pipe; 2000 m of 95/8-in. intermediate pipe,
meetings are subject to publication review by Editorial Committees of the Society of Petroleum
Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial
to case the Magallanes formation; and a 7-in. production liner in
purposes without the written consent of the Society of Petroleum Engineers is prohibited. 81/2-in. hole, to total depth, through the Springhill gas-producing
Permission to reproduce in print is restricted to an abstract of not more than 300 words;
illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where formation (Fig. 2).
and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX
75083-3836, U.S.A., fax 01-972-952-9435.
Drilling
Several alternative designs were considered in order to reduce
Abstract cost, with special focus on the completion requirements. The
The An Aike–Barda Las Vegas field, located in the Austral basin analysis of possible wellbore size reduction led to the design of
80 km west of Rio Gallegos, Argentina, represents an important the AA-6 well, with 30% savings as shown in Fig. 8. This well
discovery in basin development in recent years. The field is an was cased to 600 m of 95/8-in. surface pipe; 2000 m of 7-in.
important Springhill formation gas reservoir at an approximate intermediate pipe; and a 41/2-in. production liner in 61/8-in. hole
depth of 3100 m and with static pressure of 4400 psi. Gas rates at the total depth, through the Springhill gas-producing
are up to 1 MM m3/d/well. formation. This reduced diameter well configuration schematic is
Drilling appraisal and development wells requires the shown in Fig. 3.
optimization of every operation involved. In this context, The time/depth curves of these wells before and after the
improvements in well construction and completion methodology changes (Fig. 4) show that rig time and costs were significantly
are important contributions. Original well design included 133/8- reduced with the new reduced diameter design (Fig. 5). Down to
in. surface and 95/8-in. and 7-in. casings, with a permanent 2000 m, the on bottom rotating time was reduced by 3.3 days, by
packer and 41/2-in. tubing. The new monobore well design drilling an 81/2-in. versus 121/2-in. borehole (Fig. 6). Spud to the
reduces the diameter of each drilled section, narrowing to a 41/2- total depth, rig time was reduced by 9 days (Fig. 7). Rig time
in. monobore installation through the pay zone. The rigless had the greatest impact on the total cost reduction, as shown in
completion includes coiled tubing. Fig. 5. Reduced requirements for mud and tubular goods were
Before adopting the design change, potential risk analyses also significant factors in containing overall well costs with the
were made to account for the possibility of future reentries and reduced diameter design.
for simultaneous development of a second target (Magallanes The AA-3 and AA-5 wells were drilled with the first design
formation) at 1700 m. The final well design model showed a (Fig. 2), AA-6 was drilled as shown in Fig. 3, and the AA-8 and
cost savings of 30 percent, a sizeable impact on the economics AA-9 wells were drilled with the new design shown in Fig. 10.
of this project. To lower drilling costs further, other alternatives were
considered. Leak-off tests were conducted in the AA-6 well to
History measure the pressure integrity of the formation. This information
The Springhill formation gas reservoir at a depth of 3100 m showed that the intermediate casing could be eliminated, further
produces up to 1 MM m3/d/well and has a static pressure of 4400 decreasing costs and allowing for an improved recompletion
psi. Fig. 1 shows the stratigraphic sequence of the An Aike field. over the Magallanes formation (1700 m) at a later date. The
2 R. GARCÍA, E. ALFARO, A. BERNARDIS, D. CASALIS, J. GALLARDO, D. DEL ZOTTO, A. ALONSO SPE 69498

production casing was designed in a tapered fashion allowing to procedure reduced the overall completion rig time as well as the
complete the well as a monobore. The required custom device associated intervention risk. While it provided a safe, reliable
was not ready for the AA-8, so 7-in. casing was run to total and more cost-effective alternative to traditional intervention,
depth in this well (Fig. 9). the greater challenge was to find a still more flexible and
The AA-9 production casing was successfully set as a economical way to complete these wells. Flexibility would a be
tapered string. This well was drilled to 850 m with a 121/4-in. a very important consideration when drilling a horizontal or
drill bit and cased with 95/8-in. surface pipe. Then, an 81/2-in. multilateral well from the same vertical well. For this reason, the
borehole was drilled with a PDC bit until the Springhill gas- new solution had to begin with a vertical well to reach new
producing formation was reached, continuing with a roller cone drainage areas while maintaining all the advantages of the
bit of the same diameter to the total depth. A 7-in. and 41/2-in. monobore design.
tapered string (Fig. 10) was run as production casing down to the To achieve this goal, two project procedures were addressed:
total depth and cemented with excellent results in well AA-9. 1) a reliable means of running and connecting 41/2-in. string and
2) a device capable of performing a good cementing job.
Completion The team of technicians developed a reliable 7 x 41/2-in.
Early completions performed in the An Aike field were carried crossover tool (Figs. 13a and 13b). This crossover tool is run
out according to conventional industry practice. Once the liner with the usual 7- and 41/2-in. casing string, and cementing is
cementing job was concluded, the drilling rig was rigged down performed by pumping all the fluids from the surface through
to make ready for running the completion (Figs. 11a, 11b and the casing using a specially designed plug (Fig. 14). This plug
11c). These figures show the sequence of events and all the tools has two rubber wings capable of sweeping cement inside 7-in.
used in a conventional completion. The liner had a tieback casing and two more inside 41/2-in. casing. The 41/2-in.
capable of supporting pressures up to 10,000 psi. production string is connected to the casing by an anchor tubing
The completion job required rigging up, cleaning the well, seal assembly that has been modified (Fig. 15) so that the
running CBL–VDL logs, setting the 7 x 41/2-in. production completion assembly can be replaced by this simple crossover
packer above the pay zone, and perforating. The production tool. This practice is followed to run the logs, perforate the well
test—usually a 48-hr test—was then conducted with all the and conduct well testing—all with reduced surface equipment
necessary surface facilities. Sometimes the well had to be and a coiled tubing unit. The coiled tubing unit is used to change
swabbed to start the flow, and swabbing a gas well always fluids and sometimes to clean and underbalance the well.
involves additional risk.
Completing the well with this technique usually takes 8 or 9 Conclusion
days depending on the duration of the production test. Once the The completion and drilling technique used in the An Aike field
production test is concluded, the well remains completed (Fig. works reliably in a range of rigless completions. The systems
11c) for connection to the production facilities. and tools are designed to reduce completion costs, minimize
Under these conditions, drilling and completion are formation damage and significantly lower the risks related to
expensive because of the lengthy rig time and high material cost. completions, rig operations and fishing associated with slickline
The challenge was to reduce the cost of completing these wells and swabbing. The technique also allows the placement of
while considering all the costs that would accrue during the life completion equipment in a way not previously used.
of these wells. In other words, the An Aike team had to consider Application of the technique described will provide the
not only the drilling and completion costs but also the opportunity to develop projects that cannot be economically
intervention costs over the life of the well. justified using conventional completions practices and will
After some weeks, the drilling and completions engineers significantly improve the efficiency of completion scenarios in
came up with a new casing design. In their design, the first step fields such as the An Aike.
was to reduce the completion time while taking on as little
additional risk as possible. Once the 7 x 41/2-in. liner hanger had Acknowledgments
been set and cemented, the next step was to clean the well, set To Perez Companc for permission to publish this paper.
the 7 x 41/2-in. packing assembly (Figs. 12a, 12b and 12c) and
run 41/2-in. production tubing with the drilling rig on site. These
figures show the tools used and the sequence of events needed to
perform a completion job using the monobore technique in 41/2-
in. hole. The liner used is a hydraulic tool with the same
mechanical characteristics described above.
All the completion tasks used through-tubing techniques with
the equipment already on site (Figs. 12a, 12b and 12c). This
SPE 69498 OPTIMIZING DEVELOPMENT COSTS BY APPLYING A MONOBORE WELL DESIGN 3

Fig. 1—Stratigraphic sequence of the An Aike field. Fig. 2— Initial casing string design used in the An Aike field.
4 R. GARCÍA, E. ALFARO, A. BERNARDIS, D. CASALIS, J. GALLARDO, D. DEL ZOTTO, A. ALONSO SPE 69498

Fig. 4—Comparison of rates of penetration in the An Aike field.

Fig. 3—Casing string design for a well with a reduced wellbore size.

Fig. 5—Cost breakdown of well construction in the An Aike field. Fig. 6—Drilling time in the An Aike field.
SPE 69498 OPTIMIZING DEVELOPMENT COSTS BY APPLYING A MONOBORE WELL DESIGN 5

Fig. 7—Comparison of drilling time in the An Aike field. Fig. 8— Evaluation of drilling costs in the An Aike field.

Fig. 9—Casing string design of the AA-8 well. A 7-in. casing was run to total Fig. 10—Tapered production casing string design for the AA-9 well.
depth.
6 R. GARCÍA, E. ALFARO, A. BERNARDIS, D. CASALIS, J. GALLARDO, D. DEL ZOTTO, A. ALONSO SPE 69498

5
1. Run liner with “J” and without top packer (7) 1. Run seal nipple (8) with 7 x 9 / 8-in. hydraulic packer (9) and tieback (10)
2. Hang and cement up to tieback 2. Engage seal nipple (8) in tieback; also “J” is engaged
5
3. Wash inside the tieback 3. 7 x 9 / 8-in. hydraulic packer (9) is set and 4.75-in. bore packer is tested
4. Pull out the setting tool 4. Release anchor latch

Figs. 11a and 11b—Running the original completion. Sequence of events.

SPE 69498 OPTIMIZING DEVELOPMENT COSTS BY APPLYING A MONOBORE WELL DESIGN 7

1. Run production seal nipple with latch (11) and ON-OFF with 3.81- 1. Run liner without top packer
in. profile (12) 2. Hang and cement up to tieback
2. Engage seal nipple (11) and anchor latch 3. Wash inside the tieback
3. Release ON-OFF (12) 4. Pull out the setting tool
4. Engage ON-OFF (12); assemble wellhead
5. Run CBL–VDL logs; perforate and test the well

Fig. 12a—Running the completion in a well with a reduced wellbore

Fig. 11c—Final steps of the original completion. size.
8 R. GARCÍA, E. ALFARO, A. BERNARDIS, D. CASALIS, J. GALLARDO, D. DEL ZOTTO, A. ALONSO SPE 69498

1. Run seal nipple and permanent packer with 4.75-in. bore

2. Set and test permanent packer
3. Disengage anchor latch
4. Engage anchor latch; assemble wellhead
5. Run CBL–VDL logs; perforate and test the well

Figs. 12b and 12c—Final steps for the modified completion.

SPE 69498 OPTIMIZING DEVELOPMENT COSTS BY APPLYING A MONOBORE WELL DESIGN 9

1 1
1. Run 4 / 2-in. casing, receptacle polished bore, 7 x 4 / 2-in. crossover and 7-in. casing
2. Cement; drop combined plug; displace and hang the piping

Figs. 13a and 13b—Crossover tool developed by the team of technicians of the An Aike field.
10 R. GARCÍA, E. ALFARO, A. BERNARDIS, D. CASALIS, J. GALLARDO, D. DEL ZOTTO, A. ALONSO SPE 69498

1
1. Run locator seal assembly with anchor latch and 4 2/ -in. tubing
2. Release anchor latch
3. Engage anchor latch; assemble wellhead
4. Run CBL–VDL logs; perforate and test the well.

Fig. 14—Conventional plug (above) and specially designed plug for Fig. 15—Modified anchor tubing seal assembly.
cementing operations (below).