SPECIAL REPORT: OCTG

Drilling / completing with tubing cuts well costs by 30%

Here's how and why Pemex redesigned its Northern Mexico gas well drilling program to drill-in with, and cement, 3-1/2-in. tubing as the final production string, including design criteria, advantages, limitations

José C. de León Mojarro and Martin Terrazas, Pemex Exploration & Production, Northern Region; and Abraham Julián Eljure, Hydril Co.

onventional industry practice for drilling gas wells dictates the use of drill pipe only. However, as described here, Pemex Exploration & Production (PEP) has demonstrated success with a new technique for drilling-in the last section with tubing, and completing the well with that final drillstring functioning as both production casing and tubing, i.e., a "slimhole, tubingless" technique. A key technology in the success of this new drilling / completion method is use of upset tubing employing Hydril's proprietary Wedge Thread technology.

In PEP's North Region producing areas of the Burgos basin, Reynosa and Tamaulipas, the operator has successfully drilled more than 40 wells with the new technique. Estimated per-well savings have averaged 30 to 40%. The background of the Pemex study leading up to the new design is presented here. Conventional and new techniques are compared, and details of the designs are featured in tables and figures.

Introduction

The operator's objective was to reduce material and service costs incurred in all activities needed to drill gas wells in Northern Mexico to increase the profit yield of the Burgos basin. According to economic research, these drilling activities required 80% of the total investment; the other 20% involved production facilities, exploration studies and environmental protection services.

For this economic analysis, total drilling cost included materials, services, indirect costs and rig costs. Of this, materials / services costs were 75% of total drilling cost, and were directly associated with: well design (casing / tubing design, drilling fluids, bits, hydraulic system, rig capacity, etc.); drill pipe strings; cementing; and well completion.

State-of-the-art technology was needed to achieve the cost reduction goal; therefore, it was determined that well geometry had to be reduced, and also, a tubingless completion technique had to be used. Consequently, other important reductions would be attained, including: amount of steel, cement / drilling fluid volumes, and cementing / drilling fluids / completion services.

The slimhole design was used as a first step to optimize well geometry, i.e., to reduce hole and casing diameters. Second, it was necessary to apply the tubingless technique — which has been used since the last decade by other South Texas operators — to produce gas in similar fields in Burgos basin. With this technique, the tubing works as a production casing and packerless tubing. In this technique, the tubing is cemented up to the last casing shoe, and perforated to produce the reservoir fluid to surface.

Finally, looking to reduce cost of the well's last section even more, the challenge was to find a tubing with an adequate connection that could: 1) drill this step, 2) be used to complete the gas well with the tubingless technique, and 3) guarantee reliability in higher pressure gas wells that require metal sealing combined with good structural capability. After several string analyses, it was determined that a 3-1/2-in. tubing with a Hydril Type 533 Wedge Thread connection and metal seal on internal-external upset pipe, as described later, could perform to load requirements for torsion, tension, compression, bending and buckling.

Conventional Well Design

The conventional drilling program, see Table 1, used tricone bits of 17-1/2-, 12-1/4- and 8-1/2-in. dia. for casing diameters of 13-3/8, 9-5/8 and 7 in., respectively. The final completion was typically 2-7/8-in. tubing with a permanent packer on top of the production zone, Fig. 1. This well design took about 37 to 40 days, considering drilling and completion.

This conventional well design required a 4-1/2-in. drill pipe for drilling the three sections due to the capacity of this pipe (torsion, tension and hydraulics geometry). Table 2 shows typical drill pipe string design to achieve this program.

The first section was drilled with a 1.2-g/cc-density water-based mud. For the second and third sections, the drilling fluid was 1.3- and 1.8-g/cc-density oil-based mud, respectively.

New Well Design

The slimhole design was used as a first step to reduce well geometry, i.e., reduce hole and casing diameters. This program required 12-1/4-in. tricone, and 8-1/2- and 5-7/8-in., PDC polycrystalline diamond bits for 9-5/8-, 7- and 3-1/2-in. casing diameters, respectively, Fig. 1.

For surface and intermediate casing, the same criteria applied as for the conventional well design. But for the tubing, the design must consider that the string would perform several functions: as a production casing, as a tubing to carry produced fluid to surface, and to resist stresses generated by hydraulic fracturing, see Table 3 — this technique is called "tubingless."

To achieve this program, there were two choices: 1) drill the three sections with drill pipe only, or 2) drill the first two sections with drill pipe and the third section with tubing. These two options are further described below:

1. To drill the three sections with only drill pipe required 4-1/2-in. drill pipe to drill the first two sections and 3-1/2-in. drill pipe to drill the third section, as shown in Table 4.
2. To drill the first two sections with drill pipe and the third section with tubing required 4-1/2-in. drill pipe for the first two sections and 3-1/2-in. tubing with a strong connection to drill the third section, as shown in Table 5.

From Tables 4 and 5, it is clear that the considered tubing connection had only a 50% torsion efficiency, compared with the standard 3-1/2-in. IF (internal flush) normally used for drilling this section. Even though this was the big challenge, the decision was made to proceed considering that, in the Burgos basin area, sands are soft to medium formations, and thus capability of the Type 533 Wedge Thread connection would be enough to drill the complete third section. Fig. 2 illustrates the connection's principal features.

In the beginning, this well design took around 26 to 29 days, considering drilling and completion. Today, average drilling / completion time has been reduced to 20 days or less, once the learning curve is established.

Drilling With Tubing

Presently, PEP is using the above described tubing under the following conditions:

• Applying 4 to 6-mt weight on a 5-7/8-in. bit
• Using nine joints of 4-3/4-in. by 2-in. drill collars
• Using 12 joints of 3-1/2-in. heavy weight pipe
• Stabilizers on bit and 1st, 3rd and 9th drill collars
• Drilling 1,200 to 1,500 m (3,900 to 4,900 ft) average lengths of the third section
• Rotary rate = 130 to 150 rpm
• Pump rate, avg. = 250 gpm
• Pump pressure, avg. = 2,900 psi
• Mud weight = 1.75 to 1.8 g/cc
• Type of mud = Oil base
• Rotary time to drill the third section = 50 to 75 hr
• Three normal trips to drill section without coring
• Six to nine trips when taking cores.

Tubingless Completion

This technique uses the tubing as production casing and also as tubing without a packer. The tubing has to be cemented up to the last casing shoe and perforated.

First, to design the tubing string, triaxial analysis was used to choose the proper pipe. Fig. 3 shows the 3-1/2-in., 9.3-lb/ft N-80 tubing with selected connection and performance with this connection considering the Von Mises curve. The connection resists 100% pipe body ratings for tension, compression and bending; and the 100%-rated metal to metal seal maintains gas sealing capability for collapse and internal pressure under high axial and bending loads.

Running considerations. For the 3-1/2-in. tubing, it is required to make-up every single connection to 3,200 ft-lb and hydraulically test with 9,000 psi to guarantee full string integrity to avoid any leakage during cementing, fracturing and production life.

Cementing considerations. For the third section, using the tubingless technique, cementing operations are critical, and primary cementing must be successful. Therefore, it is highly recommended to put special emphasis on: 1) mud conditions (density / viscosity) before cementing; 2) mixing the slurry (density / viscosity); 3) type of slurry, which has to be an anti-gas-migration cement; 4) displacement technique; and 5) tubing rotation with 15 to 20 rpm during cementing. Also to avoid cleaning the well with coiled tubing, using a clean fluid (brine) for completion and cement displacement was recommended.

During production, the tubing is subjected to increasing temperatures, which will consequently cause length increase and compressive stresses that affect stability of the non-cemented portion of the tubing (upper part). This could cause buckling that would obstruct running / retrieving of wireline tools, plus joint failure due to pipe compression. To avoid this buckling, it is necessary to apply an additional tension load to the pipe's buoyant weight at the end of the cement job, and also, maintain final pressure until cement thickening time is reached.

Fracturing considerations. The tubing is subjected to internal pressure loads during hydraulic fracturing, as well as tension stresses over its buoyant weight, which must be evaluated to choose the adequate connection to resist these additional loads. Therefore, using flush joints in plain-end pipe is not recommended, since they would considerably reduce the tubing's tension capacity.

Conventional / Tubingless Comparison

The slimhole and tubingless well design has been used in gas-compacted sands, low-permeability formations, where drilling cost must be low so that field development is profitable. However, the following considerations were still taken into account.

Primary applications are:

• In low risk fields when the area is sufficiently known
• In areas where corrosion / scaling are not critical, and
• Where primary cement jobs have high success rates.

The new well design offers these advantages:

• Drilling mud, completion fluids and cement slurry reductions
• Less steel needed
• Lower bit cost
• Volume reduction of sand as sand plugs for multiple hydraulic fracs
• Faster / more efficient cleaning after fracing
• Elimination of packer and wireline equipment to set packer
• Less drilling / completion time, and
• Elimination of additional drill pipe for third section.

Some disadvantages include:

• Primary cementing requires strict quality control
• Application restricted to 3,200-m (10,500-ft) depths
• More complicated major workover due to reduced diameters
• Resistance to change for new challenges
• Requires good quality team, material and services, and
• The 3-1/2-in. string must be handled for running / drilling with tubing procedures, not standard drill pipe procedures.

Summary / Conclusions

Main achievements and conclusions of this new well design are noted here.

First, using the new well design for drilling / completion, time has been reduced by 50% per well in Arcabuz and Culebras fields, compared with conventional design. New wells cost 30% less than the conventional wells.

Analyzing materials and services, the new well design offers these savings: drilling fluids, 42%; casing and tubing, 31%; rig time, 32%; cementing, 12%; bits, 16%; and wellheads, 13%.

The successful experience, using the slimhole / tubingless design in Arcabuz and Culebras has spread to other development fields, e.g., Cuitlahuac, Corindon and Pandura in Burgos basin, with the same program, since this represents a profitable option. To guarantee success of this well design in other fields, it is necessary to individually analyze the risk and current information to evaluate the project.

Finally, it is emphasized that, in using only tubing procedures to handle, run and drill with this pipe, be careful not to handle the tubing with standard drill pipe procedures, because it could damage the pipes and connections.

Acknowledgment

The authors are grateful to Pemex Exploration and Production, Northern Region and Hydril Co. for support, and permission to publish this paper. This article was first published by the authors as paper SPE 40051, "Breaking a paradigm: Drilling with tubing gas wells," and presented at the 1998 International Petroleum Conference and Exhibition, Villahermosa, Mexico, March 3 – 5, 1998.

References

Greenip, J. F., "Determining stress in tubing using triaxial evaluation," paper SPE 6760, presented at the 1977 SPE Annual Fall Technical Conference and Exhibition, Denver, Colorado, Oct. 9 – 12, 1977.

Greenip, J. F., "Designing and running pipe," five-part series in Oil and Gas Journal, Oct. 9, 1978 – Nov. 27, 1978.

Hills, J. O., "A review of casing-string design principles and practices," Drilling and production practice, API, 1951, p. 91.

Scott, W. and J. Earl "Small diameter well completion," Part 1 and 2, World Oil, August 1961, p. 57 and September 1961, p. 79.

Shook, A. and B. Brunsman, "Slim hole technology evolution targets cost reductions," Petroleum Engineer International, September 1994, p. 39.

Silva, M., J. M. Bujanos Sanchez and J. G. Leon Loya, "Optimizacion del diseno de pozos en la cuenca de Burgos," presented at the 1997 AIPM Annual Conference and Exhibition, Zacatecas, April 16 – 20, 1997.

The authors

José C. de León Mojarro, drilling manager for the Northern Region, Pemex Exploration and Production, received a BS in petroleum engineering from the University of Mexico (UNAM) in 1973 and an MS in drilling, completion and workover in 1986. He has served in a variety of positions in engineering, operations and management since joining Pemex in 1973. A current major project is to increase gas production in Burgos basin in Reynosa, Tamaulipas. Mr. Mojarro is a member of SPE, CIPM and AIPM.

Martin Terrazas, deputy manager for engineering in the Northern Region, Pemex Exploration and Production, earned a BS in pertroleum engineering from the University of Mexico (UNAM), and continued his MS in drilling, completion and workover in 1986. Since the beginning of his professional career, he has been interested in new technologies for oil / gas wells, to optimize performance of Mexican reservoirs and reduce well costs. Mr. Terrazas is a member of SPE, CIPM and AIPM.

Abraham Julián Eljure, director of sales and marketing for Hydril Co. in Mexico and Central America, received the BS in petroleum engineering from the University of Mexico (UNAM) in 1986, and is presently working on an MBA degree. He started in the petroleum industry working as a field engineer with Halliburton in 1987, and has been with Hydril since 1990. He is responsible for marketing strategies which optimize casing, tubing and drill pipe string designs. Mr. Eljure is a member of SPE and AIPM.

Copyright © 1999 World Oil
Copyright © 1999 Gulf Publishing Company