OPERATOR/SERVICE TEAM CUTS COST OF COMPLETING MARGINAL GAS WELLS

Jan. 16, 1995
Ray N. Walker , Pat Watson Union Pacific Resources Corp. Fort Worth, Tex. Larry Buchanan , C.D. Martin Halliburton Energy Services Fort Worth, Tex. By combining optimized drilling and completion procedures with an operator/service company alliance, Union Pacific Resources Corp. (UPRC) decreased drilling/completion costs by 24%/well in its East Texas Cotton Valley gas production operations. Improved design of tubulars, cement, mud system, bits, fracturing gel, and zone isolation led to the steep

Ray N. Walker, Pat Watson
Union Pacific Resources Corp.
Fort Worth, Tex.
Larry Buchanan, C.D. Martin
Halliburton Energy Services
Fort Worth, Tex.

By combining optimized drilling and completion procedures with an operator/service company alliance, Union Pacific Resources Corp. (UPRC) decreased drilling/completion costs by 24%/well in its East Texas Cotton Valley gas production operations.

Improved design of tubulars, cement, mud system, bits, fracturing gel, and zone isolation led to the steep decline in drilling and completion costs.

These lower costs will allow UPRC to drill and complete wells at much less than 1993 costs and enable it to explore for "marginal" gas-producing reservoirs in East Texas. In the past, gas reserves easily justified well costs of $1 million/well. However, for marginal areas this cost had to be substantially reduced. Many areas considered marginal at $1 million are feasible at one-half that cost.

The exploit marginal-acreage team (EMAT) of UPRC and Halliburton Energy Services (HES) personnel was formed in March 1993 to find ways to improve the economics of completing wells in marginal areas.

DRILLING COST

By July 1994, UPRC had trimmed drilling costs alone from $453,000 to $399,000/well.

The traditional UPRC well program in East Texas included 10 3/4-in. surface pipe in a 14 3/4-in. hole to 1,500 ft, even though the Texas Railroad Commission normally required less than 700 ft.

Current UPRC practice is to install 10 3/4-in. surface casing in a 13 1/2-in. hole or 9 5/8-in. casing in a 12 1/4-in. hole to 1,000 ft.

Savings include pipe cost, cementing cost, drilling time, and installation time. Besides reducing the cement volume, the surface casing slurry was changed from a blend of cement, pozzolan, water, and bentonite to cement, 2% reactive silicate, 3% salt, and water.

For the long-string slurries, the cement was changed from Class H with silica flour to higher yielding blends of cement, pozzolan, and bentonite. Cement tests at Halliburton's area laboratory, assured that the new cement met the specifications established jointly between UPRC and HES. The result was a more economical slurry that provides adequate annular protection.

Drilling bits now are selected specifically for targeted intervals, even if total drilling time is extended. Two to three bits per well are being saved through this selection process.

Fixed cutter (PDC) bits drill from surface casing to 6,100 ft and are used in more than one well or in multiple zones of the same well. Drilling bit designs and structures are continually being improved for specific applications and zones.

Optimized drilling fluid and chemical makeup has reduced the amount of mud used. Smaller diameter well bores also contribute to reduced mud volume.

A closed-loop mud system for holding and circulating the mud, eliminates the need for a reserve pit. Another consequence is that the site size is smaller, reducing site preparation costs and damages paid to the landowner. Intangible benefits include less environmental liability and improved landowner relations.

COMPLETION STYLES

Fig. 1 (22254 bytes) illustrates the completion styles used by UPRC in East Texas gas fields.

Style 1 has dual production strings of 2 7/8-in. tubing to about 7,000 ft, and 4 1/2-in. casing to TD. Hole size is 9 7/8-in. to 7,000 ft, and a 7 7/8-in. from 7,000 ft to TD.

Style 2 has 4 1/2-in. casing installed to TD in a 7 7/8-in. hole.

Style 3 has a single string of 2 7/8-in. tubing to TD in a 2 7/8-in. hole.

Style 4 is multiple 2 7/8-in. strings or combinations of 2 7/8 in. and 2 3/8-in. strings in a 7 7/8-in. well bore. In these cases multiple zones can be produced without commingling different zones or dealing with zones with different bottom hole pressures.

FRACTURE STIMULATION

Extract From a Drill Out Job Log (38112 bytes)

To determine frac fluid efficiency (FE), on site data acquisition systems analyze data during the pre-pad stage. A typical test requires a shut down of about 15-30 min to determine an accurate leakoff coefficient, measurement of closure pressure, and fluid efficiency. A computer on location calculates net pressure, percent pad, fluid-loss needed, and required pad gel loading.

These data are also sent by cellular phone to UPRC headquarters in Fort Worth where UPRC in-house software analyzes the FE test. This enables UPRC and HES representatives in both Fort Worth and on location to comment on design changes before starting the fracture treatment. Engineers now participate in real-time decisions, thus saving costs and improving completion practices.

The gel loading of fracturing fluid has been one area of focus for reducing cost. The previous gel was a high-temperature carboxymethyl-hydroxypropylguar cross-linked with zirconium. From March 1993 to February 1994, the team concentrated on optimizing treatments with this gel system to obtain more economical gel loadings. This optimization led to decreasing fracturing costs by 10%.

In January 1994, UPRC field-tested a new guar fracturing fluid with a zirconium crosslink. UPRC has used the guar fluid in 80 Cotton Valley fracture treatments, to date, making it the preferred fluid. This fluid reduced fracturing costs by 8% cost.

ZONE ISOLATION

To isolate zones in multi-zone frac applications, UPRC recently incorporated a drillable bridge plug (DBP) made of ceramics, fiber-composites, brass, and rubber. Up to four of these DBPs have been run in a single well bore and successfully drilled out with coiled tubing and mud motors.

The UPRC/Halliburton alliance prompted the development of this quick-drilling bridge plug. These DBPs have replaced sand plugs and retrievable bridge plugs (RBP) for isolating zones and thus eliminated many problems associated with both sand plugs and RBPs.

The new DBPs were tested in an actual well bore and were brought into production almost immediately because of the identified need and willingness of UPRC to proceed with the new technology.

Zonal isolation, normally, is by sand plugs, A calculated volume of sand is pumped in a minimum amount of fluid and spotted across the lowest interval that has previously been fracture stimulated. After the sand settles out of the fluid, the sand plug will be pressure tested and tagged with a slick line to assure that the sand plug top is at the correct depth. The next interval is then perforated and stimulated.

The common problems with this type of zonal isolation are:

  • All or a portion of the sand plug may be pumped into the isolated interval during the fracture stimulation treatment of sequential interval. Usually there is no sure method to determine whether the sand plug failed or adequately isolated the zone in question during the subsequent frac, and there is no assurance that the intervals are stimulated as designed.

  • The actual sand plug top may differ from the calculated top. In this case, completion expense increases and fracturing the upper intervals is delayed. It may become necessary to re-spot the sand plug or wash out the plug with coiled tubing and reset the sand plug.

  • In some instances, the sand plug will be set and tested. If the subsequent formation is at a lower pressure, the sand plug will often move up the hole (and often cover) the lower pressured interval. This situation is time intensive and expensive to remedy. It often requires washing out with coiled tubing, reperforating, and flowing the previously fractured interval to equalize pressures.

Retrievable bridge plugs (RBP) have had little success in isolating Cotton Valley intervals. Typically an RBP is set after fracturing the first interval and before perforating and stimulating the next zone. The problem is to retrieve the RBP after the next zone is stimulated.

Cotton Valley experience shows that retrieving an RBP is either very difficult or impossible. This can add significant cost and delay.

The new, coiled tubing drillable BP is set on an electric line and has been designed to withstand the pressures encountered in the Cotton Valley. The advantages of this BP are:

  • Positive placement and pressure response with no time delay and with positive isolation of fracturing treatment.

  • No additional cost when compared to a perfect, first time sand plug.

  • Drilled in a short time with coiled tubing. The pressure control equipment on the coiled tubing unit allows for drilling out the plug without using a snubbing unit for well control.

  • Enhanced opportunities to improve and shorten the completion process.

The accompanying box extracts information from a typical fracture job log with a quick-drilling plug to isolate zones for fracturing. Note that perforations were shot over the bare bridge plug. There was no sand placed on the plug.

The bridge plugs were drilled out with a 2 7/8-in., two-stage mud motor (run by water) with 4,000 lb weight on bit furnished by the coiled tubing string. Drill out time with the coiled tubing and mud motor averaged 1 1/2 hr. Research continues on further reducing the drill out time.

The drillable bridge plugs can be set on tubing, drill pipe, or wire line.

THE ALLIANCE

UPRC and Halliburton began their alliance on Mar. 1, 1993. Halliburton furnished six full-time personnel, and UPRC furnished office facilities. Two project managers and a data base specialist are in the same offices as UPRC's engineering staff. Two field coordinators and a production enhancement specialist are in the field.

Fracturing operations are monitored at UPRC headquarters in Fort Worth by cellular phone connected to an automatic and remote control data acquisition system at the well site.

As the alliance has matured, UPRC has turned all matters of job design and execution over to the Halliburton representatives. Halliburton also coordinates logistics such as water supply and arrangements for logging services. UPRC's reliance on Halliburton for these tasks has enabled UPRC to focus its staff on other opportunities in East Texas.

Fig. 2 (8049 bytes) illustrates how UPRC has been able to accomplish much more work with fewer technical people. This would not have been possible without the support from Halliburton.

The relationship has quickened the application of new technology. Development of the drillable bridge plug was prompted by a UPRC request, and UPRC was the first operating company to apply the tool in a production well.

UPRC was the first to attempt drilling out the plug with coiled tubing and to drill out multiple plugs in the same well. UPRC was also the first to perforate over the bare (no sand covering) bridge plug, and one of the first to field test the new guar fracture fluid.

UPRC also pioneered the use of its in-house software with Halliburton's equipment to enhance remote monitoring capabilities.

Other benefits of the alliance from the UPRC perspective are:

  • Eliminate duplication of effort
  • Have engineering and technical support in-house
  • Consolidate billing and electronic data interchange
  • Have coordination of field support
  • Have technical and research support
  • Exchange technology and operational knowledge easily
  • Improve communications through better relationships.

Benefits as seen by Halliburton are:

  • Allow long-range planning because of long-term commitments
  • Obtain a better grasp of operator's needs
  • Enhance scheduling
  • Achieve better communications
  • Exchange knowledge base easier
  • Access multi-company computers
  • Access electronic mail.

THE AUTHORS

Ray N. Walker Jr. (second from left) is a staff engineer for UPRC in Forth Worth where he is responsible for development of UPRC gas reserves in East Texas. Walker has a BS in agricultural engineering from Texas A&M University.

Walker is a member of SPE and API and is chairman of the East Texas Gas Producers Association. He is a registered professional engineer in Texas.

Pat Watson (extreme left) is a drilling superintendent for UPRC in its East Texas operational area. He has held engineering positions in operations, production, and drilling. Watson has a BS in natural gas engineering from Texas A&I University and is a member of the SPE and the American Association of Drilling Engineers (AADE). He is a registered professional engineer in Texas.

Larry Buchanan (right) is a technical advisor for Halliburton Energy Services in Fort Worth and project leader of the UPRC/HES Alliance. He has held a variety of engineering and management positions within Halliburton. Buchanan has a BS in civil engineering from Texas A&M University. He is a registered professional engineer in Texas and a member of SPE and the AADE.

C.D. Martin (center) is a Halliburton Energy Services technical advisor currently assigned to the UPRC/HES Alliance in Fort Worth. He has held a variety of engineering and management positions since 1979. Martin has a BS in agricultural engineering from Texas A&M University. He is a member of SPE and AADE.

Copyright 1995 Oil & Gas Journal. All Rights Reserved.