Technology Project management improved multiwell shallow gas development

D. Lane Becker
Husky Oil Operations Ltd.
Calgary

Based on a presentation to the Canadian Association of Drilling Engineers/Canadian Association of Oilwell Drilling Contractors spring meeting, Calgary, Apr. 19-21.

Because of time and economic constraints, a multiwell shallow gas develoment project in southeastern Alberta required thorough prejob planning and special drilling, cementing, and completions designs.

The project took place during a period of peak industry activity, putting extra challenges on logistics and services.

The Medicine Hat shallow gas project, undertaken by Husky Oil Operations Ltd. in mid-1994, was a high-volume, short time frame, and economically tight project involving 41 wells from 12 pad locations.

The average true vertical depth of the wells was 850 m, with measured depths of the directional wells as much as 1,175 m (3,900 ft). The wells were drilled with flocculated water, perforated with an average gun length of 7.5 m (25 ft), stimulated with a 30-40 ton (20/40 mesh sand) nitrogen-assisted water fracture treatment, and cleaned out with endless tubing supported with air.

The project was completed in less than 7 months and is currently producing an average of about 275,000 cu m/day (9.7 MMcfd).

Over the past 10 years there has been extensive shallow gas development in southeastern Alberta. The potential to develop further the Medicine Hat reservoir in the Hussar field was recognized by Husky in 1993, and the decision to proceed with the Medicine Hat shallow gas project was made in the following year.

The Husky Hussar production field is located about 80 km east of Calgary near the village of Hussar, Alta. (Fig. 1)(57578 bytes).

Standard drilling and completion methods were not feasible, given the economic and time constraints. Drilling, cementing, and completion methods were, therefore, designed to meet the primary objective of completing the project cost effectively and within the time available. One individual coordinated both drilling and completions to bring continuity and cohesiveness to the project.

Reservoir description

The Medicine Hat formation is the primary gas reservoir in the Hussar field. It lies in the Upper Colorado group and is of Upper Cretaceous age. The average anticipated net pay thickness was 2 m with a reservoir temperature of 17 C. and pressure between 1,800 and 3,020 kPa.

Fig. 2 (148623 bytes) shows the reservoir formations with the drilling prognosis and potential problems.

Drilling

Thirty directional (not exceeding 50 deviation) and 11 vertical wells were drilled from 12 pads (3 or 4 wells per pad). The primary advantages realized from drilling directionally from the pads were reduced tie-in and facility costs and minimized environmental impact. Six of the 12 pads were constructed on existing well locations and only required enlarging.

The prespud and precompletion meetings included the project team, all contractors, and service companies to make the people working on the project familiar with the project objectives, the operations program, economics responsibilities, areas of potential optimization, and coordinating and invoicing procedures.

Based on depth, hole size, and directional requirements, a light double rig rated for 1,500 m and with a high pump capacity was acquired. Two drilling rig contractors were used and work began Oct. 7-8, 1994, on wells 11-5 and 7-7.

Slant-type rigs were not available.

On average, drilling time of vertical and directional wells was 1.5-2.5 days. The 41 wells were drilled starting with the out-lying locations and working towards the area core, where most pads were located. Crop land was drilled as soon as possible so that restoration could be completed quickly.

The average rate of penetration (ROP) was 35 m/hr and the most successful tooth bits were IADC (International Association of Drilling Contractors) type 116, which were able to drill a complete hole; button bits were unsuccessful. Annular velocities for circulating ranged between 50 and 54 m/min (Table 1)(27760 bytes). A Class 1a blowout preventer (diverter) was used in conjunction with a flare tank.

Because there were no local sloughs, creeks, or lakes, water was purchased from landowners. All water for cementing was tested and purchased from a water well near Standard, Alta., because that water was low in chlorides. When a shortage was encountered before fracturing, a good quality water supply was obtained from Strathmore, Alta.

Directional

Project team members met to discuss well bore terminal angles, well bore displacement, restriction relative to hole sizes, and preferred completion techniques. An initial well profile was created, which optimized build rates at 4/30 m of total vertical depth (TVD), to be monitored by single-shot instrumentation.

The primary goal was to intersect the formation within a 25-m radius of the target. Well deviation did not exceed 50 so wells could be perforated with electric line.

Surveys were shot after every two kelly lengths were drilled down until the angle was established, then reduced to every 30 or 40 m. The design also considered potential TVD discrepancies resulting from systematic errors, common in highly deviated, largely displaced wells. Elastic survey calculations and ellipse of uncertainty (cone of error) studies show it is not uncommon for survey results to be out by 0.25-0.50.

The highly displaced well bores (10-5 and 11-7, with displacements of 355 m and 535 m, respectively) were gyroscopically surveyed to verify single-shot readings. Results indicated that a correction of +0.5 was required. A survey subsequently conducted on a third well (6-23) indicated that the +0.5 correction showed improved correlation.

BHA

The following bottom hole assembly (BHA) was recommended for vertical wells: 200-mm (778-in.) bit, bit sub, 159-mm shock sub (if required), six 159-mm drill collars, combination bumper sub, jars, twelve 159-mm drill collars, and a crossover sub to the drill pipe.

The following BHA was recommended for directional wells: 200-mm bit, positive displacement motor (1 setting), 159-mm 0 orienting sub, three 159-mm Monel collars, 159-mm jar, a crossover sub, and 114.3-mm or 101.5-mm heavy weight drill pipe.

Casing

Hole and casing size of the conductor pipe were 406 mm and 219 mm, respectively, to a depth of 20 m. The production hole and casing string were 200 mm and 114 mm, respectively, to a maximum anticipated measured depth of 1,150 m. A casing weight of 17.26 kg/m was used (burst = 36.8 MPa) based on offset fracture breakdown pressures.

A float shoe/float collar combination was used. Centralization was designed to achieve quality standoff from total depth (TD) to 50 m above pay to ensure integrity for the fracture treatments, and from 300 m to surface to ensure integrity between and throughout potable aquifers.

One standoff band per joint was installed from TD to 10 m above pay, and one bow spring centralizer per joint was installed from 300 m to surface. One standoff band was used every three joints for the remaining string length. The TD was increased to allow for two additional joints (24 m) below the anticipated pay depth.

Handling and trucking costs were reduced by stocking the large quantity of casing (40,000 m), as well as other accessories, at a main storage yard in southeast Calgary.

The rat-hole drilling contractor drilled 406-mm holes 20-m deep, and 219-mm industrial grade conductor pipe, supplied by the contractor, was cemented into place. This pipe gave a substantial cost saving compared to API (American Petroleum Institute) casing, when cutting off the collars, transporting, and handling the casing were considered.

Although the Alberta Energy Utilities Board (AEUB) waived the requirement of pressure cementing if water, gravel, or boulders were not encountered, shallow water flows were encountered above 20 m in about 60% of the holes.

Once conductor pipe was in place on four of the pads, drilling commenced.

Drilling fluid

Husky and the drilling fluids contractor agreed on the following objectives:

• Employ the most economical methods available.

• Minimize volumes, reduce disposal costs, and be familiar with disposal limits.

• Be aware of potential problems on high-angle wells.

• Whenever possible, drill wells with clean water; mud up only when necessary.

• Use a mud company representative on the first two wells to train the rig crews about operating efficiently.

• Maintain good communication.

The directional and vertical wells were drilled with flocculated water to TD. Gypsum was added to reduce ion buildup, keeping cleanup costs low. Alcomer viscosity sweeps were used for hole cleaning, as required.

An XCD polymer was made available if hole problems were encountered on highly deviated wells. One fully equipped mud van for each drilling rig was located on the pad lease. Viscosity sweeps were circulated every 200-250 m, and it was not necessary to mud up with XCD polymer.

A conventional tank system, with an effective circulating volume of 180-200 cu m, was used and set up as a sequential cascading system. A Lykal cone bottom tank, in conjunction with a settling tank and rig suction tanks, was found to be inefficient (circulating volume was between 120 and 150 cu m), resulting in unnecessary loads of "dirty" water being taken to the sump.

A remote sump was used to improve the efficiency of fluid handling and lease restoration when compared to local sumps. To offset the possibility of contamination, a pit for excess cement was prepared on unusable land at the 6-6 location.

Cement

Quality and economics were the most important considerations in the cementing design. Available information indicated that gas migration and other concerns were not at issue.

Thus a 1:1:2 Class G for lead cement was used with a tail-in of quick setting, low-temperature thixotropic BV (Halliburton Energy Services) cement, to about 50 m above the proposed pay interval. It was expected that thixotropic BV would provide better behind-pipe integrity for the fracture treatments. This cement is more predictable than previous thixotropic blends, more reasonable in costs compared to filler cement, and has good compressive strength.

Because the Medicine Hat formation presents a potential for swelling clays, the cement was displaced with freshwater mixed with a clay stabilizer rather than KCl; KCl is not environmentally friendly and results in costly disposal. Treated water in the well bore saves the cost of circulating the fluid via endless tubing prior to perforating and fracture.

Cement returns were encountered on all wells but slumped about 5-10 m subsequent to pumping. All the wells were top filled to the surface with premix cement.

Completions

Completions involved four main areas: wellheads, perforating, fracturing, and cleanouts.

Wellheads

Initially, tree savers were installed based on offset well fracture breakdown pressures. Some difficulty was incurred when installing the tree savers, as a number of the production valves had been overtorqued upon installation. Based on the observed treating pressures and cleanup times of the first two wells, rental wellheads (21 MPa rated) were substituted for the remainder of the frac jobs

Perforating

All the wells were perforated via wire line with an 86-mm Erhsc loaded with 22 g/charge at 90 phasing using a mast unit. The wells were perforated overbalanced to save the cost of swabbing the well bores down and because high differential pressures were not obtainable.

Following AEUB requirements, full-length, cased hole gamma ray-neutron-casing collar locator (GR-N-CCL) logs were obtained (Fig. 3)(91010 bytes) . These logs were run close to the completion of the drilling program to save time; a logging consultant was hired to advise on the perforating intervals. Rather than using different gun lengths on each well, cost and time were reduced by using an average perforation interval of 7.5 m on all wells.

Fracturing

With costs, possible materials shortages, and environmental considerations in mind, the fracturing design consisted of a 30-ton borate gel system with a low-temperature encapsulated breaker assisted with nitrogen.

The specific properties of the fracturing fluid system included the following:

• Energy assist, to reduce cleanup time

• Low residue, to maintain as much fracture conductivity as possible

• High viscosity, because experience in this region showed that cross-linked gel systems perform much better than linear systems

• Environmentally sound, because some of the return fluid may contact the ground during flow back

• Attractive break profile (

• Economical to use.

All the tanks and fracture equipment were rigged up central to the wells. Two tree savers were on location so that the fracture treatments could be done without waiting on cleanup bleed down.

The pressure was bled to below 7 MPa after frac. Fracturing treatments began on the 12-5 well on Dec. 2, 1994. A goal of one pad (four wells) per day was established. After a few treatments, sand densities were increased, and the overall tonnage was increased to 40 tons (Fig. 4)(55426).

The objective of the latter was to achieve a tighter sand pack and increase the nitrogen volume to lessen the cleanup duration. Out of the 40 fracture treatments performed, there were only three sand-offsone was regained and two had 14-16 tons in the formation prior to pressuring up.

Cleanup

The nature of the cleanup was dependent on the nitrogen and on how the wells came back on flow. The initial cleanup was very foamy and remained so until the well died after about 10 hr.

After the breaker concentration was increased, cleanup was more efficient, with little foam or sand. Nevertheless, the wells continued to die and required an endless tubing clean out. After circulating out about 1 cu m of sand, the wells flowed freely.

Recommendations

The Medicine Hat shallow gas project was successfully completed, meeting all project objectives, in less than 7 months. The wells currently produce between 225,000 and 320,000 cu m/day. The Medicine Hat shallow gas project provides a good model for similar projects. In particular, the following recommendation are made:

Project development

• Plan the project thoroughly before startup because of project size, restrictive economics, and timing.

• Assign an assistant to the coordinator to help with paperwork.

• Conduct prespud and precompletion meetings. Inform contractors and service companies that they are to provide cost control, submitting an invoice for each pad, and that they are to provide end-of-project reports and recommendations.

• Use project drilling and completion spreadsheets to track costs and time spent, but also to coordinate the project and measure successes and failures.

• Conduct weekly project team meetings (they allow business unit updates and are valuable for reviewing project objectives and operations).

• Visit the prospective project area well before licensing to become familiar with the land, andowners, nearby towns, service locations, water supply, and other facilities. Potential local impacts of the project, such as on water wells, should also be assessed to prevent liability.

• Take into account the industry activity level in planning for services.

  Lease acquisition

• Avoid delays in acquiring leases by identifying well sites as soon as possible and signing with landowners agreements that identify compensation for land value, number of wells per pad, incidental disturbances, possible adverse effects, and loss of use. The number of acres taken out of production can only be resolved when the well sites have been surveyed.

• Allow extra time to check a large number of surveys for accuracy, to plan the order in which the wells are drilled (taking into account surface and bottom hole target locations), and to obtain well licenses where external approvals are required (if, for example, pipelines and coal reserves are involved).

• Use existing lease sites where possible, because reclamation costs can be reduced.

• Choose flat drill sites close to existing access roads to minimize construction and reclamation costs. Begin construction in the late summer or early fall to minimize cost of stripping and storing topsoil; removal of subsoil also depends on the flatness of the site.

• Begin drilling after freeze-up and prior to breakup to minimize damage to the access road and the site itself. Drilling waste can be disposed of without surface damage, and topsoil need only be removed (on a flat site) under the rig.

• Use the land spread while drilling technique for sump disposal with a backup remote sump available if this technique cannot be accomplished.

• Bury cement returns in a separate pit on the well site, 1 m below subsoil depth or alternatively in an approved landfill.

Drilling

• Be sure that the drilling rig has a skidding capacity and an experienced crew.

• Review and compare the advantages and disadvantages of slant hole and conventional directional drilling.

• Consider local contractors because they are experienced in the region and moving costs can be minimized.

• Do a cost comparison for drilling the conductor holes with a rat hole drilling rig or a water well drilling unit.

• Use construction-grade conductor pipe.

• Do cost estimates based on pressure cementing all of the conductor pipe.

• Review directional proposals and final surveys to determine whether survey frequency can be reduced.

• Do gyroscopic surveys as required to ensure directional accuracy.

• Use J-55, 14.1 kg/m casing. (The fracture breakdown pressure was below the 32.2-MPa burst rating.)

• Use proven drill bit technology while being aware of new, improved alternatives. Do not use retip drilling bits.

• Use a central location for stocking casing and accessories to reduce handling costs.

• Use 114.3-mm drill pipe to obtain better hole cleaning (higher annular velocities) and directional control.

• Use the fluid system described and continue with Alcomer sweeps. Use a mud engineer to train the rig crews on the first few holes and to do periodic checks of the work.

• Use the conventional tank system to obtain the most effective retention time.

• Use lead and tail cement blends as described. Use a clay stabilizer (not KCl) to prevent clay swelling during fracture stimulation.

Completions

• Use existing wellhead system consisting of a production valve and bell nipple.

• Contract a logging consultant to determine perforation intervals and supervise perforation.

• Use a standard gun length.

• Attempt to obtain a waiver to the requirement of full length logging of the production casing.

• Consider using 12/20 or 16/30 mesh frac sand to obtain a tighter frac with higher conductivity and to reduce sand flow back problems.

• Pump large sand volumes at high concentrations.

• Maintain fast break of frac fluid and consider increasing nitrogen content.

• Monitor production declines of wells to optimize fracture designs.

• Obtain AEUB approval to spread frac fluid on location or into the sump, followed by land spread, to save disposal costs.

Acknowledgment

The author thanks Husky Oil Operations Ltd. for the opportunity to publish this article and acknowledges the contributions of the project team, consultants, contractors, and our service companies for the success of the Medicine Hat shallow gas project. The author also thanks Brent Tufford, Ian Simister, and Ron Dusterhoft for their assistance in the preparation of this article.

The Author