Phillips drills entire OBM exploratory well with vacuum-cuttings system

A specially designed waste management system, which capitalizes on emerging vacuum cuttings-handling technology and a sophisticated hydraulic-monitoring program, played key roles in drilling an exploratory well offshore Norway almost entirely with oil-based mud (OBM).

Phillips Petroleum Co., Stavanger, employed this approach to managing its drilling fluids on the exploration well Ebba 2/7-31, in the North Sea's Central Graben trough on the southeast fringe of the Ekofisk complex. The company drilled the high-temperature, high-pressure (HTHP) well in 238 ft of water with the Maersk Gallant jack up at a true vertical depth (TVD) of 16,300 ft.

Bottomhole temperatures and pressures soared as high as 350° F. and 13,000 psi on this well, requiring one of the heaviest mud weights in the area at 18 ppg.

Drilling a well from below surface casing to TD with OBM is certainly not uncommon in the Norwegian North Sea. Until the Ebba 2/7-31 prospect, however, operators reserved OBM programs exclusively for development projects that include on-site injection wells. For example, the 50-well template Ekofisk II redevelopment project employed OBM out underneath the 20-in. casing shoe to TD, with the cuttings slurrified and injected on location.

On the other hand, exploratory projects usually do not have immediate access to injection wells. Therefore, to meet the environmental regulations for oil-based systems, operators must bag the cuttings for off-site disposal-a costly and risky proposition.

Typical drilling program

In a representative Central Graben exploration well, operators typically set the 133/8-in. casing shoe at 8,000 ft, covering the Tertiary formations in the upper hole section while providing a sufficient confidence level before setting a deeper 95/8-in. casing string in the Cretaceous HTHP interval.

At this point, the operator drills the 95/8-in. section to 14,000 ft, then runs casing to seal off the upper weak zones and fractures before entering the problematic Jurassic Mandal and Lower Ula sands.

On the whole, the 2,500 ft of 81/2 and optional 61/2-in. sections, located below the 97/8-in. casing shoe to TD, is where well control difficulties arise. Here, the estimated differential between pore pressure and fracture gradient poses a small operating window of 0.2 ppg, making preservation of the correct mud weight a paramount concern.

In the past, exploration wells drilled in the Central Graben used water-based drilling fluid systems up to the 133/8-in. casing shoe, usually set between 7,000 and 8,000 ft.

These water-based systems, however, had difficulty coping with the young and highly reactive clays present in the upper-hole sections of the Central Graben prospects where gumbo-related problems, including stuck pipe and severe balling, dramatically impact drilling efficiency and costs.

The emergence of highly inhibitive water-based fluids, such as KCl-glycol systems, has improved upper-hole drilling efficiency considerably. Yet even with this technology, the lengthy 171/2-in. interval and appropriate mud weights required to harness the pore pressures has forced operators to spend an inordinate amount of time drilling and reconditioning the hole.

Previously, the sections below the 133/8-in. casing shoe could be drilled with synthetic-base fluid systems. In this case, cuttings can be discharged into the sea as long as they meet strict guidelines of 8 and 12% by weight oil-on-cuttings for the 121/4 and 81/2-in. hole sections, respectively.

In the early 1980s, operators obtained permission on a handful of wells to use synthetic fluids from surface to TD, but environmental restrictions have since then limited its use entirely to the lower sections of Norwegian North Sea wells.

Another method

In the early planning stages for the Ebba 2/7-31 wildcat, Phillips elected to apply an integrated fluids engineering program to manage both drilling fluids and waste management. This approach capitalizes on a natural grouping of fluids-related products and services used to optimize the design, delivery, and management of wellsite fluids and generated wastes.^{1 2}

At the same time, the company decided to use OBM for most of the Ebba 2/7-31 wellbore with the assistance of an existing vacuum cuttings handling technology. With this site-specific, waste-management system, it became possible to address the environmental issues. In a previous well in the North Sea, vacuum cuttings-handling technology successfully managed the waste generated in an 81/2-in. hole section.

In that well, however, cuttings were collected in containers and taken ashore for incineration, an approach that was not seen as a viable option for the Ebba 2/7-31 because a much larger volume of cuttings would be generated over an appreciably shorter period of time.

At the onset, the only other alternative was to collect the cuttings in large bags and transport these off-site for injection or incineration. This option was later discounted as too messy and labor-intensive. Additionally, with the rough sea conditions that prevail during the January-February drilling period, this method posed serious environmental liabilities for the operator.

An analysis of rig capabilities and a calculation of the volume of waste to be generated prompted the decision to employ a modified vacuum cuttings-handling system. Therefore, cuttings would be collected in specially built containers and shipped to the Central Ekofisk 2/4-X platform for slurrification and re-injection.

Vacuum cuttings-handling technology, in which cuttings are directly sucked from a shaker cuttings trough to a sealed collection box or automated hopper, introduces a relatively new process. Suction from the cuttings trough is accomplished through a flexible plastic hose that allows the accompanying vacuum power skid, rig vacuum tank, and cuttings collection box to be located almost anywhere on the rig.

The system is totally contained-thereby preventing the possibility of spill-and powerful enough to handle both fluids and cuttings vertically as well as horizontally. Because of the proportionately larger volume and size of cuttings to be generated in the upper intervals of the Ebba 2/7-31, engineers specially designed new tanks with 41/2 cu m capacity and a maximum gross weight limit of 9.2 tonnes.

The tanks, each weighing 2.8 tonnes, worked off of air vacuum applied at a rate of 300 km/hr using a 4-in. hose connected to one side and an identical hose running to a collection point beneath the shakers.

As shown in Fig. 1, the entire operation was self enclosed, in turn making it impossible through direct observation to tell tank levels. Consequently, each tank was positioned on a newly designed weigh station where load cells signaled the operator as the cuttings approached the prescribed fill limit. The amount of cuttings discharged into each tank depended on the crane carrying capacity, which in turn depended upon sea conditions.

Three 100-hp vacuum units and three rig vacuum tanks were installed on the rig, together with a containment area that consisted of six "Duo-Vac" tanks and six weigh stations. A specially fabricated collection trough was mounted beneath the cantilever.

From here, the cuttings were removed by three 4-in. diameter PVC pipes (Bazookas), conveyed by vacuum-assisted air flow through a spider arrangement of hoses into the tanks.

Two independent weigh tables and tanks were earmarked for each of the three vacuum units. The independent nature of the setup provided a safety valve in case one vacuum unit became inoperative.

The operation itself proceeded in relatively simple manner. After each tank became full, a service crane would lift it off the weigh station then off load it to one of two work boats alongside the rig. Simultaneously, another tank was filled on deck, while a third empty container would be removed from the boat and placed on the now-vacant weigh station.

Once each boat was filled to its 75-container capacity (Fig. 2), it proceeded on the 1-hr trip to the Ekofisk 2/4-X platform, while its counterpart took position adjacent to the rig, repeating the process. Thus, the operation underwent no interruption while drilling. A total of 150 containers were built for the Ebba project with 20-30 located on the rig at any one time.

In addition to the drilling rig modifications, the injection platform was retrofitted with one double hopper, one dual tank, and a 100-hp vacuum unit. The Duo-Vac tanks empty by vacuum-assisted air flow through a double hopper that proceeded directly into a slurrification unit for final processing prior to injection.

The process was entirely contained, minimizing exposure of the oily cuttings to rig and platform personnel or the environment.

Drilling fluid program

For the 16-in. section alone, it was estimated that the faster drilling time using OBM saves 7 days of rig time as compared to even the most inhibitive water-based system. Additionally, the improved inhibition from OBM would promote better wellbore stability enabling the operator to replace the 171/2-in. upper section with a 16-in. hole and still use 133/8-in. casing, thereby reducing the volume of cuttings destined for disposal.

Operationally, the use of mineral oil or synthetic-based fluids in the lower sections-prone to lost circulation-presented an economic drawback. In earlier wells, maintaining improper density and rheological properties within the narrowly defined fracture and pore pressure gradients resulted in losses of up to 6,000 bbl of expensive synthetic-based muds.

Of greater consequence, however, was the threat of serious well control problems throughout those intervals. Because one-third of the well kicks occur while the bit is off bottom (OGJ, Dec. 16, 1996, p. 27),³ the risks became even more pronounced during tripping operations. In addition, invert emulsion fluids can mask well-control problems as formation gas is readily soluble in these fluid types.

Hydraulic monitoring

Careful monitoring of fluid properties from the lower 121/4-in. section to TD became crucial for the safe and cost-effective drilling of the prospect. Accordingly, the operator relied on real-time data generated from a unitized software package designed specifically for calculating pump pressures, equivalent circulating (ECD), and equivalent static (ESD) densities, as well as surge and swab pressures for oil and synthetic-based systems (OGJ, Mar. 3, 1997, p. 43).⁴

The "Virtual Hydraulics" program subdivides the well into short depth segments to account for the impact of temperature and pressure on the density and rheological properties of the invert emulsion fluids. This variable downhole rheology is combined with localized downhole conditions to generate accurate hydraulics calculations.

This characteristic permitted a unique downhole perspective of rheology and hydraulics at a single point in time, provided accurate data for maintaining well control, reduced the incidence of lost circulation, and improved overall drilling performance with fewer operational problems. The program calculates downhole pressure under static and dynamic conditions and allows for fluid property changes due to thermal and pressure conditions.

For the Ebba 2/7-31 prospect, it was agreed that once the well reached the lower 121/4-in. section, a critical well-analysis engineer would be stationed on the rig to operate the software program. Fann 70 HTHP rheological properties would be measured on shore at regular intervals or anytime the density or rheological properties were significantly altered.

These data would assist in providing accurate up-to-date behavior of the fluid in the lower 121/4, 81/2, and 61/2 -in. intervals. Data generated from the software program established tripping speeds for the drillstrings as well as casing and liners.

Waste management

The operator incorporated weather-related downtime, particularly in the 16 and 121/4-in. sections, into the acceptance criteria for the project. In those two sections, however, 84.5 hr of downtime were directly attributed to bad weather and "teething problems" associated with the new waste-management equipment and procedures.

The downtime included an unplanned trip to change out measurement-while-drilling batteries that failed because of the delays.

Fortunately, no further equipment related downtime was experienced in the 81/2 and 61/2-in. sections, nor for the remainder of the well.

The 16-in. section, beginning at 1,945 ft, drilled to 6,400 ft in 49 hr including connections. The 4,455 ft drilled at an average penetration rate of 92 fph, with penetration rates rising to 200 fph once the cuttings collection problems were rectified.

For the 16-in. section, 186 Duo-Vac tanks, each containing an average 2.9 tonnes of oily cuttings, were loaded and hauled to the platform for re-injection. That represents a total cuttings collection and disposal of 534.5 tonnes (Table 1).

The 7,565-ft, 121/4-in. section drilled at an average penetration rate of 42 fph in 179 hr from 6,400 to 13,965 ft. A total of 32 hr were lost waiting on weather when high seas prohibited either crane operation or the positioning of the supply boats alongside the rig.

At the end of the 121/4-in. section, a total of 209 containers, containing 680.6 tonnes of cuttings, had been transported at a rate of 3.2 tonnes/container.

At the end of the well, 1,606.8 tonnes of oil-based cuttings were processed along with 249.9 tonnes of oily slops, returned LCM, and other waste. Once on the platform, average processing times required 36 min to empty each tank. Times varied from 15 min for the larger upper hole cuttings to 60 min for the smaller cuttings generated from the lower sections.

Impact of hydraulics program

Fig. 3 (at right) shows the final well profile, while Fig. 4 (below right)shows corresponding mud weights. Of particular note is the very narrow pore pressure and fracture gradient observed in the lower sections of the well. As mentioned, the constricted window made accurate calculations of ECD and ESD.

The critical well-analysis engineer began calculating parameters using data from the software program in the lower part of the 121/4-in. section (11,000 ft). The eventual ECD calculations correlated very closely to those reported by the pressure-while-drilling tool.

The data generated with the hydraulics software program became even more strategic in the elevated temperatures and pressures along the 61/2-in. section because no pressure-while-drilling tool was available.

Throughout the lower 121/4, 81/2 and 61/2-in. hole sections, data obtained with the software package optimized ECD by allowing the fluid engineer to reduce rheological properties without affecting penetration rates. Yield point and low-end readings were reduced below the programmed specifications with no negative effect on hole cleaning.

The program was particularly beneficial in the 81/2 and 61/2-in. hole sections where temperature had a dominant effect on downhole pressure. Early in the 81/2-in. section, the weight in the suction pits dropped while pumping and increased while tripping. Fig. 5 shows a representative output, showing the relationship of mud density to downhole temperature.

Data produced from the software determined the precise pressures required; thereby maintaining a constant weight and avoiding pitfalls that could arise by over-reacting and improperly treating the mud when weight variances were observed at the surface.

The output, updated every 100-200 ft, enabled the derrickman to maintain the proper mud weight in the pits according to the downhole temperature.

On this well, the static hole volume changes vs. time were quite small, with temperature increases in the lower sections balanced with the temperature decreases in the upper hole.

By considering surge-and-swab densities when the bit was off-bottom, the software program allowed the operator to reduce tripping time considerably. In the past, a great deal of time was spent pumping during trips. Fortunately, output from the hydraulics program provided for a maximum sustainable speed without compromising well control.

The trip speed was calculated against depth within the stipulated ECDs and ESDs at the shoe or current TD. The optimized trip speed contributed to a reduction in rig time, estimated to be as much as 5-6 days total through the critical stages of the well.

Despite the extremely narrow gradient, the well reached TD without a single well-control incident. Mud losses did occur, however, such as 500 bbl lost from a kick further up the 121/4-in. section.

Cost breakdown

Based on a $185,000/day rig rate, the 4 days drilling time saved in the upper hole with OBM resulted in a gross cost reduction of $740,000. The savings become even more impressive when total mud costs are considered. By using OBM as opposed to using a water-based system in the uphole sections, followed by the more expensive synthetic-based fluid system, the operator saved $560,000 in direct mud costs.

The reduced rig time easily compensated for the cost incurred during the short period of utilizing a second workboat on location. Even with those costs and the weather-related downtime, the operation resulted in net savings of $169,000 in rig and fluid-related costs. Table 2 shows the net cost saving on Ebba 2/7-31.

Acknowledgments

The authors wish to thank the management of Phillips Petroleum Co., Norway, Maersk Drilling Norge, and M-I LLC for permission to publish this article. Additional thanks are extended to Kelly Talkington, Thore Bergsaker, Dag Gullesen, and Åsbjørn Dysvik for their contributions.

References

1. Hudson, C., and Pruett, J., "Integrated Approach Optimizes Results," American Oil & Gas Reporter, August 1998.
2. Nicholson, S., and Hudson, C., "Integrated Fluids Approach Cuts Waste, Costs in Texas Wildlife Refuge," Petroleum Engineer International, March 1999.
3. Wilson, J.A., "The Role of Human Factors in Initation and Control of Kicks on the UKCS," International Association of Drilling Contractors Well Control Conference for Europe, Milan, June 7-9, 1995.
4. Wood, T., and Billon, B., "SBM Drilling Fluid System Sets Deepwater GOM Record," World Oil, October 1997.

The Authors