Based on Kamal, B., Saboor, A., MacFarlane, G., Kernche, F., “Significant Performance Improvement with MPD in HPHT Narrow Drilling Window Campaign in the North Sea,” OTC-31217-MS, Offshore Technology Conference, Houston, Aug. 16-19, 2021.
A series of North Sea high-pressure high-temperature (HPHT) wells were conventionally undrillable due to narrow mud-weight windows (NMWW) and high losses while entering the reservoir. Managed-pressure drilling (MPD) with constant bottom-hole pressure (CBHP) monitoring drilled three wells with statically underbalanced mud weights while dynamically managing pressure above formation pore pressure (PP). MPD maintained equivalent circulation density (ECD) between pore and fracture pressure windows.
Rig-up and commissioning was above specified MPD time for the first well but declined 44% to within specs in the third well. All wells reached TD without well-control incidents.
Drilling campaign
The field is a large HPHT development in the UK sector of the Central North Sea in 92 m of water. The reservoir contains Jurassic sand 5,300 m below sea level with 16,000 psi initial reservoir pressure and 200° C. reservoir temperature. The field was initially developed with five wells which heavily depleted the reservoir by the early 2000s. A 2006 infill well program stalled due to drilling difficulties and total losses in the target Chalk Group.
A drilling campaign using MPD started in 2017 and has completed three wells to date. MPD was chosen because it improves safety by diverting and isolating well returns from the drill floor. It has instant control of bottom-hole pressure and provides real-time formation pressure and fracture pressure evaluation through long connection tests, dynamic pore pressure tests (DPPT), and dynamic fracture integrity tests (DFIT). Minimum overbalance on the well reduced losses and CBHP-control balanced cap rock pore pressure regardless of pump pressure.
Drilling was based on most likely (ML) and commitment case (CC) pore and fracture initiation pressure (FIP) profiles (Fig 1). The system drilled the 12 ½-in., 8 ½-in. HPHT sections and the 5 5/8-in. NMWW section.
The Chalk Group was the key problem in the 12 ½-in. section. NMWW through this group meant that mud weight close to balance was required while tripping out of hole. Two significant faults were identified by seismic, and wells had consistent gas influx through this section.
The 8 ½-in. section had to be drilled without penetrating the reservoir. TD of the 8 ½-in. section was carefully chosen to drill though the caprock with 7-in. drill-in liner. Mud weight could then be reduced for reservoir drilling.
Minimum fracture pressure in the 5 5/8-in. reservoir section was in the 1.10-1.30 specific gravity (sg) equivalent mud weight (EMW) range, and risk of losses was high. Overburden stress in weak zones can activate fractures and faults leading to unpredictable fluid loss or influx. Previous attempts to conventionally control (without MPD) this uncertain pore pressure-fracture window with mud weight resulted in well control issues, differential sticking, and total losses.
MPD planning accounts for these risks with hydraulic simulations based on mud weight to select optimum EMW (Fig. 2). A well-control matrix (WCM) specified guidelines between conventional and MPD well control to operate the system safely without breaching surface or subsurface pressure containment barriers. The WCM initially handled 3 bbl influx though the MPD system, but the limit increased to 5 bbl with continuous improvements.
MPD operations
Well B MPD rig-up and pressure test were completed in 368 hr, which was longer than specified MPD time. Subsequent Wells C and D took advantage of improvements in the system and lessons learned to reduce rig-up time. The rig crew fabricated tie-in points for the MPD lines, flowline, and mud gas separator (MGS). With these improvements, commissioning was reduced to about 200 hr.
Normal flow path for MPD is a closed system in which the rig pumps fluid down the string and takes returns from the annulus through the MPD choke manifold via a rotating choke device (RCD). During normal operations returns go to the flowline but will divert to the MGS in case of influx of gas.
CBHP variant of MPD in Well B and Well C kept mud weight statically underbalanced but dynamically overbalanced. In Well D, bottom hole ECD was kept below pore pressure and bottom hole pressure was continuously monitored in real time. DPPT and DFIT tests defined the drilling window which was key to safely reducing MW in this well. MPD DFIT advantages over conventional formation integrity tests are speed, real-time monitoring of BHP via pressure while drilling (PWD) tools, eliminating mud conditioning, and improving accuracy from stable temperatures.
12 ½-in. section
Fig. 3 shows drilling curves for the 12 ½-in. section. The 12 ½-in. section on Well B was drilled with 1.88 sg statically underbalanced mud. DPPT and DFITs were performed while drilling and ECD was maintained 0.04-0.05 sg above pore pressure. MW increased to 1.94 where pore-pressure ramp was expected and maximum ECD was limited to 2.05 sg EMW while evaluating the drilling window. Losses were encountered during the DFIT and a series of loss circulation pills (LCM) were pumped but failed to strengthen the formation. The bottom hole assembly (BHA) was pulled, and a cement stringer was run to squeeze off the zone with MPD. DFIT showed stable pressure at 2.05 sg EMW, and the section was drilled to TD with 12 days lost curing losses.
Well C was drilled with 1.92 sg MW with bottom hole ECD 0.02 sg above pore pressure. The section was drilled successfully to TD but losses occurred when displacing the well to 2.04 sg EMW. A cement stringer was run in the well and a successful cement squeeze job was performed. Sixteen days were spent curing losses.
Lessons from Wells B and C resulted in lower mud weight for Well D. The well was drilled with 1.86 sg MW which increased to 1.88 sg during drilling. Bottom hole ECD was maintained 0.04 sg below pore pressure. A series of DPPTs were performed to evaluate gas levels and pore pressure. After reaching TD, the bottom hole window was tested with DPPT and DFIT. Optimum selection of MW saved 10 authorization-for-expenditure (AFE) days and reduced MW by 0.09 sg.
8 ½-in. section
Fig. 4 shows drilling curves for the 8 ½-in. section. The 8 ½-in. section on Well B started with 1.94 sg statically underbalanced MW. Bottom hole ECD was maintained 0.10-0.11 sg above pore pressure with a series of DPPT and DFITs while drilling. Losses were encountered which were cured with MPD cement squeeze jobs, but continuous losses while drilling to TD resulted in MW reduction to 1.88 sg. Twenty-six days were spent curing losses in this section.
Well C was drilled with 1.84 sg MW in this section. Bottom hole ECD was maintained 0.01 sg above pore pressure. The section was drilled to TD without losses, but losses were encountered at TD during a DFIT to determine tripping mud weight. Six days were spent curing losses.
Well D was drilled with 1.79 sg MW and bottom hole ECD was maintained 0.03 sg below pore pressure. The section was drilled with a single-bit run saving 15 AFE days.
Drilling improvements
Fig. 5 shows efficiency improvements with experience. MPD service cost was reduced 12% and overall drilling cost dropped 19% during the three-well campaign, reflecting reduction in lost time from efficiencies in rig-up of the MPD equipment, better management of losses from Well B to Well D, and savings from the rig service provider.
Other improvements to the system included:
- Improved bearing-assembly sealing elements. The life of the seals during drilling Well D was improved by limiting back-reaming to only 75% of a single joint instead of a full stand. This limitation prevented the tool joint from passing through the sealing elements, and no retrieved elements were cracked or failed.
- Mud coolers on return lines. Surface mud return temperature was 77° C. which is above the polyurethane sealing element specifications. Adding the cooler reduced temperatures below the working temperature rating, and an additional recommendation was made to replace the polyurethane with natural sealing elements with higher temperature ratings.
- Revised temperature model. The model in the MPD hydraulic simulator did not accurately match bottom-hole temperatures recorded with PWD tools. The software was revised and calculated-BHT closely matched PWD-measured temperature.
- Improved DPPT and DFIT time. Well B averaged 1-hr testing time which declined about 28% (to 35 min) on Well D.
