Managed-Pressure Drilling Solves HP/HT Challenges Offshore Vietnam
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Drilling in deeper formations with high-pressure/high-temperature (HP/HT) margins increases the tendency and frequency of well-control incidents related to anomalies of formation pressures and temperatures. This paper discusses how managed-pressure-drilling (MPD) technology led to cost savings in two wells drilled in the Hai Thach gas field offshore southern Vietnam. The wells were drilled from a semisubmersible tender-assisted rig with an automated MPD choke manifold and docking-station rotating control device (RCD), integrated on a flexible plug-and-play basis to enable easy rig up and rig down and the moving of equipment between wells.
MPD systems have built a track record of success in mitigating drilling hazards related to uncertain formation pore pressures and narrow-pressure operating windows common to HP/HT exploration and development wells. In these wells, slow rates of penetration, wellbore-stability issues, ballooning, accuracy of influx-detection systems, and differential sticking can result in well-control problems and nonproductive time (NPT).
The Nam Con Son (NCS) basin off the southern coast of Vietnam presents such challenges. It is one of a series of Tertiary rift basins created on Vietnam’s continental shelf as a consequence of the East Sea seafloor spreading.
The formation pressure profiles of offset wells in the central NCS basin, including the Hai Thach and Moc Tinh gas fields, are characterized by overpressure beneath the late Pliocene/Quaternary deltaic sedimentary section. The overpressure occurs with a high-pressure ramp in the thick, post-rift, deep marine, Late Miocene/Early Pliocene shale interval. Overpressure retains in the syn-rift and pre-rift sedimentary section with lower ramp.
A higher pore pressure of approximately 17.3 lbm/gal at a shallower-than-predicted depth was encountered when drilling the 12¼-×14½-in. underreamed (UR) section of Bien Dong Well WHP-HT1. Increasing mud weight (MW) was not practical because high equivalent circulating density (ECD) exceeded the unexpected, low leakoff test result at the casing shoe. This led to the decision to call off the well total depth (TD) early and set the contingency 11¾-×13⅝-in. expandable liner to cover the weak formation. A total of 46 days was required to complete the planned depth of the well section.
As a part of remedial actions based on the experience of drilling Well 1, and with added concern of potential ballooning given high pore pressures and a narrow operating window, the operator’s drilling team decided to deploy MPD technology with constant bottomhole pressure (CBHP) and early kick-loss detection capabilities on Wells WHP-HT 2 and 3.
Well 1 Drilling Background and Challenges
Well WHP-HT1 was the second well drilled from the Hai Thach platform. It was drilled conventionally, with no application of MPD. While drilling the 12¼‑in.-hole section, several well-control issues occurred as a result of unexpected higher pore pressure and lower-than-expected extended leakoff test (XLOT) results at the 14½-in. oversize shoe.
The contingency plan was to stop drilling and set a contingency 11¾-×13⅝‑in. expandable liner to cover the weak formation zone, and then raise MW as required to continue drilling the 12¼-in.-hole section. The expandable liner was run and cemented successfully.
When drilling the 12¼-in. upper section, the well experienced partial mud losses while circulating to bottom before pulling out of the hole for contingency UR equipment. MW was reduced from 17.6 to 17.4 lbm/gal. The low XLOT at the 14½-in. shoe and excessive ECD caused by high MW led to loss issues while drilling. During well-control mitigation, the rig damaged the blowout-preventer annular packer while circulating and stripping through it.
The drilling team determined that MPD technology would allow drilling at balance for a similar well case and would also save time when mitigating well-control situations.
Operational and Engineering Planning
The drilling team followed a detailed plan to engineer the optimal MPD-CBHP application for the next two wells. The MPD system and equipment were designed to permit application of CBHP drilling until section TD; allow flexible switching between MPD and conventional drilling at any time, if required; and complement rig well-control equipment without changing it.
A static, slightly overbalanced MW (approximately 100-psi overbalance) was premodeled to comply with the operator’s well-design policy. Prehydraulic modeling was used to analyze well data to ensure that Wells WHP-HT2 and WHP-HT3 could be drilled successfully by walking the line. Calculating anticipated surface backpressure (SBP) was required at any unplanned event to comply with the pressure capability of the MPD surface-control equipment.
The annulus flow behavior during MPD application was simulated to define circulating parameters to be used as reference points during actual well operations. The operating window was interpreted by maintaining the dynamic and static downhole pressure within a window bounded by the difference between maximum formation pressure of 17.3 lbm/gal and a minimum expected fluid loss pressure of 18.1 lbm/gal equivalent MW throughout the 12¼-in.-hole section. Both limits were evaluated throughout the operation by adjusting SBP to enable instantaneous changes in ECD. The ECD management plan was computed using bit depth/TD as a pivot point.
Preliminary hydraulic analysis based on initial well data indicated that both wells could be drilled safely by walking the line immediately above predicted pore pressure because applying MPD would allow maintaining a CBHP condition, overbalanced during pumpoff scenarios, especially while making connections. This would enable maintaining the bottomhole pressure at greater than the pore pressure without fracturing the formation.
Preliminary hydraulic analysis of the 8½-in.-hole section indicated that it could be drilled to TD with 17.2-lbm/gal MW and maximum flow rate of 450 gal/min. Higher flow rate would expose the formation to fracturing because of high ECD. It was recommended to drill out the 10‑in. shoe with conservative parameters (280 gal/min, 80 rev/min) within the casing shoe pressure limits. A 200- to 250-psi SBP would be applied to maintain CBHP while pumps were off.
MPD System Description
MPD equipment consists of two main components: an RCD and an MPD choke manifold. The RCD forms a pressure seal at the top of the wellbore; the MPD choke manifold is installed at the MPD main return flowline with an accurate Coriolis flowmeter to provide real-time wellbore pressure control when drilling.
The system also includes isolation valves, flowline piping and hoses, and crossovers to route fluid returns. An MPD degassing line is connected to the rig mud/gas separator from downstream of the MPD choke manifold to safely vent formation gas when required. Dedicated rig mud pumps must be capable of operating simultaneously and independently to pump into the drillstring and annulus during operation.
With input of hydraulic modeling and system pressure readings through the external standpipe manifold and SBP sensors, a proprietary control algorithm of an automated MPD choke-control system allows calculation of the amount of SBP required for any given change of flow and pressure. When the MPD system detects changes in the model-calculated ECD, the active chokes adjust until a measured SBP has reached the calculated set point to compensate for the actual downhole friction loss.
During a connection or any other pumpoff event, the driller brings up dedicated rig pumps as MPD auxiliary pumps before turning off the drilling pumps. With the drilling-mud pumps off, the injected mud flow to annulus through the MPD choke manifold provides the required volume for SBP control to energize fluid in the wellbore. Injecting mud flow through the flowmeter keeps it reliable in an active monitoring mode for kick-loss detection during pump off.
MPD of Wells 2 and 3 Wells WHP-HT2 and WHP-HT3 were drilled using MPD, enabling the well team to apply sufficient SBP to compensate for downhole friction loss from pressure fluctuation while maintaining a reliable active monitoring mode with kick-loss detection. Time savings were realized by running in the hole with SBP applied instead of washing down with every stand during a trip.
The RCD bearing assembly was installed, followed by MPD fingerprinting, while the bottomhole assembly was still inside the 13⅝-in. casing shoe before drilling the shoe track. This is recognized as the in-casing test, or cased-hole fingerprinting. Its main purpose is to ensure effective communication and practical training with the rig crews, especially the tool pusher, driller, and assistant driller, who control the annulus pressure during connections, tripping, and unexpected pumpoff events.
Using MPD-CBHP to drill Wells 2 and 3 made it possible to apply sufficient SBP to compensate for downhole friction loss from wellbore-pressure fluctuation while maintaining a reliable active monitoring mode with kick-loss detection. Applying the technology also enabled the crew to identify and differentiate between ballooning and influxes, which saved the operator significant operational days and cost. Well WHP-HT1 took 46 days to reach section TD and did not achieve its objectives. Well objectives for the next two wells were achieved using MPD, which enabled drilling the 12¼‑in.-hole section with the lowest MW to accommodate the narrow drilling window. The wells took a total of 10 days and 14 days, respectively, to reach well section TD. Drilling curves for all three wells are included in the complete paper.
For a limited time, the complete paper SPE 191927 is free to SPE members.
Managed-Pressure Drilling Solves HP/HT Challenges Offshore Vietnam
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