PETRONAS has been drilling carbonate reservoirs offshore Sarawak since the 90's. However, with more prospects being explored, the challenges have escalated as the company has embarked into exploring the remaining carbonate pinnacles where the primary objective is to identify the gas or oil water contacts of the prospects. Some of these carbonate reservoirs are characterized by the presence of large karsts and fractures, leading to a frequent scenario of total mud losses and kicks. Conventional drilling practices are not considered a safe or economical option to drill the carbonate sections. Additional problems associated with the drilling operation in these zones includes poor hole cleaning, low ROP, high vibrations and stuck pipe events. Implementing the Managed Pressure Drilling (MPD) variant called Pressurized Mud Cap Drilling (PMCD) allowed the drilling team to reach targeted total depths on several wells. Upon encountering unsustainable losses the wells were converted over to PMCD. Light Annular Mud (LAM) was injected into the annulus and a sacrificial fluid (SAC) was pumped down the drillstring allowing drilling to continue to total depth. By successfully implementing the PMCD technique, the operator was able to reduce risk and reach the exploration targets successfully. Lessons learned surrounding operational techniques, pressure limitations of the drilling system and continuous training and development of the operating team have expanded the application for the operator. The authors present lessons learned of wells drilled to date and key lessons learned as the Operator evolves to improve execution of PMCD.

Drilling the reservoir section in the Sagari field (Peru) presents many challenges, such as wellbore collapsing in the extremely mechanically unstable Shinai formation; differential sticking in low-pressure, high-permeability sandstone reservoirs; and total losses due to the presence of natural fractures. This paper describes how the implementation of automated managed pressure drilling (MPD) and managed pressure cementing (MPC) techniques allowed overcoming those challenges in a remote location where logistics and equipment mobilization is an additional challenge. The preliminary geomechanical study indicated that an equivalent density (ED) of 10.5-lbm/gal was required to maintain wellbore stability, while 10.8-lbm/gal could not be exceeded due to the risk of differential sticking. Additionally, eliminating pressure variations in the mechanically unstable Shinai formation would prevent wellbore collapse. The MPD strategy for drilling the original 8.5-in hole section and sidetrack consisted in using an automated MPD System to maintain the ED profile within the 10.5 to 10.7-lbm/gal window along the open hole and a near-constant pressure of 10.5-lbm/gal in the most unstable Shinai formation at all times. Due to its reduced footprint, this automated MPD equipment package could easily be airlifted by helicopter to the remote rigsite. The MPD strategy was implemented as per plan; it successfully prevented wellbore instability and differential sticking and contributed to the excellent condition of the wellbore. Indeed, the production liner was run down the 2,700ft of open hole smoothly in less than six hours and later well testing revealed that the mechanical skin factor in the reservoir section was equal to zero. When drilling the last feet of the sidetrack with an ED of 10.5-lbm/gal, a natural fracture was encountered; it was immediately detected by the MPD Coriolis flow meter located at the well returns, allowing for a quick response and curing losses rapidly. However, this further reduced the operating window size. MPC allowed using a statically underbalanced drilling fluid, while ensuring well integrity and preventing wellbore collapsing during cement placement. The estimated ED on bottom was monitored in real-time and losses were successfully prevented. The coupling of the wiper plug on the landing collar was observed as per plan, and successful zonal isolation was later confirmed by cement bond log (CBL) and casing integrity test (CIT). In addition to the application of managed pressure techniques in the production section, MPC of the intermediate 9 5/8-in casing was performed as a contingency measure, as the reduced annular flow area between the two casing strings and the narrow pore pressure -fracture pressure window would not allow cementing the casing conventionally.

The SB Field is located in Block PM on the west side of the Malay Basin, Malaysia. It is notorious for its steeply rising pressure ramp, narrow drilling operation window and inter-bedded sand, coal, and shale formations. Block PM is still at the exploration and appraisal stage with limited petrophysical information. Well SBD-2 was the second attempt to reach and cross the F & H sands of this basin. Despite using managed pressure drilling, the first attempt failed when an influx exceeded the fracture gradient, resulting in total fluid losses. Due to the shallow pressure ramp and narrow window between pore pressure and fracture gradient, a repeat attempt was initially deemed "un-drillable". However, the design team felt the target could be reached using an automated managed pressure drilling technology. The team was able to maintain constant bottom hole pressure over three demanding hole sections and reach target total depth. The 8-1/2" × 14-3/4" section required minimum overbalance to manage "wellbore breathing" and to control potential losses to weaker horizons. In the 10-1/2" × 12-1/4" section, the system was used to identify and react quickly to kicks in high pressure sands and also to eliminate wellbore breathing/ballooning. In the final 8-1/2" × 9-1/2" section, the objective was to maintain overbalance in the narrow pressure window between pore pressure and fracture gradient. This paper will describe the design efforts employed while preparing to drill the SBD-2 well. The challenges and lessons learned, particularly managing pore pressure prediction with multiple techniques will be discussed. Lessons learned and recommended workflows for similar projects will also be outlined.

This paper describes the use of the Managed Pressure Drilling technology in the largest offshore gas field in Latin American and the first offshore gas field to be brought to production in Venezuela. Managed Pressure Drilling technology with the assistance of Continues Circulation System was successfully implemented in the drilling of an extended horizontal section across a fractured and faulted limestone reservoir in an offshore gas well in the Venezuela Perla field. This paper presents the planning, operation and challenges faced while drilling across the reservoir and while running the production liner, how the severe losses were managed keeping the bottom hole pressure within a narrow mud window and preventing gas influxes with the assistance of the Automated MPD system Managed Pressure Drilling (MPD) is a technology where well control is maintained during the drilling operation by using a constant bottomhole pressure through the application of a surface back pressure (SBP) with the utilization of MPD chokes and a Rotating Control Device (RCD). The accurate measurements of flow in/out are essential to the MPD system to provide early indication of well losses or gains with the use of mass flow meter to measure flow rate and mud density (Coriolis meter). The closed fluid system provides high resolution of mud density, flow rates and pressure with the ability to direct measure formation pressure at key places and fracture gradients without detaining the drilling operation. The Perla field is located in the CARDON-IV block in waters of the Golf de Venezuela, 50 km offshore Peninsula Paraguana. Perla consists of one production platform with a total gas production 500 MMscfd dedicated for local consumption. The objective reservoir is the lower carbonate at a depth of approximately 9000ft SS. The thickness of the reservoir is approximately 700ft. The anticipated production from each well is in the order of 80 MMCFD to 135 MMCFD with an initial condensate yield of 25-30 BC/MMCF. In previous wells, severe lost circulations were encountered while drilling the Lower Carbonate Reservoir which has a formation pressure of 9.8 ppg at the top. Several LCM pills and eventually cement squeezes were required to control these losses. In some cases, major losses were encountered, resulting in early termination of the section. Losses of this magnitude are due to a fractured carbonate and the crossing of several faults along the open hole.

Hydrocarbon exploration and production relies on Blowout Preventers (BOPs) to prevent catastrophic accidents; however, currently there are no in-situ or rapidly deployable backup systems for BOPs. This paper presents a method and machine for predictably stemming an uncontrolled flow resulting from a failed Blowout Preventer. The tool, referred to as the "Hampering Active Wellbore Kit" (HAWK), is a machine that can feed wire (with varying material properties along its length) through a BOP's existing ports and into the wellbore. The wire, initially stored in spools inside the device, forms a tangled wire mass (TWM) inside the wellbore that serves to gradually stem the uncontrolled flow. A design theory is described for wire feeding in order to form a TWM in a free flowing conduit, and the efficacy of the method is evaluated by comparing flow rates of a single wellbore before and after the introduction of the TWM. A prototype machine for direct attachment to a BOP as a backup safety system is presented based on operating constraints and industry requirements.