During the second quarter of 2002 Petronas Carigali, the State Oil Company of Malaysia, embarked on a campaign to utilize Expandable Sand Screen (ESS®) in unconsolidated multi-zonal sandstone completions in the Baram and Alab fields, offshore Malaysia. The primary objective of the application of ESS® technology was to control sand in conjunction with minimum skin damage without encountering operational problems/constraints which are inherently associated with gravel packing as a means of sand control. A total of five deviated cased holes were equipped with ESS® with mixed results which have been documented in details in a previous publication by the authors (SPE paper # 80449). Further investigation revealed that the wells completed with ESS® have achieved satisfactory improvement in productivity. ESS® technology has now proven to be one of the best available sand control techniques for the Baram field. This paper will focus on Petronas Carigali's experience in ESS® technology implemented in a deep horizontal open hole section of a sandy well which is to be equipped with a gravel pack assembly in the upper section inside the cased hole section, thereby providing an excellent source of comparison between the performance of gravel packing and expandable sand screen technology. Installation of ESS® in well BA-47, being the first deep horizontal open hole application in Malaysia, was an operational challenge with a few lessons learnt which may be shared by other operators. The primary objective of the well has been successfully realized as evidenced by better than expected sand free production. The execution of ESS® installation was successful with some problems encountered while initiating the expansion process. After some modifications on the expansion string and mud/brine system, the expansion process was carried out smoothly. The secondary objective of the ESS® application was to assess/evaluate the enhancement/impairment of productivity of the well using ESS®, in comparison with the technique of gravel packing. The well is presently in the process of being cleaned up. Preliminary data indicates higher than expected production. PI and PBU tests are planned for the well as soon the well has cleaned up and/or stabilized. Introduction The Baram field is located about 25km NNW of Lutong, Offshore Sarawak in Baram Delta, Malaysia (Fig 1& 2). The main Baram field was discovered in 1963. Baram reservoirs are composed of many sand layers which are of Miocene age consisting of alternating sequence of sand and shale beds. The drive mechanism of the reservoir is strong water drive. Well # BA-47 was the first ESS® application in a horizontal open hole completion located offshore Malaysia. The previous wells from Alab/Baram fields were multi-zonal cased hole ESS® applications which were successfully executed. The well profile, trajectory, well overview, seismic cross-section and well diagram are shown in Fig 3, 4, 5, 6 respectively. There are two main reservoirs completed in this well which are I4.0 and I6.0 sandstones. Both the formations consist of highly unconsolidated & friable sands requiring sand control to produce the wells. The formation has a uniformity co-efficient of +3 and a sonic transit time of 110 μsec/ft. The average porosity, permeability and water saturation for these reservoirs are 29%, 1000 mD and 37% respectively (Fig 7). In view of the success achieved and lessons learnt from the previous wells, deployment of ESS® was preferred over Open Hole Gravel Pack (OHGP).

Using a Dynamic Hydraulic and Well Control Simulator to predict and establish wellbore pressures in a narrow margin HPHT well has allowed the operator to set operational limits during drilling, tripping, casing and cementing operations. A previous attempt to reach the objectives for the well failed. A much more rigorous approach to wellbore pressure management was undertaken prior to drilling this second well. A complete review of the expected pressure limitations was conducted, this review included a detailed overview of pore and fracture pressures as well as casing setting depths, hole sizes, temperature effects and proposed mud weights. This resulted in an improved prediction of the pressure windows for each of the proposed hole sections. Each hole section was in turn reviewed for optimal mud weights and this included a detailed review of equivalent static, equivalent circulating and dynamic kick tolerance limitations for the proposed mud weights. Surge and Swab calculations then determined maximum tripping speeds and cementing calculations ensured that pore and fracture pressure limits were not breached with the proposed cement volumes and pump schedules. This paper presents the approach that was taken in proving a complete pressure management system for a narrow margin HPHT exploration well. The use of dynamic hydraulic models allowed accurate predictions of down hole pressures during virtually all drilling operational phases a hole section. Calculated down hole pressures were compared to PWD tools, proving that the accuracy of the dynamic hydraulic predictions was within the required limits to allow drilling without a PWD tool if required. Combining the available pore pressure and fracture pressure data, with mud weight schedules, pump rates, tripping rates and cementing operations allowed optimization of the drilling parameters thus ensuring that this narrow margin HPHT well, was drilled successfully to its target depth and all of its objectives were met.

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.

Despite the short planning time of 18 months and very limited geological data, TTD-1 HPHT Exploration well in Block SK of East Malaysia, was successfully drilled to its technical limit by adopting some innovative HPHT practices. Various technical challenges were successfully overcame including an abnormally steep pressure ramp (17 psi/ft), high mud weight (18 ppg), high overbalance (3,000 psi), narrow drilling margin (until 0.7 ppg window), wellbore breathing, pore pressure of 14,000 psi and temperatures of 325° F.During drilling, the actual operating window was successfully mapped out in real-time. The lower boundary was defined by pore pressure modeling, MDT logging and dynamic flow checks using MPD. The upper boundary, fracture gradient, was derived from dynamic formation integrity tests & leak-off tests utilizing MPD. Other techniques such as use of smaller tubular, low-flow MWD tools and bridging agent also contributed to the success. Wellbore breathing was well controlled to a minimum level.Various simulations have assisted the HPHT section to be drilled beyond conventional defined limits. Two real-time monitoring centers assisted in improving drilling efficiency and real-time decision making. The well highlighted limitations of acquiring formation pressure in tight formation using FPWD tools, life of MPD seal element and gas invasion in production zone cementation.The authors will present and share the HPHT drilling practices adopted to successfully drill the deepest HPHT well to date for PETRONAS Carigali in Malaysia.

HPHT wells are typically associated with high complexity, technically challenging, long duration, high risk and high NPT as many things could go wrong especially when any of the critical nitty- gritty details are overlooked. The complexity is amplified with high risk of losses in carbonate reservoir with high level of contaminants compounded by the requirement of high mud weight above 17 ppg during monsoon season in an offshore environment. The above sums up the challenges an operator had to manage in a groundbreaking HPHT carbonate appraisal well which had successfully pushed the historical envelope of such well category in Central Luconia area, off the coast of Sarawak where one of the new records of the deepest and hottest carbonate HPHT well had been created. This well took almost 4 months to drill with production testing carried out in a safe and efficient manner whereby more than 4000m of vertical interval was covered by 6 hole sections. With the seamless support from host authority, JV partners and all contractors, the well was successfully delivered within the planned duration and cost, despite the extreme challenges brought about by the COVID-19 pandemic. This paper will share the experience of the entire cycle from pre job engineering/planning, execution, key lesson learnt and optimization plan for future exploitations which includes an appraisal well and followed by more than a dozen of development wells.