Increased global energy demand has forced the oil and gas industry to search for hydrocarbons in increasingly challenging locations such as high temperature, high pressure (HTHP) reservoirs. This paper presents the field performance of a new fit-for-purpose synthetic-based mud (SBM) used to drill an ultra-HTHP deep gas exploration well offshore Malaysia. The well was drilled to a total depth (TD) of 14, 380 ft (4, 383 m) and reached the highest recorded bottomhole temperature (BHT) of 488°F (253°C) in Southeast Asia. To overcome the anticipated drilling challenges in the extreme environments, the operator and service company collaborated to identify a thermally stable, high-density drilling fluid that met the operator's needs. The drilling fluid was formulated for a maximum density of 18 lb per gallon (ppg), but reached the Southeast Asia record of 19.1 ppg mud weight at TD. The use of dual weighting materials (barite and manganese tetraoxide) yielded lower plastic viscosity (PV) for the high-density mud, leading to improved hydraulics and lower equivalent circulating density (ECD). The drilling fluid encompassed excellent temperature stability with no weighting agent sag and no high-temperature gelation observed after remaining static for five days at BHT during wireline logging. In this respect, it eliminated the rig time spent for additional circulating or conditioning of drilling muds and fluid treatment cost. Moreover, the fluid also provided good wellbore stability with no non-productive time (NPT) from drilling fluid performance. Comparison of field data and laboratory results highlighted the benefits of competent drilling fluid design and testing. As a result of thorough planning and comprehensive laboratory testing, desirable drilling fluid properties were maintained despite extreme HTHP conditions, minimizing trips and operational costs.

Owing to the high depletion and narrow drilling windows characteristic of many wells in the South China Sea, the risks of severe losses increase exponentially. Mud density, sufficient to maintain well control, typically exceeds the fracture gradient of the clastic and coal formations. Thus, operators face a dilemma in balancing the need for mud weight to remain below the fracture gradient to avoid losses, while also providing sufficient density to block influxes into the well. This paper describes the development and application of a process that essentially stabilized troublesome zones and enabled the wells to be drilled with mud weights higher than the maximum density. The authors will describe the drilling process that stabilizes microfractures in the formations and mitigates many of the issues associated with wellbore instability. The presentation of a case history will illustrate the historical mud weights and properties used to drill offset wells, and the corresponding hole stability problems. The comparative analysis demonstrates how the use of a higher mud weight eliminated well influxes while simultaneously achieving zero mud losses to the formation. Furthermore, the technology delivered additional wellbore strength to weak formations, allowing the drilling operation to be completed as per plan. Accordingly, the operator significantly reduced the wellbore stability challenges associated with lost circulation, stuck pipe and well instability, thereby facilitating easier logging and delivering a quality, and less costly, producing well.

Global energy demand has driven the oil and gas industry to search for hydrocarbons in increasingly challenging reservoirs including those at high pressure and temperature (HPHT) such as found in the South Malay Basin of Malaysia. Competent well designs and enabling HPHT technologies such as advanced drilling fluid designs that are stable at HPHT conditions are critical to successful drilling and completion of these wells. This paper discusses the laboratory evaluation of potential HPHT drilling fluid designs considered for a deep gas exploration well in the Duyong Deep-1 field located in the South Malay basin of Malaysia expected to reach 455 °F (235 °C) and 13,683 psi. Laboratory testing encompassed fluid rheology, fluid loss, sag, electrical stability and chemical analysis before and after extended dynamic and static aging up to this temperature and pressure. Results were examined to identify strengths and weaknesses of the fluid designed. Improved-performance drilling fluid formulations underwent further pressure, temperature and hydraulic simulations to ensure adequate hydraulics and hole cleaning. As a result, suitable drilling fluid formulations for the ultra-HPHT gas well were successfully formulated with a maximum density of 18 ppg and thermal stability of 455 °F. The selected drilling mud design was stable and maintained desirable rheological properties including shear strength less than 200 lb/100 ft2 at static BHT at 16 and 48 hours.

Technology Update Wells in the South China Sea are characterized by high depletion and narrow drilling windows which exponentially increase the risk of incurring severe losses. Mud density, sufficient to maintain well control, typically exceeds the fracture gradient of the clastic and coal formations. Therefore, operators face a dilemma in balancing the need for mud weight (MW) to remain below the fracture gradient to avoid losses, while also providing sufficient density to block influxes into the well.  The Alpha field, with a water depth of approximately 26 m (85 ft), is located in Sarawak Basin, offshore Malaysia. This area has historically been classified as a “high risk” drilling environment due to clastic deposition and unstable coal formations.   A process is described that stabilized troublesome zones and enabled the wells to be drilled with MWs higher than the maximum density predicted by leak-off tests or formation integrity tests. A drilling process stabilized microfractures and mitigated many of the issues associated with wellbore instability. The use of a wellbore “shield” allowed use of a higher mud weight which eliminated well influxes while simultaneously achieving zero mud losses to the formation.  Furthermore, the technology delivered additional wellbore strength to weak formations, allowing the drilling operation to be completed as per plan. Accordingly, the operator significantly reduced the challenges associated with lost circulation, stuck pipe, and well instability, thereby facilitating easier logging and delivering a quality, and less costly, producing well.  Problem-Solving Process Offset well analysis. To understand the drilling risks and past issues, the team led by Petronas analyzed the root source of stuck pipe in offset wells. The cost of stuck pipe and wellbore instability was valued at $5.7 million for Offset 1. The analysis determined the stuck pipe event occurred at the coal layer with three main contributing factors: Failure in understanding the coal and weak zone structure prior to drilling Insufficient fracture bridging material while drilling the coal Poor drilling and tripping practices across the coal seam layer that resulted in a stuck bottomhole assembly Predrilling geomechanics analysis. Failures in offset wells were studied through geomechanics analysis to identify the minimum MW requirement for weak zones and the coal layer. The challenge: excessive MW will lead to coal destabilization, whereas too-low MW may lead to borehole collapse. Borehole breakouts were predicted using the geomechanical model and the actual MW used during drilling offset wells. Many of the predicted breakouts were related to weak coal layers in the 12¼-in. sections. An internal geomechanical report also indicated that the drilling problems frequently occurred after reaching section total depth and were likely a result of time-dependent failure mechanisms and/or mud-rock interaction.

X-1 well is one of the wells from project X, a field development project located offshore Peninsular Malaysia. The well has become the signature well for project X as it managed to achieve single digit (in million dollar) well cost, a rare occasion for offshore Malaysia development wells. Project X wells team has taken several initiatives and strategies to reduce well cost and ultimately achieving low cost well (LCW) status as defined by the company's wells department. Since year 2014, crude oil price has fallen from its heyday to as low as USD27 per barrel in 2015. Oil and gas (O&G) operators around the world have been struggling to make profit and fulfill their capital commitment. The company's wells department has since came out with criteria for LCW to be benchmarked by the company's projects. To be recognized as LCW, a well needs to be below USD 15 million with minimum depth of 1500 m and key performance indexes (KPIs) better than or equal to Malaysia Petroleum Management's (MPM) Drilling Minimum Standard without compromising operational safety, reserve development, well integrity and environmental aspects. In the quest to achieve LCW, project X wells team has engaged several strategies to ultimately reduce X-1 well cost by 40% from initial estimated. These strategies involved the optimization of critical areas such as well design & engineering, well planning and operations. After painstakingly planned and implemented above cost saving strategies within restricted time frame, project X wells team has successfully reduced 40% of initially estimated X-1 well cost. The reduction has proven that with focused planning and execution, coupled with full support from management especially with new contracting strategy, LCW is possible and able to help O&G operators to improve their bottom line. Low oil price environment has appeared to be the silver lining in O&G operators’ efforts to drive down cost as it appears to provide the opportunity for operators to re-evaluate their current contracts, planning and operation practices.