Objectives/Scope This paper shares results from the first field deployment of an active sealing device in a narrow margin deepwater well in the Black Sea. The active sealing device represents a clean-sheet design approach purpose built for deepwater MPD operations. This paper shares highlights from the detailed design through the prototype testing to the first-use stages of the program. Methods, Procedures, Process This paper discusses three distinct program phases covering the overall process from concept development to field operation. First, the detailed design phase is discussed, introducing the reader to system components and functionalities. The second phase of full-scale testing is discussed from the design verification, system optimization, and systems integration testing perspectives. Finally, field results are shared detailing findings from the first deployment on a dynamically positioned deepwater rig drilling a narrow margin MPD well in the Black Sea. Results/Observations/Conclusions The paper shares findings, insights, and results from each of the phases of the active sealing device development program. Upscaling passive RCD technology for deepwater has negative effects on system performance. A non-rotating, externally functioned seal sleeve element eliminates multiple high wear components. Elimination of bearing assemblies and rotary seals removes common failure modes seen in deepwater. Redundant, actively controlled seal elements ensure wellbore seal quality throughout the seal life. A lubrication system injects mud between seal elements, enabling seal condition monitoring. Active seal condition monitoring alerts the rig crew when to replace the elements prior to failure. Full-scale testing has been completed demonstrating the system under simulated drilling conditions. Seal life demonstrated to outlast most deepwater MPD hole sections. Operational testing and integration testing reduce commissioning and testing time consumed on the rig. Active sealing device successfully integrated into the drilling riser and MPD specialty joint. Multi-modal system provides rig crew with distinct operational strategies to meet current parameters. Consistent seal life enables rig crew to drill MPD sections with confidence in the wellbore seal. Deepwater well with multiple MPD sections successfully drilled using new active sealing device. Novel/Additive Information The project includes secondary novel aspects such as drilling contractor ownership of the subsea and topside MPD equipment. The MPD system is integrated into the drilling control system allowing communication between the rig, subsea, MPD topsides, and all third-party systems, while also sharing commonality with other rigs in the fleet. An objective of the MPD system design is to enable new models of fleet management to meet drilling contractor operations.

Continuous efforts are made in drilling engineering to identify and develop advanced tools and technologies to maximize rate of penetration (ROP). Optimization of ROP has a major impact on both the reduction of the cost in terms of cost per foot and well delivery. Numerous correlations, methods, designs, models, and tools for ROP optimization are available in literature but rarely are applied in drilling operations. This paper introduces a robust methodology aiming to optimize the rate of penetration without inducing any associated wellbore stability problems. The objective of this paper is to detail the methodology and the effectiveness of the technique introduced. We report performance indicators for a trial well drilled using the novel approach and compare the findings with a conventionally drilled offset well. The drilling parameters for a challenging horizontal hole section were collected and analyzed to evaluate their effect on ROP performance. The drilling parameters selected are from corresponding hole sizes, formation and mud types with respect to the offset well for a consistent comparison. The proposed approach contributed to an enhanced well drilling performance by more than 40% and was instrumental in mitigation of stuck pipe incidents. In this paper, we introduced and verified a novel technique to maximize the rate of penetration (ROP) by optimizing the drilling parameters (RPM and WOB). As long as the CCA is less than 0.05, the proposed workflow in this study can be used to determine an optimized ROP in conjunction with a minimized DSE yielding ideal RPM and WOB values thereby reducing the cost per foor drilled. Evidence of the efficiency of the proposed procedure is provided by comparing the ROP and DSE measured for a horizontal section drilled employing the technique with data for an offset well drilled in a non-optimized fashion. Compared to the latter case, we reported a 44% improvement in ROP and a 48% reduction in DSE.

The drilling of the exploration wells in Xihu depression in East China Sea becomes very challenging as the drilling campaign shifts towards the deeper part of the west slope. Due to the complex pressure compartments formed by highly faulted blocks, unexpected high pressure encountered in the targeted formations has caused the early abandonment of some of the wells without managing to properly evaluate the reservoir potential. Providing an accurate pore pressure prediction therefore becomes very crucial to enable the decision-making process required for drilling success. An integrated approach was adopted to combine detailed predrill prediction with real-time pore pressure monitoring considering the uncertainties in the seismic velocities and varying geological conditions in different faulted blocks. During the predrill modelling, a few nearby offset wells were reviewed in detail to construct the pore pressure model and to understand the overpresure mechanisms and geological settings. Seismic velocities at offset well locations were also compared with the acoustic logs to understand the uncertainties in different datasets. For the planed well, a range of low, high and most possible pore pressure profiles were interpreted using all the available data including seismic velocity and depth-stretched logs from different offset wells to account for the geological and geophysical uncertainties. During the drilling of the exploration well, real-time pore pressure monitoring was conducted by integrating the Logging While Drilling (LWD) acoustic and resistivity logs, mud logging and drilling data. Pore pressure and fracture gradient profiles were updated in real-time to enable proactive decision making to optimize mud weights and casing points to reduce drilling risks and hazards. This approach was applied in the drilling of one of the exploration wells in Xihu depression. The well was drilled successfully by optimizing the casing design based on the real-time pressure monitoring results. This enabled the operator to properly evaluate and appraise the reservoir potential owing to setting a liner just above the high overpressured section in the deeper formations that caused drilling issues in previous wells. The overpressure magnitude was confirmed later by blind drilling for testing purposes. After the completion of the planed well drilling, a post drill summary was conducted to compare the pressure models at different stages. In addition to the final detailed pressure model, a clearer understanding and interpretation of the overpressure transition, overpressure mechanisms and pressure variations compared to the nearby area were summarized and correlated for reference, while planning for drilling of the future wells.

Complete to intermittent dynamic losses during drilling operations in the Early Permian reservoirs of the Bowen Basin are common because of depleted zones, particularly in the Bandana Coal Measures. The losses encountered while attempting to drill to total depth (TD) result in notable setbacks in time, remediation costs, and zonal isolation integrity. Operators have access to a large portfolio of loss circulation (LC) treatments depending on the loss type, rate, and nature of losses. This paper presents a low-solids, highly thixotropic (LSHT) cement system that can help cure losses without incurring costly nonproductive time (NPT). During the recent Springwater campaign, which consisted of 12 wells targeting the Cattle Creek Coal Measures, three of the wells experienced significant to total losses. A number of conventional lost circulation materials (LCMs), including particulate materials, reticulated foams, and fibers, were unsuccessful in curing the losses. As an alternative to a conventional LC cement plug, an LSHT cement system was deployed. The low-solids content and avoidance of any traditional LCMsenable the LSHT system to be pumped through the bottomhole assembly (BHA), which allows for continued drilling. The LSHT cement system is shear-rate dependent, yielding to thin rheologies on application of shear to easily penetrate into the loss zone. When shear is reduced, the slurry gels rapidly to arrest the rate of flow. Additionally, the quick early compressive strength development at shallow depths allows operations to continue without incurring significant loss of operating hours. The solutions provided were pumped through open-ended pipe in one case and through the BHA with a drilling bit in another; both performed in the same manner without hampering equipment capability. Successful application of the LSHT cement technology helps minimize time lost using conventional cement plugs because the LSHT cement can be pumped through the BHA, saving time associated with tripping in and out of the hole to change the BHA. Additionally, the system's early compressive strength development yields time savings, along with savings in otherwise lost fluids, and achieves drilling efficiencies to help manage drilling operations costs.

The paper presents a case study of an Operator who successfully drilled two challenging wells through optimization of the drilling fluids. Well A was a HPHT well drilled with mud weight up to 18.6 ppg with overbalanced pressure as high as 6,800 psi – the highest overbalanced pressure experienced by the Operator to date. Well B was required to drill through depleted sand and unstable shale where series of severe loss circulation and wellbore instability issues were experienced in the nearby wells. Due to its HPHT nature, the design of the drilling fluids in Well A was expected to have a total solids content up to 70% by volume. Due to this high solid content, the rheology of the fluids system is inherently high posing an issue related to excessive ECD. To further exacerbate the issue, the extreme differential pressure which was expected to be observed in Well A requires the inclusion of bridging material in the system as part of the mitigation plan to minimize the risk of differential sticking. Conventional bridging material such as calcium carbonate and graphite with concentration between 20 to 40 ppb will further increase the amount of solids in the system. Likewise, in Well B, the Operator also observed that the application of common bridging material in the drilling fluids does not help in addressing the severe losses and wellbores instability issue observed in the offset wells. Almost 60% of the offsets encountered severe loss circulation as high as 6,000 bbl mud loss per well. This paper will share several initiatives by the Operator during the design stage in order to optimize the mud formulation to address the challenges for both of these wells. These include evaluation of various types of bridging material and "a must have" mud testing to assess the performance of the drilling fluids system. Subsequently, the Operator has successfully drilled these wells with no issues related to differential sticking, loss circulation and wellbore instability.

Drilling in Yinggehai basin of South China Sea is challenging due to high pressure gradient (2.20-2.30 g/cm 3 ) and high temperature (186-196 0 C). Several wells did not reach target and were abandoned due to severe wellbore instability of gas kick and mud loss. In order to drill safely, drilling geomechanics techniques were applied in well LD-6, including: 1) real-time monitored pore pressure and fracture pressure with logging while drilling (LWD) technique; 2) predicted over-pressured reservoir depth and formation pressure ahead of bit with borehole vertical seismic profile (VSP); 3) wellbore stability analysis to reveal the mechanism of mud loss in Huangliu formation. With drilling geomechanics techniques, well LD-6 was successfully drilled and completed. The achievements were:1) formation pore pressure and fracture pressure were accurately monitored while drilling. The predicted reservoir pore pressure gradient was 2.27g/cm 3 and actual measurement was 2.28 g/cm 3 ; 2) The top depth of over-pressured reservoir, S1 Sand, was predicted within 3 meters versus actual depth. The 9-5/8" casing successfully set in shale formation above S1 Sand, which enabled a manageable pressure window for drilling 8-3/8" reservoir section; 3) the wellbore stability analysis with borehole resistivity image revealed that mud loss only occurred in sand and mainly caused by drilling-induced tensile fractures. Stresses computation results indicated that horizontal stress anisotropy in sand is larger than shale; and breakdown pressure in sand is smaller than that in shale. With this finding, drilling parameters was adjusted accordingly and managed downhole pressure within the narrow safe mud weight window. The drilling experiences in well LD-6 has proved the advantages of drilling geomechanics techniques, especially in HTHP area. It can predict and mitigate drilling risks, optimize mud weight and completion diagram, improve operational safety and reduce costs.

This paper presents a method used in combination with Managed Pressure Drilling (MPD) to determine real time pore pressures while drilling a deepwater exploration well. Not only was the pore pressure accurately determined but additional procedures were implemented to improve efficiency. This deepwater well was the first time MPD used on a semisubmersible rig in Myanmar by both operator and the drilling contractor. MPD was used on all the well sections below the surface casing with the main objectives for MPD listed as follows: Safe and efficient drilling of the well to planned TD. Elimination of contingency casing strings. Enhanced influx detection. Determination of pore and fracture pressure while drilling. The expected pore pressure based on seismic interpretation for the well was provided by the geoscience team. It was presented as minimum and maximum pore pressures. Fracture pressures were provided as sand fracture (minimum) and shale fracture pressures (maximum). A large uncertainty in pore pressures was expected. MPD was combined with real time pore pressure prediction to estimate pore pressures. MPD procedures were reviewed and amended as required to reflect the actual well architecture, actual equipment, and rig capabilities. Most MPD projects are designed to maintain a Constant Bottom Hole Pressure (CBHP) and not to determine pore pressures. Since a significant pore pressure ramp was expected as soon as drilling started below the surface casing a solution had to be found. Methods to make connections and dummy connections were reviewed and discussed to assist the determination of pore pressures using connection and background gas indicators. The devised procedure could be used for all drillstring connections including any dummy connections made throughout the entire well to provide the real time pore pressure team with consistent data. Additional procedures were developed to ensure that bottom hole circulating pressures were maintained using a combination of MPD choke pressures and increasing mud weights while drilling. The paper presents the procedures that were developed and implemented to successfully drill the exploration well to TD. These procedures have now been field tested and proven to be successful not only to accurately determine pore pressures but also to ensure mud weight management. The procedures will be used again on future wells to determine pore pressures and manage BHP to ensure that maximum benefits are derived from MPD operations on deepwater exploration wells.

The managed pressure drilling technique has been widely applied in land to solve different technical and well control issues as well as ensuring the safety of field personnel. Offshore exploration drilling is one of the most challenging operations due to its nature of drilling hazards and facing environment. There is a great need of applying managed pressure technique in offshore drilling. A new MPD equipment is developed, which is named as pressure control drilling system (PCDS), and performs its first application in offshore drilling to reach its further potential. The PCDS is applied in an exploration well located in the gulf of Bohai to perform a near-balanced drilling operation for the purpose of reducing the density of drilling fluid. It utilizes the microflux control technique to precisely monitor the wellbore condition and detect the overflow and loss of circulation in time. The technique of constant bottom hole pressure is used by the PCDS to maintain the bottom hole pressure constant and minimize the fluctuations of bottom hole pressure during making connections and round trip, enhancing the drilling performance. The equivalent circulating density of 1.08-1.09 g/cm 3 is obtained by the proposed PCDS using the solid-free drilling fluid with a density of 1.03g/cm 3 . While nearby wells use the drilling fluid with the density of 1.15-1.20 g/cm 3 at the same Stratum. Cooperated with the drilling fluid of lower density, utilization of the proposed pressure control drilling system significantly avoids the formation damage. The chip hold-down effect is minimized by the proposed PCDS to increase the ROP. The average ROP of nearby wells is 4.02 m/h. While the average ROP of the well using the proposed PCDS is 7.23 m/h, indicating the increase of 80 percent. With the assistance of the proposed PCDS, the drilling team set a single bit footage record of 312.88 m and daily footage record of 163 m, which demonstrates a great improvement of operation efficiency. No drilling compliancy occurs during drilling in the target stratum. Utilization of PCDS dramatically minimizes the potential of well control and ensures the down-hole safety. This application is a successful attempt of the pressure control drilling system in the offshore operation, demonstrating the wide range of applications of the PCDS. Proper utilization of the PCDS can optimize the offshore drilling operation, prevent drilling issues such as well kick and loss of circulation, minimize the non-productive time and therefore reduce the drilling cost.

The fracture pressure in the reservoir is a function of reservoir pressure. Reservoir depletion will reduce the magnitude of reservoir pressure and consequently the reservoir fracture pressure. The fracture pressure changes because of reservoir depletion can lead to challenges like closure of mud weight window. Hence, the ability of predicting the fracture pressure changes due to reservoir depletion is a key for field development including infill drilling campaign. A reasonable amount of field data has been published across the oil and gas industry to understand fracture pressure reduction as a function of reservoir depletion. The data show approximately a linear relationship between the reduction of fracture pressure with reducing reservoir pressure. Several studies and laboratory measurements have also been made to assess the impact of the reservoir depletion on the fracture pressure. Almost all the studies and laboratory measurements show reduction of fracture pressure as a function of reservoir depletion. In this study, we present several field examples showing that severe reservoir depletion has little to no impact on the fracture pressure and consequently on the mud weight window. The examples show that heavily depleted reservoirs were drilled with high over balanced mud weight without seeing any sign of loss events. These observations are not fully aligned with what has been observed in the published field data.

A major operator in Malaysia planned to drill into a 6,000-ft horizontal thin-oil rim. The three-well campaign posed very challenging well deliveries for the operator due to potential losses to faults and karst zones, high uncertainty of reservoir productivity, long horizontal laterals, and openhole completions containing an Autonomous Inflow Control Device (AICD) with a low solids tolerance. An optimized drill-in fluid (DIF) and delayed filter-cake breaker were designed and tested to address the following challenges: reduced filtrate invasion, a targeted filter-cake breaking delay time, and high well production rates. In addition, there was a need for a mitigation strategy for total losses and the resulting impossibility of placing the delayed breaker across the entire reservoir section. A customized NaCl-based 9.2 lb/gal DIF with an optimally sized ground marble bridging package was designed to facilitate filter-cake removal using a compatible delayed acid-release cake breaker. This was achieved through the addition of special additives in the DIF to increase the acid solubility of the filter cake. The DIF also included special additives proven to facilitate liftoff of filter cake at relatively low differential pressure, and for enhanced thermal stability of the polymers used. Testing confirmed that the DIF filter cake was efficiently removed by the breaker within the customized delay time. Corrosion testing of the metallurgy used in the completion equipment demonstrated low corrosion rates at the expected 265°F bottomhole temperature (BHT) by both DIF and breaker systems. Laboratory test results confirmed a high return permeability of 97.5% using the integrated DIF and breaker system. Three wells were drilled in the thin-oil rim reservoir and were completed using this system without losses. A relatively high ROP of 90 to 175 feet per hour without differential sticking issues maximized drilling efficiency and reduced the overall drilling costs. DIF density and properties were controlled through a dump-and-dilute technique. The wells were drilled to TD, and the completions run without incident. After the breaker was spotted, sufficient delay time was achieved with which to remove the wash pipe prior to closing the reservoir isolation valve. Approximately two months after spotting the first breaker, the wells were brought online, and the actual gas/oil production rates of the three wells were 50% above expectation. This paper presents the design and successful application of an integrated DIF/breaker system for drilling and completing three of the most complex extended-reach wells drilled by the operator in Malaysia. The complementary designs of the DIF and breaker system components contributed to the successful drilling and production results of these three challenging wells.

Stretching the engineering limit in order to deliver a high pressure, wildcat well, ZT-1, driven by design optimization and allocated resources which resulted in well cost optimization. For a successful delivery of ZT-1 well, three (3) engineering limit focus area has been identified and tackled with proper risk mitigations for well design optimization. ZT-1 well was designed based on prognosed mid case PPFG, with sensitivity to high case PPFG. As per standard practises, exploration well design need to consider a drill kick tolerance scenario of 25bbls in 8-1/2" hole section. However, ZT-1 opted for a reduced drill kick tolerance of 10 bbls in order to drill the wildcat reservoir in one-hole section, by considering well operational point of view. Second focus area with regards to collapse and triaxial safety factor for 7" production liner. According to company casing design standard, full evacuation to atmospheric load case need to be considered for production casing, which failed in ZT-1 well design. Since the probability of the said load case to occur in ZT-1 well is very low due to its clastic nature, team applied risk based design approach by using actual data from manufacturer to enable the usage of said 7" casing. Third focus area linked to the lower hard cement pressure test value. According to company Pressure Containment and Control standard, casing should be tested after the cement is hard, to the lesser of 70% of maximum internal maximum internal yield pressure (MIYP), or FIT or LOT plus 500 psi, or 200bbls influx from max PP for exploration well. Since ZT-1 well is using the standard G-Cement, the limitation is on cement integrity that does not allow hard cement pressure test to meet the three criteria's, hence derogation was raised. The three-focus area was challenged with calculated risks and proper mitigations in place. For first focus area, real time pore pressure prediction, assisted by FPWD were utilized to assess the operational limits. A robust Total Depth (TD) decision tree criteria were developed, based on PPFG uncertainty and drilling was limited up to drill kick tolerance to safeguard the operations. Second focus area enable us to utilize current OCTG resources hence resulted in cost avoidance. The third focus area is to allow fast decision-making during operation in case of the plug does not bump thus will cause hard cement pressure test. These effective decision frameworks were developed without compromising the well and the cement integrity. The three derogations were raised to stretch the design and operational envelope set by company in order to deliver fit for purpose well design without process safety incident. ZT-1 was drilled safely to deliver the well objectives.

What constitutes a marginal field varies greatly but it is certain that extended time periods of low oil prices only magnify the challenges in developing such fields as it can stir even the largest reservoirs to go from commercially viable to marginal. E field is a marginal development project that must contend with all these unique set of challenges. For many years the project struggled to achieve minimum thresholds for funding. To develop the field during a low oil price market represented a cost-opportunity whilst presenting a value challenge. It is an extremely challenging thin oil rim reservoir development, under a complex and heterogenous geological environment, involving six long-to-extended reach wells in a loss-prone karstified carbonate. While the well planning and design built upon the Operator's considerable experience in carbonate and long reach drilling in the region, the campaign remained unique as the characteristic resided beyond the envelope of what had been accomplished before. The key distrincions were the much longer lateral length and the combined scope to target the thin oil rim in addition to the gas cap, which was the first-time application in this area. This is where technology played a vital part, as an enabler for delivering a complex project in a competitive manner. This paper briefly describes the planning stage of the campaign to ensure that the project was competitively scoped and delivered a fit-for-purpose solution, with focus on the technology implementation to address specific drilling challenges. Furthermore, it explains how a robust front-end loading, replication, and strong collaboration were key to making developable what was previously uneconomic.

Surge and swab pressure generated during pipe tripping operations tends to result in various wellbore stability and integrity problems. To monitor these problems, prediction of these differential pressure is required for the smooth functioning of drilling operations. An analytical predictive model is presented in this research for surge and swab pressure. This model is developed under steady-state condition for Yield Power Law fluid. A fluid filled wellbore with drill-pipe/casing is considered as two concentric cylindrical pipes for developing this model. In this concentrical cylinder inner pipe is moving at certain velocity and the outer pipe is stationary. Due to movement of inner pipe, drilling fluid will start displacing in annulus and results in pressure surges. A predictive model is developed by analytically combining the frictional pressure loss and mud clinging effect to forecast this pressure surge due to couette fluid flow phenomena in wellbore. The newly developed model (NDM) is validated with two existing analytical models and reported experimental data that are available in the published literature. A parametric analysis is carried out to identify the effect of various parameters on pressure differential. This research suggests that with the increase in pipe tripping velocity, surge pressure also tends to increase because of high viscous drag of fluid. It is also found that the increase in diameter ratio surge pressure also tends to increase due to large shearing effect between pipe wall and fluid. In conclusion this model is predicting the suitable range of tripping speed and diameter ratio under tolerable wellbore pore and fracture pressure to assure downhole wellbeing. Unlike most of the existing model, NDM requires less numerical analysis which make it easier to understand and apply in real case situation. The model considers mud clinging effect for precise prediction of surge/swab pressure gradient.

This paper provides insight on planning and equipment-selection processes to successfully ream and drill in 9 5/8-in. casing through a water-sensitive shale formation, followed by a two-stage cement job to isolate lost-circulation zones. Proper placement of cement all the way to surface would be essential for providing an additional annular barrier to prevent casing-to-casing annular gas migration. Selection of the equipment is dictated by the operation to be performed (i.e., drilling new hole versus reaming a tight section), the type of reamer or drill shoe used, selection of specialized drilling tools and centralizers, along with stage cementing tools with integral packing elements, among many other requirements. Current drilling with casing (DwC) applications allow for plastering cuttings to the wellbore wall, creating a barrier that minimizes fluid losses. It also reduces the annular clearance between the casing and the wellbore wall, thus improving velocity and hole cleaning compared to conventional drilling practice. And, by introducing a stage cementing tool with an integrated packer, the annular barrier can be set inside the previous casing string to facilitate two-stage cementing, thus enabling full circulation, with cement to surface. Currently, 23 wells have been completed using this approach. A few of these jobs stand out. In one case, the casing string was reamed 501-ft (153-m) for 7.75 hours at speeds between 20 and 25 rpm using an eccentric nose shoe with carbide cutting structure on the exterior. Following the first stage of cementing (with zero returns received at surface), the team inflated the packer element of the stage cementing tool and initiated the second stage of cementing. During a second bottoms-up circulation, returns at the surface indicated successful setting and a successful second-stage cementing job in a reamed hole. In another case, the string was reamed 316 ft over 3.75 hours with 20 RPM rotation, until the bottom of the conventionally drilled hole was reached. Using a specialized drilling shoe, the string was then drilled 301 ft over 14.75 hours with 20 to 50 RPM rotation to the desired depth. Based on the broad success of this technique, the service provider built a detailed database of field jobs. This database provides a better understanding of the parameters and recommendations for this application. These insights include how to improve standoff and minimize damage to the element while rotating by using rigid centralizers, implementation of shouldered connections to allow torque transmission without compromising thread integrity, recommended RPMs and torque based on internal and external components of the tool, among others. This well construction technique has saved hundreds of hours of rig time by enabling operators to drill with the two-stage cementer (with integral packer in the string) instead of having to continue drilling a problematic open hole with a conventional assembly and run casing afterwards. By performing successful two-stage cement jobs, the need to perform top cement jobs due to total losses is eliminated. And finally, the technique eliminates the need for conditioning the hole to allow casing placement at TD, an operation that would require an additional trip with a dedicated bottom hole assembly (BHA).

Qiongdongnan Basin has deep water and narrow pressure window in South China Sea. In the process of drilling, it is often accompanied by complicated conditions, such as gas invasion, well leakage and breath effect during drilling. Therefore, we have carried out long-term research and practice. According to SPP, dc index, drilling fluid displacement and density and so on, we established a real-time gas invasion early warning neural network model. We formed multi factor measures to prevent lost circulation during drilling. We have drilled more than 20 deep-water narrow pressure wells, and the success rate of drilling reached 100%. Key words: Ultra-deepwater drilling; Narrow pressure window; Gas invasion; Well leakage; Breathing effect

In 2016 PETRONAS embarked on the challenge of drilling and completing high temperature, highly deviated fractured carbonate development wells using Pressurized Mud Cap Drilling (PMCD) techniques. With equivalent formation pressure gradients of 13ppg, H2S levels of 140ppm and formations with potential for massive losses, but also very high gas productivity, severe challenges were presented to the drilling engineering and operations teams and to the logistical infrastructure; these challenges were successfully overcome, ensuring that the wells were delivered safely using the planned Tender Assisted Drilling Rig. Maintaining well control integrity throughout all drilling and completion operations is always crucial to ensuring safe well delivery. In wells with total losses, drilled through highly productive carbonate formations, there is a high risk that any loss of the primary drilling fluid barrier may result in the well flipping out to gas very rapidly. This risk is highest during trips out of the hole, when the Rotating Control Device (RCD) pressure seal must be removed to retrieve the drilling BHA and run the lower completion. For wells with total losses, options to control the well during trips have traditionally involved a combination of methods including setting gunk plugs, setting composite bridge plugs, or using a preinstalled Downhole Isolation Valve. The purpose of this paper is to present a fourth option, the top-kill method using a dual-density fluid system. During the 2015-2016 PETRONAS development drilling campaign, following thorough risk assessments and detailed planning and logistical evaluation, this method was proven to be a reliable and safe means of controlling the well during trips. A total of five (5) wells were drilled from the development platform, using a surface BOP stack and an RCD. Top kill operations were engineered by pumping two types of fluid into the annulus at surface; a slightly underbalanced Light Annular Mud and a heavier density Kill Mud. By combining these fluids, the well was put into an engineered overbalanced state, with the loss rate controlled via a pre-determined pumping rate. Once the RCD seal element was re-installed, the well reverted back to pumping Light Annular Mud into the annulus as per normal PMCD procedures. This paper highlights the meticulous planning, execution, training and continuous learning that was evident in these challenging operations. This paper also discusses critical HSE concerns and makes recommendations for future PMCD projects.

Over the past decade, three mega-trends have created a groundswell of worldwide demand for government regulations on well construction activities. The first, hydrocarbon exploration and production in remote places and in reservoirs that are difficult to access and/or produce. The second, technology developments that have gradually redefined the boundaries of "conventional" in the different codes of practice. And the third, and perhaps the most important, is the renewed and urgent focus on environmental impact and sustainability, hastened by the rise of alternative sources of energy and the industry's serious and preventable incidents. In addition, as organizations cut costs and make their best to navigate the low oil-price environment, there is an admitted concern of regulators (e.g. BSEE, HSE and PSA, 2017 ) that such optimization could result in squeezed margins in assets, operating systems and organizations. In response, regulators have moved toward standardization. Most operators have welcomed this approach, as criteria for approvals are clearer and equipment development costs decrease as a result of the shared functional specifications. For well construction, one of the key industry initiatives to address the major system level risks relies on independent Well Design Verification/Assurance. It consist on applying disciplined engineering processes to examine a given design and analytically determine conformity with requirements (after API TR 17T8, 2015 ). The specified requirements include the mechanical integrity, life cycle service, and other survability requirements. This tool is an independent compliance assessment. This paper describes the approach, major elements and high key considerations derived from accumulated experience of performing independent Well Design Verification for different clients and operators around the world.

Pore pressure prediction and geomechanical modelling play a very important role in well planning. The exploration focus worldwide is moving more and more into the challenging environments. Well planning and design in high pressure high temperature (HPHT) environments comprise numerous challenges such as play identification and prospect de-risking to drillability and development to production. Overpressure prediction is one of the principal challenges facing the oil industry today, as exploration focus worldwide moves further into the HPHT environments. Pressure related problems in HPHT wells include well control incidents, lost circulation, formation breathing, differential sticking, reduced rates of penetration, and reservoir damage, many which can potentially lead to expensive sidetracks, well abandonments and underground blowouts. A better understanding of the prevalent pore pressure regimes including generating mechanisms, pressure maintenance and dissipation through geologic time enables invaluable insight into these challenges and the ability to mitigate or minimize them. It is important to analyse the challenges prior to drilling so that various plans and systems can be established. Once the pore pressure regime is well understood, the next step is to understand the stress regime. Thus building a geomechanical model is the next key element for well design. The stress model can be used for wellbore stability analysis to understand wellbore failures and help in thedesignof optimum mud weights. Additionally in HPHT environments, thermal-induced stresses and their impacts on stability must also be considered. This understanding helps in modelling wellbore failures due to heating and cooling arising from mud circulation. Other considerations including drilling through faults can set another aspect of wellbore failure which could further complicate the already difficult drilling situation. This paper presents a case study on using geomechanical evaluations to reduce drilling risks and costs in a high-pressure/high-temperature (HP/HT) well located in offshore Asia Pacific. The major risk anticipated for this well, which was drilled to explore a deep-play (>3.5 Km), was high-pressure (>10,000 psi) and high-temperature (>2000C) with narrow margin drilling conditions. The geomechanical study provided inputs for an effective well design.

Shallow gas seepage was first spotted at a central processing platform offshore Malaysia in 2010, acknowledged as Platform T in this paper. Frequent monitoring of the gas seepage was performed through ROV baseline survey and a comprehensive geophysical survey was conducted to understand the characteristics of the gas seepage and to ensure that the integrity of the foundation at Platform T was not compromised. The origin of the gas could not be ascertained at that point of time. A soil investigation campaign was performed in 2016 to study the origin of the gas seepage. Two boreholes were drilled; a composite borehole to 150m below seabed for the purpose of soil sampling and in-situ testing and a pilot hole to 155m below seabed, which was later converted to a fit-for-purpose relief well as an alternate migration path for the gas. During the soil investigation campaign, dissipation tests were performed at several layers which were potentially the source or migration path for the gas. Five soil samples were segregated for headspace test to identify the gas type which subsequently can be used to identify the origin of the gas. Dissipation tests performed at four depth intervals indicates pore water pressure less than 20% of the vertical effective stress and appear to continue decreasing if the test had not been stopped. It was concluded that a low to negligible amount of excess pore pressure exist in clayey silt layers. Results from headspace test show presence of methane corresponding to the clayey silt layers as reported in the boring logs. The gas most likely comes from biogenic sources, feeding on organic matter in situ over a large depth range. It is unlikely that there are large pockets of gas in the soil due to its homogeneous clayey nature and the lack of excess pore pressure in other permeable clayey silt layers encountered. Instead, it is more likely that when pore water at certain depth encounters a more permeable path, such as a borehole, it rises up through this path due to the temperature gradient in the soil. As the water rises, the pressure decreases, which could cause gases dissolved in the water to come out of solution and form bubbles. As a result, the gas will have no impact on the integrity of the foundation at Platform T. The fit-for-purpose relief well design as well as adopting headspace testing can be used to address the shallow gas issue at Platform T in a cost-effective and efficient manner.

In some wells, especially those drilled through fractured formations, the difference between the fracture pressure and the reservoir pressure becomes narrow. In these wells, maintaining ECD within the limits of fracture and reservoir pressures is a very challenging task, as many parameters have to be adjusted simultanusly to maintain the ECD. When changing the pump rate and the backpressure to maintain the ECD within the MPD window, drilling fluid mass will change and an extra amount of fluid will be accumulated or released from the system as a result of the transient flow. A numerical model is developed to enable the computation of the system mass change at any time due to change of the drilling parameters, which has to match the difference between the inflow and outflow. Any deviation will be interpreted as an external mass source (formation influx) or leak (fluid losses) and this can be used to enables early detection of losses or of formation influxes.