Completing primary cementing operations under the rig floor (also known as offline cementing) instead of conventional cementing is an emerging approach that continues to gain industry interest. This is because of the opportunity this method presents for reducing operational flat time and optimizing rig use, resulting in significant cost savings. It is essential to relate the concept of offline cementing with regards to hydrocarbons (HCs) presence in the formation. Offline cementing is a straightforward method when there are no HCs present in the wellbore and when the pore pressure is at hydrostatic. A single barrier in the form of overbalance mud weight is acceptable for this condition. However, when HCs are present and/or over-pressured formation, a dual barrier (mechanical and Kill Weight Mud, KWM) is necessary to help prevent uncontrolled influx from the borehole to the external environment. During the Malaysian operation discussed here, this barrier requirement was also essential to local regulatory procedures and guidelines for upstream activities as well as the operating company's technical standard for well barriers and integrity. Thus, two well barriers were required during all well activities and operations. A dual barrier offline cementing (DBOC) system with special application of Treating Iron Works Valves (TIW Valves) and a Subsea Release (SSR) plug set was constructed to enable offline cementing within the HC section. This concept not only allowed cementing job to be executed, but at the same time allows other offline drilling activities, such as surface equipment rig-up, pressure testing lines, pre-job circulation, and cementing operations to be done while at the same time maintaining the two-barrier requirement while the blowout preventer (BOP) is removed. A new set of challenges were encountered while completing offline cementing across a HC section. Because the environment for placing a competent cement slurry was not optimal, the quality of the wellbore seal could have potentially been affected. Thus, a tailored job procedure coupled with continuous engagement between the operating company, service partners and rig owner (through joint risk-assessment sessions) established alignment and suitability of individual operations. The cement slurry design was carefully tailored, and a detailed computer aided simulation was performed to help ensure cementing operations could be accomplished without compromising operational objectives. As a result, the DBOC concept was successfully implemented for the first time in Malaysia across three highly deviated development wells, thus streamlining cementing activities. A recent collaboration in a major Malaysian National Oil Company (NOC) is highlighted, discussing the materialization of unconventional offline cementing objectives across a HC section in a challenging wellbore environment while minimizing rig time and maintaining safety standards. Various challenges encountered are discussed with the intention of sharing information and industry lessons learned. The application of the DBOC system could be a game-changer, offering significant variation from the conventional rig floor cementing currently being practiced.

Setting multiple plugs across a horizontal well can be a challenge. One way to do this is using the "pump and pull" methodology to achieve the objectives set out by the project team. Tailoring of the cement slurries and the execution of cementing operations for the successful deployment of multiple cement plugs using this method to achieve a dependable barrier across a horizontal reservoir section will be reviewed and discussed. A development well in Malaysia lost a bottom hole assembly (BHA) in their 8.5" hole section. This resulted in the requirement to abandon a long horizontal section along with the requirement to spot a 2,100 ft continuous cement plug on top of the BHA to abandon the well. The main challenge for setting a cement plug across a horizontal section, is cement slumping and stuck pipe, which might result in repeating cement plug jobs or non-productive time having a negative impact on well economics. To achieve isolation objectives in the first attempt, this long continual plug was broken up amongst four smaller individual plugs "stacked" on top of each other. The first 3 plugs were designed to each be 600 ft in length followed by a 340 ft plug. To avoid cement slumping, a cement support tool was deployed above the BHA before the first plug in the horizontal section. The first three plugs were placed in the horizontal open hole section and the fourth plug was placed at an inclination of 75 degrees, all using the "pump and pull" method. The pump and pull method is a common practice for worker operations with coil tubing and this similar technique can be applied in ERD drilling operations to aid in the homogeneous and accurate placement of cement plugs. However, for this job, the pump and pull placement method was preferred to aid in the homogenous and accurate placement of cement slurry through the horizontal open hole section. Detailed job calculations, the slurry design which was tailored for this application along with detailed operational procedures which resulted in the successful placement of all plugs on the first attempt under challenging well conditions will all be discussed. The approach utilized here resulted in the successful placement of a 2,100 ft continuous plug which isolated the BHA and saved the project valuable rig time. Similar approaches can be used in other areas to achieve successful results in first attempts to help well economics.

Open Hole Stand-Alone-Screen (OHSAS) design have been used in the oil & gas industries to monetize unconsolidated reservoirs. Design steps includes optimum screen selection, drill in fluid & breaker design, running in hole procedures, bean up plan & post tie in monitoring. This paper will discuss in detail on overall strategy implemented during OHSAS deployment in Field A, involving 4 horizontal oil wells in AABB reservoir & its post-production results. OHSAS is selected based on sonic travel time info showing >90usec/ft, Unconfined Compressive Strength (UCS) value ranging from 3000-5000psi & historical sand production. History from offset wells completed with pre-perforated liners, suggested 8 out of 9 wells had history of sand production once producing with high water cut. Screen selections was design based on Particle Size Distribution (PSD) data performed through Laser Particle Size Analysis (LPSA) & Sieve Analysis using samples from conventional & side wall cores. Several samples were then selected to execute the sand retention test (SRT) on different screen sizes & types. Screen placements across the horizontal open hole was designed into segmented zones with swell packer & Autonomous Inflow Control Device (AICD) were used to balance flow contributions along the horizontal sections and GOR control. Modelling work was performed to decide on well segmentation, sensitivity on rates, pressure drop across completion and erosional risks assessments. Selection of drill in fluid & breaker fluid system were designed to ensure the horizontal segment can be drilled effectively with optimum bridging, less susceptible to formation damage & screen plugging. Lab tests conducted to facilitate selections for all wells were production screen test, Permeability Plugging Test & Return Permeability Testing using core samples. OHSAS deployments were strategized to avoid stuck risks associated through dog leg severity management, torque & drag analysis with deployment of optimum centralizer placements to reduce dragged & placement of optimum number of swell packers. Optimization on lower completion were performed based on actual logging resu lts to improve overall well performance through isolation of shaly or gassy segment using blanks, use of tandem swell packer in gas segment & use of optimum AICD valve numbers. Post completion, specific bean up program was followed to ensure natural sand packing is properly established in the annular space between screen face and the open hole segment within allowable drawdown. Real time monitoring on flowing parameters especially bottomhole pressure through PDG & sand rate (if any) were performed during well tests. Multi rate test & Pressure build up (PBU) test verified that all 4 wells were able to meet at least 20% higher production rates than plan, with no major sand productions produced at surface. The holistic approach outlined in this paper is important in achieving long lasting application of OHSAS in unconsolidated reservoir right from design to production phase.