In 2018, an operator in Malaysia completed a sidetrack campaign consisting of injector wells. These wells were planned for maximum productivity via sustainable wellbore zonal isolation. The presence of Carbon Dioxide (CO2) in these wells elevated concern about the zonal isolation of cement across the interval. Moreover, for an injector well, the cement must exhibit resilient properties by design of enhanced mechanical properties to provide long-term isolation based on a cyclic wellbore. An advanced slurry system was designed that enabled the set cement to manifest superior properties in three parameters—corrosion resistance against CO2, flexibility against wellbore stress changes, and expansion to mitigate microannuli. The design of the slag-based flexible cement system with expanding additive (slag-flex) considered all three parameters in the fit-for-purpose application of a resilient and flexible expansive cement system in a CO2-rich well. The system’s mechanical properties, such as Young’s Modulus, Poisson’s Ratio, and tensile strength, were verified with laboratory-scale testing and validation against stress analysis software to confirm on the resilient and flexible properties. The laboratory testing result demonstrated the improved properties of the system, including high tensile strength and low Young’s modulus. Furthermore, the reduced water content of the system decreases the permeability of set cement and thus increases resistance towards corrosive substance such as CO2. For certain cases in the past, two separate slurry systems had to be designed—a lead slurry with CO2-resistant properties and a tail slurry with flexible and resilient properties. Often, several issues arose from this practice, including complex logistics due to cement silo blend arrangement and complexity during job execution. Hence, this new system presents a novel idea and methodology that will deliver value to the oilfield industry by integrating CO2 resistance, flexibility and expansion properties in a single slurry system. The system was successfully pumped in wells in Malaysia; no sustained casing pressure has been recorded to date, and wells have been delivered to their intended zonal isolation requirements without compromising well design and overall integrity. This is an innovative application of this type of cement system in the region, and the long-term zonal isolation and well integrity assurance in these and future wells have the potential to save millions of dollars in remedial work. The cement system is currently recognized as the default technology for CO2-rich injector wells in Malaysia.

Effective zonal isolation in wellbores with a challenging mud removal environment is well known to be very difficult to achieve. In wells at the technical limits of Non- Aqueous Fluid (NAF) removal prior to cement placement, cement bond quality and hydraulic isolation can be compromised by leaving channels behind the casing, which can result in several long-term well integrity issues. An Interactive Cementing System (ICS) is developed through special experimental methodologies to mitigate mud channeling issues and improve zonal isolation, by immediately interacting with any residual mud channels left in the well after cement is in place, hence reducing the permeability of mud channels and sealing off microannulus gaps. Casing centralization is considered to have the greatest influence on mud removal efficiency because it directly affects the flow movement on each side of the wellbore. Mud removal has been studied from numerical simulations, laboratory experiments, and field results, and these show that good mud removal can be achieved only when adequate casing standoff is achieved during cementation. In modern wells where there are many operational restrictions and limitations, especially in highly deviated and horizontal wellbores, final cement designs may not allow good casing standoff and thus not all of the best practices for effective mud removal can be applied. The objective of the innovative cement system is to have a design that interacts with residual mud in the annulus to "fix" the channels, thereby enhancing cement bond quality and zonal isolation. Two detailed case histories of the application of this technology in the development campaign showed visible improvement in cement bond logs using the ultrasonic imaging tool as compared to offset well that was cemented using a conventional cement system. After two successful implementations, the ICS was selected as the cement system of choice for wells with challenging mud removal.

In August 2014, PTTEP International started an appraisal drilling campaign in M9 block offshore Myanmar. The scope of work was 10 wells to be drilled using a moored semi-submersible rig. The purpose of these wells was to further firm-up the hydrocarbon potential of the field and also to find additional reserves within the Zawtika gas prospect to support field development plans which included platform installations in future project phases 1B & 1C. Therefore, ensuring integrity and proper well isolation for drilling, testing and well abandonment purposes was of critical importance. Maintaining operational integrity and surface efficiency is also highly required considering the challenging conditions typical of any remote location like Myanmar.Offshore project management in Myanmar is quite challenging. Many operators find that the far distances from out-of-country support facilities and load-out points to well locations make logistics a critical success factor with huge potential to affect cost and key performance indicators. In this project, the requirement from fast-drilling and high frequency of cement jobs it was important to eliminate any issues arising from design and preparation. One of main technical challenges was overcoming the risk of lost circulation. The top-hole operation required the dual 30Љ ϫ 13-3/8Љ casing with both annuli being cemented in single operation and achieving cement returns to seabed.For operation integrity, a project support model has been set up to manage and achieve flawless service delivery starting with a comprehensive Project Readiness Assessment (PRA) tool enabling full analysis of all requirements: technical engineering, project logistics coordination necessary between bases in Thailand and Myanmar, detailed materials preparation & load-out procedure, equipment maintenance procedure, and communication protocol. During the project, deepwater operation integrity management tools were deployed to manage processes as per standard for every single cement job to satisfy design, execution and evaluation requirements. As a result, 10 out of 10 wells in M9A project have been delivered to expectation without any operational failure or cementing-related non-productive time. To maintain equivalent circulating density within limits imposed by formation properties, all primary casing cement slurries were pumped at densities below 15.0ppg, including gas-tight slurries where necessary. To mitigate the risks of loss circulation across the critical intermediate formations, a proprietary, new fiber-based LCM technology was introduced and deployed successfully, notably for the first time in Myanmar.The Appraisal campaign has been completed in May 2015 with all wells successfully drilled and abandonment barriers installed without any annulus communication incident, well barrier leak or regulatory-recordable HSE or well integrity issue. The project is a real example of team work between the operator and service company, application of fit-for-purpose solutions, and use of transformative quality man...

Monobore cementation is defined as where a single production tubing size runs from the pay zone all the way to surface and is cemented in place. This type of well design greatly reduce rig time and cost. The challenge however is to achieve a good cement in the annulus as a well barrier and to have a clean internal tubing after the cementing job to allow for successful production of the well. To achieve a clean internal tubing, a distinct bottom and top plugs were used as a means of mechanical separation. For fluids design, mud had to be thinned down prior to the cementing job and, a designed fiber based spacer system was used to physically scrub any mud-film sticking on the tubing walls. The centralizers and cement system were designed to allow for efficient displacement of mud and hence providing good overall placement and top of cement in the tubing-casing annulus. The cement in the annulus will be verified by pressure testing the annulus to 500 psi higher than previous shoe leak-off. This approach was implemented for the campaign of six wells, all designed with 5-1/2in monobore tubing. The bottomhole static temperature (BHST) of the well ranges from 300 to 350°F. The cementing system also had to be designed to cater to the challenge of this field, having CO2 as high as 60%, high temperatures, and a long open hole section that requires isolation and cement to set within a required timeframe. The cementing jobs were validated by no losses or gains during the job, floats holding at the end of the cementing job, differential pressure of cement prior to bumping the plug, density and pump rates executed as planned, accepted pressure test criteria of the annulus, output validation of cement contamination in pipe and annulus based on fluids and final well information. To further validate this system, the cement bond log was also run as part of the evaluation process and the cement log showed that zonal isolation was achieved. After the perforations, the perforation tool was pulled out to surface and the tool looked very clean with no signs of contaminated mud or cement around the tool. We demonstrate how this unique cementing approach can be a solution for the challenges of monobore cementing and one of the biggest problems of monobore cementing in the industry.

As Malaysia’s first tension leg platform, the Shell Malikai project, represents an unconventional approach towards deepwater operation in this region. In a field embedded characterized by reservoir drawdown from adjacent production wells, the lowest cementing margin is 0.65 ppg. Annular gaps between casings of as tight as 0.53 in each side further elevates the equivalent circulating density (ECD). Cementing software simulation predicts risk of heavy losses during cement placement and subsequently lack of isolation between multiple hydrocarbon-bearing zones. The loss of zonal isolation would mean crossflow between the reservoir. At worst case, some of the water injector wells may be abandoned due to inability to inject into the target reservoir and uncertainties of injection efficiency. This represents a significant loss of capital investment. A two-pronged solution has been developed to secure the long-term well integrity of the deepwater project. Implementation involved front-end design, modelling, planning, and execution. Two-stage cementing is a technique by which selected intervals along the casing can be cemented in separate stages. It reduces the risk of losses due to long column of cement slurry exerting high hydrostatic head towards the weak formation. In 11 3/4in liner with tight annular gap, the risk of taking losses is high. Therefore, two-stage cementing was employed, combined with specialized blended lightweight 11.5-ppg cement. First-stage cement will provide good liner shoe strength for drilling ahead, and second-stage cement will provide zonal isolation for two hydrocarbon zones near the top of the liner. For 9 5/8in liner, due to the presence of a pressure ramp at the top of the section and weak formation at the bottom, managed pressure cementing (MPC) was the chosen approach to mitigate the risk of losses. MPC is a technique that enables cementation to be conducted in a hydrostatically underbalanced condition where surface backpressure (SBP) is applied to maintain the bottomhole pressure between the highest pore pressure and the lowest fracture pressure of the well. The combination of MPC and two-stage cementing, together with other existing best practices, formed an integrated solution in narrow margin cementing. This has resulted in flawless cementation for two water injector wells. No losses were observed during cement displacement, there was no gas migration, and the liner top packer was successfully set, and pressure tested in MPC mode. A subsequent cement log confirmed the top of cement requirement was fulfilled. The paper will further explain on how this unconventional technique were planned and executed.