This paper describes the implementation of pressurized mud cap drilling (PMCD) technology, a variant of Managed Pressure Drilling (MPD), a successful technique frequently used on oil and gas fields in Kazakhstan. It also considers the planning phase, operational aspects, and results of drilling with the PMCD technique through challenging formations. PMCD technology with a rotating control device (RCD) is a form of blind drilling, where the drilling fluid and formation cuttings are not transported to the surface. It is a non-conventional drilling technique designed to maintain annular wellbore pressure to prevent total loss of circulation. A sacrificial fluid (SAC) is injected through the drill string and light annular fluid is pumped down from the annulus to maintain borehole fill and prevent annular gas migration. Wells in this field have encountered uncontrollable losses while drilling sections of the fractured carbonate. As a result, the application of PMCD technology to meet those challenges was an obvious choice in order to achieve target depth. Conventionally drilling of the 8-in. section resulted in fluid losses of more than 450 m3. Consequently, passing through these challenging zones the rig crew switched from conventional drilling to PMCD. The wells were then successfully drilled using the PMCD method, without any issues or well-control incidents, and planned TD was attained. By enabling the client to reach TD, Weatherford PMCD equipment transformed a previously undrillable well into a potentially valuable asset. This operation demonstrated that PMCD can be a viable drilling technique for future wells in the field. PMCD technologies included reduced consumption of lost-circulation material (LCM) and reduced loss of mud to the formation, keeping the wells economically viable. The main objectives of these wells were to drill safely and efficiently to target depth (TD), to deliver the wells for production on schedule, reduce non-productive time (NPT), minimize the drilling risks and hazards, and optimize the drilling program.

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An increase in differential sticking events, due to depletion of the reservoir and high angle wells being actively drilled in recent years, was a primary driver to utilize Managed Pressure Drilling technology in the Tengiz field. MPD offers a more dynamic and rapid wellbore pressure control by being able to adjust the surface back pressure applied at the annulus for a given mud weight, decreasing the risk of differential sticking while maintaining constant bottom hole pressure conditions. The paper describes the results of the first Managed Pressure Drilling application in the Tengiz field and experience gained during execution where drilling multiple formations together enabled the target depth to be reached without NPT. It further highlights the operational complexity and the challenges faced during the implementation of this technology while drilling formations with varying pore pressures. The reservoir hole section had different pressure intervals, which required higher mud weight and thus high potential of differentially stuck-pipe conditions. The successful field trial shows that the Constant Bottom Hole Pressure (CBHP) application provides flexibility to be able to manage annular pressures when applying surface back pressure using an MPD choke manifold. The paper elaborates on the lessons learned and how CBHP was implemented continuously with regards to health, safety, and environment (HSE) during drilling operations. The short-term goals were to evaluate whether the application of MPD could avoid the risk of differential sticking and reduce pumps-off gas, enhance drilling performance by using lower ECD, reducing well control time by working as early kick detection tool and provide a potential for mud cost savings, along with a long-term goal of providing the option to optimize the casing design by reducing one liner section and combining drilling of two reservoir sections in one run.

This case study describes the approach taken when drilling an 11 5/8-in. hole section through a salt formation on the Chinarevskoye field in the West Kazakhstan Oblast region where high-intensity brine influxes and subsequent flow had been encountered. The intensity of the brine flow, when encountered, had ranged from 5,000 to 6,000 L/min at an equivalent kick density of 2.2 SG, and it is believed to be among the most intense brine flow experienced in the world during drilling operations. Standard well control measures proved to be inefficient because of the narrow margin between pore pressure and fracture pressure gradients. Several techniques were applied to combat such influxes in a safe manner with minimum associated nonproductive time (NPT). The high-pressured formation in this hole section is associated not only with brine influxes, but also with losses and gas increase scenarios. As a result, the company adopted unconventional drilling techniques with a combination of planned flow-while-drilling (FWD) and mud-cap drilling techniques to reach total depth (TD). These two techniques created a viable and cost-effective solution to mitigate such challenges, helped the company to drill to the planned section TD, and consequently complete the well within the defined authorization for expenditure (AFE) without associated NPT. The paper will cover and emphasize techniques, along with details on running casing and cementing the hole section, which required an unconventional approach for success. The paper will also briefly outline the equipment used, such as rotating control devices (RCDs), a choke manifold, and a separator when drilling this section and their limitations. Despite the complications, the well was successfully drilled, and this experience provided an opportunity for learning. The marked improvements in well control, loss management, and cementation displayed that combining knowledge and experience can reduce the negative impact on well costs when drilling similar cases.

This paper describes the development and field deployment of a new downhole isolation valve system called the Retrievable, Instrumented & Tandem Downhole Deployment Valve (RIT-DDV). The purpose of this technology is to provide a temporary mechanical barrier to isolate and monitor the well during drilling operations in an environment where a full column of single-phase fluid cannot be maintained. The RIT-DDV is based on predominantly used downhole isolation valve (DIV) design and technology, which is a hydraulic flapper-type isolation device installed in the casing that seals the open hole during pipe tripping operations. The key features of the new RIT-DDV systems are dual flapper valves with three downhole pressure and temperature gauges to take measurements above, between, and below the flappers. The advantage of this configuration is that it enhances safety by enabling double-block-and-bleed system functionality, providing valve redundancy, and moreover allowing for continuous real-time monitoring of downhole well conditions. In addition, the RIT-DDV is designed to be reusable and can be tested upon installation and replaced if necessary. The RIT-DDV system enabled the operator to isolate and monitor the well while drilling through a depleted formation that prevented drilling with a full column of single-phase drilling fluid. The RIT-DDV was successfully trialed in western Kazakhstan and demonstrated the potential of this technology to enhance the safety of drilling heavily fractured carbonate formations with reservoir fluids containing hydrogen sulfide (H2S) / carbon dioxide (CO2) that are prone to total loss of circulation. The downhole pressure / temperature monitoring capabilities that the system provides within the casing string helped drill through the depleted fractured carbonate reservoir section without incurring non-productive time (NPT).