Managed pressure operations enable keeping the equivalent circulation density (ECD) within a narrow pore-frac pressure window during drilling and cementing while maintaining the wellbore stability and controlling formation pressures. The operation becomes more complex during a cementing job, where fluids with different density and rheology parameters are pumped downhole at varying rates, resulting in different friction pressure profiles. Proper numerical simulators must be used to model such variations and keep the downhole pressure between the pore and fracture pressures during the operation. Managed pressure techniques and technology were critical to the successful cementation of the 7-in. liner at 12,000 ft. in a gas field in Saudi Arabia, across formations ranging from a high-pressure zone with 2.36 SG (19.65 ppg) formation pore pressure to a depleted low-pressure formation with 2.44 SG (20.32 ppg) fracture pressure. The challenge in this job was to maintain the ECD at 2.40 SG (20 ppg) throughout the cement job to avoid any losses or flow from the formations. An automatic choke setup on the return flow line with a dynamic control system was used to drill the 8.375-in. open hole with KCl polymer mud. Precise cementing simulation was used to determine the ECD during cement placement. Numerous pre-calculations and simulations were run to evaluate various scenarios prior to the cement job to ensure effective manipulation of back pressure through managed pressure drilling (MPD) equipment to maintain ECD at the desired value throughout the cementation process. The detailed simulations run by cementing and MPD engineers prior to the job and a collaborative approach were instrumental in defining a final cementing plan, completing the layout of equipment used for the cementing job, and executing the job with real-time monitoring of all critical parameters affecting ECD and evaluation of the cement job.

Gas Migration through cement columns has been an industry problem for many years. The most problematic areas for gas migrations occur in deep gas wells. To control gas migration, cementing practices should be optimized. The cementing practices include cement composition, drilling fluids composition, spacer composition and operations such as pumping procedure and pressure testing. Gas migration can occur due to settling in high-density cement slurries. Cement densities required to successfully cement the zone could be as high as 170 pcf (Pounds per Cubic Foot). As cement slurry sets, hydrostatic pressure is reduced on the formation. During this transition, gases can travel up through the cement column resulting in gas being present at the surface. Gas migration problems can also occur due to poor displacement. Spacers, cements and drilling fluids should be designed and tested for compatibility for good displacements and bonding. Different types of spacer is required for each type of drilling fluid such as salted drilling fluid or oil based fluids. Testing should include running rheology tests, thickening time tests and compressive strength development tests. Cement shrinkage is another factor that can cause gas migration problems. Expansion additives are usually added to overcome this problem. However, attention should be made to optimize the concentration and type used to avoid over expansion behavior that can cause micro cracks in the cement matrix. Different cycling effect in temperature and pressure can cause gas migration channels due to creation of micro cracks. This paper highlights some of the effort to prevent casing/casing pressure leaks from deep gas wells.

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Liner lap testing operations in the gas fields have evolved to include shoe track drill out operations in the same trip. Typically, a drilling BHA is run and spaced below an inflow test packer to drill out the shoe track to 20ft above the shoe. A landing sub or no-go lands in the liner top at the predetermined bit depth to activate a test packer mechanically. This order of operation exposes the packer elements to debris circulated from drill out operations resulting in damage to the packer elements or incorrect engagement of the packer elements and casing ID. Deploying a hydraulically activated collapsible land sub in conjunction with the mechanical inflow test packer allows a change in the order of this operation. The collapsible landing sub is run in hole below the test packer and lands in the liner top to facilitate the packer activation. The liner lap test can be conducted with little or no drill-out debris in the well. Once the liner lap test is considered successful, the landing sub is hydraulically collapsed allowing entry into and below the liner top. Drilling operations can then resume without concern to packer element damage. Applications of this system include liner lap testing and any subsequent drilling operation in the same trip. This paper introduces and discusses the step change in operational liner lap testing procedures while incorporate this new approach to market technology of the collapsible landing sub. It describes the lesson learned and the limitations of the previous method of conducting this operation. It analyzes and compares actual job data and success rates between the previous methods and methods incorporating the new technology. This paper shows that using the collapsible landing sub in conjunction with the mechanical in flow test packer cost reduction and increases reliability and profitability in these operations.

Since the beginning of drilling for oil, improving efficiency and reducing the cost of hydrocarbon recovery have been key issues when designing a well. Since then, new methods and techniques have developed the industry. One of the most critical events in the oil and gas industry was the invention of the liner hanger. Since Liner Hangers are utilized as the primary solution to wellbore construction, they have been designed with such requirements in mind. This paper will deliver an insight to an innovation life cycle where a stakeholder collaborated together to successfully deliver, plan and complete the first 15,000 PSI, 400 °F high pressure- high temperature (HPHT) Liner Hanger designed to overcome the operational obstacles that conventional liner hangers have when deployed with Multistage Frac (MSF) completion systems but still allows for successful operations in cemented completions. This liner hanger technology has been run in different parts of the world and has proven since the beginning that with all the features included in the designed stages.