Summary Tensile and shear failures are two common cement-sheath failure criteria. Tensile failure occurs when a stress on the cement surpasses the tensile strength of the cement, and shear failure happens when a stress exceeds the shear strength of the cement. The objective of this study is to introduce a laboratory method that investigates the effects of fatigue (cyclical loading) on the cement sheath. Chances of cement-sheath failure also increase when the application involves high-pressure/high-temperature conditions; therefore, this test setup is rated to 25,000 psi and 450°F. In this method, fatigue-failure cycle and stress magnitude could reveal the extent of the fatigue tolerance of different slurry designs relative to each other. One could program and adjust casing pressure (Pi), pore pressure (PP), temperature, cycle intervals, and ramp rates to conduct a cyclical-loading test automatically. Failures caused by thermal and stress loading may occur as a result of temperature and pressure-induced stresses created by well events such as hydraulic fracturing, cyclic steam injection, steam-assisted gravity drainage, production, completion, or remedial treatments. Thermal and stress cycles could impose a risk to zonal isolation and lead to a delay in hydrocarbon production. Studying such effects could be helpful in developing a better understanding of the cement-sheath-failure threshold and, in fact, could be complementary to mechanical-properties measurement. The cement sheath fails after a certain number of cycles when reaching its fatigue-endurance limit. This research showcases examples in which the fatigue-failure cycles were identified for 1,000-, 2,000-, and 5,000-psi pressure differentials between the pore pressure (exposed to the outside of the sheath) and the casing pressure. For these experiments, the pore pressure and temperature were held constant at 15,000 psi and 330°F whereas the casing pressure varied cyclically between 15,000 and 16,000 psi (Set A), 17,000 psi (Set B), and 20,000 psi (Set C).
Chances of cement sheath failure increase considerably when the application involves deepwater, high pressure high temperature (HPHT) conditions. Such failures may occur as a result of temperature and pressure-induced stresses created by well events such as hydraulic fracturing, cyclic steam injection, steam assisted gravity drainage (SAGD), production, completion, or other remedial treatments. Thermal and stress cycles could impose the risk of losing zonal isolation and lead to delay in hydrocarbon production.Cement mechanical properties measurment solely would not be sufficient to predict the failure threshold of a cement sheath. Some experimental studies were conducted about the effect of cyclical loading on the integrity of casing and drill strings but less research have been done about the in situ cement sheath integrity under cyclical loading. This paper introduces a new Ultra HPHT experimental set up and an applicable method to evaluate cement sheath integrity under cyclical loading. It also provides insights to find the cement fatigue failure cycle for the set cement at elevated pressures and temperatures.This system was built and completed by benefiting from the capabilities of an extreme HPHT Rheometer. Cement samples could be cured for number of hours in the newly developed HPHT cell and then instantly tested under cyclical loading in various scenarios at high temperatures. The cement sheath fails after a certain number of cycles when reaches its fatigue endurance limit. This research showcases scenarios in which the fatigue failure cycles were identified for 1,000 psi, 2,000 psi and 5,000 psi, pressure differentials between the confining pressure (exposed to outside of the sheath) and the casing pressure. During these experiments, the confining pressure and temperature were held constant at 15,000 psi and 330 ̊ F while the casing pressure varied cyclically between 15,000 psi and 16,000 psi (Set A), 17,000 (Set B) and 20,000 (Set C). A stable chemistry of Class H cement plus 35% silica was used to prevent cement retrogression. Cement sheath failures such as radial cracking, debonding and disking occured due to cyclical loadings. Finally, a fatigue failure envelope was generated by the obtained data. This curve represents the extent of cement sheath endurance at HPHT conditions under cyclical loading.
A successful cement job results in complete zonal isolation while saving time and money. To achieve these goals, various factors such as well security, casing centralization, effective mud removal, and gas migration must be considered in the design. For the cement job to be successful, the permeability of the set cement must be low enough to prevent any fluid flow through the cement, possibly damaging the casing. Therefore, the design of the cement must be such that it prevents:Micro-annuli formationStress crackingCorrosive fluid invasionFluid migrationAnnular gas pressure In High Pressure/High Temperature (HPHT), cases, a more flexible cement which expands more than conventional cement may prevent cement failure. The stress in the cement is strongly dependent on temperature and pressure as well as the lithology and in-situ stress. Since the stress is so dependent on temperature, the temperature variation must be precisely predicted to achieve the proper design of the cement slurry and eliminate excessive time spent waiting on cement. In addition, a post-job analysis is necessary to ascertain zonal complete isolation and avoid unnecessary remedial work. By increasing the flexibility of the set cement (lowering the Young's modulus) we could reduced the tensile stress in the cement sheath during thermal expansion. This could be a solution to the problem of cement stability in high temperature cases. Here we report the use of the Finite Element Method, (FEM), to investigate the stress fields around and inside the cement in and to forecast the condition of cement failure. This study mostly focuses on the cement-casing boundary. This method is more powerful than conventional stability methods since complex boundary conditions are involved as initial conditions and are investigated simultaneously to more accurately predict cement failure. Introduction There are many of challenges dealing with cementing wells under High Pressure High Temperature (HPHT) conditions. Cement design and placement are very critical under these conditions. Since the casing stability is very dependent on cement integrity, and bonding with the casing and formation, operators must do everything feasible in order to insure a successful cement job.
For economic and technical reasons, the industry has used directional, extended-reach, horizontal, and multilateral wells. Although technologies are well developed for these wells and there are numerous successes in the last decade, these wells still have high levels of risk in drilling and completion. Well control is one of the relatively unanswered but important operations, because improper well control, followed by a blowout, is one of the most expensive and feared operational hazards.To maintain a specified bottomhole pressure (BHP), surface choke pressures highly depend on kick vertical height in the well and well trajectory. As the final hold angle of the well increases from vertical, shut-in casing pressure (SICP) reduces to shut-in drillpipe pressure (SIDPP) and remains the same as long as the kick stays in the horizontal section. For equal vertical depths, the maximum choke pressure is insensitive to hold angles or hold lengths, as long as the initial pit-volume gain is the same. However, for directional and extended-reach wells, choke pressure can increase even without kick expansion, because of the gain of kick vertical height in the build section. This may mask choke-pressure reduction because of larger annular capacity when the kick passes the casing shoe, especially if the kickoff point (KOP) and casingshoe depth are close.In multilateral wells with more than one kicking wellbore, SIDPP is affected by both formation overpressure and kick size in each wellbore. The maximum value among them will appear at the surface. Therefore, we should be careful in the interpretation of the shut-in pressures. For safe kick circulation, we must consider additional pressure to compensate for hydrostatic-pressure reduction resulting from kick migration and expansion in branch wellbores. Two-Phase Kick Model.The appropriate assumptions and governing equations are critical to simulate realistic well-control operations. There are two typical types of assumption for modeling a gas kick: one is two-phase, and the other is single-phase. Considering the kick as a two-phase mixture, there are many computer models 6-8 for analysis of transient kick behavior. Eight variables describe the two-phase flow system completely. They are pressure, temperature, gas and liquid fractions, gas and liquid densities, and gas and liquid velocities. For water-based muds, we typically assume there is incompressible mud with a known temperature profile in the wellbore. Therefore, there are five unknowns: gas
Good flow and pressure control is essential for successful Underbalanced Drilling (UBD) operations. This work evaluates the use of Model Predictive Control (MPC) for integrated control of well conditions and the topside separation system during UBD. The downhole well pressure, separator liquid levels, and the separator pressure are controlled by manipulation of the rig pump, the choke, and the separator valves. The control system adheres to downhole and topside constraints. These constraints include pore and collapse pressures, minimum flow rate for hole cleaning, maximum choke pressure, separator pressure, and separator liquid levels. The proposed MPC solution uses simple Hammerstein-Wiener models, where parameters are determined by system identification incorporated into standard drilling procedures. The control system is tested using a high-fidelity multi-phase flow simulator (OLGA) for some common drilling scenarios, including drilling into a producing formation and performing connections. We show that the MPC solution is able to take proactive action to ensure safe and efficient operation without having to enter well control mode or shutting down the separator system. By limiting the amount and variation in influx from the reservoir, we get less Non-Productive Time (NPT), we improve safety, and we may to some extent be able to reduce the footprint of the equipment.
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