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.
The tester set initial opening pressure of a gas-lift valve (GLV) and port size are no indication of its injection-gas passage at a given injection-gas pressure for unloading and/or gas lifting a well. The initial test rack opening pressure (Ptro) of a GLV creates an opening force that slightly exceeds the valve’s closing force. The importance of the required injection-gas throughput performance of a GLV for unloading and gas lifting a well increases for very high daily liquid production rate wells and for wells that the workovers are very costly. A test procedure that allows individual injection-gas throughput rate testing of every GLV and check valve prior to being installed in a well is described in this paper. The method includes GLVs with cross-over seats that prevent stem travel probe test measurements. The test requires very little gas volume and is based on a rapid pressure decline (blow-down). Recent computer electronics as National Instruments LabVIEW software and 4 channel data acquisition instrument control hardware can record up to 12,500 pressure readings per second per channel. Test procedures are now possible to dynamically test the gas throughput performance of a GLV in a fraction of a second. GLV replacement can be very costly – even by wireline in wells with subsea wellheads. After setting the Ptro and aging (stabilizing) this set opening pressure, the dynamic blow-down test can be performed on each GLV with check valve. If the GLV passes this test, the valve will have the injection-gas throughput required to unload and/or gas lift the well. Every supplier of gas-lift valves should offer this testing option to the producer.
Each gas lift valve (GLV) is a variable orifice until a fully open port area is attained (under maximum stem travel). As the ball (stem) moves away from the ball/seat contact area, the area open to flow increases until the flow area upstream to the port area equals or exceeds the fully open port area. Laboratory gas dynamic throughput testing indicates that each injection-operated GLV often does not open fully in actual operation, mainly because of the bellows stacking phenomena. As a result, the stem forms a restriction upstream to the flow path. Therefore, actual flow through the GLV can be less than expected. This paper addresses such issues and recommends a simple but effective solution. A modified design for the GLV seat was created to help reduce the required stem travel to generate a flow area equal to the port area. Theoretical calculations confirm the actual gas dynamic measurements and show that the minimum stem travel for the modified design improves from 5 to 58% compared to using a conventional sharp-edged seat. This improvement should have a significant impact on GLV performance. The modified seats for all different ports sizes were manufactured and tested using a benchmark valve test. The experiments showed that for the same stem travel, the new design has a larger flowing area than that of the sharp-edged seat. This paper details the new design, theoretical calculations, and experimental results.
The before closure analysis (BCA) method describes the unsteady flow of fracturing fluid into a formation considering time-dependent fracture face resistance. It provides a methodology for calculating the permeability and fracture face resistance instead of calculating the conventional leakoff coefficient. The original BCA model developed by Mayerhofer et al. (1995) has been simplified by different authors, including Valkó and Economides (1999). It is found that their proposed simplified formulation has some inconsistencies, which results in erroneous analysis of data and interpretation of permeability. In this paper, the inconsistencies in the formulation have been addressed and resolved. The formulation of the corrected model is presented in a complete fashion. A discussion on sensitivity of the analysis, effect of pressure-dependent permeability, height recession, tip extension, and the effect of the reservoir fluid type is also provided. To validate the approach, two field examples of conventional oil reservoirs are presented as well. In the second case, the results are compared to the after closure analysis (ACA), and the effect of normal leakoff and pressure- dependent leakoff (PDL) on the BCA plot is discussed. The importance of considering correct data points in a normal leakoff portion is shown and illustrated on a BCA plot.
Several recovery processes have been proposed for heavy oil and oil sand reservoirs, depending on the reservoir and fluid properties. Among these, steam-assisted gravity drainage (SAGD) is widely used, and surface mining is considered the best approach in very shallow depths. However, deposits exist that are too shallow for SAGD but too deep for mining, requiring special techniques to recover the hydrocarbon economically. In addition, significant reserves are left behind as stranded reserves, as well as reserves that are usually characterized with weak caprock integrity and without enough pay thickness for SAGD to be economically viable. This paper focuses on a new technology that involves creating several mechanically induced inclusions in a single well. The production process is similar to a single-well SAGD. This method is proposed to assist both more uniform steam injection and bitumen production processes. The current setup is developed for vertical well applications; however, upon successful planning, the next version will be employed for horizontal applications. The current system consists of a vertical well with multiple vertical inclusions, which are used for simultaneous steam injection and liquid production purposes. Steam is injected into the upper part of the formation, and the drained liquid is collected at the bottom of the inclusions. Unlike the conventional steam chamber geometry in SAGD processes, steam moves outward from the inclusion faces into the formation and tends to move laterally out and vertically upward over time. Simulation studies of the system show that the success of such a technique depends on the inclusion dimensions as well as injection rate and pressure. In this study, the effects of inclusion dimensions and steam properties on the performance of such a process are investigated. Reservoir simulations of realistic reservoir conditions show promising results in terms of cumulative steam oil ratio (CSOR) and production rate. Early peak oil production occurred at approximately 100 days from the startup, and the CSOR dropped to under 3 m3/m3 after 100 days. The optimum inclusion dimensions and the best injection scenario for different net pays at different depths and geological conditions are illustrated in the paper.
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