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This paper discusses the experiences and good practices established from successfully executing two managed pressure cementing (MPC) jobs within an ultra high-pressure/high-temperature (HP/HT) well in offshore Malaysia. The risks associated with cementing in sections with narrow margins between pore pressure and fracture gradient can often limit the length of each cased section, hence limiting the final total depth (TD) of the well. A new cementing technique using managed pressure drilling (MPD) equipment and processes allows the wellbore to be displaced with a hydrostatically underbalanced mud after the casing string has landed and then cemented with a hydrostatically underbalanced spacer and cement slurry. This technique was used to successfully cement an 11 3/4-in. intermediate liner and a 9 7/8-in. production liner, which, in turn, enabled the operator to reach the target depth. The 11 3/4-in. liner was cemented successfully without losses or gains, despite only a 0.2-lbm/gal window (15.6 to 15.8 lbm/gal), with bottomhole static temperature (BHST) of 133°C. This job was executed with a 15.0-lbm/gal mud, a 15.0-lbm/gal spacer, a 15.0-lbm/gal cement slurry, and up to 400 psi surface backpressure (SBP). The 9 7/8-in. liner was also cemented successfully without losses or gains with a 0.9-lbm/gal window (17.4 to 18.3 lbm/gal) with BHST of 163°C. This job was executed with a 17.0-lbm/gal mud, a 17.0-lbm/gal spacer, a 17.0-lbm/gal cement slurry, and up to 600 psi SBP. A cement bond log (CBL) was run for the 9 7/8-in. production liner and the results showed good bonding across the entire openhole section, including the critical target zones. The prejob engineering and execution involved extensive hydraulic modeling, closely coordinated with the MPD service provider, and comprehensive risk analysis and mitigation plans.
This paper discusses the experiences and good practices established from successfully executing two managed pressure cementing (MPC) jobs within an ultra high-pressure/high-temperature (HP/HT) well in offshore Malaysia. The risks associated with cementing in sections with narrow margins between pore pressure and fracture gradient can often limit the length of each cased section, hence limiting the final total depth (TD) of the well. A new cementing technique using managed pressure drilling (MPD) equipment and processes allows the wellbore to be displaced with a hydrostatically underbalanced mud after the casing string has landed and then cemented with a hydrostatically underbalanced spacer and cement slurry. This technique was used to successfully cement an 11 3/4-in. intermediate liner and a 9 7/8-in. production liner, which, in turn, enabled the operator to reach the target depth. The 11 3/4-in. liner was cemented successfully without losses or gains, despite only a 0.2-lbm/gal window (15.6 to 15.8 lbm/gal), with bottomhole static temperature (BHST) of 133°C. This job was executed with a 15.0-lbm/gal mud, a 15.0-lbm/gal spacer, a 15.0-lbm/gal cement slurry, and up to 400 psi surface backpressure (SBP). The 9 7/8-in. liner was also cemented successfully without losses or gains with a 0.9-lbm/gal window (17.4 to 18.3 lbm/gal) with BHST of 163°C. This job was executed with a 17.0-lbm/gal mud, a 17.0-lbm/gal spacer, a 17.0-lbm/gal cement slurry, and up to 600 psi SBP. A cement bond log (CBL) was run for the 9 7/8-in. production liner and the results showed good bonding across the entire openhole section, including the critical target zones. The prejob engineering and execution involved extensive hydraulic modeling, closely coordinated with the MPD service provider, and comprehensive risk analysis and mitigation plans.
In various parts of the world, heavy oil projects use high temperatures in order to support the oil production. Most of these projects are still on-going after several years of high temperature well exposure, while others have been suspended due to operational and environmental issues. The well integrity time span should extend itself beyond the field estimated operational date. These wells (observation, productions or abandoned) are highly susceptible to leaks due to cement degradation resulting from thermo-chemical-mechanical loads. Therefore, successful further development of heavy oil reservoirs requires a closer look at the assessment of well integrity and its prediction for extensive periods of time. During the life of the well, the casing-cement-rock system is experiencing, as a secondary problem, a cumulative damage. This could explain the sustained casing pressure that appears after years of good well integrity. Long time exposure of the well to several loads as well as cyclic load changes may affect the well response due to a rather unexplored degradation of the mechanical, chemical and thermal parameters. In this case, the typical loading mechanisms are thermal, associated with superimposed chemical and mechanical loads. A large number of studies has been conducted to investigate the very complex chemical degradation process of Portland cement systems, which is influenced by temperature, pressure, chemical reactions and their products and, more important, time. A literature review of various investigations on well degradation processes has shown that most of the experiments are time-constrained, and therefore the well integrity is limited to the interval in which results extrapolation is possible. Cement retrogression has also been investigated and research led to recommendations of adding silica flour to the Portland cement. The least investigated aspects of the cements are their cyclic resistance to variable loads. This paper will critically analyze the various existing well integrity concepts and point out the future need for research to improve the prediction of well integrity. The results of the work show that the major unknowns are long term properties of the downhole environment like casing, cement, and the interaction between casing-cement-formation. Moreover, a simple, yet attention-grabbing experimental investigation has been carried out on several cement samples with different properties by simulating the cement layer associated to the surface casing of a well exposed to temperature variations. Due to the shallow depths, the cementing of the surface casing may yield specific well integrity issues generated by low slurry density requirements, original low temperature environment, high fluid-formation temperature differences, all leading to potential problems related to health, safety and environmental standards worldwide (e.g. aquifers damage, operational risk, etc.).
Thermal injection is a key method for enhanced oil recovery (EOR). During thermal injection, special steam injection wells are drilled to heat the crude oil in the formation to reduce its viscosity and help improve oil recovery. Zonal isolation of steam injection wells can be challenging because the temperature of steam on surface can reach up to 500°F. Regardless, achieving all zonal isolation objectives on the first attempt is necessary because any remedial treatments in such wells could adversely impact well integrity. This paper discusses best practices used for zonal isolation of steam injection wells in the Issaran field, Egypt. This field is located approximately 290 km southeast of Cairo and 3 km inland from the western shore of the Gulf of Suez. This field was discovered in 1981 and covers an area of 20,000 acres. This is among one of the few heavy oil fractured carbonate reservoirs in the world. During 2012 to 2015, more than 40 wells were drilled and successfully cemented in this area. Because of the unique characteristics of the fractured reservoir, special lightweight high-compressive-strength cement slurry was designed to help ensure the equivalent circulating density (ECD) during cementing would be less than the formation fracture gradient. During laboratory testing, this slurry was exposed to downhole steam temperatures for more than 10 days to determine its long-term compressive strength and evaluate the potential for strength retrogression. As a contingency to minimize losses during cementing, glass fibers were added to the cement slurry. The secondary purpose of these special fibers was to increase the tensile strength of the cement slurry. To help improve the mechanical properties of the slurry, special elastomers were also added. Finite element analysis (FEA) was performed to calculate the desired Young's modulus and Poisson's ratio of the cement slurry, and the concentration of the elastomers was adjusted accordingly. Although the wells had minor deviations, casing centralization was optimized to help ensure homogenous distribution of the cement slurry in the annulus. Mud displacement and filter-cake removal are also key parameters for a successful cementing operation, so a tuned rheology spacer was designed to help achieve rheological hierarchy based on the rheological parameters of the mud and the cement. Surfactants were added to help erode the mud filter cake before the cementing operation. Also, three-dimensional (3D) modeling was performed to help optimize displacement efficiency and mud removal before the cementing operation. Post-cementing operations in all wells showed that the designed cement slurry was suitable for such applications and resulted in achieving all of the objectives of zonal isolation. This paper provides details of the slurry design parameters and best practices and can be used as a reference for cementing such systems in the future.
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