Cementing high-pressure, high-temperature (HPHT) wells poses various challenges not seen at normal well conditions. For instance, the following objectives are critical for HPHT wells:Prevent losses during drilling fluid circulation and cement slurry placement.Displace the drilling fluid and place the cement slurry effectively.Prevent free-water or gas-channel development.Reduce slurry fluid loss.Provide support for the production packers.Decrease compression loads on casing connectors.Prevent damage to cement sheath.Prevent annular gas pressure over the life of the well. The industry is recognizing the interaction between these factors to determine the optimal cement job design for accomplishing these objectives. This paper presents and discusses the engineering analysis to determine the optimum foamed cement sheath properties for integrity during the life of the well at HPHT conditions. Also, this paper compares foamed cement to nonfoamed slurries in achieving these objectives. Other important issues discussed are the performance of nitrogen at HPHT conditions and the rheological properties of the foams. Key issues addressed are the state and solubility of nitrogen under downhole conditions and the integrity of the cement sheath during the life of the well. Thermodynamic solution theory and experimental studies are applied to the former, and finite element analysis is applied to the later. Case examples are presented discussing foamed and conventional operations at near HPHT conditions for some Norwegian, North Sea wells. Cement properties are contrasted for the different foamed and conventional cement slurry properties with respect to:Achieving the HPHT objectives, such as placement efficiency and sheath propertiesPrejob design to obtain the objectivesJob planning and proceduresJob executionLogging of foamed cementPost-job evaluation of the cement systems Introduction Traditionally, the industry has concentrated on the short-term properties that are applicable when the cement is still in slurry form. This effort is necessary and important for effective cement-slurry mixing and placement. However, the long-term integrity of cement depends on the material/mechanical properties of the cement sheath, such as Young's modulus, tensile strength, and resistance to downhole chemical attack. Considering properties of the cement sheath for long-term integrity is critical if the well is subjected to large changes in stress levels such as with HPHT wells. Recent experience has shown that after well operations such as completing, pressure testing, injecting, stimulating, and producing, the cement sheath could lose its ability to provide zonal isolation.1 Failure of the cement sheath is most often caused by pressure- or temperature-induced stresses inherent in well operations. This failure can create a path for formation fluids to enter the annulus, which can pressurize the well and render it unsafe to operate. Failure can also cause premature water production that can limit the economic life of the well. Consequently, if the cement sheath fails during its active life, the objective of producing hydrocarbons safely and economically may not be met. The cement sheath should have optimum properties so it can withstand the stresses from well operations. In general, cement slurry should be compensated for volume reduction during hydration and the mechanical properties should be optimized for the well operations.

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Understanding the heat transfer phenomena encountered in extreme oil and gas reservoir environments [i.e., thermal recovery, high-pressure/high-temperature (HP/HT), deepwater, etc.] and geothermal wells is important to enhance the exploration and production of subterranean energy resources. However, there can be a lack of information about thermal properties of current oilwell cement systems, which are key inputs for any cement sheath stress simulator that accounts for the thermal cycling effect on the integrity of the annular sealant. Having thermal data for multiple sealant systems is important to allow for risk reduction and production maximization by reducing wellbore construction uncertainty during the planning stage, therefore allowing operators to make well-informed decisions. This paper discusses the thermal conductivity and thermal expansion of neat, foamed, and elastic oilwell cements. These properties were measured in hydrated and dehydrated states at ambient pressure and at temperatures ranging from 25 to 100°C (77 to 212°F). Both thermal conductivity and thermal expansion measured on dehydrated cement samples were less than hydrated samples, which is most likely attributed to the effect of evaporable water within the cement specimens. Mathematical relationships were derived for thermal and physical (i.e., density) properties of cement, thus allowing for approximate characterization of the thermal behavior of oilwell cements. The effect of the thermal properties of different cement systems on the integrity of a typical thermal recovery well was evaluated as a case study. Elastic properties of the aforementioned cement systems were also studied, yielding characteristic curves for each system. Moreover, the impact of cyclic loads on determining acceptable stress levels of annular sealants is also presented, along with its economic benefits. This allows for the optimal design of dependable sealants for long-term integrity during the planning stage.

The effectiveness of a permanent abandonment plug is measured by its ability to bridge the wellbore cross section both vertically and horizontally, including all annuli, with a plugging medium which can withstand the rigors of the environment to which it is exposed (Figure 1 – Barrier Requirements). The most common method for placing a plug in cased hole with an uncemented annulus has required section milling of the casing, making a clean out run and underreaming of the open hole prior to placing a balanced cement plug. A new method is presented which creates a permanent abandonment plug through the use of a system which perforates uncemented casing, washes the annular space and then mechanically places the cement across the wellbore cross section in a single run. This paper outlines the design methods, laboratory testing and operational elements that were assessed during the development phase, as well as the results of field trials used to qualify this technique.

In certain areas of the Norwegian waters, shallow pressurized sands containing either gas or water occasionally create problems during drilling and surface casing installation. In 2018, an operator drilled three wells in the Norwegian waters with such special challenges. In this case the challenge was water flow but not gas. The NORSOK D010 shallow gas flow potential was classified as zero. Each of the wells had a shallow water flow challenge in an over-pressured sand that normally would require setting a shallow 20-in. surface casing and a riser installation before passing the zone to enable controlling the pressure on the sands using weighted drilling fluid; also requiring a 17-in. liner installation to cover the sand before further drilling. If the surface casing could be set deep enough to cover the over-pressurized sands, substantial savings could be obtained on each well by eliminating the need for an additional section and installation of an extra liner or casing. Furthermore, a deeper-set surface casing would reduce the risk of not obtaining an adequate leak-off test below the shoe. A deep-set surface casing would also allow for down-scaling the well from 20-in. to 13-3/8-in. surface casing. A riserless drilling fluid return system allows for controlling the pressure while drilling, but this has to be turned off during cementing as cement is expected in returns. The use of conventional cement systems would potentially put the well in under-balance for a substantial period of time and consequently potentially result in a water-flow situation requiring a re-spud, as has been the case for a reference well in the area in which substantial downtime was experienced due to water flow after cementing the surface casing. The solution was a riserless drilling fluid return system during drilling, followed by a tailored cement solution. A tailored spacer and foam cement system were deployed; the short transition time of the cement and the inherent compressibility of foams both reduced the exposure time in under-balance. The solution was successfully deployed on all three wells with no flow observed post placement. This paper will detail this successful case study.