Design and Surveillance Tools Help Lower Integrity Risks for High-Temperature Wells
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Thermal-well operations come with significant additional complexity in regard to maintaining wellbore integrity and hydraulic isolation from other formations. This is because of the extreme loads that may be placed on the well casing and liners, caused by the wide set of operating temperatures and pressures the wellbores may experience. To ensure that the wellbores can fulfill their anticipated operating need safely, careful design of the casing, liners, connections, and cement during the project-development phase is an absolute requirement.
Wells designed for heavy-oil thermal-recovery projects will be exposed to a potentially wide range of operating temperatures. These can exceed 340°C for the deepest heavy-oil-bearing formations and can be as low as 5°C during well workovers. Such a range of operating conditions will cause the casing to yield under compressive conditions, and most likely under tensile conditions also, as it undergoes thermal cycling from the heating and cooling requirements of well operations. A thermal cycle is defined here as the confined casing material being heated to the point that it yields and plastically deforms under a compressive load, followed at some later time by sufficient cooling to force it to yield and plastically deform under a tensile load. This is an operating requirement for which casing and liners are not normally designed in conventional applications but is frequently unavoidable in thermal operations. As a result, consideration of material properties of the tubulars requires a much deeper understanding of the chemistry, manufacturing, and heat-treating processes in order to select the optimal material. Similarly, casing connections play a key role in well integrity, based on their ability to withstand stress cycles in the casing or liner string.
Casing-cement composition and placement procedures are also key design parameters because thermal cycling of the casing will expose the cement to very large stresses across the metal/cement bond and potentially can alter the cement properties themselves.
In turn, the operating practices applied to wellbores and the operating envelopes used to determine safe limits become keys to long-term integrity and safety.
The level of surveillance applied to operating wellbores also will have a significant effect on their long-term performance. A lack of periodic testing can easily mask integrity issues that can, if not caught in time, result in significant, uncontrolled surface events and the loss of a wellbore. A variety of tools and techniques are available to monitor thermal wellbores and allow for early identification of warning signs.
Thermal wellbore applications can expose the casing material to extreme stress changes, often operating in the post-yield plastic-deformation range rather than remaining within the elastic limits by not exceeding its yield strength (YS) (Fig. 1 above). To enable material to operate in this stress range, close attention must be paid to the difference between the YS and the ultimate tensile strength (UTS) of the material. In conventional casing applications where YS is not to be exceeded, the UTS may be very similar to the YS because the material is not expected to experience plastic deformation. In the case of thermal applications, the yield-to-tensile ratio of the casing material should be less than 0.9 so that the UTS is higher enough, compared with the YS, so that, despite the casing being plastically deformed, it will still retain its strength and not fail. This can be manipulated to some extent with the steel chemistry during the manufacturing process and heat treatment afterward.
To be able to handle the cyclic stress changes, casing connections are recommended to have at least the same strength as the body of the casing/liner and offer a reliable, tested seal. Plastic deformation can have a significant effect on connection sealability if the stress loads weaken the quality of the metal/metal seal or alter the load distribution within the made-up connection.
Regarding the grade of steel, the degree to which yielding of the material will occur under tensile conditions and how this will affect work hardening of the material must be considered. Material with a lower YS will tend to work harden more as it is exposed to cumulative thermal cycles and, particularly, the more it is cooled below its tensile YS. This can cause casing material that is sour-rated at the time of installation to become unsuitable for sour conditions if its hardness increases too much.
As a direct consequence, exposure of work-hardened material can increase the risk of failure from environmental cracking involving either hydrogen sulfide or caustic. In the former case, significant cooling of casing material that has become sufficiently hard can cause sulfide-stress cracking, particularly at the connections. For the latter, if low-quality steam is injected down the casing annulus routinely, exposure of the typically high-pH steam liquids to casing connections that are under tensile stress and have started to seep can result in caustic cracking at the connection. Repairs of casing under either scenario may limit the future pressure rating, and thus the temperature rating, of the wellbore and, therefore, limit what the wellbore can be safely used for.
For long-term hydraulic isolation of the active heavy-oil reservoir across the cap rock and from the overburden, the cement formulation must be able to withstand the full range of cyclic conditions it will be exposed to and their cumulative effects. Because Portland-type cements are the primary type of oilfield cements used and the upper temperature limit of conventional Class G (or equivalent) cements is approximately 115°C, desirable cement properties, such as strength and low permeability, must be protected against high temperatures. This is achieved through the addition of silica flour to the dry cement in the amount of at least 30%. The presence of the silica flour significantly delays the thermal-degradation reaction of Portland cement, typically allowing it to withstand the high operating temperatures beyond the useful life of the well.
As with casing and liner materials, the downhole completion equipment also must be designed for the range of operating conditions it is likely to be exposed to. Downhole packers need to be able to manage the temperature differentials and to seal reliably. Expansion joints for the tubing must be designed to manage the full range of operating temperatures, including any workovers, without placing undue loads on the packer or wellhead hanger and must demonstrate the ability to maintain a seal and movement under repeated thermal cycles.
Surface wellhead tie-ins to the gathering-system lines must allow for thermal growth of the wellhead caused by the steam injection. Surface thermal growth is common with high-temperature wells; any uncemented or poorly cemented portions of the production casing near surface will want to expand upward. Where surface or intermediate casing is directly tied to the wellhead, the constrained, compressive load will create large forces on the casing hangers, potentially resulting in wellhead leaks and failure. No wellhead growth would normally occur in this situation. A better solution is to use an environmental pack-off/seal on the surface or intermediate casing that is not physically tied to the wellhead but still forms a reasonable seal around the production casing.
A key factor that will affect casing and connection integrity over the life of a well is the maximum temperature the casing will be exposed to, as well as the minimum temperatures the previously heated string will see when allowed to cool.
Well-workover kill operations, or even the effect of shallow aquifer zones on a shut-in wellbore, will cause K55 material to yield under tensile load even after the first steaming cycle because of wellbore cooling. If tensile yielding is not prevented, the cumulative effect of this will be hardening and accelerated fatigue of the casing material, which may cause it to fail prematurely. For L80-grade materials, the degree of tensile yielding will be much less significant because of its greater strength and will not occur until a much lower temperature is reached compared with K55. A best practice in well-workover operations to safeguard the casing is to use kill fluid that is as hot as possible.
Monitoring of thermal wells is a key activity not only for maximizing production but also for preventing well failures by detecting upcoming problems or obtaining early indication of a failure so that remedial action can be taken rapidly.
The most successful passive monitoring technique is the use of microseismic within the area of operations. A downhole geophone array can provide good data resolution within up to a 600-m radius.
If the microseismic data are monitored continuously, the technology can provide an early warning of an event precursor or an actual event, allowing further investigation and potentially preventing a catastrophic failure.
Another passive tool that can be used across a thermal development area is interferometric synthetic aperture radar, where surface ground deformation induced by the thermal and pressure effects of the subsurface recovery process can be measured from permanent surface reflectors. The system can offer high accuracy of surface elevation changes and can be applied to thermally stimulated reservoirs at depths of at least 600 m. Changes in surface deformation away from the expected near-wellbore thermally affected area, or that are unexpectedly high, may indicate loss of containment of the injected steam and pressure, potentially affecting one or more wellbores.
Design and Surveillance Tools Help Lower Integrity Risks for High-Temperature Wells
01 January 2018
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