Not long ago, “high temperature” downhole meant anything over 350°F (176.6°C). But the term high pressure/high temperature (HP/HT) has a broader meaning. Temperature and pressure differentials present the true challenge (Figure 1). A well in 9,000 ft (2,730 m) of water with a bottomhole temperature (BHT) of 200°F (93°C) would not be categorized as an HP/HT well in most situations. Yet casing and cement at the mudline would be subjected to a 150°F (66°C) temperature differential when the well is put on production.



Figure 1. Cement sheath responses to cyclic pressure differentials. (Images courtesy of Halliburton)

During a high-rate stimulation treatment on a 19,000 ft (5,791 m) well with a BHT of 430°F (221°C), cement and casing at the perforations can be cooled to less than 130°F (54°C), creating a differential of more than 300°F (149°C). This puts incredible stresses on the cement, casing, and formation, and these stresses are compounded by exposure to high pressure differentials.


Wells have been drilled sporadically for several years with BHTs in the range of 450°F (232°C). Most recently, wells have been drilled (and more are planned) with predicted downhole temperatures of 550°F (288°C) or more. Tools and systems are now under development for temperatures greater than 600°F (316°C).


Most HP/HT wells begin to exhibit high temperatures at depths around 18,000 to 20,000 ft (5,486 to 6,096 m), although in areas where there is geothermal activity, hot drilling conditions can occur much higher up in the well. In either case, it is a mistake to wait until the bit reaches the HP/HT interval to begin planning or even placing the type of cement slurry that will be needed to finish the well. A total system approach is required.


Planning a successful HP/HT well means considering every aspect of the operation. A common mistake has been designing cement jobs for the surface and intermediate casing strings in accordance with upper hole conditions, when in fact even the surface casing will encounter extreme wellhead temperatures during drilling and certainly once the well is producing. The well has to be engineered for the total temperature and pressure load, and every cement slurry should be designed to withstand potentially drastic temperature and pressure differentials.


Planning time is critical


The allocation of planning time is critical to success. A single routine cement test at a moderate temperature such as 250°F (121°C) may be completed in 4 to 10 hours. However, that same test at high-temperature conditions (e.g., 500°F [260°C]) requires 20 to30 hours of lab time using much more sophisticated equipment. For example, thickening time consistometers are available to test slurries to 750°F (399°C) and 50,000 psi, but that is only part of the slurry design-and-test process. Making an accurate evaluation of the long-term cement mechanical properties is much more difficult.


Testing limitations


It is not possible at present to fully test the mechanical properties of a cured HP/HT slurry at the expected curing temperature and pressure. Even as researchers continue to develop materials and chemicals that will give operators the slurry properties needed for cementing casing in HP/HT wells, only in the last 5 years has the industry recognized the corresponding need to develop the means to modify the mechanical properties of set cement. Well conditions demand that we design cement sheaths that can accommodate expected stresses, but the technology to reliably perform and evaluate destructive mechanical property testing at HP/HT conditions is in its infancy.


It is well known that cement set time accelerates as temperature increases, and that conventional cement retarder chemistry degrades at higher temperatures. New retarder systems have been designed and tested to withstand placement temperatures in excess of 550°F (288°C), a significant stretch from the previous comfort zone of approximately 425°F (218°C). While this is good news, retarding set time is only one consideration in HP/HT slurry design. Several other factors such as slurry stability at extreme temperatures must be taken into account.


Current technology


Operators drilling deep, hot wells are likely to encounter moderate to high levels of CO2, which is corrosive to Portland cement under certain conditions. Cements are currently available that have been designed to resist CO2 at lower temperatures, but the ability to place these specialized systems at extreme temperatures is still under development. Thermal thinning is another serious issue at extreme temperatures. The polymers that have historically provided good slurry stability up to 425°F (218°C) are not always robust enough for the slurries needed in HP/HT operations. Not only are more thermally stable polymers needed but there is a greater dependency on self-suspending slurries that rely on ultra-fine manganese oxide or hematite particles for density, and ultrafine grinds of crystalline silica for both improved slurry stability and faster reactivity to aid in prevention of strength retrogression. Using these design practices reduces reliance on conventional viscosifiers, but there is still more development needed in this area.


Drilling and completion practices can influence the quality of the cement job. For example, when casing is pressure tested prior to drilling out cement, the resulting expansion and contraction of the casing may create a micro annulus if the differential is severe enough and the cement sheath has not been designed to prevent it. High-rate frac jobs can exert a similar stress: the frac fluid is relatively cool as it is pumped downhole, but flowback immediately heats the casing and cement sheath to formation temperature. The casing and cement sheath experience these two temperature extremes in rapid succession. Unless the cement was designed to handle such stresses, it will be subject to radial cracking and shear failure, and the well may be subject to loss of isolation across multiple zones or even total mechanical failure.


Role of fluids


Displacement fluids also play a role in the behavior of the casing and cement. Displacing a 21.0 lb/gal cement slurry with a low-density brine is a proven technique to reduce the stress on cement during curing and subsequent well operations. However, this practice may strain surface pumping capabilities and expose the components to unnecessarily high pressures during displacement. Using Finite Element Analysis tools to examine the effects of various brine densities used for cement job displacement is the key to balancing the pressure limitations against the desired stress-reduction needs. Displacing with a heavier brine may cost more per barrel initially, but it can help minimize mechanical stresses that would lead to costly interventions and cement sheath failures later in the producing life of the well.


Therefore, to design an HP/HT cement that will help preserve the life of the well, we should have answers to the following questions: What are the maximum temperature and pressure differentials that the well will experience? What type of completion is planned? What is the sequence of the completion operations? Is a frac job planned? What type of brine will be used? What are the limitations of surface pumping equipment?


Development of standards


As yet there are no industry standards for ultra HP/HT cement design. These standards — should they be developed — should account for much more than a conventional cement job design per casing string. The well should be planned from top to bottom, including completion methods and production management, to help ensure that the steep investment in operational costs can continue to be offset by a strong gas market. The investment should also support much-needed research and development projects. Not acting early enough presents a financial risk to operators, service companies and the global fossil fuel-driven economy: the potential delay or even loss of reserves that result from the absence of enabling technologies.