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Abstract Cementing through coiled tubing is not a new service line. However, it remains one that has received little technical attention. In reality, there is a great deal of science behind the successful execution of such cementing operations. Failure to understand the complexities of cement placement in a well can lead to catastrophic failure, including the loss of the coiled tubing, the entire well, or both. This paper outlines the techniques behind cementing through coiled tubing, illustrating the pitfalls and suggesting best operating procedures. The issues covered are: -When to use cement darts. How to land cement darts. How to manage liquid freefall. How to clean up cement. What should the displacement/contaminant fluid be? What are the best nozzles? Slurry design. Introduction Cementing is an every day operation in the oil patch, the most common application being the cementing of steel casings and liners in the ground. Cementing through coiled tubing is a much smaller business but nevertheless is conducted daily throughout the world. The typical cementing application through coiled tubing is not one of placing large volumes of cement behind casing strings; it is one of placing a relatively small volume of cement in a well for remedial purposes. Typical applications are: -Curing channeling behind tubulars. Blocking off perforations. Squeezing off perforations. Placing, in conjunction with packers, for wellbore isolation or abandonment. Placing through holes in completion strings to produce "cement packers". Curing lost circulation zones during drilling. Forming plugs for drilling sidetracks - "cement whipstocks". In all of these applications, the initial goal is to place a volume of uncontaminated cement at some point in a well. Subsequently, the cement may be squeezed against the formation, left to set in place, or circulated out before it sets. Each of these operations has potential pitfalls that can lead to quite catastrophic failures. This paper lists some of these potential failures and illustrates the correct procedures designed to minimize the risk of such failures. The paper refers only to pumping small volumes of cement through coiled tubing, not to primary cementing operations through large tubulars. Unique aspects of coiled tubing work lead to differing procedures for the two different applications. The chemistry of cement is complex and is not the subject of this paper. This paper refers only to the physical properties of the cement slurry during placement. Cement Slurry Properties General Description Oilfield cement is typically "Class G" or "Class H" cement particles suspended in water along with other solid and liquid additives. It is principally calcium silicate with particle sizes ranging from 1µm to 100µm, averaging 20µm. When mixed with water, the cement slurry sets with time to form a largely impermeable (1µD), largely acid resistant, solid material that is strong in compression, weak in tension. Cement slurries are typically dense as compared to water, although they can be mixed with a wide range of densities through the use of different additives. The standard density of "Class G" cement is 15.8ppg, or a specific gravity of 1.9. Cement slurries are very abrasive and can quickly destroy bottom hole assemblies that generate high fluid velocities and are not made of wear resistant materials such as tungsten carbide.
One of the main objectives of a primary cement job is to prevent formation fluids from migrating into the annulus. To achieve this objective, the cement sheath should withstand the stresses induced by the various well operations and maintain integrity during the life of the well. However, the majority of the cement design programs in the industry today consider only the slurry properties and do not assess the effect of the mechanical properties of the cement sheath on the final well design.
A design procedure has been developed to estimate the risk of cement failure as a function of cement sheath and formation characteristics and well loading. A few examples of well loading are pressure testing, well completion operations, hydraulic fracturing, and hydrocarbon production. The design procedure is based on a finite element analysis and simulates the sequence of events from drilling through cement hydration, well completion, and production operations. The cement failure modes simulated are debonding, cracking, and plastic deformation.
The cement is assumed to behave linearly as long as its tensile strength or compressive shear strength are not exceeded. The material modeling adopted for the undamaged cement is a Hookean model bounded by smear cracking in tension and Mohr- Coulomb in the compressive shear. Shrinkage and expansion of the cement are included in the material model.
The need to design a fit-for-purpose cement sheath is accentuated by the sustained casing pressure observed on a number of wells after they were put on production and on some HPHT wells after the displacement fluid was changed over to a wellcompletion fluid. The pressure in the annulus side sometimes results in an inability to continue further operation. Applications are discussed and examples are provided. From the processes reviewed in this paper, one can estimate the risk of failure of various cement systems and select a fit-for-purpose system that will minimize the overall cost. This process should improve the economics of constructing and producing oil and gas wells (cost effective life cycle design) and also improve safety because zonal isolation failures may be reduced.
The main purpose of a primary cement job is to provide effective zonal isolation for the life of the well so that oil and gas can be produced safely and economically. To achieve this objective, the drilling fluid should be removed from both the wide and narrow annulus and the entire annulus should be filled with competent cement. The cement should meet both the short-term and long-term requirements imposed by the operational regime of the well. Typical short- and long-term properties that are required from the cement are listed in Table 1.
Traditionally, the industry has concentrated on the shortterm properties that are applicable when the cement is still in slurry form. This 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, resistance to downhole chemical attack, etc. The need to consider properties of the cement sheath for long-term integrity is critical if the well is subjected to "large" changes in stress levels.
After placing cement in the annulus, if there is not any immediate migration of fluid to the surface, it is likely that short-term properties such as density, rate-of-strength development, and fluid loss of the cement have been designed satisfactorily.
Abstract Main factors which are responsible for the corrosion of the cement sheath in wells are determined based on lab tests and field analyses from a literature survey. A description of the chemistry, mineralogy, physical properties of API well cements and their mechanisms of corrosion in the presence of aggressive formation and injection fluids (such as magnesia or sulfate containing brines and CO2) are given. API cement hydration mainly produces Calcium-Silicate-Hydrate (C-S-H) phases, which are responsible for the strength, and portlandite "Ca(OH)2" which is basically a weak point within the cement matrix. Increasing permeability and portlandite content reduce strength and chemical resistance of set cement towards corrosive media. The addition of pozzolanic materials eliminates portlandite and allows lowering the water content in the cement system. Both effects can reduce the permeability and improve the mechanical properties of set cement. Cement specimens were prepared and exposed to CO2 loaded water at 300 °F and 3,000 psi for 6 months. Mechanical properties tests, microscopy, and quantitative CaCO3 analyses revealed significantly less corrosion and negative impacts for an API cement-pozzolan blend compared to a conventional API cement design at same density. Practical and economical concepts for improvements of the cement sheath with respect to cement slurry design, cementing process and the impact of factors such as temperature or cement admixtures are presented to mitigate cement corrosion.
A new method of foamed cement evaluation using a comparison of openhole and cased-hole neutron logs is described to complement existing techniques using acoustic cement evaluation logs. Together, it is possible to identify neat cement, foamed cement, fluid and air behind pipe. Favorable results are achieved in a case study, whether the armulus is bounded by formation or a larger casing string.
Primary cementing is critical in thermal project wells, especially those in cyclic steam (huff 'n puff) service. In addition to zonal isolation, good cement can minimize casing buckling or elongation due to thermal stresses. Lightweight or foamed cements are typically used in reservoirs with low fracture gradients. With such cements, the presence of a consistent cement sheath is difficult to confirm with conventional, acoustic-based methods.
Cement evaluation is complicated for low-density cements. As shown in Figure 1 (Figures are given at the end of the paper), acoustic impedances for annular fluids and foamed cement are very similar. Conventional cement evaluation logs rely on a significant contrast in acoustic properties between cement and annular fluids. The ellipse in Figure I represents the area where this contrast is lost because measured values of acoustic impedance for foamed cement and annular fluids overlap. When evaluated using ultrasonic logs, foamed cement typically exhibits low and highly variable acoustic impedance measurements.
Cement evaluation in concentric pipe is complicated by reflected and guided energy from the outer casing string. Observations from other neutron logging in the area suggested that dual-detector neutron (DDN) logging would be sensitive to nitrified and glass bead lightened cements.