Zonal isolation throughout the life of the well is important to help ensure that health, safety, and environmental (HSE) standards are not compromised and that the well operates economically. The life expectancy of a well is dependent on the protection that the wellbore can receive from primary cementing operations. A primary cement job design that provides zonal isolation and preserves structural integrity over the life of the well can reduce or eliminate the need for remedial operations. Achieving successful zonal isolation comprises three key mechanisms:Design and delivery of a reliable cement system that can withstand the effects of the operational loading and cyclical stresses exerted on the well by drilling, completion, and production operations.An auto-seal feature in the cement sheath itself. In the event that the cement sheath fails and develops cracks and/or micro-annuli because of primary cementing job failure in the presence of a mud filter cake, the sealant sheath can then react and respond in an attempt to automatically seal itself if formation fluid enters the cemented annulus. This is a fail-safe technology mode that can be included in the design of the cement slurry.Employing a packer element as part of the casing/liner string that can swell and seal the annulus if formation fluid comes in contact with the element. This additional contingency can help prevent flow of the hydrocarbon past the packer element by creating an effective mechanical seal. By applying these features, it is possible to effectively and successfully perform primary cementing operations with additional protective options and place sealants that will last throughout the life of the well (Fig. 1). Introduction Experience has shown that the mechanical properties of a sealant placed behind the casing is important to the success of a well throughout its productive life and ultimately minimizes its abandonment efforts and cost. This issue becomes more crucial when high-pressure, high-temperature (HPHT) wells are designed, drilled, and completed. In case of gas wells, the most common element of concern is the pressure encountered at different stages of the well's life, whereas for oil-producing wells, temperature may be of similar concern. Events such as high-pressure fracturing/acidizing, pressure testing, and high-pressure production can damage the cement sheath behind the pipe in any well. This possibility will require more scrutiny of the sealant mechanical properties to help ensure good quality zonal isolation. Mechanical properties required of a cement system should be determined by studying formation competency, drilling/completion fluid densities, completion methods, production regime(s), and future abandonment necessities. In general, cement sheath damage can be classified into three general categories: debonding, radial cracking, or shattering. The failure can be caused when tangential forces exceed bonding forces, tensile strength, and plastic limits. This paper presents a three-step approach to design, placement, and completion of a tuned slurry system that can protect zonal isolation throughout the planned operations of a well. As oilfield cementing evolves over time, more and more considerations should be brought into the design stage. These can include temperature cycling, high-pressure stimulations, and the method used to produce the well. Each operation performed on a well has an effect on the cement sheath behind the pipe. The effects should be considered before the primary cement job to minimize the costs necessary to maintain and abandon the well.

Near-surface casing corrosion has been observed to occur on operating steam-assisted gravity drainage (SAGD) wells in the Surmont field. The corrosion issue could pose risks to containment assurance and have negative implications on well economics throughout the life cycle. This paper discusses how the corrosion was first identified and then successfully mitigated using a high temperature coating solution on the production casing. The methodology used for coating testing, evaluation, and selection is also discussed. A two-tiered testing program was developed to qualify suitable coatings for the Surmont application. Eleven coating systems from various suppliers were first tested in the lab in a screening exercise to identify the best-in-class coatings for further evaluation. The top six performing coatings were then tested in the field environment to complete the evaluation. Coating performance was evaluated using a series of standard test methods. Out of the eleven candidate coatings, only two coatings qualified for the high temperature application in Surmont. These coatings are expected to provide long-term corrosion protection of the production casing at an optimized cost. One of these two coatings was successfully applied on an operating well and has provided reliable corrosion protection after four years of service. The methodology discussed in this paper for coating evaluation and application has been successfully implemented in the Surmont field. The findings from this work can be used to mitigate near-surface corrosion which will result in improved containment assurance and well economics.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDrilling in the Arctic can present a number of challenges even before the drilling begins. Among the challenges are logistic difficulties, weather extremes, and environmental sensitivities. To offset the production decline for natural gas in North America operators must confront these challenges by resuming exploration in the Arctic.The target in this case study is a well in the Paktoa field. The design challenge presented by this well was to drill the well to total depth (TD) with the lowest number of casing strings while avoiding remedial cementing operations. Given that the mud-weight window predicted for this wellbore was quite narrow, well planners determined that no fewer than five casing strings were needed to reach TD. Multiple casing strings can lead to tighter annuli and more challenging cementing operations.Using modeling software as an aid to cement design, planners determined that the cement on the first liner, from 1,300 to 2,600 ft, could not be circulated conventionally without breaking down the formation because of the high equivalent circulating density (ECD). The greatest contributor to the high ECD is the tight annulus of the liner lap. The model parameters were reversed and the model predicted that a reverse-circulation cementing (RCC) operation would be successful.RCC is a method of pumping cement down the annulus and receiving returns inside the casing. One advantage of reverse circulating is that the ECD is reduced and less pressure is exerted on the formation. This will help reduce or eliminate cement losses into weak formations.Placing the cement down the annulus appeared to be feasible with the computer model but to conduct the operation in the field, other challenges were addressed. In a reverse operation, the float valve is removed or sheared out before pumping cement. This is not of concern with a normal casing * Formerly employed by Devon-Canada