There is a very large number of wells worldwide that leak or have sustained casing pressure (SCP). In Central Europe and the Middle East there are hundreds of wells with reports of trapped pressure that cannot be bled off. In the US and Canada there are thousands of wells leaking to surface, which may or may not be discharged to the atmosphere. Furthermore, 25% of all wells in the Gulf of Mexico have measurable sustained casing pressure. Additionally, remedial work fixing issues relating to cement failure has been estimated to be more than $50M a year in the US alone. Throughout the lifecycle of a well, planned cycle or operational changes can contribute to unknown damage to the cement sheath integrity that is hard to identify or locate, including the generation of a microannulus. Within flow paths, hydrocarbons can either migrate to surface, or become trapped below the wellhead leading to pressure build-up. Typical events occur during cementing, while perforating or stimulating, throughout the subsequent production, and even after abandonment. These can easily create this loss of cement integrity. This paper describes a novel isolation system that is activated only when a cement integrity problem occurs. The system will automatically and rapidly form a complete hydraulic barrier by swelling in the presence of hydrocarbon flow. Once activated, it will seal the damaged zone, and will even be able to be activated again, should further damage occur again during production or abandonment. The system has properties equivalent to conventional cement systems, and requires no modifications to standard surface equipment. High pressure static and dynamic laboratory tests highlight the ability of the system to rapidly shut off gas flows within 30 minutes. Field tests have also highlighted the robustness of the system, with a number of wells currently using the system remaining leak-free. Introduction The number of wells worldwide that leak or have sustained casing pressure (SCP) is an astonishingly high percentage, and as the demand for natural gas is increasing, the situation is likely only to get worse. In the United States, for example, demand will continue to grow during the next two decades, and has been estimated to reach a level as high as 35 quadrillion Btu (quads) by the year 2020.1 Correspondingly, a high number of new wells will need to be constructed to cater for this demand. If there is no change in current well construction techniques and materials, the incidence of leaks or of SCP is likely to track the well construction rate at a similar pace. Techniques for locating and exploiting natural gas have made huge advances since the early days of 1821 when the first natural gas well in the United States was drilled. However, m any of today's wells are still at risk, despite modern advances in well construction processes and materials. Failure to isolate sources of hydrocarbon either early in the well construction process or long after production begins has resulted in abnormally pressured casing strings and leaks of gas into zones that would otherwise not be gas-bearing. Abnormal pressure at the surface may often be easy to detect, although the source or root cause may be difficult to determine. Even when attempting "industry best practices" some annular pressure problems still occur. The quality of field practices may exacerbate tubing and casing leaks. The interdependencies of various well-construction processes is critical to building successful gas and oil wells for the future.2 This paper describes a new novel concept for zonal isolation based on a new material called self-healing cement (SHC). This concept does not preclude good cementing practices, but will enhance the chance of success where perceived long term pressure risk is anticipated. The objective of SHC is to provide long-term zonal isolation with a material that has self-repairing properties within the set cement. For example, this material enables automatic repair when a microannulus, internal cement crack or other flow path is created, and thus prevents flow of formation fluids through potential leak paths along the annulus. The concept focuses on long-term durability of the cement sheath material in oil and gas wells, and thus cement sheath repair without the need for well intervention.

The drilling of deep Foothills wells in western Alberta presents numerous challenges. Intermediate casing in these wells is typically set at 3,200 to 3,400 m TVD, but may be set as deep as 3,600 m TVD without regulatory exceptions. Regulatory requirements dictate the need for cement at least 100 m above the top of the highest potential productive interval. It is also required that no annular gas is present at surface. To eliminate surface casing vent flows, it has been determined that nuisance gas stringers that are above the regulatory top of the cement requirement must be isolated. This has resulted in a need to bring top of cement back inside of the previous casing. Historically, operators opted to utilize a stage tool in this casing string to achieve a top of cement sufficient to meet regulatory requirements. While this approach has been successful at meeting requirements, remedial cementing has often been required to seal surface casing vent flows. A limitation of this approach is that the stage tool is exposed to periods of contact with the drillstring while the subsequent hole section is being drilled, resulting in wear and potential leaks. Development of a new high performance, low-density cement system has provided the ability to address all of the above issues. Utilization of this cement system allows wells to be cemented in a single stage with the top of cement lifted into the previous casing. This paper describes the new cement system and its application in solving the problems described above. Case histories including evaluations are provided. Introduction Background Successful cementation of wells in the Central Alberta Foothills region presents a difficult challenge with regard to gas migration and/or Surface Casing Vent Flows (SCVF). Specific fields where difficulties have been encountered include: Bighorn, Brown Creek, Cordel, Deanne, Lovett River, Mountain Park, and Stolberg. Surface casing is normally set at approximately 610 m (2,000 ft.) to cover all groundwater in this region. The wells are cased and cemented with an intermediate casing at a measured depth range of 3,200 to 3,600 m (10,500 to 11,812 ft.). Then another ±1,000 m (3,280 ft.) horizontal section is drilled and completed openhole. Numerous formations can be identified as potential gas sources in these wells (Figure 1). The Belly River sands, while not considered producible in this area, are a source of nuisance gas that may result in a SCVF. The Cardium sand, which may repeat as many as three times due to faulting, is another potential gas source. The Wapiabi, Blackstone, and Blairmore shales may all contain coal seams and high-pressure inter-bedded sand stringers that can be sources of nuisance gas. The Cadomin sand and Nordegg Lime may also contain gas, although they may not always be sufficiently porous in this area to be of concern. Alberta Energy Utilities Board (AEUB) regulations(1) require that the uppermost Cardium sand must be covered since it is the shallowest producing interval in the area. The AEUB also requires that the well cannot have a SCVF.

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