This study used an advanced airflow, energy and humidity modelling tool to evaluate the potential for residential mechanical pre-cooling strategies to reduce peak electricity demand. Simulations were performed for a typical new home in all US DOE Climate Zones. The results show that the effectiveness of pre-cooling is highly dependent on climate zone and the selected pre-cooling strategy. The expected energy trade-off between cooling peak energy savings and increased off-peak energy use is also shown. Best pre-cooling results for most climates were obtained using a short pre-cooling time window with a high pre-cooling set point temperature. All pre-cooling strategies caused the annual cooling energy demand of the simulated buildings to increase. However, pre-cooling for long time periods with a low temperature set point can eliminate up to 97% of the annual peak cooling load of the building.

The trend to expand production into high pressure/high temperature (HP/HT) fields in the North Sea and other producing areas has created a demand for new equipment that is designed to reliably function in the extreme environmental conditions that are inherent to these fields. This paper will describe a joint project in which a major North Sea operator and an engineering/manufacturing company developed a retrievable-type production packer for HP/HT service. Included in the discussion will be the critical design issues that were addressed, the unique methodology that was used to resolve these issues, and the resulting packer design. Also covered will be the results concluded from the prototype testing that confirmed the functionality of the design in accordance with the operator's specifications. Introduction The production packer is a critical item in any completion. Although the surface-controlled subsurface safety valve (SCSSV) may be relied upon as a downhole safety barrier to close off well flow should a catastrophic situation occur at the surface, the packer must remain firmly anchored in the casing and must maintain sealing capability between the production tubing and casing1 even after the SCSSV has closed. While there have been many recommended practices, procedures and standards generated to define how the SCSSV should be designed, tested and operated, no standards have been established for production packers. As a result of the recent economic pressures in the oilfield, operating companies have felt that consideration should be directed toward developments that offer increased production. Often, however, these developments are in deeper, more corrosive environments with greater differential pressures and higher temperatures than were encountered in traditional environments. As is usually the case when any scope of application is enlarged, newer equipment that can maintain integrity in a wider range of conditions must be sought. When considering the high pressure/high temperature environment, in certain instances such as in the case of the retrievable packer, equipment has not been available that could withstand the rigorous conditions of the HP/HT environment. The equipment typically considered to be classed as HP/HT must have a rated working pressure of greater than 10,000 psi and a rated working temperature that is greater than 350 F. Until now, all production packers for HP/HT applications have been of the permanent type because HP/HT retrievable designs simply did not exist. Permanent HP/HT packers have been used successfully without catastrophic failures for more than ten years in severe conditions. However, because a retrievable packer can be removed during a workover or prior to well clean-up operations without milling, many consider it to be a more desirable option. The following problem areas exist in milling when considering development in an HP/HT environment:–Wells are up to 18,000 feet deep, highly deviated, or horizontal with complex S-profiles, complicating retrieving operations.–Casing is corrosion resistant alloy (CRA), and as such, is considered an asset too valuable to expose to potential milling damage.–The production tubing and packer components will also be of CRA material; thus, milling is difficult.–Milling difficulties increase costs. In the development of HP/HT equipment for these extreme environmental applications, the completion equipment must be thoroughly tested to verify the design calculations. Because of the wide scope of varied conditions encountered, the related completion equipment is typically nonstandard, usually having been developed for a particular field or operator. P. 513

Reliability of downhole completion equipment is a key factor in the total return on well investment. Although the need to reduce failures and minimize risk has brought about increased desire for operating companies to share information, no industry standards have been established for reliability assessment of completion equipment. This paper will discuss examples of assessment schemes developed in the North Sea that could be used in the process of establishing industry measurement standards. Establishment of these standards would significantly support the goals of the oil industry to improve operational and cost efficiencies. Introduction Requirement for 20-year equipment reliability is both common and justified. Some of the earliest platforms in the North Sea are still in place after more than 25 years, but the majority of wells have been worked over at least once. The average tenure of completion/production engineers responsible for design, selection and performance of downhole completion equipment is much less than 20 years - so, how do these engineers make informed decisions? The larger operating companies rely on the experience of experts who provide input on completion design but even so, this input is usually influenced by the personal experiences of those individuals. Unfortunately, broad-range sharing of information across the industry for benchmarking of completion equipment performance has been poor or non-existent. Since equipment integrity is essential not only for cost efficiency but also for safety of personnel and the environment, more information is needed on long-term reliability benchmarking during the initial stage of completion design. The key factors needed to assess equipment reliability are collection, storage, and analysis of well data. However, failure to agree on how to establish industry-wide reporting methods and performance benchmarks for the data will retard the process of continuous improvement in our industry. Additionally, if the methodology used to collect and interpret the data is not understood and accepted by both the operating companies and the equipment manufacturers, the goal to develop a tool that can provide significant value to the industry will not be accomplished. For these reasons, development of reliable standards will require commitment and participation from all parties. Reliability Factors Prevention of equipment failure is similar to the prevention of accidents. The goal must be zero, and there must be systems in place to help the industry make continuous improvement towards attaining that goal. Industry standards have been implemented for accident reporting, and the lost-time incident frequency (LTIF) index has been widely accepted as the benchmark measure for continuous improvement. Unfortunately, equivalent standards for reporting and benchmarking equipment failures and completion performance have not yet been implemented although an International Standard ISO/142241 was issued in July 1999. This standard has an expansive scope, and it is too early to predict its widespread acceptance for downhole equipment. Factors that affect well completion reliability and the fundamental considerations that must be considered to reduce probability of failure are shown in Table 1. These factors are listed in order of time rather than importance.

Effective coordination of the supply of downhole completion equipment is critical for oil and gas companies. The process usually includes planning, procurement, storage, call off and onshore preparation of completion components and assemblies. At current daily costs for rigs and fixed platforms, the consequences of late supply or failure of just one item can be significant and may exceed the original purchase cost of the entire completion. Major completion components include subsurface safety valves, landing nipples, circulating devices, expansion joints, production packers, and seal assemblies. Hundreds of components may be handled due to variations in well type, well conditions, casing size, tubing thread, and individual well engineers' preferences. Accessory items such as pup joints, flow couplings, blast joints, and crossovers must also be coordinated. Involvement of several different suppliers can further complicate the process. Two operating units of a major North Sea Operator have joined forces to implement a new approach to improve efficiency and reduce the overall cost of downhole completion equipment by issuing a joint, pan-European tender. European Community regulations were adhered to in generation of a "functional requirements" tender, as opposed to a full specification tender. This enabled potential suppliers to propose "fit for purpose" equipment which already has a proven track record rather than new designs, which would require testing to prove compliance with a client specific specification. Following the "functional requirements" tender, a commercial tender was completed. The commercial tender included options for the level of materials management covered by the service companies who satisfied the functional requirements. Details of operating value drivers used to direct focus on potential cost savings are described as well as how total cost of ownership has been reduced to the benefit of both the end users and the lead suppliers. Performance measures developed for the agreement are discussed, as well as how these measures reflect progress towards stated goals. The authors feel that the processes and procedures presented in this paper have considerable potential benefit to other oil and gas operating companies.