The purpose of this paper is to provide the oil industry completion engineers with a workable method for selecting the appropriate fluid loss control systems for their completions. Fluid loss has long been recognized as a major concern when determining completion costs and assessing well management. For this reason, much research has been dedicated to investigating various methods and equipment to address the scenarios from which fluid loss results. Numerous papers have been written over the years on fluid loss control during well completion and workover. Many of these papers describe a specific method that has been used to address the problem, and a number of innovative devices and fluids have been developed. Most of these devices or systems have been addressed individually in the literature or as comparisons between products that are similar in design and function. Little has been provided on evaluating the merits of a variety of systems in an effort to provide a means of selecting an appropriate solution on a well-by-well or situation basis. This paper provides an in-depth discussion on the benefits, limitations, methods of operation, and possible applications for each of the methods and equipment currently in use.

In the Indonesian Archipelago oil-and-gas fields, high pressure/high temperature (HP/HT) sour-service applications are becoming more prevalent as new areas are being explored and defined. In order to select the appropriate metallurgy and elastomers for completion products in these corrosive environments, careful consideration must be given to the well environment. Therefore, thorough review of well data is required so that completion cost efficiency can be realized, and product integrity can be maintained. This paper will present a selection process that can be used to identify the most appropriate metallurgy and elastomers for various wellbore environments, and in the case histories presented here, was beneficial in selecting the completion components for the HP/HT applications in these fields.

fax 01-972-952-9435. AbstractConventional liner-hanger systems typically rely upon the primary cement job as the main method of sealing the liner/casing overlap, and liner-top packers are run either integrally with the liner hanger or separately in a second trip. In certain applications, however, cementing the complete liner may not be feasible or obtaining a primary cement seal at the liner top may not be achievable; in these situations, a liner-top packer must be used as the primary seal. In cases where the top of cement is above the overlap but below the hanger, the liner top packer is used as a back-up seal for the overlap.Almost all liner-top packers that are run integrally to the liner hanger are set through the application of weight applied through the drill-pipe or landing string. The capability of the liner-top packer to seal with a single element at the maximum pressure rating requires that a sufficient setting force of up to 100,000 lbf be applied through the drill pipe to the packer mechanism. Work performed in Latin America recently showed the limitations of this process and how shallow linertop installations might not have the string weight to apply a sufficient setting force to the liner-top packer.A conventional alternative to an integral packer design is a secondary tie-back packer, but this alternative requires at least two extra trips into the wellbore and picking up of a string of large drill collars to supply the significant force required.A solution was found that was capable of resolving this problem, and the innovative technology applied will be the focus of this paper. An expandable liner hanger that allows a hydraulic setting force to be applied locally to the hanger was used. The setting force for the packer was measurable and consistent. With the success experienced on the first well, the expandable liner hanger was used in subsequent jobs, and in all of them, the operator saved several days of rig time in addition to experiencing a successful completion.

This paper will discuss case studies and details of a pinpoint stimulation/completion process that uses stimulation sleeve technologies in conjunction with swelling packers as part of an openhole, horizontal, well lateral liner that is anchored by an expandable liner hanger. This system will allow an operator to accurately place several individual stimulation treatments without additional intervention in the wellbore. This is accomplished by installing the closed stimulation sleeves and swellable packers as part of the completion string, (horizontal openhole liner) and positioning the string in the wellbore so that the stimulation sleeves are located within the desired production pay zones. The completion string is then anchored in position with an expandable liner hanger. The swellable packers are allowed to expand for a few days and isolate the zones between each of the sliding sleeves. Stimulation/frac equipment is rigged up, and a series of progressively larger balls are dropped throughout the multistage pumping operation. The balls land on the tapered baffles in the sleeves, each of them opening in sequence and sealing off the previously treated zones below. Once opened, a stimulation sleeve allows pumping a treatment into the zone where it is positioned. After being opened, the stimulation sleeves maintain the capability to be closed and reopened, with minor intervention, with a shifting tool allowing for restimulation or other workover at a later date. This new service is a field-proven process with 120 wells completed and more than 850 stages/zones treated. This method reduces the time and cost needed to complete multiple intervals in a well, and bring production on line faster by comparison to conventional multizone horizontal fracturing/stimulation techniques such as multiple perforating and setting plugs. Introduction Multizone wells can pose completion challenges for operators. One challenge—isolating and fracture-stimulating multiple pay zones during the well completion process—is especially demanding when working with cemented production casing strings, openhole completions, or openhole packers and perforated liners. In a conventional completion/stimulation process, the cemented casing string is perforated in the toe and stimulation begins. Sequential steps in this completion process require the operator to set plugs, perforate, and fracture each zone individually. Depending on the well design and fracture-treatment design requirements, several hours per zone may be required for the plug and TCP/wireline trips that prepare each stimulation stage, leaving the fracturing crew idle. Continued innovation has made this process somewhat more efficient in horizontal applications by use of pumpdown composite plugs, but, at its best, operators can still only perform three or possibly four fracture stages per day on a single well. With the increased activity of today's industry, scheduling equipment and manpower for future fracture dates is becoming more difficult and could result in delays in production when multiple fracture treatments are desired. When using an openhole completion technique, the operator drills into the formation and opens a path to the wellbore for production. This works well in formations that have structural stability and contain natural fractures. However, problems arise when stimulation treatments are desired because 'bullhead' fracturing treatments usually result in fracturing the weakest point in the formation without treating the entire pay zone. This complication prevents operators from achieving the maximum potential payout on their investment, and can result in additional expenses for interventions associated with re-stimulating to increase production to make the well commercially viable.

Typically, Liner-hanger systems have relied upon the primary cement job to provide sealing of the liner/casing overlap. Liner top packers have been run either integrally with the liner hanger or separately in a second trip. In certain applications, cementing the complete liner or obtaining a primary cement seal at the liner top has not been achievable. In these situations, a liner top packer must be used as the primary seal. In cases where the top of cement is above the overlap but below the hanger, the liner-top packer is used as a back-up seal for the overlap.Almost all liner-top packers are run integrally with the liner hanger and are set through the application of weight applied through the drill-pipe or landing string. The capability of the liner-top packer to seal at the maximum pressures rated requires that sufficient setting force of up to 80,000 lbf be applied through the drill-pipe to the packer mechanism. Recently, work performed in Latin America showed the limitations of this process when used in shallow liner-top installations where the available drill string weight is not available.A secondary tie-back packer design offers a conventional alternative to an integral packer design, but installation of this type of configuration requires at least two extra trips into the wellbore and picking up of a string of large drill collars in order to have capability to supply the significant setting force required.A solution that resolved the problems discussed above was an expandable liner hanger, which allows setting force to be applied locally to the hanger body through hydraulic pressure. The setting force for the packer was measurable and consistent.The expandable liner hanger was used in two subsequent jobs, and all three jobs were successful, saving the operator several days of rig time.The case history discussion and system description presented in this paper will verify the flexibility and integrity of the expandable liner hanger.