In the oil and gas industry, it is a common practice to install production casing through producing formations, with cement providing the primary inter-zonal isolation in the annulus. However, inadequate displacement efficiencies, fluid contamination, and loss circulation intervals sometimes limit the ability of a cementing operation to provide zonal isolation sufficient to prevent annular communication over the life of the well. Formation damage caused by cementing operations can also adversely affect life-of-the-well production capabilities, thereby adversely affecting the economics of the well. New completion technologies using swellable elastomers can offer an alternative to cementing operations performed over producing formations. However, conventional floating equipment has limited the application of swellable elastomers in some completion operations. For example, in noncemented completions where swellable elastomers provide the only annular barrier, a mechanical seal having a service life equal to the life of the well under downhole conditions is required at the toe of the production casing. This paper describes the benefits of swellable elastomers used to provide life-of-the-well zonal isolation. Additionally, the paper recounts a problem job in which improperly selected check valves were used and new check valves specifically designed for noncemented completions were successfully introduced. Lastly, this paper provides details about equipment designed for a south Texas well that will incorporate SEPs, float equipment, and a combination wiper plug designed specifically for a noncemented completion to be performed in late 2007 or early 2008. Introduction Though the use of swellable elastomers is becoming more and more common, one component of the system that has not received sufficient attention is the float assembly that can be used with swellable element packers (SEP). This paper will review a problem job in which the use of conventional float assemblies resulted in a near-miss incident. A detailed description of the problem and a proposed solution are discussed. Common Completion Methods Numerous completion methods are available for producing oil wells and injection wells. The type of completion method used is governed by the type of reservoir present, the intended production operations, and a host of other factors. Dyson et al. (1999) described several sand control and non-sand control completion methods, focusing mostly on single-string completions. The following are examples of standard industry methods currently being applied.The most simple and cost-effective completion method available is the openhole or "barefoot" completion. This method is used in hard formations where the oil-producing zone is consolidated and not loose. The oil-producing zone is completely open, and no liner or perforated casing is used to case the hole (Fig. 1) (Helmy, et al. 2006).A second completion method involves the use of a slotted liner or gravel pack liner. Typically, the liner is suspended or hung from the bottom of an intermediate string and does not reach surface. These types of liners prevent the entry of sands and solids into the liner ID using either a series of slots or screens, or using gravel (Fig. 2).One of the most common methods of completion is cementing production casing in place through the producing formation, and then perforating the casing. Because the liner or casing must remain in place for the life of the well and its replacement would be very costly, another string of pipe called tubing is run into the well to act as the flow string (Fig. 3).
This paper describes the development of a downhole cleaning device based on fluidic oscillation. This fluidic oscillator is used for removal of deposits from the near-wellbore area, perforations, and screens. The cleaning device creates pressure waves within the wellbore and formation fluids that (1) break up near-wellbore damage and (2) restore and enhance the permeability of the perforations and near-wellbore area. Fluidic oscillators have been used for various purposes in a wide range of industries for many years. They typically exhibit reliable oscillation over a wide range of flow rates and have no moving parts. The cleaning tools presented here are specifically designed for high-pressure, submerged operation and maximum pressure-pulse amplitude. The unique design has been carefully refined through theoretical and experimental methods. This paper discusses fluidic oscillator theory and presents a numerical analysis of a specific oscillator design, as well as an analysis of experimental test data at various flow rates. The provided case histories demonstrate the utility of fluidic oscillation as a wellbore-cleaning device. Introduction The industry has taken a quantum leap with the release and commercial application of the next generation of fluidic oscillator near-wellbore stimulation service. Over 50 successful field jobs have been performed with this new technology. In many cases, production increased over previous treatments that used an older type of fluidic oscillator. Several unique case histories resulting in production increase and job time reduction are discussed later in this paper. The new design is unique in its adaptation of the classical feedback loop oscillator design. One innovative design feature is the ability to tune the output frequency of this tool by scaling the oscillator pattern for optimum cleaning and stimulation efficiency as our knowledge and database of production results grows. Unlike other "use-as-is" fluidic oscillators this next generation fluidic oscillator design is "living" technology that can grow and adapt to field feedback. The fluidic oscillator is a downhole, cleaning device based on patented and patent-pending fluidic oscillator technology that generates alternating bursts of fluid. This tool is used for the removal of deposits from the near-wellbore area, perforations, and screens. The cleaning device creates pressure waves within the wellbore and formation fluids that can (1) break up near-wellbore damage and (2) restore and enhance the permeability of the perforations and near-wellbore area. This tool incorporates the proven, classical feedback loop theory for generation of the Coanda effect. Fluidic oscillators are available in sizes from 1.69 to 2.88-in. OD and are adaptable to both jointed pipe and coiled tubing applications. The tools operate at an optimal pressure drop of approximately 2,000 psi and oscillate at a frequency between 300 to 600 Hz. The tools are rated to 400°F and are suitable for sour gas service. Fluidic oscillators incorporate several design features that help improve reliability, function, and performance while reducing tool life-cycle costs. These features include:A patented, metal-to-metal, tapered seal---no moving parts or seals.Side jets that maximize cleaning energy by direct impingement on the casing or near wellbore.Multi-angular fluid impingement.Higher energy output over a narrower frequency range than conventional oscillators.Turbulence created by side and down jets that helps lift debris out of the hole.A down jet that clears debris, obstructions, or bridges while tripping into hole.Adaptability for running on either coiled tubing or jointed pipe.Customized inserts to maximize flow rate and pressures.Replaceable inserts manufactured using modern high-tech electrical discharge machining (EDM) process.
Drilling operations performed through the shoe-track are generally considered duplicated effort by many operators. Nonetheless, shoe-track drillout is an operation that must be performed on all surface or intermediate casing strings or liners. Slow penetration rates are often experienced, even when drilling through so-called drillable casing equipment. Today's costly drilling operations force operators to attempt to reduce nonproductive operations whenever possible. Therefore, improved shoe-track drillout performance can improve operators' overall drilling cost and schedule. Thus, a better understanding of downhole dynamics is necessary to develop improved drilling procedures. A review of jobs from the North Sea database of cement jobs and shoe-track drillouts revealed that, of the more than 1,200 data points available to the authors, 83% of the drillout times were less than three hours; 70% of the drillout times were less than two hours; and 50% of the drillout times were less than one and one-half hours, with the overall average being 93 minutes. When a single type of cementing casing equipment was drilled in some wells in 30 minutes and other wells in three hours, questions were raised as to what major contributing factors determine actual drillout time. Two case histories are presented with close attention paid to drilling parameters that adversely affect actual weight applied by the bit to the target being drilled. A better understanding of weight on bit (WOB) and weight on target (WOT) is needed to best determine drilling procedures to be used for any given drillout. This paper documents lessons learned from successful drillouts performed with conventional and rotary-steerable drilling assemblies. Software-driven recommendations are provided for improved interpretation of downhole forces applied to the target being drilled. Introduction During the past several years, much progress has been made in fixed-cutter bit designs. Improved technology and manufacturing processes have improved bit performance and reliability to the extent that polycrystalline diamond compact (PDC) bits are successfully encroaching into hard-rock drilling applications. Formations that once were reserved for roller cone bits are successfully being drilled with PDC bits. Additionally, it is becoming more common for PDC bits to be used to drill out cementing plugs and float equipment. These achievements reflect recent improvements in technology and the innovation involved in bit design and manufacture. The aggressive cutting nature of many fixed-cutter bits is designed to maximize bit performance when drilling formations. However, this aggressive nature can cause large debris to be created when drilling through cementing plugs or other cementing casing equipment (Fig. 1). Specifically, the elastomer and phenolic materials commonly used in the construction of cementing plugs and floating equipment tend to tear or fragment into large pieces rather than the typical shearing that occurs when drilling formations. The cuttings created when drilling cementing casing equipment are more significant than cuttings created when drilling formation. In some situations, such debris can become lodged in the junk slot area of the fixed-cutter bit. Therefore, special consideration should be made when determining procedures to be followed when drilling out shoe tracks.
Producing well conditions in the southern region of Mexico present challenges that can benefit from the use of a newly developed intervention technology. This paper describes the development of this real-time fiber-optic (RTFO) integrated system. RTFO is used for depth correlation and real-time pressure and temperature monitoring inside the coiled tubing (CT) and the outer annulus. Additionally, distributed temperature sensing (DTS) survey capabilities can provide instantaneous evaluation of downhole treatments in real-time. The data is transmitted by means of a 4-mm fiber-optic (FO) capillary to surface data acquisition equipment, allowing both monitoring and job execution changes in real-time. This technology allows operators to make immediate treatment decisions to help achieve the best results possible. Additional sensor expansion is possible because of the modular design of the bottomhole assembly (BHA). This paper discusses the fast-track developmental process of the RTFO system as well as quantitative lab and full-scale yard testing. Case histories from three high-temperature deep candidate wells in the Latin American region are presented. Lessons learned from the initial field trials and the resulting next-generation design enhancements and sensor expansion capability of the tool are also highlighted. The synergy of the CT RTFO system, cleaning nozzle selection, and a tailored fluid program proved to be a successful combination for effective cleaning of the case history wells discussed.
Operators today face an ever-increasing demand for locating commercial reserves and producing those reserves with attention to exploration and development costs. In addition to basic financial pressures, operators also strive to reduce the environmental impact of well construction and production operations. Extended-reach drilling technology allows operators to reach recoverable reserves that, in the past, were unreachable. Specifically, extended-reach drilling from a multipad wellsite allows significant portions of the well-construction costs to be distributed amongst multiple wells, rather than being carried by an individual wellbore. Also, the capability to drill multiple wells from a single pad reduces the environmental impact of the drilling operation. Extending wellbore reach from a given pad depends on the location of the target formation. Depth, horizontal distance, and production type significantly affect the type of drilling program as well as the casing running operation. Casing flotation is a proven technology that has been deployed in fields around the world to extend the attainable lateral reach of the casing running operation. In many wells, the buckling limits of the casing being run, rather than insufficient hook load, prevent successful casing running operations from pushing the casing into the lateral section. In some cases, slack-off loads with small casing strings cause helical buckling and lock-up of the casing before reaching total depth. This paper documents the use of flotation technology in several wells where casing lock-up caused by buckling limits was averted to allow successful casing running operations to be performed without the requirement of costly premium torque-shouldered connections. Detailed prejob planning and computer simulations are provided to demonstrate the limits without casing flotation and the step out achieved with it.
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