The challenge with through tubing sidetrack completions has been dealing with small clearances and the lack of ready-made equipment. Over the last 10 years and 450 coiled tubing drilling sidetracks on Alaska's North Slope a number of unique completion designs have been developed to maximize production and achieve vertical/zonal isolation. These completion techniques are now proven, and may make lower cost through tubing sidetracks more feasible for other mature fields. Introduction Low cost reservoir access is a key component to sustaining production from maturing fields. Coiled tubing drilling (CTD) and through tubing rotary drilling (TTRD) can achieve significant cost savings by sidetracking through existing production tubing. However, the critical completion phase of these sidetracks is challenged by small clearances and custom equipment. During the course of completing over 450 CTD sidetracks through 4 1/2-in. and 3 1/2-in. production tubing in Alaska, a number of innovative completion designs have been developed to maximize production, achieve zonal isolation, allow for selective multilateral production, and preserve the parent wellbore for additional sidetrack opportunities. This paper will detail specialized liner cementing equipment and techniques and provide design and operational guidelines for several proven through tubing completion options:Tapered 3 3/16-in. × 2 7/8-in. fully cemented liners. Placement of larger 3 3/16-in. liner in the upper build section permits future sidetracks (with 2 3/4-in. bit) to other undrained oil deposits.Insertion of a specialized sub in the liner provides flexibility for low cost selective multilateral production or low cost patch isolation of upper oil lense perforations.Combined cemented and slotted liner "bonzai" completions save tubing conveyed perforating costs.Preserving parent wellbore production - Standing valves in inflatable bridge plugs or in whipstock anchor packers provide protection to existing perforations while drilling and allow production to be re-established. When the lateral liner has to be cemented, hollow whipstocks can be used to re-establish production from the parent wellbore.Aluminum kickoff billet at top of liner provides 100% lining of wishbone multi-laterals.Work is progressing with expandable screens and solid liners to address unconsolidated sands and wellbore instability. Continuous innovation and close collaboration with the service industry has yielded successful solutions for challenging through tubing completions. These proven techniques have positioned CTD as the preferred method for re-entry sidetracks on Alaska's North Slope (figure 1). The completion options discussed in this paper may make low cost through tubing sidetracks more feasible for other mature fields.
Technology that permits simultaneous drilling and reaming was introduced in a high-pressure exploration well in the operator's Nile Delta program. This paper describes the development of ream while drilling (RWD) technology and its application in one well in the Mediterranean Sea offshore Egypt. In combination with an anti-whirl PDC bit and oil-based mud, the tool was first used to drill a 13 3/4" hole below the 13 3/8" caing. Afterwards, the RWD system successfully drilled a 12 1/4" hole below the 11 3/4" casing. For both sections, the operations were accomplished in a total of three runs at average penetration rates as much as 152% higher than those recorded in the best available offsets. Total savings resulted from simultaneous drilling and reaming was US $1 million. Introduction To date, Amoco Egypt Oil Company has drilled four wells as operator of the Ras El Barr Concession, located offshore the Mediterranean Nile Delta area, some 56 km northeast of Damietta (Fig. 1). The first two wells - Ha'py-l and Seth-l evaluated upper Pliocene sands (1800-2000 m). The Jj 70- 1 (Akhen-l) exploration well represented the operator's first attempt to evaluate the Middle Miocene Serravallian sands (3564 - 4200 m), in which a sizable gas accumulation had been discovered in an adjoining concession. Concurrent with the drilling of Akhen-1, the operator prepared the well design for Ji 70–2 (Osiris East - 1), which was intended to be a third shallow gas test. Located 6 km east of Akhen-1, the Osiris East-l was originally being designed as a further evaluation of the Ha'py-l (A20 sand sequence). However, with the unexpected discovery of gas in the deeper Pliocene sands of Akhen-1, the Osiris- 1 was re-designed as a second Serravallian evaluation. Figure 2 illustrates the structural cross-section of the Ras El Barr Concession, highlighting the mapped horizon of the A70 gas sands (Kafr El Sheikh) discovered in Akhen-1 and their correlation to the subsequent Osiris E-l. Stratigraphically, the Middle Miocene Serravallian section consists primarily of shales with streaky sandstones in the upper section and blocky sandstone bodies near the base of the section. These two sections represented the main producing sands in the adjoining Serravallian producer (Offset 1). The Serravallian section underlies the Kafr El Sheikh formation, which consists primarily of highly reactive shales with thin sandstone and siltstone streaks. Figure 3 illustrates the lithology representative of the two Ras El Barr Serravallian tests wells, along with the corresponding rock strength and abrasive characteristics. As shown in the figure, with the exception of an anhydrite stringer at 2850 m, the Serravallian and the wet Pliocene sands of the overlying Kafr El Sheikh formation ((1292- 3564 m) are not particularly hard or abrasive. Conversely, abnormal and variable pore pressures and resultant hole instability problems - swelling shales, caving, tight holes and eventual loss of circulation - encountered in Nile Delta wells have been well-documented in the literature. More specifically, the overpressured zones originate through the 2272-m thick Kafr El Sheikh formation, primarily because of overburden and tectonic effects. The pressure gradually increases with depth and shale percent, reaching its maximum value near the bottom of the Kafr El Sheikh shale. Thus, completing a trouble-free well through the Kafr El Sheikh requires the optimum in mud type/weight. P. 61^
Smart well completions include downhole gauges, sliding circulation valves, open/close safety valves, control lines, and fiber cables or a combination of these. One method for deploying this downhole equipment is achieved by affixing it to the outside of the casing and permanently cementing it in place; however, a challenge with external-casing equipment is helping to prevent damaging the installation if perforating is the chosen method to establish effective communication between the wellbore and formation. This challenge is further magnified when the well is drilled near-vertical and run on the outside of a large-diameter casing. This paper discusses the execution of an engineered design of service to perforate a 7-in. diameter production smart well completion using 4 5/8-in. tubing-conveyed perforating (TCP) gun assemblies. As part of the completion design, the TCP gun assemblies were hung below the bottomhole assembly (BHA). A fiber-optic (FO) package was run external to the casing, and the well had a deviation less than 5°, preventing the use of high-side logging tools. Various options, discussed later in this paper, were considered to locate the azimuthal orientation of the fiber cables, including a new-to-market technology tool. Ultimately, a method was devised to engineer an ultrasonic logging tool to be deployed in conjunction with a north-finding gyroscope tool to accurately determine the location of the external-casing equipment. TCP guns were then hung below the tubing string, which included a fixed-point orienting sub that could be used to confirm the direction of all the planned perforations. To achieve operational and economic objectives, the TCP assembly was dropped to the bottom of the well so that the well could be immediately placed on production without killing the well or retrieving the spent perforating guns. The well was successfully perforated without damage to the external-gauge equipment, showcasing that collaborating with the operator, and understanding their value drivers, led to an engineered solution that maximized the asset value of the well.
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