Remedial cementing operations and zone abandonment are difficult to accomplish when low-pressure formations possess high feed rates at low, or even vacuum, surface pressures. Such is the case with several heavy-oil wells recently abandoned in Western Canada. These wells and their respective formations average an economic life of approximately ten years, during which a large amount of formation sand is produced. Traditionally, whenever exposed to hydrostatic pressure, these zones exhibit a vacuum at very large feedrates. Scorecard results of conventional cement squeezes required an average of 2.6 attempts to obtain a positive squeeze pressure. Many conventional cementing abandonment attempts were unsuccessful, resulting in the placement of a casing patch across the open perforations. The mechanical seal was effective in sealing the wellbore, which allowed exploitation of deeper zones. However, this seal reduced the casing internal diameter and can limit further production operations. Also, this mechanical seal may not serve as a final abandonment under certain government regulations. The solution to this challenge was developed by tailoring a treatment pumping schedule that incorporates the use of foamed nonreactive, reactive spacers and foamed cement blends. This new treatment design was used on several wells in early 2002. On most of the wells, positive squeeze pressure was obtained on the first attempt and saved approximately CAD $15,000 per well. The improved process is now being planned for two adjacent fields. This paper details the well challenges and results found by a Canadian operator to successfully abandon low-pressure, heavy-oil producing zones. The solution developed for the case history wells is also presented. Introduction When the economic limit of a hydrocarbon producing well is reached, the well or zone should be plugged and abandoned. Traditional abandonment and sealing techniques include cement squeezes, gel squeezes, bridge plugs, patches, scab liners, and straddle packers.1,2 Cement and gel technologies are typically used for behind-casing repair, and mechanical workover options are usually confined to sealing the casing. For example, a successful technique in completing the abandonment process incorporates the use of mechanical means such as casing patches, casing clad, and/or bridge plugs. Once the mechanical barrier is set above or across the target zone, the wellbore can be circulated with a full hydrostatic column and the well abandoned. However, some government regulatory agencies do not accept mechanical seals as a final abandonment of the well. Typically, to meet regulatory guidelines, the operators must place cement slurry across the open or perforated section. Unfortunately, conventional cement slurries, which have densities from1680 kg/m3 to 2040 kg/m3 (14 to 17 lb/gal) will quickly build hydrostatic pressure in the casing relative to the target formation. In the case of abandoning low-pressure zones, the density of the cement column could fracture the target formation. The hydrostatic pressure of the cement column is high enough to initiate fluid flow into the formation, and the entire perforated interval may not be covered with cement. This results in some of the perforations being sealed while other adjacent perforations remain open. As mentioned earlier, cement technology is commonly a standard technique for zone abandonment. Cements provide a strong, near-wellbore block of gas and fluid production and are able to fill perforation tunnels, channels behind pipe, and washout zones behind pipe. Cement that has adequate strength development and other properties can be designed to withstand future fracture treatments and acid stimulations. However, cement has limitations, such as difficulty penetrating deeply porous rock of a potential gas source or microchannels that develop from cement sheath cracking or poor mud displacement (Figs. 1–3),3–9 resulting in interzone fluid communication.
A downhole force recorder is presented that uses onboard strain gauges along with temperature and pressure sensors to measure and record the forces experienced by a downhole assembly at the end of a coiled-tubing string. Field trials are discussed in order to demonstrate the benefits of the downhole force recorder during a typical fracturing operation. The downhole recorder measures force, pressure and temperature. The recorder utilizes a system of onboard strain gauges, pressure transducers and temperature sensors in order to determine the force applied to the gauge. The pressure and temperature sensors are used to filter the pressure and temperature effects out of the force measurement, as well as to record standard treatment data. All data is stored onboard the tool and recovered postjob at surface. The data obtained is then downloaded and compared to a static tubing forces model to validate the results captured in dynamic well conditions. Field trials were completed over the course of two and a half years, with design improvements to refine data capture capabilities. Initial downhole recorder trials showed that pressure had a large effect on the force measurement. This was offset by calculating the piston areas of the gauge and writing algorithms to remove the pressure-induced force. The latest field trials verify the data collected by the downhole force recorder represents actual force measurements in dynamic well conditions and in varied reservoir types. This data provides more precise downhole information than the general data found in static models. The downhole force recorder has been successfully used in over a hundred deployments. Four significant uses for accurate downhole force measurments have been identified: validating third-party force models and better calibrating downhole force recorders used under similar fracturing operationscompleting an informed rootcause analysis when troubleshooting job performance issuesproviding operators with more information on force, pressure, and temperature to support job planning for typical completionsinfluencing future product development driven by force and depth requirements captured under specific well conditions. Novel/Additive Information: The novelty of the new downhole force recorder is its ability to accurately determine the force experienced by a bottomholeassembly (BHA) at the end of the string when used during typical fracturing operations. Capturing this new downhole force information will transform how operators approach job planning and troubleshooting on well completions, and how tool designers approach future product development for fracturing operations.
This paper documents recent field cases in which attempts were made to mitigate casing vent flows (CVF's) on producing and abandoned wells by incorporating permeability-blocking gels with specialized cement blends. CVF's are defined in this paper as sustained gas pressure on the annuli of producing and surface casings. The amount of gas flow rate can vary from a few bubbles to cubic meters per day. However, when the annuli are shut-in, the gas pressure can build to a significant amount. The procedures detailed in this paper are the result of lab studies and postjob reviews of failed remedial attempts. Specific attention is given to why squeeze-cementing procedures can fail to provide long-term seals against source-gas production from casing vents. In most cases, rework of the abandonment procedures cost the operators over $200,000 CAD. The studies showed four possible causes of recurring CVF's:Development of thaumasite in the setting cementLeaking isolation toolsIncomplete long-term seal of source zonesIncorrect source detection or squeeze interval Cement-source quality and bulk handling methods were also investigated, but showed no evidence of probable cause. This paper explains the findings from laboratory studies and job reviews that lead to improved procedures. These improved solutions were conducted on 23 wells in the later part of 2001. Introduction The industry commonly encounters annular gas pressure on cemented casing annuli. However, this condition is often referred to in different terms based on the local interpretation of the problem. Terms such as sustained annular-casing pressure, annular gas pressure, casing vent flows, or annular gas flows refer to the same general problem. This problem exists when gas pressure builds on casing-by-casing annuli, the pressure is bled to zero, then the gas pressure returns over time. The amount of gas pressure can vary from slightly above atmospheric pressure to that of near deepgas reservoir pressure depending on the gas source and flow path from the source to the surface. Also, the amount of gas bled from the annuli can vary from a very slight flow to 1,000's of standard cubic meters per day. For uniformity in this paper, the described problem of gas pressure in the casing-by-casing annulus will be referred to as casing vent flows (CVF's). CVF's can be caused by several factors. However, the industry has recognized the following factors as the main causes:Poor mud displacement in the primary cement placement (Fig. 1)Cement sheath failure, resulting in sheath cracking (Fig. 2)Gas migration through the setting cement creating gas channels in the set cement (Fig. 3)Low cement top These factors are well documented, appearing frequently in past research. An overview is given in the following sections. Poor Mud Displacement. CVF can also achieve a firm foothold if mud displacement during the primary cementing operations is poor. A primary requisite for lowering the chances of CVF is effective mud displacement,1–3 which provides a relatively clean pipe and formation surface to which the cement slurry can bond. Generally, 90% mud displacement efficiency provides adequate zonal isolation, while 95% provides excellent zonal isolation.4 Lowering the drilled-solids content of the drilling mud, conditioning the hole, and reducing the long-term gel strength of the drilling mud helps obtain more efficient mud displacement.4 A properly designed cement system does not eliminate the need for proper mud conditioning or for following best cementing practices.2 These best practices include pipe movement, casing centralization, and spacer design in addition to mud conditioning as stated above. Poor Mud Displacement. CVF can also achieve a firm foothold if mud displacement during the primary cementing operations is poor. A primary requisite for lowering the chances of CVF is effective mud displacement,1–3 which provides a relatively clean pipe and formation surface to which the cement slurry can bond. Generally, 90% mud displacement efficiency provides adequate zonal isolation, while 95% provides excellent zonal isolation.4 Lowering the drilled-solids content of the drilling mud, conditioning the hole, and reducing the long-term gel strength of the drilling mud helps obtain more efficient mud displacement.4 A properly designed cement system does not eliminate the need for proper mud conditioning or for following best cementing practices.2 These best practices include pipe movement, casing centralization, and spacer design in addition to mud conditioning as stated above.
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