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A number of cementitious materials used for cementing wells do not fall into any specific API or ASTM classification.These materials include: Pozzolanic materials include any natural or industrial siliceous or silico-aluminous material, which will combine with lime in the presence of water at ordinary temperatures to produce strength-developing insoluble compounds similar to those formed from hydration of Portland cement. Typically, pozzolanic material is categorized as natural or artificial, and can be either processed or unprocessed. The most common sources of natural pozzolanic materials are volcanic materials and diatomaceous earth (DE). Artificial pozzolanic materials are produced by partially calcining natural materials such as clays, shales, and certain siliceous rocks, or are more usually obtained as an industrial byproduct. Pozzolanic oilwell cements are typically used to produce lightweight slurries.
Most primary cement jobs are performed by pumping the slurry down the casing and up the annulus; however, modified techniques can be used for special situations. Conductor, surface, protection, and production strings are usually cemented by the single-stage method, which is performed by pumping cement slurry through the casing shoe and using top and bottom plugs. There are various types of heads for continuous cementing, as well as special adaptors for rotating or reciprocating casing. Stage-cementing tools, or differential valve (DV) tools, are used to cement multiple sections behind the same casing string, or to cement a critical long section in multistages. Stage cementing may reduce mud contamination and lessens the possibility of high filtrate loss or formation breakdown caused by high hydrostatic pressures, which is often a cause for lost circulation.
The predominant cause of cementing failure appears to be channels of gelled drilling fluid remaining in the annulus after the cement is in place. If drilling-fluid channels are eliminated, any number of cementing compositions will provide an effective seal. Proper hole preparation is the key to success. In evaluating factors that affect the displacement of drilling fluid, it is necessary to consider the flow pattern in an eccentric annulus (i.e., where the pipe is closer to one side of the hole than the other). Flow velocity in an eccentric annulus is not uniform, and the highest velocity occurs in the side of the hole with the largest clearance.
Remedial cementing requires as much technical, engineering, and operational experience, as primary cementing but is often done when wellbore conditions are unknown or out of control, and when wasted rig time and escalating costs force poor decisions and high risk. Squeeze cementing is a "correction" process that is usually only necessary to correct a problem in the wellbore. Before using a squeeze application, a series of decisions must be made to determine (1) if a problem exists, (2) the magnitude of the problem, (3) if squeeze cementing will correct it, (4) the risk factors present, and (5) if economics will support it. Most squeeze applications are unnecessary because they result from poor primary-cement-job evaluations or job diagnostics. Squeeze cementing is a dehydration process.
El-Husseiny, Mahmoud Ahmed (Egyptian Natural Gas Holding Company) | Khaled, Samir Mohamed (AL-Azhar University and the British University in Egypt.) | El-Fakharany, Taher El-Sebaay (AL-Azhar University.) | Al-Nadi, Yehia Mohamed (AL-Azhar University.)
Abstract Although devised in 2003, managed pressure drilling (MPD) has gained widespread popularity in recent years to precisely control the annular pressure profile throughout the wellbore. Due to the relatively high cost and complexity of implementing MPD, some operators still face a challenge deciding whether or not to MPD the well. In the offshore Mediterranean of Egypt, severe to catastrophic mud losses are encountered while conventionally drilling deepwater wells through cavernous fractured carbonate gas reservoirs with a narrow pore pressure-fracture gradient (PP-FG) window, leading to the risk of not reaching the planned target depth (TD). Furthermore, treating such losses was associated with long non-productive time (NPT), massive volume consumption of cement, and lost-circulation materials (LCM), in addition to well control situations encountered several times due to loss of hydrostatic head during severe losses. Accordingly, the operator decided to abandon the conventional drilling method and implement MPD technology to drill these problematic formations. In this paper, the application of MPD is to be examined versus the conventional drilling in terms of well control events, NPT, rate of penetration (ROP), mud losses per drilled meter, LCM volume pumped, and drilling operations optimization. According to the comparative study, MPD application showed a drastic improvement in all drilling performance aspects over the conventional drilling where the mud losses per drilled meter reduced from 19.6 m/m to 3.7m/m (123.2 bbl/m to 23.4 bbl/m). In addition to that, a 35% reduction of NPT and also a 35% reduction of LCM pumped, and 67.2 % reduction by volume of cement pumped to cure the mud losses. Moreover, the average mechanical rate of penetration increased by 37.4%. MPD was also credited with eliminating the need for an additional contingent 7" liner which was conventionally used to isolate the thief zone. The MPD ability to precisely control bottom hole pressure during drilling with the integration of MPD early kick detection system enables the rapid response in case of mud loss or kick, eliminating kick-loss cycles, well control events, and drilling flat time to change mud density. This paper provides an advanced and in-depth study for deep-water drilling problems of a natural gas field in the East Mediterranean and presents a comprehensive analysis of the MPD application with a drilling performance assessment (average ROP, mud losses, LCM and cement volumes, well control events) emphasizing how MPD can offer a practical solution for future drilling of challenging deepwater gas wells.
Elyas, Mohamed (Weatherford) | Freile, Daniel Agustin (Weatherford) | Pawlowski, Maciej (Weatherford) | Tagarieva, Larisa (Weatherford) | Elaila, Shamseldin Zakrya (Kuwait Oil Company) | Sergeev, Evgeny (Kuwait Oil Company)
Abstract While drilling an 8 /2-incli section of a north Kuwait producer well, severe mud losses were encountered. Hence, it was decided to design a light weight cement for the 7-inch liner section to avoid further losses while pumping the slurry. The main objective was to achieve a hydraulic isolation to avoid any heavy remedial intervention and potential dump flood behind the liner from the high-pressure Lower Burgan (LB) to Shuaiba. Full suite of well integrity logs were ran to properly assess whether enough hydraulic isolation was in place. To evaluate the bonding quality of the cement, two independent measurements were carried out across the 7-inch liner with the ultrasonic and sonic bond logs. A subsequent temperature survey was recorded to determine any geothermal anomaly, which could be indicative of fluid movement behind the casing. Finally, oxygen activation stations were conducted based on the cement log and temperature surveys to assure no water movement behind the casing. The ultrasonic and sonic bond log measurements showed an acceptable bond quality generally. However, the top part of Shuaiba formation up to LB exhibited relatively lower bond quality. The subsequent temperature and oxygen activation logs indicated that the zonal hydraulic isolation was achieved by showing no water movement behind the 7-inch liner. The two complementary surveys helped to take the proper forward decision for this well to go ahead with the planned perforation without cement remedial squeeze, since enough hydraulic isolation was proved to be in place behind the 7-inch liner. Additionally, this saved the rig utilization time and cost by avoiding unnecessary remedial operation. This is usually a heavy-duty operation, which takes time and induces holes in the casing that should be avoided, knowing this type of operation only provides a very marginal gain in terms of isolation. Furthermore, the well is currently producing at 0% water cut after completion. The proper cement design using light weight cement and optimized casing-landing plan were crucial to achieve good cement placement against formation. The use of the right well integrity approach helped to confirm that effective hydraulic isolation was achieved. Hence all these efforts resulted in the saved rig utilization time and cost by avoiding unnecessary squeeze intervention.
Abstract Assurance of well integrity is critical and important throughout the entire well's life cycle. Pressure build-up between cemented casings annuli has been a major challenge all around the world. Cement is the main element that provides isolation and protection for the well. The cause for pressure build-up in most cases is a compromise of cement sheath integrity that allows fluids to migrate through micro-channels from the formation all the way to the surface. These problems prompt cementing technologists to explore new cementing solutions, to achieve reliable long-term zonal isolation in these extreme conditions by elevating shear bond strength along-with minimal shrinkage. The resin-cement system can be regarded as a novel technology to assure long term zonal isolation. This paper presents case histories to support the efficiency and reliability of the resin-cement system to avoid casing to casing annulus (CCA) pressure build-up. This paper presents lab testing and application of the resin-cement system, where potential high-pressure influx was expected across a water-bearing formation. The resin-cement system was designed to be placed as a tail slurry to provide a better set of mechanical properties in comparison to a conventional slurry. The combined mixture of resin and cement slurry provided all the necessary properties of the desired product. The slurry was batch-mixed to ensure the homogeneity of resin-cement slurry mixture. The cement treatment was performed as designed and met all zonal isolation objectives. Resin-cement’s increased compressive strength, ductility, and enhanced shear bond strength helped to provide a dependable barrier that would help prevent future sustained casing pressure (SCP). The producing performance of a well depends in great part on a good primary cementing job. The success of achieving zonal isolation, which is the main objective of cementing, is mainly attributed to the cement design. The resin-cement system is evolving as a new solution within the industry, replacing conventional cement in many crucial primary cementing applications. This paper highlights the necessary laboratory testing, field execution procedures, and treatment evaluation methods so that this technology can be a key resource for such operations in the future. The paper describes the process used to design the resin-cement system and how its application was significant to the success of the jobs. By keeping adequate strength and flexibility, this new cement system mitigates the risk of cement sheath failure throughout the life of well. It provides a long-term well integrity solution for any well exposed to a high-pressure environment.
Abstract The Khazzan and Ghazeer gas fields in the Sultanate of Oman are projected to deliver production of gas and condensate for decades to come. Over the life of the project, around 300 wells will be drilled, with a target drilling and completion time of 42 days for a vertical well. The high intensity of the well construction requires a standardized and robust approach for well cementing to deliver high-quality well integrity and zonal isolation. The wells are designed with a surface casing, an intermediate casing, a production casing or production liner, and a cemented completion. Most sections are challenging in terms of zonal isolation. The surface casing is set across a shallow-water carbonate formation, prone to lost circulation and shallow water flow. The production casing or production liner is set across fractured limestones and gas-bearing zones that can cause A- and B-Annulus sustained casing pressure if not properly isolated. The cemented completion is set across a high-temperature sandstone reservoir with depletion and the cement sheath is subjected to very high pressure and temperature variations during the fracturing treatment. A standardized cement blend is implemented for the entire field from the top section down to the reservoir. This blend works over a wide slurry density and temperature range, has expanding properties, and can sustain the high temperature of the reservoir section. For all wells, the shallow-water flow zone on the surface casing is isolated by a conventional 11.9 ppg lightweight lead slurry, capped with a reactive sodium silicate gel, and a 15.8 ppg cement slurry pumped through a system of one-inch flexible pipes inserted in the casing/conductor annulus. The long intermediate casing is cemented in one stage using a conventional lightweight slurry containing a high-performance lost circulation material to seal the carbonate microfractures. The excess cement volume is based on loss volume calculated from a lift pressure analysis. The cemented completion uses a conventional 13.7 - 14.5 ppg cement slurry; the cement is pre-stressed in situ with an expanding agent to prevent cement failure when fracturing the tight sandstone reservoir with high-pressure treatment. Zonal isolation success in a high-intensity drilling environment is assessed through key performance zonal isolation indicators. Short-term zonal isolation indicators are systematically used to evaluate cement barrier placement before proceeding with installing the next casing string. Long-term zonal isolation indicators are used to evaluate well integrity over the life of the field. A-Annulus and B-Annulus well pressures are monitored through a network of sensors transmitting data in real time. Since the standardization of cementing practices in the Khazzan field short-term job objectives met have increased from 76% to 92 % and the wells with sustained casing pressure have decreased from 22 % to 0%.
Abstract In workover phase prior to commencing sidetrack operation, it is required to recover old existing completion string for isolating & abandoning existing reservoir section in accordance with well integrity and global well abandonment standards. Prior to utilization of the coiled tubing cementing approach, the practice was to recover all existing completion by cutting and pulling out the dual tubing or mill the permanent packer. After all the completion recovery, spot and squeeze cementing operations were conducted. However a major drawback of this process is, until recovering some part of completion string, the actual physical condition of the completion strings remains unknown and it poses high risk to get stuck in cased hole or end up in loosing accessibility inside completion string due to corrosion. Furthermore, in some of the old wells had failure to recover completion components like a dual flow assembly and a dual packer due to completion age, had led to improper zonal isolation. Even if all the old existing completion is recovered successfully, it consumes a lot of operation time and several fishing trips with overshot or junk mill BHA (Bottom Hole Assembly). In order to minimize the risk of being stuck or loosing accessibility and ending up failing to recover existing completion and to save operational time, the coiled tubing cementing was conducted to isolate existing reservoir and leave remaining parts of completion downhole. During the operation phase, injectivity test was performed by pumping sea water followed by bull heading kill fluid in to the reservoir. Losses rate was evaluated while observing the well, a high viscosity pill was spotted in order to treat losses and control loss rate. Coiled tubing was rigged up on Long string and run in hole to tag a landing nipple in existing completion string in order to have reference of depth corrected against ORTE (Original Rotary Table Elevation) depths while using the coiled tubing for operations. After having correct reference of depth with tagging completions nipple accessory, coiled tubing with slim OD cementing BHA was run in hole to tag PBTD (Plug Back Total Depth) and then picked up to certain depth while spotting cement slurry at controlled speed. Once the complete amount of slurry was spotted during picking up coiled tubing was pulled out to be away from cement slurry and then coiled tubing BOP (Blow Out Preventer) was closed and cement was squeezed in to the formation. After squeezing pre determined volume or archiving the lock up pressure, coiled tubing was pulled further up and circulated out to ensure all cement slurry out from coiled tubing (inside and outside). Top of cement was confirmed by tagging with the milling assembly connected to coiled tubing and the pressure test was performed after waiting on cement to confirm the integrity of the barrier. For short string, similar abandonment plug process was followed as that of the long string. After performing tagging operations, cement was spotted while pulling out the coil tubing to certain depth and then coil tubing was picked up above the cement to squeeze cement in to the formation. Similar coiled tubing cement operation for isolating lower perforations was performed on three other wells, and proper zonal isolation was achieved against reservoirs. This improved approach of abandoning lower reservoir prior to completions recovery proved to save 2-3 days of rig operational time in comparison to previous operations practices of recovering existing completion completely & then perform cementing operations for zonal isolation against each reservoir. Based on the successful result in three wells, it is concluded that this coiled tubing cement operation is effective for zonal isolation and provide savings in operation days.