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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.
Abstract Successful liner cementing in unconventional shale wells is strongly dependent on slurry stability. A delayed-release, high-temperature suspending agent was developed that provides viscosification and stabilization of the slurry without causing excessive viscosification and mixing problems at the wellsite. The suspending aid was prepared from water-soluble, thermally stable monomers copolymerized with degradable crosslinking monomers. The crosslinks degrade as the temperature of the slurry increases, ultimately resulting in dissolution of the polymer and concomitant slurry viscosification. The performance of the suspending aid was demonstrated by means of laboratory testing under typical Eagle Ford shale conditions. Improvements were observed in terms of fluid-loss control (54 cc/30 min [control] to 28 cc/30 min), free fluid (5% [control] to 0%), sedimentation (Δρ 5.2 lbm/gal [control] to Δρ 0.2 lbm/gal), and consistometer off/on tests. Three field examples from the Eagle Ford are presented where the suspending aid was used to establish the desired mud-spacer-cement rheological hierarchy at bottomhole circulating temperature (BHCT); provide sufficient slurry stability to set the liner top plug, circulate out excess cement, and produce a competent cement sheath; and improve the mixability and stability of a barite-weighted spacer.
In parts of South Texas, the cementing of long drilling and production liners has long been one of the most challenging production liners has long been one of the most challenging aspects of well completion. High formation pressures require mud and cement weights that approach the equivalent fracture gradient of the exposed open hole interval. Very low pump rates and excessively long job times have been common due to the constraints imposed by tight annular clearances and the use of heavy, viscous cement slurries.
Another problem associated with these wells is the temperature gradient in this area. Geothermal gradients of 2 deg.F /100 ft. create large temperature differentials from liner top to bottom, even with liners of only moderate length. Consequently, developing TOL compressive strength and adequate seal at the liner lap has been difficult with the cement retarder concentrations necessary for bottom hole conditions.
Positive and/or negative differential pressure tests are normally Positive and/or negative differential pressure tests are normally used to evaluate these jobs and, in many cases, results have been poor. Since these wells are subjected to hydraulic fracturing upon completion, the integrity of the cement sheath is essential and squeeze work must often be performed to achieve good zonal isolation.
A new design approach has significantly reduced the problems associated with cementing these wells. This approach centres on the careful selection of spacers and the use of high-performance cement slurries. Desirable properties of the latt include very low fluid-loss and exceptional fluidity (low rheology) without development of free water or sedimentation.
Early compressive strengths of these systems are also superior to those of the systems used historically in this area. Case histories from several wells are used to demonstrate the success this approach.
Deep cementing operations in the south Texas area have for years been complicated by hole geometry, temperature offerentials, close pressure tolerances, and, in some areas, post-placement gas flow.Casing programs in the deep gas fields of post-placement gas flow.Casing programs in the deep gas fields of this area usually involve setting four strings of pipe to a total depth of between 12,000 and 17,000 feet (see Fig. 1). In a typical well, the shoe of the intermediate casing is set around 10,000 feet. The interval from 10,000-13,000 feet is normally cased with a drilling liner which extends 200-500 ft back into the intermediate string. Annular configuration for this drilling liner is usually 7 5/8, or 7 3/4 inch casing inside 8 1/2 inch open hole, or 9 5/8" casing in 10 1/2 inch hole. Below the drilling liner, the well is drilled to TD and completed either with a full string or a production liner. If a production liner is run, it will frequently be tied-back to surface at a later date.
Temperature gradients in south Texas range from 1.7 deg.F/100 feet of depth near the coast up to 2.2 deg.F/100 feet in extreme south-central Texas. In setting deep liners, this presents two problems. First, temperature gradients of 2.0 deg.F/100 feet translate to very high bottom hole static and correspondingly high bottom hole circulating temperatures, making slurry designs complex. Second, these gradients result in large temperature differentials even over modest length liners, making compressive strength development at the liner top a legitimate concern.
Abstract The two principal functions of oilwell cementing are to restrict fluid movement between zones within the formation and to bond and support the casing. Apart from these, the cement sheath also protects casing from corroding, protects the casing from shock loads when drilling deeper, and plugs lost circulation or thief zones. Once cement is placed in the wellbore, initial setting occurs wherein development of compressive strength becomes more important for further drilling operations. Early strength development is important to help ensure structural support to the casing and hydraulic and mechanical isolation of downhole intervals. Delays in strength development cause significant amounts of lost time because of the need to wait on cement (WOC). Typically, an accelerator is often used to enable early strength development in cement. It is desired that an accelerator should improve overall compressive strength without causing excessive gelation. Nanomaterials (being smaller in size and higher in surface area) are used in several fields, including catalysis, polymers, electronics, and biomedicals. Because of a higher surface area, these materials can also be used in oilwell cementing to accelerate the cement hydration process. Moreover, they are often required in small quantities. This paper documents a case in which nanosilica was used in cement formulations to develop high early strength. Nanosilica also helps enhance final compressive strength and helps control fluid loss. Using the correct quantity of nanosilica, it is possible to design cement slurry with low rheology and good mechanical properties while controlling fluid loss.
The composition and properties of a new type of cementing mixture are discussed. In these compositions, API Class A or C cements are added to a stable water-in-oil emulsion instead of the usual water. The cement disperses in the oil phase and remains out of contact with the water under normal conditions of mixing and storage. At higher temperatures, such as those encountered down-hole during placement, the emulsion breaks and cement hydration can then proceed.
An extremely low filtration rate is obtained; the major part of the filtrate is oil. Thickening times of the mixture may be increased to meet the 18,000-ft casing cementing schedule by varying the amount of emulsifier. As in conventional Portland cement mixtures, high-temperature strength retrogression can be overcome by addition of silica flour.
Results of several field applications show that mixing presents no difficulty if emulsion blenders are used and the emulsion is prepared beforehand.
Water-in-oil emulsions, in which oil is the continuous or external phase and in which water exists as discrete droplets, have for some time been used successfully in drilling muds to reduce filtration loss. Applied to cement slurries, the same results are obtained; i. e., the fluid-loss is greatly reduced. In addition, thickening times may be extended, lower densities and strengths obtained, and water-base borehole fluids more easily displaced without contamination of the cement.
A low filtration rate is often a desirable property in oil well cements since loss of fluid increases placement difficulties and may also cause damage to water-sensitive producing formations. In the casing cementing operation where the cement slurry is pumped into the narrow annulus between open hole and casing, rapid loss of fluid to a porous formation can cause the slurry to thicken and plug the annulus before the desired fill is obtained. Where a casing or a liner is cemented against a productive formation and the well completed through perforations, the fluid lost between the time the cement first contacts the formation and the time a set is obtained may invade the zone past the depth of the perforations. If the sand contains a material which will swell upon contact with cement filtrate, permanent damage may result.