Summary. Highly flexible cement systems can he designed to accommodate a broad range of well conditions with a relatively small number of additives that are readily available from any cementing service company. Fluid-loss additives can be used with dispersants and small amounts of KCI (when applicable) to design slurries for most primary cementing applications-e.g., cementing in CO, and salt-zone environments and prevention of annular flow after cementing. This paper illustrates how materials and slurry properties that are easily specified can be used to improve wellsite success. Introduction The vast array of cementing additives available to the operator today can be mind-boggling, especially if the user does not have direct access to a cementing laboratory for the design and testing of slurries. What at first may appear as a confusing jumble of cementing systems with different applications can be simplified greatly by use of a few well-chosen additives and good cementing practices. Industry has developed several practices that aid in cement-slurry placement. These includepipe movement (either rotation or reciprocation);centralization;wipers across pay zonesuse of both float shoe and collar;minimum two-joint casing between the float shoe and collar;use of both top and bottom cementing plugs;use of appropriate spacers, washes, or scavenger cement slurries;minimization of surge pressures while pipe is run;good displacement practices (to avoid cement channeling); andoptimum use of mixing equipment for density control. We do not intend to expand upon any of these practices. They were mentioned to emphasize that slurry design cannot substitute for well-engineered placement techniques, nor can good mechanical practices substitute for poor slurry design. We advocate the use of fluid-loss additives, coupled with dispersants and small amounts of KCl, as the basis of sound cement-slurry design, a concept that has applications over a wide range of cementing conditions. This paper discussesthe prevention of annular flow after cementing,cementing in plastic salt environments, andcementing in CO, environments. Prevention of Annular Flow After Cementing Annular flow after cementing occurs when the cement column placed in the annulus fails to contain formation pressures and allows formation fluids (gas, oil, or water) to flow into the wellbore. This is, in fact, a kick that occurs after cement has been pumped into place, a phenomenon that has been studied extensively by a number of investigators. Several mechanisms have been postulated to explain this occurrence, including the following.Dehydration of the cement slurry. Dehydration is caused by insufficient fluid-loss control. If it is severe enough, cement solids will bridge the annulus and prevent transmission of the hydrostatic pressure from the still-fluid cement column above the bridge. If the hydrostatic pressure is reduced to a level less than existing formation pressure below the bridge, formation fluids can enter the wellbore.Free-water pockets and channels. These are caused by a separation of cement solids and mix water and can lead to annular flow after cementing because a continuous water channel can exert only the hydrostatic pressure of the mix water itself (usually 8.33 Ibm/gal [998 kg/m 3 1). If this equivalent pressure is less than the formation pressure, annular flow can occur.Slurry; gelation. This can cause flow after cementing because the attraction between the hydrating cement particles may prevent the hydrostatic pressure of the fluid cement column from being fully transmitted to the exposed formations. In effect, the hydrating cement column "supports some of its own weight." Again, if the effective hydrostatic head of the fluid column is reduced to a level below formation pressure, formation fluids can enter the wellbore. Each of these three mechanisms explains why a cement column with a density greater than that of the drilling-fluid column used to drill the well could fail to contain formation pressures. In reality, these mechanisms are not as discrete and as tightly defined as a simple listing may lead the reader to conclude. All three may coexist during a given cement jobs which mechanism will predominate depends on both the well conditions and the cement-slurry design. Some techniques for predicting the potential for annular flow after cementing have been presented in the literature, but sound slurry design using good fluid-loss additives can alleviate all these potential problems. The Cement Unit of Chevron Services' Drilling Technology Center (DTC) initiated a test program to address the problem areas of flow after cementing. Table 1 summarizes the test results for the majority of fluid-loss additives currently, on the market. These tests are intended to show typical field formulations covering a wide range of bottomhole circulating temperatures (BHCT's). The slurries were designed to have thickening times in the 4- to 5-hour range and slurry densities were designed at 16.4 lbm/gal 1965 kg/m, 3, with the exception of Additive F, which was intend by the particular service to be mixed at a density of 15.6 lbm/gal 1869 kg/m] 3. API Class H cement was used for all slurry designs in Table 1, with all tests performed according to API Spec. guidelines. The data in Table 1 illustrate the concept of using a simple slurry design to combat each of the three mechanisms of annular flow alter cementing. First, as the name implies, the function of a fluid-loss additive is to prevent the uncontrolled dehydration of the cement slurry. While there is general agreement that fluid-loss control is beneficial to the cement slurry, there is some contention as to optimum fluid- loss values. Although such factors as permeability and differential pressure affect dehydration of the cement slurry, good field results have been obtained with a maximum value of 100 ml in 30 minutes for casing jobs and 50 mL in 30 minutes for liner cementations. These values are easily obtained because of the multiple role of the fluid-loss additive. Because these materials are organic, they retard the set of the cement slurry. When sufficient fluid-loss additive is used to obtain the required thickening time, the desired level of fluid-loss control is also obtained. Second, fluid-loss control decreases the volume reduction during slurry hydration. Compare the volume-reduction values in Table 1. with the same values for slurries lacking fluid-loss control in Table 2. The fluid-loss-controlled values are generally an order of magnitude smaller than the noncontrolled values. Third, the fluid-loss additive controls free water. The concentration of fluid-loss additive that provides thickening time and hydration control will also control water separation, provided that reasonable cement/water ratios are used. Zero free water under downhole conditions of temperature and pressure is the goal when the cement slurry is designed. Fourth, and finally, cement slurries designed with fluid-loss additives control slurry gelation. Slurries that rely on fluid-loss ad ditives and dispersants exhibit a "right-angle set" as opposed to a "gel set." These two concepts are illustrated by the strip charts in Fig. 1 . The gel set is characterized by a slow gain in consistency until the final pumping time is reached. By contrast, the right- angleset slurry remains thin until close to the end of the thickening time period and then thickens rapidly to final consistency. Also important is the static gel-strength development.
Over the years, cement packers have been used to provide zonal isolation above the production packer without pulling the completion. Experience has shown that the risks associated with placement of the packers is fairly high and leaks are difficult to repair. A number of ways to place cement packers have been developed over the years and a new method has been recently field trial tested in the Gulf of Mexico in the SMI 288 field. This paper introduces a novel approach developed to install a completion, in a through-tubing process, to recover otherwise uneconomical, behind pipe reserves that are above existing production packer installations. The entire process takes advantage of significantly improved mature technologies. The application of this process can increase recoverable reserves and avoid expensive workover costs when the reserve estimates are questionable. This paper will discuss the methodology used and the results of a case history included to illustrate the implementation of the process. It involved creating a window in the tubing across the new zone and placement of a cement packer above the window. The window was created so as to lower the completion drawdown and lower the risk of completing in wells requiring sand control. Introduction Recompletions offshore in the Gulf of Mexico are sometimes not performed due to the cost of rig mobilization, risk and reserve base remaining in the wellbore Cement packers placed above an existing production packer offer a rigless means of casing isolation and allow production from marginally economical up hole selective candidates. The concept of placing a cement packer in the tubing-casing annulus is not new. There are many variations in how this has been accomplished utilizing varying methods and different types of equipment. In the past, the success rate of placing cement packers that isolate has not been very high. Small micro channels, which develope for various reasons do not result in a complete hydraulic seal of the annular area. This restricts annular flow, but does not completely seal it off. Such leaks result in casing pressure that is difficult to remedy since injection rates/pressures are usually insufficient/too high to perform a cement squeeze repair. An effort was made to develop a better, more reliable way to place cement packers and successfully test them. A Cement Packer Team was commissioned within Chevron in the fall of 1993. Past processes were reviewed, noting the deficiencies. The session resulted in an outline of ideas and issues that must be addressed in order to increase the reliability of the cement placement process. Additionally, at this point it was noted that a method of removing a section of tubing without having to mobilize a rig would result in better perforating performance and would also facilitate placement of a through tubing sand control means (ie, through tubing gravel pack, resin consolidation, fracture with proppant flowback additive, etc). Creation of the window in the tubing string was considered important in lowering the risk of an unsuccessful completion. It became apparent that a casing access window (CAW) completion procedure could be used with good candidate wells and that there are some wells that would require less sophisticated (and less expensive) techniques in the overall procedure. P. 623
This paper demonstrates how simple instrumentation can be used for evaluating the wett ability of cementing spacers and preflushes in a laboratory. With detailed knowledge of a solution's "apparent" wett ability, service companies and operators can more effectively choose the surfactants required for displacing nonaqueous drilling fluids and leaving the casing "water-wet." Water-wet casing allows the cement to adhere more easily to the surface, reducing the potential for remedial zonal isolation treatments. A new laboratory device has been developed that more precisely assesses wett ability. This device indicates "apparent" wett ability by measuring the electrical activity in the test fluid during the water-wetting process. Oil-external drilling fluids do not conduct electricity; water-external spacers do. As the oil-wet surface of the test container becomes water-wet, the device registers electrical activity and a meter displays the "apparent" wett ability in dimensionless units called Hogans (Hn). Introduction Historically, technicians have evaluated wett ability by dipping a glass rod into the drilling fluid and observing the fluid's behaviour on the surface of the rod. The rod is then dipped in the spacer solution and rinsed with water until it is free of the fluid and any oil film. At that point, the surface of the rod is considered to be water-wet. Several variations of gravimetric evaluations also exist where a test coupon is weighed before and after it has soaked for a specified period in various fluids. Because these methods are highly subjective, quality control is virtually impossible. Factors such as temperature variation, hardness, amount of water, and use of agitation can affect test results, and tests involving the same drilling fluid and spacers are subject to varied interpretation. Additionally, gravimetric methods do not account for the effects of high-yield-point fluids that can adhere to the coupons, rendering any weight indication of drilling-fluid removal or water wett ability useless. Pure drilling fluid and pure spacer do not accurately represent the drilling fluid/spacer mixture that occurs in the down hole mixing zone. Compared with actual field results, the test results obtained with the pure forms can be exaggerated. The new apparent wett ability apparatus was developed in response to the demand for greater precision in wett ability assessment. This paper presents case-history accounts of wett ability measurement in the field, and shows how using instrumentation to determine apparent wett ability saves time and cost of materials. Specifically, the discussion focuses on two locations, south Texas and the Gulf of Mexico (GOM). The paper does not deal directly with the rheological aspects of displacement. However, because surfactants affect the rheology of the mixing interface, the surfactant packages designed through testing result in greater compatibility and displacement efficiency. Wett Ability Transition Through the Drilling Fluid/Spacer Interface Volume Understanding the relationship between emulsions and drilling fluids/spacers is a prerequisite for designing a surfactant package that will displace a nonaqueous drilling fluid with a cement spacer. Synthetic, mineral, and oil-based drilling fluids are oleaginous (oil-external) fluids. These fluids consist of an oil or synthetic continuous phase and an internal aqueous phase, usually containing salts such as calcium chloride (CaCl2) in concentrations up to saturation (Fig. 1, Page 6). As an aqueous spacer displaces the oleaginous fluid in the wellbore, both fluids come into contact in the intermixing zone. Throughout the intermixing zone, the oleaginous emulsion will absorb water until the water droplets become so large that the external oil layer can no longer contain them (Fig. 2, Page 6). At this point, the emulsion breaks.1 If the aqueous fluid contains no surfactants or contains inappropriate types or concentrations of surfactants, the break in the emulsion can result in phase separation, the settling of solids, or a spike in viscosity. All of these results can be detrimental to the displacement process.
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