Summary A newly built mobile cement-testing laboratory assists in monitoring blended cement quality and design. The unit contains the equipment required to perform tests for oilwell cements described in API's Spec 10. Case histories are presented describing how use of the mobile cement laboratory improved cementing success on critical cement jobs. Introduction Cementing practices, equipment, and materials have changed as wells have become deeper and technology has advanced. Many cementing systems have been devised. The number of different systems that can be designed by varying the components is almost endless. The pumping time of a cementing system is controlled by the class of cement, the well temperature and pressure, and the type and amounts of additives. In 1939, the first pressure/temperature thickening-time tester was developed, enabling, the industry to forecast slurry performance accurately. Proper "aboveground" density is essential to the successful accomplishment of any well-cementing operation. Only a small amount of water (about 25%) is necessary for cement to set satisfactorily. More water must be added, however, for the cement system to be pumpable. Mixing and pumping equipment has evolved continuously over the past few years. Unfortunately, maintaining slurry density during, cement jobs is still a problem. Cement is usually handled in bulk form, In most cases, additives can be blended with bulk cement to suit any well condition. To achieve success. critical cement-jobs require accurate testing in the laboratory, proper blending of the cement and additives, and correct mixing of the slurry to designed density. A gamut of pilot tests must be run to ensure a good slurry design. After the system has been blended, samples also must be tested. Many oil companies depend solely on the cement service companies to meet these criteria. Chevron, however, has developed a cooperative testing program that works closely with the service company field and laboratory personnel. This program relies heavily on monitoring the quality and performance of cement and additives. Using this program, Chevron and the service company can verify the slurry performance. Over the past few years, a number of major oil companies have experienced situations in which pilot test and blend sample test results did not correlate. Some companies are willing, to accept a 40% variation in thickening time between the pilot and blend tests. In 1982, we implemented a field study to evaluate service companies' blending equipment and procedures. The following recommendations resulted from this study:layer the cement and additives,weigh additives on a close tolerance scale,move the cement a minimum of six times before samples are taken, andobtain accurate (representative) samples while the blend is going to the tank in which it will be transported to the rig. Very close correlation between pilot and blend sample tests was achieved with the implementation of these recommended procedures. While developing these recommendations. we observed a long period between blending, of the cement with additives and testing of the samples. Although the samples were "hot shotted" to both the Chevron and service company laboratories, in most cases, the cement was on location before testing of the blend samples began. In the past, other methods of analyzing cement blend samples. such as a chemical analysis, have been attempted, but none provided the accuracy of a thickening-time test on a high-pressure, high-temperature consistometer. Because of the time required to ship samples and inadequate alternative testing methods, a full-scale testing laboratory with the ability to operate at remote wellsites or service company blending facilities was needed. Capabilities We designed the mobile cement-testing laboratory with the following objectives:equip a self-contained vehicle with equipment that would reliably perform thickening-time. fluid-loss, free-water, and rheology tests on cement slurries for critical casing strings on any well:to provide living accommodations for two people on location:to provide reserve capabilities;to be within the weight limitation of the vehicle:to meet safety requirements;to provide access to laboratory equipment for maintenance and service:to provide for the calibration of the testing equipment; andto be cost-effective. JPT P. 1032^

Proposal Described are proof-of-concept developments to form a seal for mitigating sustained casing pressure caused by annular pressure buildup. Annular pressure can result from numerous sources, including tubing leaks, loss of isolation potential within the cement column because of poor mud displacement, free water-induced channels, stress fractures, and failure of the cement to cover all potential sources of annular pressure. In most cases, annular pressure is not observed at the wellhead until the well is placed on production, making it difficult to identify, access, or remediate the pressure source. A new and novel approach to remediation has been tested in which a low-melt-point alloy metal is dropped down the backside of the casing where annular pressure has been observed. The metal is allowed to accumulate at the top of cement or other physical barrier, melted with an induction-heating tool, and allowed to cool and solidify. This process forms an annular seal to stop fluid communication between the formation and wellhead. This method was demonstrated within a full-scale, simulated well section. An electromagnetic induction tool provided sufficient localized heating to completely melt solder-type alloy metal placed between concentric casings. Subsequent pressure-testing verified that a complete melt, sufficient to provide an effective seal against fluid pressure, was achieved in both water- and synthetic-based drilling fluids. Shear-bond test results of various alloys were equal or superior to cement, and the solid-liquid phase transitions (set points) occurred at precise temperature levels. All metals tested contained bismuth because of its unique characteristic of expanding upon solidification to provide enhanced pressure-containment performance. Full-scale testing was conducted using 17-ft long concentric annular models constructed of 8-in. and 5-in. diameter steel pipes. Subsequent field-testing is currently being planned. Introduction This paper summarizes experimental efforts to form an annular seal for the purpose of mitigating sustained casing pressure, or annular gas pressure buildup. Annular pressure can result from numerous sources such as tubing leaks, loss of isolation potential within the cement column caused by poor mud displacement, free water- induced channels, stress fractures, or failure of the cement to cover all potential sources of annular pressure. In most cases, annular pressure is not observed at the wellhead until after the well is placed on production, making it difficult to resolve the matter, i.e., isolate the zone from which formation fluid communication is taking place. There is seldom a feasible means of physically reaching any of the key points of fluid communication after the occurrence has been observed. Past efforts to remediate have been compromised by failure to reach deeply into the annulus and by chemical contamination of the remedial sealant. The proposed method drops a low-melt-point alloy metal down the backside of the casing where annular pressure has been observed. The metal is then melted by an innovative heating process and allowed to cool and solidify. The intent is to form an annular seal to stop fluid communication between the rock formation and the wellhead as deeply within the annulus as physically possible. This concept was tested using a commercial tool developed for use in artificial lift that produces heat at select locations by electromagnetic induction. The tests described are also intended to determine whether this tool has application for the purpose described. Background A major purpose of primary cementing is to form a permanent seal between the borehole wall and the casing run into it. Total success in this effort implies that all nonproduced formation fluids remain in their respective formations for the entire productive and post-abandonment life of the well. Sustained casing pressure (SCP) detected on the backside of the casing can be an indication of fluid or gas movement within the annulus. This movement can result from failed or insufficient cement coverage, communication through tubular connections and seals, or thermal expansion of fluids in a confined space during production operations. This discussion will focus on remediation of fluid movement or communication.

Drilling oil wells offshore in water depths exceeding 1000 m is not uncommon in many parts of the world. These conditions present a number of challenges for successfully drilling and completing these wells. A major challenge is predicting the temperature of various fluids, such as drilling muds and cements, when they are circulated or placed in the well and during static periods. What sounds like an easy task for the majority of land or offshore wells with shallow water depths turns out to be much more difficult for deepwater wells. This is particularly caused by inverse temperature gradients across the sea and convective thermal exchanges between the sea and the fluids in the riser and/or drillpipe.To better understand the phenomena involved, a series of temperature measurements was made as part of a joint industry project (JIP). The primary objective of these measurements was specifically to monitor the cooling effect of the sea by measuring the fluid temperature at the mudline depth. All temperature data were measured by a sensor deployed inside the bottomhole assembly (BHA) while circulating or drilling. Data were collected in the Gulf of Mexico, Brazil, Indonesia, and west Africa in an average water depth of 1200 m.A summary of the temperature measurements is presented, and comparison is also made with the predictions of a numerical simulator. Detailed interpretation of the data gathered pinpoints the importance of correctly accounting for the exact temperature profile in the sea as well as the velocity of sea currents vs. depth.

Drilling oil wells offshore in water depths exceeding1000 m is not uncommon in many parts of the world. These conditions present a number of challenges for successfully cementing even the shallowest strings. A major challenge is predicting the temperature to which the cementing fluid(s) will be submitted during and after placement so that laboratory procedures can best simulate the actual situation. What sounds like an easy task for the majority of land wells or offshore wells with shallow water depths turns out to be much more difficult for deepwater wells. This is due in particular to inverse temperature gradients across the sea and convective thermal exchanges between the sea and the fluids in the riser and/or drill pipe. To better understand the phenomena involved, a series of temperature measurements was made as part of a joint industry project. The primary objective of these measurements was specifically to monitor the cooling effect of the sea through the measurement of the fluid temperature at the mud line depth. All temperature data were measured by a sensor deployed inside the bottomhole assembly while circulating or drilling. This method was selected for its low cost and lack of interference with drilling operations. Data were collected in the Gulf of Mexico, Brazil, Indonesia and West Africa with an average water depth of 1200 m. A summary of the temperature measurements is presented. Comparison is also made with the predictions of a numerical simulator. The detailed interpretation of these data gathered pinpoints the importance of correctly accounting for the exact temperature profile in the sea as well as the velocity of sea currents versus depth. The outcome of this study helps to define better cement slurry testing procedures for deepwater applications. As a result the technology that is best suited for these specific conditions can be selected on a more rigorous technical basis. Introduction Knowing the temperature profile in an oil well can be quite important for designing drilling operations. But this piece of information is critical for designing cementing operations for obvious reasons. This is even more important in the particular case of deepwater wells for which inadequate knowledge of the temperature can have severe consequences. During drilling operations the cool-down of the fluid in the riser can affect mud rheology, especially for synthetic based mud (SBM), and cause high circulating pressure when pumping is resumed after shut-down, or excessive surge and swab pressures when the pipe is run in or pulled out of the hole. Low fluid temperature combined with relatively high pressures, as may occur in deepwater drilling conditions, could also cause formation of gas hydrates resulting in several adverse effects such as plugging at the BOP's or in the riser. In the temperature range encountered when cementing shallow strings of deepwater wells a deviation of 5 to 10°C (9 to 18°F) in the circulating temperature can greatly impact the design of the cement slurry. The reason is that the setting time and the compressive strength development can be quite sensitive to temperature in the 5 to 15°C (41 to 59°F) range. For the conductor and surface casings predicting the temperature profile at the end of cement placement is the first step towards giving reliable estimates of compressive strength development. This can lead to substantial savings through a better estimation of the waiting on cement time necessary prior to releasing the casings1.