For the heavy oil fields of the Orinoco oil belt in Venezuela, a new cementing concept was successfully applied to maintain zonal isolation during long term exposure to temperatures up to 1,202°F (650 °C) in a process called in-situ combustion. These unconventional wells are often associated with weak and unconsolidated formations complicating proper cement placement and the resulting cement sheath must withstand extreme stresses due to the temperature and pressure cycles during the in-situ combustion process. During a comprehensive lab study API cement based slurries were engineered with high temperature stable aluminosilicate fibers. The corresponding cement specimens were cured and then exposed in a furnace with temperature cycles up to 1,202°F (650 °C) simulating the anticipated wellbore changes. Mechanical properties and permeabilities of these cementing systems were used in a computerized cement-sheath model to evaluate potential failures from stresses during the in-situ combustion process. The cementing systems containing 50% of the aluminosilicate fiber were suitable to withstand thermal degradation without any visual cracks. The computerized cement-sheath simulations indicated that stresses induced by prompt pressure and temperature changes during the heat cycles are not causing failures for the lead cement sheath which was critical to provide zonal isolation above the combustion zone. The biggest improvement of this thermal shock resistant cementing system towards the corresponding cementing systems not containing the aluminosilicate fibers was the significantly reduced Young's modulus by around -20%, while the tensile strength increased by at least +60% resulting in a desired resilient cement sheath. The actual cement jobs in the field were successfully executed as planned without any losses or incidents. So far, no well integrity issues have been observed since the well was cemented in March 2012 with the following combustion process. The thermal shock resistant cementing system, based on API cement, has advantageous towards refractory cements (such as high alumina cements) due to economics, ready availability, but in particular because it performs reliably by adjusting the slurry performance with common chemical admixtures and being flexible in design simplifying operations while contributing to a high-quality job.

Chemical and physical modification of a sustainable, derivatized-cellulose polymer has created a single material capable of replacing several different cement additives. This slowly-hydrating, hydrophilic biopolymer is capable of performing as a fluid loss agent, suspending agent, free water control agent, and extender for use in wells up to 225°F and in some conditions up to 250 °F. The single, new cement additive effectively and economically replaces separate fluid loss additives, free water control, and slurry stabilizers as well as reduces retarder loadings. Laboratory and field results, operational aspects, and slurry design simplification are conferred in this publication. Standard API test results using Class H ordinary Portland cement slurries with densities ranging from 13.5 ppg to 15.5 ppg including a 14.5 ppg cement blend containing 50% fly ash at multiple temperatures are presented. The biopolymer works best with the lower and middle density cements. Unlike most fluid loss polymers, this new additive doesn't produce the high initial viscosities, thereby reducing pumping horsepower requirements and equipment wear and tear. A field case in an 18,000 ft horizontal well (8k ft vertical, 10k ft horizontal) confirms the polymer's effectiveness. Preventing fluid loss is critical in maintaining the proper amount of water to give the cement proper density and mechanical properties. Without adequate suspension and free water control, cement particles will settle at the bottom of the slurry resulting in poor zonal isolation. Slurries containing the cellulose biopolymer performed equal to or better than slurries containing multiple, traditional additives. These additives can interact with each other both antagonistically and cooperatively so that a minor change in one can cause unwanted ripple effects to the slurry properties. This makes slurry design complicated and time-consuming. Replacing several of the commonly-used additives with this modified cellulose minimizes and even removes these complicating ripple effects. The polymer's ability to serve different roles at the same time leads to smaller additive inventories, easier logistics, less time spent on slurry design iterations, and simplified field operations which all add up to improved economics and reduced chance of error during placement of the cement.

As cement changes from liquid slurry to solid, its load-bearing response, strength and permeability characteristics are expected to change with time. Consequently the ability of any cement to withstand changes in wellbore pressure and temperature will be determined, in part, by the changes in elastic properties, failure criteria and permeability that occur over time. An experimental study of time evolution of mechanical and flow properties of Class G neat cement is presented in this study. The objectives of this intra-laboratory test program were to answer the following questions: How rapidly do the mechanical and flow properties evolve over time? Can changes in microtexture be observed and correlated to those properties?What are the optimal times required to observe time-independent responses?What is happening to the water in the cement and does it correlate with the time evolution observed in mechanical properties and permeability? Measurements of liquid permeability, static and dynamic elastic properties, compressive and tensile strengths, pore size distribution and microtexture and fabric photography were recorded over a 10 day interval. The time evolution of mechanical and flow properties for 15.8 pound per gallon Class G cement and their relationships with water content are presented throughout the paper. Permeability is shown to dramatically decrease and equilibrate over the first 24-32 hours, while the mechanical properties continued to increase over a longer time period. The changes in mechanical/flow properties were strongly correlated to the decrease in water content and the shifting of pore size to smaller distribution functions. Complete stabilization of static elastic properties was not observed after 10 days, implying that, for certain cement formulations, these properties may need to cure for longer than industry standard times. From tests results, 96 hour cure times may be insufficient to characterize certain mechanical properties of wellbore cements. This study also sets a base standard for comparison with more complex cement chemistry's that are currently (and in the future) being used in oil-field operations. The authors also concluded that the use of NMR measurements of pore size and, in turn, water content correlate very well with conventionally used methods. Motivation for this study is based on limited data available on the simultaneous response of all critical wellbore cement properties from the very early stages of hydration to long-term set.

Cementing sour wells can be very challenging; even when best practices are followed, the integrity of the cement, casing, and/or tubing can be jeopardized. In such cases, challenging and costly remedial work is necessary due to the complicated nature of the environment. A safe, cost effective way to prevent the need for remedial work is the use of self-sealing systems; however, until now, there was no data that validated self-sealing systems’ capability to tolerate exposure to H2S. This paper focuses on the newly discovered ability for the self-sealing systems to withstand exposure to H2S while maintaining self-sealing properties. To confirm that the self-sealing material is uninhibited by H2S, a gas mixture of H2S in nitrogen was bubbled through a mixture of self-sealing material and water. The concentration and rates used were picked to mimic a standard sour well’s condition allowing the testing to recreate the challenging well environment. The self-sealing material was then added to the cement slurry and transferred to the crack/seal equipment for testing. The results from the experiment were compared to a self-sealing slurry with the same components but in which the self-sealing material had not been exposed to H2S. Both systems were able to seal multiple times, validating the ability of the exposed material to withstand H2S exposure. The finding from this study opens the door for self-sealing cements to address several kinds of corrosive gases. Because the system was able to withstand exposure to such a strong gas, it will likely be able to tolerate weaker corrosive gases such as CO2. The discovery from this experiment promotes a new use for self-sealing cements. No longer will their use be limited to cracks in the cement matrix but also as an extra precaution when working in sour wells and corrosive environments.

Cementing in wellbores with low fracture gradients can be challenging due to the risk of formation breakdowns when exceeding maximum allowable equivalent circulation densities (ECDs). Consequences include severe losses and formation damage, and insufficient placement of the cement slurry that necessitates time-consuming and costly remedial cementing to ensure zonal isolation.In recent cementing operations in Spain, the formation integrity test (FIT) of the open hole section indicated that the formation would have been broken down and losses occurred based on calculated equivalent circulating densities (ECDs) if the cement slurry had been pumped in a single-stage to achieve the operator's top-of-cement goal. As a solution to this problem, cementing was performed in stages, using specialty tools. However, during these operations, the stage tool did not work properly, wasting rig time and resulting in unsuccessful cement placement.To overcome this issue, the operator decided to cement the section in a single stage, preceded by a novel aqueous spacer system that aids in strengthening weak formations and controlling circulation losses. Before the operation, laboratory testing was conducted to ensure the spacer system's performance in weak, porous formations and better understand its mechanism. This paper will outline the laboratory testing, modeling and engineering design that preceded this successful single stage cementing job in a horizontal wellbore, with a final ECD calculated to be 0.12 g/cm 3 (1.00 lb/gal) higher than the FIT-estimated figure.