Offshore cementing poses many challenges across the world as drilling oper ations move towards deep-water and ultra -deep-water. As a new initiative of continuous improvement, a deep-water cementing peer review process was started early 2011. To this date, th is team has reviewed more than 12 00 deep-water cementing jobs in more than 30 countries worldwide.

Four deepwater wells in the Gulf of Mexico were identified for permanent abandonment in accordance with local regulations. The abandonment plan called for multiple cement plugs to isolate the production zones from seabed in each well. The most challenging cement plugs in each well were the ones directly above the production packer isolating the casing-tubing annulus and the production tubing. To avoid cement left in the Christmas tree at seabed and potential plugging off any valves in the manifold, cement plugs could not be placed the direct way, pumping down the production tubing. An unconventional approach was proposed to address the challenge. It involved reverse placement of cement plugs, which is not common in deepwater even in these days. Using this technique, cement was pumped down the casing-production tubing annulus and, through perforations, back up the production tubing. Risk analysis indicated very low likelihood of plugging off any valves in the tree. However, this configuration did not allow use of mechanical separators between fluids to prevent intermixing. Additional challenges in placing the plug were the high deviation of the section and the completion brine in the wellbore. Simulation of reverse placement is not possible with existing software. Therefore, the jobs were designed using experimental software, which enabled the design engineer to accurately reconstruct field conditions. Additional attention was given to the job procedure to minimize contamination with the brine and optimize cement placement. Viscous spacer was pumped ahead and behind the slurry to displace the brine. The slurry was designed with low fluid loss to be squeezed through perforations in the production tubing without plugging them off. A total of seven plugs were placed using the reverse placement technique. Specific requirements with regards to the top of cement and plug integrity had to be met before any of the cement plugs could be accepted by the operator. All plugs were tagged and pressure tested successfully in the annulus as well as inside the production tubing on the first attempt. As a result of the campaign, the four wells were abandoned as per schedule and within budget.

Foamed cement is often used to seal the annulus of many surface casing strings in deepwater offshore wells. The objective of this paper is to highlight the benefits a foamed fluid placement simulator brings to the design and evaluation processes for foam cement jobs.A dynamic compressible hydraulic model that simulates the flow of nitrified fluids during primary cementing operations is presented. For a long time, the industry had relied on models that used average density properties for the foamed fluid. Yet the foam quality can change from 70% at surface conditions to 10% or less at bottomhole conditions. In terms of density this ranges from 600 kg/m 3 (5 lb/gal) to 1800 kg/m 3 (15 lb/gal). The average density approximation is therefore too coarse. In reality, there is continuous changing of fluid density and rheology during placement of the foamed fluids due to the changes of pressure and temperature along the flow path. Both density and rheology variations can be taken into account in a compressible hydraulic model that simulates the flow of nitrified fluids during primary cementing operations.Measurements taken on actual foam cement jobs are compared to the simulator's output. The actual data and the simulated output compare favorably. Discrepancies between the model and acquired data are also analyzed to improve the understanding of the actual operation. The inherent limitations of post job analysis are discussed. The absence of caliper or known geometry on surface and conductor casings becomes more obvious. The placement of sensors on flow lines, the absence of sensors after the foam cross, and the uncertainty on geothermal gradient are also sources of divergence between the model and the measurements as will be seen through case study in this paper.The continuous improvement of the model and the simulator will contribute to more robust foam cement job designs. Robust foam cement job designs will assure the isolation integrity of the structural casing strings for deepwater wells and ensure safe operations while executing this type of jobs.

Zonal isolation in narrow pressure windows has traditionally been challenging. This is due to cement slurry losses or potential fluid flow after cement placement. Accurate pressure data are essential for well control and successful primary cementing. Higher fluid densities and pumping rates can lead to induced fracture and lost circulation. Often, to mitigate the potential for dynamic losses during cement placement, low-density Newtonian fluids (preflush) are pumped ahead of weighted spacers. It is recognized in the industry that Newtonian fluids achieve a turbulent flow regime much easier than non-Newtonian fluids. The impact of Newtonian fluids on the stability of nonaqueous fluid (NAF) systems and weighted spacers are often disregarded during cement job design and testing.During cement placement, especially in extended reach wells, depending on the volume of preflush needed to maintain adequate wellbore security, a long column of preflush/mud interface may be created. With the Newtonian phase in turbulent flow, the erodability of the mud interface increases significantly. Though preferred for cementing, Newtonian fluids have a detrimental effect on the stability of the fluid interface. Whenever the yield point of the interface falls below the critical value for solids suspension or the slip velocity, weighting material sags out of the mud; this results in hydrostatic imbalance in the fluid column. When the overall hydrostatic pressure falls below the formation pressure at any point in the wellbore, the cement slurry will be invaded by formation fluid influx and a flow pathway created while cement is setting. This channel can become a flow path for hydrocarbons to the surface, leading to sustained casing pressure or a hydrocarbon seep to surface or seabed.In the Caspian region, an engineering approach was implemented to manage cementing equivalent circulating densities (ECD) when designing cement jobs using lighter and Newtonian fluids ahead of weighted spacers. It has led to successful zonal isolation for recent wells and an evaluation of design considerations for cementing ERD wells.

Cementing formations with medium to high gas migration severity in cold conditions is considered a very challenging operation for major operators in Turkmenistan. The liquid gas migration agents used in Turkmenistan for the above mentioned severities incur additional operational and technical challenges, particularly during the winter months as the ambient temperature falls below zero. In addition to the climatic challenges, Turkmenistan drilling activity often encounters the additional challenges of high pressures and narrow pore / frac windows. This paper focuses on case studies to analyze the application of both liquid and solid gas migration prevention additives compared with conventional slurry systems in overcoming challenges encountered while cementing across gas bearing formations. To address such challenges, a solid polymer gas migration prevention additive has been field tested successfully in environments such as Canada, USA and Russia having similar conditions as Turkmenistan. A description is then given of a successful method of combining a special solid polymer based gas migration prevention system with good cementing practices, in order to not only achieve the primary objective of the cementing operation, but also yield improved logistics in terms of storage, handling, and no associated mix fluid aging or detrimental effect of thawing. Field case histories are presented, illustrating the versatility of the system in solving gas migration problems in seasonal climate changes.Above all, solid gas migration prevention polymers are considered the best cost effective solution compared to the liquid gas migration agents of the same family which is considered as the key value for commercial oil and gas production.