Three studies were conducted to replicate and extend Dweck's findings regarding young children's responses to challenging achievement situations. Dweck's dichotomous helplessness classification system (i.e., task choice, task choice reason) was replicated with kindergartners, n = 235 (50% male), and first graders, n = 70 (46% male). To test whether individual differences in young children's responses to challenging situations are stable over time, 1- and 5-year follow-ups of the kindergartners were conducted. On the basis of children's responses on age-appropriate behavioral tasks, a composite of cognitive, behavioral, and affective helplessness indices predicted helplessness at 1 and 5 years later, n = 114 (50% male), above and beyond kindergarten task ability and gender, p<.05. Kindergarten helplessness predicted teacher ratings of children's helplessness 5 years later as well, p<.05. The implications of these findings for early intervention are discussed.

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Several lost circulation materials (LCMs) are available to operators who wish to minimize downtime while combating lost circulation. In general, fine to medium-sized particulate-based materials mixed into the mud system are the first line of defense. When this fails, the common response is coarser LCM, which often cannot be pumped through downhole tools. Operators then might choose to pull out of hole (POOH) with the drilling bottomhole assembly (BHA) and run in with a cement stinger. This paper discusses a practical, field-proven solution that eliminates time-consuming and potentially hazardous trips in and out of hole. This is done by using a right-angled set, temperature-activated fluid that, once set, exhibits similar characteristics to Portland cement. It can be confidently pumped through the BHA to combat all static or dynamic losses. The cases discussed in this paper were located in the 43/19a Cavendish field in the southern North Sea, while drilling through Plattendolomit. Plattendolomit is a thin, complexly folded and rafted dolomite that is found within the Zechstein halites. This formation presents significant well-control challenges with the potential for high overpressures coupled with high-rate dynamic losses, particularly Quads 43 and 44. The novel fluid was used to cure dynamic losses of up to 400 bbl/hr. The fluid was also used to isolate the well to allow safe tripping to replace worn blowout preventer (BOP) components. As small changes in bottomhole pressure caused high-rate losses and gains, it was not possible to kill the well by conventional means. A plug was set inside the casing that isolated the kick/loss zones from the wellbore. Because it was possible to drill out the isolation plug with a drilling shoe on the liner, considerable rig-time was saved. Introduction Field/Formation The two wells that were treated by the novel rigid setting fluid (RSF) were drilled in the Cavendish field in block 43/19a. The formation that proved troublesome during drilling was the Zechstein super-group, in particular, the Plattendolomit. Two hundred and fifty million years ago, during the Late Palaeozoic period, the Zechstein basin was formed. The Zechstein basin was formed by multiple changes in sea level, resulting in precipitation of salts through evaporation. This led to a sequencing of the formations because the salts with the lowest-solubility precipitate formed the first layer with following layers of precipitates forming above. The sequence is: carbonates at the base (calcite and dolomite), sulphates above, and halite on top. The dolomite acts as the reservoir rock because of its porosity and permeability. The sulphate layer above forms a seal but can also penetrate the dolomite, reducing its permeability and porosity. The rock salt lies above the sulphates and can cause various drilling issues (Williamson et al. 1997). The Plattendolomit, formed within the Zechstein formation, is often the site for losses and gains. The losses can be caused by formation breakdown or vuggy porosity. Both losses and gains can be experienced. If the volume of mud returning to the surface is less than the volume of mud being pumped, the well is said to be taking loses, this is caused by mud being lost to the formation. Gains are fluid entering the wellbore while the pumps are shut down. This situation can be explained by charging or fluid exchange (Finnie 2001). The RSF is ideal in these salt-bearing formations because the base fluid used is concentrated brine, thus avoiding the possibility of compatibility issues.

The target reservoirs are several limestone layers separated by shales and extend over a vertical height of up to 100 m. The reservoirs are developed differently in almost every well, and natural fractures exist in some, but not in all, wells. The wells are completed with regular 13 3/8-in. casing to around 900 m, 9 5/8-in. casing to around 3400 m, and a 7-in. liner through the reservoir section at around 4100 m. Surface temperatures range from +20°C in summer to -50°C and lower in winter, with bottomhole temperatures (BHTs) around 50°C. Both for producers as well as injectors, a properly designed matrix acid treatment covering the entire reservoir proved to be the most successful production enhancement technique. Most of the wells were completed in a way that allowed the matrix acid stimulation treatments to be conducted in two stages. Both stages covered more than one perforation set. However, for the second stage the job team had to consider that the first stage covering the lower zones was already completed, and fluid would most likely be pumped into this lower zone. The challenge was to provide good diversion over the entire reservoir for one stage and, even more difficult, to divert the majority of the acid into the upper zone for the second stage. In addition, this reservoir oil has relatively high paraffin content, and paraffin deposition, hindering if not eliminating production, will occur below a certain temperature. This fact had to be considered in the matrix acid stimulation design. For a single-stage treatment, or the treatment of the lower zones, a combination of Insitu Crosslinked Acid (ICA) and maximum pressure/maximum rate technique (MPMR) proved to give excellent diversion over these intervals. ICA is a chemical diversion technique. It features a thin, gelled acid with a viscosity of approximately 25 cP that forms a highly viscous crosslinked gel when the acid spends on the formation to a pH of approximately 2. The crosslinked gel can effectively stop any further fluid invasion, and following acid stages will be diverted to different parts of the zone. As the spending continues further, the crosslink will break again at a pH of approximately 4. The MPMR technique uses the concept of dynamic diversion, whereby the pressure remains constant just below frac pressure, and the rate is increased as the acid spends on the formation. Bottomhole (BH) gauge data are available to show the effect of diversion and eliminate any possible effects from friction and hydrostatic pressures that can affect surface data. For the treatment of the upper zone, when the lower zone was already stimulated and could not be isolated by mechanical means, additional diversion was required to seal off the perforations of the lower zone. A combination of Biodegradable PerfPac Balls and ICA was pumped at the beginning of the treatment to divert the remaining matrix acid treatment away from the lower zone and optimize stimulation of the upper zone. This paper shows how a properly engineered matrix acid treatment using a combination of diversion techniques can result in optimized stimulation treatments. In a carbonate formation, efficient diversion of acid fluids is even more important than in a sandstone reservoir because the acid-carbonate dissolution reaction rate is so fast. Introduction One of the most important factors affecting the success or failure of any matrix acid treatments is the correct downhole placement of the acid for optimum zonal coverage. This will depend largely on the completion design that is being run on a specific well, but also on formation and reservoir issues; e.g., certain completion scenarios eliminate a potential use of packers for isolating two zones of interest. In this case other means of stimulating both zones effectively must be identified and optimized.

It is often stated that necessity is the mother of invention. Never is this proverb more relevant than in the offshore oil and gas environment we currently operate in where real step changes leading to reduced capital and operational expenditure opportunities are sought and embraced by field operators. This paper discusses the pre-job planning, field execution and lessons learned from one such technology that challenged conventional thinking of sand faced completion, casedhole completion and well integrity to successfully deliver a single-trip, interventionless, sand control completion in deepwater Bonga Field, located on the continental slope of the Niger Delta. Convention dictates that the vast majority of offshore completions be run in two and sometimes three trips which routinely takes in excess of eight to ten days to deploy. Given the day rate of high specification rigs capable of drilling in deep water environments, the ability to reduce this time was deemed paramount to the economics of the project. Utilizing a collaborative approach to initial concept design, risk assessment, extensive testing and contingency planning at component and system level, a single-trip, interventionless, sand control completion system was designed and successfully installed. This paper describes the completion architecture, operational sequence and challenges leading to the installation of an interventionless completion. A clearly defined set of deliverables and design principles were drawn up to guide the direction of the project including: successfully deploying the upper and lower completion in one trip, and testing all barriers. Adopting a simple, low risk and high reward design, meeting clients well barrier requirements and utilizing proven cost-effective technology are examples of design principles used. The system was tested and evolved through a number of iterations in an onshore trial well environment on a number of occasions leading to the first successful deployment completed in the second half of 2018, resulting in an average completion installation time of 5 days, versus the average 10 days for deploying multi-trip completions. Details of the successful installations, lessons learned, along with planned future activity are outlined within the body of this paper. While several of the components incorporated in the single-trip system had been run previously in isolation, this paper also discusses the steps taken to facilitate the first full-system approach to the application of radio frequency identification (RFID) enabled tools in the first single-trip, interventionless sand control completion system. Several components within the completion have been equipped with this technology including a multi-cycle ball valve, wire wrapped screens fitted with inflow control device (ICD), remote operated sliding sleeve for annular fluid displacement.