Perforating wells calls for careful planning to maximize well productivity over the life of the well, and to prevent time and money losses due to unexpected side effects. A large class of wells and in particular high-pressure wells are susceptible to gunshock damage when they are perforated with inappropriate gun systems. This paper presents applications of a simulation methodology to predict gunshock loads for tubing-conveyed and wireline-conveyed perforating jobs. With this simulation methodology we can evaluate the sensitivity of gunshock loads to changes in gun type, charge type, shot density, cable size, tubing size and length, number of shock absorbers, rathole length, placement and setting of packers, and early reservoir response, among many others.When planning perforating jobs, engineers strive to minimize the risk of equipment damage due to gunshock loads. With the simulation software presented in this paper, engineers can identify perforating jobs with significant risk of gunshock related damage, such as unintentional pull-offs, bent tubing and unset packers. When predicted gunshock loads are large, changes to the perforating equipment or job execution parameters are made to reduce gunshock loads to an acceptable level.Fast gauge pressure data from perforating jobs shows that wellbore pressure transients can be accurately predicted. For well prepared simulation models, typical peak sustained pressure amplitudes at the gauges are on average within 10% of simulated values. In jobs where shock absorbers were used, residual deformations of crushable elements correlate well with predicted peak axial loads; which confirms that gunshock loads on the equipment are well predicted.With the simulation methodology described in this paper engineers can evaluate perforating job designs in a short time, and they can optimize perforating jobs by reducing gunshock loads and equipment costs. The ability to predict and mitigate gunshock damage in perforating operations is very important because of the high cost of typical high-pressure wells.

Flaring has received significant attention over the past few decades and has become a major concern for many operators today. One of the contributors to hydrocarbon flaring is well clean-up operations, where traditionally oil and gas are disposed by flaring at the wellsite. This paper will share in details how integrating various technologies allowed to come up with a cost effective, zero flaring solution for well clean-up operations, that substantially reduced overall field carbon footprint. A common alternative to flaring is to store the crude in tanks and/or pump crude into production line, if available. However, the associated gas is typically flared off, as using gas compressors to inject gas into production line is extremely cost intensive and operationally complex. As an alternative, fit for purpose multiphase pumps, specifically designed to handle clean-up operations and combined with a high pressure surface well testing package proved to be a successful, innovative and cost effective solution to bring new wells to production without gas flaring. The pumps, installed at the inlet of a high-pressure separator, boost the pressure such that both oil and gas can flow directly into the production line, while water and spent acid from well stimulation treatment are separated out onsite into water tanks. The method does not require any hydrocarbon flaring, thereby drastically reducing emissions for well clean up and start up operations. The solution enabled a reduction of an average of 24 Kilo-Tonnes of CO2 equivalent of emmissions per well clean up, when compared to 100% flaring, resulting in a very significant and measurable positive environmental impact. The pumps proved to be reliable and fit for purpose, by toleranting high gas-volume-fraction (GVF) conditions and unstable flow, which is vital for clean-up operations. In addition, the setup proved to be an efficient pressure-boosting package, to gain additional production, by overcoming the high backpressure from the production lines network. The package was introduced in the giant Karachaganak oil and gas condensate field in Western Kazakhstan in high H2S environment, and was used in 13 wells over a two-years period, resulting in significant net production gains for the operator.