Method development of laboratory bench and rig tests for assessing the suitability for application of chemicals via down-hole pressure tube systems is presented. Areas of interest include precipitation or viscosity changes due to solvent loss both in bulk samples and samples in capillaries, and long term product stability in capillaries using new flow rigs designed to more fully replicate pressure tube injection phenomena (particularly chemical stability under extreme T and P conditions). Indeed fluid stability and other challenges relating to down-hole continuous injection have led to a number of failures being recorded in recent years indicating that the physical properties rather than the absolute performance of the chemicals is often key to their successful deployment.Continuous chemical injection systems for down-hole application are being included in more well completions as their usefulness is recognised. While the initial capital costs are increased, such systems provide a number of benefits over reliance on squeeze treatments for down-hole application. These may include the opportunity to use chemicals unsuitable for squeeze treatment due to the risk of formation damage, the ability to maintain higher doses, and avoiding the need to interrupt production to apply chemicals in complex subsea wells.Using the developed methods we have identified a number of ways in which formulated scale inhibitors may produce problems within continual injection systems. These include particulate formation and line plugging in capillaries, and solid formation or viscosity increases in response to solvent loss within a tube (as opposed to bulk samples).These methods will form the basis for future qualification procedures for chemicals intended for down-hole chemical injection with the aim of avoiding application issues in the field. They have been developed both to better understand chemical / fluid stability under down-hole continuous injection conditions following a number of recorded field deployment problems, and then to provide improved qualification for new chemicals and systems.
Amine-based chemicals used for scavenging of hydrogen sulphide will cause precipitation of carbonate scales, under a wide range of conditions. They are effective as scavengers, and have health, safety and environmental advantages compared to other scavenger chemicals. Unfortunately, they significantly raise the pH of all process waters that they are mixed with, and thus exacerbate the scaling tendencies of dissolved carbonate minerals. Calcium carbonate, magnesium carbonate and iron carbonate scales can occur over a wide range of temperatures, pressures, and carbonate concentrations. In many process configurations there is no alternative but to allow the mixing of scavenger with produced water. In those cases, extensive laboratory work is typically required to select an appropriate scale inhibitor. It is usually necessary in such studies to understand in detail the chemistry of the solution and its pH and alkalinity characteristics.
This paper describes a laboratory and modelling study into halite (sodium chloride, rock salt) deposition in mature gas production wells. Halite deposition can result in significant production and integrity issues, and mitigation measures are primarily based upon injection of low-salinity wash water, often coupled with careful control of production parameters (such as well drawdown), for which scale-prediction models are used. Laboratory investigation of halite scaling and performance of halite inhibitors typically uses the mixing of incompatible brines or cooling a saturated solution, either in bottle tests or using a dynamic scale rig. While these methods allow precipitation kinetics and inhibitor performance to be examined, they are far from ideal as they require significant modification of the brine chemistry and deposition conditions. In this paper, we describe a novel approach to laboratory investigation of halite deposition that much more closely mimics the evaporative scaling mechanism mostly widely experienced in the field, and can be performed using produced-water compositions and conditions that are much more representative of the field. It is based upon a dynamic, flowing system where field-representative formation water is co-injected with gas at an appropriate level of under-saturation in water content to that expected under production conditions. Electrolyte prediction software was used to model the halite scaling tendency in the experiments, and very good correlation was found between the prediction of supersaturation and the onset of precipitation and deposition. This agreement implies that the scale-prediction model is accurate for halite scaling via this mechanism, and adds much confidence to the use of this tool for optimizing production parameters to minimize the effects of halite scaling in the field. The work also confirms earlier reports that the critical scaling tendency for halite – the value at which significant precipitation and deposition occurs in the field – is very close to unity for the conditions tested in this work. The new laboratory method was also used to generate calcium carbonate scaling by the mechanism – primarily transfer of CO2 to the gas phase – that is by far the predominant one found in the field; this led to observation of a mixed halite/calcium carbonate deposit.
Scale deposition in oilfield production systems is influenced by thermodynamic supersaturation and kinetics, but also by hydrodynamic effects such as surface shear stress and turbulence. Results from experimental work investigating the impact of these hydrodynamic factors on scale location and correlating them to field flow regimes are presented. Laboratory tests have been conducted using both a benchtop jet impingement method and large-scale, high flow rate "pilot rig" apparatus. Both of these systems result in high shear stress conditions and can simulate hydrodynamic regimes representative of those expected in devices such as inflow control valves, inflow control devices, and sand control screens. The pilot rig is able to reproduce field-representative flow rates and fluid flow dynamics through full-size test pieces containing nozzles and restrictions. The results of this work demonstrate that the hydrodynamic regime has a significant influence on scale deposition. Increased levels of surface shear stress and turbulence result in a greater potential for scale formation than low shear, laminar flow conditions. This is particularly apparent in systems which are mildly supersaturated. The location of scale deposits was found to correlate with local shear stress and the pilot rig tests confirmed field observations that zones experiencing the highest level of shear are not necessarily those with the greatest deposit; the induced scale may deposit downstream in areas of lower surface shear. Additionally, the presence of these high shear locations upstream of the lower shear regime may lead to scaling in the lower shear region which would otherwise not be experienced. Supportive Computational Fluid Dynamic modelling of fluid flow within the pilot rig system correlated with the experimental findings is also described. This work allows a greater understanding of the hydrodynamic factors, in particular surface shear stress, influence oilfield scale deposition and has demonstrated the utility of both benchtop and pilot-scale methods for testing under appropriate conditions.
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