Sarah Jane Dyer

The effect of temperature and pressure on oilfield scale formation

Dynamic tube blocking tests have been conducted to determine the effect of increasing temperature and pressure on barium sulphate and calcium carbonate scale formation, as part of a study considering the application of scale inhibitors in high pressure and high temperature reservoirs. As pressure was increased, the scaling tendency of the carbonate and sulphate scaling brines tested was found to decrease, as was predicted by scale prediction software. As temperature was increased, the scaling tendency of the carbonate scaling brine increased, whereas that of the high sulphate scaling brine system was found to decrease. The effect of temperature on scaling tendency was more significant than that of pressure. A low sulphate scaling brine was also tested and this failed to precipitate scale during the tests at the lowest temperature (50 °C), although at this lowest temperature, it was predicted to have the highest scaling tendency. Under these test conditions, the kinetic rate of scale precipitation was low, so the kinetic rate of precipitation became more significant relative to the thermodynamic drive for precipitation.

Thermal stability of generic barium sulphate scale inhibitor species under static and dynamic conditions

Polyvinyl sulphonate (PVS), phosphino polycarboxylic acid (PPCA), and penta-phosphonate (DETPMP) scale inhibitor species have been investigated for their suitability for application in high pressure and high temperature (HP/HT) reservoirs. The thermal stabilities of solid and solution samples of these generic scale inhibitors have been determined at temperatures of 175 and 200 °C at low pressure (<15 bar) and at 175 °C at high pressure (515 bar). The potential stabilising effect of adsorption onto Clashach core has also been investigated for the PVS and DETPMP species and the effect of acid hydrolysis on the stability of PPCA and PVS has been considered. The results of this study indicate that PVS was the most thermally stable scale inhibitor species tested and was not degraded after thermal ageing in aqueous solution at 200 °C for 14 days, whereas DETPMP was rapidly degraded when thermally aged at 175 °C. The stability of PPCA at 180°C was dependent on solution pH, but the thermal stability of PVS was unaffected by the solution pH.

Factors Affecting the Thermal Stability of Conventional Scale Inhibitors for Application in High Pressure/High Temperature Reservoirs

Following an earlier paper (SPE 37274, 1997), we have continued to investigate the thermal stability of scale inhibitors for application in high pressure/high temperature (HP/HT) reservoirs. HP/HT reservoirs are currently under development in the North Sea and are characterised by high salinity brines (TDS > 300,000 ppm) high temperatures (T > 175°C) and high pressures (12,000 - 15,000 psi, ∼ 800 - 1050 bar). At present produced brines are treated with scale inhibitors to prevent mineral scale deposition within tubulars and topside equipment. However, the conventional polymer and phosphonate scale inhibitors currently being used may not be appropriate for application in the harsh HP/HT reservoirs. In this work, results are presented from static thermal stability tests conducted on conventional polymer and phosphonate scale inhibitors including phosphinopolycarboxylate (PPCA), polyvinyl sulphonate (PVS), penta-phosphonate (DETPMP) and hexa-phosphonate (TETHMP). The stability of the scale inhibitors has been considered at temperatures ranging from 120°C to 200°C and other factors which may affect thermal stability have also been investigated, including solution pH and the presence of oxygen radicals, iron and common cations (Na + , Ca 2+ , Mg 2+ ) in the inhibitor solution. The results from this work demonstrate how factors such as pH and brine composition control thermal stability. Furthermore, the controlling influence of certain factors, such as solution pH, affect different species differently. This work assists in the selection of scale inhibitors for use in HP/HT applications.

Potential application of amine methylene phosphonate-based inhibitor species in HP/HT environments for improved carbonate scale inhibitor performance

In recent years, a number of new high-pressure/high-temperature (HP/HT) reservoirs have been developed in the North Sea [for example, the Eastern Trough Area Project (ETAP) and Shearwater fields] that have several important scale-control issues. In addition to their ability to prevent scale formation, these include inhibitor/ brine compatibility and the thermal stability of the scale inhibitor. Previous works have strongly indicated that amine methylene phosphonic acid-based inhibitor species, such as pentaphosphonate (DETPMP) and hexaphosphonate (TETHMP), are considerably less thermally stable than polymeric species, such as PVS and the S-Co species. As a consequence, the phosphonate-based species have been reported as less applicable for deployment in high-temperature reservoir systems. However, more recent studies that examined a range of different amine methylene phosphonic acid-based inhibitor species have shown that certain species are thermally stable at temperatures exceeding 160°C. This paper presents the initial screening study undertaken to select a scale inhibitor for the Shearwater reservoir and includes an examination of some phosphonate species to determine potential application in HP/HT reservoir systems.

Modeling the Effect of Triazine Based Sulphide Scavengers on the in situ pH and Scaling Tendency

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. We have developed a modelling methodology which can approximate the effect of triazine type H2S scavengers using an analogue amine as an effective weak base. The effective weak base has a base dissociation constant of the right order compared to monoethanol amine. It therefore simulates the pH effects, and the titration curves of the amine / CO2 / carbonate buffer system that were measured in the lab. Using this methodology we show how the production process has a significant impact on the in situ scaling potentials and how improved modelling and laboratory tests are able to better simulate the field conditions and aid understanding of the process chemistry issues and solutions. Introduction: One of the options for removing H2S from produced hydrocarbon gas is to inject an amine-based chemical scavenger. While such scavengers can be effective at removing H2S, scaling is a common problem. Both the unreacted scavenger and its reaction products contain alkaline amines. If either the scavenger or its reaction products are mixed with produced water containing carbonates, the increase in the pH will increase the probability of carbonate scale. One of the strategies used to prevent scaling is to inject the scavenger directly into the gas stream. This can be accomplished downstream of any one of several gas/liquid separation vessels in a facility. By adding the scavenger to the gas, the scavenger does not immediately contact the produced water. This strategy works well to prevent scaling in the injection system. However, transporting the reacted scavenger through a production facility, and ultimately disposing of reaction products often poses a challenge. Many questions arise regarding the ultimate fate of the reacted scavenger. Fouling and corrosion of downstream equipment is a major concern among operators. When considering disposal into a subsurface reservoir, the possibility of scaling in the reservoir and injectivity impairment are issues that must be addressed. If the reservoir is a producing reservoir, then souring from a nitrogen food source must also be considered. When considering overboard disposal, the Environmental Impact must be assessed. Often it is not possible to completely segregate the scavenger reaction products from the produced water in a facility. The process configuration may not provide two parallel water-based processing systems. At some point, there may not be any alternative than to mix the produced water and the scavenger reaction products together.