Gordon Michael Graham

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.

The Influence of Formation Calcium and Magnesium on the Effectiveness of Generically Different Barium Sulphate Oilfield Scale Inhibitors

Using chemical scale inhibitors is one of the most common methods of preventing downhole and topside mineral scale formation in oil fields. Several aspects of the brine composition may affect the performance of the various scale inhibitors. In this paper, we focus on the roles of calcium and magnesium ion concentrations. The calcium concentration in a particular reservoir and in the inhibitor slug often determines the extent to which the inhibitor species is retained in the near-wellbore area (i.e., on its adsorption or precipitation behavior). What is less well understood is the effect of divalent cations on the inhibition process itself. Common ion effects are well known; however, for pentaphosphonate inhibitor species (e.g., DETPMP), significant improvements in inhibition efficiency have been reported by increasing the calcium concentration in the solution. In this paper, we expand significantly on such observations. The effect of calcium and magnesium cation concentrations is examined for a wide range of generically different inhibitor species, including pentaphosphonate, hexaphosphonate, phosphinopolycarboxylate, polyvinyl sulphonate, and sulphonated polyacrylate copolymers. The results clearly indicate how different inhibitor species are affected quite differently by changes in [Ca 2 + ] and [Mg 2 + ] and how this difference relates to the cation affinity of the inhibitors active functional groups. The results were obtained by comparing the barium sulphate inhibition efficiency of various species in mixtures of a low/medium scaling (Brent type) formation brine and seawater (SW) and also in a more severe scaling (Forties type) formation brine/SW mixture. Barium sulphate inhibition efficiencies were examined by static inhibition efficiency tests, with residence times ranging from 30 minutes to 24 hours. Phosphonates are shown to be poor inhibitors at very low [Ca 2 + ], indicating that their effectiveness is controlled by the formation of Ca 2 + /phosphonate inhibitor complexes, as discussed in previous works. 1 , 2 On the other hand, polymeric polycarboxylate inhibitors are shown to be effective even at very low [Ca 2 + ], indicating that the formation of multiple bonds between the polymer and the crystal surface allows for stronger adsorption and, thereby, inhibition. However, it appears that strong ionic bonds involving calcium cation bridging are required for the phosphonate-based species. Conversely, when the magnesium ion concentration is increased, the performance of the phosphonate is significantly reduced, whereas the other polymeric species are relatively unaffected. This can be accounted for in terms of the cation affinity of different inhibitor functional groups in a similar manner as comparative adsorption and inhibitor/brine compatibility effects. For the polycarboxylate inhibitor species examined in this work, a clear maximum in inhibition efficiency is observed with increasing calcium concentration. This is explained, from related experiments, in terms of complexation (incompatibility) and differences in the adsorption modes at the scale surface.

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.

New pressure flow cell to monitor BaSO4 precipitation using synchrotron in situ angle-dispersive X-ray diffraction

A flow cell has been commissioned to monitor in situ precipitation reactions under non-ambient conditions. The majority of high-pressure systems use anvils and presses to obtain high pressures around a small reaction area; however, this prototype is unique in that solutions may be examined as they flow through the cell under pressure. The cell is made of single-crystal silicon, which is capable of withstanding the high pressures created by liquid flow within the cell. With the capability of reaching pressures of up to 4 x 10(7) Pa, the cell is ideal for work on geological and oilfield systems. Here it is used to examine the formation of barium sulfate scale in situ under non-ambient conditions using angle-dispersive XRD on beamline X17b1 at the NSLS.

A computational study of the effect of doping divalent cations in barite

The presence of divalent cations during the nucleation of barium sulfate can alter the properties of the nucleated material. Here, a computational study of the effect of doping barium sulfate with divalent cations (Ca2+ and Sr2+) is presented. The calculations provide information on the energies and lattice parameter changes involved in the doping process and consequent lattice relaxation. Two methods were used to model the doping process. Firstly, the Mott–Littleton method was used to calculate the solution energy of a single dopant cation in the barite lattice, and secondly, the supercell method was used, which enabled varying dopant concentrations to be modelled. The results were in good agreement with available experimental data.

The Implication of HP/HT Reservoir Conditions on the Selection and Application of Conventional Scale Inhibitors: Thermal Stability Studies

In this paper, results are presented which highlight the problems associated with preventing scale and other mineral deposition in the new high pressure, high temperature (HP/HT) reservoirs which are currently under development in the North Sea and elsewhere. These HP/HT systems are characterised by very high salinity brines (TDS up to ∼ 300,000+ ppm), high reservoir temperatures (> 175°C) and pressures up to 15,000 psi and above. A range of mineral deposition or scaling problems are expected for many HP/HT reservoirs. The current practice in conventional oil reservoirs is to treat produced brines with low levels of scale inhibitor in order to prevent mineral scale deposition within the tubulars or in topside equipment. However, in such harsh HP/HT environments, the currently used polymer and phosphonate scale inhibitor chemistries may not be appropriate due to a combination of factors including thermal stability and brine compatibility. In this work, results are presented from static thermal stability tests conducted on conventional polymer and phosphonate scale inhibitors including phosphino-polycarboxylate (PPCA), polyvinyl sulphonate (PVS), sulphonated acrylate co-polymers (VS-Co), penta-phosphonate (DETPMP) and hexaphosphonate (Hexa-P). The paper focuses on the application (continual injection or squeeze) of scale inhibitor in these HP/HT reservoirs and the implications which this has for inhibitor selection. In addition, results from two in situ thermal stability coreflood experiments (at 175°C) are presented, using phosphonate and polyvinyl-sulphonate scale inhibitors, which give some indication of the in situ stability characteristics of these two species. These results help to determine the direction in which research should proceed in order to identify new scale inhibitor species for HP/HT applications.

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.