Wilt, Michael (Schlumberger) | Zhang, Ping (Schlumberger) | Maeki, Jorge (Schlumberger) | Netto, Paulo (Petrobras) | Queiroz, Jorge L.S. (Petrobras) | Santos, Jaciara B. (Petrobras) | Oliveira, Valterlene (Petrobras)
Fan, Chunfang (Rice University) | Kan, Amy (Rice University) | Zhang, Ping (Rice University) | Lu, Haiping (Rice University) | Work, Sarah (Rice University) | Yu, Jie (Rice University) | Tomson, Mason (Rice University)
With the advance of new exploration and production technologies, oil and gas production has gone to deeper and tighter formations than ever before. These developments have also brought challenges in scale prediction and inhibition, such as the prevention of scale formation at high temperatures (150-200°C), pressures (1,000-1,500 bar), and total dissolved solids (TDS) (>300,000 mg/L) commonly experienced at these depths. This paper will discuss (1) the challenges of scale prediction at high temperatures, pressures, and TDS; (2) an efficient method to study the nucleation kinetics of scale formation and inhibition at these conditions; and (3) the kinetics of barite-crystal nucleation and precipitation in the presence of various scale inhibitors and the effectiveness of those inhibitors. In this study, nine scale inhibitors have been evaluated at 70-200°C to determine if they can successfully prevent barite precipitation. The results show that only a few inhibitors can effectively inhibit barite formation at 200°C. Although it is commonly believed that phosphonate scale inhibitors may not work for high-temperature inhibition applications, the results from this study suggest that barite-scale inhibition by phosphonate inhibitors was not impaired at 200°C under strictly anoxic condition in NaCl brine. However, phosphonate inhibitors can precipitate with Ca2+ at high temperatures and, hence, can reduce efficiency. In addition, the relationships of scale inhibition to types of inhibitors and temperature are explored in this study. This paper addresses the limits of the current predition of mineral solubility at high-temperature/high-pressure (HT/HP) conditions and sheds light on inhibitior selection for HT/HP application. The findings from this paper can be used as guidelines for applications in an HT/HP oilfield environment.
Lu, Haiping (Rice University) | Kan, Amy (Rice University) | Zhang, Ping (Rice University) | Yu, Jie (Rice University) | Fan, Chunfang (Rice University) | Work, Sarah (Rice University) | Tomson, Mason B. (Rice University)
Calcium sulfate is one of the major mineral scales in oil and gas production. Hemihydrate (CaSO4•0.5H2O) and anhydrite (CaSO4) are the predominant sulfate scales formed at high temperature, while gypsum (CaSO4•2H2O) scale may form at low temperatures (<~45°C). However, it has been shown in this study that anhydrite can form at low temperature in the presence of excess amounts of monoethylene glycol (MEG), and this may occur during offshore production with long tie-backs. The prediction and prevention of calcium sulfate scales requires knowledge of the phase behavior of the three major phases of calcium sulfate.
The phase behavior of different calcium sulfate phases is related to the supersaturation state, temperature, and fugacity of water. In this study, the effect of a common hydrate inhibitor, MEG, on calcium sulfate solubility and phase behavior was investigated. This study was run with NaCl/CaSO4/MEG/H2O solutions at 0-6 molality (M) NaCl and 0-95 wt% MEG at 4-70°C. Three approaches were taken to determine the kinetics of calcium sulfate phase transition at various temperatures, ionic strengths, and MEG concentrations: (1) dissolution of gypsum, (2) dissolution of anhydrite, and (3) nucleation and precipitation of calcium sulfate by mixing calcium- and sulfate-containing solutions. The effect of scale inhibitors on phase transition was also evaluated. Phase transition of gypsum to anhydrite was observed in the presence of high concentrations of NaCl and MEG, regardless of the experimental approach. The transition boundary of temperature and concentrations of NaCl and MEG can be estimated from solubility of calcium sulfate and the fugacity of water. The inhibition mechanism of hexamethylene diamine tetra (methylene phosphonic acid) (HDTMP), one of the most effective inhibitors for calcium sulfate scale, was also tested by investigating the kinetics of precipitation and inhibition of calcium sulfate.
Fan, Chunfang (Rice University) | Shi, Wei (Rice University) | Zhang, Ping (Rice University) | Lu, Haiping (Rice University) | Zhang, Nan (Rice University) | Work, Sarah (Rice University) | Al-Saiari, Hamad (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Scale control in deepwater oil and gas production is often challenging not only because of the geological and mechanical limitations associated with deepwater wells, but also because of the high-temperature (>150°C) and high-pressure (>10,000 psi) (HT/HP) environment, which may be associated with brine containing high total dissolved solids (TDSs) (> 300,000 mg/L). These extreme conditions make scale prediction, control, and testing difficult because of the requirements for special alloys, pumps, and control equipment that are not readily available. Therefore, few reliable ultrahigh-temperature/ultrahigh-pressure (ultra-HT/HP) data are available. To overcome such challenges, an efficient flow-loop method has been established to study both the equilibrium and the kinetics of scale formation and inhibition at ultra-HT/HP conditions. This paper will discuss (1) an efficient flow-loop method to study the solubility of scale minerals at ultra-HT/HP conditions, (2) solubility of barite at temperature up to 200°C and pressure up to 20,000 psi, and (3) scale control and inhibitor selection for deepwater oil and gas production at ultra-HT/HP conditions. Specifically, the performance and thermal stability of some common scale inhibitors at the high-temperature conditions were studied in terms of barite-scale inhibition. The results to date indicated that (1) the solubility of barite at up to 200°C and 24,000 psi can be measured precisely by this newly developed flow-loop apparatus, (2) the rate of mineral scale formation at HT/HP may be considerably faster than previously projected from low-temperature studies and, hence, difficult to inhibit, (3) different scale inhibitors have shown considerably different thermal stability. The results and findings from these studies validate a new HT/HP apparatus for scale and inhibitor testing and information for better scale control at HT/HP conditions.