Da, Chang (The University of Texas at Austin) | Elhag, Armo (Khalifa University of Science and Technology) | Jian, Guoqing (Rice University) | Zhang, Leilei (Rice University) | Alzobaidi, Shehab (The University of Texas at Austin) | Zhang, Xuan (China University of Petroleum) | Al Sumaiti, Ali (Khalifa University of Science and Technology) | Biswal, Sibani (Rice University) | Hirasaki, George (Rice University) | Johnston, Keith (The University of Texas at Austin)
Stabilization of CO2 in water (C/W) foams with surfactants at high temperatures and high salinities is challenging, due to limited solubility of surfactants in aqueous phase, foamability and thermal stability. The apparent viscosities of C/W foams has been raised to up to 35 cP with viscoelastic aqueous phases formed with a diamine surfactant, C16-18N(CH3)C3N(CH3)2 (Duomeen TTM), or a zwitterionic surfactant, cetyl betaine, at 120 °C in 22% total-dissolved-solids (TDS) brine. Duomeen TTM is switchable from the nonionic (unprotonated amine) state, where it is soluble in CO2, to the cationic (protonated amine) state in an aqueous phase under pH ~6. Therefore, it may be injected in either the aqueous phase or the CO2 phase. The formation of viscoelastic phases with both surfactants lowers the minimum pressure gradient (MPG), and strengthens the lamella against drainage and Ostwald ripening by making the external aqueous phase more viscous, leading to stable foam even at very high foam quality. Both surfactants were shown to have excellent thermal stability and to form unstable emulsions when mixed with oil (dodecane). The core flood results showed that strong foam could be easily generated with both surfactants at a superficial velocity of 4 ft/day. The oil/water (O/W) partition coefficient of Duomeen TTM was very sensitive to pH, while that of cetyl betaine was constant over a wide range of pH. The ability to stabilize C/W foams at high temperature and salinity conditions with a single thermally stable surfactant is of great benefit to a wide range of applications including EOR, CO2 sequestration and hydraulic fracturing.
Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Jian, Guoqing (Rice University) | Ma, Kun (Total) | Mateen, Khalid (Total) | Ren, Guangwei (Total) | Bourdarot, Gilles (Total) | Morel, Danielle (Total) | Biswal, Sibani (Rice University) | Hirasaki, George (Rice University)
The high formation heterogeneity in naturally fractured limestone reservoirs requires mobility control agents to improve sweep efficiency and boost oil recovery. However, typical mobility control agents, such as polymers and gels, are impractical in tight sub-10-mD formations due to potential plugging issues. The objective of this study is to demonstrate the feasibility of a low-interfacial-tension (low-IFT) foam process in fractured low-permeability limestone reservoirs and to investigate relevant geochemical interactions.
The low-IFT foam process was investigated through core flooding experiments in homogenous and fractured oil-wet cores with sub-10-mD matrix permeability. The performance of a low-IFT foaming formulation and a well-known standard foamer (AOS C14-16) were compared in terms of the efficiency of oil recovery. The effluent ionic concentrations were measured to understand how the geochemical properties of limestone influenced the low-IFT foam process. Aqueous stability and phase behavior tests with crushed core materials and brines containing various divalent ion concentrations were conducted to interpret the observations in the core flooding experiments.
Low-IFT foam process can achieve significant incremental oil recovery in fractured oil-wet limestone reservoirs with sub-10-mD matrix permeability. Low-IFT foam flooding in a fractured oil-wet limestone core with 5-mD matrix permeability achieved 64% incremental oil recovery compared to water flooding. In this process, because of the significantly lower capillary entry pressure for surfactant solution compared to gas, foam primarily diverted surfactant solution from the fracture into the matrix. This selective diversion effect resulted in surfactant or weak foam flooding in the tight matrix and hence improved the invading fluids flow in it. Meanwhile, the low-IFT property of the foaming formulation mobilized the remaining oil in the matrix. This oil mobilization effect of low-IFT formulation achieved lower remaining oil saturation in the swept zones compared with the formulation lacking low-IFT property with oil. The limestone geochemical instability caused additional challenges for the low-IFT foam process in limestone reservoirs compared to dolomite reservoirs. The reactions of calcite with injected fluids, such as mineral dissolution and the exchange of Calcium and Magnesium, were found to increase the Ca2+ concentration in the produced fluids. Because the low-IFT foam process is sensitive to brine salinity, the additional Ca2+ may cause potential surfactant precipitation and unfavorable over-optimum conditions. It therefore may cause injectivity and phase trapping issues especially in the homogenous limestone.
Results in this work demonstrated that despite the challenges associated with limestone dissolution, a low-IFT foam process can remarkably extend chemical EOR in fractured oil-wet tight reservoirs with matrix permeability as low as 5 mD.
Dong, Pengfei (Rice University) | Puerto, Maura (Rice University) | Jian, Guoqing (Rice University) | Ma, Kun (Total E&P) | Mateen, Khalid (Total E&P) | Ren, Guangwei (Total E&P) | Bourdarot, Gilles (Total E&P) | Morel, Danielle (Total E&P) | Bourrel, Maurice (Total E&P) | Biswal, Sibani Lisa (Rice University) | Hirasaki, George (Rice University)
Oil recovery in heterogeneous carbonate reservoirs is typically inefficient because of the presence of high-permeability fracture networks and unfavorable capillary forces within the oil-wet matrix. Foam, as a mobility-control agent, has been proposed to mitigate the effect of reservoir heterogeneity by diverting injected fluids from the high-permeability fractured zones into the low-permeability unswept rock matrix, hence improving the sweep efficiency. This paper describes the use of a low-interfacial-tension (low-IFT) foaming formulation to improve oil recovery in highly heterogeneous/fractured oil-wet carbonate reservoirs. This formulation provides both mobility control and oil/water IFT reduction to overcome the unfavorable capillary forces preventing invading fluids from entering an oil-filled matrix. Thus, as expected, the combination of mobility control and low-IFT significantly improves oil recovery compared with either foam or surfactant flooding.
A three-component surfactant formulation was tailored using phase-behavior tests with seawater and crude oil from a targeted reservoir. The optimized formulation simultaneously can generate IFT of 10-2 mN/m and strong foam in porous media when oil is present. Foam flooding was investigated in a representative fractured core system, in which a well-defined fracture was created by splitting the core lengthwise and precisely controlling the fracture aperture by applying a specific confining pressure. The foam-flooding experiments reveal that, in an oil-wet fractured Edward Brown dolomite, our low-IFT foaming formulation recovers approximately 72% original oil in place (OOIP), whereas waterflooding recovers only less than 2% OOIP; moreover, the residual oil saturation in the matrix was lowered by more than 20% compared with a foaming formulation lacking a low-IFT property. Coreflood results also indicate that the low-IFT foam diverts primarily the aqueous surfactant solution into the matrix because of (1) mobility reduction caused by foam in the fracture, (2) significantly lower capillary entry pressure for surfactant solution compared with gas, and (3) increasing the water relative permeability in the matrix by decreasing the residual oil. The selective diversion effect of this low-IFT foaming system effectively recovers the trapped oil, which cannot be recovered with single surfactant or high-IFT foaming formulations applied to highly heterogeneous or fractured reservoirs.
Kan, Amy T. (Rice University) | Dai, Joey Zhaoyi (Rice University) | Deng, Guannan (Rice University) | Ruan, Gedeng (Rice University) | Li, Wei (Rice University) | Harouaka, Khadouja (Rice University) | Lu, Yi-Tsung (Rice University) | Wang, Xin (Rice University) | Zhao, Yue (Rice University) | Tomson, Mason B. (Rice University)
Numerous saturation indices and computer algorithms have been developed to determine if, when, and where scale will form, but scale prediction can still be challenging since the predictions from different models often differ significantly at extreme conditions. Furthermore, there is a great need to accurately interpret the partitioning of H2O, CO2, and H2S in different phases, and the speciations of CO2 and H2S. This presentation is to summarize current developments in the Equation of State and the Pitzer models to accurately model the partitioning of H2O, CO2, and H2S in hydrocarbon/aqueous phases and the aqueous ion activities at ultra high temperature, pressure and mixed electrolytes conditions. The equations derived from the Pitzer ion-interaction theory have been parametrized by regression of over 10,000 experimental data from publications in the last 170+ years using a genetic algorithm on the super computer, DAVinCI. With this new model, the 95% confidence intervals of the estimation errors for solution density are within 4*10'4 g/cm3. The relative errors of CO2 solubility prediction are within 0.75%. The estimation errors of the saturation index mean values for calcite, barite, gypsum, anhydrite, and celestite are within ± 0.1, and that for halite is within ± 0.01, most of which are within experimental uncertainties. This model accurately defines the pH of the production tubing at various temperature and pressure regimes and the risk of H2S exposure and corrosion. The developed model is able to predict the density of soluble chloride and sulfate salt solutions within ±0.1% relative error. The ability to accurately predict the density of a given solution at temperature and pressure allows one to deduce when freshwater breakthrough will occur. Lastly, accurate predictions can only be reliable with accurate data input. The need to improve accuracy of scale prediction with quality data will also be discussed.
Deng, Guannan (Rice University) | Kan, Amy T. (Rice University) | Dai, Zhaoyi (Rice University) | Lu, Alex Y. (Rice University) | Harouaka, Khadouja (Rice University) | Zhao, Yue (Rice University) | Wang, Xin (Rice University) | Tomson, Mason B. (Rice University)
High Ca concentration up to 40,000 mg/L in produced water was observed in Marcellus shale gas wells, such extremely high concentration have great impact to solubility of sulfate scales. To evaluate this impact, the virial coefficients for Ca-SO4 ion-interaction needs to be quantified in Pitzer equation for different P-T regimes. More solubility data with high Ca concentration at high temperature (>120°C) needs to be experimentally determined.
The solubility of anhydrite at Ca2+ concentration up to 1 m (mol/kg H2O) from temperature of 120°C to 220°C and at saturated vapor pressure was measured. A stainless-steel pressure proof reactor was designed to contain a Pyrex bottle, in which reagent grade anhydrite powder was mixed with salt solution of 0.25 m, 0.5 m, 0.77 m, and 1 m CaCl2. Sample was taken by using inner pressure to push solution through inline-filter, and then the Ca2+ and SO42- concentrations in the filtrate was determined by inductively coupled plasma optical emission spectrometry (ICP-OES) and compared over time to confirm when solubility equilibrium was reached.
Results shows that current Pitzer's equation model (ScaleSoftPitzer 2017) predicts saturation index (SI) values with an error of less than 0.1SI at up to 0.77 m Ca2+, but shows an error as much as −0.21 SI at 1 m Ca2+ condition. For typical produced water with less than 30,000 mg/L Ca (about 0.75 m), the current model gives a reliable prediction of anhydrite solubility. If the produced water contains greater than 30,000 mg/L Ca, the model may yield error that are as much as −0.2 SI. Further experiments are needed to correct the Pitzer equation coefficients for better scale predication at higher than 30,000 mg/L Ca.
Zhang, Nan (Statoil) | Schmidt, Darren (Statoil) | Choi, Wanjoo (Statoil) | Sundararajan, Desikan (Statoil) | Reisenauer, Zach (Statoil) | Freeman, Jack (Statoil) | Kristensen, Eivind Lie (Statoil) | Dai, Zhaoyi (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Produced water from the Bakken and Three Forks formations in the Williston Basin is notably high in total dissolved solids, which leads to many well maintenance issues related to halite scaling (salt precipitation). Fresh water is widely used to prevent halite scaling; however, initial treatment programs tend to "overtreat" the problem and leads to high operation and maintenance costs. An effort to improve halite scale management has been explored, which includes identification of wells that need fresh water injection; optimization of the fresh water volumes; minimizing deferred oil production; and preventing other scales associated with the presence of fresh water in the wellbore. Several methodologies have been applied to characterize halite scaling and achieve optimization of fresh water treatments. A scaling prediction model was developed and validated with literature data and field data. The model calculates saturation ratios and optimal fresh water volume, which provides critical inputs for treatment recommendations. Field tests have been conducted to dynamically characterize produced fluids. Results have influenced new methods for treatment and fresh water injection techniques. Halite scale inhibitors have also been examined in laboratory and field tests. This work resulted in optimizing both fresh water and chemical treatment programs to minimize halite scaling. Significant cost savings have been achieved from reduced fresh water usage, thereby lowered produced water disposal.
Harouaka, Khadouja (Rice University) | Lu, Yi Tsung (Rice University) | Ruan, Gedeng (Rice University) | Sriyarathne, H. Dushanee (Rice University) | Li, Wei (Rice University) | Deng, Guannan (Rice University) | Zhao, Yue (Rice University) | Wang, Xin (Rice University) | Kan, Amy T (Rice University) | Tomson, Mason (Rice University)
Calcium carbonate deposition experiments were carried out by pumping a brine solution through PTFE plastic, carbon steel, and 316 stainless steel tubing at 150°C and at a maximum SICaCO3 of 1.36. The kinetics of deposition were inferred from the variation of HCO3- concentration in the effluent with changing flow rate. The inhibition kinetics were determined before, during, and after the addition of NTMP inhibitor into the system. On the metal surfaces, deposition occurred within 10 minutes of the start of the experiment and had similar behavior with changing flow rate, whereas deposition did not begin on the PTFE surface until 30 minutes had passed. No more than 1ppm of NTMP was sufficient to completely halt deposition in the PTFE and stainless steel experiments, whereas up to 2 ppm of NTMP was required in the carbon steel experiment. The deposition kinetics were indistinguishable between the metal surfaces, and were ultimately similar on the smoother hydrophobic PTFE surface once an initial coating of scale had developed. The inhibition efficiency of the NTMP was negatively affected by the corrosion products produced in the carbon steel experiments, assumed to be primarily dissolved Fe (II). Inhibitor retention was higher in the metal surfaces than in the PTFE, possibly due to the preferential adsorption of the NTMP to the surface of the Fe rich steel tubing. Our results suggest that it is the hydrodynamics of brine in the tubing, controlled by flow rate, and the SI that are the main factors controlling scale deposition. Calcium carbonate scale attachment occurs via heterogenous nucleation directly onto the surface of the tube when the brine solution approaches oversaturation from a state of equilibrium with respect to calcium carbonate. The mechanism of inhibition in our system is likely to proceed through the formation of Ca- and Fe-NTMP complexes that either poison the growth surfaces of the scale, or drop the SI of the calcium carbonate by reducing the acitivity of free Ca in the brine.
Lu, Alex Yi-Tsung (Rice University) | Ruan, Gedeng (Rice University) | Harouaka, Khadouja (Rice University) | Sriyarathne, Dushanee (Rice University) | Li, Wei (Rice University) | Deng, Guannan (Rice University) | Zhao, Yue (Rice University) | Wang, Xing (Rice University) | Kan, Amy (Rice University) | Tomson, Mason (Rice University)
Deposition of inorganic scale has always been a common problem in oilfield pipes, especially in raising safety risk and producing cost. However, the fundamentals of deposition mechanism and the effect of various surface, temperature, flow rate and inhibitors on deposition rate has not been systematically studied. The objective of this research is to reveal the process of barium sulfate deposition on stainless steel surfaces.
In this work a novel continuous flow apparatus has been set up to enable further investigation of deposition rate, crystal size and morphology and the effect of scale inhibitor. In this apparatus supersaturate barium sulfate solution is mixed and passed through a 3 feet stainless steel tubing with ID = 0.04 inch or 0.21 inch at 70 to 120 degree C. The barium concentration is measured at the effluent to quantify the concentration drop. After 1 to 200 hours the tubing is cut into pieces to measure the barite deposition amount and observe the barite crystal morphology using SEM.
Under the experimental conditions, the deposition rate along the stainless steel tubing can be modelled by second order crystal growth kinetics, the SEM micrograph also shows that most of deposited barite is micrometer sized crystals. The highest deposition rate happens at the beginning of the tubing even before the expected induction time of bariums sulfate. The results indicated that the deposition happens even before the mixed solution is expected to form particles, which suggest that the heterogeneous nucleation might be the dominate mechanism in the initial stage, then crystal growth takes place and governs the deposition.
The mechanism of scale attachment to tubing surface has never been well-understood. The apparatus in this work provides a reliable and reproducible method to investigate barium sulfate deposition. The findings in this research will enhance our knowledge of mineral scale deposition process, and aid the use of inhibitors in mineral scale control.
Li, Wei (Rice University) | Ruan, Gedeng (Rice University) | Bhandari, Narayan (Rice University) | Wang, Xin (Rice University) | Liu, Ya (Rice University) | Dushane, H. (Rice University) | Sriyarathne, M. (Rice University) | Harouaka, Khadouja (Rice University) | Lu, Yi-Tsung (Rice University) | Deng, Guannan (Rice University) | Zhao, Yue (Rice University) | Kan, Amy T. (Rice University) | Tomson, Mason (Rice University)
Increasing production activities in sour environments with equipment and piping made of low corrosion- resistant carbon steel result in significant iron sulfides (FeS) corrosion and scaling problems. FeS scale control is challenging as FeS formation is favored in production water chemistry (extremely low solubility and fast precipitation kinetics) with complex phase transformations. Efficient chemical control of FeS scales has not been found. A polymeric compound containing amide or its derivative functionalities showed a promising effect by controlling the FeS particle size on a nano-meter scale at threshold quantities. The FeS scales were successfully managed by forming a stable FeS particle suspension in the aqueous phase without partitioning into the oil-water interface. Current development focuses on understanding the interactions between the polymeric-compound based dispersants and environmental factors such as the presence of an oil phase, as well as silica. In addition, performance improvement of the identified dispersants by new chemical additives has been explored. Our results show that biocides such as Tetrakis (hydroxymethyl) phosphonium chloride (THPS) may not be as effective as needed for FeS scale inhibition benefit. At the tested conditions, EDTA shows satisfactory FeS scale inhibition and dissolution performance. In addition, silica significantly affects wettability of FeS particles with part of the previously oil-wet FeS partitioning into the aqueous phase. The FeS inhibition and dissolution effects of EDTA are kinetically "poisoned" by silica; while FeS-dispersing effect of polymeric compounds remains unaffected. However, the previously-shown ability that polymer dispersants keep already-formed large size FeS particles in the aqueous phase is also impaired.