Foaming in absorber column for sour gas treatment using amine is a common problem which adversely affects column performance leading to reduction in sales and fuel-gas production and solvent loss. Mostly antifoam injection has been a common method to counter the foaming, large dosage and frequent dosing of antifoam many a times aggravates the problem. This study details an alternative technique based on pressure pulse mechanism to control foaming in one of ONGC's gas sweetening plants.
One of ONGC's amine based sour gas sweetening plants faced severe foaming problem frequently. The feed rate is 200 kscm/hr and absorber column operating pressure is 51 kg/cm2. The experiment utilizes the property of surface tension which fluctuates with change in pressure of the system leading to foam collapse. The experimental procedure involved varying the sour gas feed rate, thereby creating pressure pulse inside the absorber column. Differential pressure across the column which is an indicator of foaming tendency is then monitored and controlled within 1.0 kg/cm2 and recorded for establishing effectiveness of the method.
It is observed that by providing a number of cycles of pressure pulse in the absorber, the differential pressure stabilizes gradually which indicates collapse of foam. It shows that whenever there is increase in feed, expansion of bubble takes place which provides high interfacial liquid-vapour contact. On the other hand whenever there is decrease in feed rate, compression of bubble takes place which provides low interfacial liquid-vapour contact. Surface layer surrounding the bubbles in a foam acts as a membrane or skin that can stretch or relax in response to change in pressure and gives a mechanical shock which breaks the bubble. The increase of size ultimately leads to instability and break-up of the upper surface and releases the liquid holdup. Hence by using feed rate spikes, the pressure of the bubble is pulsed to higher levels and returned to substantially the original level. This cycle continues for a selected number of times so that this pressure pulse travels through the liquid and bubbles and affects its surface tension. This results into a transition phase which in very high energy level breaks the bubble and releases the gas and decreases the liquid hold up and controls the foaming phenomenon.
This paper will gives an insight into a novel methodology of mitigating foaming problem in a sour gas treating absorber just by varying the feed rates in a controlled manner. This technique eliminates the need for injecting antifoam agents which in turn will reduce the operating expenditure of the plant. Adverse impact on environment due to excessive use of antifoam agent is also minimized.
Xu, Zhengming (China University of Petroleum, Beijing) | Wu, Kan (Texas A&M University) | Song, Xianzhi (China University of Petroleum, Beijing) | Li, Gensheng (China University of Petroleum, Beijing) | Zhu, Zhaopeng (China University of Petroleum, Beijing) | Sun, Baojiang (China University of Petroleum, East China)
Energized fracturing fluids, including foams, carbon dioxide (CO2), and nitrogen (N2), are widely used for multistage fracturing in horizontal wells. However, because density, rheology, and thermal properties are sensitive to temperature and pressure, it is important to understand the flow and thermal behaviors of energized fracturing fluids along the wellbore. In this study, a unified steady-state model is developed to simulate the flow and thermal behaviors of different energized fracturing fluids and to investigate the changes of fluid properties from the wellhead to the toe of the horizontal wellbore. The velocity and pressure are calculated using continuity and momentum equations. Temperature profiles of the whole wellbore/formation system are obtained by simultaneously solving energy equations of different thermal regions. Temperature, pressure, and energized-fluid properties are coupled in both depth and radial directions using an iteration scheme. This model is verified against field data from energized-fluid-injection operations. The relative average errors for pressure and temperature are less than 5%. The effects of injection pressure, mass-flow rate, annulus-fluid type, foam quality, and proppant volumetric concentration on pressure and temperature distributions are analyzed. Influence degrees of these operating parameters on the bottomhole pressure (BHP) for different energized fracturing fluids are calculated. The required injection parameters at the surface to achieve designed bottomhole treating parameters for different energized fracturing fluids are compared. The results of this study might help field operators to select the most-suitable energized fluid and further optimize energized-fluid-fracturing treatments.
Fredriksen, Sunniva B. (University of Bergen) | Alcorn, Zachary P. (University of Bergen) | Frøland, Anders (University of Bergen) | Viken, Anita (University of Bergen) | Rognmo, Arthur U. (University of Bergen) | Seland, John G. (University of Bergen) | Ersland, Geir (University of Bergen) | Fernø, Martin A. (University of Bergen) | Graue, Arne (University of Bergen)
An integrated enhanced-oil-recovery (EOR) (IEOR) approach is used in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension (IFT), alter wettability, and establish conditions for capillary continuity to improve tertiary carbon dioxide (CO2) foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. Outcrop core plugs were aged to reflect conditions of an ongoing CO2-foam injection field pilot in west Texas. Surfactants were screened for their ability to change the wetting state from oil-wet using the Darcy-scale Amott-Harvey index. A cationic surfactant was the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place (OIP) (OOIP), verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.
Junwen, Wu (Sinopec Research Institute of Petroleum Exploration and Development) | Wenfeng, Jia (Sinopec Research Institute of Petroleum Engineering) | Rusheng, Zhang (Sinopec Research Institute of Petroleum Exploration and Development) | Xueqi, Cen (Sinopec Research Institute of Petroleum Exploration and Development) | Haibo, Wang (Sinopec Research Institute of Petroleum Exploration and Development) | Jun, Niu (Sinopec Research Institute of Petroleum Exploration and Development)
The high efficient foam unloading agent was developed to solve the problem of unloading of liquid loading gas well with high gas temperature, salinity and high concentration of H2S gas and gas condensate. The Gemini anionic surfactant with special comb structure was synthesized as foaming agent molecule, the modified nanoparticles with certain size and degree of hydrophobicity was adopted as solid foam stabilizer, and the fluorocarbon surfactant was designed and synthesised as gas condensate resistance components. The indoor experiment results show that the foam unloading agent showed good foaming and foam stabilizing ability when the temperature is as high as 150°C, salinity is up to 250000 ppm and H2S concentration up to 2000 ppm. Besides, the foam unloading agent present good liquid carrying ability when the volume fraction of gas condensate is as high as 50%. The field test of this foam unloading agent in Longfengshan north 201-XY well shows that, the average gas production increased from 7256 m3/day to 11329 m3/day, increased by 56%, the average differential pressure between tubing and casing dropped from 2.66 MPa to 2.38 MPa, fell by 10.5%, both liquid yield and gas production are obvious, which prove that the foam unloading agent can meet the demand of drainage gas recovery for high content gas condensate gas field.
Low steam viscosity during steam injection can cause steam override and channeling issues for heavy oil recovery, resulting in high operating cost and low oil recovery. One of the common methods to increase the viscosity of steam is by co-injecting surfactants that generate stable foams with steam. The objective of this research is to develop structure-property relationships for surfactants in order to identify surfactant candidates as the steam foam additives for heavy oil recovery.
In this study, alkyl propoxy ethoxy ether carboxylate (alkyl PO EO ECA) surfactants were evaluated. Surfactant solutions at 1 wt% prepared in 1 wt% NaCl were aged at up to 250 °C in Parr reactors for up to 2 weeks. The degradation of the surfactants was quantified based on High Performance Liquid Chromatography profiles of the surfactants before and after the aging process. The foaming performance of the surfactants was evaluated at 1 wt% concentration at varied temperatures from 100 to 250 °C in a high temperature high pressure visual cell. Sand-packed columns were performed to evaluate the ability of the surfactant to increase the apparent viscosity of steam.
The results showed that alkyl PO EO ECA surfactants exhibit excellent chemical stability at up to 250 °C. However, the chemical stability of these surfactants are dependent on the hydrophobe structure as well as the numbers of PO and EO units of the surfactants. Among the studied surfactants, only ECA surfactants with specific structures were able to generate stable foam at 250 °C. It was found that the ECA surfactants with both PO and EO units and a long branched hydrophobe demonstrated to be excellent foaming agents that were able to increase the apparent viscosity of steam by three orders of magnitude at 250 °C in sand-pack columns. In the presence of bitumen, these surfactants were able to increase the steam apparent viscosity by two orders of magnitude. This increase in the steam apparent viscosity is sufficient to overcome the steam override and channeling during steam injection.
Past research has randomly identified some sulfonate and ether carboxylate surfactants as foaming agents for steam EOR processes. This work, however, evaluated these surfactants systematically in order to develop the structure-property relationships that can be used to optimize surfactants as steam foaming agents for thermal EOR processes at up to 250 °C.
Wei, Bing (Southwest Petroleum University) | Wang, Yuanyuan (Southwest Petroleum University) | Chen, Shengen (Southwest Petroleum University) | Mao, Runxue (Southwest Petroleum University) | Ning, Jian (Southwest Petroleum University) | Wang, Wanlu (Southwest Petroleum University)
Foams were introduced to enhanced oil recovery (EOR) for the purpose of improving sweep efficiency via mitigating gas breakthrough. In prior works, well-defined nanocellulose-based nanofluids, which can well stabilize foam film as a green alternative to reduce the environmental impact, were successfully prepared in our group. However, due to the costly manufacturing process, its field scale application is restricted. In order to further simply the manufacturing process and minimize the cost, in this study, we proposed another family of functional nanocellulose, in which lignin fraction was remained as well as carboxyl groups. The primary objective of the present work is to investigate the synergism between the lignin-nanocellulose (L-NC) and surfactant in foam film stabilization. Particular attention was placed on the relation between the chemical composition of L-NC and its stabilizing effect. Direct measurements of foamability, drainage half-time, foam morphology, foam decay, etc., were performed. The results showed that after the contents of lignin and carboxyl group were well tailored, the resultant L-NC can significantly improve the stability of foam either in the absence or presence of crude oil. The flooding dynamics observed in core plugs indicated that the L-NC stabilized foams could properly migrate in porous media and generated larger flow resistance accross the cores than surfactant-only foam.
Jie, Zhang (CNPC Engineering technology R&D company limited) | Xu, Xianguang (CNPC Engineering technology R&D company limited) | Wang, Lihui (CNPC Engineering technology R&D company limited) | Li, long (CNPC Engineering technology R&D company limited) | Zhang, Die (CNPC Engineering technology R&D company limited) | Zhao, Zhiliang (CNPC Engineering technology R&D company limited) | Wang, Shuangwei (CNPC Engineering technology R&D company limited)
Severe formation damage is induced by the invasion of working fluid and the subsequent water blocking. Surface modification by surfactant adsorption can change the wettability of the rock surface to enhance the removal efficiency of reservoir fluid and reduce the water blockage damage. Therefore, surfactant shows a good potential applicant in condense reservoir. In the current paper, an oligomeric silicone surfactant (OSSF) containing sulfonic acid groups is synthesized to improve the water flowback effect.
The critical micelle concentration (CMC) is determined by equilibrium surface tension. Micelle can be formed above the CMC and its size and distribution increase with the concentration. At the same time, the surface tension increases with the aging temperature but decreases with the adding of inorganic salt. The OSSF adsorption through solid-liquid surface can change the surface chemical composition and transfer the wettability of reservoir from water-wet to gas-wet by decreasing the surface energy. Increasing temperature leads to the change in the adsorption isotherm from Langmuir type (L-type) to "double plateau" type (LS- type). Quantum chemistry study shows that the adsorbed layer of OSSF can reduce the adhesive force of CH4 and H2O on the pore surface of cores. The OSSF can also decease the initial foaming volume and stability in induction period and accelerating period of sodium dodecyl benzene sulfonate (SDBS).
It is found that the surface tension of OSSF increases with aging temperature but decreases with the adding of inorganic salts.The OSSF has positive effect on wettability reversal to water-wet reservoir by adsorption on solid-liquid interface. The results indicate OSSF adsorption layer can change surface chemical composition and exhibit lower interface energy than that of the cores. The presence of NaCl can decrease foaming volume and improve foam stability of OSSF. At the same time, OSSF can decease the initial foaming volume and stability in induction period and accelerating period of sodium dodecyl benzene sulfonate (SDBS).
The targeted reservoir for foam mobility control is usually layered or heterogeneous. However, a major limitation of existing foam models is that there are no dependencies of the foam modeling parameters on permeability, even though the permeability is accounted inherently only through changes in gas-water capillary pressure and shear rate. This results in considerable errors in predicting the foam mobility at largely varying permeabilities, which prevents users from simulating correctly the conformance achievable with the help of foam in heterogeneous reservoirs.
Developing a foam simulator with systematic permeability-dependencies of foam properties is a key enabler for the rigorous simulation of foam floods in the field. An advanced population-balance foam model has been developed with reasonable physical mechanisms associated with the effect of permeability on the bubble density, foam generation and stability in porous media. The derivations indicate that the gas viscosity scaling constant increases with permeability exponentially, while the upper limit of foam texture, the foam generation coefficient, and the limiting capillary pressure decrease exponentially as the permeability increases. All these factors collectively affect the foam mobility. The upper limit of foam texture and the foam generation coefficient share the same power-law exponent with permeability because of the similar fundament. As a result, three additional power-law exponents are needed to correlate with permeability in the new model.
To verify the correlations of the parameters with the permeability change, an automated regression program was applied to fit the resistance factors of several groups of foam flood experiments with foam quality scans at different permeabilities. The newly developed permeability-dependency functions showed its great competency in matching all the experimental data in a wide range of permeability. The optimized parameters are largely consistent with the theoretical exponents of the power-law functions of the aforementioned physical properties correlated to permeability, but also suggest extra modifications. In particular, the exponent for the limiting capillary pressure is about -0.5, which is equivalent to that the limiting water saturation is approximately independent of the permeability according to the Leverett J-function. As a result, the new functions of permeability dependencies for the foam-model parameters in the population-balance model enables the foam modeling with only a single input of foam parameters at a referenced permeability. A 2D layered reservoir case was used to test the new permeability functions, which shows the significant difference in terms of the oil recovery and the injector BHP between whether considering the permeability effect or not.
This paper proposed, for the first time, a systematic methodology to account for the critical permeability effect to simulate foam flooding in heterogeneous reservoirs. This is a key advance in consideration of the major limitation of existing reservoir simulators using fixed or ad-hoc foam-model parameters throughout the entire reservoir. This new model enables the reservoir engineers to simulate and optimize the foam performance in real fields with better accuracy of foam physics in porous media.
Unconventional oil and gas resources such as shale gas, shale oil, CBM, tight gas and oil have attracted more and more attention worldwide in recent years. However, most of the formations of unconventional oil and gas are suffering from poor geological condition, thus the resources can not be developed without fracturing stimulation. Conventional hydraulic fracturing usually consumes a huge amount of water and also leads to the pollutions of surface water and even residential water. In addition, the formation damage caused by incomplete gel breaking, adsorption of polymers, clay expansion and water blocking are still not fully eliminated.
Thus, in this work, ultra-dry CO2 foam stabilized by graphene oxide (GO) were explored to get a fracturing fluid characterized by low water consumption, environmental friendliness, high efficiency and low formation damage. The foam quality of fracturing fluid in the study was higher than 90%, thus the water consumption of fracturing fluid was lower than 10% of total volume. The foam stability, rheology and dynamic filtration were studied by using a large-scale fracturing fluid test device.
The results showed that the stability and thermal adaptability of ultra-dry CO2 foam were enhanced by the addition of graphene oxide. The interfacial dilatational viscoelastic modulus of CO2/liquid was increased when the graphene oxide was used with saponin, implying that the bubble film interface became solid-like; The ultra-dry CO2 foam enhanced by the graphene oxide showed a shear thinning behavior. The effective viscosity of ultra-dry CO2 foam was increased by adding graphene oxide and its viscosity was higher than 50 mPa·s at a shear rate of 100s-1; Moreover, compared to pure surfactant foam, the filtration control performance of ultra-dry CO2 foam was also enhanced by graphene oxide. At a filtration pressure difference of 3.5MPa, the filtration coefficient of ultra-dry CO2 foam was decreased significantly by the addition of graphene oxide. Although the core damage caused by foam with graphene oxide was slightly higher than that of pure surfactant foam, the permeability damage was still below 10%, implying that the foam as a fracturing fluid is relatively clean to formation.
Ultra-dry CO2 foam fracturing fluid stabilized by graphene oxide provides a new high-performance fracturing system for unconventional oil and gas at water-deficient area. This study will be beneficial to fracturing applications characterized by low water consumption, environmental friendliness, high efficiency and low formation damage.
Carbon dioxide (CO2) storage in subsurface formations is recognized as the most effective method of permanently sequestering greenhouse gases. However, the possibility of leakage of mobile gases from the storage reservoir is a cause of environmental concern. This study aims to address this concern. A method is presented that can fast-track capillary trapping of gas during gas injection into subsurface geological formations such that a limited amount of free gas is available in case a leakage occur. The method can reduce the time scale of capillary (residual) trapping from decades to weeks. A laboratory experiment indicated that this can be achieved with foam-assisted water alternating gas (FAWAG) injection. In the laboratory setup, capillary trapping of gas was monitored in real time for every successive FAWAG cycle. The trapped gas were stable and remained trapped even after a prolonged water injection. The foaming agents added to the injected water facilitated the increased trapped gas saturation. However, high temperature and salinity significantly reduced the effectiveness of the foam. The type or composition of the injected gas also affect the effectiveness of the foam. The foam is most effective in N2 or N2-rich gas compared to CO2 gas. This was due to the low interfacial tension between the CO2 and the foaming solution. Improvement in foam effectiveness in high temperature high salinity and low IFT environment is much possible as ongoing research works indicate.