Fracturing fluids are commonly formulated with fresh water to ensure reliable rheology. However, fresh water is becoming more costly, and in some areas, it is difficult to obtain. Therefore, using produced water in hydraulic fracturing has received increased attention in the last few years. A major challenge, however, is its high total dissolved solids (TDS) content, which could cause formation damage and negatively affect fracturing fluid rheology. The objective of this study is to investigate the feasibility of using produced water to formulate crosslinked-gel-based fracturing fluid. This paper focuses on the compatibility of water with the fracturing fluid system and the effect of salts on the fluid rheology.
Produced water samples were analyzed to determine different ion concentrations. Solutions of synthetic water with different amounts of salts were prepared. The fracturing fluid system consisted of natural guar polymer, borate-based crosslinker, biocide, surfactant, clay controller, scale inhibitor, and pH buffer. Compatibility tests of the fluid system were conducted at different cation concentrations. Apparent viscosity of the fracturing fluid was measured using a high-pressure high-temperature rotational rheometer. All rheology tests were conducted at a temperature of 180°F and were conducted according to API 13m procedure with a three-hour test duration. Fluid breaking test was also performed to ensure high fracture and proppant pack conductivity.
Produced water analysis showed a TDS content of 125,000 ppm, including Na, Ca, K, and Mg ion concentrations of 36,000, 10,500, 1,700, and 700 ppm, respectively. Results indicated the potential of produced water to cause formation damage. Therefore, produced water was diluted with fresh water and directly used to formulate the fracturing fluid. Divalent cations were found to be the main source of precipitation, and the reduced amounts of each ion were determined to prevent precipitation. The separate and combined effects of Na, K, Ca, and Mg ions on the viscosity of the fracturing fluid were also studied. Fluid viscosity was found to be significantly affected by the concentrations of divalent cations regardless of the concentrations of monovalent cations. Monovalent cations reduced the viscosity of fracturing fluid only in the absence of divalent cations, and showed no effect in the presence of Ca and Mg ions. Water with reduced concentrations of monovalent and divalent cations showed the most suitable environment for polymer hydration and crosslinking.
This paper contributes to the understanding of the main factors that enable the use of produced water for hydraulic fracturing operations. Maximizing the use of produced water could reduce its disposal costs, mitigate environmental impacts, and solve fresh water acquisition challenges.
San, Jingshan (New Mexico Institute of Mining and Technology) | Wang, Sai (New Mexico Institute of Mining and Technology) | Yu, Jianjia (New Mexico Institute of Mining and Technology) | Lee, Robert (New Mexico Institute of Mining and Technology) | Liu, Ning (New Mexico Institute of Mining and Technology)
This paper reports the study of the effect of different ions (monovalent, bivalent, and multiple ions) on nanosilica-stabilized CO2 foam generation. CO2 foam was generated by co-injecting CO2/5,000 ppm nanosilica dispersion (dispersed in different concentrations of brine) into a sandstone core under 1,500 psi and room temperature. A sapphire observation cell was used to determine the foam texture and foam stability. Pressure drop across the core was measured to estimate the foam mobility. The results indicated that more CO2 foam was generated as the NaCl concentration increased from 1.0% to 10%. Also the foam texture became denser and foam stability improved with the NaCl concentration increase. The CO2 foam mobility decreased from 13.1 md/cp to 2.6 md/cp when the NaCl concentration increased from 1% to 10%. For the bivalent ions, the generated CO2 foam mobility decreased from 19.7 md/cp to 4.8 md/cp when CaCl2 concentration increased from 0.1% to 1.0%. Synthetic produced water with total dissolved solids of 17,835 ppm was prepared to investigate the effect of multiple ions on foam generation. The results showed that dense, stable CO2 foam was generated as the synthetic produced water and nanosilica dispersion/CO2 flowed through a porous medium. The lifetime of the foam was observed to be more than two days as the foam stood at room temperature. Mobility of the foam was calculated as 5.2 md/cp.
Alkan, H. (Wintershall Holding GmbH) | Klueglein, N. (BASF SE) | Mahler, E. (BASF SE) | Kögler, F. (Wintershall Holding GmbH) | Beier, K. (Freiberg University) | Jelinek, W. (Wintershall Holding GmbH) | Herold, A. (BASF SE) | Hatscher, S. (Wintershall Holding GmbH) | Leonhardt, B. (Wintershall Holding GmbH)
This paper provides an update on a microbial enhanced oil recovery (MEOR) project conducted by Wintershall and BASF. Overall nutrient development and planning of a single well field trial (huff'n'puff, HnP) including risk management are described. A nutrient solution is tailored to stimulate growth and metabolite production of a reservoir community of various indigenous microbial species in a Wintershall operated oil field with challenging reservoir characteristics, including high salinity (160,000 ppm). Up-scaled imbibition experiments performed with sandstone cores using MEOR-oil systems are compared with injection brine-oil systems and assessed for the implications on incremental oil. The results of sandpack and coreflood experiments performed with optimized nutrient solutions are discussed regarding incremental oil recovery and responsible EOR mechanisms. A MEOR modelling concept developed using STARS/CMG is used to estimate additional oil production under various feeding strategies after the calibration of the EOR mechanisms assigned.
As the laboratory and numerical works have indicated the feasibility of the MEOR field application, emphasis has been put on risk issues ranked in the register of the project. The key risk is potential souring of the reservoir due to the activation of the sulphate reducing bacteria (SRB) growing on the metabolites generated by the MEOR target community. Conventional mitigation measures have been tested in short and long-term experiments. An innovative solution had been developed to assure H2S free application without any consequences to the reservoir and to the MEOR application.
A single well pilot application is planned in a pre-selected well of the Wintershall field studied with two main objectives: (1) proof of the concept of risk mitigation and (2) stimulation of growth and metabolite production. Identification of operational issues as well as data gathering to improve the forecasting methods towards full-field predictions are secondary objectives. A monitoring plan has been initiated to establish a baseline in terms of microbiological and petro-dynamic parameters. Temperature and volumetric distributions have been predicted based on the results of an injectivity test performed in the well. The data is used to design the HnP operation and the surface setup for the injection rate of 100 m3/day nutrient solution under well-defined conditions.
Low-salinity waterflooding has been portrayed as an effective enhanced-oil recovery technology. Despite compelling laboratory and field evidence of its potential, the underlying mechanisms still remain controversial. In this study, the enhanced-oil recovery mechanisms are investigated considering a distinct interfacial effect, i.e. water-crude oil interfacial viscoelasticity, through analysis of capillary hysteresis. An experimental setup with an oil-wet and a water-wet media on each end face of the core sample was utilized to capture capillary and rock electrical properties hysteresis. Moreover, new improvements over the traditional quasi-static porous plate method were implemented to accelerate measurements. Two experiments were conducted on Minnelusa formation rock samples and TC crude oil, at low temperature (30 °C) and without any significant aging as to minimize wettability alteration. Two core plugs were flooded with high-salinity and low-salinity brines, separately. It is found that the dynamic-static method with a ceramic disk, i.e. a combination of continuous injection in drainage and stepwise quasi-static method in imbibition on short 1" long core samples, allows one to capture the correct envelopes of the capillary pressure curves and save ~ 30% of the total time; a thin membrane is anticipated to save ~90% with respect to traditional quasi-static porous plate method. The capillary hysteresis experiments at low temperature prove that low-salinity brine is able to suppress capillary hysteresis. This is attributed to the formation of a more visco-elastic brine-crude oil interface upon exposure to low-salinity brine, leading to a more continuous oil phase. In addition, we show that wettability plays an essential role on electrical resistivity and the more oil-wet, the more hysteresis occurs, namely that resistivity values in imbibition are higher than those in drainage. The findings in this paper demonstrate that low-salinity waterflooding can still increase oil recovery even in the absence of wettability alteration.
Compositional reservoir simulation plays a vital role in the development of conventional and unconventional reservoirs. Two major building blocks of compositional simulation are phase behavior and fluid transport computations. The oil and gas reserves and flow of reservoir fluids are strongly dependent on phase behavior. In conventional reservoirs, capillary pressure is relatively small and is typically ignored in phase behavior calculations. However, large capillary pressure values are encountered in tight formations such as shales; and therefore, its effects should not be ignored in phase equilibria calculations. Neglecting the effects of capillary pressure on phase behavior can lead to an inaccurate estimation of original oil and gas in place as well as recovery performance. In spite of this, the effect of capillary pressure on phase behavior in tight reservoirs has not been well studied using compositional simulation, especially for hydraulically-fractured reservoirs.
In this paper, we develop a new compositional reservoir simulator capable of modeling discrete fractures and incorporating the effect of capillary pressure on phase behavior. Large-scale natural and hydraulic fractures in tight rocks and shales are modeled with a technique called Embedded Discrete Fracture Model (EDFM) where fractures are modeled explicitly without using local grid refinement or an unstructured grid. Flow of hydrocarbons occurs simultaneously within similar and different porosity types. Capillary pressure is considered in both flow and flash calculations, where simulations also include variable pore size as a function of gas saturation in each grid block. We examine the impact of capillary pressure on the original oil in place and cumulative oil production for different initial reservoir pressures (above and below the bubble-point pressure) on Bakken and Eagle Ford fluids. The importance of capillary pressure on both flow and flash calculations from hydraulically fractured horizontal wells during primary depletion in fractured tight reservoirs using Bakken fluid composition is demonstrated.
Phase behavior calculations show that bubble-point pressure is suppressed allowing the production to remain in the single-phase region for a longer period of time and altering phase compositions and fluid properties such as density and viscosity of equilibrium liquid and vapor. The results show that bubble-point suppression is larger in the Eagle Ford shale than for Bakken. When capillary pressure is considered, we found an increase in original oil in place up to 4.1% for Bakken and 46.33% for the Eagle Ford crude. Depending on the initial reservoir pressure, cumulative primary production after one year increases owing to capillary pressure by approximately 9.0 – 38.2% for Bakken oil and 7.2 – 154% for Eagle Ford oil. The recovery increase caused by capillary pressure becomes more significant when reservoir pressure is far below bubble-point pressure. The simulation results with hydraulically fractured wells give similar recovery differences; cumulative oil production after 1 year is 3.5 – 5.2% greater when capillary pressure is considered in phase behavior calculations for Bakken.
A physically based generic viscosity model for synthetic polymer solutions has been created. It gives viscosities as a function of shear rates (Carreau curves). The input to the model is concentration, temperature, salinity and molecular weight (polymer type). A model for mechanical degradation of synthetic polymer solutions has also been developed. It calculates the solution viscosity after mechanical degradation by flow through a porous medium. The two models are linked through molecular weight distributions of the polymer solutions.
The viscosity model fits very well experimental data from viscometry. The mechanical degradation model also fits available experimental data when utilising a correction factor. The models have good predictive power and can be used for different purposes such as, estimating mechanical degradation for different plugging scenarios calculating the added polymer concentration needed to achieve a given in-situ viscosity at a certain level of degradation calculating the viscosity degradation for a diluted production fluid with known Mw (from analysis) and unknown concentration. estimating degradation during operation of a well based on the pressure data choosing the best polymer solution for a specific field calculating the effects of pre-shearing (before injection) and the optimal degree of pre-shearing perform case studies to investigate the impact of system parameters on polymer degradation
estimating mechanical degradation for different plugging scenarios
calculating the added polymer concentration needed to achieve a given in-situ viscosity at a certain level of degradation
calculating the viscosity degradation for a diluted production fluid with known Mw (from analysis) and unknown concentration.
estimating degradation during operation of a well based on the pressure data
choosing the best polymer solution for a specific field
calculating the effects of pre-shearing (before injection) and the optimal degree of pre-shearing
perform case studies to investigate the impact of system parameters on polymer degradation
The models have also been used for further development to estimate polymer injectivity as well as degradation in process equipment.
Currently, the model predicts slightly increasing degradation for decreasing water salinity which is opposite the trend indicated by most experimental data. Reasons for the deviation are disussed together with suggestions for possible extention of the model.
Guo, Hu (China University of Petroleum) | Li, Yiqiang (China University of Petroleum) | Gu, Yuanyuan (China University of Petroleum) | Wang, Fuyong (China University of Petroleum) | Yuliang, Zhang (Research Institute of Xinjiang Oilfield Company, CNPC)
ASP flooding is one of the most promising EOR technologies. Lots of laboratory studies and pilot tests have been finished in Daqing oilfield which is the largest oilfield in China. Comparison of two typical strong alkali ASP (WASP) and weak alkali ASP (SASP) pilots are presented with detained information.
ASP flooding could not only remarkably improve displacement efficiency but also improve sweep efficiency due to the low interfacial tension effect and mobility control technique with help of viscosity enhancement and emulsification effects. The incremental recovery of two ASP was near, while in peak oil production period after the injection took effects, WASP had high oil production rate than SASP. The emulsification effects in weak alkali ASP was weaker than strong one. The chromatographic separation was different in two pilot tests, in which weak alkali ASP had alleviated chromatographic separation. The constitution production sequence was both polymer first, then alkali and finally surfactant. The time gap between surfactant and polymer was about 0.0606 PV for strong alkali ASP, while a respective value of 0.1281PV for weak alkali ASP. Scaling was different and thus anti-scale technique adopted in two pilot tests were a little different. The overall input-output ratio for two tests was different and weak alkali ASP performed much better. Comparison was first made between strong alkali and weak alkali based ASP flooding from field tests perspective. Weak alkali based ASP is proven the development trend.
Polymer flooding is a widely used commercial process with a low cost per barrel of produced oil, For this application, hydrolyzed polyacrylamide (HPAM) polymers are the most widely used type of polymer. In an era of low cost oil, it is becoming even more essential to optimize the polymer flooding design under realistic reservoir conditions. The objective of this research was to better understand and predict the behavior of HPAM polymers and their effect on residual oil saturation, in order to improve the capability of optimizing field design and performance. The corefloods were performed under typical field conditions of low pressure gradients and low capillary numbers. The polymer floods of the viscous oils recovered much more oil than the water floods, with up to 24% lower oil saturation after the polymer flood than the water flood. The experimental data are in good agreement with the fractional flow analysis using the assumptions that the true residual oil saturations and end point relative permeabilities are the same for both water and polymer. This suggests that for more viscous oils, the oil saturation at the end of water flood (i.e. at greater than 99% water cut) is better described as ‘emaining’ oil saturation rather than the true ‘esidual’ oil saturation. This was true for all of the corefloods regardless of the core permeability and without the need for assuming a permeability reduction factor in the fractional flow analysis.
It is generally assumed that while the presence of foam reduces the mobility of the gas phase, it does not alter the mobility of the liquid phase. Here, the effect of surfactant type and concentration on the behavior of nitrogen foam flow in porous media is investigated by simultaneous injection of gas and surfactant into Bentheimer sandstone cores. Different surfactant types, viz., anionic alpha-olefin-sulfonate (AOS) and zwitterionic Betaine with different surfactant concentrations from critical-micelle-concentration (CMC) to higher concentration are used in this study. The foam strength is quantified by measuring the pressure drop in different sections of the core. The liquid saturation is measured by analyzing the X-ray images obtained in a medical CT-scanner.
It is shown that the connate water saturation is reduced by increasing the surfactant concentration, and therefore the relative permeability relation for the aqueous phase should be modified when fitting the data to the foam models. It is observed that it is not possible to fit one monotonic liquid relative permeability curve to all the data points, obtained with different surfactant type and concentration in one rock type. Moreover, increasing AOS concentration above a certain value does not have a significant effect on the mobility reduction of the gas phase; however it modifies the liquid relative permeability. These results indicate that the water relative permeability measured in absence of surfactant should not be used to model the flow of foam in porous media, as it can lead to erroneous calculations of the liquid saturation.
Wu, Xingcai (Research Inst. of Petroleum E&D, RIPED, CNPC) | Yang, Zhongjian (Qinghai Oilfield Company, QOC, CNPC) | Xu, Hanbing (RIPED) | Zhang, Lihui (QOC) | Xiong, Chunming (RIPED) | Yang, Huazhen (Huabei Oilfield Company, HOC, CNPC) | Shao, Liming (RIPED) | Kang, Bo (Chengdu North Petroleum E&D Technology Co. Ltd.) | Fu, Yaxiu (HOC) | Tian, Xiaoyan (Startwell Energy Co. Ltd) | Cao, Huiqing (HOC)
Though polymer flooding is widely considered as a good EOR method for heterogeneous fields, it's always a difficulty to be applied in high temperature and high salinity reservoirs, limited by polymer property. GS-E31 reservoir in West China has ultra-high temperature, 258.8°F (126°C), and ultra-high salinity, 18×104mg/L. It is highly heterogeneous, developed with flowing channels. Starting in July 2012, a new polymer (SMG) flooding was pilot tested, with success technically and economically.
Before SMG injection, tracer test was conducted in the pilot, figuring out the distribution position and direction of prevailing flowing channels. The microscopic pore structure and size were studied. The temperature and salinity resistance of the new particle-type polymer under reservoir condition was tested. The oil displacing effect was simulated on parallel dual core model. For the pilot test, two slugs with different particle sizes were designed. To guarantee the flooding effect, a preposed PPG (preformed particle gel) slug with larger size was designed to inhibit prevailing flow channels.
The lab studies showed the new polymer particles kept stable appearance within 100 days under the reservoir temperature and salinity, denoting high capacity of temperature and salinity resistance. And by physical simulation it could obtain EOR of 12.3%. The pilot test was started in July 2012 and ended in December 2013, and the total liquid injection amount was 12.2×104m3, which was 0.1 PV. During operation, the polymer particle size and concentration were adjusted based on the observing data. As a result, the monthly oil rate of the pilot was increased from 1313 t to 2049.6 t, with increase of 736.6 t; and the water cut was decreased from 91.7% to 84.1%. The cumulative oil incremental was 1.03×104t, and the cumulative water production decrease was 4.79×104m3. The input-output ratio was 1:2.09. Though the economical result was not ideal, it was still acceptable under such severe reservoir conditions. Besides, the surveillance showed the preposed channeling inhibition slug did not perform well, which affected the NPF effect, and especially led to the quick water cut rising in the follow-up water injection phase.
Summarizing the lat studies and pilot tests, the new particle-type polymer has obtained a large breakthrough for temperature and salinity resistance comparing to traditional polymer, and the EOR mechanism is different. The matching relationship between particle size and formation pore size is very important for polymer flooding effect. To further study on lab evaluation method and plan optimization is needed. The technology has important referencing meaning for efficiently developing high temperature and high salinity fields.