Liu, Yang (Northeast Petroleum University) | Zhuge, Xianglong (Northeast Petroleum University) | Wang, Zhihua (Northeast Petroleum University) | Huang, Bin (Northeast Petroleum University) | Le, Xinpeng (Daqing Oilfield Company Limited)
Under the hovering background of low oil price, alkali/surfactant/polymer (ASP) flooding technique is proven to be vitally important for enhance oil recovery (EOR) in oil industry. The production practice in Daqing Oilfield (China) shows that the EOR of ASP flooding is more than 10% original oil in place (OOIP) over conventional polymer flooding. However, the problems of corrosion and scaling that surface facilities and pipelines encounter with still remain very challenging in ASP flooding production, especially in the strong alkali (NaOH) ASP flooding fields. In the industrialized-application of ASP flooding process, these problems are drawing more and more attention.
The corrosion behaviors of surface facilities and pipelines that utilized in strong alkali (NaOH) and weak alkali (Na2CO3) ASP flooding fields were characterized with the integration of production practice, the general anticorrosion measures and the failure of internal coating in fields were presented and demonstrated. A coating solution for fluorocarbons surface treatment was proposed and tested in this case study. The performance of interior surface coatings including corrosion-scaling resistance, wax-deposition inhibition and drag reduction was evaluated with the existence of ASP chemicals in produced emulsions, and the mechanism was discussed from both film-forming and reducing surface energy aspect. The distinct competitive advantage of fluorocarbons interior coating for anticorrosion and wax-deposition inhibition in ASP flooding production was presented.
Considerable corrosion and scaling were created and covering the surface facilities such as the storage tanks of ASP chemicals, the pipelines for injection and production, and the heating furnaces in ASP flooding production. Both of the applied physical and chemical protection measures are facing to the challenges of service life, potential environmental threats and unpredictable cost-effectiveness. High bond energy and strong chemistry inertia of fluorinated resins can prevent the coating structure from being destroyed and develop flexibility and weatherability of the coating. The pore resistance and shielding performance of fluorocarbon coating in corrosion environment highlighted actually result from the superior mechanical properties, super-hydrophobicity, and self-cleaning performance. Furthermore, the low surface energy and low coefficient of friction of the fluorocarbon interior coating provide the possibility of pipeline wax-deposition inhibition and drag reduction. The maximum wax-deposition inhibition rate and the maximum drag reduction rate reached 46.42% and 60.00% respectively for high-viscosity ASP flooding produced emulsions in this case study. The reasonable coating configurations and process are certainly indispensable in the potential applications of fluorocarbons surface technology.
The case study contributes to the existing knowledge in the implementation of chemical EOR project for a green oilfield development, and it is also helpful to accelerate industrialized-application of ASP flooding and design another emerging pattern-flood pilot.
Zhong, Huiying (Northeast Petroleum University) | Yang, Tingbao (Northeast Petroleum University) | Yin, Hongjun (Northeast Petroleum University) | Fu, Chunquan (Northeast Petroleum University) | Lu, Jun (The University of Tulsa)
Chemical combination flooding technique especially alkali/surfactant/polymer (ASP) flooding has proven to be an indispensable way to enhance oil recovery (EOR). The progress of this flooding technique in Daqing Oilfield (China) shows that it is promising to keep production from falling and help oil companies make profit in a low-oil-price era. However, the ASP chemicals chromatographic separation and loss in sandstone formation are still the weaknesses in the promotion of ASP flooding.
Laboratory investigations for characterizing the behavior and distinction of chemicals loss in sandstone reservoir with strong base (NaOH) and weak base (Na2CO3) ASP flooding were recently carried out. The experiments were designed to pointedly study the chromatographic separation, and consumption loss behaviors of alkali and surfactant in sandstone reservoirs with ASP flooding. Furthermore, the incremental oil recovery factor in heterogeneous sandstone reservoirs with strong base (NaOH) and weak base (Na2CO3) ASP flooding process was evaluated and compared. The loss rates of chemicals and the permeability damage degree in various experiments were determined respectively, the consumption loss mechanism and influencing factors were discussed, and the formulation composition and slug combination patterns were also optimized. Then, the role of ASP chemicals loss in sandstone formation during ASP combination flooding EOR process was worked out.
The results indicated that the chemicals loss behaviors could be weakened and the chemicals chromatographic separation phenomenon could be alleviated in weak base (Na2CO3) ASP flooding, and the average loss rate of alkali and surfactant could drop 9.61% and 15.67% respectively in heterogeneous sandstone reservoirs comparing to strong base (NaOH) ASP flooding. The profitable EOR effect could also be obtained with weak base (Na2CO3) ASP flooding, and the enhanced oil recovery could still reach 20% or more. Moreover, an approximately 15% reduction in permeability damage rate could be realized in the weak base (Na2CO3) ASP flooding instead of strong base (NaOH) system, and the reservoir flow assurance issues related to chemicals loss behaviors could be addressed. The optimal design of ASP formulation and slug combination pattern could technically and economically achieve high oil recovery in sandstone reservoirs with weak base (Na2CO3) ASP flooding.
The results are beneficial to well understand the chemical combination flooding mechanism and can contribute to the existing knowledge in the chemicals super additive effects during EOR process, and it is also significant to further improve the oil displacement efficiency and reduce the injection cost in heterogeneous sandstone reservoirs with weak base (Na2CO3) ASP flooding process.
Kim, Do Hoon (Chevron Energy Technology Company) | Alexis, Dennis (Chevron Energy Technology Company) | New, Peter (Chevron Upstream Europe) | Jackson, Adam C (Chevron Upstream Europe) | Espinosa, David (Chevron Energy Technology Company) | Isbell, Taylor Jordan (Chevron Energy Technology Company) | Poulsen, Anette (Chevron Upstream Europe, Chevron Energy Technology Company) | McKilligan, Derek (Chevron Upstream Europe) | Salman, Mohamad (Chevron Energy Technology Company, University of Houston) | Malik, Taimur (Chevron Energy Technology Company) | Thach, Sophany (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Polymer mixing is often challenging under offshore conditions due to space constraints. A theoretical approach is required to better understand the drivers for polymer hydration and design optimal field mixing systems. We share a novel theoretical approach to gain insights into the energy required for optimum mixing of novel liquid polymers. We present a new parameter, "Specific Mixing Energy" that is measured under both lab and field mixing conditions and can be used to scale-up laboratory mixing. We developed a simplified laboratory mixing process for novel liquid polymer that provided acceptable viscosity yield, filtration ratio (FR), and non-plugging behavior during injectivity tests in a surrogate core. A FR less than 1.5 using a 1.2 μm filter at 1 bar was considered acceptable for inverted polymer quality. We developed estimates for specific mixing energy required for lab polymer inversion to achieve these stringent FR standards and comparable viscosity yield. We then conducted yard trials with both single-stage and dual-stage mixing of the novel liquid polymer and developed correlations for specific mixing energy under dynamic conditions. Based upon the results of lab and yard trials, we tested the approach in a field injectivity test. The FR and viscosity were also correlated to a specific mixing energy to establish the desired operating window range from laboratory to field-scale applications. Such information can be used to enhance EOR applications using liquid polymers in offshore environments.
Qi, Pengpeng (Kemira Chemicals, LLC) | Lashgari, Hamid (University of Texas at Austin) | Luo, Haishan (University of Texas at Austin, TOTAL) | Delshad, Mojdeh (University of Texas at Austin) | Pope, Gary (University of Texas at Austin) | Balhoff, Matthew (University of Texas at Austin)
Experimental data in numerous publications show that viscoelastic polymers can significantly reduce residual oil saturation under favorable conditions. The effect of viscoelasticity is in addition to improved sweep efficiency of polymer flooding. The residual oil saturation decreases with increasing dimensionless Deborah number (a measure of the relative elasticity). We used these extensive coreflood data to develop a new model that is referred to here as an Elastic Desaturation Curve (EDC). The new EDC model was implemented into a reservoir simulator and used to simulate polymer floods at both the lab and field scales. The simulated coreflood results match the experimental oil cut, oil recovery and pressure drop data. The simulator was then used to predict the effectiveness of polymer floods in a quarter five-spot well pattern under favorable field conditions. The field-scale simulations show that a viscoelastic polymer flood can recover significantly more oil (12% OOIP for the base case simulation) compared to an inelastic polymer flood of the same polymer viscosity. A sensitivity analysis shows that polymer concentration, salinity, well spacing, permeability, heterogeneity and injection rate affect the incremental oil recovery due to elasticity. The results suggest that the use of viscoelastic polymers could be a beneficial enhanced oil recovery strategy at the field scale under favorable conditions.
Guo, Hu (China University of Petroleum, Beijing) | Li, Yiqiang (China University of Petroleum, Beijing) | Kong, Debin (China University of Petroleum, Beijing) | Ma, Ruicheng (China University of Petroleum, Beijing) | Li, Binhui (China University of Petroleum, Beijing) | Wang, Fuyong (China University of Petroleum, Beijing)
Although the alkali/surfactant/polymer (ASP) flooding technique used for enhanced oil recovery (EOR) was put forward many years ago, it was not until 2014 that it was first put into practice in industrial applications with hundreds of injectors and producers in the Daqing Oil Field in China. In this study, 30 ASP-flooding field tests in China were reviewed to promote the better use of this promising technology. Up to the present, ASP flooding in the Daqing Oil Field deserves the most attention.
Alkali type does affect the ASP-flooding effect. Strong alkali [using sodium hydroxide (NaOH)] ASP flooding (SASP) was given more emphasis than weak alkali [using sodium carbonate (Na2CO3)] ASP flooding (WASP) for a long time in the Daqing Oil Field because of the lower interfacial tension (IFT) of the surfactant and the higher recovery associated with NaOH than with Na2CO3. Other ASP-flooding field tests completed in China all used Na2CO3. With progress in surfactant production, a recent large-scale WASP field test in the Daqing Oil Field produced an incremental oil recovery nearly 30% higher than most previous SASP recoveries and close to the value of the most-successful SASP test. However, the most-successful SASP test was partly attributed to the weak alkali factor. Recent studies have shown that the WASP incremental oil recovery factor could be as good as that of SASP but with much-better economic benefits.
Screening of surfactant by IFT test is very important in the ASP-flooding practice in China. Whether dynamic or equilibrium IFT should be selected as criteria in surfactant screening is still in dispute. Many believe the equilibrium IFT is more important than the dynamic IFT in terms of the displacement efficiency; thus, it is better to choose a lower dynamic IFT when the equilibrium IFT meets the 10–3 order-of-magnitude requirement. However, it is impossible for many surfactants to form ultralow equilibrium IFT. Because of the low acid value of the Daqing crude oil, the asphaltene and resin components play a very important role in reducing the oil/water IFT and asphaltene is believed to be more influential, although more work is required to resolve this controversial issue.
Whether polymer viscoelasticity can reduce the residual oil saturation is still a matter of debate. Advances in surfactant production and in the overcoming of scaling and produced-fluid-handling challenges form the foundation of the industrial application of ASP flooding. Further work is advised on the emulsification effect of ASP flooding. According to one field test, the EOR routine should be selected depending on consideration of the residual oil type to decide whether to increase the sweep volume and/or displacement efficiency. The micellar flooding failure in one ASP field test in China has led all subsequent field tests in China to choose the “low concentration, large slug” technical route instead of the “high concentration, small slug” one. ASP flooding can increase oil recovery by 30% at a cost of less than USD 30/bbl; thus, this technique can be used in response to low-oil-price challenges.
Enhanced Oil Recovery (EOR) has been utilized in Trinidad and Tobago for over 50 years. Most projects so far have focused on thermal as well as gas injection along with the more conventional waterfloods. In spite of that, recovery factors are still relatively low and the country's oil production has been declining for some time. Surprisingly, given the progress in chemical EOR and in particular polymer flooding in the last 10 years, these processes have not been used in Trinidad and we suggest that it might be time to consider their application. Similarly, foam has been used extensively worldwide to improve performances of gas and steam injection but has not yet been used in the country.
The situation of EOR in Trinidad will be first reviewed along with the characteristics of the main reservoirs. Then the potential for the application of chemical-based EOR methods such as polymer, surfactant and foams will be studied by comparing the characteristics of Trinidad's reservoirs to others worldwide which have seen the applications of chemical-based EOR methods.
This review and screening suggests that there is no technical barrier to the application of all these EOR methods in Trinidad. Most reservoirs produce heavy oil and are heavily faulted, but polymer injection has been widely applied in heavy oil reservoirs as well as in faulted reservoirs before, and suitable examples will be provided in the paper. Similarly, these characteristics do not present any specific difficulty for foam-enhanced gas or steam injection. The main issue appears to be the identification of suitable water sources for the projects.
This paper proposes a new look at EOR opportunities in Trinidad using conventional methods which have not been used in the country. This will help reservoir engineers who are considering such applications in the country and hopefully will eventually result in an increase in the oil production in the future.
Dukeran, Rajiv (The University of Trinidad and Tobago) | Soroush, Mohammad (The University of Trinidad and Tobago) | Alexander, David (The University of Trinidad and Tobago) | Shahkarami, Alireza (Saint Francis University) | Boodlal, Donnie (The University of Trinidad and Tobago)
The objective of this paper is to assess the application of polymer flooding in Trinidad heavy oil reservoirs. Uncertainty analyses on several synthetic models have been performed to evaluate how variations in reservoir properties affect the oil recovery factor (RF) and Net Present Value (NPV).
Three (3) phases were conducted for the polymer flooding assessment. Phase 1 included a core flooding simulation to assess the oil viscosity sensitivity region and the ranges of polymer concentration for optimization. Phase 2 carried out uncertainty analysis using synthetic models to optimize polymer flooding with respect to NPV. Phase 3 discussed more detail analysis of parameters effects and confirmed the observations in previous cases using analytical approach.
Three types of polymer were used in the models, Flopaam 3130S, 3430S and 3630S. In core flooding simulation, optimal range of polymer concentration was estimated between 500ppm to 5000ppm. On recovery-viscosity plot, a high viscosity oil requires a higher polymer concentration to have higher recovery. Our results showed that this trend was not always true mainly due to the low reservoir fracture pressure, since a higher concentration and/or a higher molecular weight polymer require higher injection pressure. Uncertainty analysis in Phased 2 to 3 indicated that °API /viscosity, depth, permeability and polymer concentration had the highest effect on RF and NPV.
This paper also presents optimal polymer concentration versus oil viscosity for Trinidad oil reservoirs. Moreover, this work determines the reservoirs where the polymer flooding is applicable and recommend proxy models to estimate RF and NPV versus reservoir parameters.
Yu, Tao (PetroChina) | Lei, Zhengdong (PetroChina) | Li, Jiahong (PetroChina) | Hou, Jianfeng (PetroChina) | An, Xiaoping (PetroChina) | Zhou, Xiaoying (PetroChina) | Deng, Xili (PetroChina) | Wang, Jinfang (PetroChina)
Objectives/Scope: Waterflood development in low permeability sandstone reservoir is characterized by poor sweep efficiency and fast water breakthrough. Infill drilling has been developed in China for decades as a method of accelerating production and increasing ultimate recovery for such mature waterflooded field. However, optimizing infill drilling pattern entails additional challenges because of the complicated remaining oil distribution affected by reservoir heterogeneity and multi-scale fractures after long-lasting production.
Methods, Procedures, Process: The proposed workflow is a four-step methodology based on a case study of tight oil sandstone reservoirs (average permeability between 0.3mD to 10mD) in Ordos Basin, which is the second largest oil-bearing basin in China. Firstly, a statistical analysis and dynamic diagnosis using real data were applied in order to evaluate waterflood performance. Secondly, the dynamic characteristics of each category were identified by integrating decline analysis, injection/production profile, tracer monitoring and well testing interpretation etc. Moreover, the densely- spaced inspection well core data indicating remaining oil distribution and flush zone was observed. Thirdly, the dominant factors influencing production were investigated considering geological features, waterflooding injection intensity, in-situ stress field etc. Finally, different infill drilling scenarios were simulated and optimized based on the understandings and the field implementation results were presented.
Results, Observations, Conclusions: Three typical production modes and a diagnosis chart were presented indicating effective drive, watered out and poor drive, respectively. The watered out producers performs as drastic water breakthrough, sudden drop of hall plot, sharp spike of GR curve in injection profile and significant amount of tracer production, whereas, poor drive wells act like depletion mode with continuous production drop and extremely low pressure maintenance. Multi parameter analysis explains fracture propagation and reservoir heterogeneity are the dominant factors in watered out region, while oversized well spacing results in poor drive performance, which is testified by real core samples from newly drilled inspection wells. Numerical simulation results indicates that: an optimized staggered line-drive pattern gave the best result for watered out region and the predicted recovery at 95% water cut improved 6.6% of OOIP. This infill drilling optimization methodology was successfully implemented in WY Reservoir and resulted in 6% decrease in water cut and 13% increase in production rate. The estimated ultimate recovery (EUR) improved about 5% of OOIP.
Novel/Additive Information: This paper provides an optimized infill drilling methodology and a case study for better understanding the production performance and infill drilling workflow in waterflooded tight oil sandstone reservoirs. It offers a guidance for future infill drilling of similar reservoirs.
Guo, Hu (China University of Petroleum-Beijing) | Dong, Jiayu (No. 3 Oil Production Plant of Daqing Oilfield Company, Petro China) | Wang, Zhengbo (Research Institute of Petroleum Exploration & Development, Petro China) | Liu, Huifeng (Tarim Oil Company, Petro China) | Ma, Ruicheng (China University of Petroleum-Beijing) | Kong, Debing (China University of Petroleum-Beijing) | Wang, Fuyong (China University of Petroleum-Beijing) | Xin, Xiankang (China University of Petroleum-Beijing) | Li, Yiqiang (China University of Petroleum-Beijing) | She, Haicheng (Xi'an University of Technology)
This paper provides field scale EOR survey in China which is in line with biennial worldwide EOR survey published by Oil& Gas Journal (OGJ). The EOR progress in China is not available due to language difference and other reasons in OGJ EOR survey. From 2018, EOR survey in China will be published biennially. The first part of this survey mainly focuses on basic information. Chemical flooding, unconventional heavy oil, green recovery and natural gas recovery progress in China will be surveyed and discussed in detail in the other four parts elsewhere. The EOR projects including field tests and field applications in China are summarized in the same pattern as OGJ to the largest extent for better readership outside China. Most data is collected from published journal papers and reports. Different from other countries, there are only four major oil companies in China: CNPC, SINOPEC, CNOOC and Yanchang Oil. The 28 branch companies of these four companies are both operator and owners. Oil and gas production from CNOOC is all offshore. CNPC is the largest oil company in China and its oil production in 2016 accounts for 54% oil production in China. EOR survey in China includes chemical flooding (polymer, SP and ASP flooding, gas flooding (CO2, nitrogen and air), thermal production, MEOR, and foam flooding. EOR production in China in 2016 accounts for 18% total oil production, while chemical EOR accounts for 10 %. Up to present, there has been more than 34 ASP flooding projects in China, most in Daqing. The total ASP oil production in 2016 is 407 million tons. More than 30 SP flooding projects have been carried out, with incremental oil recovery factor of 7%-18% OOIP. More than 170 polymer flooding projects have been carried out. Polymer flooding has been used widely in Daqing, Shengli, Xinjiang, Liaohe, He'nan and Bohai. The incremental oil recovery from polymer flooding and ASP flooding is 7%-15% and 18%-30% OOIP respectively. Gas flooding in China is not as successful as chemical EOR. Polymer flooding production in the largest offshore oilfield in CNOOC accounts for 25% total oil production in 2016. While EOR production in China accounts for 15%-18% in recent years, however, the world EOR oil production only accounts for about 3.3% total oil production. EOR is greatly affected by oil price, as indicated from 26 years EOR content change in America. It is the first time that detailed EOR survey in China in line with worldwide EOR survey in OGJ is given. The EOR survey in China provides valuable and helpful information for engineers and researchers in oil and gas industry.
One major concern for Alkaline Surfactant Polymer (ASP) flooding is the possibility of inorganic scale formation near the wellbore and in the production facility. In this process, the precipitation reactions of multivalent hardness ions present in the carbonate reservoirs with alkalis in high pH brines might damage the formation, production facilities, and cause severe flow assurance issues. Therefore, it is crucial to understand the geochemical reactions and possibility of scale formation and its associated problems to develop mitigation plans. In this paper, we performed geochemical simulations to investigate the likelihood of inorganic scale formation during ASP flooding in a 5-spot pilot project in one of the largest carbonate reservoirs in the Middle East.
We used a coupled chemical flooding simulator and geochemical (IPhreeqc) framework for this study. First, we incorporated published laboratory data in a geomodel realization of the pilot area. Second, we used the pilot model to investigate the possibility of scale formation during ASP flooding considering a comprehensive system of reactions. Using IPhreeqc, we were able to include thermodynamic databases with various geochemical reactions and capabilities such as saturation index calculation, reversible and irreversible reactions, kinetic reaction, and impacts of temperature and pressure on reaction constants and solubility products. Thus, we were able to show how and where the scales may form.
Our results indicated that the mixing of very hard formation water or water from the subzones near the production wellbore with the injected alkaline water causes scale deposition. We observed calcite dissolutions with slight increase in pH near the injection wellbores after soft seawater preflush. As the ASP solution was injected and high pH brine propagated, carbonate scale and to a lesser extent hydroxide scale formed near the producer. Moreover, although some carbonate and magnesium hydroxide deposits in the formation, but there was negligible effect on reservoir properties. Furthermore, according to our simulation results, most of the scales deposited near the production wellbore, which increases the chance of reducing wellbore productivity and production system damage. These results can help in developing mitigation strategies i.e. preflood the reservoir with soft brine before introducing the ASP slug and optimize the soft brine injection time.
To the best of our knowledge, this is the first study that a comprehensive chemical flood reactive transport simulator is used to assess scale formation during ASP flooding in a carbonate reservoir. Our approach can be used to identify and mitigate challenges and associated design problems for field-scale ASP scenarios.