La Cira Infantas is the oldest oil field in Colombia. It has approximately 100 years of production, and it is located in the Middle Magdalena Valley Basin, producing from a black oil multilayered and heterogeneous sandstone reservoir. Primary production began in 1918 until 1959 when the first water flooding process began. In 2005, Oxy Colombia and Ecopetrol initiated a joint venture of a new redeveloped water flooding process. Since the joint venture, the field has expanded to 400 patterns and 1,000 active producer wells, 95% of which are under a water flooding process. The redesign of the field considers 20-acre to 25-acre on average and 5-spot to 7-spot inverted patterns. Injector wells have a selective string completion, with mandrels and packers that allow having control on the vertical distribution of the volume of water per mandrel group. In order to monitor water flood performance in the field, a reservoir surveillance methodology, based on dimensionless variables, has been implemented.
The methodology was originally applied for a CO2 flood surveillance and was later extended to fit water flooding monitoring purposes. The paper presents the application of the dimensionless methodology, which allows the evaluation of water flood areas independently of their pattern configuration. This allows the comparison between patterns, sector or areas versus a theoretical ideal performance curve and quickly identify underperforming patterns in order to propose remedial actions.
The application of this methodology has opened new opportunities in the field including the identification of well candidates for chemical stimulation jobs and conformance jobs, isolation jobs in producer wells as well as pump upsize opportunities. Additionally, it has improved the technical evaluation of workover jobs. Because of this, in the last four years La Cira Infantas has extended its portfolio activity, executing over 400 workover jobs. More importantly, it has allowed the transfer of more than 20MMBO into PDP reserves, and the production of 3,000BOPD of incremental oil production per year since 2014.
This paper will provide an insight into the water flooding surveillance carried out in La Cira Infantas, which has proven to be very successful in Oxy's business units.
Wang, Yang (China University of Petroleum – Beijing and Pennsylvania State University) | Cheng, Shiqing (China University of Petroleum – Beijing) | Zhang, Kaidi (Lusheng Petroleum Development Co., Ltd, SINOPEC Shengli Oilfield Company) | Xu, Jianchun (China University of Petroleum – East China) | Qin, Jiazheng (China University of Petroleum – Beijing) | He, Youwei (China University of Petroleum – Beijing and Texas A&M University) | Luo, Le (China University of Petroleum – Beijing) | Yu, Haiyang (China University of Petroleum – Beijing)
Pressure-transient analysis (PTA) of water injectors with waterflood-induced fractures (WIFs) is much more complicated than hydraulic fracturing producers due to the variation of fracture properties in the shutting time. In plenty of cases, current analysis techniques could result in misleading interpretations if the WIFs are not well realized or characterized. This paper presents a comprehensive analysis for five cases that focuses on the interpretation of different types of pressure responses in water injectors.
The characteristic of radial composite model of water injector indicates the water erosion and expansion of mini-fractures in the inner region. The commonplace phenomena of prolonged storage effect, bi-storage effect and interpreted considerably large storage coefficient suggest that WIF(s) may be induced by long time water injection. Based on this interpreted large storage coefficient, fracture half-length can be obtained. In the meanwhile, the fracture length shrinks and fracture conductivity decreases as the closing of WIF, which has a considerable influence on pressure responses. Results show that the upward of pressure derivative curve may not only be caused by closed outer boundary condition, but also the decreasing of fracture conductivity (DFC). As for multiple WIFs, they would close successively after shutting in the well due to the different stress conditions perpendicular to fracture walls, which behaves as several unit slopes on the pressure derivative curves in the log-log plot.
Aiming at different representative types of pressure responses cases in Huaqing reservoir, Changqing Oilfield, we innovatively analyze them from a different perspective and get a new understanding of water injector behaviors with WIF(s), which provides a guideline for the interpretation of water injection wells in tight reservoirs.
This paper examines oil displacement as a function of polymer solution viscosity during laboratory studies in support of a polymer flood in the Cactus Lake reservoir in Canada. When displacing 1610-cp crude oil from field cores (at 27°C and 1 ft/d), oil recovery efficiency increased with polymer solution viscosity up to 25 cp (7.3 s-1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of the paper explores why this result occurred. That is, was it due to the core, the oil, the saturation history, the relative permeability characteristics, emulsification, or simply the nature of the test? Floods in field cores examined relative permeability for different saturation histories—including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1000 cp. In nine field cores, relative permeability to water (
Polymer flooding has been applied to the development of an offshore oil field S18 located in Bohai Gulf, China, where the water and polymer injection wells are alternately distributed. Field tests have indicated that the oil production and economic profit are significantly affected by the interference between alternately injected water and polymer. Therefore, it is of great importance to quantify the water-polymer interference (WPI) and thus improve the oil production. In this paper, the polymer flooding performance for the offshore oil field S18 has been evaluated by using a newly proposed WPI factor. The developed model provides a new way to evaluate the polymer flooding performance for the offshore oil field. More specifically, onshore and offshore polymer injection processes are thoroughly compared in terms of field performance, reservoir properties, and polymer flooding parameters. Then, a conceptual model is developed to analyze and quantify the interference between the injected water and polymer. The WPI factor is firstly introduced and quantified by a water cut funnel prediction method. The WPI factor is found to increase with the water injection rate and decrease with the polymer concentration. Subsequently, the reservoir simulation model of S18 oil field is well developed including 50 injectors and 93 producers with well-matched field production data. The WPI factor is accordingly optimized by tuning the water injection rate and polymer concentration at different blocks of the S18 oil field with the assistance of orthogonal design method. Consequently, the overall WPI factor of the S18 oil field is decreased by 8.20% after the optimized polymer & water injection scheme is applied, resulting in an increased oil recovery by 0.24%.
Chen, Szu-Ying (University of California at Santa Barbara) | Kaufman, Yair (University of California at Santa Barbara) | Kristiansen, Kai (University of California at Santa Barbara) | Howard, A. Dobbs (University of California at Santa Barbara) | Nicholas, A. Cadirov (University of California at Santa Barbara) | Seo, Dongjin (University of California at Santa Barbara) | Alex, M. Schrader (University of California at Santa Barbara) | Roberto, C. Andresen Eguiluz (University of California at Santa Barbara) | Mohammed, B. Alotaibi (Saudi Aramco) | Subhash, C. Ayirala (Saudi Aramco) | James, R. Boles (UCSB) | Ali, A. Yousef (Saudi Aramco) | Jacob, N. Israelachvili (UCSB)
Waterflooding via injection of chemistry-optimized low-salinity – also, low ionic strength/concentration – waters, such as SmartWater, is becoming increasingly attractive for improved oil recovery, especially in carbonate reservoirs. In this manuscript, we describe the results from a series of experiments and theoretical modeling to determine the mechanisms that govern the
We measured various interrelated crude-oil(
The results presented in this manuscript are of practical significance to provide a better understanding of SmartWater flooding mechanisms in carbonates at multiple length scales, including subnano-, nano-, micro-, and macroscopic scales. The new fundamental understandings presented in this study will also guide the optimization of SmartWater flooding processes in other reservoir systems.
Pilot testing results and economics from a novel electrochemical desalination technology for enhanced oil recovery (EOR) produced water are presented. The pilot objectives were: (1) economically desalt produced water to improve hydrocarbon recovery and lower polymer consumption costs for chemical flood EOR; (2) inform full scale plant development with a field pilot; and (3) optimize pre-filtration, chemical consumption, and energy use to realize a greater than 20% return on investment through reduced polymer consumption.
The paper will present EOR operators with a novel option to reuse produced water as low salinity injection water and recycle polymer to reduce chemical EOR flood operating costs.
This paper presents modeling CO2 enhanced oil recovery (EOR) flood performance through the application of dimensionless scaling for both forecasting and surveillance purposes. While the methodology has been used successfully for West Texas CO2 floods for more than two decades, a recent modification in the process enhances the certainty of forecasted tertiary response based on simulation and analog results. The primary focus of this paper is on how this new approach improves the use of analog or observed production history to develop more reliable forecasts for EOR processes. Business units favor analog methods since they are fast, adaptable and explicit.
Analog tertiary production response is the incremental oil production over an estimated base waterflood oil recovery. The original formulation, published in a different paper (
This paper summarizes BP's Alaskan viscous oil resource appraisal strategy to de-risk viscous oil resource progression with a goal to improve recovery factor by 10%. A key to recovery improvement is application of improved oil recovery/enhanced oil recovery (IOR/EOR) methods. However, even after detailed studies, moving to the next stage including field pilots is not always easy in the mature and remote Alaskan North Slope.
The paper also covers BP's Alaskan viscous oil technology strategy, extraction technologies selection, simulation and analytical studies, laboratory studies, and field trials for various shortlisted methods. A comprehensive study strategy conducted for progressing chemical EOR processes is discussed. The paper also addresses the challenges of obtaining new core and fluid samples for laboratory studies and logistical and economic considerations for field trials due to location and weather conditions in this part of the world.
Recent studies have shown that enhanced oil recovery will be the focal point for approximately 50% of the global oil production in the upcoming two-three decades. According to the several ballpark studies conducted on EOR techniques, results show that for reservoirs with oil viscosities ranging from 10 to 150 m Pa.s., polymer flooding seems to be an ideal development strategy. However, when the oil viscosities exceed 150 m Pa.s., polymer injectivity and pumping efficiencies can turn out to be major inhibiting factors, thereby limiting the range of oil viscosities for which polymer flooding can be utilized. The core reason for this is that the values of viscosity for the injected water containing polymer, calculated for the beneficial mobility ratio, can lead to the inhibiting factor stated above.
Previously conducted lab studies have shown that supramolecular systems are very resistant in high temperature - high salinity systems. To be able to achieve the easier injection, the injected supramolecular viscosity will be kept at lower values and then increased to the levels right before or upon contacting the oil in the reservoir.
The core difference between conventional polymer systems and supramolecular polymer systems is that the latter disassemble and re-assemble as opposed to degradation when exposed to extreme shear stress and temperatures. It can therefore be said that supramolecular polymer systems are self-healing in nature. The phenomenon has been observed in cases where polymers with high molecular weight are forced through narrow flow channels. Though molecular division takes place, supramolecular systems have shown a tendency of reassembly later on. Therefore, adaptability of these systems to bounded or restricted environments can be established.
This study will add the modeling and simulation components of supramolecular systems which can be effectively utilized in high temperature-high salinity conditions through adjustments to viscosities and interfacial properties of these assemblies. This will help compare the displacement efficiency of supramolecular systems which efficiently perform in a wide range of reservoirs such as thin zones, and reservoirs within permafrost conditions. This can significantly benefit the oil and gas companies worldwide in preparing a technically feasible, but also, a cost effective EOR development strategy, whenever polymer injection is of consideration.
This paper discusses a review and adaptation of some classic waterflood performance analytical methods, such as
These classic techniques account for the solution of the one-dimension frontal advance Buckley-Leverett theory (1942), assuming stable flow. In addition, the traditional semilog linear relationship between oil-water relative permeability ratio and water saturationis assumed (constant parameters
This work proposes to redefine aforementioned classic waterflood performance analytical methods with novel oil and water relative permeability expressions derived from the effective-fingering model(EFM) presented by
Adaptation of classic equations (stable) to solutions that account for unstable flow results in more reliable diagnostic-plot techniques for the case of viscous-oil, allowing to correct predictions of oil and water production in the case of heavy-oil waterflooding Additionally, new equations resulted in unified solutions that can be applied for both stable and unstable waterflood and help to improve reliability when estimating ultimate oil recovery, volumetric sweep efficiency, and various reservoir parameters. In the presence of viscous fingering, the water breakthrough and oil recovery from new
In its entirety, these novel waterflood performance analytical methods incorporate viscous fingering features in the traditional flow functions, encouraging the ability to predict ultimate oil recovery for both unstable and stable waterflooding cases and for chemical flooding (i.e., polymer with future adaptation) in heavy-oil reservoirs and facilitating the optimization of heavy-oil enhanced oil recovery (EOR) projects. These results might provide a basis to adapt other classic waterflood performance analytical methods.