Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Wang, Zhe (Research Institute of Petroleum Exploration and Development, CNPC) | Wu, Kangyun (Research Inst. Petr. Expl/Dev) | Hou, Qingfeng (Research Institute of Petroleum Exploration and Development, CNPC) | Long, Hang (Research Institute of Petroleum Exploration and Development, CNPC)
Lab study of chemical EOR for the carbonate reservoir was performed through core characterization, chemical formula screening, surfactant adsorption losses experiments and oil displacement core flooding tests of chemical flooding.
The research results lay the foundation of future pilot tests for chemical combination flooding applying to carbonate reservoirs.
Core characterization by scanning electron microscope and mercury injection capillary pressure experiment prove that there are plenty micropores and a few emposieu within rock, porosity of formation cores is relatively high but permeability is low, the reservoir lithology belonged to typical biostromal carbonate reservoir and the heterogeneity is severe. Chemical flooding formula was investigated by polymer and surfactant screening tests. Salt tolerant polymers including STARPAM and KYPAM showed good viscosifying performances than conventional polymer when prepared with formation water. Amphoteric surfactant AS-13 and anion-nonionic surfactant SPS1708 were selected and ultra-low interfacial tension between crude oil and formation water can be obtained in alkali-surfactant-polymer (ASP) and alkali free surfactant-polymer (SP) systems. Adsorption losses of surfactants on core sample showed that the dynamic adsorption losses of surfactant AS-13 and SPS1708 were 0.46mg/g and 0.37mg/g respectively. Core flooding tests of chemical flooding proved that more than 17~18% incremental oil recovery over water flooding could be obtained with ASP (0.6wt% Na3PO4 + 0.3wt% surfactant + 1000ppm polymer) or SP (0.3wt% surfactant + 1000ppm polymer) flooding. The effect of both ASP and SP flooding was better than that of surfactant flooding.
The experimental results are considered to be technical feasibility and confirm the effectiveness of chemical EOR methods especially the SP flooding for the biostromal carbonate reservoir, which may present further understanding for chemical EOR field application in carbonate reservoirs.
Zhu, Youyi (Research Inst. Petr. Expl/Dev) | Hou, Qingfeng (Research Institute of Petroleum Exploration & Development, CNPC) | Weng, Rui (Research Inst. Petr. Expl/Dev) | Jian, Guoqing (Research Institute of Petroleum Exploration & Development, CNPC) | Luo, Yousong (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Jianguo (Research Institute of Petroleum Exploration & Development, CNPC)
For mature oil fields, foam flooding is an attractive chemical EOR technique and many pilot tests have been carried out in China. The performance of foam flooding pilot tests and its affect factors on oil recovery was discussed in this paper. The development trend and key technologies of foam flooding technique are pointed out.
Eighteen foam flooding pilot tests have been carried out in China from 1994 to 2010. Good performance have achieved in sixteen pilot tests. Through effects analysis of the pilot tests, three main aspects are concluded for affecting the performance of foam flooding tests. First, the characteristics of target reservoirs influence effects of foam flooding tests. The performance of foam flooding in higher oil viscous reservoirs is better than that in light oil reservoirs. The reservoir temperature and formation water salinity also influences the effects of foam flooding. Secondly, the chemical formula of foam solution and the size of slug influence the performance of foam flooding. The stability of foam formula influences the effects of foam flooding greatly. With the same amount of surfactant solution, the effect of high concentration small-sized slug is better than that in low concentration large-sized slug. Last, the injection method and gas liquid ratio can directly influence the foam performance in the reservoir, gas and liquid mixing injecting model is better than surfactant solution-alternation-gas (SAG) injection, and reasonable gas liquid ratio is important for guarantee good effects of foam flood.
At present, the trend of foam flooding in China is from nitrogen foam flooding and natural gas foam flooding to air foam flooding. The key technologies of foam flooding are the development of high stable foam formula with oil tolerance, salt and temperature resistance, good injection method and reasonable injection parameter etc.
Accurate realistic modeling of the physics governing the process occurring during an EOR displacement is an important challenge the industry is facing when trying to understand and evaluate the potential enhanced-oil-recovery may bring to a given reservoir. Numerical models have been widely used for this task, displacing the traditional analytical techniques under the premise of more reliable results as a function of a detailed representation of the reservoir recovery mechanisms within the models, and often time models which, typically were designed for primary and/or secondary depletion processes are used directly for the tertiary evaluation. This paper is a continuation of an early investigation aimed to address the main challenges of modeling the fine scale displacements with a full field numerical model.
The effects of model resolution, relative permeability up-scaling and force balance for immiscible displacements were investigated in our first paper. Here we concentrate on the effects of reservoir heterogeneity together with model resolution for both miscible and immiscible displacements. Up-scaling challenges are presented as a function of the displacement type and force balance, as well as the effect of fine level heterogeneity and viscous and capillary forces balance during EOR injection processes.
Miscible/Immiscible carbon dioxide injection is considered as one of the most effective technology to improve oil recovery from complicated formations. Main factor restraining wide application of this technology is its dependence on natural CO2 sources, transportation of CO2, breakthrough of CO2 to production wells, corrosion of well and field equipment, safety and environmental problems etc. However, in-situ carbon dioxide generation technology is eliminating CO2 negative impact and strong control of the process.
The EOR mechanism of proposal technology is described as follows: acid and exothermic chemical reaction function relieve deep reservoir damage, micronucleus systems formed possess abnormal reological properties allowing to improve water flooding efficiency, CO2 as a super-critical fluid decreases oil viscosity and gas form CO2 reaches such place in the formation where not many solvents can enter to, foamed gas-liquid system creates additional resistance for water injected after gas-liquid system, surfactant formed decreases interfacial tension in oil-water contact, and CO2 solved in oil increases oil volume what affects on displacement of residual oil.
Lab research shows that proposed technology can decrease injection pressure of damaged core by 11.7MPa, gas generation amount and oil volume increasing rate increases with temperature and system concentration increasing, oil volume increasing rate and oil viscosity reducing rate increasing with oil viscosity increasing. Under the conditions of 60 degrees Celsius, 10MPa, 2010mPa.s, it can increase oil volume by 25%, reduce oil viscosity by 52.7%, improve recovery efficiency by 7.6%~14.2%.
Field pilot tests were conducted in seven injection wells in China Bohai offshore oilfield in 2009~2010. All the wells present significant effect of decreasing injection pressure and increasing injection rate, average decreasing pressure by 3.2MPa, average increasing injection rate of single well by 22118m3, cumulative increasing injection rate by 154827m3, cumulative increasing oil of around production wells by 29000m3. Field pilot tests shows that proposed technology can be applied in a wide range of geological conditions, and be the key to recovering huge amount of oil from highly watered, depleted, heterogeneous and other type of so called hard-to-recover oil reserves.
Enhanced oil recovery (EOR) is fundamental to increasing the ultimate recovery of a reservoir. Among several parameters that govern the success of an EOR project, profile modification is a key factor when flooding heterogeneous reservoirs with multiple zones. Given the time and economic constraints, simultaneous flooding of all zones of interest is preferred although it can be difficult for reasons such as a varying pressure and fluid injectivity/productivity profile caused by permeability contrasts between zones. Injection fluids can bypass low-permeability oil-saturated zones, not achieving the full benefit of injection if the profile is not properly modified. Failure to modify production profiles can lead to early water and gas breakthrough. To mitigate these problems, various approaches such as mechanical downhole equipment or chemical treatments have been used.
This paper presents a comparison of the use of mechanical versus chemical conformance control systems in different scenarios. Conformance control is defined as the process that helps improve the drive mechanism for better sweep of reservoir. The basic premises of both mechanical and chemical systems are introduced. Their applicability, operational benefits, and disadvantages are also described. A 3D reservoir simulator is used to illustrate the varying sweep efficiencies, depending on the conformance control method used. The result from the best case with both injector and producer profile modification demonstrated nearly double the oil recovery compared to the base case with no treatment.
Foam assisted CO2 enhanced oil recovery has attracted increasing attention of oil companies (operators and service companies) and research institutions mainly due to the potentially high benefit of foam on CO2-EOR.
Miscible and immiscible CO2 flooding projects are respectively proven and potential EOR methods. Both methods have suffered from limited efficiency due to gravity segregation, gas override, viscous fingering and channeling through high
permeability streaks. Numerous theoretical and experimental studies as well as field applications have indicated that foaming of CO2 reduces its mobility, thereby helping to control the above negative effects. However, there are still various conceptual and operational challenges, which may compromise the success and application of foam assisted CO2-EOR.
This paper presents a critical survey of the foam assisted CO2-EOR process to reveal its strengths, highlight knowledge gaps and suggest ways. The oil recovery mechanisms involved in CO2 foam flood, the effect of gaseous and soluble CO2 on the process, synergic effect of foaming agent and ultra-low IFT surfactants, logistic and operational concerns, etc. were identified as among the main challenges for this process. Moreover, the complex flow behaviour of CO2, oil, micro-emulsion and brine system dictates a detailed study of the physical-chemical aspects of CO2 foam flow for a successful design. Unavailability of reliable predictive tools due to the less understood concepts and phenomena adds more challenges to the process results and application justifications.
The study highlights the recent achievements and analysis about foam application and different parameters, which cannot be avoided for a successful foam assisted CO2 flood design and implementation. Accordingly, the study also addresses prospects and suggests necessary guidelines to be considered for the success of CO2 foam projects.
This paper focuses on the design, the operation and the laboratory work needed for performing a successfull Single Well Tracer Test (SWTT) campaign in the Handil mature field Indonesia. Three tests have been performed in different waterflooded reservoirs to assess the repartition of Remaining Oil Saturation (ROS) in the field.
An extensive laboratory work has been performed prior to tests to screen chemicals that could be used and then to measure the two main parameters needed for the design of the tests: the partitioning coefficient of the primary tracer between water and oil (Kd) and the hydrolysis reaction rate (kH) of the primary tracer into the water. Measurements were performed at reservoir temperature and pressure conditions using recombined live oil sample and recombined brine with respect to the salinity of each reservoir. Results indicate very low discrepancy of Kd value between reservoirs (4 to 5), while kH show a strong linear dependency with salinity (from 0.12 to 0.45 day-1). To take into account the presence of trapped gas saturation, we measured also the partitioning coefficient of AcOET between the water and the gas phase at reservoir pressure and temperature. As expected the Kd water/gas was low compare to the water/oil with a value of 0.5.
Tests were performed in parallel after the installation and the calibration of laboratory equipments and the commissionning of the injection barge. The tracer profiles quality recorded from the three tests was very good with high tracer recovery and low scattering data. However the interpretation was challenging, and numerical simulation was necessary to handle non ideal phenomenan occurring during these tests and to get reliable ROS estimation. The ROS values range between 20-30% which allows moving forward in the identification of potential EOR reservoir candidates and locations of future pilot zones for the more promising EOR processes.
Polymer flooding is a well established tertiary EOR technique to improve mobility control of a waterflood. Currently partially hydrolyzed polyacrylamide (HPAM) is the industry workhorse in polymer EOR in reservoirs with low salinity and temperature. Biopolymers including hydroxyethylcellulose (HEC) and Xanthan are soluble and excellent viscosifiers in high salinity conditions. This paper will provide a literature review on the use of biopolymers for EOR and focus specifically on the benefits of HEC as a mobility control polymer.
Zhong, Liguo (China University of Petroleum Beijing) | Dong, Zhaoxia (China University of Petroleum Beijing) | Hou, Jirui (China University of Petroleum Beijing) | Li, Yiqiang (China University of Petroleum Beijing) | Sun, Yongtao (China Oilfield Services Limited) | Zhao, Lichang (China Oilfield Service Co.Ltd.) | Lu, Wenkai (Daqing Oifield Company, CNPC) | Qin, Fenglan (Daqing Oifield Company, CNPC)
In consideration of the difficulty to setup conventional steam generator on offshore production platform, a compact steam and flue gas generator is developed to thermally stimulate offshore heavy oil reservoir, which consists of water treatment and injection unit, fuel injection unit, air injection unit, and metering and controlling unit. The temperature of steam and flue gas generated is usually 200-350? with 13.1-28.3wt% flue gas, the injection pressure could be up to 20MPa, and steam injection rate is 80-270 m3/day. In past two years, cyclic steam-flue gas co-injection are applied to 8 offshore horizontal heavy oil wells completed thermally or non-thermally with screen pipe, and up to 3 times of oil production rate in average is observed compared to that of cold production, the peak oil production is more than 100 m3/day.
In order to optimize the steam and flue gas co-injection strategy, laboratory experiments such as rheological characteristic measurement and PVT visualization of mixture of heavy oil and flue gas, 1D micro model displacement and 3D macro sandpack model stimulation, and numerical simulation are carried out to investigate the EOR principles. It shows significant synergistic EOR effect in steam and flue gas co-injection because of the foamy oil flow, improvement in heating and sweeping efficiency and gravity assisted drainage, besides of the combined reduction in oil viscosity by heating and gas solution. Flue gas plays an important role in co-stimulation of heavy oil with lower viscosity (500-2000mPa•s under reservoir condition) for the foamy oil flow and enlargement of heating and sweeping efficiency, at the same time, steam heating becomes more important for heavy oil with larger viscosity. At last, based on above researching results an empirical formula is developed to optimize ratio of flue gas to steam according to special reservoir conditions.
With the depletion of light oil, heavy oil is becoming one of the most promising resources to meet future energy consumption. It is estimated that total resources of heavy oil are 3396 billion barrels worldwide. Water flooding can only achieve less than 20% of heavy oil recovery. Thermal recovery has been proven as a feasible method to recover heavy oil. But it is not suitable for thin layers and deep reservoirs due to excessive heat loss. Polymer flooding and CO2 flooding are potential EOR techniques for the heavy oil reservoirs not suitable for thermal recovery. However, polymer degradation and high costs seriously hinder its field applications. Carbon Dioxide immiscible flooding effectively recovers heavy oil thanks to several mechanisms, such as oil swelling, viscosity reduction and blow-down recovery. This paper discusses the developments in CO2 immiscible flooding at laboratory scale as well as field scale. Laboratory tests show that CO2 can significantly improve heavy oil recover by 30%. Several field cases in USA, Turkey and Trinidad are reviewed. Field experiences show that CO2 flooding is a successful EOR method for heavy oil fields. However, some issues are encountered in field applications, including early gas breakthrough, corrosion, CO2 availability and high costs.