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.
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.
The development of chemical enhanced oil recovery projects throughout the world is on a fast pace, led by a will to increase the final recovery of mature and newly developed hydrocarbon reservoirs The validation of the process is usually achieved by implementing an injection pilot; the goal is to understand, secure, and optimize the technology and to assess its efficiency on increasing final oil recovery for carefully determined capital and operational expenditures.
One of the key factors for a successful polymer flood is the polymer solution viscosity that must remain on target during the transport from its initial preparation, to the well head and down to the reservoir. Thus, a reliable method is required to measure and monitor the polymer solution viscosity on different points along the dissolution, dilution, mixing, and injection lines. This method must take into account the polymer solution characteristics among which the non-Newtonian behavior and sensitivity to mechanical and chemical degradations.
This paper presents recent developments of a specific in-line viscometer, which can measure the viscosity at low shear-rate, as per real reservoir conditions, with pressures ranging up to 250 barg. The equipment consists in a low flow, non-shearing pump, which circulates the solution through a given tube (length and diameter) where the pressure drop is measured and allows low-shear viscosity to be extrapolated. Calibration methods and first results are presented in this paper to illustrate the accuracy of the technology and potential installation benefits for chemical enhanced oil recovery operations. The viscometer is made of highly resistant material and can be implemented in all hazardous areas in remote mode without manual operations, no waste and very little maintenance.
This new device has been designed to solve the common issues encountered with the vast majority of commercial equipment that is not compatible with currently injected polyacrylamide solutions. It will also allow operators to gather reliable data compared to manual sampling methods that, in addition to requiring manpower, are not easy to conduct without degrading the polymer solutions.
This paper discusses a structured combination of procedures used to investigate polymers for EOR application with the focus on performance, compatibility with production chemicals and phase behaviour. This approach allows for early identification of risks and points to further work necessary for mitigation before field implementation. The case studied here was a system with total dissolved solids (TDS) of 80000 mg/l and temperature requirements of 40 to 70 oC. Effective screening of polymers has benefited from dissolution/viscosity, thermal stability and filtration tests. At lower temperatures (40 oC), polymers were shown to be fit-for-purpose for the conditions evaluated. All polymers showed loss of viscosity with some leading to complete viscosity loss at increased temperatures. This is the result of hydrolysis and interaction with the divalent cations present in the make-up synthetic brine. In-situ viscosity allowed for identification of phase behaviour effects which could affect injectivity (difference in apparent and rheometer viscosity). For the best performing polymer the presence of corrosion and scale inhibitors did not affect viscosity. No detrimental effects on corrosion inhibition and water in oil emulsions were observed. Increases in oil in water with potential fouling/deposition was identified for future study.
Chemical injection in enhanced oil recovery (EOR) projects is a complex process because it involves multiple chemicals with complex fluids. Costs for even a small-scale pilot test could be up in the millions of US dollars (USD) and large-scale field-wide expansion would be in the 100s of millions USD for onshore projects. Costs for offshore projects would increase by multiple folds compared to onshore projects with comparable sizes.
This paper discusses (1) conventional designs for small- or large-scale injection facilities, (2) recent improvements in conventional designs, and (3) new concepts in chemical injection facility designs that can improve the quality, lower the cost, and reduce the lead time in the implementation of chemical EOR (CEOR) projects.
Qiang, Wang (CNPC Research Institute of Petroleum Exploration & Development) | Ming, Gao (CNPC Research Institute of Petroleum Exploration & Development) | Zhaoxia, Liu (CNPC Research Institute of Petroleum Exploration & Development) | Bakar, Mohamad Abu (PETRONAS) | Chong, Yeap Yeow (PETRONAS) | Adnan, Izwan B. (PETRONAS)
The objective of this paper is to scope the Chemical EOR potential in both GNPOC and PDOC fields in Sudan. From the initial EOR screening, the most amenable EOR processes identified for both GNPOC and PDOC are mainly chemical and thermal EOR. Chemical EOR is the leading EOR process in GNPOC fields while thermal EOR is the leading EOR process in PDOC fields.
Chemical EOR evaluation was performed using Eclipse EOR black oil simulator. Simulations were performed on sector models constructed or extracted from full field models which have been conditioned to the current reservoir condition. The chemical input data was referenced mainly from Qing Hai oil field lab data which oil properties are similar to that of Sudan's. The chemical EOR evaluation encompass 3 different types of chemical processes; polymer flooding, surfactant-polymer (SP) flooding and alkaline-surfactant-polymer (ASP) flooding. Chemical EOR can potentially improve field recovery factor between 4-18% depending on the type of chemical EOR process. ASP flooding possess the highest potential with incremental oil recovery over waterflood ranging between 12%-18% followed by SP flooding and polymer flooding. ASP flooding is taken as the reference chemical process in this study as it as it represent the highest chemical potential.
The outcome of this study is believe to be helpful to successful planning of Chemical EOR applications in sudan.
Chemical EOR projects were very active during 1980?s, however, during 90?s the interest in chemical EOR has fallen due to the low oil prices and also technical challenges that the methods poses. While surfactant flooding has difficult design considerations of chemicals, large capital requirements and is very sensitive to local reservoir heterogeneities, alkali can react strongly with minerals in the connate water and reservoir rocks may adversely impact the process. This complex process is yet to be understood. If the field is offshore, chemical EOR becomes even more challenging due to sophisticated logistics, incremental costs, highly deviated wells, larger well spacing and limited well slots on the platform. However, recently there has been a renewed interest in chemical flooding mainly due to valuable insights gained through chemical floods done in the past and better technical understanding of the processes and favorable economic conditions
For robust production forecasts, various uncertainties due to complex chemical processes should be quantified thoroughly. Some of the important uncertainties for full field production forecasts are chemical adsorption on rock surface, interfacial tension (IFT) and residual oil saturation reduction by chemical. Proper coreflood experiments are critical to reduce these uncertainties. Careful matching of coreflood experiments in numerical simulations is also important which provides key inputs for full field forecast. Another important element in the successful commercial application for chemical EOR process is a well-designed pilot. After the completion of pilot, the results should be carefully matched in the simulation model. Once satisfactory match is obtained, the key step would be to upscale the results to the full field level.
Discussed in this paper are the impact of some of these uncertainties and the method used to reduce them. In this paper the workflow and key tasks in dealing with the simulation of chemical EOR process elements like residual oil saturation, IFT reduction and adsorption parameters are discussed. The results show that the incremental oil is very sensitive to the various simulation inputs.
Two commercial Alkali Surfactant Polymer (ASP) floods became operational in the Taber area of Alberta, Canada in 2006 and 2008. Both of these floods used NaOH as the Alkali. Throughout the course of both projects extreme scale deposition was observed in downhole production equipment, gathering systems, and in the production facility. Early in the life of the floods the scale composition was predominantly calcium carbonate, however over time the scale changed to consist of greater amounts of amorphous silicate.
Scale inhibition and remediation strategies have been developed which include a comprehensive monitoring program, chemical scale inhibition, and mechanical scale prevention techniques. As a result of the large amount of data gathered, models were created to predict scale severity, content, and develop specific mitigation plans. Although clear field wide scaling trends can be identified over the life of these projects, scale mitigation strategies still need to be customized for each well.
Although scale remains an operational challenge in these fields, with proper mitigation procedures it can be managed. This report documents the success in reducing the impact of the scale problem and slowing the depositional rate. When designing ASP floods it is important to plan for scale deposition and be proactive on scale mitigation.
Omar, Shaziera (Universiti Teknologi Malaysia) | Jaafar, Mohd Zaidi (Universiti Teknologi Malaysia) | Ismail, Abdul Razak (Universiti Teknologi Malaysia) | Wan Sulaiman, Wan Rosli (Universiti Teknologi Malaysia)
The natural pressure in hydrocarbon reservoirs is only sufficient in producing small amount of hydrocarbon at the end of the depletion stage. Therefore, in order to enhance or increase the hydrocarbon recovery, water or other fluids are injected into the formation to extract the hydrocarbon from the pore space. This common practice is known as Improved or Enhanced Oil Recovery (IOR or EOR). Foam is purposely used in some of the EOR displacement processes in order to control the mobility ratio, hence improving the volumetric sweep efficiency.
The efficiency of a foam displacement process in EOR depends largely on the stability of the foam films. In laboratory, foam stability is usually measured through physical observation of the foam bubble in a glass tube. Unfortunately, this direct observation is not possible in the reservoir. Therefore, indirect measurement such as the measurement of electrokinetic signal would be a better alternative. This study aims to determine the correlation between the foam stability and the associated streaming potential signals which resulted from the flowing fluid in foam assisted water alternate gas (FAWAG) process.
The experimental work will be conducted at the Reservoir and Drilling Engineering Laboratories at the Faculty of Petroleum and Renewable Energy Engineering (FPREE), UTM. The investigation includes sample preparation, sample analysis, displacing fluid formation, rheological properties test and electrokinetic signal measurement by using NI Data Acquisition System (NIDAS). It is expected that the burst of the foam bubble will change the pattern of the electrokinetic signals.
The research findings could lead to a new approach in monitoring a FAWAG process. Application in the real field could benefit the oil and gas industry in term of making the EOR process more efficient and more economic.