Current global demand for fossil fuel such as oil is still high. This encourages oil and gas industries to improve their effort of finding new discoveries, developing technique and maximizing recovery of their current resources including in low-permeability reservoir. Enhanced oil recovery (EOR) is a technique to enhanced ultimate recovery. Since technology has been continuously developed such as nanotechnology/nano-size material, EOR methods have improved. One of them is Nano-EOR that triggered great attention in last decade. Nanoparticles may alter the reservoir fluid composition and rock-fluid properties to assist in mobilizing trapped oil. Most of observation from lab-scale reported that it seems potentially interesting for EOR.
Since reservoir management is very essential for the success of all improved/enhanced oil recovery (IOR/EOR) methods, optimizing nanofluids concentration is a proposed reservoir management to maximize oil recovery using Nano-EOR in this paper. Low-permeability water-wet Berea sandstones core-plugs with porosity ranged 13-15% and permeability ranged 5-20 mD were tested. A hydrophilic silica nanoparticles with primary particle size 7 nm was employed without surface treatment. Nanofluids with various concentration ranged 0.01 - 0.1 wt.% were synthesized with synthetic saline water for optimizing study. The wettability alteration due to nanofluids was observed; coreflood experiment was conducted and compared its displacement efficiency.
The results observed a range of nanofluids concentration that could maximize oil recovery in low-permeability water-wet Berea sandstone. Although contact angle of aqueous phase decreases as nanofluids concentration increase which means easier of oil to be released but we observed that higher concentration (e.g. 0.1 wt.%) has a tendency to block pore network and will decrease or even without additional oil recovery.
This study provides if concentration of nanofluids has an important parameter in Nano-EOR and could be optimized to maximize oil recovery of low-permeability water-wet Berea sandstone.
Humphry, Katherine Jane (Shell Global Solutions International) | van der Lee, Merit (Shell Global Solutions International) | Southwick, Jeff G. (Sarawak Shell) | Ineke, Erik M. (Shell Global Solutions International) | van Batenburg, Diederik W (Shell Global Solutions International)
Workflows to assess the technical and economic suitability of an enhanced oil recovery (EOR) technique for a particular field generally involve laboratory testing, such as core flooding experiments, and field-scale reservoir modelling. When building field scale models and interpreting laboratory experiments it is important to understand the flow properties of all phases present.
Alkali-surfactant-polymer flooding (ASP) is an EOR technique under consideration for a number of Malaysian oil fields. In ASP flooding, surface-active molecules decrease the interfacial tension between water and crude oil, increasing the capillary number, and recovering oil trapped in the reservoir pores. The ultra-low interfacial tensions needed for ASP flooding occur when the surface active molecules are equally soluble in the brine and oil phases. Under these conditions, in addition to the brine and oil phases, a third thermodynamically stable phase is formed. This third phase is known as a microemulsion. While the flow properties of crude oil and polymer-enriched brine are well understood, little has been done to characterize the microemulsion phase, particularly with respect to rheology in porous media.
Here, preliminary measurements of microemulsion rheology are presented. Large volumes of microemulsion, with and without polymer, are generated using model alkali-surfactant (AS) and alkali-surfactant-polymer (ASP) systems. These microemulsions are studied using conventional shear rheology. The viscosities measured using a conventional shear rheometer indicate microemulsion viscosities higher than either the AS(P) solution or decane from which they are comprised. Additionally, an in situ, or apparent, viscosity is recovered from core flooding experiments in Berea sandstone, where pressure drop across the core is recorded as a function of the flow rate of the microemulsion through the core. In situ viscosity measurements in Berea sandstone indicate apparent viscosities 1.5 to 6 times larger than those measured in a conventional shear rheometer. The implication of these results for ASP flooding is discussed.
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.
In previous publications, we introduced a methodology to assist in choosing between polymer flooding and infill well drilling. The method has been firstly applied to a synthetic scenario with constant economic parameters, which has demonstrated the impact that oil price can have on the decision making process (Alusta, et. al. SPE 143300) and the method is then applied and tested with varied operational and economic parameters to investigate whether it is better to start polymer flooding earlier or later in the life of the project (Alusta et al., SPE 150454).
The method was then applied to actual field data where the choice of infill well drilling has already been made, to test the robustness of the method against a conventional decision making process for which there is historical data. Application of the method identified that polymer injection would indeed be economically unfavourable (Alusta et al., SPE 163298).
The approach is then carried out in a field where the choice has yet to be made, a field which is currently under waterflood management, and where the operator is considering polymer flooding as an alternative (or in addition) to infill well drilling. Application of the method has identified that under certain technical conditions (related to polymer concentration and duration of polymer injection) and certain economic conditions (related to oil price and operating costs) polymer flooding entails a significant risk of failure, but that if appropriate technical choices are made, and under prevailing economic conditions, polymer flooding is very beneficial for this field, and a combination of polymer flooding and infill well drilling is optimal.
We consider that this approach will be very useful to the industry in helping to make the appropriate choice between potentially various EOR techniques and infill well drilling, taking full account of reservoir engineering AND economic considerations TOGETHER.
Haynes, Andrew Kenneth (Chevron Australia Pty Ltd) | Clough, Martyn David (Chevron Australia Pty Ltd) | Fletcher, Alistair J. P. (Chevron Australia Pty Ltd) | Weston, Stuart (Chevron Australia Pty Ltd)
Barrow Island's Windalia reservoir is Australia's largest onshore waterflooding operation and has been under active waterflood since 1967. The highly heterogeneous reservoir consists of fine-grained, bioturbated argillaceous sandstone that is high in glauconite clay. The high clay content results in a low average permeability (5 md) despite high porosities (25-30%) and hence fracture stimulation is required to achieve economic production rates.
The Windalia reservoir and fluid properties preclude the use of traditional EOR technology, with thermal, miscible and mobility control processes all deemed unfeasible through screening studies. Consequently, the in-depth flow diversion mechanism was developed and applied, which utilizes a low molecular weight polymer to drive the growth of induced hydraulic fractures in the treated injection wells. A 3-injector pilot was executed involving polymer injection for two years, with no detrimental injectivity losses observed for polymer concentrations up to 750 ppm. Considerable fracture growth, oil production rate uplift and reduction in water cut were observed throughout the pilot pattern, in line with predictions:
• Fracture half-lengths increased from 6 ft to 400 ft in one injector and from 141 ft to 322 ft in another
• An initial oil rate uplift of 38% relative to the production baseline was observed; a more conservative estimate suggested that at least half of this was attributable to the tertiary recovery process
• The water-oil ratio was observed to fall from 15 to 11, similarly timed with the oil production increase.
These improvements were observed consistently throughout the pilot area and were distinct from the waterflood behavior elsewhere in the field. This paper briefly summarizes the technology screening and pilot execution stages, after which the results from the pilot are presented and discussed. This technology may be of use in other low-permeability waterfloods with induced injector fractures, for which traditional EOR practices are believed to be unfeasible.
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.
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.
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.
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.