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.
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.
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.
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.
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.
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.
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.