Liu, Keyu (CSIRO Earth Science and Resource Engineering) | Clennell, Michael Benedict (CSIRO Earth Science and Resource Engineering) | Honari, Abdolvahab (University of Western Australia) | Sayem, Taschfeen (University of Western Australia) | Rashid, Abdul (CSIRO Earth Science and Resource Engineering) | Wei, Xiaofang (Research Institute of Petroleum Exploration and Development, PetroChina) | Saeedi, Ali (Curtin University)
A series of laboratory investigation on factors affecting Enhanced Oil and Gas Recovery and CO2 geo-sequestration were conducted. The coreflooding experiments were done using a relatively heavy crude oil (18° API), a number of brines of 0.18%-2.5% NaCl and varieties of cores with a range porosity and permeability from 15% and 17 mD to 19% and 330 mD under some typical reservoir pressure-temperature condition of 1164-3300 psi and 50-83 °C. Factors affecting CO2 enhanced oil and gas recovery including the effects of the petrophysical properties of the reservoir rocks, formation water salinity, reservoir pressure, the Minimum Miscibility Pressure (MMP), total volume (PV) injected and injection rate and gravity segregation.
Excellent recovery factors in the range of 27%-34% Original Oil In Place (OOIP) and almost 100% gas recovery were achieved through immiscible and miscible CO2 flooding. Some of the coreflooding experiments were monitored with a medical CT in real time. The coreflooding experiments have shown that (1) reservoir petrophysical properties with permeability difference of up to an order of magnitude do not affect the CO2 EOR factor; (2) variable EOR can be achieved both at reservoir pressures below or above the CO2-oil MMP; (3) Incremental oil recovery is proportional to the pore volume (PV) of CO2 injected up to 3PV; (4) No significant additional recovery was observed beyond the MMP; (5) CO2-Water alternating gas (WAG) flooding can be quite effective in EOR in terms of the less amount of CO2 injected as compared to that for the single CO2-water flooding to achieve the same EOR; (6) there is no benefit to use low-salinity CO2 WAG flooding; (7) the optimum injection rate in the laboratory is around 1 cc/minute. These finding may provide some useful insight and guide for the field application of CO2 enhanced oil and gas recovery; (8) During enhanced gas recovery using supercritical CO2, gravity segregation may occur in some porous-permeable reservoir with denser supercritical CO2 preferentially enter through the bottom of the reservoir.
Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they may not flow gas at optimum rates without advanced production improvement techniques.
The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include mechanical damage to formation rock, plugging of natural fractures by mud solid particles invasion, relative permeability reduction around wellbore as a result of filtrate invasion, liquid leak-off into the formation during fracturing operations, water blocking, skin due to wellbore breakouts, and the damage associated with perforation. Drilling and fracturing fluids invasion mostly occurs through natural fractures and may also lead to serious permeability reduction in the rock matrix that surrounds the natural or hydraulic fractures.
This study represents evaluation of different damage mechanisms in tight gas formations, and examines the factors that can have significant influence on total skin factor and well productivity. Reservoir simulation was carried out based on a typical West Australian tight gas reservoir in order to understand how well productivity is affected by each of the damage mechanisms such as natural fractures plugging, mud filtrate invasion, water blocking and perforation.
Bahrami, Hassan (Curtin U. of Technology) | Rezaee, Mohammad Reza (Tehran University) | Nazhat, Delair Honer (Curtin U. of Technology) | Ostojic, Jakov (Curtin U. of Technology) | Clennell, Michael Benedict (CSIRO Petroleum) | Jamili, Ahmad (University of Oklahoma )
Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they might not flow gas at optimum rates without advanced production improvement techniques.
The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include mechanical damage to formation rock, water blocking, relative permeability reduction around wellbore as a result of filtrate invasion and liquid leak-off into the formation during fracturing operations. Drilling and fracturing fluids invasion mostly occurs through permeable zones or natural fractures and might also lead to serious permeability reduction in the rock matrix that surrounds the wellbore, natural fractures, or hydraulic fracture wings.
This study represents evaluation of water blocking damage in tight gas formations, and the influence on core flow efficiency and well productivity. Core scale reservoir simulations were carried out based on a typical Western Australia tight gas reservoir in order to numerically model liquid invasion during overbalanced, balanced and underbalanced drilling, and the effect on gas production in clean-up period. The simulation results describe how water blocking reduces near wellbore permeability and affects well productivity and gas recovery from tight gas reservoirs.
This work is a part of a fundamental study investigating the efficiency of the alkaline- surfactant-polymer (ASP) flooding process. While heterogeneity in pore structure is a key concern of our research, it is necessary first to have a clear understanding of the baseline behavior when porosity, permeability and throat size are tightly controlled. This control was achieved by manufacturing a homogenous carbonate-cemented sandstone using the calcite in-situ precipitation system (CIPS). We present the multiphase flow properties of the artificial CIPS rocks, including previously unpublished results on oil/water capillary behavior and relative permeability.
In the core flooding experiments described here we used zero clay content and kept the same throat size and pore size distribution and kept the same chemical composition of the ASP slug. The polymer that was used in the flooding was polyacrylamide (1560 ppm) and the surfactant was alpha olefin sulfonate (1% w/w) and the alkaline was NaOH (0.5% w/w). Along with ASP floods, two surfactant floods were run with concentrations of 1% and 0.1% (w/w). Two identical specially fabricated CIPS carbonate cemented cores were used. The silica grains of both cores are primarily silica cemented by calcite. Both cores have a permeability of 1.8 Darcy and porosity of 19.4%. The only experimental variable was then the oils type and we choose oils such that their viscosities have close values. Australian heavy crude oil (18 API) and highly refined paraffinic oil (Ondina 68) were used in the core flooding study.
Two ASP floods were run, and although all the physical parameters were kept same except oil type, the outcome was significantly different. While recovery of both the refined oil and the crude oil was the same after initial waterflood, the crude oil was mobilized more by the ASP process, through both microemulsion and banking processes. The experiment with the refined paraffinic oil produced less ultimate recovery, and only the microemulsion process was significant.
With the petroleum industry endeavouring to develop oil and gas fields in deepwater and to increase its activities in onshore arctic environments, greater emphasis should be placed on quantifying the hazards to drilling operations posed by gas hydrates. In spite of gas hydrate-bearing sediments having been drilled successfully in the past, it is important, as future drilling operations progress into deeper and ultradeep waters, to develop a sound understanding of gas hydrate-related hazards and thereby identify ahead of time when problems are likely to occur. It is also highly desirable to define the envelope of risk-free operations so that unnecessary costs and delays associated with mitigation of the problems are not incurred.
This paper describes the specific requirements to develop a comprehensive risk management capability for drilling in gas hydrate-bearing sediments. The methodology adopted concentrates on reducing risk and uncertainty associated with gas hydrates and associated shallow gas geohazards in deep water. These will be achieved by means of determining the petrophysical, mechanical and thermodynamic properties of gas hydrate-bearing sediments, and developing a fully coupled model for wellbore stability in the sediments, and methodology for drilling fluid design optimization and a risk assessment and optimization framework. Examples of laboratory measured petrophysical and mechanical properties of gas hydrate-bearing sediments, and results of time-dependent wellbore stability in such sediments are presented and discussed.