China Offshore oilfield is rich in heavy oil, M oilfield in Bohai Bay is themost thick heavy oil field in offshore by far with the formation oil viscosityas high as 450 ~ 950mPa.s. Using conventional oil field development (depletionand water flooding), the heavy oil field exposed its limits, such as lowproductivity of single well, low production rate and low predictedrecovery. As we all know, the development effect of thermal recovery is not only relatedwith the thermal recovery methods (steam stimulation, steam flooding, etc.), but also related with the thermal medium (steam, hot water, flue gas etc.). Anew thermal media called multi-thermal fluid, which contains steam, hot waterand flue gas was researched for horizontal well stimulation, which is to injectN2 and CO2 at the same time when injecting steam. This multi-thermal fluidcould employ various mechanisms of each fluid, including reducing oil viscosityby heating and dissolving gas, increasing pressure by injecting gas, expandingheating range, reducing heat loss and gas assisting gravity drive etc. With theadvantages of single thermal injection, this method made up the disadvantagesof single thermal fluid injection and can improve steam stimulation effect insome special formation conditions. In this article, the author first analyzed the characterization ofmulti-thermal fluid, and then researched its stimulation theory. Based on thistheory, the single element of geological data, such as dip angle, permeability, rock compression coefficient, formation thickness, oil viscosity, and injectiondata, such as injection volume, gas-water-ratio and CO2 concentration wasanalyzed using numerical simulation software. Based on this result, selectingdata that make more contribution in incremental oil, production rate, and EORto make sensitivity study to summarize formation that multi-thermal fluid couldbe applied.
In order to test the effectiveness and efficiency of nano-microspheres which can be used to effectively reduce water cut with a small slug size, a series of experimental tests have been conducted to evaluate the performance of nano-microspheres and factors affecting the performance. Those tests include hydration swelling characteristics, blocking and migration characteristics, salt resistance, shear resistance and so on. Based on the experimental study, detailed pilot test design were conducted by considering the different reservoir pore structures and microsphere sizes used for oil displacement, so that the slug size is minimized while the net revenue is maximized. Since 2009, deep profile control technology by injecting small slug-size nano-microsphere has been developed in offshore oilfields in Bohai Sea. The main mechanism of nano-microsphere is different from the traditional approaches which increase the water phase viscosity to improve mobility ratio. In nano-microsphere deep profile control technology, nano/micron level microspheres were dispersed in the water phase. Along with the water injected into formation, microspheres swell under the formation condition, plug the water channels, reduce the permeability of high permeable zone, dynamically change the water flow paths, thus increase the water sweeping efficiency. Since 2009, a total of 17 well patterns have implemented in QHD, BZ28, BZ29 oilfields in Bohai Sea. In all those tests, small slug sizes in the range from 0.01 to 0.02 PV were used. Water cut is reduced from 80% to 70% and cumulative oil production was increased by 13.1×106m3. The economic evaluation suggests that for every one dollar investment on this technology, 3.1 dollar can be made even when the oil price is $30 per barrel. So the project has a good technical and economic outcome even in extreme low oil prices.
More than 80% oil resources were heavy oil in Bohai Bay of China. Generally, we used water flooding in the reservoirs with the viscosity less than 400cp. But there were many challenges during water injection in conventional heavy oil reservoirs because high oil-water viscosity ratio lead quick breakthrough of injecting water. And with the oil-water viscosity ratio increasing, the breakthrough of injecting water became more serious. In order to solve these problems, the gel treatments on the injection wells pilot test were conducted in x oilfield during the year 2009 to 2011. Before pilot test, laboratory study under field conditions was conducted to determine the chemical parameters of the gel. We also did numerical simulation study with CMG. A range of variation of critical parameters was evaluated in the simulation for understanding the gelation process undergroud. The model was used to predict the reservoir response under different chemical parameters. Results from simulation showed that water cut reduction ranged from 15.9 to 36.6% which matched the trends observed in wells. On the other hand, dynamic method was also used to evaluate the gel pilot test. The Hall curve analysis was used to evaluate the effectiveness of the injection well and to calculate the resistance factor (RF) & residual resistance factor (RRF) (RF from 1.82 to 6.88, and RRF from 1.29 to 7.97). The decline curve analysis was used to obtain net incremental oil by gel injection treatment. Results from two well patterns conducted gel pilot test in 2009 indicated that water cut reduction ranged from 3.2 to 36.8% and average oil production increases 15.7m3/d. Based on results, another two wells in 2010 and two wells in 2011 were conducted, and we received good effectiveness by gel treatments. The pilot test & evaluation technology provide the foundation for promoting application of techniques to stabilize oil rate and control water production in conventional heavy oil reservoirs of China offshore oilfield
a b s t r a c tAiming at the large error in productivity predication and incomplete consideration in completion parameters design of perforated horizontal well, a model which coupled the relationship of pressure and flow rate in reservoir seepage, near-wellbore inflow and wellbore flow was established. The impact of near-wellbore heterogeneity, wellbore flow pressure drop and completion parameters on the inflow profile of horizontal well is analysed. Studies showed that with a stronger near-wellbore heterogeneity, the inflow profile would fluctuate more seriously. Perforation density had a great influence on the inflow profile and local changes of it would bring a shunt effect. Completion design of variable density perforated horizontal well with an optimized inflow profile which was close to a standard profile would improve the horizontal well development effect. The achievement can provide directive meanings to productivity predication and completion parameters design of horizontal wells in oilfield.
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