| Block Shen-84 is located in Liaohe basin in the Jinganbao oil-bearing structure belt of Damintun depression in Xinmin city,Liaoning province,northeast China.The block is an anticline faulted structure whose oil-bearing strata dips in the northwest direction with major axis 2.8km and minor axis 0.8 km within an area of 2.2 km2.Oil bearing segment S34 is of the Shahejie formation,Paleogene period（Eocene）within 1000-2800m subsurface depth with average porosity of 20.9%and average low permeability of 2.96×10-3μm2（3mD）.Reservoir depositional environment belongs to the fluvial-deltaic depositional system with relatively small sand body and complex depositional structure.There are 12 depositional environments or sedimentary micro-facies of which 10 are flood plain;lake（lacustrine mud）;flood basin-distributary channel;levee;main channel（fluvial environment）,deltaic plain（channel）;deltaic front;flood basin;crevasse splay;and mouth bar.The reservoir is heterogeneous with high variation in thickness of geological zonation framework having poor horizontal and vertical connectivity;no gas cap and bottom water but having edge water with negligible pressure support and essentially fresh formation water.Shen-84 characterised by high pour point oil（42-67℃.,average of 51℃.）with specific gravity of0.87（31.140 API）,paraffin content of 37.5%,and 16-19.3%resin and high asphaltene content.Whereas the average reservoir temperature of 67.5℃is just a few degrees above the maximum pour point temperature,albeit a dead oil value.These make exploitation difficult,marked by low recovery of 11.27%and 14.99%as at August 2008.The low recovery is attributed to the nature of the fluid with the peculiarity of controlled formation damage near wellbore of production and injection wells,and non-Newtonian fluid behaviour.Damage is because of paraffin crystallisation,precipitation and deposition due to gas expansion and evolution at production wells causing temperature decline;and cold waterflooding resulting in loss of injectivity.The primary goal of this study the cause（s）of reservoir damage as well as overflooding of most reservoirs vis-à-vis high watercut.This is with the aim of defining a robust an optimal recovery strategy,but within the possible confines of economics and technology.To achieve this goal,analytical and numerical approaches were used to define the existing problem and based on the knowledge acquired about the case study,some measures were taken to remedy the situation.Based on our findings,some recommendations were made.Because we are dealing with a high pour point crude oil,it was important to first of all,understand the influence of reservoir temperature and rock permeability on oil rheology.To achieve this,two major analyses（fluid and rock）were carried out.Fluid analysis was to define the reservoir fluid rheology while core analysis was aimed at examining the effect of temperature,oil viscosity,lithology,pressure,and wetting fluid,on oil displacement efficiency.It was shown that the transition temperature for block Shen 84-An12,below which oil fails to flow,was 61.2℃.At lower temperatures,the apparent viscosity was shear dependent,but the shear time does not affect its value.Hence,the crude can be classified as one with shear-thinning characteristics.There is a high sensitivity（73-84%）of rock permeability to acidification and the reduction in permeability could be due to re-precipitation of dissolved minerals upon encounter with air.There is also a decrease in permeability at low salinity is as a result of fine particles which collect and migrate towards the rock’s pore throat.The efficiency of water drive depended on viscosity of crude oil and formation temperature.In addition,displacement efficiency was also related to reservoir lithology.Heterogeneity,small pore radius,and high shale content are additional factors militating against efficiency of water displacement.As temperature increased,permeability saturation curve shifted to the right,the two-phase region widened and isotonic saturation point increased,the irreducible water increased while the residual oil saturation was significantly reduced.When temperature was below the wax precipitation point,permeability saturation curve shifted to the right with increased pressure gradient while binary-phase region expanded.Although temperature was the major controlling factor,high-pressure gradient may also improve the rheology of crude oil which could enhance better recovery efficiency.The remaining oil distribution has largely been influenced by not only the sedimentary micro-facies but also by the compartmentalised nature of the block,flood pattern and high pour point nature of the crude oil.The crude oil characteristics and low injection temperature affected injectivity and waterflooding.The sedimentary microfacies are the main factors affecting the distribution of remaining oil,and the injection water is controlled by the sedimentary facies.To this end,the use of steam,particularly through the steam-assisted gravity drainage was suggested as a good option for high output,based on the above analysis that indicated that temperature is the major controlling factor.We tested our results against that obtained two years earlier and discovered an offset of 11%（from 54%to 48%）in the average distribution of oil.This can be taken as a testament to the accuracy of our model given the fact that saturation is expected to decline over time.The mechanism of Asphaltene precipitation and deposition is not fully understood until now.Asphaltene deposition in the reservoir is a complex problem and it is impossible to do field experiments.Laboratory tests are expensive and time consuming.In order to study effects of Asphaltene deposition,it is necessary to rely on different models which are developed for asphaltene adsorption and deposition.The lack of information makes modelling and simulation of asphaltene deposition become difficult.No satisfactory model and simulator are available for asphaltene deposition in reservoirs during primary oil recovery.Therefore,it is necessary to obtain a better understanding of the problem and establish a better model to simulate the asphaltene precipitation and deposition in petroleum reservoirs during primary and secondary oil recovery.For such a high pour point and asphaltene and paraffin content,it became pertinent to understand the mechanism by which asphaltene deposition had occurred and what the controlling factors are.This work has investigated the asphaltene deposition mechanism and a model was defined which defines the process.This simple model that requires only the reservoir temperature.This model seems to interpret the literature very well with an accuracy of over 95%.The relationship between asphaltene deposition and other reservoir properties i.e.,pressure and depth were also investigated,both of which agreed with the fact that asphaltene deposition is a function of pressure and depth amongst other things.,as established in the literature.Significant results of the studied area include:（1）For special reservoirs such as the one under study,dealing with the high pour point of crude oil requires special approach such as optimal temperature regime needed for good oil recovery and this work has been able to achieve that.（2）Besides paraffin,the increase in water encroachment and the reduction of tubing head pressure over the period was also responsible for formation damage.This has also led to overflooding of reservoirs.（3）It is technologically more feasible to use heat control rather than injected cool（general temperature）water.（4）A reasonable comparison of HU with lithology for the highest quality HU and had higher accuracy for the lowest quality HU which corresponded to R20,pore throat radius at 20% cumulative mercury saturation.（5）History match of reservoir performance based on wells and on the entire field was 90 and 80% respectively,which is reasonable and acceptable.The cumulative oil production for block 6759 is 984,600 tons while the recovery rate is 22.53%.In block 7161,cumulative oil production is 146,600 tons at 16.52%rate of recovery.The cumulative oil production of block 6420 is 13.20 million tons,and the recovery degree is 23.81%.Finally,the accumulated oil production in block A 12 is 277,900 tons,recovering at 23.17%.（6）Remaining oil distribution was deduced to be at an average value of 48%across the four blocks concerned.This has updated previous findings and it shows that the field is still viable.（7）A simple model of asphaltene deposition and adsorption was derived for block Shean84-An12, which requires only the reservoir temperature to determine the asphaltene content.In conclusion,the nature of the reservoir crude oil has hampered the reasonable recovery of oil initially in-place as regard to the reservoir temperature and pour point temperature as evident in wax build-up prevention strategy and remediation at production wells and adverse injectivity issues with cold waterflooding.Injection rate been reduced to the subsurface temperature comfortable zone by avoiding the paraffin precipitation window had sustained production so far.However,this measure has failed overtime given the monumental increase in watercut.In order to achieve further recovery,higher heating would be required,which is not only economically unwise but also technically difficult.Asphaltene deposition model was developed with respect to reservoir temperature and this was further used to deduce the interaction between reservoir depth and pressure as the relate to asphaltene precipitation.The results indicate that there is high（12-17%）asphaltene present in the crude oil bee studied.Because of the lack of sufficient data,our findings may need to be further validated with a comprehensive experimental data as opposed to the one available from literature.As far as temperature regime is concerned,maintaining an injection rate of 163m3/day at 45℃ has proven to be sufficient for further oil recovery.This was correlated with well data and both results were in good agreement. |
