Experimental Research on the Millimeter-Scale Distribution of Oil in Heterogeneous Reservoirs

Oil saturation is a critical parameter when designing oil field development plans.This study focuses on the change of oil saturation during water flooding.Particularly,a meter-level artificial model is used to conduct relevant experiments on the basis of similarity principles and taking into account the layer geological characteristics of the reservoir.The displacement experiment’s total recovery rate is 41.35%.The changes in the remaining oil saturation at a millimeter-scale are examined using medical spiral computer tomography principles.In all experimental stages,regions exists where the oil saturation decline is more than 10.0%.The shrinkage percentage is 20.70%in the horizontal well production stage.The oil saturation reduction in other parts is less than 10.0%,and there are regions where the oil saturation increases in the conventional water flooding stage.

A well test model for stress-sensitive and heterogeneous reservoirs with non-uniform thicknesses

In view of the anisotropy,heterogeneity and stress-sensitive permeability in low permeability reservoirs,an analytical well test model was established by introducing the concept of permeability modulus.This model considered the permeability stress-sensitivity,wellbore storage effect,and the skin effect.The perturbation technique and Laplace transformation were used to solve the mathematical model analytically in Laplace space,and the bottom-hole pressure type curves were plotted and analyzed in real space by using the Stehfest numerical inversion.

Visualization of Water Plugging Displacement with Foam/Gel Flooding in Internally Heterogeneous Reservoirs

During the displacement of water plugging with binary flooding in internally heterogeneous reservoirs,it is essential to understand the distributions of remaining oil as well as the oil displacement mechanisms at different stages.In this study,two types of internally heterogeneous systems,i.e.,vertical and horizontal wells are investigated experimentally through a microscopic approach.The results show that plugging agent types have a greater impact on oil recovery than well types,and foam injection can enhance oil recovery more effectively than gel injection.Additionally,the injection sequence of plugging agents significantly affects oil displacement efficiency.Injecting gel after foam is more beneficial.According to the present results,the main formation mechanisms of remaining oil in each displacement stage are influenced by:capillary force,viscous force,inertial force,shear force,microscopic fingering&channeling.

The ternary combination of polymer gel, microsphere and surfactant for conformance control and oil displacement to improve oil recovery in strong heterogeneous reservoir

The reservoir heterogeneity of Suizhong 36-1 oilfield is very obvious,the average permeability reaches 2000mD.Long-term water injection development leads to serious water channeling in high permeability layers,resulting in ineffective circulation of injected water and reduction of oil recovery.It is urgent to form an effective EOR method.In this paper,the oil displacement effect of different combination slugs including polymer gel,polymer microsphere and surfactant is evaluated by means of conformance control and chemical flooding.Three-layer heterogeneous 3-D plate model is used for oil displacement experiment.The experimental results show that the combination slug sequentially composed of polymer gel,polymer microspheres and surfactant have the best oil displacement effect with the oil recovery increment by 21.2% after the first water flooding.In addition,using the best slug combination for two rounds flooding,the recovery factor increased by 28.2% compared with the first water flooding.This paper provides some new insights for enhanced oil recovery in strong heterogeneity reservoir.

Enhanced oil recovery mechanisms of polymer flooding in a heterogeneous oil reservoir

Taking reservoir rocks and fluids of the Daqing,Dagang and Changqing oilfields as research objects,the EOR mechanisms and technical approach of polymer flooding were discussed.By comparing the displacement performances of ordinary polymer,glycerol,polymer in"sheet-net"structure and heterogeneous weak gel at the same viscosity and concentration,the relationship between the viscosity of polymer displacement agents and displacement performance was demonstrated,and the method of improving polymer flooding effect was worked out.The main mechanism of polymer flooding to increase oil recovery is the swept volume expansion of water injection due to polymer retention in porous media.The viscosity of polymer agents has no positive correlation with polymer flooding effect.Although polymer of"sheet-net"structure has strong capacity in increasing viscosity,it has poor compatibility with pore throat structure of reservoir rock,low injectivity and low shear resistance.Heterogeneous weak gel system has higher adsorption and capture capacity in porous media,which is easy to retain in porous media,and can effectively establish seepage resistance in high permeability layers(zones).Compared with polymer solutions with the same viscosity or concentration,it has stronger ability to expand swept volume.Long term injection of polymer flooding agents will inevitably lead to fluid entry profile reversal,and thus worsening of polymer flooding effect.Alternate injection of high retention and low or non-retention displacement agents can further improve the displacement effect of polymer flooding agents.

A semi-analytical rate-transient analysis model for light oil reservoirs exhibiting reservoir heterogeneity and multiphase flow

Rate-transient analysis(RTA)has been widely applied to extract estimates of reservoir/hydraulic fracture properties.However,the majority of RTA techniques can lead to misdiagnosis of reservoir/fracture information when the reservoir exhibits reservoir heterogeneity and multiphase flow simultaneously.This work proposes a practical-yet-rigorous method to decouple the effects of reservoir heterogeneity and multiphase flow during TLF,and improve the evaluation of reservoir/fracture properties.A new,general,semi-analytical model is proposed that explicitly accounts for multiphase flow,fractalbased reservoir heterogeneity,anomalous diffusion,and pressure-dependent fluid properties.This is achieved by introducing a new Boltzmann-type transformation,the exponent of which includes reservoir heterogeneity and anomalous diffusion.In order to decouple the effects of reservoir heterogeneity and multiphase flow during TLF,the modified Boltzmann variable allows the conversion of three partial differential equations(PDE's)(i.e.,oil,gas and water diffusion equations)into ordinary differential equations(ODE's)that are easily solved using the Runge-Kutta(RK)method.A modified time-power-law plot is also proposed to estimate the reservoir and fracture properties,recognizing that the classical square-root-of-time-plot is no longer valid when various reservoir complexities are exhibited simultaneously.Using the slope of the straight line on the modified time-power-law plot,the linear flow parameter can be estimated with more confidence.Moreover,because of the new Boltzmann-type transformation,reservoir and fracture properties can be derived more efficiently without the need for defining complex pseudo-variable transformations.Using the new semi-analytical model,the effects of multiphase flow,reservoir heterogeneity and anomalous diffusion on rate-decline behavior are evaluated.For the case of approximately constant flowing pressure,multiphase flow impacts initial oil rate,which is a function of oil relative permeability and well flowing pressure.However,multiphase flow has a minor effect on the oil production decline exponent.Reservoir heterogeneity/anomalous diffusion affect both the initial oil production rate and production decline exponent.The production decline exponent constant is a function of reservoir heterogeneity/anomalous diffusion only.The practical significance of this work is the advancement of RTA techniques to allow for more complex reservoir scenarios,leading to more accurate production forecasting and better-informed capital planning.

Sedimentary Micro-facies and Macro Heterogeneity of Reservoir Beds in the Third Member of the Qingshankou Formation,Qian'an Area,Songliao Basin

An analysis of drill cores and well logs shows that the main micro-facies of the third member sand bodies of the Qingshankou Formation in Qian＇an are subaqueous distributary channel facies, sheet sand facies and subaqueous fan facies （olistostrome）. Maps showing the distribution of these micro-facies together with inter-channel bay and prodelta mocro-facies are presented for different time-slices （lower, middle and upper parts of the Qingshankou Formation）. These maps reveal the instability and change of sediment transport in the Baokang sedimentary system during the depositional period. Sediment transport was from the west in the early stage, from the south in the middle stage and from the northwest in the late stage. Values of thickness, porosity and permeability of the sand bodies in the third member of the Qingshankou Formation show that they have low to medium porosity and low permeability, and are characterized by serious reservoir heterogeneity. The joints between micro-facies and subaqueous fan micro-facies are characterized by the highest heterogeneity, the sheet sand and distal sand bar subfacies come next, and the heterogeneity of the subaqueous distributary channel sand bodies is relatively weak.

Research on reservoir bed heterogeneity,interlayers and seal layers and controlling factors of 2+3 sands of upper second member,Shahejie Formation,in the west of the Pucheng Oilfield

Terminal fans have formed the sedimentary system of the 2＋3 sands of the upper second member, Shahejie formation in the west of the Pucheng Oilfield, Bohai Bay Basin, East China. Based on well logging data and physical properties of the reservoir beds, the 2＋3 sands were divided into 16 sublayers. The heterogeneity of reservoir beds and distribution of interlayers and seal layers in the 2＋3 sands were investigated. The intra-layer heterogeneity and inter-layer heterogeneity primarily belong to the severely heterogeneous classification. The spatial differentiation of sedimentary microfacies resulted in a change of reservoir bed heterogeneity, strong in the middle and southern parts, weak in the northern part. Spatial distribution of interlayers and seal layers is dominated by sedimentary microfacies, and they are thick in north-eastern and middle parts, thin in the south-western part.

A Review of Formation Mechanism Study on Reservoirs with Tilted Oil-water Contacts

The distribution characteristics of the oil-water contact are the basis for the reservoir exploration and development and reserves evaluation. The reservoir with a tilted oil-water contact has a unique formation mechanism, and the understanding of its distribution and formation mechanism will directly affect the evaluations for the reservoir type, well deployment, selection of well pattern and type, determination of test section, and reserves evaluation. Based on the analysis of reservoir characteristics, petrophysical properties and geological structure in 40 reservoirs worldwide with tilted oil-water contacts, the progress of the research on the formation mechanisms of titled oil-water contacts is summarized in terms of the hydrodynamic conditions, reservoir heterogeneity, neotectonic movement and oil-gas exploitation. According to the formation mechanism of tilted oil-water contacts and the needs of exploration research, different aspects of research methods are summarized and classified, such as the calculation of equipotential surfaces for oil and water in the formation, analysis of formation pressure and analysis of reservoir physical properties and so on. Based upon statistical analysis, it is suggested that the degree of the inclination of the oil-water contact be divided based on the dip of oil-water contact（DipTOWC）. The tilted oil-water contact is divided into three categories： large dip（DipTOWC≥55 m/km）, medium dip（4 m/km≤DipTOWC55 m/km）, and small dip（DipTOWC4 m/km）. The classification and evaluation method can be combined with structure amplitude and reservoir property. The formation mechanism of domestic and international reservoirs with tilted oil-water contacts are summarized in this paper, which have important significance in guiding the exploration and development of the oilfield with tilted oil-water contacts, reserves evaluation, and well deployment.

Heterogeneity and influencing factors of marine gravity flow tight sandstone under abnormally high pressure:A case study from the Miocene Huangliu Formation reservoirs in LD10 area,Yinggehai Basin,South China Sea

The characteristics of reservoir heterogeneity of the marine gravity flow tight sandstone from the Miocene Huangliu Formation under abnormally high pressure setting at LD10 area in Yinggehai Basin are studied,and the influencing factors on reservoir heterogeneity are discussed,based on modular formation dynamics test,thin sections,XRD analysis of clay minerals,scanning electron microscopy,measurement of pore throat image,porosity and permeability,and high pressure Hg injection,as well as the stimulation of burial thermal history.The aim is to elucidate characteristics of the heterogeneity and the evolution process of heterogeneity of the reservoir,and predict the favorable reservoirs distribution.(1)The heterogeneity of the reservoir is mainly controlled by the cement heterogeneity,pore throat heterogeneity,quality of the reservoir heterogeneity,and the diagenesis under an abnormally high pressure setting.(2)The differences in pore-throat structure caused by diagenetic evolution affected the intergranular material heterogeneity and the pore throat heterogeneity,and finally controlled the heterogeneity of reservoir quality.(3)Compared with the reservoir under normal pressure,abnormally high pressure restrains strength of the compaction and cementation and enhances the dissolution of the reservoir to some extent,and abnormally high pressure thus weakening the heterogeneity of the reservoir to a certain degree.The favorable reservoirs are mainly distributed in the gravity flow sand body under the strong overpressure zone in the middle and lower part of Huangliu Formation.

3D geo-cellular static virtual outcrop model and its implications for reservoir petro-physical characteristics and heterogeneities

Geostatistical data plays a vibrant role for surface-based reservoir modeling through outcrop analogues,which is used to understand three-dimensional(3D)variability of petrophysical properties.The main purpose of this study is to improvise the surface-based 3D geo-modeling to demonstrate petrophysical characteristics and heterogeneities of Sandakan reservoirs,NW Borneo.We used point cloud data from Light Detection and Ranging(Li DAR)to build high-resolution virtual outcrop modeling(VOM)onto which we mapped 6 different lithofacies.Porosity and permeability of core plugs were measured to determine the average variance of petrophysical properties for each lithofacies.By utilizing the integration of VOMs analogues and petrophysical properties in Petrel^(TM),we demonstrated the distribution and associations of all lithofacies in pseudo wells that have inherent thin beds heterogeneities in 3D geocellular model.The results concluded that the heterogeneity of thin beds in lithofacies is dependent on porosity and permeability with input dataset.According to the final model,cross-bedding sandstone(CBS),hummocky cross-stratified sandstone(HCSS)and trough cross-bedding sandstone(TCBS)show good reservoir quality due to high porosity ranging from:25.6%to 20.4%and,19.3%-14.5%,and permeability ranging from:74.03 mD to 66.84 mD and,64.86 mD to 21.01 mD.In contrast,massive to weak laminae sandstone(MWLS)and bioturbated sandstone(BS)show fair to poor reservoir quality,caused baffling of surrounding mud sediments in the reservoir lithofacies.Results also revealed that Li DAR based VOM with petrophysical properties can significantly reduce the risk and minimize the cost of reservoir modeling in petroleum industry.

Implementation of a Petrographical and Petrophysical Workflow Protocol for Studying the Impact of Heterogeneity on the Rock Typing and Reservoir Quality of Reefal Limestone:A Case Study on the Nullipore Carbonates in the Gulf of Suez

This study focuses on the heterogeneity of the middle Miocene syn-rift Belayim nullipore(reefal)marine sequences in the Gulf of Suez and its impacts on reservoir quality.The sequences consist of coralline algal reef limestones with a highly complex dual-porosity system of primary and secondary porosities of widely varying percentages.To achieve a precise mathematical modeling of these reservoir sequences,a workflow protocol was applied to separate these sequences into a number of hydraulic flow units(HFUs)and reservoir rock types(RRTs).This has been achieved by conducting a conventional core analysis on the nullipore marine sequence.To illustrate the heterogeneity of the nullipore reservoir,the Dykstra-Parsons coefficient(V)has been estimated(V=0.91),indicating an extremely heterogeneous reservoir.A slight to high anisotropy(λ_(k))has been assigned for the studied nullipore sequences.A stratigraphic modified Lorenz plot(SMLP)was applied to define the optimum number of HFUs and barriers/baffles in each of the studied wells.Integrating the permeability-porosity,reservoir quality index-normalized porosity index(RQI-NPI)and the RQI-flow zone indicator(RQIFZI)plots,the discrete rock types(DRT)and the R35 techniques enable the discrimination of the reservoir sequences into 4 RRTs/HFUs.The RRT4 packstone samples are characterized by the best reservoir properties(moderate permeability anisotropy,with a good-to-fair reservoir quality index),whereas the RRT1 mudstone samples have the lowest flow and storage capacities,as well as the tightest reservoir quality.

Vertical-well-assisted SAGD dilation process in heterogeneous super-heavy oil reservoirs:Numerical simulations

PetroChina’s Karamay heavy oil reservoirs mostly comprise Jurassic deposits of braided fluvial facies that have a low porosity,extremely high bitumen viscosity,and strong heterogeneities within the reservoir.Steam-assisted gravity drainage(SAGD)dilation start-up has been proven an efficient reservoir geomechanical stimulation method as it shortens the steam circulation time,reduces steam usage,and increases the oil production rates.This method worked well on relatively good-quality oil sand reservoirs.However,for reservoirs with heterogeneous reservoir properties along the SAGD well,field well production data indicated the presence of non-uniform steam chambers in post-dilation SAGD wells.Enhanced dilation methods,such as vertical-well-assisted SAGD dilation(VW-SAGD-Dilation)are have been used,and field pilot tests have yielded promising results.This reservoir stimulation process utilizes one or more vertical wells beside the SAGD well to initiate the formation of dilation zones that connect to the dilation zone formed during the conventional SAGD dilation start-up.Compared with the normal SAGD dilation start-up,this composite dilation process creates a uniform dilation zone along the SAGD well,thus improving the thermal conformance and well productivity.The vertical well and SAGD well are connected by this composite dilation zone,which enables the combined use of the SAGD process and cyclic steam stimulation process.This paper presents our understanding and numerical case studies of this enhanced dilation strategy.The well production data from the postdilation wells were positive(uniform steam chamber growth and higher oil rate),which highlights the promising potential of using geomechanical dilation as a reservoir stimulation method to create a large stimulated reservoir volume in heterogeneous super-heavy oil reservoirs.

Numerical simulation of the impact of polymer rheology on polymer injectivity using a multilevel local grid refinement method

Polymer injectivity is an important factor for evaluating the project economics of chemical flood,which is highly related to the polymer viscosity.Because the flow rate varies rapidly near injectors and significantly changes the polymer viscosity due to the non-Newtonian rheological behavior,the polymer viscosity near the wellbore is difficult to estimate accurately with the practical gridblock size in reservoir simulation.To reduce the impact of polymer rheology upon chemical EOR simulations,we used an efficient multilevel local grid refinement（LGR）method that provides a higher resolution of the flows in the near-wellbore region.An efficient numerical scheme was proposed to accurately solve the pressure equation and concentration equations on the multilevel grid for both homogeneous and heterogeneous reservoir cases.The block list and connections of the multilevel grid are generated via an efficient and extensible algorithm.Field case simulation results indicate that the proposed LGR is consistent with the analytical injectivity model and achieves the closest results to the full grid refinement,which considerably improves the accuracy of solutions compared with the original grid.In addition,the method was validated by comparing it with the LGR module of CMG_STARS.Besides polymer injectivity calculations,the LGR method is applicable for other problems in need of near-wellbore treatment,such as fractures near wells.

A Novel Energy Lifting Approach Using J-Function and Flow Zone Indicator for Oil Fields

The X field is located in the southwestern part of block NX89 of Kentan Basin in Libya.This field is produced from Hailan multilayer consolidated sandstone with moderate rock property and a relatively low energy supplying.The reserve of subsurface energy sources is declining with years.Therefore,techniques were combined to achieve the energy optimization and increase hydrocarbon recovery.In order to understand the subsurface formation of the reservoir and facilitate oil production,global hydraulic element technique was used to quantify the reservoir rock types.In addition,stratigraphic modified Lorenz plot was used for reservoir layering.Reservoir heterogeneity was identified using stratigraphic modified Lorenz plot and Dykstra-Parsons coefficient.Leverett J-functionwas used to average the 13 capillary pressure curves into four main curves to represent the whole reservoir based on flow zone indicator values.Capillary pressure was calculated and plotted with normalized water saturation;a single average curve was defined to represent the rest of the curves.Water saturation was calculated using single and multiple J-functions and compared with the available logs.With multiple J-functions,the matching results were good for both high and low-quality layers,whereas using a single J-function,the match was poor,especially for low FZI layers such as H4c and H6a.Four rock types were identified for this reservoir ranging from medium to good reservoir quality and six different layers were obtained.The reservoir was heterogeneous with a Lorenz coefficient value of approximately 0.72 and a Dykstra-Parsons value of 0.70.All approaches used in this paper were validated and showed improved hydrocarbon recovery factor.

PRESSURE TRANSIENT ANALYSIS OF HETEROGENOUS RESERVOIRS WITH IMPERMEABILITY BARRIER USING PERTURBATION BOUNDARY ELEMENT METHOD

The transient flow mathematical model of arbitrary shaped heterogeneous reservoirs with impermeability barrier is proposed in this paper. In order to establish this model, the perturbation method is employed and the solution of model is expanded into a series in powers of perturbation parameter. By using the Boundary Element Method (BEM) and Duhamel principle, wellbore pressure with effects of skins and wellbore storage is obtained. The type curves are plotted and analyzed considering effects of heterogeneity, arbitrary shape and impermeable barriers. Finally, the results obtained by perturbation boundary element method is compared with the analytical solution and is available for the transient pressure analysis of arbitrary shaped reservoirs.

Numerical study on the effect of reservoir heterogeneity and gas supply on hydrate accumulation in subsea shallow formations

Seepage-type gas hydrate accumulation in subsea shallow formations involves complicated thermohydro-solid coupling processes and matching problem between various accumulation elements.Theformation physical properties control local natural gas migration pathway and thus the final reservoircharacteristics of hydrates.In this paper,a novel mixed-flux model for gas hydrate accumulation isestablished and then used to simulate the process of methane gas migration into the shallow stratum toform a hydrate reservoir.The effects of reservoir heterogeneity and gas source conditions on the distribution of pore fluid and hydrate accumulation are examined.The simulation results show thatreservoir heterogeneity is conducive to the retention and lateral migration of CH4 in a hydrate stabilityzone.CH4 can contact more pore water to form a large hydrate reserve,but the formed hydrate is oftendispersed.Low-permeability layers enhance the trapping of CH4 and form a uniform and large hydratesaturation.Besides,gas source conditions have an important impact on the hydrate accumulation inreservoirs.Large gas flux,small pore water flux,continuous gas supply,high content of heavy components in natural gas,and numerous gas source points contribute to large amounts of hydrates generationin a certain time period.The presented work will deepen our understanding of the controls of natural gashydrate systems in subea shallow formations.

Reconstruction and prediction of capillary pressure curve based on Particle Swarm Optimization-Back Propagation Neural Network method

Capillary pressure curve plays a critical role in the reservoir evaluation.It is essential to reconstruct and predict capillary pressure curve properly.Many traditional capillary pressure correlations have been suggested in the literature.However,their major limitation is mainly applicable to homogenous reservoir,and the larger error will be caused when heterogeneous reservoir is dealt by using these mathematical correlations.This study aims at providing an important method based on Particle Swarm Optimization-Back Propagation Neural Network(PSO-BP neural network)to represent and predict capillary pressure curve for homogenous and heterogeneous reservoir.The combination of PSO algorithm and BP neural network converges quickly,which improves the accuracy and efficiency of simulation.In this paper,core samples from three blocks of the same marine-sand reservoir,whose porosity is between 0.6%and 20.0%and permeability is between 0.1mD and 6117mD,are investigated by PSO-BP neural network method and J-Function method respectively.The reconstruction and prediction results are compared with the results obtained by mercury intrusion method in laboratory.The results show that capillary pressure curves reconstructed and predicted by PSO-BP neural network method are in better agreement with mercury intrusion curves than J-Function method,with 0.1%e5%and 5%e8%relative error respectively,which can totally meet the in-situ requirements.It is also demonstrated that PSO-BP neural network method is more suitable for homogenous and heterogeneous reservoir.©2018 Southwest Petroleum University.

Polymeric microsphere injection in large pore-size porous media

High water-cut has become a worldwide challenge for oil production.It requires extensive efforts to process and dispose.This entails expanding water handling facilities and incurring high power consumption costs.Polymeric microsphere injection is a cost-effective way to deal with excessive water production from subterranean formations.This study reports a laboratory investigation on polymeric microsphere injection in a large volume to identify its in-depth fluid diversion capacity in a porous media with large pore/particle size ratio.The performance of polymeric microsphere injection was evaluated using etched glass micromodels based on the pore network of a natural carbonate rock,which were treated as water-wet or oil-wet micromodels.Waterflooding was conducted to displace oil at reservoir temperature of 95°C,followed by one pore volume of polymeric microsphere injection.Three polymeric microsphere samples with median particle size of 0.05,0.3,and 20μm were used to investigate the impact of particle size of the polymeric microspheres on incremental oil production capacity.Although the polymeric microspheres were much smaller than the pores,additional oil production was observed.The incremental oil production increased with increasing polymeric microsphere concentration and particle size.As a comparison,polymeric microsphere solutions were injected into oil-wet and water-wet micromodels after waterflooding.It was observed that the oil production in oil-wet micromodel was much higher than that in water-wet micromodel.The wettability of micromodels affected the distribution patterns of the remaining oil after waterflooding and further dominated the performance of the microsphere injection.The study supports the applicability of microsphere injection in oil-wet heterogeneous carbonates.