Changes in filtration and capacitance properties of highly porous reservoir in underground gas storage:CT-based and geomechanical modeling

The paper presents the results of comprehensive studies of filtration and capacitance properties of highly porous reservoir rocks of the aquifer of an underground gas storage facility.The geomechanical part of the research included studying the dependence of rock permeability on the stress-strain state in the vicinity of the wells,and physical modeling of the implementation of the method of increasing the permeability of the wellbore zone-the method of directional unloading of the reservoir.The digital part of the research included computed tomography(CT)-based computer analysis of the internal structure,pore space characteristics,and filtration properties before and after the tests.According to the results of physical modeling of deformation and filtration processes,it is found that the permeability of rocks before fracture depends on the stress-strain state insignificantly,and this influence is reversible.However,when downhole pressure reaches 7-8 MPa,macrocracks in the rock begin to grow,accompanied by irreversible permeability increase.Porosity,geodesic tortuosity and permeability values were obtained based on digital studies and numerical modeling.A weak degree of transversal anisotropy of the filtration properties of rocks was detected.Based on the analysis of pore size distribution,pressure field and flow velocities,high homogeneity and connectivity of the rock pore space is shown.The absence of pronounced changes in pore space characteristics and pore permeability after non-uniform triaxial loading rocks was shown.On the basis of geometrical analysis of pore space,the reasons for weak permeability anisotropy were identified.The filtration-capacitance properties obtained from the digital analysis showed very good agreement with the results of field and laboratory measurements.The physical modeling has confirmed the efficiency of application of the directional unloading method for the reservoir under study.The necessary parameters of its application were calculated:bottomhole geometry,stage of operation,stresses and pressure drawdown value.

Response of coal reservoir porosity to magma intrusion in the Shandong Qiwu Mine,China

The Qiwu Mine is located in the Ten Xian coal field of Shandong province.It experienced repeated volcanic activity,after the coal beds formed,where magma intrusion was significant The effect of coal reservoir porosity after magma intrusion was studied by analysis of regional and mine structure and magmatic activity.Experimental methods including maceral measurement under the microscope and mercury porosimetry were used for testing the pore structure.The authors believe that magma intrusion into low-rank bituminous coal causes reservoir porosity to gradually increase：the closer to the magmatic rock a sample is,the less the porosity.The pore size distribution also changes.In the natural coal bed the pore size is mainly in the transitive and middle pore range.However,the coal changes to anthracite next to the magmatic rock and larger pores dominate.Regional magma thermal evolution caused coal close to magmatic rock to be roasted,which reduced the volatile matter,developed larger holes,and destroyed plant tissue holes.The primary reason for a porosity decrease in the vicinity of magmatic rock is that Bituminite resulting from the roasting fills the holes that were present initially.

The coupling of dynamics and permeability in the hydrocarbon accumulation period controls the oil-bearing potential of low permeability reservoirs:a case study of the low permeability turbidite reservoirs in the middle part of the third member of Shahejie

The relationships between permeability and dynamics in hydrocarbon accumulation determine oil- bearing potential （the potential oil charge） of low perme- ability reservoirs. The evolution of porosity and permeability of low permeability turbidite reservoirs of the middle part of the third member of the Shahejie Formation in the Dongying Sag has been investigated by detailed core descriptions, thin section analyses, fluid inclusion analyses, carbon and oxygen isotope analyses, mercury injection, porosity and permeability testing, and basin modeling. The cutoff values for the permeability of the reservoirs in the accumulation period were calculated after detailing the accumulation dynamics and reservoir pore structures, then the distribution pattern of the oil-bearing potential of reservoirs controlled by the matching relationship between dynamics and permeability during the accumulation period were summarized. On the basis of the observed diagenetic features and with regard to the paragenetic sequences, the reservoirs can be subdivided into four types of diagenetic facies. The reservoirs experienced two periods of hydro- carbon accumulation. In the early accumulation period, the reservoirs except for diagenetic facies A had middle to high permeability ranging from 10 × 10-3 gm2 to 4207 × 10-3 lain2. In the later accumulation period, the reservoirs except for diagenetic facies C had low permeability ranging from 0.015 × 10-3 gm2 to 62× 10-3 -3m2. In the early accumulation period, the fluid pressure increased by the hydrocarbon generation was 1.4-11.3 MPa with an average value of 5.1 MPa, and a surplus pressure of 1.8-12.6 MPa with an average value of 6.3 MPa. In the later accumulation period, the fluid pressure increased by the hydrocarbon generation process was 0.7-12.7 MPa with an average value of 5.36 MPa and a surplus pressure of 1.3-16.2 MPa with an average value of 6.5 MPa. Even though different types of reservoirs exist, all can form hydrocarbon accumulations in the early accumulation per- iod. Such types of reservoirs can form hydrocarbon accumulation with high accumulation dynamics; however, reservoirs with diagenetic facies A and diagenetic facies B do not develop accumulation conditions with low accumu- lation dynamics in the late accumulation period for very low permeability. At more than 3000 m burial depth, a larger proportion of turbidite reservoirs are oil charged due to the proximity to the source rock, Also at these depths, lenticular sand bodies can accumulate hydrocarbons. At shallower depths, only the reservoirs with oil-source fault development can accumulate hydrocarbons. For flat surfaces, hydrocarbons have always been accumulated in the reservoirs around the oil-source faults and areas near the center of subsags with high accumulation dynamics.

Influence of strong preformed particle gels on low permeable formations in mature reservoirs

In mature reservoirs,the success of preformed particle gel（PPG） treatment rests primarily on the ability of the PPG to reduce and/or plug the high permeable formations,but not damage the low permeable formations.Static test models（filtration test model and pressure test model）were used to determine the effect of PPG on low permeable formations.This work used a strong preformed particle gel,Daqing（DQ） gel made by a Chinese company.The particle gel sizes were ranged from 30 to 120 mesh for this work.PPGs are sized in a millimeter or micrometer,which can absorb over a hundred times their weight in liquids.The gel strength was approximately 6500 Pa for a completely swollen PPG with 1 %（weight percentage） NaCl solution（brine）.0.05 %,1 %,and 10 % NaCl solutions were used in experiments.Sandstone core permeability was measured before and after PPG treatments.The relationship between cumulative filtration volumes versus filtration times was determined.The results indicate that DQ gels of a particle size of 30–80 mesh did not damage the cores of a low permeability of 3–25 m D.The DQ gels of a smaller particle size ranging from 100 to 120 mesh damaged the core and a cake was formed on the core surface.The results also indicate that more damage occurred when a high load pressure（400 psi） was applied on the high permeability cores（290–310 m D）.The penetration of the particle gelsinto the low permeable formations can be decreased by the best selection of gel types,particle sizes,and brine concentrations.

An experimental study of fracture initiation mechanisms during hydraulic fracturing

The mechanism of fracture initiation is the basic issue for hydraulic fracture technology. Because of the huge differences in fracture initiation mechanisms for different reservoirs,some successful fracturing techniques applied to porosity reservoirs are ineffectual for fractured reservoirs.Laboratory tests using a process simulation device were performed to confirm the characteristics of fracture initiation and propagation in different reservoirs.The influences of crustal stress field,confining pressure,and natural fractures on the fracture initiation and propagation are discussed.Experimental results demonstrate that stress concentration around the hole would significantly increase the fracture pressure of the rock.At the same time,natural fractures in the borehole wall would eliminate the stress concentration,which leads to a decrease in the fracture initiation pressure.

A numerical approach for pressure transient analysis of a vertical well with complex fractures

A new well test model for a vertical fractured well is developed based on a discrete-fracture model in which the fractures are discretized as one dimensional（1-D） entities.The model overcomes the weakness of complex meshing,a large number of grids, and instability in conventional stripe-fracture models. Then, the discrete-fracture model is implemented using a hybrid element finite-element method.Triangular elements are used for matrix and line elements for the fractures. The finite element formulation is validated by comparing with the semi-analytical solution of a single vertical fractured well. The accuracy of the approach is shown through several examples with different fracture apertures,fracture conductivity, and fracture amount. Results from the discrete-fracture model agree reasonably well with the stripefracture model and the analytic solutions. The advantages of the discrete-fracture model are presented in mesh generation, computational improvement, and abilities to handle complex fractures like wedge-shaped fractures and fractures with branches. Analytical results show that the number of grids in the discrete-fracture model is 10 % less than stripefracture model, and computational efficiency increases by about 50 %. The more fractures there are, the more the computational efficiency increases.

Genetic mechanisms of secondary pore development zones of Es_4~x in the north zone of the Minfeng Sag in the Dongying Depression,East China

The genetic mechanisms of the secondary pore development zones in the lower part of the fourth member of the Shahejie Formation（Es_4／6x） were studied based on core observations,petrographic analysis,fluid inclusion analysis,and petrophysical measurements along with knowledge of the tectonic evolution history,organic matter thermal evolution,and hydrocarbon accumulation history.Two secondary pore development zones exist in Es_4~x,the depths of which range from 4200 to 4500 m and from 4700 to 4900 m,respectively.The reservoirs in these zones mainly consist of conglomerate in the middle fan braided channels of nearshore subaqueous fans,and the secondary pores in these reservoirs primarily originated from the dissolution of feldspars and carbonate cements.The reservoirs experienced ‘‘alkaline–acidic–alkaline–acidic–weak acidic＇＇,‘‘normal pressure–overpressure–normal pressure＇＇,and‘‘formation temperature increasing–decreasing–increasing＇＇ diagenetic environments.The diagenetic evolution sequences were ‘‘compaction/gypsum cementation/halite cementation/pyrite cementation/siderite cementation–feldspar dissolution/quartz overgrowth–carbonate cementation/quartz dissolution/feldspar overgrowth–carbonate dissolution/feldspar dissolution/quartz overgrowth–pyrite cementation and asphalt filling＇＇.Many secondary pores（fewer than the number of primary pores） were formed by feldspar dissolution during early acidic geochemical systems with organic acid when the burial depth of the reservoirs was relatively shallow.Subsequently,the pore spaces wereslightly changed because of protection from early hydrocarbon charging and fluid overpressure during deep burial.Finally,the present secondary pore development zones were formed when many primary pores were filled by asphalt and pyrite from oil cracking in deeply buried paleoreservoirs.

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.

Research on seismic fluid identification driven by rock physics

Seismic fluid identification works as an effective approach to characterize the fluid feature and distribution of the reservoir underground with seismic data. Rock physics which builds bridge between the elastic parameters and reservoir parameters sets the foundation of seismic fluid identification, which is also a hot topic on the study of quantitative characterization of oil/gas reservoirs. Study on seismic fluid identification driven by rock physics has proved to be rewarding in recognizing the fluid feature and distributed regularity of the oil/gas reservoirs. This paper summarizes the key scientific problems immersed in seismic fluid identification, and emphatically reviews the main progress of seismic fluid identification driven by rock physics domestic and overseas, as well as discusses the opportunities, challenges and future research direction related to seismic fluid identification. Theoretical study and practical application indicate that we should incorporate rock physics, numerical simulation, seismic data processing and seismic inversion together to enhance the precision of seismic fluid identification.