Extra-low Permeability Research Articles

Monitoring and evaluating the volume fracturing effect of horizontal well

The volume fracturing technology has been the key technology to develop extra-low permeability, ultra-low permeability, and even the tight oil and gas reservoirs. Based on the real case of a volume fracturing horizontal well in Jilin Oilfield, the microseismic (MS) technology was used to monitor the effect of volume fracturing, and the MS monitoring results were analyzed. Using the data of fracturing operation and MS monitoring, a single-well numerical simulation model with stimulated reservoir volume (SRV) was built, to evaluate the volume fracturing effect of horizontal wells. The results of the study show that the MS monitoring technology can predict the fracture distribution, size, and direction of the volume fracturing horizontal well. The volume fracturing technology of horizontal well can enhance the initial oil yield of single wells and cumulative oil production. Both of the volume fracturing and CO2 miscible flooding technologies are effective methods to develop tight oil reservoirs.

Threshold pressure gradient of fluid flow through multi-porous media in low and extra-low permeability reservoirs

After analyzing many studies of fluid flow theory of multi-porous media in low and extra-low permeability reservoirs and the numerical simulation of non-Darcy flow, we found that a negative flow rate occurs in the existing non-Darcy flow equation, which is unreasonable. We believe that the existing equation can only be considered as a discriminant to judging Darcy flow or non-Darcy flow, and cannot be taken as a fluid flow governing equation of multi-porous media. Our analysis of the experimental results shows that the threshold pressure gradient (TPG) of low and extra-low permeability reservoirs is excessively high, and does not conform to fluid flow through multi-porous media in the actual reservoir situation. Therefore, we present a reasonable TPG ranging from 0.006 to 0.04 MPa/m at the well depth of 1500 m and oil drainage distance of 500 m. The results of our study also indicate that the non-Darcy flow phenomenon will disappear when the TPG reaches a certain value. In addition, the TPG or non-Darcy flow in low and extra-low permeability reservoirs does not need to be considered in the productivity prediction and reservoir numerical simulation. At present, the black oil model or dual-porous media is suitable for simulating low and extra-low permeability reservoirs.

Experimental Study of the Effect of Injection Different Kinds of Water on Extra Low Permeability Reservoir

The experiment study effect of injection different kinds of water on extra low permeability reservoir of Yushulin Oilfield. In the condition of actual temperature and pressure of the reservoir, through the experimental study the effect of injection different kinds of water on extra low permeability core. Experiments include injecting clean water, injecting clean water with scale inhibitor, injecting traditional treated sewage, injecting deep treated sewage, injecting deep treated sewage with scale inhibitor. The experimental results show that: Long term injecting clean water and clean water with scale inhibitor are harmless to core; Injecting traditional treated sewage, high content of oil and impurity bring injection pressure go up, the permeability of core down sharply; Injecting deep treated (aeration + flotation (PAC+PAM) + filtration + ultra filtration (FeCl3)) sewage must be added scale inhibitor, otherwise injection pressure continuously increase, permeability of the core continuously decrease, which seriously affect injection water.

A new approach to estimating recovery factor for extra-low permeability water-flooding sandstone reservoirs

The methods of estimating recovery factor of newly added measured reserves in existing petroleum reserves standardization of China are unsuitable for sandstone oil reservoirs of extra-low permeability with water flooding, so new empirical formula method and analogous method for estimating recovery factor of the reservoirs are studied. The key parameters influencing recovery factor are permeability, formation oil viscosity, porosity, mobility and well spacing density. Based on the requirements such as longer development time, reliable reserves and available reservoir parameters, 37 sandstone oil reservoirs of extra-low permeability were selected, and 19 recovery factor models were summarized. With consideration of high multiple regression coefficient and low standard error, 4 empirical formulae suitable for reservoir of water-flood development with vertical well were established. Comparison of calculated results from the empirical formulae and calibrated recovery factors of PetroChina recently shows that the formulae match well. It is important to choose reservoir with successful pilots and/or developed in large scale as benchmark reservoirs in the analogy estimation. Based on the principle of keeping consistent of analogous method with production performance, a practical example of Chang 8 reservoir, Triassic, FX oilfield was given to illustrate the determination of recovery factor of extra-low permeability reservoir. Empirical formula method and analogous method have their advantages and disadvantages, reserves estimators should pay great attention to the reliability of data, to application condition for empirical formula method and to the avoidance of single reservoirs in analogous method.

A Study of Influential Factors of Advance Water Injection in Extra-Low Permeability Reservoir

This paper study on the permeability, start-up pressure gradient and stress sensitivity of advance water injection in extra-low permeability reservoir in Fuyu Oil layer of Daqing Oilfield. Experimental results show that the reasonable formation pressure level should be at about 120% in the advance water injection experiment, advanced water injection in the the early stage have higher oil production, the water breakthrough, earlier than synchronous water injection has certain inhibitory effect of water cut rise; Under the premise of advance water injection can overcome the start-up pressure, the lower the level of the reservoir permeability, the higher improve recovery efficiency of the proportion; permeability retention rate increase by about 22% with 5×10-3μm2 core and effectively overcome the stress sensitivity of low permeability reservoir damage; Advanced water injection can overcome stress sensitivity and restoring formation pressure, all that influence the start-up pressure gradient, which significantly reduce the start-up pressure gradient.

Study on the Optimal Design Methodology of Fracture Spacing in Low-Permeability Reservoir Horizontal Well

Threshold pressure gradient for extra-low permeability reservoir is studied experimentally. A production model is established which couples wellbore pipe flow, fracture linear flow and reservoir non-Darcy flow. The influence of bottom-hole pressure and reservoir permeability on threshold distance is performed based on the model. A fracture spacing design method is provided for different bottom-hole pressure and reservoir permeability. Results show that threshold pressure gradient increases considerably as permeability decreases when permeability is below 0.02 mD; threshold pressure gradient is relatively lower when permeability is greater than 0.1 mD; threshold pressure gradient decreases gradually and flattens when permeability lies between 0.02 mD and 0.1 mD. Simulated threshold pressure gradient of formation water is as one-third as that of crude oil. While permeability is between 0.01-0.05 mD, 0.05-0.1 mD, 0.1-0.5 mD and 0.5-1.0 mD, the optimal fracture spacing is about 9 m, 16 m; 36 m and 50 m.

Experimental Study on CO<sub>2</sub> Displacement Program

3D and three-phase simulating module of extra-low permeability reservoirs in YSL Oilfield has been established by using PVTi module and E300 module of ECLIPSE. Based on historical matching, Parameters such as gas injection volume, slug size, gas/water ratio, the speed of gas injection and injection rate of sequent water flooding in water alternating gas were considered. The volume of increasing oil and oil-draining rate were taken as evaluation criterion. Then orthogonal test design was preceded according to the principle orthogonal experimental design. Through intuitive and variance analysis with the test results, primary and secondary orders evaluation criterion effected by injection parameters were obtained. The best combination scheme of water alternating gas injection parameters was optimized, which provides theoretical direction and technical support to water alternating gas injection parameters optimization in spot CO2displacement[1-3].

Influencing Factor Study of CO<sub>2</sub>-Assisted Gravity Drainage in Extra-Low Permeability Reservoir

CO2 flooding is an important method of enhancing oil recovery (EOR) in extra-low permeability reservoir, which can resolve the problems of water flooding effectively. The EOR theory and influencing factors of CO2-assisted gravity drainage were studied in this paper. The influencing factors, such as reservoir dip, injection volume, injecting position, well placement and reservoir effective thickness were analyzed and optimized based on the theoretical numerical model which had been established according to Tuha Niuquanhu inclined reservoir parameters. This research indicates that CO2-assisted gravity drainage can effectively EOR if appropriate parameters were adopted. The results of this paper can offer suggestions to similar reservoir development.

Impact Factors Analysis of Buildup Well Test in Low Permeability Reservoir

With low permeability reservoir into the scale of development, well test gets further attention and application. But in the field application, well test interpretation model, interpretation methods of choice still exist more problems in low permeability and extra-low permeability reservoir. In this paper, with low permeability reservoir build-up well test process, we established mathematical model of the low permeability reservoir build-up well test, and deduce the analytical solution of the mathematical model. Using the deduced theoretical formula, analyze the impact factors. The results of the study show that: well storage coefficient, inner zone permeability and outer zone permeability are sensitive factors; skin coefficient is not sensitive factors.

Versatile Fabrication of Nanocomposite Microcapsules with Controlled Shell Thickness and Low Permeability

Novel ethyl phenylacetate (EPA)-loaded nanocomposite microcapsules with polyurea (PU) /poly (melamine formaldehyde) (PMF) shells were facilely and fabricated: by using silica nanoparticle-stabilized oil-in-water (o/w) emulsion template and subsequent interfacial reaction and in situ polymerization. SiO2 nanoparticles absorbed at the interface between oil and water to stabilize the o/w emulsions. The oil droplets containing EPA, isophorone diisocyanate (IPDI) and tolylene 2,4-diisocyanate-terminated poly (propylene glycol) (PPG-TDI) were subsequently reacted with MF prepolymer (pre-MF) dissolved in water phases. The interfacial reaction between pre-MF and IPDI produced interior PU walls. Meanwhile, the in situ polymerization of pre-MF generated exterior PMF walls. It was found that these in/out double walls were compact together. The resulting capsules had spherical shapes and rough exterior surfaces, and could be easily isolated, dried, and redispersed in epoxy resins. The size of the produced microcapsules was dependent on the concentration of SiO2 nanoparticles. The dynamic thermal gravimetric analysis (TGA) demonstrated that the capsules showed excellent thermal stability with little weight loss when exposed at 150 °C for 2 h. Interestingly, with a double PU/PMF shell, these capsules exhibited an extra-low permeability. Moreover, these microcapsules can also demonstrate exceelent magnetic responsiveness after introducing magnetic nanoparticles inside. We believe our microcapsules could be potential candidates in microcapsule engineering, self-healing composites, and drug-carrying systems.

Research on Flow Units of Extra-Low Permeability Reservoirs in Fault Block Sheng554 of Shengping Oilfield

Taking the example of the fourth member of the Lower Cretaceous Quantou formation reservoirs in fault block Sheng554 of Sanzhao sag, this article discusses the methodology of flow units in extra-low permeability reservoirs. The research on flow units in such reservoirs can be divided into two ranks, one is to determine the distribution of seepage barriers and inner connected sands， the other is to analyze the differentia of fluid flow in the inner connected sands so as to subdivide the flow units. The result shows that the pelitic barriers are rather developed in fault block Sheng554. Through the analysis of differentia of fluid flow, according to the value of flow zone index (FZI), the inner connected sands can be classified into three types of flow units, among which type A with FZI value greater than 1.0 has better permeable property and higher intensity of water injection, and the ability of permeability and water injection of type B with FZI value between 0.5 and 1.0 takes the second place, and type C is the worst flow unit with the worst permeable property and intensity of water injection with FZI value less than 0.5. Among the three types of flow units, type A poorly develops, while type B and type C develops well. The research on flow units can provide reliable geologic bases for forecasting the distribution of remaining oil in extra-low permeability reservoirs and for developing remaining oil in the study area.

Research and Application of Deconvolution in Well Test Analysis of Extra-low Permeability Sandstone Reservoirs

For extra-low permeability sandstone reservoirs, traditional well test analysis techniques are always limited by wellbore storage coefficient and the low flow velocity in the porous media. Results derived using traditional well test analysis techniques are meaningless or useless. A deconvolution method based on the newly robust solution algorithms is applied for extra-low permeability sandstone reservoirs. Deconvolution codes were developed based on von Schroeter deconvolution algorithm and Levitan deconvolution algorithm. Though the study is based on synthetic cases and a field case, it is proved that the deconvolution algorithm works well in well test analysis of extra-low permeability sandstone reservoirs.

Features of Coal Pore & Fracture in Chuandong and their Relationship with Extra-Low Permeability

The comparative datas from home and abroad indicate that extra-low permeability of coal seam is the basic reason why the gas outbursts obviously demonstrate three features in Chuandong. Further analysis on the microstructure of coal pore and fracture show that, firstly，the quantity of micro pores is much more than that of macro pores; the total volume of the pores is large while the volume of interconnected pores is small. This is helpful to gas storage but going against gas flow. Secondly, fracture density varys with magnification; there are many short fractures but only a few long fractures; all of the fractures are similar in width and in the form of zigzag; the directivity of fracture extension is irregular. Thirdly, fracture fillings are mainly hard inorganic matters. It is put forward that both pressure sensitive effect and water sensitivity effect exist in the coal seam and they are "double-edged swords" to permeability. In order to increase the permeability, it is necessary to change passive exhausting into active driving, remove gas reservoir and provide the passageway for gas dissipation.

Characteristics of carbonate cementation in clastic rocks from the Chang 6 sandbody of Yanchang Formation, southern Ordos Basin

Densification of reservoir is an important factor that restricts oil and gas exploration from low porosity and extra-low permeability reservoirs. Carbonate cementation was heavily developed in Chang 6 sandbody, a facies of underwater distributary channel in delta front, of Upper Triassic Yanchang Formation in Fuxian area, southern Ordos Basin, and the cementation is one of the major factors that affect quality of reservoir. Based on the macro-microcosmic petrology and geochemistry features, the genesis of densification of carbonate-cemented reservoir was systematically discussed. The carbonate cementation can be classified into endogenous and exogenous, and the essential differences between them are that they were formed in different fluids and in different diagenesis periods. With the aid of identification of thin sections, analyses on electron probe, trace and rare-earth elements, carbon and oxygen isotope, we propose that the endogenous fluid for cementation came from the rock itself during early diagenetic stage. The minerals related to endogenous fluid had good shapes. The reservoir property was enhanced with porosity increasing by 3%–8% because of later dissolution by endogenous fluid. The exogenous fluid might be water combining with CO2, likely released from organic matter-rich mudstone. Calcite cement, in form of substrate cementation, was precipitated from the fluid and filled in the remaining pores of sandstones in late diagenetic stage as variations of physical and chemical conditions. The exogenous cement reduced rock porosity, damaged reservoir property, affected some oil enrichment, and seriously caused Chang 6 reservoir densification. Some of the dense layers that formed on top of sandbody could have served as diagenetic traps, and thus the exogenous cementation area could be favorable for oil exploration.

Characteristics and causes of Mesozoic reservoirs with extra-low permeability and high water cut in northern Shaanxi

Abstract Considering actual oil field development and based on comprehensive analysis on the oil production and oil test data, this paper summarizes the characteristics of the Chang 6 reservoir of extra-low permeability and high water cut in the Weijialou Oilfield in northern Shaanxi and the distribution rule of high water cut zones. The results show that the Chang 6 reservoir in the Weijialou Oilfield is a typical reservoir of extra-low permeability and high water cut, its water cut contour shows irregular annular distribution around local structure highs in plane. The water cut distribution within the reservoir shows high heterogeneity; along the NE-SW direction, water cut change is relatively stable, water cut contour extending in band shape; along the NW-SE direction, water cut fluctuates greatly, contours showing an alternating distribution of high and low water cut zones; there exists high water cut zone out-thrusting locally. Lack of effective hydrocarbon source rocks and poor resource conditions are the underlying causes of high water cut in the Chang 6 extra-low permeability reservoir. High crude oil viscosity, great difference of fluid properties, high fluidity ratio, and well developed natural fractures are the main internal cause of the high water cut.

Quantitative Evaluation of Micro Pore Throat Characteristics in Extra Low Permeability Sandstone Oil Reservoir of Yanchang Group in Ordos Basin Using Constant Rate Mercury Penetration Technique

Micro pore throat characteristics of extra low permeability sandstone oil reservoir of Yangchang group in Ordos basin are analyzed using constant rate mercury penetration technique. The results show that pore radius distributes similarly, in 100～200μm, peak values are about 140μm in extra low permeability sandstone oil reservoir. The lower the permeability is, the narrower the distribution ranges of throat are, content of smaller throats become high and variation is more sensitive to permeability, distribution ranges of pore throat radius ratio are wide and permeability has bigger influence on input mercury saturation of throat in extra low permeability sandstone oil reservoir. The difference of pore throat characteristics mainly depends on throat in extra low permeability sandstone oil reservoir. The impacts of pore and throat on total capillary curve are various to different permeability cores, Throat development should be paid more attention in middle or later stage of oil development to extra low permeability sandstone oil reservoir.

Physical simulation of fluid flow and production performance in extra-low permeability porous media

For extra-low permeability reservoirs, with a permeability of about 0.3×10−3 µm2, fluid flow and production performance in cores were studied. A long core holder with a multi-location piezometric measurement was specially designed. An artificial long core, about 700 mm long and with a cross section of 45mm×45mm, was used. In the experiment, pressure distribution along the core can be measured in real time. Single phase flow in the core was investigated. Different modes of production in long cores were also simulated including natural depletion, water flooding, and advanced water flooding. Through physical simulation, flow parameters were collected and production characteristics in extra-low permeability cores were studied. From experimental results, it can be seen that fluid flow in extra-low permeability cores is different from that in high permeability cores. Transmission of pressure in extra-low permeability cores is very slow, and it needs a long time for the pressure to become stable. The distribution curve of pressure along the core is nonlinear and the production rate in extra-low permeability reservoirs decreases sharply. The development effects of different production modes in extra-low permeability cores were compared with one another. Among the production modes, advanced water flooding has much potential for effective development of extra-low permeability reservoirs. Natural depletion and conventional water flooding can also be used in early production periods. In addition, the countermeasures and some ideas especially for the potential development of extra-low permeability reservoirs are suggested.

Origin Analysis of Extra Low-Permeability and Evaluation for Example Reservoir in the Yan25 Area of Ansai Oil Field

The origin of extra low-permeability and influential factors of Chang6 reservoir in the Yan25 area of Ansai Oil Field are studied synthetically through using the log information,testing and analytical information such as Casting section,scanning electron microscope,X diffraction,grain size analysis and mercury penetration et al.and then,the reservoir is evaluated.The results show that accumulation properties are worse,the reservoir mainly develops intergranular pore and emposieu,and pore structure types are fine pore and microscopic throat.Sedimentation and diagenesis have impacted on the origins of extra low-permeability together,such as accumulation properties are various in the different Sedimentary microfacies.The great content of low-energy component,fine grade and the low compositional maturity are the main reasons that cause the extra low-permeability.Compaction and cementation have decreased the porosity,then the permeability have become worse.However,denudation and fractures have improved the extra low-permeability characteristics to some great extent.According to the analysis of properties and pore structure parameters,the reservoir is classified into 3 classes,subsea river channel and mouth bar sand body are the main distributed facies belt of the reservoir.

The Relationship between Fractures and Tectonic Stress Field in the Extra Low-Permeability Sandstone Reservoir at the South of Western Sichuan Depression

The formation and distribution of fractures are controlled by paleotectonic stress field, and their preservative status and effects on development are dominated by the modern stress field. Since Triassic, it has experienced four tectonic movements and developed four sets of tectonic fractures in the extra low-permeability sandstone reservoir at the south of western Sichuan depression. The strikes of fractures are in the S-N, NE-SW, E-W, and NW-SE directions respectively. At the end of Triassic, under the horizontal compression tectonic stress field, for which the maximum principal stress direction was NW-SE, the fractures were well developed near the S-N faults and at the end of NE-SW faults, because of their stress concentration. At the end of Cretaceous, in the horizontal compression stress fields of the NE-SW direction, the stress was obviously lower near the NE-SW faults, thus, fractures mainly developed near the S-N faults. At the end of Neogene-Early Pleistocene, under the horizontal compression tectonic stress fields of E-W direction, stress concentrated near the NE-SW faults and fractures developed at these places, especially at the end of the NE-SE faults, the cross positions of NE-SW, and S-N faults. Therefore, fractures developed mostly near S-N faults and NE-SW faults. At the cross positions of the above two sets of faults, the degree of development of the fractures was the highest. Under the modern stress field of the NW-SE direction, the NW-SE fractures were mainly the seepage ones with tensional state, the best connectivity, the widest aperture, the highest permeability, and the minimum opening pressure.