Impacts of proppant distribution on development of tight oil reservoirs with threshold pressure gradient

Field evidence indicates that proppant distribution and threshold pressure gradient have great impacts on well productivity.Aiming at the development of unconventional oil reservoirs in Triassic Chang-7 Unit,Ordos Basin of China,we presented an integrated workflow to investigate how(1)proppant placement in induced fracture and(2)non-linear flow in reservoir matrix would affect well productivity and fluid flow in the reservoir.Compared with our research before(Yue et al.,2020),here we extended this study into the development of multi-stage fractured horizontal wells(MFHWs)with large-scale complicated fracture geometry.The integrated workflow is based on the finite element method and consists of simulation models for proppant-laden fluid flow,fracture flow,and non-linear seepage flow,respectively.Simulation results indicate that the distribution of proppant inside the induced cracks significantly affects the productivity of the MFHW.When we assign an idealized proppant distribution instead of the real distribution,there will be an overestimation of 44.98%in daily oil rate and 30.63%in cumulative oil production after continuous development of 1000 days.Besides,threshold pressure gradient(TPG)also significantly affects the well performance in tight oil reservoirs.If we simply apply linear Darcy’s law to the reservoir matrix,the overall cumulative oil production can be overrated by 77%after 1000 days of development.In general,this research provides new insights into the development of tight oil reservoirs with TPG and meanwhile reveals the significance of proppant distribution and non-linear fluid flow in the production scenario design.

The effects of various factors on spontaneous imbibition in tight oil reservoirs

Slickwater fracturing fluids have gained widespread application in the development of tight oil reservoirs. After the fracturing process, the active components present in slickwater can directly induce spontaneous imbibition within the reservoir. Several variables influence the eventual recovery rate within this procedure, including slickwater composition, formation temperature, degree of reservoir fracture development, and the reservoir characteristics. Nonetheless, the underlying mechanisms governing these influences remain relatively understudied. In this investigation, using the Chang-7 block of the Changqing Oilfield as the study site, we employ EM-30 slickwater fracturing fluid to explore the effects of the drag-reducing agent concentration, imbibition temperature, core permeability, and core fracture development on spontaneous imbibition. An elevated drag-reducing agent concentration is observed to diminish the degree of medium and small pore utilization. Furthermore, higher temperatures and an augmented permeability enhance the fluid flow properties, thereby contributing to an increased utilization rate across all pore sizes. Reduced fracture development results in a lower fluid utilization across diverse pore types. This study deepens our understanding of the pivotal factors affecting spontaneous imbibition in tight reservoirs following fracturing. The findings act as theoretical, technical, and scientific foundations for optimizing fracturing strategies in tight oil reservoir transformations.

Study on the Impact of Massive Refracturing on the Fracture Network in Tight Oil Reservoir Horizontal Wells

Class III tight oil reservoirs have low porosity and permeability,which are often responsible for low production rates and limited recovery.Extensive repeated fracturing is a well-known technique to fix some of these issues.With such methods,existing fractures are refractured,and/or new fractures are created to facilitate communication with natural fractures.This study explored how different refracturing methods affect horizontal well fracture networks,with a special focus on morphology and related fluid flow changes.In particular,the study relied on the unconventional fracture model(UFM).The evolution of fracture morphology and flow field after the initial fracturing were analyzed accordingly.The simulation results indicated that increased formation energy and reduced reservoir stress differences can promote fracture expansion.It was shown that the length of the fracture network,the width of the fracture network,and the complexity of the fracture can be improved,the oil drainage area can be increased,the distance of oil and gas seepage can be reduced,and the production of a single well can be significantly increased.

An Integrated Optimization Method for CO_(2) Pre-Injection during Hydraulic Fracturing in Heavy Oil Reservoirs

CO_(2) pre-injection during hydraulic fracturing is an important method for the development of medium to deep heavy oil reservoirs.It reduces the interfacial tension and viscosity of crude oil,enhances its flowability,maintains reservoir pressure,and increases reservoir drainage capacity.Taking the Badaowan Formation as an example,in this study a detailed three-dimensional geomechanical model based on static data from well logging interpretations is elaborated,which can take into account both vertical and horizontal geological variations and mechanical characteristics.A comprehensive analysis of the impact of key construction parameters on Pre-CO_(2) based fracturing(such as cluster spacing and injection volume),is therefore conducted.Thereafter,using optimized construction parameters,a non-structured grid for dynamic development prediction is introduced,and the capacity variations of different production scenarios are assessed.On the basis of the simulation results,reasonable fracturing parameters are finally determined,including cluster spacing,fracturing fluid volume,proppant concentration,and well spacing.

Optimization of operational strategies for rich gas enhanced oil recovery based on a pilot test in the Bakken tight oil reservoir

Horizontal well drilling and multistage hydraulic fracturing have been demonstrated as effective approaches for stimulating oil production in the Bakken tight oil reservoir.However,after multiple years of production,primary oil recovery in the Bakken is generally less than 10%of the estimated original oil in place.Gas huff‘n’puff(HnP)has been tested in the Bakken Formation as an enhanced oil recovery(EOR)method;however,most field pilot test results showed no significant incremental oil production.One of the factors affecting HnP EOR performance is premature gas breakthrough,which is one of the most critical issues observed in the field because of the presence of interwell fractures.Consequently,injected gas rapidly reaches adjacent production wells without contacting reservoir rock and increasing oil recovery.Proper conformance control is therefore needed to avoid early gas breakthrough and improve EOR performance.In this study,a rich gas EOR pilot in the Bakken was carefully analyzed to collect the essential reservoir and operational data.A simulation model with 16 wells was then developed to reproduce the production history and predict the EOR performance with and without conformance control.EOR operational strategies,including single-and multiple-well HnP,with different gas injection constraints were investigated.The simulation results of single-well HnP without conformance control showed that a rich gas injection rate of at least 10 MMscfd was needed to yield meaningful incremental oil production.The strategy of conformance control via water injection could significantly improve oil production in the HnP well,but injecting an excessive amount of water also leads to water breakthrough and loss of oil production in the offset wells.By analyzing the production performance of the wells individually,the arrangement of wells was optimized for multiple-well HnP EOR.The multiwell results showed that rich gas EOR could improve oil production up to 7.4%by employing conformance control strategies.Furthermore,replacing rich gas with propane as the injection gas could result in 14%of incremental oil production.

Temporal variations in geochemistry of hydraulic fracturing fluid and flowback water in a tight oil reservoir

Hydraulic fracturing facilitates the development and exploitation of unconventional reservoirs.In this study,the injected hydraulic fracturing fluid(HFF)and flowback and produced water(FPW)in tight oil reservoirs of the Lucaogou Formation in the Junggar Basin are temporally sampled from day 1 to day 64.Freshwater is used for fracturing,and HFF is obtained.The chemical and isotopic parameters(including the water type,total salinity,total dissolved solids(TDS),pH,concentrations of Na^(+),Cl^(-),Ba^(+),K^(+),Fe^(2+)+Fe^(3+),and CO_(3)^(2-),dD,and δ^(18)O)are experimentally obtained,and their variations with time are systematically analyzed based on the flowback water.The results show that the water type,Na/Cl ratio,total salinity,and TDS of the FPW change periodically primarily due to the HFF mixing with formation water,thus causing δD and δ^(18)O to deviate from the meteoric water line of Xinjiang.Because of watererock interaction(WRI),the concentrations of Fe^(2+)+Fe^(3+)and CO_(3)^(2-)of the FPW increase over time,with the solution pH becoming more alkaline.Furthermore,based on the significant changes observed in the geochemistry of the FPW,three separate time intervals of flowback time are identified:Stage Ⅰ(<10 days),where the FPW is dominated by the HFF and the changes in ions and isotopes are mainly caused by the WRI;Stage Ⅱ(10-37 days),where the FPW is dominated by the addition of formation water to the HFF and the WRI is weakened;and finally,Stage Ⅲ(>37 days),where the FPW is dominated by the chemistry of the formation water.The methodology implemented in this study can provide critical support for the source identification of formation water.

Geochemical studies of the Silurian oil reservoir in the Well Shun-9 prospect area, Tarim Basin, NW China

Commercial oil flow has been obtained from the sandstone reservoir of the Lower Silurian Kelpintag Formation in the Well Shun-9 prospect area.In the present studies,10 Silurian oil and oil sand samples from six wells in the area were analyzed for their molecular and carbon isotopic compositions,oil alteration（biodegradation）,oil source rock correlation and oil reservoir filling direction.All the Silurian oils and oil sands are characterized by low Pr/Ph and C21/C23 tricyclic terpane（〈1.0） ratios,＂V＂-pattern C27-C29 steranes distribution,low C28-sterane and triaromatic dinosterane abundances and light δ13C values,which can be correlated well with the carbonate source rock of the O3 l Lianglitage Formation.Different oil biodegradation levels have also been confirmed for the different oils/oil sands intervals.With the S1k2 seal,oils and oil sands from the S1k1 interval of the Kelpintag Formation have only suffered light biodegradation as confirmed by the presence of ＂UCM＂ and absence of 25-norhopanes,whereas the S1k3-1 oil sands were heavily biodegraded（proved by the presence of 25-norhopanes） due to the lack of the S1k2 seal,which suggests a significant role of the S1k2 seal in the protection of the Silurian oil reservoir.Based on the Ts/（Ts＋Tm） and 4-/1-MDBT ratios as reservoir filling tracers,a general oil filling direction from NW to SE has been also estimated for the Silurian oil reservoir in the Well Shun-9 prospect area.

Necessity and feasibility of improving the residual resistance factor of polymer flooding in heavy oil reservoirs

The efficiency of water flooding in heavy oil reservoirs would be improved by increasing the viscosity of the displacing phase, but the sweep efficiency is not of significance due to the low mobility of the vicious oil. On the basis of mobility control theory, increasing the residual resistance factor not only reduces the water-oil mobility ratio but also decreases the requirement for viscosity enhancement of the polymer solution. The residual resistance factor caused by hydrophobic associating polymer solution is higher than that caused by polyacrylamide solution in brine containing high concentrations of calcium and magnesium ions. The results of numerical simulations show that the polymer flooding efficiency improved by increasing the residual resistance factor is far better than that by only increasing solution viscosity. The recovery factor of heavy oil reservoirs （70 mPa·s） can be enhanced by hydrophobic associating polymer solution of high residual resistance factor （more than 3） and high effective viscosity （24 mPa·s）. Therefore, increasing the residual resistance factor of the polymer solution not only decreases the requirement for the viscosity of polymer solution injected into heavy oil reservoirs but also is favorable to enhanced oil recovery during polymer flooding.

Enhancement of the imbibition recovery by surfactants in tight oil reservoirs

Hydraulic fracturing technology can significantly increase oil production from tight oil formations, but performance data show that production declines rapidly. In the long term, it is necessary to increase the development efficiency of block matrix, surfactant-aided imbibition is a potential way. The current work aimed to explain comprehensively how surfactants can enhance the imbibition rate. Laboratory experiments were performed to investigate the effects of wettability, interfacial tension(IFT), and relative permeability as the key parameters underlying surfactant solution imbibition. Two different types of surfactants, sodium dodecyl sulfate and polyethylene glycol octylphenol ether, at varied concentrations were tested on reservoir rocks. Experimental results showed that the oil recovery rate increased with increased wettability alteration and IFT and decreased residual oil saturation. A mechanistic simulator developed in previous studies was used to perform parametric analysis after successful laboratory-scale validation. Results were proven by parametric studies. This study,which examined the mechanism and factors influencing surfactant solution imbibition, can improve understanding of surfactant-aided imbibition and surfactant screening.

A FEM-DFN model for the interaction and propagation of multi-cluster fractures during variable fluid-viscosity injection in layered shale oil reservoir

To investigate the height growth of multi-cluster fractures during variable fluid-viscosity fracturing in a layered shale oil reservoir,a two-dimensional finite element method(FEM)-discrete fracture network(DFN)model coupled with flow,stress and damage is proposed.A traction-separation law is used to describe the mixed-mode response of the damaged adhesive fractures,and the cubic law is used to describe the fluid flow within the fractures.The rock deformation is controlled by the in-situ stress,fracture cohesion and fluid pressure on the hydraulic fracture surface.The coupled finite element equations are solved by the explicit time difference method.The effects of the fracturing treatment parameters including fluid viscosity,pumping rate and cluster spacing on the geometries of multifractures are investigated.The results show that variable fluid-viscosity injection can improve the complexity of the fracture network and height of the main fractures simultaneously.The pumping rate of15 m^(3)/min,variable fluid-viscosity of 3-9-21-36-45 mPa s with a cluster spacing of 7.5 m is the ideal treatment strategy.The field application shows that the peak daily production of the application well with the optimized injection procedu re of variable fluid-viscosity fracturing is 171 tons(about 2.85 times that of the adjacent well),which is the highest daily production record of a single shale oil well in China,marking a strategic breakthrough of commercial shale oil production in the Jiyang Depression,Shengli Oilfield.The variable fluid-viscosity fracturing technique is proved to be very effective for improving shale oil production.

Numerical simulation of hydraulic fracture propagation in tight oil reservoirs by volumetric fracturing

Volumetric fracturing is a primary stimulation technology for economical and effective exploitation of tight oil reservoirs. The main mechanism is to connect natural fractures to generate a fracture network system which can enhance the stimulated reservoir volume. By using the combined finite and discrete element method, a model was built to describe hydraulic fracture propagation in tight oil reservoirs. Considering the effect of horizontal stress difference, number and spacing of perforation clus- ters, injection rate, and the density of natural fractures on fracture propagation, we used this model to simulate the fracture propagation in a tight formation of a certain oil- field. Simulation results show that when the horizontal stress difference is lower than 5 MPa, it is beneficial to form a complex fracture network system. If the horizontal stress difference is higher than 6 MPa, it is easy to form a planar fracture system; with high horizontal stress differ- ence, increasing the number of perforation clusters is beneficial to open and connect more natural fractures, and to improve the complexity of fracture network and the stimulated reservoir volume （SRV）. As the injection rate increases, the effect of volumetric fracturing may be improved; the density of natural fractures may only have a great influence on the effect of volume stimulation in a low horizontal stress difference.

Laboratory to field scale assessment for EOR applicability in tight oil reservoirs

Tight oil reservoirs are contributing a major role to fulfill the overall crude oil needs,especially in the US.However,the dilemma is their ultra-tight permeability and an uneconomically short-lived primary recovery factor.Therefore,the application of EOR in the early reservoir development phase is considered effective for fast-paced and economical tight oil recovery.To achieve these objectives,it is imperative to determine the optimum EOR potential and the best-suited EOR application for every individual tight oil reservoir to maximize its ultimate recovery factor.Since most of the tight oil reservoirs are found in wide spatial source rock with complex and compacted pores and poor geophysical properties yet they hold high saturation of good quality oil and therefore,every single percent increase in oil recovery from such huge reservoirs potentially provide an additional million barrels of oil.Hence,the EOR application in such reservoirs is quite essential.However,the physical understanding of EOR applications in different circumstances from laboratory to field scale is the key to success and similarly,the fundamental physical concepts of fluid flow-dynamics under confinement conditions play an important role.This paper presents a detailed discussion on laboratory-based experimental achievements at micro-scale including fundamental concepts under confinement environment,physics-based numerical studies,and recent actual field piloting experiences based on the U.S.unconventional plays.The objective of this paper is to discuss all the critical reservoir rock and fluid properties and their contribution to reservoir development through massive multi-staged hydraulic fracture networks and the EOR applications.Especially the CO_(2)and produced hydrocarbon gas injection through single well-based huff-n-puff operational constraints are discussed in detail both at micro and macro scale.

Predicting the present-day in situ stress distribution within the Yanchang Formation Chang 7 shale oil reservoir of Ordos Basin, central China

The Yanchang Formation Chang 7 oil-bearing layer of the Ordos Basin is important in China for producing shale oil.The present-day in situ stress state is of practical implications for the exploration and development of shale oil;however,few studies are focused on stress distributions within the Chang 7 reservoir.In this study,the present-day in situ stress distribution within the Chang 7 reservoir was predicted using the combined spring model based on well logs and measured stress data.The results indicate that stress magnitudes increase with burial depth within the Chang 7 reservoir.Overall,the horizontal maximum principal stress(SHmax),horizontal minimum principal stress(Shmin) and vertical stress(Sv) follow the relationship of Sv≥SHmax>Shmin,indicating a dominant normal faulting stress regime within the Chang 7 reservoir of Ordos Basin.Laterally,high stress values are mainly distributed in the northwestern parts of the studied region,while low stress values are found in the southeastern parts.Factors influencing stress distributions are also analyzed.Stress magnitudes within the Chang 7 reservoir show a positive linear relationship with burial depth.A larger value of Young's modulus results in higher stress magnitudes,and the differential horizontal stress becomes higher when the rock Young's modulus grows larger.

Research into polymer injection timing for Bohai heavy oil reservoirs

Polymer flooding has been proven to effectively improve oil recovery in the Bohai Oil Field. However, due to high oil viscosity and significant formation heterogeneity, it is necessary to further improve the displacement effectiveness of polymer flooding in heavy oil reservoirs in the service life of offshore platforms. In this paper, the effects of the water/oil mobility ratio in heavy oil reservoirs and the dimensionless oil productivity index on polymer flooding effectiveness were studied utilizing rel- ative permeability curves. The results showed that when the water saturation was less than the value, where the water/oil mobility ratio was equal to 1, polymer flooding could effectively control the increase of fractional water flow, which meant that the upper limit of water/oil ratio suitable for polymer flooding should be the value when the water/oil mobility ratio was equal to 1. Mean while, by injecting a certain volume of water to create water channels in the reservoir, the polymer flooding would be the most effective in improving sweep efficiency, and lower the fractional flow of water to the value corresponding to △Jmax. Considering the service life of the platform and the polymer mobility control capacity, the best polymer injection timing for heavy oil reservoirs was optimized. It has been tested for reservoirs with crude oil viscosity of 123 and 70 mPa s, the optimum polymer flooding effec- tiveness could be obtained when the polymer floods were initiated at the time when the fractional flow of water were 10 % and 25 %, respectively. The injection timing range for polymer flooding was also theoretically analyzed for the Bohai Oil Field utilizing which provided methods for effectiveness. relative permeability curves, improving polymer flooding

Oxidization characteristics and thermal miscible flooding of high pressure air injection in light oil reservoirs

Physical modeling,numerical simulation and field case analysis were carried out to find out the subsurface thermal oxidation state,thermal oxidation front characteristics and production dynamic characteristics of high pressure air injection thermal oxidation miscible flooding technology.The lighter the composition and the lower the viscosity of the crude oil,the lower the fuel consumption and the combustion temperature are.The thermal oxidation front of light oil and volatile oil can advance stably,and a medium-temperature thermal oxidation stable displacement state can be formed in the light oil reservoir under high pressure conditions.With strong thermal gasification and distillation,light oil and volatile oil are likely to form a single phase zone of gasification and distillation with thermal flue gas at the high-temperature and high-pressure heat front,finally,an air-injection thermal miscible front.In light oil reservoirs,the development process of high-pressure air-injection thermal miscible flooding can be divided into three stages:boosting pressure stage,low gas-oil ratio and high-efficiency stable production stage and high gas-oil ratio production stage.Approximately 70%of crude oil is produced during the boosting pressure stage and low gas-oil ratio high-efficiency and stable production stage.

Re–Os Dating of Bitumen from Paleo–Oil Reservoir in the Qinglong Antimony Deposit, Guizhou Province, China and Its Geological Significance

Abundant organic inclusions are present in the Qinglong antimony deposit. However, the source rocks of these organic matters have not been reliably identified. Recently, a paleo--oil reservoir was found in the Qinglong antimony deposit. In view of similar components of gaseous hydrocarbon, we propose that the organic matters observed in inclusions in Qinglong antimony deposit would come from this paleo-oil reservoir. We used the Re-Os dating method to determine the age of the bitumen from this paleo-oil reservoir, and obtained an isochron age of 254.3~2.8 Ma. The age indicates that the oil- generation from source rock occurred in the early Late Permian, earlier than the Sb mineralization age （-148~8.5 Ma） in the Qinglong antimony deposit area. After oil generation from Devonian source rock, first and secondary migration, the crude oil have probably entered into the fractures and pores of volcanic rocks and limestone and formed a paleo-oil reservoir in the western wing of Dachang anticline. As burial process deepened, the crude oil has turned into natural gas, migrates into the core of Dachang anticline and formed a paleo-gas reservoir. The hydrocarbons （including CH4） in the reservoirs can serve as reducing agent to provide the sulfur required for Sb mineralization through thermal chemical reduction of sulfates. Therefore, the formation of oil-gas in the area is a prerequisite for the Sb mineralization in the Qinglong antimony deposit.

Discussion on the sweep efficiency of hybrid steam-chemical process in heavy oil reservoirs: An experimental study

Non-condensable gas(NCG),foam and surfactant are the three commonly-used additives in hybrid steam-chemical processes for heavy oil reservoirs.Their application can effectively control the steam injection profile and increase the sweep efficiency.In this paper,the methods of microscale visualized experiment and macroscale 3D experiment are applied to systematically evaluate the areal and vertical sweep efficiencies of different hybrid steam-chemical processes.First,a series of static tests are performed to evaluate the effect of different additives on heavy oil properties.Then,by a series of tests on the microscale visualized model,the areal sweep efficiencies of a baseline steam flooding process and different follow-up hybrid EOR processes are obtained from the collected 2D images.Specifically,they include the hybrid steam-N_(2)process,hybrid steam-N2/foam process,hybrid steam-surfactant process and hybrid steam-N2/foam/surfactant process(N2/foam slug first and steam-surfactant co-injection then).From the results of static tests and visualized micromodels,the pore scale EOR mechanisms and the difference between them can be discussed.For the vertical sweep efficiencies,a macroscale 3D experiment of steam flooding process and a follow-up hybrid EOR process is conducted.Thereafter,combing the macroscale 3D experiment and laboratory-scaled numerical simulation,the vertical and overall sweep efficiencies of different hybrid steam-chemical processes are evaluated.Results indicate that compared with a steam flooding process,the areal sweep efficiency of a hybrid steam-N2process is lower.It is caused by the high mobility ratio in a steam-N2-heavy oil system.By contrast,the enhancement of sweep efficiency by a hybrid steam-N2/foam/surfactant process is the highest.It is because of the high resistance capacity of NCG foam system and the performance of surfactant.Specifically,a surfactant can interact with the oil film in chief zone and reduce the interfacial energy,and thus the oil droplets/films formed during steam injection stage are unlocked.For NCG foam,it can plug the chief steam flow zone and thus the subsequent injected steam is re-directed.Simultaneously,from the collected 2D images,it is also observed that the reservoir microscopic heterogeneity can have an important effect on their sweep efficiencies.From the 3D experiment and laboratory-scaled numerical simulation,it is found that a N2/foam slug can increase the thermal front angle by about 150 and increase the vertical sweep efficiency by about 26%.Among the four processes,a multiple hybrid EOR process(steam-N2/foam/surfactant process) is recommended than the other ones.This paper provides a novel method to systematically evaluate the sweep efficiency of hybrid steam-chemical process and some new insights on the mechanisms of sweep efficiency enhancement are also addressed.It can benefit the expansion of hybrid steam-chemical processes in the post steamed heavy oil reservoirs.

Key oil accumulation periods of ultra-deep fault-controlled oil reservoir in northern Tarim Basin, NW China

A giant fault-controlled oilfield has been found in the ultra-deep(greater than 6000 m) Ordovician carbonate strata in the northern Tarim Basin. It is of great significance for hydrocarbon accumulation study and oil exploitation to determine the key oil accumulation periods. Based on detailed petrographic analysis, fluid inclusion association(FIA) in calcite samples filling in fractures from 12 wells were analyzed, and key accumulation periods of the strike-slip fault-controlled oilfield was studied by combining oil generation periods of the source rocks, formation periods of the fault and traps, and the fluid inclusion data.(1) There are multiple types of FIA, among them, two types of oil inclusions, the type with yellow fluorescence from the depression area and the type with yellow-green fluorescence from the uplift area with different maturities indicate two oil charging stages.(2) The homogenization temperature of the brine inclusions in FIA is mostly affected by temperature rises, and the minimum temperature of brine inclusions symbiotic with oil inclusions is closer to the reservoir temperature during its forming period.(3) FIA with yellow fluorescence all have homogenization temperatures below 50 ℃, while the FIA with yellow-green fluorescence have homogenization temperatures of 70–90 ℃ tested, suggesting two oil accumulation stages in Middle-Late Caledonian and Late Hercynian.(4) The Middle-Late Ordovician is the key formation period of the strike-slip fault, fracture-cave reservoir and trap there.(5) The oil generation peak of the main source rock of the Lower Cambrian is in the Late Ordovician, and the oil accumulation stage is mainly the Late Ordovician in the depression area, but is mainly the Early Permian in the uplift area. The key oil accumulation period of the strike-slip fault-controlled reservoirs is the Late Caledonian, the depression area has preserved the primary oil reservoirs formed in the Caledonian, while the uplift area has secondary oil reservoirs adjusted from the depression area during the Late Hercynian. Oil reservoir preservation conditions are the key factor for oil enrichment in the strike-slip fault zone of northern Tarim, and the Aman transition zone in the depression is richer in oil and gas and has greater potential for exploration and development.

A novel approach of tight oil reservoirs stimulation based on fracture controlling optimization and design

To deal with the stress interference caused by simultaneous propagation of multiple fractures and the wettability reversal and physical property changes of the reservoir caused by fracturing fluid getting in during large-volume fracturing of tight oil reservoirs through a horizontal well, a non-planar 3D fracture growth model was built, wettability reversal characterizing parameters and change of relative permeability curve were introduced to correct the production prediction model of fractured horizontal well, a fracturing design optimization software(Fr Smart) by integrating geological and engineering data was developed, and a fracturing design optimization approach for tight oil reservoirs based on fracture control was worked out. The adaptability of the method was analyzed and the fracture parameters of horizontal wells in tight oil reservoirs were optimized. The simulation results show that fracturing technology based on fracture control is suitable for tight oil reservoirs, and by optimizing fracture parameters, this technology makes it possible to produce the maximum amount of reserves in the well-controlled unit of unconventional reservoirs. The key points of fracturing design optimization based on fracture control include increasing lateral length of and reducing the row spacing between horizontal wells, increasing perforation clusters in one stage to decrease the spacing of neighboring fractures, and also avoiding interference of old and new fracturing wells. Field tests show that this technology can increase single well production and ultimate recovery. Using this technology in developing unconventional resources such as tight oil reservoirs in China will enhance the economics significantly.

Geomechanical response of overburden caused by CO_2 injection into a depleted oil reservoir

This study investigates the hydro-mechanical aspects of carbon dioxide(CO2) injection into a depleted oil reservoir through the use of coupled multiphase fluid flow and geomechanical modeling.Both singlephase and multiphase fluid flow analyses coupled with geomechanics were carried out at the West Pearl Queen depleted oil reservoir site,and modeling results were compared with available measured data.The site geology and the material properties determined on the basis of available geophysical data were used in the analyses.Modeling results from the coupled multiphase fluid flow and geomechanical analyses show that computed fluid pressures match well with available measured data.The hydromechanical properties of the reservoir have a significant influence on computed fluid pressures and surface deformations.Hence,an accurate geologic characterization of the sequestration site and determination of engineering properties are important issues for the reliability of model predictions.The computed fluid pressure response is also significantly influenced by the relative permeability curves used in multiphase fluid flow models.While the multiphase fluid flow models provide more accurate fluid pressure response,single-phase fluid flow models can be used to obtain approximate solutions.The ground surface deformations obtained from single-phase fluid flow models coupled with geomechanics are slightly lower than those predicted by multiphase fluid flow models coupled with geomechanics.However,the advantage of a single-phase model is the simplicity.Limited field monitoring of subsurface fluid pressure and ground surface deformations during fluid injection can be used in calibrating coupled fluid flow and geomechanical models.The calibrated models can be used for investigating the performance of large-scale CO2storage in depleted oil reservoirs.