Lithologic Reservoirs

It is the foamy oil which was seemed as the main factor leading the unexpected high production and high recovery of some heavy oil reservoirs in Canada and Venezuela. When it comes to the issue of foamy oil viscosity,there are disputes about whether the viscosity is higher or not than that of the initial live oil. In order to get a better understanding of the issue, this paper carried out detailed investigation about the foamy oil viscosity on three aspects：the relationship between the viscosity and the unexpected high production, the viscosity model of foamy oil and the influencing factors of foamy oil viscosity. It is considered that the influencing factors of the foamy oil viscosity include the pressure depletion rate, stabilization time, measuring device, dispersed gas volume fraction, pressure and flow rate, expansion ratio, surfactant, the size of dispersed bubble, the shearing rate and the conventional or unconventional testing method, and the controversy of the foamy oil viscosity is relevant to these influencing factors,and it is mainly caused by the measuring of the viscosity. Furthermore, the seepage mechanism of foamy oil has important significance for heavy oil reservoir numerical simulation and the optimization design of gas injection for heavy oil reservoir.

Distribution patterns of single sand body in Fuyu oil layer in the northern Honggang area, Songliao Basin

Sun Yu，Dong Yiming，Wang Jiping，Ma Shizhong，Yu Limin，Yan Baiquan

2016, Vol.28(4): 9–15 Abstract ( 651 ) PDF (673 KB) ( 663 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.002

The understanding of single sand body distribution is unclear and the prediction of lithologic prospects is difficult in Fuyu oil layer in the northern Honggang area, Songliao Basin. Using core data of 8 wells, analysis and test results of 226 core samples and logging data of 386 wells, this paper studied the genesis types, contact relationships and distribution patterns of single sand body in the northern Honggang area. The results show that the single sand body types of Fuyu oil layer are mainly distributary channel, subaqueous distributary channel and mouth bar sand bodies. In the plane, multi?branch distributary channel, subaqueous distributary channel and mouth bar sand bodies are distributed in a dense and narrow band. The vertical single sand body distribution is controlled by sediment supply and sedimentary evolution, and it shows the characteristics of“vertical subsection”and“differentiation between the north and the south”. The superimposed pattern of the distributary channel sand bodies is complex, which results in complex reservoir single sand body distribution in Fuyu oil layer. The contact relationship between different distributary channel and subaqeuous distributary channel sand bodies in Fuyu oil layer can be divided into four types, such as overlapping,stacking, migrating and isolated contact. The contact relationship between the distributary channel, subaqueous distributary channel sand bodies and thin sand bodies or the mouth barsand bodies is mainly an abrupt contact. Multi?phase thin sand bodies or mouth bar sand bodies are often in a“stacking”contact relationship. These results can provide an important basis for the prediction of lithologic traps and study on oil/water distribution rule of Fuyu oil layer in the northern Honggang area.

Differences of shale between Longmaxi Formation and Da’anzhai member in Sichuan Basin

Yan Jianping，Cui Zhipeng，Geng Bin，Guo Hongmei，Li Xingwen

2016, Vol.28(4): 16–23 Abstract ( 508 ) PDF (501 KB) ( 570 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.003

The exploration of nonmarine shale oil and gas gets more and more attention. This paper selected nonmarine shale in Da’anzhai member of Lower Jurassic Ziliujing Formation in Sichuan Basin to conduct comparison with marine shale in Lower Silurian Longmaxi Formation which has gained achievements of preliminary scale production,and then analyzed their differences in strata，rock types，rock fabric，organic geochemical characteristics and physical properties of shale reservoir, so as to establish an evaluation standard for nonmarine shale gas exploration and development in Sichuan Basin. The results show that the buried depth of Longmaxi Formation is generally 2 000?4 000 m, where black siliceous shale, chert, carbonaceous shale and dark gray mudstone are mainly developed, with lamellar structure, and the main minerals of shale are quartz, carbonate minerals, clay minerals, muscovite and pyrite. With higher content of organic matters, Longmaxi shale contains 1%-4% of TOC, with Ro of 2.4%-3.6%, being at the high-over mature stage of gas generation, and dominated by type Ⅰ-kerogen, it mainly developed intergranular pores, intracrystalline pores and microfissure. In addition, the tectonic preservation conditions are good. The buried depth of Da’anzhai member is generally 1 400-4 300 m, where dark shale is mainly developed. Characterized by dark shale with thin coquina or both interbedded, the shale developed lamellation with lamellar structure, and the main minerals are quartz, feldspar, clay minerals, calcite, dolomite and pyrite. The shale in Da’anzhai member contains 0.58%-3.81% of TOC, with Ro of 1.05%-1.85%, being at mature?high mature stage, and dominated by type Ⅱ2 -kerogen, it mainly developed intergranular pores, intracrystalline pores, organism pores, dissolved pores and fissures. Da’anzhai member has features of the coexistence of fractured coquina reservoirs or pore?micro fractured reservoir containing organic coquina with shale gas reservoir. It is considered that compared with Longmaxi Formation, the Da’anzhai member in Sichuan Basin also has a large shale gas resource potential and good prospects for exploration and development.

Main controlling factors of glutenite reservoir of fan delta in Mabei slope, Junggar Basin

Zou Niuniu，Zhang Daquan，Qian Haitao，Wu Tao，Shi Ji’an

2016, Vol.28(4): 24–33 Abstract ( 522 ) PDF (1491 KB) ( 681 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.004

Typical glutenite reservoirs of fan delta are developed in Triassic Baikouquan Formation in Mabei slope,northwestern margin of Junggar Basin, which are characterized by low porosity and low permeability with low compositional maturity and middle textural maturity. In order to disclose the main controlling factors for the development of glutenite reservoirs and predict favorable reservoir distribution, based on the data of thin sections, scanning electron microscope, thin section examination of fluorescence characteristics and physical properties, the controlling effects on glutenite reservoirs were discussed of the following aspects: lithology, sedimentary facies, sedimentary structure and palaeogeomorphology, diagenesis, as well as hydrocarbon- charging. The results show that lithology is the material basis of forming high quality glutenite reservoir; the favorable sedimentary facies is crucial for reservoir quality; sedi?mentary structure and paleogeomorphology decided by strong syngenetic faulting plays a key role in the glutinite body distribution; diagenesis and hydrocarbon-charging are favorable for improving the properties of glutenite reservoir. Fan delta front subaqueous distributary channel glutenite and mouth bar sandstone are favorable reservoirs whose hydrodynamic condition is stable and stronger, and fan delta plain distributary channel glutenite is fair.

Source rock characteristics and hydrocarbon generation kinetics: A case study of the Permian Lucaogou Formation in Jimusar Sag, Junggar Basin

Ji Hongjie，Qiu Zhen，Tao Huifei，Ma Dongxu，Liao Peng，Wang Qi

2016, Vol.28(4): 34–42 Abstract ( 573 ) PDF (702 KB) ( 875 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.005

There are abundant petroleum resources in the Permian Lucaogou Formation in Jimusar Sag, Junggar Basin. The source rock types of the Lucaogou Formation include shale, carbonate shale and silty mudstone. These source rocks are characterized by high organic carbon content, high hydrocarbon generation potential, low maturity to maturity and Ⅰ-Ⅱ type kerogen. Based on conventional organic geochemistry evaluation of the source rocks, the source rock samples with low?middle maturity and high organic carbon content were selected to carry out pyrolysis and hydrocarbon generation kinetics simulation experiments under open system, and the haracteristics of the hydrocarbon generation and expulsion were studied. The results show that the reaction activation energy of the source rocks is 210 kJ/mol. The hydrocarbon generation and expulsion characteristics of the three kinds of source rocks are different. The shale has the highest hydrocarbon generation content and hydrocarbon expulsion rate, followed by carbonate shale, and the silty mudstone has the lowest hydrocarbon generation content and hydrocarbon expulsion rate. It is considered that the main driving force of the hydrocarbon expulsion and tight oil accumulation is the pressure increased by the hydrocarbon generation of source rocks in the Lucaogou Formation, and the shale and carbonate shale are the favorable targets for tight oil exploration.

Clastic strata compaction law and its application to paleostructure restoration

Guo Ying，Tang Liangjie，Ni Jinlong

2016, Vol.28(4): 43–50 Abstract ( 528 ) PDF (595 KB) ( 605 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.006

The compaction of clastic rock has different paths in different geological settings or at different evolution stages, so it is the emphasis and the difficulty in oil and gas exploration works. In the past decades, domestic and foreign researchers have done a lot of work to promote the quantitative study of the compaction of clastic rocks. However,because of the regionality and limitations about the research results, its applicability receives a serious challenge.Based on the related research results, this paper reviewed the following five aspacts, including the influencing factors of compaction, methods for characterizing the compaction law, normal compaction curve construction scheme,tectonic characteristics restoring and quantitative evaluation of error. The result shows that the research about clastic rock compaction law and its application in palaeostructure restoration is still in the initial stage. It is pointed out that selecting suitable methods for characterizing the formation compaction law and error evaluation, according to the geological characteristics of the study area, is the key for the research and application of clastic strata compaction law.

Characteristics and genesis of tight sandstone reservoir of Shanxi Formation in Linxing area, Ordos Basin

Zhao Da，Xu Hao，Wang Lei，Tang Dazhen，Meng Shangzhi，Li Ling

2016, Vol.28(4): 43–50 Abstract ( 342 ) PDF (834 KB) ( 809 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.007

Linxing area in Ordos Basin has great potential of natural gas exploration and development, so it is an important succeeding area for tight sandstone gas exploration. Due to the poor physical properties of tight sandstone reservoir and complex genesis of tight reservoir, the industrial development of tight sandstone gas in this area is restricted. Based on the data of X?ray diffraction, scanning electron microscope, cathodoluminescence, cast thin section, fluid inclusions and laboratory test, the characteristics and genesis of tight sandstone reservoirs of Shanxi Formation in Lingxing area were studied. The result shows that the sandstone reservoirs are mainly litharenite and sub ? litharenite, and the pore types are mainly primary intergranular pores and secondary dissolved pores. The reservoir physical pro?perties are poor, with the average reservoir porosity of 5.9% and the average permeability of 0.073 mD. Both the disp?lacement pressure and the median saturation pressure are high. The pore throat radius is small and the sorting is poor. The diagenetic sequence of tight sandstone reservoir is divided into four generations of clay filling, which makes the reservoir tight. The quantitative analysis of porosity evolution shows that reservoir quality in the study area is mainly affected by compaction and cementation. The porosity loss due to the compaction is 17.1% at the early diagenetic stage, and the porosity loss due to the compaction and cementation is 22.9% at the middle diagenetic stage. In cementation, a large number of clay minerals filled the pores and clogged the throat,which makes the primary intergranular pores become tiny intercrystalline pores. In addition, it makes the pore surface rough and increases the detour degrees, resulting in the reservoir porosity and permeability greatly reduced.

Tight reservoir characteristics and porosity evolution of Chang 8^₁in western Jiyuan area

Wang Yang，Li Shutong，Mou Weiwei，Yan Cancan

2016, Vol.28(4): 59–66 Abstract ( 446 ) PDF (866 KB) ( 569 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.008

Analysis of porosity evolution is an effective way to restore the densification process and clear the reasons of reservoir densification. The data of core drilling observation, cast sections, SEM and grain size analysis were used to analyze the characteristics and porosity evolution of Chang 81 tight reservoir in western Jiyuan area,Ordos Basin. The results show that the Chang 81 reservoir rock types are mainly fine?grained lithic arkose and feldspathic litharenite, the pore types are mainly intergranular pores and dissolved pores of feldspar, and the pore structure is poor.The clastic rocks experienced compaction, cementation and dissolution, thus producing tight reservoirs with low porosity and low permeability. Based on rock thin section observation, the porosity evolution during diagenesis was recovered by statistical analysis method, and the contribution value of each diagenesis on porosity evolution was quantitatively obtained. The porosity evolution parameters show that the primary porosity of Chang 81 reservoir is 41.35% , the porosity loss rates during the process of mechanic compaction and the process of cementation and metasomasis are 57.10% and 32.55%, respectively. The porosity increase rates during the process of dissolution and the fracturing are 6.48% and 0.15%, respectively. The porosity of Chang 81 reservoir calculated is 7.02%, and the porosity analyzed in the laboratory is 7.12% , so the error rate in the quantitative study of porosity is 1.40% . The Chang 81 reservoir in Jiyuan area has a relatively high primary porosity, but the porosity loss rate is 89.65% resulted by mechanic compaction and cementation. In fact, although sedimentary condition is the basis for the formation of original compositions and the rock texture, the strong compaction, strong cementation and weak dissolution are the dominant diagenesis types which destroyed the reservoir physical properties to become tight reservoir.

Sequence stratigraphy and depositional systems of Wenchang Formation in the southern Lufeng area, Pearl River Mouth Basin

Chen Feng，Zhu Xiaomin，Ge Jiawang，Li Ming，Wu Chenbingjie

2016, Vol.28(4): 67–77，94 Abstract ( 535 ) PDF (1150 KB) ( 656 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.009

Lufeng Depression is a proven rich?hydrocarbon accumulation area in the Pearl River Mouth Basin. The drilling of oil and gas mainly focused on the Wenchang Formation in the southern Lufeng depression in the past years.Because of multiple tectonic movements and limited amounts of drilling wells, the evolution of depositional systems and favorable reservoirs distribution are unclear, which restricts further hydrocarbon exploration in Lufeng Depression. Under the guidance of sedimentology and sequence stratigraphy, the sequence stratigraphy framework and depositional systems were discussed based on the comprehensive analyses of core, logging and new acquired 3D seismic data.According to the characteristics of seismic reflection and wireline logging changes, the Wenchang Formation is a second?order sequence, and it can be subdivided into six third-order sequences, which represent a complete sedimentary filling process of the lacustrine basin including initial rifting, intensive rifting, weak rifting and thermal depression from bottom to top. According to seismic reflection characteristics, several types of seismic facies were recognized including subparallel-hummoky seismic facies, parallel-subparallel sheet-shaped seismic facies, wedge-chaotic infilling seismic facies, fastigiate or wedge progradational seismic facies, progradational seismic facies（oblique or sigmodial)and moundy seismic facies. The distribution of these seismic facies of Wenchang Formation is related in the vertical profile.Depositional systems composed of braided river delta, nearshore subaqueous fan, fan delta, lacustrine and turbidity fan are developed during the Wenchang depositional stage. Controlled by rifting stages, the depositional systems display obvious cycling characteristics vertically. This study points out that the braided river delta front sandstone in SQ2 would be the favorable exploration targets. The nearshore subaqueous fan, fan delta and turbidity fan in SQ3 and SQ4 are the potential exploration targets.

Determination of seismic wave velocity by compressibility of rocks

Li Chuanliang，Zhu Suyang

2016, Vol.28(4): 78–81 Abstract ( 443 ) PDF (327 KB) ( 463 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.010

Seismic wave is stress wave, and also elastic wave, of which the velocity is closely related with density and compressibility of media. Seismic wave velocity of single?phase media can be calculated by theoretical equations,while there is no theoretical equation for calculating the seismic wave velocity of dual?phase media. The existing empirical equations and physical models have some drawbacks, and exaggerate the effect of porosity on seismic wave velocity. According to the study of this paper, two?phase media can be viewed as pseudo single?phase media, so its seismic wave velocity can be calculated by the equation of single?phase media with the average parameters of matrix and fluid in formation rocks. The calculation analysis shows that porosity has not so much effect on seismic wave velocity as known before in the range of formation porosity. The equation proposed in this paper can be taken as a new method to determine the seismic wave velocity of formation, with practicability and broad application prospect.

Prediction of water breakthrough time for bottom-water gas reservoir with barrier

Huang Quanhua，Lu Yun，Chen Chong

2016, Vol.28(4): 82–87 Abstract ( 423 ) PDF (425 KB) ( 853 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.011

Water coning of gas well is an important factor for affecting gas well productivity and gas reservoir recovery efficiency. It is essential to accurately predict water breakthrough time of gas well and delay bottom water coning for rational development of bottom?water gas reservoir. In terms of high production gas wells of thick gas reservoirs, based on two phase flow theory and law of fluid flow in porous media, this paper established a physical model and deduced the water breakthrough time formula for bottom?water gas reservoir with barrier considering non-Darcy effect, and analyzed effects of the position and length of the artificial barrier on water breakthrough time of gas well, and optimized the position and length of the artificial barrier through graphic method. Case study shows that artificial barrier has a very good effect for inhibiting bottom water, and can greatly extend the waterless gas recovery period of the gas well. This study can guide the prediction of breakthrough time of bottom-water gas reservoirs with barrier and the design of artificial barrier for bottom?water gas reservoir without barrier.

Productivity calculation method of fractured horizontal wells with gas-water two-phase in low permeability gas reservoirs

Yuan Lin，Li Xiaoping，Liu Jianjun

2016, Vol.28(4): 88–94 Abstract ( 449 ) PDF (482 KB) ( 214 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.012

Developing low permeability gas reservoirs with horizontal well technology supported by hydraulic fracturing has become the trend globally, while gas well with water restricted the productivity seriously. Based on the filtration theory of gas-water two?phase in the reservoir and hydraulic fracture, considering stress sensitivity and slippage effect in reservoirs, as well as high velocity non - Darcy flow in the hydraulic fracture, this paper defined the generalized pseudo pressure of gas-water two-phase, and used the theory of potential superimposition to establish a new productivity model of fractured horizontal wells with gas-water two-phase in low permeability gas reservoirs. Case study shows that theoretical inflow performance relationship（IPR）curve is in a good coincidence with the actual test data; moreover,the relative error of absolute open flow calculated by the new model is small compared with that calculated productivity test, just 5.4%, which indicates the high accuracy of the new model. Sensitivity analysis result demonstrates that as the increasing of the number, half length and conductivity of fracture, the absolute open flow increases, but the increasing trend becomes more and more gentle, while as the increasing of water-gas volume ratio, the absolute open flow decreases obviously. This study is helpful for productivity prediction and fracture optimization design of fractured horizontal wells with gas-water two?phase in low permeability gas reservoirs.

Study on natural gamma-ray model reconstruction method

Shi Xiaoqian

2016, Vol.28(4): 95–100 Abstract ( 456 ) PDF (387 KB) ( 734 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.013

Oil and gas reservoirs are often distributed in several strata in different sedimentary periods. Due to the differences of buried depth, lithology and mineral content in sand shale formation during different sedimentary periods, the logging responses of the same lithology are different. Natural gamma?ray logging curve is affected by sedimentation in some regions, so its log value increases or decreases with buried depth change. If use the log value to calculate the shale content of reservoirs or carry out reservoir parameter inversion, it is unable to use a unified standard（formula）to evaluate the shale content of target zone. Based on the analyses of logging response differences of natural gamma-ray logging curve during different sedimentary periods, as well as its change characteristics with buried depth and formation lithology, the inverse operation of shale content calculation method in the comprehensive interpretation of log data was used to reconstruct natural gamma ?ray logging curve. The result shows that the reconstructed natural gamma -ray logging curve is not affected by factors such as strata of different sedimentary periods, and a unified standard can be used to carry out lithology interpretation for the target zone during different geological periods. This reconstruction method can be applied for reservoir inversion and shale content calculation for different types of sand shale formation.

Adaptability of polymer to reservoir pore structure in Pubei Oilfield

Zhang Jihong，Guo Xin

2016, Vol.28(4): 101–105 Abstract ( 411 ) PDF (319 KB) ( 472 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.014

In order to seek a polymer solution flooding method suitable for oil recovery in Pubei Oilfield of Songliao Basin, a mercury injection experiment with cores from A1 well field in Pubei Oilfield was carried out. Pubei Oilfield belongs to typical low permeability reservoir. By measuring the hydrodynamic diameter of common polyacrylamide polymer and salt?resistant polymer, this paper investigated the adaptability of two kinds of polymers to the reservoir pore strucutre under different preparation conditions from the microscopic aspect, and compared the displacement efficiency by cylindrical cores. The experiment result shows that the oil recovery enhanced by 700 mg/L of salt-resistant polymer is 3.22% higher than that by 1 200 mg/L of common polymer. It is proved that salt?resistant polymer is more suitable for the flooding in Pubei Oilfield.

Pressure transient analysis on CO₂ flooding in low permeability reservoirs considering fluid heterogeneity

Li Youquan，Meng Fankun，Yan Yan，Han Fengrui，Yu Weijie，Zhou Shiyu

2016, Vol.28(4): 106–112 Abstract ( 501 ) PDF (491 KB) ( 370 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.015

CO2 flooding in low permeability reservoirs is considered as one of the most significant EOR methods.However, there is lack of clear recognition on pressure response performance during the flooding process currently.Injection of CO2 will change the physical property of reservoir fluids, and three zones could be developed, which are CO2 zone, CO2 -oil transition zone and unswept oil zone, respectively. Hence, based on the seepage theory of composite reservoir model, the power?law and Newton interpolation equations were introduced to describe the variable characteri?stics of fluid heterogeneity in CO2 -oil transition zone. The well testing model for CO2 flooding in low permeability reservoir was presented, and it was solved by numerical differential method. The pressure transient curves at two different fluid heterogeneity variation forms were analyzed. The results demonstrate that for power-law variation of viscosity and compressibility in CO2 -oil transition zone, the mobility and diffusivity ratio between CO2 zone and CO2 -oil transition zone increased with variation exponents, which leads to the rise of pressure derivative curves slope. As the compressibility in CO2 -oil transition zone varied discontinuously, since the increase of diffusivity ration between CO2 region and CO2 -oil transition region, the pressure derivative curves would drop. Finally,the well testing explanation method for CO2 flooding was presented through the application of real case.

Adjustment measures of remaining oil tapping based on sand body structure

Hu Hao

2016, Vol.28(4): 111–120 Abstract ( 426 ) PDF (681 KB) ( 611 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.016

The development of Xing 6 block of Daqing Oilfield has entered the later stage with high water cut. The distribution of remaining oil in reservoir is complex, so analyzing the remaining oil distribution by making sublayer as the research object can not meet the needs of the remaining oil research in the later stage. Therefore, the paper refined the internal sand body structure in Xing 6 block, summed up five typical characteristics of sand body structure, discussed the relationships of the sand body structure with the formation and distribution of remaining oil, and proposed corresponding strategies for tapping the potential remaining oil, namely reshooting and water plugging adjustment plan.The plan designs 57 reshooting wells, 6 water plugging wells. It is estimated that the average daily oil production of single well increases by 2.9 t, and comprehensive water cut decreases by 6% after the implementation of the plan. This plan has some guidance for tapping the potential remaining oil in maturing oilfield in the late stage of high water cut development.

Influence of thermal alteration of minerals in strong water sensitive reservoir on physical properties：A case study from the first member of Shahejie Formation in Jinjia Oilfield

Chen Lihua

2016, Vol.28(4): 121–126 Abstract ( 469 ) PDF (601 KB) ( 403 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.017

The heavy oil reservoir of the first member of Shahejie Formation in Jinjia Oilfield has strong water sensitivity. In the process of steam stimulation, minerals are easy to change at high temperatures, which makes pore structure change and affects reservoir physical properties. In order to understand the characteristics of mineral changes and their effects on reservoir physical properties, an autoclave physics simulation was conducted. Experiment results show that the changes of minerals in the reservoir at high temperatures were reflected in the following three aspects：the expansion caused by the changes of crystal spacing of montmorillonite, mineral dissolution and transformation, as well as dissolved pores. From 200 ℃ to 300 ℃, the expansion of montmorillonite weakened and was gradually near to disappear, and the dissolution further strengthened, which makes the pores large and medium, and then reservoir connectivity and physical properties further changed better. In the steam stimulation process of strong water sensitivity heavy oil reservoirs, it need to ensure the temperature and dryness of injecting steam to make the reservoir temperature higher than 200 ℃ , so as to reduce reservoir water sensitivity, and improve reservoir physical properties and enhance development effect.

Water cut change law with time in waterflooding oilfield

Xu Ying，Pan Youjun，Zhou Rongping，Wu Di，Pu Yu’e，Xiao Lu

2016, Vol.28(4): 127–132 Abstract ( 518 ) PDF (369 KB) ( 664 )

doi: https://doi.org/10.3969/j.issn.1673-8926.2016.04.018

Predicting water cut is an important part of reservoir engineering study. At present, we can only establish the relationship between water cut and production level for the water cut prediction, but the oilfield workers often want to get the water cut change law with the time of oilfield development. Based on waterflooding characteristic curve equation, combined with Arps and Logistic production decline equation and Rayleigh model for production change whole process respectively, the relation formula between water cut and time was derived when the oilfield production follows different change law. This change law can provide a reliable theoretical basis for the analyses of the dynamic and stable situation of oilfield, the establishment of development plan and the control of technical countermeasure.