Gas-Water Production of a Continental Tight-Sandstone Gas Reservoir under Different Fracturing Conditions

A numerical model of hydraulic fracture propagation is introduced for a representative reservoir(Yuanba continental tight sandstone gas reservoir in Northeast Sichuan).Different parameters are considered,i.e.,the interlayer stress difference,the fracturing discharge rate and the fracturing fluid viscosity.The results show that these factors affect the gas and water production by influencing the fracture size.The interlayer stress difference can effectively control the fracture height.The greater the stress difference,the smaller the dimensionless reconstruction volume of the reservoir,while the flowback rate and gas production are lower.A large displacement fracturing construction increases the fracture-forming efficiency and expands the fracture size.The larger the displacement of fracturing construction,the larger the dimensionless reconstruction volume of the reservoir,and the higher the fracture-forming efficiency of fracturing fluid,the flowback rate,and the gas production.Low viscosity fracturing fluid is suitable for long fractures,while high viscosity fracturing fluid is suitable for wide fractures.With an increase in the fracturing fluid viscosity,the dimensionless reconstruction volume and flowback rate of the reservoir display a non-monotonic behavior,however,their changes are relatively small.

Inter-layer interference for multi-layered tight gas reservoir in the absence and presence of movable water

Due to the dissimilarity among different producing layers,the influences of inter-layer interference on the production performance of a multi-layer gas reservoir are possible.However,systematic studies of inter-layer interference for tight gas reservoirs are really limited,especially for those reservoirs in the presence of water.In this work,five types of possible inter-layer interferences,including both absence and presence of water,are identified for commingled production of tight gas reservoirs.Subsequently,a series of reservoir-scale and pore-scale numerical simulations are conducted to quantify the degree of influence of each type of interference.Consistent field evidence from the Yan'an tight gas reservoir(Ordos Basin,China)is found to support the simulation results.Additionally,suggestions are proposed to mitigate the potential inter-layer interferences.The results indicate that,in the absence of water,commingled production is favorable in two situations:when there is a difference in physical properties and when there is a difference in the pressure system of each layer.For reservoirs with a multi-pressure system,the backflow phenomenon,which significantly influences the production performance,only occurs under extreme conditions(such as very low production rates or well shut-in periods).When water is introduced into the multi-layer system,inter-layer interference becomes nearly inevitable.Perforating both the gas-rich layer and water-rich layer for commingled production is not desirable,as it can trigger water invasion from the water-rich layer into the gas-rich layer.The gas-rich layer might also be interfered with by water from the neighboring unperforated water-rich layer,where the water might break the barrier(eg weak joint surface,cement in fractures)between the two layers and migrate into the gas-rich layer.Additionally,the gas-rich layer could possibly be interfered with by water that accumulates at the bottom of the wellbore due to gravitational differentiation during shut-in operations.

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.

A transient production prediction method for tight condensate gas wells with multiphase flow

Considering the phase behaviors in condensate gas reservoirs and the oil-gas two-phase linear flow and boundary-dominated flow in the reservoir,a method for predicting the relationship between oil saturation and pressure in the full-path of tight condensate gas well is proposed,and a model for predicting the transient production from tight condensate gas wells with multiphase flow is established.The research indicates that the relationship curve between condensate oil saturation and pressure is crucial for calculating the pseudo-pressure.In the early stage of production or in areas far from the wellbore with high reservoir pressure,the condensate oil saturation can be calculated using early-stage production dynamic data through material balance models.In the late stage of production or in areas close to the wellbore with low reservoir pressure,the condensate oil saturation can be calculated using the data of constant composition expansion test.In the middle stages of production or when reservoir pressure is at an intermediate level,the data obtained from the previous two stages can be interpolated to form a complete full-path relationship curve between oil saturation and pressure.Through simulation and field application,the new method is verified to be reliable and practical.It can be applied for prediction of middle-stage and late-stage production of tight condensate gas wells and assessment of single-well recoverable reserves.

Blasingame production decline type curves for analysing a multi-fractured horizontal well in tight gas reservoirs

Production decline analysis has been considered as an important method to obtain the flow parameters, reservoir properties and original gas in place. Although advanced Blasingame production decline analysis methods for vertical wells, fractured wells and horizontal wells are widely used, limited study has conducted on Blasingame production decline type curves for multi-fractured horizontal well(MFHW). Based on the perpendicular bisection(PEBI) grids, a numerical model was developed and the solution was obtained using control volume finite element method and the fully implicit method. Blasingame production decline-type curves of the infinitely conductive MFHW were plotted through computer programming. A field case was presented to analyse and verify the model developed. Five flow regimes, including early formation linear flow, early radial flow, compound linear flow, transient flow and pseudo-radial flow, are recognized. Fracture spacing is the main factor that affects early radial flow, compound linear flow and transient flow, the distance from the well to the circular boundary affects the pseudo-radial flow, and the type curves are also significantly affected by the formation permeability, fracture number and fracture half-length. The validation of field case suggests that the Blasingame production decline type curves proposed in this work can be applied to the production decline analysis for MFHW in tight gas reservoirs.

A new model for predicting irreducible water saturation in tight gas reservoirs

The irreducible water saturation(Swir) is a significant parameter for relative permeability prediction and initial hydrocarbon reserves estimation.However,the complex pore structures of the tight rocks and multiple factors of the formation conditions make the parameter difficult to be accurately predicted by the conventional methods in tight gas reservoirs.In this study,a new model was derived to calculate Swir based on the capillary model and the fractal theory.The model incorporated different types of immobile water and considered the stress effect.The dead or stationary water(DSW) was considered in this model,which described the phenomena of water trapped in the dead-end pores due to detour flow and complex pore structures.The water film,stress effect and formation temperature were also considered in the proposed model.The results calculated by the proposed model are in a good agreement with the experimental data.This proves that for tight sandstone gas reservoirs the Swir calculated from the new model is more accurate.The irreducible water saturation calculated from the new model reveals that Swir is controlled by the critical capillary radius,DSW coefficient,effective stress and formation temperature.

A novel steady-state productivity equation for horizontal wells in bottom water drive gas reservoirs

It is known that there is a discrepancy between field data and the results predicted from the previous equations derived by simplifying three-dimensional（3-D） flow into two-dimensions（2-D）.This paper presents a new steady-state productivity equation for horizontal wells in bottom water drive gas reservoirs.Firstly,the fundamental solution to the 3-D steady-state Laplace equation is derived with the philosophy of source and the Green function for a horizontal well located at the center of the laterally infinite gas reservoir.Then,using the fundamental solution and the Simpson integral formula,the average pseudo-pressure equation and the steady-state productivity equation are achieved for the horizontal section.Two case-studies are given in the paper,the results calculated from the newly-derived formula are very close to the numerical simulation performed with the Canadian software CMG and the real production data,indicating that the new formula can be used to predict the steady-state productivity of such horizontal gas wells.

Geological characteristics and high production control factors of shale gas reservoirs in Silurian Longmaxi Formation, southern Sichuan Basin, SW China

Marine shale gas resources have great potential in the south of the Sichuan Basin in China.At present,the high-quality shale gas resources at depth of 2000–3500 m are under effective development,and strategic breakthroughs have been made in deeper shale gas resources at depth of 3500–4500 m.To promote the effective production of shale gas in this area,this study examines key factors controlling high shale gas production and presents the next exploration direction in the southern Sichuan Basin based on summarizing the geological understandings from the Lower Silurian Longmaxi Formation shale gas exploration combined with the latest results of geological evaluation.The results show that:(1)The relative sea depth in marine shelf sedimentary environment controls the development and distribution of reservoirs.In the relatively deep water area in deep-water shelf,grade-I reservoirs with a larger continuous thickness develop.The relative depth of sea in marine shelf sedimentary environment can be determined by redox conditions.The research shows that the uranium to thorium mass ratio greater than 1.25 indicates relatively deep water in anoxic reduction environment,and the uranium to thorium mass ratio of 0.75–1.25 indicates semi-deep water in weak reduction and weak oxidation environment,and the uranium to thorium mass ratio less than 0.75 indicates relatively shallow water in strong oxidation environment.(2)The propped fractures in shale reservoirs subject to fracturing treatment are generally 10–12 m high,if grade-I reservoirs are more than 10 m in continuous thickness,then all the propped section would be high-quality reserves;in this case,the longer the continuous thickness of penetrated grade-I reservoirs,the higher the production will be.(3)The shale gas reservoirs at 3500–4500 m depth in southern Sichuan are characterized by high formation pressure,high pressure coefficient,well preserved pores,good pore structure and high proportion of free gas,making them the most favorable new field for shale gas exploration;and the pressure coefficient greater than 1.2 is a necessary condition for shale gas wells to obtain high production.(4)High production wells in the deep shale gas reservoirs are those in areas where Long11-Long13 sub-beds are more than 10 m thick,with 1500 m long horizontal section,grade-I reservoirs penetration rate of over 90%,and fractured by dense cutting+high intensity sand injection+large displacement+large liquid volume.(5)The relatively deep-water area in the deep-water shelf and the area at depth of 3500–4500 m well overlap in the southern Sichuan,and the overlapping area is the most favorable shale gas exploration and development zones in the southern Sichuan in the future.With advancement in theory and technology,annual shale gas production in the southern Sichuan is expected to reach 450×108 m3.

A new method to calculate the productivity index for vertical fractured well of tight gas reservoir

Generally the irreducible water saturation of low permeability gas reservoir is quite high which leads to the permeability stress sensibility and threshold pressure gradient. Under the assumption that permeability varies with experimental law of the pseudo pressure drop, according to concepts of perturbable ellipses and equivalent developing regulations, the calculation method of stable production of hydraulically fractured gas well in low permeability reservoirs is investigated with threshold pressure. And productivity curve is drawn and analyzed. The result shows that, permeability modulus and threshold pressure have effect on production of fractured gas well. The higher the permeability modulus and the threshold pressure, the lower the production is. Therefore, the impact of stress sensitive and threshold pressure must he considered when analyzing the productivity of vertical fracture well in low permeability gas reservoir.

Production forecasting methods for different types of gas reservoirs

Hydrocarbon production in oil and gas fields generally progresses through stages of production ramp-up,plateau(peak),and decline during field development,with the whole process primarily modeled and forecasted using lifecycle models.SINOPEC's conventional gas reservoirs are dominated by carbonates,low-permeability tight sandstone,condensate,volcanic rocks,and medium-to-high-permeability sandstone.This study identifies the optimal production forecasting models by comparing the fitting coefficients of different models and calculating the relative errors in technically recoverable reserves.To improve forecast precision,it suggests substituting exponential smoothing method-derived predictions for anomalous data caused by subjective influences like market dynamics and maintenance activities.The preferred models for carbonate gas reservoir production forecasts are the generalized Weng's,Beta,Class-I generalized mathematical,and Hu-Chen models.The Vapor pressure and Beta models are optimal for forecasting the annual productivity of wells(APW)from gas-bearing low-permeability tight sandstone reservoirs.The Wang-Li,Beta,and Yu QT tb models are apt for moderate-to-small-reserves,single low-permeability tight sandstone gas reservoirs.The Rayleigh,Hu-Chen,and generalized Weng's models are suitable for condensate gas reservoirs.For medium-to-high-permeability sandstone gas reservoirs,the lognormal,generalized gamma,and Beta models are recommended.

Sichuan super gas basin in southwest China

A sedimentary basin is classified as a super basin when its cumulative production exceeds 5 billion barrels of oil equivalent(6.82×10^(8) t of oil or 7931.66×10^(8) m^(3) of gas)and its remaining recoverable resources are at least 5 billion barrels of oil equivalent.By the end of 2019,the total output of oil and gas in Sichuan Basin had been 6569×10^(8) m^(3),the ratio of gas to oil was 80:1,and the total remaining recoverable resources reached 136404×10^(8) m^(3),which makes it as a second-tier super basin.Because the output is mainly gas,it is a super gas basin.The reason why the Sichuan Basin is a super gas basin is that it has four advantages:(1)The advantage of gas source rocks:it has the most gas source rocks(9 sets)among all the basins in China.(2)The advantage of resource quantity:it has the most total remaining recoverable resources among all the basins in China(136404×10^(8) m^(3)).(3)The advantage of large gas fields:it has the most large gas fields(27)among all the basins in China.(4)The advantage of total production:by the end of 2019,the total gas production had been 6487.8×10^(8) m^(3),which ranked the first among all the basins in China.There are four major breakthroughs in natural gas exploration in Sichuan Basin:(1)Breakthrough in shale gas:shale gas was firstly found in the Ordovician Wufeng-Silurian Longmaxi formations in China.(2)Breakthrough in tight sandstone gas:the Triassic Xu2 Member gas reservoir in Zhongba gas field is the first high recovery tight sandstone gas reservoir in China.(3)Breakthrough in giant carbonate gas fields.(4)Breakthrough in ultra-deep gas reservoir.These breakthroughs have led to important progress in different basins across the country.Super basins are classified according to three criteria:accumulative oil and gas production,remaining recoverable resources,tectonic attributes of the basin and the proportion of oil and gas in accumulative oil and gas production.

东胜气田致密高含水气藏合采气井效果评价及产出影响因素分析

为了确定鄂尔多斯盆地北缘致密高含水气藏合采气井开发效果,指导同类型气藏合采气井高效开发。以东胜气田致密高含水气藏为研究对象,分析了单采井与合采井不同开发阶段、不同井区及纵向上的产出效果,以及合采井层间含气性差异对合采井产出的影响,明确了东胜气田致密高含水气藏合采井的开发效果及层间产出的影响因素。研究结果表明:①东胜气田致密高含水气藏合采井具有初期压力高、产量高的特征,但整体开发效果与气藏含气性或产水情况有相关性;②通过参数对比分析,合采井生产层产出效果与产层物性、含气性具有明显的正相关性,产层之间的含气性差异也会影响合采开发效果;③合采井稳定生产临界携液(携泡)流量与气井水气比也具有一定的相关性。结论认为:①东胜气田致密高含水气藏合采井初期压力、产量较高,但在低含气饱和度(高水气比)区域合采井整体开发效果较差,同时气田合采井随着开发时间的推移纵向上层间的产出状况也不断发生变化;②合采气井生产层物性、含气性越好,生产层的产出效果越好,且以物性条件为主导,但在较大的层间含气性差异下,合采井层间易发生严重的气液倒灌使得整体开发效果变差;③合采气井水气比越高,稳定生产临界携液(携泡)流量越大。

东胜气田致密高含水气藏合采气井层间干扰影响因素

为了明确鄂尔多斯盆地北缘致密高含水气藏合采气井层间干扰及其影响因素,指导同类型气藏合采气井高效开发,以该盆地北缘东胜气田致密高含水气藏为研究对象,分析了储集层地质条件、储集层改造对合采井产层段贡献的影响,指出了该类合采气井层间干扰的主控因素。研究结果表明:(1)合采井各产层段贡献率主要受各产层段的孔隙度、渗透率及含气饱和度控制,其产层段孔隙度占主导地位;(2)储层压裂改造对于提高气井产量具有较大的作用,但对合采井各产层段的贡献率却很小;(3)对于致密高含水气藏而言,含气饱和度是合采井产层段贡献率及层间干扰的一个重要影响因子;(4)合采井各产层段之间的孔隙度级差、渗透率级差及含气饱和度级差直接影响着合采井层间干扰程度。结论认为:(1)合采井产层段的孔隙度越大、渗透性越好、含气饱和度越高,则产层段的产量贡献率越大;(2)合采井孔隙度、渗透率及含气饱和度3个参数的级差越大,层间干扰程度越大,当孔隙度级差大于1.248或渗透率级差大于2.69或含气饱和度级差大于1.22时,合采井层间干扰已经非常严重,亟需开展治理。

各向异性致密砂岩气藏分段压裂水平井气水两相产能预测模型

致密砂岩气藏具有储层物性差、孔喉结构复杂、各向异性强、初始含水饱和度覆盖范围大等特征,导致储层中流体的渗流机理复杂,为气井产能的准确预测及评价带来了巨大挑战。为此,基于气水两相非达西渗流理论,综合考虑储层各向异性、储层基质和裂缝不同程度的应力敏感性和两相启动压力梯度、高速非达西渗流效应、气体滑脱效应以及裂缝导流能力与缝间干扰等复杂因素,利用坐标变换、扰动椭圆理论、等价发展矩形理论、当量井径原理、压力叠加原理、水电相似原理等方法,建立了适用于各向异性致密砂岩气藏分段压裂水平井气水两相产能预测的新模型。通过矿场实例验证了新模型的准确性和实用性,并绘制了气水两相产能预测曲线,评价了敏感参数对产能的影响规律。研究结果表明:随着气体滑脱效应、裂缝导流能力、裂缝半长、裂缝条数、水平井井筒与地层主渗透率方向夹角的增大,压裂水平井的无阻流量增大;而随着储层各向异性、储层应力敏感性、裂缝应力敏感性、两相启动压力梯度、生产水气比增大,压裂水平井的无阻流量降低;水相对气相的流动具有抑制作用,且驱替压差越大,抑制作用越显著,因此需提前采取防水和治水措施。该研究成果进一步缩小了致密砂岩气藏产能预测结果与矿场实际产量的差距,有助于致密砂岩气藏的参数评估、动态预测以及产能评价和勘探开发决策制定。

东胜气田独贵气区高含水致密砂岩气藏气井合理工作制度

为了有效支撑高含水致密砂岩气藏高效开发,以鄂尔多斯盆地东胜气田独贵气区为研究对象,在研究高含水致密砂岩气井不同水气比条件下产出特征的基础上,分析了应力敏感及生产压差对气井产出的影响,评价了不同配产工作制度下气井的产出效果,提出了气井差异化配产方案及压降速率控制标准。研究结果表明:①研究区气藏储层孔喉组合以微孔细喉为主,具有低孔隙度—特低孔隙度、致密低渗透及强非均质性的特征;②高含水致密砂岩气藏气井开发效果受产水量影响较大,气井水气比越高,产气量递减越大、压降速率越快、弹性产率越低;③随着生产压差不断扩大,造成部分毛细管水和束缚水膜变成可动水,气井产水量增加,弹性产率变低,累计产气量减小,稳产难度增大,开发效果变差。结论认为:①对于衰竭式开发的高含水致密砂岩气藏,控制气井的配产和压降速率是延长气井稳产期、提高天然气采收率的重要手段;②所建立的高含水致密砂岩气藏气井差异化配产方案和气井压降速率控制图版在生产实践中证明符合率达到87.5%,可推广应用于同类型气藏的开发开采,更好地指导气井效益开发。

东胜致密低渗产水气藏水平井一点法产能模型研究

为进一步提升气藏产能预测的精度,针对东胜气田锦30井区作了水平井产能模型研究。借鉴Giger、Joshi、Borisov、陈元千等人提出的油藏水平井产能公式推导过程,并遵循渗流规律建立了气藏水平井产能公式;基于气相渗透率与含水率的拟合关系分析水气比对气井流入动态曲线的影响规律,发现不同水气比条件下的无因次流入动态曲线重合且为直线,但无阻流量受水气比的影响较大;提出产水气井无因次无阻流量新理念,建立了无因次无阻流量与水气比的关系式,进而在此基础上推导出一点法产能预测模型。

东胜气田A井区二叠系下石盒子组高含水气藏地质建模

为了精细描述致密高含水气藏可供开发调整的有利区、明确储集层参数的空间展布特征,以鄂尔多斯盆地东胜气田A井区二叠系下石盒子组气藏为研究对象,分析了适合高含水气藏的建模方法,综合岩心、测井、钻井等资料,借助Petrel软件建立了该区下石盒子组气藏三维地质模型。研究结果表明:①研究区整体上为北东高、南西低的宽缓单斜,区内发育两条正断层、小型鼻状隆起以及背斜构造;②盒1段河道及复合心滩规模较大,呈“砂包泥”状,盒2+3段河道及心滩规模相对较小,呈“泥包砂”状,研究区泥岩夹层占比为50%,粉砂岩夹层和致密层夹层占比为30%;③所建模型数据与实际钻井情况较为相符,能够快速高效地计算研究区天然气地质储量,计算出A井区下石盒子组气藏天然气地质储量为341.16×10^(8) m^(3)。结论认为:①利用精细水平井单层划分成果细化地层微构造可以建立全区精细构造模型;②建立水平井构型控制的沉积微相模型及隔夹层模型能有效提高物性参数模型的准确度和有效性;③沉积微相、岩石相、断层等主控因素约束的水平井气藏属性参数建模能有效提高物性参数模型的准确度和有效性,在致密高含水气藏“多、薄、窄、密、强、杂”型的储层空间中适用性好。

Theory, technology and prospects of conventional and unconventional natural gas

The development of natural gas in China has entered a golden and leap-forward stage, which is a necessary bridge to clean energy. This in-depth study on the status quo, theory, technology and prospect of natural gas development shows:(1) The global remaining proven recoverable reserves of natural gas are 186×1012 m3, and the reserves-production ratio is 52.4, indicating a solid resource base for long-term and rapid development.(2) Ten formation and distribution laws of conventional and unconventional natural gas reservoirs have been proposed. In terms of exploration geology, the theory of conventional "monolithic" giant gas fields with different gas sources, and an unconventional gas accumulation theory with continuous distribution of "sweet areas" in different lithologic reservoirs have been established; in terms of development geology, a development theory of conventional structural gas reservoirs is oriented to "controlling water intrusion", while a development theory of unconventional gas is concentrated on man-made gas reservoirs.(3) With the geological resources(excluding hydrates) of 210×1012 m3 and the total proven rate of the resources less than 2% at present, the natural gas in China will see a constant increase in reserve and production; by 2030, the proven geological reserves of natural gas are expected to reach about(6 000-7 000)×108 m3, the production of conventional and unconventional natural gas each will reach about 1 000×108 m3, and the gas consumption will reach 5 500×108 m3. The dependence on imported natural gas may be 64% by 2030, and 70% by 2050.(4) Ten measures for future development of natural gas have been proposed, including strengthening exploration in large-scale resource areas, increasing the development benefits of unconventional gas, and enhancing the peak adjusting capacity of gas storage and scale construction of liquified natural gas.

致密含水气藏气井提高配产对开发效果影响研究

致密含水气藏具有低压、低孔、低渗、非均质性强、含气饱和度低以及孔喉细小等储层特征。为了研究提高配产对致密含水气藏气井开发效果的影响,对比分析了提高配产前后不同提高配产比例和不同液气比气井的压力、单井最终可采储量(EUR)及阶段累产气等开发参数。研究结果表明:1)提高配产比例及气井液气比越大,气井EUR下降幅度也越大;当气井提高配产比例大于50%或液气比大于5 m^(3)/(×10^(4) m ^(3))时,EUR下降比例可达40%。2)致密含水储层应力敏感程度增幅7%~12%,且含水饱和度越高,应力敏感程度越强,渗透率急剧降低。3)生产压差增大,参与流动的地层水增多,近井地带更易积液且积液范围将扩展至地层中部,造成采收率大幅下降。4)井筒内液滴回落,流体侵入储层容易引起近井地带水锁,造成气相渗流能力大幅下降。该研究成果对同类型含水气藏科学合理开发有指导意义。

底水气藏水侵规律数值模拟研究:以元坝长兴组气藏为例

有水气藏开发过程中,边底水的侵入严重影响气井产能,但是目前对底水气藏水侵规律缺乏深层次认识。为此,基于元坝长兴组气藏2类产水气井生产特征,结合气藏实际地质特征、水体性质及气-水界面关系,分别设计直井和水平井水侵机理数值模拟模型,重点分析采气速度、水体大小、致密层连通性及避水高度等因素对生产及水侵影响规律。研究结果表明:(1)采气速度是影响水侵的主要因素,水体一定,采速越高,水侵越快,气井稳产期越短,水平井在一定程度上能有效抑制水侵;(2)水体大小是影响水侵重要因素,水体倍数越大,水侵越严重,气井稳产期越短;(3)致密性夹层能在一定程度上抑制水侵,渗透性夹层(Kiz=100%Kz)对应的底水锥进速度最快,稳产期最短;(4)随着避水高度的增加,水气比上升变缓,气井见水时间变晚。结论认为:对于底水气藏,保持合理的生产压差或优化配产是控制底水快速锥进的关键;若储层中天然致密层无效,则可通过建立较低垂向连通性的人工隔夹层(致密夹层)抑制底水锥进;同时,钻井设计或后期补射孔时,需兼顾射开程度和避水高度对生产的影响。本文研究成果以期为底水气藏高效开发提供理论指导。