A new mathematical model for horizontal wells with variable density perforation completion in bottom water reservoirs

Horizontal wells are commonly used in bottom water reservoirs,which can increase contact area between wellbores and reservoirs.There are many completion methods used to control cresting,among which variable density perforation is an effective one.It is difficult to evaluate well productivity and to analyze inflow profiles of horizontal wells with quantities of unevenly distributed perforations,which are characterized by different parameters.In this paper,fluid flow in each wellbore perforation,as well as the reservoir,was analyzed.A comprehensive model,coupling the fluid flow in the reservoir and the wellbore pressure drawdown,was developed based on potential functions and solved using the numerical discrete method.Then,a bottom water cresting model was established on the basis of the piston-like displacement principle.Finally,bottom water cresting parameters and factors influencing inflow profile were analyzed.A more systematic optimization method was proposed by introducing the concept of cumulative free-water production,which could maintain a balance（or then a balance is achieved）between stabilizing oil production and controlling bottom water cresting.Results show that the inflow profile is affected by the perforation distribution.Wells with denser perforation density at the toe end and thinner density at the heel end may obtain low production,but the water breakthrough time is delayed.Taking cumulative free-water production as a parameter to evaluate perforation strategies is advisable in bottom water reservoirs.

Analysis of Factors Influencing Shut in Pressure Cone in Offshore Strong Bottom Water Reservoir

X oilfield is an offshore strong bottom water reservoir with water cut up to 96% at present, and liquid extraction has become one of the main ways to increase oil production. However, the current liquid production of the oilfield reaches 60,000 m3/d due to the limitation of offshore platform, well trough and equipment, the oilfield is unable to continue liquid extraction. In order to maximize the oil production of the oilfield, it is necessary to study the strategy of shut in and cone pressure. Through numerical simulation, this paper analyzes the influence of different factors, such as crude oil density, viscosity, reservoir thickness, interlayer, permeability and so on, on the drop height of water cone and the effect of precipitation and oil increase after well shut in. At the same time, the weight of each factor is analyzed by combining the actual dynamic data with the fuzzy mathematics method, and the strategy of well shut in and cone pressure is formulated for the offshore strong bottom water reservoir. It provides the basis and guidance for the reasonable use of shut in pressure cone when the reservoir with strong bottom water meets the bottleneck of liquid volume.

Study on Water Ridge Variation of Horizontal Wells in Bottom Water Reservoir

X oilfield is a typical strong bottom water reservoir in Bohai Sea. It is developed by single sand body horizontal well. The edge and bottom water of the reservoir is active and natural energy development mode is adopted. At present, the comprehensive water cut of the oilfield is more than 96%, and has entered the stage of high water cut oil recovery. At present, fluid extraction from old wells and new adjustment wells are the main ways to increase oil production. With the deepening of development, the distribution of underground remaining oil is becoming more and more complex. In order to further improve the implementation effect of adjustment wells, the study of residual oil distribution law is increasingly important, and the study of water ridge morphology of horizontal wells in bottom water reservoir has an important guiding role in the study of remaining oil distribution. The main contents of this paper are as follows: the influence of horizontal well spacing, vertical and horizontal permeability ratio, single well liquid production, vertical position of horizontal well, oil-water viscosity ratio, water cut and interlayer on water ridge morphology. These understandings can effectively guide the deployment and optimization of adjustment wells. It provides technical support for the prediction of watered out thickness and optimization of adjustment well layout scheme in X oilfield, and guides the further development and production of the oilfield.

Identification of Interlayer in Strong Bottom Water Reservoir and Its Influence on Development Effect

X oilfield is located in Bohai Sea area, in which G oil formation is a typical drape anticline structure, which is composed of multiple sets of thick sandy conglomerate and multiple sets of argillaceous intercalation. From the perspective of development effect, muddy interlayer has a great impact on the oilfield. In this paper, through core identification and well logging identification, the electrical discrimination standard is summarized to identify the interlayer. Through statistics and analysis of the production performance of actual wells, the influence of muddy interlayer on the development performance of oil wells is summarized. This study provides guidance for the development of strong bottom water reservoirs with interlayer.

Critical parameters of horizontal well influenced by semi-permeable barrier in bottom water reservoir

It is well-known that barriers have a significant impact on the production performance of horizontal wells developed in a bottom water drive reservoir. In most cases, reservoir barriers are semi-permeable. Based on previous research on impermeable reservoir barrier, a mathematical flow model was derived for a horizontal well of a bottom water drive reservoir with a semi-permeable barrier. Besides, analytical equations were also presented to calculate critical parameters, such as production rate,pressure and potential difference. The effects of barrier, well and reservoir parameters on our model results were further investigated.The results show that the larger the barrier size is or the higher the barrier location is, the higher the critical production rate and potential difference of a horizontal well are. When the barrier permeability equals the formation permeability or the barrier width equals zero, the critical production rates converge to the values same to that of the case with no barrier. When the barrier permeability equals zero, the problem is regarded as a case of impermeable barrier. This model can be applied to predicting horizontal wells' critical production parameters in reservoirs with semi-permeable barriers.

Remaining oil distribution in (Ng_3)~3 bottom water reservoir of Lin 2-6 fault-block in Huimin depression and potential tapping in horizontal well

Oil reservoirs with secondary bottom water in Ng33 members (in Guantao formation, Paleogene system) of Lin2-6 fault block in Huimin depression (Bohai Bay Basin) have entered the late stage of ultra-high water-containing-exploitation. Oil exploitation from vertical wells is becoming more and more inefficient. The reservoir type, with water displacing oil and the remaining oil distribution are specifically studied in order to improve the efficiency of the recovery ratio. An integrated scheme for adjusting horizontal wells has been designed and the key technique of the scheme optimized. The study shows that: 1) the positive rhythm of fluvial depositional features is the internal cause of the flooding of oil reservoirs while water injection, injection-production patterns and accumulative petroleum production are the external causes; 2) oil-water driving patterns have transferred from edge water advancing to bottom-water-coning; distribution of the remaining oil mainly concentrates in the upper rhythm and top of the middle rhythm in Ng33 members; 3) a great deal of remaining oil is enriched in high positions of faults, in axes of tiny structures, in stagnation areas among water-injection wells and oil-wells and in tectonic saddle areas with sparse wells. Compared with vertical wells, horizontal wells have advantages such as high recovery, high off-take potential, high critical output, large controlling areas and long time of bottom-water breakthrough.

A novel method for predicting breakthrough time of horizontal wells in bottom water reservoirs

Dimensional analysis and numerical simulations were carried out to research prediction method of breakthrough time of horizontal wells in bottom water reservoir. Four dimensionless independent variables and dimensionless time were derived from 10 influencing factors of the problem by using dimensional analysis. Simulations of horizontal well in reservoir with bottom water were run to find the prediction correlation. A general and concise functional relationship for predicting breakthrough time was established based on simulation results and theoretical analysis. The breakthrough time of one conceptual model predicted by the correlation is very close to the result by Eclipse with less than 2% error. The practical breakthrough time of one well in Helder oilfield is 10 d, and the predicted results by the method is 11.2 d, which is more accurate than the analytical result. Case study indicates that the method could predict breakthrough time of horizontal well under different reservoir conditions accurately. For its university and ease of use, the method is suitable for quick prediction of breakthrough time.

The Residual Potential of Bottom Water Reservoir Based upon Genetic Algorithm for the Relative Permeability Inversion

X oilfield has successfully adopted horizontal wells to develop strong bottom water reservoirs, as a typical representative of development styles in the Bohai offshore oilfield. At present, many contributions to methods of inverting relative permeability curve and forecasting residual recoverable reserves had been made by investigators, but rarely involved in horizontal wells’ in bottom water reservoir. As the pore volume injected was less (usually under 30 PV), the relative permeability curve endpoint had become a serious distortion. That caused a certain deviation in forecasting residual recoverable reserves in the practical value of field directly. For the performance of water cresting, the common method existed some problems, such as no pertinence, ineffectiveness and less affecting factors considered. This paper adopts the streamlines theory with two phases flowing to solve that. Meanwhile, based on the research coupling genetic algorithm, optimized relative permeability curve was calculated by bottom-water drive model. The residual oil saturation calculated was lower than the initial’s, and the hydrophilic property was more reinforced, due to improving the pore volume injected vastly. Also, the study finally helped us enhance residual recoverable reserves degree at high water cut stage, more than 20%, taking Guantao sandstone as an example. As oil field being gradually entering high water cut stage, this method had a great significance to evaluate the development effect and guide the potential of the reservoir.

Adaptability of Development Methods for Offshore Gas Cap Edge Water Reservoirs under Different Permeability Levels

The BZ 34-1 oilfield is a typical gas cap edge water reservoir in the Bohai oilfield. The main characteristics of the oilfield were multi-phase sand body stacking and the sand body was composed of three parts: gas cap, oil reservoir, and edge water. The actual production site results show that the permeability difference of multi-layer sand bodies has a serious impact on the development effect. This article establishes a typical reservoir model numerical model based on the total recovery degree of the reservoir and the recovery degree of each layer, and analyzes the impact of permeability gradient. As the permeability gradient increases, the total recovery degree of all four well patterns decreases, and the total recovery degree gradually decreases. The recovery degree of low permeability layers gradually decreases, and the recovery degree of high permeability layers gradually increases. As the permeability gradient increases, the degree of recovery gradually decreases under different water contents. As the permeability gradient increases, the reduction rate of remaining oil saturation in low permeability layers is slower, while the reduction rate of remaining oil saturation in high permeability layers was faster. By analyzing the impact of permeability gradient on the development effect of oil fields, we could further deepen our understanding of gas cap edge water reservoirs and guide the development of this type of oil field.

The critical rate of horizontal wells in bottom-water reservoirs with an impermeable barrier

Barrier impacts on water cut and critical rate of horizontal wells in bottom water-drive reservoirs have been recognized but not investigated quantitatively. Considering the existence of impermeable barriers in oil formations, this paper developed a horizontal well flow model and obtained mathematical equations for the critical rate when water cresting forms in bottom-water reservoirs. The result shows that the barrier increases the critical rate and delays water breakthrough. Further study of the barrier size and location shows that increases in the barrier size and the distance between the barrier and oil-water contact lead to higher critical rates. The critical rate gradually approaches a constant as the barrier size increases. The case study shows the method presented here can be used to predict the critical rate in a bottom-water reservoir and applied to investigate the water cresting behavior of horizontal wells.

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.

Study of the Law about Water-Cut Variation for the Fractured Metamorphic Reservoir of Buried Hill with Bottom Water

Aiming at the complex flowing environment including the buried hill of Metamorphite, the active bottom water and the fracture at Budate Reservoir within Beir Depression of the Hailar Basin, combining the laboratory studies and based on analysis of its drive mechanism, field wells’ parameters were used to analyze the effects of different conditions of the fractured metamorphic reservoir with bottom water on its law of wa-ter-cut variation and the waterflooding efficiency. The results show that for the Budate buried hill reservoir with bottom water, the gravity should be taken into consideration to determine reasonable perforation ratio and production pressure difference. And because of the acid sensitivity of the buried hill reservoir, application of proper clay stabilizer will enhance the field oil recovery to a satisfactory extent.

Easy Determination of Water Influx in Reservoirs

This p aper presents two methods for easy determination of water influx in reservoirs based on the material balance theory of reservoirs,i.e.,the Net Production V olume Curve,and the Production Index Curve.These methods can be used for esti-ma tion of water influx in reservoirs without any assumption of aquifer shape and size by applying the production performance data.Hence the tedium of the c onventional trial-and-error calculations and obvious uncertainty could be over come in ap plication of the easy and practical new methods.

衰竭底水气藏注CO_(2)提高天然气采收率与碳封存机理

气藏注CO_(2)提高天然气采收率并实现碳封存有望成为大幅度提高天然气产量与碳减排协同的潜在关键技术。为了给底水气藏注CO_(2)高效开发提供指导,针对地层水盐度对CO_(2)-CH_(4)-H_(2)O-NaCl体系相平衡影响、气藏注气过程中压力变化对CO_(2)-CH_(4)-H_(2)O-NaCl体系相平衡影响、注采方案对注CO_(2)提高气藏采收率影响、盐度对注CO_(2)提产及封存影响等目前认识不清的问题开展了CO_(2)-CH_(4)-H_(2)O-NaCl体系相平衡规律及注CO_(2)提采与封存数值模拟研究。研究结果表明:①随着盐度增加,CO_(2)和CH_(4)在盐水中的溶解度降低,液相的密度和黏度增加,盐度对气相性质几乎没有影响;②随着压力增加,CO_(2)和CH_(4)在液相中的溶解度均增加,气相、液相密度和黏度均增加,液相偏差因子随压力增加而增加,气相偏差因子先减小后增加;③同注同采方案CH_(4)产量更稳定且产出的CO_(2)少,而先注后采方案则会加速CO_(2)与CH_(4)的混合,CO_(2)封存量低,前者更适合注CO_(2)提采及封存;④在不考虑盐析效应的前提下,盐度对CH_(4)采收率和CO_(2)封存量的影响几乎可以忽略不计,不同盐度的衰竭底水气藏中CH_(4)采收率均超过80%、CO_(2)封存率均超过99%,短期注CO_(2)过程中,CO_(2)主要以气态或超临界态的形式被封存,少部分CO_(2)溶解在液相中,100年后CO_(2)在液相中的溶解质量分数约为5%。结论认为,衰竭底水气藏注CO_(2)能增压补能、驱替置换残余天然气,提高采收率并实现碳封存。

基于BP神经网络的低渗透底水油藏油井见水模式预测模型

注水开发使得低渗透底水油藏油井见水模式更加复杂,需要进一步明确及预测油井见水模式来针对性地指导水淹治理措施。神经网络模型具备处理多元回归问题和计算速度快等优势,可被用于分析地质工程多因素参数与油井见水模式的内在关系,构建见水模式预测模型。在油井见水模式划分的基础上,通过灰色关联理论和神经网络算法对BCL低渗透底水油藏油井见水模式的主控因素和预测模型进行了研究。发现水层厚度、隔夹层数、隔夹层长度和避水高度是该类油藏注水开发下影响油井见水模式的主控因素。基于主控因素结合神经网络算法建立了油井见水模式预测模型。通过对18组测试数据进行验证,平均预测误差1.4%,获得了较好的预测精度。通过易于获取的主控因素快速预测注水开发低渗透底水油藏油井的见水模式,为该类油藏的高含水针对性治理提供基础依据。

N区块底水油藏不同夹层油井见水时间预测公式参数优化

底水油藏底水锥进,使油井过早见水,导致含水率快速上升,产油量快速递减,为改变这些不利因素,提前预测油井的见水时间显得尤为重要。通常,底水油藏按照夹层渗透性质可分为无夹层井区和不渗透性夹层井区。本研究首先选用合理的预测见水时间公式,结果表明无夹层井区油井预测见水时间与实际见水时间最大绝对误差为11.1 d,最大相对误差5.6%;不渗透性夹层井区油井预测见水时间与实际见水时间最大绝对误差为19.0 d,最大相对误差7.2%;此外,在无夹层井区添加人工隔板抑制底水锥进,可使该井区的油井见水时间得到不同程度的延缓。本研究运用Eclipse数值模拟软件优化最佳地层垂向渗透率系数α,结果表明采出程度为20.1%,较未优化前提高了3.9%;综合含水率下降了4.7%,累计产油量增加了250×10^(3)m^(3)。最后,鉴于不渗透性夹层见水时间可受多种因素影响,本研究采用正交试验设计并结合各因子R值结果可见极差最大是夹层半径rb,根据极差排序将影响模型预测见水时间参数由大到小排序,排序结果得到最佳组合方案,即:夹层半径r_(b)>夹层距油水界面高度h_(b)>油井的打开程度b>产油量q_(o),方案使得预测累计产油量增加了383×10^(3)m^(3)(5%),采出程度提高了4%。

薄层砂岩边底水油藏空气辅助内源微生物驱油技术

针对边底水油藏“双高阶段”零散分布剩余油如何有效动用、低成本高效微生物驱油体系如何研发、微生物驱效果评价及配套技术攻关等难题,建立微生物驱筛选图版并评价了油藏微生物驱的适应性;利用微生物分子生态学技术全面解析了油藏微生物群落结构,筛选了乳化效果好的采油功能菌株H3;通过对主要营养成分碳源、氮源、磷源的筛选,开展单因素实验和正交实验,确定了可实现原油乳化分散和抑制硫酸盐还原菌生长的复合粉激活体系;研究了底水油层“船底形”剩余油富集特征,形成了“微生物乳化+空气提效+稠化剂封堵”提高采收率驱油模式,明确了提高采收率幅度与注入菌体浓度、注入孔隙体积倍数正相关。将研究成果应用于准噶尔盆地陆梁油田薄层砂岩边底水油藏,实施“4注20采”微生物驱提高采收率矿场先导试验,注入微生物激活剂0.13倍孔隙体积,2017至2023年阶段增油5.6×104 t,采收率提高4.0个百分点,增油效果好的井主要分布在总菌浓度高、石油地质储量大、构造高部位、油层厚度大、底水薄、采出程度较高的区域。研究成果对丰富微生物驱提高采收率技术序列具有借鉴作用。

底水油藏水侵量计算新方法

针对底水油藏的开发,在缺乏试井数据的情况下采用常规油藏物质平衡法以及试井分析方法均难以确定水驱控制储量,进而无法获得水体参数和特征来计算油田的水侵量。为了更加准确的预测水驱油田水侵量,结合生产动态资料,选择符合的水驱特征曲线计算水驱控制储量。在此基础上,考虑油环油、溶解气、水体等因素,建立物质平衡方程,通过亏空体积曲线法计算获得水侵量。利用Fetkvoitch拟稳态模型,采用试错法,优化计算水体体积和水侵系数,保证Fetkvoitch拟稳态模型求解的水侵量和亏空体积曲线法求解的水侵量最接近,得到最优的水体体积和水侵系数对未来生产动态中水侵量进行预测。运用油藏数值模拟软件建立的模型与本文提出两种的计算方法拟合结果对比可知的水体体积的误差为2.6%、水侵指数的误差为2.2%,计算结果准确,为底水油藏计算水侵量提供了可靠的依据,并为预测水侵量提供了新的方法。

吴A区侏罗系油藏黏弹自调剂调驱效果分析

吴A区延9、延10底水油藏于2017年开始水驱动用程度大幅度下降,只有38.0%,受重力影响,吸水段逐渐下移,受地层平面非均质性和层间非均质性强、前期注入强度和采液强度大的影响,底水过早锥进导致油井见水,甚至见注入水发生水淹,常规堵水调剖措施无法完成地层深部地带封堵。为延缓注入水沿大孔道和微裂缝等地层深部高渗通道突进,提高注入水的波及体积,改善吸水剖面,吴A区延9、延10油藏于2022年8月开展黏弹自调剂调驱矿场试验。试验结果表明,2022年8月-2023年10月注入黏弹自调剂后,调驱效果较好,深入地层后能有效滞留于孔喉,平均单井日注水量下降,注入压力由7.20MPa上升到7.80MPa;整体吸水指数由38.1m^(3)/(d·MPa)下降到25.1m^(3)/(d·MPa);黏弹自调剂在地层中形成有效封堵,有效改善油水流度比以及提高洗油效率,注入黏弹自调剂后月度递减率由0.10%下降到-0.40%,月度含水率上升幅度由0.03%下降到0.02%。

底水油藏底水分布规律及射孔参数优化——以周长油田延安组油藏为例

为了明确射孔参数底水油藏开发的影响,针对由于早期布井随意性较大,无井网格局,无具体的开发方案,导致研究区采油速度低、递减快,稳产难度大的问题,运用油藏地质参数分析和油藏数值模拟的研究方法,分析不同射孔参数条件下,不同类型底水油藏开发效果。结果表明:1)研究区主力油层延10层底水发育,水井射孔注水厚度大小不一,对应油井受效和开采效果有明显差异;2)依据夹层分布和油水接触关系,目标油藏分为直接接触型、不稳定夹层型和稳定夹层型3类;3)Ⅰ类底水直接接触型水井射孔程度越高,越有利于抑制底水突进;最优油井射孔程度约为2 m;4)Ⅱ类/Ⅲ类型隔层分隔底水型水井射孔程度越高,开发效果越好;油井射孔程度约为70%时,开发效果好。该研究成果对同类型底水油藏开发参数设计及稳油控水提高采收率具有指导意义。