Due to the complex reservoir types and strong heterogeneity of fractured–vuggy reservoirs with aquifers, evaluating such reservoirs’ dynamic reserves and aquifer size is challenging. This paper established a segmented elastic-drive material balance equation based on the material balance principle by combining the functional relationships among the crude oil volume factor, crude oil compressibility, and formation pressure. The PELT algorithm was used to segment the water invasion stages, and nonlinear least squares fitting was employed to determine the rock compressibility, dynamic reserves, and aquifer size of fractured–vuggy reservoirs. This study shows that production in fractured–vuggy reservoirs with aquifers can be divided into three stages: no water invasion, initial water invasion, and full water invasion. Rock compressibility and dynamic reserves can be calculated using production data from the no water invasion stage, while the aquifer size can be determined from data in the water invasion stage. Influenced by connectivity and production regulations, aquifers may not be fully affected by pressure waves, causing the aquifer size to increase gradually until stabilization. Compared with numerical simulation data, the method presented in this paper achieves errors of 0.34%, 0.67%, and 1.19% for rock compressibility, dynamic reserves, and aquifer size, respectively.

The Tarim Basin boasts significant reserves of deep, high-pressure natural gas. However, these reservoirs encounter challenges as actual development outcomes fall short of planned expectations. Ultra-deep fractured low-porosity sandstone gas reservoirs are characterized by deep burial, dense matrix, and well-developed fractures. Using the DA gas reservoir as an example, this paper conducts multidisciplinary joint research and has developed new dynamic characterization methods such as physical simulation, modeling, and numerical simulation for such water-bearing gas reservoirs. A novel large-scale physical simulation device was developed to more accurately simulate water invasion dynamics, surpassing traditional core-scale models in realism. A comprehensive approach includes field observations, core analysis, imaging logs, well tests, production data, and water invasion simulation experiments, alongside development practice verification, to systematically explores these dynamics. Additionally, the study incorporates geological and numerical simulation methods that account for changes in the dynamic stress and permeability fields, establishing a model for fracture behavior over time and space. This method yields historical and predictive results that align closely with actual production dynamics. Firstly, physical simulation experiments (820*420*50 mm) confirm that large fractures serve as principal flow pathways during triple media permeation, with edge and bottom water advancing swiftly through these channels. The study on DA gas reservoir highlights several key findings regarding its fracture systems and dynamics. Secondly, the north–south fault system is more open and effective than the east–west system, with fracture development peaking at the core, diminishing westward, and least pronounced at the wing. These fractures are less filled and have a smaller angle, mainly occurring around 20 m at the base, influenced by fault planes, micro-faults, and lithology. Numerical modeling indicates that the bottom water in the south rapidly invades the top areas along the north–south oriented fractures, causing the wells in the top areas to encounter water earlier than those in the lower areas of the eastern and western wings. The degree of fracture development in the eastern and western wings is low, and the speed of edge water invasion is relatively slow. Based on water invasion performance, a development strategy of “controlling high areas and draining low areas” is proposed, which is expected to increase the recovery by 5

Assessment for water control management is critical to economically develop naturally fractured gas reservoirs, of which the profitability is heavily influenced by the water invasion. Water intrusion can occur through several mechanisms such as water coning/fingering/channeling through fractures that connect the water zone to the wellbore. Therefore, understanding water intrusion mechanisms plays a vital role in maximizing such reservoirs’ recovery and avoid workover costs. This study starts by establishing a base case reservoir with a water zone and non-producing zone, in which the well is located. Natural fracture (NF) paths are generated to connect the wellbore and the water zone and are numerically simulated by embedded discrete fracture model (EDFM). In order to fully apprehend variables that affect the shape and magnitude of water flow rates, 7 parameters. These include number of NF paths, lengths of NF paths, conductivity of NF paths, relative permeability of NF paths, number of natural fractures within water zone, production pressure drawdown, and water zone permeability. The simulated results of water flow rates are compared summarized between different scenarios of each sensitivity parameter. The following major observations are found. First, the more or the longer the NF paths, the more water intrusion time is delayed. The conductivity of NF paths affects water break through time and its magnitude. Lastly, the production pressure drawdown also affects both the intrusion time and the amount of intrusion. This investigation adds crucial information to field modeling and vastly helps guide the decision-making process of wells operation by anticipating water intrusion behaviors through NF paths.

The Tarim Basin's fractured-vuggy reservoirs have been discovered on a large scale in recent years, with annual production reaching tens of millions of tons. However, due to the complex interrelationships of reservoir pores, fractures, and cavities, the evaluation of the reserves and types through conventional waterflooding methods remains highly limited. Due to the significant differences between actual fractured-vuggy reservoirs models and traditional water injection indication curve models that treat the reservoir as homogeneous, a new water injection indication curve model has been proposed. This model considers various types of elastic energy changes and is suitable for fractured-vuggy carbonate reservoirs driven by bottom water. By plotting the relationship curves between stratigraphical pressure and cumulative injection volume, the study established graphs depicting the average formation pressure versus cumulative injection volume under different dynamic reserves and water influx scenarios. Adjustments to the dynamic reserves and water influx were made by fitting the actual pressure trends, effectively predicting reservoir pressure changes under various injection and production intensities. The research demonstrated that the pressure changes within the fractured-vuggy reservoirs calculated by this method closely match the actual changes. The reliability of this method was validated using data from the MX1 well group, yielding more accurate dynamic reserve and water influx curves. The water injection indication curve model for bottom water driven fractured-vuggy reservoirs established in this study clarifies the replenishment of reservoir pressure and accurately assesses the energy of the water body and the scale of the reserves. It plays a crucial role in formulating rational water injection development strategies and enhancing the displacement efficiency of fractured-vuggy units.

Based on the tectonic genesis and seismic data of fault-controlled fractured-vuggy reservoirs, the typical fractured-vuggy structure features were analyzed. A 3D large-scale visual physical model of “tree-like” fractured-vuggy structure was designed and made. The experiments of bottom-water flooding and multi-media synergistic oil displacement after bottom-water flooding were conducted with different production rates and different well-reservoir configuration relationships. The formation mechanisms and distribution rules of residual oil during bottom-water flooding under such fractured-vuggy structure were revealed. The producing characteristics of residual oil under different production methods after bottom-water flooding were discovered. The results show that the remaining oil in “tree-like” fractured-vuggy structure after bottom-water flooding mainly include the remaining oil of non-well controlled fault zones and the attic remaining oil at the top of well controlled fault zones. There exists obvious water channeling of bottom-water along the fault at high production rate, but intermittent drainage can effectively weaken the interference effect between fault zones to inhibit water channeling. Compared with the vertical well, horizontal well can reduce the difference in flow conductivity between fault zones and show better resistance to water channeling. The closer the horizontal well locates to the upper part of the “canopy”, the higher the oil recovery is at the bottom-water flooding stage. However, comprehensive consideration of the bottom-water flooding and subsequent gas injection development, the total recovery is higher when the horizontal well locates in the middle part of the “canopy” and drills through a large number of fault zones. After bottom water flooding, the effect of gas huff and puff is better than that of gas flooding, and the effect of gas huff and puff with large slug is better than that of small slug. Because such development method can effectively develop the remaining oil of non-well controlled fault zones and the attic remaining oil at the top of well controlled fault zones transversely connected with oil wells, thus greatly improving the oil recovery.

Abstract With complicated accumulation mechanism of fractured-caved carbonate formations, characterization of reservoir and fluid distribution has great uncertainty due to varied oil-water contact and discontinuous reservoir, which brings difficulties to refined reservoir characterization and development index prediction. However, wells are always completed in upper part of the reservoir, instead of drilled through the pay zone, leaving the oil-water contact unknown below the well. It's urgent for a reservoir unit to confirm the oil-water contact. In the study, a method is proposed to constrain the pore volume and aquifer volume in a fractured-caved model based on the projection of water injection data. A material balance equation set of cyclic water injection in the fractured-caved reservoir is used to calculate the total volume of the connected reservoir drained by wells and distinguish the volume proportion of water in the fluid, according to the formation pressure recovery caused by the certain water injection volume in each cycle. A geological model is built via multi-attribute modeling technology and then modified by the outcome of former dynamic reserve evaluation. The seismic attribute threshold of reservoir extraction is controlled by the total reservoir volume, thus the volume of geological model determined. The depth of oil-water contact is adjusted to fit the oil and water volumes related to the water volume ratio, finally a reasonable oil-water contact obtained. Fractured-caved reservoir model and oil-water contact depth are further verified and corrected by drilling and completion data, oil testing and water production data. The feasibility and reliability of the method are demonstrated by a case study in Tarim Oilfield, where the depth of oil-water contact is deduced as −6342m from the first producer in the reservoir unit, and the oil testing of second producer supports it. The method can be applied to single wells or well groups in fractured-caved reservoir that have not yet seen water breakthrough after water injection. It can improve the geological understanding of the reservoir, evaluate the development potential of water injection, and predict the water breakthrough, helpful to the adjustment of development measures.

In practical oilfield production, the phenomenon of water influx typically shortens the water-free recovery period of wells, leading to water flooding and causing a sharp decline in the production well yields, bringing great harm to production. Water invasion usually occurs as a result of the elastic expansion of the water as well as the compaction of the aquifer pore space. However, it can be due to the special characteristics of fractured-vuggy reservoirs such as non-homogeneity and the discrete distribution of the pore spaces. It is challenging to use traditional seepage flow theories to analyze the characteristics of water influx. Also, reservoir numerical simulation methods require numerous parameters which are difficult to obtain, which significantly reduces the accuracy of the results. In this study, considering the driving energy for water influx, a water influx characteristic model was obtained by fitting a graph plate. Subsequently, an iterative calculation method was used to simultaneously obtain water influx volume and OOIP. The aquifer to hydrocarbon ratio was determined by fitting the water influx curve with the graphic plate. Results show that the calculation method is sensitive to the values of reservoir pressure and the crude oil formation volume factor. After applying the method to one field case, it was discovered that water influx performance can be characterized into two types, i.e., linear water influx and logarithmic water influx. In the early stages, the water influx rate of logarithmic water influx is greater compared to linear water influx. However, the volume and energy of waterbody are limited, and the water invasion phenomenon occurs almost exclusively within a short period after the invasion. On the other hand, the volume of waterbody invaded by linear water influx is larger, and it can maintain a stable rate of water influx. The results of the study can provide theoretical support for the waterbody energy evaluation and dynamic analysis of water influx, as well as the control and management of water in these types of reservoirs.

The karst fractured-vuggy reservoirs in the Tarim Basin of China have abundant reserves, and show enormous development potential. This type of reservoirs is highly heterogeneous, with multiple storage types such as matrix, fractures, and karst caves coexisting, and the fractured-vuggy combination patterns and the oil-water relationships are very complex. The unclear understanding of the distribution of remaining oil leads to large differences in development effects. How to achieve efficient development of karst fractured-vuggy reservoirs is a serious technical challenge. In this article, based on the typical connected structure patterns of fractured-vuggy units, and by using 3D printing technology, 2D and 3D simulation physical models of fractured-vuggy combinations that meet geometric similarity, motion similarity, dynamic similarity, and characteristic parameter similarity were designed. Indoor water and gas flooding displacement experiments were conducted to study the fluid flow mechanism and remaining oil distribution in the fractured-vuggy combinations, and to reveal the control mechanism of the fractured-vuggy connected structure. The study shows that under fracture injection and cave production mode, the oil-water displacement is more uniform, the remaining oil is retained less, and the water injection effect is better. Due to the high flow rate of gas in the fractured-vuggy medium and the easy occurrence of gas channeling, the gas injection effect under the cave injection and fracture production mode is significantly better than that of the fracture injection and cave production mode. For situations with multiple fractures and caves, during water injection and gas injection development, the efficiency of producing nearby caves is higher, and the remaining oil in distant caves and the top of fractures is distributed in a continuous pattern. The connection relationship between fractures and caves has a significant influence on the distribution of remaining oil, but the injection rate has little effect on the distribution of remaining oil. The water-flooded remaining oil in the 3D fractured-vuggy physical model is mainly distributed in three patterns: attic pattern, low-amplitude residual hill pattern, and blind end pattern. This article provides a method reference for studying the distribution pattern of remaining oil and the optimization design of development plans for similar types of reservoirs.

Discrete reservoirs are commonly seen in fractured-caved carbonate reservoirs. The effect of cyclic huff-n-puff in single well and water flooding in well group is varied for different wells. Some wells fail in water injection stimulation due to unforeseen high water cut. Therefore, it is necessary to estimate the displacing potential of water injection after its start and adjust the development strategy in time. The oil volume and water volume are required to be distinguished from the drainage pore volume of an isolated reservoir besides the conventional dynamic reserve evaluation. Based on the material balance principle, a mathematical model for dynamic reserve evaluation is established considering the volume ratio of oil and water. Then controlling equation describing the relationship between pressure recovery and water volume ratio in reservoir is combined with boundary conditions at time nodes before and after water injection to numerically solve the model. The dynamic reserve of crude oil and water can be accurately concluded to deepen the understanding of oil-water distribution characteristic in fractured-caved reservoirs. The method has been proved to meet the actual production after the application in Halahatang Oilfield in Tarim Basin, providing a reliable potential estimation for subsequent recovery enhancement measures.

In fractured-caved carbonate oil reservoirs with well-developed dissolved caves, most of the caves are generally connected by large fractures to form separate and independent fractured-caved systems. The oil well basically intersects some fractures, and fractures connect one or two large-scale dissolved caves in series or parallel model to form an independent fractured-caved unit. Moreover, due to the large size of the dissolved cave in the fractured-caved unit, it no longer follows Darcy's law, but shows features belongs to pipe flow, free flow or a seepage-pipe flow. In this case, the conventional equivalent multiple porous media seepage mathematical model is inaccurate to characterize this kind of fractured-caved reservoir units. This study simplifies the structure of the large bead-shaped fractured-caved reservoir and shows how the well-cave and cave-cave units are connected through fractures. Results show that the connected fracture flow exsits in the periphery of the large cave dissolved caves in the area far from wells. Thus either a linear series or a parallel mathematical model is applied to simulate the connection of the two dissolved caves. The fluid flow in fractures is still considered as seepage flow, while in large dissolved caves it is considered as free flow. Therefore, the dual-cave dual-fracture series mathematical model and dual-cave single-fracture parallel mathematical model considering seepage-free flow coupling are established. Laplace transform is then used to mathematically solve the model, and Stehfest numerical inversion is conducted to draw the typical rate transient analysis curves. Finally, sensitivity analysis is applied to discuss the relationship between controling factors of the flow and actual reservoirs. Based on the rate transient analysis type curves, geometric parameters such as radius of cave, permeability and length of the large-scale fracture and dynamic reserves can be obtained. Finally, a field case in a bead-string fractured-caved reservoir unit of Tarim basin is implemented to verify the effectiveness of the proposed models and methods. The parameters obtained by type curve match support exploitation of fractured-caved reservoirs.

Abstract Fracture-cavity carbonate reservoirs have abundant reserves of crude oil in place, but they are composed of matrix, fractures and cavities of various sizes, and characterized by strong heterogeneity. Fracture-cavity carbonate reservoirs in China are typically discovered with depth higher than 5000 m at high temperature, high pressure and strong stress. The deformation of fracture and cavity exerts a great impact on fluid flow, while the traditional continuum mechanic theory is inefficient to cope with the strong fluid-solid coupling effect occurred in this type of reservoir. This paper proposes an embedded discrete fracture-cavity model considering fluid flow and solid deformation in order to perform transient production analysis during depletion-drive stage of fracture-cavity carbonate reservoirs. Based on the double logarithmic characteristics of typical production history curve, oil production of fracture-cavity carbonate reservoirs can be divided into four stages: fluid flow in fracture, transition from fracture to cavity, response to cavity and boundary control. Bottom water only affects the fluid flow when entering the boundary-control stage, which can greatly inhibit the sharp decline of oil production history. By accurately conducting transient production analysis, true reservoir properties in actual fracture-cavity unit can be obtained by numerical inversion of production history. The proposed methodology provides a theoretical support for understanding reservoir fluid flow in fracture-cavity carbonate reservoirs. Introduction Fracture-cavity carbonate reservoirs are widely distributed in the Tarim basin, China, generally with depth higher than 6000m[1]. Various reservoir spaces exist simultaneously including matrix, fracture and cavities of different sizes in this type of reservoir. Strongly affected the high in-situ stress, severe heterogeneity, various reservoir spaces and complicated oil-water relationships, depletion-drive development is mainly enforced. The natural decline of oil production is larger than 25%, and there exists a great difficulty to further improve production performance[2-5]. The traditional continuous theory is no longer suitable, and great efforts have been made to clarify to underlying mechanism of fluid exchange and its effect on actual oil production[6,7]. To resolve these issues, an embedded discrete fracture-cavity model considering the fluid flow and solid deformation is proposed in this paper, and used to carry out transient production analysis to investigate the underlying fluid flow during depletion-drive development. Using the proposed methodology, the reservoir properties of actual fracture-cavity carbonate reservoir are further estimated.

Carbonate reservoirs are mainly fractured-caved reservoirs with very well-developed dissolved pores, fractures, and caves. They have strong heterogeneity with various types of reservoir pore spaces. Using seismic inversion and reservoir static characterization, the result shows that the fractured-caved carbonate rocks in China are mainly caves with poor connectivity and complex oil-water distribution. Large-scale dissolved caves are mostly discrete and isolated, while the fractures are complex and various. The fracture features are observed either as a single large fractures or as a local fracture network. The characteristics of fluid flow in fracture-caved reservoirs vary as a result of the different combinations of fractures and caves. Currently, the static characterization technology of fractured-caved reservoirs is influenced by the limited resolution of seismic data, leading to large interpretation errors. In contrast, the dynamic method is a more reliable and effective method to determine reservoir parameters. However, traditional seepage equations cannot accurately characterize the flow pattern of fractured-caved carbonate reservoirs. In the case of a single large-scale dissolved fractured-caved reservoir, oil wells are usually connected to large caves through large fractures or directly drilled into large dissolved caves. In this study, the large-scale dissolved caved reservoir is simplified into two cases: (1) a single-cave and single-fracture series model composed of a single-cave and a single-fracture and (2) a composite model of dissolved caves and surrounding fracture networks. Note that the flow in a large cave is considered as free flow due to its large scale. The flow in a large fracture connected to the cave is considered as flow through porous media, and the flow in the reservoir surrounding the fracture network is considered as multiple-porosity model seepage flow. The corresponding seepage-free flow coupling mathematical model of different fractured-caved reservoirs has been established on this basis. We also obtained the rate transient analysis type curves of the oil well, conducted sensitivity analysis of each parameter, constructed the corresponding rate transient analysis curves, analyzed sensitivities of each parameter, and finally designed a dynamic evaluation method of well and reservoir parameters for different types of fractured-caved carbonate reservoirs. This study extensively applies this method in the Halahatang Oilfield of China and evaluates parameters such as reservoir reserves and physical properties to provide rational guidance for developing fractured-caved carbonate reservoirs.

Due to the severe heterogeneity of carbonate reservoirs, the traditional reservoir engineering methods for waterflooding performance forecast, mainly including the material balance equation, waterflooding characteristic curve and production decline curve, suffer from less reliability. The fine-scale reservoir numerical simulation is extremely time-consuming, because petrophysical properties in carbonate geological models change so drastically. To predict the development performance rapidly, a new method for large-scale thick carbonate reservoirs is proposed. By combining the geological characteristics and dynamic performance of each well, vertical stacking pattern of the reservoir are classified, and also good insights into the lateral distribution of typical stacking patterns are also gained. The stacking pattern distributions are further projected onto the waterflooding well pattern, followed by rapid evaluation of production and injection rate of every block. Based on the simulation results for typical stacking pattern blocks, type curves of water flooding on different stacking pattern reservoirs are workout. Then the waterflooding performance for the whole carbonate reservoir is step-by-step quickly predicted at a constant liquid rate so as to keep the reservoir injection-production balance with voidage replacement ratio 1. Finally, a large-scale thick porous carbonate reservoir in the Middle East is taken as an example to show the workflow of the proposed method. The accuracy is further validated by comparing the predicted results from numerical simulation, indicating that the proposed method can save a lot of calculation time while ensuring the accuracy of performance forecast.

本文针对经典Welsh与Reinhard算法进行改进,提出一种基于分通道自适应匹配的梯度保持色彩迁移算法.引入L、a、b三通道作为匹配依据,因通道间的序列不相关,对单一通道进行处理时不会影响到另外两通道,消除了RGB颜色模式中单一目标区域易受多通道影响的弊端;对整体灰度值相近的图像,将色度均值差异最大的待处理区与背景区通道及参考图像对应通道进行自适应匹配,解决了Welsh算法对灰度差异小或灰度范围重叠的彩色源图像分级易造成误判的问题.然后引入梯度因子,同参考图像与源图像标准差比值作加权运算,将结果作为本文改进迁移算法的缩放比例系数,对匹配到的每组像素采用保持梯度的色彩迁移算法进行着色,避免了Reinhard算法易出现色彩细节信息丢失、阶调间过渡不自然等问题.实验证明,本文改进算法所得目标图像的彩色化效果均优于经典Welsh与Reinhard算法,极大提升了色彩迁移算法的灵活性与适用性.

本文针对传统灰度直方图分割法未综合考虑图像色度及纹理特征、对灰度差异不明显或灰度范围重叠的图像出现过分割或欠分割等问题,提出一种新的基于Lab分通道直方图的彩色图像分割算法,引入具有序列不相关性的亮度L通道、红绿a通道及蓝黄b通道3种分割依据,通过Newton插值法进行拟合运算,可针对不同亮度、色度属性图像进行自由选择,并运用邻域灰度值相匹配原则解决相邻目标区域边缘像素的准确匹配问题,分局部、分形态、分区域实现图像中不同目标的提取.经验证,该法对区域亮度差异较大图像及区域色度差异显著于亮度差异图像的分割效果,均优于传统灰度直方图分割法,极大提升了直方图分割算法的适用性.将其与经典Reinhard色彩迁移算法结合,将源图像感兴趣目标区域经分通道分割后分别进行色彩迁移变换,较好解决了经典Reinhard算法对图像非目标区域的干扰、色彩误传及阶调层次损失严重等问题,突破传统迁移算法只能整体着色的局限性,实现分区域精准着色.

鲁迈拉油田Mishrif油藏是中东地区典型的大型整装礁滩相碳酸盐岩油藏,由于其储层非均质性强,易导致注入水沿渗透率高的薄层即贼层过早水窜,降低注入水波及效率,因此有效识别贼层并制定合理开发技术对策是提高研究区注水开发效果的关键.为此,提出一种基于动、静态资料综合识别贼层的方法.首先根据岩心和成像测井等静态资料确定贼层发育成因,然后利用单井产液剖面测试等动态资料计算储层动态渗透率,并与测井解释得到的静态渗透率对比进而识别贼层;最终综合地层层序划分等静态资料,确定研究区不同的贼层发育模式.通过数值模拟研究,提出贼层在块状和层状储层中不同发育模式下油水井的最优射孔策略,并应用于Mishrif油藏注水试验区,已取得预期的注水开发效果.