Search

This paper presents an analysis of four aspects, including the distribution and production of global oil and gas fields, the distribution and changes of remaining recoverable reserves, the differences in oil and gas production between regions/countries, and the development potentials of oil and gas fields unproduced and to be produced in 2023. On this basis, the situation and characteristics of global oil and gas development are expounded, and the trend of global oil and gas development is summarized. In 2023, upstream oil and gas production landscape is expanding, and the number of oil and gas fields in production is increasing significantly; oil and gas recoverable reserves increased year-on-year, driven by significant contributions from new discoveries and reserve re-estimates; the overall oil and gas production grew continuously, with notable contributions from new projects coming online and capacity expansion efforts; and the oil and gas fields unproduced or to be produced, especially large onshore conventional oil fields and economically challenging offshore gas fields, host abundant recoverable reserves. From the perspectives of reshaping oil and gas production areas due to the pandemic and Russia-Ukraine conflicts, geopolitical crises, capital expenditure structures in petroleum exploration and development, and the proactive layout of oil and gas associated resources, the trend of global oil and gas development in 2023 was analyzed systematically. The enlightenment and suggestions in four aspects are proposed for Chinese oil companies to focus on core businesses and clarify development strategies in the post-pandemic era and the context of energy transition: The global oil and gas landscape is undergoing profound adjustments, and it is essential to grasp development trends, especially in core businesses; upstream business exhibits a strong potential, and emerging fields are considered as new growth poles; the prospects for tight/shale oil and gas are promising, and new pathways to ensure national energy security are explored; cutting-edge breakthroughs are achieved in emerging industries of strategic importance, and a comprehensive energy collaboration system for supply security is established.

The SAGP (steam and gas push) process is an effective enhanced oil recovery (EOR) method for heavy oil reservoirs. Understanding the microscopic interactions among steam, non-condensable gasses (NCGs), and heavy oil under reservoir conditions in SAGP processes is important for their EOR applications. In this study, molecular simulations were performed to investigate the microscopic interactions among steam, NCG, and heavy oil under reservoir conditions in SAGP processes. In addition, the microscopic EOR mechanisms during SAGP processes and the effects of operational parameters (NCG type, NCG–steam mole ratio, temperature, and pressure) were discussed. The results show that the diffusion and dissolution of CH4 molecules and the extraction of steam molecules cause the molecules of saturates with light molecular weights in the oil globules to stretch and gradually detach from one another, resulting in the swelling of heavy oil. Compared with N2, CH4 has a stronger ability to diffuse and dissolve in heavy oil, swell the heavy oil, and reduce the density and viscosity of heavy oil. For this reason, compared with cases where N2 is used, SAGP processes perform better when CH4 is used, indicating that CH4 can be used as the injected NCG in the SAGP process to improve heavy oil recovery. As the NCG–steam mole ratio and injection pressure increase, the diffusion and solubility abilities of CH4 in heavy oil increase, enabling CH4 to perform better in swelling the heavy oil and reducing the density and viscosity of heavy oil. Hence, increasing the NCG–steam mole ratio and injection pressure is helpful in improving the performance of SAGP processes in heavy oil reservoirs. However, the NCG–steam mole ratio and injection pressure should be reasonably determined based on actual field conditions because excessively high NCG–steam mole ratios and injection pressures lead to higher operation costs. Increasing the temperature is favorable for increasing the diffusion coefficient of CH4 in heavy oil, swelling heavy oil, and reducing the oil density and viscosity. However, high temperatures can result in intensified thermal motion of CH4 molecules, reduce the interaction energy between CH4 molecules and heavy oil molecules, and increase the difference in the Hildebrand solubility parameter between heavy oil and CH4–steam mixtures, which is unfavorable for the dissolution of CH4 in heavy oil. This study can help readers deeply understand the microscopic interactions among steam, NCG, and heavy oil under reservoir conditions in SAGP processes and its results can provide valuable information for the actual application of SAGP processes in enhancing heavy oil recovery.

Through analysis of four aspects, including the distribution and production of global oil and gas fields, the distribution and changes of remaining recoverable reserves, the differences in oil and gas production between regions/countries, and the development potential of oil and gas fields with production capacity not built and to be built, this paper presents the situation and trends of global oil and gas development in 2022. It is found that, in 2022, oil and gas fields are widely distributed worldwide, and upstream production activities continue to recover; the oil and gas reserves decrease slightly year on year, and the oil and gas reserves in sea areas increase significantly; the oil and gas production increases continuously, and the key resource countries make a significant contribution in oil and gas production growth; the oil and gas fields with production capacity not built and to be built hold abundant reserves, and their development potential will be gradually released with the economic benefits increase. Further analysis is conducted from the perspectives of global oil and gas resources continuity, geopolitical risks, potential of international cooperation, and upgrade of unconventional oil and gas technology. Finally, in view of core business domains and strategies under the new situation, the Chinese oil companies are recommended to: (1) keep a foothold in onshore conventional oil and gas development by virtue of their comparative advantages and learning from other's experience in cooperation; (2) carry out pilot tests on development adjustment, and deepen the international cooperation in enhanced oil/gas recovery; (3) improve the oil and gas operation capabilities in sea areas to transform from follower as minority shareholder to joint venture and then to independent operations; and (4) seek appropriate ways for shale oil/gas development to reduce the dependence on foreign oil and gas.

Liquefied natural gas (LNG), recognized as the fossil fuel with the lowest carbon emission intensity, is a crucial transitional energy source in the global shift towards low-carbon energy. As the natural gas industry undergoes rapid expansion, the complexity of investment business models has increased significantly. Optimizing the combination of various segments within the value chain has become standard practice, making it essential to control risks and enhance economic benefits in these multifaceted scenarios. This paper introduces an integrated economic model encompassing upstream, liquefaction, shipping, regasification, and consumption, suitable for both upstream and downstream integration. The model offers a comprehensive analysis of the primary business models and key factors across each segment of the value chain. By constructing a robust economic evaluation framework, the study aims to provide a holistic approach to understanding the economic feasibility of LNG projects. Two detailed case studies are conducted to demonstrate the application and effectiveness of the proposed model, highlighting its capability to guide investment decisions, support risk management, and optimize asset portfolios. The integrated economic model developed in this study serves as a valuable tool for stakeholders in the LNG industry. It not only facilitates informed investment decision-making but also enhances the strategic management of risks and resources. By leveraging this model, investors and managers can better navigate the complexities of the LNG business, ensuring sustainable and economically viable operations.

By analyzing the distribution of global oil and gas fields and the reasons why some oil and gas fields are not in production, the distribution characteristics of oil and gas remaining recoverable reserves and their year-on-year changes, the distribution characteristics of oil and gas production and their year-on-year changes, and the development potential of oil and gas to be tapped in 2021, this paper sorts out systematically the current status and characteristics of global oil and gas development, summaries the major trends of global oil and gas development, puts forward enlightenment for international oil and gas cooperation. In 2021, oil and gas fields were widely distributed, the number of non-producing oil and gas fields was large; the whole oil and gas remaining recoverable reserves declined slightly, unconventional oil and gas remaining recoverable reserves dropped significantly; the overall oil and gas production continuously increased, the outputs of key resource-host countries kept year-on-year growth; undeveloped oilfields had abundant reserves and great development potential. Combined with global oil and gas geopolitics, oil and gas industry development trends, oil and gas investment intensity, and the tracking and judgment of hotspot fields, the major trends of global oil and gas development in 2021 are summarized. On this basis, the four aspects of enlightenment and suggestions for international oil and gas cooperation and development strategies are put forward: attach great importance to the obligation of marine abandonment to ensure high-quality and long-term benefit development of offshore oil and gas; adhere to the principle of not going to dangerous and chaotic places, strengthen the concentration of oil and gas assets, and establish multi stable supply bases; based on the multi-scenario demand of natural gas, realize the transformation from integrated collaboration to full oil and gas industry chain development; increase the acquisition of high-quality large-scale assets, and pay attention to the continuous optimization of the shareholding ratio of projects at different stages.

The aim of this paper is to illustrate the impact of stress-sensitive permeability on productivity in naturally fracture carbonate reservoirs. First, stress sensitivity evaluation experiments were conducted on artificial cores with matrix, uncemented fracture, partially- cemented fracture and fully-cemented fracture by measuring their permeability in the process of increasing confining pressure. Then, a new mathematical model for productivity prediction in naturally fractured carbonate reservoir with consideration of stress-sensitive permeability is developed. Comparisons have been made between the new model prediction results and field measured data to verify the accuracy of the new model. Finally, based on the validated model, the detailed impact of permeability modulus on productivity is analysed. The experiment results show that the strength of stress sensitivity, evaluated by permeability modulus, of cores with uncemented fracture and partially-cemented fracture is generally an order of magnitude larger than that of cores with matrix and fully-cemented fracture. The results show the new model can be simplified to the classic model (Vogel equation) under the condition of the stress sensitivity being not taken into account, which means the class model is corresponding to a special case of this new model. Field application shows that the new model is reliable and correct. Moreover, with the help of the new model, it is found that the impact of stress-sensitive permeability on productivity increases with increasing permeability modulus and decreasing flow bottom hole pressure.

Carboniferous carbonate reservoirs at the eastern edge of the Pre-Caspian Basin have undergone complex sedimentation, diagenesis and tectonism processes, and developed various reservoir space types of pores, cavities and fractures with complicated combination patterns which create intricate pore-throats structure. The complex pore-throat structure leads to the complex porosity-permeability relationship, bringing great challenges for classification and evaluation of reservoirs and efficient development. Based on the comprehensive analysis on cores, thin sections, SEM, mercury intrusion, routine core analysis and various tests, this paper systematically investigated the features and main controlling factors of pore-throats structure and its impact on the porosity-permeability relationship of the four reservoir types which were pore-cavity-fracture, pore-cavity, pore-fracture and pore, and three progresses are made. (1) A set of classification and descriptive approach for pore-throat structure of Carboniferous carbonate reservoirs applied to the eastern edge of the Pre-Caspian Basin was established. Four types of pore-throat structures were developed which were wide multimodal mode, wide bimodal mode, centralized unimodal mode and asymmetry bimodal mode, respectively. The discriminant index of pore-throat structure was proposed, realizing the quantitative characterization of pore-throat structure types. (2) The microscopic heterogeneity of pore reservoir was the strongest and four types of pore-throat structures were all developed. The pore-fracture and pore-cavity-fracture reservoirs took the second place, and the microscopic heterogeneity of pore-cavity reservoir was the weakest. It was revealed that the main controlling factor of pore-throat structure was the combination patterns of reservoir space types formed by sedimentation, diagenesis and tectonism. (3) It was revealed that the development of various pore-throat structure types was the important factor affecting poroperm relationship of reservoirs. The calculation accuracy of permeability of reservoirs can be improved remarkably by subdividing the pore-throat structure types. This study deepens the understanding of pore-throat structure of complicated carbonate reservoirs, and is conducive to classification and evaluation, establishment of precise porosity-permeability relationship and highly efficient development of carbonate reservoirs.

AbstractThe purpose of this study is to introduce a new three-linear flow model for capturing the dynamic behavior of water flooding with different fracture occurrences in carbonate reservoirs. Low-angle and high-angle fractures with different occurrences are usually developed in carbonate reservoirs. It is difficult to simulate the water injection development process and the law of water flooding is unclear, due to the large variation of the fracture dip. Based on the characteristics of water flooding displacement streamlines in fractured cores with different occurrences, the matrix is discretized into a number of one-dimensional linear subregions, and the channeling effect between each subregion is considered in this paper. The fractures are divided into the same number of fracture cells along with the matrix subregion, and the conduction effect between the fracture cells is considered. The fractured core injection-production system is divided into three areas of linear flow: The injected fluid flows horizontally and linearly from the matrix area at the inlet end of the core to the fracture and then linearly diverts from the fracture area. Finally, the matrix area at the outlet end of the core also presents a horizontal linear flow pattern. Thus, a trilinear flow model for water flooding oil in fractured cores with different occurrences is established. The modified BL equation is used to construct the matrix water-flooding analytical solution, and the fracture system establishes a finite-volume numerical solution, forming a high-efficiency semianalytical solution method for water-flooding BL-CVF. Compared with traditional numerical simulation methods, the accuracy is over 86%, the model is easy to construct, and the calculation efficiency is high. In addition, it can flexibly portray cracks at any dip angle, calculate various indicators of water flooding, and simulate the pressure field and saturation field, with great application effect. The research results show that the greater the fracture dip angle, the higher the oil displacement efficiency. When the fracture dip angle is above 45°, the fracture occurrence has almost no effect on the oil displacement efficiency. The water breakthrough time of through fractures is earlier than that of nonthrough fractures, and the oil displacement efficiency and injection pressure are more significantly affected by the fracture permeability. With the increase of fracture permeability, the oil displacement efficiency and the injection pressure of perforated fractured cores dropped drastically. The findings of this study can help for better understanding of the water drive law and optimizing its parameters in cores with different fracture occurrences. The three-linear flow model has strong adaptability and can accurately solve low-permeability reservoirs and high-angle fractures, but there are some errors for high-permeability reservoirs with long fractures.

In view of the lack of rate decline prediction model of acid-fracturing vertical wells (AFVWs) in pore-cavity-fracture carbonate reservoirs, a prediction model of AFVWs with consideration of wormholes and fractures generated by acid fracturing is established by using the idea of compound reservoir. Acid fracturing significantly increases well productivity in the early period, but in the late period, its impact on instantaneous and cumulative production almost disappears. A higher interzonal diffusivity ratio or a lower interzonal conductivity ratio generated by acid fracturing can bring a better stimulation effect in the early period. Three typical production stages can be observed on the conventional productivity curves under constant wellbore pressure, corresponding to early linear decline stage, middle stable production stage, and late depletion decline stage, respectively. A new productivity function is defined by using a pseudo-steady state constant, and a set of new type rate decline curves of AFVWs in pore-cavity-fracture carbonate reservoirs is plotted and presented. Six typical flow regimes can be identified on these new type curves, including two or three V-shaped segments. The duration of all flow regimes and the depth and amplitude of V-shaped segments are controlled by interzonal diffusivity ratio, interzonal conductivity ratio, elastic storability ratio, crossflow coefficient, and boundary conditions. Reservoir parameter interpretation and future productivity prediction for an oil well in North Truva Oilfield were conducted by using our proposed model. The prediction results are consistent with the actual production, proving our model’s accuracy and reliability. Compared with the conventional rate decline curves, these new type rate decline curves have more prominent flow regimes and can improve well-test inversion accuracy, reduce shut-in time, and increase well productivity.

AbstractStress sensitivity has always been a research hotspot in fractured-porous reservoirs and shows huge impacts on well productivity during the depletion development. Due to the continuous reservoir pressure change, accurate evaluation of stress sensitivity and its influence on well productivity is of great significance to optimize well working system. Taking horizontal well trajectory as the research object, the principal focus of this work is on the analysis of inflow performance for a horizontal well coupling stress sensitivity and reservoir pressure change in a fractured-porous reservoir. Firstly, a relationship between permeability damage rate and stress sensitivity coefficient was established to quantitatively evaluate the influence of reservoir pressure and stress sensitivity on reservoir permeability. Secondly, considering stress sensitivity and reservoir pressure drop, a set of practical productivity equations were derived for a horizontal well in a fractured-porous reservoir by adopting the equivalent seepage resistance method. Finally, the influence of relevant important factors on the inflow performance of horizontal wells was discussed in depth. Results show that a positive correlation exists between stress sensitivity coefficient and maximum permeability damage rate. At the same maximum permeability damage rate, high initial reservoir pressure corresponds to low stress sensitivity coefficient. In general, stress sensitivity coefficient mainly ranges from 0 to 0.2. Reservoir pressure change drastically affects the production dynamic characteristics of horizontal wells, and both the inflow performance curve and the production index curve decline and shrink as reservoir pressure decreases. Stress sensitivity is negatively correlated with horizontal well productivity, and the inflow performance/production index curve bends closer to bottom-hole pressure axis, and an inflection point can be observed with the aggravation of stress sensitivity. In addition, horizontal wellbore length and initial reservoir permeability also show significant effects on the inflow performance and are positively correlated with well productivity. For water cut, it has little effect on the well production when bottom-hole pressure drawdown is low, but its effect gets stronger as the drawdown becomes higher. Meaningfully, depending on these newly established productivity equations, a reasonable production system can be quantitatively optimized and achieved for the horizontal wells in fractured-porous reservoirs.

Abstract As the accurate productivity prediction of cyclic steam stimulation with horizontal well (CSSHW) is essential for its effective utilization in heavy oil reservoirs, a novel integrated model for predicting productivity of CSSHW was proposed in this paper. Firstly, governing equations to predict thermophysical parameters of injected steam in the horizontal well were established. On the basis, the heating model for radius of hot fluid zone and steam zone were derived respectively according to a more realistic temperature distribution of formation. Then, coupled with heating model, the productivity prediction model was established according to the principle of equivalent percolation resistance. Then, comparisons have been made among the new model results, CMG STARS results, and measured data to verify its accuracy. Finally, after the new proposed model is validated, the effects of steam quality and injection rate on heating radius and oil production were analyzed in detail. The results indicate that the result of new model is in good agreement with that of CMG STARS and measured data, verifying the correctness of the model. In addition, the radius of hot fluid zone and steam zone both decreases with horizontal well length because of the heat losses as the steam flows along the horizontal wellbore. Influential factor analysis shows that high steam quality and steam injection rate can improve heating radius and cumulative oil production.

Minimum miscible pressure is a key parameter to screen and design miscible gas injection projects. The aim of this paper is to establish a correlation with only a few input parameters to easily and accurately predict minimum miscible pressure for the reinjection of produced gas with high acidic components. First, the critical parameters of equation of state for each component of the crude oil were obtained through fitting pressure-volume-temperature (PVT) experimental results. Based on the analytically calculated minimum miscible pressures from mixing-cell method, an empirical correlation for predicting minimum miscible pressure in the displacement of crude oil by produced gas was regressed. Finally, the correlation’s accuracy was tested by comparing the minimum miscible pressures predicted from the new proposed correlation to other previous correlations and 20 experimental slim-tube minimum miscible pressures of 12 oil samples. The results indicate that the analytically calculated minimum miscible pressures from the mixing-cell method have a relative error of 0.5% compared to the slim-tube experiment results, which supports its reliability. Furthermore, the new proposed correlation is observed to be superior in terms of the average relative error being only 6.4% for all the 75 analytically calculated minimum miscible pressures and 20 experimental slim-tube minimum miscible pressures, which is lower than the average relative error obtained from other previous correlations.

Acid fracturing has been widely used as an industry practice in explored and developed carbonate reservoirs. It is very important to understand responses of reservoirs and improve production performance of a well due to the presence of fracture networks by stimulation treatments. Pressure transient analysis is one of the most effective diagnostic techniques available to enhance our understanding of natural and artificial-etched fracture behavior. This work presented a novel mathematical model for unsteady state flow of naturally fractured porous medium into multiple etched fractures intersecting a vertical well, and three different geometric shapes of matrix blocks containing slabs, cylinders and spheres were considered. The new solution was derived by using the Laplace transformation and the point source function integral approach. The polar coordinate transformation was used to deal with the radial distribution of arbitrary fracture number and angle. Then the model was validated by comparison with three published cases. Finally, type curves were plotted to identify flow regimes: linear flow, transitional flow, pseudoradial flow, and boundary dominant flow if the closed or constant pressure boundary exists. Furthermore, sensitivity analysis was investigated. The results showed that the acid-etched fracture parameters containing fracture number, fracture distribution and conductivity had a significant impact on pressure behavior at early times. However, natural fracture storativity coefficient and interporosity flow parameter mainly affected the transitional flow at intermediate times. Moreover, the shape of matrix blocks had a little influence on transient responses at intermediate times. It is found that multiple etched fractures existing near the wellbore consume less pressure drop and increase the productivity of a well as a whole.

Based on about 20 years of accumulated experience and knowledge of oil and gas field development in overseas countries and regions for China's oil companies, the development features, ideas, models and plan designing strategies of overseas oil and gas fields were comprehensively summarized. Overseas oil and gas field development has ten major features, such as non-identity project resource, diversity of contract type, complexity of cooperation model, and so on. The overseas oil and gas field development aims at the maximization of production and benefit during the limited contract period, so the overseas oil and gas field development models are established as giving priority to production by natural energy, building large-scale production capacity, putting into production as soon as possible, realizing high oil production recovery rate, and achieving rapid payback period of investment. According to the overseas contract mode, a set of strategies for overseas oil and gas field development plans were made. For tax systems contracts, the strategy is to adopt the mode of “first fat and then thinner, easier in the first and then harder”, that is, early investment pace, production increase rate, development workload and production were decided by the change of tax stipulated in the contract. For production share contracts, the strategy is to give priority to high production with a few wells at a high production recovery rate to increase the cost-oil and shorten the period of payback. For technical service contracts, the strategy is that the optimal production target and workload of the project were determined by the return on investment, so as to ensure that the peak production and stable production periods meet the contract requirements. Key words: overseas oil and gas field, development ideas, technical strategy, development model, contract type, development plan design

Due to superheated steam as a pure gas, the ordinary steam model for the calculation of horizontal well-bore parameters based on two phases flow theory isn't applicable to the superheated steam injection process. According to the conservation of mass, conservation of momentum and conservation of energy, a calculation model for on-way parameters of horizontal well-bore in the superheated steam injection considering the steam phase changing is set up. The on-way parameters of temperature, pressure and dryness of a horizontal well injected superheated steam from Kazakhstan Kumsai oilfield is calculated using the model, and the calculation result of the new model is in good agreement with that of the field data, which verifies the effectiveness of the model. Sensitivity analysis indicates that the length to the heel of horizontal well undergoing the steam phase state changing increases as the injection rate or the degree of superheat increases, but the increase extent is not significant when the injection rate is larger than 8 t/h or the degree of superheat is larger than 80 °C. In the permeability distribution pattern that the permeability increases along the horizontal well-bore, steam temperature is decreased at the lowest rate and the length to the heel of horizontal well undergoing the steam phase changing is the longest. Key words: heavy oil, horizontal well, superheated steam, steam phase changing, on-way parameters, calculation model, steam injection rate

The pressure balance between gas cap and oil ring is likely to be broken during their concurrent production in gas cap reservoirs. In order to increase the whole development efficiency of the concurrent production of gas cap and oil ring, the Zhanzhol gas cap reservoir of Kazakhstan was taken as example to carry out the research, a three-dimensional visualization physical model was established based on the similarity criterion of oil phase, gas phase and water phase, and a reservoir engineering model of fluid interface moving rate was also set up according to the material balance principle. The calculation results of reservoir engineering model tally with the results of physical simulation experiment and reservoir dynamic test data. The moving rate template of fluid interface under three development modes, depletion development, barrier water injection development and barrier plus pattern water injection development have been also established by reservoir engineering method. The main controlling factors under different development modes have been figured out: for depletion development, the main controlling factors on the stabilization of oil-gas contact are oil recovery rate and gas recovery rate; for barrier water injection development, the main controlling factors are oil recovery rate, gas recovery rate and production-injection ratio; and for barrier plus pattern water injection development, the main controlling factors are oil recovery rate, gas recovery rate, production-injection ratio and the ratio of barrier water injection to pattern water injection. Key words: Zhanzhol oil field, gas cap reservoir, concurrent production of gas cap and oil ring, fluid interface, moving rule

Reservoir Γ north, which belongs to Zhanzhol, Kazakhstan, a fracture-pore typed carbonate oilfield, has a variety of reservoir types. According to the combination pattern of different voids and the relationship between porosity and permeability, carbonate reservoirs are classified into four types which are fracture-cavity-pore typed (referred to as composite typed here after), fracture-pore typed, pore typed and fracture typed, and the identification of which by well logging data is realized. There is a little difference in the producing degree within the same reservoir type for composite typed and fracture typed reservoirs. However, there are large differences in the producing degree for fracture-pore typed and pore typed reservoirs. In order to appraise the producing degree of reservoirs more exactly, key parameters affecting the producing degree of fracture-pore typed and pore typed reservoirs are selected separately, which, for the fracture-pore typed are reservoir quality index (RQI), pore throat radius at mercury saturation of 50% (R50), total permeability (Kf+Km), and the ratio of fracture permeability to matrix permeability (Kf/Km), and for the pore typed are RQI, R50, and matrix permeability (Km). With the integrated consideration of matrix and fracture, a flow unit classification method for dual medium reservoir is established, and taking these parameters as clustering variants, four types of reservoirs are further divided into six kinds of reservoir flow units by the means of neural network clustering technology. Based on reservoir flow unit modeling, a numerical simulation model is built with each type of reservoir flow units adopting its corresponding relative permeability curve, based on which, the distribution regularity of remaining oil of reservoir Γ north is studied and demonstrated. Eight new wells are designed according to the research result, and put into production in 2013 with the initial daily oil production rate being 2.3 times that of nearby old wells. Key words: carbonate oil reservoir, reservoir type, reservoir flow unit, neural network clustering technology, reservoir flow unit model, remaining oil

Taking the Kumkol oilfield of high water cut in the South Turgay Basin, Kazakstan as an example, this article built the architecture models of meandering river sandstones, braided river sandstones and delta sandstones, and analyzed the influence of the superimposed structure characteristics between different types of sandstones and internal architecture features on warterflooding mechanisms and effects. The meandering river sandstones are mainly characterized by lateral accretion shale beddings inside, with simple overlay-relationship in sand bodies. In meandering river sandstones, injected water almost sweeps through the bottom of sand bodies and the bottom part of the sandstones is previously waterflooded, and the thickness ratio of strong and moderate waterflooded zone is about 51.8%. Braided river sandstones are characterized by nearly horizontal interlayers inside, with low heterogeneity and uniform waterflooding sweep vertically, and the thickness ratio of strong and moderate waterflooded zone is as high as 81.7%. The superimposed structure and architecture of delta sandstone is relatively complicated; different types of sandstones overlay each other frequently and shale interbeds are developed in sandstones. The injected water is obstructed not only by impermeable or low-permeable layers between sand bodies but also by shale interbeds in sandstones, with low sweep range of injected water, and the thickness ratio of strong and moderate waterflooded zone is only 32.6%. The braided river sandstone has low rising velocity of water cut and high no-water recovery degree, and its waterflooding development effect is the best. The waterflood sweep of delta sandstones is poor, with fast rising velocity of water cut and low no-water recovery degree, and its waterflooding development effect is the worst. The waterflooding development effect of meandering river sandstones is moderate among these three types of sandstones. Key words: South Turgay Basin, sandstone type, meandering river, braided river, delta, warterflooding degree, warterflooding characteristics, remaining oil

Taking the Kenjiyak Oilfield in Kazakhstan as an example, the fracture characteristics and genetic mechanism of carbonate reservoirs with overpressure were discussed. The study showed that carbonate reservoirs are formed under overpressure developed hydraulic fractures besides tectonic fractures and karstic fractures. The Carboniferous sub-salt hydraulic fractures in Kenkiyak are mainly formed in the Mesozoic and Cenozoic, on a macroscopic level they cut rocks into brecciated texture or are packed by calcite veins, on a microscopic level they are in a radiant distribution around pores. The formation and evolution of the fracture system in the region experienced three main stages, including structure transforming and uplifting, structure stretching and subsiding, and hydraulic cracking. In the stage of hydraulic cracking, salt movement and tectonic movement lead to the formation of overpressure zone, with the pressure coefficient of 1.84. Overpressure leads to the formation of hydraulic fractures in the Carboniferous low permeable carbonate reservoirs under the Permian non-permeable mudstones, and also leads to reopening, widening and prolonging of former tectonic fractures. Hydraulic fractures are mainly the extensional fracture, which has late opening time and low filling degree, thus is the main effective fractures in the study area. 摘要: ：以哈萨克斯坦肯基亚克油田为例讨论了异常高压碳酸盐岩油藏储集层裂缝特征及形成机制。异常高压条件下形成的碳酸盐岩储集层除发育构造裂缝和岩溶裂缝外，还发育水力破裂缝。盐下石炭系水力破裂缝形成于中、新生代，宏观上表现为将岩体切割成角砾状及充填方解石脉，微观上表现为沿孔隙周围呈放射状分布。该区裂缝系统的形成与演化经历了3个主要阶段，即构造变形与抬升阶段、构造拉张与沉降阶段、水力破裂阶段。在水力破裂阶段，在盐丘活动、构造运动等多种因素作用下，盐下地层中形成异常高压带，压力系数高达1.84，在异常高压条件下，二叠系泥岩不渗透层下的石炭系碳酸盐岩低渗透层发生破裂，形成水力破裂缝，同时使早期闭合的裂缝开启、扩张和延伸。水力破裂缝以张性裂缝为主，其张开时间晚，充填程度低，是研究区主要的有效裂缝。图8参13 Key words: carbonates, overpressure, tectonic fracture, hydraulic fracture, genetic mechanism

Fracture aperture of a fractured reservoir can be affected by both matrix elasticity and fracture compressibility when the reservoir pressure decreases, namely stress sensitivity. An elasticity parameter coupling Young’s modulus and Poisson’s ratio was introduced to reflect this geomechanical behavior, and a new model incorporating geomechanics was developed to analyze the flow behavior of a horizontal well in a naturally fractured reservoir. Pressure solutions for two cases—uniform-flux and infinite-conductivity—were derived, respectively. For the uniform-flux case, the effect of dimensionless elasticity parameter on the pressure-drop profile becomes stronger with continuing production, and the profile may be like a bow. Nine flow regimes can be observed on the transient response of the infinite-conductivity case. Stress sensitivity mainly affects the late-flow period and a larger dimensionless elasticity parameter causes a greater pressure drop. Due to stress sensitivity, the pressure derivative curve exhibits an upward tendency in the pseudo-radial flow regime, and the slope is greater than “1” in the pseudo-steady flow regime. For KT-I formation in the North Truva field, its elasticity parameter decreases with the increase of Young’s modulus or Poisson’s ratio and ranges from 8 × 10−8 Pa−1 to 1.1 × 10−7 Pa−1. Meanwhile, the transient response of H519 has a slight negative correlation with Young’s modulus and Poisson’s ratio in the pseudo-steady flow regime.

The central layer Yu-III in Akshabulak oilfield is a sandstone reservoir with strong edge water, whose major development characteristics are high oil recovery rate and heterogeneous water invasion. Aiming at this problem, the development policy chart of concurrent displacement of natural water and injected water is established on the basis of material balance principle. Injection-production ratio and oil recovery rate are the main controlling factors for the concurrent displacement of natural water and injected water. Each injection-production ratio corresponds with only one rational oil recovery rate, and the rational oil recovery rate increases with the injection-production ratio. When the actual injection-production ratio of the central Yu-III reservoir is 0.9, the rational oil recovery rate should be 4%.

Reorientation fractures may be formed in soft and shallow formations during fracturing stimulation and then affect well productivity. The principal focus of this study is on the productivity analysis for a horizontal well with multiple reorientation fractures in an anisotropic reservoir. Combining the nodal analysis technique and fracture-wing method, a semi-analytical model for a horizontal well with multiple finiteconductivity reorientation fractures was established to calculate its dimensionless productivity index and derivative for production evaluation. A classic case in the literature was selected to verify the accuracy of our semi-analytical solution and the verification indicates this new solution is reliable. Results show that for a fixed fracture configuration the dimensionless productivity index of the proposed model first goes up and then remains constant with the increase of fracture conductivity, and optimal fracture conductivity can be determined on derivative curves. Strong permeability anisotropy is a negative factor for well production and the productivity index gradually decreases with the increase of anisotropic factor. As principal fracture angle goes up, horizontal well's productivity index increases correspondingly. However, the effect of reoriented fracture angle on the productivity index is not as strong as that of principal fracture angle. When reoriented fracture angle is smaller than principal fracture angle, reoriented factor should be as low as possible to achieve optimal productivity index. Meanwhile, well productivity index rises up with the increase of fracture number and fracture spacing, but the horizontal well has optimal reorientation fracture number and fracture spacing to get the economical productivity. Furthermore, the influence of the rotation of one central reorientation fracture on productivity index is weaker than that caused by the rotation of one external reorientation fracture. In addition, the asymmetrical distribution of one or more reorientation fractures slightly affects the productivity index when fracture conductivity is high enough. [ABSTRACT FROM AUTHOR]

Maintaining the reservoir pressure by gas injection is frequently adopted in the development of gas condensate reservoir. The aim of this work is to investigate the phase behavior of condensate oil and remaining condensate gas in the formation under gas injection. The DZT gas condensate reservoir in East China is taken as an example. The multiple contact calculation based on cell-to-cell method and phase equilibrium calculations based on PR Equation of State (EOS) were utilized to evaluate the displacement mechanism and phase behavior change. The research results show that different pure gas has different miscible mechanism in the displacement of condensate oil: vaporizing gas drive for N2 and CH4; condensing gas drive for CO2 and C2H6. Meanwhile, there is a vaporing gas drive rather than a condensing gas drive for injecting produced gas. When the condensate oil is mixed with 0.44 mole fraction of produced gas, the phase behavior of the petroleum mixture reverses, and the condensate oil is converted to condensate gas. About the reinjection of produced gas, the enrichment ability of hydrocarbons is better than that of no-hydrocarbons. After injecting produced gas, retrograde condensation is more difficult to occur, and the remaining condensate gas develops toward dry gas. [ABSTRACT FROM AUTHOR]