Fault-controlled fractured-vuggy reservoirs are extremely heterogeneous and exhibit the diversity and complexity in inter-well connectivity. Clarifying the influence of faults and karsts on reservoirs is conducive to reservoir connectivity analysis and injection-production strategy adjustment. Taking Unit T in the Tuofutai area of Tahe oilfield as an example, the development characteristics of reservoirs were systematically analyzed based on the results of seismic interpretation and the analysis of overlying water system and production performance responses. It was clarified that the reservoir development is mainly controlled by faults and surface water systems. The difference in karstification intensity leads to different characteristics of the reservoirs, which makes development wells show different production behaviors and inter-well connectivities. Based on the analysis of dynamic and static data, an inter-well connectivity model suitable for fault-controlled fractured-vuggy reservoirs was established, which can provide a basis for the adjustment of subsequent treatments.
Compared with conventional oil reservoirs, tight oil reservoirs have poor physical properties and low permeability, and wells drilled in these reservoirs need to be fractured for more production. Due to the geological features and special development techniques, there are many factors affecting the production of these reservoirs, and the simple analogy method commonly used on site for production prediction cannot meet the actual needs. In order to solve this problem, taking the tight oil reservoir in Pingbei oilfield of Ordos basin as the research object and based on the Darcy equation, the main influencing factors for production were quantitatively described through grey theoretical analysis. Moreover, a mathematical model was established by using the multiple regression method, and applied to predict the production of new wells in order to verify the reliability of the model. Production prediction by using the multidisciplinary method that combines the grey theory and multiple regression is more scientific and accurate than by using traditional methods, and it can provide a reference for the development of similar oil reservoirs.
Regarding complex flow regime and large error in lifecycle production prediction for fractured horizontal wells in tight oil reservoirs, the stretched exponential production decline (SEPD) model dominated by transient flow and transitional flow and the exponential model dominated by boundary-dominated flow (BDF) were selected and combined based on the research on the adaptability of empirical production decline model proposed in previous studies. Given equal production and equal decline rate at nodes, a new lifecycle segmented production prediction model with BDF time as node was constructed. Furthermore, the methods for predicting BDF time based on the generalized regression neural network algorithm and for determining the parameters of piecewise function by least square fitting were established. The results show that, whether the BDF is attained, the new model realizes a better fitting than the SEPD or exponential model, and its prediction results are closer to the exponential evaluation results in the late stage of production with an error of less than 5%.
In order to clarify the productivity and production performance of Ma131 dense-spacing 3D development pad,the production characteristics and unstable production/productivity were predicted,a workflow for performance analysis and productivity prediction was established,and the key parameters such as equivalent formation permeability and effective fracture half-length,etc. were determined for single well productivity prediction. Oil in the target reservoir is easy to be degassed,which may be effectively alleviated by running the gas nozzle into the hole in the early stage. The use of over-sized oil nozzle in the early stage of flowback may greatly decrease the fracture volume; in this case,a pressure-managed flowback is necessary. The P50 productivity prediction results obtained from the production decline curves and the analytical model can complement each other,providing a more accurate and reasonable productivity prediction interval. The average effective fracture half-length of horizontal well in T1b3 is greater than that in T1b1 2; therefore,the well spacing can be further optimized.
Influenced by the increasing reservoir types in Changqing oilfield and the low international crude oil price, clarifying the benefit categories of reservoirs and identifying the oil production limits of different types of reservoirs under different oil prices are urgent for Changqing Oilfield Company to make production and operation decisions. By combining the benefit evaluation with reservoir research, dynamic development, well production failure and comprehensive treatment, the relationship between cost or development index and benefits for different types of reservoirs was established, and the influencing factors of low-benefit wells were analyzed, providing a reference for cost-effective development of reservoirs.
In order to determine the productivity of each fracturing section of a horizontal well after staged fracturing in the Sulige gas field, the production profile of horizontal wells and its influencing factors such as reservoir heterogeneity, flow characteristic, multistage fracturing technique and production pressure difference were analyzed. It is found that physical properties of reservoirs and development degree of effective sand bodies are the main factors controlling gas well productivity, and they have greater effect than the flow dominant term at the heel and toe of the horizontal well in an ideal model. The increase in production pressure difference aggravates the difference in gas production rate among fracturing sections in strongly heterogeneous reservoirs. The uneven distribution of induced fractures leads to different gas productivities of perforation clusters in the same fracturing section. Therefore, for multi-stage fractured horizontal wells, technical countermeasures such as optimization of perforation sections, differential stimulation of horizontal sections, and uniform fracture propagation by temporary plugging were proposed so as to improve the development effect of tight gas reservoirs.
When the conventional optimization algorithms are applied to optimized development of large scale reservoirs, the problems such as slow convergence speed, low optimization efficiency and difficult integration with field applications occur. To solve these problems, a well production performance control model was established. A global optimal solution of the model was found by using the simulated annealing genetic (SAG) algorithm and Latin hypercube sampling (LHS) algorithm. Furthermore, the convergence speed of the local solution of the model was accelerated by using the synchronous perturbation stochastic approximation (SPSA) algorithm, and a well production performance control software was developed and applied to the H block in Daqing oilfield. Compared with conventional well production systems, the best scheme of the optimized well production performance control model increases the cumulative oil production of H block by 5.68×104 m3 within 5 years, which ensures the well production performance control and optimization, and provides a new method for efficient development of large-scale oilfields.
The Permian fluvial sandstone gas reservoirs in the Sulige gas field are tight and contain effective sand bodies that are mostly isolated or banded. After gas wells are put into production, reservoir fluid stays consistently in an unsteady flow state, and it is late to reach the boundary-dominated flow state. In this case, the traditional Arps production decline analysis method is not sufficient for field application. This paper analyzed the causes for the poor adaptability of the Arps production decline analysis method. On this basis, the variation law of the decline exponent of wells in tight gas reservoirs was identified by numerical simulation, and the relationship between the decline exponent and the flow period of fluid in gas wells was clarified. Finally, it was proposed to use the channel linear flow model to predict the production in the unsteady flow period and the Arps model to predict the production in the boundary-dominated flow period. For the gas wells in the unsteady flow period, the critical point time to attain boundary-dominated flow is determined by the theoretical formula; in the boundary-dominated flow period, the time of inflection point deviating from the linear flow is the critical point time. The field application shows that the proposed combined production decline model is accurate and effective in predicting the decline characteristics and indicators of gas wells.
In the Sulige gas field, tight sandstone gas reservoirs present a high water saturation. The water cut increases rapidly after the gas wells are put into production. With the increase of water cut, the production of gas wells declines greatly or even stops. Based on the analysis of production performance of water-producing gas wells, the relationships between the water saturation and the cumulative gas production and recovery rate of the gas wells were established. Combined with the single well investment and natural gas price, the minimum cumulative gas production required to recoup the investment in a gas well was determined, and accordingly the upper limit of reservoir water saturation was determined. Furthermore, taking the minimum cumulative gas production of gas wells as the standard, and considering the reservoir water saturation and reservoir thickness, the quantitative indicators for the logging interpretation of gas layers, gas-water layers and gas-bearing water layers were determined. The results show that the upper limit of water saturation of tight sandstone reservoirs in the central part of Sulige gas field is 48.2%, and when the economic minimum cumulative gas production in the life cycle of a gas well reaches 1 260×104 m3, the gas well is profitable.
In the process of transforming the Mahu conglomerate reservoirs in the Junggar basin from large-scale development to profitable development，it is particularly important to select reasonable fracturing parameters under the premise of considering economic benefits. In order to realize the optimization of key fracturing parameters for the Mahu conglomerate reservoirs，an equivalent KGD fracture propagation model was established to realize the rapid estimation of fracture shape. By using the heuristic particle swarm optimization algorithm and taking the rate of return as the objective function，a combined optimization on fracturing scale, cluster number and displacement was carried out for pay zones in the Mahu conglomerate reservoirs. The optimization results show that with the increase of the iteration number，the high-cost development plan finally converges to a combined optimization plan with the best comprehensive development effect，thus enabling the optimization of fracturing parameters for Ma 131 block.
As a key parameter, the effective storage capacity of a UGS affects the function, peaking capability, parameters and design of the UGS, so its accurate evaluation is very important. When converting an abnormally-high-pressure water-containing condensate gas reservoir into a UGS, factors such as abnormally high pressure, water intrusion and reverse condensate affect the storage capacity. Considering abnormally high pressure, the upper limit of the pressure for the UGS is designed to be 58.00 MPa, which is much lower than the original formation pressure. The difference of the gas volume coefficient results in the difference of the storage capacity of the UGS. During the injection-production process, water flows back and forth in the UGS, which dramatically affects the utilization of reservoir space. In the alternative production-injection process, when the formation pressure is lower than the dew point pressure, separated condensate oil has a certain influence on the storage capacity. In response to this problem, an improved dual model integrating material balance and numerical simulation was established. Based on the dynamic reserves of gas reservoirs, factors such as abnormal high pressure, reverse condensation, water intrusion were quantitatively analyzed, and a set of methods for evaluating the capacity of the UGS were developed. The set of methods was applied for constructing the Lunnan-59 Carboniferous UGS. The effective storage capacity of the UGS was accurately evaluated. This lays a foundation for the research on the parameters of the UGS, and ensures the successful construction of the Lunnan-59 Carboniferous UGS.
Well Hutan-1 is the first ultra-deep and abnormally high-pressure gas well that revealed a significant discovery in gas exploration in the middle section of Junggar basin’s southern margin. However, during the production test, the wellhead pressure of this well fluctuated greatly, making it impossible to effectively determine reservoir parameters and reasonably evaluate productivity. Based on the principle of particle bridging and plugging, and by using the gas reservoir dynamic analysis method, the variation of cyclic plugging and unplugging of the particles in fractures was investigated, and a dual-medium flow model for Well Hutan-1 was established for analyzing the characteristics and genesis mechanism of wellhead pressure fluctuation in the well. The research shows that the cyclic plugging and unplugging of the particles in fractures is the main reason for the large pressure fluctuation. With the continuous migration of the particles and unplugging in fractures, the pressure fluctuation amplitude and the skin factor gradually decrease, and the gas productivity tends to be stable. During the cyclic plugging and unplugging of the particles in fractures, the greater the fracture aperture, the greater the pressure fluctuation amplitude. Given the same fracture aperture, the proximal fractures are plugged and unplugged, resulting in a great pressure fluctuation amplitude, while the opposite is true at the distal fractures. The research provides a basis for the study of reservoir characteristics, well deployment, and productivity evaluation in the middle section of the Junggar basin’s southern margin, and provides a reference for analyzing pressure fluctuation in the same type of ultra-deep and abnormally high-pressure gas wells.
The Sebei gas field in the Qaidam basin is an anticline-type shallow unconsolidated sandstone gas field driven by weak edge water，and is exploited by depletion. According to water-gas ratio (WGR)，the production process in the gas field can be divided into four stages: low water-cut steady production stage，initial water invasion stage，edge water breakthrough stage，and strong water invasion stage. The occurrence of water invasion can be accurately monitored based on WGR. The edge water breakthrough stage can be used as a time window for predicting the large-scale water invasion of edge water，so as to adjust the development plan and extend the steady production period. The strong water invasion stage with high water cut corresponds to a long production period，so it is an important stage for enhanced oil recovery while producing with water.
In order to determine the role of natural fractures in the forming of hydraulic fracture network in tight sandstone reservoirs, a numerical model was established using the coupled hydraulic-mechanical-damage (HMD) model, and a fracture network model was generated in the numerical model by the Monte-Carlo method. With these models, the influences of natural fracture orientation, natural fracture strength, horizontal principal stress difference, fracturing fluid injection rate and fracturing fluid viscosity on the propagation of hydraulic fractures were analyzed. The results show that when the angle between the natural fracture and the maximum horizontal principal stress direction ranges from 30° to 60°, the induced hydraulic fractures are the most complex. The increase in natural fracture strength is not conducive to the generation of branch and steering fractures. Under the condition of low horizontal principal stress difference, the orientation of natural fractures dominates the extension of hydraulic fractures. Under the condition of high horizontal principal stress difference, stress dominates the extension of hydraulic fractures. When the horizontal principal stress difference falls between 3.0 and 4.5 MPa, the hydraulic fractures exhibit the highest complexity and the largest extension. Increasing the injection rate of fracturing fluid can promote the formation of complex hydraulic fracture network. Appropriately increasing the viscosity of fracturing fluid can promote fracture propagation, but too high viscosity can only lead to complex fractures in limited areas around the perforations.
For heavy oil reservoirs, the enhanced oil recovery (EOR) mechanism of injecting different gases or compound of gases after multiple cycles of oxygen-reduced air huff and puff following water flooding is unclear. In this paper, experiments were conducted with one-dimensional and three-dimensional physical models, and numerical simulations were performed on well pair model and inverted five-spot well pattern model. Based on the comparative analysis on production and components of oil recovered in different cycles of huff and puff and flow process research, the oil displacement and washing mechanisms during huff and puff with three gases, i.e. oxygen-reduced air, CO2 and natural gas, in heavy oil reservoirs were discussed. The results show that the EOR mechanism of oxygen-reduced air huff and puff is dominated by water plugging, and the water front may readily break through after multiple cycles of operation and then fail quickly. The huff and puff with CO2 slug followed by oxygen-reduced air plays a synergy of water plugging and remaining oil displacement. The huff and puff with oxygen-reduced air injection followed by natural gas dissolves the heavy components of the oil in near-wellbore area, achieving multiple effects of increasing energy, reducing viscosity and dredging pores. EOR mechanisms of huff and puff with three gases and their compound have been clarified through the experiments and numerical simulations on 10 cycles of huff and puff, and have been verified by field wells. The conclusions are of guiding significance for enhancing oil recovery by gas huff and puff in similar reservoirs.
In order to understand the propagation and extension of hydraulic fractures in the sandy conglomerate reservoirs of Permian Wuerhe formation，Junggar basin，the influences of gravel characteristics，in-situ stress，and other factors on the fracture propagation were studied by using the Realistic Failure Process Analysis (RFPA) software. According to the results of numerical simulation，the fracture propagation process under different conditions was studied，the evolution and shape of the fractures were described，and a model for evaluating the fracabilty of the sandy conglomerate reservoirs was established. The results show that the gravel strength and matrix strength of Wuerhe formation are quite different. The gravel strength ranges from 216.62 MPa to 2 032.64 MPa，which is 2-4 times of matrix strength. The rock mechanical properties of conglomerates differ significantly. When gravel content is small，fracture propagation is mainly affected by principal stress. When the grain size of gravel is small，fractures mainly extend bypassing the gravel. With the increase of grain size or gravel content，the inhibition and shielding effects of gravel on fractures become obvious，which reduces the extension of fractures. The greater the difference between gravel strength and matrix strength，the stronger the fractures are blocked by the gravel，and the more easily the fractures extend in the way of bypassing the gravel rather than penetrating the gravel，which reduces the extension of fractures. Based on grey relational analysis (GRA) and analytic hierarchy process (AHP)，a model for calculating the fracabilty evaluation coefficient of the sandy conglomerate reservoirs was established，which considers the factors such as gravel characteristics and horizontal in-situ stress. The fracabilty evaluation coefficient is positively correlated with dimensionless fracture area and fluid production index per meter.
In this paper，the geological and development characteristics in the FQ oilfield in the Tarim basin were analyzed，and then the productivity test method，nozzle flow method and reservoir numerical simulation method were developed to optimize the reasonable productivity in ultra-deep fault-controlled fractured-vuggy reservoirs. The results show that the primary oil recovery of ultra-deep fault-controlled fractured-vuggy reservoirs can be divided into early stage，middle stage and late stage，which differ greatly in development characteristics. The ultra-deep fault-controlled fractured-vuggy reservoirs in the FQ oilfield exhibit four types of productivity test curves: convex，linear，upturned and stepped. For wells showing the convex curves，the productivity at the inflection of the curves is the reasonable productivity. For wells showing the linear and upturned curves，the maximum test productivity is the reasonable productivity，but the nozzle testing productivity needs to be continuously expanded until the inflection of the curves appears. For wells following the stepped curves，the maximum test productivity after reaching the step will be the reasonable productivity. When the well productivity is optimized by the nozzle flow method，the productivity at the inflection of the nozzle flow curves is the reasonable productivity. The reservoir numerical simulation method is suitable for optimizing the well productivity in the middle and late stages of primary oil recovery，that is，the reasonable productivity is determined by optimizing the key indicators such as water breakthrough time，cumulative oil production，and recovery rate.
Large errors often occur in the fitting of oil-water two-phase flow data with the Willhite mathematical model. In this paper，a new mathematical model of oil/water relative permeability was proposed. When fitting the relative permeability curves of oil phase and water phase，the new model can use the multiple linear regression method with a single variable to obtain the optimal solution. Especially，when fitting the arched relative permeability curves of water phase，the difference between the optimal estimate of undetermined parameters in the arched curves and the optimal estimate of undetermined parameters in common concave relative permeability curves of water phase is small，so that the relative permeability curves of the standard water phase for multiple rock samples determined by using the arithmetic mean method are basically located in the middle of the relative permeability curves of water phase. After obtaining the relative permeability curves of the standard oil/water phase，combining with the Welge equation after water breakthrough in the oil production well，and by using the water displacing oil analytical method，the formulas for calculating parameters such as the water saturation at the water flooding front，the average water saturation after the water flooding front，water cut，and oil displacement efficiency were determined. This study provides a new method for investigating the water flooding laws.
In different stages of the collaborative construction of underground gas storage (UGS) and gas flooding, the produced gas-oil ratio (GOR) varies greatly, and the complex oil, gas and water three-phase flow occurs in several stages. Currently, the multiphase productivity of UGS is generally calculated by converting oil production to gas equivalent, which produces relatively large errors. On the basis of the three-phase flow differential equation, the three-phase pseudo pressures of oil, gas and water were introduced, and a three-phase flow productivity calculation method considering the influence of high-speed non-Darcy flow of gas was established. With the help of this method, the oil phase productivity equation, gas phase productivity equation, and inflow performance relationship (IPR) curve in gas flooding stage, collaborative construction stage, and UGS stage were obtained and then compared with production data. The results show that the productivity calculated by the three-phase flow productivity calculation method is less than 6.16% in each of the three stages. When the production pressure difference is small, the calculation results from the traditional conversion method and the three-phase flow productivity calculation method are close. However, with the progress of construction, the error of the traditional conversion method becomes larger. The three-phase flow productivity calculation method is simple, accurate, and operable. It is of guiding significance for predicting the productivities in different stages of collaborative construction of UGS and gas flooding.
In order to determine the pore-throat structure and the mobility of crude oil in the shale reservoirs of the Lucaogou formation in the Jimsar sag，the reservoirs were classified by means of thin section identification，scanning electron microscope (SEM)，and experiments such as high-pressure mercury intrusion. The mobility of the shale oil was evaluated through a displacement-NMR combined experiment to reveal the movable oil proportion，pore size variation and its controlling factors，and then establish a quantitative evaluation model of shale oil mobility. The Lucaogou formation develops 5 types of reservoir spaces including intergranular pores，intergranular-dissolution-intercrystalline pores，dissolution pores，dissolution-intercrystalline pores，and intercrystalline pores. The intergranular pores are mainly found in the silty-fine sandstone and sandy dolomite，and exhibit the best mobility. The dissolution pores are mainly in the dolomitic siltstone，and exhibits moderate mobility. Other pores are mainly in mudstone，argillaceous dolomite and limy sandstone，and show poor mobility. The lower limit of pore throats for shale oil moving is determined to be 20 nm. When the pore throat size are 60 nm and 150 nm，the movability is significantly improved，which corresponds well to the tested production capacity. Shale oil occurrence and pore-throat structure jointly affect the mobility of shale oil. The pore throats and shale oil occurrence in silty-fine sandstone and dolomitic siltstone are the best，which are the most favorable lithofacies for developing the mixed shale oil in the Lucaogou formation.
