Multilayer Reservoir Research Articles

A New Methodology for the Multilayer Tight Oil Reservoir Water Injection Efficiency Evaluation and Real-Time Optimization

It is important to determine the reasonable injection and production rates in the development of multilayer tight oil reservoir with water flooding treatment. Based on the INSIM (interconnection-based numeric simulation model), a connected network model, a new method is designed to evaluate the water injection efficiency of different layers in water flooding reservoirs and to optimize the injection-production system to produce more oil. Based on the types of sedimentary facies and corresponding injection-production data, the interwell connections are divided into four major categories (middle channel, channel edge, middle channel bar, and channel bar edge) and twelve subclasses. This classification standard of interwell connections could help to significantly improve the accuracy of judging the dominant flow path without constructing a complicated geological model. The interaction of interwells such as injection-production correlation and water injection efficiency could be revealed by simulating the production performance and computing the layer dividing coefficient and well dividing coefficient. A numerical example is used to validate this method by comparing results from FrontSim and this method, and the computational efficiency of this method is several dozen times faster than that of the traditional numerical simulation. This method is applied to quickly optimize the production schedule of a tight oil reservoir with the water flooding treatment, that is, the water injection rate of multilayer reservoirs could be optimized subtly by the injection efficiency of different layers, and the target of producing more oil with lower water cut could be achieved.

A new prediction method of reservoir porosity based on improved Kriging interpolation

In the process of oil and gas field development, the pore characteristics of reservoir are the main factors that affect the reservoir capacity and production efficiency. The physical property parameters and pressure distribution of layers have changed greatly, and the pressure system of multi-pressure layer is formed underground of multi-layer reservoir and heterogeneous sandstone oil reservoir after water injection and chemical injection. Accurate prediction of reservoir physical properties and formation pressure distribution after changes is significance for efficient production and safe operation of reservoirs. In this paper, based on geostatistics theory and percolation mechanics theory, combined with reservoir geology, drilling, development and testing data of Bohai Oilfield, the prediction method of reservoir porosity based on improved Kriging interpolation and effective thickness has been established. This prediction method can provide certain guidance for the formulation of oilfield injection and production distribution plans at the oilfield and the shut-in and adjustment plans for injection-production wells during drilling and completion operations.

On the possibility of operational management of reservoir pressure in a multilayer reservoir exploited by dual completion and injection method based on recording current gas factor of products extracted from each reservoir

The paper discusses the problem of operating complex and expensive telemetering equipment designed to monitor and control a multilayer field operation using the dual completion and injection method. The author offers an alternative to the applied wireless and wired data transmission (as the first type does not have the required range and the second does not have the required reliability) technology. It is a new method for monitoring and controlling reservoir pressure in real time based on recording the current gas factor of the products extracted from each layer using dual completion method and ensuring its relative stability due to the operational management of their reservoir pressure through the dual injection system. At the same time, it is proposed to use commercially available automated group measure unit equipped with corresponding sensors as the means of measuring gas/oil ratio. Testing the method of reservoir pressure management proposed by the author for the two-layer reservoir of the Tedinskoye field of Lukoil-Severneftegaz confirmed its effectiveness, which served as the basis for the development of an appropriate methodological guide and filing of a patent.

ES-MDA applied to estimate skin zone properties from injectivity tests data in multilayer reservoirs

Estimating reservoir properties, such as the skin factor, is an essential role of injectivity tests. Nevertheless, determining individual layer properties in multilayer systems remains a difficult task. Some techniques have been proposed to compute layer permeabilities and skin factors based on the pressure response of reservoirs under single-phase flow. Regardless, determining layer skin zone permeability and radius remains challenging. Ensemble-based techniques are optimization methods known for its easy implementation and good data match when estimating model parameters. Notably, the ensemble smoother with multiple data assimilation (ES-MDA) has proven to be a powerful parameter estimation tool. Thereby, this work attempts to apply the ES-MDA to determine individual layer skin zone properties. To the best of the authors’ knowledge, this is the first time that ES-MDA is applied to this problem. In all tested cases, the resulting histogram contains the reference parameters. We also presented a sensitivity study regarding the performance of ES-MDA when different number of assimilations and ensemble sizes are used.

Problems and methods of hydraulic fracturing in multilayered oil reservoirs with the continuous perforation

One of the most common problems during hydraulic fracturing (HF) in the oil fields of Kazakhstan is a continuous perforation of all productive layers in the section of pay zone, which subsequently causes many risks of a different nature during fracking operations and difficulties in the development of oil reserves. Despite the historical reality, which is an actual problem, there are currently attempts to do fracturing in such difficult conditions. The main complicating factor is the formation of not one long fracture, but the development of several short fractures parallel to each other. This necessitates further development of technology in order to improve the efficiency of hydraulic fracturing.

Neural Network Production Split Model Based on Kriging Interpolation Method and Grey Correlation Analysis Method

Oil well production split is an important prerequisite for the efficient development of multi-layered reservoir. Conventional split methods do not consider the synergistic influence of dynamic and static factors related to the oil layer with certain errors. Based on the related dynamic and static parameters of production wells and production data, a neural network split model considering Kriging interpolation and grey correlation method was established. Before the model is established, the involved data is first sorted, and Kriging interpolation is used to complete the data at the appropriate time. Then, the grey correlation analysis method is used to calculate the correlation of the dynamic and static parameters related to reservoir production, and the main parameters of it are extracted. The main parameters are treated as input and substituted into the double hidden layer neural network for modelling, and the resulting model is used to split the production of each layer of the oil well. This method is applied to the production well of the N block of the Y Oilfield. Compared with the conventional method, the accuracy is significantly improved, which is in line with the actual reservoir characteristics.

Transient Behavior of Vertical Commingled Well in Vertical Non-Uniform Boundary Radii Reservoir

Transient behavior analysis, including rate transient analysis (RTA) and pressure transient analysis (PTA), is a powerful tool to investigate the production performance of the vertical commingled well from long-term production data and capture the formation parameters of the multilayer reservoir from transient well testing data. Current transient behavior analysis models hardly consider the effect of vertical non-uniform boundary radii (VNBR) on transient performances (rate decline and pressure response). The VNBR may cause an obvious novel radial flow regime and rate decline type, which can easily be mistaken as a radial composite reservoir. In this paper, we present a VNBR transient behavior analysis model, the extended vertical uniform boundary radii (VUBR), to investigate the rate decline behavior and pressure response characteristics through diagnostic type curves. Results indicate that the dimensionless production integral derivative curve or pressure derivative curve can magnify the differences so that we can diagnose the outer-convex shape and size of the VNBR. Therefore, it is significant to incorporate the effects of VNBR into the transient behavior analysis models of the vertical commingled well, and the model proposed in this paper enables us to better evaluate well performance, capture formation characteristics and diagnose flow regimes based on rate/pressure transient data.

Assessment of the Oil and Gas Potential of the Basement of the Southern Part of the Siberian Platform and Deep-Seated Oil Exploration

The main goal is to assess the oil and gas potential of the basement of the southern part of the Siberian Platform as an additional source for the long-term filling of the East Siberia–Pacific Ocean pipeline with hydrocarbons. The initial reserves in the fields, which were discovered in the sedimentary cover on the Siberian Platform, are far below the reserves of the fields of Western Siberia and the Volga Region, where the drilling of deep wells showed the connection of reserves with the basement; the reserves are renewed in a natural way. On the Siberian Platform, the drilling usually ended at the “cover–basement” boundary (at the most productive level). In the wells, there are the following signs that indicate the oil and gas potential of the basement: “black” zircons in granitoids containing radioactive elements, multi-layered oil reservoirs, which are associated with deep faults, and mantle fluids bearing hydrogen and liquid hydrocarbons. Based on the signs listed, which indicate the promising basement rocks, it is necessary to change the existing methods for prospecting and evaluating oil in the sedimentary cover and to focus on the exploration of heavy deep oil in the basement rocks.

Algorithm For Constructing Modified Relative Phase Permeability For The Average Model Of Three-Phase Filtration In A Multilayered Layer

The paper presents models of relative phase permeabilities for laboratory relative phase permeabilities. A technique has been developed for modifying the relative phase permeabilities taking into account the jet flow. Using a computational experiment, the applicability of the proposed averaged models was investigated. The models described in the article are applicable in numerical calculations for multilayered reservoirs in order to reduce the dimension of the problems under consideration.

Research on profile inversion controlling methods of multi-slug polymer alternative injection

ABSTRACTThe development practice of polymer flooding shows that the injection profile easily inverses during the process of single slug polymer flooding. The low effective or ineffective circulation of abundant injecting water in high permeability layer, low producing degree of low permeability layer and large polymer volume have influenced the sweep efficiency and oil recovery of polymer flooding. In view of these questions, the alternative injection method of various viscosity polymer slugs is studied. This paper explains the theory of enhanced oil recovery of multi-slug polymer alternative injection. The experiment results show that the alternative injection of high and low viscosity polymer slugs has a better effect than single slug polymer flooding. The mobility differences between high-low permeability layers can be effectively reduced. For a multi-layer heterogeneous reservoir, there is an optimal alternative cycle. Reasonable slug size can not only inhibit dominant channel forming in high permeability layer but also can effectively produce low permeability layer and control profile inversion to a certain extent. This provides a technical support for studying the controlling methods of profile inversion.

Experimental Investigation of Oil Recovery Performance and Permeability Damage in Multilayer Reservoirs after CO2 and Water–Alternating-CO2 (CO2–WAG) Flooding at Miscible Pressures

Blockage in reservoirs caused by asphaltene deposits and inorganic interactions is a serious problem that may exacerbate the complexity of displacement characteristics in heterogeneous multilayer s...

Secondary formation damage of low-pressure layer during commingled production in multilayered tight gas reservoirs

This paper experimentally investigates fluid back-flow behavior and formation damage during commingled production in multilayered tight gas reservoirs. The development of fluid back-flow in commingled tight gas reservoirs was simulated using a newly designed experimental platform. The results indicate that when there is a pressure difference between different layers during commingled production from tight gas reservoir, water produced from the high-pressure layer will invade the low-pressure layer along with gas back-flow and will accumulate in the near-wellbore area. This will lead to an increase in water saturation and a decline in permeability in the low-pressure layer and result in a significant reduction in ultimate recovery. The outcomes of these experiments demonstrate that as well as the formation damage caused by the working fluid during drilling and fracturing, “Secondary Formation Damage” also occurs during commingled production in multilayered tight gas reservoirs. This secondary formation damage mainly occurs in the near-wellbore area of low-pressure layers and is more severe with greater proximity to the wellbore. Through further experimentation to assess the factors influencing secondary formation damage, it is shown that the degree of secondary formation damage increases with decreasing original formation pressure, original water saturation, and permeability in the lower-pressure layer.

Determining skin zone properties from injectivity tests in single- and multilayer reservoirs

This work proposes an interpretation technique for injectivity tests that provides a new estimation for skin zone permeability and radius in single-layer reservoirs. A means to compute the reservoir skin factor in multilayer commingled reservoirs is also presented. Under the assumption that layer flow-rates are decoupled, the suggested method was extended to compute individual layer permeabilities and skin factors. The results indicate that this hypothesis is valid in reservoirs where layer skin factors are similar.

Experimental evaluation of interlayer interference during commingled production in a tight sandstone gas reservoir with multi-pressure systems

With consideration of its effectiveness and efficiency, commingled production of coalbed methane has been widely adopted for a multi-layer reservoir, though strong interlayer interference and backflow may occur. In this paper, techniques have been developed to experimentally evaluate the performance of commingled production in a tight sandstone gas reservoir with interlayer interference. Core samples with different physical properties are then employed to evaluate the performance of multi-pressure commingled production with long cores, while its interlayer interference is characterized. Gas is mainly produced from a relatively high pressure layer at the early stage, when backflow occurs in a relatively low pressure layer. During the commingled production stage, the relatively low pressure layer with good physical properties will contribute the most to gas production. Furthermore, the larger the net gas production rate is, the shorter the backflow time will be. In addition to honoring the power-law relationship between flow rate and backflow time, shut-in operation has imposed a negative impact on the multi-layer commingled production.

Characterizing CO2 plume migration in multi-layer reservoirs with strong heterogeneity and low permeability using time-lapse 2D VSP technology and numerical simulation

One of the great challenges in carbon capture and storage (CCS) development is the monitoring and determination of the underground CO2 plume migration. We show that time-lapse 2D vertical seismic profiling (VSP) technology can support the monitoring and numerical modeling of CO2 plume migration at a storage site. Using the Shenhua CCS demonstration project in China as a case study, we predicted the physical parameters of the main reservoir, including the distribution of bodies of sandstone and their porosity and permeability, required to upgrade the geological model. We also interpreted the characteristics of historical CO2 plume migration in one seismic profile of the second and third periods of VSP monitoring. Based on a new upgraded geological model, we simulated the historical CO2 plume migration characteristics under the actual injection scenario of the demonstration project. The results of the simulation exhibited good consistency with the time-lapse VSP monitored in the profile, thus indicating that both the geological and numerical models have a certain degree of credibility. We further simulated the characteristics of CO2 plume migration after the injection well shutoff before 2035.

Numerical solution of the inverse coefficient problem of filtration in a multilayer reservoir

This work proposes a computational algorithm based on the regularization method for determining the hydraulic conductivity coefficient of a layered oil reservoir. The results of hydrodynamic investigations of vertical wells, opening a layered reservoir, are used as initial information.

A Multilayer Reservoir Thermal Stratification Module for Earth System Models

AbstractThermal stratification in reservoirs is a critical process that regulates downstream riverine energy and biogeochemical cycling. Current stratification models either simplify vertical energy process, reservoir geometry or neglecting the effects of reservoir operation. Here we present a new multilayer reservoir stratification model that can be applied for reservoir and stream temperature simulation at regional or global scale. With a multilayer vertical discretization, we introduce a newly developed storage‐area‐depth dataset to improve parameterization of advection processes in and out of the reservoir. The new model better represents vertical temperature gradient and subsequently temperature of water released to downstream. The stratification model is applied to 1,400 reservoirs over the contiguous United States and validated against observed surface, profile, and outflow temperature data over 130 reservoirs subjected to various levels of regulation. The Nash‐Sutcliffe values are higher than 0.5 for about 77% of the validated reservoirs using surface temperature while the average values of root mean square error and bias are 3.6 °C and −1.1 °C, respectively. Using the new reservoir storage‐area‐depth dataset improves the simulation of surface temperature at over 69% of the validated reservoirs compared to using simplified reservoir geometry. The reservoir stratification model contributes to improving predictive understanding of anthropogenic impact on terrestrial hydrological, ecological, and biogeochemical cycles.

Layer regrouping optimization for multilayer heterogeneous reservoirs at a high water cut stage

Due to the vertical heterogeneity of the multilayer reservoirs, which results in a great interlayer interference, the recovery of each layer is significantly different when all layers are perforated and produced simultaneously. The layer with poor reservoir properties has a smaller recovery than that with good reservoir properties. Layer regrouping is an effective method to reduce interlayer interference and improve the recovery of the layer with poor reservoir properties. However, not all layer regrouping programs are reasonable when considering the relationship of investment and income. We must find the optimal layer regrouping program. In this paper, we generate all possible layer regrouping programs by using the enumeration method with the second kind Stirling numbers. The optimal layer regrouping program is obtained with considering the effect of technique and economic factors. Based on the theory of Buckley-Leveret displacement, the cumulative oil production of each program is obtained. The more oil produced, the more favorable the program is. The feasibility of layer regrouping program is seriously depended on economic benefits, which can be calculated by net present value method. The feasibility of layer regrouping program under different drilling well number and crude oil price is analyzed. Finally, a case for layer regrouping optimization is introduced. From the case, we can conclude that when oil price is $70 per barrel and drilling well number is 2, the 237th program is the optimal layer regrouping program, whose net present value is 422.44 × 104 Chinese yuan.

Analytical approach for injection profiling through warm-back analysis in multilayer reservoirs

Injection profiling in multilayer (stratified) reservoirs is essential for successful water flooding and effective reservoir management. When possible, injection profiling may be achieved via production logging tools (PLT). An alternative approach is to utilize real-time temperature obtained e.g. via fiber optic distributed temperature sensing (DTS) to obtain the injection profiles. Development of modelling tools is required to enable analyzing temperature data to obtain the injection profiling.In this work, an analytical solution is developed to determine the transient temperature distribution in the reservoir during the warm-back period that follows cold fluid injection. The analytical model is used to introduce a temperature inversion approach to obtain the injection profile. The analytical solution is developed for single- and multi-layer reservoirs considering single-phase flow at constant rate over the injection period. The solution considers heat transfer by conduction and convection during the injection period. Warm-back is attained during the subsequent shut-in period through heat transfer by conduction in the reservoir (thermal equilibration) as well as the heat exchange between the completed layers and the surroundings. Heat transfer with the surrounding layers affects the warm-back rate the most for relatively thin layers. The analytical solution is verified through comparison against numerical simulation results obtained using a thermally coupled numerical simulator for single- and multi-layer reservoir cases. Graphical interpretation techniques are introduced by recasting the analytical solution into convenient forms. The graphical techniques are applied to synthetic warm-back data to illustrate their reliability and accuracy in obtaining the injection profile and the thermal front extent (per layer) during the injection period.

Characteristics and controlling factors of deep buried-hill reservoirs in the BZ19-6 structural belt, Bohai sea area

The BZ19-6 deep buried-hill structural belt in the southwest of Bozhong Sag, Bohai Bay Basin, is a newly discovered super-giant oil and gas bearing area. The study on its reservoirs is still in the early stage, and the characteristics and control factors of reservoir development are not understood deeply. In this paper, cores, sidewall cores, rock sections were analyzed and described. Then, based on regional structural setting, mud logging and logging data, the buried-hill reservoirs in this area were analyzed from the aspects of petrological characteristics, reservoir space types and physical properties, the inherent factors influencing the development of the reservoirs were discussed, and distribution laws of the reservoirs were investigated. And the following research results were obtained. First, the deep buried-hill reservoirs of this belt are a pan-buried hill reservoir system composed of the Palaeocene–Eocene Kongdian Fm glutenite in the upper part and the Archean buried-hill metamorphic granite in the lower part. A multi-layer reservoir structure of glutenite pore zone, weathering crust dissolution fracture zone and inner fracture zone is formed. These reservoirs are complex in genesis and diverse in type. Second, the Archean buried-hill metamorphic granite reservoir can be vertically divided into weathering crust, inner fracture zone and tight zone, and it presents the dual characteristics of porous and fractured media. Third, the buried-hill weathering crust is mainly affected by strong dissolution and leaching superimposed with fracturing, forming fractured-porous reservoir space. The reservoir of inner fracture zone is mainly controlled by the superimposition of three-phrase fractures, which forms the main development period of buried-hill fractures since the Yanshanian. Fourth, the glutenite of Kongdian Fm is a typical sieve deposit and it is mainly controlled by the late dissolution. Fifth, migmatization and supercritical fluid cryptoexplosion play a constructive role in the development of the reservoirs. In conclusion, the understanding of buried-hill glutenite and metamorphic reservoir system developed in this belt is conductive to determining the target and direction of next oil and gas exploration in this area.