Injection Strategies To Overcome Gravity Segregation in Simultaneous Gas and Water Injection Into Homogeneous Reservoirs

SPE Journal ◽  
2009 ◽  
Vol 15 (01) ◽  
pp. 76-90 ◽  
Author(s):  
W.R.. R. Rossen ◽  
C.J.. J. van Duijn ◽  
Q.P.. P. Nguyen ◽  
C.. Shen ◽  
A.K.. K. Vikingstad
Keyword(s):  
Water Flow ◽  
Oil Recovery ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Numerical Dispersion ◽  
Horizontal Distance ◽  
Mixed Gas ◽  
Gravity Segregation ◽  
Vertical Well

Summary We extend a model for gravity segregation in steady-state gas/water injection into homogeneous reservoirs for enhanced oil recovery (EOR). A new equation relates the distance gas and water flow together directly to injection pressure, independent of fluid mobilities or injection rate. We consider three additional cases: coinjection of gas and water over only a portion of the formation interval, injection of water above gas over the entire formation interval, and injection of water and gas in separate zones well separated from each other. If gas and water are injected at fixed total volumetric rates, the horizontal distance to the point of complete segregation is the same, whether gas and water are coinjected over all or any portion of the formation interval. At fixed injection pressure, the deepest penetration of mixed gas and water flow is expected when fluids are injected along the entire formation interval. At fixed total injection rate, injection of water above gas gives deeper penetration before complete segregation than does coinjection, but again exactly where the two fluids are injected does not affect the distance to the point of segregation. At fixed injection pressure, injection of water above gas is predicted to give deeper penetration before complete segregation. When injection pressure is limited, the best strategy for simultaneous injection of both phases from a vertical well would be to inject gas at the bottom of the reservoir and water over the rest of the reservoir height, with the ratio of the injection intervals adjusted to maximize overall injectivity. The 2D model applies equally to gas/water flow and to foam, and to injection of water above gas from separate intervals of a vertical well or from two parallel horizontal wells, as long as injection is uniform along each horizontal well. Sample computer simulations for foam injection agree well with the model predictions if numerical dispersion is controlled.

The Research and Evaluation of Finely Layered Water Injection Standard in Low-Permeability Reservoirs - A Case from Block A in one Low-Permeability Reservoir

2014 ◽  
Vol 1073-1076 ◽  
pp. 2310-2315 ◽  
Author(s):  
Ming Xian Wang ◽  
Wan Jing Luo ◽  
Jie Ding
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Low Permeability ◽  
Reservoir Permeability ◽  
Engineering Parameters ◽  
The Common ◽  
Common Problems ◽  
Low Permeability Reservoirs

Due to the common problems of waterflood in low-permeability reservoirs, the reasearch of finely layered water injection is carried out. This paper established the finely layered water injection standard in low-permeability reservoirs and analysed the sensitivity of engineering parameters as well as evaluated the effect of the finely layered water injection standard in Block A with the semi-quantitative to quantitative method. The results show that: according to the finely layered water injection standard, it can be divided into three types: layered water injection between the layers, layered water injection in inner layer, layered water injection between fracture segment and no-fracture segment. Under the guidance of the standard, it sloved the problem of uneven absorption profile in Block A in some degree and could improve the oil recovery by 3.5%. The sensitivity analysis shows that good performance of finely layered water injection in Block A requires the reservoir permeability ratio should be less than 10, the perforation thickness should not exceed 10 m, the amount of layered injection layers should be less than 3, the surface injection pressure should be below 14 MPa and the injection rate shuold be controlled at about 35 m3/d.

scholarly journals Experimental Study on Enhanced Oil Recovery by Nitrogen-Water Alternative Injection in Reservoir with Natural Fractures

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Xiang Li ◽  
Yuan Cheng ◽  
Wulong Tao ◽  
Shalake Sarulicaoketi ◽  
Xuhui Ji ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Water Flooding ◽  
Orthogonal Experimental Design ◽  
Fractured Reservoir ◽  
Natural Fractures ◽  
Nitrogen Injection

The production of a low permeability reservoir decreases rapidly by depletion development, and it needs to supplement formation energy to obtain stable production. Common energy supplement methods include water injection and gas injection. Nitrogen injection is an economic and effective development method for specific reservoir types. In order to study the feasibility and reasonable injection parameters of nitrogen injection development of fractured reservoir, this paper uses long cores to carry out displacement experiment. Firstly, the effects of water injection and nitrogen injection development of a fractured reservoir are compared through experiments to demonstrate the feasibility of nitrogen injection development of the fractured reservoir. Secondly, the effects of gas-water alternate displacement after water drive and gas-water alternate displacement after gas drive are compared through experiments to study the situation of water injection or gas injection development. Finally, the reasonable parameters of nitrogen gas-water alternate injection are optimized by orthogonal experimental design. Results show that nitrogen injection can effectively enhance oil production of the reservoir with natural fractures in early periods, but gas channeling easily occurs in continuous nitrogen flooding. After water flooding, gas-water alternate flooding can effectively reduce the injection pressure and improve the reservoir recovery, but the time of gas-water alternate injection cannot be too late. It is revealed that the factors influencing the nitrogen-water alternative effect are sorted from large to small as follows: cycle injected volume, nitrogen and water slug ratio, and injection rate. The optimal cycle injected volume is around 1 PV, the nitrogen and water slug ratio is between 1 and 2, and the injection rate is between 0.1 and 0.2 mL/min.

The Porous Medium of Ultra-Low Permeability Reservoir has an Effect on Oil Recovery

2013 ◽  
Vol 779-780 ◽  
pp. 1457-1461
Author(s):  
Xian Wen Li ◽  
Chun Mei Xu ◽  
Fang Yuan Guo ◽  
Xing Hong Wang
Keyword(s):  
Porous Medium ◽  
Oil Recovery ◽  
Research Result ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Rate ◽  
Particle Migration ◽  
Low Permeability ◽  
Reservoir Water ◽  
Low Permeability Reservoir

This paper from the research of the porous medium pore structure characteristics of ultra-low permeability reservoir, combined the core flow test with reservoir characteristics analysis and fluid properties analysis studying the reservoir water injection development effect. The research results show that: the microscopic heterogeneity of ultra-low permeability reservoir is strong, pore connectivity of porous medium is poor, seepage throat is very fine and microcrack is growth. During the process of water injection development there exist particle migration phenomenon, could easily cause pore throat blockage, and lead to water injection pressure rebound. According to the research result targeted on the organic mud acid deep broken down experiment, the result shows that it can achieve the purpose of depressure and increasing injection rate.

scholarly journals Study Rheological Behavior of Polymer Solution in Different-Medium-Injection-Tools

Polymers ◽  
2019 ◽  
Vol 11 (2) ◽  
pp. 319 ◽  
Author(s):  
Bin Huang ◽  
Xiaohui Li ◽  
Cheng Fu ◽  
Ying Wang ◽  
Haoran Cheng
Keyword(s):  
Molecular Weight ◽  
Polymer Solution ◽  
Oil Recovery ◽  
Injection Pressure ◽  
Injection Rate ◽  
Injection Velocity ◽  
Structural Parameter ◽  
Local Perturbation ◽  
Polymer Injection ◽  
Single Pipe

Previous studies showed the difficulty during polymer flooding and the low producing degree for the low permeability layer. To solve the problem, Daqing, the first oil company, puts forward the polymer-separate-layer-injection-technology which separates mass and pressure in a single pipe. This technology mainly increases the control range of injection pressure of fluid by using the annular de-pressure tool, and reasonably distributes the molecular weight of the polymer injected into the thin and poor layers through the shearing of the different-medium-injection-tools. This occurs, in order to take advantage of the shearing thinning property of polymer solution and avoid the energy loss caused by the turbulent flow of polymer solution due to excessive injection rate in different injection tools. Combining rheological property of polymer and local perturbation theory, a rheological model of polymer solution in different-medium-injection-tools is derived and the maximum injection velocity is determined. The ranges of polymer viscosity in different injection tools are mainly determined by the structures of the different injection tools. However, the value of polymer viscosity is mainly determined by the concentration of polymer solution. So, the relation between the molecular weight of polymer and the permeability of layers should be firstly determined, and then the structural parameter combination of the different-medium-injection-tool should be optimized. The results of the study are important for regulating polymer injection parameters in the oilfield which enhances the oil recovery with reduced the cost.

scholarly journals A Numerical Method for Computing Recovery of Oil By Hot Water Injection in a Radial System

1965 ◽  
Vol 5 (02) ◽  
pp. 131-140 ◽  
Author(s):  
K.P. Fournier
Keyword(s):  
Thermal Expansion ◽  
Oil Recovery ◽  
Viscosity Ratio ◽  
Water Injection ◽  
Injection Rate ◽  
Heat Losses ◽  
Hot Water ◽  
Radial System ◽  
System Equation ◽  
Finite Difference Equations

Abstract This report describes work on the problem of predicting oil recovery from a reservoir into which water is injected at a temperature higher than the reservoir temperature, taking into account effects of viscosity-ratio reduction, heat loss and thermal expansion. It includes the derivation of the equations involved, the finite difference equations used to solve the partial differential equation which models the system, and the results obtained using the IBM 1620 and 7090–1401 computers. Figures and tables show present results of this study of recovery as a function of reservoir thickness and injection rate. For a possible reservoir hot water flood in which 1,000 BWPD at 250F are injected, an additional 5 per cent recovery of oil in place in a swept 1,000-ft-radius reservoir is predicted after injection of one pore volume of water. INTRODUCTION The problem of predicting oil recovery from the injection of hot water has been discussed by several researchers.1–6,19 In no case has the problem of predicting heat losses been rigorously incorporated into the recovery and displacement calculation problem. Willman et al. describe an approximate method of such treatment.1 The calculation of heat losses in a reservoir and the corresponding temperature distribution while injecting a hot fluid has been attempted by several authors.7,8 In this report a method is presented to numerically predict the oil displacement by hot water in a radial system, taking into account the heat losses to adjacent strata, changes in viscosity ratio with temperature and the thermal-expansion effect for both oil and water. DERIVATION OF BASIC EQUATIONS We start with the familiar Buckley-Leverett9 equation for a radial system:*Equation 1 This can be written in the formEquation 2 This is sometimes referred to as the Lagrangian form of the displacement equation.

Reinforcement Learning From Pixels: Waterflooding Optimization

2020 ◽  
Author(s):  
Ruslan Miftakhov ◽  
Igor Efremov ◽  
Abdulaziz S. Al-Qasim
Keyword(s):  
Reinforcement Learning ◽  
Net Present Value ◽  
Vertical Section ◽  
Water Injection ◽  
Petroleum Industry ◽  
Injection Pressure ◽  
Injection Rate ◽  
Simulation Engine ◽  
First Case ◽  
The Impact

Abstract The application of Artificial Intelligence (AI) methods in the petroleum industry gain traction in recent years. In this paper, Deep Reinforcement Learning (RL) is used to maximize the Net Present Value (NPV) of waterflooding by changing the water injection rate. This research is the first step towards showing that the use of pixel information for reinforcement learning provides many advantages, such as a fundamental understanding of reservoir physics by controlling changes in pressure and saturation without directly accounting for the reservoir petrophysical properties and wells. The optimization routine based on RL by pixel data is tested on the 2D model, which is a vertical section of the SPE 10 model. It has been shown that RL can optimize waterflooding in a 2D compressible reservoir with the 2-phase flow (oil-water). The proposed optimization method is an iterative process. In the first few thousands of updates, NPV remains in the baseline since it takes more time to converge from raw pixel data than to use classical well production/injection rate information. RL optimization resulted in improving the NPV by 15 percent, where the optimum scenario shows less watercut values and more stable production in contrast to baseline optimization. Additionally, we evaluated the impact of selecting the different action set for optimization and examined two cases where water injection well can change injection pressure with a step of 200 psi and 600 psi. The results show that in the second case, RL optimization is exploiting the limitation of the reservoir simulation engine and tries to imitate a cycled injection regime, which results in a 7% higher NPV than the first case.

Research of Improving Water Injection Effect by Using Active SiO2 Nano-Powder in the Low-Permeability Oilfield

2010 ◽  
Vol 92 ◽  
pp. 207-212 ◽  
Author(s):  
Ke Liang Wang ◽  
Shou Cheng Liang ◽  
Cui Cui Wang
Keyword(s):  
Oil Recovery ◽  
Pore Volume ◽  
Water Injection ◽  
Field Tests ◽  
Injection Pressure ◽  
Rock Surface ◽  
Low Permeability ◽  
Injection Wells ◽  
Decompression Rate ◽  
Nano Powder

SiO2 nano-powder is a new type of augmented injection agent, has the ability of stronger hydrophobicity and lipophilicity, and can be adsorbed on the rock surface so that it changes the rock wettability. It can expand the pore radius effectively, reduce the flow resistance of injected water in the pores, enhance water permeability, reduce injection pressure and augment injection rate. Using artificial cores which simulated geologic conditions of a certain factory of Daqing oilfield, decompression and augmented injection experiments of SiO2 nano-powder were performed after waterflooding, best injection volume of SiO2 nano-powder under the low-permeability condition was selected. It has shown that SiO2 nano-powder inverted the rock wettability from hydrophilicity to hydrophobicity. Oil recovery was further enhanced after waterflooding. With the injection pore volume increasing, the recovery and decompression rate of SiO2 nano-powder displacement increased gradually. The best injected pore volume and injection concentration is respectively 0.6PV and 0.5%, the corresponding value of EOR is 6.84% and decompression rate is 52.78%. According to the field tests, it is shown that, in the low-permeability oilfield, the augmented injection technology of SiO2 nano-powder could enhance water injectivity of injection wells and reduce injection pressure. Consequently, it is an effective method to resolve injection problems for the low-permeability oilfield.

Optimizing Recovery for Waterflooding Under Dynamic Induced Fracturing Conditions

2009 ◽  
Vol 12 (05) ◽  
pp. 671-682 ◽  
Author(s):  
Paul J. van den Hoek ◽  
Rashid A. Al-Masfry ◽  
Dirk Zwarts ◽  
Jan-Dirk Jansen ◽  
Bernhard Hustedt ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Injection Rate ◽  
Reservoir Engineering ◽  
Spot Pattern ◽  
Engineering Parameters ◽  
Induced Fractures ◽  
Modeling Strategy ◽  
Reservoir Simulator ◽  
Fully Coupled

Summary It is well established within the industry that water injection mostly takes place under induced fracturing conditions. Particularly in low-mobility reservoirs, large fractures may be induced during the field life. This paper presents a new modeling strategy that combines fluid flow and fracture growth (fully coupled) within the framework of an existing "standard" reservoir simulator. We demonstrate the coupled simulator by applications to repeated five-spot pattern flood models, addressing various aspects that often play an important role in waterfloods: shortcut of injector and producer, fracture containment to the reservoir layer, and areal and vertical reservoir sweep. We also demonstrate how induced fracture dimensions (length, height) can be very sensitive to typical reservoir engineering parameters, such as fluid mobility, mobility ratio, 3D saturation distribution (in particular, shockfront position), 3D temperature distribution, positions of wells (producers, injectors), and geological details (e.g., layering and faulting). In particular, it is shown that lower overall (time-dependent) reservoir transmissibility will result in larger induced fractures. Finally, it is demonstrated how induced fractures can be taken into account to determine an optimum life-cycle injection rate strategy. The results presented in this paper are expected to also apply to (part of) enhanced-oil-recovery operations (e.g., polymer flooding).

scholarly journals Impact of injection rate on transient oil recovery under mixed-wet conditions: a microfluidic study

2019 ◽  
Vol 89 ◽  
pp. 04002 ◽  
Author(s):  
Magali Christensen ◽  
Xanat Zacarias-Hernandez ◽  
Yukie Tanino
Keyword(s):  
Oil Recovery ◽  
Strong Dependence ◽  
Water Injection ◽  
Microfluidic Channel ◽  
Early Time ◽  
Packed Bed ◽  
Injection Rate ◽  
End Effects ◽  
Oil Saturation ◽  
End Point

Lab-on-a-chip methods were used to visualize the pore-scale distribution of oil within a mixed-wet, quasi-monolayer of marble grains packed in a microfluidic channel as the oil was displaced by water. Water injection rates corresponding to microscopic capillary numbers between Ca = 5 × 10-8 and 2 × 10-4 (Darcy velocities between 0.3 and 1100 ft/d) were considered. As expected, early-time water invasion transitions from stable displacement to capillary fingering with decreasing Ca, with capillary fingering observed at Ca ≤ 10-5. End-point oil saturation decreases with Ca over the entire range of Ca considered, consistent with the canonical capillary desaturation curve. In contrast, Sor derived from approximate numerical simulations using reasonable Pc(Sw) do not display a strong dependence on Ca. These results suggest that the Ca dependence of end-point oil saturation is largely due to capillary end effects which, under conditions considered presently, affect the entire length of the packed bed.

The Perspective of Novel Chemical Tracer Technology in Reservoir Surveillance and Hydrodynamic Modelling for More Efficient Hydrocarbon Recovery

2021 ◽  
Author(s):  
Nadir Husein ◽  
Evgeny Aleksandrovich Malyavko ◽  
Ruslan Rashidovich Gazizov ◽  
Anton Vitalyevich Buyanov ◽  
Aleksey Aleksandrovich Romanov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Continuous Production ◽  
Economic Effect ◽  
Water Injection ◽  
Injection Rate ◽  
Reservoir Pressure ◽  
Entire Area ◽  
Field Development ◽  
Oil Companies ◽  
Maintenance System

Abstract Today, efficient field development cannot be managed without proper surveillance providing oil companies with important geological and engineering information for prompt decision-making. Once continuous production is achieved, it is necessary to maintain a consistently high level of oil recovery. As a rule, a reservoir pressure maintenance system is extensively implemented for this purpose over the entire area because of decreasing reservoir pressure. At the same time, it is important to adjust the water injection to timely prevent water cut increasing in production wells, while maintaining efficient reservoir pressure compensation across the field. That is why it is necessary to have a relevant inter-well hydrodynamic model as well as to quantify the water injection rate. There are many ways to analyse the efficiency of the reservoir pressure maintenance system, but not all of them yield a positive, and most importantly, a reliable result. It is crucial that extensive zonal production surveillance efforts generate a significant economic effect and the information obtained helps boost oil production. Thus, the main objective of this paper is to identify a method and conduct an effective study to establish the degree of reservoir connectivity and quantify the inter-well parameters of a low permeability tested field.

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