The Effect of Water-Induced Stress To Enhance Hydrocarbon Recovery in Shale Reservoirs

SPE Journal ◽  
2013 ◽  
Vol 18 (05) ◽  
pp. 897-909 ◽  
Author(s):  
Perapon Fakcharoenphol ◽  
Sarinya Charoenwongsa ◽  
Hossein Kazemi ◽  
Yu-Shu Wu
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Reservoir Pressure ◽  
Reservoir Temperature ◽  
Hydrocarbon Recovery ◽  
Induced Stress ◽  
Stress Changes ◽  
Matrix Blocks ◽  
The Matrix ◽  
Shale Reservoirs

Summary Waterflooding has been an effective improved-oil-recovery (IOR) process for several decades. However, stress induced by waterflooding has not been well studied or documented. Water injection typically increases reservoir pressure and decreases reservoir temperature. The increase in reservoir pressure and decrease in reservoir temperature synergistically reduce the effective stress. Because of such decrease in stress, existing healed natural fractures can be reactivated and/or new fractures can be created. Similar effects can enhance hydrocarbon recovery in shale reservoirs. In this paper, we calculated the magnitude of water-injection-induced stress with a coupled flow/geomechanics model. To evaluate the effect of water injection in the Bakken, a numerical-simulation study for a sector model was carried out. Stress changes caused by the volume created by the hydraulic fracture, water injection, and oil production were calculated. The Hoek-Brown failure criterion was used to compute rock-failure potential. Our numerical results for a waterflooding example show that during water injection, the synergistic effects of reservoir cooling and pore-pressure increase significantly promote rock failure, potentially reactivating healed natural macrofractures and/or creating new macrofractures, especially near an injector. The rock cooling can create small microfractures on the surface of the matrix blocks. In shale oil reservoirs, the numerical experiments indicate that stress changes during water injection can improve oil recovery by opening some of the old macrofractures and creating new small microfractures on the surface of the matrix blocks to promote shallow water invasion into the rock matrix. Furthermore, the new microfractures provide additional interface area between macrofractures and matrix to improve oil drainage when using surfactant and CO2 enhanced-oil-recovery techniques. These positive effects are particularly important farther away from the immediate vicinity of the hydraulic fracture, which is where much of the undrained oil resides.

Upscaling in Partially Fractured Oil Reservoirs Using Homogenization

SPE Journal ◽  
2010 ◽  
Vol 16 (02) ◽  
pp. 273-293 ◽  
Author(s):  
Hamidreza Salimi ◽  
Johannes Bruining
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Oil Production ◽  
High Gravity ◽  
Matrix Interface ◽  
Global Flow ◽  
Interface Area ◽  
Matrix Blocks ◽  
The Matrix ◽  
Specific Fracture

Summary Flow modeling in fractured reservoirs is largely confined to the so-called sugar-cube model. Here, we consider a situation where matrix blocks are connected to neighboring blocks so that part of the global flow occurs only in the matrix domain. We call this a partially fractured reservoir (PFR). As opposed to the sugar-cube model, global flow in the matrix blocks plays an important role in the PFR when the interconnections between the matrix blocks are sufficiently large. We apply homogenization to derive an upscaled model for PFRs that combines dual-porosity and dual-permeability concepts simultaneously. We formulate a well-posed fully implicit 3D upscaled numerical model and investigate oil-recovery mechanisms for different dimensionless characteristic numbers. As we found previously for the sugar-cube model, the Péclet number, defined here as the ratio of the capillary diffusion time in the matrix to the residence time of the fluids in the fracture, plays a crucial role. The gravity number and specific fracture/matrix-interface area play a secondary role. For low Péclet numbers and high gravity numbers, the results are sensitive to gravity and water-injection rates, but relatively insensitive to the specific fracture/matrix-interface area, matrix-block size, and reservoir geometry (i.e., sugar cube vs. PFR). At low Péclet numbers and high gravity numbers, ECLIPSE simulations using the Barenblatt or Warren and Root (BWR) approach give poor predictions and overestimate the oil recovery, but, at short injection times, show good agreement with the solution of the PFR model at intermediate Péclet numbers. At high Péclet numbers, the results are relatively insensitive to gravity, but sensitive to the other conditions mentioned. In particular, when the specific fracture/matrix-interface area is large, it enhances the imbibition and, consequently, leads to a higher oil production. If this specific interface area is small, it leads to a considerable retardation of the imbibition process, which leads to an earlier water breakthrough and lower oil recovery. The BWR (commercial simulator) simulations and the sugar-cube model result in inaccurate predictions of the oil-production rate at high Péclet numbers. This can be inferred from the discrepancy with respect to the PFR model for which we assert that it accurately predicts the oil recovery. We conclude that, at low Péclet numbers and large gravity numbers, it is advantageous to increase the water-injection rate to improve the net present value. However, at high Péclet numbers, increasing the flow rate may lead to uneconomical water cuts.

scholarly journals Pore-scale investigation of selective plugging mechanism in immiscible two-phase flow using phase-field method

2019 ◽  
Vol 74 ◽  
pp. 78 ◽  
Author(s):  
Ehsan Sabooniha ◽  
Mohammad-Reza Rokhforouz ◽  
Shahab Ayatollahi
Keyword(s):  
Oil Recovery ◽  
Phase Field ◽  
Water Injection ◽  
Flow Patterns ◽  
Field Method ◽  
Phase Field Method ◽  
Phase Flow ◽  
Computational Domain ◽  
Pore Scale ◽  
The Matrix

Biotechnology has had a major effect on improving crude oil displacement to increase petroleum production. The role of biopolymers and bio cells for selective plugging of production zones through biofilm formation has been defined. The ability of microorganisms to improve the volumetric sweep efficiency and increase oil recovery by plugging off high-permeability layers and diverting injection fluid to lower-permeability was studied through experimental tests followed by multiple simulations. The main goal of this research was to examine the selective plugging effect of hydrophobic bacteria cell on secondary oil recovery performance. In the experimental section, water and aqua solution of purified Acinetobacter strain RAG-1 were injected into an oil-saturated heterogeneous micromodel porous media. Pure water injection could expel oil by 41%, while bacterial solution injection resulted in higher oil recovery efficiency; i.e., 59%. In the simulation section, a smaller part of the heterogeneous geometry was employed as a computational domain. A numerical model was developed using coupled Cahn–Hilliard phase-field method and Navier–Stokes equations, solved by a finite element solver. In the non-plugging model, approximately 50% of the matrix oil is recovered through water injection. Seven different models, which have different plugging distributions, were constructed to evaluate the influences of selective plugging mechanism on the flow patterns. Each plugging module represents a physical phenomenon which can resist the displacing phase flow in pores, throats, and walls during Microbial-Enhanced Oil Recovery (MEOR). After plugging of the main diameter route, displacing phase inevitably exit from sidelong routes located on the top and bottom of the matrix. Our results indicate that the number of plugs occurring in the medium could significantly affect the breakthrough time. It was also observed that increasing the number of plugging modules may not necessarily lead to higher ultimate oil recovery. Furthermore, it was shown that adjacent plugs to the inlet caused flow patterns similar to the non-plugging model, and higher oil recovery factor than the models with farther plugs from the inlet. The obtained results illustrated that the fluids distribution at the pore-scale and the ultimate oil recovery are strongly dependent on the plugging distribution.

Challenges, Opportunities and Threats of Deep Bottoms-Up Water Injection in Heavy Oil Reservoir: Lessons Learnt from the G Field, South Oman

2021 ◽  
Author(s):  
Chaitanya Behera ◽  
Sandip Mahajan ◽  
Carlos Annia ◽  
Mahmood Harthi ◽  
Jane-Frances Obilaja ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Water Injection ◽  
Field Performance ◽  
Oil Field ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Light Oil ◽  
Alternative Water ◽  
Variable Water

Abstract This paper presents the results of a comprehensive study carried out to improve the understanding of deep bottom-up water injection, which enabled optimizing the recovery of a heavy oil field in South Oman. Understanding the variable water injection response and the scale of impact on oil recovery due to reservoir heterogeneity, operating reservoir pressure and liquid offtake management are the main challenges of deep bottoms-up water injection in heavy oil fields. The offtake and throughput management philosophy for heavy oil waterflood is not same as classical light oil. Due to unclear understanding of water injection response, sometimes the operators are tempted to implement alternative water injection trials leading to increase in the risk of losing reserves and unwarranted CAPEX sink. There are several examples of waterflood in heavy oil fields; however, very few examples of deep bottom water injection cases are available globally. The field G is one of the large heavy oil fields in South Oman; the oil viscosity varies between 250cp to 1500cp. The field came on-stream in 1989, but bottoms-up water-injection started in 2015, mainly to supplement the aquifer influx after 40% decline of reservoir pressure. After three years of water injection, the field liquid production was substantially lower than predicted, which implied risk on the incremental reserves. Alternative water injection concepts were tested by implementing multiple water injection trials apprehending the effectiveness of the bottoms-up water injection concept. A comprehensive integrated study including update of geocellular model, full field dynamic simulation, produced water re-injection (PWRI) model and conventional field performance analysis was undertaken for optimizing the field recovery. The Root Cause Analysis (RCA) revealed many reasons for suboptimal field performance including water injection management, productivity impairment due to near wellbore damage, well completion issues, and more importantly the variable water injection response in the field. The dynamic simulation study indicated negligible oil bank development due to frontal displacement and no water cut reversal as initial response to the water injection. Nevertheless, the significance of operating reservoir pressure, liquid offtake and throughput management impact on oil recovery cann't be precluded. The work concludes that the well reservoir management (WRM) strategy for heavy oil field is not same as the classical light oil waterflood. Nevertheless, the reservoir heterogeneity, oil column thickness and saturation history are also important influencing factors for variable water injection response in heavy oil field.

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.

scholarly journals Geomechanical Response of Fractured Reservoirs

Fluids ◽  
2018 ◽  
Vol 3 (4) ◽  
pp. 70 ◽  
Author(s):  
Ahmad Zareidarmiyan ◽  
Hossein Salarirad ◽  
Victor Vilarrasa ◽  
Silvia De Simone ◽  
Sebastia Olivella
Keyword(s):  
Oil Recovery ◽  
Shear Failure ◽  
Numerical Models ◽  
Fractured Reservoirs ◽  
Fluid Pressure ◽  
Carbonate Reservoir ◽  
Improved Oil Recovery ◽  
Matrix Blocks ◽  
The Matrix ◽  
Pressure Changes

Geologic carbon storage will most likely be feasible only if carbon dioxide (CO2) is utilized for improved oil recovery (IOR). The majority of carbonate reservoirs that bear hydrocarbons are fractured. Thus, the geomechanical response of the reservoir and caprock to IOR operations is controlled by pre-existing fractures. However, given the complexity of including fractures in numerical models, they are usually neglected and incorporated into an equivalent porous media. In this paper, we perform fully coupled thermo-hydro-mechanical numerical simulations of fluid injection and production into a naturally fractured carbonate reservoir. Simulation results show that fluid pressure propagates through the fractures much faster than the reservoir matrix as a result of their permeability contrast. Nevertheless, pressure diffusion propagates through the matrix blocks within days, reaching equilibrium with the fluid pressure in the fractures. In contrast, the cooling front remains within the fractures because it advances much faster by advection through the fractures than by conduction towards the matrix blocks. Moreover, the total stresses change proportionally to pressure changes and inversely proportional to temperature changes, with the maximum change occurring in the longitudinal direction of the fracture and the minimum in the direction normal to it. We find that shear failure is more likely to occur in the fractures and reservoir matrix that undergo cooling than in the region that is only affected by pressure changes. We also find that stability changes in the caprock are small and its integrity is maintained. We conclude that explicitly including fractures into numerical models permits identifying fracture instability that may be otherwise neglected.

scholarly journals Numerical modeling and experimental investigation on the effect of low-salinity water flooding for enhanced oil recovery in carbonate reservoirs

2021 ◽  
Vol 11 (2) ◽  
pp. 925-947
Author(s):  
Erfan Hosseini ◽  
Mohammad Sarmadivaleh ◽  
Dana Mohammadnazar
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Water Flooding ◽  
Wettability Alteration ◽  
Experimental Investigations ◽  
Core Flooding ◽  
Reservoir Temperature ◽  
Sulfate Ion ◽  
Ionic Content ◽  
Low Salinity

AbstractNumerous studies concluded that water injection with modified ionic content/salinity in sandstones would enhance the oil recovery factor due to some mechanisms. However, the effects of smart water on carbonated formations are still indeterminate due to a lack of experimental investigations and researches. This study investigates the effects of low-salinity (Low Sal) solutions and its ionic content on interfacial tension (IFT) reduction in one of the southwestern Iranian carbonated reservoirs. A set of organized tests are designed and performed to find each ion’s effects and total dissolved solids (TDS) on the candidate carbonated reservoir. A sequence of wettability and IFT (at reservoir temperature) tests are performed to observe the effects of controlling ions (sulfate, magnesium, calcium, and sodium) and different salinities on the main mechanisms (i.e., wettability alteration and IFT reduction). All IFT tests are performed at reservoir temperature (198 °F) to minimize the difference between reservoir and laboratory-observed alterations. In this paper, the effects of four different ions (SO42-, Ca2+, Mg2+, Na+) and total salinity TDS (40,000, 20,000, 5000 ppm) are investigated. From all obtained results, the best two conditions are applied in core flooding tests to obtain the relative permeability alterations using unsteady-state methods and Cydarex software. The final part is the simulation of the whole process using the Schlumberger Eclipse black oil simulator (E100, Ver. 2010) on the candidate reservoir sector. To conclude, at Low Sal (i.e., 5000 ppm), the sulfate ion increases sulfate concentration lower IFT, while in higher salinities, increasing sulfate ion increases IFT. Also, increasing calcium concentration at high TDS (i.e., 40,000 ppm) decreases the amount of wettability alteration. In comparison, in lower TDS values (20,000 and 5000 ppm), calcium shows a positive effect, and its concentration enhanced the alteration process. Using Low Sal solutions at water cut equal or below 10% lowers recovery rate during simulations while lowering the ultimate recovery of less than 5%.

scholarly journals Gravity Drainage Mechanism in Naturally Fractured Carbonate Reservoirs; Review and Application

Energies ◽  
2019 ◽  
Vol 12 (19) ◽  
pp. 3699 ◽  
Author(s):  
Faisal Awad Aljuboori ◽  
Jang Hyun Lee ◽  
Khaled A. Elraies ◽  
Karl D. Stephen
Keyword(s):  
Gravity Model ◽  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Carbonate Reservoir ◽  
Real Field ◽  
Gravity Drainage ◽  
Naturally Fractured ◽  
Fractured Carbonate ◽  
Matrix Blocks ◽  
The Matrix

Gravity drainage is one of the essential recovery mechanisms in naturally fractured reservoirs. Several mathematical formulas have been proposed to simulate the drainage process using the dual-porosity model. Nevertheless, they were varied in their abilities to capture the real saturation profiles and recovery speed in the reservoir. Therefore, understanding each mathematical model can help in deciding the best gravity model that suits each reservoir case. Real field data from a naturally fractured carbonate reservoir from the Middle East have used to examine the performance of various gravity equations. The reservoir represents a gas–oil system and has four decades of production history, which provided the required mean to evaluate the performance of each gravity model. The simulation outcomes demonstrated remarkable differences in the oil and gas saturation profile and in the oil recovery speed from the matrix blocks, which attributed to a different definition of the flow potential in the vertical direction. Moreover, a sensitivity study showed that some matrix parameters such as block height and vertical permeability exhibited a different behavior and effectiveness in each gravity model, which highlighted the associated uncertainty to the possible range that often used in the simulation. These parameters should be modelled accurately to avoid overestimation of the oil recovery from the matrix blocks, recovery speed, and to capture the advanced gas front in the oil zone.

A Parametric Study of Reservoir Cooling for Enhanced Recovery by Carbon Dioxide Flooding

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 0839-0852 ◽  
Author(s):  
Zhenzhen Wang ◽  
Amey Khanzode ◽  
Russell T. Johns
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Enhanced Recovery ◽  
Co2 Injection ◽  
Reservoir Pressure ◽  
Co2 Flooding ◽  
Reservoir Temperature ◽  
Temperature Variations ◽  
Flow Dimension ◽  
Injection Temperature

Summary Slimtube experiments and analytical calculations show that minimum miscibility pressure (MMP) can significantly decrease with a relatively modest reduction in temperature. Compositional simulation, however, is often made under isothermal conditions even though a prior waterflood may have reduced reservoir temperature in the swept zones of the reservoir. This study uses computer simulation to examine how cooling by a prior waterflood can affect recovery during a carbon dioxide (CO2) flood by lowering the MMP in the swept zones. The results show that for the cases considered, injection of cooler water can increase incremental oil recovery (IOR) significantly because of MMP reduction in the zones swept by the solvent. A parametric simulation study demonstrates how injection temperature, initial reservoir pressure, formation heterogeneity, formation thickness, heat transfer with the overburden/underburden formations, and water-alternating-gas (WAG) ratio may affect the IOR. The simulations are conducted by a long waterflood of up to 2.0 pore volumes injected before CO2 injection. The water during the secondary recovery is injected at several temperatures for selected 1D, 2D, and 3D flow models. CO2 solvent is then injected continuously, or in WAG mode, at the same waterflood-injection temperature. The increase in IORs (greater than what would have been obtained by a standard CO2 flood at original reservoir temperature) varied greatly depending on the flow dimension, initial reservoir pressure, level of heterogeneity, formation thickness, degree of energy gain from the surroundings, and injection temperature. Increases in recovery by CO2 flooding varied from a few percent to nearly 30% of original oil in place, with the highest recoveries occurring in 1D flow. For the same flow dimension, the largest increase in recoveries is achieved when the MMP is sufficiently reduced by temperature so that an otherwise immiscible or near-miscible flood becomes a multicontact miscible flood. The results demonstrate that including temperature variations in the simulations is important for floods that are nearly miscible because recoveries are most affected in that region. Further, including temperature variations could be very important to improve the quality of history matches used to understand the reservoir.

scholarly journals Water Injection for Oil Recovery in Mishrif Formation for Amarah Oil Field

2020 ◽  
Vol 21 (1) ◽  
pp. 39-44
Author(s):  
Ayat Ahmed Jassim ◽  
Abdul Aali Al-dabaj ◽  
Aqeel S. AL-Adili
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Petroleum Reservoirs ◽  
Oil Production ◽  
Oil Field ◽  
Reservoir Pressure ◽  
Vertical Wells ◽  
First Case ◽  
New Ideas

The water injection of the most important technologies to increase oil production from petroleum reservoirs. In this research, we developed a model for oil tank using the software RUBIS for reservoir simulation. This model was used to make comparison in the production of oil and the reservoir pressure for two case studies where the water was not injected in the first case study but adding new vertical wells while, later, it was injected in the second case study. It represents the results of this work that if the water is not injected, the reservoir model that has been upgraded can produce only 2.9% of the original oil in the tank. This case study also represents a drop in reservoir pressure, which was not enough to support oil production. Thus, the implementation of water injection in the second case study of the average reservoir pressure may support, which led to an increase in oil production by up to 5.5% of the original oil in the tank. so that, the use of water injection is a useful way to increase oil production. Therefore, many of the issues related to this subject valuable of study where the development of new ideas and techniques.

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