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.

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.

scholarly journals A New Method of Plugging the Fracture to Enhance Oil Production for Fractured Oil Reservoir using Gel Particles and the HPAM/Cr3+ System

Polymers ◽  
2019 ◽  
Vol 11 (3) ◽  
pp. 446 ◽  
Author(s):  
Lei Zhang ◽  
Nasir Khan ◽  
Chunsheng Pu
Keyword(s):  
Oil Recovery ◽  
Oil Production ◽  
Oil Reservoirs ◽  
New Method ◽  
Water Flooding ◽  
Whole Process ◽  
Gel Particles ◽  
The Matrix ◽  
Water Cut ◽  
Enhance Oil Recovery

Due to the strong heterogeneity between the fracture and the matrix in fractured oil reservoirs, injected water is mainly moved forward along the fracture, which results in poor water flooding. Therefore, it is necessary to reduce the water cut and increase oil production by using the conformance control technology. So far, gel particles and partially hydrolyzed polyacrylamide (HPAM)/Cr3+ gel are the most common applications due to their better suitability and low price. However, either of the two alone can only reduce the conductivity of the fracture to a certain extent, which leads to a poor effect. Therefore, to efficiently plug the fracture to enhance oil recovery, a combination of gel particles and the HPAM/Cr3+ system is used by laboratory tests according to their respective advantages. The first step is that the gel particles can compactly and uniformly cover the entire fracture and then the fracture channel is transformed into the gel particles media. This process can enhance the oil recovery to 18.5%. The second step is that a suitable HPAM/Cr3+ system based on the permeability of the gel particles media is injected in the fractured core. Thus, the fracture can be completely plugged and the oil in the matrix of the fractured core can be displaced by water flooding. This process can enhance oil recovery to 10.5%. During the whole process, the oil recovery is increased to 29% by this method. The results show that this principle can provide a new method for the sustainable and efficient development of fractured oil reservoirs.

scholarly journals Optimization of reinjection treatment technology for oilfield wastewater in Longdong area

2020 ◽  
Vol 194 ◽  
pp. 04046
Author(s):  
Xiulan Zhu ◽  
Yanlong Ran ◽  
Wenjie Guo ◽  
Ke Gai ◽  
Yanju Li ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Solid Phase ◽  
Sewage Treatment ◽  
Water Injection ◽  
Oil Production ◽  
High Water ◽  
Oil Field ◽  
Treatment Technology ◽  
Water Separation ◽  
High Water Cut

With the long-term water injection development of Longdong oilfields, most of the oilfield blocks have been fully in the mid-high water cut period, and the amount of oil production wastewater is increasing year by year. In order to prevent the waste of resources and energy of oil production sewage, the oil production sewage after reaching the standard is treated for reinjection, which will ensure the sustainable development of the oil field. Oil production wastewater contains crude oil, solid-phase suspended solids and other pollutants, with high salinity, and problems such as difficulty in oil-water separation, sludge, scaling and corrosion. The sewage treatment system uses a multifunctional water treatment device to effectively remove oil and filter through the “special microorganism + air flotation + filtration” process, and build a sludge sewage tank for sludge discharge and backwashing. The reformed oil recovery wastewater reinjection treatment technology turns “sewage” into “clear flow”, reduces operating costs, improves wastewater treatment efficiency, and meets the water quality requirements of oilfield reinjection water.

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.

Characterisation of the Fracture Path in ‘Flexible’ Refractories

2010 ◽  
Vol 70 ◽  
pp. 30-36 ◽  
Author(s):  
Harald Harmuth
Keyword(s):  
Characteristic Length ◽  
Transgranular Fracture ◽  
Matrix Interface ◽  
Fracture Path ◽  
Figures Of Merit ◽  
Microscopical Technique ◽  
The Matrix ◽  
Specific Fracture ◽  
Loss Of Strength ◽  
Microscopic Investigations

The denomination ‘flexible’ is chosen in the professional jargon of refractories technology for materials able to bear relatively high strains without or with acceptable loss of strength. In many cases this term is equivalent to relatively low brittleness. Characterisation of brittleness based on fracture mechanical investigations may use figures of merit like brittleness numbers, a so called characteristic length or the R’’’’ parameter according to Hasselman. In many cases these figures show that brittleness reduction of refractories is achieved by decrease of strength with at the same time more or less unaffected specific fracture energy. Microscopic investigations of fracture paths aim to exhibit which peculiarities of crack microstructure enable this change of mechanical properties. A microscopical technique developed for this purpose separately evaluates the relative crack lengths along the grain/matrix interface, within the matrix and within the grain. Results obtained for several types of refractories show brittleness decrease is associated by an increase of the relative crack length along the grain/matrix interface and a decrease of transgranular fracture. Prefabricated microcracks and a relatively low grain/matrix bond strength may support this type of crack propagation.

Matrix Refinement in Mass Transport Across Fracture-Matrix Interface: Application to Improved Oil Recovery in Fractured Reservoirs

2021 ◽  
Author(s):  
Sarah Abdullatif Alruwayi ◽  
Ozan Uzun ◽  
Hossein Kazemi
Keyword(s):  
Fractured Reservoirs ◽  
Block Size ◽  
Grid Cell ◽  
Matrix Interface ◽  
Unsteady State ◽  
Matrix Block ◽  
Matrix Blocks ◽  
The Matrix ◽  
Saturation Distribution ◽  
State Pressure

Abstract In this paper, we will show that it is highly beneficial to model dual-porosity reservoirs using matrix refinement (similar to the multiple interacting continua, MINC, of Preuss, 1985) for water displacing oil. Two practical situations are considered. The first is the effect of matrix refinement on the unsteady-state pressure solution, and the second situation is modeling water-oil, Buckley-Leverett (BL) displacement in waterflooding a fracture-dominated flow domain. The usefulness of matrix refinement will be illustrated using a three-node refinement of individual matrix blocks. Furthermore, this model was modified to account for matrix block size variability within each grid cell (in other words, statistical distribution of matrix size within each grid cell) using a discrete matrix-block-size distribution function. The paper will include two mathematical models, one unsteady-state pressure solution of the pressure diffusivity equation for use in rate transient analysis, and a second model, the Buckley-Leverett model to track saturation changes both in the reservoir fractures and within individual matrix blocks. To illustrate the effect of matrix heterogeneity on modeling results, we used three matrix bock sizes within each computation grid and one level of grid refinement for the individual matrix blocks. A critical issue in dual-porosity modeling is that much of the fluid interactions occur at the fracture-matrix interface. Therefore, refining the matrix block helps capture a more accurate transport of the fluid in-and-out of the matrix blocks. Our numerical results indicate that the none-refined matrix models provide only a poor approximation to saturation distribution within individual matrices. In other words, the saturation distribution is numerically dispersed; that is, no matrix refinement causes unwarranted large numerical dispersion in saturation distribution. Furthermore, matrix block size-distribution is more representative of fractured reservoirs.

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 Simulation Study of Allied In-Situ Injection and Production for Enhancing Shale Oil Recovery and CO2 Emission Control

Energies ◽  
2019 ◽  
Vol 12 (20) ◽  
pp. 3961
Author(s):  
Haiyang Yu ◽  
Songchao Qi ◽  
Zhewei Chen ◽  
Shiqing Cheng ◽  
Qichao Xie ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Co2 Emission ◽  
Gas Injection ◽  
Water Injection ◽  
Oil Production ◽  
Injection Rate ◽  
Oil Reservoirs ◽  
Shale Oil ◽  
Shale Oil Reservoirs

The global greenhouse effect makes carbon dioxide (CO2) emission reduction an important task for the world, however, CO2 can be used as injected fluid to develop shale oil reservoirs. Conventional water injection and gas injection methods cannot achieve desired development results for shale oil reservoirs. Poor injection capacity exists in water injection development, while the time of gas breakthrough is early and gas channeling is serious for gas injection development. These problems will lead to insufficient formation energy supplement, rapid energy depletion, and low ultimate recovery. Gas injection huff and puff (huff-n-puff), as another improved method, is applied to develop shale oil reservoirs. However, the shortcomings of huff-n-puff are the low sweep efficiency and poor performance for the late development of oilfields. Therefore, this paper adopts firstly the method of Allied In-Situ Injection and Production (AIIP) combined with CO2 huff-n-puff to develop shale oil reservoirs. Based on the data of Shengli Oilfield, a dual-porosity and dual-permeability model in reservoir-scale is established. Compared with traditional CO2 huff-n-puff and depletion method, the cumulative oil production of AIIP combined with CO2 huff-n-puff increases by 13,077 and 17,450 m3 respectively, indicating that this method has a good application prospect. Sensitivity analyses are further conducted, including injection volume, injection rate, soaking time, fracture half-length, and fracture spacing. The results indicate that injection volume, not injection rate, is the important factor affecting the performance. With the increment of fracture half-length and the decrement of fracture spacing, the cumulative oil production of the single well increases, but the incremental rate slows down gradually. With the increment of soaking time, cumulative oil production increases first and then decreases. These parameters have a relatively suitable value, which makes the performance better. This new method can not only enhance shale oil recovery, but also can be used for CO2 emission control.

scholarly journals Macroscopic visual displacement of a polymer solution for enhanced oil recovery: Hele-Shaw cell experiments and computational simulation

2020 ◽  
Vol 66 (3 May-Jun) ◽  
pp. 273
Author(s):  
S. De Santiago ◽  
O. Olivares-Xometl ◽  
N. V. Likhanova ◽  
I. V. Lijanova ◽  
P. Arellanes-Lozada
Keyword(s):  
Oil Recovery ◽  
Flow Direction ◽  
Computational Simulation ◽  
Homogeneous Medium ◽  
Oil Production ◽  
Field Application ◽  
Polymer Flooding ◽  
Water Flooding ◽  
The Matrix ◽  
The One

Numerous laboratory studies and field application tests have shown that polymer flooding is an effective method to improve the oil recovery by displacing residual oil after water flooding. In this work, a series of visual model displacement experiments was conducted in Hele-Shaw cells to determine the effectiveness of polymer flooding in homogeneous and fractured media with a fracture parallel or perpendicular to the flow direction. The matrix with parallel fracture to the flow direction presented a delay in the oil production process during water and polymer flooding with respect to the homogeneous medium and the one with perpendicular fracture, where the highest recovery numbers during waterflooding and polymer flooding were achieved for the medium with perpendicular fracture to the flow direction, reaching 56 % of cumulative oil recovery. The displacement results and multiphasic simulation show that the homogeneous medium is an attractive candidate for additional recovery application with polymer flooding after water flooding when the oil production reached almost zero, although the production rate is lower than the one obtained for a porous medium with a fracture perpendicular to the flow direction.

scholarly journals Field application of a modular multiple thermal fluid generator for heavy oil recovery

2021 ◽  
Author(s):  
Liguo Zhong ◽  
Cheng Wang ◽  
Yigang Liu ◽  
Wei Zhang ◽  
Xiaodong Han ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Fuel Injection ◽  
Water Injection ◽  
Oil Production ◽  
Field Application ◽  
Injection System ◽  
Water Volume ◽  
Oil Viscosity ◽  
Production Platform

AbstractA modular multiple thermal fluid generator is introduced to enhance heavy oil production, which consists of water treatment system, fuel injection system, air compressor, central burning and heat exchanging system, and measuring and controlling system. All the components are mounted in three separated light shelters, which are easy to be lifted and installed, especially on the offshore production platform. It could be operated under 350 ℃ and 20 MPa, and the temperature and GWR (ratio of the volume of gas to the equivalent water volume of steam under standard conditions) could be adjusted by the water injection rate under the given heating capability of the central burning chamber. The temperature of the generated fluid is usually 200–300 ℃ with GWR of 200–300 m3/m3. Compared to conventional steam generator, such compact multiple thermal fluid generator is easy to be installed on the offshore oil production platform, and the generated multiple thermal fluid is potential to enhance heavy oil production in mechanisms of reducing heavy oil viscosity by both heating and injected gas, enlarging the heating reservoir chamber, and pressure by injected gas. In the past 10 years, the multiple thermal fluid generator has been applied to more than 40 wells in Bohai Offshore Oilfield and Xinjiang Oilfield in cyclic multiple thermal fluid stimulation (CMTFS in short) process. As a result, the multiple thermal fluid generators were operated soundly, and the heavy oil production of these wells was enhanced remarkably. (The oil production rate was 2–3 times more than cold production.)

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