Improved oil recovery by gel technology: Water shutoff and conformance control

Sadeghnejad, Saeid; Ashrafizadeh, Marjan; Nourani, Meysam

doi:10.1016/b978-0-12-821931-7.00001-8

Cited by 12 publications

(4 citation statements)

References 193 publications

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“…This metric assesses how well the polymer is retained by comparing the ratio of pressure differentials after secondary water injection to that during the initial water injection before the introduction of the polymer, maintaining consistent flow rates, as detailed by Equation ( 2). The residual resistance factor is indicative of the extent to which the polymer has reduced permeability following secondary water injection [51] Resistance factor ¼ ΔP polymer ΔP waterflooding ¼ k water =μ water k polymer =μ polymer (1) Residual resistance factor ¼ ΔP postÀwaterflooding ΔP waterflooding ¼ k water =μ water k post-water =μ post-water (2) where the symbols "k" and "μ" represent the permeability and viscosity, respectively.…”

Section: Lmp Adsorptionmentioning

confidence: 99%

Chemical Enhanced Oil Recovery and Viscose Flooding into Sandstone Reservoirs Using a Natural Polymer Extracted from Sucrose‐Rich Waste by Bacterial Activity

Nowrouzi,

Mohammadi,

Khaksar Manshad

2024

Energy Tech

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In this research, it was attempted to describe in vitro the efficiency of a natural polymer synthesized from sugarcane waste by bacteria for application in enhanced crude oil recovery. Necessary experiments were carried out with the main targets of extraction and description of the polymer and its effectiveness in enhanced oil recovery. It is shown that in the polymer concentrations of 1, 2, 5, and 8 wt%, the viscosity is equal to 26.08, 76.51, 100.94, and 168.36 mPa s. A shear‐thinning flow behavior is observed at initial shear rates. The sandstone wettability alteration is observed through the contact angles at concentrations of 1, 2, 5, and 8 wt% that are 85.93°, 72.19°, 76.51°, and 71.09°, respectively. Based on salinity compatibility, the polymer work up to a salinity of 90 000 ppm and based on viscosity tests, up to a salinity of 120 000 ppm. Regarding the performance of the polymer solution against temperature, it shows an acceptable performance in increasing the viscosity at the highest temperature of 75 °C. The water cut reaches its minimum of 8%, and then increases. By injecting 3.3 Pore volum (PV), the oil recovery reaches 81.4%. In a polymeric slug injection program, the oil recovery factor reaches 74.8%.Similarly, the water cut starts to decrease after the injection of polymer, and finally, after the injection of 0.9 PV including 0.5 PV of the polymer solution and 0.4 PV of water, reaches its minimum during the experiment, i.e., 22%.

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Section: Lmp Adsorptionmentioning

confidence: 99%

Chemical Enhanced Oil Recovery and Viscose Flooding into Sandstone Reservoirs Using a Natural Polymer Extracted from Sucrose‐Rich Waste by Bacterial Activity

Nowrouzi,

Mohammadi,

Khaksar Manshad

2024

Energy Tech

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“…These reservoirs are among the special reservoirs that change the fluid flow regime of the reservoirs and affect the well productivity (Yang et al, 2018;Radwan et al, 2021). Sometimes, in some areas, the presence of deep fractures causes water conning in these areas, and undesirable fluids flow to less permeable areas, where they are wasted in the subsurface (Ali et al, 2021;Sadeghnejad et al, 2022). Many techniques have been used to identify fracture density.…”

Section: Introductionmentioning

confidence: 99%

Prediction of fracture density in a gas reservoir using robust computational approaches

Gao

Hazbeh²,

Davoodi³

et al. 2023

Front. Earth Sci.

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One of the challenges that reservoir engineers, drilling engineers, and geoscientists face in the oil and gas industry is determining the fracture density (FVDC) of reservoir rock. This critical parameter is valuable because its presence in oil and gas reservoirs boosts productivity and is pivotal for reservoir management, operation, and ultimately energy management. This valuable parameter is determined by some expensive operations such as FMI logs and core analysis techniques. As a result, this paper attempts to predict this important parameter using petrophysics logs routinely collected at oil and gas wells and by applying four robust computational algorithms and artificial intelligence hybrids. A total of 6067 data points were collected from three gas wells (#W1, #W2, and #W3) in one gas reservoir in Southwest Asia. Following feature selection, the input variables include spectral gamma ray (SGR); sonic porosity (PHIS); potassium (POTA); photoelectric absorption factor (PEF); neutron porosity (NPHI); sonic transition time (DT); bulk density (RHOB); and corrected gamma ray (CGR). In this study, four hybrids of two networks were used, including least squares support vector machine (LSSVM) and multi-layer perceptron (MLP) with two optimizers particle swarm optimizer (PSO) and genetic algorithm (GA). Four robust hybrid machine learning models were applied, and these are LSSVM-PSO/GA and MLP-PSO/GA, which had not previously used for prediction of FVDC. In addition, the k-fold cross validation method with k equal to 8 was used in this article. When the performance accuracy of the hybrid algorithms for the FVDC prediction is compared, the revealed result is LSSVM-PSO > LSSVM-GA > MLP-PSO > MLP-GA. The study revealed that the best algorithm for predicting FVDC among the four algorithms is LSSVM-PSO (for total dataset RMSE = 0.0463 1/m; R2 = 0.9995). This algorithm has several advantages, including: 1) lower adjustment parameters, 2) high search efficiency, 3) fast convergence speed, 4) increased global search capability, and 5) preventing the local optimum from falling. When compared to other models, this model has the lowest error.

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“…In recent years, the technique of working with pressure has been thoroughly researched and widely used 21–23 . Currently, the commonly used temporary plugging technology with pressure operation can be mainly divided into: mechanical temporary plugging technology 24,25 and chemical temporary plugging technology 26–29 . Chemical temporary plugging technology is widely used because of its good plugging effect, low cost, low risk, and other advantages 30–32 .…”

Section: Introductionmentioning

confidence: 99%

“…[21][22][23] Currently, the commonly used temporary plugging technology with pressure operation can be mainly divided into: mechanical temporary plugging technology 24,25 and chemical temporary plugging technology. [26][27][28][29] Chemical temporary plugging technology is widely used because of its good plugging effect, low cost, low risk, and other advantages. [30][31][32] By injecting a certain amount of working fluid at the wellhead, spontaneous gel formation under downhole temperature and pressure conditions, forming a plugging agent, effectively preventing the formation fluid from gushing out and massive leakage.…”

Section: Introductionmentioning

confidence: 99%

Research and performance evaluation of modified nano‐silica gel plugging agent

Zheng

Luo

2023

J of Applied Polymer Sci

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Due to the difficulties in plugging high-pressure injection wells, the short period of plugging, and the use of modified nano-silica, a novel chemical gel plugging agent has been created. Modification of silica using silane coupling agents, and using the aqueous free radical polymerization method synthesized chemical plugging agent with AM, AA, and DMDAAC. The optimum synthesis conditions were screened by single-factor analysis: mass ratio m(AM):m (AA):m(DMDAAC) = 8:1.5:1, modified nano-silica concentration of 1.0%, total monomer mass concentration of 8.0%, initiator concentration of 0.3%, the cross-linker concentration of 0.4%, and coagulant concentration of 0.6%. The performance of the chemical plugging agent was evaluated under the target oil formation conditions. The experimental results showed that the chemical plugging agent exhibited good temperature resistance at 40-100 C, good salt resistance at mineralization (0.5-2.5) Â 10 4 mg/L, and the chemical plugging agent breaks through pressure gradients of 1.12, 15.42 and 90.15 MPa/m in the wellbore, fracture and core, respectively, compared with most gel plugging agents, this plugging agent is more suitable for sealing with pressure work. After adding the breakout agent, the fluid after breakout is fluid-like with low viscosity, which is convenient for reverse discharge and will not cause harm to the reservoir and ensure the subsequent normal construction operation.

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Improved oil recovery by gel technology: Water shutoff and conformance control

Cited by 12 publications

References 193 publications

Chemical Enhanced Oil Recovery and Viscose Flooding into Sandstone Reservoirs Using a Natural Polymer Extracted from Sucrose‐Rich Waste by Bacterial Activity

Chemical Enhanced Oil Recovery and Viscose Flooding into Sandstone Reservoirs Using a Natural Polymer Extracted from Sucrose‐Rich Waste by Bacterial Activity

Prediction of fracture density in a gas reservoir using robust computational approaches

Research and performance evaluation of modified nano‐silica gel plugging agent

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