Research and Application of Micro-Expansion and Anti-Channeling Cement Slurry System in Agadem Oilfield

The overall liner cementing qualification rate is only 40% in Agadem block of Niger, The cement slurry system used in the field has a UCA transition time of 43min, and an expansion rate of -0.03% in 24h, which result in a poor anti-gas channeling performance. The expansive agent and the anti-gas channeling toughening agent of anti-channeling agent were optimized through experiment study. A novel micro-expansion anti-gas channel cement slurry system which is suitable for Agadem block was obtained through experiment optimization study: 100% G +2 ∼ 4% fluid loss agent +3 ∼ 4.5% anti-channeling agent +1 ∼ 2% expansion agent-100S +0.15 ∼ 0.4% retarder +0 ∼ 0.3% dispersant +0 ∼ 0.25% defoamer + water. This new cement system has a good anti-gas channeling performance, the cement strength is 24.5-35.0MPa after 24hrs, the UCA transition time is 16-18min, and the expansion rate is 1.5-1.7%. At the same time, a cementing prepad fluid suitable for the block and the micro-expansion cement slurry system is selected to ensure the performance of the cement slurry's anti-channeling performance. The field test results proofs the good performance of the new cement system. The cementing qualification rate of Koulele W-5 well is 96%, and the second interface cementation is Good. The cementing qualification rate of Trakes CN-1 well is 100% which second interface cementation is Excellent. This paper has positive guidance and reference for cementing in Agadem block.

Study on Fluid Behaviors of Foam-Assisted Nitrogen Flooding on a Three-Dimensional Visualized Fracture–Vuggy Model

Tahe Oilfield, located in northwest China, is an unconventional fracture–vuggy carbonate reservoir. The foam-assisted nitrogen gas flooding technology has been proven to be a potential EOR technology. However, the flow behaviors of foam-assisted nitrogen gas in fracture–vuggy structures are not clear due to the complex fracture–vuggy structures and their strong heterogeneity. In this work, a three-dimensional visualized fracture–vuggy model is designed and fabricated to investigate the fluids behaviors of foam-assisted N2 flooding and classify the residual oil types after foam-assisted N2 flooding. Experimental results reveal that foam slug can enlarge the sweep efficiency, suppress the formation of nitrogen gas channeling, and detach the oil film. Additionally, the evolution processes of the gas–oil and oil–water interfaces are investigated and analyzed. Moreover, the residual oil types after foam-assisted N2 flooding and nitrogen gas flooding, respectively, are classified and summarized. Compared to nitrogen gas flooding after water flooding, 12.36% more oil can be recovered through foam-assisted N2 flooding. This work further studies the fluid flow behaviors of foam-assisted N2 in the three-dimensional visualized fracture–vuggy carbonate model and also confirms the previous achievements.

Numerical Simulation via CFD Methods of Nitrogen Flooding in Carbonate Fractured-Vuggy Reservoirs

A reservoir-scale numerical conceptual model was established according to the actual geological characteristics of a carbonate fractured-vuggy reservoir. Considering the difference in density and viscosity of fluids under reservoir conditions, CFD (computational fluid dynamic) porous medium model was applied to simulate the process of nitrogen displacement in a fractured-vuggy reservoir after water flooding. The effects of gas injection rate, injection mode, and injector–producer location relation were studied. The results show that nitrogen flooding can yield additional oil recovery of 7–15% after water flooding. Low-speed nitrogen injection is beneficial in obtaining higher oil recovery. High speed injection can expand the sweep area, but gas channeling occurs more easily. In gas–water mixed injection mode, there is fluid disturbance in the reservoir. The gas channeling is faster in low injector–high producer mode, while the high injector–low producer mode is beneficial for increasing the gas sweep range. Nevertheless, the increment of recovery is closely related to well pattern. After nitrogen flooding, there are still a lot of remaining oil distributed in the trap area of gas cap and bottom water in the reservoir that water and gas injection can’t sweep. The establishment of the numerical conceptual model compensates for the deficiency of physical simulation research, stating that only limited parameters can be simulated during experiments, and provides theoretical bases for nitrogen flooding in fractured-vuggy reservoir.

Numerical Analysis of the Behavior of Gas Hydrate Layers After Cementing Operations

Since the 2000s, the number of gas hydrate wells (i.e., exploration wells, production test wells) has increased. Moreover, in the marine environment, gas hydrate zones are drilled in conventional hydrocarbon wells. Different than conventional hydrocarbon wells, the heat released with cement hydration cannot be ignored because gas hydrates are heat sensitive. In this study, by analyzing different cement compositions (conventional cement compositions and novel low-heat of hydration cement), it is aimed to investigate the effect of the heat of cement hydration on gas hydrate zones near the wellbore. For this purpose, numerical simulations with TOUGH+HYDRATE simulator were conducted in the conditions of the Nankai Trough gas hydrates. According to the numerical simulations in this study, if the increase in temperature in the cemented layer is above 30°C, significant gas hydrate dissociation occurs, and free gas evolved in the porous media. This might cause gas channeling and poor cement bond. The heat released with cement hydration generally affects the interval between the cemented layer and 0.25 m away from the cemented layer. Within a few days after cementing, pressure, temperature, gas hydrate saturation, and gas saturation returned to almost their original values.

Laboratory Studies For Design of a Foam Pilot For Reducing Gas Channeling From Gas Cap in Production Well in Messoyakhskoye Field

Messoyakhskoye field, operated by Gazprom Neft, is currently experiencing gas channeling from gas cap in production wells because of strong heterogeneity. Foam for a long has been considered as a good candidate for gas blocking, (Svorstol I. et al., 1996), (Hanssen, J. E., & Dalland, M. 1994), (Aarra, M. G. et al., 1996). However, foam injection for gas blocking in injection well is different from that in production well, where it is necessary to selectively and long-term impact on gas-saturated highly permeable areas without affecting the phase permeability of oil in the reservoir. This paper provides detailed laboratory studies that show how to determine suitable foam systems for gas blocking in production well. For gas blocking in production well, a long half-life time is required to sustain stable foam because a continuous shear of surfactant solution/gas can't be achieved like in injection well. Therefore, reinforced foam by polymer is chosen. Four polymer stabilizers and five foam agents were evaluated using bulk test to determine foaming ability, foam stability, and effect of oil by comparing foam rate and half-life time to determine the suitable foam system. Furthermore, filtration experiments were conducted at reservoir conditions to determine the optimal injection mode by evaluating apparent viscosity, breakthrough pressure gradient, resistance factor, and residual resistance factor. Polymer can significantly improve half-life time (increase foam stability), and the higher the polymer concentration, the longer the half-life time. But simultaneously, a high polymer concentration will increase the initial viscosity of solution, which not only decreases the foam rate, but also increases difficulties in injection. Therefore, an optimal polymer concentration of about 0.15-0.2 wt% is determined considering all these influences. Filtration experiments showed that the apparent viscosity in core first increased and then deceased with foam quality (the ratio of gas volume to foam volume (gas + liquid). The optimal injection mode is co-injection of surfactant/polymer solution and gas to in-situ generate foam at the optimal foam quality of about 0.65. Filtration experiments on the different permeability cores showed that gas-blocking ability of polymer reinforced foam is better in high-permeability cores, which is beneficial for blocking high permeability zone. It should be also noted that under a certain ratio of oil to foam solution (about lower than 1 to 1), the presence of oil slowly decreased foam rate with increasing oil volume, but significantly increased half -life time, which is favorable for foam treatment in production well. This work highlights the difference between foam injection for gas blocking in production well and injection well, and emphasizes the use of polymer reinforced foam. Moreover, this work shows systematic experimental methods for choosing suitable foam systems for gas blocking in production well considering different factors, which provides a guide regarding what kinds of foaming agents and polymer stabilizers should be used and how to evaluate them for designing a pilot application.

Field Pilot Test of Micro-Dispersed Gel Foam in Fractured-Vuggy Carbonate Reservoirs

This paper summarizes the change rule of production performance and the EOR efficiency from the micro-dispersed gel foam injection in the fractured-vuggy carbonate reservoir of Tahe Oilfield. The TK722CH2 well group injected gas from August 2014 to September 2018. During the gas injection stage, the effect of periodic gas injection decreased obviously, the effective direction of gas injection was single and the risk of gas channeling increased greatly. The field pilot test f micro-dispersed gel foam was carried out on September 20, 2018. The fluid is injected into well group in three slugs: micro-dispersed gel foam, normal foam and nitrogen gas. As a part of the foam pilot test monitoring, a gas tracer study was performed before and after the injection of gel foam in the reservoir. After the pilot test was carried out in the TK722CH2 well group, the subsequent injection gas swept new fractures and vugs, and a new dynamic connectivity has been established. The connectivity of well group changed from 1 injection well connects with 1 production well to 1 injection well connects with 4 production wells. Through the field pilot test of micro-dispersed gel foam, this paper verifies the effect of improve gas flooding and increase sweep volume of micro-dispersed gel foam. By analyzing the results of the field pilot test, the relevant technical mechanism of micro-dispersed gel foam in fractured-vuggy reservoir is revealed. As a result, the field pilot test in this paper provides theoretical basis and technical support for the efficient development of fractured-vuggy carbonate reservoir.