Improved Cyclic Stimulation Using Gas Mixtures

Abstract

Cyclic gas injection processes have been primarily restricted to the use of pure CO2 or CO2 that has been slightly contaminated with reservoir gases. However, it is difficult to employ CO2 in certain circumstances due to transport, economic, or corrosion problems. This paper presents the results of laboratory investigations of the cyclic gas injection process using methane, nitrogen and mixtures of these gases with CO2. Cyclic gas injections were performed at immiscible conditions in consolidated sandstone cores that contained waterflood residual oil. Cyclic CO2 injections were performed under analogous conditions for comparative purposes. Pure methane recovered approximately the same amount of waterflood residual oil as CO2, whereas pure nitrogen recovered about half that amount. Pure CO2 was more mobile in porous media than pure CH4 or N2. Certain CO2/N2 and CO2/CH4 mixtures yielded outstanding results, recovering 2-3 times the waterflood residual oil produced by pure CO2. Maximum recovery was obtained with mixtures containing 10-25% CO2. Introduction Cyclic gas injection is a single-well enhanced oil recovery (EOR) process which involves the injection of a slug of gas into a well. After gas injection, the well is shut-in for a "soak" period to allow time for equilibration. Then, the well is reopened and production is resumed. Cyclic CO2 injection, which is also known as CO2 huff 'n' puff, is the most common cyclic gas injection process. Although the process was originally proposed as an alternative to cyclic steam injection for the recovery of heavy crude, it has primarily been used for the recovery of light oils. Numerous field tests have been performed and the results revealed that the process is economically feasible in diverse reservoir environments. Although field results indicate that cyclic CO2 injection may be successfully implemented under a variety of conditions, application of CO2 processes offshore, and in certain isolated locations onshore, are limited due to CO2 transportation costs. Offshore application of CO2 is additionally restricted due to difficulties in isolating CO2 contamination, and the resulting corrosion. Gases other than CO2 have been employed to a wide extent in full-scale EOR processes that involve well-to-well flooding. The gases that have been used include methane, rich gas, nitrogen, and flue gas. Methane and rich gas are non-corrosive, and are frequently available from production streams. Nitrogen is also non-corrosive, and there are inexpensive procedures available for extraction of nitrogen from air. Flue (or engine exhaust) gas is primarily nitrogen mixed with 10-20% CO2. It is a product of combustion and is generated by combustion facilities such as power plants. Despite the widespread use of these gases in well-to-well processes, only a limited number of reports concerning the use of gases other than CO2 have appeared in the cyclic injection literature. Haines and Monge examined the feasibility of cyclic natural gas injection for the recovery of light oils. The natural gas employed in the study was primarily methane contaminated with less than 2% nitrogen, CO2, and ethane. Coreflood and numerical simulation results indicated that the natural gas injection process was a technically and economically feasible EOR option, and that repressurization and gas relative permeability hysteresis were the most important recovery mechanisms. Shelton and Morris utilized cyclic rich gas injection to improve production rates in viscous oil reservoirs. The rich gas employed in the field tests consisted of methane enriched with propane. P. 95

CO2 Huff 'n' Puff Revives Shallow Light-Oil-Depleted Reservoirs

“…In this study, the other end of the core was closed to model a reservoir's closed outer boundary frequently encountered in field cases. The reservoir boundary condition modeled in this study was different from those by other previous literatures (Monger-McClure and Coma, 1988;Thomas et al, 1990;Monger-McClure et al, 1991;Bardon et al, 1994;Shayegi et al, 1996;Zhang et al, 2006), where a constant reservoir boundary with an aquifer was involved.…”

“…All those operations occurred at reservoir conditions (12.9MPa and 44℃). Compared with the huff 'n' puff corefloods by other researchers (Monger-McClure and Coma, 1988;Thomas et al, 1990;Monger-McClure et al, 1991;Bardon et al, 1994;Shayegi et al, 1996;Zhang et al, 2006), the saturated core with oil in this study was not flooded again with formation water since here CO 2 huff 'n' puff process was applied at the primary stage of production.…”

Modeling, analysis, and screening of cyclic pressure pulsing with nitrogen in hydraulically fractured wells

“…Later, cyclic injection of carbon dioxide was utilized for heavy oil in California (Sankur and Emanuel 1983), Arkansas (Khatib et al 1981), and Turkey (Bardon et al 1986), and for light and medium types of oil in Kentucky (Bardon et al 1994), Texas (Haskin and Alston 1989), and Louisiana (Monger and Coma 1988). In the 1990s and 2000s, nitrogen and mixtures with nitrogen were proposed and successfully applied (Shayegi et al 1996;Miller and Gaudin 2000). Artun et al (2010Artun et al ( , 2011aArtun et al ( , b, 2012 performed detailed parametric studies of the process by analyzing a large set of reservoir simulation runs and developed proxy models to be used for screening and optimization of cyclic pressure pulsing with nitrogen and carbon dioxide in naturally fractured reservoirs.…”

Development of universal proxy models for screening and optimization of cyclic pressure pulsing in naturally fractured reservoirs

“…Later, a number of experimental, modeling and field studies have been presented with pure CO 2 injection. In addition, there are studies that considered using pure N 2 (Miller and Gaudin, 2000), and mixtures of these gases with CO 2 (Shayegi et al, 1996). CO 2 was first proposed as a substitute for steam to recover heavy oil with cyclic injection.…”