Daulat Debataraja Mamora

Light- and Heavy-Solvent Impacts on Solvent-Aided-SAGD Process: A Low-Pressure Experimental Study

Coinjecting solvent with steam under steam-assisted gravity-drainage (SAGD) process to reduce the required steam amount for heavy-oil production has gained importance in recent years. The objective of this experimental study was to investigate the drainage mechanism of coinjecting light and heavy solvents to improve production performance. A 2D cross-sectional low-pressure scaled physical model was constructed. The model represented a half-symmetry cross section of a typical SAGD drainage in the Athabasca formation. Using an infrared camera, we visualized and recorded expansion of the steam chamber and temperature distribution. The fluid injection rate, pressure, and temperature, and produced-liquid volumes were also recorded. The results show that the relative condensation time of solvent and steam results in different production performances. Light solvent, delivered in the vapour phase to the entire fluid interface, reduces the bitumen viscosity along the whole vapour-chamber boundary, but it may build a thick gas blanket that may reduce the heat transfer from the high-temperature vapour chamber to the surrounding low-temperature bitumen. Coinjecting a suitable multicomponent-solvent mixture, including a heavy solvent, can enhance the production performance by altering the condensation dynamics of the light hydrocarbons. The conclusions from this study can be used to design suitable solvent mixtures and coinjection strategies to deliver a higher production rate, higher recovery factor with lower cumulative steam required/oil ratio (CSOR), and lower cumulative energy required for oil production (CEOR) from SAGD performance.

Effect of Flue-Gas Impurities on the Process of Injection and Storage of CO2 in Depleted Gas Reservoirs

Our previous coreflood experiments—injecting pure CO2 into carbonate cores—showed that the process is a win-win technology, sequestrating CO2 while recovering a significant amount of hitherto unrecoverable natural gas that could help defray the cost of CO2 sequestration. In this paper, we report our findings on the effect of “impurities” in flue gas—N2, O2, H2O, SO2, NO2, and CO—on the displacement of natural gas during CO2 sequestration. Results show that injection of CO2 with approximately less than 1mole% impurities would result in practically the same volume of CO2 being sequestered as injecting pure CO2. This gas would have the advantage of being a cheaper separation process compared to pure CO2 as not all the impurities are removed. Although separation of CO2 out of flue gas is a costly process, it appears that this is necessary to maximize CO2 sequestration volume, reduce compression costs of N2 (approximately 80% of the stream), and improve sweep efficiency and gas recovery in the reservoir.

Numerical Investigation of Potential Injection Strategies To Reduce Shale Barrier Impacts on SAGD Process

It is well known that shale barriers significantly reduce steam-assisted gravity drainage (SAGD) performance in Athabasca fields. An extensive 2D simulation study shows that the flow resistance at the end of shale barriers and the extra heat absorbed by the residual water inside the unproductive shale barrier are the main reasons for the shale barrier effects. Long continuous shale barriers located vertically above or near the wellbore delay production performance significantly. We investigated potential strategies, including solvent coinjection, top injector application, or a combination of both, to reduce the shale barrier impacts. Solvent in the vapour phase can pass through the narrow flow path at the end of a shale barrier. Meanwhile, because the phase condenses from vapour to liquid, solvent efficiently reduces the flow resistance of the shale barrier. Liquid solvent coinjection can accelerate the near-wellbore flow and reduce the residual oil saturation at the wellbore vicinity. Coinjecting a multicomponent solvent can flush out the oil at different areas with different drainage mechanisms from vaporized and liquid components. Additional injector application at the top of the reservoir results in only marginal improvement.

Experimental Study of Solvent-Based Emulsion Injection to Enhance Heavy Oil Recovery in Alaska North Slope Area

Experimental Study of Solvent Based Emulsion Injection to Enhance Heavy Oil Recovery. (May 2010) Fangda Qiu, B.S.,China University of Petroleum (Beijing) Chair of Advisory Committee: Dr. Daulat D. Mamora This study presents the results of nano-particle and surfactant-stabilized solventbased emulsion core flooding studies under laboratory conditions that investigate the recovery mechanisms of chemical flooding in a heavy oil reservoir. In the study, bench tests, including the phase behavior test, rheology studies and interfacial tension measurement are performed and reported for the optimum selecting method for the nano-emulsion. Specifically, nano-emulsion systems with high viscosity have been injected into sandstone cores containing Alaska North Slope West Sak heavy oil with 16 API°, which was dewatered in the laboratory condition. The experiment results suggest that the potential application of this kind of emulsion flooding is a promising EOR (enhanced oil recovery) process for some heavy oil reservoirs in Alaska, Canada and Venezuela after primary production. Heavy oil lacks mobility under reservoir conditions and is not suitable for the application of the thermal recovery method because of environmental issues or technical problems. Core flooding experiments were performed on cores with varied permeabilities. Comparisons between direct injection of nano-emulsion systems and nano-emulsion

Production Acceleration and Injectivity Enhancement Using Steam-Propane Injection for Hamaca Extra-Heavy Oil

The largest known hydrocarbon deposit in the world, the Orinoco Belt in Venezuela, contains oil with a gravity ranging from 9 to 14° API. The Hamaca project encompasses more than 400 square miles of the Orinoco Belt and is believed to contain more than 30 billion barrels of extra-heavy oil (9° API). Production of the project started in November 2001 and the target is to produce some 30,000 m 3 (190,000 barrels) a day over a life span of more than 35 years. This study found that using propane as a steam additive can accelerate oil production and improve the effect of steam injectivity in the Hamaca field. In our laboratory study, steam-propane injection accelerated the start of oil production by 21% compared to that with pure steam injection. In the field, this could translate into significant gains in discounted revenues and a reduction in steam injection costs. Second, steam injectivity with propane as an additive was up to three times higher than that for pure steam injection. Third, accelerated oil production and increased injectivity were practically the same for all of the runs using propane as a steam additive (irrespective of the propane-steam mass ratios). Propane appears to be a viable steam additive at propane-steam mass ratios as low as 2.5:100.

Simulation studies of steam-propane injection for the Hamaca heavy oil field

Simulation studies were performed to evaluate a novel technology, steam-propane injection, for heavy Hamaca crude oil from Venezuelas Orinoco Basin. The oil has a specific gravity of 1.005 (9.3° API) and a viscosity of 25 Pa.s (25,000 cp) at 50° C. Two types of studies were performed: a simulation study to history-match laboratory results and a reservoir simulation study of steam-propane injection in a 5-spot pattern. A 1D 48 grid-cell model was used to describe the sand mix in the injection cell. A ten pseudo-component oil model for Hamaca oil was developed based on composition up to C 10 that gave a satisfactory history match of experimental results. Components in the C 7 - C 10 range appear to play a significant role during steam-propane injection and therefore need to be described in greater detail. The pseudo-component oil model was subsequently used in the reservoir model. The reservoir model represented a symmetry volume that is one-eighth of a 10-acre 5-spot pattern. A 9 x 5 x 10 3D Cartesian model was used to describe the symmetry volume, with one axis (x-axis) oriented parallel to the injector-producer direction. Simulation results indicate the following. First, oil production acceleration of 15% was observed with a propane-steam mass ratio (PSR) of 0.05 compared to pure steam injection. A substantial gain in discounted revenue and savings in steam injection cost would be realized. Second, unlike the experimental results, the oil production rate peak with steam-propane injection, 175 m 3 /d (1,100 STBID), is significantly higher than that with pure steam injection, 110 m 3 /d (690 STB/D). Third, oil production acceleration increases with increasing propane content. And finally, oil recovery (at the end of the five-year forecast period) increases from 2.3% OOIP for pure steam injection to 7.0% OOIP for steam-propane injection with a PSR of 0.05. Both experimental and simulation studies indicate that steam-propane injection is a very promising technology. Further research, followed by field tests, are recommended to better understand and verify the process under actual field conditions.

The effect of skin location, production interval and permeability on performance of horizontal wells

Abstract A three-dimensional reservoir simulation study has been carried out based on the production performance of an actual horizontal well completed on an oilrim reservoir. Although the absolute values of the simulation results are applicable to the well and reservoir studied, the main conclusions of the study are pertinent to horizontal well performance in general. The study quantified the detrimental effect of formation damage and low vertical/horizontal permeability ratio on the productivity of a horizontal well, which may be improved by increasing the length of the producing interval. Well productivity is found to be more adversely affected by formation damage near the toe-end than by that near the heel-end. Thus, when stimulating a horizontal well, intervals near the toe-end should not be ignored.

Experimental Investigation of Caustic Steam Injection for Heavy Oils

Experimental Investigation of Caustic Steam Injection for Heavy Oils.

Experimental and Analytical Studies of Hydrocarbon Yields under Dry, Steam, and Steam-Propane Distillation

Abstract This paper presents experimental studies to confirm and understand oil production accelerated when propane is used as additive during steam injection. Distillation experiments were performed using seven-component synthetic oil consisting of equal weights of alkanes. For comparison purposes, three different distillations were investigated: dry, steam, and steam-propane distillation, the latter at a propane-steam mass ratio of 0.05. Based on the experimental results, it is noted that the components appear to boil off at lower temperatures with steam-propane injection than with pure steam injection (with reference to dry distillation). Lowering of hydrocarbon boiling points by steam-propane injection appears to be the fundamental phenomenon that can explain: (1) higher yields during distillation of the synthetic oil, and (2) production acceleration, reduction in produced oil density and viscosity, and improved steam injectivity during steam-propane displacement of crude oils. Also, a thermodynamic description of the hydrocarbon synthetic mixture was done. The activity fugacity coefficient, the specific Gibbs energy, and the vaporization equilibrium ratio were calculated. It was founded that the largest activity fugacity coefficient and the smallest specific Gibbs energy were presented when steam-propane is used in the distillation experiments. The experimental procedure and method of analysis developed in this study will be beneficial to future researches in understanding the effect of propane as steam additive on actual crude oils.

Chemical Plug for Zone Isolation in Horizontal Wells

A laboratory study has been conducted on the use of chemical plugs, instead of conventional mechanical packers, to isolate water and gas-producing zones in horizontal wells. Results of experiments using horizontal wellbore models, consisting of PVC pipes internally lined with sand, indicate that slumping of the chemical plug could be avoided if the plug were spotted in a viscous brine pill. Of the three chemicals tested, a monomer, a polyacrylamide, and a plastic, only the plastic plug had a sufficiently high holding pressure. Research is being continued using a full-scale horizontal wellbore model.