Enhanced oil displacement in a reservoir is highly affected by wettability alterations in conjunction with the lowering of viscosities during steam assisted gravity drainage (SAGD) for bitumen extraction. The impartation of energy in the form of heat to the fluid by injecting steam triggers an alteration to a more water-wet state during SAGD. However, the presence of three distinct phases in the reservoir has implications for the effective modeling of the complex fluid dynamics. Dependency of the relative permeability endpoints on the temperature realized as a function of the introduction of steam is difficult to model. Optimization of any steam process requires simulation in order to adequately characterize years of flow and so a model that is capable of representing three phase flow is necessary. To obtain this a pseudo-two phase relative permeability is proposed that assumes fractional flow theory is valid and treats the experiments as a waterflood.
In this study, experimental recovery data for two SAGD experiments and one hot water flood are empirically matched by manipulating relative permeabilities. The analytical approach implemented allows for the representation of fluid flow in the reservoir by achieving a pseudo-two phase relative permeability that results in comparable performance to the experiments. Waterflooding techniques were utilized which allowed for the negation of the steam phase in the model and so two-phase flow was established.
The sensitivity of the relative permeability curves to temperature change results in the inability to formulate a generic three-phase curve and so the pseudo-two phase curve is valuable for the purpose of simulation. The methodology presented enables the formulation of a simplified relative permeability that is unique to each process used and in that specific location. The model that was established was validated and proven credible by the good match with the experimentally obtained values.
As one of the unconventional resources, tight oil has become one of the most important contributor of oil reserves and production growth. The successful commercial production of tight oil is mainly reliant on the advancement in horizontal drilling and multistage hydraulic fracturing technique. Development of tight oil reservoirs remains in an early stage. Primary oil recovery factor in these reservoirs is very low, leaving substantial volume of oil trapped underground due to the low porosity, low permeability characteristic of tight oil reservoirs. Thus, investigation of enhanced oil recovery methods is more than imperative in tight oil reservoirs. CO2 Huff-and-Puff technology has been effectively applied in conventional reservoirs and can be tailored to adapt for the characteristics of tight oil reservoirs.
In this study, the performance of water flooding in tight oil reservoir is studied and compared with that of the CO2 Huff-and-Puff process. Sensitivity analysis demonstrates that the performance of CO2 Huff-and-Puff is more sensitive to the length of gas injection and production step in each cycle, compared to the soaking time. The CO2 Huff-and-Puff process is optimized and an adaptive CO2 Huff-and-Puff process is conducted for tight oil reservoirs after primary production. Simulation results show that the adaptive cycle length CO2 Huff-and-Puff process can improve the incremental oil recovery by 11.1% over a fixed cycle length process. Finally, the inter-well interference during CO2 Huff-and-Puff is studied, and it is found that a multi-well asynchronous CO2 Huff-and-Puff pattern can improve the incremental oil recovery by 31.6% over that of a synchronous pattern.
The Medicine Hat Glauconitic C Pool is located partially inside the city limits of Medicine Hat, Alberta, Canada. This 15-18° API oil pool is under waterflood. Reservoir management strategies in the pool are limited by the reservoir quality, wellbore architecture and business environment. Surface land access due to the expanding Medicine Hat city limits and pre-existing wellbore orientations have constrained the waterflood pattern and infill drilling options. Current estimates indicate 21% of the oil in place will be recovered at the end of the waterflood.
The polymer flood pilot was started in 2012 with a goal to achieve 6% incremental recovery with a one year initial response time. The pilot's designed injection rate was 6,300 bbl/d (1000 m3/d) in 5 injectors, each representing different reservoir conditions and injection patterns. Following injection, pre-existing water channels and high permeability streaks resulted in rapid polymer breakthrough in as little as 48 hours in some cases.
To increase the efficiency of the polymer flood and reduce cycling polymerized water, a new approach to reservoir management had to be considered:
Each of the 5 patterns inside the pilot was monitored and managed individually, with a fit-for-purpose strategy in mind. Although 1 year to response was estimated, after four months, oil rates and oil cuts increased unexpectedly. However, after reaching peak production, the expected steep decline was observed. New reservoir management strategies were implemented in order to slow the decline and attempt to increase the incremental recovery from 6% to 10%: attempts to block water channels in the injectors, producer shut-ins and frequent injection target changes proved beneficial.
Each of the 5 patterns inside the pilot was monitored and managed individually, with a fit-for-purpose strategy in mind.
Although 1 year to response was estimated, after four months, oil rates and oil cuts increased unexpectedly. However, after reaching peak production, the expected steep decline was observed.
New reservoir management strategies were implemented in order to slow the decline and attempt to increase the incremental recovery from 6% to 10%: attempts to block water channels in the injectors, producer shut-ins and frequent injection target changes proved beneficial.
The polymer pilot has exceeded expectations to date.
This case study provides an outline of the changes that were made and the results that have been observed.
This paper addresses two questions for polymer flooding. First, what polymer solution viscosity should be injected? A base-case reservoir-engineering method is present for making that decision, which focuses on waterflood mobility ratios and the permeability contrast in the reservoir. However, some current field applications use injected polymer viscosities that deviate substantially from this methodology. At one end of the range, Canadian projects inject only 30-cp polymer solutions to displace 1000-3000-cp oil. Logic given to support this choice include (1) the mobility ratio in an unfavorable displacement is not as bad as indicated by the endpoint mobility ratio, (2) economics limit use of higher polymer concentrations, (3) some improvement in mobility ratio is better than a straight waterflood, (4) a belief that the polymer will provide a substantial residual resistance factor (permeability reduction), and (5) injectivity limits the allowable viscosity of the injected fluid. At the other end of the range, a project in Daqing, China, injected 150-300-cp polymer solutions to displace 10-cp oil. The primary reason given for this choice was a belief that high molecular weight viscoelastic HPAM polymers can reduce the residual oil saturation below that expected for a waterflood or for less viscous polymer floods. This paper will examine the validity of each of these beliefs.
The second question is: when should polymer injection be stopped or reduced? For existing polymer floods, this question is particularly relevant in the current low oil-price environment. Should these projects be switched to water injection immediately? Should the polymer concentration be reduced or graded? Should the polymer concentration stay the same but reduce the injection rate? These questions are discussed.
Aminzadeh, Behdad (Chevron Energy Technology Company) | Hoang, Viet (Chevron Energy Technology Company) | Inouye, Art (Chevron Energy Technology Company) | Izgec, Omer (Chevron Energy Technology Company) | Walker, Dustin (Chevron Energy Technology Company) | Chung, Doo (Chevron Energy Technology Company) | Nizamidin, Nabijan (Chevron Energy Technology Company) | Tang, Tom (Chevron Energy Technology Company) | Lolley, Chris (Chevron Energy Technology Company) | Dwarakanath, Varadarajan (Chevron Energy Technology Company)
Alkali flooding in heavy oil reservoirs is known to stabilize emulsion in-situ and improve the recovery beyond that of conventional waterflood under certain boundary and initial conditions. The overarching goal of this study is to develop a systematic approach to optimize this process and capture underlying recovery mechanisms. Therefore, we experimentally evaluated the performance of alkali flood as a function of emulsion type and viscosity. Phase behavior and viscosity of the microemulsion are modified by introducing seven different surfactants. Microscope imaging techniques are employed to measure the droplet size distribution for type I and II emulsions. Viscosities of generated emulsions are measured with a rotational rheometer at low temperatures and with an electromagnetic viscometer at reservoir conditions. Finally, corefloods are conducted at different conditions to evaluate the performance of displacement as a function of emulsion type and viscosity. Enhanced alkali floods showed an incremental recovery of 8 – 50% beyond that of waterflood. Formation of higher viscosity emulsion has a large contribution on the sweep efficiency and therefore improved oil recovery during alkali flood; however, other mechanisms (e.g. entrainment and entrapment) also have contribute to the incremental recovery. Results of our experiments indicated that the incremental recovery is a strong function of emulsion type, emulsion viscosity, and the droplet size distribution.
Aqueous based foam injection has gained interest for conventional oil recovery in recent times. Foam can control the mobility ratio and improve the sweep efficiency in oil reservoirs over gas flooding. However, due to the high viscosity of oil, its application in heavy oil reservoirs is challenging. Moreover, oil-wet nature of carbonate reservoirs makes it difficult for aqueous based foam to efficiently remove the heavy oil. On the other hand, hydrocarbon solvents have been used for decreasing the heavy oil viscosity and increase its recovery by diffusion and mixing mechanisms. However, low rate of diffusion/dispersion and inadequate sweep efficiently, especially in heterogeneous reservoirs, are of the main challenges during solvent injection. Combination of foam and solvent (solvent based foam) can overcome the challenges existing in the separate application of aqueous based foam and solvent injection for heavy oil recovery. The challenge is to understand how the combination of solvent and foam will help us to improve the heavy oil sweep efficiency.
This paper introduced a new approach to increase sweep efficiency during heavy oil recovery with the help of hydrocarbon solvent-based CO2 foam. Foam was generated with the help of a fluorosurfactant in the hydrocarbon solvent. Static bulk performances of foam were analyzed at different concentrations of surfactant. Surface tension measurement was also performed to study the adsorption of surfactant into the liquid-gas interface and its effect on foamability and foam stability. A specially designed fractured micromodel (oil wet, representing fractured carbonate reservoirs) were used to visualize the pore scale phenomena during solvent based foam injection. A high quality camera was utilized to capture high quality images/movies.
According to static experiments, although the value of the surface tension of hydrocarbon solvent was initially low, the addition of surfactant slightly decreased the surface tension further and surfactant adsorption at the interface improved the foam stability. This process was more evident in higher concentration of surfactant. In addition, dynamic pore scale observation through this study revealed that solvent based foam can significantly contribute to heavy oil recovery with different mechanisms. At initial stage, solvent diffuses and mixes with viscous oil and reduce the viscosity. Later, foam bubbles improve the sweep efficiency by diverting the solvent toward untouched part of the porous media. In addition, foam bubbles partially blocked the opening area in matrix/swept-area increasing the contact of solvent and heavy oil, providing better mixing. Therefore, oil is swept much faster and more efficiently from the grain in oil-wet porous media compared to that of conventional solvent flooding.
Successful application of solvent based foam can significantly improve the heavy oil recovery in reservoirs with high heterogeneity and oil-wet matrix. Cooperation of diffusion/dispersion and mobility reduction will result in faster oil production and lesser amount of oil will leave behind improving the sweep efficiency.
By coupling heat and mass transfer for C3H8–
Solvent Aided-Steam Flooding (SA-SF) focuses on maximizing the oil production by reducing the economic and environmental challenges created by steam generation. However, the solvent selection is vital due to the interaction of solvents with asphaltenes. Moreover, the polar nature of asphaltenes also enables asphaltene-steam interaction which may result in emulsion formation. This study investigates solvent-asphaltene-steam interaction during SA-SF with low and high molecular weight asphaltene insoluble solvents.
Two different solvents were tested; n-hexane (E1 and E4) and a commercial solvent (CS) (E2 and E5) with four flooding experiments; two miscible flooding (E1 and E2) and two SA-SF (E4 and E5) experiments. Results were compared with steam flooding (E3) experiment. The performance evaluation of different enhanced oil recovery methods was accomplished by comparing the oil recovery rates. The asphaltene content of produced oil samples was determined by standard methods. The asphaltene-steam interaction was analyzed with microscopic images, and the water content of produced oil samples was measured by Thermogravimetric Analysis (TGA).
Even though similar cumulative oil productions were obtained by the end of E1 (n-hexane-flooding) and E2 (CS-flooding), the produced oil quality varied due to asphaltene and clay contents. While higher clay content was measured for E1, E2 had a lower quality, due to higher asphaltene contents. This finding is due to the heavy dearomatized hydrocarbons composition of the CS which ranges from C11 up to C16 and enables more asphaltene production. Even though, E5 yielded the highest liquid production among all experiments; the produced liquid was composed of emulsified oil. The solvent aided-steam flooding (SA-SF) experimental results, which have been conducted with n-hexane/steam (E4) and CS/steam (E5) injections, suggest that as the asphaltene content increases in produced oil samples, more hard-to-break emulsions are formed. The unusual stability of these emulsions can be attributed to the nature of the asphaltene present in the produced oil.
From the results presented, it is recommended the use of lower carbon number solvents to leave the larger amounts of asphaltenes in the reservoirs. The solvents differed in their interactions with the asphaltenes present in the oil and with the steam that has a direct impact not only on the quantity of oil produced but the quality as well. Hence, the wise selection of the appropriate solvent cannot be ignored during solvent aided-steam flooding processes.
Kuznetsov, Oleksandr (Baker Hughes) | Mazyar, Oleg (Baker Hughes) | Agrawal, Devesh (Baker Hughes) | Suresh, Radhika (Baker Hughes) | Feng, Xianhua (Baker Hughes) | Behles, Jackie (Baker Hughes) | Khabashesku, Valery (Baker Hughes)
Oil sand ore flotation is a primary method of bitumen recovery from mined Athabasca tar sands. In bitumen flotation, suspended biwettable ore fines, such as clays, tend to migrate to oil-water interfaces, creating slime coating on liberated bitumen droplets. Slime coating significantly reduces the efficiency of the flotation process and overall oil recovery. Ultra-dispersed hydrophilic silica nanoparticles were found to stabilize biwettable ore fines in an aqueous phase by adsorbing onto fines surfaces, even at concentrations as low as 50 ppm. As a result, fine solids move away from oil/water interfaces, reducing the slime coating and increasing bitumen recovery during flotation of low-grade ore by more than 5%. The addition of nanoparticles has no negative effect on froth quality or oil, water and solid separation in naphthenic and paraffinic froth treatment processes. Detailed molecular dynamics (MD) simulations revealed mechanisms that improve bitumen liberation from mined oil sands in a flotation process. The studies demonstrated that colloidal nanoparticles affect many stages of the bitumen extraction process from bitumen separation to clay wettability alteration.