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.
Polymer flooding is a widely used commercial process with a low cost per barrel of produced oil, For this application, hydrolyzed polyacrylamide (HPAM) polymers are the most widely used type of polymer. In an era of low cost oil, it is becoming even more essential to optimize the polymer flooding design under realistic reservoir conditions. The objective of this research was to better understand and predict the behavior of HPAM polymers and their effect on residual oil saturation, in order to improve the capability of optimizing field design and performance. The corefloods were performed under typical field conditions of low pressure gradients and low capillary numbers. The polymer floods of the viscous oils recovered much more oil than the water floods, with up to 24% lower oil saturation after the polymer flood than the water flood. The experimental data are in good agreement with the fractional flow analysis using the assumptions that the true residual oil saturations and end point relative permeabilities are the same for both water and polymer. This suggests that for more viscous oils, the oil saturation at the end of water flood (i.e. at greater than 99% water cut) is better described as ‘emaining’ oil saturation rather than the true ‘esidual’ oil saturation. This was true for all of the corefloods regardless of the core permeability and without the need for assuming a permeability reduction factor in the fractional flow analysis.
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.
Water-based polymers are often used to improve oil recovery by increasing displacement sweep efficiency. However, recent laboratory and field work has suggested these polymers, which are often viscoelastic, may also reduce residual oil saturation. The objective of this work is to investigate the effect of viscoelastic polymers on residual oil saturation in Bentheimer sandstones and identify conditions and mechanisms for the improved recovery. Bentheimer sandstones were saturated with a heavy oil (120cp) and then waterflooded to residual oil saturation using brine followed by an inelastic Newtonian fluid (diluted glycerin). These floods were followed by injection of a viscoelastic polymer, hydrolyzed polyacrylamide (HPAM).
Significant reduction in residual oil was observed for all core floods performed at constant pressure drop when the polymer had significant elasticity (determined by the dimensionless Deborah number,
As polymer injection has not reached the same maturity as waterflooding, implementing polymer injection projects at field scale requires a workflow comprising screening of the portfolio of an organization for oil fields potentially amenable for polymer injection, laboratory and field testing followed by sector- and field implementation and roll-out in the portfolio.
Going through the workflow, not only the subsurface uncertainty is reduced but also the knowledge about the cost structure and operating capabilities of the organization improved.
Analyzing the economics of polymer injection projects shows that costs can be split into polymer injector-producer (polymer pattern) dependent and independent costs. Knowing these costs, a Minimum Economic Number of Patterns (MENP) is defined to achieve Net Present Value zero. This number is used to determine a Minimum Economic Field Size (MEFS) for polymer injection which is taken into account in the screening of the portfolio.
Defining a robustness criterion for economics, the minimum number of patterns for polymer injection meeting this criterion is calculated. This criterion is applied to generate a diagram allowing for screening of fields for polymer economics using pattern dependent and pattern independent costs and Utility Factor.
The cost structure reveals how the NPV of polymer projects changes with number of patterns, incremental oil and injectivity. Injectivity is of particular importance as it determines the Chemical Affected Reservoir Volume (CARV) or speed of production.
A sensitivity analysis of the NPV showed that for the cost structure used here, in addition to the polymer costs, the well costs are important for the economics of a full-field polymer injection project.
Alkaline-surfactant-polymer (ASP) flooding of a viscous oil (100 cp) is studied here in a two-dimensional (2D) sand pack. An ASP formulation was developed by studying the phase behavior of the oil with several alkaline-surfactant formulations. The effectiveness of the ASP formulation was validated in a 1D sand pack by conducting a water flood followed by a stable ASP flood. Reservoir sand was then packed into a 2D square steel cell similar to a quarter five-spot pattern. Several ASP floods were then conducted in this 2D cell to study both the displacement and sweep efficiency of ASP floods. First, the polymer concentration was varied to find an optimum polymer concentration. Then the waterflood extent was varied (0–1 PV) after which the ASP flood was initiated. The oil recovery, oil cut, effluent concentration and pressure drop were monitored during the floods. The tertiary ASP flood was very effective in 1D and validated the ASP formulation. The 2D tertiary ASP flood also recovered most of the oil (~98% of OOIP) when the ASP slug viscosity exceeded the oil viscosity, but the pressure gradients were high at ~ 1ft/d injection. When the ASP slug viscosity was lowered to ~1/3 of oil viscosity, oil recovery dropped slightly to 90% OOIP. However, it also decreased the pressure gradient 5 times, which would give good flow rates in the field conditions. As the extent of waterflood preceding ASP got shorter, the oil was recovered faster (for the same pore volumes injected), but the pressure gradient was higher for the ASP flood than the water flood. The ultimate recovery was independent of the extent of waterflood.
A wormhole dynamic growth model has been developed and incorporated with a commercial reservoir simulator, i.e., CMG, to characterize wormhole growth for cold heavy oil production with sand (CHOPS) processes and extends its application to a field well. More specifically, geomechanics analysis associated with a collapsed pore and its throat structure has been performed to quantify the sand production. Then, a sand failure criterion and a four-direction pressure difference analysis are respectively proposed to determine the sand production rate and the potential direction of wormhole generation and growth. By considering the uncertainties associated with the parameters involved in the wormhole growth model, history matching is respectively conducted to estimate the critical breakdown pressure, superficial area of the collapsed throats, and coefficients of the permeability-porosity correlation for a field CHOPS well. Subsequently, the dynamic wormhole growth model has been validated with a synthetic model and then extended to a CHOPS well for determining its wormhole network. It is found from both the synthetic case and field application that the newly proposed technique can be used to determine the corresponding wormhole network as a function of time by history matching the production profile. Furthermore, the history matched models can also be utilized to optimize the following enhanced oil recovery processes such as cyclic solvent injection.
When compared with steam-assisted gravity drainage (SAGD) operations in the McMurray Formation, Athabasca Oil Sands, SAGD projects in the Clearwater Formation at Cold Lake did not perform as expected, likely because of reservoir properties. This paper will use the Orion SAGD case study to: (1) investigate the impacts of reservoir properties on the SAGD thermal efficiency by field evidences; (2) identify key geological parameters influencing each well pad; and (3) summarize major geological challenges for Orion SAGD expansion.
Wireline log data were interpreted to characterize reservoir properties, which were used to build 3D models. 3D visualizations and 2D cross sections of the reservoir revealed spatial distribution and heterogeneity of each property. SAGD production performance was analyzed using: (1) temperature profiles that monitored the growth of the steam chamber; (2) cumulative steam-oil ratios (CSORs); and (3) oil production rates (OPRates), which are direct indicators of thermal efficiency.
Results show that impermeable barriers and low-permeability zones were detrimental to steam injectivity and steam chamber growth, as observation wells in Pilot Pads 1 and 3 did not detect any steam saturation. High-permeability zones favored high steam injectivity and mobility, especially in Pad 105. Steam chambers were irregularly shaped by high shale-content zones, as two sharp spikes displayed on the temperature profile in Pad 103. Low oil-saturation zones and thin net-pays increased the CSORs, as seen in Pads 106 and 104. Impermeable barriers are almost horizontal, making no difference on well pad orientation by their dip angles. Lack of porosity variation made it difficult to identify the impact of porosity on each well pad.
The relatively extensive distribution of impermeable barriers between and above well pairs, as well as the relatively large area of low oil saturation and thin net-pay, were identified as major geological challenges.
Dwarakanath, Varadarajan (Chevron) | Dean, Robert M. (Chevron) | Slaughter, Will (Chevron) | Alexis, Dennis (Chevron) | Espinosa, David (Chevron) | Kim, Do Hoon (Chevron) | Lee, Vincent (Chevron) | Malik, Taimur (Chevron) | Winslow, Greg (Chevron) | Jackson, Adam C. (Chevron) | Thach, Sophany (Chevron)
Polymer flooding by liquid polymers is an attractive technology for rapid deployment in remote locations. Liquid polymers are typically oil external emulsions with included surfactant inversion packages to allow for rapid polymer hydration. During polymer injection, a small amount of oil is typically co-injected with the polymer. The accumulation of the emulsion oil near the wellbore during continuous polymer injection will reduce near wellbore permeability. The objective of this paper is to evaluate the long-term effect of liquid polymer use on polymer injectivity. We also present a method to remediate the near well damage induced by the emulsion oil using a remediation surfactant that selectively solubilizes and removes the near wellbore oil accumulation. We evaluated several liquid polymers using a combination of rheology measurement, filtration ratio testing and long-term injection coreflood experiments. The change in polymer injectivity was quantified in surrogate core after multiple pore volumes of liquid polymer injection. Promising polymers were further evaluated in both clean and oil-saturated cores. In addition, phase behavior experiments and corefloods were conducted to develop a surfactant solution to remediate the damage induced by oil accumulation. Permeability reduction due to long term liquid polymer injection was quantified in cores with varying permeabilities. The critical permeability where no damage was observed was identified for promising liquid polymers. A surfactant formulation tailored for one of the liquid polymers improved injectivity three- to five-fold and confirms our hypothesis of permeability reduction due to emulsion oil accumulation. Such information can be used to better select appropriate polymers for EOR in areas where powder polymer use may not be feasible.
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.