Skauge, T. (CIPR Uni Research) | Skauge, A. (CIPR Uni Research) | Salmo, I. C. (CIPR Uni Research) | Ormehaug, P. A. (CIPR Uni Research) | Al-Azri, N. (PDO) | Wassing, L. M. (Shell Global Solutions International BV) | Glasbergen, G. (Shell Global Solutions International BV) | Van Wunnik, J. N. (Shell Global Solutions International BV) | Masalmeh, S. K. (Shell Global Solutions International BV)
Polymer injectivity is a critical parameter for implementation of polymer flood projects. An improved understanding of polymer injectivity is important in order to facilitate an increase in polymer EOR implementation. Typically, injectivity studies are performed using linear core floods. Here we demonstrate that polymer flow in radial and linear models may be significantly different and discuss the concept in theoretical and experimental terms.
Linear core floods using partially hydrolyzed polyacrylamides (HPAM) were performed at various rates to determine in-situ viscosity and polymer injectivity. Radial polymer floods were performed on Bentheimer discs (30 cm diameter, 2-3 cm thickness) with pressure taps distributed between a central injector and the perimeter production well. The in-situ rheological data are also compared to bulk rheology. The experimental set up allowed a detailed analysis of pressure changes from well injection to production line in the radial models and using internal pressure taps in linear cores.
Linear core floods show degradation of polymer at high flow rates and a severe degree of shear thickening leading to presumably high injection pressures. This is in agreement with current literature. However, the radial injectivity experiments show a significant reduction in differential pressure compared to the linear core floods. Onset of shear thickening occurs at significantly higher flow velocities than for linear core floods. These data confirm that polymer flow is significantly different in linear and radial flow. This is partly explained by the fact that linear floods are being performed at steady state conditions, while radial injections go through transient (unsteady state) and semi-transient pressure regimes.
History matching of polymer injectivity was performed for radial injection experiments. Differences in polymer injectivity are discussed in the framework of theoretical and experimental considerations. The results may have impact on evaluation of polymer flood projects as polymer injectivity is a key risk factor for implementation.
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.
Luo, Haishan (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Upscaling of unstable immiscible flow remains an unsolved challenge for the oil industry. The absence of a reliable upscaling approach greatly hinders the effective reservoir simulation and optimization of heavy oil recoveries using waterflood, polymer flood and other chemical floods, which are inherently unstable processes. The difficulty in upscaling unstable flow lies in estimating the propagation of fingers smaller than the gridblock size. Using classical relative permeabilities obtained from stable flow analysis can lead to incorrect oil recovery and pressure drop in reservoir simulations.
In a recent study based on abundant experimental data, it is found that the heavy-oil recovery by waterfloods and polymer floods has a power-law correlation with a dimensionless number (named viscous finger number in this paper), which is a combination of viscosity ratio, capillary number, permeability, and the cross-section area of the core. Based upon this important finding as well as the features of unstable immiscible floods, an effective-finger model is developed in this paper. A porous medium domain is dynamically identified as three effective zones, which are two-phase flow zone, oil single-phase flow zone, and bypassed oil (isolated oil island) zone, respectively. Flow functions are derived according to effective flows in these zones. This new model is capable of history-matching a set of heavy-oil waterflood corefloods under different viscosity ratios and injection rates. Model parameters obtained from the history match also have a power-law correlation with the viscous finger number.
The build-up of this correlation contains reasonable physical meanings to quantitatively characterize the upscaled behavior of viscous fingering effects. Having such a correlation enables the estimation of model parameters in any gridblock of the reservoir by knowing the local viscous finger number in reservoir simulations. The model is applied to several heavy-oil field cases with waterfloods and polymer floods with different heterogeneities. Oil recovery in water flooding of viscous oils is overpredicted by classical simulation methods which do not incorporate viscous fingering properly. Simulation results indicate that the new model reasonably differentiates the oil recoveries at different viscous finger numbers, e.g., lower injection rate leads to higher oil recovery. In contrast, classical simulations obtain close oil recoveries under different injection rates or degrees of polymer shear-thinning, which is apparently incorrect for unstable floods. Moreover, coarse-grid simulations using the new model are able to obtain consistent saturation and pressure maps with fine-grid simulations when the correlation lengths are not smaller than the coarse gridblock size. Furthermore, it is well captured by the model that the shear-shinning polymer solution can strengthen the fingering in high-permeability regions due to increased capillary number and viscosity ratio, which is not observed in waterflood. As a whole, the new model shows encouraging capability to simulate unstable water and polymer floods in heavy oil reservoirs, and hence can facilitate the optimization of heavy-oil EOR projects.
Fracturing fluids are commonly formulated with fresh water to ensure reliable rheology. However, fresh water is becoming more costly, and in some areas, it is difficult to obtain. Therefore, using produced water in hydraulic fracturing has received increased attention in the last few years. A major challenge, however, is its high total dissolved solids (TDS) content, which could cause formation damage and negatively affect fracturing fluid rheology. The objective of this study is to investigate the feasibility of using produced water to formulate crosslinked-gel-based fracturing fluid. This paper focuses on the compatibility of water with the fracturing fluid system and the effect of salts on the fluid rheology.
Produced water samples were analyzed to determine different ion concentrations. Solutions of synthetic water with different amounts of salts were prepared. The fracturing fluid system consisted of natural guar polymer, borate-based crosslinker, biocide, surfactant, clay controller, scale inhibitor, and pH buffer. Compatibility tests of the fluid system were conducted at different cation concentrations. Apparent viscosity of the fracturing fluid was measured using a high-pressure high-temperature rotational rheometer. All rheology tests were conducted at a temperature of 180°F and were conducted according to API 13m procedure with a three-hour test duration. Fluid breaking test was also performed to ensure high fracture and proppant pack conductivity.
Produced water analysis showed a TDS content of 125,000 ppm, including Na, Ca, K, and Mg ion concentrations of 36,000, 10,500, 1,700, and 700 ppm, respectively. Results indicated the potential of produced water to cause formation damage. Therefore, produced water was diluted with fresh water and directly used to formulate the fracturing fluid. Divalent cations were found to be the main source of precipitation, and the reduced amounts of each ion were determined to prevent precipitation. The separate and combined effects of Na, K, Ca, and Mg ions on the viscosity of the fracturing fluid were also studied. Fluid viscosity was found to be significantly affected by the concentrations of divalent cations regardless of the concentrations of monovalent cations. Monovalent cations reduced the viscosity of fracturing fluid only in the absence of divalent cations, and showed no effect in the presence of Ca and Mg ions. Water with reduced concentrations of monovalent and divalent cations showed the most suitable environment for polymer hydration and crosslinking.
This paper contributes to the understanding of the main factors that enable the use of produced water for hydraulic fracturing operations. Maximizing the use of produced water could reduce its disposal costs, mitigate environmental impacts, and solve fresh water acquisition challenges.
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.
Microemulsion properties significantly impact any EOR process that relies on surfactants or soaps to generate ultralow interfacial tension to displace trapped oil. Unfavorable microemulsion viscosity can lead to high chemical retention, low oil recovery, and overall unfavorable performance across all modes. Controlling microemulsion properties is important in conventional approaches like surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) flooding, in addition to new applications like gravity stable displacements, spontaneous imbibition in fractured carbonates and unstable floods of viscous oil. Despite the central importance, microemulsion viscosity and rheology remain poorly understood.
This paper describes the results of an extensive experimental microemulsion study. We evaluated the effect of polymer on microemulsion viscosity in different microemulsion phase types (i.e. oil in water, bi-continuous, water in oil emulsions). We measured microemulsion viscosities across a broad salinity range for several crudes from light (API >30°) to heavy oils (API<14°) and observed Newtonian rheology for all phase types. The effect of cosolvents on microemulsion viscosity was also evaluated. Finally, we evaluated microemulsions with and without alkali to help understand potential differences between ASP and SP microemulsions.
We include many observations consistent with earlier literature using recently developed surfactants and report the microemulsion viscosity details for many high performance surfactant formulations across a wide range of conditions. We have also describe several observations, including polymer decreasing the required time to achieve equilibrium in microemulsion pipettes and the qualitative change in microemulsion behavior with and without polymer in Windsor Type III microemulsions.
Achieving maximum oil recovery utilizing CO2 has limitations when operating at, or very close, to the Minimum Miscibility Pressure (MMP) of the CO2 in the oil. A modular source of CO2 would allow Enhanced Oil Recovery (EOR) flooding of "stranded" and shallow reservoirs. Unfortunately, modular sources of CO2 production often include CO and N2 mixed with the CO2. Thus, testing for EOR application of a mixed gas-containing CO2, N2, and CO was initiated.
Bench scale testing using Rising Bubble Apparatus (RBA), Slim Tubes, and linear core flood have been conducted on oils ranging from 16-42° gravities having viscosities of 0.5-280 cp. All tests were conducted at reservoir temperatures and pressures. CO, being a strong reducing agent, was further tested on reservoir rock containing swelling clays with hydrated ferric hydroxides. Due to the apparent reduction of the ferric hydroxide, and the liberation of its water of hydration, an increase in matrix permeability and clay stabilization, was observed.
For most oils tested, the CO2/CO mixture increased rate of oil recovery by 2-3X, using only 50-60% as much gas/bo as compared to pure CO2. Recovery factors of 80%, at immiscible pressures 30-40% below CO2 MMP, were achieved. Addition of 15% N2 (v/v) to the CO2/CO mixture did not impair oil recovery. Interfacial testing (IFT) of oils, using pure CO, demonstrated a lowering of the IFT. RBA testing of asphaltine-rich heavy oils has shown that a mixture of CO2/CO dissolves into the oil at a far faster rate than either CO2 or CO individually and faster than the sum of both individual gases. A similar test using non-asphaltine type oils did not display this unique characteristic. Slim tube testing suggests that CO facilitates the mobilization of asphaltine-rich heavy oils and lowers viscosity. A linear corefloods of a reservoir containing 5% smectite + illite/smectite + and chlorite demonstrated a 275% increase in matrix permeability. Packed column tests, containing quartz sand and bentonite, demonstrated up to 300-900% increase in permeability in the presence of CO.
Thus a method to recover oil faster, from stranded reservoirs, at pressures below MMP, using significantly less gas, appears possible. In addition the use of CO, either alone or in combination with CO2 and/or N2, has been shown to increase matrix permeability. Such a gas mixture may be beneficial to achieving low pressure EOR from shallow, "stranded" reservoirs, non-conventional shale oil reservoirs, and viscous, heavy oil reservoirs at low temperatures. Incorporation of CO, or CO2/CO, in a frac fluid, or alternately as a post frac cleanup for shale oil and gas applications appears to warrant investigation.
Suarez, Ricardo G. Suarez (SPE University of Calgary) | Scott, Carlos E. (SPE University of Calgary) | Pereira-Almao, Pedro (SPE University of Calgary) | Hejazi, S. Hossein (SPE University of Calgary)
Nanocatalytic in-situ upgrading is a novel oil recovery method that involves chemical, thermal and miscible processes. In this work the main oil recovery mechanisms of nanocatalytic in-situ upgrading were studied, particularly the ones that promote additional oil production from low matrix permeability blocks.
Heavy oil recovery from Silurian dolomite cores was studied using a cylindrical core holder set-up. Fractures in the system were represented by a gap between the core sample and core holder wall. Oil recovery experiments were conducted in batch-mode using hydrogen and a trimetallic nano-catalyst. The cores were fully saturated with heavy-oil and the fractures were filled with hydrogen and vacuum residue with ultra-dispersed nano-catalyst at 300 °C and 1000 psig. The produced oil from the matrix was collected and the recovery factor for each experiment was calculated. Moreover, the residual oil in the core was extracted using a solvent. Both samples (i.e., produced and residual oil) were characterised by laboratory measurements and analytical techniques in order to assess oil quality distribution.
Experimental results revealed a significant increment in oil recovery with hydrogen injection. This increment suggests that during nanocatalytic in-situ upgrading oil is produced due to the presence of hydrogen in gas form. Results also demonstrated that, by use of an ultra-dispersed Ni-W-Mo nano-catalyst, the oils contained in both the fracture and matrix, were upgraded.
This research fosters the understanding of the main recovery mechanisms from carbonate matrix blocks by use of nanocatalytic in-situ upgrading. This study contributes to better understanding a recovery technique that will unlock heavy-oil resources contained in carbonate rocks.
Polymer transport and preparation can present a key challenge in chemical EOR project implementation.
Hydrolyzed polyacrylamide in emulsion form presents some advantages, including an easier transportation and a simplification of the injection process. The trade off is a lower active concentration (~30% - 50%), which increases the volumes to be transported, as well as the presence of oil and emulsifiers, which may have unintended effects in the reservoir.
In this article, we compare two industrial and commercially-available polymers, one in powder form from the gel process, and the other in an inverse emulsion, with similar viscosifying power.
Properties of both polymers are investigated through rheological and screen factor measurements, filterability tests on bulk solutions, shear thickening behavior and resistance to shear degradation in porous medium. The likely origin of the observed differences is discussed in light of the two polymerization methods (bulk vs. emulsion) that lead to differences in polydispersity. Mobility reduction and residual resistance factor measurements during propagation tests at low velocity give some insight on the propagation of the stabilized oil droplets coming from the injected emulsion. Finally, oil recovery efficiency is investigated through secondary polymer injections on sandpacks. No significant difference was observed between the polymers in term of oil recovery or pressure behavior.
These results are relevant to oil companies planning polymer or surfactant-polymer pilots and considering the tradeoffs between emulsion and powder polymers.
Alexis, Dennis (Chevron Energy Technology Company) | Varadarajan, Dwarakanath (Chevron Energy Technology Company) | Kim, Do Hoon (Chevron Energy Technology Company) | Winslow, Greg (Chevron Energy Technology Company) | Malik, Taimur (Chevron Energy Technology Company)
Performance of current synthetic EOR polymers is primarily constrained by salinity, temperature and shear which restrict their application to low to moderate salinity, low to moderate temperature and relatively high permeability reservoirs. The primary goal of the current work is to qualify recently developed associative polymers (AP) for EOR applications as well as to study their behavior in porous media. We also compare their performance with conventional non-associative polymers. In this work, we present the evaluation of several associative polymers. Two broad types of associative polymers were tested, one with a partially hydrolyzed poly acrylamide (HPAM) backbone and the other with a sulfonated HPAM backbone. The concentrations of the tested polymer vary between 75 ppm and 1000 ppm. We demonstrate the applicability of these innovative AP's through the carefully controlled lab experiments: (1) Corefloods in sandpacks to compare the sweep behaviors with conventional HPAM's. (2) Single phase flooding experiments are carried out in consolidated outcrop rocks to identify optimal polymer concentrations to achieve the desired in-situ resistance. (3) One dimensional displacement experiments with 8 cP and 90 cP oil are carried out in both unconsolidated and consolidated rocks at different temperatures to validate improved oil recovery. Results generally indicate that associative polymers require lower polymer concentration to generate high resistance factors in porous media and have stable long term injectivity behavior in high permeability rocks (>1D). Associative polymers with HPAM backbone have better filterability and injectivity in comparison to those with HPAM sulfonated backbone in low permeability(<300mD) rocks. Improved oil recovery in high permeability rocks compare well with conventional HPAM and sulfonated HPAM polymers. Based on the laboratory results, we are able to establish the selection baseline for associative polymers in different permeability rocks, salinities and temperatures. Such information can be used to select and screen the appropriate associative polymers, resulting in extending their applicability envelope in EOR.