Although geochemical reactions are the fundamental basis of the alkaline/surfactant/polymer (ASP) flooding, their importance is commonly overlooked and not fully assessed. Common assumptions made when modeling geochemical reactions in ASP floods include: 1) ideal solution (i.e., using molalities rather than ion activities) for the water and aqueous geochemical species 2) limiting the number of reactions (i.e., oil/alkali and alkali consumptions) rather than including the entire thermodynamically-equilibrated system 3) ignoring the effect of temperature and pressure on reactions 4) local equilibrium ignoring the kinetics. To the best of our knowledge, the significance of these assumptions has never been discussed in the literature. In this paper we investigate the importance of geochemical reactions during alkaline/surfactant/polymer floods using a comprehensive tool in the sense of surfactant/soap phase behavior as well as geochemistry.
We coupled the United States Geological Survey (USGS) state-of-the-art geochemical tool, with 3D flow and transport chemical flooding module of UTCHEM. This geochemical module includes several thermodynamic databases with various geochemical reactions, such as ion speciation by applying several ion-association aqueous models, mineral, solid-solution, surface-complexation, and ion-exchange reaction. It has capabilities of saturation index calculation, reversible and irreversible reactions, kinetic reaction, mixing solutions, inverse modeling and includes impacts of temperature and pressure on reaction constants and solubility products. The chemical flood simulator has a three phase (water, oil, microemulsion) phase behavior package for the mixture of surfactant/soap, oil, and water as a function of surfactant/soap, salinity, temperature, and co-solvent concentration. Hence, the coupled software package provides a comprehensive tool to assess the significance of geochemical assumptions typically imposed in modeling ASP floods. Moreover, this integrated tool enables modeling of variations in mineralogy present in reservoir rocks. We parallelized the geochemistry module of this coupled simulator for large-scale reservoir simulations.
Our simulation results show that the assumption of ideal solution overestimates ASP oil recovery. Assuming only a subset of reactions for a coupled system is not recommended, particularly when a large number of geochemical species is involved, as is the case in realistic applications of ASP. Reservoir pressure has a negligible effect but temperature has a significant impact on geochemical calculations. Although mineral reaction kinetics is largely a function of the temperature and in-situ water composition, some general conclusions can be drawn as follows: to a good approximation, minerals with slow rate kinetic reaction (e.g., quartz) can be excluded when modeling ASP laboratory floods. However, minerals with fast rate kinetic reactions (e.g., calcite) must be included when modeling lab results. On the other hand, in modeling field-scale applications, local equilibrium assumption (LEA) can be applied for fast rate kinetic minerals, whereas kinetics should be used for slow rate kinetic minerals.
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.
Preliminary studies have been done to characterize rock-fluid properties, and flow mechanisms in the shale reservoirs. Most of these studies, through modifying methods used for conventional reservoirs, fail to capture dynamic features of shale rock and fluids in confined nano-pore space. In unconventional reservoirs, interactions between the wall of shale and the contained fluid significantly affect phase and flow behaviors. The inability to model capillarity with the consideration of pore size distribution characteristics using commercial software may lead to an inaccurate oil production performance in Bakken. This paper presents a novel formulation that consistently evaluates capillary force and adsorption using pore size distribution (PSD) directly from core measurements. The new findings could better address differences in flow mechanisms in unconventional reservoirs, and thus lead to an optimized IOR practice.
Wang, D. (University of North Dakota) | Dawson, M. (Statoil Gulf Services LLC) | Butler, R. (University of North Dakota) | Li, H. (Statoil Gulf Services LLC) | Zhang, J. (University of North Dakota) | Olatunji, K. (University of North Dakota)
With the recent dramatic drop in oil price, production from ultra-tight resources, like the Bakken formation, may drop substantially. Since expenditures for drilling, completion, and fracking have already been made, existing wells will continue to flow, but oil rates will decline—rapidly in many cases. In a low oil-price environment, what can be done to sustain oil production from these tight formations?
We are testing a surfactant imbibition process to recovery oil from shales. We measured surfactant imbibition rates and oil recovery values in laboratory cores from the Bakken shale. After optimizing surfactant formulations at reservoir conditions, we observed oil recovery values up to 10–20% OOIP incremental over brine imbibition. However, whether or not surfactant imbibition will be a viable recovery process depends on achieving sufficiently high oil production rates in a field setting—which requires that we identify conditions that will maximize imbibition rate, as well as total oil recovery. In this paper, we describe laboratory evaluations of oil recovery using different core plugs. These recovery studies involved
(1) surfactant formulation optimization on concentration, salinity and pH, (2) characterization of phase behavior, (3) spontaneous imbibition, and (4) forced imbibition (flooding) with gravity drainage assistance.
In preserved cores, we observed: (1) Formulations using 0.1% surfactant concentration at 4% TDS salinity showed favorable oil recoveries (up to 40% OOIP). (2) Generally, surfactant formulations at optimal concentration and salinity were stable at high temperature (115°C). (3) Injectivity/permeability enhancements up to 75 percent occurred after acidification using acetic acid or HCl. (4) Wettability alteration is the dominant mechanism for surfactant imbibition. Of course, actions that increase fracture width will aid gravity drainage and oil recovery. This information is being used to design and implement a field application of the surfactant imbibition process in an ultra-tight resource.
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.
Prieto, C. A. (CEPSA Research Center) | Rodriguez, R. (CEPSA Research Center) | Romero, P. (CEPSA Research Center) | Blin, N. (CEPSA Research Center) | Panadero, A. (CEPSA Research Center) | Escudero, M. J. (CEPSA Research Center) | Barrio, I. (CEPSA Research Center) | Alvarez, E. (CEPSA Research Center) | Montes, J. (CEPSA EP) | Angulo, R. | Cubillos, H.
The design of an alkali-surfactant-polymer (ASP) formulation for chemical Enhanced Oil Recovery poses multiple challenges from the experimental point of view. The present research examines the laboratory procedures and experimental results aimed at selecting the most suitable chemicals for an ASP pilot trial at the Caracara Sur field (Los Llanos Basin, Colombia). The key challenge was the limited compatibility of the surfactant and polymer selected under reservoir conditions (temperature and total salinity), leading to phase separation of the ASP solution and losses of the activity of both chemicals. An extension of the experimental program was required to re-design the formulation and mitigate risks of damaging the formation in the following field trials. The formulation comprised an alkyl benzene sulfonate as main ingredient, a hydrolyzed polyacrylamide as viscosifying agent and some weak alkali to reach the optimum salinity of the mixture. A mono-alkyl diphenyl disulfonate ether was added as coupling agent to improve compatibility of the ASP mixture. The performance of the selected ASP formulation was assessed by means of interfacial tension measurements, long-term thermal stability tests and dynamic core-flooding tests. The formulation provided ultra-low interfacial tension (< 10-2 mN/m) and viscosity enough to assure an appropriate mobility control. Hence, the formulation was considered to be suitable for further testing in the field pilot.
Fortenberry, R. (Ultimate EOR Services) | Delshad, M. (Ultimate EOR Services) | Suniga, P. (Ultimate EOR Services) | Koyassan Veedu, F. (DeGolyer & MacNaughton) | Wang, P. (DeGolyer & MacNaughton) | Al-Kaaoud, H. (Kuwait Oil Company) | Singh, B. B. (Kuwait Oil Company) | Tiwari, S. (Kuwait Oil Company) | Baroon, B. (Kuwait Oil Company) | Pope, G. A. (University of Texas at Austin)
Our team has developed a new simulation model for an upcoming 5-spot Alkaline-Surfactant-Polymer (ASP) pilot in the Sabriyah Mauddud reservoir in Kuwait. We present new pilot simulation results based on new data from pilot wells and an updated geocelluar reservoir model. New cores and well logs were used to update the geocellular model, including initial fluid distributions, permeability and layer flow allocation.
From the updated geocellular model a smaller dynamic sector model was extracted to history match field performance of a waterflood pattern. From the dynamic model a yet smaller pilot model was extracted and refined to simulate the 5-spot ASP pilot.
We used this pilot model to evaluate injection composition, zonal completions, observation well locations, interwell tracer test design and predicted performance of ASP flooding. A sensitivity analysis for some important design variables and pilot performance benchmarks is also included. We used multiple interwell tracer test simulations to estimate reservoir sweep efficiency for both water and ASP fluids, and to help us understand how well operations will affect this unconfined ASP pilot. This work details some crucial aspects of pre-ASP pilot design and implementation.
Okwen, Roland T. (Illinois State Geological Survey, Prairie Research Institute, University of Illinois at Urbana-Champaign) | Frailey, Scott M. (Illinois State Geological Survey, Prairie Research Institute, University of Illinois at Urbana-Champaign)
Historically, deep oil reservoirs with temperatures and pressures above the critical point of carbon dioxide (CO2) are generally preferred over shallower reservoirs in enhanced oil recovery (EOR) and CO2 storage operations because of high recovery and storage efficiencies associated with miscible floods. As a result, shallower reservoirs containing significant volumes of recoverable resource are generally overlooked. However, basins with relatively low geothermal gradients and high fracture gradients, such as the Illinois Basin, can sustain pressures above the vapor pressure of CO2 where CO2 changes from a gas to liquid. Liquid CO2 has fluid properties similar to that of supercritical CO2 and is more readily miscible with oil.
This study evaluates the EOR potential of low-temperature reservoirs based on the performance of a miscible liquid CO2 flood pilot at the Mumford Hills oil field in Posey County, Indiana. About 7,000 tons (6,350 tonnes) of CO2 were injected into a Mississippian sandstone reservoir over a period of 1 year to demonstrate miscible CO2 EOR in low-temperature oil reservoirs. The reservoir model was calibrated with available historical primary waterflood, and CO2 flood pilot data. The calibrated reservoir model was used to simulate different full-field CO2 EOR development scenarios. The projected oil recovery factors range between 10% and 14%, which compares well to the Permian Basin supercritical CO2 flood recovery range of 8% to 16%.
The oil recovery factors from the simulated scenarios suggest that liquid CO2 floods in low-temperature oil reservoirs can achieve an incremental oil recovery similar to deeper, supercritical CO2 floods. Re-evaluating previously overlooked shallow depleted reservoirs as potential candidates for liquid CO2 EOR provides the opportunity to increase the development of these shallow oil reservoirs available for miscible CO2 flooding
In the case of surfactant EOR, an optimum formulation of surfactant has to be injected in the reservoir. This so-called optimum formulation corresponds to a minimum in the interfacial tension and a maximum in oil recovery and may be obtained with an appropriate balance of the hydrophobic and hydrophilic affinities of the surfactant. Salinity—scan tests are generally used to screen phase behavior of surfactant formulations before conducting time-consuming coreflood tests. The objective of this study was to develop a high-throughput dynamic microfluidic tensiometer, with the aim of studying interfacial phenomena between EOR injected formulations and crude oils and of optimizing chemical EOR processes for pilot or field applications.
We have selected a method based on the Rayleigh-Plateau instability and the analysis of the droplets to jetting transition in a coaxial flow of two fluids. In fact, in coaxial flows, the transition between a droplet and a jetting regime depends on the velocities of each phase, the viscosity ratio, the confinement and the interfacial tension (IFT). As the three first parameters are known, the dynamic interfacial tension can be calculated. This microfluidic device has been specifically designed to support high temperatures (up to 150°C), high pressures (up to 150 bars) and is compatible with complex fluids such as crude oils and solutions of surfactants and polymers.
The method was first developed and validated on a microfluidic device on model fluids at ambient temperature and atmospheric pressure for IFTs higher than 1 mN/m. It was then successfully applied for the measurement of IFTs over more than four decades. Measurements were also performed with a crude oil and a typical surfactant formulation. The validation of the HP/HT assembly, which has been designed with the aim to work in reservoir conditions, is currently under progress. By using this tensiometer, it would be quite easy to perform in short time numerous salinity scans on real systems in order to get the evolution of IFT and determine the optimal salinity S*.
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.