Mukherjee, Biplab (The Dow Chemical Company) | Patil, Pramod D. (The Dow Chemical Company) | Gao, Michael (The Dow Chemical Company) | Miao, Wenke (The Dow Chemical Company) | Potisek, Stephanie (The Dow Chemical Company) | Rozowski, Pete (The Dow Chemical Company)
Steam injection is a widespread thermal enhanced oil recovery (EOR) method to increase oil mobility. The introduction of steam heats the reservoir, ultimately lowering oil viscosity and in turn enhancing heavy oil recovery. In the steam injection process, recovery of oil is limited by steam channeling due to reservoir heterogeneities. Early breakthrough implies that there is a large consumption of steam and incomplete reservoir drainage. Injection of surfactant with steam and a non-condensable gas such as nitrogen can generate foam
In this paper, a systematic approach to screen surfactants for field applications at high temperature is presented. A feasibility test was conducted with the surfactant formulation (HSF-X) at target reservoir conditions to understand the thermal stability and adsorption behavior of the surfactant. Investigation found that the thermal decomposition and adsorption of the surfactant on sandstone rock under static conditions was mimimum at 200°C. In core flood testing conducted using silica sand and natural sandstone cores, foam generated by injecting N2 and HSF-X surfactant solution was able reduce steam mobility between 40 to 100 times at 100°C and 10 to 15 times at 200°C more compared to steam mobility in the absence of the foam. Finally oil recovery experiments at 200°C using silica sand cores indicated the ability of the HSF-X surfactant to foam in the presence of oil and enhance recovery of oil (a +20% increase in the original oil in place (OOIP) was observed).
Recent studies have shown that enhanced oil recovery will be the focal point for approximately 50% of the global oil production in the upcoming two-three decades. According to the several ballpark studies conducted on EOR techniques, results show that for reservoirs with oil viscosities ranging from 10 to 150 m Pa.s., polymer flooding seems to be an ideal development strategy. However, when the oil viscosities exceed 150 m Pa.s., polymer injectivity and pumping efficiencies can turn out to be major inhibiting factors, thereby limiting the range of oil viscosities for which polymer flooding can be utilized. The core reason for this is that the values of viscosity for the injected water containing polymer, calculated for the beneficial mobility ratio, can lead to the inhibiting factor stated above.
Previously conducted lab studies have shown that supramolecular systems are very resistant in high temperature - high salinity systems. To be able to achieve the easier injection, the injected supramolecular viscosity will be kept at lower values and then increased to the levels right before or upon contacting the oil in the reservoir.
The core difference between conventional polymer systems and supramolecular polymer systems is that the latter disassemble and re-assemble as opposed to degradation when exposed to extreme shear stress and temperatures. It can therefore be said that supramolecular polymer systems are self-healing in nature. The phenomenon has been observed in cases where polymers with high molecular weight are forced through narrow flow channels. Though molecular division takes place, supramolecular systems have shown a tendency of reassembly later on. Therefore, adaptability of these systems to bounded or restricted environments can be established.
This study will add the modeling and simulation components of supramolecular systems which can be effectively utilized in high temperature-high salinity conditions through adjustments to viscosities and interfacial properties of these assemblies. This will help compare the displacement efficiency of supramolecular systems which efficiently perform in a wide range of reservoirs such as thin zones, and reservoirs within permafrost conditions. This can significantly benefit the oil and gas companies worldwide in preparing a technically feasible, but also, a cost effective EOR development strategy, whenever polymer injection is of consideration.
The ASP process may still be promising for surfactant flooding of shaley formations that have high surfactant adsorption with conventional surfactant-polymer flooding. Positive sites on clays are sites where anionic surfactant adsorption occurs in conventional surfactant flooding. High pH of alkali converts positive clay sites to negative sites. In addition, sodium carbonate sequesters calcium ions due to the small solubility product of calcium carbonate. If the formation has pyrite or siderite present, the core material in the laboratory environment will likely have a coating of ferric oxide that contributes to the anionic surfactant adsorption sites. Thus the test core should be restored to reducing conditions to better represent in situ conditions.
The ASP process has two sources of surface active materials. One is injected synthetic surfactant and the other is soap generated in-situ by reaction of alkali with naphthenic acids in crude oil. However, this adds to the complexity of the process because the optimal salinity becomes a function of both the concentration of injected surfactant and in-situ generated soap. Water soluble active soap number (WSASN) is used instead of total acid number (TAN) to estimate the optimal salinity. When WSASN rather than TAN is used to estimate the soap content, the logarithm of the optimal salinity is a linear function of the soap fraction. In this presentation, we demonstrate the technology to estimate the optimal salinity of soap/surfactant mixtures and use it to develop formulations with great potential to recover oil for a weakly consolidated sandstone reservoir.
The potential of incremental oil recovery by the ASP formulation is evaluated by ASP flooding tests on both quartz sand packs and formation material. The ASP formulation recovered more than 95% of the water flooded residual oil using a 0.5 PV slug of either 0.3% or 0.5% NI blend surfactant. The sodium carbonate concentration was 1.0% and the polymer concentration was 0.3%. Moreover, it is found from simulation results that the development of soap/surfactant gradient in ASP flooding ensures the process passing through the optimal condition, where minimum IFT and low residual oil saturation will be attained.
The objective of this research was to develop a surfactant formulation for EOR in an oil-wet, high-salinity, fractured dolomite reservoir at ~100°C. A key requirement was achievement of interfacial tension (IFT) sufficiently low to spontaneously displace oil from the matrix by buoyancy. The formulation developed to do so was a blend of lauryl betaine and C15-18 internal olefin sulfonate, supplemented by a smaller amount of i-C13 ethoxylated carboxylate, all thermally stable and commercially available surfactants although the carboxylate not in quantities required for largescale EOR processes. Proportions of the three surfactants for injection in hard sea water were selected using equilibrium phase behavior results and estimates of IFT obtained by a novel technique based on the manner in which oil exits a small, vertically-oriented, rectangular oil-wet capillary cell as it is displaced upward in the cell by surfactant solution. The ability to recover oil from an oil-wet dolomite core was confirmed by an Amott imbibition cell experiment in which 50% recovery was observed for a core initially fully saturated with oil. The formulation's ability to generate strong foam in porous media was presented earlier in SPE-181732-MS. Research at Rice for three additional projects having carbonate reservoirs but different crude oils, brines, and temperatures of at least 60°C demonstrated formulation versatility by showing good oil recovery by core floods with modestly adjusted proportions of the same three surfactants (SPE-184569-MS, 2017; SPE-190259-MS 2018, US Patent 9,856,412). In the first two of these cited studies, the foamed formulation was injected to recover crude oils from a novel model fracture-matrix system.
This paper describes a new chemical EOR numerical model capable of simulating surfactant and polymer floods. We present the highlights of a highly efficient and robust IMPES implementation within a legacy, in-house gas-oil-water compositional simulator. The additional computational overhead, over say a waterflood calculation, is on the order of only 20% for large scale (type pattern model) simulations. We present performance results both in serial as well as parallel (multi-processor) mode.
Flow within all three Winsor Type environments is modeled, with the ability to transition between the different types. The effects of a separate microemulsion (ME) phase are accounted for. Temperature effects on surfactant phase behavior as well as on adsorption are also considered. Other important physical effects that are modeled include phase trapping and oil bypassed by surfactant, near wellbore polymer injectivity and the reduction of surfactant adsorption associated with a sacrificial agent such as alkali. Gas phase is included in the model.
The model has been extensively benchmarked against another reservoir simulator. We also present some validation results at the laboratory as well as at the field scale.
After 6 years of continous polymer injection in El Corcobo Norte field, pilot's preliminar evaluation showed promising results. Although the evaluation is still ongoing, polymer technology economics look good enough to sustain a project expansion.
Located in the Neuquén Basin, El Corcobo Norte field is an unconsolidated, underpressurized, strongly water-wet sandstone reservoir, producing medium-heavy oil from the Centenario Formation. Reservoir drive is waterflood, which has been implemented since the beginning of the field's development. Up to date the field has more than 650 producers and 350 injectors, mostly developed under 20 acres, inverted 7-spot patterns. Main challenge for this field's operation is sand production and chanelling issues that leave bypassed or undrained oil zones.
Since 2008 EOR technologies were evaluated in order to increase ultimate recovery factor. As a results of this screening, polymer injection was chosen as the first candidate to test in the field. Polymer pilot design and execution was described in SPE 160078 ("Desing and Execution of a Polymer Injection Pilot in Argentina") and pilot preliminar evaluation was presented in SPE 181210 ("Evaluation of a Polymer Injection Pilot in Argentina").
Based on the pilot's learnings, an expansion project was designed to maximize the use of the available capacity and upscale polymer injection as efficiently as possible, considering field's current operational conditions.
The present article will focus on describing the upscale of the polymer pilot and the strategy to optimize the project's operation.
Alfarge, Dheiaa (Iraqi Ministry of Oil, Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
In shale oil reservoirs, Improved Oil Recovery (IOR) methods are relatively considered as new concepts compared with in conventional oil reservoirs. Different IOR techniques have been investigated by using lab experiments, numerical simulation studies, and limited pilot tests. Unconventional IOR methods include injecting CO2, surfactant, natural gas, and water. However, CO2 injection is the most investigated option due to different reasons. CO2 has lower miscibility pressure with shale oils, and has special properties in its supercritical conditions, and CO2 injection also solves greenhouse problems. In this paper, numerical simulation methods of compositional models were incorporated with LS-LR-DK (logarithmically spaced, locally refined, and dual permeability) reservoir models and Local Grids Refinement (LGR) of hydraulic fractures conditions to investigate the feasibility of CO2 injection in shale oil reservoirs. Different mechanisms for CO2 interactions with organic surface, shale brine, and shale oil were implemented in different scenarios of numerical models. Molecular diffusion mechanisms, adsorption effects, and aqueous solubility effects were simulated in this study. In addition, linear elastic models and stress-dependent correlations were used to consider geomechanics coupling effects on production and injection processes of CO2-EOR in shale oil reservoirs. Some of the results for this simulation study were validated by matching the performance of some CO2 fields’ pilots performed in Bakken formation, in North Dakota and Montana portions.
This study extremely found that some of the CO2-EOR pilot tests have a match with the typical simulated diagnostic plots which have CO2 molecular-diffusion rate that is significantly low. Furthermore, this research indicated that CO2 molecular diffusion mechanism has a clearly positive effect on CO2-EOR in huff-n-puff protocol; however, this mechanism has a relatively negative effect on continuous flooding mode of CO2-EOR. Both of dissolution and adsorption mechanisms have a negative effect on CO2 performance in terms of enhancing oil recovery in unconventional formations. Geomechanics coupling has a clear effect on CO2-EOR performance, and different geomechanics models have a different validity in these shale plays. Stress dependent correlations give the best match with CO2-EOR pilots in Bakken formation while linear elastic models would give the best match in Eagle Ford formation. This study explains the effects of different nano and macro mechanisms on the performance of CO2-EOR in unconventional reservoirs since these plays are much complex and very different from conventional formations. Also, general guidelines have been provided in this study to enhance success of CO2-EOR in these types of reservoirs.
Kim, Ijung (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Worthen, Andrew J. (McKetta Department of Chemical Engineering, The University of Texas at Austin) | Lotfollahi, Mohammad (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Johnston, Keith P. (McKetta Department of Chemical Engineering, The University of Texas at Austin) | DiCarlo, David A. (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin) | Huh, Chun (Department of Petroleum and Geosystems Engineering, The University of Texas at Austin)
The immense nanotechnology advances in other industries provided opportunities to rapidly develop various applications of nanoparticles in the oil and gas industry. In particular, nanoparticle has shown its capability to improve the emulsion stability by generating so-called Pickering emulsion, which is expected to improve EOR processes with better conformance control. Recent studies showed a significant synergy between nanoparticles and very low concentration of surfactant, in generating highly stable emulsions. This study's focus is to exploit the synergy's benefit in employing such emulsions for improved mobility control, especially under high-salinity conditions.
Hydrophilic silica nanoparticles were employed to quantify the synergy of nanoparticle and surfactant in oil-in-brine emulsion formation. The nanoparticle and/or the selected surfactant in aqueous phase and decane were co-injected into a sandpack column to generate oil-in-brine emulsions. Four different surfactants (cationic, nonionic, zwitterionic, and anionic) were examined, and the emulsion stability was analyzed using microscope and rheometer.
Strong and stable emulsions were successfully generated in the combinations of either cationic or nonionic surfactant with nanoparticles, while the nanoparticles and the surfactant by themselves were unable to generate stable emulsions. The synergy was most significant with the cationic surfactant, while the anionic surfactant was least effective, indicating the electrostatic interactions with surfactant and liquid/liquid interface as a decisive factor. With the zwitterionic surfactant, the synergy effect was not as great as the cationic surfactant. The synergy was greater with the nonionic surfactant than the zwitterionic surfactant, implying that the surfactant adsorption at oil-brine interface can be increased by hydrogen bonding between surfactant and nanoparticle when the electrostatic repulsion is no longer effective.
In generating highly stable emulsions for improved control for adverse-mobility waterflooding in harsh-condition reservoirs, we show a procedure to find the optimum choice of surfactant and its concentration to effectively and efficiently generate the nanoparticle-stabilized emulsion exploiting their synergy. The findings in this study propose a way to maximize the beneficial use of nanoparticle-stabilized emulsions for EOR at minimum cost for nanoparticle and surfactant.
Post-fracturing production data analysis indicates stimulation of some west Texas wells with surfactant additives did not enhance production as high as expected. Analysis of flowback and produced water for surfactant residues revealed 99% of surfactant was retained inside wells (
Literature precedent exists that polyelectrolyte (PET)-based SAs could significantly reduce surfactant adsorption not only onto a variety of outcrop minerals (Carlpool dolomite, calcite, kaolinite, Berea sandstone, Indiana limestone, etc.) and metal oxide nanoparticles, but also unconventional shale formulations in which surface area can be up to 700 m2/g. In this study, the adsorptions of surfactant and SA to proppants were first examined. Results indicate no adsorption was observed to proppant for both surfactants and PET-based SAs. SAs (0.5 to 1 gal/1,000 gal (gpt)) were then injected with surfactant (1 to 3 gpt) at an appropriate ratio into column-packed shale formulations (primarily composed of calcite, dolomite, quartz, illite, pyrite, and plagioclase feldspar) to investigate its effectiveness in controlling surfactant retention caused by adsorption. Laboratory testing revealed injection of 3 gpt mixture of surfactant and SA has a similar adsorption profile (surface tension as a function of time) as 3 gpt surfactant alone based on the dynamic surface tension measurement. Notably, the addition of SAs resulted in lower surface tension and enhanced hydrocarbon solubility; and thus, an improved oil recovery by surfactant was achieved as evidenced by the oil recovery tests. Additionally, 68% friction reduction of the fracturing fluid with surfactant and SA was sufficient for the field operation compared to the guar-based fluid used in the hydraulic fracturing applications.
As a result of the laboratory findings, field trials were executed on a three well pad in the Permian basin (PB). For the first 30 days oil and gas production appeared to be significantly higher than the average production from offset wells in the same area that were previously fractured with the same surfactant.
An important factor during the life of a heavy crude reservoir is the oil mobility. It depends on two factors, oil viscosity and oil relative permeability. Two characteristics of nanoparticles that make them attractive for assisting IOR and EOR processes are their size (1 to 100 nm) and ability to manipulate their behavior. Due to their nano-sized structure, nanomaterials have large tunable specific surface areas that lead to an increase in the proportion of atoms on the surface of the particle, indicating an increasing in surface energy. Nanoparticles are also able to flow through typical reservoir pore spaces with sizes at or below 1 micron without the risk to block the pore space. Nanofluids or "smart fluids" can be designed by tuning nanoparticle properties, and are prepared by adding small concentrations of nanoparticles to a liquid phase in order to enhance or improve some of the fluid properties. However the use of nanoparticles and nanofluids for oil mobility has been poorly studied. Hence, the scope of this work is to present the field evaluation of nanofluids for improving oil mobility and mitigate alteration of wettability in two Colombian heavy oil fields; Castilla and Chichimene. Asphaltenes sorption tests with two different types of nanomaterials were performed for selecting the best nanoparticle for each type of oil. An oil based nanofluid (OBN) containing these nanoparticles was evaluated as viscosity reducer under static conditions. Displacement tests through a porous media in core plugs from Castilla and Chichimene at reservoir conditions were also performed. OBN was evaluated to reduce oil viscosity varying oil temperature and water content. Maximum change in oil viscosity is achieved at 122°F and 2% of nanofluid dosage. The use of the nanofluid increased oil recovery in the core flooding tests, caused by the removal of asphaltenes from the aggregation system, reduction of oil viscosity, and the effective restoration of original core wettability. Two field trials were performed in Castilla (CNA and CNB wells), by forcing 200 bbl and 150 bbl of nanofluid respectively as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 270 bopd in CNA and 280 bopd in CNB and BSW reductions of ~11% were observed. In Chichimene also two trials were performed (CHA and CHB), by forcing 86 bbl of and 107 bbl of nanofluid as main treatment within a radius of penetration of ~3 ft. Instantaneous oil rate increases of 310 bopd in CHA and 87 bopd in CHB were achieved not BSW reduction has been observed yet. Interventions were performed few months ago and long term effects are still under evaluation. Results look promising making possible to think extending application of nanofluid in other wells in these fields.