Moreno Ortiz, Jaime Eduardo (Schlumberger) | Gossuin, Jean (Schlumberger) | Liu, Yunlong (Schlumberger) | Klemin, Denis (Schlumberger) | Gurpinar, Omer (Schlumberger) | Gheneim Herrera, Thaer (Schlumberger)
Challenges on EOR process upscaling have been discussed extensively in the industry and effects of diffusion, dispersion, heterogeneity, force balance and frontal velocity -among others, recognized and qualified, along with the importance of understanding the numerical model finite difference equations and modeling strategy. Augmenting the upscaling complexity is the often-limited understanding/data on the EOR displacement at different scales (from micro to full field), including the EOR agent/rock/fluid interactions that is often available at the early stages of the EOR process de-risking.
A common denominator for the EOR process characterization and upscaling (along with the discretization of the displacement) is the non-uniqueness nature of the problem. As the complexity of numerical representation of the EOR process increases (thus increasing data characterization requirements), so does the number of plausible solutions and challenges when dealing with an otherwise incomplete dataset. Digital rock has evolved as a strong alternative to complement laboratory corefloods, allowing for EOR agent optimization on a high-resolution digital representation of the pore structure, detailed digital fluid model of both reservoir fluids and EOR agents and physical rock-EOR agent-reservoir fluid interaction, thus providing several calibration points to ensure the finite-difference model calibration and upscaling preserve the process behavior.
This paper discusses the use of digital rock solutions on the EOR deployment, particularly on translating the results to numerical finite difference models, addressing the inherent laboratory measurement uncertainty and proposing a fit-for-purpose multi-scale upscaling strategy that addresses both effects of heterogeneity and EOR agent characterization during the upscale process.
This paper addresses the challenges of chemical flooding upscaling, particularly polymer by using a real-life polymer injection case where digital rock, corefloods and more importantly pilot results are available to test and validate our observations. Using a polymer coreflood and digital rock results as input, numerical finite difference simulation models were built and calibrated to effectively reproduce the displacement physics observed on both digital rock and corefloods, digital flood results were used to bridge the laboratory-to-numerical model step by providing effective upscaled polymer properties as well as intrinsic rock properties such as relative permeability and capillary pressures, which are then taken through a series of multi-scale finite difference models to identify, validate and quantify upscaling requirements, addressing polymer deformation through pore throats and effective simulation viscosity. Digital rock is used to rank and resolve ambiguity on the finite difference model calibration by providing an otherwise rare opportunity to visualize the displacement in the 3D space. The analysis shed a new light on fluid-fluid and fluid-rock interaction at pore scale and enabled us to improve on the finite difference model generation and polymer properties.
Hydraulic fracturing with slickwater is a common practice in developing unconventional resources in North America. The proppant placement in the fractures largely determines the productivity of the well as it affects the conductivity of fractures. Despite the wide use of the slickwater fracturing and the importance of the proppant placement, the proppant transport is still not fully understood and the efficiency of the proppant placement is mostly bound to the changes to proppant properties, friction reducers, and guar technology. Although the degradable fiber is currently used in some cases, it has not been well investigated. In this experimental study, we conducted proppant transport experiment using different fluid composition of fiber and guar gum in three types of proppant transport slot equipment. The results indicate that the use of degradable fibers with or without the guar gum as viscosifier can produce fracture slurry applicable in both conventional and unconventional fracturing helping proppant placement in the reservoir.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Noles, Jerry (Coil Chem LLC) | Kim, Sangjoon (Coil Chem LLC)
Viscoelastic property of high-viscosity friction reducers (HVFRs) was developed as an alternative fracturing fluid system because of advantages such as the ability to transport particles, higher fracture conductivity, and potential lower cost due to fewer chemicals and equipment on location. However, concerns remain about using HVFRs to transport proppant in DI water and harsh brine solution (e.g. 2wt% KCl and 10 lbs. brine). The primary objective of this study is to investigate the viscoelastic property that can help to understand the true proppant transporting capacity of fracturing fluids in high-TDS environment.
To address the evaluation performance of HVFRs, a comprehensive review of numerous papers associated to viscoelastic property of hydraulic fracturing fluids were investigated and summarized. This paper also provides a full comparison study of viscosity and elastic modulus between HVFRs and among fracturing fluids such as xanthan, polyacrylamide-based emulsion polymer, and guar. Moreover, viscosity profiles and elastic modulus were conducted at different temperatures. Better proppant transportation effect though higher viscosity through Stoke's law and the effect on proppant transportation from elastic modulus comparison were also investigated. Finally, HVFR Conductivity test and successful field test result were explained.
The results of the experimental work show that viscoelastic property HVFRs provides good behavior to transport proppant. Viscosity profile decreased slightly as the temperature increased from 75 to 150 when the DI water was used. While using 10 lbs. Brine the viscosity was reduced by 33%. The longer polymer chains of HVFR indicated better elastic modulus in DI water. The elastic modulus also indicated that the highest values at frequency 4.5 Hz from each amplitude, and lower values as amplitude was increased. Although high molecular weight HVFRs were utilized on the conductivity test, the results observed that the regained permeability was up to 110%. Finally, the promising results from the case study showed that using HVFRs could be performed economically and efficiently for the purpose of proppant transportation and pressure reduction in high TDS fluids.
Quintero, Harvey (ChemTerra Innovation) | Farion, Grant (Trican Well Service LTD.) | Gardener, David (ChemTerra Innovation) | O'Neil, Bill (ChemTerra Innovation) | Hawkes, Robert (Trican Well Service LTD.) | Wang, Chuan (ChemTerra Innovation) | Cisternas, Pablo (American Air Liquide) | Pruvot, Antoine (American Air Liquide) | McAndrew, James (American Air Liquide) | Tsuber, Leo (Badger Mining Corporation)
This study aims to demonstrate the true benefit of an innovative salt tolerant high viscosity friction reducer (HVFR) that excels at promoting extended proppant suspension and vertical distribution into the fracture when it is used as a base fluid for the Capillary Bridge Slurry (CBS) and other conventional fracturing fluid systems in combination with nitrogen.
The completion of super-lateral wells now being drilled in tight oil and gas shales in North America, with record lengths close to 4 miles, demand for greater carrying capability of low viscosity (slickwater) fracturing fluids, where significant sand settling can occur before the proppant even reaches the fractures. This has sparked recent interest in the development and application of salt tolerant polyacrylamide-based friction reducers, referred to as High Viscous Friction Reducers (HVFR). The downfall of these first generation HVFR's is the lack of compatibility with high salinity brines such as recycled and flowback water, and diminished ability to reduce friction pressure during hydraulic fracturing treatments when compared to industry standard FR's.
Herein, we report the field application of a unique salt tolerant HVFR (HVFR-ST), that consistently provides higher viscosity values (corresponding industry standard HVFR loading comparison) when tested in brines, without sacrificing friction reduction effectiveness. Additionally, a new concept of fracturing fluid referred to as Capillary Bridge Slurry (CBS) has been successfully implemented in North America, where through a surface modification to the proppant, the addition of a gas phase such as N2, and the use of a polyacrylamide-based friction reducer, the proppant becomes part of the fluid structure and is no longer the burden to be carried. The combination of HVFR's and the surface modified proppant can effectively combat the issues faced with proppant transport in long laterals.
This paper will highlight the results on the analysis of the governing proppant transport mechanisms (suspended and bed) of CBS system formulated with HVFR-ST, in the presence of nitrogen (N2), where no detrimental effect in the average distance traveled of the sand particle in the Proppant Transport Test Bench (PTTB) was observed when the brine concentration of the base fluid was increased from 1% to 5% in comparison to industry standard HVFR (HVFR-FW).
Field production data on wells stimulated with CBS show a significant upside (~ 50%) in liquid hydrocarbon production than offsetting wells over a ~ one year period of time.
Friction loop data carried out at 45 L/min (11.89 gals/min) flow rate in an internal diameter pipe of 0.305" shows a reduction on friction pressure in excess of 70%, when HVFR was tested in 5% API brine (4% (w/v) NaCl and 1% (w/v) CaCl2·2H2O) at loadings as low as 0.1%. Furthermore, dynamic measurements within the viscoelastic regime/behavior of the HVFR at different loadings in the oscillatory viscometer will provide learnings on the elasticity-proppant transport relationship of the different fracturing fluid systems.
Through the use of laboratory testing and field study cases, this paper will illustrate the true benefits on the use of salt tolerant HVFR's as a base fluid with the increasing demand of re-cycled and flowback water use in fracturing fluid systems.
As exploration for oil and gas continues, it becomes necessary to produce from deeper formations, have low permeability, and higher temperature. Unconventional shale formations utilize slickwater fracturing fluids due to the shale’s unique geomechanical properties. On the other hand, conventional formations require crosslinked fracturing fluids to properly enhance productivity.
Guar and its derivatives have a history of success in crosslinked hydraulic fracturing fluids. However, they require higher polymer loading to withstand higher temperature environments. This leads to an increase in mixing time and additive requirements. Most importantly, due to the high polymer loading, they do not break completely and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly.
In this work, a new hybrid dual polymer hydraulic fracturing fluid is developed. The fluid consists of a guar derivative and a polyacrylamide-based synthetic polymer. Compared to conventional fracturing fluids, this new system is easily hydrated, requires fewer additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings.
The polymer mixture solutions were prepared at a total polymer concentration of 20 to 40 lb/1,000 gal and at a volume ratio of 2:1, 1:1, and 1:2. The fluids were crosslinked with a metallic crosslinker and broken with an oxidizer at 300°F. Testing focused on crosslinker to polymer ratio analysis to effectively lower loading while maintaining sufficient performance to carry proppant at this temperature. HP/HT rheometer was used to measure viscosity, storage modulus, and fluid breaking performance. HP/HT aging cell and HP/HT see-through cell were utilized for proppant settling. FTIR, Cryo-SEM and HP/HT rheometer were also utilized to understand the interaction.
Results indicate that the dual polymer fracturing fluid is able to generate stable viscosity at 300°F and 100 s-1. Results show that the dual polymer fracturing fluid can generate higher viscosity compared to the individual polymer fracturing fluid. Also, properly understanding and tuning the crosslinker to polymer ratio generates excellent performance at 20 lb/1,000 gal. The two polymers form an improved crosslinking network that enhances proppant carrying properties. It also demonstrates a clean and controlled break performance with an oxidizer.
Extensive experiments were pursued to evaluate the new dual polymer system for the first time. This system exhibits a positive interaction between polysaccharide and polyacrylamide families and generates excellent rheological properties. The major benefit of using a mixed polymer system is to reduce polymer loading. Lower loading is highly desirable because it reduces material cost, eases field operation and potentially lowers damage to the fracture face, proppant pack, and formation.
Initial rate and decline are the two main parameters defining the economics of unconventional shale oil development. To improve economics, companies drill longer horizontal wells with more than twenty equidistant stages, different completion strategies and various additives such as surfactants and nano surfactants. This procedure evolves to factory mode in which tasks are optimized in timing and performance without attention to the matrix aspects of improving the recovery. Here, we report the design of a mutual solvent injection pilot in the Vaca Muerta unconventional reservoir during the completion of four unconventional shale oil wells. Reducing
Vaca Muerta has been long regarded as a water wet shale because of the limited water backflow post-fracking job. Alternating water injection was implementing assuming that the well productivity is driven by spontaneous imbibition, but this strategy has been unsuccessful as capillary pressure hysteresis drives this mechanism. We started studying Vaca Muerta from the rock microstructure using energy-dispersive spectrometry and focused gallium Ion Beam ablation FIB SEM images. The microstructure varied widely from millimeters in the same plug which could be expected because in shale rocks millimeters represent more years of deposition than in a conventional reservoir. We identified intercalations of massive water wet zones and strongly oil wet zones in the Vaca Muerta kitchen zone. The oil wet intercalations have high porosity and adsorption isotherm indicating 100 to 1000 times more permeability than the water wet zone. The water wet intercalations are highly saturated with water, and on the contrary, the oil wet intercalations are highly saturated with oil. The pilot designed consisted of four wells in which we will test different injection concentrations but keeping the total mass constant. In this manner, we will estimate the volume contacted by the solvent.
The laboratory protocol indicates a large percentage of macro and meso-pores. We implemented the dimethyl-ether injection which changes the interfacial tension, viscosity and wettability and we obtained the modified relative permeabilities which were the injection of dimethyl ether at 30% concentration along with the hydraulic fracture stimulation stages doubled the initial oil production rate.
The pilot consisted of five wells in which we will test different injection concentrations but keeping the total mass constant. In this manner, using the numerical simulation, we will estimate the volume contacted by the solvent.
Intercalations of high porosity high permeabilities zones in which the injection of a mutual solvent that reduces viscosity and could change wettability in oil wet/water-wet Vaca Muerta improving matrix connectivity.
In preparation for a field pilot of cyclic solvent injection (CSI) on two depleted cold heavy oil production with sand (CHOPS) wells, a series of oilsands coreflood experiments were conducted to evaluate the effectiveness of various commercially available solvents and make a solvent recommendation for the pilot. Oil recovery and solvent recovery were the key performance indicators used to compare CSI effectiveness of each solvent blend. The operating pressure for each test was kept relatively constant for each solvent blend tested. Tested solvents included blends of methane/propane, carbon dioxide/propane, methane/ethane, 100% ethane, and nitrogen. Sensitivities for depletion rate and blowdown pressure are also presented. Overall the 100% ethane test performed the best with the highest oil recovery and solvent recovery in the fewest cycles. Due to the lack of commercial ethane supply and the industry experience with methane/propane in Husky Edam’s CSI pilot, a methane/propane blend was recommended for the field pilot in Manatokan East near Bonnyville Alberta Canada.
This study will demonstrate a comparison of completion fluid designs in operations and production across several pads in Gonzales and Lavaca counties in the Eagle Ford Basin. The use of tunable friction reducers (FRs) significantly improves completion efficiency and production. The paper also illustrates how tunable FRs provide greater versatility at the wellhead by replacing multiple fracturing fluid systems such as conventional friction reducer and linear gel with a single additive.
When conventional FRs prove inadequate in slickwater designs, subsequent HVFR and linear gel designs are utilized. This study demonstrates that tunable FRs provide the flexibility to be run at lower concentrations as an effective and efficient friction reducer. Should the slickwater treatment be insufficient, the FR concentration can easily be increased to achieve improved results for pressure reduction and sand placement while minimizing chemical additives and equipment on location. In addition, this tunable FR is engineered with breakable linkages that minimize formation damage to help improving production.
Tunable FRs can be run at less concentration compared to conventional FRs while delivering the same friction reduction as slickwater. Increasing the concentration produces a higher viscosity similar to that seen in linear gel. This flexibility is achieved with less equipment and additives and can be executed on- the-fly while pumping. This design has enabled an operator in the Eagle Ford to complete more stages with less shutdowns and screenouts. Eliminating equipment and extra additives simiplified logistics, reduced the footprint and equipment-related non-produtive time (NPT). Overall, production results taken over the first 12 months show that wells completed with the tunable FR had noticeably superior performance in cumulative production, which is normalized by lateral length. These improvements can be attributed to the proppant transport capabilities and the breakability of the tunable FR, which minimizes residue left in the formation and, in turn, provides greater regain conductivity.
Additional benefits include simplified delivery and smaller jobsite footprint requirements, which lead to significant cost savings. The tunability of the FR allows it to be administered on the fly while pumping, giving design change flexibility, enhancing overall operational efficiency. Since there is no need of hydration unit or dry-on-the-fly (DOTF) unit used for hybrid linear gel design, fewer NPT hours due to equipment breakdown was seen on location.
Ghosh, Pinaki (The University of Texas at Austin) | Zepeda, Angel (The University of Texas at Austin) | Bernal, Gildardo (The University of Texas at Austin) | Mohanty, Kishore (The University of Texas at Austin)
Waterflood in low permeability carbonate reservoirs (<50 mD) leaves behind a substantial amount of oil due to capillary trapping and poor sweep. Addition of polymer to the injected water increases the viscosity of the aqueous phase and decreases the mobility ratio, thus, improving the sweep efficiency and oil production from the tight formations. Performance of current synthetic EOR polymers is limited by salinity, temperature and injectivity issues in low permeability formations. Mechanical shear degradation can be applied to high molecular weight synthetic polymers to improve the injectivitiy; but makes the process less economical due to significant viscosity loss and consequent increase in polymer dosage. Recently, a different class of polymer has been developed called "hydrophobically modified associative polymers (AP)". The primary goal of this work is to investigate the performance of associative polymers in low permeability carbonate reservoirs. We compare the performance of associative polymers with that of conventional HPAM polymers in low permeability formations. A low molecular weight associative polymer was investigated as part of this study. A detailed study of polymer rheology and the effect of salinity at the reservoir temperature (60 °C) was performed. Additional experiments were performed in bulk and porous media to investigate the synergy of associative polymers with hydrophilic surfactant blends at different brine salinities. Single phase polymer flow experiments were performed in outcrop Edwards Yellow and Indiana limestone cores of low permeability to determine the optimum polymer concentration to achieve the desired in-situ resistance factor (or apparent viscosity). Similar experiments were performed with HPAM polymer for a comparative study. Results showed successful transport of this associative polymer in low permeability formations after a small degree of shear degradation. The resistance factors for the associative polymer were higher than those for HPAM. Shear degraded polymers showed significant improvement in polymer transport in lower permeability cores with reduction in RRF.
Wax and paraffin precipitation is a major problem around the world, costing the petroleum industry billions of dollars yearly. As temperature drops below the Wax Appearance or Wax Precipitation Temperature (WAT/WPT) of crudes, paraffin starts to precipitate out and restrict or block the effective flow. There are different methods, such as mechanical and chemical remediation to deal with wax issues. Among the latter ones, the use of surfactants is favorably looked upon since they are small molecules with surface activity properties. This study aims to introduce novel aliphatic non-ionic surfactants with different chain length and degree of ethoxylation. In addition to chain length, the impact of branching on the hydrophobic part of the surfactants was also studied.
A waxy crude oil from Brazil was characterized through determining its carbon distribution, WAT, viscosity and density based on industry standard methods. Several surfactants with different combinations of chain length/ethoxylation number were then selected for screening. The performance of surfactants was evaluated based on data obtained from treated crude versus the control sample through different experiments. Rheology studies were conducted at 50 to -10°C and at shear rates of 5 and 300 s-1. The cold finger instrument was utilized to determine paraffin content of the untreated and treated crude. Finally, the paraffin crystal size was analyzed through microscopic studies.
The results showed that shear rate can affect the wax treatment outcome as well as the effective concentration of surfactant. Therefore, it is important to assess the rheology at high and low shear rates. Some surfactants in the present study performed great at both low and high shear rates and were able to reduce the viscosity by 80% at temperatures well below WAT of the crude oil. The microscopy results confirmed that wax crystals were reduced in size and were more dispersed after treating the crude with these surfactants. The findings from High Temperature Gas Chromatography showed that the deposition of heavy fraction part of crude (C40+) is reduced after treating the crude oil with the surfactants in the present study.
The current study addresses the wax precipitation/deposition challenges of heavy crudes and proposes mitigating them through the use of some new non-aromatic non-ionic surfactants. The chemistries and findings of this research help the oil and gas industry to save money and time by mitigating flow assurance problems.