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Abstract In the past, high-viscosity fluids have been the preferred method for increased proppant suspension and transport. This methodology has been effective using systems such as borate-crosslinked fluid with the downside of considerable damage to the proppant pack, typically resulting in about 85% percent regain conductivity. While this may still be acceptable, the major limitation of these systems is the additional loss of needed fracture length. Often, with low viscosity fluids such as linear gels and friction reducers, fracture length may be established allowing breaks into the secondary fractures and mechanical reactivation of the pre-existing natural fracture network may be enhanced. However, these low viscosity fluids cannot offer efficient suspending characteristics within the fracture under static conditions, which may lead to early settling. As a response to this industry demand, a novel fluid has been developed to optimize the hydraulic fracturing process by enhancing proppant transport with reduced friction losses, less fresh water requirements and smaller footprint of pressure pumping equipment. Novel fluid technology from which the polymer was engineered to form a network of packed structures from polymer associations providing the maximum proppant suspension, breaking with the traditional concept relying on viscosity to enhance proppant transport during treatments, is described with extensive experimental testing. The results show that the fluid exhibits outstanding properties and benefits to transport proppant without settling in addition to a considerable reduction in fresh water requirements and maintenance costs associated with surface equipment footprint, as the current trend is unsustainable. New physics consisting of a hybrid rheology analytical model and fluid structures to correlate elastic fluids rheology parameters, firstly, n′ and k′ values, and secondly the storage, and loss moduli profile (G′ and G″ accordingly), is presented. The complex fluid behavior deviates from common rheology models and, its elastic properties, such as storage modulus (G′), loss modulus (G″), and angular frequency (rad-sec) are discussed in the context of the unique fluid characteristics of a network of packed structures from polymer associations. Physics-based analytical model results compute the viscosity, and elastic parameters based on shear rate to calculate the pressure losses along the flow path from surface lines, tubular goods, perforations, and fracture, optimizing horse power requirements based on reduced pressure loses, will be presented [16]. The presentation will demonstrate that such physics and unique fluid behavior are achieved via a novel elastic and a network of packed structures from accociative polymer fluid, having proper proppant suspension, effectively placed at low viscosity, less fresh water requirement, low injection pressures, with no settling and 98% retained conductivities.
Abstract Hydraulic fracturing has always been associated with significant volumes of fracturing fluid invading the formation matrix, which leads to water blockage and a reduction in relative permeability to gas or oil. In Shale and tight formations, this has become more challenging since capillary forces have profound impact on water retention and hence, water recovery and subsequent oil productivity. Surfactants and microemulsions have been extensively reported as flowback additives to lower surface and interfacial tension to maximize water recovery. Most of the previous studies focused on a few testing methods to validate a surfactant or a microemulsion formulation for flowback use. In this work, a new environmentally friendly water-based surfactant formulation (Surf-I) was evaluated for flowback and its performance was compared against several industry standards of microemulsions and non-ionic alcohol ethoxylated surfactant. Surface tension (ST), interfacial tension (IFT), contact angle (CA), and coreflood tests were conducted in a wide range of typical field conditions of water salinity, temperature, crude oil type, and surfactant concentration. Core flow testing on 0.1-0.3 md Kentucky sandstone was conducted simulating oil reservoirs following constant-pressure flow schemes of 50-500 psi. Water recovery and oil productivity were determined for each pressure stage. The new formulation showed a surface tension of 26 mN/m with CMC corresponding to a load of 0.1-0.3 gpt, depending on the water salinity. Interfacial tension measurements varied from 0.17 mN/m to 10 mN/m, depending on the crude oil type and temperature. Contact angle measurements indicated the surfactant ability to water-wet controlled substrates. The coreflood results confirmed the benefit of using surfactants for flowback versus non-surfactant cases, especially at low- to mid-pressure flow and. At 50 psi pressure difference, no oil was observed in the no-surfactant case. At 100, 250, and 500 psi the oil productivity with surfactant was 53, 22, and 20% higher than the base case. The results also showed that a formulation with ultra-low IFT (5E-2 mN/m), can initially recover substantial water volume but did not show a superior performance over the new formulation. The data obtained in this study can be used to identify the optimum criteria of a flowback additive in terms of surface tension, IFT, and wettability requirement to enhance water recovery and maximize oil productivity.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
ABSTRACT The Oil and Gas Industry has gathered extensive and positive experience of applying corrosion inhibitors to control carbon steel corrosion in CO2 and H2S environments. Occasionally, asset failures caused by corrosion are observed due to an erroneous application of corrosion inhibitor. In many cases, overuse or incorrect use of surfactants in a commercial corrosion inhibitor package has attributed to these asset failures. In this paper, a comprehensive evaluation was conducted in order to determine what surfactant could be used to enhance the corrosion inhibition of imidazoline. The results presented here show that the appropriate selection and mixing ratio of surfactant with imdazoline are key successful factors required to formulate an effective corrosion inhibitor and to build a multi-function chemical. Misuse of surfactants can cause antagonistic results of the end product. In addition, increasing the concentration would not reverse the poor performance but rather make it worse. This is true in regards to both general corrosion and localized corrosion. INTRODUCTION Over the last several decades, corrosion inhibitors are one of the most important and widely utilized asset integrity chemicals in the Oil and Gas Industry. The industry has gathered extensive experience and knowledge of how to develop, evaluate, and apply corrosion inhibitors in the lab and field. These studies shared important guidance for corrosion engineers to apply corrosion inhibitors successfully in the field. Other researchers investigated the availability of corrosion inhibitor to contribute to corrosion inhibition. Some reported the effect of surface active compounds on corrosion inhibition. In the end, all these studies and findings aimed to reduce the corrosion rate to the controlled level and, therefore, reduce the failure events of facilities. The success or failure of a corrosion inhibition program is still being determined in the field. Occasionally, failures are observed due to misapplication of a corrosion inhibitor. The research in this paper attempts to fundamentally study the behavior of corrosion inhibition compounds and the effects of how other surfactants affect the performance of a commercial corrosion inhibitor. It was found that some surfactants will have synergistic effect with the main corrosion inhibition compound, while other surfactants produce antagonistic effects.. These findings will enhance the successful opportunities for a corrosion engineer to develop new corrosion inhibitors and apply them successfully in the field.
Abstract Surfactants have been used in the oil industry for decades as multi-functions additive in stimulation fluids. In hydraulic fracturing, surfactants and microemulsions have been extensively reported numerously as flowback additives to lower surface and interfacial tension to aid water recovery. Fracturing fluids invade the matrix during the fracturing, and if not recovered, leads to water blockage and a reduction to relative permeability to gas or oil. This problem is more challenging in low- permeability formations since capillary forces have more profound impact on water retention, and hence water recovery and subsequent oil productivity. In this work, surface tension, interfacial tension, foam stability, sand-packed columns, and coreflood experiments were performed on a selected environmentally friendly water-based surfactant formulation. The performance of the surfactant of interest was compared to two commercial microemulsion and one non-ionic alcohol ethoxylated. The results confirmed the benefit of using surfactants for flowback compared to non-surfactant case. Surface tension (ST) alone cannot be used as a selecting criterion for flow back. The alcohol exthoxylated, while reducing the ST to same level as the two microemulsions, showed very poor performance in packed column and coreflood tests. Although interfacial tension (IFT) seems to be more reasonable criteria, adsorption and emulsion tendency are other challenges that can hinder the performance of good surfactants with low IFT. Based on the data, a surfactant that lowers the IFT with the selected oil to below 1 mN/m is more likely to outperform other surfactants with higher IFT.
Summary Friction reducers (FRs) represent an essential component in any slickwater-fracturing fluid. Although the majority of previous research on these fluids has focused on evaluating the friction-reduction performance of chemical components, only a few studies have addressed the potential damage these chemicals can cause to the formation. Because of the polymeric nature of these chemicals—typically polyacrylamide (PAM)—an FR can either filter out onto the surface of the formation or penetrate deeply to plug the pores. In addition, breaking these polymers at temperatures lower than 200°F remains a problem. The present study introduces a new FR that replaces the linear gel with an enhanced proppant-carrying capacity and reduced potential for formation damage. Friction-reduction performance, proppant settling, breakability, and coreflood experiments using tight sandstone cores at 150°F were conducted to investigate a new FR (FR1). The performance of the new FR was compared with two different FRs: a salt-tolerant polymer that is a copolymer of acrylamide and acrylamido-methylpropane sulfonate (FR2), and a guar-based polymer (FR3). Different breakers were used to examine the breakability of the three FRs, including ammonium persulfate (APS), sodium persulfate (SPS), hydrogen peroxide (HP), and sodium bromate (SB). The friction reduction of the new chemical was higher than 70% in fresh water or 2 wt% potassium chloride (KCl) in the presence of calcium chloride (CaCl2) or choline chloride. The presence of 1 lbm/1,000 gal of different types of breakers did not affect the friction-reduction performance. The friction reduction of 1 gal/1,000 gal of the new FR1 was also higher than that of the guar-based FR3 at a load of 4 gal/1,000 gal at the same conditions. The results show that the new FR is breakable with any of the tested breakers. Among the four tested breakers, APS is the most-efficient breaker. Static and dynamic proppant-settling tests further indicated a superior performance of FR1 for proppant suspension compared with a PAM FR (FR2). Coreflood experiments showed that FR1 did not cause any residual damage to the core permeability when APS was used as a breaker, compared with 10% and 9% damage when FR2 and FR3 were tested, respectively. Coreflood tests also showed that FR1 is breakable using SB with only 2.5% damage, whereas FR2 and FR3 resulted in 47% and 41% damage, respectively. The results also show that higher salinity does not affect the breakability of the new FR. The proposed FR shows higher friction-reduction performance and better proppant-carrying capacity with no formation damage, compared with the conventional counterparts. Hence, FR1 is a viable choice for application in fracturing formations with proppants.
- North America > United States > Texas (0.69)
- Asia (0.68)
- North America > Canada (0.68)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.88)
- Geology > Mineral > Silicate (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.35)
Abstract Viscoelastic surfactants (VES) have been used to replace polymer-based fluids as effective, cleaner, and non-damaging viscofying carriers in frac-packing, acid fracturing, and matrix acidizing. However, several limitations challenge the use of VES-based fluids including: thermal instability, incompatibility with alcohol-based corrosion inhibitor, and intolerance to the presence of contaminating iron. This work introduces a new VES-based acid system for diversion in matrix acidizing that exhibits excellent thermal stability and diversion performance in both low-and high-temperature conditions. Rheology measurements were conducted on spent VES-acid system as a function of temperature (77- 300°F) at a pH of 4-5. The effect of acidizing additives on the VES viscosity was investigated. The additives included a corrosion inhibitor, non-emulsifier, iron-chelating agent, and iron-reducing agent. Single and dual coreflood experiments were performed using limestone core samples with an initial permeability range of 4-200 md and a permeability contrast of 1.5-55. Post CT-scan imaging was conducted to investigate the wormhole topography. The diversion characteristic of the new VES in the dual coreflood experiments was evaluated by the structure and the extent of wormhole propagation in the low-permeability core. Rheological data for 15 wt% HCl spent VES-solutions showed a maximum viscosity of 200-800 over a temperature range of 150-170°F, depending on the VES concentration in the sample. Without acidizing additives, a minimum of 50 cP was obtained at 195, 230, 250, and 275°F at 4, 5, 6, and 8 vol% of the VES in solution, respectively. None of the tested acidizing additives had a negative impact on the VES viscosity. At 8% VES loading, the acidizing package was optimized such that a minimum of 75 cP was obtained at 300°F. Dual coreflood experiments were conducted at 150 and 250°F, and the results proved the ability of the proposed VES to divert efficiently in limestone formations. Single coreflood experiments also confirmed these results. Coreflood data indicated that a range of permeability contrast of 4-10 is the optimum for diversion ability in terms of the final permeability enhancement of the low-permeability cores. The results revealed 18.6, 45.6, 82%, and infinity when the permeability contrast was 28.3, 14.4, 6. 3, 1.63, respectively. A dual coreflood experiment was conducted for two cores with a permeability contrast of 1.6 at 150°F. The VES-acid system in the presence of all acidizing additives exhibited divergent performance that exceeded the performance of the VES in the absence of additivies. These results prove the stable performance of the VES and the enhancement in viscosity response after addition of both the iron-control agent and the non-emulsfier, which resulted in less acid leakoff and better wormhole structure.
- North America > United States > Texas (0.71)
- Asia (0.68)
Abstract Friction reducers (FRs) are crucial components in any slickwater fracturing fluid. Revising the previous literature showed that the majority of research focused on evaluating the friction-reduction performance of these chemicals. Another important aspect, which a few studies addressed, is the potential damage friction reducers can cause, especially to low-permeability formations. Friction reducers are polymeric in nature (typically polyacrylamide); therefore, they can either filter out onto the surface of the formation or penetrate deeply to plug the pores. Breaking these polymers at temperatures lower than 200°F remains a challenge. This work evaluates a non-damaging and breakable friction reducer that can be a replacement for liner gel with enhanced proppant-carrying capacity. Friction-reduction performance, proppant settling, breakability, and coreflood experiments were conducted to investigate the new friction reducer (FR1) in terms of friction-reduction, breakability, and the potential damage it might cause to tight sandstone cores at 150°F. The results of the new friction reducers were compared against two conventional friction reducers; one polyacrylamide-based (FR2), and one guar-based (FR3). Different breakers were used to examine the breakability performance; ammonium persulfate (APS), sodium persulfate (SPS), hydrogen peroxide (H2O2), and sodium bromate (SB). The friction reduction of the new chemical was always higher than 65% in both fresh water and 2 wt% KCl. The presence of calcium chloride did not affect the friction-reduction performance, compared to performance reduction in the cases of FR2 and FR3. The presence of 1 gpt of different types of breakers did not affect the friction-reduction performance, even for stronger breaker (friction-reduction performance was 67% with APS breaker comparing to 68.5 % with no breaker). The new friction reducer is easily breakable in the three tested breakers: ammonium persulfate, sodium persulfate, and hydrogen peroxide. Among the three, ammonium persulfate was the most efficient breaker. Static and dynamic proppant settling tests indicated a superior performance of FR1 compared to the other conventional friction reducer (FR2). Coreflood experiments showed that the new friction reducer FR1 did not result in any formation damage with APS breaker at low KCl concentration (5 wt%) and high KCl concentration (20 wt%). A 9% formation damage was observed at weaker breaker (SB), comparing to 47 and 41.5% damage when the other two conventional friction reducers FR2 and FR3 were tested, respectively. The proposed friction reducer has higher friction-reduction performance and better proppant-carrying capacity with no formation damage compared to the conventional friction reducers.
- Geology > Mineral (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.36)
Abstract Friction reducers (FRs) represent an essential component in any slickwater fracturing fluid. While the majority of the previous research focused on evaluating the friction-reduction performance of these chemicals, only a few studies addressed the potential damage these chemical can cause to the formation. Because of the polymeric nature of these chemicals (typically PAM, polyacrylamide), a friction reducer can either filter out onto the surface of the formation or penetrate deeply to plug the pores. In addition, breaking these polymers at temperatures lower than 200°F remains a problem. This work introduces a new and non-damaging friction reducer that can be a replacement for liner gel with enhanced proppant-carrying capacity. Friction-reduction performance, proppant settling, viscosity, and coreflood studies were conducted with the following objectives: (1) investigate the effect of using the new FR on the permeability of tight sandstone formation compared to two conventional FRs, (2) test the performance of the new FR in different salinity environments from fresh to saline water, and (3) examine the effectiveness of breaking the new FR using different breakers. The friction reduction of the new chemical was higher than 65% in fresh water or 2 wt% KCl in the presence of calcium chloride or choline chloride. The presence of 1 gpt of different types of breaker did not affect the friction reduction performance. The friction-reduction of 1 gpt of the new FR1 was higher than the guar-based FR3 at load of 4 gpt at the same conditions. The results also showed that the new friction reducer is easily breakable in any of the three tested breakers: ammonium persulfate, sodium persulfate, and hydrogen peroxide. Among the three, ammonium persulfate was the most efficient breaker. Static and dynamic proppant settling tests indicated a superior performance of FR1 compared to another conventional polyacrylamide friction reducer (FR2). Coreflood experiments showed that the new friction reducer FR1 did not result in any residual damage to the formation permeability compared to 10 and 7% damage when the other two conventional friction reducers FR2 and FR3 were tested, respectively. Coreflood tests also showed that the new friction reducer is breakable using a weaker breaker such as sodium bromate with a minimum of 2.5% damage. The results showed that higher salinity did not affect the breakability of the new friction reducer.
- Geology > Mineral (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well Intervention (1.00)
Abstract Enhancing complexity of the created fracture geometry is the primary challenge for hydraulic fracturing treatment design in shale formations because of their stress anisotropy. Near-wellbore diversion may be required to evenly stimulate all perforated clusters; far-field diversion inside the created fracture may induce additional branch fracturing by overcoming the stresses holding the natural fractures closed. Increasing the pressure within the fracture enables further fracture extension. The objective of this study is to experimentally confirm the bridging ability of a swelling diverter particle and to establish a correlation between increase in pressure and its location (far-field or near-wellbore) with time, pressure, proppant and diverter loading, fluid viscosity, and fluid types. The study confirmed that increasing fluid viscosity and/or reducing flow permeability will increase the flow resistance (and therefore pressure) in any path. For fracturing application, an HEC fluid with extremely high viscosity (millions of centipoise) developed maximum increase in pressure of 3 psi/in. of fracture length. Swelling particles of the type described in the study can increase their diameter in water by up to 500% at 75°F and 800% at 175°F in water. If this growth occurs during flow in a fracture, it can preclude further movement and create a “bridge” that increases the fluid pressure inside the fracture. Injecting 100-mesh sand with the particles increased the bridging pressure from 12.5 psi/in. of fracture length for the particles alone to 125 psi/in of fracture length. The authors believe that this occurs because the sand particles create friction with the fracture face. Particles swell more rapidly in water than in 30 pptg linear guar gel, and more rapidly in linear gel than in crosslinked 30 pptg guar gel. Therefore, variations in the fracturing fluid can control the swelling of particles, a factor that can be used to “place” the diverter material deep in the fracture for far-field diversion, or closer to the perforations for near-wellbore diversion. An oxidizer breaker can be used to break the swollen particles, leaving no visible precipitation as indication of damage. The results from this paper can help in understanding the diversion parameters required to effectively enhance the complexity of the fracturing geometry.
- North America > United States > Texas (0.94)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.94)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.94)
- (20 more...)
Abstract Oil and gas productivity from shale formations can be dependent on the flow behavior of the hydraulic fracturing fluids used in stimulation treatments. Because of the unique characteristics of shale formations, including low permeability, existence of micro-fractures, and sensitivity to contacting fluids, it is difficult to evaluate the complex microscopic interactions occurring between the fracturing fluids and the reservoir rock using traditional laboratory methods. Therefore, the objective of this study is to evaluate the interaction between fracturing fluid and representative shale cores by quantifying the invaded fluid volume during the treatment and shut-in time as a function of pore geometry using nuclear magnetic resonance (NMR) technology. Shale outcrop cores from the Eagle Ford, Barnett, Marcellus, and Mancos were evaluated in this study. Cores were submerged in various fracturing fluids under pressure and temperature for two days. The increase in the volume of the fluid invaded into the cores was quantified using NMR as a function of the average pore radius. To mimic the flowback recovery process, the cores were placed in a vacuum cell for an hour, and the decreased fluid volumes within the cores were measured. Test conditions in this study investigated the effects of clay control additives and surfactants. Furthermore, the effect of operating parameters such as the pressure and fracturing fluid contact time was investigated. NMR techniques enable the effective evaluation of additives, such as surfactants and clay control additives, which until now may have been selected solely based on best practices established from stimulating local conventional formations. Additionally, this comprehensive fluid evaluation technology supports the creation of customized fracturing fluids, targeted for individual shale formations, to maximize factors such as post-fracturing load recovery, and to aid in the advancement of the industry's understanding of new fracture modeling concepts.