Displacement Fluids Research Articles

Mechanical Performance of Bentonite Plugs in Abandonment Operations of Petroleum Wells

This study aims to evaluate how the operational procedure adopted for pellet placement and the exposure to subsurface conditions influence the mechanical integrity of bentonite plugs used as barrier elements in the abandonment of petroleum wells. To this end, the plugs were formed by hydrating the pellets directly in water, simulating the onshore procedure, while the offshore plugs were obtained from pellets hydrated in deionized water after immersion in diesel or olefin, which are suggested as displacement fluids. The plugs obtained were tested by compression and adhesion tests. These mechanical tests were also carried out for specimens obtained from plugs exposed to four formulations of synthetic formation waters. The results obtained demonstrated that, in the offshore procedure, the previous contact with olefin may adversely affects the mechanical stability of bentonite plugs, while plugs formed from pellets immersed in diesel presented satisfactory mechanical properties. However, the contact with formation water evidenced that the onshore plug presents superior resistance than the offshore plug previously immersed in diesel. The highly successful performance of the onshore plug was attested by the maintenance of the compressive strength, which exhibited a maximum reduction of 13%, even after exposure to the most saline formation waters.

A Systematic Microfluidic Study of the Use of Diluted Silica Sols to Enhance Oil Displacement.

The paper presents the results of a systematic microfluidic study of the application of nanosuspensions for enhanced oil recovery. For the first time, approximately a dozen nanosuspensions prepared by the dilution of silica sols as displacement fluids were considered. The concentration of nanoparticles in the suspensions varied from 0.125 to 2 wt%, and their size ranged from 10 to 35 nm. Furthermore, the silica sols under consideration differed in their compositions of functional groups and pH. The effects of concentration, nanoparticle size, fluid flow rate, and the viscosity of the displaced oil were investigated using microfluidic technology. The microfluidic experiments demonstrated that the application of nanosuspensions for water flooding has significant potential. The efficiency of oil displacement by nanosuspensions was found to increase significantly (up to 30%) with the increasing concentration and decreasing average size of nanoparticles. The application of nanosuspensions for the enhancement of oil recovery is most appropriate for reservoirs with highly viscous oil.

Evaluation of Saline Solutions and Organic Compounds as Displacement Fluids of Bentonite Pellets for Application in Abandonment of Offshore Wells

One of the operational challenges regarding the use of bentonite pellets as sealing materials in the abandonment of offshore fields consists of their placement inside the well. This study aimed to analyze the interaction of fluid media, consisting of saline solutions (NaCl, CaCl2 and KCl) and organic compounds (diesel, glycerin and olefin), with bentonite pellets, for their applications as displacement fluids in offshore oil well abandonment operations. The physical integrity of the bentonite pellets in contact with the fluids was verified through visual inspections and dispersibility tests. Linear swelling tests were also performed to evaluate the swelling potentials of the pellets in deionized water after their contact with the fluid media. The results indicated that the NaCl, CaCl2 and KCl solutions completely compromised the physical integrity of the pellets, while diesel and olefin showed the best responses regarding the structural preservation. Furthermore, the linear swelling tests showed that, even after the contact with diesel and olefin for 1 h, the bentonite pellets reached a total swelling of 78% in water after 24 h. In this way, diesel and olefin proved to be highly promising alternatives to be used as displacement fluids for bentonite pellets in wells that will be abandoned in a submarine environment.

Mechanical Study and Key Parameter Optimization of Temporary Plugging Fracturing in Tight Reservoirs

Staging fracturing with balls for temporary plugging is a crucial technique used to stimulate deep reservoirs. However, the transport of matter confined in a trap is very complicated. To investigate the influence of various factors on the force exerted by the ball sealer during the construction of the temporary plug, we analyse the ball sealer migration in three stages: before, after, and after the pump is stopped. We examine the effect of density, viscosity, displacement, number of holes, and fracturing fluid viscosity on the confined force state of the spherical sealer. Based on a model of entrainment dynamics with three stress states, we analyse the motion and force properties of the sphere. With this analysis, we have identified the main factors that affect the force exerted by the ball sealer. Our findings suggest that reducing the number of holes, especially when using high displacement and high viscosity fracturing fluids, can optimize the force state of the plug sphere and increase the plug efficiency. This conclusion provides a theoretical foundation for the formulation and optimization of a staged FRAC construction scheme with plug balls.

Microfluidic Study of Enhanced Oil Recovery during Flooding with Polyacrylamide Polymer Solutions.

A series of experiments have been carried out on the flooding of microfluidic chips simulating a homogeneous porous structure with various displacement fluids. Water and polyacrylamide polymer solutions were used as displacement fluids. Three different polyacrylamides with different properties are considered. The results of a microfluidic study of polymer flooding showed that the displacement efficiency increases significantly with increasing polymer concentration. Thus, when using a 0.1% polymer solution of polyacrylamide grade 2540, a 23% increase in the oil displacement efficiency was obtained compared to water. The study of the effect of various polymers on the efficiency of oil displacement showed that the maximum efficiency of oil displacement, other things being equal, can be achieved using polyacrylamide grade 2540, which has the highest charge density among those considered. Thus, when using polymer 2515 with a charge density of 10%, the oil displacement efficiency increased by 12.5% compared to water, while when using polymer 2540 with a charge density of 30%, the oil displacement efficiency increased by 23.6%.

Experimental Study on Enhanced Oil Recovery of PPG/ASP Heterogeneous System after Polymer Flooding

Following the application of polymer flooding in Daqing Oilfield, the heterogeneity between different layers has intensified, resulting in the formation of more favorable seepage channels and cross-flow of displacement fluids. Consequently, the circulation efficiency has decreased, necessitating the exploration of methods to enhance oil recovery. This paper focuses on experimental research utilizing a newly developed precrosslinked particle gel (PPG) combined with alkali surfactant polymer (ASP) to create a heterogeneous composite system. This study aims to improve the efficiency of heterogeneous system flooding after polymer flooding. The addition of PPG particles enhances the viscoelasticity of the ASP system, reduces the interfacial tension between the heterogeneous system and crude oil, and provides excellent stability. The heterogeneous system has high resistance and residual resistance coefficients during the migration process in a long core model, achieving an improvement rate of up to 90.1% under the permeability ratio of 9 between high and low permeability layers. Employing heterogeneous system flooding after polymer flooding can increase oil recovery by 14.6%. Furthermore, the oil recovery rate of low permeability layers can reach 28.6%. The experimental results confirm that the application of PPG/ASP heterogeneous flooding after polymer flooding can effectively plug high-flow seepage channels and improve oil washing efficiency. These findings hold significant implications for further reservoir development after polymer flooding.

Adsorption of the Xanthan Gum Polymer and Sodium Dodecylbenzenesulfonate Surfactant in Sandstone Reservoirs: Experimental and Density Function Theory Studies.

Chemical flooding using a polymer and/or surfactant has been widely applied in oilfields worldwide for enhanced oil recovery. Chemical adsorption in reservoirs has a significant effect on the rock permeability and wettability and hence can affect the overall oil production. In this work, two chemicals, namely, the xanthan gum (XG) biopolymer and sodium dodecylbenzenesulfonate (SDBS) anionic surfactant, were used individually as displacement fluids. The amount of chemical adsorption on the rock surface and the residual resistance factor (permeability reduction) were calculated throughout the flooding experiments using an unconsolidated sandstone (SS) pack model. The effects of the injected chemicals’ concentration and reservoir salinity on adsorption capacity have been examined. Additionally, the effect of the addition of nanosilica particles (NSPs) to the injected fluid on the rock adsorption was also investigated. The results showed that the amount of XG and SDBS adsorption on the rock surface increased, albeit to a different extent, by increasing the chemical concentration at the applied salinities (0, 3.5, 5, and 10%) of the displacement fluids. Also, the permeability reduction increased with the increase in XG and SDBS concentrations; however, permeability reduction due to SDBS flooding was lower than that of XG in SS. The use of NSPs as a coinjectant to the XG and SDBS displacement fluids increased the adsorption on the SS rock. A plausible mechanism for the adsorption of the XG/NSP and SDBS/NSP blends on the SS surface was proposed. A density function theory calculation was employed to establish a relation between the adsorptivity of NSPs on SDBS and XG and the total energy and dipole moment of the molecules.

Part 1: Oil displacement by foam injection in Hele-Shaw cell with a pattern of impermeable regions

Gas flooding is one of the most effective enhanced oil recovery (EOR) techniques. However, mobility control of the injected gas has always been an issue, especially for heterogeneous and fractured reservoirs. There is still a need to understand the phase interference (relative Permeability) and oil production from such heterogeneous and fractured systems. This study investigates the displacement of oil in a fractured system, conducted in a Hele-Shaw set up with a pattern of obstructions or impermeable regions. This 2D pattern is printed from an actual rock cross-section, obtained from high-resolution micro-computed tomography. Different displacement fluids were utilized, including water, gas, and foam in secondary and tertiary injection modes. Relative permeability curves were generated, which depict the interference between the phases flowing through the Hele-Shaw cell with tortuosity. The results showed that secondary foam injection is the most efficient technique as opposed to the other methods. Also, N2-foam achieves better recovery than air-foam, which is due to the solubility of N2 gas in the aqueous phase. This study provides more insight into foam flooding when high surfactant concentration is used. Under this condition, the effectiveness of foam injection compared to conventional water and gas injections is due to both emulsification and foam displacement effects.

Experimental Study on High-Performers Quaternary Copolymer Based on Host-Guest Effect.

A quaternary polymer (HGP) was prepared by the free-radical polymerization of acrylamide, acrylic acid, maleic anhydride functionalized β-cyclodextrin (MAH-β-CD), and N-(3-methacrylamidopropyl)-N, N-dimethylnaphthalen-1-aminium chloride (NAP). It was found that host–guest behavior occurred most effectively at a molar rate of NAP and CD with 1:1, which exhibited better solubility than hydrophobically associative polymer. Moreover, the as-prepared polymer has superior salt tolerance, shear resistance, and viscoelasticity due to host–guest strategy. More importantly, the HGP solution simulates the distribution of formation water in the Bohai SZ1-1 oilfield has good rheological properties at 120 °C. All results show that the proposed polymer could be a competitive candidate in oilfield applications such as fracturing fluids, displacement fluids, and drilling fluids.

Analysis of the Influence of Fractured Reservoir Heterogeneity and Injection Rate on Oil Displacement Effect

Based on the characteristics of actual fractured heterogeneous reservoirs, similarity criteria are designed. This paper carried out physical experiments considering the fracture density and matrix permeability. The heterogeneity of fractured reservoirs and the displacement effect under different injection rates of displacement fluids are studied. The results show that under the same injection rate, the degree of recovery decreases with the increase of permeability. The average reduction range of different displacement fluids is 6-20%. The degree of recovery increases as the injection rate increases. But the increase will be reduced, and different injection media will be different. This research provides a reliable basis and guiding significance for the rational combination of development layers and the determination of a reasonable injection rate.

Displacement Mechanisms of Residual Oil Film in 2D Microchannels.

This paper explores displacement mechanisms of the residual oil film in microchannels by analyzing the following items after wetting hysteresis occurs: resistance on the residual oil film by the rock wall, the interfacial tension between displacement fluid and residual oil film, and horizontal stress acting on residual oil film by displacement fluids. Based on the continuity equations, motion equations, and constitutive equations of viscoelastic fluid, the numerical simulation is used to calculate the distribution of horizontal stress acting on the residual oil film by displacement fluids with different rheological properties. The results of the study show that increasing the horizontal stress on the oil film fundamentally mobilized the oil film and made it movable. Under the condition that the flow rate of the displacement fluid was constant, the value and direction of the horizontal stress acting on the oil film by the viscoelastic fluid changed. The elasticity changed the law of stress on the residual oil film, which is more conducive to mobilizing the oil film.

An investigation into the roles of chlorides and sulphate salts on the performance of low-salinity injection in sandstone reservoirs: experimental approach

Numerous studies have been carried out to ascertain the mechanisms of low-salinity and smart water flooding technique for improved oil recovery. Focus was often on brine composition and, specifically, the cationic content in sandstone reservoirs. Given the importance of the salt composition and concentration, tweaking the active ions which are responsible for the fluids–rock equilibrium will bring into effect numerous mechanisms of displacement which have been extensively debated. This experimental study, however, was carried out to evaluate the extent of the roles of chloride- and sulphate-based brines in improved oil recovery. To carry this out, 70,000 ppm sulphates- and chloride-based brines were prepared to simulate formation water and 5000 ppm brines of the same species as low-salinity displacement fluids. Core flooding process was used to simulate the displacement of oil by using four (4) native sandstones core samples, obtained from Burgan oil field in Kuwait, at operating conditions of 1500 psig and 50 °C. The core samples were injected with 70,000 ppm chloride and sulphates and subsequently flooded with the 5000 ppm counterparts in a forced imbibition process. Separate evaluations of chloride- and sulphate-based brines were carried out to investigate the displacement efficiencies of each brine species. The results showed that in both high- and low-salinity displacement tests, the SO4 brine presented better recovery of up to 89% of the initial oil saturation (Soi). Several mechanisms of displacement were observed to be responsible for improved recovery during SO4 brine displacement. IFT measurement experiments also confirmed that there was reduction in IFT at test conditions between SO4 brine and oil and visual inspection of the effluent showed a degree emulsification of oil and brines. Changes in pH were observed in the low-salinity flooding, and negligible changes were noticed in the high-salinity floods. These results provide an insight into the roles of chloride and sulphate ions in the design of smart “designer” water and low-salinity injection scenarios.

NANOFLUID INJECTIVITY STUDY FOR ITS APPLICATION IN A PROCESS OF ENHANCED OIL RECOVERY (CEOR)

The application of tertiary recovery techniques through chemical injection (CEOR) is in full development in the mature oil fields of Argentina. An experimental study of nanofluids intended for enhanced oil recovery is presented in this work. A polyacrylamide solution prepared in brine with addition of silica nanoparticles was used as the focus of the study. Dynamic sweep tests of the displacement fluids in a laboratory-scale triaxial cell using a standard Berea sandstone cores that simulates the formation of the reservoir allow the calculation of parameters related to its injectivity, which take into account damage to the formation and blockade of poral throats , such as the resistance factor (FR), the residual resistance factor (FRR), the inaccessible pore volume (VPI) and the dynamic retention of the nanofluid (RD). The injection of the nanofluid has not produced an increase in the damage of the porous medium, so it is potential for its application in the displacement of crude oil.

Viscoelastic effects on residual oil distribution in flows through pillared microchannels

HypothesisMultiphase flow through porous media is important in a number of industrial, natural and biological processes. One application is enhanced oil recovery (EOR), where a resident oil phase is displaced by a Newtonian or polymeric fluid. In EOR, the two-phase immiscible displacement through heterogonous porous media is usually governed by competing viscous and capillary forces, expressed through a Capillary number Ca, and viscosity ratio of the displacing and displaced fluid. However, when viscoelastic displacement fluids are used, elastic forces in the displacement fluid also become significant. It is hypothesized that elastic instabilities are responsible for enhanced oil recovery through an elastic microsweep mechanism. ExperimentsIn this work, we use a simplified geometry in the form of a pillared microchannel. We analyze the trapped residual oil size distribution after displacement by a Newtonian fluid, a nearly inelastic shear thinning fluid, and viscoelastic polymers and surfactant solutions. FindingsWe find that viscoelastic polymers and surfactant solutions can displace more oil compared to Newtonian fluids and nearly inelastic shear thinning polymers at similar Ca numbers. Beyond a critical Ca number, the size of residual oil blobs decreases significantly for viscoelastic fluids. This critical Ca number directly corresponds to flow rates where elastic instabilities occur in single phase flow, suggesting a close link between enhancement of oil recovery and appearance of elastic instabilities.

Technology Update: Adjustable, Supramolecular Viscosity Modifiers as Displacement Fluids in EOR

Technology Update We report a novel type of viscosity modifier relying on the supramolecular assemblies that have pH-adjustable viscosities and robust tolerance against high temperatures and salinities, and are resistant to shear-induced degradation. This technology is developed collaboratively by Texas A&M University, Incendium Technologies, and VaalbaraSoft. When reservoir oil is displaced by plain waterflooding, the injected water fingers through the reservoirs because of the high mobility ratio (Rachford Jr. 1964). Water fingers leave most of the oil behind, which leads to inefficient oil recovery. Hence, the viscosity modifiers are often added in the displacing fluid, (i.e., water) to better match the viscosity of reservoir oil and enable a uniform advance of the waterfront to effectively sweep the reservoir oil. Currently, for oil recovery applications, most commonly used viscosity modifiers are water-soluble polymers such as hydrolyzed polyacrylamide, polyvinyl alcohol, and poly(vinylpyrrolidone) (Taylor and Nasr-El-Din 1998). Likewise, water-soluble biopolymers, in particular polysaccharides such as xanthan and guar, are also used in some fields (Alquraishi and Alsewailem 2012). Current Technology Limitations While the above-mentioned viscosity modifiers can satisfy part of the oil recovery needs, these polymers still experience some challenges that hinder their effectiveness. For example, when the viscosity of reservoir oil is high, so should the displacing fluid be to match the mobility ratio. The current heuristics suggest that polymer flooding should be applied in reservoirs with oil viscosities between 10 and 150 cP (Taber et al. 1997). The key factor limiting the recommended range is that for oil viscosities greater than 150 cP, the injected-water-viscosity values required for a favorable mobility ratio correspond to prohibitively low values of polymer injectivity. In addition, pumping high-viscosity displacing fluids tends to lead to clogging in oil wells, which results in a major economic well operating loss. One potential solution is to use dis-placement fluids with an adjustable viscosity, with the fluid having a low viscosity at the injection site and a high viscosity upon reaching the oil phase. Furthermore, having an adjustable-viscosity displacement fluid can help to reduce pumping-related operational costs because pumping efficacy generally decreases as fluid viscosity increases. The above-mentioned polymers do not offer viscosities that can be controlled in such a fashion.

Wellbore to fracture proppant-placement-fluid rheology

Novel reservoir engineering displacement fluids (cetyltrimethylammonium bromide and sodium salicylate in water) are examined as candidates for proppant placement during fracturing. The need for additional crosslinkers, breakers or contact with hydrocarbons to change the viscosity is eliminated. These materials have a viscoelastic response governed by flow. Two fluid compositions are investigated in relation to Newtonian fluids of similar base viscosity to determine how shear induced structures (SIS) influence flow properties in the near-wellbore region of a fracture. In Couette flow, the fluid displays shear thickening and thinning within a discrete shear regime. Extensional flow tests in a microfluidic device reveal a flow resistance up to 25 times higher than Newtonian fluids. This extra flow resistance is due to an induced intermicellar network and has potential application for improved proppant carrying after injection via a perforation. Particle image velocimetry is used to visualise the entrance flow in a fracture. Instabilities are reduced as flow through the perforation increases. The viscosity contrast ratio between zero-shear viscosity and maximum viscosity response determines the extra proppant carrying capacity.

Features of hydrocarbon distribution in the viscous oil-aqueous phase system during testing of oil displacement fluids

The chemical composition of high-viscosity Mongolian oil and the influence of surfactant-based, composite oil displacement agents on the distribution of hydrocarbons (HCs) during thermostating of the crude oil-agent (oil-water) system under laboratory conditions have been studied. It has been shown that the presence of the agent in the system leads to redistribution of hydrocarbons, a change in the HC composition of the oil phase, and an increase in the concentration of petroleum components in the aqueous phase. The increase is especially noticeable when a surfactant is used: the proportion of light C10–C15 alkanes increases in the oil and C16–C25 alkanes and cyclohexanes dominate in the aqueous phase.

Use of pH-Responsive Amphiphilic Systems as Displacement Fluids in Enhanced Oil Recovery

Summary We report a novel approach that is based on the complexation and supramolecular assembly of an amino-amide and maleic acid to control viscosity of aqueous displacement fluids. It is shown that the addition of only 2 wt% of adaptable amphiphile/maleic acid into water increases the viscosity of water by a factor of 4.5×105. This superior viscosity behavior is ascribed to the formation and entanglements of layered cylindrical supramolecular assemblies with diameters of several hundred nanometers. Furthermore, the viscosity of the amphiphile solution can be increased 12 times by changing pH from 4 to 8 in a reversible manner. Such a property can be very beneficial for oil-recovery applications when the injectivity becomes a limitation. In addition, the use of switchable viscosity can reduce the energy cost associated with pumping large volumes of viscous displacement fluids. We also demonstrate the proof of concept for the use of adaptable amphiphile solutions in enhanced oil recovery (EOR) as oil-displacement fluids through column experiments. Overall, this study shows that pH-switchable supramolecular assemblies have very intriguing properties that can significantly affect EOR technologies.

Stinger or Tailpipe Placement of Cement Plugs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 168005, ’Don't Get Stung Setting Balanced Cement Plugs: A Look at Current Industry Practices for Placing Cement Plugs in a Wellbore Using a Stinger or Tailpipe,’ by Justin Roye, Schlumberger, and Sam Pickett, Chesapeake, prepared for the 2014 IADC/SPE Drilling Conference and Exhibition, Fort Worth, Texas, USA, 4-6 March. The paper has not been peer reviewed. The most common method used for the placement of cement plugs is the balanced-plug method using drillpipe, tubing, or a combination of both. A stinger with a smaller diameter than the drillpipe is commonly run on the bottom of the drillpipe for setting a balanced plug. However, a mathematical analysis of what occurs once dynamic conditions are initiated by pulling out of hole (POOH) with a small-diameter stinger shows that the initially balanced system quickly becomes unbalanced. Introduction The balanced-plug method of calculating plug-placement volumes has long been a standard industry practice for setting plugs in the wellbore. Volumes are calculated in such a way that all fluids both inside and outside of the pipe are at the same height, thus resulting in a hydrostatically balanced system. The basic assumption behind the balanced-plug calculation method is that the fluid is going to remain in place while the drillpipe is simply pulled through the fluids with minimal falling of the fluid level to fill the void left behind by the metal displacement of the drillpipe. This assumption is correct, neglecting the frictional drag forces on the fluid, when the drillpipe outer diameter (OD) and inner diameter (ID) are the same from top to bottom. However, when the drillpipe includes a stinger at the bottom, there is a disruption in the hydrostatic equilibrium between the column of fluid inside and outside the drillpipe, resulting in flow at the bottom of the stinger between the two regions. As soon as this dynamic situation is imposed on the fluids in the wellbore, the fluids downhole begin to experience a continual shifting in hydrostatic conditions. When a stinger is used at the bottom of a larger-diameter drillpipe, the difference in volumetric capacities per annular length can be substantial. The difference in the volumetric capacities inside the pipe per length can also be substantial. As a given length of larger-diameter drillpipe is pulled out at surface, all the fluid that was contained within that drillpipe, and the fluid in the annulus that was surrounding it, will attempt to stay in place. As noted earlier, there will be some drop in the fluid level caused by the removal of the volume of steel in the drillpipe. However, a much longer length or column height of fluid per unit volume is displaced within the smaller-diameter stinger because of its smaller capacity. After pulling out several hundred lineal feet of drillpipe at the surface, a substantial difference in lineal footage of fluid has passed through the stinger. If these fluid-column-height changes are not taken into account in the placement calculations, as they are not in the balanced-plug method, the result will be a plug that has had other displacement fluids dumped into the middle of the cement as the drillpipe is pulled out of hole.

An Experimental Investigation of Fracture Impacts on the Dispersion of Miscible Displacement Processes: Qualitative Analysis

Dispersion phenomena of miscible displacement processes conducted on porous media have been investigated by many researchers in different engineering field in the past 50 years. In microscopic scale, the pore size distribution has been shown to cause dispersion of two miscible displacement fluids flowing through laboratory core scale. In field scale, the heterogeneity of reservoir formation has been shown to be a main cause of dispersion. One of the heterogeneities of reservoir formation is the presence of networks of fractures. The roles of network fractures on dispersion have not been investigated in enhanced oil recovery miscible displacement processes. In this work, the effect of fractures on dispersion was investigated by conducting miscible displacement laboratory tests on micromodels. The tests were performed under two different injection rates with two different fracture orientations. The results show that breakthrough time is reduced when the fracture is present in the micromodel. Higher pore volume injection of displacing fluid is needed for fractured patterns to reach normalized concentration of one in comparison with the homogeneous one. The experimental results suggest that the breakthrough curve of the fractured system has three distinct regions in comparison with the homogeneous system. Also, the results show that a system with a fracture perpendicular to the flow direction acts as a dead end pore system.