The performance of surfactant-enhanced oil recovery (EOR) in fractured carbonates relies on spontaneous imbibition or low IFT-aided gravity drainage. This work investigated the synergism between wettability effects and IFT reduction mediated by a variety of surfactants through experiments and numerical simulation studies. Experiments have shown that oil can be recovered from oil-wet Silurian dolomite fracture blocks either by capillarity driven imbibition, gravity-driven imbibition or low tension-aided gravity drainage. The mixture of wettability alteration (WA) surfacant with IFT reduction surfactant exhibits the synergistic effect on the imbibition oil recovery from oil-wet carbonate rocks. It was found that divalent ion scavengers help the wettability altertion capability of some sulfonate surfactants in hard brine, which leads to the high oil recovery up to 70% OOIP (IFT+WA), compared with oil recovery of 30-50% OOIP by sulfonate surfactant only (only IFT reduction). We proposed a mechanism that the presence of a sufficient amount of divalent ion scavengers in the anionic surfactant formulation reduces the free divalent cations in hard brine, which then promotes the release of surfactant monomers from the micelles and enhances wettability alteration by surfactant adsorption. The UTCHEM simulation results confirmed the existence of synergism between IFT reduction and WA in spontaneous imbibition processes. According to the capillary desaturation curve (CDC), that residual oil saturation after gravity drainage is approximately 10% to 20% higher than gravity-driven spontaneous imbibition when two processes have the similar trapping numbers, confirming that the wettability alteration contributes to the ultimate oil recovery.
Viscoelastic surfactant (VES) fracture fluids were developed as a nondamaging alternative to conventional polymer-based fluids. However, the viscosity performance of typical VES fluids is dramatically reduced at high temperature. Therefore, these fluids are typically limited to treat relatively low-temperature formations unless foamed with nitrogen or carbon dioxide. Recent laboratory work has shown that viscosity alone may not accurately assess proppant transport. Thus, combination of rotational and oscillatory measurements to determine the fluid viscous and elastic properties can better predict whether the fluid can be applied successfully in the field.
The present study was conducted to introduce a new Gemini VES system that can gel and maintain useful viscosity up to 275°F, which can provide additional downhole benefits. Dynamic and static proppant settling tests were conducted using a high-pressure/high-temperature visualization cell to confirm the effect of elastic properties of this fluid on proppant settling. Finally, proppant settling tests were conducted with three proppant types of the same size, but different density and shape at a range of concentrations.
Experimental results show that the surfactant gel behaved as an elastic material (elastic regime), where the elastic modulus (G') was dominant over the viscous modulus (G”) during the tested range of frequency. This behavior gives perfect proppant transport properties. At temperature less than 225°F, Values of G' were independent of the frequency and/or shear rate values, while G” increased with increasing frequency and/or shear rate. At higher temperature, both G' and G” increased with increasing frequency and/or shear rate. This gives a good proppant-carrying capacity during dynamic conditions (mixing and injection) with a small pressure drop. The addition of an internal liquid breaker increases the viscous regime with time and temperature. When elastic regime dominates, 100% proppant suspension was confirmed for at least two hours at static and dynamic conditions and temperatures in the range of 75 to 250°F.
In view of the great impact of asphaltene deposition in the petroleum industry, it is of paramount importance to estimate the tendency of crude oils and petroleum products towards precipitation as well as the potential amount of material that can precipitate. These are important parameters to consider in designing and monitoring of different processes in the petroleum value chain. It is common knowledge that asphaltene precipitation is strongly related to the colloidal nature of petroleum materials. Rather recently, a new method to evaluate the colloidal stability of crude oils was developed based on the determination of the solubility distribution of asphaltenes. It was found that samples from different origins give different solubility distribution patterns and that those patterns can be correlated to precipitation tendencies of crude oils.
In this work, asphaltene distributions in solid deposits are analyzed and compared to the original asphaltene distributions in the corresponding original oils. Additional chemical and physical properties were also examined and compared. This study aims to link specific asphaltene solubility distribution patterns to the formation of deposits and to find out how asphaltenes found in deposits are compared with the asphaltenes in the materials that originated them. This information is relevant for thermodynamic as well as kinetic modeling of the asphaltene deposition phenomena.
The results indicated significant differences between asphaltenes from the original crude oils and their corresponding deposits. Quantification of these differences in terms of solubility was carried out and showed that asphaltenes from deposits are in average composed of less soluble asphaltenes than those present in the original crude oils. In practical terms, this means that asphaltenes separated using heptane or pentane might not be representative of the asphaltenes found in deposits. The compositional variation of solid deposits seems to point out towards a complex mechanism of formation that is usually not considered in the tools used to model this phenomenon.
The incompatibility of cement and shale and the subsequent failure of primary cementing jobs is a very significant concern in the oil & gas industry. On wells ranging from hydraulically fractured shale land wells to deepwater wells, this incompatibility leads to an increased risk in failing to isolate zones, which could possibly present a well control hazard and can lead to sustained casing pressure. The cement-shale interface presents a weak link that often becomes compromised by the loads incurred either during drilling, completion/stimulation or production phases.
To formulate cements for effective zonal isolation, it is crucial to evaluate the bond strength of the cement-shale interface. Although several studies have focused on the interactions between cement and sandstone, very few studies have addressed the bonding behavior of cement with shale. The conventional push-out test protocol used to measure cement-to-sandstone shear bond strength has proven to be difficult to apply to shale due to its laminated and/or brittle nature that complicates sample preparation and can lead to shale or cement matrix failure instead of failure at the interface. In this paper, we present a novel, simple and versatile laboratory test procedure to measure the shear bond strength between cement and shale.
The new procedure was used to develop cement formulations to improve the cement-to-shale bond. Various types of surfactants were added to cement slurry to evaluate their effects on cement bonding property. Our results indicate that bond strength of cement with shale can be enhanced by incorporating particular surfactants in cement slurries.
Polymer retention caused by increase of hydrodynamic force acting upon polymer molecules was evaluated in this study. The results indicate this hydrodynamic retention is strongly flow rate dependent. In the low-flow region, the retention increases abruptly with increased flow rate. In contrast, in the high-flow region, the increase becomes much more gradual. Our results also demonstrate that this flow-induced retention is totally reversible (no incremental irreversible retention occurs), which is also confirmed by the constant residual resistance factors determined after 100 PV of brine postflush. Consistent with previous literature, distinct flow behaviors of partially hydrolyzed polyacrylamide (HPAM) and xanthan polymers in porous media were observed. For HPAM, in the low-flow regime, Newtonian behavior (i.e., resistance factor is independent of flow rate) was exhibited. In the moderate-to-high-flow regime, HPAM showed shear-thickening behavior (resistance factor increase with flow rate). In contrast, only shear thinning (resistance factor decreases with flow rate) was detected for xanthan polymer. By analyzing the retention and rheology of both HPAM and xanthan polymers, we show that hydrodynamic retention has little effect on polymer rheology in porous media.
Carboxylated guar or cellulose fluids are among the most robust fracturing fluids because they crosslink at both high and low pH with transition metal compounds and exhibit tremendous thermal stability. Low-pH fluids are preferred for stimulation treatments using low-quality water or when foamed with CO2 for low-pressure formations. Such systems are often challenged with rapid viscosity development or insufficiently delayed crosslinking, which generates high pipe friction pressure. The ability to effectively control viscosity development in low-pH fracturing fluid will improve the applicability of carboxylated guar- or cellulose-based fracturing fluids.
A novel approach is reported in this paper to delay the crosslink of low-pH fracturing fluid using a slow-dissolving, solid organic acid in hydrated polymer containing zirconium crosslinker, to slowly lower the pH of the fluid to the optimum pH where crosslinking occurs. The slow pH reduction results in a slow viscosity build-up (delay) with increasing temperature, without compromising fluid rheology performance. The novel approach will complement existing chemical delay methods. Preliminary results show that crosslink time can be increased by using less organic acid; for instance, decreasing organic loading from 16 to 4 ppt led to crosslink time increase of 97 to 510 s.
To further simplify field handling of such organic acid material, the organic acid is slurried in hydrocarbon. Dissolution experiments demonstrate that the slurried acid (1.024-1.710 g/100 mL) dissolves in water more slowly than an approximate amount of solid acid (0.43g/100mL), which offers additional benefits to control delayed crosslinking.
This new patent-pending approach to crosslink delay increases the delay options for crosslinked low-pH carboxylated guar and cellulose because the delay can be tailored to suit different well stimulation fluid requirements. The rheology evaluation as a function of varying loading of both solid and slurried organic acid, as well as the rate of pH change are discussed in this paper.
Successful liner cementing in unconventional shale wells is strongly dependent on slurry stability. A delayed-release, high-temperature suspending agent was developed that provides viscosification and stabilization of the slurry without causing excessive viscosification and mixing problems at the wellsite. The suspending aid was prepared from water-soluble, thermally stable monomers copolymerized with degradable crosslinking monomers. The crosslinks degrade as the temperature of the slurry increases, ultimately resulting in dissolution of the polymer and concomitant slurry viscosification. The performance of the suspending aid was demonstrated by means of laboratory testing under typical Eagle Ford shale conditions. Improvements were observed in terms of fluid-loss control (54 cc/30 min [control] to 28 cc/30 min), free fluid (5% [control] to 0%), sedimentation (?? 5.2 lbm/gal [control] to ?? 0.2 lbm/gal), and consistometer off/on tests. Three field examples from the Eagle Ford are presented where the suspending aid was used to establish the desired mud-spacer-cement rheological hierarchy at bottomhole circulating temperature (BHCT); provide sufficient slurry stability to set the liner top plug, circulate out excess cement, and produce a competent cement sheath; and improve the mixability and stability of a barite-weighted spacer.
Oil well cementing uses a variety of organic additives such as dispersing agents, retarders or fluid loss control additives. The later, which prevent interstitial water from filtering into the formation during cement placement, are generally polymer based. A widely used class of fluid loss control additive are the high molecular weight Sulfonated copolymers, generally comprising AMPS (2-Acrylamido-2-methylpropane sulfonic acid) copolymerized with Acrylamide (Am) or N, N' Dimethylacrylamide (DMA). The mechanism of action of these polymers has been studied recently and it was demonstrated that adsorption onto the cement surface is crucial to achieve the required product performance. It was also shown that other solutes and admixtures present in the cement interstitial solution can hinder adsorption resulting in performance losses. Thus it has been recommended to incorporate an additional monomer containing strongly adsorbing units in the copolymer to enhance the interaction with the cement surfaces hence limiting competitive adsorption issues.
In this study we investigated the use of diblock copolymers comprising a short but strongly adsorbing block and a long second block of DMA-AMPS as a potential new class of filtration control agent. We showed that diblock copolymers with much lower molecular weights than statistical polymers can provide satisfactory fluid loss control performance. Furthermore, it was demonstrated that these structured polymers show good formulation flexibility and deliver more robust performance in the presence of a wide range of admixtures and solutes.
Finally we focused on the analysis of the adsorption on cement of various formulation admixtures and how it affected the adsorption of our diblock copolymers. With the aid of an analytical method utilising size exclusion chromatography of collected filtrate from HPHT filtration cells, it was possible to have a direct access to a fluid loss polymer concentration in the filtrate even in the case of complex formulations.
Based on these studies, the mechanism of action of the diblock copolymers as fluid loss control agents is discussed with reference to that evoked for statistical polymers.
Kadhum, Mohannad J. (University of Oklahoma) | Swatske, Daniel P. (University of Oklahoma) | Chen, Changlong (University of Oklahoma) | Resasco, Daniel E. (University of Oklahoma) | Harwell, Jeffrey H. (University of Oklahoma) | Shiau, Ben (University of Oklahoma)
Carbon nanotube hybrids (CNTs) have attracted research interest due to their interfacial activity. CNTs can stabilize emulsions and foams and can be used as contrast agents or tracers in rock matrix. In addition, catalytic functionalities can be attached to the nanotubes making them delivery vehicles for catalyst into zones deep inside the reservoir.
Generating stable dispersion of CNTs in harsh reservoir conditions has been the main challenge for utilizing the tubes in in-situ reservoir applications. This is because the dispersed tubes tend to form aggregates that settle down in the presence of high ionic strength (high salinity) brines. In this work, stable dispersion of carbon nanotubes prepared in reservoir fluids is realized by successfully separating individual tubes using such additives as polymers and surfactants. For example, the CNTs would be well dispersed via sonication with highly polarizable polymer such as polyvinyl pyrrolidone (PVP) or Gum Arabic (GA). To mitigating their agglomeration, a secondary additive such as hydroxyethyl cellulose (HEC) polymer is also added to provide adequate steric repulsion for their propagation in porous media at high salinity brines. The nanotube dispersion generated using these dual polymer system is able to deliver successfully through both consolidated cores (200mD permeability of Berea sandstone) and sand pack experiments (4D permeability) with minimal retention at mimic reservoir conditions (65°C and brine compositions of 8% NaCl and 2% CaCl2). Results of the eluted nanoparticles indicate that greater than 80% recovery of injected concentration observed in both consolidated and non-consolidated porous media. Small adsorbed amount of nanotubes is capable of saturating the adsorption sites inside porous media resulting in complete propagation of subsequent injections; this is corroborated by nanotube concentrations approaching 100% of the injected concentration after few pore volumes of injection.
Experiments also demonstrated that in the presence of residual oil inside crushed Berea sandstone sand columns, the extent of nanotubes adsorption to the oil/water interface is a function of the level of oil saturation.
This work is providing insight about the full potential of using carbon nanotubes in oilfield development applications.
Waterflooding has been used for decades as a secondary oil recovery mode to support oil reservoir pressure and drive oil into producing wells. Recently, extensive experimental work has indicated that optimizing the salinity of the injected water is an enhanced oil recovery technique that improves oil recovery in sandstone and carbonate reservoirs. Ion interactions between formation water, crude oil, injection water, and rock surface are quite complex. The question is how the surface charge of the minerals of sandstone formation affects the waterflooding performance. In this study the zeta potential measurements are conducted for rock/brine interfaces using the Phase Analysis Light Scattering (PALS) technique.
This work demonstrates the results of zeta potential experiments to evaluate the effect of electrical surface charge and double layer expansion for common sandstone minerals. Four sandstone rock types (Buff Berea, Grey Berea, Parker, and Bandera) with different clay contents are studied. In addition, several minerals such as quartz, carbonate (calcite and dolomite), clays (kaolinite, chlorite, and montmorillonite), micas (muscovite, biotite, and illite), feldspars (microcline and anorthoclase), and ilmenite are selected to perform this work. Various brines are tested including seawater, 20% diluted-seawater, 0.5 wt% NaCl, 0.5 wt% MgCl2, and 0.5 wt% CaCl2.
Based on the results of 100 experiments we found that the monovalent cations are more efficient in increasing the absolute values of the zeta potential than the divalent cations at 25°C. Zeta potential becomes more negative while the salinity of the brine decreased. Changing the pH of the solution causes a significant alteration in charge of Buff Berea and Bandera sandstone particles and subsequently, the zeta potential values. The zeta potential of Bandera is more negative than that of Buff Berea at any condition of pH in the range of 5 and 10. It is observed from the results that most of the minerals tends to be more stable for 0.5 wt% NaCl solutions compared to 0.5 wt% CaCl2 and 0.5 wt% MgCl2 solutions. Feldspars surfaces charge are significantly influenced using 0.5 wt% NaCl, followed by micas and clays. The resulting zeta potentials for the dolomite and calcite minerals showed different trend from the other sandstone minerals for low-salinity brine. For dolomite, all the samples show positive zeta potentials at original pH. At low pH, dolomite shows small negative zeta potentials in 0.5 wt% NaCl.