In-situ gelled acids have been used for acid diversion in heterogeneous carbonate reservoirs for more than two decades. Most of the gelled systems are based on an anionic polymer that has a cleaning problem after the acid treatments that leads to formation damage. This work evaluates a new cationic-polymer acid system with the self-breaking ability for the application as an acid divergent in carbonate reservoirs.
Experimental studies have been conducted to examine the rheological properties of the polymer-based acid systems. The apparent viscosities of the live and the partially neutralized acids at pH from 0 to 5 were measured against the shear rate (0 to 1,000 s-1). The impact of salinity and temperature (80 to 250°F) on the rheological properties of the acid system was also studied. The viscoelastic properties of the gelled acid system were evaluated using an oscillatory rheometer. Dynamic sweep tests were used to determine the elastic (G’) and viscous modulus (G") of the system. Single coreflood experiments were conducted on Indiana limestone cores to study the nature of diversion caused by the polymer-acid system. The impact of permeability contrast on the process of diversion was investigated by conducting dual coreflood experiments on Indiana limestone cores which had a permeability contrast of 1.5-20. CT scans were conducted to study the propagation of wormhole post acid injection for both single and dual corefloods.
The live acid system displayed a non-Newtonian shear-thinning behavior with the viscosity declining with temperature. For 5 wt% HCl and 20 gpt polymer content at 10 s-1, the viscosity decreased from 230 to 40 cp with temperature increasing from 88 to 250°F. Acid spending tests demonstrated that the acid generated a gel with a significant improvement in viscosity to 260 cp (at 250°F and 10 s-1) after it reached a pH of 2. The highly viscous gel plugged the wormhole and forced the acid that followed to the next higher permeability zone. The viscosity of gel continued to increase until it broke down to 69 cp (at 250°F and 10 s-1) at a pH of 4.8, which provides a self-breaking system and better cleaning. Coreflood studies indicated that the wormhole and the diversion process is dependent on the temperature and the flow rate. There was no indication of any damage caused by the system. The injected acid volume to breakthrough (PVBT) decreased from 2.2 to 1.4 when the temperature increased from 150 to 250°F.
The strong elastic nature of the gel (G’= 3.976 Pa at 1 Hz) formed by the partially neutralized acid system proves its suitability as a candidate for use as a diverting agent. This novel acid-polymer system has significant promise for usage in acid diversion to improve stimulation of carbonate reservoirs.
Viscoelastic surfactants (VES) are essential components in self-diverting acid systems. Their low thermal stability limits their application at elevated temperatures. The industry introduced new VES chemistries with modified hydrophilic functional groups, which enhances their thermal stability. These new chemistries are still challenged by the lack of compatibility with corrosion inhibitors (CI). This work aims to study the nature and the mechanism of the interaction between the VES and the corrosion inhibitors, which affects both the rheological and corrosion inhibition characteristics of the self-diverting acid system.
This study is based on rheology and corrosion inhibition tests, where combinations of VES and corrosion inhibitors are tested and complemented with chemical and microscopic analysis. Negatively charged thiourea and positively charged quaternary ammonium corrosion inhibitors were selected to study their impact on both cationic and zwitterionic VES systems. Each mixture of the corrosion inhibitor and the VES was blended in a 15 and 20 wt% HCl acid mixture, then assessed for its viscosity at different shear rates, CI concentrations, and temperatures up to 280°F in live and spent acid conditions. Each acid solution was assessed using Fourier-Transform-Infra-Red (FTIR) before and after each rheology and corrosion test to track the changes of the mixture functional groups. Each mixture was examined under a polarizing microscope to assess its colloidal nature. The corrosion inhibition effectiveness of selected acid mixtures was evaluated. N-80 steel coupons were immersed statically in the acid mixture for 6 hours at 150°F and 1,000 psi. The corrosion rate was evaluated by using metal coupon weight loss analysis followed by optical microscope examination for the metal surface.
The interaction between the CI and the VES surface charges and molecular geometries dictates both the rheological and the inhibitive properties of the acid mixtures. The use of a small molecular structure anionic CI with a cationic VES, results in a fine monodispersed CI particles in the VES-acid system. The opposite charges between the CI and the VES results in electrostatic attraction forces. Both the fine dispersion and the electrostatic attraction enhances the rheological performance of the mixture and packs the corrosion-inhibiting layer. The addition of a bulk and similarly charged CI with the VES results in a coarse polydispersed CI particles with repulsive nature with the VES. These properties increase the shear-induced structures and lower the packing of the inhibition layer deposited on the metal coupons, which decrease the rheological performance of the acid mixture and increase its corrosion rate. The FTIR analysis shows that there is no chemical reaction between the CIs and the VESs tested.
This work investigates the interactions between the corrosion inhibitors and the viscoelastic surfactants. It explains the impact of the surface charge of both corrosion inhibitors and VES on their rheological and corrosion inhibition characteristics. It adds a selection criterion for compatible VES and corrosion inhibitors.
Iron sulfide is a $1.4 billion/year problem in the oil and gas industry receiving little R&D attention. The low success rate of organic acids and polyaminocarboxylic acids (PACA) prompts a more focused investigation and development of new dissolvers for the treatment of iron sulfide scales. This study evaluates the solubility of the iron sulfide scale by commonly used simple organic acids and describes two new blends that outperform the aforementioned standalone dissolvers at 1,000 psi and 150°F.
Bottle and autoclave tests evaluated the efficacy of various dissolvers to dissolve the iron sulfide scale. Bottle tests helped in evaluating the dissolvers’ potential to dissolve iron sulfide. A Hastelloy-B autoclave with a maximum operating pressure and temperature of 1,800 psi and 350°F, respectively, contained the iron sulfide and the dissolver for the anoxic dissolution tests. Formic acid, maleic acid, lactic acid, citric acid, oxalic acid, ethylenediaminetetraacetic acid disodium salt (Na2EDTA), and pentapotassium diethyltriaminepentaacetic acid (K5DTPA) were used. The simple organic acids added to Na2EDTA helped in improving the solubility of the scale. Two final experiments with the most successful blends were conducted for 24 hours. Concentration of the dissolver varied from 1-10 wt%. The experiments were conducted for 4 hours at 150°F, and a pressure of 1,000 psi. Elemental analysis using the Inductively Coupled Plasma (ICP) determined the efficiency of scale removal. Dräger tubes measured the H2S concentration inside the autoclave at the end of the experiment. The degree of saturation of the dissolvers calculated from the ICP measurements helped in evaluating its utilization.
An XRD study showed the initial iron sulfide scale was mainly pyrrhotite (67%), mackinawite (23%), troilite (5%), and remaining wuestite (5%). Bottle tests showed that maleic acid is the best reactant for iron sulfide in terms of the speed of the reaction. However, citric acid can react with the iron sulfide at lower concentrations and is more effective. Similar to the bottle test, maleic acid yielded the maximum solubility among standalone treatments. An inductively coupled plasma analysis of iron concentration showed a solubility of 10.6 g/L iron in maleic acid. The next best treatment was with formic acid, dissolving a maximum of 9.7 g/L iron. Oxalic acid converted the iron sulfide to iron (II) oxalate, which is insoluble in water. K5DTPA was a poor dissolver of iron sulfide with less than 1 g/L iron solubility. Blends of Na2EDTA and a synergist helped in improving the dissolution. Adding 5 wt% potassium oxalate to 15 wt% Na2EDTA helped in dissolving 70.1% of the initial iron at 1,000 psi, 150°F, and 24 hours soaking time. A blend of 15 wt% Na2EDTA and 5 wt% potassium citrate dissolved 87% of iron at the same conditions.
Development of novel dissolvers that are less corrosive and safer than traditional dissolvers is a necessary step to improve the dissolution of iron sulfide scales. The combination of polyaminocarboxylic acids with their synergists is unexplored in dissolving iron sulfide. This study provides an evaluation of various dissolvers in addition to developing two new synergistic blends for iron sulfide scale treatment. These dissolvers are good alternatives to traditional treatments and can reduce operational risk and mitigate flow assurance problems.
The proposed paper presents a detailed study on evolving CO2 due to calcite mineral dissolution, and its ensuing activity during the matrix acidizing of sanstone reservoirs. Coreflood experiments were conducted in acidizing, and interpreted via simulation studies using a three-phase, two scale continuum model. Sensitivity studies were then performed on the calibrated simulation model. Acid injection was performed on 6 in.-length, 1.5 in.-diameter Bandera Brown sandstone cores of variable calcite content, using 15 wt% HCl single-phase coreflood experiments at high back pressures were conducted to calibrate and initially test the three-phase, two-scale continuum model. Experimentally measured rock-heterogeneity via computed tomography (CT) scans, relative-permeability and capillary pressures, oil-water interfacial tension and contact-angle parameters were inputs for three-phase, two-scale model-based history matching and sensitivity studies. The three-phase, two-scale continuum model was able to match all performed coreflood experiments with a good level of accuracy. The acid-calcite chemical reaction parameters were fixed in all cases to ensure consistency in analysis. Oil production was observed, with an average of 40% recovery of the residual oil in place at CO2 miscible pressures. CO2 miscibility in oil enhances swelling with time, which was seen as the main mechanism for oil production. A direct symmetry was observed between the oil recovery and average CO2 moles in oil. The recovery curve flattened once surrounding oil reached its full-saturation level with CO2. Reduction in oil-water interfacial-tension increased the recovery factor only by a slight margin, owing to dependency on evolved CO2 volume. Immiscible CO2 conditions yielded no residual oil recovery. The successful application of the three-phase, two-scale continuum model approach sets a new bar in the area of sandstone acidizing. The acid breakthrough criterion has been revised toward application in a three-phase environment. The potential of CO2, a by-product of acidizing, towards its contribution in swelling oil in the presence of a three-phase environment, and towards possible oil recovery in the event of flowing back a well.
Reaction kinetics between calcite and acid systems has been studied using the rotating disk apparatus (RDA). However, simplifying assumptions have been made to develop the current equations used to interpret RDA experiments to enable solving them analytically in contrast to using numerical methods. Experimental results revealed inadequacy of some of these assumptions, which necessitates the use of a computational fluid dynamics (CFD) model to investigate their impact on the RDA results. The objectives of the current work are threefold: (1) develop a CFD model to simulate the reaction in the RDA, (2) Identify the error associated with the assumptions in the original equations, and (3) develop a proxy model from the results that can accurately represent the reaction in the RDA.
In developing the CFD model, the averaged-continuum approach was used to simulate the chemical reaction on the disk surface. Both Newtonian and non-Newtonian fluids were studied to investigate the adequacy of the equations’ assumptions. To validate the model, simulations were compared with experimental results. Experiments were run at 0.25, 0.5, 1, and 1.25M HCl with marble using the RDA at 250°F. Rotation speeds of 200, 400, 600, and 1,000 rpm were tested at each acid concentration. The diffusion coefficient was then calculated. Parameters of the CFD model were then adjusted to match the rock dissolved throughout the RDA experiments.
The rock dissolved in the disk from the CFD model matched the results from the RDA experiments. The transition from mass-transfer to the kinetics-limited reaction behavior was captured by the CFD model. The velocity and viscosity profiles for both Newtonian and non-Newtonian fluids showed the effect of the container's boundaries on the flow. Results indicate that this effect is pronounced in the case of Newtonian fluids at high rotational speeds. Moreover, the impact of varying viscosities in the case of non-Newtonian fluids resulted in errors in estimating the reaction kinetics. Finally, a proxy model was obtained to reduce the computational time involved in accurately simulating the experiments.
The present work developed the first CFD model to accurately evaluate reaction kinetics and diffusion coefficient in the RDA with minimum assumptions. More specifically, the model relaxes the infinite acting, constant fluid properties, and constant reaction surface area assumptions. Finally, the proxy model obtained results in reduced computational time with minimal compromise on accuracy.
The design process of carbonate matrix acidizing treatments requires coring and conducting linear, radial core-flood experiments. With the current environment revolving around cutting costs, it becomes increasingly more important to accurately design cost effective acidizing treatments. This work aims to introduce a novel approach to predicting the performance of acid treatments in the field using log data only. A radial reactive flow simulator, using porosity distributed from logs, is utilized to provide accurate predictions without the need for experiments.
Core-flood acidizing experiments at two temperatures (150 and 200°F) with two acid concentrations were studied. A reactive flow simulator was built using porosity distribution derived from computed tomography (CT) scan and tuned to match experimental data. A new radial simulation model of 3.25 ft. radius was utilized to study acid propagation under field conditions. For accurate predictions, porosity was distributed using cores CT scan derived values. Simulation results were compared with traditional 1-D models. Different porosity distributions, including gamma distributions, were used in the radial model.
The reactive flow simulator was able to accurately capture wormhole propagation inside the linear core. A greater than 90% match between experimental and simulated acid pore volume to breakthrough (PVBT) was obtained using two different temperatures and acid concentrations. The simulation results from the radial field scale model show that the optimum velocity can be higher or lower than those predicted from lab experiments. Accordingly, caution must be taken when linear core flood data is used to predict acid propagation in the field. The simulations showed that traditional upscaling models overpredict acid volumes, as the predicted volumes are double at moderate to high injection rates. Models using statistically distributed porosity can provide accurate acid propagation predictions, with a relative percentage error less than 25% at extremely high injection rates.
This work introduces an accurate model using porosity directly from logs to predict acid performance while avoiding expensive designs. The simulation results revealed that traditional designs overpredict acid volumes required for field treatments. The statistically distributed porosity can be used as a substitute for CT scan derived porosity with low effect on model predictability. The reactive flow simulator can accurately match experimental data.
After hydraulically fracturing of shale gas wells, theoretical and experimental studies showed that over 75% of the injected water-based fracture fluids left unrecovered. The trapped water causes permeability damage and productivity impairment. The flowback water also tends to be highly saline, often with TDS contents of as much as 200,000 ppm. This study aims to investigate the effect of well shut-in before flowback stage (the soaking process) on the production of shale and tight sandstone formations.
Shale and sandstone samples were analyzed by X-ray diffraction (XRD). Marcellus shale and Kentucky sandstone cores were used. A modified core flood setup was used to allow porosity measurements by gas expansion method, then pulse decay permeability measurements, and fluid injection during the leak-off process. Nitrogen was used for gas expansion and permeability measurements, while 5 wt% KCl brine was used as representative of leak-off fracturing fluid. The fracturing fluid was injected under a constant pressure gradient (300 in the case of sandstone cores and 1,500 psi in the case of shale cores. After removing the pressure gradient, gas permeability was measured at different soaking times. Computed tomography (CT) was used to scan the cores during the experiment to observe the propagation of fracturing fluid in the core with time.
The results show increasing the regain permeability for sandstone formation was 60% of its initial value directly after the leak-off stage. Then, the regain permeability decreased with increasing the soaking time 38% of its initial value after the core completely invaded with leak-off fluid. The regain permeability was then increased with longer soaking time, as a result of reducing the chocking effect at the core inlet. The propagation rate of water saturation front from CT-scan data decreased with time until reaching the core outlet. The regain permeability on shale cores was 0.14 of its initial value and decreased with soaking time, due to depressed relative permeability curve on this tight pore-space cores.
This study addresses the mechanism of production enhancement or reduction as a result of the soaking process for shale and tight sandstone formations.
Almubarak, Tariq (Texas A&M University) | Li, Leiming (Aramco Services Company) | Nasr-El-Din, Hisham (Texas A&M University) | Ng, Jun Hong (Texas A&M University) | Sokhanvarian, Khatere (Sasol Chemical) | Alkhaldi, Mohammed (Saudi Aramco) | Almubarak, Sama (Saudi Aramco)
In order to satisfy the demand for oil and gas, it becomes increasingly necessary to produce from formations that are deeper, have low permeability, and higher temperature. Conventionally, hydraulic fracturing fluids make use of viscosifiers such as guar and its derivatives to generate the rheological properties required during the fracturing process. However, to withstand the high-temperature environments, higher loadings of polymer is required. This leads to an increase in polymer and additive concentrations. Most importantly, these higher loading fluids do not break completely, and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly.
This work builds on previous work which introduced a new hybrid dual polymer hydraulic fracturing fluid that was developed for high-temperature applications. 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 less additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings. In this work, the fluid is further optimized to withstand even higher temperatures up to 400°F.
Total polymer loadings of 30 lb/1,000 gal and 40 lb/1,000 gal dual polymer fracturing fluid were tested in this work and were prepared in the ratio of 1:1 and 1:2 (CMHPG: Synthetic). They were then crosslinked with a metallic crosslinker and placed in a HPHT rheometer to measure the viscosity between 200 and 400°F. After observing the failure temperature of the mixtures, additives such as buffers, crosslinking delayers, and oxygen scavengers were added and tested at temperatures above that point. The type of crosslinker used was also varied to observe the effects of the rate of release of the metallic crosslinker on thermal stability.
The results indicate that the 1:2 (CMHPG: Synthetic) mixture performed better at temperatures exceeding 330°F than the 1:1 mixture. The failure point of both mixtures was observed to be 350°F for the latter while the former failed at 370°F. The addition of a crosslinker that allowed a more controllable release was observed to improve the thermal stability of the fluid mixture above 370°F by increasing the polymer's shear tolerance. The addition of additives to the mixture was shown to improve the thermal stability of the solution to varying degrees. Of the three additives, the most significant enhancement came from the addition of oxygen scavengers while the least was from the buffer solution.
CO2 foam has been used to improve the sweep efficiency for EOR as a replacement for polymers to avoid potential formation damage. Foams degrade at high temperatures (>212°F), in high-salinity environments, and in contact with crude oil. The present work evaluates nanoparticles and viscoelastic surfactants (VES) to improve foam stability when these foams are used as EOR fluid.
This study investigates the stability of alpha olefin sulfonate (AOS) foam for different foam solutions in the presence of nanoparticles and viscosifiers (VES). To achieve this objective, foam stability tests were conducted at different temperatures up to 150°F. Foam stability was studied in a high-pressure view chamber (HPVC) to find the optimal. Single and dual-coreflood experiments were conducted at 150°F to investigate the divergent ability for the foam solutions on heterogonous sandstone formations. Boise and Berea sandstone cores with permeability contrast of 10-15 were saturated initially with a dead crude oil. The CO2 foam was injected with 80% quality as tertiary recovery mode. The oil recovery and the pressure drop across the core were measured for the different foam solutions.
Adding silica nanoparticles (0.1 wt%) of size 140 nm and viscoelastic cocamidopropyl betaine surfactant (cocobetaine VES) (0.4 wt%) to the AOS (0.5 wt%) solution improves foam stability. In contact with crude oil, unstable oil-in-water microemulsion generated inside the foam lamella that decreased foam stability. A weak foam was formed for AOS solution, but the foam stability increased by adding nanoparticles and VES. From the single coreflood experiments, the oil recovery from the conventional water flooding 47% of the original oil-in-place. AOS was not able to enhance the oil recovery. No more oil was recovered by AOS foam, however, extra oil was recovered in the presence of nanoparticles (19 %) and VES (26%). The dual-coreflood experiments revealed low sweep efficiency during the water flooding as a secondary recovery. Adding nanoparticles and VES to the AOS foam system increased the sweep efficiency and increased the oil recovery from the low permeability cores.
Nanoparticles and VES were able to improve the foam stability for AOS solution. Adding nanoparticles is highly recommended for EOR applications, particularly at high temperatures.
Almubarak, Tariq (Texas A&M University) | Ng, Jun Hong (Texas A&M University) | Sokhanvarian, Khatere (Sasol Performance Chemicals, Texas A&M) | AlKhaldi, Mohammed (Saudi Aramco EXPEC ARC) | Nasr-El-Din, Hisham (Texas A&M University)
As exploration for oil and gas continues, it becomes necessary to produce from formations that are deeper, have low permeability, and higher temperature. Conventionally, guar and its derivatives have been successfully utilized as hydraulic fracturing fluids. However, they require higher polymer loading to withstand the high-temperature environments. This leads to an increase in mixing time and additive requirements. Most importantly, 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 for high-temperature applications. 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 concentrations ranging from 20 to 40 lb/1,000 gal at a ratio of 2:1, 1:1, and 1:2. The fluids were crosslinked with a metallic crosslinker and broken with an oxidizer at 300-350°F. Testing focused on crosslinker to polymer ratio analysis to effectively lower loading while maintaining sufficient performance to carry proppant at these harsh conditions. HP/HT rheometer was used to measure viscosity and elastic modulus. HP/HT see-through cell was utilized for proppant settling.
Results indicate that the dual polymer fracturing fluid is able to generate stable viscosity at 300-350°F and 100 s-1. Results show that the dual polymer fluid can generate higher viscosity compared to the individual single polymer system. Also, properly understanding and tuning the crosslinker to polymer ratio generates excellent performance even at 20 lb/1,000 gal. The two polymers form a shared crosslinking network that improves proppant carrying capacity at lower polymer loadings and high temperatures. It also demonstrates a clean and controlled break performance with an oxidizer.
The major benefit of using a mixed polymer system is to reduce polymer loading at harsher conditions. Lower loading is highly desirable because it reduces material cost, eases field operation and lowers damage to the fracture face, proppant pack and formation.