Relative Permeability Modifiers as a Chemical Means to Control Water Production in Oil and Gas Reservoirs

It is challenging to control water production in horizontal wells or in vertical wells having oil and water produced from the same zone using conventional methods such as through-tubing bridge plugs or other mechanical means. Relative permeability modifiers (RPMs), known to selectively reduce the relative permeability to water with minimum impact on the relative permeability to oil or gas, are considered a promising technology for solving this problem. The current generation of RPMs, unlike the old ones, can tolerate high hardness and so have higher success rates. An extensive experimental work was carried out to evaluate three RPMs for water control in gas and oil wells. Test conditions included gas flow in sandstone cores with temperatures of up to 300°F, and oil flow in carbonate cores with temperatures as high as 220°F. The effect of initial core permeability to brine, RPM concentration, flow rate, and water-wetting surfactants on the effectiveness of RPM to reduce water production was investigated using sandstone and carbonate cores. Coreflood experiments were undertaken at downhole conditions. The end-point relative permeabilities to various phases were measured. A back pressure of 500 psi, an overburden pressure of 3,500 to 5,000 psi and flow rates of 0.1 to 5 cm3/min were used. The concentration of RPM polymers was monitored in the core effluent using total organic carbon (TOC) analyzer to determine polymer retention in the core. The results revealed that temperature adversely affected the effectiveness of all RPMs evaluated. A better reduction in permeability to water was obtained at 220°F compared to that obtained at 300°F. The use of RPM at the right concentrations was found to significantly reduce permeability to water. A better water reduction was obtained at higher polymer injection rates, which was attributed to flow-induced polymer retention. Adsorption of RPM polymer tended to alter wettability of a carbonate rock to more water-wet. This paper discusses the effects of the above parameters on the performance of RPM in sandstone and carbonate reservoirs, and it gives some recommendations for improving the success rate of these chemical applications in the field.

SmartWater Synergy with Microsphere Injection for Permeable Carbonates

This paper presents a laboratory study on combination of SmartWater with microsphere injection to improve oil production in carbonates, which increases the sweep efficiency and oil displacement efficiency. In this study, the properties of a micro-sized polymeric microsphere were investigated including size distribution, rheology, and zeta potential in SmartWater, compared with conventional high salinity injection water. Coreflooding tests using natural permeable carbonate cores were performed to evaluate flow performance and oil production potential at 95°C and 3,100 psi pore pressure. The flow performance was evaluated by the injection of 1 pore volume microspheres, followed by excessive water injection. Oil displacement tests were also performed by injecting 1 pore volume of microspheres dissolved in SmartWater after conventional waterflooding. The median particle size of the microsphere in conventional injection water with a salinity of 57,670 ppm was about 0.25 µm. The particle size was increased by 50% to 100% with reduced elastic modulus when the microsphere dispersed in SmartWater with lower salinity. The zeta potential value of microsphere was decreased in SmartWater compared to that in conventional injection water, showing more negatively charge property. Flow performance of microsphere solutions in the carbonate cores was found to be dependent on their particle size, strength, and suspension stability. The results from coreflooding tests showed that the microsphere dispersed in SmartWater would result in higher differential pressure than that observed in conventional injection water. The SmartWater caused the microspheres swell to larger but softer particles with better suspension stability, which enhanced both the migration and blocking efficiency of microsphere injection. The oil displacement tests confirmed that the microsphere in SmartWater displaced more oil than that obtained with conventional injection water. This result was clearly supported by the higher differential pressure from microsphere injection in SmartWater. The oil bank appeared historically in the post water injection stage, which was quite different from the reported findings of typical mobility controlling agents in the existing knowledge. The microspheres were observed in the core flood produced fluids, indicating the improvement of microsphere migration by SmartWater. This work, for the first time, demonstrated that the combination of SmartWater and microsphere injection yields additional oil production. The proposed hybrid technique can provide a cost-effective way to improve waterflooding performance in heterogeneous carbonates.

Injectivity and Propagation of Sulfonated Acrylamide-Based Copolymers in Low Permeability Carbonate Reservoir Cores in Harsh Salinity and Temperature Conditions : Challenges and Learnings from a Middle East Onshore Case Study

Polymer flooding is one of the most mature EOR technology applied successfully in a broad range of reservoir conditions. The last developments made in polymer chemistries allowed pushing the boundaries of applicability towards higher temperature and salinity carbonate reservoirs. Specifically designed sulfonated acrylamide-based copolymers (SPAM) have been proven to be stable for more than one year at 120°C and are the best candidates to comply with Middle East carbonate reservoir conditions. Numerous studies have shown good injectivity and propagation properties of SPAM in carbonate cores with permeabilities ranging from 70 to 150 mD in presence of oil. This study aims at providing new insights on the propagation of SPAM in carbonate reservoir cores having permeabilities ranging between 10 and 40 mD. Polymer screening was performed in the conditions of ADNOC onshore carbonate reservoir using a 260 g/L TDS synthetic formation brine together with oil and core material from the reservoir. All the experiments were performed at residual oil saturation (Sor). The experimental approach aimed at reproducing the transport of the polymer entering the reservoir from the sand face up to a certain depth. Three reservoir coreflood experiments were performed in series at increasing temperatures and decreasing rates to mimic the progression of the polymer in the reservoir with a radial velocity profile. A polymer solution at 2000 ppm was injected in the first core at 100 mL/h and 40°C. Effluents were collected and injected in the second core at 20 mL/h and 70°C. Effluents were collected again and injected in the third core at 4 mL/h and 120°C. A further innovative approach using reservoir minicores (6 mm length disks) was also implemented to screen the impact of different parameters such as Sor, molecular weight and prefiltration step on the injectivity of the polymer solutions. According to minicores data, shearing of the polymer should help to ensure good propagation and avoid pressure build-up at the core inlet. This result was confirmed through an injection in a larger core at Sor and at 120°C. When comparing the injection of sheared and unsheared polymer at the same concentration, core inlet impairment was suppressed with the sheared polymer and the same range of mobility reduction (Rm) was achieved in the internal section of the core although viscosity was lower for the sheared polymer. Such result indicates that shearing is an efficient way to improve injectivity while maximizing the mobility reduction by suppressing the loss of product by filtration/retention at the core inlet. This paper gives new insights concerning SPAM rheology in low permeability carbonate cores. Additionally, it provides an innovative and easier approach for screening polymer solutions to anticipate their propagation in more advanced coreflooding experiments.

Comparative Analysis of Aminopolycarboxylate Chelants Improves Iron Control in Acidizing Operations

Aminopolycarboxylate-based chelants are used to control iron precipitation during acidizing operations by interacting directly with the iron, resulting in water-soluble complexes. This paper highlights that, in order to improve the effectiveness of iron control during acidizing operations, the type and the concentration of the chelants should be based on the formation properties and the well characteristics by comparing the cheltors’ performance as iron-control agents at different temperatures and pH environments with different levels of iron concentrations and chelant to iron molar ratios in acid (HCl). This study also addresses the interactions between the tested iron-control additives and acid, as well as the performance of the chelants in carbonate cores. Laboratory experiments were conducted to investigate the performance of nitrilotriacetic acid (NTA), glutamic acid, N, N-diacetic acid (GLDA), diethylenetriaminepentaacetic acid (DTPA), ethylenediamine-tetraacetic acid (EDTA), and hydroxyethylethylenediaminetriacetic acid (HEDTA) as iron control additives in 5 wt% HCl at pH values 0 to 4.5 to simulate carbonate acidizing at temperatures of 70 to 300°F, and initial iron concentrations of 2000 ppm. The performance of NTA and EDTA was also compared at higher initial iron concentration (4000 ppm). This work also quantified the effects of acid additives such as corrosion inhibitor and non-ionic surfactant on the chelation performance. Coreflood experiments using carbonate cores in acid with chelant helped determine its influence on permeability. Testing chelant-to-acid molar ratios of 1:1, 1.1:1, 1.2:1, 1.3:1, 1.4:1, 1.5:1, and 2:1 relative to iron concentration yielded optimal values. Additional tests monitored iron precipitation in solution using an inductively coupled argon plasma (ICAP) emission spectroscopy. Precipitates were filtered and analyzed using X-ray diffraction (XRD), X-ray fluorescence (XRF), and scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS). Without chelant, at 70°F and 2000 ppm initial iron concentration, precipitation began at pH 1.45 and completed by pH 2.42. At 150 and 210°F, iron precipitated at pH 0.68 and 0.3 and completed by pH 1.3 and 1, respectively. At 70°F, NTA showed a minimum of 98% chelation at pH 4.3; however, its performance declined at 150°F to 74% chelation at pH 4.24, and at 210°F to 53% chelation at pH 4.0. Although DTPA dissolves completely in live acid, precipitations occurred at partially spent acid. At pH 0.15, SEM-EDS showed that the precipitate contains as much as 13 wt% iron. Thus, DTPA is not a suitable iron-control agent. HEDTA showed a 90% chelation at 210°F and pH 4.8. GLDA's performance declined to less than 50% at 150°F. At higher iron concentrations of 4000 ppm, Na3NTA kept all iron in solution in a 5 wt% HCl up to pH 4.0 at 70°F and its performance declined to a minimum of 97% at pH 4.7 at same temperature. At 150°F, and 210°F, Na3NTA started to gradually decline at pH values greater than 3.9, and 3.5, respectively. The minimum chelation reached by NTA was 91% at pH 4.4, at 150°F, and 73% at pH 4 at 210°F. Upon comparing the NTA's results at high iron concentrations to the popular EDTA, Na4EDTA at 1-to-1 mole ratio with iron exceeded its maximum solubility in 5 wt% HCl and precipitated in the original solution. For NTA, a molar ratio of 1.4:1 is optimal at 70 and 150°F, showing chelation performance of 95% and 94%, respectively, while a molar ratio of 1.5:1 is optimal at 210°F, showing a chelation performance of 87%. This study's results improve field operations by identifying NTA and HEDTA as having the best iron-control chelation performance of the five additives tested, thus reducing guesswork and streamlining production. The work also provided recommendations for choosing the best type of iron-control agent based on solubility and coreflood analysis. The results can be used to design more efficient acidizing fluids. This work won second place in the Masters division of the 2020 Gulf Coast Regional Student Paper Contest, April 2020.

Green Enhanced Oil Recovery for Carbonate Reservoirs

Green enhanced oil recovery (GEOR) is an eco-friendly EOR technique involving the injection of specific green fluids to improve macroscopic and microscopic sweep efficiencies, boosting residual oil production. The environmentally friendly surfactant-polymer (SP) flood is successfully tested in a sandstone reservoir. However, the applicability of the SP method does not extend to carbonate reservoirs yet and requires comprehensive investigation. This work aims to explore the oil recovery competency of a green SP formulation in carbonate through experimental and modelling studies. Numerous formulations of SP with ketone, alcohol, and organic acid are selected based on phase behavior and interfacial tension (IFT) reduction capabilities to examine their potential for enhancing residual oil production from carbonate cores. A blending of nonionic green surfactant alkyl polyglucoside (APG), xanthan gum (XG) biopolymer, and butanone recovered 22% tertiary oil from the carbonate core. This formulation recovered more than double residual crude than that of the APG, XG, and acetone. Similarly, a combination of APG, XG, acrylic acid, and butanol increased significantly more oil than the APG, XG, and acrylic acid formulation. The APG, XG, and butanone mixture is efficient with regards to boosting tertiary oil recovery from the carbonate core.

Cost-Effective Chemical EOR for Heterogenous Carbonate Reservoirs Using a Ketone-Surfactant System

The complexity, high cost, and potential environmental concerns of chemical enhanced oil recovery (EOR) methods have diminished their field applications considerably. However, considering the significant incremental oil recoveries that can be obtained from these methods encourage researchers to explore ways to reduce both complexity, cost, and environmental concerns of such systems. This is especially important in carbonate formations, where after waterflooding, much of the oil remains trapped in complex reservoir pores—especially if the reservoir contains an interconnected fracture network of flow channels within the bulk rock matrix. In this paper, we present an experimental assessment of several simple chemical EOR waterflooding systems comprising of small concentrations of a low cost, low molecular weight ketone and a non-ionic surfactant in association with low-salinity brine. The experiments were conducted in carbonate cores from a Permian Basin San Andres Formation. Four different oil displacement scenarios were investigated using San Andres carbonate cores from the Central Vacuum Field in New Mexico. This included 1) low-salinity brine, 2) low-salinity brine with a surfactant, 3) low-salinity brine with a ketone, and 4) low-salinity brine with a combined ketone-surfactant system. Static imbibition experiments were conducted using a spontaneous imbibition apparatus in addition to the use of a high-speed centrifuge to saturate the cores to irreducible brine saturation. Adding a 1% concentration of 3-pentanone and a 1% non-ionic surfactant to a low-salinity brine yielded oil recoveries of 44% from the 3-pentanone system, compared to 11.4% from low-salinity brine only. The oil recovery is enhanced by a single mechanism or synergy of several mechanisms that includes interfacial tension (IFT) reduction by surfactant, capillary imbibition, favorable wettability alteration by ketone, and osmotic low-salinity brine imbibition. The IFT decreased to 1.79 mN/m upon addition of non-ionic surfactant to low-salinity brine, and it reduced to 2.96 mN/m in a mixture of 3-pentanone and non-ionic surfactant in low-salinity brine. Furthermore, ketone improved the core wettability by reducing the contact angle to 43.9° from 50.7° in the low-salinity brine experiment. In addition, the low-salinity brine systems caused mineral dissolution, which created an alkali environment confirmed by an increase in the brine pH. We believe the increase in pH increased the hydrophilic character of the pores; thus, increasing oil recovery.

Analytical Model for Estimation of Pore Volume to Breakthrough in Carbonate Acidizing with Organic and Mineral Acids

Acidizing is one of the most useful methods in the oil well stimulations. This treatment technique creates capillary wormholes in the carbonate formations to enhanced fluids flow production of a reservoir. One of the main indexes for recognizing the wormhole characterization is the pore volume to breakthrough number. Therefore, calculating this number is one of the main goals in the carbonate acidizing. Obtaining this number is always required for experimental works, which needs time, energy and cost. In this article, an empirical model was used to evaluate carbonate acidizing procedure in the limestone and dolomite cores as the carbonate cores. This empirical model measures the number of wormholes formed in the carbonate cores after acid injection by using the conservation of mass law. In this method, the transport relative reaction rates of acid and core inside the structure of wormhole was maintained during the wormhole creation process. Growing the wormhole in the carbonate formation was developed step by step. Changes in acid concentration as an injected fluid flow were accounted for in this empirical model. Also, the changes in carbonate porosity, the effect of Damköhler number, and injection rate were included in the model. Two types of carbonate rocks and five types of acids with different molar masses were used in this model for the analysis and validation of the model. The results from experimental works was significance and justifies the use of use of the law for mass transport and chemical reactions. Evaluation of the developed model with other experimental and numerical results gave an excellent assessment of 95.45% for the average accuracy and 0.9933 for the average coefficient of determination. Therefore, an empirical technique to approximate the pore volumes to breakthrough number in the limestone and dolomite cores with high accuracy using physical core and acid properties is proposed.