High-temperature Reservoirs Research Articles

Characteristics of microbiota, core sulfate-reducing taxa and corrosion rates in production water from five petroleum reservoirs in China

Microbial diversity and activities in petroleum reservoir systems can be altered by water-flooding operation, but the current understanding of the mechanism for such changes in microbial composition characteristics and community is inadequate. In this study, microbial communities especially functional groups in production water from five petroleum reservoirs in China were investigated by chemical and molecular biological analyses. The dominant and core phyla in the five oil reservoirs were Proteobacteria, Deferribacterota, Firmicutes, Desulfobacterota, Euryarchaeota and Thermoplasmatota. At the genus level, the dominant taxa in each petroleum reservoir were different, and not all of the dominant genera were the core members across the five oil reservoirs. The microbiologically influenced corrosion (MIC) were investigated for the functional groups in each production water. The corrosion rates in production water were higher than controls with a positive correlation to the abundances of sulfate-reducing prokaryotes (SRP). The SRP diversity based on the aprA and dsrA gene analysis showed that obvious differences were evident between onshore (JS, SL, DQ and XJ) and offshore (BS) oilfields. The core SRP taxa in onshore oilfields were Desulfomicrobium and Desulfovibrio, also with Desulfotomaculum in medium/low-temperature oil reservoirs (DQ and XJ), but in high-temperature petroleum reservoirs (JS, BS and SL), Archaeoglobus, Thermodesulfobacterium and Thermodesulfovibrio were the core groups. Statistical analysis indicated that temperature, electron acceptors and donors showed significant influence on the SRP community. This research reveals the characteristics of microbial and functional community as well as their interaction mechanism on corrosion in petroleum reservoir environments, and will improve industrial bio-control and management of MIC in oilfields.

How the Brain Becomes the Mind: Can Thermodynamics Explain the Emergence and Nature of Emotions?

The neural systems’ electric activities are fundamental for the phenomenology of consciousness. Sensory perception triggers an information/energy exchange with the environment, but the brain’s recurrent activations maintain a resting state with constant parameters. Therefore, perception forms a closed thermodynamic cycle. In physics, the Carnot engine is an ideal thermodynamic cycle that converts heat from a hot reservoir into work, or inversely, requires work to transfer heat from a low- to a high-temperature reservoir (the reversed Carnot cycle). We analyze the high entropy brain by the endothermic reversed Carnot cycle. Its irreversible activations provide temporal directionality for future orientation. A flexible transfer between neural states inspires openness and creativity. In contrast, the low entropy resting state parallels reversible activations, which impose past focus via repetitive thinking, remorse, and regret. The exothermic Carnot cycle degrades mental energy. Therefore, the brain’s energy/information balance formulates motivation, sensed as position or negative emotions. Our work provides an analytical perspective of positive and negative emotions and spontaneous behavior from the free energy principle. Furthermore, electrical activities, thoughts, and beliefs lend themselves to a temporal organization, an orthogonal condition to physical systems. Here, we suggest that an experimental validation of the thermodynamic origin of emotions might inspire better treatment options for mental diseases.

Experiment on Gas–Liquid Sulfur Relative Permeability under High-Temperature High-Pressure Sour Gas Reservoir Condition

In the development of high temperature sour gas reservoirs, gas–liquid sulfur two phase percolations exist, which have a significant impact on the gas permeability and gas well productivity. There are currently few reports on experimental studies on gas–liquid sulfur relative permeability. This study improves the experimental equipment and process, and it proposes an experimental method for measuring the gas–liquid sulfur relative permeability curve. Several typical core samples from a sour gas reservoir in Sichuan Basin, China were selected for experimental study, and the gas–liquid sulfur relative permeability under high temperature and high pressure (HTHP) was measured. The results show that, first, the critical flowing saturation of liquid sulfur was 40%, and the gas–liquid sulfur co-flow zone was narrow. With the increase in the liquid sulfur saturation, the gas relative permeability decreased rapidly. Second, the better the physical properties of the core, the greater the damage of liquid sulfur to the core properties. The residual liquid sulfur saturation of the fractured core was higher than matrix core, and as liquid sulfur saturation increased, so did the damage to gas permeability. Third, temperature had an effect on the gas–liquid sulfur relative permeability. Gas relative permeability decreased as the temperature rose, while the liquid sulfur relative permeability remained essentially constant. Fourth, the rock effective stress had a significant impact on the gas–liquid sulfur relative permeability. The relative permeability of gas and liquid sulfur decreased as the effective stress increased, and the fractured core was more sensitive to stress.

Dynamic Behaviors and Mechanisms of Air-Foam Flooding at High Pressure and Reservoir Temperature via Microfluidic Experiments.

Air injection has been proven to be an effective improved oil recovery technique for deep and light oil reservoirs with low permeability and poor water injectivity. But the efficiency of air injection in highly heterogeneous reservoirs is low due to poor gas sweeping that may lead to early oxygen breakthrough caused by gas channeling and viscous fingering. Foam can be used to assist air injection to overcome the obstacles of early gas breakthrough and to increase the displacement and sweeping efficiency. In this paper, laser-etched visual microscopic pore models were used as microfluidic devices to study the air-foam flooding process in porous media at reservoir temperature and high pressure. The dynamic behaviors and relevant mechanisms of air-foam flooding were investigated. Typical mechanisms of foam generation in porous media are achieved in different parts of the micromodel, which can be listed as follows: lamella leave-behind, lamella division, and snap off. Analysis on flow states of air foam showed that foams migrate in porous media by bursting and regenerating during the flooding process. It can be observed that the flow mode of foam in porous media is the separate flow of gas and liquid through microscopic displacement experiments, suggesting that foam should not be treated as a homogeneous phase in heterogeneous porous media. The pressing, occupying, and selective blocking effects of foam in porous media exhibited different oil displacement performances with the presence of various pore geometries and networks. Tiny foams also showed stripping and carrying effects on larger oil droplets benefiting from the lipophilicity of foam. Through comprehensive analysis on overall and local oil displacement mechanisms, air-foam injection could enhance the microscopic sweep volume and improve the oil displacement efficiency.

Study of the reinforced mechanism of fly ash on amphiphilic polymer gel

Amphiphilic polymer gels are widely used in heterogeneous reservoirs for conformance control technology. However, in high temperature and high salinity of calcium and magnesium reservoirs, amphiphilic polymer gels cannot maintain effective performance. In this work, a novel reinforced amphiphilic polymer gel (F-PADC gel) was prepared by physically mixing polymer solution and fly ash (FA), which is an extremely low cost material. The viscoelasticity and stability of the F-PADC gel were studied by rheometry and micro-rheometry. The reinforced mechanism of FA on amphiphilic polymer gels was revealed. The results show that the addition of FA can make the gel more robust with a denser network structure. On the fifth day, the elastic modulus ( G ′) increases from 5.2 to 7.0 Pa and the viscosity modulus ( G ″) increases from 0.4 to 0.6 Pa at the frequency of 1 Hz, which improves the viscoelasticity of the gel system. More importantly, the F-PADC gel does not degrade after aging at 85 °C for 180 d. And its viscoelasticity increases obviously, G ′ and G ″ increase to 110.0 Pa and 3.5 Pa, respectively, showing excellent anti-aging stability. Moreover, FA amphiphilic polymer gels have a good injectivity and a perfect plugging rate of 98.86%, which is better than that of sole amphiphilic polymer gels. This novel mixed FA amphiphilic polymer gels can prove to be a better alternative to conventional polymer gels to enhance oil recovery in high temperature and high salinity reservoirs.

An evaluation framework for production performance of high-temperature fractured and karstified geothermal reservoirs: Production mechanism, sensitivity study, and key parameters ranking

High-temperature (>150 °C) geothermal resources have great potential for sustainable power generation. These geothermal resources can be exploited efficiently through highly permeable geological structures, i.e. tectonic fractures and dissolution caves, which thus are categorized as fractured and karstified geothermal reservoirs. However, the study of long-term cold fluids injection into these high-temperature geothermal systems is faced with significant unsolved challenges, i.e. the simulation of coupled porous media flow and free flow in multiscale and heterogeneous fracture-cave networks with distinct thermo-hydro-mechanical (THM) coupling effects. To address these challenges, we develop a novel coupled THM model based on the discrete fracture-cave network approach. We then apply this model to perform the analysis of THM coupling mechanism, sensitivity study, and key parameters ranking to identify the development characteristics of high-temperature geothermal reservoirs. Results show that with respect to coupled THM processes, the fluid flow and heat transfer are dominated by connected fracture clusters and are strongly influenced by the inclusion of caves. However, the behavior of solid deformation is governed by the distribution of caves. As to the reservoir thermal performance under different working fluids, i.e. water and CO2, the water-based geothermal reservoir exhibits longer service life, greater global thermal power, and higher heat extraction rate than the CO2-based one. Regarding sensitivity analysis and key factors ranking, fracture attributes (fracture length and density) are the two most important parameters in regulating the geothermal extraction performance. Caves fall out as the third most significant parameter. However, the operating parameters (i.e. injection temperature, injection pressure, production pressure, well length, and well distance) play a limited role in influencing thermal performance compared with geometrical parameters of fractures and caves. The developed model and insights obtained from our research have crucial implications for understanding and optimizing the thermal production of high-temperature fractured and karstified geothermal reservoirs.

Silicate Scaling Formation: Impact of pH in High-Temperature Reservoir and Its Characterization Study

Silicate scaling tends to form and be aggravated during high pH Alkaline Surfactant Polymer (ASP) floods and this silicate scale deposition affects oil production. Hence, it is important to examine the conditions that lead to silicate scale forming. The severity of the silicate scaling reaction, the type and morphology of silica/silicate scale formed in an experimental ASP flood were studied for pH values 5, 8.5, and 11, whilst the temperature was kept constant at 90 ℃. In addition, the impact of calcium ion was studied and spectroscopic analyses were used to identify the extent of scaling reaction, morphology type and the functional group present in the precipitates. This was performed using imagery of the generated precipitates. It was observed that the silica/silicate scale is most severe at the highest pH and Ca:Mg molar ratios examined. Magnesium hydroxide and calcium hydroxide were observed to precipitate along with the silica and Mg-silicate/Ca-silicate scale at pH 11. The presence of calcium ions altered the morphology of the precipitates formed from amorphous to microcrystalline/crystalline. In conclusion, pH affects the type, morphology, and severity of the silica/silicate scale produced in the studied scaling system. The comprehensive and conclusive data showing how pH affects the silicate scaling reaction reported here are vital in providing the foundation to further investigate the management and prevention of this silicate scaling. Copyright © 2022 by Authors, Published by BCREC Group. This is an open access article under the CC BY-SA License (https://creativecommons.org/licenses/by-sa/4.0)

Laboratory Comparative Study of Anionic and Cationic High-Viscosity Friction Reducers in Moderate to Extremely High Total Dissolved Solids Environments

Summary High-viscosity friction reducers (HVFRs) have been recently gaining more attention and increasing in use, not only as friction-reducing agents but also as proppant carriers. Reusing produced water has also been driven by both environmental and economic benefits. Currently, most friction reducers on the market are anionic friction reducers, which are fully compatible with most produced water with low to medium level of total dissolved solids (TDS) but show a significant drop at high TDS conditions in terms of their friction reduction performance in most cases. On the contrary, cationic friction reducers are believed to have better TDS tolerance and friction reduction performance under high TDS conditions. However, concerns remain about performance of using anionic and cationic HVFRs with produced water to transport proppant. The ultimate objective of this experimental study is to comparably analyze the proppant transport capabilities of anionic and cationic HVFRs in high TDS and reservoir temperature environments. An anionic HVFR and a cationic HVFR, both at 4 gallons per thousand gallons (GPT), were selected and analyzed. The rheology measurements of these anionic and cationic HVFRs were conducted in deionized (DI) water and high TDS water conditions. Static and dynamic proppant settling tests were conducted at various TDS conditions at reservoir temperature. Wall retardation and particle hindering on the performance of both anionic and cationic HVFRs were also observed and investigated using the particle image velocimetry (PIV) method. The results showed that the anionic HVFR had higher viscosity than the cationic HVFR due to larger molecular weight and had much higher elasticity. Increase in TDS concentration would decrease the viscous and elastic profiles of both anionic and cationic HVFRs. In particular, the elastic profile became negligible for both HVFRs. Besides, the “critical salinity” phenomenon was observed. Above this salinity, the viscosity of HVFRs was no longer affected by increasing TDS level. The “critical salinity” for both of the 4-GPT anionic and cationic HVFRs was in the range of 30 000 to 200 000 mg/L. Moreover, the cationic HVFR had lower “critical salinity” than the anionic HVFR. Finally, the correlation between rheology and proppant transport capabilities of HVFRs is discussed in this paper, and a simplified decision-making process of selecting fracturing fluids is proposed.

Development and Performance Evaluation of a Selective Plugging System for High-Temperature and High-Salinity Water-Bearing Gas Reservoir

In the development of natural gas reservoirs, the water produced in wells will cause a decline in gas well productivity. In this study, a selective frozen gel plugging agent system suitable for water plugging in gas reservoirs under conditions of high temperature and high salinity. The plugging capacity of the gel system was evaluated. The experimental results showed that: (1) the optimal experimental scheme of the frozen gelling system was as follows: 107 °C with 1.0% AM-AMPS +0.6% p-benzenediol +0.6% hexamethylenetetramine +0.2% thiourea. (2) The optimal injection volume of the system for water phase plugging was 0.5 PV, and the system has an excellent plugging effect at a permeability of 356–3118 mD. (3) The system could also effectively improve the degree of heterogeneity, and the smaller the degree of heterogeneity, the better the improvement effect. (4) The gel system had a good effect on different plugging methods, and the gas medium did not affect the plugging performance. This study provides a sufficient theoretical basis for the exploitation of high-temperature and high-salinity water-bearing gas reservoirs through experimental research, which is of great significance for improving production capacity.

Preparation of supramolecular viscoelastic polymers with shear, temperature, and salt resistance/sensitivity by amphiphilic functional monomer modification

To develop high-salinity, high-temperature reservoirs, a novel supramolecular viscoelastic polymer-based fracturing fluid modified with an amphiphilic functional monomer was developed. Investigation of the thickening ability, solubility, and rheology revealed that the as-developed gel system with a rigid hydrophobically associating space network structure and linear entanglement can improve the thickening ability, solubility, temperature adaptation range, and chemical environment resistance sensitivity of supramolecular polymers. The surface/interfacial tension test revealed that the modified polymers exhibit surface and interface activity. At an MHAP-15 concentration of 1500 mg/L, the surface tension was 39.29 Nm/m. At an MHAP-15 concentration of 800 mg/L, a minimum interfacial tension of 0.86 Nm/m was observed. The shear sensitivity test revealed that the copolymer fluid exhibits a high creep recovery performance and elastic response as well as a 100% viscosity recovery rate. In addition, the viscoelasticity and thixotropy of the copolymer solution were investigated. The results revealed that the higher the number of the oxyethylene groups in amphiphilic functional monomers, the higher the increase in the viscous modulus of the copolymer solution. In the modified polymer, the highest energy was required for the destruction of the MHAP-15 solution, reaching 66.5 Pa; this result confirmed the best synergistic effect of hydrophobic association and linear entanglement of the MHAP-15 solution molecules, as well as the best temperature and salt resistance. The viscosity of 0.6 wt% MHAP-15 was 120 mPa s after shearing for 50 min at 120 °C and at 170 s−1. At 160 °C and 100 s−1, the viscosity of the 0.8 wt% MHAP-15 polymer solution reached 153 mPa s after shearing for 50 min. At a NaCl concentration of 25 × 104 mg/L, the viscosities of the 0.6 wt% and 0.8 wt% MHAP-15 solutions were 203 and 245 mPa s, respectively, indicative of the stimulation response of salt thickening. At a CaCl2 concentration of 2 × 104 mg/L, the viscosity of 0.6 wt% MHAP-15 was 87 mPa s, and the viscosity retention rate was 47.9%. Finally, by X-ray diffraction, the particle size test in solution, and scanning electron microscopy, the higher the number of oxyethylene groups in the amphiphilic functional monomers, the higher the mixing entropy of copolymers, and the particle size in solution and multi-peak distribution were higher, as well as more clear linear entanglement between copolymers; all of these factors were conducive to the formation of large-scale supramolecular structures of super-bridged copolymers.

Preparation and migration study of multi-walled carbon nanotube hybrid polymer gel particles: EOR implication

Multi-walled carbon nanotube hybrid polymer gel particles (MWCNTs-HPGP) were synthesized using the free radical polymerization approach to reduce water cut at first. The microstructure, particle size distribution, swelling characteristics, strength, and rheology of MWCNTs-HPGP were then studied. Subsequently, the migration and plugging properties of MWCNTs-HPGP were assessed at the core scale. The morphology of MWCNTs-HPGP was irregular with interpenetration networks, and MWCNTs-HPGP could expand by 48.2–94 times in brine with varying salinities (0 ∼ 20 × 104 mg/L NaCl), according to experimental results. After 60 d of age, MWCNTs-HPGP retained 95.2% of strength. Furthermore, the MWCNTs-HPGP dispersion solution’s shearing thinning feature and good viscoelasticity supplied it with favorable injectivity and deep migrating capacity. In addition, when the matching coefficient (β, the ratio of MWCNTs-HPGP median particle size to the average pore diameter) was 1.06 and the flooding rate was 0.5 mL/min, MWCNTs-HPGP could efficiently plug large pores with a plugging efficiency ranging from 82.7% to 98.5%. All the experimental results demonstrated that MWCNTs-HPGP could be a potential candidate for deep profile control and displacement in high temperature and high salinity reservoirs.

Thermally Insulating, Thermal Shock Resistant Calcium Aluminate Phosphate Cement Composites for Reservoir Thermal Energy Storage.

This paper presents the use of hydrophobic silica aerogel (HSA) and hydrophilic fly ash cenosphere (FCS) aggregates for improvements in the thermal insulating and mechanical properties of 100- and 250 °C-autoclaved calcium aluminate phosphate (CaP) cement composites reinforced with micro-glass (MGF) and micro-carbon (MCF) fibers for deployment in medium- (100 °C) and high-temperature (250 °C) reservoir thermal energy storage systems. The following six factors were assessed: (1) Hydrothermal stability of HSA; (2) Pozzolanic activity of the two aggregates and MGF in an alkali cement environment; (3) CaP cement slurry heat release during hydration and chemical reactions; (4) Composite phase compositions and phase transitions; (5) Mechanical behavior; (6) Thermal shock (TS) resistance at temperature gradients of 150 and 225 °C. The results showed that hydrophobic trimethylsilyl groups in trimethylsiloxy-linked silica aerogel structure were susceptible to hydrothermal degradation at 250 °C. This degradation was followed by pozzolanic reactions (PR) of HSA, its dissolution, and the formation of a porous microstructure that caused a major loss in the compressive strength of the composites at 250 °C. The pozzolanic activities of FCS and MGF were moderate, and they offered improved interfacial bonding at cement-FCS and cement-MGF joints through a bridging effect by PR products. Despite the PR of MGF, both MGF and MCF played an essential role in minimizing the considerable losses in compressive strength, particularly in toughness, engendered by incorporating weak HSA. As a result, a FCS/HSA ratio of 90/10 in the CaP composite system was identified as the most effective hybrid insulating aggregate composition, with a persistent compressive strength of more than 7 MPa after three TS tests at a 150 °C temperature gradient. This composite displayed thermal conductivity of 0.28 and 0.35 W/mK after TS with 225 and 150 °C thermal gradients, respectively. These values, below the TC of water (TC water = 0.6 W/mK), were measured under water-saturated conditions for applications in underground reservoirs. However, considering the hydrothermal disintegration of HSA at 250 °C, these CaP composites have potential applications for use in thermally insulating, thermal shock-resistant well cement in a mid-temperature range (100 to 175 °C) reservoir thermal energy storage system.

Geochemical distribution of helium, hydrogen, carbon dioxide, and methane in Sakhalin Island mud volcanoes, hot springs, and cold seeps

The Asian-Pacific - continental margins have been the object of intensive geochemical research in recent years, as areas within this zone have been found to contain large hydrocarbon deposits in a variety of forms including: oil, natural gas, gas condensate, and gas hydrates. One such area is Sakhalin Island, located in Russia's Far Eastern Federal District. Genetically, the territory of Sakhalin Island is a part of the shelf of the Hokkaido-Sakhalin fold area, therefore, the nature of the sub-vertical gas migration is controlled by deep faults, along which the concentrations of natural gases change, and is also influenced by high seismotectonic activity of the Okhotsk region. This paper presents data regarding the distribution of helium, hydrogen, carbon dioxide and methane from mud volcanoes, thermal springs, mineral waters and other seep types on Sakhalin island and the surrounding marine margins, along with an interpretation of the geological and tectonic factors that have likely led to the present distribution of these gases. In general, the results of geothermometry equations based on the concentration and stable isotopic composition of carbon dioxide indicate much higher temperatures than equations involving the saturation concentrations of hydrogen gas. We interpret this to indicate that deeply-sourced carbon dioxide does not reequilibrate at near-surface conditions, whereas the equilibration time for hydrogen gas is relatively rapid. Areas on the island which are observed to have active degassing, coupled with high apparent reservoir temperatures also provide indicators of geodynamics along the regional tectonic structures. Mud volcanoes to the south of the island are predominantly situated at the juncture between NW-SE trending faults which extend the entire length of Sakhalin and continue as far south as Hokkaido Island, and more recently developed NE-SW trending faults. Despite the relatively low water temperatures of these mud volcanoes, the high reservoir temperatures indicated by gas chemistry suggest a source of fluids and gas at several km from the surface.

Experimental Realization of a Quantum Refrigerator Driven by Indefinite Causal Orders.

Indefinite causal order (ICO) is playing a key role in recent quantum technologies. Here, we experimentally study quantum thermodynamics driven by ICO on nuclear spins using the nuclear magnetic resonance system. We realize the ICO of two thermalizing channels to exhibit how the mechanism works, and show that the working substance can be cooled or heated albeit it undergoes thermal contacts with reservoirs of the same temperature. Moreover, we construct a single cycle of the ICO refrigerator based on the Maxwell's demon mechanism, and evaluate its performance by measuring the work consumption and the heat energy extracted from the low-temperature reservoir. Unlike classical refrigerators in which the coefficient of performance (COP) is perversely higher the closer the temperature of the high-temperature and low-temperature reservoirs are to each other, the ICO refrigerator's COP is always bounded to small values due to the nonunit success probability in projecting the ancillary qubit to the preferable subspace. To enhance the COP, we propose and experimentally demonstrate a general framework based on the density matrix exponentiation (DME) approach, as an extension to the ICO refrigeration. The COP is observed to be enhanced by more than 3 times with the DME approach. Our Letter demonstrates a new way for nonclassical heat exchange, and paves the way towards construction of quantum refrigerators on a quantum system.

Catanionic Surfactants for Improving Oil Production in Carbonate Reservoirs

Summary This paper presents the development of catanionic surfactants composed of cationic and anionic surfactants to make them high-performance products for chemical flooding in high-temperature and high-salinity carbonate reservoirs. The objective of this study is to optimize the surfactant chemistry by mixing oppositely charged anionic surfactants and cationic surfactants (CASs), which results in significant synergistic effects in interfacial properties due to electrostatic attraction to improve oil production at the given harsh conditions. The optimal mixing surfactant ratios were determined according to the brine-surfactant compatibility, microemulsion phase behavior, and the interfacial tension (IFT) between oil and surfactant solutions in high-salinity brine at 90°C. Comprehensive performance of the catanionic surfactants was evaluated, including adsorption of the surfactants onto the carbonate rocks and the long-term stability at 95°C. The coreflooding displacement experiments were performed using carbonate core plugs at 95°C to evaluate the potential of the optimal catanionic surfactant in improving oil recovery. Three catanionic surfactants with good compatibility were developed in this study. It appeared that the synergistic effect between the mixing surfactants was enhanced with increasing temperature. Although the IFT of the individual surfactants with crude oil was between 10−1 and 100 mN/m, a significant IFT reduction in the magnitude of 10−2 to 10−3 mN/m was observed by mixing the selected anionic surfactants and CASs. A salinity scan showed that the IFT values maintained a value of 10−2 mN/m in a wide salinity range, which demonstrated the effectiveness of the catanionic surfactant. In microemulsion phase behavior studies, the developed catanionic surfactant solution in the presence of crude oil exhibited Winsor Type III emulsions. The static adsorption quantities of the catanionic surfactants were lower than the values of the individual surfactants. All these indicated the feasibility of catanionic surfactants for their applications in the harsh reservoir conditions. The results of coreflooding displacement tests demonstrated significant oil recovery improvement beyond waterflooding. This work provides an efficient way to get surfactant formulations by mixing oppositely charged surfactants to obtain high performance in improving oil production under harsh conditions.

Minimizing calcium lactate precipitation via the addition of gluconate ions for matrix acidizing with lactic acid

Organic acids are commonly used to replace hydrochloric acid (HCl) in high reservoir temperature applications, as they are less corrosive and weaker than HCl. However, organic acids have shown some problems due to acid reaction product solubility. One such organic acid, lactic acid, produces calcium lactate when it reacts with calcite, which has a low solubility in water. However, reaction product solubility can be improved by up to five times when gluconate ions coexist with lactate and calcium ions. The objective of this research is to evaluate lactic and gluconic acid mixtures in term of dissolving calcite, reaction product, corrosion, wettability and generating dominant wormhole.Lactic and gluconic acids were mixed together using deionized water and seawater to conduct calcite solubility tests. Corrosion tests, between 4 and 12 h, were also run under reservoir conditions. A formation response test (FRT) apparatus was used to run different coreflood tests using different combinations of injection rates, total acid concentration, and temperatures. These tests were accompanied with analytical analysis utilizing ICP and IC to measure calcium, iron and sulfate ions in solution.The results showed that mixing lactic and gluconic acids at a 1:1 M ratio provided the optimal results as no precipitation occurred at total acid strengths of 10 wt% and up to 27 wt%. Seawater usage caused calcium sulfate precipitation; therefore, three scale inhibitors were evaluated to determine mitigation rates. Acid-calcite dissolving results were satisfactory when limestone was exposed to a 1:1 and 2:1 M ratio of crushed core-to-acid ratios as at least 50% of the crushed core was dissolved. However, the two-acid mixture showed a corrosion rate that was higher than the acceptable rates and a trace of iron lactate precipitation occurred at 200 and 300 °F. Five gpt from a sulfur-based corrosion inhibitor was enough to mitigate the corrosion rate to allow for 8 h of testing. Coreflood tests showed that the mixture penetrated limestone core with minimal acid pore volume without any face dissolution or salt precipitation on the core faces.This research presents a set of diverse experimental data to confirm that lactic acid accompanied by gluconic acid can penetrate carbonate formation without any by-product precipitation. The two organic acids are less corrosive and less hazardous which can provide a safe operation environment and can decrease replacement and maintenance costs.

A selective water control and gas augmentation method based on APR gel

Water production will seriously affect the economics of gas well in the development of oil field. However, the conventional water shutoff agent is easy to block the gas flow channel at the same time of plugging the water. In this paper, a temperature and salt resistant polymer gel system composed of acrylamide/acryloyl morpholine/vinylpyrrolidone terpolymer (APR) and polyethyleneimine/modified alumina nanoparticle cross-linker was developed. At the same time, a selective water control and gas augmentation method based on APR gel was established. The effect of gel composition on its performance was mainly studied, and the water & gas shutoff performance in harsh environment was also researched by sandpack flow experiment. The gelation time could be controlled within 2–14 h by adjusting the concentration of the polymer, cross-linker, and deoxidant. In addition, the dehydration rate of the gel was only 2.6% after 180 days heat aging at 107 °C and 230,000 mg/L mineralization. The scanning electron microscope (SEM) showed that the uniform distribution of the network structure resulted in the gel with excellent stability in harsh environments. Sand filling experiments indicated that the plugging rate of gel for sand filling models with different permeability was all above 90% in harsh environment (107 ℃, 230000 mg/L salinity). Besides, laboratory experiments have illustrated that the injection pattern of the gel has a significant influence on its water & gas shutoff performance. Injecting 0.5PV gel solution first, then injecting 6PV N2, the shutoff performance of gel for water was nine times as good as that of gas. The research provides technical guidance for the water shutoff of high-temperature and high-salt gas reservoirs.

Chemical-assisted MMP reduction on methane-oil systems: Implications for natural gas injection to enhanced oil recovery

Miscible natural gas injection is widely considered as a practical and efficient enhanced oil recovery technique. However, the main challenge in this process is the high minimum miscibility pressure (MMP) between natural gas and crude oil, which limits its application and recovery factor, especially in high-temperature reservoirs. Therefore, we present a novel investigation to quantify the effect of chemical-assisted MMP reduction on the oil recovery factor. Firstly, we measured the interfacial tension (IFT) of the methane-oil system in the presence of chemical or CO2 to calculate the MMP reduction at a constant temperature (373K) using the vanishing interfacial tension (VIT) method. Afterwards, we performed three coreflooding experiments to quantify the effect of MMP reduction on the oil recovery factor under different injection scenarios.The interfacial tension measurements show that adding a small fraction (1.5 wt%) of the tested surfactant (SOLOTERRA ME-6) achieved 9% of MMP reduction, while adding 20 wt% of CO2 to the methane yields 13% of MMP reduction. Then, the coreflooding results highlight the significance of achieving miscibility during gas injection, as the ultimate recovery factor increased from 65.5% under immiscible conditions to 77.2% using chemical-assisted methane, and to 79% using gas mixture after achieving near miscible condition. The results demonstrate the promising potential of the MMP reduction to significantly increase the oil recovery factor during gas injection. Furthermore, these results will likely expand the application envelop of the miscible gas injection, in addition to the environmental benefits of utilizing the produced gas by re-injection/recycling instead of flaring which contributes to reducing the greenhouse gas emissions.

Synthesis and Mechanical Properties of Polyacrylamide Gel Doped with Graphene Oxide

Polyacrylamide (PAM)/polyethyleneimine (PEI) gels doped with graphene oxide (GO) were prepared. Their structure and properties were systematically studied by X-ray diffraction (XRD), Fourier transition infrared spectrum (FT-IR), Raman spectroscopy, scanning electron microscopy (SEM), differential scanning calorimetry (DSC), and rheological experiments. The results showed that the graphene oxide (GO) nanosheets were significantly involved in the cross-linking reaction between the main agent (PAM) and the cross-linker (PEI), serving as multi-functional cross-linker and effective reinforcing nanofillers. Increasing the main agent and cross-linker content, the strength of gels was enhanced effectively. The GO could effectively adjust the strength and the gelation time to exhibit characteristics of weak gel, thanks to the improved three-dimensional honeycombed structure with controllable pore size. The DSC confirmed that the PAM/PEI/GO gel exhibited excellent thermal stability and did not dehydrate above 170 °C. This work provides theoretical support for further optimization of polyacrylamide gel used in ultra-deep and high-temperature reservoirs for water control.

Low-temperature in situ CO2 enhanced oil recovery

The new generation in situ CO2 enhanced oil recovery (ICE), which delivers CO2 by injection of a CO2 generating agent solution, was proven to offer robust recovery performances and potential cost and workflow benefits. However, the developed ICE systems are either formulated with a complex fluid recipe or a simplified version of a fluid system limited by high-temperature requirements. This work focused on removing the requirement of high reservoir temperature in our previous work while maintaining the simplicity of the single fluid injection system. Urease is studied as the catalyst for urea hydrolysis and evaluated experimentally. The denaturation behavior of urease and the reaction kinetics of the catalyzed urea hydrolysis process are tested at different urea concentrations, urease concentrations, and temperatures. Four sets of one-dimensional sand pack flowthrough experiments are conducted to verify the tertiary recovery potential of the newly developed low-temperature ICE system with different lithology. The extent of wettability alteration and the recovery mechanism for different lithologies was determined through core sample imbibition experiments and direct contact angle measurements. From the experimental results, urease-catalyzed urea hydrolysis is proven to be effective in tertiary oil recovery applications below the 50 °C reservoir temperature range with urea conversion ratio up to 68.7 %. The selected low-temperature ICE system (10 wt% urea solution with 31 U/g urease) had superior tertiary recoveries(Etr) in the flowthrough test for sandstone(Etr = 31.3 %) and carbonate(Etr = 27.5 %) than the corresponding high-temperature cases. Imbibition tests of this improved formulation with various porous media show distinct wettability reversal trends towards a more water-wet state post imbibition. This trend is associated with the produced NH3 and CO2 due to urea hydrolysis. Both oil-aged sandstone and carbonate imbibition tests show noticeable water wetness improvement. The observations of this work significantly expand the operational envelopes of the current ICE system.