High-temperature Reservoirs Research Articles

Optimization of surfactant-polymer flooding for enhanced oil recovery

Chemical enhanced oil recovery applications continue to face a variety of obstacles, particularly in high saline and high-temperature reservoirs, in addition to high chemical prices. This issue creates difficulty in developing optimal recipes that can withstand these extreme circumstances and so achieve maximal hydrocarbon recovery at the lowest feasible cost. The usefulness of surfactant polymer (SP) in mobilizing oil and increasing sweep efficiency in carbonate rocks is assessed in this article. A thermo-viscosifying polymer and an acrylamido tertiary butyl sulfonate (ATBS)/acrylamide (AM) copolymer were employed. Surfactants of various grades of amphoteric carboxybetain are used. These potential chemicals were chosen after a thorough study of previous research, which included long-term thermal stability, fluid rheology, interfacial tension, adsorption, and microfluidic tests. The contact angles were measured using a captive drop analyzer at high pressure and high temperature. The core-flooding experiments for slug size and injection sequence optimization were carried out using 12-inch long and 1.5-inch diameter limestone cores. For two weeks, the samples were aged. The trials were carried out at 90 °C. The seawater (SW) salinity utilized in the injection was 57,000 ppm. The findings highlighted the importance of surfactant-polymer interactions in wettability and fluid rheology. The best chemical combination was carboxybetaine (0.05 wt%) and ATBS/AM (0.25 wt%) which recovered 31.29% of the residual oil saturation (ROS), or 11.63% of the original oil in place (OIIP). The optimal slug size was 3.5 PV, which recovered 34.21% of the ROS and 17.05% of the OIIP. The optimum injection sequence was the co-injection of surfactant and polymer SW-S1P1-SW, which extracted 31.29% of the ROS and 11.63% of the OIIP. The recoveries were discovered to be related to the slug’s size. The chemical injection sequence was critical to the eventual oil recovery. Among the other sequences, SW-SP-SW had the highest recovery (SW-P-S-SW, SW-S-SW-P-SW, and SW-P-SW-S-SW). This is thought to be owing to the compounds' synergistic impact. We found that there is no systematic optimization process that combines the effect of chemicals, slug size, and sequence in one study, which gave us the motivation to cover the research gap.

Study on Water-Soluble Phenolic Resin Gels for High-Temperature and High-Salinity Oil Reservoir

High water cut of produced fluid is one of the most common problems in reservoir development. At present, injecting plugging agents and other profile control and water plugging technologies are the most widely used solutions. With the development of deep oil and gas resources, high-temperature and high-salinity (HTHS) reservoirs are becoming increasingly common. Conventional polymers are prone to hydrolysis and thermal degradation under HTHS conditions, making polymer flooding or polymer-based gels less effective. Phenol–aldehyde crosslinking agent gels can be applied to different reservoirs with a wide range of salinity, but there exist the disadvantage of high cost of gelants. The cost of water-soluble phenolic resin gels is low. Based on the research of former scientists, copolymers consisting of acrylamide (AM) and 2-Acrylamido-2-Methylpropanesulfonic acid (AMPS) and modified water-soluble phenolic resin were used to prepare gels in the paper. The experimental results show that the gelant with 1.0 wt% AM-AMPS copolymer (AMPS content is 47%), 1.0 wt% modified water-soluble phenolic resin and 0.4 wt% thiourea has gelation time of 7.5 h, storage modulus of 18 Pa and no syneresis after aging for 90 days at 105 °C in simulated Tahe water of 22 × 104 mg/L salinity. By comprehensively comparing the effectiveness of the gels prepared by a kind of phenolic aldehyde composite crosslinking agent and modified water-soluble phenolic resin, it is found that the gel constructed by the modified water-soluble phenolic resin not only reduces costs, but also has shorter gelation time and higher gel strength. The oil displacement experiment with a visual glass plate model proves that the forming gel has good plugging ability and thus improves the sweep efficiency. The research expands the application range of water-soluble phenolic resin gels, which has an important implication for profile control and water plugging in the HTHS reservoirs.

Synthesis and Performance Evaluation of a Novel Nanoparticle Coupling Expanded Granule Plugging Agent.

This study focuses on the characteristics of fractured and vuggy high-temperature and high-salt reservoirs in the Tahe Oilfield. The Acrylamide/2-acrylamide-2-methylpropanesulfonic copolymer salt was selected as a polymer; the hydroquinone and hexamethylene tetramine was selected as the crosslinking agent with a ratio of 1:1; the nanoparticle SiO2 was selected, and its dosage was optimized to 0.3%; Additionally, a novel nanoparticle coupling polymer gel was independently synthesized. The surface of the gel was a three-dimensional network structure, with grids arranged in pieces and interlaced with each other, and the structure was very stable. The SiO2 nanoparticles were attached to the gel skeleton, forming effective coupling and enhancing the strength of the gel skeleton. To solve the problem of complex gel preparation and transportation, the novel gel is compressed, pelletized, and dried into expanded particles through industrial granulation, and the disadvantage of the rapid expansion of expanded particles is optimized through physical film coating treatment. Finally, a novel nanoparticle coupling expanded granule plugging agent was developed. Evaluation of the performance of the novel nanoparticle coupling expanded granule plugging agent. With an increase in temperature and mineralization, the expansion multiplier of granules decreases; aged under high-temperature and high-salt conditions for 30 days, the expansion multiplier of granules can still reach 3.5 times, the toughness index is 1.61, and the long-term stability of the granules can be good; the water plugging rate of granules is 97.84%, which is superior to other widely used particle-based plugging agents.

Three-dimensional magnetotelluric inversion for the characterization of the Sol de Mañana high-enthalpy geothermal field, Bolivia

We describe the three-dimensional magnetotelluric modeling results of Laguna Colorada - Sol de Mañana geothermal field in SW Bolivia. It is located near Laguna Colorada in the foothills of the Western Cordillera of the Andes and at the margin of the Altiplano-Puna Magma Body (APMB), which is characterized by a vast electrical conductivity anomaly and corresponding seismic anomalies in the mid and deep crust. The magnetotelluric (MT) data comprising 70 stations were modeled by a 3-D inversion. The final model shows a broad conductor at a few hundred meters in depth, which we interpret as the confining cap layer. Beneath, equally widespread, a layer of intermediate resistivity marks the high-temperature hydrothermal reservoir. Detailed interpretation of MT data with information from existing wells suggests a potential for a high-enthalpy geothermal field.

PH-Responsive Viscoelastic Fluids of a C22-Tailed Surfactant Induced by Trivalent Metal Ions.

pH-responsive viscoelastic fluids are often achieved by adding hydrotropes into surfactant solutions. However, the use of metal salts to prepare pH-responsive viscoelastic fluids has been less documented. Herein, a pH-responsive viscoelastic fluid was developed by blending an ultra-long-chain tertiary amine, N-erucamidopropyl-N, N-dimethylamine (UC22AMPM), with metal salts (i.e., AlCl3, CrCl3, and FeCl3). The effects of the surfactant/metal salt mixing ratio and the type of metal ions on the viscoelasticity and phase behavior of fluids were systematically examined by appearance observation and rheometry. To elucidate the role of metal ions, the rheological properties between AlCl3- and HCl-UC22AMPM systems were compared. Results showed the above metal salt evoked the low-viscosity UC22AMPM dispersions to form viscoelastic solutions. Similar to HCl, AlCl3 could also protonate the UC22AMPM into a cationic surfactant, forming wormlike micelles (WLMs). Notably, much stronger viscoelastic behavior was evidenced in the UC22AMPM-AlCl3 systems because the Al3+ as metal chelators coordinated with WLMs, promoting the increment of viscosity. By tuning the pH, the macroscopic appearance of the UC22AMPM-AlCl3 system switched between transparent solutions and milky dispersion, concomitant with a viscosity variation of one order of magnitude. Importantly, the UC22AMPM-AlCl3 systems showed a constant viscosity of 40 mPa·s at 80 °C and 170 s-1 for 120 min, indicative of good heat and shear resistances. The metal-containing viscoelastic fluids are expected to be good candidates for high-temperature reservoir hydraulic fracturing.

A comparative analysis of the effect of nanoparticles/surfactant assisted foam injection on the gas mobility control at different heterogeneities

Foam flooding is a popular method for increasing oil recovery in reservoirs with varying levels of heterogeneity. One common foam flooding technique is surfactant-assisted foam flooding (SF), which uses surfactants to create stable foam. However, SF is limited in high-pressure, high-temperature, and high-salinity reservoirs. To overcome these limitations, researchers have proposed a new approach called nanoparticles-assisted foam flooding (NAF), which involves adding nanoparticles to improve surfactant properties. While SF has been shown to improve sweep efficiency in heterogeneous reservoirs, the potential benefits of NAF are not fully understood. In this study, researchers investigated the performance of SF and NAF in controlling gas mobility in reservoirs with different levels of heterogeneity. They defined heterogeneity levels using sequential Gaussian simulation with varying standard deviation values. They also included a gas–water flooding (GW) scenario as a baseline. The results showed that SF effectively delayed breakthroughs and improved recovery factors in highly heterogeneous reservoirs. The researchers also compared normalized values of breakthrough time, breakthrough recovery factor, and recovery factor after 50 years for SF and NAF, which were normalized by corresponding GW results. Simulation results showed that SF and NAF could increase the normalized breakthrough time (SF: 10–17%, NAF: 12–42%), breakthrough recovery factor (SF: 11–20%, NAF: 16–53%), and recovery factor after 50 years (SF: 0–4%, NAF: 0–23%) compared to GW, depending on the heterogeneity level and NP concentration. The benefits of NAF compared to SF and GW were due to a significant decrease in gas mobility and saturation in the topmost layers, which facilitated the piston-wise movement of the front, resulting in higher sweep efficiency and recovery factor.

WATER PRODUCTION ISOLATION TECHNIQUES FOR OIL-WELLS WITH HIGH RESERVOIR TEMPERATURE

Advanced drilling technology makes it possible to penetrate oil and gas sites with deep bedding of oil reservoir, a complex multi-layer structure and a high reservoir temperature at the well bottom, reaching 150°C. The difficult geology of oil strata leads to the fact that the productive layers of a well are flooded unevenly. In this work the causes for water cut in reservoirs are given, repair and insulation work and technologies for isolation of water-bearing intervals in the oil-producing wells considered. Grouting composites for water inflow limitation in reservoirs with low temperature (up to 100°C) and high-temperature reservoirs are studied. For water flood control in the oil and gas wells with high temperature viscoelastic composites with extended gel-time and high stable strength and adhesive properties has been proposed. The advantage of polymer-based composites is their kinetic behavior in dynamic mode, when filtering in a porous medium, which makes it possible to isolate effectively intake formations with different channel openings with a small flow rate of the mixture.

Preparation and properties of a double quaternary ammonium copolymer used in acid fracturing

Triethylamine (TEA), 1, 4-dibromobutane (C 4 H 8 Br 2 ) and N, N -dimethylaminopropyl acrylamide (DMAPAA) were selected to synthesize a double quaternary ammonium cationic monomer (TDD). TDD, acrylamide (AM), 2-acrylamido-2-methylpropane sulfonic acid (AMPS) and acrylic acid (AA) were used to create a quadripolymer (PAAT) that was characterized by FT-IR and 1 H NMR. Following that, the basic performance of thickened acid was assessed. The results revealed that PAAT outperformed PAA (copolymerized by AM, AMPS and AA) in terms of acid solubility, thickening performance, temperature resistance and shear resistance. Furthermore, this crosslinked acid containing PAAT was subjected to a series of performance evaluations. The viscosity of the crosslinked acid could be kept at 67 mPa·s at 160°C after 90 min and the weight loss rate of crosslinked acid in acid-rock reaction at 60 min was 23%, indicating the temperature resistance and retarder performance of the crosslinked acid solution was significantly better than that of the thickening acid and the blank acid. A scanning electron microscopy experiment revealed that crosslinked acid has good corrosion ability and low damage to the reservoir. The above experimental results indicated that the thickener PAAT has a promising future application in acid fracturing of high-temperature and high-mineralization carbonate reservoirs.

Experimental study on the plugging and profile control of preformed particle gels in high temperature and salinity reservoir

AbstractA novel modified polysaccharide composite preformed particle gel (MCPG) was synthesized as a profile control agent to improve the situation of high water cut and low oil recovery. Then, the structure of MCPG was characterized by Fourier transform infrared spectroscopy (FTIR), X‐ray diffraction (XRD), and environmental scanning electron microscope (ESEM). Subsequently, the impact of MCPG on enhanced oil recovery was investigated through nuclear magnetic resonance (NMR) and core displacement experiments. The results of FTIR, XRD, and ESEM indicate that monomers have been successfully intercalated into the layered structure of nanoscale sodium bentonite. In the condition of 130°C and salinity of 240,000 mg/L, the value of the swelling ratio and the toughness factor can reach about 30 and 0.87, respectively. The results of nonlinear fitting indicate that the relationship between the resistance coefficient and residual resistance coefficient with the matching coefficient (β) followed a power function, while the blocking water efficiency with β followed an exponential function. When the permeability ratio was as high as 30.58, MCPG still exhibited excellent profile improvement performance. NMR experiments proved that MCPG increased the displacement resistance in large pores and effectively enhanced the displacement efficiency in medium pores and small pores. The oil displacement efficiency in MCPG flooding and subsequent water flooding stages increased by 18.65% and 8.42%, respectively.

Composite stimulation technology for improving fracture length and conductivity of unconventional reservoirs

Unconventional reservoirs have strong heterogeneity, with significant differences in the distribution of porosity and permeability. Fracturing is an important technology for increasing natural gas production in unconventional oil and gas reservoirs. For unconventional reservoirs with high temperature and low permeability, the rapid increase in acid rock reaction rate leads to a significant decrease in the effective distance of acidic fluids and fracture conductivity, especially the inability to obtain effective support at the fracture tip, which restricts the increase in production of high-temperature unconventional oil and gas reservoirs. To address the above issues, a composite fracturing method is proposed, which first uses a proppant to support the crack tip, and then uses gelled acid to corrode the middle and rear parts of the crack. According to the fracture conductivity achievement test experiment and proppant migration experiment, when 40/70 mesh ceramsite and 100 mesh ceramsite are mixed at a mass ratio of 1:4, the fracture conductivity can reach 21.8 μm·cm2 under the effective closing pressure of 60 MPa, which is 123% higher than the fracture conductivity of cementitious acid corrosion. The gel is used to carry 40/70 mesh and 100 mesh ceramsite, and the Equilibrium level of the sand embankment can reach 38 cm. At the same time, the sand dike formed by different particle sizes of ceramic particles is smoother than the sand vein formed by a single particle size of proppant, and the migration ability of ceramic particles to the fracture tip is better. The composite stimulation technology has been applied to 9 wells in carbonate and shale oil and gas reservoirs. After fracturing, the production of oil and gas wells is 210% higher than that of gelled acid fracturing, and the composite stimulation technology has achieved good stimulation effects.

Hydrochemical, D–O–Sr isotopic and electromagnetic characteristics of geothermal waters from the Erdaoqiao area, SW China: Insights into genetic mechanism and scaling potential

The Erdaoqiao area has been the hot area of geothermal resource prospecting in southwestern China. Significance difference of scaling potential has been found between left and right riverbanks of the Erdaoqiao area. However, there still has no interpretation for the scaling difference since the genetic mechanism of geothermal waters remains unclear. In this study, hydrochemical, D–O–Sr isotopic and electromagnetic (EM) approaches were integrated to clarify the genetic mechanism and quantitively evaluate scaling potential of geothermal waters. All geothermal waters belonged to Ca–Na–HCO3 type and were determined by the weathering and/or dissolution of carbonates (66.87%) and silicates (31.53%) with cation exchange based on hydrochemical and Sr isotopic analyses. Na–K–Mg triangle diagram indicated they were immature water mixed by shallow cold water. Quartz geothermometer indicated the shallow reservoir temperatures (after cold–water mixing) of left riverbank (88.46 °C–90.51 °C) were higher than those of right riverbank (61.20 °C–87.89 °C). Silica – Enthalpy methods revealed the initial geothermal reservoir temperatures and cold-water mixing ratio were 102.03 °C–138.93 °C and 65.24%–85.87% in the right riverbank, 144.11 °C–146.76 °C and 73.08%–74.79% in the left riverbank of the Erdaoqiao area. D-O isotopes proposed the geothermal waters were recharged by atmospheric precipitation in the elevation of 4957 m to 5118 m. Therefore, the genetic model of geothermal waters in the Erdaoqiao area can be constructed. Stronger calcite scaling in left riverbank was attributed to deeper circulation identified by higher reservoir temperature and electromagnetic exploration. Quantitively evaluation demonstrated that the weight of scaling during 48 h in left riverbank (2968 kg) was four times higher than that in right riverbank (748 kg). The achievements of this study contribute to geothermal exploration in the Erdaoqiao and other similar areas worldwide.

Light stable Cr isotope compositions of mid-ocean ridge basalts: Implications for mantle source composition

Stable isotopes of chromium (Cr) and iron (Fe), both multivalent elements in silicate melts, are valuable proxies of redox conditions in magmatic systems. Partial melting and fractional crystallization have been identified as the dominant fractionation processes for Cr and Fe isotopes in high-temperature reservoirs that can lead to small but detectable isotope variations in igneous rocks. More recently, however, the source mineralogy has been suggested to play an important role, which can ultimately affect the magnitude of Cr and Fe isotopic fractionation during partial melting and thus the Cr and Fe isotopic composition of the originating melt.With the aim to investigate the role of magmatic processes and the source Cr and Fe isotope signatures on the isotope composition of these transition metals in normal mid-ocean ridge basalts (N-MORB), we analyzed 21 well-characterized MORB glasses from the southern East-Pacific Rise, Pacific-Antarctic Ridge and Mid-Atlantic Ridge. The Cr isotope compositions of N-MORB show a narrow range from −0.278 to −0.186 ‰ in δ53/52Cr (i.e., difference of a sample’s 53Cr/52Cr ratio relative to the international reference material NIST SRM979), with an average value of −0.237 ± 0.050 ‰ (2SD; n = 19). As such, the average N-MORB δ53/52Cr value is significantly lower than that of Bulk Silicate Earth of −0.12 ± 0.06 ‰ and the Cr isotope compositions reported for most ocean island basalts ranging from ∼ −0.23 to 0.00 ‰. Iron isotopic compositions of these MORB range from +0.032 to +0.137 ‰ in δ56/54Fe (i.e., difference of a sample’s 56Fe/54Fe ratio relative to the international reference material IRMM014) and are within the range of previously published MORB data. The lack of correlations between N-MORB Cr isotope signatures and indices of magmatic differentiation suggests a negligible control of this process on Cr stable isotopes. Partial melting modeling using pMELTS provides evidence that the significant offset towards lower δ53/52Cr values of N-MORB cannot be produced by decompression partial melting of a lherzolithic source such as the depleted upper mantle alone. Instead, we suggest that the lower δ53/52Cr values of MORB could be linked to intrinsic small-scale 53Cr-depleted pyroxene-rich domains in the upper mantle that influence the melt’s Cr isotopic budget during partial melting.

Polymer Screening for Efficient Water Cut Reduction in a Sandstone Oilfield in Kazakhstan.

Polymer flooding is one of the most widely used and effective enhanced oil recovery techniques. It can improve the macroscopic sweep efficiency of a reservoir by controlling the fractional flow of water. The applicability of polymer flooding for one of the sandstone fields in Kazakhstan was evaluated in this study and polymer screening was carried out to choose the most appropriate polymer among four hydrolyzed polyacrylamide polymer samples. Polymer samples were prepared in Caspian seawater (CSW) and assessed based on rheology, thermal stability, sensitivity to non-ionic materials and oxygen, and static adsorption. All the tests were performed at a reservoir temperature of 63 °C. Based on the results of the screening study, tolerance of a polymer towards high-temperature reservoir conditions, resistance to bacterial activity and dissolved oxygen present in make-up brine, chemical degradation, and reduced adsorption on rock surface were considered the most important screening parameters. As a result of this screening study, one out of four polymers was selected for the target field as it showed a negligible effect of bacterial activity on thermal stability. The results of static adsorption also showed 13-14% lower adsorption of the selected polymer compared to other polymers tested in the study. The results of this study demonstrate important screening criteria to be followed during polymer selection for an oilfield as the polymer should be selected based on not only polymer characteristics but also the polymer interactions with the ionic and non-ionic components of the make-up brine.

Mechanical Properties of High-Temperature Granite under Liquid Nitrogen Cooling

The cooling characteristics of liquid nitrogen can effectively weaken the mechanical properties of dry hot rock reservoirs, improve the porosity and permeability of dry hot rock, and thus improve the development and utilization of geothermal resources. In order to explore the weakening effect of liquid nitrogen cooling characteristics on high-temperature reservoir rocks, uniaxial compression tests, Brazil splitting tests, and three-point bending tests were conducted on high-temperature granite, and synchronous acoustic emission tests were conducted to monitor the damage evolution of rocks. It is found that under the action of liquid nitrogen, the elastic modulus, peak strength, fracture toughness, and other mechanical properties of granite decrease to varying degrees. At different initial temperatures, the damage degree of liquid nitrogen to granite is different. The higher the initial temperature of granite, the greater the damage effect of liquid nitrogen on granite. The low-temperature characteristics of liquid nitrogen not only have the effect of cracking damage on granite but also have the effect of thermal stress on granite. If the temperature difference between the two is large, the heat released in the combination process will be higher. The greater the temperature difference, the greater the damage to granite. Under the action of liquid nitrogen, the acoustic emission characteristics of granite also show different evolution laws, and the ringing count of rock increases significantly, which indicates that liquid nitrogen aggravates the internal damage of granite, making the rock more fractured during fracturing. The research results can provide some scientific guidance for the development and utilization of geothermal energy.

Rheological studies of high-density fracturing fluid using high-density brine and carboxymethyl hydroxypropyl guar (CMHPG) for high-temperature well condition

This work investigated carboxymethyl hydroxypropyl guar (CMHPG) as a potential base polymer for a fracturing fluid used in deep tight gas wells, synonym to high-temperature reservoirs. Fracturing is a common method to improve oil production by creating fractures in potentially productive reservoirs using fracturing fluids. Fracturing fluids are typically composed of water, sand, proppant, and many different additives to alter the capabilities of the fluid.A stable high-density fracturing fluid (HDFF) was developed to cope with scorching good temperatures up to 350F (177C)as well as to reduce the surface treating pressure. The HDFF consists of NaBr heavy brine, CMHPG, clay stabilizers, and zirconium and borate crosslinkers. A linear gel fluid was prepared by combining NaBr brine with CMHPG before adding the additives. The resulting fluid was then tested using a high-pressure, high-temperature (HPHT) rheometer.The results showed that the performance of the HDFF was optimum in an alkaline environment between pH 10 to 12. The efficiency of zirconium and borate crosslinkers were optimum at 0.7 ppm and 1.5 ppt, respectively. Concentrations higher than these values are not only uneconomical but will cause the fluid to be overly crosslinked, consequently reducing efficiency. In actual field operation, this is disastrous when the fluid does not flow to the fracturing column but instead swirls around the drill string as the drill string rotates. On the other hand, a reduction of concentration below the optimum values can cause fluid instability at high temperature reservoirs.The study was limited to using two different kinds of crosslinkers and various concentrations. Future studies can be conducted using other kinds of crosslinkers, as well as an investigation into the effects of varying temperatures, pressures, and pH on the HDFF using CMHPG.It can be concluded that HDFF using CMHPG as the base polymer can be a potential use in formulating fracturing fluids.Information on the rheological behaviour of HDFF using NaBr and CMHPG can provide a reference point for future scientists in developing a new formulation of fracturing fluid.

The importance of facies, grain size and clay content in controlling fluvial reservoir quality – an example from the Triassic Skagerrak Formation, Central North Sea, UK

Clay-coated grains play an important role in preserving reservoir quality in high-pressure, high-temperature (HPHT) sandstone reservoirs. Previous studies have shown that the completeness of coverage of clay coats effectively inhibits quartz cementation. However, the main factors controlling the extent of coverage remain controversial. This research sheds light on the influence of different depositional processes and hydrodynamics on clay-coat coverage and reservoir quality evolution. Detailed petrographic analysis of core samples from the Triassic fluvial Skagerrak Formation, Central North Sea, identified that channel facies offer the best reservoir quality; however, this varies as a function of depositional energy, grain size and clay content. Due to their coarser grain size and lower clay content, high-energy channel sandstones have higher permeabilities (100–1150 mD) than low-energy channel sandstones (<100 mD). Porosity is preserved due to grain-coating clays, with clay-coat coverage correlating with grain size, clay-coat volume and quartz cement. Higher coverage (70–98%) occurs in finer-grained, low-energy channel sandstones. In contrast, lower coverage (<50%) occurs in coarser-grained, high-energy channel sandstones. Quartz cement modelling showed a clear correlation between available quartz surface area and quartz cement volume. Although high-energy channel sandstones have better reservoir quality, they present moderate quartz overgrowths due to lesser coat coverage, and are thus prone to allowing further quartz cementation and porosity loss in ultra-deep HPHT settings. Conversely, low-energy channel sandstones containing moderate amounts of clay occurring as clay coats are more likely to preserve porosity in ultra-deep HPHT settings and form viable reservoirs for exploration. Supplementary material: of data and technique used in this study are available at https://doi.org/10.6084/m9.figshare.c.6438450

Research status and development trend of key technologies for enhanced geothermal systems

Enhanced geothermal system (EGS) is a primary method to develop geothermal resources stored in hot dry rock (HDR), but it faces several key problems, such as unreasonable hydraulic fracture networks at high reservoir temperature, unclear multi-scale and multi-field coupling regularity, low heat extraction efficiency caused by the flashing flow in geothermal wells, and low thermoelectric conversion efficiency of geothermal fluid, which restricts the large-scale commercial development of geothermal resources. To resolve these major bottleneck problems, systematically reviews and analysis of the research progress and development trend of EGS are conducted in this paper. Particular attentions are devoted to four key technologies involved in the development of HDR geothermal resource by EGS: (1) the hydraulic fracturing technology for HDR reservoirs, including reservoir reconstruction methods, hydraulic fracturing network forming mechanisms and fracture propagation prediction models is illustrated in detail; (2) the fracture characterization methods, mathematical models and solution methods are described from three aspects including pore-scale multi-field coupled models, reservoir-scale multi-field coupled models and upscaling methods; (3) the efficient extraction technology of wellbore thermal fluid, involving the mechanism of flashing flows in geothermal wells and the experimental and numerical methods for investigating the characteristics offlashing flows are discussed; (4) the HDR geothermal power generation technologies, considering the principles of geothermal power generation, the types of power generation systems and the main application markets are introduced. In conclusion, EGS is a technology-intensive system, however, due to the complex working conditions of the underground reservoirs and the instability of the ground equipment, theoretical research tends to be separated from the practice. For the purpose of promoting the applicability of EGS, intimate combination and mutual guidance with the pilot tests are necessary to develop a production-research combined mode, and to raise the awareness and break through the key points in a constant back-and-forth.

Synthesis and evaluation of magnetite nanoparticles coated with (acrylamide-vinylpyrrolidone) polymers on the thermostability for application in harsh offshore reservoirs

To avoid the instability and degradation of downhole injection fluids, such as polymers and surfactants, for use in high-temperature (HT) offshore reservoirs, nanofluids with particles modified in different ways have been proposed as a capable thermoresistant, highly active solutions which can be used in many offshore oil and gas exploitation works, especially in enhancing oil recovery. This study presented the process of synthesising two nanocomposite materials for nanofluid preparation. First, magnetite nanoparticles (MNPs(A and B)) were prepared by standard coprecipitation and hydrothermal methods. Then, polymer-coated magnetite nanoparticles (PCM(A) and PCM(B)) were synthesised by directly covering magnetite with oleic acid (OA) to get OA-MNPs, and then simultaneously enveloped with copolymers of acrylamide and the N-vinyl pyrrolidone via polymerisation reaction. The obtained PCMs characteristics were analysed by all required analytical tools. In addition, the thermostability of PCM-based nanofluids as downhole injection agents for HT offshore reservoir applications was investigated by bottle test annealing PCM(A)- and PCM(B)- based nanofluids at the White Tiger (WT) Miocene and Oligocene reservoir temperatures. Based on the obtained data, MNPs have an average particle size of 12 nm and 10 nm for MNPs A and B. A dominant phase of magnetite (Fe3O4) and 10.5% and 11% of the mass of PCM belong to their copolymer coating. The good thermostability of nanofluids annealed for 31 days (at 120 °C for PCM(A)- and 134 °C for PCM(B)-based nanofluids) showed a promised orientation for use as an EOR agent in HT offshore reservoirs recommendation.

A practical upper-bound efficiency model for solar power plants

Abstract A generalized model for the maximum work rate extractable from the Sun is developed considering a reversible and an endoreversible system to define a more practical upper-bound efficiency for the conversion of solar radiation into work and power. This model is based on a photo-thermal work extractor in communication with a high-temperature radiation reservoir and a low-temperature heat sink. Following the model, a parametric analysis of the concentration acceptance product (ξ) and thermal conductance is performed to identify the interdependence of variables for the solar exergy. The results are compared with existing models to provide a practical baseline of work and power extractable from concentrated solar power plants (CSP) technologies. Therefore, it is possible to quantify the irreversibilities of an idealized thermodynamic system operating between the Sun and the absorber (via radiative transfer) and the environment (via convective transfer).

Simulation investigation of room-temperature reciprocating packed bed magnetic refrigerator cycle: Comparison of magnetocaloric effect evaluated methods

Built-in method and straightforward adiabatic temperature change method have been widely used in the simulation investigation of Active Magnetic Regeneration Refrigeration (AMRR) cycle. Nevertheless, the difference between the abovementioned two approaches has rarely been discussed. In this regard, a simulation study on the reciprocating packed bed magnetic refrigeration cycle is presented with the special emphasis on the influence of the different magnetocaloric effect evaluated methods, where Gd and water working as magnetic material and heat transfer fluid. With the help of Finite Element Method (FEM), the numerical solutions of the thermodynamic equations of Gd and water can be obtained. Utilizing the FEM, the two methods can lead to same results when the time interval approaches zero. For a comparatively large time interval, the accurate heat expelled to the high-temperature reservoir can be achieved via the straightforward adiabatic temperature change method while the accurate heat absorbing from the low-temperature reservoir can be obtained via the built-in method. Moreover, calculated Coefficient of Performance (COP) via the straightforward adiabatic temperature change method is larger than that via the built-in method.