High Temperature Gas Reservoir Research Articles

Modified guanidine gel fracturing fluid system and performance optimization for ultra-deep and ultra-high temperature oil and gas reservoirs

The development of deep high-temperature oil and gas reservoirs gives rise to a rise in reservoir temperature along with the depth of the oil reservoir, thereby imposing higher requirements on the heat resistance of fracturing fluid. Guar gum fracturing fluid has difficulty tolerating temperatures exceeding 160 °C, thereby demanding the development of corresponding cross-linking agents, temperature stabilizers, and other additives to enhance the thermal stability of the fracturing system. Considering the distinctive characteristics of deep and ultra-deep reservoirs, such as extreme burial depth (exceeding 6000 m), ultra-high temperature (higher than 160 °C), and high fracturing pressure, an experimental modification of a guar gum fracturing fluid system was carried out, specifically tailored for ultra-high temperatures. The experiment identified and selected individual agents for ultra-high temperature fracturing fluids, including crosslinking agents, thermal stabilizers, flowback aids, and clay inhibitors. Through rigorous experimentation, these key agents for an ultra-high temperature fracturing fluid system have been successfully developed, including the optimal thickener GBA1-2, crosslinking agent BA1-1, anti-swelling agent FB-1, and gel breaker TS-1. The evaluation of diverse additive dosages has facilitated the development of an optimal guar fracturing fluid system, which exhibits outstanding high-temperature resistance while minimizing damage and friction. The outcomes of our experiments indicate that even after subjecting our ultra-high temperature fracturing fluid to 2 h of shearing at 170 s−1 at 180 °C, its viscosity remained above 200 mPa s—a distinct proof of its superior performance in withstanding high temperatures. This achievement represents a substantial progress in providing a suitable fracturing fluid system for the transformation and stimulation of ultra-deep and ultra-high temperature reservoirs, and also lays a solid foundation for further exploration and application in related fields in the future.

Investigation Into the Dominant Factors of Gas Recovery in High-Temperature and High-Pressure Gas Reservoir

Investigation Into the Dominant Factors of Gas Recovery in High-Temperature and High-Pressure Gas Reservoir

Experimental study on critical sand production pressure gradient at different production stages of high temperature and high pressure tight sandstone gas reservoir

AbstractSand production is a common issue in sandstone gas reservoir development, severely impacting the productivity of sandstone gas wells. In order to thoroughly investigate the sand production characteristics of high‐temperature and high‐pressure tight sandstone gas reservoirs, this study focuses on six core samples from tight sandstone gas reservoirs(three samples with fractures), under reservoir conditions (185 MPa, 160°C), sand production experiments were conducted to thoroughly investigate the sand production patterns in sandstone reservoirs under the combined influence of different effective stresses and production pressure differentials. The results indicate: (1) under the simultaneous increase of effective pressure and production pressure differential, sand production near the wellbore (r = 0.1 m) becomes more likely in the reservoir; (2) in actual reservoirs without fractures near the wellbore (r = 0.1 m), sand production phenomena do not occur; (3) reservoirs with fractures near the wellbore (r = 0.1 m) are more prone to sand production, under an effective stress of 90 MPa, with specimens containing fractures exhibiting a 76.48% lower critical sand production pressure gradient compared to those without fractures; (4) when the pore fluid pressure is 95 MPa, the maximum gas production rate for Well X without sand production is 12.4 × 104 m3/d. The experimental results have guiding significance for the rational production of gas wells in this type of reservoir.

Atrimonas thermophila gen. nov., sp. nov., a novel anaerobic thermophilic bacterium of the phylum Atribacterota isolated from deep subsurface gas field and proposal of Atrimonadaceae fam. nov. within the class Atribacteria in the phylum Atribacterota

A novel anaerobic, thermophilic bacterium of the class Atribacteria, strain M15T, was isolated from a high-temperature gas reservoir, Japan. Cells of strain M15T were gram-negative, short oval-shaped, and lacked flagella. Growth occurred at 45–75 °C (optimum 70–75 °C) and pH 6.5–8.5 (optimum pH 7.5–8.0) and was fast under optimal conditions (doubling time 11.4 h). Yeast extract was required for growth. Fermentative growth with glucose, arabinose, xylose, and cellobiose was observed. The major fermentative end products of glucose were acetate and hydrogen. The major cellular fatty acids were C16:0, iso-C15:0, and C18:0. The genomic G + C content was 46.0 mol%. Fluorescence and electron microscopy observations revealed the intracellular localization of genomic DNA surrounded by a membrane in the cells of strain M15T as reported in a sole validly described species of the class Atribacteria in the phylum Atribacterota, Atribacter laminatus strain RT761T, suggesting that the unique morphological traits are widely shared in this class. Phylogenetic analyses indicated that strain M15T belongs to a distinct family-level lineage in the class Atribacteria and shows low similarities to Atribacter laminatus strain RT761T (16S rRNA gene sequence identity of 90.1 %, average nucleotide identity [ANI] of 66.1 %, average amino acid identity [AAI] of 55.8 %). Phenotypic traits of strain M15T (thermophilic, fast-growing, relatively high G + C content, etc.) were clearly distinct from A. laminatus. Based on these phenotypic and genomic properties, we propose a novel genus and species, Atrimonas thermophila gen. nov., sp. nov. for strain M15T (=JCM39389T, =KCTC25731T) representing a novel family Atrimonadaceae fam., nov. in the class Atribacteria.

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.

Current status and development trends of CO2 storage with enhanced natural gas recovery (CS-EGR)

CO2 storage with enhanced gas recovery (CSEGR) technology is a pivotal solution to mitigate the greenhouse effect and respond to national energy conservation and emission reduction policies. This involves injecting CO2 into gas reservoirs for storage and using it to displace gas into producing wells to enhance production. This paper provides a comprehensive analysis of the primary mechanisms of CO2 storage in gas reservoirs, quantifies the long-term contribution of these, and summarizes the methods used to evaluate CO2 storage potential. The mechanisms of the displacement of natural gas by CO2 are explained and two technical difficulties are addressed: the degree of CO2-natural gas mixing and competitive adsorption and displacement of CO2-CH4. Besides, the main factors affecting CSEGR are studied thoroughly, and the currently typical CSEGR field pilot tests across the word are considered along with CSEGR economic policy research. This paper then identifies the current challenges and future trends in CSEGR development. The results show, firstly, in the later stage of gas reservoir development, high rates of CO2 injection at the bottom of the gas reservoir and CH4 production at the top can significantly enhance gas recovery. Secondly, in previous studies, the degree of CO2-natural gas mixing has been studied more in sandstones and carbonates, while CO2-CH4 competitive adsorption has been studied more in shales and coal seams. The results of all these studies demonstrate the feasibility of CSEGR. Thirdly, Four major storage mechanisms interact to stabilize CO2 storage in gas reservoirs, but there is no systematic method to evaluate the CO2 storage potential. Finally, among recent experimental and simulation studies, CSEGR analytic techniques that consider complex formation conditions need to be further explored. Additionally, combining CSEGR with geothermal energy development in high temperature gas reservoirs presents a promising avenue for exploration.

Optimization and Performance Evaluation of Foam Acid Systems for Plugging Removal in Low Pressure Oil and Gas Reservoirs

Foam acidization has unique advantages such as low damage, low filtration, low friction, high efficiency, excellent retardation, and fast liquid discharge rate, which is suitable for stimulation and reconstruction of low-pressure oil and gas reservoirs that have been developed over many years. It is obtained that the main chemical components of downhole plugging materials include vegetable oil, fatty acids and their esters, silicone oil, amide polymers, and additional organic components, as well as non-organic components, elemental sulfur, ferrous sulfide, iron disulfide, silicon dioxide, mineral salts, etc. The performance of foam acid was investigated by experiments, including the effective range of action of active acids, reducing filtration, increasing temperature resistance and high-temperature stability of foam acid deep wells. The new foam acid system is developed and optimized to suitable for low-pressure deep well acidification operations. Experimental evaluation optimized the acid foaming agent and foam stabilizer and developed a new foam acid formulation with foam stability, filter loss reduction, temperature resistance, and easy backflow performance. The experimental condition is that the temperature is 90 °C, the foam quality can reach more than 70% when mixed for more than 30 s, the average half-life is 38.75 min, and the liquid separation rate is 19.90 s/mL. Its suspension is better than that of conventional hydrochloric acid, its corrosion rate is 1.872 g/m2·h, and the flowback rate of foam acid residue reaches 97%. Experimental evaluation has shown that the developed foam acid features high surface activity, stable foam, strong temperature resistance, significant speed and corrosion suppression, and excellent drainage assist performance. Dynamical simulation evaluation of reservoir core foam acidification demonstrated that the foam features long-life, strong suspension capacity, excellent rheology, low filtration, and significant acidization and plug removal effects, and can be used in stimulating the medium-deep, high-temperature, and low-pressure oil and gas reservoirs.

Experimental study of variable density compound water control based on continuous packer——A case study of deep-water HP/HT LS25 gas field in the South China Sea

Based on the deep-water high temperature and high pressure LS25 gas field in the Nanhai Reservoir, through the design of heterogeneous formations and the design of water control experimental schemes, physical simulation experiments of different gas reservoir water control processes have been completed, focusing on evaluating the variable density compound water control technology based on continuous packers. In terms of the adaptability of deep-water gas reservoirs, on this basis, combined with the experiment-mine scale conversion method, a water-controlled exploitation plan for deep water high-temperature and high-pressure gas reservoirs is given. The experimental results show that: (1) Under elastic production conditions, the water body of the bottom water in the gas reservoir rises in a “progressive” manner in the initial stage, and generally develops in a “cone progression” in the middle and late stages. (2) There are obvious differences in the effects of various water control processes. A single continuous sealing body has no obvious effect on bottom water control during the gas production period of a gas well, and a single variable density screen process has no obvious effect on water control in the early stage of gas well production. The effect is good, but the risk of water channeling cannot be avoided after the gas well breaks through. The experimental effect of the variable density composite water control process based on the continuous packer is good, and the bottom water coning effect has changed to a certain extent. The experiments show that the water-free gas production period of the composite water control process is 13.7 years, the total gas production time is extended to 15.8 years, the total gas production after water control is as high as 12.37×108m3, and the recovery rate of gas wells is 9.2%, which is higher than that of elastic production. The research results aim to establish an optimal water control development model for high temperature and high-pressure deep water gas reservoirs and provide a good technical support for rational and scientific research on water control in horizontal wells of offshore deep water gas reservoirs.

Analysis of water invasion effect and development scheme design for deep water HHT gas reservoir: A case study of LS25 gas field

Based on the South China Sea deepwater high temperature and high pressure gas reservoir LS25 gas field, 3D geological model and a numerical reservoir model of LS25 gas field are established. Through numerical simulation of gas reservoir production, quantitative analysis of water invasion characteristics of 11 wells has been completed. The whole process of water invasion in space is as follows: bottom water conies in the early stage, forming water cone shape, the scale of the water body to the ridge increases, and the horizontal section completely emerges. Through comparative study, it is concluded that the combined water control technology of variable density screen pipe has the best water control effect. According to the prediction and analysis of the final production plan of variable density technology, it can prolong the water-free gas production period of the gas reservoir by 0.7 years, prolong the total production time by 1.9 years, increase the gas production by 1.9×108m3, and increase the recovery factor by 10.5% compared with that without water control measures. The research results are aimed to establish an optimal water control development model for buried hill gas reservoirs, and provide a good technical support for reasonable and scientific water control research of horizontal wells in offshore buried hill fractured gas reservoirs.

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.

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.

Use of a Polymer Gel for Killing a High-Temperature and High-Pressure Gas Well

Summary In the processes of oil and gas drilling, gas easily invades wellbores and adversely influences the safety in high-pressure gas reservoir drilling activities. In this study, a polymer gel was prepared for well killing in high-pressure gas reservoirs. The gelation performance of the gel under different conditions was experimentally examined. The gel can maintain high shear resistance, high-temperature resistance, and high-temperature long-term stability at 160°C and is thus suitable for the long-term isolation of high-temperature formations. The gel is sensitive to high concentrations of salt ions and must be prepared in the field using saline solutions with Na+ and Ca2+ concentrations lower than 20 000 and 500 mg/L, respectively. The gel can be easily oxidized and disintegrated by acidic solutions. The gel disintegration rate may reach 100% when subjected to ammonium persulfate and hydrochloric acid aqueous solutions at 160°C. Moreover, the polymer gel performance in application scenarios was examined. The gel density can be increased using barite and magnetite. The water loss percentage of the gel is less than 10% at 160°C, rendering its use suitable for well killing in openhole intervals, especially in water-sensitive formations such as mudstone and shale. The permeability recovery of the gas reservoir core is more than 90% when gasflooding is performed with oxidative degradation of the gel. The gel exhibits excellent well kill capacity, with a maximum value of 8.8 MPa/100 m after aging at 160°C for 3 days. Successful field test was conducted in the Tarim Basin, Xinjiang, China, which indicates that the gel can be used for well killing in high-temperature and high-pressure gas reservoirs.

A Chemical Design Example of Hydraulic Fracturing Fluids in High-Temperature Hydrocarbon Reservoirs: Case Study

Production optimization problem in hydrocarbon reservoirs has garnered prime importance in the last few years. There are numerous methods to achieve the requisite and desired production rates. One such method is hydraulic fracturing, which has been used since the 1940s. Like many other technologies, hydraulic fracturing considers the usage of various chemicals for formulating the fracturing fluid. It has a concomitant challenge of optimal selection of such fluid as per the given conditions. The objective of this study was to validate the composition of hydraulic fracturing fluid for fracturing jobs in high-temperature Jurassic oil and gas reservoirs located in Western Kazakhstan.
 A series of laboratory tests were conducted to select suitable chemicals on a scientific and practical basis. Methods used were fluid thermal stability tests, shear test and stability test - all executed on Chandler 5550 rotational viscometer. Several other tests such as emulsion break test, water analysis, crosslinking time, pH measurement and gel tests were also performed. Herein, justifications from known sources are provided alongside the enumerated laboratory tests. Thus, gelling agents, crosslinkers, breakers and various additives such as demulsifiers, pH buffers, clay inhibitors and biocides were selected. Each component has its own chemical equivalent with the desired concentration.
 The formulated hydraulic fracturing fluid was successfully implemented in 20-ton hydraulic fracturing job in the Jurassic sandstone deposits with bottom-hole temperature up to 105 ℃ and a permeability about 3 mD. The operation was successful and resulted in production increase and promising long-lasting effects.
 HIGHLIGHTS
 
 One of the common problem in hydraulic fracturing jobs is a proper fracturing fluid design in compliance with well and formation conditions
 Series of lab testing such as fluid thermal stability tests, shear test and stability test, emulsion break test, water analysis, crosslinking time, pH measurement and gel tests were performed for the proposed fracturing fluid composition
 The optimal formulation of the hydraulic fracturing fluid was selected for operations at high temperatures of the Jurassic clastic formations, in particular at 105 ℃ at depths of more than 2,000 m
 
 GRAPHICAL ABSTRACT

Influence Factors of the Bottom Hole Flow Pressure in a High-Pressure and High-Temperature Condensate Gas Reservoir: Applicability Analysis

Influence Factors of the Bottom Hole Flow Pressure in a High-Pressure and High-Temperature Condensate Gas Reservoir: Applicability Analysis

Microscopic Mechanism of Variations in Physical Parameters of Natural Gas Containing CO2 at Ultrahigh Temperature and High Pressure.

Owing to limitations imposed by the experimental requirements, it is difficult to carry out pressure–volume–temperature experiments on CO2-containing natural gas in high-temperature and ultrahigh-pressure gas reservoirs. Relevant research is also insufficient, which has led to a lack of clarity in current understanding of the microscopic mechanism of variations in the deviation factor of high-CO2 natural gas under high-temperature and ultrahigh-pressure conditions. This has greatly limited the development of natural gas reservoirs containing CO2. To reveal the microscopic mechanism of variations in the deviation factor of natural gas containing CO2 as a function of pressure under high-temperature and high-pressure conditions, by physical simulation experiments, the deviation factors of samples of sour natural gas with known CO2 contents from the Ledong gas reservoir were determined. Then, according to the idealized parameters of the physical experiment, a molecular model of natural gas containing CO2 was established using molecular simulation methods. Changes in molecular density, molecular volume, nonbonding interaction energy, potential energy, and kinetic energy during variations in the deviation factor of a CO2-containing natural gas system as a function of pressure under high-temperature and ultrahigh-pressure conditions were quantitatively studied. Using molecular simulation techniques, it was found that the changes in total energy, kinetic energy, and potential energy between molecules are the internal factors that cause variations in the deviation factor of natural gas systems containing CO2 under ultrahigh-temperature and high-pressure conditions. The results show that the increase of carbon dioxide content in natural gas will cause the total energy of natural gas molecules to decrease when the pressure is constant. This means that the higher the CO2 content in natural gas, the easier it will be compressed. This study should lay the foundation for investigating the mechanisms of the occurrence of CO2-containing natural gas, as well as facilitating the exploitation of CO2-containing natural gas.

Quantitative characterization of salting out during development of deep high temperature gas reservoirs

The formation water evaporates seriously because of the drastic pressure change in near-well zone during the exploitation of deep high temperature gas reservoir. The crystallization salt precipitates in the formation when the salt concentration of formation water increases to solubility limit, which results in the decrease of reservoir porosity and permeability. At present, there is a lack of the prediction and process design of salting out in deep high temperature gas reservoirs. The evaporation salting out experiment of formation water was carried out firstly in this paper, and the volume model of salting out zone was established based on the water content model of natural gas, the porosity and permeability model of reservoir, and the kinetics model of salting out. And the characterization method of predicting porosity and permeability of high temperature gas reservoir after salting out was established by fitting and modifying the model finally, which could provide a theoretical basis for salting out plugging formation in depressurization production of gas reservoirs and laid a foundation for the efficient development of deep high temperature gas reservoirs.

Modeling of gas viscosity at high pressure-high temperature conditions: Integrating radial basis function neural network with evolutionary algorithms

Increase in global natural gas production over the last 15 years has led to the use of new and untapped reservoirs including high pressure-high temperature ones in order to meet the consumer demands. As flow characteristics of gas in various environments such as porous media, wells, and pipelines are influenced by its viscosity, it is an important parameter for petroleum engineers. In this work, an immense gas viscosity dataset consisting of 3017 laboratory data points was used for properly implementing two smart techniques: radial basis function neural network with two training algorithms as well as multilayer perceptron neural network with four training algorithms. By using these techniques, various models with high accuracies were developed for viscosities estimation of gas mixture, pure methane, and pure nitrogen at high pressures (5000–25000 psia) and high temperatures (100–1880 °F). The radial basis function (RBF) neural network with ant colony optimization (ACO) (namely RBF-ACO model) is considered as the best model. Average absolute relative errors of the aforementioned model for estimating pure methane, pure nitrogen and gas mixture viscosities are 0.36 %, 0.49 %, and 1.76 %, respectively. RBF-ACO model provides better results comparing with other presented empirical models. Also, RBF neural network optimized by particle swarm optimization (PSO) shows a high error for estimating the viscosities of methane and gas mixture and RBF neural network optimized by genetic algorithm (GA) yields a high error for estimating the viscosity of gas mixture. Afterwards, effects of input parameters on the viscosity value obtained by RBF-ACO model, were investigated using the relevancy factor. Finally, based on numerical simulation, a sensitivity analysis was conducted for measuring the uncertainty of cumulative gas production resulted from gas viscosity estimation for a high pressure-high temperature gas reservoir. This process indicates that accurate estimation of gas viscosity plays an important role in reliable estimation of cumulative gas production.

EXPERIMENTAL STUDY ON WATER-GAS PERMEABILITY OF HIGH-TEMPERATURE AND HIGH-PRESSURE SANDSTONE GAS RESERVOIRS IN YINGQIONG BASIN

EXPERIMENTAL STUDY ON WATER-GAS PERMEABILITY OF HIGH-TEMPERATURE AND HIGH-PRESSURE SANDSTONE GAS RESERVOIRS IN YINGQIONG BASIN

A simulation experiment method for HTHP gas well productivity

In recent years, a series of major natural gas exploration discoveries and breakthroughs have been achieved in deep and ultra-deep carbonate gas reservoirs in the Sichuan Basin, and all discovered gas reservoirs are characterized by great burial depth, complex pore structures and high formation temperature and pore pressure. In order to accurately predict the gas flow rate of single well in high temperature and high pressure (HTHP) gas reservoirs and clarify the gas flow characteristics under formation conditions, this paper establishes a productivity simulation experimental device and method based on the formation temperature and pore pressure of carbonate gas reservoirs in the Middle Permian Qixia Formation of northwestern Sichuan Basin and the Upper Sinian Dengying Formation of central Sichuan Basin. Then, the cores of above mentioned gas reservoirs are selected to carry out the productivity simulation experiment under HTHP. Finally, the gas flow characteristics are studied. And the following research results are obtained. First, the newly established productivity simulation experimental device and method suitable for the conditions of 160 °C formation temperature and 100 MPa pore pressure is used to predict the natural gas AOF (absolute open flow) of Well S-1 in the Qixia Formation gas reservoir of northwestern Sichuan Basin. And the prediction result is better accordant with the calculation result of theoretical model, with a relative error of only 2.12%. Second, based on the Klinkenberg permeability under surface conditions, the single-well gas flow rate calculated from the productivity simulation experiment is better accordant with the gas flow rate from field completion testing; while based on the Klinkenberg permeability under formation conditions, the single-well gas flow rate calculated from the productivity simulation experiment is better accordant with the AOF. Third, the change of formation temperature and pore pressure has a significant influence on rock permeability, and the permeability is more sensitive to stress than to temperature. Fourth, to carry out the reservoir stress sensitivity experiment and the productivity simulation experiment, it is required that core samples be recovered to the formation conditions for aging, or the experimental results may have characteristics of strong stress sensitivity and cannot be used for reservoir engineering evaluation directly. In conclusion, the production rate and AOF of HTHP gas wells can be predicted accurately by means of productivity simulation experiment, based on drilling core samples. In addition, the Klinkenberg permeability under formation conditions can be evaluated by using the relational expression between surface or Klinkenberg permeability under formation conditions and single-well gas flow rate, combined with gas well testing data.

Investigation of a high temperature gel system for application in saline oil and gas reservoirs for profile modification

The deeper the burial of the oil and gas reservoir, the higher the temperature of the oil and gas reservoir. When profile adjustment of water injection wells, plugging of oil production wells (gas production wells) and temporary plugging or killing of oil production wells (gas production wells) are required, the higher the temperature resistance of the plugging agent (above 150 °C) is required. In addition, high temperature resistant plugging agents should also be used in profile control or water plugging in reservoirs (120°C–200 °C) that are thermally recovered by steam injection or in situ combustion. It is of great importance to develop a high-temperature-resistant gel plugging system to fulfill the requirements of deep buried high-temperature oil or gas reservoirs or thermal recovery high-temperature oil reservoir operations.A gel system formed by the terpolymer (L-1) and a new cross-linking system (HB-1) was developed, and its properties were systematically studied in the condition of extremely high temperature. Studies have shown that the gel system could form stable continuous 3D network structures in high temperature (120°C–200 °C) and thus have an excellent long-term thermal stability.The gel system can adjust the strength by changing the concentration of the terpolymer (0.05%–1%) and the crosslinker (0.05%–1%), which can achieve different construction requirements. Compared with the conventional high-temperature-resistant gel, the cross-linking system HB-1 contains 4 hydroxyl groups (–CH2OH), it can crosslink with 4 amide groups (–CONH2) on the terpolymer. Therefore, this gel system can form a smaller grid size of 3D network structures (less than 5 μm), so it has stronger temperature resistance and better long-term thermal stability. When the temperature is 200 °C, the grid size of network structure is about 10 μm, but the strength of the gel system can still be maintained at code F-G. When the salinity of the water solution is 200,000 mg/L, the gel system on the contact surface can still maintain a small grid size of 3D network structures (about 10 μm). The gel system could maintain most of the initial viscosity and viscoelasticity, even after experiencing the mechanical shear or the porous-media shear. A gel system with strength F can still be formed after shearing by the pore media of 10 sand-packed tubes, and the plugging rate of each sand-packed tube exceeds 97%. It can be found by scanning electron microscope pictures that the gel system can be very firmly attached to the pore media, which can achieve profile adjustment of the formation. The gel system could have great potential in the application of high temperature oil or gas reservoirs.