Formation Permeability Research Articles

STUDY ON HYDROGEOLOGICAL ASPECT OF GALANG SUB-DISTRICT, BATAM CITY FOR ACCEPTANCE OF PROSPECTIVE NPP SITES

This is a preliminary study in the selection of Nuclear Power Plant (NPP) site in Batam's Barelang area to support industrial growth in the area in the future. The initial site selection was conducted in 2015 and 2017 in the pre-survey phase, considering hydrogeological aspect. The results of previous research showed four potential areas, namely Pasir Panjang Beach, Tanjung Batu, Dapur 3 and Tanjung Rame. The hydrogeological aspect plays an important role in the consideration of site acceptance. This is related to the consideration of potential flow of radioactively contaminated groundwater seepage in the site area, in the event of a potential release. The acceptance of the NPP site from the hydrogeological aspect is based on the site’s permeable geological formation and porosity condition, where groundwater can be stored. The purpose of the study was to assess the potential site in Galang Sub-district, Batam City based on hydrogeological aspects which include surface geology, groundwater productivity and rock porosity. Research methods include primary and secondary data collection, literature review and ranking analysis. The results showed that Tanjung Batu, Dapur 3 and Tanjung Rame could be chosen as the potential sites for NPP based on the hydrogeological aspect. The three regions have surface geology in the form of sandstone, clay and claystone rock with medium rock porosity level and medium groundwater productivity. Pasir Panjang Beach is less preferable because it has a high porosity of rocks with the productivity of aquifers is being spread widely.

Estimation of fracture half-length with fast Gaussian pressure transient and RTA methods: Wolfcamp shale formation case study

Accurate estimation of fracture half-lengths in shale gas and oil reservoirs is critical for optimizing stimulation design, evaluating production potential, monitoring reservoir performance, and making informed economic decisions. Assessing the dimensions of hydraulic fractures and the quality of well completions in shale gas and oil reservoirs typically involves techniques such as chemical tracers, microseismic fiber optics, and production logs, which can be time-consuming and costly. This study demonstrates an alternative approach to estimate fracture half-lengths using the Gaussian pressure transient (GPT) Method, which has recently emerged as a novel technique for quantifying pressure depletion around single wells, multiple wells, and hydraulic fractures. The GPT method is compared to the well-established rate transient analysis (RTA) method to evaluate its effectiveness in estimating fracture parameters. The study used production data from 11 wells at the hydraulic fracture test site 1 in the Midland Basin of West Texas from Upper and Middle Wolfcamp (WC) formations. The data included flow rates and pressure readings, and the fracture half-lengths of the 11 wells were individually estimated by matching the production data to historical records. The GPT method can calculate the fracture half-length from daily production data, given a certain formation permeability. Independently, the traditional RTA method was applied to separately estimate the fracture half-length. The results of the two methods (GPT and RTA) are within an acceptable, small error margin for all 5 of the Middle WC wells studied, and for 5 of the 6 Upper WC wells. The slight deviation in the case of the Upper WC well is due to the different production control and a longer time for the well to reach constant bottomhole pressure. The estimated stimulated surface area for the Middle and Upper WC wells was correlated to the injected proppant volume and the total fluid production. Applying RTA and GPT methods to the historic production data improves the fracture diagnostics accuracy by reducing the uncertainty in the estimation of fracture dimensions, for given formation permeability values of the stimulated rock volume.

Assessing the impact of dip angle on carbon storage in saline reservoirs to aid site selection

Reservoir dip angle and permeability significantly impact CO2 plume migration and the amount of secondary phase trapping in storage formations. There is a fundamental trade-off between up-dip plume migration and secondary trapping that can be advantageous, or disadvantageous, for selecting an optimal CO2 storage site. For example, low permeability reservoirs have limited plume migration up-dip, consequently, residual and solubility trapping are also limited. On the contrary, for highly permeable reservoirs, up-dip migration can be fast and extensive, leading to accelerated residual and solubility trapping. By performing a systematic simulation study of plume migration and secondary trapping in reservoirs with a range of permeabilities and dip angles, we found that having a dip angle of at least 1° and permeability of at least 500mD results in up to 88% of the plume being immobilized 100 years post-injection. In reservoirs with a permeability of at least 500mD, we can optimize the amount of immobilized CO2 while limiting the amount of plume migration. As reservoir dip angles increase up to 2° and permeability increases, CO2 plume migration increases progressively, and up to 8x more mass of CO2 can migrate up-dip versus down-dip. At the same time, CO2 solubility in brine and residual trapping work to decrease the plume volume and can immobilize 28% to 90% of the CO2 plume over 100 years post-injection. Five influential parameters were identified that strongly influence the plume volume during the post-injection period for these dipping reservoirs: CO2 saturation, residual gas saturation, CO2 solubility in brine, CO2 density, and formation permeability. We also investigated the impact of simulation grid resolution, the maximum non-wetting phase saturation, and the pore-size distribution parameter on predicted plume behavior. This work provides simple, reliable relationships between key site screening metrics, reservoir dip angle, and permeability to inform the site selection process and monitoring, measurement, and verification (MMV) design.

A New Analytical Method for Calculating Subsidence Resulting by Fluid Withdrawal from Disk-Shaped Confined Aquifers

This work presents the derivation of analytical solutions concerning the radial subsidence distribution ensuing from fluid extraction from a disk-shaped confined aquifer in homogeneous formations. The study draws upon methodologies developed in petroleum geomechanics of deep reservoirs to estimate surface uplift due to CO2 injection using Hankel-transformed thin plate theory. These methods yield simplified expressions as compared to previous results derived using the superposition principle on surface uplift from a uniform pressure field. Hence, closed-form formulas for the subsidence at the well location are re-derived, while the formulas for the subsidence field are deducted by both methods and the mathematical relation between the two methodologies is discussed. Additionally, innovative closed-form asymptotic solutions for radial subsidence distribution are deduced for scenarios involving deep aquifers. These solutions demonstrate exceptional accuracy when aquifer depth exceeds aquifer diameter, exhibiting independence from formation permeability and fluid viscosity. The study explores the influence of physical parameters on the subsidence field.

Numerical Investigation of Influential Factors in Hydraulic Fracturing Processes Using Coupled Discrete Element‐Lattice Boltzmann Method

AbstractHydraulic fracturing is widely used to stimulate unconventional reservoirs, but a systematic and comprehensive investigation into the hydraulic fracturing process is insufficient. In this work, a discrete element‐lattice Boltzmann method is implemented to simulate the hydro‐mechanical behavior in a hydraulic fracturing process. Different influential factors, including treatment parameters (injection rates and fluid viscosity), formation parameters (in situ stress states and natural fractures) and rock properties (heterogeneity of rock strengths and rock permeability), are considered and their impacts on the initiation and propagation of hydraulic fractures are evaluated. A higher injection rate, increased viscosity, and larger in situ stress will lead to an increase in the initiation pressure. Conversely, higher formation permeability and a greater degree of heterogeneity in bond strengths will result in a decrease in the initiation pressure. The complexity of generated fractures is significantly influenced by the injection rate and degree of heterogeneity. However, fluid viscosity, in situ stress states, and formation permeability individually do not affect the geometrical complexity. Shear displacement can occur during a hydraulic fracturing process due to increased pore pressure and variations in in situ stress caused by injected fluid. Low‐viscosity fluid with a high injection rate can have a significant pressure buildup and generate complex fracture networks in low‐permeability heterogeneous formations. Natural fractures can significantly impact the complexity of generated fractures, while more in‐depth research is required regarding complex natural fracture distributions.

The Using of Unconventional Method depending on Well Power in the Mishrif Formation to Release Differential Stuck Pipe, Nahr Umr Oil Field, Southern Iraq

One of the main drilling problems is differential stuck pipe that lead to excessive non-productive time. The drill string usually stuck in the filter cake in permeable formations because it becomes immobile as a result of the drill string movement to connect a new pipe, make a trip, handle a drilling issue, etc. because there is a high permeability zone and a pressure difference between formation and filtering. So, without first releasing it by mechanical or chemical processes, the driller is unable to reciprocate or rotate it. Nahr Umr oil field was selected to study the problem of differential stuck pipe occurred while tripping out in the Hartha Formation and procedure steps to formulate the appropriate method to release the stuck string. Used unconventional method to free stuck pipe depend on well power in the Mishrif Formation after the conventional method failed to treat the problem. Then, the results were discussed with estimating stuck pipe depth and the force needed to release the string and comparison between the methods relative to the time and cost. Also, the result can be concluded that the appropriate mud weight is 1.27gm/cc. On the other hand, it was concluded that the unconventional method cheaper than the conventional method but it can be used if the formations contain oil or salt water only.

Hydraulic injection tests in the pilot EGS borehole PVGT-LT1 in Litoměřice, Czechia

Successful utilization of geothermal energy is conditioned by sufficient permeability of the rock formation as a heat exchanger. We present results of hydraulic injection tests carried out in 2020 in the pilot geothermal borehole PVGT-LT1 in Litoměřice, Czech Republic, which samples 800 m of Paleozoic and Mesozoic sediments on the top of a crystalline basement. The low hydraulic conductivity on the order of 10−11 m/s obtained by recovery tests was verified by large-scale injection tests monitored by DTS temperature logging. During the first test, 24 m3 of water were injected and a permeable fracture was created at 880 m depth, breaking through the ignimbrite layer. The opening pressure of 12.55 MPa corresponds to the lower estimate of the minimum stress at this depth. The second injection was performed 7 months later and 202 m3 were injected at flow rates reaching 50 l/min. It showed that the fracture had been preserved since the first injection, which was documented by a non-zero flow rate at the smallest injection pressures and also by a stabilized water level in the borehole, which dropped immediately after the fracture formation. No induced seismicity accompanied the injection, which indicates a possibly low seismogenic potential of this area of the Bohemian Massif. The model of finite conductive fracture fitted to the pressure decay curve during shut-in intervals gives an estimate of a fracture half-length exceeding 100 m.

Reactive flow of microemulsion-based EDTA fluid for carbonate stimulation

Traditional methods for stimulating carbonate formations primarily rely on the use of highly reactive acids, such as hydrochloric acid (HCl), to create wormholes. However, the limitations of this approach in certain scenarios have prompted the exploration of alternative strategies. In this study, we investigate the synergistic potential between microemulsion and ethylenediaminetetraacetic acid (EDTA) for stimulating carbonate formations. Microemulsion systems were formulated using a nonionic surfactant, sec-butanol as a cosurfactant, xylene as the oily phase, and an aqueous solution of EDTA as the water phase. The microemulsions were characterized by phase equilibrium and rheological behavior. Coreflooding and static dissolution experiments were performed. We employ microCT imaging to evaluate the change in porosity in static dissolution experiments. The results reveal that microemulsions containing EDTA presented remarkable stability and were able to significantly enhance carbonate rock permeability up to 85%, indicating that dissolution occurred and the rock was stimulated. Analyses of microCT images on static dissolution experiments of Indiana limestones in reactive microemulsions indicate an increase in porosity, confirming the dissolution process. These findings highlight the synergistic effect of EDTA in microemulsion media for enhancing the rock permeability of carbonate formation as an alternative as low reactive system.

Reactive Transport Modeling of Chemical Stimulation Processes for an Enhanced Geothermal System (EGS)

An enhanced geothermal system is a kind of artificial geothermal system, which can economically exploit geothermal energy from deep thermal rock mass with low permeability by artificially created geothermal reservoirs. Chemical stimulation refers to a reservoir permeability enhancement method that injects a chemical stimulant into the fractured geothermal reservoir to improve the formation permeability by dissolving minerals. In this study, a reactive solute transport model was established based on TOUGHREACT to find out the effect of chemical stimulation on the reconstruction of a granite-hosted enhanced geothermal system reservoir. The results show that chemical stimulation with mud acid as a stimulant can effectively improve the permeability of fractures near the injection well, the effective penetration distance can reach more than 20 m after 5 days. The improvement of porosity and permeability was mainly caused by the dissolution of feldspar and chlorite. The permeability enhancement increased with the injection flow rate and HF concentration in the stimulant, which was weakly affected by the change in injection temperature. The method of chemical enhancement processes can provide a reference for subsequent enhanced geothermal system engineering designs.

Effects of fluid flow in triple porosity medium on fracture width and its propagation during lost circulation control

During oil and gas well construction, lost circulation is one of the major challenges, and to migrate the problem, lost circulation materials (LCMs) should be used to resist fracture reopening with the hypothesis of fracture tip isolation. A triple porosity medium Darcy flowing model was developed to capture pressure distribution along the fracture surface, coupled with a dislocation-based fracture mechanics model to calculate fracture width and assess its propagation. In the model, mud cake on wellbore and fracture surface was considered as the third type of pore medium. The rest dual pore medium models incorporate the fluid flow through LCMs within fracture and the fluid leakoff from fracture into matrix. Sensitivity analyses of the key parameters, such as triple pore medium permeability, viscosity, wellbore pressure, plugging location are implemented, and the results emphasize that fracturing resistance effect of LCMs was controlled not only by the fluid flow within fractures, but also by the flow through mud cake on wellbore into matrix. To inhibit fracture reopening, in high permeability formations, both reduction of mud cake permeability and LCMs permeability were required while in lower permeability formations, fluid flow within fractures dominates and should be minimized. Besides, tip isolation can be achieved by extending sealing fracture length. However, high wellbore pressure or long operation time will result in elevated distances and unallowable fluid loss. Then, wellbore pressure must be reduced to cure the lost circulation. More viscosity of the fluid and total integrity plugging of LCMs are another major factor extending the time for pressure transfer to fracture tip, resisting unexpected fracture propagation. The method proposed in this study clarifies that tip isolation can be realized by fracture plugging and reduction of fluid filtration from the wellbore to matrix. Moreover, operational insights on LCMs design can also be derived.

A phase‐field model for hydraulic fracture nucleation and propagation in porous media

AbstractMany geo‐engineering applications, for example, enhanced geothermal systems, rely on hydraulic fracturing to enhance the permeability of natural formations and allow for sufficient fluid circulation. Over the past few decades, the phase‐field method has grown in popularity as a valid approach to modeling hydraulic fracturing because of the ease of handling complex fracture propagation geometries. However, existing phase‐field methods cannot appropriately capture nucleation of hydraulic fractures because their formulations are solely energy‐based and do not explicitly take into account the strength of the material. Thus, in this work, we propose a novel phase‐field formulation for hydraulic fracturing with the main goal of modeling fracture nucleation in porous media, for example, rocks. Built on the variational formulation of previous phase‐field methods, the proposed model incorporates the material strength envelope for hydraulic fracture nucleation through two important steps: (i) an external driving force term, included in the damage evolution equation, that accounts for the material strength; (ii) a properly designed damage function that defines the fluid pressure contribution on the crack driving force. The comparison of numerical results for two‐dimensional test cases with existing analytical solutions demonstrates that the proposed phase‐field model can accurately model both nucleation and propagation of hydraulic fractures. Additionally, we present the simulation of hydraulic fracturing in a three‐dimensional domain with various stress conditions to demonstrate the applicability of the method to realistic scenarios.

Temperature-sensitive and amphiphilic silica nanoparticle-stabilized Pickering emulsion for water shutoff

Due to the shale matrix's low permeability and narrow pore throats, conventional Pickering emulsion plugging agents are unable to effectively seal the formation, making it challenging to create a reliable mud cake that prevents fluid penetration. To address this issue, SiO2 nanoparticles (PEG200-SiO2-OTES) with amphiphilic and temperature-sensitive properties were synthesized for this study. These modified particles were used to prepare temperature-sensitive Pickering emulsions. The aim was to use the emulsion as a carrier to transport the nanoparticles to the specified stratum to release and seal the pore throat. This temperature-sensitive smart Pickering emulsion-based plugging agent (POOP) is used to water shutoff. The produced material had a particle size of around 20 nm, according to structural studies, and had a sensitive temperature response (response temperature of 80 °C). Furthermore, laboratory tests and characterizations revealed that the average diameter of the POOP emulsion droplets was measured to be 1.62 µm, with the emulsion exhibiting a response temperature for breakage at approximately 80 °C.The plugging agent could release PEG200-SiO2-OTES particles at the response temperature of the formation. At this temperature, the plugging agent particles undergo a transition from hydrophilic to hydrophobic, effectively sealing the low permeability (100 mD) and high permeability (1000 mD) formations with sealing efficiencies of up to 83.56% and 75.07% respectively.

Mechanisms of emerging resistance associated with non-antibiotic antimicrobial agents: a state-of-the-art review.

Although the development of resistance by microorganisms to antimicrobial drugs has been recognized as a global public health concern, the contribution of various non-antibiotic antimicrobial agents to the development of antimicrobial resistance (AMR) remains largely neglected. The present review discusses various chemical substances and factors other than typical antibiotics, such as preservatives, disinfectants, biocides, heavy metals and improper chemical sterilization that contribute to the development of AMR. Furthermore, it encompasses the mechanisms like co-resistance and co-selection, horizontal gene transfer, changes in the composition and permeability of cell membrane, efflux pumps, transposons, biofilm formation and enzymatic degradation of antimicrobial chemicals which underlie the development of resistance to various non-antibiotic antimicrobial agents. In addition, the review addresses the resistance-associated changes that develops in microorganisms due to these agents, which ultimately contribute to the development of resistance to antibiotics. In order to prevent the indiscriminate use of chemical substances and create novel therapeutic agents to halt resistance development, a more holistic scientific approach might provide diversified views on crucial factors contributing to the persistence and spread of AMR. The review illustrates the common and less explored mechanisms contributing directly or indirectly to the development of AMR by non-antimicrobial agents that are commonly used.

Acid-Soluble Drilling Fluid in the Northern Carbonate Reservoir of the Yishan Slope in the Ordos Basin

The carbonate reservoir in the northern Yishan slope of the Ordos Basin presents significant challenges to gas field exploration and development. With its low pressure, limited porosity, low permeability, and abundance of micro-fractures, the reservoir is resistant to acid dissolution. Once solid particles block these fractures during drilling and completion, serious reservoir damage ensues. To address these obstacles, we engineered an acid-soluble, solid-free drilling fluid system in the lab. This involved incorporating sodium carboxymethyl cellulose, heat-resistant starch, fungicides, and lubricants. Contrasted with the commonly used potassium ammonium based drilling fluid system, our innovative solution showed notable improvements. Specifically, the density decreased by 0.04 to 0.06 g/cm3, and the solid content decreased by 4.0% to 6.50%, while the acid-soluble rate surged from 8.50% to 95.45%. In addition, the reservoir permeability recovery value saw an increase from 51.50% to 95.88%. In practical field application, we employed this novel drilling fluid system in ten horizontal wells. Following acid fracturing and reconstruction, these wells registered a 75.94% increase in gas production compared to nearby wells. Our findings demonstrate that the proposed system effectively mitigates the incursion of solid-phase particles into the reservoir while enhancing acidification during acid fracturing. This results in the swift removal of plugging, restoration of formation permeability, and improved well production. Our research thus introduces a drilling and completion fluid system of high efficiency with superior reservoir protection performance, potentially offering substantial benefits to the development of carbonate rock salt gas reservoirs.

Mass Transfer Analysis of CO2-Water-Rock Geochemical Reactions in Reservoirs

It is difficult to exploit low-permeability reservoirs, and CO2 flooding is an effective method to improve oil recovery from low permeability reservoirs. However, in the process of CO2 flooding, acidic fluids dissolved in formation water will react with rock to cause dissolution and precipitation, resulting in pores and precipitates, changing the evolution law of seepage channels, destroying formation integrity, and affecting the effect of CO2 oil displacement. The change in rock’s physical properties and the mass transfer law between CO2-water-rock are unclear. This paper considers the coupling effects of seepage, mechanics, and chemistry when CO2 is injected into the formation. The mass transfer model of CO2-water-rock in the geochemical reaction process is established on this basis. The physical properties of the reservoir after CO2 injection are quantitatively studied based on the microscopic mechanism of chemical reaction, and the migration law of solute in the reservoir rock during CO2 flooding under the coupling effects of multiple fields is clarified. The experimental results show that with the increase in reaction time, the initial dissolution reaction of formation rocks will be transformed into a precipitation reaction of calcite, magnesite, and clay minerals. The porosity and permeability of the rocks near the well first increase and then decrease. The far well end is still dominated by dissolution reactions, and the average values of formation porosity and permeability show an upward trend. Although the dissolution reaction of CO2-water-rock can improve the physical properties of reservoir rocks to a certain extent, the mutual transformation of the dissolution reaction and precipitation reaction further exacerbates the heterogeneity of formation pore structure, leading to the instability of CO2 migration, uneven displacement, and destruction of formation stability. The research results of this paper solve the problem of quantitative calculation of physical parameters under the coupling effect of multiple fields after CO2 injection into reservoirs and can predict the changes in formation physical properties, which can provide a certain theoretical basis for evaluating formation integrity and adjusting CO2 injection under the condition of CO2 flooding.

Research and performance optimization of carbon dioxide foam fracturing fluid suitable for shale reservoir

Compared to conventional fracturing techniques, foam fracturing has numerous advantages, including good shear resistance, strong sand carrying capacity, low fluid loss, low damage, and fast return rates. It is particularly suitable for stimulation in low pressure, low permeability, and water-sensitive formations. Specifically, CO2 foam fracturing is crucial in energy savings and emission reductions, controlling the expansion of reservoir clay minerals, reducing crude oil viscosity, and improving the production of water-locked reservoirs. In this paper, we investigate the foam fracturing fluid and evaluate its performance. We selected thickeners with good foaming stability and foaming agents with excellent performance at low dosage levels, based on experimental evaluation. We finally determined the formulation of the foam fracturing fluid by analyzing the experimental data, such as foam half-life, foam mass, and viscosity. We experimentally evaluated the viscosity, static sand settling properties, and rheological properties of the fluid. After being tested on the reservoir core, the foam fracturing fluid has a viscosity of 2 mPas. Moreover, the residue content is 1.1 mg/L, the surface tension is 24.5 mN/m, and the interfacial tension is 1.5 mN/m. The fluid-carrying sand experiment of 40–70 mesh ceramic particles, commonly used in shale gas fracking, was evaluated. The sand-to-liquid ratio was set at 40% for the static sand-carrying experiment. The flow of the fluid-carrying sand was good, and the settling property was satisfactory for 3 h. We used shale reservoir cores from well W-1 to assess the rate of foam fracture, which was less than 19%. Under the experimental conditions of a shear rate of 170 S−1 and a temperature of 90°C, the viscosity of fracturing fluid was measured to be greater than 50 mPas, 90 min after shear, demonstrating the excellent temperature and shear resistance of the foam fracturing fluid. Using CO2 foam fracturing fluid can significantly improve the reconstruction effect of low permeability hydrocarbon reservoirs (especially unconventional reservoirs) and solve problems related to water resources and environmental protection during the process of oil and gas reservoir development. It will be a major factor in improving construction impacts and addressing water and environmental concerns for low permeability hydrocarbon reservoirs, particularly unconventional ones that utilize CO2 foam fracturing fluids.

Synthesis of Short Peptides with Perfluoroalkyl Side Chains and Evaluation of Their Cellular Uptake Efficiency.

With an increasing demand for macromolecular biotherapeutics, the issue of their poor cell-penetrating abilities requires viable and relevant solutions. Herein, we report tripeptides bearing an amino acid with a perfluoroalkyl (RF ) group adjacent to the α-carbon. RF -containing tripeptides were synthesized and evaluated for their ability to transport a conjugated hydrophilic dye (Alexa Fluor 647) into the cells. RF -containing tripeptides with the fluorophore showed high cellular uptake efficiency and none of them were cytotoxic. Interestingly, we demonstrated that the absolute configuration of perfluoroalkylated amino acids (RF -AAs) affects not only nanoparticle formation but also the cell permeability of the tripeptides. These novel RF -containing tripeptides are potentially useful as short and noncationic cell-penetrating peptides (CPPs).

Experimental Investigation of Mechanical Properties of Clay–Cement Slurry Containing Graphene Oxide

As a widely used material in underground engineering, clay–cement slurry grouting is known for its initial poor anti-seepage and filtration capacity, the low strength of the resulting stone body, and its tendency towards brittle failure. To explore efficient and environmentally friendly grouting materials, industrial-grade graphene oxide (GO) was incorporated into a clay–cement slurry to create a new type of slurry called a GO composite. These GO composites were then utilized to reinforce fractured formations. Uniaxial compression tests, shear strength tests, permeability tests, and electron microscopy scans were conducted to investigate the strength, permeability, and microscopic features of the GO composite-reinforced fractured formations. Furthermore, the optimization effect and application prospects of graphene oxide on clay–cement slurry materials were evaluated. The experimental results demonstrated that the modified slurry effectively improved the compressive strength (increased by 7.2% to 32.5%) and shear strength (increased by 28.6% to 105.3%) of consolidated fractured gravel. By conducting orthogonal experiments with range analysis, variance analysis, and multiple regression analysis, it was shown that there was a strong correlation between the consolidated body and three factors influencing the permeability coefficient. Among these factors, the OPC content had the most significant impact on the permeability coefficient, followed by the GO content. Graphene oxide was found to promote cement hydration reactions, guide the growth of hydration products on the surface of graphene oxide nanosheets, optimize the pore structure in grouting materials, and reduce microcracks between the slurry and the fractured gravel interface. Electron microscopy characterization and fractal analysis revealed that the addition of graphene oxide effectively reduced the degree of microdamage during the sample’s failure process. This ensured the integrity of the sample during the unstable failure process, enhanced the material’s toughness, and improved its ability to resist loads.

Hydraulic fracturing using high-boiling fraction of oil as a fracturing fluid

Background: In recent years, there has been a trend towards deterioration in the structure of residual reserves at the fields of Kazakhstan. A significant part of the reserves is located in low-permeability reservoirs and in the zones not covered by flooding. The main factor negatively affecting the productivity and efficiency of development is the heterogeneity of oil reservoirs.
 Oil-saturated formations are an alternation of permeable oil-saturated sand or limestone and impermeable clay or dolomite layers, lenses and interlayers. Up to 1020 interlayers can be distinguished within the reservoir, which indicates a strong compartmentalization of the reservoirs. Due to the complexity of the structure of oil deposits, it is very difficult or impossible to ensure complete drainage of the entire volume of the deposit and complete coverage of oil displacement by water into production wells through injection wells.
 Aim: Increasing oil recovery in a cost-effective way.
 Materials and methods: Experimental studies of the processes of impact on the bottomhole formation zone with high-boiling oil components were carried out using a laboratory machine for diamond drilling, an installation for determining the permeability of a rock in terms of liquid and gas, an installation for determining oil viscosity, and an installation for pumping fracturing fluid into the reservoir model.
 Results: As a result of applying the hydraulic fracturing method using high-boiling oil components, it is possible to increase the permeability of low-permeability formations and significantly increase oil recovery.
 Conclusion: Due to the geological structure of multi-layer oilfields, water-based gel fracturing fluids to increase oil flow to wells are considered ineffective due to the adsorption of gels with long molecules in the pores of the formation and swelling of the clay particles of the reservoir when they interact with the water-based fluid.

A coupling prediction model of annular pressure build-up for deepwater oil and gas wells during transient-state testing

To accurately predict annular pressure build-up of deepwater high pressure-high temperature oil and gas wells during the transient-state testing, a coupling prediction model of trapped & untrapped annular pressure build-up is proposed. For the short-term process of gas well transient testing, a wellbore transient heat transfer model has been established. Then the improved coupling model of trapped & untrapped annular pressure build-up is established, which is not only novelly considering fluid thermodynamic properties (isobaric expansion coefficient and isothermal compression coefficient) under high pressure-high temperature conditions and annulus fluid mass changes of untrapped annulus, but also considering annulus volume changes. For precise coupling calculating the annular pressure build-up, the annulus is divided into infinitesimal grid cells along well depth. The impact of different considering factors, testing times, testing production rates, formation permeability and cement sheath sealing positions on the annular pressure build-up in the model is investigated. The results show that conventional models (high pressure-high temperature properties and mass changes of the fluid are not considered) will greatly overestimate the annular pressure build-up; as the testing time increases, the impact of untrapped annulus fluid mass changes on the annular pressure build-up will gradually take the dominant role; reasonably optimizing the setting of untrapped annulus open hole section in high permeability formations and increasing the distance between cement sheath and the upper casing shoe can effectively relieve the increasing annular pressure build-up. These findings can achieve accurate prediction of trapped and untrapped annular pressure build-up, and play an important role in guaranteeing the wellbore integrity and safety of deepwater oil and gas wells during transient-state testing.