Gas Wells Research Articles

Effect and mechanism of calcination on improving the hydration activity of titanium extraction slag

Titanium extraction slag (TES) is a special waste residue in China’s Panxi region. It exhibits low hydration activity because of its high titanium content and carbon- and chlorine-based impurities introduced during production. Thus, TES wastes can only be stored in large quantities. Oil and gas wells’ high-temperature and high-pressure environments contribute to TES hydration. However, its hydration activity should be improved to transform it into a well cementing material. The optimal calcination temperature was 550 ℃. Using NaOH (6 %) as an activator, the compressive strength values of the calcined TES cured for 1 and 14 days reach 19.23 and 34.40 MPa, respectively, 65.49 % and 39.78 % higher than those of untreated TES. These values meet oil and gas well cementing construction requirements. X-ray diffraction, 29Si nuclear magnetic resonance, scanning electron microscopy, and other characterization methods indicate that calcination can reduce the content of the glassy phase in TES. However, it induces impurity removal and reduces the degree of glassy phase polymerization. Thus, TES’s ion leaching and deposition rates, hydration, and compressive strength after calcination improved. Therefore, the method proposed in this study can be successfully used to convert TES into new cementing materials for large-scale applications.

A Full-Stage Productivity Equation for Constant-Volume Gas Reservoirs and Its Application

Gas well production involves various stages, including stable, variable, and declining production. However, existing production-capacity equations typically apply only to the stable production stage, limiting their effectiveness in evaluating gas well productivity across all stages. To address this, the material balance equation and Darcy’s equation were employed to account for changes in average formation pressure due to pressure drop funnels. The concept of a pressure-conversion skin factor was introduced, and its approximation was developed, leading to the establishment and solution of a full-stage productivity equation. Numerical simulations were then conducted to verify the accuracy and applicability of this equation. The findings are as follows: ① The full-stage productivity equation remains effective even when production rates and pressure are not constant, with the only potential source of inaccuracy being the approximative solution for the pressure conversion-skin factor. ② Numerical simulations demonstrated that the approximate solution closely matched the numerical simulation results for average formation pressure across various production stages and fundamental parameters, showing a consistent trend and high precision. The approximate and independent approximation solutions for absolute open-flow capacity were nearly identical, indicating the full-stage productivity equation’s applicability throughout the production of gas wells. ③ Application results revealed that the full-stage productivity equation offers superior accuracy compared to the modified isochronous well test. ④ The approximate solution generally provides slightly higher accuracy, and the independent approximate solution effectively eliminates the influence of gas leakage radius. Therefore, the use of the approximate solution is recommended to calculate the average formation pressure and the independent approximate solution to calculate the absolute open-flow capacity. The full-stage productivity equation developed in this study is not constrained by the production system, making it suitable for productivity evaluation across all stages of gas well production. This has significant implications for the effective development of gas fields.

A novel foaming formulation with excellent salt-resistant for foam assisted deliquification of gas wells

In this paper, an excellent foaming formula for natural gas well deliquification was developed, which was based on the synthesized dodecyl ethylethanolamine (DEEA), commercially obtained cocamidopropyl betaine (CAPB) and sodium lauryl glutamate (SLG). The foaming properties and liquid unloading properties were studied, which showed that the optimal molar ratio of DEEA/CAPB/SLG ternary complex turned out to be 14:21:15. At a total concentration of 15 mM in the liquid phase, the optimal DEEA/CAPB/SLG mixture exhibited excellent foaming and liquid unloading capability at various conditions of methanol, condensate oil and salts contents and temperatures. At the methanol content of 45%, the foaming efficiency and liquid unloading efficiency of the DEEA/CAPB/SLG mixture were measured to be 100% and 25.5 ± 2.2%, respectively. When the condensate oil content was 10–30%, the liquid unloading efficiency ranged from 18.0 ± 2.1% to 25.0 ± 2.5%, which was much higher than that (8.3 ± 0.9%) obtained without condensate. The presence of salts retarded the performance of the DEEA/CAPB/SLG mixture, however, the addition of a chelating agent, trisodium nitrilotriacetic acid (NTA), to DEEA/CAPB/SLG could enhance the foaming efficiency and unloading performance at a salinity level of up to 41 × 104 mg/L, which might be the highest salt-resistant level of the gas well foaming mixture. The introduction of 10% methanol exhibited a positive effect on the DEEA/CAPB/SLG mixture’s foaming and liquid unloading performance against temperature (up to 90 °C). At 90 °C, the DEEA/CAPB/SLG foam could remove almost all the liquid from the column.

Evaluation of heavy metal fixation ability from drilling waste of oil and gas wells using treated sugarcane bagasse

Evaluation of heavy metal fixation ability from drilling waste of oil and gas wells using treated sugarcane bagasse

Study on the corrosion and damage behaviours of P110 tubing of deep shale gas wells

This study conducts weight loss corrosion experiments by a high-temperature autoclave to investigate the corrosion behaviours and the damage rules of mechanical properties of P110 tubing under coupling working conditions of multiple factors (temperature 50–155 °C, CO2 content 1%–2%, Cl− content 10,000–20,000 mg/L). It analyses the characteristics of corrosion products of P110 steel using X-ray diffraction, scanning electron microscopy, and energy dispersive spectroscopy (EDS). In addition, the 3D morphology and size of local corrosion pits are measured microscopically. The mechanical properties’ damage behaviours at different tubing positions are analysed by constant-load tensile stress corrosion tests. The results showed that the average corrosion rate of the tubing reaches the maximum value of 1.627 mm/a at the middle section of the shale gas well. With an increase in temperature and CO2 partial pressure, the depth of the local corrosion pits on the tubing rises from 3.8 to 25.0 μm. The yield strength and tensile strength of the tubing at the bottom-hole section reduced by less than 8%, and the coupling damage effect of stress and corrosive mediums is serious. The tubing shows a sensitivity to stress corrosion cracking at the bottom-hole section. It was recommended that corrosion inhibitors should be cyclically added to inhibit CO2 corrosion to control the corrosion rate of the tubing within the range of medium-degree corrosion, thus ensuring that the strength reduction of P110 tubing under the corrosion working conditions containing CO2 and sulphate-reducing bacteria coupled with tensile stress is within the controllable range of safety factor.

Quantitative Study on the Anticollapse Ability of Casing in Shale Gas Wells under Complex Load Conditions.

Implementing novel technologies, including the "well factory" model and zipper fracturing techniques, has become prevalent in shale gas development. During completion operations such as lowering casing and multistage fracturing, the casing is subjected to many complex loads, reducing its strength and increasing the risk of casing deformation. By establishing a casing wear model and conducting multistage cyclic loading experiments and numerical simulations, we analyzed the change rule of casing anticollapse strength under complex loads, developed a calculation method for casing comprehensive anticollapse ability under complex loads, and applied the method to an illustrative calculation. The study shows that the wear effect during completion has a negligible impact on the strength of the casing. The casing anticollapse strength exhibits a linear decline in correlation with the number of cycles. The zipper fracturing operation resulted in a nonuniform distribution of geo-stress around the well, and the casing anticollapse strength demonstrated a nearly linear decline in correlation with the nonuniformity of geo-stress. In the presence of both internal and external effects, the casing anticollapse strength exhibited a decline exceeding 15%, thereby increasing the risk of casing deformation. This research method can provide computational guidance for preventing casing deformation in field fracturing construction.

Coupling analysis of multi-annular temperature and pressure gradients in oil and gas wells considering fluid thermodynamic properties

A coupled prediction model for temperature and pressure is developed for the annulus of multiple casings to prevent damaging the integrity of oil and gas wells due to annular pressures. The complex structure of the oil and gas well requires dividing the calculation of the annular pressure into three stages based on the annulus level. The annular temperature and pressure gradients of the wellbore are then studied. The hydrostatic pressure changes of the annular fluid at different temperatures, pressures, and well depths are analyzed considering the influence of the isobaric expansion coefficient and isothermal compression coefficient in annular fluids. The pressure gradients of annular fluids A, B, and C with production time and well depth are discussed along with the deformation of production casings. Results show that the annular fluid density and hydrostatic pressure decrease with the increase of temperature, while they will increase with the increase of annular pressure. The annular pressure increases first and then decreases from the bottom of the well to the wellhead. The annular pressure increases the fastest in the early production stages.

Low-density granite-based geopolymer for well cementing: The role of burnt lime in enhancing early strength

In the pursuit of sustainable solutions within the oil and gas industry, the environmental and mechanical limitations of Ordinary Portland Cement (OPC) have led to the evaluation of more sustainable alternative materials for oilwell cementing applications. Particularly in shallow-depth cementing operations, where low-density slurries are essential to prevent formation breakdown, current solutions fall short in balancing environmental impact with the industry's performance requirements. Geopolymers, known for their reduced carbon footprint and comparable mechanical properties, have been seen as a promising alternative. However, increasing water content to lower the slurry density remains a challenge for geopolymers due to the weakening effect and prolonged reaction. The specific role of burnt lime (CaO) has the potential to enhance the early strength of low-density geopolymers yet remains under-explored for this particular case. This study aims to fill this gap by examining the effects of two different reactivities of CaO on a low-density granite-based geopolymer at low temperatures and investigate the potential of CaO to enhance the early strength of low-density geopolymers, aiming to provide a sustainable alternative to traditional cementing materials in oil well operation. The investigation consists of viscosity measurements, pumpability tests, and compressive strength evaluations. Additionally, isothermal calorimetry, TGA, XRD, and SEM were conducted to gain a deeper understanding of the behavior of each sample. Supplementary tests were conducted to evaluate the effect of varying CaO concentrations and the impact of mud contamination on the performance of low-density geopolymers. The investigation revealed that calcium oxide did not significantly impact the initial viscosity of the slurry however, it affects gelation and rate of the reaction. Short-term strength was shown to be affected by CaO at two different temperatures, yet negligible effects were seen in the long-term period for geopolymers with a high water-to-solid ratio. The findings suggest that CaO can significantly enhance the early strength of geopolymers, which are crucial properties for cementing operations in oil and gas wells. This could contribute to accelerate the possibility of geopolymers as a viable sustainable replacement for Portland cement especially in shallow and low-temperature well-cementing applications.

Study on the Gas Phase Liquid Carrying Velocity of Deep Coalbed Gas Well with Atomization Assisted Production

In order to clarify the gas-phase carrying capacity after the atomization of water from the bottom of deep coalbed wells, considering characteristics of atomization-assisted production and the dynamic equilibrium principle of gas–liquid two-phase flow in the wellbore, the gas-phase liquid-carrying drop model was established, and the solution method of the upstream and downstream driving force of liquid drop flow was studied. We also verified the theoretical model through physical simulation. Then, the law for the influence of droplet size, wellbore inclination, wellbore diameter, and wellhead back pressure of the critical liquid-carrying velocity in the gas phase is analyzed using the model. The results show the following: ① the larger the diameter of atomized droplets, the greater the gravity force applied to it, the worse the ability to be carried by the gas phase, a onefold increase in droplet diameter corresponds to the increase in the minimum critical velocity of the gas phase by 1.45 times; ② with the increase in wellbore inclination, the liquid-carrying capacity of the gas phase decreases, and the minimum critical liquid-carrying velocity of equal diameter droplets increases by 0.01438 m/s or 1.27 times for the increase in wellbore inclination by 10°; ③ with the increase in wellbore diameter, both the driving force of a droplet of equal diameter and the flow resistance through the gas phase in the wellbore decrease within the range of a driving pressure difference of 0.2 Mpa; the decrease in liquid-carrying velocity caused by the decrease in received flow resistance can reach the maximum value of 0.0473 m/s; ④ with the increase in wellhead back pressure, the driving force of equal-diameter droplets decreases, the resistance against passing through the high-concentration gas phase increases, and the gas-phase-carrying droplets start the game; ⑤ the atomization-assisted production has the function of drainage gas recovery, and the adoption of atomization-assisted production technology can increase the production time of a coalbed gas flowing well, enabling the wells to have a good transition time interval for the conversion of flowing wells to pumping ones, which provides a precise production dynamic basis for the efficient design and implements the overall strategy of drainage gas recovery by deep-well pumping. In short, this technology has the high-efficiency liquid-carrying function of “water atomization to help liquid-phase flow and increase gas production”, as well as obvious technical advantages, which can provide a new idea for the development of deep coalbed methane wells and other types of gas wells with water.

Geological, physiochemical, mineralogical, and rheological characterizations of clay deposits in Northeast Libya

ABSTRACT This study was conducted on bentonite deposits in Um Al Rozm and Ain Al Ghazala areas that lie between Latitudes º32 “00 ‘30 and º32 “33 ‘30 N and Longitudes º23 “00 ‘30 and º23 “20 ‘30 E in Northeast Libya. The objective of this study is the assessment of geological, physiochemical, mineralogical, and rheological properties and the potentiality of utilizing these rocks as drilling fluids for oil and gas wells. Chemical and mineralogical analyses were performed by XRF and XRD, respectively. Rheological properties are investigated before and after the treatment process by adding additive materials such as Na2CO3 and CMC. The chemical analysis results of bentonite showed a discrepancy in the proportions of the major components. The results after the treatment process for bentonite in Um Al Rozm exhibit rheological properties consistent with those stipulated by API and other standard bentonites, but for Ain Al Ghazala, the results are unsatisfactory. Mineral analysis of bentonite from the two areas revealed a difference in the mineral composition. The bentonite of the Um Al Rozm area is Na-bentonite, while the bentonite of the Ain Al Ghazala area is Ca-bentonite, whose rheological properties aren’t acceptable as drilling fluid properties stipulated by API.

The Current Status and Development Trend of Water Control Technology for Horizontal Wells

In the advancement of bottom water reservoir development, water breakthrough poses a significant challenge to the productivity of oil and gas wells, underscoring the paramount importance of effective water control strategies. Given the intricate nature of the factors leading to reservoir water breakthrough, a one-size-fits-all approach to water management is non-existent. Rather, tailored water control techniques are necessary to address the diverse causes of this phenomenon. This paper delves into the evolution and application of water control technologies, particularly focusing on the prevalent horizontal well water control methodologies. Horizontal well variable density water control, segmented water control, double horizontal well oil recovery water control, along with advanced solutions such as ICD (Inflow Control Device), ICV (Inflow Control Valve), AICD (Autonomous Inflow Control Device), and AICV (Autonomous Inflow Control Valve) water control systems are comprehensively introduced. Furthermore, center-controlled, mechanical plugging, and chemical plugging water control technologies are also examined in depth, accompanied by a thorough analysis of their respective strengths, limitations, and adaptability to various scenarios. By keeping abreast of both domestic and international trends in horizontal well water control, the future trajectory of this field is forecasted. Emerging as key technologies are novel composite water control systems, dual-purpose water control and sand prevention techniques, and intelligent water control solutions. These advancements promise to revolutionize the management of water breakthrough in bottom water reservoirs, enhancing oil and gas recovery efficiency and sustainability.

Multi-scale nonlinear reservoir flow simulation based on digital core reconstruction

During the exploitation of oil and gas reservoirs, changes in reservoir physical or fluid properties will lead to alterations in formation seepage capacity, subsequently impacting the productivity of oil and gas wells. Therefore, it is crucial to evaluate the variations in reservoir physical and fluid properties as well as their influence on oil and gas well productivity during reservoir exploitation.It employs a descriptive approach to investigate cross-scale (i.e., micro-scale → small-scale → large-scale) fluid seepage phenomena in water flooding. By leveraging digital core reconstruction technology and focusing on micro-pore network simulation, it establishes an analytical framework for studying cross-scale seepage fields, facilitating the exploration of the micro-seepage mechanism that governs non-homogeneous water flooding's impact on liquid production capacity within a reservoir. Integrating constraints from micro-pore network simulation and small-scale core displacement test data, while considering macro-heterogeneity near wellbore areas as flow unit divisions and superposition bases within large-scale reservoirs, it reveals the nonlinear flow characteristics of changes in liquid production capacity in water-flooding oil reservoirs based on microscopic digital core analysis. This approach aligns with findings from small-scale core testing and sweep coefficient correction while also addressing the non-uniform distribution characteristics of physical parameters within large-scale reservoirs.By integrating permeability field characteristics at three levels, this approach optimizes its technical advantages in describing dynamic permeability fields at each level, thereby facilitating precise prediction of water drive oil development effects.

Wastewater production footprint of conventional and unconventional oil and gas wells in North America

Wastewater production footprint of conventional and unconventional oil and gas wells in North America

Numerical simulation analysis of casing-in-casing cementing in the horizontal section of shale gas wells

Numerical simulation analysis of casing-in-casing cementing in the horizontal section of shale gas wells

Experimental study on the critical flow velocity for sand production in shale gas wells

The purpose of this study is to determine the critical flow velocity for the sand production of shale gas wells under different conditions through experiments and to predict the sand production of gas wells. The experiment is based on the API fracture diversion experimental device. To study the influence of shale physical properties on sand production, a shale rock plate was used as the propped material in the API fracture conductivity experiment. The results show that when the closure pressure exceeds the critical fracture point of shale, the critical flow velocity for sand production will decrease on a large scale. A proppant with a large particle size is helpful for maintaining fracture opening, and the critical sand production velocity is greater. The higher the viscosity of the fluid is, the lower the critical sand production velocity. This paper provides a reference method for determining the critical sand production velocity in shale gas wells.

Efficient development technology of Upper Paleozoic Lower Shihezi tight sandstone gas reservoir in northeastern Ordos Basin

Abstract The Lower Shihezi Formation of the Upper Paleozoic at the northeastern margin of the Ordos Basin develops widely distributed thick massive and multilayer gas reservoirs. How to formulate an effective development policy is a difficult and hot spot. In this article, reservoir characteristics and production capacity influencing factors of the tight gas sandstone in Lower Shihezi Formation in this area are systematically studied, and optimization schemes of development measures for massive and multilayer gas reservoirs are proposed. The results show that the petrophysical characteristics of the small pore–mesopore type gas reservoir in the target layer are the best, with the average porosity, permeability, and coordination number of 7.6%, 0.74 mD, and 3.3, respectively. Thick sand body, high structural position, good petrophysical properties, and high drilling rate of sandstone are all conducive to drilling high production gas wells. Development policies for massive and multilayer gas reservoirs have been formulated: (1) the preferred well type for massive gas reservoir is vertical well + horizontal well, while the preferred well type for multilayer gas reservoir is horizontal well + stepped horizontal well; (2) the reasonable horizontal segment length of massive gas reservoir is 1,000 m, and the reasonable horizontal segment length of multilayer gas reservoir is 1,250 m; (3) similar to massive and multilayer gas reservoirs, the more the fracture stages, the higher the cumulative gas production, and the optimal fracture stage number of both gas reservoirs is 8; (4) the optimal fracture half-length and the angle between the fracture and the horizontal section are 140 m and 90°, respectively; and (5) the reasonable well spacing of vertical wells is 600 m and that of horizontal wells is 750 m. The development policy proposed in this study is suitable for the efficient development of complex tight sandstone gas reservoirs in similar areas.

Solar thermal energy and CO2 storage in saline aquifers for renewable energy space heating

There are a large number of abandoned oil and gas wells and corresponding depleted oil/gas reservoirs (DOGR) throughout the world, which are recognized as one of the best geological formations of saline aquifers for thermal energy storage and CO2 sequestration and however, the lack of innovative technique limits the efficient use of underground storage space. Here a novel scheme of storing solar thermal energy and concomitantly sequestrating CO2 in DOGR for renewable energy heating is proposed, which uses CO2 as thermal energy storage working fluid. The process of thermal energy storage and release as well as CO2 sequestration in DOGR are simulated, and thermal performance and CO2 dissolution in DOGR are analyzed. The results for twenty years of operation show that the thermal recovery efficiency reaches up to 82.93 %, which is 76 % higher than the traditional high temperature aquifer thermal energy storage. Energy storage capacity per heating season, energy storage density per unit volume of underground space and energy efficiency are respectively 57,222.27 GJ, 22,943.01 kJ/m3 and 96.19 %. Furthermore, the dissolved CO2 during thermal energy storage and extraction is 54.76 % larger than that of mere CO2 sequestration due to the repeated expansion and contraction of gas and water interface caused by the periodically injection and extraction of CO2, indicating that energy storage accelerates CO2 sequestration. To sum up, the new scheme is a high value-added technical route for solar thermal energy storage and CO2 sequestration as well as renewable energy heating.

Numerical Analysis of Low-Enthalpy Deep Geothermal Energy Extraction Using a Novel Gravity Heat Pipe Design

Geothermal energy, derived from the Earth’s internal heat, can be harnessed due to the geothermal gradient between the Earth’s interior and its surface. This heat, sustained by radiogenic decay, varies across regions, and is highest near volcanic areas. In 2020, 108 countries utilised geothermal energy, with an installed capacity of 15,950 MWe for electricity and 107,727 MWt for direct use in 2019. Low-enthalpy sources require binary systems for power production. Open-loop systems face issues like scaling, difficult water treatment, and potential seismicity, while closed-loop systems, using abandoned petroleum or gas wells, reduce costs and environmental impacts greatly. The novel geothermal gravity heat pipe (GGHP) design eliminates parasitic power consumption by using hydrostatic pressure for fluid circulation. Implemented in an abandoned well in north-east (NE) Slovenia, the GGHP uses a numerical finite difference method to model heat flow. The system vaporises the working fluid in the borehole, condenses it at the surface, and uses gravitational flow for circulation, maintaining efficient heat extraction. The model predicts that continuous maximum capacity extraction depletes usable heat rapidly. Future work will explore sustainable heat extraction and potential discontinuous operation for improved efficiency.

Mechanism and application of gas phase trapping by spontaneous imbibition

For fractured gas reservoirs with strong water drive, gas phase trapping affects the gas recovery significantly. The recovery may be less than 50% for some reservoirs while it is only 12% for Beaver River gas field. The gas phase trapping mechanism has been revealed by the results of depletion experimental test. The residual pressure of the trapped gas is as high as 11.75 MPa with a 12.8 cm imbibition layer resulting in gas recovery deceased 49.5% compared with that without imbibition layer. A mathematical model is built to calculate the imbibition thickness based on capillary pressure and relative permeability of the matrix. The gas phase trapping are analyzed by two representative wells in Weiyuan gas field, the intermittent production reinforces the imbibition thickness and result in gas trapped in the matrix block with high residual pressure for the low performace gas wells, the extremely low gas recovery can be explained more rationally. That lays a foundation of improving the gas recovery for fractured reservoirs.

Evaluation of casing corrosion in different well sections and application of anti-corrosion schemes for shale gas wells in the southern Sichuan basin

Evaluation of casing corrosion in different well sections and application of anti-corrosion schemes for shale gas wells in the southern Sichuan basin