Low Formation Pressure Research Articles

Research on Optimization of Intermittent Production Process System

As gas wells enter later production stages, the formation pressure decreases and liquid accumulates at the bottom of the gas well. The formation pressure is insufficient to lift the accumulated liquid from the bottom of the well to the surface. At this time, a large number of gas wells need to undergo intermittent production to maintain their production capacity. This article focuses on the four stages of intermittent production in gas wells, considering the changes in slip gas holdup, pressure, and gas–liquid flow in and out of tubing and casing, and establishes a transient mathematical model for intermittent production in gas wells in stages. By using the dynamic tracking technology of moving liquid slugs to divide the wellbore grid and solve it in stages, the optimal shut-in time for intermittent production of gas wells was obtained. The transient mathematical model developed for intermittent gas well production achieved a high historical fit accuracy of over 90%. This indicates that the simulation results are in line with the actual situation of gas well intermittent production and can effectively guide intermittent production. The optimized intermittent production system of gas wells has a higher cumulative gas production compared to the original system, achieving the optimization of intermittent production system. This method is beneficial for guiding efficient production of gas wells in low-pressure formations.

Shale oil recovery by CO2 injection in Jiyang Depression, Bohai Bay Basin, East China

Laboratory experiments, numerical simulations and fracturing technology were combined to address the problems in shale oil recovery by CO2 injection. The laboratory experiments were conducted to investigate the displacement mechanisms of shale oil extraction by CO2 injection, and the influences of CO2 pre-pad on shale mechanical properties. Numerical simulations were performed about influences of CO2 pre-pad fracturing and puff-n-huff for energy replenishment on the recovery efficiency. The findings obtained were applied to the field tests of CO2 pre-pad fracturing and single well puff-n-huff. The results show that the efficiency of CO2 puff-n-huff is affected by micro- and nano-scale effect, kerogen, adsorbed oil and so on, and a longer soaking time in a reasonable range leads to a higher exploitation degree of shale oil. In the “injection + soaking” stage, the exploitation degree of heavy hydrocarbons is enhanced by CO2 through its effects of solubility-diffusion and mass-transfer. In the “huff” stage, crude oil in large pores is displaced by CO2 to surrounding larger pores or bedding fractures and finally flows to the production well. The injection of CO2 pre-pad is conducive to keeping the rock brittle and reducing the fracture breakdown pressure, and the CO2 is liable to filter along the bedding surface, thereby creating a more complex fracture. Increasing the volume of CO2 pre-pad can improve the energizing effect, and enhance the replenishment of formation energy. Moreover, the oil recovery is more enhanced by CO2 huff-n-puff with the lower shale matrix permeability, the lower formation pressure, and the larger heavy hydrocarbon content. The field tests demonstrate a good performance with the pressure maintained well after CO2 pre-pad fracturing, the formation energy replenished effectively after CO2 huff-n-puff in a single well, and the well productivity improved.

Flowback Additive for Acidizing Fluid to Stimulate Carbonate Gas Reservoirs

Summary Acidizing of oil- and gas-bearing carbonate reservoirs is generally undertaken by using strong mineral acids such as hydrochloric acid (HCl) to enhance permeability. One of the major challenges associated with HCl injection is tuning the reactivity profile to favor the transport of live acid deep into the reservoir while achieving a minimum rock face dissolution. The mineral acid is therefore emulsified in a hydrocarbon phase (e.g., diesel) to retard its reactivity with the rock matrix. The use of emulsified acid is hindered by several limitations such as low emulsion stability at high temperatures, pumping limitations due to high viscosity, the potential of formation damage, and cumbersome mixing procedures at the field scale. In addition, the brines formed as a result of this reaction can be difficult to produce due to higher density and capillary pressures, unfavorable wettability, and low formation pressure. Here, we report on the development of dual-purpose additives that were specifically designed to enhance the recovery of high-density brines and retard the acid/rock reactivity upon addition to the stimulation treatment. Accordingly, seven new additives with fluid flowback properties were developed for use in a single-phase acidizing fluid consisting of HCl (15 wt% and 28 wt%) with the required additives, such as corrosion inhibitor and intensifier, and H2S scavenger. The flowback enhancers (FBEs) were formulated from a blend of water, ester or terpene solvents, alcohols, and surfactants to form optically clear nano- and microemulsions. Surfactant selection was driven by the need to exhibit demulsification properties with condensate, high chemical and thermal stability, compatibility in strongly acidic media, and high-density brines under harsh reservoir conditions. To assess the FBE performance in acidizing formulations (i.e., to serve as both an FBE and retarder), screening studies consisting of static rock dissolution tests and surface tension measurements were performed to downselect FBEs suitable for this application. This was coupled with brine displacement tests in addition to compatibility and stability studies. FBEs that demonstrated superior performance were then selected for further evaluation under reservoir conditions [i.e., core flow matrix acidizing to measure regained permeability and computed tomography (CT) scan for analyzing the wormhole propagation]. The droplet size of the as-prepared nano- and microemulsions was found to be between 10 nm and 850 nm. The FBEs formulated in this study were found to prevent emulsion formation in the presence of condensate and demonstrated remarkable chemical and thermal stability in concentrated acid at temperatures up to 300°F for a duration of up to 24 hours, as confirmed by the consistent low surface tension values (21–29 mN/m). With regard to fluid displacement, column tests performed under ambient conditions revealed quick brine displacement with recovery exceeding 75 vol% in comparison with 16 vol% in the absence of the FBE. Interestingly, the addition of a select FBE from this study to 28 wt% HCl was found to retard the reaction of carbonate dissolution at room temperature. This led us to assess the performance under reservoir conditions utilizing core flow testing. Accordingly, the addition of FBE-F to 28 wt% HCl led to an improvement in permeability by up to 267% as compared with 15% without FBE added. These results are further supported by the CT scan images of the acidized cores, which revealed the formation of a deeper wormhole in the presence of a select FBE.

Technological efficiency of applying viscoelastic systems for temporary blocking of productive reservoir when completing wells under conditions of abnormally low formation pressures

The article examines the technical and economic aspects of well killing under conditions of abnormal low reservoir pressure (ALRP). The possibility of joint use of compositions for temporary blocking of a productive formation, having different functional abilities to plug fluid-conducting channels, has been studied. Requirements for blocking fluids (BF) for killing during repair works in wells with excess ALRP have been formulated. The results of research and technical solutions in the field of development of viscoelastic systems for temporary blocking of productive formations in wells in conditions above the ALRP are presented. The results of laboratory and bench studies on the development of a gel-forming destructuring polymer-based biosol and fillers are presented. The advantage of using a destructurable biological fluid for temporary blocking of a productive formation in conditions above the maximum pressure limit using chemical reagents belonging to the following groups: polymers, salts, surfactants, acids, alkalis and fillers has been analyzed. The results of determining the mechanical properties of the resulting BF gel are presented. A gel-forming composition has been proposed that has high blocking properties and an optimal formulation of an alkaline destructor that ensures the destruction of the gel based on gammaxan. Formulations of viscoelastic destructurable fluids for killing wells in conditions exceeding the ALRP have been recommended for practical use. Keywords: well; bottomhole formation zone; blocking; blocking fluids; viscoelastic compositions; destructuring; ALRP.

Fluid-Loss Control Technology: From Laboratory to Well Field

Effective fluid-loss control in oil wells is a critical concern for the oil industry, particularly given the substantial reserves situated in carbonate reservoirs globally. The prevalence of such reservoirs is expected to rise with the slow depletion of hydrocarbons, intensifying the need to address challenges related to deteriorating reservoir properties post well-killing operations. This deterioration results in significant annual losses in hydrocarbon production at major oil enterprises, impacting key performance indicators. To tackle this issue, this study focuses on enhancing well-killing technology efficiency in carbonate reservoirs with abnormally low formation pressures. To address this issue, the authors propose the development of new blocking compositions that prevent the fluid loss of treatment fluids by the productive reservoir. The research tasks include a comprehensive analysis of global experience in well-killing technology; the development of blocking compositions; an investigation of their physico-chemical, rheological, and filtration properties; and an evaluation of their effectiveness in complicated conditions. The technology’s application in the oil and gas condensate fields of the Volga-Ural province showcases its practical implementation. This study provides valuable insights and solutions for improved fluid-loss control in carbonate reservoirs, ultimately enhancing well performance and hydrocarbon recovery.

Повышение эффективности глушения скважин на истощенных газоконденсатных месторождениях с сверх аномально низкими пластовыми давлениями

The problem is studied by the example of gas condensate fields at the final stage of development, where production wells have abnormally low reservoir pressures and their killing for repair work is a serious challenge requiring a search for new solutions. The work is motivated by the need to create a method for controlling hydrodynamic processes in a pre-blocked bottom-hole zone of the formation, for carrying out repair work in wells, preventing destruction of the reservoir formation and ensuring the preservation of its fluid-capacitance properties. The possibilities of an integrated approach to killing wells under conditions of extremely low formation pressures are considered, which includes controlling hydrodynamic processes in the “well-reservoir” system, previously blocked in the near-wellbore zone by special process fluids. It has been specified that the use of blocking fluids (with filler) helps to level the injectivity profile and form an insulating screen in the bottomhole zone of the formation, creating the necessary conditions for killing wells in order to carry out repair work in them. To control hydrodynamic processes, a mathematical model of the blocking process in the near-wellbore formation zone is proposed. It has a three-stage scheme that ensures equalization of the injectivity profile under conditions of extremely low formation pressures. The possibilities of using gel-forming blocking fluids with filler to create a temporary screen that prevents the penetration of killing fluid into highly permeable formations from abnormally low formation pressures have been explored. Based on the results of the study, we can conclude that the control of hydrodynamic processes in the near-wellbore zone of the formation at abnormally low formation pressures creates the necessary condition for effective blocking of the productive horizon in gas and gas-condensate wells, and due to the sequential treatment of the formation with a special liquid to level the injectivity profile and gel-forming blocking composition, allows one to kill the well and prevents the working fluid from penetrating into the depths of the formation during work.

Laboratory studies of induction of flow using vibratory wave draining in carbonate low-permeability reservoirs

The object of the study is a laboratory unit for inducing flow to the well using vibration wave draining in carbonate low-permeability reservoirs. Vibratory wave draining is a method used to stimulate flow draining to the well. The method is based on the fact that mechanical waves generated in the soil can cause the opening of microcracks and pores, which leads to an increase in the fluid flow. Vibratory wave scouring can be effectively used to increase fluid flow in low-permeability carbonate reservoirs. Carbonate reservoirs are a common type of reservoir in the oil and gas industry. They often have low permeability, which makes it difficult to extract fluid. With the help of the plunger device developed in the work, a fluid disturbance was created, thereby creating elastic waves in the conventional well (plastic pipe), which were measured using a manual contact vibrometer. This demonstrated the effectiveness of the vibratory method to increase the well productivity and helped to improve the permeability of the rocks, providing better access to challenge the influx of hydrocarbon products. It is shown that with a significant decrease in the permeability of the formation well zone (FWZ), the flow induction should be started only after the restoration works. Otherwise, the well will be significantly hydrodynamically imperfect due to the quality of the reservoir opening, and the flow of production into the well will occur only through a few separate areas of the reservoir with relatively high permeability, which will lead to uneven production of the reservoir and low return of hydrocarbons. Therefore, it is advisable to use the developed method of influencing the productive layer in low-permeability rocks, such as carbonates with layers of clay, siltstones, argillites, and others, with low formation pressures. The obtained results are based on the generation of vibrations that are transmitted to the wellbore. These vibrations can help break up contaminants and fines in carbonate rocks, facilitating the release of hydrocarbon products and improving permeability.

Accumulation and exploration enlightenment of shallow normal-pressure shale gas in southeastern Sichuan Basin, SW China

Based on the drilling, logging, experimental and testing data of Well PD1, a shallow normal-pressure shale gas well in the Laochangping anticline in southeastern Sichuan Basin, the shallow shale gas reservoirs of the Ordovician Wufeng Formation to Silurian Longmaxi Formation (Wufeng–Longmaxi) were investigated in terms of geological characteristics, occurrence mechanism, and adsorption-desorption characteristics, to reveal the enrichment laws and high-yield mechanism of shallow normal-pressure shale gas in complex structure areas. First, the shallow shale gas reservoirs are similar to the medium–deep shale gas reservoirs in static indicators such as high-quality shale thickness, geochemistry, physical properties and mineral composition, but the former is geologically characterized by low formation pressure coefficient, low gas content, high proportion of adsorbed gas, low in-situ stress, and big difference between principal stresses. Second, shallow shales in the complex structure areas have the gas occurrence characteristics including low total gas content (1.1–4.8 m3/t), high adsorbed gas content (2.5–2.8 m3/t), low sensitive desorption pressure (1.7–2.5 MPa), and good self-sealing. Third, the adsorbed gas enrichment of shales is mainly controlled by organic matter abundance, formation temperature and formation pressure: the higher the organic matter abundance and formation pressure, the lower the formation temperature and the higher the adsorption capacity, which is more beneficial for the adsorbed gas occurrence. Fourth, the shallow normal-pressure shale gas corresponds to low sensitive desorption pressure. The adsorbed gas can be rapidly desorbed and recovered when the flowing pressure is reduced below the sensitive desorption pressure. Fifth, the exploration breakthrough of Well PD1 demonstrates that the shallow complex structure areas with adsorbed gas in dominance can form large-scale shale reservoirs, and confirms the good exploration potential of shallow normal-pressure shale gas in the margin of the Sichuan Basin.

Development technologies for Triassic Chang 7 shale oil in Ordos Basin: A case study of Qingcheng Oilfield, NW China

The reservoirs in the seventh member of the Triassic Yanchang Formation (Chang 7 Member) in the Qingcheng Oilfield of the Ordos Basin are characterized by thin sandbody, tight rocks, high heterogeneity, low formation pressure coefficient, and complex geomorphology. Through the efforts in the stages of exploration, appraisal, pilot testing and development, a series of key technologies have been formed, including “sweet spot” optimization, differentiated three-dimensional well deployment, fast drilling and completion of large-cluster horizontal well, intensively-staged volume fracturing in long horizontal well, and optimization of rational production system. Furthermore, a production organization mode represented by factory-like operations on loess platform has been implemented. Application of these technologies has enabled to significantly improve the single-well production of the Qingcheng Oilfield, reduce the investment cost, and realize a large-scale and beneficial development at a full cost below $55 per barrel. In 2022, the annual production of Chang 7 shale oil in the Ordos Basin reached 221×104 t, accounting for 70% of the annual shale oil production of China. The practice of development technologies in the Qingcheng Oilfield provides valuable references for efficient development of continental shale oil.

Technical and technological solutions for limiting water inflow in gas wells with a horizontal bore end

The article considers the main group of reasons for water inflow in gas wells under conditions of abnormally low formation pressures. Approaches are outlined for the conditional allocation of the main stages that the well goes through until it is decommissioned due to complete watering. Two different ways of solving the problem of water inflow limitation in gas wells with a horizontal bore end are examined. The most promising technical and technological solutions for isolating the flooded section of the reservoir are discussed. It is noted that the proposed physicochemical method for limiting water inflow using phase permeability modifiers is more reliable, including when the level of gas water contact increases significantly and there is a high probability of watering the well. To improve formation treatment efficiency and achieve the best performance, mathematical calculations are proposed to determine the minimum installation depth of the modifying screen in the formation, which ensures the achievement of a technical result. The parameters of the modifying composition for preventing water inflow and the procedure for determining the parameters to prevent water inflow in gas wells are given. Some results of applying the technology of water inflow limitation in gas wells with preliminary blocking of the bottomhole formation zone are considered. Keywords: well; watering; pressure; water inflow restriction; modifier; method; composition

Numerical Simulation Study of Pressure Transfer Based on the Integration of Fracturing, Shut-in and Production in Tight Reservoirs

As an important replacement resource for conventional oil and gas, tight oil and gas are quite abundant. Long horizontal wells and multi-stage fracturing have become key technologies for developing tight oil and gas, and reasonable shut-in measures can improve the utilization efficiency of fracturing fluid. Therefore, it is especially critical to master the pressure transfer law during the shut-in process in tight reservoirs to further improve the energy efficiency of fracturing fluid. However, many studies have mostly focused on the separate design of fracturing, shut-in and production, and have not yet revealed the pressure transfer law during shutting in well based on the integration of fracturing, shut-in and production, which makes it difficult to realize the efficient development of tight oil and gas. Taking the tight oil reservoir in Block M as an example, the geological model of the target block was established using an integrated fracturing development software platform, on which the simulation of fracture extension, well shut-in and production was carried out. The changes in the reservoir pressure field during shutting in well were analyzed, and the influence law of fracturing fluid volume, shut-in time, reservoir original formation pressure and fracture network complexity on the effect of well shut-in were studied to optimize the shut-in system. It was found that the retained fluid increases, the pore pressure of the near-fracture matrix increases, and the diffusion distance of fracturing fluid to the distant matrix increases. The tight oil production increased after shutting in well, and the optimal retained fluid volume of 9600 m3 was actually preferred based on the model. The pore pressure of the near-fracture matrix decreases as the shut-in time increases, the diffusion distance of fracturing fluid to the distant matrix increases, and the pore pressure decreases with an increase in diffusion distance. The tight oil production increased after shutting in well, and the optimal shut-in time was actually preferred to be 90 days based on the model. The increase in formation pressure on abnormal low pressure formation is larger, and the production can be significantly improved after shutting in well. The more complex the fracture network is, the more obvious the non-uniform variation in matrix pore pressure during shutting in well. The research is of great significance for the optimal design of a shut-in system for tight reservoirs and the sustainable development of oil and gas resources in China.

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.

Features of the structure, study and development of a unique geological object of the Republic of Komi – the Nizhnechutinskoye oil field

The modern idea of the geological structure of oil deposits of the Nizhnechutinskoye field is presented. The uniqueness of the field lies in the shallow depths of productive deposits. The oil-saturated layer is 100 m. The shallow depths of productive formations led to low formation temperature and pressure. Under such conditions, oil is inactive, characterized by high viscosity, and dissolved gas is practically absent. The features of the formation of the sedimentary cover in the area of the field predetermined the block structure, while the rocks of the productive horizon are characterized by a complex system of vertical fractures, which greatly complicates the process of oil recovery. A distinctive feature of the studied section of the field is the presence of effusive rocks underlying the main productive stratum and overlapping the lower productive layer. The article systematizes the results of field trial operation, which revealed a number of complicating factors, which is associated primarily with the uniqueness of the geological structure of the studied deposits. Despite the solid history of studying the Nizhnechutinskoye field, which has almost 300 years, given the negligible depth of productive deposits, oil production at this field still remains a difficult task.

Analysis of the distributions of petrophysical characteristics of sections and their relationships with loss during drilling wells in old fields with anomalously low formation pressures

The article is devoted to the study of the main factors that play an important role in the occurrence of such complications as lost circulation. The article presents the results of studies of the distributions of the petrophysical characteristics of the reservoirs and their influence on the occurrence of losses, which made it possible to substantiate the tasks, ways to solve them and the nature of the initial information necessary for this; based on the methods of mathematical statistics and fuzzy cluster analysis, an assessment was made of the mutual correspondence of geological conditions and the severity of losses, which made it possible to justify the interval, the severity of losses and the choice of a way to deal with them. Keywords: abnormally low reservoir pressures; petrophysical characteristics; fuzzy cluster analysis; losses.

Особенности проведения ремонтновосстановительных работ в газовых скважинах месторождений Западной Сибири, находящихся на стадии падающей добычи

Introduction. The article discusses the features of carrying out repair and restoration work in gas wells of Western Siberian fields that are at the stage of declining production. The compositions of process fluids used to block the bottomhole formation zone during well killing, to isolate the inflow of formation waters in various mining and geological conditions are given. The compositions of process fluids used in repair and restoration work in certain fields of Western Siberia are presented. They are easily removed when inducing inflow from the formation, and allow providing the required pressure at the bottomhole, as well as maintaining the reservoir properties of the productive formation and preventing its destruction. Materials and research methods. Based on the generalization of field experience in killing wells, fields at the stage of declining production, the results of their own theoretical, laboratory and bench studies. Research results and their discussion. When killing wells with temporary blocking of the bottomhole formation zone, the choice of the composition of process fluids with high stability, low filtration, in a wide range of adjustable density and rheological properties, allows creating the necessary repression on the formation and carrying out various operations in the well without complications. Technological fluids for killing wells, which are direct-type emulsion systems based on a composite reagent, are pseudo-plastic systems in terms of rheological parameters, where the density range is 900-1000 kg/m3. The properties of the emulsion solution based on the kill fluid reagent are determined by the complex effect of the reagents included in its composition. Filler-based blocking fluids are used to temporarily block the bottomhole formation zone of wells, and are prepared by introducing the calculated amount of the reagent into the required volume of killing fluid based on the killing fluid reagent. As a water-insulating composition for creating an insulating barrier in the reservoir, a formulation of a gel-forming composition based on a reagent – a dry mixture for carrying out repair and restoration work and a gelforming reagent – is considered. Conclusions. Based on the study, it was determined that the most promising technology for killing wells under conditions of abnormally low formation pressures is the technology of preliminary blocking of the bottomhole formation zone using blocking fluids with filler. To ensure high efficiency of repair and restoration work, preliminary calculations of the process fluids used are necessary, taking into account the mining and geological conditions of the reservoir and the geometric parameters of the well.

Corrosion Behavior of P110 Steel in Simulated CO<sub>2</sub> and Formation Water Environment

The corrosion behavior and mechanism of P110 steel tubing in in low CO2 particle pressure and high salinity formation water environment was investigated through high temperature and high pressure dynamic immersion tests, macro-morphology analysis, scanning electron microscopy(SEM) inspection, energy disperse spectroscopy(EDS) analysis and X-ray diffraction(XRD) analysis. The Results showed that the increasing of CO2 partial pressure accelerated the corrosion process of P110 tubing steel, and the corrosion rates of P110 tubing decreased with the increasing of temperature. Furthermore, the high content of Ca2+ in the formation water also had a big influence on the corrosion behavior of P110 tubing steel, for it could affect the precipitation quantity and morphology of CaCO3 at different temperature and CO2 particle pressure.

Technical advances in well type and drilling & completion for high-efficient development of coalbed methane in China

Compared with the United States, Australia, Canada, and other countries, China's coalbed methane reservoir is featured by low formation pressure, low permeability, low gas saturation, and strong heterogeneity, which not only increases the difficulty of reservoir stimulation but also restricts the single well production and the recovery efficiency of coalbed methane (CBM). In view of this, the research and application of horizontal drilling and completion technology of CBM at home and abroad are reviewed to provide references and theoretical supports for the advancement of the horizontal well engineering technology of CBM in China. This paper introduces a series of horizontal drilling and completion technologies (e.g., the well type design, well structure optimization, well trajectory control, wellbore stability, completion optimization, reservoir protection, etc.). The advanced technologies and their adaptability, including screen pipe completion and stimulation with dual-layer tubular strings, radial horizontal well screen pipe completion and magnetic steering drilling, are dialectically discussed in this paper. In addition, a novel integrated engineering mode for the efficient and green development of deep CBM and coal through the underground “well factory” is proposed. The conclusions are as follows: (1) In view of the geological conditions and surface environment of the coal seam in China, the horizontal drilling and completion technologies of high rank coalbed methane should be further refined, and an integrated development for the coal measure gas is required; (2) More efforts should be made to strengthen the innovative research on horizontal drilling & completion technology for low-medium rank coals and the broken coal, so as to identify the efficient development mode for the complex coalbed methane reservoir; (3) When encountering major technical challenges during the green and efficient development of unconventional coal mines such as deep coal mines, low grade coal mines and thin coal seams in China, it is necessary to explore the development mode via in-situ conversion process based on underground “well factory” to realize the integrated green and efficient development of deep CBM and coal; (4) The high quality transformation with low-carbon and green energy in China will not only ensure national energy security, but also achieve the goal of “carbon peaking and carbon neutrality”.

An Integrated Method to Mitigate Hazards from Hydraulic Fracturing–Induced Earthquakes in the Duvernay Shale Play

Summary In recent decades, a remarkable increase in induced seismicity in the Western Canada Sedimentary Basin (WCSB) has been largely attributed to hydraulic fracturing (HF) operations in unconventional plays. However, a mitigation strategy concerning geological, geomechanical, and operational susceptibilities to HF-induced seismicity has not been well understood. This work proposes an integrated method to mitigate potential risks from HF-induced seismicity in the Duvernay play near Crooked Lake. The geological susceptibility to induced seismicity is evaluated first from site-specific formation pressure and a distance to the Precambrian basement. The regional in-situ stress and rock mechanical properties are then assessed to determine the geomechanical susceptibility to induced seismicity. Next, the operational factors are determined by comparing induced seismicity with operational parameters such as total injection fluids and proppant mass. It is found that regions with a low formation pressure (<60 MPa), a great distance from the base Duvernay to the Precambrian basement (>260 m), a low minimum principal stress (<70 MPa), and a low brittleness index (<0.45) tend to be induced-seismicity-quiescent regions. Finally, a multiple linear regression (MLR)-based approach is proposed by considering the relative importance of different parameters. The MLR analysis indicates that brittleness index, formation pressure, and total injection volume are the top three controlling factors. Three new horizontal wells are drilled and the MLR analysis of these wells using the three most important parameters is conducted. High-resolution monitoring results indicated that 95% of the induced events had a local magnitude of less than 2.0 during and after the HF operations (3-month time window and 5-km well-event distance), among which the maximum magnitude reached ML3.05 (<red light magnitude ML4.0). Therefore, the MLR-based approach was successfully validated, suggesting that this approach can be applied to mitigate potential seismicity risks in upcoming wells in the Fox Creek region. Such a workflow can also be applied to other regions to guide seismicity-free fracturing operations in unconventional plays.

Stimulation mechanism and model establishment of enhanced imbibition oil recovery for A nano fracturing fluid

Chang 7 shale reservoir of Ordos Basin has characteristics of low porosity, ultra-low permeability, and low formation pressure coefficient. After hydraulic fracturing, the production of shale oil declines rapidly, and it has no solutions to replenish the formation energy. Currently, a nano variable-viscosity slickwater (named: NSI) is being used in the field for fracturing production. Compared with conventional fracturing fluid systems, the NSI system can increase production of oil wells by more than 4 times, and its economic benefits are very remarkable. The lab experiment shows that NSI system after the gel breaking has ability of enhanced imbibition oil recovery (EIOR), which may be an important stimulation mechanism of the NSI system. However, the contribution of EIOR to oil production is still unclear, and the corresponding mechanism and model are still lacking. Therefore, the fracturing parameters of Changqing Chang 7 reservoir were firstly optimized without considering the imbibition, and two wells were used to carry out field experiments with NSI and conventional slickwater. Then, commercial software is used to predict oil production. It was found that the actual production was higher than the predicted production. To explain this phenomenon, the effect of imbibition on enhanced oil recovery was investigated experimentally under reservoir temperature and pressure. The NMR T2 spectrum was quantitatively analyzed to clarify the variation of oil and water distribution in different pores of core. The results showed that capillary force was dominant in the small pores of core, and small pores were the main positions of EIOR. Water film was formed in large pores, which increases the migration resistance of the liquid, and allowed gravity to play an obvious role. Finally, based on the modified Aronofsky index model, an EIOR model suitable for the Changqing Chang 7 reservoir was proposed, which achieved a better match between actual production and simulated production of horizontal wells.

Optimization of cementing displacement efficiency based on circulation pressure of a shale gas horizontal well in low pressure and leakage formations

The well trajectory of horizontal wells are constantly changing due to the variation of well inclination and azimuth with depth, leading to a large difference of displacement efficiency in the annulus compared to a vertical well. In low pressure and leakage formations, optimizing injection parameters to improve displacement efficiency is a hot and difficult research topic for researchers and field engineers, particularly the complex well. A fluid flow model inside the casing and annulus was established during primary cementing under an eccentric casing. Pressure distribution in the eccentric and concentric annuli were compared with the field data. Based on the principle of the maximum circulation pressure being lower than formation leakage pressure, the injection rate and fluid density were optimized to improve displacement efficiency, using Computational Fluid Dynamics (CFD) methods and investigating the mud retention volume on the wall. The results indicated that the pressure model in a casing eccentricity with an error of 1% to 3.5% is in good agreement with the actual pump pressure. Frictional pressure loss in the eccentric annulus was 13% to 25% lower than in the concentric annulus. Appropriately increasing the fluid density difference (spacer and lead slurry), the mud retention volume in the annulus of the horizontal section decreased significantly, while increasing the injection rate at the wellhead had little influence on displacement efficiency. The sequence of displacement efficiency from high to low was horizontal section > deflecting section > vertical section. The results of this study allow a better understanding of casing eccentricity effect on circulation pressure and equivalent circulation density (ECD) distributions in the annuls. The complex displacement mechanism analysis for the horizontal, deflecting, and vertical sections provides practical guidance in improving displacement efficiency by optimizing the most effective operation parameters.