Interpretable Machine Learning for Shale Gas Productivity Prediction: Western Chongqing Block Case Study

Fracturing technologies of deep shale gas horizontal wells in the Weirong Block, southern Sichuan Basin

The Sichuan Basin, China's largest shale gas development region, encompasses the natural fracture-rich Luzhou Block. The high-density non-uniform natural fractures in this area significantly influence the construction quality and efficiency of deep shale gas horizontal wells. Research indicates that the mechanical properties and spatial distribution of these natural fractures affect the propagation and diversion of hydraulic fractures, but the governing laws remain to be fully elucidated. This study categorizes the Luzhou Block's naturally fractured areas into six types based on their development characteristics and relative positions to horizontal well sections. Furthermore, it introduces a method for morphological inversion of shale gas well fracture networks using microseismic monitoring data. This method was applied to 24 deep shale gas wells in the Block and combined with the six types of naturally fractured areas, the above underlying influence mechanism was derived. Then it reveals how naturally fractured areas with different characteristics influence the fracture network morphology and complexity and analyzes the relationship between fracture network quality and well production. The results demonstrate that during the hydraulic fracturing process in deep shale gas reservoirs, the development areas of natural fractures can capture or intercept the fracture network, obstructing its expansion behavior, reducing its area and complexity, and ultimately leading to a decrease in gas well production. In particular, when a small-angle, large-scale naturally fractured area develops near the wellbore, the hydraulic fractures will quickly propagate to this area. After activating and communicating the natural fractures, it may cause rapid fluid filtration and a sharp drop in the net pressure within the fractures, severely impacting stimulation performance. It suggests that adjusting construction parameters appropriately may mitigate the adverse impact of natural fractures on the fracturing effect. These findings clarify how naturally fractured areas with different development characteristics affect stimulation performance and offer insights and references for designing and optimizing deep shale gas well fracturing technology.

In the Luzhou region of the Sichuan Basin, deep shale gas horizontal wells at depths over 3,500 meters have experienced casing deformation issues during staged fracturing operations. This problem has significantly constrained the development efficiency of deep shale gas in this area. A multi-factor analysis was conducted on typical deep shale gas horizontal wells in the Luzhou block, further clarifying the main characteristics and causes of casing deformation. Physical simulation analysis of casing deformation during shale gas well fracturing revealed the mechanism behind the casing deformation, providing a theoretical basis for prediction and prevention. It was found that casing deformation in deep horizontal wells in the Luzhou block is primarily influenced by geological and engineering factors. During fracturing, large volumes of fracturing fluid are injected into the formation, and after connecting with natural fractures, the formation exerts shear stress on the wellbore, leading to casing damage. The results show that in the presence of natural fractures, varying stress conditions can alter the direction of hydraulic fracture propagation. Under strike-slip fault stress conditions, hydraulic fractures are prone to deflection, causing shear failure. The stress state and the inclination of natural fractures are the primary factors influencing the slip and movement of the fracture surfaces. Under strike-slip fault stress conditions, natural fractures are more likely to experience slip and shear, leading to casing deformation. The closer the natural fractures are to the Coulomb failure surface, the more likely they are to slip and displace, causing casing deformation. Further analysis of field wells confirmed the factors contributing to casing deformation, providing technical guidance and experience for the prediction and prevention of casing deformation.

Horizontal gas wells are one of the key technologies for the production of shale gas reservoirs. Compared with conventional gas reservoirs, horizontal shale gas wells have ultra-long and complex lateral sections. Overall, toe-up, toe-down, and horizontal trajectories will be exhibited in the lateral section. The statistical results of field production data indicate that the lateral trajectory has a significant impact on the estimated ultimate recovery. However, the mechanism has not yet been fully revealed owing to the complicated two-phase flow in lateral pipes. Therefore, taking horizontal shale gas wells’ lateral section as the research object, we designed our experimental parameter ranges based on horizontal shale gas wells in the Changning shale gas field. Simulation experimental tests were conducted on the pipe with an inclined angle from −15° to 15° to analyze the effects of different gas velocities, liquid velocities, and pipe inclinations on flow patterns and liquid holdup. Based on our observations and measurements, we evaluated the flow pattern prediction methods and drew a new flow pattern map for pipes with an inclined angle from −15° to 15°. Based on the momentum conservations between the gas and liquid phases and measured liquid holdup data, a new liquid holdup model was established in the pipes with inclined angle from −15° to 15°. Experimental and field-measured data were collected to verify the new method’s accuracy.

The right of W mineral cover an area of 143.77km2. As shale gas horizontal wells are prone to casing deformation by segmental fracturing, the casing deformation rate exceeds 45%, which seriously affects the production capacity construction of shale gas wells in W block. A set of techniques for high-strength balanced fracturing process in multiple clusters for preventing casing deformation in W shale gas wells has been developed, including: 1) two evaluation indexes, namely stress-strain brittleness index and vertical stress and difference index between vertical stress and minimum horizontal stress, have been added to establish W deep shale fracturing quality evaluation index plate and realize fine division of segment clusters; 2) a multi-scale fracture network fracturing numerical model for W Shale gas wells was established for the first time via Eclipese software, and key fracture parameters such as optimal fracture half-length, flow conductivity and complexity were obtained; 3) in engineering construction, a multi-cluster, small particle size and variable displacement combination injection fracturing scheme has been proposed for two injection modes: planar perforation and spiral perforation, respectively, with the objective of reducing casing. INTRODUCTION Shale gas, as a new unconventional natural gas resource, occupies an increasingly important position in the energy sector. The economic development of deep shale gas in the US has gone through a process of continuous exploration and testing, improvement and refinement, with some blocks now meeting the requirements for economic development. Among them, 3 deep shale gas blocks in Haynesville, Eagle Ford and Canna Woodford with burial depths of 3500-4100m have been economically developed with single well gas production of more than 5×104m3/d after segmental fracturing of horizontal wells, with an average final gas recovery of more than 1×108m3 per well and an integrated cost of less than US$12 million per well (T.Lowe et al.,2014; Mauricio et al.,2013).

ABSTRACT: The performance of deep shale gas reservoirs is controlled by several factors, and there is a difference in gas production between fracturing stages. Thus, clarification and quantification of main controlling factors of production is indispensable. In this paper, based on the distributed optic fiber logging data of a deep shale gas well in southern Sichuan, the hierarchical fuzzy comprehensive evaluation method and analytic hierarchy process were used to determine major controlling factors, and a performance evaluation model was established. The results show that the gas production of fracturing stages calculated by above model is highly consistent with measured results. Reservoir physical properties are major factors affecting gas production. The production potential of a stage with high geological quality can be improved by increasing clusters, average pumping rate, proppant injection intensity to achieve complicated fracture networks and increasing the proportion of ceramic proppant to ensure effective conductivity. Given that the contribution of stage lengths to gas production is low, for an interval with poor geological quality, stage lengths can be increased appropriately to reach a balance point of cost-effectiveness and stimulation effect. This study provides a basis for shale gas fracturing optimization and production improvement. 1. INTRODUCTION With increasing demand for clean energy, the shale gas plays a vital role in global energy market (Ma & Xie, 2018; Zhang et al., 2019; Zou et al., 2021). Sichuan Basin has abundant shale gas resources (Ma, 2017; J. Wang et al., 2023). Changning, Fuling, Weiyuan, Weirong shale gas fields have been discovered successively in Upper Ordovician Wufeng Fm and Lower Silurian Longmaxi Fm marine shale (Feng, 2022; Guo, 2021). In more than ten years of exploration and practice, understanding on reservoir has been deepened, and the horizontal well drilling and fracturing technology has been improved. At present, the development technology for shale gas reservoirs shallower than 3500 m is sophisticated, and Weiyuan-Changning-Zhaotong National Shale Gas Demonstration Zone has been formed, realizing large-scale industrial development of medium-depth and shallow shale gas (He et al., 2023; P. F. Jiang et al., 2023; Xie et al., 2019). Deep shale gas has become an important replacement target for shale gas development in China, and enhancing exploration and development of deep shale gas is of great strategic significance to ensure national energy security (Yang et al., 2019). The shale gas production capacity is affected by many factors, and there is difference in EUR of single wells in the same block and even in fracturing stages (He et al., 2018). Jia et al. (2017) analyzed geological and engineering factors affecting the production of shale gas horizontal wells in Changning-Weiyuan and Zhaotong demonstration zones, and proposed the technical direction of increasing the production of horizontal wells in different blocks. Wang et al. (2017) carried out study on the trend of effects of key geological and engineering factors on fracturing effect, and analyzed the influence degree of factors on the 6 months cumulative production of single wells by using multiple linear regression method. X. Chen et al. (2020) carried out fine reservoir evaluation based on the geological and well logging data of coring wells in Weiyuan area, and quantified relationship between fracturing fluid volume, proppant volume and pumping rate and fracture network effectiveness. J. Chen et al. (2020) et al. carried out study on main controlling factors of shale gas production of horizontal wells in Changning area, and established the production prediction model of productivity in shale gas horizontal well fracturing with the BP neural network method based on genetic algorithm. A lot of efforts have been put in research on analysis of controlling factors of shale gas productivity and establishment of productivity prediction models. Nevertheless, there is a lack of research on deep shale gas and systematic research on quantitative evaluation of non-uniform production control factors. Therefore, understanding the origin of gas production differences and quantification of main factors are of great significance to deepen geological understanding, optimize development plan and increase the single well production.

ABSTRACT: Lost circulation is a technical problem in drilling engineering, resulting in increased drilling cost and extended drilling cycle. Reservoir rocks in Block A of Shale Gas have the characteristics of low porosity and low permeability, strong heterogeneity and fault fracture development. Lost circulation is mainly caused by fracture. Seismic fracture prediction to assess lost circulation risk has limitations. Therefore, it is necessary to study more effective methods of lost circulation risk assessment. In this paper, based on the analysis of lost circulation, seismic prediction on fractures and rock mechanics parameters in block A, a comprehensive evaluation method of lost circulation index is formed by using seismic prediction of the relative degree of fracture development, fracture apparent length and the combination of Young’s modulus and Poisson’s ratio in 3D attribute modeling, and the classification evaluation standard is established. The method is used to evaluate the lost circulation risk of completion drilling in shale gas well of Block A, and the evaluation results are consistent with the well drilling data. Lost circulation index evaluation method can effectively evaluate the risk of lost circulation in shale formation with low porosity and low permeability, strong heterogeneity and fracture development, which can promote the efficient development of shale gas. 1. INTRODUCTION With reservoir exploration and development, it is more difficult for conventional oil and gas resources to increase reserves and production. Unconventional oil and gas resources are of strategic importance. As an important unconventional energy source, shale gas has become a hotspot in global resource development. Shale gas development can effectively alleviate the energy crisis, reduce the pressure on natural gas gaps, improve the energy structure, and ensure national energy security. In recent years, with the continuous development and improvement of the basic theory and technology development of shale gas in China, Fuling, Sichuan Changning-Weiyuan and Zhaotong national shale gas demonstration areas have been established. Shale gas production in southern Sichuan basin reaches 128×108m3 in 2021. Horizontal well drilling technology is the key to the shale gas resources development. With continuous research and exploration, PetroChina has made remarkable progress in unconventional oil and gas horizontal well drilling and completion technology through the introduction of advanced oil and gas engineering technology from North America. The average length of the horizontal section of shale gas horizontal wells in 2021 has reached 1760 meters, and the average drilling cycle is controlled within 80 days(Jun et al.2018). However, the complex geological conditions of China’s shale gas lead to drilling accident. According to statistics, the average well accident time of shale gas horizontal wells in 2021 is 7.25 days, mainly for lost circulation time. Lost circulation is still the main factor restricting the drilling cycle and drilling efficiency of shale gas horizontal wells.

Research and engineering application of pre-stressed cementing technology for preventing micro-annulus caused by cyclic loading-unloading in deep shale gas horizontal wells

Accurate modeling of multi-fracture horizontal shale gas wells is the holy grail of shale gas reservoirs. Modeling shale gas wells is difficult because of the lack of subsurface data and inability to model correct physics. Some of the biggest uncertainties in shale gas reservoirs are the length of fractures, existing natural fracture network, matrix permeability, adsorption, and size of stimulated rock volume (SRV). Numerous techniques are used to reduce these uncertainties, such as Diagnostic Fracture Injection Test (DFIT), micro-seismic monitoring and Special Core Analysis (SCAL). In this paper we present a new numerical approach to model multi-fracture shale gas wells. The problem is simplified in terms of modeling the natural fracture network intersected by the induced fractures by creating a SRV around the well with size and permeability of the SRV used as uncertainty parameters. Individual fracture stages are modeled explicitly by utilizing logarithmic local grid refinement (LGR). We apply this methodology to two field cases. First case corresponds to a multi-fracture shale gas well in Oklahoma. A detailed design of experiment study is also performed to identify main uncertainties and generate a probabilistic production forecast. Numerical simulation model, coupled with an in-house probabilistic tool, is used for this study. Second case corresponds to shale gas horizontal well in east Texas. Daily production and pressure data is history matched using a numerical model. History matching provided us with great insight and better understanding of different uncertainty parameters and how they affect early to late production of horizontal shale gas wells.

The development mode of deep shale gas “Pad drilling” cluster horizontal wells could greatly reduce the single-well drilling cost and is also the significant measure for scale benefit development of shale gas. For pad drilling, the small wellhead distance of cluster well group, complicated well profile and long horizontal section result in such engineering problems as high well collision probability in upper well section, high trajectory control difficulties and large drill string torque and drag. A reasonable 3D horizontal well profile and the reasonable profile parameters are the premise for the safe and rapid drilling of shale gas horizontal well. Therefore, optimizing type and the well profile parameters suitable for deep shale gas horizontal well could help improve drilling efficiency, lower drilling risk and save drilling cost. In this paper, the three types of trajectory profile, including 3D trajectory in spatial oblique plane (large 3D), dual 2D trajectory and dual 2D and small 3D combined trajectory profile were developed, and under the same surface location and target zone, three different types of shale gas horizontal well were planed; the differences of these three trajectories in well depth, drill string torque and drag and well separation factor were compared through drill string torque and drag analysis and collision prevention analysis. The analysis results show: Dual 2D trajectory or dual 2D and small 3D combined trajectory is featured by small drill string drag and torque, low trajectory control difficulty and low well collision probability and is therefore more suitable for trajectory plan of deep shale gas horizontal wells.

Technical difficulties in the cementing of horizontal shale gas wells in Weiyuan block and the countermeasures

Theoretical analysis and field application of cooling bottom hole by mud density reduction during drilling in deep shale gas well

Recently, shale gas resource has been developed beneficially on a large scale in China. More than 400 shale gas horizontal wells have been drilled in south Sichuan since 2014. However, with the increasing buried depth of target stratum and the extension of horizontal intervals of shale-gas horizontal wells, the development of Chinese shale gas is becoming more and more difficult. Over the past four years, some wellbore instability related issues–stuck pipe and rotary steering system fish downhole occured during drilling the shale gas wells. The reason is particularly analyzed based on the drilling performance data of these horizontal wells, which will offer the establishment of general practice guidelines and recognition of opportunities for improvement in south Sichuan shale drilling. Oil-based drilling fluid (OBM) is a typical drilling fluid type currently used in the south Sichuan shale play. However, water-based mud (WBM) has also been used in more than 60 wells since 2015. It is analyzed the drilling performances of over four hundred horizontal south Sichuan shale wells drilled by 14 operators from 2014 to 2018, including overall drilling days, well depth, lateral length, as well as fish rotary steering systems. A comparative analysis is also made among different drilling fluid types of different operators to assess their performances and to identify the key challenges when drilling south Sichuan shale. The analyses contained formation characteristics, mud chemistry, mud rheological property, plugging property, solid content, stability, density and chloride and so on. Then, lots of experiments are carried out to solve the problems of borehole stability and hole cleaning. The analysis shows that the drilled well depth and the horizontal length are getting bigger and bigger. The overall performance of WBMs lags behind that of OBMs in south Sichuan shale drilling. Most fish RSS happened when the operations of back reaming, pick up stands and trip-out were carried out. The lost circulation nearly covered all the well sections. These issues lead to excessive amounts of time spent on costly fishing, sidetracking, plugging operations and the long drilling days. The performances of oil-based drilling fluids of different operating companies were quite different. Lab test results show that shale formation is more complex than before. With the increase of well depth, the clay minerals decreased and brittle minerals raised. The natural fractured formation increases and the drillable "sweet" layer thins. The main mechanics of shale instable is the strong capillarity on amphiphilic shale surface causes the invasion of fluid into formation, then leads the fracturing and de-lamination along the bedding planes and enlargement of natural fractures. It is effective to control the harmful low-density solid for improving the performance of OBM. The suitableφ6 value of OBM and a big delivery capacity will work in hole cleaning while drilling lateral sections. A nanoscale polymer was developed in lab to improve the plugging effect significantly after adding in OBM. An amphiphobic material was used to transform the wettability of shale, which was favorable for borehole stability. The analyses and results of this study on drilling performance data provide lessons learned and general guidelines for current drilling practices such as drilling fluid selections and mud property control in the south Sichuan shale gas of China.

Multi-stage hydraulic fracturing has become the key technology to complete horizontal wells in shale gas reservoirs. In each stage, multiple perforation clusters are used to create multiple transverse fractures. How to place these clusters significantly affects both the short-term and long-term production performance of horizontal shale gas wells. The author’s previous work has demonstrated that when more than two fractures are created, mechanical interaction among fractures creates strong stress concentrations around the inner fractures. As a result, the fractures between two edge fractures, i.e., sub-center and center fractures, are limited to dilate, and their widths are much less than the edge-fractures’ width. In this paper, reservoir simulation models were constructed by quantitatively incorporating the findings of the author’s previous work to investigate the impacts of the number of perforation clusters and cluster spacing on production performance of horizontal shale gas wells. The paper illustrates that with the same cluster spacing, the scenario with more clusters has lower ultimate gas recovery because of increased number of less-effective inner fractures. Given the same lateral length of a horizontal well, although reducing cluster spacing increases the total number of fractures, smaller cluster spacing doesn’t necessarily improve well performance. An inadequate small cluster spacing can actually lead to more less-effective and ineffective fractures, and therefore lower gas rate and ultimate recovery.

Shale gas is mostly produced using horizontal wells, since shale gas reservoirs have low porosity and permeability. It is challenging to predict a horizontal well’s critical liquid-carrying gas flow rate because horizontal wells have more complicated well structures and gas–liquid two-phase pipe flows than vertical wells. In addition, there are significant differences between shale gas reservoirs and conventional natural gas reservoirs as well as dynamic changes in the liquid production rate. The majority of critical liquid-carrying models currently in use in engineering are based on the force analysis of droplets in the gas stream or liquid film on the pipe wall in annular-mist flow in the vertical wellbore. However, they do not take into account the impact of changes to the entire wellbore structure and dynamic changes in the liquid production rate on gas–liquid two-phase flow patterns and liquid carrying in the wellbore. In order to perform the critical gas velocity test for liquid carrying in the entire wellbore of horizontal wells, a visual liquid-carrying simulation experimental device for the entire wellbore of horizontal wells and a high-speed camera were used in this study. The onset of liquid accumulation was analyzed comprehensively according to the overall increase of the wellbore liquid and the change of the system pressure. A modified K–H wave theory liquid-carrying model was developed by taking into account the impacts of liquid production rate and well inclination angle based on the experimental data, the K–H wave theory, the cross-section actual gas velocity, and the angle correction correlation formula. The improved liquid-carrying model is in good accordance with the test findings, according to the experimental results. In Shunan Gas Mine, Sichuan, China, there are eight deep shale gas wells, which produced a total of 25 sets of tests. The modified model was used to forecast and diagnose the liquid-carrying capacity in the entire wellbore of these wells. The diagnosis results are in good agreement with the actual production situation, and the coincidence rate is 92%.