To clarify the source and accumulation model of deep oil and gas in the Dongdaohaizi Sag of the Junggar Basin, the geochemical characteristics of source rocks and hydrocarbons in sag, slope, and peripheral uplift zones were comparatively investigated through maceral analysis, n-alkane and biomarker testing, and fluid inclusion homogenization temperature measurement. The research results are obtained in four aspects. (i) The Carboniferous source rocks in the Dongdaohaizi Sag are mainly composed of humic kerogen with remarkable potential of gas generation, while the source rocks in the Middle Permian Lower Wuerhe Formation are represented by hybrid kerogen capable of both oil and gas generation. Moreover, the sag zone is found with a much higher thermal maturity of organic matters (Ro) than the uplift zone. (ii) The crude oil in the eastern Dinan Uplift and Baijiahai Uplift is a mixture of mature oil from the Lower Wuerhe Formation and the Carboniferous crude oil, with natural gas primary consisting of over-mature Carboniferous dry gas, mixed with minor Permian natural gas. The crude oil in the slope and sag zones mainly originates from mature to highly-mature oil from the Lower Wuerhe Formation, mixed with minor Carboniferous oil, while the natural gas is a mixture from the Lower Wuerhe Formation and the Carboniferous. (iii) There are three phases of hydrocarbon charging in the sag and slope zones (i.e., Early Triassic-Middle Triassic, Late Triassic-Middle Jurassic, and Late Jurassic-Early Cretaceous), and two phases of charging in the uplift zone. And (iv) the thickness and total organic carbon content of source rocks increase from the uplift zone toward the sag zone, with the mudstone thickness of the Lower Wuerhe Formation in the sag zone reaching 536 m, and the biomarkers reveal that the input of aquatic organisms is more significant in the sag zone. In conclusion, the deep oil and gas accumulation in the Dongdaohaizi Sag is controlled by multi-phase tectonic activities, and the high-maturity source rocks and fault systems in the sag zone jointly dominate the differential distribution of hydrocarbons, providing a referential “source-fault-reservoir” coupled accumulation model for deep oil and gas exploration in the interior basin.
To clarify the sedimentary characteristics and hydrocarbon exploration significance of shallow-water delta in the first member of Middle Jurassic Shaximiao Formation (hereinafter referred to as Sha-1 Member) in the western-central Sichuan Basin, the sedimentary setting, sedimentary microfacies types, sand-body distribution patterns, and geophysical response features of Sha-1 Member were analyzed systematically, and a sedimentary model was established, using the core, logging and contiguous 3D seismic data. Research results are shown as follows: (i) During the sedimentation period of Sha-1 Member, the paleotopography was gentle, with shallow water body that rose and fell frequently, a large shallow-water delta was developed under the alternating humid-arid climates, contributing the subaqueous distributary channel sand bodies with the cumulative thicknesses ranging 15-40 m, the widths of 300-8 000 m, and the maximum extension up to 200 km. (ii) The subaqueous distributary channel sand bodies are distributed in a reticulate pattern, enclosed within interdistributary bay mudstones, possibly forming large-scale lithologic traps, and accounting for more than 50% of the front sedimentary area. In contrast, the reverse-graded river mouth bars are sporadically developed and small in scale (with individual layer thickness not exceeding 6 m). (iii) The seismic responses reveal the bright spot of “trough at the top and peak at the bottom” with medium to strong amplitude. Strong amplitude continuous reflection is observed along the channel, while the amplitude weakens to both sides of the channel in the transverse direction. High-resolution 3D seismic data are crucial for the fine characterization of sand bodies. (iv) The shallow-water delta front sand bodies of Sha-1 Member show good physical properties (with the porosity of 7%-13%, and the permeability of 0.01-1.00 mD), and form an efficient source-reservoir assemblage with the underlying source rocks of the Upper Triassic Xujiahe Formation, supporting the discovery of large-scale gas reservoirs such as the Tianfu Gasfield in the central Sichuan Basin (with proven reserves of 1 500×10⁸ m³). In conclusion, the shallow-water delta is the main contributor to the current increase in continental tight gas reserves in the Sichuan Basin; besides, its sedimentary model featuring wide channel, thick sand body and optimal configuration provides a reusable geological model and technical paradigm for hydrocarbon exploration of similar reservoirs in the Xujiahe Formation and the Middle Jurassic Lianggaoshan Formation within the basin.
To clarify the characteristics and controlling factors of the Upper Carboniferous tight sandstone reservoirs in Shiqiantan Sag, eastern Junggar Basin, a systematic study was conducted by using analysis techniques such as cast thin section, scanning electron microscope (SEM), electron probe microanalyzer, X-ray diffraction (XRD), and fluid inclusion, together with the sequence stratigraphic framework and sedimentary facies analysis. Results show that (i) Shiqiantan Formation reservoirs are complex in rock types. The delta plain-front lithology mainly develops sandstone with relatively coarse grain size and relatively low content of impurities, with good physical properties. However, the littoral-neritic deposits exhibit a wide range of lithologies, mainly consisting of sandstones, bioclastic silty claystones and arenaceous bioclastic limestones, with fine grain size, complex composition, high carbonate content and poor physical properties; (ii) the main storage spaces of Shiqiantan Formation reservoirs are secondary dissolved pores (e.g. feldspathic/lithic intragranular dissolved pores and laumontite interstitial dissolved pores) and microfractures (e.g. structural fractures and dissolved fractures); (iii) Shiqiantan Formation reservoirs are significantly controlled by diagenesis. Specifically, compaction served as the primary driver to reduce porosity, cementation of various calcites played a critical role in destructing pores, and clay minerals like chlorite and illite-smectite mixed layer severely impeded the permeability regardless of their benefits for micropore development; and (iv) deep hydrothermal dissolution associated with tectonic activities has the most significant effect on improving reservoir properties. Secondary dissolved pores and structure-fracturing-induced micropores are configured to enhance the pore connectivity and the permeability, and sandstone reservoirs in synsedimentary facies belts near the faults show relatively good physical properties. In conclusion, the delta front coarse-grained sandstones and the hydrothermal-tectonic alternation zones are targets with high-quality reservoirs, and acidic fluids formed during hydrocarbon generation of source rocks and deep hydrothermal process jointly controlled the creation of secondary pores.
Characteristically distinct flower reversal structures are widely observed in the structural zones in the western uplift and the III and IV secondary structural zones in the eastern reversal anticline of Doseo Basin, western Central Africa. However, these structures are indefinite in types, evolution process and relation with hydrocarbon accumulation. Based on drilling, logging and seismic data, a systematic study was conducted through analyzing equilibrium profiles, structures and hydrocarbon accumulation. Results show that (i) in the Early Cretaceous Neocomian-Barremian, the basin developed as an extensional rift, with its structural configuration and scale shaped initially; (ii) the III and IV secondary structural zones in the eastern reversal anticline are flower-shaped reversal structures controlled by strike-slip faults F1 and F2, and above them are the widespread development of an unconventional positive flower reversal structures. The prominent manifestation is that the upward divergent part of the flower shaped structure is mainly composed of small normal faults, but the geological morphology presents an antiform, while the western uplift structural belt develops large conventional positive flower reversal structures; (iii) the structural zones in the western uplift develop large-scale conventional positive flower reversal structures. The basin has evolved primarily in three stages: extensional rift, strike-slip, and depression. During the depression stage, it has also undergone three episodes of structural inversion. The evolution process of positive flower reversal structures are predominantly characterized by short rifting and long depression, strong extension-strike-slip, and three episodes of impulse reversion strong in the west and weak in the west; (iv) structural reversion activities controlled the development and distribution of positive flower reversal structures and associated traps; and (v) the traps of positive flower reversal structures at the III and IV secondary structural zones in the eastern reversal anticline are categorized into inner-source and above-source hydrocarbon accumulation models, and show good matches in terms of trap-formation time, peak hydrocarbon generation and expulsion of effective source rocks, episodes of structural reversion, and fault reactivation time.
In order to improve the accuracy of sub-sand layer group structural maps for target point optimization, geosteering, and reserve estimation during field development, a fine interpretation for sandbody top-bottom surfaces was completed and a time structure map was obtained using the dominant seismic information gradient -90° phase shift technology. Constrained by both well-point velocities and the lateral variation trend of seismic velocities, depth structure maps of the sandbody top-bottom surfaces were generated adopting a variable-velocity mapping method. By using the depth-domain seismic stratigraphic slicing technology, slices adjacent to the target layer were extracted. Through well-point horizon calibration, the depth structure maps of sub-sand layer groups were ultimately obtained. The results show that, (i) compared with the conventional well-point horizon calibration methods, the new approach significantly improves the accuracy of structure maps, with an absolute structural error of only 4 m in drilled wells; (ii) the planar distribution of sandbodies can be accurately depicted based on the sub-layer structure to guide the trajectory optimization of development wells, increasing the drilling encounter rate of high-quality thick reservoirs to 65%; (iii) the AVO gradient -90° phase shift technology effectively addresses the challenge of identifying “dim spot” reservoirs in the mid-deep layers, enhancing the reflection clarity of sandbody top and bottom; and (iv) the variable-velocity mapping technology reduces the structural error caused by the lateral velocity variations by integrating well-seismic velocities with structural trends. It is concluded that the interlayer structural mapping technology can significantly enhance the structure prediction accuracy of sub-sand layer groups, and it provides a reliable technical support for the efficient development of ultra-low permeability gas reservoirs.
In order to accurately predict the pore pressure in the Lower Silurian Longmaxi Formation and its overlying strata of the Nanchuan block in the transform zone on the southeastern margin of the Sichuan Basin, to help prevent frequent complex failures such as lost circulation, borehole collapse and pipe sticking caused by the weak pressure bearing capacity and poor stability of the overlying Lower Silurian Hanjiadian-Xiaoheba Formations, a new method for predicting formation pore pressure was developed based on the poroelasticity. The results show that, (i) fundamentally, this method comprehensively considers the formation mechanism of Silurian pore pressure, endowing it with strong pertinence and adaptability;(ii) verification in multiple wells for the method demonstrates that the average error of the predicted equivalent densities of pore pressure is about 1.6%, a 66% reduction compared with the improved Eaton method (4.7%), indicating high accuracy; and (iii) this method has achieved remarkable results in the practical application to multiple drilling platforms in the study area; by accurately controlling the drilling fluid density according to the prediction results of the new method, the proportion of wells experiencing lost circulation reduced by 67.8%, and the leakage volume per well decreased by 48%. It is concluded that this method provides a basis for the safe drilling design of shale gas wells in the Longmaxi Formation of the Nanchuan block. In engineering practice, it can provide reliable pore pressure data to effectively guide operations such as drilling parameter optimization and the rational adjustment of drilling fluid density, mitigate lost-circulation problems, reduce the incidence of downhole complex situations and improve drilling efficiency. Meanwhile, it can serve as a reference for pore pressure prediction in similar strata, and facilitate the efficient development and utilization of shale gas resources.
In order to reduce the failure rate of drilling tool in large-diameter boreholes in the Sichuan-Chongqing area, the service history of drill collar was reviewed with the failure accident of Ø228.6 mm drill collar while tripping out of the large-diameter borehole (Ø406.4 mm) of Well Z201-A as an example. In addition, the fracture-surface characteristics, drill string mechanical simulation and downhole vibration strength were analyzed. Accordingly, the causes of the failure were determined, and the drilling tool safety management measures were proposed. Research results are shown as follows: (i) The case drill collar failed due to fatigue, caused by weakened drill collar strength, complex loading on the drilling tool, and intense downhole vibration. (ii) After being used many times, the outer diameter of the drill collar is reduced from 228.6 mm to 226.0 mm, and the box-to-pin thread bending strength ratio (BSR) is 2.18, lower than the API standard value of 2.5. The weakening strength of box thread is one of the reasons for the failure. (iii) Mechanical simulations of the drill string reveal higher bending moments and stresses in large-diameter boreholes compared to small ones. The weak point of the bottom hole assembly (BHA) is adjacent to the centralizer, exhibiting the accelerated fatigue, which is the main reason for the failure. As the result, the broken drill collar is right above the centralizer. (iv) The surface strata where the large-diameter borehole (Ø660.4 mm) of the first spudding in Well Z201-A drilled into have alternate soft and hard lithologies. The wellhead torque measurements suggest intense downhole vibration with peak lateral vibration exceeding 30 g, which brings extreme damage to the thread. The downhole vibration calculation results indicate that the larger the borehole diameter, the greater the average equivalent stress of drilling tool, and for the borehole with diameter above Ø444.5 mm, the average equivalent stress increases exponentially. Compared with the weight on bit (WOB) fluctuation, the torque fluctuation has greater influence on the stress amplitude of drilling tool. (v) Based on the above findings, the specific measures for drilling tool safety management are proposed from two aspects, i.e., drilling technology and drilling tool management. It is concluded that the findings provide guidance for the safety of drilling tool in large-diameter boreholes, which is beneficial for reducing drilling tool accident rate, shortening drilling cycle, controlling costs, ensuring optimal and fast drilling, and improving quality and efficiency.
In the process of oil and gas well drilling in the Sichuan-Chongqing area, the presence of lost-return formations often result in unsuccessful plugging, even drilling accidents. To address the problem, a method for calculating two key parameters, namely the running depth of cementing tool and the sinking height of cement plug, was developed on the basis of the pressure balance principle. Additionally, the slurry design criteria were improved and the operation workflow was optimized, thus forming an integrated high-injection and high-squeeze cementing plug technology. Research results indicate that, (i) the density of plugging slurry is equal to that of drilling fluid, ensuring the slurry retention in wellbore as well as the success rate of cementing plug; (ii) the calculated running depth can not only quantitatively control the length of cement plug, but also ensure the safety of drilling tool; (iii) the adoption of bradenhead squeeze effectively directs the slurry flowing to the thief zone, increasing the success rate of plugging; (iv) staged squeezing the gelling cement into formation at the initial setting time effectively enhances the pressure-bearing capacity of formation; and (v) this technology has been applied in 33 wells, achieving the success rate of one-trip plugging of 90.9%, and statistical results of 7 wells show that the average pressure-bearing capacity per well is increased by 31.4%. In conclusion, the high-injection and high-squeeze cementing plug technology demonstrates remarkable effectiveness in sealing the lost-return formations in the Sichuan-Chongqing area, and can realize safe plugging while improving the formation pressure-bearing capacity in a single operation. It provides a technical guarantee for efficient drilling and safe production.
In order to improve the safe drilling efficiency of ⌀311.2 mm borehole for the deep shale gas in the Da’an block of western Chongqing on the southeastern margin of the Sichuan Basin, some supporting technologies including the bit selection, drilling fluid optimization, acid-gas control, and lost circulation treatment were adopted to address the technical challenges, such as the wellbore collapse and bit balling up in the Lower Jurassic Lianggaoshan-Ziliujing Formations, the strong abrasiveness of the Upper Triassic Xujiahe Formation, the developed pyrite and chert in the Upper Permian Longtan-Middle Permian Qixia Formations, and the lost circulation and acid-gas contamination in the Lower Triassic Jialingjiang-Middle Permian Maokou Formations. The stratigraphic characteristics and drilling difficulties were analyzed, and the key measures for enhancing the rate of penetration (ROP) in hard-to-drill formations were identified. In addition, drilling parameters and bottom hole assembly (BHA) were optimized, and an anti-contamination drilling fluid system and the lost circulation treatment process were improved. The results show that, (i) the application of drill bits SD6542BF and ES1656TEU in the Xujiahe Formation, and GS1606T, SD6542BF and TS616 in the Longtan-Qixia Formations increases the ROP to 6.36 m/h and 3.47 m/h, respectively; (ii) the high-density organic salt polysulfonate drilling fluid system, combined with calcium oxide, calcium chloride and gypsum treatment agent can effectively address acid-gas contamination, maintaining the pH value of drilling fluid equal to or greater than 10 and the calcium ion concentration greater than 600 mg/L; (iii) the implementation of the three-level measures of plugging while drilling, targeted bridge-slurry plugging, and cement plugging improves significantly the success rate of lost circulation treatment, reducing the proportion of lost circulation-related non-productive time (NPT) to 0.48%; and (iv) the optimized trajectory design and screw curvature (1.00°-1.25°) and the increased proportion of composite drilling have achieved one-trip drilling of Xujiahe Formation 7 well times, with an average drilling cycle of 26.28 d and a ROP of 6.58 m/h. It is concluded that the supporting technologies can significantly improve the drilling efficiency of ⌀311.2 mm borehole in the Da’an block, and provide technical support for the safe and efficient development of deep shale gas.
Oil and gas exploration and development in the Sichuan-Chongqing area has extended into deep and ultra-deep horizons, and the upper reservoirs have become depleted due to significant decrease of formation pressure after years of production. When a highly deviated well penetrates a long depleted zone, the combination of long extended well section and low formation pressure coefficient frequently triggers severe lost circulation. This in turn causes downhole problems such as pressure-differential-induced sticking and collapse-induced sticking, prolonging the drilling cycle and raising single well costs. To solve these problems, a comprehensive study was carried out covering drilling fluid property, bottom hole assembly (BHA), borehole cleaning, and fine design and operation. Guided by the philosophy of “potent plugging, minimal contact, efficient cleaning, precise operation, and rapid response”, a set of supporting technologies were developed for sticking prevention and safe drilling optimization in depleted zones. Study results show that, (i) “potent plugging” is achieved through optimized drilling-fluid system and properties, and safe operation density; (ii) “minimal contact” is achieved by optimized BHA and timely addition of glass microspheres; (iii) “efficient cleaning” is achieved via variable displacement drilling and high-efficiency circular sand carrying; (iv) “precise operation” is achieved by wellbore trajectory design and control in depleted formations; (v) “rapid response” is achieved through targeted technical measures for lost circulation and pipe sticking; and (vi) the technologies have been successfully applied in 4 wells in high-sulfur gas reservoirs of the northeastern Sichuan Basin and 22 shale-gas well operations in the southern Sichuan Basin. It is concluded that the technologies have efficiently solved the severe lost circulation and pipe sticking problems encountered while drilling highly deviated wells through long low-pressure depleted zones, and thus provide a reference for similar situations.
To systematically investigate the precision of elemental sulfur solubility measurement in natural gas by saturated dissolution method, 20 samples from the same batch underwent repeated testing across 12 domestic laboratories. A precision systematic analysis for elemental sulfur solubility was conducted in accordance with the ISO 4259-1 Precision of measurement methods and results — Part 1: Determination of precision data in relation to methods of test. Firstly, GESD method, Cochran and Hawkins method, and Cook distance were utilized for pre-screening, testing, and analyzing data outlier, respectively. Then, statistical models and automated data processing approaches were used for repeatability and reproducibility evaluations. Finally, the concentration-dependent precision characteristics were clarified through refined segmented concentration intervals. Results indicated that (1) all experimental data can pass the outlier test; (2) degrees of freedom of both repeatability and reproducibility meet the requirements of statistical analysis; and (3) under repeatability/reproducibility conditions, within a 95% confidence interval, the difference between two independent results obtained does not exceed the repeatability/reproducibility limit within the corresponding concentration range. The established precision analysis system can accurately evaluate the consistency and reliability of test data. The determination of repeatability and reproducibility limits provides critical technical support for developing the ISO standard Determination of elemental sulfur solubility by saturated dissolution method as well as the revision and improvement of current industry standards.
To address the problems in the existing methods for predicting CO2 solubility in brine such as complex process, narrow applicability, and low accuracy, a modeling method based on machine learning technology termed “weight reconstruction + secondary training + deep optimization” was proposed to construct a LightGBM-based prediction model. Firstly, experimental data of CO2 solubility in brine were extensively investigated according to the general situations of saline aquifers of major basins in China. Secondly, a LightGBM-based prediction model was preliminarily established using the TPE algorithm and five-fold cross validation. In addition, the model was deeply optimized with respect to the decision tree structure and out-of-bag sampling frequency using grid search method. Finally, the new model was employed to analyze the variation laws of CO2 solubility, after its comprehensive performance was evaluated through various indicators. The results show that the newly established CO2 solubility prediction model has high prediction accuracy and reliability, strong generalization ability, with a mean square error of 0.00089 (mol/kg)2, a mean absolute percentage error of 3.78%, and a determination coefficient of 0.994, outperforming conventional models such as Duan&Sun, KRR, RBFNN-BAC and SVM. The CO2 solubility in brine is most affected by temperature, followed by pressure, and least by ion concentration. Moreover, the variation of CO2 solubility with temperature reverses at the pressure of 20 MPa. It is concluded that the research results can provide a basis for evaluating the potential of CO2 sequestration in saline aquifers and selecting suitable sequestration sites.
Converting a depleted fractured ultra-high-pressure gas reservoir of Upper Permian Changxing Formation in the Tongluoxia structure of eastern Sichuan Basin fault-fold belt into a high-pressure underground gas storage (UGS) presents parameter design challenges. In this paper, the key parameters of UGS construction such as upper limit pressure, injection-production well number, and gas injection-production rate were designed using an integrated static-dynamic analysis method, based on the geological and development characteristics, as well as the evaluation of single-well injection-production capacity under different fracture distribution patterns, and the interaction design of working gas volume in different pressure intervals and number of wells, following the design strategy of “optimal interval selection, efficient injection and production, emergency support, and phased implementation”. In addition, the geological and engineering understanding of UGS construction was deepened, and the parameters were optimized through pilot trials and injection-production practice. Research results are shown as follows: (i) Single-well productivity varies significantly depending on fracture development characteristics, and the simulated average rational production rates under different conditions can be used as the designed gas injection-production rates of new wells, i.e., 5.6×104-268.5×104 m3/d as the production rates and 69.7×104-214.2×104 m3/d as the injection rates. (ii) To complete the cyclical injection-production tasks, nine wells are needed with an upper limit pressure greater than 38 MPa. Considering surface conditions and numerical simulation results, the final design parameters are set as upper limit pressure of 40 MPa, storage capacity of 13.8×108 m3, working gas volume of 9.2×108 m3, cushion gas volume of 4.6×108 m3, average daily gas injection rate of 460×104 m3, and average daily gas production rate of 766×104 m3. (iii) In view of the surface conditions of the construction site, three injection-production platforms are deployed, and nine injection-production wells are arranged along the fracture-developed part of No. 36 fault zone. (iv) As the newly deployed wells are put into production and the gas injection volume is increased, the working gas volume and storage capacity of the UGS reach the expectations gradually, indicating that increasing the number of wells is an effective way to enlarge storage space. (v) The Tongluoxia UGS project was completed and put into production on December 15, 2024, and is currently in good operation. In conclusion, it is feasible to convert a depleted fractured ultra-high-pressure gas reservoir into a high-pressure UGS. The Tongluoxia UGS, as China’s first successful case, provides a reference for UGS construction parameter design and operation.
Natural gas development projects are characterized by large-scale investment, high technical requirements and numerous risk factors. To ensure investment returns and enhance decision-making scientificity, economic evaluation is essential for the projects. A generalizable and standardized economic evaluation model was constructed based on existing criteria, to provide quantification basis and assist decision making. The objective laws between investment and production in the multi-round evaluations for a tight gas reservoir development scheme were investigated using MATLAB and EXCEL, combined with the statistical regression method. In addition, multi-factor sensitivity analysis was performed on the key economic parameters. Research results are shown as follows: (i) Both linear functions and nonlinear functions with marginal diminishing effect can fit well the relation of investment and production in the development scheme. The investment is positively correlated to the production, that is, the production increases with the investment, but there still exists marginal diminishing effect, thus merely increasing investment cannot sustain production growth. (ii) Sensitivity analysis indicates that, with the operation costs and product prices of the scheme held constant, a 30% reduction in investment yields the optimal return on investment. (iii) When using the constructed model to optimize gas reservoir development scheme, it is essential to strengthen the integration of technical and economic considerations, so as to determine a technically feasible and economically optimal scheme after multiple rounds of comparative selection. It is concluded that a systematic and comprehensive economic evaluation is crucial for natural gas development projects; the proposed analysis framework and economic evaluation model are generalizable, and readily extensible to more application scenarios as parameter sets accumulate.
