There exists a series of problems in gas wells with high water production, such as high pressure loss in production and transportation system, difficulty in wellbore fluid carrying, low efficiency of surface gathering and transportation, and high cost of produced water treatment. To solve these problems for massive and beneficial development of high water-cut gas reservoirs, a single-well production and injection technology was optimized through numerical simulation and field practice. The results show that, (i) the developed technology of single-well production and injection using electric submersible pump (ESP) not only achieves efficient gas production by deep pumping and strong drainage, but also ensures that the produced water can be reinjected downhole; (ii) the established computational fluid dynamics (CFD) numerical model of the downhole gas-liquid separator of the technology can predict the gas separation efficiency at the outlet of the separator, with an average error of 6.92%; a second-level downhole gas-liquid separator is designed to ensure that the separation efficiency reaches over 90%, effectively solving the problem of frequent gas locking and pump jamming in the operation of ESP wells; and (iii) this technology can effectively reduce the wellbore dynamic liquid level and bottomhole flow pressure; it has been successfully applied to 50 watered-out producers for production resumption and stable recovery, bringing about cumulative increase in gas production by 8 000×١٠⁴ m³, achieving downhole reinjection of all the produced water with a cumulative volume of 20×١٠⁴ m³, corresponding to 40 million yuan saved in water treatment costs. It is concluded that by the ESP single-well production and injection technology, the purpose of producing gas only has been realized through the downhole reinjection of produced water, exploring a new way for beneficially exploiting high water-cut gas reservoirs at home and abroad.

Significant interwell interference may be occurred during multi-well production because of the good interwell connectivity, negatively impacting the development of gas reservoirs. Conventional methods primarily rely on qualitative assessments for interwell interference, making it difficult to conduct quantitative evaluations. This limitation prevents the provision of a basis for optimizing the production system of gas wells in interfering well groups. Therefore, a mathematical model for multi-well interference seepage was established by adopting the unstable seepage theory and source function method. Based on the dimensionless of pressure drop superposition under the interwell interference, a characteristic parameter known as the interwell interference factor was proposed, to develop a new method for quantitatively evaluating the intensity of interwell interference using production performance data. Furthermore, taking two gas wells in a well group as an example, numerical simulation and mechanism analysis were conducted for this method. Subsequently, two well groups (each with two gas wells) of the Permian Qixia Formation gas reservoir in the central Sichuan Basin were chosen as study cases for application verification and prediction. The following results are obtained. (i) For the interfering well group with two gas wells, as the gas production from a well increases, the interwell interference factor of its adjacent well increases, indicating that the interference from the well on the adjacent well is intensified, conversely, the interference is lowered. (ii) The interference factor curves between the two gas wells intersect in an “X” shape, the sum of interference factors at the intersection is minimal, indicating the lowest intensity of interwell interference. (iii) The production allocation scheme corresponding to the intersection of the interference factor curves represents the optimal production system, based on which well production allocation can be adjusted to optimize the gas reserve producing in the interfering well group. It is concluded that the new method is beneficial and effective for the quantitative evaluation of interwell interference intensity in multi-well production, and helpful to field production management.

Substantial gas flow has been achieved from the Permian Changxing Formation in both two wells of Pengxi-Wusheng platform sag recently, indicating great natural-gas exploration prospects in this block. The distribution of bioreef-beach bodies in Penglai-Cangxi-Longgang block is not yet clear due to different morphological characteristics of bioreef developed in other blocks and diverse seismic-response characteristics even though some large platform marginal bioreef-beach composite reservoirs such as Longgang and Yuanba were discovered on the western Kaijiang-Liangping trough in the early days. Therefore, based on drilling and seismic data, both distribution and exploration prospects were figured out for Changxing bioreef reservoirs in this block through forward modeling and paleogeomorphological characterization. Results show that (i) this Changxing Formation here can be divided into seven sorts of seismic facies which are summarized as “one depression”, “one platform” and “one trough”. And “one platform” can be subdivided into “three uplifts and two sags”; (ii) there developed six bioreef-beach bodies, including isolated hummocky intra-platform pinnacle bioreef, intra-platform patch bioreef group, large-scale gentle hummocky platform marginal bioreef, jagged platform marginal bioreef, horizontally and vertically deposited platform marginal bioreef; and (iii) the Y-shaped platform margin on the eastern Pengxi-Wusheng intra-platform sag, as a favorable area, is 942 km² while the abnormal bioreef-beach belt in the higher belt of Cangxi-Jiange region of 498 km². In conclusion, with strong comparability, both the higher belt of Cangxi region and southern Yuanba zone have great prospects in natural-gas exploration.

To reveal the fracture initiation mechanism in CO₂ fracturing, experiments and tests were conducted with small-sized and large-sized rock samples, and large-scale fields through large-scale physical simulation experiment of CO₂ fracturing, X-ray diffraction (XRD) detection, rock mechanics testing, rock sample CT scanning, and interpretations of water hammer pressure response and downhole microseismic fracture monitoring during on-site fracturing. The results are obtained in five aspects. First, supercritical carbon dioxide (SC-CO₂) has an extremely strong capability of filtration and penetration in rocks, and the area of the artificial fractures it causes is much smaller than that formed by conventional hydraulic fracturing. Second, CO₂ has a significant dissolution effect on calcite and dolomite in rocks, leading to a decrease in the Young’s modulus, shear modulus, and compressive strength of rocks, and an increase in rock brittleness index. Third, affected by the CO₂ soaking, the fracture surface formed after rock rupture is relatively rough and poorly integrated. Such fractures show a good conductivity even without proppants, achieving self-propping of artificial fractures. Fourth, the instantaneous pump-off pressure of CO₂ fracturing exhibits small-amplitude and long-duration fluctuations, and its pressure conduction behaviors are distinctly different from those of conventional hydraulic fracturing. Fifth, the mixed fracturing mechanism of SC-CO₂ fracturing provides a good explanation for the phenomena of less acoustic emission signals in physical simulation experiments of CO₂ fracturing, and fewer microseismic events in field tests, proving the rationality of the mixed fracturing mechanism. It is concluded that the fractures initiated by CO₂ fracturing, with no proppant added, can achieve good stimulation performance, proving the rationality of the self-propping theory of CO₂ fracturing.

The existing fracturing technologies are not very adaptable to the deep shale gas development in the Luzhou block of southern Sichuan Basin, where the development of natural fractures is abnormal and the geological-engineering conditions are complex. To solve this problem, a 3D reservoir model was established to analyze the requirements for the geometric parameters of hydraulic fracture network with the goal of fully producing well-controlled reserves. Then, matrix model and natural fracture model were constructed based on the fine division of natural fracture patterns. Finally, the key fracturing parameters such as cluster number per stage, flow rate, and fracturing fluid intensity were optimized by using the hydraulic fracturing numerical simulation technology. The results show that the natural fractures in the Luzhou block are divided into two types (network fracture and unidirectional fracture), and the latter is subdivided into four patterns (high-angle fracture, low-angle fracture, parallel proximal fracture, and parallel distal fracture). The fracturing parameters for the two fracture types are optimized by using the numerical simulation. The results have been successfully applied to the test well on site, indicating that no downhole complexity occurred during the fracturing operation, and the estimated ultimate recovery (EUR) after fracturing is higher than the average of the well area. It is concluded that the optimized fracturing parameters for different natural fracture types effectively guide the optimization of fracturing plan for deep shale gas wells in the Luzhou block, and provide technical guarantee of fracturing parameter design for the development of deep shale gas in the study area and similar blocks.

Some petrological, geochemical and geophysical studies were conducted on the high-quality reservoirs of marine carbonate rocks as the main gas producers in Sichuan Basin and the common origin of each quality reservoir was discussed in an effort to broaden petroleum domains. Results show that (i) there exists an exclusive sedimentation named as rock fragmentation in these carbonate reservoirs, which the early diagenetic carbonate mud may be transported once more under poor concretion; (ii) controlled longitudinally by sedimentation cycles, this fragmentation has a certain periodicity and fundamentally extends into the mid-late highstand system tract of the cycles. While laterally by paleogeomorphology, especially syndepositional faults or slope break; (iii) this fragmentation mechanism stems from the difference of sedimentation rate among various depositional settings. When there is an obvious division between two kinds of adjacent setting, massive carbonate sediments at the higher position with larger calcareous space cannot accumulate in place. Being transported in low-lying zones towards the sea and following the principle of sedimentary differentiation, weakly consolidated carbonate rocks suffer from fracturing and collapse under the influence of paleogeography, gravity, and hydropower; and (iv) the quality reservoirs are closely related to fragments. The fragmentation may alter the mud’s physical composition and generate numerous original intergranular pores and vugs to enlarge the fragments’ surface area. And some unstable mineral within the fragments are fully dissolved by undersaturated fluid in low-lying zones, further having much extension in reservoir space. And carbonate sediments change apparently in their physical properties under the effect of both fragmentation and submarine karstification. In conclusion, for the rock fragmentation, the mechanism to form the beach, reservoir and trap can make traditional theories more colorful. Being conducive to broadening exploration domains, this innovative model provides a new exploiting idea in low-energy facies belts, structural slope or low-lying areas in Sichuan Basin.

High pressure (HP) (60-80 MPa) in cementing operation usually brings challenges and high safety risks to cementing head operation in deep shale gas wells in southern Sichuan Basin. Therefore, a HP pneumatically remote-controlled wired cementing head with dual rubber plugs (Ø139.7 mm, with working pressure of 90 MPa) is developed, which is quite different from the conventional one in structure and working principle. The new cementing head is equipped with a 90° rotating switch stop pin assembly to control three flow channels (main channel, bypass channel, and the flow channel between the main and bypass channels), achieving the switching of the channels and the release of rubber plugs in one operation. The pneumatic control system consists of a pneumatic control box and a pneumatic stop pin assembly. The pneumatic control box is connected to the gas source of well site on one side and to the cementing head on the other side. With the power of the gas source, the pneumatic control box controls the rotary valves on the cementing head, and releases rubber plugs and switches flow channels with the handles on the box. Lab test and field application provide the findings as follows. (i) The cementing head performed well during lab testing. Under a pressure of 40 MPa, the rotary plug switch was turned in 2 seconds, the hydrostatic sealing pressure was 100 MPa and the strength pressure reached 137 MPa. (ii) Successful field application in five well operations showed that the time from starting the control system to releasing the rubber plugs was less than 3 seconds, the remote distance was adjustable between 5 to 20 m, and the entire operation process was continuous and stable. (iii) Four to six minutes were saved during the cementing stage from the completion of cement slurry injection to the start of displacement process, compared to using a conventional cementing head. The conclusion suggests that the developed cementing head has strong pressure resistance and a reliable remote control system, ensuring the safety and convenience. It lays the foundation for the automation of field cementing operations.

To figure out what the tectonic-sedimentary differentiation in Wushenqi paleouplift of northern Ordos Basin has affected on the peripheral Ordovician Majiagou Formation, the internal stress during the deposition of this formation was investigated on the basis of seismic, logging and core data and outcrop survey. And then, paleogeomorphological variations within the basin were determined through paleogeomorphological mapping to make clear lithofacies paleogeography of key Majiagou members. Additionally, the internal lithofacies differentiation was clarified as well. Results show that (i) the paleouplift was active intermittently under the regional tectonism during the deposition of Majiagou Formation, creating the obvious uplift-depression differentiation here; (ii) there existed clear differentiation in the paleogeography for this formation. Jingxi depression linked with Mizhi depression and they connected to open sea during the transgression, in which the lime flat microfacies were extended into the deep whereas the dolomitic flat and limy dolomitic flat microfacies into the paleouplift; and (iii) these two depressions were separated by Wushenqi paleouplift during the regression, and their connection to the open sea was also obstructed by other paleouplifts. And gypsum salt lakes were stretched into the depressions, and gypsum-bearing dolomitic flat and dolomitic flat microfacies into Wushenqi paleouplift. It is concluded that Wushenqi paleouplift exerts the effect on the lithofacies paleogeographical framework of one uplift and two depressions throughout the deposition of Majiagou Formation.

As an unconventional hydrocarbon resource, the coal-rock gas of the Lower Cretaceous Huoshiling Formation in southern Songliao Basin is characterized by wide distribution and large reserves. It is an important replacement resource of conventional gas. However, in the Formation, the carbonaceous mudstones with high hardness contain developed microfractures which are mostly horizontal. When the wellbore inclination angle reaches more than 88°, a large number of rock fragments will be produced from the carbonaceous mudstone sidewall. These fragments cannot be broken along with the rotation of drilling tools and are difficult to be carried to the ground, making the wellbore cleaning very challenging. The fragments accumulated at the bottom hole may cause downhole accidents such as pipe blocking and even sticking during tripping process. In severe cases, plugging and sidetracking may be required. Therefore, some researches have been conducted on accurate prediction of collapse pressure, optimization of drilling fluid performance, and determination of anti-sticking measures. The results show that the sidewall can be mechanically supported in an effective manner through optimization of drilling fluid density on the basis of prediction of the collapse pressure in carbonaceous mudstones and coal rocks by means of software modeling with the aid of core experiment results and logging data, and determination of formation leakage pressure through leak off test during pilot hole operation. Moreover, the risk of sticking can be greatly mitigated by enhancing the plugging and inhibition capacities of drilling fluid, optimizing the drilling assembly and formulating appropriate anti-sticking measures. During field application, the issue of sticking was successfully resolved four times, and effectively prevented eight times. Additionally, the length of the horizontal section was extended from 287 m to 765 m, initially addressing the sticking problem when drilling through carbonaceous mudstone intervals of this area. The research results are conducive to facilitating the exploration and development of deep coal-rock gas in the Songliao Basin.

Taking the conventional gas of the Sichuan Basin as an example, a high-accuracy combination production forecasting model (hereinafter referred to as the “new model”) that conforms to the “wave-like” growth characteristics of conventional gas production has been established by using the Shapley value method to assign weights to the three models commonly used in predicting peak gas production, namely Hubbert, Gauss and GM (1, N), with the purpose of improving the prediction accuracy. The research results are obtained in three aspects. (i) According to the prediction using the new model, the conventional gas production is expected to reach its peak in 2046, with a production of 412×10⁸ m³/a. The relatively stable production period will be from 2038 to 2054, lasting for 17 years. (ii) The new model that effectively integrates the advantages of the above-mentioned three models is accurate and reliable, with a relative error lower than that of a single model. (iii) Further evaluation on the four models (Hubbert, Gauss, GM (1, N), and the new model) through residual analysis and accuracy test has confirmed that the new model satisfies F-test and t-test, with the smallest test values and the highest accuracy. Both the residual and standardized residual are lower than those of the other models, and the prediction stability is the best. It is concluded that the new model established by the Shapley value method can accurately predict peak gas production, providing reliable data for the formulation and optimization of mid- to long-term gas production plan.

Deep shale gas in the Upper Ordovician Wufeng Formation to the Lower Silurian Longmaxi Formation, LZ block, southern Sichuan Basin, boasts great exploration prospects. For these reservoirs, to evaluate the fracturability becomes the focus but a hard problem due to their strong heterogeneity in rock composition and texture as well as physical properties. Some rock samples with three angles of 0°, 45°, and 90° relative to the bedding plane were selected from full-diameter cores for X-ray diffraction, electron microscopy, triaxial compression and acoustic testing in order to provide foundation for evaluating the deep shale-gas sweetspots and fracturability in this block and surrounding areas. Furthermore, the relation of mechanical parameters to mineral component was discussed to compare the difference among dynamic and static mechanical parameters as well as elastic-wave velocity in all directions, which may offer an in-depth insight on the parameters and anisotropy in the deep shale. Results show that (i) the shale in the study area is mainly composed of quartz and clay. For certain samples parallel to the bedding plane or at 45°, the Young’s modulus obviously assumes positive correlation with quartz content while negative one with clay content. In contrast, the correlation of this modulus with quartz or clay content is poor for other samples perpendicular to the bedding plane; (ii) static mechanical parameters may be affected by the effective confining pressure. And the Young’s modulus changes with increasing pressure while both Poisson’s ratio and peak strength may increase or decrease, respectively; (iii) evident anisotropy represents in the mechanical parameters and elastic wave. The Young’s modulus, peak strength, and P- and S-wave velocities in some samples parallel to the bedding plane are higher than those at 45° or perpendicular to the bedding plane; and (iv) for all samples, the dynamic modulus is greater than the static one. The dynamic vs. static Young’s modulus in the vertical direction and the Poisson’s ratio in the parallel direction all present stronger linear positive correlation. This correlation is also stronger at 45°.

As a major domain for the coming productivity replacement of tight gas in Sichuan Basin, the gas reservoirs of the Upper Triassic Xujiahe 4 Member in Tianfu gasfield are typical low-permeability ones with complex lithology and pore structure. There often exists nonlinear relation in porosity and permeability as well as non-Archie rock-electro relation, creating great challenges in computing logging parameters (e.g. water saturation) and identifying gas or water. Thus, introduced the conductive porosity as an intermediate variable, a high-precision computing model of cementation index was established through petrophysical experiments in order for accurate water-saturation computation. And with the variable m value, another model for this computation was confirmed. The obtained saturation was compared with that measured directly from array acoustic elastic parameters. Results show that (i) the variable m value is thoroughly correlated to the difference between effective porosity and conductive porosity. And the confirmed model with the variable m value may achieve more accurate saturation than that from conventional models; and (ii) the established method for computing the water saturation induced from array acoustic elastic parameters, which array acoustic logging data is used for saturation computation and many experiments on elastic parameters are conducted under different water saturation, may yield the overestimated saturation especially in some calcareous interlayer. In conclusion, the water saturation achieved from the model with the variable m value is correlated to that from sealed coring, satisfying the need of reservoir evaluation.

Petroleum exploration success is commonly evaluated using each of indexes, for example reserve-discovered cost and proven geological reserves per well. Such evaluation pattern, however, is too simple, bringing about the evaluated index incapable of mirroring the internal composition in this success thoroughly and systematically, and the evaluated results failing to give objective response to practical benefits. It is hard to make measures in depth. Thus, dependent on some achievement data of recent years, the exploration success was quantitatively appraised through the created comprehensive evaluation model. Results show that (i) with the success as the soul, the preliminary index system covering four categories and nineteen sub-indexes is set up through sorting out principal indexes which may characterize the success at the whole exploration process; (ii) including four categories and thirteen sub-indexes, the core index system is also built by means of the principal component analysis (PCA) to screen indexes; (iii) the scoring coefficient is attained for each index by way of PCA. And taken the coefficient share as the weight, the comprehensive evaluation model is developed through the synthetical index method; and (iv) in accordance with the appraised success, the standard for success division is established by means of k-means cluster analysis. In conclusion, these established systems are rather reasonable and the evaluated results boast the quality of objectivity, which is conducive to the petroleum exploration success in continuous optimization.

Deep shale gas reservoirs in the Upper Ordovician Wufeng - Lower Silurian Longmaxi Formations in the Yuxi block have great potential for further enhancing and stabilizing shale gas production of the southern Sichuan Basin. The H202 well area in this block has already entered the stage of large-scale productivity construction, but still faces challenges such as significant differences in the development effects of producing wells and unclear factors affecting productivity. To technically support the subsequent development of deep shale gas in the area, a geology-engineering integrated study was conducted on typical producing wells, by considering the factors including the distribution of Class I continuous reservoirs, targets, fracture characteristics and distribution, fracturing intensity, and proppant types. Based on summarizing the drainage gas recovery characteristics and production effects of producing wells, comparing and evaluating comprehensively the adaptability of development strategies, drilling techniques, and fracturing processes, the high-production well models in areas with fracture network were established, and the optimization measures were proposed for subsequent development of wells to be produced. The results indicate that, (i) static parameters of the reservoir are fundamental, and the areas with fracture network are selected for well placement by taking into account the basic characteristics including structure, sedimentation, reservoir, and fracture distribution; (ii) attention should be taken to ensure the penetration rate of high-quality reservoir and increase the drilling length of platinum target zone; (iii) operation parameters (displacement of 20 m³/min, fracturing fluid intensity of 40 m³/m, and proppant injection intensity of 4 t/m) should be improved in the areas with fracture network, so as to enhance the reservoir stimulation effects; and gradual prevention and control measures should be taken in the areas with unidirectional fractures, in order to especially ensure the wellbore integrity; and (iv) the proportion of ceramic proppant should be increased for both development effects and economic benefits. The research results provide a guidance for subsequent platform deployment and production, thereby facilitating the large-scale and beneficial development of deep shale gas.

Based on the Al-Hussainy productivity equation in pseudo-pressure form, the critical pressure turning point of overpressured gas reservoirs was determined using the μZ-p and p/μZ-p plots, subsequently, the “one point method” productivity evaluation formula in pressure form for overpressured gas reservoirs was derived and established. Research results indicate that, (i) the pressure coefficients of typical overpressured gas reservoirs in China range from 1.34 to 2.29, and the initial formation pressures range from 49.28 to 150.00 MPa; (ii) based on the pressure-volume-temperature (PVT) parameters of 18 typical overpressured gas reservoirs at home and abroad, the critical pressure turning point of such reservoirs is determined to be 53.00 MPa; (iii) when the pressure of an overpressured gas reservoir exceeds 53.00 MPa, μZ and p are approximately linearly related, and p/μZ is approximately constant; in this case, the pressure binomial productivity equation should be used for solution; (iv) the established productivity evaluation formula is similar to the Chen Yuanqian’s “one point method” formula, with the distinction that the productivity equation coefficients and the absolute open flow (q_AOF) of gas well in the former are solved with the pressure binomial productivity equation; and (v) without the multi-point test, the stable empirical coefficient α' for gas well is unknown; if the average value of α' (i.e. 0.164 4) is utilized, there may exist an uncertainty. It is concluded that from the theoretical perspective, the proposed “one point method” formula in pressure form is more suitable for overpressured gas reservoirs. The application results show that the established productivity evaluation formula has an average error of 49.16% in calculating the q_AOF, which is lower as compared with the Chen Yuanqian’s “one point method” formula.

Annually, 400 wells are deployed by slimhole sidetrack drilling in Shengli oilfield of Bohai Gulf Basin to exploit remaining oil in this mature field. However, most of them are confronted with wellbore instability in shales, bit balling, large dogleg degree and backing pressure especially in horizontal wells with small radius, high annular pressure loss in slimhole, and cutting bed formation. It is essential to optimize drilling-fluid technologies. Thus, the system design and solid phase control were analyzed and made for the technologies used in the sidetrack slimhole. And the composition, field operation, and complexity cause/treatment were investigated for the polyol-polymer mixed metal hydroxide (MMH) system. Results show that (i) this system may guarantee the sidetrack slimhole drilling in various sections because of its better performance in inhibition, lubrication, wellbore stability and reservoir protection; and (ii) as two major parameters to condition drilling fluid, both funnel viscosity and ratio of yield point to plastic viscosity may ensure this stability and cutting-carrying in slimhole, and proper rheological parameters is also a key technique for the stability. In conclusion, 2%-3% polyol added to the original polymer MMH system may guarantee the cutting bed removed effectively, the clean and stable wellhole during drilling without any complexity, thus reducing the drilling or completion period and drilling costs, which may be conducive to tapping the potential of remaining resources in old oilfields.

As a new exploration and development domain of tight gas in Ordos Basin, Qingshimao gasfield is the first large one with the natural-gas reserves exceeding 100 billion cubic meters in Ningxia Hui Autonomous Region. Low gas production and high water-gas ratio emerged at the process of production test in this field, creating more challenges in beneficial development of tight-gas sandstone reservoirs. Thus, the eighth member of the Permian Lower Shihezi Formation (He 8 Member) was taken as an example to probe into physical properties and pore-throat microstructure in such reservoirs by means of porosity and permeability analysis, cast thin-section identification, and constant-rate mercury injection in order to figure out gas-water seepage laws and development mechanisms. Then, the initial water saturation was ascertained for these reservoirs on the basis of the sealed coring for pyrolysis weighing, routine coring or displacement and nuclear magnetic resonance. Additionally, both seepage laws and development mechanisms were made clear with the help of gas-water two-phase seepage experiments. Results show that (i) with low porosity and permeability, and medium to high water saturation, this member is generally tight gas reservoirs in which three types are developed, i.e., matrix porous type, fractured type, and matrix porous or underdeveloped fractured type; (ii) partial waterbody in some reservoirs whose characteristics are tight matrix, locally developed fractures and higher initial water saturation, is prone to non-uniform fingering along fractures. Hence, controlling water lock effect and avoiding water block damage are crucial to the beneficial development; and (iii) without cores, the criteria can be roughly established to identify produced fluids in the light of physical properties and gas content, providing geological evidence for selecting the best perforation interval and water control. In conclusion, all above results offer references for the selection of targeted zones and intervals for subsequent development in Qingshimao gasfield.

Fractured-porous gas reservoirs with low resistivity are extended in the second member of the Upper Triassic Xujiahe Formation (Xujiahe 2 Member), Xinchang area, western Sichuan Basin. They are characterized by tight lithology, strong heterogeneity, and complex gas-water relation, resulting in considerable uncertainty in identifying reservoir-fluid properties by using conventional logs or popular gas-water crossplots. Thus, the (T₂-T₁) two-dimensional nuclear magnetic resonance (NMR) logging crossplot was created for identifying gas and water after optimizing both design and gauge on the basis of one-dimensional NMR logging. Moreover, the identification for this sort of reservoirs was discussed in the light of principles of apparent porosity frequency spectrum dependent on electrical imaging logging. Results show that (i) fluid components possess unlike zoning characteristics in the two-dimensional identification crossplot from which movable gas and water components in such reservoirs can be identified actively; (ii) with high resolution and coverage around wells, the imaging logging is available for not only pore structure analysis but gas-water identification in the low-resistivity fractured-porous reservoirs; and (iii) it is assumed the evaluated low-resistivity reservoir as a gas layer, but not as a gas-water layer. The gas-water identification interpreted from this new technology has higher coincidence with that of gas testing from previous 80% to current 95% or so.

In order to address the challenges of limited drilling data, strong heterogeneity, and severe formation energy voidage in a low-permeability thin interbedded oil reservoir in the western South China Sea, and then to accurately predict the pressure during reverse pressure drive and fracturing operations in this reservoir, operation pressure prediction models were developed based on the Spearman correlation and grey relational analysis (GRA), together with linear regression and machine learning technologies. Firstly, geological reservoir and engineering parameters that significantly affect the pressure gradient of fracture extension were screened out through Spearman correlation and GRA. Secondly, based on the selected parameters, operation pressure prediction models were established by using linear regression and machine learning methods. Finally, these models were validated using the actual data from Well A1 in the reservoir. The results indicate that, (i) the methods of Spearman correlation and GRA can effectively identify key parameters affecting the pressure gradient of fracture extension; (ii) the prediction deviation rates of both linear regression and machine learning are within 10%, meeting the required engineering accuracy; (iii) when high-viscosity fracturing fluids are used, the prediction accuracy of machine learning is much superior to that of linear regression; and (iv) the predicted values of operation pressure in pressure drive and fracturing are highly consistent with the actual ones in Well A1, validating the reliability of the established models. The conclusion suggests that the operation pressure prediction method based on machine learning can provide an accurate guidance for reverse pressure drive and fracturing operations in the low-permeability thin interbedded reservoir in the western South China Sea. Additionally, it can serve as a reference for pressure prediction in similar reservoir stimulation operations.

Working fluid invading into shale gas reservoirs may trigger hydration damage to shale under physical and chemical interactions during drilling and completion, further leading to fracture propagation and extension or even borehole instability, which may badly affect drilling safety and stimulation performance. Therefore, some experiments about hydration, ultrasonic transmission and nuclear magnetic resonance (NMR) were implemented on shale samples from the Lower Silurian Longmaxi Formation of Sichuan Basin in an effort to figure out hydration controls on shale’s pore structure and acoustic attributes. Variations in pore structure, acoustic velocity, and frequency-domain signals at different hydration times were discussed for these samples to reveal an intrinsic relation between the first two variations. Furthermore, dependent on elastic parameters, the quantitative characterization was established on the degree of hydration damage to shale. Results show that (i) in term of the pore structure throughout the hydration, small pores increase in their number, the size gets bigger successively, and large pores and microfractures emerge; (ii) with the increase of hydration time, the velocity decreases in a dramatic and then gentle manner. Low-frequency components evidently become lesser in frequency-domain signals after shale hydration; and (iii) the hydration damage accelerates and then slows down little by little, fast damage in the first six hours, sluggish in the following eighteen hours, and tending to be stable in the later twenty-four hours.