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.
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.
Being an important exploration target of tight oil in Ordos Basin, the eighth member of the Upper Triassic Yanchang Formation (Chang 8 Member) has been discovered from several super-giant oilfields in Jiyuan, Xifeng, Maling areas, suggesting great exploration potential. Therefore, the first submember of Chang 8 Member (Chang 81 submember) in Wuqi-Shunning area was taken as an example to discuss the distribution of effective tight sandstone reservoirs affected by both sedimentation and diagenesis in this basin. For Chang 81 reservoirs, the petrology, diagenesis and physical properties were studied through core observation, cast thin-section observation, scanning electron microscopy (SEM) and physical property analysis. In addition, the distribution of diagenetic facies belts was figured out, and some favorable zones were predicted for reservoir extension. Results show that (i) characterized by extremely low porosity and permeability, these Chang 81 reservoirs with intergranular pores and feldspar dissolved pores as the dominant reservoir space are dominated by fine- to medium-grained feldspathic sandstone and lithic feldspathic sandstone; (ii) dissolution is deemed as the main constructive diagenesis while both compaction and cementation as destructive one. This dissolution in Wuqi has slightly higher intensity than that in Shunning, whereas the compaction and cementation intensity in Wuqi evidently lower than that in Shunning; and (iii) five diagenetic facies can be divided in the study area in line with diagenetic minerals and diagenesis type and intensity, including carbonate + illite cemented tight facies, compaction-pressolution tight facies, authigenic clay + carbonate cemented facies, chlorite thin-film cementation + dissolution facies, and quartz-enlarged cementation + dissolution facies, among which the latter two are most favorable for reservoir extension. In conclusion, the central Wuqi-Shunning area is in favor of diagenetic facies and reservoir extension.
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.
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.
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 (qAOF) 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 qAOF, which is lower as compared with the Chen Yuanqian’s “one point method” formula.
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.
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.
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.
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.
In the cementing plug operations for leaky water-producing layers in the Sichuan-Chongqing area, there are recurring problems such as the failure to form plugs after repeated cement injection, insufficient strength of the formed plugs, and difficulty in determining the length of plugged section. To solve these problems, the pressure balance states before, during and after plugging were analyzed deeply with full consideration of the factors related to cementing plug, together with the characteristics of the leaky water-producing layers. Then, a computation model for cementing plug was established, and the method for calculating key parameters such as the injection volume of cement slurry and plugging depth was derived. Finally, the scheme of cementing plug was optimized, and verified through field application. The results show that, (i) the injection volume of cement slurry and the plugging depth are the critical parameters in the design of cementing plug technology, and their optimal values can be calculated by the new method; (ii) the mixing and channeling of cement slurry influencing the quality of cementing plug and plugged section length lead to the loss of section length at the top and bottom surfaces of cement plug, with the expected reasonable range of the total loss being 50-100 m; and (iii) the field application in Wells TC4 and LG64 is smooth and achieves successful plugging in one trip, which significantly improves the success rate of one-trip cementing plug in the leaky water-producing layers, while controlling precisely plugged section length and plugging depth, verifying the effectiveness of the new calculation method, and achieving the optimization for the original technologies. It is concluded that the optimized cementing plug technology for leaky water-producing layers is helpful for improving the operation efficiency, and reducing the scrapped footage of subsequent side tracking.
To understand the gas-water migration dynamic behaviors and the capacity variation laws of underground gas storage (UGS) converted from edge-bottom water gas reservoir during the multi-cycle injection and production process, the operation performance of the H UGS was analyzed and evaluated by using the numerical simulation technology, from the aspects of the variation of gas injection-production rate, the distribution characteristics of formation pressure, and the lateral and vertical variation of gas-water contact. The results are obtained in four aspects. First, in the process of multi-cycle injection and production, as the number of gas injectors and producers increases, the daily gas injection and production of the UGS increase steadily, and its peak-shaving and supply-guarantee capability gets enhanced year by year. Second, after multi-cycle injection and production, the formation pressure spreads gradually from structural high to structural low, and the pressure distribution tends to become more balanced. The gas injected into the UGS can be produced effectively as a whole. Third, the injection and production process of UGS is obviously different from gas reservoir development process. During the development process, gas-water migration is mainly unidirectional, with the gas-water front advancing into the interior of gas reservoir. Whereas in the process of UGS operation, multi-cycle injection and production are alternated, and the gas-water front advances outward from the UGS during injection but inward into the gas reservoir during production, i.e., moving forward and backward with the alteration of injection and production. Fourth, as the multiple-cycle injection and production goes on, the formation water is drained out of reservoir pores, and gas saturation increases correspondingly, which not only reduces the water invasion risk of the UGS in the production process compared with that in the development process, but also provides the UGS with the potential of continuous capacity expansion. The conclusion is that the gas-water migration dynamic behaviors and capacity variation laws of the UGSs converted form edge-bottom water gas reservoirs have a direct influence on their storage capacity and producing efficiency, and the research results are referential for the injection and production design and efficient operation of similar UGSs.
In order to reduce the intense noise generated by the throttling at the wellhead of high pressure (usually corresponding to high yield) gas well, diminish its hazards to well site and the surrounding environment, maintain the physical and mental health of personnel and meet the requirements of environmental protection authorities for noise pollution control standards, this paper analyzed the causes and influencing factors of noise, and explored the noise control methods, by combining computational fluid dynamics (CFD) simulation with field test, based on the investigation on MX gas field. The following research results have been obtained. (i) The noise at a single-well station is mainly the jet noise generated by throttling at each stage and the noise generated by high-speed unstable gas flow. (ii) The gas pressure ratio before and after throttling point (hereinafter referred to as pressure ratio) is an important factor influencing noise: when the pressure ratio is less than the critical value (1.89), the noise is relatively low; whereas the pressure ratio is higher than the critical value, the noise is large, especially when the gas flow velocity reaches or exceeds the sound speed (supersonic), intense shock wave noise is generated to intensify the jet noise, resulting in high noise frequency. (iii) The targeted comprehensive noise control methods are proposed: for intense jet noise, the combination of pressure ratio regulation and sound arrester is adopted to keep the pressure ratio below the critical value during throttling; for high-speed unstable gas flow noise, the combination of local throttling stabilization and sound arrester is adopted; and for the plant boundary noise, the physical wall or sound insulation screen can be built to reduce the noise significantly. The research results provide theoretical support and practical guidance for the noise control of single-well stations of high pressure gas wells, and the green production of natural gas.
