Multiple suites of tight glutenite gas reservoirs are extended vertically into the Upper Triassic Xujiahe Formation, Zitong-Qiulin area, indicating a broad prospect in multi-layered stereoscopic exploration. However, there was a lack of intensive awareness on both sedimentary paleoenvironment and provenance, resulting that it seems difficult to make the breakthrough in regional exploration to constrain the next research badly. It is necessary to investigate thoroughly this paleoenvironment. Thus, the third to second members of Xujiahe Formation (Xujiahe 3 Member to Xujiahe 2 Member), as the principal gas sands in Zitong-Qiulin area, were taken as examples. And based on drilling and seismic data, the rock types, mineral content, provenance, paleoclimate, paleosalinity and paleoredox conditions were systematically discussed through microscopic thin-section identification, X-ray diffraction (XRD) of whole rock minerals, and rare earth element (REE) analysis. Results show that (i) the upper Xujiahe 2 Member is dominated by feldspathic lithic sandstone well developed with quartz (˃50%) and feldspar; (ii) due to carbonate stemmed from Longmenshan Mountain, calcium is always found in the lower Xujiahe 3 Member which is dominated by carbonate debris developed with calcite and dolomite, and quartz content below 50%; and (iii) the lower member represents more complex features in REEs than those in the upper member, indicating an impression of multiple source. The study area as a whole is in a humid dry and hot paleoclimate when both members are deposited in the relatively freshwater-prone oxidizing setting. By contrast, with higher paleosalinity and stronger oxidation, the lower member is deposited in a more humid circumstance. The above results are referential for understanding the microscopic characteristics and sedimentary paleoenvironment together with updating the stratigraphic division on the principal sands of Xujiahe Formation, northwestern Sichuan Basin.

In recent years, the tight sandstone reservoirs in the JQ gas field of the Sichuan Basin have shown good exploration and development potential. However, in the process of development, the reservoir rocks may be damaged due to stress sensitivity, which will affect the productivity of gas wells. In order to clarify the stress sensitivity of reservoir rocks and its impact on single-well productivity for purpose of efficient development of gas reservoirs, a stress sensitivity evaluation experiment was carried out for tight sandstone reservoirs of the Shaximiao Formation in the JQ gas field, at formation temperature and in two pressure states (variable confining pressure and variable back pressure). The results are obtained in four aspects. First, at variable confining pressure, the reservoir rocks have the permeability loss rate of 78.83%-95.85%, with strong stress sensitivity generally. Second, at variable back pressure, the reservoir rocks have the permeability loss rate of 1.48%-64.02%. Samples with lower permeability exhibit non- to weak sensitivity of stress. The better the permeability, the stronger the sensitivity. Third, the stress sensitivity of sandbody No.6 is stronger than that of sandbody No.8. Fourth, the stress sensitivity has a serious impact on gas well productivity, with the production decreasing from 1.75×10⁴ m³/d to 0.17×10⁴ m³/d. The higher the frequency of lifting and lowering the outlet pressure, the lower the resulting yield. Therefore, to make a production strategy for reservoirs with good permeability or stimulated reservoirs, appropriate production pressure difference should be chosen so as to prevent premature closure of throats and fractures under excessively high production pressure differences. Moreover, stress sensitivity should be reduced as much as possible, in order to improve the well productivity and recovery, and ensure the long-term stable production for tight sandstone gas reservoirs.

Exploration practices have revealed abundant oil and gas resources in the Neoproterozoic Upper Sinian Dengying Formation, Sichuan Basin. To ascertain paleostructure controls on reservoir and its forming together with sedimentation, and to theoretically support the subsequent exploration in this formation, it is essential to study the tectono-sedimentary response during Dengying period. Thus, the western boundary of craton was discussed according to gravity and magnetic, tectonic and sedimentary data to make clear both distribution and genesis of paleo-rift. Moreover, sedimentary patterns were explored for the Upper Yangtze Craton during the Late Sinian Dengying period in line with the train of thought on structure-controlled depositional architecture. Results show that (i) for the Yangtze Craton, its west side extends westward to Jinshajiang-Honghe fault zone from Longmenshan-Anninghe fault zone, creating the so-called Pan-Yangtze Craton where is developed with three intra-cratonic rifts; (ii) the western Pan-Yangtze Craton is divided into two sub-cratonic basins of the east and the west through these rifts; (iii) the east sub-cratonic basin is dominated by dolomite in relatively restricted depositional setting, while the west of thicker limestone in relatively open setting; and (iv) with lateral connection, a superior source-reservoir assemblage which serves as the key exploration target in the Dengying Formation is built due to sedimentary buildup in the rifts or platform marginal zones on both sides of the craton. It is worth to note Wanyuan-Dazhou rift as an exploration prospect.

Exploited by their own natural energy, the Jurassic tight oil reservoirs, central Sichuan Basin, feature a high solution gas-oil ratio, better gas drive, large flow resistance greatly induced from throat and microfracture, small output and low primary recovery. It is essential to probe into flow mechanisms during the drive for these ultra-low permeability reservoirs in order to intensively draw on their reserves. Thus, matrix cores and artificially fractured cores were used for discussion on permeability, relative permeability and saturation. In addition, some flow resistance experiments and relative-permeability tests were performed under the same irreducible water conditions. Results show that (i) for both matrix and fractured cores, the saturation in dual-phase flow zones increases and the residual-oil saturation decreases with the increase of permeability; (ii) the lower the permeability is, the earlier the resistance arises, and the earlier the gas bubble originates from degassing affects on permeability; (iii) when the bottomhole flowing pressure is larger than the backpressure at the resistance’s knee point, there is a favorable pressure zone for solution-gas drive, and the degassing has a slight impact on oil flow, allowing for energy utilization of drive with effect; and (iv) according to the trial simulation on the drive model, oil wells with solution-gas drive may exhibit small drainage radius, faster pressure drop near the wellbore, and nonlinear pressure distribution. All results provide certain reference for optimizing development modes together with maintaining and improving productivity in the tight oil reservoirs.

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.

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.

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.

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.

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.

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°.

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.

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.

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.

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.

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.

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.

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.

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.

The pay zone of the Shunbei Oilfield, located in the central-western Tarim Basin, is composed of Ordovician carbonates, with reservoir buried depth exceeding 8 000 m and bottom-hole temperature reaching as high as 180℃. In order to improve the success rate of drilling in this area and address problems of wellbore stability, borehole cleaning, and lubrication preventing sticking existing in the directional drilling of ultra-deep slim hole, an efficient, low-friction and high-temperature resistant drilling fluid system was developed by analyzing the technical difficulties of drilling fluid, making technical countermeasures, and optimizing treatment agents. Evaluation experiment and field application reveal the results in three aspects. (i) This drilling fluid system possesses excellent properties of high-temperature resistance, settling stability, inhibition, sealing, and lubrication. (ii) Applied to the fourth-spudding sections of four wells in fault block 8 of the Shunbei Oilfield, with the assistance of corresponding drilling fluid maintenance and treatment processes on site, the drilling fluid system accelerated ROP by 36.91% and shortened average drilling cycle by 14.41% compared to the four wells previously drilled in this block, achieving the optimized and fast drilling. (iii) The utilization of this drilling fluid effectively resolved problems of wellbore stability, borehole cleaning, and lubrication preventing sticking. It is manifested as: wells using the fluid have good wellbore quality, with an average hole diameter enlargement rate of 5.86%, a reduction of 31.62% compared to the previously drilled wells; the drilling fluid has strong suspension and carrying capacity, and good lubricity, bringing about good borehole cleaning effects, smooth directional drilling with low friction and torque. It is concluded that the successful application of the drilling fluid system provides technical support for future oil and gas exploration and development in the area, and has reference significance for the formula and field operation of drilling fluid in ultra-deep directional wells of other blocks.