A fractured horizontal well in shale oil reservoir should be soaked before it is put into production. In order to quickly evaluate the effect of volume fracturing, a post-frac evaluation method based on the data of soaking pressure of shale oil reservoirs was proposed. Through numerical simulation of well soaking, the pressure diffusion and fluid migration in the stimulation area controlled by the fractured horizontal well were characterized, and a post-closure linear flow calculation model and a fracture storage control calculation model were established. Then a calculation method for inverting fracture parameters and formation pressure was formed. The results show that after pump is stopped, the stimulation area goes through 9 flow stages such as flows controlled by fractures in end section of wellbore, by fractures in the whole wellbore and by reservoir matrix, and the pressure drop derivatives appear as multiple straight-line segments with different slopes in log-log coordinates. This method has been applied to four typical shale oil horizontal wells in Jimsar sag, which proves that the data of soaking pressure can be used for the inversion of fracture parameters and formation pressure, and also verifies the applicability of the proposed method. The study results provide a reference for evaluating fracturing effect and optimizing well spacing.
Formation pressure which can reflect porosity，compaction，and fluid occurrence of underground rock formation is very important for discovering effective reservoirs. Regarding the status that the effective stress coefficient is set as 1 for simplification when calculating formation pressure，the dynamic effective stress coefficient considering pore structure parameters is calculated based on a unified rock skeleton model and the Gassmann equation，formation pressure and pressure coefficient are estimated by using the conventional Eaton method，and the accuracy of formation pressure estimation is improved. Taking carbonate and sandstone reservoirs as examples，the estimated formation pressures show anomalies in water layers，dry layers，and gas layers. Compared with the results obtained from the conventional Eaton method，the proposed method provides a more accurate estimate of formation pressure，thus facilitating a more reliable discovery of effective reservoirs.
In order to improve the precision of VSP seismic imaging, a VSP reverse time migration (RTM) operator with 16-order finite difference accuracy was constructed, and then the algorithm accuracy of VSP key links and the interchangeability of shot and receiver points were analyzed by using impulse responses to verify the accuracy of the 3D VSP RTM operator. Based on the standard theoretical model of lava dome, the imaging effects of normalized VSP RTM and conventional cross-correlation RTM were compared. It is found that VSP RTM can describe the geological body boundary and formation interface more clearly and more accurately, and can eliminate the uneven influence of folds to make energy distribution more uniform, with no well trace. The high-precision 3D VSP RTM technology was applied to the walkaway VSP data of Well L in the Songliao basin, and accurate and fine imaging of near-wellbore formations and small faults was achieved, which further verified the accuracy of the technology. The proposed VSP RTM technology can help improve the imaging accuracy of complex reservoirs around the wellbore.
According to the typical characteristics of low permeability reservoirs in Changqing oilfield, parallel core and double-layered core experiments were carried out to simulate the effect of unstable waterflooding in heterogeneous low permeability reservoirs. Due to the poor visibility of core experiments, numerical models for simulating interlayer and intralayer heterogeneous reservoirs were established, which may reveal the stimulation mechanism of unstable waterflooding according to the change of flow field. The results show that for interlayer heterogeneous reservoirs, compared with continuous waterflooding, unstable waterflooding can promote the advancement of the flooding front in the layers with lower permeability, and give full play to capillary force in oil displacement, so unstable waterflooding can significantly improve the oil recovery of the layers with lower permeability, and the pattern of short-term injection combined with long-term quit can enhance the recovery rate the most. For intralayer heterogeneous reservoirs, unstable waterflooding can generate pressure oscillations in the layers to enable the fluid percolation between the higher permeability layers and the lower permeability layers, so that the sweep efficiency of injected water in the lower permeability layers is increased and the recovery rate of the lower permeability layers is enhanced, thereby increasing the total oil recovery rate of the reservoir.
The Carboniferous-Permian sandstone gas reservoirs in the Ordos basin are tight, with obvious different gas saturations from part to part of the reservoir unit, complex gas-bearing pattern, non-uniform reservoir pressure systems, and highly heterogeneous distribution of reserves as a whole. This paper compared the geological and development characteristics between Carboniferous-Permian tight sandstone gas reservoirs and the conventional sandstone gas reservoirs in Yanchang gas field in Ordos basin. It is found that there is a threshold pressure gradient during the development of the Carboniferous-Permian tight sandstone gas reservoirs, and the single-well produced geological reserves and the single-well reserves producing radius increase with the decrease of the bottom hole pressure. When the abandonment pressure is reached, the single-well produced geological reserves and the single-well reserves producing radius reach the maximum values. Accordingly, by analyzing the distribution of reserves during the development of tight sandstone gas reservoirs, the material balance equation under the condition of threshold pressure gradient was established, and the relationship between cumulative production and bottom hole pressure was obtained. Furthermore, two methods for calculating the threshold pressure gradient were analyzed. On this basis, the method for calculating the single-well producing geological reserves and the single-well technically recoverable reserves in tight sandstone gas reservoirs was proposed, which provides a theoretical basis for the optimization of well pattern to develop tight sandstone gas reservoirs. The theoretical calculation method has been improved to form a simplified method for calculating single-well producing geological reserves, which is referential for well pattern deployment in undeveloped blocks.
Hydraulic fracturing is an effective method for developing the shale reservoirs in the Permian Fengcheng formation in the Mahu sag，but the propagation characteristics of hydraulic fractures are unclear. Maye-1H，a typical horizontal well in this area，suffered from difficulties in fracturing initiation and sand addition. Thus，it is urgent to carry out hydraulic fracturing simulation to clarify the impacts of natural fractures，rock mechanical properties，and operation parameters on fracturing effect. According to the actual operation parameters such as pump pressure，fracturing fluid displacement and added sand volume in Well Maye-1H，a 2D hydraulic fracture propagation model and a 3D hydraulic fracturing model were established by using Abaqus software and Petrel software，and then numerical simulation on hydraulic fracture propagation was performed. The results show that the fracturing effect is closely related to natural fractures. The lower the tensile strength of the rock where natural fractures are developed，the easier the hydraulic fractures tend to be captured by the natural fractures. When the Young’s modulus in the fractured interval is relatively large，the hydraulic fractures formed are small in width，and most of them propagate and slip along the natural fracture trend，making it difficult to add sand. When the Young’s modulus in the fractured interval is relatively small，the hydraulic fractures formed are large in width，and they can directly pass through the natural fractures，making sand adding relatively easy.
Hydrocarbon-rich continental diamictite developed in the Permian Fengcheng formation of Mahu sag, Junggar basin is characterized by varieties of minerals and rapid variation of lithology. Conventional logging cannot be used to effectively identify the lithology of diamictite. By using lithology scan logging, the mass fractions of the main elements in the formation are obtained, and the mineral mass fraction is then calculated according to the relationship between mineral-sensitive elements and minerals. The diamictite index is constructed by using the ratio of felsic mineral content to carbonate mineral content, and the shale index is constructed by using the difference between neutron porosity and nuclear magnetic resonance total porosity. Then the lithology identification chart for the diamictite in the Fengcheng formation is formed by intersecting the diamictite index and the shale index. The results show that the calculation of mineral content is accurate with the average relative error of only 6.5%, and the lithology interpretation exhibits a coincidence rate of 90.9%, which meets the needs of logging evaluation. The proposed method provides a reference for logging lithology identification of diamictite shale reservoirs.
In order to further accelerate the exploration and development for shale oil in the Lower Permian Fengcheng formation in the Mahu sag，Junggar basin，sweet spots of shale oil should be identified. Considering that lithology is the main factor controlling geological sweet spots，and brittleness index and horizontal principal stress difference are the main factors controlling engineering sweet spots，seismic methods of predicting geological and engineering sweet spots were established on the basis of prestack simultaneous inversion. In terms of geological sweet spots，by using core，experiment，drilling and logging data，the dominant lithology for shale oil sweet spots was identified to be dolomitic siltstone，the elastic parameters sensitive to the dominant lithology were selected，and the distribution of dolomitic siltstone was predicted by using prestack isimultaneous nversion and lithofacies probability analysis techniques. In terms of engineering sweet spots，using the Young’s modulus and Poisson’s ratio obtained from prestack simultaneous inversion，cubes of brittleness index and in-situ stress for the study area were obtained through the Rickman brittleness index method and a combined spring model. The predicted results are consistent with the actual drilling results，which confirms the accuracy of the prediction of geological and engineering sweet spots. The proposed methods can provide references for shale oil exploration and development in other areas.
The Sebei gas field，a major natural gas producing area in the Qaidam basin，is characterized by multiple layers，easy sand production，and gas reservoirs with edge water. With the progress of the gas field development，reservoir plugging due to the factors such as water blocking damage，clay mineral hydration swelling and migration，and increased volume of the fluid entering wellbore occurs frequently in gas wells，which seriously affects well productivity. In the Sebei gas field，the unconsolidated sandstone gas reservoirs have high shale content and are suffering intensified water production. Through simulation experiment，it is determined that the influencing factor of reservoir plugging is clay mineral content. In order to protect the reservoirs，by selecting proper and economical plugging removal fluids，a chemical plugging removal technology has been developed for unconsolidated sandstone gas reservoirs in the Sebei gas field. Field application shows that this plugging removal technology is featured with fast operation，high efficiency and long validity，showing a good performance and application prospect.
In the upper Es4 in Y184 well block，northern Bonan subsag of Zhanhua sag， multi-stage fan delta deposits are developed，and characterized by thin sand bodies individually，great variation laterally and sandstone interbedded with shale，making it very difficult to perform quantitative prediction，which restricts the efficient development of this well block. Through deep learning and seismic attribute prediction，virtual wells were constructed to solve the problem of insufficient training samples for deep learning in the study area. Thus，a nonlinear relationship between sand body thickness and seismic attributes was clarified，and a network model for predicting sand body thickness using seismic attributes was established. This method can accurately predict sand body thickness and lateral distribution with a significantly improved accuracy，and provides a new idea for the prediction of tight sandstone reservoirs.
Production and steam chamber location are critical for steam assisted gravity drainage (SAGD) in heavy oil reservoirs. The existing prediction model only considers the lateral expansion of steam chamber and cannot predict the production of adjacent wells after steam chamber contact. According to the different characteristics of the steam chamber in the lateral expansion stage and the downward expansion stage, a parameter of thermal penetration depth was introduced, the flow potential function was modified, and a parabolic production prediction model was established. The results show that the production increases gradually in the initial lateral expansion stage of steam chamber, and then decreases due to the reduction of the inclination of the steam chamber interface; in the downward expansion stage of steam chamber, the production further decreases. The model analysis reveals that SAGD is more suitable for thick reservoir development, and the optimal well spacing needs to be determined depending on the oilfield conditions. The parabolic production prediction model takes the characteristics of the steam chamber into account in the downward expansion stage, and the accuracy of the model is verified by comparing with the previous experimental data.
In order to improve the effective reservoir encounter rate during sidetracking drilling in existing wells,with a block in central Sulige gas field as an example,and combined with the geological characteristics and development status of the gas field,the key geological technologies for sidetracking horizontal drilling in existing wells were summarized from the aspects of optimal deployment and geosteering. On this basis,the development effect of sidetracking horizontal wells was discussed in light of drilling effect,production index,benefit evaluation,etc.,and the influence of various factors on the development effect was comprehensively analyzed. The research results show that the remaining gas mainly enriches in the areas including the rim of mid-channel bar,braided channel,and middle or bottom of the mid-channel bar in the sand belt of main channel. Based on the economic evaluation,the selection criteria for sidetracking well locations were established,that is,the lower limit of the effective thickness of recoverable beds is 4 m vertically,and the lower limit of the abundance of the remaining reserves is 0.42×108 m3/km2 on the plane. Using 3D geological model,stratigraphic dip evaluation,pilot hole information and data acquired while drilling,the horizontal-well geosteering sidetracking technology was formed,and three horizontal-section geosteering modes were provided. For 23 sidetracking horizontal wells in the study area,the average effective reservoir encounter rate is 59.7%,the average initial gas production is 2.9×104 m3,and the cumulative incremental production is 3.13×108 m3.
Fractures are developed in the igneous strata of the Kelameili gas field. The composite structure consisting of natural fractures and pores or cavities in such fractured formations may result in a large difference between the leakage pressure and the formation fracture pressure during drilling. The leakage mechanism was investigated according to the fracture-pore occurrence and the fracture opening/closing，connection and filling of the igneous rocks in different well sections，the leakage pressure models under different fracture states were constructed，and the layered leakage pressure profile was plotted depending upon pore pressure，in-situ stress and other parameters，so as to determine the leakage law of natural fractures in the igneous rocks in the Kelameili gas field. The results show that the leakage pressure of closed fractures in the igneous rocks is controlled by in-situ stress，and the leakage pressure of open fractures is affected by formation pore pressure and filling state. Furthermore，combining with the drilling parameters from typical wells，the variation law of fracture leakage pressure under different well trajectories was analyzed，and the safe density window of drilling fluid was determined to ensure drilling safety.
The oil and gas reservoirs in the Qiketai formation of Middle Jurassic in the Pubei area of Taibei sag, Turpan-Hami basin, are controlled by lithology. Early exploration confirmed that there are thin oil-bearing sand layers with the thickness of 6-15 m at the bottom of the Qiketai formation. It is difficult for conventional inversion methods to predict these sand layers and these methods often yield large errors due to the limitations of the frequency band of seismic data. In order to improve inversion accuracy, a facies-controlled geostatistical inversion method based on low-frequency model optimization was proposed. Combined with the characteristics of large structural relief and greatly varying sedimentary facies in the study area, the low-frequency model was established by combining the compaction trend correction method and the seismic attribute constraint method to obtain the deterministic inversion results. On this basis, a facies-controlled model was established for facies-controlled geostatistical inversion, thus enabling the identification of thin sand layers in the study area. This method effectively complements the low-frequency information missed in seismic signals, and improves the longitudinal resolution of the inversion results. By using this method, a thin sand layer with the thickness of 7 m can be identified, and the inversion result is basically consistent with the actual thickness of sand body, which confirms the effectiveness of this method in predicting thin sand layers in Pubei area.
For multi-layer gas reservoirs in the Shenmu gas field, improper selection of geological targets for horizontal well development may lead to the problems such as poor economic benefits and unrecovered reserves. The development scale and stacking patterns of sand bodies in these multi-layer gas reservoirs were investigated, and the single-layer, double-layer and multi-layer gas reservoir models were established by adopting the concept of reserves concentration. Taking the horizontal well stimulation ratio as the basis for economic benefit evaluation, the reservoir limit of horizontal well development in multi-layer reservoirs was evaluated. The research shows that large-scale composite effective reservoirs are locally developed in the Lower Permian Taiyuan formation and the second member of the Lower Permian Shanxi formation in the Shenmu gas field, with an effective thickness of 6.0-9.0 m and a length of 1 600-3 200 m. These intervals satisfy the optimal reservoir conditions for horizontal well development, namely the reserves concentration greater than 75% and the permeability ratio of the dominant layer to the secondary producing layer ranging from 0.8 to 3.9.
The ultra-deep formations in the Kuqa depression are rich in oil and gas resources，with strong reservoir heterogeneity and obvious well-to-well productivity difference. The present-day in-situ stress plays an important role in wellbore trajectory design，horizontal well operations，and fracturing design，but the current research methods are disadvantageous in many aspects. On the basis of the measured present-day in-situ stress，the relationship between in-situ stress and logging parameters was constructed，and the prediction of the present-day in-situ stress in the ultra-deep tight sandstone reservoirs in the Bozi gas reservoir of Kuqa depression was realized by using BP neural network. The results show that BP neural network is an effective method for predicting in-situ stress，with just a small error between the predicted and measured in-situ stress values，which is generally less than 10%. In the Lower Cretaceous of the Bozi gas reservoir，the maximum horizontal principal stress is the largest，followed by the vertical principal stress，and the minimum horizontal principal stress is the smallest. Generally，the strike-slip stress mechanism is universal，and the maximum horizontal principal stress is predominantly NE-SW trending in the east and NW-SE trending in the west of the Bozi gas reservoir. Compared with sandstone intervals，the sandstone-mudstone interbedding interval exhibits a stronger fluctuation of in-situ stress and a sudden high in-situ stress locally. The horizontal wells drilled along NE-SW direction in the east of the Bozi gas reservoir and along NW-SE direction in the west are relatively stable，while the vertical wells are prone to collapse.
When tight oil reservoirs are developed by depletion mode, oil production declines rapidly. In order to explore a more effective development technique, a CO2 inter-fracture flooding model for horizontal well was established using the CMG-GEM software to simulate how the factors such as CO2 injection volume, injection pressure, reservoir temperature, fracture spacing and fracture length affect horizontal well productivity. The results show that CO2 inter-fracture flooding in a horizontal well can greatly increase the CO2 swept area, fully exploit the remaining oil, and improve the development effect. When the injection pressure is 25 MPa, the CO2 injection volume is close to and not more than 10×104 m3. The peak production rate rises with the increase of injection pressure, fracture spacing and fracture half-length. The peak production rate at the reservoir temperature of 80°C is higher than that at other temperatures; however, the higher the reservoir temperature, the less time will be needed to reach the peak daily production rate.
In order to realize the identification of the connected fractured-vuggy structures in the Tahe oilfield，based on the seismic interpretation results of large-scale reservoirs，together with the drilling，logging，testing，tracer and other data，the reservoir types in near-well and inter-well areas were identified. By identifying the reservoirs with static and dynamic monitoring methods，the characteristic parameters of the dynamic methods for identifying reservoirs in fractured-vuggy units were determined to improve the reliability of the identification. Depending upon the types of reservoirs identified with static and dynamic methods，the connected fractured-vuggy structures were constructed according to their in spatial position relationship. The application in the identification of single-well fractured-vuggy structures in the X unit reveals that the proposed comprehensive method is more reliable in identification of fractured-vuggy structure than a single static or dynamic method.
The reservoirs controlled by deep and large faults are generally thick and deep. Therefore, a well cannot penetrate completely through an entire reservoir. For calculating the oil column height in fault-controlled reservoirs, a physical model of oil column height in fault-controlled reservoir was established. On this basis, the idea of the wellbore temperature profile extrapolation method was discussed, a formula for calculating oil column height with the conversion method of oil-water column pressure coefficient was derived, and the dynamic reserves inverse method considering the cuboid drainage area and the equivalent flow resistance method considering the influence of gravity were proposed. The four methods were applied to two wells drilled into a fault-controlled reservoir in Fuman oilfield of Tarim basin. The results show that the oil column heights calculated by the four methods are consistent, and the average oil column heights of the two wells are 675.39 m and 634.60 m, respectively.
The southern margin of the Junggar Basin is a mountainous area with severe surface fluctuations. The conventional seismic processing method cannot meet the needs of the assumptions of the processing method due to the actual geological structure of the surface and deep layers，resulting in an unsatisfactory imaging effect and a large error between the interpreted depth and the measured drilling depth. In order to improve the quality of seismic data processing in the area，a seismic data processing method based on rugged datum was explored by using the velocity modeling with double square root operator. The method can reduce the distortion of wave field caused by the horizontal datum correction of the common midpoint (CMP) gather and provide a velocity field similar to the real observation surface for pre-stack migration，thus realizing the efficient integration of the time-domain datum and the depth-domain datum. The actual application of the new method show good seismic data processing results，with accurate migration imaging homing，satisfactory focusing，and significantly reduced error between the depth obtained from seismic interpretation and the depth measured by drilling. The new method provides a reference for seismic data processing in similar mountainous areas.
