The unconsolidated sandstone reservoir in the Toutunhe formation of Santai oilfield, Junggar basin is characterized by complex pore structures, strong heterogeneity and large difference in fluid distribution. In order to clarify the occurrence characteristics of the movable fluid in the unconsolidated sandstone reservoir, typical core samples were taken from the unconsolidated sandstone reservoir, and tested on their NMR (nuclear magnetic resonance) T2 spectra before and after centrifugation, and the T2 cut-offs and saturation of the movable fluid in the reservoir were evaluated quantitatively. The results show that the pore structures in the reservoir of Tou 2 member are complex, and the pore throats are thin and poorly connected; and the T2 spectra has proved the saturation of the movable fluid ranging from 80.42% to 82.57%, with an average of 81.39%, the porosity of the movable fluid ranges from 13.91% to 17.98%, with an average of 15.88%, and the T2 cut-offs is from 1.86 to 4.64 ms, with an average of 3.06 ms. The movable fluid mainly occupy larger pores, while the bound fluid is mainly distributed in smaller pores. The best centrifugal force to the core sample is 1.02 MPa. In the samples No. 4 and No. 7 with poorly developed large pores, the saturation of the movable fluid in larger pores differs greatly from that in smaller pores after four times of centrifugation. As for the sample No. 5 with well developed large pores, increasing centrifugal force can significantly increase the saturation of the movable fluid. And when the centrifugal force is close to 1.02 MPa, which is the optimal centrifugal force, there is almost no difference in the contribution of different pores to the parameters of the movable fluid.
The Kuqa depression in the Tarim basin is rich in oil and gas resources and has great potential for exploration. However, the geological setting in this area is complex and the target layers are generally buried deeper than 6 000 m, or even more than 8 000 m, making oil and gas exploration and development difficult. Considering the geological engineering characteristics and existing problems of ultra-deep wells in the Kuqa depression, a solution based on the concept of geology-engineering integration is proposed, and the successful practice of the first pre-salt highly-deviated well in Tarim oilfield is introduced. Research and practices show that geomechanical research is beneficial to reducing drilling complexities and increasing rate of penetration, can help select favorable reservoirs and optimize stimulation schemes, and finally support the ROP improvement and production enhancement. The geology-engineering integration is necessary for efficient development of complex oil and gas reservoirs. In this aspect, multiple disciplines will be collaborated in operations through the life cycle of each well to generate the maximum benefits and achieve overall progress from well location deployment, drilling engineering, well completion and stimulation to oil/gas production engineering, thereby facilitating the construction of large oil and gas fields.
Shale gas reservoir has multi-scale pore structures, so that shale gas flows in multiple ways including absorbing, diffusing and non-Darcy flow. Present shale gas flowing models only take the permeability and porosity of natural fractures as stress sensitivity factors, but experiments show that the diffusion coefficient is also sensitive to stress. To accurately predict and analyze shale gas reservoir and fluid parameters, it is necessary to establish a fractured horizontal well test model which should consider multi-scale pore structures and multiple gas flowing mechanisms, and it is also helpful to production performance analysis and subsequent development plan making. In this study, according to the multi-scale pore structures, and assuming that the shale gas reservoir is a dual medium with matrix and fractures, we built a fractured horizontal well test model which takes diffusion coefficient, and porosity and permeability of natural fractures as stress sensitive parameters, and analyzed the effects of fracturing scale and reservoir parameters on well test curve. The results show that fracturing parameters mainly affect early post-fracturing production, while reservoir parameters mainly affect late production. The model was applied in a typical shale reservoir block in China, and the modelling result well matched with the measured production data. It is a guiding reference to effective development of shale gas reservoirs.
As a typical oilfield developing low-permeability reservoirs in China, Changqing oilfield has huge resources of tight oil and gas. However, strong reservoir heterogeneity, poor injection-production connectivity and low oil recovery make it urgent to describe the reservoir development units in details to improve the development effects of well groups at medium-high water cut stage. Taking well group Q011-35 as a case, this study evaluated the waterflooding development effect of the well group based on the contact types of the target Chang 61 sand bodies and the results of tracer monitoring and reservoir numerical simulation. It is concluded that the well group Q011-35 is strongly heterogeneous. Laterally, there are high-permeability zones in the northwest and southwest, while vertically, Chang $6^2_1$ is flooded more completely than Chang $6^1_1$, and the remaining oil in Chang $6^1_1$ is richer, indicating reservoir connectivity and injection-production relationship are controlling factors on the distribution of remaining oil. The combination of tracer monitoring and reservoir numerical simulation eliminates the limitations caused by a single method in evaluating interwell connectivity, therefore the results are more accurate and reasonable. The conclusion is a reference to fine evaluation on waterflooding development effect of low-permeability reservoirs and taking effective measures for potential tapping of remaining oil.
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.
During implementing the recent “High-Quality and Efficient Exploration” strategy, evaluation and optimization of seismic exploration have attracted extensive attention. In processing and interpretation of the seismic data from the lithologic reservoirs in Junggar basin, a “Three Lists and One Countermeasure” method and its evaluation system are put forward based on a goal-oriented integrated workflow, and remarkable results have been achieved in field application. However, this evaluation system does not cover seismic data acquisition and mainly consists of some qualitative description methods. Therefore, by taking seismic data with effective bandwidth as a key indicator, a corresponding index system of seismic acquisition is proposed, then evaluation and optimization of seismic acquisition plan are contained in the evaluation and optimization system for seismic exploration, and finally the “Three Lists and One Countermeasure V2.0” is established. The optimized seismic evaluation system has been applied in multiple projects for lithologic reservoir exploration and remarkable results have been obtained. The methods proposed in this paper can be references to evaluating and optimizing seismic exploration for lithologic reservoirs in similar areas.
The core of the conglomerate reservoir from upper Wuerhe formation of Permian is very easy to break after immersed in fluids, so that it is difficult to evaluate how gel-breaking fracturing fluid damages the reservoir, and it is impossible to determine the factors controlling reservoir damage in the southern Mahu area, Junggar basin. This study used X-ray Micro-CT technology to scan core samples and reconstructed the three-dimensional pore structure, and then characterized the pore changes on different sections by the ball-stick model and the threshold segmentation method. The results show that, after the reservoir was damaged by gel-breaking fracturing fluid, the average pore radius, average throat radius, average throat length, average pore-to-throat ratio, porosity and permeability were reduced by 42.1%, 32.7%, 19.1%, 45.3%, 7.7% and 33.8%, respectively. After fractured by gel-breaking fracturing fluid, the reservoir was damaged, resulting in reduced porosity and permeability, especially a significant change in permeability. Swelling montmorillonite in the clay minerals and particle migration are the factors that can cause damage to the reservoir, and the interaction between gel-breaking fracturing fluid and the reservoir is the primary factor causing reservoir damage.
This paper reviews the establishment and development process of the Welge equation, and derives the Welge equation for oil wells after water breakthrough according to the finding that the water cut at the outlet of an oil well drilled in homogeneous reservoirs is numerically equal to that of this oil well after water breakthrough. Using this equation, the mutual conversion between water drive curves and oil-water two-phase flow characteristics can be realized. Taking Iraj Ersaghi’s watercut variation law, Maximov-Tong Xianzhang’s water drive characteristic curve and Efros’s experimental results as examples, the formation process and applicable conditions of them are discussed, and the classical theories and methods of water flooding are further understood. The result provides a reference for evaluating water flooding reservoirs.
In Mahu sag, where there is abundant oil in place, the reservoirs in Permian Fengcheng formation are thick and have revealed good oil/gas show. However, the thin interbeds are complex in lithological assemblages and greatly variable in in-situ stress, so fine separate-layer fracturing must be done to recover the reserves. Based on the numerical simulation method, the factors influencing fracture propagation during multi-layer fracturing were analyzed, providing a basis for rational selection of layers for multi-layer or separate-layer fracturing. The results show that the reservoir stress difference influences fracture propagation the most, followed by fracturing fluid displacement and viscosity, and the reservoir thickness ratio influences the least. Based on the BP neural network algorithm, machine learning was carried out on the numerical simulation results, and a multi-factor fine separate-layer fracturing decision-making model that considers both geological and engineering factors was established. Using this decision-making model, multi-layer or separate-layer fracturing prediction and fracturing parameter optimization were made for 6 wells in the Fengcheng formation on the Manan slope. Post-frac flowing production tests demonstrated that the daily oil production of some wells reached 10.34-32.37 t, and the average single-well production was increased by nearly 50% compared with the traditional fracturing process. The study results can provide effective guidance for the optimization of the fracturing process of thin interbeds in the Mahu sag.
For H gas storage in Xinjiang, the largest gas-reservoir-type sandstone underground gas storage in China, the adjustment plan adopts full arrangement with horizontal wells. The single well is characterized by intensive injection and production as well as large-displacement huff and puff. If the production pressure difference is too large, the rock skeleton may be damaged, and the sand carried out may erode the production string or even block the wellbore, causing production suspension of gas wells and affecting the overall peak-shaving capability of the gas storage. This paper discusses the early warning on critical sand production in horizontal wells based on pressure monitoring. Based on the material balance equation, state equation and flow equation applicable to the H gas storage, a dynamic production pressure difference monitoring model of horizontal wells was established. Meanwhile, the field test on critical sand production pressure difference of horizontal wells was carried out, and the criterion “C” formula model determining rock solidity was defined to predict the critical sand production pressure difference. Finally, an early warning model for critical sand production in horizontal wells based on pressure monitoring was established. The coincidence between the model-derived pressure and the measured pressure exceeds 93%. The model can realize the real-time monitoring of the dynamic production pressure difference in horizontal wells and also lay a foundation for the evaluation of maximum peak-shaving capacity and subsequent peak-shaving and production allocation of the gas storage.
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.
For the conglomerate in the Mahu sag, the law and controlling factors of fracture propagation are unclear. A numerical simulation model for conglomerate was constructed to analyze the law of fracture propagation in conglomerate with different material properties under different loading modes. The results show that the higher the gravel content, the lower the cementation strength and the greater the relative strength of gravel to matrix, the more complex the fractures created in the conglomerate. Influenced by loading mode, the most complex fractures are created in the conglomerate under the combined action of tensile and shear loads. The attracting and shielding effects of gravel on conglomerate fractures promote the formation of complex fracture network in the conglomerate.
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.
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.
In order to clarify the meso-structures and flow characteristics of oil sands in the Jurassic Qigu formation in Fengcheng oilfield, a three-medium image segmenting method suitable for oil sands was proposed by using micron CT grayscale images and conventional image segmenting method. Using the new method, digital oil sand cores were obtained from physical experiments, and finally a pore network model was built. The research shows that when constructing digital oil sand cores, it is necessary to propose a three-medium image segmenting method suitable for oil sands on the basis of the binary image segmenting method for porous media, to distinguish the particles, asphaltenes and pores in oil sands. Only when the side length of the representative volume unit of a digital core is greater than 3.0 mm, it can truly reflect the meso-structures of oil sands. The contact between particle and asphaltene in the oil sands of the Jurassic Qigu formation in Fengcheng oilfield are divided into three types: particle contact, cementing contact and suspending contact. Furthermore, the oil sands are strongly heterogenous and anisotropic, and asphaltene as a part of framework or as pore fluid, its absolute permeability is about 2 orders of magnitude higher than the effective permeability. As a result, the phase state of the asphaltene significantly affects the meso-structures of the oil sands.
Conglomerate reservoirs are generally very heterogeneous, so it is easy to induce large channels during water flooding, resulting in low flooding efficiency, rapid water cut rise and unfavorable development effect. For shallow conglomerate reservoirs which are variable in lithofacies and poor in reservoir continuity, to improve the recovery of polymer flooding, horizontal fractures can be induced through multiple-stage fracturing in arched wells. Based on the geological model of the northwestern block of District Qidong-1 in Karamay oilfield, production history matching was performed for the high water-cut conglomerate reservoirs. Then we set up an injection-production well pattern composed of vertical wells and extended-reach arched wells with horizontal fractures induced by multi-stage fracturing stimulation in the area with enriched remaining oil, and conducted numerical simulation on how to enhance the recovery. The results show that the optimal polymer injecting intensity in the study area is about 0.05 PV/a; the sweep coefficient of an angular injection well pattern is higher than that of an edge injection well pattern; and the polymer flooding effect is the best when horizontal fractures are induced in the upper interval of an arched well. An arched well can make full use of horizontal fractures to improve fluid flow near the wellbore, and it can boost the effect of polymer in profile controlling. The two mechanisms complement each other and can effectively improve the advancement of flooding front, and enhance the recovery of shallow conglomerate reservoirs.
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.
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.
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.
Accurate prediction of clay minerals is the key to deep drilling operation and pay zone protection. In order to determine the distribution law of clay minerals in the Jurassic Ahe formation in the northern tectonic zone of the Kuqa depression, Tarim basin, a well logging model and a combined model based on BP neural network were constructed by using GR logging parameters, cation exchange capacity, hydrogen index and photoelectric absorption cross-section index. The average absolute errors of the two models are 5.34% and 2.38%, respectively. Applied to Well Yinan 5, the average absolute errors of the models are 4.64% and 3.45%, respectively, by considering X-ray diffraction data. The prediction result shows that the clay mineral contents from high to low are illite, chlorite, illite/smectite mixed layer and kaolinite in Well Yinan 5. Damages from velocity sensitivity and acid sensitivity should be prevented in reservoir development.
