The Ordovician fractured carbonate reservoir in the Shunbei field is buried ~7300m below ground level and has presented great challenges for the drilling of extra deep, deviated development wells. Borehole instability-related drilling problems including pipe stuck, pack-off, and mud losses have been experienced frequently during drilling, with many wells being sidetracked three or four times before reaching the target. To understand the failure mechanism and optimize the drilling design to mitigate the drilling risk has become crucial for the field development. As the basis of the investigation, detailed geomechanical modelling was conducted for a selected area with the most representative drilling problems. Laboratory core tests, wireline logs, image data and drilling experiences were used to build geomechanical models characterizing the in situ stress, pore pressure and rock mechanical properties in both the overburden and reservoir sections. Stress-induced borehole failures observed in the image logs were analysed to help diagnose the failure mechanisms together with the cavings recovered from the problematic wells, which provided significant insights into the likely nature of instability problems in the wells. The geomechanical modelling from a series of wells revealed that the stress magnitudes in the selected area vary based on the structural location. The wells near the major fault system appear to be in a normal faulting stress regime in the Ordovician reservoir, while the wells nearby the secondary fault system are in a strike-slip faulting stress regime. Different stress regimes and horizontal stress anisotropies have resulted in different behaviors during drilling, with breakouts seen in some vertical wells while not in other vertical wells despite using similar mud weights. during drilling. The variable stress conditions plus the highly developed fractures have caused serious borehole collapse in some wells, but reasonably good hole condition in other wells. Wells using higher mud weight are not necessarily the ones having fewer drilling problems. Although the complex lithology, great depth, and unpredictable distribution of intrusive rocks has complicated the drilling problems, a proper definition of suitable mud weight to control borehole collapse and understanding of the natural fractures might play a bigger role in maintaining borehole stability and mitigating drilling risk. A good understanding of the stress condition and rock mechanical properties appears to be helpful in defining the proper mud weights and optimizing other drilling parameters to help mitigate the complex drilling problems encountered during drilling in the Shunbei field. However, additional work on the fracture distribution and trend of stress change in the field might be required to help investigate the problem further.

Oil and gas companies operating carbonate oil and gas condensate fields in Kazakhstan have been carrying out acid stimulation activities leading to a substantial increase in hydrocarbon production. Nearly all treatments were considered a success. Nevertheless, a certain level of optimization in the production enhancement methods that could, potentially, have brought additional technical and financial benefits, were overlooked due to various reasons. A comprehensive review of historical treatments on several fields located in West-Kazakhstan region was performed to identify areas to improve post-stimulation well performance. This review identified improvements including "cleaner" fluid selection, optimised design and treatment schedules. Historical treatments in the oil field typically used straight hydrochloric acid as the main acid, polymer-gelled (self-diverting) acid as the chemical diverter, and linear guar gel for displacement, and diagnostic tests. The application of a modern single-phase retarded acid to replace the straight hydrochloric acid was identified as a key improvement that would yield more efficient wormhole generation and an improved stimulation ratio. Another opportunity for improvement was to upgrade the chemical diversion system from polymer-based self-diverting acid to a viscoelastic surfactant-based (polymer-free) diverting acid system. The use of an oil-based displacement fluid with high retained permeability instead of linear gel and to reduce the hydrostatic pressure post-acidizing, thereby improving flowback, was also employed. Extended core flow testing for regained permeability and solubility were carried out with several acid systems to compare their capabilities and efficiency to create conductive wormholes, and their dissolution capacities. Additionally, emulsion, and sludging tendency upon contact with wellbore tubulars and formation crude was checked to verify the acids’ compatibility with hydrocarbons produced from the target reservoir. After the prerequisite laboratory testing, field trials commenced applying various combinations of fluid technologies in high-rate matrix stimulation treatments. The optimizations resulted in higher (normalized) post-stimulation productivity index (PI), facilitated formation cleanup, and enabled more efficient operations. A similar approach is, currently, being implemented in other stimulation projects in the region, and the results are being replicated. As has been mentioned above, one of the main enhancements implemented as part of this work is the employment of the single-phase retarded acid. Most of the published literature discussing application of the acid covers the cases of stimulation of relatively hot reservoirs (BHST>100°C) as acidizing of high-temperature carbonate rock using traditional hydrochloric acid is a great challenge. The current paper provides details of the case studies, where the acid system was successfully implemented in combination with several other stimulation technologies for mid-temperature ranges. One of the objectives was also to assess whether application of reduced volumes of the retarded and diverting acids would still lead to improved wells’ productivity. Positive results of the laboratory studies, treatment modeling, and field trials were validated by the increasing normalized post-stimulation PI with each optimization step.

The highly complex geology of the Sichuan Shale gas play, especially in relation to natural fracture systems at different scales, affects the hydraulic completion efficiency and performance. Ant-tracking-based workflows and borehole image data are regularly used to optimize completion campaigns, but bridge-plug-stuck and screen-out risks are still high. The lack of sufficient understanding and accurate identification of the natural fracture systems are the major challenges to address these engineering risks. Surface microseismic monitoring campaigns were conducted over several wells of the Changning field, Sichuan Basin, China. The surface receivers were placed in a radial pattern to record microseismicity generated by hydraulic fracturing. The failure mechanism of all mapped microseismic events (i.e., strike, dip, rake, etc.) was extracted using a moment tensor inversion (MTI) method. Improved understanding of the natural fracture systems and their influence during the hydraulic fracturing process has been achieved by integrating the regional geological data, pumping data and MTI results. Several hydraulic fracturing cases that stimulated near natural fracture systems were investigated. The microseismic monitoring results show that (i) most of the hydraulically induced fractures located in the vicinity of the natural facture or fault did not propagate along the regional maximum stress direction, (ii) the bridge plug got stuck and (iii) screen-out happened frequently in these areas. Moment tensor inversion reveals that (i) the dominant failure mechanism of the natural fractures different from hydraulically induced fractures, (ii) more than one group of natural fractures develop along different directions. Real-time adjustments of the pumping schedule and bridge-plug settings were conducted to reduce engineering risks based on the improved understanding of natural fractures, which proved effective. The innovation of using surface microseismic monitoring results to improve understanding of natural fractures and reduce the engineering risks in real time represents a key step forward to mitigate natural fracture influence and improve the effectiveness of stimulation.

The first hydraulic-jet-fracturing multizone completion application was performed in an offshore high-permeability oil well located in the Bozhong oil field in Bohai Bay, China. A detailed case study is presented, highlighting operational challenges and lessons learned from the offshore multizone completion in the Bozhong field. Most offshore high-permeability oilwell completions in the Bozhong field employ tubing conveyed perforation (TCP) followed by frac-packing as multi-zone completions, which is practical in this field. Unlike conventional multizone frac-pack completions, to run perforation guns, the perforating must be completed first, followed by running isolation packers to complete the multizone frac-packing treatments. For hydraulic-jet-fracturing multizone completions, the hydraulic jetting tools are delivered to the target depth using drill pipe; following that, slurry fluid is pumped through the drill pipe to cut through the casing to create fluid flowing channels, which communicate with the pay zone formation. Lastly, the fracturing operation is completed by pumping both proppant slurry through the drill pipe and cleaning fluid through the annulus simultaneously, which creates dynamic hydraulic diversion as functions of isolation between zones. After completing one treatment zone, the tools are pulled to the next target depth, repeating the procedures, until the entire well is complete. After the fracturing treatment, the operator runs production tubing and other accessories, putting the well into production as usual. A detailed completion design and step-by-step operational procedures were prepared based on well data and work conditions to help ensure the effectiveness and safety of the offshore operation. Although some challenges were encountered during the operation, it was overall successfully performed, and significant performance improvement was achieved. After being in production for months, the candidate well has maintained a longer high-production-rate period than the offset wells completed using conventional multizone frac-pack completions. This hydraulic-jet-fracturing multizone completion has proven successful in the Bozhong oil field. The experiences and lessons learned can help benefit future multizone completion optimization for other similar offshore high-permeability oil wells.

The development well drilling for the deep carbonate reservoir in Shunbei field, located in Tarim Baisn in Northwest of China, has been challenging because of the great depth, complex lithology, highly fractured reservoirs and the stress condition of the field. Although vertical wells could mostly be drilled to over 7,000 m deep by continuous reaming, deviated well drilling turned out to be extremely challenging. These wells are associated with frequent hole instability related issues such as stuck pipe and pack off, which results in sidetracks. To help understand the different drilling behaviors in different parts of the Shunbei field, a pilot area was selected to construct a 3D geomechanical model to understand the lateral variations in stress and rock properties by integrating the spatial structural and lithology changes. A 3D geomechanical model is built using the well-based models as foundation and integrating the surface seismic interpreted surfaces, attributes and velocity volumes. Based on detailed well-centric geomechanical modeling, an understanding of the three principal stresses, pore pressure and rock mechanical properties and parameters of the formations was previously developed at the offset wells locations in Shunbei field. Rock mechanical properties, pore pressure and stresses were populated in 3D space using inverted seismic volumes and relationships developed in the well-centric models, honoring the 3D static geological and structural models. 3D geomechanical modeling is an effective method to capture the lateral variations away from the offset wells and helps to diagnose and understand the drilling problem in the complex deep carbonate reservoir.

Initial hydraulic fracturing of shale oil reservoirs has often resulted in disappointing results, with low connected volumes and productivity degradation with depletion. To improve the single well production and oil recovery, re-fracturing techniques have received increased attention, but face the challenges of economy, applicability and feasibility. In this paper, the propagation mechanism during re-fracturing operations is explored through laboratory experiments. Firstly, mechanical analysis and fracturing simulation experiments were performed using the formation cores. After the fracturing simulation experiment, the fractured core was soaked in supercritical CO 2 to enhance the re-fracturing effect. Then a re-fracturing simulation experiment was performed to analyze the fracturing propagation mechanism. Meanwhile, some new cores are soaked into supercritical CO 2 to explore the changes of mechanical properties under different soak time. The mechanical analysis experiment showed that supercritical CO 2 soak has a strong influence on the uniaxial compressive and tensile strength of shale. With an increase of soak time, both the compressive and tensile strength clearly decreased. During the first fracturing operation, fractures propagated only along the horizontal bedding and could not open the rock matrix. After supercritical CO 2 soak, re-fracturing could open the horizontal bedding more easily as well as extend to the rock matrix, creating a more complex fractured system, enhancing oil recovery.

Water production represents a major challenge over the life of a reservoir. It is an important issue that directly affects hydrocarbon production and total reserves recovery around the world, especially in fractured reservoirs. In the south of Mexico, several naturally fractured, low-pressure reservoirs experience production disruptions when water from the aquifer channels invades oil-producing intervals through high-conductivity fractures. Water shutoff (WSO) treatments vary in design approach and efficacy percentage due to the difference in environments and formations that are subject to water breakthrough. For the last decade, in southern Mexico, different treatments have been performed without achieving the expected results in the described reservoirs. These treatments have included different types of fluids, including rigid setting gels; reactive pills; selective water setting cement; and conventional cement slurries, with or without the use of mechanical aids such as mechanical plugs, cement retainers, or coiled tubing for precise placement. One of the biggest challenges of WSO in these reservoirs is that the proposed treatments must have a high level of penetration into the natural fractures but, at the same time, they need to be displaced with nitrogen or light hydrocarbon derivatives to balance reservoir pressure, avoiding total losses of fluids into the highly conductive, low-pressure reservoir where they will lose the ability to control water flow from the aquifer. Using the synergies of the operator's reservoir knowledge, diagnostic workflow, and historical treatment records coupled with service company's treatment engineering technologies and local ability to manipulate and enhance existing WSO fluids, we exercised a systematic evaluation approach to the evaluation of past unsuccessful experiences and proposed adjustments to conventional treatments using rigid gel and conventional cement slurries for water control. Integrating the relevant findings following operator's water control diagnostic workflow with the study of relevant papers and methodologies used by oil companies around the globe, we proposed a different treatment strategy consisting in the addition of a reactive pill between the rigid gel and the cement to keep the treatment in the vicinity of the wellbore, viscous spacers between each treatment fluid to avoid contamination while traveling downhole, the inclusion of lost circulation fibers to create a fibrous net to promote cement filter-cake development and tailored treatment displacement with a predefined pressure according to reservoir condition that is close to the reservoir-equivalent hydrostatic pressure. During the past 2 years, the application of rigorous evaluation of potential candidates and the combination of these three enhanced WSO fluids in the described sequence reduced unwanted water production in two naturally fractured low-pressure reservoirs. In three field cases, the use of the proposed methodology led to a reduction of overall water production from an initial value between 70 and 100% to levels below 30%. Incremental oil production has been maintained in the best cases for more than 2 years after the treatments. The most significant result occurred in the first field case, where the water cut was reduced from 90% to less than 2% and oil production increased 12 times, obtaining a cumulative oil production of 240,000 bbl in a year. The documented methodology is a work in progress; we cannot replicate the technique exactly because each well presents challenges according to its construction and structural placement. Similar WSO treatments have been successfully applied in several wells in southern Mexico, increasing oil production and recoverable reserves. Continuous improvement efforts have also led to efficiency enhancement over time, as results and lessons learned are captured to be shared and replicated in similar reservoirs.

Defining pressure dependent permeability (PDP) behaviour in coalbed methane (CBM) or coal seam gas (CSG) reservoirs using reservoir simulation is non-unique based on the uncertainty in coal properties and input parameters. A diagnostic fracture injection test (DFIT) can be used to investigate bulk permeability at a reservoir level and at lowered net effective stress conditions. As coal has minimal matrix porosity and under DFIT conditions cleat porosity is fluid saturated with reasonably definable total compressibility values, the DFIT data can provide insight into PDP parameters. At pressures above the fissure opening pressure, pressure dependent leak off (PDL) behaviour increases exponentially with increasing pressure. Many authors have noted that with decreasing pressure PDP declines exponentially with increasing net effective stress. Thus, PDP behaviour can be defined by PDL. In this paper, we show how combined analyses, using typically collected field data, can be used to better define and constrain the modelling of PDP. We illustrate this process based on a well case study that includes the following data: fracture fabric and porosity reasonably defined from image log and areal core studies; DFIT data acquired under initial saturation conditions; hydraulic fracturing data; and longer term production data. These analyses will be integrated and used to constrain the parameters required to obtain a rate and pressure history-match from the post-frac well production data. This workflow has application in other coal seam gas cases by identifying key variables where hydraulic fracturing performance has been unable to overcome limitations based on pressure or stress dependent behaviours and often accompanied by low reservoir permeability values. While this is purposely targeting areas where only typically collected field data is available, this workflow can include coal testing data for matrix swelling/shrinkage properties or other production data analysis techniques.

This paper pointed out that the simulation accuracy of original embedded discrete fracture model (EDFM) during early-time production of multi-stage fractured horizontal well is low due to the linear pressure distribution assumption in matrix cells containing fracture cells. To resolve the above limitation of original EDFM, a modified EDFM is presented by adding multi-layer virtual cells adjacent and parallel to fracture cells and changing the connections between cells. This modified EDFM can make the same function like LGR technique, and does not bring any complexity to pre-processing algorithm of EDFM, especially for its 3D implementations. A test case and an application example for complex fracture network are implemented to verify that this modified EDFM can significantly improve the early-time simulation accuracy to greatly eliminate the errors of the original EDFM.

Choosing an appropriate technique for upscaling the permeability of the discreet fracture network (DFN) model is vital for maximizing recovery from naturally fractured reservoirs (NFR). Flow -based upscaling is accurate, yet it is computationally expensive. Analytical (i.e. Oda method) upscaling is computationally efficient; however, it is only accurate for well-connected fractures. The objective of this paper is to analyze the performance of the newly developed Oda corrected method which addresses issues associated with previous upscaling methods. This research was executed by using a commercial numerical simulator and by using data set from the Teapot Dome Reservoir. Furthermore, DFN modeling was used to generate different realizations for the fracture network. Consequently, sensitivity analysis was performed through a realisti c uncertainty quantification to generate a base case and 6 different DFN realizations. The main parameters used for this study are fracture length and intensity. Afterwards, the fracture permeability corresponding to each DFN realization was upscaled using the above-mentioned methods. Finally, differences between the upscaling methods were evaluated and analyzed using flow-based upscaling as the criterion. Indeed, the analysis revealed that the new Oda corrected method can calculate the equivalent permeability tensor with adequate accuracy. However, it overestimates the permeability when fracture networks are below the percolation threshold and/or when fractures length is large. Hence, this method is recommended for networks with moderate to high intensity. Furthermore, it has been deduced that fracture length has a great impact on the connectivity of fractures, albeit its effect on permeability is limited by fracturing density. Additionally, it has been found that the length of fractures has an immense impact on the anisotropy ratio and control the occurrence of water bypassing, which were not captured by the Oda method.

Complex reservoirs can be located within clastic and carbonate type environments. This paper reflects the complexity within such and in particular of the clastic family, i.e. sandstones, siltstones. These reservoirs can, on occasion, be associated with limited matrix permeabilities. These permeabilities can be in the range of microdarcies and even as low as nanodarcies with natural fractures (NF) or fissures within the framework which significantly enhance the production levels via secondary porosity mechanisms. In general, the production capability from matrix permeability as identified on their own do not possess sufficient conductivity to keep the reservoir at viable long-term commercial levels of production. Under the conditions where natural fissures/fractures prevail, a situation arises where the induced hydraulic fractures may promote interaction with the natural fracture/fissure resulting in an enhanced fluid leak off, which consequently can arrest the induced fracture and can lead to negative early job screen out. The propagation of the induced fracture will be dependent on the magnitude of stress on the rock itself and the four (4) listed typical types of natural fracture/fissure interactions. Type 1 fractures provide reservoir storage capacity and permeability. Type 2 fractures provide the permeability and the matrix provides porosity. In Type 3, the matrix permeability already provides sufficient primary permeability with the fractures adding additional flow capacity, and Type 4 natural fractures are filled with minerals and provide neither additional porosity nor permeability. The paper will present alternative options to keep these natural fractures/fissures open after frac. Common practice in this environment has included the use of 100-mesh sand pumped ahead of the planned hydraulic fracture to minimize the effect of fluid loss. Typically, this methodology has relative success from the viewpoint of job execution and leak-off control; however, this can reduce the conductivity of vugular spaces within the natural fracture/fissure and rock matrix conductivity, and therefore may influence potential production from the reservoir. It is expected that dilation of the natural fracture and subsequent propping with the placed 100-mesh natural sand is evident for existing open natural fractures. Consequently, there will be losses to the secondary porosity conductivity and the potential ultimate reduction of production of the reservoir. To minimize this effect, a fully self-degrading particulate derived from a natural polylactide polymer (PLA) was used to control the natural fissure interactions and subsequently minimize fluid loss during the induced hydraulic fracturing operation. Since the fully self-degrading particulate-derived PLA technology can control fluid loss into naturally fractured reservoirs while ultimately keeping clean and open fractures without losses in permeability post-induced frac operation, the paper documents the use of three fixed numbers of PLA slugs, pumped ahead of a fracturing stimulation alternating among 1) biodegradable particulates, 2) mixing in defined proportions of 100-mesh proppant particulates, and 3) biodegradable particulates, to allow temporarily plugging the natural fracture spaces without conductivity loss when the fracturing operation is complete. Author informs that the 3 steps of slugs can be reaped with the same fluids anytime that magnitude of Natural Fissures "NF" shows as high density and dips, it is possible increase and or decrease the PLA and natural sand concentrations and volume. The biodegradable particulates completely degrade within a few hours and subsequently leave the natural fracture with fully open, clean pathways for optimum hydrocarbon production potential.

Even with the current development of unconventional reservoirs in the United States, where tens of thousands of wells have been drilled and completed, there is not enough understanding of the production and successful completion drivers in unconventional plays. The Marcellus shale is a naturally fractured formation, and it is vital to account for the natural fractures during a simulation study. A discrete fracture network (DFN) model and a 3D mechanical earth model (3D MEM) were created and used to determine the complexity of the hydraulic fracture geometry. The microseismic data obtained during the hydraulic fracture simulations served to constrain the hydraulic fracture footprint. The proposed workflow uses unconventional fracture modeling (UFM) to predict the propagation of complex hydraulic fracture networks with pre-existing natural fractures and model the stress shadow effect and the lamination effect considering different proppant placement by type within the fracture. Propped and unpropped fracture half-lengths obtained during history matching provide calibration for the UFM. Based on the calibrated model, an analysis of the current perforation efficiency was performed, which showed that almost half of the perforations do not contribute to the production. Optimization of well spacing and cluster spacing was performed on a two-well pad to account for well interference such as fracture hits, stress shadow, and depletion after 30 years of production. The recommended well spacing and completion design improved production by up to 20% per well compared to the initial development plan. The complex approach is becoming a new norm for the successful development of unconventional reservoirs because simple analytical models cannot address well interference issues and account for heterogeneity in the rock properties. The presented workflow can be consistently applied to evaluate well spacing and interference in time for the subsequent wells completed in the Marcellus to help achieve maximum recovery.

The Keshen gas formation is located in the Tarim basin, western China, characterized with developed heterogeneous natural fractures, with most prospective tight gas opportunities. Though high initial gas production rate is commonly achieved, a rapid decline sometimes occurs during the long-term gas production when an unsuitable drawdown pressure is applied. This paper presents studies of the stress-dependent permeability of the core samples from the ultra-deep, naturally fractured tight gas reservoir in the Tarim basin, China and investigates its impact on the long-term gas recovery. In this work, tight sandstone samples with different morphology of natural fractures were obtained from three exploration wells in the Tarim Basin. Permeability was measured using the pulse decay method by increasing the effective stress from 600psi to 6500psi, in steps of 1000psi, and repeating the same procedure in the reverse order. In addition, a numerical simulation model was established and validated by fitting the results of the experimental data to study the effect of natural fracture dip on the stress-dependent permeability. Different permeability decline characteristics were observed for tight sandstone samples with different dominant flow channels (i.e., matrix or natural fractures). Due to the existence of natural fractures in the tight reservoir, the stress dependency and hysteresis of permeability is larger. Specifically, the hysteresis of stress dependent permeability is the largest if a natural fracture is through the whole sample and vertical to the end faces. Moreover, for the samples studied in this work, the permeability declines more as the effective stress reaches 3000psi if the natural fracture dip is large compared to that of the samples with a smaller natural fracture dip. Furthermore, a control strategy was proposed to address the stress sensitivity of permeability through the numerical simulation results. Interpreting the permeability decline characteristics provides insights of the gas production behavior from tight sandstone reservoir while proper reservoir pressure needs to be maintained to mitigate the sharp production decline and enhance the ultimate gas recovery for the tight reservoirs with developed natural fractures.

For the multi-stage fracturing in horizontal shale gas well, the stimulated reservoir volume (SRV) is a pivotal parameter to determine the fracturing performance. However, SRV estimation remains a longstanding challenge in shale gas reservoir due to its complex forming mechanism, most of the current SRV estimation methods are either expensive or time-consuming. In this paper, a 3D mathematical model of SRV is established by simulating the four key processes—multiple hydraulic fractures propagation, reservoir pressure lifting, formation stress variation and natural fractures failure—during each fracturing stage in shale gas reservoir. This model considers the interference effect of multiple fractures, and subdivides the SRV into shear-SRV and tensile-SRV according to the failure type of natural fractures network. In order to validate the feasibility and reliability of the model, it was first implemented to a pilot well in the FL gas field in southwest China to estimate a SRV that matches well with the microseismic signals monitored onsite. Then, this model was applied to FL gas field on a large scale, the application results show that although most horizontal wells have been effectively fractured with desired SRV, there are still unstimulated regions left between neighboring wells, so it needs to drill infill wells in current well pattern and reduce the well spacing in the future. This research explores an efficient method to estimate the SRV without high cost or complicated process, provides the theoretical basis and guidelines for pre-fracturing design and post-fracturing evaluation in shale gas reservoir.

Microseismic monitoring technology is widely used to characterize the fracture network and provide enough information on fracture geometry and properties. We go beyond the existing method that uses planar fractures or orthogonal conjugate fractures for representing the fracture network. Our novel method of characterization involves an integrated workflow to utilize L-system based fractal geometry to describe fracture propagation pattern, density and network connectivity. Integer programming is incorporated into matching the origination points of the microseismic events during the fracture geometry matching procession. Furthermore, multilevel of the fractal fracture network model (FFNM) is calibrated by using genetic algorithm to help specifying the properties of fracture network. The additional rate transient analysis allows to interpret the relationship between well performance and complex fracture network features. The application of this workflow on unconventional shale gas start with calculating fractal fracture network geometry and determining fracture length for both hydraulic fracture and induced fracture. And also estimating stimulated reservoir volume (SRV) and fracture parameters with combination of production data. Field case study is presented for fractured horizontal well, the matching result shows that the fracture propagation path has a good fitness with microseismic event. We also carry out rate transient analysis to interpreting the performance of complex fracture network parameters. This indicates that only connected stimulated fractures does most of the contribution to gas production. The better connectivity of multi-level fracture network, the better performance of fractured well during long time development. Besides, the most significant new finding is that SRV increases as fractal fracture induced levels increase, and this relationship appears to be fracture geometry-dependent. The novelty of this new method is expected to become a more efficient process for accurate characterization of shale reservoir complex fracture network and improvement hydraulic fracture optimization.

The Lucaogou formation in Junggar basin is the most potential tight oil reservoir in China. However, the disappointing production of a pilot appraisal project with 10 horizontal wells adopting multistage fracturing hold back the further development. The multiple laminated sand-shale formation with horizontal beddings severely affect the fracture height and geometry. This paper provides comprehensive large-scale-block fracturing experiments and field microseismic monitoring data to examine the effect of the highly laminated rock fabric on fracture geometry. Hydraulic fracturing polyaxial tests were conducted using large-scale Lucaogou tight oil outcrops simulating a vertical well and horizontal well respectively. Cross-linked gel and slickwater were used to examine the effect of fluid viscosity on fracture propagation. Fracturing pressure analysis, acoustic emission monitoring, rock splitting and tracing the dyed fluid were combined to investigate the hydraulic fracture geometry and propagation mechanism. Field microseismic monitoring results along with the wellbore trajectory, stress profiles and formation characterization were also analyzed. Large-scale-block fracturing tests show that the treatment pressure in the fracture is increasing steady, which represent the severe fracture containment or high process-zone stress, both are indication of bad stimulation potential. Rock splitting and acoustic emission mapping results proved that fracture initiated and propagated along the horizontal bedding. And the rock heterogeneity and natural fracture play a decisive role in fracture propagation. Field microseismic monitoring results also indicate that the monitoring fracture geometry is much more complicated than predicted. The microseismic mapping shows that fracture propagates downward when the stimulated interval was drilled below the target layer and propagate upward or confined in the pay zone when the interval was drilled above the target layer. Both laboratory and field results suggest that the hydraulic fracture of Luchaogou tight oil reservoir is almost determined both by the landing place in the formation and the natural fractures. Bedding-parallel stimulation would hinder fracture height and more complexity might be observed in a microseismic cloud, but it would probably not beneficial for production. Moreover, when we start flow back and the weight of the overburden is realized, the bedding planes being propped open could lose conductivity because of embedment and proppant pack collapsed. The identification of the target layer in the centimeter-level laminated Luchaogou tight oil formation was challenging and the multiple horizontal beddings severely confined and hinder the fracture propagating vertically, even though larger fluid and proppant volume were injected at higher rate. Well trajectory, natural fracture identification and its direction and layer heterogeneity are the major concerns when stimulated highly laminated formation, which is a typical characteristic of China's tight oil reservoirs.

The Surat Basin Coal Seam Gas (CSG) is maturing from exploration to production to meet sales targets for several Liquefied Natural Gas projects. This requires effective and predictable reservoir performance that is controlled by permeability, gas saturation and matching the well completion technique to the ground conditions. Permeability in coal has major dependence on in-situ stress and natural fractures, and these will have characteristics that vary from field scale to larger regional scale faults and folds. This study investigates the spatial and stratigraphic variability of stress and fracture orientation relative to measured permeability within the Walloon Subgroup (WSG) that hosts CSG resources within the Surat Basin. Open file wireline data from 33 vertical wells across the eastern part of the Surat Basin are used to calculate the in-situ stress orientation and fracture distributions within the WSG. Present day in-situ stress orientations were identified from the borehole breakout and drilling induced tensile fractures. Permeability data from 13 wells are compared using the in-situ stress and fracture data from image log interpretation. CSG reservoir permeability is, in general sensitive to the changes in effective stress and primary permeability is reduced exponentially with increasing effective vertical stress. However, this relationship does not always hold true. Permeability within the WSG is also affected by the angle between present day in-situ stress orientation and fracture or joint trends and fracture dip angle. Wells in the relatively simple structural areas with subtle faulting show higher permeability when the coal fracture trends are parallel and up to 40 degrees to the present day in-situ stress. Permeability is significantly less outside this range. Most of the high permeability zones tend to occur in the areas where there is significant rotation of in-situ stress from the regional mean stress orientation (commonly ENE – WSW). The observed stress rotation is attributed to the stress perturbations mainly from folds and faults within the Surat sedimentary succession, suggesting local structural influence on the permeability distribution within the WSG. Few analyses of permeability versus stress and fracture properties are in the public domain for the Surat Basin. This study illustrates the connection between different structural domains, stress and fractures in previously unidentified areas of oblique-slip faulting, in some cases reactivating and in others creating new features from basement through the Jurassic to Tertiary succession.

Keshen gas field, located on the northern margin of the Tarim basin, Western China, is an unconventional sandstone tight gas reservoir with extreme reservoir conditions: ultra-deep, low porosity, low matrix permeability, high temperature and high pore pressure. In order to gain economic production most wells should be stimulated to enhance single well performance. Previous studies show that natural fractures (NF) play the most important role on productivity. Detailed studies on block KS2 found that well performance is controlled by the intersection angle ( θ ) between NF strike and direction of the maximum horizontal stress. When the interaction angle is small, well productivity is good. Otherwise, well productivity is poor. Based on this conclusion, different simulation options were proposed: 1) Acid hydraulic fracturing for wells with small angle, and 2) Proppant hydraulic fracturing for wells with big angle. New problems were meet when we applied this rule to other blocks, such as block KS8. In this block most wells reached a good production even if the intersection angle is big (>40°). Therefore, it is unreasonable to determine stimulation options based on the intersection angle for these wells. In order to establish alternative stimulation options, deeper analyze focused on natural fractures has been conducted. First, the tectonic history was studied to understand the NF creation and it was found that natural fractures are associated with two main tectonic phases. Most of the natural fractures developed during the earliest phase are infilled by calcite or shale(set 1), Whereas NFs developed during the last phase are open or partially open, have high permeability and are contributing to the production(set 2). Wells with reticular NFs have two sets of NFs and have high production. Advanced analyses of borehole images, including fracture classification according to the tectonic events, fracture density, and intersection angle computation, allowed us to create four main classes: class 1 : presence of reticular fractures, class 2 : parallel fractures with small intersection angle, class 3 : parallel fractures with big intersection angle, and class 4 : no natural fractures. New stimulation options were proposed based on these four classes: class 1 : acidizing without hydraulic fracturing, class 2 : acid hydraulic fracturing, class 3 : proppant hydraulic fracturing, and class 4 : it is hard to get economic production for these wells, even if the proppant hydraulic fracturing is operated. These new stimulation options have been applied in new blocks of Keshen tight gas field and provide a practical way to optimize the stimulation, to ensure well performance, and to reduce the cost associated with multiple stimulation phases in this tight gas field.

Tahe Naturally Fractured Carbonate Reservoir has implemented nitrogen gas flooding since 2013, with daily oil production of 7580 bbls and oil recovery increment of 0.83% by the end of 2015. However, the presence of fractures significantly affects gas swept volume and production performance, so large amount of oil reserves is poorly flooded due to gas channeling through fractures. The fluid flow mechanisms in fractured models were discussed in order to improve field gas flooding efficiency. Based on the geological constrains of Tahe Oilfield, fractured models with different apertures were fabricated using acrylic glass to model carbonate matrix wettability and for a better observation on fluid flow behavior. The models were placed vertically and horizontally to simulate the high-angle and low-angle fractures in the formation. Gas displacing oil experiments were performed at different injection velocities. The oil displacement characteristics were depicted and the production performance was recorded and discussed. Experimental data were history matched through numerical simulation, and thus a sensitivity study was conducted via design of experiments. For downward gas injection in the high-angle fractured model with a given aperture, a critical injection velocity was obtained below which piston-like displacement was observed. Channeling factor was defined to characterize the injected gas channeling features. It gradually increased and reached its maximum value with increasing injection velocities. The relationship between channeling factor and injection velocity was well fitted by Langmuir equation, and the mechanism behind it was elucidated. Based on their relationship, three gas/oil flow regions were illustrated including non-channeling, transitional channeling, and stable channeling. For all fractured models, the critical injection velocity increased and the maximum channeling factor declined with the increase of fracture aperture. A standard curve was plotted, which enables us to determine different flow regions according to the fracture aperture and injection velocity. For oil displacement in the low-angle fractured models, the top part was flooded at a specific range of injection velocity. Gravity effect was weakened and the middle part was flooded at relatively high injection velocities. Numerical fractured models were built and thus calibrated by history matching all the experimental data at different fracture apertures and injection velocities. A sensitivity study was conducted and the weighting of different variables was emphasized via DOE. Previous studies were mostly focused on gas flooding efficiency in naturally fractured carbonate reservoirs; however, this study visually depicted the gas-oil flow behavior through lab experiments, and demonstrated the weighting of different variables via numerical simulation using DOE. This paper could provide an insight into field gas injection projects and the development of the commercial numerical simulator that is specialized for naturally fractured carbonate reservoirs.

In traditional Discrete Fracture Network (DFN) method for fractured porous media simulation, fractures are modelled in different scales and orientations using single computational grid. However, a large number of small grids near both ends of fracture are generated, which substantially reduce the computation efficiency. In this paper, a new line fracture approach is presented to avoid generation of small grids. Combined with Multi-Point Flux Approximation (MPFA) algorithm, the simulation efficiency is highly improved without losing accuracy. We present a modified mesh generation algorithm in which the volume of large fractures is set zero by neglecting the fracture width. The fracture aperture (very short line) is treated as single node during mesh generation using the paving method. Therefore, the number of small grids around the fracture is significantly decreased. In this paper, a quadrilateral unstructured grid system is generated using the proposed paving method. Then, by taking the median dual of quadrilateral mesh as the control volume, all fracture properties such as the aperture and permeability are accounted for as independent parameters in discrete fractures. The governing equations of DFN model are derived and solved using MPFA algorithm for oil-water two-phase flow. A new discrete fracture network model using line fracture approach is developed. To show the efficiency and accuracy of the new model, the proposed method is applied to a case study of two separated and two crossed fractures, in the computation domain with the scale of 50 by 50 meters. Compared with the standard DFN model including the width of fractures, the computation efficiency of the new model is highly improved (by 2.5 times), due to the large reduction of grid numbers (20%). Good agreement in water and oil saturation distributions resulted from the two models validates the newly developed method. Simulation of naturally fractured reservoirs has been a challenge for decades. Discrete fracture network modelling is a promising approach. However, without an efficient grid generation method, DFN model is not feasible and practical due to the large amount of computational time. The novelty of the present work is the improved model using line fracture approach. The new grid generation algorithm is coupled with multi-point flux approximation approach for flow simulation in fracture network system. High efficiency and accuracy of the developed method is readily applied to fractured reservoir simulation. Sponsored by NSFC (Natural Science Fund of China - "the numerical simulation of natural fractured reservoir based on the unstructured hexahedral grid system and concurrent computation") (No. 51474179)