bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fracture Complexity: Analysis Methodology and Signature Pressure Behavior of Hydraulic Fracture Propagation from Horizontal Wellbores
Authors: Bazan Lucas W. , Meyer Bruce R. 
Published: November 2015

AbstractDuring hydraulic fracture propagation three regions may be identified from the pressure response referred to as: 1) near-well, that extends tens of inches, 2) mid-field, that extends tens of feet and 3) far-field, that extends hundreds of feet from the wellbore. Each region can experience simple, tortuous, and complex fracture behavior creating unique pressure signatures. It has been observed that complex fractures with extended fracture storage can result from hydraulic fracture stimulation in highly deviated and horizontal wells. Complexity is created as a result of induced hydraulic fractures turning and twisting as they exit the wellbore in the near-well region, propagating into the mid-field region, and then re-orienting in the direction of principal stresses in the far-field. This results in anomalously high apparent net pressures as evident by increased ISIP's and rapidly declining pressures that dissipate minutes after shut-in.This paper presents minifrac and post-job pressure matching case studies that identify and describe mid-field fracture complexity (MFC), or extended wellbore pressure storage. The pressure behavior supports complex fracture propagation, high fracturing pressures and pressure fall-off responses typically observed in horizontal shale wells. High apparent fracturing stress gradients are often seen that are much greater than the over-burden stress-gradients. Although suggestive, these high stress gradients are not indicative of horizontal fractures in the far-field. Uncharacteristically high MFC is also not necessarily related to fracture complexity in the far-field. A methodology is presented that identifies the "actual" ISIP which allows for in-situ stress calibration, true net pressure identification, proper minifrac interpretation and an improved fracture treatment design.Rapidly declining pressure during a shut-in as a result of MFC resembles pressure dependent fluid loss and often is misinterpreted as such. However, the pressure response is a result of extended fracture storage and energy dissipation in the mid-field region, which can result in multiple closure signatures. Multiple closure events are indicative of complex fracture network behavior as a result of stress anisotropy and creation of multiple non-planar fractures in the mid-field region. Additionally, hydraulically induced secondary fractures perpendicular to the maximum horizontal stress can provide insight into stress anisotropy. Identifying and incorporating MFC into pressure interpretation analyses will enhance fracture treatment design and post-job pressure matching providing a systematic methodology for designing and analyzing horizontal shale fracture treatments. Information regarding MFC is critical in interpreting fracture treatment pressure responses and optimizing fracture treatment designs in horizontal wells, including well spacing and fracture interference.
Anisotropic Wellbore Stability Model for Transversely Isotropic Formation and Its Application in Drilling Through Shale Formation
Authors: Lu Y. H. , Chen M.. , Jin Y.. , Chen G.. , Lin B. T. , Liang C.. , Ji J. X. 
Published: November 2015

Abstract
Severe borehole collapse has occurred during extended reach drillingsin shale formations of Dongping Block, Qinghai Oil-field. An extreme difficulty is to choose mud weight lower bounds properly. Previous isotropic wellbore stability model does not consider the heterogeneities in transversely isotropic porous media like shale, thus fails to predict mud weight accurately. To solve the problem, a new wellbore stability modelis proposed; and an optimized nano-type drilling fluid is designed.whichcan be applied fordrilling operation.
The wellbore stability modelis developed through four steps: 1. The far-field stressesare transformed from an in-situ stress coordinate system to a borehole coordinate system; 2. An analytical solution for a near-borehole stress distribution in an elastic anisotropic formation under a transformed in-situ stresses regime is used, based on the complex-variable elasticity theory and the Biot's consolidation theory; 3. The around-borehole stressesare transformed from the borehole coordinate system to a weak-plane coordinate system; 4. An improved Mohr-Coulomb failure criterion is used to identify rock failure mode (along weak plane or through rock matrix) and to calculate the mud weight lower bound.
In addition, laboratory experimensts have demonstrated the ability for water-soluble hybrid nano-particles to plug shale matrix and micro cracks inside the shale, which helps to prevent chemical erosion of fluid to the rock. By sealing natural fractures with nanoparticles and optimizing mud weight using the new wellbore stability model, the borehole instability is effectively controlled. A procedure is also developed for wellbore stability analyses based on a comprehensive consideration of the formation property, the mud chemical property and the mud weight. This approach was applied to 12 deviated pilot wells drilled through shale formation in Dongping Block, where high pore pressure and natural fracture systems prevail: the mud weight is increased from previous 1.5g/cm3 to the present 1.85g/cm3. It is observed that the drilling time and the drilling complexities have been reduced by up to 52.4% and 62.4%, respectively, with significant cost savings.
The Application of Mud Weight Optimization Method in Fractured Tight Sandstone Formation
Authors: Liu M.. , Jin Y.. , Lu Y. H. , Chen M.. , Hou B.. , Yang S.. , Wen X.. , Chen Y.. 
Published: November 2015

Abstract
Fractured tight sandstone formation is an important unconventional oil and gas accumulation distributed in a wide region of Tarim oilfield in China at great depth, and has several distinct features: high-pressure/high- temperature drilling environment, low rock matrix permeability, well-developed natural fracture system, and highly anisotropic in-situ stress. Even using highly inhibitive oil-based fluid during drilling operation, mud loss and wellbore collapse still occurred frequently. Moreover, in many wells when the mud weight is added, borehole conditions become not better but worse. Contrary to the traditional field experiences, collapse pressure itself has a mud weight window.
According to the field observations and literature reviews, we built a model based on the poroelastic theory, coordinate transformation technique and temperature field simulation. We found that classical Mud Weight Window is no longer being appropriate for wellbore analysis in fractured tight sandstone foremation. Instead, a Crtical Mud Weight Window is proposed, which properly explained unusual drilling problems.
A mud weight optimization strategy is also discussed to minimize the shear failure region around a borehole. In addition, a flow chart including the experimental equipments and calculating method is presented.This approach is applied to explain the drilling problems in 8 vertical wells drilled through Bashijiqike formation. It is observed that the new method may provide more accurate instructions for mud weight selection.
Finally, we presented a field case study in Keshen block, Tarim field. In this case, the engineers used our method to choose the mud weight. As a result, this model offers reasonable mud weight that is useful to mitigate borehole instability in fractured tight sandstone formation.
Novel Well Test Design for the Evaluation of Complete Well Permeability and Productivity for CSG Wells in the Surat Basin
Authors: Bottomley W.. , Schouten J.. , McDonald E.. , Cooney T.. 
Published: November 2015

Abstract
The Surat Basin Coal Seam Gas (CSG) play requires a vast number of wells to develop, and reservoir productivity changes quickly over small distances. Well testing provides a means to evaluate these changes. But, the high cost of conventional testing precludes sufficient tests to ensure areal and statistical coverage across a large well stock. This paper discusses a new approach whose reduced cost allows five times more wells to be tested than conventional methods. By testing more wells, there is more data for subsurface model calibration and productivity fairways can be better mapped and developed.
In the Surat Basin CSG play there is an industry-wide completion technique that uses air to lift every well to size the initial downhole pump for dewatering. This paper describes an enhancement to this standard pump sizing test which facilitates the provision of key reservoir information: full well permeability, skin and productivity. This novel well test is termed an Air Assisted Flow Test (AAFT).
During the AAFT the well is produced at a predictable drawdown for up to an hour whilst accurate rate measurements are made at surface. A downhole shut-in is then performed and a pressure gauge measures the build-up pressure response. The additional equipment and rig time have been designed to add a minimal cost to the standard completion operation and test cost is 20% of a traditional Drill Stem Test (DST).
Field tests using the AAFT and multiple dual packer DST's in the same well clearly demonstrate that both testing methodologies deliver the same results. It is therefore valid to incorporate the AAFT into the extensive permeability database for the Surat Basin. Additionally drawdown dependent skin has been observed in data from the new AAFT. This phenomenon is interpreted to be the result of stress dependent coal fracture permeability in the near well bore region.
This new testing method is only directly relevant to CSG developments. However the awareness to gather additional data, from enhancing a standard operation, is applicable to all unconventional and conventional reservoirs.
Application of UDM-2 Drilling Fluid Technology in the Development of Upper-Deep Oil and Gas Resources in Tarim Basin
Authors: Zhu Jinzhi , Li Long , Li Lei , Zhang Zhen , Cheng Rongchao , Zhang Jie , Liu Xiao , Li Jiaxue 
Published: November 2015

Abstract
The oil-gas exploitation techniques of the piedmont tectonic formation of Tarim Basin are facing a great challenge. Due to the ultra-high temperature (up to 180 °C), high pressure (mud weight up to 2.6 s.g.), ultra-thick composite gypsum-salt formations (thickness up to 4137 m), high pressure brine layer, significant non-productive time (NPT) and low rate of penetration (ROP) are encountered in dealing with borehole instability, stuck pipe, high pressure brine influx and downhole losses. To meet the need of drilling operation in the piedmont tectonic formation, a kind of high-temperature high density oil-based drilling fluid system known as UDM-2 drilling fluid system is developed.
UDM-2 drilling fluid system has excellent comprehensive properties, and it could resolve the contradiction between safety drilling of complicated deep wells and formation complexity. UDM-2 drilling fluid system has been recommended to run for about 60 wells in this block, resulting in very good results.
Three sets of plugging technology for oil-based drilling fluids are applied successfully in the gypsum-salt formations or pay zones, and the total volume of loss of UDM-2 drilling fluids to the formation is significantly reduced from the beginning of the project, so the drilling time and cost can be saved remarkably.
The large-scale application of UDM-2 drilling fluid technology has brought great economic and social benefits, and provides a strong technical support for efficient production and development of upper-deep oil and gas resources in Tarim Basin.
Quick Tricks, Tips, Analytical Methods and Other Proxy Tools for the Unconventional Reservoir Engineer
Authors: Jordan Colin Lyle 
Published: November 2015

Abstract
The unconventional reservoir engineer is required to evaluate increasingly complex data. In additional to the rapid advancement of technology used to complete and stimulate unconventional resources, there has been a proliferation of type curve procedures (i.e. pressure and rate transient analysis), decline techniques, and reservoir modelling strategies in the literature. Specific challenges are the analysis of single and multi-phase flow form hydraulically stimulated horizontal and multi-lateral wells. Although state of the art simulation techniques can be used to model any complex reservoir and well architecture, restrictions on data quality, project schedules, and budgets do not always allow for detailed simulation and analysis. Furthermore, initialization of the numerical model often requires some form of analytical modelling as a precursor to the larger model.
However, complex scenarios production analysis or forecasting of horizontal wells, dual and tri-laterals, fracture horizontals as well heterogeneous reservoirs can be simplified by using an proxy model which is accurate (if not exact) with respect to long-term deliverability and resource/reserve estimation. Complex wells and reservoirs can be modelled and analyzed by using a simple homogenous reservoir with effective permeability, skin, and wellbore radius combinations. Examples will demonstrate this procedure would allow for the use of simple analytical software tools in lieu of simulation, or the generation of reliable forecasts in the absence of completion/reservoir data
Saudi Arabia's Emerging Unconventional Carbonate Shale Resources: Moving to Horizontals with an Integrated Engineering and Geosciences Approach
Authors: Al-Mulhim N. I. , Korosa M.. , Ahmed A.. , Hakami A.. , Sadykov A.. , Baki S.. , Asiri K. S. , Al Ruwaished Azmi 
Published: November 2015

Abstract
Unconventional resources in Saudi Arabia symbolize an opportunity to extend required gas plateaus in the long term, to substitute gas for liquid fuels, and to provide potential feedstock for the growing chemical industry. This paper aims to outline an integrated completion engineering and geosciences approach that was applied in the Jafurah shale gas play. The goal was to address complex unconventional reservoirs and their associated challenges, and to determine the optimum completion and fracture design.
Sweet spot identification within the Jurassic Tuwaiq Mountain Formation in the Jafurah basin represents a major challenge as it requires a large number of wells drilled over a wide geographical area with high associated costs. This requires innovative drilling, completion and stimulation practices. In order to identify and maximize potential frac stages and placements, a comprehensive study was completed using an advanced workflow encompassing drilling, geophysics, geomechanics, reservoir characterization, completion and fracturing and microseismic monitoring.
The targeted Jurassic Tuwaiq Mountain rocks are calcareous and interpreted to have been deposited in a restricted marine environment within an intra-shelf basin. This shale carbonate play shows a high Total Organic Content (TOC), low clay content, good matrix permeability, high gas saturation and high effective porosity. Scanning Electron microscope (SEM) images exhibit a dominant presence of organic porosity associated with the kerogen. Initial results from vertical wells drilled in the Jafurah basin proved that proppant fracturing can be successfully placed, and indicated the presence of a potential gas rich play within the same source rock. Subsequent horizontal wells were the first liquid rich/gas carbonate horizontal wells with ultra-low shale permeability in Saudi Arabia. The first horizontal wells had excellent gas production with significant amounts of condensate.
By further building on experience from the drilled and stimulated wells, the lessons learned provide a foundation for the completion of future unconventional gas wells in the Jafurah basin.
Study of Pore Structure of Gas Shale with Low-Field NMR: Examples from the Longmaxi Formation, Southern Sichuan Basin, China
Authors: Chen Yulin , Zhang Liehui , Li Jianchao 
Published: November 2015

Abstract
Pore structure of gas shale which possesses lots of nanopores is complex. NMR measurement can not only obtain accurate sample parameters but also provide an approach to quantitatively study pore structure. This paper Integrates NMR, mercury injection, nitrogen adsorption and X-ray diffraction to analyze the relationships of pore structure, surface to volume ratio and mineral components.
Both nitrogen adsorption and mercury-injection have some limitations in characterizating of pore structure of gas shale. In this paper we integrate pore size distribution curve of nitrogen adsorption and mercury-injection. Comparison and analyses of NMR T2 spectra and the integrated pore size distribution curve calculate NMR pore size distribution. Capillary pressure curve is constructed based on NMR T2 spectra for quantitatively studying pore structure of gas shale. The diagrams of relationship between characteristic parameters of pore structure, surface to volume ratio and mineral components such as clay minerals, pyrite and TOC are established.
NMR study has been implemented on 15 samples from Longmaxi formation. The results show the porosity range from 2.24% to 5.76%. The NMR pore size distribution curves is more precise than the curves that calculated only according to nitrogen adsorption or mercury-injection. Calculating separation coefficient, skewness, structure coefficient, median pressure and other parameters from constructed capillary pressure curves indicate high threshold pressure, poor connectivity, and complex pore size distribution. Porosity has a positive correlation with clay mineral content, TOC, pyrite. Most of surface to volume ratio and pore volume are provided by micropores and mesopores.
Using integration pore size distribution curve of nitrogen adsorption and mercury-injection to calculate parameter of NMR pore size distribution is a more exact approach than only using nitrogen adsorption or mercury-injection. Capillary pressure curve constructed by NMR T2 spectra can provide information of micropores and mesopores which mercury-injection cannot correctly characterize.
Evaluating Dynamic Behaviour of a Complex In-Situ Gas Composition From a Coal Seam Reservoir - A Case Study From Fairview Early Permian Cattle Creek Coals
Authors: Falcon G. E. 
Published: November 2015

Abstract
Early Permian Cattle Creek Coals in Fairview Field in Queensland Australia is an insitu multicomponent Coal Seam Gas Reservoir. The Early Permian East coals or Springwater play typically occur at depths between 1,100 m to 1,800 m. These medium volatile bituminous coals are characterized as having lower permeability (&lt;5 mD), a high gas content (10 – 15 m3/t daf), an elevated concentration of ethane and heavier hydrocarbon components (2 – 14% C2+), and higher inerts concentration (0.2 – 12% CO2, &lt; 3% N2) than found in many CSG fields. .
An analysis and history match of the production data from existing appraisal wells with a particular emphasis on the produced gas composition and its variation with depletion was performed using both an in-house compositional simulator which used the extended Langmuir Isotherm as the basis for the equilibrium relationship between the free and the sorbed gas phase and a commercial compositional simulator. Methane, Carbon Dioxide, Ethane, Propane and Nitrogen were simulated during this study.
The results showed potential differences between the produced gas composition obtained during well production (considering the adsorption/desorption behavior of a multicomponent gas in a coal seam reservoir) and the in-situ gas composition determined from gas sampling during desorption tests. Heating value profiles were generated and compared illustrating the potential impact of the reservoir dynamic behaviour.
The results also showed how the produced concentration of N2 (free gas phase) can be 4 to 7 times higher than its insitu concentration and that a variation of up to 75% of the initial concentration in free gas phase of CO2 and C2H6 concentration is possible due to the variability of the isotherms indicated from core.
Causes of and Responses to Abnormal Fracture Pressure on Ultra-Deep Shale in Southern China
Authors: Shan Qinglin , Jin Yan , Chen Mian , Yang Shuai , Zhang Xudong , Wu Jun , Huang Jianyi 
Published: November 2015

Abstract
Shale gas development by hydraulic fracturing in Southern China highlights the features of high fracture pressure and of serious difficulties in proppant placement due to deep burial (over 4000 m). This scenario differs from that in North America.
To solve the problems described above, conventional triaxial tests were conducted on the properties of rock mechanics under a simulated high temperature and high pressure reservoir environment. A full-size 3-D finite element method (FEM) is used to predict the fracture pressure of deep shale formation, taking both the rock deformation behavior of ultra-deep shale and the influence of fracturing fluid filtration into account. Effective engineering approaches are also presented that focus on reducing the friction of fracturing fluid and on the efficiency of acid pretreatment.
The triaxial compressive test results indicate that under the condition of high temperature and increasing confining pressure, the plasticity of the rock is strengthened and the nonlinear characteristic will inhibit fracture initiation. The correctness and reliability of the FEM model are confirmed through a comparison of the FEM model calculation result with the field data. Moreover, preliminary proposals are made for perforation parameter optimization based on this model. An optimal perforation phase angle of 60° and a perforation density of 18 perforations/m are considered appropriate parameters. A long perforation tunnel (more than 1 m) mitigates the state that the majority of the perforation component endures pressure stress. Finally, both laboratory test and field application results show that a refined slick water system design can generate a friction reducing rate of no less than 75% and that a new acid system can lower pressure by 10–15 MPa before fracturing. As a result, fracture pressure is reduced.
This work presents a method of addressing the challenges arising from the abnormal hydraulic fracture pressure on ultra-deep shale, including the causes determined during laboratory tests and the treatments generalized from FEM results and engineering approaches. These solutions are a necessary step toward reducing fracture pressure in deep shale gas development.