ORCID Profile
0000-0002-9018-774X
Current Organisation
University of New South Wales
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Publisher: Elsevier BV
Date: 10-2000
Publisher: American Society of Civil Engineers (ASCE)
Date: 08-2013
Publisher: Wiley
Date: 2002
DOI: 10.1002/NAG.208
Publisher: SPE
Date: 09-11-2015
DOI: 10.2118/176920-MS
Abstract: Most shale plays have to be hydraulically fractured to acquire commercial production. Shales are typically characterised by varying quantities of clay, carbonate and organic material, therefore each shale type has different deformational properties, which lead to different outcomes with respect to hydraulic fracture efficiency. Unconsolidated, high clay content or organic rich shales exhibit visco-elastic or visco-plastic behaviour, acoording to many researchers[1–3]. Although the effect of this time-dependent behaviour on fracture propagation is considerable it has not yet received much attention. The aim of this paper is to address the time-dependent response of shale under hydraulic stimulation, more specifically, to monitor fracture parameters change and deformation at crack tip area depending on the lag time between stress and strain. In this paper, an innovative method to analyse time-dependent deformation of material at fracture tip and its effect on propagation of hydraulically induced fractures by incorporating visco-elastic behaviour is presented. To characterise fracture state, J integral is revised and implemented in the framework of finite element model. The fracture is treated explicitly with refined mesh around the crack tip in order to obtain detailed information in static state. During loading condition, visco-elasticity and visco-plasticity is not differentiated for practical purposes. The results show that under a centain hydraulic pressure a crack creeps rapidly and possibly propagates. It is shown that stress intensity factor and revised J integral has a rapid changing gradient at the beginning and becomes stable over time. The crack tends to be wider and shorter in creeping shale. Propagation process is hindered by viscous energy dissipation and successive cohesive force. In simulation the experimental data from US shale plays are used to study fracture propagation behaviour under viscoelastic behaviour. Results of this study allow industry gain a better understanding of deformational behaviour of shale when fracturing. The know-how derived from this study will assist planning effective stimulation program in the development of shale gas reservoirs.
Publisher: Elsevier BV
Date: 2021
Publisher: Elsevier BV
Date: 2017
Publisher: SPE
Date: 07-11-2016
DOI: 10.2118/183342-MS
Abstract: This paper presents a new and innovative approach for the estimation of relative permeability of porous fractured carbonate rocks. The presented method differs from previous studies in that the relative permeability estimation for three different systems that exists in fractured rocks is measured. Fracture, matrix, as well as fracture-matrix porous systems are all taking into account with laboratory measurements of relative permeability and capillary pressure. In this study, both steady and un-steady states are used for the estimation of relative permeability in addition to the produced water during drainage flooding. Fracture surface topography is imaged by the use of surface scanning technique to determine the asperities of the surface and their heights. Simulation based on Reynolds equation is considered when developing the mathematical formulation of multiphase flow simulation. The developed mathematical model based on the integration of Darcy, cubic law and Reynolds to account for the variation of different porosity systems. The results simulated numerically are in a good agreement with the laboratory.
Publisher: Oil Gas Scientific Research Project Institute
Date: 30-06-2021
Abstract: Dual porosity in sandstones is considered as a key parameter that controls hydrocarbon production. Understanding of distribution of secondary pores, might give some insights about the heterogeneity of the reservoir for a particular area and as a result can help to produce more oil applying more efficient well-planning and design techniques. The studied oilfield is located about 40 km offshore Brunei Darussalam. In order to find out mechanisms that could lead to the development of secondary pores number of studies was conducted including helium porosity measurements, Mercury Injection Capillary Pressure, Micro-CT images (µ-CT images), X-Ray Diffraction, Petrography analysis, Scanning Electron Microscopy with Energy Dispersive Spectroscopy and Focus Ion Beam Scanning Electron Microscopes. The results showed that effective porosity that was formed by secondary pores was caused by the erosion, fracturing, and dissolution of sedimentary grains, authigenic minerals that are a part of pore-filling cement, and authigenic replacive minerals.
Publisher: Society of Petroleum Engineers (SPE)
Date: 05-04-2016
DOI: 10.2118/174392-PA
Abstract: The water leakoff into the shale matrix during the hydraulic-fracture treatment has been a critical issue in determining fracture geometry. Furthermore, water leakoff also affects mechanical properties of the surrounding rock matrix which, in turn, affects fracture propagation. Conventional approaches for the prediction of leakoff were inadequate because several important phenomena are ignored. In this paper, several effects on water leakoff into shale matrix during shale-gas reservoir stimulation are considered. A simplified structure is used to depict the complex pore network in shale. Different interactive forces involved in water displacement considering the osmotic and capillary effects are taken into account in the mathematical formulation of the model. The proposed numerical model is used to study the water leakoff and the consequent pressure increase caused by gas entrapment. The potential influence of the increase in pore pressure on the generation of microfractures is also discussed. The simulation results show reasonable agreement with the previous studies, and indicate that the water leakoff greatly depends on composition and structure of shale matrix. Clay minerals, for ex le, are naturally prone to water invasion, and draw water faster than hydrophilic minerals and organic matter because of the osmotic effect. Furthermore, the invaded water significantly increases the pore pressure within the shale matrix because of gas entrapment, which leads to a strong nonlinear relationship between leakoff and the square root of time. An increase in pore pressure also results in a decrease in effective stress that leads to the generation of tension-induced microfractures in shale matrix. This study emphasizes the significance of osmotic and capillary effects as well as gas entrapment on hydraulic-fracturing treatment of shale-gas reservoirs. Moreover, the new leakoff model can be applied to assist the investigation of fracture-propagation behavior in a shale-gas reservoir.
Publisher: Elsevier BV
Date: 03-2020
Publisher: Elsevier BV
Date: 10-2000
Publisher: SPE
Date: 14-04-1997
DOI: 10.2118/38043-MS
Abstract: Stress tests in two fields in Central Australia revealed insitu horizontal stresses which are significantly higher than what would otherwise be expected assuming linear-elastic fracture mechanics. The state of insitu stresses in the two fields falls into a strike-slip fault regime. The stress regime in the region probably has a tectonic origin, similar to the Chimney Butte field in the Green River Basin, Wyoming where high insitu stresses arise from neo-tectonic activity. The high horizontal insitu stresses and stress anisotropy in the region may cause drilling induced shear fractures and therefore stress heterogeneity around the wellbore. Stress modelling shows that an existing natural or induced fracture prior to hydraulic fracturing, if permeable and aligned at a small angle with respect to the maximum horizontal stress, allows a hydraulic fracture to develop from its tip at a lower breakdown pressure. Such a hydraulic fracture, once initiated, would experience turning in order to align itself with the far-field minimum stress. It is postulated that pre-existing fractures and shear failures of the rock around wellbore during the breakdown stage increases the probability of near-wellbore tortuosity in the form of multiple fractures and fracture turning. Hydraulic fracturing is increasingly used to stimulate low permeability gas reservoirs in Australia, particularly in Central Australia. However, as in other regions of the world, hydraulic fracture treatments in Australia generally experience higher treating pressures than are otherwise predicted by models, particularly during proppant addition stages. Such abnormally high treating pressures often precede premature, near-wellbore screen-outs, generally reduce maximum allowable proppant concentrations, severely reducing the effectiveness of treatments. Previous studies have suggested that fracture width restrictions, in the near-wellbore region, is the major cause of these high treatment pressures. This phenomenon, more commonly called Near-Wellbore Tortuosity, is generally characterised by any complicated, tortuous pathways connecting wellbores with main fractures. The resulting 'bottle-necks' increases pressure drops, and restricts the passage of proppant into main fractures. Cleary et al. grouped Near-Wellbore Tortuosity into two categories:multiple fracturing and fracture reorientation. Multiple fracturing refers to the initiation and propagation of more than one hydraulic fracture from a single wellbore. Multiple fractures compete for opening space within the same region, such that the in idual fracture branches have widths reduced by a factor of (where N is the number of fracture branches) as compared with an idealised single fracture. While multiple fracturing occurs to varying degrees in all hydraulically fractured wells, it is more common in deviated and horizontal wells. Davidson et al. and Stadulis et al. describe case studies in which multiple fracturing were clearly the origin of the type of fracture treatment problems described above. P. 247^
Publisher: Elsevier BV
Date: 03-2018
Publisher: American Chemical Society (ACS)
Date: 09-08-2018
Publisher: Springer Science and Business Media LLC
Date: 06-2020
Publisher: American Association of Petroleum Geologists
Date: 2018
Publisher: Springer Science and Business Media LLC
Date: 08-02-2021
Publisher: Informa UK Limited
Date: 07-1992
Publisher: SPE
Date: 24-08-2016
DOI: 10.2118/181799-MS
Abstract: Unconventional gas reservoirs (shale gas, tight gas and coal bed methane) constitute a large percentage of natural gas supply. Hydraulic fracturing is commonly used to break-up rock matrix and connect natural fractures and cleats to create gas flow pathways. Application of hydraulic fracturing, however, poses several problems including extremely low matrix permeability and poor connectivity between matrix and fractures. Several studies have been made in field and in laboratory to open and interconnect these natural fractures and cleat system with cold fluid, results of which are found to be promising. In this paper we present a parametric design analysis as to the application of thermal stress (due to cold fluid injection) induced hydraulic fracture treatment. Propagation of natural fractures and cleats surrounding the induced hydraulic fracture by thermal induced stress is investigated in hydro-thermo-mechanical (THM) framework both numerically and experimentally to quantify the effect of thermal shock. Increase in fracture (natural fractures and cleats) aperture and propagation is modelled by cohesive zone method. Numerical results were validated by injecting cold liquid in 1 in diameter coal s le and changes in permeability were recorded. During the same time, the changes in aperture and length of cleat and fractures respectively were monitored by μ-CT. Numerical results show that as the cooling front due to invasion of cold fluid moves into the matrix, it facilitates initiation of cracks in planes of weakness and/ or causes the cleats and natural fractures to open and propagate some distance away from the hydraulic fracture surface. This phenomenon is more pronounced around crack tips due to severe thermal straining. It was also observed that SIF and J-integral of cracks are much higher than that without thermal effect. Thermal stress induced cleats and natural fracture propagation surrounding the treatment area extends the reach of the hydraulic fracture which otherwise could not have been connected. In this paper we present a quantitative analysis of the effect of thermal stress on fracture/ cleat propagation behaviour so that an improved understanding is gained with regard to the application of low temperature fracturing.
Publisher: Springer Science and Business Media LLC
Date: 2000
Publisher: SPE
Date: 20-04-1999
DOI: 10.2118/54360-MS
Abstract: Hydraulic fracturing is a widely used stimulation technique in the petroleum industry for enhanced hydrocarbon recovery from low permeable reservoirs. Technological advancements in directional drilling have led the petroleum industry to drill arbitrarily deviated wellbores for development of reservoirs, which otherwise could not be economically produced. Efficient prediction of fracture initiation pressure from such deviated wellbores is therefore essential for petroleum industries to undertake effective hydraulic fracture stimulation tasks. This paper presents a generic model for prediction of hydraulic fracture initiation pressure and the orientation and location of fractures on the wellbore wall. The generic model is finally ramified to develop criteria for initiation of longitudinal, transverse and T-shaped or H-shaped fractures, with and without perforations. Final form of fracture initiation criteria for specified cases presented in the paper can be used by engineers for prediction of fracture initiation pressure. However, the estimation of fracture initiation pressure for deviated wellbores is cumbersome requiring numerical iterations. For such cases, results are presented graphically in terms of non-dimensional parameters to cover various stress regimes and wellbore deviations. Thus, the charts presented in this paper will be a useful tool for prediction of fracture initiation pressure for given in-situ stresses and help engineers to minimize computational efforts. Results of this study suggest that horizontal wellbores under the normal faulting stress condition requires less pressure for fracture initiation compared to vertical wellbores. In general, there is an optimum deviation that requires minimum fracture initiation pressure for a given set of in-situ stresses. Longitudinal fractures usually initiate from wellbores which are aligned with one of the in-situ stresses. Under some specific stress conditions, transverse fractures may also initiate directly from the wellbore wall. Without appropriate pressure control, longitudinal fractures also, however, initiate at some elevated pressure during the propagation of transverse fractures. This introduces the so-called T-shaped or H-shaped fractures. Perforations at appropriate alignment usually contribute in fracture initiation at lowe pressure.
Publisher: SPE
Date: 07-09-1998
DOI: 10.2118/47789-MS
Abstract: Slips and tongs produce permanent marks on pipe body and tool joints. Such marks develop high stress concentration that reduces strength of pipes. The remaining strength of pipes often falls below the pipe stresses which can lead to tubular failure. Slim pipes are most susceptables to failure due to die- marks. In many instances, slim pipes are handled using double elevator system to reduce pipe failure. In this paper, results of a recent study of various die-mark related failures of drill pipes under different loading conditions, with particular emphasis on fatigue damage are presented. Stress concentration due to die-marks is characterised by finite element analyses as a function of mark sizes to cover various gripping systems available in the market. Then a methodology is presented for the prediction of failure due to cumulative fatigue damage. Effect of stress concentration arising from die-marks is taken into account in the analysis. Results of this study suggest that the effect of stress concentration on the cumulative fatigue damage may be significant depending on particular gripping system in use. In most cases, the fatigue life evaluation based on conventional assumption of smooth pipe surface is found to be very unsafe. Thus, a new approach is proposed in this paper for prediction of true safe life of marked drillpipes against fatigue failure. Fatigue damage results are presented in graphical forms. Calculation of cumulative fatigue damage of drillpipes used in a number of drilling events is then presented systematically in tabular form to assist drilling engineers in the evaluation of actual remaining fatigue life of drillpipes for the target drilling event using a particular gripping system. P. 125
Publisher: Elsevier BV
Date: 06-2004
Publisher: Informa UK Limited
Date: 05-2005
Publisher: Elsevier BV
Date: 02-2006
Publisher: Elsevier BV
Date: 09-1999
Publisher: Elsevier BV
Date: 09-2015
Publisher: Elsevier BV
Date: 05-2012
Publisher: Elsevier BV
Date: 10-1992
Publisher: ASME International
Date: 29-08-2003
DOI: 10.1115/1.1595111
Abstract: During drilling operations, the mud filtrate interacts with the pore fluid around the wellbore and changes pore pressure by capillary and chemical potential effects. Thus the change in pore pressure around borehole becomes time-dependent, particularly in extremely low permeability shaley formations. In this paper, the change in pore pressure due to capillary and chemical potential effects are investigated experimentally. Analytical models are also developed based on the experimental results. A wellbore stability analysis model incorporating the time-dependent change in pore pressure is applied to a vertical well in a shale formation under normal fault stress regime.
Publisher: Informa UK Limited
Date: 09-1992
Publisher: Elsevier BV
Date: 12-2021
Publisher: SAGE Publications
Date: 12-2014
DOI: 10.1260/0144-5987.32.6.943
Abstract: Geological storage of CO 2 is considered widely as an efficient method of mitigation of greenhouse gas emission. CO 2 storage mechanism includes structural trapping, residual gas trapping, solubility trapping and mineral trapping. The shale cap rock acts as a seal for the storage when CO 2 accumulates at the top of the reservoir. The injected CO 2 may migrate through the cap rock under buoyancy force or pressure build-up which depends on the seal capacity of the cap rock. As a result, the effectiveness of containment of injected CO 2 in the reservoir is largely dependent on the migration rate of CO 2 through the cap rock. This paper investigates the effects of CO 2 leakage through cap rock by a combination of experimental studies and numerical simulation. Firstly, experimental measurements on shale core s les collected from Australian cap rocks were conducted to determine properties, such as capillary pressure, pore size distribution and permeability. Based on the measured cap rock properties, the effect of thickness and permeability of cap rocks on CO 2 leakage was studied using a commercial compositional simulator. Experimental results show that the permeabilities of the shale s les measured by transient pulse technique range from 60 to 300 nD a non-Darcy calibration factor which equals the ratio of the measured permeability ided by 1000, is identified for s les with permeability lower than 1000 nD. Numerical simulation results show that the largest leakage of CO 2 through the seal (cap cock) is about 7.0% with seal thickness of 3m and vertical permeability of 90 nD both shale thickness and permeability affect the CO 2 leakage significantly with a given seal permeability, the leakage rate has a power relationship with shale thickness.
Publisher: SPE
Date: 11-1998
DOI: 10.2118/50423-MS
Abstract: Multi-stage, transversely fractured horizontal wellbores have the potential to greatly increase production from low permeability formations. Such completions are, however, susceptible to problems associated with near-wellbore tortuosity, particularly multiple fracturing from the same perforated interval. A criterion, based on that by Drucker and Prager, has been derived, which predicts the wellbore pressures required to initiate secondary multiple transverse hydraulic fractures in close proximity to primary fractures. Secondary fracture initiation pressures predicted by this new criterion compare reasonably well with those measured during a series of unique laboratory-scale multiple hydraulic fracture interaction tests. Both the multiple fracture initiation criterion and the laboratory results suggest that close proximity of primary hydraulic fractures increases the initiation pressures of secondary multiple fractures by the order of only 14 percent. This demonstrates that transversely fractured horizontal wellbores have limited capacities to resist the initiation of multiple fractures from adjacent perforations or intersecting heterogeneities. Petroleum engineers can use the multiple fracture initiation criterion when designing hydraulic fracture treatments to establish injection pressure limits, above which additional multiple fractures will initiate and propagate from the wellbore.
Publisher: Elsevier BV
Date: 09-2019
Publisher: SPE
Date: 20-02-2002
DOI: 10.2118/73754-MS
Abstract: Uncontrolled growth of hydraulic fractures and initiation of secondary multiple fractures may occur due to execution of a fracture treatment with inappropriate values for various treatment parameters: fracturing fluid viscosity, injection rate, injection time and proppant concentration. Such uncontrolled fracturing is not only uneconomic due to increased treatment cost but may also damage the formation irreversibly, resulting in productivity lower than even unfractured wells. Also excessive pressure drawdown during production from hydraulically fractured wells may result in sand production due to mechanical failure of perforation tunnels. This paper presents an integrated model to optimize treatment parameters in order to achieve maximum possible Net Present Value (NPV) while the above mentioned formation damage aspects are avoided by satisfying various constraints. These constraints are formulated as functions of treatment parameters, fracture geometry and mechanical and petrophysical properties of the reservoir so that the critical conditions that induce the formation damage in different modes do not become active. Additional constraints are also formulated to ensure that the optimally designed treatment can be executed in the field by using the specified surface equipment, and fracture width restriction does not occur. A genetic-evolutionary computing algorithm is integrated to solve the constrained treatment design problem such that it finds optimum values for treatment parameters and fracture geometry that are formation compatible. The capability of the model is demonstrated in the paper by application to a gas reservoir.
Publisher: SPE
Date: 09-09-1996
DOI: 10.2118/36405-MS
Abstract: Slim bole drilling has significant potential to reduce well costs. This cost savings are especially important with increased demand for reduced capital budget under current economic conditions in the oil industry. The savings can be achieved by use of smaller drilling rigs and/or workover rigs, reduced casing size, reducing requirement for drilling consumables and other costs associated with hole size. Cost savings achieved from slim hole drilling, however, can be offset by inability to effectively transmit the weight to the bit, increased mechanical failures of drill pipes and tools, in particular, in drilling at greater depths (depths greater then 1,500 m), reduced horizontal section of drilled hole, and lack of directional control. This paper investigates the effects of borehole parameters on drill pipe stability in an inclined and curved hole by means of non-linear analysis of Finite Elements Methods (FEM). Results are presented in the form of a set of tables and diagrams to predict Critical Buckling Loads (CBL), pipe/hole contact forces, contact points, contact lengths, and buckled pipe bending stresses. Drilling parameters considered are: hole inclination and curvature, pipe size, hole size, pipe thickness, mechanical properties of drill pipes and weight on bit. This paper presents critical buckling loads for drill pipe in vertical, inclined, horizontal, and curved oilfield type of boreholes. These findings are different in that no past work has encompassed both inclined and curved boreholes (Figure 1) in buckling research nor did it use non-linear mechanics which is permitted with the FEM. Buckling Problems. Buckling of oilfield drill pipe which is confined in a drill hole usually does not cause immediate failure but leads to premature failure through fatigue and erosion. In horizontal wells "lockup" of drill strings terminates the controlled drilling of the reach section. Lockup occurs when the compression at any location within the drill string is equal to or is greater than the drill string's resistance to buckling at that location. In other words, the weight on the bit plus the drag on the drill string is greater than or equal to the CBL of the string. Lockup is analogous to the act of attempting to push a rope through a horizontal section of pipe. The rope (the drill string) coils (buckles) just inside the entrance of the pipe (the well bore) and the far end of rope stops moving within the pipe. The rope is locked up. In a real bore hole, at lockup, the buckling of the drill string prevents the transfer of the weight of the drill string in the vertical section of the hole through the reach section to the drill bit. This is because the drill string no longer lies flat along the bottom of the horizontal section of the hole but is wound around the inside of the bore hole, probably in the shape of a helix. Without the weight on the drill bit, drilling ceases and the drilling of the reach is terminated. Current buckling models are based on Arthur Lubinski's pioneering work in the 1950's. The Bogy and Paslay paper on buckling of drill pipe in inclined holes was published in 1964. Other buckling work is based on Leonhard Euler's equations for determining buckling of long slender columns published in 1757. Most of the buckling models are based on critical assumptions. The most critical assumption is that the wellbore and drill string together act in a linear manner. For straight and vertical holes, this is an adequate assumption but, for horizontal and long reach wells, this assumption can and does cause significant errors with respect to actual drilling operations. Adding non-straight conditions to the long reach hole can cause even higher errors. These errors are caused by the non-linear nature of drill string buckling. Current models can not take into account these non-linearities. However, FEM can take these non-linearities into account. P. 313
Publisher: Elsevier BV
Date: 03-2022
Publisher: Informa UK Limited
Date: 09-2005
Publisher: Springer Science and Business Media LLC
Date: 23-04-2020
Publisher: Elsevier BV
Date: 07-2011
Publisher: American Chemical Society (ACS)
Date: 02-2020
Publisher: American Chemical Society (ACS)
Date: 11-07-2019
Publisher: Wiley
Date: 04-09-2015
DOI: 10.1111/GWAT.12365
Abstract: Reservoir behavior due to injection and circulation of cold fluid is studied with a shear displacement model based on the distributed dislocation technique, in a poro-thermoelastic environment. The approach is applied to a selected volume of Soultz geothermal reservoir at a depth range of 3600 to 3700 m. Permeability enhancement and geothermal potential of Soultz geothermal reservoir are assessed over a stimulation period of 3 months and a fluid circulation period of 14 years. This study-by shedding light onto another source of uncertainty-points toward a special role for the fracture surface asperities in predicting the shear dilation of fractures. It was also observed that thermal stress has a significant impact on changing the reservoir stress field. The effect of thermal stresses on reservoir behavior is more evident over longer circulation term as the rock matrix temperature is significantly lowered. Change in the fracture permeability due to the thermal stresses can also lead to the short circuiting between the injection and production wells which in turn decreases the produced fluid temperature significantly. The effect of thermal stress persists during the whole circulation period as it has significant impact on the continuous increase in the flow rate due to improved permeability over the circulation period. In the current study, taking into account the thermal stress resulted in a decrease of about 7 °C in predicted produced fluid temperature after 14 years of cold fluid circulation a difference which notably influences the potential prediction of an enhanced geothermal system.
Publisher: Elsevier BV
Date: 2017
Publisher: Elsevier BV
Date: 07-2010
Publisher: SPE
Date: 05-10-1997
DOI: 10.2118/38631-MS
Abstract: Premature screen-outs, and low in-place proppant concentrations occur frequently during hydraulic fracture treatments carried out in Central Australia. Two and three dimensional numerical modelling studies have been carried out, investigating factors affecting hydraulic fracture initiation, and near-wellbore fracture tortuosity, in highly stressed conditions. The 2D modelling suggests that drilling induced shear fractures, if oriented close to the maximum horizontal in-situ stress direction and inflated during treatment, may promote the initiation of multiple hydraulic fractures. Near-wellbore tortuosity and screen-outs are more likely in such situations. The results of this study also suggest that the elongated borehole geometry due to breakouts does not significantly alter the impact of preexisting fractures (either natural or induced) on hydraulic fracture initiation. 3D stress modelling indicated that fracture initiation may occur from perforations oriented even at large angles with respect to the maximum in-situ stress direction. Both numerical modelling and analytical analysis suggest that starter fractures initiate at the base, rather than the tip of perforations and that the initiation of horizontal starter fractures from perforations is independent of fluid pressure. For properly oriented perforations, horizontal starter fractures are unlikely to initiate because the strong reverse faulting regime required is rare at most reservoir depths. In strike-slip stress regimes, such as that experienced in Central Australia, however, the initiation of horizontal starter fractures is possible if perforations are misaligned with the minimum horizontal in-situ stress. This significantly increases the likelihood of near-wellbore tortuosity and the possibility of near-wellbore screen-outs. These studies highlight the benefits of aligning perforations in the maximum horizontal stress direction in eliminating reduced near-wellbore tortuosity. Hydraulic fracture treatments of tight formations in Central Australia often experience abnormally high treating pressures and fail to achieve adequate fracture conductivities due to low proppant concentration. The length of these fractures are commonly shorter than anticipated as a result of premature screen-out. A recent study has found that the hydrocarbon bearing formations in Central Australia have relatively high horizontal in-situ stresses and that the stress regime in the region is probably strike-slip faulting. In addition, FMS log images of selected wellbores in the region show widespread and consistent borehole breakouts in sandstones or coals, and tensile fractures in shales. Intuitively, these high horizontal stresses and associated induced shear fractures which cause borehole breakouts (see Fig. 1) may, in a manner similar to that of natural fractures, cause near-wellbore hydraulic fracture tortuosity However, the significant difference between these two types of fractures is that induced shear fractures occur in planes parallel with the minimum horizontal stress () (Fig. 1), whereas natural fractures are randomly oriented. It is therefore unclear what role such stress induced shear fractures play in the complication of hydraulic fracture initiation. The significant majority of high treating pressures and premature screen-outs in Central Australia, as experienced elsewhere, is ultimately near-wellbore fracture tortuosity which is manifested as multiple fractures or fracture reorientation. Regardless of form, the origin of near-wellbore tortuosity can be traced back to hydraulic fracture initiation, which is in turn controlled by the stress distribution around the wellbore during the breakdown stage. Therefore, a study of hydraulic fracture initiation in the presence of pre-existing fractures (either natural or induced shear fractures) under the influence of near-wellbore stresses, may help engineers establish a link between high in-situ stresses and an increased risk of premature screen-out. There exists much literature regarding experimental studies of hydraulic fracture initiation. P. 621^
Publisher: American Chemical Society (ACS)
Date: 04-11-2020
Publisher: Elsevier BV
Date: 12-2018
Publisher: American Chemical Society (ACS)
Date: 14-10-2021
Publisher: Elsevier BV
Date: 05-2007
Publisher: Springer Science and Business Media LLC
Date: 18-05-2018
Publisher: Society of Petroleum Engineers (SPE)
Date: 06-2002
DOI: 10.2118/78355-PA
Abstract: This paper presents a model for an alternative stimulation technology for naturally fractured tight gas or hot dry rock (HDR) reservoirs in which conventional hydraulic fracturing is relatively inefficient. The model stochastically simulates field-representative natural fractures by processing field data from cores, logs, and other sources. Deformations of these fractures are formulated as functions of fluid pressure inside fractures and in-situ stresses. The permeability enhancement and reservoir growth pattern are then formulated as functions of fracture deformations. While verified, the capability of the model to simulate field representative natural fractures is found to be satisfactory. The model is also applied to central Australian reservoirs to investigate permeability enhancement behavior with respect to various fracture attributes. The production performance of the proposed stimulation technology is assessed, and its potential for applications to tight gas reservoirs is also found to be very high.
Publisher: Elsevier BV
Date: 05-1997
Publisher: Elsevier BV
Date: 05-2018
Publisher: Informa UK Limited
Date: 16-06-2020
Publisher: Springer Science and Business Media LLC
Date: 05-10-2018
Publisher: Society of Petroleum Engineers (SPE)
Date: 09-1998
DOI: 10.2118/51186-PA
Abstract: A new mathematical model is presented that enables the prediction of various modes of cuttings transport in highly deviated to horizontal annuli that have been observed in laboratories. The model consists of three components: a bed of particles of uniform concentration, a dispersed layer in which particle concentration is varied, and a fluid-flow layer that could be a clear fluid or a turbulent suspension. The model predictions exhibit good agreement with experimental observations.
Publisher: Elsevier BV
Date: 04-2016
Publisher: Frontiers Media SA
Date: 09-11-2020
Publisher: Springer Science and Business Media LLC
Date: 30-01-2015
Publisher: American Association of Petroleum Geologists
Date: 2018
Publisher: Elsevier BV
Date: 11-2020
Publisher: Informa UK Limited
Date: 09-2002
Publisher: Elsevier BV
Date: 09-2016
Publisher: Informa UK Limited
Date: 11-01-2003
Publisher: Elsevier BV
Date: 03-1995
Publisher: Elsevier BV
Date: 03-2018
Publisher: Elsevier BV
Date: 10-2016
Publisher: Elsevier BV
Date: 07-2011
Publisher: Elsevier BV
Date: 12-2016
Publisher: Elsevier BV
Date: 02-2020
DOI: 10.1016/J.SCITOTENV.2019.135941
Abstract: CO
Publisher: American Physical Society (APS)
Date: 29-10-2018
Publisher: IOP Publishing
Date: 10-1995
Publisher: American Chemical Society (ACS)
Date: 20-10-2021
Publisher: Springer Science and Business Media LLC
Date: 06-2010
Publisher: Elsevier BV
Date: 2015
Publisher: Society of Petroleum Engineers (SPE)
Date: 10-2001
DOI: 10.2118/01-10-04
Abstract: Multi-stage, transversely fractured horizontal wellbores have the potential to greatly increase production from low permeability formations. Such completions are, however, susceptible to problems associated with near-wellbore tortuosity, particularly multiple fracturing from the same perforated interval. A criterion, based on that by Drucker and Prager, has been derived, which predicts the wellbore pressures required to initiate secondary multiple transverse hydraulic fractures in close proximity to primary fractures. Secondary fracture initiation pressures predicted by this new criterion compare reasonably well with those measured during a series of unique laboratory-scale multiple hydraulic fracture interaction tests. Both the multiple fracture initiation criterion and the laboratory results suggest that close proximity of primary hydraulic fractures increases the initiation pressures of secondary multiple fractures by the order of only 14%. This demonstrates that transversely fractured horizontal wellbores have limited capacities to resist the initiation of multiple fractures from adjacent perforations or intersecting heterogeneities. Petroleum engineers can use the multiple fracture initiation criterion when designing hydraulic fracture treatments to establish injection pressure limits, above which additional multiple fractures will initiate and propagate from the wellbore. A significant proportion of the worldwide recoverable hydrocarbon resource exists in reservoirs possessing permeabilities of less than one milli-Darcy (mD). At present, low production rates accompanying such poor permeabilities imply that, if hydrocarbons are to be exploited economically, some form of permeability enhancement or stimulation must be carried out within these reservoirs. Even where initial permeabilities are relatively high, stimulation may still be required to overcome problems associated with localised permeability damage due to, for ex le, drilling mud invasion. Matrix acidisation and hydraulic fracturing remain the principal reservoir stimulation techniques. The advantages of horizontal wells in comparison with vertical wells have been extensively documented. Indeed, in an increasing number of fields throughout the world, the production of hydrocarbons is performed exclusively through horizontal wells. Whilst still a relatively rare form of completion, fractured horizontal wells are becoming more common in low permeability formations. This is particularly so where surface geographies dictate that wells must deviate from central drill pads, such as in offshore or arctic regions. Hydraulic fractures, regardless of their origin, always attempt to propagate in planes orthogonal to the minimum horizontal stress, in what is commonly referred to as the "preferred fracture plane." However, while hydraulic fracture propagation planes are fixed, the horizontal wellbores from which they emanate may assume completely arbitrary orientations. Two limiting wellborefracture configurations are the focus of much attention:"Longitudinal Fractures" propagate in planes parallel with wellbore axes, as illustrated in Figure 1. They form where horizontal wells are drilled parallel with the larger of the horizontal stresses (or parallel with the preferred fracture plane) "Transverse Fractures" propagate in planes orthogonal to wellbore axes, as illustrated in Figure 2. They form where horizontal wells are drilled perpendicular to the larger of the horizontal stresses (or perpendicular to the preferred fracture plane). A number of studies have been carried out, comparing the production character
Publisher: Elsevier BV
Date: 10-2015
Publisher: Informa UK Limited
Date: 05-2002
Publisher: EAGE Publications BV
Date: 2013
Publisher: Elsevier BV
Date: 05-1992
Publisher: SPE
Date: 09-11-2015
DOI: 10.2118/176971-MS
Abstract: Characterization of flow processes in multi-scale porous system (nanopores to mesopores) in tight rocks, such as the shales, is challenging because of the coexistence of various flow regimes in the porous media. Although some methods based on dusty gas model (DGM) have been applied to determine the apparent gas permeability of shales (Javadpour 2009, Freeman et al. 2011, Sakhaee-Pour and Bryant 2012, Chen et al. 2015), they fail to describe gas flow process in nanopores in detail. In this paper, we present an innovative methodology for estimating apparent gas permeability of shales by coupling multiscale flow mechanisms. The Lattice Boltzmann Method (LBM) with effective viscosity and a general second-order boundary condition is used to analyze the various flow regimes involved in the single microchannel. The desirable agreement between the simulation results and that from the DSMC studies for the rarefied flow prompts the application of the derived correction factor for estimating permeability of shale gas reservoirs. In order to realize this, the porous medium is represented by a bundle of capillaries with diameters determined by mercury injection capillary pressure (MICP) curves. The porous flow is simulated by Darcy's law with derived correction factor the surface diffusion of adsorption gas in kerogen pores is simulated based on Langmuir model and Fick's law. An extensive integration based on fractal dimension is performed to estimate the total flow rate and thereby the apparent permeability of typical shale s les. MICP and a transient pressure pulse technique are employed on 7 shale s les to obtain the pore size distribution and permeability. The result shows that the estimated gas permeability matches well with the measured permeability with a 20% variation, indicating that the physics based model presented in this paper is highly effective in predicting gas permeability of tight formations, such as the shales.
Publisher: American Society of Civil Engineers (ASCE)
Date: 10-2011
Publisher: SPE
Date: 07-11-2016
DOI: 10.2118/183275-MS
Abstract: Flow simulation in shale is challenging due to its multiscale porous structure and multi-physics gas flow in these pores. Because network of pores is capable of characterizing the three dimensional (3D) distribution of pores and throats, it is widely used to estimate the apparent gas permeability of porous media, such as shale. Pores residing in shale have a broad spectrum of size ranging from a few nanometers to micrometers, therefore, multiple flow regimes, including the continuum flow, slip flow, transition flow and sometimes Knudsen diffusion are controlling the flow in the porous structure of shale. In addition, surface diffusion occurs on the adsorption layer of organic matters also contributes to the total flow rate. For the network modelling in the literature, the employed equaitons fail to account for these flow mechanisms. In view of this, Beskok and Karniadakis (1999)’s equation and Fick’s equation are employed to describe the non-continuum flow and surface diffusion, respectively, in a reconstructed network of shale. The simulation results provide an improved understanding of gas flow behaviour in shale matrix. It has been observed that the apparent gas permeability increases by a factor of 2.4, with 21% contribution arising from surface diffusion when the downstream pressure depletes from 9 MPa to 2 MPa. Sensitivity analyses imply that the apparent gas permeability is dependent on the size and shape of throats, compressibility factor and type of gas, Langmuir adsorption parameters and reservoir conditions.
Publisher: Elsevier BV
Date: 2020
Publisher: Springer Science and Business Media LLC
Date: 11-2011
Publisher: Informa UK Limited
Date: 2000
Publisher: Inderscience Publishers
Date: 2019
Publisher: Elsevier BV
Date: 10-2018
Publisher: Springer Science and Business Media LLC
Date: 26-03-2011
Publisher: SPE
Date: 12-10-1998
DOI: 10.2118/50093-MS
Abstract: A large, though relatively untapped tight gas resource is thought to exist within Australia. Experience from the North Sea and the United States suggests that transversely fractured horizontal wells may be used to exploit tight gas resources more effectively than more conventional means, such as fractured vertical wells or fully completed horizontal wells. However, transversely fractured horizontal wells are relatively expensive completion options, and are commonly afflicted by complications associated with complex fracture geometries. Therefore, careful planning and screening of prospective reservoirs is essential. Using an analytical pseudo steady state inflow model, this study reviews the reservoir conditions required for the successful application of transversely fractured horizontal wells. To avoid fracture reorientation, transverse fractures should ideally be initiated directly from the wellbore and possess no longitudinal components. Reservoirs which possess natural fractures or create large differential stresses across horizontal wellbore sections will be predisposed towards the successful placement of transverse fractures. Guidelines are presented which enable the identification of such reservoirs. A case study has been performed which demonstrates the applicability of transversely fractured horizontal wells in the context of Australian tight gas reservoirs. P. 315
Publisher: SPE
Date: 09-11-2015
DOI: 10.2118/177928-MS
Abstract: In this paper, we present an integrated approach to study the effect of low salinity water flooding on the oil recovery. This is achieved in four steps: first, we have extended our multiphase fluid flow simulation in porous matrix discrete fractures by integrating the electrochemical model. The electrochemical model estimates disjoining pressure from the knowledge of which in turn is a function of different chemical species and their concentration, pH and temperature. Next, the film thickness, which is controlled by different chemical species is determined by using atomic force microscopy and compared with the values estimated by the chemical model. In the third step, we carried out low salinity water flooding on fractured carbonate core s les using a combination of different ions and their concentrations and recovered oil was measured. In these laboratory experiments water floods in core s les with single fractures are simulated to study the effect of heterogeneity (discontinuity) on oil recovery. In the final step we have used our multiphase flow simulator to study low salinity water flooding in laboratory core scale. The results of this study are evaluated by comparing with the results obtained in the laboratory. The results of this study show that the water film thickness is directly related to brine concentration. There exist, however, an optimum concentration at which maximum thickness can be reached. Above this optimum concentration water film thickness gradually decreases. Core flood tests have shown similar results, that is maximum oil recovery can be obtained at an optimum brine concentration.
Publisher: Elsevier BV
Date: 11-2021
Publisher: Springer Science and Business Media LLC
Date: 17-10-2015
Publisher: Informa UK Limited
Date: 18-10-2013
Publisher: Wiley
Date: 23-11-2015
DOI: 10.1111/GFL.12156
Publisher: Informa UK Limited
Date: 22-10-2007
Publisher: SPE
Date: 28-10-1996
DOI: 10.2118/37392-MS
Abstract: Inadequate weight on bit leads to drilling at lower rate of penetration which reflect itself with expensive drilling intervals. Weight on bit is provided by slacking of some of the weights of the tubulars on bit. From the mechanical point of view this means putting bottom section of drill string into compression. The upper limit of the compressional stress that can be imposed on a drill string is bounded by the minimum stress which can lead to the failure of the tubulars. One type of the failure of drill string is called 'drill string buckling'. As the size of tubular decreases, their ability to transmit weight on bit without buckling decreases. Curvature and inclination of drilled hole increase or decrease the amount of compressional load that can be imposed on tubular without buckling. This load is known as Critical Buckling Load. This paper presents a finite element and an experimental approaches to predict the critical buckling load for dropping and building sections of holes. Drilling at minimum cost necessitates optimum weight on bit. This weight is provided by slacking off some of the weights of drill string on bit. As the hook load decreases and slacked off length increases neutral point moves up in the drill string. At the same time, compressional stresses below the neutral point increase. There is a critical value of compressional stresses such that below which pipes are stable. In other word, pipes still have resistance against bending. However, if this value is exceeded then they will shown no resistance against bending. This phenomenon is known as buckling of tubulars and this critical value is known as Critical Buckling Load. Buckling is not desired in drillstring because of several reasons. One of the reasons is that it may lead to premature failure of the drillstring through fatigue and erosion. It may lead to termination of drilling due to drill string lockup especially in horizontal wells. Lockup occurs when the compression at any location within the drill string is equal to or is greater than the drillstring's resistance to buckling at that location. Therefore, it becomes impossible to provide the necessary weight on bit. Without the weight on the bit, drilling ceases and drilling of the reach is terminated. Therefore, it is essential to determine the maximum load that can be imposed on drillstring. Critical Buckling Load is not a unique number for a given diameter pipe. There are a number of borehole parameters affecting the magnitude of it. Such as, hole curvature, hole inclination, hole to pipe friction, etc. (Figure 1). Therefore, Critical Buckling Load for a given size pipe can not be determined independent without taking borehole data into consideration. Compressive load at which pipes buckle can be predicted based on Eigenvalue analyses or based on large Deflection Analysis of Finite Elements Methods. Eigenvalue analysis has the short coming of estimating the upper bound of critical buckling load (bifurcation load). Whereas, the more critical lower bound can be predicted with Large Deflection analysis of Finite Elements Methods (Figure 2). This study makes use of large deflection analysis of FEM to predict the critical buckling load in dropping holes. This paper also presents an experimental study to predict the critical buckling load in building holes. During a buckling simulation, the drill pipe is released and is allowed to slide down the wall of the borehole and settle into a stable position within the borehole. The pipe may or may not be buckled at the end of the simulation. If the pipe is buckled there will be a length of pipe in contact with the opposite side of the wall of the borehole (high side). The force created by the contact is called the contact force. It's direction is normal to the wall of the borehole. Whether the pipe buckles or only bends, two forces acting on the drill pipe will be created. P. 641
Publisher: SPE
Date: 07-09-1998
DOI: 10.2118/47786-MS
Abstract: Wellbore instability and formation damage are the two major problems encountered by the petroleum industry. It is commonly accepted that formation damage is mainly caused by fluid-rock interaction due to the change in pore fluid chemistry which is caused by invading mud filtrate. Invasion of mud filtrate can be reduced by forming a tight filter cake on the wellbore wall. A tight filter cake can also provide support to the wellbore wall and prevent wellbore collapse. Therefore, the most effective option for solving wellbore instability and formation damage problems is to design a drilling mud that is compatible with formations in relation to both fluid-rock interaction and mud caking characteristics. This paper considers a number of mud systems with novel features and investigates their potential use in drilling and completion of tight gas formations in Central Australia, which are highly susceptible to formation damage. Among the four (4) muds investigated, ester based mud has been found to be the most effective in reducing formation damage by producing a tight filter cake on the wellbore wall. P. 113
Publisher: Elsevier BV
Date: 05-2017
Publisher: InTech
Date: 17-05-2013
DOI: 10.5772/56447
Publisher: Elsevier BV
Date: 02-2007
Publisher: Elsevier BV
Date: 10-2001
Publisher: Springer Science and Business Media LLC
Date: 15-05-2020
Publisher: Elsevier BV
Date: 08-2002
Publisher: American Society of Civil Engineers (ASCE)
Date: 12-2013
Publisher: Elsevier BV
Date: 11-2017
Publisher: Elsevier BV
Date: 05-2020
Publisher: Elsevier BV
Date: 10-2010
Publisher: Elsevier BV
Date: 08-2002
Publisher: American Chemical Society (ACS)
Date: 24-06-2020
Publisher: Elsevier BV
Date: 09-2000
Publisher: Society of Petroleum Engineers
Date: 2015
DOI: 10.2118/178532-MS
Publisher: Springer Science and Business Media LLC
Date: 08-04-2020
Publisher: Elsevier BV
Date: 10-2017
Publisher: Wiley
Date: 1993
Publisher: Informa UK Limited
Date: 04-2013
Publisher: American Chemical Society (ACS)
Date: 16-06-2021
Publisher: Elsevier BV
Date: 10-2017
Location: United Kingdom of Great Britain and Northern Ireland
Location: Bangladesh
Location: Saudi Arabia
No related grants have been discovered for Sheik Rahman.