It is widely understood that injection and production activities can induce additional stress fields that will couple with the in situ stress field. An increased shear stress may cause serious casing stability issue, and casing integrity is one of the major issues in the development of an oilfield. In this thesis, I will present a methodology for semi-quantitatively addressing the physical processes, the occurrence, and the key influential factors associated with large-area casing shear issues in Daqing Oilfield. In the research, I will investigate reservoir heterogeneity and the far-field stress field in the Daqing Oilfield, China; I will review fundamental theories of rock strength, rock failure, casing shear, and techniques for coupling fluid flow and mechanical response of the reservoirs; and I will present mathematical simulations of large-area casing shear in one typical area (X1-3B) in Daqing Oilfield, under different regimes of water-affected shale area ratio and block pressure difference. Heterogeneity in Daqing Oilfield varies according to the scale. Mega-heterogeneity is not too serious: the geometry of the oilfield is simple, the structure is flat, and faults are numerous and complex, but distributed evenly. Macro-heterogeneity is, however, intense. Horizontal macro-heterogeneity is associated with lateral variations because of different depositional facies. Vertical macro-heterogeneity of Daqing Oilfield because of layering is typified by up to 100 individual sand layers with thickness ranging from 0.2 to 20 m and permeability ranging from 20 to 1600 mD (average 230 mD). Furthermore, there are a number of stacked sand-silt-shale (clastic lithofacies) sequences. Mercury porosimetry and photo-micro-graphic analyses were used to investigate the micro-heterogeneity of Daqing Oilfield. This method yields a complete pore size distribution, from several nanometers to several thousands of micro-meters as well as cumulative pore volume distributions, pore-throat aspect ratios, and fractal dimensions. The fractal dimension can be used to describe the heterogeneity at the pore scale; for sandstones, the larger the fractal dimension of a specific pore structure, the more heterogeneous it is. Reservoir sandstones of Daqing Oilfield have similar porosity and mineralogy, so their micro-heterogeneity lies in a micro-structure of considerable variability. Differences in micro-structure affect permeability, which also varies considerably and evidences a considerable amount of micro-scale anisotropy. Finally, the number and nature of faults in the oilfield make the macro-scale heterogeneity more complex. Rock strength is affected by both intrinsic factors and external factors. Increased water saturation affects rock strength by decreasing both rock cohesion and rock friction angle. In Daqing Oilfield, is seems that a 5% increase of water content in shale can decrease the maximum shearing resistance of shale by approximately 40%. Hysteretic behavior leads to porosity and permeability decreases during the compaction stage of oilfield development (increasing σ'). Also, injection pressures are inevitably kept as high as possible in the pursuit of greater production rates. These lead to non-homogeneous distributions of pressures as well as in changes of material behavior over time. Loss of shear strength with water content increase, inherent reservoir heterogeneity, and long periods of high-pressure water injection from a number of wells are three key factors leading to casing shear occurring over large areas in Daqing Oilfield. Reservoir heterogeneity and structural complexity foster uneven formation pressure distribution, leading to inter-block pressure differences. Sustained long-term elevated pressures affect overburden shale mechanical strength as well as reducing normal stresses, and the affected area increases with time under high-pressure injection so that the affected areas overlap at the field scale and alter the in situ stress field. Once the maximum compressive stress parallels or nearly parallels the differential pressure, and the water-affected shale area is big enough, the shear stability of the interface between the shale and the sandstone is severely compromised, and when the thrust stress imposed exceeds the shearing resistance, the strata will slip in a direction corresponding to the vector from high-pressure to low-pressure areas. The change in this slip and creep displacement field is the major reason for the serious casing deformation damage in Daqing Oilfield. To quantify the scale effect of the water-affected shale area on casing stability, coupled non-linear poroelastic fluid flow was simulated for a typical area. The Daqing Oilfield simulation result is in coincidence with the in situ observation of disturbed stress fields and casing displacement. The water-affected area has a scale effect on the casing stability. The ratio of the water-affected shale formation area to the total area influences the stability coefficient much more than the block pressure difference. In the studied area, under conditions of injection pressure of 12.7 MPa and no more than 2.5 MPa block pressure difference, the water-affected ratio should be smaller than 0.50 or so in order to maintain areal casing stability. By history matching, in the studied area under current development condition and considering the water-affected ratio, so long as the injection pressure and pressure differential between blocks are controlled to be less than 12.7 MPa and 0.86 MPa respectively, formation shear slip along a horizontal surface will no longer occur.

It is widely understood that injection and production activities can induce additional stress fields that will couple with the in situ stress field. An increased shear stress may cause serious casing stability issue, and casing integrity is one of the major issues in the development of an oilfield. In this thesis, I will present a methodology for semi-quantitatively addressing the physical processes, the occurrence, and the key influential factors associated with large-area casing shear issues in Daqing Oilfield. In the research, I will investigate reservoir heterogeneity and the far-field stress field in the Daqing Oilfield, China; I will review fundamental theories of rock strength, rock failure, casing shear, and techniques for coupling fluid flow and mechanical response of the reservoirs; and I will present mathematical simulations of large-area casing shear in one typical area (X1-3B) in Daqing Oilfield, under different regimes of water-affected shale area ratio and block pressure difference. Heterogeneity in Daqing Oilfield varies according to the scale. Mega-heterogeneity is not too serious: the geometry of the oilfield is simple, the structure is flat, and faults are numerous and complex, but distributed evenly. Macro-heterogeneity is, however, intense. Horizontal macro-heterogeneity is associated with lateral variations because of different depositional facies. Vertical macro-heterogeneity of Daqing Oilfield because of layering is typified by up to 100 individual sand layers with thickness ranging from 0.2 to 20 m and permeability ranging from 20 to 1600 mD (average 230 mD). Furthermore, there are a number of stacked sand-silt-shale (clastic lithofacies) sequences. Mercury porosimetry and photo-micro-graphic analyses were used to investigate the micro-heterogeneity of Daqing Oilfield. This method yields a complete pore size distribution, from several nanometers to several thousands of micro-meters as well as cumulative pore volume distributions, pore-throat aspect ratios, and fractal dimensions. The fractal dimension can be used to describe the heterogeneity at the pore scale; for sandstones, the larger the fractal dimension of a specific pore structure, the more heterogeneous it is. Reservoir sandstones of Daqing Oilfield have similar porosity and mineralogy, so their micro-heterogeneity lies in a micro-structure of considerable variability. Differences in micro-structure affect permeability, which also varies considerably and evidences a considerable amount of micro-scale anisotropy. Finally, the number and nature of faults in the oilfield make the macro-scale heterogeneity more complex. Rock strength is affected by both intrinsic factors and external factors. Increased water saturation affects rock strength by decreasing both rock cohesion and rock friction angle. In Daqing Oilfield, is seems that a 5% increase of water content in shale can decrease the maximum shearing resistance of shale by approximately 40%. Hysteretic behavior leads to porosity and permeability decreases during the compaction stage of oilfield development (increasing σ'). Also, injection pressures are inevitably kept as high as possible in the pursuit of greater production rates. These lead to non-homogeneous distributions of pressures as well as in changes of material behavior over time. Loss of shear strength with water content increase, inherent reservoir heterogeneity, and long periods of high-pressure water injection from a number of wells are three key factors leading to casing shear occurring over large areas in Daqing Oilfield. Reservoir heterogeneity and structural complexity foster uneven formation pressure distribution, leading to inter-block pressure differences. Sustained long-term elevated pressures affect overburden shale mechanical strength as well as reducing normal stresses, and the affected area increases with time under high-pressure injection so that the affected areas overlap at the field scale and alter the in situ stress field. Once the maximum compressive stress parallels or nearly parallels the differential pressure, and the water-affected shale area is big enough, the shear stability of the interface between the shale and the sandstone is severely compromised, and when the thrust stress imposed exceeds the shearing resistance, the strata will slip in a direction corresponding to the vector from high-pressure to low-pressure areas. The change in this slip and creep displacement field is the major reason for the serious casing deformation damage in Daqing Oilfield. To quantify the scale effect of the water-affected shale area on casing stability, coupled non-linear poroelastic fluid flow was simulated for a typical area. The Daqing Oilfield simulation result is in coincidence with the in situ observation of disturbed stress fields and casing displacement. The water-affected area has a scale effect on the casing stability. The ratio of the water-affected shale formation area to the total area influences the stability coefficient much more than the block pressure difference. In the studied area, under conditions of injection pressure of 12.7 MPa and no more than 2.5 MPa block pressure difference, the water-affected ratio should be smaller than 0.50 or so in order to maintain areal casing stability. By history matching, in the studied area under current development condition and considering the water-affected ratio, so long as the injection pressure and pressure differential between blocks are controlled to be less than 12.7 MPa and 0.86 MPa respectively, formation shear slip along a horizontal surface will no longer occur.

Predicting the performance of wells in compartmentalized reservoirs can be quite challenging to most conventional reservoir engineering tools. The purpose of this research is to develop a Compartmentalized Gas Depletion Model that applies not only to conventional consolidated reservoirs (with constant formation compressibility) but also to unconsolidated reservoirs (with variable formation compressibility) by including geomechanics, permeability deterioration and compartmentalization to estimate the OGIP and performance characteristics of each compartment in such reservoirs given production data. A geomechanics model was developed using available correlation in the industry to estimate variable pore volume compressibility, reservoir compaction and permeability reduction. The geomechanics calculations were combined with gas material balance equation and pseudo-steady state equation and the model was used to predict well performance. Simulated production data from a conventional gas Simulator was used for consolidated reservoir cases while synthetic data (generated by the model using known parameters) was used for unconsolidated reservoir cases. In both cases, the Compartmentalized Depletion Model was used to analyze data, and estimate the OGIP and Jg of each compartment in a compartmentalized gas reservoir and predict the subsequent reservoir performance. The analysis was done by history-matching gas rate with the model using an optimization technique. The model gave satisfactory results with both consolidated and unconsolidated reservoirs for single and multiple reservoir layers. It was demonstrated that for unconsolidated reservoirs, reduction in permeability and reservoir compaction could be very significant especially for unconsolidated gas reservoirs with large pay thickness and large depletion pressure.

Predicting the performance of wells in compartmentalized reservoirs can be quite challenging to most conventional reservoir engineering tools. The purpose of this research is to develop a Compartmentalized Gas Depletion Model that applies not only to conventional consolidated reservoirs (with constant formation compressibility) but also to unconsolidated reservoirs (with variable formation compressibility) by including geomechanics, permeability deterioration and compartmentalization to estimate the OGIP and performance characteristics of each compartment in such reservoirs given production data. A geomechanics model was developed using available correlation in the industry to estimate variable pore volume compressibility, reservoir compaction and permeability reduction. The geomechanics calculations were combined with gas material balance equation and pseudo-steady state equation and the model was used to predict well performance. Simulated production data from a conventional gas Simulator was used for consolidated reservoir cases while synthetic data (generated by the model using known parameters) was used for unconsolidated reservoir cases. In both cases, the Compartmentalized Depletion Model was used to analyze data, and estimate the OGIP and Jg of each compartment in a compartmentalized gas reservoir and predict the subsequent reservoir performance. The analysis was done by history-matching gas rate with the model using an optimization technique. The model gave satisfactory results with both consolidated and unconsolidated reservoirs for single and multiple reservoir layers. It was demonstrated that for unconsolidated reservoirs, reduction in permeability and reservoir compaction could be very significant especially for unconsolidated gas reservoirs with large pay thickness and large depletion pressure.

The objective of this thesis is to identify the value of geomechanics and engineering geology to mine enterprise value for hardrock underground mines. It was decided that the most effective way to highlight the value of geomechanics and engineering geology was by identifying an increase in expenditure that could be economically justified in the present to mitigate the cost of a future event, thus providing a means for showing the economic value of the work performed. Cost models were generated for several events based on the direct cost, value of ore lost and decline in value of ore due to the event. A cost associated with fatalities was also included. Six rockburst events were developed into cost models from publicly available information. A further 13 were developed from confidential information provided by mining companies, bringing the total number of events analyzed to 19. A probabilistic approach was then taken to identify the probability of a rockburst with a certain magnitude occurring and, if an event occurs, the probability it will cause damage. The former is based on the Gutenberg-Richter Frequency-Magnitude relationship while the latter was derived from Unusual Occurrence Reports provided by the Ontario Ministry of Labour. Three case studies were then developed to show how to use the average cost of a rockburst event in conjunction with the probability analysis to arrive at an increase in expenditure above baseline spending. It was found that the total average cost of a rockburst based on the 19 events analyzed from 13 mines in 4 different countries for events occurring between 1984 and 2009 is $35.4 million (2010 CAD) with a range of $1.1 to $263.5 million (2010 CAD). Using the probabilistic method outlined above and cost models from the specific region involved, the increase in expenditure for the Ontario hard rock underground case study, Mine A and Mine B was found to be $12.1 million (2010 CAD), $5 million (2010 CAD) and $4.0 million (2010 CAD) respectively. / Thesis (Master, Mining Engineering) -- Queen's University, 2011-11-06 14:03:21.589

No description available.

No description available.

Recently, there has been considerable interest in the study of coupled fluid flow – geomechanics simulation, integrated into reservoir engineering. One of the most challenging problems in the petroleum industry is the understanding and predicting of subsidence at the surface due to formation compaction at depth, the result of withdrawal of fluid from a reservoir. In some oil fields, the compacting reservoir can support oil and gas production. However, the effects of compaction and subsidence may be linked to expenditures of millions of dollars in remedial work. The phenomena can also cause excessive stress at the well casing and within the completion zone where collapse of structural integrity could lead to loss of production. In addition, surface subsidence can result in problems at the wellhead or with pipeline systems and platform foundations. Recorded practice reveals that although these problems can be observed and measured, the technical methods to do this involve time, expense, with consideration uncertainty in expected compaction and are often not carried out. Alternatively, prediction of compaction and subsidence can be done using numerical reservoir simulation to estimate the extent of damage and assess measurement procedures. With regard to reservoir simulation approaches, most of the previous research and investigations are based on deterministic coupled theory applied to continuum porous media. In this work, uncertainty of parameters in reservoir is also considered. This thesis firstly investigates and reviews fully coupled fluid flow – geomechanics modeling theory as applied to reservoir engineering and geomechanics research. A finite element method is applied for solving the governing fully coupled equations. Also simplified analytical solutions that present more efficient methods for estimating compaction and subsidence are reviewed. These equations are used in uncertainty and stochastic simulations. Secondly, porosity and permeability variations can occur as a result of compaction. The research will explore changes of porosity and permeability in stress sensitive reservoirs. Thirdly, the content of this thesis incorporates the effects of large structures on stress variability and the impact of large structural features on compaction. Finally, this thesis deals with affect of pore collapse on multiphase fluid and rock properties. A test case from Venezuelan field is considered in detail; investigating reservoir performance and resultant compaction and subsidence. The research concludes that the application of coupled fluid flow – geomechanics modeling is paramount in estimating compaction and subsidence in oil fields. The governing equations that represent behaviour of fluid flow and deformation of the rock have been taken into account as well as the link between increasing effective stress and permeability/porosity. From both theory and experiment, this thesis shows that the influence of effective stress on the change in permeability is larger than the effect of reduction in porosity. In addition, the stochastic approach used has the advantage of covering the impact of uncertainty when predicting subsidence and compaction. This thesis also demonstrates the influence of a large structure (i.e. a fault) on stress regimes. Mathematical models are derived for each fault model to estimate the perturbed stress. All models are based on Mohr–Coulomb’s failure criteria in a faulted area. The analysis of different stress regimes due to nearby faults shows that effective stress regimes vary significantly compared to a conventional model. Subsequently, the selection of fault models, fault friction, internal friction angle and Poisson’s ratio are most important to assess the influence of the discontinuity on the reservoir compaction and subsidence because it can cause a significant change in stress regimes. To deal with multiphase flow in compacting reservoirs, this thesis presents a new method to generate the relative permeability curves in a compacting reservoir. The principle for calculating the new values of irreducible water saturation (Swir) due to compaction is demonstrated in this research. Using coupled reservoir simulators, fluid production due to compaction is simulated more comprehensively. In the case example presented, water production is reduced by approximately 70% compared to conventional modeling which does not consider changes in relative permeability. This project can be extended by applying the theory and practical methodologies developed to other case studies, where compaction and stress sensitivity dominate the drive mechanism. / http://proxy.library.adelaide.edu.au/login?url= http://library.adelaide.edu.au/cgi-bin/Pwebrecon.cgi?BBID=1374653 / Thesis (Ph.D.) - University of Adelaide, Australian School of Petroleum, 2007

No description available.

Geothermal energy potential depends on locating highly porous and permeable zones that support fluid flow to extract heat. Hot springs in the playa of Surprise Valley, CA are distributed along gaps and bends in magnetic anomalies interpreted as sub-cropping mafic dikes (Glen et al., 2013). In addition to these dikes in the Valley Playa, dikes outcrop in the Hays Canyon Range (HCR) that defines the eastern margin of the valley. Dikes in the HCR have two distinct attitudes (1) N-S striking dikes (~180) that dip 60oW, and (2) NNW-SSE striking dikes (~330) that dip 85oE. Both attitudes are spatially associated with locally high fracture density and minor hydrothermal alteration that may have formed from dike emplacement. This study tests whether the distribution of hot springs can be explained by elastic distortions around an array of opening dikes that promotes localized dilation to support a network of open secondary structures focusing fluid flow to supply the hot springs. This is done through two mechanical model experiments which use boundary elements in an elastic half-space. The first model is a sensitivity study investigating the role of dike dimensions and position in the density stratigraphy on their opening. Field analysis constrains the strike-length, thickness, and the upper tip position of dikes, although height is unknown. The model reproduced the mapped dike-length (4000 m) and thickness (2.0 m) with a dike-height of 60000m and a magma density of 2500 kg/m3 which is consistent with mafic dikes. The second model applies the dike dimensions and calculates the resulting stress state and fracture potential around an array of dikes conforming to both attitudes of the dike array mapped magnetic anomalies and informed by from field results of dike orientation in the Hays Canyon Range. Simulations of the N-S trend predict regions of enhanced Coulomb stress and tension that promote fracture formation and opening near dike tips where segments are isolated and where two closely spaced dike segments underlap. Conversely, compression is enhanced along the dike walls and where the segments closely overlap. The NNW-SSE trending array of dikes predict increased Coulomb stress and tension at similar locations in the array, but with more extreme values. Thus, the NNW-SSE dike array geometry better matches areas of enhanced fracturing with locations with active hot springs (as well as regions of enhanced compression with their absence) than the geometry of the N-S dike array. / Geology / Accompanied by 3 *.M files: 1)Sawyer_temple_0225M_171/WORKFLOW_p3dResults_Sensitivity_positionbc_interrogation_3d_NCD.m 2)Sawyer_temple_0225M_171/WORKFLOW_p3dResults_Sensitivity_positionbc_figures.m 3)Sawyer_temple_0225M_171/WORKFLOW_p3d_SV_toy_dikes_Sensitivity_positionbc.m