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Abstract: This paper presents the results of investigations into two field cases in Australia where expensive fracture treatments did not yield expected benefits. Field_1 contains a thin gas reservoir in which more than 20 vertical wells were drilled and hydraulically fractured. The post-frac well tests yielded low production rates prompting to a comprehensive study. Among other reservoir properties, the in-situ stresses were characterized and found to be in the reverse faulting stress regime. Through 3D mixed-mode simulation of hydraulic fracture propagation, the first part of this paper shows that the vertical fracture initiated from the vertical wellbore would turn and twist to be horizontal during propagation and would require extremely high treatment pressure and leave very little conduit for flow. These were the main reasons for multiple screen-outs during treatments and post-frac low production rates from the reservoir. A number of potentially effective hydraulic fracture treatments have been recommended for the reservoir. Field_2 contains a tight-gas reservoir, which a number of operators have attempted to develop by hydraulic fracturing over the last 30 years. After every attempt, the post-frac flow rate was lower than the pre-frac rate and therefore the well was plugged and abandoned. The second part of this paper presents the results of a comprehensive investigation into the field. The investigation has established the inadequacy of the treatment carried out in the reservoir to achieve the expected production rate, and demonstrated how more effective treatments could be designed by using a constrained hydraulic fracturing optimization model. [Copyright &y& Elsevier]

Abstract: Wellbore stability remains as one of the major challenges to drilling engineers. Results of recent survey showed about one third of non-productive time of drilling operation is classified as borehole problem, where a significant part is attributed to borehole instability. The thermal regime of a formation in the vicinity of a wellbore affects the stability of the well significantly during drilling operations, especially in High pressure High Temperature (HPHT) wells. This paper describes how the thermal behavior of a tubular-wellbore-reservoir system is altered during mud loss, as well as its consequent impact on near-wellbore state of stresses and critical mud weights. A fully coupled three dimensional thermal-poro-elastic model, integrated with a transient tubular-wellbore-reservoir heat flow model, is developed to evaluate near-wellbore stresses and pore pressure redistribution during mud loss. The forced convective heat transfer coefficients in both conduits-drillpipe and annulus-are rigorously determined as a function of local flow and fluid properties. The results reveal that continuous mud loss destabilizes the wellbore as the pressure window shifts considerably over time. Critical mud weights for both tensile and compressive failures decrease during mud loss over the entire length of the wellbore, in addition to the point of loss. During severe losses, the fracture gradient at the bottom of the well can decrease by over 1 ppg within the first hour. This can intensify the existing fracturing condition and allow the development of new fractures at other locations, which leads to further losses as time progresses. This model enables prediction of a more realistic operating window during lost circulation by taking additional thermally-induced effects into account. In addition, failure indexes during mud loss considering P-ρ-T coupling effect on a compressible mud column in the annulus are investigated with the proposed model. During drilling operations, especially Managed Pressure Drilling (MPD) and offshore applications with moderate to severe mud loss, the operation window should be modified by taking mud loss-induced thermal stresses into account. The mud type, wellbore geometry, circulation rate, and other parameters affect the magnitude of shift in critical mud weight during mud loss, hence evaluations should be based on specific cases. [ABSTRACT FROM AUTHOR]

Researchers have long investigated the difference between static and dynamic Young's modulus in terms of values and application. In field experiences, dynamic Young's modulus can often be calculated using logging data, while core data for static experiments in the lab are scarce. On the other hand, geomechanical analyses are traditionally based on static values. Therefore, it is essential to estimate static Young's modulus based on dynamic data for petroleum reservoir case studies. A number of empirical equations have been suggested to estimate static Young's modulus based on dynamic Young's modulus. However, the validity of these relations are limited and local. In this paper, 10 suggested relations were evaluated against an experimental dataset from different geographic locations. The validity of each relation was evaluated, and the results confirmed the dependency of these equations to the original datasets. Based on the concept of effective Young's modulus, we suggested a relationship to predict the value of static Young's modulus from dynamic Young's modulus and porosity data. The approach was performed for different rock types, and the predictions were found to be very accurate. This research explored different views on this aspect and facilitated better decision making to determine the static Young's modulus of rocks in the case where only dynamic data were available. [ABSTRACT FROM AUTHOR]

In recent years, the increasing energy demand has led the oil and gas industry to explore unconventional reservoirs. The hydraulic fracturing technique (fracking) has been adopted in order to increase the reservoir drainage area. Nevertheless, there is an environmental concern about the contamination of aquifers due to this technique. The operation design requires predicting the induced fracture geometry to avoid hazards related to fracking. Hydraulic fracturing changes the state of stress at crack tip leading to more uncertainties in the definition of crack geometry, especially in naturally fractured formations. For such, analytical solutions and numerical simulations have been employed in recent decades. Nevertheless, the numerical models require high computational effort. This paper proposes an artificial neural network (ANN) to predict the interaction between hydraulic fracture and natural fractures. We performed over 800 simulations to build the training database varying the rock mechanical properties and model parameters, such as the approach angle between hydraulic fracture and natural fracture, in-situ stress magnitudes, friction angle, and fracture energy. The ANN results are compared against analytical solutions and numerical models, showing excellent agreement. These results show that the trained neural network can predict fracture interaction accurately. They also suggest that the most sensible parameters were taken into account in the proposed ANN. • Considerable number of fracture interaction simulations to database. • Application of Artificial Intelligence Technique. • Verification of the results with analytical solutions and simulations using other meshes. • Applied case study. [ABSTRACT FROM AUTHOR]

Abstract: Due to low permeability of tight gas shale, production in commercial quantities requires effective hydraulic fracturing and horizontal drilling technologies. Therefore, understanding rock properties and earth''s stresses is an important step toward reservoir evaluation and ultimately development of these kinds of resources. Furthermore, successful production from such a complex formation is heavily dependent on selection of appropriate completion technology which requires having sufficient knowledge of borehole shape or say enlarged zones. Borehole enlargements or specifically breakouts provide valuable information for evaluation of in-situ stresses and verification of geomechanical models. Customarily used methods to identify breakouts, i.e., caliper and image logs, suffer from several limitations. In addition, good quality image logs are not usually available in shaly formations due to requirement of using oil-based mud. This led to the need for developing a new technique to identify borehole enlargement zones using petrophysical logs which are often acquired in majority of the wells. This study proposes a new multi-variable approach to identify borehole enlargement zones in tight gas shale using some petrophysical logs, mud weight and overburden stress data. This approach employs number of data processing techniques including Bayesian classification, wavelet decomposition and data fusion to determine borehole intervals with maximum likelihood of enlargement. This paper explains the methodology and presents its results in four study wells in Barnett gas shale. The study confirms the applicability and the generalization capability of the approach in shaly formations with a significant accuracy. [Copyright &y& Elsevier]

There are only a few related studies focused on the steam assisted gravity drainage (SAGD) dilation start-up technology (termed as dilation start-up in this paper), especially with true triaxial stress physical modelling experiments in the laboratory. Therefore, in order to better understand the dilation start-up process, four large-scale (1050 mm × 410 mm × 410 mm) true triaxial experiments of SAGD start-up with dual horizontal wells were conducted for the first time by using the oil sands from the Xinjiang oilfield, northwest China. The dilation process characterized by temperature changes at different positions inside the experimental samples was monitored in real time. The performance differences between dilation start-up and conventional start-up were discussed in detail, and the effects of dilation pressure and dilation time on the dilation process were also studied. The experimental results indicate that dilation start-up can significantly reduce the well communication time between injector and producer, and enhance the range of dilation zone and improve the uniformity of dilation zone along the horizontal wellbores. Moreover, we find that dilation pressure is an essential factor influencing the dilation effect. The average communication parameter increases by 5% if dilation pressure increases by 10% whereas the standard deviation of communication parameter decreases. The evolution of dilation zone with time shows that long-time dilation prompts the uniform propagation of dilation zone along the horizontal wellbores. This study provides guidance for the optimization of SAGD dilation start-up in shallow heavy oil reservoirs. • Four large-scale true triaxial experiments of SAGD start-up with dual horizontal wells were conducted. • Dilation process characterized by temperature changes inside the samples was monitored in real time. • Effects of dilation pressure and dilation time on the SAGD dilation start-up were studied. [ABSTRACT FROM AUTHOR]

Steam-assisted gravity drainage (SAGD) methods have been widely applied in oil-sands exploitation globally. SAGD processes are effective only after thermal and hydraulic communication between the injector and producer has been established during the start-up operation of the well pair. The geomechanical SAGD dilation startup has been considered a promising technology that can enhance permeabilities of heavy-oil reservoirs and reduce thermal conformance time. However, limited studies have focused on the practical operational procedures of geomechanical SAGD dilation startup. This paper presents the application of SAGD dilation startup technology in a shallow super heavy-oil reservoir in the Karamay oil field, China. The general reservoir geology and geomechanical characteristics were investigated and used to propose a practical approach to determine dilation initiation pressure. We also summarize the SAGD well completions and geomechanical SAGD dilation startup procedures. A case study using a real SAGD well is presented and analyzed. We then share the field operation procedures and results after dilation startup. The objective of the research was to reduce the steam circulation time and achieve uniform thermal conformance along the SAGD well. Our field results highlight the promising potential of using water injection to create a dilated zone and dramatically enhance reservoir permeability. The performance of SAGD dilation startup in the Karamay oil field is evaluated by comparing the cumulative oil production rate with those from SAGD wells using conventional startup. • The geomechanical properties of Karamay heavy oil reservoirs are characterized. • A practical approach to determine dilation initiation pressure for SAGD startup is proposed. • A field case study of geomechanical SAGD dilation startup is presented and analyzed. [ABSTRACT FROM AUTHOR]

The Efficient development of shale reservoirs becomes increasingly dependent upon infill wells in China to stabilize the gas production. The accurate calculation of dynamic evolution of stress field is important for the design of fracturing and infill wells. The extraction of gas flow results in stress-sensitive and significantly alters the original in-situ stress field, which brings difficulties on geomechanical design for fracturing treatment. Hitherto, the main factors that affect the principal stress alteration is unclear, especially when considering the interference between fractures and wells. Besides, the transport mechanisms of shale gas flow are complex, which bring difficulties in the modeling of deformable multi-continuum. In this paper, an adaptive model that couples multi-continuum matrix and discrete fractures is developed. According to the effective stress coefficients of matrix pores and natural fractures, the total deformation is decomposed into two parts: matrix pore pressure depletion induced deformation and natural fracture pressure depletion induced deformation. The model is then validated to simulate hydromechanical coupling processes in fractured-shale reservoirs during the production period. Sensitivity analysis of stress alteration is also performed to study the alteration angle of the minimum horizontal principal stress during production. The modeling results show that the pressure depletion in natural fractures is the fastest, which dominates the shale deformation. Besides, the gas desorption in organic matters enlarges the alteration angle of the minimum horizontal principal stress during production. Finally, we find the difference between adsorption rate and desorption rate, instead of the total adsorbed gas amount, determines the adsorbed gas production. • A hierarchical approach integrating DFNs with multi-continuum concept to model gas transport in shale. • Impacts of pressure depletion patterns of three continua on the stress field are considered. • The gas flow and the rock deformation are fully coupled. [ABSTRACT FROM AUTHOR]

Shale has typical characteristics of multi-scale space for gas storage and migration. It is suitable for description by a triple medium model composed of double continuous medium and discrete fracture model, and need to consider multiple migration mechanisms. Besides, during gas production, effective stress and desorption will cause the deformation of shale, leading to the dynamic changes in porosity and permeability. In this paper, a fully coupled model was established to evaluate the shale gas production dynamics, including the governing equation of shale deformation and the governing equation of gas migration in the matrix, micro-fractures, and hydraulic fractures, respectively. All processes are coupled by the dynamic models of porosity and permeability for matrix and micro-fractures, and by the gas exchange between different systems. The fully coupled model was solved by the finite element method through the PDE solver software named COMSOL Multiphysics. The rationality of this fully coupled model is verified by the production data of Barnett shale. The validated model was applied to study the effects of adsorption and geomechanics parameters on dynamic changes of porosity and permeability, and gas production. Moreover, the impact of primary fracture geometry and secondary fracture distribution parameters on production were also analyzed. Simulation results show that the adsorption parameters have essential effects on both gas flow and production; that the geomechanics parameters have important influences on the evolution of porosity and permeability; that optimizing the distribution and development of hydraulic fracture and secondary fracture is beneficial to the efficient development of shale gas. • A fully coupled model is established to evaluate the shale gas production dynamics. • The dynamic models of apparent permeability considering compression and matrix shrinkage are derived. • A complex hydraulic fracture network is considered in the area of Stimulated Reservoir Volume. [ABSTRACT FROM AUTHOR]