Infill-Well Fracturing Optimization in Tightly Spaced Horizontal Wells

SPE Journal ◽  
2016 ◽  
Vol 22 (02) ◽  
pp. 582-595 ◽  
Author(s):  
Reza Safari ◽  
Richard Lewis ◽  
Xiaodan Ma ◽  
Uno Mutlu ◽  
Ahmad Ghassemi
Keyword(s):  
Stress State ◽  
Stress Field ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Horizontal Wells ◽  
In Situ Stress ◽  
Work Flow ◽  
Treatment Schedule ◽  
Reservoir Geomechanics

Summary Cost-effective production from unconventional reservoirs relies on creating new reservoir surface area where fractures are extended into and produce from undepleted zones. Field observations indicate that infill-well fractures could propagate toward nearby producers and depleted zones. This communication between infill and producer wells has been seen to cause casing collapse, and negatively affect current production levels. In this paper, an integrated reservoir/geomechanics/fracture work flow is established to optimize infill-well treatment schedule and to minimize fracture communication between wells. In particular, the paper presents: (i) numerical evaluation of depletion-induced stress changes between tightly spaced producers, (ii) hydraulic-fracture curving in a perturbed stress field, and (iii) hydraulic-fracture communication between wells, and infill-well treatment-design optimization to maximize production. A systematic study of depletion effects and the key parameters that control fracture curving allows us to improve the infill-well fracture design by minimizing the communication between wells while maximizing the hydraulic-fracture extent. Depletion perturbs the in-situ stress tensor in the formation around fractured horizontal wells. The analysis shows that the perturbed-stress field is a function of stress/formation anisotropy, fluid mobility, pore pressure, operating bottomhole pressure (BHP), and Biot's constant. A fracture-propagation model, coupled with the altered in-situ stress field, is used to predict the hydraulic-fracture propagation path(s) and their radius of curvature (i.e., if the stress state dictates that the fractures should curve). The analyses are performed for different infill-well treatment schedule(s), and yield the most-likely fracture geometries (taking into account uncertainties in a shale formation). Resulting infill-well fracture geometries are imported into a reservoir simulator to quantify the production and to identify the optimal design parameters. The coupled work flow (reservoir/geomechanics/fracture) is then applied to a field example to demonstrate the feasibility of its application at the reservoir scale. The results show that (a) infill-well fractures between tightly spaced horizontal wells can intentionally be curved and (b) communication between wells and fracture-coverage area can be controlled by adjusting stimulation parameters to maximize recovery. Forward coupled modeling can be useful in guiding when to drill infill wells before the altered-stress state negatively affects production outcome.

Hydraulic Fracture Geometry: Fracture Containment in Layered Formations

1982 ◽  
Vol 22 (03) ◽  
pp. 341-349 ◽  
Author(s):  
H.A.M. van Eekelen
Keyword(s):  
Stress Field ◽  
Cross Section ◽  
Horizontal Plane ◽  
Fluid Pressure ◽  
Vertical Plane ◽  
Fracture Propagation ◽  
In Situ Stress ◽  
Design Procedures ◽  
Fracture Height

Abstract One of the main problems in hydraulic fracturing technology is the prediction of fracture height. In particular, the question of what constitutes a barrier to vertical fracture propagation is crucial to the success of field operations. An analysis of hydraulic fracture containment effects has been performed. The main conclusion is that in most cases the fracture will penetrate into the layers adjoining the pay zone, the depth of penetration being determined by the differences in stiffness and in horizontal in-situ stress between the pay zone and the adjoining layers. For the case of a stiffness contrast, an estimate of the penetration depth is given. Introduction Current design procedures for hydraulic fracturing of oil and gas reservoirs are based predominantly on the fracturing theories of Perkins and Kern, Nordgren, and Geertsma and de Klerk. In the model proposed by Perkins and Kern, and improved by Nordgren, the formation stiffness is concentrated in vertical planes perpendicular to the direction of fracture propagation, The fracture cross section in these planes is assumed elliptical, and the stiffness of the formation in the horizontal plane is neglected. In the model proposed by Geertsma and de Klerk, the stiffness of the formation is concentrated in the horizontal plane. The fracture cross section in the vertical plane is assumed rectangular, and the stiffness in the vertical plane is neglected. In both models, the fluid pressure is assumed a function of the distance from the borehole, independent of the transverse coordinates. The theory by Perkins and Kern is more appropriate for long fractures (L/H >1, where L and H are length and height of the fracture), whereas the model by Geertsma and de Klerk is applicable for short fractures, L/H less than 1. The main shortcoming of these fracture-design procedures is that they assume a constant, preassigned fracture height. H. The value of H has a strong influence on the result, for fracture length, fracture width, and proppant transport. Usually, the estimated fracture height is based on assumed "barrier action" of rock layers above and below the pay zone. This situation is rather unsatisfactory. Moreover, if these layers do not contain the fracture, large volumes of fracturing fluid may be lost in fracturing unproductive strata, and communication with unwanted formations may be opened up. Whether an adjacent formation will act as a fracture barrier may depend on a number of factors: differences in in-situ stress, elastic properties, fracture toughness, ductility, and permeability; and the bonding at the interface. We analyze these factors with respect to their relative influence on fracture containment. Differences in in-situ stress and differences in elastic properties affect the global or overall stress field around the fracture, and, hence, the three-dimensional shape of the fracture. This shape, together with the horizontal and vertical fracture propagation rates, determines the fluid pressure distribution in the fracture, which in turn affects the stress field around the fracture. Consequently, the elastic stress field, the fluid pressure field, and the fracture propagation pattern are intimately coupled, which makes the fracture propagation problem a complicated one. Whether at a certain point of the fracture edge the fracture will propagate is determined by the intensity of the stress concentration at that point. This stress concentration depends on the global stress distribution in and around the fracture, but it also is affected directly by local ductility, permeability, and elastic modulus in the tip region. SPEJ P. 341^

scholarly journals A multi-stage 3-D stress field modelling approach exemplified in the Bavarian Molasse Basin

Solid Earth ◽  
2016 ◽  
Vol 7 (5) ◽  
pp. 1365-1382 ◽  
Author(s):  
Moritz O. Ziegler ◽  
Oliver Heidbach ◽  
John Reinecker ◽  
Anna M. Przybycin ◽  
Magdalena Scheck-Wenderoth
Keyword(s):  
Stress State ◽  
Stress Field ◽  
Large Scale ◽  
Scattered Data ◽  
In Situ Stress ◽  
Scale Model ◽  
Molasse Basin ◽  
Multi Stage ◽  
Subsurface Engineering

Abstract. The knowledge of the contemporary in situ stress state is a key issue for safe and sustainable subsurface engineering. However, information on the orientation and magnitudes of the stress state is limited and often not available for the areas of interest. Therefore 3-D geomechanical–numerical modelling is used to estimate the in situ stress state and the distance of faults from failure for application in subsurface engineering. The main challenge in this approach is to bridge the gap in scale between the widely scattered data used for calibration of the model and the high resolution in the target area required for the application. We present a multi-stage 3-D geomechanical–numerical approach which provides a state-of-the-art model of the stress field for a reservoir-scale area from widely scattered data records. Therefore, we first use a large-scale regional model which is calibrated by available stress data and provides the full 3-D stress tensor at discrete points in the entire model volume. The modelled stress state is used subsequently for the calibration of a smaller-scale model located within the large-scale model in an area without any observed stress data records. We exemplify this approach with two-stages for the area around Munich in the German Molasse Basin. As an example of application, we estimate the scalar values for slip tendency and fracture potential from the model results as measures for the criticality of fault reactivation in the reservoir-scale model. The modelling results show that variations due to uncertainties in the input data are mainly introduced by the uncertain material properties and missing SHmax magnitude estimates needed for a more reliable model calibration. This leads to the conclusion that at this stage the model's reliability depends only on the amount and quality of available stress information rather than on the modelling technique itself or on local details of the model geometry. Any improvements in modelling and increases in model reliability can only be achieved using more high-quality data for calibration.

Containment of Massive Hydraulic Fractures

1978 ◽  
Vol 18 (01) ◽  
pp. 27-32 ◽  
Author(s):  
E.R. Simonson ◽  
A.S. Abou-Sayed ◽  
R.J. Clifton
Keyword(s):  
Hydraulic Fracture ◽  
Oil And Gas ◽  
Fracture Propagation ◽  
Rocky Mountain ◽  
In Situ Stress ◽  
Hydraulic Fractures ◽  
Pressure Gradients ◽  
In Situ Stresses ◽  
Gas Bearing

Abstract Hydraulic fracture containment is discussed in relationship to linear elastic fracture mechanics. Three cases are analyzed,the effect of different material properties for the pay zone and the barrier formation,the characteristics of fracture propagation into regions of varying in-situ stress, propagation into regions of varying in-situ stress, andthe effect of hydrostatic pressure gradients on fracture propagation into overlying or underlying barrier formations. Analysis shows the importance of the elastic properties, the in-situ stresses, and the pressure gradients on fracture containment. Introduction Application of massive hydraulic fracture (MHF) techniques to the Rocky Mountain gas fields has been uneven, with some successes and some failures. The primary thrust of rock mechanics research in this area is to understand those factors that contribute to the success of MHF techniques and those conditions that lead to failures. There are many possible reasons why MHF techniques fail, including migration of the fracture into overlying or underlying barrier formations, degradation of permeability caused by application of hydraulic permeability caused by application of hydraulic fracturing fluid, loss of fracturing fluid into preexisting cracks or fissures, or extreme errors in preexisting cracks or fissures, or extreme errors in estimating the quantity of in-place gas. Also, a poor estimate of the in-situ permeability can result in failures that may "appear" to be caused by the hydraulic fracture process. Previous research showed that in-situ permeabilities can be one order of magnitude or more lower than permeabilities measured at near atmospheric conditions. Moreover, studies have investigated the degradation in both fracture permeability and formation permeability caused by the application of hydraulic fracture fluids. Further discussion of this subject is beyond the scope of this paper. This study will deal mainly with the containment of hydraulic fractures to the pay zone. In general, the lithology of the Rocky Mountain region is composed of oil- and gas-bearing sandstone layers interspaced with shales (Fig. 1). However, some sandstone layers may be water aquifers and penetration of the hydraulic fracture into these penetration of the hydraulic fracture into these aquifer layers is undesirable. Also, the shale layers can separate producible oil- and gas-bearing zones from nonproducible ones. Shale layers between the pay zone and other zones can be vital in increasing successful stimulation. If the shale layers act as barrier layers, the hydraulic fracture can be contained within the pay zone. The in-situ stresses and the stiffness, as characterized by the shear modulus of the zones, play significant roles in the containment of a play significant roles in the containment of a hydraulic fracture. The in-situ stresses result from forces in the earth's crust and constitute the compressive far-field stresses that act to close the hydraulic fracture. Fig. 2 shows a schematic representation of in-situ stresses acting on a vertical hydraulic fracture. Horizontal components of in-situ stresses may vary from layer to layer (Fig. 2). For example, direct measurements of in-situ stresses in shales has shown the minimum horizontal principal stress is nearly equal to the overburden principal stress is nearly equal to the overburden stress. SPEJ P. 27

Investigation of the influence of natural fractures and in situ stress on hydraulic fracture propagation using a distinct-element approach

2015 ◽  
Vol 52 (7) ◽  
pp. 926-946 ◽  
Author(s):  
N. Zangeneh ◽  
E. Eberhardt ◽  
R.M. Bustin
Keyword(s):  
Rock Mass ◽  
Hydraulic Fracturing ◽  
Hydraulic Fracture ◽  
Distinct Element ◽  
Fracture Propagation ◽  
In Situ Stress ◽  
Natural Fractures ◽  
Geological Conditions ◽  
Hydraulic Fracture Propagation

Hydraulic fracturing is the primary means for enhancing rock mass permeability and improving well productivity in tight reservoir rocks. Significant advances have been made in hydraulic fracturing theory and the development of design simulators; however, these generally rely on continuum treatments of the rock mass. In situ, the geological conditions are much more complex, complicated by the presence of natural fractures and planes of weakness such as bedding planes, joints, and faults. Further complexity arises from the influence of the in situ stress field, which has its own heterogeneity. Together, these factors may either enhance or diminish the effectiveness of the hydraulic fracturing treatment and subsequent hydrocarbon production. Results are presented here from a series of two-dimensional (2-D) numerical experiments investigating the influence of natural fractures on the modeling of hydraulic fracture propagation. Distinct-element techniques applying a transient, coupled hydromechanical solution are evaluated with respect to their ability to account for both tensile rupture of intact rock in response to fluid injection and shear and dilation along existing joints. A Voronoi tessellation scheme is used to add the necessary degrees of freedom to model the propagation path of a hydraulically driven fracture. The analysis is carried out for several geometrical variants related to hypothetical geological scenarios simulating a naturally fractured shale gas reservoir. The results show that key interactions develop with the natural fractures that influence the size, orientation, and path of the hydraulic fracture as well as the stimulated volume. These interactions may also decrease the size and effectiveness of the stimulation by diverting the injected fluid and proppant and by limiting the extent of the hydraulic fracture.

Advanced Semianalytical Geomechanical Model for Wellbore-Strengthening Applications

SPE Journal ◽  
2015 ◽  
Vol 20 (06) ◽  
pp. 1276-1286 ◽  
Author(s):  
Mojtaba P. Shahri ◽  
Trevor T. Oar ◽  
Reza Safari ◽  
Moji Karimi ◽  
Uno Mutlu
Keyword(s):  
Stress Field ◽  
In Situ Stress ◽  
Work Flow ◽  
Fracture Characteristics ◽  
Fracture Width ◽  
Lost Circulation ◽  
Fracture Length ◽  
Width Distribution ◽  
Wellbore Strengthening

Summary Drilling depleted reservoirs often encounters a host of problems leading to increases in cost and nonproductive time. One of these problems faced by drillers is lost circulation of drilling fluids, which can lead to greater issues such as differential sticking and well-control events. Field applications show that wellbore strengthening effectively helps reduce mud-loss volume by increasing the safe mud-weight window. Wellbore-strengthening applications are usually designed on the basis of induced-fracture characteristics (i.e., fracture length, fracture width, and stress-intensity factor). In general, these fracture characteristics depend on several parameters, including in-situ stress magnitude, in-situ stress anisotropy, mechanical properties, rock texture, wellbore geometry, mud weight, wellbore trajectory, pore pressure, natural fractures, and formation anisotropy. Analytical models available in the literature oversimplify the fracture-initiation and fracture-propagation process with assumptions such as isotropic stress field, no near-wellbore stress-perturbation effects, vertical or horizontal wells only (no deviation/inclination), constant fracture length, and constant pressure within the fracture. For more-accurate predictions, different numerical methods, such as finite element and boundary element, have been used to determine fracture-width distribution. However, these calculations can be computationally costly or difficult to implement in near-real time. The aim of this study is to provide a fast-running, semianalytical work flow to accurately predict fracture-width distribution and fracture-reinitiation pressure (FRIP). The algorithm and work flow can account for near-wellbore-stress perturbations, far-field-stress anisotropy, and wellbore inclination/deviation. The semianalytical algorithm is modeled after singular integral formulation of stress field and solved by use of Gauss-Chebyshev polynomials. The proposed model is computationally efficient and accurate. The model also provides a comprehensive perspective on formation-strengthening scenarios; a tool for improved lost-circulation-materials design; and an explanation of how they are applicable during drilling operation (in particular, through depleted zones). Sensitivity analysis included in this paper quantifies the effect of different rock properties, in-situ-stress field/anisotropy, and wellbore geometry/deviation on the fracture-width distribution and FRIP. In addition, the case study presented in this paper demonstrates the applicability of the proposed work flow in the field.

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