Walters D.A.,Taurus Reservoir Solutions |
Han G.,Hess Corporation
46th US Rock Mechanics / Geomechanics Symposium 2012 | Year: 2012
Fracpack completions are widely used as the most efficient sand control method in deep GOM fields. For fracpacked wells, rock stability issues are often no longer considered when well drawdown is decided. While fracpacks can prevent sand from entering the wellbore, it is not unusual to witness skin increase and productivity loss over production time. Contradictory to conventional thought that productivity loss results from flow-related fines migration or mechanical failure of completion equipment, this paper documents a field study where it is found the fracpack stimulation and completion surprisingly increases the risk of rock failure around the fracture resulting in severe production decline. The well studied is a fracpacked condensate producer from a high permeability turbidite sandstone reservoir with a strong water drive. After 2-3 years of production, well productivity declines more quickly than expected. Well test analysis attributed the productivity loss to skin at the fracture face and additional permeability damage around the fracture. Extensive rock lab tests have shown that, despite high fluid flow rate, little fines are produced. However, significant permeability reduction occurs when the loading stress increases to a threshold level. The solids produced and collected consist of mainly sand chips and particles. In preparation for geomechanical modeling a rock constitutive model has been developed and calibrated to drilling events, logs, and core data. A detailed geomechanical model with an embedded fracture has been coupled with fluid flow near the wellbore to simulate the fracpack followed by drawdown and long-term depletion investigating rock stability around the fracture. Simulation results indicate that the placement of a propped hydraulic fracture during fracpack operations has two side effects: on one hand, it increases rock strength at most locations around the fracture, which is consistent with what industry has believed; on the other hand, there are certain areas, especially surrounding the fracture tip that have been weakened due to elevated shear stress levels. Rock failure occurs at a certain level of drawdown and depletion, either in shear failure mode or compaction failure mode, depending on the location with respect to the fracture, rock strength, and stress path. It is postulated that this depletion induced failure mobilizes the fines which are then transported to the fracture resulting in plugging of the completion. A stress path analysis is used in conjunction with the calibrated cap and cone failure surface to estimate the critical drawdown and depletion causing rock failure. This analysis can be used to manage drawdown as well as investigate variations of the fracpack completion to reduce the risk of fines mobilization. Copyright 2012 ARMA, American Rock Mechanics Association.
Jimenez B.L.,University of Calgary |
Yu G.,IHS |
Aguilera R.,University of Calgary |
Settari A.,Taurus Reservoir Solutions
SPE Production and Operations | Year: 2015
The determination of the minimum horizontal (in-situ) stress (MHS) is one of the most-important aspects in the characterization of geomechanical behavior of petroleum reservoirs because a good knowledge of such stress is critical in many activities of practical importance, including design of hydraulic-fracturing treatments and estimation of the distribution of MHS for reservoir-simulation purposes. The main objective of the study is to calibrate well logs with available mini-frac data for estimating the MHS in the tight-gas Monteith formation, Nikanassin Group of the Western Canada Sedimentary Basin. For deep formations such as Monteith, the minimum stress is generally horizontal. Thus, the focus of this research is the MHS of the Monteith formation. First, actual values of the MHS at different well locations are acquired from the analysis of surface-pressure data during minifrac treatments. Next, the estimates calculated from an existing correlation and from actual mini-frac data are matched for calibration purposes. Finally, vertical and horizontal Biot's constant values are determined to generate a correlation applicable to the Monteith formation. Vertical Biot's constant ranging between 0.1 and 0.45 is obtained in this study, whereas horizontal Biot's constant is found to vary from 0.94 to 1.0. Three vertical wells located in the same township with available compressional and shear sonic logs and mini-frac data are selected for this work. The Monteith was hydraulically fractured in these wells in isolation. This aspect is important because there are many commingled completions in the area from which selective Monteith data are not available. Five additional wells in the same general area are selected to assist in the analysis. It is concluded that assuming vertical and horizontal Biot's constants equal to 1.0 is not appropriate for the Monteith formation in the study area. The procedure presented in this paper, which uses real data, is robust and has the potential to help in obtaining more-reliable geomechanical values in other tight formations around the world. Copyright © 2015 Society of Petroleum Engineers.
Teatini P.,University of Padua |
Gambolati G.,University of Padua |
Ferronato M.,University of Padua |
Settari A.T.,University of Calgary |
Walters D.,Taurus Reservoir Solutions
Journal of Geodynamics | Year: 2011
The subsurface injection of fluid (water, gas, vapour) occurs worldwide for a variety of purposes, e.g. to enhance oil production (EOR), store gas in depleted gas/oil fields, recharge overdrafted aquifer systems (ASR), and mitigate anthropogenic land subsidence. Irrespective of the injection target, some areas have experienced an observed land uplift ranging from a few millimetres to tens of centimetres over a time period of a few months to several years depending on the quantity and spatial distribution of the fluid used, pore pressure increase, geological setting (depth, thickness, and area extent), and hydro-geomechanical properties of the injected formation. The present paper reviews the fundamental geomechanical processes that govern land upheaval due to fluid injection in the subsurface and presents a survey of some interesting examples of anthropogenic uplift measured in the past by the traditional levelling technique and in recent times with the aid of satellite technology. The examples addressed include Long Beach, Santa Clara Valley, and Santa Ana basin, California; Las Vegas Valley, Nevada; Cold Lake and other similar sites, Canada; Tokyo and Osaka, Japan; Taipei, Taiwan; Krechba, Algeria; Upper Palatinate, Germany; Chioggia and Ravenna, Italy. © 2010 Elsevier Ltd.
Nassir M.,Taurus Reservoir Solutions |
Settari A.,Taurus Reservoir Solutions |
Wan R.,University of Calgary
SPE Journal | Year: 2014
Hydraulic fracturing is essential for the economic development of tight gas reservoirs and shale-gas reservoirs. Current techniques are unable to predict the stimulated-reservoir-volume (SRV) dependence on fracturing-job and rock-mechanics parameters, which precludes any meaningful optimization. In the authors' previous work on the SRV-propagation prediction, the combined tensile/ shear fracturing model applied to the fracturing of tight gas formations has shown the creation of a relatively narrow, focused SRV that resembled behavior dominated by a single fracture. In this work, the model has been significantly improved by the implementation of a rigorous full Newton elasto-plastic solution of the geomechanics of rock containing induced fractures. The results reveal interesting features of complex-fracture propagation in tight formations, which are in broad agreement with the shapes of SRVs obtained from microseismic imaging. The developed code is flexible enough to allow either tensile or shear fracturing or the occurrence of both to be examined on the basis of initial reservoir conditions. Different cases of 2D and 3D simulations will be presented that demonstrate some important features of the process. First, it is found that a wide SRV can result in cases in which initial reservoir conditions are close to the shear-fracturing point, such as in formations with microfractures, partially cemented natural fractures, and abnormally high initial pore pressure. Second, the SRV width is found to depend on the horizontal stress contrast, as expected. Third, wide SRV growth is associated with constant or increasing pumping pressure necessary for further failed-zone growth as a result of the loss of elastic coupling by off-planar failure propagation. Further, under high injection pressure, an efficient fracture elasto-plastic constitutive model developed can drive both maximal and minimal effective stresses to zero or tensile, and, therefore, the creation of tensile fracturing can be predicted simultaneously with shear fracturing. This will then provide a means of modeling proppant transport. The new model is a significant step toward the development of an integrated predictive tool for the optimization of shale-gas development. Copyright © 2014 Society of Petroleum Engineers.
Hocking G.,Geo Sierra LLC |
Walters D.A.,Taurus Reservoir Solutions
Society of Petroleum Engineers - SPE Heavy Oil Conference Canada 2013 | Year: 2013
Performance of conventional, steam-assisted gravity drainage (SAGD) horizontal well completions can be significantly impacted in formations with low vertical permeability and interbedded mudstone layers impeding vertical drainage. Also, because of shallow depth, caprock integrity, and/or thief zone issues, the lower operating steam pressure for SAGD completions can impact its ability to grow the steam chamber vertically in a timely manner. Such performance degradation results in lower production rates and often higher steam oil ratios. A vertical well injector/producer was proposed that consists of vertical, propped planes at varying azimuths installed from the bottom to the top of pay. Steam is injected at the top of the pay and liquids are extracted at the bottom. The well operates immediately in SAGD mode (i.e., the continuous injection of steam and the continuous extraction of liquids), resulting in peak production achieved within 30 to 45 days. Reservoir simulations show that the single-well SAGD system's performance is superior to a conventional SAGD completion, achieving greater than 2xNPV10 (net present value) of conventional SAGD in clean McMurray channel sand. Incorporating multiple vertical producer wells with a single central vertical SAGD injector/producer well, yields system performance far superior to a conventional SAGD completion, achieving greater than 6xNPV10 of a conventional SAGD completion in clean McMurray channel sand. The oil production rate for the vertical SAGD system with multiple producers is 4x faster than a conventional SAGD completion, with a greater recovery factor, and a lower cumulative steam oil ratio (SOR) of 1.5 compared to 2.5 resulting in a 40% saving in both Capex and Opex. Simulations of the system in variable geology, indicate that the vertical drainage efficiency of the system is virtually independent of geology, provided the multi-azimuth, high permeability propped vertical planes connect the wells hydraulically and are constructed continuously throughout the pay thickness. Copyright 2013, Society of Petroleum Engineers.