The East Duvernay shale basin is the newest addition to the list of prolific reservoirs in Western Canada. Over the last 3 years, horizontal drilling and multistage hydraulic fracturing have increased significantly. Because much of the play is still relatively new, much of the drilling has been limited to single wells or two wells per pad. Due to the low permeability of the matrix, hydraulic fracturing is required to unlock the full potential of the East Duvernay field. Because geomechanics is a critical factor in determining the effectiveness of hydraulic fracture propagation, we examined how varying the pore pressure profiles affects modeled in situ stresses, hydraulic fracture geometries, and overall field optimization.
The pore pressure varies across the East Duvernay shale basin with the depth of the reservoir and other geomechanical parameters. The stresses in the Ireton, Upper Duvernay, Lower Duvernay, and Cooking Lake reservoirs also varies from the West to the East shale basins. High-tier logging, core measurements, and field data were used to build a mechanical earth model, which is then input for hydraulic fracture simulations. Whole core images and image logs indicate the Duvernay to be a naturally fractured reservoir. Because pore pressure is a direct input into the interpretation for in situ stresses, we sensitized on seven pore pressure profiles through the Ireton, Upper and Lower Duvernay, and Cooking Lake reservoirs. Typical pumping design currently being implemented in the Upper Duvernay was used to determine hydraulic fracture geometry based on the various in situ stress profiles. Black oil PVT models were built to run numerical reservoir simulation production forecasts to understand the effect of variations in geomechanical properties on well production performance. The effect of the varying hydraulic fracture properties on well spacing was also investigated for the seven pore pressure profiles, by combining the complex hydraulic fracturing and reservoir simulation.
The results clearly indicated the need to better understand, quantify, and constrain the in situ stress profiles variations with changes in pore pressure models. Hydraulic fracture length is greater within the Upper Duvernay when a constant pore pressure is modeled in the Ireton, Duvernay and the Cooking Lake, which leads to an overestimation of production. If a normal pore pressure is modeled in the Ireton with overpressure in the Duvernay, the hydraulic fracture grows into the Ireton and gives a more realistic production forecast. When the modeled pore pressure is gradually ramped up from the Lower Ireton into the Duvernay, slightly greater fracture length is created in the Duvernay but not enough to make a huge difference in forecasted production. These varying results for the modeled hydraulic fracture geometries impact the optimum number of wells per section.
As more wells come on production and the economic viability of the play is proven, operators will drill more wells per section. Thoroughly understanding the variations in geomechanics across the formations above and below the Duvernay is important. This objective of this study was to drive the conversation about the data that need to be collected and tests that should be run to support the optimization of economic development of the play for years to come.
Analytically-derived criteria are presented for the orientation of fracture initiation from horizontal wellbores drilled in porous-permeable (poroelastic) media. This involves drilling-induced tensile fractures (DITFs) from non-perforated wellbores and completion-induced hydraulic fractures (CIHFs) from perforated wellbores with cylindrical perforation geometry. The criteria are developed considering the tangential stresses on two points (extremes) around the base of the perforation; one for the initiation of longitudinal fractures and another for the initiation of transverse fractures, with respect to the wellbore. In-situ stress state, wellbore pressure, and the formation's mechanical and poroelastic properties are independent variables that are shown to control the orientation of the initiated hydraulic fractures; the dependent variable.
The DITF orientation can be used to constrain the magnitude of the maximum horizontal stress; the most difficult aspect of the in-situ stress tensor to constrain. Transverse CIHF initiation only occurs over a narrow wellbore pressure-at-breakdown window, while longitudinal initiation occurs at comparatively higher wellbore pressures. However, transverse CIHF initiation occurs more frequently than transverse DITFs, because the presence of perforations aids transverse fracture initiation. The region of the in-situ stress states where transverse initiation is promoted is shown in dimensionless plots for perforated and non-perforated wellbores. Fracture initiation criteria for specific cases presented can be used to predict the orientation of fracture initiation in oilfield operations.
The orientation of CIHFs controls the productivity of hydrocarbon reservoirs. Productivity from low permeability formations is greatly improved having multiple fractures oriented transversely rather than longitudinally, relative to a horizontal wellbore. Fracture initiation often follows a plane different to the final fracture propagation plane. Stress re-orientation in the near-wellbore region may promote fracture initiation of different orientation than the orientation dictated by the far-field stresses. The range of in-situ stress states in which transverse fracture initiation is promoted increases as Biot's poroelastic coefficient,
ABSTRACT: Fracture initiation often follows a plane different to the final fracture propagation plane. Stress reorientation in the near-wellbore region may promote fracture initiation of different orientation than the one dictated by the far-field stresses. A three-dimensional numerical analysis using a geomechanical model is performed to assess an analytical orientation criterion for fracture initiation in perforated wellbores. This is accomplished by considering the tangential stresses on two points (extremes) around the base of the perforation; one for the initiation of transverse fractures and another for the initiation of longitudinal fractures. In-situ stress state, wellbore pressure, perforation geometry and the formation’s mechanical properties are independent variables that are shown to control the orientation of the initiated hydraulic fractures; the dependent variable.
We find that it is likely for typical hydraulic fracture treatments to achieve longitudinal fracture initiation in horizontal wells as transverse initiation will only occur over a narrow window of conditions including low wellbore pressure at breakdown and formation tensile strength. In contradiction with existing analytical models, the numerical study shows that the tangential stress which induces transverse fracture initiation is a function of wellbore pressure just as the stress inducing longitudinal fracture initiation. This makes the breakdown pressure window for transverse fracture initiation smaller compared to the prediction of the analytical model.
Hydraulic fracturing is a reservoir stimulation method used since the 1940s. This is accomplished by high pressure fluid injection which either creates cracks that propagate through the rock matrix or can reopen natural pre-existing fractures. Commonly, 20 to 40 fracture stages are placed in a horizontal well with four or more fractures pumped per stage simultaneously. The industrial impact of this technology has been massive and is responsible for the advances in the development of tight unconventional petroleum resources such as shale gas and oil (Michael, 2014 and Michael, 2016a).
The hydraulic fracture orientation controls the well productivity from hydrocarbon reservoirs. In this study we investigate critical parameters controlling the orientation of hydraulic fracture initiation in perforated horizontal wellbores. Productivity from low permeability (“tight”) formations is greatly improved having multiple fractures oriented transversely rather than longitudinally relative to a horizontal wellbore. This is useful for completion design engineers; when targeting low permeability formations, horizontal wells should be made to induce multiple transverse fractures, as opposed to longitudinal fractures which are more effective in higher permeability formations.
Interpretation of logs from an exploration pilot well and a lateral drilled from the pilot in the Late Cretaceous Natih formation in the Sultanate of Oman was used for designing a multistage hydraulic fracturing treatment. A high-tier logging suite including borehole image, advanced dipole sonic, geochemical, and triple combo data was acquired in both wellbores. The objective of the pilot hole was to select the best landing point in terms of reservoir quality (RQ) and completion quality (CQ) so that a horizontal well could be drilled and multistage stimulations performed in the organic-rich Natih B source rock.
In contrast to much of North America, significant tectonic forces are frequently present in this region. The geomechanical setting might thus strongly affect hydraulic fracture initiation, propagation and proppant placement. It therefore plays an important role in lateral landing point selection. Borehole images, integrated with petrophysical and geomechanical log properties, were used to identify the optimum landing zone. Breakouts as well as longitudinal and transverse drilling-induced fractures were identified on the pilot borehole images over the Natih Formation, indicating a large horizontal stress anisotropy and a compressional tectonic setting. An interval from which vertical hydraulic fractures would initiate at low initiation pressure and grow vertically to contact intervals with good RQ was selected as the target lateral landing point. Image and dipole sonic data were acquired in the horizontal well, and both longitudinal and transverse induced fractures were identified. Those data were used to selectively place hydraulic fracturing stages. Diagnostic injection tests on each stimulation treatment confirmed low fracture initiation pressures and the creation of vertical hydraulic fractures, thus validating the selection of both the landing point and the location of the hydraulic fracture initiation points. All treatments were successfully placed to completion.
This paper demonstrates that a workflow based on the combination of image and dipole sonic logs in both a pilot well and a lateral drilled from the pilot enables the creation of vertical hydraulic fractures at moderately low initiation pressures and successful placement of stimulation treatments in the lateral. This technique shows promise for effective hydraulic fracturing in regions where significant tectonic forces are present.
Rana, Rohit (Independent Geomechanics and Pore Pressure Consultant) | Hansen, Kirk S. (Shell India Markets Private Limited) | Kandpal, Jyoti (Shell India Markets Private Limited) | Kumar, Rajan (Shell India Markets Private Limited) | Schutjens, Peter (Shell India Markets Private Limited) | Muro, Leytzher (Shell India Markets Private Limited) | Rees, Daniel (Brunei Shell Petroleum Co Sdn Bhd) | Latief, Agus I. (Brunei Shell Petroleum Co Sdn Bhd)
Knowledge of the in-situ stress state and how it varies with reservoir depletion is important for the design and execution of in-fill drilling. This paper highlights the key geomechanical aspects and their usage in planning of wells through severely depleted (up to 25 MPa) and overpressured zones within a very short depth interval (few 10s of m), in an onshore gas field in Brunei. With focus shifting from oil to deep-gas development, drilling complications include risks of wellbore instability, excessive mud loss and internal blowouts, as well as differential sticking in the depleted reservoirs. Moreover, fracturing of the depleted sands while drilling infill wells carries the risk of jeopardizing production at nearby producing wells because of locally altered flow paths. The risks were evaluated by application of empirical and analytical geomechanical models of stress changes with depletion, and by elasto-plastic finite element models of borehole instability (collapse) due to shear failure.
Our results show that for an average depletion rate of 1 MPa/year, the drilling window (difference between maximum allowable mud weight controlled by fracture pressure and minimum mud weight controlled by formation pore pressure or borehole collapse pressure, whichever is greater) is likely to remain open for the coming 12 years. Minifrac or extended leak-off tests at different stages of field development should be taken to monitor stress changes within the reservoirs and provide updates for calibration of the geomechanical model.
Next to showing the geomechanical model results and their application to drilling, we demonstrate the refinement of pore pressure/fracture pressure predictions (i.e. narrowing down the uncertainty in the drilling window) for mature fields where producing "from the bottom up" has not been feasible. We also indicate how risks associated with drilling through depleted/undepleted reservoir sequences in a single hole section can be managed to as low as reasonably practicable with the help of geomechanical input. These results "open the door" for accessing deeper potential pay zones by drilling through severely depleted formations.
ABSTRACT: Hydraulic fracturing (HF) stimulation of oil wells have made possible the current flourishing oil production from pay zones. Longer initial fractures length and shorter spacing increases oil production. However, these operations usually are expensive and may even cause interference and subsequent reduction in oil production. Analytical models do not consider fracture interference and assume equal fracture half-lengths. Therefore, optimizing initial fractures geometry using numerical methods is of high importance in a successful HF operation. Various geometrical parameters of initial HF cracks including patterns, spacings and crack lengths have been modeled using a higher order displacement discontinuity method (HODDM) in a horizontal oil well. Some of the most encountered problems in HF processes such as fracture interference and fracture arrest have been detected through numerical simulations. Considering several different loading cases, most suitable crack geometrical parameters have been obtained. The results are also confirmed by in-situ measurements available in the literature.
The combination of multiple hydraulic fracturing (HF) and horizontal drilling has led to an enhanced production of hydrocarbon from reservoirs with low permeability. The primary objective of HF is to improve the natural connections of wellbores and reservoirs. Many fundamental aspects in HF are yet ambiguous and require further investigations. One of these aspects is the arrangement and orientation of the initial perforations. The orientation of a wellbore and the in-situ stress regime have important effects on the initiation of a HF process (Rahman et al. 2000, Abdollahipour et al. 2016).
Multiple transverse hydraulic fractures are the main contributor to a high hydrocarbon production (Freeman et al. 2013, Zhao et al. 2014, Guo et al. 2014, Abdollahipour et al. 2016). Optimization of the hydraulic fracture parameters such as the fracture spacing and fracture half-length is of paramount importance.
Previous works have established that higher number of fractures in the formation around the wellbore results in a faster hydrocarbon production (Kalantari-Dahaghi 2011, Fazelipour 2011). In some cases, more than 20 fracture stages have been tried in a horizontal well in order to increase the fracture contact with the formation, and to produce high initial rates.The studies have suggested that the initial production increases linearly with the number of fractures but a high flow rate is not sustainable and declines sharply once the fractures interfere over a given lateral length (Castaneda et al. 2010, King 2010). It is obvious that the longer the initial fracture length and the shorter their spacings, the higher the oil production will be.
Abija, Abija (Akaha Celestine/Dept. of Geology, University of Port Harcourt) | Ankwo, Fidelis (Akaha Celestine/Dept. of Geology, University of Port Harcourt) | Tse, Tse (Akaha Celestine/Dept. of Geology, University of Port Harcourt)
In situ stress magnitude and orientation are necessary for oil and gas field development planning to achieve optimal well placement whether vertical, deviated or horizontal, wellbore stability analysis for safe and stable drilling to reduce non-productive time, fault stability and cap rock integrity modeling for CO2 geosequestration and stage placement of hydraulic fracture for optimum production in unconventional plays. These were evaluated using wireline logs, leak off test and vertical seismic profile data in an onshore field, Eastern Niger Delta whose stratigraphic sequence is the typical interlayered, normal to abnormal pressured shales and sandstones of the Agbada Formation. The vertical stress magnitude ranges from 23.08 - 25.57 MPa/km, minimum effective horizontal stress from 13.80 - 14.03 MPa/km and maximum effective horizontal stress from 16.06 - 17.65 MPa/km inferring a normal fault stress regime. The minimum horizontal stress orientation varies from 16° - 33° forming the most stable orientation for geosteering a directional well while the maximum horizontal stress orientation is N60°E - N123°E in agreement with the regional fault orientations in the Niger Delta. ENE – WSW, WNW – ESE and other maximum horizontal stress orientations suggest multiple sources of stress, and in situ stress rotation across fault surfaces depicts wellbore instability issues. Structural evolution depicts NE – SW and NW-SE trending faults in the direction of the maximum horizontal stress. Directional well inclination angles of 16° and 33° were predicted in wells 10 and 11 respectively and mud weight window predicted using 2D Mohr - Coulomb failure criterion yielded an optimum mud weight window of 10 - 14.0ppg with overpressure accounting for mud weights as high as 25ppg and minimum mud weight exceeding the maximum mud weight in some sections.
Gao, Jiajia (College of Petroleum Engineering, China University of Petroleum-Beijing) | Deng, Jingen (College of Petroleum Engineering, China University of Petroleum-Beijing) | Yan, Wei (College of Petroleum Engineering, China University of Petroleum-Beijing) | Feng, Yutian (Bohai Petroleum institute) | Wang, Houdong (College of Petroleum Engineering, China University of Petroleum-Beijing) | Xia, Yang (College of Petroleum Engineering, China University of Petroleum-Beijing)
The present paper develop an integrated geomechanical wellbore stability model that incorporates the theoretical derivation regarding Mogi-Coulomb strength criterion with the favor of Lode's parameter and stress invariants, the anisotropic rock strength characteristic associated with weak plane, the coordinates transformations pertaining to borehole and weak plane systems as well as chemo-poro-thermoelastic solutions around a pressurized inclined borehole to analyze the extent of shear failure and tensile fracture regions in horizontal boreholes. The results regarding a horizontal wellbore drilled along the direction of minimum horizontal in situ stress from present paper show that increasing the mud salinity could contribute to consolidating the formation and alleviating the wellbore instability with respect to shear failure where thermal osmosis intensifying the chemical osmosis effect. Moreover, the drilling mud with higher salinity where thermal osmosis weakening the chemical osmosis effect boosts the favorable conditions required for concurrence associated with longitudinal and transverse fractures in the top and low sides of the horizontal wellbore while the corresponding combined tensile fracture regions progressively aggrandize with time progress.
Wellbore instability issues are often encountered when drilling the inert to generating mud cake due to low permeability regarding shale formation with the laminated heterogeneity and chemically active characteristics in deep high temperature environment by horizontal borehole. Accordingly, it is necessary and urgent to understand the complex wellbore instability mechanism with reference to time dependent reestablishment of stresses and pore pressure around ther wellbore determined by poroelastic effect associated with undrained loading after instantaneous bored (Detournay and Cheng, 1988), chemical effect related to the chemical osmotic flow resulting from solute transfer (Heidug and Wong, 1996; Yu et al.,2003; Ghassemi and Diek, 2003; 2009; Zhou and Ghassemi, 2009) as well as water activity difference (Chen et al., 2003) between drilling mud and pore fluid in shale formation, thermal effects arising from heat transport (McTigue, 1986; Chen and Ewy, 2005; Zhou and Ghassemi, 2009) and thermal osmotic (Ghassemi and Diek, 2002; Ghassemi and Diek, 2009).
Shale formations are characterized by parallel discontinuous planes of weaknesses configurations of which may exhibit pronouncedly more potential to fail along the slip surfaces as compared to through compact rock matrix. Accordingly, the strength criteria pertaining to shale rock may be determined by different controlling factors associated with dominated failure behaviors. In regard to intact rock failure, poly-axial shear failure strength criteria, such as: Modified Lade (Ewy,1999) and Mogi-Coulomb (Al-Ajmi and Zimmerman, 2005) appropriately evaluate the strengthening effect concerning the intermediate principle stress such that efficiently guide the practical drilling designs, however, Mohr-Coulomb criterion is expected to be significantly conservative in estimating the minimum mud pressure required to ensure the wellbore stability, since the influence of intermediate principal stress on rock strength is disregarded. In another aspect, the single plane of weakness theory is expressed in the form of Mohr-Coulomb differentiating failure modes of the intact rock and weak plane by the angle between major principal stress and the normal of isotropic planes of laminated medium (Jaeger et al.2007).
Hansen, Kirk S. (Shell International Exploration and Production) | Wang, Gary (Shell International Exploration and Production) | Adeleye, Olayinka (Shell International Exploration and Production) | McNeil, Katja V. (Shell Development Australia) | Couzens-Schultz, Brent A. (Shell International Exploration and Production) | Azbel, Kostia (Shell International Exploration and Production) | Sarfare, Manoj D. (Shell International Exploration and Production) | Tare, Uday (Shell International Exploration and Production)
Pore-pressure (PP) and fracture-gradient (FG) predictions were prepared for Prelude development wells in the Browse basin in offshore northwest Australia. The PP forecasts were based on resistivity- and sonic-based models calibrated with pressure measurements and drilling events, such as kicks from existing wells. FGs were based on leakoff tests and loss events from offset wells and were not necessarily equal to either the minimum compressive principal stress (often considered a lower bound to FG) or the formation-breakdown pressure (often considered an upper bound to FG that includes effects of formation tensile strength and nearwellbore hoop stress). The minimum compressive horizontal stress was calculated from lithology-dependent effective-stress ratios. Maximum horizontal stress was inferred from observed breakouts. PP and stresses were combined with formation properties from well logs and laboratory rock-mechanics tests to provide input for elastoplastic (shales) and poroelastic (sands) boreholestability (BHS) models. These techniques are applicable to exploration, appraisal, or early-development wells that have potential for encountering geopressured formations in high-angle well sections requiring good predrill estimates to adequately plan the casing and drilling programs and determine BHS. The predrill studies can be extended to provide integrated real-time PP and BHS while drilling, and the models can be recalibrated after each well to provide updated predictions for subsequent wells. There are only minor deviations in the predicted PP and FG among the different well locations considered. Common features include potential loss zones in the shallow overburden, pressure ramp within the Jamieson, pressure regression below the Aptian, and near-hydrostatic pressure within the Upper Swan and below. The BHS models indicate that minimum-required mud weight in deviated sections could be up to 20% higher than that required to balance formation PP. In one well that would cross a suspected fault, the risk of fault reopening or reactivation is low.
Tare, Uday Arun (Shell International E&P Inc.) | Sarfare, Manoj Dnyandeo (Shell International E&P Inc.) | Azbel, Konstantin (Shell International Exploration and Production Inc.) | Wang, Gary (Shell International Exploration and Production Inc.) | Couzens-Schultz, Brent Alan (Shell International E&P Inc.) | Adeleye, Olayinka (Shell International Exploration and Production Inc.) | Hansen, Kirk S (Shell International E&P Inc.) | McNeil, Katja V. (Shell Development Australia Pty Ltd)
Pore pressure (PP) and fracture gradient (FG) predictions were prepared for Prelude development wells in the Browse Basin, offshore northwest Australia. The PP forecasts were based on resistivity- and sonic-based models calibrated with pressure measurements and drilling events such as kicks from existing wells. Fracture gradients were based on leakoff tests and loss events from offset wells and were not necessarily equal to the minimum compressive horizontal stress, which was calculated from lithology-dependent effective stress ratios. Maximum horizontal stress was inferred from observed breakouts. Pore pressure and stresses were combined with formation properties from well logs and laboratory rock mechanics tests to provide input for elasto-plastic (shales) and poro-elastic (sands) borehole stability models.
These techniques are applicable to exploration, appraisal, or early development wells that have potential for encountering geopressured formations in high-angle well sections requiring good pre-drill estimates to adequately plan the casing and drilling programs and determine borehole stability. The pre-drill studies can be extended to provide integrated real-time pore pressure and borehole stability while drilling, and the models can be recalibrated following each well to provide updated predictions for subsequent wells.
There are only minor deviations in the predicted PP and FG among the different well locations considered. Common features include potential loss zones in the shallow overburden, pressure ramp within the Jamieson, pressure regression below the Aptian, and near-hydrostatic pressure within the Upper Swan and below. The borehole stability models indicate that minimum required mud weight in deviated sections could be up to 20% higher than required to balance formation pore pressure. In one well that would cross a suspected fault, the risk of fault reopening or reactivation is low.
This study indicates that use of integrated borehole stability and PP/FG models can result in higher minimum required mud weights and narrower drilling windows than would be suggested from the PP/FG models by themselves and can therefore contribute to enhanced safety, optimized well designs, and reduction of non-productive drilling time. Lost circulation at mud weights well below the minimum in-situ stress can be explained by reactivation or initiation of shear fractures.
Prelude is a gas and gas-condensate field that was discovered in 2007 in the Browse Basin, offshore northwest Australia; it will be developed utilizing the world's first floating liquefied natural gas (FLNG) facility. The Prelude development will require several wells drilled at high angle from approximately the same surface locations to near-horizontal sections within the target reservoir as chosen from among eight potential well paths (Figure 1). The potential for moderately geopressured formations requires good pre-drill estimates of pore pressure (PP) and fracture gradient (FG) to adequately plan the casing and drilling programs and (combined with the high-angle well sections) determine borehole stability. Expected (P50), minimum (nominally P15), and maximum (nominally P85) cases are considered for both PP and FG to account for uncertainty in the predictions.