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,
Global natural gas consumption is projected to grow from 112 Tcf to 163 Tcf in the next 20 years representing an increase rate of nearly 2% annually; this implies not only enormous investment, but also new challenges and search for geoscientists and petroleum professionals with expertise in this new fields. Shales are the most abundant sedimentary rocks in sedimentary basins of the earth; but, small portion of them would achieve commercial productivity. This course will train the attendees on the evaluation methods and techniques that can be utilized to delineate productive shales from barren shales. One of the major challenges of gas shale reservoirs is to apply conventional log data to acquire reservoir rock properties. In this course log analysis for gas shale reservoirs will be demonstrated practically to estimate reservoir properties.
Al-Anssari, Sarmad (Curtin University, University of Baghdad, Edith Cowan University) | Arain, Zain-UL-Abedin (Curtin University) | Barifcani, Ahmed (Curtin University) | Keshavarz, Alireza (Edith Cowan University) | Ali, Muhammad (Curtin University, Edith Cowan University) | Iglauer, Stefan (Edith Cowan University)
Nanoparticles (NPs) based techniques have shown great promises in all fields of science and industry. Nanofluid-flooding, as a replacement for water-flooding, has been suggested as an applicable application for enhanced oil recovery (EOR). The subsequent presence of these NPs and its potential aggregations in the porous media; however, can dramatically intensify the complexity of subsequent CO2 storage projects in the depleted hydrocarbon reservoir. Typically, CO2 from major emitters is injected into the low-productivity oil reservoir for storage and incremental oil recovery, as the last EOR stage. In this work, An extensive serious of experiments have been conducted using a high-pressure temperature vessel to apply a wide range of CO2-pressure (0.1 to 20 MPa), temperature (23 to 70 °C), and salinity (0 to 20wt% NaCl) during CO2/water interfacial tension (IFT) measurements. Moreover, to mimic all potential scenarios several nanofluids at different and NPs load were used. IFT of CO2/nanofluid system was measured using the pendant drop method as it is convenient and flexible technique, particularly at the high-pressure and high-temperature condition. Experimentally, a nanofluid droplet is allowed to hang from one end of a dispensing needle with the presence of CO2 at the desired pressure and temperature. Regardless of the effects of CO2-pressure, temperature, and salt concentration on the IFT of the CO2/nanofluid system, NPs have shown a limited effect on IFT reduction. Remarkably, increased NPs concentration (from 0.01 to 0.05 wt%) can noticeably reduce IFT of the CO2-nanofluid system. However, no further reduction in IFT values was noticed when the NPs load was ≥ 0.05 wt%. Salinity, on the other hand, showed a dramatic impact on IFT and also on the ability of NPs to reduce IFT. Results showed that IFT increases with salinity particularly at relatively low pressures (≤ 5 MPa). Moreover, increased salinity can eliminate the effect of NPs on IFT. Interestingly, the initial NP size has no influence on the ability of NPs to reduce IFT. Consequently, the potential nanofluid-flooding processes during EOR have no negative effect on the later CO2-geosequestration projects.
Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market, which in the near future is expected to coincide with domestic energy shortages arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.
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.
Global natural gas consumption is projected to grow from 112 Tcf to 163 Tcf in the next 20 years representing an increase rate of nearly 2% annually; this implies not only enormous investment, but also new challenges and search for geoscientists and petroleum professionals with expertise in this new fields. Shales are the most abundant sedimentary rocks in sedimentary basins of the earth; but, small portion of them would achieve commercial productivity. This course will train the attendees on the evaluation methods and techniques that can be utilized to delineate productive shales from barren shales. One of the major challenges of gas shale reservoirs is to apply conventional log data to acquire reservoir rock properties. Organic matter richness, thermal maturity status, porosity, permeability, frees gas saturation, adsorbed gas volume and rock mechanical characteristics are among those critical parameters that have to be estimated for gas shale field assessment.
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.
It is desirable to obtain airborne gravity data with sufficient accuracy over both short and long wavelengths in order to accurately image subsurface mass distributions and structures from near surface to greater depths. Airborne gravity gradiometry (AGG) offers an efficient and cost-effective means to acquire high accuracy gravity data that can have wavelengths as short as a couple of hundred meters; however, the long wavelength content in the AGG gravity is limited by the decreasing gravity accuracy with increasing wavelength. Airborne gravimetry (AG) is usually limited to short wavelengths of a few kilometers but its accuracy improves at wavelengths above about ten kilometers. The Full spectrum Falcon simultaneously acquires both Falcon (AGG) data and sGrav (AG) data and thus provides a complete gravity dataset. In this work we demonstrate the technology and data processing schemes to obtain high accuracy gravity over a broad bandwidth.
Presentation Date: Wednesday, September 27, 2017
Start Time: 11:00 AM
Presentation Type: ORAL