Costin, Simona (Imperial Oil) | Smith, Richard (Imperial Oil) | Yuan, Yanguang (Bitcan Geoscience and Engineering) | Andjelkovic, Dragan (Schlumberger Canada) | Garcia Rosas, Gabriel (Schlumberger Canada)
Open-hole mini-frac tests are seldom performed in the Athabasca and Cold Lake oil sands due to the complexity of operations. In this paper we present the results of open-hole injections tests performed in Cold Lake, Alberta (AB), Canada. The objective of the injection tests was to assess the in-situ stress condition in the Cretaceous Colorado Group. The injection tests results combined with the run of formation image logs (FMI) before and after the injection have enabled not only the determination of the in-situ minimum stress in the rock, but also the full 3-D stress tensor, along with the orientation and inclination of the hydraulic fracture. The tests were performed in IOL 102/08-02-066-03W4 (N10 Passive Seimic Well, 'PSW'). The injection tests have revealed that the vertical stress in the area is the in-situ minimum stress, consistent with previous measurements. The hydraulically-induced fracture has sub-horizontal to moderate dip angle, mostly owing to the preexisting fabric of the rock, and peaks in the general NE-SW direction. Numerical modeling of the in-situ stresses has shown that the values of the vertical and the minimum horizontal stresses are close, with the vertical stress consistently being smaller than the minimum horizontal stress in all tested zones.
Hirschmiller, John (GLJ Petroleum Consultants Ltd.) | Biryukov, Anton (Verdazo Analytics) | Groulx, Bertrand (Verdazo Analytics) | Emmerson, Brian (Verdazo Analytics) | Quinell, Scott (GLJ Petroleum Consultants Ltd.)
This machine learning study incorporates geoscience and engineering data to characterize which geological, reservoir and completion data contribute most significantly to well production performance. A better understanding of the key factors that predict well performance is essential in assessing the commercial viability of exploration and development, in the optimization of capital spending to increase rates of return, and in reserve and resource evaluations.
Machine learning models provide an objective, analytical means to interpret large, complex datasets. Generally, such models demand large databases of consistently evaluated data. As geological data is interpretive, often varying from one geologist to another, or from one pool to another, it can be difficult to incorporate geological data into regional machine learning models. Consequently, efforts to use machine learning in the oil and gas industry to predict well performance are often focused exclusively on engineering completion technology. However, this case study has utilized a regional geological Spirit River database with consistent petrophysical evaluation methodology across the entire play. This geological database is complemented with public completion and fracture data and production data to build predictive models using inputs from all subsurface disciplines.
Redundancies in the data were identified and removed. Features explaining a significant proportion of the variance in production were also removed if their effect was captured by more fundamental, correlated features that were more straightforward to interpret. The dataset was distilled to 13 key features providing predictions with a similar precision to those obtained using the full-featured dataset.
The thirteen features in this case study are a combination of geological, reservoir and completion data, underlining that an approach integrating both geoscience and engineering data is vital to predicting and optimizing well performance accurately for future wells.
A sizeable portion of the Athabasca oil sand reservoir is classified as Inclined Heterolithic Stratification lithosomes (IHSs). However, due to the significant heterogeneity of IHSs and the minimal experimental studies on them, their hydro-geomechanical properties are relatively unknown. The main objectives of this study are investigating the geomechanical constitutive behavior of IHSs and linking their geological and mechanical characteristics to their hydraulic behavior to estimate the permeability evolution of IHSs during a Steam Assisted Gravity Drainage (SAGD) operation. To that end, a detailed methodology for reconstitution of analog IHS specimens was developed, and a microscopic comparative study was conducted between analog and in situ IHS samples. The SAGD-induced stress paths were experimentally simulated by running isotropic cyclic consolidation and drained triaxial shearing tests on analog IHSs. Both series of experiments were performed in conjunction with permeability tests at different strain levels, flow rates, and stress states. Additionally, an analog sample with bioturbation was tested to examine the hydro-geomechanical effects of bioturbation. Finally, the hydro-mechanical characteristics of analog IHS were compared with its constituent layers (sand and mud).
The microscopic study showed that the layers’ integration and grain size distribution are similar in analog and in-situ IHS specimens. The results also revealed that geomechanical properties of IHSs, such as shear strength, bulk compressibility, Young's modulus, and dilation angle, are stress state dependent. In other words, elevating confining pressure could significantly increase the strength and elastic modulus of a sample, while decreasing the compressibility and dilation angle. In contrast, the friction angle and Poisson's ratio are not very sensitive to changes in the isotropic confining stress. An important finding of this study is that the effect of an IHS sample's volume change on permeability is contingent on the stress state and stress path. Volume change during isotropic unloading-reloading resulted in permeability increases and sample dilation during compression shearing resulted in permeability decreases, especially at high effective confining stresses. Moreover, the tests revealed that the existence of bioturbation dramatically improves permeability of IHSs in comparison to equivalent non-bioturbated specimens but has negligible effects on its mechanical properties, which remain similar to non-bioturbated specimens. The results also showed that bioturbation has minimal impact on permeability changes during shearing. Lastly, experimental correlations were developed for each of the parameters mentioned above.
For the first time, specialized experimental protocols have been developed that guide the infrastructure and processes required to reconstitute analog IHS specimens and conduct geomechanical testing on them. This study also delivered fundamental constitutive data to better understand the geomechanical behavior of IHS reservoir and its permeability evolution during the in-situ recovery processes. Such data can be used to accurately capture the reservoir behavior and increase the efficiency of SAGD operations in IHS reservoirs.
Heavy oil is defined as liquid petroleum of less than 20 API gravity or more than 200 cp viscosity at reservoir conditions. No explicit differentiation is made between heavy oil and oil sands (tar sands), although the criteria of less than 12 API gravity and greater than 10,000 cp are sometimes used to define oil sands. Unconsolidated sandstones (UCSS) are sandstones (or sands) that possess no true tensile strength arising from grain-to-grain mineral cementation.
The water recovered from hydraulic-fracturing operations (i.e., flowback water) is highly saline, and can be analyzed for reservoir characterization. Past studies measured ion-concentration data during imbibition experiments to explain the production of saline flowback water. However, the reported laboratory data of ion concentration are approximately three orders of magnitude lower than those reported in the field. It has been hypothesized that the significant surface area created by hydraulic-fracturing operations is one of the primary reasons for the highly saline flowback water.
In this study, we investigate shale/water interactions by measuring the mass of total ion produced (TIP) during water-imbibition experiments. We conduct two sets of imbibition experiments at low-temperature/low-pressure (LT/LP) and high-temperature and high-pressure (HT/HP) conditions. We study the effects of rock surface area (As), temperature, and pressure on TIP during imbibition experiments. Laboratory results indicate that pressure does not have a significant effect on TIP, whereas increasing As and temperature both increase TIP. We use the flowback-chemical data and the laboratory data of ion concentration to estimate the fracture surface area (Af) for two wells completed in the Horn River Basin (HRB), Canada. For both wells, the estimated Af values from LT/LP and HT/HP test results have similar orders of magnitude (approximately 5.0×106 m2) compared with those calculated from production and flowback rate-transient analysis (RTA) (approximately 106 m2). The proposed scaleup procedure can be used as an alternative approach for a quick estimation of Af using early-flowback chemical data.
Chakraborty, Srimanta (Baker Hughes, a GE Company) | Panchakarla, Anjana (Baker Hughes, a GE Company) | Deshpande, Chandrashekhar (Baker Hughes, a GE Company) | Malik, Sonia (Baker Hughes, a GE Company) | Singh Majithia, Pritpal (ONGC) | Chaudhary, Sunil (ONGC) | Murthy, AVR (ONGC)
Conventional volumetric analysis has its own limitations & challenges to characterize fluid types in complex clastic reservoirs. Presence of shale and radioactive minerals in sandstones makes the evaluation more complicated compared to clean reservoirs as uncertainty become higher to ascertain grain density & total porosity. Delineation of pay zones (heavy oil bearing) & estimation of saturation become more uncertain due to reservoir complexities.
Elemental spectroscopy log can provide real time grain density, TOC (Total Organic Carbon) and mineralogy for complex reservoirs (radioactive sand). However, to determine the fluid type and porosity in this type of reservoir, Nuclear Magnetic Resonance (NMR) would be the best choice due to its capability of recording simultaneous T1 (Spin-lattice relaxation time) and T2 (Spin-Spin relaxation time) including diffusivity measurement sequences. Compare to the traditional 1D T2 spectrum based interpretation methodology; A new approach of using constrained 2D NMR inversion, enhances the capability to discern different fluid phases by mapping proton density as a function of T2 relaxation time (T2int) in the first parameter dimension and diffusion coefficient "D" (or T1 relaxation time or T1/T2app ratio) in the second parameter dimension. An integrated approach is used by combining NMR and Elemental spectroscopy results to reduce formation evaluation uncertainties in heavy oil reservoirs.
Successful integration of NMR, Elemental Spectroscopy Log with Image and Acoustic results helps to understand reservoir properties in study area. The advantage of using constrained 2D NMR over conventional 2D NMR reduces the uncertainty of responses between Clay Bound Water (CBW) and heavy oil, which has similar T2 relaxation mechanism. Integration of Clay volume from Elemental Spectroscopy measurements in constrained 2D NMR helps to differentiate the heavy oil and clay bound water responses. Furthermore, the combination of NMR & Elemental Spectroscopy results helps to segregate the existence of heavier oil & lighter oil components in the reservoir. Based on these results, potential hydrocarbon zones was identified and successful testing attempts were made.
This paper shows an approach of using constrained 2D NMR results over conventional 2D NMR to overcome reservoir uncertainties & to identify potential pay zones.
Very few papers describe waterflood projects in heavy oil reservoirs, and even less that involve the use of horizontal injectors and producers. A few years ago, Beliveau presented a review of waterfloods in viscous oil in several pools mostly in Canada and demonstrated that excellent results can be obtained in most cases, but he mostly focused on pools with vertical wells. The purpose of this paper is to present results of several heavy oil waterfloods in Canada that use horizontal producers and injectors.
The production performances of eight heavy oil pools where waterflood has been implemented using horizontal wells have been studied. The pools are thin and bottom water is present in some of them; oil viscosity ranges from a few hundred to a few thousand centipoises. The overall performances of each flood will be discussed and compared to other heavy oil pools where waterflood is implemented with vertical wells. In addition, more detailed analyses will be performed in some patterns to better evaluate the impact of bottom water, well length, spacing and other factors on the flood performances.
As could be expected, water breakthrough is generally fast, within a few months from the beginning of injection; but more surprisingly, Water Oil Ratio can often remain stable for long periods of time. Ultimate recovery is expected to vary from a few percents OOIP to over 20%OOIP. Similarly, to waterfloods with vertical wells, a large portion of the reserves can be recovered while producing at high Water Oil Ratio.
This paper will present results of several waterfloods in heavy oil reservoirs in Canada which use horizontal wells. There are very few such field cases in the literature thus the information provided will be of interest to engineers who are considering waterflood as a follow-up to primary production in heavy oil reservoirs developed with horizontal wells.
The Senlac SAGD (Steam-Assisted Gravity Drainage) project is Saskatchewan, Canada, does not have the same name recognition as its much bigger brothers in the Alberta Oil Sands but it certainly deserves to be known better. Senlac was the first industrial SAGD project in Canada back in 1997 and since then it has been the site for other technological innovations such as the use of solvent in addition with steam to increase recovery and reduce the Steam Oil Ratio, as well as the testing of wedge wells - wells drilled between SAGD well pairs to benefit from the heat remaining in the reservoir. The reservoir in Senlac is the Dina-Cummings of Lower Cretaceous age and is much smaller than the McMurray formation which is the site of most of the large-scale oil sands project but the oil is only 5,000 cp thus it is mobile at reservoir temperature. This is a significant difference which allows well pairs to achieve excellent production and recovery even though reservoir thickness is only 8-16 m, well below the standard cutoff for SAGD. The presence of bottom water under parts of the field is an added challenge to the operations. The paper will present the field characteristics and production performances as well as the main technological developments such as the Solvent Added Process and the use of wedge wells. The paper will present a complete case study of a SAGD project in a heavy oil reservoir where oil is mobile. Most SAGD project so far have been conducted in bitumen but the paper will show the potential for this technology in thinner and smaller reservoirs.
Measurement of geomechanical properties using seismic and laboratory methods have been used in oil and gas industry for several years. Laboratory methods, in most cases, take only small samples from consolidated rocks, which may not be representative of the elastic regime existing in the reservoir owing to sample size. In general, geomechanical studies are performed on a well-by-well basis. Measurements calculated at the wellsite are then used as calibration points to convert the 3-D seismic data to geomechanical cube. However, elastic properties measured this way are restricted to the well location and cannot be interpolated across the reservoir. To overcome these challenges, this paper describes an approach for deriving and discretizing geomechanical and other elastic properties in the reservoir by integrating results of 3D geo-cellular and basin models.
The workflow presented in this paper is utilized to calculate cell-by-cell elastic properties of the reservoir by integrating parameters from both basin model and 3D geo-cellular grid. The basin model reconstructs the geologic history (i.e. burial history) by back-stripping the reservoir to its original depositional thickness. Through this reconstruction, the mechanical compaction, pore pressures, effective stress, and porosity-vs-depth relationships are established for the reservoirs. In the final stage, dicretized calculations of geomechanical properties are assigned to each lithotype (facies) in the geomodel. The discretization of elastic properties into 3D grids resulted in better understanding of the prevailing rock elastic properties and stress regimes helping hydraulic fracturing operators in the effective design of their depletion strategies with minimal drilling risks and costs. This approach provides an innovative way of determining effective minimum horizontal stress for the entire reservoir through distribution of elastic properties in a 3D grid. The conventional approach of using small sample plugs is not sufficient to describe elastic properties for an entire reservoir and can be replaced by current approach.
The steam-assisted gravity drainage (SAGD) process is the most successful in-situ recovery method for heavy oil and bitumen. It is commonly suggested that heat conduction is the dominant mechanism of heat transfer near the edge of steam chamber. Heat convection is neglected in classical models.
In this study, three novel heat tranfer models have been developed to describe the transient heat transfer coupled with steady flow in different injection situations during SAGD process. Both heat conduction and heat convection were taken into account in the three models. Model #1 represents a continuous fluid injection at constant temperature. Model #2 represents a continuous fluid injection with exponentially decreasing temperature. Model #3 represents a periodic fluid injection, in which high temperature fluid is injected at the beginning and then lower temperature fluid is injected instead after a period of time. In the models, reservoir and fluid properties were integrated into two parameters, i.e., thermal diffusivity of reservoir and fluid system, and thermal convection velocity of injection fluid. The two parameters are constant under steady flow condition. The analytical solutions to the three heat tranfer models were derived and validated. The effects of thermal diffusivity and thermal convection velocity were examined.
It is found that heat convection and heat conduction occur simultaneously in SAGD process, fluid flow motivates convective heat transfer and increases the overall rate of heat transfer. It is also found that the temperature curves predicted by the analytical solutions in this study show excellent agreements with those predicted by COMSOL. In the reservoir and fluid system with larger thermal diffusivity, the heating area is larger, and the temperature increasing rate is smaller at the same observation location. When the steam is injected at a higher thermal convection velocity, heat can be transported to further distance, and the temperature increasing rate is larger at the same observation location.
The newly proposed heat transfer models and newly developed analytical solutions are simple and efficient to quickly obtain the temperature profiles in heavy oil reservoirs during SAGD process.