Virues, Claudio (Nexen Energy ULC) | Lypkie, Kevin (Nexen Energy ULC) | Pyecroft, James (Nexen Energy ULC) | Zafar, Hammad (Nexen Energy ULC) | Lehmann, Jurgen (Nexen Energy ULC) | Hendrick, Jason (Nexen Energy ULC)
This paper outlines a drilling, completions reservoir guided analytical model to assess cased uncemented (CUC) multi-fractured horizontal wells (MFHW) in the Canadian Horn River Basin. The typical Horn River shale gas development involves drilling and hydraulically fracturing multiple horizontal wells from a single surface pad location. The wells are hydraulically fractured in a sequential manner from the toe to the heel of the horizontal section, alternating from well to well. This manner of hydraulic fracturing allows concurrent operations that maximize operational efficiency and reduce completion costs. Microseismic (MS) data shows that hydraulic fracture stimulation results in a very complex stimulated reservoir volume (SRV). Surveillance data including MS as well as proppant and fluid tracer data shows that hydraulic fractures reactivate the natural fracture system and can extend beyond inter-well distances. Production analysis however indicates that the effective drainage volume, post stimulation is significantly smaller than what is observed with MS.
The objective of the cased uncemented MFHW was to achieve improved productivity over the standard cased cemented horizontal well design. The hypothesis was that the CUC wellbore would have improved connection to the reservoir and the natural fracture system existing within the target shales. In addition, the CUC well would benefit by increased reservoir contact and connection to fractures created from offset wells on the pad. The first experimental well was drilled on Nexen's 18 well pad, completed in 2012. A swellable packer system was conveyed as part of the casing string to isolate each hydraulic fracture stage. A second generation cased uncemented well with mechanical packers was tested in 2013.
This paper will discuss how the conceptual model of this new technology can be translated into an analytical model by guiding the workflow with drilling, completions and reservoir understanding and how the surveillance data such as MS, production logs, and tracers validate the process along the way.
This approach allows generating production forecasting and reserves estimates of this new technology allowing economics to be run and decision to go forward to be made. Some of the design considerations and production indications will be addressed, concluding with a discussion of the results.
Horizontal drilling and hydraulic fracturing have enabled production from Bakken tight oil reseroirs. However, since the primary recovery is very low, it is important to use enhanced oil recovery methods to unlock part of the remaining oil in the reservoir. In this study, the CO2 injection as a huff-n-puff EOR process is studied. Numerical simulation was used for coupling the reservoir fluid flow with geomechanics to study the stress and deformation of reservoir rock in a CO2-EOR process. The simulation was performed through porosity and permeability relationships with pressure, temperature, and mean total stress for iterative coupling of stress and flow to account for the effect of geomechanics in CO2-EOR.
Coalbed Methane (CBM) is becoming a significant portion of the US gas resource and is gaining importance in Australia, China, Indonesia and Europe. CBM reserves in the United States are estimated at some 450 Tscf. In Australia, CBM resources exceed 300 Tscf, while China has a resource potential greater than the United States and Australia combined. Recent advances in well design and production technology offer scope to significantly increase the proportion of gas contained in coal that can be commercialized. Generally, initial water saturation is 100% within coal seams and gas can only be found as an adsorbed phase inside the coal matrix, so how much adsorbed gas can be released at an economical rate will determine the ultimate gas recovery. The Langmuir isotherm has been widely used in industry to describe the pressure dependence of adsorbed gas. However, temperature dependent adsorption behavior and its major implications for evaluating thermal stimulation as a recovery method for coalbed methane have not been thoroughly explored. Therefore in order to investigate the feasibility of thermal treatment in coal bed methane reservoir successfully, it is crucial to understand the effects of thermal stimulation on the adsorption and desorption phenomenon, and how can we exploit such effects to enhance coalbed methane recovery from hydraulically fractured reservoirs.
In this study, we propose a method to evaluate desorbed gas as a function of pressure and temperature in coal seams, by regression on Langmuir isotherm data. In addition, a CBM reservoir simulator is developed, which is capable of capturing real gas diffusion in the coal matrix and flow in the hydraulic fractures, as well as the heat transfer process within the matrix. This simulator enables us to investigate various thermal stimulation techniques on the global well performance and recovery.
The results of this study show that by increasing the formation temperature, ultimate gas recovery can be improved in CBM reservoirs. The higher the thermal stimulation treatment temperature, the more extra gas can be recovered. However, the efficiency of thermal stimulation is mostly constrained by how much the formation area/volume that can be stimulated in a reasonable period of time. Due to the low heat conductivity of coal, it is not possible to heat up a large drainage area/volume by heating the surface of vertical hydraulic fractures directly. If the heating source (e.g., electromagnetically excited nano-particles) can be dispersed further into the formation through the cleat system during hydraulic fracture execution, then larger formation area/volume can be heated up, depending on how further the nano-particles can be pushed and the arrangement of production (injection) wells. In the case of horizontal fractures, a large formation volume can be thermally stimulated if the fractures can be placed close enough to cover the whole lateral area. Thermal stimulation by hot water/steam injection can increase formation temperature more rapidly than direct element heating methods, especially when the formation permeability is large. Considering large amount of residual adsorption gas still left behind even with low production pressure, thermal stimulation has the potential to enhance CBM recovery substantially if techniques and designs are tailored to the formation properties appropriately.
Zhang, K. (University of Calgary) | Qin, T. (University of Calgary) | Wu, K. (University of Calgary) | Jing, G. (University of Calgary) | Han, J. (University of Calgary) | Hong, A. (University of Stavanger) | Zhang, J. (China Univeristy of Petroleum) | Chen, S. (University of Calgary) | Chen, Z. (University of Calgary)
As a result of poor fluid delivery in tight oil reservoirs, oil production drops rapidly at early stages of depletion development. While water flooding only boosts production to a limited extent, CO2 miscible flooding seems a promising technique in improving tight oil recovery. Generally, CO2 flooding is performed only after water flooding gives better results than natural depletion. Since cumulative CO2 injection versus oil production goes up as formation permeability goes down, it is crucial to select suitable reservoir candidates to conduct CO2 flooding to be economically successful. There are several methods of ranking candidate reservoirs for the CO2 enahnced oil recovery (EOR) process based on criteria on reservoir parameters. Nevertheless, few of them take account of an oil recovery increment and risk analysis. In this paper, an integrated method for CO2 flooding reservoir screening criteria is presented, considering asphaltene precipitation and an oil recovery factor increment. This method is based on the least squares method, reservoir simulation, and fuzzy analytical hierarchy process, associated with equation of state (EOS) compositional calculations and compositional modelling. It is applicable in high diversity and can be used as guidance to screen tight oil reservoirs for CO2 flooding.
Do fractures help or hinder production in hydraulically stimulated resource plays? Most say they help, but some say they hinder. After monitoring productivity for over 10 years in a number of plays in Shell's unconventional portfolio, it appears that the evidence for fractures helping is more conceptual than empirical, further substantiated by a detailed literature review. The objective of this paper therefore is to bring some objectivity to the discussion around the impact of structure using logical arguments by reason, incorporating knowledge of the variability in structure and well performance within the spectrum of unconventional plays.
Fundamental to this assessment is the recognition that different scales of features will have a markedly different impact. And to communicate the concepts herein, small-scale features are referred to as "natural fractures" and large-scale features, referred to as "faults" or "lineaments".
This analysis indicates that the variability in (small-scale) natural fracture intensity across most plays is not sufficient to be detected in well performance metrics, given the other sub-surface heterogeneity and the large range in estimated ultimate recovery (EUR) for any given set of wells. Furthermore, natural fracture connectivity is typically low and stimulation of networks is not supported by data or trials. It is proposed to consider natural fractures as an intrinsic rock property which will modify the bulk geomechanical properties of the formation. The only exception found was for folded tight-sand plays, where fracture network connectivity may be sufficient to provide a measurable enhanced deliverability.
Understanding the impact of seismically-visible, planar, structural features (e.g. faults or lineaments) proved to be more problematic, with operators reporting both EUR increases and decreases. This inconsistency is explained with a novel concept classifying faults as
Rather than searching for a production performance correlation, it is suggested that an enhanced understanding of the physical processes during a hydraulic stimulation would be more beneficial to clarify the impact of structure. And to this aim, a compilation of potential fracturing diagnostics is presented herein.
Accurate and repeatable assessments of in situ stress magnitudes and orientation in unconventional reservoirs can be complicated by the heterogeneous, inelastic, and/or anisotropic mechanical properties of these rocks and their complex history of burial and diagenesis. The associated vertical and lateral variation in pore pressure and stress through the target zones and bounding intervals can further complicate this effort. For these reasons, some additional factors need to be considered beyond the typical workflow of determining closure stress from standard mini-frac data and using this data to calibrate log derived stress profiles. We present some case study examples from hydrocarbon-producing shales where a more rigorous analysis of the mechanical properties of the shale has allowed a more accurate and repeatable assessment of in situ stress and potential for lamination shearing. Horizontal fracture growth through shear activation of bedding-parallel fabric can be a preferred fracture propagation mechanism in these shales and this behavior can be diagnosed by this improved workflow. In one case study example, in the tight gas Montney siltstone of Western Canada, shear strength anisotropy is shown to be very significant, with bedding parallel shear cohesion less than 10% of the bulk rock cohesion. For such situations it can be shown that shear fracturing of laminations is likely. It has been demonstrated through pressure transient analysis of minifrac injection and flowback data that this can be diagnosed. Many fracturing related mechanisms are also stress dependent and their understanding requires assessment of all in situ stress magnitudes, not just minimum horizontal stress. An improved method of analyzing these stress magnitudes and fracturing mechanisms is described through anisotropy measurements in core samples and a micro-mechanical understanding of the rock fabric. In this way, a petrophysical relationship can be established between anisotropy parameters and rock properties.
Weatherhead, S. (Suncor Energy Oil and Gas Partnership) | Djidjelli, A. (M-I SWACO, a Schlumberger company) | Leeds, M. (M-I SWACO, a Schlumberger company) | Mujumdar, H. (M-I SWACO, a Schlumberger company)
Interest in the unconventional shale gas plays continues to grow in Western Canada. The Montney formation found in North Eastern British Columbia can be particularly challenging due to drilling in the Canadian Foothills. Wells in the area are known for deep, hard, abrasive and abnormally pressured formations. Further challenges include unexpected fractures, lost circulation and coals seams. The combination of these drilling issues can cause a significant increase in expected drilling times (slow ROP and NPT).
Following some difficulty drilling offset wells due to well control issues, future designs incorporated a higher, more conservative mud weight. This let to slower ROP and corresponding NPT.
A new approach with MPD and lighter mud weight was proposed. For the intermediate sections, the first well changed from a weighted to un-weighted invert emulsion. The second well was drilled with a pure base oil system to lower the fluids solids content. The horizontal section was initially planned to drill with a density of 1400kg/m3 weighted invert. A MPD program was proposed drilling with a 1250kg/m3 weighted invert for the next two wells and adjusting backpressure to match the required bottom hole ECD.
The key operational objectives for the operator were increased ROP and a reduction of NPT. This was accomplished by lower ECD associated with lower mud densities, lower drilled solids and lower viscosities. A secondary benefit was the reduction of whole mud losses. Mud losses were reduced in manner that allowed for fast safe well control in the event a pressured fracture (kick) was encountered.
A reduction of more than 7.4 days vs AFE from spud to rig release was largely attributed to utilizing MPD technique and the team work of everyone involved on location. NPT was reduced from 100 hours to 8 hours on the final well of the project. The second MPD well of the project was considered a big success, with the following results (refer
MPD2 vs Best Conventional well Performance Data
MPD2 vs Best Conventional well Performance Data
As the activity in NE British Colombia's Montney play continues to grow, it is important that other operators learn the benefits of utilizing MPD. This includes safely decreasing days on the well by increasing ROP and reducing influx and losse related NPT caused by excessive mud weight.
The Montney Formation, a tight unconventional reservoir in Western Canada, has been explored for the past two decades and over the last 10 years has moved towards being a primary exploration target. Qualitative and quantitative petrophysical analysis of the Montney Formation has always been a challenge to researchers. Reservoir characterization is generally hindered by lab-based methods for permeability estimation, proper estimation of the pore size distribution and development of correlations between the rock properties and hydraulic flow.
This report examines results from permeametry, mercury porosimetry, helium pycnometry and scanning electron microscopy (SEM) images performed on 53 samples of the Montney Formation to understand the complicated pore network structure of the rock and study the predictive power of a permeability prediction model.
Pulse-Decay permeability is measured on cores at effective reservoir pressure. Crushed samples are used to obtain mercury capillary pressure, pore size distribution curves, GRI and mercury porosity and matrix permeability. SEM images are used to study pore development and porosity as well as investigating the presence of microfractures. The permeabilities of these samples range from 10 nanodarcies to 0.1 milidarcies and porosities range from 2-10 percent. Due to high surface intrusions in the mercury porosimetry tests, extraction of pore size distributions and capillary pressure curves are problematic and cut-offs are applied based on the derivative of the capillary pressure curve to help understand the complicated pore network of the rock and correlate it with permeability.
This study shows that mercury porosimetry results can be used to categorize the rocks into subcategories for further analysis. Different methods correlating rock properties to permeability are examined. The results specifically indicate that pulse-decay permeability is influenced by over-burden pressure and the presence of microfractures and that the appropriate pore diameter shows consistent correlation with the derivative of the capillary pressure curve.
Ash deposits are found interbedded within organic mudstones such as the Vaca Muerta, Niobrara and Eagle Ford shales. Alteration of ash deposits interbedded within mudstones and shales have presented challenges for completion and production including pinching of fractures and swelling upon contact with drilling and completion fluids. This paper will review the mineralogic and petrologic variations in altered ash beds found within the Eagle Ford and examine the impact these chemical and physical properties can have on completion. The paper will also present a methodology for detection of ash beds using high-resolution measurements. Understanding and detecting the mineralogic variation between the altered ash beds will enable better completion and minimize risk during production.
In a vertically transverse isotropic (VTI) medium, accurate prediction of the vertical and horizontal Young's moduli (E) and Poisson's ratios (?) is crucial to predicting minimum horizontal stress (shmin) and hence selecting drilling mud, cement weights, and perforation locations. Fully characterizing geomechanical properties of VTI shale requires five independent stiffness coefficients: C33, C44, C66, C11, and C13. In a vertical well, C33 and C44 are directly calculated from the velocity of the vertically propagating P- and S- waves, while C66 is estimated from the Stoneley wave velocity. To obtain C11 and C13, an empirical model must be employed. This study integrates laboratory mechanical and sonic measurements to evaluate the ANNIE and modified-ANNIE models and extend the dynamic-to-static conversion equation.
Laboratory static and dynamic geomechanical methods were applied to multiple core materials extracted at different depths from a target shale play. The dynamic elastic moduli were measured using a laboratory sonic scanner; velocities were measured in different directions to obtain C33, C44, C11, C66, and C13. The dynamic data were then applied in the ANNIE and modified-ANNIE models for estimating the dynamic elastic moduli, including dynamic Young's modulus and Poisson's ratio. The static elastic moduli were measured using axial compression experiments; horizontal and vertical core plugs were tested to account for anisotropy.
Static and dynamic results illustrated horizontal Young's moduli were predominantly higher than vertical Young's moduli, which suggested a horizontal layered structure. Vertical Poisson's ratios can be greater or smaller than horizontal Poisson's ratios, which is consistent with the prediction of the modified-ANNIE model. Conversely, the ANNIE model always predicts ?(vert) = ?(horz). Static and dynamic data illustrated the anisotropic shmin was predominantly higher than the isotropic shmin. This implied that using an isotropic model to predict laminated shale will underestimate shmin. It was noticed that the static Young's modulus increased with decreasing porosity for the target interval. The elastic moduli measured from the dynamic method were consistently higher than those measured from the static method. The dynamic and static data were used to fit the widely-used dynamic-to-static conversion equations—the Canady and Morales equations. The Canady equation was extended to the "very hard" (greater than 70 GPa Young's modulus) regime, while the Morales equation was extended to the regime of porosity < 10%. Finally, shmin predicted by different models was compared with the measurements, showing that modified-ANNIE improved the prediction by solving the stress underestimation issue of the ANNIE and isotropic models.