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Kalhor Mohammadi, Mojtaba (International Drilling Fluids) | Taraghikhah, Shervin (International Drilling Fluids) | Karimi Rad, Mohammad Saeed (International Drilling Fluids) | Tahmasbi Nowtaraki, Koroush (International Drilling Fluids)
Abstract Developing high-performance environmentally friendly drilling fluids is always a requirement by oil and gas operators to reduce the waste management associated cost with the drilling fluid treatment and disposal. Conventional water-based drilling fluid is formulated with the brine-based polymer which consists of sodium and potassium chloride salts to improve the performance of the polymer and also providing clay inhibition in reactive clay and shale. This paper describes the development of nanotechnology-based drilling fluid to replace salt from the conventional application. Nano Based Low Saline Water Based Mud (NBLS-WBM) was formulated and developed based on laboratory experiments. Different nano additives with different concentrations were evaluated and the optimum concentration was selected to reduce the sodium and potassium chloride salts concentration to almost zero. The rheological properties and fluid loss were measured according to the API standard before and after hot rolling. Also, HPHT fluid loss, lubricity, and shale inhibition were evaluated. All the results were compared with sodium salt-saturated and potassium-based polymer muds. Laboratory evaluation of NBLS-WBM indicated that sodium salt concentration can be reduced considerably up to 5% W/V and potassium chloride can be eliminated by adding 1% W/W of nano additive. The rheological properties including plastic viscosity and yield point were constant and stable after hot rolling 16 hours at 250 °F. Also, Clay inhibition improved significantly up to 95% recovery comparing with conventional water-based polymer mud. Although the application of nanotechnology to improve the performance of conventional water-based drilling fluid was studied by many researchers, it is the novelty of this research to reduce the salt concentration and remove it to develop the new generation of salt-free water-based drilling fluid with economical consideration and lower environmental impact.
Abstract Distributed Fiber Optics (DFO) technology has been the new face for unconventional well diagnostics. This technology focuses on measuring Distributed Acoustic Sensing (DAS) and Distrusted Temperature Sensing (DTS) to give an in-depth understanding of well productivity pre and post stimulation. Many different completion design strategies, both on surface and downhole, are used to obtain the best fracture network outcome; however, with complex geological features, different fracture designs, and fracture driven interactions (FDIs) effecting nearby wells, it is difficult to grasp a full understanding on completion design performance for each well. Validating completion designs and improving on the learnings found in each data set should be the foundation in developing each field. Capturing a data set with strong evidence of what works and what doesn't, can help the operator make better engineering decisions to make more efficient wells as well as help gauge the spacing between each well. The focus of this paper will be on a few case studies in the Bakken which vividly show how infill wells greatly interfered with production output. A DFO deployed with a 0.6" OD, 23,000-foot-long carbon fiber rod to acquire DAS and DTS for post frac flow, completion, and interference evaluation. This paper will dive into the DFO measurements taken post frac to further explain what effects are seen on completion designs caused by interferences with infill wells; the learnings taken from the DFO post frac were applied to further escalate the understanding and awareness of how infill wells will preform on future pad sites. A showcase of three separate data sets from the Bakken will identify how effective DFO technology can be in evaluating and making informed decisions on future frac completions. In this paper we will also show and discuss how DFO can measure real time FDI events and what measures can be taken to lessen the impact on negative interference caused by infill wells.
Rodríguez-Pradilla, Germán (School of Earth Sciences, University of Bristol, UK.) | Eaton, David (Department of Geoscience, University of Calgary, Canada.) | Popp, Melanie (geoLOGIC Systems Ltd., Calgary, Canada.)
Abstract The goal of this work is to calibrate a regional predictive model for maximum magnitude of seismic activity associated with hydraulic-fracturing in low-permeability formations in the Western Canada Sedimentary Basin (WCSB). Hydraulic fracturing data (i.e. total injected volume, injection rate, and pressure) were compiled from more than 40,000 hydraulic-fractured wells in the WCSB. These wells were drilled into more than 100 different formations over a 20-year period (January 1st, 2000 and January 1st, 2020). The total injected volume per unit area was calculated utilizing an area of 0.2° in longitude by 0.1° in latitude (or approximately 13x11km, somewhat larger than a standard township of 6x6 miles). This volume was then used to correlate with reported seismicity in the same unit areas. Collectively, within the 143 km area considered in this study, a correlation between the total injected volume and the maximum magnitude of seismic events was observed. Results are similar to the maximum-magnitude forecasting model proposed by A. McGarr (JGR, 2014) for seismic events induced by wastewater injection wells in central US. The McGarr method is also based on the total injected fluid per well (or per multiple nearby wells located in the same unit area). However, in some areas in the WCSB, lower injected fluid volumes than the McGarr model predicts were needed to induce seismic events of magnitude 3.0 or higher, although with a similar linear relation. The result of this work is the calculation of a calibration parameter for the McGarr model to better predict the magnitudes of seismic events associated with the injected volumes of hydraulic fracturing. This model can be used to predict induced seismicity in future unconventional hydraulic fracturing treatments and prevent large-magnitude seismic events from occurring. The rich dataset available from the WCSB allowed us to carry out a robust analysis of the influence of critical parameters (such as the total injected fluid) in the maximum magnitude of seismic events associated with the hydraulic-fracturing stimulation of unconventional wells. This analysis could be replicated for any other sedimentary basin with unconventional wells by compiling similar stimulation and earthquake data as in this study.
Hui, Gang (University of Calgary, Alberta, Canada) | Chen, Shengnan (University of Calgary, Alberta, Canada) | Gu, Fei (PetroChina Research Institute of Petroleum Exploration and Development, Beijing, China)
Abstract The recent seismicity rate increase in Fox Creek is believed to be linked to the hydraulic fracturing operations near the region. However, the spatiotemporal evolution of hydraulic fracturing-induced seismicity is not well understood. Here, a coupled approach of geology, geomechanics, and hydrology is proposed to characterize the spatiotemporal evolution of hydraulic fracturing-induced seismicity. The seismogenic faults in the vicinity of stimulated wells are derived from the focal mechanisms of mainshock event and lineament features of induced events. In addition, the propagation of hydraulic fractures is simulated by using the PKN model, in combination with inferred fault, to characterize the possible well-fault hydrological communication. The original stress state of inferred fault is determined based on the geomechanics analysis. Based on the poroelasticity theory, the coupled flow-geomechanics simulation is finally conducted to quantitatively understand the fluid diffusion and poroelastic stress perturbation in response to hydraulic fracturing. A case study of a moment-magnitude-3.4 earthquake near Fox Creek is utilized to demonstrate the applicability of the coupled approach. It is shown that hydraulic fractures propagated along NE45° and connected with one North-south trending fault, causing the activation of fault and triggered the large magnitude event during fracturing operations. The barrier property of inferred fault under the strike-slip faulting regime constrains the nucleation position of induced seismicity within the injection layer. The combined changes of pore pressure and poroelastic stress caused the inferred fault to move towards the failure state and triggered the earthquake swarms. The associated spatiotemporal changes of Coulomb Failure Stress along the fault plane is well in line with the spatiotemporal pattern of induced seismicity in the studied case. Risks of seismic hazards could be reduced by decreasing fracturing job size during fracturing stimulations.
Yang, Xinxiang (University of Alberta (Corresponding author) | Kuru, Ergun (email: email@example.com)) | Gingras, Murray (University of Alberta) | Biddle, Sara (University of Alberta) | Lin, Zichao (University of Alberta) | Iremonger, Simon (University of Alberta)
Summary Cement-rock interface is a major component of the wellbore barrier system. Leakage may result from the poor bonding between cement and rock interface. In this paper we investigate possible factors that may affect the cement-rock interface bonding. More specifically, integrity of the cement-rock interface was characterized using micro-computed tomography (CT) and environmental scanning electron microscopy (ESEM). Hollow cylinder rock samples were prepared by using rock samples (e.g., Banff dolostone, Pekisko limestone, Doig sandstone, Notikewin siltstone, Montney siltstone, and Wilrich siltstone) collected from different Alberta wells at various depths. Two abandonment cement blends were injected into the rock open hole. By using ESEM (0.05-mm resolution) and micro-CT (11.92-mm resolution) techniques, the 2D and 3D models of the cement-rock interface were developed. Energy-dispersive X-ray spectroscopy (EDS) was conducted to analyze chemical characteristic of the cement-rock samples. Using the CT images, computational fluid dynamics (CFD) models were built to simulate fluid flow through the cement-rock samples. For both cement and rock, there is a nonuniform porosity distribution in radial and axial directions. For most of the cement-rock samples, the highest porosity region in the cement column was found at the cement-rock interface. Optimizing the chemistry of the cement system enhances the cement-rock interface bond by effectively reducing the gap between cement and rock observed in ESEM images. Although cement migration was observed in the rough rock surface in porous rocks, the rock interface and matrix zones have almost identical element concentrations. For the investigated samples, the chance for significant chemical reaction at the cement-rock interface is minimal. CFD simulation based on digital cement models showed that the cement-rock interface has more chance to act as the main flow pathway when intact (low permeability) caprock exists. The sample preparation, image analysis and simulation methods used in this study can be also applied to other cement interface studies (e.g., cement-casing, casing-cement-rock). From the practical field application point of view, the results presented here would help to have a better understanding of the requirements for designing optimum cement formulations to establish effective zonal isolation and reduce the greenhouse gas emissions from oil and gas wells. Introduction Wellbore cement is the most important barrier element because it provides zonal isolation to prevent uncontrolled flow of formation fluid to the surface as well as crossflow among various underground formations.
von Gunten, Konstantin (University of Alberta) | Snihur, Katherine N. (University of Alberta) | McKay, Ryan T. (University of Alberta) | Serpe, Michael (University of Alberta) | Kenney, Janice P. L. (MacEwan University) | Alessi, Daniel S. (University of Alberta)
Summary Partially hydrolyzed polyacrylamide (PHPA) friction reducer was investigated in produced water from hydraulically fractured wells in the Duvernay and Montney Formations of western Canada. Produced water from systems that used nonencapsulated breaker had little residual solids (<0.3 g/L) and high degrees of hydrolysis, as shown by Fourier-transform infrared (FTIR) spectroscopy. Where an encapsulated breaker was used, more colloidal solids (1.1–2.2 g/L) were found with lower degrees of hydrolysis. In this system, the molecular weight (MW) of polymers was investigated, which decreased to <2% of the original weight within 1 hour of flowback. This was accompanied by slow hydrolysis and an increase in methine over methylene groups. Increased polymer-fragment concentrations were found to be correlated with a higher abundance of metal-carrying colloidal phases. This can lead to problems such as higher heavy-metal mobility in the case of produced-water spills and can cause membrane fouling during produced-water recycling and reuse.
Abstract The use of multi-lateral wells started in the mid-1990s in particular in Canada, and they have since been used in many countries. However, few papers on multi-lateral wells focus on their production performances, thus what could be expected from such wells in terms of production and recovery factor is not clear and this paper will attempt to address that gap. Taking advantage of public data, the production performances of various multi-lateral wells in Western Canada have been studied. In the cases reviewed in this paper, these wells always target a single formation; they have been used in a variety of fields and reservoirs, mostly for primary production but also for polymer flooding in some cases. Multiple examples will be provided, mostly in heavy oil reservoirs, and production performances will be compared to nearby horizontal and vertical wells whenever possible. From the more classical dual and tri-lateral to more complex architectures with 7 or 8 laterals, and the more exotic, with laterals drilled from laterals, the paper will present the architecture and performances of these complex wells and of some fields that have been developed almost exclusively with multi-lateral wells. Interestingly, multi-lateral wells have not been used much for secondary or tertiary recovery, probably due to the difficulty of controlling water production after breakthrough. However, field results suggest that this may not be such a difficult proposition. One of the most remarkable wells producing a 1,250 cp oil under polymer flood has achieved a cumulative production of over 3MM bbl, which puts it among the top producers in Canada. Although multi-lateral wells have been in use for over 25 years, very few papers have been devoted to the description of their production performances. This paper will bring some clarity on these aspects. It is hoped that this paper will encourage operators to reconsider the use of multi-lateral wells in their fields.
Summary Alternate or out-of-sequence fracturing (OOSF) has been field tested in western Siberia in 2014 and in western Canada in 2017, 2018, and 2019, with operational success and positive well-production performance. It is conducted by fracturing Stage 1 (at the toe) and then fracturing Stage 3 (toward the heel), followed by tripping back to place Stage 2 (center fracture) between Stages 1 and 3 (outside fractures). During placing the center fracture, OOSF can exploit the reduced stress anisotropy to effectively activate the planes of weakness (natural fractures, fissures, faults, and joints) to potentially create failure surfaces with different breakdown angles in virtually all directions. This can potentially lead to branch fractures that can connect the hydraulic fractures to stress-relief fractures that are created while placing the outside fractures, ultimately generating a complex fracture network and enhancing fracture connectivity. Despite prior works on fracture modeling (calibrated by field tests) and geomechanical modeling, a comparative analysis of wellbore-breakdown character and hydraulic-fracture orientation during OOSF is still lacking. Thus, in this study, the solutions to 3D Kirsch equations are provided for both low and high stress anisotropies to analyze the differences in breakdown gradient, failure angle, and fracture orientation under various geomechanical and treatment-design conditions. The consideration is given to an intact rock from an isotropic stress state to high-stress-anisotropy conditions. The results are analyzed in the context of the downhole-measured pressures and temperatures. The results indicate that the reduced stress anisotropy during OOSF leads to favorable treating conditions: With a net fracture-extension pressure greater than the reduced stress anisotropy, fracture complexity can be created by allowing the fracture to grow with different failure angles. Also, a well can be drilled and fractured at any inclination or azimuth with favorable breakdown gradients of 45 to 85% of the overburden gradient. The reduced stress anisotropy can also trigger some challenges. The near-well stress-concentration effects can become more pronounced, promoting longitudinal fracture creation. For treatments with tortuosity greater than the stress anisotropy, longitudinal fractures can be created instead of transverse fractures because the tortuosity is transmitted to the wellbore body and not into the fractures. In this case, to initiate transverse fractures, either the wellbore must intersect the pre-existing transverse notches or the near-well pore-fluid pressure must exceed the axial stress and rock strength (before the hoop stress reaches the tensile failure point). In addition, the fracture might lose directional control and follow any path of weakness. Hence, the rock-fabric effects become more dominant under a low-stress-anisotropy regime, which means that with no pre-existing transverse natural fractures or notches, a longitudinal fracture can be generated at the bottom and top of an intact horizontal wellbore. This is the first attempt in identifying the circumstances that should be avoided for optimizing OOSF through geomechanical modeling and the analysis of the downhole-measured pressures and temperatures to reveal the differences in breakdown character using the Kirsch equations under various geomechanical and treatment conditions during the low-stress-anisotropy regime.
Summary In this paper, we investigate the change in oil effective permeability () caused by fracturing‐fluid (FF) leakoff after hydraulic fracturing (HF) of tight carbonate reservoirs. We perform a series of flooding tests on core plugs with a range of porosity and permeability collected from the Midale tight carbonate formation onshore Canada to simulate FF‐leakoff/flowback processes. First, we clean and saturate the plugs with reservoir brine and oil, and age the plugs in the oil for 14 days under reservoir conditions (P = 172 bar and T = 60°C). Then, we measure before (baseline) and after the leakoff process to evaluate the effects of FF properties, shut‐in duration, and plug properties on regained permeability values. We found that adding appropriate surfactants in FF not only significantly reduces impairment caused by leakoff, but also improves compared with the original baseline for a low‐permeability carbonate plug. For a plug with relatively high permeability (kair > 0.13 md), freshwater leakoff reduced by 55% (from 1.57 to 0.7 md) while FF (with surfactants) reduced by only 10%. The observed improvement in regained is primarily because of the reduction of interfacial tension (IFT) by the surfactants (from 26.07 to 5.79 mN/m). The contact‐angle (CA) measurements before and after the flowback process do not show any significant wettability alteration. The results show that for plugs with kair > 0.13 md, FF leakoff reduces by 5 to 10%, and this range only increases slightly by increasing the shut‐in time from 3 to 14 days. However, for the plug with kair < 0.09 md, the regained permeability is even higher than the original before the leakoff process. We observed 28.52 and 64.61% increase in after 3‐ and 14‐day shut‐in periods, respectively. This observation is explained by an effective reduction of IFT between the oil and brine in the pore network of the tight plug, which significantly reduces irreducible water saturation (Swirr) and consequently increases . Under such conditions, extending the shut‐in time enhances the mixing between invaded FF and oil/brine initially in the plug, leading to more effective reductions in IFT and consequently Swirr. Finally, the results show that the regained permeability strongly depends on the permeability, pore structure, and Swirr of the plugs.
van Oort, Eric (The University of Texas at Austin) | Chen, Dongmei (The University of Texas at Austin) | Ashok, Pradeepkumar (The University of Texas at Austin) | Fallah, Amirhossein (The University of Texas at Austin)
Abstract Deep closed-loop geothermal systems (DCLGS) are introduced as an alternative to traditional enhanced geothermal systems (EGS) for green energy production that is globally scalable and dispatchable. Recent modeling work shows that DCLGS can generate an amount of power that is similar to EGS, while overcoming many of the downsides of EGS (such as induced seismicity, emissions to air, mineral scaling etc.). DCLGS wells can be constructed by leveraging and extending oil & gas extended reach drilling (ERD) and high-pressure high-temperature (HPHT) drilling expertise in particular. The objectives of this paper are two-fold. First, we demonstrate that DCLGS wells can generate power/electricity on a scale that is comparable to EGS, i.e. on the order of 40-55 MW per well. To this extent, we have developed a coupled hydraulic-thermal model, validated using oil and gas well cases, that can simulate various DCLGS well configurations. Secondly, we highlight the technology gaps and needs that still exist for economically drilling DCLGS wells, showing that it is possible to extend oil & gas technology, expertise and experience in ERD and HPHT drilling to construct complex DCLGS wells. Our coupled hydraulic-thermal sensitivity analyses show that there are key well drilling and design parameters that will ultimately affect DCLGS operating efficiency, including strategic deployment of managed pressure drilling / operation (MPD/MPO) technology, the use of vacuum-insulated tubing (VIT), and the selection of the completion in the high-temperature rock zones. Results show that optimum design and execution can boost geothermal power generation to 50 MW and beyond. In addition, historical ERD and HPHT well experience is reviewed to establish the current state-of-the-art in complex well construction and highlight what specific technology developments require attention and investment to make DCLGS a reality in the near-future (with a time horizon of ~10 years). A main conclusion is that DCLGS is a realistic and viable alternative to EGS, with effective mitigation of many of the (potentially show-stopping) downsides of EGS. Oil and gas companies are currently highly interested in green, sustainable energy to meet their environmental goals. DCLGS well construction allows them to actively develop a sustainable energy field in which they already have extensive domain expertise. DCLGS offers oil and gas companies a new direction for profitable business development while meeting environmental goals, and at the same time enables workforce retention, retraining and re-deployment using the highly transferable skills of oil and gas workers.