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Conventional well completions in soft formations (the compressive strength is less than 1,000 psi) commonly produce formation sand or fines with fluids. These formations are usually geologically young (Tertiary age) and shallow, and they have little or no natural cementation. "Friable" and "Unconsolidated" are two commonly used terms to describe the nature of the reservoir material. Sand production can plug tubing, casing, flowlines and surface vessels. It can erode equipment that leads to loss of well control or unwanted fluid emissions.
Calgary-based Tourmaline Oil Corp. announced today that it is acquiring Black Swan Energy in an all-stock deal valued at CAD $1.1 billion. The transaction is set to boost Tourmaline's output by 50,000 BOE/D and the company expects to average around 500,000 BOE/D by mid-2022. The operator said the Black Swan acquisition is one of several it has made recently to become the largest producer in the north Montney Shale area of British Columbia. Black Swan's 231,000-acre position gives Tourmaline an estimated 1,600 horizontal drilling locations and proven and probable reserves of 491.9 million BOE. Tourmaline said in its announcement that Black Swan has not booked material reserves in other areas that it sees as having high potential and complementary to its existing footprint.
Pembina Pipeline will acquire a 50% stake in the proposed $2.4-billion Cedar LNG Project to develop the floating LNG facility in British Columbia in partnership with indigenous group, the Haisla Nation. The pipeline operator expects to invest about $90 million into Cedar LNG over the next 24 months, including costs to acquire its interest in the project as well as development costs prior to the final investment decision expected sometime in 2023. The company, which will acquire the equity interests in Cedar LNG from PTE Cedar LP and Delfin Midstream Inc., will operate the project going forward. Haisla will own the remaining 50% stake. Pembina has been busy of late.
Abstract Drilling in deep high-pressure high-temperature (HPHT) abrasive sandstone pose significant challenges: low rate of penetration (ROP), bit wear, differential sticking, and wellbore instability issues. These issues are magnified when attempting to drill long laterals in the direction of minimum stress. This paper focuses on the use of Managed Pressure Drilling (MPD) and Artificial Intelligence (AI) analytics to improve ROP. MPD is normally used to help drilling in formations with narrow mud weight window, it achieves this by controlling the surface backpressure to keep the annular pressure in the wellbore above the pore pressure and below the fracture gradient. One key benefit of using MPD is that high mud weight is no longer required, since the Equivalent Circulating Density (ECD) is going to be managed to maintain the overbalance. An example of a well that was drilled using MPD solely for ROP improvement is presented in this paper. This well achieved almost double the ROP of a control well, which was drilled in the same formation with no MPD. Essentially most of the drilling parameters used, which include, pump rate, revolution per minute (RPM), weight on bit (WOB), and other drilling practices, are controlled by the people on the rig. Incorporating AI analytics in the equation, help minimizes human intervention and could achieve further improvement in ROP. After the ROP improvement observed while using MPD, both technologies were combined in a well drilling the same formation. An example is presented for the well drilled using both technologies.
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.
Woodside has decided to exit its 50% nonoperated participating interest in the proposed Kitimat Liquefied Natural Gas (KLNG) development, located in British Columbia, Canada. The exit will include the divestment or wind-up and restoration of assets, leases, and agreements covering the 480 km Pacific Trail Pipeline route and the site for the proposed LNG facility at Bish Cove. Project operator Chevron announced its plan to divest its 50% interest in KLNG in December 2019. Woodside said it will work with Chevron to protect the project's value during the exit. The costs associated with the decision to exit KLNG are expected to affect 2021 net profit after tax up to $60 million.
Abstract Assessment of effective mechanical properties such as elastic properties and brittleness can be challenging in the presence of complex rock composition, pore structure, and spatial distribution of minerals, especially in the absence of acoustic measurements. Conventional methods such as effective medium modeling, are not reliable for assessments of mechanical properties in complex formations such as carbonates, because solid skeleton of carbonates does not consist of granular minerals with ideal shapes. The effective medium models also overlook both the spatial distribution of petrophysical properties, and the coupled hydraulic and mechanical (HM) processes, which causes significant uncertainties in geomechanical evaluations. The objective of this paper is to develop a numerical method to enhance assessment of effective mechanical properties of anisotropic and heterogenous carbonate formations by modeling the variation of effective stress and the evolution of corresponding strain. The developed method takes into account the coupled HM processes, the realistic spatial distribution of rock inclusions (i.e., rock fabrics), dynamic fluid flow, pore pressure, and pore structure. To achieve this objective, we develop a pore-scale numerical simulator by satisfying conservation equations and considering the coupling among relevant HM phenomena. We adopt peridynamic theory to discretize the micro-scale medium. The inputs to our numerical modeling include pore-scale images of rock samples as well as mechanical and hydraulic properties of each rock inclusion. We perform image processing on micro-CT scan images of rock samples to obtain a realistic micro-scale structure of both rock matrix (i.e., concentration, spatial distribution, and shape of rock constituents) and pore space. We then assign realistic mechanical and hydraulic properties to each rock constituent within the pore-scale medium. The outcomes of numerical modeling include the variation of effective stress and the evolution of corresponding strain by honoring the variability in mechanical/hydraulic properties of rock inclusions caused by their spatial distribution, pore pressure, pore structure, natural fractures, and dynamic fluid flow at the micro-scale domain. We then compare the outcomes of numerical models with the mechanical properties estimated based on effective medium models.
Abstract Characterization of hydraulic fracture system in multi-fractured horizontal wells (MFHW) is one of the key steps in well spacing optimization of tight and shale reservoirs. Different methods have been proposed in the industry including core-through, micro-seismic, off-set pressure data monitoring during hydraulic fracturing, pressure depletion mapping, rate-transient analysis, pressure-transient analysis, and pressure interference test. Pressure interference test for a production and monitoring well pair includes flowing the production well at a stable rate while keeping the monitoring well shut-in and recording its pressure. In this study, the coupled flow of gas in hydraulic fractures and matrix systems during pressure interference test is modeled using an analytical method. The model is based on Laplace transform combined with pseudo-pressure and pseudo-time. The model is validated against numerical simulation to make sure the inter-well communication test is reasonably represented. Two key parameters were introduced and calculated with time using the analytical model including pressure drawdown ratio and pressure decline ratio. The model is applied to two field cases from Montney formation. In this case, two wells in the gas condensate region of Montney were selected for a pressure interference test. The monitoring well was equipped with downhole gauges. As the producing well was opened for production, the bottom-hole pressure of the monitoring well started declining at much lower rate than the production well. The pressure decline rate in the monitoring well eventually approached that of the producing well after days of production. This whole process was modeled using the analytical model of this study by adjusting the conductivity of the communicating fractures between the well pairs. This study provides a practical analytical tool for quantitative analysis of the interference test in MFHWs. This model can be integrated with other tools for improved characterization of hydraulic fracture systems in tight and shale reservoirs.
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.