Shell Canada Limited (French: Shell Canada Limitée) is the subsidiary of British conglomerate Shell plc and one of Canada's largest integrated oil companies. Exploration and production of oil, natural gas and sulphur is a major part of its business, as well as the marketing of gasoline and related products through the company's approximately 1,800 stations across Canada.After a global reorganization by the European parent, Shell's North American operations are controlled by Shell Energy North America, which is headquartered in Houston, Texas. Shell Energy North America's Canadian operational unit, Shell Canada, maintains a regional corporate office in Calgary, Alberta. Shell Canada also maintains a major office in Toronto, Ontario.
Accurate modeling of hydraulic fracture geometry in heterogeneous shale formations remains a persistent challenge, particularly when limited to sparse core data or low-resolution well geophysical logs. This study introduces a workflow that integrates high-resolution scratch test data with advanced signal processing, statistical methods, and machine learning (ML) to quantify centimeter-scale heterogeneity and translate it into simulation-ready geomechanical properties. The objective is to enhance the fracture propagation and vertical containment predictions in unconventional reservoirs through improved mechanical property characterization and physics-based modeling. Scratch test data from multiple wells were analyzed to develop continuous strength profiles at centimeter-scale resolution. The raw data were processed using Fast Fourier Transform (FFT)–based denoising, followed by moving-average upscaling to align the data with the sampling interval of conventional wireline logs. The denoised core-scale data were correlated with well logs through supervised ML models, including Random Forest, Gradient Boosting, and Support Vector Machine (SVM) algorithms. Among these, the Random Forest model achieved the highest accuracy (R2 > 0.84) and was used to generate continuous, synthetic scratch-equivalent strength logs across uncored well sections. Fracture toughness was subsequently derived from the predicted scratch strength using an energetic size-effect formulation, and both horizontal and vertical toughness values were upscaled following the Dontsov–Suarez-Rivera (2021) fracture-energy-based homogenization method. The homogenized datasets were incorporated into a commercial hydraulic fracturing simulator to evaluate the sensitivity of fracture geometry to depth resolution of the fracture toughness profile. Fracture simulations using high-resolution inputs produced more complex fracture geometries, with limited height growth and improved alignment with stress-derived barriers. This study demonstrates a practical, end-to-end approach that links laboratory-scale mechanical data with field-scale hydraulic fracture modeling, offering a framework to reduce uncertainty in fracture design for heterogeneous shale reservoirs.
Abstract This paper presents a detailed case study on reservoir fluids planning, development, and execution for a high-permeability, highly depleted, extended horizontal slim hole well with Open-Hole Gravel Pack (OHGP) (with brine alpha-beta completions) in the Gulf of America (GoA). The targeted sand layer presents a robust opportunity to unlock unique volumes and accelerate production for the operator. With limited OHGP completions experience in depleted slim hole in the GoA, in addition to mitigating risks associated with the selected sand control design; robust reservoir drill-in fluid, screen running fluid, gravel pack carrier fluid, and acid breaker solutions had to be developed. Discussed is a fluid testing scope used to address well challenges and guide formulation optimization. Candidate fluids had to go through numerous stress tests including extended high pressure fluid loss, contamination, and formation damage evaluation. A description of the tests and methods used is provided allowing readers the ability to reproduce all results. The operator successfully drilled and completed the target sand utilizing water-based drilling system with zero NPT attributed to fluids performance, significantly lower drawdown pressure, and meeting all key subsurface outcomes. In most cases, a synthetic-based drilling system would be chosen due to bias in perceived benefits of shale inhibition, thinner filter cake, and better lubricity for screen running. This paper highlights the considerations made and the subsequent tests performed proving that in this scenario, utilizing a water-based system is more beneficial holistically both in well construction and production. A mindset shift was essential, avoiding the confirmation bias of one-system-fits-all.
Abstract This paper will present a detailed case study involving the planning and execution for drilling two extremely depleted sections in a deepwater well in the Gulf of America. This field was originally brought on production in 2018, and the main reservoirs have not had any pressure maintenance (waterflood). The operator decided to drill water injectors to deliver more value and extend the field life, but it has long been considered a risk that these wells could be "undrillable" due to severe depletion combined with borehole stability challenges. With significant subsurface uncertainty due to limited offsets, some of which had experienced significant losses with less depletion, the team planned for a wide variety of possible outcomes to get this well down. The operations team also deployed all levers at their disposal, including strategic casing design, a detailed wellbore strengthening and lost circulation material (LCM) plan capable of achieving fracture widths greater than 1,300 microns and managed pressure drilling (MPD) operations. The team challenged the limits of traditional well operating windows, including the maximum fracture widths that could be achieved while drilling, the minimum mud weight that could be deployed to manage borehole instability and the use of MPD to maintain the downhole mud weight equivalent to the drilling equivalent circulating densities (ECDs). After a massive lost circulation event occurred, the team listened to the well and deployed a unique solution comprised of all available depleted drilling techniques to safely deliver the well. This analysis will be highlighted, the recovery plan will be discussed, and this paper will contrast a previous deepwater well that was abandoned in the mid 2000's in a very similar severely depleted drilling application. Lastly, this information was analyzed and used to successfully drill a subsequent well in the field, confirming how critical data can be transferred across a severely depleted field to operate within the drilling window and successfully adapt a strategy.
Microseismic monitoring represents a key surveillance technology to verify the integrity of subsurface CO2 storage sites. The precise location of microseismic events is first and foremost a direct and immediate indication of caprock and seal behavior but could also provide insight into CO2 plume migration. Tiny precursor movements provide diagnostic information about injection-related reservoir and caprock dynamics long before potential seal failure occurs. We present a case study from the Quest CCS facility in Canada, where a variety of different monitoring technologies are employed. We present the different microseismic sensor technologies and array configurations currently installed at the site and compare them against each other with respect to their reliability and effectiveness in providing the required verification information.
Kuwait Oil Company (KOC) have been actively recovering hydrocarbons from Heavy-oil reservoirs located in the Northern Kuwait (NK) Fields. Northern Kuwait Heavy Oil (NKHO) reserves are mainly located in two major fields: Field-1 (cold well) and Field-2 (thermal well). Currently, this heavy oil field is in the developmental phase, and KOC plans to add additional wells yearly. Field-2 is a thermal field, currently producing with a water cut of approximately 45%. Typically, water coning is a major challenge that hinders thermal recovery in a heavy oil reservoir with a bottom or boundary aquifer. This situation typically occurs when the production zone is near an aquifer or a water-bearing formation with a permeable connection, based on the ratio of horizontal to vertical permeability between the oil production zone and water formation. Coning occurs with pressure drawdown, causing water to migrate from the bottom to the wellbore. This is strictly a near-wellbore phenomenon that occurs only once the pressure forces drawing fluids toward the wellbore exceed the natural buoyancy forces that segregate gas and water from oil. Coning is a rate-sensitive phenomenon generally associated with high production rates. Although it can be controlled by decreasing the production rates, this approach is unfavorable because oil production is reduced and water production impacts the economic life of reservoirs and ultimate recovery. Moreover, it increases the operating expenses such as pumping, water/oil separation, and equipment costs. Additionally, excess water production causes wellbore corrosion, scaling, and sand production problems. Because of the chemical complexity of the produced water, its disposal is a major environmental concern. This also increases the disposal costs. Therefore, developing a proper and economical method to shut off or lower excess water has become one of the most significant concerns of the KOC in the NKHO field. Field-2 is a relatively new emerging field with increased intervention complexity due to an increase in water cuts. Early remedial job trials using conventional thermal slurries were unsuccessful in Field-2. This study illustrates the deployment of a novel cementing solution to address the challenges associated with conventional thermal cement for low-pressure, low-temperature, water-shut-off cement squeeze jobs. The slurry design and approach have good potential for vast applications in Kuwait and heavy oil fields worldwide.
