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When it comes to methane, there is good news and bad news. Even though carbon dioxide (CO2) has a longer-lasting effect, methane has more than 80 times the warming power of CO2 over the first 20 years after it reaches the Earth's atmosphere and sets the pace for warming in the near term. The challenge of managing methane emissions is a moving target that evolves daily, driven by regulatory uncertainty; altering standards and expectations from government, the public, and various regulatory groups; and carbon markets. Understanding and navigating the options can be overwhelming. No incentives currently exist to use technology other than leak detection and repair (LDAR) solutions specified by regulators, and proponents of alternative leak detection and repair (alt-LDAR) programs must prove that their program works through emissions-reduction equivalence.
Romer, Michael Christopher (ExxonMobil Upstream Research Company) | Spiecker, Matt (ExxonMobil Upstream Research Company) | Hall, Tim James (ExxonMobil Upstream Research Company) | Dieudonne, Raphaël (Hydro Leduc) | Porel, François (Hydro Leduc) | Jerzak, Laurent (Hydro Leduc) | Ortiz, Santos Daniel (KSWC Engineering & Machining) | King, George Randall (KSWC Engineering & Machining) | Gohil, Kartikkumar Jaysingbhai (KSWC Engineering & Machining) | Tapie, William (Deteq Services) | Peters, Michael (MTI) | Curkan, Brandon Alexander (C-FER Technologies)
Summary What do you do after plunger lifting? What if lift gas is not readily available or your liquid level is around a bend? What can you do with a well that has low reservoir pressure, liquid-loading trouble, and fragile economics? Do you give up on the remaining reserves and advance to plugging and abandonment? These questions were considered, and the answers were found to be unsatisfactory. This paper will describe the development and testing of a novel wireline-deployed positive-displacement pump (WLPDP) that was invented to address these challenges. Artificial-lift (AL) pumps have historically been developed with high-producing oil wells in mind. Pumps for late-life wells have mostly been repurposed from these applications and optimized for reduced liquids production. The WLPDP development began with the constraints of late-life wells with the goal of addressing reserves that conventional AL methods would struggle to produce profitably. Internal and industry-wide data were first reviewed to determine what WLPDP specifications would address the majority of late-life wells. The primary target was gas wells, although “stripper” oil wells were also considered. The resulting goal was a pump that could deliver 30 BFPD from 10,000-ft true vertical depth (TVD). The pumping system must be cost-effective to be a viable solution, which led to several design boundaries. Pumps fail and replacement costs can drive economics, so the system must be deployable/retrievable through tubing. The majority of new onshore wells have tortuous geometries, so the system must be able to function at the desired depth despite them—without damaging associated downhole components. The system should use as many off-the-shelf components and known technologies as possible to reduce development costs and encourage integration. Finally, the pump should be able to handle a variety of wellbore liquids, produced gases, and limited solids. The WLPDP was designed to meet the established specifications and boundary conditions. The 2.25-in.-outer-diameter (OD) pump is deployed through tubing. and powered with a standard wireline (WL) logging cable. The cable powers a direct-current (DC) motor that drives an axial piston pump. The piston pump circulates a dielectric oil between two bladders by means of a switching valve. When each bladder expands, it pressurizes inlet-wellbore liquids, pushing them out of the well. Produced gas flows in the annulus between the tubing and production casing. The intake/discharge check valves and bladders are the only internal pump components that contact the wellbore fluids. The WLPDP system was able to meet the design-volume/pressure specifications in all orientations, as confirmed through laboratory and integration testing. Targeted studies were conducted to verify/improve check-valve reliability, gas handling, elastomer suitability, and cable-corrosion resistance. The results of these and related studies will be discussed in the paper.
Kumar, Shailesh (Indian Institute of Petroleum and Energy) | Rajput, Vikrant Singh (Oil and Natural Gas Corporation Limited) | Mahto, Vikas (Indian Institute of Technology (Indian School of Mines) (Corresponding author)
Summary The development of concentrated and highly stable oil-in-water (O/W) emulsion is considered to be a cost-effective alternative for the transportation of produced heavy crude oils. However, the demulsification of a transported O/W emulsion is necessary once it reaches the destination. This article experimentally investigates the performance of four low-cost chemicals of varying water solubility as potential demulsifiers, independently and in combinations, for demulsifying two Indian heavy crude O/W emulsions prepared for pipeline transportation. The chemical demulsifiers used, in order of their higher water solubility, are: polyethylene glycol 400 (PEG) > polyoxyethylene (20) sorbitan monooleate (Tween-80) > linear alkylbenzene sulfonic acid (LABSA) > n-octylamine (OA). For this study, stable O/W emulsions (in the 60:40 ratio) of two Indian heavy crude oils were prepared using high-frequency ultrasonic waves in the presence of Triton X-100 as a surfactant. Both crude oils were characterized at first based on their physicochemical properties, infrared (IR) spectrum, and rheological properties. Prepared O/W emulsions were characterized based on rheological properties and droplet size. A bottle test method with heating (using a water bath) and enhanced gravity (by centrifuge) has been used to study the demulsification efficiency of used chemicals. Complete demulsification of both emulsions was achieved as desired. The synergetic effect of the interaction between two suitable demulsifiers provided remarkably better performance than that of independent returns, leading to minimization of the amount of demulsifier and the energy requirement for complete demulsification of both emulsions.
A total of 11 universities have secured their eligibility to participate in the the 2021 PetroBowl Championship that will be held during the 2021 SPE Annual Technical Conference & Exhibition in Dubai. The teams won their regional qualifiers for the Europe, Russia and Caspian, and North America and Canada regions during Q1 2021. The remaining 21 spots will be filled in the next few months from universities in the Asia Pacific, Middle East and North Africa, Sub-Saharan Africa, and Latin America and Caribbean regions. The PetroBowl is SPE's largest student competition in which petroleum engineering students from SPE student chapters around the world participate to demonstrate their expertise on topics relevant to the petroleum industry. The contest moved to a virtual platform last year due to Covid-19 travel restrictions and this year's regional qualifiers were also conducted virtually.
Suncor Energy is preparing for all contingencies when in comes to the fate of the Terra Nova FPSO. The operator recently issued Expressions of Interest (EOI) related to the FPSO, including two that prepare for decommissioning of the vessel and the field, while another provides an update to a previous EOI preparing for remediation of the FPSO to support the asset life-extension project. The move has the Newfoundland and Labrador Oil & Gas Industries Association (NOIA) concerned about the future of the vessel and the field. "NOIA members and our Board of Directors are deeply concerned for the future of the Terra Nova Project and the far-reaching impacts decommissioning and abandonment would have upon our industry, the people who work in it, and our province," said Charlene Johnson, chief executive of NOIA. "I understand the deadline to reach a deal on the Terra Nova Project was extended to April 30--which has now passed--and NOIA is encouraging all parties to reach an agreement as quickly as possible."
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 The industry is facing significant challenges due to the recent downturn in oil prices, particularly for the development of tight reservoirs. It is more critical than ever to 1) identify the sweet spots with less uncertainty and 2) optimize the completion-design parameters. The overall objective of this study is to quantify and compare the effects of reservoir quality and completion intensity on well productivity. We developed a supervised fuzzy clustering (SFC) algorithm to rank reservoir quality and completion intensity, and analyze their relative impacts on wells' productivity. We collected reservoir properties and completion-design parameters of 1,784 horizontal oil and gas wells completed in the Western Canadian Sedimentary Basin. Then, we used SFC to classify 1) reservoir quality represented by porosity, hydrocarbon saturation, net pay thickness and initial reservoir pressure; and 2) completion-design intensity represented by proppant concentration, number of stages and injected water volume per stage. Finally, we investigated the relative impacts of reservoir quality and completion intensity on wells' productivity in terms of first year cumulative barrel of oil equivalent (BOE). The results show that in low-quality reservoirs, wells' productivity follows reservoir quality. However, in high-quality reservoirs, the role of completion-design becomes significant, and the productivity can be deterred by inefficient completion design. The results suggest that in low-quality reservoirs, the productivity can be enhanced with less intense completion design, while in high-quality reservoirs, a more intense completion significantly enhances the productivity. Keywords Reservoir quality; completion intensity; supervised fuzzy clustering, approximate reasoning,tight reservoirs development
Abstract Recovery factor for multi-fractured horizontal wells (MFHWs) at development spacing in tight reservoirs is closely related to the effective horizontal and vertical extents of the hydraulic fractures. Direct measurement of pressure depletion away from the existing producers can be used to estimate the extent of the hydraulic fractures. Monitoring wells equipped with downhole gauges, DFITs from multiple new wells close to an existing (parent) well, and calculation of formation pressure from drilling data are among the methods used for pressure depletion mapping. This study focuses on acquisition of pressure depletion data using multi-well diagnostic fracture injection tests (DFITs), analysis of the results using reservoir simulation, and integration of the results with production data analysis of the parent well using rate-transient analysis (RTA) and reservoir simulation. In this method, DFITs are run on all the new wells close to an existing (parent) well and the data is analyzed to estimate reservoir pressure at each DFIT location. A combination of the DFIT results provides a map of pressure depletion around the existing well, while production data analysis of the parent well provides fracture conductivity and surface area and formation permeability. Furthermore, reservoir simulation is tuned such that it can also match the pressure depletion map by adjusting the system permeability and fracture geometry of the parent well. The workflow of this study was applied to two field case from Montney formation in Western Canadian Sedimentary Basin. In Field Case 1, DFIT results from nine new wells were used to map the pressure depletion away from the toe fracture of a parent well (four wells toeing toward the parent well and five wells in the same direction as the parent). RTA and reservoir simulation are used to analyze the production data of the parent well qualitatively and quantitatively. The reservoir model is then used to match the pressure depletion map and the production data of the parent well and the outputs of the model includes hydraulic fracture half-lengths on both sides of the parent well, formation permeability, fracture surface area and fracture conductivity. In Field Case 2, the production data from an existing well and DFIT result from a new well toeing toward the existing wells were incorporated into a reservoir simulation model. The model outputs include system permeability and fracture surface area. It is recommended to try the method for more cases in a specific reservoir area to get a statistical understanding of the system permeability and fracture geometry for different completion designs. This study provides a practical and cost-effective approach for pressure depletion mapping using multi-well DFITs and the analysis of the resulting data using reservoir simulation and RTA. The study also encourages the practitioners to take every opportunity to run DFITs and gather pressure data from as many well as possible with focus on child wells.
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.
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.