Operators in unconventional shales are continuously looking for ways to reduce potential emissions from production facilities. This is especially challenging in liquid-rich regions, such as the Marcellus Shale. As regulations and various industry best practices evolve, facility designs and equipment must evolve as well. Facility-design improvements and successful operational procedures were examined to eliminate or significantly reduce emissions (Porter et al. 2016).
By taking a proactive approach, operators can significantly reduce emissions. In a previous work (Porter et al. 2016), we discussed the key elements of a successful program: (1) a facility design and operational philosophy that considers emission controls, (2) a comprehensive maintenance program that addresses all unplanned or unintended releases encountered during optical-gas-imaging inspections and allows for feedback to facilitate corrective action, and (3) a focused plan for improving technology to diminish the quantity of future leaks. Applying enhanced technology and past experiences to older designs is often the most efficient measure for reducing potential emissions. While these elements are crucial, equally important is the historical defining and tracking of actual identified leaks and the documentation of corrective actions that were taken (Porter et al. 2016). This work further corroborates these key elements.
Additional facility designs for maximum emissions reduction were compared to facility designs in our previous work (Porter et al. 2016), using calculated emissions for each scenario. As well production increases (owing to longer lateral drilling and enhanced stimulation practices), wellsite liquid handling and vapor control become challenging. Techniques for effectively controlling vapors and mitigating emissions were explored in detail, using an actual case study. Also, a previous leak-detection field study with preliminary data was updated with additional years of data, which yielded further clarification of emissions released on a field and pad level with resulting variations in time. Detailed data analysis compiled from inspections identified the most common areas where leaks occur within a production facility—the majority of which were located on atmospheric stock tanks. Data further demonstrated the effectiveness of higher-quality tank relief valves for reducing fugitive leaks.
Production-facility emissions can be managed by using effective production-facility designs and technologies. The present work offers an improved understanding of how technological evolutions can support effective design solutions and processes in a modern shale-gas development (Porter et al. 2016).
Renato P. Coutinho and Paulo J. Waltrich*, Louisiana State University Summary In this paper we describe using a commercial transient multiphase-flow simulator to develop a new operational procedure for liquidassisted gas lift (LAGL) unloading. The simulation model is used in our study to perform sensitivity analysis on the controlling parameters for the LAGL unloading operation. This simulation model is validated with experimental data from field-scale test data presented by Coutinho et al. (2018). From the simulation results and experimental data, it is possible to demonstrate how the injection of a gas/liquid mixture can significantly decrease the injection pressure for unloading operations. Different combinations of injection gas/liquid ratio are numerically tested to evaluate the effect of gas/liquid ratio on the injection pressure during the complete unloading operation. The validated model was used with a newly developed procedure for the complete unloading operation. The modeling results show that using the LAGL technique enabled us to reduce the injection pressure from 1,200 psig, when using single-phase gas in a singlepoint injection system, to approximately 700 psig, when injecting gas/liquid mixtures in a single-point injection system. Analyses on the effect of gas lift valve-orifice size, also presented here, show that using large orifice sizes might reduce the effect of flow friction through the gas lift valve, which directly affects the efficiency of the LAGL unloading operations. As part of the gas lift technique, heavy fluids (e.g., reservoir or completion fluids) need to be lifted out of the casing and production tubing to start or reestablish production. This fluid-removal process is known as wellbore unloading. The kickoff injection pressure is kept low to reduce compression power (Capucci and Serra 1991), which is directly related to the reduction of compressor size and compression cost. Empirical methods are often used to determine the vertical position of the gas lift valves.
Gaurav Seth, Ernesto Valbuena, Soong Tam, Will Da Sie, Hemant Kumar, Brian Arias, and Troy Price, Chevron Summary In this paper we present the results and analyses from an integrated simulation study focused on evaluating and selecting subsea boosting systems. The integrated model uses field-management strategies incorporating flowline routing, field and gathering-network constraints, and rate allocation. Novel techniques to model subsea networks enable selection of the boosting system and provide an improved understanding of dynamic conditions encountered in deepwater assets. The selected boosting system ensures safe and reliable operations while improving the project's net present value. Combining responses from reservoir and network systems into an integrated model to evaluate the subsea design requirements is a unique aspect of this study, because this involves novel modeling techniques for boosting systems (pumps). Analysis of these outputs leads to an improved understanding of field operation strategies, equipment selection and sizing, and production forecasts. The integrated model uses inflow performance relationships (IPRs) from reservoir simulation and vertical lift tables to generate performance curves (PCs), representing well deliverability as a function of tubinghead pressure. Comprehensive field-management logic uses the PCs to determine optimal well operating rates that satisfy all subsurface and surface constraints. This approach reduces a complex set of constraints to a single operating rate. Well operating rate is also a function of the pump power, the pump suction pressure, and the fluid phase behavior across the pumps. The integrated model delivers pump performance within its operating envelope and ensures equipment integrity. Two components of the subsea boosting system, single-and multiphase pumps, drove performance optimization and selection of system operating conditions. The study incorporated a comprehensive analysis of system constraints through implementation of complex field-management rules that accounted for well integrity (completions), performance of network equipment (valves, boosters, pump power requirements), facility capacities, and reservoir deliverability. The integrated study identified the different limiting system constraints throughout the life of the field and improved the overall efficiency of the gathering system. Use of PCs to reduce the constraints to a single operating rate provides tremendous computational performance improvement.
In this paper we describe a novel method for water unloading of natural gas wells in mature reservoirs experiencing low reservoir pressures. Current methods for water unloading from gas wells have at least one of the drawbacks of restricting gas production, requiring external energy, using consumable surfactants, or being labor intensive. The proposed design offers a new approach to water unloading that does not restrict or interrupt gas production. It can operate without external energy, and uses no consumables. Virtual and physical simulators have been developed and the full-scale version of the concept has been studied in test wells to demonstrate the feasibility and performance of the new water-unloading concept. An industrial-grade preproduction prototype was tested successfully in a test gas well to validate this study.
A so-called perturb-and-observe (P&O) algorithm is adapted for a novel centrifugal pump to continuously optimize the point of operation. The novel pump coalesces and increases the size of oil droplets in the produced water, resulting in a unique relationship between the coalescing effect and the point of operation, and allowing for the successful implementation of the P&O algorithm. The algorithm was implemented in two different setups, one measuring the dropletsize distribution between the hydrocyclone and the pump, and the other measuring the oil concentration downstream of the hydrocyclone. The latter was considered the most robust because it required no prior knowledge of the system. Nonetheless, both setups achieved satisfying results and compared favorably with a third setup, where the optimal point of operation was predicted using measurements of the upstream produced-water characteristics. Introduction During oil and gas production, significant amounts of water are often produced along with the hydrocarbon mixture. Coproduced water, usually called produced water, can be a considerable source of pollution because it contains combinations of organic and inorganic materials that can lead to toxicity. Because of this, produced water is cleaned before being discharged into the sea or reinjected into a reservoir (Fakhru'l-Razi et al. 2009). Subsequently, in combination with other treatment technologies, hydrocyclones are often used to remove the remaining dispersed oil from the produced water.
Ghobadi, Jalil (Markel Corporation) | Ramirez, David (Texas A&M University, Kingsville) | Khoramfar, Shooka (Texas A&M University, Kingsville) | Jerman, Robert E. (Markel Corporation) | Crane, Michele (Markel Corporation) | Oladosu, Olufemi (Texas A&M University, Kingsville)
Separation of carbon dioxide (CO2) from methane (CH4) using a gas/liquid membrane-contacting system is a promising alternative to conventional absorption techniques, such as wet scrubbers. The main objective of this research was to design, develop, and implement a hollow-fiber membrane-contacting system to absorb and separate CO2 from CH4 in a simulated flare-gas stream.
A gas/liquid contacting system was constructed using microporous polytetrafluoroethylene (PTFE) hollow fibers as a highly hydrophobic membrane. The module used for the experimental studies had 51-mm diameter and 200-mm effective length. The membrane module had a packing density of 60%, and the PTFE hollow fiber used in this module had a mean pore size of 0.48 mm. Experiments were conducted in a laboratory-scale plant fed with a simulated flare-gas mixture containing 2.5% CO2 balanced with CH4 that could produce varying concentrations of inlet gas using a mass-flow controller.
CO2-separation-experimentation studies were performed, and the effect of operational variables on the separation efficiency of the system has been studied. To optimize the gas-separation performance of the membrane module, the effects of gas/liquid-flow rates, the concentration of absorbent, and the nature of the scrubbing liquid were examined. The absorption efficiency of deionized (DI) water and aqueous solutions of sodium hydroxide (NaOH) and diethanolamine (DEA) as the physical and chemical absorbents were compared. Results indicated that increasing the flow rate and concentration of the scrubbing liquid can enhance the separation efficiency; however, increasing the flow rates of the gas phase had a negative effect on the CO2-absorption performance of the system.
The conventional chemical-absorption processes for the separation of CO2 have many drawbacks, such as flooding, channeling, and foaming that can impair the mass transfer between gas and liquid, and possible equipment failure caused by corrosion. Membrane processes can offer attractive opportunities for gas-treatment applications, including removal of acidic-gas compounds from flare-gas streams that can help to mitigate the adverse health effects associated with burning the waste gases.
In this paper we focus on electrical-submersible-pump (ESP) failure caused by scale buildup. Weak fluctuations recorded in the motor current signals several weeks before a failure indicate a change in the motor load. Advanced signal analysis of the motor current data reveals the presence of a dynamic characteristic in the ESP signal during rapid scale buildup in the pump stages. On the basis of the raw data from the motor current draw, a dynamic cascade can be identified in the current marked with the superimposition of several characteristic frequencies added over time that develop into a chaotic trend. Our analysis was conducted with different signal-processing tools, such as Fourier transform, wavelet transform, and chaotic attractors, which described the nature of the scale signature in the current logs. This analysis was the first step toward developing a real-time diagnostic tool for predicting ESP failures.
In this work we expand on the carbon dioxide (CO2) corrosion-rate model presented by DeWaard et al. (1995) using a parameter-varying (PV) approach to improve prediction accuracy. Specifically, the constant coefficients of the reaction-kinetics-dependent term are replaced with varying parameters presented as a function of mean flow velocity and pH. On the basis of experimental data provided by Nešic et al. (1996) and Dugstad et al. (1994), we compare the corrosion-rate predictions between the original model and the proposed model. A significant improvement of the correlation coefficient (R2) from 0.54 to 0.90 is achieved when the PV coefficients replace the constant coefficients. Accurate predictions of the CO2 corrosion rate affect useful life forecasting of oil and gas systems during front-end engineering design studies, facilitate condition-based maintenance, and serve as the basis for the creation of a digital twin for this process.
When waxy oil is transported through a pipeline and the pipeline operating temperature drops below the waxappearance temperature (WAT), the wax will precipitate and eventually deposit onto the pipeline's interior surface if a temperature gradient between the bulk fluid and the pipe wall exists. However, because of various operational factors, routine pigging might be delayed for an extended period, thus allowing the wax deposit to accumulate. When this occurs, progressive pigging is required to gradually remove the wax accumulation. Typically, it starts by launching a bore-finding pig (BFP), as shown in Figure 1, followed by pigs with progressively increasing diameters until the routine pig can be fully resumed. An example of a series of progressive pigs and an example of an intermediate cleaning (IC) pig are shown in Figs. 2 and 3, respectively.
During an acid fracturing treatment in a carbonate reservoir, acid is injected into the formation, thus creating hydraulic fractures and opening existing natural fractures. As the acid flows into natural fractures that intersect hydraulic fractures (main fractures), it etches the walls of the natural fractures, which then increases the natural fractures’ width and generates conductivity. On the other hand, because of the increased acid leakoff into natural fractures, the acid volume in the main fracture decreases, resulting in less conductivity for the main fracture. Existing acid fracturing models estimate the fracture conductivity by assuming that the acid flows and reacts in the hydraulic fractures only. To accurately predict the performance of acid fracturing in naturally fractured carbonate reservoirs, the acid etching of natural fractures should be taken into account when calculating the overall fracture conductivity.
A model was developed to predict the acid fracturing performance in naturally fractured reservoirs. The model assumed that the main fracture was intersected by transverse symmetric natural fractures. The model simulated the acid transport, acid/rock reaction, fracture width increase resulting from etching of the fracture walls, and acid leakoff through natural fractures. The model also assumed that the flow (into natural fractures) and the leakoff were pressure-dependent and were changing with time. The conductivity calculation was based on the previously developed correlation that accounts for the heterogeneous nature of carbonate rock.
The effect of the natural fractures’ geometry on leakoff and created fracture conductivity was investigated. The results showed that length and dynamic width, as well as the natural-fracture spacing, played a significant role in defining the leakoff rate and the conductivity of the hydraulic fracture and the natural fractures. It was also found that the position of the natural fractures along the hydraulicfracture length affected the etching of the natural fractures and the resultant conductivity.
The aim of the model is to enable better prediction of the acid fracture conductivity for naturally fractured carbonate reservoirs and improve the feasibility of acid fracturing applications for this type of formation.