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Casing and tubing strings are the main parts of the well construction. All wells drilled for the purpose of oil or gas production (or injecting materials into underground formations) must be cased with material with sufficient strength and functionality. Casing is the major structural component of a well. The cost of casing is a major part of the overall well cost, so selection of casing size, grade, connectors, and setting depth is a primary engineering and economic consideration. Conductor casing is the first string set below the structural casing (i.e., drive pipe or marine conductor run to protect loose near-surface formations and to enable circulation of drilling fluid).
While downhole pumps and sucker rods are the chief components of a sucker-rod lift type artificial lift system, a number of other components are also used in the subsurface portion of the system. These include tubing, tubing anchor-catchers, tubing rotators, sinker bars, rod centralizers, and paraffin scrapers. Tubing provides detailed information on the design, selection, and use of tubing for production wells. As related to most sucker-rod-lifted wells, the standard weight of external-upset-end, API tubing should be used because of the increased wall thickness in the threaded ends. Thus, if there is rod coupling-on-tubing wear, more life and fewer leaks will be realized than if nonupset API tubing is used. Using API Grade J55 tubing, consider full-body normalizing after upsetting to prevent "ringworm corrosion" in the heat-affected upset region when the tubing is placed in corrosive (H2S or CO2) service.
Replacing a rod string one rod at a time is not normally a good operating practice; thus, the economic life of a rod string needs to be considered if rods start to fail. Typically, the rod-string section will be replaced after two or three failures, while the entire rod string may be replaced after three or four failures. However, the reasons for failures need to be investigated and the root cause for this failure must be determined to extend the rod life in the future. An SPE paper by Powers considers the factors that enter into the decision about when to replace the entire rod string after sustaining the calculated number of failures. Usually, wells of the same type in a field can be grouped together and the necessary calculations do not have to be performed for each well. Sufficient calculations need to be done to assess the economic impact for all wells in a field. There has been a long history of work trying to model or design sucker-rod strings. This includes the original work from Slonneger and Mills on vibration effects of rod strings. Fatigue of rods also was considered in 1940.
Progressing cavity pump systems are, in general, highly flexible in terms of their ability to function effectively in a diverse range of applications. As with other artificial-lift systems, the basic objective in the design of a PCP system is to select system components and operating parameters (e.g., pump speed) that can achieve the desired fluid production rates while not exceeding the mechanical performance capabilities of the equipment components to facilitate optimal service life and system value. When a PCP system is designed for a particular application, both the system components and operating environment must be considered to ensure that a suitable system design is achieved. Figure 1 presents a "design process" flow chart that outlines the many factors and considerations that should be addressed in the selection of an effective overall system configuration and operating strategy. At each step, the designer selects certain operating parameters or specific equipment components and must then assess the impacts of these decisions on system performance. For example, selection of a particular tubing size is based on such design considerations as flow losses and casing size.
The American Petroleum Institute (API) has numerous manufacturing requirements for tubing. Many API standards have also been adopted by the International Standards Organization (ISO). The tubing purchaser and designer should be aware of API requirements and testing procedures (see API Spec. All tubing should meet API minimum requirements. In critical wells, the purchaser may want to receive and review the manufacturer's test results.
Casing and tubing costs are significant factors in the well cost that must be properly estimated in the authority for expenditure (AFE). In some cases, they may account for 50 to 60% of the total expenditures. The costs are dependent on well depth, size, grade requirements, and couplings. Pipe costs are influenced heavily by several factors. Pipe size is a major consideration.
The Merriam-Webster Dictionary defines simulate as assuming the appearance of without the reality. Simulation of petroleum reservoir performance refers to the construction and operation of a model whose behavior assumes the appearance of actual reservoir behavior. The model itself is either physical (for example, a laboratory sandpack) or mathematical. A mathematical model is a set of equations that, subject to certain assumptions, describes the physical processes active in the reservoir. Although the model itself obviously lacks the reality of the reservoir, the behavior of a valid model simulates--assumes the appearance of--the actual reservoir. The purpose of simulation is estimation of field performance (e.g., oil recovery) under one or more producing schemes. Whereas the field can be produced only once, at considerable expense, a model can be produced or run many times at low expense over a short period of time. Observation of model results that represent different producing ...
Bit- and casing-size selection can mean the difference between a well that must be abandoned before completion and a well that is an economic and engineering success. Improper size selection can result in holes so small that the well must be abandoned because of drilling or completion problems. The drilling engineer (and well planner) is responsible for designing the hole geometry to avoid these problems. However, a successful well is not necessarily an economic success. For example, a well design that allows for satisfactory, trouble-free drilling and completion may be an economic failure, because the drilling costs are greater than the expected return on investment.
Pathak, Varun (Computer Modelling Group Ltd.) | Mirzabozorg, Arash (Computer Modelling Group Ltd.) | Zuloaga, Pavel (Pluspetrol Peru Corp.) | Dorival Vargas, Jose Miguel (Pluspetrol Peru Corp.) | Klix, Belen (Pluspetrol)
Camisea asset is possibly the most important mega gas asset in South America, and constitutes for more than 90% of Peru’s gas production. The asset consists of several fields with varying degrees of subsurface complexities, multiple fluid types ranging from very lean to very rich gas condensate. The combined production is routed to gas processing plant via a network of pipelines. The entire development is in an environmentally sensitive area and adds to the complexity of the surface network design process. For these reasons, performing integrated production systems simulations is essential for designing the surface network with appropriate fidelities for each component of the IPSM.
In current work, a complex integrated production system was developed for Block A of the asset. It is a 2-field system with complex fluid behavior. The various fluids blend in the well tubings, as well in the combined surface network. The produced gas is treated in the plant for liquid extraction, and dry gas is routed for sales and re-injection. For all this work, a new multi-fidelity IPSM tool was used in both implicit as well as explicit coupling mode.
This was achieved by doing both implicit as well as explicit coupling of the reservoir simulation models with well models and surface network model. As a result of this work, a reliable long-term production forecast of the field could be performed. Additionally, the pipe design and network constraints could be evaluated and compression needs variation with time could be assessed. Lastly, with the use of a fit-for-purpose fidelity level for any IPSM component, more efficient and reliable forecasts could be readily generated.
A comparison between implicit and explicit coupling of IPSM components is generally missing from the available literature. This study fills in this gap by providing the option to do the two couplings using a single simulation tool, thus providing a consistent comparison. In addition to the various long-term production forecasts, the benefits and drawbacks of the two coupling approaches has been presented in this paper.
McPhail, Finlay (Shell Global Solutions International B.V.) | Auburtin, Erwan (TechnipFMC) | van Haaften, Ewoud (Shell Global Solutions International B.V.) | Yates, Darren (Shell Brasil Exploration and Production) | McConochie, Jason (Shell Australia Pty. Ltd.) | Leridon, Aurelien (TechnipFMC) | Lefebvre, Timothee (TechnipFMC)
The Prelude Floating Liquefied Natural Gas (FLNG) facility is designed to offload Liquefied Natural Gas (LNG) and Liquefied Petroleum Gas (LPG) to carrier vessels moored in a Side by Side (SBS) configuration, using Marine Loading Arm (MLA) technology. This operation is novel and therefore could impact the project economics. The design was subject to extensive verification to ensure it could reliably support operations. Robust methods of quantitatively assessing an entirely novel, and complex, offshore operation were developed.
The high offtake cadence, exposed location, and range of different variables associated with the Prelude operation represented multiple technical challenges. There are few international standards which can be drawn from for this type of operation.
Limiting criteria for the operation have been developed through bridge simulations and consultation with marine technical experts. Additional limiting criteria are derived from marine hardware. Wind tunnel modelling, wave basin modelling, and other experiments have been performed. Innovative modelling techniques for multibody hydrodynamic modelling were developed to provide quantification of operational effectiveness and reliability. Novel operational assessment tools and method have been developed.
Hydrodynamic models have been developed for a range of different LNG and LPG carriers based on potential theory. These models include non-linear mooring characteristics, multi-body coupling, and coupling with sloshing effects. Multiple research projects have been executed to effectively model these different characteristics and validate the numerical modelling.
These models have been analyzed against a set of statistically representative MetOcean data derived from a 39 year hindcast of the Prelude location. The reduction of this data to statistically representative bins simplified modelling overhead. Multiple and increasing permutations of carriers, load conditions, and mooring configurations resulted in more than 100,000 time-domain simulations being required to evaluate the operation.
Combinations of different simulations and stages of loading to derive ‘window’ operability were established based on work with marine experts. Significant effort was applied to develop realistic models and assumptions for input to economic assessment and predictive tools for operational planning.
To mitigate the effects of a range of transient conditions, methodologies for employing the FLNG thruster system were developed in coordination with the marine and operations team. Methods for modelling these operational approaches were derived to enhance the operational effectiveness of FLNG and improve the predictive capabilities for operators.
Prelude represents the first of its kind for such a scale and exposed location. Significant novel methods for effectively analyzing such a complex situation were pioneered and refined for this project. There has also been an important feedback loop between operations readiness, operations, and analysis which has lead to safe and successful first operations. Measurements collected aboard Prelude and during future operations should enable further refinement and accuracy of modelling to support enhanced operational effectiveness.