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Kashou, Sam (Texaco Upstream Technology Department ) | Matthews, Patrick (Texaco Upstream Technology Department ) | Song, Shanhong (Chevron Petroleum Technology Company) | Peterson, Bret (Texaco New Orleans Business Unit - GOM Operations ) | Descant, Frank (Chevron North America Exploration and Production)
Abstract The rapid uptake of transient multiphase flow simulation of wells demonstrates the recognised value to the Industry of this relatively new technique. In offshore, subsea and deepwater well locations, and in long horizontal, multi-layer, multi-lateral, big-bore and complex well completions, Industry can benefit from dynamic simulation for sound engineering design, and optimisation of costs and production. Dynamic simulation provides the possibility of building a virtual well that can be used to analyse "what if" case scenarios and predict specific results. It is an excellent tool to understand transient well behaviour and determine the optimum process to eliminate or minimise potential transient problems. It does not replace NODAL® analysis but fills a gap where NODAL® analysis techniques cannot provide solutions. Once the dynamic well model is validated it can also be used as an implicit gauge and/or a virtual DTS during production/injection operations. This paper details some applications, and provides guidelines for the proper use of dynamic simulation in key areas including: well clean-up, well kick-off, watercut limit, flow stability, flow assurance (hydrates), gas lift requirements, large tubing ID flow, production optimisation, and well test equipment sizing. Well Dynamic Simulation is a useful tool that can be used during FEED and at any stage of the well life cycle to "virtually" run through a complete case scenario and predict the well multi-phase flow behaviour (including trends and profiles of liquid hold-up, pressure and temperature), providing valuable information to optimise technical, operational and HSE integrity during design and operation of production systems. Introduction Dynamic simulation is a proven tool applied for years by facilities engineers for pipeline and slugcatcher designs. The application of multiphase flow transient simulation in wells is a new practice which requires different understanding and expertise. Multi-discipline teams or cross-discipline experience is required to properly build and integrate the well model into the total production system model. The development of offshore, subsea, and deepwater fields and the use of more sophisticated drilling techniques and well completions require greater understanding of the transient pressures, temperatures and liquid hold-up. The high capital and operating costs, clearly merit detailed dynamic analysis of wells and associated production systems. Currently, there are no best practice standards for the application of dynamic simulation to wells. The main objective of this paper is, therefore, to create awareness and present some guidelines to facilitate the application of this technique in order to optimise well integrity, well operations, well life cycle design and production. Firstly, the dynamic simulation techniques are compared with traditional steady state NODAL® analysis techniques to define the areas of application. Secondly, the main well dynamic applications (using "predictive" and "matching" approaches) are discussed and examples of relevant cases are provided. The results of which provide the confidence to use dynamic simulation in design and operations to minimise risk, uncertainty, safety hazards and environmental impact and optimise CAPEX-OPEX and production. The dynamic simulation work covered in this paper was performed using the multiphase flow transient numerical simulator OLGA.
Abstract A deepwater satellite field project encompasses two fields which are in the general vicinity of two existing Floating Production Storage and Offloading (FPSO) vessels. A number of development architectures that include various subsea tie-backs to two existing FPSOs and, in some cases, an additional FPSO were potential candidates for development. To accelerate the project schedule, Reservoir and Subsea, Umbilicals, Risers, and Flowlines (SURF) Engineering were conducted in parallel. In order to establish an optimal SURF architecture, a method to forecast production behavior of the various architectures is required. To achieve this objective, an Integrated Production Modeling (IPM) tool was developed. Components of this tool model reservoir material balance, well, flowline, riser, and facility performance throughout the project life. Flow assurance analysis, project planning, evaluation, and optimization are facilitated by this model. IPM achieves these objectives by enabling rapid generation of production forecasts consistent with available field information while honoring hydraulic and capacity constraints. When an optimal SURF architecture was developed, system operability was assessed by applying transient flowline and riser analysis to the production system. System operability requires that the SURF architecture is viable over a range of operating conditions spanning upside and turndown scenarios. Upon completion of the rigorous reservoir models, rate profiles were generated by reservoir simulation and compared to the range of rates used to develop the SURF architecture. The reservoir simulation rate profile was contained within the operating range used to develop the SURF architecture. Application of IPM resulted in an optimal SURF architecture, which was developed in parallel with the rigorous reservoir models. The parallel engineering effort allowed an extensive investigation of SURF architectures while accelerating the project schedule.
Simms, Gerard John (LLOG Exploration Company L L C) | Fowler, Richard Lee (LLOG Exploration Co LLC) | Cooley, Bruce Dale (LLOG Exploration Co LLC) | Leontaritis, Kosta J. (Asphwax Inc.) | Krishnathasan, Kana (Intecsea)
Abstract This paper will discuss the viability of producing multiple deepwaterreservoirs with vastly different fluid properties from a subsea development in3,100 feet of water in the Gulf of Mexico. A summary of the diagnostic anddetailed flow assurance (FA) testing of different density oils will bepresented, addressing viscosity including non-Newtonian behavior, wax, asphaltene and hydrate behavior, downhole and flowline commingling, and fluidcompatibility tests. The paper will discuss the transient behavior in a deepwater subsea developmentusing the results from the transient simulation model. Operability of theinfield flowline system as it pertains to hydraulics, pressure, temperature, wax appearance, hydrate formation, slugging, commingling of zones, shutdown, and restarts will be addressed. Provisions for pigging and a chemical programwere added for extra assurance. A larger size oil export line was selected toallow sufficient capacity for blended and/or heavy oils after restart. Finally, the steady state model was used to link the reservoir tanks, wellbores, andflowlines to confirm the hydraulics of the production system (i.e. flowlinesize and facility capacity). Background The Who Dat field is located in the Mississippi Canyon protraction area of theGulf of Mexico in blocks 503, 504, and 547 (Figure 1), and is being developedusing the Opti-Ex semisubmersible floating production system (FPS) which has acapacity of 60 MBOPD and 150 MMCFD. The Who Dat discovery is primarily oil andconsists of ten stacked amplitude-supported reservoirs in a salt withdrawalmini-basin. Three wells have been drilled to date, penetrating over 700' of netpay in nine distinct reservoirs ranging in depth from 12,000' to 17,000' TVD. Both gas and oil reservoirs were found with varying fluid properties (Table 1).A significant amount of fluid data were acquired in the open hole programresulting in over 60 downhole fluid samples. Twelve full PVT studies and eightdiagnostic flow assurance studies were performed for early fluid understanding. Later, flowback oil samples were acquired, rechecked, and furtherevaluated. The field will be developed with 12 subsea wells (i.e. wet trees) flowing tothree four-slot subsea manifolds. Drill center A has one (1) manifold and drillcenter E has two (2) manifolds. Each drill center's manifolds are connected tothe production facility (FPS) via dual 6" nominal wet insulated flowlines andflexible risers with the capacity of roundtrip pigging. The length of theseinfield flowlines are about 3 miles and the geometry of the seafloor results ina down sloping flowpath. The project includes a 10" gas export line and 14" oilexport line also using flexible risers. The field subsea layout is shown inFigures 2 and 3. The key inputs into the flow assurance process are non-contaminated fluidsamples and detailed lab analysis. In the case of system selection for the WhoDat field, fluid samples were available from three wells and multipleformations. There are some uncertainties about key formation fluid propertiesdue to drilling fluid contamination, such as viscosity, foaming, and waxcontent. Project challenges from a flow assurance perspective are summarizedbelow:Wide variation in the physical properties of the fluids in each reservoir(density from 15° to 45° API) High viscosity of produced fluids Foaming of fluids and affects on metering Commingling production Downward sloping flowpath of oil and gas (flowlines) Non-Newtonian fluid behavior (oil export pipeline)