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Formation damage can occur in the vicinity of the wellbore or far field in the reservoir. Organic and inorganic deposition such as asphaltene, paraffin, iron sulfide, barium sulfate and calcium carbonate are the most commonly encountered scale types of damage. Accidental interactions between the completion kill fluid after the perforation or the drilling fluid while drilling through the target zone are also major causes. The decline of well productivity is the first indication of formation damage and can be used as a determining factor of its severity. Therefore, the type of damage, the mechanisms, and controls need to be analyzed and predicted.
This paper presents a detailed and comprehensive review of formation damage including both the external and internal types and the far field and near-wellbore damage. Damage can be identified by observing changes mainly in the well productivity; however, it can be also observed using retrieved equipment such as logging tools and downhole pumps or due to the restricted entry of completion equipment such as inflow control devices (ICDs). The impact of well configuration on the formation damage and the remedy afterwards is also discussed in details.
The present study provides a solution and control criteria for the formation damage and a comprehensive mechanistic modeling is proposed. The model is applied by coupling reservoir modeling with the wellbore conservation equations through the pressure. The effect of horizontal laterals is included by developing three-phase transient equations to account for the flow rate change from toe to heel in the drain hole.
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.
Fadel, A. (Abu Qir Petroleum Company) | Safwat, H. (Abu Qir Petroleum Company) | Dabbour, M. (Abu Qir Petroleum Company) | Belli, A. (Abu Qir Petroleum Company) | Darwish, H. (Schlumberger) | Nagy, M. (Schlumberger)
Abstract The main objective of this paper is to identify any current and future bottlenecks in the production system while honoring operational constraints on wells, production separators, pipelines, and total field gas/liquid processing capacity. It also concerns with identifying any flow assurance issues taking in consideration different field development scenarios for an offshore gas condensate field in the Mediterranean (Abu Qir Field). Liquid loading in gas wells occur when the gas flow rate falls below a critical rate due to reservoir depletion where the accompanying liquids cannot be lifted to surface. Such liquid accumulations at the wellbore can cause the gas well to cease production eventually. Severe slug flow (i.e., terrain-dominated slug flow) was studied. Severe slug flow is characterized by extremely long liquid slugs generated at the base of the vertical riser. This phenomenon occurs at low gas and liquid flow rates and for negative pipeline inclinations. To evaluate future development options and to provide a monitoring tool and realistic results, a multi-disciplinary Petroleum Engineering study was carried out. Unknown reservoir parameters were estimated using the modern production data analysis method, which was also used as a reliable forecasting tool. Steady state multiphase flow simulator and the forecast from production data analysis and numerical reservoir simulator were used to identify any current and future bottlenecks and also optimize the production taking in considerations field's constraints. Transient multiphase flow simulator was used to identify and mitigate transient flow assurance issues i.e. liquid loading in gas wells and slugs in the pipelines. Other scenarios were also studied include: platform start-up and shutdown; production Ramp up due to the introduced platform; and Hydrates no show time due to any shutdown. This helped us to determine the proper design envelope of the new system. This integrated workflow helped in optimizing the current operating conditions and decreasing field operating cost by increasing the current gas production rate by 6%. We managed to prevent the decline in reserves by more than 10% in the future caused by production system bottlenecks. Choke size for each well was identified honoring existing constrains (reservoir pressure, flow velocity limits, etc.) to increase field gas production. Outlet pressure of a surface network was maximized in order to minimize operational costs of gas processing while maintaining required gas production level. Different scenarios were carried out to come with procedures to prevent and mitigate production instabilities and also decreasing the deferred production. This work can subsequently propose an integrated field management workflow on addressing various production issues especially in case of limited data availability and how different domains can co-operate to reach the optimum operating scenarios.
Mata, Carlos (ADNOC Upstream) | Saputelli, Luigi (ADNOC Upstream) | Mohan, Richard (ADNOC Upstream) | Rubio, Erismar (ADNOC Onshore) | Al-Attar, Momamed Ali (ADNOC Onshore) | Alhosani, Abdulla (ADNOC Onshore) | Al-Hosani, Fatima (ADNOC Onshore) | Reddicharla, Nagaraju (ADNOC Onshore)
Production operations in a modern oilfield production system becomes gradually more complex as the water cut increases and artificial lift is applied. To ensure production is continuously optimized, closer communication and a positive feedback loop are required between the petroleum engineer, the production supervisor and control room operators. ADNOC is developing a series of decision support systems to improve collaboration in production operations. One of the key systems consists of 2D operating envelopes charts for the gas lift wells, which relate the control variables of the wells, gas lift rate and production choke opening, with the expected flow behavior. The operating envelopes are visible in the control room and provide guidance to the operators on the stable production range of the wells, whilst leaving flexibility for adjustments, as the immediate production context evolves throughout the day.
The operating envelopes were computed by performing sensitivities on choke and gas lift settings on nodal analysis models of wells, chokes and flowlines, with different manifold pressures. The calculated rates and pressures are compared with a series of mechanical, reservoir and production constraints, to build the 2D envelope chart. The envelope shows the region where the well is in a stable and safe region, together with regions exceeding the maximum allowed casing pressure (MAWOP), hydrate formation, flowing below bubble point, exceeding allowed rates, tubing + flowline erosion, casing heading and tubing heading. The current operating point is shown in the chart, together with the recommended optimum setpoints.
Production operations use the system as a guidance tool to control the wells. The petroleum engineer is expected to keep the well models up to date, to make the operating envelopes robust. On the other hand, the operators are expected to test the wells frequently, to ensure the good quality of the models. Around 2-5% of oil production increase is expected from the continued use of this framework.
This paper discusses a method for optimizing production facilities design for onshore/offshore wells during new field development. Optimizing the development of new oil and gas fields necessitates the use of accurate predication techniques to minimize uncertainties associated with day-to-day operational challenges related to wells, pipelines and surface facilities. It involves the use of a transient multiphase flow simulator (TMFS) for designing new oil and gas production systems to determine the feasibility of its economic development.
A synthetic offshore oil field that covers a wide range of subsurface and surface facility data is considered in this paper. 32 wells and two reservoirs are considered to evaluate the effect of varying sizes of tubing, wellhead choke, flowline, riser, and transport line. A detailed investigation of the scenario of emergency shutdowns to study its effect on the system is performed using TMFS. Other scenarios are also evaluated such as startup, depressurization, pigging, wax deposition, and hydrate formation.
This paper provides a method to minimize the cost by selecting the optimum pipelines sizes and diameters, and investigating the requirements of insulation, risk of pipeline corrosions and other related flow assurance parameters. Different facility design scenarios are considered using TMFS tool to achieve operational flexibility and eliminate associated risks. Pressure and temperature conditions are evaluated under several parametric scenarios to determine the best dimensions of the production system. This paper will also provide insight into factors affecting the flow assurance of oil and gas reservoirs.