TX 75083-3836, U.S.A., fax (+1) 214-952-9435. AbstractA numerical model has been developed that addresses both plugging of, and sand production through single wrapped screens. The model was developed on the basis of a fractal model for the particle size distribution of reservoir sands. A database of sand types from the North Sea and Haltenbanken areas was established. Principal component analysis was used to reduce the number of significant variables in the database, and to provide a basis for a prediction model for critical slot widths. A series of laboratory experiments were performed, and four critical slot widths were identified for each sand type, defining a safe design interval for screen slot width. A mathematical model was developed that can be used to predict the critical slot widths for other sand types from the area.
Summary In this paper we present a field case based upon a reservoir operated by Statoil in the Norwegian Sea. The case concerns a series of water injectors-i.e., both subsea and platform-that underwent extreme losses of injectivity over short periods of time. When worked over, the wells showed extreme amounts of sand fill that sometimes were several hundreds of meters above the top perforation. The link between well shut-ins and injectivity losses was clear right from the onset of the study. The life of the injectors is thoroughly reviewed and the reasons for the injectivity losses are established.First, it is shown that even under no flow conditions corresponding to shut-in periods, the rock around the wells is too weak to sustain the stresses and fails.Second, it is established that, because of permeability heterogeneity, the wells crossflow during shut-in periods, hence allowing sand to be produced in front of the perforated interval.Third, it is shown that under routine operation conditions the particles produced in front of the perforated intervals are not able to settle in the rathole before injection restarts and hence plug the perforation tunnel upon injection restart.Finally, it is demonstrated that, during a standard shut-in, pressure waves as large as 80 bar are generated because of the so-called water hammer effect that hits the formations as a seismic wave would do. As a consequence, the formation already weakened by sand production undergoes liquefaction that triggers large amounts of sand to be released in the well, thus killing totally its injectivity. Finally, we present how the operating conditions of the wells were successfully changed to avoid repetition of the problems experienced previously. Introduction The problem of sand production has been studied extensively for years by the oil industry and much is known about it.1–9 However, this problem has naturally been associated with producers and not injectors for various obvious reasons.The stress condition around injectors is less prone to lead to sand failure than on producers because of "negative" drawdown.Injectors are rarely backproduced and therefore sand is quite unlikely to be brought to surface and hence be a problem. Yet in truly poorly consolidated reservoirs, even injectors may be affected by the phenomenon of sand failure. In fact, in poorly consolidated reservoirs, injectors are sometimes equipped with sand control means. As for producers, wells with sand controls often suffer from injectivity losses compared with naturally completed ones. However, almost nothing seems to have been reported in the literature in the past about the problem. The only exception is a recent paper by Conoco,10 which presents a case of injectivity losses on water injectors in a weak sandstone reservoir similar to the one addressed below. In this paper we introduce a field case from a reservoir in the Norwegian Sea operated by Statoil that clearly illustrates the risks and problems posed by sand production on injection wells. In this poorly consolidated reservoir, both subsea and platform injectors that were naturally completed had both progressive and dramatic injectivity losses. Several wells even lost all injectivity. We will first present the history of the subsea injectors. We will then show that for the types of formation and in situ stresses expected in the reservoir, the rock around the injectors is under failure conditions during shut-in periods. We will then show that during these shut-in periods crossflow takes place from one layer to another, leading to the production of sand. We will then show how the traditional operating conditions of the field did not allow enough time for such particles to settle and hence the first cause for injectivity loss will be highlighted, i.e., plugging of the perforation tunnels, leading to progressive injectivity loss. Then the dramatic injectivity losses with wells going from 8000 to 0 m3/d in half an hour will be tied to the pressure waves generated during the sudden shutdown of the pumps. Finally, we will show how the operating conditions of the field were altered to avoid reproduction of the problems experienced by the field. Note that in each section specific field observations and measurements will be called upon to confirm the validity of the physical phenomenon used to explain the problem. History of the Subsea Injectors The production and injection wells on the field were predrilled before being put into operation in the fall of 1995 (Fig. 1). The subsea injectors are subvertical with deviations inferior to 25°. After perforation in the aquifer, the wells were quickly backflowed for perforation cleanup purposes. About 5 m3 of water was backproduced. Initially, the wells had quite a good injectivity index and they were easily able to fulfill their target, with capacities to deliver up to 9000 m3/d with the field injection system. Unfortunately, these ideal conditions soon started to deteriorate and daily monitoring of the well injectivity index showed a steady decrease that was not explained at the time. In order to try to improve the situation, a decision was made to backproduce the wells in the winter of 1996. The amount of fluid produced was quite small, less than 50 m3. Immediately upon starting injection, the injectivity was good but it soon decreased quickly within half an hour. It was therefore decided to allow a longer period of flow and to clean the flow line of the sand it contained before restarting injection. During such an operation, the wells were backproduced for 700 to 800 m3. The result of this back production was dramatic. The injection rate of all wells was above 8000 m3/d, with wellhead pressures often at half the full pump capacity. However, as after the initial completion, the injectivity index started to deteriorate again. Furthermore, the injectivity decrease became more dramatic. In several cases, injectivity was completely lost after a brief shut-in of the injection system. As opposed to classical progressive injectivity loss this event will be called dramatic injection loss. To illustrate it, let us look at a typical sequence of events.
This paper presents a field case based upon a reservoir operated by Statoil in the Norwegian Sea. The case concerns a series of water injectors - i.e. both sub-sea and platform - that underwent extreme losses of injectivity over short periods of time. When worked over, the wells showed extreme amounts of sand fill that sometimes were several hundreds of meters above the top perforation. Furthermore, the link between well shut-ins and injectivity losses was clear right from the onset of the study. The life of the injectors is thoroughly reviewed and the reasons for the injectivity losses are established.First, it is shown that even under no flow conditions corresponding to shut in periods, the rock around the wells is too weak to sustain the stresses and fails.Second, it is established that because of permeability heterogeneity, the wells are cross flowing during shut in periods hence allowing sand to be produced in front of the perforated interval.Third it is shown that under routine operation conditions, the produced particles in front of the perforated intervals are not able to settle down in the rat-hole before injection restarts and hence plug the perforation tunnel upon injection restart.Finally, it is demonstrated that during a standard shut in, pressure waves as large as 80 bars are generated because of the so-called water hammer effect that hits the formations as would a seismic wave do. As a consequence, the formation already weakened by sand production undergoes liquefaction that triggers large amounts of sand to be released in the well, hence killing totally its injectivity. Finally, the paper presents how the operating conditions of the wells were successfully changed to avoid the repetition of the problems experienced previously. P. 107
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