Salt Precipitation in Gas Reservoirs
- Quirinius Teunis Van Dorp (OMV Austria E&P) | Maarten Slijkhuis (Wintershall Noordzee B.V.) | Pacelli Lidio Jose Zitha (Delft U. of Technology)
- Document ID
- Society of Petroleum Engineers
- 8th European Formation Damage Conference, 27-29 May, Scheveningen, The Netherlands
- Publication Date
- Document Type
- Conference Paper
- 2009. Society of Petroleum Engineers
- 4.6 Natural Gas, 5.4.2 Gas Injection Methods, 1.8 Formation Damage, 2.2.2 Perforating, 1.2.3 Rock properties, 4.1.2 Separation and Treating, 5.2 Reservoir Fluid Dynamics, 4.1.4 Gas Processing, 5.5 Reservoir Simulation, 5.5.2 Core Analysis, 5.2.1 Phase Behavior and PVT Measurements, 1.6.9 Coring, Fishing, 4.3.4 Scale, 5.3.2 Multiphase Flow, 2.4.3 Sand/Solids Control
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This paper reports a study of halite precipitation in gas reservoirs and the ensuing formation damage. The examination of productivity decline in several wells revealed that halite precipitation is most likely due to water evaporation with pressure drop in the vicinity of the well-bore. Hence the model was developed in an attempt to capture the main features of this phenomenon. In addition to the classical mass and momentum conservation equations the model includes equations describing: (a) the evaporation and salt precipitation kinetics and (b) the modification of porosity and permeability due to restriction of the pores by the halite precipitate. The equations were solved numerically for the one dimensional case, using standard reservoir simulation methods.
Laboratory experiments were performed using a sand pack containing highly saline water at ‘irreducible' water saturation. The sand pack was conical in shape to simulate radial inflow effects. CT scans of the sand pack were used during the experiments, in conjunction with pressure drops monitored over several sand pack segments, to reveal the details of salt precipitation. This enabled us also to quantify the water saturation and to check the integrity of the sand pack, as pressured gas flow might cause viscous fingering. Simulator results clearly show increased pressure drop over the length of the sand pack; especially so at the narrow outlet section of the sand pack, indicating that salt precipitation occurs predominantly in what would be the near wellbore region. CT scans and conductivity measurements of individual sand pack segments have confirmed these results in the lab.
Production wells in gas reservoirs occasionally experience rapid performance decline as recovery progresses. In many cases, this behaviour may be attributed to halite scale in the near well bore area around the perforated pay zone or within the wellbore (Figure 21). For certain gas wells in the North Sea region, regular down-hole fresh water treatments lasting half a day are required to restore production rates (Figure 20). Figure 20 shows production rates as a function of time. From the end of March to the end of May a rapid decline in production rates is observed. A water wash at the end of May was sufficient to restore production rates. Further water treatments at the beginning of July and the end of August again were required to maintain high flow rates. It is clear that these treatments allowed overall production decline from end of March to end of August to be limited to 100,000 Nm3/day, which is related to natural depletion.
Salt accumulation has been indicated by mechanical wireline surveys, a video camera survey (Figure 21 and Figure 22), and by well performance data (Figure 20). Most salt was found in the upper perforations. A salt sample revealed almost pure halite scale.
A better understanding of salt precipitation phenomena as well as the conditions under which this takes place is needed for a better productivity control. It may reduce or even eliminate the necessity for down-hole fresh water washes. This study is concerned with the modeling of the salt precipitation process. Several models for this phenomenon have been reported in the literature.
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