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Halite Scale Formation in Gas-Producing Wells
0263–8762/03/$23.50+0.00 # Institution of Chemical Engineers Trans IChemE, Vol 81, Part A, March 2003
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HALITE SCALE FORMATION IN GAS-PRODUCING WELLS ¨ HLER W. KLEINITZ, G. DIETZSCH and M. KO Preussag Energie GmbH, Lingen, Germany
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n Northern German gas reservoirs, the precipitation of salt from the reservoir water is observed to an increasing extent as recovery progresses. The resulting halite scale causes a signi cant decrease in production rate, all the way to complete blockage of the ow paths and ultimately the abandonment of wells. In order to remove salt deposits as well as prevent the precipitation of salt in the zone immediately surrounding the well, fresh water treatments are performed at regular intervals during production operations. This paper addresses the entrainment of reservoir water from gas reservoirs, even in reservoirs without active edge-water drive, and the halite precipitation in depleted gas wells on the basis of theoretical considerations. The discussion includes a description of chemical parameters determined from analysis of reservoir water for the early detection of salt precipitates in the reservoir rock. Besides the implementation of the fresh water treatment in practice, special attention is paid to the dissolution behaviour of halite scale. The ionic distribution in the back-produced treatment uid is evaluated with reference to the prevailing reservoir conditions. During the past 17 years, a large number of fresh water stimulations have been conducted in Northern German gas reservoirs. The results of these operations are explained in detail. The success of the stimulation based on the change in productivity index is evaluated and interpreted for parameters such as treatment volume and shut-in time. Keywords: halite-scale; early prediction; dissolution of halite scale; simulation; tailend production.
of their occurrence in the near wellbore area, fresh water treatments are performed during production operations, in addition to the mechanical removal of halite scale from the tubing and perforation zone with the use of scrapers. The objective of all such measures is to maintain or restore the original permeability conditions. In the present publication, precipitation of dissolved salts from the entrained water, chemical parameters for early detection of salt precipitation in the reservoir, dissolution
INTRODUCTION During the production of gas from reservoirs in Northern Germany, the precipitation of salt from the reservoir water is observed to an increasing extent as recovery progresses. In a similar manner, this phenomenon is also encountered during the injection of dry gas into porous aquifers for storage. Salt deposits are formed in the production string as well as in the perforation zone. It must be assumed that the formation in the near well bore area is also affected by salt precipitation. Halite precipitates have also been detected during well testing operations (Kleinitz and To¨lcke, 1982); the precipitation was caused by pressure drop with saturated brine. To illustrate the halite scale formation in the porous medium, an SEM picture (Kleinitz and To¨lcke, 1982) of a formation rock with salt deposits in a pore channel is shown in Figure 1. The presence of halite scale on the internal surface of the pore and the associated constriction of the cross-sectional area, with the resulting impairment in permeability, is clearly evident. For a pore diameter of about 30 mm, the thickness of the halite deposit is between 3 and 4.5 mm. The growth of a halite crystal into the pore channel is visible in the middle of the gure. In the course of production, the precipitated salts cause a signi cant decrease in productivity, all the way to complete blockage to ow and ultimately the abandonment of wells. For the elimination of salt precipitates, as well as prevention
Figure 1. SEM-picture of halite crystal in a rock matrix.
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HALITE SCALE FORMATION behaviour of halite scale and evaluation of the stimulations performed in a selected gas eld are discussed. LITERATURE SURVEY The occurrence of salt deposits in the reservoir rock, in the borehole, or both, whether in gas wells or in HTHP wells (Jasinski and Sablerolle, 1996), has been published only sporadically. In general, a distinction is made between salt precipitates which occur in gas wells with decreased reservoir pressure (Dietzsch, 2000) and those which are formed during injection of dry gas into porous media for storage (Kleinitz, 1978; Mill et al., 1997). In the publications, the causes are analysed, the effects of the halite scale on the production behaviour are evaluated (Kleinitz and To¨lcke, 1982), and stimulation measures are proposed (Wagner, 1995; Kleinitz et al., 2001). Chare´ (1976) and Couture et al. (1996) have considered the basic theoretical principles of salt precipitation in porous media, whereas Jasinski (Jasinski and Sablerolle, 1996; Jasinski and Frigo, 1996), Weiss et al. (1999), and Franke and Go¨sele (1999) have discussed aspects of mathematical modelling. Dietzel et al. (1998) have considered the transport of water from the reservoir to the well as a result of a decrease in pressure and mobilization of connate water. Dietzel et al. (1993) has described problems (forming of water blocks) occurred in stimulation due to decreasing owing pressure as a result of reservoir depletion. HALITE PRECIPITATION IN GAS WELLS The cause of halite precipitation in depleted gas wells is explained with the aid of Figure 2. In this gure, the maximal water content in methane is plotted as a function of the pressure and water salinity. The recovery factor for a gas eld in Northern Germany is also included in the Figure 2. The decrease in reservoir pressure can be derived from the p=Z behaviour. As is well known, the reservoir pressure decreases as recovery progresses. On the other hand, the solubility of water in the gas increases with decreasing reservoir pressure. The water content in methane increases decidedly beyond 200 bar for the reservoir considered here. The salinity does not change the curve’s general form, but alters the absolute values quite signi cantly.
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As production progresses and the pressure decreases as a result, the salt concentration in the remaining reservoir water increases until halite scale is formed. The evaporation of water and consequently the crystallization of salt from the present residual water as a result of pressure decline do not lead to a blockage, because an increase in salt volume as a result of crystallization can de nitely be excluded. The salt blockage occurs in a dynamic system, a continuous ow of water to the well which evaporates in the near-wellbore and causes progressive build-up. Dietzel et al. (1998) described the occurrence of free water when there is no apparent ow of edge water, schematically drawn in Figure 3. The pressure drop resulting from production leads to an expansion of the pore water and consequently to an increase in water saturation beyond the point of irreducible water saturation. This leads to a greater proportion of free saline reservoir water being transported with the gas ow to the production well. As it results from decreasing reservoir pressure, the increase in pore water evaporation is particularly pronounced in zones subject to substantial pressure decrease, that is, in the proximity of the well. Here the concentration of the original as well as the entrained reservoir water rises beyond the solubility limit to precipitate salt. The transport of salt through the zone of strong evaporation leads to additional salt precipitation, thus giving rise to observed impairment of ow. The importance of salt precipitation investigations for Northern Germany gas wells is shown in Figure 3. Beyond a recovery factor of 60–70%, as explained in Figure 2, the absorption of water into the gas can increase decidedly for a number of gas reservoirs; thus the associated increase in salt concentration in the water of the pores may also be favoured. Furthermore, highly mineralized formation water (TDS 150–330 g l¡1) is present in many gas reservoirs of Northern Germany. In some cases, a slight loss of water is quite suf cient for initiating the precipitation of halite from this formation water. In Figure 4 the present recovery factor for 51 gas elds in Northern Germany is given. As indicated the recovery factor for 43% of the elds is situated within the critical range between 60 and 100%. In these gas elds, fresh water treatments are performed by Preussag Energie at regular intervals in some of the wells by dissolving the salt in the perforated and in the skin zone for years. INDICATIONS OF HALITE PRECIPITATION
Figure 2. Water content in methane and recovery factor as a function of pressure and water salinity (Tres ˆ 145¯ C).
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In production operations, early detection of salt precipitation on the basis of simple criteria is a prerequisite for the implementation of stimulation measures in due time. As shown by experience in practice, a consideration of the productivity index in gas wells is not suf cient for the detection of initial plugging by salt precipitates. Subsequent initiation of stimulation measures has often proved to be too late for restoring the original ow conditions. In other words, plugging of the pores by halite scale has already progressed to such an extent that the salt can no longer be redissolved with the use of salt-free water (fresh water), or can be dissolved only after very long shut-in times at the well. A possible approach for the early detection of halite precipitation may be the interpretation of the ionic distribution in the entrained reservoir water during production. As a result of sea water evaporation during the formation of
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Figure 3. Occurrence of mobile water.
Figure 4. Recorded factors of Northern German gas elds.
Zechstein saliniferous successions, the concentration of dissolved ions in the brines varied during the successive precipitation sequences; this effect has been known for many years (Carpenter, 1978). The reservoir water produced from a selected gas well was evaporated under controlled
conditions until crystallization of the dissolved salts. During the evaporation, water samples were taken and analysed for their chemical composition. The ionic concentration and the density of the respective brine were thus recorded. In combination with the visual inspection of the corresponding salt precipitates, this procedure may indicate the presence of inorganic scale in the reservoir and in the well. For taking into account the condensation of water in the tubing during production, quotients were calculated for the various cations and anions. These analyses were performed at temperature of 23¯ C and standard pressure in the laboratory. Special emphasis has been placed on the variation of these quotients as a function of the brine density as well as visual observation of the occurrence of salt precipitates. The purpose of these quotients is to detect and utilize a signi cant change in their values as an indication when salt precipitation occurs. For this purpose, it is assumed that the quotients remain constant at the moment of total dissolution, regardless of the density, but change clearly at the moment of initial precipitation. For the reservoir water considered, salt precipitation (Table 1) was observed at a brine density of 1.235 g cm¡3.
Table 1. Ionic quotients before and after NaCl precipitation.
Quotient Na=Li Na=K Na=Mg Na=Ca Na=Cl K=Mg K=Cl Mg=Cl Ca=Mg Ca=Cl Na=(Ca ‡ Cl) (Na ‡ K)=Cl (Ca ‡ Mg)=Cl
Salt precipitation
Reservoir water rbrine ˆ 1.10
Critical density rbrine ˆ 1.235
rbrine ˆ 1.25
rbrine ˆ 1.30
480 17 45 1.3 0.3 2.7 0.022 0.0065 34 0.23 0.24 0.33 0.25
460 16.5 42 1.25 0.3 2.6 0.024 0.007 34 0.23 0.25 0.33 0.23
400 14 40 1.2 0.3 2.5 0.025 0.008 34 0.25 0.25 0.33 0.25
100 2 10 0.2 0.1 2.8 0.035 0.012 33 0.4 0.07 0.13 0.4
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Up to this point, the concentrations of all ions increased linearly with the density. In Table 1, the sensitivity of various quotients is compared for the ranges before salt precipitation (r 1.100 and 1.235 g cm¡3) and after salt precipitation (r 1.25 and 1.30 g cm¡3). For the well considered, the following quotients may provide as indicators, on an mg l¡1 basis, for the recognition of salt precipitation: Na=Li, Na=K and Na=(Ca ‡ Cl). Potassium salts are known to precipitate at the end of the deposition sequence during the evaporation of sea water; consequently, potassium as well as lithium and bromide remain in solution in the course of the initial saliniferous successions. The experimental results clearly indicate that the sodium concentration decreases after salt crystallization. Since KCl is employed for the protection of clays during fresh water stimulation, the quotient Na=Li is applied, among others. Hence, the quotient (Figure 5) for sodium and lithium was employed as an indicator for early detection of salt precipitation. The quotient Na=Li has a value of about 460 before salt crystallization and values de nitely less than 400 in the case of salt precipitation. The use of this quotient for monitoring production wells can therefore be recommended.
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The process of halite dissolution in water is controlled by the exchange of liquid on the crystal which is dissolving. Under convective conditions in the free aqueous phase, a halite particle with a diameter of 1 mm dissolves in about 2900 s (Schlu¨nder, 1996). Under owing conditions, the dissolution time is only 85 s for equal dimensions. If these considerations in the bulk uid water are applied to the porous medium, the dissolution rate for salt is signi cantly lower. Furthermore, this value decreases with decreasing porosity of the rock material. On the basis of published data (Kretzschmar et al., 1986), the reduction factor for the dissolution rate (free convection) is about 100 under the reservoir conditions considered. Thus, a rough estimate indicates that a halite grain with a diameter of 1 mm would require about 3 days to dissolve completely in the porous medium. The soak times employed in practice are gained from experiences, because the dissolution of halite in situ is dominated by diffusion. Large sections of the porous matrix are completely blocked off and convective conditions cannot be assumed. In the absence of forced movement, signi cant diffusion is required to get suf cient quantities of low-salinity water in the vicinity of halite scale.
DISSOLUTION BEHAVIOUR OF HALITE The dissolution of deposited halite scale in the porous medium is slow, since the process is essentially controlled by the diffusion rate in the crystal-surface=solution system. For this reason, the conditions involved in the course of stimulation must be distinguished: free convection and ow, on the one hand, and the salt concentration in the treatment medium, on the other hand. These parameters are decisive for the success of fresh water stimulation and are considered in the following. Dissolution Rate for Halite As indicated by Hentschel and Kleinitz (1976), the average dissolution rate for halite is 1.28 £ 10¡4 cm3 (cm2 s)¡1 at 20¯ C under conditions of free convection. Since the process is diffusion-controlled, this value decreases signi cantly with increasing salt concentration in the bulk liquid. At a brine concentration of 100 g NaCl l¡1, the dissolution rate has a value of 1.2 £ 10¡4 cm3 (cm2 s)¡1; at 250 g NaCl l¡1, however, the value is only 0.3 £ 10¡4 cm3 (cm2 s)¡1.
Dissolution of Natural Halite Scale For many years (Kleinitz, 1978; Wagner, 1995), fresh water treatments have been performed by dissolving halite in the vicinity of the well and in the tubing. In order to take the effect of reservoir depletion into account for the well considered, about 3% butyl glycol (EGMBE) is added to the water, on the basis of a study by Dietzel et al. (1993). The resulting decrease in interfacial tension in the water–gas system facilitates the back- ow of the treatment slug. In laboratory tests, the dissolution rate was compared for a de ned cubic sample of natural downhole halite scale in pure water and in a 2% KCl solution with 3% butyl glycol. The following values were obtained at 23¯ C: water, 1.8 £ 10¡4 cm3 (cm2 s)¡1; water ‡ 2% KCl ‡ 3% butyl glycol, 1.6 £ 10¡4 cm3 (cm2 s)¡1. In the latter case, the somewhat lower dissolution rate is due to the KCl contained in the water; in practical operations, the addition of KCl is necessary for protecting the clays in the reservoir. For application to reservoir conditions, the fact that the diffusion rate is lower in the porous medium must be considered in this case too. In effect, therefore, the interfacially active component of the butyl glycol does not accelerate the dissolution process.
STIMULATION
Figure 5. Na=Li-quotient vs brine density.
Trans IChemE, Vol 81, Part A, March 2003
Fresh water treatments are performed in order to avoid or remove scale deposits and thus maintain the productivity of gas wells. The evaluation of pressure build-up and PLT measurements at individual wells provides information on the variation of the skin effect and thus allows conclusions on permeability reduction in the zone immediately surrounding the well. By increasing the bottom-hole pressure, for instance, with a decrease in rate, additional perforation or stimulation measures, pressure conditions which cause supersaturation of the formation water can at
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Table 2. Treatment of Well 2. Productivity index (from production data) Date February 93 October 93 March 94 December 94 March 95 November 95 October 96 October 97 December 98 October 99 April 00 March 01
Treatment uid composition
Before m3(Vn)
After (h bar2)¡1
Improvement (%)
Ranking
Shut-in time (h)
Volume (m3)
EGMBE (%)
KCl (%)
LiCl (%)
Citric acid (%)
0.5 1.1 1.6 0.6 0.8 1.8 1.0 1.5 2.2 2.0 3.0 2.5
2.1 2.6 1.5 1.3 1.3 1.8 1.6 2.0 2.2 3.0 3.0 3.0
320 136 ¡6 117 63 0 60 33 0 50 0 20
1 1 6 1 2 6 2 3 6 2 6 4
504 456 336 120 552 312 624 384 216 336 552 384
47.0 45.0 24.6 19.0 20.0 40.0 41.4 44.0 40.0 42.0 38.0 40.0
3 3 3 3 3 3 3 3 3 3 3 3
2 2 2 2 2 2 2 2 2 2 2 2
0 0 0 0 0 0 24.4 0 0 0 0 0
0 0 0 0 0 0 0 0 0 5 5 5
Evaluation of Halite Treatments
Figure 6. Treatment evaluation, PI before and after stimulation.
least be delayed. A prolonged shut-in period at the well (Dietzel et al., 1998) can also provide a temporary improvement in productivity index as a result of the recondensation of water vapour associated with the pressure build-up.
In a Northern Germany gas eld (formation: Bunter reservoir) operated by Preussag Energie with gas production from three wells (named Well 1, Well 2 and Well 3) fresh water treatments are applied for avoiding or removing salt precipitates. For the formation with a permeability of about 7 mD and an average porosity of 12%, the calculated value of the hydraulic equivalent diameter is 1.4 mm. A halite crystal of this size is suf cient for plugging the pore channel for the gas ow. The TDS content of the original reservoir water is 308 g l¡1, and the reservoir temperature is 110¯ C. The results of several years’ stimulation are discussed for Well 2 in detail. After Well 2 came on production in 1979, in 1985 production uctuations due to halite precipitation were reported and the rst fresh water treatment was launched. The recovery factor for the eld was only 10%. In this case, a slight loss of water led to salt crystallization. Twenty-seven cubic metres of fresh water were bull-headed and the well was shut-in for 1 h. The density of the back ow was monitored continuously. After chemical water analysis, the
Figure 7. Water cut in course of production of Well 2.
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HALITE SCALE FORMATION
Figure 8. Back ow behaviour of different treatments.
Figure 9. Treatment success in course of gas production.
produced water contained approximately 1000 kg of salt (halite equivalent). Fresh water stimulations have been performed in Well 2 once or twice a year. The value of the quotient Na=K was 24.8 § 1.3 before and 9.7 § 3.1 after salt precipitation. At present, the recovery factor for the eld is about 50%. The composition of the treatment uid and the results of stimulation are summarized for the past 12 years for Well 2 in Table 2. The speci c treatment volume varies between 1 and 2 m3 m¡1 as referred to the net thickness. This value corresponds to a theoretical average penetration depth of 1.1–1.7 m in the zone surrounding the well. The
shut-in time required for redissolution of precipitated halite ranges between 5 and 26 days. The implementation and evaluation of the treatments was done on the basis of productivity index, as shown in Figure 6. The plot presents the productivity index during production. The early detection method, as described above section, cannot be applied so far. Figure 7 illustrates the produced water cut and the theoretical water cut due to condensation in the production tubing for the Well 2. The theoretical water and the produced water cut are similar. Thus no reservoir water is produced, as needed for early halite scale detection. Owing to the produced condensate water, the density of the produced water is around 1.0 g cm¡3, as can be derived from Figure 8 for volume indices greater than 0.8. The results of stimulation have been appraised on the basis of the change in productivity index [m3(Vn) (h bar2)¡1] before and after the fresh water treatment (Figure 6). On an appraisal scale, the success of stimulation has been ranked in correspondence with the improvement in productivity index: DPI µ0% ! 6; DPI 0–10% ! 5; DPI 10–25% ! 4; DPI 25–50% ! 3; DPI 50–100% ! 2; DPI >100% ! 1. The results of 12 treatments performed on Well 2 during the period from 1993 to 2001 are compiled in Table 2. The results of stimulation have been ranked corresponding to the success achieved. The grades uctuate between 1 and 6, with an average value of 3.3 for all treatments. Thus, the achieved PI improvement is not constant during the time period evaluated. From a consideration of the shut-in time and the improvement in productivity index, it is evident that a maximum is attained in a few wells after 300 h (12.5 d ). For these wells, the increase in productivity index is about 240% at optimal ef ciency. A conspicuous feature is a frequent ranking pattern for repeated stimulations. The observed improvements correspond to the ranking sequence 6–1–6. These cycles are independent of the treatment volume, shut-in time, total dissolved salts and recovery factor. A provable interpretation of this behaviour with due consideration of all factors and an extension to the remaining wells in the eld is not yet feasible. A total of 27 fresh water stimulations have been evaluated for the gas eld concerned. In Figure 9, the resulting improvement in production index is plotted as a function
Figure 10. Fresh water treatment—bull heading.
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of the cumulative gas production per well (Wells 1–3). The plot clari es the importance of early detection of halite precipitation in the wellbore for high stimulation success. As can be seen from Figure 9, the ef ciency of the fresh water treatments decreases with cumulative gas production. Furthermore, the treatment must be optimized, in order to permanently dissolve halite scale in the near-wellbore area. The most crucial point for fresh water treatments in those reservoirs is reached when the reservoir pressure, on the one hand, is responsible for high halite scale potential in the wellbore area, and on the other hand is not able to back- ow the necessary amount of stimulation uid.
before and after stimulation. The frequently observed succession of highly successful and totally ineffective stimulation treatments cannot be interpreted in an unambiguous manner. No relationship can be detected between the amount of dissolved salt and the improvement in productivity index for the gas eld considered. An analysis of the back- owing uid after fresh water stimulation in a Bunter reservoir well has indicated that the major portion of the halite scale is deposited in the lower tubing and perforation zone. There is also evidence of its occurrence in the formation, at least in the near-wellbore area.
Well Speci c Evaluation
REFERENCES
During the back- ow phase of the injected fresh water slug, the density of the entrained water was determined, among other data. For Well 2, this value is plotted as a function of the speci c back- ow volume (V=Vo, Vo ˆ injection volume) over the period from 1988 to 1997 (Figure 8). From this plot, it is evident that the density maximum is shifted toward low V=Vo values from 1988 to 1991. This effect can be interpreted by assuming that the salt deposits have been displaced from the reservoir toward the perforation over the years. The data for 1993 exhibit a maximum at the beginning of back- ow and between 0.3 and 0.5 V=Vo. In 1997, on the other hand, the highest density occurred at the beginning and then decreased continuously during subsequent back- ow. This observation is explained by the displacement of salt precipitation from the zone surrounding the well through the perforation all the way to the lower tubing section. An explanation of the observed shift in the density of the back- ow brine is given in Figure 10 for the time period from 1988 to 1997. The reservoir pressure in the eld under consideration decreased from 300 to 160 bar during this period. This led to the following production behaviour. The water for treatment is bull-headed via the tubing. The treatment volume is then slowly injected into the reservoir by percolation of gas through the water column. It must be assumed that the treatment volume has penetrated deeply into the formation at high reservoir pressure (1988). As the pressure declines during the years, stimulation uid remains in the lower tubing zone and dissolves the halite scale inside the tubing (1997).
Carpenter, A. B., 1978, Origin and chemical evolution of brines in sedimentary basins. SPE 7504. Chare´, I., 1976, Trocknung von Agglomeraten bei Anwesenheit auskristallisierender Stoffe. Festigkeit und Struktur der durch die auskristallisierten Stoffe verfestigten Granulate. Dissertation, Karlsruhe. Couture, F., Jomaa, W. and Puiggali, J.-R., 1996, Relative permeability relations: a key factor for a drying model. Transp Porous Media, 23. Dietzel, H.-J., Kleinitz, W. and Littmann, W., 1993, Wiederherstellung der Zu ußbedingungen nach Aufwa¨ltigungs- und Komplettierungsarbeiten in Gasbohrungen, Erdo¨l Erdgas Kohle, 11. Dietzel, H.-J., Kleinitz, W. and Ko¨hler, M., 1998, The occurrence of water in gas wells, Nat Resourc Dev, 48. Dietzsch, G., 2000, Ein uss der Salzbildung auf das Produktionsverhalten von Gasbohrungen bei abgesenktem Fließdruck. TU BA Freiberg, Diplomarbeit. Franke, D. and Go¨sele, W., 1999, Hydrodynamischer Ansatz zur Modellierung von Fa¨llungen, Chem Ing Techn, 11. Hentschel, J. and Kleinitz, W., 1976, Aufbau der Salzgesteine des Salzstockes Etzel, abgeleitet aus Kernuntersuchungen und Loginterpretation, Kali Steinsalz, 7. Jasinski, R. and Frigo, D., 1996, The modelling and prediction of halite scale, Solving Oil eld Scaling Conference, January. Jasinski, R. and Sablerolle, W., 1996, Computer modelling HTHP salt and scale formation, Expl Prod Newsl, July. Kleinitz, W., 1978, Speicherprojekt Kalle der VEW, Auftreten und Verhindern von Salzausfa¨llungen im Speichergestein, interner Bericht Preussag AG. Kleinitz, W. and To¨lcke, W., 1982, Bildungsbedingungenvon Ablagerungen in Gasbohrungen und deren Beseitigung, Erdo¨l-Erdgas-Zeitschr, 4. Kleinitz, W., Dietzsch, G. and Ko¨hler, M., 2001, The precipitation of salt in gas producing wells; SPE 68953, Formation Damage Conference. Kretzschmar, H.-J., Czolbe, P. and Bauer, K., 1986, Diffusionsmessungen an Speicher-gesteinen mit unterschiedlichen Gasen und Messapparaturen, Erdo¨l Kohle-Erdgas, March. Mill, D., Beckmann, H. and Beinlich, W., 1997, Maßnahmen zur Injektivita¨tssteigerung=Verbesserung der Zu ußbedingungen von Gasspeichersonden durch Salzau o¨sung, DGMK-Tagungsband 9701. ¨ ber das Vorkommen des Strontium, Lithium und Bor in Peter, S.,1965, U Salzlo¨sungen aus dem deutschen Zechstein, Interner Bericht BEB. Schlu¨nder, E.-U., 1996, Einfu¨hrung in die Stoffu¨bertragung, Vieweg. Wagner, L., 1995, Stimulation von Gasbohrungen bei Salzausfa¨llungen. Diplomarbeit TU BA, Freiberg. Weiss, G., Henning, T., Ku¨mmel, R. and Tschernhaew, J., 1999, Modellierung von Stofftransport und Kristallisation in dispersen Systemen, Chem Ing Techn, 11.
CONCLUSIONS The production of entrained water from gas reservoirs can result in the deposition of halite scale as the wellhead pressure decreases. This phenomenon is associated with the increase in the solubility of water in methane with declining pressure. As a result of this process, the productivity is severely impaired, and wells may even have to be abandoned. For the early detection of halite scale deposits from entrained reservoir water, the use of certain quotients [Na=Li; Na=K; Na=(Ca ‡ Cl)] as indicators is proposed. In the case of halite precipitation downhole, these quotients vary signi cantly. For the evaluation of 27 fresh water treatments performed in a gas eld, an appraisal scale has been de ned; this ranking system is based on the change in productivity index
ADDRESS Correspondence concerning this paper should be addressed to Dr. W. Kleinitz, Preussag Energie GmbH, D-49808 Lingen, Waldstr. 39, Germany. E-mail: [email protected] The paper was presented at the 13th International Oil eld Chemistry Symposium, held in Geilo, Norway, 17–20 March 2002. The manuscript was received 29 May 2002 and accepted for publication after revision 17 January 2003.
Trans IChemE, Vol 81, Part A, March 2003
www.ingentaselect.com=titles=02638762.htm
HALITE SCALE FORMATION IN GAS-PRODUCING WELLS ¨ HLER W. KLEINITZ, G. DIETZSCH and M. KO Preussag Energie GmbH, Lingen, Germany
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n Northern German gas reservoirs, the precipitation of salt from the reservoir water is observed to an increasing extent as recovery progresses. The resulting halite scale causes a signi cant decrease in production rate, all the way to complete blockage of the ow paths and ultimately the abandonment of wells. In order to remove salt deposits as well as prevent the precipitation of salt in the zone immediately surrounding the well, fresh water treatments are performed at regular intervals during production operations. This paper addresses the entrainment of reservoir water from gas reservoirs, even in reservoirs without active edge-water drive, and the halite precipitation in depleted gas wells on the basis of theoretical considerations. The discussion includes a description of chemical parameters determined from analysis of reservoir water for the early detection of salt precipitates in the reservoir rock. Besides the implementation of the fresh water treatment in practice, special attention is paid to the dissolution behaviour of halite scale. The ionic distribution in the back-produced treatment uid is evaluated with reference to the prevailing reservoir conditions. During the past 17 years, a large number of fresh water stimulations have been conducted in Northern German gas reservoirs. The results of these operations are explained in detail. The success of the stimulation based on the change in productivity index is evaluated and interpreted for parameters such as treatment volume and shut-in time. Keywords: halite-scale; early prediction; dissolution of halite scale; simulation; tailend production.
of their occurrence in the near wellbore area, fresh water treatments are performed during production operations, in addition to the mechanical removal of halite scale from the tubing and perforation zone with the use of scrapers. The objective of all such measures is to maintain or restore the original permeability conditions. In the present publication, precipitation of dissolved salts from the entrained water, chemical parameters for early detection of salt precipitation in the reservoir, dissolution
INTRODUCTION During the production of gas from reservoirs in Northern Germany, the precipitation of salt from the reservoir water is observed to an increasing extent as recovery progresses. In a similar manner, this phenomenon is also encountered during the injection of dry gas into porous aquifers for storage. Salt deposits are formed in the production string as well as in the perforation zone. It must be assumed that the formation in the near well bore area is also affected by salt precipitation. Halite precipitates have also been detected during well testing operations (Kleinitz and To¨lcke, 1982); the precipitation was caused by pressure drop with saturated brine. To illustrate the halite scale formation in the porous medium, an SEM picture (Kleinitz and To¨lcke, 1982) of a formation rock with salt deposits in a pore channel is shown in Figure 1. The presence of halite scale on the internal surface of the pore and the associated constriction of the cross-sectional area, with the resulting impairment in permeability, is clearly evident. For a pore diameter of about 30 mm, the thickness of the halite deposit is between 3 and 4.5 mm. The growth of a halite crystal into the pore channel is visible in the middle of the gure. In the course of production, the precipitated salts cause a signi cant decrease in productivity, all the way to complete blockage to ow and ultimately the abandonment of wells. For the elimination of salt precipitates, as well as prevention
Figure 1. SEM-picture of halite crystal in a rock matrix.
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HALITE SCALE FORMATION behaviour of halite scale and evaluation of the stimulations performed in a selected gas eld are discussed. LITERATURE SURVEY The occurrence of salt deposits in the reservoir rock, in the borehole, or both, whether in gas wells or in HTHP wells (Jasinski and Sablerolle, 1996), has been published only sporadically. In general, a distinction is made between salt precipitates which occur in gas wells with decreased reservoir pressure (Dietzsch, 2000) and those which are formed during injection of dry gas into porous media for storage (Kleinitz, 1978; Mill et al., 1997). In the publications, the causes are analysed, the effects of the halite scale on the production behaviour are evaluated (Kleinitz and To¨lcke, 1982), and stimulation measures are proposed (Wagner, 1995; Kleinitz et al., 2001). Chare´ (1976) and Couture et al. (1996) have considered the basic theoretical principles of salt precipitation in porous media, whereas Jasinski (Jasinski and Sablerolle, 1996; Jasinski and Frigo, 1996), Weiss et al. (1999), and Franke and Go¨sele (1999) have discussed aspects of mathematical modelling. Dietzel et al. (1998) have considered the transport of water from the reservoir to the well as a result of a decrease in pressure and mobilization of connate water. Dietzel et al. (1993) has described problems (forming of water blocks) occurred in stimulation due to decreasing owing pressure as a result of reservoir depletion. HALITE PRECIPITATION IN GAS WELLS The cause of halite precipitation in depleted gas wells is explained with the aid of Figure 2. In this gure, the maximal water content in methane is plotted as a function of the pressure and water salinity. The recovery factor for a gas eld in Northern Germany is also included in the Figure 2. The decrease in reservoir pressure can be derived from the p=Z behaviour. As is well known, the reservoir pressure decreases as recovery progresses. On the other hand, the solubility of water in the gas increases with decreasing reservoir pressure. The water content in methane increases decidedly beyond 200 bar for the reservoir considered here. The salinity does not change the curve’s general form, but alters the absolute values quite signi cantly.
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As production progresses and the pressure decreases as a result, the salt concentration in the remaining reservoir water increases until halite scale is formed. The evaporation of water and consequently the crystallization of salt from the present residual water as a result of pressure decline do not lead to a blockage, because an increase in salt volume as a result of crystallization can de nitely be excluded. The salt blockage occurs in a dynamic system, a continuous ow of water to the well which evaporates in the near-wellbore and causes progressive build-up. Dietzel et al. (1998) described the occurrence of free water when there is no apparent ow of edge water, schematically drawn in Figure 3. The pressure drop resulting from production leads to an expansion of the pore water and consequently to an increase in water saturation beyond the point of irreducible water saturation. This leads to a greater proportion of free saline reservoir water being transported with the gas ow to the production well. As it results from decreasing reservoir pressure, the increase in pore water evaporation is particularly pronounced in zones subject to substantial pressure decrease, that is, in the proximity of the well. Here the concentration of the original as well as the entrained reservoir water rises beyond the solubility limit to precipitate salt. The transport of salt through the zone of strong evaporation leads to additional salt precipitation, thus giving rise to observed impairment of ow. The importance of salt precipitation investigations for Northern Germany gas wells is shown in Figure 3. Beyond a recovery factor of 60–70%, as explained in Figure 2, the absorption of water into the gas can increase decidedly for a number of gas reservoirs; thus the associated increase in salt concentration in the water of the pores may also be favoured. Furthermore, highly mineralized formation water (TDS 150–330 g l¡1) is present in many gas reservoirs of Northern Germany. In some cases, a slight loss of water is quite suf cient for initiating the precipitation of halite from this formation water. In Figure 4 the present recovery factor for 51 gas elds in Northern Germany is given. As indicated the recovery factor for 43% of the elds is situated within the critical range between 60 and 100%. In these gas elds, fresh water treatments are performed by Preussag Energie at regular intervals in some of the wells by dissolving the salt in the perforated and in the skin zone for years. INDICATIONS OF HALITE PRECIPITATION
Figure 2. Water content in methane and recovery factor as a function of pressure and water salinity (Tres ˆ 145¯ C).
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In production operations, early detection of salt precipitation on the basis of simple criteria is a prerequisite for the implementation of stimulation measures in due time. As shown by experience in practice, a consideration of the productivity index in gas wells is not suf cient for the detection of initial plugging by salt precipitates. Subsequent initiation of stimulation measures has often proved to be too late for restoring the original ow conditions. In other words, plugging of the pores by halite scale has already progressed to such an extent that the salt can no longer be redissolved with the use of salt-free water (fresh water), or can be dissolved only after very long shut-in times at the well. A possible approach for the early detection of halite precipitation may be the interpretation of the ionic distribution in the entrained reservoir water during production. As a result of sea water evaporation during the formation of
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Figure 3. Occurrence of mobile water.
Figure 4. Recorded factors of Northern German gas elds.
Zechstein saliniferous successions, the concentration of dissolved ions in the brines varied during the successive precipitation sequences; this effect has been known for many years (Carpenter, 1978). The reservoir water produced from a selected gas well was evaporated under controlled
conditions until crystallization of the dissolved salts. During the evaporation, water samples were taken and analysed for their chemical composition. The ionic concentration and the density of the respective brine were thus recorded. In combination with the visual inspection of the corresponding salt precipitates, this procedure may indicate the presence of inorganic scale in the reservoir and in the well. For taking into account the condensation of water in the tubing during production, quotients were calculated for the various cations and anions. These analyses were performed at temperature of 23¯ C and standard pressure in the laboratory. Special emphasis has been placed on the variation of these quotients as a function of the brine density as well as visual observation of the occurrence of salt precipitates. The purpose of these quotients is to detect and utilize a signi cant change in their values as an indication when salt precipitation occurs. For this purpose, it is assumed that the quotients remain constant at the moment of total dissolution, regardless of the density, but change clearly at the moment of initial precipitation. For the reservoir water considered, salt precipitation (Table 1) was observed at a brine density of 1.235 g cm¡3.
Table 1. Ionic quotients before and after NaCl precipitation.
Quotient Na=Li Na=K Na=Mg Na=Ca Na=Cl K=Mg K=Cl Mg=Cl Ca=Mg Ca=Cl Na=(Ca ‡ Cl) (Na ‡ K)=Cl (Ca ‡ Mg)=Cl
Salt precipitation
Reservoir water rbrine ˆ 1.10
Critical density rbrine ˆ 1.235
rbrine ˆ 1.25
rbrine ˆ 1.30
480 17 45 1.3 0.3 2.7 0.022 0.0065 34 0.23 0.24 0.33 0.25
460 16.5 42 1.25 0.3 2.6 0.024 0.007 34 0.23 0.25 0.33 0.23
400 14 40 1.2 0.3 2.5 0.025 0.008 34 0.25 0.25 0.33 0.25
100 2 10 0.2 0.1 2.8 0.035 0.012 33 0.4 0.07 0.13 0.4
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Up to this point, the concentrations of all ions increased linearly with the density. In Table 1, the sensitivity of various quotients is compared for the ranges before salt precipitation (r 1.100 and 1.235 g cm¡3) and after salt precipitation (r 1.25 and 1.30 g cm¡3). For the well considered, the following quotients may provide as indicators, on an mg l¡1 basis, for the recognition of salt precipitation: Na=Li, Na=K and Na=(Ca ‡ Cl). Potassium salts are known to precipitate at the end of the deposition sequence during the evaporation of sea water; consequently, potassium as well as lithium and bromide remain in solution in the course of the initial saliniferous successions. The experimental results clearly indicate that the sodium concentration decreases after salt crystallization. Since KCl is employed for the protection of clays during fresh water stimulation, the quotient Na=Li is applied, among others. Hence, the quotient (Figure 5) for sodium and lithium was employed as an indicator for early detection of salt precipitation. The quotient Na=Li has a value of about 460 before salt crystallization and values de nitely less than 400 in the case of salt precipitation. The use of this quotient for monitoring production wells can therefore be recommended.
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The process of halite dissolution in water is controlled by the exchange of liquid on the crystal which is dissolving. Under convective conditions in the free aqueous phase, a halite particle with a diameter of 1 mm dissolves in about 2900 s (Schlu¨nder, 1996). Under owing conditions, the dissolution time is only 85 s for equal dimensions. If these considerations in the bulk uid water are applied to the porous medium, the dissolution rate for salt is signi cantly lower. Furthermore, this value decreases with decreasing porosity of the rock material. On the basis of published data (Kretzschmar et al., 1986), the reduction factor for the dissolution rate (free convection) is about 100 under the reservoir conditions considered. Thus, a rough estimate indicates that a halite grain with a diameter of 1 mm would require about 3 days to dissolve completely in the porous medium. The soak times employed in practice are gained from experiences, because the dissolution of halite in situ is dominated by diffusion. Large sections of the porous matrix are completely blocked off and convective conditions cannot be assumed. In the absence of forced movement, signi cant diffusion is required to get suf cient quantities of low-salinity water in the vicinity of halite scale.
DISSOLUTION BEHAVIOUR OF HALITE The dissolution of deposited halite scale in the porous medium is slow, since the process is essentially controlled by the diffusion rate in the crystal-surface=solution system. For this reason, the conditions involved in the course of stimulation must be distinguished: free convection and ow, on the one hand, and the salt concentration in the treatment medium, on the other hand. These parameters are decisive for the success of fresh water stimulation and are considered in the following. Dissolution Rate for Halite As indicated by Hentschel and Kleinitz (1976), the average dissolution rate for halite is 1.28 £ 10¡4 cm3 (cm2 s)¡1 at 20¯ C under conditions of free convection. Since the process is diffusion-controlled, this value decreases signi cantly with increasing salt concentration in the bulk liquid. At a brine concentration of 100 g NaCl l¡1, the dissolution rate has a value of 1.2 £ 10¡4 cm3 (cm2 s)¡1; at 250 g NaCl l¡1, however, the value is only 0.3 £ 10¡4 cm3 (cm2 s)¡1.
Dissolution of Natural Halite Scale For many years (Kleinitz, 1978; Wagner, 1995), fresh water treatments have been performed by dissolving halite in the vicinity of the well and in the tubing. In order to take the effect of reservoir depletion into account for the well considered, about 3% butyl glycol (EGMBE) is added to the water, on the basis of a study by Dietzel et al. (1993). The resulting decrease in interfacial tension in the water–gas system facilitates the back- ow of the treatment slug. In laboratory tests, the dissolution rate was compared for a de ned cubic sample of natural downhole halite scale in pure water and in a 2% KCl solution with 3% butyl glycol. The following values were obtained at 23¯ C: water, 1.8 £ 10¡4 cm3 (cm2 s)¡1; water ‡ 2% KCl ‡ 3% butyl glycol, 1.6 £ 10¡4 cm3 (cm2 s)¡1. In the latter case, the somewhat lower dissolution rate is due to the KCl contained in the water; in practical operations, the addition of KCl is necessary for protecting the clays in the reservoir. For application to reservoir conditions, the fact that the diffusion rate is lower in the porous medium must be considered in this case too. In effect, therefore, the interfacially active component of the butyl glycol does not accelerate the dissolution process.
STIMULATION
Figure 5. Na=Li-quotient vs brine density.
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Fresh water treatments are performed in order to avoid or remove scale deposits and thus maintain the productivity of gas wells. The evaluation of pressure build-up and PLT measurements at individual wells provides information on the variation of the skin effect and thus allows conclusions on permeability reduction in the zone immediately surrounding the well. By increasing the bottom-hole pressure, for instance, with a decrease in rate, additional perforation or stimulation measures, pressure conditions which cause supersaturation of the formation water can at
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Table 2. Treatment of Well 2. Productivity index (from production data) Date February 93 October 93 March 94 December 94 March 95 November 95 October 96 October 97 December 98 October 99 April 00 March 01
Treatment uid composition
Before m3(Vn)
After (h bar2)¡1
Improvement (%)
Ranking
Shut-in time (h)
Volume (m3)
EGMBE (%)
KCl (%)
LiCl (%)
Citric acid (%)
0.5 1.1 1.6 0.6 0.8 1.8 1.0 1.5 2.2 2.0 3.0 2.5
2.1 2.6 1.5 1.3 1.3 1.8 1.6 2.0 2.2 3.0 3.0 3.0
320 136 ¡6 117 63 0 60 33 0 50 0 20
1 1 6 1 2 6 2 3 6 2 6 4
504 456 336 120 552 312 624 384 216 336 552 384
47.0 45.0 24.6 19.0 20.0 40.0 41.4 44.0 40.0 42.0 38.0 40.0
3 3 3 3 3 3 3 3 3 3 3 3
2 2 2 2 2 2 2 2 2 2 2 2
0 0 0 0 0 0 24.4 0 0 0 0 0
0 0 0 0 0 0 0 0 0 5 5 5
Evaluation of Halite Treatments
Figure 6. Treatment evaluation, PI before and after stimulation.
least be delayed. A prolonged shut-in period at the well (Dietzel et al., 1998) can also provide a temporary improvement in productivity index as a result of the recondensation of water vapour associated with the pressure build-up.
In a Northern Germany gas eld (formation: Bunter reservoir) operated by Preussag Energie with gas production from three wells (named Well 1, Well 2 and Well 3) fresh water treatments are applied for avoiding or removing salt precipitates. For the formation with a permeability of about 7 mD and an average porosity of 12%, the calculated value of the hydraulic equivalent diameter is 1.4 mm. A halite crystal of this size is suf cient for plugging the pore channel for the gas ow. The TDS content of the original reservoir water is 308 g l¡1, and the reservoir temperature is 110¯ C. The results of several years’ stimulation are discussed for Well 2 in detail. After Well 2 came on production in 1979, in 1985 production uctuations due to halite precipitation were reported and the rst fresh water treatment was launched. The recovery factor for the eld was only 10%. In this case, a slight loss of water led to salt crystallization. Twenty-seven cubic metres of fresh water were bull-headed and the well was shut-in for 1 h. The density of the back ow was monitored continuously. After chemical water analysis, the
Figure 7. Water cut in course of production of Well 2.
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HALITE SCALE FORMATION
Figure 8. Back ow behaviour of different treatments.
Figure 9. Treatment success in course of gas production.
produced water contained approximately 1000 kg of salt (halite equivalent). Fresh water stimulations have been performed in Well 2 once or twice a year. The value of the quotient Na=K was 24.8 § 1.3 before and 9.7 § 3.1 after salt precipitation. At present, the recovery factor for the eld is about 50%. The composition of the treatment uid and the results of stimulation are summarized for the past 12 years for Well 2 in Table 2. The speci c treatment volume varies between 1 and 2 m3 m¡1 as referred to the net thickness. This value corresponds to a theoretical average penetration depth of 1.1–1.7 m in the zone surrounding the well. The
shut-in time required for redissolution of precipitated halite ranges between 5 and 26 days. The implementation and evaluation of the treatments was done on the basis of productivity index, as shown in Figure 6. The plot presents the productivity index during production. The early detection method, as described above section, cannot be applied so far. Figure 7 illustrates the produced water cut and the theoretical water cut due to condensation in the production tubing for the Well 2. The theoretical water and the produced water cut are similar. Thus no reservoir water is produced, as needed for early halite scale detection. Owing to the produced condensate water, the density of the produced water is around 1.0 g cm¡3, as can be derived from Figure 8 for volume indices greater than 0.8. The results of stimulation have been appraised on the basis of the change in productivity index [m3(Vn) (h bar2)¡1] before and after the fresh water treatment (Figure 6). On an appraisal scale, the success of stimulation has been ranked in correspondence with the improvement in productivity index: DPI µ0% ! 6; DPI 0–10% ! 5; DPI 10–25% ! 4; DPI 25–50% ! 3; DPI 50–100% ! 2; DPI >100% ! 1. The results of 12 treatments performed on Well 2 during the period from 1993 to 2001 are compiled in Table 2. The results of stimulation have been ranked corresponding to the success achieved. The grades uctuate between 1 and 6, with an average value of 3.3 for all treatments. Thus, the achieved PI improvement is not constant during the time period evaluated. From a consideration of the shut-in time and the improvement in productivity index, it is evident that a maximum is attained in a few wells after 300 h (12.5 d ). For these wells, the increase in productivity index is about 240% at optimal ef ciency. A conspicuous feature is a frequent ranking pattern for repeated stimulations. The observed improvements correspond to the ranking sequence 6–1–6. These cycles are independent of the treatment volume, shut-in time, total dissolved salts and recovery factor. A provable interpretation of this behaviour with due consideration of all factors and an extension to the remaining wells in the eld is not yet feasible. A total of 27 fresh water stimulations have been evaluated for the gas eld concerned. In Figure 9, the resulting improvement in production index is plotted as a function
Figure 10. Fresh water treatment—bull heading.
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of the cumulative gas production per well (Wells 1–3). The plot clari es the importance of early detection of halite precipitation in the wellbore for high stimulation success. As can be seen from Figure 9, the ef ciency of the fresh water treatments decreases with cumulative gas production. Furthermore, the treatment must be optimized, in order to permanently dissolve halite scale in the near-wellbore area. The most crucial point for fresh water treatments in those reservoirs is reached when the reservoir pressure, on the one hand, is responsible for high halite scale potential in the wellbore area, and on the other hand is not able to back- ow the necessary amount of stimulation uid.
before and after stimulation. The frequently observed succession of highly successful and totally ineffective stimulation treatments cannot be interpreted in an unambiguous manner. No relationship can be detected between the amount of dissolved salt and the improvement in productivity index for the gas eld considered. An analysis of the back- owing uid after fresh water stimulation in a Bunter reservoir well has indicated that the major portion of the halite scale is deposited in the lower tubing and perforation zone. There is also evidence of its occurrence in the formation, at least in the near-wellbore area.
Well Speci c Evaluation
REFERENCES
During the back- ow phase of the injected fresh water slug, the density of the entrained water was determined, among other data. For Well 2, this value is plotted as a function of the speci c back- ow volume (V=Vo, Vo ˆ injection volume) over the period from 1988 to 1997 (Figure 8). From this plot, it is evident that the density maximum is shifted toward low V=Vo values from 1988 to 1991. This effect can be interpreted by assuming that the salt deposits have been displaced from the reservoir toward the perforation over the years. The data for 1993 exhibit a maximum at the beginning of back- ow and between 0.3 and 0.5 V=Vo. In 1997, on the other hand, the highest density occurred at the beginning and then decreased continuously during subsequent back- ow. This observation is explained by the displacement of salt precipitation from the zone surrounding the well through the perforation all the way to the lower tubing section. An explanation of the observed shift in the density of the back- ow brine is given in Figure 10 for the time period from 1988 to 1997. The reservoir pressure in the eld under consideration decreased from 300 to 160 bar during this period. This led to the following production behaviour. The water for treatment is bull-headed via the tubing. The treatment volume is then slowly injected into the reservoir by percolation of gas through the water column. It must be assumed that the treatment volume has penetrated deeply into the formation at high reservoir pressure (1988). As the pressure declines during the years, stimulation uid remains in the lower tubing zone and dissolves the halite scale inside the tubing (1997).
Carpenter, A. B., 1978, Origin and chemical evolution of brines in sedimentary basins. SPE 7504. Chare´, I., 1976, Trocknung von Agglomeraten bei Anwesenheit auskristallisierender Stoffe. Festigkeit und Struktur der durch die auskristallisierten Stoffe verfestigten Granulate. Dissertation, Karlsruhe. Couture, F., Jomaa, W. and Puiggali, J.-R., 1996, Relative permeability relations: a key factor for a drying model. Transp Porous Media, 23. Dietzel, H.-J., Kleinitz, W. and Littmann, W., 1993, Wiederherstellung der Zu ußbedingungen nach Aufwa¨ltigungs- und Komplettierungsarbeiten in Gasbohrungen, Erdo¨l Erdgas Kohle, 11. Dietzel, H.-J., Kleinitz, W. and Ko¨hler, M., 1998, The occurrence of water in gas wells, Nat Resourc Dev, 48. Dietzsch, G., 2000, Ein uss der Salzbildung auf das Produktionsverhalten von Gasbohrungen bei abgesenktem Fließdruck. TU BA Freiberg, Diplomarbeit. Franke, D. and Go¨sele, W., 1999, Hydrodynamischer Ansatz zur Modellierung von Fa¨llungen, Chem Ing Techn, 11. Hentschel, J. and Kleinitz, W., 1976, Aufbau der Salzgesteine des Salzstockes Etzel, abgeleitet aus Kernuntersuchungen und Loginterpretation, Kali Steinsalz, 7. Jasinski, R. and Frigo, D., 1996, The modelling and prediction of halite scale, Solving Oil eld Scaling Conference, January. Jasinski, R. and Sablerolle, W., 1996, Computer modelling HTHP salt and scale formation, Expl Prod Newsl, July. Kleinitz, W., 1978, Speicherprojekt Kalle der VEW, Auftreten und Verhindern von Salzausfa¨llungen im Speichergestein, interner Bericht Preussag AG. Kleinitz, W. and To¨lcke, W., 1982, Bildungsbedingungenvon Ablagerungen in Gasbohrungen und deren Beseitigung, Erdo¨l-Erdgas-Zeitschr, 4. Kleinitz, W., Dietzsch, G. and Ko¨hler, M., 2001, The precipitation of salt in gas producing wells; SPE 68953, Formation Damage Conference. Kretzschmar, H.-J., Czolbe, P. and Bauer, K., 1986, Diffusionsmessungen an Speicher-gesteinen mit unterschiedlichen Gasen und Messapparaturen, Erdo¨l Kohle-Erdgas, March. Mill, D., Beckmann, H. and Beinlich, W., 1997, Maßnahmen zur Injektivita¨tssteigerung=Verbesserung der Zu ußbedingungen von Gasspeichersonden durch Salzau o¨sung, DGMK-Tagungsband 9701. ¨ ber das Vorkommen des Strontium, Lithium und Bor in Peter, S.,1965, U Salzlo¨sungen aus dem deutschen Zechstein, Interner Bericht BEB. Schlu¨nder, E.-U., 1996, Einfu¨hrung in die Stoffu¨bertragung, Vieweg. Wagner, L., 1995, Stimulation von Gasbohrungen bei Salzausfa¨llungen. Diplomarbeit TU BA, Freiberg. Weiss, G., Henning, T., Ku¨mmel, R. and Tschernhaew, J., 1999, Modellierung von Stofftransport und Kristallisation in dispersen Systemen, Chem Ing Techn, 11.
CONCLUSIONS The production of entrained water from gas reservoirs can result in the deposition of halite scale as the wellhead pressure decreases. This phenomenon is associated with the increase in the solubility of water in methane with declining pressure. As a result of this process, the productivity is severely impaired, and wells may even have to be abandoned. For the early detection of halite scale deposits from entrained reservoir water, the use of certain quotients [Na=Li; Na=K; Na=(Ca ‡ Cl)] as indicators is proposed. In the case of halite precipitation downhole, these quotients vary signi cantly. For the evaluation of 27 fresh water treatments performed in a gas eld, an appraisal scale has been de ned; this ranking system is based on the change in productivity index
ADDRESS Correspondence concerning this paper should be addressed to Dr. W. Kleinitz, Preussag Energie GmbH, D-49808 Lingen, Waldstr. 39, Germany. E-mail: [email protected] The paper was presented at the 13th International Oil eld Chemistry Symposium, held in Geilo, Norway, 17–20 March 2002. The manuscript was received 29 May 2002 and accepted for publication after revision 17 January 2003.
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