Efficient reservoir management

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2 In Saudi Arabia, intense surveillance of a wateflooding scheme in a complex carbonate reservoir has come up with a few surprises. For example, it has shown that fluid flow in a large and highly stratified reservoir appears to be much simpler than the geology indicates. The monitoring programme has also revealed how the production strategy has influenced the vertical and horizontal water sweep. This has prompted Saudi Arabian Company to further investigate water encroachment patterns in the reservoir. Mahmood Rahman, Petroleum Engineering Specialist with Saudi Aramco and consultant Manfred Wittmann outline how the peripheral waterflooding scheme has been monitored and explain how this mass of data is now being incorporated into a geological model of the reservoir that will form the basis for 3-D simulation studies. This article is based on SPE Paper 2137, Case Study: Performance of a Complex Carbonate Reservoir Under Peripheral Injection, by M. Rahman, M. B. Sunbul and M. D. McGuire of Saudi Aramco presented at the SPE Middle East Show, Bahrain, November 1991.

3 Efficient reservoir management relies on a good understanding of a field s characteristics and performance. Using open hole logs as a datum, this knowledge can be built up over a field s life with carefully planned monitoring programmes. But this is often too late. What a manager really needs is a comprehensive and accurate model to help predict a reservoir s response to drilling and recovery methods. This article takes a practical look at the development of a major carbonate field in Saudia Arabia. The 25 km long by 15 km wide anticlinal reservoir was discovered in Exploitation was started in 197 and has been achieved by flooding the field with water injected through a series of wells on the northern periphery of the reservoir. Over the past 2 years a fifth of the original oil in place has been produced. But, evaluation of areal and vertical sweep has shown areas of the reservoir where oil is not being effectively displaced by the peripheral waterflooding technique. The observed performance has been incorporated into a geological model of the reservoir and forms the basis of a 3-D simulation of the entire field which has been built to guide future reservoir drainage management. The producing formation is one of a number of Late Jurassic shallowingupward sequences in this region of Saudi Arabia (see Middle East Well Evaluation Review, 1991 Number 11). The fine, permeable, carbonate grainstones become gravel-sized towards the top of the formation giving most wells typical shallowing-upward and/or coarsening-upward porosity profiles (figure 4.2). This is a favourable permeability distribution for peripheral waterflooding as the gravity pull is offset by the lower resistance to flow at the top of the reservoir. During deposition, the field area straddled a gently sloping carbonate platform margin (figure 4.3). This separated a broad, flat area of shallow water (a carbonate shelf) from a deeper, restricted basin. Carbonate grainstones formed quickly on the northern shelf. Below, in the basin, a slow rain of pelagic sediments produced finegrained rocks with poor permeability. A transitional zone developed between these two depositional environments. This variation in deposition is responsible for the rapid facies changes from grainstones on the northern ramp to mudstones in the basin. Associated with this is a reduction in reservoir quality from north to south. The geometry of the depositional layers was affected by the gentle slope of the margin (1-2 degrees). As a result, the geologic layers were not originally deposited as flat, horizontal beds, but were sigmoid-shaped similar to those shown in figure 4.3. Producer well Injection well Observation well Fig. 4.1: MONITORING PERFORMANCE: Exploitation of this Saudi Arabian reservoir started in 197. Since then, a fifth of the oil-in-place has been produced. However, saturation monitoring has shown areas where potential oil reserves have been missed by the peripheral waterflooding technique. 44 Middle East Well Evaluation Review

4 Variations in sea level during the Late Jurassic also affected the shape and make up of geologic layers. This resulted in highstand, lowstand and transgressive sequence system tracts (figure 4.3). Geologic layers, deposited during highstand sea level, built out toward the basin and draped successively over one another like tiles on a roof. As a result, the reservoir facies within the highstand layers remained in close contact. During the following lowstand time there was little or no deposition on top of the shelf or at the outer ramp. Instead, layers filled up the basin. As the sea level began to rise again a series of transgressive backstep grainstones were deposited at the top of the reservoir. As these backstep grainstones incompletely overlapped one another, the uppermost part of the reservoir is made up of different aged grainstones across the field. Fig. 4.2: Typical log showing the shallowing-upwards sequence in the reservoir. Gamma Ray API Depth Bulk density g/cc 1 ft Top of formation Base of formation South North Basin Outer ramp margin Outer ramp A B C C' Transgressive system tract Lowstand system tract Time line Depositional cycle E' G H I X/F Highstand system tract Boundstones Organic rich lime mudstones Packstones/ wackestones Gravels Grainstones Fig. 4.3: BLAME IT ON THE RAIN: The reservoir is situated in Late Jurassic sediments which straddle the edge of a gently sloping carbonate platform. Porous carbonate grainstones formed in the shallow waters to the north. In the deeper waters to the south, a fine rain of pelagic sediments formed fine-grained mudstones with poor permeability. The two different types of rock are separated by a transitional zone which developed between these two different depositional environments. Number 13,

5 CYAN MAGENTA YELLOW BLACK As predicted by the depositional model, the reservoir is better developed in the north and progressively thins and degrades to the south. The relatively low oil viscosity (.5 cp at reservoir condition, about twice the viscosity of the injection water) together with the end-point relative permeability to oil being considerably higher than to water, gives the waterflood a favourable mobility ratio. In the developed northern area of the field, productivity is generally high. However, the reservoir is highly heterogeneous and consists of a mixture of lithologies. Porosities vary between 1% and 23%, while permeabilities range from 5 md to 5 md. This is not uncommon in a carbonate reservoir where permeability depends on both porosity and rock type. For the same porosity, calcareous grainstones have permeabilities that are an order of magnitude higher than fine-grained micritic rocks. The reservoir is also highly stratified with large permeability variations between layers. Figure 4.4 is a core porosity and permeability plot for a typical crestal well. Even in the well-developed upper portion of the reservoir there is a large permeability variation. The reservoir heterogeneity is illustrated in the north-south cross-section shown in figure 4.5. It illustrates the essential reservoir characteristics, ie high variability and a general deterioration of quality from north to south. Fig. 4.4: Core permeability and porosity plot from a typical crestal well. There is a large permeability variation in the top part of the reservoir. Core permeability.1 1, 5 Permeability md Porosity % <1 md 1-1 md 1-1 md Measured depth ft Core porosity >1% South Well X Permeability (md) 3 6 K>2 Well Y Permeability (md) 3 6 Well Z Permeability (md) 3 North Depth ft Fig. 4.5: This 'fence' permeability diagram clearly indicates the wide range of permeability across the field. K>2 8 K<2 816 K< Middle East Well Evaluation Review

6 42 Pressure, Psig Pressure Decline and build-up Immediately after production started in 197, the reservoir pressure fell dramatically (figure 4.6). To stem the fall, a waterflood pressure maintenance project was initiated in January 1973 using injection water from a shallow, relatively fresh, aquifer. Injection wells were drilled close to the trailing edge of the OOWC and completed open hole. The objectives were clear: Year Fig. 4.6: WEAK AQUIFER: As soon as production started in 197, the reservoir presure went into rapid decline. At this rate, bubble-point pressure would have been reached within two years. To prevent this, the operator embarked on a peripheral waterflood scheme which successfully managed to reverse the pressure decline. 1. Producer Residual oil saturation. Injector To ensure the reservoir pressure remained above the bubble point. To keep wells flowing at high water cuts to obviate the need for pumps or gas lift. To move the oil towards producing wells situated in the updip area. Two years after injection started, water began to breakthrough in the first row of producers. Initially these wet wells had to be shut in or recompleted to drier zones towards the top of the reservoir. However, water production was allowed from 1981 when wet crude handling facilities were installed. Since then, the field s average water cut has only increased to around 2% although the flood front has advanced to the crestal area. This low water cut is maintained because all wells flow naturally, so when an individual well s water cut increases to between 6% and 7%, it becomes water logged, stops flowing and dies. Hence, the total water (and oil) production is reduced. To sustain the overall oil rate, new wells are drilled and dead wells worked over and recompleted to drier zones. By December 1989, a total of 75 wells had been drilled. Of these 42 were producers, 15 were injectors and the remainder were observation wells. S w Connate water saturation. Time (distance) Fig 4.7: Since the injection wells are located outside the trailing edge of the OOWC - and because of the favourable mobility ratio - large banks of high salinity aquifer or formation water advance through the reservoir ahead of the injection water. This results in an increase in log readings followed by a decrease as the formation water is replaced by less saline flood water. Direction of flood Number 13,

7 Porosity Depth PNL PNL PNL PNL ft CU CU CU CU 9 % Fig. 4.8: SALT SURVEILLANCE: These time-lapse pulsed neutron logs give a clear indication of the movement of the waterflood front across a section of the field. Top of Res Base of Res. 82 Neutrons and networks Extensive monitoring has been used to observe the waterflood sweeping across the reservoir. The principal saturation monitoring tool has been the Pulse Neutron Capture Log (PNL). This log has been run on a routine basis since the mid-197s when flood water started to break through in the outer producing wells. Because of the high formation water salinity of 24, ppm total dissolved solids (TDS), PNL logs have been very effective in tracking the advance of the flood front through the reservoir (figures 4.7 and 4.8). In addition to producing and observation wells, PNL logs have been run in 25 deep wells and these have provided excellent waterflood observation points as they are not hampered by fluid invasion, acid or other effects. Once the high salinity flood front has passed through a monitoring point, it is followed by the relatively fresh injection water - salinity 24, ppm TDS. The resultant mixed salinity environment makes quantitative interpretation of PNL logs difficult - the calculation depends on a known water salinity factor. Further complications arise when a zone is just starting to deplete and contains both oil and formation water while another zone in the same well has already been swept and contains a mixture of formation and injection water. In this situation it is difficult to distinguish one zone from another using PNL logs. To overcome this mixed salinity problem, a network of key wells has been established. These wells are frequently logged to monitor qualitatively the displacement of oil-first by formation water which causes an increase in PNL response, and then by the injection water which causes a decrease in PNL response. In addition, wet wells are routinely tested and samples of produced water collected for geochemical analysis. From this, the proportion of injection and formation water in the wet producing zones of the well is estimated. Finally, flowmeter surveys with gradiomanometers are conducted to obtain the flow profile and identify water producing zones (see Go with the flow in this issue). Well performance, geochemical data and flowmeter-gradio results are combined with the PNL log interpretation for each well to establish: Zones that are sweeping or responding to the peripheral flood, and; Zones indicating no significant movement or sweep. Figure 4.8 is an example of this type of surveillance data. It shows the progress of the waterflood as observed from time-lapse PNL logging of a typical flank well. Another important aspect of the waterflood monitoring effort is the evaluation drilling program that was started in the late 198 s. This is aimed at evaluating the sweep in the reservoir s undrilled areas, between the injectors and first row producers. In addition to cores and open- hole logs, these wells provide the opportunity to selectively test individual layers to determine fluid content and salinity and to run wireline multiple-pressure testers, such as Repeat Formation Tester (RFT), across the reservoir. Over the past four years, a total of eight evaluation wells have been drilled. Integrating data from these wells with routine surveillance data from the 67 existing wells gave a good understanding of the reservoir s water encroachment patterns and flow characteristics. It also produced a good assessment of the areal and vertical sweep across the reservoir, which was the primary objective in evaluating the performance of the waterflood. Such measurements have been made easier with the arrival of the Reservoir Saturation Tool (RST*) into the Middle East (see Middle East Well Evaluation Review, Number 11, 1991). 48 Middle East Well Evaluation Review

8 A CLEAN SWEEP The effectiveness of a reservoir waterflooding scheme depends on three basic factors - the microscopic displacement, and the areal and vertical sweep efficiencies. For best results, these factors should be determined by a detailed reservoir study which includes simulation. However, a quick assessment of the waterflood performance can be made by assigning a value between. and 1. for each of the three efficiency factors. The overall waterflood efficiency can then be computed by multiplying these three values. For example, a reservoir with microscopic, areal and vertical sweep efficiencies of.6,.7 and.5 respectively would have an overall flood efficiency of.21. In other words, only 21 percent of the oil-in-place would be recovered. Microscopic displacement efficiency is a measure of how easily the oil can be removed from the rock pores. Efficiency values can be obtained from laboratory core studies or the Log-inject-Log technique using equipment such as the Thermal Decay Time tool. The use of surfactants, which improve the rock wettability and reduce the interfacial tension in the system, can increase displacement efficiency. Areal sweep efficiency is a measure of how much of the reservoir has been in contact with the flood water in an areal plane. Vertical sweep efficiency is a measure of the uniformity of water invasion in a vertical cross section. Both the areal and vertical sweep are dependent on a large number of factors: the distribution of horizontal and vertical permeability, anisotropy, wettability, reservoir thickness, fluid characteristics, the injection/production rates, the placement of perforations, type of injected fluid (water or gas), the well spacing etc. Proper planning of a waterflood should take into account most of these parameters and the predictions are usually based on model studies (both numerical and laboratory). The actual waterflood performance can be estimated by examining saturation data from in-fill and observation wells and tracer surveys. In a tracer survey, chemical or mildly radioactive tracers are added to the injection water and their arrival time at the producing well is noted. Today, reservoir simulation studies are playing an increasingly important role in determining the areal and vertical movement of the injected water. They also help to guide drilling programmes aimed at maximising the sweep efficiency of the waterflood. Areal sweep Sand Injection wells Producer Fig. 4.9: AREAL SWEEP: A measure of how much oil is left behind in areas not swept by the waterflood. Fig. 4.1: VERTICAL SWEEP: Defined as the crosssectional area contacted by the injected fluid divided by the cross-sectional area enclosed in all layers behind the fluid front. Fig. 4.11: MICROSCOPIC DISPLACEMENT: Relates to the removal of oil by water on the porescale. Number 13,

9 CYAN MAGENTA YELLOW BLACK The term sweep, as used here, implies that a part of the reservoir has been contacted by formation or injection water. Because of the problem of mixed salinity, no effort was made to evaluate displacement efficiency. As there was no reliable simulation model available, sweep was evaluated by generating a series of cross sections parallel and perpendicular to the structure (figure 4.12). encroachment data from individual wells was superimposed on these sections and the swept and unswept zones identified and correlated from well to well. The reservoir was then divided into a number of layers, based on permeability. For each of these layers, maps were drawn showing the swept and unswept zones. In addition, net oil isopachs were prepared to estimate the volume of unswept oil. From this waterflood evaluation, which is mainly based on observed performance, several important conclusions can be drawn: 1. In spite of the complexity and significant variation in rock-type and permeability, all facies with a permeability greater than 2 md responded to the peripheral flood. Upper and middle sections of the reservoir, which contained most of the permeable layers, were flooding together almost as one package. 2. The lower part of the reservoir, where the permeability is generally less than 1 md, was not flooding at all. In spite of being completely overlain by flood water in the permeable zones above, there was no noticeable encroachment of water or displacement of oil from these tighter facies. It is possible that the tight lower zones that are not flooding may be more oil wet than the more permeable zones above. However there is no wettability data to support this (see box on page 55). 3. On the northern flank of the field, there was unswept oil in the permeable upper part of the reservoir. 4. Although early PNL and resistivity logs showed water breakthrough in the highest permeability zones, there are no major fingers anywhere in the reservoir. This is believed to be due to good vertical permeability, favourable mobility ratio and the field operating strategy of restricting the producers ahead of the flood front. A good way to illustrate water encroachment in a reservoir is through cross sections (figures 4.13 to 4.16). The east-west section AA' represents the northern flank, an area that is close to the injectors, and had more injection water pass through it. This section is shown both stratigraphically (figure 4.13) and structurally (figure 4.14). B L A M A B C D F E I H J N O' K C' P Q R Fig. 4.12: ON THE WATERFRONT: Prior to the development of a reservoir simulation model, the only way to assess the efficiency of a waterflooding scheme was to generate a series of crosssections across the field. These helped to locate the swept and unswept zones. This map shows the approximate location of each of the sections presented in figures 4.13 through There are two distinct permeability zones - the lower zone with permeability generally less than 1 md and the upper zone which ranges from 2 to 5 md. Individual log sections show the porosity profile on the left track. On the right track, injection wells show the flowmeter profile while producing or observation wells show the PNL log response. These sections clearly show that: is entering more or less uniformly into the permeable zones (K>2 md). It then gravitates down to the base of the permeable zone and continues to ride on top of the tight zone (K<1md). The flood water is sweeping through the middle section of the reservoir with oil above and below. Time-lapse PNL logs show that the oil at the top is still moving, although at a slow pace. The oil in the tight facies (K<1 md) is not sweeping at all. The cross section BB' (figure 4.15) goes through the crestal area from east to west flank. It shows a dry crestal producer with a flood front approaching from both sides. This cross section shows a similar flooding pattern as G A' B' observed in section AA'. However, there are differences: The injection wells have a poor flow profile because the permeable facies have become thinner on the flanks. But even then, the flood water is sweeping through the permeable zones (K>2 md) but completely by-passing the tighter zone (K<1 md) below. The thickness of the unswept oil at the top is much thinner (2 ft) than the unswept oil column (8 ft) observed in the northern cross section, AA'. This, as will be shown later, is primarily due to better drainage in the crestal area compared to the northern flank. The north-south cross section, A'C' (figure 4.16) which goes from the injection well in the north flank to the dry wells in the south, confirms the sweep pattern observed in the two east-west cross sections, AA' and BB. N 5 Middle East Well Evaluation Review

10 A Well - A Well - B Well - C Well - D Well - E Well - F Well - G Top res A' Fig. 4.13: East-west stratigraphic cross section showing two distinct permeability zones. The flood water is sweeping through the middle of the reservoir, leaving oil above and below. Base res Injector W K = 2-5 K=1 Swept zone E Injector A OOWC Well - A Well - B Well - C W Well - D Well - E Well - F K = 2 K = 1 Swept zone E Well - G OOWC Top res Base res A' Fig. 4.14: Structural section along the same line as that of figure B Well - L Flood Flood front front Well - M Well - N Well - O Well - P Well - Q Well - R Top res. B' Fig. 4.15: East-west cross section through the crestal area revealing a dry producer with the flood front approaching from both sides. Base res. Injector W K = 2-5 K = 1 Swept zone E Injector C' Flood front Well - K Well - J Well - I Well - H Well - F Well - G Dry Wet K 2-5 Top res A' Fig. 4.16: This north-south section confirms the sweep pattern which was observed in the east-west sections. K =1 Base res S Swept zone N Injector Number 13,

11 CYAN MAGENTA YELLOW BLACK Fig. 4.17: VERTICAL EQUILIBRIUM: RFT pressure profile of a crestal evaluation well indicates absence of barriers. The best evidence of good vertical permeability can be obtained from RFT pressure profiles of wells drilled in both producing and non-producing areas of the reservoir. Twelve recently tested wells showed a uniform pressure profile across the permeable section of the reservoir. Figure 4.17 illustrates a pressure profile of a crestal evaluation well. There is no differential depletion and the pressure profile across the permeable section of the reservoir is uniform. This confirms the absence of extensive horizontal barriers and indicates that there is enough vertical communication between layers to allow movement of oil and water across the reservoir. The average mobility ratio of the waterflood is estimated at.4. Based on experience with other waterfloods, such a favourable mobility ratio has a very positive impact on areal and vertical sweep since it eliminates any possibility of viscous channelling (or fingering) of water through the oil, causing early water breakthrough in the producing wells. Also, reservoir management has been a key factor in ensuring good areal and vertical sweep. A producing strategy was implemented in This restricted or shut in dry producers ahead of the flood front and preferentially produced the wet wells to the rear. As shown by the water arrival isochrones in figure 4.18, this slowed down the rate of advance of the flood front, avoiding water breakthrough along high permeability streaks and allowing gravity forces to smooth out the effect of stratification. This is why there is no evidence of fingering in the reservoir even though the early resistivity and PNL logs showed water breakthrough in thin, highly permeable zones (figure 4.19). Resid. Moved HCarbon 5 % Depth ft RFT Pressure-Psig / interface DST 278 Bbl/day.3% cut Gradient =.3 Psi/ft DST 843 Bbl/day 56% cut Gradient =.42 Psi/ft Gradient =.52 Psi/ft Supercharged? DST 395 Bbl/day % cut Gradient =.3 Psi/ft 1978 Fig. 4.18: FLOOD FRONT ADVANCE: Movement of the flood front across the field was slowed down by preferentially producing the wet wells and restricting the dry crestal wells Flood front Producer well Injector well Observation well 52 Middle East Well Evaluation Review

12 A sweeping improvement There is a column of dry oil at the top of the reservoir that is sweeping very slowly (figures 4.8 and 4.13). These unswept zones were identified and isopach maps showing the thickness and extent of this unswept oil were drawn for each layer. To investigate the reason for this lack of sweep in the permeable upper portion of the reservoir, especially in the NE flank where there is adequate injection support, all possible factors that may have a bearing on sweep were critically reviewed. Structure, gross pay, pressure, permeability, cumulative injection/withdrawal, current injection/production etc are some of the factors that were examined (figures 4.21 to 4.26). However, the parameter that gave the closest correlation with poor sweep is poor drainage. Currently, most of the producing wells are located in the crestal area of the reservoir. There is very little withdrawal from the NE flank where the oil at the top has stopped moving. This is partly due to the reservoir being flat (formation dip ) and also because the crestal production is effectively supported by injection water moving through the highly permeable middle section of the reservoir. Therefore, there is no horizontal pressure gradient to drive oil from the NE flank to the producing wells in the central area. Plans are underway to improve recovery of the unswept oil by providing more drainage points in the NE flank. This will be done by recompleting existing wells and drilling infill wells. However, because of the relatively thin oil column and underlying water, wells are expected to cone water. Therefore, horizontal wells are being planned and eventually artificial lift will be required to produce these wells at higher water cuts. As regards the unswept oil in the tighter lower part of the reservoir, it is believed that the current peripheral flood will recover very little oil from this facies. Developing these tighter facies may require waterflooding at very close spacing or some other recovery technique. Porosity 5 % Depth ft Dry oil PNL Playback 1977 Sigma cu 1984 Sigma cu 1988 Sigma cu Fig. 4.19: EARLY WARNING: breakthrough in the thin, highly permeable zones can be clearly seen in this early log. However, the producing strategy was designed to prevent this from occurring in the crestal area of the field. 5 Flood Swept zone Fig. 4.2: Thickness and areal extent of the unswept oil zone. front Unswept oil Flood front Number 13,

13 6 CYAN MAGENTA YELLOW BLACK psig 4 Unswept oil Flood front Fig. 4.21: Structure versus unswept oil in layer BBI. Fig. 4.22: Gross Pay versus unswept oil in layer BBI. Fig. 4.23: Isobaric map versus unswept oil in layer BB md Flood front Flood front Unswept oil Producer Injection well Observation well Unswept oil Producer Injection well Observation well Unswept oil Fig. 4.24: Permeability versus unswept oil in layer BBI. Fig. 4.25: Cumulative production/ injection versus unswept oil in layer BBI. Fig. 4.26: Current drainage/injection versus unswept oil in layer BBI. Looking to the future The performance characteristics of the field have now been incorporated into a new geological reservoir description which forms the basis of a 3-D simulation model of the entire field. Reservoir simulation is now in progress and will be used as a key reservoir management tool. It will not only be used to predict future performance but also to optimize the producing and development strategies for the field. Acknowledgement Appreciation is given to the Saudi Arabian Ministry of Petroleum and Mineral Resources and to Saudi Aramco for permission to publish this paper. 54 Middle East Well Evaluation Review

14 WET...WET...WET Wettability is an extremely important factor as it controls the location, flow and distribution of fluids in a reservoir. It is a measure of the preference that the rock exhibits for either oil or water and has been defined as the tendency of one fluid to spread on or adhere to a solid surface in the presence of other immiscible fluids. If a rock is water wet, the water will tend to occupy small pores and be in contact with most of the rock surface - the ideal situation for anyone wishing to extract oil from a reservoir. In an oil-wet system, the rock retains the oil in its small pore spaces, making production more difficult. There are several ways of assessing wettability. One relies on measuring the contact angle which is formed when a drop of water is placed on a rock surface immersed in oil (see figure). If the rock is water wet, the contact angle is less than 9. In an oil-wet system, the angle exceeds 9. Wettability measurements on core samples are not always reliable because it is difficult to retain the original wetting character of the rock during sampling or in the laboratory. Logging techniques, which measure the difference in resistivity between oil- and water-wet rocks, can provide some estimates of in-situ wettability measurements. θ c Rock wet (θ c > 9 ) θ c Rock wet (θ c < 9 ) Fig. 4.27: In water-wet systems, the contact angle is less than 9. Fig. 4.28: In oil-wet rocks, the converse is true. Further reading: Wettability Literature Survey - Part 1: Rock//Brine Interactions and the Effects of Core Handling on Wettability by W.G. Anderson in Journal of Petroleum Technology, Oct. 1986, page Number 13,