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SPE 89376
A New Way to Diagnose Injectivity Decline During Fractured Water Injection By Modifying Conventional Hall Analysis K. I. Ojukwu, P. J. van den Hoek, Shell International Exploration and Production B.V.
Copyright 2004, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 2004 SPE/DOE Fourteenth Symposium on Improved Oil Recovery held in Tulsa, Oklahoma, U.S.A., 17–21 April 2004. This paper was selected for presentation by an SPE Program Committee following review of information contained in a proposal submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to a proposal of not more than 300 words; illustrations may not be copied. The proposal must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
Abstract For many years, unfiltered produced water has been used in the flooding of heavy oil reservoir in Southern Oman for pressure maintenance. Initially it was thought that the water injection was under matrix conditions. However, it is well accepted in the industry that water injection and particularly produced water injection almost, always takes place under fracturing condition. Significant decline in injectivity was repeatedly seen due to downhole blockages. Routine clean-ups and acidizations were carried out without success. Early 2003, a dedicated study was conducted to identify the root cause of this problem and recommend a remedial action. The purpose was to determine if the decline is due to poor water quality, reservoir compartmentalization, matrix/fracture or wellbore plugging. An unconventional approach was used to conduct a comprehensive study using historical data by modifying the Hall-Analysis technique. It was concluded that poor water quality was the problem. The interpretation of the Modified Hall Plot together with Bottomhole Pressure (BHP) vs. Rate plot also provided evidence of wellbore and/or fracture plugging. Both qualitative and quantitative analyses characterized the initial matrix injection period and fracturing injection regime that followed. Fracture plugging, routine well stimulations and fracture propagation trends were interpreted from the plots. A 3D in-house simulation package for waterflood under fracturing conditions was used, independently, to simulate injection conditions and confirm the results. Simulated injection pressure was much lower than actual field data confirming severe plugging. Further analysis showed that the plugging was due to unconventional particulates different from solids and oil contaminants in water. Recommendation was made to identify the contaminant and maintain a maximum suspended solid concentration of
100ppm to contain fracture propagation. A recent filter trial confirmed the presence of FeS contaminant. Successful remedial action was taken followed by re-commissioning and water treatment facility design to realize estimated 150m3/d/well and improving ultimate recovery. Recently, another field study has successfully completed adopting same technique. By modifying Hall Analysis technique, it is possible to use field data for diagnosing matrix/fracturing regimes, assessing degree of damage and determining the location of the damage. 1. Introduction For many years, unfiltered produced water has been used in the flooding of heavy oil reservoir in Southern Oman for pressure maintenance. Initially it was thought that the water injection was under matrix conditions. However, it is well accepted in the industry that water injection and particularly produced water injection almost, always takes place under fracturing condition. Significant decline in injectivity was repeatedly seen in the five injectors due to downhole blockages. Routine clean-ups and acidizations were carried out without success. Early 2003, a dedicated study was conducted to identify the root cause of this problem and recommend a remedial action. At the time of this study, it was not clear whether the injection was under fractured or matrix condition. Main objective of this study was to investigate water quality required for matrix and controlled fracturing injection, evaluate the subsurface aspects of the injectivity decline mechanism, and to provide guidance for well remediation/recommissioning and water treatment facility design. An unconventional approach was used to conduct a comprehensive study using historical data by modifying the Hall-Analysis technique. Hall devised a qualitative approach to eliminate the complications of both pressure and injection rate variations. Since then many articles have been published in this subject showing how it can be used in a particular field, or in comparison with some other method of treatment. However, in most cases its only use is in recognizing formation damage1. In this paper, we have modified Hall’s technique by using it to quantify damage Skin. Using this approach it was concluded that poor water quality was the problem. The interpretation of the Modified Hall Plot together with BHP vs. Rate plot also provided evidence of wellbore
2 SPE 89376
and/or fracture plugging. Both qualitative and quantitative analyses characterized the initial matrix injection period and fracturing injection regime that followed. Fracture plugging, routine well stimulations and fracture propagation trends were interpreted from the plots. A 3D in-house simulation package for waterflood under fracturing conditions was used2, independently, to simulate injection conditions and confirm the results. Simulated injection pressure was much lower than actual field data confirming severe plugging. Further analysis showed that the plugging was due to unconventional particulates different from solids and oil contaminants in water. Recommendation was made to identify the contaminant and maintain a maximum suspended solid concentration of 100ppm to contain fracture propagation. A recent filter trial confirmed the presence of FeS contaminant. Successful remedial action was taken followed by re-commissioning and water treatment facility design to realize estimated 150m3/d/well and improving ultimate recovery. Recently, this technique has been successfully applied in two other fields in Oman. By modifying Hall Analysis technique, it is possible to use field data for diagnosing matrix/fracturing regimes, assessing degree of damage and determining the location of the damage 2. Water Injection Fig. 1a and Fig. 1b show the performance of five produced water injectors X1, X2, X3, X4, X5 in X-field, a Southern Oman field. This field had suffered a huge decline in pressure, from an average of 180Bar down to 80Bar owing to poor aquifer support. It was then planned to implement produced water injection under fracturing condition in order to inject some 350m3/d of produced water per well. Produced water injection began in 1999 and reached a peak injection rate of 600 m3/d before starting to show a rapid decline in 2002 as shown in Fig. 2. In the same token, all the wells have individually shown injectivity decline behavior throughout their lifetime. Fig. 2 equally shows the time-lapse pressure decline in the field, which is a combination of repeat formation tester and pressure build-up surveys data. Routine acid stimulation jobs have been carried out to remedy the injectors, thereby temporarily restoring their injectivities without any lasting solution. In late November 2002, X1 injector revealed a dramatic improvement in injection rate, from 30m3/d to 350m3/d, after a stimulation trial, which was mistaken for a possible casing leak or cement bond failure. Water injection was carried out via a 200Bar capacity horizontal electrical submersible pump. Due to the limited injection pressure, it is not possible to increase injection rate once the 200Bar of wellhead pump capacity is reached. Therefore, either injectivity decline continues until total injectivity is lost or a well stimulation is executed to restore injectivity. Fig. 3 shows a block diagram of the flow station facility, which is located about 13km from the field, and this is where all produced water from the surrounding fields is channeled.
Prior to this study, a produced water node-to-node sampling was carried out in the area. The result showed that the produced water supplied to X-field has (Total Suspended Solids) TSS concentration of 234ppm and (Oil-in-Water) OIW concentration of 40-200ppm. It had been noted that oil over flow in the CPI due to malfunctioning of interface and trip levels led to slugging of the injection line. Furthermore, an increase in production was seen around the same period when water injection began, (Fig. 2). However, there was no recorded reservoir pressure data during this period to indicate pressure communication.
3. Injection Zone Fig. 4 shows the well-well correlation for the X-field including the various formations and interlaying shales. There are three production intervals, Zone A and Zone B and Zone C with intervals at 1399m-1435m, 1435m-1491m and 1491m-1526m respectively. The aim of the waterflood is to constrain water injection into Zone C primarily for pressure maintenance and as such, it is desired to keep the induced fracture from propagating across the shale cap rock into upper Zone B. Due to this fact, the scope of this study extended to determining the water quality that is required to keep the induced fracture from growing beyond Zone C over a ten year period. Injection zone, Zone C, is a 35m interval and characterized by an average permeability of 23md and water end-point relative permeability of 0.15. The NG ratio is 0.5 and has an estimated drainage radius of 915m derived from half the minimum injector to producer spacing. The water injectors are completed in a formation interval of 35m using 12 shots-per-foot HSD guns, big hole charges and no gravel packs. The flow conduit is identical 3.5” tubing in 7” liners. 4. Diagnostic Methodology The methodology adopted was to investigate the entire potential areas starting from the facility, wells, then to the reservoir. The possible causative agents comprise of the following, • Facility: TSS, OIW, SHMOO6 (oil coated solids such as
FeS or clay particles) and other facility contaminants. Also inline guard filters (if any) can get plugged.
• Wells: Perforation plugging, wellbore fill by scale/sand/corrosion debris and mechanical restrictions.
• Reservoir: Matrix plugging, fracture plugging and compartmentalization.
In order to determine which of these factors that could influence the injectivity a two-process methodology was used, namely, Diagnostic Evaluation and Matrix & Fractured Injection simulation. The Diagnostic Evaluation addresses the both facility and wells aspects while the Matrix & Fractured Simulation deals with the Reservoir aspect. Conventional Hall Slope Hall originally proposed this plot method in 1963 to qualitatively analyze the performance of waterflood injection wells. The conventional Hall plot is the integral of the pressure
SPE 89376 3
drop with respect to time versus cumulative injection using historical injection data (Fig 5)3. Hall devised the following approach to eliminate the complications of both pressure and injection rate variations. This method was based on Darcy’s law for steady-state, Newtonian flow of a well centered in a circular reservoir, which is given in Eq. 1. Observation of the pressure function plot reveals that if an injection well is stimulated, there should be a decrease in slope, and if a well is damaged, the slope should increase. Regardless of the constant value assumed for pr, the slope changes mentioned above would still occur1. Only the intercepts would change. The Hall Plot analysis for steady-state matrix injection3,4, is a plot of
in dtpp rw )( −∑ psi.day versus in dtqw∑ bbl will yield a slope governed by the Eq. 1,
effw
w
eww
statesteady hkrrB
SlopeHall}{ln2.141 ⎟⎟
⎠
⎞⎜⎜⎝
⎛
=µ
Eq. 1: Hall Equation for steady state Modified Hall Slope The conventional Hall Slope can be modified for a semi-steady state injection by modifying Eq. 1.
effw
w
eww
statesteadysemi hkrrB
SlopeHall}
43{ln2.141 −⎟⎟
⎠
⎞⎜⎜⎝
⎛
=−
µ
Eq. 2: Hall Equation Modified for semi-steady state The equation for Skin Factor is given by4,5,
Eq. 3: Pressure Drop Across Skin By accounting for both Skin (substituting Eq. 3 in Eq. 2) and average reservoir pressure, Eq. 2 could be further modified to Eq. 4.
effw
w
eww
hk
SrrB
SlopeHallModified}
43{ln2.141 +−⎟⎟
⎠
⎞⎜⎜⎝
⎛
=µ
Eq. 4: Modified Hall Equation As in the popular radial flow equation, the Skin concept makes it possible to quantify matrix damage/plugging at every upward slope or fracture initiation at the initial downward slope.3 Successive downward slopes could be further quantified as fracture propagation or near wellbore stimulation. Beyond the point of initial fracture, successive upward slopes are interpreted as fracture plugging or wellbore plugging. Positive Skin signifies matrix damage or fracture plugging while negative Skin, on the other hand, signifies initial fracture, fracture growth or stimulation. To determine
the actual location of the damage, a bottomhole pressure vs. rate plot was used. Pressure-Rate Plot The plot of bottomhole injection pressure against injection rate is schematically represented in Fig 6. This plot is qualitatively helpful in differentiating between wellbore plugging and fracture plugging. In matrix injection, the bottomhole pressure (BHP) is a direct function of injection rate. Once the formation is fractured, the BHP remains fairly constant during injection as the injection rate varies. This pressure is called the Fracture Propagation Pressure (FPP). The increase in rate during fractured injection is accounted for by the fracture growth laterally and transversely causing the pressure to remain at the FPP. In principle, a horizontal straight line along the FPP defines a fracture in a given formation. However, it is possible for this straight to shift upwards parallel to each other due to plugging. Successive parallel lines close together can be interpreted as a sign of gradual plugging while wide gaps between these lines could be a sign of sudden plugging. In this study, gradual plugging has been likened to fracture plugging while sudden plugging is associated to wellbore plugging effect. With this understanding, all the X-field wells were diagnosed.
5. Diagnosis of Water Injectors The methodology described above was used to diagnose the performance of the five produced water injectors in X-field. This technique was used to investigate both the facility and wells causes by looking into the historical injection performance. With the Modified Hall Analysis technique each injector’s flow regimes were identified using the Skin values. It was generally found that the initial matrix regimes only lasted for a couple of days before fractures were initiated. Initial fracture is characterized by sharp decrease in Hall Slope (downward slope), which is marked by higher injection rate. Subsequent increase in Hall Slope, after the initial fracture, is interpreted as injectivity decline due to fracture plugging or closure. However, for a fracture to close, the injection pressure will have to reduce to the Fracture Closing Pressure (FCP).
effw
wwskin hk
qSBP µ2.141=∆
Three of the five injection wells, X1, X3 and X4 have been selected to illustrate this technique. The same diagnostic technique applied to X2 & X5 yielded conclusive results and will be summarized. Well X1 Hall Analysis & Interpretation Fig. 7 fully illustrates the Hall Plot of X1 well from start of injection to the time of stimulation in November 2002. Fig. 8 shows the Hall plot from the time of stimulation job to the time of commencement of this study. The plots also include the BHP and injection rate record against cumulative water injection. First, the initial slope was identified in the Hall Plot. By equating this slope to the Modified Hall Slope, Eq. 4, it was possible to estimate the value of Skin using the given parameters listed below,
4 SPE 89376
µw= 0.5cp, kw= kkrw= 23md x 0.15= 3.45md hw= h x NG= 35m x 0.5 = 17.5m = 57.4ft re = 2986ft rw= 0.354ft Bw= 1 Matrix Skin was calculated as 27 taking a slope of 55psi.day/m3. This implies that injection into X1 well commenced under matrix conditions before inducing the initial fracture at point ‘a’. After point ‘a’ the Skin value of –3.9 confirms an initial fracture. An average rate of 150m3/day was sustained until 6000m3 of injection when the curve began to slope upwards rapidly implying significant plugging of the fracture. Fracture propagation at point ‘b’ sharply changed the slope downwards to 55psi.day/m3, which gives an equivalent Skin of 27. This Skin is interpreted as being due to a partially plugged fracture causing an injection rate increase to 75m3/day (50% of initial fracture regime). By identifying this historical trend, the reason for the current injectivity decline in X1 became apparent from the very high slope seen at the end. The conclusion is that X1 is severely plugging under fracturing conditions prior to the stimulation job. The Pressure-Rate plot (Fig. 9) confirms that this is possibly a mixture of both wellbore and fracture plugging. Each trend line shows fractured injection over a given period of time. This is explained by the fact that fracture lines are wider at the beginning and then followed by closer lines at the top.
Further analysis of the post-stimulation Hall plot (Fig. 8) yields a fairly single straight line with a slope of 6.9psi.day/m3 (Skin= -5), which is interpreted as a unplugged fracture condition. This result implies that a remarkable improvement in injectivity has been achieved during the stimulation job. The post-stimulation Tubing Head Pressure (THP) of 80Bar at injection rate of 350m3/day was supported by the fracture simulation using in-house induced fracture simulation package whose results are presented in section 7. The post-stimulation Pressure-Rate plot of X1 (Fig. 10) shows a clear trend line, which is interpreted as indicating minimal plugging as would be expected after a matrix/fracture stimulation.
Well X4 Hall Analysis & Interpretation Fig. 11 and Fig. 12 illustrate the Hall Plot and Pressure-Rate Plot of X4 well, respectively. In a similar manner as X1 these plots were interpreted and found that injection started almost under fracturing conditions masking the early matrix injection period. The initial fracture period (slope= 7.9psi.day/m3 corresponding to Skin of –3.9) lasted for about 30 days at 200m3/day, and a THP of 60Bar. The above finding is supported by computer simulation done using the in-house fracture simulation package (Fig. 13). On the other hand, Fig. 12 shows evidence of wellbore plugging as seen from the significant jump in fracture trend lines and this can be spotted on Hall Plot at point ‘a’. The fracture trend lines mapped between July 2002 and October 2002 illustrate that the fact that they represent later time periods as the THP trend moves upwards.
Well X3 Hall Analysis & Interpretation Fig. 14 and Fig. 15 are the Hall Plot and Pressure-Rate Plot of X3 well respectively. This well was diagnosed in much the same way as X1 & X4. The results show both the matrix and fractured injection regimes. Fig. 14 shows the short matrix injection period (Skin= 31), which was followed by fracture initiation (Skin= -7). By comparing the last slope with the initial fracture slope, it is clear that this well is excessively plugging. Also, the Pressure-Rate Plot (Fig. 15) illustrates close fracture trend lines, which infers that this well is likely plugging at the fracture.
6. Matrix Injection simulation of X-Field Matrix injection simulation of produced water injection into X-field injectors was performed using an in-house matrix injection simulation package. This simulation package is capable of modelling filtercake damage by using the specification of contaminated produced water to generate an injectivity decline curve given various formation and completion information. The simulator was used to replicate injection under matrix conditions for X-field. Fig.16 shows the resulting injectivity half-life of about 2 days for water quality of 234ppm TSS. While checking with higher permeability such as in X2 & X5 wells, it was found that sustainable matrix injection is possible for as long as 50 days at 300m3/day. This fact is in line with observations made from Hall Analyses of the injectors historical performance described earlier. Fig. 16 can be used to predict what happens if the solid loading is reduced to TSS of 5ppm from 234ppm, and that the injectivity half-life could possibly extend to 130 days.
7. Fractured Injection simulation Fracture simulations of produced water injection into X-field water injectors were carried using a dedicated in-house 3D fracture simulator for (produced) water re-injection 7-11. The simulation was done under a ‘Constant Flow Boundary’ assumption. The quality of the produced water in these simulations represented a ‘base case’ (234mg/l TSS, 40ppm dispersed OIW). Fracture Description Fig. 17b shows a fracture of approximately 55m length formed over ten years of continuous injection at 350m3/day. This fracture remains contained within the depleted reservoir sandstone for about 82 months before eventually breaking out of the shale barrier at 1460m. However, actual injection into Zone C has been going on for only about 40 months. Fig. 17c shows that the resultant BHP for fractured injection is approximately equal to 240Bar, which corresponds to THP of 80Bar, in line with field observations. Fig. 17a shows how fracture width grows with time. The maximum fracture width after the ten-year injection period is about 120mm.
SPE 89376 5
By comparing the THP and Rate results from the simulation with those acquired in the field, it was observed that the Skin estimates using the Eq. 3 for pressure drop across Skin. µw= 0.5cp, kw= kkrw= 23md x 0.15= 3.45md hw= h x NG= 35m x 0.5 = 17.5m = 57.4ft ∆Pskin= BHPinjection – BHPsimulation = 350Bar–240Bar = 110Bar= 1595psi. q= 5 to 300m3/day = 62 – 1860bwpd. Bw= 1 By substituting the above parameters into Eq. 3, an estimate of Skin was determined to lie between 2.4 – 72. This range of damage agrees with the values estimated from Modified Hall technique earlier in this paper. Water Temperature Effect The sensitivity runs made with changing water temperatures show that the thermo-elastic effect due to changing water temperature is insignificant. Effect of Reservoir Compartmentalization The effect of reservoir compartmentalization was investigated using the in-house simulation package under a ‘No Flow Boundary’ assumption. Fig. 18 illustrates the result. From this result, it means that if the reservoir pressure were inflated from 80Bar to 180Bar would only increase the BHP/THP by 35Bar/30Bar, respectively. This change does not explain the reason for the excessive THP seen at the injectors. Therefore, it was agreed that the injectivity decline in all the five injectors could not be caused by pressure inflation in the reservoir. Effect of TSS & OIW Contamination The most important result of the fracture simulations is that in spite of the significant contamination of the injection water, it can be pumped away without any injectivity problems, even though poor water quality has the potential to jeopardize fracture containment in Zone C. Therefore, it was concluded that the recent injectivity problems in X-field cannot be primarily ascribed to impairment (plugging) of the fracture. Fig. 19 shows a sensitivity plot for varying TSS and OIW owing to injection of conventional silt/clay & oily water. Since the in-house simulation package only handles silt/clay particles with dispersed oil, usually quoted as TSS and OIW, it was concluded that the plugging agent is most likely different from conventional silt/clay particles & dispersed oil in water, which is the computer model consideration. Effect of Contamination on Fracture Containment Fig. 19 is a sensitivity plot of THP / Fracture Height vs. Time, that demonstrates the effect of water contaminants on fracture growth. The horizontal line intersecting the ordinate at 48m in the figure represents the top of the shale barrier above Zone C. From these curves it is clear that higher injection rate and TSS would yield bigger fracture size and consequently lower THP accounting for the higher fluid leak-off.
Injection water quality, though cleaner now, has been very poor in the past. It was noted from simulation that the worst-case scenario, shown as one of the curves in Fig. 19, indicate that 900ppm TSS and 900ppm OIW, together, can reduce the fracture breakout point to within 30 months. This implies that there is a possibility of fracture breakout in the field. The most important information deduced from the sensitivity runs is the importance of controlling produced water quality for fracture containment. It was found that by keeping the TSS & OIW below 100ppm and 40ppm, respectively, it is possible to prevent possible fracture breakout from the shale barrier into the overlaying Zone B reservoir. 7. Follow-up recommendations
• To address the root cause of the plugging by conduction a facility filter trial.
• To properly monitor the water quality (on-line monitoring of TSS and OIW).
• To perform a bailer run for wellbore evaluation for possible sand, scale or oil cake plugging and analysis collected samples.
• To clean all injectors and the waterlines purged prior to commissioning.
• A Step-Rate-Test and Fall-Off Test should be performed whenever an injector is placed online to further understand injectivity behavior and fracture growth.
• To limit the TSS to 100ppm in order to minimize the chance of fracture breakout into the upper Zone B.
8. Conclusions By modifying Hall analysis technique, it was possible to complete an evaluation of the Southern Oman field using historical field data and reservoir, well and fluid parameters. The study was completed within a reasonable scope of time and quite inexpensively.
The following remarks are the main conclusions from this work.
• Modified Hall analysis was useful in characterizing matrix, plugging matrix, initial fracture, plugging fracture, stimulation and fracture growth events.
• With the Modified Hall Plot technique, it was possible to quantify the extent of damage in most of the injection regimes.
• The Pressure-Rate Plot was useful in predicting the location of damage, either at wellbore or fracture, from which recommendations were made for well remediation
• There is a chance of early fracture breakout into the upper Zone B if a poorer water quality is injected.
• Modified Hall Plots showed that water injection is taking place under fracturing conditions, even at the poorest rates of injection.
6 SPE 89376
• The simulations also showed that injection of the very contaminated disposal water could not result in the extent of damage seen in the water injection wells.
• Injectors are plugged by unknown contaminants different from the traditional suspended solids and dispersed oil as modeled by the simulator.
• The computer simulation showed that the effect of reservoir pressure inflation, changes in water temperature and oil-in-water on fracture properties are negligible.
• The above conclusions led to a set of recommendations for an improved way of operating the disposal well. These recommendations also apply to new disposal wells that are currently being drilled.
• Facility filter trial was conducted in March 2003, as recommended, during which the filters clogged with slugs of Schmoo-like substance (FeS mixed in water) within 18 hours of operation. Fig. 20 is the picture of a sample of the Schmoo-like substance collected at the filter trial.
• The recommendations have been followed up, as a result of which all the wells have been in operation trouble-free over the last six months.
• The injectors’ performances are currently at an extra average of 150m3/day per well.
• Using the Modified Hall technique, the extent of damage was estimated for all injectors.
• Skin estimates obtained by comparing the simulation result to the five injectors led to the conclusion that X4, X2, X3 and X5 have poor injectivity in an increasing order of severity.
• Most of the plugging in X3 seem to concentrate at the fracture, while X2 and X4 are likely plugging at both wellbore and fracture locations.
• X1 is currently performing as expected, although it was diagnosed as plugging in the fracture, which explains why acid stimulation technique proved effective in restoring injectivity back to normal.
• All the desired objectives of this study were inexpensively met using the new technique. Only well historical data and field data were used to perform all the analysis.
Acknowledgment The authors are grateful to Petroleum Development Oman and Shell International Exploration and Production B.V. for permission to publish this work.
Nomenclature B= Formation Volume Factor, dimensionless µ= Viscosity, cp kw= Permeability to water, millidarcy heff= Height, feet re= External drainage radius, feet rw= Wellbore radius, feet
pw= Wellbore pressure, psi pr= Reservoir pressure, psi pe= Average reservoir pressure, psi qw= Cumulative water injection volume, bbl S= Skin, dimensionless NG= Net to Gross Ratio, dimensionless t= Time, days. ∆Pskin= Pressure drop across Skin, psi. q= Water injection rate, bbl/day.
References 1. Hawe, D. Direct Approach Through Hall Plot Evaluation
Improves The Accuracy of Formation Damage Calculations and Eliminates Pressure Fall-Off Testing. SPE5989.
2. Van den Hoek, P.J., Matsuura, T., De Kroon, M. and Gheissary, G. 1999. Simulation of Produced Water Re-Injection Under Fracturing Conditions. SPEPF, August, 166-176.
3. Hall, H.N. How to analyze Waterflood Injection Well Performance. World oil, October 1963, pp 128-130.
4. Dake, L.P. Fundamentals of Reservoir Engineering. SPE Lib. Elsevier Science 1997.
5. Dake, L.P. The Practice of Reservoir Engineering. SPE Lib. Elsevier Science 1999.
6. Bohon, W.M., Blumer, Chan, A.F., Ly, K.T. D.J. Novel Chemical Dispersant for Removal of Organic/Inorganic “SCHMOO” Scale in Produced Water Injection Systems. NACE International, Paper No. 73, 1998.
7. Van den Hoek, P.J., Khatib, Z.I. Causes of Injectivity Problems During Fractured Water Disposal And Their Remediation. SPE 74416. February 2002.
8. Koning, E.J.L., 1988. Waterflooding under fracturing conditions. Ph. D. Thesis, Technical University of Delft.
9. Settari, A, 1980. Simulation of hydraulic fracturing processes, SPEJ, December, 487-500.
10. Gheissary, G., Fokker, P.A., Egberts, P.J.P., Floris, F.J.T., Sommerauer, G., and Kenter, C.J. 1998. Simulation of Fractures Induced by Produced Water Re-Injection in a Multi-Layer Reservoir. SPE 54735, SPE/ISRM Eurock ’98, Trondheim, Norway, 8–10 July 1998
11. Van den Hoek, P.J. 1993. New 3D model for optimised design of hydraulic fractures and simulation of drill-cuttings reinjection. SPE 26679, 1993 Offshore European Conference, Aberdeen.
Unit Conversions 1Bar = 14.5037738psi 1bbl = 0.1589873m3
1m = 3.2808399ft 1KPa = 0.145psi 1md = 10-15m2
1Bar = 10-2Kpa 1m3/day = 6.28981bbl/day
SPE 89376 7
Figure 1a. Injector Performance
X1
0 50
100 150 200 250 300 350 400 450 500
01/01/02 01/03/02 01/05/02 01/07/02 01/10/02 01/12/02 01/02/03 01/04/03 Date
Rate m3/d
BJ-02 Poor BJ-02 Good
X2
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BJ-25
Figure 1b. Injector Performance
X4
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Figure 2. X-Field Historical Pressure & Production Trend
Southern Oman Field - Zone A
0
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Nov-84 Mar-86 Aug-87 Dec-88 May-90 Sep-91 Jan-93 Jun-94 Oct-95 Mar-97 Jul-98 Dec-99 Apr-01 Sep-02 Jan-04
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sure
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)
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Start of produced water Injection with X1, X2
Injectivity Decline
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X3,X4 & X5 i j t
8 SPE 89376
Figure 3. Production Facility And Water Quality Mapping
Fig. 5. Hall Plot
Fig. 6. Pressure –Rate Plot
Fig. 4. X-Field Well-Well Correlation
Field X
Field Y
X Injectors
Production Flow Station
Field X Production Station
6", PE lined C S, 13km
12", G RE DP=23barg, 55
X-1, 2, 3, 4, 5
reservoirs
?
TSS= 234 ppm (jan. 2003) OIW = 40 – 200ppm X2 W ell Data
470 m g/l - 613 m g/l
131 m g/l - 785 m g/l Zone C Zone B Shale
FPP
Botto
mho
le P
ress
ure
Injection Rate
Gradual Plugging
Sudden Plugging
Matrix Injection
Fractured Injection
SPE 89376 9
Fig. 7. Pre-Stimulation Hall Plot for X1 Well
Fig. 8. Post-Stimulation Hall Plot for X1 Well
Fig. 9. Pre-Stimulation Pressure-Rate
Fig. 10. Post-Stimulation Pressure-Ra
for X1 Well
Fig. 11. Hall Plot for X4 Well
j
Fracture Slope,y = 7.9065x
Plugged Fracture Slope,y = 25.335x - 112328
0.00
200000.00
400000.00
600000.00
800000.00
1000000.00
1200000.00
1400000.00
1600000.00
1800000.00
2000000.00
0 10000 20000 30000 40000 50000 60000 70000 80000 90000Cumulative Water Injection (m3)
Inte
gral
(BH
P-Pi
)dt (
ps.ft
)
0
200
400
600
800
1000
1200
Rat
e m
3/d,
TH
P B
ar
SumD(BHP-Pi)xdt Series5 Series4Rate THPLinear (Series4) Linear
Fracture Skin, S= - 3.9 Plugged Fracture Skin, S= 8
Fractured injectionmatches PWRI-frac simulation result
Severe plugging occurs.Injection rate remains same at higher pressure.
Kh=250mdft. Small Fracture iniated
Matr
Fig. 12. Pressure-Rate Plot for X4 Well
ix Slope y = 55.051xFracture S lo pe y = 9.7131x + 40504
0
500000
1000000
1500000
2000000
2500000
0 5000 10000 15000 20000 25000
Cum ulative W ater Injection, m 3
Inte
gral
(BH
P-Pr
) dt,
psi.
day
0
50
100
150
200
250
Rat
e, m
3/d;
Pre
ssur
e, b
ar
DelPdt THP Rate Linear (DelPdt) Linear
Rapid plugging followed by possible stim ulation/fracture growth
Gradual plugging
Severe plugging prior to rem ediation
Frac ture Initiation PointS= -3.9
Initia l M atrix Skin= 27
Fracture Skin at 130m 3/d= -3.9
Matrix Slope, S=27
W ell improvement by stimulation or fracture growth
Hall
a
b Rate
BHP
P
Fracture Slope y = 6.8899x
0
50000
100000
150000
200000
250000
300000
350000
400000
0 10000 20000 30000 40000 500Cumulative Water Injection m3
Inte
gral
(D
P*dt
), ps
i.day
500
600No Matrix InjectionFracture Skin at 380m3/d = - 5
THP
Water I
Fracturing injection with minimal plugging
B H P V s R a te fo r H J -2 0
4 00 00
0
5000
10000
15000
20000
25000
30000
35000
40000
0 50 100 150Injection Rate m3/d
BH
P K
Pa
Near-wellbore plugging suspected
0
5000
10000
15000
20000
25000
30000
0 100 200 300 400Injection Rate m3/d
BH
P K
Pa
Minimal Plugging
Hall
300
tion
Rat
e (m
3/d)
Or Pre
ssur
e (B
ar
400 )
njecti
2 50 00
3 00 00
3 50 00
KPa
B H P K P aS er ies 2
8 O c to be r 2 00 2 to 22 O c to be r 20 02C um ula tive In jec tion = 49 ,22 5 m 3
e
Rat0
100
200
Wat
er In
jec
Tubi
ng H
ead
5 00 0
1 00 00
1 50 00
2 00 00
BH
P
L ine ar (S eries2 )L ine ar
4 Ju ly 2 00 2 to 5 Ju ly 20 02C um ula tive In jec tion = 2 ,1 56 m 3
e
P
BHPl
te
00
200
5
Rat
on Rate
Hall
ot for X1 Well
Plot
Fig. 13. Simulation Output for B for X4 Well
Fig. 14. Hall Plot for X3 Well
60000-100
00 1 00 2 00 3 00
In je ctio n R a te m 3/d
250
BHP KPa
Hall Plot for B
Matrix Slope, y = 86.827x
0.00
200000.00
400000.00
600000.00
800000.00
1000000.00
1200000.00
1400000.00
1600000.00
1800000.00
2000000.00
0 10000 20000 300
Cumulative Wate
Inte
gral
(BH
P-Pi
)dt (
psi.f
t)
SumD(BHP-Pi)xdt
Sudden fracture initiation
Initial Matrix Skin, S= 31
Fracture Skin at 200m3/d, S= - 7
Possible matrix injection of relatively low kh
Stimulation Or fracture propagation
Improvement made possible by either stimulation or fracture growth
Graduexten
fracture plugging
Severe plugging occurs
00 600
BHP KPa
Hall
HP, THP & R
4 00 5 00
J 25
00 40000
r Injection (m3)
Rate TH
al but consistent plugging ds for long duration
Reducedpressure
Stimulation Or fracture propagation
e
BH
Rateate vs. Time
6 00
600
700
800P Linear (
Severe plugging
Hall300
400
500
Rat
e m
3/d,
TH
P B
ar rate due to drop
P
BH RatFracture Slope,y = 2.6356x + 216436
50000 600000
100
200
10 SPE 89376
Fig. 15. Pressure-Rate Plot for X3 Well
Fig. 16. Matrix Solid Loading vs. Injector Half-Life
Fig. 17. Fracture Simulation Using 234ppm TSS and 40ppm OIW at 350m3/day
0
5000
10000
15000
20000
25000
30000
35000
40000
0 100 200 300 400 500 600 700 800Water Injection Rate m3/d
BH
P K
Pa
BHP
Fracture face plugging Suspected
a. Fracture Width Contours
b. Fracture Length Contours
c. BHP & THP vs Time Plot
Fig. 18. Effect of Compartmentalization on Fracture Properties a. Pressure Vs Time Plot
b. Depth, Time Vs Fracture Length Plot
SPE 89376 11
Fig. 19. Effect of Varying TSS & OIW on THP And Fracture growth
0
2
4
6
8
10
12
-10 10 30 50 70 90 110 130 150
Time (Months)
Wel
lHea
d Pr
essu
re (M
Pa)
0
10
20
30
40
50
60
70
80
90
100
Frac
ture
Hie
ght U
p (m
)
BestCase_R-350_T-100_O-40
BASECase_R-350_T-234_O-40
R-350_T-234_O-500
R-350_T-500_O-40
WorstCase_R-350_T-900_O-900
BestCase_R-350_T-100_O-40
BASECase_R-350_T-234_O-40
R-350_T-234_O-500
R-350_T-500_O-40
WorstCase_R-350_T-900_O-900
UPPER GHARIF BOUNDARYLIMIT
Frac
ture
Hei
ght
W
ellh
ead
Pres
sure
Fig. 20. A Picture of Schmoo-like Substance (FeS) Sampled During Trial
