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1 SPE Injectivity of Frac-Packed Wells: A Case Study of the Guando Field A. Suri, SPE, and M.M. Sharma, SPE, U. T. Austin, J.M.M. Moreno, SPE, Petrobras Colombia Ltd. Copyright 2010, Society of Petroleum Engineers This paper was prepared for presentation at the 2010 SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, USA, February This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The Guando field in Colombia, South America, is a sandstone reservoir with an initial pressure about 150 psi at GOC. A waterflood has been implemented since early in the life of the field. A complete set of data has been maintained on each of the injectors since This data set includes: daily injection rates, pressures, water quality and solids analysis. Injection into four different hydraulically fractured reservoir units is controlled by down-hole valves. In some cases wells are operated at injection pressures above the fracture gradient. To ensure good reservoir sweep efficiency, waterflood control and assurance of injectivity for each reservoir unit a detailed study of the injectivity of each injector was undertaken to understand the possible growth of fractures and its impact on fracpack injectivity, injection profile and oil recovery. Field data indicates that the quality of river and produced water streams, mechanical configuration, stimulation of injector wells and injection facilities are important parameters that control the injectivity behavior. Injection well simulations are presented to show that the injectivity behavior can be history matched quite well and this process provides valuable insight into the dependence of injection parameters such as injection rate and water quality on injection profiles and fracture growth. This paper presents data and history match simulations for seven injectors from the field. The results allow us to estimate the fracture lengths that are created in the injectors and to thereby evaluate the effectiveness of injection schemes being implemented. This history match study allowed us to make recommendations for future injection rates and water quality into each of the injectors. To the best of our knowledge this is the first time that the injectivity of multi-layered, frac-packed injectors has been history matched with field data over an extended period of time. These history matched results validate our injection well model for frac-packed injectors and provide important guidance on future injection well design in addition to making concrete recommendations for the Guando field. Introduction Completions in injectors that are completed in poorly consolidated sands must ensure that water injection can be continued for extended periods of time without sand failure. This usually means that a choice must be made between frac-packing the well, cased-hole gravel packing it or running sand control screens. There is very limited systematic well data available for the long term performace of these sand control options in injectors. This paper presents the results of such a data set together with a simulation study to understand the reasons for the injectivity behavior observed in some of these injectors. Sharma et al. (1999) reported on injection into a set of five injectors in the Gulf of Mexico. These injectors were completed with cased-hole gravel packs and sea-water was injected. The injection water quality was carefully monitored and despite excellent water quality, severe declines in injectivity were observed in all the injectors when the injection pressure was maintained constant and below the fracture gradient. This study clearly demonstrated that the use of gravel pack completions results in rather short injector half-lives even though the injection water quality was good. McCarty et al. (2006) utilized frac-packed completions for water injectors in sand control environments and observed no sand control failure over more than five years of injection with most injectors showing good injectivity for at least 5 years. Around the world, injectors are fractured to: 1) meet sand control requirements, and 2) improve injectivity compared to gravel-pack, cased-hole perforated completions. The additional expense of using a frac-pack completion is easily justified if the injectivity remains high over long periods of time. This study presents field data that demonstrates that frac-pack completions can, in some cases, help to maintain injectivity over long periods of time. However, there are some instances

2 2 SPE 125 where this may not be the case. Suri and Sharma (2008) developed a model for estimating the injectivity of frac-packed injectors over long periods of water injection. They showed that the plugging of the frac-pack by the injected solids plays an important role in the injectivity decline. In the present study, field data from the Guando field is analyzed for 7 injectors that typify the behavior of other injectors in the field. The injectivity decline over a seven year period is analyzed and the results are interpreted in terms of the likely mechanisms of injectivity decline. It is shown that widely different injectivity behavior is observed in the wells depending on the specific injection conditions. The Guando Field The Guando field is a major oil field in Columbia that was discovered in February It is located 70 miles southwest of Bogota, near Melgar-Tolima, in a mountaineous area 4,100 ft above sea level. Geologically it is termed as Cretaceous lower Guadalupe sandstone at a depth between 2,800 and 4,000 feet below surface and roughly 1800 ft above sea level. Valbuena Amaris et al. (2005) and Valbuena Amaris et al. (2009) have presented a detailed description of the Guando full field development plan, along with the approach to develop the low underpressured Guando field. Ariza et al. (2006) have described the artifical lift systems (PCP) used in Guando field production optimization. The most recent statistics on the Guando field are as follows: 1. Total oil production till date: MBO 2. Current total oil production rate: BOPD 3. Total water injected till date: MBW 4. Current total water injection rate: 102,000 BWPD The reservoir is relatively thick, with an average gross sand thickness of 670 feet. The sands are highly porous and permeable with an average porosity of 18% and permeability ranging from 1 to 1000 md. The oil is medium light with an API gravity of 27 o 31 o (0.89 g/cc). The reservoir has six major zones/layers named ARIN 1 ARIN 6 (shown in Figure 1) with ARIN 3 and ARIN 4 being the major oil producing zones. Reservoir pressures are low (100 to 400 psi) with an oil viscosity of 7 cp; therefore, waterflooding has been implemented as an enhanced oil recovery method, with a 2:1 injection-production ratio. Almost all wells (producers and injectors) were fractured to bypass the formation damage caused by overbalance drilling (1000 psi over average reservoir pressure of 300 psi). A seven spot well pattern with injection well in the center as well as the upstructure periphery is developed for water injection and the well spacing is reduced to 145 m. The end point mobility ratio (injection water mobility divided by oil mobility) is 1.15 which is close to favorable (<1). Within four months of pilot injection start-up, clear response was observed in the offset producers as evidenced by a GOR decrease followed by a steady increase in oil production. The water injection facility capacity was upgraded to 65,000 BWPD with maximum water injection pressure at the topside equal to 2200 psi. The water injection simulations show that the primary oil recovery of 11 % can be increased to 30 % by water injection. Guando field injectors were fractured to bypass the drilling damage so as to have a reasonably high initial injectivity. However most Guando injectors started to have injectivity decline and therefore a study was done to quantify the cause and its remediation. Figure 1: Guando field reservoir zonation.

3 SPE Injectivity Model for Fractured Wells A model for injectivity decline in water injection wells has been developed in the past at the University of Texas at Austin (Ref. 3, 4). The model was recently extended to frac-packed injectors (Ref. 5). Some of the important features of the injection well model are: 1. The oil is displaced by the injected water as a piston, i.e. sharp saturation change from water to oil at the front location. The reservoir is divided into horizontal layers of constant thickness. 2. Filtration of solids in the injection water result in plugging of both the frac-pack and the rock matrix resulting in a decline in the injectivity. A filtration model originally developed by Rajagopalan and Tien (1976) with minor modifications at high velocities is applied to calculate the particle deposition rate in the fracture and the formation from the fines in the injection water. A model for reduction in formation permeability due to particle deposition and consequently development of a filter cake and further growth of the initial injection well fracture was used to calculate the change in injectivity with time (Saripalli et al. (1999)). 3. The fractures are constant height equal to the layer height and grow only laterally. These fracture result in an elliptical waterflood front and the axes of the growing ellipse are confocal to the fracture tips as the two foci. The pressure drop in different regions of the reservoir was computed and the dimensions of the ellipses were used to estimate the thermal stresses and the resulting change in injectivity. 4. Particle plugging is assumed to be uniform in the fracture. 5. Fracture growth, changes in fluid mobility and permeability changes in the fracture and the formation matrix are the primary factors controlling the well injectivity. 6. The increase in pore pressure due to water injection is accounted for adjusting the minimum horizontal stress. Sharma et al. (2000) have used this model in the past to history match five injectors in the Gulf of Mexico to match declining injectivity. However they only matched the injectivity of the wells and did not present the fracture growth in these injectors. A comprehensive model for water injection into frac-packed injectors is further developed by Suri et al (2007) with non-uniform deposition of particles in the frac-pack and non-uniform leak-off of the injected water into the formation from the frac-pack. Simulation of Frac-Packed Injectors Seven injectors completed in the ARIN-3 and ARIN-4 oil bearing zones were chosen for this study. The important data for each injector, zone depth, thickness, porosity, permeability, pore pressure, E, ν, and σ hmin are shown in Table 1. Four injectors are completed in the ARIN-3 zone, 2 injectors in the ARIN-4 zone and 1 injector is completed in both the ARIN-3 and ARIN-4. Our objective was to use the actual measured surface water injection rate into these injectors with a known range of water quality and to compare the calculated BHP with the field observed BHP (estimated from the measured THP). The computed and actual injectivity of these injectors is also compared over the period of injection. Table 1 lists the important parameters needed to conduct the simulation. These were estimated from logs, core tests and stress tests conducted in some of the injectors. Details of these tests are not provided in this paper. Table 1: Layer and rock mechanical properties for the seven history matched injectors. Pore Well Sand Depth TVD (ft) Thick ness (ft) Av. Perm (md) Av. Poros ity pressure (psi), Drainage boundary (ft) E (Mpsi) ν (Poisso n's ratio) Min. horizontal stress grad. (psi/ft) σ hmin (psi) WELL-1 Arin , , 2553 WELL-2 Arin , , 3653 WELL-3 Arin , , 2956 WELL-4 Arin , , 2926 WELL-5 Arin , , 2825 WELL-6 Arin , , 2339 Arin , , 2294 WELL-7 Arin , , 1375 All these injectors were hydraulically fractured before the start of water injection. From the total volume of proppants pumped, initial fracture length estimates in these seven injectors were calculated as shown in Table 2. An average width of 0.5 inches, a proppant density of 165 lbs/ft 3, a fracture porosity of 0.35, and a fracture height equal to the layer height was assumed in calculating the length of the hydraulic fracture. Table 2 also shows the initial skin due to these initial hydraulic fractures. Skin due to drilling and fracturing were assumed and were tuned to obtain the best simulation fits that matched the field data. In injectors (WELL-4, WELL-5, and WELL-7) skin due to drilling and fracturing were assumed to be zero to get the best match to the initial injectivity. Efforts to match simulation results with field data suggested that two injectors

4 4 SPE 125 (WELL-2 and WELL-3) had a net positive skin even after hydraulic fracturing. The second parameter that was used in the history matching was the injected solids concentration. For these two wells an injected particle concentration of over 100 ppm was used, as opposed to typical values of about 50 ppm measured by the daily water sampling program in the field. Well name Table 2: Calculated hydraulic fracture length prior to water injection with initial skin and water quality for the seven injectors. Sand Wt. of proppants (lbs) Vol. of proppants (ft 3 ) Height of fracture (ft) Estimated fracture length (ft) Initial Skin for Ideal Fracture Skin due to drilling & fracturing Initial net skin Assumed solids conc. (ppm) WELL-1 ARIN WELL-2 ARIN WELL-3 ARIN WELL-4 ARIN WELL-5 ARIN WELL-6 ARIN ARIN WELL-7 ARIN Because the actual initial fracture length has the largest impact on BHP and injectivity, it was necessary to tune this parameter guided by the estimated fracture length as a reference parameter. Table 3 shows the assumed initial hydraulic fracture length, initial net skin and water quality that gave the best history match with the field data. Table 3: Fracture length and water quality obtained from a history match of field data. Initial fracpack length before water injection (ft) Initial Skin for Ideal Fracture Skin due to drilling & fracturing Initial net skin Assumed water quality (ppm of solids) Well name Sand WELL-1 ARIN WELL-2 ARIN WELL-3 ARIN WELL-4 ARIN WELL-5 ARIN ARIN WELL-6 ARIN WELL-7 ARIN The field measured daily injection rate was input to the injection well simulator (UTWID-7.1) developed at the University of Texas at Austin (Saripalli et al. (1999), Sharma et al. (2000)). The simulator allowed us to capture all of the variations in the injection rates, shut-downs and restarts. Pressure transient effects associated with shutdowns and restarts are modeled in this work but are not obvious at the time scales discussed in this paper. Results and Discussion Figures 2 to 22 present simulation results compared against field data for the seven injectors. Input parameters that were common to all the injectors and used in the simulations are listed in Table 4. Simulation results generated for two sets of inputs with two different initial fracture lengths; well skin and injection water quality (shown in Tables 2 and 3) are discussed next for each of the seven injectors. Table 4: Input parameters common between the 7 injectors. r w 3.5 inch S wi 0.3 dp 5 micron S or 0.3 T R 90 o F o k rw 0.07 T w 90 o F o k ro 0.6 φ fp 0.35 c f 1.2 E-6 1/psi φ c 0.2 c gr 0.15 E-6 1/psi

5 SPE ρ p 2.65 g/cc c o 5 E-6 1/psi ρ w 1 g/cc c w 2.6 E-6 1/psi μ w 0.76 cp μ o 7.5 cp Injector 1: WELL-1 WELL-1 injector is completed in ARIN-3 with a TVD of 2300 ft and a sand thickness of 146 ft (Table 1). Injection was started on Sept with rates shown in Figure 2. These injection rates were input to UTWID 7.0, our injection well simulator and the simulated BHP and injectivity were obtained and compared against the field data as shown in Figure 2. Figure 2: Injection rates, BHP (field and simulated) for WELL-1. Results of two simulation cases are presented: (a) An initial fracture length of 119 ft, calculated from vol. of proppants pumped, skin = -1 and 30 ppm injection solids and (b) A short initial fracture length of 10 ft, skin = -2.8 and 30 ppm injection solids. The field BHP gradually increased in a few months to 3100 psi and remained constant (Figure 2). Note that the field BHP is ovelain by simulated BHP s (in the plot). The simulated BHP with the assumed longer fracture length (119 ft) did not match the field data very well. The simulations with the smaller initial fracture length of 10 ft matched the field data best. With this smaller fracture length, the BHP rose above the fracture propagation pressure very early and even at low rates the simulated BHP was nearly constant at 3100 psi. The injectivity data also matched better with the smaller initial fracture length (Figure 3). We, therefore, conclude that the frac-pack in place was short and that fracture extension (both length and width growth) occured as water was injected into the well. An estimate of the fracture length with time as obtained from simulations for the two initial fracture lengths is shown on the right side of Figure 3. At a bottom-hole pressure in excess of 3,100 psi, fracture growth occurs and that this results in a constant injectivity and relatively constant BHPs. This corresponds roughly to the minimum horizontal stress in the ARIN-3 zone in this well (2553 psi). Note that the min. horizontal stress increased from the initial 2553 psi because of an increase in pore pressure. Figure 3: Injectivity (field and simulated) and fracture length predictions from simulations for WELL-1.

6 6 SPE 125 Figure 4 shows a cross-plot (BHP vs. injection rate) for the field and two simulations. The cross-plot shows a satisfactory match between the field data and the simulation with a short initial fracture length of 10 ft. This further points to our conclusion that the initial fracture in WELL-1 was short and close to 10 ft. The growth of the fracture is intimately tied to the water quality. With the water quality measured in the field (used as an input), it is seen that the fractures do not grow beyond about 25 feet in length (at field injection rates). With the estimated frac-pack dimensions and the history match obtained, it is now possible to conduct what-if simulations to explore the impact of water quality. For example if produced water were to be injected into the well, the impact of it on the injectivity and fracture growth can be estimated and decisions can be made early in the phase of the life of this injector. Figure 4: BHP vs. injection rate plot for WELL-1. Injector 2: WELL-2 This well is also completed in the ARIN-3 but is 1200 ft deeper that WELL-1 with a TVD 3512 ft. It, therefore, has a much higher minimum horizontal stress. The injection was started on March with rates and BHP (field data and two simulations) are shown in Figure 5. The injection rate in this well started at around 1000 BWPD and declined to less than 50 BWPD in 4 years. The injectivity behavior observed in this well is quite different than that observed in the previous well. A very severe decline in injectivity from 0.45 bbl/day/psi to 0.01 bbl/day /psi (a 50 fold decline) is observed. For this well, just as in the previous case, two simulation runs are presented here: a) An initial fracture length of 56 ft calculated from vol. of proppants pumped, skin = 1 and 700 ppm solids in the injected water; and b) a small initial fracture of 3 ft, skin = 1. The two simulation results for the BHP in comparison to the field BHP are shown in Figure 5. Both simulated BHP s matched reasonably well with the field BHP for this injector with fluctuations in the simulated BHP s. Moreover the solids concentration was increased from 50 ppm (believed upper limit) to 700 ppm and 100 ppm to match closely with the field data. Figure 5: Injection rates, BHP (field and simulated) for WELL-2.

7 SPE We believe that the BHP in this well did not go much above the minimum horizontal stress of 3653 psi (higher stress in the layers) and, therefore, the injectivity of this well kept declining. The higher stress in this well led to minimal fracture growth (right side of Figure 6) even with the 3 ft initial fracture. The continuous plugging of the frac-pack by the injected solids resulted in a significant reduction in the injectivity since there was no additional frac-pack growth. This is consistent with the simulation results and clearly explains what needs to be done if incremental injectivity is needed. Increasing the BHP above psi (with higher THP and pump pressure) would result in an increase in injectivity as the fracture will then begin to propagate. Figure 6: Injectivity (field and simulated) and fracture length predictions from simulations for WELL-2. Figure 7 shows the cross-plot (BHP vs. injection rate) for the field and two simulations. The cross-plot shows a satisfactory match between the field data and the simulation with a better match for the longer initial fracture length of 56 ft. Figure 7: BHP vs. injection rate plot for WELL-2. Injector 3: WELL-3 This injector is also nearly as deep as WELL-2 with TVD 3478 ft and has a higher minimum horizontal stress. Injection was started on March with an average of 700 BWPD. The injection rates were increased up to 1400 BWPD at 2 months but then the injection rates kept declining and reached an average of 25 BWPD in 3 years. This injectivity decline behavior is similar to WELL-2 and is attributed to the high minimum horizontal stress in this well. For this well, as in the previous cases, two simulation cases are presented: a) an initial fracture length of 36 ft from vol. of proppants pumped, s=1 and 250 ppm solids; and b) a small initial fracture of 10 ft, s=-2 and 100 ppm of solids. The two simulation results for the BHP in comparison to the field BHP are shown in Figure 8. Both simulated BHP s matched well with the field BHP for this injector with fluctuations in the simulated BHP s related to changing injection rates similar to WELL-2 simulations. The solids concentration for this well was also assumed higher than 50 ppm in the two simulations to match closely with the field data.

8 8 SPE 125 Figure 8: Injection rates, BHP (field and simulated) for WELL-3. The injectivity comparison between field data and the two simulations is shown in Figure 9. The BHP in this well similar to WELL-2 did not go much above the minimum horizontal stress of 2956 psi (high stress injector) and, therefore, the injectivity of this well kept declining. The higher stress in this well did not lead to much fracture growth (right side of Figure 9). The continuous plugging of the frac-pack by the injected solids resulted in a significant reduction in the injectivity due to no additional frac-pack growth. Increasing the BHP much above the min. horizontal stress (with higher THP and pump pressure) would result in an increase in injectivity as the fracture will then begin to propagate. Figure 9: Injectivity (field and simulated) and fracture length predictions from simulations for WELL-3. Figure 10: BHP vs. injection rate plot for WELL-3.

9 SPE Figure 10 shows the cross-plot (BHP vs. injection rate) for the field data and two simulations. The cross-plot shows a satisfactory match between the field data and the simulation with a better match for the longer initial fracture length of 36 ft. Injector 4: WELL-4 This well was slightly shallower than the previous well WELL-3 with a TVD of 3251 ft and has a relatively smaller minimum horizontal stress. Injection was started on March with an average of 700 BWPD. The injection rates were increased and have remained nearly constant with an average of 3000 BWPD over 3 years. This relatively constant injectivity behavior is similar to the first well WELL-1 and is attributed to the BHP going above the minimum horizontal stress. For this well, just one simulation was conducted with an initial fracture length of 33 ft calculated from the volume of proppants pumped, and 50 ppm solids in the injected water. The simulated BHP in comparison to the field BHP is shown in Figure 11. The simulated BHP matched very well with the field BHP for this injector. The solids concentration for this well was also with in the field measured range of 50 ppm. The injectivity comparison between field and the simulation is shown in Figure 12. The data clearly suggests that the BHP in this well went above the minimum horizontal stress resulting in a constant injectivity for this well. Figure 11: Injection rates, BHP (field and simulated) for WELL-4. Figure 12: Injectivity (field and simulated) and fracture length predictions from simulations for WELL-4. Figure 13 shows the cross-plot (BHP vs. injection rate) for the field and the simulation. The cross-plot shows a satisfactory match between the field data and the simulation.

10 10 SPE 125 Figure 13: BHP vs. injection rate plot for WELL-4. Injector 5: WELL-5 This well was the deepest well studied with a TVD 3669 ft. However, due to a lower stress gradient it had a relatively small minimum horizontal stress. Injection was started on March with an average injection rate of 700 BWPD and the rates were increased to an an average of 3000 BWPD in 3 years (left side of Figure 14). This injector had a relatively constant BHP and injectivity, a behavior similar to the first well WELL-1 and is attributed to BHP going above the minimum horizontal stress which led to fracture extension. The two simulations that were conducted were: a) an initial fracture length of 39 ft calculated from vol. of proppants pumped, s=-3.73 and 15 ppm solids in the injected water; and b) a smaller initial fracture of 30 ft, s=-3.5 and 30 ppm injection solids. The two simulation results for the BHP in comparison to the field BHP are shown in Figure 14. Both simulated BHP s matched well with the field BHP. The solids concentration for this well was also under the field measured solids concentration of 50 ppm. Figure 14: Injection rates, BHP (field and simulated) for WELL-5. The injectivity from the field data and the simulations is shown in Figure 15. Reasonable agreement is observed between the data and the two simulation cases. We believe that the BHP in this well went above the minimum horizontal stress as indicated by the plot on the right side of Figure 15 with fracture lengths higher than the initial and therefore the injectivity of this well remained constant as the injected solids were accommodated by the extended fracture.

11 SPE Figure 15: Injectivity (field and simulated) and fracture length predictions from simulations for WELL-5. Figure 16 shows the cross-plot (BHP vs. injection rate) for the field and the simulation. The cross-plot shows a satisfactory match between the field data and the simulation. Above a certain injection rate the BHP became constant even with increasing injection rates because of fracture extension with BHP roughly equal to min. horizontal stress. Figure 16: BHP vs. injection rate plot for WELL-5. Injector 6: WELL-6 This well was completed both in ARIN-3 and ARIN-4 at TVD s 3204 ft and 3476 ft and water was injected in both the zones with one through tubing and the other through annulas. It is a relatively deep well but due to low stress gradient the two zones minimum horizontal stresses are much smaller than most of the other wells. The injection was started on July with 100 BWPD into ARIN-3 and 300 BWPD into ARIN-4. The injection rates were gradually increased in both the zones as shown in the left plot of Figure 17. ARIN-4 kh product (permeability x thickness) is nearly 2.5 of ARIN-3 kh product (Table 1) and therefore the injection rate in ARIN-4 was nearly 2.5 times higher. The individual injection rates into the zones were fed independently to UTWID and the corresponding BHP s were obtained for the two zones. Similar to the previous injectors, two sets of simulations were conducted with two initial fracture lengths. The two simulations were: a) an initial fracture length of 46 ft in ARIN-3 and 31 ft in ARIN-4 calculated from vol. of proppants pumped, skin = in ARIN-3 and skin = -3 in ARIN-4 and 20 ppm solids in the injected water; and b) a smaller initial fracture of 10 ft in ARIN-3 and 31 ft in ARIN-4, skin = in ARIN-3 and skin = -1.8 in ARIN-4 and 20 ppm solids in the injected water. The first set of simulations with longer fracture length in ARIN-3 did not match the field BHP in the two zones as shown in the right side plot of Figure 17. However, the second set of simulations with smaller initial fracture length in ARIN-3 resulted in a simulated BHP to match well with the field BHP as shown in the left side of Figure 18...

12 12 SPE 125 Figure 17: Injection rates, BHP (field and simulated) for WELL-6. Figure 18: BHP, Injectivity (field and simulated) and fracture length predictions from simulations for WELL-6. The corresponding simulated injectivities for the two zones compared against the field injectivities for the two zones with smaller initial fracture length are shown in Figure 18 right and Figure 19 left. The two zones simulated injectivities matched well with the field injectivities. The BHP and injectivities were fairly constant with ARIN-4 injectivity close to 1 bpd/psi and ARIN-3 injectivity close to 0.4 bpd/psi (note again that ARIN-3 kh product is 0.4 times of ARIN-4 kh product). The fracture length estimated in the two zones from the simulations is shown in the right side plot of Figure 19. Figure 19: Injectivity (field and simulated) and fracture length predictions from simulations for WELL-6.

13 SPE Injector 7: WELL-7 This well was shallow with TVD 2500 ft and has the lowest stress gradient with smallest minimum horizontal stress amongst the 7 injectors. The injection was started on February with an average of 1000 BWPD with rates increased to 2000 BWPD. Recently the injection rates in this injector have been increased to 4000 BWPD (left side of Figure 14). The two simulations that were conducted were: a) an initial fracture length of 25 ft calculated from vol. of proppants pumped, skin = and 20 ppm solids in the injected water; and b) a smaller initial fracture of 10 ft, skin = -2.8 and 20 ppm solids. The simulation results for the BHP in comparison to the field BHP are shown in right side plot of Figure 20. Both simulated BHP s matched well with the field BHP. Due to very low min. horizontal stress of only 1375 psi, the fractures were propagated with increasing injection rates while the BHP remained nearly constant around 2000 psi. A relatively constant BHP and constant injectivity is observed in this well and is attributed to BHP going above the minimum horizontal stress which led to fracture extension. Figure 20: Injection rates, BHP (field and simulated) for WELL-7. The injectivity comparison between the field and the simulations are shown in left side plot of Figure 21. The BHP in this well went above the minimum horizontal stress and caused the initial fracture to extend as shown by the simulations in the plot on the right side of Figure 21 with fracture lengths higher than the initial. The injectivity of this well remained fairly constant at 1 bpd/psi for initial few years but then increased to 2 bpd/psi as the injection rates were doubled. Figure 22 shows the cross-plot (BHP vs. injection rate) for the field and the two simulations. The cross-plot shows a satisfactory match between the field data and the simulation. Above a certain injection rate the BHP became constant even with increasing injection rates because of fracture extension with BHP roughly equal to min. horizontal stress. Figure 21: Injectivity (field and simulated) and fracture length predictions from simulations for WELL-7.

14 14 SPE 125 Figure 22: BHP vs. injection rate plot for WELL-7. Conclusions The injectivity behavior of frac-packed water injection wells in the Guando field were analyzed based on injection rates, bottom hole pressures and water quality recorded over a four year period. By history matching the field data additional insight into their behavior was obtained and recommendations were made for future injection plans. Some of the conclusions that were drawn from this study are as follows: 1. Two types of injectivity behavior are observed in the injection wells studied: a) in some injectors the injectivity remained fairly constant over long periods of injection; and b) in other injectors the injectivity declined by a factor of 50 over the same time period. 2. In injectors with higher in-situ stresses (WELL-2 and WELL-3) fracture extension did not occur which led to drastic injectivity decline (50 fold reduction). In these wells the BHP did not increase above the minimum horizontal stress and as a result the injectivity of these wells declined dramatically as the fracture and matrix were plugged by injected solids. 3. In injectors with lower in-situ stresses, the BHP went above the minimum horizontal stress and led to fracture extension and a fairly constant injectivity. 4. The extent of injectivity decline observed in the injectors depends on the difference in the initial BHP which determines the initial injectivity and the fracture propagation pressure which determines the long term injectivity. 5. Simulations conducted for the seven injectors matched the field data reasonably well. History matching the injectivity behavior required adjusting the initial skins, the fracture lengths and the water quality. These matches are not unique but when guided by estimates of these parameters from field measurements, they provide reliable indicators of what may be happening in each injector. 6. The simulations show that the induced fracture lengths are less than 100 ft in the 7 injectors. Minimal effect on the reservoir sweep efficiency is expected because of the growth of injection induced fracture lengths. Small fracture lengths are expected for all the injectors in Guando assuming they had similar injection rates and water quality. 7. Simulations can be conducted to reliably predict the performance of these injectors under future injection conditions (for example produced water injection). Ackowledgements The authors wish to thank to Petrobras and its contract partners Ecopetrol S. A and Nexen for the opportunity to be part of the Guando field development project and for grantining to present and publish this paper. The authors wish to thank to the UT team and its technical support. Nomenclature (All variables are in SI units) C Concentration of suspended particles C i Concentration of suspended particles at the injection well-formation face C d Volume of solids deposited per unit bulk volume of the porous medium C w Specific heat of water Diameter of suspended solids d p d f d g Diameter of formation grains Diameter of frac-pack gravels E Young's modulus of the formation h Formation thickness / layer thickness I Injectivity, q / (P wf - P R ) k fp Initial permeability of the frac-pack Initial permeability of the formation k h

15 SPE o k ro o k rw k c L f L fp P R P wf q r e r w R S or S wi t T i T R u End point relative permeability to oil End point relative perm. to water Permeability of external filter cake fracture length from wellbore to the tip Initial frac-pack length from wellbore to the tip Reservoir pressure at the drainage boundary (re) Bottom-hole pressure in the well Total fluid injection rate into the well Drainage radius Well radius Flow resistance, Δp/q Residual oil saturation Initial water saturation Time Injection fluid temperature Reservoir temperature Darcy velocity Greek symbols α Coefficient of thermal expansion β p φ φ c φ f φ fp λ μ w μ o ν ρ w ρ p ρ o ρ gr σ hmin ΔT Δσ T Δσ P Coefficient of pore pressure expansion Porosity External cake porosity Initial formation porosity Initial frac-pack porosity Filtration coefficient of the formation Viscosity of water Viscosity of oil Poisson's ratio Density of water Density of suspended solids in the injection water Density of reservoir oil Density of mineral grains Minimum horizontal stress Temperature difference between the injected fluid and the reservoir Decrease in stress due to thermoelastic stress perpendicular to the fracture Increase in stress due to poroelastic stress perpendicular to the fracture References 1. Ariza, H., Rojas, C., Rivera, V., Torres, F Decreasing Well Downtime in Guando Oil Field by Using Continuos Sucker Rod. Paper SPE presented at the SPE ATCE, San Antonio, Texas, U.S.A., September. 2. McCarty, R.A. et al The Resiliency of Frac-Packed Subsea Injection Wells. Paper SPE presented at the SPE ATCE, San Antonio, Texas, USA, September. 3. Rajgopalan, R., and Tien, C Trajectory Analysis of Deep-Bed Filtration with Sphere- in-cell Porous Media Model. AICHE Journal, Vol. 22, No Saripalli, K.P., et al Role of Fracture Face and Formation Plugging in Injection Well Fracturing and Injectivity Decline. Paper SPE presented at the SPE/EPA Exploration and Production Environmental Conference, Austin, February 28 March Sharma, M.M. et al Injectivity Decline in Water Injection Wells: An Offshore Gulf of Mexico Case Study. SPE Production & Facilities. February. 6. Suri, A., Sharma, M.M A Model for Water Injection into Frac-Packed Wells. Paper SPE presented at the SPE ATCE, Anaheim, California, U.S.A., November. 7. Valbuena Amaris O. H., De Freitas, L. C. S., Gomes, H. P., Pereira, J. R. B Guando Field: Underpressured-Field Development. Paper SPE presented at the SPE LACPEC, Rio de Janeiro, Brazil, June. 8. Valbuena Amaris O. H., Montoya Moreno, J. M., Duran B., Rovira, D. L Guando Field: Underpressured-Field, Part II Paper SPE presented at the SPE LACPEC, Cartagena, Colombia, 31 May 3 June.