Palabras clave/Keywords/Palabras-chave:

Flood, injection, injeção, inyección, mobilidade, mobility, movilidad, pilot, piloto, polímero, polymer, reservatórios, reservoir, yacimiento.

Problem Statement

Petrocedeño is a joint venture between PDVSA (60%), TOTAL (30.4%), and Equinor (Former Statoil with 9.6 %); it operates in the Zuata main field, which is located in the Orinoco Belt. The reservoir is an unconsolidated sandstone of Miocene age, from where oil of 8.5°API is being produced since 1999. The field has an area of 399 Km2, and more of 300 stratigraphic wells. At the moment, more than 711 producing wells have been drilled since the beginning of the exploitation of the field. After reach a plateau of production of 200,000 Bbl/d, efforts have been made to apply enhanced oil recovery technologies that could be an efficient solution to increase the recovery factor, and to revitalize the field. One of the possibilities is the polymer flooding technology. After performing the preliminary set of pre-project evaluations, and obtain promising results from laboratory analysis, it was decided to execute a pilot test in an area of the field, where conditions showed no interest of applying any thermal recovery technique. The reservoir pressure at the moment of project start up was 315 psia, the reservoir temperature 115.5 °F; average porosity of 0.32; the reservoir absolute permeability is estimated between 19 – 15 Darcy, and the reservoir thickness is 25'. The oil mobility is very low due to very high viscosity, estimated in 4150 cP according PVT data (reservoir conditions: 115.5 °F and 315 psia). The reservoir is one hydraulic unit given the results of salinity of produced water samples, and petrophysic correlation. In the year 2016, the pilot test started operations. Since then, polymer solution at a concentration between 900 ppm and 1,600 ppm was injected in the reservoir which is a deltaic sedimentary environment, composed by distributary channel fills and mouth bars. Four rocks types were indentified using petrophysic concepts, being that the predominant rock type has an average permeability of 15 Darcy, and a water saturation of 6% (porosity was stablished in 0.32). The polymer flooding is injected through three injectors wells (Well AA06, AA07, AA08) affecting each one of them at two producers wells (AA01, AA02, AA03, AA04). For more detail, see the figure 1, where the location of the wells is showed.

Risk assessment before pilot project start up indicated that was necessary to establish if the expected polymer solution mobility was achieved, so several laboratory analyses were carried out: core flood experiments, and polymer retention tests, however uncertainties regarding actual field application, such as polymer solution quality, and the governing reservoir conditions, encourage the idea of apply field experiments and operational tests. The objectives of the pilot test are to provide quick answers to questions like injection performance, polymer stability, and effect of heterogeneities, among others. The results will determine if the technology represents a feasible opportunity for the future development of this field.

Introduction

The polymer pilot test consist of three injectors wells affecting five producers wells (see figure 1). A polymer solution with an apparent viscosity of 66 cP (considering a shear rate of 7.34 sec−1) was injected in each of the injectors during the first three months, to displace the oil in the reservoir. The initial conditions prior to injection could be appreciated in the figure 1, as you can see, the reservoir pressure is approximately 315 psia, with a temperature of 115.5 °F, this could be used to estimate a reservoir oil viscosity of 4,150 cP, considering the PVT data of the field.

The reservoir petrophysic data can be observed in the table I. It can be also seen that the effective permeability according to petrophysics is between 15 and 19 Darcy, and reservoir porosity between 0.32 and 0.35 fraction. The injector wells go through clean sand, with no important variations in shale content, and resistivity measurements (see figure 2 and figure 4). The polymer solution is injected using the annular, between the casing of 7" and 2 3/8" tubing that serves as holder for the permanent down hole sensors. The wells are completed with slotted liners, with 5% of open flow area (500 microns slot opening). After the polymer solution reach the slotted liner section during injection, the fluid go through the liners slots and then enters to the reservoir. The casing, liners, and pipelines are made of stainless steel (13% chromium), so no chemical degradation is expected to occur due to Iron presence. The well schematic can be appreciated in figure 5.

According to fiber optic interpretation data, the effective length in all the injector wells, should be less than the one estimated by petrophysic analysis. The effective length was obtained tracking the location of the hot bank fluid that formed in the vertical section as it moves in the horizontal section when the injection was restarted. In the figure 2, it can be appreciated this process, the static temperature trace was taken at 10:23 am, and then the injection was started. No change in temperature occurred after 4,100' (see figures 2, and 3). The effective length estimated by petrophysic analysis in the case of the well AA06 is equal to 1,450', however the temperature response indicates that the effective length should be around 610'. Similar results were obtained for the wells AA07, and AA08; in these cases they showed an effective length of 352' and 1,159' respectively. This last case was interesting because the well AA08 showed a better injection profile compared to the others wells (see figure 4). Details regarding well completion can be appreciated in figure 5.

Water for polymer preparation is obtained from a producer well perforated in an aquifer not connected with the oil reservoir. As you may observe in table II, the water which is in the oil reservoir show a higher salinity compared with the supplied water.

The process of polymer solution preparation can be observed in figure 6. No important variations of temperature are present in the process. Oxygen is kept out of the preparation process using nitrogen as a blanketing gas in the maturation tank and in the water supply tank. The quality of the polymer solution is evaluated at the end of the process after analyzing samples recollected in the sampling points located at the outlets of the injection pumps A, B, and C. Right now, the pumps A, B, and C are out of services because the wells are injecting at lower pressure than expected. Only with the pressure supplied by the water supply pump (89.7 psia) is enough to push the polymer solution in to the reservoir.

Methodology

The methodology followed was; initially properly validate characteristics of the water used for preparation, and reservoir connate water characteristics. We evaluated also the rheology of the polymer solution injected in the reservoir, and also its quality; by means of laboratory analysis on site: The laboratory analyses to establish polymer quality were executed on daily basis. For the case of the pressure tests analyses, the effective length of the injector wells were established using fiber optic data obtained from permanent down hole sensors, then five fall off tests were planned and executed, and the results were analysed using the current theory of pressure transient test analysis. This approach is similar to others presented before (Manichand et al., 2010), the main difference is the importance given to the polymer solution mobility estimation at reservoir conditions.

Results and Discussion

Water preparation and reservoir water evaluation

The parameters, showed in table III, were measured monthly according to the surveillance plan. The principal concern was the iron, and oxygen content. These two parameters were measured on site, using colorimetric tubes. Also, suspended solid content and pH were part of the analyses performed on site.

The water samples needed for the analyses were collected using plastic bottles, cured with nitric acid. Each day, the collected samples were transferred to the laboratory to perform the analyses (The laboratory is located outside the field). The purpose of these analyses was validating the field results obtained on site using less accurate procedures and instruments available in the field. The results are presented in the table IV. Little variation is observed in the results, just a little increase in the iron content. These results could be attributed to iron oxide released from the water production line (water producer well).

As it was mentioned before, part of the analysis were performed on site. For example, the iron and oxygen were quantified more frequently using colometric tubes. The appreciation of the colometric tubes depends on the user, so less variation is observed. According to these results, the maximum expected iron content should be 1.7 ppm (see figure 7). Note that iron content determined in the lab outside the field is also plotted in the figure. Oxygen content is lower than 0.2 ppm (see figure 8).

Polymer solution rheology and quality proper characterization of the polymer solution is a key parameter necessary to simulate the solution behavior in the reservoir and in the surface facilities. In our case, several laboratory analyses were performed in order to characterize properly the polymer solution, using the water source available. The apparent viscosity at different shear rates and concentration was measured. The results in figure 9 indicated the polymer solution viscosity was highly affected by the shear rate. For example at reservoir conditions, the expected shear rate is between 1 and 10 Sec−1, so the viscosity in the reservoir should be between 152 cP and 55 cP (for a polymer solution with a concentration of 880 ppm). For this pilot test, the polymer chosen is Flopaam 3630S, with an average molecular weight of 18 million g/mol and 30% hydrolysis. In figure 10 is presented the viscosity measured at 7.34 sec−1 for different concentrations. According to these results, the yield viscosity could be fitted using a polynomial function, given that the temperature is 116 °F and no changes in water composition.

Each curve (for a different concentration in figure 9) has also a different flow behavior index and a different consistency or power law constant (see table V). The power law model (Carreau, 1972) can be used to estimate the values of the consistency and the flow behavior index mentioned before. The apparent viscosity is denoted as μapar, the consistency with the letter "K", and flow behavior index with the letter "n", in the equation 1.

Water is a newtonian fluid, so the flow behavior index is equal to one. A complete degradation could result in flow behavior index close to the value of one, and also a reduction of the consistency value (Shupe, 1981). Seright et al. (2010) observed that no shear thinning behavior was observed during theirs experiments, and concluded that the heavier species of polymer molecules responsible for the occurrence of the shear thinning behavior were retained in the porous media, causing that the polymer behaved as a Newtonianfluid. They also mentioned that when in presence of low salinity brines and high polymer concentrations, it may be possible to observe shear shinning behavior. In our case, the water in the reservoir could severely reduce the viscosity of the polymer solution, given that some mixture between the injected polymer solution and reservoir water occurs. The figure 11, shows the effect of mixing water from the reservoir with the polymer solution. For this lab analysis we prepared a polymer solution with a concentration of 2,000 ppm, using water with total dissolved solids of 356 ppm, this was a synthetic water solution prepared according to the composition of the water produced by the aquifer. Also, the brine used to represent the connate water was a synthetic brine prepared following the composition presented in table II (water present in the reservoir). In the figure 11, the line which represents 0%, show the measured viscosity considering no mixing. Mixing 5% of the water from the reservoir with the prepared polymer solution could reduce to a 40% the apparent viscosity of the last. The analysis was performed under an anoxic atmosphere, so no alteration by Oxygen could be expected. The temperature was kept at 116.6 °F; and the viscosity was measured at 7.34 sec−1 in each case.

Thanks to the results so far, we concluded that the polymer solution presented good quality and conserved its properties before entering the injectors’ wells.

Interpretation of fall off tests

The fall off tests and the Hall chart were used to evaluate the characteristics and the behavior of the polymer solution at the reservoir level. With models proposed in the literature we could estimate the mobility of the polymer solution in the reservoir (Knight, 1973), (Thomas et al., 2012) and these estimations gave us an idea of the behavior of the polymer solution in the reservoir.

The injection wells were completed with multisensors located in the horizontal section of the well (figure 5). The analysis methods applied in the interpretation of the fall off tests were: Cartesian and type curve (Knight, 1973), (Thomas et al., 2012).

In total, five (5) fall off tests were carried out. Table VII shows the duration of the test, the average injection rate before closing in, and the viscosity of the injected fluid. Surface conditions; means that the viscosity was measured on samples prior to enter into the injection wells, considering a shear rate of 7.34 sec−1. The first fall off was unplanned, while the subsequent closures were planned. The followed conditions for each planned test were:

Continuing with the fall off test analysis, the behavior of the pressure derivatives of well AA06 for the others fall off tests 2, 3, 4 and 5, showed a different tendency compared with first one, in this case linear trends of slopes near in magnitude were present (figure 19, 20, and 21), for the first three fall off tests, which couldn't be considered linear flow because the observed slopes were between 0.15 and 0.16. From the analysis of the fall off 4 (see figure 19), it is observed that the pressure derivative is stabilized at a higher level, and it is displaced in time, allowing reaching the conclusion that the fluid has difficulty entering the reservoir due to a decrease in the mobility of the polymer solution.

The polymer solution mobility values estimated for the well AA06 using the first stabilization is presented in table IX. After this first derivative stabilization, a second stabilization is observed. If the second derivative stabilization is used to obtain the polymer solution mobility, the estimated values could differ by 25% between each other. The reason behind these changes could be explained by the effect of water saturation in the area of investigation, shear effects, or changes in water effective permeability caused by polymer retention.

Uncertainties in establishing the effective water saturation, and shear rate, make difficult the estimation of the in situ viscosity, but assuming an effective permeability of 2.5 Darcy, which was obtained from core analysis, and considering 100% water saturation, we can estimate a viscosity of 7.3 cP for the second fall off, and a viscosity of 17.2 cP for the fall off test number 4. This would indicate a reduction of the expected viscosity at reservoir conditions, and the alteration of the polymer solution characteristics. Also, given the reduction in the water mobility, the results were an indication of a possible water permeability reduction.

Continuing with the fall off test analysis, the behavior of the pressure derivatives of well AA06 for the others fall off tests 2, 3, 4 and 5, showed a different tendency compared with first one, in this case linear trends of slopes near in magnitude were present (figure 19, 20, and 21), for the first three fall off tests, which couldn't be considered linear flow because the observed slopes were between 0.15 and 0.16. From the analysis of the fall off 4 (see figure 19), it is observed that the pressure derivative is stabilized at a higher level, and it is displaced in time, allowing reaching the conclusion that the fluid has difficulty entering the reservoir due to a decrease in the mobility of the polymer solution.

The polymer solution mobility values estimated for the well AA06 using the first stabilization is presented in table IX. After this first derivative stabilization, a second stabilization is observed. If the second derivative stabilization is used to obtain the polymer solution mobility, the estimated values could differ by 25% between each other. The reason behind these changes could be explained by the effect of water saturation in the area of investigation, shear effects, or changes in water effective permeability caused by polymer retention.

Uncertainties in establishing the effective water saturation, and shear rate, make difficult the estimation of the in situ viscosity, but assuming an effective permeability of 2.5 Darcy, which was obtained from core analysis, and considering 100% water saturation, we can estimate a viscosity of 7.3 cP for the second fall off, and a viscosity of 17.2 cP for the fall off test number 4. This would indicate a reduction of the expected viscosity at reservoir conditions, and the alteration of the polymer solution characteristics. Also, given the reduction in the water mobility, the results were an indication of a possible water permeability reduction.

As it is observed in table VII, in the case of the fall off 4, the polymer solution viscosity was reduced from 180 cP to 66 cP. This promoted a different behavior from the previous fall offs. In the figure 20, the first one corresponds to a mobility of 145 mD/cP, and the second a mobility of 109 mD/cP. As we stated before, this appears to be related to the previously introduced change in polymer concentration (see table VII), where a polymer solution bank with an average concentration of 1,700 ppm is moving ahead of a polymer bank with a concentration of 980 ppm. We associated the first pressure derivative behavior to the characteristics of the polymer solution with a concentration of 980 ppm, which is closer to the well, later the observed derivative behavior could be related to the polymer bank with a concentration of 1,700 ppm.

In figure 21, it can be appreciated that the last part of the pressure derivative of the fall off test 4 is superimposed with a portion of the derivative of the fall off 3, indicating similar motilities. This was not observed in the previous tests, so it was concluded that this signature corresponded to the previous polymer bank (1,700 ppm).

The result from each analysis is presented in table IX in the case of the well AA06. In the case of the first fall off, we use the result obtained from the Newtonian interpretation, similar results could be obtained using the non-Newtonian methodology. The mobility shows a decrease in the fall off 2 (after 60 days of injection). These estimations indicate the alteration of the fluid in reservoir conditions, and possibly a reduction in effective permeability. The results of the transient test in the case of the Well AA06 showed significant reduction of water mobility after the fall off 3. Simple observation of the derivative behavior indicates that the mobility was reduced from for the same concentration at different moments of the flooding process. This change in mobility as the injection progressed, indicated a better displacement efficiency and also that the causes behind the higher mobility at the beginning of the injection process could be associated to polymer retention (Willhite et. al., 1977), (Zhang et. al., 2014), mechanical degradation (Heemskerk et. al., 1984), and salinity alteration. Between these factors, polymer retention is associated with viscosity reduction and permeability reduction, which is consistent with the results observed, but the amount of polymer retention has a maximum possible value, meaning that after some time the affectation should disappear. Similarly, the affectation caused by water mixing (Mixing injection water with reservoir water), should be temporary also, at least in the vicinity of the injector well, causing at the beginning of the flooding process a low value of viscosity, as we expect according to the results of laboratory analysis that you can appreciate in the figure 10. Finally, mechanical degradation should be present all the time, because the injection is occurring under matrix regimen (parting pressure is 1,200 psi, and injection pressure has reached a maximum of 560 psi), meaning that near the wellbore the shear stress could be high enough to break the large polymer molecules, and therefore reducing the viscosity of the polymer solution. In the case of the wells AA07 and AA08, the results are presented in the table X, and the table XI. In the case of the well AA07, the fall off 3 and 5, couldn't be analyzed because of the storage, and wellbore issues. The pressure derivative behavior observed in figure 22 was caused by an unintentional error during shut in operations, so the results could not be of use (the injection was restarted by a mistake). In the case of the well AA08, the fall off 1, 2, and 3 could not be analyzed because the behavior showed by the pressure derivative. However, the tendency of the reduction of mobility as injection progressed was observed in these two wells (see figure 24 and 25).

progressed, which was to expect because of the increase in the concentration of the polymer solution, except in the case of the reduction in polymer concentration after the fall off 3. It is normally accepted that displacement efficiency should increase as the mobility of the injected fluid diminished compared with displaced fluid, but there is an economical limit for the amount of polymer employed to reach an acceptable recovery factor. So an optimization process is recommended in order to find the proper concentration to be injected for the future expansion of the project.

These findings will be used to improve the project performance after implementation of changes in different aspects, such as:

• Flood strategy: Continuous injection vs. slug injection with different viscosities will be evaluated.

• Improve the polymer stability: In order to be more resistant to the conditions found in the reservoir.

• Well completion design: Changes in the completion design in order to reduce the storage effect, and improve the injection profile.

• Investigate the possible negative effect on polymer solution viscosity caused by high shear rates, which could be occurring at the sand face.

Conclusions

• The polymer solution under study showed a very strong shear shinning behavior at surface conditions, thanks to the low salinity of the water used for preparation.

• The negative effects of iron and oxygen content were discarded as a possible cause of polymer viscosity affectation.

• Salinity of the reservoir water could affect negatively the polymer solution viscosity, depending on the mixing degree that is occurring in the reservoir between the two aqueous solutions.

• The evaluation of the characteristics of the polymer solution at different points of the preparation process indicated that the injected fluid retained most of its properties before entering the injector wells, indicating that no degradation was taking place at surface conditions.

• Filterability ratio indicated that the polymer solution presented good quality, suitable for the injection process.

• A reduction in the mobility of the polymer solution was also observed using fall off test interpretations. This conclusion was also supported by the behavior of the Hall plot derivative.

• No lineal behavior was observed in the derivative response in all the cases studied; instead, radial stabilization were present in all the studied fall off tests.

·       The observed resistance factor increase from 1, 3 to 7. The reasons behind this could be related to polymer retention.

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