Study of the Initial Conditions of the Super Gigant Akal Reservoir

A Study of the Initial and Exploitation Conditions of the Super Giant Akal Offshore Naturally Fractured Reservoir

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A Study of the Initial and Exploitation Conditions of the Super Giant Akal Offshore Naturally Fractured Reservoir Alfredo Leon-G, Pemex Fernando Samaniego-V, UNAM Heber Cinco Ley, Pemex and UNAM Fernando Rodriguez, Pemex and UNAM Jos Luis Snchez B., Pemex Fernando Ascencio C., PEMEX Juan E. Ladron G., PEMEX Agustin Galindo, PEMEX

Abstract:

The Akal reservoir is located on the continental shelf of the Gulf of Mexico, along the coastal States of Tabasco and Campeche, approximately 50 miles northwest of Cd. del Carmen, in water depths ranging from 35 to 50 meters. This field has been producing over 1 million barrels of oil per day since the early 1980s. The Akal reservoir structure consists of an asymmetric anticline, with maximum net thickness of 980 meters. The oil density in the reservoir ranges from 20 to 22 API. The Akal reservoir is in calcareous rocks of Cretaceous age, and is highly fractured, including vugs, interconnected by a complex system of fractures and micro-fractures. Due to the big reservoir thickness and high permeability in the fractures ranging typically from 2 to 5 Darcys, once the bubblepoint pressure was reached, a secondary gravity drainage gas cap began to form in June 1980. After an initial presentation of the characteristics of this field, this work focuses in a systematic study of the very complete data set of temperature, pressure and composition of the fluids, with the purpose of evaluating the gravity segregation, thermal convection and molecular diffusion effects on the reservoir behavior, under initial and dynamic conditions, which resulted in a conceptual reservoir model. A discussion is also included of the reservoir behavior starting May 2000, when the biggest ever 1200 MMscf/D Nitrogen injection project started. This gas injected in the gas cap is used as a pressure maintenance process, with highly successful results so far, allowing an important production increase from this field, reading approximately 2.1 MMSTB/D.

Introduction The Akal reservoir, discovered in 1976 and located about 50 miles offshore in the Bay of Campeche, Mxico, Fig. 1, is part of the Cantarell Complex, that additionally includes the Nohoch, Chac and the deeper Sihil block located under the Akal field1. This complex covers and area of about 41019 acres.

The Akal reservoir structure consists of an asymmetric anticline, bounded on the West by a normal fault and by an inverse fault on the Northern and Easter sides. The Southern portion of this anticline presents formation characteristics of low porosity, and it is limited by a water oil contact.

The exploitation from the Akal reservoir started in June 1979, with the Akal 1-A well which produced 34000 STB/D, of 22 API gravity. This super giant field has an original oil in place (OOIP) of 32 billions stock tank barrels. The main pay zones of the Akal field are hydraulically continuous over a thickness of 1200 m, corresponding to highly fractured and vuggy carbonate formations, from Jurassic, Cretaceous and lower Paleocene ages; others less important calcarenite and sandstone formations are from the upper Paleocene and middle Eocene.

Oil in this reservoir was initially undersaturated, with a pressure at the reference depth of 2300 meters subsea level, mssl, of 270 kg/cm2; all reservoir pressures in this paper unless otherwise stated, will be referred to this depth. Average porosity in the reservoir is 8 percent; secondary porosity (micro fractures, fractures and vugs) may account for up to a 35% of this

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value; typical absolute permeability for the primary (matrix) and secondary systems of this naturally fractured reservoir are 0.3 and 5000 md, respectively.

Initially the wells of the Akal field produced at an average rate of 29000 STB/D. As an example, the 1981 production for the field of 1.5 MMSTB/D was provided by 40 wells, Fig. 2. However, due to the pressure depletion of the field, the 1995

1MMSTB/D production required 150 gas-lift wells, which gives an average production well of about 7000 STB/D.

The purpose of this study is to present the results of a systematic study of a complete data set of temperature, pressure and composition of the fluids of the Akal reservoir, with the aim of evaluating the gravity segregation mechanism, the thermal convection and molecular diffusion effects, on the reservoir behavior under initial and dynamic conditions, which provided a conceptual reservoir model of this naturally fractured macrovugular reservoir.

The Main Production Mechanism of the Akal Reservoir: Gravity Segregation First, to further describe the characteristics of the main producing formation of this field, Fig. 3 presents a view of a whole core of around 4.5 diameter by 6 length, which includes some of the secondary porosity features. In addition, Fig. 4 shows a set of tomography images2 for a typical whole core (Fig. 3) of the main producing formation for this field. The secondary porosity of this porous medium can be mainly observed as dark portions within the circular images.

Studies conducted at early exploitation times for this reservoir3, indicated that its characteristics of high permeability and a big thickness, would most probably result in an efficient gravity segregation production mechanism. A series of studies have been reported in the literature concluding that the recovery factor (RF) for reservoirs with similar properties to those of Akal, where gravity segregation is the main producing mechanism, including the implementation of an enhanced recovery project (EOR), could be even higher than 80 percent.4,5,6

The initial pressure of the reservoir, referred to the highest structural position of the reservoir anticline of 1100 mssl, was 167 kg/cm2, and a bubble point pressure of 150 (kg/cm2)7,8 which results for this part of the reservoir in an undersaturated average pressure difference value of 17 kg/cm2. The early predictions came true, and in mid 1981 the partially completed productive wells completed in the highest structural position of the anticline9, started to show a decreasing gas-oil ratio (GOR), due to the gas released from solution once the bubble point pressure was reached, that was migrating upstructure to form a growing secondary gas cap. In brief, the Akal field was produced under full gravity segregation conditions10-14 up to May 2000, when a 1200 MMSCFD nitrogen injection process started. As already mentioned, the reservoir has an associated aquifer, that is shared with other neighboring fields15,16; before the implementation of the nitrogen injection process, the aquifer moved 480 m from its original position of 3200 mssl. Fig. 5 shows the variation of the average pressure vs. time for this reservoir, for primary production conditions prior to the start of the injection process.

Next, the process undergone by an oil reservoir where a secondary gas cap will be formed, is described by means of the pressure and fluid behavior vs. depth shown in Fig. 6. First, for undersaturated conditions the pressure through all the formation thickness is higher than the bubble point pressure (pb)17-19; the initial variation of pressure vs. depth is shown by line A. As previously described, once the bubble point pressure is reached in the reservoir, gas will come out of solution and a secondary gas cap will start to form at the upper portion of the structure, line B. After some time a defined gas-oil contact will appear, with a progressively downward position.

The hydrocarbon zone between the depth level where the reservoir pressure corresponds to the bubble point pressure and the GOC depth, physically presents saturations of gas and oil where the two phases are flowing, the former going upwards to increase the volume (mass) of the secondary gas cap and the latter flowing downward20; this zone is shown in Fig. 6 as the upper portion of part (C); it has been called gassing zone (GZ) or oil and gas flowing zone (OGFZ). In the undersaturated zone indicated by part (D) in this figure, the oil composition is the original at the corresponding depth. Next the water invaded zone (WIZ) is found, where




the oil in this portion of the reservoir, that was part of the original oil zone (OOZ), has been displaced, remaining under residual conditions (Sorw).

Convection of Fluids in a Reservoir It has been indicated that in reservoirs that present naturally fractured conditions from medium to high levels, with high relief and intermediate or lighter gravity, may have uniform PVT properties with depth, indicating that because of the temperature gradient, fluid convection developed within the fractures before production commenced21. In a naturally fractured reservoir (NFR), conditions of a high permeability in the fractures cause a convection velocity, which is due to the geothermal temperature gradient that affects the fluids in the fractures, in such a way that the warmer lighter fluids at deeper conditions tend to flow upward, and colder heavier fluids at lower depths flow downward. This process gives as a result that reservoirs such as Kirkuk22 that presents convection conditions, show a smaller temperature gradient.

Saidi21 has reported an average temperature gradient of the NFR Iranian Haft Kel field of 1.2C/100m, while the gradient for the upper part of the reservoir was 0.72C/100 m. On the other hand, the temperature gradient estimated by the author for the non fractured fields of the Asmari area was 2.5C/100 m.

Peaceman19 concluded the oil in the fractures of the OGFZ contains less dissolved gas and is consequently heavier than that saturating the deeper undersaturated oil zone, which generates a convective effect. Jacqmin23 discusses that the vertical temperature gradient in many reservoirs is not big enough to produce fluid convection; however, he states that horizontal density gradients may cause convection under the influence of gravity segregation. In a more recent study Ghorayeb and Firoozabadi24 presented a simulation study for the evaluation of convection on the fluid composition in a NFR, concluding that well hydraulically connected fractures favor convection.

Initial and Exploitation Conditions of the Akal Field In the present section the data set of the Akal Reservoir will be discussed.

Variation of temperature vs depth. Figure 7 presents the complete data set of static temperatures vs. depth for the Akal reservoir, which clearly show an important dispersion. After a careful evaluation of temperature measurements from different wells, only data where shut-in times were long enough were used in a refined analysis: Figure 8 shows the selected data for the different platforms. Different areal gradients are observed in this figure, with smaller values toward the North part of the field, and increasing to the south. It can also be observed that for the shallower central portions of the field above 2000 mssl the gradients are smaller, ranging between 0.14 and 0.54C/100 m, increasing as we get closer to the flanks of the reservoir, with a range of 0.90 to 1.89C/100 m. Expressions for the correlations computed for some of the platforms are included in Table 1.

The low gradient values for the central portion of the reservoir indicate the effect of fluid convection, while the greater gradient values found in the flanks are associated with mostly non-existent convection. A more detailed discussion regarding these results has been presented elsewhere25.

The lower temperature gradient values found in the shallow central portion of the anticline structure, correspond to the most highly naturally fractured conditions of the producing formation of this field. The estimated unbalanced areal gradients indicate convective effects with a North-South orientation.

Variation of the PVT properties and of the oil composition. A detailed analysis of the PVT results, both conventional and compositional26 found that the experimental results obtained by three different laboratories based on equivalent oil samples,




reported differences in some properties and/or parameters that were bigger than the estimated experimental errors.

With the purpose of analyzing the variation of the PVT properties and of the hydrocarbon composition with depth, at the original reservoir conditions, the results of five analysis were used, see Table 2; it should be noticed in this table that the sampling depth range was 1326 m, between the shallowest production interval, for well C-94A, and the deepest for well C-82. Fig. 9 presents the variation of methane (C1) and of heptanes plus (C7+) vs. depth, for the samples of Table 2, showing that contrary to what is found in reservoirs where gravity segregation is the main producing mechanism, the C1 and C7+ compositions decrease with depth.

Figure 10 presents complementary results of the variation of other components vs depth, such N2, H2S, CO2, C2, C3, iC4, and nC4 and for iC4, nC5 and C6, showing again as already discussed for Fig. 9 that the compositions decrease with depth for the former group and increase for the heavier latter.

Figures 11, 12, 13 and 14 show the variation of the saturation pressure pb, and of the following properties at this pressure, the solution gas ratio and the GOR, the oil formation volume factor, and the oil density, vs. (the middle production interval) depth, it is observed that within the experimental accuracy, these results confirm that the oil composition and PVT properties of the central shallower part of the reservoir, at original conditions were essentially, constant which indicates active convection fluid flow conditions.

Special PVT studies on samples collected in 1997. With the purpose of estimating the PVT properties of the reservoir fluids and its mixtures with Nitrogen, the fluid to be injected in the year 2000, an oil sampling program was implemented in 1997: Three different wells were selected with producing intervals, located in a way that samples from the upper, middle an lower parts of the oil zone could be collected27. Table 3 shows the basic information of the compositional PVT studies conducted on these samples; in particular, the second and the last columns include the information of the collecting depth, and the description of these data with respect to its distance to the GOC of the reservoir at that time, which essentially states that the sample of well C-79 was collected near the GOC, at an intermediate distance for well C-49 and at a deep (large) distance for well C-285, close to the WOC.

Figures 15, 16 and 17 show the variation of the bubblepoint pressures pb, and of the solution gas ratio Rsb and of the oil density

ob at this pressure, previously reported in Table 3; these results indicate that the first two listed parameters present an increasing behavior with depth and the last of them show a decreasing sequence, with a range between the maximum and the minimum value of around 1.5%, that may be within the experimental measurement accuracy for this parameter; another possible explanation for these results will be next presented. Table 4 presents the composition of the three oil samples up to heptanes plus, C7+; it can be noticed that the mole percent for the C7+ for the samples of wells C-49 and C-79, taken at a near and intermediate distance from the GOC, increase with depth, in accordance to what would be expected for alterated samples collected in the gassing zone (that between the oil zone and the gas cap, Fig. 6); however, for the sample of well C-285, the C7+ mole fraction is very close to the value estimated at original conditions (see Table 2), concluding that this sample was collected in the undersaturated oil zone (Fig. 6).

Variation of the PVT properties with the exploitation time. As briefly discussed previously, a reservoir producing under gravity segregation conditions would show a characteristic behavior with the exploitation time, in a way that the different hydrocarbon zones and the WOC (Fig. 6) will be a function of the reservoir pressure, and of the variation of the PVT properties as related to the fluid composition. A proper simulation of this behavior is essential, because any deviation with respect to the real behavior would indicate the influence of other effects in addition to gravity segregation, such as convection and/or diffusion.




Figure 18 shows the downward movement of the gas-oil contact (GOC) level vs time, estimated from TDT and production logs.

With the purpose of estimating the variation of the volumes of the secondary gas cap, of the gassing zone and of the oil zone, with the exploitation time, a calculation of the variation of the reservoir pressure vs. depth was made for the years 1980, 82, 84, 86, 88, 90, 92, 94, 94, 97, 98 and 2000, based on the data of the average reservoir pressure shown in Fig. 5 and of the pressure gradients computed using the density information. Fig. 19 shows the results obtained; in this figure the data for the original bubble point pressure is also included, clearly presenting two different behaviors, a constant (vertical) for the central portion of the field and the remaining that shows a decrease with depth. Fig. 20 presents the three saturation pressures reported in the 1997 study24; it can be noticed that the samples collected in wells C-49 and C-79 have a bubble point pressure practically coincident with the reservoir pressure, but this is not the case for the well C-285 samples, that has a bubble point pressure higher than the reservoir pressure, which means that it was collected in the undersaturated oil zone (Fig. 6).

Figure 21 shows a comparison of the EOS predictions for years 1980, 88 and 97, of the solution gas ratio Rs vs. depth, using the PVT results of the 1980 study of the sample of well C-94-A (Table 2); it can be observed that at the initial undersaturated conditions, the ratio Rs was constant and as the exploitation time increases the Rs decreases for depths below the GOC, due to the already discussed upward gas flow, and as the upper limit of the saturated oil zone is reached, the ratio increases until the original Rs behavior, and then follows a constant value for depths in the oil zone. Also shown in this figures are the values for the ratio Rs reported in the 1997 study, observing a good agreement between the calculated (simulated) and measured data for wells C-49 and C-79; however, the deviation previously described (Fig. 20) for the results of the well C-285 sample, is also shown for the Rs value, confirming that this sample was collected in the under-saturated oil zone.

Figure 22 presents a comparison of the EOS predictions for years 1980, 88 and 97, as already discussed for Fig. 21 of the oil density vs. depth; it can be noticed that for the under-saturated 1980 conditions the density increases with depth. The behavior of this parameter for exploitation times when the secondary gas cap has been formed shows a growing tendency presenting constant bigger values with respect to that at original conditions for depths corresponding to this cap, and as the gassing zone is reached, the behavior follows a decreasing trend, that changes to increasing as we enter into the oil zone. This figure also shows the results for the oil density obtained from the 1997 study, with similar results as discussed for Figs. 20 and 21.

Figure 23 shows a comparison of the calculated and measured oil density vs. depth; the conclusions that can be made are again just about the same to those stated in relation to Figures 20 to 22, with the only exception that the more recent study did not report values for the oil density.

The 1200 MMscf/D Nitrogen Injection Project. Reservoir simulation studies,28,29,30 indicated, that the implementation of a gas cap pressure maintenance project would yield optimized oil recovery in the Akal reservoir. Predictions showed that exploitation under natural depletion, the Akal reservoir would have reached an average pressure of 1180 psi and oil production rates of 3200 STB/D per well by year 2004. Under these conditions, long times, approximately 80 years, would have been required to produce the Akal oil remaining reserves30, with the needed replacement of production facilities. Water influx would have also continued in the reservoir, with poorer oil recovery factor as compared to gas cap invasion.

The considerations described, along with results from other technical and economical studies, led to the conclusion that gas cap pressure maintenance by nitrogen injection was required to optimize the exploitation of the Akal reservoir31. Technical and economical analysis of several simulated production-injection scenarios28,29 concluded that optimum results would be obtained for a field oil rate of 2 MMSTB/D for 4 years, which would require a 1200 MMscf/D nitrogen gas cap injection. This oil production rate would then start declining.




Estimations for the additional oil and gas recoveries, resulting from this nitrogen injection project are 2324 MMSTB and 870 MMMcf, respectively.

The gas cap pressure maintenance project started in May 2000 with a rate of 300 MMscf/D and by same year December, the design 1200 MMscf/D injection rate was reached. Nitrogen is injected into the gas cap through seven wells, completed at the top of the reservoir structure. The field behavior has been closely followed up through an implemented systematic program for the monitoring of pressure, nitrogen concentration and the gas-oil contact downward movement31.

Discussion of Results The main finding from the results presented in the last section is based on the fact, that there is a close agreement between the EOS predictions based on the characterization of PVT results of original samples, and those measured in the 1997 study, which basically means that the convection and diffusion effects under the primary exploitation conditions of the reservoir are negligible. This means that the viscous and gravity segregation forces dominate the fluid flow in the reservoir. However, as previously discussed in this paper with regard to the variation of the temperature, composition and PVT properties vs. depth, initially before the start of exploitation the reservoir presented active convection conditions. Figures 24 and 25 show comparisons of the variations of the measured bubblepoint pressure and of the percents for C1 and C7+ vs. depth, with the EOS calculated (simulated) values, based on the PVT results of the oil original sample of well C-94; it can be observed that the differences are important, because the real measurements are under the effect of fluid convection, while the simulated results do not consider this effect.

Conclusion The purpose of this paper has been to present the results of a systematic study of a complete data set of temperature, pressure and composition of the fluids of the Akal reservoir, with the main aim of evaluating the gravity segregation, thermal convection and molecular diffusion mechanisms on the reservoir behavior, under initial and dynamic conditions, which would provide a conceptual reservoir model of this naturally fractured and vuggy reservoir.

From the results of this study, the following conclusions are pertinent:

1) Based on the measured temperature gradients, important convection effects were acting at initial conditions in the structurally central upper part of the reservoir. In the lower part of the reservoir normal gradients were measured, which indicates that convection is not important.

2) Confirming conclusion (1), the variation of the initial bubblepoint pressure vs. depth was essentially constant in the central higher part of the reservoir, and increases in the lower part of the formation.

3) The mole percent of heptanes plus, C7+, for initial conditions decreases with depth, indicating the effect of convection of fluids.

4) The convection effect prevailing at initial conditions is associated with the main naturally fractured and macrovugular characteristics of the reservoir. This effect is only acting at initial conditions.

5) The PVT results of the 1997 study indicates that the Akal reservoir under primary production has been mainly producing under the effect of gravity segregation, and that for these dynamic conditions the fluid convection effects have not important.

References 1. Ortega Gonzlez, G.: Mantenimiento de Presin y Bombeo Neumtico, la Mejor Alternativa para

Explotar las Reservas del Complejo Cantarell, paper presented at the Annual Conference of the Mexican Association of Petroleum Engineers.

2. Herrera, G.R., personal communication, UNAM, Mxico, D.F. (2002).




3. Samaniego V.F.: Mecanismo de Segregacin Gravitacional y su Efectividad en el Yacimiento akal, PEMEX, Internal Report, Mxico, D.F., (1980).

4. Cook, R.E.: Analysis of Gravity Segregation Performance During Natural Depletion, Society of Petroleum Engineers Jour. (Sept. 1962) pp. 261-274.

5. King, R.L., Stiles, J.H. Jr. and Wagooner, S.M.: A Reservoir Study of the Hawkins Woodbine Field, paper SPE 2972 presented at the 45th Annual Fall Meeting of SPE, Houston, Texas, 4-7 Oct., 1970.

6. Joslin, W.J.: Applying the Frontal Advance Equation to Vertical Segregation Reservoirs, Jour. Pet. Tech. (Jan. 1961) 87-94.

7. Pemex Exploracin y Produccin: Las Reservas de Hidrocarburos en Mxico, Volumen 2: Los Principales Campos de Petrleo y Gas en Mxico, First Edition, Mxico, D.F. (April 1999).

8. Jimnez B.O.E. and Godina R.A.: Campo Cantarell Evaluacin del avance del Contacto Gas-aceite, Ingeniera Petrolera, (Nov. 1990), 9-19.

9. Samaniego V.F.: Estudio de la Productividad del Pozo Akal 1-A, Ingeniera Petrolera, Vol. XX, No. 6 (June 1980) 13-17.

10. Godina R.A. and Torres R.A.: Akal Field (Cantarell Complex) Conditions of Exploration, Analysis and Prediction, paper SPE 28714 presented at SPE International Petroleum Conference & Exhibition of Mxico, Veracruz, Mxico, 10-13 October 1994.

11. Arvalo, V.J.A., Samaniego, V.F., Lpez, C.F.F. and Urquieta, S., E.: On the Exploitation Conditions of the Akal Reservoir Considering Gas Cap Nitrogen Injection, paper SPE 35319 presented at the SPE International Petroleum Conference & Exhibition of Mxico, Villahermosa, Mxico, 5-7 March, 1996.

12. Limn H., T., de la Fuente, G., Garza P., G. And Monroy H., M.: Overview of the Cantarell Field Development Program, paper OTC 10860 presented at 1999 Offshore Technology Conference, Houston, Texas, 3-6 May.

13. Rodrguez, F., Ortega, G., Snchez, J.L. and Jimnez, O.: Reservoir Management Issues in Cantarell Nitrogen Injection Project, paper OTC 13178 presented at 2001 Offshore Technology Conference, Houston, Texas, 30 april-3 May.

14. Limn H., T., Garza P., G. And Lechuga A., C.: Status of the Cantarell Field Development Program: An Overview, paper OTC 13175 presented at 2001 Offshore Technology Conference, Houston, Texas, 30 April-3 May.

15. Miguel H.N., Durn A., R., Zona Regional Conectada por Acufero Asociado a los Yacimientos de la Formacin Brecha-Cretcico de la Regin Marina, Ingeniera Petrolera, Vol. XXXVI, No. 10 (Oct. 1996).

16. Advisory Study of the Caan field located in the Bay of Campeche, Mxico. A NSAI study for PEMEX E&P, Houston, TX, January 1999.

17. Andresseb, K.H., Baker R.I. and Raoofi J.: Development of Methods for Analysis of Iranian Asmari Reservoirs (June 1963).

18. Yamamoto R.H., Pedgett J.B., and Ford W.T.: Compositional Reservoir Simulation for Fissured Systems: The Single Block Model, paper SPE 2666 presented at the Annual Fall Meeting, Denver Co. Oct. 1969.

19. Peaceman D.W.: Convection in Fractured Reservoir The Effect of Matrix - Fissure transfer on the Instability of a Density Inversion in a Vertical Fissure, paper SPE 5523, presented at the Annual Fall Meeting Dallas, Tx. (1975).

20. Saidi, A.M.: Reservoir Engineering of Fractured Reservoirs, Fundamental and Practical Aspects, Edition Presse, Paris (1987), Chapter 5.

21. Saidi, A.M.: Twenty Years of Gas Injection History into Well Fractured Haft Kel Field Iran, paper SPE 35309 presented at the 1996 SPE International Petroleum Conference & Exhibition in Mexico, 5-7 March, Villahermosa, Tab.

22. Freeman H.A. and Natanson: S.G.; Recovery Problems in a Fractured Pore Systems: Kirkuk Field, (1959).

23. Jacqmin D: Interaction of Natural Convection and Gravity Segregation in Oil Gas Reservoirs, SPE Reservoir Engineering (May 1990) 233-238.

24. Ghoreyeb K. and Firoozabadi A.: A Numerical Study of Natural Convection and Diffusion in Fractured Porous Media, paper SPE 52347.

25. Len G.A., Samaniego, V.F., Flores C., S., Ladrn de G., J.E., Ascencio C., F., Galindo N., A., Rodrguez de la G., F. and Snchez B., J.L.: Variacin de las Propiedades PVT en el Yacimiento Akal Debido a los Efectos de Conveccin y Segregacin Gravitacional, technical report, Pemex (Dec. 1980) 127 pp.

26. Whitson, C.H. and Brule, M.R.: Phase Behavior, SPE monograph, Vol. 20, Richardson, Texas (2000).

27. LE Romander J.F. and Kalayjian F.: Study of Nitrogen Injection in the Cantarell Complex (Mxico), Final Report of Project B4392015, French Petroleum Institute (2000).

28. Advisory study of the Cantarell Complex fields (Akal, Chac, Kutz and Nohoch) located offshore Campeche Mxico, prepared for PEMEX E&P, by NSAI, June 1996

29. Cantarell Complex Special Simulation Runs, Schlumberger-geoquest, Denver, CO., August 1998. 30. Feasibility Study of Gas Injection in Offshore Mexican Oil Reservoirs, a Unigas, CO. study

prepared for PEMEX E&P, Norman, OK., December 1996.




31. Snchez, J.L., Astidillo, A., Rodrguez F., Morales, J. And Rodrguez, A.: Nitrogen Injection in the Cantarell Ckomplex: Results after Four Years of Operation, paper SPE 97385 presented at the Latin American and Caribeean Petroleum Engineering, Conference and Exhibition, Ro de Janeiro, Brazil, 20-23 June, 2005.

Acknowledgments The authors want to thank you Mr. Guillermo Ortega G., Head of the Cantarell Assett, and to Mr. Oscar Jimnez B. and Mr. Alfonso Urriza V. of the Exploitation Design of this Asset, for their help and permission to present this paper.

TABLE 1. AVERAGE TEMPERATURE CORRELATIONS FOR THE WELLS IN THE DIFERENT PLATAFORMS.

PLATAFORM GRADIENT (oC/100m) EQUATION

(T=C), H=DEPTH [MBSL]

TEMPERATURE (at 2300 MBSL)

AKAL I 0.47 UPPER * 1.48 LOWER T=0.004717H+85.8726T=0.0148H+66.23

96.72 100.27

AKAL D 0.28 T=0.002849H+92.572 49.01

AKAL B 1.10 T=0.0116H+69.177 95.80

AKAL E 0.54 T=0.0054H+90.129 102.50

AKAL F 0.41 T=0.0041H+92.43 101.80

AKAL G 0.30 T=0.003077H+92.763 99.84

AKAL H 0.36 T=0.0036H+69.735 105.01

AKAL J 1.27 T=0.0127H+73.633 102.80

AKAL M 1.67 T=0.0167H+55.45 93.80

AKAL N 0.14 T=0.001403H+93.313 96.54

AKAL L 0.90 T=0.0090H+76.3509 97.05

AKAL O 1.89 T=0.0189H+54.868 102.00

NOHOCH A 1.20 T=0.0120H+84.000 111.60

NOHOCH B 1.75 T=0.01757H+74.297 112.40

AKAL P 1.71 T=0.0171H+63.714 103.00

AKAL R 1.00 T=0.010H+88.000 111.00

*The temperature measurements followed two approximately linear trends.

TABLE 2. COMPOSITION AND PVT PROPERTIES OF DIFFERENT ORIGINAL SAMPLES OF THE AKAL

RESERVOIR CRUDE OIL.




WELL C-94A C-57-A C-8 C-2011-D C-82

AKAL 2 AKAL 3 AKAL 701

DATE OF SAMPLING 15/9/78 30/9/78 27/4/80 6/5/80 21/4/79

COMPONENT (COMPOSITION (% MOL)

H2S 1.03 1.13 1.32 1.43 1.05

CO2 1.85 2.96 1.64 1.62 1.68

N2 0.28 0.40 0.26 0.20 0.98

C1 28.84 28.20 29.58 26.84 29.52

C2 8.68 8.38 8.63 8.47 8.40

C3 6.22 5.68 6.37 6.47 6.57

IC4 0.96 1.64 1.18 1.03 1.06

NC4 3.34 3.27 3.07 3.44 3.47

IC5 1.21 1.03 1.60 1.49 1.14

NC5 1.29 1.71 2.17 2.31 1.25

C6 2.49 3.78 2.89 4.29 3.45

C7 43.81 41.82 41.29 42.41 41.43

TOTAL 100.00 100.00 100.00 100.00 100.00

MWC7+ 315.00 330.00 326.00 328.00 328.79

rC7+ 0.929 0.934 0.931 0.930 0.936

Depth (mbsl) 1246 2477 2062 2260 2572

Temp.(oC) 97 101 86 102 101

Pb (kg/cm2) 151 150 147 137 159

Bob (m3/m3) 1.321 1.308 1.306 1.31 1.322

Rsb (m3/m3) 87.6 84.2 86.9 82.3 87.6

ob (gr/cm3) 0.787 0.798 0.790 0.791 0.807

sc (gr/cm3) 0.912 0.913 0.919 0.914

ob (cp) 2.32 2.54 2.78 2.27 2.03

GOR (m3/m3) 72.10 68.04 79.61 70.89 75.16

TABLE 3. PVT PROPERTIES OF THE SAMPLES OF WELLS C-79, C-49 AND C-285,COLLECTED IN DECEMBER

1997.




WELL DEPTH Rs GAS

MOLECULARWEIGHT

LIQUID MOLECULAR

WEIGHT

CRUDE OIL

MOLECULARWEIGHT

LIGHT CRUDE

OIL FRACTION

N2-C11

HEAVY CRUDE

OIL FRACTION

C11+

(mv) (m3/m3) gr/mol s.c. Gr/mol

s.c. gr/mol (% weight) (% weight)

79 1967 52 29.66 320 194.56 22.2 63.84

49 2269 65 29.98 316 177.46 23.37 61.18

285 2630 72 30.74 312 169.55 24.56 61.08

WELL TEMPERA-TURE PRESSURE pb Bob

ob sc COMMENTS

*

(C) kg/cm2 kg/cm2 (m3/m3) gr/cm3 gr/cm3

79 97 91.80 85.68 1.23 0.81 0.92 Taken near

the gas oil contact

49 101 114.24 114.24 1.23 0.80 0.93 Intermediate

285 102 141.77 126.47 1.28 0.80 0.93 Deep

Related to the oil sample depth

TABLE 4. COMPOSITION OF THE OIL IN WELLS C-49, C-79 AND C-285, COLLECTED IN DECEMBER 1997.

COMPONENT CANTARELL-79 CANTARELL-49 CANTARELL-285

%

MOLE

MOLECULAR

WEIGHT

%

MOLE

MOLECULAR

WEIGHT

%

MOLE

MOLECULAR

WEIGHT N2 0.03 28.02 0.06 28.02 0.20 28.02

CO2 1.50 44.01 1.35 44.01 1.38 44.01 H2S 1.49 34.08 1.68 34.08 1.46 34.08 C1 20.60 16.04 24.21 16.04 25.18 16.04 C2 8.85 30.07 8.64 30.07 8.66 30.07 C3 7.10 44.10 6.99 44.10 7.08 44.10 Ic4 1.12 58.12 1.20 58.12 1.26 58.12

NC4 3.46 58.12 3.94 58.12 4.27 58.12 IC5 1.58 71.92 1.79 71.95 2.09 71.95 NC5 2.15 72.15 2.35 72.15 2.84 72.15 C6 4.19 85.32 3.92 85.36 4.62 85.41

C7+ 47.93 357.14 43.87 357.65 40.96 363.02

TOTAL 100.00 100.00 100.00

CORRECTED MOLECULAR WEIGHT C7+

342.00 333.98 317.63

TABLE 5. COMPARISON OF THE MEASURED AND EOS CALCULATED OIL COMPOSITION WELLS. C-79, C-49

AND C-285 AND C-94A.




COMPONENT WELL C-79 WELL C-49 WELL C-285

MEASURED SIMULATED MEASURED SIMULATED MEASURED SIMULATED

PRESSURE (kg/cm2) 86 86 114 114 126 126

H2S 1.49 1.04 1.68 1.04 1.46 1.03

CO2 1.50 1.65 1.35 1.78 1.38 1.82

N2 0.03 0.15 0.06 0.22 0.20 0.25

C1 20.60 20.33 24.21 25.28 25.18 27.28

C2 8.85 8.44 8.64 8.61 8.66 8.66

C3 7.10 6.57 6.99 6.38 7.08 6.29

IC4 1.12 1.05 1.20 1.00 1.26 0.98

NC4 3.46 3.71 3.94 3.49 4.27 3.41

IC5 1.58 1.37 1.79 1.28 2.09 1.24

NC5 2.15 1.47 2.35 1.36 2.84 1.32

C6 4.19 2.87 3.92 2.65 4.62 2.56

C7+ 47.93 51.35 43.87 46.91 40.96 45.16

100.00 100.00 100.00 100.00 100.00 100.00

DOS BOCASDOS BOCAS

ESCALA GRAFICAESCALA GRAFICA

KAXKAX--11

UECHUECH

KABKAB--101101

SINANSINAN 101A101A1A1A

YUMYUM--22401401

MAYMAY--11

MISONMISON--11

KIXKIX--11

KIXKIX--22

YAXCHEYAXCHE--11

00 30 Km30 Km

CIUDAD DELCIUDAD DELCARMEN CARMEN

OCHOCH POLPOL

BATABBATABTOLOCTOLOC

CAANCAAN

CHUCCHUC

200 m.200 m.

100 m.100 m.

50 m.50 m.

25 m.25 m.

IXTALIXTAL

MALOOBMALOOB--103103

ZAAPZAAP--11KUKU

LUMLUM--11BACABBACAB

IXTOCIXTOC--11TARATUNICHTARATUNICH

301301201201

10110111

ABKATUNABKATUN

EKEKBALAMBALAM

FRONTERAFRONTERA

TAKINTAKIN

22--BB

620620500500 540540 580580460460

21302130

21702170

20902090

20502050

47 miles47 miles

KutzKutzAkalAkal

NohochNohochChacChac

CANTARELLCANTARELL

DOS BOCASDOS BOCAS

ESCALA GRAFICAESCALA GRAFICA

KAXKAX--11

UECHUECH

KABKAB--101101

SINANSINAN 101A101A1A1A

YUMYUM--22401401

MAYMAY--11

MISONMISON--11

KIXKIX--11

KIXKIX--22

YAXCHEYAXCHE--11

00 30 Km30 Km

CIUDAD DELCIUDAD DELCARMEN CARMEN

OCHOCH POLPOL

BATABBATABTOLOCTOLOC

CAANCAAN

CHUCCHUC

200 m.200 m.

100 m.100 m.

50 m.50 m.

25 m.25 m.

IXTALIXTAL

MALOOBMALOOB--103103

ZAAPZAAP--11KUKU

LUMLUM--11BACABBACAB

IXTOCIXTOC--11TARATUNICHTARATUNICH

301301201201

10110111

ABKATUNABKATUN

EKEKBALAMBALAM

FRONTERAFRONTERA

TAKINTAKIN

22--BB

620620500500 540540 580580460460

21302130

21702170

20902090

20502050

47 miles47 miles

KutzKutzAkalAkal


KutzKutzAkalAkal


CANTARELLCANTARELL

Fig. 1. Cantarell complex location.




Fig. 2. Akal pressure and production behavior.

Fig. 3. Typical whole core of the Paleocene breccia of the Akal reservoir.




Fig. 4. Computer tomography images for a vuggy naturally fractured whole core.

Fig. 5. Field and reservoir simulation static pressures for Akal field.




Fig. 6. Pressure and fluid behavior vs. depth for a gravity segregation reservoir11.

Fig. 7. Variation of the reservoir temperature vs. depth, as related to the measurement date, for the Akal field.

Fig. 8. Variation of the Akal reservoir temperature vs. depth.




Fig. 9. Variation of the mole percent of C1 and C7+ vs. depth for the original oil samples of the Akal reservoir.

Fig. 10. Variation of the mole percent of N2, CO2, H2S, C2, C3, iC4, nC4, iC5 and C6 vs. depth, for the original oil samples of the Akal reservoir.

1000

2000

3000

100 150 200BUBBLEPOINT PRESSURE (kg/cm2)

DEP

TH (M

BSL

)

Fig. 11. Variation of the saturation pressure vs. depth for the Akal reservoir, from compositional PVT results obtained based on original oil samples.




Fig. 12. Variation of the solution bubblepoint solution gas ratio and of the GOR vs. depth for the Akal reservoir, from compositional PVT results obtained based on original oil samples.

Fig. 13. Variation of the oil formation volume factor vs. depth for the Akal reservoir, from compositional PVT results obtained based on original oil samples.

Fig. 14. Variation of the oil density vs. depth for the Akal reservoir, from compositional PVT results obtained based on original oil samples.




Fig. 15. Variation of the bubble point pressure and of the static bottomhole pressure vs. depth, for the oil samples of wells C-79, C-49 and C-285.

Fig. 16. Variation of the solution gas ratio vs. depth, for the oil samples of wells C-79, C-49 and C-285.

Fig. 17. Variation of the oil density vs. depth, for the oil samples of wells C-79, C-49 and C-285.




Fig. 18. Downward movement of the gas-oil contact (GOC) level vs. time for the Akal reservoir.

Fig.19.Pressure behavior vs. depth for different exploitation times, of the Akal reservoir.

Fig. 20. Comparison of the reservoir pressure and of the bubblepoint pressure variation vs. depth, based on PVT data from the samples of wells C-49, C-79 and C-285.




Fig. 21. Comparison of the variation of the solution gas ratio vs. depth for well C-94 with results from samples of wells C-49, C-79 and C-285.

Fig. 22. Comparison of the variation of the oil reservoir pressure and of the bubblepoint pressure vs. depth for well C-94 with results from samples of wells C-49, C-79 and C-285.

Fig. 23. Comparison of the variation of the oil viscosity vs. depth for well C-94 with results from samples of wells C-49, C-79 and C-285.




1000

2000

3000

0 50 100 150 200

SATURATION PRESSURE (kg/cm2)

DEP

TH (

MB

SL)

Pb SIMULATED Pb MEASURED

Fig. 24. PVT and EOS simulated (well C-94) bubblepoint pressure for the Akal reservoir.

1000

2000

3000

0 20 40 60

COMPOSITION (% mole)

DEP

TH (

MB

SL)

C1 SIMULATED C7+ SIMULATED

C1 MEASURED C7+ MEASURED

FIG. 25. PVT and EOS simulated (well C-94) mole percents for C1 and C7+ for the Akal reservoir.


Study of the Initial Conditions of the Super Gigant Akal Reservoir

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