Sedimentological Control on Permeability Anisotropy and Heterogeneity in Shorefae Reservoir, Niger Delta, Nigeria

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1 Volume 6 No.1, January 216 ISSN IJST. All rights reserved Sedimentological Control on Permeability Anisotropy and Heterogeneity in Shorefae Reservoir, Niger Delta, Nigeria Raphael O. Oyanyan and Richmond U. Ideozu Department of Geology, P.M.B. 5323, University of Port Harcourt, Nigeria ABSTRACT Anisotropy in permeability causes directional preferences in permeability which can results in reservoir fluid coning that impact oil recovery from reservoirs. Therefore, this study was done to evaluate sedimentological control on permeability anisotropy in shorefae reservoir, as well as to understand the relationship between permeability anisotropy and heterogeneity. Lorenz coefficient indicates that the studied shoreface reservoir sandstone is heterogeneous. The evaluation of vertical to horizontal permeability ratio (Kv/Kh) within the shoreface reservoir sandstone revealed that core permeability varies in vertical and horizontal direction, indicating anisotropy. Lithofacies heterogeneity is attributed to grain sizes, burrows, bioturbation, mud-drapes and inter-bedding or intercalated shales. It was found that the biogenic textural heterogeneities (varied burrow types), primary sedimentary structures, mud drapes and the intervening shaly mudstone identified in the cored intervals do create different levels of permeability anisotropy in the different sub-depositional facies. Therefore, permeability anisotropy is controlled by lithofacies heterogeneity. Keywords: Permeability Anisotropy, heterogeneity, shoreface reservoir, fluid coning 1. INTRODUCTION Permeability is said to be anisotropic if its values varies in vertical and horizontal direction. Anisotropy in permeability causes directional preferences in permeability and its determination helps the prediction of potential for reservoir fluid coning; well perforation productivity and sweep orientation in hydrocarbon production [1; 2; 3]. Coning is a term used to describe the mechanism underlying the upward movement of water and/or the downward movement of gas into the perforations of a producing well and can seriously impact the well productivity and influence the degree of depletion and the overall recovery efficiency of the oil reservoirs [4]. It can results in early water or gas break which can consequently leads to early field abandonment or oil-zone bypass. One of the factors that determine the degree or rapidity of coning is the difference between vertical and horizontal permeability [4]. Therefore, the knowledge of permeability anisotropy helps the reservoir geologists and engineers to make informed decision on well design and completion for optimum hydrocarbon production from a reservoir. Sandstones develop anisotropic characteristics during deposition in response to the depositional process [5]. Lewis [6]; and Meyer and Krause [7] gave grain-scale or layer-scale heterogeneities (cross bedding and shales) in sedimentary rock as determinant factors of permeability anisotropy, while according to Ehlig-Economides et al. [4], anisotropy is caused at many length scales, by compaction and variation in depositional environment, lithification and lithology. Therefore, the aim of this study is to determine the relationship between permeability anisotropy and reservoir heterogeneity in shoreface deposit as well as to underscore the sedimentary factors responsible for permeability anisotropy in shoreface deposit in the study area. 1.1 Study Area The study area is onshore oil filed located in Rivers State of Nigeria, about 6km from Port Harcourt, the capital city of the state (Fig.1). It is a matured field that has produced hydrocarbon for more than fifteen years from mainly Late Oligocene reservoirs sands of Greater Ughelli depobelt of Niger Delta basin [8; 9]. The geology of the study area is that of Niger Delta which is well-known and discussed elsewhere [9; 1; 11; 12]. In summary, the Niger Delta basin consists of three Formations, from top to bottom, Benin, Agbada and Akata Formations. Benin Formation has a maximum thickness of 2m and is dominantly made up of sand and gravel. Agbada Formation has a maximum thickness of 4m and consists of interstratified sandstones and shale. Akata Formation has a maximum thickness of 65m and mainly made up of overpressured marine shale with thin silt and sandy interbeds. Hydrocarbon occurs in the Agbada Formation. Thus, the reservoir sands of the study area are that of Agbada Formation.

2 Volume 6 No.1, January 216 ISSN IJST. All rights reserved 5E 8E 6N 6N 3N 5E Study area 8E 3N Figure 1: Google earth map of Niger Delta showing the study area. 2. DATA SETS AND METHOD Data used in this study are 68 horizontal and 14 vertical air permeability values from cored shoreface deposit, and the photographs of the cored samples. Depositional facies in the cored intervals was first of all determined to understand the macroscopic level of reservoir heterogeneity which according to Buatois [13] is expressed at the facies scale. Then permeability heterogeneity was quantified using Lorenz curve and coefficient [14]. The consideration of relative homogeneity or heterogeneity of permeability is very necessary in the determination of permeability anisotropy [15]. The detailed method of calculating Lorenz coefficient (L k) can be found in Ahmed [4] and Lyons [16]. Lorenz plot was constructed by plotting fraction of total flow capacity (K h) against fraction of total volume (Øh) and adding a third column which represents the line of perfect equality. The greater the deviation of the Lorenz curve from 45 line of perfect quality, the greater the heterogeneity of the reservoir. Lorenz coefficient (L K) varies from to 1, where uniform or homogeneous permeability is and the highest level of heterogeneity is 1. The anisotropy in permeability of the reservoir sand-body was quantified by cross-plotting horizontal permeability against vertical permeability s values (full diameter measurements). The correlation coefficient indicates equality and inequality between vertical and horizontal permeability. The higher the correlation coefficient, the greater the equality of permeability values in the two directions. The sedimentological control on vertical permeability anisotropy was studied by calculating K-ratio (K v/k h) of the identified depositional facies units. The closer the K-ratio is to 1., the more homogeneous and isotropic the reservoir interval, while the greater or lesser the K-ratio is than 1., the more heterogeneous and anisotropic the reservoir interval. 3. RESULTS AND DISCUSSION 3.1 Depositional Facies The depositional facies indentified in the cored interval as shown in Fig. 2 include upper shoreface, lower shoreface, offshore/transitional zone, transgressive sandstone and tidal inlet-fill/tidal flat. The sedimentological and petrophysical properties of these facies or sub-environment of deposition in Niger Delta have been described in detailed by Oyanyan and Oti [17]. However, in summary, lithofacies heterogeneity as shown in Fig. 2 is attributed to grain sizes, burrows, bioturbation, muddrapes and inter-bedding or intercalated shales. It is a coarsening upward succession of lithofacies, with upper shoreface on top and offshore/transitional zone at the base. Pervasiveness of mud drapes decrease from lower shoreface to upper shoreface. Bioturbation decreases from offshore to uppershoreface. Upper shoreface is dominated by vertical/ oblique burrows such as that of Ophiomorpha, Fugichnia (an escaped burrow) and

3 Volume 6 No.1, January 216 ISSN IJST. All rights reserved Teichichnus. While lower shoreface is dominated by horizontal burrows such as that of Asterosoma, Planolites, and palaeophycus. The coarsening upward succession of lithofacies is overlain by transgressive sandstone and tidal inlet-fill deposited when the depositional environment was inundated during marine transgression. 3 FU Tidal inlet-fill 2 Oph Transgr. sandstone cm (b) Upper shoreface Lower Shoreface cm (c) 3 Ast Offshore/transition zone Sand Sparse-uncommon bioturbation Horizontal burrow Shale Moderate -common Oblique burrow Mudstone Mud-drape bioturbation bioturbation Vertical burrow Abundant -complete Erosive boundary Oph= Ophiomorpha, Ast= Asterosoma, F= Fugichnia 2 cm Ast (d) Oph (a) Figure 2: Lithofacies log with core pictures showing depositional facies, variations in grain sizes and biturbation intensity, burrows and mud drapes on cores. 3.2 Reservoir Quality and Permeability Heterogeneity The lorenz curve indicates the contrast between high and low permeability values (Fig. 3). The plot exhibit wide concavity toward the upper left corner, indicating heterogeneity [4]. Also Lorenz coefficient (L K) of.65 calculated by dividing area (ABCA=.326) above the straight line of perfect equality (AC) by the area (ACDA =.5) below the line indicates that the reservoir is heterogeneous. Though the reservoir is heterogeneous, core permeability that is between 5md and above 1,md and core porosity between 1 and 28% indicate good to excellent reservoir quality (Fig. 4) [18]. Also, as shown in Fig. 4 there is a close match between porosity and permeability except at m where there is high porosity but low permeability. From the sedimentological study of the cored interval, that depth interval is the tidal inlet deposit within a transgressive systems tract. The miss-match between porosity and permeability values is probably due to clay thin pore throat lining and compaction [19]. The plot shows that the reservoir quality is depositionally controlled.

4 Volume 6 No.1, January 216 ISSN IJST. All rights reserved 3.3 Permeability Anisotropy The large scatter of points and low correlation coefficient of.412 in Fig. 5 indicates high inequality between vertical and horizontal permeability, which means preference for one directional flow as a result of heterogeneity in permeability in X, Y and Z direction [1]. As indicated in Fig. 6, the most isotropic and homogenous interval are tidal inlet fill (thin and massive), transgressive sandstone (thin and massive) and offshore-transition deposit (Common to completely bioturbated) with K-ratio that range from.64 to.81. They have K-ratios close to 1. The rest intervals are highly anisotropic and heterogeneous with K-ratios either far greater than or lower than 1. Therefore as illustrated in Fig. 6, permeability anisotropy is facies dependent [2]. Figure 3: Illustration of flow capacity distribution and reservoir heterogeneity. The vertically burrowed and massive sandstone parts of upper shoreface have higher vertical permeability than horizontal permeability with an average K-ratio that varies from 1.49 to 2.6 (far greater than 1). Therefore, the preferred fluid flow direction is vertical. The facies therefore has high potential for fluid coning. The mud draped cross-bedded sandstone of upper and proximal lower shoreface has an average K-ratio of.17 (far less than 1) indicating an enhanced horizontal permeability more than vertical permeability. Therefore, the preferred fluid flow direction is horizontal. Similarly, lower shoreface deposit characterized by thin intervening shaly mudstones, primary sedimentary structures, and mudrapes have higher horizontal permeability than vertical permeability values with an average K ratio of.18 (far less than 1). From the foregoing, the biogenic textural heterogeneities (varied burrow types), primary sedimentary structures, mud drapes and the intervening shaly mudstone identified in the X1 cored intervals create varied anisotropic permeability levels in the shoreface sand-body. Therefore, reservoir geologist and engineers involved in reservoir management should always monitor fluid contacts against zones or facies units with K-ratios far greater than 1 Figure 4: Core permeability and porosity depth plot of the studied cored reservoir. It shows the close matching of porosity and permeability. Figure 5: Cross-plot of horizontal permeability versus vertical core permeability values.

5 Volume 6 No.1, January 216 ISSN IJST. All rights reserved XI- Cored interval ( m) permeability than horizontal permeability and therefore have high potential for fluid coning. Therefore, reservoir geologist and engineers involved in reservoir management should always monitor fluid contacts against zones or facies units with K-ratios far greater than 1. Acknowledgment The authors are very grateful to Total Exploration and production Company, Port Harcourt and the Department of Petroleum Resources (DPR) for the provision of the data used in this study. REFERENCES [1] White, H. J., Skopec, R. A., Ramirez, F. A., Rodas, J. A. and Bonilla, G Reservoir characteristicsof the Hollin and Napo formations, western Oriente basin, Ecuador, in A. J. Tankard, R. Suárez S., and H. J. Welsink, Petroleum basins of South America: AAPG Memoir 62, pp [2] Ayan, C., Colley, N., Cowan, G., Ezekwe, E., Wannell, M., Goode, P. Halford, F., Joseph, J., Mongini, J., Obondoko, P., Pop, J., Measuring permeability Anisotropy: The latest approach. Oilfield Review (October), pp [3] Ehlig-Economides, C., Ebbs, D., Fetkovich, M. And Meehan, D. N., 199. Factoring Anisotropy into well design. Oilfield review 2, No 4 (October), pp Figure 6: The plot of vertical and horizontal permeability values against depth and vertical distribution of K-ratios. It shows the variations of permeability anisotropy in different depositional facies. 4. CONCLUSIONS 1. Though shoreface reservoir is laterally extensive and of high petrophysicla quality, it is also very heterogeneous and the degree of heterogeneity determines the degree of permeability anisotropy. 2. Permeability anisotropy is caused by primary and biogenic sedimentary heterogeneity. Mud drapes, scattered mud lined burrows and intercalated shale bed increase permeability anisosopy, while abundant to complete bioturbation reduces it. 3. Variability in sedimentary facies, governs fluid behavior, and porosity and permeability heterogeneity and anisotropy. The vertically burrowed sandstone parts of shoreface reserservoir sand-body have higher vertical [4] Ahmed, T. 26. Reservoir engineering handbook. Third edition. Elsevier Inc. Publ., 1472p. [5] Torres, H. A., Aguayo, H. C., Lea, M. M., Monjaras, J. B., Eric P. P., Erik M. S., and Gelmunt E. V., 21. Anisotropy and Petrophysics of a Gas Reservoir in a Horizontal Well with a High Angle Pilot Well, Burgos Basin, Mexico. Search and Discovery Article #4525. *Adapted from extended abstract prepared for poster presentation at AAPG International Conference and Exhibition, Rio de Janeiro, Brazil, November 15-18, 29. [6] Lewis, J. J. M Outcrop-derived quantitative models of permeability heterogeneity for genetically different sand bodies. SPE Paper Presented at the 63rd Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Houston, Texas, pp [7] Meyer, R. and Krause, F. F., 26. Permeability anisotropy and heterogeneity of a sandstone reservoir analogue: An estuarine to shoreface depositional system in the Virgelle Member, Milk River Formation, Writing-on-Stone

6 Volume 6 No.1, January 216 ISSN IJST. All rights reserved Provincial Park, southern Alberta. Bulletin Of Canadian Petroleum Geology, 54(4), pp [8] Stacher, P., Present understanding of the Niger-Delta hydrocarbon habitat in: M.N. Oti and G. Portma (Editors), Geology of Deltas. A.A. Balkema, Rotterdam, pp [9] Reijers, T. J. A., 211. Stratigraphy and sedimentology of the Niger Delta. Geologos, 17 (3): [1] Short, K. C., and A. J. Stauble, Outline of geology of Niger Delta: AAPG Bulletin, 51: [11] Doust, H., and E.M. Omatsola, Niger Delta, in Edwards, J.D. and Santogrossi, P. A. eds., Divergent/passive margin basins: AAPG Memoir 48: [12] Nwajide, C.S., 213. Geology of Nigeria s Sedimentary Basins. CSS Books Ltd, Lagos, 565p. [13] Buatois, L. A., Saccavino, L. L. and Zavala, C., 211, Ichnologic signatures of hyperpycnal flow deposits in Cretaceous river-dominated deltas, Austral Basin, southern Argentina, in R. M. Slatt and C. Zavala, eds., Sediment transfer from shelf to deep water Revisiting the delivery system: AAPG Studies in Geology, 61, pp [14] Schmalz, J. P., and Rahme, H.D The Variation of Waterflood Performance With Variation in Permeability Profile, Prod. Monthly, 15 (9), [15] Meyer, R. 22. Anisotropy of sandstone permeability. Crewes Research Report, 14, pp [16] Lyons, W. C Standard handbook of petroleum & natural gas engineering. Houston, Tex.: Gulf Pub. Co., Volume 2, ISBN: , 733p. [17] Oyanyan, R. O. and Oti, M. N Down-dip cross sectional variability in sedimentological and petrophysical properties of shoreface parasequence reservoir, Niger Delta. Petroleum Technology Development Journal (ISSN ): An International Journal; 5 (2), pp [18] Dresser, A Well logging and interpretation techniques. The course for home study. Dresser Atlas Publ., 17p. [19] Ali, S. A., Clark,W. J., Moore, W. R., Dribus, J. R. 21. Diagenesis and Reservoir quality. Oilfield Review (Summer), Schlumberger Publ. 22 (2), pp [2] Elfenbein,C., Husby, Ø. And Ringrose, P., 25. Geologically based estimation of k v / k h ratios :an example from the Garn Formation,Tyrihans Field, Mid- Norway. In :Dore,A.G. and Vining,B.A.(eds) Petroleum Geology:North-West Europe and Global Perspectives Proceedings of the 6 th Petroleum Geology Conference, the GeologicalSociety, London,