Oil from Granitoid Rocks - Reservoir Characterization of Fractured Basement in Neuquén Basin, Octógono Field, Argentina*

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1 Oil from Granitoid Rocks - Reservoir Characterization of Fractured Basement in Neuquén Basin, Octógono Field, Argentina* Diego E. Velo 1, Rodrigo Ugarte 1, Oscar Pioli 1, Fernando Rey 1, Diego Narrillos 1, Mario Pascual 1, Fernando Creus 1, and Omar Castillo 1 Search and Discovery Article #20280 (2014)** Posted November 24, 2014 *Adapted from oral presentation given at AAPG International Conference & Exhibition, Istanbul, Turkey, September 14-17, 2014 **Datapages Serial rights given by author. For all other rights contact author directly. 1 YPF S.A., Neuquen, Argentina (diego@petroleo.net.ar) Abstract Located in Argentina, the Paleozoic basement in the Octógono Field, Huechulafquen Formation, consists of granitoid rocks underlying Los Molles shale which is the seal and one of the source rocks together with the Vaca Muerta Formation. The field was discovered in 1918 and produced from shallow reservoirs. Development activity in the basement is a recent upside. The main tectonic pillar was formed in the Early Jurassic. After rifting, sedimentary units of the Cuyo Group were deposited on the basement in hemi-grabens, later elevated during tectonic inversion during the Upper Jurassic. The structure was already formed when hydrocarbon migration started. All permeability and storage had been originated from fracturing and alteration. Fracturing is the result of tectonic processes that raised the basement more than 1000 m above the surrounding rocks. These occurred before the initial stages of the basin and several reactivations took place. Six alteration zones corresponding to the differential weathering can be correlated based on 3D seismic and well logs. Resistivity is affected by iron content; also, due to the low matrix porosity, small variations in the mineralogy strongly affect indirect storage estimations. Resistivity, NMR and acoustic logs allow deriving an estimation of total fluid as well as storage and permeability indicators. A fracture intensity index can be obtained from picking of open discontinuities. NMR allows the characterization of total pore space, in addition to the interpretation of fluids by the analysis of diffusion maps and comparison

2 of T2 spectra. A permeability indicator is based in the reduction of velocity and amplitude of the Stoneley wave in presence of mobile fluids, a function of mobility that can be seen as a coupling into a formation wave known as a slow wave. The reservoir is described by partition coefficient and classifies as type BA (35% of storage in macrofractures). The recovery factor is estimated at 25% considering expansion of a 300 m thick gas cap. The oil leg is 450 m thick, down to the depth of chaotic seismic reflectors typical of unaltered basement. Faults at seismic resolution and each of the alteration zones are mapped in detail. The integration of the processed information into a 3D model allows identifying regions where storage capacity is higher. Mapping of fracture intensity helps to orientate the development to sectors where flow capacity is higher, thus optimizing EUR. References Cited Aguilera, R., 1999, Recovery Factors and Reserves in Naturally Fractured Reservoirs: Journal of Canadian Petroleum Technology, Distinguished Authors Series, v. 38/7. doi.org/ /99-07-da. Coalson, E.B., D. J. Hartmann, and J.B. Thomas, 1985, Productive characteristics of common reservoir porosity types: Bulletin of the South Texas Geological Society, (February 1985) v. 25/6.

3 O i l F r o m G r a n i t o i d R o c k s. R e s e r v o i r C h a r a c t e r i z a t i o n o f T h e F r a c t u r e d B a s e m e n t o f T h e N e u q u é n B a s i n, O c t o g o n o F i e l d, A r g e n t i n a September AAPG ICE, Istanbul

4 Objectives Reservoir characterization of Huechulafquen Formación (Basement). To analyze opportunities in not yet exploited resources in a mature field with just a marginal production. Incorporation of the naturally fractured Paleozoic Basement as main objective for development, project conceptualization and execution. To explain production behavior from the geological model. The Paleozoic basement of the Mesozoic back arc Neuquén Basin. 2

5 Peri-urban location Norte de Octógono Campamento 2 Campamento 1 Cutral Co Plaza Huincul Sudeste Octógono Campamento 1, was discovered in 1918, main development was in the 1950s decade. 3

6 PRD Liquid (m3/d) Production / Operative PRD Gas (km3/d) Production History Rise in Producción Petróleo (m3/d) Gas (km3/d) Tiempo (YY) 0 Ene-12 Cierre Sep 2013 Delta Qoil (m3/d) Qgas(km3/d) Qw(m3/d) 50 wells, 29 of them during the 2012/14 campaign. 4

7 Zonas trituradas (almacenamiento en matriz) Harina de falla Zapala PHCC Huechulafquen Fm. Chachil Limestone Los Molles Fm. Outcrop analogue 30 Km away in the Cerro Granito. 5

8 G. CUYO Stratigraphic column / Structure * 1\ r CUENCA NEUQUINA COLUM NA ESTRATIGRAFICA SINT~T ICA Regi6n Sur y Dorsa l de Huincu l NazcaStage Broken foreland basin Campamento I Sinistral convergence >45 TERCIARIO o n ~ u G. r, NEUQUÉN,-, rn CENTENARIO F. QUINTUCO Late Farallon Foreland basin Sinistral convergence >45 Early Farallon * Intraplate deformation F. VACA MUERTA F. LOTENA CHALLACÓ F. LAJAS \ Aluk Stage Intraplate deformation Campa menlo I - - B F. LOS MOLLES Sinistral convergence >45 F. LA JARDINERA / PC Rift Stage F. HUECHULA FQUEN EVOLUCIÓN TECTÓNICA Sedimentary Mesozoic sediments (Los Molles shale) directly above and hemigrabens Tectonic inversion by oblique convergence, reactivation of extension faults during Toarcian. 6

9 Expansion by microfractures Expansion by microfractures The basement in rock cores. Left: fractured reservoir, right: unaltered granodiorite 7

10 Macro y Microfisuras (pseudo) matrix porosity and fracture porosity 8

11 / I' ~.~ '< / /,/' ~ Arcose levels dated Toarcian, source from the Basement, deposited in structural lows 9

12 Seismic features in Basamento A A Los Molles B0 B1 B2 B1 B Fractures at seismic scale on top of Basamento B3 B4 B5 B Tope B B2 B3 A A B4 B B5 Seismic features, correlation zones, expression in well logs. Gas cap up to 300 m thick placed in B0 and B1, there is some compartimentalization due to acid dykes as recognized in the Cerro Granito 10

13 M2R9 STPERM Evaluation by variable m = n and some crossplots 4 % a d MPHE 240 ohmm SW: Archie con M variable = N Relación cualitativa entre SP y MPERM VCL = 1- MPHE/PHIT MPHE b UMAPP/RHOMAPP TO GRD c PORs = ZNPHI - SPHI PORf = PART x PHIT CNCF/ZDEN GR GR GRD TO Variable m: arithmetic average between rescaled EMOD and S amplitude, and the relation of Log (RT) / log PHIT 11

14 Storage Capacity (MPHE x h) Locally higher fracture intensity in lower storage capacity causes high initial rates altough a higher decline Espolón de BSM Storage Capacity (MPHE x h) given by matrix porosity due to micro-fracturing as the main property as a key to productivity 12

15 Flow Capacity (STPERM x h) \ 1600_1X1M ~ ~ ~ B 11/ ~ \1 II Flow Capacity (SPERM x h), also dip azimuth indicator, its relation with Qoi 13

16 Preliminary analysis and reservoir type Conceptual model: 100 % porosity due to (micro) fracturing By production behavior a OOIP Recovery Estimation c By Partition Coefficient b Microfractures SW > 20% 5 to 7.5 % of the reservoir is non-fractured 60 to 65 % of the reservoir is micro-fractured 25 to 30 % of the reservoir is fractured a and b) modified from Aguilera, Roberto, 1999: "Recovery Factors and Reserves in Naturally Fractured Reservoirs", Journal of Canadian Petroleum Technology, Distinguished Authors Series, July 1999, volume 38, no. 7.b) adapted from Coalson, E. B., D. J. Hartmann, y J. B. Thomas, 1985, Productive characteristics of common reservoir porosity types: Bulletin of the South Texas Geological Society, v. 25, no. 6 Reservoir type BA 65 % of storage in matrix. Recovery factor estimated in 25 % after natural declino and gas cap expansion. SW = 10 to 20 in microfractures. 14

17 Conclusions 5 correlation zones are recognized based on differences in seismic features. The presence of wide acid dykes would cause compartmentalization as recognized by differences in the GOC. The key property in order to explain reservoir behavior and potential (within original pressure) is Storage Capacity (MPHE x h) Macrofractures may increase Flow Capacity (STPERM x h) in regions where MPHE x h is low. Higher storage is due to matrix porosity caused by intense micro-fracturing AAPG ICE, Istanbul,