Casablanca Field, a depleted karstic oil reservoir for geological storage of CO2

Casablanca Field, a depleted karstic oil reservoir for geological storage of CO2 Virginie Mignot 1, Yann Le Gallo **1, Jean-Claude Lecomte 1, Tristan Euzen 1, Tomas Vallaure 2, Juan Mallo 2 1 Institut Français du Pétrole (IFP), Rueil-Malmaison, France 2 REPSOLYPF, Madrid, Spain Summary The study of Casablanca field case for CO 2 storage is of major interest for several reasons: offshore reservoir, complex effective porosity network (called fractures in the text) carbonate reservoir related to complex karstic geology and diagenetic evolution of carbonate reservoir, depleted oil reservoir near the end of production, large pressure support due to an active aquifer. Considering the reservoir heterogeneity and the specificity of the data required to assess CO 2 relationships with host rock and fluids at the reservoir, the available data is somewhat insufficient thus, an optimized methodology has been followed to build a consistent reservoir model. This model has been used to study CO 2 injection scenarios and will be used for long term behavior assessment in the near future. The full study will ascertain the ability of this field to be used as a safe geological CO 2 storage. Introduction A main objective of the CASTOR European project is to contribute to the feasibility and acceptance of the concept of geological storage of CO 2 and to validate this concept on real sites. The aim of this project is to develop and apply a methodology for the selection and the secure management of storage sites by improving assessment methods, defining acceptance criteria, and developing a strategy for safety-focused, cost-effective site monitoring. This paper gives some insight of one of the four field cases treated in this project, namely the Casablanca field case. Casablanca oil field, operated by Repsol-YPF is located in the Mediterranean sea on the East coast of Spain, 43 km from Tarragona. The field was discovered in 1975 by Chevron. Its production started in 1977. Cumulative production Casablanca is 143 Mbbls as of August 2005. Since the oil production is declining and the economic limit of the field will be reached in the next few years, Repsol-YPF is evaluating the possibility of using this field for storage of the 0.5 10 6 tons of CO 2 per year produced by its Tarragona refinery (20% of refinery's total yearly production). The Casablanca field case in the CASTOR project has been divided into several steps: geological study, reservoir modeling, forecast of CO 2 injection, wells integrity and long term behavior of the CO 2 in the subsurface. This paper addresses the first three steps of the study with special emphasis on the work methodology. Brief geological description of the offshore Casablanca field. The Casablanca oil-field is located along the Montanazo ridge on the south-east flank of the Tarragona trough and produce oil from karstified and fractured Jurassic-Cretaceous carbonates. It is considered as paleogeomorphic trap (Watson, 1982), as the hydrocarbons were trapped in hills of Mesozoic karst ** Presenter : Yann.le.gallo@ifp.fr, +33 1 47 52 67 45 Corresponding Author : J-Claude.lecomte@ifp.fr, +33 1 47 52 73 04 Full Paper GHGT-8 1

sealed by Neogene deposits. The Casablanca field was sourced from the Early Miocene Casablanca Shale. The oil migration began in early Pliocene in the Tarragona trough. The structure of the field, which measures 1 by 11 km in map view and covers 10.4 km2, portrays the karsted and eroded remnant of a paleotopographic, fault-bounded ridge. Five prominent culminations, representing the tops of buried hills, account for most of the significant oil production from the field (Lomando et al., 1993). The onshore Garraf horst is located along the Catalan Coastal Range, about 20 km south-west of Barcelona between the Vallès-Penedes graben and the Barcelona Graben This horst is limited to the northwest by NE-SW normal faults controlling the onlap of the Neogene sediments on the Mezosoic horst flank and to the northeast by NW-SE vertical strike-slip faults. The onshore Garraf outcrop provides the best general modern analogue for the karst development in offshore reservoirs, because of the preservation of Tertiary morphologies. The analysis of the modern karst system of the Garraf area provides information on the factors controlling the distribution of porosity related to the Paleogene karstification processes. The Garraf outcrop analogue provides useful information about what would be the Casablanca karst system during the Paleogene and its evolution during the rifting and early burial history. The identification of paleomorphologically controlled enhanced permeability zones can be used to interpret reservoir properties at the top of the reservoir, below the unconformity. However, the primary porosity of the Paleogene karst was mostly obliterated as shown by the well cores and outcrop data. The analysis of the outcrops of the Garraf area has shown that the top Mesozoic unconformity is not a sharp surface, but involved locally complex brecciated zones that may correspond to good reservoir bodies (casquetes). Finally, Late Miocene and Pliocene burial history was associated with hydrothermal activity along major faults, fractures and brecciated zones, dramatically enhancing the reservoir properties and responsible for the actual effective porosity network. However, the outcrop data do not provide information on the Late Pliocene hydrothermal karstification and dolomitization observed offshore in the Casablanca field, because of different burial history of the onshore Mesozoic rocks. From regional geological knowledge, from analogue outcrops studies, from well logs interpretation and from long term production data, we have inferred and decided to start static reservoir modeling with the following basic assumptions : - concerning the reservoir matrix petrophysical properties, we will distinguish brecciated zones and non brecciated zones ; - petrophysical properties (porosity and permeability) of the matrix are relatively low except in the north of the structure where vuggy cretaceous sediments are present. Matrix petrophysical properties are unable to explain existing long term production data. - dynamic reservoir behavior of Casablanca field could be mainly explained by opened tectonic fractures and faults, by karstic enlarged open fractures, by reactivated interbreccia porosity and very high connectivity between probable multi-levels of collapsed or filled paleocave systems. Except in the northern part of the field, matrix porosity has not been affected by late corrosive hydrothermal fluids and is influence on productivity will be negligible. As usual in collapsed or filled paleocave systems, it is very difficult to extract detailed information concerning the internal architecture of the reservoir from seismic data. The only seismic valuable information is the actual topography of the reservoir. If in first approximation, we assume that this topography is more or less an image of the paleotopography, it would be possible to identify the surface paleo drainage system and its relationships with karst system. Rain fall drainage system could be associated with karst features, vertical shafts, dolines and paleocave systems and this at different scales (fractal system). On Garraf outcrops, 3D Full Paper GHGT-8 2

polyhedrons structures seem to be limited by fracturation network or swarms. Due to the difficulties to extract relevant information from available data to build a detailed 3D reservoir model, we proposed to apply the following scenario. Static reservoir modeling will be started by following steps : - Top of reservoir will be seismic depth interpretation including upper breccia zone on the flanks. - Base of reservoir will be an estimation of the initial water level. - Simple layering in Jurassic and Cretaceous honoring well data analysis will be provided. - Initial zonation in reservoir in terms of brecciated and non brecciated zones using petrophysical knowledge. - Rough estimate of OOIP (original oil in place) and matrix properties will give indication for % of OOIP stored in effective porosity network ; - Information about paleodrainage system could be used to define model zones. All these parameters will be inferred from existing data (3D seismic surveys, well logs, core descriptions, well test interpretations) and a priori adjusted to realistic values. The pertinence of these basic assumptions will strongly influence quality of final fluid flow reservoir model. From these initial data and hypothesis, different reservoir models will be hydrodynamically tested with respect to the production data history on a well by well basis. IFP Optimisation tools were used to reach this aim in close cooperation with the Repsol team. Construction of a reservoir model of the Casablanca field Methodology used to build a reservoir model of the Casablanca field Due to the scarcity of geological data and to the complexity of the effective porous network, it was not possible to construct a static detailed 3D geological model of the Casablanca field. The chosen methodology was to build a simple reservoir model and refine it iteratively with new geological features to better fit the well production history. This has been done in two main steps: the first one considered simple reservoir models and the second one more complex reservoir models with new geological data integrated during the study. History matching parameters were water production rates and total fluid rates (water and oil, no free gas exist as the reservoir is strongly under saturated due to a very active aquifer) and well bottom hole pressures. Once the model has been considered sufficiently matched, CO 2 injection scenarios investigate its migration in the reservoir. First reservoir models During the first step of the study, the geological data used for the model were the structural top and bottom (OWC) surfaces of the reservoir, no other geological and petrophysical data was available. Two successive reservoir models were used for hydrodynamic simulations: - a homogeneous stratified reservoir model: the highly fractured (understand effective porosity network created by late hydrothermal dissolution) reservoir has been considered first to behave like an equivalent homogeneous reservoir with one permeability ratio (vertical permeability by horizontal permeability), one horizontal permeability and one porosity value determined from the Original Oil In Place value (OOIP). Results of the simulation indicated the impossibility of matching production rates with a homogeneous reservoir model. This first reservoir model has highlighted the necessity of splitting the reservoir into homogeneous stratigraphical strata. - A stratigraphic layering with an average dip angle of 2 degrees to the North was Full Paper GHGT-8 3

subsequently added, based on biostratigraphical data. Porosity was homogeneous in this second reservoir model but horizontal permeability and permeability ratio were different in each strata. The history matching of this first homogeneous layered reservoir model using a history matching optimization IFP software called CONDOR has underlined the possibility of matching the production of some of the production wells. However, it has also shown that it has not been possible to reproduce the sharp and fast water entry on a few wells or the odd behavior of some others. Geological brainstorming One hypothesis for the sharp and fast water production in some wells and difficulty to match their production is the probable existence of fractures corridors (swarms) located in the vicinity of these wells. Outcrop studies along the Spanish coast showed the presence of polygonal fractures arrangement at different scales in similar karstic formations. Those fractures are principally located in low topographic points and could be associated with paleo drainage area. The presence of several stratigraphic layers with an average dip angle of 2 degrees, previously arbitrarily delimited, is verified by a biostratigraphycal and petrophysical study showing the presence of wells markers splitting the reservoir in four stratigraphic strata. The necessity of being heterogeneous concerning porosity, as concerning permeability which is already done, has been underlined by the porosity value given on each well studied. Fractures described previously were modeled by high vertical permeability zone over the entire reservoir model. The different geological and petrophysical layering hypothesis were evaluated using Athos-First, IFP reservoir simulator. The best phenomenological reservoir model with respect to production history matching assumes no fractures corridors, four stratigraphic strata and a layering with a dip angle of 2 degrees to the North. Improvement of the reservoir model, second step Only local porosity values are known and horizontal permeability and permeability ratio values in each strata came from the first reservoir study. A workflow was designed to history matched oil and water productions by optimizing the petrophysical properties heterogeneities and accuracies under available constraints (permeability and porosity range, porosity measurements, production data, pressure and OOIP). As no information existed on the petrophysical property distribution, a particular workflow has been used to adjust both petrophysical properties and their distribution within the Casablanca field. First, the influencing petrophysical parameters (porosity, horizontal permeability and permeability ratio) were identified for each well with an IFP software called COUGAR. Then, automatic optimization on porosity, horizontal permeability and permeability ratio was carried out with an IFP software called CONDOR to history match water and oil production and well pressure. COUGAR which is based on the experimental design approach, ranks the uncertain parameters with respect to a user defined objective function, for instance water rate versus time on a well by well basis. This tool determines and launches the minimum number of fluid flow simulations required to get this ranking. Once the parameter ranking has been done, it is possible to eliminate the uncertain parameters that have a limited influence on the specified objective function. In Casablanca case, fifteen uncertain parameters (only porosity and permeability of the different layers) were considered. Thirty reservoir simulations were required to assess the influence of each parameter and rank them. For each uncertain parameter, an interval between a minimum value and a maximum value was defined. Porosity intervals came from petrophysical data. For K h and K v /K h, intervals, the minimum and maximum values came from the first results of the reservoir study. COUGAR results indicated that each well is influenced by a group of parameters different from one group to another. All parameters had opposite influence on different wells influenced. In the case of "wells incompatibility", hypotheses Full Paper GHGT-8 4

were made to better match well productions and the considered strata was split horizontally (reference to xy zone related to paleodrainage areas) with respect to the studied petrophysical property i.e. a well in each horizontal domain. Thus, petrophysical heterogeneities distribution enable accurate match of the water and oil production rates. The CONDOR tool is designed to perform automatic history matching using several reservoir simulators which, in this study, is Athos-First. After iterations CONDOR obtains the best match using least square optimization of one or several objective functions with the user defined uncertain parameters. In Casablanca field case, the objective function minimized the differences between observed and calculated oil and water rates. Since all wells were not influenced by the same parameters, the optimization was carried for each uncertain parameter out on well by well basis, then kept constant these parameters when matching another well, and so one until all wells were matched. With this approach, one well after the other, the number of uncertain parameters in the model has decreased at each step. This approach has allowed to verify and to guide history matching at each step. Each strata with two wells which could not be matched with the same parameter values, was subsequently split in new zones considering the different values of the parameters before carrying out the matching process. Results Figure 1: History matching evolution in well Casablanca-6 At the end of the matching process, petrophysical parameters distribution and values were optimized. The final reservoir model contains: six horizontal permeability, ten permeability ratio and ten porosity zones. The intervals of values are respectively: 350 md to 2090.5 md, 0.011 to 0.99 and 0.06 to 0.18. These results are consistent with the parameter range provided by Repsol-YPF at the beginning of the study. The permeability are really high with respect since the Casablanca field is highly fractured with apertures up to 3 mm and oil is located only in the fractures and not in the matrix. Concerning the matched parameters, aquifer strength has been matched simultaneously to get the correct pressure variations during production. The aquifer maintain the pressure within 10 bars of the initial pressure. Finally, with the reservoir model with no explicit fractures corridors, with four heterogeneous petrophysical strata concerning porosity, horizontal permeability and permeability ratio and with a layering with a dip angle of 2 degrees to the North, seven wells have been history matched, three wells have been history matched until 2001. Electro submersible pumps (ESP) have been installed on those three wells in 2001 which could be an a priori explanation for the problem of history matching since this date. Concerning the pressure variations during production, the OOIP and the recovery factor, the simulated values were closed to the real one. The workflow optimized the reservoir model of the Casablanca field with the limited available data. Full Paper GHGT-8 5

This workflow helped to understand and define the petrophysical values distribution accurately within the reservoir model. The next step is the simulation of CO 2 injection in the Casablanca field. CO 2 injection The reservoir model described before was matched using a Black-Oil model. However, CO 2 injection requires compositional modeling approach to account for CO 2 dissolution in water and oil. The compositional approach defines the fluid behavior with Peng-Robinson equation of state but requires larger CPU time. The CO 2 injection was modeled using COORES the research fluid flow code dedicated to CO 2 geological storage. Compositional PVT data from the Casablanca field was used to model the dissolution of CO 2 in oil and water at the reservoir conditions. Switching between l from Athos-First to COORES requires minor changes of the datasets as the two software are compatible. Since PVT analyses are still in progress, the CO 2 injection results are still preliminary. The injection was modeled using a Dead-Oil model which enables COORES to compute gas migration within the reservoir. The CASA-11 well, the down-deepest one was selected to injected CO 2 to allow a better sweep efficiency of the reservoir. The scenario considered EOR but with a reduced CO2 injection rate (8 10 4 tons of CO 2 per year) to maintain local reservoir pressure below its initial values thus avoiding any fracturation. This safety constraint strongly restricts the injection potential of the field. The production of all wells but CASA-11 was set to their values at the end of history match CO 2 breakthrough occurred in the neighboring well, CASA-12, after ten year of injection i.e. 8.7 10 5 tons of CO 2. which represents only 1.5 year of CO 2 production from the Tarragona refinery. No significant over pressuring of the reservoir was computed. CO2 EOR optimization strategy is currently investigated. Conclusion The study of Casablanca field case for CO 2 storage is of major interest for several reasons: offshore reservoir, complex effective porosity network carbonate reservoir related to complex karstic geology and late diagenetic evolution of carbonate reservoir, depleted oil reservoir at end of production, huge aquifer maintaining the pressure. Considering the heterogeneity of the reservoir and the specificity of the data required to assess CO 2 relationships with host rock and fluids at the reservoir, the available data is somewhat insufficient thus, an optimized methodology has been followed to build a consistent reservoir model. This model has been used to study CO 2 injection scenarios and will be used for long term behavior assessment in the next future. The full study will ascertain the ability of this field to be used as a safe geological CO 2 storage. We have demonstrated that in such a karstic reservoir with scarce geological data comparing to effective complexity, it is nevertheless possible to build a coherent reservoir model matching well by well more than 25 years of production. The use of an appropriate methodology like previously described in this paper with the help of optimization tools like COUGAR and CONDOR is an effective way to obtain a realistic and efficient reservoir model to start CO2 injection modelisations. Full Paper GHGT-8 6