--> --> Abstract: Geological and Reservoir Characterization of North-Eastern Neuquina Basin Heavy Oil Belt, from discovery to EOR in 3 years (Argentina), by Martín Cevallos, Diego Vaamonde, Nicolás Marot, Gregg Vernon, Bernardo Franco, and Gustavo Fortunato; #90075 (2008)

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Geological and Reservoir Characterization of North-Eastern Neuquina Basin Heavy Oil Belt, from discovery to EOR in 3 years (Argentina)

Martín Cevallos 1, Diego Vaamonde1, Nicolás Marot1, Gregg Vernon2, Bernardo Franco1,  and Gustavo Fortunato1

1Petro Andina Resources Ltd., Maipú 1210 4° P., (1006) Buenos Aires, Argentina
2
Petro Andina Res. Inc., Suite 1000, Energy Plaza East Tower, Calgary, Canada

Summary

Petro Andina Resources (Operator) and Repsol-YPF (50% WI) initiated operations in Argentina in 2004, by acquisition of two blocks in the NE margin of the Neuquina Basin, comprising 1400 sq km. The study area is located northwards from the Colorado River, in Mendoza and La Pampa Provinces, between two major productive regions of the basin, the Agrio Belt to the North West (1.1 BBOE produced) and the Catriel Region to the South East (0.6 BBOE produced). Sparse exploration activities had been conducted by different operators in those blocks over the last 40 years (one well per 100 sq km and 3-4 km spacing 2D seismic). The only two productive well (JCP x-3, 1985; ECo.x-1, 1998) were abandoned due to problems with sand and water production.

The Neuquina Basin (West-Central Argentina) is the most prolific in the country, accounting for 9.8 BBOE of produced and remaining reserves. Currently daily production is 144.5 MBO and 2.8 BCFG. Exploration and development started more than 80 years ago, with the largest discoveries in the 1960’s and a reserves growth step in the 90’s with the advent of 3D seismic. Since then, exploration activity has been mainly focused on the exploitation of previously productive tracts and the search for deeper targets. Meanwhile, non productive regions of the basin remained with sparse exploration activity.

Petro Andina has conducted an aggressive exploration and delineation program triggered by the exciting results of one work over and three wildcats in 2004. This program to date has included the acquisition of 900 sq km of 3D, the drilling of 24 exploration / appraisal and more than 70 delineation / development wells (with more than 300 locations remaining to be drilled). During the exploration and appraisal stages PetroAndina successfully tested unconventional drilling and completion techniques and also implemented three EOR pilots.

The consortium led by Petro Andina executed an aggressive work program, running parallel exploration, delineation and development programs that leveraged off 50 years of Canadian heavy oil experience. In less than three years Petro Andina has had five oil discoveries certifying over 210 MMbbl OOIP (2P, gross).

Current operated production (05/2007) is ~12,000 bbl/day, positioning the company among the top ten oil producers in Argentina. Petro Andina is actively working to expand and develop this under explored play concept.

Geological Setting

Most of the sedimentary section of the basin was deposited in the Jurassic and Cretaceous, in a back-arc depocenter partially connected with the Pacific Ocean in a dominant extensional regime. During High Stand stages, a relatively shallow sea covered the embayment, with anoxic-suboxic black shale deposition at the basin center and broad platforms at the basin edge where clastic and carbonate reservoirs were deposited. During Low Stand stages, Pacific Ocean connection was restricted or closed with the consequent basin desiccation and the initiation of continental basin conditions (fluvial ephemeral, aeolian sand seas, playa lakes, evaporites). This context generated several stratigraphic plays that are proved and well understood in the productive tracts of the basin, but under-explored at the North Eastern basin edge.

In the study area, trap style is dominantly stratigraphic, with both depositional and erosional controls on reservoirs bodies. The updip edges of the pools are defined by subtle angular unconformities and transitions from high tidal energy coastal zones to protected low energy lagoons and back barrier environments. Top seal is provided by shales associated with marine flooding events in the case of Lower Centenario accumulations. The critical updip seal for Lower and Upper Centenario pools is the marginal marine to continental heterolithic section at the base of Neuquén Gr. Basal seals, also critical for the trap configuration, are provided by offshore shales that represent the distal facies of each parasequence. Lateral seals are more complex and controlled by two different processes observed at field scale: tidal sediment bypass areas that resulted in limited sand depositions and early diagenesis (mainly calcareous cementation) in extended areas. Local lateral barriers are caused by sand body shale outs at ebb tidal deltas and tidal channels edges, barrier island cut by tidal creeks, lagoons, etc.

The reservoir units are part of the Centenario Fm (Hauterivian/Barremian). This unit overlies the calcareous-siliciclastic marine deposits of Mulichinco Formation and it is in turn covered by the Neuquén Gr. continental deposits over a major unconformity (basin change from back-arc regime to foreland basin). The Rayoso Gr., that overlies Centenario/Agrio Formations at the basin center is not present in the studied area due to a combination of erosions episodes of the pre-Neuquén Gr sections and non-deposition on the basin edge highlands. The Centenario Formation is composed by two Members (Lower and Upper Centenario). These two members are comprised of a succession of third order sequences built by Transgressive and High Stand System tracts, with general coarsening upward arrangement. The reservoir bodies consist of ebb tidal deltas, tidal channels and barrier islands deposits parallel to the paleo shoreline. Individual reservoir bodies vary from 1 to 5 km wide and eith 1 to 8 m thick. These high reservoir quality rocks shale out basinward to lower shore face facies and to lagoon / back barrier heterolithic deposits to the basin margin.

Reservoir Characterization

Most of the producible oil is hosted in fine to very fine unconsolidated feldespathic-litharenite sandstones, very well sorted and with very low interstitial shale volume (< 5%). Depth ranges from 600 to 700 meters with dipping angles of 1 to 3 degrees. Tertiary and Quaternary surface basalts sheets, together with current arid weather conditions are responsible for a thick vadose zone (around 300 meter thick) resulting in an underpressured regime at reservoir levels (400 psi at 600 meters). These conditions resulted in a high porosity reservoir, ranging from 28 to 34 % of porosity, and high permeability of 1 to 5 Darcies. Subtle variations in grain size alter the productivity and water saturation (increasing inversely with grain size). Although predominantly fine grained sand, reservoirs can vary in proportion of medium, very fine and silty sands. These variations can have a vertically grading arrangement in massive and laminated fashions.

Reservoirs have being divided and mapped at parasequence level, normally 5 to 15 meters gross thickness, and 0.5 to 8 meters net thickness. Each parasequence has a particular fluid distribution, with constant oil / water contacts mappable over 0.5 to 5 km distances. There is a rising OWC arrangement along the strike direction of the stratigraphic traps, from the South East to the North West.

Seismic Interpretation

Stratigraphic plays were identified by review of the sparse well data and the interpretation of 2D seismic that was reprocessed using modern static correction techniques. The interpretation was initially tested through workovers in old wells and by drilling 3 new wells. An initial 200 sq km 3D seismic survey was conducted in parallel allowing improved pools mapping and identifying several new prospects. Key elements of the seismic interpretation were seismic stratigraphic analysis of reflection geometries and amplitude analysis. Bounding surfaces and internal sequence arrangements were identified through the reflector geometry analysis; meanwhile amplitude analysis allowed identification of reservoir sweet spots before discoveries. In the appraisal / delineation stages, 3D seismic played a key role in locating wells optimally for proper evaluation of the reserves and geological framework. After drilling more than 100 wells, the overall regression correlation between seismic signature and net pay is better than 70%.

Heavy Oil Characterization

Production and PVT data show little variation in API gravity and viscosity for the heavy oil accumulations detected so far. Dead oil API gravity varies roughly from 18 to 20° API, with an average of 19 °API. In the same way, oil viscosities vary from 300 to 700 cp for dead oil (160 – 350 cp live oil). This variation in viscosity is small partly because there is only a 1.5°C variance in reservoir temperature over the entire heavy oil trend. The relatively high viscosity for this 19° API oil is related to the in-situ bio-degradation and water washing that the oil has undergone. This crude is naphtenic and acidic, in marked contrast to all prior discoveries in the Neuquen Basin.

The differential liberation data shows bubble-point pressures (180-280 psi) slightly lower than the original reservoir pressure (340-450 psi) for each accumulation. However, on-going oil geochemistry studies and GOR performance suggest that the oil accumulations are probably saturated with gas, which maintains an equilibrium pressure by leaking off through the top seals and/or updip seals and accumulates in shallower reservoirs. These shallower gas pools are now being put on production for own use lease fuel.

Depletion and EOR applied Techniques

CHOPS (Cold Heavy Oil Production) technique had been applied from the beginning of the exploitation. The perforating strategy, the well clean up using PTS (Pump-to-Service) and the use of PCP pumps are examples of common practices applied on every well to encourage sand production and, therefore, wormhole generation. Initial well production ranges from 10 to 70 m3/d of oil, with an average of 35 m3/d. Taking into account the reservoir quality, the well performance and the fluid properties, this primary depletion strategy is expected to achieve a primary recovery factor of 8 to 15%.

In November 2005, a water flood pilot project was initiated in the JCP Field. The objective was to acquire high quality data to understand water injectivity and well behavior. Pressures were measured continuously in all wells within and offsetting the pattern, and pressure response was positive after 8 months of injection. Secondary recovery is expected to range between 20 to 30%. Water flooding will expand to field scale at JCP and ECN commencing in Q3 2007.

Petro Andina is also piloting a steam injection and a horizontal drilling this year. Three wells are being equipped for a huff and puff pilot with steam injection scheduled to start in Q3 of 2007. Additionally, two horizontal wells will be drilled in Q4 2007 to evaluate both cold and thermally assisted production.

Development Strategy

The initial plan was designed to optimize value by accomplishing both production ramp up and reserves growth. The drilling program of each discovery to date has been divided in three stages. The appraisal stage (1-3 months) was designed to address area extension of the pool and to characterize its trapping mechanism. The Delineation Stage (3-8 months) was designed to maximize reserves booking and to collect data for reservoir modeling and production growth; including drilling at 0.5 to 2 km spacing, fluid and rock sample collection and the implementation of an EOR Pilot at a tighter spacing to accelerate response time. The staged development strategy has been very successful in helping develop a balance of analysis of well performance, reservoir simulation, EOR Pilot results and design of facilities capacity on parallel paths.

Conclusion

The study area, an extension outside the “traditional” productive edge of Neuquina Basin, was identified as a potential stratigraphic heavy oil productive trend from logs and existing 2D seismic. Exploration, delineation and EOR pilots were done almost in parallel to mitigate the lack of analogies and infrastructure in the region.

The joint venture has been able to import and apply 50 years of Canadian heavy oil experience to all the activities from the start of the program. The use of aerated drilling mud, improved cementing procedures, the application of CHOPS to enhance production, the advanced lab work, field pilot testing of waterflood and testing of different development spacings has been key to achieving a an economic operation in a new environment.

Innovative ideas, the right people, skills and culture, leveraging Canadian experience in heavy oil exploration and exploitation, and good luck have all been critical in allowing PetroAndina to achieve this success.

Acknowledgements

To all Petro Andina staff who have participated in making the project a success, mainly to: Wayne Foo, Daniel Kokogian, Bill Skinner, Chris Dale, Eric Furlan, Wai Ma, Daniel Ferreiro. To Repsol-YPF, in particular to all staff linked to Petro Andina Operations in Argentina.

 

AAPG Search and Discovery Article #90075©2008 AAPG Hedberg Conference, Banff, Alberta, Canada