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ESTANCIA DOS LAGUNAS: PRODUCING GAS AND CONDENSATE FROM A VOLCANIC ROCK IN THE ARGENTINEAN AUSTRAL BASIN

Leandro Venara 1, Gloria Bahl Chambi 1, Andrés Cremonini 1, Marcelo Limeres 1

1. Chevron Argentina S.R.L. Keywords: 1. volcanic; 2. Tobífera; 3. gas; 4. unconventional; 5. Estancia Dos Lagunas.

Abstract The development and production behavior of an unconventional reservoir is presented. The Estancia Dos Lagunas gas field was discovered in 1999 by Petrolera Argentina San Jorge. The field is located in the South of Argentina (Santa Cruz Province), in the Austral Basin. The structure was developed with the drilling of 16 wells, most of them producing from the Serie Tobífera. This unit is composed of volcanic and volcaniclastic rocks deposited during the rifting stage of the basin. Historically, the Serie Tobífera was considered the economic basement of the basin. However, in some cases these volcanic rocks have good reservoir properties due to primary and secondary processes. The characterization of this unconventional reservoir is far from being understood applying conventional log analysis and seismic interpretation. Therefore, the reservoir analysis has to be done using all the available information (seismic data, electrical logs, mud logging, core analyses, production tests and pressure data). The comparison of the static information with the actual dynamic behavior of the wells helps gaining a better understanding of the field. Finally, the dynamic and well production behaviors are analyzed. Lessons learned can be used for analog developments.

1. Introduction The Estancia Dos Lagunas (EDL) gas field is located in the South of Argentina (Santa Cruz Province), approximately 110 kilometers to the Northwest of Río Gallegos city, in the Austral Basin (Figure 1). The field belongs to the Campo Bremen block and was discovered in 1999 by Petrolera Argentina San Jorge and acquired in 2000 by Chevron Argentina. Other developments in the block are the Campo Bremen gas field and the Filomena oil field. The discovery well was Estancia Dos Lagunas x-1 (EDL.x-1), which tested gas and condensate from the Springhill Formation sandstones (main reservoir of Austral Basin). Later, the consequent field development, led to the discovery of hydrocarbons in the Serie Tobífera volcanic and volcaniclastic rocks which have become the major reservoir of the field. Sixteen wells have been drilled in the structure. With the exception of three of them that produced from the Springhill Formation, all are productive from the Serie Tobífera volcanic rocks at an average depth of 1,675 meters below ground level (m.b.g.l.). The total structure area is 25 km2 and the total cumulative production up to December 2008 is 65,600 MMscf (1,860 MMm3) of gas and 1.35 x 106 bbl (214 Mm3) of condensate. The produced gas has a condensate gas ratio (CGR) of 21 bbl/MMscf (120 m3/MMm3) and is classified as a “wet gas”. Gas dehydration and conditioning are performed in the Campo Bremen facilities and exported to the General San Martín gas pipeline. Historically, the Serie Tobífera was considered the economic basement of the basin, however during the last two decades an important number of discoveries have been made in this unit. Thus, the Serie Tobífera became a secondary or upside objective in most of the prospects of the basin. Several studies have been conducted (Hinterwimmer, 2002; Sruoga and Rubinstein, 2002; Sruoga et al., 2004; Sruoga and Rubinstein, 2007) which made important contributions to the understanding of the nature of the processes that generate reservoir conditions in the Serie Tobífera volcanic and volcaniclastic rocks. The aim of this paper is to present a case study of gas and condensate production from a non-conventional reservoir, such as the Serie Tobífera igneous rocks. The techniques applied to characterize the reservoir, plan well completions, optimize production and operational experience will be discussed. The lessons learned during the development of the EDL field can be valuable for the study of analogous fields.

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2. Geological Setting – Location and Stratigraphy The Austral Basin, also known as Magallanes Basin is located in the southern tip of South America and covers part of the present territories of Argentina and Chile (Figure 1). The limits of the basin are the following: to the North, the Deseado Massif; to the East, the Río Chico Ridge; to the South and West, the Andean Fold and Thrust Belt (Sruoga et al., 2004).

Figure 1. Estancia Dos Lagunas field location. The Austral Basin has two main structural domains, an eastern one dominated by normal fault-related structures and a western one characterized by the Andean Fold and Thrust Belt (Biddle et al., 1986). The EDL field is located in the eastern province, which is characterized by a general structural pattern of Northwest to North-Northwest oriented normal faults. This structural pattern gave origin to a paleo-topography dominated by grabens and half-grabens. The geotectonical evolution of the basin can be summarized into three stages: rift, sag and foreland phases (Robbiano et al., 1996). The stratigraphy of the basin is characterized by a Paleozoic metamorphic basement, which is overlain by Late Jurassic silicic volcanic and volcaniclastic rocks (Biddle et al., 1986). This unit has been defined as Serie Tobífera by Thomas (1949), and its rocks were originated during the rift stage of the basin. Sruoga and Rubinstein (2002), Sruoga et al. (2004) and Sruoga and Rubinstein (2007) mentioned that the Serie Tobífera is the subsurface equivalent of the lithostratigraphic unit called Chon-Aike Province. Also, Bruhn et al. (1978) and Gust et al. (1985) correlated the Serie Tobífera to another unit, the volcanic province of Patagonia. The extrusion of the Serie Tobífera volcanic and volcaniclastic rocks led to the generation of a paleo-relief, that exerted a great influence on the distribution of the overlying unit, called Springhill Formation, a basal transgressive sandstone, that constitutes the main reservoir of the basin. The age of this psammite is Late Jurassic to Early Cretaceous (Biddle et al., 1986). The rest of the sedimentary fill is mainly pelitic with sandstones interbedded and it is composed by units with ages that range from Late Cretaceous up to Late Tertiary. Figure 2 displays a stratigraphic column of the studied area.

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Figure 2. Austral Basin Stratigraphy.

3. Field Description The studied field is located in the Campo Bremen block, an exploitation concession operated by Chevron Argentina. Between 1965 and 1991 all the exploration and development activities were carried out by YPF, the former national oil company of Argentina. During that period of time 1,200 kilometers of 2D seismic data were acquired, as well as thirty four exploratory and development wells were drilled. In 1991 Glacco took over the operation of the block and during its management drilled one exploratory well. On August, 1997 Petrolera Argentina San Jorge acquired Glacco and went on with the operation. Since the acquisition of Glacco and until 1999 the new operator reprocessed 1,200 kilometers and acquired 99 kilometers of 2D seismic data, acquired 450 square kilometers of 3D seismic data and drilled eight wells (exploratory and development). Finally, in 2000 Chevron Argentina took over Petrolera Argentina San Jorge and continued the operation of the concession up to the present.

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The EDL field was discovered in 1999 by Petrolera Argentina San Jorge with the drilling of the EDL.x-1 well. The objective of that well was to explore a structural high and to evaluate the hydrocarbon potential of the Springhill Formation sandstones and the Serie Tobífera igneous rocks. During the completion, the well tested gas in the Springhill Formation. Later, as a result of subsequent drilling activities, hydrocarbons were also discovered in the volcanic and volcaniclastic rocks of the Serie Tobífera. The EDL.a-3 well tested gas during completion but it was never put on stream. Following the confirmation of gas existence in the Serie Tobífera, the field development was carried on, with the drilling of thirteen more wells. In most cases (twelve) gas and condensate were tested and put on stream from the igneous unit. The trap is a structural high that can be described as a Northeast-Southwest oriented anticline, segmented by two conjugate fault systems, one with a Northwest-Southeast strike which is coincident with the regional structural trend and the other one with a Northeast-Southwest strike (Figure 3 and Figure 4). This structural high has an area of 23 km2. It configures a “bald high” devoid of Springhill Formation sandstones sedimentation, which is constrained to the flanks (Figure 5). The source rock is represented by claystones and shales of the Lower Palermo Aike Formation and its lateral equivalents. These pelitic sediments constitute also the vertical seal. Although some wells have produced gas and condensate from the Springhill Formation sandstones (EDL.x-1, EDL.a-2 and EDL.a-6), the main reservoir of the field is constituted by the igneous rocks of the Serie Tobífera, which will be described more deeply in the following section. According to pressure data obtained from RFT tests, the gas water contact (GWC) was established at 1,402 meters below sea level (m.b.s.l.) (Figure 5). This is ascertained by the fact that several wells have tested water below that depth, for instance EDL.a-3 (Figure 5). On the other hand, the two deepest gas down to (GDT) were established in EDL-15 and EDL.a-10 (Figure 5).

Figure 3. Estancia Dos Lagunas Field. SSW-NNW Arbitrary Seismic Line.

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Figure 4. Estancia Dos Lagunas Field. Top Serie Tobífera Depth Structural Map.

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Figure 5. Estancia Dos Lagunas Field. SW-N Structural Cross Section.

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4. Reservoir Characterization During the exploratory stage, as well as during the field development, several Serie Tobífera intervals were cored. Laboratory studies on basic petrophysics, sedimentology, petrography, X ray diffraction, scanning electron microscope, etc. were performed. Based on the previously mentioned studies, the Serie Tobífera rocks were characterized lithologically as massive vitric tuffs, light greenish gray, light olive gray, grayish green and pale gray in color. These rocks have been petrographically classified as ignimbrites, dacitic to rhyolitic in composition with slight degree of welding, high proportion of vitric material as matrix and subordinated crystalloclasts and lithoclasts. Vitroclasts are abundant and are represented by shards and pumice fragments, mainly flattened, forming fiammes. In some cases, the pumice fragments are slightly altered to clays. Crystalloclasts are, in general, homogeneously distributed and are composed of quartz (in some cases fractured) and generally subordinated plagioclase and potassium feldspar. Lithoclasts are composed of tuffs, andesites and schists. Following the definitions established by Llambías (2003), the Serie Tobífera deposits in the EDL field can be classified as high-grade or reomorphic ignimbrites. On the other hand, according to the results of the petrographical studies and following the principles and conclusions established by different authors (Sruoga and Rubinstein, 2002; Sruoga et al., 2004; Sruoga and Rubinstein, 2007), it was determined that the pore system is mainly generated by primary processes (i.e. processes related to the pre-emplacement and the final cooling phases that are developed under closed-system conditions) and modified by secondary processes (i.e. processes that are developed under open-system conditions once the cooling phase is ended). As it was pointed out before, the primary processes were the main mechanism of the pore system generation. Several primary processes led to the development of different porosity types. They were identified through macroscopic and microscopic analyses. For instance, slight degree of welding led to the generation of intershard and intrapumice pores (Figure 6); gas release processes caused gas pipes (Figure 6 and Figure 7) and vesicles; deuteric crystal dissolution processes produced intracrystalline pores (Figure 8). On the other hand, the secondary processes modified the original petrophysical properties of the rocks. The occurrence of these processes caused in some cases an improvement and in other cases a deterioration of the pore system characteristics. The secondary processes that have affected the Serie Tobífera rocks in the EDL field are mainly glass dissolution, which generated false shard mold pores that improve the petrophysics (Figure 8), and silicification processes that affected negatively the original reservoir conditions (Figure 9). The EDL-7 well is an interesting example in which porosity and permeability are seriously affected by silicification (Figure 9 and Figure 10). The porosity and permeability data from core analyses show a high spread (see porosity vs. permeability plot, Figure 11). Porosity ranges from 5 % to 35 % approximately, while permeability values range from 0.005 md to 100 md. High differences can be observed between the plug samples and the full diameter samples of well EDL-7. The plug samples correspond to the silicified cored interval in which, both porosity and permeability, are negatively affected; while the full diameter samples correlate to the non-altered cored interval in which the petrophysical properties are much better.

Figure 6. Detail at the microscope of gas release pipes (red arrows) and intrapumice porosity (yellow arrow).

Well EDL-7 – Depth 1,694.10 m.

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Figure 7. Well Alto Dos Lagunas x-1 core photograph showing gas release pipes (red arrows).

Figure 8. Detail at the microscope of false shard molds generated by glass dissolution (yellow arrow) and intracrystalline pores originated by feldspar crystalloclast dissolution (red arrow). Well EDL.a-4 – Depth

1,623.13 m.

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Figure 9. Well EDL-7 core photograph displaying Serie Tobífera interval with no reservoir conditions (silicified interval).

Figure 10. Well EDL-7 core photograph displaying Serie Tobífera interval with reservoir conditions.

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Log Kh vs. Porosity - Serie TobíferaEstancia Dos Lagunas Field

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Figure 11. EDL field - Serie Tobífera core data. Gas Permeability (Kh) versus Porosity chart. (References: P

(Plugs) and FD (Full Diameter samples)). Taking into account the igneous origin of the Serie Tobífera, the log evaluation of this unit presents great difficulties. The use of ordinary techniques, such as Archie’s equation to estimate the hydrocarbon saturation, cannot be applied. As a consequence, the Serie Tobífera reservoir characterization requires an integrated data collection and analysis in order to predict its hydrocarbon potential. The latest wells drilled in the basin have proved, as mentioned by Hinterwimmer (2002), that the reservoir characterization of these igneous rocks should be done integrally. Not only the log information should be taken into account but also other data (seismic data, mud logging, core analysis, production tests and pressure data). In three different cases (wells EDL-7, EDL.a-11 and EDL-15) the total gas readings, along with hydrocarbon shows data, were taken into account at the moment of deciding which interval to perforate (Figure 12, Figure 13 and Figure 14). Also, the total gas readings are a valuable tool to infer the GWC, as it can be seen in EDL-7, EDL-12 and EDL-15 (Figure 12, Figure 13 and Figure 15). Furthermore, in well EDL-12 the identification of a “drilling break”, i.e. a sharp increase in the rate of penetration between 1,695 m and 1,700 m, helped to recognize an interval with reservoir conditions. In addition to the “drilling break”, hydrocarbon shows were also found in the same depth interval (Figure 15). On the other hand, and regarding seismic data, amplitude anomalies have been detected in the field area. Hence, a seismic inversion process was performed and as a result of it, low impedance zones were identified (Figure 4). All wells were drilled inside these zones with the exception of EDL.a-3, a well that was never put on stream due to low productivity.

Figure 12. Well EDL-15 – Composite Log.

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Figure 13. Well EDL-7 – Composite Log.

Figure 14. Well EDL.a-11 – Composite Log.

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Figure 15. Well EDL-12 – Composite Log.

5. Fluid Properties Separator gas chromatographies are available for twelve wells. No significant differences are observed among them. The initial CGR was about 21 bbl/MMscf (120 m3/MMm3) and condensate gravity is about 83º API. There is no significant variation in the observed historical CGR (see production profile, Figure 17). No dew point exists at reservoir temperature. The fluid is classified as “wet gas”. The same result is obtained using McCain’s Fluid Classification (McCain, 1994). The phase envelope is estimated using the PVTP Petex software (Figure 16). For the estimation of gas-fluid parameters, dry gas correlations were used. A mathematical recombination of the separator gas and the condensate was performed to estimate the composition of the wellstream. (Figure 16) The average reservoir temperature is 212ºF (100ºC). It was estimated by static gradients (reference depth: 1,402 m.b.s.l. (GWC)).

Recombined Fluid - Phase EnvelopeEstancia Dos Lagunas Field

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N2 3.7784 0 3.8676CO2 0.0313 0 0.0320C1 86.2894 0 88.3259C2 4.3259 0 4.4280C3 1.9531 0.0380 1.9983iC4 0.5114 0.1289 0.5205nC4 0.7306 11.7562 0.4704iC5 0.4736 13.7624 0.1600nC5 0.3100 9.9450 0.0826C6 0.5742 22.9182 0.0468C7 0.5667 22.0264 0.0602C8 0.3592 15.3367 0.0057C9 0.0730 3.0796 0.0020C10 0.0168 0.7291 0C11 0.0055 0.2366 0C12 7.12E-04 0.0309 0C13 1.61E-04 0.0070 0C14 8.53E-05 0.0037 0

C15+ 3.69E-05 0.0016 0

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Figure 16. Phase envelope and recombined gas composition.

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6. Production History The gas production from the Serie Tobífera began with Alto Dos Lagunas x-1 well (ADL.x-1) in 2000. Several drilling campaigns were carried out until 2005 (see production history, Figure 17). Wells producing from the Springhill Formation (EDL.x-1, EDL.a-2 and EDL.a-6), are not included in the graph as those wells represent only a small percentage of the total field cumulative production. The Serie Tobífera cumulative production up to December 2008 was 58,000 MMscf (1,650 MMm3) of gas and 1.20 x 106 bbl (190 Mm3) of condensate. Two different compression systems exist in the EDL field. The historical wellhead flowing pressure values follow two different trends (Figure 18). The reduction from high and medium pressure to medium and low pressure systems and the consequent production increase in 2006 are observed. The produced fluids of EDL and Campo Bremen fields are treated in the same dew point plant and exported to the General San Martín gas pipeline. The usual well completion is 5 ½-in. production casing and 2 ⅞-in. tubing. Reservoir water breakthrough has been observed in most wells. The water gas ratio (WGR) shows a steep increase in 2006 after the back pressure was reduced. Wells with gas rate above the liquid loading threshold rate (0.9 MMscf/D, 25 Mm3/d) continued production with only small reductions on gas rate (see Figure 19, ADL.x-1 well production data), while wells with low gas rates reduced completely their production. The structural position of the wells has no impact on early water production. Wells in the highest positions like EDL.a-5, EDL-13 and ADL.x-1 are producing reservoir water earlier than the structurally lower positioned EDL.a-10 well, indicating water encroachments from the bottom of the tuff rather than an aquifer approaching from the flanks of the structure.

Production History - Estancia Dos Lagunas Field

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Figure 17. Production History.

Well Head Pressure History - Estancia Dos Lagunas Field

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Figure 18. Well Head Pressure History.

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7. Well Productivity and Stimulations Moderate well productivities have been achieved. Initial well productions vary between 2 MMscf/D (60 Mm3/d) and a maximum of 6 MMscf/D (170 Mm3/d) (ADL. x-1). The well productivity is monitored estimating a productivity index for each individual production test. Well ADL.x-1 is given as an example of the historical values (Figure 19). The K1 factor (ratio between pseudopressure and gas production rate) has been used as an indication of productivity. Smaller K1 factors correspond to higher productivity. A progressive decrease on productivity can be correlated with WGR increase. K1: productivity index (psi/ (cp-scf/D)) Pws: bottom hole shut-in pressure (psi) µ: gas viscosity (cp) µ(p): gas pseudopressure (psi/cp) Pwf: bottom hole flowing pressure (psi) Z: ideal gas deviation factor The same K1 factor has been correlated to the estimated net pay for each well (Figure 20), observing an increasing productivity trend (smaller K1) for increasing net pay. Several hydraulically fractured wells, mainly EDL-7 and EDL-9, show good productivity although they have small net pay, which indicates a good effectiveness of those stimulations. Concerning acid stimulations, HCl-HF has been performed in almost all wells during the completion. In most cases good production increase could be established. During 2004 and 2005, a stimulation campaign was performed using acetic acid with additives. Coiled tubing equipment was used for the interventions. Diverse results were obtained. Well EDL.a-4 increased its potential (no stimulation was performed during completion). Wells EDL.a-5 and EDL-7 maintained their productivity, while EDL-8, EDL-14 and EDL-15 decreased their potential.

ADL.x-1 Productivity Monitoring

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Well Productivity Analysis

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Figure 20. Well productivity analysis.

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8. Pressure Data and Material Balance The initial reservoir pressure was 2,119 psi @ 1,407 m.b.s.l. (RFT ADL.x-1). The latest static pressure gradient campaign shows a range between 1,130 psi and 1,560 psi (Figure 21, pressure history). Depletion was observed in the wells initial shut-in pressure when zones close to producers were developed. However, the spread on pressure values shows a relatively weak dynamic connection throughout the structure. A shut-in period of 24 hours was routinely used for static pressure gradient surveys. This time has proved to be too short, since longer stabilization periods have been used in the latest campaign in April 2008. Higher stabilized pressure values were obtained in the same wells when the shut-in period was extended. A shut-in period of one week, confirming well head pressure stabilization, is recommended for future measurements. A material balance was performed for the whole structure as a single tank. The P/Z plot (Figure 21) shows a large spread on pressure data. Splitting the structure into separate tanks was not possible since no clear pressure trends could be identified for different zones of the structure. Z values were obtained from a dry gas correlation. Taking into account the latest surveys (longer shut-in periods as explained before) an OGIP between 120 and 200 Bcf (3,400 and 5,700 MMm3) was estimated. The OGIP estimated from volumetrics presents a high range of uncertainty. Porosity cut-off, net-thickness, and gas saturation values are, as described in the reservoir characterization section, very difficult to establish. An OGIP range between 150 and 250 Bcf (4,250 and 7,100 MMm3) was calculated. The comparison with the dynamic estimation leads to the conclusion that zones of the reservoir that are located further from the wells or have low permeability are being drained at lower rates and maintain higher pressure values. If operation allows it, more frequent pressure surveys and longer shut-in periods can help reducing the uncertainty on the dynamic estimation. In both dynamic and static OGIP estimation (and hence, reserves estimation) a relatively high degree of uncertainty remains.

Reservoir Pressure - Estancia Dos Lagunas Field

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Figure 21. Pressure History, RFT and Static Gradients. P/Z plot.

9. Conclusions The Estancia Dos Lagunas Field has been described. Geology, reservoir characterization, development history and dynamic information have been analyzed. As stated in earlier studies related to the Serie Tobífera, it has been confirmed that primary processes have strongly influenced the pore system generation. Reservoir characterization was performed using all available information from seismic data, electrical logs, mud logging, core analyses, production tests and pressure data. The traditional analysis of clastic reservoirs cannot be applied. The well productivities can be classified as moderate. HCl-HF acid stimulations showed good productivity increases, as well as hydraulic fracture stimulations. Most wells showed water encroachments, but only small production reductions were observed in wells with enough liquid loading capacity. A well productivity monitoring method based on the pseudopressure equation was used to evaluate the effect of stimulations. Due to the complex reservoir characterization, high uncertainties in volumetric OGIP estimations exist. For the reserves calculation, the frequent shut-in pressure surveys are crucial for the estimation of production forecasts from dynamic models.

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Acknowledgements We acknowledge Chevron Argentina for making the resources and information available for this technical paper. Many thanks to Darío González, Alejandro Luppi, Cristina Masarik, John Peters, David Robledo and Carlos Wickenhagen for their contributions.

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