The authors thank Halliburton management for permission to publish this work and Mike Mullen (President of SPC) for discussions and time spent teaching.
SPE 167707 Shale and Tight Reservoirs: A Possible Geomechanical Control in the Success of Producing Wells, Neuquén Basin, Argentina Mariano N. Garcia, Federico Sorenson, and Hernan Stockman, Halliburton; Carlos Zavala, GCS Argentina Copyright 2014, Society of Petroleum Engineers This paper was prepared for presentation at the SPE/EAGE European Unconventional Conference and Exhibition held in Vienna, Austria, 25–27 February 2014. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract Many tight and shale-oil gas reservoirs are being explored in Argentina to increase local hydrocarbon production. As known, hydrocarbon resources in the Neuquén basin are massive; however, many are far from being developed to the degree that they can be called resources. Significant work has yet to be done to make this happen. It is also well known that large areas in the Neuquén basin are under strike-slip stress conditions that may be a strong influence on stimulation effectiveness. After analyzing the production results of several wells and their associated oil/gas fields, a hypothesis was developed that suggests a possible relationship between the tectonic framework and the location of successful wells. This hypothesis might not only explain the productivity results of some wells to Vaca Muerta shale and other tight reservoirs, but also could help in locations of new wells to help reduce investment risks and improve productivity. This analysis compares aspects from structural geology, petrophysics, and completion descriptions observed in different fields to productivity results. Information included in this paper is sufficient to improve understanding of the conditions for a good or bad well based on this hypothesis; therefore, these lessons can be applied to generate conclusions. Introduction The Neuquén basin in southwestern Argentina is considered one of the richest basins in South America for unconventional oil/gas resources. This basin was formed in the Late Triassic period and filled during the Jurassic and Cretaceous with a marine to continental sedimentary column up to 7-km thick. In recent years, the understanding of the hydrocarbon potential of Late Jurassic/Early Cretaceous marine shales of the Vaca Muerta formation has dramatically changed the exploration paradigm in the basin. According to estimates by state-run energy firm YPF, the Vaca Muerta shale oil and gas field has 661 billion barrels of oil (BBO) and 1,181 trillion cubic feet (tcf) of natural gas resources. These data have encouraged an aggressive drilling campaign initially in areas located close to conventional reservoirs, currently with varied success. The goal of this paper is to introduce some case histories and discuss possible control guidelines in the effectiveness of wells targeting tight formations and shale reservoirs in mature fields. Geologic Framework Stratigraphy. Located in west-central Argentina (Fig. 1), the Neuquén basin contributed with 37.9% and 54.2% of Argentina’s total oil and gas production, respectively, in 2012. This basin was defined as a back-arc ensialic basin generated by thermal-tectonic collapse of a complex framework of Paleozoic accreted terranes behind a stationary magmatic arc during the Late Triassic (Mpodozis and Ramos 1989; Ramos et al. 2011). Its sedimentary infill occurred mainly during the Jurassic and Cretaceous, with a clastic and minor carbonate/evaporitic succession up to 7,000-m thick (Fig. 1). In the southern area, basin fill and evolution has been controlled by the interaction of the magmatic arc and subduction area (east-west efforts) with the still active North Patagonian massif (southeast-northwest efforts), resulting in a variety of syn- and post-depositional tectonic structures (Bettini 1984; Mosquera et al. 2011).
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Fig. 1—Location map (A) and generalized stratigraphic column (B) of the Neuquén Basin (modified after Zavala et al. 2006).
Basin infill comprises at least three stages: the first stage (Late Triassic–Early Jurassic) is characterized by the deposition of volcanic and volcaniclastic materials (Precuyo Gp), having a high variable thickness and a restricted distribution controlled by half-graben occurrence. The second stage (Early-Late Jurassic) is represented by a mainly clastic prograding continental to marine succession (Cuyo and Lotena groups) deposited over a tectonically-induced irregular relief. Several tectonics episodes and sea level changes occurred during deposition, resulting in a pronounced control on the facies changes and geometry of their related units. The third stage (Late Jurassic–Late Cretaceous) is composed of a thick marine to continental succession (Mendoza, Rayoso, and Neuquén groups). These deposits have the more extensive geographical occurrence in the basin, and their thickness changes more regularly. Sea level changes and minor tectonic movements control the development of internal depositional cycles. Fig. 1 shows a generalized stratigraphic column for the basin, with an indication of the main conventional reservoirs and source rocks. Conventional gas and oil production in the basin (Fig. 2) is mainly concentrated in three areas: 1) the basin center, which is primarily a gas-bearing zone, 2) the north-eastern platform, and (3) the Huíncul arch (Hogg 1989). Main source rocks belong to the third stage (Vaca Muerta and Agrio formations, Fig. 1), although the Los Molles formation (second stage) and the Precuyo group (first stage) have organic rich levels with high oleogenetic potential (Legarreta et al. 2008). Conventional reservoirs are relatively common in the three stages, but their optimum characteristics frequently depend on structural, stratigraphic, and diagenetic factors. The increasing interest in producing unconventional resources (mainly shale) in the basin has recently opened new and exciting exploration perspectives.
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Fig. 2—Location of main conventional reservoirs in the Neuquén basin (after Hogg 1989).
Structural Evolution. According to its location between the Andean front belt (west) and the North Patagonian Massif (southeast), the Neuquén basin records a relatively complex tectonic history (Mosquera et al. 2011), characterized by (1) an initial rifting (Late Triassic); (2) punctuated inversion of ancient normal faults (NW-SE compressional efforts during the Toarcian–Valanginian) mainly affecting the Huincul Arch and associated structures during the Early Aluk phase (Mosquera and Ramos 2006); (3) Late Cretaceous (Cenomanian-Maastrichtian) W-E compressive deformation during the Farallón Stage (Mosquera et al. 2011); (4) Miocene W-E compression during the Nazca stage associated with the development of the Agrio foldbelt (Zamora Balcarce et al. 2006); and finally (5) the extensional collapse of axial structures in the Huincul Arch during the Pliocene (Mosquera and Ramos 2006). The progressive change in the orientation of compressional efforts between the NW-SE to W-E during the Mesozoic and Cenozoic resulted in a dominance of dextral pull-apart structures in the northern margin of the Huincul Arch (Silvestro and Zubiri 2008). The Case-Study Area As previously discussed, the northern margin of the Huincul Arch is mainly in a strike-slip stress condition. Under this stress condition, there are associated faults and structures, as shown in Fig. 3.
Fig. 3—Pull-apart and contractional structures typical of strike-slip stress conditions (from JPB 2011).
Even though there are many combinations of type of structures, they can be classified into three groups: extensional, contractional, and quiet. Because most of the study area is under the strike-slip stress condition, this classification can cover
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most of the case examples. Fig. 4 shows an example of different structural conditions in the surroundings of a strike-slip fractured area.
Fig. 4—Deformational structures related to a strike-slip stress regime (modified from JPB 2011).
Even though the typical analysis of the far-field stresses suggests strike-slip stress conditions, for specific locations such as extensional areas (pull-apart), the stress condition could be normal, or at least the horizontal stress anisotropy could be much lower compared to the quiet zone, even though it might still be in a strike-slip stress condition. For the case of the contractional areas (push-up), the local stress condition might still be strike slip but with a higher horizontal stress anisotropy. To summarize, it is understood that, using a basin or field-scale view, most of the area is under a strike-slip stress regime; however, using an infield scale, it might be found that more relaxed (pull-apart) or stressed areas (push-up) exist. In the Neuquén basin so far, conventional high-permeability reservoir rocks have been developed, so fields normally have been drilled in the surroundings of faulted areas and structural traps. Besides this, exploratory wells are always drilled away from faulted zones to establish the field´s limits or some other targets, such as evaluating hydrocarbon saturation in tight reservoirs with stratigraphic traps. Similar events occur when the objective is a shale reservoir. The object of interest could be the faulted area or not, looking for the presence of more natural fractures and system permeability. In different shales in the US, the objective of operators can change from reservoir to reservoir. For example, in the Bakken, looking for faulted areas might be beneficial, while the opposite seems to occur in the Barnett (Bowker 2007). Determining this for the Vaca Muerta and Molles shales is a difficult and expensive endeavor. In this study, two well types are defined with a difference in their position with respect to local structural conditions. Well Type A was drilled in a quiet, non-faulted area or far from them, and Well Type B was drilled inside the extensional faulted area, as shown in Fig. 5. Hypothesis A typical well, which will go on to produce from a reservoir rock, would be Type B. In many cases, it is understood that faults might have worked as conductive pathways through which the reservoir rock was charged with hydrocarbon from the source rock. At the same time, it could be understood that the source rock was partially depleted in the surroundings of this extensional faulted area. At the contractional area, fractures might work more as seals rather than conductive pathways because of high friction and possible damage across faults.
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Fig. 5—Well type diagram depending on structural condition (modified from JPB 2011).
It is understood that Type B wells drilled to produce from shale might not be as good producers as Type A wells because of their partial depletion, while Type B wells producing from reservoir rocks should be better than Type A wells producing also from the reservoir rock (keeping in mind that only tight reservoirs are included). On the other hand, reserves associated with Type A wells should be much larger than those associated with Type B wells. Next, existing examples of wells drilled in the Neuquén basin in the extensional and quiet zones with objectives of shale and tight gas reservoir rocks are discussed to better understand these situations. Shale Wells Case Histories Two case histories are presented. Vertical wells were drilled and completed with very different productivity responses, where it was understood after analysis that the main reason for such a different production result could be attributed to the structural conditions of each well type. Case 1. Case 1 includes two different wells, which will be called A and B. Well A was drilled in the quiet zone from a structural point of view, and Well B was drilled at the extensional zone. Because both were exploratory wells, a good set of logs and core data were available. Figs. 6 and 7 present the petrophysical interpretation. For each well, the mineralogy, total organic content (TOC), elastic properties, matrix density, and porosity were calibrated to core data. Additionally, and because all core data were available, an estimation of bbl of oil/acre was performed to compare resources available for each case. This estimation was built using S1 results from a pyrolysis tests.
Fig. 6—Well Type A with cumulative resources estimation of 151,027 bbl/acre from S1.
Fig. 7—Well Type B with cumulative resources estimation of 145,953 bbl/acre from S1.
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By no means are these considered accurate estimations of oil/acre. Instead, the relative values between both wells are the focus in lieu of the absolute values. Both wells are in the same field, at similar depth, and there is no reason to think that burial or maturity history are very different. Both wells were completed in a short time frame and with a very similar approach using the same type of fracturing fluids, chemistry, and proppant pumped by the same service company. Of course, it is impossible to say that exactly the same procedures were performed for each or that the reservoirs are identical; however, the reservoirs and completion were very comparable. A lower oil rate would be expected from Well B because it has one less fracturing stage, but that is not the main highlight identified. Well A started and kept flowing naturally for at least six months. Well B required gas lift installation just a few days after the flowback, suggesting that the reservoir was not able to communicate its pressure to the wellbore. Of course, the very first and most common thing to consider is some type of fracture/formation damage. Extensive analysis were run to determine any type of problems related to quality control (QC) of the fluid, proppant crushing, embedment, etc. As presented by Garcia et al. (2013), several laboratory tests were run to evaluate and minimize formation and fracture damage while stimulating the Vaca Muerta formation, as was the case in these two wells. Nothing really suggested that any issues existed related to QC or formation/fracture damage. Figs. 8 and 9 show examples of one fracturing treatment chart from each well. It can be observed that treating pressures, instantaneous shut-in pressures (ISIPs), and the fracturing plan were very similar. Besides any type of analysis that could be performed with pressure response, microseismic was run at each well to help understand the stimulated reservoir volume (SRV) for each case. In looking at the total oil/acre numbers that were calculated for each well, for the case of Well B, it is surprisingly 10% lower than for Well A, which had good oil production with high wellhead pressure for at least six months. Would it be possible to think that Well B was only able to produce what is available in the matrix? Its location suggests the possible presence of many more natural fractures, so system permeability might have helped the oil to leak from the source rock to the reservoirs (which have been producing for many years in this part of the field).
Fig. 8—Well Type A fracturing treatment.
Fig. 9—Well Type B fracturing treatment.
Case 2. Case 2 includes three different wells also completed in a relatively short time. Two were completed by the same service company. Only one well would qualify as Type A (quiet zone), which had very good production and was naturally flowing for at least 250 days. The other two wells were Type B (extensional zone) and required gas lift very soon in their production history, as shown in Fig. 10. Of course, cumulative production from Well A was much higher than the other two (Fig. 11).
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Fig. 10—Oil rate and cumulative oil from the three wells.
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Fig. 11—Shale oil log interpretation of the Type A well.
As was the case for the wells from Case 1, the petrophysics from these three appeared very similar. Completion of the Type B wells (lower production) were performed, each one by different service companies and also with even bigger treatments than Well A. Case 2 is a less mature and shallower field than Case 1; however, a similar production profile was identified for similar well types, from a structural point of view. Type A wells are better producers, with higher wellhead pressure than Type B wells, all producing from the Vaca Muerta formation. Tight Gas Wells Case Using the same criteria as with the shale wells, two example wells are included that were drilled with the objective of producing from a tight gas reservoir. A Type A well was drilled in a quiet zone, and a Type B well was drilled in an extensional zone, both in the same field and completed with the same technology, proppant type, and fracture designs in a short time frame but by different service companies. Figs. 12 and 13 present the log interpretation for each case. It should be mentioned that also for this project, core data were available from other wells, so a reasonably good understanding of the rock properties was available. Also, it should be mentioned that for the last five years, there has been extensive work in this field trying to characterize the reservoir, working not only with petrophysical data but also with elastic properties, geomechanics, completion, production, and reservoir modeling information. From a geomechanical understanding, it was observed that pore pressure was in the order of 0.67 psi/ft and horizontal stress anisotropy was in the order of 4,400 psi (0.35 psi/ft) for the quiet typical zone within this field. This being said, it is understood that hydraulic fractures tend to develop the common bi-wing geometry because of high horizontal stress anisotropy. Support for this understanding is that, as a general rule in this field, when performing a production history match, only primary porosity and permeability were required in the reservoir model. Quite often, in many other reservoirs, dual permeability/porosity models are required to history match production when geomechanical conditions are present and proper stimulation techniques are applied.
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Fig. 12—Tight gas well interpretation of the Type B well.
Fig. 13—Tight gas well interpretation of the Type A well.
For these wells, a diagnostic fracture injection test (DFIT) was performed on each zone before fracturing. Table 1 shows a summary of the transmissibility estimated from calibrated logs and the estimated values from the DFIT. For Well Type A in a quiet zone, the estimated values from the logs agree with those from the DFIT; while for Well Type B in the extensional zone (more relaxed stress condition compared to Well A), transmissibility from the DFIT was much higher than that calculated from the logs (primary permeability). It is understood that this KgH difference in Well B might by associated with the presence or capability to reactivate planes of weakness in the rock. Pore pressure for both cases was the same. TABLE 1—SUMMARY OF KgH FROM LOGS AND DFIT Well A Logs (KgH) DFIT (KgH)
Zone 1 0.65 0.68
Well B Zone 2 0.68 0.62
Zone 1 1.41 2.7
Zone 2 0.56 3.12
Production from Well B was 2.5 times higher than production from Well A. Performing a production analysis from Well A, it was concluded that an average 200 to 250 ft of infinite conductive fracture half-length was present, which is understood to be normal in this field (Fig. 14).
Fig. 14—Production history match of Well Type A to different effective fracture half-lengths.
Production results for Well Type A should not be viewed as a poor result. It produces according to the matrix properties and a bi-wing propped fracture length. Its production might be improved by generating a longer effective fracture length, but
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it is beyond the scope of this work to discuss whether this would be the best method or if it was economic. The production profile is normal at these wells and could change from well to well, mainly because of matrix KgH and effective fracture half-length. A benefit from this reservoir model is that the economics of the project can be built based on a Well Type A characteristics to create less investment risks. Summary It is understood that for the Neuquén basin, when developing tight reservoir rocks, reservoir KgH (md-ft) and effective fracture length play a critical role in productivity; however, sweet spots could be found at locally relaxed zones (extensional) because, at these less-stressed areas, secondary permeability could be developed while stimulating the reservoir if completion is properly performed. To summarize, if well location and completion type are correct, then production from these Type B wells might be much higher than from the average Type A well in the same field drilled in a typical quiet zone (in a strikeslip stress condition). However, the resources associated with these “sweet spots areas” might not be as large as the ones associated with average Type A wells. On the other hand, when developing shale reservoirs (this applies not only for Vaca Muerta), it is understood that the outcome could be very different. At quiet areas (Well Type A), productivity could be higher than at extensional areas (Well Type B). At the same time, resources associated with Type A wells should be much larger than with Type B wells. With this being said, it is understood that resources from shale reservoirs can have very high probability to become reserves (with the related recovery factor) and could help with the economics of developing tight reservoirs in quiet zones if production from shale and tight reservoirs is comingled at vertical wells. Even though it might be basic for many, the importance of combining the understanding of the following items for reservoir and source rocks should be emphasized: • Primary porosity and permeability. • Leakoff type during DFIT. • Reservoir pore pressure. • Local stress condition and its changes across the field, as well as the different structures, faults, and lineaments. Acknowledgments The authors thank Halliburton management for permission to publish this work and Mike Mullen (President of SPC) for discussions and time spent teaching. Nomenclature KgH = Transmissibility. SRV = Stimulated reservoir volume References Bettini, E.H. 1984. Pautas sobre cronología estructural en el área del Cerro Lotena, Cerro Granito y su implicancia en el significado de la dorsal del Neuquèn, provincia del Neuquèn. IX Congreso Geológico Argentino, actas 2: 342–361. Bowker, K.A. 2007. Barnett Shale Gas Production, Fort Worth Basin: Issues and Discussion. AAPG Bulletin 91 (4): 523–533. García M.N., Sorenson, F., Bonapace, J.C. et al. 2013. Vaca Muerta Shale Reservoir Characterization and Description: The Starting Point for Development of a Shale Play with Very Good Possibilities for a Successful Project. Paper URTeC 1508336 presented at the Unconventional Resources Technology Conference, Denver, Colorado, USA, 12–14 August. Hogg, S.L. 1993. Geology and hydrocarbon potential of the Neuquén Basin. Journal of Petroleum Geology 16: 383–396. JPB. 2011. http://www.files.ethz.ch/structuralgeology/JPB/files/English/1Introtecto.pdf (accessed September 2013). Legarreta, L., Villar, H.J., Cruz, C.E. et al. 2008. Revisión integrada de los sistemas generadores, estilos de migración-entrampamiento, y volumetría de hidrocarburos en los distritos productivos de la cuenca Neuquina, Argentina. In: Cruz, C.E., Rodríguez, J.F., Hechern, J.J., Villar, H.J. (eds.), Sistemas Petroleros de las Cuencas Andinas. Instituto Argentino del Petróleo y el Gas, Buenos Aires, 79–108. Mosquera, A. and Ramos, V.A. 2006. Intraplate deformation in the Neuquén Embayment. En: Kay, S. and Ramos, V. (eds.): Evolution of an Andean margin: a tectonic and magmatic view from the Andes to the Neuquén Basin (35°-39°S lat), Geological Society of America, Special Paper 407: 97–123. Mosquera, A., Silvestro J., Ramos, V.A. et al. 2011. La estructura de la dorsal de Huincul. En Leanza, H. et al. (eds.) Geología y Recursos Naturales de la Provincia del Neuquén, 17º Congreso Geológico Argentino, Relatorio 385-398, Neuquén. Mpodozis, C. and Ramos, V. 1989. The Andes of Chile and Argentina. Ericksen, G.E., Cañas Pinochet, M.T., and Reinemund, J.A. (eds.) Geology of the Andes and its relation to hydrocarbon and mineral resources. Circum-Pacific Council for Energy and Mineral Resources, Earth Sciences series v.11, Houston, Texas, USA. Ramos, V.A., Mosquera, A., Folguera, A.Y. et al. 2011. Evolución tectónica de los Andes y del engolfamiento neuquino adyacente. En Leanza, H. et al. (eds.), Geología y Recursos Naturales de la Provincia del Neuquén, 17º Congreso Geológico Argentino, Relatorio 335-344, Neuquén. Silvestro, J. and Zubiri, M. 2008. Convergencia Oblicua: Modelo estructural alternativo para la Dorsal Neuquina (39°S) – Neuquén. Revista de la Asociación Geológica Argentina 63 (1): 49–64.
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Zamora Balcarce, G., Zapata, T., Del Pino, D. et al. 2006. Structural evolution and magmatic characteristics of the Agrio fold-and thrust belt. En: Kay, S.M. and Ramos, V.A. (Eds.): Evolution of an Andean margin: A tectonic and magmatic view from the Andes to the Neuquén Basin (35°-39° S lat), Geological Society of America, Special Paper 407: 125–145. doi:10.1130/2006.2407(06). Zavala, C., Ponce, J., Arcuri, M. et al. 2006. Ancient Lacustrine hyperpycnites: a depositional model from a case study in the Rayoso Formation (Cretaceous) of west-central Argentina. Journal of Sedimentary Research 76: 40–58.
