Geologic Controls on Production of Shale Play ...

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Geologic Controls on Production of Shale Play Resources: Case of the Eagle Ford, Bakken and Niobrara Manas Pathak*, University of Utah; Milind Deo, University of Utah; Jonathan Craig, Eni Exploration & Production Division; Raymond Levey, Energy & Geoscience Institute Copyright 2014, Unconventional Resources Technology Conference (URTeC) DOI 10.15530/urtec-2014-1922781 This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, U SA, 25-27 August 2014. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitt ed by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does s o at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper without the written consent of URTeC is prohibited.

Summary Recent developments in shale technology have revolutionized oil and gas production in the United States. However, there is still a strong requirement for assessing the prospectivity of emerging shale plays, both in the United States and internationally. This paper is an attempt to generalize the results from three major US shale plays: Bakken, Eagle Ford and Niobrara, and to use these to assess the prospectivity of emerging shale plays elsewhere. Porosity, permeability, total organic carbon (TOC) content, thickness, brittleness, composition and maturity of shales are all important in the generation and retention of hydrocarbons. Factors such as depositional environment, uplift and burial, proximity to porous media, presence of natural factures, and reservoir pressure distribution over geologic time all also affect the ability of shales to retain hydrocarbons and be economically productive reservoirs. As an example, in the Eagle Ford Shale, regional overpressure has been generated through disequilibrium compaction as a result of rapid burial from the Late Cretaceous to the Palaeogene. Post-burial uplift is least in the Central Eagle Ford and the generated over pressure is, therefore, best preserved there. Overpressured shale reservoirs usually have high free gas contents. This is critical for high fluid flow rates from shales. Across the Karnes Trough in the northeast of the play, there is a good seal to the Eagle Ford Formation and, hence, good production, despite the fact that the production from the overlying Austin Chalk reservoir is poor in this area. Thus, the potential of a particular shale reservoir to produce hydrocarbons could be generalized into a “retention” factor. The geologic features that control the retention and production of hydrocarbons in these three shale plays are compared and analyzed. An attempt is made to correlate these factors and their contributions over geologic time scales in order to estimate hydrocarbon in-place in each. The results obtained from the study of these three major shale plays are generalized to provide insights into the relationships between geologic features, retention and production trends for shale plays. ‘Retention’ factor charts are prepared to provide a quick assessment of the prospectivity of emerging shale resources plays. Eagle Ford The Eagle Ford play is a successful US shale play across a large part of Texas. It covers an area approximately 50 miles wide and 400 miles long and has thickness which varies from 50 to 300 feet, at a depth which ranges from 1,500 to 14,000 feet. It overlies the Buda Limestone and is overlain by the famous conventional reservoir of the Austin Chalk Formation. The Austin Chalk consists of interbedded highly fractured chalks, volcanic ash and marls. The Austin Chalk Formation and Eagle Ford Formation reservoirs are parts of the same hydrocarbon system, the hydrocarbons in both being sourced from the south dipping Eagle Ford Formation. The oil in the Austin Chalk Formation is derived from a Type II kerogen and entered the Austin Chalk reservoir through vertical migration from the underlying Eagle Ford Formation.

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The Eagle Ford play deepens and dips southwards and thickens towards the southeast. To the northeast, the formation thins to about 50 feet over the San Marcos Arch and to the northeast of the San Marcos Arch, hydrocarbons from the Eagle Ford charged the Woodbine sands. Continuing farther northeast, the Eagle Ford Formation is absent in the Sabine Uplift. The laterally equivalent Tuscaloosa Formation replaces the Eagle Ford Formation to the northeast of Sabine Uplift and in Louisiana and Mississippi (Lock and Peschier, 2006). The southern limit of the Eagle Ford play runs parallel to the Cretaceous Shelf Edge. It pinches out in the Maverick Basin where the equivalent Boquillas Formations is developed. The Eagle Ford Formation is divided into two intervals in a transgressive and regressive system: The Upper Eagle Ford marks the beginning of a regressive cycle, with deposition in near shore environments. The Lower Eagle Ford is a laminated, organic rich, marine shale which was deposited during the earlier transgressive phase. However, in the Hawkville region (a restricted basin confined between two shelf edges) in the south, the Upper Eagle Ford Formation also consists of dark marine shale. The organic matter in Eagle Ford Formation has been preserved because of the anoxic conditions which prevailed during the period of the Cretaceous Cenomanian - Turonian boundary (Dawson, 2000). The average mineralogical composition of the Eagle Ford Formation is 20% quartz, 50% calcite, 20% clay and 10% kerogen. It has mean porosity of 6% and mean permeability of 180nd (Martin et al., 2011). The maturation of the Type II and Type II+III kerogen in the Eagle Ford Formation occurred in deeper southern parts of the play where the formation passed progressively through the oil, gas condensates and dry gas maturity windows. The migration of hydrocarbons started soon after the generation suggesting the presence of in situ migration pathways along bedding planes within the Eagle Ford Formation (Martin et al., 2011). Due to the absence of traps, the hydrocarbons migrated up dip and northwards until the vertical fractures of the Austin Chalk were encountered and then migrated upwards through these vertical fractures to charge the conventional Austin Chalk reservoir in fields such as Gonzalles and Pearsell (Fig. 1). However, in the parts of the play where the Eagle Ford Formation is thicker and contains stratigraphic traps with enough natural fractures and sealing faults, such as in the Hawkville area (maximum gas producing area of Eagle Ford Play) and in the Karnes Trough (maximum oil producing area of the Eagle Ford) more of the generated hydrocarbons were retained within the Eagle Ford Formation (Martin et al., 2011 and Edman, 2010). In the Karnes Trough, because of good sealing mechanisms within the Eagle Ford formation, there is good production from the Eagle Ford Formation and relatively poor production from the overlying Austin Chalk reservoir. The Eagle Ford Formation is of similar thickness (about 200 feet) and at about the same depth in both the Hawkville and Karnes areas. The different types of kerogen present (Type II & III and Type III respectively) in the two areas accounts for the different hydrocarbon phases (gas and oil respectively) present. There are two possible ways of generating overpressure in shales: (1) rapid burial of the shales, and/or (2) generation of hydrocarbons within the shales. If other parameters stay the same, due to the dominant effect of temperature over the pressure, the gas sorption capacity of the shales decreases as they are buried more deeply: As a consequence, free gas is produced in the formation resulting in a high Gas-Oil Ratio (GOR) if the formation is sealed (Hao et al., 2013). This is critical for high fluid flow rates from shales. If the formation is later uplifted, however, the gas is again sorbed. In the case of an open or partially open system, the free gas may leak and even with increasing gas sorption capacity as a result of the uplift, the shales may be undersaturated as there is insufficient gas left to absorb. Another important implication of increased pore pressure or overpressure is that it will result in fracturing during uplift due to the decrease in the overburden pressure. When the pore pressure exceeds the fracture gradient of the rock, natural fractures are created, enhancing permeability and leading to better production. In the Eagle Ford Play, overpressure has been generated regionally through disequilibrium compaction as a result of rapid burial from the Late Cretaceous to the Palaeogene. The western part of the play has been buried and uplifted and is no longer overpressured, but still has high GOR. Post-burial uplift is least in the eastern part of the play and the generated overpressure is best preserved here (Cander, 2013). Hence, when burial of the formation is involved, the retention of pressure in the formation is not primarily dependent on petroleum generation. The maximum production in Eagle Ford Play therefore occurs in areas with the highest reservoir pressure.

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Figure 1: Migration pathways in Eagle Ford (Modified from Martin et al., 2011)

Bakken The Upper Devonian to Lower Mississippian Bakken Formation in the Williston Basin is one of the most prolific tight oil plays in the US. The source rocks in the Bakken unconventional play consists of organic-rich Lower and Upper Bakken Shale Members (Fig. 2). The Middle Bakken Member consists of interbedded siltstones, mudstones, and sandstones (Pollastro et al., 2013; Smith and Bustin, 1996, 2000). The Williston basin is a large intercratonic depression occupying an area of some 300,000 square miles across parts of North Dakota, South Dakota and Montana. Throughout the Williston basin, the three members of the Bakken Formation are continuous with maximum thickness of 160 ft. near the basin center in North Dakota (Pollastro et al., 2013) and thinning progressively towards the margins of the basins. The three members exhibit an overlapping relationship with the youngest member having the greatest geographic extent and defining the maximum depositional limit of the Bakken Formation. The middle member, together with the Upper Devonian Three Forks Formation which underlies the Bakken Formation are the current target producing horizons. Production is from the areas where the Bakken Formation is thermally mature with respect to oil generation. The presence of a significant thickness of high quality reservoir, overpressure and of optimal organic and geochemical characteristics combine to make the Bakken formation a particularly prolific play. The lower and upper shale members have average TOC contents of approximately 10 and 35 weight percent respectively (Pollastro et al., 2013). Natural fractures are suspected to play a key role in the recovery of oil and gas from the Bakken Formation. Horizontal and vertical natural fractures are present in all three members and are formed as the result of regional tectonics and the development of overpressure due to hydrocarbon generation and expulsion (LeFever, 1992 and Pollastro et al., 2013). Regional tectonic regimes include wrench faulting, compression–extension, fault movement and salt dissolution and collapse.

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Figure 2: Stratigraphic cross section of Bakken Formation (modified from Pollastro et al., 2013)

Other important factors are the migration of hydrocarbons and presence of trapping mechanisms. Like the Eagle Ford Play, production in the Bakken Formation increases with increasing pore pressure (Theloy and Sonnenberg, 2012). However, in contrast to the Eagle Ford Play, the overpressure in the Bakken Formation is due to hydrocarbon generation alone (Pitman et al., 2001). Overpressure resulted in the development of natural fractures which enhanced the permeability and, hence, also the production. The areas in which the Bakken Formation is thermally immature are normally pressured, devoid of natural fractures and act as barriers to the up-dip migration of hydrocarbons from areas where the Bakken Formation is thermally mature. The Middle member of the Bakken Formation is the primary producer and exhibits sandstone and dolomite porosity ranging from 2% to 12% (Sonneneberg and Pramudito, 2009) and permeability of 0.001 md to 7.0 md. The porosity increases with increasing quartz and dolomite content and decreases where cements and clays occupy the pore spaces. Sanish sand is locally developed on top of the Upper Devonian Three Forks Formation in the central Williston Basin (LeFever, 1991) where it is also a target horizon for production. It consists of siltstone, sandstone and dolomite. Niobrara The Niobrara shale is a developing Upper Cretaceous (Coniacian-Campanian) unconventional play in the Rocky Mountain region where thermally mature source rocks are interbedded with low permeability chalk, shale and siltstone reservoirs. Thermogenic gas is produced from the deeper parts of the Piceance basin which are within the gas generation window and in northern Montana (Bowdoin Basin). Thermogenic gas and oil occurs at depths greater than 6000 feet, but in the deeper and thermally matured parts of the Niobrara Play, burial diagenesis (chemical and mechanical compaction and cementation) has reduced the porosities to less than 10%. However, natural fractures compensate for the loss of porosity and make the deeper Niobrara Play particularly prolific. The Niobrara Play is a dual porosity system with both fracture and matrix porosity. Biogenic gas is produced from chalk reservoirs in the eastern part of the Western Interior Cretaceous Basin in northeastern Colorado. The Western Interior Cretaceous Basin is a complex foreland basin of Cretaceous age. The basin has thickest strata in western margin (Fig. 3) (Mountainous areas, Wasatch front). Claystones and sandstones dominate the succession in the western part of the Western Interior Cretaceous Basin along with source rocks. These grade laterally into calcareous shales in the east. The TOC content of the shales increases eastwards as the siliciclastic content decreases and the carbonate content increases. TOC is 2-8% in the east but reduces to 1-3% in the west of the Western Interior Cretaceous Basin

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(Landon et al., 2001). The Niobrara shale was buried between 1,000-15,000 feet more than its present depth because of sediment loading. The Tertiary strata were partially eroded during a period of regional Neogene uplift. As in the Eagle Ford Play, this uplift and erosion caused natural fractures to develop in the formation as the effective stresses decreased during the uplift. In the Niobrara Play, however, fracturing occurred because of combined effect of Laramide tectonic activity, Neogene extension and hydrocarbon generation. The Niobrara shale was deposited in a foreland basin in the Western Interior Cretaceous seaway of North America during a period of major marine transgression (Sonnenberg, 2011; Longman et al., 1998). This major transgression probably reflects the maximum sea level highstand and correlates with the period of major source rock deposition throughout the world. Chalks were deposited during the transgression, while marls and shales were deposited during periods of regression accompanied by freshwater run-off due to high rainfall and climate warming. The deposited organic matter was preserved on the seafloor under anoxic conditions as a result of the development of a vertically stagnant water column and was subsequently buried. Niobrara is a general term given to 4 chalky and 3 marly intervals in eastern part of the Western Interior Cretaceous Basin. The basal chalk unit, the Hay’s Member is the purest limestone. It is overlain by Smoky Hill Member which contains 6 organic rich sub-members (Hann, 1981; Sonnenberg, 2011) which vary from marls and chalky shales to chalks. The Mancos shale is the equivalent shale /siltstone unit to the Niobrara in the western part of the region. The shales in the Mancos/ Niobrara successions are dark-grey and generally organic rich (>1% weight percent TOC). They are the source rocks and also the seals for the chalky and sandy reservoirs in the west and the east of the Western Interior Cretaceous Basin respectively.

Figure 3: Generalised cross section of Western Interior cretaceous Basin (Modified from Sonnenberg, 2011)

Warm water from the Gulf promoted carbonate production, while cooler Arctic water and siliciclastic input from the west inhibited carbonate deposition in the west. The source rocks in the play are organic rich with TOC contents varying from 0.5 to 8 wt% (Longman, 2011; Sonnenberg 2011) with an average of 3%. The kerogen is dominantly type II oil prone. As discussed above, the reservoir facies change from east to west across the Western Interior Cretaceous Basin. In the Niobrara, the reservoir facies consists of interbedded shaley limestone, marls and chalks in the east and shalier and siltier facies in the west. Mechanical and chemical compaction (diagenesis) reduced the porosities and permeabilities to such a degree that natural fractures are, again, critical for good production. The overpressure generated as a result of the Neogene tectonics is largely responsible for the natural fractures developed in the Niobrara shale.

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Chalks are the primary target of horizontal drilling in the east because they are more brittle and ‘fracable’ than marls and calcareous shales. However, there is also production of hydrocarbon from fractured marls in the central fractured sand and silt facies in the western part of the Western Interior Cretaceous Basin. The presence of good reservoir facies (brittle chalk), a well-developed fracture network, mature source rocks, and a favorable tectonic history for fracture formation make the Niobrara a prolific play. Conclusion, Generalization and Retention Chart The analysis of these three major U.S. shale plays demonstrates that geological factors, such as porosity, permeability, TOC, thickness, mineralogy, maturity, reservoir pressure, tectonic history and the presence of natural fractures, are the primary controls on the amount of hydrocarbon retained in these unconventional petroleum systems. An attempt is made here to quantify the ability of these systems to retain the hydrocarbons by assigning a ‘retention factor’ to the main geological factors in order to develop ‘retention charts’. The scale for the retention factor of each geologic parameter is kept consistent throughout the analysis to predict the relative prospectivity of the shale plays. The weighting factors (wi) of each geological parameter is defined as the weight the geologic parameter carries in defining the overall prospectivity of the play. In this analysis, the weights and maximum values of the scale used for each factor are based on data in the public domain for the three shale plays and can be changed in the light of additional information and on the basis of personal knowledge. The ‘retention charts’ (Table 1a and 1b) can be used to quickly assess any emerging shale play by comparing it with known plays or to compare regions within a play. Retention Chart

Geologic Factors Porosity Permeability Trapping TOC Maturity Mineralogy (composition, mechanical property) Natural fractures (fracture porosity) Reservoir pressure Total

Weighted Retention Factors Eagle Middle Ford Bakken Niobrara 6 7 5 4 7 6 7 8 7 3 5 2 5 6 5

Scale 0-10 0-10 0-10 0-10 0-10

Weights (Wi, 0-1) 0.8 0.8 0.9 0.6 0.7

Weighted Scale 0-8 0-8 0-9 0-6 0-7

0-10

0.8

0-8

6

7

5

0-10 0-10

0.5 0.5

0-5 0-5 0-58

3 4 38

4 4 48

3 3 36

64.41

81.36

61.02

% Retention Table 1 (a): Retention chart for three shale plays

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Scaled Maximum 8

Corrosponding value 12%

8

Millidarcies range

Trapping

9

Enough stratigraphic and structural traps to retain the hydrocarbon in the formation

TOC

6

>15% by weight (Mean Value)

Maturity

7

Ro = 0.6-1.3

Mineralogy (composition, mechanical properties)

8

Have fractures/ fracable with good reservoir properties

Natural fractures (fracture porosity)

5

Highly fractured as a result of combination of burial, hydrocarbon generation and tectonics

Reservoir pressure

5

1.0 psi/ft

Geologic Factors Porosity Permeability

Table 1 (b): Table providing actual values corresponding to the scaled maximum for each geologic factor

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