Exploration Insights March 2020

8 | Halliburton Landmark Exploration Insights | 9 Legend A Tuwaiq Mountain-Hanifa Hanifa Vaca Muerta B Vaca Muerta 20 Eagle Ford 80 Wolfcamp Barnett Bakken 50 50 GDE — LST GR Source Unit RES Fracture Baffle 20 m 700 MFS Maximum onlap of organic-rich facies Maximum downlap of deep-marine carbonate MRS 750 Unit 2 SB 800 SB Organic-rich facies with thin intercalated carbonate = target zone MFS SB Unit 3 850 MFS Intercalated area = HSD MFS MRS SB MFS SB Gross Lithology Organic-rich Mudstone Shallow Carbonate Deep Carbonate Shallow Claystone Continental Clastics Grainstones Reworked Sequence Stratigraphy Unit 1 Thick brittle carbonate = fracture barrier SB MFS Homogeneous orgain-rich facies - High TOC = High pay MRS (Maximum Regressive Surface) SB (Sequence Boundary) MFS (Maximum Flooding Surface) Source Unit Fracture Baffle Landing Zone Induced Fracture Network (Generalized vertical extent — equivalent to the Stimulated Rock Volume) © 2020 Halliburton Figure 4> A) Middle–Late Jurassic Resource Interval. B) Vaca Muerta-Quintuco Resource Interval. Note the similar stratigraphic architectures and lithological variability of these low-angle carbonate ramp systems. C) High-graded stratigraphic domain (HSD) concept illustrated in map and cross-section views. D) Applying the HSD concept to a Vaca Muerta type well. Each HSD contains three distinct units with different lithological and geomechanical properties. This stratigraphic organization can be anticipated within a sequence stratigraphic framework and used to better understand the distribution of landing zones and fracture baffles. permeability is significantly enhanced within fracture zones (>2000 mD). Fracture density and connectivity are highly variable and are impacted by structural features (e.g. proximity to faults), depositional facies, bed thickness, and diagenetic overprint. Tight plays can be enhanced by structural and stratigraphic trapping mechanisms. For the Austin Chalk, structural trapping is important, with migrated hydrocarbons trapped within hanging wall fault blocks and broad anticlines. Stratigraphic trapping mechanisms are also common, with the low porosity and low permeability unfractured rock matrix forming an effective top and lateral seal. Based on an understanding of the analogous Austin Chalk play, exploration and appraisal of Middle–Late Jurassic tight carbonate play concepts within the Middle East should focus on areas in which fractured carbonates are juxtaposed with mature source rocks, enabling simple migration pathways into self-sealed fracture zones. Within the producing Najmah (T1) Monterey Legend D Intercalated Area — HSD (map view) and Sargelu (T2) tight plays in Kuwait, fracture density increases with proximity to major faults. Additionally, the degree of natural fracturing is strongly impacted by the mechanical stratigraphy, with considerably lower fracture density found within argillaceous carbonates with higher clay content (Al-Failakawi et al., 2019). These relationships are analogous to those observed within the Austin Chalk, where fractures are concentrated on downthrown fault blocks and within thick chalk benches that lack ductile marl intercalations. Mineralogy Analogue: Eagle Ford The Tuwaiq Mountain and Hanifa plays (S1 and S2) are carbonate-dominated (> 95 wt%) with very low clay content (Hakami et al., 2016) (Figure 5). This results in a brittle unconventional reservoir that is very conducive to hydraulic fracture stimulation. This high carbonate content differentiates the Tuwaiq Mountain and Hanifa formations from the majority of established North American resource plays. Haynesville 80 Silica 20 20 50 80 Carbonate GDE — MFS C Marcellus Figure 5> Ternary plot depicting the average mineralogical composition of the Tuwaiq Mountain play, and various established resource plays. Data derived from Hakami et al. (2016) (Tuwaiq Mountain Formation), Marchal et al. (2016) (Vaca Muerta play), and Allix et al. (2010) (North American resource plays). The Eagle Ford, onshore U.S. Gulf of Mexico, is often regarded as the closest analogue to the emerging Tuwaiq Mountain shale play (e.g., Hakami et al., 2016; Almubarak et al., 2017), as it is also a carbonate-dominated (>60 wt%) resource play with a minor clay and silica fraction (Clemons et al., 2016). For this reason, the Eagle Ford is used to inform reservoir completion and production forecasting in the emerging Tuawaiq Mountain shale play. Indeed, the initial reservoir completion designs tested in the Tuwaiq Mountain play are analogous to the Eagle Ford, and production is benchmarked against this play (Almubarak et al., 2017). The impact of increased clay content on well performance within the Eagle Ford play is highly applicable to the Jubaila play (S3). In the Eagle Ford play, there is an increase in clay content to the east of the San Marcos arch, which is closely associated with degraded unconventional reservoir quality and lower production rate from lateral wells (Clemons et al., 2016). Because the Jubaila Formation has a relatively high clay content, the unconventional reservoir is likely to be more ductile, and — based on the Eagle Ford analogue — poorer well performance is anticipated. For this reason, the Jubaila play is considered the least attractive shale play target. Porosity Development Analogue: Marcellus The primary driver of unconventional reservoir quality within the Tuwaiq Mountain (S1) and Hanifa (S2) plays is total organic carbon (TOC), because an increase in TOC corresponds with increases in porosity, permeability, and hydrocarbon saturation within the unconventional reservoir (Hakami et al., 2016). This is because the vast majority of porosity within the Tuwaiq Mountain Formation (~90%) is organic hosted (Hakami et al., 2016). Since organic porosity is derived from the breakdown of kerogen, the pores become more interconnected during maturation, increasing permeability, and are intrinsically saturated with the generated hydrocarbons. The majority of established shale plays provide hydrocarbon storage capacity in organically- hosted porosity and matrix porosity (and in some cases, fracture porosity). The proportion of organically-hosted to matrix-hosted porosity can vary significantly between plays. Analogues for understanding the controls on unconventional reservoir quality within the Tuwaiq Mountain and Hanifa shale plays should have a similar porosity- type distribution, skewed toward the organic- hosted endmember. The Marcellus play in the U.S. Appalachian Basin is an excellent analogue for understanding porosity development in the Tuwaiq Mountain and Hanifa plays, because the vast majority of porosity is also organically hosted (Zagorski et al., 2017). Well production rates within the Marcellus play are sensitive to TOC (Figure 6A). Strong well performance within the Southwest Core production sweet spot of the Marcellus play, in northwestern Virginia and southwestern Pennsylvania, is principally driven by extremely high TOCs (8 to 12 wt%), despite the relatively thin gross thickness of the resource interval (10 to 40 m) (Zagorski et al., 2017). As organically-hosted porosity is generated during the breakdown of kerogen during maturation, another important consideration is the thermal maturity within the play. Production sweet spots within the Marcellus play are all within the gas window (>1.35 Ro equivalent) (Zagorski et al., 2017). Wells drilled within the oil window have generally underperformed (Figure 6B), which might partially reflect increased viscosity of the hydrocarbon phase, as well as a reduction in organically hosted porosity.

Exploration Insights March 2020 | Page 8