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Площадь: 117416.37 км²
Burgos Basin
Geologic Aspects
Situated in the northeastern part of Mexico in the states of Coahuila, Tamaulipas and Nuevo Leon, Burgos basin was originated in the early Tertiary period and covers an area of approximately 110,000 km2. Presently the major activity is centered in the onshore part in an area of approximately 30,000 km2 (PEMEX E&P Provincia Petrolera Burgos, 2013). Geologically, it extends to the north into the Río Grande Embayment in the U.S. Thick sediments from the Mesozoic and Cenozoic eras have been deposit through different periods of regional compression and extension, in addition to the deformation created by shale and salt diapirs (Perez Cruz, 1993). During the early Mesozoic era, Burgos was exposed to extensional tectonic regimes associated with the opening of the Gulf of Mexico. The Laramide Orogeny, developed at the end of the Cretaceous period and during part of the Cenozoic era, caused uplift and folding in the western part of the basin, giving origin to the Fold-Thrust Belt of the Sierra Madre Oriental and the development of foreland basins, including the Burgos basin. (PEMEX E&P Provincia Petrolera Burgos, 2013).
According to the stratigraphic and structural geometry, the basin can be subdivided geologically into five elongated and subparallel N-S production strips that obey primarily marine regressions and extensional faulting activity. These strips, shown in Figure 1 Upper graph shows five production strips trending approximately N-S in the Burgos basin. Lower graph shows structural cross section A-A’ (PEMEX E&P Provincia Petrolera Burgos, 2013)., are referred to as the Jurassic and Cretaceous strip, Paleocene strip, Eocene strip, Oligocene strip, and Miocene strip (Echánove, 1986). The two prospective shale targets are the Upper Cretaceous (Eagle Ford and Agua Nueva formations) and the Upper Jurassic (La Casita and Pimienta formations) as shown in Figure 2 in Chapter One.
Figure 1. Upper graph shows five production strips trending approximately N-S in the Burgos basin. Lower graph shows structural cross section A-A’ (PEMEX E&P Provincia Petrolera Burgos, 2013).
Figure 2. Stratigraphic column of Mexican Basins including kerogen type and TOC (PEMEX E&P, 2012)
The EIA (2013) based on an analogy with the Texas Eagle Ford Formation, determined that the net organically-rich shale thickness within the prospective area in Burgos basin ranges from 200 to 300 ft. However, recent exploration wells amplified the range from 100 to 300 ft. The total organic content (TOC) ranges from 1.95 to 6% and the effective porosity from 1 to 9%. (Parra et al. 2013). The EIA (2013) reported that the vitrinite reflectance (Ro) ranges from 0.85% to 1.6% depending on depth. Most of the reservoirs in the formation are over-pressured with a gradient assumed to be in the order of 0.65 psi/ft. Advanced Resources International (ARI) identified the Eagle Ford Shale in the Burgos Basin to be Mexico’s top-ranked shale prospect (EIA, 2013). Morales Velasco et al. (2010) have also presented an assessment of the Eagle Ford shale in the Burgos basin.
PEMEX made its first shale discovery in the Burgos Basin during the late 2010 and early 2011 while trying to prove the hydrocarbon continuity of the Eagle Ford Shale between Texas and Mexico. Horbury et al. (2013) estimated the overall formation interval across the western margin of the Burgos Basin to range from 100 to 300 m in thickness. This objective of proving hydrocarbon continuity was achieved by drilling the Emergente-1 well in the wet gas window. The well is located a few kilometers south of the Texas/Coahuila border. This was followed by wells Habano-1 and Montañés-1 in the limits of the oil and wet gas windows, and Nómada-1 in the oil window, which resulted non-productive. Figure 3 shows a seismic section that includes well Emergente-1 and four U.S wells drilled through the Eagle Ford shale in Texas.
Figure 3. Seismic view including well Emergente-1 and comparison with wells drilled through the Eagle Ford shale in Texas, USA, including GR and Sonic logs. The U.S. wells produce from the deeper Cretaceous Edwards Formation (PEMEX E&P, 2012).
Engineering Aspects
The exploitation of conventional reservoirs in the Burgos basin began in 1942. To date, 227 fields have been discovered (mostly natural gas). These conventional reservoirs typically have low permeability and are characterized by rapidly declining gas production. On the unconventional side, PEMEX has identified 133 exploration opportunities.
Eagle Ford shale gas well Emergente-1 (Figure 3) was hydraulically fractured in 17 stages using 8 million gallons of slick-water and 42,563 sacks of quartz sand proppant (Parra et al., 2013). The stimulation treatment design was based on log analysis, laboratory evaluation of cores, mineralogy (X-Ray Diffraction and Scanning Electron Microscopy), capillary suction tests, and triaxial geomechanical tests, that helped to characterize the Eagle Ford shale in Mexico. Nonetheless, Araujo et al. (2011) stated that running a Diagnostic Fracture Injection Test (DFIT) was the key to succeed in the treatment. The investment for drilling well Emergente-1 was significant (US $20- 25 million). The well flowed at an initial rate of 2.8 MMcf/d through a 18/64” choke (time interval not reported), which was not economic with current gas prices (EIA, 2013). The lateral was oriented due south and positioned in the organic-rich lower Eagle Ford zone, where TOC reaches 4.5%. However, the learning-curve in the area has been good. The Emergente-1 was drilled completed in a total of five months, while the new wells in the area can be drilled and completed in about one month (Stevens and Moodhe, 2015).
After the successful technical (but not economic) results obtained in Emergente-1, well Nómada1 was completed in the oil window of Eagle Ford formation, but unfortunately, the well resulted non-productive.
Two years later, well Montañés-1 was drilled in the upper Eagle Ford Shale with an azimuth mostly parallel to the expected minimum horizontal stress direction and measured a pressure of 2800 psi, temperature of 169 °F, permeability of 200 nD, effective porosity of 1 to 8% and an average TOC of 1.95%, which increased from 2.71% to 6% the lower Eagle Ford. The well was hydraulically fractured with 14 stages at 55 bpm injection using 180,000 lb of white sand per stage and 2.5 million gallons of fracturing fluid (Parra et al. 2013). Subsequent Eagle Ford Shale wells in the northern Burgos basin tested low-moderate oil and gas rates, much lower than the rates obtained in the Pimienta Formation in the southern part of the Burgos basin. However, it is not clear whether the poorer results in the north are due to tighter rock quality or perhaps less efficient fracture stimulation designs (Stevens and Moodhe, 2015). Well Gamma-1 was drilled in mid-2013 and is considered the well with the maximum horizontal length of 2200 m (Figure 4). It produced disappointing rates of about 0.3 MMcf/d and 12 bpd of oil from the Eagle Ford shale.
Figure 4. Horizontal length and depth of exploration wells drilled in the Eagle Ford shale (PEMEX E&P, 2014).
Following Montañés-1, well Habano-1 was drilled 1 in the Mexican Eagle Ford shale and Anhélido-1 in the Pimienta formation. The Habano-1 was drilled at 3770 m (MD), which corresponds to TVD of about 2,064 m, with a lateral length of approximately 1,493 m. The estimated reservoir properties stemming from this well are as follows: pressure 4,000 psi, temperature 167 °F, permeability ~200 nD, effective porosity from 3 to 9% and TOC from 3 to 5% (Parra et al., 2013). Martinez Contreras (2015) characterized the formation as having a micritic matrix with detrital clay, planktonic foraminifera, sealed with calcite and authigenic clay, and occasional pyrite. Samples measured 54% calcite, 18% quartz, and 19% clay with 9% other minerals.
The Habano-1 well was hydraulically fractured with 16 stages and five perforation clusters per stage. The first eight stages were hydraulically fractured using slick-water. Due to some pressure spikes observed during these stages, the remaining stages used a combination of slick-water and linear gel to place the proppant in the shale formation. The hydraulic fracturing jobs were pumped at 65 barrels per minute (bpm), using a total of 350,000 lb of white sand per stage and approximately 5.1 million gallons of fracturing fluid. The production test yielded a maximum gas production of 4.6 MMcf/d and a maximum condensate production of 146 barrels per day (bpd) while flowing by 28/64” and 26/64” chokes, respectively (Parra et al., 2013). The average wellhead pressure was 2,265 psi. Interval 3,703 to 3,643 m showed commercial production capacity with an initial production of 2.771 MMcf/d gas and 27 bpd crude. The volume of production justified the drilling of three more wells (Habano-21, 71 and 2) that are in production.
The next horizontal well, Anhélido-1, tested the Pimienta formation. Stevens and Moodhe (2015) with a large database established that “the Pimienta Formation is composed of marine-deposited black shale and shaly limestone containing Type II/III kerogen, divided into four intervals with varying concentration of carbonate mineralogy and TOC richness that ranged up to 4%. Tmax ranges from 450 to 454°C, which indicates a condensate to wet gas thermal maturity. The X-Ray Diffraction measured favorably brittle mineralogy: 70% calcite, 1% dolomite, 10% quartz, and 11% illite clay.” Subsequently, based on XRD mineralogy, petrophysics and well log analysis, Granados-Hernandez at al. (2017) indicated that oil prone kerogen type II was the most common and that TOC ranged from 0.5% to 8.5%, weight %. They also identified four lithological members with the following rock properties: porosity ranging from 1 to 19% (6% average); hydrocarbon saturation from 35 to 95% (70% average); bulk volume hydrocarbon from 1 to 13 (4% average), and matrix permeability ranging from 2.5 nD to 4.6 µD.
Well Anhélido-1 was stimulated with 17 stages and five perforation clusters about 1 m long, 20 deep-penetrating shots per meter, 60° phased (Stevens and Moodhe, 2015). The job was performed with a uniform injection using a total proppant mass of 5.1 million lb sand and 12 million gallons of fracturing fluid. The fractured interval is characterized by low clay content and high TOC. It is brittle and homogeneous with a medium-strong fracture gradient from 0.92 to 1.02 psi/ft. The estimated propped fracture length and height were 133 m and 95 m, respectively (Stevens and Moodhe, 2015).
The initial production test achieved a maximum rate of about 500 bpd of 37° API oil with 1.5 MMcf/d of wet gas (24-hour rate). These rates dropped rapidly but stabilized at 80 to 90 bpd and 0.6 MMcf/d of gas after one year with a cumulative production of about 40,000 bbls and an estimated ultimate recovery (EUR) of over 100,000 bbl. (Stevens and Moodhe, 2015). Granados Hernandez at al. (2017) calculated a slightly larger EUR of 120,000 bbls of oil and 0.9 Bscf of gas in 20 years. They made a comparison of various shale formations and observed that Pimienta has approximately twice the thickness of the Eagle Ford shale (Table 1). They further indicated that the resource base in Pimienta is around 2.6 MMBOE/mi2, which is larger as compared with Eagle Ford, Avalon & Bone Springs, and Bakken shales. Although probably not economical at this time, results in this formation show that there are outstanding opportunities in the Burgos basin. Based on experience in the Eagle Ford shale in Texas it is anticipated that there will be increases in productivity with advances in the learning curve. The learning curve includes many different issues such as hydraulic fracturing, completions, surface instalations and the general modus operandi.
Table 1 Comparison of Shale Formations (from Granados Hernandez et. al, 2017).
In 2013, six exploration wells were drilled parallel to the trace of the first wells expanding the prospective limits. Well Tangram-1 encountered 215 m of Pimienta shale in the dry gas window. The well produced dry gas at 10.9 MMcf/d, the highest rate for a shale gas well in Mexico so far. In 2014 horizontal wells Cefiro-1, Nerita-1, Batial-1, and Mosquete-1 were completed with multistage hydraulic fractures in the Pimienta shale. The last well on record now, the Serbal-1, was completed in 2015. The location of these wells is presented in Figure 5 Location of 18 exploration wells drilled from 2010 to 2015 in Burgos and Sabinas Basins (Modified from PEMEX E&P, 2014).
Figure 5. Location of 18 exploration wells drilled from 2010 to 2015 in Burgos and Sabinas Basins (Modified from PEMEX E&P, 2014).
As indicated above the exploration wells were stimulated in highly brittle intervals but high fracture gradient 0.92 to 1.02 psi/ft. However, Medina Eleno and Valenzuela (2010) carried out a hydraulically fracturing job, and years later performed a refracturing operation in the overlying Eocene tight sandstones with a low fracture gradient of 0.58 psi/ft. The fracture closure pressure was 6,150 psi at a depth of 3,217 m. This is an indicator of effective fracturing and refracturing jobs to be kept in mind for future stimulations in the Burgos Basin (Stevens and Moodhe, 2015). Water requirement to perform the stimulations is one of the major concerns in the program.
PEMEX expects to reduce the water requirement to half the volume for every treatment, and to recycle the water used in explorations wells, such as Habano-1 and Arbolero-1.
Resources
Commercial production from conventional reservoirs started in 1945 with the discovery of the Mision field. Production was gas condensate in the Vicksburg play. Pemex started exploring for gas-rich and liquid-rich shale reservoirs in Burgos basin in 2010. Two shale targets were the initial steps of the exploration program: Eagle Ford (Cretaceous) and Pimienta (Jurassic) shales. Emergente-1 was the first shale gas well to be drilled horizontally. It is located on the border of Texas/Coahuila just south of the Rio Grande. Its initial production rate was 2.8 MMcf/d (Dominguez-Vargas, 2014). It proved to be a very important well because it highlighted the shale potential in Mexico as it corroborated the continuity of the Eagle Ford trend from Texas to Mexico. The production history of well Emergente-1 is shown in Figure 6.
Figure 6. Production history of the Emergente-1 well (CNH, 2016).
By 2012, three more wells had been completed in the Mexican Eagle Ford shale (Montañés-1, Nómada-1 and Habano-1), and one well in the Pimienta formation, the Anhélido-1 that produced oil and gas. The oil and gas production of well Anhélido-1 is presented in Figure 1. The well was closed after 431 days due to budget constraints (Granados-Hernandez et al., 2017). The gas production of Habano field is shown in Figure 7. The well Habano-1 is still producing at a rate of 0.31 MMcf/d. These wells corroborated the existence of gas in these formations and were instrumental for preparing plans for the development of these fields (Parra et al., 2013).
Figure 7. Production history of the Habano field (CNH, 2016).
Prospective resources are undiscovered hydrocarbon volumes that are expected to be recovered with an exploratory strategy. Prospective resources of Burgos Basin including oil, condensate and dry gas in 2013 were 10.8 billion boe (PEMEX E&P, 2014). A complete summary of results presented by PEMEX as well as the Energy Information Administration (EIA) is presented in Table 2.
Four more unconventional basins in Mexico have also been identified.
Table 2. Estimated Shale gas and shale oil resources based on studies carried out by PEMEX (2012) and EIA/ARI (2013).
Summary of Published Shale Resources
In 2012, due to the success of wells completed in the Eagle Ford shale in Texas, PEMEX made its evaluation of oil and gas resources in Mexican shales.
Table 2 summarizes results of the studies published by PEMEX in 2012 and the EIA/ARI in 2013. The results are different, but in both instances, there are important indications of oil, wet gas and dry gas in the Mexican basins considered in their studies. It must be noted that at the time PEMEX and EIA/ARI made their evaluations, there were limited geologic data and reservoir information, which obviously affected the estimated volumes. As exploration and development of shale resources are in their infancy in Mexico, it is likely that the volumes shown in Table 2 are conservative.
Based on experience in the United States, it is anticipated that optimization of completions, hydraulic fracturing jobs, refracturing (Urban et al., 2016) and improved recovery methods (Fragoso et al. 2015) will lead to larger recoveries of oil and gas, as discussed in more detail in Chapter 5 dealing with production decline analysis.
Data source: Cruz Luque, M. M. (2017). Evaluation of Cretaceous and Jurassic shales in the Burgos Basin, Mexico (Unpublished master's thesis). University of Calgary, Calgary, AB.
Следующий Бассейн: Western Gulf