The Cretaceous Eagle Ford of South Texas is a major unconventional play. Age equivalent rocks are present in the adjacent Burgos Basin, Mexico along with other unconventional targets in the Jurassic. The objective of this study was to map areas of unconventional potential from basinwide maturity predictions provided by 3D modeling. This study has identified oil, wet gas and dry gas areas of interest for the Cretaceous and Jurassic targets. These areas of interest can then be used to focus followup studies by companies or institutions evaluating joint ventures and/or lease sale blocks in the basin.
The 3D model for the Burgos Basin was made using publicly available information. Regional structure maps were made by integrating published structure maps and cross sections. Structure maps, temperature gradients from well logs and a tertiary erosion map were the key inputs used to model maturity. The Cretaceous Agua Nueva and the Jurassic La Casita/Pimienta Formations were the primary zones of interest. Rock maturity data was available for one Cretaceous and one Jurassic well. The model was also verified by comparing to Cretaceous and Jurassic unconventional well results.
Structural strike of the Eagle Ford in south Texas is southwest to northeast. Near the border structural strike abruptly changes to nearly north - south. In the Burgos Basin, the Mesozoic section dips eastward toward the Gulf of Mexico due to over 30,000 feet of Tertiary sand and shale deposition. Faulting in the Tertiary section generally soles out above the Mesozoic, so the Mesozoic is mostly tectonically undisturbed which is favorable for unconventional targets.
The prospective area for the Cretaceous and Jurassic is essentially coincident and is over 40 miles wide and 300 miles long. The prospective area was defined according to depth and modeled vitrinite reflectance equivalence (VRE). Measured depths of 5,000 to 15,000 feet and VRE greater than 0.8 were used. The rationale was that shallower than 5,000 feet would have low pressure and temperature and greater than 15,000 feet would have too high a well cost for horizontal wells. The oil prospective area is from 0.8 to 1.1 VRE, wet gas from 1.1 to 1.7 VRE and dry gas over 1.7 VRE. Oil spacing was assumed to be 100 acres and gas spacing 200 acres. Total recoverable resources are estimated at approximately 27 BBOE of which 15% are liquids (oil and condensate) and 85% are gas.
Post-production performance after hydraulic fracturing has been studied for decades. Most of the issues that arise are related to drainage area and low pore pressure after the fracture is created. The goal of hydraulic fracturing is to always try to maintain the original reservoir pressure while still providing the best geometry possible. Treatment options vary, depending on the pressure and capacity of the formation to return fluids pumped to minimize face damage.
Some tight-gas wells respond very well to new, improved fracturing techniques, and proppant-carrying fluids have been continuously modified to reduce damage in the formation. But, for some wells, such as the gas fields in the Burgos basin in North Mexico—located in the North-East area of the country and bordered with South Texas in the USA—problems still persist.
This is especially problematic in unconventional gas reservoirs, such as ultralow-permeability or tight-gas sands. When fracturing, the damage mechanism must be mitigated to help prevent fracture face damage. By reducing fracture face damage caused by the use of conventional surfactants, which absorb rapidly within the first few inches and result in fluid phase trapping, relative permeability, and wettability issues, substantially increased regained permeability can be achieved in unconventional reservoirs, with the primary purpose using surfactant-reducing surface and capillary tension.
This study discusses revised operations where a novel microemulsion (ME) surfactant was used, the fluid recovery that occurred during the cleanout process, and the hydrocarbons production a few months after the stimulation. Also, these wells were compared, as much as possible, to those that received a conventional treatment. Results demonstrate exceptional water recoveries compared with conventional ME surfactant treatments.
Valenzuela, Ariel (Pemex) | Guzman, Javier (Pemex) | Sanchez Moreno, Sabino (Pemex) | Garcia Mondragon, Gabriel (Pemex) | Gutierrez Rodruigues, Luis Alberto (Schlumberger) | Exler, Victor Ariel (Schlumberger) | Ramirez, Carlos (Schlumberger) | Parra, Pablo Alejandro (Schlumberger) | Pena, Alejandro Andres (Schlumberger)
Rivera, Juan Galvan (Pemex) | Carrillo, Alejandro Barrera (Pemex) | Luna, Jose Balbino (Halliburton Energy Services Group) | Garcia, Raul (Halliburton Mexico) | Soriano, J. Eduardo (Halliburton Energy Services Group)
The rapid post-fracture production rate decline observed in both oil and gas wells is normally associated with loss of fracture conductivity, often attributed to invasion of formation fines into the proppant pack, loss of fracture width caused by proppant flowback, and fines derived from proppant crushing. However, recent studies have indicated that solid material generated from a geochemical process in the fracture face known as proppant diagenesis has considerable impact on proppant conductivity.
Although diagenesis is a slow geological process, lab tests show that proppant diagenesis can occur in fractions of a year. Post-fracture rapid production decline in high-temperature/high-stress wells seems to be the main symptom of proppant diagenesis. Recent lab tests have shown that the process can be prevented by isolating the direct contact proppant/ formation through the use of hydrophobic materials.
The liquid resin systems (LRS), a specific type of hydrophobic material, have been used in the industry to prevent proppant flowback. The proppant is coated on-the-fly on location with a LRS. This technology has also proved to increase and sustain fracture conductivity over time. The production data presented in this paper comes from some tight-gas fields located at the Burgos Basin in north Mexico. The formation fractured is an intermediate/high-temperature and high-stress sandstone. The wells previously fractured in these fields historically had a rapid post-fracture production decline rate.
The wells successfully treated with LRS material show a significant production increase compared to untreated offset wells because of a substantial change of the conductivity of the fracture. Based on laboratory experiments on proppant diagenesis and field results, it has been observed that the proppant diagenesis protection treatment provided by the LRS significantly contributed to the production increase of the treated wells.
Rapid production decline rate is associated with the loss of fracture conductivity after hydraulic fracture stimulation. This loss of conductivity has often been attributed to the migration of formation fines into the proppant pack or the generation of fines derived from proppant crushing. Surface modification agents were introduced in the stimulation market around 1997, and according to literature published since then, these materials have been helping to sustain fracture conductivity, and subsequently, mitigating production decline rates.
This paper presents long-term results from the use of these materials in hydraulic fracture stimulation operations in the Burgos Basin in northern Mexico; results from offset wells are also presented for correlation and comparison. Production from this basin comes from low-permeability sandstones normally considered tight gas formations.
Burgos Basin is located in northeastern Mexico along the southern border of the U.S. This gas basin covers more than 50,000 km2 (Fig. 1) and accounts for one third of the reserves of nonassociated gas in the country. The gas fields are located along well-defined bands that extend across the shared border between Mexico and the U.S. They are complex, sandy reservoirs, higly compartmentalized, and made up of a great number of small independent blocks characterized by very low permeability. Sustaining a high production level in this area requires a large number of wells to be drilled and hydraulically fractured.1
Burgos Basin gas production started in the mid-Forties; however, its complex characteristics caused a rapid decline by the early Nineties. In 1994, a second phase began when an intensive drilling program for exploration and development was kicked off with the goal of increasing gas production. New reserves were added by improving drilling and completion methods, identifying bypassed pay, identifying field extensions from 3D seismic information, and making new exploration discoveries.
Fig. 1—Burgos Basin location in northern Mexico.
Factors Affecting Fracture Conductivity
Several factors affect the conductivity of a propped fracture and ultimately the productivity of a well. As mentioned, the migration of fines onto the proppant pack after a hydraulic treatment has been recognized as one of the main factors affecting fracture conductivity. This occurs when flocculation of the fines creates larger particles that result in a pack plugging. Infiltration of fines into a pack in effect reduces the conductive width of the fracture and provides a source of fines that may migrate upon stress cycling. Fines can be a product of the proppant breakdown under closure stress or they can come from the formation that is in contact with the proppant bed. Fines migration is often related to unconsolidated formations; however, it can also come from hard rocks if the fracture face crushes under the load of the proppant.2
The present work shows the Tertiary gas reservoirs that display an inverted gamma ray curve in the well logs. These reservoirs with thicknesses of 2 m to 50 m are located in siliciclastic sediments of Oligocene Vicksburg, and have good porosity "ø" (14 to 19 %) and permeability "k" (1 to 140 md). The gamma ray anomaly has been observed in over 60 wells (exploratory and development) that belong to 9 fields (Árabe, Cañón, Comitas, Cuitláhuac, Fundador, Kryptón, Pame, Santander and Sigma). A definition for this type of reservoirs sets out here and it is tried to determine the origin of the inverted response in the gamma ray curve. These sands have produced gas and condensate with initial flow rates from 1 to 5.5 MMscfd and wellhead flowing pressures of 800 to 4000 psi.
Burgos basin includes an area of 50,000 Km2, located in the western part of Gulf of México, in the states of Tamaulipas and Nuevo Leon. In the last years the Burgos basin has become one of the most important non associated gas producers of Mexico. The present paper shows the producing Tertiary gas sands that display an inverted gamma ray curve (GR). These reservoirs with thicknesses of 2 to 50 m are located in siliciclastics sediments of Oligocene Vicksburg, and have good porosity "ø" (14 to 19 %) and permeability "k" (1 to 140 md). This anomaly (inverted response) has been observed in more than 65 wells (exploratory and infill) pertaining to 8 fields (Árabe, Cañón, Comitas, Cuitlahuac, Fundador, Krypton, Santander and Sigma). All this reservoirs have gas effects; it looks like shaly bodies; this is a really complex behavior, and trying to calculate the shale volume with gamma ray and neutron-porosity curves, normally used to obtain it; is impossible; that is why the shale volume is calculated from resistivity and sonic logs like a good alternative.
Fig. 1 Location map of the area. The image shows the gas fields where the inverted or anomalous gamma ray (GR) curve has been observed. Its alignment is North - South. The fields are located in the Eastern part of the Burgos basin.(available in full paper)
A definition for this type of deposits is proposed in this work and it is tried to determine the origin of the inverted response in the gamma ray curve, taking into account laboratory reports of sidewall cores (description, petrography, images of Scanning Electron Microscope -SEM- and mineralogy) and special logs (gamma ray spectroscopy -CSNG-). These sands have had initial flow rates of 1 to 5, 5 MMscfd with initial pressures of 800 to over 4000 psi.
Definition of inverted gamma ray reservoir: it is that reservoir whose value of Gamma Ray (GR) is bigger than value of the clay throughout the logged interval, produces hydrocarbons and it has good response in the porosity well logs (NPHI-DPHI). See figure 2.
The Burgos Basin in northeastern Mexico as shown in Fig. 1 produces from the clastic Paleocene in the western portion of the basin to the Miocene in the east. Fig. 2 is a stratigraphic chart of the Tertiary. As different Tertiary formations exhibit different structural styles, the primary structural style of each major formation will be discussed and compared. Structural features across the Burgos Basin are not uniform, but complex. Interpretation on 2D and 3D seismic data, on both regional and field development scales, has revealed faults and structures that result not only from extensional forces, but also from compressional or transverse forces. The purpose of this paper is to give a general synopsis of many of the structural styles that have been observed in the Burgos Basin. A common perception that structuring in Burgos is similar to South Texas may limit a more complete understanding of the basin's true potential.
A majority of the faults are normal faults. Fault displacements range from a few meters to greater than 2000m (along the major growth fault systems). The extensional normal faults found in the basin have listric and high angle fault planes, syndepositional and post-depositional movement. Generally, synthetic faults are down-to-the-east and antithetic faults are down-to-the-west. Extensional structures include anticlines, synclines and graben systems.
While most of the structuring is consistent with traditional Gulf of Mexico basin extensional tectonics, faults with reverse throw, normal faults along which there has been subsequent reverse movement, and anticlinal folds have been observed. These features may be related to deformation occurring in the mountains to the west of the Burgos Basin and result from transverse movement that extends as far to the east as the border with the United States. These anomalous structures are strikingly visible on 3D seismic data. A northeast-southwest or northwest-southeast trend is observed in non-extensional faults and may influence producing trends through the formation of natural fracture systems.
As is common in South Texas, a majority of the faults are normal faults as characterized by Diegel 1 and Stricklin 2. The distribution of the major fault systems is illustrated on Fig. 3. Fault displacements range from a few meters to greater than 2000m (along the major growth fault systems). The extensional normal faults found in the basin trend in a north south direction and become younger to the east. Generally, synthetic faults are down-to-the-east and antithetic faults are down-to-the-west. Production is found in the extensional anticlines and graben systems. While most of the structuring is consistent with traditional Gulf of Mexico Basin extensional tectonics, various types of faults with reverse throw, basement involved thrusts, normal faults along which there has been subsequent reverse movement and anticlinal folds have been observed.
This project describes the implementation of the first-ever vertical seismic profile (VSP) in Mexico using compressional (P) and shear (S) wave sources to determine fracture orientation, which is directly related to the reservoir characterization. The rel
Franco, J.L.A. (Pemex) | de la Torre, Hermilo Gonzalez (Pemex) | Mercado Ortiz, Manuel A. (Pemex-Coordinación Area Oriental) | Wielemaker, Erik (Schlumberger) | Plona, Thomas Joseph (Schlumberger) | Saldungaray, Pablo Jose (Schlumberger) | Mikhaltseva, Irina (Schlumberger)
Shear waves propagate through rock with different velocities in different directions. This phenomenon is called acoustic anisotropy, and it is caused by the anisotropic nature of the rock's elastic properties. All sedimentary rocks exhibit some degree of acoustic anisotropy related to aligned fractures, layering, or stress imbalance. Until recently, wireline sonic tools were able to measure the anisotropy magnitude and orientation reliably only if the velocity anisotropy was greater than 5%. In this paper, we will discuss the field test results from multiple wells of a new sonic tool that is able to measure anisotropy as low as 1%. We will also comment on how to identify the cause of the anisotropy and its applications. Because we can measure the acoustic anisotropy with this new tool—even if it is very low—and relate it to the earth-stress direction, we are able to provide reservoir engineers with valuable information to optimize the field development and improve well production.
The tests were conducted in several Pemex development wells in northern Mexico, mostly in the Burgos basin. The target formations were tight gas sands. The sands have very low permeability and must be stimulated to produce hydrocarbons in commercial quantities. These hydraulically fractured vertical wells have elliptical drainage patterns, and optimum reservoir drainage depends on the correct well placement to avoid creating interference between wells (overlapping drainage areas) or leaving areas untouched (drainage gaps). Since hydraulic fractures open in a plane perpendicular to the minimum stress, determining stress direction is crucial to the placement of new wells. Also, it can help to look for in-field drilling opportunities in brown fields where early drilling strategies did not consider the stress orientation when selecting well locations. In addition, by knowing the stress-field state, it is possible to apply oriented perforating techniques to maximize the results of the fracture treatments.
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