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