The initial high cost of exploitation of the sustained, increasingly growing development of unconventional resources in Argentina has resulted in concentrating all efforts to increase well productivity while reducing construction and completion costs. The optimization of hydraulic fracture (HF) treatments is vitally important. It is the primary strategy used to achieve an optimal reservoir drainage area, consequently characterizing the fracture geometry, including the height, for the continuous improvement of HF treatment and planning.
Several types of technologies and methodologies are used to estimate fracture height during and after a hydraulic stimulation treatment. These technologies can provide information about the fracture geometry and extension in the near-wellbore (NWB) and far-field areas. The determination of a reliable correlation between those methodologies represents a challenge as a result of formation complexity, heterogeneity, and limitations of evaluation technologies. It is well-known that some areas in the Vaca Muerta formation contain layers that can act as fracture barriers and are responsible for fracture containment.
This paper presents a fast and simple methodology that uses conventional well logs [gamma ray (GR), sonic, and density] from pilot wells to identify potential fracture barriers. This approach establishes a means to evaluate the degree to which the rock will have the ability to control fracture height growth. This methodology was determined useful for planning perforation intervals or clusters placement, particularly in those formations with stress profile showing reduced stress contrast and, when complemented with geological information, this method also provides useful information for horizontal well trajectory. Case studies are provided to illustrate examples of the proposed fracture barrier index (FBI) being calibrated or compared to other fracture height assessment. Additionally, the benefits of adding this new approach to current methodologies and technologies to aid completion design optimization and decision making is discussed.
Buali, Mustafa (Saudi Aramco) | Ginest, Noel (Saudi Aramco) | Leal, Jairo (Saudi Aramco) | Sambo, Oscar (Saudi Aramco) | Chacon, Alejandro (Halliburton—Boots & Coots) | Vielma, Jose (Halliburton—Boots & Coots)
The carbonate gas producing zones of the Ghawar field have been impacted by extensive FeS scale deposition, reducing overall gas production and significantly increasing risks of well interventions. Previous remediation included the use of workover rigs, which can be costly because of the time necessary for workovers and lost production. H2S levels (2 to 5%) found in the reservoir also contribute to higher costs and risks when using workover rigs.
A chemical solution was also considered, but the FeS could not be 100% dissolved with HCl and the chemical reaction generated large amounts of H2S in addition to existing high levels of H2S in the reservoir. This poses a safety concern with the returns at surface along with potential corrosion of the coiled tubing (CT) and completion. Therefore, the safest and most economical method was deemed to be mechanical descaling with CT.
This paper discusses two wells where mechanical descaling was applied using CT. Each well involved four major challenges that included low reservoir pressure, increased reservoir temperature, horizontal openhole completion, and scale with high specific gravity (3.7 to 4.3). The low reservoir pressure required pay zone isolation to allow for returns to circulate out the heavy scale and to minimize fluid losses to the formation. The fact that the wells had long, openhole sections created another challenge for isolation and cleanout. With a bottomhole temperature (BHT) as high as to 310°F, the operational envelope of temporary chemical packers in combination with loss circulation materials (LCMs) to isolate the openhole section had to be expanded. Following mechanical descaling with CT, the final challenge discussed in this paper is the process to clean out the LCM in the horizontal openhole and bring the well back to maximum gas production using pinpoint stimulation techniques.