Case Study: Application of a Viscoelastic Surfactant-Based CO2 Compatible Fracturing Fluid in the Frontier Formation, Big Horn Basin, Wyoming.
- Oscar A. Bustos (Schlumberger) | Keith Roy Heiken (Schlumberger) | Mark Edward Stewart (Schlumberger) | Peter Maximilian Mueller (Saga Petroleum LLC) | Eric Lipinski (Saga Petroleum) | Toan Bui (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- Rocky Mountain Oil & Gas Technology Symposium, 16-18 April, Denver, Colorado, U.S.A.
- Publication Date
- Document Type
- Conference Paper
- 2007. Society of Petroleum Engineers
- 2.4.3 Sand/Solids Control, 5.5.8 History Matching, 4.1.2 Separation and Treating, 1.2.3 Rock properties, 3.3.1 Production Logging, 3 Production and Well Operations, 2.5.1 Fracture design and containment, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.6 Natural Gas, 4.1.5 Processing Equipment, 1.8 Formation Damage, 2.2.2 Perforating, 5.1 Reservoir Characterisation, 5.3.2 Multiphase Flow, 5.6.5 Tracers, 1.6 Drilling Operations, 2.4.6 Frac and Pack, 5.6.1 Open hole/cased hole log analysis, 5.6.9 Production Forecasting
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CO2 based fluids are commonly used to fracture stimulate formations with low reservoir pressure as well as formations that are more sensitive to water treatments (high capillary pressure, swelling clays etc). In particular, the Frontier Formation located in Bighorn Basin, Wyoming, has seen a variety of stimulation fluids used over the past years with varying degrees of success. When dealing with water sensitive formations, a common practice has been to use oil-based fluids. However, fluids of this nature can have detrimental effects on gas zones with low reservoir pressure and this might be the reason for erratic well performance of previously treated Frontier completions. It has also been determined that oil-based fluids can alter the reservoir wettability and hence cause formation damage. With this in mind and considering the environmental and economical benefits of using a water-based fracturing fluid, a novel visco-elastic surfactant based, CO2-compatible, high foam quality (>60%) fluid was proposed as the main fracturing fluid. This paper will discuss the first application of this visco-elastic based fluid on wells in Park County, Wyoming.
This paper will discuss stimulation with the new fluid and how pin-point pressure measurement enabled the operator to make informed decisions to define fracturing/completion strategy. We also present the additional benefits of incorporating existing dipole sonic tool information to calibrate "in-situ?? stress, Young's Modulus and Poisson's ratio. Finally, a production history match is conducted on wells treated with the new fluid.
In the Big Horn Basin northeastern Wyoming, there are several different fields that have been stimulated with a variety of techniques and fracturing fluids. An operator in the Big Horn basin has recently been using a polymer-free viscoelastic surfactant-based fracturing fluid that is compatible with carbon dioxide (CO2). For the two applications referenced on this paper, foam with high foam quality (70% quality) was used, where foam quality refers to the percentage ratio of CO2 over the total foamed fluid volume. With such high qualities, the amount of water used is minimized as well as potential problems associated with clays swelling and change in relative permeability. An additional benefit of CO2-based fluid is that it provides a weak acidic (low pH) environment that prevents even further common problems associated with clay swelling. The negative effects of using higher pH fluids in the Frontier formation in the Big Horn Basin can be found in references such as SPE paper by Lehman et al.
Case studies of two wells are presented on this paper. On the first well, after a pressure build up on the Muddy Formation that showed lower than expected reservoir pressure and permeability, it was decided to fracture stimulate only the first Frontier formation, and, as a result of the stimulation, the well is producing on average 1,100 Mscf/day. On the second well, reservoir characterization was fundamental to select the best stimulation practice, considering the fact that this well was a direct offset form a well drilled and completed in 1993. Accordingly, the operator opted to run a dipole sonic imaging tool to have a better estimation of critical rock mechanics properties like Young's Modulus, Poisson's Ratio and "in-situ?? stress. An additional benefit from such log is the stress profile, which is one of the most important parameters to estimate fracture height growth. Additionally, since the four Frontiers members were clearly identified, a wireline pressure tool was used to take several pressures points across different members. As a result of this improved characterization, the second Frontier formation was skipped from any stimulation, and two stages were performed, the first one combining the third and fourth Frontier and the second stage targeting only the first Frontier. Radioactive tracers ( RA ) were used on the first stage. The well has been producing on average 670 Mscf/day over the last 4 months, and two temperature logs have been run to identify what zones are producing. In summary, most production is coming from the third and fourth members of the Frontier.
Finally, a production simulator is used to history match well production for each case using the fracture and reservoir properties measured or calculated after a fracturing pressure matching.
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