Field Study of the Physical and Chemical Factors Affecting Downhole Scale Deposition in the North Dakota Bakken Formation
- Lawrence M. Cenegy (Hess Corporation) | Clyde A. McAfee (Hess Corporation) | Leonard Kalfayan (Hess Corporation)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- October 2012
- Document Type
- Journal Paper
- 67 - 76
- 2012. Society of Petroleum Engineers
- 1.8 Formation Damage, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.3.4 Scale, 5.2 Reservoir Fluid Dynamics, 2.5.2 Fracturing Materials (Fluids, Proppant)
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North Dakota Bakken oil recovery has increased nearly 100-fold over the last 5 years, driven by technological advancements in hydraulic fracturing and completion design. For one North Dakota operator with 150 Bakken producing wells, 22 of the wells have experienced at least one event of severe calcium carbonate scaling in the pump and production tubing, leading to well failure. Bakken wells are completed to a vertical depth of approximately 10,000 ft, with horizontal laterals up to 10,000 ft, and are produced by means of multizone hydraulic fracturing.
The operator initially conducted a typical scale-prediction study to reduce well failures and maintain oil production. However, the scale-prediction study was challenging to perform for these Bakken wells because of the variability of the composition of the produced water. Attention then turned to the tracking and analysis of historical field conditions. A "post-mortem" of data collected from all failed wells because of scale was conducted, considering the failure type, date, type of hydraulic-fracturing procedure, pump-intake pressure, scale-inhibitor residual, calcium carbonate scaling index, geographic failure concentration, production time to failure, and cumulative water production to failure.
Results showed that 82% of the wells failed during early production (defined as less than 20,000 bbls of water produced and 2 years' production since first oil), after which failures became increasingly rare. This correlated with transient alkalinity spikes in the water analyses attributed to fracturing-fluid flowback during this critical period. Simulated blending of fracturing and formation waters demonstrated that this was the most important period to maintain high scale-inhibitor residuals because of high deposition potentials.
This paper discusses the various field and laboratory studies conducted in an effort to understand the problem, the results obtained, and the implications. Also discussed is the evaluation of two scale inhibitors before and after laboratory aging in simulated fracturing fluids.
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