Remediation of Production Loss Due to Proppant Flowback in Existing Wellbores
- Philip Duke Nguyen (Halliburton Energy Services) | Neil Alan Stegent (Halliburton Energy Services Group) | Stephen Robert Ingram (Halliburton)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 24-27 September, San Antonio, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2006. Society of Petroleum Engineers
- 3.1.1 Beam and related pumping techniques, 3.1.2 Electric Submersible Pumps, 4.6 Natural Gas, 4.3.4 Scale, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 2.2.2 Perforating, 1.8 Formation Damage, 3.1 Artificial Lift Systems, 2 Well Completion, 4.1.2 Separation and Treating, 1.6.1 Drilling Operation Management, 3.1.7 Progressing Cavity Pumps, 4.2 Pipelines, Flowlines and Risers, 4.1.5 Processing Equipment, 2.5.1 Fracture design and containment, 2.4.3 Sand/Solids Control, 2.5.2 Fracturing Materials (Fluids, Proppant), 3 Production and Well Operations
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This paper presents the results of experimental study and field case histories of a remedial treatment technique using a low-viscosity consolidating agent placed into the propped fractures by coiled tubing (CT) or jointed pipe coupled with a pressure pulsing tool. The treatment fluids are designed to provide consolidation for previously placed proppant near the wellbore without damaging the permeability of the proppant pack. The consolidation treatment transforms the loosely packed proppant in the fractures and the formation sand close to the wellbore into cohesive, consolidated, yet highly permeable packs.
Laboratory flow testing indicates that the proppant pack in a fracture model under closure stress required low-strength bonds between proppant grains to withstand high production flow rates. Field case histories are also presented to discuss treatment procedures, precautions, and recommendations for implementing the treatment process. One major advantage of this remedial treatment method is the ability to place the treatment fluid into the propped fractures, regardless of the number of perforation intervals and their lengths without mechanical isolation between the intervals. The fluid placement efficiency of this process makes remediation economically feasible, especially in wells with marginal reserves.
Many fracture-stimulated wells in the world today are subjected to curtailed production rates because of sustained proppant flowback problems. In fact, many wells are actually shut in because operators found them to be uneconomical to produce at subsequently lowered rates. Typically, production becomes restricted, such as by perforations being covered with produced proppant. The proppant produced during production often causes damage to downhole pumps and to surface equipment. In addition, repairing the equipment often results in costly downtime for the wells.
Low production rates directly affect potential revenue for the operator. Frequent workovers required for cleanup or sand removal, including shut-in time, also factor into the revenue losses caused by proppant flowback or sand infill. However, the problem will return and the loss of revenue will continue to stack up unless a treatment can be found that will remediate the problem at its source and not simply clean up the wellbore.
After an initial completion, it is often very difficult to conduct cost-effective remedial treatments to treat proppant production problems. Conventional remedial treatments are usually inadequate without some type of mechanical isolation technique. Conventional methods with a good chance of effective treatment are usually either too high a risk for well problems or too costly to consider for low-return reservoir conditions (or both).
Resin materials have also been applied to treat proppant flowback. However, a key problem with using these materials has been an inability to achieve a uniform placement of the resin into propped fractures for the entire perforated interval. This problem is amplified by the presence of variable permeability, perforation debris, formation damage in the near-wellbore region, and the high viscosity of many resin materials.
A system that attacks the problem at its source is a better approach to this problem. Using a system of precisely placed treatment fluids into propped fractures conveyed by coiled tubing can turn many marginal wells into excellent producers, and do so cost-effectively. The treatment chemicals introduced into the formation form a consolidated, highly permeable pack that can withstand the high drawdown associated with the production. This paper discusses such a system.
What Causes Proppant Flowback?
In a number of in-depth studies for determining mechanisms that cause proppant flowback,1,2 researchers found contradictions in numerical analyses of proppant flowback phenomena and field data. Despite broad coverage, literature on the subject neither provides a clear understanding of when to expect proppant flowback nor furnishes guidelines as to which proppant characteristics help prevent flowback. The following are known to contribute to proppant flowback:
• Flowback rate and fluid rheology.
• Formation closure stress and closure rate.
• Fracture face hardness and proppant embedment.
• Fracture height, width, and tortuosity.
• Proppant size, distribution, and angularity.
• Distribution of proppant within a fracture.
• Proppant binding forces.
• Perforation size, density, and orientation.
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