During the life of producing wells, there comes a time when the well approaches its economic viability as a producing well. If the reservoir potential is sufficient to support the expenditure, many wells are candidates for recompletion, reperforation, or restimulation. This type of focus on the Barnett shale began in the late 1990s. Drilling activity dramatically increased during the ensuing years and now there are more than 14,000 wells that have been drilled, most of which are producing wells. A lot of these wells are potential candidates for restimulation (refrac) because their production rates have declined but still have significant reservoir potential. The completion techniques deployed in the Barnett evolved over time to where many wells have dozensof perforation clusters and hundreds of individual perforations. Generally, refracsare ineffectual unless the perforations can be temporarily isolated so that the energy of the subsequent fracturing treatment can be focused on individual portions of the reservoir. Additionally, refrac candidate wells often contain challenging wellbore environments that further complicate the ability to successfully refrac the wells. The use of biodegradable particulates to facilitate the temporary diversion and concentration of frac energy has increased the success of restimulation. This paper discusses the recent development of techniques and materials being used in refracturing operations. Included are discussions of laboratory results of new and novel materials, along with case histories of refrac wells demonstrating application of such materials and techniques.

The success of all oilfield chemical treatments is dependent upon fluid placement efficiency. In acid-stimulation treatments, the acid should be placed so that all potentially productive intervals accept a sufficient portion of the total acid volume. The same is true for scale-inhibitor squeeze treatments. It is critical for the inhibitor to be distributed as uniformly as possible over the interval of interest. Various diversion techniques are available to assist in alteration of the injection profile during matrix treatments. Likewise, several computer design programs are available to advise on appropriate diversion techniques and allow numerical simulation of the diversion process and efficiency. Rarely are placement models validated in the field. Recently, a joint project was initiated to develop a novel fluid-diversion process. This project resulted in a particulate-diversion agent that has several advantages over traditional particulate diverters. Advantages include little or no environmental impact, negligible solubility at surface conditions, controlled permeability of the filter cake or perforation pack, upper temperature limit significantly higher than traditional diverting agents (excluding salt), compatibility with nearly all treatment fluids, diverter degradation at bottomhole conditions to eliminate post-treatment removal, and excellent regained permeability. The chemical development is not the only unique and novel aspect of this joint development. An extensive field trial was conducted, incorporating multiple step-rate tests, fluid-efficiency tests, treatment-pressure matching, pressure-buildup tests, temperature surveys, and injection profiles. These tests were performed in a 226ºF sandstone reservoir at approximately 11,900 ft MD. Testing was performedbefore diversion,during injection of the diverter,immediately after diverter placement, andfinally 1–2 days later to confirm diverter degradation. The pressure-matching techniques used in this study would not be unique in proppant-fracturing applications; however, the application to matrix stimulation and chemical placement techniques using both pressure matches and injection profile matches are unique and novel processes. Introduction Success of a stimulation or chemical squeeze treatment often depends on complete coverage of all zones. In many cases, placement of the stimulation fluids or squeeze chemicals is just as important as the fluids selected. Unless the zone of interest is extremely thin and/or has no permeability variations, simply pumping the treatment into the formation will not ensure that all of the productive intervals will be treated. The most likely recipient of most of the injected fluids will be the highest-permeability, lowest pressure, or least-damaged intervals. To achieve uniform placement of injected fluids, the original flow distribution across the interval to be treated must be altered to provide generally equal fluid-invasion profiles. The methods used to alter this flow distribution are called diversion methods, since their purpose is to divert the flow of fluid from one portion of the interval being treated to another. Fig. 1 illustrates a successful diversion experiment carried out with two formation cores of different permeability (470 mD and 1.4 Darcy) in a parallel-flow apparatus. Before diversion, the higher-permeability core accepted 75% of the total inflow. After diversion, the inflow was uniformly distributed between the two cores. The diversion method best suited for a particular situation depends on many factors, including the type of well completion, perforation density, casing and cement sheath integrity, and formation characteristics. Selection of the most appropriate diversion method is greatly influenced by the variations in formation permeability along the interval to be treated. Laboratory experiments have shown that the maximum flow contrast (a ratio of injection rates)1 that can be diverted by manipulating rate alone is about 10. With greater permeability contrasts, more aggressive diversion techniques are required. The surest way to uniformly treat the complete interval is with a mechanical-isolation device such as a straddle packer or movable packer/bridge plug assemblies. This approach, however, requires well intervention and is often cost-prohibitive. As a result, various other diversion methods are more commonly used. Diversion methods fall into four general categories:ball sealers,viscous fluids,foam, andparticulate-diverting agents. This paper will focus on one novel, degradable, particulate diverting agent.

No abstract

fax 01-972-952-9435.References at the end of the paper. AbstractMany wells completed in soft, poorly consolidated formations tend to underperform relative to the reservoirs production potential. Steep production declines are also indicative of problems with the reservoir. These problems are often attributed to poor drilling and completion practices. Formation-incompatible fluids can be lost to the formation, resulting in significant nearwell permeability loss. Advances in soft-rock stimulation technology have made frac-packing the preferred method for bypassing damaged regions within the formation and for optimizing access to productive zones. Because many soft formations produce fines that can invade the proppant pack and lower productivity, choosing the optimal proppant size for such operations is paramount to overall production-enhancement success.Numerous studies describe the optimization of proppant size as means of minimizing fines invasion and maximizing pack conductivity. This paper examines other mechanisms that affect pack conductivity and the prevention of fines invasion and migration. The results of this study provide a greater understanding of proppant-pack damage mechanisms and present evidence that proppant coated with chemical agents that make the proppant surfaces tacky can significantly improve fracture conductivity.Microscopic observations of the proppant-pack/formation interface were performed with a dynamic flow model. Images taken from this model indicate that several parameters, such as particle surface charge, wettability, and proppant tackiness, greatly influence fines migration into a proppant pack, regardless of the proppant sizing criteria used. API conductivity measurements performed with realistic pressures, closure stresses, and flow rates were used to confirm micromodel observations. This procedure provided a quantitative measure of the effects of size criteria and proppant tackiness on fracture conductivity. Fines invasion beyond the proppant-pack/formation interface was determined through postmeasurement microscopic examinations.The effect of proppant tackifiers on the proppant-pack/ formation interface was also examined, resulting in significant changes in proppant-sizing criteria for frac-packing operations. These findings should have a significant impact on future fracpack designs.

This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.