In addition, he said physical deformations sometimes cause excessive fracture conductivity loss. Tighter formations often create higher pressures.Ībou-Sayed said the drop in EUR values is in part due to low effective system permeability and the design and implementation of ineffective completion and stimulation strategies. Abou-Sayed said operators should observe reservoir pressure at three times: at the time of perforation, on the day the well is opened up to fracture, and during the first stage of production. “What we have seen with many companies is that they’ll have different drawdown criteria from the first week to the second week, and from the second week to the third week.”Īs shale formations are fractured under local conditions, the maximum drawdown level is not measured from the initial reservoir pressure. “It’s not going to kill you immediately,” he said. Exco concluded that this was because it could maintain sufficient backpressure.Ībou-Sayed said it is important, but not critical, to find an accurate bottomhole pressure when determining the maximum drawdown level. Production from the horizontal well was shown to be similar to the vertical wells, but the horizontal well’s pressure profile was significantly higher and declined at a slower rate. The methodology involved the development of a maximum drawdown limit based on well depth, reservoir pressure, bottomhole flowing pressure, and critical closure stress on the proppant pack.Īfter initial testing on some of its vertical wells, Exco applied a finalized drawdown method to every vertical well and an additional horizontal well, which was produced with increasing choke sizes to help maximize early water recovery while maintaining the drawdown below the maximum limit. As a result, the company implemented a controlled drawdown strategy in the wells’ early lives. The Haynesville shale was determined to be soft and friable, potentially supporting proppant embedment and negatively impacting production. Launched by Exco Resources in March 2008, the program sought to increase production in the Haynesville Shale reservoir located in east Texas and northern Louisiana. “You have to take all of that into consideration, otherwise you will see your productivity go way down very quickly.”Ībou-Sayed discussed the Haynesville Shale Development Program. “When you are locating the reservoir or reducing the downhole pressure, you are putting more closure pressure on the proppant, and you are closing the nonpropped fracture,” he said. Abou-Sayed said downhole flow pressure, reservoir pressure, and choke size are the parameters over which operators can exert the greatest control. Among them were the permeability of the formation and various types of pressures, such as the initial reservoir pressure, the pressure at the safety relief valve, and the closure pressures on the hydraulic fracturing proppant and unpropped fracture surfaces. In the presentation, titled “Shale Well Drawdown Management and Surveillance to Avoid EUR Loss and Impact on Refracturing,” Abou-Sayed listed several parameters that affect production management strategies. However, as shale plays have taken up a larger percentage of the overall market, annual decreases in estimated ultimate recovery (EUR) values for shale wells is now a major concern for operators.Īt a presentation hosted by the SPE Gulf Coast Section, Ibrahim Abou-Sayed discussed how the adoption of drawdown management strategies have helped mitigate and reduce these losses.Ībou-Sayed, the founder and president of i-Stimulation Solutions, also spoke about the elements of drawdown management that have been found to have the most significant impact on shale well productivity. The increase in production from hydraulic fracturing operations in recent years has had a dramatic effect on the oil and gas industry.
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