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Unconventional completions in North America have seen a paradigm shift in volumes of proppant pumped since 2014. There is a clear noticeable trend in both oil prices and proppant volumes – thanks to low product and service costs that accompanied the oil price crash in early 2015. As the industry continues to recover, operators are reevaluating completion designs to understand if these proppant volumes are beyond what is optimal. This paper analyzes trends in completion sizes and types across all major unconventional oil and gas plays in the US since 2011 and tracks their impact on well productivity.
Completion and production data since 2011 from more than 70,000 horizontal wells in seven major basins (Gulf Coast, Permian, Appalachian, Anadarko, Haynesville, Williston and Denver Julesburg basins) and 11 major oil/gas producing formations were analyzed to examine developments in proppant and fluid volumes. Average concentration of proppant per gallon of fluid pumped was used to understand transitional trends in fracturing fluid types with time. Production performance indicators such as First month, Best 3 or Best 12 months of oil and gas production were mapped against completion volumes to evaluate if there are added economic advantages to pumping larger designs.
In general, all major basins have seen progressive improvements in average well performance since 2011, with the Permian Basin showing the highest improvement, increasing from an average first-six-months oil production of 25,000 bbl in 2011 to 75,000 bbl in 2017. The Gulf Coast basin, where the Eagle Ford formation is located, has seen a 6-fold increase in proppant volumes pumped per foot of lateral since 2011 while the Permian and Appalachian basins hit peak proppant volumes in 2015 and 2016 respectively. In Permian and Eagleford wells, higher proppant volumes in general have resulted in better production up to a certain concentration. In Williston and Denver basins, most operators are moving away from gelled fluids, and reduced average proppant concentration per fluid volume pumped shows inclination toward hybrid or slickwater designs. While some of these observations are tied to reservoir quality, proppant volumes have begun to peak as operators have either reached an optimal point or are in the process of reducing volumes.
Demand for proppant is expected to nearly double by 2020. As oil prices continue to recover, well AFEs continue to increase, despite multiple efforts to improve capital efficiency. The need for enhanced fracture conductivity and extended half-lengths on EURs are been discussed by combining actual observed production data and sensitivities using calibrated production models. The industry is moving toward large-volume slickwater fracturing operations using smaller proppants, but he operating landscape is expected to see a correction when such designs become less economical.
Ejofodomi, Efejera (Schlumberger) | Sethi, Richa (Schlumberger) | Aktas, Elcin (Schlumberger) | Padgett, Julie (Schlumberger) | Mackay, Bruce (Schlumberger) | Mirakyan, Andrey (Schlumberger) | McCrackin, Ben (Manti Tarka Permian) | Douglas, Chris (Manti Tarka Permian)
As with most shale reservoirs, understanding the production-driving mechanism in the Wolfcamp formation, Delaware basin, is difficult due to several factors, including large variations in mineralogy, lithology, wetting characteristics, etc. Only after the production mechanisms have been determined can an optimized completion strategy be developed to effectively maximize the well deliverability performance.
An integrated, unconventional workflow, coupled with a new laboratory measurement technique, was used to understand the production-driving mechanism in the Wolfcamp shale formation and develop an optimized completion strategy that increased the well performance while reducing the completion costs. The workflow is based on the seismic-to-simulation workflow that models complex hydraulic fractures and their interaction with preexisting natural fracture networks and the resulting production impact. This process was applied on a horizontal well in the field and comprises three main steps: modeling the created complex hydraulic fracture systems, matching the observed production response, and developing an optimized completion strategy to be applied on future wells, including a new intrinsic rock-fluid interaction process to identify the optimum flowback-aid additive.
The integrated workflow was applied on a producing Wolfcamp horizontal well in Ward County, Texas. The results revealed significant degradation of the hydraulic fracture systems within the first 2 months of production. Three possible causes were identified: improper flowback procedure, inadequate completion strategy, and resistance to flow due to rock-fluid interactions. Advanced flowback analysis indicated no proppant mobilization; thus, the first possible cause was eliminated. The calibrated fracture system indicated a highly conductive system with limited surface area away from the wellbore. But the results from the production sensitivity analyses demonstrated that the extent of the propped surface area away from the wellbore was a larger driver of the production than the fracture conductivity. Thus, an optimized completion strategy was developed that maximized the propped fracture surface area. However, this still could not account for the degree of degradation observed.
A new fluid compatibility testing process revealed that the flowback additive pumped on the well was ineffective and negatively affected the ability of the fracture system to flow back stimulation fluids. Thus, an optimum flowback aid along with a clay stabilizer were determined and integrated into the optimized completion strategy. The new design was executed on a newly drilled Wolfcamp shale horizontal well. The first year of production showed a 70% increase in cumulative oil with 50% less pressure degradation compared to the offset. Additionally, oil and chemical tracer data indicated that all the stimulated stages were contributing to flow.
The innovative integration of unconventional fracture modeling with rock-fluid compatibility testing is a step change in completion optimization and provides the ability to properly understand and predict the well performance. The positive impact of these results provided an excellent platform for efficiently determining the optimum completion strategy including fluid additives to maximize production in the Wolfcamp shale, and the approach serves as a model that is readily applicable to other unconventional basins.
The oil and gas industry has adopted several methods to obtain insight as to how a fluid may affect reservoir material. The Capillary Suction Time (CST) test has become a de facto standard test method, largely due to its simplicity and speed. The most obvious shortcoming of the CST test is that it introduces a medium (paper) that is far different from anything found in an actual reservoir; in fact, one may argue that the CST test is essentially a measure of the interaction of the test fluid with the paper. The lack of theoretical foundation of the CST test precludes reproduceable results or proper estimation of errors in measurement. We present a new test method that observes only intrinsic properties of the formation in contact with a test fluid, bolstered by a strong theoretical basis, in stark contrast to the CST test.
Our method preserves the desirable attributes of the CST test, but replaces imbibition into paper with imbibition into reservoir material. The method uses a comminuted sample, and the results from the imbibition step are used to determine formation wettability in the form of the advancing contact angle. The results from a subsequent drainage test are used to determine the receding contact angle, and the capillary pressure versus saturation curve.
Prior to performing the drainage test, test fluid is placed on top of the saturated pack and the permeability of the pack to the test fluid is determined. The permeability of the pack to liquid is then compared to the pretest permeability of the pack determined using nitrogen. Use of this pack as a testing environment allows the technique to be applied to formation samples of virtually any permeability and porosity.
We have found that there is no correlation between CST test data and the permeability data obtained using the new method presented here. We present several cases in which a positive result from a CST test is inconsistent with the results obtained from the new test method. We maintain that the discrepancies cast serious doubts on the general applicability of the CST test as a tool for studying rock/fluid interactions.
In summary, there is a great need to standardize testing that investigates rock/fluid interactions. The widely used CST method introduces a foreign material and it does not offer sufficient resolution, reproducibility, or estimation of error. Even if the CST method were adequate, the lack of standardization in testing and analysis methodologies makes comparisons of published results difficult.
Our method provides superior results. The strong theoretical foundation of the new method allows rigorous analysis making comparisons between treating fluid options far more trustworthy.