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More operators are increasing their activity level in shale oil plays as the commodity price has stabilized. Activity has been at a fever pitch in the Permian Basin where over half of the North American land rigs drilling for oil are located. Operators realize that well performance varies both positively and negatively along reservoir quality and completion design changes as well as the drilling time of infill wells. Previous studies included investigation of the average type curve for gas wells located in core areas of various unconventional plays across the US. The Permian Basin is predominantly an oil-rich basin with multiple benches; the challenge associated with discerning which bench a well was landed in makes it difficult to compare completions. This paper seeks to generate decline trends for wells drilled in the Wolfbone and Wolfberry sequences of the Permian Basin while also examining the changes in completion evolution and parent/child relationships. A similar workflow from previous studies was also applied to generate the decline curves for wells by bench and producing year. First, the horizontal wells were categorized based on which formation the laterals were landed in. Then, the moving window approach was used to identify the parent and child wells in each major formation. Based on this information, the production performance and completion between the parent and child wells were compared by bench and completion time. In this paper, we investigated the change in decline rate by applying the ratio of best 1-month production (B1) and the best 12 consecutive months (B12) production rate with relation to parent and child well spacing across respective formation layers. We also examined the completion factors in combination with the child/infill well production performance to determine the production improvement and degradation causes, thereby providing a reference for child/infill well design.

In most US unconventional basins, operators often start development by drilling the minimum number of wells needed to hold their acreage. These initial wells are sometimes called "parent" wells. Operators then start drilling their infill development wells, which many operators are currently in the process of doing across various unconventional basins. Infill performance can be highly variable, with operators making great efforts to ensure infill wells perform comparable to or better than existing parent wells. This challenge will become more magnified in the unconventional industry as infill development surpasses parent well drilling. To add more uncertainty, limited research exists showing basin-wide trends as to how infill wells can be expected to perform on average in comparison to their parent well counterparts. We studied infill well performance in numerous US basins, with the objectives of understanding performance trends and their causes, along with providing recommendations for maximizing infill well potential. We evaluated the performance of newly drilled infill wells compared to their parent wells, which had been produced for some time. With publicly available production and well information, an evaluation was performed for the following major unconventional basins: Bakken/Three Forks, Barnett, Bone Springs, Eagle Ford, Fayetteville, Haynesville, Marcellus, Niobrara, Wolfcamp (Midland and Delaware Basins), and Woodford. Using a spatial, statistical approach with key production indicators, we identified key trends across the various basins where the infill wells produced at different production rates compared to their parent wells. Overall, there is about a 50% chance that a child well will outperform a parent well; However, normalizing production to total proppant pumped and lateral length suggests that larger volumes with longer laterals in infill wells may be needed to achieve similar rates to the parent wells. Underperformance of infill wells may likely be because of existing depletion and inter-well production competition with both parent and other infill wells. Additionally, in areas where significant depletion is expected, predicting the performance of new infill wells can be very difficult. This paper will discuss alternative methodologies and technologies that may help understand and increase the production potential of lower performing infill wells.

As unconventional basins mature, infill drilling and completion campaigns take a more central role in field development planning, not only for maximizing infill well potential, but also for protecting the economic potential of pre-existing wells. Reservoir depletion from parent wells can create localized "pressure sinks." When a nearby infill well is fractured, the hydraulic fracture grows towards areas of lowest stress (the depleted area), which can damage the parent well. Subsequently, the production potential of the new well is decreased because it is now draining from the same reservoir area as the parent well. In a damaging fracturing hit from an infill well, the parent well can lose some to all of its production compared to rates before the fracturing hit. Sometimes, simply shutting in the parent well is not sufficient to prevent this damage. In this paper, more than 3,100 fracture interferences in 5 major basins (Eagle Ford, Bakken, Haynesville, Niobrara, and Woodford) are examined to determine which basins are more prone to positive or negative fracture interferences from new infill wells. The Haynesville and Bakken have more positive fracture hits than the other basins, while a majority of the fracture hits in the Woodford and Niobrara are negative. With the advent of modern diversion-based refracturing techniques, it is possible to create a "pressure barrier" around the parent well that helps redirect the new fracturing treatment into other, virgin areas of reservoir. By refracturing the parent well first, this may not only preserve the original production of the parent well, but it may also increase the production of the parent well as well as the new infill wells. Although refracturing adds to the capital expenditure of the project, project economics may be more favorable with the investment in parent well refracturing. Examples of parent well refracturing are also presented in this paper.

Oil prices have fallen to lows not seen in years. These low oil prices and sustained low gas prices have drastically reduced the number of new wells being drilled in US unconventional plays as oversupply from these plays has reached an all-time high in US storage levels. One alternative to drilling new wells is to hydraulically refracture older wells to enhance production and gain additional economic returns. With each successful refracturing operation, service companies are improving on methods to divert refracturing fluid and proppant without the use of mechanical diversion techniques. To ensure success and meet economic hurdles, refracturing requires thorough preparation, proper candidate selection, and effective diversion techniques. The authors of this paper studied the economic potential and applicability of refracturing in six different unconventional plays across the US, including the Haynesville, Fayetteville, Barnett, Woodford, Eagle Ford, and Bakken plays. The expected rates of return for refracturing were compared to the economics of new wells to determine which alternative is a better use of capital spending and how the economics vary by play. Major challenges with refracturing horizontal laterals are highlighted, along with criteria for picking the best refracturing candidates to reduce risk and help meet economic hurdles. We carefully searched through over 20,000 laterals completed since the second half of 2013 in the US and found more than 100 horizontal wells refractured by chemical diversion means based on public records. The production results of these wells were evaluated to identify the best basins for economic success. The Haynesville and Eagle Ford show the best rates of return, whereas other basins will require higher market prices, changes to current refracturing techniques, and/or identification of the best refracturing candidates to minimize the associated risks. The number of economic horizontal refracture candidates across the various basins will vary with fluctuations in oil and gas prices.