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The US Energy Information Administration's forecast gas price is below USD 5/Mcf through

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.

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.

Examples of an integrated approach for quantifying oil and gas production potential in different hydrocarbon windows of the Eagle Ford Shale are presented. The Eagle Ford basin is unique in that reservoir fluids range from black oil to dry gas depending on the geology, burial depth, and temperature. The main goal of this paper is to guide operators to an understanding of potential reserves and their distribution in the Eagle Ford through the use of our specialized analysis and methodology to estimate ultimate recoveries. Data from the Eagle Ford Shale was compiled and analyzed to gain knowledge about the basin. The geology aided in indentifying "sweet spots" based on the various thermal maturation windows. Also, recent drilling and completion activities were examined in addition to the observed production from public databases. The intent was to determine curent completion practices in different parts of the Eagle Ford and also provide insight on the relationship between geologic features and production trends. A rapid asset evaluation case study is presented to demonstrate technique and workflow that uses vintage vertical well data to provide an estimate of asset value and reserves for a typical horizontal well in the Eagle Ford. The results of the study identifies "sweet spots" of oil and gas production and indicates that 1) Eagle Ford production is related to the maturation windows, as well as structure; 2) the best wells in the Eagle Ford are in the thicker areas; 3) Austin Chalk production relates to the underlying Eagle Ford production; 4) different completions for different areas and types of hydrocarbons should be considered, and 5) data and knowledge integration is the key for rapid evaluation of asset value in the Eagle Ford Shale. Operators can use this information and technique to help 1) better understand the uniqueness of the Eagle Ford Shale, 2) optimize their completion design and field development plan, and 3) calibrate expectations on oil and gas reserves potential under their acreage.