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From using history matching to recording microseismic; exploration, completion, and production groups in the oil and gas industry don't know exactly where stimulation treatments are placed and how efficient that placement has been. Exploration geologists and geophysicists want to know placement effectiveness to relate current geologic parameters with future potential formations. Completion engineers want to use tubular and downhole hardware systems to be as cost-effective as possible and to minimize total stimulation treatment cost. Production engineers are seeking to maximize production for as long a time frame as possible. Fracturing placement and verification cuts across all segments of an asset.
With recent technology and methodology advancements, the industry can inject particulate oilsoluble tracers (OST) with the proppant and measure those tracers effectively from fracture tip to production tank. While still not accurately describing the exact fracture geometry or parameters such as fracture conductivity (fcd), the industry can now qualitatively measure production from each stage. With each stage uniquely identified by post-fracture production, fracture size and capital expenditure associated with the placement of the fracturing treatment can be optimized.
Broadview Energy recently pumped a fracturing treatment into the 637 m (2089 ft) total vertical depth (TVD) Sparky clastic zone through a 114 mm (4.5") liner string in a horizontal wellbore using mechanically operated sleeves. Broadview Energy sequentially alternated the size of the fracturing treatments along the length of the well between 7.5 t (16, 534 lb) and 5 t (11,023 lb) of 16-30 fracturing sand as the proppant. Alternating the fracture size served to isolate geologic and fluid heterogeneities.
Measuring the OST concentration from each fracture treatment showed results that were not directly proportional with the size of the treatment; namely, a 50% larger stage treatment yielded a 33% improvement in OST return. Using tracer technology to show observable variations of completion methods, Broadview Energy hypothesizes that, with further testing, it would be possible to recognize the threshold in fracture size and prevent diminishing returns in future fracture treatments with similar geologic conditions.
Pumping multiple unique stimulation designs in a single multistage lateral combined with particulate oil-soluble tracer chemicals (OSTs) accelerates the traditional trial and error process of optimizing stimulation designs. Applying this methodology to various fracturing sand volumes provides discrete data for stimulation analysis. When compared to a large sample of wells, the data shows that OST tracer recovery may be used as a proxy to estimate oil production.
Altering fracture designs within the same wellbore with OSTs provides significant data that is useful for optimizing stimulation designs. Solid particulate OSTs differ from liquid OSTs in that the particulates remain locked in-situ in the proppant pack after the frac pressure wave has subsided. Formation pressure will not force the solid tracer back into the wellbore as sometimes occurs with liquid tracers. The unique chemistry of OSTs allows the tracing chemicals to dissolve only into produced oil, which is sampled at the surface for laboratory analysis.
Multi-stage lateral wells utilizing alternating stimulation designs with unique OSTs yield data suggesting increased proppant volumes lead to larger oil recoveries compared to lower proppant volumes. Ninety-four horizontal wells within the same bench of the Wolfcamp formation with various proppant volumes show a statistically significant correlation between proppant volumes and estimated ultimate recoveries (EURs). The OST recovery results closely match the trend of the 94 full-well completions, giving evidence that OST recoveries are a quantitative analogy for oil production over time. Increased proppant loading OST tests, beyond the range of full-well data available, show no gain in OST recovery. This suggests that adding more proppant in this specific portion of the reservoir may not add economic value to the operator.
The unique ability of OSTs to generate granular information at the individual stage level accelerates an operator's learning curve as optimizing stimulation design often requires costly investments in reservoir information. Another approach is to optimize stimulation design using empirical data if wells in a similar geological and petrophysical makeup exist. The OST alternating-stage-design methodology can be applied to other variables, providing a rapid trial-and-error process that yields significant empirical data for optimizing completion variables.
Abstract Hydraulic Fracturing is an important technology to enhance production from tight gas reservoirs. Several techniques have been utilized to attempt to evaluate the effectiveness of hydraulic fracturing treatments. One technique, radioactive tracers, is currently used on over 15% of the stimulation treatments performed in the U.S. With proper materials, design, and execution, tracers can be used to locate the presence and concentration of proppant at the wellbore in order to evaluate vertical and radial proppant distribution. A comprehensive study of over 100 fracture treatments has been completed in which radioactive tracers were used along with production logs, stress logs, post-fracturing completion reports, and production history to analyze completion effectiveness in four different reservoirs. Additionally, an economic benefit model was constructed to evaluate the benefit/cost ratio of applying the technology. Introduction Over the years, stimulation operations such as hydraulic fracturing have proven to be a crucial resource for enhancing the productivity of tight gas reservoirs. However, truly optimal results can only be attained if the effectiveness of stimulation treatments can be thoroughly evaluated. Post-stimulation evaluation can provide opportunities to identify and possibly correct problems in wells already stimulated. Treatment and completion schemes for future wells can be altered as necessary to maximize stimulation effectiveness. Recent advances in radioactive tracer technology have significantly expanded the capability to evaluate stimulation treatments. Logging tools can now differentiate multiple isotopes and thereby quantify fracture aperture width and proppant distributions near the wellbore. Tracers have been developed that eliminate "wash off" effects and thus minimize the possibility that the tracer and traced proppant end up in different places. We evaluated the ability of tracers to identify zones which were not completely stimulated and we computed the resulting economic benefits of correcting or avoiding these problems. The analysis included 98 wells with 136 fracture treatments in four formations. We compared the fracture treatment design, tracer logs, open hole logs, and production data on a well-by-well basis. Results indicate that in nearly 40% of the completions one or more zones did not receive any or all of the designed treatment. Using a numerical reservoir simulator and a pseudo 3-D fracture design model, we generated production and revenue forecasts for the actual treatment, the optimal treatment, and other possible outcomes. We computed the benefits and costs that would arise by applying tracer technology to correct or avoid non-optimal treatments a fraction of the time. The benefit-to-cost ratios indicate that even when problems are correctable in only a small percentage of completions, the economic benefits still significantly outweigh the costs. As with other technology applications, the benefit is achieved by significant production increases in a small percentage of the wells to which this technology is applied. Based on information gathered in this study, guidelines have been developed for designing and analyzing radioactive tracer programs that can maximize productivity and overall profit. Stimulation Evaluation Openhole logs, tracer surveys, fracture design, and production data were obtained on 98 wells with 136 fracture treatments from four formations: Almond sand in Wyoming, Cotton Valley sand in East Texas, Delaware sand in New Mexico, and Red Fork sand in Oklahoma. An integrated analysis of the data was performed to determine if tracers could identify instances in which the actual fracture height was greater than the design height or where selected pay within a larger completion interval was unstimulated or understimulated. We identified each problem in each formation, as shown in Table 1. P. 957
Abstract This paper compares flowback efficiencies using polymer concentration and frac fluid tracer methods. Results are presented for the flowback efficiency of each frac fluid segment using non-radioactive chemical frac tracers injected in a well as well as the results for the total flowback efficiencies using polymer concentration and frac fluid trace analysis methods. Two wells were fraced and traced with various chemical frac tracers. Upon commencing flowback, samples of produced aqueous solution were collected according to a pre-designed sampling schedule that lasted for 72 hours. Samples were analyzed for tracer, polymer, calcium, potassium, sodium, and chlorine concentrations. With the use of the mass balance technique, the total flowback volume and flowback efficiency for each fluid segment were calculated using the tracer method. In addition, total flowback and flowback efficiency were calculated using both polymer concentration and tracer methods. To better evaluate and compare the results of polymer concentration and frac fluid tracer analyses, dynamic fluid leakoff tests were conducted in a laboratory environment using both low and high permeability core samples. Detailed laboratory and field results are presented along with comparison of flowback results from both polymer concentration and frac fluid tracer methods. Introduction Chemical Frac Tracers Chemical frac tracers (CFTs) were originally developed in an effort to bolster the level of understanding regarding the dynamics of hydraulic fracture placement, subsequent fluid flowback and proppant bed cleanup. Borrowing from many years of experience with interwell tracing where non-radioactive chemical tracers have been successfully used to evaluate interwell communications, several families of these chemical compounds were identified that could potentially be placed in each segment of the frac fluid so as to more directly measure the flowback efficiency of each fluid segment. Armed with this flowback profile data together with the treatment pressure history of the frac treatment, it was believed that much could potentially be learned both about the dynamics of segmented fluid placement as well as segmented fluid flowback and cleanup. Given the established formation/fracture damage potential for conventional proppant transport fluids, those fluid segments not adequately recovered following the treatment could, in principle, detrimentally affect flow capacity of the propped fracture. Chemical frac tracers were designed to be placed in chemically-differentiated and/or proppant-differentiated fluid segments of the fracturing fluid so as to assess the cleanup of the fracture as a function of segment fluid chemistry and/or fracture geometry. In so doing, it was believed that the sufficiency or insufficiency of addition rates for key frac fluid additives such as polymers, breakers and gel stabilizers could be assessed. It was also believed that the relative cleanup of individual frac treatment segments in a multiple stage completion procedure could be monitored. It was further hoped that inferences could be made from these data regarding lateral placement effectiveness of proppants and vertical communication between zones. Furthermore, the tracer analysis results could be used to assess the amount of each injected segment recovered and hence to calculate flowback efficiency. Background Fluid flowback can be either of a fracture-tip or near-wellbore type. If flowback is of the near-wellbore type, it indicates extensive near-wellbore leakoff due to a highly permeable zone around the wellbore. This causes the entire pad fluid segment to leakoff near the wellbore and, therefore, the pad fluid is first to be recovered. In a low permeability formation, pad flows to the fracture tip due to low permeability and/or damaged permeability around the wellbore resulting in minimal leak-off near the wellbore. Once the well is subjected to flowback under this condition, what is injected first flows back last, if fluids are formulated properly. If some segments of gelled frac fluid are not broken effectively before the well is subjected to flowback, the early injected fluids could potentially finger through the late injected unbroken fluids and flowback first.
Ramos, Claudio R. (Pro Technics Division of Core Laboratories LP) | Warren, Mark N. (Pro Technics Division of Core Laboratories LP) | Jayakumar, Swathika (Pro Technics Division of Core Laboratories LP)
Abstract The optimistic outlook of the petroleum E&P industry, especially with regard to the re-balancing of oil and natural gas prices, has led to a renewed interest in tight gas and liquids-rich plays, more specifically in the Niobrara and Codell formations in the Denver-Julesburg (DJ) Basin. Through the use of post-stimulation completion diagnostics, insights have been obtained that can be utilized to optimize future hydraulic fracturing completions. Formations with less than one millidarcy permeability require reservoir stimulation in order to economically produce oil and gas. Engineers will often optimize a well's completion, spacing and hydraulic fracturing treatments to maximize its return with respect to cost. This paper will illustrate the use of post-stimulation completion diagnostics in identifying trends that are associated with effective completions in the Niobrara and Codell formations. In addition, case histories will be presented which illustrate methods that have increased the overall completion effectiveness in relation to proppant placement, wellbore deliverability and, ultimately, increased production performance. A horizontal well database (> 350 wells) was compiled to identify effective completion trends across the Niobrara and Codell formations. By employing proppant and fluid-based tracers, hydraulic fracture geometry, well deliverability and production performance were measured to identify trends that increased overall completion effectiveness. Primary completion results highlight areas including, but not limited to, effective proppant placement, full lateral production, frac stage length and containment, perforation cluster/sleeveefficiency, wellbore lateral length and inter-well communication between Niobrara and Codell formations. Many of the insights gained through this use of post-stimulation completion diagnostics in the Niobrara and Codell formations have led to increased completion optimization, production enhancements and field-wide cost reductions.