No abstract

Hydrocarbon production has been long existent in the Denver Julesburg basin and with the development of horizontal drilling technology the Niobrara has become one of the most economical plays even with lower oil prices. The multi-bench Niobrara formation is the primary target in the basin followed by the Codell. Even with the better economics, the Niobrara and the Codell completions are not optimized yet. The operators are still aiming for more and more stages with lesser spacing thus increasing the costs. The objective of this study is to show that stage spacing can be optimized with low cost diversion technology yielding equal or better production with fewer stages thus lowering costs. In this optimization study, two Niobrara "C" bench lateral wells from the same pad that are next to each other were selected as candidates. The first well, Well-K was completed with 28 stages geometrically spaced at 153 feet utilizing the perf-n-plug methodology. The second well, Well-L was completed with 20 stages, geometrically spaced at 215 feet, also utilizing the perf-n-plug methodology. Well-L was stimulated utilizing the intra-stage diversion process and had approximately 404,000 lbm less proppant than Well-K. Well-K was completed without the diversion technology. Following stimulation and flowback, Fibercoil with Distributed Temperature Survey (DTS) and Distributed Acoustic Survey (DAS) capabilities were run in both the wells to diagnose the contribution from each perforation cluster. The Fibercoil results clearly showed that Well-L with larger stage spacing and intra-stage diversion had 80% fracture initiation as opposed to 60% with the limited-entry Well-K that had shorter stage spacing. The production results so far are very encouraging for the L-well. The 180-day cumulative oil production for Well-L is almost similar to Well-K with the normalized barrels of equivalent oil (BOE) per foot, BOE/ft. difference being lower by 3%. This study has clearly shown us that with some additional enhancement intra-stage diversion can be used to optimize stage spacing without compromising production. The post-frac fracture modeling analysis along with the Fibercoil results including warm-back analysis and production for the two wells is presented.

One of the most promising targets for resource rock stimulation in South America is the Vaca Muerta (VM) shale in western Argentina. Because of high initial costs and also the typical reservoir information that must be acquired, it is common practice for operators to begin exploration projects with vertical wells. This is also the case for unconventional reservoirs, so initial vertical wells are used for reservoir characterization/initial comprehension and also to test the productivity of the different intervals.Within the Neuquina basin, existing vertical wells were typically drilled to produce reservoirs below the VM source rock. Presently, with these reservoirs depleted in many areas, existing wells are often a great opportunity to investigate this upper unconventional target. Unfortunately, most of these wells are not viable candidates because they were designed to be completed through tubing. Casings and wellheads, in general, are not sufficiently strong to support pressure requirements for fracture stimulation of unconventional reservoirs. This paper discusses the preparation of a well originally drilled in 1974 to allow for the new objective of hydraulic fracturing the VM shale to test the productivity of its different intervals. A coiled tubing (CT) assisted pinpoint completion technique (hydrajet perforating and annulus fracturing) was used to independently stimulate small intervals. To help assure that most of the reservoir was indeed stimulated, 12 single-zone fracturing stages were used for 130 meters of gross interval.To isolate the upper (weakest) section of the wellbore, a 4 1/2-in. P-110 casing and swellable packer were installed.

The Mancos shale in the San Juan basin can present challenging conditions when hydraulic fracturing treatments are performed in horizontal wells. Some of the issues while completing a well in the Mancos can be caused by overall geomechanics and reservoir properties; for example, high horizontal stress anisotropy and the presence of discontinuities, such as microfractures and lamination. This paper presents three case studies in which hydraulic fracturing placement issues were explored. Normally, the interactions of geomechanics and reservoir properties cause high treating pressures or premature screenouts, as presented in previous publications. Ramurthy et al. (2009a, 2009b) and Potocki (2012) explain how and why properties, such as process zone stress (PZS), pressure-dependent leakoff (PDL), and geomechanics, can affect the hydraulic fracturing conditions and production results. Depending on how the well is completed, these challenging conditions can be either enhanced or minimized. When the reservoir and geomechanics are not taken into consideration in the completion design of the well, issues can occur during the hydraulic fracturing of the formation. Issues including screenouts, pressure outs, and high pressure while trying to initiate the fracture can lead to the formation not allowing the placement of the designed treatment, improper stimulation of the reservoir, excessive completion costs, and more commonly than not, poor production. This paper presents three case studies. In all three studies, similar reservoir characteristics and geomechanical conditions occur, which pose challenging obstacles for both completion and production. The challenges were each addressed in different ways, resulting in different outcomes. In one case, no action was taken to mitigate these obstacles. In the second case, the area was studied using analysis service data, treatment data, and public information. This knowledge was applied to assist in the completion of the treatment without issues. In a more recent case, in a well with similar conditions as the two previous studies, only a portion of the recommendations were applied, with mixed results. This paper presents the knowledge gained from the three case studies conducted in the Mancos shale, San Juan basin. General suggestions are presented when similar conditions are encountered while completing a well.

The Frontier formation in the Moxa Arch (Wyoming) is a complex, tight sandstone reservoir. As with any other tight formations, hydraulic-fracture stimulation is required to unlock the hydrocarbon reserves. This reservoir is also known for having high water and condensate production that seriously diminish the gas production, despite good reservoir quality, and can cause confusion when comparing the effectiveness of different stimulation techniques. A good understanding of reservoir characterization and production analysis is critical when comparing the effectiveness of different stimulation treatments across the field. This work addresses these topics by applying a systematic loop process that begins with reservoir evaluation, followed by completion design and production history analysis to identify the optimal treatment for each area in the field. The measure of success in this model was the accurate prediction of production using a reservoir flow-capacity model based on the parameters obtained from a calibrated log model specific to this reservoir and year-over-year production improvement. Once production capacity of the reservoir was known, an analysis allowed completion designs to be ranked by efficiency, from best to worst. Production-history matching provided additional information for a better understanding of the reservoir, as well as some other completion efficiencies. The results of this analysis were the key to identify necessary changes to improve fracture designs.In this study, fifty one (51) wells that were completed before 2006 were used to generate the model to predict production. The model was later successfully tested using fourteen wells completed in 2007, where actual production matched model predictions and showed improvement over similar offset completions.Different hydraulic-fracture treatment-design criteria were presented as a result of this study as optimized designs based on return on investment (ROI) for the Frontier formation. Each design criteria corresponds to specific areas of the field, where very clear and different fluid/gas ratios were identified.