Activity in the Barnett shale of north Texas has continued to surge over the past several years, and with this surge in activity has come a steady evolution of completion strategies. Most operators agree that the best Barnett shale wells are those that have the most extensive fracture network development. One of the biggest challenges facing operators has been determining which completion strategy will create the largest fracture network along with identifying the most cost-effective diagnostic methods for evaluating those strategies and ultimately optimizing the completions. This paper will describe an integrated completion diagnostic methodology for assessing and potentially optimizing Barnett shale completion strategies. The methodology described employs radioactive tracing and logging together with chemical tracing and conventional completion metrics to evaluate the effectiveness of Barnett completions. This methodology will be utilized to assess the effectiveness of four pairs of simultaneously-fractured parallel horizontal laterals located in three different areas stretching from the western edge of the Barnett "Core Area" to the western edge of the play's expansion acreage. Key completion parameters were identified that can be used to optimize future Barnett completions in this and potentially other areas within the basin. Introduction The Barnett shale is a successful development target as an unconventional reservoir in north Texas' Fort Worth Basin. The majority of the production from the Barnett is located in the Railroad Commission Newark, East field. Total gas production from all north Texas Barnett fields is in excess of 2.5 bcf/d from approximately 6800 wells, with cumulative production of 2.9 tcf as of April 2007. The Barnett is a Mississippian-aged marine deposit. Within the basin, the Barnett ranges in thickness between far less than a hundred feet in the far south and west (as it is affected by the Bend Arch and Llano highs), to over a thousand feet of thickness next to the northeastern edge (near the Munster Arch). The Barnett is typically seen as a black organic-rich shale. It is unique in its relatively low clay content and high quartz content. This mineralogical anomaly is thought to contribute to the good fracture conductivity that can be created during the hydraulic fracturing completion of Barnett shale wells. Unconformably underlying the Barnett shale is either the Ordovician-aged Ellenberger (limestone and dolomite) or a thin Simpson and Viola section. The distinction in the underlying formation is controlled by the position of the erosional limit of the Ellenberger limestone and dolomite or Simpson and Viola sections. While both instances represent a long period of sub-aerial exposure, the cave creation and subsequent karst topography development of the Ellenberger surface is of present importance and significance as it relates to the development of the Barnett shale reservoir. While most of the basin was relatively quiet through Barnett deposition, local karsts represent relatively active features that did see significant structural "development" during Barnett deposition. It is thought that this karst topography developed slowly as overburden weight collapsed the cave systems. This collapse was accommodated by the filling of Barnett lows, resulting in "ring-faulted" collapse structures with locally thickened Barnett sections. Areas of the basin that have preserved sections of the Simpson and Viola were largely "protected" from the Ellenberger's karsting effects. These areas are found in the far north and east portions of the basin, toward the Muenster Arch and Ouachita Thrust front. The Viola, where present, provides the additional mechanical benefit of providing a frac barrier during hydraulic fracture stimulation of the overlying Barnett rock.
Completion optimization continues to be a priority for many operators. The process of adding diverter to hydraulic fracturing treatments remains one of the fastest growing techniques to gain operational efficiency while maintaining the desired reservoir contact during the treatment. Case studies in this paper are utilized to illustrate the effects of diversion on the overall completion program. Evaluating diversion effectiveness and relating it back to overall completion effectiveness remains a challenge with surface pressure data alone. Diagnostics in the form of proppant tracing are applied to evaluate the near-wellbore coverage of the stage with the use of diversion. These stages are also evaluated based on the shift in treatment as a result of the diversion. Unique proppant tracers are utilized before and after diverter drops to evaluate changes in the treatment over time. The results of diversion based on the overall stage coverage and the role that the diverter played in obtaining this coverage is presented in several case studies. Examples include data from projects that utilize different types of diverting techniques. The overall completion effectiveness based on missed clusters is illustrated in the case studies presented in this paper. Diversion cleanup and fracture interference while using diversion is evaluated using chemical tracers. Diversion will be discussed in an interwell communication case history. In addition to the evaluation of diversion, baseline examples are included without diverter material. These baseline examples are sometimes referred to as "ghost stages." The diagnostic approach to this compilation of case histories compares the results of over 20 wells using completion diagnostics. All of the stages evaluated are summarized for perforation efficiency and diversion effectiveness.
Fluid and proppant tracers and other simple measurements in returning load water flow back can be very useful in helping to describe fracture development in shales; including such parameters as fracture complexity, frac conductivity, height growth, frac barrier effectiveness, well-to-well and frac-to-frac interference, water entry points and general fracturing execution. For most engineers, flow back ion charts have often had little relevance beyond estimating frac stage flow back activity; however, combining fluid tracer information with low-level gamma emitting proppant tracers, microseismic, simple salinity measurements and water return rate can help describe fracture and formation behaviors that lead to faster optimization of fracturing design and application. This paper will use fluid and proppant tracer results from over a hundred shale frac stages in horizontal wells along with other measurements of frac flow back and blend them with microseismic, frac pumping records, production logging and production results to build a framework for better analysis of frac flow back.
Proper fluid and proppant placement are crucial to a successful propped fracture stimulation. Numerous completion diagnostic technologies are available to characterize the placement of the treatment. Until recently, characterization of fracturing fluid cleanup could only be simulated in the laboratory and anecdotally monitored in the field. A technique utilizing a family of unique, environmentally friendly, fracturing fluid compatible, chemical tracers has now been developed for quantifying segment-by-segment recovery for individual fracturing treatments and stage-by-stage recovery for multi-stage fracturing treatments. East Texas Bossier Sand case histories demonstrate that individual, chemically-differentiated and/or proppant-differentiated, fracturing treatment segments are often not being effectively recovered. It has also been demonstrated that the chemical make-up and/or the proppant scheduling of these individual fracturing fluid segments may not only be detrimentally effecting their incremental cleanup but ultimately the production contribution from the corresponding portions of the fractured reservoir. The validation of improvements in fracturing fluid cleanup and production enhancement resulting at least in part from changes in the chemistry of the fracturing fluids and/or changes in proppant scheduling are demonstrated using the tracer technology. Introduction Chemical Frac Tracers In an effort to bolster the level of understanding regarding the dynamics of hydraulic fracture placement and subsequent fluid flowback and cleanup, the technology of chemical frac tracers (CFT's) was born. Borrowing from many years of experience with interwell tracing, several families of non-radioactive chemical compounds were identified that could potentially be placed in segmented portions 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 the effective flow capacity of the fractured interval. 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 stages 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.
Since the first modern Marcellus completion in Washington County, Pennsylvania in 2004, over 2000 Marcellus wells (horizontal and vertical) have either been permitted or drilled through October 2009 in the Appalachian Basin. The Marcellus play has become one of the most widely discussed plays in the nation, with numerous operators drilling and completing wells in Pennsylvania, West Virginia, Ohio, and New York. While the play is still in its infancy, reported production rates and reserves compare very favorably to other established North American shale plays. The play's wide geographic range has led to numerous and varied completion schemes being utilized. One primary concern has been determining the optimal size and type of stimulation treatment for a given area. One premise has been that equivalent EUR's should be less of an optimization determinant than production curves, especially early-time production, as revenue generated closer in time to capital spent is worth more than far-into-the-future revenue, and thus completions that lead to high initial production rates are more desirable for optimum rates of return and improved net present values. This paper will describe an unsuccessful attempt to reduce the size (primarily proppant volume used) of the frac treatments, thus lowering the overall completion costs, without sacrificing higher-rate, early-time production. The ultimate conclusion was that a substantial reduction in proppant volume, even though it was replaced with additional fluid volume, had a detrimental effect on fracture volume created, early-time production, and EUR. As this optimization process continues, some wells like the reduced sand volume wells discussed in this paper will require restimulation to maximize overall fracture network creation. Two successful horizontal shale refracture stimulations will also be described in this paper.
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