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Abstract In previous frac designs, proppant tracer logs revealed poor proppant distribution between clusters. In this study, various technologies were utilized to improve cluster efficiency, primarily focusing on selecting perforations in like-rock, adjusting perforation designs and the use of diverters. Effectiveness of the changes were analyzed using proppant tracer. This study consisted of a group of four wells completed sequentially. Sections of each well were divided into completion design groups characterized by different perforating methodologies. Perforation placement was primarily driven by RockMSE (Mechanical Specific Energy), a calculation derived from drilling data that relates to a rock's compressive strength. Additionally, the RockMSE values were compared alongside three different datasets: gamma ray collected while drilling, a calculation of stresses from accelerometer data placed at the bit, and Pulsed Neutron Cross Dipole Sonic log data. The results of this study showed strong indications that fluid flow is greatly affected by rock strength as mapped with the RockMSE, with fluid preferentially entering areas with low RockMSE. It was found that placing clusters in similar rock types yielded an improved fluid distribution. Additional improved fluid distribution was observed by adjusting hole diameter, number of perforations and pump rate.
This paper describes a novel process that uses standard drilling data obtained during the drilling of an infill well to identify induced hydraulic fractures that were created during the stimulation of a legacy well. Five case studies are presented to illustrate some insights gained through the application of this process.
This method of detecting fractures involves analyzing the amount of energy expended during the drilling of an infill well. Localized depletion around induced fractures created during stimulation of a legacy well and subsequent production can result in an increased differential pressure between the wellbore and the formation while drilling. This increased differential results in more energy being required to drill through the localized depletion caused by the fracture, allowing these fractures to be precisely located. Mapping these fractures allows operators to gain significant insight in to fracture growth and depletion patterns. In addition, by avoiding these areas of localized depletion during completion, negative fracture interactions can potentially be significantly mitigated or even avoided.
The 5 case studies presented show how this technique has been utilized to understand drainage patterns in stacked plays and how it can be used to understand the extent of dominant fractures being created as well as the horizontal stress orientation as indicated by the fracture direction. The method being deployed in this paper was developed, in February of 2019. This paper is the first to describe how this technique has been used in multiple applications, across multiple basins and reservoirs, to gain insight in to fracture growth and reservoir development as well as to mitigate fracture interactions which have been plaguing the industry.
As more unconventional resource development programs move to an infill drilling phase, understanding the interactions between primary/legacy (parent) and infill (child) wells is becoming more and more important. In some cases, these interactions are positive with no long-term damage to the parent well and can sometimes even increase the production. In many cases though, these "frac-hits" can be quite damaging to the parent wells with loss of production, increased water cut, sand fill, casing collapse or loss of the parent well. Loss of treatment fluid and proppant to the parent well can also mean that the child well is less effectively stimulated resulting in a reduction of potential production from the child well and lower ROI on the infill drilling program. It is because of these risks that many operators seek to minimize primary & infill well interactions.
Abstract This paper presents a new methodology that takes readily available drilling data, to identify the location and relative magnitude of localized depletion that is likely caused by induced fractures that are intersected by a newly drilled well. This paper describes the process used to identify the fractures and presents a case study in the Utica Shale that validates the results. In recent years, mechanical specific energy (MSE) has been used to assess mechanical properties of rocks. It is further known that changes in reservoir pressure will also influence MSE. This new process analyzes a modified mechanical specific energy, and looks for anomalous increases in MSE, which should be present when drilling through a depleted fracture. To verify the existence of depleted fractures, a set of three wells were analyzed using this technique, a parent well, and two child wells. Analysis showed that there were no signs of depleted fractures detected in the parent well, while the two child wells both contained multiple drilling signatures that were consistent with depleted fractures. The location of the apparent depleted fractures in the child well were not only consistent with the location of the parent well, but also sections in the parent well that were most likely to create dominant fractures. The identified fractures in the child wells, also were consistent in location, magnitude and area of effect across both wells. These consistencies further promote the conclusion that dominant fractures created while completing the parent well, being penetrated and identified in both child wells. Based on the work done, there is clear indication that the proposed methodology can potentially be used to identify depleted fractures. This information can further be used in order to design completion strategies aimed at reducing both the probability and severity of parent-child fracture interactions such as frac hits. The paper presented will describe the first successful attempt to characterize depleted induced fractures using standard drilling data, without the use of any additional tools being run in the wellbore. This process will provide significant impact, not only in designing completions for parent-child well pairs, but will also further the understanding of far field fracture effects such as the extent of fracture extension, depletion around a fracture, and implications for well spacing.
Abstract A project was initiated in the Wolfcamp shale to reduce the operational complexity and costs associated with hydraulic fracturing. The goal was to use dissolvable diverter to increase fracturing stage lengths while maintaining an average cluster spacing similar to the current completion design without affecting well productivity. To ensure maximum effectiveness, a unique methodology was employed that uses reservoir properties along the lateral to create stage specific diverter strategies. The methodology used to design the diverter strategies begins with understanding well heterogeneity along the lateral. Estimations of minimum in situ stress at each cluster were combined with estimates of pressure increases caused by stress shadow both from previous stages and between treatment clusters to determine fracture breakdown pressures along the lateral. This data was used to selectively segregate the clusters into those that would be treated before diversion and those that would be treated after diversion. Additionally, calculations including hoop stresses and perforation friction were used to ensure pumping pressures remained in a range that increased the probability that clusters designed to take fluid after diverter were not prematurely broken down during the initial pumping treatment. This approach of engineered diversion was applied to three wells located in the Wolfcamp shale of the Midland Basin. The completion incorporated a designed stage length that averaged 315 ft with nine perforation clusters per stage using a single diversion drop. Typical well designs in this field contain stages that are 175 ft in length with five perforation clusters. Thus, this revised design constituted an eighty percent increase in stage length over conventional stage designs. The goal of the treatment was to increase stage length without affecting production. During the treatment of the new engineered diverter stages, there was clear indication that after the first portion of the fracture was completed and diverter had seated on the perforations, the fluid was effectively diverted to virgin rock. This is a positive indication that the stage-specific diverter design was effective. Additionally, when comparing production between the three wells in this study and conventionally stimulated offset wells, there was no appreciable difference in production. This case study represents one of the earliest applications of a fully engineered diversion strategy and will describe how lessons learned during this application can be applied to further improve economics and effectiveness of diverters in horizontal shale plays.
Abstract With the advent of horizontal drilling and fracturing low-permeability reservoirs to produce hydrocarbons, it has become common practice within most fields to drill wells in the direction of minimum horizontal stress in a normal stress region to maximize production and minimize drilling risk. The primary reason for this is that induced fractures tend to propagate along the plane containing the intermediate and maximum stresses (typically overburden and maximum horizontal stresses in a normally stressed region), which, under these conditions, is perpendicular to the horizontal wellbore. This allows for maximum extension away from the wellbore into the reservoir allowing for maximum reservoir contact by the induced fractures. This has been consistently demonstrated to provide the maximum coverage. However, it is sometimes the case that wells are drilled at an azimuth that is not in line with the minimum stress. This might be due to such things as irregular lease boundaries or perhaps even variations in localized stress regimes that cause the stress direction to shift from the expected regional stress directions. These changes in a drilled well's azimuth with respect to minimum in-situ stress can have a significant effect on stimulation effectiveness and, eventually, the estimated ultimate recovery (EUR) of the wells. A study of off-azimuth drilling addressed issues of how to determine minimum stress direction, the effect of such drilling on wellbore stability and the safe mud-weight window, how the completion design might be affected, and how to estimate the expected changes in productivity. Theoretical and empirical data were used to quantify these effects; data used included wireline logs, publicly available production data, microseismic data, and computer simulations, with a particular emphasis on the Marcellus shale.
Kaufman, Peter (Schlumberger) | Atwood, Keith (Schlumberger) | Forrest, Gary (Schlumberger) | Walker, Kirby (Schlumberger) | Wutherich, Kevin (Schlumberger) | Delozier, Denise (Schlumberger) | Perakis, Alex (Schlumberger) | Borchardt, Shannon (Schlumberger) | Hauser, Ken (Schlumberger)
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Middle East Oil and Gas Show and Conference held in Manama, Bahrain, 10-13 March 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied.
Abstract It has long been accepted that one of the most cost-effective strategies for completing a horizontal shale gas well is to pump several fracture stimulation treatments along the lateral with each treatment contacting several perforation clusters spread out over a few hundred feet. Typically, these clusters are placed geometrically from toe to heel with the same distance between clusters and no other consideration as to the location of these perforations. While this process simplifies the design of the completion, there are indications that this can be ineffective in contacting the maximum amount of reservoir. The fracture treatment will tend to follow the path of least resistance; intervals where stresses are the lowest will be preferentially stimulated over intervals that have higher stress concentrations. This effect was very clearly seen in a recent stimulation campaign performed in the Marcellus shale. During the fracturing treatments on several laterals, large gaps in microseismic events were observed where some perforation clusters appeared to take little to no fluid. Outlined in this paper is one particular example where even with use of a very aggressive limited-entry perforating technique, which uses perforation friction pressure to help distribute flow equally to each perforation, microseismic monitoring still showed 35% of the clusters receiving no fluid. To improve stimulation coverage, two completions were designed using data acquired from horizontal well logs. Interpretations of lithology and stress along the wellbore allowed perforation selection in these wells using a newly developed software platform in such a way that the induced fractures were afforded the best chance of distributing equally along the lateral. Microseismic monitoring obtained during the stimulation of these wells clearly indicated significantly better fracture coverage. Additionally, stimulation treating pressures were reduced by targeting lower stressed sections, resulting in less difficulty placing proppant.
Abstract Gas wells in the Marcellus shale are usually completed with a hydraulic fracture treatment in order to create a conductive proppant pack for fluid flow to the wellbore thus effectively increasing well productivity. A novel hydraulic fracture technique which creates a network of open channels within the created fracture has recently been introduced to the oil and gas industry with over 1400 successful treatment stages pumped in other ultra-low permeability, gas-bearing unconventional reservoirs. Channel fracturing boasts higher fracture conductivity and better fracture cleanup amongst its other claims. This paper reviews the applicability of the novel hydraulic fracturing technique in the Marcellus shale and details a case study investigating the possible production gains that may be obtained when channel fracturing is applied in this play. This feasibility study briefly describes the Channel Hydraulic Fracturing technique and investigates the geophysical properties of the Marcellus shale to see if Channel fracturing is applicable in the play. The methods employed involves analyzing over 160 well logs spread across the Marcellus shale in order to create a grid map of counties and regions within the Marcellus Shale area that meet the criteria required for the applicability of the new technology. The technique is then compared to conventional hydraulic fracturing by reviewing initial production results from a Marcellus well with a conventional hydraulic fracture and performing production analysis and history matching using a production analysis software package. The conventional hydraulic fracture parameters are then replaced with channel fracturing parameters to obtain incremental production estimates. The results of the study indicate that the Channel Fracturing technique is applicable without in most areas of the Marcellus shale play. The results of the simulation and case study show increased gas production from the new technique over conventional fracturing methods.
Abstract Horizontal wells drilled in unconventional gas reservoirs are often completed by combining multiple perforation clusters in a hydraulic fracture treatment stage. Each treatment stage is typically prevented from communicating by using an isolation plug. It is a challenge to design a limited entry completion that comprehensively ensures that all perforation clusters are equally stimulated within a treatment stage (Miller et al, 2011, Mcdaniel et al, 1999). Slippage or failure of isolation plugs have also been known to occur during treatment execution and in many cases, these failures are discovered only after the well stimulation has been completed. This paper presents three case studies in the Marcellus Shale where real-time microseismic Hydraulic Fracture Monitoring (HFM) was used to evaluate the behavior and development of the induced fracture and a need for the corrective intervention was observed. In one of the cases, an innovative corrective action was implemented and microseismic results show that the intervention was successful. This study shows how real-time microseismic monitoring can been used for not only evaluating fracture geometry and azimuth but can also be used as a diagnostic tool for observing operational failures in completion tools as well as making real-time changes to completion design in order to improve completion efficiency. Some of the potential failures that may be diagnosed using HFM analyzed in this study include loss of isolation between hydraulic fracture stages, breach in casing integrity, poor cement bond in annulus and confirmation of plug ball seating. The first case study describes a hydraulic fracture treatment where the real-time HFM interpretation was useful in identifying a failure in the isolation plug between completion stages. This observation during the treatment execution was later confirmed by tagging the depth of the plug during coiled tubing operations. A production log was also run in the well and showed limited production contribution from the stage with the plug failure. The other two case studies address the use of real-time HFM interpretation to identify undesired fracture growth into an already stimulated region. Subsequent intervention by using an isolation plug between perforation clusters as a means of diversion was implemented in one of the cases. These examples clearly show how real-time microseismic monitoring can be used to adapt conventional completion designs to the dynamic nature of completion operations in the field. The paper also highlights the innovative use of an isolation plug as a diversion mechanism during fracture treatment.