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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.
Abstract Perforation-imaging studies have indicated highly variable results on effectively treating all perforation clusters within a given fracturing stage in horizontal well plug-and-perf applications, even when limited entry designs were used. A field test was executed to trial differing perforating designs and levels of perforation friction for identifying a preferred technique for evenly distributing treatment volume along the lateral. The test was implemented in a horizontal well in the Eagle Ford formation of south Texas. After treatment and plug drill-out operations were completed, a downhole camera was run to visualize perforation entry holes along the entire lateral section. Shaped perforating charges described as equal entry hole charges were used in all stages. The resulting images were analyzed to determine entry hole dimensions and erosion characteristics to determine if alternate perforating strategies provided improved results, as compared to the standard design of multi-phase perforating with 1200 psi of perforation friction. Test results indicate that orienting perforations in a straight line (zero-phase) along the high side of the wellbore significantly improved treatment distribution among perforation clusters. Oriented perforating achieved this benefit without needing to increase initial perforation friction beyond the area standard of 1200 psi. Another result from this project was development of a statistical process for evaluating perforation entry hole erosion data. Entry hole erosion datasets are complex and difficult to analyze. The statistical process presented in this paper demonstrates a clear way to compare the effectiveness of different perforation designs. This paper also covers the operational difficulties encountered during the project which added complexity to analyzing the results. Lastly, this paper offers suggestions for future modifications for oriented perforation designs to further improve limited entry effectiveness.
Thiessen, Scott (Hunting Energy Services - Titan Division) | Han, Oliver (Hunting Energy Services - Titan Division) | Ahmed, Ramadan (University of Oklahoma) | Elgaddafi, Rida (University of Oklahoma)
ABSTRACT In hydraulic fracturing, determining the perforation pressure loss is a critical step in the design strategy, on-site troubleshooting diagnostics and post-fracture analysis. Historically, the most widely assumed and thus unknown components in the perforation friction equationare the coefficient of discharge and the holistic perforation diameter. The perforation coefficient of discharge has long been assumed as a dynamic variable dependent on the amount of fluid and proppant pumped through the perforations. This variable becomes increasingly important when clusters are spaced closer together and fewer perforations are shot such as in a limited entry design. Limited entry is a perforating technique used to generate uniform fractures along the wellbore by creating appropriate pressure differentials from cluster to cluster. With the adoption of consistent hole perforating shaped charges, the perforating diameters are more consistent and predictable. While not all consistent hole shaped charges have low diameter variability, the perforating diameters downhole are no longer an unknown, particularly after the introduction of downhole cameras. Therefore, the coefficient of discharge is the only unknown variable remaining. This paper presents an experimental methodology to accurately define the true coefficient of discharge in common completions perforated by a known consistent hole shaped charge. The test setup is illustrated, detailed test steps are discussed, and experimental data with correlations of rate per perforation and discharge coefficient is presented. Completions tested included 4-1/2", 5", and 5-1/2" casings in common weights and grades. Various perforating strategies were examined such as single shot and angled shot. Critical parameters such as entry hole diameters were made by the actual shaped charges and measured before and after the test. Freshwater and slickwater were used as hydraulic fluid and circulated at real-world pump rates through each perforation to simulate the actual field flow conditions. Based on the study, several correlations for the coefficient of discharge of flow through a perforation are created considering casing thickness, entry hole diameter and rate per perforation for the given consistent hole shaped charges. These correlations can improve perforation and fracturing designs where perforation friction are important variables.
Abstract With recent advances in downhole imaging technology, it has become evident that surface perforation testing does not directly translate to downhole conditions. A total of 279 pre- and 595 post- fracture treatment perforations were imaged in this analysis. Pre-treatment perforation hole size was highly variable, even with oriented equal-entry charges. Because of high pre-fracture treatment variability, it is not recommended to use an average diameter of unstimulated perforations to evaluate cluster efficiency of perforations post-fracture treatment. Ideally, perforations should be individually imaged before and after treatment for direct comparison. However, since pre-treatment imaging is costly, an alternate methodology is presented. The findings in this paper will challenge current understanding of actual pre-treatment hole sizes, their variability, and their implications on cluster efficiency. Cluster efficiency cutoff limits have historically been subjective and promoted a false confidence in the ability of Completions Engineers to extend stage lengths and adjust perforation designs. A more stringent and calculated method of determining cluster efficiency is presented. Utilizing both wireline pumpdown for pre-treatment measurements, and coil tubing for post-treatment measurements, downhole imaging technology was deployed to measure perforations from four separate perforation charge manufacturers for pre- and post- treatment erosional analysis. Additionally, while understanding the strike/slip stress state of the Anadarko basin, perforations were oriented at 90° and 270° (degrees from top of wellbore), parallel to the maximum rock stress, promoting a shorter and less tortuous path to the fracture initiation point. Perforating at 90° and 270° reduced tortuosity and surface treating pressure, promoted a less variable pre-treatment perforation hole size due to its symmetry, and resulted in a significant increase in cluster efficiency verses pervious designs. This project effectively optimized a perforation design utilizing pre- and post- fracture treatment perforation imaging and a thorough understanding of pre-treatment perforation hole size to evaluate the effectiveness of stress-targeted, oriented perforating and its effect on cluster efficiency, tortuosity, and pre-treatment hole size variability. The optimized design resulted in 84%-97% cluster efficiency and reduced surface treating pressure by 770 psi. This workflow can be applied by Completions Engineers to any unconventional basin where plug and perf design is utilized.
Summary In multiple-stage hydraulic fracturing treatments performed in horizontal wells, treatment confinement is the state in which fracturing fluid and proppant flow out of the wellbore only through the specific perforations targeted for the fracturing stage. The terms treatment confinement and treatment isolation are synonymous. Isolation from previously treated intervals is a necessary condition for efficient treatment along the lateral. Failure to confine fracturing stages can be a result of failure of the fracture plug to maintain a seal or the development of casing breaches (holes) in the proximity of the fracture plug. Both conditions can be strongly impacted by proppant induced erosion. This paper is a sequel to a previous publication in which casing erosion and breaches were investigated in fracture treated horizontal wells in the Montney Formation (White et al. 2020). Integrated diagnostic methods based on data from treating pressure analysis, fiber-optic measurements, and downhole imaging were applied to investigate the root cause of failure. It was determined that treatment pressure analysis was effective in diagnosing casing and associated fracture plug integrity-loss events. This was achieved by (1) identifying treating pressure trends and anomalies during the main part of the treatment that signify confinement loss, (2) calculating near-wellbore friction at the end of treatments to compare to the friction expected for a confined treatment, and (3) analyzing step-down tests conducted during the pad stage and overflush stage at the end of the treatment to determine the near-wellbore frictional components of perforation friction and near-wellbore tortuosity. This information enables comparison of previous with current treatments for determining the effects of job design and fracture plug modifications on treatment confinement. The objective of this paper is to validate that useful conclusions on the degree of treatment confinement can be made using only stand-alonepressure-based analysis. This is achieved by comparing the analysis results with fiber-optic and post-treatment wellbore imaging measurements. Also highlighted is the use of downhole gauges for accurately calculating pipe friction, which is necessary for accurately calculating bottomhole treating pressure at the active treatment interval.
This paper presents the evolution of a Bakken advanced completion design with the added enhancement of extreme limited entry (XLE) perforating. With this strategy, an operator has consistently stimulated more than 11 perforation clusters per stage. The high number of active clusters, or fracture-initiation points, has been measured directly with radioactive tracers and fiber-optic diagnostics and is validated through improved production relative to offset completions. The technique, as the name suggests, pushes the level of perforation friction past 1,500 psi. Additional sources of pressure variations have been identified and can be summed up as the fracture-entry pressure.
Summary The primary objectives of perforating a lengthy cased‐and‐cemented wellbore section for fracture stimulation are to enable extensive communication with the reservoir and control the allocation of fluid and proppant into multiple intervals as efficiently as possible during fracturing treatments. Simultaneously treating multiple intervals reduces the number of fracture stages required, thus reducing treatment cost. One way to control the allocation is to use limited‐entry perforating. Execution and optimization of limited‐entry perforating requires awareness of the factors that can affect performance. This paper presents a case study of plug‐and‐perforate horizontal‐well treatments in an unconventional shale play in which various diagnostic methods were used to better understand these factors. Within the case study, three types of perforation‐evaluation diagnostics were implemented: injection step‐down tests and pressure analysis of the fracturing treatments, video‐based perforation imaging, and distributed acoustic sensing (DAS). Injection step‐down tests indicated that all perforations were initially accepting fluid. Surface‐pressure analysis of the main fracturing treatments indicated that in certain cases, several perforations were not accepting fluid and proppant (slurry) by the end of the job. Video‐based imaging indicated that a large majority of perforations showed unambiguous evidence of significant proppant entry. Evaluation of the erosion patterns on the perforations showed a positional bias where for a given fracture stage, perforations in clusters nearest the heel of the well were more eroded than perforations in clusters nearest the toe of the well. DAS analysis showed a positional bias, allocating more slurry volume to clusters nearest the heel of the well. However, DAS analysis also showed that changing the number of perforations in a cluster had a larger effect than the positional bias. The results of the case study indicated that a staggered perforation design using more gradual changes among clusters would lead to a more balanced treatment. This scenario was evaluated along with a job design featuring high excess perforation friction and an equal number of perforations in each cluster. Fracture‐simulation runs indicated that both tactics are likely to improve slurry allocation.
Abstract This paper presents initial field results of a novel perforating technology for horizontal multistage unconventional wells. The gun system improves operational safety, efficiency and reliability with an ultracompact and simple plug-and-play design. The initial field results indicate that the enhanced casing holes distribution lower the required treating pressures because of lower tortuosity losses. The new gun system delivers better wireline and fracturing efficiency than conventional guns. The design of the new perforating system is unique in that it has multiple perforating shaped charges placed in the same plane. This produces multiple perforations in planes normal to the well, reducing near-wellbore tortuosity and the associated pressure loss during pumping, uniform frac growth from every cluster, improved proppant placement, reduced screen outs, and improved productivity. Shaped charge entrance holes are uniform and sized to maximize uniform frac placement. The new perforating system is packaged in a compact design that has less than half the length and weight of a conventional gun system. This new ultrashort, ultralight gun reduces HSE risks with easier handling and less lubricator length required for rig up. Finally, the new system is fully disposable, and its new detonation system is simple to assemble and operate, which translates into significant improvements in safety and reliability. The system brings multiple benefits over previous systems, and this paper highlights field trial results. This innovative perforating system has demonstrated a robust field performance adding significant value to multistage fracturing operations, reducing tortuosity and treating pressures, and realizing a step change in safety, efficiency and reliability. Introduction Since the early days of horizontal wells in unconventional reservoirs, it has been known that many hydraulic fractures are required to maximize the economic potential of wells from very low permeability reservoirs. While this implies the use of multistage fracturing technology, this is only part of the solution. The use of limited entry perforating has been extensively used to create multiple fractures within each stage of a multistage completion, even when the fracture propagation pressure varies considerably from one cluster to another. By restricting the flow rate into a single cluster-fracture, it is possible to force fluid into all cluster-fractures, thus creating similar fracture lengths from all clusters, and therefore significantly increasing the stimulated volume and the total production of the well.
Summary Heel-dominated treatment distribution among multiple perforation clusters is frequently observed in plug-and-perforate (plug-and-perf) stages, causing small propped surface areas, suboptimal production, and unexpected fracture hits. A multifracture simulator with a novel wellbore-fluid and proppant-transport model is applied to quantify treatment distribution among multiple perforation clusters in a plug-and-perf operation. A simulation base case is set up on the basis of a field treatment design with four clusters. Simulation results show that the two toe-side clusters screened out early in the treatment and the two heelside clusters were dominant. The simulated proppant placement is consistent with distributed-acoustic-sensing observations. The impact of different perforating strategies and pumping schedules on final treatment distribution is investigated. An optimal plug-and-perf design is defined as one that minimizes the SD of the treatment distribution among perforation clusters, and maximizes the PSA. Both perforating strategy and pumping schedule are found to affect the final treatment distribution significantly, and uniform treatment distribution is shown to create more PSA. Having fewer perforations per cluster was found to promote uniform fluid and proppant placement. Other helpful strategies include reducing the number of perforations near the heel and using small, lightweight proppant. The stress shadow effect is accounted for using the displacement discontinuity method (DDM) and was found to play a smaller role than perforation friction and proppant inertia in most cases. An automated process is developed to optimize plug-and-perf completion design with multiple decision variables using a genetic algorithm (GA). Thirteen parameters are optimized simultaneously. The optimal design solution creates an almost even treatment distribution and more than doubles the PSA compared with the base case. The multifracture model presented in this paper provides a way to quantify fluid and proppant distribution for any perforating strategy and pumping schedule, and provides more insight into the physics relevant to plug-and-perf treatment distribution. The perforation and pumping schedule recommendations presented in this paper provide directional guidance for the design of fracturing jobs with balanced treatment distribution and large PSA. Introduction plug-and-perf completions have been widely used in unconventional wells because of their cost-effectiveness.
Haustveit, Kyle (Devon Energy) | Elliott, Brendan (Devon Energy) | Haffener, Jackson (Devon Energy) | Ketter, Chris (Devon Energy) | O'Brien, Josh (Devon Energy) | Almasoodi, Mouin (Devon Energy) | Moos, Sheldon (Devon Energy) | Klaassen, Trevor (Devon Energy) | Dahlgren, Kyle (Devon Energy) | Ingle, Trevor (Devon Energy) | Roberts, Jon (Devon Energy) | Gerding, Eric (Devon Energy) | Borell, Jarret (Devon Energy) | Sharma, Sundeep (Devon Energy) | Deeg, Wolfgang (Formerly Devon Energy)
Over the past decade the shale revolution has driven a dramatic increase in hydraulically stimulated wells. Since 2010, hundreds of thousands of hydraulically fractured stages have been completed on an annual basis in the US alone. It is well known that the geology and geomechanical features vary along a lateral due to landing variations, structural changes, depletion impacts, and intra-well shadowing. The variations along a lateral have the potential to impact the fluid distribution in a multi-cluster stimulation which can impact the drainage pattern and ultimately the economics of the well and unit being exploited. Due to the lack of low-cost, scalable diagnostics capable of monitoring cluster efficiency, most wells are completed using geometric cluster spacing and the same pump schedule across a lateral with known variations.
A breakthrough patent-pending pressure monitoring technique using an offset sealed wellbore as a monitoring source has led to advancements in quantifying cluster efficiencies of hydraulic stimulations in real-time. To date, over 1,500 stages have been monitored using the technique. Sealed Wellbore Pressure Monitoring (SWPM) is a low-cost, non-intrusive method used to evaluate and quantify fracture growth rates and fracture driven interactions during a hydraulic stimulation. The measurements can be made with only a surface pressure gauge on a monitor well.
SWPM provides insight into a wide range of fracture characteristics and can be applied to improve the understanding of hydraulic fractures in the following ways: Qualitative cluster efficiency/fluid distribution Fracture count in the far-field Fracture height and fracture half-length Depletion identification and mitigation Fracture model calibration Fracture closure time estimation
Qualitative cluster efficiency/fluid distribution
Fracture count in the far-field
Fracture height and fracture half-length
Depletion identification and mitigation
Fracture model calibration
Fracture closure time estimation
The technique has been validated using low frequency Distributed Acoustic Sensing (DAS) strain monitoring, microseismic monitoring, video-based downhole perforation imaging, and production logging. This paper will review multiple SWPM case studies collected from projects performed in the Anadarko Basin (Meramec), Permian Delaware Basin (Wolfcamp), and Permian Delaware Basin (Leonard/Avalon).