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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 Uniformity of proppant distribution among multiple perforation clusters affects treatment efficiency in multistage fractured wells stimulated using the plug-and-perf technique. Multiple physical phenomena taking place in the well and perforation tunnels can cause uneven proppant distribution among multiple clusters. The problem has been studied in the recent years with experimental and computational fluid dynamics (CFD) methods, which provide useful insights but are impractical for routine designs. Simplified models that incorporated the proppant transport efficiency (PTE) correlation derived from the CFD results in a hydraulic fracture model have been also presented in literature. In this paper, we present a numerical model that simulates the transient proppant slurry flow in the wellbore, considering proppant transport and settling including bed formation, rate- and concentration-dependent pressure drop, PTE, and dynamic pressure coupling with the hydraulic fractures. The model is efficient and is designed to be an independent wellbore transport model so it can be integrated with any fracture models, including fully 3D and/or complex fracture network models, for practical design optimization. The model predictions are compared and found to agree with previously published studies. Parametric studies demonstrate sensitivity of proppant distribution to grain size, fluid viscosity, and pumping rate for fixed perforation designs. Analysis of the simulation results shows that the dominant cause of uneven proppant distribution is proppant inertia. Possible slurry stratification is less important, except for the cases with relatively low flow rates and near toe clusters. Accordingly, proppant distribution is less sensitive to perforation phasing than to the number of perforations in clusters. Alterations of the number of perforations per cluster within a stage enable achieving more even proppant distribution.
Grove, Brenden (Halliburton Jet Research Center) | McGregor, Jacob (Halliburton Jet Research Center) | DeHart, Rory (Halliburton Jet Research Center) | Dusterhoft, Ron (Halliburton) | Stegent, Neil (Halliburton) | Grader, Avrami (Ingrain, a Halliburton Service)
Abstract Hydraulically fractured completions dominate industry perforating activity, particularly in North American land basins. This has led to the development of fracture-optimized perforating systems in recent years. Aside from overarching safety, reliability, and efficiency priorities, the main technical performance attribute of these systems is consistent hole size in the casing, driven by limited entry fracture design considerations. While the industry continues to seek further improvements in hole size consistency, attention is also being directed to the perforations more holistically, from a perspective of maximizing the effectiveness of subsequent hydraulic fracturing and ultimately production operations. To this end, this paper presents two related activities addressing the development, qualification, and optimization of perf-for-frac systems. The first is a surface testing protocol used to characterize perforating system performance, in particular casing hole size and consistency. The second is a laboratory program, recently conducted to investigate perforating stressed Eagle Ford shale samples at downhole conditions. This program explored the influences of charge size, formation lamination direction, pore fluid, and dynamic underbalance on perforation characteristics. Casing hole size was also assessed. For the first activity (surface testing), we find that using cement-backed casing can be an important feature to ensure more downhole-realistic results. For the second activity (laboratory program), perforation casing hole sizes for the charges tested were in line with expectations based on existing surface test data, exhibiting negligible pressure dependency. Corresponding penetration depths into the stressed shale samples generally ranged from 3.5-in to 5-in, which is much shallower than might be expected based on surface concrete performance. Dynamic underbalance was found to exhibit some slight effect on the tunnel fill characteristics, while pore system fluid was found to have minimal influence on the results. An interesting feature of the perforated samples was the complex fracture network at the perforation tips, which appeared "propped" to some extent with charge liner debris. Some of these fractures were formation beds which had delaminated during the shot, a phenomenon observed for perforations both parallel and perpendicular to the laminations. The implications of these results to the downhole environment continues to be assessed. Of particular interest is the impact these phenomena might have on fracture initiation, formation breakdown, and treatment stages which accompany subsequent hydraulic fracturing pumping operations.
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.
Kebert, Brent (Colorado School of Mines) | Almulhim, Abdulraof (Colorado School of Mines) | Miskimins, Jennifer (Colorado School of Mines) | Hunter, William (Ovintiv Inc) | Soehner, Gage (Ovintiv Inc)
Abstract Successfully treating each cluster within a hydraulic fracturing stage is a key objective for "plug-n-perf" well completions. Most operating companies would agree that the main underlying desire for a successful completion is related to future production capability. In unconventional reservoirs, propped and conductive hydraulic fractures are the primary completion result that drives production and reserve recovery. When designing a treatment, the spacing of clusters is critical to optimizing production and reserve recovery parameters, and therefore, even proppant distribution across a single stage delivers a well the greatest potential for optimized production performance. Diverting the fracturing fluid and proppant evenly across the clusters in a stage allows the greatest opportunity for each cluster to produce equally and drain the associated reservoir volume. Generating equal, producing fractures across a horizontal wellbore is a difficult problem that operators are still trying to solve. This work models the fluid and proppant distribution across a field-scale, 250-ft long, horizontal hydraulic fracturing stage, replicating realistic field conditions. By utilizing computational fluid dynamics (CFD), this paper investigates the effected proppant distribution results from a fracturing stage mimicking the presence of both a leaking plug and the impacts of stress shadowing. The proppant concentration throughout the wellbore, along with internal wellbore pressure and velocity, are also reviewed to gain an understanding of the effect of the field conditions. Additionally, this paper illustrates the effect of different proppant "ramping" conditions during the fracturing stage. Proppant ramping schedules can be smooth or sharp when increasing proppant concentration, which alters the proppant concentrations throughout the wellbore and associated perforation clusters. Unanticipated alterations of the proppant concentration within the wellbore can lead to early screenouts. Gaining a better understanding of the proppant distribution and concentration inside the wellbore can lead to improved designs of hydraulic fracturing completions.
Abstract A breakthrough patent-pending pressure diagnostic technique using offset sealed wellbores as monitoring sources was introduced at the 2020 Hydraulic Fracturing Technology Conference. This technique quantifies various hydraulic fracture parameters using only a surface gauge mounted on the sealed wellbore(s). The initial concept, operational processes, and analysis techniques were developed and deployed by Devon Energy. By scaling and automating the process, Sealed Wellbore Pressure Monitoring (SWPM) is now available to the industry as a repeatable workflow that greatly reduces analysis time and improves visualizations to aid data interpretations. The authors successfully automated the SWPM analysis procedure using a cloud-based software platform designed to ingest, process, and analyze high-frequency hydraulic fracturing data. The minimum data for the analysis consists of the standard frac treatment data combined with the high-resolution pressure gauge data for each sealed wellbore. The team developed machine learning algorithms to identify the key events required by a sealed wellbore pressure analysis: the start, end, and magnitude of each pressure response detected in the sealed wellbore(s) while actively fracturing offset wells. The result is a rapid, repeatable SWPM analysis that minimizes individual interpretation biases. The primary deliverables from SWPM analyses are the Volumes to First Response (VFR) on a per stage basis. In many projects, multiple pressure responses within a single stage have been observed, which provides valuable insight into fracture network complexity and cluster/stage efficiency. Various methods are used to visualize and statistically analyze the data. A scalable process facilitates creating a statistical database for comparing completion designs that can be segmented by play, formation, or other geological variations. Completion designs can then be optimized based upon the observed well responses. With enough observations and based on certain spacings, probabilities of when to expect fracture interactions could be assigned for different plays.
Abstract The Walloons coal measures located in Surat Basin (eastern Australia) is a well-known coal seam gas play that has been under production for several years. The well completion in this play is primarily driven by coal permeability which varies from 1 Darcy or more in regions with significant natural fractures to less than 1md in areas with underdeveloped cleat networks. For an economic development of the latter, fracturing treatment designs that effectively stimulate numerous and often thin coals seams, and enhance inter-seam connectivity, are a clear choice. Fracture stimulation of Surat basin coals however has its own challenges given their unique geologic and geomechanical features that include (a) low net to gross ratio of ~0.1 in nearly 300 m (984.3 ft) of gross interval, (b) on average 60 seams per well ranging from 0.4 m to 3 m in thickness, (c) non-gas bearing and reactive interburden, and (d) stress regimes that vary as a function of depth. To address these challenges, low rate, low viscosity, and high proppant concentration coiled tubing (CT) conveyed pinpoint stimulation methods were introduced basin-wide after successful technology pilots in 2015 (Pandey and Flottmann 2015). This novel stimulation technique led to noticeable improvements in the well performance, but also highlighted the areas that could be improved – especially stage spacing and standoff, perforation strategy, and number of stages, all aimed at maximizing coal coverage during well stimulation. This paper summarizes the findings from a 6-well multi-stage stimulation pilot aimed at studying fracture geometries to improve standoff efficiency and maximizing coal connectivity amongst various coal seams of Walloons coal package. In the design matrix that targeted shallow (300 to 600 m) gas-bearing coal seams, the stimulation treatments varied in volume, injection rate, proppant concentration, fluid type, perforation spacing, and standoff between adjacent stages. Treatment designs were simulated using a field-data calibrated, log-based stress model. After necessary adjustments in the field, the treatments were pumped down the CT at injection rates ranging from 12 to 16 bbl/min (0.032 to 0.042 m/s). Post-stimulation modeling and history-matching using numerical simulators showed the dependence of fracture growth not only on pumping parameters, but also on depth. Shallower stages showed a strong propensity of limited growth which was corroborated by additional field measurements and previous work in the field (Kirk-Burnnand et al. 2015). These and other such observations led to revision of early guidelines on standoff and was considered a major step that now enabled a cost-effective inclusion of additional coal seams in the stimulation program. The learnings from the pilot study were implemented on development wells and can potentially also serve as a template for similar pinpoint completions worldwide.
Liu, Xinghui (Chevron Corporation) | Wang, Jiehao (Chevron Corporation) | Singh, Amit (Chevron Corporation) | Rijken, Margaretha (Chevron Corporation) | Chrusch, Larry (Chevron Corporation) | Wehunt, Dean (Chevron Corporation) | Ahmad, Faraj (Colorado School of Mines) | Miskimins, Jennifer (Colorado School of Mines)
Abstract Multi-stage plug-n-perf fracturing of horizontal wells has proven to be an effective method to develop unconventional reservoirs. Various studies have shown uneven fluid and proppant distributions across all perforation clusters. It is commonly believed that both fracturing fluid and proppant contribute to unconventional well performance. Achieving uniform fluid and proppant placement is an important step toward optimal stimulation. This paper discusses how to achieve such uniform placement in each stage via a CFD (Computational Fluid Dynamics) modeling approach. CFD models in several lab scales were built and calibrated using experimental data of proppant transport through horizontal pipes in several laboratory configurations. A field-scale model was then built and validated using perforation erosion data from downhole camera observations and the same model parameters calibrated in the lab-scale model. With the field-scale model validated, CFD simulations were performed to evaluate the impact of key parameters on fluid and proppant placement in individual perforations and clusters. Some key parameters investigated in this study included perforation parameters (size, orientation, number), cluster spacing, cluster count per stage, fluid properties, proppant properties, pumping rates, casing sizes, and stress shadow effects, etc. Both lab and CFD results show that bottom-side perforations receive significantly more proppant than top-side perforations due to gravitational effects. Lab and CFD results also show that proppant distribution is increasingly toe-biased at higher rates. Proppant concentration along the wellbore from heel to toe generally varies significantly. Gravity, momentum, viscous drag, and turbulent dispersion are key factors affecting proppant transport in horizontal wellbores. This study demonstrates that near-uniform fluid and proppant placement across all clusters in each stage is achievable by optimizing perforation, cluster, and other treatment design factors. Validated CFD modeling plays an important role in this design optimization process.
Abstract Fracture treatments and stage designs for new wells have evolved considerably over the past decade contributingto significant production growth. For example, in the acreage discussed hererecently used higher intensity fracturing methods provided an ~80% increase in recovery rates compared with legacy wells. Older wells completed originally with less efficient techniques can also benefit from these more up-to-date designs and treatments using re-fracturing methods. These offer the prospect of economically boosting production in appropriately selected wells. While adding in-fill wells has often been favored by Operators as a lowerrisk option the number of wells being re-fractured has grown every year for the last decade. In this case study two adjacent Eagle Ford wells, comprising a newly completed and a re-fractured well, allow both methods to be considered and compared. Completion design and fracture treatment effectiveness are evaluated using the uniformity of proppant distribution at cluster and stage level as the primary measure. Perforation erosion measurements from downhole video footage is used as the main diagnostic. Novel data acquisition methods combined with successful well preparation provided comprehensive and high-quality datasets. The subsequent proppant distribution analysis for the two wells provides the highest confidence results presented to date. Clear, repeatable trends in distribution are observed and these are compared across multiple stage designs for both the newly completed and re-fractured well. Variations in design parameters and how these effects distribution and ultimately recovery are discussed. These include changes to perforation count per cluster, cluster spacing, cluster count per stage, stage length, perforation charge size and treatment rates and volumes. As a final consideration production records for the evaluated wells are also discussed. Historical industry data shows that the number of wells being re-fractured increases relative to the number of newly drilled wells being completed during periods of low oil and gas prices. With the industry again facing harsh economic realities an increasing number of decisions will be made on whether new or refractured wells, or a combination of both, provide the best solution to replace otherwise inevitable production decline. This paper attempts to provide a detailed understanding of how proppant distribution, as a significant factor in production for hydraulically fractured wells, can be evaluated and considered in these decisions.
Mondal, Somnath (Shell Exploration & Production Co.) | Zhang, Min (University of Texas at Austin) | Huckabee, Paul (Shell Exploration & Production Co.) | Ugueto, Gustavo (Shell Exploration & Production Co.) | Jones, Raymond (Shell Exploration & Production Co.) | Vitthal, Sanjay (Shell Exploration & Production Co.) | Nasse, David (Shell Exploration & Production Co.) | Sharma, Mukul (University of Texas at Austin)
Abstract This paper presents advancements in step-down-test (SDT) interpretation to better design perforation clusters. The methods provided here allow us to better estimate the pressure drop in perforations and near-wellbore tortuosity in hydraulic fracturing treatments. Data is presented from field tests from fracturing stages with different completion architectures across multiple basins including Permian Delaware, Vaca Muerta, Montney, and Utica. The sensitivity of near-wellbore pressure drops and perforation size on stimulation distribution effectiveness in plug-and-perf (PnP) treatments is modeled using a coupled hydraulic fracturing simulator. This advanced analysis of SDT data enables us to improve stimulation distribution effectiveness in multi-cluster or multiple entry completions. This analysis goes much further than the methodology presented in URTeC2019-1141 and additional examples are presented to illustrate its advantages. In a typical SDT, the injection flowrate is reduced in four or five abrupt decrements or "steps", each with a duration long enough for the rate and pressure to stabilize. The pressure-rate response is used to estimate the magnitude of perforation efficiency and near-wellbore tortuosity. In this paper, two SDTs with clean fluids were conducted in each stage - one before and another after proppant slurry was injected. SDTs were conducted in cemented single-point entry (cSPE) sleeves, which present a unique opportunity to measure only near-wellbore tortuosity using bottom-hole pressure gauge at sleeve depth, negligible perforation pressure drops, and less uncertainty in interpretation. SDTs were conducted in PnP stages in multiple unconventional basins. The results from one set of PnP stages with optic fiber distributed sensing were modeled with a hydraulic fracturing simulator that combines wellbore proppant transport, perforation size growth, near-wellbore pressure drop, and hydraulic fracture propagation. Past SDT analysis assumed that the pressure drop due to near-wellbore tortuosity is proportional to the flow rate raised to an exponent, β = 0.5, which typically overestimates perforation friction from SDTs. Theoretical derivations show that β is related to the geometry and flow type in the near-wellbore region. Results show that initial β (before proppant slurry) is typically around 0.5, but the final value of β (after proppant slurry) is approximately 1, likely due to the erosion of near-wellbore tortuosity by the proppant slurry. The new methodology incorporates the increase in β due proppant slurry erosion. Hydraulic fracturing modeling, calibrated with optic fiber data, demonstrates that the stimulation distribution effectiveness must consider the interdependence of proppant segregation in the wellbore, perforation erosion, and near-wellbore tortuosity. An improved methodology is presented to quantify the magnitude of perforation and near-wellbore tortuosity related pressure drops before and after pumping of proppant slurry in typical PnP hydraulic fracture stimulations. The workflow presented here shows how the uncertainties in the magnitude of near-wellbore complexity and perforation size, along with uncertainties in hydraulic fracture propagation parameters, can be incorporated in perforation cluster design.