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Hui, Gang (University of Calgary, Alberta, Canada) | Chen, Shengnan (University of Calgary, Alberta, Canada) | Gu, Fei (PetroChina Research Institute of Petroleum Exploration and Development, Beijing, China)
Abstract The recent seismicity rate increase in Fox Creek is believed to be linked to the hydraulic fracturing operations near the region. However, the spatiotemporal evolution of hydraulic fracturing-induced seismicity is not well understood. Here, a coupled approach of geology, geomechanics, and hydrology is proposed to characterize the spatiotemporal evolution of hydraulic fracturing-induced seismicity. The seismogenic faults in the vicinity of stimulated wells are derived from the focal mechanisms of mainshock event and lineament features of induced events. In addition, the propagation of hydraulic fractures is simulated by using the PKN model, in combination with inferred fault, to characterize the possible well-fault hydrological communication. The original stress state of inferred fault is determined based on the geomechanics analysis. Based on the poroelasticity theory, the coupled flow-geomechanics simulation is finally conducted to quantitatively understand the fluid diffusion and poroelastic stress perturbation in response to hydraulic fracturing. A case study of a moment-magnitude-3.4 earthquake near Fox Creek is utilized to demonstrate the applicability of the coupled approach. It is shown that hydraulic fractures propagated along NE45° and connected with one North-south trending fault, causing the activation of fault and triggered the large magnitude event during fracturing operations. The barrier property of inferred fault under the strike-slip faulting regime constrains the nucleation position of induced seismicity within the injection layer. The combined changes of pore pressure and poroelastic stress caused the inferred fault to move towards the failure state and triggered the earthquake swarms. The associated spatiotemporal changes of Coulomb Failure Stress along the fault plane is well in line with the spatiotemporal pattern of induced seismicity in the studied case. Risks of seismic hazards could be reduced by decreasing fracturing job size during fracturing stimulations.
Abstract Proppant transport in horizontal wellbores has received significant industry focus over the past decade. One of the most challenging tasks in the hydraulic fracturing of a horizontal well is to predict the proppant concentration that enters each perforation cluster within the same stage. The main objective of this research is to investigate the effect of different limited-entry perforation configurations on proppant transport, settling, and distribution across different perforation clusters in multistage horizontal wells. To simulate a fracturing stage in a horizontal wellbore, a laboratory-based 30-foot horizontal clear apparatus with three perforation clusters is used. Fresh water (~1 cp) is utilized as the carrier fluid to transport the proppant. This research incorporates the effect of testing three different injection rates each at four different proppant concentrations on proppant transport. Different limited-entry perforation configurations are also used to test the perforation effect on proppant transport using similar injection rates and proppant concentrations for the same proppant size. The proppant is mixed with fresh water in a 200-gallon tank for at least 10 minutes to ensure the consistency of the slurry mixture. The mixture is then injected into the transparent horizontal wellbore through a slurry pump. This laboratory apparatus also includes a variable frequency drive, a flow meter, and two pressure transducers located right before the first two perforation clusters. Sieve analysis is conducted to understand the ability of fresh water to carry bigger particles of the mixture at different injection rates, proppant concentrations, and perforation configurations. The results show different fluid and proppant distributions occur when altering the perforation configurations, injection rates, and proppant concentrations. The effect of gravity is extreme when using a limited entry configuration at each cluster (1 SPF) located at the bottom of the pipe, especially at low injection rates, resulting in uneven proppant distribution with a heal-biased distribution. However, even proppant distribution is observed by changing the limited entry perforation configuration to the top of the horizontal pipe at similar injection rates and low proppant concentration. Increasing the proppant concentration reduces the void spaces between the particles and pushes them away toward the toe cluster. Even proppant distribution is also observed across the three perforation clusters when using high flow rates and a 2 SPF perforation configuration located at both the top and the bottom of the pipe. The results of the sieve analyses show different size distributions of the settled and exited proppant through different perforations and clusters. This illustrates the ability of fresh water to transport different percentages of different proppant sizes to different perforations and clusters within a single stage. Frequently, the injected proppant is assumed to be distributed evenly across the perforation clusters and that the distribution of fluid and proppant is identical. However, this research adds data to the portfolio that this assumption is generally not valid. Additionally, the distribution of the transported proppant is observed to be different across individual clusters and different perforations within each cluster. Such information is beneficial to understanding transport in horizontal, multi-stage completions and how such impacts the overall treatment efficiency, especially when employing limited-entry perforation techniques.
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.
John, Blevins (Hibernia Resources) | Van Domelen, Mark (Downhole Chemical Solutions) | West, Zach (Downhole Chemical Solutions) | Rall, Jason (Downhole Chemical Solutions) | Wakefield, Drake (Downhole Chemical Solutions)
Abstract Since the early development of unconventional resource plays, slickwater fracturing fluids have expanded rapidly and are now the most common type of fluid system used in the industry. Slickwater and viscosifying friction reducer (VFR) fluids consist of polyacrylamide (PAM) polymers and are typically delivered to location in a liquid form such as a suspension or emulsion in a hydrocarbon-based carrier fluid. Recently, advances in dry powder delivery operations have provided unique advantages over the liquid versions of FRs including cost savings and improved health, safety and environmental (HSE) aspects. This paper describes the dry powder delivery process and describes the advantages that this new technology has brought to field operations. The method involves delivering polyacrylamide powder for slickwater fracturing treatments directly into the source water on location, thereby eliminating the use of liquid polymer slurries or emulsions. Liquid friction reducers typically contain 20-30% active polymer loading, with the remaining volume being the carrier fluid to keep the polymer in suspension. By delivering 100% powder, several benefits are gained including elimination of truck deliveries of FR liquids to location, reduction of total chemical volumes by 70-80%, reduction of spill hazards, and lower overall chemical costs. Different powders are available for various applications including the use of fresh or produced water, and viscosifying or non-viscosifying polymers. The key technology for "dry on the fly" (DOTF) operations is the powder delivery equipment. Due to the different molecular structures between polyacrylamide and guar polymers, delivering PAM is more technically challenging than guar and requires much higher mixing energy to achieve proper dispersion and hydration. The delivery system described in this paper uses a unique technology which creates the necessary conditions for powder mixing and has been successfully applied on over 350 wells since early 2019, with over 7,000 tons of polymer delivered.
Abstract The main functions of hydraulic fracturing fluids are to create a fracture network and to carry and place the proppant into the created fractures networks, thus, adding to fracture conductivity. Significant research has been performed to develop ideal fracturing fluid systems. The development focus has mainly been on optimization of a fluid rheology that can transport and place the proppant into the primary and any subsidiary fractures with less damage to the formation and at a lower cost. The main goal of this work is to add to the understanding and optimization of proppant transport in complex hydraulic fracture networks. Specifically for this study, focus is placed on two different fluids, water-glycerin solution and water-sodium chloride solution, representing varying fluid densities and viscosities. The effects of changing fluid viscosities, densities, proppant densities, proppant sizes, proppant concentrations, and slurry injection rates on proppant transport were then experimentally investigated. This experimental work shows that viscosity has a greater impact on the proppant transport than fluid density does, thus implying a larger impact on the resulting fracture conductivity. The results of this work show that a water-glycerin solution, with a viscosity of 4.3 cp, has significant proppant carrying capacity with proppants delivered uniformly to greater distances. On the other hand, the results show that a water-sodium chloride solution of 9.24 ppg density has less capability to carry the proppant deep into the fractures indicating that viscosity has a greater impact on the proppant transport than fluid density does. The lab results also showed that increasing proppant concentrations and injection rates has a positive impact on proppant transport.
Shahri, Mojtaba (Apache Corp.) | Tucker, Andrew (Apache Corp.) | Rice, Craig (Apache Corp.) | Lathrop, Zach (Apache Corp.) | Ratcliff, Dave (ResFrac) | McClure, Mark (ResFrac) | Fowler, Garrett (ResFrac)
Abstract In the last decade, we have observed major advancements in different modeling techniques for hydraulic fracturing propagation. Direct monitoring techniques such as fibre-optics can be used to calibrate these models and significantly enhance our understanding of subsurface processes. In this study, we present field monitoring observations indicating consistently oriented, planar fractures in an offset-well at different landing zones in the Permian basin. Frac hit counts, location, and timing statistics can be compiled from the data using offset wells at different distances and depths. The statistics can be used to calibrate a detailed three-dimensional fully coupled hydraulic fracturing and reservoir simulator. In addition to these high-level observations, detailed fibre signatures such as strain response during frac arrival to the monitoring well, post shut-in frac propagation and frac speed degradation with length can be modeled using the simulator for further calibration purposes. Application to frac modeling calibration is presented through different case studies. The simulator was used to directly generate the ‘waterfall plot’ output from the fibre-optic under a variety of scenarios. The history match to the large, detailed synthetic fibre dataset provided exceptional model calibration, enabling a detailed description of the fracture geometry, and a high-confidence estimation of key model parameters. The detailed synthetic fibre data generated by the simulator were remarkably consistent with the actual data. This indicates a good consistency with classical analytical fracture mechanics predictions and further confirm the interpretation of planar fracture propagation. This study shows how careful integration of offset-well fibre-optic measurements can provide detailed characterization of fracture geometry, growth rate, and physics. The result is a detailed picture of hydraulic fracture propagation in the Midland Basin. The comparison of the waterfall plot simulations and data indicate that hydraulic fractures can, in fact, be very well modeled as nearly-linear cracks (the ‘planar fracture modeling’ approach).
Abstract Early hydraulic fracturing completions in the Vaca Muerta Formation in central Argentina have incorporated the use of conventional fluid systems, such as linear and crosslinked guar-based polymers. Within the past few years, however, the benefits of viscosifying friction reducers (VFR) have been demonstrated in the industry, predominantly within the United States. The objective of this project was to trial the VFR fluid technology in fracturing operations in this area for potential use for full field development. After studying the potential advantages of the VFR technology including cost savings, simplified operations and enhanced well production, a project was initiated to determine if those same benefits could be obtained. To accomplish this, studies were performed to ensure economic and technical justification through a stepwise process of laboratory testing, logistical and operational considerations, a single well field trial, and a five well development phase evaluation project. The pilot project was performed on a horizontal, 27 stage lateral in the Aguada Pichana Oeste field in the Neuquen Basin of Argentina. The five well development phase evaluation project was performed in the Lindero Atravesado field. Positive laboratory test results led to a field trial using this technology, during which several benefits of the VFR fluid system began to emerge. Operational efficiency was an early success, including a reduction in the quantity of chemicals on location, more simplified pumping schedules, and low pumping pressures. Secondly, significant cost savings were realized compared to previous fluid system packages. Finally, positive production results were observed, leading to the decision to incorporate this technology into full field development operations. This paper will review the results of the stepwise evaluation process along with a focus on the economic benefits and well production from the development phase evaluation project. This paper describes the transition by Pan American Energy (PAE) from conventional fracturing fluids to viscosifying friction reducer (VFR) technology in the Vaca Muerta Formation. The paper highlights the performance of a relatively new treatment fluid which delivered positive results in a strategic international asset. The project has led to full field development using this technology. The same efficiencies provided by this system can potentially be realized through applications in other basins.
Abstract The Delaware Basin encompasses 6.4 million acres throughout Southeastern New Mexico and West Texas. With large players such as ExxonMobil, Shell or Oxy typically grabbing headlines, it's easy to forget the multitude of smaller public and private E&P operators who exist in and around the acreage positions of the aforementioned companies. Regardless of the size of the acreage holding, a consistent theme is that a typical horizontal well drilled and completed (D&C) will yield water cuts of 60-90% at any given period in its productive lifespan. Saltwater production, handling and disposal (SWD) is a drag on lease operating expenses (LOE). SWD costs via trucking, pipeline, or on-lease SWD wells can range between $0.50-$3.00/bbl. As existing infrastructure is exhausted, water handling costs have been projected to rise to over $5.00/bbl. Additionally, restricted access to SWD could cause production curtailments and thus impacting operators beyond direct LOE. Well completion operations are impacted by freshwater procurement costs starting around $0.75/bbl. Regardless of final frac design, water consumption during fracturing operations typically exceeds 500,000 bbls or $375,000 per well. Significant value exists for recycling produced water via an on-lease pit and utilizing it for future frac operations. The produced water turns into an asset if the operator can efficiently manage to substitute higher and higher percentages of freshwater with produced water. Many smaller operators (defined as less than 50,000 acres) may view produced water recycling as an operation best left to large E&P's with their massive capital budgets and contiguous acreage. Fortunately, even a 5 well, section development plan can yield returns from an on-lease produced water recycling program.
Abstract The analyses of parent-child well performance is a complex problem depending on the interplay between timing, completion design, formation properties, direct frac-hits and well spacing. Assessing the impact of well spacing on parent or child well performance is therefore challenging. A naïve approach that is purely observational does not control for completion design or formation properties and can compromise well spacing decisions and economics and perhaps, lead to non-intuitive results. By using concepts from causal inference in randomized clinical trials, we quantify the impact of well spacing decisions on parent and child well performance. The fundamental concept behind causal inference is that causality facilitates prediction; but being able to predict does not imply causality because of association between the variables. In this study, we work with a large dataset of over 3000 wells in a large oil-bearing province in Texas. The dataset includes several covariates such as completion design (proppant/fluid volumes, frac-stages, lateral length, cluster spacing, clusters/stage and others) and formation properties (mechanical and petrophysical properties) as well as downhole location. We evaluate the impact of well spacing on 6-month and 1-year cumulative oil in four groups associated with different ranges of parent-child spacing. By assessing the statistical balance between the covariates for both parent and child well groups (controlling for completion and formation properties), we estimate the causal impact of well spacing on parent and child well performance. We compare our analyses with the routine naïve approach that gives non-intuitive results. In each of the four groups associated with different ranges of parent-child well spacing, the causal workflow quantifies the production loss associated with the parent and child well. This degradation in performance is seen to decrease with increasing well spacing and we provide an optimal well spacing value for this specific multi-bench unconventional play that has been validated in the field. The naïve analyses based on simply assessing association or correlation, on the contrary, shows increasing child well degradation for increasing well spacing, which is simply not supported by the data. The routinely applied correlative analyses between the outcome (cumulative oil) and predictors (well spacing) fails simply because it does not control for variations in completion design over the years, nor does it account for variations in the formation properties. To our knowledge, there is no other paper in petroleum engineering literature that speaks of causal inference. This is a fundamental precept in medicine to assess drug efficacy by controlling for age, sex, habits and other covariates. The same workflow can easily be generalized to assess well spacing decisions and parent-child well performance across multi-generational completion designs and spatially variant formation properties.