E. R. Freeman, D. A. Anschutz, J. J. Renkes, PropTester, Inc. and David Milton-Tayler, FracTech Ltd; SPE Members

Qualifying proppant performance prior to a frac job, or simply verifying proppant performance after a frac job, can add significant value to propped fracture stimulations. Through a blend of established practices and new technology, data can be generated that will give an engineer insight into how specific proppants are designed to perform.

A primary objective is to establish representative, reliable and reproducible data via a sample collected from a large mass. American Petroleum Institute (API) Recommended Practices (RP) identifies three primary tenets: 1) representative sampling from a flowing stream, 2) standardized testing with calibrated equipment, and 3) sample retention for follow-up evaluation. Application of these practices ensures that proppant test data is valid (e.g. representative, reliable, and reproducible). Yet, these practices alone typically quantify quality but do not qualify proppant performance.
Correlation of valid well-site proppant data with published information (literature, web-sites, or fracturing simulators) enables one to identify disparities. Any differences in part may be the result of mining anomalies, manufacturing defects, transportation abuse, and/or contamination. These can directly impact the delivered performance of your chosen proppant.

Lastly, this paper introduces new patented technology that enables well-site proppant sampling and evaluation before the fracturing treatment. Having pre-frac data gives one the opportunity to make any necessary changes in fracture design and implementation to get the most from available proppant.
Case histories, onshore and offshore, support “qualifying proppant performance”.

H. D. Brannon, C. J. Stephenson, BJ Services Company, E. R. Freeman, D. A. Anschutz, J. J. Renkes, and A. R. Rickards, PropTester Inc.; SPE Members

Abstract
The sands employed as fracturing proppant have been historically qualified for that purpose based upon their ability to meet quality standards described by the American Petroleum Institute (API, 1995) and more recently, by the International Organization for Standardization (ISO, 2006). Notable products meeting those standards include white sands from the Ottawa deposits in the north central United States, and the so-called brown sands from deposits in central or the “heart” of Texas. Until recent times, these “quality” sand deposits provided sufficient supplies for the ongoing needs. However, the unprecedented surge of hydraulic fracturing activities over the past few years has resulted in demand outpacing the supply for sands that meet these requirements.

Consequently, many ‘new’ sand deposits are being evaluated for use in fracturing applications, but unfortunately, a great many of those when subjected to API / ISO standards fail to make the grade in one area or another. Interestingly, it is commonly similar criteria which are being failed including acid solubility, sphericity & roundness, crush strength, and particle distribution. Thus, one is given cause to question the relevance of some testing practices on ‘real world’ performance of sand in a fracturing treatment.

It is this point which illustrates a “Catch 22”. A sand can pass industry standards as a quality proppant, but it may not necessarily meet the performance, or conductivity, requirements of a reservoir. Yet, as this study demonstrates, a sand source that fails some of the standard testing parameters might still meet the flow capacity needs of a reservoir.

One can better understand the role that industry standards play in predicting sand performance and in approving sand deposits through closer examination. So, first, a discussion of some of the individual quality standards and their influence will be shared. Secondly, empirical data will demonstrate relative impact on sand performance, via conductivity, when one or more of qualifying parameters fails to pass. Lastly, guidance will be provided for the use of sands and other proppants, which although technically are unacceptable per industry standards, may be perfectly acceptable as ‘fit-for-purpose’ proppants in at least some segment of the fracturing market.

J.L. Gidley, SPE, John L. Gidley & Assocs., Inc.; G.S. Penny, SPE, STIM-LAB, Inc.; R.R. McDaniel, SPE, Acme Resin Div. Borden

Long-term conductivity testing at realistic environment conditions has greatly improved the measurement of proppant pack permeability. However, the use of low flow rates to insure Darcy flow in such measurements has masked the total effect of failed proppant fines on proppant pack permeability. As flow rates increase, corresponding with those commonly found in the field, fines are mobilized and migrate into new positions that reduce the permeability of the proppant pack beyond that normally observed in conductivity measurements. This effect has generally been overlooked in proppant pack design.

This paper examines the extent of conductivity reduction caused by migrating proppant fines and the effect of proppant type on the extent of that reduction. The role of fines migration on the conductivity of proppant packs containing two different types of proppants, where the more capable proppant is used near the wellbore, is also evaluated. Representative commercially available proppants, including sand, resin-coated sand, and low density ceramics are included in the study.

T.W. Muecke, SPE-AIME, Exxon Production Research Co.

Microscopic observations of fine-particle movement in micromodels of porous media have shown that transport of these particles by fluids moving through pores is controlled by several factors. Besides mechanical bridging at pore restrictions, fines movement also is influenced strongly by particle wettability and the relative amounts of fluids flowing through the pores when two or more immiscible fluids are present.

S.K. Schubarth, SPE, Halliburton Energy Services, S.L. Cobb, SPE, Carbo Ceramics Inc.; R.G. Jeffrey, SPE, CSIRO Petroleum

The effect of closure stress on fracture conductivity has been well documented by laboratory measurement. Common industry practice for estimating closure stress on proppant in the field is to subtract flowing bottomhole pressure from the estimated in-situ stress of the pay interval fractured. This paper proposes that the closure stress on proppant in a fracture can be significantly higher than common estimations due to the influence of the bounding layers and the elastic response of the formation acting on the proppant. In this paper we will review past literature on fracture propagation, fracture conductivity and proppant placement and demonstrate the impact that increased proppant stress due to bounding layers can have on fracture conductivity and ultimately production.

Stephen Schubarth, Schubarth Inc. and David Milton-Taylor, FracTech Ltd.

Proppant conductivity is an important design criterion in hydraulic fracturing treatments. Knowing how different proppants behave under changing stress conditions is important to fracture stimulation success. Conductivity and non-Darcy flow effects has been laboratory measured for all ceramic proppants. Unfortunately, almost all laboratory measurements are performed with an increasing stress and cyclic stress behavior is not observed. Often, in the production of oil and gas wells, shut-in periods occur and pressure in the wellbore and proppant pack increases causing stress to be relieved on the pack. When production begins again, stress is increased on the pack. This is stress cycling and past publications1 have noted that stress cycling can cause a reduction in proppant pack conductivity.

C.M. Kim and J.R. Willingham, BJ-Titan Services Co

Once a reservoir is hydraulically fractured, the fracture may experience several repeated production/shut-in cycles. Evidence of reduced rate of recovery as wells are placed back on production, has been noted in gas wells that have been exposed to this type of cycling. As the cycling process is repeated, the propped fracture undergoes the ups and downs of closure stress, resulting in a gradual reduction in fracture conductivity.

Chris J. Stephenson, Allan R. Rickards and Harold D. Brannon, SPE Members, BJ Services Company

Proppant mesh size is arguably the most important characteristic for controlling and describing the quality of a particular propping material. More importantly the mesh size relates to the permeability performance of the proppant. For many years now, a series of American Petroleum Institute Recommended Practices have existed for testing the quality of the numerous proppants available. Along with testing procedures, these documents contain suggested typical proppant sizes, such as 20/40 mesh, and the size specifications they should meet both at the source and at the point of application. In addition to other size criteria, it has long been accepted that if a batch of proppant has at least 90% of its mass between the designating mesh sizes, it passes an acceptable quality control target. However, it is possible to have two samples of 20/40 proppant that are both 90% in-size but could, for example, have a two-fold difference in permeability due to differences in distribution. In this case would the median diameter be a more informative description of the proppant size?

G. Navaira, SPE, Chevron; M. Hupp, T. Palisch, SPE, CARBO Ceramics Inc; J. Renkes, SPE, PropTester, Inc
Copyright 2008, Society of Petroleum Engineers

This paper was prepared for presentation at the 2008 SPE International Symposium and Exhibition on Formation Damage Control held in Lafayette, Louisiana, U.S.A., 13–15 February 2008. 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. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

Offshore completions in the Gulf of Mexico must typically address sand control. Our industry has made significant progress with respect to sand control equipment and implementation. However, even properly designed and executed completions are subject to mechanical failure, with the first indications often being production of solids into a common separation facility. In many offshore completions, particularly sub-sea or multi-zone completions, it is often difficult and expensive to determine which well or specific completion interval has failed, most times requiring production to be shut in for diagnosis. Not until that point can a remedy be evaluated.

One GOM producer engaged the services of a proppant supplier to determine whether a suite of proppants/gravel could be developed that could be uniquely identified and placed in each completion interval. In the event of proppant production to surface (mechanical failure), the surface samples would be analyzed to directly determine which interval had failed. The proppant needed to be non-radioactive yet identifiable with standard laboratory techniques. The supplier subsequently developed a methodology whereby the proppant could be “tagged” with over 20 unique markers.

This paper will discuss how the tagging agents are incorporated to become a permanent component of the pellet. The results of laboratory testing will be provided, verifying that the taggant does not materially affect the performance of the proppant. In addition, the authors will review case histories where this new product was successfully placed in multi-zone frac pack completions in several deepwater GOM completions. The paper will also describe basic laboratory techniques used to successfully identify the source of proppant found in a surface choke subsequent to the frac. The economic savings provided by this novel approach will be presented, as well as other potential applications for this new product.

Incorporating Temperature, Time, and Cyclic Loading: What Does It Tell Us?

E.R. Freeman, SPE, D.A. Anschutz, SPE, A.R. Rickards, SPE, PropTester, Inc., and M.J. Callanan, SPE, Sintex Minerals & Services, Inc.
Copyright 2009, Society of Petroleum Engineers

This paper was prepared for presentation at the 2009 SPE Hydraulic Fracturing Technology Conference held in The Woodlands, Texas, USA, 19–21 January 2009.

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. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract

The American Petroleum Institute (API) crush tests for proppants found in recommended practices (e.g. RP 56, 58, & 60) are typically used to compare the crush resistance of recognized API proppant sizes at a predetermined stress under dry and ambient conditions (API, 1995). This procedure has remained the same through several API committees since the early 1980s without change. More recently, the International Organization for Standardization, ISO 13503-2, reviewed the procedure and made only slight changes, most notably in the time for which the stress is to be applied (ISO, 2006). The “new” procedure from ISO gives no indication of how the stress changes the overall mesh distribution. It also sheds no light on how key factors such as moisture, temperature, time, or cyclic loading change performance characteristics. This work addresses these issues.

The down-hole environment where the proppants are placed is wet, hot, and pressurized. Incorporating these variables into a modified API test procedure for crush resistance better represents actual down-hole conditions to which a proppant is subjected. This information is critical in establishing required propped fracture conductivity, and thus, proppant selection.

In this study a standard API crush cell was modified for pressurized fluid flow at temperature and used to quantify the effects of the parameters described as compared to standard API crush tests. Tests were performed on the following proppants: light weight ceramic (LWC), intermediate density ceramic (IDC), and high strength bauxite (HSB).

Modified testing exposes critical proppant failures under conditions that more closely simulate those experienced downhole; these failures are not be revealed by current standard API/ISO test procedures. The modified procedure results in an improved method for better understanding downhole proppant pack performance.

I.J. Renkes, D.A. Anschutz, K. Sutter, A.R. Rickards, PropTester, Inc.

This paper was presented at the SPE Hydraulic Fracturing Technology Conference and Exhibition in The Woodlands, Texas, USA in January 2017 by Ian Renkes.

Abstract
Long-term conductivity of proppants, currently defined by API RP 19D, has been used since the early 1970's as the standard for evaluating the conductivity and permeability of proppants for use in hydraulic fracturing. Proppants are typically tested across their useful range in 2,000-psi (137.89-bar) increments (i.e. 2-4-6-8K-psi…) and held 50 hours at each stress level, ramp rates between each stress and the test temperatures are also defined by API RP 19D. Frac sand is tested at 150°F (65.5°C) and ceramic proppants at 250°F (121.11°C). Proppant suppliers use this, among other testing parameters, to develop data to market their products to the industry. As with any standard, the test has its limitations. The test is expensive, time-consuming and in many cases does not match the application.

Point-specific 50 hour (PS50) conductivity tests follow the procedures outlined in API RP 19D but use point-specific stress and point-specific temperature, modeling a specific application. Although not yet sanctioned by the API, the test can generate meaningful data in less time, for a specific purpose and save money. Point-specific testing has maximized Research & Development budgets and increased the time to market for new products. Operators have benefited by tailoring proppants for their specific well conditions.

In this work, we plan to compare point-specific test data to API RP 19D data over a range of stress and time as the industry pushes the envelope on the applicable stress for proppants. Aven, Tang and Weaver brought out that "it is normal to observe a continuous decline in conductivity, although less than 5% on a daily basis if the measurement is carried longer than two days. It is rare that the system actually achieves equilibrium conductivity during that time, but the rate of change of conductivity does slow down1."

Could the point-specific test be extended to achieve equilibrium and still be comparable to existing data from the standardized test? Multiple tests were conducted to compare these two methods of conductivity tests at normal duration, a point-specific 50 hour (PS50) conductivity test and the API RP 19D conductivity test which the test spends 50 hours at each 2,000 psi (137.89-bar) increment. Results presented in this paper will help answer these questions and aid engineers make more informed decisions faster and with a lower economic cost.

B.D. Olmen, D.A. Anschutz, H.D. Brannon, K.M. Stribling

This paper was presented at the SPE Annual Technical Conference and Exhibition in Dallas, Texas, USA in September 2018 by Michelle Stribling.

Abstract
Flashback 10 years ago to 2008: the North American hydraulic fracturing industry utilized a then record breaking 21.41 Billion pounds and experienced exponential growth year-over-year (excluding 2015 and 2016). Prior to 2008, proppant demand grew at a relatively modest pace and overwhelmingly consisted of 20/40 mesh high quality natural sands and synthetic proppants. Fundamental changes in drilling and completion practices has given rise to a significant increase in the application of smaller mesh proppants, most notably 40/70, 30/50 and various forms of what is generically referred to as 100 mesh sand (i.e., sands that are predominantly smaller than 70 mesh) in natural gas and liquid applications. Proppant demand has now soared, increasing significantly as a result of the new high-intensity completions practices in horizontal wells. In 2018, an estimated 200 Billion pounds will be used for the first time in history (or 10 times that used in 2008).

The proppant supply industry responded well to the increased demand in the past decade, but the industry is increasingly concerned about future supply limitations and the potential impact on completion practices subject to high volume, quality and mesh size availability.

This paper summarizes the historical supply of proppant by type and source, and the driver for each proppant type based on the authors’ current and prior research. The paper will further clarify the basics of proppant by type and size (e.g., what is 100 mesh?) and will address some of the challenges that both the proppant supplier and end-user may face subject to current or desired completion practices. Key observations will be: 1) Potential limitations in the amount of proppant size and type, 2) The impact that specific proppant shortages may have on both supplier and end-user, and 3) Risk factors the proppant supply base may experience subject to future changes in completion design.

The objective of this effort is to encourage the need to study alternative completion designs subject to proppant availability. It is specifically not the intent of this paper to propose one form of completion practice or proppant type over the other.

D.A. Anschutz, T.A. Lowrey, K.M. Stribling, PropTester, Inc., P.J. Wildt, Consultant

This paper was presented at the SPE Annual Technical Conference and Exhibition in Calgary, Alberta, Canada in September 2019 by Michelle Stribling.

Abstract
Within the last decade, technical advancements in horizontal drilling have created an environment in the hydraulic fracturing industry resulting in a paradigm shift for the completion of unconventional wells. This shift away from conventional, vertical, bi-wing fractures with large diameter proppant, to the current unconventional design of multi-zone laterals, requires a new generation of proppants and carrying fluids. This proposes a challenge to the industry to successfully place proppant into the far field regions of potentially multiple fracture networks. To meet this challenge the industry has dedicated numerous resources to study proppant transport behavior and carrying agent behavior to better understand and apply materials that will economically optimize well completions.

This paper focuses on how proppant is transported with different fracturing fluids using a combination of pipe flow and patent-pending slot flow tests to study their behavior in various sections of a simulated fracture, including near-wellbore and far-field (low shear) fracture environments.

The objectives for the project are defined as:

- Identify proppant transport characteristics (40/70 and 100 mesh frac sand) through an open channel of high shear, low shear, leak off and low-to-zero shear environments with various fluids (slickwater, HVFR, linear gel and crosslinked gel).
- Determine how changes in geometry (incline, decline, dead-end, drop-off, and banking) impact proppant placement.
- Determine the carrying capabilities of various fluids with 40/70 and 100 mesh proppants.

Comprehensive testing was performed on three separate test designs: pipe flow, standard 4′x8′ slot flow and patent-pending 4′×8′ slot flow with obstructions inside the structure. Test procedures are designed to simulate a typical West Texas unconventional well with 100 bbl/min, 5 ½″ casing, 15,000′ of casing. Fluids are conditioned to well specifications prior to entering the test design. Fluid and proppant are trapped, and the equipment is disassembled for further analysis after each test. The collected data includes shear rates, fluid viscosities, mean particle diameter, proppant distribution, proppant concentration, pictures and videos.

Observations and conclusions include, but are not limited to, the changes/lack of changes of mean particle diameter of the proppant within the structure, comparative analysis of the carrying capabilities of slickwater, high viscosity friction reducers (HVFR), linear gel and crosslinked gel. Noteworthy differences between 40/70 and 100 mesh behavior are evaluated. An in-depth study on the carrying capabilities of high concentrations of HVFR (4 gpt and 6 gpt) is also included.

The goal of this project is to add further knowledge and insight into the design of unconventional completion techniques and to evaluate new and/or novel proppant and fracturing fluids. With the rapid shift to fine mesh proppants and a lack of comparative production data (ranging from 12-24 months), the industry is relying heavily on research and development to identify effective products for unconventional well completions. These learnings should allow for further development of materials and technologies targeted expressly for unconventional completions.

C. Mark Pearson; Garrett Fowler; K. Michelle Stribling; Jeromy McChesney; Mark McClure; Tom McGuigan; Don Anschutz; Pat Wildt

This paper was presented at the Virtual SPE Annual Technical Conference and Exhibition in October 2020 by Mark Pearson.

In conventional formations it has long been established that designing fracture treatments with improved near-wellbore conductivity generates improved production and economic returns. This is accomplished by pumping treatments with increased proppant concentration in the final stages (the traditional proppant ramp design), and in some cases by changing proppant size or type in the final stages to effect greater near-wellbore conductivity - commonly referred to as a "tail-in" design. These designs overcome the impacts of greater near-wellbore pressure loss during production caused by flow concentration in the near-wellbore region compared to distal parts of the fracture.

For vertical wells and crosslinked fracture fluid treatments, the fluid flow and suspended proppant transport is effectively "piston" flow and it was a relatively straight forward matter to engineer the near-wellbore region with a tail-in of higher conductivity proppant. For unconventional reservoirs, with multi-stage horizontal completions using slickwater fluids, it has not been obvious how best to create this improved near-wellbore conductivity and most operators have employed a "one size fits all" strategy of pumping a single proppant type unless there was perhaps a need for flowback control in which case a resin coated proppant might be used as a tail-in.

This paper reports the results of two projects to address the engineering of the near-wellbore fracture conductivity for horizontal well fracturing. Firstly, a series of laboratory tests were run in a 10 ft. × 20 ft. slot wall to visualize near-wellbore proppant duning and layering associated with both "lead-in" and "tail-in" designs. The impacts of these depositions were then quantified using a 3D hydraulic fracture / reservoir simulation code for a variety of stimulation designs in the Middle Bakken and Three Forks formations of the Williston Basin.

The results of this work show that well stimulation treatments in liquid-rich unconventional formations would benefit from a combination of small (5 to 10%) lead-ins and tail-ins of high conductivity ceramic proppant. This minimizes the effects of radial flow convergence in the transverse fractures generated from the horizontal well and maximizes the economic benefit of the well stimulation. In addition to paying out the small cost increase in only 1 to 2 months, the proppant bands of higher conductivity ceramic help mitigate the effects of longer-term sand crushing and degradation on near-wellbore plugging and thus increases 3-year cumulative free cash flow and the Estimated Ultimate Recovery (EUR) of the well.

Amit Singh, Xinghui Liu, Wang Jiehao, Peggy Rijken, Chevron Corporation, Michelle Stribling, Pat Wildt, Don Anschutz, PropTester, Inc.

This paper was presented at the Virtual SPE Annual Technical Conference and Exhibition in October 2020 by Amit Singh.

Abstract
Unconventional completions have experienced many different trends within the last decade. Many of the changes are based on learnings using conventional fracture mechanisms and studies. Previous studies evaluated the impact of various parameters on proppant transport by pumping a premixed proppant laden slurry into an open, homogenous slot to visually monitor proppant distribution. Basic flow characteristics can be captured with this type of traditional tests; however, it misses significant factors of unconventional fracture mechanisms including tortuosity, variable width, leak-off, and the ability for in-situ analysis of the materials after being pumped. This paper discusses the need and development of new equipment with innovative features, and several revolutionary laboratory techniques that were specifically applied to further understand proppant and fluid behavior in unconventional reservoirs.

Unconventional fracture characteristics learnings from industry's advanced field studies were included while defining the features of new comprehensive test equipment to represent the unconventional fracture mechanisms. This ultimately led to the construction of a large, sectional, 10'x20’ slot flow wall. The twenty-five sections of the wall were modified to accommodate a wide variety of testing regimes and flow patterns. Additionally, the pumping equipment delivering the proppant laden slurry was upgraded to adhere to today's completion designs. Through the use of large fluid tanks, proppant hoppers, a mixing blender tub, pump and flow loop, shear history, and multiple types of proppant and fluid were integrated into the test procedures to better replicate current pump schedules. Flow meters, pressure transducers, a densitometer, and linear variable differential transformers were installed to monitor the movement of the material and structure throughout the test. After testing, the patent-pending equipment is designed for disassembly for detailed analysis on the proppant and fluid. Equipment can also be modified on a smaller scale to create a winged fracture, transverse fracture and a tilted fracture, all of which are necessary when analyzing fracture and proppant transport behavior in an unconventional reservoir.

The new, comprehensive, large and tortuous slot flow equipment allowed the creation of a customized tortuous path for the proppant and fluid for twenty feet before exiting the structure into separate effluent tanks. The slot has an original width of 0.5 inches but can be tailored to establish varying slot widths and/or complete obstructions using panel inserts. With multiple inlet points, fracture growth can be documented with a total of one hundred side panel leak-off ports and eight additional leak-off ports along the top. To maximize learnings from each test, innovative test practices were applied such as, dying the frac sand of different mesh size groups to visualize the segregation of the proppant while pumping, and mounting 10-15 cameras throughout the structure to document slurry behavior through the acrylic panes. Data analyzed included, but was not limited to, a sieve analysis, proppant concentration, fluid viscosity, and proppant conductivity testing on the samples. The testing demonstrated a significant impact on proppant transport, dune generation, and dune structure after shut-in through a tortuous path with varying fracture width and leak-off ports as compared to standard slot flow test.

This paper introduces novel, comprehensive, large, and tortuous slot flow testing equipment with features to represent the unconventional fracture behavior. Advanced equipment capabilities, test procedures and data collection methodology allow the industry to optimize the selection and deployment of various fracturing materials and treatment designs for unconventional well production enhancement.