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
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.
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.
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.